Oil Recovery Technology Research Articles

Preparation of styrene‐phenylamine monomer copolymer nanospheres and its performance for stabilizing CO2 foam

AbstractImproving the stability of CO2 foam is a core concern in CO2 foam flooding oil recovery technology. Using hydrophobic nano‐SiO2 to enhance the stability of CO2 foam is a common approach, but hydrophobic nano‐SiO2 faces challenges, such as easy aggregation, difficult dispersion, and performance needs to improve. In this article, a novel dispersion of styrene‐phenylamine monomer copolymer (PSSN) nanosphere with primary amine groups on the surface was synthesized. The synthesis conditions of PSSN were optimized, and its performance for stabilizing CO2 foam was evaluated. The experimental results demonstrated that PSSN had better performance for stabilizing CO2 foam than that of hydrophobic nano‐SiO2 when using cocamidopropyl betaine (CAB) as the foaming agent. With the CAB concentration of 4000 mg/L and PSSN concentration of 100 mg/L in the brine having salinity of 8460 mg/L, the half‐life of CO2 foam at 90°C was 131 min, which was 43 min longer than that stabilized by hydrophobic nano‐SiO2 under the same conditions. This is for the first time that polystyrene microspheres with amine groups on the surface was used to stabilize CO2 foam. The study provides a new nanoparticle option for stabilizing CO2 foam.

Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

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.

ANALYSIS OF THE CHANGE IN THE RHEOLOGICAL CURVE OF THE FLOW OF NON-NEWTONIAN OILS IN THE FIELDS OF WESTERN KAZAKHSTAN

In order to improve oil recovery technologies, the task of studying the rheological properties of oil, which largely determine the development indicators of the development target, namely, the rate of oil withdrawal, the stability and nature of the movement of the front of displacement of oil by water or gas, and, as a result, final oil recovery, is becoming urgent. In this regard, there is a need for in-depth studies of the rheoviscidity properties of produced oils.This article presents the results of laboratory studies to study the rheological characteristics of both high-paraffin and heavy high-viscosity oils using the example of oil from fields in Western Kazakhstan. Since structured oils are thixotropic systems, all experiments were carried out with the same degree of structure destruction in oil, both anhydrous oils and those with different water cuts were studied. The authors also showed the nature of the change in the rheological curve of the flow of oil emulsion of various water cuts to identify the temperature interval where non-Newtonian properties of various oils are manifested. Their main physical and chemical properties are also given, and kinematic viscosities of oil with different densities are compared. The results of laboratory studies of viscosity change with temperature increase for Karazhanbas oil emulsion with different water cut are considered. Despite differences in viscosity values of different degrees of watered samples of highly paraffinic oil, the tendency of oil viscosity change depending on the shear gradient is the same. The formation of structured systems of resin and asphaltene particles is observed in flows with relatively low shear gradients. As a result, oil viscosity dependence on the shear gradient in the range of low values from 0 to 20 s-1 must be taken into account when solving tasks for high-paraffin production. The results obtained are of practical interest, since when creating a compositional model and technological modeling of the collection and transport system, the rheological characteristics of the oil of a particular field, as well as the presence of thixotropic properties, must be taken into account.

Pore-scale fluid distribution and remaining oil during tertiary low-salinity waterflooding in a carbonate

The utilization of low-salinity waterflooding as a promising enhanced oil recovery method has exhibited exciting results in various experiments conducted at different scales. For carbonate rock, pore-scale understanding of the fluid distribution and remaining oil after low-salinity waterflooding is essential, especially the geometry and topology analysis of oil clusters. We performed the tertiary low-salinity waterflooding and employed X-ray micro-CT to probe the pore-scale displacement mechanism, fluid configuration, oil recovery, and remaining oil distribution. We found that the core becomes less oil-wet after low-salinity waterflooding. Furthermore, we analyzed the oil-rock and oil-brine interfacial areas to further support the wettability alteration. By comparing images after high-salinity waterflooding and low-salinity waterflooding, it is proven that wettability alteration has a significant impact on the behavior of the two-phase flow. Our research demonstrates that low-salinity waterflooding is an effective tertiary enhanced oil recovery technology in carbonate, which changes the wettability of rock and results in less film and singlet oil.

