CO_(2)flooding enhanced oil recovery(CO_(2)-EOR)represents a significant technology in the low permeability reservoir.With the fractures and heterogeneity in low permeability reservoirs,CO_(2)-EOR is susceptible to pe...CO_(2)flooding enhanced oil recovery(CO_(2)-EOR)represents a significant technology in the low permeability reservoir.With the fractures and heterogeneity in low permeability reservoirs,CO_(2)-EOR is susceptible to pessimistic gas channeling.Consequently,there is a need to develop conformance control materials that can be used in CO_(2)-EOR.Herein,to address the challenges of low strength and poor stability of polymer gel in high temperature and low permeability reservoirs,a new organic/metal ion composite crosslinking polymer gel(AR-Gel)is reported,which is formed by low hydrolysis and medium to high molecular weight polymer(CX-305),organic crosslinking agent(phenolic resin),and aluminium citrate(AI(Ⅲ)).The crosslinking of AI(Ⅲ)with carboxyl group and organic/metal ion double crosslinking can construct a more complex and stable polymer gel structure on the basis of traditional chemical crosslinking,to cope with the harsh conditions such as high temperature.The structure-activity relationship of AR-Gel was revealed by rheology behavior and micro-morphology.The applicability of AR-Gel in reservoir was investigated,as was its strength and stability in supercritical CO_(2).The anti-gas channeling and enhanced oil recovery of AR-Gel were investigated using low permeability fractured cores,and the field process parameters were provided.The gel can be used to meet supercritical CO_(2)reservoirs at 110℃and 20,000 mg/L salinity,with long-term stability over 60 days.The plugging rate of AR-Gel for fractured co re was 97%,with subsequent CO_(2)flooding re sulting in an enhanced oil recovery by 34.5%.ARGel can effectively control CO_(2)gas channeling and enhanced oil recovery.It offers a new material with high strength and temperature resistance,which is particularly beneficial in the CO_(2)flooding for the conformance control of oil field.展开更多
This study focuses on the hydrated ion bridge(HIB)effect at the oil-rock interface in low-to ultra-low-permeability oil reservoirs.It systematically summarizes the research methodologies,formation mechanisms,interacti...This study focuses on the hydrated ion bridge(HIB)effect at the oil-rock interface in low-to ultra-low-permeability oil reservoirs.It systematically summarizes the research methodologies,formation mechanisms,interaction strength,and disruption mechanisms of HIB,and discusses the influencing mechanisms of HIB on the occurrence state and mobility of crude oil.On this basis,the key challenges inherent in the current HIB research are analyzed,and prospective directions for future development are proposed.Currently,research in this field primarily relies on experimental characterization techniques and molecular simulation methods.The microscopic interactions involved in HIB formation mainly include electrostatic interactions,hydrogen bonds and van der Waals forces.Notably,the hydrogen bonds between polar molecules in crude oil and hydrated ions serve as the primary sites for disrupting the HIB effect.The interaction strength of HIB is collectively modulated by ion type and concentration,reservoir solution environment,mineral type of reservoir rocks,and polar components in crude oil,which subsequently influence the occurrence state and mobility of crude oil.Systematic challenges persist in HIB-related research across three dimensions:research methodologies,scale integration and geological complexity.Specifically,the dynamic evolution mechanism of HIB remains inadequately elucidated;a discontinuity exists in the connection of spatiotemporal cross-scale modeling and prediction;and the reproducibility of actual geological environments in experimental settings is insufficient.Future research may pursue breakthroughs in the following three aspects:(1)developing in-situ dynamic experimental characterization techniques and machine learning-augmented simulation strategies;(2)establishing a framework for cross-scale model fusion and upscaling prediction;and(3)conducting in-depth studies on HIB under the coupled effects of complex mineral systems and multi-physical fields.展开更多
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 exploi...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.展开更多
The relationships between permeability and dynamics in hydrocarbon accumulation determine oil- bearing potential （the potential oil charge） of low perme- ability reservoirs. The evolution of porosity and permeabilit...The relationships between permeability and dynamics in hydrocarbon accumulation determine oil- bearing potential （the potential oil charge） of low perme- ability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member of the Shahejie Formation in the Dongying Sag has been investigated by detailed core descriptions, thin section analyses, fluid inclusion analyses, carbon and oxygen isotope analyses, mercury injection, porosity and permeability testing, and basin modeling. The cutoff values for the permeability of the reservoirs in the accumulation period were calculated after detailing the accumulation dynamics and reservoir pore structures, then the distribution pattern of the oil-bearing potential of reservoirs controlled by the matching relationship between dynamics and permeability during the accumulation period were summarized. On the basis of the observed diagenetic features and with regard to the paragenetic sequences, the reservoirs can be subdivided into four types of diagenetic facies. The reservoirs experienced two periods of hydro- carbon accumulation. In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high permeability ranging from 10 × 10-3 gm2 to 4207 × 10-3 lain2. In the later accumulation period, the reservoirs except for diagenetic facies C had low permeability ranging from 0.015 × 10-3 gm2 to 62× 10-3 -3m2. In the early accumulation period, the fluid pressure increased by the hydrocarbon generation was 1.4-11.3 MPa with an average value of 5.1 MPa, and a surplus pressure of 1.8-12.6 MPa with an average value of 6.3 MPa. In the later accumulation period, the fluid pressure increased by the hydrocarbon generation process was 0.7-12.7 MPa with an average value of 5.36 MPa and a surplus pressure of 1.3-16.2 MPa with an average value of 6.5 MPa. Even though different types of reservoirs exist, all can form hydrocarbon accumulations in the early accumulation per- iod. Such types of reservoirs can form hydrocarbon accumulation with high accumulation dynamics; however, reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation conditions with low accumu- lation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock, Also at these depths, lenticular sand bodies can accumulate hydrocarbons. At shallower depths, only the reservoirs with oil-source fault development can accumulate hydrocarbons. For flat surfaces, hydrocarbons have always been accumulated in the reservoirs around the oil-source faults and areas near the center of subsags with high accumulation dynamics.展开更多
The resistivity experimental measurements of core samples drilled from low permeability reservoirs of Ordos Basin, Northwest China, illustrate that the cementation factors are not agminate, but vary from 1.335 to 1.74...The resistivity experimental measurements of core samples drilled from low permeability reservoirs of Ordos Basin, Northwest China, illustrate that the cementation factors are not agminate, but vary from 1.335 to 1.749. This leads to a challenge for the estimation of water and hydrocarbon sa- turation. Based on the analysis of Purcell equation and assumption that rock resistivity is determined by the parallel connection of numerous capillary resistances, a theoretical expression of cementation factor in terms of porosity and permeability is established. Then, cementation factor can be calculated if the parameters of porosity and permeability are determined. In the field application, porosity can be easily obtained by conventional logs. However, it is a tough challenge to estimate permeability due to the strong heterogeneity of low permeability reservoirs. Thus, the Schlumberger Doll Research （SDR） model derived from NMR logs has been proposed to estimate permeability. Based on the analysis of the theoretical expressions of cementation factor and SDR model, a novel cementation factor prediction model, which is relevant to porosity and logarithmic mean of NMR T2 spectrum （T21m）, is derived. The advantage of this model is that all the input information can be acquired from NMR logs accurately. In order to confirm the credibility of the novel model, the resistivity and corresponding laboratory NMR measurements of 27 core samples are conducted. The credibility of the model is confirmed by compar- ing the predicted cementation factors with the core analyzed results. The absolute errors for all core samples are lower than 0.071. Once this model is extended to field application, the accuracy of water and hydrocarbon saturation estimation will be significantly improved.展开更多
