Steam-oil Ratio Research Articles

Sensitivity Analysis to Operational Parameters of the Offset Well During Fast-SAGD Process in Naturally Fractured Reservoir

Few studies were done to investigate performance of the Fast steam-assisted gravity damage (SAGD) recovery method especially in naturally fractured reservoirs (NFR). The authors studied some cyclic steam stimulated operational parameters effects on the Fast-SAGD performance in NFR. A synthetic 2D homogenous model was constructed by Computer Modelling Group's (CMG) and simulated using the STARS module. Comparison between SAGD and Fast-SAGD recovery methods in this model shows great increase in the oil production but small increase of thermal efficiency in the Fast-SAGD recovery method. Simulation outcomes represent 17% increment in ultimate recovery factor but small reduction in steam-oil ratio. Results show that increasing the number of offset cycles and injection period yield increment in the oil production. Increasing the offset injection rate causes growth in the oil production, but has an optimal value. By increasing the distance between the offset well and SAGD well pairs up to a certain value, oil production increases but decreases after that point. This is due to the ability of the fractures in making connection between the steam chambers in higher distances. When production bottom-hole pressure decreases, the heated oil in near well region is subjected to more pressure drop and causes more oil to be produced. More offset wells result in higher production but simultaneously lower recovery factors. Increasing and decreasing soak time as the last investigated parameter did not affect the trend of production anyway.

Numerical modeling of steam injection in heavy oil reservoirs

In this communication, a three-dimensional, three-phase numerical model is presented for simulation of steam injection in heavy oil reservoirs. Formulation details, numerical solution method, and computational results are presented. The model includes the effects of three-phase relative permeability, capillary pressure, and temperature and pressure-dependent fluid properties. Interphase mass transfer of water-steam is allowed, but the oil is assumed nonvolatile and the hydrocarbon gas is insoluble in liquid phases. The three-phase mass balance and the energy balance equations are solved simultaneously using finite difference method. Some steam injection laboratory data are used for studying the accuracy of this model. Comprehensive and comparative studies together with extensive sensitivity analysis among various important parameters are conducted to understand steam injection performance in the heavy oil reservoir. This work indicates that steam injection can improve oil recovery from almost zero up to nearly 60% during a fixed period of time. In addition, it shows that only 30% of OOIP can be recovered by hot water injection method. The results demonstrate that there is an optimum time for oil production that is determined according to the flow of oil production and steam–oil ratio (SOR).

Numerical Simulation Study of Field Scale SAGD and ES-SAGD Processes Investigating the Effect of Relative Permeabilities

Steam Assisted Gravity Drainage (SAGD) has been proved to be an effective method in producing from extra heavy oil or bitumen resources. The main recovery mechanism in this process is viscosity reduction by introducing heat into the reservoir. The Solvent Co-Injection processes (SCI) or Expanding Solvent SAGD (ES-SAGD) are alternative methods to the conventional SAGD. In these processes reduction in the oil viscosity is achieved by a combination of latent heat from steam and dissolution of solvents into bitumen. These alternative methods lower the steam requirements and associated costs with it, as well as the amount of carbon dioxide emission into the atmosphere caused by steam generation process.In this work some numerical simulations were conducted to examine the effect of relative permeability data on the performance of SAGD and ES-SAGD processes. Temperature dependant relative permeability data, that shows variation of end points with temperature, was tested against fixed relative permeabilities. Oil production was found to be strongly dependant on the end point relative permeability data. It is suggested to use temperature dependant relative permeabilities in numerical simulations. This must be considered as a matching criterion, when trying to history match field data.Solvent co-injection showed promising results both in terms of improved recovery factor and reduced steam oil ratio as an economical criterion. In addition, the high solvent recoveries of 97-100% in all solvent co-injection runs make the process even more economically interesting. Injecting only 2% on a molar basis of pentane, hexane or heptane as solvent, boosted the oil rates up.

