The reservoir physical parameters (such as porosity, permeability, phase permeability, etc.) will change in the process of water injection development with the continuous flushing effect of high magnification water drive, which may have adverse effects on development if they cannot be accurately characterized. In this paper, we try to quantitative characterize the time -varying features of pore structure from the microscopic perspective. We used high-resolution 3D micro-CT (MCT) images to supplement the analysis of the physical properties of the rocks, and we used 3D pore network modeling technology to generate a 3D model of the rock samples. Then the relevant static micro-pore parameters are derived to study the changes of rock properties in different periods of development. Pore parameters were obtained to study the changes in porosity, permeability and pore size distribution of the rocks under different expulsion multiples, and to visualize the time-varying pattern of the microstructure of the rock samples under different stages of water injection. Under low-multiple water-driven conditions (10 PV), the physical properties of the rock samples did not change significantly, with an average facies change of only 1.98%. When reaching high multiples of water drive (more than 500PV), the change rate reaches more than 15%. And with the increase of water drive multiples, the distribution of pore radius and throat radius of rock samples showed an obvious right-shift trend, and the pores and throats increased, which was consistent with the results of CT scanning photographs. Equation fitting of the simulation results reveals that the core micro-parameters show an overall logarithmic relationship with the change of water drive. In this paper, a new application of Micro CT is provided to quantify the microstructure of water-injected reservoirs. By adopting this method, the effect of water-drive multiplicity on reservoir structure can be illustrated from a microscopic perspective. Meanwhile, compared with previous studies, this paper further investigates the effect of time-variation based on the qualitative analysis of the effect of time-variation of water-driven in reservoirs, and regresses time-variation curves and formulas through the changes in multiple water-driven states, which fills in the gap of the current lack of quantitative research and provides new understanding and optimization of the development of oilfields. The study will provide a new perspective for understanding and optimizing oilfield development.

Summary The integration of fracturing, energy enhancement, and imbibition (IFEI) has proven successful in shale oil development, with one of the keys to enhancing development efficiency lying in improving imbibition effectiveness during the well shut-in phase. Carbonated water (CW) imbibition effectively combines the advantages of CO2 and water for enhanced oil recovery. Nevertheless, research on its performance in shale oil reservoirs remains scarce, and its application in fracturing has not been investigated. This study, for the first time, proposes using CW as a dispersion medium in the formulation of carbonated fracturing fluid to enhance IFEI development in shale oil. Computed tomography (CT) online scanning experiments were specifically designed to investigate the countercurrent imbibition distance (CID) and recovery (CIR) across various fluids, including formation water, nanovariable viscosity slickwater (NVS) fracturing fluids, and the newly formulated carbonated fracturing fluid. Additionally, separate imbibition experiments were carried out to assess the overall imbibition recovery of these fluids, focusing on exploring various factors influencing the imbibition of carbonated fracturing fluid. CT scans reveal that carbonated fracturing fluid significantly enhances imbibition performance, achieving a CID of 1.75 cm and a CIR of 6.95%. Compared with formation water and NVS fracturing fluids, it exhibits increases in CID by 0.75 and 0.25 cm, and improvements in CIR by 4.77 and 1.90%, respectively. Further insights from the imbibition experiments demonstrate that carbonated fracturing fluid achieved the highest recovery at 29.28%, surpassing NVS fracturing fluids (25.17%) and formation water (10.21%). Enhanced imbibition recovery was facilitated by elevated CO2 content, higher temperatures, and increased matrix permeability. Correlation analysis reveals that among the parameters selected, CO2 content exerts the most significant influence, followed by permeability, with temperature having the least impact. This study offers novel insights into the efficient development of shale oil through IFEI and the use of CW.

