Ultra-low Permeability Research Articles

Mineralogical and hydraulic characteristics of mudstone in the Tamusu candidate area in northwest China for high-level radioactive waste geological disposal

AbstractThe Tamusu region in northwest China is a key candidate area for China's clay rock deep geological repositories (DGRs) for high-level radioactive waste (HLRW) as it is composed of a continuous layer of thick lacustrine mudstone. To evaluate this mudstone as a host rock, two special test boreholes were drilled to investigate its spatial distribution and mineralogical and hydraulic characteristics. The southwest boundary and depositional centre of the lake basin were well delineated by boreholes TZK-1 and TZK-2. The continuous single-layer thickness of the target mudstone formation was up to 300 m at a depth of 500–800 m. Three main mineral types were determined, namely carbonates (mainly dolomite and ankerite), analcime and albite, and their abundance was used to distinguish three different facies. Other mineral phases, such as clay minerals (mainly illite and kaolinite), pyrite, hematite, quartz and calcite, were present as admixtures. The presence of carbonates may increase the mechanical strength and analcime may enhance the radionuclide adsorption properties of the mudstone. The self-sealing properties, which may be affected by the small amount of clay minerals, remain to be investigated. The hydraulic conductivity of the mudstone determined via in situ pulse tests ranged from 10–13 to 10–10 m s–1, suggesting that the Tamusu mudstone has ultra-low permeability. The transmissivity of the Tamusu mudstone fluctuated in regions with varying lithologies, but remained relatively constant for consistent lithologies. In summary, these preliminarily results confirm the possible suitability of the target formation as a host rock for DGRs of China's HLRW.

Numerical investigation of Non-Darcy flow regime transitions in shale gas production

Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable.The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data.Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved.The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.

Multidomain Two-Phase Flow Model to Study the Impacts of Hydraulic Fracturing on Shale Gas Production

Hydraulic fracturing enhances the recovery of gas from ultralow permeability shales, into which water-based fracturing fluids, proppants, and activators are typically injected. However, the impacts...

Interplay between pore connectivity and permeability in shale sample

Shale formations demonstrate distinct characteristics, such as a wide spectrum of pore size from micro-scale to nano-scale, limited pore connectivity and ultra-low permeability. Despite extensive research work over recent years to characterize flow properties of shale samples, the interplay between pore connectivity and permeability still remains to be understood. In this study, numerical methods were used in tandem with experimental data to characterize and evaluate pore connectivity of shale samples.To evaluate permeability and pore connectivity in the shale matrix, three-dimensional (3D) pore structure constructed by stacking scanning electron microscopy (SEM) images of an Eagle Ford sample is used. First, static petrophysical properties of the shale sample such as total and the connected porosity, pore size distribution and geometric tortuosity are calculated and evaluated. Next, pore connectivity is assessed using Euler-Poincare Characteristics (EPC) method. Finally, fluid flow through the sample is simulated using Lattice Boltzmann Method (LBM) to predict single-phase permeability of the whole system.Results indicate that total porosity of the studied Eagle Ford shale sample is around 12.5% and slightly decreases as the thickness of the digital sample increases. On the other hand, the connected porosity of the sample decreases resulting in a 50% reduction when the sample thickness increases from 1 μm to 6 μm. Moreover, the calculated permeability is 17.6 md and 1.17 μd for the sample thickness of 1 μm and 6 μm, respectively; i.e. 15,000 times reduction is observed when the digital sample thickness increases. Consistent with the permeability results, the pore connectivity determined through EPC method is strongly (and inversely) correlated with the sample thickness and 80% reduction of the pore connectivity is realized when the sample thickness is increased from 1 μm to 6 μm.The results from this study will provide new insights into how pore structure characteristics scale up and help improve the better estimation of permeability in shale formations. In addition, the outcome of this work has some important implications to fluid flow research studies in shale formations.

