Cyclic Steam Stimulation Research Articles

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.

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

Laboratory experiments and pilot applications have proved that urea is an efficient agent to enhance heavy oil recovery. Numerous studies have been conducted to investigate the mechanisms of urea co-injection process in steam flooding or cyclic steam stimulation. However, investigations of applying urea in steam assisted gravity drainage (SAGD) process are rarely published. The mechanism of enhanced oil recovery in the urea assisted SAGD process has not been fully understood. Laboratory experiments and numerical simulations were conducted to study the decomposition rate of urea, the effect of urea decomposition products on reservoirs and pipelines, and the distribution of effective decomposition products of urea in the steam chamber at conditions of different concentrations, temperatures, and injection rates. The results show that the solubility of the effective urea decomposition products affects their distribution in the formation because of the huge difference between the solubility in oil and water. In SAGD process, urea cannot be completely decomposed and will produce solid decomposition products, which could block the reservoir pores and production pipelines in certain conditions. Moreover, numerical simulation indicates that the use of low-concentration urea injection in SAGD can effectively enhance oil recovery and oil production rate, while high-concentration urea can reduce the oil recovery and oil production rate. In addition, it was proved that CO2 mainly exists at the edge of the steam chamber and NH3 is distributed in the irreducible water near the well-bore. CO2 is more effective than NH3 for enhancing oil recovery in urea assisted SAGD. Studies indicate that urea co-injection is a feasible method for enhancing oil recovery in the SAGD process.

Vertical-well-assisted SAGD dilation process in heterogeneous super-heavy oil reservoirs: Numerical simulations

PetroChina’s Karamay heavy oil reservoirs mostly comprise Jurassic deposits of braided fluvial facies that have a low porosity, extremely high bitumen viscosity, and strong heterogeneities within the reservoir. Steam-assisted gravity drainage (SAGD) dilation start-up has been proven an efficient reservoir geomechanical stimulation method as it shortens the steam circulation time, reduces steam usage, and increases the oil production rates. This method worked well on relatively good-quality oil sand reservoirs. However, for reservoirs with heterogeneous reservoir properties along the SAGD well, field well production data indicated the presence of non-uniform steam chambers in post-dilation SAGD wells. Enhanced dilation methods, such as vertical-well-assisted SAGD dilation (VW-SAGD-Dilation) are have been used, and field pilot tests have yielded promising results. This reservoir stimulation process utilizes one or more vertical wells beside the SAGD well to initiate the formation of dilation zones that connect to the dilation zone formed during the conventional SAGD dilation start-up. Compared with the normal SAGD dilation start-up, this composite dilation process creates a uniform dilation zone along the SAGD well, thus improving the thermal conformance and well productivity. The vertical well and SAGD well are connected by this composite dilation zone, which enables the combined use of the SAGD process and cyclic steam stimulation process. This paper presents our understanding and numerical case studies of this enhanced dilation strategy. The well production data from the post-dilation wells were positive (uniform steam chamber growth and higher oil rate), which highlights the promising potential of using geomechanical dilation as a reservoir stimulation method to create a large stimulated reservoir volume in heterogeneous super-heavy oil reservoirs.

Sand production by hydraulic erosion during multicycle steam stimulation: An analytical study

The production of sand particles associated with the reservoir hydrocarbons becomes one of the most common problems a well of multi cycle steam stimulation may experience during reservoir lifetime. Therefore, it is essential to the investigation of sand particles migration and sand production mechanisms coupled with fluid flow for optimization design of injection and profile control parameters. This paper presents a model based on hydraulic erosion with heat transfer that can analysis release of sand fines under high temperature. The model describes the continuous hydraulic erosion of rock core by the mass conservation equation and particle transport equation, moreover, the sand production and heat transfer are connected through it is coupled with steam injection model. Then, a coupled nonlinear governing equation is derived by using porosity and liquefied sand concentration to evaluate pore enlargement behavior of flow channel and predict sand production behavior under different steam breakthrough channel. Finally, in terms of numerical processing for model, an effectively difference solution method is adopted based on PDE module in COMSOL Multiphysics. The simulation results show that the sand production model can effectively couple heat and sand production, and the relationship between sand production and channeling flow can be studied through seepage process. The degree of steam channeling affects sand production, that is, sand production increases with the increase of the number of steam breakout channels. In addition, it reveals why the sand production can be effectively slowed down by adjusting reasonable injection parameters for multicycle steam stimulation.

