Steam Injection Pressure Research Articles

Steam Injection Pressure and the SAGD Ramp-Up Process

Abstract Most SAGD projects require about one to two years for ramp-up. Over this period of time, oil rate will be below peak oil rate and SOR will be higher than long-term steady-state SOR. This paper discusses the effect of steam injection pressure on SAGD ramp-up time, the associated geomechanical effects and optimization of the ramp-up phase of SAGD. Different steam injection pressures induce different reservoir geomechanical behaviour in oil sands. Higher steam injection pressure is capable of inducing more favourable reservoir geomechanical effects (such as shear dilation and isotropic unloading), improving the reservoir permeability, and subsequently, benefiting the long-term SAGD operation. This paper indicates that the ramp-up time can be reduced due to the favourable geomechanical effects. A coupled reservoir geomechanical simulation technique was applied for this investigation. In addition, cap rock integrity concerns when applying high injection pressure are also addressed. It is recommended that during or following the ramp-up phase, the injection pressure be lowered to a safe operating pressure to ensure cap rock integrity. The effects of low and high steam chamber pressures on SAGD oil rate are also discussed. Introduction The steam-assisted gravity drainage (SAGD) process has been proven to be the most promising technology for developing the Athabasca oil sands reserves in northern Alberta. In 2001, only four commercial SAGD projects were operating in the field(1). By March 2006, the number of active SAGD projects increased to 15(2). Field SAGD operation experiences and numerical simulation show that the steam injection pressure plays an important role in SAGD production performance. In general, higher steam injection pressure helps lift fluid from downhole to the surface, increases the oil production rate, reduces the overall well life and improves the ultimate oil recovery. Some of these enhancements could result from geomechanical effects induced by higher steam chamber pressure. For the unconsolidated oil sands reservoir under certain in situ stress conditions, higher steam injection pressure tends to induce larger volumetric strain associated with shear dilation, thermal expansion, and even, tensile failure. As a result, reservoir permeability can be improved and oil recovery will be accelerated. Higher steam injection pressure, however, can also have undesirable effects. It may cause the reservoir cap rock to be breached due to geomechanical behaviour, and then result in a very high steam-oil ratio (SOR). Therefore, the time for applying high steam injection pressure needs to be optimized for maximum geomechanical benefits without causing cap rock failure. From the beginning of steam injection to the time when the partially drained zone approaches the cap rock, higher injection pressure may be safely applied. This strategy will accelerate the oil production rate for the ramp-up phase and will attain the peak SAGD oil rate sooner than otherwise possible. This paper applies a coupled reservoir geomechanical simulation (called "coupled simulation") technique(3) to investigate the relationship between the steam injection pressure and the SAGD ramp-up process.

Assessment of Optimal Operating Conditions in a SAGD Project by Design of Experiments and Response Surface Methodology

The steam-assisted gravity drainage (SAGD) is likely the most efficient and important thermal recovery in-situ method to produce extra-heavy oil and bitumen reservoirs. Indeed, a huge expansion of commercial SAGD applications is taking place, particularly in the Alberta oil sands of Canada. Numeric reservoir simulators are available for predicting SAGD performance indicators and are used as tools to support reservoir management decisions. Those decisions are related to the selection of optimal values of controllable variables, including operating conditions such as preheating period, sub-cooling temperature, maximum steam injection pressure, maximum steam injection rate and steam quality, and temperature. In order to make unbiased decisions, the optimization process should be done considering the stochastic character of reservoir variables. However, the high computational time associated to the complex numeric solution of reservoirs under the SAGD recovery process makes the integration of reservoir uncertainty to the SAGD decision-making process an almost impossible task. Thus, a calibrated-proxy is used in this work as an efficient substitute of the numeric simulator to accomplish such a task. Design of experimental techniques and response surface methodology allowed the construction of a simple model by fitting a quadratic model to reservoir simulator outputs extracted from a chosen set of simulation cases. The main purpose of this work was to optimize the production and injection constraints of a SAGD well pair, based on an Athabasca oil sands data set, in order to maximize the net present value in presence of reservoir uncertainty. The production and injection constrains considered in the problem were: injection pressure, maximum steam flow rate, and sub-cooling temperature; and the reservoir uncertainty was represented by vertical permeability, porosity, thickness, horizontal to vertical permeability, and initial oil saturation. The results indicate that experimental design and response surface techniques are excellent tools to quickly obtain valuable information about the SAGD performance.

Preparation and characteristics of moulded biodegradable cellulose fibers/MPU-20 composites (CFMCs) by steam injection technology

In this work, the moulded cellulose fibers/MPU-20 composites (CFMCs) with apparent specific gravity lower than 100 kg/m 3 and thickness of 20–200 mm have been successfully manufactured using a new design of steam injection technology and equipment. It was found that the CFMCs have good cushioning properties, with a cushion factor lower than 4. Two yield deformation stages were observed in the compressive process. Compressive stress–strain and cushion factor-stain curves were measured as a function of steam injection pressure, transmission time, holding time, MPU-20 resin dosage and apparent specific gravity. Chemical groups, crystallinity, and thermal properties of samples were studied through the use of FTIR spectroscopy, X-ray diffraction (XRD), and DTA–TGA. In addition, the microstructure and morphology were investigated by scanning electron microscope (SEM) and atomic force microscope (AFM).

