IADC/SPE 167990

Advancing Deepwater Kick Detection Austin Johnson, Christian Leuchtenberg, Scott Petrie, & David Cunningham, Managed Pressure Operations

Copyright 2014, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 46 March 2014. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.

Abstract

Numerous developments in automation have made the modern mobile offshore drilling unit a marvel of engineering achievement and a model of efficiency. Yet, even with the surge in advancements, kick detection, which can be comparatively elementary for a fixed drilling unit, has proven significantly more difficult to master on a vessel which subject to wave motion and currents. A lack of consensus on universal standards and regulations have left kick detection largely ignored. But further, the lack of innovation has been coupled with drilling in greater water depths which are subject to the use of longer risers with greater volume and weight. Thus, in addition to the complications of dynamic environments are the material requirements to properly intervene during an influx event. Operators and shipyards have kept pace with these material issues by designing larger, smarter vessels with greater capacities and better controls systems to cope with the complexities of drilling in deepwater environments. Despite the best efforts and ballooning costs, influx events continue to occur because an operating envelope and a universal philosophy for deepwater kick detection have yet to be established.

With the primary driver for deepwater and ultra-deepwater drilling being to access the most productive formations possible, a recipe is formed such that a slight variation between formation pressure and fluid pressure has the potential to draw a significant hydrocarbon volume into the well bore. When well control procedures are initiated, a series of checks take place which, though proven and reliable for detecting kicks, consume valuable response time and potentially aggravate the initial problem. After an influx has been confirmed, remedial work often takes days and sometimes weeks to recondition the well for drilling. Whether in terms of personnel, equipment, facility, environment, or finance, the risk presented to the drilling operation by influx and loss events is substantial. Therefore, an advanced approach should be adopted which views kick/loss detection as a safety critical measurement and incorporates a modern, control system based design philosophy with established methods to overcome shortcomings. This paper will describe experiences, challenges, and approaches to solving the problems related to creating an advanced early kick detection system suitable for floating mobile offshore drilling units. Necessary components, operational considerations, and design limitations will be discussed. Additionally, a discussion will offered on the current state of regulatory requirements related to kick detection and considerations for future standards. Introduction Innovation is often driven by necessity, and deepwater drilling has proven a highly innovative craft. Advanced drilling and completion techniques have opened up fields which were thought uneconomical if not altogether impossible just a few short years ago. In order to make viable deepwater drilling units, numerous technologies have had to be developed and adapted, much of which were just to overcome wave motion and currents. Dynamic positioning has unchained the operation from the sea floor allowing rigs to mobilize easier and increasing operating water depth. Better meters, automation, and integration of drilling systems have made rigs more efficient and safer while also increasing accuracy and redundancy. Indeed, the propagation of the digital age on to the drilling unit has expanded rig capabilities and has done so in a relatively short period of time. One by one, limitations have been identified and solutions have been implemented. While the onset of new technology has brought with it many new capabilities, many old concepts have been implemented alongside the new. Operators and contractors alike feel the pressure to get more rigs to work in deepwater. Operators must secure leases, add reserves, and develop their fields. Drilling contractors then must secure a slot to build a

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hull and oversee construction. Increasingly, shipyards have assumed much of the responsibility for design and outfitting of the entire vessel. With so much emphasis being put simply on getting a hull onto its day-rate, the finished product is essentially a Mobile Offshore Drilling Unit (MODU) which has been slightly improved from the last hull - potentially with a few modifications to accommodate the requirements of the operator or contractor. But largely, step changes have been defined by operating depth of the rig while other performance indicators have been neglected (Hope et al. 2012). This has meant in practice that the waves of enhancements have carried some rig systems forward while mostly washing over others such as kick detection with which this paper is concerned. One critical rig system which has been largely overlooked is the drilling fluid processing system. It is one objective of this paper to draw attention to the way this system has been advancing while simultaneously remaining comparatively neglected.