A Comparative Field-Scale Simulation Study on Feasibility of SAGD and ES-SAGD Processes in Naturally Fractured Bitumen Reservoirs

Thermal processes are widely applied in heavy oil and bitumen reservoirs. Steam-Assisted Gravity Drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD) are the two most promising techniques for production of heavy oil and bitumen reservoirs. The feasibility and efficiency of the aforementioned processes have been studied extensively for sandstone reservoirs. As there are some naturally fractured heavy oil resources in the world similar thorough studies are necessary to find out the applicability of these processes in these types of reservoirs. In this work several numerical simulations have been performed to investigate the feasibility of these methods in naturally fractured reservoirs (NFR). Dual permeability option was applied in this study. This work tries to cover the effect of several parameters such as reservoir thickness, fracture permeability, matrix permeability, fracture spacing, steam quality and oil viscosity on SAGD and ES-SAGD processes. Results have elucidated that basically both methods are efficient and economically applicable in naturally fractured reservoirs. Recovery factor and cumulative steam-oil ratio (CSOR) were economical parameters to evaluate the performance of processes. However, in some cases net amount of injected energy and oil production rate were considered for evaluation too. Generally ES-SAGD had better performance based on the recovery factor, CSOR, oil production rate and net amount of injected energy. Effect of solvent type and concentration were studied for ES-SAGD process only. For this purpose, pentane, hexane and heptane were selected. Pentane displayed better performance in earlier periods of production; however the heavier solvents showed better recovery performance at later times.

Significant Superiorities of Superheated Steam in Heavy Oil Thermal Recovery

With superheated steam there is no direct relationship between temperature and pressure, and it can exist at a wide range of temperatures. Superheated steam with high degree( >50 °C) of superheat has similar thermal physical characteristics with ideal gas and the heat transfer coefficient is 1/150-1/250 as much as that of saturated steam during heat transferring. It could release less energy and transmitted longer distances than that of saturated steam in heavy oil reservoirs. Numerical simulation shows that under the condition of carrying the same heat, superheated steam huff and puff enlarged the heating radius by about 10 m, oil production increment by 1463 t, oil steam ratio increase by 0.7. Superheated steam huff and puff was put into Kazakstan's heavy oil reservoir after saturated steam huff and puff and the average daily oil production was 2-4 times that of saturated steam huff and puff, which improved heavy oil production effectively. The secondary heavy oil thermal recovery by superheated steam huff and puff applicated in marginal heavy oil reservoirs achieved satisfactory effect.

Optimization of SAGD and solvent additive SAGD applications: Comparative analysis of optimization techniques with improved algorithm configuration

AbstractHeavy oil and bitumen recovery cost are excessive mainly due to high energy requirement to generate heat and its environmental impacts. Steam Assisted Gravity Drainage (SAGD) is an example of this case. The determination of optimal operating conditions, such as injection rates and well locations, based on reservoir and fluid characteristics is essential in the design of field applications.Many Steam Assisted Gravity Drainage (SAGD) optimization studies published in the literature combined numerical simulation with graphical or analytical techniques for design and performance evaluation. There have been limited efforts that integrated the simulation exercise with global optimization algorithms. Some studies focused on optimization of cumulative steam-to-oil ratio (cSOR) in SAGD by altering steam injection rates, while others focused on optimization of cumulative net energy-to-oil ratio (cEOR) in solvent-additive SAGD by altering injection pressures and fraction of solvent in the injection stream. Typical scoring functions were the net present value per hectare of land (NPV/ha) by controlling steam and solvent rates. Several studies also considered total project net present value calculation by changing total project area, capital cost intensities, solvent prices, discount rate, and risk factors to determine the well spacing and drilling schedule. Optimization techniques commonly used in those studies were scattered search, simulated annealing, and genetic algorithm (GA). In continuation of these efforts, we focused on optimizing the SAGD process and its extension to solvent-additive SAGD and several optimization techniques including simulated annealing and genetic algorithm were tested and compared. Additional procedures were incorporated to improve the implementation configuration and initial population or seed. The objective function was defined to obtain the lowest cumulative steam-oil ratio (cSOR) and highest recovery factor. It was used later as a scoring function by changing solvent-to-steam ratio and steam injection rates. The results in this paper can be implemented directly in the efforts of minimization of cost and environmental impacts while accelerating the recovery in SAGD.

