offshore drilling waste management review[1]

TECHNICAL REPORT

Offshore Drilling WasteManagement Review

February 2001

2001-0007

2100, 350 – 7th Ave. S.W.Calgary, AlbertaCanada T2P 3N9Tel (403) 267-1100Fax (403) 261-4622

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905, 235 Water StreetSt. John’s, NewfoundlandCanada A1C 1B6Tel (709) 724-4200Fax (709) 724-4225

Email: [email protected] Website: www.capp.ca

The Canadian Association of Petroleum Producers (CAPP) represents 150 companies that explore for, develop and produce natural gas, natural gas liquids, crude oil, synthetic crude oil, bitumen and elemental sulphur throughout Canada. CAPP member companies produce over 95 per cent of Canada’s natural gas and crude oil. CAPP also has 120 associate members that provide a wide range of services that support the upstream crude oil and natural gas industry. Together, these members and associate members are an important part of a $52-billion-a-year national industry that affects the livelihoods of more than half a million Canadians.

Review by July 2003DOCs # 25022

Disclaimer

This report was prepared under the guidance of a special Task Force of the Environment Sub-Committee of the Canadian Association of Petroleum Producers (CAPP) East Coast Committee. The report was developed with the aim of focusing discussions, specifically on drilling waste management, in the Government Working Group established to review the Offshore Waste Treatment Guidelines. Jacques Whitford Environment Limited in St. John’s, Newfoundland was retained by the Task Force to provide technical support and prepare draft material as and when needed. While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, neither Jacques Whitford Environment Limited nor CAPP guarantee its accuracy. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of Jacques Whitford Environment Limited or CAPP.

REPORT SUMMARY

This document has been prepared by the Canadian Association of Petroleum Producers (CAPP) to aid in the review of the Canadian Offshore Waste Treatment Guidelines (OWTG, NEB et al.,1996). It reviews current documentation and experience with technologies of drilling and drilling fluids, drilling waste management, drilling fluid environmental behavior in laboratory, modeling, and field studies, and discharge standards worldwide. The report examines drilling waste management and specifically addresses the disposal of synthetic based muds (SBMs). Examples from the east coast of Canada are used to illustrate the report.

Drilling Technology

The use and advancement of technology is at the core of modern drilling practices. Decision-makers are faced with the responsibility of selecting and employing a wide array of tools, products and techniques to optimize efficiency, safety and environmental compliance. Often the tools are linked together and the technologies are interdependent. The two primary phases of drilling operations conducted as part of the oil and gas extraction process are exploration and development. Exploratory drilling involves drilling wells to determine the presence of hydrocarbons. Exploration activities are usually of short duration, and involve a relatively small number of wells per field. Once hydrocarbons are discovered additional appraisal or delineation wells are drilled to determine the size of the hydrocarbon accumulation. When the size of hydrocarbon accumulation is sufficient for a commercial project, field development is then started. Development wells for petroleum production are drilled in this phase. Production drilling may span over a number of years. Although the rigs used for each type of drilling may differ, the drilling process is most often similar.

To better understand the generation of drilling waste, it is important to understand the basics of the rotary drilling process employed to drill most oil and gas wells. This process can be broken into three components: 1) the drilling rig; 2) the drillstring, bit, and casing; and 3) the drill mud circulating system. All three of these systems experience technical limitations, which in turn affect the type and quantity of waste generated by a drilling operation. By gaining a better understanding of the interrelationship between various drilling technologies, decision-makers can gain the insight necessary to make enlightened decisions that will result in the lowest overall environmental impact.

Drilling Rig: Offshore, drilling operations are performed either from jack-up drilling rigs, which are stationed on the seabed; floating units that include semi-submersibles and drillships and permanent production platforms. Regardless of the type, drilling rigs

CAPP Offshore Drilling Waste Mgmt Review February 2001

intrinsically are high-horsepower operations where the sizeable generators used for power become principal sources of air emissions. In the early days of offshore drilling, rigs were designed to operate in only 30–100 m of water. More recent developments and construction efforts for drilling rigs have focused on meeting the demand for deep water drilling. Deep water drilling rigs will be needed to service the future developments off of the east coast of Canada. The extreme demands of deepwater drilling make these rigs the most expensive to build and operate. These demands also require special technologies that ultimately constrain choice of drilling fluids and their drilling waste management options for deep water exploratory drilling.

Bits, Drillstring, and Casing: Advances in speciality tools like hydraulic mud motors, and downhole directional tools and the use of three-dimensional seismic data interpretation allow modern drilling operations to be very accurate. As well it is possible to drill horizontal and extended-reach wells to targets many miles from the platform. These innovations have resulted in optimum production and efficiencies, hence the need for fewer platforms and fewer wells to develop and produce a field. Extended reach and horizontal drilling techniques have made many fields that were previously uneconomic economically viable. The extraordinary advancements in technology and the resulting decrease in the number of wells and platforms required have also had a positive impact on the generation of drilling wastes. On average, today’s field development operations generate one-third of the drilling wastes of those earlier projects. Likewise, improved efficiencies of the drill bit and other downhole tools have helped to reduce dramatically the time required to drill a well and increase the size of the cuttings brought to surface. Larger drill cuttings are easier to remove from the drilling fluid, which reduces both the dilution volume and cuttings retention, resulting in a lower volume of waste.

Drilling Fluids: Drilling fluids (commonly known as muds), solids control equipment, and the circulating equipment are a critical and interrelated part of the drilling operation. Drilling fluids consist of a continuous liquid phase to which various chemicals and solids have been added to modify the operational properties. The drilling fluid has a host of critical functions, including controlling formation pressures removing cuttings from the well sealing permeable formations, and maintaining wellbore stability until casing is cemented in the wellbore and cooling and lubricating the drill bit. Meanwhile, solids control equipment separates drill solids from the drilling fluid, thereby allowing it to be re-circulated down the drill pipe. Depending on the geologic formation, environment, application and well objectives, drilling fluid systems are either water-based (aqueous) or non-aqueous emulsion systems.

Water-based drilling muds (WBMs) use water or brine as the continuous or external phase with the critical functions (density, viscosity, filtration, lubricity) achieved with the


addition of various materials. Non-aqueous systems use non-water soluble base fluid as the continuous phase with water (or brine) emulsified and dispersed in the base fluid. Non-aqueous drilling fluids (NAFs) include diesel, mineral oils, low-toxicity mineral oils (LTMOs), and synthetic base fluids. Studies in the North Sea and elsewhere in the 1980s, raised concerns about the environmental effects of the original high aromatic content diesels which drove the introduction of LTMOs and ultimately the development of synthetic based muds (SBMs) in the 1990s. The SBMs were developed to have the same performance as oil based muds (OBMs) but with a lower environmental impact and enhanced worker safety through lower toxicity, elimination of Polycyclic Aromatic Hydrocarbons (PAHs), faster biodegradability, and lower bioaccumulation potential.

In selecting a drilling fluid one must consider the formations that are being drilled through (e.g., whether there are unstable shales present), the wellbore complexity (e.g., whether the hole is vertical or extended reach), casing design, and pore pressure analysis. While WBMs maintain an important role in many drilling operations, NAFs offer a number of technical advantages over WBMs in difficult drilling situations (such as extended reach or drilling of high temperature/high pressure wells).

As compared to WBMs, NAFs inhibit shale hydration, consequently wellbore stability is maintained. NAFs are intrinsically lubricious; therefore, the ability to drill highly deviated extended reach and horizontal holes is enhanced over that with WBM use. In addition, NAFs are generally more stable in high-temperature applications such as those encountered in deep wells. Furthermore, NAFs are less susceptible to the formation of gas hydrates that might potentially occur during deepwater drilling operations. As a result of these characteristics, NAF use allows faster drilling rates and results in fewer drilling problems. Faster drilling also assures fewer rig days (less cost and emissions) and reduces health and safety risks to personnel. In addition, better well bore maintenance with NAF use results in reduced quantities of solids generated.

Despite their high performance, there are limitations to NAF use. These limitations include their cost (ranging from $50 to $500 per bbl US), limitations on the fluid physical properties particularly in cold water applications, reduced logging quality over WBMs, the high cost of lost circulation problems, and environmental concerns associated with NAF disposal.

Owing to the minimal technical demands, low-cost WBMs typically are used in the upper sections of most wells. As the well deepens, and/or becomes directional, the technical demands increase proportionately, necessitating displacement with either a specialized water-based system or a non-aqueous drilling fluid. In wells drilled on the east coast of Canada, the more challenging intervals employ NAFs, because of well complexity (well


depth and/or water depth, extended reach or horizontal wells), duration of the wells (depth and climatic shutdowns require a fluid system that will maintain wellbore stability), high temperature high pressure wells (encountered when drilling the deeper formations), lubricity (wells are drilled to the limits of the mechanical equipment torque capability and require sufficient lubricity), and environmental concerns (improved drilling efficiencies as documented by Hibernia, Terra Nova, and Jeanne D'Arc Basin experience, have resulted in fewer days on location, lower emissions, and reduced discharge volumes).

Environmental regulatory considerations play a significant role in both the selection of drilling fluids and the overall economics of drilling a well. The specific regulatory requirements of an area often dictate the technologies that can be used and what, if any, material can be discharged into the environment. This, in turn, influences what and how wells can be drilled. The ability to discharge NAF cuttings significantly expands the inventory of wells that can be economically drilled in an area.

Solids Control: The level of drilled solids (or cuttings) in any drilling fluid must be controlled, as a high concentration will cause drilling problems. Solids control and removal equipment and dilution is used to dilute and control the amount of drilled solids in the fluid. The removal of cuttings from an active circulating system is an imperfect process. Under all field conditions, some percentage of the drilling fluid is discarded with the drill solids, while some fraction of the drill solids are retained in the active fluid system. This contaminated fluid must then be diluted to control the build-up of the drilled solids. If a solids control system is not working efficiently, the resulting buildup of very fine drilled solids in the active circulating system can become a problem requiring the disposal of large volumes of “used” fluid. The amount of drilling fluid retained on cuttings must therefore be monitored very closely. Normal solids control systems will typically discharge cuttings with <15% by weight of base fluid. Although cuttings dryers can significantly reduce the concentration of drilling fluids on the cuttings, the trade off is that recovered liquid is high in low-gravity solids and can quickly generate the need for large dilution volumes and therefore generate large volumes of waste. This waste drilling fluid will need to be disposed of onshore or reinjected. The degree of buildup of fines in fluid varies with the local geology and may be an issue more in eastern Canada than elsewhere

Because of the superior cuttings integrity (larger and easier to remove) generated when drilling with NAFs, the solids removal efficiency is higher than it is with WBMs. Since NAFs have higher efficiency and also higher tolerances for fine solids they require less dilution than do WBMs, therefore lower volumes of NAFs are required to drill a well than WBMs. Total discharge volumes will be greater when drilling with WBMs than with NAFs because:


greater volumes of cuttings are generated from the hole enlargement which results •when drilling with WBMs;higher volumes of fluid required to drill a hole of the same dimensions; and •bulk discharge of whole WBMs. •

Drilling Waste Management Options

Residual drilling fluids and cuttings usually represent the largest volume of wastes generated from drilling operations aside from produced water. Once all source reduction options have been exhausted, recycling and waste treatment are employed to further reduce potential environmental impacts. As with the drilling process, understanding the economic, operational and environmental limitations of the available waste treatment technologies is an important step toward selecting the best technology for a particular area. One needs to understand the potential environmental impacts of ocean disposal and also the potential impacts of alternative disposal options. These other impacts include costs, resource use, air emissions, transportation and handling risks, occupational hazards, and chemical exposure. All of the relevant factors are part of a comparative framework in which the environmental, human health and safety, operational, and economic costs and benefits are evaluated.

Drilling waste management options can be roughly grouped into three categories: offshore discharge, re-injection on-site, and onshore disposal. All three groups of waste management options come with their own set of advantages and limitations. A deeper understanding of the specifics of each technology is required for key stakeholders to make the best decisions in the regulatory process.

Offshore Discharge: Offshore discharge is in most cases the least expensive and operationally uncomplicated, of the three options. In evaluating the viability of this option, one must consider whether the fluid can meet regulatory requirements for discharge, the technical drilling requirements, and the potential environmental impact. WBMs and associated cuttings have been and are being discharged from wells drilled offshore in eastern Canada. In the 1980’s, OBMs were used as well and the associated cuttings discharged. More recently, SBM cuttings are being discharged from wells drilled at Hibernia and Terra Nova, and were discharged from Sable Offshore Energy Inc. (SOEI) operations until recently. Offshore discharge has also been a critical necessity for deep water exploratory drilling where distance from shore and technological limitations constrain the use of other disposal options. The future of offshore discharge as a waste management option will depend largely on regulatory development. As long as the focus is on continuous efforts to improve the level of control of constituents placed in the receiving environment, the technology should have a place in the range of available waste management


options.

Cuttings Re-injection: Another option for drilling waste disposal is on-site cuttings reinjection (CRI). This process involves pumping fluids and seawater-diluted cuttings that have been ground into small particle sizes into an underground formation. Before injection is possible, most formations must be fractured with hydraulic pressure, creating small cracks that allow fluids and solids to be pushed away from the wellbore. Injected fluids are confined in the receiving formations mechanically (by cemented casing) and geologically (by caprock). Cuttings may be injected via the annulus of a well being drilled or into a dedicated or dual use (one that will later be completed for production) disposal well. Injection is a complicated process, requiring intricate design, specialized equipment, careful monitoring and detailed contingency plans. In evaluating the viability of CRI as a disposal option, one must consider the following:

the availability of a geologic formation suitable for accepting wastes long-term;•the types and quantities of wastes;•the requirements for surface equipment, the well design and integrity; and•the drilling development scenario.•

Cuttings generated from drilling have been injected offshore in a number of locations including the North Sea, Gulf of Mexico, and eastern Canada (Cohasset-Panuke and in late 2000, Hibernia). Experience with CRI has been variable with regard to equipment reliability and failure of the injection wells to contain the waste. Recent surveys show that CRI can be successful, with improvements over the last few years reducing downtime considerably. Research is continuing to identify the limitations of the technology as well as improvements that can extend its successful application. The most significant limitation for injection technology is the requirement for a suitable injection formation. The formation must have sealing formations that prevent broaching into other formations or to the surface. The technology has been applied primarily from bottom founded installations, and there is little worldwide experience with injecting from floating facilities. Floating drilling units have additional limitations relating to wellhead design and remotely operated vehicle (ROV) access. CRI operations can be limited by water depth as well. This will become even more of an issue when east coast Canada operations move into deeper waters. CRI may not be a technically or economically viable option for all drilling situations, especially exploratory and deep water drilling, and the applicability of this technology needs to be evaluated on a case-by-case basis.

Onshore Disposal: If drilling wastes are not handled onsite either via discharge or CRI, they will need to be transported to shore for disposal. Consideration of any onshore disposal option must also include consideration of the offshore operations and transport


associated with getting the drilling waste to shore. There are a number of environmental, operational, and economic disadvantages to the selection of onshore disposal. These operations require extensive use of support vessels to take the cuttings to a shore location. Fuel is expended by the work boats during the offshore loading and transport process, resulting in air emissions. There may be significant costs associated with transporting cuttings to a shore base; these costs may be prohibitive for remote, deepwater applications. Safety and environmental risks (potential for spill) associated with handling and transporting cuttings to shore are increased over those of other options, particularly in areas prone to inclement weather. Finally, there may be operational issues with handling large volumes of cuttings either generated from high rates of drilling or from shutdown of offloading and transport operations due to inclement weather.

Onshore, there are number of options for treatment, recycling, and disposal of drilling wastes. These options include landfill disposal, biodegradation techniques (land treatment or composting), stabilization/solidification, and thermal treatment technologies (thermal desorption and incineration) as well as some newer technologies such as the hammermill process. The viability of each of these options will depend upon assessment of environmental (e.g., potential for leaching of constituents into ground or surface water, emissions from equipment and transport to site, resultant end product, compliance with regulations), operational (e.g., presence or proximity of infrastructure or facility, climatic limitations, personnel requirements and health and safety), and economic (e.g., cost of processing, onshore transport, future liability). At the present time, operators in some parts of the world (e.g., North Sea, Gulf of Mexico, and eastern Canada), where technically and economically feasible, or where regulations prohibit discharge, may ship their cuttings to shore for disposal. As with the other options, onshore disposal may not be a technically or economically viable option for all drilling situations and the applicability and selection of this technology needs to be evaluated on a case-by-case basis.

Environmental Management Systems, Procedures, and Tools

In Canada there are many checks and balances provided by operators and regulators to ensure that environmental impacts of oil and gas operations are minimized and that changes can be made to operations if impacts are found.

First, in most cases a project undergoes an extensive approval review process. As part of the regulatory process, an environmental assessment (EA) may be done using site-specific information on the background conditions in the area. The EA predicts impacts of operations utilizing results of laboratory tests, dispersion modelling, and previous studies of impacts from like operations to predict the potential for the surrounding environment to be impacted by operations. Through this process, significant concerns can be addressed


before the project is approved. Recently, a more holistic EA approach has been taken, such as the Life-Cycle Value Assessment (LCVA) in which assessments are made of the full cycle of environmental effects that could be realized by not only proposed operations but also for alternatives (e.g., onshore disposal).

Secondly, in some jurisdictions, such as Canada and the North Sea, all chemicals used for offshore discharge must be approved for use under a chemical management system. In Canada this is the Offshore Chemical Selection Guidelines (OCSG) and in the North Sea, this is the Harmonized Mandatory Control System.

Thirdly, compliance of operations to regulatory and design standards are monitored and reported through an environmental compliance monitoring (ECM) program. This may involve monitoring of effluent streams to determine the quantities and concentrations of specific constituents and their compliance with regulated levels. Finally, environmental effects monitoring (EEM) programs determine and quantify deleterious effects to the receiving marine environment resulting from operations. The objectives of an EEM are to confirm predictions made in the EA, provide early warning of potential impacts, provide information for modifications to operational practices and procedures, and provide the basis for technical improvements. Another check on the environmental soundness of operations is the Environmental Management System (EMS) under which each oil and gas company operates. An EMS is a set of guiding principles that govern all operations of a facility and is part of an overall management system for planning, developing, implementing, achieving, reviewing and maintaining the environmental policy of a company.

Within an environmental management framework, the primary tools used by regulators and operators in evaluating the environmental behavior of drilling fluid discharges and their potential impact on the marine environment are laboratory testing, computer modelling, and field studies. More specifically, these tools are used to evaluate the following environmental issues associated with discharge of drilling fluids and cuttings: fate, persistence, and biodegradability; toxicity and smothering of marine benthos; organic enrichment and sediment anoxia of seabed sediments, and potential for bioaccumulation in marine benthos. All of the tools available to regulators and industry have their own advantages and limitations. By combining more than one of these elements in a framework of regulatory control the process becomes both more reasonable to implement and more protective of the environment. By developing a deeper understanding of all the available tools and the environmental issues that need to be addressed, stakeholders can make more effective decisions.

Laboratory Studies


Laboratory studies provide industry and regulatory agencies the ability to identify materials and concentrations of those materials that when discharged may have unacceptable environmental impacts. Properties most commonly tested for in the laboratory are biodegradability, toxicity, and to a more limited extent, potential for bioaccumulation. Laboratory results may be used to compare the relative performance of various products so those posing the least risk to the environment can be identified for use and discharge. In addition, laboratory results can be used as a monitoring tool for the routine evaluation of continuing discharges to ensure that any environmental effects at the point of discharge are consistent with the predicted effects. However, laboratory results may reflect artifacts of the laboratory setup and may be imprecise in truly replicating actual field conditions, both in terms of laboratory exposure concentrations and durations, and stresses imposed on organisms by taking them out of their natural habitat. Furthermore, although lab results may provide an indication of relative performance, they may not provide an indication of absolute performance. Consequently, one must be cautious in extrapolating laboratory results to explain or predict what is occurring in the field. The laboratory data for the newer SBMs are often compared to results from OBMs because they provide an existing environmental benchmark to measure improvements in environmental performance of the SBMs over the OBMs.

Modelling and Field Studies

Computer modelling has been used to assess drilling discharges by the oil industry and regulatory agencies worldwide. Modelling takes into account discharge volume and properties as well as characteristics of physical receiving environment to predict the fate, effect, and persistence of drill waste in the marine environment. Several computer models exist that predict the dispersion and initial depositional behavior (accumulation thickness and concentrations) of drilling fluids and drill cuttings discharged into the marine environment. In eastern Canada, computer models are also used to predict the resuspension and transport of deposited drilling wastes. However, models are limited by the quality of input data used to describe future discharge events, physical environment (e.g., currents, water column structure), and drilling fluid properties (in particular settling velocity). In addition, in high-energy environments, it is important to account for resuspension and transport after deposition, which several models can not do.

The discharge of drill muds and cuttings takes place in a wide variety of marine environments around the world. Each area is unique in terms of water temperature, bottom type, thermoclines, current speed, frequency and severity of storm events, and biota. Consequently, field studies do provide an important mechanism for understanding the environmental performance of discharged drilling wastes. However, data from field


monitoring programs are notwithout problems. Field data can also be highly variable due to natural spatial and temporal variation of nearly all environmental parameters (e.g., temperature, grain size, benthic abundance) and require careful and detailed interpretation. There are a number of EEM programs that have been conducted in eastern Canada. Results of EEMs from Cohasset-Panuke (COPAN) where LTMOs were discharged, SOEI where internal olefin SBMs were discharged, and Hibernia where paraffin SBMs were discharged, are discussed below and in detail in the report.

Environmental Issues and Effects

The tools discussed above are used within the environmental management framework to evaluate the following environmental issues associated with discharge of drilling fluids and cutting: fate, persistence, and biodegradability; toxicity and smothering of marine benthos; organic enrichment and sediment anoxia of seabed sediments, and potential for bioaccumulation in marine benthos. The environmental fate and effects of discharged cuttings is determined largely by oceanographic factors such as temperature, current direction and speed, and sediment composition. Regardless of the fluid discharged, water depths and oceanographic conditions will influence the initial accumulation and distribution of the cuttings, as well as their persistence (redistribution and biodegradation). Therefore, these factors need to be considered in developing appropriate regulatory and management strategies.

Fate: The fate (e.g., aerial thickness and extent) of cuttings discharges will depend upon the local oceanographic conditions, quantities and conditions of discharge, amount and concentration of fluids on cuttings, and fall velocity of cuttings particles. When discharged into the sea, SBM and OBM cuttings do not disperse like WBM cuttings. Because the particles are not water miscible, they tend to aggregate, falling rapidly through the water column, and accumulating in higher concentrations near the discharge point than would WBM cuttings. WBMs are generally more widely dispersed over the seabed and large piles are usually not formed. At very low retention values (<5%) NAF cuttings are believed to disperse more like WBM cuttings.

In shallower waters the initial thickness of cuttings deposition and concentrations of sediment hydrocarbons and/or metals may be higher than for deposition in deeper waters. In deepwater, natural abatement processes may be more efficient in reducing accumulations of cuttings that are spread over a larger area. However, those cuttings deposited in shallower water may disperse more readily due to bottom currents and disturbance from biological activity. Due to the lack of suitable current data, computer modelling studies on deposition and impact of discharging cuttings in water depths greater than 100-200 m are quite limited. Likewise, there have been few field-monitoring


programs at sites in deeper water depths.

Field studies of the fate of cuttings discharged on the Scotian Shelf (at SOEI), a high energy environment, indicate that the maximum accumulation of cuttings ranged from 1-3m, and that the maximum extent of visible accumulations extended out to 70m from the discharge point in one direction. It should be noted that the drill cuttings accumulations were significantly smaller than predicted from pre-discharge modelling, indicating the importance of local seafloor conditions in determining the fate of discharged materials.

Persistence and Biodegradability: Once cuttings are deposited, the physical persistence of the cuttings and elevated levels of constituents (metals and/or hydrocarbons) will depend upon the natural energy of resuspension and transport on the seafloor, the amount of biological disturbance, and the rate of biodegradation of the fluid. Duration of benthic community impact is directly related to the persistence of NAFs and the associated chemical constituents. Rates of biodegradation will depend upon seafloor conditions (temperature, oxygen availability, sediment type, fluid concentration in sediments) as well as fluid type. Crude oil, diesel and other long chain and highly branched hydrocarbons are more difficult for microbes to digest. Short chain hydrocarbon molecules like those used in synthetic-based fluids, are easier for the microbes to consume. Oxygen availability is a key factor in determining the rate of biodegradation. Studies have shown that degradation occurs more rapidly under aerobic conditions, such as those on the exposed surface of cuttings or cuttings accumulations, than under anaerobic conditions such as those within a cuttings accumulation.

The persistence of cuttings piles in the North Sea has been attributed to the slow biodegradation of the traditional OBMs discharged over many years. SBMs were introduced to address this issue, making the testing of biodegradation rates a major concern in the North Sea. Biodegradation continues to be an important characteristic accounted for in evaluating a fluid's environmental acceptability.

There are a number of different methods for determining biodegradability. Laboratory studies indicate that NAFs exhibit a range of degradation rates. Under comparable conditions, esters seem to degrade the most quickly, and other base fluids have more similar degradation rates. The extent to which base fluids differentiate in degradation rate depends upon the testing protocol used. Degradation rates in sediments decrease as base fluid concentration increases.

Field studies indicate that as compared to traditional OBMs, SBM levels in sediments decline much more rapidly. In terms of field performance, limited comparative data


indicates that esters are less persistent than olefins or ethers. In most SBM field studies, the SBM levels declined significantly, and in some cases, to non-detectable levels within one year following drilling. Most studies indicate evidence of anaerobic conditions, which is consistent with biodegradation of SBM leading to anoxic conditions. The areas that recovered the most rapidly were those where there were active bottom conditions.

This has been the case for sites on the Scotian Shelf. The SOEI EEM results indicate drill cuttings accumulations were considerably smaller than modelled, and elevated levels of hydrocarbons and barium found near the platform were short lived. Even at the Cohasset site where LTMOs were discharged, hydrocarbons were detected only at a few sites. Elevated levels of constituents related to drilling discharges have persisted from year 1 to year 2 of the Hibernia EEM. Although the measured levels are not of environmental concern, they may in part be due to the more quiescent conditions at the Hibernia site, and also to the greater volumes of material being discharged at Hibernia than at the SOEI sites.

Toxicity: Impacts to the water column from discharging SBM cuttings are considered to be negligible because the cuttings settle quickly (i.e. exposure times in the water column are low) and the water solubility of the base fluids is low. Water column impacts from discharging WBMs are considered low as well due to their rapid dispersion from the point of discharge. Studies of toxic effects resulting from SBMs have focused on the benthic community. Toxic effects on the benthic community include chemical toxicity and toxic effects due to anoxia caused by organic loading and biodegradation. The relationship between toxicity and biodegradation has been a subject of research because it appears that rapid degradation of some components can lead to more severe short-term anoxic toxic effects. As significant progress has been made to eliminate acutely toxic drilling fluid additives, more research has been focused recently on sublethal and chronic effects (longer-term impacts on physiologic responses). One of the research efforts in the area of sublethal impacts has been advanced in eastern Canada, and has focussed on the potential influence of fine particulates in the benthic boundary layer to filter feeding organisms.

Ecotoxicological testing on WBMs indicate that most have low acute aquatic toxicity and the metals contained in WBMs are not bioavailable. In two different sets and types of tests run in Canada on Canadian organisms, results indicated that SBMs such as those currently being used offshore eastern Canada, were less toxic to benthic organisms than LTMOs. However, both SBM and LTMO responses were considered to be non-toxic. In addition, in one suite of tests, SBMs showed lower aquatic toxicity than a high performance WBM.

Results of toxicity testing on samples collected as part of eastern Canada EEM programs indicate that for the most part there were no toxic responses in sediment toxicity testing.


As part of the SOEI EEM, several samples indicated a toxic response in an amphipod mortality test, but when samples from the same location were tested several months later they no longer exhibited the same toxic response. In aquatic toxicity testing (MicrotoxTM) none of the SOEI samples indicated a toxic response. Although some of the samples collected as part of the Hibernia EEM did show a toxic response in MicrotoxTM testing, those samples were dissimilar in grain size to other samples. There appears to be no correlation with the response and drilling discharges.

Bioaccumulation: Bioaccumulation is the uptake and retention of substances which are not a natural component of the environment by organisms. Generally, SBMs are not expected to bioaccumulate due to the rapid rate of their clearance from organisms, and extremely low solubility. Laboratory results support this argument. Ultimately, the propensity for SBMs to biodegrade, further reduces any potential exposure and consequent bioaccumulation in organisms.

Field studies conducted in eastern Canada, also support the above statements. Shellfish collected at COPAN, where LTMOs were discharged, did exhibit tainting and uptake of hydrocarbons. However, once discharge was discontinued levels returned to normal and the taint effect disappeared. Neither mussels nor scallops collected as part of the SOEI EEM showed any indication of taint. In addition, although low levels of hydrocarbons were detected in some scallops, it is not likely that the source is drilling fluid. At Hibernia, there is no indication of taint in the American plaice collected near the platform. Body burden data collected after two years of operations was inconclusive with regard to finding accumulations attributable to drilling discharges. Benthic Effects and Recovery: When drill cuttings are discharged during any type of drilling operation, (water based or NAF) benthic biota immediately below the point of discharge are physically smothered. Recovery of the benthic community is dependent upon the type of community affected, the thickness, aerial extent, and persistence of the cuttings (due to a combination of seafloor redistribution and biodegradation), and the availability of colonizing organisms.

Field studies of WBMs indicate that the potential for biological effects is low and depends primarily on the energy of the seafloor environment. When impacts are observed, they appear to be physical in nature, highly localized, and temporary.

Most of the knowledge about OBM cuttings discharge impacts was developed from seabed studies conducted on North Sea sites that began operations in the 1970s. While disposal practices improved from the 1970’s to the 1980’s the seabed surveys continued to evaluate the same locations. Consequently, many of the mitigative effects were masked


by the residual material from previous disposal practices. Based on results of North Sea studies, the concept of "zone of effects" was arrived at in the mid to late 1980's. The primary points are that discharges of diesel OBM cuttings can have an adverse effect on the seabed biological community directly under and in the immediate vicinity of the platform. Major effects (in some cases complete depopulation of benthic species) are confined to zones ranging up to 500m and 250 m from wellsites for multiple and single well drilling with diesel OBMs, respectively. In this zone recovery is likely to be slow. Surrounding this area of major effects is a transition zone in which lesser biological effects are detected; although hydrocarbon concentrations are still elevated. The size and extent of these zones will be dependent upon the number of wells drilled and the local current regime. Studies of long-term impacts of diesel OBM cuttings discharges indicate that hydrocarbon concentrations remained well above background levels and benthic communities were still affected for at least 8 years for some stations near the drill sites.

Ultimately, the combination of a history of high OBM retention on cuttings and measurable long term impacts led the North Sea to the phase out of OBM cuttings discharges. However, in other geographic areas (e.g., Australia, and eastern Canada), the same impacts observed in the North Sea have not been duplicated where LTMOs have been discharged. It is likely that the combination of solids control equipment, lower aromatic content and consequent lower toxicity, and receiving environment conditions resulted in low impacts and rapid recovery of the seafloor in these areas.

The impacts of SBM cuttings on marine biota are expected to be less than those of OBM due to lower toxicity and more rapid biodegradation. Studies of SBM discharges in North Sea, Australia, Gulf of Mexico, and eastern Canada have found that effects on the benthic community are usually localized (within 250 m) and show signs of recovery within one year. As with OBM discharges there may be significant reduction in biota in the immediate vicinity of the outfall. What differs from OBMs however, is the rapid rate at which recolonization and recovery occurs.

Over the longer term, the biological communities typically recolonize the affected areas in a successional manner, with initial colonization by species that are tolerant of hydrocarbons and/or opportunistic species that feed on bacteria that metabolize hydrocarbons. As time passes and hydrocarbon loads diminish, other species return via immigration and reproduction, and the community structure returns to something more closely resembling its former state.

There is limited information available from Canadian EEM programs regarding benthic effects and recovery. This is in part due to the high natural variability of infaunal communities resulting from the dynamic nature of the seafloor, in addition, at the SOEI


sites, the compactness of the seafloor made sample retrieval difficult so additional information was provided by photos and video. At COPAN, changes in the benthic infaunal community could not be definitively attributed either to drill wastes or to natural sediment transport. At SOEI, no effects on the benthic community could be detected outside of area of significant cuttings accumulations (maximum extent of 70m). However, high natural variability (spatially and temporally) of the benthic organisms makes effects detection very difficult. No benthic data was collected at Hibernia due to concerns regarding the ability to detect impacts given the high spatial variability of benthic organisms. Instead the program is relying upon the combination of sediment chemistry and physical properties, and toxicity data to provide indications of potential for benthic effects. Thus far at Hibernia, there is no indication of biologic effects on the benthic community that can be directly attributed to drilling discharges.

Overall, results of studies on the effects of discharge of drilling waste emphasize the importance of the local receiving environment including water depth and current regime on determining both the initial area affected and the persistence of hydrocarbons in the sediment.

Regulatory Regime

Discharges of drilling fluids and cuttings from offshore operations, are heavily regulated and closely monitored world wide including in the North Sea countries, Australia, the United States and Canada. The regulatory models in each jurisdiction are unique and reflect the offshore operating experience, the size and age of the industry, and the characteristics and sensitivities of their marine environments, environmental protection strategies and testing techniques, and political sensitivities. These differences have influenced a range of regulatory responses that reflect the unique situation in each country. Consequently, it is important to understand the history, framework, and reasoning that led to a particular regulatory decision.

Overview: In developing regulations, regulators have borrowed freely from the experience and results in other jurisdictions. At this time, there have been essentially two different models for addressing drilling waste disposal issues. The first model is from the North Sea where drill cuttings management initiatives have been driven by the regional OSPAR Convention. The North Sea is unique because it is a semi-enclosed water body surrounded by heavily populated industrialized countries, each with a sector of the North Sea to manage. The OSPAR convention is focused on marine discharges and does not have responsibility for onshore waste disposal. Consequently, the collective environmental and political pressures to regulate marine discharges such as drill cuttings have been much greater than in areas such as Australia, Canada, and the United States which are governed


by their own national legislation, and use a more holistic approach to management of drilling waste. However, the North Sea regulatory regime appears to be evolving to being somewhat closer to the second model than it has in the past.

The second model includes approaches taken in Australia and the United States, where systems for the management and discharge of SBM cuttings are evolving. In these areas, industry and the regulatory agencies have developed a holistic approach to the SBM cuttings management issue to ensure that all the technical, financial and environmental consequences are thoroughly evaluated before a final decision about a disposal strategy is made. This approach relies heavily on the concepts of best available technology (BAT) and best environmental management practices to achieve the best possible environmental option (BPEO). It places a strong burden on the operator to carefully manage the drilling program and be accountable for the result.

The development of guidelines for drilling fluid and drill cuttings is an ongoing process in the US and other areas at the time of publication. At the present time, the most recent OSPAR guidelines on SBMs have segregated SBM regulation from OBMs and do not subject SBMs to the same 1% retention limit as OBMs. Within OSPAR members, Norway, at this time, is continuing to use SBMs on a conservative basis with a zero discharge philosophy on minimizing overall environmental impacts. The UK has suspended SBM discharges as of year end 2000. The US has also segregated SBMs from OBMs by definition and is moving toward discharge of SBMs based on a pollution prevention strategy and indications of low potential impacts as measured in the laboratory and the field. Likewise, Australia is continuing to discharge SBMs on a strategy of evaluating the technical needs of each project and environmental sensitivities of the area on a case by case basis. In these areas, other options such as WBM discharges, and cuttings injection are also accounted for in the regulatory framework.

North Sea/Northeast Atlantic: OSPAR provides an international framework for development of a harmonised approach to environmental regulations and control of offshore drilling discharges with the primary objective of improving the aquatic environment of the Convention area in general and the North Sea in particular. Historically, the principal OSPAR concern has been the formation and persistence of diesel and mineral oil based cuttings piles in the Central and Northern North Sea. As a result of these concerns, first the use/discharge of diesel muds was banned, and later discharge of their replacement LTMOs was restricted in 1992 to 1% oil on cuttings (OOC). The development, and further evaluation of the use and discharge of synthetics lead to considerable regulatory debate regarding the setting of acceptable environmental impact criteria and the final assessment of the impact from specific fluid types. Laboratory test results indicated that SBMs were less toxic and more biodegradable than the mineral


oils they replaced.

The discharge of synthetics has been extensively discussed at the OSPAR sea based working group meetings from 1996 onwards. These efforts culminated in the OSPAR Decision 2000/3 on the use and discharge of organic-phase drilling fluids. Some of the key points of this decision are as follows:

a 1999 definition of organic phase fluids (OPF) has been replaced with separate •definitions for oil and synthetic fluids; OBM cuttings discharges are limited to 1% OOC; and•SBM cuttings discharges can be authorized on an exceptional basis based on the •application of the Best Available Technology and Best Environmental Practice.

The identification of basic environmental acceptance criteria such as toxicity, biodegradeability, and bioaccumulation potential, with consideration of hydrodynamic conditions of the receiving environment in evaluating the discharge of cuttings parallels the approach being used by the US and other areas that are continuing to discharge SBM cuttings. Likewise, this decision also includes provision for consideration of non-water quality impacts such as the conservation of resources including energy. The interpretation and application of the terms of this OSPAR draft decision are up to the individual countries.

The recent implementation of the harmonised mandatory control scheme for regulation of offshore chemicals is a major milestone for OSPAR. It is likely to change the entire approval structure in the member countries and will strengthen the process of integration of OSPAR within the European Community.

Norway: Norway has a strong regulatory framework in place, which includes environmental regulations and permits, as well as open dialogue with industry. Conditions for granting permits for use and discharge of chemicals from offshore installations are regulated by the Norwegian Pollution Control Authority. The testing requirements follow OSPAR Decisions and apply to SBM and WBMs. As the regulatory process for synthetic fluids has evolved, Norway has taken a conservative approach to discharge. At the current time, SBMs continue to be discharged on a limited basis supported by the information supplied simulated seabed studies and field studies at SBM discharge locations. In the late 1990’s, the UK regulators pushed forward with regulatory approaches based on the solid phase biodegradation test, while the Norwegian regulators retried on the simulated seabed tests and results of seabed surveys to guide their approach to synthetic fluid discharges. Presently, SBM discharge is not allowed for exploration wells and is allowed only at sites where SBMs have previously been discharged. In their discharge permit, operators must


evaluate the pros and cons of discharging SBM cuttings versus use of other organic phase fluid systems and the consequent environmental effects both on and offshore. In a recent position paper on their “zero discharge philosophy” towards SBMs, the Norwegians indicate that this implies a continual process toward obtaining the lowest possible environmental impact and not necessarily a ban on the discharge of SBMs into the marine environment.

UK: The regulation and control of offshore drilling discharges in the UK Sector of the North Sea began with approval for offshore drilling in the early 1970’s. From the inception of the Oslo and Paris conventions (later re-ratified as the OSPAR Convention) the UK Government has reviewed the effects of these offshore discharges and agreed on a harmonized approach to their further control and regulation with the other Contracting Parties of OSPAR. SBMs have borne the regulatory legacy of the effects of OBMs used in the 1970s and 1980s, particularly in the UK sector of the North Sea where these muds were commonly used and their associated cuttings discharged.

With introduction of SBMs, the UK government wanted assurance that large persistent piles such as had resulted from discharges of OBMs would not reoccur. SBMs with acceptable biodegradability and toxicity performance were approved for use at a limited number of sites, pending assessment of their in situ degradability through seabed surveys.

Although SBMs have been discharged within the UK for some years, in most cases the quality of seabed survey data has been insufficient to draw reliable conclusions. Therefore, the UK regulatory authorities decided to carry out laboratory based degradation studies investigating the rates of removal of base fluids from marine sediments relative to mineral oil. The test results indicated that at the highest concentration tested (most indicative of likely behavior within cuttings piles), all SBMs, except for esters showed little sign of biodegradation. This lead to a stepwise reduction of the discharge of SBMs. The discharge of all SBMs is being phased out by the end of 2000. While the regulators in the UK have pointed toward the laboratory degradation tests as the technical reason for moving toward elimination of SBM discharges, it appears that political response to the legacy of OBM cuttings piles has played a role as well.

United States: In the 1970’s compliance standards were developed as a means of regulating drilling fluids discharges in the US. The first regulatory permits written in the 1970’s for drilling fluid discharges effectively eliminated discharges of cuttings coated with OBM. Water based mud regulations evolved from the 1970’s through the early 1990’s. Consequently when SBMs were introduced into the USA in the early 1990’s they were not burdened with the legacy of OBMs as they were in the North Sea. Presently SBM cuttings may be discharged under the same restrictions imposed on WBMs.


Industry and the Environmental Protection Agency (EPA) recognized there were limitations to the current regulations with regard to controlling SBM discharges, and as the industry and EPA initiated a collaborative effort to develop specific controls for SBMs. In 1999, the EPA published proposed effluent limitation guidelines for synthetic based and other non-aqueous drilling fluids. Some of these were modified in April of 2000, and further changes are anticipated prior to the final ruling on these limitations at the end of 2000.

EPA intends that these proposed guidelines control the discharge of SBMs through application of appropriate levels of technology, and also encourages the use of SBMs as a replacement to diesel and mineral oil-based fluids. The EPA stated in their proposed rule that the use of SBMs and discharge of the cuttings with proper controls would overall be environmentally preferable to the use of OBMs. The technical reasoning behind the EPA's position was also stated in the proposed rule and is as follows:

There are certain drilling situations where WBM use is slow, costly, or even •

impossible, and creates large quantities of waste. In these situations, the well would traditionally be drilled with OBMs. However, now there are SBMs available which can achieve the same technical performance as OBMs yet have lower environmental impact and greater worker safety;SBM discharges would be limited in duration and would eliminate non-water quality •

impacts associated with disposal of OBM cuttings onshore or via injection (e.g., increased emissions, energy use, land-disposal); Available seabed survey data suggest that SBM cuttings impacts are limited in aerial •

extent and duration; andImpacts on the benthic community are primarily due to smothering, alteration of grain •

size due to introduction of cuttings, and anoxia (caused by decomposition of the organic base fluid). The first two impacts are also associated with WBM and WBM cuttings discharges.

In the proposed rule, there are limitations proposed on the base fluids-with regard to meeting biodegradation and sediment toxicity standards; limitations on the discharged cuttings with regard to formation oil content and fluid retention and limitations on barite chemistry. Other controls such as end of pipe toxicity testing are being considered as well.

Western Australia: The Western Australian Department of Minerals and Energy (WADME) has developed an objective case-by-case approach to assessing drilling proposals and regulating offshore drilling fluids, as opposed to using the more traditional methods of focussing on the regulation of classes of drilling fluids based on their chemical


category. A risk-based approach is used since there is a range of habitat variation coupled with the uncertainties associated with the assessment of environmental effects. WADME does not use an approval system of particular drilling fluids or chemical category in isolation but rather, considers the use of the drilling fluids in the context of the whole drilling application. This holistic approach to the assessment and regulation allows several assessment criteria to be used in the decision framework including:

environmental sensitivity of the well location;•the oceanographic conditions and the potential for cuttings accumulations;•the type and quantity of proposed drilling fluid and cuttings;•the method of cuttings disposal;•the environmental performance of the drilling fluid under standard test protocols; and•the technical justification for the proposed use of the drilling fluids.•

Canada: Canada is in a relatively early stage of offshore development in comparison with other world jurisdictions. The lessons learnt and knowledge gained in other jurisdictions have shaped the development of the east coast regulatory regime. This has provided east coast Canada with the opportunity to ensure adequate safeguards are put in place to mitigate potentially undesirable environmental effects. This is done through a mix of specific legislation, operational guidelines, and legislative provision for open environmental assessment processes.

On the Canadian east coast, offshore oil and gas developments are subject to the Atlantic Accord Implementation Act and Regulations. Two boards, known as the Canada – Newfoundland Offshore Petroleum Board (CNOPB) and the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB), administer this legislation and are responsible on behalf of the Canadian, Nova Scotian, and Newfoundland & Labrador governments for petroleum resource management in the Nova Scotia and Newfoundland offshore areas. The Boards have developed two sets of guidelines that bear directly on the management of drill fluids and cuttings. These are entitled the OWTG (NEB et al., 1996) and the Draft OCSG (NEB et al., 1999). These two guidelines provide a basis for managing the selection, use and disposal of drilling fluids and cuttings as well as other discharges and chemicals.

The OCSG provide a consistent framework for chemical selection as part of the environmentally responsible management of chemicals used in offshore drilling and production activities. All offshore drilling and production chemicals that may be discharged in the marine environment are to be subject to these guidelines. There are 13 screening criteria that are used for the selection of chemicals. These selection criteria include: identifying the chemical and its proposed use pattern, determining if it already is


approved for use in Canada and determining if it appears on international listings that have already evaluated the toxicity of chemicals for offshore uses. If further information is required, toxicity testing and risk analysis may be required.

The current (1996) OWTG describe minimum standards for the treatment and/or disposal of wastes associated with routine operations of drilling and production installations offshore Canada. The OWTG were developed during a period when synthetic based fluids were being introduced. The guidelines are therefore more explicit concerning the use and management of oil-based and water-based fluids. For drilling muds, the OWTG indicate that, when possible, WBM and SBM use is preferred over OBM use. When OBMs are approved, the OWTG require the aromatic content to be 5% or less and indicate that they should be non-acutely toxic. Whole SBMs and OBMs can not be discharged. Whereas spent and excess WBMs may be discharged overboard without treatment. For cuttings disposal, the OWTG recommend that operators consider re-injection. However, where re-injection is not technically or economically feasible, the OWTG permit on-site discharge of OBM cuttings, with an oil concentration of 15g/100 g or less of dry solids. Drill cuttings, which use diesel or other highly aromatic OBMs, can not be discharged overboard. The OWTG indicate that operators should evaluate new technologies and procedures on an ongoing basis to further reduce the amount of oil discharged on drill solids. Finally, the OWTG describe the requirement of operators to design and implement EEM and ECM monitoring programs for production operations. The results of these programs are to be used by regulatory authorities (in consultation with industry and other interested parties) to determine the continued adequacy of the waste treatment and disposal technologies and procedures employed at the drill sites.

There have been several developments both in Nova Scotia and Newfoundland since 1996, the time of implementation of these guidelines. As part of the Terra Nova Project assessment process in 1997, it was recommended that the CNOPB undertake a review of the current OWTG with regard to the adequacy of discharge regulation. To carry forward that recommendation the C-NOPB chairs and leads the review of the OWTG with the participation of the National Energy Board, the C-NSOPB, industry, other federal agencies, and members of the public.

Regulatory initiatives separate from those in Newfoundland were developed in Nova Scotia. In Condition 21 of the 1997 Development Plan Decision Report for the Sable Offshore Energy Project the C-NSOPB set a discharge limit of 1% LTMO by weight on cuttings which needed to be met as of December 31, 1999. This limit was later extended to include SBMs, and to include all hydrocarbon based drilling operations under the jurisdiction of the C-NSOPB, not just the Sable project.


TABLE OF CONTENTS

Page No.

REPORT SUMMARY i

1 INTRODUCTION 11.1 Background 21.2 Overall Regulatory Inputs 4

2 DRILLING TECHNOLOGY OVERVIEW 62.1 Drilling Rig 7

2.1.1 Function 72.1.2 Sources of Pollution 82.1.3 Limitations and Developments 92.1.4 Measuring Performance and Impacts 92.1.5 Factors Affecting Use of Technology 102.1.6 Global Experiences 10

2.2 Bits, Drillstring, and Casing 102.2.1 Function and Sources of Pollution 102.2.2 Limitations and Developments 132.2.3 Factors Affecting Use of the Technology 132.2.4 Global Experience 13

2.3 Drilling Muds 142.3.1 Function and Sources of Discharges 142.3.2 Aqueous-Based Drilling Muds 152.3.3 Non-Aqueous-Based Muds (NAF) 172.3.4 Limitations and Developments (aqueous-based systems) 192.3.5 Limitations and Developments (Non-Aqueous-Based Systems) 212.3.6 Factors Affecting the use of Technology 24

2.3.6.1 Technical Requirements 242.3.6.2 Economic Considerations 252.3.6.3 Environmental Considerations 252.3.6.4 Theoretical Example 26

2.3.7 Global Experience 262.3.8 Experiences With Non-Aqueous Drilling Muds on Canadian East

Coast 262.3.8.1 Hibernia Experience 282.3.8.2 Jeanne D’Arc Basin (JBO) Experience 292.3.8.3 SOEI Experience 292.3.8.4 Terra Nova Experience 29

2.4 Solids Control 302.4.1 Function 302.4.2 Sources of Pollution 352.4.3 Limitations and Developments 352.4.4 Measurement of Performance and Impacts on Discharges 362.4.5 Factors Affecting Use of Technology 372.4.6 Global Experiences 41


3 DRILLING WASTE MANAGEMENT TECHNOLOGIES 433.1 Offshore Discharge 44

3.1.1 Function and Sources of Pollution 443.1.2 Limitations and Developments 443.1.3 Measurement of Performance and Impacts 453.1.4 Factors Affecting Use of Technology 453.1.5 Global Experience 45

3.2 On-Site Injection/Annular Disposal – Cuttings Re-Injection 463.2.1 Function and Sources of Pollution 463.2.2 Limitations and Developments 483.2.3 Measurement of Performance and Impacts 493.2.4 Factors Affecting Use of Technology 503.2.5 Global Experience 50

3.3 Marine Transport and Onshore Disposal 523.3.1 Marine Transport 52

3.3.1.1 Function and Sources of Pollution 523.3.1.2 Limitations and Developments 533.3.1.3 Factors Affecting Use of the Technology 543.3.1.4 Global Experience 54

3.3.2 Landfill Disposal 543.3.2.1 Function and Sources of Pollution 543.3.2.2 Limitations and Developments 553.3.2.3 Management of Performance and Impacts 563.3.2.4 Factors Affecting Use of the Technology 563.3.2.5 Global Experience 56

3.3.3 Biodegradation Technologies 573.3.4 Land Treatment 57

3.3.4.1 Function and Sources of Pollution 573.3.4.2 Limitations and Developments 583.3.4.3 Measurements of Performance and Impacts 593.3.4.4 Factors Affecting Use of Technology 593.3.4.5 Global Experience 60

3.3.5 Composting 603.3.5.1 Function and Sources of Pollution 603.3.5.2 Limitations and Developments 613.3.5.3 Measurements of Performance and Impacts 613.3.5.4 Factors Affecting Use of Technology 623.3.5.5 Global Experience 62

3.3.6 Stabilization/Solidification 623.3.6.1 Function and Sources of Pollution 623.3.6.2 Limitations and Developments 633.3.6.3 Assessment of Technology Performance and Impacts 633.3.6.4 Factors Affecting Use of Technology 643.3.6.5 Global Experience 64

3.4 Thermal Treatment Technologies 653.4.1 Thermal Desorption 65

3.4.1.1 Function and Sources of Pollution 65


3.4.1.2 Limitations and Developments 653.4.1.3 Measurements of Performance and Impacts 663.4.1.4 Factors Affecting Use of Technology 663.4.1.5 Global Experience 67

3.4.2 Incineration 673.4.2.1 Function and Sources of Pollution 673.4.2.2 Limitations and Developments 673.4.2.3 Measurement Performance and Impacts 683.4.2.4 Factors Affecting Use of Technology 683.4.2.5 Global Experience 68

3.4.3 Other Waste Management Technologies 69

4 ENVIRONMENTAL MANAGEMENT PROCEDURES AND TOOLS 704.1 Environmental Management Systems 724.2 Environmental Assessment 72

4.2.1 Computer Modelling of Drilling Discharges 734.3 Drilling Fluid Approval Process 754.4 Environmental Compliance Monitoring 764.5 Environmental Effects Monitoring 774.6 Environmental Issues 78

4.6.1 Summary of Specific SBM Environmental Issues 794.7 Evaluation Tools 82

4.7.1 Sediment Quality 834.7.1.1 Physical and Chemical Characteristics 834.7.1.2 Benthic Community Structure 844.7.1.3 Toxicity 844.7.1.4 Benthic Boundary Layer (BBL) 87

4.7.2 Biota Quality 884.7.2.1 Bioaccumulation and Body Burden 884.7.2.2 Taint 914.7.2.3 Biodegradation 914.7.2.4 Fish Health 97

4.7.3 Water Quality 984.7.4 Seabirds 98

5 LABORATORY STUDIES 1005.1 WBMs 100

5.1.1 Toxicity Studies 1015.1.2 Bioaccumulation 102

5.2 NAFs 1035.2.1 Toxicity Studies 1035.2.2 Bioaccumulation Studies 1055.2.3 Taint 1075.2.4 Biodegradation Studies 108

6 MODELLING AND FIELD STUDIES 1116.1 Physical Environment 112


6.1.1 Grand Banks 1126.1.2 Scotian Shelf 1126.1.3 Deepwater Eastern Canada 1126.1.4 Gulf of Mexico 1126.1.5 North Sea 112

6.2 WBMs 1126.2.1 WBM Dispersion Behavior and Modelling 1126.2.2 WBM Fate and Effects 1126.2.3 WBM Representative Field Studies 112

6.2.3.1 Mid-Atlantic 1126.2.3.2 North Sea 1126.2.3.3 California 1126.2.3.4 Gulf of Mexico 1126.2.3.5 Georges Bank 1126.2.3.6 Lower Cook Inlet Study 112

6.3 OBMs 1126.3.1 OBM Cuttings Discharge Modelling 1126.3.2 OBM Fate and Effects 1126.3.3 OBM Representative Field Studies 112

6.3.3.1 North Sea 1126.3.3.2 Australia 1126.3.3.3 Sable Island Bank 112

6.4 SBM 1126.4.1 SBM Cuttings Discharge Modelling 1126.4.2 SBM Fate and Effects 1126.4.3 Representative Field Studies 112

6.4.3.1 North Sea 1126.4.3.2 Gulf of Mexico 1126.4.3.3 Australia 1126.4.3.4 Sable Island Bank 1126.4.3.5 Hibernia EEM 112

6.5 Conclusion 112

7 REGULATORY REVIEW 1127.1 Historical Perspective 1127.2 Northeast Atlantic/North Sea 112

7.2.1 OSPAR Development of OBM, and SBM Regulatory Controls 1127.2.1.1 Regulation of Synthetic Drilling Fluids in the North Sea

1990 - 1999 1127.2.1.2 SEBA 1127.2.1.3 Future Direction of Discharge Management 112

7.2.2 Present OSPAR Requirements and Implementation 1127.2.2.1 Introduction of a Harmonized Mandatory Control Scheme

(HMCS) 1127.2.2.2 Chemical Hazard Assessment and Risk Management (CHARM)

1127.2.3 Norway 1127.2.4 United Kingdom 112


7.2.4.1 Offshore Chemical Notification Scheme (OCNS) 1127.3 United States 112

7.3.1 Framework 1127.3.2 Regulatory Development 112

7.4 Western Australia 1127.5 Canada 112

7.5.1 Canadian East Coast Regulatory Framework 1127.5.1.1 Cooperative Regulatory Arrangements 1127.5.1.2 Newfoundland Regulatory Initiatives in Drill Cuttings/Fluid

Management 1127.5.1.3 Nova Scotia Regulatory Initiatives in Drill Cuttings/Fluid

Management 1127.5.2 Canada’s Current Offshore Waste Treatment Guidelines:

An Overview 1127.5.3 Offshore Chemical Selection Guidelines 1127.5.4 Environmental Compliance Monitoring 1127.5.5 Emerging Regulatory Issues and Requirements 112

8 REFERENCES 1128.1 Personal Communications 1128.2 Literature Cited 112

LIST OF APPENDICES

Appendix A Table of AcronymsAppendix B Hibernia EEM Monitoring VariablesAppendix C Physical and Chemical Parameters Analyzed for Hibernia EEM ProgramAppendix D Terra Nova Monitoring VariablesAppendix E Physical and Chemical Parameters for Terra Nova EEM ProgramAppendix F Sable Island Sediment Chemistry ParametersAppendix G Sable Island Taint and Body Burden ParametersAppendix H Ecotoxicological Data of Various Synthetic Based MudsAppendix I Country-Specific Requirements for Discharge of Drilling Muds and

CuttingsAppendix J OSPAR Decision 2000/3 on the Use of Organic-Phase Drilling Fluids and

Discharge of OPF Contaminated CuttingsAppendix K Hibernia ECM Monitoring VariablesAppendix L Terra Nova Monitoring Variables – Development DrillingAppendix M SOEI Monitoring Variables

LIST OF FIGURESPage No.

