Kick tolerance misconceptions and consequences for well design

TECHNOLOGY

Jerome Schubert, SPE, is an assistant professor in the Harold Vance Department of Petroleum Engineering at Texas A&M University. He has more than 30 years’ experience with Pennzoil, Enron Oil and Gas, the University of Houston– Victoria Petroleum Training Institute, and Texas A&M University. Schubert earned BS, ME, and PhD degrees in petroleum engineering from Texas A&M University. He is a coauthor of Managed Pressure Drilling and the author of more than 35 technical papers. Schubert serves on the JPT Editorial Committee and has served on several SPE committees and as a Technical Editor for SPE Drilling & Completion. He serves as Faculty Advisor for Pi Epsilon Tau. Schubert is a registered professional engineer in Texas.

Recommended additional reading at OnePetro: www.onepetro.org.

WELL CONTROL Procrastination: Is it too many things going on at once that causes us to rush to meet deadlines, or makes us forget to complete important tasks in a timely manner, or even try to do too many things at once, resulting in nothing getting done correctly? You probably are wondering how this relates to well control. In our work schedules, we all are faced with situations in which we are required to complete multiple concurrent tasks. This often is the case when we rush to finish drilling a problem well so that we can get the drilling rig moved to the next location and turn this well over to the completions team. Multiple activities must be completed concurrently that, individually, are relatively simple, but each activity requires the attention of the driller, tool pusher, company man, and others on the crew. When one of these tasks begins to go awry, our attention may be on something else, and we can miss important warnings until it is too late to avoid a disaster. What is the point? Once again, I will use the Macondo blowout as an example. To leave the well in a position to be completed by another crew, mud had to be removed from the riser and top of the well and be replaced with seawater. A spacer was pumped between the mud and seawater to prevent mixing of the seawater and mud. This is a simple enough operation, it seems, but when seawater is being pumped into the well, mud has to be pumped onto a workboat to prevent the pits from running over, and the spacer is being dumped overboard; keeping track of how much of each fluid is going where becomes a daunting task. Could this have been a contributing factor in not recognizing the beginning of the kick? JPT

SPE 138465 Qualification of WellBarrier Elements—Test Medium, Test Temperatures, and Long-Term Integrity. By Birgit Vignes, SPE, University of Stavanger. SPE 142076 Well-Integrity Analysis in Gulf of Mexico Wells Using Passive Ultrasonic Leak-Detection Method. By J.E. Johns, Seawell, et al. SPE 140255 Development of an Automated System for the Rapid Detection of Drilling Anomalies Using Standpipe and Discharge Pressure. By Don Reitsma, SPE, @balance-A Schlumberger Company. SPE 143101 A Proposed Method for Planning the Best Response to Kicks Taken During Managed-Pressure-Drilling Operations. By J.R Smith, SPE, Louisiana State University, et al.

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Kick-Tolerance Misconceptions and Consequences for Well Design

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ick tolerance defines the appropriate number and setting depths of casing strings required to achieve drilling objectives. It also is used during drilling to determine whether it is safe to continue drilling or if there is a need to run a casing string. Alternatively, it is used to indicate whether it is safe to circulate a kick out of the well or whether bullheading is necessary. During development of a new well-control system, a thorough review of the fundamental concepts involved was carried out, and, in relation to kick tolerance, a few misconceptions were identified.

Introduction Even though kick tolerance is a critical and fundamental concept for the drilling industry, there is no standard used by operators, drilling contractors, or training institutions. Hence, there are several definitions of kick tolerance and different ways of calculating it. This lack of consistency may be why the subject is not well understood and, therefore, is sometimes used dangerously. Definitions of kick tolerance may be in terms of pit gain, mud-weight increase, or underbalance pressure. Another point of disagreement is on how the predicted pore pressure should be used in calculations. Some companies use a value greater than the mud weight, while others use a value greater than the predicted pore pressure. Despite the variations, the goal is consistent: to use a procedure that ensures safe drilling of a well. Often,

this lack of a standard and of understanding the topic leads to uncertainty and discussions during drilling. Questions often arise regarding whether it is safe to continue drilling. Because wells are now drilled in more-challenging environments, such as high-pressure/high-temperature and deep and ultradeep water, a small variation in the way that kick tolerance is calculated can lead to premature abandonment of the well or, worse, to a hazardous drilling situation.

