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China’s natural gas demand is growing under the “dual carbon” goal. However, the peaking capacity of gas storage remains insufficient. Oil reservoir-based underground gas storage (UGS) has, thus, emerged as a critical research focus due to its potential for efficient capacity expansion. The complexity of seepage and phase change characteristics during the multi-cycle injection–production process has not been systematically elucidated. This study combines experimental and numerical simulations to examine the seepage and phase change characteristics. This study innovatively reveals the synergistic mechanism of permeability, pressure, and cycle. The control law of multi-factor coupling on the dynamic peaking capacity of UGS is first expounded. Oil–water mutual drive reduced oil displacement efficiency by 2.5–4.7%. Conversely, oil–gas mutual drive improved oil displacement efficiency by 3.0–4.5% and storage capacity by 4.7–6.5%. The fifth-cycle oil–gas mutual displacement in high-permeability cores (74 mD) under high pressure (22 MPa) exhibited reductions in irreducible water saturation (7.06 percentage points) and residual oil saturation (6.38 percentage points) compared with the first-cycle displacement in low-permeability cores (8.36 mD) under low pressure (16 MPa). Meanwhile, the gas storage capacity increased by 13.44 percentage points, and the displacement efficiency improved by 10.62 percentage points. Multi-cycle huff-and-puff experiments and numerical simulations revealed that post-depletion multi-cycle huff-and-puff operations can enhance the oil recovery factor by 2.74–4.22 percentage points compared to depletion. After five-cycle huff-and-puff, methane content in the produced gas increased from 80.2% to 87.3%, heavy components (C8+) in the remaining oil rose by 2.7%, and the viscosity of the remaining oil increased from 2.0 to 4.6 mPa·s. The deterioration of the physical properties of the remaining oil leads to a reduction in the recovery factor in the cycle stage. This study elucidates seepage mechanisms and phase evolution during multi-cycle injection–production, demonstrating the synergistic optimization of high-permeability reservoirs and high-pressure injection techniques for enhanced gas storage design and efficiency.

Although technical advances in hydraulically fracturing and drilling enable commercial production from tight reservoirs, oil/gas recovery remains at a low level. Due to the technical and economic limitations of well-testing operations in tight reservoirs, rate-transient analysis (RTA) has become a more attractive option. However, current RTA models hardly consider the effect of the non-uniform production on rate decline behaviors. In fact, PLT results demonstrate that production profile is non-uniform. To fill this gap, this paper presents an improved RTA model of multi-fractured horizontal wells (MFHWs) to investigate the effects of non-uniform properties of hydraulic fractures (production of fractures, fracture half-length, number of fractures, fracture conductivity, and vertical permeability) on rate transient behaviors through the diagnostic type curves. Results indicate obvious differences on the rate decline curves among the type curves of uniform properties of fractures (UPF) and non-uniform properties of fractures (NPF). The use of dimensionless production integral derivative curve magnifies the differences so that we can diagnose the phenomenon of non-uniform production. Therefore, it’s significant to incorporate the effects of NPF into the RDA models of MFHWs, and the model proposed in this paper enables us to better evaluate well performance based on long-term production data.

The successful development of tight oil reservoirs in the U.S. shows the bright future of unconventional reservoirs. Tight oil reservoirs will be the main target of exploration and development in the future, and CO2 huff-n-puff is one of the most important methods to enhance oil recovery factor of tight oil reservoirs in North America. To improve the performance of CO2 huff-n-puff, injection and production parameters need to be optimized through numerical simulation. The phase behavior and microscopic flow mechanism of CO2 huff-n-puff in porous media need to be further investigated. This paper presents a detailed review of phase behavior and microscopic flow mechanism in tight porous media by CO2 huff-n-puff. Phase behavior in tight porous media is different from that in a PVT cylinder since the capillary pressure in tight porous media reduces the bubble point pressure and increases the miscibility pressure and critical temperature. The condensate pressure in tight porous media and nonequilibrium phase behavior need to be further investigated. The microscopic flow mechanism during CO2 huff-n-puff in tight porous media is complicated, and the impact of molecular diffusion, gas-liquid interaction, and fluid-rock interaction on multiphase flow is significant especially in tight porous media. Nuclear magnetic resonance (NMR) and molecular simulation are efficient methods to describe the microscopic flow in tight oil reservoirs, while the NMR is not cost-effective and molecular simulation needs to be improved to better characterize and model the feature of porous media. The improved molecular simulation is still a feasible method to understand the microscopic flow mechanism of CO2 huff-n-puff in tight oil reservoirs in the near future. The microscopic flow model in micropore network based on digital core is worth to be established, and phase behavior needs to be further incorporated into the microscopic flow model of CO2 huff-n-puff in tight porous media.