In view of the problems of high injection pressure and low water injection rate in water injection wells of low permeability reservoirs featuring high temperature and high salinity,two new surfactants were synthesized...In view of the problems of high injection pressure and low water injection rate in water injection wells of low permeability reservoirs featuring high temperature and high salinity,two new surfactants were synthesized,including a quaternary ammonium surfactant and a betaine amphoteric surfactant.The composite surfactant system BYJ-1 was formed by mixing two kinds of surfactants.The minimum interfacial tension between BYJ-1 solution and the crude oil could reach 1.4×10^(-3) mN/m.The temperature resistance was up to 140℃,and the salt resistance could reach up to 120 g/L.For the low permeability core fully saturated with water phase,BYJ-1 could obviously reduce the starting pressure gradient of low permeability core.While for the core with residual oil,BYJ-1 could obviously reduce the injection pressure and improve the oil recovery.Moreover,the field test showed that BYJ-1 could effectively reduce the injection pressure of the water injection well,increase the injection volume,and increase the liquid production and oil production of the corresponding production well.展开更多
Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant...Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate(APGSHS) and zwitterionic surfactant octadecyl betaine(BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile,the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt%while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.展开更多
It is very important to design the optimum starting time of water injection for the development of low permeability reservoirs. In this type of reservoir the starting time of water injection will be affected by a rese...It is very important to design the optimum starting time of water injection for the development of low permeability reservoirs. In this type of reservoir the starting time of water injection will be affected by a reservoir pressure-sensitive effect. In order to optimize the starting time of water injection in low permeability reservoirs, this effect of pressure change on rock permeability of low permeability reservoirs was, at first, studied by physical simulation. It was shown that the rock permeability decreases exponentially with an increase in formation pressure. Secondly, we conducted a reservoir engineering study, from which we obtained analytic relationships between formation pressure, oil production rate, water production rate and water injection rate. After our physical, theoretical and economical analyses, we proposed an approach which takes the pressure-sensitive effect into consideration and designed the optimum starting time of water injection, based on the principle of material balance. Finally, the corresponding software was developed and applied to one block of the Jiangsu Oilfield. It is shown that water injection, in advance of production, can decrease the adverse impact of the pressure-sensitive effect on low permeability reservoir development. A water-flooding project should be preferably initiated in advance of production for no more than one year and the optimum ratio of formation pressure to initial formation pressure should be maintained at a level between 1.05 and 1.2.展开更多
CO_(2) flooding has been widely studied and applied to improve oil recovery from low permeability reservoirs.Both the experimental results and the oilfield production data indicate that produced oil components(POC)wil...CO_(2) flooding has been widely studied and applied to improve oil recovery from low permeability reservoirs.Both the experimental results and the oilfield production data indicate that produced oil components(POC)will vary during CO_(2) flooding in low permeability reservoirs.However,the present researches fail to explain the variation reason and rule.In this study,the physical model of the POC variation during CO_(2) flooding in low permeability reservoir was established,and the variation reason and rule were defined.To verify the correctness of the physical model,the interaction rule of the oil-CO_(2) system was studied by related experiments.The numerical model,including 34 components,was established based on the precise experiments matching,and simulated the POC variation during CO_(2) flooding in low permeability reservoir at different inter-well reservoir characteristics.The POC monitoring data of the CO_(2) flooding pilot test area in northeastern China were analyzed,and the POC variation rule during the oilfield production was obtained.The research results indicated that the existence of the inter-well channeling-path and the permeability difference between matrix and channeling-path are the main reasons for the POC variation during CO_(2) flooding in low permeability reservoirs.The POC variation rules are not the same at different inter-well reservoir characteristics.For the low permeability reservoirs with homogeneous inter-well reservoir,the variation of the light hydrocarbon content in POC increases initially followed by a decrease,while the variation of the heavy hydrocarbon content in POC is completely opposite.The carbon number of the most abundant component in POC will gradually increase.For the low permeability reservoirs with the channeling-path existing in the inter-well reservoir,the variation rule of the light hydrocarbon content in POC is increase-decrease-increase-decrease,while the variation rule of the heavy hydrocarbon content in POC is completely opposite.The carbon number variation rule of the most abundant component in POC is increase-decrease-increase.展开更多
To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis,...To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis, an evaluation method of fracturing effect based on production data and fracturing fluid backflow data is established, and the method is used to analyze some field cases. The vicinity area of main fracture after fracturing is divided into different stimulated regions. The permeability and area of different regions are used to characterize the stimulation strength and scale of the fracture network. The conductivity of stimulated region is defined as the product of the permeability and area of the stimulated region. Through parameter sensitivity analysis, it is found that half-length of the fracture and the permeability of the core area mainly affect the flow law near the well, that is, the early stage of production;while matrix permeability mainly affects the flow law at the far end of the fracture. Taking a typical old well in Changqing Oilfield as an example, the fracturing effect and its changes after two rounds of volume fracturing in this well are evaluated. It is found that with the increase of production time after the first volume fracturing, the permeability and conductivity of stimulated area gradually decreased, and the fracturing effect gradually decreased until disappeared;after the second volume fracturing, the permeability and conductivity of stimulated area increased significantly again.展开更多
Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and hi...Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs.Consequently,a novel conformance control system HPF-Co gel,based on high-temperature stabilizer(CoCl_(2)·H_(2)O,CCH)is developed.The HPF-Co bulk gel has better performances with high temperature(120℃)and high salinity(1×10^(5)mg/L).According to Sydansk coding system,the gel strength of HPF-Co with CCH is increased to code G.The dehydration rate of HPF-Co gel is 32.0%after aging for 150 d at 120℃,showing excellent thermal stability.The rheological properties of HPF gel and HPF-Co gel are also studied.The results show that the storage modulus(G′)of HPF-Co gel is always greater than that of HPF gel.The effect of CCH on the microstructure of the gel is studied.The results show that the HPF-Co gel with CCH has a denser gel network,and the diameter of the three-dimensional network skeleton is 1.5-3.5μm.After 90 d of aging,HPF-Co gel still has a good three-dimensional structure.Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group,which can suppress the vibration of cross-linked sites and improve the stability at high temperature.Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system,plugging rate exceeding 98%.Moreover,the results of subsequent waterflooding recovery can be improved by 17%.展开更多
