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Well control
Summary A computer simulator was developed and used to evaluate reverse circulation as a potential well-control procedure during drilling. Potential advantages of reverse circulation verified by the simulator include lower casing pressures and smaller cumulative pit gains. In addition, kick fluids are removed from the well much faster than with conventional kill procedures. Several equipment modifications will be required to implement the reverse-circulation kill procedure. Introduction Such conventional well-control methods as the driller's method or the wait-and-weight method have gained widespread acceptance in the drilling industry owing to their effectiveness and flexibility. These methods circulate kick fluids out of and kill fluids into the well following predetermined and controlled actions that require keeping bottomhole pressure (BHP) constant to prevent additional kick fluids from entering the well while maintaining annular pressures below a maximum allowable pressure limit. Both of these methods have proved effective for hydrostatically stabilizing a well, and each has relative advantages. Recognized advantages of the driller's method are that it is simple and can be applied immediately to begin well-control operations shortly after taking a kick. The wait-and-weight method improves on the driller's method by shortening total circulation time and minimizing maximum annular pressures. But this method results in additional calculations and a delay in the implementation of the well-control procedure, during which well pressures will rise because of an increase in kick fluid (gas). The success of each method relies on a well-trained crew that follows specific procedures. These methods, however, were developed with the basic assumptions that the well can be safely shut in and the kick fluids can be circulated out of the well without exceeding formation fracture or casing burst limits. During the drilling of almost any well, a well-control situation potentially may occur in which either of these assumed conditions does not exist, precluding the use of a conventional well-control procedure. One such situation commonly occurs when drilling below drive or conductor casing; formation strength is insufficient to shut in the well if gas is encountered (shallow gas problem), and the well must flow through a diverter system. Another situation occurs when a very large kick is taken during drilling of an intermediate hole. While it may be possible to shut in the well initially, the high casing-shoe pressures caused by gas expansion in the annulus may be such that the shoe will fail under these pressures and using a conventional procedure through full well circulation would be unsafe. Typically, one would be forced to operate the choke to avoid exceeding the maximum allowable casing pressure, which, in turn, would allow additional kick fluids into the well.
Summary The minimum acceptable kick tolerance can be quantified on the basis of the likelihood and consequences of an underground flow well-control incident. Safe and economical casing points can be selected on the basis of the minimum acceptable kick tolerance required to drill the next hole section. For sections with a known but manageable underground flow potential, necessary unconventional well-control contingency plans can be developed. This new approach to well control has the potential to reduce drilling costs by significantly reducing the likelihood of major drilling-related well-control incidents. Introduction The progressive stages of a well-control incident that gets out of control may be as follows: drill into a permeable gas zone underbalanced, take a kick, shut in, exceed the maximum allowable shutin casing pressure, watch drillpipe pressure drop to zero as an underground flow begins, and watch casing pressure increase until equipment failure leads to a surface blowout. During drilling at a given depth below the last casing shoe, a measure of the potential for such a scenario is the remaining kick tolerance. However, a direct tradeoff exists between kick tolerance and well cost: specifying higher-than-necessary minimum acceptable kick tolerances can increase the well cost because additional casing strings will be required. Specifying smaller-than-necessary minimum acceptable kick tolerances can lead to costly well-control incidents. This paper presents a new strategy for determining the adequacy of a given kick-tolerance value that is based on the well-control consequences of underground flows from gas zones in the given hole section. This strategy helps to optimize well costs by managing the well-control risks better than selecting an arbitrary minimum-kick-tolerance value. Well Control In the Well-Plannlng Phase The well-control consideration is an important aspect in casing-point selection during the well-planning procedure. The casing scheme is developed as a function of pore pressures, fracture gradients, wellbore stability considerations, and well-control aspects. The well-control aspect is expressed by the minimum acceptable kick tolerance required during drilling to the next casing point. Shut-In Kick Tolerance. It is defined as the kick intensity (formation pressure increment above the mud weight in use, usually expressed in pounds per gallon) that can be shut in without exceeding the fracture pressure of the weakest exposed formation after a given kick volume of a given fluid density has entered the wellbore. Equation 1 By specifying the expected influx density and the influx volume that can be readily detected and shut in by a given rig drilling a given hole size, the shut-in kick tolerance can be calculated and monitored continuously as drilling operations progress. Unless there is a pore-pressure regression, the next casing string has to be set when the shut-in kick tolerance has fallen to a specified minimum acceptable value. A minimum shut-in kick tolerance of 0.5 lbm/gal is a common design criterion used as a starting point for selecting casing points in Mobil wells. For wells linked to the Drilling Data Center in Dallas, the shut-in kick tolerance is computed and monitored in real time. The default influx volumes used by the Drilling Data Center are 20 bbl of 2-lbm/gal gas for 12 1/4-in. and larger hole sizes and 10 bbl of 2-lbm/gal gas for smaller hole sizes. The most conservative approach to casing-point selection is to prevent any possibility of underground flow. Setting casing deeper than the intersection point of a gas gradient line drawn from total depth (TD) and the fracture gradient line on a depth-vs.