Cumulative Steam-oil Ratio Research Articles

Productivity analysis by insulation design of well with vacuum insulated tubing in SAGD process

This study aims to design insulation and demonstrate its performance on the vertical section of a well in a steam-assisted gravity drainage (SAGD) process. Utilizing the reservoir characteristics of the Athabasca oil sands in Canada, we analyzed oil productivity and derived optimal operating conditions through a multi-objective optimization algorithm. For the simulation, the well's vertical section was insulated with 0.006 W/m‧°C, the thermal conductivity of vacuum insulated tubing (VIT), exhibiting high insulation efficiency. The results indicated that cumulative production increased by up to 20.24%, and production efficiency improved. Additionally, sensitivity analysis using response surface methodology (RSM) revealed that the injection bottom-hole pressure (inj_BHP) was the most significant factor in the insulated well design when parameters varied. A multi-objective optimization using particle swarm optimization (PSO) was conducted to determine the optimal operating conditions, aiming to maximize cumulative oil production and minimize the cumulative steam-oil ratio (cSOR). The optimization resulted in a 39.8% improvement in cumulative oil production and an 88.19% reduction in cSOR, compared to the non-insulation scenario. The findings of this study are anticipated to serve as a guideline for wellbore insulation design in SAGD processes.

A new pressure control scheme on steam‐assisted gravity drainage for heavy oil production

AbstractAs one the most important recovery mechanisms of steam‐assisted gravity drainage (SAGD), gravity drainage is largely dependent on the inclination angle of the steam chamber edge. The existence of solution‐gas causes an ellipsoid‐shaped chamber that has small inclination angle at the bottom, which leads to inefficient gravity drainage and slows down oil production. To address this problem, this study proposes a new scheme, variable‐pressure SAGD (VP‐SAGD). It is basically a SAGD process, at certain stages of which pressure surge is induced by controlling the operating conditions so that the shape of steam chamber can be altered. This leads to a larger slip angle in the steam chamber at the bottom and more efficient heat transport between hot steam and crude oil. Results show that VP‐SAGD is able to increase oil recovery by up to 20% and decrease cumulative steam–oil ratio (cSOR) by up to 7%. Its special oil extraction mechanisms include swabbing effect, enlarged inclination angle of steam chamber boundary at the bottom, and enhanced heat transfer. Particularly, the inclination angle is increased by up to 40%. In addition, a lower producer bottom‐hole pressure (BHP) during pressure drawdown leads to a better production incremental in later stages. The optimal timing for pressure surge is the middle stage of steam chamber growth. The lower the producer BHP decrease, the better the yield increase. Moreover, The VP‐SAGD strategy works better in heavy oil reservoirs with a permeability of k = 0.5–10 Darcy or solution gas content of greater than 2%.

Data-driven analysis of using flow control devices and extended reach wells on SAGD well performance

The industry's current trend to reduce Capital Expenditures (CapEx) and to minimize the environmental impacts has led to drilling long lateral wells and developing key innovative tools like Flow Control Devices (FCDs). This study analyzed the relative performance of various FCD deployments using data from major Steam-Assisted Gravity Drainage (SAGD) projects in Western Canada, spanning from 1997 to mid-2022. The goal is to investigate the impact of FCD deployment and increasing the lateral length on SAGD well performance in terms of boosting oil produciton and lowering cumulative Steam Oil Ratio (cSOR).This paper utilizes a normalization technique to evaluate the production history of wells, considering geological and operational parameters. Following our confidential conversations with experts in the industry, wells exceeding 850 m in lateral lengths are labeled as “long”, while those below 850 m are labeled as “short”. Eventually, normalized oil production and cSOR for all wells are analyzed. A comparison is made between short and long wells that are completed or retrofitted with FCDs, giving an insight into the role of completion design on the relative performance of SAGD wells.Reservoir thickness and reservoir quality are assessed for each well using contour maps and Gamma Ray (GR) log images. These images are digitized using image processing codes developed in our study. On average, across all projects, wells equipped with FCDs produced up to 52% more normalized oil than those without FCDs, and cSOR decreased to 18%. Long wells, on average, had lateral lengths 38% greater than short wells and produced 18% more normalized oil than all short wells. When comparing long wells with and without FCDs, the normalized oil production is improved by up to 36%, and cSOR is lowered by up to 17%. Furthermore, comparing long wells with FCDs to short wells without FCDs reveals that the normalized oil production is improved by up to 96%, and cSOR is lowered by up to 26%. The results highlight the synergistic benefits of combining longer wells with FCDs to improve normalized oil production and cSOR. The historical production analysis show that installing FCDs is the key enabler and an innovative strategy to increase productivity, reduce cSOR, and make longer wells more productive.The findings indicate that FCDs might increase oil production and decrease cSOR for SAGD well-pad developments, allowing operators to reduce Greenhouse Gas (GHG) emissions intensity. The findings may be used to examine paradigm shifts in the development of heavy oil deposits as technology advances while keeping the project economics into account.

