Gas Rises Rapidly Through Drilling Mud - DrillScience.com

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Gas Rises Rapidly Through Drilling Mud. J.A. Tarvin,* Schiumberger-Doll Research; A.P. Hamilton, Schlumberger Cambridge. Research; P.J. Gaynord, Anadrill ...
IADC/SPE 27499 Gas Rises Rapidly Through Drilling Mud J.A. Tarvin,* Schiumberger-Doll Research; A.P. Hamilton, Schlumberger Cambridge Research; P.J. Gaynord, Anadrill Schlumberger; and G.D. Lindsay, Sedco Forex Schlumberger 'SPE Member lADe Members Copyright 1994, IADC/SPE Drilling Conference. This paper was prepared for presentation at the 1994 IADC/SPE Drilling Conference held in Dallas, Texas, 15-18 February 1994. This paper was selected for presentation by an IADC/SPE Program Committee following review of inform~lion contai.n?d in an abstract submitted ~y the author(~). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International AssociatIon of Dniling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the IADC or SPE, their officers, or members. Papers presented at IADC/SPE meetings are subject to publication review by Editorial Committees of the IADC and SPE. Permission to copy is restricted to an abstract of not more than 300 wo!ds. illustrations may not be copIed. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083·3836, U.S.A. Telex, 163245 SPEUT.

ABSTRACT To understand the development of a gas kick, we must know the rate at which gas migrates upward through drilling mud. Migration rates measured in laboratory experiments are much greater than those commonly accepted by the drilling industry. To address this controversy, we use a computer simulator to model field data and test-well experiments in detail. Both the experiments and the field data show that gas migrates as fast as 6000 ftlhr [0.5 m/s] through drilling mud. The field data show that gas migration can drive surface pressure up as fast as 3000 psilhr [4.9 kPals]. These conclusions agree with laboratory experiments and contradict what is generally accepted in the industry. The results from the simulation of the field kick were incorporated in a case study. The study increases drill crew awareness of the speed at which gas can arrive at surface and demonstrates that a reduction in pump pressure can be a very late kick indicator. 1. INTRODUCTION Fluid that enters a well during drilling poses a danger to the well, the drilling rig, the environment and the crew. Gas kicks are particularly dangerous because gas reduces wellbore pressure more quickly than liquids do and because gas is more difficult to confine at the surface. Thus, gas kicks more often result in loss of well control and in surface fires and explosions. References and illustrations at end of paper. 637

Many mathematical models, or simulators, have been developed to improve detection and control of gas kicks. Past work has recently been reviewed. l These simulators require models of many physical processes in the wellbore. One of the most important of those processes is the buoyant migration of gas through drilling mud. Gas migration modifies the pressure distribution throughout the well during a kick and it determines the time when gas first reaches the surface. It is widely believed in the drilling industry that gas rises through drilling mud at 1000 ftlhr [8 cm/s] or slower, and even as slowly as 200 ftlhr [1.7 cm/s].2 Consequently, it is generally accepted that gas migration, on its own, cannot cause surface pressures to rise faster than a few hundred psi per hour. On the other hand, a variety of laboratory3-6 and test-we1l 3,7 experiments indicate that gas moves as fast as 6000 ftlhr. As a result, there should be some cases when gas migration drives pressure up at thousands of psi per hour. One would think that any (or all) fiel~ data could distinguish between these rates; but such IS not the case. The volume and composition of an influx are often uncertain; and poorly understood processes, such as loss of fluid to permeable formations or deformation of weak formations, also complicate the interpretation. To resolve this controversy, we must first realize that the experimeIits generally refer to gas volume fr~c­ tions exceeding several percent When the gas fracoon is 1% to 2%, or less, experiments show that gas moves slowly. More important is the fact that gas mi-

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GAS RISES RAPIDLY THROUGH DRILLING MUD

gration can seldom be determined directly from field data. Instead, gas migration rates are generally inferred from the rate of change of surface pressure. Johnson et at. 8,6 have shown that mud compressibility, fluid loss and wellbore compliance modify surface pressures substantially. Since the standard interpretation for surface pressures ignores these effects, it is usually invalid. In this paper, we present additional evidence that gas rises rapidly through drilling mud. Since gas easily dissolves in oil-base mud (OBM), it usually migrates slowly in OBM. The data and analysis presented here apply specifically to water-base mud (WBM). The evidence includes a field case and simulations of both field data and test-well experiments. Section 2 shows a field case that demonstrates directly that gas migrates as fast as laboratory experiments indicate. Section 3 discusses our simulation tools and methods. Section 4 gives results of the field case simulations and describes the use of the simulations in well-control training. Section 5 presents the results of simulations of the test-well experiments.

