ibp1669 08 meeting the flow assurance challenges of

______________________________1 Ph.D., Geochemistry - NALCO Ltd2 MBA., Oil and Gas Business – NALCO Brasil Ltda3 BSc., Chemical Engineering– NALCO Brasil Ltda4 Ph.D., Chemistry – NALCO Ltd

IBP1669_08MEETING THE FLOW ASSURANCE CHALLENGES OF

DEEPWATER DEVELOPMENTS – FROM CAPEX DEVELOPMENT TO FIELD START UP.

M.M.Jordan1,M.Afonso 2, D.Silva3, N.D.Feasey4

Copyright 2008, Brazilian Petroleum, Gas and Biofuels Institute - IBPThis Technical Paper was prepared for presentation at the Rio Oil & Gas Expo and Conference 2008, held between September, 15-18, 2008, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event according to the information contained in the abstract submitted by the author(s). The contents of the Technical Paper, as presented, were not reviewed by IBP. The organizers are not supposed to translate or correct the submitted papers. The material as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute’ opinion, nor that of its Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Oil & Gas Expo and Conference 2008 Proceedings.

Abstract

As oil accumulations in easily accessible locations around the world become less available developments in deeper water become a more common target for field development. Deepwater projects, particularly subsea development, present a host of challenges in terms of flow assurance and integrity. In this paper the focus will be on the chemical control of flow assurance challenges in hydrate control, scale control and wax/asphaltene control within deepwater (>750 meter) developments. The opportunities for kinetic hydrate control vs. conventional thermodynamic hydrate control will be outlined with examples of where these technologies have been applied and the limitations that still exist. The development of scale control chemical formulations specifically for subsea application and the challenges of monitoring such control programs will be highlighted with developments in real time and near real time monitoring. Organic deposit control (wax/asphaltene) will focus on the development of new chemicals that have higher activity but lower viscosity than currently used chemicals hence allowing deployment at colder temperatures and over longer distances.

The factors that need to be taken into account when selecting chemicals for deepwater application will be highlighted. Fluid viscosity, impact of hydrostatic head on injectivity, product stability at low temperature and interaction with other production chemicals will be reviewed as they pertain to effective flow assurance.

This paper brings learning from other deepwater basins with examples from the Gulf of Mexico, West Africa and Brazil, which will be used to highlight these challenges and some of the solutions currently available along with the technology gaps that exist.

1. Introduction

1.1 Flow Assurance in Subsea Facilities - the Challenges and the PrizeThe development of subsea facilities to improve the economics of marginal oilfield developments has focused

attention on the need to develop single and combination production chemicals that can function in subsea environments, Figure 1. The recent development of long (>20km) subsea tiebacks in the North Sea, Gulf of Mexico, Brazil and West Africa has focused attention on long-term product stability at seabed temperatures and the associated product specification required for this kind of service. The deepwater developments of Gulf of Mexico, Brazil and Angola with water depth of >750 meter have brought new challenges of fluid viscosity and hydrostatic pressure to be considered in the Capex phase of such projects where both continual injection and batch applications of chemical will be applied.

The following sections outline some of the technical challenges and current methods that can be utilized to eliminate or at least reduce the risk to flow assurance (in scale control, hydrate and wax inhibition) by using such chemicals and the technical considerations to be taken into account during the selection program.

Rio Oil & Gas Expo and Conference 2008

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2. Technical issues

Figure 1 shows the principle factors that have an impact on the selection of suitable scale, wax and hydrate inhibitors for a subsea application. The most effective way to evaluate the impact of these factors is to discuss each in terms of site-specific examples where these factors have been critical to product selection for applications within the North Sea, Gulf of Mexico, Brazil and West Africa.

3. Inorganic Scale Control

Specific factors affect the type, amount and location of inorganic scale deposition. The principle factors include the brine composition within the produced fluids and the pressure/temperature environment as a field matures.

3.1 Brine ChemistryThree water sources currently dominate the oilfield environment - natural depletion resulting in formation

water production, injection of seawater and aquifer water. In the past few years desulphated (sulphate-reduced) seawater has become increasingly important and produced water reinjection is receiving more focus as environmental issues become of more importance for reservoir support rather than disposal. Scale prediction programs can be used to predict the types, likelihood, and amount of mineral scales that can form. The key to managing scale control is to understand how the brine chemistry changes over the life cycle of the field for each individual well together with the ability to place scale control measures upstream of the point were scale formation is predicted to occur (Jordan et al., 2001). A number of publications in recent years have focused on the need to model reactions within the reservoir (Jordan and Mackay 2005) and to determine the impact of the resulting scaling ions being removed from the produced water. Along with the impact of reservoir stripping of ions, it is important to consider the impact of specific ions and the changing ion ratios.

