Impact of Reservoir Properties on Micro-Fracturing Stimulation Efficiency and Operational Design Optimization

A comparison of three thermal EOR processes; SAGD (Steam Assisted Gravity Drainage), HASD (Heated Annulus Steam Drive) and CYS (Cyclic Steam Stimulation), has been made using a three dimensional thermal simulator by employing a combination of vertical and horizontal wells. Reservoir characteristics and thermal and fluid properties were maintained identical for process comparison. A 10-year project-time study was undertaken for CYS with vertical wells, CYS with horizontal wells, HASD with horizontal HAS pipe and aligned vertical injector and producer, HASD with offset vertical producers, and SAGD with horizontal injector and producer. The effect of reservoir heterogeneities on process performance was also examined. CYS vertical performed significantly better than CYS horizontal both in terms of cumulative % OOIP recovery and SOR. HASD recovered more oil, though the initial production rate in HASD was low. SOR in HASD was, however, very unfavorable (more than twice that of CYS vertical). HASD with offset wells made both SOR and % OOIP recovery more favorable. SAGD had better SOR than HASD; however, it recovered about half the oil recovered by HASD at the end of ten years. An unfavorable heterogeneity feature (low permeability layers or barriers) affected the recoveries and SORs for the horizontal well processes more adversely than vertical well processes.

SAGD has been proven to be a commercially viable method to extract bitumen from oil sands reservoirs in Western Canada. To understand the influences of steam injection on reservoir and surrounding rocks and potential impacts of surface deformation on the environment, instrumentations such as piezometers, thermocouples, extensometers, tiltmeters, geophones and 4D seismic survey have been applied in SAGD projects. The effects of geomechanics on SAGD have been well documented. Collecting essential geomechanical data, interpreting them properly and incorporating them into numerical models are necessary to ensure meaningful history matching and understanding of reservoir performances. This paper outlines geomechanical data acquisition and field monitoring methods from a reservoir engineering perspective, and the applications of geomechanics in SAGD design and history matching. Minimum data acquisition programs to collect the necessary geomechanical data for different analysis purposes in SAGD projects are suggested. Primary instrumentations are briefly overviewed and recommendations to instrumentation selection are provided. Using generic Canadian oil sands reservoir and rock properties, the subsurface and surface deformation including permeability changes, reservoir movements, strains and surface uplifts etc. are simulated. The method to couple the results of geostatistics modeling, reservoir simulation and geomechanics in SAGD simulation and to link them with 4D seismic in history matching is provided. Simulations are completed with the widely applied thermal simulator, STARS ®, and its limitations are also discussed. Introduction Steam Assisted Gravity Drainage (SAGD) has been proven to be a commercially viable method to extract bitumen from oil sands reservoirs in Western Canada(1)–(3). In SAGD process, high temperature steam is injected into the reservoir with pressures closed to or higher than initial reservoir pressures. Steam temperature in the reservoir could be over 200 °C and pressure up to 5 or 6 MPa. This can cause significant geomechanical effects on the reservoir and surrounding rocks, and may also affect surface facilities and the surface surrounding environment. The influences of SAGD on bitumen recovery from oil sands have been investigated by a number of researchers such as Chalaturnyk(4), Collins(5), and Li(6), and some of their findings will be referred to in his paper. In addition to ensuring safe SAGD operations, geomechanics understanding will be necessary to investigate the potential breaking of interbedded mudstone and IHS (Inclined Heterolithic Stratification), a commonly found geological feature that often are baffle to the upward growth of a SAGD steam chamber. As demonstrated by Li(6), if these IHS can be broken, SAGD bitumen recovery would increase significantly where IHS is prevalent. Several types of field monitoring methods have been applied in SAGD projects to understand geomechanical responses and steam chamber dynamics. Piezometers and thermocouples are commonly used to monitor pressures and temperatures at observation wells and SAGD injectors and producers(4). Downhole extensometers and inclinometers (tiltmeters) were also installed in the UTF project to measure vertical strains and displacements(4). Tiltmeters are applied to monitor surface deformations and triaxial geophones to detect microseismic events during SAGD recovery(7).

