Underground Test Facility Research Articles

Performance of the SAGD Process in the Presence of a Water Sand- A Preliminary Investigation

Abstract 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.

Numerical Study and Economic Evaluation of SAGD Wind-Down Methods

Abstract At a certain point in a SAGD operation, it is no longer economic to continue steam injection when the steam-oil ratio (SOR) becomes too high. A less energy intensive gas injection process following the SAGD process can prolong oil production by using the energy in place. Numerical studies of the injection of non-condensable gas, and a mixture of steam and non-condensable gas following a SAGD operation, were conducted using the CMG's STARS reservoir simulator. The simulation results suggest that, after three to five years of SAGD operation, when three quarters of the targeted reservoir is hot, it is appropriate to start a wind-down process. Injecting non-condensable gas results in a much lower production cost compared to continued steam injection; however, the oil production is reduced. Coinjection of steam with gas produces more oil than the gas-only injection process without substantially increasing the production cost. This is probably the desired wind-down process. Optimization is needed for the co-injection process. The choice of non-condensable gas depends on the cost and availability. Introduction The huge heavy oil and bitumen resources in Western Canada have motivated efforts to develop suitable recovery processes. One of the results of these efforts is the Steam-Assisted Gravity- Drainage (SAGD) process(1), which was proposed 20 years ago. The process utilizes horizontal wells and steam injection. The relatively slower gravity drainage is compensated for by using long horizontal wells, resulting in an economic production rate. In addition, the overall recovery may be as high as 70% of the original oil-in-place (OOIP). Much research has been conducted on the process in order to obtain a better understanding of the process under various reservoir conditions, to improve the accuracy on performance prediction, and to solve operational problems. After the process was pilot tested in AOSTRA's Underground Test Facility (UTF) and showed great promise(2, 3), SAGD has been regarded as one of the leading in situ recovery processes for heavy oil and bitumen resources. Many SAGD projects are in operation, under construction, or in the planning stages in Western Canada. In the SAGD process, as the steam chamber grows, oil is gradually recovered, accompanied by an increasing steam-oil ratio. At a certain point, it is no longer economic to continue steam injection; however, the reservoir is still hot, and the energy in place can be utilized. Non-condensable gas (NCG) or a mixture of NCG and steam injection has been proposed as a wind-down process. A less energy-intensive gas injection process may maintain reservoir pressure, utilize the energy in place, and prolong oil production. Such a process has been field tested at the former UTF B patterns, and good results have been reported(8). The purpose of this study is to evaluate various possible SAGD wind-down processes, and to find the appropriate time for starting a wind-down process. Using the reservoir simulator, STARS (Computer Modelling Group Ltd.), wind-down processes of the injection of NCG, and mixture of steam, and NCG were numerically investigated. It was found that the wind-down process could produce a considerable amount of oil.

The Growth of the Steam Chamber During the Early Period of the UTF Phase B and Hangingstone Phase I Projects

Abstract Based on temperatures measured in observation wells of the UTF Phase B project, the behaviour of the rising steam chamber when it reached impermeable layers was studied using a numerical thermal simulator. Results indicated that steam could rise by detouring the impermeable layers when they exist within the channel sands. The extension of these impermeable layers is generally less than 10 m in diameter. Most of these impermeable layers became permeable after one to one and a half years of heating with steam. When steam reached shaly sands in the upper part of the reservoir, steam rise was terminated. However, in some instances, it rose slowly after one to one and a half years of heating. Steam generally stopped to rise at few metres from the bottom of the point bar sands. However, a significant amount of bitumen could be produced from these sands. In the Hangingstone reservoir, Japan Canada Oil Sands Limited (JACOS) began initial steam circulation in April 1999 and the regular SAGD operation in July 1999. The early oil production volumes were close to our expectations. An extended understanding of the rising mechanism of the steam chamber is achieved by a comparison of the performances obtained in the Hangingstone and UTF reservoirs. Markedly different characteristics between each were detected, which can be caused by the variance in geomechanical behaviour of the tar sands. Introduction The steam assisted gravity drainage (SAGD) process has been successfully tested at the UTF (Underground Test Facility) project initiated in 1988. The project consisted of a small scale test (Phase A) with three pairs of 50 m horizontal wells, a commercial scaledpilot test (Phase B) with three pairs of 500 m horizontal wells, and Phase D where wells were drilled from the surface. The performance of these tests has been reported(1-3). Japan Canada Oil Sands Limited (JACOS) has participated in the UTF project since 1992, and acquired field data. Numerical history matches were conducted for all of these phases. For example, 10,990 grids were used to match the history of all three pairs of the Phase B project. In addition to the history match of well performances, flow resistance of the annulus and tubing, the effect of gas injection, and other aspects were also studied from the data provided. The growth mechanism of the steam chamber, which is presented in this paper, is also included in these topics. The original recovery mechanism of the SAGD process described by Butler(4, 5), is based on energy flow by thermal conduction, and drainage of the heated oil by gravity. Ito and Suzuki(6) proposed the importance of convective heat transfer in the SAGD process via numerical simulation. An equation to calculate oil production rates was developed by Ito et al.(7) through a parametric study, involving a series of numerical simulation runs. A quantitative heating mechanism of the reservoir by conduction and convection was also evaluated(8, 9). The above mechanism is based on the process where it becomes mature and the steam chamber grows sideways.