3.2 Inorganic Scale/Fluid compatibilityFrom the point at which the scale inhibitor leaves the storage tanks following initial first fill until the

decommissioning of the facility, a wide range of fluids will be encountered. Their needs to be extensive fluid compatibility testing to ensure than no physical incompatibility is observed or that more subtle performance impairment is encountered. The fluids that a scale inhibitor for subsea application will encounter include the hydrostatic fluid within the umbilical and capillary injection line when they are first deployed. If any incompatibly exists then a suitable “line flushing” program must to be put in place. Evaluation of inhibitor compatibility with the produced brine is also essential under the appropriate conditions of temperature and over the range of possible brine chemistries to be expected.

3.3 Monoethylene glycol and methanolMethanol compatibility must be tested at seabed and typical flowing wellhead temperature conditions. It is

common for up to 10% methanol to pass through nylon 11 umbilical lines into the production chemical injection lines during transport along the seabed. For this reason, assessment of bulk fluid compatibility is critical. The solubility of the common scale inhibitors with thermodynamic -type hydrate control chemicals (methanol and MEG) has a significant impact on the scale inhibitor chemicals’ ability to function as an inhibitor. Solubility of scale inhibitor is generally poorest in methanol where it is believed that the scale inhibitor will form a precipitate with a cation such as calcium in high concentrations of methanol (Tomson et al., 2004). The phosphonate bis-hexamethylenetriamine penta (methylene phosphonic acid) (BHPMP) exhibits better solubility than DTPMP and this chemical’s performance within a methanol rich solution will be outlined in the field example below. Table 1 shows the brine chemistry from a gas condensate field, Field A. Into this brine methanol was applied such that the final ratio of brine to methanol was 60:40 for hydrate control. Figure 2 shows the performance of a sulphonated co-polymer and BHPMP when evaluated via dynamic tube blocking at 120C.

3.4 Inorganic Scale Inhibitor/Corrosion InhibitorA fluid compatibility test should be carried out if scale inhibitor and corrosion inhibitor are to mix at a subsea

wellhead. Even if the chemical passes such a test it is essential to assess the impact on performance. Care must be taken to ensure that when production chemicals mix within the produced water that the scale inhibitor does not interfere with the corrosion inhibitor and vice versa (Jordan et al., 2005)

3.5 Inorganic Scale Inhibitor/Suspended solids


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During the production life cycle, solids will be produced together with oil and water. These solids include produced reservoir fines (from sandstone reservoirs these are principally silicates and clay minerals, and from limestone and chalk reservoirs these are principally carbonate minerals). Other solids such as asphaltenes, scale and products of corrosion may also be present in the produced fluids. Suspended solids can have a significant impact on scale inhibitor performance as they provide a surface for chemical adsorption thus reducing the amount of available scale inhibitor to control scale formation (Jordan et al., 1997).

4. Organic Scale Control

Organic scales such as wax, asphaltene and to a lesser extent naphthenates make up the principle organic scales that present flow assurance issues in deepwater developments.

4.1 Waxes or ParaffinsThe key problems caused by wax that concern deepwater operators are:

Deposition. Wax deposits restrict flow and reduce throughput onshore as well as offshore, of course. The differences offshore are the increased remediation costs and the increased dollar impact of flow restrictions in offshore production, where wells typically have higher production rates than onshore wells.Viscosity. Offshore operations in deeper water encounter cold temperatures, especially in the case of subsea flowlines and tiebacks. The viscosity of paraffinic crude oils below the wax appearance temperature can increase greatly, causing flow problems.Re-start. Temporary shutdowns are a concern in deepwater operations with paraffinic crudes because of the chance that the oil will gel in a subsea flowline or pipeline. As stated earlier, the re-start of a plugged subsea line may be operationally or economically impossible.

4.2 AsphaltenesUnlike paraffins the asphaltene fraction of a crude oil consists of large complex aromatic structures insoluble

in non-polar solvents such as pentane and hexane but which are soluble in aromatic solvents.Asphaltene deposits form by a different mechanism than paraffinic deposits. Three types of equilibrium changes can occur to alter the stability of asphaltene micelles: chemical changes, mechanical changes or electrical action (Al-Maamari and Buckley 2000, Wang and Buckley 2001).

4.3 NaphthenatesWhile waxes and asphaltenes can be regarded as a relatively common flow assurance issue naphthenate

deposits are less common. Control of these deposits initially focused on modification of the fluid pH to maintain dissociated ions rather than allowing salts to form and more recent development have involved pH modification, chelation and demuslification to improve control. (Sorbie et al., 2005).

