Optimization of Gas-Flooding Fracturing Development in Ultra-Low Permeability Reservoirs

Ultra-low permeability reservoirs are characterized by small pore throats and poor physical properties, which areat the root of well-known problems related to injection and production. In this study, a gas injection floodingapproach is analyzed in the framework of numerical simulations. In particular, the sequence and timing of fracturechanneling and the related impact on production are considered for horizontal wells with different fracturemorphologies. Useful data and information are provided about the regulation of gas channeling and possible strategiesto delay gas channeling and optimize the gas injection volume and fracture parameters. It is shown that inorder to mitigate gas channeling and ensure high production, fracture length on the sides can be controlled andlonger fractures can be created in the middle by which full gas flooding is obtained at the fracture location in themiddle of the horizontal well. A Differential Evolution (DE) algorithm is provided by which the gas injectionvolume and the fracture parameters of gas injection flooding can be optimized. It is shown that an improvedoil recovery factor as high as 6% can be obtained.

Numerical study on gas production via a horizontal well from hydrate reservoirs with different slope angles in the South China Sea

It is important to study the effect of hydrate production on the physical and mechanical properties of low-permeability clayey–silty reservoirs for the largescale exploitation of hydrate reservoirs in the South China Sea.In this study,a multiphysical-field coupling model,combined with actual exploration drilling data and the mechanical experimental data of hydrate cores in the laboratory,was established to investigate the physical and mechanical properties of low-permeability reservoirs with different slope angles during 5-year hydrate production by the depressurization method via a horizontal well.The result shows that the permeability of reservoirs severely affects gas production rate,and the maximum gas production amount of a 20-m-long horizontal well can reach186.8 m3/day during the 5-year hydrate production.Reservoirs with smaller slope angles show higher gas production rates.The depressurization propagation and hydrate dissociation mainly develop along the direction parallel to the slope.Besides,the mean effective stress of reservoirs is concentrated in the near-wellbore area with the on-going hydrate production,and gradually decreases with the increase of the slope angle.Different from the effective stress distribution law,the total reservoir settlement amount first decreases and then increases with the increase of the slope angle.The maximum settlement of reservoirs with a 0°slope angle is up to 3.4 m,and the displacement in the near-wellbore area is as high as2.2 m after 5 years of hydrate production.It is concluded that the pore pressure drop region of low-permeability reservoirs in the South China Sea is limited,and various slope angles further lead to differences in effective stress and strain of reservoirs during hydrate production,resulting in severe uneven settlement of reservoirs.

Adaptability of Development Methods for Offshore Gas Cap Edge Water Reservoirs under Different Permeability Levels

The BZ 34-1 oilfield is a typical gas cap edge water reservoir in the Bohai oilfield. The main characteristics of the oilfield were multi-phase sand body stacking and the sand body was composed of three parts: gas cap, oil reservoir, and edge water. The actual production site results show that the permeability difference of multi-layer sand bodies has a serious impact on the development effect. This article establishes a typical reservoir model numerical model based on the total recovery degree of the reservoir and the recovery degree of each layer, and analyzes the impact of permeability gradient. As the permeability gradient increases, the total recovery degree of all four well patterns decreases, and the total recovery degree gradually decreases. The recovery degree of low permeability layers gradually decreases, and the recovery degree of high permeability layers gradually increases. As the permeability gradient increases, the degree of recovery gradually decreases under different water contents. As the permeability gradient increases, the reduction rate of remaining oil saturation in low permeability layers is slower, while the reduction rate of remaining oil saturation in high permeability layers was faster. By analyzing the impact of permeability gradient on the development effect of oil fields, we could further deepen our understanding of gas cap edge water reservoirs and guide the development of this type of oil field.