It is important to note that the scope of this paper is limited to the current state of kick detection and not Managed Pressure Drilling (MPD) as a whole, but it would be difficult to discuss one in complete isolation to the other; the two are so intertwined that it would be difficult to properly account for all variables without discussing the effect MPD has had on drilling technology. Ultimately, it is likely that the industry will see the kick detection system and the MPD system integrated into one package. Since this has mostly not yet materialized, the two subjects will be discussed separately. For the sake of an orderly discussion, conventional kick detection will discussed first, then efforts which have made enhanced kick detection (EKD) possible for fixed drilling units. Then the requirements for accurate deepwater kick detection (DKD) will be laid out. Though many concepts carry over from EKD to DKD, the advanced kick detection for floating vessels presents some non-trivial challenges and potential for better measurement that are not present even on the most advanced of fixed drilling units.

Conventional Kick Detection Kick detection is rooted in very simple and practical principles. Simple though they are, it is necessary to begin with definitions. Fundamentally, influx of hydrocarbons into the wellbore occur when an underbalanced condition occurs where rock is both permeable and hydrocarbon bearing. Multiple causes exist, such as insufficient equivalent circulating density (ECD), swabbing, and higher than expected formation pressures, etc., which can trigger the migration of the hydrocarbon fluid from the formation into the wellbore. Conversely, losses occur where an overbalanced condition is forced on rock which is permeable. Again, multiple causes exist, such excess ECD, surging, depletion, and formation pressures being lower than expected, etc., which trigger the migration of drilling fluids from the wellbore to the formation. This is the definition of a kick or loss in very modest terms.

Dating back to the earliest kick detection practices, kicks have been monitored by comparing the flow in to the return flow. Thus, influx is indicated when return flow is greater than flow in and losses are indicated return flow is less than flow in. Conventionally, the measurement of flow in has been accomplished by counting the pump strokes from the duplex or triplex mud pump. Assuming that a single phase and homogeneous fluid is being used, an efficiency factor may be applied to the stroke volume yielding a reliable and relatively accurate result. On the other hand, return flow has been a more difficult concept to master. A single phase and homogenous fluid is assumed when modeling flow in due to the fact that fluid has been processed to remove the cuttings then agitated in open, atmospheric tanks. However, this is not always the case as density can vary when mixing and pumping new materials. But even the luxuries afforded when modeling flow in are not applicable when considering the returning flow. Drilling fluid in the annulus is the mechanism for removing cuttings from the well as well as the mechanism for maintaining the Bottom Hole Pressure (BHP). The casing pressure is often manipulated in conjunction with the hydrostatic and frictional pressures to control the overall ECD. This means that the return fluid may contain dissolved gas upstream of the drilling choke, and a mixture of dissolved gas and gas bubbles downstream of the drilling choke. A rotating head or other rotating control device may be used to as a means of applying casing pressure but conventionally, casing pressure information is used as a safety limit to protect the casing or formation from overpressure and is not integrated into a kick/loss detection algorithm. When in significant volume, the returning mixture of fluid, cuttings, and gas has been used as a qualitative indicator of flow for well control alarms. Conventional meters, such as radar level/flow sensors and flow paddles can only provide a very crude estimate of the flow rate of the liquid/solid mixture. Thus, to quantitatively estimate the amount of influx into the well using conventional meters, measurement must be performed at the drilling fluid tanks where sensors can indicate the fluid level, giving an approximation of the total system volume through the use of the Pit Volume Totalizer (PVT) system.

The PVT system is the accounting tool of the drilling fluid processing plant and is employed to track the total fluid volume. Fluid system volume has long been the simplest and most reliable way to track and quantify kicks and losses. But several sources of error exist which render this method insufficient for accurately measuring small influx volumes. When a volume of gas is present in the returning fluid, the only indication at the surface initially is a rise in total fluid volume. The gas is removed via a drilling mud gas separator and, in many cases, measurement or description of the gas is performed by mud loggers after the gas has been processed. If the processed gas is metered, the metered volume does not reflect the wellbore volume due to the expansion downstream of the choke so correction factors must be applied. Additionally, different gases attribute differently to the volume in the wellbore and if any of this information is being fed back into the data acquisition system, there often is such a considerable delay that it cannot be used in real time. From the mud gas separator, liquids are sent cuttings removal equipment which consists of a series shakers and centrifuges. While these means are very good at separating the solids from the liquid, it should be noted that not all liquid is separated from the solids, meaning that

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some liquid is lost in the cuttings removal process. After cuttings removal, the fluid is sent to the drilling fluid tanks. Here, sensors are installed to monitor the fluid level height. The shape of the tank is then used to calculate the fluid volume in the tank. Multiple tanks are employed and the total system volume is known to be a summation of the volume of all active tanks, piping, and the wellbore volume, exclusive of drillstring volume. Due to the significant volume of mud in the tanks, the level reading is often not accurate. This can be remedied by reducing the number of active pits, but this only reduces the amount of error instead of addressing the sources of error. Ultimately, the accuracy of the PVT system is subject to how it is maintained and operated and the resolution of the instruments gauging it.