2. GAS VELOCITY FROM A FIELD CASE The field case occurred on a rig drilling in 120 m of water on the Mrican coast. The well was vertical with the geometry given in Table 2 and the mud density was 1170 kg/m 3 [9.8 Ibm/gal]. Shortly after a connection, both the flow out of the well and the pit level increased rapidly, as in Figure 1. Circulation was stopped briefly to check whether the well was flowing and the well was shut in just as gas reached the surface. The pit gain was 107 bbl [17 m3], with respect to the pit level measured during the preceding connection. Some mud was lost as gas blew it out of the drilling riser after the blow-out preventer (BOP) closed. The well was eventually brought under control with a kill mud density of 11.3 Ibm/gal [1350 kg/m3]. This field case is ideal for testing gas migration models, because both the start of the influx and the time of arrival of gas at the surface can be determined accurately and because the, kick lacks many of the features that complicate the interpretation of most kicks. From the timing of the kick, we can estimate the average gas velocity and compare it with predictions of gas migration models. Since the casing shoe was only 89 m above the bottom during the kick, wellbore deformation and fluid loss had minimal effect on the surface pressure. In this section, we show that the time for gas to reach the surface in this kick is consistent with laboratory measurements and is entirely inconsistent with a standard field model for gas migration. We can identify the start of the influx from the pit gain and the flow out of the well in Figure 1. Before 638

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the connection at 0 time, the flow out of the well was stable for at least 20 minutes. Since the kill mud stabilized the well, we estimate that the formation pore pressure was equivalent to a mud density of 1320 kglm 3. Since the pit level and flow out increased so rapidly, the producing formation had a high effective permeability. Although the pore pressure was 290 psi [2 MPa] greater than wellbore pressure, Figure 1 shows no flow out of the well during the connection. Therefore, the producing formation was entered after the connection and only a small quantity of gas could have been swabbed into the well during the connection. Mter drilling restarted, the flow into the well (not shown) reached 33 Us at 9 minutes and the flow out was the same at this time. However, the flow out increased by 10 Us in the next 90 seconds. Therefore, the influx started at 9.5±1 minutes. The driller's report indicates that gas reached the surface by the time the BOP closed at 24 minutes. Gas in the riser (above the BOP) continued to blow mud out of the well for some time. The time required for gas to travel the 1350 m up the well was, therefore, 14.5 minutes; and the average gas velocity Vg was 1.55 mls [18300 ft/hr]. We now compare the observed gas velocity with a correlation based on laboratory data 4 from Schlumberger Cambridge Research ("SCR correlation") and with the 1ooo-ft/hr rule of thumb generally accepted in the drilling industry. For either model, the velocity of the uppermost portion of the gas is (1)

where Vm is the velocity of the mud just above the gas and Co is a distribution factor. Co is 1.0 for the industry model and 1.35 for the SCR correlation. The slip velocity, vs, is 0.085 rnJs [1000 ft/hr] for the industry model; it depends on geometry in the SCR correlation, as shown in Table 2. Notice that these slip velocities are even greater than 0.5 m/s because the wellbore is more than 12 inches in diameter. It remains to estimate Vm from the pit gain and the flow into the well: v m -

Mud pumped + Pit Gain --:...---=-----Time . Area .

(2)

Note that Eq. (2) is an average from the start of the kick to the arrival of gas at the surface. The total mud pumped during the kick was 16.4 m 3. The measured pit gain, relative to the pit level during the connection, was 17.8 m3 . Since some mud was blown out of the well and not returned to the pits, the total quantity of mud expelled from the well was greater

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I.A. Tarvin, A. Hamilton, P. Gaynord and G.Lindsay

than the pit gain. However, most of that mud was lost after the BOP closed (i.e., after gas reached the surface). Consequently, the error in the time.avera~ed Vm is small. If we ignore the area change for the nser (this assumption overestimates Vm slightly), we find 34.2 m 3 v = 2 m 870 s . 0.0624 m

=0.63 m Is.

(3)

Thus, the SCR correlation gives a gas velocity of 1.48 mls and the industry model gives 0.72 m/s. When compared with the observed velocity of 1.55 mis, the SCR correlation is obviously much better than the industry model.

