Oil Production In Reservoirs Research Articles

Analysis of the impact of geological and engineering parameters on productivity in tight oil reservoirs

AbstractTight oil resources are abundant, but the factors affecting production capacity are complex. In this paper, focusing on tight oil reservoirs, three research works were conducted. First, using the numerical simulation software, a numerical model of tight oil reservoirs was established. Second, the influence of geological parameters such as porosity and permeability on oil production were analyzed. Third, the influence of rock compression coefficient and injection fluid on tight oil production were analyzed. Results show that: (a) When the porosity is 0.05, the cumulative oil production in the first 6 years is the highest, while in the later stage of the simulation, the cumulative oil production with a porosity of 0.1 is the highest. (b) The higher the permeability, the greater the cumulative oil production. The cumulative oil production under different permeability conditions are 1392.044, 2178.805, 2939.1704, and 4038.0878 m3, respectively. (c) Under tight reservoir conditions, the impact of different rock compression coefficients on the daily oil production of oil and gas reservoirs is not very significant. (d) The recovery effect is optimal when using the N2 injection scheme. The effectiveness of the CH4 scheme is second, and there is a certain gap compared to the N2 scheme. The development plan of injecting water has the worst effect. However, compared to the depletion development model, the cumulative oil production by injecting N2, CO2, CH4, and water has all increased.

Interpretable fracturing optimization of shale oil reservoir production based on causal inference

Interpretable fracturing optimization of shale oil reservoir production based on causal inference

Research on Mechanism of Controlling Water and Stabilizing Production in Heavy Oil Reservoirs with Edge-bottom Water

The development of edge-bottom water heavy oil reservoirs typically involves short water-free production period and a rapid increase in water cut, leading to generally low oil recovery factors. Combining the advantages of foam and viscosity reducers for composite development can effectively address the challenges in edge-bottom water reservoirs; however, the mechanism of action remains unclear. In this study, the concentrations of foaming agent and viscosity reducer were initially determined using a foam evaluator and an Anton Paar rheometer. Subsequently, a 2D large flat plate model was employed to conduct a composite group production experiment after water flooding, and then the change in oil saturation during flooding was analyzed by measuring electrical resistance. Finally, the dynamic curves of flooding were compared to analyze the mechanism of water control and oil stabilization (WCOS). The results indicate that the 2D large flat plate model and the method of inverting saturation field maps can effectively simulate the oil-water flow behavior during the composite flooding process after water flooding. The synergistic mechanism of N2 foam controlling bottom water coning and CO2 enhanced viscosity reducer to reduce viscosity in deep areas was revealed, increasing the overall recovery factor by 10.3% compared to water flooding. The mechanism of the combined oil recovery is clarified, which providing a reference for formulating WCOS plans following water flooding.

A novel meshless method for numerical simulation of fractured-vuggy reservoirs

This paper proposes a novel meshless numerical simulation method for fractured-vuggy reservoirs. Initially, model discretization involves extracting fracture and vug feature nodes along the contours of the reservoir bodies and in alignment with fracture orientations, tailored to the characteristics of the fractured-vuggy oil deposit. Subsequently, a connection element model is established within the influence domain. Based on the seepage equations of the connection system, a computational method for the parameters of the connection elements (connection transmissibility and connection volume) is defined. In addition, a sequential method is employed to solve for the pressure and saturation, achieving rapid prediction of the reservoir's production dynamics. On this basis, an automatic history matching algorithm is utilized for real-time fitting of oil–water dynamic indicators, inverting the characteristic parameters of the connection element model, and quantitatively characterizing the injection–production connection elements. The research findings indicate that the method is capable of rapidly fitting and predicting the dynamics of oil reservoir production. Furthermore, conceptual model examples have substantiated that it achieves comparable computational efficiency and superior computational accuracy when compared to the traditional finite difference (volume) method under the same nodal conditions. Additionally, the node arrangement for fractures and vugs is comparatively flexible, and it can ensure the integrity of the flow paths with a limited number of nodes to enhance predictive accuracy. Therefore, this method can effectively meet the rapid prediction requirements for fractured-vuggy reservoirs and also provides a novel meshless computational approach for the numerical simulation of such reservoirs.

