Numerical simulation study on evolution characteristics and difference of CO2 injection pressure transfer between multi-branch pinnate borehole and single borehole

The combination of the primary pore–fracture structure in coal and the spatial distribution of minerals significantly influences the complex seepage–displacement behavior of coal seams, which is a critical issue that requires close attention in CO2 geological storage in coal seams. This study conducts microcomputed tomography scanning and three-dimensional (3D) reconstruction technology, permeability testing, and numerical simulations of the seepage and displacement process, aiming to reveal the heterogeneous characteristics of coal and their influence mechanisms on the microscopic seepage and the CO2 displacing water effect. Results show that the pores and fractures in the samples are highly heterogeneous spatial distribution. The distributed dense pores and microfractures are mainly distribute in sample SX01, two axially distributed penetrating large fractures and accompanied isolated pores are developed in sample SX02, and large-scale penetrating large fractures and confined dense pores and microfractures are embedded in sample SX03. The displacement efficiency and displacement equilibrium time show a trend of first significantly decreasing and then slightly increasing with the increase in the demineralization index. The CO2 displacing water process evolves into three typical stages: the uniform weak flow stage, the strong preferential flow stage, and the weak preferential flow stage. Adjusting the CO2 injection position, CO2 injection rate, CO2 injection pressure, and CO2 injection holding time, it is possible to achieve microscale uniform flow in the coal seam, thereby improving the injectivity and storage capacity of coal seams with mineral rich coal seams.

In order to research on the impact of water sump under seam floor, by mining 93 <sub xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">upper</sub> 10 working face in Nantun Coal Mine, numerical simulation and theory study are carried out in this paper. In the theoretical study, from the failure pattern of coal floor, criterion is put forward , that is whether the water sump is affected or not is existed in the overlap with floor failure, based on "down three zone", and empirical and theoretical formula showed that -670 was out of floor failure district, within little influence; Starting from the propagation rules of mine pressure of floor, bearing stress in increased-stress zone were dividedly into point load and triangular, the mine pressure of water sump is calculated based on Boussinesq formula, and the result showed that mine pressure of water sump was much less than 5 percent of original rock stress. In the numerical simulation study, the result showed that the experimental value is in consistent with theory; maximum subsidence value of the water sump roof was about 4 mm, maximum horizontal displacement is close to the face was about 14 mm, and roadway displacement is smaller. All above could make conclusion that mining 93 <sub xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">upper</sub> 10 working face has little effect on -670 water sump under seam floor.

Performance evaluation of CO2 flooding process in tight oil reservoir via experimental and numerical simulation studies

ABSTRACT: Unconventional oil and gas resources play a crucial role in the energy sector and represent a strategic successor in the quest for increased reserves and production. Particularly, the effective development of deep shale reservoirs holds great promise. However, the development of deep shale reservoirs still faces numerous challenges, such as the inevitable temperature field disturbance and thermal effects caused by the injection of low-temperature fracturing fluids into high-temperature shale reservoirs, which significantly impact the rheological properties of the fracturing fluid. Therefore, this paper focuses on the study of temperature transfer in fractures during the injection phase, conducting two-dimensional single-fracture and two-dimensional random fractures THM (Thermo-Hydro-Mechanical) numerical simulation studies. Based on the equilibrium equations of the temperature field, flow field, and stress field, random fractures grid reservoir model was constructed, and finite element numerical simulation studies were carried out using COMSOL. The maximum relative error between analytical and numerical solutions at different locations was 1.11%, thereby verifying the viability of the numerical simulation of the fracture model. A THM coupled numerical simulation study was conducted on the two-dimensional random fractures model, studying the evolution characteristics of the temperature field and flow field, and analyzing the impact of fracture aperture, fracture network density, and formation temperature on random fractures temperature transmission. Changing these three parameters resulted in temperature differences of 47.83 K, 144.35 K, and 100.09 K at a distance of 100 m from the injection well, respectively, and it was analyzed that the fracture network density is the dominant factor affecting the temperature transmission within the random fractures Simultaneously, the rheology of the fracturing fluid was simulated based on the temperature distribution, with the viscosity decreasing from 1.09 mPa·s to 0.06 mPa·s as the temperature of the fracturing fluid changed, exhibiting a decreasing trend.