Highly thermoconductive biogel for enhancing thermal efficiency and soil self-remediation in heavy oil recovery

The thermal recovery of heavy oil is an energy-intensive process with serious soil contamination due to its low energy efficiency and refractory petrolic/metallic pollutants emissions. In this work, a thermoconductive lignin-based hydrogel CaLS-CTS/h-BN was designed and synthesized for thermal energy conservation and soil self-remediation in thermal recovery, as a profile-control and oil-displacement agent. From experimental results, with the assistance of CaLS-CTS/h-BN gel, the thermal efficiency and cumulative oil-steam ratio of steam flooding were enlarged by 260% and 293% (up to 41.3% and 0.36), as input energy declined (reduction ratio 84.8%) from 15.08 kJ·(mL oil)−1 to 2.29 kJ·(mL oil)−1, through improving heating profile and strengthening heat transfer. Meanwhile, the rapid biodegradation of CaLS-CTS/h-BN biogel alleviated the formation damage and preserved subsequent productivity. On the other hand, after application of CaLS-CTS/h-BN gel, the natural degradation ratio of petroleum pollutants in soil was increased by 254% up to 46% due to the bio-stimulation and bio-ventilation effect of the biogel. Heavy metal content of oilfield soil was reduced by 35.8 wt% (from 17.3 g·(kg soil)−1 to 10.9 g·(kg soil)−1) with multiple heavy metal contaminants (including Cd, Cr, Cu, Zn, Mn, Pb and Fe) chelated and immobilized by the biogel. This study offered a green adjuvant agent for cleaner production of heavy oil.

The impact of permeability barriers on steam-solvent coinjection – A mechanistic study using a physical model

Coinjection of steam and condensate has been studied for improving the energy efficiency of steam-assisted gravity drainage (SAGD) as solvent-assisted SAGD or SA-SAGD. However, it is not well understood how tortuous hydraulic paths under heterogeneous permeability can influence the compositional and thermal flow characteristics in SA-SAGD. We addressed this question by performing an experiment of the coinjection of steam and condensate for bitumen recovery. This paper discusses the experimental results and gives our mechanistic analysis of how the tortuous hydraulic paths affected the thermal and compositional flow and the properties of the produced bitumen in the experiment.The physical model was a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.2 m, which was filled with unconsolidated sands. Two shale plates were horizontally installed above the well pair at different elevations so that they could represent permeability barriers to cause tortuous flow paths during the SA-SAGD experiment. The porosity and permeability of the sandpack was 0.34 and 5.6 D, respectively. Initially, the oil and water saturations were 95% and 5%, respectively.After preheating for 1 day, a mixture of 98.2 mol% steam and 2.8 mol% condensate was injected at 3500 kPa for 4 days (35 cm3/min of steam, cold water equivalent). The injection and production histories along with the real-time temperature distribution were recorded during the experiment. Produced oil samples were frequently taken and analyzed for density and asphaltene content. After the experiment, the sandpack was excavated and sampled from different locations to analyze the saturation and asphaltene content of the remaining oil. The experimental results in this paper were compared with the previous SAGD and SA-SAGD experiments that used the same experimental set up with a homogeneous sandpack.Results showed that, in comparison to the homogeneous SAGD case, SA-SAGD was able to lower the cumulative steam-oil ratio (SOR) by a factor of two to three even in the presence of shale plates. Analysis of the temperature profiles indicated that the steam chamber vertically expanded from the lower part to the upper part through tortuous paths at lower temperatures. An emerging steam chamber above the shale plates occurred by convective heat from the injection well through lower-temperature flow paths between shale plates, involving light to intermediate solvent components that enabled the steam chamber to expand away from the injection well. This highlights the important role of volatile solvent components in the growth of a steam chamber in SA-SAGD under heterogeneity. The produced bitumen density in this research was closer to the original bitumen than in the homogeneous SA-SAGD case because the bitumen dilution and the solvent retention increased by the tortuous flow regime resulted in efficient drainage of oil at lower temperature.