3. SIMULATION METHODS To simulate the field case and the experiments, we used the SideKick9 gas kick simulator. The technical content of this simulator has been described previously)O It has been used to analyze field cases ll and to aid well planning. 12 Status data required for a simulation include the well geometry and trajectory and physical properties of the mud and the producing formation. The model has four boundary conditions: inlet and outlet flow rate and inlet and outlet pressure. At each time, the user specifies two of these conditions. In some cases, the pressure or flow rate can be specified at an interior point instead of a boundary. The simulator then computes the flow rates and pressures throughout the well, including the boundary conditions not specified by the user. For most simulations, the specified boundary conditions are the outlet pressure (one atmosphere) and the measured inlet flow rate. When the well is shut in, the specified boundary conditions are the inlet and outlet flow rates (both zero). 4. FIELD CASE SIMULATION The geometry of the well and the drillstring are given in Table 2. The drilling-mud and formation physical properties are given in Table 3. The pore pressure of the producing formation is estimated from the fmal kill mud density used in the successful kill operation. Since the formation porosity isn't known, it was set at 15%; it has only a minor effect on the simulations. The purpose of this modeling exercise is to simulate closely the development of a kick and its shut-in period, using the SideKick simulator with its experimentally derived gas rise correlation. Since this correlation predicts rapidly moving gas, we refer to. this simulation as "Fast Gas." For the sake of companson, we repeat the simulation, with the simulator modified to use the industry standard figure for gas rise of 1,000 ft/hr. The second simulation is called "Slow 639

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~as. ': The input data for the. ~wo simulations ~re Idenuca! except for the permeab~l~ty of the gas b.earmg ~ormatlOn. The pe~meab~hty ~as .adJu.sted mdependently for each sImulatIon unul a pIt gam of 17 m 3 was achieved after 11 minutes .o! d~lling and 3 minutes of flow check. The permeabIhty IS the only free parameter used in the simulations. Figure 2 shows the measured choke press~re along with the simulation results. All three curves nse rapidly to about 700 psi. Since the measured pressure reaches that point much sooner than the simulations do, the actual effective permeability must be higher than the estimated. Mter 700 psi, the influx stops in the simulations and all curves increase more slowly than before. Even so, the field data and "Fast Gas" both continue to rise at about 3000 psi/hr. "Slow Gas," on the other hand, increases by only 600 psi per hour. With its higher gas migration rate, Fast Gas matches the data much better. Suppose the interpretation in the previous paragraph is wrong and that a continuing gas influx was driving the pressure up, even when the choke pressure reached 1200 psi. In that case, the bottom-hole pressure would still have been much less than the formation pressure (2530 psi), since the choke pressure was still rising rapidly. One can show from simple hydrostatics that such a small pressure difference between bottom-hole and choke requires a pit gain greater than 40 m3, which is more than twice the measured gain. The only reasonable conclusion is that the influx stopped when the choke pressure passed 700 psi and that rising gas drove the pressure up at a rate of 3000 psi/hr.

Case Study for Training Once the kick had been successfully simulated it was felt that a number of lessons should be learned to prevent a reoccurrence. A case study was chosen as the most effective means of disseminating the information in a manner that would be understood, and more importantly, remembered. In the case study, an instructor presents the students with background information on the well and the current drilling operations, including all the usual complications of drilling a real well. Then he describes the sequence of events leading up to the kick and the subsequent successful kill operation. The students then work in groups to look at the incident from the rig personnel viewpoint. The groups formulate their response to the situation and indicate any problems they find with the approach outlined ~n the case study. When the groups present theIr conclusions, they must justify them to the other teams, who are free to challenge any of the points raised. The instructor ensures that certain key points are discussed.

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The instructor then presents a summary of the incident with the benefit of the simulation results. The first thing the students are shown is a video recording of the real-time simulation screen. This clearly shows the surface indicators such as the pit gain and standpipe pressure along with a picture of the corresponding downhole situation during the drilling phase. The primary use of the simulation is to visually reinforce the points covered during the classroom discussion. The students can see, for example, that the well is kicking while the driller has the pumps stopped to investigate the loss in standpipe pressure. The driller had previously asked his assistant about an increase in pit gain but was told that a mud transfer was being carried out. He was not informed when the transfer was complete. He had had previous problems with washouts and assumed this was another one. As in many of these situations, it is a combination of events that lead to the kick remaining undetected for so long. The students can identify many ways to break this chain of events. They can also see that by the time a kick has caused noticeable decrease in standpipe pressure it is already well developed. Another item covered is the change in maximum allowable annular surface pressure (MAASP) caused by the combination of gas displacement during drilling and its migration after the well has been shut in. There was some concern at the rig site that the choke pressure was exceeding the MAASP immediately after the well was shut in. The students can see on the simulation that a large amount of gas is above the casing shoe at shut-in and that this continues to increase as the gas rises. The reduced hydrostatic pressure above the casing shoe allows a greater choke pressure before the shoe reaches its breakdown pressure. Figure 3 shows that the MAASP increased by 50% during the kick. Consequently, the choke pressure could increase to 400 psi above the pre-kick MAASP before there was danger of formation breakdown. The use of the simulation helps improve the students' understanding of downhole events and how they relate to what is seen at surface. It also helps reinforce the ideas covered in the group discussion.