Steam stimulation is one of the viable methods to extract heavy oil from oil sand reservoirs in Alberta. In this thermal process, steam is injected into the oil sand reservoir. The oil sand formation expands due to an increase in pore pressure and thermal heating. This expansion results in an upward movement of the overburden, and thus, heaving of the free ground surface. This paper proposes an analytical method to estimate the surface heave induced by steam injection. The method was used to investigate the surface heave profiles under horizontal well injection. It was found that the surface heave profile is governed by the mass and heat transfer and distribution within the oil sand reservoir. The effect of the increase in pore pressure (or decrease in net overburden stress) on the surface heave is also compared to that due to the thermal expansion of the oil sand. The paper also discusses the limitations on the use of surface heave monuments and tiltmeters in monitoring the thermal recovery process. Introduction Thermal recovery processes such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) involve large volume fluid and steam injection into oil sand reservoirs. Steam injection produces a dilatation of the oil sand reservoir due to an increase in pore pressure and temperature of the reservoir. The overburden containing the reservoir responds to the steam injection by upward heaving of the free ground surface. Surface heave of up to 20 cm has been recorded(1). The profile of the surface heave reflects the distribution of the injected steam within the oil sand formation. Monitoring the surface heave evolution during the steaming operation may be used as an inverse method of monitoring the steam injection operation. This paper presents an analytical method to determine the surface heave profile induced by steam stimulation for a horizontal well. Parametric studies were conducted to investigate the important factors contributing to the surface heave profile. Problem Statement This study considers a steam stimulation operation using a horizontal well. Steam is injected into a horizontal well installed within an oil sand formation of finite thickness (Figure 1). Since the overburden serves as a competent hydraulic barrier to the fluid upward migration, it is assumed that the injected steam is contained within the oil sand reservoir, which results in an expansion of the reservoir. Thus, steam injection using a horizontal well can be treated as a two-dimensional plane strain problem. Figure 1 illustrates the problem statement. The objective of the exercise is to determine the surface heave profile as a function of the amount of steam injected into the horizontal well. Methodology Steam stimulation is a complex thermal hydraulic mechanical multiphase flow process. Determination of injected fluid distribution within the reservoir is not trivial. Since the shale overburden serves as a competent hydraulic barrier to the fluid upward migration, the geomechanical responses in the overburden are governed by the expansion pattern of the oil sand reservoir due to steam stimulation.

Numerical simulation of undulating shale breaking with steam-assisted gravity drainage (UB-SAGD) for the oil sands reservoir with a shale barrier

Summary The ever-increasing world demand for energy to satisfy current needs and future economic growth has forced the oil and gas industry to exploit challenging energy resources. Heavy oil and oil sands are challenging because of the complexity of reservoirs together with high-oil viscosities, which are often greater than hundreds of thousands to millions of centipoise. Most steam-based recovery processes, such as cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD), require a competent caprock to prevent excessive steam losses and maintain good thermal efficiency and production rates, as well as preventing steam flow to surface. However, there exist significant amounts of oil sands resources, which have little or no caprock; thus, at this point, these resources are considered inaccessible. This research examines the feasibility of using SAGD in oil sands reservoirs with no caprock with detailed thermal reservoir simulation. The results of this research provide guidelines that explain how to implement the SAGD process in shallow oil sands reservoirs with no caprock. This could unlock a resource that is currently considered inaccessible. The results show that vertical chamber growth can be controlled to some extent by using variable pressure operating strategies and coinjection of a noncondensable gas, such as methane. In oil sands reservoirs without caprocks, pressure control is critical, especially if there is to be minimal fluid invasion from the oil sands formation into the water zone above. However, the pressure must be sufficient to delay or prevent flow of water into the steam chamber. This study is important because in Alberta, Canada alone there are billions of barrels of shallow oil sands resources without sufficient caprock to operate conventional high-pressure steam recovery processes, such as CSS and SAGD. The results of the study provide a technical basis to design feasible low-pressure steam processes for such reservoirs.