Impact of formation dilation-recompaction on cyclic steam stimulation in reservoirs with bottom water: Application of an integrated coupled reservoir-geomechanical modeling workflow

To optimize Cyclic Steam Stimulation (CSS) in areas with thicker bottom water, it is crucial to examine the correlation of the bottom-water encroachment to changes in pay-zone pressure due to dilation-recompaction cycles and intermittent sequences of stress and fluid transfers. This study outlines an integrated workflow for the modeling and uncertainty assessment of CSS in heterogeneous reservoirs through coupled geomechanical-flow simulation, Latin hypercube design, and response surface methodology to probe into dilation-recompaction effects in presence of bottom water, by incorporating the oil-viscosity variation due to biodegradation and compositional variation, presence of water pockets due to compartmentalization, dilation-recompaction, and relative permeability hysteresis. The results suggest that the CSS performance is most sensitive to dilation pressure and the interaction of recompaction pressure-water pockets. While increase in dilation pressure and compressibility improves CSS, the recompaction pressure is negatively correlated with its performance. This is related to the underlying water pockets compression due to reservoir dilation during injection and water encroachment as a result of the rise of bottom water level. Higher dilation pressure and lower recompaction pressure delay the compression of the underlying water pockets. On the contrary, in the absence of bottom water, CSS is improved with lower dilation pressure and higher recompaction pressure. Clearly, the presence of bottom water reverses the favorable geomechanical envelope during the injection and production cycles.

Half a century of continuous oil production by in-situ combustion in Romania – case study Suplacu de Barcau field

Thermal oil recovery is a special technique belonging to Enhanced Oil Recovery (EOR) methods and includes steam flooding, cyclic steam stimulation, and in-situ combustion (fire flooding) applied especially in the heavy oil reservoirs. Starting 1970 in-situ combustion (ISC) process has been successfully applied continuously in the Suplacu de Barcau oil field, currently this one representing the most important reservoir operated by ISC in the world. Suplacu de Barcau field is a shallow clastic Pliocene, heavy oil reservoir, located in the North-Western Romania and geologically belonging to Eastern Pannonian Basin. The ISC process are operated using a linear combustion front propagated downstructure. The maximum oil production was recorded in 1985 when the total air injection rate has reached maximum values. Cyclic steam stimulation has been continuously applied as support for the ISC process and it had a significant contribution in the oil production rates. Nowadays the oil recovery factor it’s over 55 percent but significant potential has left. In the paper are presented the important moments in the life-time production of the oil field, such as production history, monitoring of the combustion process, technical challenges and their solving solutions, and scientific achievements revealed by many studies performed on the impact of the ISC process in the oil reservoir.

Application of Thermotropic Gels in the First Cycle of Cyclic Steam Stimulation at High-Viscosity Oil Deposits

Application of Thermotropic Gels in the First Cycle of Cyclic Steam Stimulation at High-Viscosity Oil Deposits

An Integrated Framework Based on Deep Reinforcement Learning Algorithm for Optimizing Thermal and Chemical Production in Edge-Water Heavy Oil Reservoirs

The development of heavy oil reservoirs with active edge and bottom water is one of the most challenging problems in petroleum engineering. In response to the limited thermal recovery of these reservoirs, a multi-phase and multi-component numerical simulation model for thermal and chemical recovery is proposed. An edge-water assisted chemical flooding (EAC flooding) is proposed, which can improve oil displacement efficiency and sweep efficiency by rational utilization of edge-water energy when compounding multicomponent chemical system. Then, a deep reinforcement learning algorithm, ActorCritic structure, is proposed to predict dynamic production parameters and determine the optimal working system to maximize the oil recovery according to the above mathematical model. The deep reinforcement learning (DRL) model can predict the dynamic production curves and estimate the maximum oil recovery. At the same time, the proposed model can determine the best conversion timing from cyclic steam stimulation to EAC flooding. Finally, the DRL model can automatically obtain the optimal working system, effectively improving the oil recovery while considering the economic benefits. Thus, the DRL model can solve traditional numerical simulation’s time-consuming and labor-intensive challenges and accurately give the optimal working system for developing heavy oil reservoirs with edge water in the field.

Influences of reservoir rock and fluid properties on cyclic steam stimulation efficiency in naturally fractured reservoirs

Steam injection in NFRs provides an extremely challenging problem as well as a potentially efficient EOR method. Coupling of the two distinct and contrasting matrices and fracture systems results i...