The PVT system may be used for monitoring wells at any time, but it is the primary means while circulating. The industry recognizes that significant potential for error exists in using the full mud system to detect kicks. Thus, a workflow exists for static flow checks which effectively shrinks the active volume to just the trip tank, piping and wellbore exclusive of drillstring. There are benefits to performing static flow checks just as there are drawbacks. With the active tank volume reduced, the measurement becomes more accurate. However, a static flow check may not be performed while drilling. If a kick/loss event is suspected, it is likely that the event has already occurred. While it may still be a sensible exercise to perform a static flow check, this operation has the potential to exacerbate the initial influx as can be seen in Figure 1 below.

Fig 1: Influx Event and Flow Check In this example, it can be seen that pressure is the primary indication of a kick. If accurately measured, return flow can also be used as an indicator. When a kick is suspected, the conventional response is to pick up off bottom, stop rotation, and stop pumps for a static flow check. As seen in the graph above, these actions cause a drop in bottom hole pressure which serves to accelerate the influx into the wellbore. The flow check is then performed. There are two characteristics of the flow check which are disadvantageous to the operation. The first unfavorable characteristic is that the flow check can take several minutes during a critical event; the second is that the kick volume must be increasing to show that the well is flowing. Additionally, other factors can confuse the feedback from well as a result of transitioning from dynamic to static. It should be recognized that the majority of the influx in this example correlates to the actions taken by the rig to determine whether or not an influx event was occurring. Here, it may be prudent to make the distinction between what is meant to be measured and what is actually being measured. Conventional means employ a simple volumetric material balance equation where if flow in equals flow out then the well is balanced, and danger only exists where flow in and out do not match. However, it should be recognized that this approach neglects the effects of temperature, formation breathing, fluid compressibility, and assumes a homogenous

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wellbore. In practice, a kick/loss event is defined by the difference between flow in and return flow exceeding a limit. In reality, the drilling fluid is subject to effects from temperature and pressure just as the wellbore is subject to effects from fluid pressure and formation stress. In addition to the inherent inaccuracy of traditional volumetric kick detection methods, other factors contribute to the attenuation of these indicators such as variable wellbore temperature profiles, synthetic-based fluids, vessel movements, and higher pressure and temperature (Reitsma, 2011). Assuming a single bubble model, all these effects will likely be attributed to a kick or loss event as the one culprit.

Many lessons have been learned from the Macondo blowout. In terms of early warning systems, Macondo demonstrated the shortcomings of a conventional kick detection system. The Deepwater Horizon was not equipped with a robust early warning system and relied heavily on the conventional PVT system for kick warnings. According to accident investigation report on the Macondo blowout, a key contributing factor to the incident was the simultaneous operations of offloading mud while critical well operations were being performed. No evidence was found that the crew was monitoring the pits during the time of the influx. But without the ability to isolate other operations from the well, it is likely that very little information could have been gathered from monitoring the pits. Such reliance on the conventional PVT system coupled with simultaneous PVT operations meant that the rig crew was unable to realize that a serious threat existed (Deepwater Horizon Study Group, 2011).

API Standard 53 does outline requirements for this type of flow detection and unfortunately, it is one of only a few standards which outline requirements for flow detection. The requirements outlined in API 53 related to kick detection can be summarized into three components. There must be a trip tank, a PVT system, and a return line flow sensor. The trip tank is often used for static flow checks and must have a volume and shape such that the small changes in fluid volume may register. The PVT system is used for monitoring while circulating by measuring the total volume of drilling fluid in the tanks as outlined above. Finally, API 53 specifies that a flow rate sensor must be fixed to the return flow line for early detection of gains or losses. While such a sensor is absolutely necessary for early event detection, many methods can be assumed due to the lack of specifics. For many rigs worldwide, this means that a combination of a flow paddle and potentiometer satisfies the specification and thus is the primary means of kick detection.

