Steam Stimulation Research Articles

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

Calculation of the Critical Liquid Production of Cyclic Steam Stimulation in Heavy Oil Reservoir with Edge Water

Abstract For heavy oil reservoirs with edge water, when the liquid production of cyclic steam stimulation is excessively high, there is a risk of edge-water invasion. Therefore, the liquid production of cyclic steam stimulation is of great significance to the prevention of edge-water invasion in heavy oil reservoir with edge water. Currently, many studies on the critical liquid production in oil reservoir by water flooding are conducted. However, there is few research on the critical liquid production in heavy oil reservoir by cyclic steam stimulation. To fill this gap, The formation after cyclic steam stimulation is divided into the heated zone and the unheated zone. A characterization method for the flow field parameters after cyclic steam stimulation is established. By transforming the length of the thermal swept zone, the comprehensive mobility of the heated zone is equivalently represented as the comprehensive mobility of the unheated zone. On this basis, considering the threshold pressure gradient in heavy oil, a calculation method for the critical liquid production after cyclic steam stimulation in oil reservoir is developed based on the theory of mirror reflection and the superposition of potentials. The results show: (1) Permeability being constant, the critical liquid production rate increases with the increase in cyclic steam injection quality. With a constant cyclic steam injection quality, the critical liquid production rate increases with the increase in permeability; (2) Guided by the established relationship curve diagram between critical liquid production and crude oil mobility, the development plan is designed. As a result, the comprehensive water cut in the oilfield is 8.1%, and no water invasion has occurred; (3) Guided by the established relationship curve diagram between the cumulative liquid production and cumulative heat injection corresponding to different critical liquid production rates, adjustments were made to the oilfield development plan. As a result, the critical liquid production rate for well A1 increased from 110 t/d in the first cycle to 150 t/d in the second cycle.

Two-Dimensional Physical Model Experimental Study on Sweep Efficiency of Offshore Heavy Oil Hot Water Flooding

Abstract The conventional water flooding approach for the development of ordinary heavy oil faces challenges such as high injection-production mobility, rapid increase in water cut, and low final recovery. By using the temperature-sensitive properties of heavy oil, the viscosity can be effectively reduced, and the flow capacity within porous media can be enhanced by increasing the temperature of injected water. Onshore hot water flooding is primarily used to exploit the remaining oil potential during the later stages of steam stimulation, while offshore is used to enhance efficiency during the mid to late stages of water flooding. The key to the success of hot water flooding technology lies in the improvement of the sweep coefficient. Firstly, a two-dimensional physical experiment model is designed in accordance with the geological and reservoir characteristics of the target oilfield, based on the principle of similarity. Secondly, parameters that quantitatively characterize the development law of the plane temperature field, such as the effective sweep coefficient, regular factor, and plane expansion speed of the high-temperature region, are studied. Then, through two-dimensional experiments, the effects of injection medium, formation rhythm, and timing of hot water injection on sweep efficiency and temperature field development were discussed. Finally, on the basis of two-dimensional experiments, the effects of heat injection temperature, timing of heat injection, hot water injection speed, and high permeability strip on the improvement of sweep efficiency were quantitatively analyzed by numerical simulation. The results show that compared with hot water flooding, hot water composite flooding can increase the effective sweep coefficient from 15.05 % to 28.71 %. The anti-rhythm is helpful to the upward expansion of the high temperature zone, which can increase the oil displacement efficiency by 1.5 %. Water channeling can be effectively controlled by injecting hot water with low water cut. The increase of heat injection temperature is helpful to increase the proportion of high temperature heating area. The higher the injection speed, the greater the expansion speed of the heating chamber. The research results provide a direction for the development of heavy oil conventional water flooding to improve oil recovery in offshore heavy oil.

Development of Nanofluid-Based Solvent as a Hybrid Technology for In-Situ Heavy Oil Upgrading During Cyclic Steam Stimulation Applications.

