Steam-oil Ratio Research Articles

Development of a Generalized Experimental Methodology for Investigating the Role of Steam Quality on Steamflooding Performance

Summary For steamflooding processes, steam quality plays a crucial role because it affects enhanced oil recovery mechanisms and production performance. Many numerical simulations have been performed on the role of steam quality. However, few studies have evaluated the role of steam quality on steamflooding performance by experimental measurements because of the lack of a generalized experimental methodology to accurately generate and measure steam with different qualities under reservoir conditions. The objective of this study is to propose a generalized experimental methodology for investigating the role of steam quality on steamflooding performance. A steam quality controlling box was newly designed and fabricated to generate steam with different qualities, and its reliability was verified by a novel steam quality measurement system together with a developed theoretical method. Then, a series of experiments were conducted by our designed 1D and 2D sandpack models to evaluate the steamflooding performance under different steam qualities. The results showed that the developed methodology could accurately generate and measure steam with different steam qualities. The maximum errors between desired, measured, and calculated steam qualities were 4.39% under the experimental conditions in this study. The steam quality substantially affected the steamflooding performance. A higher steam quality led to a lower water cut, a lower maximum pressure difference between the inlet and outlet of the sandpack model, a lower water/oil ratio (WOR), a lower steam/oil ratio (SOR), a higher oil recovery, and a higher oil production rate. However, there is an optimal value of steam quality from the view of heat efficiency in this study. The oil recoveries of 2D steamflooding experiments increased from 36.30 to 45.02% when the steam quality increased from 0 to 0.8. However, the optimal steam quality of 0.6 had the maximum heat efficiency at 3.16×10−5 kJ−1. This research contributes to a better understanding of steam quality on steamflooding performance and also provides a generalized methodology for other steam injection processes.

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.

Experimental Evaluation Study on High Temperature Tolerance Foam for Profile Control of Steam Huff-n-Puff

In the process of steam huff and puff to develop heavy oil reservoirs, steam channeling is the main factor that restricts the development effect, which causes that the swept area of steam is limited and unable to heat heavy oil adequately. It is important to find an economical and efficient method to prevent steam channeling from happening at steam huff and puff production; thus, a DF-2 high temperature tolerance foam system is proposed to assist steam huff and puff production in this paper. Firstly, utilizing high-temperature aging tank and high-speed stirrer device, the foam quality of DF-2 foam and four kinds of other common industrial foams were evaluated and compared; this experiment result shows that the DF-2 foam has the best temperature tolerance. Whereafter, three groups of single-sandpack experiments were carried out to investigate the change of DF-2 foam resistance factor under different conditions, which included the influence of gas liquid ratio, injection pattern, and crude oil, and the blocking capabilities of DF-2 foam were studied. Through the dual-sandpack experiment, the profile control performance and diversion capacity of the DF-2 foaming agents were studied and evaluated systematically. Finally, the DF-2 high temperature tolerance foam agent was applied to on-site production. The sandpack experiment results indicated that the resistance factor of DF-2 foam agent decreased with gas-liquid ratio, and the optimal gas-liquid ratio was 1 : 1. Coinjection of gas and liquid with foam generator is better than slug injection. Crude oil in sandpack can reduce blocking capability to some extent. During the application of the DF-2 high temperature tolerance foaming agent in the steam huff-n-puff process in M-12 Oilfield block, it had a good performance of profile control and foam blocking, solving the problem of steam channeling and improving the steam sweep area to increase the steam-oil ratio in the heavy oil reservoir, and the production performance of steam huff and puff was improved to a great extent.

Tar mitigation using insitu heat generation chemicals (part I): A comparative study

Tar is an extra-heavy oil with ultra-high viscosity. Accumulation of tar in a reservoir ultimately results in production decline. This study represents the first part of the series of investigation, which aim at developing an insitu heat generation scheme (through thermochemical reaction) for tar mitigation to improve oil production from tarmat-impacted reservoir. Comparative studies have been conducted through both coreflooding experiments and field scale numerical simulation for tar removal using injection of thermochemical fluids (TCF) at 90 °C and other fluids, including water (23 °C), hot water (90 °C), oil soluble organic solvent sludge (90 °C) and steam (210 °C). The results from coreflooding experiments revealed that TCF injection has comparable removal efficiency in terms of recovery factor (RF = 93%), with that of steam injection (RF = 94%). In comparison, the RF from water, hot water, and injection of an oil-soluble solvent sludge are 21, 53, and 85%, respectively. From the field scale simulation, the results affirmed greater efficiency of TCF injection over steam injection with higher tar recovery rate, recovery factor (RF), and Oil: Steam ratio (OSR). In addition, the simulation results revealed that cyclic injection of TCF outperformed continuous injection operation.