Determination of the Main Production Factors and Production Predictions of Test Wells in the Offshore Tight Oil Reservoirs in the L Formation of the Beibu Basin Using Multivariate Statistical Methods

This study addresses the challenge of rapidly and accurately predicting the production of test wells in offshore tight oil reservoirs, specifically within the L Formation of the Beibu Basin. This challenge is particularly pronounced in situations where drill stem tests are limited and evaluating each untested well layer is difficult. To achieve this objective, we analyzed fifteen typical test wells in the L Formation, taking into account both geological and engineering factors. Initially, Pearson correlation analysis, partial correlation analysis, and grey relational analysis were used to identify the main production factors. Based on these analyses, two types of production prediction models were developed: one employing the comprehensive production index method and the other utilizing the production coefficient method. The research identified effective permeability, porosity, oil saturation, and shale content as the main production factors for the test wells in the study area. The model verification results showed that the comprehensive production index model performs effectively for the L Formation, with an average prediction error of 20.40% compared to the actual production values. This research is significant for optimizing and stabilizing production in tight oil reservoirs.

Pressure Transient Solutions for Unbounded and Bounded Reservoirs Produced and/or Injected via Vertical Well Systems with Constant Bottomhole Pressure

Various analytical solutions for computing production and injection-induced pressure changes in aquifers and oil reservoirs have been derived over the past century. All prior solutions assumed a constant well rate as the boundary condition. However, in many practical situations, the fluid withdrawal from and/or injection into such subsurface reservoirs occurs with the aid of pump devices that maintain a constant bottomhole pressure in the well. Until now, how the well rate will decline over time, based on the pressure difference in the well relative to the initial reservoir pressure, could not be rapidly computed analytically (using the diffusivity as the key governing system parameter), because no concise expression had been derived with the boundary condition of a constant bottomhole pressure. The present study shows how the pressure diffusion equation can be readily solved for wells acting as sinks and sources with a constant bottomhole pressure condition. We consider both fractured and unfractured completions, as well as injection and production modes. The new solutions do not require an elaborate time-stepped pressure-matching procedure as in nodal analysis, the only other physics-based analytical method currently available to compute the well rate decline when a constant bottomhole pressure production system is used, which unlike our new method proposed here is limited to single well systems.

Carboxymethyl cellulose-based preformed particle gels for water management in oil and gas reservoirs

Carboxymethyl cellulose (CMC) based materials have been proposed as preformed particle gels (PPGs) for reducing excessive water production in oil and gas reservoirs. Multi-sized dry particles ranging between 100 and 1180 μm have been synthesized using microwave-assisted grafting copolymerization of CMC and acrylamide (AM)/n,n''-methylene-bisacrylamide (MBA). FTIR and SEM confirmed CMC crosslinked polyacrylamide's chemical structure and morphology (CMC/CPAM). Thermo-gravimetric analysis has demonstrated the thermal stability of dry PPGs up to 309 °C. CMC/CPAM showed slightly high absorbency in brine 2 (TDS = 67.3 g/L) compared to brine 1 (TDS = 33.65 g/L), 1% NaCl, and deionized water, with swelling ratios (SR) between 7.1 and 12.9 g/g at room temperature regulated by MBA weight ratio. The effect of particle size, pH, temperature, and aging on SR and mechanical strength was investigated and discussed based on the CMC/CPAM structures. The swollen PPGs showed excellent resistance to temperatures up to 100 °C with a storage modulus of 9 kPa. The particle size was estimated based on salinity, pH, and temperature and controlled between 118 μm and 3 mm at high temperature (100 °C) and high salinity (TDS = 67.3 g/L) conditions to match the need for carbonate reservoirs. Core flooding experiments demonstrated the effective plugging efficiency of the PPG in open fracture models.

Lattice Boltzmann simulation of cross-linked polymer gel injection in porous media

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media.

Numerical simulation study on propagation mechanism of fractures in tight oil vertical wells with multi-stage temporary plugging at the fracture mouth

The multi-stage temporary plugging and diverting fracturing technique stands as a pivotal method for enhancing production in tight oil reservoirs. At present, fracture propagation models in temporary plugging and diverting fracturing primarily focus on single-stage temporary plugging, disregarding intricate mechanisms influenced by multi-stage temporary plugging and inter-fracture interference on the redirection and propagation of artificial fractures. To address this gap, this study employs the extended finite element method and establishes a mechanical model for the propagation of multi-stage temporary plugging fractures in tight oil reservoirs based on the maximum circumferential stress criterion. Relevant numerical simulations are conducted, considering key factors such as horizontal stress differences, fracturing fluid viscosity, injection rate, and initial fracture angle, all of which influence the morphology of diversion fracture propagation. The study rigorously analyzes and compares characteristics such as the radius of diversion fractures, diversion angle, and fracture width profile corresponding to different numbers of temporary plugging stages. Numerical simulations reveal that the primary controlling factor influencing the extension of fractures is the horizontal stress difference. A smaller horizontal stress difference makes fracture diversion easier, resulting in larger redirection radii. The impact of fracturing fluid viscosity on the diversion radius and diversion angle of fractures can be deemed negligible. Larger injection rates during construction facilitate easier diversion, leading to larger diversion radii. Furthermore, when the initial fracture angle exceeds 90°, the diversion radius of fractures is significantly larger compared to cases where the initial fracture angle is less than 90°, indicating a more facile diversion of fractures.