Transient Pressure Analysis for Multifractured Horizontal Well with the Use of Multilinear Flow Model in Shale Gas Reservoir

Shale gas reservoirs (SGR) have been a central supply of carbon hydrogen energy consumption and hence widely produced with the assistance of advanced hydraulic fracturing technologies. On the one hand, due to the inherent ultralow permeability and porosity, there is stress sensitivity in the reservoirs generally. On the other hand, hydraulic fractures and the stimulated reservoir volume (SRV) generated by the massive hydraulic fracturing operation have contrast properties with the original reservoirs. These two phenomena pose huge challenges in SGR transient pressure analysis. Limited works have been done to take the stress sensitivity and spatially varying permeability of the SRV zone into consideration simultaneously. This paper first idealizes the SGR to be four linear composite regions. What is more, the SRV zone is further divided into subsections on the basis of nonuniform distribution of proppant within the SRV zone which easily yields spatially varying permeability away from the main hydraulic fracture. By means of perturbation transformation and Laplace transformation, an analytical multilinear flow model (MLFM) is obtained and validated as a comparison with the previous models. The flow regimes are identified, and the sensitivity analysis of critical parameters is conducted to further understand the transient pressure behaviors. The research results provided by this work are of significance for an effective recovery of SGR resources.

Sequentially coupled flow and geomechanical simulation with a discrete fracture model for analyzing fracturing fluid recovery and distribution in fractured ultra-low permeability gas reservoirs

More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations.The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior.This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.

Development technology status of low permeability sandstone oil reservoirs

The development of oil in low permeability sand stone resources is of great significance. The paper first presented the present situation of domestic and foreign technologies in water injection, gas injection, stimulation and enhanced oil recovery of low permeability sandstone reservoirs. Then the main problem in the development of oil reservoirs with ultra-low permeability was analyzed. Finally, the paper proposed the trend of the future development of these oil reservoirs.

Transient pressure behavior for unconventional gas wells with finite-conductivity fractures

Horizontal wells and hydraulic fracturing technologies are the only way that makes commercial production from the low and ultra-low permeability unconventional plays possible. The development of analytical and semi-analytical tools to analyze transient behavior of multi-fractured horizontal gas wells have been largely biased towards solving the simplified problem of one-dimensional (1D) Cartesian gas flow in matrix domain, which are only applicable to the production from infinite-conductivity fractures. This study presents a novel semi-analytical method for transient behavior analysis of horizontal gas wells producing from finite-conductivity fractures. Unlike the available transient analysis tools for finite-conductivity fractures which are developed based on empirical and approximate solution, the proposed solution is rigorously derived by solving the governing gas diffusivity equations written for gas flow in two contiguous regions of matrix and fracture simultaneously. Nonlinear, pressure-dependent gas properties remaining in pseudopressure-based diffusivity equations—namely viscosity and compressibility—are rigorously and straightforwardly captured in both fracture and matrix systems. The validity of proposed solution is verified against commercial numerical simulator (COMSOL Multiphysics®) for a series of synthetic cases considering constant and variable -rate production constraints. The case studies presented in this paper also showcase the applicability of proposed solution to the analysis of transient behavior of multi-fractured horizontal gas wells in shale plays under the following two state-of-the-art interpretations: 1) production from finite-conductivity hydraulic fractures in a single-porosity matrix; and 2) production from infinite-conductivity hydraulic fractures in a naturally-fractured matrix.

Fast Models of Hydrocarbon Migration Paths and Pressure Depletion Based on Complex Analysis Methods (CAM): Mini-Review and Verification

A recently developed code to model hydrocarbon migration and convective time of flight makes use of complex analysis methods (CAM) paired with Eulerian particle tracking. Because the method uses new algorithms that are uniquely developed by our research group, validation of the fast CAM solutions with independent methods is merited. Particle path solutions were compared with independent solutions methods (Eclipse). These prior and new benchmarks are briefly summarized here to further verify the results obtained with CAM codes. Pressure field solutions based on CAM are compared with independent embedded discrete fracture method (EDFM) solutions. The CAM method is particularly attractive because its grid-less nature offers fast computation times and unlimited resolution. The method is particularly well suited for solving a variety of practical field development problems. Examples are given for fast optimization of waterflood patterns. Another successful application area is the modeling of fluid withdrawal patterns in hydraulically fractured wells. Because no gridding is required, the CAM model can compute the evolution of the drained rock volume (DRV) for an unlimited (but finite) number of both hydraulic and natural fractures. Such computations of the DRV are based on the convective time of flight and show the fluid withdrawal zone in the reservoir. In contrast, pressure depletion models are based on the diffusive time of flight. In ultra-low permeability reservoirs, the pressure depletion zones do not correspond to the DRV, because the convective and diffusive displacement rates differ over an order of magnitude (diffusive time of flight being the fastest). Therefore, pressure depletion models vastly overestimate the drained volume in shale reservoirs, which is why fracture and well spacing decisions should be based on both pressure depletion and DRV models, not pressure only.

