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The Effect of Fractures on the Steam-Assisted Gravity Drainage Process Suat Bagci* Department of Petroleum and Natural Gas Engineering, Middle East Technical University, 06531 Ankara, Turkey Received August 21, 2003. Revised Manuscript Received June 29, 2004
This study presents an experimental investigation of the effect of fractures and well configurations on the steam-assisted gravity drainage (SAGD) process in a three-dimensional model, using 12.4°API gravity crude oil. A total of eight runs were conducted, using a 30 cm × 30 cm × 10 cm rectangular-shaped box model. Temperature distributions were observed using 25 thermocouples. Three different well configurations were investigatedsa horizontal injection and production well pair, a vertical injection-vertical production well pair, and a vertical injection-horizontal production well pairswith and without fractures that provided a vertical path through the horizontal producer. The influence of fracture distribution on the steam-oil ratio (SOR) and oil recovery was analyzed using the horizontal well pair scheme, a vertical injection-horizontal production well pair, and a vertical injection and vertical production well scheme. The experimental results indicated that vertical fractures improved SAGD. Maximum oil recovery was observed during the horizontal injection-horizontal production well scheme with a fractured model, because of the favorable steam-chamber geometry. Runs showed that the location of the fractures affects the performance of the process. During the early stages of the runs, the fractured model gave significantly higher SORs than those observed in the uniformpermeability reservoir.
Introduction Steam-assisted gravity drainage (SAGD) is a promising recovery process for the production of heavy oils and bitumen resources. The method ensures both a stable displacement of steam and economical rates, using gravity as the driving force and a pair of horizontal wells for injection/production. In the SAGD process, this is achieved by drilling a pair of horizontal wells, located at a short distance, one above the other. Steam is injected into the upper well and hot fluids are produced from the lower well. This progressively creates a steam chamber, which develops by condensing steam at the chamber boundary and gives latent energy to the surrounding reservoir. Heated oil and water are drained by gravity along the chamber walls toward the production well.1-4 Figure 1 shows a vertical section through a rising steam chamber. During the rise period, the oil production rate increases steadily until the steam chamber reaches the top of the reservoir. SAGD with horizontal wells not only offsets the effect of very high viscosity, by providing extended contact or by heating, but also * Author to whom correspondence should be addressed. Telephone: 90 (312) 210-4894. Fax: 90 (312) 210-2171. E-mail address: sbagci@ metu.edu.tr. (1) Butler, R. M.; Stephens, D. J. The Gravity Drainage of Steam Heated to Parallel Horizontal Wells. J. Can. Pet. Technol. 1981, 20 (April-June), 90-96. (2) Joshi, S. D.; Threlkeld, C. B. Laboratory Studies of Thermally Aided Gravity Drainage Using Horizontal Wells. AOSTRA J. Res. 1985, 2 (1), 11-19. (3) Joshi, S. D. A Review of Thermal Oil Recovery Using Horizontal Wells. In Situ 1987, 11 (2), 211-259. (4) Butler, R. M. Rise of Interfering Steam Chambers. J. Can. Pet. Technol. 1987, 26 (3), 70-75.
maintains the necessary drive needed to move the oil as the reservoir becomes depleted. A SAGD process also maintains reservoir drive and allows high recoveries. However, because of their considerable heat requirements, these processes are limited in their economic use to higher quality reservoirs.5 In SAGD, horizontal wells are usually used as injectors as well as for producers, although it is possible to use multiple vertical injectors.6 The SAGD process is characterized mainly by gravity drainage. The higher steam pressure allows shorter breakthrough time from the injection well to the production well and a higher spread rate of the steam chamber, because a higher-pressure decrease between two wells may create the driving force for moving oil. Thus, the displacement force of moving oil caused by the pressure difference between two wells should be suppressed as little as possible, especially in laboratory experiments with a scaled model. The SAGD process can be an attractive recovery process for many fractured reservoirs.7 In fractured systems, thermal conduction allows heat to sweep areas of the reservoir that are not contacted by steam. In this case, thermal expansion is an important recovery mechanism. After steam injection, viscosity reduction increases significantly as the heat migrates to the un(5) Joshi, S. D. Thermal Oil Recovery with Horizontal Wells. JPT, J. Pet. Technol. 1991, 43 (November), 1302-1314. (6) Butler, R. M. Horizontal Wells for the Recovery of Oil, Gas and Bitumen; Petroleum Society of CIM Monograph No. 2; Canadian Institute of Mining, metallurgy and Petroleum (CIM): Calgary, Alberta, Canada, 1994. (7) Joshi, S. D. A Laboratory Study of Thermal Oil Recovery Using Horizontal Wells. Presented at the 1986 SPE/DOE 5th Symposium on Enhanced Oil Recovery, Tulsa, OK, April 20-23, 1986, SPE Paper No. 14916.