Mapping of the McMurray Formation for SAGD

Abstract The McMurray formation in north-eastern Alberta contains a substantial fraction of the world's currently identified oil resources. The areal extent of the deposit is in the order of 300 km north-south and 100 km east-west. It has been estimated(1) that over 40 billion barrels (6.35 × 109 m3) are potentially recoverable with steam assisted gravity drainage (SAGD) from dual well pairs. This is in addition to the substantial reserves already accessible from surface mining operations in locations with minimal overburden. The success of potential SAGD projects is greatly dependent upon the proper identification of regions with adequate pay, limited shale barriers, and controllable bottom water and/or top gas/water. The fluvial/estuarine nature of the formation greatly limits the predictability of trends when viewed in a local context. However, when regional behaviour is coupled with geostatistical techniques, an improved understanding of these critical parameters is possible. This paper applies a computerized log analysis technique to obtain the porosity, oil saturation and permeability from the McMurray formation utilizing digitized logs. Additional analysis is performed to obtain regions of effective net pay and other performance indices. This information is then presented through the use of regional mapping with a geostatistical approach. Introduction The Athabasca tar sand deposit is located in the northeast corner of Alberta, Canada. The major accumulation within this deposit is contained within the McMurray formation of early Cretaceous age. By various estimates, the OOIP of the McMurray formation exceeds 120 e09 m3 (750 billion bbls)(2). The commercial extraction projects currently operational in this region are based on surface mining techniques. However, only a small fraction of the resource is suitable for mining operations(2). The vast majority of the region is covered by overburden deposits that exceed any currently economic surface mining technique. These more deeply buried regions may prove to be amenable to the steam assisted gravity drainage (SAGD) process or some variant(3). Several pilot/demonstration plants have shown promising results with this technology, originally developed by the Alberta Oil Sands Technology Research Authority (AOSTRA) for the underground test facility (UTF)(4). The intention of this paper is to provide an overview of some of the computerized mapping techniques that are applicable to determining the extent of the possible SAGD resource in the McMurray formation. Reservoir Requirements for SAGD The SAGD process consists of a pair of parallel horizontal wells with a 3 8 m vertical separation. During normal operation, steam is injected into the upper/injection well, while oil and steam condensate are produced from the lower/production well. The energy transferred from the condensing steam heats the formation, greatly lowering the viscosity of the oil. This enables the oil to flow via gravity to the underlying production well. The process appears to be quite robust from a theoretical perspective. The two principal governing factors, conduction heat transfer into the cold reservoir and gravity flow of fluid to the production well, are only moderately influenced by many reservoir characteristics. A number of previous studies have explored the theoretical range of applicability of the SAGD process to generic heavy oil reservoirs(5, 6).

The Effect of Gas Injection on Oil Recovery During SAGD Projects

Abstract The effect of hydrocarbon gas injection on oil production during Steam Assisted Gravity Drainage (SAGD) projects was investigated using numerical simulation. The results indicate that oil production rates as well as total oil production are significantly reduced when gas is injected with steam from the early period of a SAGD operation. This is because most of the injected gas gathers at the upper part of the leading edge of the steam chamber and prevents the growth of the steam chamber there, which results in a reduction of ultimate oil recovery. However, if the gas injection is initiated during later periods of the process, an improved steam oil ratio is obtained without significant reduction in oil production rates and the total oil production. In this case, the injected non-condensable gas migrates to the upper part of the reservoir and does not prevent the growth of the steam chamber, since the chamber had already grown to the desired size. Gas injection slows down the growth of the steam chamber in the upper part of the reservoir and induces its growth downwards. This mode of growth of the steam chamber results in an improvement in steam oil ratio as is illustrated in this paper. An understanding of this mechanism and its optimal timing are important in the enhancement of the SAGD process. Introduction More than 52 billion cubic metres (330 billion barrels) of bitumen are believed to be in place in the Athabasca oil sands deposit in Canada, which are recoverable using the Steam Assisted Gravity Drainage (SAGD) in situ recovery process(1). The SAGD process has been successfully field tested at the UTF (Underground Test Facility) project, which was initiated in 1988. The project consisted of a small scale pilot test (Phase A) with three pairs of 50 m horizontal wells, and a commercially scaled pilot test (Phase B) with three pairs of 500 m horizontal wells. The performance of these tests has been reported elsewhere(2, 3). Japan Canada Oil Sands (JACOS) has participated in the UTF project since 1992, when Phase A of the project was completed. From its participation, JACOS acquired useful field data and operating experience. The data were extensively analysed through numerical simulation. Based on this analysis, JACOS started a demonstrative SAGD pilot operation in the Hangingstone oil sands reservoir. It involved two pairs of 500 m horizontal wells, and an additional three pairs of 750 m horizontal wells were started late in 1999. The SAGD process is a simple one. It consists of two horizontal wells, an injector placed directly above a producer. At first, both wells are heated by steam circulation. When communication between the two wells is established, steam is continuously injected through the upper injector while oil and steam condensate are produced from the lower producer. The original recovery mechanism of the process was described by Butler(4, 5), who developed the energy and oil flow equations associated with it. The energy flow by thermal conduction and drainage of the heated oil by gravity are the major components of this recovery concept.

