Development Of Oil Reservoirs Research Articles

Development of ensemble learning techniques and sequential model-based optimization for enhancing the generalizability of shale wettability predictions

Quantifying the wettability of shales is important for reservoir exploration and evaluation, as well as CO2 storage. Conventional experimental measurements are time-consuming and costly, while novel machine learning (ML) algorithms are challenged to predict shale wettability with accuracy and generalizability. Therefore, this study introduces an advanced shale wettability prediction framework by fusing ensemble learning algorithm and automatic hyperparameters optimization schemes (AHOS). Specifically, we firstly collected data from various gas geo-storage conditions from the literature. Then, an ensemble learning algorithm was utilized to extract complex nonlinear relationships among influential variables and shale wettability. During the training process, multiple optimization schemes, including random search (RS), Bayesian optimization (BO), and sequential model-based optimization (SMBO), were used and compared to automatically find the optimal hyperparameters of a wettability prediction model. The results show that AHOS can automatically and efficiently obtain the optimal hyperparameters, thus improves model's generalization. In addition, the prediction model based on AHOS process can accurately predict shale wettability. Through sensitivity analysis, we also revealed that the TOC and gas type are the top two most important influencing factors, which provides insights for CO2 sequestration. Moreover, we validated that the CatBoost model outperforms other tree-based models in predicting shale wettability and the SMBO method can provide a more effective result. In summary, the proposed shale wettability prediction framework is promising and efficient, which contributes to the exploration, evaluation, and development of shale oil reservoirs, further benefit to CO2 storage.

Numerical simulation and optimization of biological nanocomposite system for enhanced oil recovery

Abstract Nanofluid flooding is a novel technology with potential for enhanced oil recovery. In this study, a biological nanocomposite system was formed by mixing hexamethyldisilazane-modified hydrophobic nano-SiO2 with a biosurfactant produced by Bacillus. The stability of the system, its influence on rock wettability, and fluid interfacial tension were investigated experimentally. Numerical simulation methods were employed to simulate the displacement efficiency of the biological nanocomposite system and optimize the injection parameters. Finally, the application effects of the system in the field were evaluated. Results indicated that the biological nanocomposite system could change rock wettability and significantly reduce the interfacial tension to 1.8 mN/m at low concentrations. The core flooding results showed that the maximum oil recovery factor of the system reached 47.07%. Numerical simulations optimized the optimal injection concentration to be 7,000 ppm and the volume of injection to be 1.75 × 10–2 pore volumes, resulting in an oil increment exceeding 10,000 m3 in field application. This study provides a solution for the green development of oil reservoirs and provides effective technical support for the numerical simulation and process scheme optimization of biological nanocomposite systems.

Experimental Study on Proppant Migration in Fractures Following Hydraulic Fracturing

Complex fracture technology is key to the successful development of unconventional oil and gas reservoirs, such as shale. Most current studies focus on how to improve the complexity of the fracture network. It is still unclear whether proppant can enter the branch fractures at all levels after the formation of complex fractures. The effects of construction displacement, proppant particle size, proppant density, fracturing fluid viscosity, sand ratio, and other factors on proppant migration in single fractures and complex fractures were studied using an experimental device independently developed by the laboratory. The results show that the lowest point height of the sandbank and the equilibrium height of the sandbank are directly proportional to the particle concentration and density, respectively, and inversely proportional to the displacement and fracturing fluid viscosity. The equilibrium time of the sandbank is inversely proportional to the displacement, particle concentration, and density, respectively, and proportional to the viscosity of the fracturing fluid. Under the same experimental conditions, the larger the branch angle, the smaller the height of the main/secondary fracture sandbank. In the design of the fracturing process, fracturing fluid with varying viscosities and proppant with different densities should be selected according to the formation conditions and fracturing targets. In the face of long fracture lengths, the combination of low-viscosity fracturing fluid with an appropriate viscosity and low-density proppant can meet the goal of placing proppant over long distances and effectively supporting fractures over extended lengths. Subsequently, high-density proppant or reduced construction displacement are adopted to usefully support fractures in the near-wellbore area. The results of this paper can provide theoretical support for proppant selection and fracturing program design.