The optimization of pre-slug size in CO2-N2 compound flooding

In order to enhance oil recovery in low and ultra-low permeability layer, both of the numerical simulation and physical model experiment have been researched. First, the dynamic distribution of CO1 and N1 in the oil and gas phase in the CO2-N2 compound flooding process was numerically simulated by using the long slim-tube model. The results show that the CO2 slug should have at least 0.3 PV to prevent the impact of N2 channeling effectively. Second, under the experimental conditions of complete miscibility of CO2-crude oil, the two types of natural cores including low and ultra-low permeability, respectively, are used for experimental study on oil displacement. The results confirm that CO2-N2 compound flooding with 0.3 PV CO2 pre-slug can achieve a good result. Finally, a five-point well pattern element model is established by CMG. The recovery and the gas cost of per ton of oil are calculated respectively for CO2-N2 compound flooding and full CO2 flooding at 300 m well spacing of low and ultra-low permeability layer. According to the simulation results, the optimal CO2 pre-slug size in CO2-N2 compound flooding under the condition of low and ultra-low permeability layer five-point well pattern is 0.4 PV.

Study on the sensitivities and damage mechanisms of ultra-low permeability sandstone reservoirs: taking Chang 6 reservoir in Jingbian oilfield as an example

This paper takes the ultra-low permeability sandstone reservoir of Jingbian oilfield in Ordos Basin as the research object, analyzes the petrological characteristics, diagenesis, physical characteristics and pore structure characteristics of the reservoir, and carries out reservoir sensitivity evaluation by using rock casting thin sections, X-ray diffraction, and sensitive flow experiments. The research results show that the ultra-low permeability Chang 6 sandstone reservoir has weak velocity sensitivity, medium-weak water sensitivity, weak salt sensitivity, weak alkali sensitivity and strong acid sensitivity; the damage mechanism of reservoir sensitivity mainly depends on the composition of clay minerals and pore structure after diagenesis. The clay mineral content from high to low is chlorite, illite, a small amount of illite / smectite layer, and kaolinite, of which the chlorite content is as high as 75 %; the reservoir has poor physical properties, the types of small hole-thin throat and small hole-fine throat. The reservoir is prone to blockage such as bridge plugging. Therefore, ultra-low permeability sandstone reservoirs are prone to different degrees of sensitivity. The reservoir characteristics are consistent with the reservoir sensitivity evaluation results.

Productivity Testing and Analysis of Low Permeability and Thick Layer of N Gas Field

For a better guidance of production, a combination of drill stem testing (DST), regional statistical method and pseudo steady-state seepage theory model was used to analyze the productivity of N gas reservoir in light of the complex geological features of the low-permeability thick-layer. Firstly, the DST method was used to test the N gas reservoir. And then the binomial pseudo-pressure method, binomial pressure square method and exponential method were used to interpret the test data of DST of this formation. Finally, the binomial pseudo-pressure interpretation method was used and the results showed that only the productivity of H3b layer was successfully tested of the four. The H3a, H4b and H5a layers are ultra-low pore and permeability gas reservoirs and the productivity of these layers can’t be explained by the available data due to the short testing time and a non-stationary state of testing pressure and quantity, resulting in the failure of the test. The productivity of the main layers were estimated and forecasted by the regional statistical method and the theoretical model of pseudo steady-state seepage, taking the arithmetic average value of the regional statistical method and the theoretical formula as the final value of absolute open flow rates(AOF). The final calculation results are as follows: the AOF of main gas layers H3a, H3b, H4b and H5a in N gas field is 31.30×104m3/d, 388.92×104m3/d, 20.82×104m3/d and 30.80×104m3/d, respectively. This method may sheds light on verifying and calculating the productivity of gas wells and determining the reasonable production allocation of gas wells.

