Steam-assisted Gravity Drainage Performance Research Articles

Significant effect of compositional grading on SAGD performance in a fractured carbonate heavy oil reservoir

In reservoir simulation, the fluid composition is usually assumed uniform for the whole reservoir, while in many reservoirs, oil and gas composition changes with depth. This phenomenon which is known as compositional grading could be significant in heavy and super heavy oil reservoirs. In these reservoirs, biodegradation and asphaltene precipitation are considered as the main reasons behind this phenomenon. Compositional grading in heavy oil reservoirs could affect fluid viscosity and vaporizing–condensing mechanism in steam-assisted gravity drainage (SAGD) operations. In this paper, through a simulation study, one of the Iranian heavy oil reservoirs which have a significant compositional grading was selected to investigate the effect of compositional grading on the performance of simulated SAGD method. The reservoir is a fractured carbonate reservoir, and its compositional grading is maintained because of the lack of convection inside the reservoir. To verify the importance of compositional grading, the performance results of the SAGD method for compositional grading case were compared with that of uniform composition case. The result showed that ignoring compositional grading would lead to underestimation of ultimate recovery in the fractured model. The study of SAGD process in a non-fractured reservoir model showed that considering compositional grading has an insignificant effect on SAGD performance.

Numerical study of herringbone injector-horizontal producer steam assisted gravity drainage (HI-SAGD) for extra-heavy oil recovery

Steam assisted gravity drainage (SAGD) has already been successfully applied in the recovery of extra-heavy oil reservoirs. However, it has been demonstrated that extra-heavy oil above shale barriers is hard to be recovered and SAGD performance is significantly limited. In this study, a novel well pattern called herringbone injector-horizontal producer assisted gravity drainage (HI-SAGD) was proposed to recover the oil above shale barriers. A series of numerical simulations were conducted to investigate the feasibility and operation strategies of HI-SAGD. The mechanisms of applying HI-SAGD to enhance oil recovery were investigated. The sensitivities of shale barrier characteristics and branches of the herringbone injector were analyzed. The results from numerical simulations show that conducting HI-SAGD with appropriate strategies can significantly improve performance. The necessary start-up strategy is to conduct two cycles of cyclic steam stimulation (CSS) after steam circulation. Thus, oil above the shale barrier can be recovered. Higher oil rate can be achieved in the early stage of the process, and oil recovery factor is improved. Field application and numerical simulations show that HI-SAGD is a promising technology for the recovery of extra-heavy oil reservoirs, especially with shale barriers above the injector.

Organic bases as additives for steam-assisted gravity drainage

Steam-assisted gravity drainage (SAGD) is a mature technology for bitumen recovery from oil sands. However, it is an energy-intensive process that requires large amounts of steam to heat and mobilize bitumen. The purpose of this work is to develop ways to enhance SAGD performance through the use of organic base additives. The research is approached from three focus areas that supplement and guide each other: characterization tests, sand-pack floods, and computational simulation. A number of key mechanisms for enhancing oil recovery were identified, high-temperature additive characterization tests were developed, and promising alkalis were tested in porous media. Simulation was employed to history-match sand-pack flood production data, in order to demonstrate the effect of an additive on the oil–water relative permeability. Based on these results, it was concluded that oxygenated organic bases had the most potential for improving bitumen recovery through reducing the oil–water interfacial tension (IFT) by increasing the pH of the system. These organic bases favorably modify the interfacial energies between the immiscible oil–water phases and enable them to flow easily through the porous media during production. Sand-pack flood tests have successfully demonstrated a 10%–15% improvement in bitumen recovery, over baseline, in the presence of IFT-reducing additives. Simulation results further showed that an IFT reduction had a positive impact on SAGD performance. This work demonstrates the potential of organic bases to improve not only SAGD, but other steam injection processes. Furthermore, a number of experimental methods were developed, tried, and tested during the course of this work.

