Core Permeability Research Articles

Study on Production Characteristics during N2 Flooding in Low Permeability Reservoirs: Effect of Matrix Permeability and Fracture

The N2 flooding enhanced oil recovery process is an important technical means for the development of low permeability reservoirs due to its good energy enhancement effect and good injectivity. Low permeability reservoirs have a large permeability span and strong heterogeneity, which will have a significant impact on gas injection development. In order to explore the influence of matrix permeability and fractures on the production characteristics of N2 flooding, this study conducted a series of displacement experiments with full-scale matrix permeability (0.1–50 mD) and different fracture conditions. The research results indicate that, in non-fracture low permeability cores, the pressure difference decreased with the matrix permeability increase, and the volume of N2 injection required to achieve the highest injection pressure decreased. In addition, the increase in matrix permeability accelerates the gas breakthrough and gas channeling, but is beneficial for improving no-gas oil recovery and ultimate oil recovery due to the decrease in crude oil flow resistance. The impact of different matrix permeability ranges on production characteristics varies. When the matrix permeability is less than 2 mD, the characteristics of oil and gas production are significantly affected by changes in matrix permeability. When the matrix permeability is greater than 2 mD, the impact of changes in matrix permeability on development effectiveness is weakened. The existence of fracture causes a high permeability channel to appear in the low permeability matrix, exacerbating the gas breakthrough and channeling, and significantly reducing the utilization of matrix crude oil (about a 50% decrease in oil recovery). The increase in matrix permeability is beneficial for weakening the heterogeneity between fractures and the matrix, alleviating the gas channeling, thereby increasing the swept volume in the low permeability matrix and improving oil recovery.

Measuring gas permeability in tight cores at high pressure: Insights into supercritical carbon dioxide seepage characteristics.

This study introduces a new, more accurate instrument for measuring gas permeability in tight cores at high pressure, surpassing the accuracy of conventional methods. Using the steady-state method, the study tested the permeability of carbon dioxide (CO2) in tight cores at various pressure conditions. We observed that, similar to nitrogen, CO2 permeability initially conformed to the Klinkenberg slip theory, but began to deviate as back pressure increased. Supercritical CO2 exhibited a slight increase in permeability, which contrasts with both nitrogen behavior and the Klinkenberg slip theory. Accurate measurement of CO2 permeability in tight rocks is crucial for assessing the feasibility and efficiency of CO2 injection and storage, which could help reduce greenhouse gas emissions and drive energy transformation. The innovative measurement approach can assist in identifying the ideal production pressure drops, injection pressures, and flow rate parameters, thus improving the recovery rate of tight oil reservoirs. Nevertheless, the study had some limitations, including prolonged stable flow time, lack of real-time flow rate display, and reliance on theoretical viscosity calculations, all of which could affect the accuracy of permeability measurements. Further research is needed to investigate CO2 permeability under diverse conditions and to deepen our understanding of CO2 transport and storage in tight cores, which could lead to improvements in CO2 sequestration and the efficiency of enhanced oil recovery.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

Integrated Core and Log Data to Determine the Reservoir Flow Unit and Rock Facies for Mishrif Formation in South Eastern Iraq

This work represents study the rock facies and flow unit classification for the Mishrif carbonate reservoir in Buzurgan oil Field, which located n the south eastern Iraq, using wire line logs, core samples and petrophysical data (log porosity and core permeability). Hydraulic flow units were identified using flow zone indicator approach and assessed within each rock type to reach better understanding of the controlling role of pore types and geometry in reservoir quality variations. Additionally, distribution of sedimentary facies and Rock Fabric Number along with porosity and permeability was analyzed in three wells (BU-1, BU-2, and BU-3). The interactive Petrophysics - IP software is used to assess the rock fabric number, flow zones, and reservoir quality index. The Mishrif Formation has four distinct rock types and groups that have been recognized using the approach. The first rock type represents a poor reservoir quality (mud-dominated fabrics) with rock-fabric numbers equals to 2.5-4, the second rock type reveals a moderate reservoir quality (wackestone-Packstone Microfacies), the third rock type depicts a good reservoir quality (grain-dominated packstone) with rock-fabric numbers equals to 1.5-2.5 and 0.5-1.5.