Active carbonated water (ACW) imbibition has emerged as a promising enhanced oil recovery method. Nevertheless, the mechanism is insufficiently understood, particularly as pore-scale oil displacement characterization remains unexplored. Furthermore, the influence of key factors on ACW imbibition performance requires systematic investigation. This study employs a custom visualization imbibition apparatus combined with nuclear magnetic resonance scanning to elucidate the pore-scale oil displacement mechanisms in ACW, and subsequently to investigate the effects of key factors on its performance. The results show that water imbibition yields a low recovery of 16.18%, with higher recovery observed in mesopores and macropores. In contrast, carbonated water (CW) imbibition increases recovery by 15.01% compared to water imbibition, with the greatest improvement in micropores, though mesopores and macropores still show higher recovery. The recovery for ACW is further enhanced to 39.22%, with recoveries of 37.16%, 38.33%, and 40.47% in macropores, mesopores, and micropores, respectively. Imbibition recovery increases with surfactant concentration, albeit with diminishing increments. Specifically, recovery increases by 6.96% when surfactant concentration is increased from 0.01 to 0.10 wt. %, and by 2.38% from 0.10 to 0.20 wt. %. Recovery also improves with increased boundary openness and permeability. Notably, the all-faces-open boundary resulted in a 16.64% higher recovery than the two-ends-open condition. Higher permeability further enhances recovery, with improvements of 8.44% and 13.18% observed at 0.31 and 1.19 mD, respectively, relative to 0.08 mD. This study provides new insights into ACW imbibition and offers valuable guidance for its application in tight oil.

Current gas well decline analysis under boundary-dominated flow (BDF) is largely based on the Arps' empirical hyperbolic decline model and the analytical type curve tools associated with pseudo-functions. Due to the nonlinear flow behavior of natural gas, these analysis methods generally require iterative calculations. In this study, the dimensionless gas rate (qg/qgi) is introduced, and an explicit method to determine the average reservoir pressure and the original gas in place (OGIP) for a volumetric gas reservoir is proposed. We show that the dimensionless gas rate in the BDF is only the function of the gas PVT parameters and reservoir pressure. Step-by-step analysis procedures are presented that enable explicit and straightforward estimation of average reservoir pressure and OGIP by straight-line analysis. Compared with current techniques, this methodology avoids the iterative calculation of pseudo-time and pseudo-pressure functions, lowers the multiplicity of type curve analysis, and is applicable in different production situations (constant/variable gas flow rate, constant/variable bottom-hole pressure) with a broad range of applications and ease of use. Reservoir numerical simulation and field examples are thoroughly discussed to highlight the capabilities of the proposed approach. (c) 2025 Sichuan Petroleum Administration. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

In carbon geo-sequestration, CO2 were injected into the reservoir, separating considerable amount of carbon emissions form the atmosphere. Conformance control is one of the key factors affecting carbon sequestration efficiency because high mobility contrast and reservoir heterogeneity would reduce sweep efficiency, leading to poor sequestration efficiency. In this work, the conformance control of non-chemical microbubble in low permeability reservoir was experimental investigated and acquired data was employed for reservoir simulation. Then, reservoir simulations were performed to investigated the sequestration performance of CO2 microbubble. The effect of conformance control, reservoir heterogeneity, gas-liquid ratio and reservoir dip angle were comprehensively analyzed. The results indicated that microbubble can achieve higher total sequestration amount than CO2 gas injection due to superior conformance control, especially in heterogenous reservoir and reservoir with dip angle. Finally, the numerical simulation was performed to predict the ripening of capillary trapped microbubble at geological time scale after injection. To establish the relationship between reservoir simulation and microbubbles ripening simulation, the function between reservoir permeability and simulation parameters is first time introduced. The simulation results demonstrate that microbubbles can maximize capillary trapping, effectively delaying the formation of a gas cap, and reducing the risk of leakage in low permeability reservoirs. In general, simulation results demonstrate that CO2 microbubble is a superior carbon sequestration technology with higher efficiency and safety. This study provides valuable insights and guidelines for field applications of non-chemical CO2 microbubble assisted carbon geo-sequestration.

The propagation of waterflood-induced fractures (WIFs) occurs during prolonged water injection and is influenced by the distribution and properties of natural fractures (NFs). Available numerical models rarely consider fracture activation and rupture in an integrated manner, which makes it difficult to reflect complex fracture morphology. In this paper, we propose a hydraulic-mechanical model with strain-dependent damage variables to describe the dynamic expansion characteristics of WIFs. There are discrete filled NFs in the matrix with non-equal-thickness joint elements, for which we derive the constitutive equations to calculate fracture widths during water injection and production. Damage variables for the matrix and fractures are calculated according to the maximum tensile stress criterion and the Mohr-Coulomb criterion. A comparison between the coupled model and experimental results is conducted to demonstrate its validity. Finally, we simulated and analyzed four influencing factors of the pressure response and fracture evolution. The study demonstrates that fracture behavior and damage area evolution are highly sensitive to injection rate, communication sequence, NF density, and orientation. The activation, cross, and capture interactions between NFs and WIFs complicate the fracture-damage network and enhance seepage efficiency. High injection rates promote crack tip propagation, while lower rates facilitate the evolution of secondary fractures at low pressure. For high NF density reservoirs, low-pressure injection fully activates NFs, aiding damage evolution. In low NF density reservoirs, excessive pressure induces simpler fracture morphologies, making unstable water injection more effective than continuous injection. This work guides appropriately induced fractures to improve water absorption in tight reservoirs.