Gas-Over-Bitumen Geometry and Its SAGD Performance Analysis With Coupled Reservoir Geomechanical Simulation

Abstract In Northeastern Alberta, gas pools and oil sands reservoirs exist in which the energy content of the bitumen (or oil sands) is estimated to be 600 times greater than the gas for this region. The sealing layer between the top gas pool and the bitumen reservoir, if it exists, plays a critical role in the optimization of SAGD projects. Gas pool pressures may or may not be in communication with oil sands reservoir pressures. So, although different cases of gas-over-bitumen geometries exist, this paper is focused on the gas-over-bitumen geometries with a mudstone layer between the top gas/water and the oil sands reservoir. The top water zone is assumed to be a thief layer. The SAGD process applies higher thermal stress and induces higher pore pressures inside the mudstone layer. Thus, the mudstone becomes weaker or even fails as a result of shear failure or tensile failure. As a result, the permeability of the mudstone layer may be increased significantly and more heat loss to the gas sands and top thief water zone can result in a poor SAGD production performance. This paper discusses the SAGD production performance of the gas-over-bitumen geometries with varying mudstone permeability. The effect of steam injection pressure is also studied. The research was conducted based on both a conventional reservoir simulation and a coupled reservoir geomechanical simulation. Prior to the simulation study, the geomechanical properties of oil sands and mudstones are briefly discussed. Introduction It is reported that almost one-third of the area of Athabasca oil sand deposits have both oil sands reservoirs and gas pools (see Figure 1)(1). The associated gas is in pressure communication with bitumen within a region of influence either directly or through a connecting water zone. The non-associated gas is not in pressure communication with bitumen. As a result of an exhaustive geological study conducted of the region(2), the relationship between gas and bitumen has been divided into seven cases. This paper is focused on one of those cases: an oil sand reservoir with non-associated gas pools. A mudstone layer separates the gas pool from the underlying bitumen reservoir. For the gas-over-bitumen SAGD geometries, the effect of gas pool depressurization on the SAGD production performance has been discussed since the last decade and it is still an area of active research(3, 4). The role played by geomechanics has been discussed in terms of the process of gas pool depressurization, re-pressurization and wellbore stability analysis(3). However, to our knowledge, a detailed assessment of the mudstone geomechanical behaviour was not taken into account in the prediction of SAGD production performance. In a previous work, Li et al.(5) provided a coupled reservoir geomechanical simulation methodology which involves both the reservoir simulator, EXOTHERM, and the geomechanical simulator, FLAC. This paper applies that coupled reservoir geomechanical simulation technique to study the effect of mudstone permeability and steam injection pressure on the SAGD production performance. Prior to the section on the simulation, the geomechanical properties of oil sands, the geomechanical behaviour of the mudstone layer and the permeability variations associated with geomechanics are discussed.

Optimization of Steam Assisted Gravity Drainage in McMurray Reservoir

Abstract Many field tests of the steam assisted gravity drainage (SAGD) process have been conducted and have shown that the process is a technically effective one at extracting oil from heavy oil and bitumen reservoirs. However, it has not been firmly established whether the technology is operated at optimized conditions to yield maximum economic returns. This is especially important because typically SAGD depends on the combustion of natural gas to generate steam and this is the dominant cost. The cost of natural gas can be significant when natural gas prices are high. This research evaluates the use of a genetic algorithm optimization scheme to control a commercially available thermal reservoir simulator in order to optimize the steam injection strategy to reduce the cumulative oil to steam ratio (cSOR). The reservoir description is typical of that from a low to medium quality Athabasca reservoir. The results show that the injection strategy can be altered to reduce the cSOR up to 50% from a uniform injection pressure strategy to 1 after the steam injection strategy has been optimized. The optimized profile has high steam injection pressure at the beginning of the process before the steam chamber reaches the top of the oil-rich zone. Before the chamber reaches the oil pay, with high injection pressure, the saturation temperature is high and there are no thermal losses to the overburden. After the chamber reaches the top of the formation, the injection pressure is lowered throughout the remainder of the process. This reduction of injection pressure implies that the saturation temperature falls and consequently the losses to the overburden are lowered. Thus the overall thermal efficiency of the process is enhanced. The optimized strategy is compared to processes operating at 1,000 and 2,000 kPa constant injection pressure. Introduction Steam assisted gravity drainage (SAGD) has now been extensively tested and put into commercial production in the Athabasca and Cold Lake regions of Alberta(1–5). The majority of existing SAGD projects are based in Alberta, Canada: more than nine are located in the Athabasca region (the McMurray formation); one in the Peace River region, (the Bluesky formation); four are in the Cold Lake region (the Clearwater formation and the Grand Rapids formation); and, five are in Saskatchewan (the Grand Rapids formation). The SAGD process, shown in Figure 1, was developed by Butler(2) while at Imperial Oil in the late 1970s. The process consists of two aligned horizontal wellbores. Steam is injected into the top one, whereas reservoir fluids are produced from the bottom one. The process is non-cyclic; that is, steam is continuously injected and fluids are continuously produced. Around and above the injection well, a steam chamber grows. The injected steam flows into the steam chamber and eventually comes into contact with oil sand at its edge. The steam then releases its latent heat to the oil sand, the oil heats up, its viscosity drops, and it flows (with water condensate) under gravity down the inclined chamber edge to the production well.