Many heavy oil and oil sand reservoirs in Canada are in communication with a water sand, and in some cases, with a gas cap. Conventional thermal recovery methods using vertical wells in these thin reservoirs (5 - 10 m of pay) have been unsuccessful. The use of optimally placed horizontal wells has proved, in a few cases, to be economically feasible, due to a reduction of the heat loss to the cap rock and bottom water layer, as well as better overall heat distribution in the reservoir. Steamflooding heavy oil/oil sand reservoirs with a contiguous water sand is risky due to the possibility of short circuiting the steam chamber. The success of the Steam-Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) in Fort McMurray, Alberta has, in many ways, lent its application to these reservoirs. The success of subsequent projects depends largely on the efficient utilization of heat injected into the reservoir, among several aspects related to reservoir heterogeneities and operational strategy. This work studied how the SAGD process is affected by the presence of a water sand, and determined how heat is distributed in these reservoirs. Reservoir heterogeneities, wellbore hydraulics, and geomechanical impact were not considered in this study. The results of this study showed a relationship between ultimate recovery, heat accumulated in the reservoir, and the thickness of the water sand (bottom or top water). For the base case run, an average oil rate of 80 m3/d was maintained for 1,400 days before it started to decline. Ultimate recovery was approximately 70% of the OOIP after nine years of steam injection, and the cumulative OSR was 0.3 m3/m3 (CWE). The presence of a bottom water sand had a lesser impact on recovery than when an overlying water sand was present. Recovery efficiency decreased with increasing water sand thickness. In the case of overlying water sand, larger areal coverage of the overlying water sand severely reduced the recovery efficiency of the process, as heat was diverted (or channeled) into the "thief' zone. When a bottom water layer was present, the BHFP (bottom hole flowing pressure) of the horizontal producer could be operated at or above the pressure of the aquifer to prevent water coning and hence only affected the heat source slightly. Introduction Successful application of the SAGD Process at the Underground Test Facility (UTF) demonstrated it to be a commercially viable recovery method to exploit heavy oil and oil sand reservoirs(1–4). Some of these studies examined the mechanics of the SAGD process, while others discussed the implementation of this process (including operational constraints) at UTF. In this paper, an examination of SAGD application to an oil reservoir in communication with water sand, as well as the effects of confined and unconfined water-bearing zones, was evaluated. Heat balance calculations were also performed to establish relationships between heat accumulated in the reservoir to the thickness of the water sand and the recovery efficiency.

The Steam Assisted Gravity Drainage (SAGD) process is widely used in the Athabasca oil sands deposit to recover bitumen. Since the viscosity of bitumen is high at original reservoir conditions, heat is required to lower its viscosity to the point it becomes mobile enough to be recovered under gravity drainage. To heat the reservoir, steam is injected into the formation and thus SAGD is energy intense – on average, the steam-to-oil ratio (SOR) is equal to about 3.5 m3 (expressed as cold water equivalent) of steam injected per m3 of bitumen produced. Given that the fuel used to generate steam is the largest operating cost, the SOR is a key parameter for evaluating the economics of any SAGD project. The target for many SAGD operations is a SOR lower than 2.5 m3/m3. Here, we explore the use of dynamic distributed steam injection within a pad of SAGD wellpairs controlled via a Proportional-Integral-Derivative (PID) feedback controller, a concept we refer to as Smart Pad. The Smart Pad Reservoir Production Machine is designed to dynamically distribute steam injection along multiple well pairs so that over a period of operation, the pad-scale cSOR is dynamically improved as the process evolves. First, a method to condition the PID control gains is described and second, the controller is applied to a multiple well pair SAGD pad in an oil sands reservoir with a top water zone. The results demonstrate that automated control can lead to improvements of the SOR over that of constant pressure. The results show that automated PID control is able to detect the "sweet spots" (oil zones with better geological properties) in the reservoir and dynamically deliver more steam to that region. Meanwhile, it reduces the steam injection towards relatively worse reservoir quality zones, i.e. shale barriers, high permeability channel to the top water zone, to lower the local SOR. In this manner, the PID feedback controller provides an efficient method to recovery bitumen in SAGD operation, especially during the first 7-10 years' operation, where it helps to achieve a relatively low cSOR and maintain a normal level of oil recovery. Also, the PID controller reduces the degree of dependence of SAGD operation on the geological conditions of the reservoir. The algorithm described could be applied to any operating or new SAGD pad.