The effects of kick/loss events would be greatly diminished if the accuracy existed to detect small changes while drilling. In order to achieve this, the philosophy of kick detection must change. Strictly volumetric methods prove reliable most of the time, and as such have worked well enough to not be heavily scrutinized. Only recently and largely due to the risk mitigation and value add proposition of MPD, many operators and drilling contractors have turned toward EKD as a means of enhancing the performance of the MPD system. These improvements in methods and tools are prerequisite to a full DKD system.

Enhanced Kick Detection MPD has surfaced as a natural response to drilling in unconventional or otherwise difficult fields and the need for an EKD system has been established somewhat naturally from the imposed needs of MPD system. MPD is based in the most fundamental principles of drilling; balancing the ECD to formation pressure minimizes influx and stabilizes the wellbore. The MPD system aims to drill a well within a margin of the balanced pressure of the formations being drilled. In order to accomplish this, a rotary head or other annular sealing device is coupled with an active drilling choke which can automatically adjust the casing pressure. Though configuration of the MPD system may vary, the primary feedback mechanism for the MPD system in all cases is the return flow rate. When Bottom Hole Pressure (BHP) is lower than formation pressure, influx of formation fluid occurs.

Closing the system with an annular seal offers many benefits. Primarily, closing the system transforms kick detection from qualitative observations to quantitative observations which can be recorded by instruments in real time and at high bandwidth. The open system is unable to capture slight changes in pressure because the added pressure and volume only serve to accelerate the flow of the drilling fluid from the annulus to the mud processing equipment. But the closed system creates a fixed, known well volume which is a function of the casing and bit diameters and volume occupied by the drill string. With fluid in the wellbore being mostly incompressible, the pressure upstream of the choke and flow rate through the return line become valuable in determining the size and severity of kick. Sealing the wellbore has also led to the use of meters which can accurately measure multiphase flow. The introduction of these type of meters into drilling has truly been a step forward for kick detection. Conventionally, wellbore and fluid characteristics are determined by analyzing trends and catching samples after the fact, whereas a closed-loop system allows a higher level of automation, real time automated analysis, and actionable data for engineers to quickly make decisions, which is important when drilling any well and particularly important in deepwater environments (Pavel & Grayson, 2010). It would be ideal to have multiphase measurement capabilities directly at the formation, however, such tools may be out of reach for many years to come. Yet, by monitoring the return flow from a sealed annulus, a kick alarm may be issued within seconds of the event as opposed waiting for the fluid system volume to cross an alarm threshold. These solutions have undoubtedly reduced the amount time required to trigger an alarm. But there still exists a void in what is done with the feedback from the closed well system. MPD, though based in the simplest drilling principles, is relatively new in practice. Although the industry is working to develop systems which take a holistic approach, very few systems currently offer an automated choke which can properly respond when an influx/loss is detected because how to

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respond is not a trivial question. For example, work has been done to better estimate kick tolerance (Santos et al. 2011) which highlights how the single bubble, homogenous wellbore model fails to take important variables into account. Without all wellbore and fluid effects accounted for, flow and pressure data can only be said to be tightly correlated. This correlation is mostly trustworthy and valuable information can be extracted, but the cause of an event is the most valuable information in mitigation that event. Because of this, it should be seen that the single bubble, homogenous wellbore model which supports conventional kick detection methods can also fall short when enacting a response to a kick as well. To complicate this matter, deepwater presents challenges to kick detection to which fixed offshore installations are not subject, such as wave motion. Additionally, deepwater formations tend be some of the most prolific in the world, often, displaying high productivity which is desirable for production, but risky to drill. In such environments, even a slight drawdown pressure can invite several barrels of fluid into the wellbore in seconds. Conventional kick detection methods practically require that several barrels of fluid enter the wellbore before any alarm is raised. When these events occur, time and caution must be taken to safely mitigate the influx. But enhanced kick detection alone leaves performance to be desired if variables are left unaddressed or if it is not coupled with an appropriate automated response. Thus, due to the uncertainty and severity of these events, conventional kick detection as well as some forms of enhanced kick detection do not meet the requirements to construct a well in such difficult environments.

