SAGD Performance Research Articles

Correlations between Geomechanical Effects, SAGD Performance, and Reservoir Conditions in SAGD Operations in Alberta, Canada

Correlations between Geomechanical Effects, SAGD Performance, and Reservoir Conditions in SAGD Operations in Alberta, Canada

Field-scale SAGD Performance Evaluation Utilizing Homogeneous Reservoir Model Based on Vertical Wells

Field-scale SAGD Performance Evaluation Utilizing Homogeneous Reservoir Model Based on Vertical Wells

Feature Engineering Process on Well Log Data for Machine Learning-Based Sagd Performance Prediction

Feature Engineering Process on Well Log Data for Machine Learning-Based Sagd Performance Prediction

Breccia interlayer effects on steam-assisted gravity drainage performance: experimental and numerical study

Currently, the reservoir heterogeneity is a serious challenge for developing oil sands with SAGD method. Nexen’s Long Lake SAGD project reported that breccia interlayer was widely distributed in lower and middle part of reservoir, impeding the steam chamber expansion and heated oil drainage. In this paper, two physical experiments were conducted to study the impact of breccia interlayer on development of steam chamber and production performance. Then, a laboratory scale numerical simulation model was established and a history match was conducted based on the 3D experimental results. Finally, the sensitivity analysis of thickness and permeability of breccia layer was performed. The influence mechanism of breccia layer on SAGD performance was analyzed by comparing the temperature profile of steam chamber and production dynamics. The experimental results indicate that the existence of breccia interlayer causes a thinner steam chamber profile and longer time to reach the peak oil rate. And, the ultimate oil recovery reduced 15.8% due to much oil stuck in breccia interlayer areas. The numerical simulation results show that a lower permeability in breccia layer area has a serious adverse impact on oil recovery if the thickness of breccia layer is larger, whereas the effect of permeability on SAGD performance is limited when the breccia layer is thinner. Besides, a thicker breccia layer can increase the time required to reach the peak oil rate, but has a little impact on the ultimate oil recovery.

Prediction of top water flow rate to SAGD steam chamber and its impact on thermal efficiency

The Guantao Formation in the Block Du 84 of the Liaohe Oilfield of Northeastern China is a super heavy oil reservoir surrounded by top water, side and bottom water. Commercial development started in 1999 using vertical well Cyclic Steam Stimulation (CSS), with anticipated oil recovery factor of less than 25%. To improve the ultimate oil recovery, a pilot test of SAGD as a follow-up to CSS began in 2005 using a combination of infill horizontal wells with existing vertical wells; and the commercial expansion began in 2008 as a result of the encouraging results from pilot test. The current recovery factor over the entire development area has exceeded 45% of OOIP, with the pilot test area exceeding 68% of OOIP, and the ultimate recovery factor is predicted to exceed 70%. As the steam chamber becomes more mature and continues expanding upward, the risk of communication with the top water increases. Due to high pressure (>6.0 MPa) in the top water layer, it is not practical to balance the operating pressure in the steam chamber under the current economic conditions. The early forecasting of top water flow rates is important to assess its potential impact on SAGD performance and to formulate operating strategies for the late stage of SAGD development. In this paper, a theoretical model for predicting flow rate of top water to the SAGD chamber is established based on the incorporation of fluid flow and heat transfer mechanisms in porous media in the reservoir (barrier layer) between the steam chamber and the top water. The influence of barrier layer thickness, permeability, crude oil viscosity distribution and operating pressures in the steam chamber on the flow rate of the top water are studied. The flow of the top water into the steam chamber will lower oil to steam ratio (OSR) and the recovery process may become uneconomic when top water flow rate exceeds the current steam injection rate per well pair. The presence of high-viscosity “asphalt shell” layers near the bottom of the top water has limited mitigation effect on the flow of the top water. Under current operating conditions and 3.0 MPa pressure differential between the top water layer and steam chamber, 10 m of minimum thickness of barrier layer should be maintained to effectively mitigate the risk from inflow of top water.

