A Theoretical Analysis of Steam Stimulation

The numerical model developed in this paper gives fast, reliable, and physically meaningful results for steam stimulation and other thermal processes. The paper describes a numerical processes. The paper describes a numerical technique that simulates two-dimensional heat transfer and one-dimensional, three-dimensional heat in a multilayered reservoir. Interphase mass transfer accounts for steam condensation, solution gas drive, distillation, and solvent extraction. The mathematical development and the various features of the model are presented. Computer calculations for several test problems show the model agrees closely with analytical solutions, laboratory experiments, and field data. The major advantages of this thermal reservoir model over previous models are increased speed and reliability with little sacrifice of physical significance. These advantages stem from an implicit-pressure/explicit-saturation formulation, simultaneous solution of pressure and energy equations, and improved techniques for invoking phase constraints and calculating mass-transfer phase constraints and calculating mass-transfer terms. The model is a valuable tool for studying steam stimulation and other thermal processes. This has been demonstrated in many studies under varying reservoir conditions. Because of its speed, the model also can be used to investigate the effects of various parameters on the different thermal processes. Moreover, the model can be extended easily to treat two-and three-dimensional configurations and to include other phenomena such as gravity, capillary pressure, temperature dependence of relative pressure, temperature dependence of relative permeability, and in situ combustion. permeability, and in situ combustion Introduction Steam injection stimulates producing wells by providing localized heating in the vicinity of the providing localized heating in the vicinity of the wellbore. The use of steam injection has received considerable attention throughout the oil industry since the early 1960's. Both medium and heavy oil reservoirs are candidates for steam injection as a means of stimulating oil recovery. Currently, steam stimulation is being applied on a commercial scale in California and Venezuela. Because of the high costs associated with injecting steam in the field, it has been necessary to develop computation schemes that simulate the steam-injection process. Both analytical and numerical solutions have been used. In general, the analytical techniques remove many of the physical processes by invoking too many simplifying processes by invoking too many simplifying assumptions. On the other hand, the numerical methods incorporate most of the physical processes, but suffer from reliability problems and excessive computation-time requirements. Thus, there has been a definite need to develop an improved calculation procedure for the steam-stimulation process. procedure for the steam-stimulation process. This paper describes a numerical procedure for simulating coupled energy and mass transport in a multilayered reservoir. The model treats linear flow of three fluid phases and linear convective energy transport, but heat conduction is two-dimensional over a vertical cross-section spanning the oil sand and adjacent strata. Mathematical development of several computational features and physical phenomena is detailed in the paper. A major feature phenomena is detailed in the paper. A major feature is the simultaneous solution of mass and energy equations. Steam condensation/evaporation effects are discussed, and a new solution gas drive model is developed. Treatment of condensation terms and phase constraints for both these processes is phase constraints for both these processes is outlined. To facilitate solution when injection and production rates are high or when a vapor phase is production rates are high or when a vapor phase is present near the wellbore, semi-implicit mobilities present near the wellbore, semi-implicit mobilities are also introduced. The numerical procedure has been applied successfully to a number of problems. It has accurately matched experimental and analytical results; and in both single and multicycle steam-stimulation treatments, it has accurately matched field data. In addition to steam stimulation, the model has been tested on other reservoir engineering problems involving thermal operation. In all studies, problems involving thermal operation. In all studies, computation time was small. SPEJ p. 65

It is difficult to produce oil from diatomite due to unique rock properties such as low permeability, high porosity, fine laminations, and fractures. Steam injection is a promising enhanced oil recovery method for diatomite, but the generation and injection of steam may lead to large energy cost and, potentially, well failures. Injection of hot water instead of steam provides a means to decouple pressure and temperature while still achieving the benefits of thermal recovery. This study investigates and compares oil recoveries from fractured diatomite cores (1.5 ″, 3.5 ″, and 5 ″diameter) using hot water and steam. Both hot water and steam injection at 200 °C were applied under spontaneous and forced imbibition conditions. Cores from two different reservoirs (A and B) were used. The B reservoir oil and brine formation were adopted for all cases. Synthetic steam boiler feed was used to create hot water and steam. An X-ray CT scanner was used to visualize in-situ phases saturations and characterize the porosity/oil saturation distribution. Wettability alteration toward water-wet conditions was observed clearly at elevated temperature (200 °C) for all cores. The Amott index, Iw, for hot water and steam injection around 200 °C with reservoir A conditions were 0.41 (A#1) and 0.36 (A#2), respectively. The final oil recovery from A cores at 45 °C and 200 °C were 62- 64 % and 78- 82 % OOIP, respectively. The A reservoir whole core with 5 ″ diameter at 45 °C showed greater oil recovery from spontaneous imbibition than the 1.5 ″ diameter core. The Iw and final oil recovery from core A with both steam and hot water injection at 200 °C was nearly identical. With B core, the Iw increased from 0.28 (45 °C, water) to 0.34 (200 °C, steam). The Iw of B core was equal to 0.33 after both hot water injection and steam injection. The final oil recoveries of both hot water and steam at 200 °C showed 76 % and 80 % OOIP, respectively. Both in situ visualization and effluent analysis shows that rock dissolution and fines migrations contribute the evolution of fracture and pore networks within the core. Therefore, results suggest that hot water provides the benefits of thermal recovery, in some regards, while decoupling pressure and temperature.