Extensive application of rate transient method in performance analysis for low permeability gas reservoirs

Rate transient method is a recently-developed performance analysis tool specially designed for low-permeability or tight gas reservoirs. This method, theoretically based on pressure transient analysis, integrates material balance principle and the concept of material balance pseudo-time proposed by Blansingame. With daily production data of gas well, it could be used to calculate OGIP, current formation pressure, permeability, skin factor, to identify complex geologic boundaries, to determine whether drainage boundary has been reached, to calculate drainage area and drainage radius for single well and to predict performance. It has been extensively employed in more than ten low-permeability gas fields. It proves that most problems in performance analysis for low permeability gas reservoirs could be solved by this method. Field practices show great economical benefits could be achieved by employing this method in gas field development.

Advances in enhanced oil recovery technologies for low permeability reservoirs

Low permeability oil and gas resources are rich and have great potential all over the world, which has gradually become the main goal of oil and gas development. However, after traditional primary and secondary exploitation, there is still a large amount of remaining oil that has not been recovered.Therefore, in recent years, enhanced oil recovery(EOR) technologies for low permeability reservoirs have been greatly developed to further improve crude oil production. This study presents a comprehensive review of EOR technologies in low permeability reservoirs with an emphasis on gas flooding, surfactant flooding, nanofluid flooding and imbibition EOR technologies. In addition, two kinds of gel systems are introduced for conformance control in low permeability reservoirs with channeling problems. Finally,the technical challenges, directions and outlooks of EOR in low permeability reservoirs are addressed.

Profile improvement during CO_2 flooding in ultra-low permeability reservoirs

Gas flooding such as CO2 flooding may be effectively applied to ultra-low permeability reservoirs, but gas channeling is inevitable due to low viscosity and high mobility of gas and formation heterogeneity. In order to mitigate or prevent gas channeling, ethylenediamine is chosen for permeability profile control. The reaction mechanism of ethylenediamine with CO2, injection performance, swept volume, and enhanced oil recovery were systematically evaluated. The reaction product of ethylenediamine and CO2 was a white solid or a light yellow viscous liquid, which would mitigate or prevent gas channeling. Also, ethylenediamine could be easily injected into ultra-low permeability cores at high temperature with protective ethanol slugs. The core was swept by injection of 0.3 PV ethylenediamine. Oil displacement tests performed on heterogeneous models with closed fractures, oil recovery was significantly enhanced with injection of ethylenediamine. Experimental results showed that using ethylenediamine to plug high permeability layers would provide a new research idea for the gas injection in fractured, heterogeneous and ultra-low permeability reservoirs. This technology has the potential to be widely applied in oilfields.

Feasibility of Gas Drive in Fang-48 Fault Block Oil Reservoir

The Fang-48 fault block oil reservoir is an extremely low permeability reservoir, and it is difficult to produce such a reservoir by waterflooding. Laboratory analysis of reservoir oil shows that the minimum miscibility pressure for CO2 drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so the displacement mechanism is miscible drive. The threshold pressure gradient for gas injection is less than that for waterflooding, and the recovery by gas drive is higher than waterflooding. Furthermore, the threshold pressure gradient for carbon dioxide injection is smaller than that for hydrocarbon gas, and the oil recovery by carbon dioxide drive is higher than that by hydrocarbon gas displacement, so carbon dioxide drive is recommended for the development of the Fang-48 fault block oil reservoir.

Sediment permeability change on natural gas hydrate dissociation induced by depressurization

The permeability of a natural gas hydrate reservoir is a critical parameter associated with gas hydrate production.Upon producing gas from a hydrate reservoir via depressurization,the permeability of sediments changes in two ways with hydrate dissociation,increasing with more pore space released from hydrate and decreasing due to pore compression by stronger effective stress related to depressurization.In order to study the evolution of sediment permeability during the production process with the depressurization method,an improved pore network model(PNM)method is developed to establish the permeability change model.In this model,permeability change induced by hydrate dissociation is investigated under hydrate occurrence morphology of pore filling and grain coating.The results obtained show that hydrate occurrence in sediment pore is with significant influence on permeability change.Within a reasonable degree of pore compression in field trial,the effect of pore space release on the reservoir permeability is greater than that of pore compression.The permeability of hydrate containing sediments keeps increasing in the course of gas production,no matter with what hydrate occurrence in sediment pore.