Kick-Tolerance Calculation— Current Approach The first step of a simplified kick-tolerance calculation (i.e., constant temperature, constant density, and no compressibility) is to define the maximum vertical height of a gas influx Hmax at the casing shoe (assumed to be the weakest point in the open hole). Hmax is determined on the basis of fracture gradient; mud weight; kick-fluid density; predicted pore pressure; and adjusted maximum allowable annular surface pressure (MAASP), which is reduced by a safety margin. What is conceptually wrong is that if the bottomhole-assembly (BHA) length is greater than Hmax, the kick cannot be circulated out of the wellbore because it will reach the top of the drill collars with a kick height greater than Hmax, which would induce losses at the shoe.

Misconception 1: Kick Volume Around the BHA To address this point properly, an extra calculation must be performed if

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140113, “Kick-Tolerance Misconceptions and Consequences for Well Design,” by Helio Santos, SPE, Erdem Catak, SPE, and Sandeep Valluri, Safekick, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1–3 March. The paper has not been peer reviewed.

the BHA length is greater than Hmax. Instead, Hmax must be at the top of the drill collars. Then, calculations must be made for the volume across the top of the drill collars and must be taken to the bottom of the wellbore by use of Boyle’s law, in the same way that it is used with the kick volume calculated at the casing shoe. Usually, if Hmax is greater than the BHA length, the difference in annular volume compensates the expansion of the gas when it travels upward, reducing the chances of creating a problem.

Misconception 2: Safety Margin The safety margin can lead to an overly conservative solution. This conservative approach can lead to the use of unnecessary casings and liners in the well design, especially in deep water. It has been widely accepted that when calculating kick tolerance, a safety margin should be applied to the MAASP to reduce the chance of inducing fractures during a well-control event. MAASP is calculated on the basis of fracture pressure at the casing shoe (assumed to be the weakest point in the open hole) and current mud weight above the casing shoe. In most cases, the safety margin comprises three components: chokeoperator error, annular frictional pressure loss, and chokeline frictional pressure loss. Some companies and publications call for the use of only the first two terms as safety margin. Although each well section is different, many procedures establish a fixed value for the safety margin to be used when calculating kick tolerance. Typical values are 150 or 200 psi. A value of 100  psi is assumed for the choke-operator error and the remaining for the frictionalpressure-loss component. Because the physical principle and rationale behind the annular frictional pressure loss and

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chokeline frictional pressure loss are the same, the effects will be grouped together. The choke-operator-error component is addressed separately, to make sure that each effect is understood and evaluated independently. Annular and Chokeline Frictional Pressure Loss. When fluid is circulated in a well during a well-control operation, frictional pressure loss in the chokeline and annulus will be generated. The magnitude of the frictional pressure loss will depend on well geometry and the length and diameter of the chokeline. In deepwater and slimhole wells, the frictional-pressure-loss component can be significant. To prevent formation fracturing, the backpressure applied at surface while the well is static should be compensated when the fluidcirculation rate changes. Because it is difficult to estimate frictional pressure loss in real time during well-control events, the adopted approach has been to subtract the frictional-pressure-loss value from the MAASP. Even though this

approach reduces the chances of fracturing the formation, it imposes large sacrifices in the well design, leading to several unnecessary casing strings. The alternative approach would be to use this frictional pressure loss proactively during any fluid circulation; it makes no difference to the wellbore whether the pressure at the bottom is coming from a choke at surface or from friction generated in the wellbore. Choke-Operator Error. The chokeoperator error is intended to compensate for expected poor manual control of the choke by the operator. Today’s standard is to use a 100-psi safety factor. However, automated chokes are readily available. Automation allows better control with smaller oscillations in pressure, and it removes issues related to operator fatigue or error. Automated chokes have been used reliably in applications including drilling, well control, and well cleanup. With improved control, the 100-psi safety margin can be reduced to 20 psi or less.

Misconception 3: Simplification Current kick-tolerance calculations are based on many assumptions and simplifications. The belief is that these simplifications represent the worst-case scenario, thus leading to a safe well design. Afterflow Effect. Usually, for the sake of simplicity, the afterflow effect is ignored. Therefore, kick tolerance is considered equal to the maximum allowable pit gain. In reality, the formation continues to flow until the casing pressure increases enough to equilibrate the bottomhole pressure to the sandface pressure at the point of influx. Accordingly, when determining maximum allowable pit gain, the additional flow into the well after shut-in must be considered. This afterflow volume may be significant, especially for deep wells with large bores. Some companies use a fixed value (e.g., 10 bbl). This simplification can lead to a conservative result. However, companies not taking this effect into account may encounter dangerous situations. In