This paper evaluates solvent-based nanofluids for in situ heavy oil upgrading during cyclic steam stimulation (CSS) applications. The study includes a comprehensive analysis of the properties and characteristics of nanofluids, as well as their performance in in situ upgrading and oil recovery. The evaluation includes laboratory experiments to investigate the effects of the nanoparticle's chemical nature, asphaltene adsorption and gasification, heavy oil recovery, and quality upgrading. The results show that alumina-based nanoparticles have a higher efficiency in asphaltene adsorption and catalytic decomposition at low temperatures (<250 °C) than ceria and silica nanoparticles. Specifically, alumina nanoparticles achieved asphaltene adsorption of 48 mg g-1, while ceria adsorbed 42 mg g-1. Alumina and ceria required around 90 and 135 min for 100% asphaltene conversion. Nanofluids were designed by varying nanoparticle and surfactant concentrations dispersed in naphtha, obtaining that the nanofluid containing 0.05 wt % of nanoparticles and 0.05 wt % of surfactant presents the highest yield in increasing API gravity by 5° and reducing oil viscosity by 90% in thermal experiments. Finally, the nanofluid was evaluated under dynamic conditions. The results show that nanofluid-based solvents can significantly improve the recovery and upgrading of heavy oil during CSS applications. When the steam injection technology was assisted by naphtha and nanofluid, 64% and 75% of the original oil in place were recovered, respectively. The effluents obtained in each stage presented lower API gravity values and higher viscosities for those obtained without a nanofluid. Specifically, the API gravity of the recovered oil rose from 11.9° to 34°, and the viscosity decreased to below 100 cP. The paper concludes by highlighting the potential of nanofluid-based solvents as a promising technology for heavy oil recovery and upgrading in the future.

Riedel shear structures reactivation may induce earthquakes through long-term steam injection: A case study of a heavy oil production field in northwestern China

Conventional heavy oil exploitation methods involve steam stimulation and flooding. An oil field in northwestern China has been producing heavy oil via steam injection for several decades. The production area has been seismically quiet until an increase in seismicity occurred several years ago. An array of 40 seismographs has been deployed between July and October 2021 to monitor seismicity and resolve the possible causes of the recent seismicity. Using an end-to-end machine-learning-based high-precision earthquake location workflow, we analyze a microseismic sequence comprised of 178 events that occurred in the study area. Numerical simulations incorporating Coulomb failure stress suggest that prolonged steam injection can reactivate faults and induce seismic events. Similarly, fluid diffusion through conduits may achieve the same effect. Analysis of the focal mechanism solutions of 21 strike-slip and thrust events with [Formula: see text] in conjunction with the background stress regime ([Formula: see text] azimuth = N15°W) reveal that the stress distribution is compatible with a left-lateral Riedel shear structure (RSS) model. Therefore, we can speculate that steam injection may induce earthquakes by reactivating preexisting RSS fault structures. To conclude, the recent seismic events could have been induced by two possible mechanisms: (1) long-term steam injection may cause the static stress level on the faults beneath the reservoir to build up to critical levels, following which a slight stress disturbance can trigger an earthquake and (2) fluid conduits may transport condensed water to basement faults, weakening the faults through fluid diffusion.

Effect of foaming agent to CO2 ratio on heavy oil recovery efficiency during steam stimulation

Heavy oil reservoirs generally have strong non-homogeneity. In this paper, firstly, physical simulation experiments of steam stimulation in straight wells were carried out to analyze the effects of the composite system of foaming agents and CO2 on the temperature field, oil production and water content. Secondly, the effects of foaming agents and CO2 on the steam stimulation efficiency of horizontal wells were analyzed using the horizontal well sand filling model. Finally, steam drive physical simulation experiments were conducted to analyze the effects of foaming agent and CO2 segment plug on formation pressure, recovery and water content. Results show that: after injecting CO2 + foaming agent into the vertical well for several cycles, the temperature field affected area increased significantly; Compared with foaming agent: CO2 = 2:1, for foaming agent: CO2 = 1:1, the swept area is more uniform and the recovery factor is higher.

