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Energy & Fuels 2005, 19, 1037-1046

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Seven-Spot Steam Injection Experiments in Heavy Oil Reservoirs Having a Bottom Water Zone Suat Bagci Department of Petroleum and Natural Gas Engineering, Middle East Techncial University, Ankara, Turkey Received October 11, 2004. Revised Manuscript Received February 14, 2005

A 3-D scaled physical model was used to compare the performance of steam injection in reservoirs having a bottom water zone with the application of different well configurations. The model was triangular, designed to represent 1/12 of a seven-spot pattern in the Batı Kozluca field in Turkey. Nine experiments were conducted by using the triangular model with or without a bottom water zone. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effects on oil recovery. The physical properties of a crushed limestone and crude oil (12.4° API) mixture were kept constant during the experiments. Steam was injected through a vertical well. Strings of thermocouples were used to observe the 3-D temperature distribution inside the model. The maximum oil recoveries were obtained by placing the horizontal producers along the hypotenuse of the triangular model. This well configuration provided better oil recovery than any other well configuration, even in the presence of a bottom water zone. Oil recoveries decreased with an increase in the thickness of the bottom water zone. The steam-oil ratio increased in the presence of bottom water.

Introduction Thermal recovery methods are widely known and applied worldwide for secondary and tertiary oil recovery. Of all the thermal recovery methods, steam injection is the most popular. Following steam injection into any heavy oil reservoir, the viscosity, specific gravity, and flow resistance of the fluid in the reservoir changes, resulting in oil production increases. The reduction in the viscosity, as a result of an increase in the temperature, facilitates the movement of the heavy oil. Because of their numerous advantages, horizontal wells have gained attention in the petroleum industry.1,2 Horizontal wells provide larger contact within a reservoir and, hence, eliminate the need for multiple vertical wells to acquire the same reservoir drainage. Recovery is 2-5 times greater than that of a nonstimulated vertical well. In the case where vertical penetration of the formations would be uneconomical, drilling of the horizontal well would render a sufficient well bore opening and the possibility of a more economic recovery. Horizontal wells in a reservoir in which coning of water and gas are predominant provide a better oil recovery while the coning effects are minimized. Horizontal wells sweep more oil in fractured reservoirs due to their better scope for intersecting the voids and fractures. Steam override is a common phenomenon in steam injection processes. Steam rises to the formation top and sweeps the upper portion of the reservoir. The lower portion is (1) Butler, R. M. The Potential for Horizontal Wells for Petroleum Production. J. Can. Pet. Technol. 1989, 28 (3), 39-47. (2) Joshi, S. D. A Review of Horizontal Well Technology. Presented at the 1986 Tar Sand Symposium; Report No. DOE/METC-87/6073, 112-131, 1986.

primarily swept by condensate. Consequently, zones of high oil saturation occur in the lower portion of the reservoir after a steam flood. Horizontal wells used in combination with vertical wells can provide a way to improve the overall sweep efficiency, and can help to drain such oil zones if the horizontal wells are placed at the bottom of the water zone. In Turkey, 80% of the oil reservoirs are heavy-oil reservoirs.3 These heavy oils are usually mobile under reservoir conditions and most can be produced with primary production but recovery is very low. Because of the amount of heavy oil in reserves, it was decided to study the effect of steam with various well configurations on the recovery of Batı Kozluca heavy oil under laboratory conditions. The reservoir has 138 million STB of crude oil of 12.4°API gravity. The reservoir is a simple anticlinal type with an average thickness of 37.5 m and a depth of 1500 m. The study was performed to analyze the effects of diverse well configurations and bottom water zone thicknesses on the recovery of heavy oil by continuous steam injection in a 3-D scaled model. Literature Review Horizontal wells have been successfully used in conjunction with steam drive, cyclic steam stimulation, and steam-assisted gravity drainage to produce oil from heavy-oil and tar-sand reservoirs. The effects of bottom water zone and steam injection on horizontal wells (3) Kanta, K.; Topkaya, I. Development of Oil and Natural Gas Resources and Prospects of Enhanced Oil Recovery in Turkey; Report, Turkish Petroleum Corp., 1983, p 21.