4.4 Hydrate ControlHydrates can form in production equipment, pipelines, processing facilities and downhole equipment.

Deposits can form on pipe walls and in meters and valves. In systems with gas and condensate or gas and oil they often form as free particles that then agglomerate. Blockages in deepwater pipelines can be extremely costly and plugs can take many days to dissociate or to be removed by thermal/chemical/mechanical means. Often well re-start is a significant risk where fluids are cold such that the fluids either enter the hydrate formation zone or the degree of subcooling increases.

Prevention of hydrates can be undertaken in a number of ways, often in combination (Sloan 2003):(1) Water removal is an ideal option but it not possible in deepwater operations (2) If the temperature is maintained high enough then operation is within the hydrate-free zone. Insulation of lines or

heating using hot fluids or electrical tracing can be used(3) Operating at a sufficiently low pressure (4) Use of thermodynamic hydrate inhibitors (THI) such as methanol or monoethylene glycol (MEG) reduce the

hydrate formation temperature(5) More recently the use of Low Dose Hydrate Inhibitors (LDHI) has proved successful.

LDHIs consist of two different classes. Kinetic Hydrate Inhibitors (KHI) interfere with the kinetics of hydrate formation. These chemicals, often polymeric, bond with the hydrate cage and slow crystal growth such that the induction time exceeds the residence time of free water in the line. Anti-Agglomerants (AA) allow hydrates to form but only as a slush like, non-adherent transportable material within the hydrocarbon phase. These can provide protection at lower subcoolings than for KHIs (Sloan, 2003 and Mehta et al., 2002).


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4.5 Material compatibilityAs subsea completions become more complex and the range of materials used for seals and umbilical

becomes wider, it is critical to assess the compatibility of single and combination products (scale, wax, asphaltene, hydrate control) against all the materials present within the topside storage tanks, pumps, umbilicals, chemical distribution valves, wellheads, flowlines and the topside process.

5. System Conditions

The development of subsea fields with long tie backs to existing platforms and the development of new deepwater facilities with subsea infrastructure present challenging flow assurance issues, not least the impact of temperature on fluid properties. The flow lines can range from 5 km to over 80 km long with limited or no insulation which can result in significant changes in fluid temperature and long residence times for fluids within the flowline. The impact of changes in pressure along these flow lines is similar to current operations - the principle challenge of subsea operation is temperature decline and long residence time which impact inorganic, organic and hydrate control.

5.1 Cooling time and residence timeIn terms of the impact that such changes in fluid temperature can have on scale control, an example of a

North Sea formation water (Field B, Table 2) mixing with injection seawater at the range of temperatures it will encounter as it flows back to the process some 15 km away. It is well know that the mass of barium sulphate scale is not significantly affected by fluid cooling an increase in supersaturation is expected. Publications in recent years have outlined the challenges of scale control within low temperature brines with a sulphate scale risk (Sorbie and Laing 2004) with the suggestion that polymers such as Vs-Co and poly vinyl sulphonate (PVS) offer the best performance when compared to phosphonates such as DTPMP and polymers such as phosphino-poly-carboxylic acid (PPCA). To evaluate the required concentration of scale inhibitor within the production system from wellhead/manifold conditions at 75C to arrival at 40C standard static bottle tests form part of the testing programme (Jordan et al., 1996). The test programme for this study has been published previously (Jordan et al., 2005).

Prior to mixing, the test brines were equilibrated at the respective temperatures. Sub-samples were taken from the test brine mixtures after 2 hours which was the estimated transport time for fluids leaving the wellhead/manifold and arriving at the process facility (Figure 3). It is clear that the vinyl sulphonate shows very acceptable levels of performance at 25ppm but the phosphate ester was unable to control scale even at 500 ppm. This finding is in accordance with the published work on scale inhibitor performance at lower temperatures (Sorbie and Laing 2004). The remaining question is whether or not this type of evaluation is an accurate reflection of the actual production environment. The fluids during production cool from 75C to 40C over a 2-hour period therefore a more accurate evaluation process is to mix the brine at 75C and cool the resulting mixture to 40C over a 2-hour period. Static bottle test results carried out in this way with the same formation water: seawater mixture is presented in Figure 4. It is clear that the slow cooling from 75C to 40C has resulted in the phosphate ester showing a significant improvement in barium sulphate inhibition efficiency performance with similar result as the vinyl sulphonate co-polymer with 5-10ppm chemical required for control.

5.2 Impact of cooling and residence time on hydrate controlLow temperature and high pressure favors hydrate formation & hence deepwater production can present a

severe challenge. Computer programs can be used to predict the severity of the challenge and with that knowledge a strategy for dealing with the issue developed at the CAPEX stage. In a conventional ‘ideal’ approach insulated lines (or potentially heated lines) would be used in combination with THI.

Appropriate lab tests can be used to determine the performance of LDHIs by simulating the field conditions, fluids and gases and residence time.