Cyclic steam stimulation (CSS) was tested in some of the wells of a Kuwaiti heavy oil field. It was observed that the produced water-oil ratio of the CSS wells was much less than the expected range of 0.5 to 1 in a first cycle and up to 2 in a second cycle. High water retention was diagnosed in the formation which led to further investigation to confirm it and to find out its causes. The analysis presented is based on several approaches. Field injection and production data of each well were analyzed to estimate water-oil ratio. Temperature survey was carried out during soaking period to observe vertical movement of steam, if any. Laboratory steamflood experiments were performed on composite plugs. It was followed by oil injection (drainage) to mimic the CSS process and to quantify the water retention and to compare it with the field data. Moreover, detailed geological analysis is discussed to understand the nature of the formation. The analysis reveals that the baffle located just above the oil formation becomes active at high pressure and allows steam to pass through it. Heat is transferred upwards not only by conduction but also by convection. Migration of steam into baffle and an upper horizon was confirmed by temperature surveys taken in the CSS wells during soaking period. Baffle acts as a thief zone and retains a great deal of water and not allowing water to come back during production phase even when pressure goes down. In summary presence of baffle is the main reason behind high water retention in the formation. The above methodology has been adopted for the first time in the field under consideration. This will help in optimizing the steam injection strategy in future CSS wells.

In this study, the influence of direct steam injection (DSI) on the performance and emissions of marine engines is investigated. Simulation models are developed and tested based on experimental data. Steam is obtained by waste heat recovery in a marine engine. The limitations of DSI parameters are investigated based on the exhaust gas temperature. The steam quantity and temperature decrease with a decrease in load. The results show that steam mass plays an important role in NOx reduction and improving power. For a steam/fuel ratio of 1.27 at 100% load, the brake power improved by 3.09% and NOx emissions decreased by 4.67%. A higher degree of improvement is obtained with an increase in steam mass. The steam temperature and injection timing only slightly influenced the brake power and NOx emissions. When steam-injection timing improved to 12°CA at 100% load with injection duration decreasing from 85°CA to 25°CA, brake power improved from 3,485.7 to 3,529.7 kW. All of this demonstrates that the DSI approach has excellent energy-saving and emission reduction potential for marine engines. The steam-injection strategy should be optimized in the future.