Steam-assisted gravity drainage (SAGD) is widely applied to recover bitumen and heavy oil resources. Reservoir heterogeneity, especially the presence of shale barriers, continues to challenge the performance of SAGD. A novel enhanced oil recovery process, bottom-up assisted pressure drive, is proposed to improve the oil production in the reservoirs with shale barriers. In this work, numerical simulation is applied to investigate the feasibility of a bottom-up assisted pressure drive process. A reservoir model with typical oil sand reservoir properties is developed considering shale barriers. The performance of bottom-up assisted pressure drive and SAGD is compared under the same reservoir conditions, including steam chamber development, oil production rate, cumulative oil production, and the pressure difference between injector and production. The inherent mechanisms associated with the bottom-up assisted pressure drive are also well understood and confirmed. In the bottom-up assisted pressure drive, a flat steam chamber is developed from the bottom of the reservoir in the early stage of the process and grows upward with the injection of steam. The large volume of the steam chamber and the huge contact area between steam and bitumen contribute to a high oil production rate. The peak oil production rate in the bottom-up assisted pressure drive is approximately three times that in the SAGD process. The cumulative oil production in the bottom-up assisted pressure drive is 20% higher than that in the SAGD process. The effect of shale barriers on bottom-up assisted pressure drive is less, indicating one advantage of this novel process over SAGD in oil sands reservoirs with shale barriers. The pressure difference in the bottom-up assisted pressure drive is greater than that in the SAGD process. The pressure drive is another mechanism for improving oil production. The calculated net present value (NPV) in the bottom-up assisted pressure drive process is 27% higher than that in the SAGD process. This is mainly attributed to the high oil production rate in the early stage of the process and high cumulative oil production. The simulation study in this work provides technical support for the future field applications of this novel recovery process.

The ever increasing world demand for energy to satisfy the current needs and future economic growth has forced the oil and gas industry to exploit challenging energy resources. Heavy oil and oil sands are challenging due to the complexity of the reservoirs together with the high oil viscosities which are often greater than hundreds of thousands to millions of centipoise. Most steam-based recovery processes such as Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD) require a competent cap-rock to prevent excessive steam losses and maintain good thermal efficiency and production rates. However, there exist significant amounts of oil sand resources which have little or no cap-rock and thus, at this point, these resources are considered inaccessible. This research examines the feasibility of using SAGD in oil sands reservoirs with no cap rock with detailed thermal reservoir simulation. The results of this research provide guidelines on how to implement the SAGD process in shallow oil sands reservoirs with no cap rock. This could unlock a resource that is currently considered inaccessible. The results show that vertical chamber growth can be controlled to some extent by using variable pressure operating strategies and co-injection of a non-condensable gas such as methane. In oil sands reservoirs without cap-rocks, pressure control is critical especially if there is to be minimal fluid invasion from the oil sands formation into the water zone above. However, the pressure must be sufficient to delay or prevent flow of water into the steam chamber. This study is important since in Alberta, Canada alone there are billions of barrels of shallow oil sands resources without sufficient cap rock to operate conventional high pressure steam recovery processes such as CSS and SAGD. The results of the study provide a technical basis to design feasible low pressure steam processes for such reservoirs.

Performance of multiple thermal fluids assisted gravity drainage process in post SAGD reservoirs

Steam-assisted gravity drainage in oil sand reservoirs using a combination of vertical and horizontal wells

Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells

Prediction of steam-assisted gravity drainage steam to oil ratio from reservoir characteristics