S . TEST·WELL EXPERIMENTS

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the fraction to 3% for all simulations. This small quantity of oil changed the nitrogen solubility of the mud significantly and affected all simulations. The gas was injected through coiled tubing inserted inside the drillstring to the bottom of the well. Several injection procedures were used. In the best method, the desired quantity of nitrogen was injected into the tubing as a single slug, with plugs on each end to keep the gas separated from the mud in the tubing. More mud was then pumped into the tubing to displace the gas into the annulus. The pressure at the tubing head was held nearly constant during the gas displacement. . We have analyzed four WBM experiments that used this injection method, because the start and end of injection are clear. Each of the four experiments involved a different procedure after the gas injection. The key data from these experiments are the simultaneous pressure measurements at six depths in the annulus. The pressure difference between adjacent transducers changes abruptly when gas first enters the interval between them. Thus, plots of pressure differences are direct indicators of gas migration. Figure 4 shows a schematic drawing of the wellbore and a typical curve for the pressure difference. The depths of the six pressure transducers, with respect to the kelly bushing, are given in the Table 4 for each of the four experiments. Since the choke is above the kelly bushing, its depth is negative. To see the effects of the gas-migration relation, we have simulated the experiments two ways with SideKick. First, we used the standard gas-slip relation, which includes both a slip velocity and a distribution factor. The slip relation is derived from laboratory experiments6 and includes the effects of the well geometry and trajectory. The parameters in the relation have not been modified to match these experiments. A typical slip velocity for these experimental conditions is about 0.55 mls [6500 ftlhr]. Curves derived from this computation are labeled "Fast Gas." Second, we used a typical industry estimate of 0.085 mls [1000 ftlhr] for the slip velocity. Curves derived from that computation are labeled "Slow Gas. "

Experiment I

The test-well data come from the well-control experiments performed at Rogalands Research Institute l3 , where nitrogen gas was injected into a 15OO-m deep, cased well. The experiments were performed with both OBM and WBM. Since the OBM experiments were done first, the WBM contained some oil. Several measurements showed that the oil fraction was between 2% and 4% by volume. Since there is no reason why the oil fraction should have varied, we attribute the fluctuation to measurement errors and set 640

This is the largest of the four kicks, with 400 kg [880 Ibm] of gas injected. At bottom-hole conditions, the gas would displace 15.7 bbl [2.5 m 3]of mud. At the start of injection, the gas filled the whole coiled tubing string. At a given flow rate, the frictional pressure for mud is much higher than for gas. Since the pump pressure was nearly constant during injection, the flow rate into. the well decreased significantly as mud displaced gas in the tubing. Therefore, the gas injection rate was much higher than

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5

the average, initially. The measured flow rate out of the well confinns this change. In the simulations, we have used an injection rate that starts at 1.1 kg/s and then rapidly decreases to 0.2 kg/so Figure 5 shows the pressure difference Pb - P4 for Experiment I. All three curves drop sharply at 17 minutes when injection starts. The curves level off or tum upward when gas reaches P4. This event occurs at 24 minutes in the data and 23 minutes in the standard SideKick ("Fast Gas") model. The Slow Gas model is several minutes late. All the curves have jumps at 39 minutes when injection ended and the well was shut in. These jumps result from changes in frictional pressure that occur when the flow rate changes abruptly. Figure 6 shows the pressure differences in the next four intervals of the well. The Slow Gas simulation is obviously incorrect It has the gas arriving several minutes late in the P4 - P3 interval and 30 minutes late in the P3 - P2 interval. The gas does not reach the P2 - PI and PI - Pchoke intervals until circulation starts again at 130 minutes. The data clearly disagree with this simulation. On the other hand, the Fast Gas simulation has gas arriving within a few minutes of the correct time in all intervals. Preliminary simulations of this experimentS ignored the oil content of the mud and used a gas migration relation based on earlier experiments. 4 Thus, the results shown here differ somewhat from the preliminary ones; but the conclusions are the same.