Summary Equations presented in this paper represent the steamdrive process assuming steam rises quickly to an impermeable overburden. Subsequent growth of the volume heated results from increase in both the area and thickness of the region heated to steam temperature. Equations derived predictthe rate of increase of steam zone thickness and areal extent,the volume of oil displaced from the steam zone and the heated reservoir beneath it,the reduced injection rate that will sustain steam after an area has been headted to steam temperature, andthe additional oil displaced after steam injection is stopped. Predictions are compared to observed behavior of Chevron's Kern River (CA) 10-pattern pilot steamdrive. Introduction Marx and Langenheim1 presented a valid relationship between the rate of injection of a hot fluid and the area heated by the fluid. The usefulness of the resulting predictions is limited by the assumption that hot fluids heat each areal increment of the reservoir uniformly from top to bottom. Typical steamdrive performance is different from that predicted by Marx and Langenheim because the difference between densities of steam and liquids causes steam to rise to the top of a permeable interval. Because of this gravity override, heat losses are not to the confining impermeable beds but partly to the permeable reservoir beneath the steam zone. Several models based on assumed or observed average steam zone thickness have been proposed. The model presented here enables prediction of steam zone thickness as well as the area covered by steam. Conditions Assumed Steam is assumed to rise to the top of a permeable reservoir in time negligible compared with that required to heat the total reservoir area. The horizontal pressure gradient in the steam zone is assumed to be much less than the vertical pressure gradient on liquids caused by the difference between densities of steam and liquids. Single values are assumed for both oil and water saturations throughout the steam zone. Fortunately, predictions depend only indirectly on water saturation, which seldom is known accurately. Because the horizontal pressure gradient in the heated reservoir immediately below the steam zone equals the small horizontal pressure gradient in the steam zone, horizontal flow immediately below the steam interface is neglected. Oil saturations in the heated reservoir beneath the steam are assumed to be the residual oil saturation to hot-waterflooding. The thickness of the interval flooded by hot water is represented by a single temperature that be estimated from laboratory data or field measurements. With this assumption, temperature-dependent relative permeabilities and flow properties are represented by a single temperature and a single oil saturation. The portion of injected heat that leads to steam zone growth is assumed equal to the portion in steam vapor. Injected hot water, like that from steam condensation, is assumed to fall quickly to the reservoir beneath the steam zone, where it contributes to oil displacement but does not influence steam zone growth. Predicted Steam Zone Growth and Oil Displacement Equations representing the concepts described as follows are presented in the Appendices. The rate of steam condensation resulting from heat diffusion into the overburden is a function of the time since the areal increment considered was first heated (Appendix A, Eq. A-4). The volume rate at which water flows downward through the steam zone equals the rate of steam condensation at the overburden/reservoir interface.The volume rate (per unit area) of water flowing downward beneath the steam interface minus that in the steam zone equals the volume rate of water displaced by movement of the steam interface (Eq. A-5).The enthalpy (per unit area) carried by the downward flow of oil and water beneath the steam interface minus that carried by water flowing downward through the steam zone equals the rate of interface motion times the difference in enthalpy above and below the interface (Eq. A-7).Vertical displacement of the steam interface does not require a change in the temperature gradient just below the interface.

Cyclic steam stimulation is an effective thermal recovery method for heavy oil recovery. The key potential mechanism is the growth of the steam chamber after steam injection. Taking the LD5X heavy oil reservoir as an example, besides the interlayer developed in this area, the top water and bottom water distribute above and below the interlayer. These factors may have adverse effects on the development of the steam chamber, thus affecting the final heavy oil exploitation. In this work, our goal is to study the effects of interlayer permeability and well–interlayer distance on CSS performance (in the presence of top and bottom water). We developed a high-temperature-resistant interlayer. Based on the simulated interlayer, the field scale model was converted into a laboratory element model through the similarity criterion. In order to quantitatively evaluate the performance of steam stimulation, a thermal detector was used to measure the dynamic growth of the steam chamber and record the production data. The experimental results show that the self-made interlayer has high-temperature resistance, adjustable permeability, and little difference between the physical parameters and the target interlayer. During the cyclic steam stimulation process, the steam chamber presents two different stages in the presence of the top water area, namely the normal production stage and the top water discharge stage. The bottom water has little effect on the growth of the steam chamber. The small interlayer permeability, the increase in horizontal well–interlayer distance, and the existence of the interlayer will delay the top water leakage during steam stimulation. This study has reference significance for us to develop heavy oil resources with a top water barrier when implementing steam stimulation technology.

This report details the findings of an in-depth study undertaken to assess the viability of the steam injection process in the heavy oil bearing Nacatoch sands of Arkansas. Published screening criteria and DOE`s steamflood predictive models were utilized to screen and select reservoirs for further scrutiny. Although, several prospects satisfied the steam injection screening criteria, only a single candidate was selected for detailed simulation studies. The selection was based on the availability of needed data for simulation and the uniqueness of the reservoir. The reservoir investigated is a shallow, thin, low-permeability reservoir with low initial oil saturation and has an underlying water sand. The study showed that the reservoir will respond favorably to steamdrive, but not to cyclic steaming. Steam stimulation, however, is necessary to improve steam injectivity during subsequent steamdrive. Further, in such marginal heavy oil reservoirs (i.e., reservoir characterized by thin pay zone and low initial oil saturation) conventional steamdrive (i.e., steam injection using vertical wells) is unlikely to be economical, and nonconventional methods must be utilized. It was found that the use of horizontal injectors and horizontal producers significantly improved the recovery and oil-steam ratio and improved the economics. It is recommended that the applicability of horizontal steam injection technology in this reservoir be further investigated.