With the global energy consumption on the rise and the gradual decline in conventional oil production, unconventional reservoirs have received considerable attention in the last decade. However, due to the unique physical properties and a large number of micro/nanopores in unconventional reservoirs, fluid flow in these reservoirs is considerably different from conventional ones. Therefore, it is highly important to conduct research on elucidating these fluid flow mechanisms. Furthermore, to avoid problems associated with the rapid production decline and low recovery efficiency in such reservoirs, an enhanced oil recovery technology that can efficiently and economically develop unconventional reservoirs is urgently required. This paper systematically summarizes the current research on flow mechanisms, including capillary imbibition, molecular-scale fluid flow and productivity prediction in unconventional reservoirs, and introduces the enhanced oil recovery and application status of hydraulic fracturing assisted oil displacement technology, along with a brief analysis of their advantages and disadvantages. This study is intended to serve a reference for the efficient development of unconventional reservoirs. Document Type: Perspective Cited as: Wang, F., Xu, H., Wang, S., Deng, J., Wang, Y. Fluid flow and efficient development technologies in unconventional reservoirs: State-of-the-art methods and future perspectives. Advances in Geo-Energy Research, 2024, 12(3): 237-240. https://doi.org/10.46690/ager.2024.06.07

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil–water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves.

Spontaneous imbibition is an essential method to enhance recovery during fracturing shut-in of tight reservoirs. However, most of the investigations are primarily focused on the mechanism of water imbibition to enhance recovery; the mechanism of fracturing fluid to enhance recovery and the lower limit of imbibition flow are remained insufficiently investigated. This paper identifies the pore structure characteristic of tight reservoirs, the fracturing fluid imbibition, and the lower limit of imbibition flow by combining nuclear magnetic resonance and high-pressure mercury intrusion methods, clarifying the mechanism of fracturing fluid recovery enhancement. The core-scale super diffusion model of fracturing fluid was established, and the sensitivity analysis of imbibition-influencing factors was conducted. The experimental results indicated that high interfacial tension increased the driving force and decreased the lower limit of imbibition flow, while low interfacial tension decreased the crude oil flow resistance and increased the lower limit of imbibition flow. The imbibition recovery improved with the increase of matrix permeability and decreased with the increase of crude oil viscosity. The degree of mobilization of micropores decreases and the degree of mobilization of mesopores with macropores increases with decreasing interfacial tension. The increase in matrix permeability elevated the degree of mobilization of each pore, while the increase of crude oil viscosity decreased the reduction of each pore. The simulation results fitted well with the experimental data, verifying the reasonableness of the model. The results indicated that the imbibition recovery was positively correlated with the characteristic parameters of the capillary force and negatively correlated with the core length and the viscosity of the fracturing fluid. The investigation in this paper provides a new theoretical basis for the improvement of recovery in tight reservoirs.

CO 2 flooding is a widely-used technique for enhancing oil production, with miscible CO 2 flooding exhibiting higher recovery potential compared to both immiscible and near-miscible CO 2 flooding. However, the problem of insufficient CO 2 supply is increasingly critical in many reservoirs. When faced with a shortage of gas supply, the key to the successful implementation of miscible CO 2 flooding lies in accurately predicting the MMP of impure CO 2 . This study leverages MMP data derived from both experimental and simulation results, utilizing both linear and nonlinear regression methodologies to formulate empirical correlations for MMP prediction. In addition, ridge regression is used to solve collinearity problem. Compared with former investigations, the impure CO 2 correlation proposed in this study integrates the ratio of the specific injection gas mole fraction to the crude oil mole fraction as novel independent variables. This inclusion reflects the actual interaction between the specific injection gas and crude oil during the miscibility process. Furthermore, the correlation can be linearized to the greatest extent through this way and such linearization illustrates the fundamental concepts more distinctly, offering a more practical and comprehensible approach. This formula combines the prediction of the minimum miscible pressure with the interaction mechanism of the miscible process, and the dominant factors in the miscible process can be determined. In terms of reducing the minimum miscible pressure, the interaction between C 4 + C 5 in the injected gas and C 1 + N 2 in the crude oil component is the strongest, while the interaction between N 2 in the injected gas and C 2-6 in the crude oil was most significant in increasing the minimum miscible pressure by comparison. The correlations presented for impure CO 2 yield an average absolute deviation of 2.18 % and sustain a relative deviation within +/- 10 %, surpassing previously published correlations. This study highlights the accuracy and effectiveness of the developed correlations for estimating MMP for impure CO 2 . The suggested MMP correlation offers a practical and efficient means of determining MMP for the implementation of impure CO 2 miscible flooding in the field.