Synthesis and performance evaluation of low‐damage variable viscosity integrated drag reducer

AbstractTo solve problems such as inadequate proppant carrying capacity, a complex viscosity changing process, and limited environmental friendliness associated with traditional slick water fracturing fluids, a variable viscosity friction reducer called Jianghan friction reducer (JHFR) with low damage, high drag reduction, and strong proppant‐carrying capacity is prepared by inverse emulsion polymerization. The properties of JHFR are investigated by viscometer, JHFR‐II high‐temperature and high‐pressure slick water drag reduction rate tester, surface tension meter, and JHCQ Core dynamic damage evaluation device. The result shows that the dissolution time of JHFR is less than 120 s. The drag reduction of 0.08 wt% JHFR (4.83 mPa s) is 80.3%. When the concentration of JHFR increases from 0.08 to 0.8 wt %, the viscosity of the JHFR increases from 4.83to 97.41 mPa s. After sheared at 90°C and 170 s−1 for 60 min, the viscosity of 0.8 wt% JHFR still maintains 51 mPa s. The damage rate of JHFR to core matrix permeability is lower than 30%. JHFR also shows the advantages of easy breakage and low residue. It provides guidance for the design and selection of fracturing fluid for unconventional oil and gas reservoir development.

Optimization of fracturing technology for unconventional dense oil reservoirs based on rock brittleness index

The concept of volume fracturing has revolutionized the conventional limits of low permeability, expanded the effective resource space, and significantly enhanced oil well production in tight oil reservoir development. This paper elucidates the mechanism of volume fracturing technology for tight sandstone reservoirs by considering multiple factors such as the initiation range of multi-fractures, influence of far-well horizontal principal stress on fracture initiation and propagation, degree of natural fractures development, and mechanical parameters of reservoir rock. Through simulation based on the mechanical parameters of reservoir rock, a comparative analysis was conducted between the model-calculated rock fracture pressure value and measured data from fracturing construction wells in the study area. The results revealed that there was a discrepancy within 10% between the model calculations and actual data. By simulating the effects of different injection volumes of fracturing fluid, pumping rates, and perforation methods on the fracture geometry, optimal design parameters for volume fracturing technology were obtained. Additionally, we propose optimization ideas and suggestions for construction parameters applicable to field operations. The simulation results indicate that a minimum recommended fluid volume scale exceeding 1800 m3 is advised for the reservoir. Based on frictional calculations, it is recommended to have an on-site construction rate not less than 18.0 m3/min along with 36–48 holes/section for perforation purposes. The numerical simulation research presented in this paper provides a theoretical reference basis and practical guidance for the application of fracturing network technology in tight sandstone reservoirs.

Molecular insight into the enhanced oil recovery potential of a seawater-based zwitterionic/anionic surfactant compound for heavy oil reservoirs

Zwitterionic/anionic surfactant mixtures can produce many synergistic effects that benefit heavy oil production. In this work, a seawater-based zwitterionic/anionic surfactant compound was prepared using cocoamidopropyl betaine (CAB) and alkyl polyoxyethylene ether sodium sulfate (AES), emphasizing their synergistic effects in enhancing conventional heavy oil recovery. First, the emulsification capability and the oil displacement efficiency of the surfactant compound were tested through laboratory experiments. Then the impacts of salinity, cation types, surfactant formulation and solution pH on surfactant-surfactant or surfactant-heavy oil interactions were systematically explored through molecular dynamics simulations to unveil the underlying mechanisms of enhanced oil recovery. The results showed that, (1) in a seawater-based system, when the AES/CAB concentration ratio was 1:1, a large wormlike micelle was formed due to the cation bridging of Ca2+ and Mg2+ ions, which not only strengthened the attractive interactions between the AES-SO4− and the CAB-N+ functional groups, but also screened the repulsive interactions between the AES-SO4− and the CAB-COO− functional groups. (2) Through mixed adsorption, the arrangement of AES/CAB molecules at the aqueous/heavy oil interface was more compact. (3) By incorporating the AES/CAB mixture into the associative structures of asphaltene and resins, it could effectively weaken the attraction interactions between the asphaltenes and the resins. Through these synergies, an additional oil recovery of 24.93 % was yielded by combining AES/CAB flooding and subsequent seawater flooding, compared to 19.38 % in the pure AES case. This study provides important insights into the microscopic mechanisms of zwitterionic/anionic surfactant mixtures, which can facilitate the effective development of heavy oil reservoirs and guide the complex formulation of cost-effective surfactant compounds.