Marine algae biomass: A viable and renewable resource for biofuel production: A review

Global energy shortages, as well as rising greenhouse gas emissions, have fueled the search for sustainable renewable energy sources. Recent research has identified microalgae and macroalgae biofuel as one of the major renewable energy sources for environmentally friendly growth, with the potential to replace fossil-based energy sources. The primary disadvantages associated with oil crops and lignocellulose-based biofuels were absent in marine microalgae and macroalgae biofuel. Algae-based renewable energy sources are technically and economically viable, as well as cost competitive; they require no additional land, use little water, and help to reduce atmospheric CO2. Commercial extraction of macroalgae and microalgae biofuel, however, remains impossible due to a small biomass amount and costly downstream procedures. Marine algae-based biofuel production can be made viable by installing sophisticated photobioreactors and developing low-cost biomass collection, drying, and oil recovery technologies. Commercial manufacturing is also achieved through improved genetically modified approaches to stress management, as well as technological metabolic processes to increase lipid production. Furthermore, emerging technologies such as algal-bacterial interactions for improving marine algae growth and lipid production are being investigated. This review focuses on marine algae-based biofuel production and sustainability, economic values, challenges encountered during the commercialization of marine algae biofuels, potential solutions to these challenges, and practicality.

Application of machine learning in on-line calibration of flow measurement errors

With the vigorous construction of an intelligent pipe network, an automatic flowmeter was the key to realize online flow measurement of oil and gas. Ensuring the accuracy of flow measurement was very important to achieve real-time feedback on oil–gas production status for adjusting the oil recovery technology. However, due to the changing flow state of the oil–gas in the pipe and the error of the flow-meter itself, there were some errors during flow measurement. Therefore, based on the machine learning method, this paper corrected the errors caused by the pulsating flow and the flowmeter itself in data drift. The results showed that the toy–LSTM model can measure the pulsating flow accurately. When the number of toy–LSTM model neurons was ranged between 10 and 50, both RMSE and R2 showed good performance. The average of multiple predicted results presented higher accuracy than that of single predicted results, and furthermore, the drop rate can significantly increase the robustness of the toy–LSTM model. It should be noted that the optimal case proposed in this paper was based on a specific condition in the field. In the actual application, it was necessary to comprehensively consider the number of branch pipes, the change in oil well production, the characteristics of the oil–gas–water mixture, and other factors to determine the specific values of the number of neurons, the drop rate, and other parameters. Aiming at the distortion caused by the data drift of the flowmeter itself, the program was designed and data were collected from the software platform, information collector, and base station. The data acquisition of temperature–pressure integrated sensor and flowmeter was carried out in the field. In 20 groups of experiments, the online corrected program based on the Mexican Hat wavelet transform can realize accurate identification and automatic corrected responses, and the corrected time was within 5 min.

Carbon Dioxide Oil Repulsion in the Sandstone Reservoirs of Lunnan Oilfield, Tarim Basin

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO2) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO2-assisted oil displacement under diverse operational parameters: injection pressures, CO2 concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO2, the dynamics of CO2 injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO2’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO2 injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO2 viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO2 flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO2 injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO2 purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO2 flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments.

Supercritical water upgrading of heavy oil: Effects of reservoir minerals on pyrolysis product distribution

Supercritical water upgrading (SCWU) is a promising technology for heavy oil recovery and refining, in which minerals could act as catalysts, but the effect on the upgraded product distribution remains unclear. In this study, heavy oil upgrading experiments in supercritical water (SCW) were carried out at 400°C and 25 MPa to investigate the effects of reservoir minerals such as quartz, carbonate, feldspar and clay minerals on the upgrading process. The result indicated that carbonate minerals and clay-bearing minerals produced noticeable benefits to the SCWU of heavy oil process. In carbonate minerals, dolomite showed the strongest catalytic effect in promoting hydrothermal cracking of hydrocarbon macromolecules, with a 5.6 % reduction in heavy fraction and a 12.2 % increase in light fraction of the upgraded oil. Clay-bearing minerals mainly exhibited oil-enhancing and coking-inhibiting benefits, calcium montmorillonite exhibited the most significant increase in oil production of 9 %, while zeolite most significantly reduced the coke activation energy by 62 %. Regarding the catalytic mechanism, the catalytic effect of carbonates originated from the MgO and CaO sites on the surface. For clay minerals, the acidic catalytic sites exist in the interlayer domains of montmorillonite and in the pores of zeolite provided higher catalytic efficiencies in oil production. This study demonstrated the feasibility of using natural minerals as inexpensive catalysts for supercritical water upgrading of heavy oil.