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this paper, formation flow after shut-in is considered to be equal to the well’s total compressibility. Temperature Effect. The change in temperature along the wellbore will affect the density and the rheology of the mud, having a direct effect on the hydrostatic gradient and the frictional pressure losses during circulation. Currently, it is assumed that the temperature in the openhole section is constant; thus, no correction to the volume calculation is applied. The effects of temperature on influx volume are described by Charles law, which states that the volume of the gas is directly proportional to the absolute temperature. Contrary to the afterflow effect, the temperature correction results in a higher kick tolerance. Therefore, the conventional constant-temperature assumption results in a conservative solution. z-Factor Correction. z-factor (compressibility factor) enables use of idealgas equations to model real-gas behav-

ior. Because calculating the z-factor is not straightforward, the industry has assumed a constant z-factor equal to 1.0 when performing gas-behavior calculations. In this paper, a 0.6-SG hydrocarbon gas is assumed as the influx fluid. The pseudocritical properties were calculated using Katz’s correlations. Then, the z-factor was calculated by use of Dranchuk and Abou-Kassem correlations combined with the Newton-Raphson iterative method. z-factors were calculated for conditions along the open hole and were used in the bottomhole kick-volume calculations through the real-gas law. Influx-Density Correction. Kick-fluid density was assumed to be 1.9 lbm/gal and constant along the openhole section. Once the z-factor was calculated, the influx density was estimated. Using 0.6 SG for hydrocarbon gas and the pressure, temperature, and z-factor for the point of interest (i.e., casing shoe and bottomhole conditions), volumes at the bottom of the well were calculated.

Influx density had a direct effect in the kick-tolerance calculation.

Combined Correction Effects on Kick Tolerance Because some effects increase the kick tolerance while others reduce it, it is important to combine all the effects to identify the overall effect on kick tolerance. The consequences are not consistent, illustrating why it is important to take all effects into account. It has been argued that the overall conservative nature of the single-bubble model will eliminate any detrimental effect produced by simplifications. Because the magnitude of each simplification and conceptual error is different, the change of the final result cannot be predicted. If it is clear that a conservative approach is being used, the consequences might be only economical, with the end result being an overengineered well. However, when the scenario leads to increased risk, as is the case with calculating the kick volume on bottom, this simplification should not be acceptable. JPT

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Kick Detection and Well Control in a Closed Wellbore

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losing the wellbore at the top with a rotating control device (RCD) for some kind of managed-pressuredrilling (MPD) operations raises a number of issues with regard to well control and kick detection. The use of an RCD provides drillers with an additional level of comfort because it is a pressure-management device, but it does not eliminate the need to have well control as a primary objective. Early kick detection and annular-pressure control are essential parts of MPD operations, but there can be confusion as to where the responsibility for well control lies.

drilled are unknown, then kicks can still be taken. This leads to the next challenge: To contain an influx safely, the influx first must be detected. If MPD is used to control the bottomhole pressure (BHP) in the well, then it can be stated that MPD is the primary well control because the pressure in the well is controlled to avoid an influx of formation fluids into the wellbore. The use of an RCD to close in the wellbore makes drilling operations safer. However, it must be noted that, often, the objectives of MPD are to reduce the hydrostatic pressure, avoid losses, and drill the well with a lower mud weight. Reducing the mud weight can introduce more well-control events.

Introduction The detection of inflow from a formation is one of the primary safety aspects of drilling operations. Even with a closed wellbore and with the use of MPD technology, kick detection and the subsequent well-control procedures must remain in place. The rig crew can get a false sense of security that with MPD, the well is controlled at all times and as such there is no further need for well control. The causes of kicks are not removed when MPD operations are being conducted. The procedures and risk assessments for MPD operations must include kick-detection and well-control methods and procedures.

Primary Well Control Controlling the annular-pressure profile is one of the main reasons for MPD, but it may not avoid kicks in a well. If the pore pressures of the formations being

MPD Operations Fig. 1 diagrams the MPD flow process. The RCD is installed on top of the annular preventer and closes the wellbore around the drillpipe. The outlet from the RCD is split between the main return flowline and the MPD choke manifold. The MPD manifold is installed in parallel with the rig’s main flowline and in parallel with the rig’s conventional rig choke manifold. This setup allows conventional circulation and circulation through the MPD manifold. Backpressure can be applied to the well at any time by use of the MPD manifold. Any gas being circulated out through the MPD manifold can be vented safely through the mud/ gas separator. If the surface pressure exceeds the RCD pressure ratings, the entire well-control setup can be switched quickly to standard drilling well-control equipment. During tripping operations,

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 143099, “Kick Detection and Well Control in a Closed Wellbore,” by Steve Nas, SPE, Weatherford, prepared for the 2011 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Denver, 5–6 April. The paper has not been peer reviewed.

circulation with the trip tank can be performed through the MPD manifold or through the existing flowline. When MPD equipment is used, it is important that the secondary wellcontrol equipment, such as blowout preventer (BOP) and rig choke manifolds, remain ready for operations. The secondary well-control equipment should not be used for routine drilling operations during the MPD operations.