Sedimentary Evolution Laws and Main Controlling Factors of the Nenjiang Formation in the Songnan Da’anbei Area, China

Shallow-water deltas serve as a critical area for the exploration and development of terrestrial lacustrine oil and gas reservoirs. Current research on oil and gas exploration and development in China’s terrestrial lacustrine basins primarily focuses on their delta front facies zones. Despite extensive discussions on the sedimentary characteristics of shallow-water deltas by predecessors, there is a lack of comprehensive analysis on the combined effects of dynamic factors such as climate change, lake level fluctuations, and sediment supply. This paper, through a detailed examination of 12 core samples and integrating data from 493 exploratory, appraisal, and development wells in the study area, establishes a stratigraphic correlation framework using well–seismic integration techniques. It identifies two main sedimentary facies types in the southern Da’anbei area of the Songliao Basin: shallow-water deltas and lake facies, which can be further subdivided into four sub-facies and nine microfacies. Two depositional models for the shallow-water deltas of the Southern Songliao Nenjiang Formation are established: a deeper water background with channel-river mouth bar sequences forming the delta front framework and a shallower water background with channel-sheet sand sequences forming the delta front framework. This paper also discusses the controlling effects of paleoclimate, sediment supply, and lake level changes on sedimentary evolution, providing a scientific basis for the exploration of lithologic oil and gas reservoirs in the Nenjiang Formation of the study area and the deployment of horizontal wells.

A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.

Pore-scale investigations of permeability of saturated porous media: Pore structure efficiency

Accurate estimation of permeability and the establishment of correlations with pore space properties have garnered attention due to the increasing demand for oil and gas reservoir development as well as geological carbon sequestration. However, prevailing theoretical and empirical models often rely on porosity and pore sizes as key pore space properties to predict permeability, overlooking the variability of pore structure. To delineate the intrinsic associations between permeability and pore space properties, a self-developed visualized experimental system with controllable pore space properties is used to measure permeability of porous media with varying porosity and particle arrangements. Various parameters, encompassing porosity, pore sizes (maximum pore diameter and pore throat diameter) and fractal parameters (pore fractal dimension, succolarity, and lacunarity) are extracted to quantify pore space properties, and further utilized to develop permeability models. Results demonstrate a positive correlation between permeability and porosity, maximum pore diameter, and average pore throat diameter. Additionally, particle arrangements yield pronounced anisotropy in permeability. Relying solely on porosity and pore sizes to portray pore space properties falls short of comprehensively characterizing permeability. Incorporating fractal characterization through metrics like succolarity and lacunarity emerges as a potent avenue for delineating heterogeneity and pore connectivity. This approach proves useful in characterizing the effect of pore structure variability on permeability. The established permeability model rooted in flow direction succolarity and normalized lacunarity aligns effectively with experimental data, capturing the essential physics of permeability variation.

Detailed Characterization of Pore Results of Continental Shale Reservoir in Fengcheng Formation, Mahu Sag.