The existing researches on surfactant micellar solutions mainly focus on the formulation optimization and core flooding test, and the types and mechanisms of cleanup additives suitable for low permeability reservoir r...The existing researches on surfactant micellar solutions mainly focus on the formulation optimization and core flooding test, and the types and mechanisms of cleanup additives suitable for low permeability reservoir remain unclear. The flowback efficiencies of different types of surfactant micellar solutions were evaluated by core experiments, a multi-level pore-throat system micromodel characterizing pore-throat structures of low permeability reservoir was made, and flooding and flowback experiments of brine and surfactant micellar solutions of different salinities were conducted with the micromodel to show the oil flowback process in micron pores under the effect of surfactant micellar solution visually and reveal the mechanisms of enhancing displacement and flowback efficiency of surfactant micellar solution. During the displacement and flowback of brine and low salinity surfactant micellar solution, many small droplets were produced, when the small droplets passed through pore-throats, huge percolation resistance was created due to Jamin’s effect, leading to the rise of displacement and flowback pressure differences and the drop of flowback efficiency. The surfactant micellar solutions with critical salinity and optimal salinity that were miscible with crude oil to form Winsor Ⅲ micro-emulsion didnot produce mass small droplets, so they could effectively reduce percolation resistance and enhance oil displacement and flowback efficiency.展开更多
In the pursuit of sustainable oil and gas resource extraction,the innovative integration of carbon capture,utilization,and storage(CCUS)technology has emerged as the most promising approach.During the CCUS process,int...In the pursuit of sustainable oil and gas resource extraction,the innovative integration of carbon capture,utilization,and storage(CCUS)technology has emerged as the most promising approach.During the CCUS process,intricate physicochemical interactions between the injected CO_(2),facilitated through various injection strategies(Water Alternative Gas:WAG/Continue Gas Injection:CGI)and the formation fluids and heterogeneous mineral assemblages within the reservoir trigger alterations in mineral structures,consequently impacting permeability and recovery factors,constituting a pivotal aspect.Precisely delineating and quantifying these interactions is paramount for optimizing process design and evaluating reservoir dynamics in the successful implementation of CCUS operations.This study has carried out qualitative and quantitative characterization of mineral heterogeneity,different pore types,and mineral combination characteristics from a low-permeability sandstone reservoir.Additionally,the effect on the physical properties of minerals from different development methods(WAG/CGI)was investigated using numerical simulation for CCUS applications.The results indicate that the saturated CO_(2)fluid selectively dissolves the potassium feldspar(orthoclase)in intergranular pores,while the intergranular pores are filled with illite and secondary precipitated clay minerals.It initially dissolves the sensitive mineral(ankerite)in the intergranular pores.The decrease of ankerite and increase of illite result from the prolonged contact period between saturated CO_(2)and minerals,which changes the mineral cementation to argillaceous type,thus affecting permeability in the context of CCUS.The spatial impact on reservoir physical properties depends on the spatial heterogeneity of the original sensitive minerals(ankerite,anorthite,illite,etc.)distributed in the study area.In the WAG scheme,the physicochemical interaction between saturated CO_(2)and reservoir minerals is more intense than in the CGI scheme for CCUS operations,significantly impacting cumulative production.展开更多
As flow environment is poor in low permeability reservoirs, wells are always fractured in order to gain better economic benefits. Well testing analysis is very necessary for fracturing wells. However, available test a...As flow environment is poor in low permeability reservoirs, wells are always fractured in order to gain better economic benefits. Well testing analysis is very necessary for fracturing wells. However, available test analysis methods are of slow fitting speed and low fitting precision. In this paper, we first use a comprehensive evaluation method of analytical well testing, numerical well testing and well testing design. Many dynamic parameters such as fracture length, fracture conductivity, skin factor, etc are obtained. An example to illustrate accurate results of this method is given.展开更多
The Second Member of the Shahejie Formation in A oilfield,Bohai Bay Basin,contains typical medium-low porosityand low permeability tight sandstone reservoirs.To study the features(petrology,porosity and physical prope...The Second Member of the Shahejie Formation in A oilfield,Bohai Bay Basin,contains typical medium-low porosityand low permeability tight sandstone reservoirs.To study the features(petrology,porosity and physical properties)and forming mechanism of the target reservoirs,a series of experimental data were used,including cores observation,casting section identification,electron microscope observation and X-ray diffraction,combining with the theory of sedimentary petrology,reservoir sedimentology.The results show that the reservoir is porous reservoir featuring in middle composition and texture maturity,lithic arkoses,secondary dissolution porosity and I type of pore structure.The forming mechanisms of the reservoirs include sedimentation and diagenesis.Sedimentary facies are mainly by braid river deltas front sub-facies,the microfacies of underwater distributary channel have the best reservoir physical property and oiliness,easily forming favorable reservoirs.Particle size and the content of matrix are controlled by sedimentary hydrodynamic in different kinds of microfacies,then the best reservoirs are the coarse grained sandstone which have low matrix content.Primary pores in the reservoirs were almost killed by compaction and the cementation of carbonate cements and clay minerals,paulopost solution created secondary pores which are the mainly reservoir space.But the dissolution is not so strong that reservoirs still have low permeability.Therefore,secondary pores area in underwater distributary channel is the most favorable area for reservoirs to develop.展开更多
In a low permeability reservoir, the existence of a moving boundary is considered in the study of the transient porous flow with threshold pressure gradient. The transmission of the moving boundary directly indicates ...In a low permeability reservoir, the existence of a moving boundary is considered in the study of the transient porous flow with threshold pressure gradient. The transmission of the moving boundary directly indicates the size of the drainage area as well as the apparent influences on the pressure behavior. The nonlinear transient flow mathematical model in which the threshold pressure gradient and the moving boundary are incorporated is solved by advanced mathematical methods. This paper presents some new analytical solutions describing the pressure distribution at a constant rate and the production decline in a constant pressure production with the boundary propagation. It is shown that the greater the threshold pressure gradient, the slower the transmission of the moving boundary, the larger the pressure loss will be, and there is no radial flow in the middle and later phases of the wellface pressure for a well at a constant rate. We have the the maximum moving boundary at a specific drawdown pressure for a low permeability reservoir The greater the threshold pressure gradient, the smaller the maximum moving boundary distance, the quicker the production decline for a well in a constant pressure production will be. The type curve charts for the modern well test analysis and the rate transient analysis with a moving boundary are obtained and the field test and the production data are interpreted as examples to illustrate how to use our new results.展开更多