The paper represents a simulation investigation about the crack evolution and acoustic emission characteristics of coal specimen subjected to conventional compression loading with four confining pressures. From the simulation tests, the following conclusions can be drawn. (1) Under the confining pressure of 0.5, 1.0 and 1.5 MPa, at the stress peak point, the number of total cracks in coal specimen are 3.33, 4.28 and 4.50 times of that under uniaxial stress state, respectively. That is, with the increase of confining pressure, the number of total cracks at coal specimen failure gradually increases, but the increase rate gradually decreases. (2) Under the confining pressure of 0, 0.5, 1.0 and 1.5 MPa, at the stress peak point, the proportion of tensile cracks in the total cracks decreases from 100% to 95.95%, and the proportion of shear cracks increases from 0 to 4.05%. These show that with the increase of confining pressure, the coal specimen presents a transition trend from tensile failure to shear failure. (3) When the confining pressure is less than 1.0 MPa, the confining pressure has an obvious effect on the crack distribution of coal specimen subjected to conventional compression loading, but when the confining pressure exceeds 1.0 MPa, this effect gradually weakens. (4) The maximum value of acoustic emission impact counts slightly lags behind the time point corresponding to the peak strength, namely, the coal specimen is destroyed at some point in the post-peak phase.

A statistical damage model (SDM) of fully-graded concrete was created using statistical damage theory, based on the mechanical properties of axial tension and axial compression of the material. The SDM considers two damage modes, fracture and yield, and explains the intrinsic connection between the mesoscopic damage evolution mechanism and the macroscopic nonlinear mechanical behavior of fully-graded concrete. The artificial bee colony (ABC) algorithm was used to obtain the optimal parameter combination through an intelligent search of parameters εa, εh, εb and H in the constitutive model by taking the test data as the target value, and the sum of the squares of the differences between the target value and the predicted value as the objective function. The SDM numerical simulation model of fully-graded concrete is proposed by compiling subroutines in FORTRAN by constructing two modules of data model and damage analysis. The numerical results under uniaxial and biaxial forces are in agreement with the experimental results, which verifies the accuracy of the program. The model also analyzes the characteristics of mesoscopic damage evolution and predicts the mechanical properties under triaxial forces. The results show that the proposed numerical simulation model can reflect the salient features for fully-graded concrete under uniaxial, biaxial and triaxial loading conditions, and the evolution law of mesoscopic parameters. Therefore, the proposed model serves as a basis for the refined finite element analysis of hydraulic fully-graded concrete structures and reveals the mesoscopic damage mechanism of concrete under different load environments.

This paper aims to clarify the mechanism and feasibility of carbon dioxide (CO2) injection into carbonate gas reservoirs to enhance recovery and evaluate its potential. Based on this, a theoretical basis for large-scale field tests is provided, and parameter optimization for mine tests is supported. The synergistic application of CO2 capture, utilization, and storage (CCUS) technology and CO2-enhanced gas recovery (CO2-EGR) technology is also explored. With ongoing global warming, the synergistic application of CCUS and CO2-EGR technologies can contribute to global climate governance. Most gas reservoirs in the Sichuan Basin are in the late stages of development. PetroChina has selected the WL gas reservoir to conduct CO2 injection tests to enhance recovery. However, the mechanism and potential of CO2 gas injection into the carbonate gas reservoirs to enhance recovery remain unclear. Through extensive experimental and numerical simulation studies, this research aims to demonstrate the feasibility and clarify the influencing factors of CCUS-EGR, paving the way for practical applications in the field and contributing to the global effort to reduce CO2 emissions. First, we conducted experiments to observe the phase behavior of CO2 displacing methane (CH4) under different temperature and pressure conditions. The experiments were performed under high-temperature- and high-pressure-resistant containers, which could be observed from outside, using high-definition cameras to capture the entire process of gas phase changes. Subsequently, long-core displacement experiments were carried out in a simulated reservoir environment. These experiments involved the displacement of CH4 by CO2 through various injection methods and under different production conditions. The objective was to elucidate the potential and influencing factors of CO2 injection for enhancing recovery under laboratory conditions. Finally, based on the experimental results, comprehensive numerical simulation studies were performed with different injection and production parameters on the mechanisms of CO2 injection to improve recovery and storage in the subject WL gas reservoir. The most reasonable injection and production plans were chosen, and the potential for CO2 injection to enhance recovery and storage in the field-scale WL gas reservoir was clarified. Phase behavior experiments indicate that when CO2 reaches a supercritical state, the CO2-CH4 mixed system presents a vertical distribution of pure CO2, a transition zone, and CH4. However, as the temperature increases, the transition zone continues to expand. The long-core experiment results show that low injection pressure is favorable for natural gas development but increases the length of the transition zone between CO2 and CH4. A higher reservoir pressure during CO2 displacement results in a lower flow ratio that is closer to piston displacement, achieving a higher recovery rate. High injection rates can lead to the rapid accumulation of inlet pressure, thus achieving high-pressure injection effects. Numerical simulation studies can help choose the best CO2 injection and production plan for the WL gas reservoir, which could cumulatively recover about 500 million cubic meters (m3) of natural gas, accounting for approximately 9% of dynamic reserves and about 8% of geological reserves, while storing about 3.6 million tons of CO2.