An Investigation Into Optimal Solvent Use and the Nature of Vapor/Liquid Interface in Solvent-Aided SAGD Process With a Semianalytical Approach

Summary The steam-assisted gravity-drainage (SAGD) process is used widely to recover heavy oil and bitumen from formations in which no other recovery method has proved to be economical. It is an energy-intensive process, and because of economic and environmental reasons, solvents as additives to the injected steam are being explored currently to reduce the energy and emissions intensity of SAGD. The solvent-aided process (SAP), tested in the field and described in the literature, is one such attempt. In the SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam. Thus, the viscosity of the oil is also reduced because of solvent dilution in addition to heating. The SAP can improve the energy efficiency of SAGD significantly, thus reducing the heat requirement, as shown in field trials discussed elsewhere. However, on the use of the right amount of solvent that can result in best overall performance, there is very little discussion in the literature. Because of the high cost of such solvents, there is incentive to optimize their use in SAGD. Recently, various authors have attempted to address the subject with, for example, arbitrary time-dependent schemes of solvent injections, assessing their impact on results or by treating the internal reservoir dynamics as a black box and using optimization methods, such as genetic algorithms (GAs), to estimate the optimal amount of solvent. While these approaches orient us to the problem in a context-specific manner, it is believed a generalized treatment to estimate optimal use of solvent requires a mechanism-based understanding. The approach presented in this paper is aimed at estimating the optimal solvent in the context of SAGD. It combines the existing Butler's oil-drainage analytical models (Butler 1985, 1988, 1994) for SAGD and vapor extraction (VAPEX), which deal with heating effect and solvent-dilution effect one at a time, into one. Then, it calculates the time-dependent steam rates to maintain the predicted oil rates in conjuction with solvent rates and, thus, estimates the solvent/steam ratio (SSR) and the steam/oil ratio (SOR). The results are discussed for a few light-alkane solvents. In the process of this exercise, it is discovered that to obtain reasonable SSR and SOR, a significant amount of oil has to drain from a diffuse layer, which has a varying temperature, solvent concentration, and gas saturation (from maximaum gas saturation at the injection end to zero at the vapor/liquid interface).

A Tricky Tradeoff - Can Adding a Little Solvent Yield a Lot More Heavy Crude?

Years of small-scale testing have shown that adding a small amount of a light hydrocarbon to steam can yield large gains in heavy-oil output and reduce emissions; but, no one has proven it can be done on the large scale common in the Canadian oil sands. That could change soon. Two innovative Canadian operators—Imperial Oil and Cenovus Energy—are working on commercial steam-injection installations. They have spent more than a decade developing and testing ways to add solvents such as butane to steam to increase production and ultimate recoveries. If it works on a large scale, it will allow heavy-oil producers to use significantly less steam per barrel to coax out thick crude. Lowering the steam/oil ratio (SOR)—which represents the barrels of water used to produce an added barrel of oil—could offer a profitable path to reduced emissions. “If you can improve the thermal efficiency—the steam/oil ratio—emissions go down. Also, costs go down,” said Ian Gates, an associate professor at the University of Calgary, whose research includes solvents. “It all goes in the same direction. You make more money with lower greenhouse emissions.” Based on laboratory work and field tests, the combination of heat and solvents can increase production—30% or more is often cited—though some have done better and some worse. Cenovus’ pilot program, which was run at two locations, showed it could reduce its steam/oil ratio by 25%, said Subodh Gupta, chief of technology development for the company spun off by Encana. He also said the greater efficiency could allow wide well spacing. Imperial said it sees a significant increase in the amount of oil it will ultimately be able to produce. The operator, which improved its estimated recoveries from 20% to 40% at its Cold Lake field by improved reservoir analysis, steam injection, and drilling techniques, said that solvent use plus continued improvements in those three areas “have the potential to increase recovery to more than 60%.” Despite the potential, many working on the technology express concerns about the cost of the solvent required. “There is no doubt it works, but solvent is quite expensive,” said Neil Edmunds, vice president for enhanced oil recovery at Laricina Energy, who has long been involved in solvent research and simulation work. For companies considering the idea, he said, the cost of the solvent can be “sobering.”