Figure 2.1 Required Resources and Byproducts of Drilling Operations. 6Figure 2.2 Semi-Submersible Drilling Rig 8Figure 2.3 Bit and Drillstring 11


Figure 2.4 Drillstring Components 12Figure 2.5 Mud Circulating System 14Figure 2.6 Size Classification of Drilling Solids and Effective Removal Ranges

of Solids Control Equipment 31Figure 2.7 Change in Drill Solid Surface Area Resulting From Degradation 32Figure 2.8 Adjustable Linear Shaker. 33Figure 2.9 Hydrocyclone Applications 34Figure 2.10 Cross-Section of a Decanting Centrifuge 34Figure 2.11 Relationship of SRE and Dilution Volumes Required 37Figure 6.1 Locations of three oil fields on the Grand Banks; Hibernia is drilling

and producing; Terra Nova is in the development stage with drillingonly ongoing; White Rose is in the permit stage with several delineationwells to date 112

Figure 6.2 Scotian Shelf Production Activity 112Figure 6.3 Plot Showing the Dilution Ratios Observed in Various Field Studies 112Figure 7.1 OCSG Process 112

LIST OF TABLESPage No.

Table 2.1 Typical Properties of Various Non-Aqueous Base Muds 23Table 2.2 Examples of Technically Demanding Hibernia Wells 28Table 2.3 ROP of comparable Hibernia Wells using WB and SB Mud Systems 29Table 2.4 Impact of Mud Type and Solids Removal Efficiency on Waste Volume

(based on drilling of 2500 m of 311mm hole) 39Table 2.5 Hibernia Wells 311 mm Interval: Volumes of SBM and WBM used per

Meter Drilled 40Table 1.6 SBM Cuttings Volume and Discharge Estimates for SOEI Wells 42Table 3.1 Framework of Parameters for Evaluating Disposal Options 43Table 3.2 Advantages (+) and Disadvantages (-) of Offshore Discharge Technology

44Table 3.3 Advantages (+) and Disadvantages (-) of Cuttings Re-injection 49Table 3.4 Advantages (+) and Disadvantages (-) of Marine Transport 53Table 3.5 Advantages (+) and Disadvantages (-) of Landfill Disposal 55Table 3.6 Advantages (+) and Disadvantages (-) of Land Treatment Technology 59Table 3.7 Advantages (+) and Disadvantages (-) of Composting Technology 61Table 3.8 Advantages (+) and Disadvantages (-) of Stabilization/Solidification 63Table 3.9 Advantages (+) and Disadvantages (-) of Thermal Desorption 66Table 3.10 Advantages (+) and Disadvantages (-) of Incineration 68Table 4.1 EEM Monitoring Parameters Associated with Canadian EEM Programs 78Table 4.2 Toxicity Rating System (GESAMP, 1997 as cited in Patin, 1999). 85Table 4.3 Outline of Typical Toxicity Analyses 86Table 4.4 Bioaccumulation Methods Summary 90Table 4.5 Summary of Test Procedures Used in the Biodegradation Testing

of Synthetic-Based Drilling Fluids (from USEPA, 1999b) 95Table 5.1 Toxicity Test Results of Five Drilling Muds (from Harris, 1998) 104Table 5.2 Log Pow Values and BCF-values Available for Base Fluids in SBM Drilling


Muds (from Vik et al., 1996) 106Table 5.3 Biodegradation Test Results for SBMs and mineral oils (from Vik et al.,

1996) 109Table 6.1 Physical Setting in Three Oil Producing Regions 112Table 6.2 The Zones Of Effect Of OBM Cuttings Discharge 112Table 7.1 Summary of Originally Proposed and April 2000 Notice on Limitations for

SBM Discharges (USEPA, 1999a; USEPA, 2000) 112Table 7.2 Summary of September 1996 Offshore Waste Treatment Guidelines 112

INTRODUCTION1

This document has been prepared by CAPP (the Canadian Association of Petroleum Producers) to aid in the review of the Offshore Waste Treatment Guidelines (OWTG; NEB et al., 1996). The guideline review group includes agencies that regulate offshore oil and gas exploration and production and other stakeholders. Of particular concern is drilling waste management and the disposal of synthetic-based mud (SBM) cuttings. The Canada-Newfoundland Offshore Petroleum Board (C-NOPB), the Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) and the National Energy Board (NEB) jointly published the OWTG in 1996 and are aiming to publish revised guidelines in 2001. The current OWTG describe minimum standards for the treatment and/or disposal of wastes associated with the routine operations of drilling and production installations offshore Canada. Further, the guidelines describe requirements for operators to design and implement environmental effect monitoring (EEM) and environmental compliance monitoring (ECM) programs. See Appendix A for a Table of Acronyms.

The three Boards have indicated that the review will be guided by the “Precautionary Principle,” specifically Principle 15 of the Rio Declaration on Environment and Development. The Precautionary Principle, in essence, stipulates that where there are threats of serious or irreversible environmental damage, lack of full scientific certainty shall not be used as a reason for postponing cost-effective measures to prevent environmental degradation. In the review process, consideration will be given to results of EEM programs conducted on east coast Canada, and other jurisdictions as appropriate, discharge standards in effect or proposed in other jurisdictions and the underlying technical support of these, the degree to which Canadian discharge scenarios represent threats to Canadian marine environments, as well as current state-of-the-art technologies in minimization, treatment and disposal of offshore drilling and production wastes.

Drilling wastes are an inevitable by-product of oil exploration and development. Technological advances, health and safety concerns and environmental effects awareness have resulted in changes in regulatory requirements and operating regimes for the oil industry. This document reviews current documentation and experience on drilling technologies, environmental receptors, monitoring programs, life-cycle analysis and the current regulatory frameworks in selected operating environments. More specifically, this review document focuses on the composition, management and disposal of drilling waste from offshore drilling operations.

Subsequent sections of the document provide the following:

drilling technology overview for rigs, drillstring, and circulation system (Chapter 2);•


drilling waste management technologies (Chapter 3);•environmental management procedures and tools (Chapter 4);•laboratory studies on drilling muds (Chapter 5);•modelling and field studies on fate and effects of drilling discharges (Chapter 6); and•review of global drilling waste management regulations (Chapter 7).•

Background1.1

Drilling muds are a complex mixture of clays or other colloidal agents, materials that add weight, and chemicals. Their properties require monitoring and constant adjustment to fulfill their primary functions, which include (Lepine, 1984):

carrying cuttings to the surface;•controlling pressures occurring in formations; and•providing a protective coating around the borehole to preserve the hole and protect •the potential oil and gas reservoirs.

Drilling muds are subject to continual contamination by formation fluids and solids from the geological formations drilled. On the Canadian east coast, the disposal of these muds and drill cuttings follow the most recent OWTG (NEB et al., 1996), which supersede the Waste Treatment Guidelines (Canada Oil and Gas Lands Administration and Canada-Newfoundland Offshore Petroleum Board, 1989) and the Guidelines for the Use of Oil-Based Drilling Muds (Canada Oil and Gas Lands Administration, 1993). The current OWTG are to undergo a review and revision, with a scheduled release of revised guidelines in 2001.

The current OWTG describe minimum standards for the treatment and/or disposal of wastes associated with routine operations of drilling and production installations offshore Canada. These wastes include produced water, drilling muds, drill solids, storage displacement water, bilge and ballast water, deck drainage, produced sand, well treatment muds, cooling water, desalination brine, sanitary and food wastes, water for testing fire control systems, other wastes and residues, unused substances and other substances. The focus of this review document is drilling muds and drill solids, specifically, the muds that are found as residue on drill solids (cuttings).

For drilling muds, the OWTG indicate that water-based muds (WBMs) and synthetic-based muds (SBMs) use is preferred over oil-based muds (OBMs), if possible. OBM use requires specific approval and is limited to specific portions of the well. When OBMs are approved for use, the OWTG require the aromatic hydrocarbon content to be 5% or less and indicate that the base muds should be non-acutely toxic as measured by protocols


developed by Environment Canada (1985). The OWTG indicate that OBMs and SBMs remaining from mud change-overs or drilling program completion should be recovered and recycled, or disposed of in an approved manner onshore. Spent and excess WBMs may be discharged without treatment.

The OWTG permit WBMs and SBM cuttings to be discharged overboard without treatment. For OBM drill solids (cuttings) disposal, the OWTG recommend that the operator consider re-injection. Where re-injection is not technically or economically feasible, the OWTG permit on-site discharge of treated OBMs with an oil concentration (from all sources) reduced to 15 g/100 g or less of dry solids as determined by protocols for sampling and analysis (API, 1991). Cuttings from OBMs, which use diesel or similar highly aromatic oils as the continuous phase of the mud, can not be discharged overboard. The OWTG indicate that operators should evaluate new technologies and procedures on an ongoing basis to further reduce the amount of oil retained on drill solids.

Present application of the OWTG varies between Newfoundland and Nova Scotia. In the former, overboard discharge of SBM cuttings are allowed, assuming that the amount of SBM retained on the cuttings is as low a level as feasible with existing technology. In the latter, overboard discharge of SBM cuttings is allowed subject to an SBM on cutting retention limit of 1%. Due to the inability of present cuttings cleaning technology to meet this limit, SBM cuttings from offshore Nova Scotia operations are currently shipped to shore for disposal. Further details on regulatory requirements are discussed in Section 7.

The OWTG also require operators to design and implement EEM and ECM programs for production operations. The results of these programs are used by regulatory authorities (in consultation with industry and other interested parties) to determine the continued adequacy of waste treatment and disposal technologies and procedures employed at drill sites.

The face of offshore drilling technology is quickly changing in Canada as in the rest of the world - novel down-hole drilling equipment, extended reach drilling, multiple wells from single drill locations, development of environmentally friendly SBFs, etc. - all with the aim of ensuring cost effective development of remote and challenging oil and gas reserves. In addition, on Canada's east coast (east coast Newfoundland and Nova Scotia, in particular) drilling is moving from the shallower Banks (water depths of 20-150m) to the deeper Continental slopes (water depths of 200 m to in excess of 1000m).

Development of resources in these new locations, generally further from shore (> 200 nautical miles) and with harsher environmental conditions than those on the Banks, pose technical, logistical, and economic challenges. These challenges require innovative and


cost effective solutions to ensure continued access to these remote reserves of oil and gas. The approach of guidelines such as the OWTG are very important in ensuring careful weighing of all factors to promote flexibility and a cost effective balance between continued operations and environmental quality. Use of new approaches in the evaluation of cuttings management options (i.e., life-cycle approach) significantly advances the selection of the most environmentally sound cuttings management option.

Overall Regulatory Inputs1.2

Discharges, particularly of drilling muds and cuttings from offshore drilling operations, are heavily regulated and closely monitored in most geographic areas including the North Sea, offshore Australia, the United States Outer Continental Shelf, and offshore Canada. The regulatory models in each jurisdiction are unique and reflect the offshore operating history and experience, the size and age of the industry, and the characteristics and sensitivities of their marine environments. Increasing public awareness and concern about the real, and perceived, environmental consequences of offshore exploration and production activities have driven the development of increasingly stringent environmental management requirements and regulations. Sustainable development and the precautionary principle are major drivers behind the regulatory response to these pressures. Over the last 20 years, the need for continuous operational improvement in offshore exploratory and development drilling operations has driven the evolution of new technologies to meet environmental challenges. Increasingly, the regulatory requirements have driven both regulators and industry to develop more sophisticated full life-cycle management systems that recognize not only the operational and financial considerations, but also the full range of environmental consequences, at every stage of the process.

SBMs have borne the regulatory legacy of the effects of OBMs used in the 1970s and 1980s, particularly in the North Sea where these muds were commonly used and their associated cuttings discharged. Regulators have been cautious to approve the discharge of SBM cuttings despite the fact that science seems to indicate that the environmental effects associated with SBM cuttings are more restricted in area, less toxic, and last for a shorter period of time than those associated with OBMs. The SBM family of drilling muds and cuttings have been the subject of extensive testing and examination by regulators in a wide range of environments around the world to determine the most appropriate management systems for their areas of jurisdiction. The evolution of the regulations is requiring the oil industry to adopt more rigorous drilling mud management systems and to undertake more extensive research, development, and monitoring programs to assess the environmental effects associated with the discharge of cuttings before approvals are received.


In light of the need to address environmental factors and the development of new technologies, collaborative relationships between regulators and industry have been formed in a number of jurisdictions. Areas such as Australia, Canada and the United States, which are governed by their own national legislation and are signatories to regional marine environmental management conventions, have been key in the development of a regulatory system that has established rigorous standards to which all operators are expected to conform.


DRILLING TECHNOLOGY OVERVIEW2

The use and management of advanced technology is at the core of modern drilling practices. Decision-makers are faced with the responsibility of selecting and employing an array of tools, products and techniques to optimize efficiency, safety and environmental compliance. Often the tools are linked together and the technologies are interdependent. Therefore, prior to discussing the potential environmental effects of discharges from a drilling operation, it is important to review the tools and products used to drill an offshore well.

As illustrated in Figure 2.1, with the assortment of equipment, materials and personnel required to drill an oil or gas well, generated wastes are inevitable. The characteristics and volume of these wastes depend on the materials/equipment that are selected for a given application and how efficiently they are used. Currently, the management and minimization of waste and discharges follows a three-pronged approach:

adhering to good pollution prevention practices;•maximizing recycling; and•treating waste products prior to disposal to minimize potential environmental impacts.•

Figure 1 Required Resources and Byproducts of Drilling Operations.

Air Discharges

Water Discharges

Solid Waste

Oil and Gas that can be used for energy

Equipment

Fuel

Personnel

Supplies

The two primary phases of drilling operations conducted as part of oil and gas extraction process are exploration and development. Exploratory drilling involves drilling wells to determine the presence of hydrocarbons. Exploration activities are usually of short duration, and involve a relatively small number of wells. Once hydrocarbons are discovered additional appraisal or delineation wells are drilled to determine the size of the hydrocarbon accumulation. When the size of hydrocarbon accumulation is sufficient for commercial development, field development is started. Development wells for production are drilled in this phase. Production drilling may span over a duration of a number of years. Although the rigs used for each type of drilling may differ, the drilling process is generally similar.

To better understand the generation of waste from a drilling operation, it is important to understand the basics of the rotary drilling process employed to drill the vast majority of oil and gas wells. This process can be broken into three sections: 1) the drilling rig; 2) the drillstring (including bits) and casing; and 3) the circulating system. This section will briefly review these components, with an overall focus on understanding their limitations, measuring performance, and pollution prevention. Correspondingly, the various drilling mud and solid control systems used in this process will be examined, with a similar focus on limitations, performance measurement and pollution prevention, along with the factors to consider in using and managing the technology, and global experiences.

Drilling Rig2.1

Function2.1.1

Since offshore drilling typically is conducted in remote locations, the operation itself is basically a self-contained unit, with the drilling rig providing support for the other components used to drill a well. Offshore, drilling operations are performed either from jack-up drilling rigs, which are stationed on the seabed; floating units which includes semi-submersibles (Figure 2.2) and drillships and permanent production platforms.

The rig structure provides a stable and safe area for the personnel carrying out the drilling operation. Large fuel-burning generators provide electricity to power the draw works (winches and sheaves) that lift the drillstring. The same generators also power all associated mechanical systems and pumps required for circulating drilling mud, turning the rotary table, and providing power to the living quarters.

Typically, 100-130 personnel are stationed on a floating drilling unit or jackup. Drilling and production platforms, such as Hibernia, normally have approximately 200 personnel on board.


The type of rig also dictates the positioning of the wellheads and Christmas trees, which are a collection of valves through which the well is produced and tested. On platform and jack-up rigs, the wellheads and Christmas trees are located above water level, whereas on floating rigs they are located on the seafloor. At Terra Nova, the wellheads and Christmas trees are installed approximately 10 m into the seabed at the bottom of “glory holes” to prevent iceberg interference with equipment. The location of these two components can impact the ability to apply certain techniques for minimizing environmental impact, particularly cuttings re-injection (CRI). Such procedures are more difficult on a floating rig than on a stationary platform, and will be discussed in more detail in Section 3.2.

Sources of Pollution2.1.2

Regardless of the type, drilling rigs intrinsically are high-horsepower operations where the sizeable generators used for power become principal sources of air emissions. The generators used on jackups and floating drilling units are powered with diesel, with fuel consumption ranging up to 15-35 m3 per day. Those used on platforms use either diesel or produced gas, both of which result in air emissions.

Figure 2 Semi-Submersible Drilling Rig


Presently, all of the three types of drilling rigs are used on the east coast of Canada. Hibernia utilizes two platform rigs, Terra Nova and Jeanne D’Arc Basin Operations (JBO) both use semi-submersibles, while PanCanadian and Sable Offshore Energy Inc. (SOEI) use jackups. The power requirements for the two rigs on Hibernia are approximately seven megawatts, translating to approximately 38 tonnes of fuel consumed per day. The semi-submersible Global Marine Grand Banks used in JBO consumes in the order of 20 tonnes of diesel per day. The jackups used on SOEI consume an average of about 15 tonnes of diesel fuel per day, while the semi-submersible that is now being used by Terra Nova consumes approximately 25 tonnes of diesel every day it is drilling.

Examples of solid wastes generated from operations include used oil, spent solvents used for cleaning, used parts, sewage and food wastes from the living quarters and other support functions, used pallets, and other trash that is normally compacted and sent back onshore for proper disposal. Water discharges include grey and black water, ballast water, bilge water, deck and machinery space drainage water, and cooling water. Some types of drilling muds and cuttings may also be discharged. The size of the rig also impacts the daily level of discharges.

Limitations and Developments2.1.3

The limitations of a drilling rig are driven by its ability to operate in a maximum water depth and pull maximum weight with its draw works. In the pioneer days of offshore drilling, rigs were designed to operate in only 30–100 m of water. Bottom supported units (jackups and platform rigs) are typically used when drilling in shallow waters (jackups can be used in water depths up to 137 m). With the steady advances in technology, floating drilling units have now evolved to allow drilling in water depths as great as 3,600 m, with well depths of more than 10,000 m. There may be space and weight limitations, particularly on floating drilling units, which will influence the potential for installation of additional equipment (i.e., cuttings dryers, reinjection equipment, and cuttings storage units). Likewise, specialised drilling platforms have allowed drilling to progress in particularly harsh environments, such as those found offshore Newfoundland and Nova Scotia. Technical advances in drilling tools have fostered the advent of high-angle, extended-reach, horizontal and other well configurations that facilitate faster, more efficient and more productive drilling.

More recent developments and construction efforts for drilling rigs have focused on meeting the demand for deep water drilling. Deep water drilling rigs will be needed to explore the many new areas off of the east coast of Canada. The extreme demands of deepwater drilling make these rigs the most expensive to build and operate.


Measuring Performance and Impacts2.1.4 The efficiency of the drilling rig impacts the nature and volume of discharges. The first priority of a drilling rig is to operate in a safe and reliable manner. In the best case, the equipment is maintained in peak operating condition, thereby reducing emissions from the generators by minimizing unproductive-time that can extend the operations and the rate of emissions. Poorly maintained equipment can fail at critical times, resulting in long delays that extend the time required to drill a well.

As the drilling operation progresses, the overall effectiveness of the drilling rig is monitored using key performance indicators that include:

cost per meter drilled;•cost per day on location;•trouble time as a percent of total time on location;•ability to reach the drilling target;•well productivity; •horsepower and fuel consumption; and•Environmental Health and Safety (EH&S) performance.•

Factors Affecting Use of Technology2.1.5

As mentioned, a drilling rig is selected for a particular application based primarily on its ability to operate in the targeted water depth and the capacity of its draw works and derrick to support the weight of the drillstring and casing required to reach the desired well depth. Additional factors include the availability of the rig on the global market, its age, the reputation of the drilling contractor and the condition of the on-board equipment. Adjustments to maintenance schedules and specific pieces of equipment are continually made to maximize efficiency.

Global Experiences2.1.6

Excluding platform rigs, 664 offshore drilling units comprise the global fleet, with 145 of those suited for deepwater drilling (>610 m). At the time of writing, the daily operational costs of these drilling rigs range from $59,000–$300,000.

Bits, Drillstring, and Casing2.2

Function and Sources of Pollution2.2.1


The bit, which is attached to the drillstring (pipe) (Figures 2.3 and 2.4), cuts the formation rock into drilled cuttings, thereby creating the wellbore. The diameter of the bit is larger than that of the drillstring, which leaves a space between the pipe and the wellbore wall called the annulus. Drilling mud is circulated inside the drill pipe and through small jets or holes in the bit. The velocity of the mud through the bit jets, in tandem with the viscosity of the mud, flushes drilled cuttings away from the bit and transports them through the annulus to the surface. At predetermined intervals, steel casing, which is slightly smaller than the hole diameter, is cemented into the open hole. As the well deepens, the casing telescopes into smaller and smaller diameters. Once the final casing string is cemented, production tubing is installed to serve as a conduit for the produced oil and gas.

Traditionally, the bit revolved via the rotary table, which rotated the drill pipe at the surface while transferring torque to the bit through the drillstring. Today, in addition to the drill pipe, specialized tools are attached near the bottom of the drillstring. Advances in these speciality tools have transformed modern drilling practices very significantly.

Figure 3 Bit and Drillstring


Figure 4 Drillstring Components


0

Today, advanced directional tools allow exact bottom hole positions to be reported by way of hydraulic signals in the drillstring. In addition, downhole mud motors, which are large hydraulic-powered turbines at the lower end of the drillstring, allow the bit to be turned without rotating the drillstring. The combination of hydraulic mud motors, downhole directional tools and three-dimensional seismic data allows drilling operations to penetrate very precise targets and greatly reduce the number of wells required to produce a field. This combination of technologies has also led to extended-reach wells that drill horizontally to reach targets miles away from the platform or drill horizontally through a production zone. These innovations have resulted in optimum production and efficiencies, hence the need for fewer platforms and fewer wells to develop and produce a field. Where in the past a field may have required two or three platforms and up to 150 development wells, today that same field may be developed with one platform and only 50 wells. Employing these advanced techniques can alter field development economics significantly. Extended reach and horizontal drilling techniques have made many fields economically viable, where in the past they would not have been developed because of their exorbitant


development cost.

The extraordinary advancements in technology and the resulting decrease in the number of wells and platforms required have had a correspondingly positive impact on the generation of drilling wastes. On average, today’s field development operations generate one-third of the drilling wastes of those earlier projects. Likewise, improved efficiencies of the drill bit and other downhole tools have helped to reduce dramatically the time required to drill a well and increase the size of the cuttings brought to surface. As detailed in Section 2.3, larger drill cuttings are easier to remove from the drilling mud, which reduces both the dilution volume and cuttings retention, resulting in a lower volume of waste.


As with all technologies, drill bits, downhole tools, and casing have inherent limitations that can result in replacement or well control problems, respectively. Drill bits eventually wear down or become dull, while other downhole tools occasionally fail. However, more times than not, both the drillstring and bits are limited by the performance of the drilling muds. The interrelationship between the drillstring, lubricity, hole stability, and drilling muds is discussed in Section 2.3.

Factors Affecting Use of the Technology2.2.3

The bit, downhole tools, and casing program are carefully designed to optimize efficiency, taking into consideration the formations to be drilled, the cost of the drilling rig, pore pressure profiles and other related factors. As drilling in an area progresses, the lessons learned are transferred to the next well in an effort to continually improve overall efficiencies.

Global Experience2.2.4

As with most modern offshore operations, extensive use of mud motors, directional drilling and improved drilling bits have been used to maximize efficiencies worldwide. The advanced drilling technology available today is used throughout Canada’s east coast. Locally, experiences associated with maximum achievable extended reach drilling is detailed in Section 2.3.8.

Drilling Muds2.3

Function and Sources of Discharges2.3.1


Drilling muds (muds), solids control equipment, and the circulating system constitute a critical and interrelated part of the drilling operation. Without drilling muds, virtually no wells could be drilled (except shallow, low-pressure wells). Basically, drilling muds are liquids that are pumped at high pressures and circulated through the drill pipe and bit and returned to the surface through the annulus between the drillpipe and casing. The mud is passed through mechanical solids control equipment to remove the solids, chemically treated to adjust physical and chemical properties, and eventually re-circulated into the well through the drillpipe (Figure 2.5).

Figure 5 Mud Circulating System

The drilling mud has a host of critical functions, including controlling formation pressures, removing cuttings from the well, sealing permeable formations, and maintaining wellbore stability until casing is cemented in the wellbore. Meanwhile, solids control equipment


separates drill solids from the drilling mud, thereby allowing it to be re-circulated down the drill pipe. The pumps drive the circulating system with sufficient pressure and volume to remove the cuttings away from the bit and lift them to the surface. Additional functions of drilling muds include: minimizing damage to the producing formations (reservoirs), cooling and lubricating the bit and drillstring assembly, preventing the formation of gas hydrates in well control equipment, transmitting hydraulic energy to the drilling tools and bits, ensuring that the formations can be evaluated with logging equipment, controlling corrosion and facilitate cementing of casings.

Drilling mud systems must possess a number of key properties to perform their critical functions, including:

sufficient density to control subsurface pressure;•viscosity adequate to suspend cuttings and eventually remove them from the wellbore;•satisfactory filtration properties that allow the drilling mud to build a thin layer of •solids onto the permeable formations, thereby creating a seal against the invasion of muds and solids; andenough lubricity to rotate the drillstring and the bit.•

The main component of a drilling mud system is the base mud. Depending on the lithology, environment, application and well objectives, drilling mud systems designed to achieve these key properties are either water-based (aqueous) or non-aqueous emulsion systems.

Aqueous-Based Drilling Muds2.3.2

In the early years of the petroleum exploration industry, water-based drilling muds were used exclusively. Those early systems were simply mixtures of water and soil that were found to extend the ability to drill deeper wells. Today, water-based drilling muds use water or brine as the continuous or external phase, with the critical functions (density, viscosity, filtration, and lubricity) achieved with the addition of various materials. Owing to the combination of products and salts used in the initial formulation, water-based drilling muds vary widely. The selection of a particular system is dictated by the characteristics of the formations being drilled.

Density to provide hydrostatic pressure is provided by adding a high-density mineral, such as barite (barium sulfate), hematite and other iron ores. Depending on the well depth, drilling mud specific gravity (SG) as high as 2.0-2.3 SG may be required to control subsurface pressures and allow for safe drilling operations. Without these high-density additives, subsurface pressures cannot be controlled and the resulting blowouts could


cause loss of life and generate large oil spills.

Viscosifiers, such as the commonly used bentonite (sodium montmorillonite) clay, keep weighting agents suspended. Without sufficient viscosity, the barite will not stay suspended in the drilling mud, and the cuttings cannot be removed from the wellbore. Both of these situations can lead to severe drilling problems.

Bentonite has a high affinity for water and when dispersed in fresh water, swells as much as 20 times its dry state. High molecular-weight, water-soluble polymers have been substituted for clays in some situations and are effective at concentrations of 0.1-0.5 % in the drilling mud.

In addition to viscosifiers, chemical thinners are often required to lower the viscosity and maintain the required flow properties. In WBMs it is common for drill cuttings to hydrate and, thus, result in excessive viscosity of the drilling mud. Drilling muds that become too viscous require more pump pressure to circulate, thus increasing the hydraulic pressure on the formation. In some situations, the combination of drilling mud density and hydraulic circulating pressure can exceed the fracture gradient of the formation, propagating the loss of whole mud. Dispersing agents, which typically are anionic polymers (highly negatively charged) with a molecular weight under 50,000, or lignosulfonates, are used to control mud viscosity in water-based drilling muds.

Filtration control is necessary to seal off the permeable formations. The hydrostatic pressure on the drilling mud column pushes the filtrate (liquid phase of mud) into permeable subsurface formations and deposits a thin filter cake on the borehole wall. If the deposition of the filter cake is not controlled, it can close off the borehole. Various mud-loss additives are capable of reducing filtrate loss and minimizing filtercake build-up. The most common filtration control products are bentonite clays and polymers, usually comprising carboxymethyl cellulose or starches.

Maintaining wellbore stability until the casing is cemented in place is achieved by a combination of drilling mud properties. The density of the mud provides the necessary hydrostatic pressure, while chemical stability is obtained with specific additives that seal the permeable formations (i.e., sandstones) and prevent hydration of the hydrophilic shales comprising the sides of the wellbore. Most wells encounter shale formations, which possess a high content of clay, prior to reaching hydrocarbon production zones. In contact with water, the clays tend to swell (called hydration), dispersing shale particles into the hole and drilling mud. This hydration of clays can lead to sloughing of whole chunks of shale into the wellbore, which poses a multitude of mechanical problems. Viscosity naturally increases when shale clays disperse into the drilling mud, mandating dilution or


the use of thinners. Shale hydration can be addressed with additives designed to either ironically inhibit swelling or physically encapsulate the clays. However, these treatments are rarely totally effective.

Providing lubrication to the drill bit and drillstring is also critical to the success of the drilling operation. As the angle of the wellbore increases (drilling wells with a horizontal displacement), lubricity provided by the drilling mud becomes increasingly critical, since the degree of torque and drag that can be applied to the drillstring is limited. Common lubricants in WBMs include hydrocarbon compounds, polyglycols and even plastic or glass beads on occasion.

Many additives designed for water-based mud systems serve multiple functions and do not fit neatly into the aforementioned categories. They may include many speciality additives and commercial chemicals to control pH, corrosion, foaming problems, temperature stability, and other problems.

Non-Aqueous-Based Muds (NAF)2.3.3

Non-aqueous systems, which also provide essential drilling mud functions, use a non-water soluble base mud as the continuous phase with water (brine) emulsified and dispersed in the base mud. Non-aqueous drilling muds include diesel, mineral oils, low-toxicity mineral oils (LTMOs), and synthetic base muds. Early in the petroleum industry, diesel and crude oil were the basis of non-aqueous muds. Over the years, efforts to employ non-aqueous muds with less environmental impact intensified. First, there was the switch from diesel to mineral oils as the base mud, followed by the introduction of LTMOs with very low concentrations of PAHs, which are unsaturated and toxic cyclic compounds. The next generation saw the launch of synthetic fluids that possess virtually no PAHs and have a variety of specific chemistries designed to optimize drilling and environmental performance. Examples of SBMs include esters, ethers, acetals, paraffins, and olefins. These muds can be designed to exclude specific chemical constituents known to be toxic. In addition, the synthetic muds have little or no aromatic content, which also greatly reduces their toxicity. Specially treated paraffin compounds derived from pure feedstocks have also been included in this definition.

In selecting an SBM, one must consider cost, drilling performance and environment performance. These characteristics vary depending upon the particular chemistry of the synthetic base mud. For example, traditional esters exhibit high rates of biodegradation due to their chemical structure. However this same structure makes them susceptible to contamination. High cost, high viscosity, and temperature stability problems have made traditional esters a poor choice for deepwater and high temperature drilling.


Emulsifiers are used in non-aqueous muds to stabilize a water-in-oil emulsion. The continuous phase is the non-aqueous mud that is in contact with both the wellbore and solid particles. With this formulation, hydration of solids cannot take place, as the water is broken into small droplets and uniformly dispersed in the base mud. These droplets are suspended in the base mud with surfactants that act between the phases, preventing them from coalescing. In turn, the emulsified water droplets provide viscosity, and to a small extent, mud-loss control and wellbore stability. In contrast to early generation OBMs, SBMs use less toxic emulsifiers with the concentrations controlled at much lower levels through focus on material balance.

As with aqueous muds, high-density minerals, such as barite, provide sufficient density. Again, like water-based systems, high specific gravity solids are required to control subsurface pressure and allow safe drilling operation. The same density additives used in WBMs are used in their non-aqueous counterpart to increase mud density.

The emulsion of water droplets in the base mud produces primary viscosity in non-aqueous or invert emulsion systems. When more base mud is added, the distance between water droplets increases, which in turn decreases the mud viscosity. Likewise, the addition of more emulsifiers increases the emulsion stability and also decreases the viscosity. In addition to adjusting the ratio of base mud and water, the use of organophilic (oil-adhering) clays helps provide the necessary level of viscosity to the base mud.

Typically, the hydration of drill cuttings and the wellbore surface that occur in WBMs are used does not transpire in non-aqueous invert emulsions because the drill cuttings are exposed to the base mud and not water. Thus, thinners are not required for these systems. On the other hand, cuttings may not hydrate, but they can be ground mechanically into fine particles, which can build up to an unacceptable level in the mud system. When this occurs, the fine-solids mud system must be diluted to an acceptable range using additional base mud.

In these systems, the filtercake is actually formed by the invert emulsion. The base mud is pushed hydrostatically into the formation, which consequently will not cause the clay particles to hydrate.

As with a water-base system, in a non-aqueous system, maintaining a pre-cased stable wellbore is achieved by a combination of hydrostatic pressure, which is provided by the density of the mud, and chemical stability, which is accomplished by coating the solids around the well with base mud. When non-aqueous invert emulsion mud systems are used, clays in the wellbore will not hydrate and slough into the drilled hole, even if the


formation is exposed to the drilling mud for extended periods. Additionally, the combination of a thin filter cake and shale inhibition usually results in the drilling of an in-gauge hole (where the diameter of the hole is virtually the same as the diameter of a drill bit).

Furthermore, the inherent lubricity of an invert emulsion base mud sufficiently provides the lubrication that is especially critical in drilling high-angle wells, as explained in Chapter 2.3.5. For non-aqueous fluid (NAF), coefficients of friction normally are 50% lower than that for water-base systems. Coefficients of friction measure the effective lubricity of a liquid, with the lower the value, the higher the lubrication characteristics. If the coefficient of friction is too high, the excessive torque and drag while turning the bit or lifting the drillstring can prevent drilling from continuing.

From a performance standpoint, non-aqueous muds are far superior to water-based systems. Non-aqueous drilling mud systems permit more efficient drilling of highly complex extended reach and horizontal wells required for field development on Canada’s east coast. In addition to providing superior performance on the basic technical requirements for drilling muds, NAFs also perform in regard to key secondary functions.

In terms of deep water drilling issues, there is less of a risk of forming gas hydrates when NAFs are used rather than WBMs. Gas hydrates are (relatively) stable solids that can plug lines and valve when they form. They form under certain conditions of pressure and temperature in the presence of free gas and water. These conditions can occur during critical well operations and may present a risk to operations, especially in deep water. The water phase of the NAF does not normally contribute to hydrate problems because it is present in a relatively low concentration (20% or less by volume) and it generally has a high salt content (primarily for shale inhibition).

Gas solubility of NAFs provide an advantage (over WBMs) in preventing gas migration up the well during shut in procedures. NAFs result in fewer instances of stuck pipe and hole problems, which put rig-based workers into more dangerous operations and can lead to accidents. Also most high cost and high risk operations like exploration in deepwater need to use “logged while drilling” (LWD) tools to identify high pressure and other risky conditions - these LWD tools are usually neutron (radioactive tools). Using WBM would lead to more cases of stuck pipe where neutron tools would have to be abandoned in a lost wellbore. Again "fishing" and abandoning radioactive tools involve more risky rig procedures and re-drilling.

Limitations and Developments (aqueous-based systems)2.3.4


The rudimentary formulations that characterized the earliest water-base drilling mud systems have now advanced to where the primary focus is improving performance to expand the range of wells than can be drilled successfully with these muds. While WBMs maintain an important role in many drilling operations, the applications of water-base drilling muds remain limited by:

Shale Inhibition: Since water serves as the base mud, and some shales tend to react •excessively to water, some shales have a tendency to hydrate once exposure is initiated. Significant progress in shale stabilizers has been realized, but the problem is that many of the highly ionic stabilizers also tend to exhibit acute toxicity in the laboratory toxicity tests because they alter the ionic balance in the test organisms. Such changes are unlikely to occur under field conditions due to rapid dilution when discharged. Therefore, these types of additives are limited by both the amount that can be used and the applications. Today, research is focusing on the development of low-toxicity shale inhibitors.

Effective Lubricity: Since offshore drilling depends heavily on directional and •extended reach wells, lubrication is a critical component in drilling mud design. Today’s water-base mud systems fall short in this criteria, as they are unable to impart adequate lubricity, and increase the necessary torque, required to overcome the frictional forces generated when a drill pipe is essentially laying against the side of the wellbore. Without sufficient lubricity, some horizontal/directional wells may not reach their target. Historically, technology limitations such as those seen with WBMs have required field developers to install more platforms. As more platforms are required, rising costs may prevent a field from being developed. Therefore, it is clear that lubricity is a critically important function of a drilling mud system used in this application.

In addition, as with shale inhibitors, the toxicity of lubricants now on the market remains an issue. In the early years, diesel oil was commonly used as a lubricant, followed by the introduction of surfactants. Currently, lubricants are usually non-toxic polyglycol compounds.

Temperature Limitations: Formation temperatures increase in proportion to depth •and as the wellbore exceeds 100ºC, many of the additives used in aqueous systems begin to thermally degrade, thereby reducing performance. At higher temperatures, the drilling mud begins to exhibit gelation, which makes it more difficult to re-circulate the system after it has been stagnant. High-temperature stabilizers, such as polyacrylates and lignosulfonates, are required to prevent gelation and increase temperature stability. These chemicals add complexity and costs to the operation.


High Pressure High Temperature Wells are drilled much more safely with NAF's due to the much improved temperature stability of the drilling mud at high densities. It is very difficult to control the properties, especially suspension of barite, with WBMs. There have been developments in high temperature waterbase polymers, but there have been little improvement in the control properties (especially density and prevention of high temperature gellation), and have poor filter cake characteristics, resulting in high incidences of stuck pipe.

Gas Hydrate Formation: There is a greater risk of forming gas hydrates in WBMs •than in NAFs. In order to prevent the formation of gas hydrates, significant concentrations of salt and or glycols are required in the active drilling mud system. While these measures can be effective in shallower waters the potential for gas hydrate formation continues to pose a significant risk for deep water drilling with WBMs.

Overall Drilling Efficiencies: Generally, when compared to non-aqueous muds, •water-based systems generate lower rates of penetration (ROP) and have more problems with contamination. While research programs are addressing these limitations and new products and technologies are being introduced, drilling efficiencies remain comparably lower with aqueous drilling muds. Furthermore, incidents of stuck pipe and other problems are much higher with water-based drilling muds. Reduced drilling efficiencies and increased drilling problems extend the time it takes to drill, exacerbating the associated environmental impact of the operation.

Limitations and Developments (Non-Aqueous-Based Systems)2.3.5

Non-aqueous mud systems assuage the performance limitations inherent in water-based systems. Since shales do not hydrate in the presence of NAFs, wellbore stability is maintained. NAFs are intrinsically lubricious; therefore, the ability to drill high-angle holes is enhanced. In addition, these muds are thermally stable up to 130ºC. Individual thermal stability performance is dependent upon the chemical structure of the base mud. Of the typical synthetics used, traditional esters have exhibited the lowest degree of thermal stability.

Nevertheless, while shale stability is greatly enhanced compared to water-base systems, some mechanical shale stability problems can cause significant well difficulties. Further, although the friction between the wellbore and the drillstring is greatly reduced, the limits of the torque on the drillsting are met eventually. Therefore, continued research into shale stability and additional lubricants is continuing. Non-aqueous muds also are limited by:


High Cost: Unlike aqueous muds, the base-mud cost for these systems is very high, •ranging from $50–$500 US per barrel ($250-$2,500/m³). The considerably higher cost of the base mud must be justified by a proportionately higher level of performance. As the engineering of non-aqueous muds has progressed, so too has the cost of the base muds. Earlier generations employed No. 2 diesel fuel, which was widely used and remained relatively low in price. As non-aqueous drilling muds switched from diesel to LTMOs, which require more processing and have limited availability, the cost of the base mud increased. Contemporary synthetic-based muds are constructed from manufactured chemical compounds that are usually three to five times more expensive than mineral oils.

Physical Properties: Pour point and viscosity are two key mud parameters that must •be addressed in the formulation of a non-aqueous mud system, especially when engineering for a cold water application. In cold water environments, if the pour point is higher than the water temperature, the base mud can gel or solidify. Further, the low-temperature viscosity can increase to the point that it causes the bottom-hole circulating pressures to fracture the formation, leading to a loss of whole mud downhole. This is particularly critical in deepwater wells where the acceptable downhole pressure gradients are narrow. Additional details of non-aqueous base mud physical properties can be found in Table 2.1.

Reduced Logging Quality: In order to identify when oil and/or gas has been •discovered in commercial quantities, drilling operations use logging tools to identify petroleum-laden formations. Since the most effective logging tools use electrical currents to identify prospective formations, the drilling mud must be capable of conducting electricity. Given the insulating properties of the base muds, conventional non-aqueous muds do not conduct electricity. Consequently, they may not be acceptable where high-resolution electric log information is critical. However, new technology is unfolding that promises to significantly improve the logging capability of non-aqueous drilling muds.

Lost Circulation: The cost of losing whole mud to the formations rises dramatically •when the mud being lost is a premium non-aqueous system. Consequently, despite their higher level of performance, these systems may not be economically viable for drilling formations prone to lost circulation.


Table 2.1 Typical Properties of Various Non-Aqueous Base Muds

Property Diesel LTMO² Synthetic¹PAO Ester Ether Acetal LP LAO IO

Specific Gravity 0.855 0.804 0.80 0.85 0.83 0.84 0.77 0.77 – 0.79 0.77-0.79Viscosity at 40°C 2.65 1.68 5.0 – 6.0 5.0 – 6.0 6.0 3.5 1.75 –

2.52.1 – 3.1 3.1

Flash Point (°C) 195 160 >150 >150 >160 >135 >90 113 – 146 137Pour Point (°C) <-55 <-15 <-40 <-60 -10 -12 – +3 -24Aniline Point (°C) 151 174 108 25 40 >93 -94 -94

Friedheim and Conn, 1996.1.Boyd et al., 19852.


Environmental Concerns: The environmental concerns associated with non-aqueous •mud use are discussed in more detail in subsequent chapters. Briefly, the two key constituents of these systems that produce environmental concerns are the mud itself and, in land-based disposal operations, the brine phase. In offshore areas that no longer allow the direct discharge of non-aqueous muds, an assortment of disposal technologies have been developed which are discussed in Chapter 3. Each of these technologies have an associated environmental cost which must be taken into consideration when determining whether or not to permit discharge. The high costs of the synthetic and LTMO base muds are often justified if the cuttings are allowed to be discharged.

Factors Affecting the use of Technology2.3.6

Universally, a framework of decisions is formed by the technical requirements of the specific drilling program, the economics of the drilling program, and the local environmental regulations. Within this framework, well planners design wells and select drilling mud systems. What follows is a brief description of each phase of this framework with a theoretical example.

Technical Requirements2.3.6.1

The following criteria define the technical requirements for drilling muds:

Formations to be drilled and the resulting contaminants. Non-reactive shales •require low levels of inhibition; reactive shales and salt formations require high levels of inhibition. For example, this may lead to the decision to use a NAF system instead of a WBM for drilling in reactive shales.

Wellbore complexity. Simple wells with vertical geometries can be drilled with •simple drilling muds systems. Conversely, more technically demanding wells, such as those that are drilled deep, and others with extended reach, horizontal and S-shaped configurations, require special mud properties. These properties include lubricity, low filtration with excellent filtercake quality, wellbore stability with minimum differential pressure between the hydrostatic head of the mud and the formation pressures, and formation stability, even with extended exposure to drilling muds. For example, a simple vertical well may be drilled with WBMs, while an extended-reach well would require use of an NAF system.

Casing design and pore pressure analysis. Generally, higher density muds are •required as the well deepens. This makes the selection of casing points and


corresponding mud weights critical, as installing casing strings is one of the more expensive aspects of the drilling operation. Often the improved hole stability provided by NAF systems allow use of smaller casing size or allow casing to be set deeper than would be possible if WBM were used, thereby improving drilling efficiency.

Deep water drilling. Deep water wells, even non-deviated exploratory wells, achieve •improved performance with NAFs, thus affecting choice of drilling fluids. Control of gas hydrates, improved drill rates with reduced trouble and concomitant safety issues, environmentally-friendly SBM fluids release in the event of emergency disconnects, and other performance features heavily favour use of NAFs (especially SBMs) over WBMs in deepwater drilling fluids systems.

Economic Considerations2.3.6.2

The economic framework is based on balancing the cost of the various elements required to drill a well. These costs include the drilling rig, the drilling mud, treatment equipment, and disposal costs (including injection and/or drilling waste transportation costs). Chief among those elements is the drilling rig cost. In cases where the daily rental rate is lower, the operator has the flexibility to select lower-cost technical options, even though doing so may extend the time it takes to drill a well. For example, though drilling with water-based drilling muds may typically take longer; they are less expensive than non-aqueous systems. If the daily rig rate is low enough, the lower cost of the mud system may counterbalance the longer time on location. Conversely, when a higher-cost rig is required, the operator usually opts to select more premium technologies that will shorten the duration of the drilling operation. Clearly, one of the more fascinating aspects of this decision process is risk analysis. For instance, selecting a water-based drilling mud system increases the risk of stuck pipe that could typically take three to seven days to correct. Then again, selecting a diesel oil-based system, which would require that the cuttings be hauled to shore, raises concerns that inclement weather could prevent the safe offloading of waste, effectively shutting down the drilling operation until conditions improve. Ultimately, the value of the targeted oil and gas reserves must be weighed against all drilling and production costs. If the ratio of cost to value is too high, the operator may elect to expend its resources in another geographic area until the technology is available to improve the fiscal outlook in the originally targeted location.

Environmental Considerations2.3.6.3

Environmental regulatory considerations play a significant role in both the selection of drilling muds and the overall economics of drilling a well. The specific regulatory requirements of an area often dictate the technologies that can be used and what, if any,


material can be discharged into the environment. This, in turn, influences what and how wells can be drilled. On a wider scale, the ability to discharge non-aqueous mud cuttings significantly expands the inventory of wells that can be economically drilled in an area. Environmental restrictions or limitations on the base mud selection can serve to increase or decrease the cost of the drilling mud. In some areas, mud systems are selected strictly on the basis of local environmental regulations. In others, specific regulations may not be in place, leading operators to base their selection criteria on the predicted environmental impacts of discharges. Either way, environmental considerations significantly influence the available technologies that can be used to drill a well.

Theoretical Example 2.3.6.4

To illustrate the interrelationship of technical, environmental, and economic elements, consider the operator planning to drill an offshore well. The pre-drilling research indicates that the targeted formations comprise highly (water) reactive shales that require an inhibitive drilling mud system. Local environmental regulations allow, within a set toxicity limit, only the discharge of WBM muds and cuttings. Now, the operator has a basic framework from which to make its decisions. Due to the toxicity limitation, the operator is limited to lower concentrations of ionic shale inhibitors, putting the operation in jeopardy as the shales could hydrate and create severe drilling problems that may prevent completion of the well. As an alternative the operator could consider the use of NAFs and evaluate the impacts of limited or no discharge operations on the project economics. The operator also has to take into consideration unexpected equipment failure and weather conditions that could put the economic feasibility of the project at risk. At the end of the day, all of the drilling/disposal costs, the risk of unexpected events and the technical drilling demands must reach some degree of equilibrium before the well can be considered an economic success.


Owing to the minimal technical demands, low-cost water-based drilling muds typically are run in the upper sections of most wells. As the well deepens, and/or becomes directional, the technical demands increase proportionately, necessitating displacement with either a specialized water-based system or a non-aqueous drilling mud. In addition to the myriad of technical requirements, various government regulatory agencies have developed a wide range of regulatory options for drilling wastes.

Experiences With Non-Aqueous Drilling Muds on Canadian East 2.3.8Coast


In wells drilled on the east coast of Canada, the more challenging intervals employ non-aqueous drilling muds, because of:

Complexity: Drilling projects in this region include deep, extended reach or •horizontal wells that penetrate formations that can be unstable and problematic.

Deep Water Drilling: As exploration and drilling continue off of the Canadian east •coast the likely trend is for more deep water drilling. As in other areas of the world, the move toward deep water typically requires the use of NAF muds for both technical and economic reasons. Because of the inability to inject cuttings in deep water configurations and the potential for emergency riser disconnects (during which all drilling muds would be released into the water column), most areas have promoted SBM use and discharge of SBM cuttings instead of OBM use and transport of the cuttings to shore.

Duration of Wells: The depth of the wells and climatic shutdowns (i.e., off location •weather-induced delays, icebergs) require a mud system that will maintain wellbore stability with minimal chemical interaction with the formation.

High Temperature High Pressure (HTHP) Wells: High temperature high pressure •conditions can be encountered when drilling the deeper formations offshore the east coast of Canada. The HTHP wells are drilled much more safely with NAFs due to the much improved temperature stability of the drilling mud at high densities. For these reasons NAFs have been used for drilling HTHP wells off Nova Scotia. In addition most of the wells drilled West of the Shetland Islands use NAFs for the same reasons.

Lubricity: Most wells are drilled to the limits of the mechanical equipment torque •capability. Without sufficient lubricity, these wells could not be drilled as planned.

Environmental Concern: The impact of synthetic-based muds to the marine •environment is low while also delivering the wellbore stability and lubricity of conventional oil based drilling muds. Hence, drilling efficiencies have improved dramatically, resulting in fewer days required for a given operation. Reduced days on location translates into reduced environmental impact.

In some areas, the production from horizontal wells is four times greater than that from conventional deviated wells. The improved efficiency from these well geometries maximizes performance at lower costs and reduced environmental impact. As previously discussed, using extended reach technology allows operators on the Canadian east coast to increase production from a field using only one platform.


Hibernia Experience2.3.8.1

To date, 15 wells have been drilled on the Hibernia Platform. The first four wells were drilled to total depth with WBMs. These initial wells were drilled to approximately 4,600 m at inclinations of 40º or less. The next three wells proved to be much more demanding as they were drilled to greater depths and at higher inclinations than the initial wells, as illustrated in Table 2.2. These three wells were drilled with WBMs for the top hole portion and were then drilled with SBMs to the planned total depth. This two-phase drilling mud program is typical wherever NAFs are used.

Table 2.2 Examples of Technically Demanding Hibernia Wells

Well Name Depth (m) Inclination (degrees)GICX 6,938 66GIB1 7,236 70OPC1 8,485 72

This analysis compares the performance of WBMs and SBMs in the technically demanding 311 mm section of select Hibernia wells. Significant data has been collected while drilling this interval, which historically has posed the most challenges.

First, despite their significantly higher up-front cost, mud cost per metre when using SBMs averaged US $140, compared to US $250/metre when using WBMs. The disparity in costs is a direct result of the improved rate of penetration, solids removal efficiency (SRE), wellbore stability, and the solids tolerance of the SBM.

Second, extended reach wells (ERW) that are drilled from Hibernia, make torque and drag modelling an integral part of the well planning process. Accordingly, the drilling mud has a direct impact on the projected torque and drag. Typically, friction factors for WBMs range from 0.35 to 0.45, while the SBMs used on Hibernia have exhibited factors as low as 0.19 to 0.20. Thus, the platform can successfully drill extended-reach wells without exceeding torque limitations, allowing the successful draining of more distant producing zones.

Third, sustainable ROP is one of the most visible indicators of drilling mud performance and overall efficiency. For the purposes of this analysis, two wells of similar trajectories have been selected, one using a WBM and the other a SBM to drill the 311-mm section. As shown in Table 2.3, the ROP of the SBM is greater than the WBM. Consequently to drill a comparable length of hole (for example 4450m) it would take 34 days with a WBM and only 28 with an SBM. The decrease in days of drilling results in cost savings and reduces overall discharges.


Table 2.3 ROP of comparable Hibernia Wells using WB and SB Mud Systems

Well Name Measured Depth (m) Mud System ROP (m/day)WIW1(B-16-9) 4450 Water-Based 130OPB1 (B-16-14) 6489 Synthetic-Based 160

Furthermore, once a section of hole is drilled and prior to the running and cementing of casing, the formation evaluation program may require that wireline logs be run across the interval. To date, on Hibernia, five wells drilled with WBMs have experienced hole stability problems in the 311 mm section, which have resulted in logging problems. In contrast none of the 311 mm sections drilled with SBM have experienced instability problems.

Jeanne D’Arc Basin (JBO) Experience2.3.8.2

The JBO used SBMs to drill its Hebron M-04 well in the year 2000. Based on JBO’s economic evaluation of SBMs versus WBMs, it was conservatively estimated that using synthetics would save 230.5 hours of rig time (9.6 days) or $5,000,000. Additional intangible benefits cited were reduction in risk associated with stuck pipe.

An example of the increased efficiency with SBM use is revealed in the fact that the top section of M-04 which was drilled with SBM was drilled in 53% of the time that was required to drill a similar interval with WBM on the Ben Nevis well, L-55.

SOEI Experience2.3.8.3

SOEI estimated that development wells would take 15-25 days longer and cost an additional $6,000,000 - $9,000,000 if WBMs were used rather than SBMs. Furthermore, WBM use significantly increases the discharge volumes.

Terra Nova Experience2.3.8.4

The Terra Nova Project has realized considerable improvement in drilling efficiencies with the use of SBMs. Initially, the first well, PG-2, used a premium WBM (KCl/Polymer). Many problems occurred while using the WBM. The drillstring became stuck in the hole twice (one stuck pipe incident requiring severence of the drill string and a sidetrack). Two logging attempts also failed due to poor hole conditions. The casing had to be installed at


a shallower depth than planned, resulting in a smaller diameter production liner (less production capacity and increased future intervention costs). After day 88, the WBM was replaced with a SBM, which allowed the drilling to proceed without further problems. This well in total took 122 drilling days to reach 3,333m depth.

The next well, GIG3, a technically more difficult well, used SBMs and finished drilling in 54 days with the planned casing and liner program, reaching a depth of 3,343m.

It is important to note that improved drilling efficiency has a considerable effect on emission levels. Every tonne of diesel fuel consumed contributes to approximately 3.25 tonnes of CO2 and 0.06 tonnes of NOx emissions (M. Innerarity, pers. comm). Considering that nearly 100 tonnes of diesel are consumed daily by the rigs working off east coast Canada, it is clear that minimizing the length of a drilling operation can dramatically reduce greenhouse emissions.

Solids Control2.4

Function 2.4.1

Effective solids control optimises the size, type and amount of solids in the drilling muds. As discussed earlier in this section, bentonite or organophillic clays, barite or other density-adjustment materials are the typical solids added to a mud system to achieve desired properties. Drilled cuttings, on the other hands, are undesirable solids.