Development of the theory and technology for low permeability reservoirs in China

The development theories of low-permeability oil and gas reservoirs are refined, the key development technologies are summarized, and the prospect and technical direction of sustainable development are discussed based on the understanding and research on developed low-permeability oil and gas resources in China. The main achievements include:(1) the theories of low-permeability reservoir seepage, dual-medium seepage, relative homogeneity, etc.(2) the well location optimization technology combining favorable area of reservoir with gas-bearing prediction and combining pre-stack with post-stack;(3) oriented perforating multi-fracture, multistage sand adding, multistage temporary plugging, vertical well multilayer, horizontal and other fracturing techniques to improve productivity of single well;(4) the technology of increasing injection and keeping pressure, such as overall decreasing pressure, local pressurization, shaped charge stamping and plugging removal, fine separate injection, mild advanced water injection and so on;(5) enhanced recovery technology of optimization of injection-production well network in horizontal wells. To continue to develop low-permeability reserves economically and effectively, there are three aspects of work to be done well:(1) depending on technical improvement, continue to innovate new technologies and methods, establish a new mode of low quality reservoir development economically, determine the main technical boundaries and form replacement technology reserves of advanced development;(2) adhering to the management system of low cost technology & low cost, set up a complete set of low-cost dual integration innovation system through continuous innovation in technology and management;(3) striving for national preferential policies.

Numerical simulation-based correction of relative permeability hysteresis in water-invaded underground gas storage during multi-cycle injection and production

By conducting relative permeability experiments of multi-cycle gas-water displacement and imbibition on natural cores,we discuss relative permeability hysteresis effect in underground gas storage during multi-cycle injection and production.A correction method for relative permeability hysteresis in numerical simulation of water-invaded gas storage has been worked out using the Carlson and Killough models.A geologic model of water-invaded sandstone gas storage with medium-low permeability is built to investigate the impacts of relative permeability hysteresis on fluid distribution and production performance during multi-cycle injection and production of the gas storage.The study shows that relative permeability hysteresis effect occurs during high-speed injection and production in gas storage converted from water-invaded gas reservoir,and leads to increase of gas-water transition zone width and thickness,shrinkage of the area of high-efficiency gas storage,and decrease of the peak value variation of pore volume containing gas,and then reduces the storage capacity,working gas volume,and high-efficiency operation span of the gas storage.Numerical simulations exhibit large prediction errors of performance indexes if this hysteresis effect is not considered.Killough and Carlson methods can be used to correct the relative permeability hysteresis effect in water-invaded underground gas storage to improve the prediction accuracy.The Killough method has better adaptability to the example model.

Porosity Calculation of Tight Sand Gas Reservoirs with GA-CM Hybrid Optimization Log Interpretation Method

Tight sand gas reservoirs are our country’s fairly rich unconventional natural gas resources, and their exploration and development is of prime importance. Sulige Gas Field which located in the northern Ordos Basin is tight sand gas reservoirs. It is typically featured by low porosity and low permeability, and the error of porosity calculation by traditional methods is larger. Multicomponent explanation model is built by analyzing the thin slice data, and the objective function is got according to the concept of optimization log interpretation method. This paper puts the Genetic Algorithm and the Complex Algorithm together to form the GA-CM Hybrid Algorithm for searching the optimal solution of the objective function, getting the porosity of tight sandstone gas reservoirs. The deviation got by this method is lesser compared with the core porosity, with a high reliability.