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during the recovery of heavy oil have not been investigated until recently. Therefore, only a limited amount of laboratory and field data are available in the literature. The first instance where steam was injected into an underlying water sand was in the case of the Slocum field in northeast Texas. However, despite the high oil saturation (65%), the large quantities of steam required for the process reduced the profitability of the project.4 Prats5 included a bottom water zone in his studies to model Shell’s Peace River formation. In his tests, the bottom water zone had a high initial fluid mobility that allowed him to inject steam into the model. Pursley6 used a scaled model of the Cold Lake reservoir (100 000 mPa s at 13 °C) to examine the effect of steam injection into a thin bottom water layer (15% PV) and an overlying gas zone (2.5% PV). It was concluded that the tendency of steam override was responsible for the high recovery obtained in the bottom water case, because it enabled steam to contact a greater portion of the sand. Further, a steam drive through a basal water sand appeared to be feasible only if the vertical permeability was high and if heating close to the base of the oil sand could be effected. Ehrlich,7 and Huygen and Lowry8 performed steamflooding experiments through a simulated bottom water layer in scaled laboratory models of the Wabasca formation (5 × 106 mPa s at 13 °C). High recovery was achieved as a result of convective and conductive heating of bitumen due to steam flow through the bottom water zone. In all cases, bottom water provided the initial injectivity path for steam in viscous oil sands. Doscher and Huang9 investigated steam-flood performance through a thin bottom water zone (15% of total pay). Their studies indicated that while steam initially advanced through the basal sand, continued injection caused the oil to drain down and be carried through the water zone. Eventually, with continued steam injection, steam override occurred. Contrary to previous studies, increasing the steam injection rate did not result in a monotonic increase in the steam-oil ratio at any given recovery factor. In fact, they concluded that there was a critical injection rate above and below which steamflood performance decreased. Proctor et al.10 studied steam injection strategies for thin bottom water reservoirs in a scaled physical model. They showed that the effect of bottom water is small for some minimum bottom water thickness (10% gross thickness). Kaleli (4) Hall, A. L.; Bowman, R. W. Operation and Performance of the Slocum Thermal Recovery Project. J. Pet. Technol. 1973, 25, 402-408. (5) Prats, M. Peace River Steam Drive Scaled Model Experiments. Presented at 28th Annual Technical Meeting, Edmonton, Alberta, 1977. (6) Pursley, S. A. Experimental Studies of Thermal Recovery Processes. Presented at the Symposium on Heavy Crude Oil, Maracaibo, Venezuela, 1974. (7) Ehrlich, R. Laboratory Investigation of Steam Displacement in the Wabasca Grand Rapids ‘A’ Sand. Presented at the 28th Annual Technical Meeting, Edmonton, Alberta, 1977. (8) Huygen, H. A.; Lowry, W. E., Jr. Steamflooding Wabasca Tar Sand through the Bottom Water ZonesScaled Lab Experiments. SPE Paper No. 8398, Presented at the 54th Annual Fall Technical Conference and Expo, Las Vegas, Nevada, 1979. (9) Doscher, T. M.; Huang, W. Steam-Drive Performance Judged Quickly from Use of Physical Models. Oil Gas J. 1979, 52-57. (10) Proctor, M. L.; George, A. E.; Farouq Ali, S. M. Steam Injection Strategies for Thin, Bottom Water Reservoirs. SPE Paper No. 16338, Presented at the SPE California Regional Meeting, Ventura, California, 1987.

