Thermal Enhanced Oil Recovery Research Articles

Innovative approaches in enhanced oil recovery: A focus on gas injection synergies with other EOR methods

Enhanced Oil Recovery (EOR) techniques have become crucial in extending the productive life of mature oil fields and maximizing resource extraction. Among these, gas injection methods, particularly those involving CO₂, nitrogen, and hydrocarbon gases, have shown significant promise. This review focuses on the innovative synergies achieved by combining gas injection with other EOR methods to enhance recovery efficiency and economic viability. Gas injection techniques work by increasing reservoir pressure and reducing oil viscosity, facilitating easier flow and extraction. When integrated with other EOR methods such as thermal, chemical, and microbial techniques, the synergistic effects can lead to even greater enhancements in oil recovery. For instance, the combination of gas injection with thermal EOR, like steam injection, can improve the displacement of heavy oils by simultaneously reducing viscosity and enhancing thermal conductivity within the reservoir. Similarly, integrating gas injection with chemical EOR methods, such as polymer flooding, can optimize the sweep efficiency by leveraging the mobility control provided by polymers and the pressure maintenance by gases. Recent advancements in monitoring and simulation technologies have further improved the effectiveness of these combined approaches. Real-time reservoir simulation and 4D seismic monitoring allow for precise tracking of gas and fluid movements, enabling dynamic adjustments to injection parameters for optimal performance. Smart well technologies, equipped with advanced downhole sensors, provide continuous data on reservoir conditions, facilitating more responsive and adaptive EOR strategies. However, these innovative synergies are not without challenges. Economic feasibility remains a significant concern, particularly given the high costs associated with gas procurement and the integration of multiple EOR techniques. Additionally, managing the complex interactions between different EOR methods and heterogeneous reservoir conditions requires sophisticated modeling and robust operational protocols. In conclusion, the integration of gas injection with other EOR methods offers a promising pathway to enhance oil recovery rates and extend the lifespan of mature reservoirs. Continued research and development, coupled with cross-industry collaboration, are essential to overcoming the economic and technical challenges associated with these innovative approaches. This review underscores the potential for gas injection synergies to revolutionize EOR practices and drive sustainable growth in the oil and gas industry.

Forecasting the efficiency of waterflooding, thermal and chemical enhanced oil recovery methods in Bobrikovian reservoirs

The development of reserves contained viscous and highly viscous oil poses one of the major challenges in modern reservoir engineering. The poor performance of conventional waterflooding prompts the application of enhanced oil recovery (EOR) methods, of which thermal and chemical EOR are considered the most efficient. Reservoir simulation is a powerful tool for evaluating EOR performance. Serial runs of a history-matched model of a Bobrikovian reservoir are used to evaluate the incremental oil production due to each EOR technique and formulate the efficiency limits of the process performance criteria. In contrast to previous studies that evaluated EOR applications using reservoir simulation modeling, an entirely new quality model is derived through automatic history matching performed by solving an inverse problem. Another novel feature is the automated selection of the optimum field development scenario given a user-defined objective function. Evaluating the performance of hot water injection in a Bobrikovian reservoir suggests that this technology yields positive effects when the injected water temperature ranges from 50 °C to 90 °C. The surfactant–polymer flooding method is also investigated. The largest incremental oil production with a constant surfactant concentration of 0.5% is observed for a polyacrylamide concentration of 0.25%, which can be attributed to a water cut reduction due to plugging the well-drained and flushed reservoir zones. The greatest incremental oil production is achieved when injecting 1.5% surfactant and 0.25% polyacrylamide. The highest efficiency per ton of injected chemicals is obtained when injecting 0.5% polyacrylamide and 0.10% surfactant. Keywords: High-viscosity oil; EOR; thermal methods; surfactant-polymer flooding; reservoir simulation; history matching; injection simulation scenario.