Influences of reservoir rock and fluid properties on cyclic steam stimulation efficiency in naturally fractured reservoirs

Influences of reservoir rock and fluid properties on cyclic steam stimulation efficiency in naturally fractured reservoirs

Application of Thermotropic Gels in the First Cycle of Cyclic Steam Stimulation at High-Viscosity Oil Deposits

Application of Thermotropic Gels in the First Cycle of Cyclic Steam Stimulation at High-Viscosity Oil Deposits

An investigation of production performance by cyclic steam stimulation using horizontal well in heavy oil reservoirs

In this paper, a new semi-analytical model considering the non-isothermal effect is proposed to predict heated radius and production performance in a cyclic steam stimulated (CSS) horizontal well.Firstly, an assumption of three heated areas based non-isothermal distribution is introduced. Based on the fluid flow behavior of CSS process in a horizontal well, the spreading of heated area can be classified into three stages. And the heated radius can be derived using the energy conservation equation and area equivalent principle respectively. Then a new semi-analytical model for predicting the production performance by using the equivalent flow resistance method is established. After validation of the new model with numerical simulation and oil field data, the effect of non-isothermal on production performance is analyzed in detail. The results show that a larger injection rate, a bigger error caused by isothermal model when steam injection rate exceeds 200 m3/d. Also, the average water saturation rise has an increase of 1.85% and the average temperature has a drop of 21.12% if the non-isothermal effect is considered.This paper provides an accurate and quick method for estimating the heated radius and production performance in a horizontal well during CSS process.

Experimental Study on the Cyclic Steam Stimulation Assisted by Flue Gas Under Shallow Heavy-Oil Reservoir Conditions: Optimization of the Steam-Flue Gas Ratio

Normally, the recovery effect of a heavy-oil reservoir gradually deteriorates after multiple rounds of cyclic steam stimulation (CSS). However, the injection of flue gas can effectively increase the utilization degree of steam heat energy, which improves the recovery effect. In this paper, an experimental method for CSS using an energy storage container was established. Based on this method, a one-dimensional core physical simulation experiment for CSS under different flue gas ratios was performed. During the experiment, the changes in temperature field, oil production rate, increase in backpressure, and oil recovery factors were tested. In addition, differences in these data under different injection steam-flue gas ratios were compared. The results show that the flue gas provides a channel of fluids in porous media for steam, which is conducive to the heat transfer of steam to the deeper part of the sandpack. The sandpack has a higher temperature in each cycle than the CSS. The core temperature of each round of flue-gas-assisted CSS is higher than that of the CSS. The final oil recovery factors of flue-gas-assisted CSS using different steam-flue gas ratios are 22.2, 26.7, 30.8, 24.4, and 21.6%, while that of CSS is only 17.2%. According to the experiment, it is concluded that the best steam-flue gas ratio to optimize the flue-gas-assisted CSS is 1:10. With the combined effect of three factors (the temperature field of the sandpack, energizing effect of the flue gas, and degree of oil during recovery), the flue-gas-assisted CSS using the steam-flue gas ratio of 1:10 maximizes the steam heat transfer, increases the energy of return discharge, replenishes formation energy, and improves the oil recovery factor. Through the experiment, the research results provide theoretical guidance for improving the effectiveness of the CSS of heavy-oil reservoirs.

Research on influencing factors of injection capacity in cycle steam stimulation process with horizontal well in Bohai oilfield

Since the beginning of the 21st century, the proportion of heavy oil production has been increasing. Cycle steam stimulation (CSS in short) is the prevailing technology for the development of heavy oil reservoirs and has made a great contribution to the development of heavy oil. However, the current research on the factors affecting the steam injection capacity of CSS heavy oil reservoirs and the degree of influence of each factor is insufficient. Oil recovery and heat utilization efficiency are poor, especially in the oil fields with poor reservoir conditions and severe heterogeneity. In this paper, the reservoir geological model of the Bohai oilfield was established, and the CSS development was predicted. The problems in the development process of CSS in Bohai oilfield were pointed out. Then, laboratory experiments were carried out to study the steam absorption law of CSS heavy oil reservoirs in consideration of reservoir permeability, steam injection rate, steam injection temperature and crude oil viscosity. The result showed that higher formation permeability and steam injection temperature could improve oil displacement efficiency; higher steam injection rate would reduce oil displacement efficiency. Finally, the influence rules of different injection-production parameters were clarified to shed some lights on the efficient exploitation of heavy oil reservoirs.