Improving mining development modelling based on the thermal methods

Introduction. The problem of oil recovery growth and oil reserves management improvement in active oil fields is growing annually. It is possible to increase oil recovery and improve oil reserves management by introducing the thermal methods of oil production. This method was applied at the Yarega oil field. The thermal mining development technology is currently being implemented at the Yarega territory on an industrial scale. Lyael territory is developed by SAGD technology. Heat capacity and thermal conductivity are crucial characteristics of rocks. Reference books and databases lack reliable data on sedimentary rocks thermal properties. The traditional experimental base of thermal petrophysics cannot provide representative information on the thermal properties of rocks, considering rock heterogeneity and anisotropy, various fluid saturation, and pressure and temperature fluctuations. Results. According to special petrophysical studies of the Yarega highly viscous oil field core, ambiguity has been revealed in the thermal properties of rocks, including anisotropy, heat capacity and thermal conductivity. When applying laboratory results in modeling, divergence in oil production and cumulative steam oil ratio can reach 60%. Main ambiguity arising in the course of thermal mine development modeling has been identified. The ambiguity is associated with the account of production for a well, a large number of underground wells, and low reservoir pressure (lower than atmospheric pressure). These problems are successfully solved by specialists of the Yarega field, who maintain highly viscous oil development. At low reservoir pressures, the simulator encounters errors on low pressure values during well operation. Conclusions. At the Yarega field, permanent geological and technological model is currently actively being implemented. It is aimed at solving technological problems of ambiguity in the development of highly viscous oil by thermal methods using advanced software.

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Steam huff and puff has become one of the most widely used technologies to enhance oil recovery during the early phase in heavy oil reservoirs. However, when the development entered in the later phase gradually, the production performance had characteristics with low oil-to-steam ratio and the oil recovery is generally 20–30%. Predecessors usually study a certain follow-up method for a block, and the well pattern is very regular. For the oilfield in the later phase of steam huff and puff, there was a lack of systematic comparison and evaluation with different follow-up methods under irregular well patterns. In this paper, the heavy oil reservoir in block G of Liaohe oilfield was taken as an example. In view of the complex geological conditions and irregular well pattern, the follow-up developing strategies, steam flooding (SF), steam assisted gravity drainage (SAGD) and fire flooding (FF) were compared and evaluated by numerical simulation. A model with seven components and four reactions (used in FF) was established by using STARS module of CMG software. A variety of combined well patterns with vertical and horizontal wells were designed for comparing the production performance. In total, two cases of SF, three cases of SAGD, and two cases of FF were simulated and the oil recovery were studied. The results indicated that these follow-up development methods can enhance oil recovery in different degrees. The combined well pattern with vertical and horizontal wells had a better production performance than that of only vertical wells. In the study, the performance of FF with the horizontal well was the best (oil recovery was 31.7% in the 20th year; cumulative air oil ratio was 3973 m3/m3; final oil recovery was 54.6%), while the SAGD with one horizontal well was the worst (oil recovery was 15.3% in the 20th year; cumulative steam oil ratio was 17.7 t/m3; final oil recovery was 32.6%). Compared with SAGD and FF, the performance of SF was not the best and far from the worst (oil recovery was 40.3% in the 20th year; cumulative steam oil ratio was 12.7 t/m3; final oil recovery was 40.3%). The results show that when the well pattern conditions are complex, the number of wells is large, and the formation is heterogeneous, the SAGD of the vertical and horizontal well combination is obviously affected by the inter well interference. Meanwhile, SAGD production has certain delay and high water cut. It seems that the production performance of SF is not affected by horizontal wells, and the water cut is high. FF with horizontal wells has obvious production performance and can find more uniform formation temperature rise and stable water cut between 0.5 and 0.7.