Prospects and current state of chemical EOR methods applied in Kazakhstan

At present, at almost all fields of the Republic of Kazakhstan the main technology of oil recovery enhancement is the traditional method of waterflooding of productive formations. Many oil and gas fields in Kazakhstan are at a late stage of development and are categorized as «mature» fields. In the global experience of mature field development, the key focus is on the application of enhanced oil recovery (EOR) techniques - chemical, thermal, gas and microbiological methods. This paper considers the application of chemical EOR at a number of Kazakh fields such as Zaburunye, North Buzachi, Kalamkas, East Moldabek. As the results of the pilot studies have shown, the most effective EOR here is the application of polymer flooding. It should also be noted that polymer flooding is successfully applied in Kazakhstan for high-viscosity oil fields such as North Buzachi (oil viscosity 316-417 mPa·s), East Moldabek (oil viscosity 246-377 mPa·s). In this case, water cut, smoothing of injectivity profile and, as a result, increase of oil production is achieved. Successful application of the technology largely depends on the parameters of physical and chemical impact at each stage - the volume of injection of gel-polymer composition, concentration of ingredients, the flow rate of filtered water, the presence and linear size of cracks, the permeability of pore channels and etc. Polymer flooding applied in Kazakhstan showed its technological and economic efficiency on the example of pilot tests, laboratory studies, which reduces water cut and increases oil production. Widespread use of EOR methods would allow increasing recoverable oil reserves by at least 5-10 %. Keywords: Enhanced Oil Recovery (EOR); gas Injection; hydrocarbon recovery methods; chemical EOR methods; thermal EOR methods; oil production; polymer flooding; oil recovery.

Machine Learning Techniques in Enhanced Oil Recovery Screening Using Semisupervised Label Propagation

Summary Efficiently choosing the optimal enhanced oil recovery (EOR) technique is a critical requirement in reservoir engineering. Machine learning (ML) methods, with a well-established history of application, serve as a swift and dependable tool for EOR screening. In this paper, we aim to evaluate the effectiveness of various ML algorithms for EOR screening, utilizing a comprehensive database of nearly 1,000 EOR projects. This study delves into a comprehensive evaluation of regression and classification-based algorithms to develop a reliable screening system for EOR predictions and address challenges such as limited labeled data and missing values. Our analysis considered various EOR processes, including gas injection, chemical, and thermal EOR techniques. Various ML methods such as random forest (RF), K-nearest neighbors (KNN), support vector machine (SVM), shallow artificial neural networks (SANN), naive Bayes classifier (NBC), logistic regression (LR), and decision tree (DT) are applied, enabling both intermethod comparisons and evaluations against advanced methods, multiobjective deep artificial neural networks (MDANN), and multiobjective artificial neural networks (MANN). These advanced techniques provide the unique capability to concurrently address both regression and classification tasks. Considering that conventional methods can only be implemented on a single task, the RF, MANN, MDANN, and KNN algorithms demonstrated top-tier performance in our classification analysis. Regarding the regression task, KNN, RF, and MDANN displayed exceptional performance, signifying their prowess in predictive accuracy. However, MANN exhibited moderate performance in regression analysis. In addition, our study identified areas where certain algorithms, such as support vector regression (SVR), exhibited weaker performance, highlighting the importance of comprehensive model evaluation. This paper contributes novel insights into the application of ML techniques for EOR screening in the petroleum industry. By addressing challenges such as limited labeled data and missing values and by providing a thorough evaluation of various ML algorithms, our study offers valuable information for decision-makers in the oil and gas sector, aiding in the selection of suitable algorithms for EOR projects. In addition, the use of semisupervised label propagation and advanced techniques like KNN imputation adds to the existing body of literature, enhancing the state of knowledge in this domain.

Nanotechnology Applications in Enhanced Oil Recovery (EOR)