Many heavy oil and oil sand reservoirs are in communication with water sand(s). Depending on the density (°API gravity) of oil, the water sand could lie above or below the oil zone. Steamflooding a heavy oil or oil sand reservoir with a contiguous water sand (water which may lie below or above the oil-bearing zone) is risky due to the possibility of short circuiting the steam chamber. The Steam Assisted Gravity Drainage (SAGD) process was first tested at the Underground Test Facility (UTF) in Fort McMurray, Alberta. The successful application of this process to Athabasca-type oil sands has extended its application to other heavy oil and oil sands reservoirs. To date, the application of this process to a variety of different reservoirs has shown mixed results due to a variety of reasons. In our opnion, the success of these projects depends on: 1) accurate reservoir description, 2) efficient utilization of heat injected into the reservoir, 3) understanding displacement mechanism, 4) understanding of geomechanics (the interaction between the fluids and the reservoir at elevated temperatures and pressure), and 5) overcoming various operational constraints. This paper looks at how the SAGD process is affected by the presence of water sand, and determines how heat is distributed in these reservoirs. Results of this numerical simulation study show a relationship between ultimate recovery, heat accumulated in the reservoir and the thickness of the water sand (bottom or top water). For the base case run, an average rate of 80 m3/d was maintained for 1400 days before it started to decline. Ultimate recovery was approximately 70% of the OOIP after 9 years of steam injection, and the cumulative OSR was 0.3 m3/m3 (CWE). The presence of a bottom water sand has a lesser impact on recovery than the case where an overlying water sand is present. As the thickness of the water sand increases, the recovery efficiency decreases. Increasing the areal coverage of the bottom water sand resulted in slightly reduced recovery as compared with the confined bottom water sand. On the other hand, increasing the areal coverage of the overlying water sand, that is 9m thick, severely reduced the recovery efficiency of the process as heat is diverted (or channeled) into the "thief" zone. The oil steam ratio (OSR) in this run was below 0.15 m3/ m3 (CWE) after 400 days of injection. When a bottom water layer is present, the BHFP (bottom hole flowing pressure) of the horizontal producer could be operated at or above the pressure of the aquifer to prevent water coning and hence only effecting the heat source slightly.

At the Hangingstone reservoir of the Athabasca oil sands, Japan Canada Oil Sands (JACOS) started initial steam circulation of the SAGD Phase I project in April 1999, and the regular operation in July. The expected performance was achieved in the early period. The operation pressures were gradually raised from 4,800 kPa in mid-November 1999 to 5,300 kPa in mid- December. In early 2000, initial circulation of the Phase II wells, which consist of three SAGD pairs of 750 m wells, were started. Steam produced at the Phase I steam generator was supplied to warm up these wells. Because of this dual use of steam, the injection pressure of the Phase I wells had to be reduced to 4,600 kPa. A significant change in the growth rate of the steam chamber was detected at some of the observation wells. This was reflected as a suspension of vertical growth of the steam chamber. A new generator to supply steam for Phase II wells was completed in July 2000. Accordingly, the steam injection pressures for Phase I wells were increased in August and the vertical growth of the steam chamber was resumed. The measured temperature changes in the observation wells, the results of numerical simulation study, and conceivable mechanism of the growth of steam chamber are presented in the paper. Introduction The Steam Assisted Gravity Drainage (SAGD) process has been widely accepted as an in situ recovery process of bitumen from oil sands reservoirs. There are many pilot and commercial scale projects currently underway in Alberta(1). Japan Canada Oil Sands Ltd. (JACOS) has participated in the Underground Test Facility (UTF) project since 1992 and has endeavored to develop a clear understanding of the process. The original recovery mechanism presented by Butler(2) has been improved by introducing more realistic convective heat flow(3–5) and accumulation of noncondensable gas(6) in the reservoir. The major effort, however, made during the last ten years was a field study using a numerical simulator. Special emphasis was placed on understanding the growth mechanism of the steam chamber by rigorous simulation of temperature changes at observation wells. Most of the temperature changes measured at observation wells and horizontal production wells for many SAGD projects, including Imperial Oil's vertical-horizontal well project(7), UTF Phases A, B, and D, and Hangingstone Phases I and II, have been reproduced by numerical simulation. A part of the above study involving the UTF Phase B and early Hangingstone Phase I projects(8) was presented in 2000. A phenomenon of "generation of an impermeable layer during the AGD process" was developed during the subsequent examination of the previous article(8), which is presented in this paper. Hangingstone SAGD A-Pair The Hangingstone Phase I SAGD project consists of two pairs (A-pair and B-pair) of 500 m horizontal wells. Initial circulation was conducted from April 14 to July 27, 1999, followed by a regular SAGD operation. The early performance was close to our expectation(8) and the steam chamber was detected in many observation wells.