10.1021/ef0301553 CCC: $27.50 © 2004 American Chemical Society Published on Web 09/18/2004
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Figure 1. Schematic representation of the steam-assisted gravity drainage (SAGD) process.
swept regions. When compared to homogeneous systems without fractures, vaporization in fractured systems takes a longer time. This is mainly due to the fact that the injected steam flows at a high speed through the fractures without heating the reservoir matrix.8 The previous experimental studies were performed for homogeneous, isotropic, heavy-oil reservoirs and tar sand reservoirs. Thus, these previous studies cannot be used to understand the effect of heterogeneity and anisotropy on the performance of the SAGD process. In this study, however, an experimental study of the SAGD process in both homogeneous and fractured reservoirs was performed. The objective of this study was not only to perform oil production with SAGD, using horizontal wells, but also to evaluate the effects of various well configuration schemes and vertical fractures. Literature Review Butler and Stephens1 reported pioneering work on SAGD. They were the first to introduce the important concept of oil displacement through a thin boundary layer around the expanding steam chamber. They further reported experimental data, as well as a semianalytical numerical solution. Their results indicate that the process requires continuous steam injection and continuous oil drainage for maximum oil production efficiency. Huygen and Black,9 on the other hand, concluded that cyclic steam stimulation, using a horizontal well, is the best production technique for fractured reservoirs. They also reported that vertical fractures are not ideal for steam flooding if horizontal wells are used for production. Joshi and Therlkeld2 conducted experimental studies on oil production with thermally aided gravity drainage, using horizontal wells, and evaluated the effects of various well configuration schemes and vertical fractures. The high initial oil (8) Hoffman, B. T.; Kovscek, A. R. Light-Oil Steam Drive in Fractured Low-Permeability Reservoirs. Presented at the SPE Western Regional/AAPG Pacific Section Joint Meeting, Long Beach, CA, May 19-24, 2003, SPE Paper No. 83491. (9) Huygen, H. H. A.; Black, J. B. Steaming through Horizontal Wells and Fractures-a Scaled Model Test. Presented at the Second European Symposium on Enhanced Oil Recovery, Paris, November, 1982.
recovery with vertical fractures helped to improve the economics of the SAGD process. Griffin and Trofimenkoff10 extended a theory for steam injection from a vertical well situated above the horizontal production well and presented laboratory results in support of their theory. Both low-pressure visual models and high-pressure models of SAGD experiments showed good agreement with the theory. Low-pressure models indicate that the theory developed by Butler and co-workers 1,11 accurately predicts the rate of oil production and analyzes the effects of oil viscosity on the production rate. The scaled models indicate that the process has a long life span and the steam override and subsequent overburden heat loss are not as great as initially indicated by the proposed theory. Joshi7 reported results on using SAGD with vertical and horizontal injectors. He found that vertical injectors with a horizontal producer gave faster recovery than using a horizontal injector-horizontal producer in reservoirs with shale barriers. He also indicated that vertical fractures perpendicular to a horizontal injector improved the rate of oil recovery when compared with a horizontal injector-horizontal producer. Furthermore, Yang and Butler11 also studied reservoir homogeneities of two different types: (i) reservoirs with thin shale layers, and (ii) reservoirs with layers of different permeability. They discovered that a short horizontal barrier does not significantly affect the general performance of the SAGD process. However, a long barrier decreases the production rate. When a higher permeability layer was located above a lower permeability layer, faster production was noticed, as opposed to when a lower permeability layer was located above a higher permeability layer. The vertical well spacing between injection and production wells is the most important factor for deter(10) Griffin, P. J.; Trofimenkoff, P. N. Laboratory Studies of the Steam-Assisted Gravity Drainage Process. AOSTRA J. Res. 1986, 2 (4), 197-203. (11) Yang, G.; Butler, R. M. Effects of Reservoir Heterogeneties on Heavy Oil Recovery by Steam Assisted Gravity Drainage. Presented at the 40th Annual Technical Meeting of the Petroleum Society of CIM, Banff, Alberta, Canada, May 28-31, 1989.