In order to build a model for the Chang-8 low permeability sandstone reservoir in the Yanchang formation of the Xifeng oil field,we studied sedimentation and diagenesis of sandstone and analyzed major factors controll...In order to build a model for the Chang-8 low permeability sandstone reservoir in the Yanchang formation of the Xifeng oil field,we studied sedimentation and diagenesis of sandstone and analyzed major factors controlling this low permeability reservoir.By doing so,we have made clear that the spatial distribution of reservoir attribute parameters is controlled by the spatial distribution of various kinds of sandstone bodies.By taking advantage of many coring wells and high quality logging data,we used regression analysis for a single well with geological conditions as constraints,to build the interpretation model for logging data and to calculate attribute parameters for a single well,which ensured accuracy of the 1-D vertical model.On this basis,we built a litho-facies model to replace the sedimentary facies model.In addition,we also built a porosity model by using a sequential Gaussian simulation with the lithofacies model as the constraint.In the end,we built a permeability model by using Markov-Bayes simula-tion,with the porosity attribute as the covariate.The results show that the permeability model reflects very well the relative differences between low permeability values,which is of great importance for locating high permeability zones and forecasting zones favorable for exploration and exploitation.展开更多
Low permeability sandstone reservoirs in China typically have more complicated geological conditions, pore structures, and flow characteristics as compared to medium-to-high-permeability sandstone reservoirs. Traditio...Low permeability sandstone reservoirs in China typically have more complicated geological conditions, pore structures, and flow characteristics as compared to medium-to-high-permeability sandstone reservoirs. Traditional geological and seepage theories, and engineering methods are not applicable to the development of these low permeability reservoirs, and wells drilled into them often produce oil and gas at very low rates. Recent breakthroughs in reservoir exploitation technology have greatly improved the productivity of low permeability reservoirs, making them the primary target for oil exploration and extraction in China. The development theories and practices applied to low permeability reservoirs in China are reviewed in this study— based on relevant geological and engineering practices, including drilling, fracturing, recovery, and surface engineering. A unique series of technological advances that aid the development of low permeability reservoirs in China are summarized here. This study may serve as a meaningful guide in achieving scale efficiency for the development of low permeability reservoirs.展开更多
The development of low-permeability oil and gas resources presents a significant challenge to traditional development methods.To address the problem of“no injection and no production”in low-permeability reservoirs,a...The development of low-permeability oil and gas resources presents a significant challenge to traditional development methods.To address the problem of“no injection and no production”in low-permeability reservoirs,a novel fracture-injection-production integration technology named fracturing-flooding has been proposed by oilfield sites.This technology combines the advantages of conventional fracturing,water flooding,and chemical flooding,resulting in improved reservoir physical properties,increased injection,replenished energy,and increased oil displacement efficiency.The technology is especially suitable for low-permeability reservoirs that suffer from lack of energy,and strong heterogeneity.Fracturing-flooding technology has shown significant results and broad development prospects in some oilfields in China.This paper analyzes the development status of fracturing-flooding technology from its development history,technical mechanism,technical characteristics,process flow,types of fracturing and oil displacement fluids,and field applications.Physical and numerical simulations of fracturingflooding technology are also summarized.The results suggest that fracturing-flooding technology is more effective than conventional fracturing,water flooding,and chemical flooding in stimulating lowpermeability tight reservoirs and improving oil recovery.Moreover,it has a high input-output ratio and can be utilized for future reservoir stimulation and transformation.展开更多
The mechanism of the fluid flow in low permeability reservoirs is different from that in middle-high permeability reservoirs because of the existence of the Threshold Pressure Gradient （TPG）. When the pressure gradi...The mechanism of the fluid flow in low permeability reservoirs is different from that in middle-high permeability reservoirs because of the existence of the Threshold Pressure Gradient （TPG）. When the pressure gradient at some location is greater than the TPG, the fluid in porous media begins to flow. By applying the mirror image method and the principle of potential superposition, the steady-state pressure distribution and the stream function for infinite five-spot well patterns can be obtained for a low permeability reservoir with the TPG effect. Based on the streamlines distribution, the flowing and stagnant zones in five-spot well patterns can be clearly seen. By the definition of the effective startup coefficient （SUC）, the ratio of the flowing and stagnant zones can be calculated accurately. It is shown that the SUC for five-spot well patterns is not constant, but decreases with the increase of the di- mensionless TPG. By increasing the effective permeability of the formation （such as by the acid treatment and the hydraulic fracture）, in increasing the injection-production differential pressure or shortening the well space （such as by infilling well）, the SUC can be improved. The results of the sensitivity analysis show that a better choice for the SUC enhancement is to shorten the well spacing for small permeability reservoirs and to increase the pressure difference for large permeability reservoirs. This streamline approach can be used to determine the distribution of remaining oil and provide guidance for infilling well.展开更多
基金project was supported by the Fund of State Key Laboratory of Deep Oil and Gas,China University of Petroleum(East China)(No.SKLDOG2024-ZYRC-06)Key Program of National Natural Science Foundation of China(52130401)+1 种基金National Natural Science Foundation of China(52104055,52374058)Shandong Provincial Natural Science Foundation,China(ZR2021ME171,ZR2024YQ043)。
文摘CO_(2)flooding enhanced oil recovery(CO_(2)-EOR)represents a significant technology in the low permeability reservoir.With the fractures and heterogeneity in low permeability reservoirs,CO_(2)-EOR is susceptible to pessimistic gas channeling.Consequently,there is a need to develop conformance control materials that can be used in CO_(2)-EOR.Herein,to address the challenges of low strength and poor stability of polymer gel in high temperature and low permeability reservoirs,a new organic/metal ion composite crosslinking polymer gel(AR-Gel)is reported,which is formed by low hydrolysis and medium to high molecular weight polymer(CX-305),organic crosslinking agent(phenolic resin),and aluminium citrate(AI(Ⅲ)).The crosslinking of AI(Ⅲ)with carboxyl group and organic/metal ion double crosslinking can construct a more complex and stable polymer gel structure on the basis of traditional chemical crosslinking,to cope with the harsh conditions such as high temperature.The structure-activity relationship of AR-Gel was revealed by rheology behavior and micro-morphology.The applicability of AR-Gel in reservoir was investigated,as was its strength and stability in supercritical CO_(2).The anti-gas channeling and enhanced oil recovery of AR-Gel were investigated using low permeability fractured cores,and the field process parameters were provided.The gel can be used to meet supercritical CO_(2)reservoirs at 110℃and 20,000 mg/L salinity,with long-term stability over 60 days.The plugging rate of AR-Gel for fractured co re was 97%,with subsequent CO_(2)flooding re sulting in an enhanced oil recovery by 34.5%.ARGel can effectively control CO_(2)gas channeling and enhanced oil recovery.It offers a new material with high strength and temperature resistance,which is particularly beneficial in the CO_(2)flooding for the conformance control of oil field.