-pressure plot (Fig. 1) will enable a well to be shut in on any size kick without fracturing the formation. If the well does not fracture in the open hole after taking a kick, then an underground flow situation cannot develop. In most cases, this will require the casing to be set only a short distance above zones that can flow. This conservative practice is very costly, and there is a risk of reaching the final available casing point before reaching the well's planned TD. On the other hand, having zero shut-in kick tolerance is the least conservative approach to casing-point selection. This will barely allow mud to be circulated. Any pressure increase from a kick in the wellbore annulus will cause a fluid loss at the shoe - i.e., underground flow. There is no safety factor for this scenario. The greater the shut-in kick tolerance desired at any given depth, the deeper the last casing must be set. For a given shut-in kick tolerance, any combination of a larger kick volume or a higher formation pressure would result in underground flow. Consequently, in the well-design process, the shut-in kick tolerance used has to be acceptable for well-control purposes but also allow the well to be drilled economically with the required minimum casing size across the pay zone. For example, Fig. 2 shows a casing point selected on the basis of a specified shut-in kick tolerance value with a specified influx volume of gas. (Notice that the resulting casing point to reach TD is shallower in Fig. 2 than in Fig. 1.) The criterion for the minimum acceptable shut-in kick tolerance for a wellbore section must be set according to how well the pore pressures are known and the risk one is willing to take. The risk of setting too little casing is that underground flow will result. The risk of being too conservative is having to set additional strings of casing to reach TD. Both will increase drilling costs. Hence, there is an optimum shut-in kick tolerance that minimizes the cost of each hole section of a well. Fig. 3 illustrates that the optimum shut-in kick tolerance depends on the underground flow potential of zones in the hole section being considered. Circulating Kick Tolerance. It is defined as the kick intensity that can be circulating out without rupturing the formation or bursting the casing after a given gas kick volume has been allowed to enter the wellbore. Gas expansion is responsible for the increasing annular pressures required when the kick is circulated out to maintain constant bottomhole pressure (BHP). The larger the gas kick volume, the larger the volume of mud that has to be bled off and the higher the resulting backpressure that has to be maintained during circulation of the kick out of the well. The four factors that control the magnitude of the pressure load imposed on the wellbore while a gas kick is circulated out are the influx volume, the wellbore geometry, the kick intensity indicated by the initial shut-in drillpipe pressure (SIDPP), and the kill procedure used to circulate the kick out. Hence, for a given well design and kill procedure, downhole loads from circulating out a gas kick can be limited in magnitude only by limiting the kick intensity and the kick volume. Shut-In Kick Tolerance. It is defined as the kick intensity (formation pressure increment above the mud weight in use, usually expressed in pounds per gallon) that can be shut in without exceeding the fracture pressure of the weakest exposed formation after a given kick volume of a given fluid density has entered the wellbore. Equation 1 By specifying the expected influx density and the influx volume that can be readily detected and shut in by a given rig drilling a given hole size, the shut-in kick tolerance can be calculated and monitored continuously as drilling operations progress. Unless there is a pore-pressure regression, the next casing string has to be set when the shut-in kick tolerance has fallen to a specified minimum acceptable value. A minimum shut-in kick tolerance of 0.5 lbm/gal is a common design criterion used as a starting point for selecting casing points in Mobil wells. For wells linked to the Drilling Data Center in Dallas, the shut-in kick tolerance is computed and monitored in real time. The default influx volumes used by the Drilling Data Center are 20 bbl of 2-lbm/gal gas for 12 1/4-in. and larger hole sizes and 10 bbl of 2-lbm/gal gas for smaller hole sizes. The most conservative approach to casing-point selection is to prevent any possibility of underground flow. Setting casing deeper than the intersection point of a gas gradient line drawn from total depth (TD) and the fracture gradient line on a depth-vs.-pressure plot (Fig. 1) will enable a well to be shut in on any size kick without fracturing the formation. If the well does not fracture in the open hole after taking a kick, then an underground flow situation cannot develop. In most cases, this will require the casing to be set only a short distance above zones that can flow. This conservative practice is very costly, and there is a risk of reaching the final available casing point before reaching the well's planned TD. On the other hand, having zero shut-in kick tolerance is the least conservative approach to casing-point selection. This will barely allow mud to be circulated. Any pressure increase from a kick in the wellbore annulus will cause a fluid loss at the shoe - i.e., underground flow. There is no safety factor for this scenario. The greater the shut-in kick tolerance desired at any given depth, the deeper the last casing must be set. For a given shut-in kick tolerance, any combination of a larger kick volume or a higher formation pressure would result in underground flow. Consequently, in the well-design process, the shut-in kick tolerance used has to be acceptable for well-control purposes but also allow the well to be drilled economically with the required minimum casing size across the pay zone. For example, Fig. 2 shows a casing point selected on the basis of a specified shut-in kick tolerance value with a specified influx volume of gas. (Notice that the resulting casing point to reach TD is shallower in Fig. 2 than in Fig. 1.) The criterion for the minimum acceptable shut-in kick tolerance for a wellbore section must be set according to how well the pore pressures are known and the risk one is willing to take. The risk of setting too little casing is that underground flow will result. The risk of being too conservative is having to set additional strings of casing to reach TD. Both will increase drilling costs. Hence, there is an optimum shut-in kick tolerance that minimizes the cost of each hole section of a well. Fig. 3 illustrates that the optimum shut-in kick tolerance depends on the underground flow potential of zones in the hole section being considered. Circulating Kick Tolerance. It is defined as the kick intensity that can be circulating out without rupturing the formation or bursting the casing after a given gas kick volume has been allowed to enter the wellbore. Gas expansion is responsible for the increasing annular pressures required when the kick is circulated out to maintain constant bottomhole pressure (BHP). The larger the gas kick volume, the larger the volume of mud that has to be bled off and the higher the resulting backpressure that has to be maintained during circulation of the kick out of the well. The four factors that control the magnitude of the pressure load imposed on the wellbore while a gas kick is circulated out are the influx volume, the wellbore geometry, the kick intensity indicated by the initial shut-in drillpipe pressure (SIDPP), and the kill procedure used to circulate the kick out. Hence, for a given well design and kill procedure, downhole loads from circulating out a gas kick can be limited in magnitude only by limiting the kick intensity and the kick volume.