Permeability Variations Associated With Shearing and Isotropic Unloading During the SAGD Process

Abstract This paper discusses the variations of reservoir permeability within unconsolidated sands due to isotropic and deviatoric (shear) processes during the SAGD process. Isotropic unloading results from the steam injection pressure, which is generally higher than the initial reservoir pressure. The high steam injection pressure results in the increase of pore pressure and reduces the confining effective stress within the drained zone and part of the partially drained zone. The shearing process is induced primarily by changes in total stress but can also occur with increased pore pressures. High steam temperatures associated with the SAGD process result in significant volumetric expansion of the reservoir material within the steam chamber. Thus, total stress is increased and the shearing process may occur beyond the steam chamber surface. Both the isotropic unloading and shearing processes can induce reservoir permeability variation because of the change in pore space, pore shape, and pore throat. For isotropic unloading, the configuration of the grains or their relative position is, for the most part, unchanged and the grains simply move apart without relative rearrangement. Whereas the shearing process induces substantial relative motion of the grains and significant changes in pore geometry. Based on lab test results, it is summarized that the isotropic unloading process produces much smaller changes in volume, absolute permeability, and water effective permeability compared to the shearing process. Consequently, incorporating stress-induced permeability change within coupled reservoir geomechanical simulations requires different relationships or models for these two conditions. In addition, some empirical permeability relationships, such as the Kozeny- Carman model, Tortike's equation, and Chardabellas's terms, are also discussed. Introduction The SAGD process has become a commercially viable technology to develop the vast oil sands resources in Canada. Reservoir simulation is used as valuable design tool for development projects and to predict SAGD production performance. However, in some instances, conventional reservoir simulation may not be suitable for predicting performance because it does not take into account the coupled mechanisms between fluid flow and reservoir deformation. In these cases, a coupled reservoir geomechanical simulation may be required. A requirement for these coupled simulations is suitable relationships between reservoir permeability and geomechanical behaviour. Oldak owski conducted a series of tests based on both reconstituted oil sands specimens and drilled oil sands cores to characterize the relationships of permeability and geomechanical processes(3).Permeability variations of sandstone and other high strength materials experiencing the isotropic unloading and shearing processes have also been studied(2). Chalaturnyk summarized test results on oil sands and provided the relationship between oil sands compressibility and confining effective stress(3). It is known that oil sands samples can be easily disturbed during the sampling process. In order to minimize the disturbance, Touhidi-Baghini(4) took the test specimens from an exposed outcrop of bitumen-free Mc- Murray Formation sandstone, northeast of Fort McMurray. Based on these specimens, experimental studies were conducted on the permeability variation during the shearing process. This paper systematically discusses the oil sands permeability variations due to the isotropic unloading and shearing process based on Oldakowski's and Touhidi-Baghini's test results. In addition, some empirical permeability relationship

Controlling steam flood migration using air injection wells

Plumes of contamination emanate from nonaqueous-phase liquid sources as its constituents slowly dissolve into passing groundwater. For a large, well-characterized source, an aggressive technology such as steam flooding can accelerate cleanup. Steam is injected through a series of wells within and around a source area, and the steam zone grows radially around each injection well. The steam front drives the contamination to a system of groundwater pumping wells in the saturated zone and soil vapor extraction wells in the vadose zone. The movement of steam in the subsurface is governed primarily by soil heterogeneity and gravity. Steam is buoyant in groundwater and tends to migrate upward unless injected below a continuous confining layer. Groundwater pumping rates and vacuums typical of steam flooding are generally low compared to the steam injection rate and pressure and have limited influence over the lateral growth of the steam zone. To overcome these limitations, a system of air injection wells can be used to direct the steam zone growth. This paper presents results of sand-box experiments using air injection to prevent the outward growth of a steam zone between extraction wells with a discontinuous confining layer limiting the upward migration of steam. These experiments were numerically modeled with the multiphase nonisothermal code T2VOC. When confined vertically, the experiments and modeling show that outward migration of the steam front can be effectively controlled by placing air injection wells opposite steam injection wells. This technique can direct steam zone growth toward difficult access sources and away from areas where steam is not desired. Control of a proposed full-scale steam flood of the M-Area settling basin at the Savannah River Site was modeled using this method and the results are presented in this paper.