Application of carbon dioxide to improve the technology of oil recovery during well treatment

Application of carbon dioxide to improve the technology of oil recovery during well treatment

Research on Microbial Community Structure in Different Blocks of Alkaline–Surfactant–Polymer Flooding to Confirm Optimal Stage of Indigenous Microbial Flooding

The microbial communities associated with alkaline–surfactant–polymer (ASP)-flooded reservoirs have rarely been investigated. In this study, high-throughput sequencing was used to analyse the indigenous microbial communities in two different blocks, the water flooding after the alkaline–surfactant–polymer flooding block and the alkaline–surfactant–polymer flooding block, and to ascertain the optimal stage for the implementation of indigenous microbial oil recovery technology. The different displacement blocks had significant effects on the indigenous microbial community at the genus level according to an alpha diversity analysis and community composition. In water flooding after alkaline–surfactant–polymer flooding, the dominant genus of Pseudomonas exceeded 30%, increasing to 52.1% in alkaline–surfactant–polymer flooding, but alpha diversity decreased. Through a co-occurrence network analysis, it was found that the complexity of the water flooding after alkaline–surfactant–polymer flooding was higher than that of alkaline–surfactant–polymer flooding. This means that the water flooding ecosystem after alkaline–surfactant–polymer flooding was more stable and less susceptible to external environmental influences. In addition, there were significant differences in the functional redundancy of microbial communities in different blocks. In summary, the optimal stage for implementing local microbial oil recovery technology may be water flooding after alkaline–surfactant–polymer flooding.

Systematic Review of Solubility, Thickening Properties and Mechanisms of Thickener for Supercritical Carbon Dioxide.

Supercritical carbon dioxide (CO2) has extremely important applications in the extraction of unconventional oil and gas, especially in fracturing and enhanced oil recovery (EOR) technologies. It can not only relieve water resource wastage and environmental pollution caused by traditional mining methods, but also effectively store CO2 and mitigate the greenhouse effect. However, the low viscosity nature of supercritical CO2 gives rise to challenges such as viscosity fingering, limited sand-carrying capacity, high filtration loss, low oil and gas recovery efficiency, and potential rock adsorption. To overcome these challenges, low-rock-adsorption thickeners are required to enhance the viscosity of supercritical CO2. Through research into the literature, this article reviews the solubility and thickening characteristics of four types of polymer thickeners, namely surfactants, hydrocarbons, fluorinated polymers, and silicone polymers in supercritical CO2. The thickening mechanisms of polymer thickeners were also analyzed, including intermolecular interactions, LA-LB interactions, hydrogen bonding, and functionalized polymers, and so on.

Research and Application of Non-Steady-State CO2 Huff-n-Puff Oil Recovery Technology in High-Water-Cut and Low-Permeability Reservoirs

In response to the issues of poor water flooding efficiency, low oil production rates, and low recovery rates during the high-water-cut period in the low-permeability reservoirs of the Mutou Oilfield, the non-steady-state (NSS) CO2 huff-n-puff oil recovery technology was explored. The NSS CO2 huff-n-puff can improve the development effect of low-permeability reservoirs by replenishing the reservoir energy and significantly increasing the crude oil mobility. Experimental investigations were carried out, including a crude oil and CO2–crude oil swelling experiment, minimum miscibility pressure testing experiment, high-temperature and high-pressure microfluidic experiment, and NSS CO2 huff-n-puff oil recovery on-site pilot test. The experimental results showed that the main mechanisms of NSS CO2 huff-n-puff include dissolution, expansion, viscosity reduction, and swept volume enlargement, which can effectively mobilize the remaining oil from the various pore throats within the reservoir. The high-temperature and high-pressure microfluidic experiment achieved an ultimate recovery rate of 83.1% for NSS CO2 huff-n-puff, which was 7.9% higher than the rate of 75.2% obtained for steady injection. This method can effectively utilize the remaining oil in the corners and edges, enlarge the swept volume, and increase the recovery rate. Field trials of NSS CO2 huff-n-puff in a low-permeability reservoir in the Mutou Oilfield indicated that it cumulatively increased the oil production by 1134.5 tons. The achieved results and insights were systematically analyzed and could provide key technical support for the application of NSS CO2 huff-n-puff technology in low-permeability reservoirs, promoting the innovative development of this technology.