Combination of Cyclic Steam Stimulation and Steam Flooding to Improve Oil Recovery in Unconsolidated Sand Heavy Oil Reservoir

Steam injection can be success in increasing oil recovery by determining the steam chamber growth. It will impact on the steam distribution and steam performance in covering hot areas in the reservoir. An injection plan and a proper cyclic steam stimulation (CSS) schedule are critical in predicting how steam chamber can grow and cover the heat area. A reservoir simulation model will be used to understand how CSS really impact in steam chamber generation and affect the oil recovery. This paper generates numerous scenarios to see how steam working in heavy oil system particularly in unconsolidated sand reservoir. Combine the CSS method and steam injection continue investigate in this research. We will validate the scenarios based on the how fast steam chest can grow and get maximum oil recovery. Reservoir simulation resulted how steam chest behavior in unconsolidated sand to improve oil recovery; It concluded that by combining CSS and Steam Injection, we may get a faster steam chest growth and higher oil recovery by 61.5% of heavy oil system.

Thermal Viscous Fingering in Thermal Recovery Processes

Heat and fluid flow at the edge of steam chambers found in thermal recovery processes such as steam-assisted gravity drainage and cyclic steam stimulation remain unresolved. Given the multiple phases present and contrast of thermophysical properties, it remains unclear where instabilities occur within this thin, yet critical, zone of the process. In the research reported here, heat and fluid flow are examined in vertical and horizontal sections of a steam chamber to understand the differences between the two orientations by using detailed and fine-gridded thermal reservoir simulation models. The results show that heat transfer in vertical and horizontal directions are different with greater heat transfer found in the vertical orientation. In the vertical direction, heat transfer occurs with mobilized bitumen draining with subsequent steam moving into the emptied pore space. Conduction beyond the edge of the chamber dominates and heated, low viscosity bitumen fingers into cold, higher viscosity bitumen at the edge of the chamber. Relative permeability effects are observed which can interfere with enhanced oil mobility.

Low temperature oxidation of heavy oil in oxygen-reduced air: Effect of pressure and oxygen content on heat release

Air injection for in situ combustion (ISC) and air injection assisted cyclic steam stimulation (AACSS) techniques have a good application prospective in the development of heavy oils, while the explosion risk in the process of air injection is of great concern and has restricted the application of the technology. So that injection of oxygen-reduced air has been proposed to eliminate and control the explosion of oil/gas mixture with air. In this study, low-temperature oxidation experiments of heavy oil samples were conducted using a small batch reactor under the pressure of 5–15 MPa and oxygen content of 5%–15% at 225 °C in order to investigate the effect of oxygen content and pressure on the reaction rate and heat release during oxidation of heavy oil with oxygen-reduced air. The variations of temperature and pressure during the oxidation reaction were measured in the experiment, and the explosion phenomena of heavy oils were observed in the air with high oxygen contents (oxygen content more than 15%). The reaction rate and the exothermic heat of the reaction were calculated based on the pressure and temperature curves and using an improved heat loss model. The experimental results showed that reducing the oxygen content (e.g. reduced oxygen less than 10%) in air can effectively prevent the explosion of oil-gas mixtures, and the reaction rate and heat release during heavy oil oxidation are linearly proportional to pressure and oxygen content in the injected air when oil is in excess. The results of this study indicate that the heat generated in oil oxidation, which is important for the ISC and AACSS processes, can be controlled by pressure and oxygen content of the injected air, which can lay a good foundation for the oxygen-reduced air injection technique, especially for its application in deep heavy oil reservoirs, in which injection of oxygen-reduced air at high pressure can offset the effect of low oxygen content on heat release.