Issues With Reservoir Geomechanical Simulations of the SAGD Process

Abstract In the SAGD process, steam injection may result in pore pressure changes around the steam chamber in the reservoir. The magnitude of the pore pressure change depends on the steam injection pressure and the relative position of the steam chamber within the reservoir. Injected steam also increases the temperature within and adjacent to the steam chamber and thus introduces thermal expansion effects. The complex interaction of pore pressure and temperature throughout the reservoir result in varying degrees of reservoir geomechanical interactions that must be considered when contemplating reservoir geomechanical simulations of the SAGD process. The primary geomechanical influence on SAGD recovery is associated with the volume change of the sand matrix in response to effective stress changes induced by steam injection pressures and temperatures. Reservoir parameters and processes, such as compressibility, porosity (pore volume), absolute permeability, relative permeability, saturations, capillary pressure, enthalpy transmissibility, gas evolution, and thermal expansion effects, are all affected by bulk volume changes. In this paper, variations of these parameters due to geomechanical effect are analyzed and discussed based on related test results, calculation, and simulation. Their impacts on reservoir geomechanical simulations of the SAGD process are discussed. Introduction Reasonable prediction of SAGD performance by numerical simulation is an integral component in the design and management of a SAGD project. Conventional reservoir numerical simulation emphasizes multiphase flow in the porous media but generally does not take the interactions between fluid and solid into account. It applies elastic rock compressibility to characterize the coupling mechanism of multiphase flow and rock skeleton. The assumption of this treatment is that the boundary loads and temperature are constant, Δp = Δ σ'(1, 2). All analytical flow equations in petroleum engineering are based on this assumption. It is clear that the recovery process of conventional oil from sandstones and most carbonate rocks can roughly satisfy this assumption. For the SAGD process, however, volumetric deformations within the reservoir due to pore pressure and temperature changes result in variations of both in situ stress and strain. These stress and strain variations are functions of the in situ boundary conditions. Due to different directional deformation in response to in situ heating, the total stresses in vertical and horizontal directions may also vary. Moreover, the SAGD process is mainly applied in friable or uncemented (unconsolidated) oil sands that geomechanically behave differently to their cemented counterparts. Under these conditions, the assumption used in conventional numerical simulation is no longer effective because the total stress changes within the reservoir.

When Is It Important to Consider Geomechanics in SAGD Operations?

Abstract This paper generalizes the typical reservoir conditions for which SAGD is being implemented or considered in order to parametrically analyze the influence of geomechanical factors on the startup and production phases of SAGD projects. Numerical simulation of the SAGD process using a thermal reservoir program and a geomechanical program is used to assess the relative influence geomechanics may have on SAGD operations. While variations to the initial dual well SAGD process are becoming numerous, this study presents analysis results for only dual well SAGD geometries. A primary focus of this research is to clearly define the role of pore volume change (compressibility or shear-induced) on the basis of fundamental geomechanical parameters and correct an ongoing misconception that formation dilation can be simulated based on injection pressure alone. Dilation is a complicated process controlled by significantly more parameters than just injection pressure. Clear, definable guidelines are presented to aid SAGD project designers in determining the relative importance of the geomechanical response of their particular reservoir. The major geomechanical/ reservoir factors studied include:initial in situ effective stress state;initial pore pressure;steam injection pressure and temperature; and,process geometry variables, such as well spacing and wellpair spacing. Introduction The geomechanical response of an oil sands/heavy oil reservoir is complex, reacting to both near and far field temperatures and pore pressures. To aid in elucidating fundamental geomechanical principles affecting the steam assisted gravity drainage (SAGD) rocess and to gain insight into a reservoir's response to thermal loading and pore pressure change, a parametric analysis of the SAGD process within three separate but similar reservoir settings was completed. Since the objective of this paper is to highlight how the geomechanical response affects the SAGD process, twodimensional analyses of reservoir cross sections with basic treatment of the inherent complex geology have been conducted. Thenalysis results presented herein are not intended to portray a history match of any particular SAGD operation. Fully coupled thermal-stress-fluid flow analyses are extremely difficult to conduct. While fully coupled mathematical formulations exist(1–3), the computational effort in their solution is onerous and continues to be an area of active research. Coupled solutions that consider single phase flow only have become common(4, 5) and are routinely utilized in both advanced reservoir simulations and geotechnical/hydrogeological simulations. Consequently, a decoupled approach was adopted for the analyses presented herein. The decoupled approach consisted of conducting a reservoir simulation of SAGD using STARS (an advanced process and hermal reservoir simulator developed by CMG in Calgary) and utilizing the temperatures and pore pressures as input to an effective stress geomechanical simulation of the formation response to SAGD. In agreement with Tortike(3), that while the removal of "feedback" to the fluid flow model would not allow conclusions to be drawn regarding the fluid solution, this decoupled approach would permit conclusions to be drawn and inferences to be made concerning the likely response of the formation to the SAGD process.

The Effect of Operating Pressure on the Growth of the Steam Chamber Detected at the Hangingstone SAGD Project

Abstract 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.