Investigation of Horizontal Well for Cyclic Steam-Solvent Stimulation to Escalate Heavy Oil Production

Indonesia's oil reserves that have been exploited on a large scale are light oil because the recovery technique is much easier than the heavy oil. Generally, heavy oil has a high viscosity compared to light oil. In most cases, to reduce high oil viscosity (greater than 50 cp) using steam injection. Cyclic steam stimulation (CSS) is one of processes that commercially developed by numerous oil company to producing of heavy oil reservoir. The CSS can apply in vertical well or horizontal well. The research of CSS in horizontal well is still limited reported in the literature. On the other hand, the horizontal well has drainage area more wide compared with vertical well. In this study, solvent addition in cyclic steam stimulation will be tested with reservoir simulation. The steam was injected on the well, after that soaking time and the last was producing of liquid fluid reservoir. As the result, the oil production increases 3 times higher compared to without solvent. Furthermore, cumulative steam oil ratio (CSOR) and cumulative energy oil ratio (CEOS) decrease about 50% and 16%, respectively. In here, effect of solvent added in the steam, the steam distribution and drainage area wider.

Machine-Learning Approach for Forecasting Steam-Assisted Gravity-Drainage Performance in the Presence of Noncondensable Gases.

Steam-assisted gravity drainage (SAGD) is an effective enhanced oil recovery method for heavy oil reservoirs. The addition of certain amounts of noncondensable gases (NCG) may reduce the steam consumption, yet this requires new design-related decisions to be made. In this study, we aimed to develop a machine-learning-based forecasting model that can help in the design of SAGD applications with NCG. Experiments with or without carbon dioxide (CO2) or n-butane (n-C4H10) mixed with steam were performed in a scaled physical model to explore SAGD mechanisms. The model was filled with crushed limestone that was premixed with heavy oil of 12.4° API gravity. Throughout the experiments, temperature, pressure, and production were continuously monitored. The experimental results were used to train neural-network models that can predict oil recovery (%) and cumulative steam–oil ratio (CSOR). The input parameters included injected gas composition, prior saturation with CO2 or n-C4H10, separation between wells, and pore volume injected. Among different neural-network architectures tested, a 3-hidden-layer structure with 40, 30, and 20 neurons was chosen as the forecasting model. The model was able to predict oil recovery and CSOR with R2 values of 0.98 and 0.95, respectively. Variable importance analysis indicated that pore volume injected, distance between wells, and prior CO2 saturation are the most critical parameters that would affect the performance, in agreement with the experiments.

Bitumen Recovery Performance of SAGD and Butane- and Hexane-Aided SAGD in the Presence of Shale Barriers.