The level of drilled solids (cuttings) in any drilling mud must be controlled, as too high a concentration will cause drilling problems. Solids control (solids removal) equipment and dilution are used to control the amount of drilled solids in the drilling mud. Drilled cuttings may be separated into low-gravity (2.3–2.8 SG) and high-gravity solids (>4.2 SG). The two are distinguished by the additives used in the active mud system to impart desired properties: high-gravity solids are used to provide density; low-gravity solids provide viscosity, filtration control and other properties. Typically, the specific gravity of drill cuttings is in the low-gravity range. However, they rarely have the desirable properties of bentonite or organiophillic clays, the other component of low gravity solids.

It is important to understand how particle sizes in drilling muds are classified and the types of solids that fall into each category. Further, it is important to be aware of the effect solids have on the properties of a drilling mud system as they are ground into finer and finer particles.

A small fraction of the solids should be colloidal sized (<2µm) for needed viscosity. Too


high a concentration of colloidal solids is problematic as it increases viscosity beyond the desired range. Figure 2.6 shows the classification of solids found in drilling mud and associated cuttings and the effective separation range of various types of solids control equipment.

Figure 6 Size Classification of Drilling Solids and Effective Removal Ranges of Solids Control Equipment

The effect of particle size degradation on surface area is presented in Fig. 2.7. As illustrated, the original drill cutting particle was 40µm in diameter with a surface area of 9,600 µm2. As an individual particle is broken and degraded the number of particles and surface area increases until the original particle is broken into 64,000 cubes, each with a surface area of 1µm2. At that time, the surface area has increased to 384,000 µm2, which is 40 times more than the original surface area. In drilling muds, viscosity increases proportionally with the surface area of solids. The surface area of solids must all be wetted with either water or base mud. As the increased surface area reduces the amount of free liquid, mud viscosity increases, thereby reducing the overall performance of the drilling mud. For this reason, removing drill solids before they are ground into fine particles is a high priority.


Figure 7 Change in Drill Solid Surface Area Resulting From Degradation

Drill solids can be separated by :

settling;•screening;•processing through hydrocyclones; and •processing through rotating centrifuges.•

Shale shakers (Figure 2.8), which essentially are vibrating screen separators, are the primary solids control devices. The mud and cuttings are routed to shale shakers once they reach the surface. At one end of the shale shaker, the material is collected in a box where the mixture of liquid and solids is evenly distributed onto a vibrating horizontal screen. The vibration transports the cuttings to the far edge of the screen, where they are discharged. Meanwhile, the mud flows through the screen and is collected for further processing and reuse in the active circulating system. Shale shakers are designed to treat 100% of the mud flow and can remove up to 100% of all solids larger than the screen mesh. The primary limitation of the technology is that very fine screen mesh will also remove the barite particles used to weight the system. Also, shale shakers are unable to remove silt and colloidal-sized particles, hence dilution and other equipment is required to control fine and ultra-fine drill solids.


Figure 8 Adjustable Linear Shaker.

Hydrocyclones (Figure 2.9) and decanting centrifuges (Figure 2.10) use enhanced gravity separation to separate drill solids from the drilling mud. Separation is governed by Stokes Law, which shows that particles of the same mass (density x volume) will settle at the same rate. Consequently, an undesirable low-gravity solid 1.5 times larger than a barite particle will settle at the same rate. As a result, hydrocyclones and centrifuges are not flawless in separating unwanted drill solids from muds containing needed barite. Nevertheless, the advantages of this equipment outweigh its limitations.


Figure 9 Hydrocyclone Applications

Figure 10 Cross-Section of a Decanting Centrifuge

Hydrocyclones typically are used with un-weighted WBMs to remove sand and silt-size particles that can not be removed by the shale shakers. Centrifugal pumps pressure the


mud through a tangential opening in the large end of a funnel-shaped hydrocyclone. This produced flow, resembling the motion of a tornado, whirls the mud, expelling the wet and higher-mass solids through the open bottom, while the liquid returns through the top of the hydrocyclone, where it is eventually returned to the active system. Since hydrocyclones also remove barite, they normally are not used with weighted drilling mud systems.

Centrifuges (Figure 2.10), which can produce very high G-forces (600-800 G), are used in a variety of ways to remove solids from the drilling mud. For weighted drilling muds, a centrifuge normally is arranged to recover barite, which is returned to the active mud system. In WBMs, the liquid phase containing the detrimental drill solids is discharged and replaced with new volume. In dual-centrifuge configurations, the discarded liquid can be processed further, so that it can be separated from the low-gravity solids and returned to the active mud system. This technique is frequently used on invert emulsion systems to recover and recycle costly base mud. The primary drawback to centrifuges is their relatively low processing rates (<40g/min).

One of the newest solids control technologies is cuttings dryers, which allow “wet” cuttings expelled from a shale shaker to be centrifuged and dried before discharge. These devices were adapted from the coal industry where they are used to separate slurries of coal. The design is a combination of a fine-screen (similar to those used on a shale shaker) and a rotating basket that generates centrifugal forces. Most of the mud is removed from the cuttings and returned to the active circulating system. Unfortunately, the high concentration of fines in the recovered mud can require additional or increases the amount of dilution required. This will be discussed further in Chapter 2.4.3.

Sources of Pollution2.4.2

If operated with perfect efficiency, the mechanical solids control equipment would return 100% of the drilling mud to the circulating system, with 100% of the drill solids being discarded. However, under all field conditions, some percentage of the drilling mud is discarded with the drill solids, while some fraction of the drill solids are retained in the active mud system. Consequently, the cuttings and residual muds typically are considered sources of pollution. When the mud volume used to dilute the drill solids that are retained in the active system exceeds the available storage capacity of the drilling rig, that excess mud is disposed as waste. Addressing the issue of drilling solids removal is a constant problem every day on every well.



As discussed above, the removal of cuttings from an active circulating system is an imperfect process. While being circulated up the hole, the cuttings break into fine particles. Also, a significant percentage of cuttings can remain in the mud system when being processed through the solids control system. This contaminated mud must then be diluted to control the build-up of the drilled solids. The excess liquid required for dilution must be disposed of properly. If a solids control system is working efficiently, the resulting colloidal buildup of drilled solids in the active circulating system can become a problem requiring the disposal of large volumes of “used” mud.

For NAFs, an effective solids control process consists of:

Efficient shale shakers. They should allow the finest screens to be used to screen-•out the smallest cuttings possible, while dramatically minimizing the amount of mud associated with the cuttings.Centrifuges. They should remove the very fine particles and minimize the build-up of •colloidal-sized cuttings.Dilution of new mud. A programmed dilution to maintain correct properties in •conjunction with the efficiency of the solids control equipment in cuttings removal can reduce significantly the volume of mud requiring dilution.

As mentioned, in some cases cuttings are dried to reduce the amount of mud on cuttings. Although use of cuttings dryers can decrease the volume of mud being discharged with cuttings, it may ultimately result in an increase in the volume of drilling muds contaminated with fines that need to be disposed of. The degree of buildup of fines in mud varies with the local geology and may be an issue more in eastern Canada than elsewhere. Testing is planned to assess the fines buildup in drilling fluids. A vertical centrifuge will be tested on cuttings from a Nova Scotia well to determine the degree of fines buildup in a mud system. Today, efforts are in place to improve techniques and the performance of solids control equipment. Another limitation of this technology is potential weight and space limitations on drilling rigs (in particular floating ones) which can influence the ability to add solid control equipment skids.

Measurement of Performance and Impacts on Discharges2.4.4

On the average, a solids control system can remove approximately 75% of the cuttings drilled. The 25% remaining in the mud system must be diluted to maintain the proper drilling mud properties. Due to the superior cuttings integrity (larger and easier to remove) generated when drilling with NAFs, the SRE is higher than it is when WBMs are used. Since NAFs have higher SREs, and also higher tolerances for fine solids, they require less dilution than WBMs. The efficiency of the solids control process and the mud


system’s tolerance to fine solids dictate the dilution rates required to maintain an acceptable range of fine and ultra-fine solids. The relationship between SRE and the corresponding dilution volumes required to maintain a various concentrations of low-gravity solids (LGS) is depicted in Figure 2.11.

Drilling Fluid Requirements

0 m3

500 m3

1000 m3

1500 m3

2000 m3

2500 m3

3000 m3

3500 m3

20 %SRE 40 %SRE 60 %SRE 80 %SRE

% Solids Removal Efficiency (SRE)

Volu

me

2 %LGS 4 %LGS 6 %LGS 8 %LGS


Figure 11 Relationship of SRE and Dilution Volumes Required

The amount of drilling mud retained on cuttings must be monitored very closely when using NAFs. Normally, this is accomplished by measuring the weight of the drilling mud associated with a known weight of solids (retort analysis). Normal solids control systems will typically discharge cuttings with <15% by weight base mud. Larger cuttings, with their smaller surface area, tend to have lower cuttings retention values. Consequently, using coarser mesh screens can lower the retention values of the cuttings being discharged. However, while this practice may result in compliance with regulatory requirements, the finer cuttings that are retained in the mud system quickly degrade, requiring increased dilution, resulting in a large volume of unusable drilling mud that will have to be managed. Although cuttings dryers can significantly reduce the concentration of drilling muds on the cuttings, the trade off is that recovered liquid is high in low-gravity solids (reduced SRE) and can quickly generate the need for large dilution volumes and thus generates large volumes of waste mud. It is important to note that the waste drilling mud (containing an excessive content of drilled solids) must either be reinjected or shipped to shore for disposal.

Factors Affecting Use of Technology 2.4.5

The volume of drilling wastes discharged (cuttings and adhering mud as well as whole WBM-if used), drilling mud stored for reuse or disposal (NAFs only) will be a function of


the SRE of the system. As well as the drilling mud selected (NAF or WBM), and the retention of mud on cuttings (NAFs only). Compared to that of WBMs, the ability of NAFs to prevent cuttings dispersion, facilitate better solids removal efficiency, and tolerate solids contamination translates into less volume of mud required to drill a well.

The equations provided below lead the reader through the steps of estimating waste volumes generated from drilling. In addition, an example is provided of the volumes of wastes generated by drilling with WBMS versus those generated by drilling with NAFs (Table 2.4).

Volume of cuttings drilled. •The volume of cuttings drilled is a function of the hole diameter and length.

Volume of Cuttings (m3) = (Dia. Of hole, mm) 2/1273000 x length of hole drilled(m),or

= Π x (Radius of hole( m))2 x length of hole drilled (m)

Note: the use of WBMs results in larger holes, consequently a "washout" factor of 15-20% is usually added to estimate the total volume of cuttings generated when drilling with WBMs.

Volume and Weight of cuttings discharged•Generally, discharged cuttings that are coated with drilling mud have a volume ratio of 60% cuttings to 40% drilling mud.

Volume of cuttings discharged = volume of cutting drilled x (SRE/100)

Weight of cuttings discharged = m3 of cuttings x 2600 kg/m3

Volume and Weight of NAF mud discharged •

Weight of mud discharged = weight of cuttings discharged x (% mud retention on cuttings/100)

Volume of mud discharged = weight of mud discharged/ mud density

Volume of mud required•The volume of mud required for a particular drilling operation is a function of the volume of cuttings, the SRE, and the fraction of drill solids in the mud.


Mud Req’d (m3) = (Vol. of Cuttings, m3) x (1-SRE/100) x (1-Fraction Drill Solids in Mud)(Fraction Drill Solids in Mud)

For WBMs this will be the volume of mud discharged. For NAFs this will be the volume of mud that will be reused or disposed of (referred to later as "stored").

Note: The SRE is usually 60-80% for WBMs, but may be up to 95% for NAFs. The fraction of drill solids may range from 8-10% by volume for NAFs and 3-5% for WBMs.

Table 2.4, illustrates the importance of high-efficiency solids control equipment and drilling mud type on the overall quantity of waste generated. The values in Table 2.4 were generated based on the following assumptions:

2500 m of 311 mm diameter hole is drilled;•15% by weight base mud retained on cuttings when drilling NAF;•the fraction of drill solids in the NAF is 9% by volume;•the fraction of drill solids in WBMs is 5% by volume;•the specific gravity (SG) of the cuttings is 2.6;•the specific gravity of the base mud is 0.8;•the mud stored is either used or contaminated NAFs that have to be treated by some •method other than offshore discharge; andusing WBM would have enlarged the hole diameter, thereby increasing cuttings •volume by 20% (i.e., 300 m3 of cuttings generated).

Table 2.4 Impact of Mud Type and Solids Removal Efficiency on Waste Volume (based on drilling of 2500 m of 311mm hole)

Mud Type, SRE

Vol. of Mud Discharged

(m3)

Vol. Of Cuttings Discharged

(m3)

Vol. of Mud Stored(m3)

Vol. Of Base Mud Discharged

(m3)WBM 60% 2078.6 164.1NAF 60% 114 768.4 55.6WBM 70% 1559.0 191.5NAF 70%

133 576.3 64.8

WBM 80% 1039.3 218.8NAF 95% 152 384.2 74.1

Example calculations of the values in this table for both WBMs and NAFs are provided below.


WBMs: (assuming SRE of 70% and hole diameter increase of 20%)

Vol of hole drilled, m3 = ((311 * 1.2)2 / 1273000) x 2500m = 273.5 m3

Vol. of mud req'd, m3 = [(273.5)(1 - 0.7)(1 - 0.05)] / (0.05) = 1559.0 m3

Vol. of cuttings discharged (m3)= (273.5)(0.7) = 191.45 m3

This amount of mud, 1559.0 m3, would be discharged along with the 191.45 m3 of cuttings that is removed by solids control equipment.

NAF's: (assuming SRE of 80%, no hole diameter increase, and 15% by weight mud on cuttings)

Vol. of hole drilled, m3 = (311)2/ (1273000 x 2500m) = 190.0 m3

Vol. of mud req’d, m3 = (190)(1-0.8)(1-0.09) / (0.09) = 384.2 m3

Vol. of cuttings discharged = 190 m3 X 0.9 = 152.0 m3

The amount of base mud discharged with the cuttings, assuming 15% by weight mud on cuttings, can be calculated as follows:

Weight of cuttings discharged = 152 x 2.6 = 395.2 metric tonnes (MT)Volume of base mud discharged = (395.2 X 0.15) / 0.8 mud SG = 74.1 m3 of base mud

Owing to the dispersion of the cuttings, it is difficult to obtain an SRE of more than 70% when using water-based drilling muds. On the other hand, the SRE for SBM's can approach 95%. As the SRE is improved, the cuttings discharge increases and the mud requirements reduce.

An example from Hibernia (Table 2.5) also helps illustrate the same concepts as the calculations above.

Table 2.5 Hibernia Wells 311 mm Interval: Volumes of SBM and WBM Used per Meter Drilled

Well Name Fluid Type Volume Used(m3)

Volume/Length (m3/m)

Volume Whole Mud

DischargedOPQ2 (B-16-2) WBM 1940 1.071 1940OPR1 (B-16-4) WBM 2347 1.165 2347OPW1 (B-16-3) WBM 1323 0.83 1323GICX (B-16-5) SBM 402 0.128 0


OPC1 (B-16-11) SBM 909 0.23 0The following can be concluded from Figure 2.11 and the examples above:

the volume of WBM required is much greater than that of NAF to drill a hole of the •same dimensions;greater volumes of cuttings will be generated and consequently discharged when •WBM's are used rather than NAFs due to the hole enlargement which results when drilling with WBMs;overall total discharge volumes are greater when drilling with WBMs than with NAFs;•as the SRE goes down, the volume of NAF to be stored goes up; and•as the SRE goes up, the volume of cuttings and base mud discharged goes up. •However, at the same time, the volume of NAF for storage goes down. As discussed earlier, this mud is reused as long as it is not overly contaminated with either a large amount of drilled solids or a large content of colloidal sized particles, which cause viscosity problems. However, the increase of NAF in storage continues to grow as more wells are drilled. Eventually, the large volumes of NAF that are collected require disposal (either onshore or by reinjection) due to a build up in fines.

It should be noted that equipment has been recently developed that further reduce the base mud that adheres to cuttings (i.e., cuttings dryers). Although this equipment can reduce the mud on cuttings, the trade off is reduction of SRE due to fines buildup in the mud. This fines buildup in the mud increases the contaminated drilling mud that must be disposed of. Furthermore, it is important to note that a reduction in the amount of base mud discharged with the cuttings causes colloidal solids buildup in the drilling mud. This subsequently drops the SRE, while increasing the volume of drilling mud required.

Global Experiences2.4.6

Worldwide drilling operations use the basic solids control equipment described here. Efficiency varies based on the nature of the formations drilled, as well as the quality and maintenance of the solids control equipment. On the east coast of Canada, SOEI installed horizontal cuttings dryers with the goal of reducing the SBM retention on cuttings to 10% consequently reducing the organic loading on the seabed resulting from discharges. As a result, the project has maintained low cuttings retention numbers, but use of the dryers has contributed to the generation of more than 1,900m3 of solids-contaminated mud. Additional review of compliance data would reveal the balance of cuttings retention and dilution volumes.

Low levels of SBMs associated with cuttings discharged from four SOEI wells are illustrated in Table 2.6.


Table 2.6 SBM Cuttings Volume and Discharge Estimates for SOEI Wells

Well Name

Hole size(mm)

Estimated Interval(m)

Estimated Cuttings Volume (m3)

Estimated Synthetic Discharge (MT)

V2 311.2 3,300-5,100 137 36V5 311.2 3,635-4,730 83 22

215.9 4,730-5,030 11 3152.4 5,030-5,300 5 1

T1 311.2 3,850-4,155 23 6215.9 4,155-4,500 13 3

T5 406.4 1,130-3,965 370 77311.2 3,965-4,300 25 6215.9 4,700-4,300 15 4152.4 4,700-5,000 5 1


DRILLING WASTE MANAGEMENT TECHNOLOGIES3

Residual drilling muds and cuttings usually represent the largest volume of wastes generated from drilling operations. The most critical step in maintaining mud systems is maximizing the removal of drilled solids. Once all source reduction options have been exhausted, recycling and waste treatment are employed to further reduce potential environmental impacts. As with the drilling process, understanding the economic, operational and environmental limitations of the available waste treatment technologies is an important step toward selecting the best technology for a particular area.

One needs to not only consider potential environmental impacts of a disposal option, but also the potential impacts of alternative. These other impacts include costs, resource use, air emissions, transportation and handling risks, occupational hazards, and chemical exposure. All of these factors are part of a comparative framework in which the relative environmental, human health and safety, and economic “costs and benefits” can be evaluated. Terra Nova’s approach to addressing its Condition 20 (Williams et al., 2000) is a good example of a clear understanding of the technical, economic and environmental implications on-shore disposal, re-injection and ocean discharge options were all considered in the evaluation of the best overall management option. A framework of vital parameters by which all disposal technologies can be evaluated is shown in Table 3.1.

Table 3.1 Framework of Parameters for Evaluating Disposal Options

Economics Operational EnvironmentalImmediate costs•$/m3 for disposal•Operating cost•Energy •Maintenance•Labour•Equipment cost•Disposal of end•

productsFuture cleanup• costs•

Safety•Processing rate•Mechanical reliability•Size and portability of unit(s)•Energy requirements•Condition of end products•Number of additional personnel•

requiredMethod of disposal after•

processingWeather conditions•Human health issues/chemical•

exposure

Removal of hydrocarbons from • solids and water

Removal of heavy metals from• solids and water

Removal of salts from solids and• water

Air pollution from treatment unit •Power requirementsReduction in volume of waste•By-products of process•Compliance with regulations•Receiving physical environment•Marine species potentially at risk•Potential environmental stressors•


Offshore Discharge3.1


As the name implies, offshore discharge is a simple process in which the used drilling mud and cuttings are released into the environment on site. Typically, the cuttings from solids control equipment are flushed with water into a centralized discharge pipe (shunt line) that extends beneath the water surface. If drilling muds are discharged, they are usually released from the first two pits in the system. These so-called settling pits frequently collect sand and other drill solids not removed by the shale shakers. It is important to point out that only aqueous muds are discharged in this manner. With the exception of the residue attached to the cuttings, no non-aqueous muds are actually discharged.


Offshore discharge is limited to those muds and cuttings that meet regulatory requirement. Mud limitations and development issues are discussed in detail in Chapter 2. Environmental behaviour of drilling muds is discussed in Chapters 4,5, and 6. Regulatory requirements are discussed in Chapter 7. The advantages and disadvantages of offshore discharge technology are listed in Table 3.2.

Table 3.2 Advantages (+) and Disadvantages (-) of Offshore Discharge Technology

Economics Operational Environmental+ Very inexpensive cost per unit volume treatment

Potential future liability -cost

Cost of analysis of -discharges and Potential impacts (e.g.,

Compliance testing, Discharge modelling, EEM programs)

+ Very simple process with little equipment needed+ No transportation costs involved+ Low power requirements+ Low personnel requirements

Management requirements -of mud constituents

+ Development of non-toxic mudadditives reduces environmental impact

+ Low energy usage- No removal or stabilization of

contaminantsNo control of leachate of heavy -Metals or saltsNAF cuttings discharges regulated-in many locations

+ Can control constituents during the chemical screening process

Measurement of Performance and Impacts3.1.3

The operational and economic aspects of the effectiveness of direct discharge are discussed in Section 2. The environmental effectiveness of direct discharges is discussed in


Section 5 and 6. Management of direct discharges involves the management of the drilling fluid constituents and the solids control equipment. In order to meet the regulatory requirements for the drilling fluid, only those products that have been approved for use at the recommended concentrations can be added. The solids control equipment must be management to meet the volume discharge requirements or the cuttings retention limitation placed on the discharge.


Three factors that need to be considered in the use and management of ocean discharge are:

Can the muds that meet the regulatory requirements for use and discharge also meet 1.the operational requirements for drilling the well?

Can the muds that meet the regulatory requirements for discharge also drill the well 2.cost-effectively with minimal environmental impact?

Will direct discharge result in long-term environmental liabilities not considered in the 3.current regulatory framework?


Direct discharges of water-based drilling muds and associated cuttings have been shown to have little or no impact and, therefore, are allowed in nearly all offshore drilling sectors. On the other hand, nearly all offshore jurisdictions prohibit the direct discharge of non aqueous muds , while the on-site discharge of the associated cuttings are subject to local regulations. Specific regulatory limitations are discussed in Chapter 7.

WBMs and associated cuttings have been and are being discharged from wells drilled offshore eastern Canada. In the 1980’s OBMs were used as well and the associated cuttings discharged (Chénard et al., 1989). More recently, SBM cuttings are being discharged from wells drilled at Hibernia and Terra Nova, and were discharged from SOEI operations until recently.

The future of offshore discharge as a waste management option will depend largely on regulatory development. As long as the focus is continuous efforts to improve the level of control of the constituents placed in the receiving environment and a life-cycle analysis approach is used, the technology should have a place in the range of available waste management options.


On-Site Injection/Annular Disposal – Cuttings Re-Injection3.2


On-site cuttings reinjection (CRI) involves pumping muds and seawater-diluted cuttings that have been ground into particle sizes of <100µm into an underground formation. Before injection is possible, most formations must be fractured with hydraulic pressure, creating small cracks that allow muds and solids to be pushed away from the wellbore. Injected muds are confined in the receiving formations by mechanically (by cemented casing) and geologically (by caprock). Cuttings may be injected via the annulus of a well being drilled or into a dedicated or dual use (one that will later be completed for production) disposal well.

Though CRI frequently is referred to as a “zero discharge” option, some have noted it is a form of disposal. Consequently, by widening the definition of discharge to encompass all environmental releases, annular injection deposits drilling mud and drill cuttings into the earth. In addition, the generators that furnish the power required to grind and inject the slurrified mud and cuttings are sources of air pollution.

Injection is a complicated process, requiring intricate design, specialized equipment, careful monitoring and detailed contingency plans. In the North Sea the design of cuttings injection operations must be undertaken in accordance with The Oil Industry International Exploration and Production Forum’s (E&P Forum) “Guidelines for the Planning of Downhole Injection Programs for Oil-Based Mud Wastes and Associated Cuttings from Offshore Well,” (E&P Forum, 1993a). While the potential geologic formations available for injection operations vary widely from area-to-area, the basic guidelines for CRI operations are applicable to most injection operations. Essentially, in designing CRI operations one must consider the following:

Waste identification and characterization: The types of wastes that could be injected, •the rates of their generation, the dilution requirements, and the overall total volumes must be determined for design. The wastes that could be injected into underground formations include the cuttings from the formations being drilled (ground to <100µm and dispersed in seawater), drilling mud that was attached to the cuttings, polymer viscosifiers (if required), and other wastes generated during operations such as slops from mud tank cleanouts.

Injection Zone(s): The most critical step in the design process is selecting a geological •zone for injection that is capable of accepting the wastes on a long-term basis. Modelling or past experience must be used to decide if a formation is suitable. There have been instances in the North Sea where injected materials have broached to the surface. Important characteristics of the injection zone are that, no muds should be able to broach to surface (a


suitable caprock must be above the injection zone), no faulting should be present that could lead to loss of containment, no fresh water aquifers can be contaminated, the injected slurry should not pose a threat to any existing well, to production reservoirs, or to any subsequent drilling operations, and finally, mud compatibility must ensure that the formation can accept the cuttings slurry.

In addition, the capacity of the injection zone must be determined, injection pressures required must be defined. An understanding of the porosity, permeability, rock characteristics (i.e., Young’s Modulus, etc.) and leak-off of the injection zone is required for the modelling.

Waste Slurry and Surface Equipment: The CRI equipment must be able to grind the •cuttings to <100 µm and disperse with seawater to meet or exceed the generation rate of the cuttings expected, condition the resultant slurry as required with viscosifiers, and inject the slurry at the required rate and pressure.

Well Integrity: All tubulars and wellheads must be designed to withstand the pressures •generated in both burst and collapse, and withstand the corrosion and erosion of the process. The casing must be set to the proper depth (and cemented as required) to ensure that the injection slurry goes into the selected formation. Lastly, the slurry must be contained by both mechanical and geological barriers. Mechanical barriers are created by: 1) tubular and wellhead design; 2) wellhead isolation valves; and 3) proper cementation of annuli. Geological barriers as discussed above, include the fracture mechanics and integrity of the injecting and receiving formations, a sealing formation above the injection zone, inaccessibility to producing reservoirs, and the capacity of the injection zone to accept all required slurry volume without causing problems to adjacent or subsequent wells.

Consideration of the above is critical in evaluating the potential for and design of CRI operations. It is imperative that a suitable formation is available for injection. Even with the best planning, however, there may be injection zone complications. Such as the fracture may screen out. This means that the fracture seals off and a higher pressure is now required to initiate another fracture. This higher pressure may exceed the capabilities of the tubulars, and the formation may “lock-up”. In this case, the slurry causes damage to the formation that prevents any additional injection. Finally, the slurry solids may settle in the annulus and block off the annular space, thereby preventing further pumping.Other problems have occurred with CRI. Broaching to surface occurs when the caprock above the injection zone or cement integrity fails, and the injected slurry appears at the seafloor. The injection mud has, on occasion, pressured-up zones, which have resulted in subsequent wells sustaining a “kick” when this unanticipated pressure has been encountered while drilling (Abou-Sayed, 1999). This situation could cause well control problems and limit future drilling at the


location. However, the most common drawback to CRI is losing the ability to pump into the injection zone, thereby requiring remedial work or an additional disposal well to be drilled.


Brine, produced water and other aqueous solutions have been reinjected in both onshore and offshore operations for some time. The use of injection for mud and cuttings disposal remains relatively new. To date, the vast experience with CRI has been from fixed platforms. Research is continuing to identify the limitations of the technology as well as improvements that can extend its successful application. The most significant limitation for injection technology is the requirement for a suitable injection formation. The formation must have sealing formations that prevent broaching into other formations or to the surface. Additionally, special wellheads are required that have shields to prevent damage. Tubulars must be designed to withstand the additional pressures and erosion. Floating drilling operations have additional limitations. Wellheads must be specially designed for both abrasion and remotely operated vehicle (ROV) accessibility (ROVs are used to operate valves and hookup the high pressure injection hoses). Water depth can be a limitation as well. Large reels for the high pressure injection hose must be installed on the rig. These reels limit the water depth to which injection technology can be used. This will become more of an issue as east coast Canada operations move to deep water. There is little worldwide experience to date of cuttings reinjection on floating operations.

While fracture modelling and monitoring methods have improved over the years, faults in the formation and uncertainties over the extent, nature and direction of fractures can make injection technology unpredictable.

Lastly, this technology may not be suitable for exploration works, as the only data that is usually available (seismic) is not suitable for determination of a suitable formation for injection.

Other limitations to the application of the technology include lack of appropriate injection zones, casing design, and development scenario considerations. Incidents of confinement failures in the casing, cement or confining formations have occasionally resulted in muds broaching the surface, other wellbores or producing formations. The technical and economic feasibility of injecting will also vary with the development scenario. For a development with many wells and platforms spread out geographically, it may be less feasible to employ the injection option than for one for which all the wells are drilled from a single location. Furthermore, depending upon the development plan, one may be able to make the economics of injection more feasible if the well can later be completed for production.

While fracture modelling and monitoring methods have improved over the years, faults in the


formation and uncertainties over the extent, nature and direction of fractures can make injection technology unpredictable.

The advantages and disadvantages of CRI are listed in Table 3.3.

Table 3.3 Advantages (+) and Disadvantages (-) of Cuttings Re-injection

Economics Operational Environmental+ No offsite transportation

needed+ Limits possibility of

surface and ground water contamination

+ Ability to dispose of other wastes that would have to be taken to shore for disposal Mistakes in application -can lead to expensive clean up costs

- Expensive and labour intensive

Shutdown of equipment can -halt drilling activities

+ Cuttings can be injected if pre-treated

+ Proven technology- Extensive equipment and labour

requirements- Application limited by the

receiving formations- Casing and wellhead design

limitationsOverpressuring and -communication between adjacent wellsVariable efficiency -Difficult for exploration wells due -to lack of knowledge of formationsLimited experience on floating -drilling operationsTechnical limitations in deep -water

+ Elimination of water column or seafloor impact

- No treatment of hydrocarbons, salts or metals

- Increase in air pollution due to large power requirements

- Possible broach to seafloor if not designed correctly

Measurement of Performance and Impacts 3.2.3

The performance of re-injection operations, as documented in the literature, is generally measured by evaluating the total volume of waste successfully disposed in an annulus, injection pressure, injection rate and containment of injected muds and solids. Other parameters include the reliability of the injection process and the ability of the injection process to keep up with the volume of waste generated at a given rate of penetration. Quality control of operations includes monitoring of pressure impact on nearby wells, tracking of the direction and location of the disposal plume, the disposal slurry properties, and the equipment condition.


When this option is selected it is because suitable geologic formations are available for


injection, and it can offer onsite disposal for production or development drilling wastes in areas that require zero discharge. The results are immediate and the technology of injection equipment is simple. The technology can treat all liquids generated on-site, including rainwater and oily slop tank waters, and the mechanics of the process are well understood by the engineers responsible for drilling wells. On the other hand, when this option is not selected, it is typically because of potential damage to the well, lack of an appropriate injection zone, a history of failure from inappropriate application of the technology, or increased overall impact of CRI compared to other options.


Cuttings generated from drilling have been injected offshore in a number of locations including the North Sea, Gulf of Mexico, Alaska, and eastern Canada. Experience in the North Sea, with CRI has been variable with regard to equipment reliability, and failure of the injection wells to contain the waste. Operators have found that despite testing the injection capacity at the time the well is drilled, once the operation is undertaken, the well will not take mud. In addition, if any mud other than seawater is left in the well between batch injection operations, it must be able to suspend solids or else the injection borehole will bridge over and no longer function. Overall operational reliability has ranged from virtually no downtime in a given year to very significant downtime per year. One operator reported the successful injection of only 40% of its intended volume, because of downtime (equipment failures) and broaching of muds to the seafloor. Thus, 60% of the oiled drill cuttings were disposed of by alternate means. Another operator reported downtime of 40-50% because of equipment failures.

For a recent North Sea platform development (Kunze and Skorve, 2000), the injection experience has been more positive with operational downtime limited. In this particular scenario, LTMO cuttings and oily waste and drainwater have been injected into a dedicated injection well which will later be completed as a production well. Use of a dedicated well minimized concerns about annular plugging, hanger erosion, and casing collapse of producers. Although a number of disposal options were available, the combination of suitable geologic conditions for injection, the development scenario which made using a dedicated injection well economic, and the regulatory restrictions combined to make CRI the best option available in this situation based on cost, operational, and environmental considerations.The following example illustrates that there is little experience with determining the ultimate capacity of a formation to accept injected wastes generated from drilling of multiple wells. On the Alaskan North Slope, an onshore injection process was proceeding uneventfully. However, the close proximity of 10 wellbores to a CRI well eventually allowed injection pressure to migrate up to the surface-casing shoe, resulting in a broach


to surface (Schmidt et al., 1999). No significant change in well behaviour was observed prior to the broach. Chemical analysis of flowing liquids showed the presence of both freshwater and diluted seawater, while no hydrocarbons or injected solids were seen at the surface. Some 2,860 m3 of liquids flowed to the surface for four days, shutting in all injection and producing wells near the broaching well.

Generally, problems that have been cited with regard to CRI include:the slurry injected underground broaches to the surface or above the seafloor; •the formations become overpressured, causing well control problems; and•plugging of formations or annuli that makes it impossible to continue the injection process.•

There have been several applications of this technology on the east coast of Canada. After difficulties at start-up, a CRI process was later carried out successfully on PanCanadian’s Cohasset-Panuke project. In addition, a CRI system is now being engineered for installation on the Hibernia platform.

Most offshore injection programs to date have been conducted from fixed leg platforms or jackups and have involved injection into a surface wellhead. As discussed in the section 3.2.2, additional technology is required to inject through subsea wellheads from a floating drilling platform. Limitations with this technology have resulted in limited use of CRI from floating facilities and in deepwater. There are only a few instances where this technology has been employed, consequently there is not a large database of information on its reliability. One vendor that supplies injection technology globally, reported that none of their projects had involved injection from a floating facility. A field test was conducted in the North Sea in the early 1990s to prove out the concept of subsea injection (Ferguson et al, 1993). Other applications include those by Statoil at the Ǻsgard field where cuttings were injected into the same well being drilled (Saasen et al, 1998) and at the Gullfaks satellite wells. There was considerable downtime associated with the Åsgard operation, however the problems were attributable more to formation problems than to the technique itself. Operations were more successful at Gullfaks. At this time the practice of injection in deepwater or injection from floating drill rigs is still in the developmental phase.

CRI may not be a viable disposal technology for all projects. For example, a Terra Nova study concluded that although CRI might be technically feasible, it was not considered to be economically feasible. The project would incur additional costs of at least $22.7 million for the necessary five disposal wells, to install CRI equipment on the semi-submersible, and equipment operation for the remainder of the drilling program. Five dedicated injection wells would be required to dispose of the cuttings due to the wide geographic separation of the glory holes. Because the technology for injecting from semi- submersibles into subsea wellheads is still in the development phase, it was estimated that there could be additional costs associated with downtime. As experience develops with the technology, downtime could be reduced as it has with injection projects that have been


conducted on fixed leg platforms. Since the writing of this report, the C-NOPB has communicated its decision on the Terra Nova application to continue discharging SBM drill cuttings at Terra Nova. The Board has decided to continue to allow the discharge of cuttings and will require Terra Nova to adhere to the Offshore Waste Treatment Guidelines following consideration by the Board of recommendations to be set out by the Guidelines Review Group.

Recent surveys show that CRI can be successful, with improvements over the last few years reducing downtime considerably. But as mentioned previously, CRI may not be a suitable option for all drilling situations, particularly exploratory and deepwater drilling. The applicability of this technology needs to be evaluated and compared by cost-benefit to other options on a case-by-case basis.

Marine Transport and Onshore Disposal3.3

The various options for onshore treatment, recycling and disposal of drilling wastes are described in the following sections.

Marine Transport 3.3.1

If drilling wastes are not handled onsite either via discharge or re-injection, they will need to be transported to shore for disposal. Consideration of the advantages and disadvantages of any onshore disposal options must also include consideration of the advantages and disadvantages of the offshore operations and transport associated with getting the drilling waste to shore.

Function and Sources of Pollution3.3.1.1

In order to get the cuttings from the drilling site offshore to a suitable onshore location, cuttings are collected into boxes and shipped to land for disposal. Handling of these cuttings will require additional personnel and equipment including either vacuum units or augers for aid in transporting the cuttings to storage or loading units. Depending upon the volumes of cuttings being generated, the storage capacity of the drilling rig or platform, and the logistics of marine transport operations, cuttings may be stored and/or transported in boxes or “skips” or in bulk containers. Frequently the operation of hauling cuttings to shore is referred to as “skip and ship”. Managing the logistics of the transport of cuttings with the available vessels, and available cuttings storage can be a complex task.

Once offloaded onshore, the cuttings are transported as necessary to another location where they undergo additional processing before being disposed of or recycled for alternative uses. Onshore treatment options will be discussed in subsequent sections of this document.


These operations require extensive use of support vessels to take the cuttings to a shore location. Fuel is expended by the work boats during the offshore loading and transport process, resulting in air emissions. Also disposal of waste onshore has a completely different suite of potential impacts such as contamination of groundwater.

Limitations and Developments3.3.1.2

Some of the primary limitations associated with marine transport relate to operational issues. The fundamental issue is the ability of the transport and supply vessels to keep up with the volumes of cuttings being generated through drilling. There may be limitations on the effectiveness of the marine transport option for operations that are a long distance from the shorebase and for those that have considerable weather downtime. In addition, space considerations on platforms or drilling rigs may limit the storage available for handling cuttings prior to their transport. If cuttings are being generated faster than they can be stored or transported, either drilling operations must cease, or cuttings will need to be temporarily discharged. Furthermore, this procedure requires implementation of considerable safety precautions. Also, disposal of cuttings onshore creates its own suite of problems for both companies and regulatory agencies.

With each of the onshore disposal options, there will be the same economic, operational, and environmental factors associated with the offshore handling and transport of the cuttings. These factors are summarized in Table 3.4. Table 3.4 Advantages (+) and Disadvantages (-) of Marine Transport

Economics Operational Environmental


Transportation cost can -be high for vessel rental and vary with distance of shorebase from the drilling locationTransportation may -require chartering of additional supply vesselsAdditional costs -associated with offshore transport equipment (vacuums, augers), cuttings boxes or bulk containers), and personnel. Operational shut-down -due to inability to handle generated cuttings would make operations more costly.

Increased handling of waste is -necessary at the drilling location and at shorebaseAdditional personnel required-Risk of exposure of personnel to -aromatic hydrocarbons is greaterEfficient collection and transportation -of waste are necessary at the drilling location Waste containers must be loaded on -workboats offshore and sent to shore creating safety hazardsThere are safety hazards associated -with offloading waste at the shorebase may be difficult to handle logistics of cuttings generated with drilling of high ROP large diameter holes Weather or logistical issues may -preclude loading and transport of cuttings, resulting in a shut down of drilling or need to discharge.

+ Waste can be removed from drilling location eliminating future liability at the rig site

+ Beneficial in environmentally sensitive areas offshore.There will be fuel use -and consequent air emissions associated with transfer of wastes to a shore base. There is an increased risk -of spills in transfer (transport to shore and offloading) Disposal onshore creates -new problems (e.g., groundwater contamination)Option results in -environmental burden shifting

Factors Affecting Use of the Technology3.3.1.3

If this option is not selected it is typically for the following reasons:

High transportation costs for getting cuttings to a shore base; these costs may be •prohibitive for remote, deepwater applications;Safety and environmental risks associated with transporting cuttings to shore, •particularly in areas prone to inclement weather;Operational issues with handling large volumes of cuttings with high ROP drilling and •with risk of shutdown due to inclement weather; andProblems associated with treatment of wastes onshore.•

Global Experience3.3.1.4

Operators in the North Sea, the Gulf of Mexico, and eastern Canada, where technically and economically feasible or, where regulations prohibit discharge, may ship their cuttings to shore for disposal. Presently SOEI is shipping cuttings to shore in Nova Scotia due to limits on the discharge of SBM cuttings as of January 1st, 2000.

Landfill Disposal 3.3.2



A landfill is an engineered waste burial site that is designed to prevent loss of content and may be lined to reduce the potential that leachate will migrate to the subsurface. Landfills are often divided into individually lined segregated "cells" The separate cells may contain different types of wastes. Wastes may be covered periodically with low permeability soils, drilling mud solids and cuttings or other similar material. When closed, a landfill may be covered with an impervious cap and may be revegetated. During operation of a landfill rainwater may enter the landfill and some liquids may be disposed. These liquids may "leach" or accumulate hazardous constituents. The resulting liquid (called leachate) typically migrates to the bottom of the landfill. If installed, a leachate collection system removes this liquid from the landfill. The transport of waste to the landfill site may be a primary source of air pollution. Also, there is potential, if not properly contained or collected, for leachate to migrate into ground water or surface waters.


Unlike many of the other onshore disposal options, landfilling does not destroy contaminants and it only prevents their migration if special provisions are made. Consequently, this disposal solution may not be permanent. There are few limitations on the type of waste that can be contained, as long as it will not interfere with the materials of construction. Also, many landfills are constructed specifically for the disposal of certain classes of wastes. A landfill designed to receive industrial wastes will have a more elaborate containment system than a landfill designed to receive municipal waste. Regulations will vary with the site location and the type of contaminants to be contained. This technology may not be acceptable in some areas since the contaminants are not treated and remain on site.

While this process may satisfy waste disposal requirements, limitations on landfill space or restriction on landfill may not make it a viable disposal option. The advantages and disadvantages of landfill disposal are listed in Table 3.5.

Table 3.5 Advantages (+) and Disadvantages (-) of Landfill Disposal



- High disposal cost per unit volume

- Transportation costs are high if a suitable landfill is not close to shore base

- Future liability can be expensive if land fill has to be cleaned up

- Leachate detection and collection systems, pit liners, long term monitoring are needed for the landfill.

- Limited number of suitable landfills available

- Safety issues associated with transport of cuttings from shorebase to landfill

+ Waste can be removed from drilling location eliminating future offshore liability

- Potential for leaching contaminants into groundwater is higher in a secure landfill than a remote offshore location

- Waste removed from remote offshore location transferring potential future liability to high profile onshore facility

- No removal or stabilization of heavy metals, salts or hydrocarbons

- Little or no control over what other waste is placed in the landfill

- Landfill disposal for all types of waste is being phased out reducing capacity

- Increased transportation and handling results in air emissions (both from equipment used and volatiles from waste) and spill risk

Management of Performance and Impacts3.3.2.3

The ability of a landfill to contain waste and leachate may require regular monitoring of air emissions and groundwater to verify that leachates are not escaping from the containment area.

Factors Affecting Use of the Technology3.3.2.4

Typically, landfills are selected when no other viable option meets local disposal requirements. Using this technology offers a simple, fixed short-term cost that meets local discharge requirements. Although this option may be available in many areas, the distances from the shore base can be extreme, resulting in high transportation costs. In some regional drilling operations, the incremental liability of continued use of a landfill is less than the liability of initiating use of a new disposal technology. When this technology is not selected it is typically for one of the following reasons:

realization of eventual liability;•transportation cost;•disposal cost at the landfill; and•sensitivity to public perception.•


Onshore landfill sites have been developed in areas of significant drilling activity. In others,


service providers offer a combination of waste collection, transportation, treatment and disposal. In the more remote and less developed areas, appropriate landfill areas have not been developed, thereby resulting in extended hauling distances. In Alaska’s Cook Inlet, for instance, the US Environmental Protection Agency (EPA) recognized that the lack of appropriate landfills and the hazards of offloading wastes in winter conditions justified ocean discharge. In the Gulf of Mexico and the North Sea, dedicated landfills are available. In other areas that have significant industrial activities, such as Western Australia, specialized industrial waste landfills are available. For more information on onshore management of drilling waste fluid see Leuterman et al., 1999. In eastern Canada, the two main operational bases are located in Halifax and St. John’s. In Halifax, a refinery and other petrochemical processing plants require an industrial waste landfill. Consequently, drill cuttings, mud, and waste brought to the facility can be treated and disposed close to the shorebase. Conversely, since there is less industrial activity in St. John’s, no nearby industrial landfill is available. Drill cuttings and mud are separated into both their non-hazardous and recyclable components by local companies. The non-hazardous components are then dumped in the local non-secured municipal landfill site at Robin Hood Bay, St. John’s. Accordingly, any disposal of treated wastes into the St. John’s municipal landfill must meet content limitations, since the facility does not have a containment system designed for industrial waste (T. Matthews, pers. comm).

Biodegradation Technologies 3.3.3

Many organic compounds present in drilling wastes may be biodgraded to carbon dioxide and water using natural biologic processes. Limitations in the natural biodegradation of constituents may be overcome by optimizing biological conditions. Conditions are optimized when the following are controlled: supply of hydrocarbon degrading bacteria, oxygen, nutrients, moisture content, temperature and pH, and salinity.

Two of the primary technologies which use biodegradation to breakdown wastes (land treatment and composting) are discussed below. Although bioreactors may also be used, they are not discussed herein. Land treatment serves also as a disposal option. Whereas composting converts the waste to a less harmful product for subsequent use or disposal. Rates of biodegradation are higher for bioreactors and composting, than for land treatment.

Land Treatment 3.3.4


Land treatment (also sometimes referred to as landspreading (refers to a one time


application) or land farming) is a process in which waste is spread evenly over a treatment area and tilled mechanically with native soil. The primary process involved is biodegradation, however significant volatilization may also occur. Tilling of the soil allows faster biodegradation of hydrocarbons, and nutrients and/or water are added to further enhance biodegradation. The mixture may be tilled periodically to aerate the soil, and additional nutrients or waste added if required. The size of the area required depends on the volume to be disposed and the concentration of constituents. Depending upon the site location a liner, overliner, and/or sprinkler system may be necessary. A Utah State study (Miller, 1975) and subsequent studies in Canada suggest land treatment offers an excellent opportunity for effective management of drilling wastes (Leuterman et al., 1999).

Potential sources of pollution from a land treatment include air emissions from the equipment used to spread and till the waste and from volatilization of hydrocarbons from the wastes, leaching of contaminants to surface waters and into groundwater, and residual concentrations of contaminants in the mud that become incorporated into the soil. Fertilizer runoff can be a problem if calculations regarding proper application quantities are not done properly.


The primary limitation of land treatment is the availability of appropriate areas. In those regions where large areas of appropriate land exists, such as Alberta, land farming has become a viable alternative to landfill disposal. The more heavily populated areas or those with rocky surfaces are not applicable for land farming. However, in cold climates where the ground freezes, employment of land treatment will be limited to those months of the year when the ground is not frozen.

Biodegradation rates depend on the site conditions (temperature, constituent concentration, aeration, nutrients, etc) and the type of hydrocarbon to be degraded. Wastes with high concentrations of oil, salt or metals may inhibit microbial activity and make the process less effective.

Local regulations may also restrict the applicability of this technology. Some areas may regulate the distance from groundwater of the site, dictate the maximum values of oil, or salt that may be applied, and require a liner. Permits to cover air emission, water quality, local land use, and health may also be required.

Land treatment may negatively impact soil productivity. Historically, calcium chloride was used as the internal phase of drilling muds and incorporating large concentrations of this salt into the land inhibits plant growth and lowers soil productivity. The issue of salt


contamination has since been addressed by using other internal phases such as calcium nitrate, which instead of inhibiting soil productivity, acts as a fertilizer. Additional advances in drilling mud formulations are anticipated to continue the trend of developing mud systems that act as soil enhancers instead of soil contaminants. Consequently, while land treatment is viewed as a waste management technique, as the technology develops, its use may evolve more into using drilling wastes as soil enhancers, thus moving from the disposal aspect of waste management to the recycling/reuse aspect of waste management.

Finally, there have been instances of local residents complaining about smells from and health problems related to a nearby land treatment facility. Such issues could limit the application of this technology in certain areas.

The advantages and disadvantages of land treatment are listed in Table 3.6.

Table 3.6 Advantages (+) and Disadvantages (-) of Land Treatment Technology

Economics Operational Environmental+ Waste treatment is

inexpensive relative to other technologies

- Transportation costs will vary with distance from shore base to land farm

- Potential future liability cost of surface and groundwater impacts

- Requires long term lease of land from landowner

+ Simple process with little equipment needed

- Possible operational and safety issues associated with transport to land farming site

- Limited use due to lack of availability of and access to suitable land

- Use limited to times of year when the ground is not frozen

- Time to break down hydrocarbons is variable (60 days to 4 years)

- In some cases, waste must be transported long distances to a suitable location

+ Dilution of salts and heavy metals+ Biodegradation of hydrocarbons+ Well accepted practice in many

areas- Regulations can be prohibitive- Runoff water in areas of high

rainfall can cause surface water contamination

- Shallow water table in some areas allows groundwater impacts

- Increase in waste volume if future clean up is required


- Environmental burden shifting from offshore to onshore

Measurements of Performance and Impacts3.3.4.3

A combination of chemical and biological indicators can be used to measure the effectiveness of land treatment. Typical chemical indicators are hydrocarbon concentrations, heavy-metal concentrations and electrical conductivity. Biological indicators include seed germination, root elongation and earthworm toxicity. In addition to


the advances in drilling mud components, some areas have developed commercial land farming operations that employ pit liners, leachate collection systems and other engineering controls to further improve the safety and performance of a land farming operation. The level of pollution containment possible with land farming technology ultimately depends on controlling both the constituents being land farmed and the parameters of the operation (the degree of fertilization, aeration, application of collection systems, etc).

Factors Affecting Use of Technology3.3.4.4

When this technology option is selected, it is usually because it is a very low-cost waste management technique that meets waste management and cleanup criteria requirements. Properly managed, land farming can be an excellent waste management technique for drilling muds and drill cuttings. When this option is not selected it usually is for one or more of the following reasons:

local regulations prohibit the waste management option;•lack of available land;•inappropriate climate conditions or topography;•contaminants from the formation generated by the drilling operation exceed safe limits;•sensitivity to long-term liability of untreated constituents that are land farmed; and•sensitivity to potential surface and groundwater contamination.•


Land treatment technology is applied worldwide, including areas such as West Texas, Venezuela, Western Canada, and Louisiana. Land farming of offshore drilling wastes in eastern Canada has not yet been attempted. Lack of available land, rockiness and lack of topsoil, frozen ground, long hauling distances, and concerns over residual soil productivity are combining to pose significant barriers to land farming in eastern Canada. For more information on land-based waste management and guidelines see Leuterman et al., 1999 and E&P Forum, 1993b.

Composting 3.3.5


Composting is a process in which wastes are mixed with bulking agents (wood chips, manure, leaves, rice hulls, etc) to enhance aeration and microbial numbers, placed in a pile,


and aerated. The mixture may be tilled periodically to increase aeration, and additional nutrients or moisture added as required. As with land treatment, the primary process acting is biodegradation. However, with composting the combination of placement of the material in a pile and addition of the bulking agent results in high temperatures in the pile which act to further increase the biodegradation rates and metabolic activity of the microbes as well as volatilization of hydrocarbons. The technology serves as a viable alternative to land treatment in situations where space is limited and where climatic conditions preclude year-round use of land treatment. The high temperatures generated in the pile allow biodegradation to continue even in cold climates.

Potential sources of pollution from a composting include air emissions from the equipment used to aerate or till the waste and from volatilization of hydrocarbons from the wastes, leaching of contaminants to the surface and into groundwater, and residual concentrations of contaminants in the mud that become incorporated into the soil.


Wastes with high concentrations of oil, salt or metals may inhibit microbial activity and make the process less effective. Local regulations may restrict the applicability of this technology. Some areas may regulate the distance from groundwater to the site, dictate the maximum values of oil, or salt that may be applied, and require a liner. Permits to cover air emission, water quality, local land use, and health may also be required.

The advantages and disadvantages of land treatment are listed in Table 3.7.

Table 3.7 Advantages (+) and Disadvantages (-) of Composting Technology



+ Waste treatment is inexpensive relative to other technologies

- Potential future liability cost of surface and groundwater contamination

- Treatment itself (disregarding land cost/rental) slightly more expensive per cubic yard than land treatment

+ Simple process with little equipment needed

+ Requires limited space and equipment

+ More rapid biodegradation than land treatment

- Limited by access to available land

+ Dilution of salts and heavy metals+ Biodegradation of hydrocarbons- Regulations can be prohibitive- Runoff water in areas of high rainfall

can cause surface water contamination

- Shallow water table in some areas allows groundwater contamination

- Increase in waste volume if future clean up is required



Measurements of Performance and Impacts3.3.5.3

Biodegradation rates will depend upon composting conditions (temperature, contaminant type and concentration, aeration, nutrients, moisture, etc). Air emissions from the composting operation need to be monitored to assure that emission control systems are not necessary. In addition, leachate from the piles needs to be tested and treated if necessary.


When this technology option is selected, it is usually because it is a very low-cost waste management technique that meets waste management and cleanup criteria requirements. Properly managed, composting can be an excellent waste management technique for drilling muds and drill cuttings. When this option is not selected it usually is for one or more of the following reasons:

local regulations prohibit the waste management option;•drilling waste contaminants exceed safe limits;•sensitivity to long-term liability of untreated constituents; and•sensitivity to potential surface and groundwater contamination.•


The petroleum industry has used composting to manage large quantities of routinely generated wastes over long periods of time. This usually requires a centralized facility and long-term management. Numerous composting projects have been successfully completed


in the United States, Canada, Indonesia, Africa, and Russia. This technology is presently being used for handling drilling waste generated from SOEI operations. For more information on composting drilling waste see McMillen et al., 1996 and E&P Forum, 1993.

Stabilization/Solidification 3.3.6


The process of stabilization involves mixing drilling wastes with a cementing agent (e.g., fly ash, kiln dust, Portland cement or silica) and allowing it to dry. Chemical interactions can range from simple absorption of liquids to complete encapsulation changing the waste material to a stable powder. The cured solids can be disposed in a landfill or alternatively used as construction material. Oily drill cuttings that have been stabilized generally are buried in a lined pit and sealed with plastic.

Wastes treated by this technology are stored, not destroyed. However, the concentrations or availability of constituents of concern may be different from those of the original waste. Sources of pollution include air emissions generated by treating the solids, surface and groundwater contamination from leachate and residual concentrations of stabilized pollutants in the soil or construction material.


The primary limitations of the technology have been the negative effects of salts and hydrocarbons on the stabilized waste matrix. High concentrations of organic compounds, salts, and bentonite interfere with curing process. Hydrocarbons and salts do not interact with the matrix, because they are physically rather than chemically bound. When stabilized solids have been used as road building material, salts have leached into nearby ditches, causing plant stress and water pollution. Because many disposal regulations are written on the basis of total constituent content and not leachable constituent content, the primary benefit of stabilization (minimize leaching) is not recognized. The advantages and disadvantages of chemical stabilization/solidification are listed in Table 3.8.

