Tight Core Research Articles

Imbibition oil recovery from tight reservoir cores using microemulsion: Experiment and simulation

Imbibition oil recovery from tight reservoir cores using microemulsion: Experiment and simulation

An improved Klinkenberg permeability model for tight reservoir cores: Effects of non-linear gas slippage to real gases

Absolute permeability is one of the most fundamental reservoir-rock properties required for reservoir simulation models. Most research studies are focused on the Klinkenberg gas slippage, considering the ideal behavior of the flowing gas under first- and second-order slippage conditions. This paper assesses the non-linear slippage of real gas through the low permeability reservoir rock samples. The cubic equation of state (van der Waals/Soave-Redlich-Kwong/Peng-Robinson), coupled with Taylor series-based non-linear slippage, predicts the apparent permeability for the non-Darcy gas flow in tight reservoir rock. The novelty of the present contribution is to develop a comprehensive mathematical model to describe the temperature- and pressure-dependent non-linear slippage effect accounting for the real gas behavior, which is based on the fundamental principle of momentum balance. The thirty-nine sets of experimental results of different authors using different core samples (e.g., coal seams, tight sandstones, tight carbonates, gas-shale reservoirs) and gases (Air, H2, He, N2, CH4, C2H6, and CO2) are used to authenticate the proposed non-linear slip model for real gases. Results show that (a) the proposed model correctly predicts infinite permeability and non-linear slippage coefficients of eight-tests non-ideal gases with an average absolute deviation of ≤9.69%, (b) non-linear slippage dominates for the core samples having permeability <1.5 mD, and (c) the first- and second-order slippage coefficients vary from 0.76 to 6.22 atm and 0.15–9.30 atm2, respectively. The proposed model is simple and may readily be applied for the reservoir simulation of coal seams, tight sandstones, tight carbonates, gas-shale reservoirs, etc., for reservoir characterization, forecasting future natural gas production, decision-making, and efficient reservoir management practices for enhanced production efficiency and sustainability.

Pore- and Core-Scale Recovery Performance of Consortium Bacteria from Low-Permeability Reservoir.

Performance evaluation of microorganisms that have emulsifying and degrading effects on crude oil has been extensively conducted in the laboratory. However, the ultimate goal of microbial enhanced oil recovery is field application, so the pilot simulation experiments are crucial. In this study, a micro-visualization model and the real cores were chosen to investigate the actual recovery efficiency and the mechanism of the consortium bacteria B-ALL, which has been proven to have good emulsification and degradation effects in lab studies in porous media. At the same time, the cast thin sections and rate-controlled porosimetry were combined to analyze the pore throat structure of the displacement core. It was found that the recovery efficiency was positively correlated with the microbial injection volume as well as the incubation time. For the microscopic model with high pores and high permeability, the efficiency of secondary water flooding can be increased by 44.77% after six days of incubation with two pore volume microbes. For the real tight cores, the maximum secondary water flooding efficiency under the same condition was 6.98%. Through visual modeling, microorganisms increase the oil washing efficiency mainly by emulsification and changing the wettability. The generated oil droplets will play a role in plugging and improving the wave efficiency. However, tight reservoirs have the characteristics of large pores and small throats, and curved and necking throats are developed, greatly reducing permeability. The microbial recovery efficiency was lower under shorter cultivation times. This study provides a practical basis for the application of consortium bacteria in tight oil fields to enhance recovery.

Model of shear strength of ultra-deep fractured sandstone considering fracture morphology

Ultra-Deep fractured tight sandstone gas reservoir, the hotpot unconventional petroleum resources, has been the subject of investigation recently. Due to the presence of natural fractures, drilling in ultra-deep fractured tight sandstone may cause complicated wellbore instabilities, which resulted in a substantial challenge to the efficient exploitation and production of tight gas resources. In order to understand the rock mechanical properties of the ultra-deep fractured tight sandstone under shear stress, tight sandstone core samples were artificially shear-fractured, the 3D characteristics of the fractures were reconstructed by CT scanning, and the fracture aperture and roughness characteristics were systematically evaluated. Simultaneously, triaxial shear strength tests were conducted to evaluate the mechanical properties of fractured rock subjected to varying confining pressures. Considering the contact relationship of the fracture surface during shearing, two indexes of average effective shear angle and contact area ratio were proposed to correct the fracture roughness, and a new fracture shear strength model was constructed, which served as the failure criterion for the fractured formation. The results show that the intact rock has a high compressive strength and can only collapse under conditions of substantial differential stress. Consequently, shear failure of fracture ought to be the primary source of wellbore instability. The fracture aperture's spatial distribution is irregular and conforms to a Gaussian distribution. A clear anisotropy in the fracture roughness is present, and there is less roughness along the initial shear failure path and more roughness perpendicularly. With an increase in normal stress, the fracture's peak shear strength rises, while the friction angle steadily falls. The innovative model's accuracy in predicting shear strength is higher than that of the weak-surface model and the JRC-JCS model.

Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates

Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10–20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4–5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8–10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery.

Study on effect of viscosity on thickness of boundary layer in tight reservoir

It has become a consensus that viscosity has an important impact on boundary layer of tight reservoirs. However, there are few quantitative studies on the effect of viscosity on boundary layer by core experiments. NMR analysis based on high-speed centrifugal gas-water and gas-oil displacement and low-temperature adsorption experiment were implemented in this study on typical tight reservoir parallel cores of Ordos and Bohai Bay basins. Total bound water/oil saturation, specific surface area and ratio of micro pore of the reservoir quantitatively were finally obtained, which were used for calculating irreducible water/oil film thickness of reservoir and analyzing influence of viscosity on movable oil and boundary layer. Research show that, movable oil saturation of core saturated high viscosity oil is 23.92% and 18.61% lower than that of core saturated low viscosity oil and water respectively, and effective seepage space is greatly reduced. The lower permeability reservoir has, the greater reduction movable space with high viscosity oil of reservoir owns. The average bound water film thickness of Ordos and Bohai Bay basin cores is 17.74 nm and 16.99 nm, respectively. The average bound oil film boundary of core in Ordos Basin is 20.72 nm. The average thickness of high viscous oil film of core in Bohai Bay basin is 38.10 nm, and the thickness of low viscosity oil film is 18.80 nm. The oil-water viscosity ratio in Ordos Basin is small, and oil-water film thickness is close, indicating that fluid viscosity has little influence on boundary layer thickness of target reservoir. The low viscosity oil-water viscosity ratio in Bohai Bay basin is small, and oil-water film thickness is close. The thickness of high viscosity oil film is more than twice that of low viscosity oil film and water film. When the oil viscosity is higher than 8.9 mPa s, thickness of boundary layer will be greatly affected, leading to a significant reduction of effective seepage throat, a significant increase of seepage resistance and development difficulty.

Experimental study of influence of CO2 treatment on fracture toughness of tight sandstone

A large amount of CO2 will be emitted after the burning of fossil fuels, causing global warming and glacier melting which will bring a huge threat to the living environment. Atmospheric clearance through the capture, utilization or storage of CO2 is one of the technologies for dealing with global climate change. In order clarify the mechanization of supercritical CO2 fracturing, the tight sandstone cores in the Jinqiu Gas field, Sichuan Basin were used to carry out the effect research of supercritical CO2 on fracture toughness. The results show that after the treatment of tight sandstone on supercritical CO2, the degradation degree of I-type fracture toughness decreases by 23.6%−33.6% when the soaking days reach 15 days. At the same reaction time, the fracture toughness under 20 MPa and 60 ℃ is lower by 3∼11% than that under 10 MPa and 50 ℃. Meanwhile, the geometric fracture trajectories of sandstone samples before and after the treatment of supercritical CO2 treatment are observed. Before the treatment, the Smax was 1.46 mm and the fracture angle was 10.24°, but after the treatment, the parameters were 0.93 mm and 3.41°, respectively. The fracture trajectories after multiple polishing were observed by SEM imaging, which shows that the fractures can propagate directly through the mineral particles after the supercritical CO2 treatment, which causes the transcrystalline fracture. It is conducive to initiating, propagating, and destroying I-type fractures under smaller external loads. The results further improve the mechanism of CO2 on fracture toughness of tight sandstone, which is useful to explore the feasibility of CO2 fracturing of low-pressure tight sandstone, and provide theoretical support for the safety of CO2 fracturing and CO2 geological sequestration of tight sandstone.