6. Physical Properties

Products intended for use in umbilicals need to have a range of physical properties measured to ensure they meet specification in terms of specific gravity, pour point, viscosity, vapour pressure, activity, particle size, solvent type and hydrate stability. Each of these measured properties is important and the purpose for each will be outlined.


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6.1 Specific GravityThis is a very basic measurement but is essential to assess the weight of filled tanks on a vessel and for

pumping calculation. Specific gravity is becoming more of an issue in deep water development where flowlines may descend over 1,000 meters to the seabed. A column of fluid of this height has a very significant impact on the ability to control pumping, both in terms of the viscous pressure drop and the impact of the hydrostatic head on the ability to accurately control flow injection rates (Wylde et al., 2005).

6.2 Pour PointThe pour point is a measure of the temperature at which a product will freeze or become unpumpable. This

value is important for subsea applications where topside pumps and tanks may be exposed to very low temperatures as in the Northern North Sea Basin.

6.3 Viscosity and ActivityThe viscosity of formulations for subsea and umbilical applications is linked to the generic chemical type

used, its concentration (activity), and the solvent type employed. In an ideal case, the activity of a product would be suitable to cover the cover the range of produced water rates and chemical injection rates possible from the pumping system, but in many cases for subsea applications, the pump injection rate may be influenced more by the viscosity and specific gravity of the fluids that can be applied (i.e. the maximum pumping pressure that the dosing pump can achieve). These are illustrated in Figure 5 where the overall pumping pressure in a chemical injection umbilical is plotted as a function of umbilical depth and viscosity for different injection line diameters (for wellhead pressure of 5,000 psi). These data suggest that for viscous, concentrated, chemicals, large bore injection lines will be required to deploy such products in deepwater (currently chemical injection pumps are limited to a maximum of 15,000 psi injection pressure).

Inorganic Scale ControlFigure 6 shows the range of viscosity for a phosphate ester cooled to –10C. It is clear that viscosity changes

with activity are not simply proportional to the activity of the product and care must be taken in obtaining the ideal combination of activity (more active chemical takes up less tank volume) and viscosity (more active chemical makes it more difficult to deploy within long seabed umbilicals).

Organic Scale ControlFigure 7 shows the viscosity profile of a new polymer with different backbone shape vs. the conventional

straight chain polymer (Linerman and Allenson 2005). It is clear that activities of up to 20% are possible where with the straight chain chemical 1-4 % active was the upper activity limit. The results has been a saving in Capex with smaller size of chemical storage tanks on the process, smaller pumps used to deploy chemical and reduced Opex cost via saving in logistics.

6.4 Vapour PressureThis is a measure of the volatility of a product, required to calculate the hazard classification of the chemicals

in storage on an offshore installation. For scale inhibitor, the type of solvent used will impact the vapour pressure only if the solvent used to formulate the product with methanol will the vapour pressure be an issue. For wax and asphaltene control this is more critical as the solvents are generally more volatile.

6.5 Suspended Solids within ChemicalsThe suspended solids loading within manufactured chemicals can be set to a standard similar to that used for

aviation industry hydraulic fluids (specification NAS 1638 level 6) so eliminating the risk of solids clogging distribution valves. The long residence time experienced by combination or single component chemicals at seabed temperatures (North Sea 4-5C) can result in the generation of small amounts of suspended solids even in chemicals filtered to NAS specifications prior to deployment. Such solids could block filters or distribution valves where tolerances can be as small as 750um. To assess the risk of this, low temperature dynamic umbilical flow loop tests can be run whereby the production chemicals are flowed through a 350 meter long section of umbilical material (with an inline filter and valves) for extended periods at the application temperature to assess any risk of blockage.

6.6 Solvents and Gas Hydrate Formation within ChemicalsMost conventional scale inhibitor chemical formulations used for topside applications rely on water as the

principle solvent. Cases have been reported in the North Sea where such chemicals used for subsea application have failed in service and resulted in plugging of the chemical delivery lines. In these cases the root causes has been


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identified as production gas bleeding up subsea injection lines, owing to the malfunctioning of non-return values. The result is the formation of a hydrate plug within the umbilical injection line. To overcome this problem, chemical inhibition of hydrates is typically implemented with thermodynamic inhibitors, such as methanol and monoethylene or triethylene glycol.

In a specific case, a Vs-Co based product was identified as offering the best protection for an operator. However the product used only water as solvent and modelling predicted that gas hydrates would form if gas bleeding into the subsea injection line were to occur. This was confirmed by autoclave testing at 2C with 190 bar pressure using a synthetic gas representative of the field.

The impact of solvent type on scale inhibitor performance also needs to be assessed. To overcome the hydrate risk, a vinyl sulphonate co-polymer was formulated with MEG.