Enhanced Oil Recovery (EOR) techniques are crucial for maximizing crude oil extraction from reservoirs, especially when traditional methods leave significant amounts of oil untapped. Recent advancements in nanotechnology have introduced innovative solutions to longstanding challenges in the oil industry. This research paper explores the application of nanotechnology in EOR, emphasizing the unique properties of nanoparticles that make them highly effective in this context. Nanoparticles, defined by their nanometer-scale dimensions, exhibit high surface area to volume ratios, quantum effects, and enhanced reactivity. These properties enable various mechanisms in EOR, including improved wettability, reduction in interfacial tension, enhanced thermal stability, selective plugging and fluid diversion, and catalytic effects. The study details how silica and titanium dioxide nanoparticles can modify rock surface properties, leading to better water imbibition and oil displacement. It also discusses how surfactant-coated nanoparticles can reduce the interfacial tension between oil and water, facilitating easier oil flow. Furthermore, the research highlights the role of metal oxide nanoparticles, such as aluminum oxide and zinc oxide, in enhancing thermal conductivity and stability during thermal EOR methods like steam flooding. The ability of polymer-coated nanoparticles to selectively plug high-permeability zones and redirect injection fluids is examined, demonstrating how this can lead to a more uniform sweep and higher oil recovery. The catalytic properties of certain nanoparticles, such as iron oxide, are also explored for their potential to promote in-situ chemical reactions that generate gases aiding oil displacement. Field applications and case studies underscore the practical benefits of nanotechnology in EOR. Examples include the use of silica nanoparticles in Middle Eastern oil fields, polymer-coated nanoparticles in Canadian heavy oil reservoirs, and iron oxide nanoparticles in Indian oil fields. These case studies have shown significant increases in oil recovery rates and operational efficiencies. However, the research also identifies several challenges that must be addressed for the widespread adoption of nanotechnology in EOR. These include the high costs and scalability issues associated with nanoparticle production and deployment, potential environmental and health risks, and the need for customized solutions to cater to the unique conditions of different reservoirs. In conclusion, while nanotechnology presents promising advancements in EOR through various mechanisms, overcoming challenges related to cost, scalability, and environmental impact is crucial. As research progresses, nanotechnology is poised to play a vital role in enhancing oil recovery and meeting global energy demands.

Exploring in-situ combustion effects on reservoir properties of heavy oil carbonate reservoir

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage.In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Determination of the main technological parameters of cyclic-steam stimulation of oil reservoirs with account of heat losses along the borehole

Due to the decline in light oil reserves, the development of high-viscosity oil fields has become more relevant today. One of the most common methods of thermal enhanced oil recovery is cyclic-steam stimulation. Compared to other techniques, this method has an advantage of providing higher thermal efficiency due to selection of its parameters with account of variations in the basic properties of a heat carrier as it moves towards the well bottom. The purpose of this work is to create a method for rapid assessment of optimal technological parameters of cyclic-steam stimulation, in which the temperature distributions along boreholes obtained from geophysical research are used as initial data. The created method allows determination of the time of hot carrier injection, steam soak and oil production. The scientific novelty of the study refers to the fact that an integrated approach relating the problem of hot carrier transportation with the problem of determination of optimal parameters for reservoir treatment is proposed for the first time. The cyclic-steam stimulation process is described by the equations of mechanics of multiphase systems. Euler’s method is used to solve the resulting system of equations. The paper presents: functions of depth-wise distributions of pressure, temperature and velocity and dryness fraction of steam; temperature distribution in the multilayer wall of the well and in the rock (considering a specified heat transfer between the layers of the well materials, water and rock at known temperatures); optimal values of the time of hot carrier injection, steam soak and oil production. The calculations have shown that, due to the in the layer of basalt fiber, the temperature in the multilayer wall of the well decreases within 80%. The maximum value of additional cumulative oil recovery has been established by analyzing the calculated bottom-hole parameters of the heat carrier.

Local thermal equilibrium constraints for energy transport equations for thermal oil recovery processes