Causes of Kicks A kick is defined as any influx that constitutes a well-control emergency. Normally, this means use of the BOP to shut in the well and, subsequently, removing the influx by use of a choke on the annulus to maintain sufficient backpressure to prevent further entry. In MPD, the well-control emergency may not apply because the system is already set up for this occurrence. The pressure in the wellbore can be controlled with surface pressure, but if the formation pressure is greater than the pressure in the wellbore and a formation is permeable, then the well will kick. Loss of primary well control usually is caused by the following. ◗ Insufficient drilling-fluid density (insufficient BHP) ◗ Failure to keep the hole full while tripping ◗ Swabbing while tripping ◗ Lost circulation

Kick Detection Detecting a kick early and limiting its volume by shutting in the well are critical to secondary well control, and they could mean the difference between a manageable situation and one that leads to loss of control. Immediately following an influx, the BHP in the annulus is reduced to some extent by the influx and by the added lift energy given by the formationfluid flow. This effect leads to a decrease

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Main Flowline

Bleedoff Valve

Shale Shakers

Rig Choke Manifold

Gas to vent

Mud/Gas Separator

Trip-Tank Fillup

MPD Choke Manifold With Coriolis Meter

Trip Tank

Trip-Tank Pump

Fig. 1—MPD-process flow diagram.

in pump pressure, but this change is very difficult to detect until relatively late in the flow. The flow into and out of the well is in a steady-state condition during normal circulation. A kick violates this balance, and the return flow out of the well will increase if a kick is taken. Following this flow increase, there also is an increase in the surface volume as formation fluid is added to the circulation process.

Kick Detection in Closed Wellbores Closing in the wellbore with an RCD, in principle, does not change the physics of kick detection. Although the level in the well is not visible, the increase in return-flow rate and increases in pit levels remain the most-reliable indicators of a kick. The use of mass-flow meters in combination with accurate standpipepressure sensors enables use of an automated kick-detection system on some MPD systems. This system works during drilling conditions, but when tripping or making connections, the flow out of the well often is the only reliable indicator of a well-control issue.

Early Kick Detection It is possible to calibrate the flow into the well from the pump strokes and then measure the flow out of the well with a Coriolis meter. A software program allows the flow in and the flow out to be calibrated inside the casing before drill-

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ing a new formation. Once calibrated, the variation between the flow in and flow out can be displayed and alarmed on the rig floor, making a highly accurate flowrate-detection system.

Ballooning Borehole ballooning or breathing, or loss/gain, is the result of slow mud losses while drilling ahead followed by mud returns after the pumps have been turned off, such as during a connection or flow check. Usually, any flow during these periods is cause for concern because it may be caused by an influx of formation water, liquid hydrocarbons, or gas. Any influx from the formation can result in a well-control problem, the magnitude of which depends on the influx volume and composition. However, if the flow is the result of mud returns, well control is not an issue. To be safe, the suspected influx can be circulated out using the choke, but this method is time consuming and wasteful, particularly if the influx is only returning mud. The normal cure is to increase the mud weight and ensure an adequate overbalance in the absence of circulation. If the mud weight is increased and the influx is only mud, the situation will get progressively worse with a rise in mud weight and, therefore, the equivalent circulating density (ECD). Mud losses will continue, and, eventually, the fracturepropagation pressure will be exceeded, resulting in total losses.

The use of accurate flowmeters helps determine whether the increased flow is an influx or returning mud. Soon after the pumps are shut down, the flow out of the well can be observed. If the flow declines, ballooning is occurring. When the pumps are started again, the flowmeter will show that the flow out of the well lags behind the flow into the well, which is another indication of ballooning. The accurate measurement of flow into and out of the well allows kick detection and detection of losses and ballooning of a wellbore, but a kick can still be taken if attention is not paid.

Handling a Kick Well control can be described as maintaining BHP within a window having upper and lower pressure limits. On the low side, the margin normally is bounded by pore pressure and wellbore stability, whereas on the high side, it can be bounded by differential sticking, lost circulation, and fracture pressure. A kick is detected in a closed wellbore by use of the mass-flow meter. With an MPD system installed, there are two choices to circulate out the influx. With MPD Equipment. The MPD choke manifold makes it possible to continue circulating, increase the backpressure on the well until the flow in and flow out are balanced, and then circulate out the influx using the “driller’s method.” This procedure will work if the forma-

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tion pressure can be obtained accurately. Once a kick is taken, the formation pressure must be determined to establish the proper kill-mud weight. The formation pressure can still be determined, but with full circulation this must take into account the ECD and the BHP must be used. Without an accurate pressure measurement through a pressure-while-drilling (PWD) tool, this may not be possible. The backpressure and ECD calculations or measurement can provide the formation pressure. Accuracy of this measurement may depend on readings from the PWD tool. The flowmeter will provide an indication of the size of the influx and can be checked with the pit levels, provided that this kick is large enough to be seen. One issue that must be considered is the potential surface pressure while circulating the kick out because the RCD pressure limits will need to be known and cannot be exceeded. Kick modeling must be conducted to establish the kick intensity and kick volumes that can be handled.