Discussion of "SAGD and Geomechanics"

Introduction As a researcher studying the role of geomechanics in the SAGD Process, it was great to read Mr. Carlson's Distinguished Authors Series paper entitled. "SAGD and Geomechanics" in the June 2003 issue of the JCPT. In response to this paper the following sections provide a discussion on SAGD-geomechanical issues raised by Mr. Carlson and presents additional observations concerning the role geomechanics my play ill the SAGD process. Particulate Nature of Oil Sands Due to the particulate nature of oil sands, its volumetric behaviour will differ depending on the loading conditions. When oil sand material is subjected to isotropic loading (Stress change equal in all directions), individual particles will generally deform in an elastic manner, with the possibility of grain crushing at high stresses, but the bulk mass of oil sands will undergo both elastic and irreversible volumetric changes with little re-orientation of the grains relative to each other. Figure 1 provides the nature of this isotropic loading relationship for oil sands and is generally similar to the conventional reservoir engineering approach to rock compressibility. When oil sands are subjected to shear Stress loading (non- isotropic or anisotropic), individual groins also deform elastically but grain crushing can become more prominent. With respect to the volume change behaviour all the mechanisms outlined in the "Interlocked Structure" section of the paper can occur. The main difference with isotropic loading, however is that shear loading can result in substantial re-orientation of the grains relative to each other. The result is that the pore volume shape and distribution (and by association, the permeability) under these loading conditions can be quite different. During the SAGD process, both isotropic and shear stress loading occur simultaneously. In the SAGD process, saturated steam with high pressure and temperature is continuously injected into the reservoir. Steam injection pressure results in in increase of pore pressure. So, effective stress is decreased and clastic deformation (expansion) occurs, which is the result of isotropic unloading. In a certain distance ahead of the.steam chamber surface, total stress increases due to the thermal expansion of the oil sand material inside the steam chamber. This Stress increase is anisotropic and shearing will probably occur in this area. Clearly the impact of porosity changes due to these two geomechanical mechanisms will create different pore geometry and it seems reasonable to expect that they will influence reservoir properties such as absolute permeability differently(1). The issue of grain crushing should also not be overlooked. Oil sand grains consist of different minerals. If the hardness of these minerals is high enough grain crushing may not occur. In contrast, if these minerals are relatively weaker, grain crushing can be an issue and must be taken into account when treating the reservoir permeability variations. For example. oil sands in the Athabasca deposit arc predominantly line 10 medium grained and uniformly graded sand whose mineralogy consists of approximately 95% quartz, 2% to 3% feldspar grains, 2% to 3% mica and clay minerals, and traces of other minerals(2,3).

Field-Scale Numerical Simulation of SAGD Process With Top-Water Thief Zone

Abstract There is a major concern that the existence of thief zones, such as top water and/or a gas cap overlying the oil sand deposit, has a detrimental effect on the oil recovery in the application of the steam-assisted gravity drainage (SAGD) process. The objective of this numerical study is to investigate SAGD performance in the Athabasca oil sands in the presence of a top water zone. The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd., has been previously validated based on a 3D SAGD laboratory experiment with top water that was conducted at the Alberta Research Council (ARC). It is believed that the numerical simulation captured the major mechanism of oil movement from the pay zone into the top water zone, as was observed in the experiment. In the field-scale simulation, SAGD performance in the presence of confined and non-confined top water zones was investigated. The operating strategies under the conditions of non-depleted top water/non-depleted pay zones and depleted top water/non-depleted pay zones were considered. Numerical findings indicated that:there is a detrimental effect of a top water zone on SAGD performance;plugging of a top water zone with oil was not observed in this study for a top water thickness of 8 m; and,operating conditions that lead to a higher pressure difference between the steam chamber and the top water, either by depletion of the top water zone pressure or a higher steam injection pressure, results in a more detrimental effect on the SAGD performance. Introduction There is a major concern by Alberta oil producers that the production of natural gas in association with oil sands would lower reservoir pressure, reduce oil recovery, and may prohibit economic oil recovery. The Alberta Department of Energy (ADOE) and Alberta Energy and Utilities Board (AEUB) initiated a series of field-scale numerical modelling studies(1, 2) to assess the potential applicability of the steam-assisted gravity drainage (SAGD) oil recovery process under a variety of reservoir conditions such as reservoir thickness, reservoir depth, initial pressure, oil saturation, and the presence of top water zones and gas caps. It was found that top water zones and gas caps are thief zones to the SAGD process. These thief zones have a detrimental effect on SAGD recovery performance, especially when the pressure in the thief zones is reduced below optimum SAGD operating pressures due to natural gas production. Movement of oil into the top water zones and gas caps is simulated to occur. The volume of this oil seems to be generally proportional to the amount of outflow from the pattern due to the thickness of the top water zones/gas caps and the pressure difference between the steam chamber and the top thief zones. SAGD process costs depend on the amount of steam that flows into the top water zones and gas caps, from which no oil is produced.