Summary Kick tolerance is a drilling parameter that has prompted both confusion and misunderstanding in the drilling industry, yet its importance to drilling engineers may be increasing exponentially. The increasing number of worldwide drilling catastrophes may spur government agencies to tighten controls on casing-setting-depth criteria, requiring pipe to be set once minimal kick tolerance values are reached. A thorough understanding of kick tolerance is necessary in both drilling operations and casing program design. Confusion involving kick tolerance may be attributed to the concept of zero gain, which is commonly referred to in many accepted definitions of kick tolerance. This paper presents an innovative approach to determining true kick tolerance that not only incorporates the conditions of an influx within the wellbore but also considers the possible reductions in kick tolerance caused by the circulation of that influx from the wellbore. New techniques are available for hand-held calculators, which are now more accurate in determining influx pressure and volume anywhere within the wellbore, A typical well example with illustrations describes kick tolerance and emphasizes the influence of other drilling parameters. Integration of kick-tolerance considerations into the well planning process also is demonstrated. Introduction The concept of kick tolerance has been controversial in the drilling industry. Many say it fosters a false sense of security. Much confusion can be credited to the term "zero gain," which is used in this commonly accepted definition: kick tolerance is the maximum increase in mud weight allowed by the pressure integrity test of the casing shoe with no influx (zero gain) in the wellbore. To the drilling hand on the rig, this means, "How much I can weight up to kill the well without breaking down the shoe, assuming zero pit gain?" All too often, the zero-gain condition is either misunderstood or omitted entirely. Previously published papers have defined kick tolerance in terms of a particular field or operation, developing equations that include safety factors, trip margins, and pit gains common to that environment. Although interesting and discernible to the drilling engineer this may add to the confusion of the average field drilling hand. In addition, governmental regulations may lead to further misunderstanding when improperly interpreted. Minerals Management Service 250.54(a)(6) states, "A safe margin, as approved by the District Supervisor, shall be maintained between the mud weight in use and the equivalent mud weight at the casing shoe as determined in the pressure integrity test." Although each well should be considered individually in the de-termination of such a safe margin, many contend that the futurwill see a standard value for this parameter defined as 0.5 lbm/gal. This requirement could mislead many drillers into believing that they can continue to drill until the mud weight equals exactly 0.5 lbm/gal less than their shoe test. For a better understanding of kick tolerance, the derivation of the kick tolerance equation, based on the above definition, is presented. This equation encompasses the effects of an influx in the presented. This equation encompasses the effects of an influx in the well-bore at initial shut-in conditions. And, of course, no examination of kick tolerance would be complete without consideration of the effects as the influx is circulated from the wellbore. It is likely that government regulatory agencies may soon dictate not only a minimum value for kick tolerance, but also the method of determining that value. A thorough understanding of kick tolerance and how to calculate it while drilling are very important for the drilling representative at the rigsite. The drilling engineer in the office also must consider kick tolerance during the well design. Pore pressure and fracture gradient information, if available, are excellent when used effectively to select casing setting points. However, kick tolerance must also be incorporated, especially in the case of long, openhole sections. Other factors, such as hole stability, may require an increase in mud weight. Should this occur, the minimum allowable kick tolerance may be experienced earlier than anticipated, and governmental regulations may require casing setting. Studies have shown an increase in the number of blowouts worldwide, resulting in escalating costs and increasing liability. The drilling program may soon come under close scrutiny by the various government agencies, which win undoubtedly set stricter guidelines for the drilling of all wells, possibly including kick tolerance.
- North America > United States > Louisiana (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Summary This paper describes a new gas-influx detection technique that monitors the acoustic response of annular measurement-while-drilling (MWD) pulses to provide a rapid, early warning of the development of potential gas-kick situations. The technique has been evaluated in both water and oil-based muds during about 40 gas-kick simulations at two full-scale testing facilities. Free gas is identified by amplitude attenuation and phase delay of MWD fundamentals and their harmonic frequencies. Detection is independent of influx location because the entire length of the annulus between the bit nozzles and a surface-pressure transducer is sampled. Detection of potential gas-kick situations generally occurred within minutes of influx initiation, before any significant gas expansion. Some tests also evaluated a downhole MWD mud-resistivity sensor. Results indicated that both these techniques, and particularly the pulse acoustics can provide unequivocal confirmation of gas and an earlier warning of gas-kick situations than conventional kick-detection techniques. Introduction The oil industry's trend to frontier deepwater exploration has increased the overall risks inherent in encountering a gas kick. In addition to a greater probability of a gas blowout offshore, technological advances in such detection have fallen short of other advances, increasing the risk of serious incidents resulting from gas -kicks. Conventional gas-kick-detection indicators suffer from reliability, accuracy, and credibility problems, and their reliance on gas expansion often results in a significant time lapse between gas entering the borehole and surface detection. Safety in offshore drilling would be enhanced greatly by a reliable gas-influx indicator with a detection capability that was virtually independent of gas expansion. Two indicators that meet these criteria are the monitoring of the signal in the annulus and the measurement of downhole mud resistivity. Testing of these measurements offers convincing evidence of their sensitivity and reliability in detecting a gas influx. Both measurements can indicate a gas influx within minutes of kick initiation; are relatively unaffected by environmental variables; and, especially for annular acoustics, are relatively inexpensive to implement. Annular Pulse Acoustics A gas-kick transient is an uncontrolled gas influx into the wellbore annulus. This gas is introduced for a wide range of injection rates and volumes. Gas concentrations may vary from as low as that characteristic of drilled, connection, and trip gas to as high as that typically associated with blowouts. The evolution of a gas 16 is a complex, dynamic phenomenon involving fluid mixing, diffusion, dispersion, and expansion. These processes interact to produce a variety of temporal and spatial changes in the annular column. This behavior creates changes in the inertia, resistance, and capacitance of the wellbore annulus, which influence the natural frequency and damping of the fluid system. Hence, the amplitude and phase relationships of acoustic signals traveling through this system can be expected to change during the evolution of a gas-kick transient. The Teleco MWD telemetry system transmits information through multifrequency, positive-pressure, binary codes. The pulser mechanism generates square waves, so in addition to the two fundamental frequencies, the resultant signal is rich in harmonics. The usual transmission channel of MWD signals is the drilling fluid contained within the drillstring bore. During the creation of a positive-p pulse, a considerably smaller negative pressure pulse is positive-p pulse, a considerably smaller negative pressure pulse is generated below the pulser mechanism. This pulse propagates to the surface within the annulus in the same manner as the pulse within the drill-string bore. Unlike the drillstring channel, however, the annular channel is frequently contaminated by gas.