Numerical Simulation Study on Mitigation of the Pressure Build-up in the Geological Formation During Injection of CO2

Conventional hydraulic fracturing is not effective in target oil development zones with available wellbores located in the azimuth of the non-maximum horizontal in-situ stress. To some extent, we think that the radial hydraulic jet drilling has the function of guiding hydraulic fracture propagation direction and promoting deep penetration, but this notion currently lacks an effective theoretical support for fracture propagation. In order to verify the technology, a 3D extended finite element numerical model of hydraulic fracturing promoted by the single radial borehole was established, and the influences of nine factors on propagation of hydraulic fracture guided by the single radial borehole were comprehensively analyzed. Moreover, the term ‘Guidance factor (Gf)’ was introduced for the first time to effectively quantify the radial borehole guidance. The guidance of nine factors was evaluated through gray correlation analysis. The experimental results were consistent with the numerical simulation results to a certain extent. The study provides theoretical evidence for the artificial control technology of directional propagation of hydraulic fracture promoted by the single radial borehole, and it predicts the guidance effect of a single radial borehole on hydraulic fracture to a certain extent, which is helpful for planning well-completion and fracturing operation parameters in radial borehole-promoted hydraulic fracturing technology.

Asphaltenes are heavy aromatic hydrocarbon compounds contained in reservoir fluids and may precipitate when reservoir pressure is reduced by production or when gas is injected into the reservoir, and then further deposit on pore-throat surfaces causing reservoir damage. At present, the research on asphaltene precipitation and reservoir damage is carried out in conventional reservoirs, and the influence of CO2 injection under high-temperature high-pressure conditions has not yet been clearly understood. In this work, the perturbed-chain statistical associating fluid theory (PC-SAFT) is applied to construct the asphaltene precipitation envelope of crude oil under the conditions of depletion development and CO2 injection development, and the precipitation conditions of asphaltenes during CO2 injection are studied. Based on the Nghiem solid phase model, the phase state simulation of asphaltene precipitation was carried out, the characteristics of asphaltene precipitation were quantitatively described. Further, through the asphaltene deposition core experiment during the CO2 injection process, the damage degree of the reservoir after asphaltene deposition and reservoir permeability levels was evaluated. Finally, the numerical simulation study was conducted after correcting the parameters to the experimental results. The asphaltene deposition distribution in the reservoir and its influence on the productivity were evaluated. The results show that with the increase in the proportion of CO2 injection, the precipitation envelope of asphaltene expands, resulting in the earlier precipitation. While there is a crossover temperature near 140 ℃, when the temperature is lower than the crossover temperature, CO2 acts as an inhibitor. The precipitation of asphaltenes in the process of CO2 injection is the desorption of colloid-asphaltene inclusions caused by gas molecules, and then to the mutual polymerization process between dispersed asphaltene molecules. CO2 injection will increase the amount of precipitation and move the precipitation curve to the right side. The degree of permeability reduction caused by the deposition of asphaltenes in the core is 12.87% - 37.54%; the deposition of asphaltenes in the reservoir is mainly around the injection-production well and along the injected gas profile. Considering asphaltenes, the oil recovery degree is reduced by 1.5%, and the injection rate is reduced by 17%. The reservoir pressure, temperature and reservoir physical properties have a strong correlation with the degree of reservoir damage, while the initial asphaltene content has a low correlation. The main contribution of this work lies in the combination of PC-SAFT calculation, experinments, phase state simulation, and numerical simulation to predict the asphatene precipitation with different pressure, temperature, and the amount of injected gas, and clarify the influence on reservoir permeability and oil production when using CO2 injection. This work will be of great interest to operators seeking to enhance oil recovery by CO2 injection in deep reservoirs.