Numerical and Experimental Modelling of the Steam Assisted Gravity Drainage (SAGD)

Abstract For complex petroleum recovery processes, an experimental investigation isusually performed with a numerical simulation to study the recoverymechanism(s). In this paper, both physical and numerical simulations of thesteam assisted gravity drainage (SAGD) process were performed. One of theobjectives of the numerical investigation was to determine the match betweenumerical results with data generated from scaled model experiments. The Computer Modelling Group's (CMG) STARS? thermal simulator was used. Resultsfrom the numerical simulation were found to be in reasonable agreement withthose obtained from the experiments for oil production rates, and cumulativeoil production. In addition, the steam chamber volume and temperaturedistribution were also examined. ffects of different parameters, such as steaminjection pressure, vertical separation between injection and production wells, nd reservoir thickness, on the performance of the SAGD process ereinvestigated. They were observed to have the same effects on both experimentaland numerical results. The numerical simulator was also used to study theinfluence of rock and fluid properties, such as oil viscosity, permeability, porosity, and the mount of heat loss from the reservoir to thesurroundings. Introduction The steam assisted gravity drainage (SAGD) process was developed by Butler(1), and is illustrated in Figure 1. It has been applied inseveral projects, including the Underground Test Facility (UTF) and has shownpromise of achieving high recovery (more than 50 % of OOIP in some cases). Many experimental and numerical studies of the SAGD process have been carriedout over the last ten years, on different aspects of the process. One of therecent numerical studies was presented by Chow and Butler(2). Theyfocused on history matching the oil recovery and the steam temperatureinterface position with those observed in the SAGD experiments by Chung and Butler(3). In the present study, numerical history matching of the experimental data, suchas the oil production and the steam chamber temperature contours [Sasaki etal.(4)] is the main focus. Furthermore, time to establish initialcommunication between the two steam injection and production wells (steambreakthrough time) was investigated. The physical and operational conditions inthe experimental study were different, compared to those used in Chung and Butler's experiments(3). They included a pressure drop of?Pi = 20 kPa, permeability of k =142 D; no pre-heating was employed.The experiments were configured to examine phenomena associated with the risingchamber. More details are provided in the following, for both experimentalinvestigation and numerical simulation. Description of the Experimental Model Several 2D visual, scaled physical models were used in the experiments. Theywere designed to represent a vertical section of a heavy oil reservoir. Themodels had sidewalls of acrylic resin (of 20 mm in thickness).

FEASIBILITY OF A STEAM FLOOD IN EWAN RESERVOIRS, NIGER DELTA

ABSTRACT This paper presents the results of a steamflood feasibility study of Ewan C-2 and C-3 reservoirs located in the Niger Delta. The study employed a steam flood process model to predict the reservoirs' performance under steam flooding. The results showed that oil/steam ratios of up to 0.76 for C-2 and 0.82 for C-3 reservoirs are obtainable at steam injection pressure of 2500 psia and steam rate of 1000 bbl/d, indicating a real potential for oil recovery by steam flooding in both reservoirs.

Steamflooding of Medium and Light Oils in Limestone Using 3-D Laboratory Model

The purpose of this study is to demonstrate the applicability of the steam injection process to medium and light oil reservoirs. A comprehensive laboratory study was conducted for the recovery of medium and light oils from an unscaled threedimensional (3-D) physical model.A total of 10 experiments were conducted to investigate the effect of steam injection on the recovery of different API gravity oils. A 3-D model with 30 cm x 30 cm x 7.5 cm dimensions was used to obtain the process parameters. Temperature distributions in the model, steam injection pressures and fluid productions were recorded during the experiments. The effect of initial oil saturation, steam injection rate, produced oil properties and temperature distribution on oil recovery were evaluated. Results indicated that the higher API gravity oils yielded considerably higher values for the oil recovery. The oil recovery increased with a decrease in the steam injection rate. The low rate runs required more steam, as reflected in the higher steam-oil and water-oil ratios, in order to achieve steam temperatures over the entire model. Steam-oil ratios decreased as the °API gravity of crude oil increased. Medium viscous crude oils, evidently vaporized the light ends, which travelled across the top of the model and condensed ahead of the steam front to form a distillate bank.

Laboratory studies of steam stripping of LNAPL‐contaminated soils

Abstract Bench‐scale laboratory experiments were conducted to evaluate the effectiveness of steam injection for in situ remediation of soils contaminated by light nonaqueous‐phase liquids (LNAPLs). Several parametric studies were performed with various combinations of soils, LNAPLs, and steam injection conditions. An increase in steam injection pressure produced a significant increase in LNAPL recovery efficiency. An increase in steam injection pressure from 12.4 to 44.8 kPa resulted in increased LNAPL recovery efficiency from 86 to 95% after one pore volume of steam injection. Higher steam injection pressure yielded maximum LNAPL recovery efficiency in significantly less time and required a smaller amount of steam than at low pressure. An increase in soil grain size or an increase in grain‐size‐distribution slope resulted in increased LNAPL recovery efficiency. The final LNAPL residual saturation was approximately 0.5% for coarse‐grained soils and 1.8% for soils with finer grain sizes. Soils with finer g...