Table 3.8 Advantages (+) and Disadvantages (-) of Stabilization/Solidification



+ Low equipment and labour cost

+ Reduced leaching of heavy metals in comparison to untreated solids

- Potential for future liability from heavy metals, salts and hydrocarbons that are not removed

- Costs increase if treated wastes are hauled off site to a landfill or other commercial disposal facility

+ Simple process easily adaptable at most locations

+ Very high processing rates

- Several people required to operate various phases of system

- Large space requirements including fixing material

+ Stabilization of heavy metals+ Solidified fixed waste passes current

leachate tests+ Reduces leaching rate that environment

can handle it safely- Salts, hydrocarbons and heavy metals are

not removed- Volume of waste is potentially increased - Salts and hydrocarbons weaken the

waste matrix and allow for possible leaching

- Fixing materials may have high concentrations of heavy metals

- Some applications can dry material rather than fix it


Assessment of Technology Performance and Impacts3.3.6.3

The performance of a stabilization operation usually is measured by its ability to pass leachate tests. The impacts on the degree of pollution is related to the level of protection offered by a particular combination of waste constituents and stabilization agents.


Typically, this technology is selected in conjunction with the use of non-aqueous drilling muds. Stabilization technology offers a cost-effective treatment of NAF cuttings to protect groundwater and surface water. It can also be applied in locations remote from landfill facilities. The technology also offers an immediate well-defined treatment in a short time frame with measurable endpoints. When this technology is not selected it is usually for one of the following reasons:

a lower cost waste management option was available;•a lack of available fixation reagent or excessive hauling distances for fixation reagents;•water table too close to the surface;•increased volume of waste;•waste is not suitable (i.e., high pH, oil content, salt content) of treated material;•long-term liability of treated waste; and•historical problems with quality control of fixation agents or the fixation process.•

While the use of stabilization in its current form has been declining, new possibilities are


emerging. New combinations of low-toxicity drilling muds and new fixation agents have offered the potential for generating a by-product material that could be used to restore damaged wetlands. The regulatory approvals for using this type of new stabilization technique have been slow in coming, because of the numerous layers of regulatory protection for damaged wetlands. More information about stabilization can be found in Leuterman et al., 1999, and E&P Forum, 1993.


The use of fixation technology has increased in the 1990s, primarily in the Western Hemisphere, with the highest usage in such areas as Columbia, Ecuador, Venezuela, Louisiana, Texas and the Rocky Mountains. Insofar as regulations are concerned, the Louisiana 29-B Regulation has a specific set of criteria for stabilized waste and Oklahoma has a set of criteria for stabilized wastes. While most of the “stabilize and bury” applications have been successful, there have been instances where stabilized waste material used in road building applications have occasionally generated leachate of oil and salt into the surrounding environment. Stabilization has not been pursued in eastern Canada, because the existing Nova Scotia industrial landfill will accept the waste without stabilization and the stabilization process does not qualify the waste for the municipal landfills in Nova Scotia and Newfoundland.

Thermal Treatment Technologies 3.4

Thermal technologies that have been used to treat drilling waste include thermal desorption and incineration. These technologies in this point in time have not been proven for offshore use so will be considered to be onshore treatment technologies.

Thermal Desorption3.4.1


This technology is used to treat OBMs or SBMs and their associated cuttings that contain a recoverable quantity of base mud. The process uses a dryer to heat and vaporize oil and water; the oil and water are subsequently cooled and condensed back to a liquid state. Afterwards, the liquids are separated by gravity. Ideally, the end products will be dry solids with no residual oil, water, salt, metals that can be disposed of in a landfill, fuel (resulting from cracking of the hydrocarbons), clean water, and recovered base mud.

Thermal desporption will produce various secondary waste streams. As the process does not operate with perfect efficiency, there will be salts and heavy metal constituents retained in the solid fractions of the by-products of the process that will require disposal. The hydrocarbons


recovered from the process can be recycled or reused. Some processes essentially “crack” the hydrocarbons if the temperature is too high, resulting in a product that is used for fuel, while others recycle the mud into the active mud system. Sources of air pollution include the fuel burned to heat the waste and the uncondensed vapors and dust that are released into the environment.


Cost is the primary limitation to thermal treatment technology. In addition, air quality controls must be in place. Because the process requires several operators, tightly controlled process parameters and expensive equipment, the treatment cost per metre cubed can be significantly higher than other disposal options. However, advances in design promise to move this technology toward lower costs and greater practicality. Presently offshore space and safety concerns limit the use of this technology to onshore facilities. If such technology could safely be operated safely and economically offshore they could allow recovered base mud to be immediately returned to the mud system. The advantages and disadvantages of thermal desorption are listed in Table 3.9.

Table 3.9 Advantages (+) and Disadvantages (-) of Thermal Desorption

Economics Operational Environmental- Cost of solving air

pollution and safety problems is high

- Initial cost of the equipment is high

+ The technology is mature+ Processing rate is high with a

relatively small machine- Multiple operators required- High operating temperatures (900 F)

can lead to explosion and fire (safety considerations)

- Vaporized oil and water are a flammable, explosive mixture.(safety considerations)

- Large volumes of vapors generated are difficult to condense.

- Long cool down time before maintenance can be performed on drier

- High temperature and CaCl2 lead to high corrosion rates

- Processes have reliability problems- Some cracking of hydrocarbons may

occur

+ Effective removal and recycling of oil and grease from solids

- Heavy metals and salts are concentrated in processed solids

- Processed water retains some emulsified oil

- Potential for elevated levels of metals, fluorides, chlorides may cause pose problems with air emission controls

- Air emissions from process may contain hydrocarbons

- Public perception of incineration has generally been unfavorable.

Measurements of Performance and Impacts 3.4.1.3


The methods developed for achieving the three basic steps of this process (vaporization, condensation, separation) determine how the unit performs economically, operationally and environmentally. Each of the waste streams: solids, water condensate, oil condensate, and air stream may require analysis to determine its characteristics so that additional treatment may be implemented if necessary and that the best recycle/disposal option can be chosen. If necessary air control measures may be implemented to capture certain constituents.

Factors Affecting Use of Technology3.4.1.4 Typically, this technology is selected in conjunction with the use of non-aqueous drilling muds. When this technology is not selected it is usually for one of the following reasons:

high costs; a lower cost waste management option was available;•concern over air emissions; and•safety concerns.•


The technology has been used in Venezuela, Ecuador, Kazakhstan, Canada and the US, where it is selected primarily for its capacity to immediately recover base mud for reuse in a mud system. Typically, the technology meets residual oil requirements in the remaining solids and is well understood. As mentioned, cost is the primary factor limiting its selection. High usage rates are required to remain competitive with other OBM treatment technologies. Furthermore, numerous experimental units have experienced operational problems, which have caused the technology to suffer an undeserved reputation of being unreliable or unsafe. The future of thermal desorption units will be driven by regulatory development and the availability of other treatment options. Because this technology offers a recycling option, it should perform well in a side-by-side overall comparison with other management options. More information on the use of thermal treatment technology can be found in Leuterman et al., 1999, and E&P Forum, 1993.

Incineration3.4.2


Incineration, which is often confused with thermal desorption, uses very high temperatures to destroy organics and remove all water from drilling waste. Combustion consumes/destroys the oil component of the waste. Solid/ash and vapor phases may be generated. The type of


incinerator best suited for handling drilling wastes is the rotary kiln; which tumbles the waste to provide extensive contact with hot burner gases. The gases produced from the rotary kiln pass through an oxidizer, wet scrubber and bag house before being vented to the atmosphere.

If the incineration is not optimized for the waste fed, incomplete combustion of the hydrocarbons in the waste may produce PAHs or formaldehyde in the waste gas stream and particulates in the exhaust gas, and ash from the incineration of solids, may contain high levels of metals, uncombusted hydrocarbons, or PAHs formed. Stabilization of residual materials may be required prior to disposal to prevent constituents from leaching into the environment.

Limitations and Developments3.4.2.2 Waste characteristics which may require special consideration when choosing disposal methods for residual solids or control measures for air emissions are metal or salt content, and the presence of regulated compounds in the form of residual oil, uncombusted hydrocarbons, or combustion products (e.g., PAHs).

The advantages and disadvantages of incineration are listed in Table 3.10.

Table 3.10 Advantages (+) and Disadvantages (-) of Incineration

Economics Operational Environmental+ Low potential for

future liability- High cost per barrel- Energy costs high - Potential transportation

costs- High labour costs- High initial cost of

equipment

+ The time required for incineration is relatively short

- Transportation of waste from the shorebase to the incinerator may be required

- Several operators required to run incineration equipment

- Process requires several pieces of air pollution equipment

- Safety concerns dealing with high temperatures on location

+ At high temperatures materials can be transformed in glass-like slags that prevent heavy metal leaching

+ Destruction of hydrocarbons+ Reduction in volume of waste- Need to dispose of residual

solid/ash- At high temperatures salts can

transform into acid compounds- Air pollution can be a problem- Public perception of incineration

has generally been unfavorable.

Measurement Performance and Impacts3.4.2.3

Depending upon the waste type, solids and vapors from the incinerator may need to be tested for metal and/or PAH content.



When this technology is not selected it is usually for one of the following reasons:

high costs; a lower cost waste management option was available;•concern over air emissions; and•safety concerns.•


Owing to its prohibitive cost, incineration is a rarely used option in the Western Hemisphere for treating and disposing of drilling mud cuttings. When it is selected, the reasons are usually because it is the only available viable option. This option has been used recently to dispose of some of the drilling wastes generated from SOEI operations. More information on incineration technology can be found in Leuterman et al., 1999 and E&P Forum, 1993.


Other Waste Management Technologies3.4.3

There are other lesser-used and in some cases unproven waste management and disposal technologies, which have been promoted by various vendors for use offshore. These include:

Solvation. This on-site process uses a solvent to remove the synthetic mud or oil from •cuttings. The contaminated solvent must be sent to shore for disposal.Silicate Encapsulation. This on-site process involves treating the cuttings with •silicates to encapsulate or “seal off” the oil or synthetic mud before discharge overboard. Over a long period of time, however, the silicate shells may break down, resulting in a slow release of the oil or synthetic fluid to the environment. Due to the dispersion and slow release, it is anticipated that the very small amounts of oil or synthetic fluid released gradually over time would readily biodegrade through natural mechanisms and would not cause anaerobic conditions on the seafloor.Briquetting. This on-site process grinds up the cuttings, adds binding material, then •forms the ground cuttings into briquettes that are dumped overboard.Hammermill: A new technology, the “Hammermill” process is presently being used •for treatment of contaminated cuttings onshore in the UK. In this process, the hammermill receives contaminated cuttings and mud from the drilling operations. The material is treated by frictional grinding of the feed in a sealed chamber such that sufficient heat is generated to flash evaporate both oil and water, leaving the dry powder oil-free (less than 0.1%). The powder is discharged through a rotary valve in the base of the chamber. The vapor stream passes into a cyclone where remaining powders carried over by the vapor are separated out and collected with the discharged powder from the chamber. The vapor is condensed in two stages so that oils and waters can be collected for re-use and discharge, respectively. The operating temperature is 270-290 degrees Celsius. This process is unique in that no combustion occurs in this process. All vapors that remain after condensation are fed by pipeline into the water transfer tank. The water is then filtered and treated, if necessary, before disposal.

There are plans to implement this technology offshore in the UK in early 2001. The consequent discharged powder would be similar in grain size to barite, and would disperse similarly to WBMs. Consequent accumulations would be expected to be negligible, and biodegradation rapid due to the low hydrocarbon content and aerobic conditions. Presently the technology is limited by capacity to process large volumes of cuttings.


ENVIRONMENTAL MANAGEMENT PROCEDURES AND TOOLS 4

As outlined in Chapters 2 and 3, the oil and gas industry has made tremendous strides in its commitment to strike a healthy balance between operational efficiency and environmental stewardship in recent years. Improvements in drilling technology and fluids have significantly reduced environmental impacts from those of the days when large quantities of diesel–based muds were discharged. Improvements in operator and regulatory policies have ensured that the environmental performance of chemicals discharged offshore has been thoroughly assessed before permission for use is granted to the operator.

This chapter will review various policies, procedures and tools which regulators and operators use in their evaluation of disposal options for drilling muds. Initially, a brief explanation of Environmental Management Systems (EMS) is provided, followed by an outline of environmental assessment approval process, environmental compliance monitoring (ECM), and environmental effects monitoring (EEM). A discussion of the environmental issues related to drilling discharges is next, and an introduction to some of the tools in EEMs, ECM, and regulatory approvals used to predict, assess, and minimize impacts from drilling discharge ends the chapter. This chapter is intended to provide an overview of subsequent chapters that deal in depth with drilling waste and the environmental impacts of drilling discharges. Subsequent chapters will review and report on data from laboratory studies, field surveys and environmental effects monitoring programs performed world wide, and specifically on the east coast of Canada.

In Canada, there are many checks and balances to ensure that environmental impacts of oil and gas operations are minimized and that changes can be made to operations if impacts are found. First a project undergoes an extensive approval review process. Secondly all chemicals used for offshore discharge must be approved for use under the OCSG. Thirdly compliance of operations are monitored and reported through an ECM, and finally the EEM provides feedback on potential environmental changes that have occurred since the commencement of operations.

There are a variety of environmental issues relating to the marine discharge of cuttings coated with NAFs. These issues include the following:

fate, persistence, and biodegradability of NAF associated with cuttings accumulation;•bioaccumulation in marine benthos;•toxicity to marine benthos;•smothering of marine benthos; and•organic enrichment and sediment anoxia in seabed sediments.•


The primary tools available to evaluate the environmental behavior of NAFs and their potential impact on seafloor biota are laboratory testing, computer modelling, and field studies. This chapter introduces these tools, discusses their advantages and limitations, and how the information gathered from each of them may be used together in evaluating the potential impacts from discharging NAFs.

Chapter 5 provides additional detail on the results of laboratory testing and conclusions reached regarding the environmental behaviour of drilling fluids. In some parts of the world, development of appropriate laboratory tests and the results from these tests has been part of the basis for regulating the discharge of NAFs associated with cuttings. Chapter 6 provides additional detail on what is known regarding the fate and effects of NAF (and WBM) cuttings discharges through computer modelling and field results.

Although laboratory studies provide a very useful tool for evaluating potential environmental impacts of offshore discharges, they have a number of limitations. In many cases testing substances under tightly controlled laboratory conditions generates repeatable results. Yet, these controlled conditions may not reflect actual field conditions and thus laboratory artifacts may be generated. For example, laboratory testing on the toxicity of drilling fluid to sediment dwelling organisms has resulted in highly variable results. Field monitoring studies are often used to evaluate actual environmental performance. However, data from field monitoring programs are not without problems either. Field data can also be highly variable due to natural spatial and temporal variation of nearly all environmental parameters (e.g., temperature, grain size, benthic abundance) and thus field studies require more careful and detailed interpretation. In order to improve the ecological relevance, repeatability or ability to detect change, laboratory studies are often modified to address a particular waste stream or receiving environment. For example, actual bottom temperatures and sediment types may be replicated in the laboratory for biodegradation testing.

The challenge in laboratory testing is achieving a balance between maximum repeatability and maximum relevance to the receiving environment. One may be able to achieve 100% repeatability, but the test results may have no environmental relevance. While mesocosm studies (indoor or outdoor tanks used to simulate nautical seabed and water conditions) may be useful in bridging the gap between laboratory results and field conditions, the high maintenance requirements and resulting high costs have minimized their use as regulatory tools.

Environmental Management Systems4.1

An Environmental Management System (EMS) is a set of guiding principles that govern


all operations of a facility. The EMS is that part of an overall management system which includes organizational structures, planning activities, responsibilities, practices, procedures, processes and resources for developing, implementing, achieving, reviewing and maintaining the environmental policy of a company. An EMS is usually based on the process of a Plan-Do-Check-Act cycle which complies with the intent of the ISO 14001 standard Environmental Management Systems – Specifications with Guidance for Use and involves:

Plan - planning for environmental management by establishing an environmental •policy, goals, objectives, targets, and procedures; defining roles and responsibilities and communicating through all levels of the organization;Do - implementing and operating the management system in accordance with these •policies and procedures and regulatory requirements, and providing the resources necessary to sustain the system;Check - monitoring and reviewing the system (auditing) to ensure it is functioning as •planned and taking corrective and preventative action when required; andAct - making the necessary adjustments to the system through management review. •

Designing for environmental protection is a simple philosophy that aims to reduce the potential for adverse environmental effects. This is achieved by complying with all applicable legislation and regulatory controls, meeting company standards and adopting project policies, which are integral to all phases of the development. An EMS provides for continual improvement of a company’s environmental policy in response to changing internal and external factors, with the objective of improving the overall environmental performance of the company.

Environmental Assessment4.2

Environmental assessments (EA) are a part of the planning stage of an EMS and are used worldwide to determine the potential impacts of operations, in this case drilling waste disposal. Using results of laboratory tests, dispersion modelling, and impact prediction, a site-specific assessment is conducted on the potential for the surrounding environment to be impacted by the operation. Specific environmental receptors are identified for assessment based on ecological or socio-economic value. Dispersion models use physical and environmental parameters to mathematically model the potential fate of drilling wastes in the area surrounding the point of discharge and are an effective assessment tool.

Environmental assessments consolidate environmental concerns early in the planning stage of a project so that significant concerns are addressed before the project is approved. Relevant literature from primary research and previous monitoring programs is reviewed to identify any potential impacts and how they may be mitigated. Examination of lessons


learned from previous projects promotes continuous improvement in the quality of environmental assessments.

Existing literature on the condition of the environment and exactly how it will react to the project operations is sometimes sparse. However, computer models are often applied to predict the fate and effects of drilling waste discharge and EEM programs are used to validate these predictions. Unfortunately, considerable time and data are required before the model predictions are validated.

Traditionally, the environmental impact of drilling fluid discharge into the marine environment has been evaluated using criteria developed from laboratory tests, modelling and impact prediction. It has been suggested that the evaluation process include potential impacts associated with disposal alternatives. A more holistic or life-cycle approach to assessment would consider potential impacts associated with land-based disposal for instance, transportation risks, air emissions, and potential for ground water contamination.

One example of a life-cycle approach is Life-Cycle Value Assessment (LCVA) which is an environmental assessment tool that integrates all aspects of the use of a product or process and its impact on the environment. The analysis includes developing a model that identifies and assesses all potential components required to complete an activity. The value of the LCVA model is the assistance it renders in explaining the complete cycle of environmental effects and associated costs that could be realized by an activity, as opposed to looking at just one aspect. Subsequent to the environmental assessment phase of the project and in support of a condition for project approval (Condition 20), Terra Nova used an LCVA approach in the development drilling/operational phase of the project to determine the best cuttings management option. The US Environmental Protection Agency has used the life-cycle approach to determine the suitability of drilling waste discharge. They concluded that ocean discharge of SBM cuttings as compared to the potential alternatives for disposal of OBM cuttings actually reduces the environmental impact on air quality, energy consumption and oil waste volumes (USEPA, 1999a).

Computer Modelling of Drilling Discharges4.2.1

Modelling has been used by the oil industry and regulatory agencies to assess drilling discharges. Several computer models exist to predict the dispersion and initial depositional behavior of drilling fluids and drill cuttings discharged into the marine environment. These models use characteristics of the ambient environment near a discharge point and parameters of the effluent to predict the trajectory and shape of discharge plumes, the concentrations of soluble and insoluble discharge components in the water column, and the accumulation of discharged solids on the seabed.


Discharge models can be used to predict the initial aerial extent and thickness of cuttings accumulations on the seabed. This information, in conjunction with other data that are not accounted for by the models, i.e., the energy available for resuspension and transport of deposited cuttings and the efficiency of biodegradation in the particular environment, can assist in determining the acceptability of discharges associated with planned exploration and development drilling. In addition, discharge models can be used to evaluate the effects of various cuttings treatment techniques on initial cuttings deposition patterns and for designing cuttings disposal practices.

In addition to these traditional dispersion models which predict the initial fate and deposition of discharged drilling wastes, there are a limited number of more specialized models which have been used. In eastern Canadian studies, the long term fate of cuttings through sediment transport under normal and storm conditions, and the transport of suspended and resuspended flocculated material and fine particles at the seafloor/sediment water column interface (the Benthic Boundary Layer-BBL) has been predicted. Concepts and applications of these long term fate and BBL transport models are described in Hannah et al., 1995 and 1997 and Loder et al., 2000.

While modelling is a tool used to assess WBM and NAF cuttings discharges, it should be used in combination with other information to get a more complete understanding of potential environmental disturbance. Models are limited by the quality of the input data used to describe future discharge events, and most traditional models do not account for re-suspension and transport of particles after initial deposition. Re-suspension and transport of cuttings particles can be significant in high-energy environments. Of particular importance to modelling NAF cuttings discharges is data describing the fall velocities of the cuttings particles. Currently, there is a limited amount of information in the literature describing the fall velocities of drill cuttings generated with non-aqueous fluids. Although research is underway to address this need, no published data on the fall velocity of cuttings produced with SBM currently exist.

As discussed later in Chapter 6, field studies have found that cuttings accumulations tend to redistribute and disperse in high-energy environments. If re-suspension and transport of cuttings are not considered when evaluating the acceptability of a drilling discharge, the model might predict that unacceptably large cuttings piles will be generated, when, in fact, strong currents near the seabed might cause cuttings accumulations to rapidly dissipate.

Drilling Fluid Approval Process4.3

Predictive testing and acceptance criteria are put in place to ensure the exclusive use of


chemicals that have met health and safety, environment and facility requirements and have passed screening and risk assessment processes. These guidelines apply to the selection and use of all chemicals used for offshore drilling and process-related activities that may potentially be discharged into the marine environment.

An example of a system for predictive testing and acceptance criteria used on Canada’s east coast is an offshore chemical management system (OCMS) called the OCSG, developed jointly by industry and government departments under the auspices of a committee co-ordinated by the C-NSOPB (NEB et. al, 1999). This system has been published as an interim guideline by the C-NSOPB for a trial period ending in 2000 with an effectiveness review to take place through the same committee in preparation for issuing a formal guideline. The OCSG is discussed in more detail in Chapter 7.

Individual operators apply the OCSG at a minimum to all bulk production and drilling chemicals that have the potential to enter the marine environment as a result of their operations. The system requires that chemicals be evaluated against a set of criteria in a stepwise fashion in the context of their proposed use pattern, such that the least potentially toxic chemicals are chosen for use offshore. This screening process is applied before chemicals are shipped offshore for use.

The screening criteria are a blend of relevant Canadian regulations, criteria developed under the Oslo and Paris Commissions for use in the North Sea and toxicity testing as appropriate. Under circumstances when little information is available, or the situation demands that a chemical with risk of significant toxicity is unavoidable for a particular application, the system makes provision for a hazard analysis and consultation with government. Hazard analysis may require tests for:

bioconcentration/bioaccumulation; •biodegradation;•chemical degradation;•adsorbability;•fate; •aquatic toxicity (Microtox™, plant, invertebrate or fish); and•sediment toxicity.•

This kind of screening and decision system has the advantage of being a pro-active process that has as its stated objective to minimize the risk of discharge of potentially toxic substances to the ocean. It directly promotes the use of the most environmentally benign chemicals. It is also an industry driven system that is open and transparent to regulatory audit. The overall effect of this system is to minimize the environmental effects of


discharges of chemicals from offshore operations.

Notwithstanding the above-noted benefits, a chemical management system may have the effect of limiting the introduction of new even more environmentally acceptable substitutes because of the process required to gain approval for new chemicals. It also focuses on individual chemicals and does not normally take into account synergistic interactions between chemicals that may either enhance, or reduce, environmental effects. In addition, the results of the screening and decision process are only as good as the information available on the chemical in questions and any longer term implications may only be verified by compliance or even longer term effects monitoring programs.

Environmental Compliance Monitoring 4.4

Environmental Compliance Monitoring (ECM) ensures that effluent discharges during drilling and production conform with regulatory standards and design specifications. ECM programs may encompass the monitoring of all effluent streams to determine the concentration and/or quantities of specific elements, compounds and their compliance with regulated levels. ECM is often referred to as “end-of-pipe” monitoring, including reporting of dose characteristics - concentration and exposure. Reporting of ECM results can be required on a daily, weekly, monthly or annual basis. ECM programs may be required and can be developed for all discharges and emissions, whether they are to the ocean, watershed or airshed.

Compliance monitoring will serve as the main tool that allows the operator to check performance efficiencies of mitigative measures used on the drill rig or production platform (e.g., drilling solids treatment, drainage treatment). Analysis of compliance monitoring data will permit the operator to identify problem areas in a timely manner in order that appropriate corrective measures can be undertaken to protect the environment. ECM also provides data that can be used in the design and interpretation of an EEM program. The ECM data may also be useful to validate predictions made during the project approval stage.

An ECM program can be very useful for those compliance tests that provide near immediate results so that operational modifications can be made if a problem with the discharge is identified (e.g., non-compliance with regulatory limits). The data from an ECM program may also be used to validate discharge concentrations estimated during the project’s environmental assessment. The database complied during an ECM program may be used to better understand factors influencing variability in the composition of a discharge. The range of time required to obtain results varies. Some basic compliance test (such as


the static sheen, cuttings retention) can yield results in hours or days, whereas others may take longer (toxicity tests, analytical tests for oil and grease). For example, results from chemical and toxicity testing of samples taken from the discharge and sent to the lab may take several weeks. If a discharge is non-compliant, corrective action is therefore delayed. Consideration must be given to the fact that lab conditions may not reflect the environment into which the discharge is released.

Environmental Effects Monitoring 4.5

An Environmental Effects Monitoring (EEM) program determines and quantifies deleterious effects to the receiving marine environment resulting from the operational discharges of a production facility. In some cases much less extensive programs may be implemented for single wells. The EEM program provides feedback to operators for use in operational decision-making, as well as to regulatory authorities, stakeholders and other members of the interested public.

The objectives of an EEM program are to confirm effects predictions made in an environmental assessment, provide an early warning of potential impacts, provide information for modifications to operational practices and procedures, and provide the basis for technological improvements.

Regulatory agencies in some jurisdictions require environmental effects monitoring programs in order to monitor the effects of offshore oil developments on receiving environments. As most effluents produced during offshore exploration and production activities (e.g., produced water, deck drainage, sanitary, drill cuttings) are released to the marine environment, EEM programs tend to focus on marine receptors.

The monitoring of marine receptors provides an early warning of problems that allows for corrective action in operations, if required. An EEM program also allows for comparison of effects and recovery rates with those predicted by modelling and laboratory tests during the assessment of the project.

Due to natural variability however, several years of EEM data are usually required before an impact is detected. Likewise, it is often experimentally difficult to establish a cause and effect relationship due to naturally occuring spatial and/or temporal variability. In order for the EEM program to be functional then, many sampling stations must be monitored, which is very expensive.

EEM programs can include sediment quality, benthic community analyses, fish body burden and taint testing. In the US, once regulators have established that the best available


technology standards and the water quality standards have been met there is no continuing requirement for EEM monitoring. The Canadian programs have learned from EEM programs elsewhere and adopted the most effective indicators to include in local monitoring programs. Canadian programs include additional site-specific, and in some cases unique, attributes such as benthic boundary layer, noise and effects on marine mammals and seabirds studies. In Canada, stakeholders are involved in all stages of the EEM design process, and the Boards and federal and provincial agencies have reviewed and approved where appropriate, all offshore EEM programs. Table 4.1 outlines the parameters tested in Canadian east coast EEM programs.

Table 4.1 EEM Monitoring Parameters Associated with Canadian EEM Programs

Monitoring ParametersCanadian Offshore Oil Operations

Hibernia Terra Nova SOEISediment QualityPhysical/Chemical Yes Yes YesBenthic Communities No Yes YesSediment Toxicity Yes Yes YesBenthic Boundary Layer Yes (by others) No YesBiota QualityBioaccumulation and Body Burden Yes Yes YesTaint Yes Yes YesFish Health No Yes NoNoise & Marine Mammals No No YesSeabirds No No YesWater QualityPhysical/Chemical/Biological No Yes No

Environmental Issues4.6

There are a variety of environmental issues relating to the marine discharge of cuttings coated with SBM's. These issues include the following:

fate, persistence, and biodegradability of SBM associated with cuttings •accumulations;toxicity to marine benthos;•bioaccumulation and depuration in marine benthos;•smothering of marine benthos; •organic enrichment and sediment anoxia of seabed sediments; and•


physical characteristics of receiving environment.•

The tools available to evaluate the environmental behaviour of SBM’s and their potential impact on the seafloor biota are laboratory testing, field experiments, and computer modelling. Computer modelling was discussed earlier in this section. The tools of laboratory testing and field monitoring programs will be discussed in Section 4.7.

Summary of Specific SBM Environmental Issues4.6.1

This section discusses how SBM cuttings behave after discharge into the ocean (based on field, laboratory, and computer modelling results), and the environmental issues associated with such discharges. Where possible, comparisons have been made with WBMs. Information on the local biota in the area of interest, in conjunction with other data-such as the potential aerial extent of deposition and thickness, the potential for re-suspension and transport, and the efficiency of biodegradation, can be used as part of the framework for developing discharge criteria.

Fate: The physical (aerial extent and thickness) and chemical characteristics of cuttings depositions will depend upon the local oceanographic conditions (including water depth and currents), quantities of cuttings discharged (in particular whether they are from single or multiple wells), amount and concentration of SBMs on cuttings, and fall velocity of the cuttings particles. When discharged into the sea, SBM and OBM cuttings do not tend to disperse like WBM cuttings do unless the fluid retention values are below 5%. Due to the fact that NAF particles are not water miscible, they tend to aggregate, resulting in rapid fall velocities. Due to the rapid fall velocity, NAF cuttings tend to fall through the water column faster, be deposited in smaller areas, and to accumulate in higher concentrations near the discharge point than would WBM cuttings. On the other hand, fine suspended solids in WBM and WBM cuttings are not trapped in agglomerations like fines associated with NAF cuttings. This allows these fines to disperse in the marine environment and travel farther than fines in NAF cuttings before contacting the seabed. Impacts to the water column from discharging NAF cuttings are considered to be negligible because the cuttings settle quickly (i.e., exposure times in the water column are low) and the water solubility of the base fluids is low. Water column impacts from discharging WBMs are considered low as well due to their rapid dispersion from the point of discharge.

In shallow and/or low energy coastal environments, the initial deposition of NAF cuttings will be more confined in area than would occur at deeper depths. Consequently, in shallower waters the initial thickness of cuttings deposition and concentrations of sediment hydrocarbons and/or metals may be higher than for deposition in deeper waters. However, as discussed in the next paragraph, once NAFs are deposited, those cuttings deposited in


shallower water tend to biodegrade more quickly, and disperse more readily due to bottom currents and disturbance from biological activity.

Persistence: Once cuttings are deposited, the physical persistence of the cuttings and elevated NAF levels will depend upon the natural energy of re-suspension, transport on the seafloor, and the rate of biodegradation of the NAFs. Duration of benthic community impact is directly related to the persistence of NAFs and associated hydrocarbons in the sediment. Field studies indicate that for NAF cuttings discharge, the areas that recovered the most rapidly were those where bottom conditions were active. Due to the tendency for adhesion between cuttings containing residual NAF’s, resuspension of NAF cuttings requires higher current velocities than those required for cuttings drilled with WBMs. Laboratory tests suggest that the threshold current velocity at the seafloor required for erosion of NAF cuttings with fluid retention values of 15% may be as high as 30 cm/s (Delvigne, 1996).

It is more likely in shallow rather than deep waters that bottom currents will act to aid in removal and redistribution of mud and cuttings, leading to more rapid disappearance of zones of high concentrations. Therefore, deposition in deep water may lead to broader initial dispersion of cuttings due to greater lateral transport of solids during settling, and lower initial concentrations on the seafloor as compared to shallow water deposition. Hydrocarbon persistence on the seafloor will depend on relative water temperatures and seabed currents. All things being equal, lower temperatures and lower currents will lead to longer persistence. Due to the lack of suitable current data, computer modelling studies on deposition and impact of discharging cuttings in water depths greater than 100-200 m are quite limited. Likewise, there have been few field-monitoring programs at sites in deeper water depths.

Biodegradation: Rates of biodegradation of the NAFs will depend upon seafloor conditions (temperature, oxygen availability, sediment type, NAF concentrations in sediments) as well as NAF type. Oxygen availability is a key factor in determining the rate of biodegradation. Studies have shown that degradation occurs more rapidly under aerobic conditions than under anaerobic conditions. One would expect aerobic conditions to be present on the exposed surface of cuttings accumulations and for dispersed or remobilized (either through the activity of bottom currents or biologic activity-bioturbation) accumulations.

Anaerobic conditions are likely to occur within the cuttings deposit. In general, seafloor conditions are oxygen poor and tend to be anoxic below the upper few centimetres. Consequently, the dynamics of the seafloor and the relationship between aerobic and anaerobic degradation rates has been the focus of much of the SBM research in the North


Sea and US.

Test results also have shown that biodegradation may occur more rapidly in muddy rather than sandy sediments. As the NAF biodegrades, it becomes hydrophilic and the fine particular mud solids will be released. This fine mud can be more easily dispersed by bottom currents, thus dispersing the accumulations. The extent to which this can occur will depend upon the biodegradability of the fluid. Toxicity: Studies of toxic effects resulting from SBMs have focused on the benthic community because laboratory and field observations indicate that the impacts from SBM discharges on the water column are negligible, and that SBM cuttings are being deposited near the point of discharge. As SBM retention values drop (below 5%), the discharge may behave more like WBMs and water column toxicity may be more of a concern.

Toxic effects on the benthic community include indirect chemical toxicity and toxic effects due to anoxia caused by organic loading and biodegradation. The relationship between toxicity and biodegradation has been a focus in some areas because it appears that rapid degradation can lead to more severe short-term anoxic toxic effects. In areas with active hydrodynamic conditions, chemical toxicity may play a more important role in SBM impacts than biodegradation as it will be more likely that cuttings will be spread out and will degrade aerobically (not resulting in significant anoxia). In areas with more quiescent hydrodynamic conditions, biodegradation and subsequent development of anoxic conditions may play more of a role in determining benthic effects than chemical toxicity.

Bioaccumulation: Bioaccumulation is the uptake and retention of substances which are not a natural component of the environment by organisms. Bioconcentration is the process by which there is a net accumulation of a chemical from water into an aquatic organism through uptake and depuration. Generally, SBMs are not expected to bioaccumulate.

Smothering: When drill cuttings are discharged during any type of drilling operation, (water based or NAF) benthic biota immediately below the point of discharge may be physically smothered. Recovery is dependent upon the type of benthic community, the structure and persistence of the cuttings pile, the chemical toxicity of the pile, and the availability of colonizing organisms.

Factors affecting Benthic Impacts and Recovery: The accumulation of drill cuttings may result in physical smothering of benthic organisms regardless of the nature of cuttings. In addition, initial deposition of cuttings can physically impact bottom biota by altering bottom sediment particle size, which may impact larval settling. For NAFs there is the additional factor of organic enrichment of the sediment, which can lead to


anoxic/anaerobic conditions as biodegradation of the organic material occurs. Anoxic conditions may also result from burial of organic matter by sediment redistribution. Most all SBM field studies have indicated evidence of anaerobic conditions in subsurface sediments (IBP SHE, 1999). Toxicity and bioaccumulation of fluid components could also lead to benthic impacts. However, potential for significant bioaccumulation of NAFs in aquatic species is also believed to be low due to their low solubility, and it is difficult to distinguish the effects of chemical toxicity from those of oxygen deprivation.

Recovery of the benthic community is dependent upon the type of community affected, the thickness, aerial extent, and persistence of the cuttings (due to a combination of seafloor redistribution and biodegradation), and the availability of colonizing organisms. Field studies have indicated that in the short-term, impacts from discharging NAFs can range from minor alterations in the biological community structure at moderate distances (i.e., 100s of meters) from the discharge point to near extinction of biota in local areas in the immediate vicinity of the outfall. Over the longer term, the biological communities typically recolonize the affected areas in a successional manner, with initial colonization by species that are tolerant of hydrocarbons and/or opportunistic species that feed on bacteria that metabolize hydrocarbons. As time passes and hydrocarbon loads diminish, other species return via immigration and reproduction, and the community structure returns to something more closely resembling its former state. Field studies on NAFs have shown a decrease in faunal densities and sensitive species near the wellsites, with a corresponding increase in opportunistic species.

In reality, the potential implications of seafloor impacts will depend on the sensitivity/significance of the bottom resources. Discharges in highly sensitive regions would likely need to be more restrictive than those in other less sensitive areas. Highly sensitive regions would be those of high productivity and diversity that are important feeding and spawning areas. Such areas could include coral reefs, mangroves, and fish nursery areas. Deepwater benthic communities are not as well studied as many other shallow water communities. However, studies associated with oil and gas development have significantly increased our understanding of deepwater biology.

Evaluation Tools4.7

The remainder of this chapter will introduce how each of the parameters listed in Table 4.1 are used as tools in EEM, ECM, and drilling fluid approval programs as part of evaluating the environmental issues discussed in Section 4.6. As illustrated in Table 4.1, there are a number of parameters measured as part of EEM programs. Parameters frequently chosen for offshore EEM programs are indicators of sediment quality, water quality and biota quality but are usually site specific in that they reflect sensitivities of the local environment.


Some tests like sediment toxicity for example, are conducted in the lab under controlled conditions. Tests like benthic community analysis evaluate natural conditions at the time of the survey. Emphasis will be placed on those parameters currently being monitored on the east coast of Canada.

Sediment Quality4.7.1

An evaluation of sediment quality may consider:

physical and chemical characteristics;•benthic community structure;•sediment toxicity; and•benthic boundary layer characteristics.•

Physical and Chemical Characteristics4.7.1.1

Particle size analysis (PSA) is usually conducted on sediment samples to look for the presence of drill muds or cuttings and to correlate with sediment chemistry and biology. PSA comparisons are usually made between results from the baseline and monitoring programs. A suite of chemical parameters are also monitored and compared to baseline. The list of parameters usually includes total petroleum hydrocarbons, total organic carbon, polycyclic aromatic hydrocarbons, and a suite of available and/or total metals. Detailed lists of parameters measured in the Hibernia, Terra Nova and SOEI EEM programs are provided in Appendices B, C, D, E, F and G, respectively.

Sediments are a common monitoring parameter because they provide important habitat to many species of invertebrates and fish and tend to accumulate many chemical elements from the water column. A change in the chemical and physical properties of sediment may be the first indication of an effect during a monitoring program. A well designed monitoring program is also able to delineate the spatial extent of any change in sediment characteristics. When the physical and chemical properties of sediments are analyzed along with benthic community structure, a more holistic assessment of sediment quality may be monitored.

Like all other natural parameters, the physical and chemical characteristics of the sediments may vary spatially and temporally for reasons other than those of drilling discharge impacts. For example, microorganisms may biodegrade hydrocarbons in the sediment to lower the initial concentration or a storm event may redistribute fine grain particles, changing the composition of the sediment. There is limited literature on the physiological or biological effect of changes in sediment chemistry and so usually


relationships may be inferred based on statistical analyses. As sampling and testing techniques have become increasingly more sophisticated, it has become easier to measure levels of constituents that were nondetectable with traditional methods. It is important to recognize that detection of the presence of a constituent in the sediment does not mean that biological effects have or will occur as a result.

Benthic Community Structure4.7.1.2

The benthic community structure is looked at in conjunction with sediment physical and chemical properties for indications of possible effects of drilling discharges. In multi-year programs, changes in the community over time are examined for signs of recovery following the cessation of discharges. Benthic community analysis involves identification and quantification (counts and sometimes biomass) of each organism in the sediment sample. There are several measures of whether a benthic community is healthy. These measures include abundance (the number of individuals of each species), biomass (the wet weight of each species or major taxonomic group, richness (the number of species per sample) and, diversity (the number of species and the degree of equability in their abundance). Often several of these indices are used together to assess the health of the benthic community. These parameters are usually compared to a baseline data set and an indication of a change in sediment quality is obtained through an analysis of community structure. Results from benthic community analysis can be used in conjunction with results from chemical and lab testing to provide a better interpretation of all tests results.

In order to account for the potential natural spatial and temporal variability in benthic communities, (e.g., benthic communities may be entirely different a few meters apart, and may vary seasonally), careful planning needs to be done to design a statistically valid and effective sampling program. If a program is not designed correctly it may be more costly than necessary and yield data that is not useful.

Toxicity4.7.1.3

There are two types of toxicity tests: water column and solid-phase (sediment) tests. These tests are used to assess the potential risks of drilling discharges to water column and bottom dwelling organisms respectively. Toxicity is categorized effects as acute (short-term i.e., hours or days), sub-chronic (delayed), or chronic (long- term i.e., weeks, months, or years). Lethal tests (e.g., Amphipod survival) measure survival over a defined exposure period. Sublethal tests (e.g., MicrotoxTM, echnoid fertilization, or juvenile polycheate growth) measure physiological functions of the test organism, such as metabolism, growth and fecundity over a defined exposure period. Tests which measure sublethal endpoints provide an indication of long-term chronic effect(s) while survival tests


typically measure short-term acute effects.The data for survival tests are generally expressed as lethal concentrations (LC) or lethal doses (LD) (dose is only used if a chemical is fed or injected into an organism). These data are often expressed as an LC50 which is the concentration of a substance that in an experimental time frame has caused a 50% reduction in the test population of organisms. Higher LC50 values imply lower toxicity because higher concentrations of the substance are required to induce mortality. The data for sublethal tests are generally expressed as an inhibition concentration (IC50) or effective concentration (EC50,) the concentration producing a defined sublethal effect in 50% of the exposed population. The rating system used for classifying materials in categories ranging from non-toxic to extremely toxic is provided in Table 4.2.

Table 4.2 Toxicity Rating System (GESAMP, 1997 as cited in Patin, 1999).

Acute Toxicity Chronic ToxicityRating 48 to 96-hr LC50

/ EC50 (mg/L)Rating No Observed Effect

Concentration (mg/L)(0) Non-toxic >1,000 - - - -(1) Practically non-toxic

100-1,000 - - - -

(2) Slightly toxic 10-100 (2) Low chronic toxicity

>1

(3) Moderately toxic

1-10 (3) Moderate chronic toxicity

0.1-1.0

(4) Highly toxic 0.1-1.0 (4) High chronic toxicity

0.01-0.1

(5) Very highly toxic

0.01-0.1 (5) Very high chronic toxicity

0.001-0.01

(6) Extremely toxic

<0.01 (6) Extremely high chronic toxicity

<0.001

*NOTE: Based on system originally developed by International Maritime Consultative Organization (IMO / FAO / UNESCO / WMO / WHO / IAEA / UN / UNEP 1969). The system was recently updated by GESAMP.

Historically, the USEPA has required extraction of a SPP from the whole drilling fluids. For WBMs the USEPA requires the operator to conduct a water column toxicity of the SPP using mysid shrimp ((Americamyis (Mysidopsis) bahia). Discharged muds must have a median 96 hour LC50 30,000 mg/L for the WBM to be allowed for disposal. The USEPA has determined that the water column toxicity test may not be appropriate for


evaluating the potential impact of SBM cuttings discharges. Instead they proposed a sediment toxicity test to evaluate the effects of SBM cuttings discharges on bottom dwelling organisms. The details of this test procedure and median lethal concentration are in the process of being worked out as part of the SBM rule making process (USEPA, 1999a).

In order to discharge cuttings in the North Sea, drilling fluid base chemicals must be preapproved by testing their toxicity to three types of marine species, an algae (Skeletonema costatum), an herbivore (Acartia tonsa), and a sediment reworker-amphipod (Corophium volutator or Abra alba). Both new and used muds are tested with aqueous phase tests conducted for the algae and herbivore, and a sedimentary phase test for the reworker. The sediment reworker has shown to have the greatest sensitivity to various synthetics and the algae and herbivore species are more affected by water-soluble substances that are almost non-existent in SBMs. Under North Sea criteria, a mud is acceptable if the LC50 for Corophium volutator (a sediment reworker) is greater than >1,000 mg/kg.

Sediment toxicity testing with the appropriate test organisms has been used to determine the biological significance of chemical and particle size constituents found in coastal sediments (NRC 1983; Environment Canada 1998). Testing involves exposing organisms to naturally occurring sediment under controlled conditions to determine if the exposure causes adverse effects on the organisms. There are a range of organisms representing different trophic levels and taxonomic groups available for use in sediment quality assessment studies. Two tests that may be conducted are Amphipod survival, which is performed to measure lethal effects, and a bacterial photoluminescence test (Microtox), which measures sublethal effects (metabolic activity) and is used primarily as a screening tool. An outline of these two analyses is provided in Table 4.3. Juvenile polychaete survival and growth toxicity tests have also been used recently to assess toxicity of marine sediments on the west coast of North America and from the Hibernia project. The juvenile polychaete bioassay produces data with a high between replicate variability that often limits the statistical power of the test. This variability may be due to the avoidance or territorial behaviour exhibited by the polychaetes. Another assay that has been used in some locations (including eastern Canada) is the inhibition of echiniod fertlization (using Litichinus pictus for eastern Canada testing. Recent use of this test as part of the SOEI EEM showed that it did not provide reliable results that correlated with other observations) (JWEL, 2000a).

Table 4.3 Outline of Typical Toxicity Analyses

Toxicity Test Amphipod Survival Bacterial Luminescence


Endpoints: biological % survival % reduction in luminescenceStatistical Significant difference from

negative control or referenceIC50 or EC50

Reference Method EPS 1/RM/26 EPS 1/RM/24Test Initiation Within 6 weeks of collection Within 6 weeks of collection Test Termination 10 days after test initiation 30 min. after test initiation

The discussion in Chapter 6 dealing with the effects of drilling fluid discharge on the ecosystem will refer to these experimental results. There has been variable effectiveness of the use of MicrotoxTM as a screening tool in eastern Canadian EEM programs. For example, at SOEI, there was not MicrotoxTM response at locations where amphipod toxicity was noted. At Hibernia, MicrotoxTM response was not correlated with drilling discharges (i.e., hydrocarbons or barium).

Toxicity testing is beneficial in that several trophic levels may be tested for several degrees of toxic response. Toxicity tests may also be conducted on the solid and liquid (pore water) phases of sediment. The flexibility of toxicity testing makes it a useful predictive tool in EEM and ECMs.

Toxicity test results must be interpreted with the understanding that lab-testing conditions may not reflect field conditions in some areas. Some test organisms are more sensitive to factors such as grain size, ammonia or sulfide, and a toxic test result may be due to changes in these or other factors rather than in a parameter of interest. Furthermore, the fluid’s test concentration in the lab may never be achieved under natural dilution and dispersion conditions. Toxicity testing also provides no indication of the duration of a toxic response.

Benthic Boundary Layer (BBL)4.7.1.4

Sediments are an integral part of the marine environment, providing habitat, feeding and rearing areas for many invertebrate and fish species. Sediment quality is intrinsically linked to water quality because sediments act as a sink and a source for chemicals in the water column. The intersection between the physical media of sediment and water, the BBL, is a dynamic ecosystem and critical to the survival of many species. The hydrodynamic conditions of the first 1 to 2 meters above the seabed determines how suspended particulate matter (SPM) is distributed to benthic organisms (Muschenheim et al., 1995).

It is the BBL where particulate waste may be deposited, resuspended and redistributed, if the particulate is fine enough and the oceanographic conditions are suitable. The condition of the benthic boundary layer is assessed using specialized equipment that samples water


and SPM within 0.5 m of the seabed. Chemical and grain size analyses are usually conducted on the samples. Sampling the benthic boundary layer is relevant because the BBL provides a potential mechanism for contaminant transport if cuttings properties and oceanographic conditions are suitable and is also the environment of prolonged exposure for the benthic community. In addition, samples of water-soluble and non-water soluble contaminants may be collected in the BBL.

Sampling the benthic boundary layer is difficult however, because of the specialized equipment required. It is also often difficult to identify the source of BBL material at each sample location because of the mobile nature of the BBL. This can complicate the delineation of an effect during an EEM program. Furthermore, correlation between the chemistry of the BBL and sediment or water chemistry has not been established.

Biota Quality4.7.2

There are several tests used to evaluate the potential for negative effects on biological communities, other than benthic community analysis. These tests may be laboratory evaluations using samples collected in the field during a monitoring program or they may be performed on specimens under controlled conditions in the laboratory.

Bioaccumulation and Body Burden4.7.2.1

Body burden is the level of contamination within the body or tissues of an organism at the time of testing. Bioaccumulation is the uptake and retention of bioavailable chemicals from an external source (water, food, sediment, air). For bioaccumulation to occur, the rate of uptake must be greater than the rate of loss of the chemical from the tissues of the organism. Biomagnification is a special case of bioaccumulation whereby a chemical, as it is passed through a food web by trophic transfer, reaches increasingly higher concentrations in the tissues of animals at each higher trophic level. While many chemicals may be bioaccumulated by marine organisms, only a few may be biomagnified. Hydrocarbons and inorganic metals may bioaccumulate in marine organisms, however they do not biomagnify. An exception is mercury in the form of organomercury compounds. Organomercury compounds are not present in drilling discharges however. Body burden may be determined on organisms that have been exposed to various constituents in the field. In addition, the potential for substances of interest to bioaccumulate may be determined in the laboratory by exposure of organisms, or by determining the chemical behavior of the substance (octanol-water partition coefficient). These methods will all be discussed below.


Body burden of an organism is measured by collecting specimens (e.g., fish, mussels) from an area of potential exposure and analysing tissues for constituents of interest. Bivalves and shellfish may make better monitoring candidates than fish as bivalves and shellfish are benthic filter or deposit feeders, which are in close contact with the sediment and generally travel limited distances as compared to fish. Certain tissues are better than others for accumulating particular contaminants. Fatty tissues, like blubber for example are usually sampled when testing PCB contamination. The liver tissue is commonly analysed for metal and hydrocarbon contamination.

Body burden testing may provide some measure of risk to human health when commercial species are monitored. Data from bioaccumulation or body burden testing on one species may be used to model the potential bioaccumulation in other species. Field sampling of long-lived species also may provide a measure of the impacts of several years of exposure.

There are limits to the interpretation and applicability of body burden data results. First, it is difficult to translate measured levels in an individual to community or population level effects. Secondly, contaminant levels may vary seasonally, and contaminants may be metabolised differently by different species and even by different genders within the same species. Thirdly, it may be difficult to determine the source of contaminants for migratory species such as fish and also to obtain specific finfish species in sufficient numbers may also be a problem. Also, as exhibited in the Hibernia EEM, there may be differences in body burden results depending on the timing (seasonality) of the survey, and which confounds the interpretation of results. Finally, few chemicals are included in regulatory limits anywhere for consumption of fish tissue.

The bioaccumulation potential of chemical substances has generally been determined from the n-octanol/water partition coefficient (expressed as log Pow) and the bioconcentration factor. The log Pow represents the ratio of a material that dissolves or disperses in octanol (the oil phase) versus water. This coefficient is used as a chemical surrogate for bioaccumulative potential. The Pow generally increases as a molecule becomes less polar (more hydrocarbon-like). The Pow may be determined by calculation (for SBMs with well know structures that are well characterized) or by laboratory methods such as the Shake Flask Method (OECD 107) or the HPLC method (OECD 117). It is generally recognized that organic chemicals with a Log Pow between 3 and 6 have the potential to significantly bioaccumulate (API/NOIA Industry Consortium, 2000a). Chemicals with Log Pow values greater that 7 are not expected to bioaccumulate in aquatic species because the molecules of such substance will be too large to move past the aqueous diffusion layer which is present at the water/gill interface (Rand, 1995).


Another value used to characterize the tendency for a chemical substance to bioaccumulate is the Bioconcentration Factor (BCF). BCF is determined by exposing an organism to a constant concentration of a test material in water until equilibrium is reached between the concentration in the water and in the tissues of the organism. BCF is the tissue concentration divided by the water concentration at equilibrium. One method used for determining BCF is OECD A-E. A log BCF value of greater than 3 may be a cause for concern. However, this type of test has technical limitations in evaluating highly water insoluble substances such as the SBMs. Water insoluble substances tend to precipitate out of solution or bind to suspended particles, which make accurate determination of the BCF difficult as it is difficult to maintain a steady concentration of base fluid in solution. In addition the Norwegian Water Technology Center recognized that the OECD accumulation methods may not be appropriate for water insoluble chemicals (Vik et al., 1996).

A summary of methods used in various bioaccumulation studies is provided in Table 4.4.

Table 4.4 Bioaccumulation Methods Summary

Source Topic Test

Friedheim, J.E., 1997 SBFs – comparison of various types

Summary of existing literature (no original data presented)

Chemex International, 1998 (CONFIDENTIAL)

IPAR 3 Mud OECD 117; log Pow

Friedheim, J.E. et al., 1991

PAO base fluid PAO SBF

log Pow

Leuterman, A.J.J., 1991 * Novasol (PAO) log Pow

Schaanning, M.T., 1995 * PAO (65% C22, 20% C32, 15% C42 and C52)

log Pow

Growcock, F.B. et al., 1994

Ester, di-ether, detergent alkylate, PAO, LTMO

Dispersibility of synthetic fluids in seawater tested (equal volumes of synthetic and water were shaken)

Færevik, I. * (Summary of results of ecotoxico-logical testing and field surveys on the Norwegian Continental Shelf)

OlefinEsters

log Pow

Environment & Resource Technology, 1994*

ISO-TEQ (C16-C18 internal olefin)

Blue mussel, Mytilus edulis; exposed to saturated aqueous concentrations of the test material under flow-through conditions for 10 days and then allowed to depurate in clean seawater for 20 days


Jones, F.V. et al., 1991 80/20 mineral oil/water;70/30 PAO/water

Mud minnow, Fundulus grandis; exposed to cuttings contaminated with the 2 test materials

Zevallos, M.A. et al., 1996 *

PAOIO

log Pow

Rushing, J.H. et al., 1991 *

LTMONovasol PAO

Mud minnow, Fundulus grandis; Experimental study of uptake in tissue and gut of test species exposed for 30 days to contaminated cuttings at 1%, 5% and 8.4% base fluid

LogPow - log of the octanol:water partition coefficient which is a measure of the amount of a material that disperses or dissolves in octanol (oil phase) versus water

Information obtained from the article summaries obtained in the US EPA documentation, USEPA, •1999b.

Taint4.7.2.2

Some fish exposed to hydrocarbons can acquire an abnormal and detectable taste that is known as “taint”. Tainting can be defined as a flavour or odour that is unnatural to the organism (GESAMP, 1985 as cited in Cordah, 1998). The principle components of petroleum hydrocarbons considered to be tainting factors are dibenzothiophenes, napthalenes and phenols (GESAMP, 1977 as cited in Cordah, 1998). These chemicals when contained within the fatty acids of a fish are vaporized; giving rise to taint that the consumer can distinguish. Taint is tested for by providing taste panelists with coded samples which they are asked to evaluate which one is different, and to rate how much they like or dislike each sample.

Although taint testing, when combined with body burden testing, may provide information on the relationship between the level of tissue contamination and detectable taint may be established. In many cases, tissue contamination is often detected without tainting and vice versa. For example, shellfish may have a petroleum like odor due to the presence of a harmless naturally occurring substance, dimethyl sulfide, which is a volatile material released by shellfish as the result of ingesting an excess of certain phytoplankton, usually in a bloom period (Ackman, 1967). Consequently it may be difficult to establish cause and effect between the presence of taint and the project operations. The test results must also be closely scrutinized because they are based on an individuals’ subjective description of taste.