Comparative Evaluation of the Application Effectiveness of Intelligent Production Optimization Methods in Offshore Oil Reservoirs

The development of offshore oil fields confronts challenges associated with high water cut and low displacement efficiency. Reservoir injection-production optimization stands out as an effective means to reduce costs and enhance efficiency in offshore oilfield development. The process of optimizing injection and production in offshore oil reservoirs involves designing strategies for a large number of wells and optimization time steps, constituting a large-scale, complex, and costly optimization computation problem. In recent years, with the rapid advancements in big data and artificial intelligence technologies, sophisticated evolutionary computation methods have found widespread application in reservoir injection-production optimization problems. However, the abundance of intelligent optimization algorithms raises the question of how to choose a method suitable for the complex optimization background of offshore oilfield injection-production optimization. This paper provides a detailed overview of the application of an existing differential evolution algorithm (DE), conventional surrogate-assisted evolutionary algorithm (CSAEA), and global–local surrogate-assisted differential evolution (GLSADE) in the context of practical offshore oilfield injection-production optimization problems. A comprehensive comparison of their performance differences is presented. The study concludes that the global–local surrogate-assisted evolutionary algorithm is the most suitable method for addressing the current challenges in offshore oilfield injection-production optimization.

Few-shot learning and modeling of 3D reservoir properties for predicting oil reservoir production

Few-shot learning and modeling of 3D reservoir properties for predicting oil reservoir production

Multi-stage development process and model of steam chamber for SAGD production in a heavy oil reservoir with an interlayer.

Steam-assisted gravity drainage (SAGD) is an efficient thermal recovery technique for oil sands and extra heavy oil exploitation. The development of steam chamber goes through multi-stage physical processes for SAGD production in a heavy oil reservoir with an interlayer. In this study, considering the situation that an interlayer is located directly above a pair of horizontal wells, we analyzed the whole process of steam chamber development. We divided the whole process into stages I-V, which are the first rising stage, the first lateral expansion stage, the second rising stage, the second lateral expansion stage and the confinement stage, respectively. Particularly, we further divided stage II into 2 periods and stage IV into 3 periods. These stages and periods can help us understand the development process of steam chamber dominated by an interlayer more profoundly. Based on the divided stages and periods, we established different models of SAGD production by assuming different geometric shapes of steam chamber in different stages and periods. Oval shape was assumed in stages I and III, and inverse triangle shape was hypothesized in stages II, IV and V. The formulas of the front distance of steam chamber and the oil production rate of SAGD were deduced from the established models for different development stages. At the end, we performed two example applications to SAGD production in heavy oil reservoirs with an interlayer. The real oil production rates were matched very well with the theoretical oil production rates calculated by the deduced formulas, which implies the multi-stage development model of steam chamber is of reliability and utility.

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.

Impacts of geomechanical damage on waterflood-induced fracture propagation in deeply deposited tight oil reservoirs

Waterflood-induced fractures can enhance the production of deep tight oil reservoirs. However, if waterflood-induced fractures propagate fast, they connect injection wells to production wells earlier, inhibiting the production of tight oil reservoirs. In the present research, the fast propagation mechanism of waterflood-induced fractures was mainly investigated. The changes in sandstone mechanical properties by water were investigated by laboratory experiments, and the relationship of the geomechanical damage of sandstones with water saturation was quantified. Flow-geomechanics-coupled numerical simulations were performed to analyze the impacts of water flooding on stress distribution in a deeply deposited tight oil reservoir. Based on the fracture mechanics theory, the propagation length of the waterflood-induced fracture was calculated and the characteristics of waterflood-induced fracture propagation were analyzed. Experimental results revealed that water changed the mineral composition and microscopic structure of sandstones. This phenomenon decreased the Young’s modulus and tensile strength of sandstones and increased the Poisson’s ratio. The changing magnitude of these properties increased with the rise of water saturation, and the maximum changing magnitude reached 70%. The water saturation distribution became heterogeneous after waterflooding, causing a heterogeneous distribution of mechanical properties. The stress around the fracture tip and the fracture propagation length were significantly affected by these property changes. After the geomechanical damage, the fracture propagation pressure decreased by about 20%. Moreover, the initial fracture length enhanced the propagation length of the waterflood-induced fracture. These results suggest that the propagation of waterflood-induced fractures becomes more significant during waterflooding; thus, the injection pressure should be reduced to avoid fast fracture propagation.