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and Farouq Ali11 studied the impact of bottom water zones on bitumen mobilization under cold conditions. They concluded that a bitumen-to-water zone thickness ratio of about 5 resulted in the best performance. Kasraie and Farouq Ali12 examined heavy oil recovery in the presence of bottom water using a numerical simulator. They concluded that thick water zones delayed the steam-flood response and consequently reduced process profitability. Singh et al.13 conducted a numerical study of a heavy reservoir with a bottom water zone. They reached similar conclusions regarding the water zone thickness as Kasraie and Farouq Ali.12 Sufi14 conducted a steam-flood test using a basal water zone. Hot water had to be circulated at a high rate for an extended period to increase the temperature and hence the effective flow capacity of the zone. The bottom water zone corresponds to the higher water saturated zone placed in the physical model. After a period of hot water injection, a high-temperature, lowoil saturated zone is created at the base. Because hot water is flowing through this zone, conductive heating allows some of the overlying tar sands to be heated. When injection is converted to steam, the injected vapor flows upward. This upward movement of steam is toward the region heated by conduction. The oil from this region drains down into the basal zone and toward the production well. The area above the steam zone is heated by conduction, which allows further counterflow of oil and steam. It uses the density difference between the oil and the steam to effectively heat a large part of the reservoir from a thin, higher water-saturated zone located at the base of the pay. Chang et al.15 investigated steam injection in a scaled laboratory model with the application of four different well configurations and two bottom water thicknesses to recover Saskatchewan heavy oil. Their results showed 68% oil was recovered by horizontal-horizontal combinations in the presence of 10% thickness of high water saturation. However, recovery was slightly better with horizontal wells than with vertical wells in the absence of bottom water. With a bottom water of 50% of model thickness, the recovery decreased about 20% in all four configurations. Suguianto and Butler16 performed steam injection experiments in a two-dimensional scaled reservoir model with a bottom water zone. The aim was to examine the effects of steam producers on oil recovery. Their results also revealed the decrease in oil recovery with the increase in the thickness of the bottom water zone. Moreover, an efficient recovery was observed when the producers were positioned at the oil-water contact. (11) Kaleli, M. K.; Farouq Ali, S. M. Mobilizing Bitumen under Reservoir Conditions. SPE Paper No. 16742, Presented at Annual Technical Meeting, Dallas, Texas, 1987. (12) Kasraie, M.; Farouq Ali, S. M. Heavy Oil Recovery in the Presence of Bottom Water. Paper No. 84-35-122, Presented at 35th Annual Technical Meeting, Calgary, Alberta, 1984. (13) Singh, B.; Malcolm, J. D.; Heidrick, T. R. Injection-Production Strategies for Reservoirs Having a Bottom Water Zone. SPE Paper No. 13623, California Regional Meeting, Bakersfield, California, 1985. (14) Sufi, A. H. Injectivity Enhancement in Tar SandssA Physical Model Study. J. Can. Pet. Technol. 1992, 28 (1), 63-74. (15) Chang, H. L.; Farouq Ali, S. M.; George, A. E. Performance of Horizontal-Vertical Well Combinations for Steam Flooding Bottom Water Formations. J. Can. Pet. Technol. 1992, 31 (5), 41-51. (16) Suguianto, S.; Butler, R. M. The Production of Conventional Heavy Oil Reservoirs with Bottom Water Using Steam-Assisted Gravity Drainage. J. Can. Pet. Technol. 1990, 29 (2), 78-86.

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Nasr and Pierce17 conducted a series of experiments on steam-CO2 injection strategies in a high-temperature, high-pressure scaled model to evaluate oil recovery processes for bottom water reservoirs. The co-injection of CO2 with steam accelerated and improved oil recovery rates as compared to steam only injection. The steamCO2 continuous injection resulted in a better performance than that from steam only or steam-CO2 sequential injection. Steam-only injection resulted in a dramatic improvement in oil recovery as compared to hot water-CO2 injection. Soaking the reservoir with carbon dioxide prior to steam injection reduced steam injectivity due to blocking of the bottom water zone with a high viscosity oil. Wong et al.18 provided a field review of the Pikes Peak steam project, showing key performance indicators of cyclic steam stimulation and steam drive in non-bottom water. To test development over relatively thin bottom water (less than 5 m), various steam processes were field-tested. On the basis of field experience and numerical simulation input, cyclic steam stimulation has been successfully conducted with economic steam-oil ratios in areas with up to 4 m of bottom water by injecting significantly larger steam slugs in what is termed a drive, block, and drain process. In thicker bottom water, the ability to operate at constant pressure to prevent bottom water influx confers an advantage to the horizontal well approach. Combinations of vertical and horizontal wells and cyclic steaming and steam flooding are being employed to minimize the impact of bottom water and also maintain a low steam-oil ratio. Rodriguez and Darche19 investigated an innovative thermal production scheme, named the “horizontal alternate steam drive (HASD)” process, to improve the recovery of mobile heavy oils in the presence of bottom water aquifers. They simulated the performances of HASD using simulation results on simple 2D homogeneous models. Using 3D simulations, HASD increased the oil recovery in the presence of moderately connected aquifers, as compared to natural depletion, and could even improve the performances obtained by more standard thermal processes such as SAGD (steam-assisted gravity drainage). Scaling of 3-D Model Scaled model studies are useful for clarifying and defining optimum well configuration and operating conditions for steam injection. The scaling of the 3-D model was performed by employing the formulas developed by Pujol and Boberg.20 The model selected for the tests was a hypothetical heavy oil reservoir drilled in a repeated seven-spot pattern. Figure 1 shows the element (17) Nasr, T. N.; Pierce, G. E. Steam-CO2 Recovery Processes for Bottom Water Oil Reservoirs. J. Can. Pet. Technol. 1995, 34 (7), 4249. (18) Wong, F. Y. F.; Anderson, D. B.; O’Rourke, J. C.; Rea, H. Q.; Scheidt, K. A. Meeting the Challenge to Extend Success at the Pikes Peak Steam Project to Areas with Bottom Water. SPE Paper No. 71630, Presented at the SPE Annual Technical Conference and Expo, New Orleans, Louisiana, 2001. (19) Rodriguez, J. R.; Darche, G. An Innovative Thermal Production Scheme for Mobile Heavy Oil Reservoirs with Bottom Aquifer, SPE Paper No. 84031, Presented SPE Annual Technical Conference and Exhibition, Denver, Colorado, 2003. (20) Pujol, L.; Boberg, T. C. Scaling Accuracy of Laboratory Steamflooding Models. SPE Paper No. 4191, Presented at California Regional Meeting, Bakersfield, California, 1972.