Biodegradation4.7.2.3

Biodegradation refers to the break down of organic materials such as hydrocarbons by microorganisms. In some parts of the world, approval for discharge of cuttings drilled with NAFs requires acceptable results from laboratory biodegradability testing. The concept is


that a material that degrades readily in standard laboratory tests will not persist for extensive periods of time in the environment upon discharge. The persistence of cuttings piles in the North Sea has been attributed to the slow biodegradation of the traditional OBMs discharged over many years. Synthetic-based fluids were introduced to address this issue, making the testing of biodegradation rates a major concern in the North Sea. In the UK sector, the rate of biodegradation became one of the driving forces behind regulatory developments. In other areas, such as Norway, the U.S., and Australia, biodegradation continues to be an important characteristic in accounted for in evaluating a fluids environmental acceptability.

A variety of freshwater and seawater biodegradation tests are available and have been used to assess the biodegradation of muds and base fluids. The test is usually conducted in the laboratory on the fluid being proposed for discharge. The rate of biodegradation depends on the microbial population level, nutrients available to the microbes, environmental factors (e.g., temperature) and the type and concentration of hydrocarbon being broken down by the microbes. Crude oil, diesel and other longer chain and highly branched hydrocarbons are more difficult for microbes to digest. Short chain hydrocarbon molecules like those used in synthetic-based fluids, are easier for the microbes to consume.

Under field conditions, the biodegradation rate will depend on factors such as nutrients in the sediment, abundance of bacteria, rate of bioturbation, and build up of waste materials and toxic metabolites. In the field, other factors will impact the biodegradation and ultimately the persistence of drilling fluids. Bottom dwelling organisms may bioturbate the material, exposing it to oxygen and also allowing it to be more easily suspended and transported. Bottom currents, resuspension, and transport of bottom materials spread the material out over a wider area, thereby reducing their concentrations. At the same time the material is exposed to oxygen which enhances biodegradation. Biodegradation takes place at the NAF/water interface and is related to the compound’s solubility in water and the bioavailability of the material to the bacteria (see Getliff et al., 1997). If aerobic conditions are maintained within the substrate, microbial activity occurs at a faster rate than if conditions were anaerobic. The total time required to biodegrade discharged NAFs can be further reduced by reducing either the concentration or the total amount of NAFs discharged with the drill cuttings.

There are a number of different methods for determining biodegradability. The primary ones fall into the categories of standard laboratory methods, solid phase tests, and simulated seabed tests. Two categories of standard laboratory methods are available for testing biodegradability of non-aqueous fluids (NAFs): aerobic, and anaerobic methods. Tests of aerobic biodegradation are most relevant to simulating conditions that would occur in area where oxygen concentrations are not depleted, i.e., those areas of the


seafloor where low to moderate concentrations of NAF are deposited and at the surface of cuttings piles. Although numerical values of degradation rates generated by these methods do not likely represent actual field degradation rates, results can be used to compare relative rates for different fluids. Aerobic tests include OECD 301B, OECD 301D, OECD 301F, OECD 306 (OECD, 1993), and Biochemical Oxygen Demand Test for Insoluble Substances (BODIS).

Investigation of anaerobic biodegradation is inherently more difficult than that of aerobic biodegradation and only recently have standardized tests been developed. Increasing attention is being paid to anaerobic tests as anaerobic biodegradation is likely the only available removal process if large-static cuttings piles are formed, or when cuttings are buried deep in the sediments. Anaerobic tests include the internal standards organization Test (ISO/DIS 11734) formerly referred to as the ECETOC technical report and a modified version of this test (Candler et al., 2000).

In recent years, other test methods that are neither purely aerobic or anaerobic and include solid phase tests (Solid Phase Biodegradation Tests (SOAEFD), and simulated seabed studies such as those developed at the Norwegian Institute for Water Research (NIVA). The basic approach of the SOAEFD test is to mix clean marine sediments with base fluid used in NAFs and to fill glass jars with the homogeneous mixture to produce concentrations of 100, 500, and 5000 mg/kg of base fluid (intended to replicate concentrations of base fluid at decreasing distance from the platform). The glass jars are placed in troughs through which a continuous laminar flow of natural ambient temperature seawater is passed. The entire sediment volume is chemically analysed to determine total losses of the base fluid from all mechanisms, not just biodegradation. Although the conditions of the SOAEFD test are ecologically relevant, the test does have a number of limitations which must be considered in interpreting the test results and in consideration of the test for use on a routine or compliance basis. The API/NOIA industry consortium discovered that in some cases there was considerable fluid loss independent of biodegradation (such as mass transfer from the sediment to the fluid phase), which would indicate that the method may not inherently be a good measure of biodegradation (API/NOIA, 2000b) and will overestimate biodegradation (Neff et al., 2000). On the other hand, it may underestimate actual disappearance in the field resulting from the additional factors of biological and physical disturbance. In addition, comparison of results from a number of tests indicated that the fluids did not perform consistently between tests and that discriminatory power was poor (API/NOIA, 2000b). Another limitation of this test is the high cost, ranging from $21k to $50k per test (API/NOIA, 2000b).

The principle of the simulated seabed study is to determine the fate of the test compound in the environment by simulating the conditions of the seabed as closely as possible. They


have also been used to investigate faunal effects and bioaccumulation and are based on introduction of used drill cuttings and simulated drill cuttings to undisturbed seabed sediments containing naturally occurring benthic flora and fauna (taken intact from the sea-floor). The test set-up consists mainly of a series of replicate experimental systems that are maintained in indoor basins, called benthic chambers, which are covered with natural seawater. At different times during the test, chambers are sampled for SBM, barite, and benthic fauna. In addition, sediment redox potential (Eh) an indication of oxygen availability can be measured. SBM washout is estimated from normalizing SBM concentrations to barite concentrations. Drilling fluid is lost from the sediment through biodegradation, washout, and bioturbation.

Summaries of some laboratory and field biodegradation protocols are presented in Table 4.5.

Biodegradation testing is useful because it measures the persistence of compounds indicating duration of potential effect. Biodegradation testing can be a valuable tool during the approval process when the persistence of several compounds are being compared.


Table 4.5 Summary of Test Procedures Used in the Biodegradation Testing of Synthetic-Based Drilling Fluids (from USEPA, 1999b)

Factors influencing test

results

Aqueous Phase Tests Sedimentary Phase Studies Seabed Surveys

Aerobic AnaerobicSeawater

(a)Freshwater Freshwater NIVA

“Seabed Simulation”

SOAEFD “Solid Phase”

Anaerobic Seawater

ISO/DIS 11734

Norwegian sector

Dutch sector Gulf of Mexico

Test Substance Base fluid or

Synthetic fluid

Base fluid or Synthetic

Fluid

Base fluid or

Synthetic Fluid

Cuttings Base Fluid Base Fluid, Synthetic Fluid

or Cuttings

Cuttings Cuttings Cuttings

Physical test conditions:Temperature °C 15-20 15-25 37 7-12 7-12 29 7-12 7-12 7-12Availability of oxygen Good Good None

Lower dependent on test concentration

Very low None Very low Very low Very low

Nutrient availability Good Good Good May be

limitingMay be limiting

May be limiting May be limiting

May be limiting

May be limiting

Test concentration 2-40 mg/l 0.5-40 mg/l 50 mg/l 700-18000 mg/kg

100, 500, 5000 mg/kg

2000 mg/kg Up to 100,000 mg/kg

Up to 4700 mg/kg

Up to 134,000 mg/kg

Depth of mud layer

Not applicable

Not applicable Not applicable

1-2 mm Mixed into the sediment

50 ml 0-20+ cm 0-20+ cm 0-20+ cm

Migration of test substance

Not applicable

Not applicable Not applicable

Possible Very low NA Very probable Extensive Extensive

Inoculum:Quantity/density

Low Generally high High Fairly low Fairly low Low Fairly low Fairly low Fairly low


Variability High Lower than seawater

Lower than seawater

High High Low High High High

Acclimation None None None Some Some Some Some Some SomeSource Seawater Activated

sludgeActivated sludge

Seawater and mixed sediments (b)

Seawater and mixed sediments

Seawater Seawater and natural benthic fauna

Seawater and natural benthic fauna

Seawater and natural benthic fauna

Renewal None None None Possible Possible None Very likely Very likely Very likely

Sampling/analyses:Sampling depth

Not relevant Not relevant Not relevant 1-2 cm 8.6 cm (c) ? 1 cm 10 cm Up to 1 m

Chemical analyses Oxygen demand/CO2

Oxygen demand/CO2

CO2 Presence of base fluid/DO/ redox

Presence of base fluid/DO/ redox

Methane, Presence of base fluid at end of test

Presence of base fluid



Macrofaunal analyses

None None None Mortality on surface (d)

None None Abundance and diversity

Abundance and diversity

Abundance and diversity

Microbial analyses

No No No Yes Yes No

Relevance of test to real environment

Aerobic degradation only

Not relevant Not relevant Relevant, but test concentrations are lower; question anaerobic condition simulation and test substance migration

Relevant; dosing more stable but misses layering as in situ

Relevant test of anaerobic degradation in warm water environments

Relevant. Difficult to obtain representative samples and compatible results from one year to another




However, quantifying biodegradation rates of base oils used in NAFs is complicated by a number of factors that could affect biodegradation rates both in the laboratory and in the field. Since environmental conditions in the sea will vary from one location to another, it is not possible to develop a standardized laboratory procedure for testing the biodegradability of these base fluids on all possible sets of environmental conditions. In addition, as a number of different protocols are used in different laboratories, it is difficult to compare data from different laboratories or that resulting from different test procedures. In one study (Slater et al., 1995 as cited in Vik et al., 1996) the biodegradation rate of a synthetic fluid, an acetal, was highly variable and depended upon the test method used. Finally, presently available standardized aerobic and anaerobic tests suitable for regulatory compliance may fall short in providing discriminatory power, repeatability, practicality, ranking of known test substances as expected, and ecological relevance. Researchers in the US are working towards modifying existing test to better meet the above criteria (Candler et al., 2000).

Fish Health4.7.2.4

A monitoring program including fish health uses several indicators of chemical stress in fish to determine the condition of the fish. The biological indicators primarily used are:

Mixed function oxygenase (MFO) - an enzyme system which commonly increases in fish •in the presence of organic pollutants, such as petroleum hydrocarbons. The activation of this enzyme acts as an early warning system to indicate exposure to low levels of pollutants.

Tissue histopathology - involves the analysis of tissues such as liver and gill for the •presence of cellular damage (i.e., lesions and tumours) which usually indicates chronic, or long-term, exposure to pollutants.

Haematology – involves analysis of different types of blood cells which can provide insight •into pollutant mediated immunotoxicity, disease resistance or tissue damage.

These sublethal tests are sometimes used as an early warning sign of an effect of contamination. However, the true implications of these signs of stress are still debated in the scientific literature. Fish health studies can compliment an EEM program because they may address concerns of commercial fishermen. Fish health studies can be used to assist in the interprepation of other data from toxicity testing and body burden analysis. These studies may compliment other data as well in that not all contaminaints bioaccumulate or are metabolised.

These tests can be overly sensitive however, reflecting stresses other than those chemically


induced. Fish health data can result in a premature conclusion of an effect if not complimented by data from other studies. Transient MFO induction is not expected to be harmful for example, but detecting prolonged induction is difficult without very frequent monitoring. The data must also consider the degree to which the species used migrate and their susceptibility to other sources of stress. In highly mobile populations such as fish, it is often difficult to identify a specific pathway responsible for inducing the measured sublethal response.

Water Quality4.7.3

Water quality monitoring is often used as a compliance monitoring tool because there are regulatory limits for discharges in marine waters in some jurisdictions (e.g., US EPA Water Quality Criteria). Water quality may be monitored a part of EEM programs due to the variety of discharges occurring during operations (e.g., sewage, drilling wastes, produced water).

If water quality is monitored during an EEM program, several physical and chemical parameters may be measured. Typically, a suite of metals and hydrocarbons are analysed, along with total suspended solids (TSS), salinity, temperature, dissolved oxygen, and pH. Concentrations of chlorophyll may also be measured.

Water quality monitoring may be useful in validating dispersion models used in the assessment and approval process such as those for produced water and WBM discharges, and also for measuring the transient levels of water-soluble portion of a waste discharge. However, the practicality of including water quality monitoring in an EEM program can be questioned because of the high degree of water column mixing and movement. The rapid dispersion and dilution of wastes discharged in open waters miminizes the potential to detect any transiently high levels of constituents. The resultant low water column concentrations observed combined with our knowledge of the toxicity of these wastes at typical field concentrations (based on laboratory studies), explains why effects to pelagic organisms are not observed by EEMs.

Seabirds4.7.4

Marine-related birds are significant predators of zooplankton, benthos and fish. Offshore marine environments may be important breeding areas for several bird species. Monitoring of seabirds may be conducted from an aircraft, a boat, from a fixed platform or a floating rig. Each method provides a unique spatial scale of data so the purpose of the data must be clear before a monitoring program is designed.


Seabirds often make up a crucial and large biomass of an offshore marine ecosystem. They are often concentrated in offshore areas during the spring or winter, depending on the species. In many areas, the degree of spatial and temporal natural variability is largely unknown; so many years of data are required before an effect is detectable. Seabird studies are further complicated by the fact that seabirds are migratory and may have more than one harmful interaction throughout the year.


LABORATORY STUDIES5

Chapter 4 provided a discussion of the laboratory tools available to evaluate the environmental performance of drilling fluids, as well as the environmental or regulatory issues behind the testing. This chapter will describe the environmental performance of WBMs and NAFs as measured in the laboratory using these tools (toxicity, bioaccumulation and biodegradation). Laboratory studies provide industry and regulatory agencies the ability to identify materials and concentrations of those materials that may have unacceptable environmental impacts when discharged. Laboratory results may be used to compare the relative performance of various products so those posing the least risk for environmental impact can be identified for use and discharge. In addition, laboratory results can be used as monitoring tools for the routine evaluation of continuing discharges to ensure that any environmental consequences observed at the point of discharge are consistent with the predicted laboratory results.

However, laboratory results may reflect artifacts of the laboratory setup and may be inprecise in truly replicating actual field conditions. For example, conditions under which organisms are tested in the laboratory may result in additional stress to the organisms that wouldn't be experienced in the organism’s natural habitat. Furthermore, laboratory exposure concentrations and durations likely would not be experienced in the field. Consequently, one must be extremely cautious in extrapolating laboratory results to explain or predict what is occurring in the field. In addition, laboratory studies have been used to assess relative performances of various products, and in many cases do not provide a measure of absolute performance.

Ultimately, the results of laboratory studies can be combined with modelling studies to predict impacts in the field. The results of these predictions can be verified during field programs.

WBMs5.1

There have been hundreds of toxicity tests conducted on the aquatic toxicity of WBMs. Most all indicating that WBMs have low acute toxicities (NRC, 1983). In addition there have been a number of tests conducted on the bioaccumulation of components (metals) contained in WBMs (Neff, 1988) that indicate that metals contained in WBMs are not bioavailable to marine organisms. Biodegradation testing has not been conducted on WBMs as they are primarily inorganic.

Toxicity Studies5.1.1


The National Research Council (NRC, 1983) examined the toxicities of over 70 drilling fluids using more than 60 species of marine organisms. These data indicated that most WBMs are relatively non-toxic. Less than 4% of whole-fluid tests and 2% of suspended particulate phase tests found substances to be moderately toxic (i.e., LC50 values between 100 to 10,000 ppm). Most of these toxic responses in the WBMs were attributed to the use of diesel fuel (No. 2 fuel oil), although this was not always substantiated by chemical characterizations. In addition, strong ionic solutions such as KCl (potassium chloride) as well as surfactants and lubricants may exhibit toxicity in laboratory testing. Crustaceans as a group were found to be more sensitive than other major taxa to drilling fluids. These species were found to be more sensitive to suspended particulate phases than to liquid phases.

In order to promote pollution prevention through product substitution, some countries use water column toxicity tests as product approval tools and/or end of pipe compliance testing. Over time this testing has generated a body of data and information on existing mud constituents and has lead to the development of many new products that perform the same function with much lower toxicity.

As significant progress has been made to eliminate acutely toxic drilling fluid additives, more attention has been focused recently on sublethal and chronic effects. At the current time, sublethal and chronic effects have not been used as regulatory tools. As research tools they have yielded preliminary results that offer additional insight into potential mechanisms of toxicity. As research progresses, sublethal and chronic toxicity tests may be used, as acute tests are currently used, to help identify products and mud systems that have lower environmental impacts.

One of the research efforts in the area of sublethal impacts has been advanced in eastern Canada, and has focussed on the influence of fine particulate in the benthic boundary layer to filter feeding organisms.

Cranford et al., (1999b) examined the chronic lethal and sublethal effects (growth, reproduction, physiological energetics) of barite, bentonite, and used water and oil-based drilling fluids on adult sea scallops. The chronic toxicity of drilling wastes studied in order of increasing toxicity observed was; WBM<bentonite<barite<LMTO. It was expected that bentonite, a biologically inert substance would have no chemical toxicity or physical disturbance on scallops. The same was expected for barite. However, high mortalities and negative growth effects were observed for bentonite on scallops. The effects of bentonite may be attributed to the negative influence of fine particles on feeding mechanisms. Barite had an even greater impact on scallop growth than bentonite and the likelihood for chemical toxicity to barite is difficult to assess. The chronic loss of mucus secretions


through adsorption to barite leading to nutritional stress and growth reductions is hypothesised to be the cause of the observed barite effect, although it has yet to be proven. WBMs were classified as the most environmentally benign of the drilling wastes examined in this study. However, the laboratory analysis was focused only on the fluids and did not take into consideration that in the field, much lower volumes of LTMOs would have been discharged than WBMs.

In fact, the physiological response of scallops to WBMs does not appear to result from physical damage to the organisms. The bentonite particles in the WBM suspension may interfere with the filter feeding process and account for the observed responses. The bentonite interference results in physiological compensation responses including a reduction in the efficiency of clay-sized particle capture, initiation of pre-ingestion particle selection, and a reduction in respiratory losses after prolonged exposure. The larger cuttings in WBMs that often dominate WBM particle size profiles do not interfere with the filter-feeding processes as severely as clay sized particles that are characteristic of bentonite.

As with all laboratory experiments, one needs to cautiously evaluate the data in light of how the conditions under which it was collected replicate the true field conditions. The authors acknowledge that drilling wastes have been observed to flocculate in seawater and accumulate in the benthic boundary layer (BBL; see Muschenheim and Milligan, 1995) and that when drilling waste particles were incorporated into large flocs they no longer affected the feeding rates of scallops (White, 1997). Flocculation of drilling waste was not observed in this experiment (Cranford et al., 1999b) study. Despite this shortcoming, the authors note that in a field study of sea scallops feeding on flocculated biologic material, the natural flocs were disrupted during feeding (Cranford et al., 1998 in Cranford et al., 1999b)

Bioaccumulation5.1.2

Bioaccumulation studies have relied on analysis of total tissue and body burdens. Heavy metals in drilling muds and cuttings are present in insoluble forms or are adsorbed on clay particles and show an even lesser tendency to bioaccumulate than soluble metals (National Research Council, 1983, Neff, 1988, Neff et al., 1989a). Limited bioaccumulation of barium and chromium by marine animals has been observed in the laboratory and occasionally in the field; however, levels of uptake are too low to affect the health of the marine organism or predators (including man). As discussed in section 4.6.2.1, biomagnification of chemicals present in drilling discharges does not occur. There has been a great deal of research on heavy metal biomagnification by marine organisms (Bascom, 1983; Neff et al., 1989a; Neff, 1988; Bryan, 1982; Kay, 1984; Schaefer et al., 1982).


Many of these studies have addressed metals from all sources - not just mud and cuttings discharges.

NAFs5.2

The different physical properties between WBMs and NAFs determine when and for what application a particular fluid (WBM or NAF) is most suitable. These differing physical properties often necessitate differing laboratory protocols to adequately characterize the fluids. Considerable effort in recent years has been devoted into the development of appropriate tools to characterize and quantify the environmental performance of NAFs. The results from these recently developed laboratory tools often form the basis for developing regulations with respect to the discharge of NAFs associated with the cuttings. The laboratory data for the newer SBMs are often compared to results from OBMs simply because they provide an existing environmental benchmark to measure improvements in environmental performance of the SBMs over the OBMs.

Information on the ecotoxicological performance (toxicity, biodegradability, and bioaccumulation potential) of various SBMs and their components is provided in Appendix H.

Toxicity Studies5.2.1

There are numerous studies of the toxicity of NAFs to marine organisms. Vik et al., (1996) examined the toxicity data for the following unused muds: ester, acetal, PAO, IO, and LAO-based. All the toxicity results for the Corophium volutator sediment reworker bioassay had acceptable LC50 based on the North Sea criteria (greater than 1,000 mg/kg). The muds ranked in order of increasing toxicity are as follows: esters < PAO < IO < Acetal < LAO. Molecular weight is a driver for differences in SBM toxicity. Substances with lower molecular weights are more toxic. This is illustrated in the relative olefin toxicity described above where PAOs are less toxic, than IOs, and LAOs. PAOs have C20 to C30 carbon chain lengths, IOs have C16 to C18, and LAOs have C14 to C16 carbon chain lengths. Molecular structure of substances is also a significant driver in toxicity. For example, aromatics are much more toxic than olefins.

Harris (1998) conducted toxicity tests on five drilling muds using standardized Canadian Protocols. The test matrix was designed to compare the relative toxicity of two SBMs (IA-35 and Neodene 1518 which have been used and discharged offshore eastern Canada) to a LTMO (Shellsol DMS that has been used and discharged offshore eastern Canada) and two water based muds (Silicate mud, Glycol mud). The WBM formulations selected are the state of the art high performance WBMs, designed to perform in difficult drilling


situations. The test matrix included two benthic toxicity tests (a crustacean-Corophium volutator, a mollusc-Macoma balthica), and two water column tests (an echinoderm-Lytichinius pictus, and bacteria-Vibrio fischeri, MicrotoxTM). The results are summarized in Table 5.1. The tests were run in one laboratory at the same time to minimize differences due to testing artifacts.

Table 5.1 Toxicity Test Results of Five Drilling Muds (from Harris, 1998)

Mud Type AmphipodCorophium Results (10 Day LC50)

Sea Urchin Fertilization Lytichinius Results (IC50- 20 Mins)% water soluble fraction (WSF)

Bacterial luminescenceMicrotoxTM Results (EC50 - 5 Mins)

BivalveMacoma Results (LC50)

Shellsol (LTMO) 2747 mg/kg 66.4 > 100% 5,310 mg/kgIA35 Mud (SBM) > 50,000 mg/kg 66.7 > 100% > 50,000 mg/kgNeodene 1518 (IO) (SBM)

> 50,000 mg/kg 66.1 > 100% > 50,000 mg/kg

Silicate (WBM) > 50,000 mg/kg 66.2 > 100% > 50,000 mg/kgGlycol (WBM) > 50,000 mg/kg 46.1 33.3, 38.5, 40.6 > 50,000 mg/kg

SBMs and LTMOs are not water miscible, therefore they would be expected to remain physically entrained in a test sediment and exhibit more toxicity than WBMs. The benthic toxicity test results clearly indicate the two SBMs and the two WBMs were less toxic than the LTMO. The LTMO would be expected to be more toxic than the SBM due to its lower molecular weight. The LC50 was higher than the highest concentration tested (>50,000 mg/kg) for the WBMs and the SBMs, whereas that for the LTMO was considerably lower. The results confirm the same contrast between SBM and LTMO toxicity observed by Cranford et al, 2000. Nevertheless all these fluids fell within the non-toxic range (>1,000 mg/kg per GESAMP, 1997).

In contrast, WBMs are water miscible and in some cases (depending upon the formulation) may exhibit more toxicity than SBMs or LTMOs in a water column test. For the MicrotoxTM test, the SBM and LTMO muds did not exhibit toxicity at the highest concentration tested, only the Glycol WBM exhibited a toxic response. All five mud samples had an inhibiting effect on the sea urchin fertilization. Glycol was the most toxic in the sea urchin fertilization test indicating the same trend observed in the MicrotoxTM test.

Acute toxicity tests have been conducted on NAFs, and the laboratory findings can differentiate SBMs from each other as well as from traditional OBMs. However, because biodegradation is considered such an important part of overall SBM performance, toxicity


testing of SBMs has not been as much of a factor in product selection as it has been with WBMs. The chronic and sublethal toxicity of SBMs have been tested using procedures developed in Norway by NIVA and in Canada by the Bedford Institute of Technology. In the more recent NIVA studies, the survival of benthic organisms has been measured over the duration of the test. The findings indicate that rapidly biodegrading SBMs such as esters have more pronounced toxic effects than do moderately biodegrading olefins and slower biodegrading mineral oils (Schaanning et al., 1996).

Cranford (1999b) investigated the chronic toxicity of a LTMO (Shellsol DMS) and compared it to barite and bentonite effects as previously described (under WBM toxicity). In this study, the first round of testing showed 100% mortality for the scallops exposed to 2 mg/l and 7 mg/l concentrations of LTMO for between 11 and 16 days. During the same time period, controls showed 100% survival. During the second round of testing, LTMO concentrations were reduced to 1 mg/l which resulted in 70% mortality by day 24. Controls during the same period showed 97% survival.

In contrast to the LTMO results, Cranford et al., (2000) examined the chronic toxicity of synthetic based muds IO1518 and IA-35. Adult sea scallops were exposed to used SBMs in recirculating raceway tanks. The results indicated the two SBMs exhibited similar rates of mortality as the controls over a 90 period at concentrations from 1 mg/l to 10 mg/l. The cause of the LTMO effects seemed to be chemical toxicity as opposed to physical disturbance. The SBM examined had a similar effect on feeding behavior as pure bentonite (which means a physical and not chemical effect).

Additional findings by Cranford et al., (2000) indicated growth was significantly affected at 0.07 and 1.0 mg SBM/L. Chronic exposure to low levels of SBMs resulted in reduced reproductive development and nutrient storage in the adductor tissue and digestive gland. Clearance rates (energy intake through feeding) had an EC50 value of 0.2 to 0.5 mg SBM/L. The SBMs examined had a similar effect on feeding behaviour as pure bentonite clay (which suggests physical rather than chemical toxicity).

One must interpret these results with caution, as it is unlikely that scallops would be continually exposed to suspended drill mud particulates on the seafloor as was done in these experiments.

Bioaccumulation Studies5.2.2

Hydrocarbons are bioaccumulated rapidly but are not persistent (Neff, 1988). Half lives for release of hydrocarbons from fish and crustaceans are usually less than one day. Half


lives for hydrocarbon release from marine bivalves are usually ten days or less. As in the case of metals, field results have demonstrated that body burdens of petroleum hydrocarbons show an inverse relation to trophic level. As discussed in Section 4.6.2.1, the bioaccumulation potential of chemical substances is traditionally determined from n-octanol/water partition coefficient (Pow) and the molecular weight of the substances and the BCF. Substances with log Pow values >7.0 are not expected to bioaccumulate in aquatic species because the molecules of such substance will be too large to move past the aqueous diffusion layer which is present at the water/gill interface (Rand, 1995). Substances with a log Pow of ≥3.0 and a substance molecular weight of ≤600 are considered likely to bioaccumulate (Schobben, 1996). The base fluids examined by Vik et al., (1996) had a log Pow of >8.0 for all except the LAO, which was >6.43 (Table 5.2).

Table 5.2 Log Pow Values and BCF-values Available for Base Fluids in SBM Drilling Muds (from Vik et al., 1996)

Drilling Fluid Log Pow Pow method used

Log BCF(on lipid weight

basis)

BCF-Method Used

IONovaplus base fluid

8.6 Calculation 0.71) OECD 305 A-E(Mytilus edulis)

AcetalAquamul B2

11.8 Calculation 3.8 OECD 305 A-E(Mytilus edulis)

PAONovasol II

11.2 Calculation 2.11) OECD 305 C-E(Mytilus edulis)

Hydrogenated paraffinic oil XP-07

11.2 Calculation 4.9 OECD 305 A-E(Mytilus edulis)

LAOUltidril base fluid

>6.43 OECD 117 HPLC

4.8 OECD 305(Mytilus edulis)

1) The vast majority of the base fluid was contained in the stomach as indigestible food matter. The present test was unable to demonstrate the “metabolic” uptake, i.e., true bioconcentration, since the mussels fed on “particulate” Novasol II.

There have been a few lab studies on exposure of bottom fish to OBM cuttings. Stagg and McIntosh 1996 exposed benthic (bottom dwelling) flatfish (Limanda limanda) to treated and untreated LTMO drill cuttings in a multi-tank study designed to investigate the accumulation of hydrocarbons and the biological effects of drill cuttings containing levels of oil which would be similar to those found 500 to 1000 m from platforms in the North Sea. The findings were as follows:

hydrocarbon concentrations measured in the liver and muscle of the fish are low;•there was no induction of the enzyme system which would be indicative of a sublethal •


response;the lack of induction was attributed to the low aromatic content of the drilling fluids;•heavy metals in sediment were almost entirely non-bioavailable to the fish and level of •heavy metals in exposed fish were not significantly different from those in control animals; andno histopathological effects attributable to drill cuttings were observed. •

Payne et al., 1989 exposed winter flounder for 30 days to OBM drill cuttings. Only low concentrations of PAHs were found in flounder livers, suggesting that OBM drill cuttings present little potential for contamination of fish stocks over any significant geographical area.

There have been a few laboratory investigations of bioaccumulation of SBM base chemicals by marine organisms. Estuarine mud minnows, Fundulus grandis were exposed in a flow through seawater bioassay system to substrates of cuttings containing different concentrations of PAO (Rushing et al., 1991). Fish were sampled and analysed for PAO in the gut and whole tissues at several times, up to 30 days. No PAO was detected in the fish tissues, and one fish contained a small amount of PAO in its gut, indicating it had ingested some SBM cuttings. In contrast, in a similar experiment, fish exposed to LTMO cuttings did bioaccumulate a small amount of hydrocarbons in their tissues.

The bioavailablity of an IO and a LAO base fluid to mussels were tested by ERT, 1994 and McKee et al., 1995 respectively. In both studies, after mussels were exposed to saturated solutions of the base chemicals in seawater they rapidly accumulated SBM chemicals in soft tissues. However, upon being returned to clean seawater, the mussels rapidly released the chemicals (95% of the IO was eliminated from the mussel within five days). The rapid uptake and release of the chemicals suggests that the mussels were filtering and retaining droplets of SBM in their gills and digestive tracts and not assimilating them into their tissues. The log BCFs estimated for the C16 and C18 IO base chemicals were 5.37 (4.18) and 5.38 (4.09) respectively, and 4.84 for the LAO.

Overall, it is likely that none of the synthetic fluids will bioaccumulate due to the rapid rate of clearance from organisms (Vik et al., 1996) and extremely low solubility. Typical lab results indicate that base fluids may show rapid uptake, but then are depurated over a short period of time. Furthermore, the propensity for SBMs to biodegrade further reduces any potential exposure and consequent bioaccumulation in organisms.

Taint5.2.3

Although there has been concern in the North Sea with regard to impact of oil and gas


operations on fish, there is only localized evidence of fish contamination (McGill et al., 1987) and taste panel studies have not shown evidence of hydrocarbon taint in a fairly comprehensive survey of Northern North Sea demersal fish (McIntosh et al., 1990).

Biodegradation Studies5.2.4

A variety of freshwater and seawater biodegradation tests are available and have been used to assess the biodegradation of muds, including base fluids. The different types of tests can be grouped into the following categories: standard laboratory tests, solid phase tests, and simulated seabed studies. Sample preparation, test concentration, test media selection, inocula source, physical test conditions (duration, temperature, pH, illumination and mixing) are crucial to providing a representative and reliable biodegradation test.

The molecular weight and molecular structure drive the relative biodegradation performance of various NAFs. The general trend is for lower molecular weight fluids to biodegrade faster because they are slightly more water soluble and easier for the bacteria to attack. Increased branching in a molecular structure slows the biodegradation rate. The molecular structure of esters promotes bacterial breakdown. However, the same ester structure makes them susceptible to chemical contamination as a drilling fluid. In addition to these general trends, the molecular structure can also drive the mechanism of aerobic or anaerobic biodegradation processes (Getliff et al., 1997). The mechanism by which olefins and esters are known to biodegrade under anaerobic conditions has been established. The mechanism for paraffins to biodegrade aerobically has not been established.

Because of their chemical makeup, the following trends have been generally established:

esters biodegrade the fastest because of their molecular structure;•after Esters, C16 C18 LAOs biodegrade next because they have a low molecular weight, •linear structure that can biodegrade anaerobically; after LAOs, IO1618 biodegrade next because they generally have a linear structure. •However, the higher molecular weight and movement of the double bond slows the bioavailability for aerobic and anaerobic biodegradation;other base fluid biodegradation rates are driven by their molecular weight and •molecular structure and show degradation rates between Esters with the highest biodegradation rate and Diesels oil with the lowest biodegradation rate; and the highly branched paraffinic structure of mineral oils and diesel are typically •considered the reason for their poor biodegradation performance.

Many of the same chemical characteristics that promote high biodegradation rates (i.e., low molecular weight) also contribute to higher toxicity. Consequently, researchers


attempt to find the right combination of molecular weight, and molecular structure to meet the specific needs of a particular regulation or receiving environment.

Vik et al., (1996) concluded that the available test data indicate a high degree of variation for any one chemical/fluid, and that comparisons of the available data require a high degree of expertise and knowledge on the detailed test protocols to avoid misleading conclusions. This is true for all of the biological tests-toxicity, bioaccumulation, and biodegradation. Table 5.3 is a collation of biodegradation data presented by Vik et al., (1996). The data was collected from a variety of sources including NIVA Aquateam, Berg et al., 1995, Slater et al., 1995, Steber et al., 1995; Schaanning, 1995a and 1995b; and Schanning 1996. The data presented for the ISO/DIS 11734 modified test was from Candler et al., 2000.

Table 5.3 Biodegradation Test Results for SBMs and Mineral Oils (from Vik et al., 1996)

Mud Type NIVA Test BODIS-SW BODIS –FW OECD 306Ester (Petrofree) > 95% 55% 89% 81%Acetal (Aquamul) 40-50% 14% 66% 14%PAO (Novadril) 40-65% 44%LAO (Ultidrill) 85-95% 66% 60%IO (Novaplus) 65-70% 80% ~ 75% a 68%Mineral Oil 40-60%Mud Type OECD301D OECD 301B ECETOC-

AnaerobicISO/DIS 11734 (mod)

Ester (Petrofree) 80%Acetal (Aquamul) 47% 71% 10%PAO (Novadril) 40%LAO (Ultidrill) 84% 53% 83-84%IO (Novaplus) 42% 37-45%Mineral Oil 5%Olive Oil 100%

a Date estimated from graphical presentation, no numbers presented to verify graphical estimation.

SW-seawaterFW-freshwater

testing by the NIVA protocol indicates that Esters and LAO biodegrade better (than •mineral oils, PAO and Acetals based upon the NIVA protocol;the ECETOC (Europe Centre for Ecotoxicolgy and Toxicology of Chemicals) •freshwater test data indicate esters biodegrade most rapidly followed by (in order of decreasing biodegradation) IO, LAO, PAO (40 to 50%), Acetal (approximately 12%),


and mineral oil (5%); results of solid phase testing (SOAEFD) indicate the biodegradation of esters •(approximately 95%) was greater than PAO and LAO (approximately 45%); the data presented in Vik et al., (1996) indicate that biodegradation of mud types •regardless of the biodegradation test employed was esters > LAO > IO > PAO/Mineral Oil > Acetal; anda variety of NIVA studies (Schaanning, 1994, 1995a; Schaanning and Laake, 1993) •indicate that esters biodegrade faster than PAO and mineral oils.

Overall, a few generalizations can be made from the results of laboratory biodegradation test that have been reported in literature to date (IBP SHE, 1999):

NAFs exhibit a range of degradation rates. Under comparable conditions, esters seem •to degrade the most quickly, and other base fluids have more similar degradation rates. The extent to which the range of base fluids appears to differentiate themselves in degradation rate depends upon the testing protocol used;degradation rates in sediments decrease as base fluid concentration increases;•degradation occurs more rapidly under aerobic than anaerobic conditions; and•sediment type (e.g., sand versus silt/clay) and temperature are determinants of •degradation rate (degradation occurs more rapidly under higher temperatures and in silt/clay sediments).


MODELLING AND FIELD STUDIES6

Field studies provide the most ecologically relevant assessment of the impacts resulting from the discharge of drilling muds and cuttings and provide validation of predictions made from laboratory studies. Field monitoring programs are used to determine the fate, effects and persistence of drill muds and cuttings in the water column and on the seafloor and their potential impacts on biota. In some cases, the North Sea for example, many of the seabed studies have looked only at the fate and persistence of drilling fluids, while many field studies have been conducted on the effects of discharging WBMs and OBMs, far fewer studies have been conducted on the effects of the discharge of SBMs.

The discharge of drill muds and cuttings takes place in a wide variety of marine environments around the world. Each area is unique in terms of water temperature, bottom type, thermoclines, current speed, frequency and severity of storm events, and biota. It is difficult to account for all these factors in an laboratory test. Consequently, field studies do provide an important mechanism for understanding the environmental performance of discharged drilling wastes. However, data from field monitoring programs are not without problems. Field data can also be highly variable due to natural spatial and temporal variation of nearly all environmental parameters (e.g., temperature, grain size, benthic abundance) and require careful and detailed interpretation.

Overall, results of studies on the effects of discharge of drilling waste emphasize the importance of the local receiving environment including water depth and current regime on determining both the initial area affected and the persistence of hydrocarbons in the sediment.

Mathematical models of the dispersion and deposition of drilling discharges provide predictions of the water column concentrations and initial aerial extent and thickness of cuttings accumulations on the seabed. Other models may be used to predict the resuspension and transport of these deposits. Results of modelling efforts can be assessed with findings of field programs. This section begins by comparing the physical oceanographic conditions that influence the dispersion and ultimately the effects from the discharge of drilling fluids in areas of major oil production (Table 6.1). Subsequently, the behaviour of drill muds discharged under different environmental conditions is discussed followed by short and long-term effects of drill mud discharges are discussed as documented by field studies and EEM programs. A brief discussion of modelling is also included to address the predicted dispersion and deposition of drilling fluids and drill cuttings.


Table 6.1 Physical Setting in Three Oil Producing Regions

Parameter East Coast Canada North Sea Gulf of Mexico 3

Grand Banks 1 Scotian Shelf 2 North North Sea 3, 4 South North Sea 3, 4

Air Temperature (°C) -37.6 to 26.8 -19.7 to 35 6.5 to 14.5 5 to 14.5Sea Surface Temperature (°C) -1 to 14 2° to 20 7.5 to 13 2 to 18 13 to 26 (surface)Sea Bottom Temperature (ºC) 0 to -0.5 (Generally stable) <5 3 to 8 3 to 16 4.9 below 1000 mPrecipitation (Annual Mean) 1,514 mm 2501 mm NA 536 – 658 mmMaximum Winds (knots) 58.2 (1-min. mean) 52.5 (1-min. mean) NA 67 (return period of 100 years) 120 (hurricane) Fog (% time – days) 40-84% highest levels

recorded for June/July.3- 32 % Highest June/July

<2% in Jan, <6% in July <5% in Jan, <3.6% in July NA

Freezing Precipitation 47 days/year with freezing rain 10.1 hrs (Annual mean) NA NA NoneWave Height 1 – 7 m normal - up to 12 m in

winter0-4 m normal - up to 6-8m winter

20-30m (50 year max.) 5 10-20m (50 year max.) 5 28 m (extreme)

Water Depth 76-88 m 14-110 m 50 - 600 (mean ±125 m) 40 m 200 m – shelf> 3600 m – central abyss

Ice / Icebergs Approximately 270 icebergs per year.

<1 iceberg in the past 60 yrs. <1% chance of ice cover in winter.

None due to warm N. Atlantic current

Ice cover along German and Danish coasts

None

Sediment Hibernia. – sand with some fines and claysTerra Nova – sand, fines and clays with patches of cobble areas.

Fine to coarse grain sand with some areas of fines, clay, & gravel

Fine sands with low mud, gravel and organic content

Coarser sands and gravel beds, mud patches throughout region

Grey silty clay primarily from the Mississippi Cone. Non-calcareous sands and clays on N and NW shelves.

Currents – wind driven (Surface)

45 – 80 cm/s 30 - 40 cm/s 12.8 – 36.1 cm/s 5.1 – 18 cm/s 50-200 cm/s

Currents – Bottom Usually < 4 cm/s 1.1 –2.6 cm/s summer2.7 –6.7 winter

NA NA 13.4 –29.8 cm/s for depths of 35 – 100 m; possible>100 cm/sec at depths >1000m

Number of Projects 2 (1 in production) 2 (1 in decommissioning)

858 exploration and appraisal wells144 production sites 5

~3,500 oil and gas “platforms”

Commercial Fisheries Existing offshore fisheries Existing offshore Fisheries

Existing offshore fisheries

Existing offshore fisheries Existing offshore fisheries


Source: 1. Mobil, 1985 and Petro-Canada, 1997 2. SOEP 1996 3. MMS 2000, MMS 1989 4. Korevaar, 1990 5. Hardisty, 1990. NA = not available


Physical Environment6.1

This section will discuss the physical environmental conditions of areas of present oil and gas development on the east coast of Canada (Grand Banks, and the Scotian Shelf), the Gulf of Mexico, and the North Sea. There are unique conditions in each of these environments which need to be considered when assessing the potential for impacts from drilling discharges. The physical environment of the east coast of Canada is generally dynamic and currents and seafloor conditions on the Scotian Shelf in particular are very dynamic. Storm activity on the Grand Banks creates more periodic events that have potential for transporting deposited drilling wastes. For these reasons, significant accumulations of drilling wastes have not been found in most areas offshore eastern Canada. Hydrodynamic conditions in deeper waters offshore eastern Canada are severe as well. Physical conditions are variable in the Gulf of Mexico. The North Sea is a semi-enclosed basin with higher energy conditions in the southern portion than in the northern portion. For this reason, greater accumulations of drilling wastes have been reported in the northern and central portions rather than the southern North Sea.

Grand Banks6.1.1

The Grand Banks is a continental shelf which extends off Newfoundland’s east and south coasts for more than 475 km, and covers an area of over 270,000 km2 (Mobil, 1985). Bottom depths generally range between 76 and 88 m, however depths can drop to over 1000 m within 5 km of the shelf edge (Figure 6.1). The major portion of the Labrador current flows to the east of the Grand Bank through the Flemish Pass between the Grand Bank and the Flemish Cap. Large clockwise eddies often form on the southeastern edge, or Tail of the Grand Bank.

Three main water masses are discernible on the Grand Banks and are based on their varying salinities and temperatures. The Labrador Current, which is the main influencing body of water for the Grand Banks, has a salinity between 34.0 and 34.3% and a temperature between 0 and 1.0ºC. The Atlantic Current water has a salinity between 34.7 and 35.1% and a temperature between 8.0 and 10.0ºC and often is associated with warm eddies arising from the Gulf Stream. The Grand Bank or Shelf Water is generally found over the entire Grand Bank and comprises the third main water type. It has a salinity of 34.1 to 34.5% and a temperature of 4.0 to 6.0ºC. A fourth water mass is often detected along the eastern and southern edges of the Grand Bank below 50 m and is a mixture of the Labrador Current water and the Atlantic Current water (Mobil, 1981).


Figure 13 Locations of three oil fields on the Grand Banks; Hibernia is drilling and producing; Terra Nova is in the development stage with drilling only ongoing; White Rose is in the permit stage with several delineation wells to date


Four major types of currents influence water mass movement on the Grand Banks; large-scale, long term currents which define circulation, mesoscale currents of intermediate duration, short-term or wind driven currents, and tides (Mobil, 1985). Tides on the Grand Banks are semi-diurnal and have maximum tidal current speeds of 28 cm/s at a depth of 25 m, 18 cm/s at 50 m and 15 cm/s at 80 m depth (Evans-Hamilton, 1981). Moored-current-meter data collected by Seaconsult (1988) between 1980 and 1986 from the Terra Nova site, indicated that the annual mean current flow speed is generally weak at 3.6 cm/s near the surface in a southwest direction; 1.8 cm/s at mid-depth in a northwest direction; and, 0.3 cm/s near the bottom in a northwest direction. However, current speeds may vary five-fold from the means (Petro Canada, 1995). Extreme current speeds with a one-year return period have also been determined to be 75 cm/s in a westerly direction at 20 m depth, 76 cm/s in a southwesterly direction at 45 m depth and 61 cm/s in a southeasterly direction at 70 m depth (Seaconsult, 1988).

In the centre of the Grand Banks, vertical mixing of the waters in winter is intense and thermoclines are not usually established. The water temperature from the surface to the bottom is generally around 1ºC. Maximum thermal stratification occurs on the southern Grand Banks, at a depth of 60 m between July and September when water temperatures may range between 0 and 15ºC. During the fall 1997 baseline characterization program for Terra Nova, CTD profiles indicated two water masses with a distinct thermocline between 30 and 50 m. The upper water mass was characterized by warmer (12 to 15oC) temperatures while the deeper water mass was characterized by low temperatures (-0.8 to -1.2oC near bottom), slightly higher salinity and slightly lower pH (JWEL, 1998).

During the baseline characterization of the Terra Nova site, sidescan sonar was used to determine the composition of the seafloor. Within the study area the seabed was homogenous on a regional scale and composed of sand and gravel. On a smaller scale, the sands were distributed in poorly organized large-scale low amplitude bedforms (sand ridges and sand waves) superimposed on a coarser (sand with scattered gravel and cobbles) substrate (JWEL, 1998). Particle size analyses conducted during the same study indicate that the substrate is 6.75 % gravel, 91.35% sand, 0.84% silt and 1.06% clay. At the Hibernia site, the bottom type was found to be similar in particle composition; 6.1% gravel, 92.3% sand, 0.27% silt, and 1.36% clay. Barrie and Collins (1989) determined that substrates at depths greater than 110 m are sandy with a grain size of about 0.2 mm, whereas substrates at depths less than 100 m are sandy with a grain size of 0.35 mm and interspersed with gravel (Barrie and Collins, 1989). Another common feature of the seafloor on the Grand Banks is iceberg scour; continuous or interrupted linear gouges or pits created by grounded icebergs (Petro-Canada, 1995). At the Terra Nova site up to 62 scours have been identified with a mean length of 566.3 m, a mean width of 24.8 m and a mean depth of 0.6 m. The maximum depth of a scour was determined to be 1.5 m.


Scotian Shelf6.1.2

The Scotian Shelf comprises the continental shelf region to the south and east of Nova Scotia. With an area of approximately 120,000 km2, the shelf is over 700 km long and 100 km wide off southwest Nova Scotia and extends eastward. Three zones have been demarcated; an inner coastal zone, a central zone and an outer zone, each having distinct topographic features. The inner coastal zone has a rough topography and is characterized by having many rocks, shoals, and islands. The central zone is comprised of both deep basins and shallow banks with depths of >200 m and <100 m, respectively (Figure 6.2). Two of the larger basins in the central zone include the Emerald Basin and the La Have Basin. Some of the predominant banks include, from northeast to southwest, Banquereau, Middle Bank, Sable Island Bank, Western Bank, Emerald Bank, La Have Bank and Browns Bank. Of these, the most extensive bank is the Sable Island Bank from which emerges Sable Island, the only bathymetric feature of its kind in the northwest Atlantic. The outer zone, extending to the edge of the continental shelf is comparatively featureless and consists of broad flat banks with relatively little bottom relief (SOEP, 1996).

In the shallow water near Sable Island, ebb tides travel southward at up to 100 cm/s whereas flood tides travel to the north at 75 cm/s. In the deeper water of the Scotian Shelf, tidal currents are generally slower and have been recorded at 15 cm/s at a depth of 100 m (SOEP, 1996). Wind can generate two types of current motion. Inertial motion, which generally lasts for several days during and following a storm, can create currents of 30-40 cm/s at the surface. These currents rapidly attenuate with increasing depth. Forced motion is generated directly by a storm event and the currents, which persist for the same period as the storm, can cause mean daily surface currents of up to 25 cm/s (SOEP, 1996). Extreme current speeds with a one-year return period have been determined by Seaconsult (1984) to be 56.5 cm/s in a southeasterly direction at 1 m above the seabed, north of Sable Island.

The water column structure over the Scotian Shelf is very diverse and is influenced by many water types. Surface water from the Gulf of St. Lawrence, the Cape Breton Current, passes between Cape Breton Island and southern Newfoundland and converges with the Labrador Current over Banquereau. The upper layer is derived from the Cape Breton Current and has large seasonal variations in temperature and a salinity of less than 32%. The middle layer comprises waters from both the Cape Breton Current and the Labrador Current and generally has a temperature less the 5ºC and a salinity between 32 and 34%. The bottom layer is water from the Labrador Current, which remain less than 5ºC and have a salinity range between 32 and 33%. To the south of the Scotian Shelf, the predominant current is the gulf stream. The northern boundary, or “wall” of the gulf stream leaves the continental shelf break near Cape Hatteras, at 75oW, and turns NE


(SOEP, 1996).

Drilling Waste Management Review August, 2000

Figure 14 Scotian Shelf Production Activity

Drilling Waste Management Review August, 2000


Most of the shallow banks on the Scotian Shelf have a substrate comprised of Sable Island sand and gravel. Substrate in the basins is generally clay and silt. Around the edges of basins and banks, the substrate is composed primarily of sand (SOEP, 1996).

Deepwater Eastern Canada6.1.3

Exploration activity offshore eastern Canada is moving towards waters significantly deeper (1000 to over 3000 m) than those found on the Grand Banks and Scotian Shelf. One such area of exploration is the Scotian Slope, the area seaward of the Scotian Shelf. Oceanographic data collected in this area for use in design specifications of drilling rigs, indicates that hydrodynamic conditions are quite severe (J. Heideman, pers. comm). Wave conditions are more severe than those of the North Sea, extreme surface currents may reach 1.4 m/sec. Wind generated currents from storms would be expected to be up to 0.5 m/sec over the upper 200 m of the water column. Currents do dissipate in intensity as depth increases from the surface. Currents at 150 m are estimated to be 90% of the surface current, 50% the surface current at 300 m, and at 600 m, 8% of surface currents. Bottom currents are unknown. Another influence in this area is possible currents and eddies resulting from the meandering of the Gulf Stream.

Gulf of Mexico6.1.4

The Gulf of Mexico is a semi-enclosed sea that is approximately 1.54 million km2 in area and has an average depth of 1500 m. It is bordered by the United States, Mexico, and Cuba with over 2600 km of primary coastline. The water mass within the Gulf of Mexico flows in a clockwise direction as water enters through the Yucatán Channel and outflows through the Straits of Florida forming a large eddy termed the Loop Current and generally maintains an average position at 25ºN and west of the 2000 m isobath off the Florida Coast. Seven water masses have been identified in the Gulf down to 1000 m. Gulf, or Common, Water is the predominant water type throughout the Gulf and extends to a depth of 250m. Sea surface temperatures are generally isothermal throughout the Gulf in August at 30 ºC. However, in January water temperature range from 25 ºC in the Loop Current to 14-15 ºC along the shallow northern coastal estuaries (MMS, 2000). Below 150 m depth, August temperatures range from 18-19 ºC in the Loop Current and Western Gulf, to 15-16 ºC in the Gulf Water. Below 1000 m, the water temperature remains relatively constant at 4.9 ºC (MMS, 2000).

Salinities vary throughout the Gulf. In the nearshore environment, the salinity is reduced due to freshwater runoff from the Rio Grande and the Mississippi River. In the Gulf, the stratification of fresh and marine water in the water column results in large volumes of the organic matter, mostly from the Mississippi River, decomposing and removing the


available oxygen from the underlying marine waters.Current speeds vary widely throughout the Gulf depending on the season, the location and the depth. At the mouth of the Mississippi River at a depth of 1000 m current speeds of 13.4 cm/s have been detected (MMS, 1989). Eddies derived from the Loop Current, which can have diameters ranging between 300 and 400 km can have surface velocities between 50 and 200 cm/s. Other extreme surface currents are wind-generated. During hurricanes surface currents may reach 150 cm/s and following the storm event inertial currents of 50 cm/s may persist for three to five days (MMS, 2000).

Sediments are varied throughout the region and range from carbonate debris off Florida, mud and silt off Mississippi and Louisiana, to sands and silts over the rest of the shelf region (Groves and Hunt, 1980).

North Sea6.1.5

The North Sea, in the Northeastern Atlantic, is bounded by six countries; the United Kingdom, Netherlands, Belgium, Germany, Denmark, and Norway. It is a shallow, rectangular basin with a surface area of 575,000 km2 and a water volume of approximately 54 km3 (McIntyre and Turnbull, 1993). Depths range between 30 and 200 m with the main bathymetric feature being Dogger Bank which separates the northern North sea from the southern North Sea.

The North Sea is a semi-enclosed body of water that receives inflow at both ends from the Atlantic Ocean. The greatest volume of water comes from the north and west of the British Isles and enters the North Sea between the Shetland Islands and Norway. This water has a high salinity, is nutrient rich, and generally extends southward. Lower salinity water flows into the North Sea from the north and west between the Shetland Islands and the Orkney Islands and travels down the east coast of the British Isles mixing with freshwater outflow from Tyne/Tees Rivers, the Humber River and various other rivers. On the eastern side of the North Sea, low salinity water enters from the Baltic Sea. Surface salinities in winter range from 29% at the confluence of Elbe River in Germany, to >35.4% north of the Shetland Islands. The horizontal water circulation is generally in a counterclockwise direction as water enters through the Straits of Dover and moves in a northeast direction over the Southern Bight to the German Bight. Vertical water movement is usually the result of a thermocline breakdown. In the northern North Sea temperature stratification usually occurs between 20 and 40 m throughout the summer. In the winter the thermocline diminishes and a complete turnover of the water column occurs. In the southern North Sea, where the depths are generally less than 50m, large tidal ranges and high current speeds break down any thermal stratification and temperatures are homogenous year-round. The minimum mean sea surface temperature is


4.5ºC, whereas the maximum mean sea surface temperature is 16.6ºC (Korevaar, 1990).

The sediments in the southern North Sea to the north side of Dogger Bank are mostly sand, sand/gravel, or mud/sand which are either derived from coastal erosion or are older glacial sands (Morris and Howarth, 1998). Frequently subjected to strong wave and current action, these sediments form large unstable underwater sand dunes. Off the Dutch coast the bottom is generally gravel, boulders and bedrock. In central and northern North Sea, large expanses are fine sand and mud with the deeper channels being filled with mud (McIntyre and Turnbull, 1993). There is no net accumulation of sediment in the North sea and the sediments are generally considered to be dispersive. Mixing of sediments is usually the result bioturbation, wave or current action, or fishing activities (Rowlatt and Davies, 1995).

Each of these areas of oil and gas production has its own unique physical environmental characteristics including water depth, current speed, storm events, bottom type, bottom temperature, and the presence of water column stratification that influence how drilling wastes are dispersed and ultimately their persistence on the seafloor.

WBMs6.2

WBM Dispersion Behavior and Modelling6.2.1

The dispersion of WBMs is largely dependent on currents and water column characteristics near the particular site of discharge. Many components of WBMs are fine-grained suspended particulate or water-soluble components that are carried for kilometres before they settle out. Many constituents of WBMs (i.e., metals) are not water-soluble or readily adsorbed by biota and are bound in the matrix of the barite and bentonite clays that make up a large fraction of the muds. WBM and WBM cutting particles are usually very fine, are widely dispersed and therefore do not form large cuttings piles. Thermoclines or haloclines can restrict the settling of fine particulates, but do not restrict the dispersion through the water column. If surface currents run in a different direction than bottom currents, fine particles are carried and may settle separately from coarser material. Field measurements indicate that the neutrally buoyant portion of a discharge at the waters surface, contains only 5 to 7 % of the total solids discharged (Ayers et al., 1980a).