Abstract As a novel, economic, and environmentally friendly enhanced oil recovery (EOR) and carbon sequestration technology, non-chemical CO2 microbubble (MB) has potential applications in low permeability reservoirs. At present, there are only few studies available focusing on non-chemical MB EOR in low permeability reservoirs. Previous studies mainly focused on its storage efficiency in saline aquifers, and more research is needed to fully understand the EOR mechanism in low permeability. In this paper, the EOR performance and its mechanisms of non-chemical CO2 MB in low permeability reservoirs are experimentally investigated. For comparations, a series of CO2-based method were also included, such as CO2 injection, water altering gas and conventional foam. The results demonstrate that CO2 MB has competitive EOR performance to conventional foam injection. The increment oil recovery of microbubbles on 2.23×10−3 μm2 and 9.46×10−3 μm2 rock samples are 11.74% and 19.59% original oil in place (OOIP), respectively. In parallel coreflood experiment, the MB increased oil recovery by 10.73% and 17.92% of OOIP on core samples with the permeability of 9.43×10−3μm2 and 2.25×10−3μm2, respectively. The CT imaging shows that the core sample has lots of residual oil zones due to microheterogeneity. After MB flooding, the average residual oil saturation of the core sample is reduced from 42.15% to 33.5% and the horizontal and vertical residual oil zones are eliminated. The results of this study comprehensively evaluated the feasibility and EOR performance of non-chemical CO2 MB in low permeability reservoirs. Overall, the results suggest that non-chemical CO2 MB is an efficient EOR method which has better displacement efficiency and conformance control ability than other CO2-based non-chemical EOR method (CO2 injection and WAG).

Fracturing fluids countercurrent imbibition is a significant method to enhance recovery during hydraulic fracturing and soaking in shale reservoirs. Most investigations have primarily focused on the fracturing fluids imbibition recovery. In this work, an on-line computed tomography device was employed for the first time to conduct experiments on the imbibition distance of fracturing fluids, quantifying the imbibition distance of fracturing fluids, establishing the model of fracturing fluids imbibition, and clarifying the mechanism of countercurrent imbibition for fracturing fluids. The findings demonstrated that the imbibition distance was 2.625 cm for high mass fraction fracturing fluid and 2.375 cm for low mass fraction fluid. For formation water with viscoelastic fracturing fluids, the imbibition distances were 1.125 and 0.875 cm. Compared to the permeability of 0.082 x 10(-3) mu m(2), the imbibition distance increased by 2.625 times at 0.217 x 10(-3) mu m(2) and by 3.25 times at 0.760 x 10(-3 )mu m(2). At injection pressures of 20 and 15 MPa, the imbibition distance increased by 1.7 and 1.61 times, compared to 5 MPa. Parameter sensitivity analysis demonstrated that crude oil and fracturing fluids viscosity were negatively correlated with imbibition distance. Low interfacial tension boosts imbibition power, extending the imbibition distance. High interfacial tension raises flow resistance, shortening the imbibition distance. Reducing the contact angle improves hydrophilicity and capillary force, extending the imbibition distance. When the permeability is below 1 x 10(-3) mu m2, the imbibition distance increases significantly with rising permeability. When the permeability exceeds 1 x 10(-3 )mu m(2), the rate of increase diminishes. The investigation in this paper provides guidance for the efficient development of shale oil.