Effects Of Reservoir Heterogeneities On Heavy Oil Recovery By Steam-Assisted Gravity Drainage

Abstract Previous studies of the SAGD process have been based on homogeneous reservoir models. In this paper, new experiments are described which simulate heterogeneous reservoirs. These include reservoirs with thin sha1e layers and reservoirs containing horizontal layers of different permeabilities. The results show that a short horizontal barrier does not affect the general performance greatly. A long horizontal barrier decreases the production rate but, in some configurations, not nearly as much as might be expected. It is observed that faster production is found when a higher permeability layer is above a lower permeability layer than when the conditions are reversed. Introduction The production of heavy oils by gravity drainage to a horizontal well with the continuous injection of steam above follows from the existing steam stimulation and steam flooding practices. The process has been recognized as steam-assisted gravity drainage (SAGD). Rapid development in this area is being encouraged by improved horizontal well drilling technology which allows more favourable economics. Butler et al.(2,3,4) carried out early experimental and theoretical studies on this area. Their theoretical predictions agreed well with the homogeneous reservoir model experiments. No reservoir is completely homogeneous, and the degrees of heterogeneity can vary significantly, even within the same field. It is necessary that preliminary experiments be performed to study the effects of reservoir heterogeneities. The research work presented here is limited to two types of reservoirs which are considered to be representative and close to the real field conditions:reservoirs with thin shale layers,reservoirs containing horizontal layers of different permeabilities. Laboratory studies were conducted using a visual reservoir model saturated with Cold Lake bitumen. The steam injection pressure employed was 153 kPa. Two different well configurations have been investigated.. The first consisted of a vertical circulation steam injector which was perforated near the top of the formation with bitumen produced at the bottom; the second employed a similar configuration to the first, bur with steam introduced slightly above the production well at the base of the formation. Photographs were taken at specified time intervals and the temperature profile was recorded continuously to provide a means for comparisons and eventually for selecting an optimal well configuration for different reservoir conditions. Experimental The two-dimensional reservoir model is that which has been described by Butler et al.(1) only with minor modifications. The schematic experimental set-up is illustrated in Figure 1. The model was scaled to the field conditions by using the method described by Butler et a1(2). The scaling parameters are shown in Table 1. One hour for the model is equivalent to 1.5 years in the field. The vertical circulating steam injector(1) was employed to initiate the communication between the injection and production well. The injection well location was adjusted vertically to allow for different steam injection locations. Figures 2a and 2b show how this vertical steam injector works. The porous materials used in the reservoir model were 2 mm and 3 mm glass beads. In order to obtain a uniformly random packing of the porous pack, the reservoir model was secured on a vibrating table.

The Production Of Conventional Heavy Oil Reservoirs With Bottom Water Using Steam-Assisted Gravity Drainage

Abstract Developing and producing conventional oil economically from reservoirs containing bottom water is' one of the most challenging technical problems in Canadian petroleum engineering This paper investigates a new, innovative thermal oil recovery process that shows potential for the economic of production heavy oil from reservoir when recovery is limited by water coning. The process as envisaged at present, would use parallel horizontal wells placed near the bottom of the reservoir with horizontal steam injection wells located vertically above the producers near to the top of the reservoir. Experiments were performed using a scaled, two-dimensional reservoir model containing an active aquifer system. The model was designed to provide dimensional similarity with specific "Lloydminister-type heavy oil" field conditions. The study investigated the mechanism, the process and the effects of steam injection Pressure, bottom water thickness, and the location of the production well; the laboratory results were extrapolated to the field conditions. It is shown that the process may produce heavy oils economically. The severity of steam coning is because the high productivity index of a horizontal well, allows practical production alrates which are below the critical steam coning rates. Water production from the aquifer is greatly reduced by operating the production wells at pressures close to that of the aquifer. The cumulative oil recovery varied from 48% (bottom water case with 41% water in the model) to 87% (no bottom water with 0% water in the model) of original oil-m-place above the production well (OOIP*). The thickness of the bottom water zone and The well configurations employed had a significant effect on the cumulative oil recovery. Introduction In Canada, there i, a vast amount of heavy oil reserves (3.5 million M3) underlying the Lloydminster area of Alberta and Saskatchewan(1). These heavy oils are usually mobile al reservoir conditions and most can be produced at a low ultimate recovery by primary production. Waterflooding is not effective because the mobility ratio of heavy oil to Water is not favourable. Most heavy oil reservoirs in Saskatchewan have thin pay zone, which have been judged unsuitable for thermal recovery. Many of the thicker reservoirs have underlying water, Attempts to produce such reservoirs by conventional means result, quickly, in the production of excessive water. The mechanism for this is well understood and is a result of the much lower viscosity or water compared to that of the oil; the Water "cones" upward into tlte well. The conventional steamflood or in situ combustion processes are usually unsuccessful due to prohibitive heat loss or air channelling through the underlying water and also excessive water will be produced(2). Therefore, the chance of recovering this type of petroleum reserves is further limited. An advantage of the technique Studied here is that the process can be operable, even though there is a significant underlying water layer. The reason that the water can be tolerated is that the pressures involved in the SAGD process, can be adjusted so that there is no tendency for water to now from the aquifer to the production well(s).

