Steam Chamber Growth Research Articles

Bitumen and heavy oil geochemistry: a tool for distinguishing barriers from baffles in oil sands reservoirs

Abstract To optimize SAGD well-pair placement and improve thermal recovery operations, geochemical bitumen composition logs are used to identify barriers and baffles to fluid flow, which may compartmentalize McMurray Formation reservoirs in the Athabasca Oil Sands. SAGD steam chamber growth and cumulative steam oil ratios are sensitive to both vertical permeability and bitumen viscosity variations, which are commonly encountered in the oil sands reservoirs. In the McMurray Formation, tidally influenced meandering channel deposits are commonly vertically stacked, forming reservoir columns up to 80 m thick. In many instances, inclined heterolithic strata (IHS), consisting of interbedded sand and silt deposited on point bars, comprise barriers to vertical steam chamber growth at multiple horizons of a reservoir. Thus, the identification, characterization, and delineation of IHS intervals is a critical step for evaluating the reservoir development potential, and designing an optimal reservoir development strategy. While siltstone beds are routinely identified in cores and geophysical logs, thin siltstone beds that can act as a barrier to fluid flow are not discernible in seismic reflection data and have proven difficult to correlate between adjacent delineation wells. In this study, geochemical bitumen analysis is used to determine the integrity and continuity of siltstone beds within IHS in order to assess their potential impact on SAGD steam chamber growth. First, high-resolution molecular composition profiles are obtained from gas chromatography–mass spectrometry analyses of bitumen extracted from cores. The continuity of biodegradation-susceptible aromatic hydrocarbon concentrations measured through vertical profiles of a reservoir were used to determine if siltstone-prone intervals observed in log and core data acted as barriers or baffles to fluid flow over geological time. Integration of the bitumen molecular composition data with geological cross-sections fosters predictions of the lateral extent of the identified barriers. Furthermore, inferences about reservoir charging and in-reservoir fluid mixing histories are also made. Geochemical log data indicate that thickness of a heterogeneous low permeability interval is not necessarily the critical attribute of a barrier to fluid flow. Integration of both sedimentological information and bitumen geochemical data is useful for the identification of barriers and baffles to fluid flow in oil sand reservoirs. The method can be applied prior to positioning of SAGD well-pairs and thus could represent an important step for development planning of heterogeneous reservoirs.

Impact of Noncondensable Gas on Performance of Steam-Assisted Gravity Drainage

Summary This study investigates, by means of numerical modelling, the impacts of naturally occurring and continuously coinjected and intermittently coinjected noncondensable gas (NCG) at different stages of the steam-assisted gravity-drainage (SAGD) process. The CMG Builder software was used to construct a homogeneous 2D baseline model based on generic Athabasca-type reservoir properties and well configuration. A fluid-component model was generated using the CMG WinProp package for modelling the phase behaviour and properties of reservoir fluids. This fluid-component model was modified to incorporate manually calculated K-values for the gas-water- and the gas-bitumen-phase equilibria. The modified fluid model was then incorporated into the baseline model and the CMG STARS thermal reservoir simulator. The simulation results of this study show that methane coinjection along with steam is generally not beneficial. Although it can reduce the heat loss to the overburden to some extent, the reduction in oil-drainage rate and total oil recovery negates the benefits of such heat-loss reduction. The poor performance of NCG addition to SAGD results from the tendency for the NCG to remain in the vicinity of the steam chamber and reduce the transfer of heat into the cold bitumen at the edges of the steam chamber, thereby impeding steam-chamber growth. Accurate modelling of NCG addition to steam in SAGD is highly dependent on the availability of appropriate relative permeability curves and gas-solubility data. NCG with steam may perform better compared with steam-only injection in SAGD if methane coinjection were investigated using a heterogeneous model in which SAGD is affected adversely by the presence of reservoir heterogeneities in the form of shale barriers, inclined heterolithic strata (IHS), and steam-thief zones.