Quantitative evaluation of water-alternative-natural gas flooding in enhancing oil recovery of fractured tight cores by NMR

As the associated gas of tight reservoirs, natural gas is abundant and noncorrosive, which is more suitable for the development of tight oil reservoirs in China. However, the mechanism of gas injection development is unclear, and the gas channeling is serious in tight reservoirs after fracturing. The water-alternating-gas (WAG) flooding is an effective means to delay gas channeling and improve oil recovery. Therefore, it is significant to clarify the mechanism of preventing gas channeling and recovering oil by water-alternation-natural gas (WANG) flooding. The WANG flooding experiments with different water–gas slugs were conducted in non-fracture and fractured tight cores. Besides, the oil distribution of different pore spaces of cores before and after displacement and the main contribution spaces on oil recovery were quantitatively analyzed by using nuclear magnetic resonance and core mercury porosimetry techniques. The results indicate that compared with natural gas flooding, the WANG flooding can retard gas channeling, increase formation energy, and enhance oil recovery by up to 14.1%, especially in fractured cores. Under the resistance of water slugs, the gas was allowed to enter smaller pores and its swept volume was expanded. Oil is mainly stored in mesopores (0.1–1 μm) and small pores (0.01–0.1 μm), accounting for over 90% of the total volume. The oil recovered mainly comes from mesopores, which accounts for over 75% of the total amount. Moreover, the WANG flooding strengthens the recovery of oil in mesopores and macropores (1–10 μm), but it also squeezes oil into small pores and micropores (0.001–0.01 μm).

Experimental evaluation of the impact of induced fractures on cyclic solvent injection performance in low-permeability hydrocarbon reservoirs

Recovery factors associated with primary recovery (pressure depletion) schemes are often small (<5–10%) for low-permeability hydrocarbon reservoirs. As a result, cyclic solvent injection (CSI) schemes, using CO2 and produced gas, are currently being considered for enhanced hydrocarbon recovery (EOR). Fracture networks, generated during hydraulic fracturing stimulation, affect both primary and enhanced recovery by increasing the surface area contacted with the low-permeability reservoir matrix. However, experimental studies of the impact of induced (hydraulic) fractures on CSI performance are sparse, particularly those that provide a realistic representation of the fracturing process by inducing fractures under stress to better represent fracture conditions (e.g., fracture surface area, fracture surface roughness). Therefore, the primary objective of this work is to develop a laboratory-based workflow for evaluating the effectiveness of fracture system in tight oil reservoirs to enhance the oil recovery during a typical CSI cycle using a combination of core-scale techniques.An in-house core-flooding methodology, that combines ‘in situ’ fracturing and cyclic gas injection, was applied. The experimental procedure includes: 1) performing multiple cycles of lean gas (i.e., 80% C1 + 20% C2) injection into an oil-saturated ‘intact’ core plug until maximum oil recovery (5%) is reached, 2) artificially fracturing the core plug under stress, 3) repeating multiple cycles of lean gas injection into the artificially-fractured core plug, under similar experimental conditions as those used for the intact core, until maximum oil recovery (23%) is reached, and 4) measuring the fractured-core liquid permeability. A well-characterized tight siltstone core plug sample obtained from the Canadian Montney Formation was analyzed as an example. The experimental results indicate that 1) fracturing under stress results in an increase in surface area and permeability, and 2) the recovery factor is enhanced by ∼ 18% after fracturing (e.g., from ∼ 5% for intact core plug to ∼ 23% for artificially-fractured core plug).This study provides a proof-of-concept experimental approach for evaluating the impact of induced fractures on CSI recovery using an identical core plug sample (intact and fractured). The proposed experimental methodology could serve as a workflow for laboratory-scale evaluation of the impact of induced fractures on CSI performance in tight hydrocarbon reservoirs.

Mitochondria-targeted nanoparticles overcome chemoresistance via downregulating BACH1/CD47 axis in ovarian carcinoma