Top lean zone and cardinal parameters affecting SAGD

SAGD is a thermal recovery process in which steam oil ratio, SOR, is a key parameter that can affect the economic outcome of the process. Reservoirs with underlying or overlying lean bitumen present challenges for SAGD as they can act as a heat sink. Water has higher heat capacity than the bitumen and thus requires more steam to heat up the reservoir leading to higher SOR. The potential outcome of operating SAGD in these conditions may be lower bitumen rate and higher steam injection rate, both of which affect plant throughput and thus the economic matrix of SAGD.This paper looks at the performance of SAGD process in the presence of top lean bitumen. It will examine the theoretical CSOR that is needed to produce the bitumen with different water saturations and will highlight the key parameters of lean bitumen affecting SAGD performance. The paper reviews performance of several fields where lean bitumen is present. The paper also analyzes simulation results to examine the impact of water saturation and the size of lean bitumen resource on the SAGD process.

Investigation of EOR mechanism for flue gas assisted SAGD

As a promising technique, flue gas assisted SAGD can not only reduce greenhouse gas emission but also increase economic benefits. However, the role that flue gas plays in flue gas assisted SAGD is still not very clear. Here, 2D visualization SAGD and condensation heat transfer (CHT) experiment were conducted, where temperature profiles can be measured and steam chamber can be observed simultaneously, to study systematically the effect of flue gas on SAGD performance and the EOR mechanisms of flue gas assisted SAGD. The experimental results showed the steam chamber development of flue gas assisted SAGD went through three stages: early fast growth stage, secondary upward growth stage, and slow lateral expansion stage. The injection of flue gas prolonged the high production period and increased the oil recovery by 23%. Flue gas can decrease the CHT coefficient and transform the condensation pattern from “drop condensation” to “film condensation”, which was the dominant mechanism to improve SAGD performance and the reason of the formation for secondary upward growth stage of steam chamber. Moreover, CHT coefficient decreased as flue gas water ratio increased. Besides, gas cap assisted residual oil downward and lateral expansion, as well as steam flow resistance reduction owing to gas fingering were two other crucial aspects improving SAGD performance.

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.

A visualization experimental study on gas penetration through interlayer to improve SAGD performance

Abstract Low-permeability interlayer is common in reservoir, which can hinder the steam chamber expansion and the gravity drainage in SAGD. It is crucial to find an economical and practicable method to promote the steam chamber to break through the interlayer. In this work, four condensation heat transfer experiments were conducted to investigate the effect of flue gas on steam condensation heat transfer. On this basis, 2D visualization tests, including a SAGD experiment and two flue gas assisted SAGD experiments, were carried out to see if the steam chamber can break through the interlayer under the effect of flue gas. Results show with the increase of gas proportion in the steam-flue gas mixture, the condensation heat transfer coefficient decreased and the condensation pattern was transformed from drop condensation to film condensation gradually. This indicates that flue gas can inhibit the condensation heat transfer, which has great influence on the heat transfer and steam chamber growth in SAGD. Visualization tests show the interlayer could block the steam chamber development. After the interlayer was heated sufficiently, flue gas could penetrate the interlayer and promote steam chamber to break through the interlayer because of its inhibiting effect on condensation heat transfer. Besides, the horizontal sweep efficiency was improved significantly under the synergistic effects of steam, gas, and interlayer. The gas addition can reduce the adverse impact of interlayer on SAGD performance, which provides a potential method to improve SAGD development in the reservoir with interlayer.

Two-phase and three-phase equilibrium K-values for modelling of non-condensable gas Co-Injection processes

To improve the efficiency of Steam Assisted Gravity Drainage process (SAGD), a small amount of non-condensable gases can be added to steam. The non-condensable gas creates an insulation film at the top of the steam chamber as a result of gas accumulation. This could prevent heat loss to the overburden, increase steam chamber propagation in the lateral direction, and consequently improve the SAGD performance. Field-scale modelling and simulation of non-condensable gas injection in a hybrid SAGD process requires a comprehensive numerical model that includes variety of mechanisms involved in the processes. During the steam/non-condensable gas co-injection, the non-condensable gas may partially be dissolved in bitumen and water, accounting for a portion of gas production from the chamber. Therefore, in order to accurately model the non-condensable gas injection process, the partitioning of the gas among the phases (oleic and aqueous) must be well understood.The most significant challenge of modelling multi-phase equilibrium in gas/bitumen/water systems is the lack of three-phase equilibrium data. This study presents a methodology to generate two-phase and three-phase K-values from the experimental solubility data. The data for binary systems at certain temperatures and pressures is translated into equilibrium K-values. The K-values were calculated either from a correlation representing the phase behavior data or from an equation of state coupled with Henry's law. Then, the generated two-phase and three-phase K-values were directly implemented in reservoir simulators to account for component partitioning in different phases. The results indicate that the generated K-values would be applicable for different types of bitumen.