In many scenarios, finer components of the discharge will flocculate to form larger particles and settle faster than they would individually (Brandsma et al., 1980). A settling velocity of 0.1-0.5 cm s-1 (assuming a 50/50 mixture of bentonite and barite) was estimated for flocculated material in tidally energetic environments (Boudreau et al., 1999). On the other hand, O’Reilly, et al., 1988 found in tests that measured mud solids


fall velocities in seawater (where flocculation occurred) that 70% of the mud solids had fall velocities less than 0.06 cm/sec. However, the degree of flocculation in highly energetic environments, like the Georges Bank, remains uncertain.

Rates of dilution and dispersion of WBMs are usually sufficient to make any effects undetectable. The rate of dilution for WBMs is usually very high immediately after discharge. Figure 6.3 illustrates how the dilution ratio generally ranges from a factor of about 103 at a distance of about 10 m or so to 106, some 1,000 m downcurrent of the discharge. Models and field measurements have calculated dilution rates at 100 to 1, ten seconds after discharge and 1,000 to 1, one minute after discharge (Brandsma et al., 1980). The rate of dilution can vary by an order of magnitude depending on the discharge properties and oceanographic conditions (Andrade and Loader, 1997). The USEPA (1999a) concludes that the dispersion of a WBM plume is considered “sufficient to minimize water quality impacts and water quality toxicity concerns in energetic, open marine waters such as domestic offshore continental shelves”.

Figure 15 Plot Showing the Dilution Ratios Observed in Various Field Studies


Note: TB = Tanner Bank, GM = Gulf of Mexico; MA = Mid-AtlanticDischarge rates ranging from 2 to 160-m3/hr (12.8 to 1,000-bbl/hr) (US EPA 1985 as cited in Patin 1999)

Because of their fine grained nature, WBMs may be more easily resuspended and transported than would NAF cuttings which are generally larger in size and have a greater tendency to adhere to one another. Modelling, and in some cases field studies, have been conducted to determine the potential for resuspension and transport of these fine-grained materials. On the east coast of Canada, models have been used to estimate the concentrations of particulate matter suspended in the BBL, and to compare these concentrations with those determined in the laboratory to cause biologic effects (Cranford et al., 1999a). The authors highlight the possible use of the model to assess operational practices for minimizing impacts to benthic fauna.

WBM Fate and Effects6.2.2

WBMs are generally widely dispersed over the seabed, large piles are usually not formed, and the resulting impacts are generally considered low. Nonetheless, impacts associated with physical alterations like smothering and sediment grain size alteration are still possible


(USEPA, 1999a). The scientific literature strongly support the view that the potential for seabed biological effects resulting from WBM and WBM cuttings discharges depends primarily on the energy of the seafloor environment. Seafloor impacts from such discharges may not be detectable at all in high-energy environments, such as those in shallow water with high currents. In lower energy environments, with slow bottom currents, cutting accumulations and biological impacts may be observed one year after drilling. However, when impacts are observed, they appear to be physical (the result of burial or alteration in sediment texture) in nature, highly localized, and temporary (Smith et al., 1997). This is in contrast to impacts from OBMs that tend to be more severe and long lasting.

The most detectable evidence of the fate of discharged WBMs is barium. Increased amounts of barite discharged compared to OBMs, can be as much as 5 or 10 times more, according to Olsgård and Gray 1995. In the case of NAFs only cuttings are discharged. The only barite that is discharged is that contained in the mud associated with the cuttings. On the other hand, when WBMs are used, the mud as well as the cuttings are discharged. This is the principal reason more barite is discharged when WBMs are used.

Barium concentrations, which are used as an indicator of barium sulfate, can increase from 0 to 100-fold above background at the drill site, but typical increases are 10 to 40-fold. In very high energy seafloor environments, there may be no increase at all (Houghton et al., 1980). Barium sulfate is an inert mineral and the barium is not in a soluble form and consequently is not considered to be bioavailable. Barium levels decrease with distance from the drill site and usually return to background levels within 1,000 to 2,000 m (USEPA, 1999b). Increases in sediment concentrations of other trace metals (As, Cd, Cr, Cu, Hg, Pb, and Zn) associated with WBMs are more spatially limited, generally to within 250 to 500 m of the drill site, although increases at 1,000 to 2,000 m have been noted (see USEPA, 1999b). The primary metals detected beyond 200m are Zn and occasionally Cr.

Sediment barium concentration increases in far-field areas are very much dependant upon conditions of the receiving environment, especially in terms of water currents and depths. In one study reviewed by the USEPA (Boothe and Presley, 1989), it was reported that sediment barium concentrations surrounding wells drilled in water depths of 13 to 34 m were much less than near wells drilled in 76 – 102 m water depths. Just 6% of the discharged barite was accounted for within 3 km of the shallow water wells, compared to 47 to 84% within 3 km of the deeper wells. As would be expected, due to differences in bottom currents, concentrations of barium at the shallow water sites were 1.2 to 2.9 times predicted background concentrations, compared to 2.0 to 4.3 times at the deeper water sites. Field studies do document some instances of localized effects resulting from WBM discharges but there is no sufficient evidence that regional impacts occur (USEPA 1999b).


Effects on water quality from the discharge of drill cuttings come primarily from turbidity, caused by the increase in suspended solids. WBMs contain a greater volume of fine-grained material, therefore, it is likely that they will remain in the water column much longer than the majority of the constituents of NAFs. However, concentrations of WBMs in the water column are so low, and exposure times so short, they are not expected to cause any acute or sublethal effects on pelagic species (Neff, 1987).

Because WBM toxicity is low and dispersion rates are high, significant adverse biological effects in the open ocean water column are not expected to occur and have never been documented. The US EPA imposed toxicity regulations on WBMs discharged to US marine waters based on drilling mud bioassays using the crustacean species Mysidopis bahia (Ayers, 1994). The 96 hr LC50 of drilling WBMs approved for discharge by the US EPA can not be less than 30,000 ppm for the SPP, which falls into the nontoxic category (GESAMP, 1997).

WBM discharge dispersion studies conducted in US waters (Ayers, 1994) show that the solids concentration in the water column drops very quickly with distance and that light transmittance and suspended solids are the only water quality parameters affected. Ayers (1994) illustrates that the maximum time an organism passing directly under the discharge pipe would be exposed to a concentration as high as the LC50 of the most toxic mud allowed for discharge under US regulations would be about 1.2 minutes. The LC50 is based on 96 hours of exposure and therefore includes an additional safety factor in exposure time. Ayers (1994) concludes that because of the low toxicity of the WBMs that are approved for discharge, the short exposure times to potentially toxic concentrations, and the small volume of water affected, clearly illustrate that significant biological effects in the water column are unlikely to result from WBM discharge.

WBM Representative Field Studies6.2.3

Mid-Atlantic6.2.3.1

The study consisted of a pre-drilling and two post-drilling (one immediately after drilling and another one year later) benthic surveys at an Exxon USA exploratory drill site in the Baltimore Canyon area of the Mid-Atlantic (Ayers et al., 1980b). The surveys were conducted during the summers of 1978, 1979, and 1980. The water depth was 120 meters. Sampling stations were arranged along six transects that radiated out as far as two miles from the well site. Sediments were sampled for infauna, metals and hydrocarbons and subjected to grain size and x-ray diffraction analysis. Side scan sonar was used to record persistent physical alterations of the seafloor. Bottom photographs and underwater


TV was used to observe epifauna and provided a means of estimating changes in megabenthic abundance. In addition to the benthic work, currents and water mass properties were measured. Also, detailed measurements of the quantity and composition of the mud and cuttings discharges were carried out and the concentration of solids in the mud plume was measured during two mud discharge dispersion tests. A clay-chrome lignosulfonate mud was used on the well.

Physical alterations to the surficial sediment in the well site area were present in both post-drilling surveys. These physical alterations consisted of increased microrelief (patches of semi-consolidated clay present in small mounds less than 10 cm high covering a 150 m diameter area at the wellsite) due to presence of cuttings and elevated barium concentrations in the sediment (no other metals were elevated). In addition, the clay content of surficial sediments had increased out to a distance of 800 m southwest (down current) of the well site. The authors anticipated these alterations would last for several years due to the low energy benthic environment of this deep-water site.

Clam dredges during the pre-drilling survey did not yield sufficient numbers of megabenthos to measure metal bioaccumulation so this was undertaken using macrobenthos. The results are somewhat suspect because only a 24 hr depuration period was allowed for the organisms to clear their alimentary canals (The optimal holding time for depuration is 2 - 3 days; however, field observations made during the pre-drilling survey showed that the organisms would not survive a 2 day holding period). Barium was elevated in polychaete worms and brittle stars immediately after drilling but not one year later. No other metals were elevated with the possible exception of chromium (there is weak evidence that chromium was elevated in some taxa as a result of the discharges). Barium levels in the organisms did not correlate with barium levels in the sediment. Megabenthic (demersal fish and crab) abundance was increased in the well site area after drilling and the increase was still observable one year after drilling was completed. Macrofauna abundance levels were lower at all stations in the first post drilling survey relative to the pre-drilling survey. This was attributed to natural variability except for those stations near and southwest of the wellsite. These stations had significantly lower abundance levels than the others. The decrease in abundance at these stations was attributed to burial effects and changes in sediment texture caused by the cuttings. These effects were much less evident one year later in the second post drilling survey. Also, one year later abundance levels at all stations had increased. As before this overall increase was attributed to natural variability. With the exception of the burrowing brittle star Amphioplus macilentus which remained depressed within 90 meters of the well site one year after drilling), macrobenthic abundance levels exhibited little or no spatial trends and no correlation with sediment barium concentrations. Diversity exhibited little if any change between pre-and post-drilling surveys except for those few stations near the wellsite that


had much lower abundance levels due to burial effects. Overall, the abundance levels of macrobenthos observed one year after drilling were well within the range of natural variation for this region of the continental shelf and the authors concluded that the impacts remaining one year after drilling were localized and minor.

This particular study demonstrates the general lack of meaningful impacts associated with WBM and cuttings discharges. This particular site has many characteristics that make it especially vulnerable to drilling discharge impacts. The water depth of 120 meters is (1) too deep for storm waves to resuspend and disperse drill cuttings and mud solids but (2) not so deep that the deposited solids are widely dispersed over a large area and present in insignificant concentrations in the sediment. Also one might expect alteration of sediment texture (by addition of clay to normally sandy bottom) to effect benthic recruitment. Even under these conditions, measurable biological impacts after drilling were relatively minor and had almost disappeared one year later.

North Sea6.2.3.2

A similar two–phase study was conducted in the North Sea, where the benthic community near a single well site was monitored for changes two months and one year after WBM drilling had ended (Daan and Mulder, 1993). The physical conditions between the sites created a much different effect. However, in the North Sea, the two-month survey revealed drill cuttings within a 25 m radius of the site, but 10 months later, no trace of cuttings could be found. The water depth at this well site was 45 m, compared to 120 m at the site off New Jersey. Daan and Mulder (1993) surmise that the cuttings were resuspended with the clays in the high-energy environment and dispersed from the site.

The lack of cuttings accumulations from WBM discharges meant that benthos were not significantly affected. No change in the benthic community could be detected during the 2 or 12 month surveys (Daan and Mulder, 1993). These findings are consistent with those of Neff (1987), who concluded that cuttings would only accumulate in low energy environments and that effects on benthic communities would only be detectable where smothering took place. Such is the case with discharges of SBMs from SOEP on the Sable Island Bank. Cuttings there have not accumulated, but have been dispersed by bottom currents and storm events (JWEL, 2000a).

California6.2.3.3

Effects of bioaccumulation of metals from WBM discharges were studied in the Santa Barbara Channel off California by Jenkins et al., (1989). Three species were selected for contaminant testing; a clam, a filter feeding polychaete and a deposit feeding polychaete.


Barium concentrations increased significantly between pre- and post-drilling sampling at all down-current stations to 1,500 m. In addition, total and bioavailable barium concentrations declined sharply with distance from the well. Each species was tested for barium concentrations and statistically significant increases were found in the clam and the filter feeding polychaete. However, over 97% of the barium remained in the granular pellets and in an insoluble form, presumably BaSO4. The remaining 3% is thought not to be sufficient to be toxic to the clam or the polychaete (Jenkins et al., 1989).

Gulf of Mexico6.2.3.4

Long-term studies on the impacts of WBMs have been conducted in the Gulf of Mexico by the Minerals Management Service (MMS). The Gulf of Mexico Offshore Operation Monitoring Experiment (GOOMEX) is a broad based multi-disciplinary research project designed to evaluate methodologies used to monitor the biological, biochemical and chemical effects of low level stresses on the ecosystem resulting from the presence of the production platform and discharges (WBM, produced water, produced sand, waste water etc) during exploration, development, and production phases of oil and gas. Three sites with decades of oil and gas production history were chosen for long-term study, all situated in northwestern Gulf of Mexico in 29 to 125 m of water. Five distances were measured between 30 and 3,000 m from the platform, along five radials. Benthic communities were evaluated with each distance and changes in community structure were tested for correlation with sediment chemistry. The health of fish and invertebrates were assessed using a control-impact design. Several physiological responses were measured at a site <100 m from the platform and at a comparison station > 3,000 m from the platform. All studies were completed 6 to 12 years after drilling activity had ceased.

Sixteen fish and four mobile invertebrate species were tested for several different physiological responses and no differences between the near-field and far-field (control) sites were determined (McDonald et al., 1996). No bioaccumulation of hydrocarbons or metals was detected in any of the invertebrate or fish species tested. However, effects at the benthic community level were apparent. Benthic communities near the platform (< 100 m) were altered by the physical structure and discharges associated with exploration and production. It has also been determined that the nearfield bottom is often altered due to the mollusc shells that fall off the platform overtime, and the hard debris that falls from the platform. These all change the general grain size distribution near the platform, therefore causing a change in the benthic community. Abundance of deposit feeding nematodes and polychaetes increased within 100 m of the platform, indicating organic enrichment, while the numbers of amphipods and harpacticoids declined (Montagna and Harper, 1996).

The effects on the more mobile species (e.g., shrimp, crab) of the benthic community were


distinct between platforms in terms of size distributions and abundance, but these differences may be due to naturally occurring differences between these areas. Community-level differences between near-field and far-field sites were always less frequent in deeper areas around each platform. The effects of seasonality on population structure and time of day changes in behavior were also less apparent with increasing depth (Ellis et al., 1996).

The presence of drill waste was observed over a few hundred metres from each of the three platform sites, but the gradient between platform sites was much different. The distribution of cuttings at each site varied due to how the cuttings were initially discharged and how local oceanographic conditions redistributed the cuttings. Hydrocarbons resulting from the operations were detectable not more than 500 m from the platform, whereas concentration gradients for certain metals (Ba and or Cd ) were apparent out to 3 km from two of the three platforms and 5 km for the other (Kennicutt et al., 1996). Although the water depth was around 125 m, the fact that the actual discharge (release of mud and cuttings) occurred near bottom (~10m off bottom, Jim Ray, pers. comm) would lead too much higher than usual metal levels in the sediments (Peterson et al., 1996). The highest PAH concentration did not exceed levels known to cause biological effects. Years of physical and biological degradation reduced initial hydrocarbon concentration, especially at shallower sites. However, at deeper locations (>80 m), the concentration of some metals (i.e., Cd and Hg) did exceed levels known to cause effects, several years even decades after drilling had ceased (Kennicutt et al., 1996). Interstitial water collected within 100 m of a platform did induce toxic response in several test organisms. Tests results were correlated with high concentrations of trace metals (Carr et al., 1996). This study also observed some toxic responses at reference stations, emphasizing the need to include enough reference stations to discriminate natural variability from effects caused by oil and gas operations (Jim Ray, pers. comm). This particular location was not typical in that dispersion was inhibited by deep water and cuttings were dispersed close to the sea floor.

Conclusions from this comprehensive study are that benthic communities near platforms are determined by a complex interaction of variations in grain size, organic matter enrichment (likely from fouling organisms growing on the platform and falling to the bottom) food and sewage waste inputs, and toxic response to contaminant exposure. Contaminant levels during these studies only exceeded levels thought to produce deleterious biological effects (i.e., PAHs at 4,000 ppb) at a few stations close to the platform.

Although levels of contamination were low, the study suggests that benthic environments around platforms were disturbed as a result of the presence of the platform, and the discharges derived from exploration and production activities.


Georges Bank 6.2.3.5

This comprehensive three year study was aimed at assessing area wide and site specific impacts of exploratory drilling on the benthic environment of Georges Bank, an important fishery located off New England (Neff, et al., 1989b, Bothner et al., 1985). Water based muds and cuttings were discharged, however, diesel fluid was added on two occasions to free-trapped pipe (Danenberger, 1983). The US Department of Interior funded the study. The principal investigators were Battelle, Woods Hole Oceanographic Institution, and the US Geological Survey. The monitoring program was carried out during the period 1981-84.

A joint federal (Natural Resources Canada) and provincial (Nova Scotia Petroleum Directorate) Review Panel has examined the potential for petroleum development on the Georges Bank (Georges Bank Review Panel Report, June 1999). The Review Panel commissioned two studies on the environmental effects of drilling waste discharge to the ocean.

Cranford et al., (1998) investigated the lethal effects of WBM on scallop, lobster and haddock larvae. This larval stage was selected, as it is the most sensitive to toxic effects. The Cranford study concluded that that there are no lethal effects anticipated from WBM discharge except at very highly localized concentrations.

Boudreau et al., (1999) conducted a study on the potential sub-lethal effects of WBM discharge on the Georges Bank. Boudreau combined bioassay studies and a benthic boundary layer transport model to predict the effects of WBM constituents (bentonite and barite) on adult scallops. Model simulations indicated a reduction in growing days within the WBM plume. The study concludes that lost growing days could potentially result in reproductive loss, however, the overall effect on scallop populations could not be determined.

Surficial sediments were sampled for chemical and benthic infauna analysis at 46 stations during 12 quarterly field surveys. The field monitoring was initiated just before drilling began and continued for nearly two years after drilling was completed. Twenty-nine stations were dedicated to site specific monitoring and were arranged in a radial array around a well site in 80 meters of water. The remaining stations were designated as regional and were distributed upcurrent, downcurrent and through the lease area. Three were grouped around another well site in 140 meters of water.

During each quarterly sampling, 6 replicate grab samples were taken at each station for infaunal and grain-size analysis and 3 for chemical analysis. Bottom photographs were


taken to document epifauna and microtopography at each station. Dredge and trawl samples were collected at some regional and site specific stations to obtain larger organisms for chemical analysis. Temperature, salinity and dissolved oxygen in the water column were also measured. In addition, the composition and quantity of drilling discharges from the 80 m water depth well site were monitored. The mud used was a clay-chrome lignosulfonate system.

During the period when drilling occurred, barium concentrations increased in bulk sediments near the well sites. No other metal concentration was elevated. Chromium concentrations were elevated in the fine fraction (about 5% of bulk sediment). However, a small but statistically significant increase in the concentration of aromatic hydrocarbons was noted at one of the stations near the well site in 80 meters of water. No increase of metal or hydrocarbon concentrations in bulk sediments was observed at any of the regional stations, though barium was elevated in fine fraction of sediments obtained from some of the downcurrent regional stations. The benthic fauna were abundant and diverse throughout the study area. There was a strong relationship between community structure, sediment type and water depth. Little seasonal variation was detected in the dominant species. Statistical analysis showed that combined replicates from a station always clustered with samples taken from that station on other cruises. The excellent replication and uniformity made it possible to detect very subtle changes in community parameters that might be related to drilling discharges; however, no changes were detected in the benthic communities that could be attributed to drilling activities.

Lower Cook Inlet Study6.2.1.6

Benthic communities in the vicinity of an exploratory well in Lower Cook Inlet, Alaska were studied before, during and after drilling (Dames and Moore, Inc., 1978; Lees and Houghton, 1980; Houghton, et al., 1980). The study was funded by ARCO and Dames and Moore was the environmental contractor. The well was located in 62 meters of water in a dynamic environment characterized by strong tidal currents (up to 104 cm/sec) and high suspended sediment loads (up to 20 mg/l). There was no visual evidence of drill cuttings (as determined by underwater photography) nor was there any elevation of barium in the sediment. The investigators were unable to demonstrate a statistically significant impact on the benthic fauna due to drilling discharges in this high energy environment. This study also examined possible water column impacts. Pink salmon fry Oncorhynchus gorbuscha, shrimp Pandalus hyupsinotus and hermit crabs Elassochirus gilli were suspended in live boxes at 100, 200 and 1000 meters downcurrent from the discharge source. After four days, there were no mortalities or sublethal effects that could be attributed to the mud discharge plume.


OBMs6.3

OBM Cuttings Discharge Modelling6.3.1

As previously described, OBMs are invert emulsions. The characteristics of OBMs that make them prevent hydration of shales and cuttings in the wellbore, prevent the hydration and dispersion of drill cuttings in the water column. Settling velocity studies have observed that cuttings with high residual mud retention tend to agglomerate and settle more rapidly than similar WBM cuttings. The combination of low hydration of shales and agglomeration of cuttings has been modelled to indicate that OBM cuttings settle rapidly and are deposited near the discharge point.

Brandsma (1996) concluded that treatment of cuttings to reduce the oil content below 5% reduces settling velocities so that oil remains in the water column at 1000 m. Although treatment raises oil concentrations well above background levels, the exposure to oil from OBM cuttings particles appears to be several orders of magnitude below levels that would cause toxic effects in the water column.

Traditional OBMs discharged in the 1970s in the North Sea were discharged using the available solids control equipment. In the late 1970 through the 1980s, improvements in solids control reduced the retention on cuttings allowing for more shale hydration, and more dispersion of the discharged cuttings. One technique for lowering the retention included washing the cuttings.

OBM Fate and Effects6.3.2

Most of the knowledge about OBM cuttings discharge impacts was developed from seabed studies conducted on North Sea sites that began operations in the 1970s. While disposal practices improved from the 1970’s to the 1980’s the seabed surveys continued to evaluate the same locations. Consequently, the residual material from previous disposal practices masked many of the improvements in environmental impact.

The most comprehensive chemical and biologic studies on the impacts of discharging diesel cuttings have been conducted in the UK sector of the North Sea. There is limited information from other sectors of the North Sea, and little to none outside of the North Sea area. Based on the detailed site assessment at locations in the North Sea where both OBM and WBMs were discharged, the Paris Commission Working Group on Oil Pollution published in 1985 a list of "agreed facts" on the impacts of OBMs on the marine environment. The main environmental points, were originally published by Davies et al., (1988). Several years following the development of the agreed facts, more recent (post-


1983) North Sea survey data were examined to determine whether the agreed facts still held and to fill in initial knowledge gaps (Davies et al., 1988). The results of this further research on the effects of OBM cuttings discharges (Davies et al., 1988) resulted in the summary of the various zones of influence as provided below in Table 6.2. These “agreed facts” have not been modified or re-evaluated since the late 1980’s and reflect the impacts that result from discharging the early generation oil based muds (diesel and mineral oil) in the North Sea. Additional information on particular studies is provided in the following paragraphs and sections.

Table 6.2 The Zones Of Effect Of OBM Cuttings Discharge(modified from Davies et al., 1984; Davies et al., 1988)

Zone Maximum extent within Range

Chemistry Biology

I 0-500 m •

development wells0-250 m single •

wells

High hydrocarbon levels- ≥1000x background; sediments largely anaerobic

Impoverished and highly modified benthic community (beneath and close to platform the seabed can comprise cuttings with no benthic fauna)

IITransition

200-1000/2000 m •

development wells out to 500m •

single wells

Hydrocarbon levels 10-700x background

Transition zone in benthic diversity and community structure

III 800-4000 m •

development wellsout to 1000 m •

single wells

Hydrocarbon levels return to background (1-10x background)

No benthic effects detected

IVBackground

No elevation of hydrocarbons

No benthic effects

Studies of fields where drilling discharges have ceased indicate that recovery and recolonization of the transition zone begins within 1-2 years, accompanied by hydrocarbon degradation. The transition zone begins to move inwards, despite the potential outward distribution of hydrocarbon-laden sediments (Davies et al., 1988). However, studies of longer term impacts indicate that the aerial extent and magnitude of effects of OBM cuttings discharge on benthic biological communities was highly variable (Olsgard and Gray, 1995). Over a period of six to nine years after termination of cuttings discharge, the sediment contamination spread so that nearly all stations two to six km from the drill site


showed evidence of elevated hydrocarbon/metals levels. There was evidence of oil biodegradation in sediments following cessation of discharge; however, effects on benthos persisted longer than the elevated hydrocarbons, suggesting that metals or some other cuttings component were contributing to the long-term effects of the discharges. Results of the Dutch North Sea monitoring program indicated that localized hydrocarbon contamination and biological effects were detectable in the Dutch North Sea as long as eight years after drilling, although the general trend is towards recovery with time. Grahl-Nielson et al., 1989 found little decrease over a five-year period, in hydrocarbon levels resulting from OBM discharges.

Consequently, the combination of a history of high OBM retention on cuttings and measurable long term impacts led the North Sea to the phase out of OBM cuttings discharges. However, in other areas, the same impacts observed in the North Sea have not been duplicated. In these areas, the combination of using a fluid lower in aromatics (an LTMO), improved solids control equipment, and the energy of the receiving environment has resulted in lower impacts and more rapid seafloor recovery.

OBM Representative Field Studies6.3.3

North Sea6.3.3.1

As with Sable Island Bank, bottom currents and storm events at the Ekofisk field in the North Sea are believed to be responsible for cuttings pile degradation (Cripps and Westerlund, 2000). Water depths in this field range from 70 to 90 m and sediments consist mainly of medium to fine sand. Seven accumulations of cuttings were measured and the rate at which the height decreases was significantly correlated with post-drilling age. This exponential rate of erosion suggests that larger piles erode faster, as one would expect. The average rate of decrease in height was calculated as 26 cm/year and a decrease in volume that ranged from 100 to 600 m3/yr. The piles investigated ranged from 900 to 5,300 m3, classified as small to medium in size.

Another study in the Ekofisk field summarized regional monitoring results from 1996 to 1998 (Byrne, 2000). Contamination was defined as TPH concentrations above 10 ppm (mg/kg) and effects on the benthic community was defined as a Shannon Wiener diversity index of less than four. Byrne (1999) concluded that 0.2% (approximately 50 km2) of the Ekofisk area (approximately 26,900 km2) was contaminated with hydrocarbons and that less than 0.1% (approximately 15 km2) showed stress on the benthic community.

Similar calculations on other fields in the North Sea were conducted and the area of contamination ranged from less than 0.1 to 1%, approximately 100 km2 in total from these


areas Byrne (1999). The area where benthic community diversity had been affected ranged from less than 0.1 to 0.2 percent approximately 25 km2 in total from these areas (Byrne, 2000). The long term sampling efforts indicate that even in the areas impacted in the North Sea from OBMs are localised and have not caused regional contamination of the seabed.

In regard to long-term impacts, Olsgard and Gray, 1995 reviewed 24 field surveys of 14 oil fields on the Norwegian continental shelf to examine long-term impacts of and recovery from OBM cuttings discharge. They found that the aerial extent and magnitude of effects of OBM cuttings discharge on benthic biological communities was highly variable. For three fields that were extensively studied, the aerial extent of sediments with elevated hydrocarbon and metal (primarily barium) content, ranged from 10 km2 to over 100 km2. Over a period of six to nine years after termination of cuttings discharge, the sediment contamination spread so that nearly all stations 2 to 6 km from the drill site showed evidence of elevated hydrocarbon/metals levels. There was evidence of oil biodegradation in sediments following cessation of discharge; however, effects on benthos persisted longer than the elevated hydrocarbons, suggesting that metals or some other cuttings component were contributing to the long-term effects of the discharges.

Daan and Mulder, 1996 examined some of the long-term impacts of OBM cuttings discharges in the Dutch North Sea. The results of their studies of drillsites in the Dutch Sector of the North Sea indicated elevated hydrocarbons in sediments up to 750 – 1000 m from the well site during the first year after drilling. At distances greater than 500 m from the well site, hydrocarbon concentrations tended to decrease to natural background levels within a few years. Hydrocarbon concentrations remained well above background levels for at least eight years at some stations within a few hundred meters of the well site. The highest concentrations were found 25-30 cm below the sediment surface. Benthic impacts were initially observed out to 1000 m, with the number of species affected and the severity of effects increasing with decreasing distance from the well site. Within a few years, recovery was evident at locations more than 500 m from the well sites. Benthic communities near the well site were still adversely affected eight years after drilling terminated.

A similar summary by Dann and Scholten of the results of a 1985-1995 Dutch North Sea monitoring program indicated that localized hydrocarbon contamination and biological effects were detectable in the Dutch North Sea as long as eight years after drilling, although the general trend is towards recovery with time. Categorization of sites according to water depth and potential for sediment erosion is a key feature of the Dutch monitoring program. The Dutch sector of the North Sea consists of waters of mostly less than 50 m depth. Sites in the southern part of this sector are considered to be in the


erosion zone. In this area, waters are less than 20 m in depth, bottom currents are strong, and the sea bottom comprises coarse sand. Sites in the northern part of this sector are considered to be in the sedimentation zone, where waters are deeper and slower bottom currents lead to more silty sediment conditions. In between these extremes, there is a transition zone of sites at intermediate depths. The results of the monitoring program were organized according to the type of site: sedimentation, transition, or erosion. The erosion-type sites had the smallest zones of hydrocarbon contamination and biological effects.

Gradients in sediment hydrocarbon concentration were detectable up to eight years after the cessation of discharges. The gradients are gradually weakening with time, indicating that hydrocarbons either are being redistributed by currents or are biodegrading. Biological effects can still be detected at relatively low (<1000 mg/kg) hydrocarbon concentrations at some of the monitoring sites. Consequently, although conditions in the Dutch North Sea are favorable for preventing the formation of cuttings piles, benthic biological effects can be detected very close to the discharge site as long as eight years after discharges have stopped.

It is of interest to note that the monitoring results showed that the character of sediment hydrocarbons changes with distance from the source. Close to the source (100 m), gas chromatography-mass spectrometry (GC-MS) evidence shows that the sediment hydrocarbons are clearly related to OBMs. At large distances (5000 m) from discharge sites, the character of the hydrocarbons indicates that their source is something other than OBM cuttings discharges. Possible sources could be hydrocarbons from shipping discharges or shore-based runoff.

Australia6.3.3.2

Oliver and Fisher (1999) surveyed a 23-well operation (North Rankin A) on Australia’s NorthWest Shelf soon after a drill program ended. Eleven of the 23 wells discharged LTMO cuttings in 125 m of water depth. Samples were taken immediately following drilling and at 1, 2 and 6 years following drilling. The findings were that acute biological effects were contained to within 400 m of the platform. Total petroleum hydrocarbon (TPH) concentrations attenuated with distance from the platform, suggesting an approximate half-life of one year for surface sediments. At another drilling site (Wanaea-3/6) where LTMOs were discharged in 70-80 m of water, biological effects were limited to within 100 m and background concentrations of hydrocarbons and metals occurred within 1,200 m of the rig, three years after drilling had ceased. Sediment dispersion mechanisms seem to be important in reducing sediment contamination, even at 70 to 80 m depths. Near-bottom currents were measured at 65 and 30 cm/s on spring and neap tides, respectively and storm events are common in the area. Biodegradation in this area is also


enhanced by year-round water temperatures between 22 and 24°C near bottom. This is a clear example that the observations in the North Sea have not been universally repeated in other receiving environments due to differences in local environment.

At another field (Lynx) on the North West Shelf, Oliver and Fisher (1999) report dramatic reductions of hydrocarbon and barium concentrations in the 12 month period following the completion of drilling. An enhanced mineral oil (EMO - linear paraffin) was discharged in 79 m of water and rapid biodegradation was anticipated, but the decrease in barium concentration suggest the cuttings were dispersed.

Sable Island Bank6.3.1.3

Environmental monitoring continues to be conducted at the Cohasset-Panuke oil fields. The Cohasset production site is located in 40 m of water and is a high energy environment characterized by a sandy bottom and poorly developed benthic community. Oceanographic conditions on Sable Island Bank have minimized the effects of LTMO cuttings discharged from the Cohasset site. Biological and sediment samples were collected at set intervals (250-3000 m) along two perpendicular transacts originating at the production platform. Sediments were analysed for macrofauna, particle size, and total and petrogenic hydrocarbons. Grain size did not detect the presence of drill cuttings and hydrocarbons were detected at just one site (located at 250 m from the platform). There was no evidence of any impact from LTMO cuttings discharge on the benthic community. Hydrocarbons in the LTMO region were not detected past the 1000 m site once the LTMO region correction factor was applied (John Parsons Associates, 1999). The correction factor eliminates the hydrocarbon fraction not associated with drill cuttings.

Contamination of shellfish from the discharge of LTMOs at the Cohasset site was studied as well (John Parson Associates, 1999). Mussels were suspended at mid-depth and near bottom at distances of 250, 500, 1,000, 1,500 m, and 10 km (the control site) from the platform for 6.5 to 28 weeks from 1993 to 1999. Taste panels were used to compare the flavour and odour of mussels from near the platform and from a control site. Tainting was detected out to 500 m only while drilling was underway and active discharge was occurring (John Parson Associates, 1999). Total hydrocarbons were also analyzed and showed that the majority of the contamination was within 500 m of the rig. When active discharge of mud and cuttings was discontinued, 1998, the total hydrocarbons were reduced to background levels. This suggests that recovery of the water column occurs shortly after drilling ceases and that any residual muds do not migrate high into the water column. Again, this is an indication that the observation of seafloor impacts from the North Sea have not been repeated on the east coast of Canada.


SBM6.4

SBM Cuttings Discharge Modelling6.4.1

When discharged into the sea, SBMs do not tend to disperse like WBMs because the cuttings are wet with base fluid. The fall velocities of SBM and OBM cuttings are greater than those for WBMs and WBM cuttings. NAF cuttings will therefore fall more rapidly through the water column, tend to be deposited in confined areas, and are more likely to form accumulations than are WBM cuttings. The dispersion and deposition pattern of discharged cuttings depends upon oceanographic conditions and effluent characteristics. The most influential oceanographic conditions are the horizontal current speed, water depth (in relation to depth of release) and density stratification (thermoclines or haloclines) (Andrade and Loder, 1997). The most important effluent characteristics affecting the dispersion and deposition of SBM cuttings are: the volume of drill cuttings, the level of fluid retention on cuttings, the depth of release, the discharge rate, and the cuttings settling velocity. The settling velocity is a function of particle size and level of fluid retention on cuttings. All these factors interact to determine the dispersion and depositional patterns of the discharge.

Because of the rapid settling velocity of the NAF cuttings (exposure time in the water column is low) and the low aquatic solubility of the base fluids, NAF cuttings discharges are not expected to have an effect on the water column. The USEPA (1999b) modelled the dispersion of SBM through the water column from exploratory and development wells. When concentrations of SBM at 100 m from the discharge point were compared to Federal water quality criteria, no exceedances were predicted at 11% or 7% cuttings retention levels.

Since SBMs were initially used in the early 1990s in the North Sea, they benefited from the numerous advances in solids control equipment from the 1970s and 1980s. Consequently, the volume of SBM discharges have always been lower than OBMs, and lower retention numbers have resulted in greater hydration and dispersion of SBM cuttings. Recent advances in solids control equipment have continued to accelerate the trend toward to lower discharge volumes and lower retention values.

Compared to shallower water depths, deep water will allow greater initial dispersion of cuttings on the seabed. In general, cuttings discharges into deepwater will form thinner accumulations because cuttings will spread over a larger area. Relative to larger, more compact cuttings piles, natural abatement processes will be more efficient at reducing cuttings accumulations that are spread over larger areas. Absolute recovery rates, however, will depend on fluid type and localized environmental conditions including


temperature, current speed, and oxygen availability.

In IBP SHE, 1999 calculations were performed to estimate the spreading and deposition associated with discharge of NAF cuttings a water depth of 999 m. Brandsma (1993) reported that OBM cuttings collected from drilling in the North Sea had fall velocities that ranged from 20 cm/sec to 60 cm/sec. It was assumed that cuttings were discharged into 999 m of water and that ambient currents travelled in a single direction and averaged 3 cm/sec. Under this scenario, cuttings will be deposited on the seabed starting around 50 m from the discharge point and will extend 152 m from the discharge point. If it is assumed that the shifting currents cause cuttings accumulations to form a donut shaped ring around the discharge point bounded by 50 m and 152 m, then the area available for deposition is approximately 65,030 m2.

A single well that discharges 212.40 m3 of NAF-coated cuttings particles (the volume generated from drilling an approximate 38.1 cm diameter well bore 1981 m with NAF) will form a pile that is roughly 33.02 cm deep if we assume uniform deposition, no mixing into sediments, and no water in the pile. If discharges occur in a location where currents tend to predominantly travel in one direction, deposition may be assumed to occur on one quarter of the ring. A single well would generate a cuttings pile roughly 1.27 cm deep with this assumption. In either case, natural abatement processes should be able to handle this volume of cuttings. If, however, this single discharge is multiplied by 50 (the number of wells that might be drilled in a relatively small area for development), then we form a pile with a depth of over 15 cm for the assumption of shifting currents, and 63.5 cm for the unidirectional current. These cuttings accumulation thicknesses, particularly with the non-uniform deposition that will actually occur, may adversely effect benthic communities in the localized area for a longer time than would the thicknesses generated from discharges from one well.

SBM Fate and Effects6.4.2

Because SBMs cuttings are frequently discharged at sites that previously used OBM, fewer studies have been conducted on sites that have exclusively discharged SBM cuttings. SBMs were specifically designed to be less toxic and to biodegrade faster than OBMs. These two SBM attributes combined with lower discharge volumes and lower retention rates since the times when OBMs were discharged, have resulted in overall lower environmental impacts (Jensen et al., 1999). Because the mechanisms of impacts are different between SBM cuttings discharges and WBM discharges, the relative degree of impact is difficult to compare.

SBMs may have more of a physical effect on the seabed than WBMs because SBMs are


more likely to form accumulations on the sea floor whereas WBMs tend to be dispersed over greater distances. The physical effects from SBMs on benthic communities are similar to those caused by OBMs in that they cause smothering, organic enrichment and hence, oxygen depletion (Daan et al., 1996). However, levels of SBM decline much more rapidly than OBMs. In most SBM studies, SBM levels declined significantly, and in some cases to non detectable levels within one year of drilling, compared to little decrease after five years for OBMs (Grahl-Nielson et al., 1989).

The USEPA (1999b) review on the effects of SBM concludes that short term severe effects on the benthic community within 200 m seem likely, and that effects out to 500 m have been demonstrated (Dann et al., 1996). Often, the only species present in affected areas are opportunistic species like polychaetes, specially adapted for survival in highly organically enriched or contaminated soils. Changes in benthic communities may be detectable beyond 500 m. However; these results are highly variable and depend on local conditions and the history of discharge at the site. Norwegian studies find most effects restricted to less than 250 m from the discharge source. Although effects may be measured out to 500 m, noise created by natural variability makes it difficult to ascribe community changes to SBM (Jensen et al., 1999). Although initiation of benthic recovery seems likely within a year of cessation of drilling, complete recovery is unlikely within that time frame. When SBMs were discharged in older fields that had history of previous OBM use, these OBMs still affect benthic fauna (Jensen et al., 1999). Most of the SBM studies indicate evidence of anaerobic conditions, which is consistent with the biodegradation of SBM leading to anoxic conditions in the sediment. These anoxic conditions may have a short term detrimental impacts on the benthos (Neff et al., 2000; IBP SHE 1999).

Toxic effects on the benthic community include indirect chemical toxicity and toxic effects due to anoxia caused by organic loading and biodegradation. In areas with active hydrodynamic conditions, chemical toxicity may play a more important role in SBM impacts than biodegradation as it will be more likely that cuttings will be spread out and will degrade aerobically (not resulting in significant anoxia). In areas with more quiescent hydrodynamic conditions, biodegradation and subsequent development of anoxic conditions may play more of a role in determining benthic effects than chemical toxicity. Ultimately all the field studies emphasize the importance of the local environment, including water depth and current regime, on determining the initial affected area and the persistence of hydrocarbons in the area.

Although SBMs are shown to have some bioaccumulation potential based on the octanol-water partitioning coefficient, hydrocarbons can be metabolized by many types of marine species (Vik et al., 1996). Furthermore, NAFs do not contain any hydrocarbons of environmental concern. Internal olefin SBMs, for example, have been shown to exhibit


high rates of uptake and depuration, with no detectable tissue residue (Environment and Resource Technology, 1994). The USEPA summarized their review of the bioaccumulation of SBMs by stating that the data are “not sufficiently extensive to be conclusive” but that they do suggest that SBMs “do not pose a serious bioaccumulation potential” (USEPA, 1999b).

Representative Field Studies6.4.3

North Sea6.4.3.1

Surveys were conducted in the North Sea 1, 2 and 11 months after a two-month drilling program using an ester-based SBM called Petrofree (Daan et al., 1996). Sediment chemistry and benthic communities were analysed from stations 75 to 3,000 m from the well.

Changes in benthic communities were observed along a gradient towards the rig. The authors speculate that the sensitive species, like echinoderms, were depleted due to organic enrichment. Benthic community richness and total abundance were significantly reduced during the 4 and 11 month surveys out to 200 m from the well and a few species were reduced in abundance up 500 and 1000 m from the rig. During the four month survey, the concentration of esters ranged from 2 to 4,700 ppm, (dry weight) within 200 m, and were detectable up to 3,000 m from the well. During the 11-month survey, the concentrations of esters within 200 m had dropped to range between 1 and 250 ppm. Between 500 and 3,000 m, the esters were below detection level (Daan et al., 1996).

Although effects on the benthic community were detectable after 11 months, signs of recovery were apparent. A substantial fraction of the esters had disappeared and species were beginning to recolonized the area near the rig. Based on the combined effects of degradation and sediment relocation, the half-life of esters was estimated as 133 days, with a lower confidence interval of 68 days (Daan et al., 1996). This study indicates that SBMs are generally characterised by short term impacts and rapid recovery.

In the Norwegian sector of the North Sea, OBM cuttings were discharged up until 1993. After this time, only SBM cuttings and WBMs were discharged. Although it has been assumed that environmental impacts of discharging SBM cuttings are less than those from discharging OBM cuttings, no collation of all seabed survey data had been performed to assess general patterns in environmental effects. Subsequently, three Norwegian organizations (Akvaplan-niva, Olsgard Consulting, and DNV) teamed together to compile and analyse 20 years of seabed studies on the effects of drilling discharges on the seabed of the Norwegian sector of the North Sea and Norwegian Sea. The results are compiled in


a publication (Jensen et al., 1999) that has been submitted to the Norwegian Ministry of Oil and Energy. The SBMs most commonly used in this region are esters, ethers, and olefins.

The major overall conclusions of the survey of field studies were as follows:

results from monitoring studies on fields where only SBMs and WBMs have been used •

indicate that discharges of cuttings associated with these fluids have little or no effect on benthic fauna outside a radius of 250 m. The exception from this is where large volumes of drilling cuttings have been discharged; in general great variations have been found in diversity outside of 250 m regardless of •

what the sediment chemistry is, and it's difficult to isolate discharge effects from natural variation; increase in the density of individuals of tolerant indicator species can be found up to •

1000m from some installations;SBM cuttings discharges have had far fewer effects on soft-bottom communities than •

OBM cuttings discharges, and that effects on soft bottom communities from SBM cuttings discharges are rarely seen outside of 250-500 m; and in older fields, previous discharge of OBMs still affects the fauna to a great extent.•

Other conclusions of the individual organizations were as follows:

DNV: In an area where a number of different drilling fluids were used, seabed studies •indicated that Finagreen (ester) degraded more quickly than Petrofree (ester), Aquamul B II (ether), and olefin based drilling fluids Novasol and Novaplus. However the authors acknowledge that the relative rates of biodegradation may vary from field to field depending upon the type of sediment, hydrodynamic conditions, etc. Olsgard Consulting: Based on multivariate analyses of 12 separate studies on 9 •different fields where SBMs have been used and associated cuttings discharged, reduced diversity was found up to 500 m, but in most cases up to 250 m. Increased density of tolerant indicator species was observed up to 1 km from some installations. Benthic fauna diversity was negatively correlated with concentrations of barium and synthetic drilling fluid. Results of comparison of impacts of different drilling fluids indicate that ether had fewer biological effects than olefins or esters, and olefins had fewer biological effects than esters. Akvaplan-niva: On the basis of statistical analyses, 87% of the species-environment •relation in sediments up to 500 m from the installation can be explained by the following: olefin, lead, copper, particle size, total organic carbon, ester, and distance.

Gulf of Mexico6.4.3.2


A study by Continental Shelf Associates (CSA, 1998) of three platforms in the Gulf of Mexico that used SBMs (LAO and IO), concluded that elevated hydrocarbon concentrations associated with SBMs occurred in highly localized patches rather than being in widespread accumulations with smooth concentration gradients. This patchiness may be the result of a lack of a dominant current direction or the fact that stations were selected according to bathymetry. Grain sizes were also highly variable between and within platform sites. Samples were collected at 50, 100, 150, 250 and 2,000 m from three platforms within 6 and 18 months of drilling. Water depths at each of the three sites ranged between 30 and 100 m.

Detectable concentrations of hydrocarbons were not found outside 150 m of drilling activity. Stations sampled at 50 and 150 m revealed SBM-associated hydrocarbon concentrations (SBM-HC) at very low concentrations. For one of the platforms, no contamination was detected at the 10 stations from 50-150 meters. At the second platform, no contamination was detected from 50–150 m at 7 of 10 stations. Two stations reported contamination at 8.4 ng/mg dry weight and one station reported contamination as 6500 ng/mg dry weight. The third platform reported no detectable contamination at 6 of 9 stations from 50-150 meters. Two stations reported contamination at 10 ng/mg and 21 ng/mg dry weight. One station reported 23,000 ng/mg dry weight basis. However, two other samples taken from the same station reported non-detect and 16 ng/mg contamination indicating the randomness of the contamination at the locations sampled. In addition to grab samples, side scan sonar observations were conducted which revealed no measurable cuttings piles around the discharge locations.

Candler et al., (1995) investigated effects of discharging 45 tonnes of PAO SBM (a small amount compared to the North sea studies) from an exploration well in 39 m of water. They found that TPH levels dropped by between 60 – 98% at all sampling stations (out to 200 m) except the closest (25 m), just 8 months after drilling had ceased. Further reductions in TPH levels were not observed 16 months later. After 2 years, only 7% of the originally discharged SBM was found within a 200 m radius of the discharge. It is unclear whether TPH concentrations during this study decreased as a result of biodegradation or sediment redistribution. In any event, species abundance and richness were reduced at a distance of 50 m from the operation two years after drilling had stopped, but areas further afield had recovered. Candler et al., (1995) also reported that 1000 mg/kg of TPH from SBMs was required before benthic community structure was affected. These study results are similar to those of SBM discharges in the North Sea; benthic community effects were restricted to a small area downcurrent of the discharge.

Two studies were conducted in the deepwater Gulf of Mexico (565m) to determine the


impacts of discharging Petrofree LE (90% LAO, 10% ester) associated with 7 development wells (Fechhelm et al., 1999). Remotely Operated Vehicle (ROV) surveys indicated that cuttings were dispersed over the bottom in a patchy fashion. Chemical analyses indicated that most of the fluid was observed along transects in the direction of the surface and mid-level currents rather than in the direction of bottom currents. Highest SBM levels were measured at 75m from the discharge point. Benthic abundance was highest in sediment along the same transect that had high SBM concentrations. ROV video was used to count demersal megafauna (primarily fish). Neither benthic fauna or demersal fish abundance appeared to have been adversely affected by the SBM cuttings discharge.

The USEPA (1999b) modelled the risk to consumers of recreational finfish and commercial shrimp caught in the Gulf of Mexico from contamination by SBM. Guidelines for the effects of SBM are not available, so exposure levels were compared to existing guidelines for the consumption of noncarcinogenic and carcinogenic (arsenic only) compounds. The results indicate that at fluid retention levels of 11% or 6%, there will be no risk of toxic or long-term effects. However, a move to the 6% cuttings retention level would reduce pollutant tissue concentrations in shrimp by 43%.

Australia6.4.3.3

Results similar to those reported in other regions have been reported for the Fortescue Field, located in 70 m of water in the Bass Straight off southeast Australia (Terrens et al., 1998). Twenty-one wells were drilled at Fortescue with WBM between 1983 and 1985. Eighteen additional wells were drilled there between October 1994 and September 1996. Most of this drilling also was performed with WBM; however, the long-reach, high-angle sections of 7 wells required the use of SBMs. During the entire 1994 – 1996 program, approximately 20,000 m3 of WBM, 5,000 m3 of cuttings, and 2,000 m3 of ester SBM on cuttings were discharged to the Bass Strait. The fate of these discharges was monitored during five seabed surveys undertaken between August 1995 (pre SBM cuttings discharges) and August 1997 (11 months after completion of SBF cuttings discharges).

Sediments were sampled at 4 stations 100 to 2000 m along a transect southwest of the platform (the direction of the prevailing water currents) and 100 m south of the platform. Sediments in the vicinity of Fortescue are medium to coarse sands, indicating a high-energy environment. The highest ester concentration in sediments (12,000 mg/kg) was in sediment collected 100 m Southwest of the platform shortly after completion of drilling with SBM. Six months later, the concentration of ester in sediment from this station had declined to 200 mg/kg. Sediment from the station 100 m south of the platform contained 1810 mg/kg ester shortly after SBM discharge and 260 mg/kg 6 months later. Most other


stations did not contain measurable concentrations of ester (<0.2 mg/kg) at any time. Thus, esters from SBM cuttings were not persistent in sediments from this high-energy environment. Barium concentration increased in sediments (maximum concentration 795 mg/kg) up to 1 km Southwest of the platform during SBM cuttings discharges. Barium concentrations remained elevated in sediment 100 m from the platform for at least 1 year after completion of drilling.

Impacts of the drilling fluids and cuttings discharges on benthic faunal communities was limited to within 100 m of the platform with recovery evident within 4 months after completion of drilling. During the time of SBM cuttings discharges, numbers of nematodes and crustaceans decreased and numbers of polychaetes increased in sediments 100 m southwest of the platform. Total abundance of benthic fauna remained nearly constant and benthic faunal diversity declined. These effects are typical of an organic enrichment effect (Pearson and Rosenberg, 1978). Within 4 months after completion of drilling, benthic biological parameters had returned to pre-drilling conditions. Recovery was attributed to a combination of ester biodegradation and the active physical seabed dispersion processes in the eastern Bass Straight.

Sable Island Bank6.4.3.4

Sable Offshore Energy Inc (SOEI) EEM program is monitoring the effects of operations, most notably the discharge of WBM, WBM cuttings, and SBM (Novaplus an IO SBM) cuttings from drilling at the Venture, Thebaud, and North Triumph wells. Venture and Thebaud are in relatively shallow water (20-22 m) and North Triumph is in deeper water (80 m). Venture and Thebaud baseline surveys were conducted in June-July 1998. At the Venture field, one baseline and three drilling surveys (November 1998, June 1999, and November 1999) were conducted. At the Thebaud field, one baseline and two drilling surveys (June 1999 and November 1999) were conducted. For the North Triumph field two baseline and one drilling survey were conducted. In addition stations adjacent to the Gully were sampled at each of the sampling periods. The Gully is a canyon feature on the Scotian Shelf.

Parameters measured as part of this program are the following: water quality; suspended particulate matter (SPM) in the benthic boundary layer (BBL); sediment quality (chemistry and toxicity); benthic habitat, and megafaunal community; shellfish body burden and taint; marine mammals; and seabirds. At each field, samples have been taken along eight radials at distances from the platform of 250 m to 20 km. Mussel moorings were set at 500 m, 1 km, 2 km, 4 km, 10 km, 13 km, and 30 km from the Venture platform. Scallops were collected from natural beds at three test areas (north of Venture, south of Thebaud, and west of North Triumph) and a reference area.


The study findings were as follows (JWEL, 2000a):

Drill cuttings piles were considerably smaller than modelled; this may be due in part to •

lower volumes being discharged from Venture than originally modelled, however, Thebaud discharges were close to predicted, and the cuttings pile was approximately half the predicted radius. Drill cuttings piles were visible within 70 m of the discharge point at Venture and Thebaud. Elevated levels of TPH and barium were found at both 250 and 500 m from the •

drilling platforms and were intermittent. Dispersion or burial appeared to occur within a six-month period and is likely attributed to sediment transport. Biodegradation of the SBM may also be a contributing factor.Water samples collected on transect out from the drilling platform and along the axis •

of the prevailing current did not contain detectable levels of hydrocarbons during drilling phase surveys. BBL sampling showed no significant differences (from baseline) in suspended •

particulate matter (SPM) or barium concentrations in the BBL around the three drilling platforms that can be attributed to drilling activities. Bentonite was not present as a component of the SPM. No effect on the benthic communities outside the cuttings accumulations could be •

detected but high natural variability at the site makes effect detection very difficult. Amphipod toxicity results were variable between the different sites. No toxic effects •

on amphipod survival were found at either the Venture or Gully sites in any of the four rounds of the EEM. Two of four samples taken at 250 m from Thebaud showed a toxic effect on amphipod survival. These samples also showed elevated TPH and barium compared to baseline. The similar toxic effect was not exhibited in samples tested from the same location several months later and TPH and barium levels were no longer elevated. Sediments taken from the North Triumph site exhibited toxicity in the baseline survey (for the 20km sample) and in 3 of 4 of the samples taken at 250m immediately following discharges of SBM cuttings; two of these samples also had elevated barium and TPH levels. Samples taken at all sites during all rounds of Microtox™ indicate no toxic effect.•

Mussels moored at the Venture site revealed no obvious flavour or odours that were •

different from the controls at any other mooring site. Aliphatic hydrocarbons were detected in tissues; only samples at collect at 500m appeared to have hydrocarbons concentrated in the range of the synthetic base oil. Aliphatic hydrocarbons may result naturally from filtering of phytoplankton. To put the levels detected at 500m into perspective, 3.04 mg/L were detected in the mussels 500m from the Venture platform. Whereas, levels measured in mussels 50m from Cohasset-Panuke were 44.5 mg/l (Zhou et al., 1996).


No taint was cited in sensory evaluations of scallops collected from natural beds in the •

project area. Low levels of aliphatic hydrocarbons were detected in scallops collected in both baseline and drilling phase surveys. Tissues of scallops collected near Thebaud did show evidence of hydrocarbons from petroleum sources. However, the source of hydrocarbons are unknown. The gas chromatogram signature of these hydrocarbons has not been matched to the drilling fluid, diesel fuel, and gas condensate from Thebaud, or gas condensate from Cohasset-Panuke. The source of hydrocarbons may be from natural seepage (JWEL, 2000a).

The SOEI EEM results up to December 1999, confirm that the combination of low discharge volumes, high energy seafloor conditions, and environmentally benign fluid characteristics resulted in low impacts and rapid recovery of the seafloor.