With Rig Equipment. If a kick is detected, conventional well-control procedures can be used as follows. 1. Pull up and space out the drillstring. 2. Stop the pumps. 3. Close the BOP. 4. Record the shut-in drillpipe pressure and the shut-in casing pressure. The shut-in drillpipe pressure will provide the level of underbalance (formation pressure), while the shut-in casing pressure will give an indication of the kick size and density. The pit levels can be measured to confirm the influx. Kick Volume and Intensity. The kick volume is the volume of formation fluid that entered the wellbore. The volume gained at surface will provide an indication of this volume. The kick intensity is defined as the pressure difference between the hydrostatic pressure in the well and the formation pressure. With these two parameters, the decision can be made whether to handle the kick with the MPD system or to close the

BOP and use the rig’s choke manifold to circulate the kick out of the hole. This decision is driven by the expected surface pressures and by the pressure ratings of the equipment. Generally, a kick with volume of 5 bbl or less and kick intensity less than 1-lbm/gal equivalent mud weight can be circulated out of the hole using the RCD and the MPD choke manifold. If BHPs are high, as in the case of high-pressure/hightemperature wells, then the values should be reviewed on a case-by-case basis. Switching From MPD to Conventional Well Control. Once a kick is taken and controlled using an MPD system, it becomes important that the driller and the MPD operator coordinate their actions if the surface pressures rise and indicate that the kick should now be controlled by the BOP system. Switching from the MPD system to the rig’s BOP and choke manifold must be accomplished in a controlled manner. Standard well-control preparations in the form of kick sheets, slow circula-

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tion rates, and pressures must be continued by the rig crew, as in all drilling operations. Although a well is drilled with MPD techniques and can be controlled with the MPD system, the driller must be able to take over at any time in the wellcontrol process. It has been seen in several MPD operations that well-control preparations by the drill crew were not being performed because the crew relied on the MPD provider to conduct well-control operations. Upon entering a well-control circulation and the system needing to be switched to lower pump rates and a different pressure, this lack of preparation can cause significant issues during the well-control operations.

MPD Operators and Well Control If the detected influx is small and has a low kick intensity, it is possible to circulate the kick out using the MPD equipment. The driller’s method normally is used for this, and the MPD operator must hold the drillpipe pressure constant while the driller circulates the kick out. Once the influx reaches the surface equipment, the MPD operator must divert any gas away from the main flowline to a suitable mud/gas separator. This process assumes that all MPD operators have the experience and understanding required for well-control operations. Before any MPD operations are conducted, it must be verified that all MPD personnel operating the choke understand the procedures and actions required when a kick is detected. The MPD operator must understand the wellcontrol situation fully. Both the MPD operator and the driller must maintain a close watch on the surface pressures to ensure that these remain within the limits of the equipment being used. Advantages of using the MPD equipment for well control include that the pipe can be moved up and down and can be rotated and that stuck-pipe incidents, often associated with well-control operations, can be avoided. If something goes wrong at any time during an MPD well-control situation, the driller must be able to stop the pumps and shut in the well using the BOPs and then continue the well-kill operation using the rig’s choke manifold. JPT

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Kick Mechanisms and Well-Control Practices in Deepwater Vugular Carbonate

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tandard well-control training that drillers receive prepares them to respond to an influx that occurs during underbalanced conditions. The mechanism by which hydrocarbons may enter the wellbore following a vugular loss can be different. One potential result is that the influx may not be detected as early as during conventional underbalanced conditions. A model was developed to explain the unique mechanism by which kicks may occur following vugular losses. Effective recognition and response practices are proposed that are consistent with that model.

Well-control equipment

Practices address reduced reaction time

Introduction

Fig. 1—The reaction time available to shut in following an influx in deepwater wells is significantly less than with surface BOPs.

When massive losses occur in vugular formations, the well’s behavior does not follow a conventional well-control scenario. Gains in pit volumes are not seen despite hydrocarbon entry, and kicks can go undetected until they have traveled some distance up the annulus. Once the kick is detected, backpressure cannot be held effectively to prevent further influx while circulating the initial kick out and the annulus-pressure trends and values appear to be unpredictable. It also is difficult to control the placement of fluids or pills. The most significant challenge is the inability to detect an influx as soon as it occurs. In deepwater wells, the distance from the vugular zone to the subsea blowout preventers (BOPs) may be short, as shown in Fig. 1.