for these flows, we find an average velocity of 0.50 mls for the gas relative to the mud. T\1is is six times the typical industry estimate, but it is only 10% less than the laboratory experiments indicate, even though the gas volume fraction was only a few percent. Although the Fast Gas simulation is better, neither simulation agrees well with all the data in this experiment. .The Fast Gas simulation accurately reproduces the pressure difference in the P4 - P3 interval, and it has gas arriving in the P3 - P2 interval at the correct time. Slow Gas is 10 minutes late in the P4 - P3 interval. It is equally late in the P3 - P2 interval, although the figure doesn't show it clearly. Both simulations have gradual changes in differential pressure between 17 and 30 minutes because the mud flow rate was decreased during that period. All the computed pressure changes in the P2 - PI and PI - Pchoke intervals result from small changes of mud flow. Thus, both simulations fail to reproduce the early arrival of gas in the upper portion of the well. It is clear that Slow Gas could never simulate the early gas arrival. but why doesn't Fast Gas do better? The reason is the relatively low gas concentration throughout the well. The uncertainty in the oil fraction results in a large relative uncertainty in the free gas fraction. In the Fast Gas simulation, the free gas fraction falls below the minimum required for the gas to move rapidly. It would be possible to match the data better if the oil fraction were reduced in the simulation.

Experiment II In this and subsequent experiments, approximately 141 kg [310 Ibm] of gas were injected. That much gas would displace about 5.5 bbl [0.9 m 3] of mud at bottom-hole conditions. Since most of the coiled tubing was filled with mud at the start of injection, the injection rate was nearly constant. Therefore, the injection rate was held constant during the simulations for Experiments II to N. In this experiment, circulation stopped when the injection finished and the gas rose into nearly static mud. Since the gas mass was relatively small, it spread out over most of the depth of the well. As a result, the gas concentration was small everywhere and the simulations are very sensitive to the oil concentration, which has a relatively high uncertainty. Figure 7 shows the data and simulations for experiment II. Gas injection started at 5 minutes and ended at 17 minutes. The data show that gas reached the P4 - P3 interval at 11 minutes and the PI - Pchoke interval at about 40 minutes. The gas traveled the 922 m interval from P4 to PI in 29 minutes. The average velocity was therefore 0.53 mls. However. during the first six minutes, mud flowed into the well at 39 gal/min and gas was injected at 25 gal/min. Correcting

Experiment III In this experiment, the circulation rate increased to 150 gal/min when the injection finished. Figure 8 shows the data and simulations. Injection started at 5 minutes and ended at 16 minutes. Fast Gas has gas arriving in each interval within two minutes of the time indicated by the data. However, the gas seems to fill the upper intervals too quickly. Slow Gas has gas arriving later and later as the gas moves up the well. The computed arrival in the highest interval is 16 minutes late. Note that the circulation reduced the length of the experiment to 45 minutes and consequently decreased the difference between the simulations.

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Experiment IV In this experiment, the circulation rate increased to 320 gal/min when the injection finished. Figure 9 shows the data and simulations. Injection started at 12 minutes and ended at 23 minutes. Significant changes of mud flow rate occurred at 23, 36 and 44 minutes. Pressure changes at those times result from frictional pressure and should be ignored. In the simulations of this experiment, the specified boundary conditions were the inlet flow rate and the measured bottom-hole pressure. Fast Gas has gas arriving in each interval

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GAS RISES RAPIDLY THROUGH DRILLING MUD

within three minutes of the time indicated by the data. Slow Gas has gas arriving later and later as the gas moves up the well. The computed arrival in the highest interval is about 12 minutes late. Once again, the circulation reduced the length of the experiment and decreased the difference between the simulations. However, it is still clear that Slow Gas is much too slow.