Evaluation And Application Of Pikes Peak Cyclic Steam Injection Pressure Data

Abstract Cyclic steam performance at Husky's Lloydminster area Pikes Peak steam pilot has been very good but efforts to further improve performance have continued. This study was initiated to determine the causes of observed injection pressure variations from well to well, and during the stimulation of a given well. A further goal was to develop applications for this information. Analysis of the injection pressure data from the pre-1985 wells was limited in scope due to wide variations in injection rate and slug size; although low injection pressures were correlated to the presence of gas caps or bottom water; and a stepwise pressure drop through the first three cycles was documented. The relatively constant first cycle injection rates and slug sizes used for the 1985 wells allowed a more thorough analysis. Four injection pressure histories were observed; sustained high pressure and three types of pressure reduction. These pressure reductions were subsequently correlated to the proximity of: bottom water, gas caps mature wells and other recently stimulated first-cycle wells. Therefore, injection pressure data can be used to supplement the reservoir description data obtained from logs and cores. First-cycle data from the 1985 wells indicate that both overlapping the heated zones of previously stimulated neighbouring wells and pressure support from the aquifer could strongly affect first-cycle well performance. Net pay appeared to have less influence. During the second cycles at the 1985 wells interwell communication occurred at all wells except those which were particularly isolated, decreasing the validity of SOR-based individual well performance evaluations. The injection pressures increased with time at the isolated wells, establishing a fifth injection pressure history. The injection pressure history types of fourteen 1987 wells have been determined, and first cycle performance predictions were made using the 1985 well data. Introduction Husky's Pikes Peak steam pilot has given very good over-all performance(1, 2), but efforts to optimize pilot performance have continued. Early in the pilot's history it was assumed that steam injection pressures during a given cycle were fairly constant from well to well, and throughout the cycle at each well. Upon closer inspection significant steam injection pressure variations were observed for both initial cycle pressure and cycle pressure history, and a study was initiated to determine the causes, A similar study conducted to develop a method for detecting casing failures at Cold Lake wells was recently published, but no other in-depth discussions of this topic were found in the literature. Due to poorer economics associated with current lower oil prices, this study emphasized analysis of routinely collected injection well casing pressure data rather than acquisition of more costly data by installing downhole pressure gauges, drilling observation wells, running tracer tests, or obtaining 3-D seismic data. Before 1985, a variety of operating conditions were used to prove the economic viability of the pilot site, and to optimize operational procedures. Hence, the conclusions drawn from the nalysis of the injection pressure data for this period have been confined to general observations about the lower pressures observed at wells with gas caps or bottom water, or at post first cycle wells.

The Commercial Viability And Comparative Economics Of Downhole Steam Generators In Alberta

Abstract Downhole steam generation is an emerging technology being developed as an alternative to conventional surface steam generation. Its major advantage is that it eliminates surface and wellbore heat losses. In addition, the reinjection of combustion gases with steam in some downhole steam generators (DSG) could create potential advantages of a steam and additive process. Over a dozen downhole steam generator designs have been developed. This paper reviews past laboratory/field experience and technical criteria for application in heavy oil and oil sands reservoirs. It includes an analysis of equipment costs, and develops economic criteria for the use of DSGs in Alberta. Introduction Among the many processes being applied for the recovery of low-gravity crude oil, thermal methods have proven to be the most successful. These methods employ steam injection, in situ combustion, or a combination of both. The use of steam, however, appears to be the most popular because it may increase oil production rate and ultimate oil recovery. The two basic injection techniques are steam stimulation and steamflood. Steam stimulation (or ‘soak’, ‘cyclic’, ‘huff-n-puff’) is a single well operation (Fig. la). Steam is injected into the well and is allowed to soak before the oil is produced. Oil viscosity is the chief variable involved, because the oil recovery depends primarily on a reduction in the viscosity(1). The production of oil is a discontinuous operation, but relatively fast. The ultimate oil recovery is low. Steamflood (or ‘drive’) requires a set of injector wells into which the steam is injected, and a set of producer wells from which the oil is produced (Fig. lb). In this operation steam distillation may be of prime importance in increasing total recovery efficiencies(l). As shown in Figure 2, a number of other variables are also involved. The production of oil is a continuous operation, but relatively slow. The ultimate oil recovery is high. Steam is conventionally produced in oil field steam generators. They differ from industrial boilers in their ability to produce low quality steam from saline water with minimal treatment(2). They can endure rapid load changes and provide unattended operation. They may be either skid-mounted or completely portable. Finally, they can utilize a wide range of liquid and gaseous fuels. In Alberta, because of its low cost, natural gas is the primary fuel source of steam generators. These generators create less pollution problems than the Californian counterparts which burn high-sulphur liquid fuels. Steam generated in conventional surface boilers suffers its largest drawback in the form of heat losses as it flows through the surface piping and in the wellbore. The biggest surface loss isup the exhaust gas stack. It is possible to recover part of this heat, but it is not economical because the acids condensing at the lower temperature are extremely corrosive. Heat lost in the wellbore could be significant in the case of deep wells which require higher steam injection pressures and temperatures. The development of downhole steam generators (DSG) was natural because it may eliminate surface and wellbore heat losses.