Experimental Analyses of Athabasca Bitumen Properties and Field Scale Numerical Simulation Study of Effective Parameters on SAGD Performance

Due to reduction of high quality oil resources and consequently increase of oil price around the world, new sources of energy should be find to relief the high demand of energy. Hence, countries like Venezuela, United States and particularly Canada came up with their unconventional reservoirs which contain bitumen, extra heavy oil and heavy oilas remarkable sources of energy. Exploitation of such kind of reservoirs was not beneficial in the past but in recent years due to the increase of oil price tendency to production from heavy oil reservoirs has incredibly increased. This paper introduces experimental measurement of Athabasca heavy crude oil properties and simulation study in a field conditions. The first-hand target of the performed study isto scrutinize and evaluate the performance and capability of steam-assisted gravity drainage (SAGD) process which is the greatest applicable thermal processes in tar sand reservoirs. The results show great recovery of heavy oil and reasonable amount of cumulative steam-oil ratio (CSOR). Sensitivity analyses have been done to realize the influence of different parameters on proficiencyof SAGD in the field. The significance of parameters such as permeability both in horizontal and vertical direction, horizontal and vertical shale barriers, injection rate, porosity, injector location, viscosity, preheating period, horizontal well length and steam quality were studied. Higher vertical and horizontal permeability, injection rate and steam quality have positive effect on oil production while Lower porosity, absence of preheating period and higher injection rate have adverse effects on SOR. Preheating period has impact on SOR at the start of the process. In fact without preheating period the amount of SOR at the start of process is very high. Horizontal shale barrier has more negative effect on oil production than vertical shale barriers. Locating injector close to the horizontal production well has nugatory impact. The shorter the length of horizontal wells the lower the recovery of oil. This work explains the aforementioned effects in details.

Improvements of Superheated Steam Stimulation in Secondary Development of Heavy Oil Reservoir

With superheated steam, there is no direct relationship between temperature and pressure, Therefore, at a particular pressure it is possible for superheated steam to exist at a wide range of temperatures higher than that of its saturated steam. The heat transfer coefficient is 1/150-1/250 as much as that of saturated steam during heat transferring, and it takes a relatively long time to cool, during which time the steam is releasing very little energy and transmitted long distances. The mechanisms of superheated steam stimulation are mainly pointed to the performance of crude oil viscosity reduced, flow environment improved, rock wettability changed, oil displacement efficiency improved. Physical simulation shows that oil displacement efficiency by superheated steam is 6-12% higher than that of saturated steam at the same temperature, and under the condition of carrying the same heat, superheated steam enlarged the heating radius by about 10m, oil steam ratio increased by 0.7. Superheated steam stimulation was put into Kazakstan’s heavy oil reservoir after two cycles of saturated steam stimulation. The average daily oil production was 2-4 times that of saturated steam stimulation, which improved heavy oil production effectively. The secondary heavy oil thermal recovery by superheated steam stimulation applied in marginal heavy oil reservoirs achieved satisfactory effect.

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.