基金Supported by the National Key Research and Development Program,China(2019YFA0708700)National Natural Science Foundation of China(52542310).
文摘This study focuses on the hydrated ion bridge(HIB)effect at the oil-rock interface in low-to ultra-low-permeability oil reservoirs.It systematically summarizes the research methodologies,formation mechanisms,interaction strength,and disruption mechanisms of HIB,and discusses the influencing mechanisms of HIB on the occurrence state and mobility of crude oil.On this basis,the key challenges inherent in the current HIB research are analyzed,and prospective directions for future development are proposed.Currently,research in this field primarily relies on experimental characterization techniques and molecular simulation methods.The microscopic interactions involved in HIB formation mainly include electrostatic interactions,hydrogen bonds and van der Waals forces.Notably,the hydrogen bonds between polar molecules in crude oil and hydrated ions serve as the primary sites for disrupting the HIB effect.The interaction strength of HIB is collectively modulated by ion type and concentration,reservoir solution environment,mineral type of reservoir rocks,and polar components in crude oil,which subsequently influence the occurrence state and mobility of crude oil.Systematic challenges persist in HIB-related research across three dimensions:research methodologies,scale integration and geological complexity.Specifically,the dynamic evolution mechanism of HIB remains inadequately elucidated;a discontinuity exists in the connection of spatiotemporal cross-scale modeling and prediction;and the reproducibility of actual geological environments in experimental settings is insufficient.Future research may pursue breakthroughs in the following three aspects:(1)developing in-situ dynamic experimental characterization techniques and machine learning-augmented simulation strategies;(2)establishing a framework for cross-scale model fusion and upscaling prediction;and(3)conducting in-depth studies on HIB under the coupled effects of complex mineral systems and multi-physical fields.
基金supported by Key Program of National Natural Science Foundation of China (No. 52130401)National Natural Science Foundation of China (No. 52104055)+1 种基金China National Postdoctoral Program for Innovative Talents (No. BX20200386)China Postdoctoral Science Foundation (No. 2021M703586)。
文摘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.
基金supported by the National Natural Science Foundation of China(Grant No.U1262203)the National Science and Technology Special Grant(No.2011ZX05006-003)+1 种基金the Fundamental Research Funds for the Central Universities(Grant No.14CX06070A)the Chinese Scholarship Council(No.201506450029)
文摘The relationships between permeability and dynamics in hydrocarbon accumulation determine oil- bearing potential （the potential oil charge） of low perme- ability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member of the Shahejie Formation in the Dongying Sag has been investigated by detailed core descriptions, thin section analyses, fluid inclusion analyses, carbon and oxygen isotope analyses, mercury injection, porosity and permeability testing, and basin modeling. The cutoff values for the permeability of the reservoirs in the accumulation period were calculated after detailing the accumulation dynamics and reservoir pore structures, then the distribution pattern of the oil-bearing potential of reservoirs controlled by the matching relationship between dynamics and permeability during the accumulation period were summarized. On the basis of the observed diagenetic features and with regard to the paragenetic sequences, the reservoirs can be subdivided into four types of diagenetic facies. The reservoirs experienced two periods of hydro- carbon accumulation. In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high permeability ranging from 10 × 10-3 gm2 to 4207 × 10-3 lain2. In the later accumulation period, the reservoirs except for diagenetic facies C had low permeability ranging from 0.015 × 10-3 gm2 to 62× 10-3 -3m2. In the early accumulation period, the fluid pressure increased by the hydrocarbon generation was 1.4-11.3 MPa with an average value of 5.1 MPa, and a surplus pressure of 1.8-12.6 MPa with an average value of 6.3 MPa. In the later accumulation period, the fluid pressure increased by the hydrocarbon generation process was 0.7-12.7 MPa with an average value of 5.36 MPa and a surplus pressure of 1.3-16.2 MPa with an average value of 6.5 MPa. Even though different types of reservoirs exist, all can form hydrocarbon accumulations in the early accumulation per- iod. Such types of reservoirs can form hydrocarbon accumulation with high accumulation dynamics; however, reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation conditions with low accumu- lation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock, Also at these depths, lenticular sand bodies can accumulate hydrocarbons. At shallower depths, only the reservoirs with oil-source fault development can accumulate hydrocarbons. For flat surfaces, hydrocarbons have always been accumulated in the reservoirs around the oil-source faults and areas near the center of subsags with high accumulation dynamics.
基金supported by the Major National Oil&Gas Specific Project of China(No.2011ZX05044)
文摘The resistivity experimental measurements of core samples drilled from low permeability reservoirs of Ordos Basin, Northwest China, illustrate that the cementation factors are not agminate, but vary from 1.335 to 1.749. This leads to a challenge for the estimation of water and hydrocarbon sa- turation. Based on the analysis of Purcell equation and assumption that rock resistivity is determined by the parallel connection of numerous capillary resistances, a theoretical expression of cementation factor in terms of porosity and permeability is established. Then, cementation factor can be calculated if the parameters of porosity and permeability are determined. In the field application, porosity can be easily obtained by conventional logs. However, it is a tough challenge to estimate permeability due to the strong heterogeneity of low permeability reservoirs. Thus, the Schlumberger Doll Research （SDR） model derived from NMR logs has been proposed to estimate permeability. Based on the analysis of the theoretical expressions of cementation factor and SDR model, a novel cementation factor prediction model, which is relevant to porosity and logarithmic mean of NMR T2 spectrum （T21m）, is derived. The advantage of this model is that all the input information can be acquired from NMR logs accurately. In order to confirm the credibility of the novel model, the resistivity and corresponding laboratory NMR measurements of 27 core samples are conducted. The credibility of the model is confirmed by compar- ing the predicted cementation factors with the core analyzed results. The absolute errors for all core samples are lower than 0.071. Once this model is extended to field application, the accuracy of water and hydrocarbon saturation estimation will be significantly improved.