In order to satisfy the requirement for DKD, kick detection methods must be examined and new tools and instruments incorporated. Fortunately, an advanced robust kick detection system can be constructed from many components that are already available and in many cases, already employed in the downstream sector of the industry. While petrochemical plants are not concerned with formation pressure, not all crude is equal, and plants must be equipped to handle upsets which can occur from introducing new chemicals and crude types into the process. In the same way that downstream prepares for unknowns from reactions, the drilling sector must begin to prepare for unknowns from fluid and formation.

Deepwater Kick Detection The feasibility of a robust DKD system is high due to the onset of advanced digital instrumentation being made available. Reduction of error should be a focus in design, but in order to be considered truly robust, the DKD system must function as a hub of information for those making decisions. Far more than just adding smart meters to conventional PVT systems, the DKD system must account for vessel movement, wellbore effects, changes in rheology and drilling parameters and feed information directly to the MPD system. This may be done in such ways as to be evolutionary and natural as opposed to revolutionary and incoherent with the larger rig design philosophy. Ultimately, DKD should be achieved in such a way as to refine and automate existing drilling data measurements and enhance proven practice with the addition of accurate flow measurement. In the effort to modernize the mud processing system, the conventional PVT system provides a firm foundation upon which to build. In order to detect small a volume influx or loss, reduction of error in the current format is the key. At least two approaches exist; one may reduce error by increasing accuracy of the instrumentation involved, and one may reduce error through discretizing the larger system into more manageable pieces.

Specifically referring to the mud processing system, it has been so historically that the well, the pits, and all processing equipment are grouped together when drilling with a closed loop configuration. This approach is reliable when detecting large volume changes but suffers in small volume change detection due to precision errors. This has been known for some time and dealt with through reducing the number of active pits, thereby reducing the volume of the system. Discretization of the pits has benefitted the PVT system. Even so, a considerable amount of noise is created by virtue of the fact that the drilling fluid in the active system is constantly moving between stations, being mixed and agitated, and subject to vessel motion. To account for noise and avoid false alarms, instrumentation providers allow crews to create a kick detection alarm threshold which could be ten or more barrels greater than the total system volume. This serves well as a reactive alert once the rig has taken an influx. But ultimately, the goal of kick detection is understand whether or not the formation is balanced or taking or losing fluid immediately and to immediately understand the cause. Thus, in the process to discretize the system, the next logical step is to separate information coming from the well from information coming from the mud processing equipment.

In accomplishing the aim of decoupling the well from the mud processing plant, it may be seen that defining boundaries between the well and the processing equipment is advantageous. A suitable boundary on the return side of the system is the flow line just downstream of the diverter. The ideal boundary for defining the inlet to the well would likely be at the top drive. This location could present some difficulties in practice due to high pressure and vibration, so for the purpose of this example, the boundary for the injection side will be the inlets to the mud pumps. To fully define the boundary, a high pressure diverter or a Rotating Control Device (RCD) would be required to be installed to seal the gap between the annulus and the drill pipe above the point the fluid exits the riser. Exactly where these definitions are set vary by configuration, but by defining the well in terms of its injection point, outlet, and sealing the annulus, error from pit volume instrumentation is fully eliminated because it no longer needs to be considered to establish a kick/loss event. At this point, a well volume, which is presumably fixed, is known.

With boundaries and volume set, the next step is to understand the flux across these boundaries. Conventional PVT systems detect influx based on volumetric accounting. Removing the mud processing system removes the noise associated

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with it. This alone increases the reliability of volumetric methods. But volumetric flow rate is not the only lens through which a kick may be spotted. Here, knowledge of the mass flow rate is gainful. Direct measurement at the mud pits allows for some confidence in the type and quality of mud being pumped downhole. It is relatively safe to assume that the mud is homogenous when it has been thoroughly mixed and agitated. However, when changing the rheology of the mud or pumping sweep, etc., it is possible to introduce mud of unknown density into the well without any real account for it. Direct measurement of the return flow at the flow line can be even more difficult due to the presence of cuttings and the likelihood of gas. But, reliable multiphase flow metering has become relatively accessible in recent years and this kind of instrumentation presents opportunity for improvement for the PVT system. Volumetric sampling methods have their place and additional forms welcomed, but understanding of the mass flow of the fluid both on the injection side and on the return side further substantiates data leading to more reliable information.