Effect of gas adsorption-induced pore radius and effective stress on shale gas permeability in slip flow: New Insights

Abstract Shale, a heterogeneous and extremely complex gas reservoir, contains low porosity and ultra-Low permeability properties at different pore scales. Its flow behaviors are more complicated due to different forms of flow regimes under laboratory conditions. Flow regimes change with respect to pore scale variation resulting in change in gas permeability. This work presents new insights regarding the change of pore radius due to gas adsorption, effective stress and impact of both on shale gas permeability measurements in flow regimes. From this study, it was revealed that the value of Klinkenberg coefficient has been affected due to gas adsorption-induced pore radius thickness impacts and resulting change in gas permeability. The gas permeability measured from new proposed equation is provides better results as compare to existing equation. Adsorption parameters are the key factors that affect radius of shale pore. Both adsorption and effective stress have an effect on the pore radius and result gas permeability change. It was found that slip effect enhances the apparent gas permeability and also changes with effective stress; therefore, combine impact of slip flow and effective stress is very important as provides understanding in evolution of apparent permeability during shale gas production.

Gas production behavior from hydrate-bearing fine natural sediments through optimized step-wise depressurization

There have been several field tests around the world to recover natural gas from gas hydrate reservoirs, yet they mostly suffer from the low productivity, sand problems and poor economic efficiency. The ultralow permeability of the sediments and an insufficient heat supply act as major barriers. Intense investigations have been carried out to study the gas production behavior from lab-synthesized hydrate-bearing coarse sands; yet the porous matrices could differ significantly from the natural sediments. Few studies have been found to focus on the role of fine natural sediments in the gas recovery performance. In this study, natural marine sediments from the South China Sea are used as the porous matrices, and gas is produced through an optimized stepwise depressurization. Significant differences in the gas production behaviors from fine natural sediments and coarse grains are found. The fine marine sediments may induce the blockage of the production well, even with protection measures; this problem will result in an uncontrolled pressure drop and gas output. Moreover, the stepwise depressurization efficiently contributes to remitting the temperature drop of the reservoir, increasing the minimum temperature from −0.5 ℃ upon a straight pressure drop to 0.27 ℃ upon a step-wise depressurization. This method can therefore help prevent the ice generation during hydrate dissociation. Additionally, a finer pressure gradient of 0.5 MPa will enhance the hydrate dissociation rate by 18.92% compared with the 2 MPa step scenario. The average gas production rate is determined to positively correlate with the Stefan number, which indicates a dominant role of the sensible heat of the reservoir in the efficient gas production. The findings could be applied in the field tests of gas hydrates to avoid ice generation and achieve a stable and continuous gas production behavior.

Investigation of increasing hydraulic fracture conductivity within producing ultra-deep coal seams using time-lapse rate transient analysis: A long-term pilot experiment in the Cooper Basin, Australia