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Figure 1. Element of symmetry for physical model. Table 1. Scaling Parameters (from Pujol and Boberg20) property distance between injection and production wells thickness permeability porosity temperature oil viscosity injection rate pressure drop time a

scaling parameters

ratio (model/field)

Lp/Lm ) aa

250

Hp/Hm ) a Kp/Km) a same same same Qp/Qm ) a ∆Pp/∆Pm ) a tp/tm ) a2

250 250 1 1 1 250 250 (250)2

a is a scaling factor. Table 2. Properties of Scaled Model and Prototype Reservoir

prototype reservoir properties 1/ pattern 12 of seven-spot distance between inj and prod. wells 202.5 m reservoir thickness 25.0 m gross reservoir thickness 37.5 m reservoir permeability 40 mdarcy reservoir porosity 25.4% reservoir temperature 50 °C oil viscosity (at 50 °C) 850 cP oil injection rate 14.4 m3/day pressure drop 3447.5 kPa time 43.4 days model properties type pattern distance between inj and prod. wells model thickness permeability porosity temperature oil viscosity (at 50 °C) oil injection rate pressure drop time

triangular 12 of seven-spot 0.81 m 0.10 m 10.0 darcy 38.0% 50 °C 850 cP 40.0 cm3/min 20.7 kPa 1 min 1/

of symmetry used for the scaled model. The scaling parameters used in this study are given in Table 1. The model used to carry out experiments represents 1/12 of an inverted seven-spot pattern in the B. Kozluca field in Turkey. A scaling factor of 250 was assumed reasonable for scaling the size of the physical model in the lab (i.e. 1 cm in the lab correspond to 2.50 m in the field) and a corresponding fcator of 2502 for the time required to perform the experiment (i.e. 8.4 min in the lab correspond to one year in the field). A length ratio of 250 between the prototype and model was selected. This required that the distance between wells in the model

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Bagci Table 3. Packing Data and Experimental Conditions steam injection

run no.

well configa

So (%)

rate bottom water Sw (cc,cwe/ pressure thickness (%) min) (kPa) (cm)

STBW-1 STBW-2 STBW-3 STBW-4 STBW-5 STBW-6 STBW-7 STBW-8 STBW-9

VI-VP VI-VP VI-VP VI-HP(s) VI-HP(s) VI-HP(s) VI-HP(h) VI-HP(h) VI-HP(h)

75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0 75.0

25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0

38.0 39.0 54.5 55.0 47.0 98.5 44.0 45.0 54.5

248 207 193 338 234 290 275 234 234

0.0 1.0 2.5 0.0 1.0 2.5 0.0 1.0 2.5

a V ) vertical, H ) horizontal, I ) injection, P ) production, (s) ) short perpendicular arm, (h) ) hypotenuse.