Hibernia EEM 6.4.3.5

The Hibernia EEM program is studying the effects of operations at the Hibernia platform. The platform was installed on the seafloor and drilling commenced June 1997. Hibernia is using a single fixed platform to complete drilling of an estimated 83 development wells over the life of the project. Prior to early 1998, Hibernia development wells were drilled with WBM. After that time, WBM has been used to drill the upper portions of all wells and synthetic based mud (SBM IPAR-3 also known as Puredrill or IA-35) the lower portions of the wells. Associated WBM and WBM and SBM cuttings have been discharged overboard.

A baseline study was conducted in the area in 1994 (sediment in August-September, and biology in December). Two EEM programs have been conducted since the start of operations, one in 1998 (sediment in August-September and biological in December) and one in 1999 (sediment in August and September and biological in June). Sediment and biological surveys are conducted on an annual basis for the first three years of production (1998-2000) and every second year thereafter. Parameters measured as part of this program are the following: sediment physical and chemical properties, sediment toxicity (MicrotoxTM, amphipod survival, and juvenile polychaete growth and survival), tissue body burden, and taint of American Plaice. The biological (fish) survey was conducted within a fishing zone (500 m to 2000 m) around the Hibernia site and at a reference location approximately 50 km north of the Hibernia platform. Sediment samples were sampled in along 8 radials starting at 250 m from the platform and radiating out 8 km from that platform with two reference sites 16 km out from the platform. In addition there is a transect of stations that run between the Hibernia platform and the Terra Nova platform.

The EEM results collected to date indicate the following (JWEL, 2000b):


there is no indication of taint in American Plaice collected near the Hibernia platform; •

there were differences in body burden data between 1998 and 1999, however, these •

data need to be considered with caution due to possible seasonal effects due to the change in sampling period; there were statistically significant increases in sediment chemistry (hydrocarbons and •

barium) levels of the 1999 samples over those of 1998 and baseline studies. Measured levels are similar to those and often less than those found at similar distances from the drilling discharge location of other offshore producing fields. In addition, the levels measured are not known to cause ecological or biological effects; PAH levels in sediments and fish tissues are less than the level of quantification (<0.05 •

mg/kg); none of the samples collected indicated a toxic response in the Amphipod or •

polychaete bioassay; although some of the 1999 samples indicated a toxic response in MicrotoxTM testing, •

this response does not appear to be correlated to drilling discharges (there was no correlation with sediment chemistry barium and hydrocarbons). In addition, grain size analysis indicated that the samples for which a response was found were dissimilar to other samples for which no response was found; anddrilling wastes appear to have been transported further from the well site than •

originally predicted from the fate and effects model. However, this modeling did not account for the severe storms that move through the area and are believed to contribute to sediment transport.

Although the results of the Hibernia EEM are not atypical of what might be expected where large volumes of SBMs have been discharged, there are some differences from the results observed at Hibernia versus those at SOEI. These differences likely result from a number of factors. Firstly, hydrodynamic conditions are Sable are more energetic than they are at Hibernia, which means that accumulations of discharged materials are less likely to persist at SOEI than at Hibernia. Also, drilling volumes and conditions were different between the two areas. At Hibernia, there has been continuous discharge of drill cuttings from a single location, whereas at SOEI, lower total volumes of cuttings were discharged, and cuttings were discharged from different locations.

Conclusion6.5

The environmental fate and effects of discharged cuttings is determined largely by oceanographic factors such as temperature, current direction and speed, and sediment composition. Regardless of the fluid discharged, water depths and oceanographic conditions will influence the initial accumulation and distribution of the cuttings, as well as


their persistence (redistribution and biodegradation). Therefore, these factors need to be considered in developing appropriate regulatory and management strategies.

Based on the available evidence large persistent cuttings piles observed in the North Sea resulting from OBM cuttings discharges have not been observed offshore eastern Canada (for LTMO (Cohasset), or SBM (SOEI) cuttings discharges on the Sable Island Bank, Hibernia, Western Australia (for LTMO, and SBM cuttings discharges), or the Gulf of Mexico. Short term impacts and rapid recovery has been documented where SBM cuttings have been discharged offshore Nova Scotia (JWEL, 2000a) and many other locations (Gulf of Mexico, Western Australia, North Sea).

The potential for effects depends largely on the physical environment in which the cuttings are discharged. In high-energy environments like the Sable Island Bank, effects may not be detectable. In lower energy environments or those in deeper water with slower bottom currents, drilling fluids may be more persistent as they will be less readily dispersed by physical mechanisms. However, in deeper waters discharged cuttings may be deposited in thinner accumulations and hence may be more readily biodegraded than thicker accumulations that could be found at shallower water depths.

The impacts of SBM cuttings discharge are expected to be less severe than those from OBM cuttings discharges due to the lower toxicity and more rapid biodegradation of SBM base fluids as compared to OBM base fluids. Effects on benthic communities are not generally caused by chemical toxicity, but by smothering and/or organic enrichment which can lead to anoxic conditions. Studies of SBM discharges into the North Sea, Australia and Gulf of Mexico have found that detectable effects on the benthic community from SBMs are usually localized (within 250 m) and show signs of recovery within one year (Jensen et al., 1999; Terrens et al., 1998; Neff et al., 2000).

REGULATORY REVIEW7

Discharges, particularly of drilling fluids and cuttings from offshore drilling operations, are heavily regulated and closely monitored in most geographic areas including the North Sea, offshore Australia, the United States Outer Continental Shelf, and offshore Canada. The regulatory models in each jurisdiction are unique and reflect the offshore operating history and experience, the size and age of the industry, the characteristics and sensitivities of their marine environments, environmental protection strategies and testing techniques, and political sensitivities. These differences have lead to a range of regulatory responses that reflect the unique situation in each country. Consequently, it is important to understand the history, framework, and reasoning that led to a particular regulatory decision.


The section begins with the historical perspective for the current regulatory regimes around the world. It provides a review of the development of various regulations associated with offshore drilling wastes, including a background of the current regulatory environment in various international jurisdictions (the North Sea/Northeast Atlantic with detail on Norway and the United Kingdom), United States, and Western Australia focusing on the discharge of SBMs associated with cuttings. In addition, the evolution and technical basis for these regulations (where applicable) are discussed. This information is used as a framework to discuss the development of regulations for the east coast Canada offshore oil and gas industry specifically those developed for Newfoundland and Nova Scotia.

Historical Perspective7.1

Studies in the North Sea and elsewhere in the 1980s, raised concerns about the environmental effects of the original high aromatic content diesels and drove the introduction of LTMOs and ultimately the development of SBMs in the 1990s. The SBMs were developed to have lower environmental impact and greater worker safety through lower toxicity, elimination of PAHs, faster biodegradability, lower bioaccumulation potential, and, in some drilling situations, less drilling waste volume.

Despite the fact that the science seems to indicate that the environmental effects associated with SBM cuttings are more restricted in area, less toxic, and last for a shorter period of time, regulators have been cautious to relax the stringent management and discharge regulations imposed for OBM cuttings. Also, the evolution of more restrictive regulations is requiring the Industry to adopt more rigorous drilling fluid management systems and undertake more extensive research, development, and monitoring programs to better assess the environmental effects associated with the discharge of SBM coated cuttings before discharge approval is given. The pressure that has driven the regulations and resulted in the new technologies has also resulted in the development of a new collaborative relationship between regulators and the Industry. The regulators have recognized that the approach to finding an acceptable solution to environmental issues, such as disposal of SBM cuttings, requires inputs from all stakeholders to ensure that the operational and financial effects of a regulation are fully understood and evaluated before final decisions are made. Formal and informal relationships have been established between Industry and regulatory bodies in the United States, Australia, and the North Sea Countries (UK, Norway, Holland, Denmark) to address, among other issues, the management of synthetic drilling fluids and the resulting cuttings.

In Norway, the oil industry association has been an active contributor to an innovative and


strategic consultative forum (MILJØSOK), which is the alliance between the Norwegian Government and industry to create an open dialogue between the stakeholders on measures to better meet environmental challenges. There is a similar relationship in the UK with the Chemical Working Group, which comprises Government and Oil Industry representatives. In Australia, the national environment agency has developed strong relations with the national oil and gas industry association to develop multiple use solutions that address issues associated with competing resource interests. In the United States, the recent work by the Environmental Protection Agency (USEPA, 1999a) to develop new effluent limitations guidelines and permit limitations for synthetic based drilling fluids continues to involve an extensive co-operative work program with the Industry.

In developing regulations, regulators have borrowed very freely from the experience and results in other jurisdictions. At this time, there have been essentially two different models for addressing drill cuttings management issues. The first model is from the North Sea where drill cuttings management initiatives have been driven by the regional OSPAR Convention. The North Sea is unique because it is a semi-enclosed water body surrounded by heavily populated industrialized countries, each with a sector of the North Sea to manage. The OSPAR convention is focused on marine discharges and is not charged with responsibility for onshore waste disposal. Consequently, the collective environmental and political pressures to regulate marine discharges such as drill cuttings have been much greater than in areas such as Australia, Canada, and the United States which are governed by their own national legislation, and use a more holistic approach to management of drilling waste. However, as will be discussed in the following sections, the North Sea regulatory regime appears to be evolving to being somewhat closer to the second model than it has in the past.

The second model type broadly includes approaches taken in Australia and the United States, where systems for the management and discharge of SBM cuttings are evolving. In these areas, industry and the regulatory agencies have developed a holistic approach to the SBM cuttings management issue to ensure that all the technical, financial and environmental consequences are thoroughly evaluated before a final decision about a disposal strategy is made. This approach relies heavily on the concepts of best available technology (BAT) and best environmental management practices to achieve the best possible environmental option (BPEO). It places a strong burden on the operator to carefully manage the drilling program and be accountable for the result.

This approach provides flexibility in considering new SBMs, environmental monitoring technologies, or new environmental effects information, to modify cuttings management requirements to assure maximum environmental protection at the most effective cost. It is


important to emphasize that this model does not necessarily mean a departure from appropriate environmental protection goals. It simply defines a regulatory objective and allows the operator to make operation specific decisions as to how the objective is met. In addition, such an approach has the added benefit of forming associations between the regulatory agencies and the Industry where there is a mutual recognition and understanding of the environmental issues and goals, and the management methodologies most appropriate for the desired outcome. A common understanding about the limitations of the available cuttings management and measurement technologies can influence the direction of regulations and ensure that unreasonably restrictive regulations do not have unintended side effects. In this model, all the stakeholders have a vested interest in, and ownership of the result.

The development of guidelines for drilling fluid and drill cuttings is an ongoing process in the US and other areas at the time of publication. At the present time, the most recent OSPAR guidelines subject SBM cuttings discharge to the same 1% retention limit as OBMs, however, their discharge may be allowed under “exceptional circumstances”. Within OSPAR members, Norway at this time is continuing to use SBMs on a conservative basis with a zero discharge philosophy on minimizing overall environmental impacts. The UK has suspended SBM discharges as of year end 2000. The US has also segregated SBMs from OBMs by definition and is moving toward discharge of SBMs based on a pollution prevention strategy and indications of low potential impacts as measured in the laboratory and the field. Likewise, Australia is continuing to discharge SBMs on a strategy of evaluating the technical needs of each project and environmental sensitivities of the area on a case by case basis. In these areas, other options such as WBM discharges, and cuttings injection are also accounted for in the regulatory framework.

As previously discussed in other chapters, there are three categories of drilling fluids and cuttings wastes: WBM, OBM, and SBM. Country-specific discharge requirements for these drilling wastes are provided in Appendix I.

Northeast Atlantic/North Sea7.2

This section will discuss the development of the regulatory framework within which oil and gas operations in the Northeast Atlantic, of which the most significant activity is in the North Sea, must operate. This then will provide more specific details on how Norway and the UK have chosen to interpret and enact these regulations.

OSPAR Development of OBM, and SBM Regulatory Controls7.2.1

Exploration for oil and gas located offshore in the North Sea began during the early


1970’s. Offshore drilling discharges within the various territorial sectors (UK, Norway, Holland, Denmark etc.) were initially regulated using conditions set for exploration licences and by voluntary agreement for approval for use and discharge of drilling chemicals with the oil exploration companies. Each territorial sector developed specific regulatory requirements for environmental approval. However, the 1972 the North Sea Countries became contracting parties to the Oslo Convention for the prevention of Marine Pollution by dumping from ships and aircraft; and in 1974 to the Paris Convention for the Prevention of Pollution from Land-based Sources. The newly formed Oslo and Paris Commissions (OSCOM and PARCOM) were then used as an international framework for development of a harmonised approach to environmental regulations and control of offshore drilling discharges. The primary objective of these commissions is to improve the aquatic environment of the Convention area in general and the North Sea in particular.

In 1992 these Conventions were combined and re-ratified by all contracting parties as the Convention for the Protection of the Marine Environment of the north–east Atlantic, known as the OSPAR Convention. The adoption of decisions, agreements and recommendations from these Commissions by the North Sea contracting parties has directly influenced the development of new drilling chemicals and required the introduction of new work practices to enable compliance with regulations. The OSPAR convention was finally entered into force in 1998.

Knowledge of the history of oil and gas development in the UK and Norwegian sectors of the North Sea is important to understanding how the various OSPAR Decisions have been interpreted within those respective areas. In the UK, the technical justification for the use of OBM and later synthetics was much easier than in Norway. Consequently much greater volumes of OBMs and SBMs were discharged in the UK sector than in the Norwegian sector of the North Sea. From the beginning, in Norway synthetic discharges were strictly controlled and generally limited to sites where OBM had previously been discharged. Also, Norway did not allow the discharge of OBM/Synthetics on exploration wells, which further limited and restricted the discharge of these fluids to developments/ existing sites.

The geographical locations of many of the early UK fields (e.g., the East Shetland Basin etc.) meant that hauling of cuttings was not regarded as practical, and there were no suitable reception facilities onshore to handle such wastes until the late 1990’s. Another option was the injection of drill cuttings, however, concerns about illegal dumping of waste has prevented the inter-field transport of cuttings, which would have made this option more practical (under the London Dumping Convention).

Regulation of Synthetic Drilling Fluids in the North Sea 1990 - 19997.2.1.1


The principal OSPAR concern has been the formation and persistence of diesel and mineral oil based cuttings piles in the Central and Northern North Sea areas (piles are not an issue in the Southern North Sea as it is much more hydrodynamically active). The initial banning of the use/discharge of diesel muds and their replacement with LTMOs was on the basis of expected environmental improvement. The regulatory restrictions on the discharge of mineral oil based drilling fluids from 1986 to 1990, and the agreed phase out by PARCOM in 1992 of the discharge of mineral oil drill cuttings to 1% OOC (PARCOM 92/2, OSPAR, 1992) prompted considerable research to find alternatives to mineral oil, which gave similar technical performance, yet complied with the developing environmental requirements. Further evaluation of the use and discharge of fluids lead in turn to considerable regulatory debate regarding the setting of acceptable environmental impact criteria and the final assessment of the impact from specific fluid types. The synthetic fluid discharge was not controlled under the existing legislation such as PARCOM 92/2. Laboratory test results indicated that SBMs were less toxic and more biodegradable than the mineral oils they replaced. However, the costs of synthesis and production meant that they were considerably more expensive than mineral oils and it was some years before their use was generally accepted by the oil industry.

As will be discussed in the following sections, the continued evidence for the formation and persistence of cuttings piles lead to further discussion at OSPAR and pressure on the UK to restrict “oily” discharges. In the UK, the regulatory authorities have progressively reviewed the available seabed survey data and instigated a laboratory based solid phase biodegradation test to rank and compare synthetic fluids against mineral oil. This has lead to the political decision within the UK to phase out the discharge of all non-aqueous fluids (following discussion and agreement with the UK Industry). At the OSPAR sea based work group (SEBA) meetings from 1996 onwards (discussed below), the discharge of synthetics has been discussed and all available data reviewed.

SEBA 7.2.1.2

Under OSPAR there are six committees which address various issues related to protection of the marine environment. The working group on Sea-Based Activities (SEBA)'s purpose is to draw up draft programmes and measures for the prevention and elimination of pollution of the maritime area from offshore installations, and dumping and dredging activities that are associated with dumping or have similar effects to the dumping of dredged material. The committee's name has recently been changed to OIG (Offshore Industry Group). What follows are the activities of SEBA as they relate to regulation of drilling discharges.

SEBA 1997


At SEBA 1997, the UK discussed their solid phase test procedure (SOAEFD) and results (described earlier in sections 4.7.2.3 and 5.2.4). The test results indicated that the acetal, IO, LAO, n-paraffin and PAO systems degraded to some extent at low concentrations and at higher concentrations showed little signs of degradation. In this regard, the UK asserted that SBMs were similar to mineral oils. Although the results from sea-bed-surveys were not available at the time, the degradation data suggested a reduction of discharges of mineral-oil-like SBM’s was advised. In view of this, the UK industry as a precautionary measure embarked on a stepwise reduction and continued to monitor the impacts of all its SBM discharges by seabed survey. SEBA 1997 noted these results on the degradation of synthetic muds and the action being taken by the UK industry. The UK suggested that a workshop be arranged in which PARCOM Decision 92/2 would be reviewed.

UK Workshop on Drilling Fluids (1997)

During November 1997, the UK Government hosted the workshop on drilling fluids which included participants from Government and Industry, including NGO's such as the E & P Forum, Greenpeace, and EOSCA. The workshop objectives were to advise the UK in their preparation of a report to SEBA 1998 concerning the development of criteria for the environmental acceptability of organic based drill cuttings discharges, which could, if appropriate lead to a revision of PARCOM Decision 92/2 on the use of oil based muds.

The workshop conclusions were that there was no need to revise PARCOM Decision 92/2 on the use of oil based muds, which would have in effect identified SBMs as OBMs. Instead, the recommendation was to develop measures and regulations with respect to the control of SBMs and other organic-based drilling fluids in an additional OSPAR measure.

SEBA 1998

Following the UK Drilling workshop the UK presented the recommendations at SEBA 1998. The outcome from the meeting was that UK was tasked to prepare a draft OSPAR Decision concerning the control of all organic-phase based drilling fluids for examination at SEBA 1999. This draft decision was to take into account:

The outcome of the 1997 workshop on drilling fluids and the comments made at i)SEBA 1998.The comments made at SEBA 1998 with respect to the injection of contaminated ii)cuttings, and any guidance from the Head of Delegation on this issue.Information which Contracting Parties deemed important and of relevance to be iii)taken into account by the UK in the preparation of this new measure (e.g.,


information related to the effectiveness of PARCOM Decision 92/2, such as the use of oil-based drilling fluids in the upper parts of wells- which would need to be defined.).

SEBA 1999

At SEBA 1999 the UK presented their draft Decision on the Use of Organic Phase Fluids (OPF), taking into account the recommendations of the UK Drilling workshop in 1997 and the discussions at SEBA 1998. The definition for Organic Phase Fluid included synthetics with all mineral oil type fluids, and applied the 1% OOC limit that had applied to mineral oils (PARCOM Decision 92/2) for the discharge of OPF cuttings. However, no agreement was reached at the SEBA meeting and other members of OSPAR did not agree with the universal application of a 1% discharge limit to all OPF discharges.

SEBA 2000

The UK presented a new amended Draft Decision of the Use of Organic Phase Fluids (OPF, OSPAR 2000). This Draft Decision was discussed and agreement reached for its introduction. The final decision is provided in Appendix J. The principle difference from the SEBA 1999 Draft is that in addition to the definition for Organic Phase Fluids (OPFs; which includes both SBMs and OBMs) there are individual definitions for oil based and synthetic fluids. The decision states that discharges into the sea of OBM cuttings at concentrations greater than 1% is prohibited (clause 3.1.4). In addition, although 1% fluid by weight is the target limit for discharge of all OPF cuttings (Appendix 1-4c), clause 3.1.6 states that SBM cuttings discharged into the sea may be authorized under exceptional circumstances and that such authorizations will be based on application of best available techniques / best environmental practice (BAT/BEP). The interpretation of “exceptional circumstances” is up to the individual countries. The UK government has made it clear that they can not see any exceptional circumstances arising that would lead to discharge of SBM cuttings. Cuttings could be discharged for reasons regarding rig safety but this would only be temporary, lasting no more than a matter of hours until the situation stabilized (Bob Williamson, pers. comm). On the other hand, Norway, which presently allows discharge of SBM at sites where there have been previous discharges, may continue to evaluate SBM cuttings discharges on a case-by-case basis rather than strictly applying the 1% limit (Ingvild Skare, pers. comm). All contracting parties are required to apply the following in making decisions regarding the management of OPF cuttings: the principles of the Harmonized Mandatory Control System (HMCS), BAT and BEP, the waste management hierarchy set out in Appendix 1 (to the decision).

The identification of basic environmental acceptance criteria such as toxicity,


biodegradability, and bioaccumulation potential, with consideration of hydrodynamic conditions of the receiving environment in evaluating the discharge of cuttings parallels the approach being used by the US and other areas that are continuing to discharge SBM cuttings. Likewise, this decision also includes provision for consideration of non-water quality impacts such as the conservation of resources including energy. The interpretation and application of the terms of this OSPAR draft decision are up to the individual countries.

Future Direction of Discharge Management 7.2.1.3

The SEBA 2000 meeting resolved some issues that have been developing for several years. There is now general agreement within OSPAR for a harmonised environmental data set for the evaluation of offshore chemicals and a mandatory harmonised approach to regulation of those chemicals using chemical hazard and risk management (CHARM). The agreement for implementation of the harmonised mandatory control scheme (HMCS) for regulation of offshore chemicals is a major milestone for OSPAR. It is likely to change the entire approval structure in the member countries. This will strengthen the process of integration of OSPAR within the European Community, as following the introduction of the HMCS, it could be said that the regulation of drilling discharges has effectively been devolved from OSPAR Decisions to the European Community in the same way that an European Union directive becomes devolved into national legislation when implemented by the European Community (Ian Still, pers. comm).

It is possible that as there is now an agreed statutory harmonised mechanism for control of these discharges, industry can develop new fluids unhindered with the burden of second guessing what the regulators may think. Also, the continued integration of OSPAR Recommendations and Decisions being implemented through European Community legislation could mean a more comprehensive approach to the assessment of environmental impact (I. Still, pers. comm). The remit of OSPAR is solely to control the aquatic environment, whereas the European Community legislative approach seeks to minimize environmental impact to all three of the environmental media, water, air, land. This is becoming a more contentious issue, as greater amounts of drilling wastes in the North Sea countries are being taken on-shore or injected into sub sea formations as a result of increasing restrictions on direct aquatic discharge.

Present OSPAR Requirements and Implementation 7.2.2

The process of the OSPAR commission developing environmental regulations and, for example, the UK government implementing these regulations is ongoing, and is strongly influenced by developments in the European Union. Hence OSPAR decision documents,


which are legally binding, have most recently adopted concepts like BAT, BEP, and the EU waste hierarchy, and have begun to integrate more fully with the European Community.

At the present time, all drilling fluids or chemicals to be used anywhere within the North Sea or North East Atlantic area require environmental approval prior to use/discharge. Following discussions at an OSPAR meeting in 1996, PARCOM Decision 96/3 was made (OSPAR, 1996), where it was decided to develop and work towards the implementation of a HMCS for the Use and Reduction of the Discharge of Offshore Chemicals before the year 2000. This system uses data supplied in the Harmonized Offshore Chemical Notification Format (EOSCA and E&P Forum, 1995) and also incorporates a pre-screening and CHARM. The scheme was to be implemented on a trial basis for two years, from 1997, with a decision on the final format of the scheme to be made by OSPAR in 1999. However, no agreement was reached at SEBA 1999, and the discussion was referred to SEBA 2000, when the final format of the scheme was finally agreed. This system requires environmental assessment using a specific data set that has been agreed and harmonised by OSPAR so that the information can be used for application anywhere within the convention area.

Each contracting party may set their own requirements as long as they are at least as stringent as those of OSPAR. The key points of the OSPAR system are as follows:

pre-approval of individual chemical products rather than formulated drilling fluids or •

effluents is required;pre-approval is based on review of ecotoxicological data that is submitted in the •

Harmonized Offshore Chemical Notification Format (EOSCA and E&P Forum, 1995). The HOCNF requires data on aquatic and sediment toxicity, biodegradability, bioaccumulation potential, adsorbability, and mammalian toxicity;where OBM or SBM formulations are to be used, information on toxicity of the •

formulation and biodegradation potential of any organic components of the mud are required, this includes the base fluid;ranges of generic chemicals including some important drilling fluid components are •

excluded from the HOCNF data submission requirement. These excluded chemicals are listed on the OSPAR PLONOR list (List of substances/preparations used and discharged offshore which are considered to Pose Little Or No Risk to the environment); anda pre-screening of all WBM drilling and production chemicals to demonstrate the •

selection for use/discharge of the least hazardous is required.

Introduction of a Harmonized Mandatory Control Scheme (HMCS) 7.2.2.1


As discussed above, final agreement on the format of the HMCS was reached at SEBA 2000. The HMCS uses the existing HOCNF format and environmental data-set, and provides a control mechanism to:

Pre-screen offshore chemicals.1.Rank according to environmental hazard.2.Eliminate or substitute, as appropriate.3.

The option to include a risk-based assessment is also given.

Chemical Hazard Assessment and Risk Management (CHARM)7.2.2.2

The central part of this new scheme is to be the hazard ranking, which is intended to be performed by a Chemical Hazard Assessment and Risk Management model (CHARM). This development was instigated following a memorandum of understanding between the Dutch and Norwegian regulatory authorities in 1993. It quickly grew to include the UK regulators, the E & P Forum and the oil sector chemical suppliers trade association European Oilfield Specialty Chemicals Association (EOSCA). The original concept of the model was that it would include any available environmental data and that it would be able to give rankings for production chemicals, water based, synthetic based drilling (and cementing) chemicals, and fluids.

The practicality of developing a model to do all this has resulted in a compromise with the model being restricted to using only the HOCNF data-set, and to assess production chemicals, and water based drilling and cementing chemicals. The synthetic drilling fluids part of the model has proved very problematical for inclusion in this latest review. It may be developed further and included if necessary.

Norway7.2.3

Norway has a strong regulatory framework in place, which blends environmental regulations and permits, as well as open dialogue with industry. Conditions for granting permits for use and discharge of chemicals from offshore installations are regulated by the Norwegian Pollution Control Authority (SFT; SFT, 1998). The testing requirements follow OSPAR decisions and apply to SBM and WBMs. The use and discharge of OBM in the Norwegian sector in the North Sea began in the 1970’s. As the regulatory process for synthetic fluids has evolved, Norway has taken a conservative approach to their use and discharge. At the current time, synthetic fluids continue to be discharged supported by the information supplied from the simulated seabed studies and the field studies at SBM


discharge locations. In the late 1990’s the UK regulators pushed forward with regulatory approaches based on the SOAEFD solid phase biodegradation test, while the Norwegian regulators relied on the NIVA tests and results of seabed surveys to guide their approach to synthetic fluid discharges (SEBA, 1997; Norway, 1997).

At the current time for all chemicals and drillings fluids used offshore Norway, the following are required:

general OSPAR HOCNF requirements. A HOCNF is required for each component or •

additive except those on the PLONOR list;OSPAR toxicity data must be presented for individual chemicals. SFT no longer •

requires testing of used drilling muds;complete biodegradability of each component is required. A range of biodegradability •

tests is accepted. Simulated seabed studies of the entire synthetic drilling formulation must also be carried out; however, mesocosm studies have usually been carried out by NIVA in Oslo;complete documentation of the bioaccumulation potential of each component must be •

submitted for products comprising several substances;alternative products need to be ranked using the CHARM model hazard mode; and•

since 1997, operators must advise of their plans for phase out for use/discharge of •

their most hazardous chemicals based on biodgradability and log Pow.

In addition to the above, there are general conditions for the discharge of oil, drilling fluids and chemicals from offshore installations. SFT sets specific requirements for each installation and field. These general conditions are:

solid particles from production containing more than 1% (weight) oil shall not be •discharged;oil contaminated separation fluid or oil used during well testing cannot be discharged;•environmental monitoring shall be implemented by the operator and in accordance •with applicable requirements stipulated by SFT (SFT, 1999);the drilling fluids and chemicals chosen by the operator will be considered on the basis •of the environmental surveys; anddischarges to the marine environment and deviations from the conditions are reported •annually to SFT in accordance with their reporting guidelines, and must include plans to reduce these deviations.

With respect to exploratory drilling, discharges are regulated through the Norwegian Petroleum Directorate (NPD) approval of the activity. The conditions for approval are set by SFT and are, in general, the same as those outlined above.


Presently, the SFT allows discharge of SBM at sites where SBM has previously been discharged with cuttings. SBM use is not allowed for exploration. In their discharge permit, operators must evaluate the pros and cons of discharging SBM cuttings versus use of other OPF systems and the consequent environmental effects both on and offshore. Recently, on their “zero discharge philosophy” towards SBMs, the Norwegians indicate that this implies a continual process toward obtaining the lowest possible environmental impact and not necessarily a ban on the discharge of SBMs into the marine environment.

Simulated seabed studies have previously been required for the introduction and use of all new synthetic drilling fluids in Norway (Vik et al., 1996). These studies which have been performed by NIVA measure biodegradation, faunal effects, and bioaccumulations of NAFs are based on introduction of used drill cuttings and simulated drill cuttings to undisturbed seabed sediments containing naturally occurring benthic flora and fauna which were taken intact from the sea-floor.

Simulated seabed studies were conducted in which sediments were spiked with low aromatic mineral oil (MO), IO, LAO, ester derived from saturated fatty acids (SFAE) and an ester derived from fish oil containing saturated and unsaturated fatty acids (FOE) Schanning et al., 1996. The results indicated that exposure to the SFAE resulted in a substantial decrease in the number of species and individuals and low diversity indices. Mineral oil was less harmful to the biota than the SFAE, the FOE and IO were essentially without biological effects, and the effects of LAO were minor. In terms of biodegradability, the fluids ranked in order of decreasing biodegradability were as follows: FOE>SFAE>LAO>IO>MO. The differences between environmental performance of the drilling fluids were not seen to be great enough to justify prohibition of one product over another, nor did data from offshore monitoring surveys support the restriction of all SBM discharges or those of one fluid versus another.

United Kingdom7.2.4

The regulation and control of offshore drilling discharges in the UK Sector of the North Sea began with approval for offshore drilling in the early 1970’s. From the inception of the Oslo and Paris conventions (later re-ratified as the OSPAR Convention) the UK Government has reviewed the effects of these offshore discharges and agreed on a harmonised approach to their further control and regulation with the other Contracting Parties of OSPAR. This section will review the regulation of OBMs and SBMs and the UK approach to implementation of the various OSPAR Decisions, culminating with the agreement to implement a Harmonised Mandatory Control Scheme (HMCS) at SEBA 2000.


With introduction of SBMs, the UK government wanted assurance that large persistent piles that had resulted from discharges of OBMs wouldn't occur, and that the SBMs would degrade at such a rate, even under anaerobic conditions, that after a few years and certainly well before abandonment, there would be no persisting environmental concern. Mud systems which had acceptable degradability performance characteristics and which received provisional Offshore Chemical Notification System (OCNS) Group E categorisation were approved for use at a limited number of sites, pending assessment of their in situ degradability. This resulted in systems based on esters, olefins, linear alkyl benzene (LAB), acetyl and n-paraffins being approved. However, all these classifications were provisional, with final approval being based on environmental impact assessment using seabed survey data following discharges of drill cuttings from these systems. Once approved there would be no need for continuing seabed surveys.

Although SBMs have been used/discharged within the UK for some years, the interpretation of the available seabed survey data obtained has been problematic. In most cases, data quality has been insufficient to draw reliable conclusions. Consequently, the UK regulatory authorities decided to carry out laboratory based degradation studies investigating the rates of removal of base fluids from marine sediments relative to mineral oil, the primary concern being the persistence of “cuttings piles” on the sea floor. The result of this solid phase testing was that at the highest concentration tested, most indicative of likely behaviour within cuttings piles, only ester based fluids were seen to degrade sufficiently, relative to mineral oil. At the time, esters were allowed to continue with their existing OCNS Group E approval, and tonnage trigger maximum discharge. The olefins and n-paraffins were not seen to degrade as quickly, their discharge was planned to be phased out by the end of 2000. At this time discharge of all SBMs will be phased out by the end of 2000. The use of these systems will still be permissible beyond the final transition date. However, it is likely that the discharged cuttings will be subject to either a 1.0% base fluid on cuttings limit or alternative controls.

Offshore Chemical Notification Scheme (OCNS)7.2.4.1

In February 1979 the UK introduced a voluntary control scheme, the Offshore Chemical Notification Scheme (OCNS) for the classification and control of water based drilling chemicals discharged offshore in the UK sector of the North Sea. The aim of the scheme was to prevent damage to the marine environment for non-oil discharges from offshore installations. It was based on the requirements of the Paris Convention Annex 1. Chemicals were classified from 0-4 based on the amounts (tonnage) that could be safely discharged without prior notification with Government:


The objectives of the OCNS were the following:

to provide operators and their sub contractors with guidance on the types of chemicals •

which Government would prefer for environmental reasons not to be used for applications which would involve their discharge to the sea;to inform Government on the usage of these chemicals and hence identify potential •

candidates for substitution;to provide operators with information on specific chemicals to enable them to take •

environmental factors more into account when selecting chemicals for specific applications; andto initiate consultation in the case of proposed large scale use of chemicals.•

A pro-forma was included requiring information on the scale of use and discharge of the chemical physical properties, chemical composition and marine toxicity of the product formulation as supplied to the user. Species for testing were not stipulated, but bullhead, plaice, and butterfish were commonly used, as was the brown shrimp for invertebrate testing.

Following agreement on a harmonized environmental testing data-set in 1994, the UK revised the OCNS to include the new test species and made some additional changes to the scheme requiring the re-application of all existing products within 5 years. This also included revising the tonnage triggers and changing the classification from Categories 0 - 4 to Groups A - E. The new groups are formed based on a more comprehensive set of tests incorporating a range of taxonomic groups using OSPARCOM approved protocols and test groups. The classification is a two-stage process whereby the initial grouping is determined by toxicity and the final grouping is determined by biodegradation and bioaccumulation potentials. The OSPAR harmonized environmental data set requirements included information for: Eco-toxicity: Algae, Herbivore, Sedimentary re-worker, Fish; Biodegradation aerobic/anaerobic; Bioaccumulation potential; and Bioconcentration Factor.

By the end of 1999 all OCNS listed chemicals had to be tested according to the OSPAR harmonized data-set. This data-set requirement is for all chemicals intended to be used and/or discharged offshore, with the exception of those listed in PARCOM List A (commonly known as the Green List) which comprises those chemicals that are regarded as posing little or no risk to the environment. The list includes natural constituents of seawater.

The OCNS classification is published in a department of trade and industry (DTI) list of notified chemicals with entries listed under each specific chemical supplier. The new


revised OCNS meets the current OSPAR requirements for a harmonized approach to control of offshore drilling chemicals and applications to the scheme are now made using the “Harmonised Offshore Chemical Notification Format” (CEFAS, 1999).

As set out in OSPAR, 2000, the UK, along with the other OSPAR countries, must apply the principles of the HMCS in reaching a decision regarding use and discharge of organic phase fluids and associated cuttings.

United States7.3

Framework7.3.1

In the United States, the US Congress adopted the Clean Water Act (CWA) to "restore, and maintain the chemical, physical, and biological integrity of the Nation's waters". In order to implement the Act the USEPA was required to issue effluent limitation guidelines and standards for industrial dischargers. These guidelines and new source performance standards are then implemented in National Pollutant Discharge Elimination Systems (NPDES) permits. The Guidelines and New Source Performance Standards are based on the degree of control that can be achieved by using various levels of pollution control technology.

The technology standards that the USEPA uses to regulate pollutants are Best Practicable Control Currently Available (BPT), Best Conventional Pollutant Control Technology (BCT), Best Available Technology Economically Achievable (BAT), New Source Performance Standards (NSPS), and Best Management Practices (BMP). Pollutants regulated are classified as conventional pollutants, non-conventional pollutants, and toxic pollutants.

In addition to technology standards, permit writers also are charged with performing water quality and sediment quality evaluations to ensure the receiving environment is not being irreparably degraded. Permit writers are required to use the more restrictive standard to determine what can be discharged. In most cases the technology standards are much more restrictive than water quality standards and permit writers typically write permits on the basis of technology based standards. The technology based standards and pollutant types will all be discussed below:

Conventional Pollutants: Conventional pollutants are defined to be oil and grease •content , 5-day biochemical oxygen demand (BOD5), TSS, pH, and fecal coliform.

Toxic and Non-Conventional Pollutants: Because of the complex chemical makeup •


of drilling fluids, EPA has elected to regulate the discharge of toxic and non-conventional pollutants by using indicator pollutants. By doing this, EPA significantly reduced the monitoring burden on the discharger while still maintaining strict control over the environmental impact of the discharge. Indicator pollutants are identified through analytical testing as those pollutants that will accurately indicate the presence of a broader class or type of pollutant. In the case of drilling fluids, EPA has identified free oil and diesel oil as indicator pollutants for many organic compounds considered toxic pollutants, i.e., benzene, xylene, PAH, ETC. For heavy metals, EPA identified mercury and cadmium as indicator pollutants. Whole effluent toxicity is used as another indicator of toxic pollutants.

BPT: Effluent guidelines based on BPT apply to discharges of conventional, toxic, and •

non-conventional pollutants from existing sources. BPT represents the average of the best existing performance for conventional pollutants. In establishing BPT effluent limitation guidelines, the EPA considers total cost in relation to the effluent reduction benefits, ages of equipment and facilities involved, the process employed, process changes required, engineering aspects of the control technologies, and non-water quality impacts. The EPA balances the cost of applying the technology against the effluent reduction benefits, as measured in pounds of pollutants removed from the discharge.

BCT: BCT represents the best control of conventional pollutants from existing point •

sources. The CWA requires that the BCT limitations be established in light of a two part "cost-reasonableness" test.

BAT: BAT effluent limitations in general represent the best available economically •

achievable performance and are the principal means for controlling the discharge of toxic and nonconventional pollutants. Under BAT, EPA identifies a treatment technology (same method as used for BPT), assesses the treatment performance of that technology, and establishes limits based on that performance.

NSPS: NSPS limitations are based on the performance of the best available •

demonstrated control technology (BADCT) and apply to all pollutants. NSPS are at least as stringent as BAT. New facilities have the opportunity to install the best and most efficient process and wastewater treatment technology for all pollutants.

BMP: Under the CWA, the EPA may use a technology standard to prevent the release •

of toxic pollutants from facility runoff, spillage, or leaks, sludge or waste disposal and drainage from raw material storage. This standard is called BMP.


Regulatory Development7.3.2

In the 1970’s compliance standards were developed as a means of regulating drilling fluids discharges in the US. The first regulatory permits written in the 1970’s for drilling fluid discharges effectively eliminated discharges of cuttings coated with OBM. Water based mud regulations evolved from the 1970’s through the early 1990’s. Consequently when SBMs were introduced into the USA in the early 1990’s they were not burdened with the legacy of OBMs as they were in the North Sea. The US EPA has identified use and discharge of SBMs as a pollution prevention technology with environmental benefits over traditional technologies (USEPA, 1999a).

In 1993, the USEPA issued its second round of effluent guidelines for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category. At this time, SBMs were just being introduced in the Gulf of Mexico; consequently the only drilling fluids on which data and information were available to the EPA in establishing these guidelines were WBMs and OBMs. The requirements applicable to drilling fluids and cuttings were the following: mercury and cadmium limitations on stock barite, prohibition of diesel oil discharges, a toxicity limit on the suspended particulate phase (SPP) generated when drilling fluids or cuttings are mixed with seawater, and no discharge of free oil as determined by the static sheen test. Subsequent to the issuance of the guidelines, as use of SBMs increased, industry did point out to the EPA the shortcomings of the guidelines for regulating SBM discharges. There were most notably, the inapplicability of the proposed SPP toxicity test, and problems with false positives from the static sheen test; (both of these tests were developed for use with WBMs). The EPA felt that prohibition on the discharges of free oil and the existing toxicity test were an adequate limitation on SBM cuttings discharges. Consequently, SBM cuttings have been allowed to be discharged under the 1993 discharge limitations on an interim basis.

In the final coastal effluent guidelines (1996), EPA identified the limitations of the current regulations with regard to controlling SBM discharges and the need for specific BPT, BAT, BCT, and NSPS controls for discharges associated with SBMs. However, due to lack of information concerning specific controls no further limitations were developed. EPA did outline the parameters it saw as important for adequate control. These included the following: the inability of the static sheen test to detect formation oil or other oil in SBMs, the inability to adequately measure the toxicity of SBMs using the SPP toxicity test. They also included the potential need for controls on base fluid based on PAH content, toxicity, biodegradation, and bioaccumulation potential and stated the intent to evaluate appropriate test methods.

As a result of identification of these issues, the industry and EPA initiated a collaborative


effort to develop specific controls for SBMs. As a result, USEPA has published proposed effluent limitation guidelines and NSPS for synthetic based and other non-aqueous drilling fluids (USEPA, 1999a) and is expected to make a final ruling on these limitations by December 2000 (Veil et al., 1999). PA intends that these proposed guidelines control the discharge of SBMs through application of appropriate levels of technology, and also encourages the use of SBMs as a replacement to diesel and mineral oil-based fluids (USEPA, 1999a). EPA stated in their proposed rule "use of SBFs and discharge of the cuttings waste with proper controls would overall be environmentally preferable to the use of OBFs." (USEPA, 1999a-pg 5490). The reasoning behind the EPA's position was also stated in the proposed rule and is as follows:

There are certain drilling situations (reactive shales, directional drilling, and drilling in •

deep water) where WBM use is slow, costly, or even impossible, and creates large quantities of waste. In these situations, the well would traditionally (prior to the 1990's) be drilled with OBMs (for which there is zero discharge of both the fluid and associated cuttings). However, now there are SBMs available, which can achieve the same technical performance as OBMs yet have lower environmental impact and greater worker safety.SBM discharges would eliminate potential impacts associated with disposal of OBM •

cuttings onshore or via injection (increased emissions, energy use, land-disposal).Although EPA recognizes that discharges of SBM cuttings may impact the receiving •

waters, the primary impacts are expected to be on the benthic community. Available seabed survey data suggest that impacts are limited to within a few hundred meters of the discharge point and significant recovery may occur within 1 to 2 years.EPA believes that impacts on the benthic community are primarily due to smothering, •

alteration of grain size due to introduction of cuttings, and anoxia (caused by decomposition of the organic base fluid). The first two impacts are also associated with WBM and WBM cuttings discharges.EPA finds that these impacts from SBM cuttings discharges are believed to be of •

limited duration, and are less harmful than non-water quality impacts associated with zero-discharge of OBM cuttings.

The proposed regulations were developed through working groups, which included representatives from the USEPA, industry, various government departments and stakeholders. These proposed regulations do not amend the current regulations for WBM, and would be applicable to discharges from offshore and coastal facilities where drilling wastes are allowed for discharge under the current effluent guidelines (i.e., oil and gas wells being drilled in offshore waters greater than “three miles” from shore and in the coastal waters of Cook Inlet, Alaska).


In April of 2000, the EPA summarized information received and collected by the EPA since the original proposed guidelines and published it in what has been referred to as the Notice of Data Availability (NODA; USEPA, 2000). The additional information collected prompted the EPA to consider other biodegradation and toxicity test methods as candidates to qualify base fluids. Based on a limited data set from the Gulf of Mexico the NODA reported a much lower proposed cuttings retention standard than was originally proposed. As a potential implementation option for cuttings retention, the Agency proposed BMPs. The other significant new data in the proposal related to the possibility of using Ester based fluids as the technology standard instead of Olefin based fluids.

Through this notice, EPA also identified many outstanding questions and solicited industry/public input. In response, industry has submitted a substantial amount of new data that will used by the EPA to develop its final regulations.

The proposed regulations are summarized in Table 7.1. Also included are the EPA's definitions of the different classes of drilling fluids. Test methods to be used to demonstrate attainment with the limitations in Table 7.1 are still being developed.


Table 7.1 Summary of Originally Proposed and April 2000 Notice on Limitations for SBM Discharges (USEPA, 1999a; USEPA, 2000)

A. Zero discharge of neat (fluids not attached to cuttings) SBMsB. Discharge of SBM cuttings:

1999 Proposal 2000 NODAStock limitations on SBM base 1.fluids (BAT/NSPS)

Maximum PAH content 10 ppm (wt based on •phenanthrene/wt.base fluid) Minimum biodegradation rate in sediment using the UK •solid phase test (biodegradation equal to or faster than C16-C18 internal olefin by solid phase test) Maximum 10 day sediment toxicity testing using •Leptocherius plumulosus (as toxic or less toxic than C16-C18 internal olefin)

Addition of a modified ISO/DIS 11734 •biodegradation test as an option. Addition of a respirometer as biodegradation test optionAddition of a modified mysid shrimp test as a •toxicity option.Option of using Ester based fluids as the •toxicity and biodegradation standard also included where practical

Discharge limitations on cuttings 2.contaminated with SBMs

No free oil by the static sheen test (BAT/BCT/NSPS)•Maximum formation oil contamination (BAT/NSPS)•Maximum well average retention of SBF on cuttings •(BAT/NSPS)

Retention of SBM base fluids on cuttings •maximum % based on BAT

Discharges remain subject to the 3.following current requirements (BAT/NSPS)

Hg in stock barite maximum 1 mg/kg •Cd in stock barite maximum 3 mg/kg•Diesel oil discharge prohibition•

Other controls being considered4. Maximum sediment toxicity of whole drilling fluid at point •of discharge (BAT/NSPS)Maximum aqueous phase toxicity of whole drilling fluid at •point of discharge (BAT/NSPS) Maximum potential for bioaccumulation of stock base fluid•Zero Discharge of NAF cuttings (BPT/BCT/BAT/NSPS)•

3 BMP options based on operational •performance

USEPA definitions of NAF classes (USEPA, 1999a)(1) A non-aqueous drilling fluid is one in which the continuous phase is a water immiscible fluid such as an oleaginous material (e.g., mineral oil, enhanced mineral oil, paraffinic oil, or synthetic material such as olefins and vegetable esters) (2) An oil-based drilling fluid has diesel oil, mineral oil, or some other oil but neither a synthetic material nor enhanced mineral oil as its continuous phase with water as the dispersed phase. Enhanced mineral oils are a subset of non-aqueous drilling fluids. Typical mineral oils have a PAH content on the order of 0.35 weight % expressed as phenanthrene. All NAFs that are not enhanced mineral oil or synthetics are considered to be oil based fluids. (3) An enhanced mineral oil is a petroleum distillate, which has been highly purified and is distinguished from diesel and conventional mineral oils in having a lower PAH (0.001 or less weight % PAH expressed as phenanthrene). (4) A synthetic based drilling fluid has a synthetic material as its continuous phase with water as the dispersed phase.


Western Australia7.4

Information presented in this section is based on material extracted from Cobby and Craddock (1999). The Western Australian Department of Minerals and Energy (WADME) has developed an objective case-by-case approach to assessing drilling proposals and regulating offshore drilling fluids, as opposed to using the more traditional methods of focussing on the regulation of classes of drilling fluids based on their chemical category. A risk-based approach is used since there is a range of habitat variation coupled with the uncertainties associated with the assessment of environmental effects. WADME does not use an approval system of particular drilling fluids or chemical category in isolation but rather, considers the use of the drilling fluids in the context of the whole drilling application. This holistic approach to the assessment and regulation allows several assessment criteria to be used in the decision framework including:

environmental sensitivity, which considers the distribution and density of the benthic •flora and fauna, site survey information, the distance of the drill site from sensitive marine habitats, and the resilience and recovery potential of the receiving environment;oceanographic conditions and seasonal effects, which considers bathymetry and seabed •morphology, local and regional currents and tides, wind directions, season events, current speed and direction, seabed temperature, and information on the fate of drill cuttings from previously drilled wells;drill cuttings disposal methods, depth of discharge source and estimated discharge •volume;technical justification of the use of a particular drilling fluid; and•drilling fluid environmental performance assessment criteria which consider •ecotoxicity, biodegradation and bioaccumulation properties of the whole and base fluids.

With respect to ecotoxicity, both acute and chronic toxicity of drilling fluids is considered by WADME. Testing is based on local species and are considered a more accurate tool for assessing acceptability of drilling proposals as the results are representative of local conditions. Testing should, however, be performed on representative fluids of those being proposed and possibly worst-case field samples.

When testing for biodegradation, both aerobic and anaerobic degradation results are considered by WADME. Aerobic degradation represents what is occurring at the surface of the cuttings pile, whereas anaerobic degradation represents what is happening inside the cuttings pile. In terms of biodegradation, ester SBMs are currently considered to be the most environmentally acceptable among available SBMs.The treatment of cuttings piles remains a point of discussion with WADME. The size and


nature of the formed piles depends on how much is deposited on the sea floor, the configuration of the platform and the oceanographic conditions of the area. When OBM and SBM cuttings are buried, the rate of natural biodegradation is limited and larger cuttings piles may be considered a source of chronic low level hydrocarbon seepage. This could lead to uptake and bioaccumulation if left for natural recovery after decommissioning. Should the pile be disturbed during decommissioning, there may be an increased potential for wider marine environmental effects. It is suggested that a comprehensive risk assessment should be supplemented by environmental monitoring data to determine the best approach to drilling piles treatment during abandonment. Various options for cuttings pile reclamation have been reviewed by Bell et al., (1998) and Cripps et al., (1998; 1999).

Canada 7.5

Canada is in a relatively early stage of offshore development in comparison with other areas, such as the North Sea. The lessons learnt and knowledge gained in other jurisdictions have shaped the development of the east coast regulatory regime. This has provided east coast Canada with the opportunity to ensure adequate safeguards are put in place to mitigate against potentially undesirable environmental effects from offshore oil and gas production and exploration operations. This is done through a mix of specific legislation, operational guidelines, and legislative provision for public environmental assessment processes.

Canada has in place legislation that prescribes public environmental assessment processes for proposed offshore oil and gas projects. In addition to its overall environmental assessment legislation, Canada has evolved a specific regulatory regime for the exploration, development and production of offshore oil and gas. The following sections summarize that part of the regulatory regime in place and under development on Canada’s east coast which addresses drill fluids/cuttings management.

Canadian East Coast Regulatory Framework7.5.1

On the Canadian east coast, offshore oil and gas development is subject to the Atlantic Accord Implementation Act and Regulations. Two Offshore Petroleum Boards were established co-operatively between the Federal and Provincial governments in Nova Scotia and Newfoundland & Labrador respectively to administer this legislation.

These two boards, known as the Canada – Newfoundland Offshore Petroleum Board (CNOPB) and the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) are responsible on behalf of the Federal, Nova Scotia and Newfoundland & Labrador


governments for petroleum resource management in the Nova Scotia and Newfoundland Offshore Areas. The Boards’ authorities are derived from the Canada-Newfoundland and the Canada – Nova Scotia Atlantic Accord Implementation Acts. The Boards’ responsibilities include:

issuance and administration of petroleum exploration and development rights; •administration of statutory requirements regulating offshore exploration, development •and production;review and approval of Canada-Newfoundland benefits and development plans;•assurance of safe working conditions for offshore operations;•protection of the environment during offshore petroleum activities; and•management of the resource including resource assessment rights management, •resource conservation and resource data management.

With regard to drill fluids/cuttings management, both the Newfoundland Offshore Area Petroleum Drilling Regulations and Nova Scotia Offshore Area Petroleum Drilling Regulations address the drilling fluid system, volume of drilling fluid, bulk handling of fuel and consumables, waste material and drill cuttings (well evaluation and deposition of samples from a well). In addition, the Newfoundland Offshore Area Petroleum Production and Conservation Regulations and Nova Scotia Offshore Area Petroleum Production and Conservation Regulations have sections that pertain to drilling fluids/cuttings management, specifically:

handling of waste material and produced water, which requires that all waste produced •and stored at the site be treated, handled and disposed of as per the environmental protection plan required under the regulations;requirements for the environmental protection plan to:•

minimize or mitigate the effect or routine operations of a production site on the −environment;provide a description of equipment and procedures for treatment, handling and −disposal of waste materials;develop compliance monitoring programs for spilled waste material; and−provide a summary of chemicals used.−

Apart from the foregoing general requirements the Boards have developed two sets of guidelines that bear directly on the management of drill fluids and cuttings. These are entitled the OWTG (NEB et al., 1996) and the Draft OCSG (NEB et al., 1999). These two guidelines provide a basis for managing the selection, use and disposal of drilling fluids and cuttings as well as other discharges and chemicals and discussed in Sections 7.6.2 & 7.6.3 respectively.


Cooperative Regulatory Arrangements7.5.1.1

While the lead agencies for oil and gas activities offshore Newfoundland and Nova Scotia are the C-NOPB and the C-NSOPB respectively, both have developed co-operative working arrangements with relevant departments in both Federal and Provincial levels of government. These arrangements are to ensure those departments’ concerns and expertise is taken into account. Relevant to the context of this document both the C-NOPB and the C-NSOPB have in place Memoranda of Understanding (MOU) with Environment Canada and Department of Fisheries and Oceans (DFO) in relation to petroleum activities in the Newfoundland and Nova Scotia offshore areas, respectively.

The intent of these MOUs is to promote and facilitate environmental protection during the exploration, development, production, and abandonment phases of offshore petroleum resource activities. The principles guiding the actions of the C-NOPB, CNSOPB, and Environment Canada and DFO include sustainable development, pollution prevention, and the precautionary principle as well as effective and efficient application of the appropriate Canadian legislation, including the conduct of environmental assessments.

The development of the OWTG and the OCSG, referred to previously, took place in close consultation with Environment Canada and DFO.

Newfoundland Regulatory Initiatives in Drill Cuttings/Fluid 7.5.1.2Management

In the offshore areas the environmental assessment process for major projects is usually conducted jointly by federal and provincial governments for both jurisdictional and efficiency reasons. These processes usually result in binding recommendations on either or both of proponents or government agencies. One such example is a recommendation that resulted as part of the environment assessment of the Terra Nova project.

While the current OWTG were scheduled for a five-year review, in Recommendation 44 of Decision 97.02 (C-NOBP, 1997) for the Terra-Nova Project, the Public Review Panel recommended that:

“… [C-NOPB] undertake a new, thorough, immediate review of the adequacy of the present regulations on discharges. The review should take full account of monitoring and management experiences in other offshore petroleum areas, and should proceed on the basis of a precautionary approach that considers the impact of specific projects and cumulative


effects as well.”

The C-NOPB accepted the recommendation and committed to re-examine the discharge levels and practices recommended in the OWTG in consultation with other Canadian regulatory agencies, taking into account the precautionary principle enunciated as Principle 15 of the Rio Declaration on Environment and Development (C-NOPB, 1997).

To carry forward the above-noted recommendations the C-NOPB chairs and leads the review of the OWTG with the participation of the National Energy Board, the C-NSOPB, industry, other federal agencies, and members of the public. The OWTG were developed during a period when synthetic based fluids were being introduced and just coming into wider use. The guidelines are therefore more explicit concerning the use and management of oil-based and water based fluids. The current OWTG (see Section 7.6. 2 below for a description of this guideline) provides examples of SBMs (although it does not explicitly define what an SBM is). However, since the OWTG were published (1996), new SBMs have become available that do not readily fit into any of the examples provided in the OWTG (those formulated using esters, ethers or polyalphaolefins).