Surfactant–Polymer Flooding: Chemical Formula Design and Evaluation for High-Temperature and High-Salinity Qinghai Gasi Reservoir

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main developing enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10−2 mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir.

Laboratory study on the transformation of oil-water interface properties under direct current electric field

Interface tension is one of the important mechanisms that affect crude oil recovery and plays an important role in the development of tight oil reservoirs. Electrical-enhanced oil recovery can be used as a technology to reduce interfacial tension and improve crude oil recovery. In the previous research process of Electrical-enhanced oil recovery, the focus was more on the influence of electric field on wettability, and the understanding of the changes in interfacial tension under electric field action is not yet comprehensive. This article designs an orthogonal experiment to study the effect of electric field on oil-water properties. The degree of influence of three factors, namely sodium chloride solution concentration (C), direct current voltage (V), and voltage action time (t), on interfacial tension is studied. Gas chromatography, four component analysis, and Fourier transform infrared spectroscopy are combined to discuss the mechanism of the influence of changes in solution pH, crude oil components, and oil phase functional groups on interfacial tension. The results show that an external electric field can effectively reduce the interfacial tension between oil and water, and the maximum change in interfacial tension after the experiment can be reduced from 23.21 mN/m to 0.37 mN/m; Through range analysis, it can be concluded that the concentration of sodium chloride solution has the greatest impact on interfacial tension, followed by DC voltage and voltage action time. The optimal experimental conditions are 0.5 mol/L sodium chloride solution, 10 V DC voltage, and a voltage action time of 18 h, and the change in interfacial tension is related to the increase in pH value. The change in crude oil composition is also an important reason for the decrease in interfacial tension under external electric fields. Finally, Fourier transform infrared spectroscopy was used to determine that under the action of an electric field, the increase in pH of the sodium chloride solution resulted in the formation of carboxylate salts through chemical reactions between alkaline substances of solution and acidic substances of the oil, which were the key factors in reducing interfacial tension. This study helps to understand and explore the principles and mechanisms of Electrical-enhanced oil recovery in improving oil recovery, with the aim of contributing to the development and promotion of Electrical-enhanced oil recovery technology.

Technical transformation of heavy/ultra-heavy oil production in China driven by low carbon goals: A review

With the growing global energy demand and limited production of conventional crude oil, the extraction of unconventional heavy and extra-heavy oil is receiving unprecedented attention. China is the fourth largest producer of heavy oil. High viscosity and complex formation environments increase the difficulty of exploiting heavy oil. To alleviate the economic cost and environmental pollution pressure brought by heavy oil production, China has achieved significant advancement in the innovation of heavy oil recovery, including accelerating the transformation of thermal technology to non-thermal technology and the use of new energy technology to achieve the goal of low-carbon economy and green environmental protection. Based on the background of heavy oil in China, this paper recharacterizes the high-viscosity mechanism of heavy oil. From different aspects, including basic principles, main characteristics, applicability, limitations, and challenges, this paper comprehensively reviews existing heavy oil recovery technologies, including thermal recovery, in-situ upgrading, cold recovery, and new energy technologies.Currently, in China, the main target of heavy oil recovery is achieving the “carbon peaking and carbon neutrality” goals, which can be described as low energy consumption, low emission, and low pollution. To facilitate the low-carbon transition in the extraction of heavy/extra-heavy oil and attain environmental sustainability goals, it is essential to increase the proportion of non-thermal factors in thermal recovery technologies, develop efficient in-situ catalysts, adopt clean cold extraction techniques, and advance the development of new energy technologies.

Research on the Functional Microbe Activation System in a Post-Polymer Flooded Reservoir

Further exploitation of the residual oil underground in post-polymer flooded reservoirs is attractive and challenging. Microbial-enhanced oil recovery (MEOR) is a promising strategy to enhance the recovery of residual oil in post-polymer flooded reservoirs. Identifying and selectively activating indigenous microorganisms with oil displacement capabilities is an urgent requirement in the current design of efficient microbial-enhanced oil recovery technologies. This study combines high-throughput sequencing with functional network analysis to identify the core functional microbes within the reservoirs. Concurrently, it devises targeted activation strategies tailored to oligotrophic conditions through an analysis of environmental factor influences. The feasibility of these strategies is then validated through physical simulation experiments. With nutrient stimulation, the overall diversity of microorganisms decreases while the abundance of functional microorganisms increases. The core displacement results showed that the oil recovery factor increased by 3.82% on the basis of polymer flooding. In summary, this research has established a system for the efficient activation of functional microorganisms under oligotrophic conditions by utilizing bioinformatics, network analysis, and indoor simulation systems. This achievement will undoubtedly lay a solid foundation for the practical implementation of microbial enhancement techniques in the field.