The mathematical framework of reservoir thermal simulators typically relies on the assumption of local thermal equilibrium (LTE) when modeling energy transport through porous media for petroleum engineering applications, including Thermal Enhanced Oil Recovery (TEOR) processes. The LTE presupposes instantaneous exchange of energy between the injected hot fluids and the reservoir's rock and fluids. Nevertheless, it is essential to acknowledge that LTE's validity becomes questionable in specific scenarios, potentially resulting in an overestimation of oil recovery, e.g., when high fluid velocities arise. Under such conditions, the local thermal non-equilibrium (LTNE) formulation may offer a more accurate representation of the energy transport physics. In this study, we present the physical constraints that must be satisfied for the application of two distinct mathematical formulations (1) the one-equation model for the fluids and rock as a whole (LTE is assumed), and (2) the two-equation model, one equation assigned to the fluids and another one to the rock (pseudo-LTNE is assumed). Such constraints were derived by examining conductive and convective heat transport properties via the theory of the method of volume averaging, specifically applied to an oil-water-gas-rock system at the pore scale. It was found that the one-equation model requires that 18 physical constraints to be satisfied, while the pseudo-LTNE model needs to fulfill 9 physical constraints. A sensitivity analysis was conducted based on factor upon which accumulation, conduction and convection constraint equations depend, aiming to identify the conditions under which LTNE occurs within the porous medium. These influencing factors encompass the characteristic time, the Peclet number, the presence of external heat sources, the distribution of phases at the pore-scale, and the disparity between rock and fluid properties. The combinations of these factors can induce the existence of local thermal non-equilibrium. One significant property is the heat transfer coefficient in the reservoir. We recommend that the pseudo-LTNE approach is reliable as long as the rock-fluid heat transfer coefficients are at least one order of magnitude larger than the fluid-fluid heat transfer coefficients (1000−10000W/(m3K)). Contrarily, the OEM should be employed only when the heat transfer coefficients surpass a threshold value of 10000W/(m3K). When injector and producer wells are hydraulically interconnected, resulting in heightened fluid velocities, it is encouraged the use of the two-equations model. The predictability and reliability of the energy models were verified by comparison of predicted oil recovery against data from laboratory experiments. The equations presented in this study consistently demonstrate their utility in assessing the reliability of energy transport models for TEOR scenarios.

Molecular insights into the synergistic mechanisms of hybrid CO2-surfactant thermal systems at heavy oil-water interfaces

A hybrid thermal recovery process is a promising EOR (Enhanced Oil Recovery) method and has been widely applied to post-steamed heavy oil reservoirs. Due to the complexity of High Temperature and High Pressure (HTHP) reservoir environments, Molecules Dynamics (MD) simulations are conducted to investigate the interfacial behavior between multiphase multicomponent fluids and heavy oil over a wide temperature range. We select CO2 and a cost-effective anionic surfactant, SDS (Sodium Dodecyl Sulfate), to build hybrid thermal systems. The interfacial behavior in different systems is characterized by the local density distribution, cluster analysis, hydrogen bond characters, solvent accessible surface area, and interaction energy. Systematic MD simulations reveal a two-step interfacial tension (IFT) reduction process stimulated by thermal migration. Both CO2 and SDS can achieve an IFT decrement with different mechanisms. Moreover, a co-addition of CO2 and SDS can further efficiently reduce the IFT. Average Reduced Density Gradient (aRDG) results reveal that a unique asphaltenes-SDS-CO2 structure improves the interfacial activities and mobility of the heavy oil phase through a bidirectional mass exchange mechanism, which ultimately realizes the most significant IFT decrement. Furthermore, an optimal concentration (10C–20S) in a hybrid thermal system is recommended because of its balanced performance. This work sheds insight into the synergistic effects of multiphase multicomponent thermal fluids on hybrid thermal systems, which will guide future field applications of hybrid thermal EOR processes.

CALCULATION OF THE BOTTOM-HOLE PARAMETERS OF THE HEAT CARRIER DURING ITS MOVEMENT ALONG THE WELLBORE OF A DIRECTIONAL WELL CONSIDERING THE FLOW STRUCTURE

Link for citation: Gilmanov A.Ya., Rodionova A.V., Shevelev A.P. Calculation of the bottom-hole parameters of the heat carrier during its movement along the wellbore of a directional well considering the flow structure. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 8, рр. 121-128. In Rus. The relevance of the research is caused by the need to involve fields with high viscosity oil in the development, since fields with low and medium viscosity oil are depleted. Oil viscosity directly depends on the temperature, therefore, thermal enhanced oil recovery methods are used to reduce the viscosity. From the point of view of using the heat injected into the formation, the most effective thermal method is the cyclic steam stimulation, i. e. cyclic steam injection into the well. However, when steam moves through the pipe, it condenses, that is why the production at the well bottom-hole are often has high water cut. Accurate calculation of the heat carrier parameters along the entire wellbore will help to avoid this problem. The main aim of the research is to determine the effect of the well inclination angle, steam quality at the wellhead, initial pressure and thermal conductivity of thermal insulation on the heat carrier characteristics in the wellbore, considering flow modes. Objects of the research are deposits with high-viscosity oil. Methods: physical and mathematical modeling of injection of a two-phase (steam-water) heat carrier into the reservoir based on the laws of conservation of mass, momentum and energy, considering the movement of the heat carrier along the wellbore of a directional well, heat loss through the walls of the well and fluid flow modes. Results. The calculation of the steam quality and heat carrier flow rate along the wellbore of a directional well was conducted. The influence of the well inclination angle on the parameters of the heat carrier at the well bottom-hole (steam quality, pressure and wellhead flow rate of the heat carrier) is analyzed. It is determined that the smaller the well inclination angle, the deeper the steam penetrates through the depth of the formation.