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mining the oil production rate. Sasaki et al.12 reported that the initial stage of production (or vertical rise of the steam chamber) was observed to be sensitive to the location of the steam injector. The oil production rate increased when the vertical well spacing became larger. However, the breakthrough time increased as the well spacing increased. Thus, vertical well spacing could be used as a governing factor to evaluate the rate of production and lead time during the initial stage of the SAGD process. Butler and co-workers,1,4,13 reported similar performance, based on reservoir height. Their works focused on the expansion of the steam chamber after it arrives at the overburden. In summary, both studies reveal that the oil production rate increased as the vertical spacing between two wells increased; however, the lead time to start oil production by gravity drainage became larger. Ong and Butler14 described an analysis of the pressure drop along the horizontal wellbore for vertical injectors/horizontal producers. They showed that the pressure decrease in the wellbore is caused a slope in the steam chamber along the well. Different methods of heating the wellbore to reduce the pressure drop were considered, such as indirect heating (circulating steam in the producer). Well Configurations and Fracture Orientation In a typical SAGD process, steam is injected into a horizontal well that is located directly above a horizontal producer. A steam chamber grows around the injection well and helps to displace heated oil toward the production well. After SAGD is initiated, a steam chamber will grow in the reservoir. Butler15 noted that the steam chamber would initially grow upward to the top of the reservoir and then begin extending horizontally. At the steam chamber boundary, steam condenses to water as heat is transferred to the heated oil. Condensed water and hot oil flow along the steam chamber to the production well. The field application of SAGD processes is possible through the use of three different well configuration schemes, as described below. The experimental well arrangements used to simulate three different well configurations are shown in Figure 2. The following schemes are depicted in Figure 2: Scheme 1: A Horizontal Well Pair. Two horizontal wells are drilled and one is placed slightly above the other. Steam is injected into the top well and oil and water are produced from the bottom well. Scheme 2: Vertical Steam Injection Wells and a Horizontal Production Well. Steam is injected into several vertical wells placed above and along the length of a horizontal production well. Scheme 3: Single Vertical Injection and Production Well. Steam is injected into the formation through the annulus and perforations in the top portion of the reservoir, and fluids are produced at the well bottom (12) Sasaki, K.; Akibayashi, S.; Yazawa, N.; Kaneko, F. Experimental Modeling of the Steam-Assisted Gravity Drainage Process-Enhancing SAGD Performance with Periodic Stimulation of the Horizontal Producer. SPE J. 2001, (March), 189-197. (13) Sugianto, S.; Butler, R. M. The Production of Conventional Heavy Oil Reservoirs with Bottom Water Using Steam-Assisted Gravity Drainage. Presented at the 41st Annual Technical Meeting of the Petroleum Society of CIM, 1990, Paper No. 89-40-33. (14) Ong, T. S.; Butler, R. M. Wellbore Flow Resistance in SteamAssisted Gravity Drainage. J. Can. Pet. Technol. 1990, 29 (2), 49-55. (15) Butler, R. M. Thermal Recovery of Oil and Bitumen; PrenticeHall: Englewood Cliffs, NJ, 1991; pp 285-359.
Figure 2. Schematic diagrams of the well configurations.
perforations through tubing. A packer is used to separate injection and production flow. There are several heavy-oil reservoirs that are heavily fractured. Past experience indicates that, generally, it is difficult to produce oil from a vertically fractured reservoir, using a vertical well. In addition, many heavyoil reservoirs have very low steam injectivity. Recent field activity indicates that steam injection in fractured reservoirs may have economic potential. Even though the injected steam in the aforementioned process moves rapidly through fractures, the heat front moves uniformly. These studies have shown that the rate of oil recovery also is enhanced. These results show that heat was efficiently transferred from the injected steam to the reservoir matrix. The following three fracture configurations were studied using the horizontal well pair: Fracture A: Widely spaced vertical fractures located only above the injection well. Fracture B: Widely spaced vertical fractures above the injection well and a fracture also between the injection and production wells. Fracture C: Closely spaced vertical fractures above the injection well and a fracture between the injection and production wells. All fractures were located along the length of injection and production wells. The experimental configurations of the three fracture schemes, previously referred as fractures A, B, and C, are shown in Figure 3.
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Figure 3. Schematic diagrams of the fracture orientations in the model.