文摘In view of the problems of high injection pressure and low water injection rate in water injection wells of low permeability reservoirs featuring high temperature and high salinity,two new surfactants were synthesized,including a quaternary ammonium surfactant and a betaine amphoteric surfactant.The composite surfactant system BYJ-1 was formed by mixing two kinds of surfactants.The minimum interfacial tension between BYJ-1 solution and the crude oil could reach 1.4×10^(-3) mN/m.The temperature resistance was up to 140℃,and the salt resistance could reach up to 120 g/L.For the low permeability core fully saturated with water phase,BYJ-1 could obviously reduce the starting pressure gradient of low permeability core.While for the core with residual oil,BYJ-1 could obviously reduce the injection pressure and improve the oil recovery.Moreover,the field test showed that BYJ-1 could effectively reduce the injection pressure of the water injection well,increase the injection volume,and increase the liquid production and oil production of the corresponding production well.
基金financially supported by National Natural Science Foundation of China(No.22302229)Beijing Municipal Excellent Talent Training Funds Youth Advanced Individual Project(No.2018000020124G163)。
文摘Emulsification is one of the important mechanisms of surfactant flooding. To improve oil recovery for low permeability reservoirs, a highly efficient emulsification oil flooding system consisting of anionic surfactant sodium alkyl glucosyl hydroxypropyl sulfonate(APGSHS) and zwitterionic surfactant octadecyl betaine(BS-18) is proposed. The performance of APGSHS/BS-18 mixed surfactant system was evaluated in terms of interfacial tension, emulsification capability, emulsion size and distribution, wettability alteration, temperature-resistance and salt-resistance. The emulsification speed was used to evaluate the emulsification ability of surfactant systems, and the results show that mixed surfactant systems can completely emulsify the crude oil into emulsions droplets even under low energy conditions. Meanwhile,the system exhibits good temperature and salt resistance. Finally, the best oil recovery of 25.45% is achieved for low permeability core by the mixed surfactant system with a total concentration of 0.3 wt%while the molar ratio of APGSHS:BS-18 is 4:6. The current study indicates that the anionic/zwitterionic mixed surfactant system can improve the oil flooding efficiency and is potential candidate for application in low permeability reservoirs.
基金Projects 2003BA613-07-05 supported by the Program of National "Fifteen" Science and Technology 04E7029 by the CNPC Innovation Foundation
文摘It is very important to design the optimum starting time of water injection for the development of low permeability reservoirs. In this type of reservoir the starting time of water injection will be affected by a reservoir pressure-sensitive effect. In order to optimize the starting time of water injection in low permeability reservoirs, this effect of pressure change on rock permeability of low permeability reservoirs was, at first, studied by physical simulation. It was shown that the rock permeability decreases exponentially with an increase in formation pressure. Secondly, we conducted a reservoir engineering study, from which we obtained analytic relationships between formation pressure, oil production rate, water production rate and water injection rate. After our physical, theoretical and economical analyses, we proposed an approach which takes the pressure-sensitive effect into consideration and designed the optimum starting time of water injection, based on the principle of material balance. Finally, the corresponding software was developed and applied to one block of the Jiangsu Oilfield. It is shown that water injection, in advance of production, can decrease the adverse impact of the pressure-sensitive effect on low permeability reservoir development. A water-flooding project should be preferably initiated in advance of production for no more than one year and the optimum ratio of formation pressure to initial formation pressure should be maintained at a level between 1.05 and 1.2.
基金supported by the National Key Research and Development Plan(No.2018YFB0605500)National Science and Technology Major Projects(No.2017ZX05009004).
文摘CO_(2) flooding has been widely studied and applied to improve oil recovery from low permeability reservoirs.Both the experimental results and the oilfield production data indicate that produced oil components(POC)will vary during CO_(2) flooding in low permeability reservoirs.However,the present researches fail to explain the variation reason and rule.In this study,the physical model of the POC variation during CO_(2) flooding in low permeability reservoir was established,and the variation reason and rule were defined.To verify the correctness of the physical model,the interaction rule of the oil-CO_(2) system was studied by related experiments.The numerical model,including 34 components,was established based on the precise experiments matching,and simulated the POC variation during CO_(2) flooding in low permeability reservoir at different inter-well reservoir characteristics.The POC monitoring data of the CO_(2) flooding pilot test area in northeastern China were analyzed,and the POC variation rule during the oilfield production was obtained.The research results indicated that the existence of the inter-well channeling-path and the permeability difference between matrix and channeling-path are the main reasons for the POC variation during CO_(2) flooding in low permeability reservoirs.The POC variation rules are not the same at different inter-well reservoir characteristics.For the low permeability reservoirs with homogeneous inter-well reservoir,the variation of the light hydrocarbon content in POC increases initially followed by a decrease,while the variation of the heavy hydrocarbon content in POC is completely opposite.The carbon number of the most abundant component in POC will gradually increase.For the low permeability reservoirs with the channeling-path existing in the inter-well reservoir,the variation rule of the light hydrocarbon content in POC is increase-decrease-increase-decrease,while the variation rule of the heavy hydrocarbon content in POC is completely opposite.The carbon number variation rule of the most abundant component in POC is increase-decrease-increase.
基金Supported by the China National Science and Technology Major Project (2017ZX05013-001)CNPC Science and Technology Major Research Project (2018B-4907)
文摘To evaluate the fracturing effect and dynamic change process after volume fracturing with vertical wells in low permeability oil reservoirs, an oil-water two-phase flow model and a well model are built. On this basis, an evaluation method of fracturing effect based on production data and fracturing fluid backflow data is established, and the method is used to analyze some field cases. The vicinity area of main fracture after fracturing is divided into different stimulated regions. The permeability and area of different regions are used to characterize the stimulation strength and scale of the fracture network. The conductivity of stimulated region is defined as the product of the permeability and area of the stimulated region. Through parameter sensitivity analysis, it is found that half-length of the fracture and the permeability of the core area mainly affect the flow law near the well, that is, the early stage of production;while matrix permeability mainly affects the flow law at the far end of the fracture. Taking a typical old well in Changqing Oilfield as an example, the fracturing effect and its changes after two rounds of volume fracturing in this well are evaluated. It is found that with the increase of production time after the first volume fracturing, the permeability and conductivity of stimulated area gradually decreased, and the fracturing effect gradually decreased until disappeared;after the second volume fracturing, the permeability and conductivity of stimulated area increased significantly again.