The exploration potential of shale oil in the Fengcheng Formation of the Mahu Sag, located in the Junggar Basin, is significant. However, there is a notable dearth of research on shale oil within this formation. This study addresses this gap by focusing on the pore structure and associated development factors of the Fengcheng Formation in Mahu Sag. A total of 113 samples from well X of the Fengcheng Formation were meticulously selected for analysis. The mineral components and pore structure of these samples were characterized using advanced techniques, including X-ray diffraction (XRD), low-temperature nitrogen adsorption (LTNA), high-pressure mercury injection (HPMI), and scanning electron microscopy (SEM). The findings reveal that, despite a relatively low content of clay minerals in the Fengcheng Formation, their presence is intricately linked to pore development. The high content of feldspar in the formation contributes significantly to the formation of clay minerals through dissolution processes. This dual influence plays a crucial role in shaping the overall pore development within the Fengcheng Formation. In addition, a comparative analysis was conducted with shale samples from other wells within the Fengcheng Formation in Mahu Sag, as well as from different basins, such as the Songliao Basin and Ordos Basin. Different from Qingshankou Formation in Songliao Basin and Yanchang Formation in Ordos Basin, the samples from Fengcheng Formation in Mahu Sag are composed of a large number of felic minerals and carbonate minerals with less clay minerals. This study underscores the paramount importance of mineral components and their respective content in influencing the pore development of shale oil reservoirs. The unique characteristics of the Fengcheng Formation in Mahu Sag, as revealed through comprehensive analyses, contribute valuable insights to the understanding of shale oil exploration potential in the Junggar Basin.

Study on the Interaction Propagation Mechanism of Inter-Cluster Fractures under Different Fracturing Sequences

Horizontal-well multi-cluster fracturing is one of the most important techniques for increasing the recovery rate in unconventional oil and gas reservoir development. However, under the influence of complex induced stress fields, the mechanism of interaction and propagation of fractures within each segment remains unclear. In this study, based on rock fracture criteria, combined with the boundary element displacement discontinuity method, a two-dimensional numerical simulation model of hydraulic fracturing crack propagation in a planar plane was established. Using this model, the interaction and propagation process of inter-cluster fractures under different fracturing sequences within horizontal well segments and the mechanism of induced stress field effects were analyzed. The influence mechanism of cluster spacing, fracture design length, and fracture internal pressure on the propagation morphology of inter-cluster fractures was also investigated. The research results indicate that, when using the alternating fracturing method, it is advisable to appropriately increase the cluster spacing to weaken the inhibitory effect of induced stress around the fractures created by prior fracturing on subsequent fracturing. Compared to the alternating fracturing method, the propagation morphology of fractures under the symmetrical fracturing method is more complex. At smaller cluster spacing, fractures created by prior fracturing are more susceptible to being captured by fractures from subsequent fracturing. The findings of this study provide reliable theoretical support for the optimization design of fracturing sequences and fracturing processes in horizontal well segments.

Displacement Mechanism and Flow Characteristics of Polymer Particle Dispersion System Based on Capillary Bundle Model

During the development of oil reservoirs, a rapid increase in water cut following reservoir flooding leads to inefficient or ineffective circulation of injected water, rendering a significant portion of the remaining oil in the reservoir inaccessible. The displacement method using polymer particle dispersion systems effectively solves the issue of rapid water breakthrough in oil reservoirs. Owing to the particle phase separation phenomenon, polymer particles can selectively penetrate into the larger pores where water circulation is inefficient, enhance their flow resistance, and thereby achieve equilibrium displacement along with an increased swept volume. This paper investigates the heterogeneous distribution of polymer particles within a porous medium, incorporates the red blood cell dendrite concentration distribution theory from biological fluid mechanics, and develops a mathematical model to delineate the viscosity characteristics of polymer particle dispersion systems, taking into account the phase separation phenomenon. Building on this foundation, it formulates a capillary bundle model for the polymer particle dispersion system specifically designed for oil displacement and proceeds to determine its relative permeability curve. Simulation outcomes reveal that at a water saturation level of 0.063, the concentration of polymer particles in fractured large pore capillaries is markedly elevated, yet capillaries with a pore size under 26 μm remain devoid of polymer particles. With the increase of water saturation, the concentration of polymer particles in large pore capillaries reduces, whereas it progressively augments in medium pore capillaries. Upon reaching a peak water saturation of 0.751, capillaries smaller than 18 μm are entirely free of polymer particles. These findings suggest that the heterogeneous distribution of polymer particles markedly inhibits the percolation capabilities of the dispersed system following a water phase breakthrough, facilitating the entry of more dispersion into oil-laden capillaries and thus enhancing the flow capacity of the oil phase.