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).

Steam and Gas Push (SAGP)-3;Recent Theoretical Developments and Laboratory Results

Abstract SAGP is a thermal oil recovery process that is similar to Steam-Assisted Gravity Drainage (SAGD) but which involves the addition of a small concentration of a non-condensable gas to the steam. This paper is a continuation of parts 1 and 2 presented at the 48th and 49th Annual Technical Meetings of the Petroleum Society. Theoretical developments and laboratory experiments continue to show significant improvements for the process as compared to SAGD. Experimental results have now been obtained with Athabasca crude oil as well as Cold Lake and Lloydminster type oils. In SAGP much of the oil displacement is caused by the flow of fingers of gas/steam rising counter-currently to the draining oil, rather than by the simple advance of a continuous steam chamber. The rising gas fingers raise the pressure in the reservoir above and this increase in pressure towards the top of the reservoir tends to push the oil down. Gas accumulates in the upper part of the reservoir and oil drains to the production well near to the bottom. The mechanism is discussed in the paper together with results from recent scaled, physical model experiments. The work demonstrates that SAGP may be expected to produce oil at rates nearly equivalent to SAGD but with much lower steam consumption. Introduction The successful applications of the Steam-Assisted Gravity Drainage (SAGD) process in the fields have provided tremendous opportunities for the development of heavy oil and bitumen resources. SAGD field projects are continuing to be constructed following the successful testing of the process at AOSTRA's Underground Test Facility (UTF) (now Northstar's Dover project). In addition to Canadian projects, this process has also been field tested in other countries(1). Most recently, the SAGD project in the Tia Juana field in Venezuela(2) is reported to produce average oil rates of 700 bpd per well pair from the first year's operation. Although SAGD is effective in producing bitumen and heavy oils, it requires a large quantity of heat to heat the whole chamber to saturated steam temperature and the heat loss to the overburden is high. The process may become uneconomic in some reservoirs such as those with thin sands, low porosity, low oil saturation, and bottom water zones. To extend the range of reservoirs that can be produced economically with SAGD technology, a new process was developed to reduce the heat loss to the overburden while maintaining high oil drainage rates. The Steam and Gas Push (SAGP) process involves the addition of a small amount of non-condensible gas, such as nitrogen or methane, to the steam. The accumulation of gas in the upper part of the chamber reduces the average temperature in the chamber and the heat loss to the overburden. As a result, the steam requirement is reduced and oil/steam ratio is improved. Both theoretical and physical model studies have been carried out at the University of Calgary with support from participants from industry, since the process was first described(3). Some mechanisms and model test results were described at the 49th ATM(4) and the 7th UNITAR International Conference on Heavy Crude and Tar Sands(5).

UTF Project Status Update, May 1997

Abstract The Underground Test Facility (UTF) is producing from three tunnel drilled 500 m long horizontal well pairs which have produced effectively at their peak rates and reached recoveries of almost 55% OOIP. Two new pairs of 750 m and 300 m horizontal wells have been drilled from the surface and were started up in April 1996. Start-up performance and well control methods have been successful. Another 750 m horizontal well pair is to be drilled from surface in the spring of 1997 and started up in the fall of 1997. Its purpose is to test methods of operating a well pair next to a depleted reservoir without losing steam to it. Net revenue from the UTF Project has funded the costs of adding three surface well pairs and related plant facilities since September 1994. The UTF Project is owned by AOSTRA with nine industry participants, including Gibson Petroleum Company Limited who was appointed Project Operator in October 1995. Introduction This is the third in a series of papers presenting the development status of the Steam Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) situated 70 km northwest of Fort McMurray, Alberta (Figure 1.1). The first paper(1), presented in 1991, covered the initiation of the UTF Project from 1984 to May 1991. It discussed the rationale for starting the UTF, the basic SAGD process, the facilities (shaft, tunnels, underground drill rig, Phase B plant), the results of the three Phase A well pairs, and the drilling and design of the three Phase B well pairs which had not yet started up. The second Paper(2) reviewed the start-up and performance of the three Phase B well pairs and facilities which had produced 500,000 barrels of bitumen at that time, May, 1994. It also discussed the economics of a potential 30,000 bpd commercial SAGD recovery project. The current paper looks at the continuing performance of the Phase B wells and facilities which have produced over 2,400,000 barrels of bitumen; the design and April 1996 start-up of two pairs of SAGD wells drilled from the surface (Phase D) which have produced over 170,000 barrels of bitumen; the design of a third surface well pair to be drilled in the spring of 1997 to test the methods of placing and operating a new well pair next to a depleted reservoir without adverse effects; the features of a produced water recycle plant scheduled for start-up in the fall of 1997; and concludes with a brief discussion of some commercial aspects related to the economics of the SAGD process at the UTF and the marketing of bitumen. The UTF Project is currently owned by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and funded jointly by AOSTRA (25%) and nine industry participants (8 113% each). In addition to Gibson, the industry participants are: Amoco Canada Petroleum Company Limited, Chevron Canada Resources Limited, China National Petroleum Co. (Canada) Ltd., Imperial Oil Resources, Japex Oil Sands Limited, Petro-Canada, Shell Canada Limited, and Suncor Inc.