Summary This paper promotes industry awareness of the potential mechanisms that may take place in the rare event of a loss of well control and how these mechanisms may be assessed for field-specific conditions. This is particularly important when exploration/appraisal drilling involves penetrating highly overpressured accumulations. Depending on the penetrating highly overpressured accumulations. Depending on the geological burial history, these over-pressures may be located in extremely competent or weakly consolidated formations, even at great depth. In-situ stress and rock-strength characteristics will play a major role with respect to the chances of reaching these target horizons successfully. Introduction One of the most hazardous situations encountered during the drilling or completion phases of oil and gas wells is a loss of well control after an influx of highly overpressured formation fluids. This may arise through any one of the following events:the sudden encounter of a highly overpressured interval, giving a significant well kick that causes fracturing of the openhole section, probably close to the last casing shoe, which may lead to significant mud losses to the fracture, further influx of formation fluids, and uncontrolled flow; swabbing in the well when tripping out drill-string, allowing influx of formation fluids; or fracturing of the openhole section by too high mud weights or by mud pressure surges when running in too fast (drillstring or casing). pressure surges when running in too fast (drillstring or casing). The unsuccessful control of a kick, with further influx of formation fluids, may lead to an external or internal blowout. External blowouts are clearly seen and nearly always result in significant rig damage apart from the risk of fatal injuries to personnel. The behavior of internal blowouts is much more difficult to predict and can range from containment of the overpressured fluids against a sealing layer located close to the blowout point to a migration of high-pressure fluids toward the surface (uncontained internal blowouts) with the potential risk of crater formation by near-surface sediment liquefaction. If liquefaction occurs directly below a rig site, rig loss is a possibility because of a loss of the soil load-bearing capacity. Internal Blowouts Internal blowouts are the uncontrolled flow of high-pressure fluids (usually hydrocarbons originally contained in an interval underlying a sealing caprock) along an openhole section and into lower-pressured permeable intervals that become charged and pressurized with hydrocarbons. permeable intervals that become charged and pressurized with hydrocarbons. The key is to determine whether the hydrocarbons are likely to remain contained within the shallower interval or will continue to move vertically (for example, by rock fracture or the wedging open of fault planes). They may then reach near-surface unconsolidated horizons that can be liquefied by the high hydrocarbon pressures, resulting in crater formation. An example of an onshore uncontained internal blowout is shown in Fig. 1. The crater formed immediately below the drilling because of soil liquefaction, resulting in total rig loss beneath the ground surface. The mechanisms that may follow an internal blowout will be governed by a number of site-specific parameters: hydrocarbon fluid pressure at the blowout depth; hydrocarbon density; length of the openhole section; in-situ-soft values and the orientation of the minimum stress; fracture propagation pressure of an induced hydraulic fracture; location of fault propagation pressure of an induced hydraulic fracture; location of fault planes and sealing vs. nonsealing faults; rock-strength characteristics at planes and sealing vs. nonsealing faults; rock-strength characteristics at each lithological horizon above the blowout location; consolidated intervals; and unconsolidated intervals. Some of these parameters can be obtained from drilling and field records.The location of the consolidated or unconsolidated formations can be determined from drilling rates, the cuttings observed at surface, and logs. The hydrocarbon pressure can be assessed from the mud weights used at the time of the initial kick and the magnitude of the kick. Mud losses occurring because of fracturing of the openhole section give information on the fracture propagation pressure. Other parameters may be found from the local field setting and will be further discussed in the next sections. Collectively, the above parameters can be used to determine whether significant vertical movement parameters can be used to determine whether significant vertical movement of high-pressure hydrocarbons is likely to occur.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (4 more...)