Ultra-low permeability, inertinite-rich, poorly cleated, dehydrated, overpressured coal seams deeper than 9000 ft (2740 m) in the Cooper Basin of central Australia represent a fundamentally different play type to shallow and “deep” coal seam gas reservoirs. Proof-of-concept gas flow was achieved in 2007. Four Patchawarra Formation coal seams were subjected to low-proppant concentration slick-water hydraulic fracture stimulation within a dedicated vertical wellbore at a depth of 9500 ft (2900 m). Gas was produced for 81/2 years at a slowly increasing base flow rate, averaging 0.1 MMscfd (2.8 Mscmd). Experimental data were gathered for characterising dynamic reservoir behaviour. This included multiple extended pressure build-up tests. The authors have previously investigated the three largest of these using time-lapse pressure transient analysis. The published results reveal a dominant bilinear flow regime, associated with an isolated domain of increasing coal fabric permeability surrounding the hydraulic fracture.This paper builds upon the time-lapse pressure transient analysis study by specifically investigating conductivity of the hydraulic fracture, which the authors postulate to have also increased. The hypothesis is tested by applying time-lapse rate transient analysis to the two specially designed pressure drawdown tests to atmospheric pressure that immediately follow the first two pressure build-up tests of the time-lapse pressure transient analysis. Between the two pressure drawdown tests, spaced 586 days apart, the wellbore flowed gas continuously for 327 days, at an average flowing bottom-hole pressure of 580 psig (4.0 MPag). Hence, there was ample opportunity for hydraulic fracture conductivity to change between the tests.Both pressure drawdown tests were monitored for 24 h using high-resolution surface pressure gauges. Each was initiated from the same surface shut-in pressure of 2500 psig (17.2 MPag). The flow pressure data are initially used to construct “diagnostic plots” that clearly identify the hydraulic fracture linear flow regime, early in each test, immediately after the dissipation of wellbore storage. Hydraulic fracture properties are then extracted using “specialty plots” that display rate-normalised pseudo-pressure difference versus linear superposition time.Comparing the slopes of the two speciality plot trends indicates that the hydraulic fracture flow property bfkf∅f increased during the 327-day gas flow period by a factor of 4. This is supported by a 60% increase in the initial gas flow rate from “hydraulic fracture storage”, from 7.5 to 12.0 MMscfd (212.4 to 340.0 Mscmd). Additionally, despite a significantly larger volume of “hydraulic fracture storage” gas being produced to surface during the second test, the duration of the hydraulic fracture linear flow regime is less than for the first. These observations are consistent with an increasingly more conductive hydraulic fracture over flowback time that allows compressed gas within it to discharge more rapidly.

Study on the dosage of temporary plugging Agent for steering fracturing

The Triassic Baikouquan Formation in the Junggar Basin has developed a large number of dense sandstore conglomerate reservoirs, which belong to ultra-low permeability and ultra-low permeability refractory reservoirs. In recent years, the productivity of single well is improved by selecting potential production wells for multi-stage steering fracturing. In order to realize the forced steering of fractures, it is very important to study the sealing pressure of temporary plugging agent. According to the actual needs of Baikouquan steering fracture, the net pressure model of steering fracture is established. The net pressure value in the seam is calculated according to the change of ground stress after steering, then calculated the minimum temporary plugging agent sealing pressure needed for a single fracture. Based on the net pressure model, the corresponding software is developed and applied to the field. The practical application effect is good, which provides economical and effective technical technical support for the continuous and stable production of low permeability oil field.

A simulation-based method to determine the coefficient of hyperbolic decline curve for tight oil production

Tight oil reservoirs are characterized by the ultra low porosity and permeability, making it a great challenge to enhance oil production. Owing to the fast development in hydraulic fracturing technology of horizontal wells, tight oil has been widely explored in North America. Individual wells have a long term of low production after a rapid production decline. This causes low cumulative production in tight oil reservoirs. A rate decline curve is the most common method to forecast their production rates. The forecast can provide useful information during decision making on future development of production wells. In this paper, a relationship is developed between the parameters of a hyperbolic decline curve and the reservoir/fracture properties when a reservoir simulation model is used based on the data from a real field. Understanding of this relationship improves the application of the hyperbolic decline curve and provides a useful reference to forecast production performance in a more convenient and efficient way. Cited as : Yu, Y., Chen, Z., Xu, J. A simulation-based method to determine the coefficient of hyperbolic decline curve for tight oil production. Advances in Geo-Energy Research, 2019, 3(4): 375-380, doi: 10.26804/ager.2019.04.04

A highly proton-conductive and vanadium-rejected long-side-chain sulfonated polybenzimidazole membrane for redox flow battery