Pending the completion of the above-noted review of the OWTG the C-NOPB defines SBMs as:

“…a drilling fluid whose continuous phase is composed of one or more fluids produced by the reaction of specific purified chemical feedstock, rather than through physical separation processes such as fractionation, distillation and minor chemical reactions such as cracking and hydro processing. Synthetic fluids typically have a total polycyclic aromatic hydrocarbon (PAH) concentration less than 10 mg/kg (often substantially less) and are non-acutely toxic in most or all marine toxicity tests.” (C-NOPB, 1998)

Furthermore, when an operator in the Newfoundland Offshore area applies to use an SBM, the CNOPB requires:

the SBM be limited to wells (or portions of wells) where drilling requirements are such •that the use of WBM is technically impractical;operators evaluate the technical and economic feasibility of re-injecting drill solids into •sub-surface formations (this was a condition of Decision 97.02 (C-NOPB, 1997)); andsolids control equipment be maintained and operated to reduce the amount of fluid on •any solids that are to discharged; the amount of fluid on solids are to be reported to C-NOPB as per the protocols for OBMs in the OWTG.


Nova Scotia Regulatory Initiatives in Drill Cuttings/Fluid 7.5.1.3Management

Regulatory initiatives separate from those in Newfoundland, developed in Nova Scotia. In Condition 21 of the 1997 Development Plan Decision Report for the Sable Offshore Energy Project the C-NSOPB set a discharge limit of 1% LTMOs by weight on cuttings which needed to be met as of December 31, 1999. In November 1998, the CNSOPB extended this limit to include SBMs, and indicated that they considered SBMs to be the same as LTMOs. As of December 31, 1999 this discharge limit was extended to include all hydrocarbon based drilling operations under the jurisdiction of the C-NSOPB, not just the Sable project. Specifically, discharges of hydrocarbon-based drilling fluids on cuttings may not exceed 1% by weight on cuttings, unless otherwise authorized by the board. Board policy with regard to non-hydrocarbon-based synthetics is that they are to be evaluated on a case-by-case basis.

The rationale for these policy decisions is to minimize petroleum hydrocarbon discharges into the marine environment, and thereby reduce the potential for hydrocarbon tainting of marine organisms.

As noted in Section 7.6.1.2 above the C-NSOPB participates in the ongoing review of the OWTG. In addition, the C-NSOPB is designated as the lead agency for the development of the OCSG which were developed in draft, based on a Hibernia model, and issued to industry for an 18 month voluntary trial in January of 1999. These guidelines are due for evaluation and final promulgation by the end of 2000. A description of the trial OCSG is provided in Section 7.5.3 below.

Canada’s Current Offshore Waste Treatment Guidelines: An 7.5.2Overview

The current (1996) OWTG describe minimum standards for the treatment and/or disposal of wastes associated with routine operations of drilling and production installations offshore Canada. These wastes include produced water, drilling muds, drill solids, storage displacement water, bilge and ballast water, deck drainage, produced sand, well treatment fluids, cooling water, desalination brine, sanitary and food wastes, water for testing fire control systems, other wastes and residues, unused substances and other substances.

For drilling muds, the 1996 OTWG indicate that, when possible, WBM and SBM use is preferred over OBM use. Use of the latter requires specific approval and is limited to specific portions of the well. When OBMs are approved, the OWTG require the aromatic


content to be 5% or less and indicate that they should be non-acutely toxic as per sampling and analysis protocols developed by Environment Canada (1985). The OWTG indicate that SBMs and OBMs remaining from drilling mud changeovers or completion of operations should be recovered and recycled, or disposed of in an approved manner onshore. The OWTG permit spent and excess WBMs to be discharged overboard without treatment.

For disposal of drill solids (cuttings), the 1996 OWTG recommend that operators consider re-injection. Where re-injection is not technically or economically feasible, the OWTG permit at-site discharge of OBM cuttings, with an oil concentration (from all sources) reduced to 15g/100 g or less of dry solids (as measured per API, 1991). Drill solids from operations, which use diesel or similar highly aromatic oils as the continuous phase of the OBM can not be discharged overboard. The OWTG indicate that operators should evaluate new technologies and procedures on an ongoing basis to further reduce the amount of oil discharged on drill solids.

The 1996 OWTG also describe the requirement of operators to design and implement EEM and ECM monitoring programs for production operations. The results of these programs are to be used by regulatory authorities (in consultation with industry and other interested parties) to determine the continued adequacy of the waste treatment and disposal technologies and procedures employed at the drill sites.

Offshore Chemical Selection Guidelines7.5.3

The purpose of the OCSG is to provide a consistent framework for chemical selection as part of the environmentally responsible management of chemicals used in offshore drilling and production activities (NEB et al., 1999). All offshore drilling and production chemicals that may be discharged in the marine environment are to be subject to these guidelines. Domestic chemicals or chemicals not used on-board offshore drilling or production facilities not associated with production or drilling, or chemicals discharged by vessels contracted for specific tasks (e.g., construction) are not subject to the guidelines. The guidelines were developed due to the limited direction provided by other regulations and legislation on the discharge of chemicals into the marine environment. There are 13 screening criteria that are used for the selection of chemicals. This selection criteria includes: identifying the chemical and its proposed use pattern, determining if it already is approved for use in Canada (i.e, the Canadian Domestic or Non-domestic Substances lists), and determining if it appears on international listings that have already evaluated the toxicity of chemicals for offshore uses (e.g., OSPAR HOCNF Taint List, OSPAR List A or B). If further information is required, toxicity testing and risk analysis may be required.


Tracking of the chosen chemical will include the quantity used and quantity discharged, as well as the discharge location. Where possible, material balance will be calculated using conservative assumptions if precise information is not available. A schematic of the various steps in the OCSG is provided in Figure 7.2.


Figure 16 OCSG Process


Environmental Compliance Monitoring 7.5.4

As discussed in Section 4.4, Environmental Compliance Monitoring (ECM) is the tool that operators and regulators use to ensure that discharges generally, and in this case those from offshore oil and gas operations, conform to both regulatory standards and design specifications. Compliance monitoring may also include compliance with design standards, which may arise from the operator itself or by agreement with the regulatory agency during the design phase.

The regulatory standards for compliance monitoring at exploration and production facilities offshore Canada are documented in the OWTG. These guidelines address, among other issues, discharges of the following:

produced water and sand;•

drilling muds (fluids) and solids and well treatment fluids;•

storage displacement, bilge and ballast, and cooling waters;•

deck drainage;•

desalinization brine; and•

sanitary and food wastes.•

The guidelines not only specify what parameters are to be measured (e.g., oil in water) and their limits but in some cases the method for measurement. Table 7.4 below summarizes some of the key compliance monitoring requirements of the OWTG.

Appendices K, L and M presents the compliance monitoring matrices for Hibernia, Terra Nova and Sable Offshore Energy Projects, respectively, to provide the reader some perspective on the conduct of ECM programs for the east coast Offshore.

Emerging Regulatory Issues and Requirements7.5.5

Cumulative effects assessment (CEA) has received increasing attention in Canada in recent years and has been the focus of several Federal Court cases brought by non-governmental organizations. CEA practice is rapidly evolving, as are expectations by responsible authorities and the public. The offshore boards (C-NOPB and C-NSOPB) and the industry recognized that Environmental Sciences Research Fund (ESRF) funding was required to address the application of cumulative effects assessment to offshore projects. In response to the report of the Terra Nova Project Assessment Panel (C-NOPB, 1997), C-NOPB sponsored a study under ESRF to look into the cumulative effects of all activities on the Grand Banks. A workshop was held mid-2000 with various Grand Bank stakeholders, including the oil and gas industry.


Table 7.2 Summary of September 1996 Offshore Waste Treatment Guidelines

(Supplements Footnoted)Type of Waste 1 Discharge

ParameterDesign Considerations

Operational Discharge Limits

Reporting Notes

Drilling DischargesOBM/cuttings • % oil on

cuttingsMust be treated < 15mg/100 g dry

weight average over 48hrs

report within 24hrs if >30mg/l over 48hrreport time series of raw and averaged data on a prescribed schedule

No discharge of whole mud; aromatic content of base oil must be <5% and should be non-acutely toxic. If re-injection is not technically or economically feasible then can discharge cuttings on site.

WBM/cuttings • - No treatment required

- - If re-injection is not technically or economically feasible then can discharge cuttings on site. Operators should develop procedures that reduce the need for the bulk disposal following changeover or completion.

SBM/cuttings 2• - No treatment required

- - No discharge of whole mud; If re-injection is not technically or economically feasible then can discharge cuttings on site

Well Treatment •Fluids

oil must be treated if sampling and analysis required then report time series of raw and averaged data on a prescribed schedule

strong acids to be neutralized; no diesel or high aromatic fluids to be discharged

1 – Operators are advised that the ‘Guidelines’ are minimum requirements and that they should strive to reduce both the volumes of waste discharged and the concentrations of contaminants therein. Furthermore as new technically and economically feasible technology becomes available these should be considered for use.Co-mingling of wastes to achieve discharge concentrations is prohibited and locations of discharges are to be approved on a case by case basis but will be generally below water/ice surface to the lowest point feasible2 – The CNOPB has recently issued guidance to operators with regard to SBMs that supplements the September 1996 Guidelines. This guidance is summarized in Section 7 of this report. Note also that the CNSOPB has recently restricted oil on drill solids (cuttings) for both OBMs and SBMs to 1% which effectively prohibits all SBM and OBM discharges in that jurisdiction.


Note: All reporting or notifications referred to in above table are to be to the Chief Conservation Officer of the Board

Type of Waste 1 Discharge Parameter

Design Considerations

Operational Discharge Limits

Reporting Notes

Water DischargesProduced Water• oil in water must be treated mean of < 40mg/l

over 30 day period report within 24hrs if >80mg/l over 48hrreport time series of raw and averaged data on a prescribed schedule

measured every 12hr with 30 day rolling mean calculated daily

Storage •Displacement Water

oil in water must be treated mean of < 15mg/l over less of 30 day period or discharge period

report if >30mg/l report time series of raw and averaged data on a prescribed schedule

measured every 12hr with 30 day rolling mean calculated daily

Bilge & Ballast •Water

oil in water must be treated < 15mg/l report within 24hrs if >15mg/l -

Deck Drainage• oil in water must be treated < 15mg/l report within 24hrs if >15mg/l -Cooling Water• residual

chlorinecase by case case by case - biocides other than chlorine need approval

Desalinization •Brine

- can be discharged without treatment

- - -

Fire Water• - can be discharged without treatment

- - -

Sanitary & Food Waste Dischargessewage and •kitchen waste

organic solids

must be treated macerated to < 6mm

- -

1 – Operators are advised that the ‘Guidelines’ are minimum requirements and that they should strive to reduce both the volumes of waste discharged and the concentrations of contaminants therein. Furthermore as new technically and economically feasible technology becomes available these should be considered for use.Co-mingling of wastes to achieve discharge concentrations is prohibited and locations of discharges are to be approved on a case by case basis but will be generally below water/ice surface to the lowest point feasibleNote: All reporting or notifications referred to in above table are to be to the Chief Conservation Officer of the Board


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APPENDIX A

Table of Acronyms

ACRONYMS

Acronym DefinitionBADCT Best Available Demonstrated Control TechnologyBAT Best Available Technology (also referred to as best available technology

economically achievableBBL Benthic Boundary LayerBCF Bio-concentration FactorBCT Best Conventional Pollutant Control TechnologyBEP Best Environmental PracticeBMP Best Management PracticesBOD Biochemical Oxygen DemandBPT Best Practical Control Technology Currently AvailableCEA Cumulative Effects AssessmentCAPP Canadian Association of Petroleum ProducersCEPA Canadian Environmental Protection ActCHARM Chemical Hazard Assessment and Risk ManagementC-NOPB Canada-Newfoundland Offshore Petroleum BoardC-NSOPB Canada-Nova Scotia Offshore Petroleum BoardCRI Cuttings Re-InjectionDFO Department Of FisheriesDSL Domestic Substances ListEA Environmental AssessmentEC50 Effective Concentration (50% effected)ECM Environmental Compliance MonitoringEEM Environmental Effects MonitoringEIA Environmental Impact AssessmentEIS Environmental Impact StatementELG Effluent Limitation GuidelinesEMO Enhanced Mineral OilsEMS Environmental Management SystemEOSCA European Oilfield Speciality Chemicals AssociationEPA Environmental Protection Agency (United States)EPP Environmental Protection PlanERW Extended Reach WellsFOE Unsaturated Fatty AcidsFPSO Floating Production, Storage and Offloading VesselFSAE Saturated Fatty AcidsGOOMEX Gulf of Mexico Offshore Monitoring ExperimentHMCS Harmonized Mandatory Control SystemHOCNF Harmonized Offshore Chemical Notification FormatIATA International Maritime Dangerous GoodsIMDG International Maritime Dangerous GoodsIC50 Inhibition Concentration (effective 50%)IO Internal Olefin

CAPP Offshore Drilling Waste Mgmt Review Page A-243 February 2001

JBO Jean D’Arc Basin OperationsLAB Linear Alkyl BenzeneLAO Linear-alpha-olefinLC50 Lethal Concentration (50% mortality)LCVA Life Cycle Value AssessmentLGS Low Gravity SolidsLTMO Low Toxicity Mineral OilLWD Logged While DrillingMFO Mixed Function OxygenMO Mineral OilMODU Mobile Offshore Drilling UnitMOU Memorandum of UnderstandingNAF Non-Aqueous FluidsNGO Non-Governmental OrganizationNIVA Norwegian Institute for Water Research NEB National Energy BoardNRC National Research CouncilNSPS New Source Performance StandardsOBF Oil Based FluidOBM Oil-Based MudOCMS Offshore Chemical Management SystemOCNS Offshore Chemical Notification SystemOCSG Offshore Chemical Selection GuidelinesOECD Organization for Economic Cooperation and Development OIG Offshore Industry GroupOOC Oil On CuttingsOPF Organic Phase Drilling FluidOSPAR Oslo and Paris ConventionOWTG Offshore Waste Treatment GuidelinesPAH Polycyclic (or Polynuclear) Aromatic HydrocarbonsPAO Poly-alpha-olefinPARCOM Paris CommissionPLONOR Pose Little Or No RiskPSA Particle Size AnalysisROP Rate of PenetrationSBF Synthetic-Based FluidsSBM Synthetic-Based MudsSEBA Working Group on Seabed ActivitiesSFAE Saturated Fatty Acids EstersSFT Norwegian Pollution Control AuthoritySG Specific GravitySOAFED Solid Phase Biodegradation TestSOEI Sable Offshore Energy IncorporatedSOEP Sable Offshore Energy ProjectSPP Suspended Particulate Phase

CAPP Offshore Drilling Waste Mgmt Review Page A-244 February 2001

SRE Solids Removal EfficiencyTLM Total Loss ManagementTPH Total Petroleum HydrocarbonTSS Total Suspended SolidsWADME Western Australia Department of Minerals and EnergyWBF Water-Based FluidsWBM Water-Based MudsWHMIS Workplace Hazardous Materials Information System

APPENDIX B

Hibernia EEM Monitoring Variables

Monitoring Variables for the Hibernia EEM Program

MonitoringVariables

Hibernia Baseline Study

Hibernia Production

Phase Study – Year One

Hibernia Production

Phase Study – Year Two

Number Sediment Sampling stations 45 44 56 D

Number of Control Stations 2 x 2 A 2 x 2 2 x 2Number of sediment samples per station 3 3 3 E

Sediment Quality Parameters - Physical/Chemical ü ü ü

- Toxicity ü ü ü

- Microtox ü ü ü

- Amphipod ü ü ü

- Echinoid Fertilization ü C

- Juvenile Polycheate ü ü ü

- Chromotox ü C

- Benthic community Appendages B

Biota - American plaice - Icelandic Scallops - Bioaccumulation - Taint

ü ü ü

ü ü F

ü ü ü

ü ü ü

CAPP Offshore Drilling Waste Mgmt Review Page B-247 February 2001

Notes:A There are two control stations that have 6 sediment samples collected per

station making 2 samples at each of the control stations.B Benthic community appendages was not included in the EEM program because

the benthic study (JWEL 1992) indicated that a large number of samples per station would be required to effectively characterise natural variability. Environment Canada indicated that it should be dropped and sediment toxicity tests incorporated instead (HMDC 1994).

C Echinoid fertilization was dropped from the program due to problems with “false positives” and limited porewater. Chromotox was conducted as a comparison for the Microtox results and was intended to be a baseline study only. Chromotox was conducted as a comparison for the Microtox results and was intended to be a baseline study only.

D Upon review of the “Hibernia Production Phase Environmental Effects Monitoring Program – Year One” (HMDC 1999), it was determined that additional stations within 1 km of the GBS would help to better assess changes that may be occurring as a result of facility operations. Additional 12 stations were added between 500m –1000m from the GBS.

E At 5 randomly selected stations in the 1999 sampling program, there were five samples collected to aid with characterising inter-station variability.

F There were insufficient Icelandic scallops at site to support a monitoring program.

APPENDIX C

Physical and Chemical Parameters Analyzedfor Hibernia EEM Program

Physical and Chemical Parameters for the Hibernia EEM Program

Hydrocarbon Parameter Chemical ParameterTotal Extractable Hydrocarbon (C11-C32) Total Inorganic/Organic Carbon (TIC/TOC)*C11-C20 (Fuel Range) AluminiumC21-C32 (Lube Range) AntimonyNapthalene ArsenicPerylene Barium1- Methylnaphthalene Beryllium2- Methylnaphthalene BoronAcenaphthylene CadmiumAcenaphthene ChromiumFlourene CobaltPhenanthrene CopperAnthracene IronFlouranthene LeadPyrene LithiumBenz[a]anthracene ManganeseChrysene MercuryBenzo[b]flouranthene MolybdenumBenzo[k]flouranthene NickelBenzo[o]pyrene SeleniumIndeno[1,2,3-cd]pyrene StrontiumDibenz[a,h]anthracene ThalliumBenzo[ghi]perylene Tin

UraniumVanadiumZinc* Sediment only

APPENDIX D

Terra Nova EEM Monitoring Variables

Monitoring Variables for the Terra Nova EEM Program

Candidate Monitoring Variables TN Baseline Characterization

TN EEM Program

Number of sediment sampling stations

50 50

Number of control stations 2 x 2 2 x 2Number of sediment samples per station

1, 2 for benthic samples

1, 2 for benthic samples

Sediment Quality - Physical/Chemical - Toxicity - Microtox - Amphipod - Benthic Community

ü ü

ü ü

ü ü

ü ü

ü üWater Quality - Physical/Chemical - Phytoplankton

ü - CTD & chemical analysis at selected

stations

ü - CTD & chemistry

ü - CTD only ü- Chlorophyll & CTD

Biota - Taint - Bioaccumulation - Fish Health - MFO Induction - Histopathology

ü ü

ü ü

ü ü

ü ü

ü ü

APPENDIX E

Physical and Chemical ParametersFor Terra Nova EEM Program

Physical and Chemical Parameters for the Terra Nova EEM Program

Hydrocarbon Parameters Chemical ParametersBenzene* Total Suspended Solids**Toluene* ArsenicEthyl Benzene* BariumXylenes* CadmiumTotal Extractable Hydrocarbon (C11-C32)*

Chromium**

C11-C20 (Fuel Range)* Cobalt**C21-C32 (Lube Range)* CopperNapthalene IronPerylene Lead1- Methylnaphthalene Lithium**2- Methylnaphthalene Manganese**Acenaphthylene MercuryAcenaphthene Nickel**Flourene ZincPhenanthreneAnthraceneFlouranthenePyreneBenz[a]anthraceneChryseneBenzo[b]flourantheneBenzo[k]flourantheneBenzo[o]pyreneIndeno[1,2,3-cd]pyreneDibenz[a,h]anthraceneBenzo[ghi]perylene1-Chloronaphhthalene2-ChloronaphhthaleneOil and Grease **Vegetable Oil and grease **Mineral oil and grease ** * Tissue and sediment only ** Seawater only

APPENDIX F

Sable Island SedimentChemistry Parameters

Candidate Parameters for Sediment Chemistry Samples – Sable Island

Candidate Inorganic Parameters Candidate Petroleum Hydrocarbon Parameters

Aluminum Total HydrocarbonsAntimony BTEX (Benzene, Toluene, Ethylbenzene,

Xylenes)Arsenic C6 to C10 RangeBarium C11 to C20 RangeBeryllium C21 to C32 RangeBoron Polycyclic Aromatic HydrocarbonsCadmium AcenaphtheneChromium AcenaphthleneCobalt AnthraceneCopper Benzo(a)anthraceneIron Benzo(a)pyreneLead Benzo(e)pyreneLithium Benzo(b)fluorantheneManganese Benzo(k)fluorantheneMercury Benzo(ghi)peryleneMolybdenum ChryseneNickel Dibenzo(a,h)anthranceneSelenium FluorantheneSilver FluoreneStrontium Indeno(1,2,3-cd)pyrene Sulphur NaphthaleneVanadium PhenanthreneZinc PyeneTotal Organic CarbonTotal Inorganic CarbonRedox PotentialParticle Size

APPENDIX G

Sable Island Taint andBody Burden Parameters

Sable Island Taint and Body Burden Candidate Parameters

Candidate Petroleum Hydrocarbon Parameters

Candidate Trace Metal Parameters

Total Petroleum Hydrocarbons BariumC11 to C20 Range CadmiumC21 to C32 Range Coppern-C12/pristane to n-C18/phytane LeadPolycyclic Aromatic Hydrocarbons (PAHs)

Zinc

Acenaphthene ChromiumAcenaphthlene AluminumAnthracene LithiumBenzo(a)anthracene IronBenzo(a)pyrene MercuryBenzo(e)pyreneBenzo(b)fluorantheneBenzo(k)fluorantheneBenzo(ghi)peryleneChryseneDibenzo(a,h)anthranceneFluorantheneFluoreneIndeno(1,2,3-cd)pyrene NaphthalenePhenanthrenePyreneC6-C20, C21-C32, C6-C32

APPENDIX H

Ecotoxicological Data of Various SyntheticBased Muds

CAPP Offshore Drilling Waste Mgmt Review Page H-259 February 2001

Composition and Environmental Information, Toxicity and Bioaccumulation Data for the Synthetic Based Drilling Muds (Vik et al, 1996 )

SBM Composition(% in drilling fluid wt/wt)

Toxicity Bioaccumulation(log Pow)

SkeletonemaEC50 (mg/l)

Acartia LC50 (mg/l)

Sediment reworker LC50

(mg/kg dw)ESTER Mud (unused) 34,000-145,600 >50,000Emulsifier 1-5 50,000 >100,000 1.7BDF 132 1-5 6.3Rheol. Control 1 0-1 46,000 <-1Rheol. Control 2 >10,000 5.1Viscosifier 0-1 10,000 5.1Rheol. Modifier 0-1 12,000 <-1Fluid loss control 10,000 7.6Lime 0-1Barite VariesCaCl3-brine 0-1Water VariesACETALMud (unused) >300,000 >50,000 ~15001 11.8Aquamul B 30-60 >100,000 >100,000 5491 >3.0-6.0Aquamul P 1-5 212 330 3071 >3.0Aquamul S 1-5 3295 8719 1511 11.8Aquamul C 0-1 899 >2,000 3881; 24432 3Aquamul F 0-1 91 13.4 4832 3Aquamul Vis 1-5 >10,000 >30,000 >12692 >3.0Aquamul M 1-5 94 1321 60592

Lime 1-5 - - - -CaCl2 brine 1-5 - - - -Barite Varies - - - -Water Varies - - - -PAOMud (unused) 82,400 >50,000 7,0001

(>10,000)2

Emulsifier 1-5 3,900 >50,000 7,0001 11.2-13.7Rheol. Control 1 1-5Rheol. Control 2 1-5Viscosifier 1-5Lime 1-5Barite VariesWater VariesInternal-olefinMud (unused)Base fluid 2,050 >10,000 3001-7,1002 8.6 (calc.)EmulsifierLAOMud (unused) >6.4Base fluidEmulsifierViscosifier


1 Abra alba (LC50 values reported in mg/l in the test reports are multiplied with 12.5 to get the results in mg/kg dw)2 Corophium volutator3 Surface active compounds. The method is not applicable.

Ecotoxicological Data for a Synthetic Based Drilling Mud (Vik et al, 1996)

Chemical Function

% in drilling

fluid (wt/wt)

Ecotoxicological Data

Molecular Weight

Toxicity E(L)C50*** Biode-gradation

(%)

Bioaccumulation

Skeletonema (mg/l)

Acartia(mg/l)

Corophium (mg/kg)

Log Pow

BCF 6

Mud (whole)

100 <600 >300,000 >50,000 ~15002

Base fluid 30-60 <600 >100,000 >100,000 6672 144

865

11.8 3.8

Additive 1 1-5 >600<600

212 330 3072 34.93.4

<3.0*

Additive 2 0-1 >600<600

3295 8719 1512 39.33.4

>3.0*

Additive 3 0-1 >600<600

899 >2000 3882

24431

4.6865

**11.8

Additive 4 0-1 >600<600

91 13.4 4831 32.93.4

***

Additive 5 1-5 > 600 >10,000 >30,000 >12691 1 **Additive 6 0-1 >600

<60094 1321 60591 10.3

2.23

>3.0>3.0

Lime 1-5 List A chemical Inorg. Inorg.CaCl2 brine 5-10 List A chemical Inorg. Inorg.Barite Varies List A chemical Inorg. Inorg.Water Varies List A chemical Inorg. Inorg.

1 Corophium 2 Abra alba3 Measured on whole preparation4 Seawater test5 Freshwater test6 Lipid weight basis* Solvent, the method was not applicable, tried in laboratory** Surface active, the method was not applicable, tried in laboratoryN/A = not available

APPENDIX I

Country-Specific Requirementsfor Discharge of Drilling Muds and Cuttings

CAPP Offshore Drilling Waste Mgmt Review Page I-263 February 2001

Appendix 4-1. Requirements for Discharge of Drilling Mud and CuttingsCountry Water Based Drilling Fluids

and CuttingsOil Based Drilling Fluid

CuttingsSynthetic Based Drilling Fluid

CuttingsEnvironmental Monitoring

RequirementsAngola- Discharge allowed• Cuttings discharge allowed, •

muds are reused.Oil on cuttings measured, no •limit provided.No other parameters •measured.

Cuttings discharge allowed, •muds are reused.Oil on cuttings measured.•

Australia

Discharge allowed subject to •1% oil limit, including free oil & diesel oil, and 17% KCl content of muds for exploratory drilling. Sampling required predischarge.Other drilling wastes can be •discharged as long as they meet the 1% oil limit.Risk assessments required by •regulator Operators describe the types of •muds to be used and may make commitments for additional testing or monitoring in Environment Plans which are submitted to the government and once accepted become binding requirements. Flow rate monitored but not •reported or limited.Some dischargers monitor •Hg/Cd.

1% oil limit.effectively •eliminates discharge. In W. A., operators were allowed approx. 15% oil limit for low tox OBM cuttings 2-3 years ago. This exception would most likely not be allowed now.

No specific regulatory •language concerning SBM.WA regulator sets a 10% dry •weight limit on SBM cuttings discharges under environmental plan regulationsOperators have discharged •esters and IO cuttings with requirements for monitoring programs determined on case by case basis. Esters seem to be acceptable •but more general acceptability of SBM not resolvedEnvironmental regulations for •offshore E&P being overhauled and may become more detailed and specific.Enhanced-mineral-oil-based •cuttings have been used in the past in W.A. & discharged.

Monitoring not required •but may be in the futureOperators may make •commitments for monitoring in environment Plans which are submitted to the government and once accepted become binding requirements


Azerbaijan

Discharge allowed as long as •low toxicity, acceptable biodegradability.Chloride content limited to less •than 4 (or 2 for some PSAs) times ambient—Caspian sea is 1/3 seawater salinity.Flow rate is estimated daily by •drilling logs and reported monthly, but it is not limited.Periodic sampling for toxicity•

testing.Before drilling, mud program •is assessed for toxicity and biodegradability.Chloride content is monitored.•Daily inventory of discharged •mud additives is maintained.Operators in •inshore/environmentally sensitive areas have more monitoring requirements; and more stringent standards.Regulators like to see MSDS •for all chemicals that can be used, but no certification process for each chemical.

No discharge of fluid or •cuttings.Injection of cuttings being •planned for exploration wells.Onshore treatment (e.g. •fixation) and / or landfilling being planned.Some operators treat cuttings •onshore;

Cuttings from synthetics may be •discharged. Voluntary commitments by BP Amoco to no discharge of synthetic cuttings. Operators expect further restrictions, primarily for production drilling. No discharge of SBM fluids.•Discharge of cuttings allowed as •long as a low toxicity, acceptable biodegradability mud is used.Some operators have a limit of •10% SBM fluid on cuttings.Discharge of enhanced-mineral-•oil-based fluids is not allowed, discharge of cuttings anticipated to be allowed as long as fluids have low toxicity and acceptable biodegradability—toxicity & biodegradability standards have not been set.

Monitoring requirements •are negotiated by each operator as part of the PSA, or through the EIAOperators are required to •conduct baseline surveys prior to commencing operations (both exploration and production). Post drilling surveys are •required as well and are proposed in the EIA.Operational monitoring of •discharges negotiated by each operator as part of PSA


Brazil No specific regulatory language •concerning WBFCurrent practice is to allow •discharge

No specific regulatory •language concerning OBF, however all drilling discharge plans need to be approved through IBAMA; IBAMA has made it clear that there will be greater scrutiny of NAF discharges (than those of WBFs) Unlikely that low tox mineral •oils would be approved-Enhanced Mineral Oil based fluids possible. Petrobras presently •discharging a highly refined paraffin mud

No specific regulatory language •concerning SBF, however all drilling discharge plans need to be approved through IBAMA; IBAMA has made it clear that there will be greater scrutiny of NAF discharges (than those of WBFs) SBM cuttings have been •discharged by Petrobras. Industry workgroup formulating •guidelines for discharge approval (laboratory testing protocols-biodegradability, sediment toxicity, and bioaccumulation) and plans to work with government to develop a framework for gaining approval for use of synthetics.


Canada 1996 guidelines allow •discharge of water-based muds without restrictions. Cuttings may be discharged if reinjection is not economically or technically feasible2. Operators are encouraged to reduce the need for bulk disposal of drilling fluids. Guidelines are under review.

1996 guidelines require •specific approval to use OBF; aromatic content of oil <5% and toxicity limit for water soluble fraction; WBF or SBF use preferred. Cuttings may be discharged if reinjection is not technically or economically feasible, subject to 15% oil on cuttings limit; cuttings from diesel or highly aromatic oils not allowed to be discharged. OBF bulk discharge not allowed. Re-injection should be considered to reduce waste discharged into the environment. Guidelines under review. Nova Scotia (C-NSOPB) has •adopted a 1% oil on cuttings limit as of YE 19993.

1996 guidelines encourage use •of WBF or SBF; aromatic content of oil <5% and toxicity limit for water soluble fraction. Cuttings may be discharged if re-injection is not economically or technically feasible subject to a 15% Oil on cuttings limit. SBF bulk discharges prohibited. Nova Scotia (Canadian Nova •Scotia Petroleum Board CNSOPB) has adopted a 1% oil on cuttings limit for synthetics as of YE 1999, effectively prohibiting discharge. The agency that regulates the •Industry in Newfoundland (CNOPB) stipulates that if re-injection is not feasible, SBM solids may be discharged without treatment; SBM includes paraffins; operator should ensure that solids control equipment is maintained and operated so as to reduce fluids on cuttings to as low a level as is reasonably practicable.

Environmental Effects and Compliance Monitoring are required for production drilling per the Offshore Waste Treatment Guidelines.


China— Discharge allowed.•Use of oil shall be avoided or •minimized.Prior to discharge, the operator •shall notify the relevant agency of oil-containing water-based drilling fluids and submit sample.If oil content >10% discharge •not allowed.If oil content <10% and further •recovery difficult, upon relevant agency approval, discharge is allowed, but operator shall pay a discharge fee.Prior to discharge, dispersant •shall not be mixed with oil-containing water-based fluids for treatment.No KCl restrictions known•Flow rate measurement is at the •discharge pipe and daily monitoring is the responsibility of environmental monitoring office of operator. Flow rate limits unknownOther monitoring requirements •for other drilling fluid components unknown.Discharge of residual oil, waste •oil, oil-containing waste and its residual liquids and solids are prohibited. These wastes shall be stored in special containers for shipment to shore.Operator shall record in the •Antipollution Record Book drilling mud, oil content of cuttings, time of discharge, and volume of discharge, etc.

Discharge of OBM cuttings •allowed, fluids not allowed.If oil content >10% discharge •not allowed.If oil content <10% and further •recovery is difficult, discharge allowed after approval from relevant agency, but operator shall pay a discharge fee.

Regulations regarding discharge •of SBM fluid/cuttings unknown.

No drilling monitoring •requirements for exploratory drilling


Denmark2 Discharge allowed subject to pre-approval requirements for drilling fluid chemicals.

Limit of 1% oil on cuttings - effectively prohibits discharge

Considered on a case by case basis but no use at present.

Equatorial Guinea

Discharge allowed• Discharge allowed; • Discharge allowed•

Kazakstan No discharge allowed per the •Petroleum Law; Environmental Protection Norms (for offshore, coastal areas & internal water bodies); and Special Ecological Requirements (for State Nature Preserve Zone in North Caspian).

No discharge allowed per the •Petroleum Law; Environmental Protection Norms (for offshore, coastal areas & internal water bodies); and Special Ecological Requirements (for State Nature Preserve Zone in North Caspian).OKIOC presently using •LTOBM and hauling cuttings ashore for thermal desorption and fluid recovery

No discharge allowed per the •Petroleum Law; Environmental Protection Norms (for offshore, coastal areas & internal water bodies); and Special Ecological Requirements (for State Nature Preserve Zone in North Caspian).

Operators are required to •conduct baseline surveys prior to commencing operationsMonitoring requirements •are stated in regulation and further negotiated by each operator through the EIA processPost drilling surveys are •required for 2 consecutive yearsMonitoring requirements •stated in regs but are negotiable.

Malaysia Discharge allowed.•Flow rate is estimated but not •reported.Drilling mud makeup is •monitored but not reportedNo additional monitoring •requirements.

Discharged allowed. •No oil limit.•

Operators are using refined •paraffins and low toxicity OBM and discharging cuttings. No regulatory action on SBM currently on horizon.No oil limit.•

No drilling monitoring •requirements; voluntary environmental monitoring sometimes conducted as part of the EIA approval processOne-time baseline study of a •new field area is often conducted as part of EIA preparation


Nigeria

To discharge, must submit •proof that mud has low toxicity to Director of Petroleum Resources (DPR) with permit application. Discharges will be treated to DPR’s satisfaction.DPR will examine WBM to •determine how hazardous and toxic it is.Cuttings contaminated with •WBM may be discharged offshore/deep water without treatment.See Appendix III for •monitoring requirements.See Appendix III for “Generic •Drilling Fluids List” showing components of drilling fluids that are regulated.

To discharge, must submit •proof that OBM has low toxicity to DPR with permit application. Discharges will be treated to DPR’s satisfaction.OBM must be recovered, •reconditioned, and recycled.Oil on cuttings, 1% with 0% •goal. On-site disposal if oil content •does not cause sheen on the receiving water.Cuttings samples shall be •analyzed by Operator as specified by DPR once a day.Point of discharge as designated •on the installation by shunting to the bottom.DPR to analyse samples at its •own discretion for toxic/hazardous substances.Operator to carry out first post-•drilling seabed survey 9 months after 5 wells have been drilled. Subsequent seabed surveys shall then be carried out after a further 18 months or further 10 wellsOperator must submit to DPR •details of sampling and analysis records within 2 weeks of completion of any well.Inspection of operations shall •be allowed at all reasonable times.

SBM must be recovered, •reconditioned, and recycled.SBM cuttings must contain 5% •drilling fluid or less for discharge. (10% for esters)Special provision for higher •retention limits have been granted for some deepwater wells

Operator to carry out first •postdrilling seabed survey after 9 months or after 5 wells have been drilled, whichever is shorter. Subsequent seabed surveys shall then be carried out after a further 18 months or 10 wells.


Norway Discharge allowed subject to •pre-approval requirements for all drilling fluid chemicals. Monitoring of discharge sites •may be required. Preapproval requirements include toxicity testing according to OSPAR protocols. No KCl limits.•Flow rate not monitored or •limited, but calculation is made of cuttings discharged based on well dimensions and wash out factor.Sampling is daily.•Discharge of other drilling •wastes not prohibited as long as pre-approval occurs.A discharge permit is required •for cementing and completion chemicals.Drilling mud makeup is •monitored and reported.

Limit of 1% oil on cuttings – •effectively prohibits discharge.

Permitting discharge of a range •of synthetics for development drilling only.SBM discharge allowed only •where technical/safety considerations preclude use of WBMSBM content of cuttings limited •to 8-18 %; operator is required to set limit based on properties of formation.Chemical monitoring of cuttings •required annually, biological monitoring required every 3 years. Applications for approval •require testing according to OSPAR format.

A baseline survey is •required prior to initiation of production drilling activities. Monitoring activities are •thereafter required to be performed every 3 years. Surveys involve sampling of sediment and analysis for biological and chemical propertiesGuidelines for monitoring •are provided in the 1999 SFT document " Environmental monitoring of petroleum activities on the Norwegian shelf: guidelines" ( in Norwegian) Guidelines for •characterizing drill cuttings piles have been prepared by the Norwegian oil industry association (OLF)


Russia—Sakhalin Island

In Russia's Exclusive Economic •Zone (beyond 12 mile Territorial Sea of Russia), control of all discharges is through the application of receiving water criteria or "maximum permissible concentrations, MPC's. All substances discharged must have certified MPC's and must meet these allowable concentrations at a distance of 250m from the discharge point. The promulgation, in 1998, of the Law on the Territorial Sea introduced uncertainty regarding the legality of ANY discharges within the 12 mile limit, at least in the minds of some Russian regulators. The Government of the Russian federation is taking steps to clarify the legal basis for discharges to the Territorial Sea (Decree by former President Putin)Toxicity testing on mud •additives, lab formulated muds, and used muds using protozoa, marine algae, acartia, and guppy at 20% salinity.Sampling frequency not •specified—several times during drilling.Mud constituents, discharge •rates, and other parameters may be regulated by the Water-use License process.

Regulatory documents do not deal specifically with oil based drilling fluids; regulations currently in draft form will prohibit cuttings discharge if oil based mud used.

Not yet discussed with regulators


The Netherlands

Discharge allowed subject to pre-approval requirements for drilling fluid chemicals. Pre-approval requirements include toxicity testing according to OSPAR protocols.

Limit of 1% oil on cuttings –effectively prohibits discharge.

Extensive monitoring requirements effectively prohibit use.

UK Discharge allowed subject to •pre-approval requirements for drilling fluid chemicals. Pre-approval requirements include toxicity testing according to OSPAR protocols.

Limit of 1% oil on cuttings – •effectively prohibits dischargePractice is to inject cuttings or •return to shore and recover oil.

Phasing out use of all but ester •based synthetics. Industry expects further restrictions on esters. Discharge of non-ester fluids will likely ceased at end of 2000

OSPAR requirements•Requirements for seabed •monitoring following discharge of SBM cuttings; data used in conjunction with laboratory data to determine fluid acceptability.

United States—California (EUSA)

Discharge allowed beyond •coastal waters (3 mi).50 lb/bbl in EPA generic mud •#1.Flow rate is monitored and •maximum annual discharge cannot exceed 215,000 bbl.Hg/Cd < 1/2 ppm.•No free oil/diesel/waste oil as •by static sheen test.No chrome lignosulfonate.•96 hr LC50 SPP >3%. Weekly •sampling; at least 1 tox. test of each mud system. Mud sample must be at 80% or greater of final depth for each mud systemSpecial restrictions for enviro. •Sensitive areas.Spotting fluids must meet •toxicity requirements.Drilling mud makeup •monitored and reported.

Discharge prohibited.•Discharge of enhanced-mineral-•oil-based mud/cuttings prohibited.Practice is to inject OBM •cuttings.

Not specifically mentioned in •current permit. Under discussion for regional permit.


United States—GOM (EUSA)

Discharge allowed > 3 miles, •not allowed < 3 miles.Toxicity limit effectively limits •KCl content.Flow rate is estimated hourly •during discharge.Flow rate is limited in •biologically sensitive areas.Toxicity: 96 hour LC50 of •suspended particulate phase >30,000 ppm.1/3 ppm Hg/Cd in barite; tested •in stock barite.Must keep a chemical inventory •and track mass/volume of all mud constituents.No free oil as measured by •static sheen test.Toxicity testing monthly. By •Exxon choice, testing every time mud system changed. Static sheen testing is performed weekly.Spotting pills may not be •discharged.No other components •regulated.

Discharge not allowed.•OBM cuttings are typically •landfilled.Exxon typically rents OBM •from mud supplier and only pay for the volume that is not returned. Cuttings are treated to varying degrees onshore and either injected or landfilled

Western GOM allows discharge •of SBM cuttings subject to the same restrictions as water-based mud until approval of EPA SBM rule.Eastern GOM does not allow •discharge.Only mud associated with •cuttings may be discharged. Currently, spills of SBM are treated as oil spills.

Compliance monitoring as detailed. No requirements for routine seabed monitoring


United States2

Coastal Waters: (e.g. inland •canals and enclosed bays). Discharge prohibited except for Alaska. Alaskan coastal waters subject to same regulations as offshore waters. Offshore Waters: Discharge •allowed subject to: >3 mi from shore (except •Alaska where >3 mi restriction does not apply)Limit on toxicity (LC50 of •suspended particulate phase >30000 ppm)Limit on Hg/Cd in barite (1/3 •ppm)No free oil (static sheen test)•No diesel oil•Discharge rate < 1000 bbl/hr•Further restrictions on rate in •areas of special biological sensitivity

Discharge prohibited Current Status•Western GOM. Discharges −allowed in the GOM subject to the same restrictions as water based muds. Eastern GOM: Discharges not −allowed. California: Discharges not −allowed. Alaska: Discharges not −allowed.

EPA developing specific •guidelines for SBM cuttings discharge.


Vietnam Discharge allowed.•No stipulations on KCl•Toxicity requirements not •stipulated concretely.In general oil content should be •lower than 1%.Any use of drilling fluids, toxic •and/or hazardous chemicals must be approved by regulatory agency in advance.Drilling mud makeup is •monitored and reported as drilling mud components in EIA report.

Discharge prohibited < 3 •nautical miles. 1% oil limit (possibly extended for certain cases) for areas beyond 3 nautical miles.Use of diesel-based drilling •fluids is totally prohibited.

No stipulations regarding SBM •cuttings. May have same restrictions as OBM cuttings.

Drilling monitoring •requirements are only generally stipulatedOperator must carry out •environmental monitoring and implementation of a program on environmental supervision in accordance with the Ministry of Science, Technology and Environment's (MOSTE) decision approving the EIA of a project or facility. Monitoring requirements •such as baseline and impact assessment studies are carried out as stipulated in the proposed and approved EIA

APPENDIX J

OSPAR DECISION 2000/3 on the Use of Organic-Phase Drilling Fluids and Discharge of OPF Contaminated Cuttings

CAPP Offshore Drilling Waste Mgmt Review Page J-277 February 2001

ANNEX 18(Ref. § 7.8a)

OSPAR CONVENTION FOR THE PROTECTION OF THE MARINE ENVIRONMENT IN THE NORTH-EAST ATLANTIC

MEETING OF THE OSPAR COMMISSION

COPENHAGEN: 26 - 30 JUNE 2000______________________________________________________________________________

OSPAR Decision 2000/3 on the Use of Organic-Phase Drilling Fluids (OPF) and the Discharge of OPF-Contaminated Cuttings

RECALLING Article 2 (3) of the Convention for the Protection of the Marine Environment of the North-East Atlantic ("OSPAR Convention"), which requires the Contracting Parties to take full account of the latest technological developments and practices when adopting Programmes and Measures;

RECALLING Article 5 of the OSPAR Convention, which requires the Contracting Parties to take all possible steps to prevent and eliminate pollution from offshore sources in accordance with the provisions of the Convention, in particular as provided for in Annex III of the Convention;

RECALLING Article 3 of Annex III of the OSPAR Convention, which prohibits any dumping of wastes or other matter from offshore installations;

RECALLING PARCOM Decision on the Notification of Chemicals Used Offshore, 1981 and PARCOM Decision 92/2 on the Use of Oil-Based Muds, the latter of which took effective steps to reduce the discharge of oil based drilling muds into the maritime area;

NOTING that recently developed synthetic drilling fluids are likely to persist when discharged into the marine environment at high concentration on drill cuttings where anaerobic conditions develop;

NOTING the recommendation of the Workshop on Drilling Fluids that a structured approach to the choice of drilling options should be implemented;

NOTING the legislation of the European Community, of the European Economic Area and corresponding legislation of other Contracting Parties which defines principles on, and makes provision for waste management;

RECOGNISING that marine pollution by drill cuttings and their associated organic phase drilling fluids (OPF) should be avoided and prevented to the greatest possible extent.

The Contracting Parties to the Convention for the Protection of the Marine Environment of the North-East Atlantic Decide:


1. Definitions

1.1 For the purpose of this Decision:a. "Organic-phase drilling fluid (OPF)" means an organic-phase drilling fluid, which is an

emulsion of water and other additives in which the continuous phase is a water-immiscible organic fluid of animal, vegetable or mineral origin;

b. "Base fluid" means the water immiscible fluid which forms the major part of the continuous phase of the OPF;

c. "Drilling fluid" means base fluid together with those additional chemicals which constitute the drilling system;

d. "Oil-based fluids (OBF)" means low aromatic and paraffinic oils and those mineral oil-based fluids that are neither synthetic fluids nor fluids of a class whose use is otherwise prohibited;

e. "Synthetic fluid" means highly refined mineral oil-based fluids and fluids derived from vegetable and animal sources;

f. "Cuttings" means solid material removed from drilled rock together with any solids and liquids derived from any adherent drilling fluids;

g. "Whole OPF" means OPF not adhering to or mixed with cuttings.

2. Purpose and scope

Purpose

2.1 The purpose of this Decision is to prevent and eliminate pollution of the maritime area by the use and discharge of OPF and OPF-contaminated cuttings.

Scope

This Decision shall apply to all OPFs used for the purpose of drilling in the course of 2.2offshore activities.

3. Programmes and Measures

3.1 Use and discharge of organic-phase drilling fluids

3.1.1 Contracting Parties shall ensure that no OPF shall be used for the purpose of drilling in the course of an offshore activity or discharged to the maritime area without prior authorisation from the national competent authority. In reaching a decision on any authorisation, Contracting Parties shall apply to the management of OPF-contaminated cuttings:

a. the principles of the Harmonised Mandatory Control System for the Use and Reduction of


the Discharge of Offshore Chemicals as set out in the applicable OSPAR Decision;

b. Best Available Techniques (BAT) and Best Environmental Practice (BEP) as set out in Appendix 1 of the OSPAR Convention;

c. the waste management hierarchy set out in Appendix 1 to this Decision.

3.1.2 The use of diesel-oil-based drilling fluids is prohibited.

3.1.3 The discharge of whole OPF to the maritime area is prohibited. The mixing of OPF with cuttings for the purpose of disposal is not acceptable.

3.1.4 The discharge into the sea of cuttings contaminated with OBF at a concentration greater than 1% by weight on dry cuttings is prohibited.

3.1.5 The use of OPF in the upper part of the well is prohibited. Exemptions may be granted by the national competent authority for geological or safety reasons.

3.1.6 The discharge into the sea of cuttings contaminated with synthetic fluids shall only be authorised in exceptional circumstances. Such authorisations shall be based on the application of BAT/BEP as set out in Appendix 1 of this Decision.

3.2 Monitoring and reporting of OPF use

3.2.1 The national competent authority shall require such monitoring and inspection as is necessary to ensure compliance with the terms of any authorisation.

3.2.2 Reporting on the use and management of OPF shall use a mass balance (volumetric) method of quantification.

4. Entry into Force

This Decision will enter into force on 16 January 2001.4.1

Upon entry into force, this Decision shall supersede:4.2a. PARCOM Decision on the Notification of Chemicals Used Offshore, 1981;

b. PARCOM Decision 92/2 on the Use of Oil-Based Muds.

5. Implementation Reports

5.1 Reports on the implementation of this Decision shall be submitted to the appropriate OSPAR subsidiary body in the intersessional period 2001/2002 in accordance with OSPAR's Standard Implementation Reporting and Assessment Procedure.

reporting on implementation, the format as set out in Appendix 2 shall apply.


Appendix 1

Best Available Techniques and Best Environmental Practice for the Management of the Use of Organic-Phase Drilling Fluids (OPF) and the Discharge of OPF Contaminated Cuttings

Best Available Techniques

BAT is described within the context of the ‘five R’s’ waste management hierarchy below. If future development leads to the production of novel, environmentally sound products and techniques then OSPAR may update this Decision to take these into account.

Reduce1. The reduction of discharges of OPF-contaminated cuttings is the primary focus of this Decision.

Examples of measures to be taken with a view to reducing these discharges are (i) prohibition on use in the upper well section, except where technically necessary, (ii) horizontal drilling and (iii) slim hole drilling.

Reuse

2. Operators will choose techniques from a range of options e.g. mud treatment plants, shale shakers, centrifuges and washing systems for cuttings, i.e. those technologies that maximise reuse consistent with safe and efficient drilling. Use of mass balance (volumetric) reporting will enable national authorities to check that reuse is being carried out effectively.

Recycle / Recover

3. In order to avoid discharges into the sea of OPF-contaminated cuttings, recycling/recovery measures should be implemented (e.g. recovery for re-use of the organic phase by distillation onshore or offshore, use of shale shakers and centrifuges).

Residue disposal

4. The following options for the management of OPF-contaminated cuttings residue should be considered:a. transportation to shore of cuttings for OPF processing (e.g. oil recovery and residue disposal);b. reinjection of such cuttings; c. offshore treatment of such cuttings with the aim of achieving the target technology standard of

1% OPF fluid by weight on dry cuttings, and the discharge of the cleaned residue;d. when cleaned residues of cuttings contaminated with synthetic fluid cannot meet that standard,

national competent authorities may authorise discharge to the sea having regard to the toxicity, biodegradability and liability to bioaccumulate of the drilling fluid concerned and of the hydrography of the receiving environment.

All the above options should be assessed on a case-by-case basis by the national competent authority before it reaches any decision on the discharge of cuttings as authorised in paragraph 3.1.6. The Contracting Party concerned will report to the Commission on the criteria used by the national competent authority in reaching its decision to authorise such discharge.

Best Environmental Practice5. In considering the various options for the control of organic phase drilling fluids account should be

taken of the conservation of resources, including energy.


1 Delete whichever is not appropriate

Appendix 2

Implementation Report Format

The format below for the implementation report on compliance with OSPAR Decision 2000/3 on the Use of Organic-Phase Drilling Fluids (OPF) and the Discharge of OPF-Contaminated Cuttings should be used to the extent possible.

Country:

Reservation applies yes/no*

Is measure applicable in your country?

yes/no*

1. If not applicable, then state why not (e.g. no relevant installation or activity)

Means of Implementation: by legislation by administrative action by negotiated agreementyes/no* yes/no* yes/no*

2. Please provide information on:

a. specific measures taken to give effect to this measure by using the attached template;

b. any special difficulties encountered, such as practical or legal problems, in the implementation of this Decision;

c. the reasons for not having fully implemented this measure should be spelt out clearly and plans for full implementation should be reported;

d. if appropriate, progress towards being able to lift the reservation.

APPENDIX K

Hibernia ECM Monitoring Variables

CAPP Offshore Drilling Waste Mgmt Review Page K-284

Waste Stream

Parameter Measured

Regulatory Limit

Sample Method & Location

Sampling Frequency

Analysis Method

Data Reporting Frequency

Produced Water

Dispersed Hydrocarbon

30 day rolling average of 40

mg/l

Grab Sample in Module

M10 d/s of degasser

Twice per day

IR Spectro-photometry

Monthly

Water Based Muds

NA NA NA NA NA NA

Synthetic Muds

Oil on Cuttings

NA Grab Sample in Module

M20 d/s of cuttings cleaning

Twice per day

Modified API Retort

Method RP 13B-2

Weekly summary

and in final well report

Storage Displacement Water


30 day average of 15

mg/l

Grab Sample in

Utility Shaft - level U-09

Twice per day


Monthly

Platform Process Drainage



mg/l


M10 d/s of oily water treatment

Twice per week


Monthly

Platform Drilling Drainage



mg/l


M20 d/s of cuttings cleaning

Twice per week


Monthly

Sanitary & Domestic Wastes

NA Particles macerated to

<6mm

NA NA NA NA

CAPP Offshore Drilling Waste Mgmt Review Page K-285

Chlorinated Seawater

Total Residual Chlorine (TRC)

Maximum of 2mg/l

instantaneous at discharge

point


M40 from Seawater return line

d/s of sewage line

Twice per day

Hach Kit – total

residual chlorine

Monthly

APPENDIX L

Terra Nova Monitoring Variables – Development Drilling

CAPP OffshoreDrilling Waste Mgmt Review Page L-287 February 2001

Effluent Parameter Sample Type and Volume

Sampling Location

SamplingFrequency

Regulatory Limit

Internal Reporting

Synthetic-based drilling cuttings/ drilling area drainage cuttings

HydrocarbonOn solids

Grab sample Below shaker cuttings discharge

Twice daily -once per 12 hour shift

N/A

(internal limit: 15 mg/L by weight)

48-h rolling average reported to Operator and TLM Environment Lead

Schedule: monthly by middle of calendar month following reporting month

Exceedances: notify within 12h

Drilling area drainage

DispersedHydrocarbon

Grab sample Centralized skimming collection discharge

Once per week

15 mg/L by weight

Per sample result reported to Operator and TLM Environment Lead



Bilge water drainage

Dispersed hydrocarbon

Grab sample Sample taken from thruster well

Once per week

15 mg/L by weight

Per sample result reported to Operator and TLM Environment Lead



Source: Terra Nova Alliance 1999

APPENDIX M

SOEI Monitoring Variables

CAPP Offshore Drilling Waste Mgmt Review Page M-289 February 2001

Waste Type Objective/Target Methodology Key Performance IndicatorProduced water

concentration of dispersed oil to •<40 mg/L¹, OR <25 mg/L averaged over 30 daysSOEI has set target of <25 mg/L •oil concentration per event

Sampling and •laboratory analysis

% of time in compliance% of time < 25 mg/L

Produced Sand <1mg/kg total oil• Sampling and •laboratory analysis

% of time in compliance

Drilling muds OBM and SBM should be •recovered and recycled or transferred to shore for proper disposal¹

Review documentation•


No discharges of OBM and SBM

Drill Solids oil concentration on drill solids •<8 g/100 g over 48 hours prior to ocean discharge prior to December 31, 1999² oil concentration on drill solids •<1g/100 g over 48 hours prior to ocean discharge after December 31, 1999²



Well Treatment Fluids

oil concentration of <40 mg/L¹ •daysSOEI has set target of <25 mg/L •oil concentration per event

Sampling and •laboratory analysisInspection•


References:¹ Offshore Waste Treatment Guidelines. September 1996. National Energy Board, Canada-Newfoundland Offshore Petroleum Board, Canada-Nova Scotia Offshore Petroleum Board.² C-NSOPB. December 1997. Sable Offshore Energy Project. Development Plan Decision Report.

offshore drilling waste management review[1]

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