Summary. Experiments to examine gas migration rates in drilling muds were performed in a 15-m [49-ft] -long, 200-mm [7.8-in.] -ID inclinable flow loop where air injection simulates gas entry during a kick. These tests were conducted using a xanthan gum (a common polymer used in drilling fluids) solution to simulate drilling muds as the liquid phase and air as the gas phase. This work represents a significant extension of existing correlations for gas/liquid flows in large pipe diameters with non-Newtonian fluids. Bubbles rise faster in drilling muds than in water despite in the increased viscosity. This surprising result is caused by the change in the flow regime, with large slug-type bubbles forming at lower void fractions. The gas velocity is independent of void fraction, thus simplifying flow modeling. Results show that a gas influx will rise faster in a well than previously believed. This has major implications for kick simulation, with gas arriving at the surface earlier than would be expected and the gas outflow rate being higher than would have been predicted. A model of the two-phase gas flow in drilling mud, including the results of this work, has been incorporated into the joint Schlumberger Cambridge Research (SCR)/BP Intl. kick model partly funded by the U.K. Dept. of Energy. Introduction The rate at which free gas rises up the wellbore has been identified as a key parameter in the development of a gas kick in a well. This paper reports a comprehensive experimental study into the two-phase paper reports a comprehensive experimental study into the two-phase flow characteristics that will occur in a well during drilling. These tests were conducted in a large vertical pipe using fluids with a rheology similar to that of drilling muds. Before this experimental study, some correlations existed for two-phase flow in circular pipes (usually small diameter) and annuli. Only very limited data were available for multiphase flows of non-Newtonian fluids. The experimental tests used a 200-mm [7.8-in.] -diameter, 12-m [39-ft] -long pipe. Because of operational reasons, a xanthan gum solution was used for the liquid phase whose behavior was rheologically similar to that of a genuine drilling mud. Data analysis techniques are also presented. The results of the gas/mud experiments are presented for the pipe geometry. Comparison between the results for gas/water flows (which are the basis of most existing kick simulators) and the gas/mud flows shows some quite striking differences. In this paper we review the existing literature in this field and describe the experimental facility used for the tests and the selection procedure used for the drilling mud analog. We compare the gas-rise velocities between air/water flows and air/mud flows. Finally, we present some results from the SCR kick simulator that demonstrate the importance of having an accurate gas-rise model. Gas/Liquid Flows Much of the two-phase flow literature is experimental and is based mainly on air/water flows in small pipes or annuli, as in the work of Aziz et al. Many authors have made theoretical studies, notably Zuber and Findlay, who derived a model that stated =CovH+vs, ....................................... (1) where = mean gas velocity and vs = gas-bubble slip velocity relative to a stationary fluid. The homogeneous velocity, vH, can be defined as VH = Qg + QL)/A, ............................... (2) where Qg and QL are the volumetric flow rates for the gas and liquid phases, respectively. They proposed that the coefficient Co was related to the distribution of bubbles an d their relative velocities across the pipe. If the gas is concentrated in the center of the pipe, where the liquid has its peak velocity, then the gas will be convected more quickly than the mean flux. By suggesting plausible velocity and void-fraction profiles, they showed that Co would range from 1.0 to 1.5. This observation was later supported with experimental results. Other authors have discussed the rise velocity of isolated bubbles in stationary columns of liquid. Wallis assumed Stokes flow both around and inside the bubble. Govier and Aziz carried this approach further. In air/water flows this approach is limited to bubbles of less than 2-mm [0.078-in.] diameter and is therefore of very little use here. Harmathy developed a correlation for experimental data to describe the rise of single, slightly larger, bubbles as a function of density difference and surface tension. This correlation, which is independent of bubble size, gives Vs = 1.53[g(pL - pG) /pL2] 1/4 ....................(3) where pL and pG=liquid and gas densities, respectively, and a = interfacial tension (IFT). For air and water, at 100-kPa [1-bar] pressure, this predicts a bubble velocity of 0.25 m/s [0.82 ft/sec]. pressure, this predicts a bubble velocity of 0.25 m/s [0.82 ft/sec]. For larger bubbles that almost fill the pipe, the slip velocity is limited by the rate at which the liquid phase will fall past the gas. Davies and Taylors considered inviscid flow around the bubble nose in order to evaluate vs. They derived the equation vs=0.35 g(PL-PG)d/pL,.............................. (4) where d=pipe diameter. This is normally referred to as the "Taylor" bubble velocity. It uses the pipe diameter as the scaling parameter. For a 200-mm [7.8-in.] -diameter pipe, this predicts a parameter. For a 200-mm [7.8-in.] -diameter pipe, this predicts a velocity of 0.5 m/s [1.6 ft/sec]. A number of vs models have been suggested for use in kick simulators that are based on these air/water flows. Most use Eq. 1 to model the flow, with v, calculated from a combination of Eqs. 3 and 4. Typical of these is the model proposed by Nickens, who assumed that Co = 1.0 for bubbly flow and Co = 1.2 for slug flow, with the flow regime determined by the void fraction F, where F=Ag/A......................................... (5) Flows with a void fraction of F less than25% were assumed to have a bubbly flow with vs from Eq. 3. For F>85% the gas transport was assumed to be entirely by Taylor bubbles, with vs calculated from Eq. 4. A linear transitional zone linked the two regimes. More representative geometries and fluids were used by Nakagawa and Bourgoyne, who reported tests made with air and water that used a 15-m [49-ft] -long, 150-mm [6-in.] pipe with a center body. Unfortunately, scatter in the experimental data makes it difficult to draw any realistic conclusions. Rader et al. studied the rise of gas swarms injected at the bottom of a vertical well but had little control on the gas injection conditions. Experimental Faculty The multiphase flow-loop test facility at SCR, Fig. 1, forms a universal multiphase flow test center. In the present test configuration, shown schematically in Fig. 2 and described in detail by Johnson and White, it has been used for gas/liquid flows, although solid/liquid and liquid/liquid flows can also be evaluated. SPEDE P. 257
- North America > United States > Louisiana (0.28)
- Europe > United Kingdom > England > Cambridgeshire > Cambridge (0.25)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.94)