Determination of binary diffusion coefficients between hot liquid solvents and bitumen with X-ray CT

Abstract The Steam Assisted Gravity Drainage (SAGD) process has been used for in-situ thermal bitumen recovery in Canada. Nevertheless, there are several drawbacks that could impair the SAGD performance. One of the main drawbacks of SAGD is nontrivial consumption of energy to generate steam. To curtail the consumption of steam, many SAGD variants have been proposed. For example, Vapor Extraction (VAPEX) was proposed as a solvent-based cold production method and Solvent-Assisted SAGD (SA-SAGD) was proposed as a solvent-assisted hybrid method. In those solvent-based/assisted methods, the dissolution of solvents in bitumen enhances the in-situ oil mobility. The speed of the mixing between solvents and bitumen in solvent-based/assisted recovery processes is dictated by dispersive mass flux which is proportional to the transverse dispersion coefficient. Diffusion coefficient, tortuosity and transverse dispersivity should be quantified to characterize the transverse dispersion coefficient. In this research, the diffusion coefficients of solvents in Athabasca bitumen were determined with X-ray computed tomography (CT). A medical X-ray CT scanner was used to capture the diffusion phenomenon occurring between fresh liquid solvents and bitumen. The experiments were designed to reproduce the in-situ high pressure, high temperature condition (3.5 MPa, 135C) where solvent and bitumen actually interact at the vapor chamber edge in the SA-SAGD process. Using our new °experimental system, we successfully measured molecular diffusion coefficients at the condition of the vapor chamber edge for the first time. In conclusion, the binary diffusion coefficients between solvents and bitumen were successfully measured at the condition where the mixing of solvents and bitumen actually occurs in the SA-SAGD process. The characterized diffusion coefficients will be input parameters for the reservoir simulation and semi-analytical models.

Performance and Economic Analysis of SAGD and VAPEX Recovery Processes

Heavy oil has attracted global attention because of its significant volume of original oil in place. However, there are several economic and operational challenges associated with heavy oil recovery due to its high viscosity and high density. Recently, steam-assisted gravity drainage (SAGD) and solvent vapor extraction (VAPEX) recovery processes have been introduced to enhance heavy oil recovery. Although SAGD recovery process achieves high oil recovery, many drawbacks are related to this process, such as produced water treatment and huge amount of water and energy required to generate steam which leads to significant CO $$_{2 }$$ emissions. On the other hand, VAPEX recovery process has many challenges such as low production rates and potential sensitivity to reservoir heterogeneity. The drawbacks of SAGD could minimize its economic profitability compared to VAPEX process. Therefore, the objective of this work is to model and evaluate the two recovery methods from the economic point of view and based on the achieved net present value (NPV). Several sensitivity studies are applied on SAGD and VAPEX to analyze the effect of different operation parameters and different reservoir conditions. The effects of aquifer and initial oil viscosity on the recovery performance of SAGD and VAPEX are analyzed. In all the cases considered, VAPEX achieved higher NPV than SAGD by at least 70%, although SAGD has higher oil recovery factor. This research shows and confirms that VAPEX is more economic profitable recovery method and it is a step forward to eliminate CO $$_{2}$$ emissions associated with thermal recovery process.

Experimental and numerical simulation studies on effects of viscosity reducers for steam assisted gravity drainage performances in extra-heavy oil reservoirs

Steam-Assisted Gravity Drainage (SAGD) has been demonstrated as an effective process for recovering extra-heavy oil. However, large volumes of steam are required to heat the viscous oil, resulting in high consumption of natural gas and water, which affects its economic benefit. Therefore, research has long focused on improving the SAGD performance. In this study, a viscosity reducer (VR) assisted SAGD (VR-SAGD) process is systematically examined by experiment and numerical simulations based on an extra-heavy oil sample from a commercial SAGD block in Xinjiang oil fields, China. A scaled two-dimensional (2D) VR-SAGD experiment is carried out using a scale model to study the mechanisms of production dynamics and to observe the steam chamber development phases of the VR-SAGD process. A history match is conducted based on the 2D experimental data, and the recovery mechanisms of VR-SAGD are discussed. Heterogeneity in terms of barriers sandwiched in the pay zone is studied, and operational parameters are optimized based on the history match results. The 2D physical simulation results show that VR-SAGD accelerates the oil rate by a factor of 1.74 and reduces the instantaneous steam-to-oil-ratio by 49.7%. The VR co-injected with steam propagates in advance and accumulates at the front of the steam chamber and around the barriers to accelerate the effect of viscosity-reduction and reduce the heat loss to the overburden. Numerical simulation results indicate that the optimum time for VR injection is during and after the phase when the steam chamber expands sideways. The optimized VR/steam volume ratio and production/injection volume ratio are 1:9 and 1.2:1, respectively. The VR-SAGD process shows good potential to improve post-SAGD performance and reduces steam consumption in extra-heavy oil reservoirs.