Assessment of the theoretical models of effective thermal conductivity based on digital rock physics for clean sandstones

Knowledge of the effective thermal conductivity (ETC) of porous media provides valuable insights into the heat flow and profoundly affects the feasibility analysis of thermal enhanced oil recovery methods and geothermal field development. Theoretical assessment of ETC based on structural properties of the porous medium and various simplification assumptions by prediction models have shown acceptable results towards ETC quantification; however, their applicability must be investigated further due to the availability of various types of such models. In this study, we first employed a digital rock approach to simulate the heat conductivity of micro-CT images of 10 clean sandstone samples using Avizo software in different directions for evacuated, air-saturated, and water-saturated conditions. The filtered and segmented images were applied to perform voxel-based ETC simulations under steady state condition. Then, the simulation results were compared to the computed ETCs for each sample by 11 theoretical models. Two well-known thermal conductivity bounds, i.e., Hashin and Shtrikman bounds and Wiener bounds were used to confirm the validity of models and simulation outputs. It was shown that the Haung model generates the best outputs for vacuum (MAPE = 0.08 and RMSE = 0.37) and air-saturated (MAPE = 0.07 and RMSE = 0.32) states. While the water-saturated condition was competently predicted by the Ribaud model (MAPE = 0.05 and RMSE = 0.31). The overall analysis indicated that the Haung model is the best model for the prediction of ETC in all three pore-filling states for clean sandstones.

Workflow of the In Situ Combustion EOR Method in Venezuela: Challenges and Opportunities.

In situ combustion (ISC) is one of the oldest thermal enhanced oil recovery methods to have been applied in Venezuela to increase the production of highly viscous crude oils, with a first field application in 1959 in the Tia Juana Field-Lake Maracaibo Basin. This method, which is characterized by high energy efficiency, consists of injecting air into the reservoir where exothermic oxidation reactions initiate to increase the mobility of the oil. Compared to other thermal enhanced oil recovery methods such as steam injection, ISC has a lower environmental impact in terms of water and fuel consumption, and emission of gases as the produced gases can be reinjected or stored. Several ISC projects have been carried out in Venezuela in Tia Juana, Morichal, Miga, and Melones fields. Although the technical results have been satisfactory in terms of viscosity reduction and improved crude oil properties (such as °API), other important aspects of project evaluations have not been convincing due to the following factors: high temperatures in producing wells, acid gases management, generation of complex emulsions, corrosion, and high CAPEX and OPEX costs. Nevertheless, additional research work has been conducted on process optimization, using catalysts and hydrogen donors, to better address these other factors. Due to the great need to increase hydrocarbon production in Venezuela and to the advantages of ISC as an upgrading technique where low-carbon fuels and hydrogen as byproducts are generated, this paper presents a revisit of ISC projects in Venezuela from R&D technical aspects to field applications. It seeks to identify the main insights regarding the success and failure of the evaluated projects and make substantiated recommendations in the case of future applications of this technology.

Biot-consistent framework for wave propagation with macroscopic fluid and thermal effects