Experimental Setup and Procedure A schematic diagram of the experimental setup is shown in Figure 4. It consists of a steam generator, the threedimensional (3-D) model, a back-pressure regulator, a wateroil separator, and a temperature scanner. The 3-D model has cross-sectional dimensions of 30 cm × 30 cm, with a thickness
Figure 4. Schematic diagram of experimental setup.
property
value
crude oil API gravity viscosity, at 20 °C matrix porosity permeability oil saturation water saturation
Batı Kozluca 12.4° 7300 cP crushed limestone 38.0% 10.0 darcy 75.0% 25.0%
of 10 cm. The top of the model is removable and acts as a flange, so that the mixture of water, oil, and crushed limestone can be packed easily. To measure the 3-D temperature distributions inside the model, 25 thermocouples were installed at the center plane of the model. Insulating materials and heaters were also used in the model. Perforated stainless-steel tubing 8 mm in diameter 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. The distance between injection and production wells was 5 cm. A 40-mesh stainlesssteel screen with dimensions of 10 cm × 15 cm was placed into the sand pack, to simulate the vertical fractures. All fractures were located along the length of injection and production wells. The oil used in this study is a 12.4°API gravity viscous crude oil from the Bati Kozluca field. The viscosity of this oil is ∼600 cP at the initial model temperature of 50 °C. The packing data and oil properties are given in Table 1. The premixing method was used to prepare the unconsolidated limestone pack mixtures for the experiments. Water and clean crushed limestone were mixed initially to meet the conditions of a water-wet system. The oil then was mixed homogeneously in the previous mixture to yield the desired fluid saturations, and the final mixture was carefully packed into the 3-D model. The oil and water saturations were chosen to be 75% and 25%, respectively, and kept the same for each experiment. In each experiment, the desired well configuration and fracture orientation were installed in the 3-D model that was then packed with the mixture of crushed limestone, oil, and water. After the packing, the model was placed vertically inside the insulation jacket. The setup was then prepared for the test and the model was heated to ∼50 °C, which was the desired reservoir temperature. Superheated steam at 50 psi(345 kPa) and 150 °C was injected into the model. Although only a small pressure drop existed between the injection and production wells, there was a significant temperature difference between the two wells. To control the pressure of the
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Figure 5. Comparison of steam-oil ratios (SORs) for different well configurations without fracture.
Figure 6. Comparison of oil recoveries for different well configurations without fracture. production well, back-pressure regulators were used at the fluid stream of the separator. The back-pressure regulators were adjusted to a pressure that was 2 psi (13.8 kPa) lower than the value of the injection pressure. During the experiments, the injection line temperature, the temperature profile in the model, the injection and production pressures, and the oil and water production data were recorded continuously. All
the experiments continued until the cumulative steam-oil ratio (SOR) began to increase rapidly.
Results and Discussion The experimental conditions and results of this study are given in Table 2. Figures 5 and 6 respectively show
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Table 2. Experimental Conditions and Results run no. 1 2 3 4 5 6 7 8
well configuration VI-HP VI-VP HI-HP HI-HP HI-HP HI-HP VI-HP VI-VP
fracture orientation
steam injection rate (cc cwe/min)
oil recovery (% OOIP at 1.0 pore volume)
steam-oil ratio, SOR (cc/cc) (at 1.0 pore volume)
A B C A A
22.0 33.0 24.5 24.8 16.6 27.0 15.3 15.4
18.46 19.55 43.22 10.52 15.01 12.44 25.26 44.00
6.97 7.41 3.21 13.23 8.94 11.03 5.39 3.48
the SOR and oil recovery, as a function of injected steam, in terms of pore volume, for various well configurations without fracture. The initial SOR with horizontal injection and horizontal production well (Scheme 1) is much larger than that for the other two schemes. However, this initial SOR value declines more rapidly for Scheme 1 than for the other schemes, and, after a fluid production of ∼60% of a pore volume, the SORs are almost equal. Figure 6 indicates that the horizontal injection and horizontal production well scheme will recover more oil than the other two schemes for the same amount of produced fluid. Greater effectiveness is achieved with this configuration, because it heats and drains the reservoir more effectively. This observation is consistent with the criterion for high recovery that was observed by Joshi and Threlkeld.2 Figure 7 shows temperature distributions as a function of different injected steam volumes for each well configuration without fracture. The temperature distributions are more uniform along the entire wellbore. For each well configuration, a large steam chamber is growing in the middle of the model. A significant upward movement of steam due to gravity is also present, especially at early times, for all cases. At later stages of the experiments, a large steam chamber grows in the middle region of the model. At this point, however, the steam chamber is just beginning to grow above the short-circuiting area between the injection and production sections. The same profile at similar relative times in the other cases displays a much larger heated area. It is important to maximize the amount of net heat injection into the reservoir at earlier stages and maximize the size of the heated volume surrounding the wellbore. As noted previously, the length, amount, and distribution of vertical fractures are important for heavy-oil recovery. The influences of fracture distribution on the SOR and oil recovery were studied, using the horizontal well pair scheme. The fractures were simulated by placing 10 cm × 15 cm, 40-mesh stainless-steel screens that were attached to the steel body of the model into the pack. The effect of various fracture schemes on the SORs is shown in Figure 8. Note that, even with the horizontal well pair configuration (Scheme 1) in a uniform-permeability reservoir without fracture, the initial SOR is ∼16.0, which eventually declines to 3.0. These SOR values are further improved by vertical fractures. As shown in Figure 8, initial SORs of 6-10.0 are observed with the fractured reservoirs. Note that, in all fracture schemes, the SOR values start to increase after at least 0.25 pore volume of steam is injected. As noted previously, this stems from the fact that steam accesses previously unswept areas more easily in vertical fractures. The ratio of permeability between the injection and production wells, and the permeability