Oil and gas formations are commonly found to be heterogeneous, and one of the most common occurrences of reservoir heterogeneity is the presence of shale barriers. Shale barriers typically have very low permeability and high initial water saturation. Due to low permeability, these barriers obstruct the oil drainage path, specifically in thermal recovery methods such as steam-assisted gravity drainage (SAGD). In addition to flow assistance, they also lead to heat losses due to absorption by the high initial water saturation. Expanding solvent steam-assisted gravity drainage (ES-SAGD) is a hybrid technique comprising solvent co-injection along with steam. Solvent being in the vapor phase can potentially overcome the restricted path due to the presence of shale barriers. This paper presents a numerical simulation study on comparison between SAGD and ES-SAGD in the presence of shale barriers. SAGD and ES-SAGD with hexane and butane are numerically simulated for 240 lognormally generated shale realizations. First, both recovery processes are analyzed over the whole simulation period. Additionally, they have also been evaluated at multiple cumulative steam oil ratio cut-offs at 2, 2.5, 3, and 3.5. Transition points are defined and explained to cluster the shale density/fractions based on similar behaviors. It was shown that the oil that cannot be mobilized and produced by SAGD because shale barriers can be reached by the vaporized solvent through tortuous paths and recovered. Also, thermal losses are reduced because of lower steam chamber temperature. This led to efficient results for ES-SAGD over SAGD in heterogeneous formations.

The Adverse Impact of Muddy Laminae on Conventional SAGD Performance and Improvement Strategy with the Multilateral Well Pattern

With further progress of Steam-Assisted Gravity Drainage (SAGD) technology, a growing number of oil sands or heavy oil reservoirs were put into production in an efficient way. However, owing to the existence of muddy laminae within reservoirs, there are challenges associated with the expansion of the steam chamber and oil drainage during the SAGD process. The purpose of this study is to evaluate the adverse impact of muddy laminae on conventional SAGD performance and introduce an improvement strategy with multilateral well patterns to reduce the adverse impact and improve the performance. In the research reported here, the reservoir numerical simulation approach is applied to conduct the research. The analysis conducted on a prototypical reservoir reveals that the steam chamber may expand slowly in some sections due to the poor capacity of heat and mass transfer, and the expansion of the steam chamber is relatively uneven along the wellbore, when the muddy laminae are existing in the formation. The influence level of the muddy laminae on conventional SAGD performance under different distribution modes is different, but the adverse effect is mainly reflected in the delay of peak oil production, the decrease in peak oil production, the decrease in steam chamber volume, and the increase in the cumulative steam oil ratio (mainly in early and middle stages of the SAGD process). On the basis of aforementioned researches, the improvement strategy with two different multilateral well patterns, planar multilateral well and upward multilateral well, is introduced to improve the SAGD performance. The results indicate that the combination of a planar multilateral injector and planar multilateral producer has the best performance. By adopting such kind of combination, the recovery factor can be increased from 31.36% to 47.08%, and the cumulative steam oil ratio can be decreased from 5.29 m3/m3 to 4.64 m3/m3 under the combined distribution mode of muddy laminae. It can be known that the branches of the planar multilateral well are very helpful for the expansion of the steam chamber and oil drainage, once the heat connection between branches of the injector and producer is well established. Overall results show that the multilateral well pattern is promising for SAGD applications at oil sands or heavy oil reservoirs which are rich in muddy laminae.

Analytical modeling of the oil steam ratio during the lifetime steam-assisted gravity drainage process in extra-heavy oil reservoirs

An analytical model to predict the steam oil ratio (SOR) of the steam-assisted gravity drainage (SAGD) process, including the growing up, expanding and depletion of the steam chamber development, is proposed through the use of steam chamber development modes, energy balance, and mass balance. The calculated instantaneous steam oil ratio (ISOR) and cumulative steam oil ratio (ISOR) using the new analytical model are compared and validated with other analytical models results and numerical simulation results. The results showed that the new analytical model can predict the changing of SOR during the lifetime of the SAGD process more accurately than other analytical models. In addition, it had a high agreement with the numerical simulation results. Additionally, the new model could predict more parameters, including water cut, steam quality, heat proportion in different parts of a reservoir than previous models. This model could be a fast-effective guide for the design, prediction, and adjustment of field dual-horizontal SAGD well pairs.