Analytical modelling of steam chamber rise stage of Steam-Assisted Gravity Drainage (SAGD) process

When steam is injected continuously in a SAGD operation, a steam chamber starts to develop in three stages; rise, lateral spreading and confinement, as observed in the field and laboratory experiments. The physics of chamber development in the first and the two last stages is different and thus modelled separately. Nearly all of the available theoretical analyses of SAGD are concerned with the lateral spreading stage of the steam chamber development with the exception of a few works which aim to determine rise velocity and oil rate. The rate of the upward growth of the steam chamber has a profound effect on the SAGD performance, because as the chamber reaches the top of the reservoir heat loss starts to play a significant role in the thermal efficiency of the process.During the rise period, as the steam chamber grows upwards, oil drains downwards and so the process at this stage must account for to the frontal instability between steam and the liquid phases in the system. Stability is affected by factors such as the flow direction, gravity, and viscosity difference between gas/steam and liquid phases. Steam condensation, on the other hand, has a stabilizing effect.In the present model, the rise velocity and the steam chamber height were calculated by combining volumetric oil displacement with Darcy oil rate considering the indirect effect of frontal instability. The model is extended to predict oil production, heat or steam injection rate, heat consumption and CSOR during this phase. Moreover, estimates of injected steam sweep efficiency and the angle between the steam chamber and the horizon are achieved. The model results show an increase in rise velocity with temperature and permeability. Also, the calculated oil production rate increases and Cumulative Steam Oil Ratio (CSOR) declines with time. This theory is tested via comparison with several field data sets to show the adequacy of the model.

Experimental study on viscosity reducers for SAGD in developing extra-heavy oil reservoirs

Steam assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 °C and is still effective after high-temperature and high-pressure (200 °C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil reservoirs.

Investigation of initial water mobility on steam-assisted gravity drainage performance using a two-dimensional physical model

Steam-assisted gravity drainage (SAGD) has become a primary commercial in-situ recovery method for oil sands in Alberta, Canada. Industrial field studies have found that the initial water mobility in oil sands has an impact on the SAGD process. However, no experimental research has been conducted to investigate such effects on SAGD performance. In this study, a novel two-dimensional (2-D) physical model with a water-flow boundary is designed for the first time to simulate the flow of initial water in oil sands during the SAGD process. The model investigates the impact of initial water mobility on the steam chamber shape and captures the growth of the steam chamber at different times. The experimental results show that low initial water mobility can promote vertical and lateral growth of the steam chamber, compared to immobile initial water, while high initial water mobility results in accelerated vertical expansion of the steam chamber in the SAGD process. The oil recovery in the scenario of low initial water mobility is 6.6% higher than that of immobile initial water scenario, and is 12.6% higher than that of high initial water mobility scenario. Subsequently, the numerical simulation study for the experiments is conducted in order to acquire insight into the effects of initial water mobility on SAGD performance. Results show that initial water mobility has a great influence on water movement profiles and water distribution along the steam chamber boundary in the SAGD process.