It is well known that long-term water injection may induce fractured channel(s), and that the fracture geometry would change with the decrease of bottom-hole pressure (BHP) during shut-in. This results in difficulties in modelling BHP behavior. This paper presents a pressure-transient procedure to analyze the BHP performance of water injectors by taking the dynamic behavior of the water injection fractured channel into consideration. Perturbation theory is adopted to solve the non-linear equations caused by decreasing fracture conductivity, while the finite-difference method is used to include the shrinking conductive fracture length during the shut-in period. Then, Duhamel’s principle is deployed to characterize the bi-storage effect; that is, fracture-storage caused by fracture closure and wellbore storage because of wellbore after-flow. Since the mobility outside of channel walls are much poorer than that in the channel, the walls are modeled as two parallel sealed boundaries. Therefore, the method of images is lastly applied to obtain the BHP response. The bi-storage phenomenon is characterized by two unit slopes in the pressure-derivative curve, and the variable fracture-storage is identified as a new flow regime in water injectors that is caused by fracture shrinkage. The interpreted storage coefficient will be much larger than the true value if the fracture-storage flow is mistakenly regarded as wellbore-storage flow. Because of the fractured channel walls and decreasing fracture conductivity, the pressure-derivative curve would increase in late time. Finally, two cases from the Changqing Oilfield are discussed to demonstrate the capabilities of the proposed approach.

The widely used application of horizontal well makes it significant to effectively evaluate rate performance of horizontal well in oil and gas reservoir. However, most models in previous work only focus on rate decline analysis (RDA) of horizontal well with single section (HWSS); they hardly address the problem that production rate distributes nonuniformly along horizontal wellbore in analyzing rate transient behaviors. However, only some horizontal segments contribute to the total production rates, and the production of each section along horizontal wellbore is not the same in fact, which may be caused by reservoir heterogeneity, selective completion, and nonuniform formation damage along horizontal wellbore. Therefore, the effect of these phenomena on rate decline characteristics cannot be ignored. The aim of this paper is to propose an analytical model to investigate transient rate response of a horizontal well with multiple sections (HWMS). The compound type curves, including the normalized production curve, the normalized production integral curve, and the production integral derivative curve, are developed to distinguish the different cases. The influences of some sensitive parameters on decline curves are further discussed. Results show obvious differences on the decline curves between the HWMS and HWSS. The parameters are sensitive on decline curves, which explore the feasible application on production performance evaluation and parameters interpretation through history matching the production data with the compound type curves in this paper.

Horizontal well (HW) has been widely applied to enhance well productivity and prevent water coning in the anisotropic reservoir subject to bottom-water drive. However, the water-cut increases quickly after only one or two years’ production in China while oil recovery still keeps at a very low level. It becomes a major challenge to effectively estimate production distribution and diagnose water-influx locations. Ignoring the effect of nonuniform production distribution along wellbore on pressure response may cause erroneous results especially for water-influx location determination. This paper developed an analytical method to determine nonuniform production distribution and estimate water-influx sections through well-testing analysis. Each HW is divided into multiple producing segments (PS) with variable parameters (e.g., location, production, length, and skin factor) in this model. By using Green’s functions and the Newman-product method, the novel transient pressure solutions of an HW can be obtained in the anisotropic reservoir with bottom-water drive. Secondly, the influences of nonuniform production-distribution on type curves are investigated by comparing the multisegment model (MSM) with the whole-segment model (WSM). Results indicate that the method proposed in this paper enables petroleum operators to interpret parameters of reservoir and HW more accurately by using well-testing interpretation on the basis of bottom-hole pressure data and further estimate water-influx sections and nonproducing segments. Additionally, relevant measures can be conducted to enhance oil production, such as water controlling for water-breakthrough segments and stimulation treatments for nonproducing locations.

Alternating polymer flooding has achieved great attractions recently in oil industry, however, the research of pressure analysis in alternating polymer flooding reservoir is rare. This work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. A new numerical pressure analysis model (three-zone composite model) is established by considering diffusion, convection, shear, and inaccessible pore volume, which is based on the rheology experiments. Based on this model, the type curves are then developed and sensitivity analysis is further conducted. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between low concentration and high concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.