Summary This paper analyzes well control for horizontal wells. It presents a computer model for predicting the pressure behavior in a horizontal well during gas-kick removal and analyzes the simulation results for several field conditions. The paper also analyzes the drillpipe-pressure schedule, the kick-tolerance concept, and the swabbing effect during tripping out of the hole. Introduction Horizontal drilling has quickly become one of the most successful technologies of the oil industry. During the past 5 years, this technology has proved to he an efficient means to improve production rates and recoveries. The importance of this technology is also confirmed by the large number of papers recently published on this topic. Although these papers discuss several aspects of horizontal drilling, one topic papers discuss several aspects of horizontal drilling, one topic remains unexplored: well control operations. This paper investigates the important aspects of well control for horizontal drilling. The first part of this paper describes a computational procedure to predict the pressure behavior in the annulus during a gas-kick circulation out of the well. The second part presents another comutational procedure for establishing the drillpipe-pressure schedule to be followed by the rig personnel during the displacement of the old mud by the kill mud. The third part discusses kick tolerance and its applications in horizontal wells. Finally, the paper presents a simplified theory for the swabbing effect during presents a simplified theory for the swabbing effect during tripping out of the hole and demonstrates the hazards of taking a kick during this operation. Horizontal Wells Fig. 1 shows the geometry of the example horizontal well. The well comprises three sections: the vertical, buildup, and horizontal Sections. The radius of curvature, r, of the 90deg. of arc of circle is defined by the buildup rate, Rbu: r=5729.58/Rbu....................(1) The length of the buildup section, Lbu, can be calculated by the following equation: Lbu=1.5708r.....................(2) In Fig. 1, the true vertical depth (TVD) is the sum of the vertical section length and the radius of curvature, and the total measured depth (MD) is the sum of the vertical, buildup, and horizontal lengths. MD's can easily be converted to vertical depths, or vice versa, with simple trigonometric relationships. Mathematical Model for the Annular Space This section describes a numerical procedure for modeling the pressure behavior inside the annular space of a horizontal well during pressure behavior inside the annular space of a horizontal well during gas-kick removal. With this numerical procedure in a FORTRAN computer program, it was possible to simulate many field conditions where pertinent drilling variables were varied to analyze their effects on pressure behavior. Later in this section, the results of the simulations are analyzed and discussed. Assumptions and Considerations. Previous studies have shown that if the gas-kick region is considered to be a plug or a single bubble, then predicted wellbore pressures will be unrealistically high. More realistic results are obtained when the gas-kick region is modeled by a two-phase zone. This study assumes that the gaskick zone is a two-phase mixture of gas and water-based mud flowing under unsteady-state conditions.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
Summary This paper summarizes the theory of using a practically oriented simulator to assess the mechanical stability of a wellbore in a triaxial, linearly elastic stress field. The model can be used to determine the range of mechanically stable well inclinations in a given formation and to produce mud-weight programs tailored to efficient and safe drilling, even in difficult conditions. In the Nelson discovery in Block 22/11 of the North Sea, the model was used to evaluate mechanical instability experienced during drilling of deviated appraisal wells through overpressured Oligocene shale. Simulation results showed that, within a range of drilling-mud densities, wells of any orientation can be drilled through the shale. However, practical considerations of formation heterogeneity, swab and surge pressures, and possible chemical interaction dictate that inclined wells beyond about 65ยฐ should not be attempted until more field data are acquired to enhance confidence in the use of the model in Block 22/11. Introduction Wellbore stability has always been fundamentally important in oil and gas recovery. Wellbore stability recently has become an area of intense study because of the need to drill highly inclined and horizontal wells. This need, which stems mainly from economic considerations (improved efficiency, reduced field development costs, development of marginal fields, etc.), has been encouraged by tremendous improvements in deviated-drilling technology. Assessments to date have shown that horizontal wells can increase production by as much as 300% compared with corresponding vertical wells, and increases in the ultimate hydrocarbon recovery are suggested. Wellbore instabilities are induced mechanically or chemically. Chemical problems arise from the interaction between the wellbore fluid and the formation and are beyond the scope of this paper. The principal mechanical problems are breakouts (or cave-ins), which result from insufficient fluid pressure in the wellbore, and tensile fracturing, which results from excessive wellbore fluid pressure. The threshold mud pressures for the onset of these two mechanisms depend on the in-situ effective stresses, the response of the formation material to a triaxial, stress field, and the field conditions. This paper summarizes a model for assessing the mechanical stability of wells that is based on classic rock-mechanics analysis and discusses its application to the Nelson field, Block 22/11. The model consists of a 3D elastic analysis of the effective in-situ stresses around a borehole in an isotropic formation, combined with the Hoek and Brown triaxial failure criterion. The well-established 3D elastic analysis has been incorporated in many other models. This model is unique because the failure criteria are derived from, or constrained by using, field data. Theoretical Considerations The mechanical stability of a wellbore can be quantified adequately with knowledge of the in-situ stress field and the material properties of the formation. The in-situ stresses in the formation are totally described by the three principal stresses, and the usual assumption made in geotechnical engineering is that these stresses are in the vertical and horizontal directions. It is also assumed that the vertical principal stress, sV, increases with depth and can be computed as the weight of the overlying vertical column of material. These assumptions, particularly true in areas of little or no tectonic activity and low topographic relief, have been validated by a collation of stress data from various countries. The minimum horizontal principal stress, sHmin is routinely determined in typical oilfield leakoff tests and fracturing operations. Experience has shown that a wide variability in the interpretation of leakoff test data exists, so caution must be exercised in the use of sHmin values derived in this manner. Owing to the uncertainties associated with the determination of the maximum horizontal principal stress, sHmax very few