Summary of Test-Well Experiments In each of the four experiments discussed above, the Fast Gas simulation is superior. If gas really does move fast, then why do surface pressures seem to imply that gas moves slowly? Johnson et al. 8 ,6 have shown that wellbore compliance and fluid loss reduce the rate of pressure increase. Here, we show that surface pressures can rise rapidly during shut-in. Figure 10 shows the choke pressure in Experiment I. During the first five minutes of shut-in, the measured pressure increases at the same rate as in the Fast Gas simulation. Thereafter, the measured pressure rises somewhat more slowly, but still far more rapidly than in the Slow Gas simulation. Eventually, the pressure stops changing because most of the gas is at the top of the well. In the Slow Gas simulation, none of the gas has reached the top of the well by the end of shut-in at 130 minutes. There is no doubt that gas moved rapidly in these experiments. 6. CONCLUSIONS A field case and four test-well experiments are all consistent with gas migration rates derived from laboratory experiments. All five comparisons show that the migration rates generally accepted in the drilling industry are much too low. If a driller believes that gas rises more slowly than it really does, he may overestimate the casingshoe pressure and the gas will arrive at the surface sooner than he expects. The driller may not be prepared when the gas surfaces, or he may misinterpret pit-level and pressure measurements. These errors can have serious consequences during a critical operational procedure. ACKNOWLEDGMENTS The authors are grateful to the United Kingdom Health and Safety Executive for supporting development of the R-model gas kick simulator from which SideKick was developed, and to Paul Sonnemann for helpful discussions. REFERENCES 1. Element, D.E., Wickens, L.M. and Butland, A.T.D.: "An Overview of Kicking Well Com-

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2. 3. 4. 5.

6. 7. 8.

9. 10. 11.

12. 13.

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puter Models," Int. Well Control Symposium, Louisiana State University, Nov. 27-29, (1989). Blount, E.: "Executive Summary," SPE Drilling Engineering 6, (1991) 236. Rader, D.W., Bourgoyne, A.T. and Ward, R.H.: "Factors Mfecting Bubble Rise Velocity of Gas Kicks," JPT (May 1975) 571-585. Johnson, A.B. and White, D.B.: "Gas Rise Velocities During Kicks," SPE Drilling Engineering 6 (1991) 257. Skalle, P., Podio, A.L. and Tronvoll, J.: "Experimental Study of Gas Rise Velocity and its Effect on Bottomhole Pressure in a Vertical Well," SPE 23160 (1991). Johnson, A.B. and Cooper, S.: "Gas Migration Velocities During Gas Kicks in Deviated Wells," SPE 26331 (1993). Hovland, F. and Rommetveit, R.: "Analysis of Gas-rise Velocities from Full-scale Kick Experiments," SPE 24580 (1992). Johnson, A.B. and Tarvin, J.A.: "Field Calculations Underestimate Gas Migration Velocities," IADC European Well Control Conf. (1993) and Oil & Gas J., November 15 (1993) 55-60. Hamilton, T.A.P., Swanson, B. and Wand, P.: "Use of New Kick Simulator Will Increase Wellsite Safety," World Oil (Sept. 1992). White, D.B. and Walton, I.e.: "A Computer Model for Kicks in Water- and Oil-Based Muds," SPE 19975, (1990). Tarvin, J.A., Walton, I., Wand, P. and White, D.B.: "Analysis of a Gas Kick Taken in a Deep Well Drilled with Oil-based Mud," SPE 22560 (1991). Leach, C.P. and Wand, P.A.: "Use of a Kick Simulator as a Well Planning Tool," SPE 24577 (1992). Rommetveit, R. and Olsen, T.L.: "Gas kick Experiments in Oil-based Muds in a Full-scale, Inclined Research Well," SPE 19561 (1989).

Table 1. Units conversion SI Units m kg m3 L MPa lO00kwm 3

factors Equivalent Customary Units 3.281 ft 2.205 Ibm 6.29 bbl. 0.2642 USgal 145 PSI 8.35 Ibm/USgal

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Riser Drillpipe Casing Drillpipe Casing Heavy Pipe Casing Drill Collars Openhole Drill Collars

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I , , , ,I, , ,

80

100

Time (min) Figure 5. Pressure difference in the bottom interval for Experiment I.

I

I

I

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,

,

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140

Figure 4. Test-well schematic. The pressure difference between adjacent transducers changes when gas first passes the lower transducer. en

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Time (min) Figure 6. Pressure differences for Experiment I.

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Time (min) Figure 8. Pressure differences for Experiment III.

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.

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Time (min) Figure 9, Pressure differences for Experiment IV,

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450

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Time (min)

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Time (min)

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. 50

I~

N -...l ~

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I.A. Tarvin, A. Hamilton, P. Gaynord and G. Lindsay

SPE 27499 1000

...,..,..,-r-'I""""I'..,..,I""'I"".,........,..I"'"'I"'.,....,..,..,...,..,..,I""'I"".,........,..I"'"'I"'.,....,..,..,...,..,..,~

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200

i

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o

20

40

60

80

100

Time (min) Figure 10. Shut-in choke pressure for Experiment I.

649

120

140

13