Operators are aware of these behaviors, and the industry has developed unique practices for drilling vugular carbonates safely. Rigs having surface BOPs address the risks by use of a rotating control device (RCD). RCDs have been used in a similar fashion at the surface on marine risers with subsea BOPs. The RCD has been installed at the top of the riser above the slip joint, and a tensionring system is under development that will enable the RCD to be placed below the slip joint. In subsea applications, the pressure that can be applied below the RCD is more limited than on land locations, usually to the rating of the slip joint or marine riser. In some cases, the rating is adequate for the given well. In

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14423, “Kick Mechanisms and Unique Well-Control Practices in Vugular Deepwater Carbonates,” by F.E. Dupriest, SPE, ExxonMobil, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15–17 November. The paper has not been peer reviewed. [Note: Conference rescheduled to 7–9 February 2012.] Copyright 2011 International Petroleum Technology Conference. Reproduced by permission.

other situations, the pressure limitations of the riser system or RCD may not provide the robust capability needed.

Attributes of Vugular Losses The unique behaviors observed during massive vugular losses are associated with the bottomhole pressure (BHP) falling instantly to equal the pore pressure in the vug. It is widely believed that the practice of filling the back side continuously prevents this drop in BHP and that an influx does not occur unless the fill rate is inadequate and the fluid level is allowed to fall sufficiently to underbalance the zone. Actually, the degree to which the BHP falls is more a function of the rate at which the loss zone can take the fluid than of the fill rate. In severe vugular losses, filling the annulus is not effective and the BHP will fall to equal the vugular pore pressure. As the vug size or density decreases, there is a point at which the fill rate will create some backpressure within the vugs at the face of the borehole, and the BHP will increase by the amount of this

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backpressure. Consequently, the BHP is almost entirely a function of the vugular conductivity rather than the annulus fill rate. When complete losses occur and the annulus level drops quickly, the vugs are likely to be large; therefore, filling the annulus continuously may not prevent the BHP from falling. The observed kicks are not the result of allowing the annulus fluid level to fall; they are caused by the well becoming underbalanced because of the drop in BHP, which allows flow from another location. However, field observations and pressure-while-drilling data show that the influx may initiate immediately with the loss in very vugular formations. The key question that cannot be answered with conventional thinking is, If the mud weight is overbalanced and flowing into the vugs, how can gas be flowing out of the same vugs? It is still good practice to fill the annulus continuously until a diagnostic pill of large lost-circulation material (LCM) can be pumped because this ensures that the influx travels down to the loss zone rather than up the annulus, but it does not prevent the influx from occurring or continuing to occur while filling. If the pore throats are in the range of 150 to 3000 μm, LCM may be effective, in which case the losses will stop, the BHP will increase above the formation pressure, and the influx will stop. If the pore throats are larger, continuous fill is used to control the gas level in the annulus until cementing or other operations can be executed to stop the loss.

Interzonal Flow Cell Wells that drill carbonates containing hydrocarbon usually are designed to have casing set in a competent impermeable formation just above the carbonate. If the carbonate is drilled without losses, or with only low seepage losses, a filter cake forms and overbalance exists across the open hole. When a vugular opening is encountered, complete losses occur and the BHP falls to equal the pore pressure. Although the annulus will continue to be filled, this procedure does not prevent the BHP from falling to equal the pore pressure in the vugular interval on bottom. The pressure at

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any point in the wellbore above the loss zone is then equal to the BHP minus the fluid head. While the greatest underbalance will be at the top of the carbonate, the entire borehole will be underbalanced by some amount as long as there is mud in the wellbore across the carbonate. If the annulus fill is stopped, the hydrocarbon will continue to flow into the wellbore and displace mud downward between the top and the loss zone until the annulus across the interval is converted entirely to hydrocarbon. At that point, there is no differential between the pressure at any point in the wellbore and that in the adjacent formation. Because the pressure at all depths is equal, the influx will stop. This is referred to as a flow cell because the process tends to drive itself. As mud swaps and moves downward across the carbonate, the flow cell again becomes unbalanced and additional influx occurs. As the swapped gas moves up the annulus, its expansion will lighten the head and a gain in pit volumes eventually will be observed. The most important operational implication of the flow cell is that an influx can occur with no gain in the pits. When an influx occurs, the rig crew should observe a sudden loss of all returns. Consequently, the work process should be to close the BOPs in response to any complete loss of returns. While a sudden complete loss will not always result in an influx, it is an indication that the opportunity for one exists. The argument can be made that the BOPs should be closed following any major loss, even one that is not complete. In theory, an influx should not occur if partial returns are maintained because getting continued returns implies that the BHP must be adequate to lift the head of the drill-weight mud. In practice, however, the loss may be temporary because continued pumping will move the gas up the annulus, which lightens the head quickly and may allow full circulation. The conservative practice is to shut in on any major loss, observe the chokeline pressure to determine whether gas is migrating, and, if possible, circulate out through the chokeline to reach “bottoms up.”