published values exist. The usual method for determining sHmax involves the use of hydrofracture stress-measurement theory and depends on the knowledge of sHmin and formation pore pressure, pp. The theory relates formation breakdown (fracturing) pressure, pc, and the uniaxial tensile strength, st, of the formation by Equation 1 where K, the poroelastic constant, has the approximate range 1 K 2, depending on formation permeability and compressibility. K = 2 is applicable to permeable formations where pc penetrates the pore spaces of the surrounding formation, and K=1 (very low permeability) recognizes the presence of pp in the surrounding pore space. When tests are performed during or soon after drilling, it can be, argued that K=1 is applicable because the formation of mudcake virtually precludes permeation of wellbore fluid into the formation. Hence, Eq. 1 reduces to Equation 2 For any wellbore pressure, pb, where pbc. Thus, the true value of sHmax is approached as pb increases, and the expression enables a least upper bound to be established for sHmax using the drilling-mud weights and wellbore pressures during leakoff and formation-integrity tests. The lower bound for sHmax is given by the sHmin trend with depth. The direction of sHmax is determined either from the fracture orientation at the wellbore after a fracturing operation1 or from analysis of wellbore breakouts. Seismological records in the area also provide estimates of stress direction. Induced Stresses Around a Wellbore. Given the in-situ stress magnitudes and direction, the formation properties, and the orientation of a wellbore, the induced stress field around the wellbore can be theoretically calculated under assumptions of linear elasticity and isotropic formation. Furthermore, knowledge of the in-situ fluid pressure allows the effective stresses around the wellbore to be derived. The equations are well known and presented elsewhere. Tensile Failure. The well-known minimum-principal-stress failure criterion is adopted for tensile failure. Failure is assumed to occur at the borehole wall when the local minimum principal stress in the borehole plane is reduced sufficiently to overcome the rock tensile strength. Induced Stresses Around a Wellbore. Given the in-situ stress magnitudes and direction, the formation properties, and the orientation of a wellbore, the induced stress field around the wellbore can be theoretically calculated under assumptions of linear elasticity and isotropic formation. Furthermore, knowledge of the in-situ fluid pressure allows the effective stresses around the wellbore to be derived. The equations are well known and presented elsewhere. Tensile Failure. The well-known minimum-principal-stress failure criterion is adopted for tensile failure. Failure is assumed to occur at the borehole wall when the local minimum principal stress in the borehole plane is reduced sufficiently to overcome the rock tensile strength.
- Europe > United Kingdom > North Sea > Central North Sea (0.71)
- North America > United States > Texas > Andrews County (0.61)
- North America > Canada > Alberta > Wetaskiwin County No. 10 (0.61)
- North America > Canada > Alberta > Ponoka County (0.61)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/6a > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/12a > Nelson Field > Forties Formation (0.99)
- (8 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- (3 more...)
Summary A comprehensive experimental wellbore model was built to simulate the multiphase flow of compressed air and sand that occurs in an air-drilling process. The model was designed to control the air volumetric flow rate and sand mass flow rate through a transparent annulus. The model also permitted observation of the sand and air in the annulus and allowed measurement of the pressure drop across the annulus. An empirical equation was developed for the minimum annulus pressure drop as a function of the sand mass flow rate through the system, the optimum annulus air velocity, the weight fraction of coarse sand particles entering the annulus, the weight fraction of coarse sand particles in the annulus, and solids loading in the annulus. The experimental results were compared with annulus pressures predicted by a semiempirical model of the air-drilling process pressures predicted by a semiempirical model of the air-drilling process developed by Angel. Angel's model failed to predict the observed minimum annulus pressure drops. In addition, the experimental results indicated that an annulus air velocity lower than the value assumed by Angel's model may be required. Introduction Air is a versatile drilling fluid often used in areas where hole conditions and economics do not permit the use of mud. Even though the costs of dusting, misting, and foaming are sometimes high, cost savings associated with a relatively high drilling rate of penetration (ROP) and avoiding such problems as lost circulation and formation damage often justify choosing an problems as lost circulation and formation damage often justify choosing an air-drilling technique over a mud-drilling operation. Because the costs associated with an airdrilling operation are often quite high, the goal of air-drilling optimization is to keep the total drilling expenditures to a minimum, even if mud drilling is uneconomical by comparison. For instance, if the airdrilling operation is overdesigned, drill cuttings are removed from the hole but money is lost on unnecessary equipment rental and excessive fuel and chemical consumption. On the other hand, if the operation is underdesigned, the hole is insufficiently cleaned and money is lost as the drilling ROP decreases and the number of downhole problems increases. problems increases. An optimized air-drilling operation is safe for drilling-rig personnel, nondamaging to the environment, and cost-effective. These personnel, nondamaging to the environment, and cost-effective. These goals are achieved by proper planning, appropriate equipment selection, and correct implementation of field procedures. Mathematical models for multiphase flow in an annulus are especially useful during the planning phase of an optimized air-drilling operation. These models are used to determine surface equipment needs. This information is then used to evaluate the economics of the drilling prospect. Only a few of these models exist, however, and they all make simplifying assumptions involving the effects of solids loading, solids size distribution, optimum annulus air velocity, minimum annulus pressure drop, particle/particle interaction forces, or the choking phenomenon. Consequently, a greater understanding of these effects is needed, especially their impact on surface equipment requirements. In addition, few multiphase annulus flow and pressure data are available to test the results of existing multiphase annulus flow models. The primary purpose of this work was to study these effects to understand better the physics of the air-drilling process and to develop an information base of experimental data for use in validating existing and future flow models. To accomplish these goals, a laboratory wellbore model was constructed to simulate the dry airdrilling process. This apparatus is briefly described later.