The platinum-based chemotherapy is a routine strategy for the treatment of ovarian cancer, while it is prone to chemoresistance in clinical, which hinders the treatment. Therefore, it is urgently needed to elucidate the underlying mechanism of drug resistance and form the appropriate strategy. The sequencing results showed that cisplatin (DDP) resistant ovarian cancer overexpressed BTB and CNC homology 1 (BACH1), and up-regulated the “don't eat me” signal CD47. We identified that hemin, a BACH1 inhibitor, could effectively down-regulate BACH1 and simultaneously inhibit CD47. Moreover, hemin has a synergistic effect with DDP. We designed a pH-responsive nanoparticle (H/D@FA–CaP–NPs) in which folic acid (FA) ensured targeting of ovarian cancer cells, while hemin inhibited BACH1 as well as down-regulated CD47, achieving the promotion of apoptosis of tumor cells and inducing phagocytosis of tumors by macrophages. Moreover, hemin has a synergistic effect with DDP to promote apoptosis of tumor cells. Structurally, hemin and DDP was encapsulated within hydrophobic 1,2-distearoyl-sn‑glycero-3-phospho-ethanolamine (DSPE) to form a tight core, and hydrophilic polyethylene glycol 2000 (PEG2000) and calcium phosphate (CaP) formed the outside shell, and FA was modified on the surface of nanoparticles. In terms of function, (a) FA enhanced the active targeting of nanoparticles to tumors; (b) NPs targeted mitochondria to induce reactive oxygen species (ROS) production; (c) hemin encapsulated in nanoparticles could specifically target BACH1, thereby down regulating CD47; (d) hemin had a synergistic effect with DDP, thus augmenting the chemotherapy. Altogether, mitochondria-targeted nanoparticles H/D@FA–CaP–NPs promoted tumor apoptosis and mobilized phagocytosis to treat tumor, providing a novel scheme for clinical treatment of cisplatin-resistant ovarian carcinoma.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

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.

Experimental investigation of gaseous solvent huff-n-puff in the Middle Bakken Formation

The efficacy of gaseous solvents in enhancing oil recovery (EOR) in unconventional reservoirs and the influence of operational and design parameters are still debated among the oil recovery research community. This work investigated the recovery-enhancing capabilities of two potent gaseous solvents, CO2 and ethane, in tight core samples. Laboratory huff-n-puff (H-n-P) experiments were conducted under three miscibility conditions to investigate the influence of the key operating parameters and the dependency of their impact on the miscibility conditions and gas composition. The results show that oil recovery increased with increasing pressure from below (BM) to above (AM) miscibility pressure in a non-linear trend, irrespective of the gas composition. Furthermore, the influence of the soak period was noticeably dependent on the miscibility condition, specifically more remarkable under AM conditions and less apparent under BM conditions. Likewise, the effect of the production period was more pronounced at AM conditions for both gases. Finally, the impact of rock surface area-to-volume (SA/V) was only observed at BM, where both gases recovered more oil in the core samples with high SA/V. In general, ethane showed a higher efficacy for oil recovery than CO2; CO2 recovered 21%–70% of oil in small core samples, while ethane could recover 32%–88%. The highest recovery was achieved with ethane injected under AM conditions, with a prolonged soak time, a short production period and into a core sample with a high SA/V. We believe the findings from this work will help better understand and design H-n-P EOR projects.

Enhanced recovery of tight reservoirs after fracturing by natural gas huff-n-puff: Underlying mechanisms and influential factors

Tight oil resources are abundant in the world. It is very important to strengthen the research on the development theory and technology of tight oil reservoirs for ensuring national energy security. Natural gas huff-n-puff can effectively improve the oil recovery of tight oil reservoirs. However, the pore-scale oil production characteristics and the mechanisms of natural gas huff-n-puff in matrix-fracture cores are poorly understood. The influence degree of important factors on oil recovery is not clear and the interactions between factors are rarely considered. In this paper, the oil production characteristics and mechanisms of natural gas huff-n-puff in tight cores with different fracture lengths were quantitatively analyzed by combining nuclear magnetic resonance (NMR) with numerical simulation technology. The influencing factors and their interactions were evaluated by the response surface method (RSM). The results show that tight cores mainly consist of medium pores (0.1–1 μm) and small pores (0.01–0.1 μm). The fracture mainly increases the proportion of macro-pores (1–10 μm) and medium pores. In the natural gas huff-n-puff process, crude oil from macro-pores (1–10 μm) and medium pores is mainly developed, and the contribution percentage of crude oil in medium pores to oil recovery is the largest, up to 98.28%. The position of gas–oil contact (GOC) moves deeper as the number of huff-n-puff cycles increases. The contents of CH4 and CO2 in the oil phase remain at a high level within the GOC, while between the GOC and the component sweep front, the contents of CH4 and CO2 in the oil phase decrease with the increase in dimensionless distance. The gas component sweep volume is increasing with the increase in fracture length. Moreover, the injected natural gas mainly extracts C3–C10 components from crude oil. The reduction law of crude oil viscosity is consistent with the migration laws of CH4 components along the path. Compared with soaking time and gas diffusion coefficient, the injection pressure is the most significant factor underlying the recovery of natural gas huff-n-puff in tight cores. Besides the influence of single-factor, the interaction effects of gas injection pressure and diffusion also should be considered to determine the huff-n-puff parameters in the field implementation of natural gas huff-n-puff in tight reservoirs after fracturing.