Strain-dependency of permeability is a key feature for coupled multiphysics phenomena during heavy oil production under steam stimulation. This feature is also the basis for accurate estimation of steam needed to properly stimulate a given target heavy oil block. In this study, a fully coupled thermal-hydro-mechanical model is established and applied to the numerical simulation of steam injection in a block of western China Xinjiang region's heavy oil field. Strain-dependent relationships have been established for hydraulic conductivity as well as Young's modulus of reservoir formations. The distribution of reservoir temperature field and pore pressure field is obtained, and a quantitative evaluation of steam injection effectiveness is provided. The principal contents include: 1) A simplified fully coupled thermal-hydro-mechanical model for heavy oil reservoir under steam injection is presented. The model incorporates strain-dependent characteristics for rock's permeability/hydraulic conductivity and elastic modulus. 2) The simplified fully coupled model is implemented via the user subroutines of Abaqus software, and 3D finite element simulations are conducted for the steam stimulation operation and oil production processes in the heavy oil block. The temperature field and pore pressure field of the reservoir are obtained under given production history and steam injection conditions. These numerical results have provided an accurate evaluation of steam injection effectiveness. These numerical results indicate that: 1) The original design of steam injection volume and soak time is insufficient to connect the temperature rise regions around wells A1 and A2 in the block in order to get ideal production rate. The temperature rise data obtained from monitoring wells verify the accuracy of the calculation results, demonstrating the accuracy and practicality of the proposed theoretical model. 2) It is found that the maximum local pore pressure induced by steam injection may exceed the bottomhole pressure of injection wells. This is due to the thermal expansion of both solids and pore fluids caused by rapid temperature rise. 3) For the target reservoir, numerical results indicate that further steam injection for 17 days on top of the original design will connect the temperature rise regions around wells A1 and A2, and the minimum temperature at various points between wells will exceed 40 °C.

The Pikes Peak Steam Project was initiated in 1981 using vertical wells on one hectare spacing. Emphasis later shifted to directional drilling, but no horizontal wells have been used. Wells are initially steam stimulated, but are drilled in three hectare inverted seven-spot patterns and eventually converted to steam drive. Performance at Pikes Peak has remained excellent since inception, with typical early cycle SORs ranging from one to three and recoveries of up to 40% OOIP before drive conversion. Project cumulative recovery is estimated to be over 50% and rising, as third quarter 1995 project performance was 1,330 m3 oil/day from 117 wells. Advantages at Pikes Peak of vertical or directional well development over horizontal well development are proposed and discussed. A vertical well steam stimulation process for bottom water areas is identified and evaluated. Introduction Horizontal wells have rejuvenated interest in selected Western Canadian heavy oil reservoirs using cold production(1–9), steam Injection(10–22), and fireflood technology(23–25). Some of these projects have been highly successful, and there is now a perception among some oil industry upper management teams that a project is not using the best technology unless it employs horizontal wells. Overlooked in this reasoning is evidence that selected projects have exhibited excellent performance using only vertical and directional wells. In the interest of brevity, this paper concentrates on one project and one technology, the Pikes Peak steam project. Emphasis is placed on discussing why vertical and directional well development likely aided project performance. Detailed discussions of other aspects of Pikes Peak project performance are available in the literature(26–29). Project Location and History The Pikes Peak project is located in Township 50, Range 23 and 24 W3M, approximately 65 km east of the town of Lloydminster (Figure 1). The discovery well was drilled in 1970. Primary production was attempted from 1977 to 1980 using reciprocating pumps, but frequent sanding problems occurred and steam stimulation was selected as an alternate exploitation process. Initial tests in 1981 with portable generators, showed sufficient promise for installation of permanent generators and addition of more wells. Higher quality steam slugs yielded very good responses, and systematic expansion was initiated. Directional drilling was incorporated in 1983 to lessen surface impact and reduce costs. Integral project development strategies included selectively drilling inside the oil/water contact and development of effective strategies for conversion from steam stimulation to follow-up steam drive. Geology and Reservoir Description The reservoir contains a viscous crude oil with a gravity of 0.99 g/cm3 and a gas-free viscosity of 25,000 mPa.s at reservoir temperature (18 °C). Van Hulten(30) concluded deposition of the Pikes Peak channel facies was contemporaneous with that of the regional Waseca sands, and channel- sand thickness variations were the result of migrating point bars. A local structural high allows the project area to be free of bottom water. The Waseca channel at Pikes Peak has been divided into a well-sorted, unconsolidated, predominantly quartz, highly permeable (5 to 10 darcies), homogeneous lower unit and a sand/shale interbedded upper unit.