Correction of source-rock permeability measurements owing to slip flow and Knudsen diffusion: a method and its evaluation

Source-rock permeability is a key parameter that controls the gas production rate from unconventional reservoirs. Measured source-rock permeability in the laboratory, however, is not an intrinsic property of a rock sample, but depends on pore pressure and temperature as a result of the relative importance of slip flow and diffusion in gas flow in lowpermeability media. To estimate the intrinsic permeability which is required to determine effective permeability values for the reservoir conditions, this study presents a simple approach to correct the laboratory permeability measurements based on the theory of gas flow in a micro/nano-tube that includes effects of viscous flow, slip flow and Knudsen diffusion under different pore pressure and temperature conditions. The approach has been verified using published shale laboratory data.The ＇＇corrected＇＇（or intrinsic） permeability is considerably smaller than the measured permeability. A larger measured permeability generally corresponds to a smaller relative difference between measured and corrected permeability values. A plot based on our approach is presented to describe the relationships between measured and corrected permeability for typical Gas Research Institute permeability test conditions. The developed approach also allows estimating the effective permeability in reservoir conditions from a laboratory permeability measurement.

Experimental Evaluation of the Mobility Profile of Enhanced Oil Recovery Gases

The mobility profiles of gases used in enhanced oil recovery (EOR) have been thoroughly investigated through the coupling operations of data mining of oilfield data and experimental data analyses. Mobility as an EOR objective function has not been previously applied to characterize potential reservoirs for EOR selection and application, even though it is a robust combinatorial function that benefits from two petrophysical variables, permeability and viscosity. The data mining approach identified mobility as a reliable objective function for reservoir characterisation. The data distribution and clustering results indicate that Gas EOR reservoirs have relatively higher mean mobility than Thermal, Microbial and Chemical EOR reservoirs. The experimental approach investigated EOR gases, CO2, CH4, N2, and Air. A modified Darcy Equation of State for gas flow through porous media was applied to evaluate which gas would competitively attain the oil displacement optimisation criterion for mobility ratio, M ≤ 1. Coupling the data mining with the experimental data results reveals that gas reservoirs can be further categorized by mobility. CH4 (18.16 mD/cp) was observed to have the highest mobility followed by Air (14.60 mD/cp), N2 (13.61 mD/cp), and CO2 (12.96 mD/cp). The gas mobility order significantly corresponds with the mobility distribution of reservoirs that implemented gas EOR processes. It was concluded that CO2 offers relatively lower mobility, therefore, it is the most competitive EOR gas to approach the mobility ratio criterion of unity or less.

Quantitative characterization of shale gas reservoir properties based on BiLSTM with attention mechanism

Evaluating the potential of shale gas reservoirs is inseparable from reservoir properties prediction.Accurate characterization of total organic carbon,porosity and permeability is necessary to understand shale gas reservoirs.Seismic data can help to estimate these parameters in the area crossing-wells.We develop an improved deep learning method to achieve shale gas reservoir properties estimation.The rela-tionship between elastic attributes and reservoir properties is built up by training a deep bidirectional long short-term memory network,which is suitable for time/depth sequence prediction,on the logging and core data.Except some commonly used technologies,such as layer normalization and dropout,we also introduce attention mechanism to further enhance the prediction accuracy.Besides,we propose to carry on the normal scores transform on the input features,which aims to make the relationship between inputs and targets clear and easy to learn.During the training process,we construct quantile loss function,then use Adam algorithm to optimize the network.Not only the characterization results,but also the confidence interval can be output that is meaningful for uncertainty analysis.The well exper-iment indicates that the method is promising for reducing prediction errors when training samples are insufficient.After analyzing in wells,the established model is acted upon seismic inverted elastic attri-butes to characterize shale gas reservoirs in the whole studied area.The estimation results coincide well with the actual development results,showing the feasibility of the novel method on the characterization for shale gas reservoirs.