On the optimum operating temperature for steam floods

The technical, environmental and economic performances of a steam flood are partly influenced by the operating temperature (pressure). However, the definition and procedure for determining the optimum operating temperature are still debatable. Employing a combination of analytic modelling and numerical simulations, this paper investigates the existence (or otherwise) of an optimum injection temperature Topt for saturated-steam floods. Considering the maximization of productivity and thermal efficiency as objective, an analytic procedure, which explores the effects of temperature on injectivity, total steam enthalpy, oil viscosity and relative permeabilities, shows that the operating temperature (pressure) of a steam flood should not exceed 515 K (3.5 MPa). A simple closed-form expression is proposed for Topt as a function of basic rock and fluid properties. For an example three-dimensional reservoir model comprising an 8-m oil shale unit sandwiched between two sandy units each 15 m thick, numerical simulations show sensitivity to temperature (and viscosity effect) in the range 350–450 K, but becomes increasingly insensitive in the band 500–650 K. It is established that ~500–550 K is the optimum band when the optimization objective is to maximize both discounted oil recovery and cumulative oil-steam ratio. These results agree with an optimum injection temperature of ~501 K estimated from the proposed analytical model in this case. Therefore, based on the results of the analytical model, thermal simulations and other considerations, it is concluded that the optimum steam-injection temperature is project and system specific. The insights gained should find relevance in the design and management of steam floods, as well as other steam-based recovery processes.

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

A thick oil sands reservoir separated into two thin oil sands reservoirs by a shale barrier, particularly when the separated reservoir thickness is less than 10 m, is inefficient for economic steam-assisted gravity drainage (SAGD) applications. This paper proposes undulating shale breaking with SAGD (UB-SAGD) to develop this type of reservoir, and the trajectory of undulating drilling to break the shale was designed. In addition, sensitivity analysis was performed to evaluate the effects of the area and permeability of a breaking zone and steam injection pressure. The UB-SAGD is a novel in-situ recovery method that applies undulating drilling to break the shale in the parallel direction and the above SAGD well pairs. In addition, it adds an extra injector to facilitate thermal communication between the upper and lower parts of the shale barrier, and the steam chamber can be expanded into the upper the oil sands layer along a flow path. As the area and permeability of the breaking zone were increased, the recovery factor (RF) and maximum NPV (M_NPV) increased, and the cumulative steam-oil ratio (CSOR) decreased. A comparison of the low and high steam injection pressures revealed the M_NPV of high steam injection pressure to be higher than that of low steam injection pressure because a high injection pressure facilitates flow in a smaller area of the breaking zone. The RF and CSOR of best result were improved by 24.65% and 10.21%, respectively, compared to two well-pairs of SAGD without undulating drilling. In addition, the M_NPV of this result was $3.05 MM higher than that of two well-pairs. The UB-SAGD will be very useful for the economic development of shale interbedded oil sands reservoirs using conventional SAGD.

Experiments and analysis on development methods for horizontal well cyclic steam stimulation in heavy oil reservoir with edge water

In the world, the reserves are very huge in heavy oil reservoirs with edge water. Therefore, the effective development of such reservoirs is of great significance for the petroleum supply. In this paper, in order to transfer aquifer energy from actual reservoir to 3D model, a novel method is established based on the elastic principle to achieve simulation of heavy oil reservoir with edge water. Then the oil-water or oil-steam relative permeability curves are measured to analyze flowing characteristics of oil and water under high temperatures. Finally, three kinds of development methods are studied experimentally including the conventional cyclic steam stimulation (CCSS), the water production at oil-water contact (WPOWC) and the water production for post steam stimulation (WPPSS). The results show that the oil viscosity and the water mobility both reduce at higher temperature; moreover, the residual oil saturation decreases but the mobile water saturation increases during temperature rising. For heavy oil reservoirs with edge water, all these characteristics are advantageous to increase oil production and decrease water production. According to the results of 3D experiments, in the process of steam injection, the heating range mainly concentrates near the wellbore and an obvious steam overlap can be observed. The oil recovery factor (ORF) of WPPSS is 8.21%, which is slightly higher than that of CCSS, however the cumulative oil steam ratio (COSR) of WPPSS is 0.96, which is obvious larger than that of CCSS. Comparing the three development methods, for WPPSS method, the same steam injection can make more oil production and the water channeling can be effectively restrained in the late cycle of CSS. The method of WPPSS can be chosen to develop heavy oil reservoirs with edge water.