The surface crude oil viscosity of the first ultra-heavy oil field in Bohai Oilfield is more than 50,00mpa·s, which is unable to be developed under the condition of original formation temperature and requires steam stimulation. In the first period of steam huff and puff well, due to sufficient formation energy, steam injection pressure is high in the process of steam injection. The measures to reduce the steam injection speed are mostly adopted in the field, but it will lead to the problem of large wellbore heat loss and affect the steam stimulation heat injection effect. In this paper, based on the oil characteristics of the first ultra-heavy oil field in Bohai Oilfield, the evaluation of oil soluble surfactant was carried out, and the experimental study of pre-injection of oil soluble surfactant to reduce steam injection pressure was carried out. It has been successfully applied in the development of the first ultra-heavy oil in Bohai oilfield. The results show that the oil soluble surfactant with asphaltene dispersibility has better temperature resistance and viscosity reduction effect, and the viscosity reduction effect is more than 95% before and after aging. Laboratory experiments show that the oil soluble surfactant can reduce the steam displacement resistance of the displacement front and the affected area. When the injection amount of oil soluble surfactant is 0.2PV, the maximum steam injection pressure can be reduced by 22.9% and the steady steam injection pressure by 10.8%. The design treatment radius of oil soluble surfactant is 0.15m, and the field test shows that the steam injection pressure decreases by 1.1MPa during steam injection.After adopting the depressurization and increase injection volume technology, the field injection pressure is effectively reduced, the steam injection effect of ultra-heavy oil is guaranteed, and the technical guarantee for the subsequent development, promotion and application of ultra-heavy oil is provided.

Summary The 10-pattern steamflood was converted to water injection in Sept. 1975 after 7 years of operation. Recovery is now 59 % of the presteam oil in place (OIP), with 22 % of this oil produced during the waterflood. Poststeam water injection apparently works best in reservoirs with large hot and unaffected zones remaining at the end of steam injection. Introduction Finding a way to end a steamflood project has been a problem for many operators. Usually this is done by stopping steam injection at the economic limit on the steam/oil ratio (SOR) and producing the reservoir to its new economic limit without steam assistance. Simulation studies conducted by Chevron U.S.A. Inc. have shown that higher ultimate recovery was possible by injecting water after a steamflood. This subsequent recovery results from heat scavenging (areally and vertically) and pressure maintenance effects. Maintaining reservoir pressure aided well productivity, prevented lateral resaturation of the depleted zone by oil from outside steamdrive areas, and prevented possible subsidence. Project economics also are improved because fuel is not needed to generate steam for the recovery of this additional oil. A successful poststeam water-injection project was reported previously. This project followed an unsuccessful steam injection program. A similar poststeam project, using a mixture of air and water, also has been reported. To our knowledge, no other poststeam waterinjection projects currently exist. Our first application of poststeam water injection was in the 10-pattern steamflood, Section 3 of the Kern River field. Steam injection began in Sept. 1968. The project was converted to cold-water injection in Sept. 1975. A previous papers described this project and its performance through Sept. 1973. Our paper updates the project's performance and status as of Jan. 1, 1981. Project Description The changes in well completions, operating practices, surface facilities and reservoir data since the first report are discussed in the following Fig. 1 shows the location and status of all wells in the project. Well Completions No temperature observation wells have been added or reworked since the beginning of the steamflood. Two of the 14 observation wells, T5-1 and T5-6, are no longer used because of apparent cement breakdowns. The 10 injection wells were 5 1/2-in. jet-perforated completions without packers. All injectors were completed in the middle of the drive zone, although originally this was not recognized. None of the injection wells have required work since completion. Wellhead injection pressures during the final steamflood period ranged from 150 to 200 psi. All injection wells have been on vacuum since water injection began. Even a change in April 1979 to unfiltered produced water apparently has not hurt injectivity. Thirty-three producers now are included in the project. Well 12-4 was drilled in Jan. 1977 to replace Well 163, which was in poor mechanical condition. Well 12-4 was completed with a 6 5/8-in. liner with 40-mesh slots. Producer 7-7 was redrilled in May 1977 to sidetrack a collapsed liner. It was completed the same way as the previous wells but with 50-mesh slots. All producers in the project have slotted liners opened to other producing intervals. Slot plugging and lack of control of placement during steam stimulations are the major drawbacks to liner completions. JPT P. 2251^