Optimal Orthogonal Design for Herringbone Wells Injection and Production Parameters of Steam Stimulation in Heavy Oil Reservoir

Herringbone wells can effectively increase the exposed area of oil layer, increase reservoir producing degree, and extend the steam swept volume, ultimately to enhance recovery. The result of steam stimulation depends on injection-production parameters. This paper studies the six injection-production parameters including steam quality, steam injection rate, steam injection pressure, soaking time, cyclic steam injection volume and the maximum lifting rate, and considers the interaction among steam quality, steam injection rate and steam injection pressure. Using visual analysis and variance analysis to analyze the test results, the optimal combination of injection-production parameters were obtained, and the various factors were sorted according to their impact on the cumulative oil steam ratio. Research shows that the impact of interaction is not significant. The results of orthogonal numerical test can provide a theoretical guidance for herringbone wells injection-production parameter analysis optimization of steam stimulation in the field, and also have some practical significance.

Effect of vapour–liquid phase behaviour of steam–light hydrocarbon systems on steam assisted gravity drainage process for bitumen recovery

The vapour–liquid phase behaviour of steam–solvent (light hydrocarbon) systems used in an oil sands recovery process called steam assisted gravity drainage (SAGD) is examined. Analysis shows that condensation occurs over a temperature range and that a concentration gradient exists between the liquid and vapour phases. In a large range of solvent concentrations, water condenses first from the vapour phase. Solvent only condenses first from the vapour phase at extremely high solvent volume fractions. Due to water condensing first at most concentrations, the ability of the solvent to directly contact the bitumen in the reservoir depends on the orientation of the vapour–liquid interface and the relative position in the vapour chamber. Addition of solvent into a mature SAGD operation can also cause a temporary suppression of the steam–oil ratio (SOR) due to the change in the temperature at the vapour–liquid interface. This effect must be taken into account in interpreting experimental or simulation results. The addition of solvent not only changes the temperature but also decreases the heat of condensation of the mixture. As the concentration of solvent changes, the SOR is also expected to change.

DESIGN OF THE INJECTION STRATEGY IN EXPANDING-SOLVENT STEAM-ASSISTED GRAVITY DRAINAGE

Steam-Assisted Gravity Drainage is effective at extracting oil from heavy oil and bitumen reservoirs. However, steam generation by natural gas combustion can render the process uneconomic. It has been suggested that addition of injected solvents improves oil rates or at least maintains similar oil rates with reduced steam. This is the basis of the Expanding Solvent - Steam Assisted Gravity Drainage process. The central idea is that steam plus solvent is better than steam alone to recover heavy oil and bitumen. In this research, the steam and solvent injection strategy is designed by optimizing the cumulative steam-oil ratio by using simulated annealing and a commercial reservoir simulator.

Exploration Method for Extra Heavy Oil Reservoir with Top Water

For an extra heavy oil reservoir with top water in Liaohe Oilfield, it is inefficiently and hard to produce by conventional thermal recovery. In this regard, the numerical modeling software – CMG is used to analyze the recovery of this reservoir by Steam-Assisted Gravity Drainage (SAGD) and Steam and incondensable gas-assisted gravity push (SAGP). The production indicators, development effects and distribution of field parameters of these two techniques are contrasted and analyzed, and the injection and production parameters for application of SAGP in wells are optimized. The study shows that, for this extra heavy oil reservoir with top water, SAGP is more effective than SAGD, and the former can reduce the steam demand, improve the oil/steam ratio (OSR), prolong the development and enhance the recovery. It is recommended, during application of SAGP on site, to inject nitrogen at volume fraction of 30-40% and when the steam chamber expands to a section with 1/3 net pay thickness away to the top water.