Towards Commercialization of the UTF Project Using Surface Drilled Horizontal SAGD Wells

Abstract The Underground Test Facility (UTF) Demonstration Project was started in 1984 and the first two phases have been completed. The UTF Project current Phase B-2 is proceeding with the testing of the tunnel drilled Steam Assisted Gravity Drainage (SAGD) wells. The UTF Project is producing about 320 cubic metres per day (m3/d) [2,000 barrels per day (BPD)] of dry bitumen which is trucked to market. The higher than predicted bitumen sales revenue has been reinvested into the project and these extra funds are being used to drill and operate SAGD wells from the surface. This paper provides some important concepts for using SAGD well pairs drilled from the surface to produced bitumen on a commercially viable basis in the Athabasca Oil Sands. The expansion demonstration program consists of drilling and completing from the surface, two 750 m SAGD horizontal well pairs, to produce an additional 320 m3/d. This will increase bitumen production from the UTF Project to 640 m3/d (4,000 BPD). Key features covered are surface drilling and completion of long horizontal wells, steam injection and monitoring, well production control, surface facilities for producing dry bitumen and getting the product to market. The design and operating aspects of a 4,800 m3/d (30,000 BPD) commercial project are reviewed. Project costs and economics favour surface drilled horizontal wells over wells drilled from underground tunnels. The purpose of this new SAGD technology is to economically develop the 140 billion cubic metres (900 billion barrels) of oil-in-place in the Athabasca oil sands region of Alberta. Of these, more than 50 billion cubic metres (330 billion barrels) are now recoverable using the SAGD technology. The nine industry participants in the UTF project own about 50% of oil sands leases in Athabasca, hence the high level of interest in developing new technologies to extract the bitumen. There are other major factors which need to be provided in order to commercially develop this resource. The paper also outlines the requirements for oil sands development in Athabasca and discusses nurturing the expansion of existing USA heavy oil markets, building a heavy crude oil pipeline from Athabasca region to Edmonton and taking advantage of new technologies such as SAGD to significantly reduce capital and operating costs. The Underground Test Facility (UTF) The purpose of the UTF is to test the concept of in situ bitumen extraction using the Steam Assisted Gravity Drainage (SAGD) process. The key features of the current UTF Project are shown in Figure 1. It consists of two vertical shafts 3.3 m in diameter penetrating 140 m of overburden, 20 m of oil sands and 15 m of limestone below which are located horizontal tunnels 5 m wide and 4 m high. The tunnels are in solid limestone and are larger where the wells are located (8 m wide × 5 m high) and smaller (4 m wide × 3 m high) where the tunnels serve only to complete the access and ventilation circuit.

Numerical Simulation of the SAGD Process In the Hangingstone Oil Sands Reservoir

Abstract This paper presents a simulation study of a steam. assisted gravity drainage (SAGD) process applied to the Hangingstone tar sands reservoir. Two pairs of 500 m long horizontal wells installed from the surface are considered. The study was conducted to forecast recovery performance and to further understand the oil production mechanism. Results predicted that more than 60% of the oil can be produced in six years of operation with a steam-oil ratio of less than 3.0. The study was extended to provide a visual understanding of the flow behaviour of steam, oil, and water in the reservoir. The fluid flow diagrams revealed that oil is displaced mainly by steam condensate and that convective energy carried by steam condensate dominates the heat transfer mechanism. The authors applied this recovery mechanism concept to the study of subcooling temperature optimization for the steam trap control. The results of this reservoir dynamics study are presented. Finally the role of this process's geomechanical effects are briefly discussed. Introduction The Hangingstone oil sands reservoir is located near Fort McMurray. The reservoir is jointly owned by Petro-Canada, Imperial Oil, Canadian Occidental, and Japan Canada Oil Sands (JACOS). The bitumen viscosity at reservoir condition is over 1,000,000 mPa.s and will not flow naturally. JACOS is going to use a Steam Assisted Gravity Drainage (SAGD) process to extract bitumen from the Hangingstone reservoir. A cyclic steam stimulation (CSS) process was extensively tested for the same reservoir over a decade. Through a numerical simulation study of the performance, it was found that the bitumen is difficult to produce at economically feasible rates using the CSS process for the subject reservoir(1). After seven cycles of CSS operation, 3,182 m3 of oil was produced for a total of 28,000 m3 of steam injection. Steam oil ratio and calendar day oil rates were 8.8 and 3.45 m3/day respectively. JACOS has been participating in the Underground Test Facility (UTF) project since 1991 when Phase A of the project was completed. From its participation, JACOS has received all of the field data plus operating and drilling experience. UTF's field data have been extensively analysed through numerical simulation. Based on the analysis of the data, it was decided to drill two pairs of 500 m horizontal wells in 1997 and to start operating the SAGD process in 1998. The expected well performance calculated using a thermal simulator is presented in the paper. Following the base case run, a series of parametric studies were conducted. Some interesting results, such as the oil recovery mechanism obtained from the study, are also included. Although many uncertainties still exist in both the recovery concept and operational procedure for the SAGD process, promising potential for its application has been demonstrated in Phases A and B of theUTF project(2, 3). One major uncertainty is whether the geomechanical change of the formation during the process is an important aspect or not. The role of geomechanical effect in the growth of the steam chamber and well performance is also presented.