Hardware and controls improvements to the PVT system will serve to further enhance the base. To install a level sensor in every tank is relatively common practice. To reduce the noise associated with agitation and fluid movement, it would be favorable to incorporate a secondary level sensor in a stilling well. This is especially advantageous in the trip tank. High speed sampling is favorable, and to get the most information from this configuration, a comparison of types of sampling would be used for data verification.

It is important to note that improvements in the accuracy of instrumentation alone will not provide the full DKD solution; process is as important as precision and accuracy, if not more so. One of the root causes identified in the Macondo blowout was that simultaneous operations interfered with the crews ability to recognize the influx. A simple calculation comparing the number of pump strokes to the tank level could have been used to identify the influx. Though tedious work for personnel, such calculations can be easily run in the PVT system. But further than automating measurement and calculation, it should be evident that the DKD system apply plant style processes to the drilling rig in order to assist in performing operations instead of being limited to recording and describing the operation.

Risers pose unique challenges and unique opportunities to offshore drilling operations. On the one hand, risers are large, heavy, time consuming to run, and do not often protect against high pressure. On the other hand, risers allow for instruments to be present in the annulus, a luxury which traditional casing strings cannot offer. This is beneficial in profiling the return fluids. Temperature may be considered in anomaly detection. Spaced along the length of the riser, multiple pressure readings allow for density measurement as the fluid is returning to the surface. The type and spacing of the pressure transducers is important. Over long distances and large pressure changes, a simple comparison may be performed between two independent transducers. However, as the distance shortens and the change becomes smaller, the readings unusable due to the resolution required. Diaphragm type pressure transducers are favorable over a shorter distance. As far as downhole pressure readings are concerned, an incorporation of BHP would be desirable. Pressure While Drilling (PWD) tools do make this possible, but careful consideration should be given as to how such data is incorporated. Mud pulse telemetry relies on a generated pressure signal to be read at surface. In terms of kick detection, it is reasonable to assume that high precision surface equipment could catch the associated influx as fast as a PWD tool could send the signal. In this case, wired pipe would be the ideal means for communicating with downhole transducer.

Concerning floating rigs specifically, an account must be given for the effect of wave motion. Accurate measurement of flow and pressure is vital, but it is also vital to have an understanding of what the flow and pressure should be. It is known that wave motion has a noticeable effect on riser volume due to the use of a telescopic slip joint. In the case of a high pressure diverter or RCD installed above the slip joint, a direct measurement can be made of the riser heave through use of a laser range finder or similar device. With the known dimensions and displacement of the slip joint, a slip joint correction factor may be applied to the known displacement resulting in a real-time calculation of riser volume as function of wave motion. An example of an unadjusted return flow rate subject to wave motion can be found in Figure 2. With a known riser heave displacement and volumetric correction factor applied, the DKD system may anticipate non-steady state conditions and alarm when anomalies occur.

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Fig 2: Surges in flow due to slip joint displacement

With the onset of pumped riser systems and the possibility of riserless systems, an alternative form of riser heave measurement must be achieved in the event the telescopic slip joint is not installed. Global positioning offers one solution while installing accelerometers offers another. In field trials, accelerometers have not yet proven reliable when compared to the laser range finder. In cases where the return flow is routed through a hose (as opposed to the riser), considerations should be made to account for any possible lag caused by using a hose.

As seen in Figure 1 earlier, drilling parameters such as drillpipe RPM, rate of penetration, and weight on bit can affect BHP. The DKD then must contain a robust control and data processing system. Incorporation of these into the DKD system will lead to a more complete understanding of the downhole conditions. Together with instrumentation, the control and data processing system creates the ability to profile flow from the well while circulating and once the pumps are off. This can help the rig crew determine whether flow is being caused by natural breathing of the formation or something more serious such as a gas influx. Such methods are in use today and are often performed as a third party service. Integration of profiling and trend spotting methods into the DKD package is desirable because ultimately it is likely that DKD expand beyond just detection and into process control. An automated kick detection system unfetters the MPD system when the two are properly coupled. While early systems will remain partitioned as outlined below in Figure 3.