Lloydminster, Saskatchewan Vertical Well SAGD Field Test Results

Summary Husky Energy's Pikes Peak steam project has been highly successful using CSS and follow-up steam drive for vertical and directional wells located on the bottomwater-free structural high inside the oil/water contact of the Waseca channel sand reservoir(1). In some areas, recoveries of up to 90% have been achieved with a cumulative steam/oil ratio (SOR) of less than 3.0. Use of CSS with follow-up drive has not been successful where bottomwater is present outside the oil/water contact. Some improvement in performance was achieved using large CSS slugs and high-steam injection rates, but in some locations CSS performances were still poor and conversion from CSS to drive has not been successful in any location. In 2008 Husky initiated a field test of a single vertical well SAGD configuration in an area outside the oil/water contact to evaluate an alternate process in which the "conventional" CSS performance of 10 wells was poor from the second or third stimulation onward. The results from the first single vertical SAGD well pilot demonstrated that a single vertical well SAGD configuration could be successfully completed and operated. The field data are being evaluated using empirical and numerical modelling methods to develop completion and operating strategies that optimize future produced oil rates and SORs. Another benefit of the field test was its demonstration of a low-cost and rapid method to help determine if a reservoir has sufficient vertical permeability for horizontal well SAGD to work.

Advanced Solvent-Additive Processes by Genetic Optimization

Summary This paper describes the application of a genetic algorithm to the development of a solvent-additive SAGD process. A review of related field projects and key simulation studies is provided, together with a discussion of the pros and cons of potential alkane solvents. Economics and the impact of dynamic and ultimate retention are discussed. A general conclusion drawn from literature is that optimal solvent application to SAGD will likely involve time variations in both rate and composition of the solvent. This results in an optimization problem that has a large number of dimensions, and is nonlinear. We have found genetic algorithms, which mimic biological evolution, have been found to be extremely effective in addressing such problems. The general methodology of application to solvent additives by Laricina Energy Ltd. is described. A key product of this effort, optimized for a simple clastic reservoir, is presented. The genetic algorithm produced an operable process, which could be described as a new combination of preexisting concepts. The process offers material improvements in thermal bitumen supply costs, as well as recovery factor. Major reductions in the physical steam/oil ratio (SOR), (and therefore) capital intensity and carbon emissions, are indicated.

Optimization of SAGD Wellbore Completions: Short-Production-TubingString Sensitivities

Summary A simulation study was conducted to examine the effects of changing the landing position of the short production-tubing string relative to the heel of a steam-assisted gravity-drainage (SAGD) production well. A homogeneous discretized wellbore model with the riser section was used in this study. Generally, a reservoir is modeled independently of the wellbore. However, this study models the reservoir and wellbore simultaneously in order to understand their interactions. SAGD performance is affected by many interrelated parameters; however, this paper is focused only on the effects of changing the short production-tubing string relative to the heel of the well. This paper outlines two independent case studies: The first study involves shortening the short production-tubing string relative to the heel of the well. It was found that as the short tubing string was pulled back from the heel of the well, the bitumen-production rate decreased, and the amount of steam produced through the short production-tubing string increased.The second case study outlines the impact of extending the short production-tubing string past the heel of the well on bitumen production and steam/oil ratio (SOR). From this case study, it was found that as the short production-tubing string was pushed past the heel of the well, the bitumen-production rate stayed the same, but the steam-injection rate decreased, which consequently decreased the SOR. It was also observed that a lower pressure differential between the injector and producer well was established when the short production-tubing string was extended. The results for this study will assist SAGD producers in re-evaluating the position of the short production-tubing string and find the most economical position for this string. This paper creates the foundation for further simulation efforts to incorporate a discretized model with the build section coupled to the reservoir. This will allow production engineers to optimize bitumen production by simultaneously simulating the reservoir and wellbore strings together. However, it must be kept in mind that the sensitivity study outlined in this paper only includes different placements of the short production-tubing string while keeping all other parameters constant. More work should be done in order to evaluate the interrelated effects of changing the location of the short production-tubing string with other wellbore and reservoir parameters.