Determination of Reservoir Hydraulic Flow Units and Permeability Estimation Using Flow Zone Indicator Method

Reservoir characterization plays a crucial role in comprehending the distribution of formation properties and fluids within heterogeneous reservoirs. This knowledge is instrumental in constructing an accurate three-dimensional model of the reservoir, facilitating predictions regarding porosity, permeability, and fluid flow distribution. Among the various methods employed for reservoir characterization, the hydraulic flow unit stands out as a widely adopted approach. By effectively subdividing the reservoir into distinct zones, each characterized by unique petrophysical and geological properties, hydraulic flow units enable comprehensive reservoir analysis. The concept of the flow unit is closely tied to the flow zone indicator, a critical parameter that defines the porosity-permeability relationships of each hydraulic flow unit. Additionally, the flow zone indicator method proves valuable in estimating permeability accurately. In this study, we demonstrate the application of the flow zone indicator method to determine hydraulic flow units within the Khasib formation. By analyzing core data and calculating the Rock Quality Index (RQI) and Flow Zone Indicator (∅Z), we differentiate the formation into four hydraulic flow units based on FZI values. Specifically, HFU 1 represents a rock of poor quality, corresponding to compact and chalky limestone. HFU 2 represents intermediate quality, corresponding to argillaceous limestone, while HFU 3 represents good quality, corresponding to porous limestone. Lastly, HFU 4 signifies an excellent reservoir rock quality characterized by vuggy limestone. By establishing a permeability equation that correlates with effective porosity for each rock type, we successfully estimate permeability. Comparing these estimated permeability values with core permeability reveals a strong agreement with a high correlation coefficient of 0.96%. Consequently, the flow zone indicator method effectively classifies the Khasib formation into four distinct hydraulic flow units and provides an accurate and reliable means of determining permeability in the reservoir. The resulting permeability equations can be applied to wells and depth intervals lacking core measurements, further emphasizing the practical utility of the FZI method.

Prediction of Hydraulic Flow Units for Jeribe Reservoir in Jambour Oil Field Applying Flow Zone Indicator Method

The Jeribe reservoir in the Jambour Oil Field is a complex and heterogeneous carbonate reservoir characterized by a wide range of permeability variations. Due to limited availability of core plugs in most wells, it becomes crucial to establish correlations between cored wells and apply them to uncored wells for predicting permeability. In recent years, the Flow Zone Indicator (FZI) approach has gained significant applicability for predicting hydraulic flow units (HFUs) and identifying rock types within the reservoir units. This paper aims to develop a permeability model based on the principles of the Flow Zone Indicator. Analysis of core permeability versus core porosity plot and Reservoir Quality Index (RQI) - Normalized porosity log-log plot reveals the presence of three distinct Hydraulic Flow Units and corresponding rock types within the Jeribe reservoir. These rock types can be identified if known. The reservoir can be divided into three groups of rock types, namely good, moderate, and bad quality. The bad rock type represents a restricted section within the reservoir, while the upper and lower parts predominantly consist of moderate-quality rock types. Conversely, the central section of the reservoir exhibits a good-quality rock type. By utilizing the Flow Zone Indicator principles, this study provides valuable insights into the hydraulic flow behavior and rock types present in the Jeribe reservoir. The proposed permeability model derived from this method can aid in predicting permeability values for uncored wells, contributing to a better understanding of the reservoir's heterogeneity and facilitating reservoir characterization and management decisions.

CO2 diffusive characteristics and influencing factors in the porous medium with saturated polyacrylamide solutions

Polyacrylamide has been widely utilized to store CO2 in reservoirs in order to alleviate the greenhouse impact. However, no studies have been conducted on the motion of CO2 in a polyacrylamide solution within porous media. This study illustrates the effect of polyacrylamide molecular weight, concentration, pressure, temperature, and pore size on the dynamic diffusion of CO2 in the core with saturated polyacrylamide solutions. The diffusion motion characteristics of CO2 were obtained by diffusion experiments. The microscopic analysis of core slices following testing showed the presence of polyacrylamide on rock particles. The pressure and CO2 mass fraction distribution inside the core were calculated by constructing a mathematical model. The results show that the increase in molecular weight and concentration of polyacrylamide decreased the diffusion ability of CO2, while temperature and pressure accelerated the diffusion of CO2. The polyacrylamide moved into the core to form an effective inhibiting effect, which was affected by CO2 and pressure. While the increase in pore size accelerates the flow rate of the polyacrylamide, it also enhances the sealing capacity of the polyacrylamide solution. Scanning electron microscopy (SEM) and energy dispersive spectroscopy (EDS) showed that the core had a high content of polyacrylamide solution inside it, and these molecules were attached to the surface of the core particles in an irregular lamellar pattern. The calculation model was consistent with the diffusion experimental results, where the CO2 diffusion coefficient in the polyacrylamide solution was in the order of 10-12 m2/s under the conditions of 5–30 MPa, 323–343 K, and a core permeability of 60 × 10-3 μm2. The results of this paper provide a new calculation for evaluating the performance of polymer plugging.