Segmentation Study of Deep Shale Gas Horizontal Wells of the South Sichuan Shale Gas

Summary The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.

Investigating optimal development approaches via bottom hole pressure control in stress-sensitive tight oil reservoirs

After volumetric fracturing, the conventional recovery methods for tight oil reservoirs rely on natural energy depletion. However, the production rate rapidly declines due to their intricate characteristics, such as threshold pressure gradient (TPG), stress sensitivity, and multi-scale porous media. This study plotted permeability loss charts based on stress sensitivity experiments. A pressure distribution equation incorporating TPG and flow in different regions was developed, and production prediction methods for tight oil reservoirs were established. The results revealed the effects of TPG and multi-region flow on pressure distribution, demonstrating the need to control bottom hole pressure (BHP) in tight oil reservoirs. Accordingly, methods to improve tight oil reservoir development were proposed by controlling BHP. Reducing BHP, increasing the imbibition displacement, and improving oil-phase mobility proved conducive to enhanced oil recovery. The development model featuring BHP control for 1000 days with initially rapid and subsequently slower BHP declines demonstrated the highest recovery rate, surpassing depletion development by 7.404%. This research helps us to optimize tight oil reservoir development plans while offering significant practical guidance for developing similar oil reservoirs, which is of the reference value for the industry.

A Novel Quantitative Evaluation Method for Viscosity Reduction Effect of Heavy Oil Cold Recovery Based on The Area Diffusion Process

After thermal recovery, the emulsification viscosity reduction technology for heavy oil cold recovery exhibits low energy consumption and low cost, making it a promising technology for ongoing heavy oil reservoir development. The evaluation and optimization of viscosity reducer is very important for the cold recovery of heavy oil. Prior research mostly employed the high-speed shear technique to measure viscosity following emulsion formation in order to evaluate viscosity reducers. This method ignores the seepage emulsification process under low dynamic conditions of formation, resulting in the selected viscosity reducer ' qualified but not ideal '. Based on the regional diffusion process, a quantitative evaluation method for cold recovery of heavy oil viscosity reduction is put forward. This method is used to simulate the static emulsification effect of heavy oil under real formation conditions, and quantitative evaluation is carried out. The outcomes demonstrate that, in comparison to the conventional assessment approach, this method is more accurate in selecting a viscosity reducer. Appropriately increasing the concentration of the viscosity reducer can improve the efficiency of viscosity reduction. The viscosity reduction effect improves with reservoir temperature. Heavy oil and viscosity reduction agent may be quickly matched using the prediction model of viscosity reduction in cold recovery of heavy oil developed by orthogonal experiment. At the same time, through field practice, the viscosity reducer chosen by this way has a good oil increase impact on oilfield production.

Development and performance evaluation of a novel SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid

Hydraulic fracturing has been proposed as a potential technology for the development of low-permeability oil reservoirs and also has promising application prospects offshore. In this study, a novel SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid was formulated. The fracturing fluid main agents, additives and reducing agents were screened. Besides, the physical and chemical properties (rheology) as well as application (i.e., sand-carrying, gel-breaking, dynamic fluid loss, dynamic damage and anti-swelling) performance of the proposed SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid were systematically investigated. It was revealed that 3.2 wt% AASB-17+1.92 wt% NaSal+0.1 wt% SC-107+0.1 wt% TS3 was the optimal SiO2-enhanced seawater-based clean fracturing fluid system formula. The SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid exhibited remarkable rheological characteristics, the temperature and shear resistance was increased by 28 %, with a maximum temperature resistance of 90ºC. This system can be applied to the fracturing development of most oil reservoirs in the Bohai Bay. In addition, the presence of SiO2 nanoparticles significantly improved the sand-carrying properties of the proposed clean fractuirng fluid system. The experimental results also suggested that the SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid showed excellent performance of shear recovery (fixed shear viscosity recovery rate was 100 %), gel breaking (30 min,1 mPa·s), filter loss (Cw=4.75×10−4 m/min1/2), anti-swelling (anti-swelling rate was 77.78 %) and salt tolerance. This study provides fundamental technical support for the application of SiO2-enhanced seawater-based temperature-resistant clean fracturing fluid in offshore fracturing.