Drilling And Completion For Steam-assisted Gravity Drainage (SAGD) Operations

My contribution to this journal issue, the theme of which is Advances in Drilling and Completion, is on the placement and application of horizontal wells for secondary production of light to medium crude oils and the primary recovery of heavy oil and bitumen. Drilling, well completion and production are complex operations determined by geological factors and technological considerations. The perspective I present in this brief review is that of an exploitation engineer with respect to how recent advances in drilling and completion facilitate and enhance the SAGD process. Innovative techniques and engineering decisions for precise drilling of horizontal wells are important in the effectiveness and efficiency of SAGD-based recovery schemes. Pairs of horizontal wells are maintained parallel in drilling through the use of magnetic guidance tools. There are multi-lateral completions, re-entry, under-balanced drilling, and the application of coiled tubing. Completion methods include the use of sand screen devices, gas lift, jet pumps and production lifting with sumps using pilot holes. Horizontal Wells and SAGD SAGD, as a primary or improved recovery technique, has evolved rapidly over the last decade. Its growth has been in tandem with the acceptance and implementation of horizontal wells. The technology is environmentally friendly and cost effective for lifting heavy oils and bitumen which are ordinarily immobile in reservoirs. Steam is injected and oil is recovered from a large zone around a horizontal well, with advantage taken of natural forces that favour counter-current gravitational movements of steam, condensates and reservoir fluids. Under gravity, mobilized oil continuously drains into a horizontal well to be moved to the surface. Various types of reservoirs can be accommodated, at different levels of pressure and maturity. The technology has been demonstrated on small scales in the laboratory of Dr. Roger Butler and in AOSTRA's Underground Test Facility. Field tests are in progress. As with any new technology, the transfer from the laboratory to the field has its trials and tribulation. Poorly planned and xecuted tests under field conditions can conceal the true potential of the scheme. The requirement for diligent planning, well-trained staff and field operators " accurately" implementing the design programs cannot be over emphasized. Considerations for SAGO Well Configurations There are at present three major arrangements of the horizontal wells in exploiting SAGD. The basic involves two wells drilled one above the other. The lower well, or producer, is located at the base of the formation. The other well, the steam injector, is located several metres above and parallel to the producer. A more recently developed scheme involves the use of a single well with dual tubing strings. Steam is injected from the surface through the one tube to exit at the toe of the well. Along the horizontal part mobilized fluids and condensates drain into the liner to be lifted through the production tubing from the heel to the surface.

Numerical Simulation Of The Steam-Assisted Gravity Drainage Process (SAGD)

Abstract Physical and numerical models can be employed together to better understand the SAGD process. When there are inadequate measured physical properties as input data, and insufficient built-in mathematical processes, it is beneficial to validate a numerical model by history matching physical model results. Based on Chung's experimental data from a physicalmodel, a two-dimensional, three-phase (bitumen, water and steam) and two-component (water & bitumen) black oil numerical model for the SAGD process was developed and tested, using the CMG "STARS" thermal simulator. Both the "Spreading Steam Chamber" and the "Rising Steam Chamber" processes were simulated. The numerical results agree reasonably well with the measured data for cumulative oil production, recovery percentage and temperature profiles in the model at different times. The results from the numerical simulation were found to be relatively insensitive to the form of the relative permeability functions employed. Linear relative permeability curves were employed to simulate the experimental production results. The model can be employed as a tool to aid in sensitivity studies and in the interpretation of the laboratory results. Introduction A reservoir can only be produced once, and it is often difficult and costly to correct mistakes in the approach, once the project has been initiated. However, a model study can be conducted several times and alternatives examined. Therefore, before launching any new technology, it is advisable to conduct extensive testing, using physical and numerical models, to evaluate various scenarios for the optimization of pattern type, size, well completions and rates. It is important, technically and financially, to have a prediction of the performance that is likely to be achieved from a given proposed recovery scheme for a given reservoir. Models, both physical and numerical, improve the understanding of reservoir processes. A physical model can provide a means for checking the accuracy and assumptions of the numerical model. Validating the numerical model is advisable by history matching with a well-defined physical model to overcome some of the limitations of numerical modelling. In some recovery processes, such as the Steam-assisted Gravity Drainage (SAGD) process(l), the physics of the situation is so complex that both physical and numerical models should be employed as complementary tools to obtain insight into different mechanisms and determine which strategies will optimize the process. Several field pilots using the SAGD process are underway. These include the three Esso Resources horizontal pilot projects at Cold Lake, Alberta, the Sceptre Resources pilot project in the Tangleflags North field near Lloydminster, Saskatchewan, and the Alberta Oil Sands Technology and Research Authority's (AOSTRA) Underground Test Facility (UTF) project in the Athabasca field near Fort McMurray, Alberta. Scope and Objective of Study The scope of this numerical simulation study is to match the oil recovery and the steam temperature interface position as observed in Chung's physical model(2,6) of the SAGD process. The objective is to investigate the feasibility, using a commercial CMG simulator ("STARS"), to history match the SAGD process, particularly the "spreading steam chamber" phase and the "rising steam chamber" phase.