基金This work has been Sponsored by CNPC Innovation Found(Grant No.2021DQ02-0202)Besides,the authors gratefully appreciate the financial support of the Science Foundation of China University of Petroleum,Beijing(Grant No.2462020XKBH013)Financial supports from the National Natural Science Foundation of China(Grant No.52174046)is also significantly acknowledged.
文摘Conformance control and water plugging are a widely used EOR method in mature oilfields.However,majority of conformance control and water plugging agents are unavoidable dehydrated situation in high-temperature and high-salinity low permeability reservoirs.Consequently,a novel conformance control system HPF-Co gel,based on high-temperature stabilizer(CoCl_(2)·H_(2)O,CCH)is developed.The HPF-Co bulk gel has better performances with high temperature(120℃)and high salinity(1×10^(5)mg/L).According to Sydansk coding system,the gel strength of HPF-Co with CCH is increased to code G.The dehydration rate of HPF-Co gel is 32.0%after aging for 150 d at 120℃,showing excellent thermal stability.The rheological properties of HPF gel and HPF-Co gel are also studied.The results show that the storage modulus(G′)of HPF-Co gel is always greater than that of HPF gel.The effect of CCH on the microstructure of the gel is studied.The results show that the HPF-Co gel with CCH has a denser gel network,and the diameter of the three-dimensional network skeleton is 1.5-3.5μm.After 90 d of aging,HPF-Co gel still has a good three-dimensional structure.Infrared spectroscopy results show that CCH forms coordination bonds with N and O atoms in the gel amide group,which can suppress the vibration of cross-linked sites and improve the stability at high temperature.Fractured core plugging test determines the optimized polymer gel injection strategy and injection velocity with HPF-Co bulk gel system,plugging rate exceeding 98%.Moreover,the results of subsequent waterflooding recovery can be improved by 17%.
基金Supported by the China National Science and Technology Major Project (2017ZX05009-005-003)Research Fund of China University of Petroleum (Beijing)(2462019QNXZ04)。
文摘The existing researches on surfactant micellar solutions mainly focus on the formulation optimization and core flooding test, and the types and mechanisms of cleanup additives suitable for low permeability reservoir remain unclear. The flowback efficiencies of different types of surfactant micellar solutions were evaluated by core experiments, a multi-level pore-throat system micromodel characterizing pore-throat structures of low permeability reservoir was made, and flooding and flowback experiments of brine and surfactant micellar solutions of different salinities were conducted with the micromodel to show the oil flowback process in micron pores under the effect of surfactant micellar solution visually and reveal the mechanisms of enhancing displacement and flowback efficiency of surfactant micellar solution. During the displacement and flowback of brine and low salinity surfactant micellar solution, many small droplets were produced, when the small droplets passed through pore-throats, huge percolation resistance was created due to Jamin’s effect, leading to the rise of displacement and flowback pressure differences and the drop of flowback efficiency. The surfactant micellar solutions with critical salinity and optimal salinity that were miscible with crude oil to form Winsor Ⅲ micro-emulsion didnot produce mass small droplets, so they could effectively reduce percolation resistance and enhance oil displacement and flowback efficiency.
基金support of The National Foreign Experts Program(Grant no.QN2022060001L)Ministry of Science and Technology of China and Intelligent Reservoir Numerical Simulation Technology(Grant no.2023DJ8403),China National Petroleum Corporation.
文摘In the pursuit of sustainable oil and gas resource extraction,the innovative integration of carbon capture,utilization,and storage(CCUS)technology has emerged as the most promising approach.During the CCUS process,intricate physicochemical interactions between the injected CO_(2),facilitated through various injection strategies(Water Alternative Gas:WAG/Continue Gas Injection:CGI)and the formation fluids and heterogeneous mineral assemblages within the reservoir trigger alterations in mineral structures,consequently impacting permeability and recovery factors,constituting a pivotal aspect.Precisely delineating and quantifying these interactions is paramount for optimizing process design and evaluating reservoir dynamics in the successful implementation of CCUS operations.This study has carried out qualitative and quantitative characterization of mineral heterogeneity,different pore types,and mineral combination characteristics from a low-permeability sandstone reservoir.Additionally,the effect on the physical properties of minerals from different development methods(WAG/CGI)was investigated using numerical simulation for CCUS applications.The results indicate that the saturated CO_(2)fluid selectively dissolves the potassium feldspar(orthoclase)in intergranular pores,while the intergranular pores are filled with illite and secondary precipitated clay minerals.It initially dissolves the sensitive mineral(ankerite)in the intergranular pores.The decrease of ankerite and increase of illite result from the prolonged contact period between saturated CO_(2)and minerals,which changes the mineral cementation to argillaceous type,thus affecting permeability in the context of CCUS.The spatial impact on reservoir physical properties depends on the spatial heterogeneity of the original sensitive minerals(ankerite,anorthite,illite,etc.)distributed in the study area.In the WAG scheme,the physicochemical interaction between saturated CO_(2)and reservoir minerals is more intense than in the CGI scheme for CCUS operations,significantly impacting cumulative production.
文摘As flow environment is poor in low permeability reservoirs, wells are always fractured in order to gain better economic benefits. Well testing analysis is very necessary for fracturing wells. However, available test analysis methods are of slow fitting speed and low fitting precision. In this paper, we first use a comprehensive evaluation method of analytical well testing, numerical well testing and well testing design. Many dynamic parameters such as fracture length, fracture conductivity, skin factor, etc are obtained. An example to illustrate accurate results of this method is given.