A Submicron-Scale Plugging Agent for Oil-Based Drilling Fluid Synthesized Using the Inverse Emulsion Polymerization Method

Due to the increasing difficulty of drilling in the later stages of oil and gas field development, the development of micro-pores and micro-fractures is becoming common. Conventional plugging agents have relatively large particle sizes. So, choosing the appropriate plugging agent can prevent leakages. Using the inverse emulsion polymerization method, acrylamide, 2-acrylamide-2-methylpropane sulfonic acid and acrylic acid were selected to be the main reaction monomers, N,N′-methylenebisacrylamide was used as a crosslinking agent, sorbitan monostearate and polyoxyethylene sorbitan anhydride monostearate were used as emulsifiers, and 2,2′-azobis(2-methylpropionamidine) dihydrochloride was used as the initiator to synthesize a nano-scale plugging agent for oil-based drilling fluid. The plugging agent was characterized using infrared spectroscopy, scanning electron microscopy, and thermogravimetry analysis. The results showed that the plugging agent is spherical and uniform in size, with particles being in the submicron range. Additionally, it exhibited strong temperature resistance. Finally, the performance of the plugging agent was evaluated via experiments conducted under normal temperature and pressure, high-temperature and high-pressure, and core-plugging conditions. After adding the plugging agent to the oil-based drilling fluid, the basic rheological properties of the oil-based drilling fluid were not significantly affected. Furthermore, the filtration loss was significantly reduced under normal temperature and pressure, as well as under high-temperature and high-pressure conditions, after aging. When the plugging agent with 3% concentration was added, the reduction rate of pore core permeability reached 96.04%. Therefore, the plugging agent for the oil-based drilling fluid can effectively improve the wellbore stability and has a promising potential for field applications.

Adsorption characteristics, isotherm, kinetics, and diffusion of nanoemulsion in tight sandstone reservoir

Nowadays, nanoemulsions have shown a high application potential in improving hydrocarbon recovery from tight reservoirs. However, the adsorption characteristics, isotherms, kinetics of nanoemulsions onto reservoir rocks surface and the diffusion behavior into reservoir matrix are still not been systematically clarified. In this work, nanoemulsion was prepared by diluted microemulsion method using two nonionic surfactants, isopropanol, limonene and 2.0 wt% KCl solution. The static adsorption capacity measurement under different influencing factors were carried out, and the adsorption process was characterized through equilibrium isotherms and kinetic studies. Also, the diffusion behavior of nanoemulsion in the sandstone reservoir matrix were evaluated by core flooding experiments. Results indicated that the nanoemulsion was successfully synthesized and the droplet size mainly distributed between 8 and 18 nm. It had been found that the optimal static adsorption experimental parameters for 0.1 wt% nanoemulsion were 1:8 solid–liquid ratio and 50/60 mesh rock powder. Equilibrium adsorption results indicated that Langmuir model yielded a better fit which means that single-layer coverage of the surfactants composed of nanoemulsion onto the rock surfaces was more probable. Meanwhile, it was concluded that the pseudo-second order model could better describe the kinetic behavior of nanoemulsion adsorption onto the rock surfaces, which revealed that the adsorption rate was positively correlated with the nanoemulsion concentration. Dynamic adsorption experiments showed that the adsorption amount is inversely proportional to the core permeability, while the diffusion coefficient increases with the increase of permeability. Moreover, the advantage of nanoemulsions over sole surfactant is that the oil nucleus in the nanoemulsions enable control the release of the attached surfactants, and there is a competitive adsorption relationship between oil nucleus and rock surface for the free surfactants in the solution, which offers a possibility for reducing the surfactant adsorption loss and extending the invasion distance in the reservoir matrix. The findings obtained in this study can help for better understanding of the interaction mechanism between nanoemulsions and reservoir rocks, and provide guidance for selecting appropriate nanoemulsions for the enhanced oil recovery (EOR) project in tight sandstone reservoirs.