7. Monitoring

7.1 Scale Inhibitor Quality ControlThe basic monitoring required for any subsea scale inhibitor is to ensure the product meets it’s agreed

specification during manufacture. Product specifications are agreed with the customer such that a product specification sheet in terms of a set of physical properties is prepared. These will include product colour/appearance, specific gravity, solution pH, particle size and concentration. A Fourier Transform Infrared (FTIR) ‘fingerprint’ is also generated for the chemical to confirm the active concentration is in agreement with manufacturing specification. A final check can also be carried out to ensure that the product inhibition performance is in agreement with the laboratory generated samples or trial samples.

7.2 Performance MonitoringA knowledge of the performance of the inhibitor in laboratory tests has historically been used to determine

whether or not a particular system is protected. This requires confidence in the correlation between laboratory results and field application. If the amount of scale inhibitor present is above the laboratory established minimum inhibitor concentration then the system is considered protected.

In the case of inorganic scales as water chemistry changes - perhaps associated with increased production of waterflood injection water – such tests need to be repeated to ensure their relevance to current field conditions

7.3 Chemical ConsumptionChemical consumption can be tracked from changes in chemical tank levels and oil or water cuts on each

well or flowline if flow meters are installed. Alternatively, attributed water/oil rates from well tests can be utilized. The estimated treatment levels of the inhibitor chemical can be confirmed via chemical residuals for scale inhibitor and asphaltene dispersancy tests (ADT) for asphaltenes or fluid viscosity properties for paraffin control but these measurements are retrospective in terms of treatment rates and assume deposition control is being achieved by linking the chemical levels and laboratory derived treatment rate values. Care must be taken to ensure that the continual injection scale inhibitor can be detected in the presence of other production chemicals.

7.4 Physical changesChanging insulation properties of downhole pressure and temperature sensors can be used to give an

indication as to the degree of deposition control within production tubing. A measurement in the change in heat conduction gives an effective measurement of the build up of deposits but may require a significant deposit to accumulate to produce measurable temperature decline. This challenge of allowing damage to occur before you can conclude that the program is not effective is also present when using changes in downhole or flowline pressure to assess scale control.

Recently a near real-time procedure has been introduced to determine the inorganic scaling potential of brines. This method uses a Thickness Shear Mode Resonator (TSMR) to allow direct measurement of the scaling potential of a brine. This device uses a piezoelectric wafer, with metal electrodes on either side

The technique offers the advantage of on-site measurement with rapid generation of results. The response of the equipment is independent of the nature of any scale inhibitor present. Many field applications of the technology (Feasey et al., 2000, Jordan et al 2003) have been carried out which attest the value of this technology.

For hydrate monitoring Sloan provides a review of monitoring methods (Sloan 2003). If a pipeline is pigged then the pig returns can provide information about the deposits, including hydrates. It is difficult to get advance notice of hydrate formation within wells and a blockage and consequent pressure drop may be the first indication.

Subsea pipeline detection includes techniques such as:


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(1) Fluid composition change and rate change(2) Pigging returns(3) Pressure drop increase(4) Acoustic detection

7.5 Suspended Solids AssessmentThe measurement of suspended solids is a common practice to determine injection water quality but the

measurement of the type, amount, texture and composition of solids within produced fluids via environmental scanning electron microscopy (ESEM) combined with energy dispersive x-ray analysis (EDX) has not, until now, been used as a routine method to monitor the effectiveness of scale control programs applied downhole, topside and for produced water reinjection. The collection/filtration of small quantities of produced water that are subsequently analysed for the texture and composition of sulphate/carbonate solids has been used in a number of fields within the North Sea, Gulf of Mexico, Offshore Brazil and West Africa as a direct method of scale inhibitor performance (Jordan et al., 2005).

8. Injection/Sampling

8.1 Deepwater Challenges Continual InjectionThe pumping of small volumes of chemicals over long distances along chemical injection umbilicals to

subsea manifolds requires greater pressures than for shallow water applications leading to potential issues around the ability of chemical injection pumps and their ability to deliver high pressures. For example, an issue has already been identified in BP’s Greater Plutonio development in West Africa where surface pump suction has been identified as a potential problem because of there being an insufficient pressure drop in the injection line (Jordan et al 2005).

Work will be needed to reformulate chemicals, such as dilution of the products to allow greater volumes of chemical to be pumped. Dilution of chemicals will obviously incur larger storage, footprint and weight on the floating production system. Furthermore, more ‘Blue Sky’ options such as subsea chemical storage and injection at the manifold and periodic re-charge from a boat will also need to be investigated.