SUMMARY In principle, wave propagation in porous media can simultaneously trigger macroscopic fluid flow and thermal flow, which can be described by Biot's poroelasticity and Lord–Shulman thermoelasticity, respectively. The physical processes of those effects are significantly different, but phenomenologically, they can lead to identical wave attenuation and dispersion and are hard to be distinguished. By using Biot's virtual concept entropy flow, the Biot-consistent General Linear Solid (the GLS) framework and matrix notation, a rigorous and convenient tool is provided to reveal the similarities and disparities between poroelasticity and thermoelasticity. By using the same framework, a Biot-consistent thermo-poroelastic model is proposed to consider macroscopic effects of fluid and thermal flows simultaneously in an elegant way. These similarities allow us to directly translate many of the available results in poroelasticity to thermoelasticity and vice versa by a simple change of notation. The disparities indicate a fundamental difference in physical mechanisms. Plane-wave analysis shows that the primary P-wave modes of thermoelasticity and poroelasticity are all GSLS-equivalent (Generalized Standard Linear Solid) and can be identical if the model parameters are selected properly. However, the corresponding slow-wave modes have significantly different phase velocity dispersion although the attenuation spectra of which are identical. Such a surprising result can be explained by the GSLS non-equivalence of the slow-wave modes and the fundamentally different mechanisms. As expected, the thermo-poroelastic model predicts four wave modes, which are the fast- and slow-P, temperature (T wave) and S waves. Two attenuation peaks due to, respectively, the thermal- and fluid-flow effects are predicted for the fast-P wave. The slow-P wave mode due to fluid flow is influenced by the thermal effects, but the T wave seems unaffected by the fluid flow. The thermo-poroelastic model is then applied to laboratory observations at 200–106 Hz for the brine-saturated tight sandstone under 35 MPa effective pressure. The unified model provides a convenient framework for studying geothermal exploration, thermal-enhanced oil recovery and other applications involving temperature variations within the porous rock.

Steamflood Injection Performance on 2 Types of Sand Heterogeneity in XYZ Field

Steamflood is one of the best thermal enhanced oil recovery methods to improve heavy oil production. This project focuses on the benchmarks of steamflood performance in two types of sand: homogenous and heterogeneous formations in the XYZ field. The co-kriging technique was implemented to generate the porosity and net to gross distribution. Afterward, twelve designs of experiments were run to obtain the oil production information and analyze the affecting factors of steamflood performance on each sand. The findings showed that clean sand provided higher oil production compared to the fining sand. Additionally, the well spacing had a higher contribution compared to the steam quality in applying steamflood injection. This study could serve as a guideline for engineers for planning the well spacing and steam quality utilization in steamflood injection in these two types of sand formation that contain heavy oil reserves.

Effective parameters on in-situ oil upgrading with nanocatalyst in large scale: Kinetics modeling

Thermal enhanced oil recovery (EOR) methods are the main techniques used to produce oil from heavy oil reservoirs. But this methods are associated with environmental challenges and do not reduce viscosity permanently. One of the new methods with less environmental challenges that can permanently improve oil quality and enhanced oil recovery is the in-situ oil upgrading with nanocatalyst. In the present study, effectiveness of the in-situ oil upgrading with nanocatalyst in improving the quality of oil and increasing the oil production have been investigated at a large-scale heavy oil reservoir with the aid of STARS simulator. Reactive flow was considered in the simulation by kinetic modelling of a reaction network with 5 pseudo-components. Also, effect of temperature and type of oil have been studied. Details on how to carry out reactions and changes in oil components over time have been investigated. In addition, steam flooding and in-situ oil upgrading with nanocatalyst were compared from the point of view of the amount of released CO2 gas and the required water. The results show that in-situ oil upgrading with nanocatalyst is a time-consuming process and causes a 40% increase in the cumulative production and 23.58% decrease in the density compared to the steam flooding.There is an optimum temperature (300 °C) for the in-situ oil upgrading process with nanocatalyst at which the maximum amount of oil is produced and has a better recovery on heavier oils. The major part of VR is converted into distillate in the heavier oil, while in the lighter oil, the dominant reaction was conversion of VR to VGO. In addition, in-situ oil upgrading with nanocatalyst reduces the required water and emission of CO2 compared to the steam flooding method and among the three factors of injection flow rate, temperature, and steam quality, the most effective factor to reduce environmental problems with the help of in-situ oil upgrading with nanocatalyst is injection flow rate.