Fractured gas condensate reservoirs (FGCR) are a complex, special, and highly valuable type of gas reservoir, accounting for a significant proportion of gas reservoir development. In recent years, with the continuous advancement of horizontal well technology, it has become the main approach for the development of FGCR. The current model is unable to accurately represent the fluid distribution in the near-well area of horizontal wells due to the unique retrograde condensation phenomenon in GCR. Additionally, the presence of fractures complicates the solution of traditional analytical models. In response to this issue, this paper proposes a novel semianalytical model for horizontal wells in FGCR, which incorporates natural fractures, multiphase flow, and the influence of stress sensitivity on pressure response. A dual-porosity model is employed to simulate fractured reservoirs, and a four-region radial composite model is developed to characterize multiphase flow resulting from retrograde condensation in GCR. The pseudopressure transform, Pedrosa transform, Laplace transform, and Finite Cosine transform are utilized to address the nonlinear partial differential equation. A systematic verification of the semianalytical solution is confirmed through a comparison with the numerical solution from computer modeling group (CMG). We thoroughly explain the physical significance of the various features by identifying the 12 flow regimes of the typical curve. Furthermore, we offer a method for assessing the extent of retrograde condensation and the size of the retrograde condensate region based on the curve's characteristics. Finally, the pressure measurements recorded from the Bohai field are carried out to validate the accuracy of the proposed model. The results show that the predictions of the new model are in good agreement with the actual production data, demonstrating the proposed solution's applicability.

Abstract Fracturing flooding is a new energy-supplement technique emerging in recent years, which requires delivering high-efficiency oil agents to the sites with enriched remaining oil through fracturing. In this paper, we introduce the main characteristics of fracturing flooding technique. The pressure responses of induced horizontal fracture of injection well is obtained by modelling the fluid flow in the fractures with variable-mass-radial flow by point source method. The fracture-closure induced flow-rate change is considered by Duhamel’s principle. Compared with conventional fractured well, the fracture properties in fracturing flooding wells vary with time during the shut-in testing period since they are not strengthened by proppants. Linear-flow analysis, fracture-storage coefficient analysis, and fracturing flooding interference analysis methods are comprehensively discussed and compared to estimate the fracture parameters based on the measured bottom-hole pressure data.

Carbonated water (CW) injection refers to a development method that involves dissolving CO2 in water under specific temperatures and pressures, followed by its injection into reservoirs for oil recovery. This technique can simultaneously enhance oil recovery and facilitate CO2 storage, although its effectiveness requires further improvement. To address this, an advanced approach known as enhanced carbonated water (ECW) injection has been proposed. This approach involves the addition of other fluids to CW, including polymers, nanofluids, surfactants, and low salinity water, to serve as displacement media during oil recovery. It aims to leverage the advantages of various technologies to further enhance oil recovery and CO2 storage effectiveness. Although ECW injection exhibits significant application potential, a systematic summary of its research progress is still lacking. Therefore, this article aims to fill this gap by systematically summarizing the latest research on ECW injection, detailing the mechanisms and performance in enhancing oil recovery and achieving CO2 storage. The method effectively exploits the synergistic benefits of CW and various displacement agents. Its primary mechanisms include increasing the dissolution of CO2 and prolonging the duration of CO2 retention in the water, reducing interfacial tension, and altering wettability. Both laboratory experiments and numerical simulations have demonstrated that ECW injection can significantly boost recovery and offer promising results in CO2 storage, presenting it as a highly prospective method for reservoir development. In addition, this paper discusses the main challenges facing this technology and explores potential future research directions, aiming to provide robust guidance for the research and application of this technology.

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir, a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed, and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established. The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure. In the early stage of production or in areas far from the wellbore with high reservoir pressure, the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models. In the late stage of production or in areas close to the wellbore with low reservoir pressure, the condensate oil saturation can be calculated using the data of constant composition expansion test. In the middle stages of production or when reservoir pressure is at an intermediate level, the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure. Through simulation and field application, the new method is verified to be reliable and practical. It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Carbonated water (CW) is defined as water in which CO 2 has been dissolved. Utilizing CW as the imbibition fluid enables the simultaneous exploitation of capillary forces and CO 2 diffusion, resulting in enhanced oil recovery (EOR) and facilitating CO 2 sequestration. Nevertheless, the literature reveals a notable scarcity of research on the imbibition of CW in shale oil reservoirs. In this study, the imbibition experiments involving formation water, surfactant, CW, and active carbonated water (ACW) were conducted on shale cores, considering reservoirspecific temperatures and pressures. Furthermore, the countercurrent imbibition distance (CID) for these fluids was quantitatively characterized using online computed tomography scanning. The EOR performance, alongside the CID and countercurrent imbibition recovery (CIR), is further compared to highlight differences in effectiveness among the fluids. The experimental results demonstrate the imbibition recovery for formation water is 10.66 %. CW and ACW can significantly enhance the imbibition recovery, achieving 28.82 % and 34.65 %, respectively, both of which are higher than surfactant. The CID and CIR for formation water are 1.125 cm and 2.35 %, respectively. While surfactant can increase the imbibition spread area and the efficiency of imbibitiondriven oil recovery to some extent, CW and ACW exhibit even great efficacy, evidenced by their higher CIDs of 1.875 cm and 2.375 cm, and CIRs of 7.09 % and 9.30 %, respectively. This paper, for the first time, investigates the imbibition recovery, CID and CIR of CW and ACW in shale matrices, which uncovers the potential for CW/ ACW imbibition in enhancing shale oil recovery.