An AI-based workflow for estimating shale barrier configurations from SAGD production histories

An artificial intelligence (AI)-based workflow is deployed to develop and test procedures for estimating shale barrier configurations from SAGD production profiles. The data employed in this project are derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs. Initially, a two-dimensional reservoir simulation model is employed. The underlying model is homogeneous. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor’s Firebag project. Reservoir heterogeneities are simulated by superimposing sets of idealized shale barrier configurations on the homogeneous model. The location and geometry of each shale barrier is parameterized by a unique set of indices. The resulting heterogeneous model is subjected to flow simulation to simulate SAGD production. Next, a two-step workflow is followed: (1) a network model based on AI tools is constructed to match the output of the reservoir simulation (shale indices are inputs, while production rate is the output) for a known training set of shale barrier configurations; (2) for a new SAGD production history generated via reservoir simulation with a shale barrier configuration that is unknown to the AI model generated in Step 1, an optimization scheme based on a genetic algorithm approach is adopted to perturb the shale indices until the difference between the target production history and the production history predicted from the AI model is minimized. A number of cases have been tested. The results show a good agreement between the shale barrier configurations predicted by the AI model with the configurations used to generate production histories in the reservoir simulation model (i.e., the “true” model). Thus, this optimization workflow offers potential to become an alternative tool for indirect inference of the uncertain distribution of shale barriers in SAGD reservoirs from data capturing field performance. This work highlights the potential of an AI-based workflow to infer the presence and distribution of heterogeneous shale barriers from field SAGD production time series data. It presents an innovative parameterization scheme suitable for representing heterogeneous characteristics of shale barriers. If this approach proves to be successful, it could allow the distribution of shale barriers to be inferred together with the impact of these barriers on SAGD performance. This would provide a basis for developing operating strategies to reduce the impact of the barriers.

Pore-scale analysis of steam-solvent coinjection: azeotropic temperature, dilution and asphaltene deposition

Steam assisted gravity drainage is the main technologically and economically feasible method for in situ bitumen extraction. However, SAGD is energy intensive with economic and environmental challenges. Steam-solvent coinjection has proposed to improve SAGD performance, where hydrocarbon solvent is simultaneously injected with steam to increase the production rate and lower the steam-oil-ratio. The addition of solvent, however, complicates an already complex multicomponent thermal-chemical process. Microfluidics is well suited to quantify the pore-scale of steam-solvent coinjection with a tight control over experimental parameters. In this study, a high-pressure high-temperature micromodel combined with optical and thermal imaging is used to probe the pore-scale of steam-solvent coinjection process at relevant reservoir conditions. The effects of butane and hexane, as well as two industrial solvents, condensate and naphtha, on the pore-scale mechanisms are quantified and compared. The in situ thermal data is used to profile and analyze the condensation zone behavior and steam-solvent azeotropic temperature for all steam-solvent cases. We find that overall performance depends on the difference between steam-solvent azeotropic temperature and steam saturation temperature, the degree of solvent-bitumen dilution, and the degree of asphaltene precipitation in the condensing zone. In contrast with pure solvents and condensate, naphtha results in the highest recovery due to a higher steam-solvent azeotropic temperature, effective dilution, with minimal asphaltene deposition.

Numerical simulation and optimization of steam-assisted gravity drainage with temperature, rate, and well distance control using an efficient hybrid optimization technique

ABSTRACTSteam-assisted gravity drainage (SAGD) is a thermal enhanced oil recovery technique through drilling of two horizontal wells. Effects of steam injection temperature, well rates, and their distance on oil recovery were analyzed and optimized. Steam temperature and well distances remarkably affect SAGD performance. Four metaheuristic algorithms (particle swarm optimization (PSO), imperialist competitive algorithm, cultural algorithm, and Bees algorithm) and pattern search optimization algorithm (PSA) are used for optimization. PSO performs better than other metaheuristics and PSA is the fastest one, while it is probable to be trapped in local optimums. Hybrid PSO-PS is proposed that starts with PSO and proceeds with PSA, and tested in an SAGD project and showed excellence over other techniques.