Modelling of 4D Seismic Data for the Monitoring of Steam Chamber Growth During the SAGD Process

Summary This paper presents an integrated workflow for the interpretation of 4D seismic data to monitor steam chamber growth during the steam-assisted gravity drainage recovery process (SAGD). Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, fluid saturations, pore pressure, and so on. The workflow is based on the generation of a geological model inspired by a real field case of the McMurray formation in the Athabasca region. The approach consists of three steps: the construction of an initial static model, the simulation of thermal production of heavy oil with two coupled fluid-flow and geomechanical models and the production of synthetic seismic maps at different stages of steam injection. The distribution of geological facies is simulated on a fine grid using a geostatistical approach, which honours all available well data. The reservoir's geomechanical and elastic properties are characterized by logs and literature at an initial stage before the start of production. Production scenarios are run to obtain pore pressure, temperature, steam and oil saturations on a detailed reservoir grid around a well pair at several stages of production. Direct coupling with a geomechanical model produces volumetric strain and mean effective stress maps as additional properties. These physical parameters are used to compute new seismic velocities and density for each stage of production according to Hertz and Gassmann formulas. Reflectivity is then computed, and a new synthetic seismic image of the reservoir is generated for each stage of production. The impacts of heterogeneities, production conditions and reservoir properties are evaluated for several simulation scenarios from the beginning of steam injection to 3 years of production. Results show that short-term seismic monitoring can help in anticipating early changes in steam injection strategy. In return, long-term periods allow the behaviour of the steam chamber to be monitored laterally and in the upper part of the reservoir. This study demonstrates the added value of 4D seismic data in the context of steam-assisted heavy oil production.

On the Impact of Permeability Heterogeneity on SAGD Steam Chamber Growth

Evolution of steam assisted gravity drainage (SAGD) steam chambers in heavy oil and bitumen reservoirs is tied to uniformity of steam pressure and quality along the length of the perforated interval of the well and reservoir geology and fluid properties adjacent to the well. If the reservoir geology has poor permeability at an interval along the wellpair, then steam delivery to and fluids production from the reservoir is not uniform. If the steam is well distributed throughout the injection well, then the key factor for a uniform steam chamber along the wellpair is reservoir geology. This is especially important in highly heterogeneous, variable thickness reservoirs where geology and reservoir oil composition may vary significantly over the length of a wellpair. Heterogeneity of a growing SAGD steam chamber is related to heterogeneity of the underlying geology. In this study the oil sands models are geostatistically populated to model spatial heterogeneity of permeability. The temperature profile (chamber growth), steam chamber height, conductive, convective, and total heat fluxes have been examined in each case. The results reveal that the length scales of steam chamber growth depend on the permeability heterogeneity. This provides a means to decide length scales for placement of in-well control devices in steam injectors in SAGD.

Laboratory Experimental Testing and Development of an Efficient Low Pressure ES-SAGD Process

Abstract Certain Athabasca reservoirs have low pressures because they have been depleted due to production of overlying gas. Other reservoirs are naturally occurring low pressure shallow bitumen reservoirs. Hence, there is a need to develop or investigate recovery processes under which such low pressure reservoirs can be developed. As a result of this, experiments were initiated to extend the Expanding Solvent-SAGD (ES-SAGD) process application to low pressure Athabasca reservoirs in order to evaluate oil recovery from such reservoirs. The goal of these experiments is to develop a low pressure ES-SAGD process with better performance than, or comparable performance to, that of the high pressure SAGD process. This paper describes five sets of laboratory experiments examining recovery processes, which includes a low pressure (500 kPag +/- 50 kPag) SAGD experiment, a propane-SAGD experiment, multi-component ES-SAGD (at low and high concentrations) experiments and a high pressure (2,100 kPag +/- 50 kPag) SAGD experiment. The results of these experiments are presented and analyzed in order to evaluate the performance of low pressure ES-SAGD in comparison to SAGD (at low and high pressure) and propane-SAGD at low pressure. The processes were assessed for recovery, recovery time, heat loss, steam chamber growth and energy efficiency. The principal conclusion is that the low pressure multi-component ES-SAGD at the right concentration (mostly at low concentration) is fairly competitive with SAGD at a high pressure. The energy consumption in the steam or steam/solvent zone per oil recovered (ECDZ) for low pressure multi-component ES-SAGD experiments is much lower than the low pressure and high pressure SAGD tests. The propane-SAGD test recovery is very low, even at higher energy consumption, than that of the ES-SAGD experiment at low concentration. The work presented in this paper shows that the application of a multi-component ES-SAGD process in the field at low pressure is a practical option. It also shows that bitumen/heavy oil reservoirs that would have remained untapped due to low reservoir pressure could be produced at lower energy consumption per oil recovered if a low pressure ES-SAGD process at low concentration of the diluents is employed in the recovery of the oil. Introduction Certain Athabasca reservoirs have low pressures because they have been depleted due to production of overlying gas. Other reservoirs are naturally occurring low pressure shallow bitumen reservoirs. The application of Expanding Solvent-SAGD (ES-SAGD)(1–2) to these low pressure reservoirs has been a major area of attention at the Alberta Research Council (ARC) in recent years. As a result of this, experiments were initiated to extend the ES-SAGD application to low pressure Athabasca reservoirs. The goal is to develop a low pressure ES-SAGD process with better performance than, or comparable performance to, that of the high pressure SAGD process and extend the ES-SAGD process application to gas-over-bitumen reservoirs and naturally occurring low pressure reservoirs. In this paper, four low pressure experiments and one high pressure experiment conducted in a 2D experimental facility at the Alberta Research Council are presented and analyzed in order to evaluate the performance of ES-SAGD at low pressure.