Evolution characteristics of SAGD steam chamber and its impacts on heavy oil production and heat consumption

Currently, Steam-Assisted Gravity Drainage (SAGD) is the most successful commercialized method used to produce bitumen from oil sands and heavy oil reservoirs. Precise description of the steam chamber evolution is important for evaluating the economic effectiveness and Greenhouse Gas (GHG) emission of the SAGD process. In this study, the properties of MacKay River Oil Sands were used in laboratory experiments to compare the chamber evolution and production performance of SAGD under different permeability distributions. Then, a mathematical model was established to predict the steam chamber evolution and the closely related oil production and heat consumption in a heterogeneous formation. Next, the calculated production performance and steam chamber evolution were compared with measured experimental data to verify the accuracy of the model. Finally, the chamber evolution characteristics and their impacts on SAGD oil production and heat consumption are discussed in this paper for formations with different permeability distributions. The results indicate that horizontal permeability controls the evolution of steam chamber such that higher horizontal permeability may cause an obvious convex shape of the chamber edge, whereas vertical permeability has little effect on the chamber shape despite significant influence on the oil production in the early stage of SAGD. Moreover, a convex-shaped chamber interface indicates a higher production rate in the spreading stage and a lower rate in the depleting stage. In addition, this study shows that to minimize the heat consumption of the SAGD process, so that GHG emission can be curbed, a concave-like chamber shape is favorable in the early spreading stage, whereas a convex shape is better in the late spreading stage and depleting stage.

In–Situ Dilation Affects Solvent–Assisted Steam–Assisted–Gravity–Drainage Performance: The Case of a Shallow Athabasca–Type Oil–Sands Reservoir

Summary It is generally accepted that solvent/steam injection in heavy-oil/bitumen reservoirs outperforms steam-only injection in terms of oil-recovery rate, ultimate oil recovery, and steam/oil ratio (SOR). Important parameters in the design of solvent-assisted steam-assisted-gravity-drainage (SA-SAGD) are solvent selection, injection strategy, and solvent retention in situ. The role of geomechanics in optimal application of SA-SAGD, however, remains largely unexplored. Recent studies suggest that solvent transport, solvent-dilution effect, and the temperature distribution around the edge of the steam chamber have major control over SA-SAGD performance. In SA-SAGD, elevated temperature and solvent concentrations within a few meters of the steam-chamber edge reduce the virgin-oil viscosity, causing oil drainage. However, this is the same region where geomechanically induced volume changes alter porosity, permeability, and relative permeability profiles. These alterations could improve the convective-heat transfer and solvent dispersion into the cold bitumen zone, and could also enhance the drainage rate. Consequently, the solvent/oil-phase behavior, steam-chamber growth, and solvent retention and distribution will be affected. This chain of events could have an effect on optimal solvent selection and solvent/steam-injection scenarios. These geomechanical considerations are of particular interest for bitumen deposits, both oil sands and carbonates, where chemical, thermal, and fluid pressures can impose significant volume changes within the reservoir, especially in shallower, lower-confining-stress settings. The role of geomechanics in SA-SAGD was explored numerically by use of a sequentially coupled modeling approach with STARS (CMG 2015a) and FLAC (Itasca 2016). A 2D shallow-depth homogeneous-oil-sands-reservoir geomodel, with properties similar to the Underground Test Facility (UTF) Phase A project, was constructed (Edmunds et al. 1994). Studies were conducted at two scales: the edge of the steam chamber and the reservoir scale including underburden and overburden. The results of these numerical studies revealed that geomechanics considerations directly affect the optimal solvent-type selection and injection strategy during a high-pressure SA-SAGD process. These studies provide valuable direction for further detailed mechanistic studies (both numerically and experimentally) and provide valuable input to the challenges of optimizing SA-SAGD processes in oil sands.

Correlating Stochastically Distributed Reservoir Heterogeneities with Steam-Assisted Gravity Drainage Production