The Nature And Control Of Geyser Phenomena In Thermal Production Risers

Abstract Efficient application of Steam-assisted Gravity Drainage (SAGD) for bitumen or heavy oil recovery requires production of large fluid volumes, close to the boiling point of water. Flowing or gas/steam lifting such wells is an attractive alternative to rod pumping, but evidence is given that the flow can be unstable, due to the large energy release of flashing water. The instabilities are the same phenomena that drive cyclic eruptions in geothermal geysers. A unique finite difference simulator is used to model and study the transient thermohydraulics of superheated water in an idealized wellbore. It is shown that some form of dynamic wellhead choking system is probably required for satisfactory control of a surface access SAGD well. The advent of horizontal wells for thermal recovery and especially for SAGD has led to the need to produce very large fluid volumes from individual wells, at high temperatures. For optimum SAGD, the temperature in the production liner should be kept close to the steam point at bottomhole pressure (steam trap production control)(l), so as to maintain the steam chamber as deep as possible. Sustained fluid production rates of 300 m3/D or more(2) are anticipated from single producers; at this rate, wellbore heat losses will have a limited cooling effect. In most SAGD applications, then, produced water will flash as pressure declines on the way to the surface. UTF Production Lifting Experience At the AOSTRA Underground Test Facility (UTF)(3), SAGD testing is carried out using horizontal wells that are drilled from a tunnel located below the oil sand reservoir. Steam generation and production treating facilities are on the surface, and standard piping carries fluids to and from the well chambers. The wellheads and production control valves are about 20 m lower in elevation than the production liners. This arrangement takes advantage of gravity to avoid flashing in the wellbore and the tunnel facilities, but production is still subject to flash conditions in the riser, during the 185 m climb to the surface. This was recognized during the design of the Phase A facilities, and it was hoped to exploit the resulting steam lift effect. The underground pump was de-rated and a steam sparge system was installed at the base of the riser to enable the lifting of cold fluids. A summary of experience with this system is shown in Figure 1. This is a scatter plot showing the average riser pressure gradients for about 700 days of Phase A operation, as a function of riser bottomhole temperature. This temperature is expressed in terms of subcooling below the steam point, to account for varying pressure. Most days fall into one of three groups indicated, corresponding to the (I) no flashing, (II) slight flashing, and (III) high enthalpy (est. 15 – 30% quality) conditions. The large gap between regions II and III represents conditions that were avoided due to extreme and persistent instability. In this region, flow consisted of geyser-like eruptions occurring at periods from one-half to several hours.

水平坑井を用いたビチューメン回収技術

Crude oil (bitumen) in oil sands is extremely heavy and the API gravity of the bitumen is usually around ten degree or less. The viscosity varies from 100, 000mPa•s to 8, 000, 000mPa•s at reservoir condition. Due to this remarkably high viscosity and low gas solubility, conventional methods of recovery are not applicable. Thermal techniques aim at reducing oil viscosity in order to increase its mobility, through the application of heat.The oil sand deposits in Alberta of Canada contain about 270 billion cubic meters of bitumen and are expected to play an increasingly important role in the Canadian and world energy picture in the near future.SAGD (Steam Assisted Gravity Drainage) process is a newly developed thermal recovery technique with a pair of horizontal wells, originated by Dr. Butler in 1978. The pilot test has been conducted at UTF (Underground Test Facility) project in Alberta province by using SAGD process since 1987. The production performance of the pilot test wells is actually much better than that of the wells of the commercially operated projects such as Esso's Cold Lake, Amoco's Wolf Lake and Shell's Peace River.This paper introduces the UTF project and explains the drilling method of a pair of horizontal wells and the basic mechanism of SAGD process comparing with CSS (Cyclic Steam Stimulation) process which is a conventional thermal technique in bitumen recovery. It also discusses the economics of the existing commercial projects and the future commercial projects by SAGD process.