A long-side-chain sulfonated polybenzimidazole (PBI-PS) membrane was successfully prepared by the reaction of PBI with 1, 3-propanesultone for improving the efficiencies of vanadium redox flow battery. The interaction between sulfonic acid and imidazole groups provides the PBI-PS membrane with excellent swelling resistance, leading to a swelling ratio of only 13% for the membrane with IEC of as high as 3.18 mmol g−1. This results in an ultra-low vanadium permeability (6.5 × 10−9 cm2 s−1). The introduction of sulfonic acid-terminated flexible side chain in the membrane also constructs good microphase separation structure, leading to a low area resistance of 0.51 Ω cm2, which is close to Nafion 212 (0.41 Ω cm2). This membrane exhibits excellent cell performance. The voltage and energy efficiencies are up to 90.73% and 89.13% at 80 mA cm−2, respectively. Furthermore, the efficiencies remain constant values for 200 cycles, and no changes in chemical structure and cell efficiencies are observed after 720 h immersion in electrolyte solution.

Nuclear-Magnetic-Resonance Study on Oil Mobilization in Shale Exposed to CO2

SummaryReservoirs in the Qian 34 10 rhythmic layer of the Qianjiang Basin are shale oil reservoirs with intersalt sediments. During the natural depletion and development process, production rate of oil decreases rapidly. Water injection and CO2 injection are potential technologies for enhanced oil recovery (EOR) in shale. Because of high salt content in formations, unsaturated water dissolves salt and damages reservoirs. CO2 does not react with salt, and CO2 injection does not damage reservoirs. Moreover, CO2 could enter the micropores of the reservoir rocks and mobilize oil by diffusion, extraction, and swelling mechanisms. To verify oil mobilization in the shale exposed to CO2, exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.NMR T2 spectrum could reflect the oil in place and be used to calculate the oil content of rock with low permeability. In this study, 10 fresh shale samples (from six depths) were analyzed, and the oil contents were determined using NMR T2 spectra. Two of the shale samples with high oil contents were selected for the CO2-exposure experiment. At a temperature of 40°C and a pressure of 17.5 MPa, the fresh shale samples were exposed to CO2, and the NMR T2 spectra obtained were used to continuously determine the oil content of the shale. The oil mobilization in the shale exposed to CO2 was determined.The results of the NMR T2 spectra showed that the NMR volume fractions of the remaining oil in seven fresh shale samples were above 10%. The recovery of the S5# shale exposed to CO2 was 51.2% after 8 days, whereas that of the S9# shale was 55.8% after 6.1 days. These results indicated that more than half of the shale oil was mobilized during the relatively long exposure time after CO2 injection. NMR T2 spectroscopy results also showed that oil in all pores could be mobilized as the exposure time increased.This study showed the quantitative results of the CO2-injection method and EOR in a shale oil reservoir of the Qianjiang Basin. All conclusions support starting a CO2-EOR pilot project in the shale oil reservoir with intersalt sediments with ultralow permeability.

Research on Residual Petroleum in Complex Ultra-low Permeability Fuyu Oil Layer in the Peripheral Area of Western Daqing City and Effect Analysis of Potential Tapping Countermeasures

Qijiabei Oilfield belongs to ultra-low permeability and secondary pore development reservoirs. After years of water injection development, it is difficult to establish effective displacement, poor long-term low-efficiency wells and low development efficiency. problem. In view of the above problems, this paper uses fine reservoir description and multi-disciplinary integration technology to finely describe the fault location, subdivided sedimentary microfacies, partition segmentation fitting physical parameters and fine residual oil research, and find out the main problems of poor oilfield development. the reason. On this basis, according to the dynamic development characteristics, under the premise of quantifying the remaining oil to the permeability level, the targeted measures are formulated for the main remaining oil types, especially for the remaining oil with poor effect, according to the divisional adjustment ideas. The sub-well distinguishing area shall be formulated with individualized measures for tapping and digging potential, that is, comprehensively considering reservoir development, connectivity, and residual oil distribution rules, and implementing targeted oil and water wells corresponding adjustment and production techniques based on the detailed description of remaining oil. The water absorption ratio of oilfield sandstone increased by 8.4%, the output ratio of small layer increased by 18.7%, the natural decline rate decreased by 6.9%, the ultimate recovery rate increased by 1.22%, the oilfield development effect became better, and the research and synthesis of residual oil in complex ultra-low permeability reservoirs Digging potential provides a reference.