Experimental and Numerical Simulation Study on CO2-Assisted Steamflooding in Ultraheavy Oil Reservoirs

Summary Certain ultraheavy oil reservoirs with depths approaching 1000 m feature wide well spacing. After cyclic steam stimulation (CSS), cold oil zones with high residual oil saturation exist between wells. This leads to a high oil saturation at the steam front during the subsequent steamflooding process, which in turn results in a high injection pressure. The simultaneous injection of CO2 and steam into the formation can optimize formation pressure and enhance steam utilization efficiency. A majority of laboratory-based experimental studies have reported favorable outcomes with CO2-assisted steamflooding. However, some field tests of CO2-assisted steamflooding have encountered severe steam channeling problems, resulting in oil recovery and an oil/steam ratio below the expected level. Consequently, this study uses an ultraheavy oil reservoir as a case study and integrates physical simulation with numerical simulation to investigate the impact of CO2-assisted steamflooding on enhanced oil recovery in ultraheavy oil reservoirs. The findings suggest that the beneficial effect of CO2 in reducing oil viscosity and injection pressure plays a significant role in models with smaller thickness, thereby improving oil production rate and recovery factor. However, as the thickness of the model increases, the adverse effect of CO2 exacerbating steam channeling becomes increasingly evident, leading to a decline in the oil recovery factor and a longer duration to reach the maximum recovery factor. Therefore, in field applications, it is essential to consider adjusting the CO2 injection method or using thermosetting plugging agents to achieve superior results.

Experimental investigation on cyclic steam stimulation assisted modified THAI to enhance oil recovery in steam-treated heavy oil

Steam injection is well accepted as a main method for heavy oil reservoirs. Currently, most heavy oil reservoirs have reached the late stage of steam treatment and encountered various challenges thus alternative methods are needed to develop the remaining oil. CSS1 Assisted Modified THAI2 (CSSAMT) is proposed to be an effective follow-up method in heavy oil reservoirs treated by steam. CSSAMT combines the benefits of ISC3 and steam, with steam acting as a protective agent for production wells threatened by combustion as well as a restrainer for oxygen breakthrough. A 3-dimensional physical model was conducted for the experiment to simulate the process and investigate the mechanism. The result demonstrates the feasibility of the CSSAMT process with a high oxygen availability of 99.8% and an average apparent H/C ratio of 0.71, achieving an oil recovery factor of 44.01%. Optimal steam injection parameters were determined as a 0.03 T (dimensionless time)-soak period followed by a 0.06 T production period. Additionally, oil upgrading results were quantitatively described through the carbon number variations, and a prediction formula correlating the sweep efficiency and the carbon number variations was proposed, showing a correlation coefficient of 0.9.

Investigating the heated zone evolution and production performance of cyclic steam stimulation with horizontal well in thick-layer heavy oil reservoirs

Cyclic steam stimulation with horizontal well (CSSHW) has emerged as an efficient commercial recovery technique for heavy oil reservoirs. Accurately calculating the evolution of the heated zone and the production performance closely linked to it is crucial for addressing the economic and environmental issues that arise in the CSSHW process. Most previous analytical or semi-analytical models have relied on the assumption of uniform temperature distribution and have focused on thin-layer heavy oil reservoirs. In this study, through analyzing the evolution of the heated zone in the CSSHW experiment, the study observes that the temperature distribution within the heated region is non-uniform and exhibits a centrally symmetric distribution with the wellbore as the axis. Then, a semi-analytical model was developed to predict the heated zone evolution and production performance of CSSHW for thick-layer heavy oil reservoirs. Next, the model was validated using field data and numerical simulation. Finally, this study analyzed the evolution of the heated zone under a multi-cycle mode and examined the effects of various factors on oil production. The results reveal that the heat, the area, and the average temperature within the heated zone all increase with the number of cycles attributed to the influence of residual heat. Single-variable analysis indicates that increasing BHP reduces the pressure differential, lowering oil production, and that permeability significantly affects oil production. Multivariate analysis shows that lowering BHP with constant steam amount improves COSR or thermal efficiency. Lower steam amount achieves higher efficiency in high vertical or horizontal permeability reservoirs, while higher BHP maintains high efficiency in such reservoirs due to better fluid mobility. The temperature-dependent threshold pressure gradient (TTPG) analysis reveals that although TTPG reduces oil production, the reduction lessens with more cycles. TTPG's impact varies with steam amount, BHP, and permeability; increasing steam enhances TTPG's effect in low vertical or horizontal permeability reservoirs, while higher vertical or horizontal permeability reduces TTPG's effectiveness. This article provides a tool for rapid optimization and performance forecasting in thick-layer heavy oil field applications.