压裂直井和多级压裂水平井是致密油气藏目前研究的主要井型,鲜有研究多层致密油气藏分层压裂井合采时非均匀导流能力裂缝参数解释问题.针对多层致密油气藏分层压裂工艺,摒弃致密储层传统压裂缝导流能力均匀的假设,考虑分层压裂缝扩展差异性引起的压裂缝导流能力不均匀现象,通过Laplace空间变换、Duhamel叠加原理和Stehfest数值反演方法,建立了具有非均匀导流能力压裂缝的多层致密油气藏分层压裂试井分析模型,研制了识别多层致密油气藏分层压裂井流动特征的试井分析图版,分析了井筒储集系数、裂缝表皮系数、压裂缝导流能力分布特征、储层物性等对油气渗流规律的影响.结果表明:多层致密油气藏分层压裂储层的油气渗流可分为5个阶段,早期流动阶段受井筒储集系数和裂缝表皮系数影响,中期流动阶段受压裂缝长度及导流能力控制;在相同生产压差下,增大各层压裂缝长度和导流能力有利于提高油气井产量;忽略压裂缝导流能力和压裂缝扩展的非均匀现象,将低估压裂缝区域压力损耗、高估压裂生产井早期产能.通过实例井试井解释,获取了各层裂缝参数.

During the production of fractured low-permeability gas condensate reservoir (FLPGCR), a phase transition takes place in both the formation and wellbore, resulting in multiphase flow when the pressure drops below the dew point pressure. Additionally, the presence of fractures causes the formation of stress-sensitive characteristics. Nevertheless, traditional analytical models, such as the two-region model or three-region model, overlook the coupling impact of the above factors, which could lead to incorrect pressure transient response and erroneous estimation of well and formation parameters. Therefore, this work presents a semianalytical model for an FLPGCR considering the effects of multiphase flow, stress-sensitive, and wellbore phase redistribution. The gas condensate reservoir is divided into N banks, and the radial fluid saturation variation is modeled by multiple annular reservoirs with a constant saturation in each annular reservoir. The behavior of a fractured reservoir is modeled by using the dual-porosity model. The Pedrosa transform was utilized to address the nonlinear differential equation arising from stress-sensitive behavior. To verify the semianalytical solution, it was compared with numerical simulation results from CMG. The results showed that there are 10 flow regimes for the proposed model. The shape of the type curve has the potential to identify the degree of blockage within the FLPGCR. The wellbore phase redistribution only affects the first transitional-flow regime, which slows the rate of pressure drop. The stress sensitivity will lead to the upward characteristic of the curve in a later stage. More attention should be paid to the upward pressure derivative curve at late times, which is conventionally regarded as the effect of a closed boundary when it may not be the case. In addition, the shape factor and composite radius may obscure the radial flow regime. Finally, the proposed model was applied to interpret the pressure measurements recorded from the Bohai field in China, which exhibits a better fitting quality than the traditional models.

Naturally fractured gas reservoirs have contributed significantly to global gas reserves and production. The classical gas-well decline analysis relies largely on Arps' empirical decline models, or modern production decline analysis associating with pseudo-variables. The explicit original gas in place determination methodology is extended from homogeneous reservoir to naturally fractured reservoir under constant or variable bottom-hole pressure conditions in gas-well rate decline analysis. Then, the relationship between gas flow rate and average reservoir pseudo-pressure in the boundary-dominated flow period is re-derived. This formula is in the same format with the equation for homogeneous reservoir by due to the introduction of a new productivity index parameter that captures the inter-porosity flow between fracture and matrix in the natural fractured reservoir. The proposed step-bystep procedures are applied here, which enable the estimation of decline exponent and the explicit and straightforward determination of the original gas in place without any iterative calculations. Four simulated cases prove that our methodology can be successfully used in heterogeneous naturally fractured reservoirs with irregular boundary under constant or variable bottom-hole pressure conditions.