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The reason for being conservative is that if circulation continues through the open stack following what is believed to be a partial-loss event and an influx has actually occurred, then a pit-volume increase may not be seen until the gas reaches a depth at which expansion occurs, or until the gas comes out of solution if using a nonaqueous fluid (NAF).

Swap Management The industry is trained to manage kicks by circulating through a choke and applying sufficient backpressure for the pressure in the annulus to become overbalanced to the flowing zone. This method is ineffective with a vugular loss because the BHP will remain equal to the pore pressure in the vugs regardless of the backpressure observed at surface. In addition, if losses are complete, there is no flow and pressure cannot be applied. The influx can be stopped permanently only by plugging the loss zone to stop the flow cell. The common practice of filling the annulus continu-

ously, which has been learned empirically, is a correct one. But filling the annulus does not stop the flow. Actually, continuous introduction of heavy mud across the carbonate ensures that the imbalance that drives the flow cell is maintained and that the influx will continue to occur. Because there is no operational technique to allow the BHP to be elevated above the pore pressure in the exposed vugs, and the mud that is pumped to fill the annulus drives even more influx, the kick response should be first to determine the fill rate that exceeds the swap rate and then to maintain this fill rate until the vugular zone can be plugged. This method is referred to as swap management. It does not stop the influx, but it does allow the annulus pressure to be controlled at the desired level during treatments or while drilling ahead.

Slide Drilling With a Straight Motor Slide drilling with no rotation through a closed subsea annular preventer with

Endowed Faculty Position -- Petroleum Engineering (Drilling and Production) Oklahoma State University The School of Mechanical & Aerospace Engineering at Oklahoma State University (OSU) invites applications for an endowed faculty position in Petroleum Engineering, with an emphasis on Drilling and Production. This position is supportive of a new interdisciplinary initiative within the College of Engineering, Architecture and Technology. Substantial increases in faculty and resources are planned. Participants in the initiative will include faculty members from Chemical Engineering, Electrical Engineering, Mechanical Engineering and other disciplines, who wish to contribute to addressing the manpower and technology development needs of the petroleum and energy industries. At the undergraduate level the participants will be responsible for a new interdisciplinary Petroleum Engineering Minor, designed to prepare Chemical, Electrical and Mechanical Engineering graduates for the Petroleum Industry. The successful applicant will join an interdisciplinary team to develop and implement undergraduate and graduate coursework and research in Petroleum Engineering. The successful candidate must have a high potential for excellent teaching at the undergraduate and graduate levels and for developing a strong, externally funded research program. An earned doctorate in engineering or a closely related field is desired. Substantial engineering and/or research experience in industry, government or academia is desired. The successful applicant will be appointed at a professorial rank consistent with experience and accomplishments. Salary and other compensation will be commensurate with achievements. Each applicant should provide a letter of application; a curriculum vita; a statement of teaching accomplishments and plans; a summary of previous and current research; a statement of plans for securing extramural funding for research and scholarship; demonstrated abilities for contributing effectively to an interdisciplinary team; and, the names and contact information for at least five references. The application package should be sent electronically to: Dr. L.L. Hoberock, Chair – Search Committee, Petroleum Engineering (Drilling & Production) Endowed Faculty Position [email protected] School of Mechanical & Aerospace Engineering, Oklahoma State University 218 Engineering North Stillwater, OK 74078-0545 Screening of applications will begin 11/01/11 and continue until the position is filled. The target starting date is negotiable, and could begin as early as 8/01/12. More details please visit http://www.mae.okstate.edu and http://www.ceat.okstate.edu .OSU is an Affirmative Action/Equal Opportunity/E-Verify Employer, compliant with EEO/AA Policy, and committed to diversity.