Evaluation of the Pilot Test Effect of Steam Stimulation in Horizontal Wells of Sand Bodies 1-1308 in Bohai L Oilfield

In order to reduce the risk of large-scale thermal recovery of heavy oil in Bohai Oilfield, L Oilfield is selected to carry out horizontal well steam stimulation pilot tests. Previous studies have summarized the rationality of the injection parameters and initial production characteristics of this experiment, but the evaluation of its development effectiveness is still blank. Based on the study of the decline law of A23H well cold recovery using reservoir engineering methods, this article evaluates the initial production capacity, production increase effect, technical recoverable reserves, and throughput cycles of steam stimulation. The results show that the thermal recovery production of steam stimulation is three times that of cold recovery, which can significantly improve the production capacity of a single well. The initial daily oil production of two wells is 74m&amp;lt;sup&amp;gt;3&amp;lt;/sup&amp;gt;/d and 90m&amp;lt;sup&amp;gt;3&amp;lt;/sup&amp;gt;/d, respectively, which is 3.0 times and 3.6 times that of the initial production of cold recovery, exceeding the design level of the reservoir; The first round has the best yield increase effect, with an average daily oil increase of 31m&amp;lt;sup&amp;gt;3&amp;lt;/sup&amp;gt;/d, and gradually decreasing thereafter. By the fifth round, it was only 13m&amp;lt;sup&amp;gt;3&amp;lt;/sup&amp;gt;/d. In terms of yield increase multiples, each round can reach about 2 times; The technically recoverable reserves are 19.03 × 10&amp;lt;sup&amp;gt;4&amp;lt;/sup&amp;gt;m&amp;lt;sup&amp;gt;3&amp;lt;/sup&amp;gt;, requiring 8-9 rounds. Through this performance evaluation, we have strengthened our confidence in promoting the application of steam injection technology in Bohai Oilfield to achieve large-scale thermal recovery.

New Insights from an Old Method after History Matching a Newly Designed 1D Cyclic Steam Stimulation Experiment

New Insights from an Old Method after History Matching a Newly Designed 1D Cyclic Steam Stimulation Experiment

A prediction method of wellhead movement with consideration of interface debonding

The cementing cement all returns to the wellhead in offshore heavy oil thermal recovery wells, and the wellhead movement (WHM) still occurs frequently, indicating serious interface debonding between the casing and cement sheath during steam stimulation. Hence, a method for evaluating the bonding performance at the casing-cement sheath interface (CS interface) is proposed, by which the axial bonding strength, radial bonding strength, and friction coefficient at the CS interface are obtained. An elastic-plastic mechanical model of the casing-cement sheath-formation (CSF) system under temperature-pressure coupling is established to clarify the axial and radial bonding failure mechanisms at the CS interface. Based on the experimental results and mechanical model of the CSF system, the calculation method for the free casing and WHM model are established with consideration of cement return height (non-cementing section), cementing quality (poorly cemented section), axial bonding failure and radial bonding failure at the CS interface, by which the accuracy and reliability of this model have been verified by on-site data. The research results could provide a theoretical basis for real-time, intelligent, and scientific prediction of WHM.