Figure 2. Well configurations.

be 81 cm and that the sand thickness in the model be 10 cm. The properties of the scaled model and their corresponding prototype are shown in Table 2. The well configurations in the model as used during the course of study are shown in Figure 2. Experimental Procedures A schematic diagram of the experimental setup is shown in Figure 3. The experimental apparatus consisted of four components: (1) a steam injection system, (2) a 3-D scaled model, (3) a fluid production system, and (4) a measuring and control system. The triangular model has dimensions of 81 cm × 69 cm × 10 cm. The model is made of steel with a thickness of 3 mm. The top of the model is removable and acts as a flange so that crushed limestone, oil, and water mixtures can readily be packed in the model. Perforated, 8 mm diameter, stainless steel tubing was used for the injection and production wells. Several 3 mm diameter holes were drilled along the length of the tubing and were covered with 100 mesh metal screen to prevent sand production. To measure the three-dimensional

Figure 3. Schematic diagram of the experimental setup.

temperature distribution inside the triangular model, 62 thermocouples were installed at the top, center, and bottom planes of the model. To compensate for heat loss from the model, it was wound with band heaters. Moreover, the gap between the model and the isolation box within which the model was placed was insulated by glass wool to attain a near adiabatic environment. The fluid production system consists of high- and low-pressure separators that were connected to the production end. Temperature data were gathered by digital temperature scanner and computer in the measuring and control system. External band heaters were controlled by heater controllers to heat the model up to a reservoir temperature of 50 °C. Injection and production pressures throughout the experiments were recorded with the help of pressure gauges at the injection and production end. At first, the wells were installed in the 3-D model according to the desired configurations shown in Figure 2. The premixing method was used in preparing the unconsolidated limestone pack mixtures for the experiments. The water, clean crushed limestone, and 12.4°API crude oil were mixed homogeneously to yield the desired fluid saturations and carefully packed into the models. The oil and water saturations were chosen as 75% and 25%, respectively, and kept the same for each experiment. The packing data and experimental conditions are shown in Table 3. The porosity and the permeability of the porous media were kept constant for each experiment. The crushed limestone consists of 92% calcite, 6.6% dolomite, and 1.4% quartz by weight, and the grain size ranges from 0.42 to 1.19 mm. A new limestone pack was used for each run in order to avoid uncertainties associated with cleaning procedures.

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Figure 4. Viscosities of Batı Kozluca crude oil. Table 4. Experimental Results

a

run no.

well configa

bottom water thickness (cm)

STBW-1 STBW-2 STBW-3 STBW-4 STBW-5 STBW-6 STBW-7 STBW-8 STBW-9

VI-VP VI-VP VI-VP VI-HP(s) VI-HP(s) VI-HP(s) VI-HP(h) VI-HP(h) VI-HP(h)

0.0 1.0 2.5 0.0 1.0 2.5 0.0 1.0 2.5

SOR

steam breakthrough

ultimate oil recovery (% OOIP)

oil recovery (% OOIP)

7.07 6.22 14.39 6.46 7.89 23.84 3.26 6.22 11.91

25 24 22 42 31 22 43 30 23

42.1 31.9 18.4 54.9 35.7 18.7 73.2 42.2 32.5

27.8 31.6 18.3 31.7 28.5 11.0 62.0 33.9 23.5

V ) vertical, H ) horizontal, I ) injection, P ) production, (s) ) short perpendicular arm, (h) ) hypotenuse.

At the end of the packing operations, thermocouples were inserted at the top, center, and bottom planes of the model. The model was placed inside the insulation box and the necessary electrical and mechanical connections were made. Prior to steam injection, the model was heated with the aid of band heaters until the temperature inside the model reached 50 °C. The temperature distribution inside the model was recorded every 10 min during each experiment. The other parameters that were recorded during the experiments were steam injection pressure, production pressure, temperatures at the inlet and outlet ends, and oil and water production data. The viscosity of B. Kozluca oil is shown in Figure 4.

Results and Discussions A total of nine experiments were carried out. Six experiments were conducted in the presence of a bottom water zone of two different thicknesses: one was 10% and the other was 25% of the total model thickness. The remaining three experiments were performed in the absence of a bottom water zone. Both vertical and horizontal producers were used in each group of experiments to recover oil, whereas only vertical injectors were used for steam injection. The horizontal producers were placed along the hypotenuse and short perpendicular arm of the triangular model. Experimental results of each experiment are shown in Table 4. Temperature Profiles. After achieving a uniform temperature of 50 °C inside the model, steam was