Enhanced Steam-assisted Gravity Drainage: A New Horizontal Well Recovery Process For Peace River, Canada

Abstract A new horizontal well recovery process, developed for application in the Peace River tar sands of Alberta, Canada, has shown sufficient technical and economic potential to warrant a field test which commenced operations in November 1993. The new process is an enhanced version of the steam assisted gravity drainage(1,2) (SAGD) process which is currently being field tested by Alberta Oil Sands Technology and Research Authority (AOSTRA) together with a consortium of industry members at the Underground Test Facility (UTF) located in northern Alberta(3–5). The SAGD well configuration, which consists of two parallel and superposed horizontal wells, with continuous steam injection occurring in the upper well and liquid and gas production from the lower well, is also utilized in the Enhanced Steam Assisted Gravity Drainage (ESAGD) process. A performance enhancement to the SAGD process is obtained through the application of a small pressure differential between adjacent pattern steam chambers. The gentle "steam drive," which occurs once sufficient bitumen mobility has been obtained between steam chambers, is observed to be tolerant of reservoir heterogeneities. Additional benefits include accelerated steam zone growth and bitumen production, up to 50% improvement in ultimate recovery efficiency, and no impairment to the thermal efficiency relative to the SAGO process. The surface access 'ESAGD field test currently underway in Peace River is described. The Peace River oil sands are 10caEed in northwestern Alberta (Figure I). Following the oil sand deposit discovery in 1949, Shell Canada began testing a variety of in situ recovery processes, including steam soak tests in 1962. steam drive and in situ combustion testing in 1965–66, followed by steam injectivity and productivity tests in 1973–74(6,7). A 31-well pilot (Peace River In Situ Pilot - PRlSP; see Figure 2) began operations in 1979, testing the pressure cycle steam drive process(7–9). Pilot operations ended in 1992 at a cumulative recovery efficiency of 65% and cumulative oil steam ratio of 0.25. In 1986, Shell Canada commenced operations in [he Peace River Expansion Project (PREP). the only commercial project in [he Peace River oil sands, with a target production of 1,600 m3/day of bitumen from 163 producers(10). The need to improve production economics by reducing production costs was the motivation behind the Peace River horizontal well study, which began in early 1991. The use of horizontal wells in a pattern steam drive was shown via numerical simulation to result in poor recovery and thermal efficiency due 10 poor steam conformance. This led to the numerical simulation study of SAGD (1,2). SAGD without any performance enhancements did not appear to yield the desired performance uplift in Peace River. Further study ultimately led to the development of the ESAGD process. Geological Description The Peace River oil sand deposit covers an area of approximately 6,200 square kilometres and contains some 12 billion cubic metres of bitumen. The productive horizon is found in the Bullhead member of the Cretaceous Bluesky/Gething zone at an average depth of 600 m, and is geologically equivalent to the shallower. productive McMurray sands in Northeastern Alberta(11).

Review of Phase A Steam-Assisted Gravity-Drainage Test

Summary This paper presents a case history of the Phase A steam-assisted gravity-drainage (SAGD) test conducted by the Alberta Oil Sands Technology & Research Authority (AOSTRA) at its underground test facility (UTF). Reservoir description, the recovery process, design of wells and other critical hardware, production operations history, and performance analysis are discussed. Phase A demonstrated a commercially viable combination of recovery, production rate, and steam/oil ratio (SOR). Completions design and production engineering progressed significantly. Phase B scaleup considerations and commercial economic projections also are discussed.

Design of the Monitoring Program For AOSTRA's Underground Test Facility, Phase B Pilot

Abstract A monitoring program for an oil sands thermal recovery pilot project is described. New methods of monitoring were used to monitor the steam-assisted gravity drainage process, and to observe the reservoir's geo-mechanical response. In addition, the performance of the access tunnels and of the production wells' surface casings were also monitored. The types, quantities, and locations of instrumentation are described. Rationale for the selection of instrumentation is presented, and approximate costs are provided. Background The Alberta Oil Sands Technology and Research Authority's Underground Test Facility (AOSTRA UTF) is located 20 km west of Syncrude in the Athabasca oil sands deposit of north-eastern Alberta. The reservoir bottom is at a depth of 160 m and the pay is 20 m thick. At the reservoir temperature of 7 °C, the viscosity of this 1.014 kg/l (8 ° gravity) bitumen is 5 Pa •s. The underburden consists of massive, underformed Waterways Formation limestone. Open pit mining of this reservoir is uneconomic because of the low pay to overburden ratio, and the relatively thin pay is uneconomic to recover with in-situ processes from vertical wells. Instead, the UTF project uses the Shaft And Tunnel Access Concept (SATAC) to gain access to the reservoir from tunnels within the limestone underburden. Horizontal well pairs were drilled into the oil sands from the tunnels. Steam injection is concurrent with the bitumen and water production. The process operates at a constant pressure (below fracture pressure) and relies on gravity drainage to deplete the reservoir(1). The phase A "laboratory scale" pilot consisted of three pairs of 160 m wells, each with 55 m of completion, and was successful(2). The subsequent Phase B pilot is operating, and consists of three pairs of 600 m wells, with 500 m completions. Purpose The intent of the monitoring program was to ensure the safety of the tunnels and wells, to quantify the success of the process, to confirm the geomechanical observations made during the Phase A laboratory scale pilot, and to assess methods of monitoring a commercial-scale project. The SATAC approach to bitumen recovery was novel enough to warrant extensive instrumentation of the shaft and tunnels. The Phase A tunnels, which provide access to the underground wellheads, had to be safe for personnel, isolate them from the pressurized steam chamber and allow for the continuous flow of steam and produced fluids between the wells and the surface. Given the observed integrity of the Phase A tunnels and the extremely consistent geology of the limestone underlying the UTF lease. The new Phase B tunnels have a reduced number of instrumented stations(3). The program is sufficiently flexible to allow for supplementary instrumentation if warranted. FIGURE 1: Plan of Phase A wells. (Available in full paper) For interpreting the process results, the data obtained from surface instrumentation in the Phase A pilot was extremely useful. It was expected that the behavior observed in the Phase A pilot would be applicable to the Phase B pilot and would therefore avoid the costs of using closely-spaced wells for monitoring small-scale phenomena.