SAGD with a Longer Wellbore

Abstract This paper investigates the feasibility of bitumen production using SAGD technology with a longer wellbore. A longer wellbore can be used to exploit a greater volume of the reservoir with a single wellpair as opposed to multiple wells; thus, decreasing pad and drilling costs. The major concern in using a longer wellbore from a reservoir engineering point of view is the potentially non-uniform steam chamber growth over the whole well length due to pressure drop in the horizontal well. Reservoir simulation was performed using Computer Modelling Group's STARS ™?simulator and the QFlow thermal wellbore simulator to address the issue. The pressure drop inside the wellbore was calculated using QFlow. Reservoir simulations were performed using STARS. A sectioned model was constructed, dividing the whole length of the horizontal wellbore into multiple sections, each with its own pressure restriction to match the pressure drop obtained from QFlow. The results showed that with a sufficiently large wellbore size that resulted in a sufficiently low pressure drop, one longer well performed as well as two shorter wells. When a smaller wellbore size was used, production from a longer well was significantly impeded due to the large pressure drop. Introduction Since the discovery of oil sands, many techniques have been tried - and improved upon - to recover the highly viscous bitumen for energy consumption. One of the methods of bitumen recovery that is becoming increasingly prevalent is a thermal in situ method called Steam-Assisted Gravity Drainage (SAGD). Butler(1) first proposed this method in the late 1970s and it was field tested in AOSTRA's Underground Test Facility (UTF) in the 1980s. The initial phase of UTF testing produced successful field results(2, 3). Following Phase A, Phase B was started, implementing the use of longer horizontal wells(4, 5). Surface-operated SAGD was studied in Phase D(6). Following these successful pilot tests, a number of commercial projects have been developed, including Petro-Canada's MacKay River project. One of the factors that needs to be considered in commercial projects is the optimization of the horizontal well length. Typically, the horizontal sections of the SAGD wells are 500 to 700 m long. This paper will examine the effectiveness of using a longer horizontal wellbore in SAGD. There is tremendous potential for economic savings in implementing longer wellbores in a SAGD project. A longer wellbore has the ability to reach greater lengths within a reservoir with one single wellbore as opposed to multiple wells. When multiple wells are drilled, multiple pads must also be built - one for each group of wells. Thus, to cover a given reservoir, the average pad cost will be lower for longer wellbores. Another significant cost advantage of the longer wellbore is the fact that fewer riser sections (also known as build sections) need to be drilled and completed. The riser section has a significantly higher cost than the horizontal section because it is generally much larger in diameter. By decreasing the number of wells in a pattern with the use of longer wells, the cost of all the riser sections is decreased significantly.