Sand control is vitally important to operation integrity in producing heavy-oil from unconsolidated reservoirs. Among various sand exclusion technologies, the open-hole gravel pack (OHGP) has been widely used in horizontal well completions. It is thus critical to quantitatively evaluate gravel packing layer damage and understand its mechanisms. In this paper, we propose an integrated study to quantitatively evaluate gravel packing damage based on the real-world scenarios and, thus provided design criteria for gavel packing. We have designed an experimental system that can measure the core pressure at multiple points in gravel layers at high pressure condition as well as track sand migration. Preliminary results indicate that pore structure of gravel packing layer changes and the permeability decreases with sand migration and plugging. Sand volume fraction, fluid viscosity, and sand radius are the main factors that cause gravel packing layer damage. We have developed a numerical model based on experimental observations. The numerical model considers liquid-solid fluid flow processes, sand migration and plugging in gravel layer. Numerical simulation studies are then performed on the gravel damage at different sand volume fraction, fluid viscosity, and sand radius. The simulated results are in agreement with experimental results. The numerical simulation studies on real-world scenarios are under investigation and we will report the numerical results in later reports.

CO2 flooding is an effective technology for suppling condensate gas reservoir pressure and mitigating global warming. In this study, numerical simulation studies have been conducted to enhance gas recovery in Pen5 condensate gas reservoir using CO2 flooding. Pen5 reservoir has lasted 20 years of primary depletion, which affected by water invasion and retrograde condensation. In numerical simulation study, the GEM module is applied to implement history‐matching of production data, and good agreement has been achieved. Based on comprehensive geological understanding, production dynamics, and numerical simulation techniques, areas with minimal impact from water invasion and retrograde condensation contamination have been delineated. The comparison between continued depletion and the implementation of CO2 injection as a replacement technology in favorable areas has demonstrated the feasibility of CO2 flooding development in these regions. The analysis of the advantages and disadvantages of using miscible flooding and immiscible flooding was conducted, and the optimal development well pattern was evaluated. In the end, the plan of CO2 flooding of Pen5 reservoir has been designed and the gas production rate in the next 10 years has been predicted. The research findings of this study have reference significance for the practical application of CO2 flooding in developing condensate gas reservoirs.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190277, “Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids-Rich Reservoirs,” by Dheiaa Alfarge, SPE, Iraqi Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Improved oil recovery (IOR) methods for shale-oil reservoirs are considered relatively new concepts compared with IOR for conventional oil reservoirs. Different IOR methods—including CO2, surfactant, natural gas, and water injection—have been investigated for unconventional reservoirs using laboratory experiments, numerical simulation studies, and limited pilot tests. For a variety of reasons, CO2 injection is the most-investigated option. In this paper, numerical simulation methods of compositional models were incorporated with logarithmically spaced, locally refined, and dual-permeability reservoir models and local grid refinement (LGR) of hydraulic-fracture conditions to investigate the feasibility of CO2 injection in shale oil reservoirs. Introduction Advancements in horizontal drilling and hydraulic fracturing enabled unconventional liquids-rich reservoirs (ULRs), such as shale and source-rock formations and very tight reservoirs, to change the oil industry. ULRs are characterized by pore throats of micro- to nanomillimeters and an ultralow permeability. Although different studies re-ported that these ULRs contain billions of recoverable oil barrels in place, it is estimated that less than 7% of the original oil in place can be recovered during the primary depletion stage. Production sustainability is the main problem behind the low oil recovery in these unconventional reservoirs. Oil wells in ULRs typically start with a high production rate, but show a steep decline rate in the first 3–5 years of production life because of the rapid depletion in the natural fractures combined with a slow recharge from the rock matrix. The logical steps of academic research such as experimental investigation, simulation studies, and pilot tests for examining the applicability of different unconventional IOR methods have just begun in the past decade. Applying one of the feasible IOR methods in most oil and gas reservoirs should be mandatory to increase the oil-recovery factor. However, the mechanisms of IOR methods in unconventional reservoirs are not necessarily the same as those in conventional reservoirs. The primary characteristics of unconventional reservoirs that might impair performing IOR operations are low porosity and ultralow permeability. As a result, finding IOR methods that are insensitive to these very small pore throats is a priority.