8.2 Deepwater Challenges - Batch treatments –Scale Squeeze or dissolversThe deployment of scale squeeze or dissolver batch treatments to platform wells is a relatively routine process

in many oilfield basins around the world to control or remove deposits (Boreng et al., 1994, Al-Ashhab et al., 2006). The issuses of chemical deployment for subsea and particularly deepwater subsea wells is the challenge of getting the fluids to be injected to the wellhead and the ability to pump at a suitably high rate to allow effective placement (Mackay et al., 2004).

Examples of subsea sea deployment of scale inhibitors via dedicated service lines conceived in the Capex phase of the project have allowed effective chemical treatments (dissolver and squeeze treatments) in a number of subsea fields. The Strathspey field (UK sector, North Sea) tied back 17 km to the Ninian Central platform utilised a 3 ¾ inch service line for deployment of scale squeeze treatments (Jordan et al., 1999) and dissolver treatments (Jordan et al., 2002). The relatively large diameter of the line permitted injection rates of up to 5BPM to be achieved. The presence of this service line has reduce the opex cost of scale squeeze treatment to the field as it matured and water cuts rose (Mackay et al., 2004, Jordan et al., 1999).

The cost associated with inclusion of service lines has been taken into account in a number of scale management evaluation studies (Graham and Collins 2004) specifically in deepwater applications and this information has been used to assess the cost of scale management options in some cases leading to the introduction of desulphated seawater injection rather then injection of seawater to facilitate management of the scale risks (Graham and Collins 2004).

In some deepwater fields were scale squeezes have been deployed to subsea wells supply vessel (with temporary pumping skid on the deck) or stimulation vessels have been utilised to allow pumping of treatments via the test lines to production wellheads (Bogaert et al., 2006, Bogaert et al., 2007). In this example the test line replaces the need for a dedicated service line and as such the test line must be able to be cleaned prior to the scale squeeze deployment.

8.3 Location of Injection PointsFor continual treatment chemical injection points must be located as far upstream in the process as possible

and in an ideal environment this would be upstream of the onset of the organic/inorganic scaling and hydrate conditions. Currently, chemical injection is limited to the production packer. Scale inhibitor injection to the


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perforations has been attempted, but the problems with controlling the dosing rate arising from local pressure variations causing line slugging limited the success of this ‘experiment’ (Wylde et al., 2005).

8.4 Pump Size and MeteringIt is critical to size pumps to cope with the range of chemical treatment rates required as scaling tendency

within the produced fluid changes along with water cut. The ability to be able to accurately meter the chemical flow, and dosage, into each well is also visual as poorly regulated distribution systems can result in poor accuracy leading to under treatment in some wells and over treatment in others.

During a scale squeeze there is a risk that during the shut-in period the fluid temperature will drop such that the fluids will be within the hydrate forming region. To avoid this THI (e.g. methanol) can be injected down the subsea line to the wellhead. Potentially a KHI blended with the scale inhibitor provides an alternative approach (Hills et al., 2006).

9. Conclusions

1) There are significant challenges, both chemical and physical, associated with the selection, application, and monitoring of organic/inorganic scale and hydrate inhibitor formulations suitable for subsea application.

2) Fluid temperature reduction during transport along extended tie-backs presents challenges to scale control owing to the reduced temperature and the possible addition of thermodynamic hydrate control chemicals. These result in changes in scale mineral supersaturation (increased), kinetics of inhibition (reduced), and chemical compatibility (reduced).

3) It has been found that the rate of fluid cooling has a significant impact on the scale inhibitor performance; as a result, modified inhibitor evaluation methods are required to truly represent the field conditions and to select the most suitable chemical for that application.

4) The solubility of scale inhibitors within methanol, MEG, and TEG is lower than in water, which has a significant impact on the chemicals ability to control scale formation.

5) The presence of other production chemicals may interfere with scale inhibitor performance (therefore appropriate performance testing in the presence of such chemicals is essential).

6) Both organic and inorganic scale inhibitor viscosity control is critical in order to allow the chemical to be injected along long flow lines at seabed temperature or down long umbilicals to deepwater wells.

7) The use of kinetic hydrate inhibitors and anti-agglomerate chemistry for hydrate control can reduce the negative impact on inorganic scale inhibitor performance observed by some thermodynamic-type chemicals, in particular methanol.

8) While THIs are established chemicals for hydrate control LDHI’s can offer substantial Capex savings where their use is appropriate.

9) Modification of the molecular structure of paraffin inhibitors has allowed more effective chemicals to be developed that can be applied as higher active formations resulting in Capex saving due to smaller chemical tanks and pumps along with Opex saving due to improved logistics based on more active formulations

10) For some subsea deepwater developments, the technical limit of continual chemical injection is being reached with pump pressures and injection line sizes requirements exceeding those available or practically possible.

11) The ability to effectively deploy and monitor batch treatment chemical via dedicated service lines or lest lines is a critical step in the Capex phase of field development.