DKD HMI

DKD

Data Acquisition and Central Processing

Module(SCADA)

DKD/PVT Instrumentation

Drilling Contractor

3rd Party Services

MPD System

Riser Gas Handling System

MPD HMI

Fig 3: Partitioned system requires crew operate the MPD system Discussion of automation often invites controversy in the drilling industry. There are risks associated overloading the operator with information as well as turning over control to machines. Questions surface on how best to accomplish the technical objective while staying within financial constraints. So it is important to understand what the drivers are when

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automating a process. Often the result of automation is the reduction of personnel. This however is not necessarily a sound driver for automating. Tremendous amounts of time and capital are spent designing and implementing automation so even when the result is removal of people from hazardous areas, the objective must be to mitigate risk and capital expenditure over the long run. An automated DKD system mitigates risks and delivers value to the drilling operation by alerting the crew to small, manageable problems before they have the chance to become large, unwieldy problems. When considering kick management through conventional means, considerable volumes of formation fluid may enter the well before a problem is suspected. Referring back to the example presented by Figure 1, a considerable amount of fluid may further be invited into the well while performing a conventional flow check. It is not uncommon to see kicks of 50 to 100 bbls or higher in deepwater environments. These events may result in the loss of a hole section or a the very least, several days of remedial work to recondition the well. It is evident that the best way to reduce the amount of corrective work is to reduce the magnitude of the event. This concept is illustrated in Figure 4 below.

Fig 4: Reducing kick volume increases operational efficiency It is envisioned that a system, referred to above as predictive driller, be created which could predict formation pressure before a noticeable influx occurs and adjust the MPD choke to anticipate a flux. Since this does not yet exist, a robust integrated DKD and MPD system which detects small volume changes and quickly responds will be the next best alternative. Reduction of kick volume directly correlates to a reduction in cost and risk associated with the kick. Therefore, early detection is vital to minimize influx.

Conclusions Conventional kick detection is based on volumetric accounting of fluid in the mud pits. While fundamentally reliable, this method is often prone to error due to system configuration. While PVT is automated, kick detection mostly relies on human comprehension to extract information from data. Exploration in deepwater mostly occurs in highly productive formations where small pressure differences can invite large volumes of fluid into the wellbore. Additionally, the use of a floating drilling unit creates additional challenges to conventional volumetric methods due to heave caused by wave

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motion. Some have turned to new metering techniques to verify data or reduce measurement error. However, a deepwater kick detection system will require a holistic approach to sufficiently meet the challenges posed by drilling in deepwater. In addition to traditional volumetric flow accounting, a mass flow accounting approach should be implemented, as well as modeling to account for fluid and wellbore effects. By detecting kicks earlier, less work is required to resolve the event. Reduced kick volume results in significant time savings which is realized through a reduction in total circulating time. Ultimately, the need for high specification pressure control equipment may be reduced if source problem, gas influx, is mitigated.

Conventional kick detection relies on PVT systems which are prone to noise and error. Floating drilling rigs face specific challenges related to kick detection due to wave motion. Discretizing the well and mud processing system reduces kick detection error. Mass flow metering can be used to better track influx into wellbore. Incorporating fluid dynamics modeling and wellbore modeling will help better interpret data and

identify the cause of an event.

References API Standard 53, Blowout Prevention Equipment Systems for Drilling Wells, fourth edition. 2012. Washington DC: API. Deepwater Horizon Study Group; Final Report on the Investigation of the Macando Well Blowout Disaster. Berkeley, California, USA, 1 March 2011. Hope, Iain; Livingston, Scott; Ogg, Jeremy; Newbuild Construction Cycles An Evolving Paradigm. Paper SPE 151350 presented at SPE IADC 2012, San Diego, California, USA, 6-8 March 2012. Pavel, D; Grayson, B; Closed-Loop Circulation 1: Advanced pressure control improves kick, loss detection. Oil & Gas Journal; Houston, TX, USA; Dec 6, 2010; Volume 108 page 84; Issue 46. Reitsma, Don; Development of an Automated System for the Rapid Detection of Drilling Anomalies using Standpipe and Discharge Pressure. Paper SPE 140255 presented at SPE IADC 2011, Amsterdam, The Netherlands, 1-3 March 2011. Santos, Helio; Catak, Erdem; Valluri, Sandeep; Kick Tolerance Misconceptions and Consequences to Well Design. Paper SPE 140113 presented at SPE IADC 2011, Amsterdam, The Netherlands, 1-3 March 2011.

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Appendix Potential DKD system configuration