Application of big data analytics in reservoir engineering has gained wide attention in recent years. However, designing practical data-driven models for correlating petrophysical measurements and Steam-Assisted Gravity Drainage (SAGD) production profiles using actual field data remains difficult. Parameterization of the complex reservoir heterogeneities in these reservoirs is not trivial. In this study, a set of attributes pertinent to characterizing stochastic distributions of shales and lean zones is formulated and used for correlating against a number of production performance measures. A comprehensive investigation of the heterogeneous distribution (continuity, size, proportions, permeability, location, orientation and saturation) of shale barriers and lean zones is presented. First, a series of two-dimensional SAGD models based on typical Athabasca oil reservoir properties and operating conditions are constructed. Geostatistical techniques are applied to stochastically model shale barriers, which are imbedded in a region of degraded rock properties referred to as Low-Quality Sand or LQS, among a background of clean sand. Parameters including correlation lengths, orientation, proportions and permeability anisotropy of the different rock facies are varied. Within each facies, spatial variations in water saturation are modeled probabilistically. In contrast to many previous simulation studies, representative multiphase flow functions and capillarity models are assigned in accordance to individual facies. A set of input attributes based on facies proportions and dimensionless correlation lengths are formulated. Next, to facilitate the assessment of different scenarios, production performance is quantified by numerous dimensionless output attributes defined from recovery factor and steam-to-oil ratio profiles. An additional dimensionless indicator is implemented to capture the production time during which the instantaneous steam-to-oil ratio has exceeded a particular economic threshold. Finally, results of the sensitivity analysis are employed as training and testing datasets in a series of neural network models to correlate the pertinent system attributes and the production performance measures. These models are also used to assess the consequences of ignoring lateral variation of heterogeneities when extracting petrophysical (log) data from vertical delineation wells alone. An important contribution of this work is that it proposes a set of input attributes for correlating reservoir heterogeneity introduced by shale barriers and lean zones to SAGD production performance. It demonstrates that these input attributes, which can be extracted from petrophysical logs, are highly correlated with the ensuing recovery response and heat loss. This work also exemplifies the feasibility and utility of data-driven models in correlating SAGD performance. Furthermore, the proposed set of system variables and modeling approach can be applied directly in field-data analysis and scale-up study of experimental models to assist field-operation design and evaluation.

Experimental study and numerical simulation of nitrogen-assisted SAGD in developing heavy oil reservoirs

The presence of significant amounts of injected steam and heat loss are unavoidable issues occurred that are observed during the steam-assisted gravity drainage (SAGD) process in developing heavy oil reservoirs. Because of these limitations and concerns, non-condensable gas co-injection has become a potential technique to enhancing oil recovery and reducing energy consumption. However, the oil production mechanism is complicated and has not been totally understood, thereby requiring further discussion. In this work, a two-dimensional physical model was designed to investigate the production mechanisms of nitrogen on SAGD. Two comparative injection schemes, specifically the conventional SAGD and nitrogen assisted SAGD (NA-SAGD), were conducted to investigate the effect of nitrogen co-injection with steam on the SAGD performance. Dynamic temperature profile changes during the two experiment processes were monitored and recorded. The observation results indicate that nitrogen accumulation at the upper part of the model resulted in the effective expansion of the NA-SAGD process steam chamber along the horizontal direction. The swept area of steam increased significantly and the residual oil saturation was reduced. The cumulative oil production of NA-SAGD was higher than that of the conventional SAGD. Moreover, the apparent heat loss reduction, which defines the heat utilization efficiency, exhibited an increase following nitrogen injection. In addition, a numerical simulation was generated to compare and verify the results obtained in the two experiments. Nitrogen co-injection with steam effectively enhanced the oil recovery. Studies indicate that NA-SAGD is a feasible method for improving oil production in developing heavy oil reservoirs.

Numerical Simulation Study on Steam-Assisted Gravity Drainage Performance in a Heavy Oil Reservoir with a Bottom Water Zone

In the Pikes Peak oil field near Lloydminster, Canada, a significant amount of heavy oil reserves is located in reservoirs with a bottom water zone. The properties of the bottom water zone and the operation parameters significantly affect oil production performance via the steam-assisted gravity drainage (SAGD) process. Thus, in order to develop this type of heavy oil resource, a full understanding of the effects of these properties is necessary. In this study, the numerical simulation approach was applied to study the effects of properties in the bottom water zone in the SAGD process, such as the initial gas oil ratio, the thickness of the reservoir, and oil saturation of the bottom water zone. In addition, some operation parameters were studied including the injection pressure, the SAGD well pair location, and five different well patterns: (1) two corner wells, (2) triple wells, (3) downhole water sink well, (4) vertical injectors with a horizontal producer, and (5) fishbone well. The numerical simulation results suggest that the properties of the bottom water zone affect production performance extremely. First, both positive and negative effects were observed when solution gas exists in the heavy oil. Second, a logarithmical relationship was investigated between the bottom water production ratio and the thickness of the bottom water zone. Third, a non-linear relation was obtained between the oil recovery factor and oil saturation in the bottom water zone, and a peak oil recovery was achieved at the oil saturation rate of 30% in the bottom water zone. Furthermore, the operation parameters affected the heavy oil production performance. Comparison of the well patterns showed that the two corner wells and the triple wells patterns obtained the highest oil recovery factors of 74.71% and 77.19%, respectively, which are almost twice the oil recovery factors gained in the conventional SAGD process (47.84%). This indicates that the optimized SAGD process with the two corner wells and the triple wells pattern is able to improve SAGD production performance in a heavy oil reservoir with a bottom water zone.