Depositional environment and aquifer properties of the Sherwood Sandstone Group in the Cleveland Basin based on investigations at Woodsmith Mine

A major mining project by Anglo American plc at Woodsmith Mine is targeting deep polyhalite deposits in the Cleveland Basin of North Yorkshire. The mine shaft design included hydrogeological assessment of the full 1600 m hydrostratigraphic sequence to be intersected. Of this sequence the most significant aquifer that will be intersected is the Sherwood Sandstone Group (SSG), which will be encountered at depths of between 800 and 1050 m below surface. Deep exploratory cored boreholes were completed at the site to allow both laboratory and field testing. The methods used to determine the aquifer characteristics comprised geotechnical laboratory testing of rock core and oilfield downhole wireline technology. Geotechnical triaxial tests were used to determine the horizontal and vertical permeability of rock core recovered from deep exploration boreholes. Wireline Elementary Log ANalyses (ELAN) and Modulation Dynamic Testing (MDT) were used to determine hydraulic conductivity and porosity of the SSG sequence encountered. Formation Micro Imager (FMI) was used to determine sedimentary depositional features. This paper presents a review of the ground investigation data collected to characterize anisotropy between horizontal and vertical flow within the SSG in this part of the Cleveland Basin. Thematic collection: This article is part of the Hydrogeology of Sandstone collection available at: https://www.lyellcollection.org/cc/hydrogeology-of-sandstone

Optimized hydrophobic magnetic nanoparticles stabilized pickering emulsion for enhanced oil recovery in complex porous media of reservoir

With an extensive application of flooding technologies in oil recovery, traditional emulsion flooding has seen many limits due to its poor stability and easy demulsification. Pursuing a new robust emulsion plays a fundamental role in developing highly effective emulsion flooding technology. In this work, a novel Pickering emulsion with special magnetic nanoparticles Fe3O4@PDA@Si was designed and prepared. To disclose the flooding mechanism from magnetic nanoparticles, the physico-chemical characterization of Fe3O4@PDA@Si was systematically examined. Meanwhile, the flooding property of the constructed Pickering emulsion was evaluated on the basis of certain downhole conditions. The results showed that the synthesis of Fe3O4@PDA@Si nanoparticles was found to have a hydrophobic core-shell structure with a diameter of 30 nm. Pickering emulsions based on Fe3O4@PDA@Si nanoparticles at an oil-to-water ratio of 5:5, 50°C, the water separation rate was only 6% and the droplet diameter of the emulsion was approximately 15 μm in the ultra-depth-of-field microscope image. This demonstrates the excellent stability of Pickering emulsions and improves the problem of easy demulsification. We further discussed the oil displacement mechanism and enhanced oil recovery effect of this type of emulsion. The microscopic flooding experiment demonstrated that profile control of the Pickering emulsion played a more important role in enhanced recovery than emulsification denudation, with the emulsion system increasing oil recovery by 10.18% in the micro model. Core flooding experiments have established that the incremental oil recovery of the Pickering emulsion increases with decreasing core permeability, from 12.36% to 17.39% as permeability drops from 834.86 to 219.34 × 10−3 μm2. This new Pickering emulsion flooding system stabilized by Fe3O4@PDA@Si nanoparticles offers an option for enhanced oil recovery (EOR).

Computed X‐ray Tomography Investigation of Porosity and Permeability of the Liujiagou Formation Sandstone Exposed to CO2‐Saturated Brine

AbstractIn order to improve CO2 capture, utilization and storage (CCUS) to solve carbon emission, sandstone from the Triassic Liujiagou Formation (LF) from the Ordos Basin in China was investigated using permeability tests and computed X‐ray tomography (CT) scanning. The presence of reactive minerals within the geological CO2 sequestration target storage formation can allow reaction with injected CO2, which changes the porosity and permeability of the LF beds, affecting storage effectiveness. To investigate the effect of chemical reactions on the pore structure and permeability of sandstone cores representing the LF CO2 storage, tests were conducted to analyze the changes in porosity and permeability of sandstone cores induced by CO2‐saturated brine at different reaction times (28‐day maximum reaction period). Porosity and permeability of the sandstone increased after reaction with CO2‐saturated brine due to mineral dissolution. The sandstone exhibited an increase in porosity and permeability after 15 days of reaction with CO2‐saturated brine. Moreover, there was an increase in the volume of large pores in the sandstone after the 28‐day period. The pore network of the sandstone was established through CT results, and the porosity calculated based on the obtained pore network was close to that measured in the test, demonstrating the feasibility to use CT to study the evolution of the microstructure of sandstone after long‐time exposure to CO2‐saturated brine.