Hybrid Technology Incorporated Into Colombian Heavy Oil Field Development Plan

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213199, “Incorporating Hybrid Technology of CSS and Foam in Heavy Oil Field Development Plans: Practical Experiences and Lessons Learned,” by Romel A. Perez, SPE, Hector A. Rodriguez, and Jorge E. Romero, Ecopetrol, et al. The paper has not been peer reviewed. _ A research and development project was conducted to study the use of preformed foams to improve cyclic steam stimulation (CSS). The field results showed benefits in incremental oil production, improvements in energy efficiency, and reduction in carbon intensity. Based on those outcomes, and with the goal of extending the production life of mature assets, the hybrid technology of CSS plus foam improvements was incorporated into the heavy oil field development plans of the Middle Magdalena Valley (MMV) basin in Colombia. Pilot Results: 2019–2022 CSS maturity is one of the major challenges in the MMV. Many wells report more than 10 steam cycles, decreasing oil productivity, and a trend of shorter steam cycles (less than 10 months). Most injected steam drained the higher-flow-capacity intervals based on the permeability contrast within the pay zone and openhole completions. Therefore, the bullhead injection of preformed foam improvements implemented before the steam cycle was proposed as part of a conformance strategy. The main goal of the pilot test was to demonstrate the efficiency of the hybrid technology, extend the production life of steam cycles, increase oil recovery, and improve energy efficiency and carbon footprint. The CSS pilot was implemented in six wells of the Teca-Cocorna field (Fig. 1). Performance was evaluated in terms of incremental oil, carbon intensity, and energy efficiency. A similar approach was proposed to evaluate energy efficiency and greenhouse emissions of CSS and hybrid CSS based on numerical simulations and the performance of two wells in Block D-80 in China. By the end of this stage, an incremental oil of approximately 32,000 STB was confirmed. Only one well recorded almost 50% of the total incremental oil of the pilot, and one well was only evaluated for 6 months because of a mechanical failure. Incremental oil recoveries and geochemical analysis confirmed the potential of this hybrid steam method to target unswept zones in idle or marginal wells operating since the 1980s. Additionally, the Teca-Cocorna pilot reduced carbon intensity and improved energy efficiency by 56% and 54%, respectively. The reduction of the carbon intensity from 83 (baseline) to 46 kg CO2/STB represents an important achievement in terms of environmental benefits and highlights the fact that the volume of natural gas used to generate steam was optimized by using less gas by extending steam cycles to a minimum of 9 months. In other words, the CCS/foam cycle can produce as much oil as two CCS cycles in the pilot wells.

Technology Focus: Heavy Oil (April 2024)

Heavy oil can be one of the more technically challenging resources to recover. It is often easy to find but hard to move. This creates an incentive for knowledge seekers and problem solvers: The puzzle pieces are on the table; we just need to put them together. The physical characteristics of heavy oil and the formations in which it is found—the puzzle pieces—are often unique to a region or even to a specific asset, so recovery techniques must be tuned, adapted, and sometimes invented for each region. Creative professionals around the world are taking up this challenge and sharing their work with us in a wealth of excellent recent publications. In particular in our featured papers, we see three different parts of the world working with three different recovery techniques. First, we have a fundamental study in paper SPE 212779 of a perennial question from Canada’s oil sands: Where does the emulsion form in the steam-assisted gravity drainage (SAGD) recovery process, where the effect of a surfactant is studied? Moving south to paper SPE 213199, we review a study that progresses from laboratory work to field implementation using foam injection in Colombia in conjunction with cyclic steam stimulation. From Colombia, we look across to the other side of the world to paper SPE 215943, where we see a transition from steamflood recovery to an adapted configuration of SAGD, with a comprehensive discussion on optimizing production in Mukhaizna field in Oman. The theme of adaptation and invention continues in our recommended reading, with discussions of fundamental research, applied and practical insights on field implementation, and all the steps in between as these are applied to heavy oil production challenges around the world. I hope you enjoy the tour. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212767 Part 1: Kinetics of Methane Exsolution From Bitumen in Thermal Recovery Processes—Experimental Study by Mohammad Khalifi, Imperial Oil Resources, et al. SPE 214113 Physical and Numerical Simulations of Offset Well Pair Combined Steam-Drive and Gravity-Drainage Process To Develop Superheavy Oil or Oil Sands Project by Guangyue Liang, China National Petroleum Corporation, et al. SPE 215342 Optimization of Chemical Acid Stimulation by Improving Selection Intervals in Lateral Section of Horizontal Well in X Field Heavy Oil Steamflood by Fatichin Fatichin, Pertamina, et al.