Computational Fluid Dynamics Modeling and Analysis of Axial and Radial Temperature of Wellbore during Injection and Production Process

Summary To solve problems such as additional tubing/casing load, casing deformation, and packer failure caused by changes in annular temperature during oil and gas reservoir fracturing and production, based on the well structure of oil and gas reservoirs and transition transient heat transfer mechanism, a four-field coupling simulation model of the temperature field in the main fluid domain of the tubing, the temperature field in the solid domain of the tubing, the temperature field in the annular fluid domain, and the temperature field in the solid domain of the casing is proposed. Considering the coupling of fluid temperature, pressure, and physical parameters, boundary conditions are established based on reservoir characteristics, wellbore heat transfer characteristics, and fracturing and production conditions, and are compiled into Fluent software for simulation through the user-defined function (UDF) method. The effects of the temperature and flow rate of injected fracturing fluid and produced oil and gas on the distribution of the wellbore temperature field and temperature gradient are studied. The research results show that by applying D14-1 and D5-5 gas wells to the model, the simulated temperature is in good agreement with the measured wellbore temperature, and the maximum errors of the simulated values of the two different wells are 6.4% and 4.3%, respectively. As the injection and production operation time increase, the heat transfer between the wellbore and the formation gradually stabilizes. At this time, the injection and production flow rate have little impact on the wellbore temperature field, while the injection and production temperature have a greater impact on the wellbore temperature field. The injection and production temperature will cause changes in annular temperature and temperature gradient, leading to an increase or decrease in pressure within a limited annular volume, resulting in local stress on the tubing and casing. The research results can provide a theoretical basis for the analysis of the temperature field and pressure field of the wellbore during fracturing and oil and gas production, ensuring the safety and stability of fracturing and production.

Evaluation of Novel Preformed Particle Gel System for Conformance Control in Mature Oil Reservoirs.

To address challenges associated with excessive water production in mature oil reservoirs, this study introduces a carboxymethyl cellulose (CMC)-based material as a novel preformed particle gel (PPG) designed to plug excessive water pathways and redistribute the subsequent injected water toward unswept zones. Through microwave-assisted grafting copolymerization of CMC with acrylamide (AM), we successfully generated multi-sized dry particles within the range of 250-800 µm. Comprehensive analyses, including Fourier-transform infrared spectroscopy (FTIR) and scanning electron microscopy (SEM), have confirmed the chemical composition and morphology of the resulting carboxymethyl cellulose-grafted crosslinked polyacrylamide (CMC/PAMBA). Swelling kinetics and rheology tests were conducted to confirm the ability of this novel PPG system to perform at different reservoir conditions. The results of core flooding experiments showed that the CMC/PAMBA PPG is capable of plugging open fractures with a water breakthrough pressure gradient of up to 144 psi/ft. This preformed particle gel (PPG) system was designed specifically for application in Middle East reservoirs, which are distinguished by high salinity and elevated temperature levels. This PPG system is able to swell up to 10 times its original size in seawater and maintain a strength of about 1300 Pa at a temperature of 80 °C. Further optimization is conceivable to enhance injection efficiency and achieve superior plugging outcomes.

Experimental and numerical simulation study on coupling tripping of partial trapezoidal threaded casing head and casing coupling

Casing connection is a common connection method in oil and gas reservoir production, and the tripping of casing will seriously hinder the production process. To study the casing tripping process and the minimum tensile load required for casing tripping under different loosening buckle states, three kinds of casing tripping tensile tests were carried out. The thread morphology of the casing head and casing coupling was analyzed by local cutting at the end of the experiment, and the thread failure area was analyzed by scanning electron microscope, and then other loosening states were studied and analyzed using numerical simulation. The research results show that as the number of loosening buckles increases, the minimum tensile load required for the casing head and casing coupling to trip decreases. The observation of the thread shape shows that the thread part of the casing head was seriously damaged. Scanning electron microscopy results show that the fracture mode at the thread of the casing head is ductile fracture. Numerical simulation results show that the maximum stress area during the tripping process is at the contact position between the thread heads. Based on the experimental and numerical simulation results, the relationship between the number of casing loosening and the minimum tensile load required for casing tripping is obtained. The research results can be used as the experimental and theoretical basis for the investigation of casing tripping accidents and can also provide experimental reference for the design of the next-generation of casing.