Analysis of the steam-thermal treatment at the Karazhanbas field

The article describes the main features of the geological structure of the Jurassic-Cretaceous productive strata of the Karazhanbas field, located on the Buzachi Peninsula (Western Kazakhstan), and the effectiveness of thermal methods and their modifications to enhance oil recovery, which have been used in the field since the 80s of the last century. The use of thermal steam stimulation in the form of thermal slugs allows not only to cover most of the formation with thermal steam stimulation by switching to unheated water injection in a number of wells and transferring steam injection to other wells, but also to intensify the movement of the thermal slug in the formation during the cold water injection process. As a result, the steam-oil ratio when using thermal rims and increasing the steam injection rate can be several times less than with continuous slow steam injection. The use of thermal steam treatment allows increasing oil recovery by 3545% of the initial balance oil reserves. Testing and implementation of new equipment and technology, as well as the study of world experience in the development of high-viscosity oil are currently relevant for the development of the Karazhanbas field.

Experimental and numerical studies on production scheme to improve energy efficiency of bitumen production through insitu oil-in-water (O/W) emulsion

Emulsification involving dispersion of bitumen droplets in a continuous aqueous phase (as oil-in-water (O/W) emulsion), is an efficient method of reducing the viscosity. The objective of this research is to harness the potential of insitu emulsification for production of bitumen to improve energy efficiency. Thus, O/W emulsion was prepared using poly vinyl alcohol (PVA) surfactant (with NaOH and ethanol additivities) at different ratios of bitumen: PVA solution viz. 70:30 (RX1), 55:45 (RX2), 40:60 (RX3). The data was incorporated in computational fluid dynamics (CFD) analysis to obtain emulsification reaction parameters at different temperatures (30–150 °C). Subsequently, numerical simulation considering insitu formation of O/W emulsion was performed at different injection temperatures (50, 100, and 150 °C). The results were compared with those of conventional steam injection at 215 °C. Significant viscosity reduction of bitumen was obtained from emulsification experiments. From numerical simulation, the proposed method resulted in higher oil: steam ratio (OSR) compared with steam injection method. Ultimately, with reference to steam injection (thermal efficiency, ΔEeff = 0.02 m3/GJ; net bitumen production = 692 m3), the most promising operation is the production from RX3, at 150 °C, with thermal efficiency, ΔEeff = 0.04 m3/GJ, and 649 m3 net bitumen production.

Steam alternating non-condensable gas injection for more heavy oil recovery

Recent studies and field operations show that co-injection of steam and non-condensable gas could reduce the steam-oil ratio significantly, which means the steam and gas push process (SAGP) could be more environmentally friendly than the conventional steam-assisted gravity drainage (SAGD) process. However, this modification may eventually cause a drop in the cumulative volume of produced oil. In this paper, we develop a technique to overcome the adverse impact of SAGP on the final oil recovery: this technique employs alternate steam and a mixture of steam and non-condensable gas injection into the viscous oil reservoir to take advantage of a high steam chamber volume, pushing pressure at the reservoir top and lower heat loss to overburden rocks, simultaneously. The technique (so-called SANG) is examined numerically in a reservoir with average properties from Athabasca, and the results are compared to the conventional SAGD and SAGP. Effects of changing reservoir properties and operating conditions on the performance of the SANG together with a cost-benefit analysis and CO2 emissions are elucidated. Based on the results, the SANG would effectively improve the performance of the thermal gravity process within viscous oil reservoirs and, provided it is validated, it can replace the conventional SAGD and SAGP.

Status Quo of a CO2-Assisted Steam-Flooding Pilot Test in China

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to reduced residual oil saturation, high steam-oil ratio, and lower profitability. A field test of the CO2-assisted steam flooding technique was carried out in the steam-flooded heavy oil reservoir in the J6 block of the Xinjiang oil field (China). In the field test, a positive response to the CO2-assisted steam flooding treatment was observed, including a gradually increasing heavy oil production, an increase in the formation pressure, and a decrease in the water cut. The production wells in the test area mainly exhibited four types of production dynamics, and some of the production wells exhibited production dynamics that were completely different from those during steam flooding. After being flooded via CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence, they yielded stable oil production. In addition, emulsified oil and CO2 foam were produced from the production well, which agreed well with the results of laboratory-scale tests. The reservoir-simulation-based prediction for the test reservoir shows that the CO2-assisted steam flooding technique can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and can yield a final recovery factor of 70%.

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.