Investigating the Impact of Hydrocarbon Solvent on In-Situ Asphaltene Precipitation in Solvent-Assisted Cyclic Steam Technique

Summary Heavy oil recovery techniques often confront a significant challenge in in-situ asphaltene precipitation. This procedure significantly affects the characteristics of reservoirs and impedes optimal oil extraction. The purpose of this research was to examine how hydrocarbon solvents affect asphaltene precipitation occurring naturally in the reservoir as well as the resulting asphaltene content in processed oil. This was conducted using a laboratory-level dynamic model and the solvent-assisted cyclic steam stimulation (CSS) method. Throughout this experiment, which comprised six cycles, the steam-solvent blend’s pressure was consistently maintained close to 680 psi and the temperature was maintained at 500°F at the injection point. The findings revealed crude oil cracking at this temperature and noticeable in-situ asphaltene precipitation during the solvent-assisted CSS process. Notably, asphaltenes demonstrated mobility within porous media, contributing to their production in subsequent CSS cycles. Compared to a steam-only CSS control experiment, a higher asphaltene content in the original oil was observed, indicating that thermodynamic changes during the experiments likely caused asphaltene cracking. To sum up, this research provides an understanding of the effects of heavy oil recovery methods that rely on solvents on the precipitation of in-situ asphaltene and the content of asphaltene in the refined oil.

Integrated analysis of cyclic steam stimulation in a heavy oil reservoir: Microseismicity, brittleness, and landing height

We compare microseismic observations against pumping information, landing heights, and various well logs. The data were acquired during cyclic-steam injection between September 2002 and December 2005. Ninety-five percent of the microseismicity occurred during injection and in the overburden; 70% of the events happened during the first cycle. Microseismicity in the overburden is likely caused by a greater brittleness than in the reservoir and a cluster of microseismic events in regions with a smaller landing height, thereby facilitating dry cracking due to the volumetric expansion of the reservoir. Yet, other areas with equally shallow landing heights displayed little to no microseismicity, pointing to an inhomogeneous steam front. Furthermore, recorded microseismicity is subject to the Kaiser effect in that event rates are low in subsequent cycles until the current injection pressure exceeds the previous maximum, explaining why 70% of the events occurred during the first cycle and possibly why microseismicity during production accounted for only 5%. Microseismicity in brittle formations can be caused by pore-pressure variations (wet cracking) and/or changes in the total stresses (dry cracking). Identification of pore-pressure variations in the overburden is important because it may indicate containment challenges. Analysis of the growth rate of the microseismic cloud combined with the shallow landing height indicated dry cracking to be more likely than wet cracking but analysis of additional data is required to strengthen this conclusion.

Ground deformation due to natural resource extraction in the Western Canada Sedimentary Basin

The study links multiple natural resource extraction activities in the Western Canada Sedimentary Basin (WCSB) with observations of ground deformation. Sentinel-1, RADARSAT-2, and RADARSAT Constellation Mission (RCM) Synthetic Aperture Radar (SAR) data acquired as early as 2015 were used to compute deformation maps and ground deformation time series. Ground deformation produced by induced earthquakes (2015 Mw 4.6 in British Columbia and 2022/23 Mw 5.1/4.6 in Alberta; and 2017/18 Mw 5.0/4.2 slow slip events in British Columbia) were mapped with individual interferograms. Long-lasting ground deformation due to Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) enhanced oil recovery and coal and potash underground mining were mapped with the Multidimensional Small Baseline Subset (MSBAS) time series method. When both ascending and descending data were available, MSBAS was used to compute two-dimensional (2D) deformation time series and rates. It was observed that seismic and aseismic ground deformation due to hydraulic fracturing and saltwater injection in WCSB had a similar surface expression (paired anomaly), spatial extent (5-10 km) and orientation (striking NW-SE), suggesting that triggering processes might be technogenic. In the case of hydraulic fracturing, ground deformation appeared soon after the beginning of the operation, while not with saltwater injection, as it took years. The source mechanism of the 2015 Mw 4.6 earthquake was obtained through inverse modelling of the two descending interferograms. The rectangular source model corresponded to a fault at 1.98 ± 0.09 km depth, with 126° ± 7° strike, 14° ± 2° dip, 72° ± 7° rake, 1.61 ± 0.24 km width, 2.54 ± 0.23 km length, and 0.19 ± 0.07 m slip. In the case of in-situ enhanced oil recovery, ground deformation varied significantly depending on the technique. Continuous uplift observed at the SAGD site had a rate of only about 0.05 m/year, while reversible uplift and subsidence at CSS sites exceeded 0.2 m/month, even though wells in both cases were located at approximately similar depths (380 m for SAGD vs 520 m for CSS). In the case of underground mining, the spatial extent of subsidence depended on the extraction depth (200-500 m for coal vs 1000 m for potash). When a mining operation was conducted in an area with topographic relief, horizontal deformation was observed in addition to subsidence. Various observed deformation signals may precede more consequential deformation events.