- Research Report > New Finding (0.65)
- Research Report > Experimental Study (0.50)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.92)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.89)
Summary. Shutting off high-pressure water flows and achieving good cement bonding during primary cementing has long been a problem experienced by operators. Corrosion, casing leaks, excessive water production, and contamination of freshwater aquifers have led to costly workover operations throughout the oil field, especially within the Permian Basin. Remedial cementing jobs are often expensive and unsuccessful when primary cementing techniques fail. Therefore, a cost-effective, engineered method for cementing off these water flows was developed. This paper describes the cementing techniques, well-control criteria, well preparation, and data evaluation. Use of new and existing cementing practices provided the flexibility necessary to handle variable well conditions. Preplanning, evaluation of produced waters, compatibility studies, and proper slurry design helped to eliminate poor cement jobs in many areas. If one works closely with service and rig personnel, the procedure can be accomplished quite effectively, even on wells in which unexpected water flows are encountered. Examples of the procedure are documented with proven field results under variable conditions. Introduction The need to shut off water flows during primary cementing is critical. Most regulatory agencies currently require protection of all freshwater zones and prohibit pressure on casing-string annuli. Casing corrosion, out-of-zone crossflow, mud contamination, and excessive hole washout are often the result of improperly cemented water flows. In most cases, improperly cemented water flows do not stop the actual flow and continue to act dynamically by channeling to other zones. Continual dissolution of salt zones and annular casing pressure typically result, often leading to casing corrosion and failure. These problems can increase drilling costs significantly and often require remedial cementing procedures. Experience in several areas has shown that remedial cementing work is expensive and time-consuming, especially when washed-out salt sections and corroded casing are involved. Existing methods for controlling water flows have met with limited success. The need to develop a simple, cost-effective procedure to handle a multitude of complications that can occur during cementing-including lost circulation, water-flow/cement incompatibility, and associated gas-was needed because these complications make most conventional cementing techniques impractical. Therefore, we decided to develop a cementing procedure that was similar to existing well-control methods to handle these procedure that was similar to existing well-control methods to handle these complications. Use of constant-bottomhole-pressure (BHP') well-control methods and sound cementing practices led to the development of a technique to control water flows during cementing. Review of Existing Procedures Over the years, several methods for controlling and cementing off water flows have been used. All have been used frequently, but their applications are limited and their success rates are poor. The most commonly used technique is the barrel-in/barrel-out method, which holds backpressure on the annulus during cementing. Water influx is limited by holding pressure on the annulus based on volume. Pressure is held with a choke so that the annular returns are equal to those of the cement and displacement mud pumped. The main problem with this technique is that it does not allow for gas expansion. In nearly all the cases studied, gas was present (mostly in small quantities) in the water flows. This can result present (mostly in small quantities) in the water flows. This can result in excessive backpressure and loss of circulation. In addition, if returns are lost while cementing with this procedure, the volume control is lost and no sound way of minimizing the water influx exists. Another common method of cementing water flows is to cement the well conventionally and then bullhead cement from surface down the annulus. This procedure usually results in good cement bonding above and below the water flow but none across it. Corrosion in the uncemented section is then accelerated and remedial cementing is often required. The use of external casing packers (ECP's) and multiple-stage cementing tools [more commonly called diverting valve (DV) tools] can minimize the uncemented area but do not actually shut off the water flow. Hence, the water flow results in the fracturing and flooding of the nearest permeable interval if the pressure is sufficient to fracture the zone. This is rarely a desirable alternative. Other problems associated with this procedure include cement contamination and formation breakdown above the procedure include cement contamination and formation breakdown above the water flow while bullheading. In several areas, regulatory agencies prohibit bullheading practices because of these problems. Other methods of prohibit bullheading practices because of these problems. Other methods of controlling water flows include openhole cementing and polymer squeeze jobs. Both have been used successfully but are often expensive and time-consuming. Also, success is very difficult to achieve in long washed-out intervals. As can be seen, all of these procedures have applications, but wellbore conditions are rarely ideal for their use. Hence, a cementing procedure to handle a multitude of wellbore conditions was required. Fracture-Gradients/Constant-BHP Procedures The planning process for wells in water-flow areas should include defining possible water-flow zones and their associated surface pressure and BHP. possible water-flow zones and their associated surface pressure and BHP. It also should include fracture gradients for zones that will be exposed before cementing. If this information is not available, we recommend that pressure-integrity tests be performed to +/-200 psi above the anticipated pressure-integrity tests be performed to +/-200 psi above the anticipated water flow surface pressure. Tests should be run at the previous casing shoe and at suspected weak zones. This procedure is not recommended for areas in which the formations do not heal after a leakoff is obtained. Determination of fracture gradients before the flow is encountered is very important because it will help to predict crossflow zones and to determine whether a two-stage cement job is required, The well should also be shut in after the flow is encountered to determine the actual pressures if well conditions are conducive to this practice. Many water flows are a direct result of water injection out of the intended zone in nearby wells. We recommend that injection wells in the vicinity of the subject well be shut down. This has helped to reduce the water-flow pressures and rates in some cases. We also advise a water-flow sample for compatibility testing. The water may pick up soluble minerals that can be incompatible with a particular cement system. If the water sample contains any chloride or magnesium, it should be tested in 5 to 25 % volume concentrations with the selected slurry because this concentration will most likely accelerate the setting process. Constant-BHP Procedures. Two constant-BHP methods were used to shut off water flows successfully during primary cementing operations. They are both simple and consistent with accepted well-control procedures. Each procedure requires some planning, but both are adaptable to several complications, such as loss of circulation and associated gas. SPEDE P. 191
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Casing and Cementing (1.00)