above the injection well, affected the SOR values. Fracture C has a more-favorable permeability ratio than that of fracture A. Therefore, consistently higher SOR values are obtained in fracture A than in fractures B and C. However, with widely spaced vertical fractures (fracture A), the initial SOR is ∼9.0, which demonstrates a significant improvement. An even better initial SOR was obtained when an additional fracture was introduced between the injection and production wells (fracture B). This additional fracture provides an easier path for displaced oil to travel toward the production well. The best results were obtained with fracture C, where fracture density above the injection well was higher than those between the injection and production wells. The very high permeability path (fractures) above the injection well helped the natural convection of steam, which resulted in efficient oil drainage. Figure 9 shows the oil recovery with the different fracture schemes. Once again, higher recovery with vertical fractures initially (fracture B), in comparison to a uniform permeability reservoir, is obvious. The high initial recovery with vertical fractures helps to improve the economics of the already-favorable process. Figure 10 shows the temperature distributions for different fracture schemes. The shape and growth of the steam chamber in a fractured pack are different from those observed in the uniform permeability pack without fracture. In the uniform-permeability pack, the initial shape of the steam chamber (0.38 pore volume of injected steam) was almost round, as shown in Figure 10. However, in a fractured pack, because the vertical fracture above the injection well provides an easy path for steam to travel vertically upward, directly toward the top of the pack, an elongated steam chamber is observed for the fracture B scheme, as shown in Figure 10. After reaching the top of the pack, this thin steam chamber spreads laterally in a mushroom-type fashion, contacting oil located at the top portion of the pack. This oil has the highest available gravity head, and, hence, it drains rapidly when heated by the steam. This results in a high initial oil production rate. However, as the steam chamber expands downward, the influence of the vertical fracture above the injection well declines. This fracture can no longer provide an easy path for steam to spread into the previously unswept area, resulting in a decline in the initially high SOR. Whether heat communication between the wells can be formed before SAGD is an important factor in heavyoil reservoirs with fractures. Heat communication directly influences development, growth, and the geometry of the steam chamber. If heat communication exists, better lateral growth behavior is observed, because this restricts the vertical growth rate, reduces the heat requirements, and increases the rate of temperature in the physical model. If heat communication does not
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Figure 7. Temperature profiles along the center plane of the model (without fracture).
form, the steam chamber grows rapidly in the vertical direction, increasing the rate of temperature in the model; this undoubtedly leads to increased heat losses at the top of the physical model. Conclusions Based on the experimental results presented in this study, the following conclusions can be drawn:
(1) Steam-assisted gravity drainage (SAGD) with a combination of vertical and horizontal wells has been demonstrated to be a viable scheme for the development of heavy-oil reservoirs. In the SAGD process, a vertical well spacing of 5 cm between injection and production horizontal wells resulted in quicker generation of the steam chamber and increased oil production.
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Figure 8. Comparison of SORs for horizontal injection-horizontal production well configuration with different fracture orientations.
Figure 9. Comparison of oil recoveries for horizontal injection-horizontal production well configuration with different fracture orientations.
(2) For the same amount of oil production, the horizontal well pair scheme gave higher recovery of the original oil in place than the other two production schemes that were examined. In addition, the horizontal well pair schemes gave higher oil-water ratios during
the initial period of the runs. Fairly high steam-oil ratios (SORs) were also observed. (3) The vertical fractures helped the SAGD process. During the early portion of the run, the fractured pack gave significantly higher SORs than those observed in
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Figure 10. Temperature profiles along the center plane of the model.
the uniform permeability reservoir. Thus, the vertical fractures could be used to improve the initial oil production rates. In fractured packs, the vaporization, viscosity reduction, and thermal expansion all contributed to the oil recovery.
(4) The fractures were successful in shortening the time required to generate near-breakthrough conditions between the two wells. They also enhanced the rate of expansion in the steam-chamber area. EF0301553