Understanding Reservoir Architectures and Steam-Chamber Growth at Christina Lake, Alberta, by Using 4D Seismic and Crosswell Seismic Imaging

Summary EnCana Corporation's Christina Lake Thermal Pilot Project located 170 km south of Fort McMurray, Alberta, Canada, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the Lower Cretaceous McMurray formation. This paper presents an analysis of time-lapse and crosswell seismic data, as part of an overall study integrating different disciplines and technologies, to understand the effects of geology on SAGD-process performance in the pilot area. A 3D baseline survey was conducted at the start of the pilot in 2001, and two follow up surveys were conducted in 2004 and 2005. In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in the vertical wellbores. The goal of the seismic surveys was to better understand steam-chamber growth and reservoir architecture by detecting lithology changes, including the occurrence and distribution of mudstone stringers. Data from the surveys, especially from the crosswell profiles, indicated significant reservoir heterogeneity, and helped to characterize reservoir architecture in the pilot area more accurately. Analysis of seismic data (both 4D and crosswell) showed steam-chamber growth and oil recovery to be influenced strongly by reservoir geology. Steam-chamber growth is especially affected by the presence of low-permeability facies in the vicinity of the SAGD well pairs. Our analysis indicates that these reservoir heterogeneities have contributed to the creation of areas within the reservoir that have been unaffected by steaming operations to date. These findings are in agreement with flow-simulation results and collectively contribute significantly to the planning of future developments.

Geomechanical Effects on the SAGD Process

Summary Steam-assisted gravity drainage (SAGD) is a robust thermal process that has revolutionized the economic recovery of heavy oil and bitumen from the immense oil-sands deposits in western Canada, which have 1.6 to 2.5 trillion bbl of oil in place. With steam injection, reservoir pressures and temperatures are raised. These elevated pressures and temperatures alter the rock stresses sufficiently to cause shear failure within and beyond the growing steam chamber. The associated increases in porosity, permeability, and water transmissibility accelerate the process. Pressures ahead of the steam chamber are substantially increased, promoting future growth of the steam chamber. A methodology for determining the optimum injection pressure for geomechanical enhancement is presented that allows operators to customize steam pressures to their reservoirs. In response, these geomechanical enhancements of porosity, permeability, and mobility alter the growth pattern of the steam chamber. The stresses in the rock will determine the directionality of the steam chamber growth; these are largely a function of the reservoir depth and tectonic loading. By anticipating the SAGD growth pattern, operators can optimize on the orientation and spacing of their wells. Core tests are essential for the determination of reservoir properties, yet oil sand core disturbance is endemic. Most core results are invalid, given the high core-disturbance results in test specimens. Discussion on the causes and mitigation of core disturbance is presented. Monitoring of the SAGD process is central to understanding where the process has been successful. Methods of monitoring the steam chamber are presented, including the use of satellite radar interferometry. Monitoring is particularly important to ensure caprock integrity because it is paramount that SAGD operations be contained within the reservoir. There are several quarter-billion-dollar SAGD projects in western Canada that are currently in the design stage. It is essential that these designs use a fuller understanding of the SAGD process to optimize well placement and facilities design. Only by including the interaction of SAGD and geomechanics can we achieve a more complete understanding of the 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.

Heat Transfer Ahead of a SAGD Steam Chamber: A Study of Thermocouple Data From Phase B of the Underground Test Facility (Dover Project)