An efficient optimization framework of cyclic steam stimulation with experimental design in extra heavy oil reservoirs

The Jurassic sandstone reservoir of the Pre-Caspian basin has abundant heavy oil resources. It has characteristics of high porosity, high permeability, shallow depth, and high crude oil viscosity. So the cyclic steam stimulation (CSS) is necessary to produce oil in an effective and economic way. However, the optimization of injection-production parameters for CSS is the premise of the technical strategies and development schemes. The conventional method usually adopts the one-parameter-at-a-time approach to perform sensitivity studies. This method is lack of interactions between different factors and difficult to determine the optimal level, in some situations even the main controlling factor is ignored.In our work, the experimental design method was used to consider the interactions of multiple injection-production parameters. The quantitative ranking of important factors was also determined. Based on geological characteristics and pilot test of the extra heavy oil reservoirs in Mortuk oilfield, the numerical simulation model was established. Firstly the two-level Plackeett-Burman experimental design was used to screen seven injection-production parameters for the CSS process. The first five parameters, the sum of their influencing weight larger than 98%, are steam injection intensity, production liquid rate, production time, steam quality and injection rate, respectively. Then the three-level Box-Behnken experimental design was used to perform optimizing studies. Two regression equations of cumulative oil production and cumulative oil steam ratio (COSR) were obtained on the basis of the response surface method, which fits very well with the numerical simulation results. Finally, the optimal values of uncertain factors were determined to maximize cumulative oil with relatively high COSR. This optimization framework is helpful for petroleum engineers to provide a quick evaluation of CSS.

Positive measure and potential implication for heavy oil recovery of dip reservoir using SAGD based on numerical analysis

To investigate the effect of the formation dip angle on the heavy oil recovery, a numerical model with the formation dip angle was established based on CMG-STARS. Using the numerical model, the steam chamber evolution and the production index were analyzed for the dip reservoir recovery. The results show that: 1) the steam chamber has an obvious asymmetrical distribution on the injection well; 2) the production index of the dip reservoir is lower than the one of the level reservoir. Furthermore, the reason of low production was analyzed from three aspects, namely, the direct reason, the root reason and the intermediate reason. The direct reason is the higher residual oil for the dip reservoir, especially in the downdip zone. The root reasons are the low steam injection amount and the non-uniform distribution of the injected steam. The intermediate reason is that the dip reservoir has a higher cumulative heat loss, especilly in the updip zone. To improve the low production, the well location was optimized as an effective measure, from the perspective of decreasing the area of the downdip zone. Especially, two evaluation objectives were set to determine the reasonable well locations under the dip unknown and the dip angle known. The well location can be reasonable with 10 m away from the center of the reservoir width under the formation dip angle known (8°). Additionally, the optimal matching relation was given between the well location and the formation dip angle, when considering the formation dip angle unknown. Finally, potential implications were obtained as the formation dip angle changing, including: 1) the steam migrates much farther in the updip zone and much nearer in the downdip zone, as the formation dip angle increasing; 2) the cumulative oil production and the cumulative oil-steam ratio show the decreasing trend as the formation dip angle increasing.