Gas and Electrical Heating Assisted Gravity Drainage(GEAGD in short) is a new heavy oil production technology, in which, dual parallel horizontal wells or combination of vertical well and horizontal well are involved as electric dipole moments to heat the reservoir in distributed resistive method. At the same time, the upper well is used as gas (N2, CO2, flue gas, hydrocarbon gas, etc.) injection well, and the lower as production well. GEAGD is applicable and potential to enhance oil production rate or oil recovery for heavy oil reservoirs produced by cold production or steam injection because it has many advantages such as high heating efficiency, eliminating oil-water flow effect on oil production, enlarging heating reservoir volume by injected gas, gravity assisted oil drainage by electrical heating and gas, pressure maintenance and heat insulation by gas cap gathered at the top of reservoir. Particularly, GEAGD is potential to recover heavy oil reservoir unfit for steam injection such as offshore heavy oil reservoir for it is difficult to install steam generator on the production platform with limited space. In this work, primary theoretical analysis, simulation experiment, and numerical simulation are carried out to investigate feasibility and potential of producing heavy oil by GEAGD. Firstly, related theoretical foundation of GEAGD is introduced. Secondly, production performance and temperature and gas distribution in GEAGD process are analyzed based on experiment and numerical simulation in detail. At last, EOR principles of GEAGD are discussed. Results of primary experiment show that larger oil production increase could be obtained by GEAGD process, and more than 6 times as much as cold production of oil production rate achieved by distributed heating GEAGD. At the same time, numerical simulation shows that more than 2 times of cumulative oil production could be obtained by dual-well concentrated heating GEAGD compared to cold production. Distributed heating or dual-well concentrated heating is recommended for GEAGD process, and heaters located in both injection well and production well or heater location in single injection well are preferred for concentrated heating GEAGD. Significant synergetic effects of gas and electrical heating are observed in GEAGD process, the gas sweep volume in GEAGD is enlarged by electrical heating compared to gas push process, at the same time, and heating volume is extended by gas flow and diffusion. Based on the achievement of this work, it is indicated that GEAGD is more feasible and potential to enhance heavy oil production than gash push and electrical heating. Introduction Steam injection such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) is the main EOR processes for heavy oil production in the world, and more than 60% heavy oil is produced by steam injection. However, there are some disadvantages or challenges for conventional steam injection:heat loss during steam flow in surface pipes and tubing (up to 20%~30% of steam enthalpy at the boiler outlet);effect of condensed water-oil flow on oil production, heating efficiency reduction for the residued water;sweep and heating efficiency decrease for steam phase splitting and steam overflow;unfit for deeper reservoir, offshore reservoir, reservoir in desert district and other water sensitive reservoirs. It is challenging to develop some innovative technology to recover steam stimulated reservoirs and unconventional heavy oil reservoirs such as offshore heavy oil reservoir not well recovered by cold production methods such as ESP.

Thermal recovery processes such as cyclic steam stimulation and steam assisted gravity drainage involve large volume fluid and steam injection into oil sand reservoirs. Thermal expansion and dilatation of oil sand formation causes horizontal and vertical displacements in the overburden. These deformations may not exert detrimental effects on casings and facilities if the deformation properties of the overburden are homogeneous without drastic local variation along depth. However, if there exists some natural (clay seams) or induced weak layers (swollen and softened shale layer), shear slip could develop along these discontinuities, thereby impairing the nearby casings and facilities. This paper develops a semi-empirical analytical method for estimating the relative shear slip along a weak layer in shale due to fluid and steam injection. The magnitude of slip depends on the volume and distribution of fluid and steam injection, and the extent and location of the weak layer. Calculated results demonstrate that the shear slip along the weak layer could impose concerns regarding the steaming strategy and environmental protection.