文摘The Second Member of the Shahejie Formation in A oilfield,Bohai Bay Basin,contains typical medium-low porosityand low permeability tight sandstone reservoirs.To study the features(petrology,porosity and physical properties)and forming mechanism of the target reservoirs,a series of experimental data were used,including cores observation,casting section identification,electron microscope observation and X-ray diffraction,combining with the theory of sedimentary petrology,reservoir sedimentology.The results show that the reservoir is porous reservoir featuring in middle composition and texture maturity,lithic arkoses,secondary dissolution porosity and I type of pore structure.The forming mechanisms of the reservoirs include sedimentation and diagenesis.Sedimentary facies are mainly by braid river deltas front sub-facies,the microfacies of underwater distributary channel have the best reservoir physical property and oiliness,easily forming favorable reservoirs.Particle size and the content of matrix are controlled by sedimentary hydrodynamic in different kinds of microfacies,then the best reservoirs are the coarse grained sandstone which have low matrix content.Primary pores in the reservoirs were almost killed by compaction and the cementation of carbonate cements and clay minerals,paulopost solution created secondary pores which are the mainly reservoir space.But the dissolution is not so strong that reservoirs still have low permeability.Therefore,secondary pores area in underwater distributary channel is the most favorable area for reservoirs to develop.
基金supported by the Fundamental Research Funds for the Central Universities,the Important National Science and Technology Specific Projects during the Eleventh Five Years Plan Period(Grant No.2009ZX05009-004-03)
文摘In a low permeability reservoir, the existence of a moving boundary is considered in the study of the transient porous flow with threshold pressure gradient. The transmission of the moving boundary directly indicates the size of the drainage area as well as the apparent influences on the pressure behavior. The nonlinear transient flow mathematical model in which the threshold pressure gradient and the moving boundary are incorporated is solved by advanced mathematical methods. This paper presents some new analytical solutions describing the pressure distribution at a constant rate and the production decline in a constant pressure production with the boundary propagation. It is shown that the greater the threshold pressure gradient, the slower the transmission of the moving boundary, the larger the pressure loss will be, and there is no radial flow in the middle and later phases of the wellface pressure for a well at a constant rate. We have the the maximum moving boundary at a specific drawdown pressure for a low permeability reservoir The greater the threshold pressure gradient, the smaller the maximum moving boundary distance, the quicker the production decline for a well in a constant pressure production will be. The type curve charts for the modern well test analysis and the rate transient analysis with a moving boundary are obtained and the field test and the production data are interpreted as examples to illustrate how to use our new results.
基金Project 50374048 supported by the National Natural Science Foundation of China
文摘In order to build a model for the Chang-8 low permeability sandstone reservoir in the Yanchang formation of the Xifeng oil field,we studied sedimentation and diagenesis of sandstone and analyzed major factors controlling this low permeability reservoir.By doing so,we have made clear that the spatial distribution of reservoir attribute parameters is controlled by the spatial distribution of various kinds of sandstone bodies.By taking advantage of many coring wells and high quality logging data,we used regression analysis for a single well with geological conditions as constraints,to build the interpretation model for logging data and to calculate attribute parameters for a single well,which ensured accuracy of the 1-D vertical model.On this basis,we built a litho-facies model to replace the sedimentary facies model.In addition,we also built a porosity model by using a sequential Gaussian simulation with the lithofacies model as the constraint.In the end,we built a permeability model by using Markov-Bayes simula-tion,with the porosity attribute as the covariate.The results show that the permeability model reflects very well the relative differences between low permeability values,which is of great importance for locating high permeability zones and forecasting zones favorable for exploration and exploitation.
基金support by the National Key Research and Development Program of China(Grant No.2018YFA0702400)is gratefully acknowledged.
文摘Low permeability sandstone reservoirs in China typically have more complicated geological conditions, pore structures, and flow characteristics as compared to medium-to-high-permeability sandstone reservoirs. Traditional geological and seepage theories, and engineering methods are not applicable to the development of these low permeability reservoirs, and wells drilled into them often produce oil and gas at very low rates. Recent breakthroughs in reservoir exploitation technology have greatly improved the productivity of low permeability reservoirs, making them the primary target for oil exploration and extraction in China. The development theories and practices applied to low permeability reservoirs in China are reviewed in this study— based on relevant geological and engineering practices, including drilling, fracturing, recovery, and surface engineering. A unique series of technological advances that aid the development of low permeability reservoirs in China are summarized here. This study may serve as a meaningful guide in achieving scale efficiency for the development of low permeability reservoirs.
基金supported by the grant from the Science and Technology Cooperation Project of the CNPC-SWPU Innovation Alliance (2020CX010501)。
文摘The development of low-permeability oil and gas resources presents a significant challenge to traditional development methods.To address the problem of“no injection and no production”in low-permeability reservoirs,a novel fracture-injection-production integration technology named fracturing-flooding has been proposed by oilfield sites.This technology combines the advantages of conventional fracturing,water flooding,and chemical flooding,resulting in improved reservoir physical properties,increased injection,replenished energy,and increased oil displacement efficiency.The technology is especially suitable for low-permeability reservoirs that suffer from lack of energy,and strong heterogeneity.Fracturing-flooding technology has shown significant results and broad development prospects in some oilfields in China.This paper analyzes the development status of fracturing-flooding technology from its development history,technical mechanism,technical characteristics,process flow,types of fracturing and oil displacement fluids,and field applications.Physical and numerical simulations of fracturingflooding technology are also summarized.The results suggest that fracturing-flooding technology is more effective than conventional fracturing,water flooding,and chemical flooding in stimulating lowpermeability tight reservoirs and improving oil recovery.Moreover,it has a high input-output ratio and can be utilized for future reservoir stimulation and transformation.
基金Project Supported by the National Natural Science Foundation of China(Grant No.51204148)
文摘The mechanism of the fluid flow in low permeability reservoirs is different from that in middle-high permeability reservoirs because of the existence of the Threshold Pressure Gradient （TPG）. When the pressure gradient at some location is greater than the TPG, the fluid in porous media begins to flow. By applying the mirror image method and the principle of potential superposition, the steady-state pressure distribution and the stream function for infinite five-spot well patterns can be obtained for a low permeability reservoir with the TPG effect. Based on the streamlines distribution, the flowing and stagnant zones in five-spot well patterns can be clearly seen. By the definition of the effective startup coefficient （SUC）, the ratio of the flowing and stagnant zones can be calculated accurately. It is shown that the SUC for five-spot well patterns is not constant, but decreases with the increase of the di- mensionless TPG. By increasing the effective permeability of the formation （such as by the acid treatment and the hydraulic fracture）, in increasing the injection-production differential pressure or shortening the well space （such as by infilling well）, the SUC can be improved. The results of the sensitivity analysis show that a better choice for the SUC enhancement is to shorten the well spacing for small permeability reservoirs and to increase the pressure difference for large permeability reservoirs. This streamline approach can be used to determine the distribution of remaining oil and provide guidance for infilling well.