Thermal energy storage biogel with good biodegradability for solar energy powered heavy oil recovery

For cleaner production of heavy oil with lower fossil fuel consumptions, solar thermal enhanced oil recovery (Solar TEOR) technologies are increasingly researched nowadays. However, the intermittency of solar radiation and inferior energy efficiency of steam flooding restricted industrial applications of Solar TEOR methods in oilfield. In this work, the eutectic NaCl–KCl and graphite were loaded into the biomass gelling matrix (crosslinked methylcellulose network) through supramolecular interactions. Then, a thermal energy storage biogel (NaCl–KCl)@G/MC with high thermal conductivity (2.06 W m−1·K−1), latent heat storage capacity (melting enthalpy: 112.4 J g−1 at 352.4 °C) and thermal reliability (melting enthalpy retention up to 94.4% after 30 cycles), was synthesized for improving the continuousness of solar thermal supply and energy efficiency of steam flooding. From the experimental results, the proposed oil recovery method — solar powered steam flooding in daytime + the thermal-storage biogel heated N2 flooding in nighttime — can meet the all-weather 24/7 production of heavy oil and improve energy efficiency (oil-steam ratio and thermal efficiency up to 0.56 and 62.1%). With (NaCl–KCl)@G/MC biogel assistance, energy consumption of oil production was decreased from 153.1 J·(mL oil)−1 to 9.9 J·(mL oil)−1 as the cost reduction of 19.8% in comparison with intermittent solar steaming. This study offers a candidate design to achieve a continuous thermal recovery of heavy oil entirely powered by solar energy, promoting the solar thermal technologies in oil industry operations.

Macroscopic mechanical properties of fluid-saturated sandstone at variable temperatures

Rocks can be viewed as composites of solid minerals with pores or cracks filled with softer material such as pore fluids, kerogen, bitumen, and other organic matter. The mechanical properties of highly viscous soft phases are highly sensitive to ambient temperatures and lead to temperature-dependent static and dynamic observations with the composite rock. However, the constituents operate by forming some effective (averaged) mechanical properties of the composite rock, and yet these averaged properties are still little known. To reveal such macroscopic temperature-dependent mechanical properties and measure their values in rock samples, a double-porosity model of porous rock with nonlinear viscosity is developed. The model is based on rigorous continuum mechanics with physically meaningful, real-valued, and time- and frequency-independent material properties and elegantly unifies the existing frequency-dependent microscopic squirt flow and mesoscopic wave-induced fluid flow models. The approach is used to accurately model the broad attenuation peaks and Young’s modulus dispersion observed in previously published laboratory experiments with glycerol-saturated Berea sandstone and invert for its mechanical properties. The observations are explained as mainly due to the temperature-dependent elastic coupling caused by non-Newtonian fluid within microcracks. Several hitherto unknown mechanical properties of the rock are constrained quantitatively: the average porosity of the microcracks, the effective high-pressure bulk modulus of the drained frame, the internal stiffness defect within the rock frame, the solid viscosities associated with bulk and shear deformations, and an exponent of nonlinearity for viscosity. These parameters constitute a Biot-consistent mechanical model of the rock, which can be used to simulate its behavior in arbitrary experimental environments. The rigorous first-principle model can be used in many applications: detailed and physically accurate interpretations of laboratory experiments, numerical wavefield simulations and seismic data inversion, reservoir characterization, geothermal exploration, thermal-enhanced oil recovery, and exploration for deep oil and gas resources in high-temperature environments.