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a straight motor enables the driller to continue to make progress during complete losses. Because the annular preventer is closed at all times, gas cannot enter the riser. A sacrificial fluid, such as seawater, is used to drill. Double floats are installed—one plunger and one flapper type. Kill-weight mud continues to be pumped down the annulus at the swap-management rate established in the process described in the preceding section. At a minimum, slide drilling continues until the local vugular system is believed to have been fully exposed. Although it varies, the general experience has been that highly vugular intervals tend to extend for only short distances. When the bit is believed to have re-entered pore throats that can be plugged with LCM or barite, a decision may be made to treat the major vugular zone above so that conventional drilling is possible until the next highly vugular network is penetrated. There are several important considerations when planning to slide drill through a closed annular preventer. The annular-preventer manufacturer should be consulted on the planned interval and the number of tool joints that will pass through the upper annular preventer. These practices are based on proprietary stripping tests with specific equipment, and not all preventers may be equally capable. The annulus injection fluid used in deepwater wells should be designed to prevent hydrate formation during unexpected upset conditions, and the drillstring should be displaced to an inhibitive fluid when needed.

Treating Vugular Losses Awareness of the flow cell has changed some elements in the treatment strategy. There are two primary challenges in treating a vugular zone. The first is to avoid overdisplacement. The resistance to flow in a vugular opening is, essentially, only the pore pressure in the vug. Because drill-weight mud is designed to be overbalanced, any treatment that is displaced with drill-weight mud is likely to be overdisplaced. This operator has developed a family of practices that use hydrostatic packers to prevent this overdisplacement. A hydrostatic packer is a

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column of light fluid pumped at the end of displacement to make the total column underbalanced to the integrity so that when pumping is stopped, the fluid cannot continue to travel downward. In the case of vugular carbonates, the integrity pushing back to support the column is, effectively, the pore pressure in the vug, so the hydrostatic packer must be designed to lighten the column sufficiently to place it underbalanced to pore pressure to prevent overdisplacement. Therefore, there will be positive pressure on the drillstring at the end of displacement. By use of surface BOPs, it is necessary to preinstall this light column in the annulus to place it underbalanced to the pore pressure and achieve a positive surface pressure to prevent the fluid from moving downward to contaminate the treatment during the operation. In subsea wells, it is possible to close the choke- and kill-line valves to remove the fluid head from the annulus so that it is necessary to use a packer only inside the drillstring. The new issue raised by the awareness of the flow cell is that even if proper steps are taken to prevent overdisplacement with drill-weight mud, the flow cell itself may displace the material to the loss zone. When pumping stops, the influx and downward displacement occur whether the fluid in the wellbore is drilling fluid, cement, or some other mobile material. Even when overdisplacement has been prevented with hydrostatic packers, a gap or poor-quality cement has sometimes been found from the top of the carbonate downward to the loss zone as a result of displacement by the flow cell. Also, as soon as hydrocarbon begins to enter the wellbore, it starts to swap with the fluid above, and this swapped material is displaced downward to the loss zone. By monitoring the stack gauge, the volume that has been swapped upward can be calculated from the rise in pressure, which reflects the height of cement or other treatment fluid that has been replaced by the light hydrocarbon. The rate of change in the annulus pressure also reflects the rate of change in the swap rate, which is a useful surveillance diagnostic in predicting the likely effec-

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tiveness of the treatment. Treatments with stable pressure, indicating that no swapping is occurring, have been uniformly effective.

Tripping Out of Hole The swap-management practices may be used while tripping. The annular preventer is kept closed, and the string is stripped out until the bottomhole assembly (BHA) arrives at the BOP. The swap rate typically is higher after the string is removed because there is more clearance in open hole or casing than in the small annulus around the string. The chokeline gauge at the stack is monitored as the string is pulled. Any rise in stack pressure is an indication that the fluid level in the chokeline has risen. Because the BHP is constant and equal to the vugular pore pressure, any rise in the fluid level in the chokeline must be the result of an increase in the volume of lighter hydrocarbon in the column and an indication that the hydrocarbonswap rate has begun to exceed the fill rate. If this situation is observed, the fill rate is increased until a stable pressure is achieved, indicating that the fill rate is adequate. In most cases, a pattern is observed quickly and the rig team establishes drilling-fill and tripping-fill rates that differ. When the BHA arrives at the BOP, steps are taken to clear any trapped gas in the stack before opening the stack temporarily to pull the BHA through. The annulus fill continues throughout the process. The process is reversed to trip in the hole. If the swap rate is not high, it can be controlled further by positioning fluid with high gel strength above the top of the carbonate. With waterbased mud and favorable conditions, a high-gel-strength pill can reduce the swap rate to less than 0.1 bbl/min with 17-lbm/gal mud positioned above gas in underground flow. In contrast, it is difficult to build gel strength in NAF pills, and the swap rate generally is high enough that it is not practical to hold a pill in position for the time required to trip. Crosslinked polymers and other materials have been considered to reduce the swap rate and resultant fill rates. JPT