Key Problems and Countermeasures in CO_(2)Flooding and Storage

Based on literature research in combination with the practice of CO_(2)flooding and storage in Jilin Oilfield,this study assesses the key problems in CO_(2)flooding and storage,proposing the corresponding countermeasures from five aspects of CO_(2)gas source condition,namely geological condition evaluation,scheme design incoordination with other production methods,economic and effectiveness evaluation,together with dynamic monitoring and safety evaluation.The results show that CO_(2)flooding is the most economic and effective CO_(2)storage method.In eastern China,inorganic origin CO_(2)gas reservoirs are widely developed and are especially the most enriched in the Paleozoic carbonate rock strata and the Cenozoic Paleogene–Neogene system,which provide a rich resource base for CO_(2)flooding and storage.In the future,CO_(2)generated in the industrial field will become the main gas source of CO_(2)flooding and storage.The evaluation of geological conditions of oil and gas reservoirs is the basis for the potential evaluation,planning scheme design and implementation of CO_(2)flooding and storage.CO_(2)storage should be below the depth of 800 m,the CO_(2)flooding and storage effects in lowpermeability oil reservoirs being the best.CO_(2)geological storage mechanisms primarily consist of tectonic geological storage,bound gas storage,dissolution storage,mineralization storage,hydrodynamic storage and coalbed adsorption storage.The practice of CO_(2)flooding and storage in Jilin Oilfield demonstratesthat the oil increment by CO_(2)flooding is at least 24%higher than by conventional water flooding.The most critical factor determining the success or failure of CO_(2)flooding and storage is economic effectiveness,which needs to be explored from two aspects:the method and technology innovation along with the carbon peaking and carbon neutrality policy support.After CO_(2)is injected into the reservoir,it will react with the reservoir and fluid,the problem of CO_(2)recovery or overflow will occur,so the dynamic monitoring and safety evaluation of CO_(2)flooding and storage are very important.This study is of great significance to the expansion of the application scope of CO_(2)flooding and storage and future scientific planning and deployment.

INVESTIGATION AND APPLICATION ON GAS-DRIVE DEVELOPMENT IN ULTRA-LOW PERMEABILITY RESERVOIRS

To select a proper displacement medium with the purpose of developing ultra-low permeability reservoirs both effectively and economically, three kinds of gases, including CO2, NG and N2, are studied through physical modeling and numerical simulation under the specified reservoir conditions. The results indicate that the oil recovery through water injection is relatively low in ultra-low permeability reservoirs, where the water breaks through early and the water cut rises rapidly. Gas injection can enhance the production, of which the gas-drive efficiency depends on the injection pressure and the gas itself. CO2 is proved to be the best one after comprehensive consideration of the recovery speed, the overall recovery efficiency and the time needed for gas to break through. The pressure of CO2 injection in the field experiments is lower, compared with that of water-drive. The injectivity index of CO2 is 7.2 times as high as that of water, and the oil production of the test well group increases by about 4 t/d.

Geologic characteristics, controlling factors and hydrocarbon accumulation mechanisms of China’s Large Gas Provinces of low porosity and permeability

Based on the analysis of the geological characteristics and controlling factors, we analyzed the formation mechanism of different types of gas reservoirs. The main characteristics of gas provinces with low porosity and permeability are mainly as follows: large area, low abundance, small gas pools and large gas provinces; widely distributed excellent hydrocarbon source rocks with closely contacted source-reservoir-cap association; development mainly in large continental depressions or in paralic shallow-river delta systems; many kinds of traps coexisting in large areas, dominantly para-layered lithologic, digenetic and capillary pressure traps; double fluid flow mechanisms of Darcy flow and non-Darcy flow; complicated gas and water relations; and having the resource distribution of highly productive "sweet spots", banding concentration, and macroscopically large areas integrated. The main controlling factors of large sandstone gas provinces with low porosity and permeability are stable dynamic backgrounds and gentle structural frameworks which control the extensive distribution of alternate (interbedded) sandstones and mudstones; weak hydropower of large gentle lake basins controlling the formation of discontinuous, low porosity and permeability reservoirs in shallow-water deltas; regionally differential diagenesis and no homogeneous digenetic facies controlling the development of favorable reservoirs and digenetic traps; and weak and dispersive reservoir-forming dynamic forces leading to the widely distributed small traps with low abundance. Low porosity and permeability gas provinces with different trap types have different formation mechanisms which include fluid diversion pressure difference interactive mechanism of lithologic-trap gas accumulations, separated differential collection mechanism of digenetic-trap gas accumulations, and the Non-Darcy flow mechanism of capillary-pressure gas accumulations.