Effective Application of Steam Assisted Gravity Drainage of Bitumen to Long Horizontal Well Pairs

Abstract A recent field test of the Steam Assisted Gravity Drainage (SAGD) process at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) has proven that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. The UTF test used well pairs that were completed for only about 5 m, however, as compared to lengths of several hundred metres which will be required for commercial application. Accordingly, the UTF Phase B test currently under construction will use wells with a full 500 m of completion. This paper reviews the design and operating requirements that have been developed to ensure that the full lengths of the Phase B well pairs contribute to bitumen recovery, i.e. that the production rates will scale up in proportion to length. The discussion proceeds from the conditions required to initiate drainage at a given location along the well pair, to the means of establishing and maintaining such conditions at every location. Numerical examples show that, for typical formation permeabilities, start-up can be achieved with thermal conduction and gravity alone, two highly predictable phenomena. This leads to consideration of design and operational requirements to ensure that conduction heating is maintained on the one hand, and gravity is not defeated (by adverse pressure gradients) on the other. In summary these are:the well pairs must be drilled so that the interwell spacing remains within specific tolerances;the liner and tubing must be large enough, relative to the completion length and expected formation productivity, so that pressure gradients are kept below certain values, anda full length tubing string must be combined with correct operating policy to ensure that the full lengths of both injection and production liners are kept hot throughout the life of the well. Introduction Butler et al(1), and Edmunds et al(2) have previously described the mechanics of two dimensional SAGD to a pair of horizontal wellbores. The recent Phase A test of SAGD at the AOSTRA UTF(3) showed that the process mechanisms work in the field as expected from previous laboratory, analytical, and numerical work. Phase A well pairs were completed for only about 55 m, however, whereas economic commercial application requires several hundred metres of active completion. AOSTRA is accordingly proceeding with a Phase B Test of three long well pairs, with 500 m completed length. In a reservoir of immobile bitumen, fluid mobility must be artificially FIGURE 1: Three dimensional start-up of a long well pair. created between a well pair before SAGD can proceed. With reference to Figure 1, it should be easy to force communication between an injector and producer over at least one section of a long well pair, but it is less clear how the remainder of the pair can be made to follow in a reasonable time, say a few months. Long delays will incur very significant economic penalties; not only will the Calendar Day Oil Rate (CDOR) be reduced, but also, because a longer time will be required to recover the same amount of oil, the Stearn/Oil Ratio (SOR) will be increased.

AOSTRA underground test facility: progress and potential : Haston, J A; Luhning, R W; Gittins, S D CIM BullV83, N938, June 1990, P53–58

AOSTRA underground test facility: progress and potential : Haston, J A; Luhning, R W; Gittins, S D CIM BullV83, N938, June 1990, P53–58

Reservoir Characterization for Chevron's HASDrive Field Trial, Athabasca Oil Sands Area, Northeastern Alberta, Canada: ABSTRACT

Chevron is currently field testing an in-situ thermal recovery process termed Heated Annulus SteamDrive (HASDrive) on the Lower Cretaceous Athabasca tar sand deposit at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) site. The HASDrive process applies heat through a subsurface horizontal pipe to the base of the bitumen-rich reservoir sands of the McMurray Formation. A vertical steam-injection well aids in mobilization of the heavy crude and sweeps hydrocarbons toward a horizontal subsurface producing well. To evaluate the HASDrive technology, a geologic model was developed to predict the distribution and geometry of reservoir sands and intervening shales. Core studies indicated deposition took place in an estuarine environment, with sands representing tidal channel deposits and shales relating to tidal flat sedimentation. A thorough program of conventional and special core analysis was done on samples from five wells. Special core analysis consisted of miscibly cleaning samples prior to determination of brine permeability. Vertical and horizontal permeability were determined for massive to cross-bedded sandstone as well as four types of shale-bearing sandstone. Of these four, thin shale beds and shale breccia were more effective in reducing permeability and may form barriers to fluid flow. Thin discontinuous shale laminae ormore » shaly wisps merely impede flow. Interactive workstation programs used core and log data petrophysical parameters as input to build a simulator grid of 2,600 blocks in 10 layers to represent a field trial area of approximately 2,000 m{sup 2}. Potential barriers capable of preventing or reducing the flow rate were identified, incorporated into the model, and treated as dimensionless shales (i.e., shaly beds with negligible thickness). The simulator model was then used to the match history of field trial fluid production.« less