Design of a Current-Transformer Based Inductive Coupler for Power-Line Communications

In this paper, the design of a current-transformer based inductive coupler for power-line communications is documented. A worst-case design is presented in a step-by-step fashion and experimentally confirmed by doing verification measurements in the laboratory as well as live, 240-V tests in a controlled environment. Although field deployment of inductive couplers usually relies on parasitic capacitance and/or surge protection capacitors to complete the current loop, in this controlled experimental setup various discrete loop capacitors were utilized to characterize the impact on transmission. A band-pass filtering response was achieved without any external filter circuitry, as internal coupler parasitic parameters were utilized for this. For the single-coupler laboratory measurements, both the lower and upper cut-off point results were approximately within 10% of predicted values. These results are quite encouraging, seeing that coupler core permeability is specified with a ± 20% tolerance. Live tests showed that (i) cable length (series inductance) impacts on the upper cut-off point of the system passband, while (ii) loop capacitance affects the lower cut-off point of the system passband.

Experimental Mechanism for Enhancing Oil Recovery by Spontaneous Imbibition with Surfactants in a Tight Sandstone Oil Reservoir

This study aims to investigate the mechanism behind surfactant enhanced oil recovery under reservoir conditions through experiments on spontaneous imbibition with surfactants. The tight sandstone samples are characterized using cast thin section (CTS), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) to determine their clay mineral composition, pore size distribution, and fluid distribution. Spontaneous imbibition experiments are then conducted using formation water and surfactant solutions as imbibition liquids, with three different types of surfactants─dodecylbenzene sulfonate (DBS), sodium dodecyl sulfate (SDS), and ammonium bromide─at two different concentrations, each to examine the effect of surfactant type. Additionally, the interfacial tension (IFT) between crude oil and different imbibition solutions is measured, and the contact angles of an oil droplet on the core surface in air, formation water, distilled water, and surfactant solution are determined. Finally, the effects of IFT, rock wettability, formation water salinity, and core permeability on final oil recovery by spontaneous imbibition are analyzed. The results indicate that surfactant-assisted spontaneous imbibition primarily operates through IFT reduction, wettability alteration, and emulsification of crude oil. However, ultralow IFT may lead to low ultimate oil recovery. To increase the ultimate oil recovery of spontaneous imbibition, reducing the salinity of the surfactant solution and creating microfractures can be effective strategies.

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T2 distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T1-T2 maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T1-T2 maps. Finally, the T1-T2 maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery.

FeSiCr soft magnetic composites with significant improvement of high-frequency magnetic properties by compositing nano-YIG ferrite insulating layer

FeSiCr soft magnetic composites (SMCs) with yttrium iron garnet (YIG) coating layer were studied in this work. The YIG with nano size was synthesized by reverse co-precipitation method, which was coated on FeSiCr powders with different YIG contents. The effect of the annealing temperature on the FeSiCr/YIG SMCs was also investigated. It was found that a moderate amount of YIG ferrite could form a thin and uniform layer, resulting in significant optimizations in core loss, permeability, and DC bias characteristics. The results show that the FeSiCr/YIG SMCs with 0.75 wt% YIG exhibit the best magnetic performance (Pcv = 131.34 mW/cm3, μe = 44.5 at 10 mT and 500 kHz). In addition, it was demonstrated that the FeSiCr/YIG SMCs with 0.75 wt% YIG presented the lowest core loss and largest permeability at the optimal annealing temperature of 500 °C. This study provides a new kind of FeSiCr/YIG SMCs which have good prospects to be used in high-frequency fields.