injected through a vertical injector. Temperature data were taken from three levels, top, center, and bottom, of the model every 10 min. Two-dimensional temperature contours were drawn along the horizontal midplane and along the vertical cross-sectional plane taken diagonally in the model. The vertical cross-sectional plane was taken near the longest side of the triangular model. In the model, when there is no bottom water, steam starts moving upward as soon as it is injected inside the model, which can be attributed to steam override. But this gravity override phenomenon becomes less severe in the course of time, as the steam moves downward at later times. Effective heating occurred after steam breakthrough in the vertically downward direction along the model, indicating steam-zone enlargement. Steam override is reduced in the presence of horizontal producers, which implies the creation of a downward flow field by horizontal producers. The temperature profiles along the vertical cross-sectional plane in Figure 5 show that the growth of temperature contours is more uniform in the model. Though the overriding of steam is apparent in the model, it exhibits a better flow geometry for the flowing fluid as observed in the areal temperature distribution along the horizontal midplane. The overall temperature level inside the model was observed to be higher during the experi-

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Figure 5. Temperature distribution in the model without a bottom water zone (VI-VP).

ments with horizontal producers and the duration of gravity override inside the models was much shorter in these experiments. Due to their larger areal contact, horizontal producers remove oil faster, and as a result, steam readily enters in the swept area. Therefore, steam override was reduced by employing horizontal producers. In the presence of an underlying bottom water zone, the growth of temperature contours along the center plane in all experiments was more erratic. Steam override was greatly reduced by the counteraction of the bottom water against the gravity effect of the steam. A decrease in the temperature levels at the top of the model was observed, and the bottom of the model showed a greater increase in the temperature levels than the experiments run in the absence of an underlying water zone. The rapid steaming of bottom water and greater mobility compared to oil resulted in a nonuniform temperature distribution inside the model, as shown in Figures 6 and 7. In addition to its thermal quality, steam flooding is a relatively stable process21 due to both fluid convection and thermal conduction effects. The first stabilizing influence is the higher volumetric vapor flow rate in the steam zone compared with the liquid flow rates ahead of the steam front. The second stabilizing effect, thermal conduction, tends to collapse irregularities at the front of the steam zone because of heat losses normal to the direction of fluid flow. Although the equipment was designed to minimize the problems related to heat losses, it is difficult to eliminate entirely heat losses. Temperature distributions during the experiments indicated that steam essentially stayed at the top of the model. At the end of the experiments, most top and center thermocouples were at steam temperature, while the bottom was heated by the effect of convective heating of the bottom water zone. The temperatures in the model indicated (21) Miller, C. A. Stability of Moving Surfaces in Fluid Systems with Heat and Mass Transport, III. Stability of Displacement fronts in Porous Media. AIChE J. 1975, 21, 474-479.

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Figure 6. Temperature distribution in the model without a bottom water zone (VI-HP(s)).

Figure 7. Temperature distribution in the model without a bottom water zone (VI-HP(h)).

nonradial flow from the injection well during the experiments. This might be due to the occurrence of heavyoil blocking, which causes the flow of injected fluid through localized channels. The temperature profiles show that the injected steam condensed and advanced in the bottom water zone for a considerable time. When the overlying oil was mobilized sufficiently, oil production started while condensate flowed in the bottom water zone. As steam flowed across the top, some of the underlying oil was heated by conduction. The temperature profiles show that the injected steam condensed and advanced in the bottom water zone for a considerable time. When the overlying oil was mobilized sufficiently, oil production started while condensate flowed in the bottom water zone. The temperature profiles in the bottom water zone show irregular shapes, indicating

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Figure 8. Steam-oil ratios as a function of injected steam (VI-VP).

Figure 9. Steam-oil ratios as a function of injected steam (VI-HP(s)).

that heavy oil was draining into the bottom water zone before being displaced to the production well. Steam-Oil Ratio. The steam-oil ratio (SOR) is indicative of the success of a steam drive. The SOR is defined as the ratio of total volume of steam injected to produce a volume of oil from the reservoir. The presence of a bottom water zone showed a different behavior for SOR in all the experiments as shown in Figures 8-10. First of all, a higher SOR was observed in all the experiments. Moreover, the SOR increases as the thickness of the bottom water zone increases for a horizontal producer. Because the bottom water is more mobile than oil and steamed rapidly, it is displaced more rapidly by horizontal producers with larger areal contact, and as a result, more steam invades inside the models to pass into

the bottom water zone. This demonstrates the improved injectivity of steam in the presence of bottom water. In the absence of a bottom water zone, the highest SOR was noticed in the vertical injection-vertical production configuration in the model. The SOR decreased toward the end of the experiment and became almost similar to the ratio that was observed in the vertical injection-horizontal production configurations. In the model this configuration exhibited a more stable trend in the SOR from the very beginning, resulting from increased heat losses from the reservoir and a decreased pressure gradient in the steam zone. Oil Recovery. Figure 11 compares the experimental oil recoveries as a function of pore volumes of injected steam as cold water equivalent (CWE). The highest

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Figure 10. Steam-oil ratios as a function of injected steam (VI-HP(h)).