Discovering Energy Consumption Patterns with Unsupervised Machine Learning for Canadian In Situ Oil Sands Operations

Canada’s in situ oil sands can help meet the global oil demand. Because of the energy-intensive extraction processes, in situ oil sands operations also play a critical role in meeting the global carbon budget. The steam oil ratio (SOR) is an indicator used to measure energy efficiency and assess greenhouse gas (GHG) emissions in the in situ oil sands industry. A low SOR indicates an extraction process that is more energy efficient and less carbon intensive. In this study, we applied machine learning methods for data-driven discovery to a public database, Petrinex, containing operating data from 2015 to 2019 extracted from over 35 million records for 20 in situ oil sands extraction operations. Two unsupervised machine learning methods, including clustering and association rules, showed that the cyclic steam stimulation (CSS) recovery method was less efficient than the steam-assisted gravity drainage (SAGD) recovery method. Chi-square tests showed a statistically significant association between the CSS recovery method and high SOR (p < 0.005). Two association rules suggested that the occurrence of non-condensable gas (NCG) co-injection produced a low SOR. Chi-square tests on the two rules identified a statistically significant relationship between gas co-injection and low SOR (p < 0.005). Association rules also indicated that there was no association between the production regions and SORs. For future in situ oil sands development, decision-makers should consider SAGD as the preferred method because it is less carbon intensive. Existing in situ oil sands projects and future development should explore the possibility of NCG co-injection with steam to reduce steam consumption and consequently reduce GHG emissions from the extraction processes.

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.

Cooperative Mechanism and Technology Parameters Optimization of Multi-thermal Fluid Huff & Puff Development in Heavy Oil Reservoir

The extra-heavy oil reservoirs in Central Asia have the characteristics of shallow burial, high crude oil viscosity, and strong reservoir heterogeneity. Conventional steam huff&puff have good initial development effects, but because energy cannot be replenished in time, steam huff&puff in the later stages huff&puff production declined fast and the effective production time is short. According to the current situation of oil reservoir development, a development technology combining multi-thermal fluid huff&puff and steam huff&puff is proposed. At the initial stage of production, steam is used to reduce viscosity, and in the later stage, N₂ in the multi-thermal fluid is used to pressurize, expand the steam chamber volume, and dissolved CO₂ to reduce viscosity. For single wells of different modes, using numerical simulation to design reasonable combined development modes and injection parameters, the research shows that multi-thermal fluid huff&puff after 5 cycles of steam huff&puff can achieve the best oil increase effect, and the best steam injection intensity 10t/m, gas injection intensity of 1500m3/m, 29 wells have been implemented in M heavy oil field in Central Asia. after use the multi-thermal fluid and superheated steam huff&puff coordinated development methods, the average well daily oil increment reached 0.6-4t/d, the water cut is reduced by 10-21%, the oil-steam ratio is increased by 0.4-0.6, realizing the efficient development of shallow buried extra-heavy oil reservoirs.

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 Gas Mobility Control by Chemical Additives Injection and Foam Generation during Steam Assisted Gravity Drainage (SAGD)

ABSTRACT Gas mobility control is highly required to obtain a sufficiently-expanded and uniformly-developed steam chamber, which is conducive to steam-assisted gravity drainage (SAGD) production. Adding chemical additives with in-situ generation of foam (CAFA-SAGD) is an approach to improve sweep efficiency, displace residual oil and reduce heat loss, enhancing SAGD performance in terms of both oil production and steam oil ratio (SOR). With the input of the obtained chemicals and foam parameters and the consideration of the principle mechanisms (steam foam mobility control and IFT reduction), it depicts the dynamic distribution of components and compares the performance of CAFA-SAGD and SAGD with numerical simulation. Foam generation and foam collapse are also incorporated. Simulation study demonstrates that steam mobility control is conducive to generate a larger oil displacement area in the lower part of the model. Also, residual oil is more depleted owing to higher injection pressure and interfacial tension reduction. The optimization from this study ensures that the oil recovery factor is improved by 5.34%.

Review of Temperature Dependence of Thermal Properties in Steam-Assisted Gravity-Drainage Process: Mathematical Formulation

Summary Steam-assisted gravity drainage (SAGD) is the preferred thermal-recovery method used to produce bitumen from Athabasca deposits in Alberta, Canada. In SAGD, heat energy is transferred from steam to the reservoir, which reduces bitumen viscosity, and enables the bitumen to flow toward the horizontal production well under gravity forces. Conduction is the main heat-transfer mechanism at the edge of the steam chamber. It is controlled by reservoir thermal conductivity and heat capacity. Both factors are temperature dependent and neglecting such dependency can cause errors that should be evaluated in one study. In this study an analytical SAGD model is discussed that includes temperature dependency in the prediction of the temperature evolution ahead of the interface, oil-production rates, and steam/oil ratio (SOR). Such a model is used to evaluate the importance of temperature dependency in different operational conditions. The results of the presented analytical model reveal that the oil rate can be calculated ignoring temperature dependency, suggesting thermal conductivity and specific heat calculated at a dimensionless temperature ratio between 0.75 to 0.8 and between 0.37 to 0.41, respectively. For both laterally expanding and angularly expanding reservoirs, the SOR is independent of the thermal conductivity. Unlike the effect of temperature-dependent thermal conductivity on SOR, temperature dependency on heat capacity significantly affects SOR. Such errors are larger for higher injection pressures (hence, higher steam-chamber temperatures). This study provides a modified Butler analytical SAGD model that combines independently calculated modification factors for thermal conductivity and heat capacity into a modification factor (CT). Interestingly, the modification factor is identical with the TANDRAIN factor that is suggested by Butler to reduce the overestimated rates from the original theory. Such a finding is important because it addresses modifications such as in TANDRAIN and LINDRAIN estimations that are a result of ignoring the temperature dependency in analytical formulation.