Experimental study on water flooding mechanism in low permeability oil reservoirs based on nuclear magnetic resonance technology

Low permeability oil reservoirs are characterized by complex pore-throat structure and complex mechanism of oil and water storage and transmission. At present, the research on cross-scale characteristics of pore-throat structure in low permeability reservoirs needs to be strengthened, and the research on oil-water evolution characteristics needs to be improved. In this paper, based on NMR method, different “porosity-permeability-original oil saturation” coupling evaluation systems are constructed, the study on oil and water distribution characteristics at different water flooding stages has been carried out, and the distribution mechanism of residual oil in pores with different sizes is analyzed. It is found out that: (a) the higher the core permeability, the lower the displacement pressure; the lower the core permeability, the higher the displacement pressure. (b) The T2 spectrum shows that micropores, mesopores and macropores in core samples are well developed. (c) The morphology of T2 spectrum can be divided into three types: high right peak and low left peak, high left peak and low right peak, and basically equal left and right peaks. In addition, under saturated oil conditions, medium and large pores are the main oil storage spaces. (d) There are three factors affecting the water flooding efficiency: the influence of micro-fractures, the influence of pore-throat heterogeneity and the influence of the degree of producing pore-throat.

Digital Core Permeability Computation by Image Processing Techniques

Calculation of REV (representative elementary volume) properties of geological porous media refers to the process of creating a 3D digital representation of a rock sample, typically obtained from imaging techniques such as X-ray microtomography. This technique allows for a detailed analysis of the internal structure and the properties of rocks, as well as precise calculation of various flow parameters. However, one major challenge with calculation of REV properties of geological porous media is the high computational cost required to generate accurate results, especially for large and complex samples. In this study, we constructed 3D digital cores of dune sand and fractured shale using CT scanning technology, and then used two image processing techniques, namely digital core image resampling and cutting, to reduce the computational cost of calculating digital core permeability. Next, a fast permeability calculation method is employed to reduce the complexity of permeability calculation. Finally, we summarized the applicability of different image processing methods to different rock samples, and provided prerequisites for high computational cost digital core permeability calculation.

Effect of surfactant on oil displacement efficiency of imbibition/huff and puff in low permeability reservoirs

ABSTRACT Low permeability and tight reservoirs are rich in microscale and even nanoscale pores, resulting in a large interfacial tension between oil and water in the pores. Surfactant can effectively improve the oil displacement efficiency during imbibition and huff and puff. In this paper, the low permeability cores with different permeability are taken as the research object, and the effects of surfactant and distilled water on the oil displacement efficiency of imbibition/huff and puff are compared and analyzed using the nuclear magnetic resonance technology. Results show that: (a) Huff and puff can significantly improve displacement efficiency, and there are mainly three reasons: the soaking time, surfactants improve infiltration efficiency, and elastic energy. (b) Imbibition is a spontaneous phenomenon in tight reservoirs, while huff and puff is artificially manipulated. (c) Due to the slow infiltration process, as the soaking time increases, the oil displacement efficiency increases. (d) when the pressure is increased from 0.1 MPa to 12 MPa, the oil recovery and displacement efficiency are increased by about 2 times. (e) Compared with imbibition displacement, huff and puff can significantly improve displacement efficiency. (f) The T2 spectrum shows that the oil displacement efficiency of surfactant imbibition is higher, and the oil displacement efficiency of imbibition is significantly lower than that of huff and puff.

Optimal design of iron-cored coil sensor in magnetic flux leakage detection of thick-walled steel pipe

Thick-walled steel pipes, which bear high internal pressure, are widely applied in nuclear power and pressure pipelines. If there are defects in the inner wall, they are easy to expand and cause accidents. Therefore, the thick-walled steel pipe must be subject to non-destructive testing after production. For the magnetic flux leakage (MFL) testing method, the detection sensitivity gradually decreases with the increase of wall thickness. To solve this problem, a new structure of MFL probe is proposed in this paper. The influence of the iron core permeability on the MFL signal is analyzed theoretically, and the effect of the core length and diameter on the MFL signal is analyzed by simulation. The variation of the MFL signal with the change of the iron core and coil lift-off is studied respectively. The simulation results are verified by experiments. It is found that the lift-off of the iron-cored coil is determined by the iron core position. Based on this phenomenon, an MFL array probe is designed, which can be used for online detection of thick-walled steel pipes to improve the detection sensitivity of inner wall defects.