Defining the Ideal Range for Reducing Oil Viscosity and the Optimal Rate of Steam Injection for a Heavy Oil Field

Heavy oil reservoirs often lend themselves well to thermal enhanced recovery techniques. Traditional methods like primary production or water injection are less effective due to the high viscosity of the oil. Steam stimulation primarily aims to elevate the reservoir's temperature, thereby reducing the oil's viscosity and improving its flow properties. Steam injection stands as one of the most prevalent thermal recovery methods, commonly applied in heavy oil reservoirs. The primary goal is to validate the process for selecting suitable reservoirs, the physical mechanisms involved, and the simulation characteristics essential for steam recovery. This study establishes the optimal multiplier for reducing oil viscosity and the ideal steam injection rate for heavy oil fields.

Study on the influence of steam state on seepage, production, migration and deposition of offshore heavy oilfields

In this paper, the influence of steam state on seepage, production, migration and deposition are refined, and the superiority of superheated steam is confirmed. Firstly, the relative permeability of oil-water and oil-steam in offshore cores was measured to analyze flowing characteristics. Then the cyclic steam stimulation of long core was conducted with supersaturated, saturated and superheated steam, and the recovery capacity was quantified, the difference in composition of produced oil was analyzed. Finally, the CT scanning and digital core 3D reconstruction were performed to visualize the influence of steam state on migration of heavy oil components. The results show that the temperature has a significantly higher effect on seepage capacity than permeability, which can effectively broaden the co-seepage range and reduce residual oil saturation. The total recovery of superheated steam is 12 % and 7 % higher than the other two steam respectively, and the main recovery cycle is the former four rounds, which accounts for over 85 % of total recovery. The retention of heavy components can reduce porosity by 4 %∼7 %, superheated steam can alleviate blockage and increase the porosity by over 2 %. This work is expected to provide valuable insights into the application of superheated steam in offshore heavy oilfields.

Efficiency estimation of super-viscous oil recovery by in-situ catalytic upgrading in cyclic steam stimulation: from laboratory screening to numerical simulation

The article provides an overview of ion-modified waterflooding technology, also known as low salinity, controlled salinity, or Smart water. This technology is currently considered one of the most promising approaches in the development of oil deposits in carbonate reservoirs due to its economic efficiency and environmental safety. The article discusses the main mechanisms and processes underlying ion-modified waterflooding and presents the results of laboratory studies conducted on core samples from foreign oil deposits. It includes an analysis of several studies, including contact angle measurements and core flooding experiments on core samples from oil deposits in carbonate reservoirs on the eastern side of the Melekess depression in the Republic of Tatarstan. It is important to note that the Vereyian deposits explored in this article are not a typical example of test objects for ion-modified water injection. This is because they are characterized by a low reservoir temperature of 23 °C, which suggests that the efficiency of the technology would likely be lower compared to studies conducted abroad, where reservoir temperatures were significantly higher. For example, Darvish Sarvestani et al. studied reservoir conditions at 90 °C, Yousef et al. – reservoir temperature of 100 °C, and Austad et al. examined the Ekofisk field at 130 °C and the Volhall field at 90 °C in Norway. However, as several studies have indicated, prolonged contact between rock samples and ion-modified water contributes to significant hydrophilization of the rock surface, as confirmed by contact angle measurements. The contact angle decreases from approximately 138.3° to 53.45° after exposure to ion-modified water. Additionally, the core flooding experiment demonstrated a slight increase in the oil displacement coefficient, reaching 9.2%. These findings suggest the potential for enhanced oil recovery by injecting Smart water into the Vereyian sediments, although further research is required to confirm the underlying mechanism.