12) Effective monitoring is required at manufacture of subsea specific chemicals and of their performance across the production system.

10. Figures


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Figure 1. Physical/Chemical Properties of Prodcution Chemicals for Subsea Application


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Blank 250ppm Methanol compatible polymer

35ppm Low Mol wt Phosphonate 25ppm Low Mol wt Phosphonate

Figure 2. Dynamic tube blocking results to assess the minimum inhibitor concentration within a 60% brine,40% methanol synthetic produced fluids mixture with

380 ppm Fe, 1,000 ppm Bicarbonate, 120C

2 5 10 25 50 100 250 500

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Formation Water:SeawaterResults as soon as temperature of oven reached 40oC (105 min since mixing)

VS-CoEster

Figure 4. MIC determination of 50:50 FW:SW, slow cool to 40C

Viscosity of Phosphate ester scale inhibitor at range of activities, diluted with water, cooling range 35C to -10C

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Figure 6. Viscosity profiles for three activities of phosphate ester (diluted with water) as the solutions

are cooled from 35C to –10C.

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EsterVS-Co

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Figure 3. MIC determination of 50:50 FW:SW, 40C

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Figure 5. Pumping pressure profiles for a 5cP fluid deployed at 5000 ppm active over varying water

depths as a function of the injection line diameter

Comparison of NewActive ModifiedPolymervs. Conventional Paraffin Inhihibitor

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New Active - 10%

Figure 7. Comparison of modified backbone paraffin inhibitors (new active) vs. the convention linear

backbone polymer to show the improved chemical viscosity at subsea application temperature (+5 to –5C)


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11. Tables

Table 1. Produced brine chemistry of Field “A” within the North Sea where carbonate scale formation

was determined to be a risk due to fluid production with 40% methanol present.

Table 2. Produced brine chemistry of Field “B” within the North Sea where sulphate scale formation was

determined to be a risk due to fluid mixing and fluid cooling.

12. Acknowledgements

The authors would like to thank Nalco for permission to publish this paper. We also acknowledge the help and co-operation of members of the asset teams and the Nalco Scale Team (Clare Johnston, Morag Elrick and David Marlow) in Aberdeen for carrying out the evaluations and treatments described in this paper.

13. References

JORDAN, M.M, SJURAETHER, K, COLLINS, I.R, FEASEY, N.D. AND EMMONS, D., “ Life cycle Management of Scale Control within Subsea Fields and its impact on Flow Assurance, Gulf of Mexico and the North Sea Basin. SPE 71557, presented at 2001 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September – 3 October 2001.

JORDAN, M.M, MACKAY, E.J., “Integrated Field Development for Effective Scale control throughout the Water cycle in Deep Water Subsea Fields” SPE 94052, presented at 14th Europec Biennial Conference, Madrid, 13-16 June 2005.

TOMSON, M.B, KAN, A.T AND FU, G., “Inhibition of Barite Scale In the Presence of Hydrate Inhibitor” SPE 87437. Presented at SPE 6th International Symposium on Oilfield Scale, 26-27th May 2004, Aberdeen, UK.

JORDAN, M.M, ARCHIBALD, I, DONALDSON, L, STEVENS, K AND KEMP, S., “Deployment, Monitoring and Optimisation of a Combined Scale/Corrosion Inhibitor within a Subsea Facility in the North Sea Basin” SPE 80214, presented at SPE International Symposium on Oilfield Chemistry, Houston, 5-7 February 2003.

JORDAN, M.M., SORBIE, K.S., MARULIER, M. TAYLOR, K, HOURSTON, K AND GRIFFIN, P., “Implication of Produced Water Chemistry and Formation Mineralogy of Inhibitor Adsorption/Desportion in ReservoirSandstone and Their Importance in the Correct Selection of Scale Squeeze Chemicals”, presented at 6th

International Symposium Chemistry in the Oil Industry. 14-17 April, 1997.LINDERMAN, O.E AND ALLENSON, S.J.: “Theoretical modelling of Tertiary Structure of Paraffin Inhibitors” SPE

93090, Presented at SPE International symposium on Oilfield Chemistry, Houston, Texas, USA. 2nd-4th February 2005.


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AL-MAAMARI, R.S.H AND BUCKLEY, J.S.: “Asphaltene Precipitation and Alteration of Wetting :Can Wettablity Change During Oil Production?” SPE 59292 presented at SPE/DOE IOR Symposium, Tulsa, 3rd to 5th April 2000.

WANG, J.X AND BUCKLEY, J.S: “An Environmental Approach to Prediction of Asphaltene Flocculation” SPE 64994, presented at the SPE Oilfield Chemistry symposium, Houston, 13th to 16th February 2001.