A Workflow for Optimization of Flow Control Devices in SAGD

In McMurray Formation, steam assisted gravity drainage is used as the primary in-situ recovery technique to recover oil sands. Different geological reservoir settings and long horizontal wells impose limitations and operational challenges on the implementation of steam-assisted gravity drainage (SAGD). The dual-string tubing system is the conventional completion scheme in SAGD. In complex reservoirs where dual-string completion cannot improve the operation performance, operators have adopted flow control devices (FCDs) to improve project economics. FCDs secure more injection/production points along the horizontal sections of the SAGD well pairs, hence, they maximize ultimate bitumen recovery and minimize cumulative steam-oil ratio (cSOR). This paper will focus on the optimization of outflow control devices (OCDs) in SAGD reservoirs with horizontal wellbore undulations. We present the detailed optimization workflow and show the optimization results for various scenarios with well pair trajectory undulation. Comparing the results of the optimized OCDs case with a dual-string case of the same SAGD model shows improvements in steam distribution, steam chamber growth, bitumen production, and net present value (NPV).

Experimental investigation of nitrogen-assisted SAGD in heavy-oil reservoirs: A two-dimensional visual analysis

Since its initial proposal, steam-assisted gravity drainage (SAGD) has become a key technology of heavy-oil recovery. Due to the large heat loss and high energy consumption in the SAGD process, gas-assisted SAGD is a way to improve the efficiency. In this paper, a two-dimensional (2D) visualization simulation experiment of SAGD is introduced. By adjusting the volume ratio of steam to nitrogen, the proportion for the nitrogen-assisted SAGD process is optimized based on a homogeneous model. The 2D visualization simulation experiment of a heterogeneous model is carried out by adjusting the length of a low-permeability interlayer. The results of the SAGD simulation experiment and nitrogen-assisted SAGD simulation experiment are analyzed. The effect of nitrogen on breaking through and bypassing the low-permeability interlayer is discussed. The experimental results show that the optimal volume ratio of steam to nitrogen is 8:2 in the process of nitrogen-assisted SAGD. At this volume ratio, the sweep efficiency, recovery factor and cumulative oil-steam ratio are the largest, and the recovery factor reaches up to 49.12%. The experimental results for the heterogeneous model with the low-permeability interlayer show that nitrogen can synergistically promote steam to break through the fully occluding interlayer and bypass partially occluding interlayers. Comparing the results of the SAGD simulation with those of the nitrogen-assisted SAGD simulation for the heterogeneous model with the low-permeability interlayer, it is found that the sweep efficiency of steam increases from 34.24% to 43.12%. This result can be explained by the effect of nitrogen on expanding the steam-swept area in the SAGD process and the synergistic action between nitrogen and steam.

Effect of Confinement and Well Interference on SAGD Performance: An Analytical Assessment

Summary In this paper, we introduce, for the first time, an analytical approach for evaluating the effect of confinement and well interference on the SAGD process and achieving a better understanding of the situation. In the well-confinement stage of SAGD, there is adjacent-chamber interference, the effective head of drainage decreases, and the heat-loss rate decreases or, in a conservative design, remains constant. Our objectives were to predict the oil-production rate, steam-injection rate, thermal efficiency, steam-chamber velocity, unsteady temperature profile, heat distribution, and the cumulative steam/oil ratio (CSOR). In this approach, heat transfer was coupled with fluid flow. The governing equations were Darcy's law, volumetric balance, and heat conduction—constitutive equations indicating the temperature dependence of some physical properties. Our model was developed on the basis of a moving-boundary problem. The predicted oil rate remained constant during the sideways-expansion phase, while the steam-injection rate had to be constantly increased. After a determined confinement time, the oil rate started to decline with time because the decreasing steam-chamber interface length was offset by a decreasing head. The unsteady temperature profiles from the model showed that lower temperatures were predicted ahead of the interface owing to the confinement effect. Also, the model showed that, for a small lateral well spacing, confinement occurred earlier and heat loss started decreasing sooner, resulting in a lower CSOR than for a large spacing. It was shown that, even though the oil rate declined faster in a confined model rather than in an unconfined model, the reservoir depleted faster, just like the angle between the steam-chamber interface and the horizon. The results were validated using experimental data reported in the literature.