This paper provides an overview of current steam injection technology. The emphasis is on steamflooding with some data on cyclic steam stimulation. subjects discussed include oil recovery and sweep latest trends in steam injection operations and equipment, operating problems, and special conditions encountered in steamflooding such as gas cap and bottom water. Introduction The purpose of this paper is to help petroleum engineers keep up with emerging steamflood technology including both reservoir and operating experience. Steam injection is the principal enhanced oil recovery method today, accounting for 90% of all oil produced by such methods. Prats estimates the produced by such methods. Prats estimates the total worldwide oil production rate due to steam is now 405,200 B/D. Production in the U.S. is about 240,000 B/D, Venezuela 148,000 B/D, and Canada 9,000 B/D. It is the most important recovery method for the oil sands of Alberta and Orinoco (Venezuela), where several large projects are in the planning and construction stages. There has been a significant advance in steam injection technology since the principal author reviewed the status of steam injection at the CIM meeting five years ago. The Oil and Gas Journal's annual review for 1978 lists 99 active steam injection projects for the United States, 41 for Venezuela, and 14 for Canada. In addition, petroleum engineers have published a number of technical papers which describe field projects and provide greater understanding on how the process can best be applied in the future. The most notable development in steam injection over the past five years is the overwhelming shift to steamflooding, with cyclic steam stimulation becoming an important adjunct, rather than a separate oil recovery precess. This is attributed to the relatively low ultimate oil recovery attainable by cyclic steam stimulation on the one hand, and to higher oil prices on the other, which have served to make the considerably lower oil-steam ratios, characteristic of steamfloods, economically attractive. STEAM INJECTION FIELD TESTS Tables 1(a) and 1(b) list the principal statistics for 12 selected steam injection field tests. These represent the major steam injection projects except for-those already reported earlier in References 2 and 3. All, except Test 6, are steamfloods. Test 6, a commercial cyclic steam stimulation project in Indonesia, is included here because of project in Indonesia, is included here because of its size and the high oil-steam ratio achieved. Unfortunately, several large projects are not listed in Table 1 because sufficient data were not available. These include: Imperial's Cold Lake Lemming project (5000 B/D: cyclic stimulation), Chanslor-Western's Midway-Sunset, California project (23,000 B/D: steamflood), Texaco's San Ardo project, California, and several projects in Venezuela. Table 1(a) gives the formation characteristics for the tests cited, while Table 1(b) lists some of the test results for the same. It is notable that the formation thickness in most cases is 100 ft. or less. There is a wide variation in reservoir pressures and oil viscosities. Tests 7 and 12 are pressures and oil viscosities. Tests 7 and 12 are essentially in the start-up stage; the data given are based upon scaled model studies. The only projects repeated from the previous survey are Tests 10 and 11, which have undergone major expansions. Table 1(b) shows that oil recoveries up to 73% have been attained in steamfloods conducted to-date, and are much higher than previously reported. Consequently, the oil-steam ratios average 0.20 bbl/bbl, or better. Test 4, Charco Redondo, was cited in Table 1 primarily because of its unique features. It was a primarily because of its unique features. It was a highly instrumented steam pilot in a waterflooded reservoir; following the steamflood, and was successfully subjected to in situ combustion.

Yarega heavy oil field (YHOF) is a naturally fractured heavy oil field where only recently steam‐assisted gravity drainage (SAGD) technology has been introduced. SAGD employed in this field has so far resulted in early steam breakthrough leading to producer well abandonment and recurrent drilling procedures invariably increasing costs. Therefore, as opposed to SAGD, we propose the joint application of cyclic steam injection (CSS) technology with fishtail wells. The advantages of CSS are well documented. The addition of fishtail wells to this strategy assists in reducing the travel time the mobilized oil takes to arrive at a well perforation. Our results demonstrate that the synergy between these two strategies can further improve recoveries in heavy oil reservoirs. A reservoir simulation model of a sector in the YHOF is employed to understand heat/mass transfer mechanisms and for production enhancement recommendations. Different well configuration strategies were tested on this model. Results from the three‐dimensional sector in the YHOF model suggest that in addition to the thermal development technologies employed in this reservoir, CSS coupled with fishtail wells provided favorable steam‐oil ratios, cumulative energy‐oil ratios, and enhanced cumulative oil recovery for a naturally fractured reservoir. Well abandonment issues arising from SAGD approach currently being applied can therefore be eliminated. Based on results from this research, we recommend the testing of a fishtail well development plan with CSS that includes a 10‐day steam injection, 10‐day soaking period, and 10‐day production period. In comparison with continuous steam injection recovery (4.5% over 3 years), our simulation results showed an improved recovery of 7% over the same period with this concept. In addition to the technical advantage of this strategy, favorable steam‐oil and energy‐oil ratios imply that minimal economic costs are achieved and carbon footprints are lessened.