Novel insights on the impact of top water on Steam-Assisted Gravity Drainage in a point bar reservoir

Summary As efforts are made to efficiently exploit and recover bitumen resources in Canada, increasingly more complex reservoirs in the Athabasca area continue to challenge the application of Steam-Assisted Gravity Drainage (SAGD) technology. Several studies have been done to investigate the impact of heterogeneities/complexities such as shale barriers, lean zones, and top and bottom water on the performance of the SAGD process. However, the literature is deficient for point bar deposits with top water zones, a common occurrence in oil sands systems. This study, by using thermal reservoir simulation, examines SAGD performance in a point bar deposit reservoir where an overlying top water and an inclined heterolithic strata (IHS) is present. The results show that where the top water is unconfined and steam injection pressure is higher than that of the top water zone, there is a loss of thermal energy, but the top water does not impact steam chamber development. At steam injection pressure lower than that of the top water zone, top water continuously drains into the reservoir and constrains the size of the chamber. However, the IHS zone helps to delay drainage of the top water into the chamber when steam is injected at underbalanced conditions. Finally, under proper steam injection pressure conditions, top water production can be considerably delayed.

Microfluidic pore-scale comparison of alcohol- and alkaline-based SAGD processes

Steam assisted gravity drainage (SAGD) is the established method for in situ bitumen extraction. However, natural gas powered generation of steam for the SAGD process results in large economic and environmental costs. Alcohol- and alkaline-based additives are emerging strategies to improve SAGD performance, and micromodels are uniquely well-suited to directly compare and quantify the effectiveness of additives with all other variables tightly controlled. The distinct effects of alcohol- and alkaline-based additives on the pore-scale mechanisms were quantified here using a representative high-pressure high-temperature glass micromodel with both optical and thermal imagings (P=0.7 and 1.3MPa; T=180 and 200°C). Alcohol addition resulted in viscous fingering, some solvency, oil-wet trapping in the mobile zone, mainly water-in-oil emulsions, and moderate increases in production. In contrast, alkaline addition resulted in water-wet surface condition, emulsification of the bitumen into discrete oil-in-water droplets, and significantly increased production. Temperature profile data combined with optical results were also used to accurately determine the interface and expansion of discrete regions formed during the SAGD including steam chamber, hot water flow zone, mobile zone, and untouched bitumen zone. Alcohol provided only a slight improvement on the steam chamber growth, while alkaline additive expanded the steam chamber by over 10% and significantly improved the overall recovery.

Effects of Lean Zones on Steam-Assisted Gravity Drainage Performance

A thorough understanding of the effects of lean zones and the improvement of steam-assisted gravity drainage (SAGD) operations with such heterogeneities is critically important for reducing the disadvantages of lean zones. The numerical model shows: (1) SAGD is most influenced by the single-layer lean zone with the above-injector (AI) location; with the decrease of interval distance and increase of thickness and water saturation in lean zones, the detrimental effect of single-layer lean zones on SAGD performance increases; (2) with the increase of period and decrease of connate and initial water saturations in lean zones, the detrimental effect of multiple-layer lean zones on SAGD performance increases; (3) reducing the injection pressure properly improves SAGD performance in leaky oil sands. The field-scale study indicates: (1) well pair 1 is most affected by lean zones in the studied pad due to the widest distribution of lean zones above its injector, and a hybrid cyclic steam stimulation (CSS)/SAGD method is proposed to overcome the practical problem of a low injection pressure in this area; (2) simulation results prove that the hybrid CSS/SAGD method is better than the conventional SAGD method in leaky oil sands.