Experimental and Economic Analysis of the Thermal Solvent and Hybrid Solvent Processes

Abstract Several partially scaled laboratory model experiments were conducted to evaluate a hybrid solvent-steam process for recovery of heavy oil or bitumen. All experiments used Athabasca UTF bitumen, and modelled a 30-metre-thick formation. The experiments were compared using a common set of economic assumptions. The experiments showed that a hybrid solvent-steam process could recover bitumen at steam-oil ratios much lower than those observed for steam assisted gravity drainage (SAGD), and achieve reasonable ultimate oil recovery (60% IOIP). The economic analysis based on experiments indicated that a hybrid solvent-steam process could be more cost-effective than SAGD for a 30-m Athabasca formation. Introduction Some heavy oil reservoirs are difficult to produce by cold production. The oil may be immobile at reservoir temperature, or there may be some initial oil mobility and some reservoir drive energy, but the sand strength precludes the production of wormholes. These reservoirs may contain dead oil, as in the case of Athabasca bitumen, or they may have some dissolved gas, as in the case of Cold Lake or Burnt Lake reservoirs. SAGD is the main commercial technology used for in-situ recovery of these oils. Because of the increasing costs for energy (natural gas) and the increasing restrictions on fresh water usage, solvent-based processes (VAPEX, Thermal Solvent, Hybrid Solvent, N-Solv, Savex) have been proposed as alternative technologies for heavy oil and bitumen production. Most of these technologies utilize a pair of horizontal wells, similar to those used in SAGD, but use a gaseous solvent, typically propane, alone or in conjunction with steam, to recover the oil. The VAPEX process may be augmented by adding heat. Heating of a horizontal wellbore will reduce bitumen viscosity sufficiently to produce a large increase in oil production rate. The heat also serves to initiate communication between the injector and the producer. The heat also serves to speed the diffusion of solvent into the oil. The combination of heated wellbores and VAPEX is known as the thermal solvent process.

Unlocking Bitumen in Thin and/or Lower Pressure Pay Using Cross SAGD (XSAGD)

Abstract Cross SAGD (XSAGD) is similar to SAGD except that the horizontal injection wells are placed perpendicular to the horizontal production wells. Some completion restriction near the points where the wells cross can be included in the initial well completions or added later to limit short-circuiting of steam between the wells. The concept of XSAGD as applied in a 20-metrethick homogeneous sand was introduced in the November 2005 International Thermal Operations and Heavy Oil Symposium in Calgary, Alberta. Expanding beyond that presentation, this paper describes simulations showing that XSAGD offers advantages over SAGD for developing thin and/or low-pressured bitumen sands. By combining both gravity drainage and lateral displacement, XSAGD can accelerate recovery, reduce steam requirements and improve economic potential compared to SAGD. Simulation results are discussed comparing SAGD and XSAGD performance for pay thickness from 10 - 40 metres, for pressures ranging from 1,500 - 4,500 kPa, and for homogeneous and heterogeneous pay. Introduction An earlier study(1) describes how XSAGD combines lateral displacement with gravity drainage to accelerate bitumen recovery compared to the SAGD(2) concept in a 20-m homogeneous sand. Some form of completion restriction near where the injection and production wells cross is necessary to limit short-circuiting of the steam and to promote lateral displacement. This restriction could be added after initial communication is established between the wells or it could be built in from the beginning. The recovery acceleration for XSAGD is partially related to the increased drawdown that can be applied to the producing wells while still maintaining effective steam-trap control. This benefit is due to the lateral offset between the active sections of the completions and the tendency for steam to gravity-override before reaching the unrestricted sections of the producing wells. Overall, XSAGD accelerates bitumen recovery and lateral expansion of the steam chamber and reduces cumulative steam oil ratio (CSOR) compared to SAGD. However, XSAGD recovery factor (RF) generally is slightly lower than SAGD RF. The capital costs for wells, pads and facilities should be essentially the same for both processes even though the pad arrangement may be somewhat less flexible for XSAGD.