Performance and mechanisms of enhanced oil recovery via CO2 assisted steam flooding technique in high heterogeneity heavy oil reservoir: PVT and 3D experimental studies

In this paper, CO2 assisted steam flooding technique was proposed to further enhance heavy oil recovery after steam flooding. PVT tests and 3D model oil displacing experiment were conducted to investigate enhancing oil recovery (EOR) mechanisms and oil displacing performance. The results indicated that CO2 dissolving in heavy oil could induce oil swelling, reduce oil relative density, and reduce oil viscosity. After steam flooding, 6.8% of sweep efficiency and 8.5% of additional oil recovery were improved by implementing CO2 assisted steam flooding. The study has suggested that CO2 assisted steam flooding is a feasible technique for recovering heavy oil after steam flooding.HighlightsCO2 dissolving heavy oil can swell oil volume and reduce oil viscosity dramatically.CO2 alternative steam flooding can improve injection pressure and oil–steam ratio, and reduce steam consumption.Introducing CO2 into steam flooding process can increase both oil displacement efficiency and sweep efficiency, then enhancing oil recovery.CO2 assisted steam flooding is a feasible technique for improving oil recovery in heavy oil reservoir after steam flooding.

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.

Analysis of Athabasca Oil Sands Investigates SAGD Performance Variability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195348, “Steam-Assisted Gravity Drainage Performance Variability—Analysis of Actual Production Data for 28 Athabasca Oil Sands Well Pairs,” by Quang T. Doan, Vincano; S.M. Farouq Ali, SPE, University of Houston; and Thomas B. Tan, SPE, Petrostudies Consultants, prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. The authors reviewed and analyzed actual field production and injection data for 28 Athabasca oil-sands-deposit SAGD well pairs (WPs). Based on analysis of field-production data, a numerical model was built and calibrated against production data from two of the poorer-performing WPs among the 28 studied. Agreement between simulated and actual cumulative oil and steam/oil ratio (SOR) was within 10% after 6 years of operations on a first-iteration basis. Problem and Investigation Methodology A survey of the literature reveals that some aspects of the SAGD process, particularly with regard to the behavior of gas, still largely are not understood. While successful history-matching simulations of SAGD WPs exist for several different projects, these rely on dead-oil pressure/volume/temperature treatment and exclude any findings and discussion on gas production. Such history-matched models likely would need to be modified significantly to be useful for modeling the wind-down stage of SAGD operations. Recent numerical studies modeling the generation of aquathermolysis gases focused on the injection of noncondensable gas into a mature SAGD steam chamber. In preparation for a series of numerical studies on aspects of SAGD performance, a reservoir model simple enough to be relatively adaptable for different geological settings was built. Such a model had to be calibrated rigorously with actual production data to provide a high degree of confidence in its results and predictive capability in appropriate contexts. The investigation in the complete paper is aimed at addressing several fundamental aspects of SAGD operations, including the effects of reservoir heterogeneities and the behavior of gas. The first part of the complete paper is focused on reviewing and analyzing actual field production data spanning more than 1,700 days from 28 SAGD WPs from four different pads (A, B, C, and D) of the Jackfish 1 project; this synopsis will not include that extensive data. Jackfish 1 Project. Jackfish 1 consists of 42 WPs divided into six pads (including the 28 WPs in Pads A, B, C, and D analyzed for the authors’ study) and is part of the geological oil-sands trend of the Athabasca oil-sands deposit. Jackfish 1 has a nameplate capacity of 35,000 BOPD, with a designed SOR of 2.7. Consistently exceeding 90% of its nameplate capacity since first steam, it is commonly considered to be a successful SAGD project. The results of data analysis for the WPs studied indicated the following: Considerable variance exists in the recovery performance of SAGD WPs on the same pad. Considering the small drainage area of the 7-WP pad (800×800 m), such variances bear important implications for the planning and execution of SAGD projects (particularly greenfield development but also with regard to brownfield expansion). The authors stress that forecasting project productivity should not be based on a single-WP, deterministic simulation model without any consideration for distributions in reservoir geology and parameters affecting SAGD performance. This assessment is equally applicable in the estimation of reserves.