SORBIE, K.S., SHEPHERD, A., SMITH, P.C., TURNER, M. AND WESTACOTT, R.E., “Napthenate Formation In Oil Production: General Theories And Field Observations”, presented at Chemistry in the Oil Industry IX, Manchester, 31/10 – 02/11 2005.

SLOAN, E.D., Hydrate Engineering, SPE Monograph Volume 21MEHTA, A.P., HEBERT, P.B., CADENA, E.R. AND WEATHERMAN, J.P., “Fulfilling the Promise of Low Dose

Hydrate Inhibitors: Journey from Academic Curiosity to Successful Filed Implementation”, presented at 2002 Offshore Technology Conference, Houston, 6-9/05 2002.

SORBIE., K.S AND LAING, N., “How Scale Inhibitors Work: Mechanisms of Selected Barium Sulphate Scale Inhibitors Across a Wide Temperature Range”. SPE 97470, presented at 6th International Symposium on Oilfield Scale, 26-27 May 2004, Aberdeen, UK.

JORDAN, M.M, SORBIE, K.S, GRAHAM, G.M., TAYLOR, K. AND HENNESSEY, S., “The Correct Selection and Application Methods for Adsorption and Precipitation Scale Inhibitors for Squeeze Treatments in the North Sea Oilfields”, SPE 31125, presented at SPE Formation Damage Control Symposium, Lafayette, L.A, 14-15 February 1996.

WYLDE, J.J, WILLIAMS, G.D. M, CAREIL, F, WEBB, P AND MORRIS, A., “ Deep Downhole Chemical Injection of BP-Operated Miller: Experience and Learning” SPE 92832, presented at SPE International Symposium on Oilfield Chemistry, Houston, 2-4 February 2005.

JORDAN, M.M., COLLINS, I.R. FEASEY, N.D AND JOHNSTON, C. “Scale Inhibitor Selection and application:-The Subsea Challenge” Presented at Chemistry in the Oil Industry IX, Manchester Conference Centre, UK, 31st

October to 2nd November 2005.FEASEY, N. D., WINTLE, R J., FRIETER, E. R. AND JORDAN, M. M., “Field Experience with a Novel Near Real-

time Monitor For Scale Deposition in Oilfield System, NACE 2000, Orlando Florida, March 2000.JORDAN, M.M., BUCKMAN, J. AND JOHNSTON, C.J., “Direct Monitoring of the Performance of Scale Control

Programs Across the Produced Water Life Cycle Via Suspended Solids”, SPE 93892, presented at European Formation Damage Conference, Scheveningen, 25-27 May 2005.

BØRENG, R., SORBIE, K.S. AND YUAN, M.D.: “The Underlying Theory and Modelling of Scale Inhibitor Squeezes in Three Offshore Wells on the Norwegian Continental Shelf,” presented at the 1994 NIF International Oil Field Chemicals Symposium, Geilo, Norway, Mar. 20-23.

AL-ASHHAB, J.K, PETRONE, D AND KOKHTAR, S.R.: “Managing Well Integrity, and Production Decline Caused by Scale” SPE 97863, presented at SPE International symposium and Exhibition on Formation Damage Control, Lafayette, LA, 15th – 17th February 2006.

MACKAY, E.J., JORDAN, M.M., FEASEY, N., SHAH, D., KUMAR, P. AND ALI, S.: “Integrated Risk Analysis for Scale Management in Deepwater Developments” paper SPE 87459, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, 26-27 May 2004.

JORDAN, M. M., EGDERTON, M., AND MACKAY, E.J.: “ Application of computer Simulation Techniques and solid Divertor to improve Inhibitor Squeeze treatments in horizontal Wells”, SPE 50713, presented at SPE International Symposium on Oilfield Chemistry, Houston, 16-19 February 1999.

GRAHAM, G.M. AND COLLINS, I.R.: “Assessing Scale Risks and Uncertainties for Subsea and Marginal Developments” paper SPE 87460, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, 26-27 May 2004.

BOGAERT, P. BERREDO, M.C, TOSCHI, C, BRYSON, B., JORDAN, M.M, FRIGO, D.M AND AFONSO, M.: “Managing Formation Damage Risk from Scale –Inhibitor Squeeze Treatments in Deepwater, Subsea Fields in the Campos Basin”, paper SPE 107633, presented at SPE European Formation Damage Conference, 30th June to 1st July 2007, Scheveninen, The Netherlands.

HILLS, E., TURNER, K., BRICE, S. AND ROSS, A., “Hydrate-Inhibited Scale Inhibitor for Use on Subsea Templates”, SPE 100472, presented at SPE Symposium on Oilfield Scale, Aberdeen, 31/05 – 01/06 2006.

ibp1669 08 meeting the flow assurance challenges of

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