A Method to Identify Pore Fluids in Heterogeneous Conglomerate Reservoirs Using a Nuclear Magnetic Resonance Log with Oil-Based Mud Invasion

Summary Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.

The discrete-imitation modeling concept of the “sucker-rod pump-well-reservoir” system and the optimization of the pumping process

A new approach to dynamic modeling based on a discrete-imitation concept has been developed. The fundamentals, including terms and principles of the concept, have been explained. The presented concept has been applied to the integrated modeling of the development of a volatile oil reservoir operated by a sucker-rod pumping well within a pump-well-reservoir system. The discrete-imitation model of the “pump-well-reservoir” system, developed based on the principles of the new concept, takes into account fluid flow between the annulus and the lifting bore. It was employed to investigate the operation of the sucker-rod pumping well. The correlation between pumping rate, pump fillage, and stroke speed has been investigated. It was observed that, as the stroke speed increases, both pump performance and pump fillage increase up to a certain point. Beyond this threshold, the pumping rate stabilizes, and the pump fillage experiences a sharp decline. Notably, the maximum pump fillage does not always align with the peak pumping rate. In such instances, achieving an optimal regime is possible only through intermittent pumping. An expression has been derived to determine the optimal pump idle time in intermittent mode.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

Numerical characterization of acid fracture wall etching morphology and experimental investigation on sensitivity factors in carbonate reservoirs

Carbonate reservoirs are marked by their low porosity and permeability, naturally occurring fractures that develop in a stochastic fashion and exhibit significant heterogeneity. Deep acidification techniques are essential for the efficient development of such oil and gas reservoirs. The effective distance of acid etching (acid etch fracture length) and the fracture conductivity stand as the two most critical parameters for assessing the efficacy of acidizing. The primary objective of using this technique is to extend the effective distance of the acid etch and enhance the fracture conductivity. The "relay-style" full-length acid etched fracture testing method is employed, achieving an accurate match between the testing temperature, pressure, fracture length, and the actual acid fracturing conditions. It employs a large-scale rock plate acid etching experimental device, in conjunction with 3D laser scanning technology, and utilizes orthogonal experimental design methods to conduct detailed numerical characterization of the rock plate fracture surfaces before and after etching with various acid fluid types, acid injection amounts, and acid injection rates. It quantifies the change in the concentration of the residual acid fluid after the acid-rock reaction, calculating the etching volume of the acid fluid and the length of the acidizing fracture. The experimental results demonstrate that both the gelled acid and the clean diverting acid exhibit long acidification distances and strong inhomogeneous etching capabilities. The etch morphology of the clean diverting acid is dominated by pitting-type and stripe-like dissociation, exhibiting a wavy pattern. In contrast, the etch morphology of the gelled acid appears band-like and groove-like. As the acid injection amount increases, the etch length increases. Under on-site working conditions, etch lengths of 46.42 m and 41.63 m were recorded for 20% gelled acid and clean diverting acid, respectively, after 60 min acid injection time. The factors affecting the etch length sensitivity are in the following order: acid injection rate > acid type > etching time. The optimal acid fracturing parameters to achieve the maximum etch length are: The etch is performed at a pump rate of 600 mL/min for 90 min using gelled acid. Quantitative characterization of acid etch fracture morphology can optimize designing parameters of acid fracturing techniques, enhance the efficiency of their modification, and further enhance the development benefits of oil and gas carbonate rock reservoirs.