Figure 11. Oil recoveries as a function of injected steam (VI-VP).

ultimate oil recovery was obtained with the absence of a bottom water zone. The oil recovery was 31.6% of OOIP for 10% of bottom water thickness (BWT ) 1.0 cm) at 1.5 pore volumes of injected steam. Oil recoveries decreased with increasing bottom water thickness with vertical injection-vertical production well configuration. Figure 12 shows the experimental oil recoveries as a function of pore volumes of injected steam with a vertical injection-horizontal production well that was placed on the hypotenuse of the model. It was observed that the vertical injection-horizontal production configuration in the triangular model without a bottom water zone gave the highest oil recovery. The oil recovery was obtained as 62.0% of OOIP at 1.5 pore volume of steam injection by placing a horizontal producer along the hypotenuse of the triangular model.

Figure 13 shows the experimental oil recoveries as a function of pore volumes of injected steam with a vertical injection-horizontal production well, which was placed along the short perpendicular arm of the model. The highest oil recovery was 31.7% of OOIP at 1.5 pore volume of steam injection. Less oil was recovered in case of the thicker bottom water zone (BWT ) 2.5 cm) than in the absence of a bottom water zone. Oil recoveries were high for vertical injection and horizontal production well configuration without a bottom water zone. The ultimate oil recoveries decreased with increasing bottom water thickness for all well configurations. All of these results agree with the earlier reporting of Suguianto and Butler.16 Moreover, a decrease in oil recovery with an increase in bottom water thickness was also confirmed by Chang et al.15

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Figure 12. Oil recoveries as a function of injected steam (VI-HP(s)).

Figure 13. Oil recoveries as a function of injected steam (VI-HP(h)).

There are two important cases with the application of steam injection in the presence of bottom water zone. In the first case, the oil above the bottom water zone invades the bottom water zone and remains as residual oil, clarifying the reason for the lower recovery in the presence of a bottom water zone. At the end of the experiments when the models were evacuated, it was noted that a 100% water saturated bottom water zone is encroached by the oil above the bottom water zone. The second case leads to the increased tendency for coning of condensate into the vertical well. The B. Kozluca field is located in southeast Turkey, close to the Syrian border. The B. Kozluca field, with an OOIP of 138 MMSTB, has been producing for more than 19 years. The main producing formation is the

carbonate Alt Sinan. Oil gravity is 12.4°API with a very high viscosity of 500 cP under reservoir conditions. The production mechanism is rock and fluid expansion with a very weak bottom water drive. By the year 2004, the cumulative oil and water production were 4.460.701 STB and 663.889 STB, respectively, and daily oil production was 570 STB/day with 20% water cut. From above experimental results, 20-70% of additional oil recovery can be expected from the B. Kozluca field with the application of steam injection as an enhanced oil recovery method.22 (22) C¸ obanog _lu, M. A Numerical Study To Evaluate the Use of WAG as an EOR Method for Oil Production Improvement at B. Kozluca Field, Turkey, SPE Paper No. 72127, Presented at the SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, 2001.

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Conclusions The following conclusions can be reached as a result of comparative laboratory steam flooding: (1) Steam override, which was predominant in vertical injection-vertical production configurations, was reduced by employing horizontal producers. A more uniform temperature distribution over the model was observable in the absence of bottom water. The bottom water, however, counteracted the gravity override of steam. (2) The greatest amount of oil was recovered by vertical injection-horizontal production (along the hypotenuse in the triangular model) well configuration in

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the absence of a bottom water zone. These configurations recovered more oil even in the presence of an underlying bottom water zone. Recovery decreased, however, with an increasing thickness of the bottom water zone. (3) A significant difference in SOR was observed between the experiments conducted with vertical and horizontal producers in the absence of a bottom water zone, whereas the difference was trivial in the presence of a bottom water zone in the model. SOR increased in vertical-horizontal configurations in the model with increasing thickness of the bottom water zone. EF0400870