Effect of Horizontal Well Production Testing on SAGD Performance in Heavy Oil Reservoirs

Effect of Horizontal Well Production Testing on SAGD Performance in Heavy Oil Reservoirs

SAGD Pad performance in a point bar deposit with a thick sandy base

The McMurray Formation in Alberta, one of the largest oil accumulations in the world, hosts bitumen with viscosity typically greater than 1 million cP. This formation is heterogeneous containing sedimentological elements such as point bar deposits which in turn consist of inclined heterolithic strata of interlayered sand-shale/siltstone sequences and abandoned mud channels. Due to shale/siltstone interbeds, the reservoir presents severe lateral and vertical lithological heterogeneity which limit vertical flow of steam ascension and bitumen drainage. As part of an ongoing study on the performance of SAGD in point bar systems, we have evaluated the impact of the geology on pad performance in a clean sand unit (on average 30m thick) with an overlying highly heterogeneous point bar deposit (on average 20m thick). The results demonstrate that the performance of a SAGD pad depends on the orientation of the wellpairs within the reservoir even when it contains a thick clean sand interval where the wellpairs are placed near the base of the clean sand. Improved steam-to-oil ratio performance is achieved when the well pairs cut across the shale layers where steam can access multiple layers of oil-laden sand between the shale layers. Even when the steam chamber is relatively uniform in the basal sand zone, steam ‘fingers’ into the heterolithic point bar leading to chamber non-uniformities and less efficient utilization of steam along the well pair, as reflected by the steam-to-oil ratio.

A Condensation Heating Model for Evaluating Early-Period SAGD Performance

In SAGD, it is important to obtain steam chamber conformance along the horizontal wellbore to shorten the ramp-up time and maximize economics. However, reservoir heterogeneity, wellbore undulation, and operation conditions make it hard to achieve this objective. This paper proposes a new method using a condensation temperature model to evaluate the steam chamber conformance of early-period SAGD by interpreting temperature falloff data. The initial temperature distribution of the model is categorized into three zones: a hot-zone of steam temperature, a cold-zone of reservoir temperature, and a transition-zone from steam temperature to reservoir temperature. All three zones are assumed to have circular shapes. This assumption is valid since the model focuses on the early stages of SAGD. The model takes into account the steam condensation on the chamber edge during shut-in, thereby being able to calculate the condensation-front (chamber edge) movement. A semi-analytical approach is developed to solve this model. Sensitivity analysis indicates that the sizes of the steam zone and transition zone, the observing location, and the thermal diffusivity of the formation directly affect the temperature behavior. The synthetic case study shows that the temperature falloffs from the condensation model and from simulation are in good agreement and suggests that the condensation model has the potential to estimate the chamber size during the early stages of SAGD, if calibrated to the field data. Because of the ready-to-use temperature data and the semi-analytic solution, the condensation model proposed in this paper can provide a quick and reliable estimation of the steam chamber size to help the engineers monitor and optimize the chamber development thereafter.

オイルサンドの開発手法とその評価

HANGINGSTONE oil sands field is approximately 50 km away from Fort McMurray, Alberta province. Japan Petroleum Exploration has been producing bitumen (oil) from this field by SAGD method through overseas subsidiary, Japan Canada Oil sands for over a decade. SAGD stands for Steam Assisted Gravity Drainage and steam is injected into oil sands reservoir to decrease the viscosity of bitumen in this process, while mobile oil is produced by the gravity force simultaneously. The production performance of SAGD is significantly affected according to geological heterogeneities and reservoir parameters such as permeability. Therefore, highly detailed geological models have been constructed to evaluate the production performance, operation strategies and new technologies applied to future green fields. Simulation approaches are considered of value in terms of its flexibility. Although base work flow of our simulation approach has been established in this work, a couple of parts of the work flow need to be brushed up further to make it applicable to future evaluations.