In order to operate a CO2 flooding scheme successfully, it is necessary to get accurate information about the reservoir dynamic performance and the fluids injected. Although some numerical simulation studies have been conducted, the complicated drive mechanisms and actual reservoir performance have not been fully understood. Thus, there is a strong industrial need to develop models using different perspectives to provide valuable and complementary insights into the reservoir performance during the CO2 flooding process. The objective of this study is to develop models using material balance equations (MBE) to analyze the field data before and after CO2 injection. After matching the historical field data, the proposed model can be applied to evaluate, monitor and predict the overall reservoir dynamic performance during the CO2 flooding process. To accurately account for the complex displacement process involving compositional effect and multiphase flow, the PVT properties of reservoir fluids and the four-phase fluid relative permeability relationship are integrated into the model. This study has investigated the effects of a number of factors, such as the reservoir pressure, the amount of CO2 injected, the CO2 partition ratios in reservoir fluids, the possibility of the existence of a free CO2 gas cap, the proportion of reservoir fluids contacted by CO2, the oil swelling and the oil relative permeability improvement. The model has been applied to analyze the Weyburn CO2 flooding project. The study has shown that the proposed MBE model is an effective complementary tool to analyze overall reservoir performance in tertiary CO2 recovery processes. The results show that:there exists a free CO2 gas cap under reservoir conditions, even if the reservoir pressure is larger than MMP (minimum miscible pressure) in the Weyburn Field;the CO2 partition ratios in oil, water and gas phases and the proportions of reservoir fluids contacted by CO2 largely affect the drive mechanism and production performance; andthe effect of CO2 solubility in water under actual reservoir conditions cannot be neglected. The proposed new model is the first one in developing and applying MBE to evaluate the overall dynamic performance for the CO2 flooding process and a valuable insight into reservoir responses during this process has been achieved. Introduction CO2 flooding is considered one of the most effective tertiary recovery processes in light/medium oil reservoirs and has achieved widespread use in the petroleum industry. However, the complicated displacement mechanisms and reservoir performance involved in the CO2 injection process have not been completely understood. Monitoring reservoir performance and obtaining accurate information regarding reservoir fluid and injected fluid using field data will help understand the mechanisms and manage the CO2 injection project efficiently. There are two types of methods that monitor and evaluate reservoir performance: numerical simulation and MBE. MBE is a classic reservoir engineering tool. It is applied to analyze the reservoir performance based on the law of conservation of matter. Compared with MBE, reservoir numerical simulation is a more modern technique for modelling reservoir performance.

Carbon dioxide flooding has been proven to be one of the most effective and viable enhanced oil recovery (EOR) processes for light and medium oil reservoirs. In the past, an extremely large number of laboratory experiments and numerical simulations have been conducted to study the CO2 EOR process. However, the specific effects of viscous and capillary forces on this tertiary oil recovery process are neither thoroughly studied nor well understood yet. In this paper, an experimental study is carried out to examine the detailed effects of viscous and capillary forces on the CO2 EOR under the actual reservoir conditions. First, the equilibrium interfacial tensions between a light crude oil and CO2 are measured at different equilibrium pressures. Second, a series of CO2 coreflood tests are performed to measure the CO2 EOR at different CO2 injection pore volumes, pressures, and rates. Each CO2 coreflood test is terminated after a total of 1.5 pore volume of CO2 is injected. The detailed experimental results show that, in general, the measured equilibrium interfacial tension is reduced with the equilibrium pressure but the measured CO2 EOR at 1.5 pore volume of CO2 is increased with the CO2 injection pressure and rate. Finally, the measured CO2 EOR at 1.5 pore volume versus injection pressure data at different CO2 injection rates are related to the measured equilibrium interfacial tension versus equilibrium pressure data in terms of the complete capillary number, which is defined as the ratio of the viscous force to the capillary force for each CO2 coreflood test. This study shows that if the complete capillary number is in an intermediate range, the CO2 EOR increases quickly with the complete capillary number. Otherwise, the CO2 EOR is lower and remains almost constant for a smaller complete capillary number, or it is higher and remains unchanged for a larger complete capillary number.