Application of Machine Learning for Shale Oil and Gas “Sweet Spots” Prediction

With the continuous improvement of shale oil and gas recovery technologies and achievements, a large amount of geological information and data have been accumulated for the description of shale reservoirs, and it has become possible to use machine learning methods for “sweet spots” prediction in shale oil and gas areas. Taking the Duvernay shale oil and gas field in Canada as an example, this paper attempts to build recoverable shale oil and gas reserve prediction models using machine learning methods and geological and development big data, to predict the distribution of recoverable shale oil and gas reserves and provide a basis for well location deployment and engineering modifications. The research results of the machine learning model in this study are as follows: ① Three machine learning methods were applied to build a prediction model and random forest showed the best performance. The R2 values of the built recoverable shale oil and gas reserves prediction models are 0.7894 and 0.8210, respectively, with an accuracy that meets the requirements of production applications; ② The geological main controlling factors for recoverable shale oil and gas reserves in this area are organic matter maturity and total organic carbon (TOC), followed by porosity and effective thickness; the main controlling factor for engineering modifications is the total proppant volume, followed by total stages and horizontal lateral length; ③ The abundance of recoverable shale oil and gas reserves in the central part of the study area is predicted to be relatively high, which makes it a favorable area for future well location deployment.

A Comprehensive Assessment of the Carbon Footprint of the Coal-to-Methanol Process Coupled with Carbon Capture-, Utilization-, and Storage-Enhanced Oil Recovery Technology

The process of coal-to-methanol conversion consumes a large amount of energy, and the use of the co-production method in conjunction with carbon capture, utilization, and storage (CCUS) technology can reduce its carbon footprint. However, little research has been devoted to comprehensively assessing the carbon footprint of the coal-to-methanol (CTM) co-production system coupled with CCUS-enhanced oil recovery technology (CCUS-EOR), and this hinders the scientific evaluation of its decarbonization-related performance. In this study, we used lifecycle assessment to introduce the coefficient of distribution of methanol and constructed a model to calculate the carbon footprint of the process of CTM co-production of liquefied natural gas (LNG) as well as CTM co-production coupled with CCUS-EOR. We used the proposed model to calculate the carbon footprint of the entire lifecycle of the process by using a case study. The results show that the carbon footprints of CTM co-production and CTM co-production coupled with CCUS-EOR are 2.63 t CO2/tCH3OH and 1.00 t CO2/tCH3OH, respectively, which is lower than that of the traditional CTM process, indicating their ability to achieve environmental sustainability. We also analyzed the composition of the carbon footprint of the coal-to-methanol process to identify the root causes of carbon emissions in it and pathways for reducing them. The work described here provided a reference for decision making and a basis for promoting the development of coal-to-methanol conversion and the CCUS industry in China.

A New Method for Optimizing Water-Flooding Strategies in Multi-Layer Sandstone Reservoirs

As one of the most important and economically enhanced oil-recovery technologies, water flooding has been applied in various oilfields worldwide for nearly a century. Stratified water injection is the key to improving water-flooding performance. In water flooding, the water-injection rate is normally optimized based on the reservoir permeability and thickness. However, this strategy is not applicable after oilfields enter the ultra-high-water-cut period. In this study, an original method for optimizing water-flooding parameters for developing multi-layer sandstone reservoirs in the entire flooding process and in a given period is proposed based on reservoir engineering theory and optimization technology. Meanwhile, optimization mathematical models that yield maximum oil recovery or net present value (NPV) are developed. The new method is verified by water-flooding experiments using Berea cores. The results show that using the method developed in this study can increase the total oil recovery by approximately 3 percent compared with the traditional method using the same water-injection amounts. The experimental results are consistent with the results from theoretical analysis. Moreover, this study shows that the geological reserves of each layer and the relative permeability curves have the greatest influence on the optimized water-injection rate, rather than the reservoir properties, which are the primary consideration in a traditional optimization method. The method developed in this study could not only be implemented in a newly developed oilfield but also could be used in a mature oilfield that has been developed for years. However, this study also shows that using the optimized water injection at an earlier stage will provide better EOR performance.