Noncondensable Gas Distribution in SAGD Chambers

Summary This paper summarizes a set of SAGD experiments conducted live under an X-ray scanner. These experiments were specifically designed for mapping noncondensable gas distribution and their movement in an active steam chamber during SAGD. Many researches over the past 3 decades have shown that noncondensable gases may have critical impacts on SAGD performance. Some may be positive and others may be negative, depending on reservoir and operating conditions. To better use the positives, avoid the negatives, and for better SAGD performance predictions, it is crucial to understand how these gases behave in a steam chamber. It is arguable that noncondensable gases tend to accumulate at the steam front where steam condenses. However, this assertion has only been supported by numerical simulations. Field observation data have been too sparse. Meaningful tracking of gas production is not a normal practice in the field. The first experiment was conducted in an aluminum vessel packed with 4 darcy sands at 1.0 MPa. The second experiment was conducted in a scalable system consisting of a titanium pressure vessel and a PEEK cell, allowing the SAGD experiment to run at 2.1 MPa. Both experiments used bitumen fully saturated with methane at reservoir conditions and were run live under the X-ray scanner. X-ray images were taken at given time intervals. Temperature profiles were obtained directly from thermocouples. Density profiles were computed from the X-ray images. Methane in the free gas phase were calculated and mapped. After each experiment, samples from the opened cell were also tested for additional observation and confirmation. These experiments confirmed the assertion that noncondensable gas tends to concentrate along the steam front. It was also demonstrated that the steam temperature zone does not coincide with the oil-depleted zone, indicating that in a SAGD reservoir with nontrivial presence of noncondensable gases, temperature measurements at observation wells alone would not reflect the boundary of the steam chamber. The more representative measure of a steam chamber should be the mapping of the oil-depleted zone. A more comprehensive monitoring of gas production plus 4D seismic would be needed to determine the oil-depleted zone in the field operation.

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.

Economic Optimization and Uncertainty Assessment of Commercial SAGD Operations

Abstract As SAGD is being increasingly used as a commercial technology to recover heavy oil and bitumen, it is essential to determine the most economical operating conditions for a SAGD operation by reservoir simulation. Furthermore, to support the decision-making process of a SAGD project, it is also important to quantitatively assess the uncertainty of its economicforecasts. In this paper, the application of global optimization, experimental design, response surface generation and Monte Carlo simulation techniques in the workflow of SAGD simulation studies were demonstrated with a real field case example. The field case is an infill SAGD project with two planned SAGD well pairs and eight existing primary production wells which have 5 years of primary production. A bottomwater zone is also present. Three major steps of the workflow are:history matching primary production data;optimizing SAGD performance; andquantifying uncertainty of the SAGD forecasts. Firstly, experimental design and DECE (Designed Exploration and Controlled Evolution) optimization methods were used to achieve a faster and better history match than the traditional manual history match. Secondly, SAGD performance was optimized by adjusting the steam injection rate and producer liquid withdrawal rate during different SAGD operation periods. Finally, experimental design and response surface generation techniques were applied to build a polynomial response surface through which the net present value (NPV) of the SAGD project is correlated with uncertain parameters and a SAGD design parameter. Monte Carlo simulation was then performed to quantify the uncertainty of SAGD forecasts in terms of cumulative probability distribution of the NPV at different values of the SAGD designparameter. The results show that the economics of this project are improved considerably through optimization. The optimum operating conditions obtained use a high initial steam rate and high production rate to develop the steam chamber. After the instantaneous steam-oil ratio reaches a certain value, both steam rate and production rate are lowered to prevent steam breakthrough to the bottomwater. The uncertainty of the project NPV was assessed, taking into consideration the uncertainties in high temperature relative permeability endpoints and the variation of the SAGD design parameter. Introduction Steam-assisted gravity drainage (SAGD) is a thermal oil recovery process which consists of pairs of two parallel horizontal wells drilled near the bottom of the pay(1). Typically, the length of the wells are between 500 and 1,000 m, the inter-well distance of the two parallel wells is between 5 and 10 m and inter-well pair spacing is between 90 and 120 m(2, 3). The top horizontal well is used to inject steam, while the bottom horizontal well is used to produce reservoir fluids. The steam injected from the top well rises into the formation, forming an expanding steam chamber around and above the injection well. The rising steam eventually loses its latent heat near the boundary of the steam chamber, heats the oil and allows it to drain to the bottom production well by gravity. Successful field tests have proven that SAGD is a viable technology for in situ recovery of heavy oil and bitumen(4–6).