Study Reviews Technologies, Work Flows in Heavy Oil Reservoir Management

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209328, “Heavy Oil Reservoir Management—Latest Technologies and Work Flows,” by Hakki Aydin, SPE, Middle East Technical University; Nirup Nagabandi, Incendium Technologies; and Cenk Temizel, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. _ Successful heavy oil reservoir management practices are built on analyzing and accurately predicting reservoir behavior over time. Given the complex nature of heavy oil reservoirs, including geomechanical properties and fluid-flow behavior, a need exists to develop a repeatable technique that can account for these complexities within an acceptable margin of accuracy. The objective of the complete paper is to conduct a comprehensive review of recent technologies and work flows developed for heavy oil reservoir management that can be used as a single source of reference for the industry. Introduction Because of its comprehensive nature, much of the complete paper is dedicated to a review of the characteristics of heavy oil reservoirs and their exploitation, including thermal and nonthermal methods and the literature dedicated thereto. This synopsis will concentrate on the authors’ reviews of work flows to manage these reservoirs and field applications of the methodologies they review. Work Flow for Heavy Oil Reservoir Management Reservoir management is a multidisciplinary field involving detailed analysis of geosciences such as reservoir engineering, geological engineering, and petrophysics. Evaluation of geological information and fluid properties helps to understand the distribution of heavy oil in the reservoir. Understanding the characteristics of heavy oil reservoirs is essential for selecting the appropriate enhanced oil recovery (EOR) method. Reservoir-surveillance techniques play a critical role in understanding complex systems. Statistical approaches might be required to handle extensive data sets of production history and petrophysical data. The main goal of the reservoir management team in thermal EOR methods is to optimize parameters in steam-injection projects to maximize recovery rates from heavy oil reservoirs. The important parameters influencing the success of thermal projects include injection rates and pressures, preferential steam paths, well profiles, and reservoir depth. Previous work has presented a work flow for optimizing steamfloods in Oman. The work flow involves a review of production and injection history, petrophysical properties, and geological descriptions. Steam/oil ratio was used as a key performance indicator for steam management; it is defined as barrels of steam injected for 1 bbl of additional oil production. The steam breakthrough was monitored from the wellhead flowing temperature of the producer wells. A sudden increase in wellhead temperature is associated with a steam breakthrough. The permeability map of the reservoir helps to select appropriate injectors for a steamflood. High-permeability wells might lead to fingering, causing less recovery. Vertical conformance is desired to achieve oil sweep with steam. Observation wells are the controlling stations of steamflooding efficiency. It is critical to place the observation wells in heterogeneous reservoirs. Geophysical methods also are applied for surveillance of steam-injection projects. Real-time surveillance plays a critical role in the optimization of heavy oil reservoirs. The authors describe a modeling technique called Production Universe (PU) that enables operators to estimate oil and water production in real time. PU is effective at finding the offending well in case of sudden changes in field-level production. PU provides an automated daily production and deferment report that guides analysts to identify low-efficiency wells for remedial operations.

Simultaneous CO2 adsorption and conversion over Ni-Pd supported CeO2 nanoparticles during catalytic n-C7 asphaltene gasification

Shallow heavy oil reservoirs are suitable for the geo-sequestration of CO2 based on its adsorption and conversion during thermal-enhanced oil recovery processes. This study aims to evaluate multifunctional nanomaterials for CO2 adsorption and its subsequent transformation into valuable sub-products during the catalytic decomposition of asphaltenes in a steam gasification atmosphere. Three ceria nanoparticles with cubic (C-CeO2), orthorhombic (O-CeO2), and spherical (S-CeO2) shapes were tested in four stages including i) CO2 adsorption at 30, 50, 100, and 200 °C between 0.084 and 3.0 MPa, ii) dynamic in-situ CO2 adsorption in the presence of steam between 170 and 230 °C at 3.0 MPa, iii) dynamic in-situ CO2 adsorption in the presence of steam with adsorbed asphaltenes between 170 and 230 °C at 3.0 MPa and iv) CO2 conversion at the same conditions. The best nanoparticle morphology was doped with 1 wt% of Ni and Pd (C-CeNiPd) and was tested in the same experiments. Among the most important results, CO2 adsorption increased in the order S-CeO2 < O-CeO2 < C-CeO2 < C-CeNiPd, regardless of the temperature. When steam was injected, CO2 adsorption is reduced in all the systems. At 200 °C adsorption decreased by 3.0 %, 2.7 %, 2.5 %, and 2.0 % in processes assisted by S-CeO2, O-CeO2, C-CeO2, and C-CeNiPd, respectively. Nanoparticles with adsorbed asphaltenes presented a high tendency for CO2 adsorption as well. The nanoparticle with the best morphology (C-CeO2) adsorbed about 24.3 % (3.92 mmol) of CO2 at 200 °C, and the yield increased after doping with Ni and Pd, obtaining CO2 adsorption of 34 %. Finally, for CO2 conversion, a mixture of gases composed of CO, CH4, H2, and light hydrocarbons (LHC) is obtained. The hydrogen production content follows a trend that agrees well with each material's adsorptive capacity and catalytic activity. The maximum %vol of H2 produced at 200 °C during asphaltene gasification was 31 %, 29 %, 24 %, and 23 % for C-CeNiPd, C-CeO2, O-CeO2, and S-CeO2, respectively.