Optimal parameters selection for SAGD and VAPEX processes

Steam Assisted Gravity Drainage (SAGD) and Solvent Vapor Extraction (VAPEX), both of the techniques have been proved to be successful for the exploitation of heavy oil reservoirs. Field development of heavy oil reservoirs requires careful determination of optimal parameters, well locations and control setting of producers and injectors. In recent years, field development decisions based on sensitivity studies have been shifting toward automated optimization. In this paper, we present the optimal parameter selection for SAGD and VAPEX. We performed the search of optimum parameters; the vertical separation between injector and producer, well controls and well locations. All these parameters have been simultaneously optimized to study and compare the performance of both processes. Also, we present an efficient method to constrain horizontal wells to preset minimum well spacing constraints. This method was then applied to constrain the well spacing between different peers of horizontal wells in the SAGD and VAPEX processes. The particle swarm optimization was used as an optimizer to determine the optimum parameters. The results indicated that the method could successfully determine the optimal parameters while satisfying the spacing constraint imposed by the user. The comparison of the results showed the better performance of SAGD over VAPEX process.

A combined method for pore-scale optical and thermal characterization of SAGD

Steam-assisted gravity drainage (SAGD) is an important oil recovery strategy for extra heavy oil and bitumen. Operators are under pressure to improve both the environmental and economic performance of SAGD. Through direct visualization, micromodels provide insight into SAGD, but methods to date cannot fully resolve the temperature field which is essential to this thermal recovery process. In this work, infrared and optical pore-scale imaging of the SAGD process within a micromodel with reservoir-relevant pore geometries, fluids, and temperatures was performed, and both recovery and pore-scale fluid behavior was quantified for different concentrations of alkaline additive. Combined microscale flow and high-resolution temperature analysis provide insight into pore-scale phenomena, and shed light on the link between the rapid temperature drop at the steam chamber interface, drainage modes, efficiency and ultimate recovery achieved in SAGD.

Improving Steam-Assisted Gravity Drainage performance in oil sands with a top water zone using polymer injection and the fishbone well pattern

In western Canada, a significant number of oil sands reserves have little or no cap rock with a top water zone. Due to huge heat loss to the top water zone, the conventional Steam-Assisted Gravity Drainage (SAGD) process is uneconomical when applied directly in this type of reservoir.In this study, it is proposed that a high temperature polymer solution can be injected into the bottom of the top water zone to establish a stable high viscosity layer that will prevent steam from leaking into the top water zone. In order to select a suitable polymer that has stable viscosity under high temperature, the viscosities of different polymer solutions at different temperatures were measured and the concentration of the selected polymer solution was optimized. Furthermore, in order to extend the connection area between the oil sands and the steam chamber, the fishbone well pattern was applied instead of the single well pair pattern.Numerical simulations were performed to evaluate the feasibility of using the selected polymer in the fishbone well pattern to improve SAGD performance in oil sands with a top water zone. The numerical simulation model was based on a typical Athabasca oil sands reservoir. In this study, the effects of steam injection pressure, polymer solution injection time, steam injection rate, and different fishbone well patterns on the performance of the SAGD process were studied and optimized.The numerical simulation results suggest that the fishbone well pattern could extend the steam distribution and that polymer injection is able to prevent heat from leaking into the top water zone. Compared to the conventional SAGD process in an oil sands reservoir with a top water zone, the optimal case using a one-fishbone well pattern and polymer injection could enhance the oil production significantly. Under these conditions, the oil recovery factor in this study increased from 10.58% to 59.02%; the cumulative steam oil ratio decreased from 10.44m3/m3 to 3.85m3/m3; and the cumulative injected energy oil ratio decreased from 24.00GJ/m3 to 8.87GJ/m3. This indicates that the SAGD process with the one-fishbone well pattern and polymer injection is able to improve SAGD performance in oil sands with a top water zone.