Effect of Temperature on Bitumen/Water Relative Permeability in Oil Sands

The steam-assisted gravity drainage (SAGD) process is among the most applicable thermal enhanced oil recovery (TEOR) methods in North American heavy oil reservoirs. In addition to improving oil mobility through viscosity reduction, the high-temperature condition that a TEOR method causes may significantly alter the fluid flow performance and behavior, as manifested by the relative permeability to fluids in the reservoir. Therefore, in a SAGD and cyclic steam stimulation (CSS), the relative permeabilities can change within the temperature-gradient region developed around the SAGD chamber or between two cycles of CSS processes. However, there is no unique two-phase relative permeability model, especially for bitumen systems to cover a wide range of temperatures. Therefore, the primary objective of this study is to history-match the results of the recent study done by Esmaeili et al. using a new methodology and to conduct limited steady-state relative permeability measurements at different temperatures to confirm the validity of displacement-based relative permeability curves and then to propose a reliable general relative permeability model as a function of temperature. Twelve history-matched bitumen/water relative permeability sets are obtained in a wide range of temperatures from 70 to 220 °C under a confining pressure higher than 1000 psi and the test pressure in the range of 350–400 psi. An in-house developed reservoir simulator was used to obtain relative permeability curves from isothermal displacement data using the history-matching approach. The results demonstrated that both production and pressure-drop data can be matched using the optimized values of parameters of the generalized Corey relative permeability model. Furthermore, a more reliable value for actual residual oil saturation was determined by applying our new methodology in history matching. A comparative analysis with the steady-state relative permeability data allowed us to determine the extent to which the unsteady-state relative permeability is affected by viscous fingering. A considerable shift in both oil and water relative permeability at higher temperatures is noticed. Furthermore, it is also noted that the endpoint relative permeability to oil and water is also altered significantly. The implicit relative permeability data obtained from this study are consistent with the results of the JBN method that were reported in our previous study. By making the parameters of the Corey relative permeability model dependent on temperature, a new model of temperature-dependent bitumen/water relative permeability in sand was developed. It is anticipated that this model can facilitate inclusion of temperature-dependent relative permeability in reservoir simulation studies.

Impact of Formation Dilation–Recompaction on Cyclic Steam Stimulation

SummaryAn integrated modeling of the cyclic steam stimulation (CSS) at the Peace River heavy-oil/oil-sand deposits in Alberta, Canada, is challenging because of the presence of compositional gradient, faulting, and bottomwater pockets, and the variations in the oil viscosity, rock dilation, fracturing, and the pay-zone-thickness variation. Both gravity and viscosity are marked by declining quality with depth, biodegradation, and compartmentalization.The high oil viscosity and low water mobility at Peace River cause low initial injectivity. High injectivity during the CSS is achieved by high-pressure injection to fail the formation mechanically and trigger fracturing and pore deformation. Moreover, the pore dilation/recompaction triggers relative permeability hysteresis.History matching of high steam injectivities is challenging when reasonable fracture lengths and rock compressibilities are used. To match injectivities, most reservoir simulations have used either a larger compressibility (“spongy-rock” approach) or long fractures. The spongy-rock approach predicts a steady increase in injection pressure, whereas during the early time of the injection cycles, injection pressures increase and then level off for most of the cycle.We describe the enhancements made in an iteratively coupled geomechanical–flow model to incorporate the modeling of both pore deformation and relative permeability hysteresis to match the injection pressures, steam injectivity, and oil/water productions from CSS at Peace River that are otherwise difficult to reproduce. The geomechanical model explains surface heave and high injectivity caused by dilation attributable to shear failure, increase in pore pressure/formation compressibility, and decrease in effective stress. A dilation pressure is specified, below which the behavior is elastic and above which a higher compressibility is used. Above a maximum porosity, further dilation is not permitted. Also, the hysteresis model calculates gridblock relative permeabilities that lie on or between the imbibition/drainage curves, making it possible to use the laboratory-derived two-phase oil–water relative permeabilities and still match the field-measured water- and oil-production volumes.By combining an iteratively coupled reservoir–geomechanical model for the CSS with stochastic workflows, including the Latin-hypercube design (LHD) and response-surface methodology (RSM), the impacts of dilation/recompaction factors (fracturing pressure, maximum injection pressure, dilation pressure, recompaction pressure, and formation compressibility) are quantified through history matching the field results and automated stochastic sensitivity analysis and uncertainty assessment.

Statistically enhanced model of oil sands operations: Well-to-wheel comparison of in situ oil sands pathways

Abstract Although the life cycle greenhouse gas (GHG) emissions associated with Canadian oil sands have been investigated in recent years, questions remain regarding the source and impact of variability in emissions in this industry over time. This study combines publicly-available data from the fifteen largest operating in situ extraction projects, i.e., cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) with a statistically-enhanced life cycle model to investigate variability in well-to-wheel (WTW) GHG emissions. We estimate that the WTW GHG emissions from CSS-derived gasoline range from 99 to 114 g CO2eq/MJ (80% confidence interval), 6–22% higher than the RFS2 baseline. The corresponding range for SAGD-derived gasoline is 98–133 g CO2eq/MJ, 5–42% higher than the RFS2 baseline. SAGD-derived gasoline has more variability as some operators “upgrade” their crudes, emitting GHGs, whereas no CSS operator employs upgrading. Without upgrading, the 90th percentile for SAGD emissions would be 114 g CO2eq/MJ. Upstream variability in GHG emissions drives the positively skewed WTW GHG distributions. This demonstrates the importance of understanding the nature and magnitude of variability and uncertainty in decision making.