This work presents numerical well testing interpretation model and analysis techniques to evaluate formation by using pressure transient data acquired with logging tools in crossflow double-layer reservoirs by polymer flooding. A well testing model is established based on rheology experiments and by considering shear, diffusion, convection, inaccessible pore volume (IPV), permeability reduction, wellbore storage effect, and skin factors. The type curves were then developed based on this model, and parameter sensitivity is analyzed. Our research shows that the type curves have five segments with different flow status: (I) wellbore storage section, (II) intermediate flow section (transient section), (III) mid-radial flow section, (IV) crossflow section (from low permeability layer to high permeability layer), and (V) systematic radial flow section. The polymer flooding field tests prove that our model can accurately determine formation parameters in crossflow double-layer reservoirs by polymer flooding. Moreover, formation damage caused by polymer flooding can also be evaluated by comparison of the interpreted permeability with initial layered permeability before polymer flooding. Comparison of the analysis of numerical solution based on flow mechanism with observed polymer flooding field test data highlights the potential for the application of this interpretation method in formation evaluation and enhanced oil recovery (EOR).

Variable-fidelity surrogate-based efficient global optimization (EGO) method with the ability to adaptively select low-fidelity (LF) and high-fidelity (HF) infill point has emerged as an alternative to further save the computational cost of the single-fidelity EGO method. However, in terms of the variable-fidelity surrogate-assisted multi-objective optimization methods, existing methods rely on empirical parameters or are unable to adaptively select LF/HF sample in the optimal search process. In this paper, two variable-fidelity hypervolume-based expected improvement criteria with analytic expressions for variable-fidelity multi-objective EGO method are proposed. The first criterion relies on the concept of variable-fidelity expected improvement matrix (VFEIM) and is obtained by aggregating the VFEIM using a simplified hypervolume-based aggregation scheme. The second criterion termed as VFEMHVI is derived analytically based on a modified hypervolume definition. Both criteria can adaptively select new LF/HF samples in the iterative optimal search process to update the variable-fidelity models towards the HF Pareto front, distinguishing the proposed methods to the rests in the open literature. The constrained versions of the two criteria are also derived for problems with constraints. The effectiveness and efficiency of the proposed methods are verified and validated over analytic problems and demonstrated by two engineering problems including aerodynamic shape optimizations of the NACA0012 and RAE2822 airfoils. The results show that the VFEMHVI combined with the normalization-based strategy to define the reference point is the most efficient one over the compared methods.

Quantitative pore-scale multiphase flow characteristics through CO 2 flooding and CO 2 foam flooding after water flooding in oil-wet fractured porous media are hardly investigated and unclear. Therefore, micro-scale visualization displacement experiments of CO 2 flooding and CO 2 foam flooding after water flooding were conducted in this study. Firstly, four micro-scale visualization models are established based on practical sandstone cores. Secondly, micro-scale visual displacement experiments were performed in the conducted porous media. Thirdly, the qualitative analyses of multiphase flow characteristics in different micromodels were carried out. Finally, the volumetric sweep efficiency (VSE), oil recovery factor (ORF) and residual oil distribution were quantitatively analyzed. Results indicate that both the parameters of fractures and displacement methods significantly affect the multiphase flow and residual oil distribution. The residual oil after displacement can be classified into four types: cluster-shaped oil, dead corner oil, oil film and columnar oil. The residual oil after water flooding was mainly cluster-shaped oil and dead corner oil, indicating that sweep efficiency is the main factor restricting ORF of water flooding. Both CO 2 flooding and CO 2 foam flooding displaced most of the cluster-shaped residual oil and dead corner residual oil after water flooding, while CO 2 foam flooding yielded better performance due to the blocking capability of foam system on high permeability areas. The fracture improved the connectivity of micromodels, leading to higher VSE and ORF, but also to earlier fluids breakthrough. Different from wide fracture, narrow fracture significantly improved VSE and ORF. In conclusion, reasonable fracturing and CO 2 foam flooding are advantageous to further enhance oil recovery after water flooding in oil reservoirs. Article Highlights Microscale displacement experiments in micromodels with different pore characteristics through CO 2 flooding and CO 2 foam flooding after water flooding. Qualitative characteristics of residual oil and multiphase flow during CO 2 flooding and CO 2 foam flooding in micromodels. Quantitative evaluation of EOR performance through CO 2 flooding and CO 2 foam flooding after water flooding based on micromodels.