Abstract Phase B at the Underground Test Facility (Dover Project) is the longest running and most instrumented SAGD pattern in the world and is operated by Devon Canada (formerly Northstar Energy Corporation). Techniques are presented which allow for the interpretation of temperature data from the pilot to better understand the growth of a SAGD steam chamber over time. Calculating the rate and direction of steam chamber movement, the in situ thermal diffusivity and the role of conduction and convection in heat transfer provide a foundation for understanding the interaction between the SAGD recovery process and the reservoir. Introduction Over 12 years have passed since the first field test of the classical SAGD recovery process at the Underground Test Facility (UTF) near Fort McMurray, Alberta, Canada. In recent years the level of activity in thermal heavy oil has increased dramatically in Canada. Butler has identified four commercial SAGD projects currently under construction or where construction is to commence soon, and two additional projects were recently announced, all of which could total over one half million barrels per day of production by 2010(1). One of the most striking characteristics of the SAGD technology is that it has undergone relatively little change since its first field trial. Fundamentally, the commercial projects which are currently under construction look very much like the original 50 m Phase A horizontals, placed on production in 1988. One reason for little change in the SAGD technology is that, so far, it has delivered excellent results. The early piloting of the SAGD process at the UTF has proven that the SAGD process can deliver good rates and reserves from the reservoir at the UTF, which is considered to be inferior to 1/3 of the Athabasca resource(2). In spite of this perception that the UTF reservoir is marginal, the first commercial length wellpairs at Phase B were highly successful, reaching a normalized productivity of 0.2 m3/d per metre of well length(3). In addition to the success of the SAGD process in recovering oil, SAGD also benefits from the fact that the performance of the early pilots was highly predictable. Butler's equation(4), developed without the benefit of any field data, has been shown to accurately predict the performance of SAGD in the field. The high predictability of the process has meant that the results of early pilots, especially the UTF pilot, have been used to history match simulation models, which have been, in turn, used to predict the performance of SAGD in new reservoirs. In fact, the subject of much of the literature on SAGD is the results of simulation modeling(5–7). At times, the results of simulation modelling are used as a basis for scientific conclusion, typically reserved for real field evidence. Relatively little actual field data is available in the public domain, which exacerbates the situation. Typically, when a new reservoir process is developed and tested in the field, a great effort is required in studying the underlying physics of the process in light of the field data, prior to simulating the process.

Impacts of Initial Gas-to-Oil Ratio (GOR) on SAGD Operations

Abstract This study addresses the important role of initial gas-to-oil ratio (GOR) in steam assisted gravity drainage (SAGD) operations. A numerical model using CMG's STARS was validated through history matching of laboratory experiments conducted at the Alberta Research Council. The impacts of initial GOR on process performance were then studied using field scale numerical simulations. The results indicate that high initial GOR may have beneficial effects, namely, reduction of oil viscosity, and improvement of the oil-to-steam ratio (OSR). A detrimental impact, however, is also shown as the gas impedes the rate of steam chamber growth, and hence reduces oil production rates. Further analysis indicated that this is because of a "dynamic vacuum" effect due to steam condensation at the front of the steam chamber. This dynamic vacuum effect dominates the diffusion process and creates a gas-rich zone at the front of the steam chamber, thereby resisting further growth of the steam chamber and slowing oil production. The same effect occurred when noncondensable gas was co-injected with steam in either live oil or dead oil reservoirs. This study addresses the important role of initial gas-to-oil ratio (GOR) in steam assisted gravity drainage (SAGD) operations. A numerical model using CMG's STARS was validated through history matching of laboratory experiments conducted at the Alberta Research Council. The impacts of initial GOR on process performance were then studied using field scale numerical simulations. The results indicate that high initial GOR may have beneficial effects, namely, reduction of oil viscosity, and improvement of the oil-to-steam ratio (OSR). A detrimental impact, however, is also shown as the gas impedes the rate of steam chamber growth, and hence reduces oil production rates. Further analysis indicated that this is because of a "dynamic vacuum" effect due to steam condensation at the front of the steam chamber. This dynamic vacuum effect dominates the diffusion process and creates a gas-rich zone at the front of the steam chamber, thereby resisting further growth of the steam chamber and slowing oil production. The same effect occurred when noncondensable gas was co-injected with steam in either live oil or dead oil reservoirs. Introduction It is generally assumed that when the steam assisted gravity drainage (SAGD) process is applied to a heavy oil reservoir with a high initial gas-to-oil ratio (GOR), there is better production than for a reservoir with a low initial GOR. This is a fairly common assumption for good reasons; the mobility of live oil in porous media is usually higher(1) than that of dead oil. The present numerical study was initiated to investigate this assumption. The approach involves the history match of 1D laboratory tests and field scale simulations. The history match was used to verify the numerical techniques and to provide reliable parameters for the use of field scale simulations. The results support the commonly believed assumption of viscosity reduction in 1D live/dead oil experiments. In field scale simulations, production predictions were compared for reservoirs with different initial GORs. There were additional effects beyond viscosity reduction.