Control factors and porosity evolution of high-quality sandstone reservoirs of Kela-2 gas field in Kuqa Depression

By using the integrated methods includingsandbodies modelling of the outcrops, sedimentary facies ofthe cores and well logs of the drilled wells, and the reservoircorrelation of interwells, it is thought that the sandstone res-ervoirs of Kela-2 gas field are a suit of high-quality naturalgas reservoirs with great thickness, extensive and continuousdistribution, high porosity and permeability, and a few bar-rier beds. Sedimentary facies and microfacies are the mainfactors controlling the reservoir distribution and interiorheterogeneity. Based on a great deal of data of rock’s thinsections, porosity, permeability, and the parameters of capil-lary pressure, the reservoir diagenesis, controls, mechanismand evolution of pores have been studied. It is consideredthat compaction in the early stage and diagenetic dolomiteand calcite cements have effect on the decline of reservoirsproperty. Now compaction is chiefly middle to weak. Thebetter reservoirs have no or a few calcite cements. In theearly of deep buried stage, there are still mainly remainderprimary intergranular pores. The authigenic kaolinite ofreservoirs is the production of the dissolution of feldsparsand lithic fragments. The dissolution results in the partlymodified and broadened secondary intergranular pores. Inthe late of deep buried stage, structure fissures and over-pressure were in favor of improving and preservation ofthese pores.

Experimental Simulation on Dynamic Variation of the Permeability of High-Rank Coal Reservoirs

In terms of the coal reservoir permeability of effective stress, coal matrix shrinkage and gas slippage,we conduct the tests of gas permeability under constant confining pressure and effective stress, as well as illustrate the cumulating method of permeability increment caused by the effects of gas slippage and coal matrix shrinkage.The results show that under the constant confining pressure, gas slippage affecting coal permeability changes to effective stress affecting it mainly. The change point increases with the increase of the confining pressure. The gas slippage effect leads to high permeability under low confining pressure, but coal matrix expansion results in the low value as confining and gas pressures increase. Combined with the drainage process of coalbed methane(CBM)well, the permeability is divided into four change stages based on the above analysis about the three effects, which can improve the change regulation understanding. Four stages are the downward phase under effective stress,the conversion phase of effective stress-coal matrix contraction effect(mainly based on effective stress), the rising stage of the effective stress-coal matrix contraction effect(mainly based on coal matrix contraction effect) and the rising phase of coal matrix contraction-slippage effect(mainly based on slippage effect). Permeability of coal reservoir during the process of drainage and production goes through four stages.

Productivity model for gas reservoirs with open-hole multi-fracturing horizontal wells and optimization of hydraulic fracture parameters

Multi-fractured horizontal wells are commonly employed to improve the productivity of low and ultra-low permeability gas reservoirs.However,conventional productivity models for open-hole multi-fractured horizontal wells do not consider the interferences between hydraulic fractures and the open-hole segments,resulting in significant errors in calculation results.In this article,a novel productivity prediction model for gas reservoirs with open-hole multi-fractured horizontal wells was proposed based on complex potential theories,potential superimposition,and numerical analysis.Herein,an open-hole segment between two adjacent fractures was regarded as an equivalent fracture,which was discretized as in cases of artificial fractures.The proposed model was then applied to investigate the effects of various parameters,such as the angle between the fracture and horizontal shaft,fracture quantity,fracture length,diversion capacity of fractures,horizontal well length,and inter-fracture distance,on the productivity of low permeability gas reservoirs with multi-fractured horizontal wells.Simulation results revealed that the quantity,length,and distribution of fractures had significant effects on the productivity of low permeability gas reservoirs while the effects of the diversion capacity of fractures and the angle between the fracture and horizontal shaft were negligible.Additionally,a U-shaped distribution of fracture lengths was preferential as the quantity of fractures at shaft ends was twice that in the middle area.