A Crisscross-Strategy-Boosted Water Flow Optimizer for Global Optimization and Oil Reservoir Production.

The growing intricacies in engineering, energy, and geology pose substantial challenges for decision makers, demanding efficient solutions for real-world production. The water flow optimizer (WFO) is an advanced metaheuristic algorithm proposed in 2021, but it still faces the challenge of falling into local optima. In order to adapt WFO more effectively to specific domains and address optimization problems more efficiently, this paper introduces an enhanced water flow optimizer (CCWFO) designed to enhance the convergence speed and accuracy of the algorithm by integrating a cross-search strategy. Comparative experiments, conducted on the CEC2017 benchmarks, illustrate the superior global optimization capability of CCWFO compared to other metaheuristic algorithms. The application of CCWFO to the production optimization of a three-channel reservoir model is explored, with a specific focus on a comparative analysis against several classical evolutionary algorithms. The experimental findings reveal that CCWFO achieves a higher net present value (NPV) within the same limited number of evaluations, establishing itself as a compelling alternative for reservoir production optimization.

GAMMA AND ELECTRO-LOGGING DURING WELL WORKOVER USING THE TECHNOLOGY OF RADIAL BRANCHING OF FORMATION

The efficiency of oil recovery from oil-bearing reservoirs by modern, Abstract. industrially developed development methods in most oil-producing countries today is considered unsatisfactory, and the final oil recovery of reservoirs in various countries and regions averages from 25 to 40 %. For example, in Latin America and Southeast Asia, average oil recovery is 24–27 %, in Iran — 16–17 %, in the USA, Canada and Saudi Arabia — 33–37 %, in the CIS countries and Russia — up to 40 %, depending on the structure of oil reserves and the development methods used [1].Therefore, the task of managing the productivity of oil and gas reservoirs remains relevant at present.The article discusses a special technology for the use of gamma and electro-logging as part of the Perfobur technical system (hereinafter referred to as pyrolysis oil). These geophysical methods of investigation, at the end of drilling radial channels over a small diameter and radius of curvature, performed with trajectory control, make it possible to prove that drilling was carried out in a given reservoir, and provide more detailed information about its productivity.One of the areas of use of pyrolysis oil is enhanced oil recovery, intensification of inflow, restoration of normal operation of wells stopped or hindered due to falling at the bottom of oil field equipment, blocking or contamination of the perforation zone, including during initial penetration [2–5].Complex geological conditions are noted, such as high reservoir fragmentation, heterogeneity of the carbonate reservoir, fracturing, large lateral permeability variability, high oil viscosity and presence of washed zones, caverns after salt-acid treatment (SW) with subsequent steam injection. Under such conditions, it is difficult to develop a field, new well logging methods are required, as well as high-quality logging to determine saturated interbeds. Effective development of the field requires the determination of the current reservoir saturation with higher accuracy, which will help the subsoil user to better develop the field, eliminate stimulation of watered beds, and carry out better and more selective intensification of interbeds. It should be noted that the presence of a steel column practically eliminates the possibility of using electrical logging methods. Therefore, it is recommended to use such methods in an open hole. Drilling of radial channels using the Perfobur technology allows electro-logging with a special tool due to the possibility of repeated entries into the drilled channels [2–5].

Hydro-mechanical numerical analysis of fault reactivation due petroleum production as trigger for submarine slope stability

Oil production in offshore regions involves the transportation of oil and gas in submarine pipelines, which are vulnerable to geological processes triggered by subsurface oil production like fault reactivation. The fault reactivation process can lead to phenomena that impact the seabed, like subsidence and fluid exudation, and can trigger instability of submarine slopes, which can result in environmental and economic damage. The present work addresses a coupled hydromechanical numerical modeling of a hypothetical case involving fault reactivation caused by oil reservoir production and its impact on an overlying submarine slope. The hypothetical case was simulated using a finite element model. The case involves a reservoir which is cut by a fault zone that reaches the seabed. The slope instability studied was induced by the injection and production of fluids in the reservoir. The fault zone is assumed to be a sealing region and a geomechanical and pressure field discontinuity within the reservoir. Int this work was used the Mohr-Coulomb elastoplastic model with Perzyna viscoplastic regularization to represent the behavior of the fault zone and the overlying submarine slope. Results showed that the fault reactivation, caused by the reservoir production, developed shear stress and shear plastic strain along the fault and through the submarine slope, causing horizontal and vertical displacements in the slope mass and acting as a trigger factor for slope stability. Pore pressure increase at the bottom of the slope structure correlated with the injection pressure artificially increased into the reservoir.