Tight hydrophobic core and flexible helices yield MscL with a high tension gating threshold and a membrane area mechanical strain buffer.

The mechanosensitive (MS) channel of large conductance, MscL, is the high-tension threshold osmolyte release valve that limits turgor pressure in bacterial cells in the event of drastic hypoosmotic shock. Despite MscL from Mycobacterium tuberculosis (TbMscL) being the first structurally characterized MS channel, its protective mechanism of activation at nearly-lytic tensions has not been fully understood. Here, we describe atomistic simulations of expansion and opening of wild-type (WT) TbMscL in comparison with five of its gain-of-function (GOF) mutants. We show that under far-field membrane tension applied to the edge of the periodic simulation cell, WT TbMscL expands into a funnel-like structure with trans-membrane helices bent by nearly 70°, but does not break its 'hydrophobic seal' within extended 20μs simulations. GOF mutants carrying hydrophilic substitutions in the hydrophobic gate of increasing severity (A20N, V21A, V21N, V21T and V21D) also quickly transition into funnel-shaped conformations but subsequently fully open within 1-8μs. This shows that solvation of the de-wetted (vapor-locked) constriction is the rate-limiting step in the gating of TbMscL preceded by area-buffering silent expansion. Pre-solvated gates in these GOF mutants reduce this transition barrier according to hydrophilicity and the most severe V21D eliminates it. We predict that the asymmetric shape-change of the periplasmic side of the channel during the silent expansion provides strain-buffering to the outer leaflet thus re-distributing the tension to the inner leaflet, where the gate resides.

A Novel Method for the Calculation of Oil–Water Relative Permeability for Tight Oil Reservoirs by Considering Nonlinear Seepage Characteristics

In view of the lack of clear physical significance of the parameters of the traditional nonlinear seepage models and the difficulty of obtaining accurate experimental measurements of the two-phase relative permeability curve, a nonlinear seepage model of a tight reservoir is established on the basis of fractal theory and boundary layer theory. The results show that the proposed model can comprehensively reflect the effects of reservoir matrix physical properties, reservoir fluid physical properties, wettability, and displacement-pressure gradient on the single-phase and two-phase nonlinear seepage characteristics of tight reservoirs. Furthermore, the introduction of the permeability loss factor makes the two-phase relative permeability model more representative of the morphological characteristics of the actual relative permeability curve and avoids the disadvantage that the relative permeability at the end point of the wetting phase has in the traditional model. Finally, by taking the tight core of Changqing Oilfield as an example, a sensitivity analysis of the proposed model is conducted, which proves the practical application of this model. The proposed model provides a convenient theoretical method for the accurate characterization of nonlinear seepage characteristics of tight reservoirs and is of great significance to the numerical simulation, productivity evaluation, and optimization of tight reservoirs.

Three-dimensional core reconstruction and performance evaluation of CO2 displacement in a tight oil reservoir

In this study, a three-dimensional tight sandstone core was reconstructed digitally using serials thin sections cut from a core sample used in laboratory carbon dioxide (CO2) flooding experiments. Based on the digital core, multiphase flow simulations were carried out to evaluate the performance of three prior laboratory-tested injection strategies: CO2 continuous injection, water alternative gas (WAG: CO2) injection, and cyclic CO2 injection. The chosen image-based reconstruction led to a close porosity and permeability match with the sampled core in an economical way. The numerical evaluation closely replicated the laboratory-tested procedures, thus providing realistic fluid distributions before CO2 injection. To determine saturation functions for CO2 injection after water flooding, sensitivities of endpoint relative permeability and capillary pressure to CO2 continuous injection were quantified. Water relative permeability was identified as a key factor. The saturation functions were used in a history match between simulations and laboratory data where close agreements were observed for all three CO2 injection strategies. Then critical enhanced oil recovery (EOR) operational parameters (soaking time, slug ratio, cycle size, and test duration) were optimized to maximize CO2 displacement performance, which led to the following observations: (1) While extended soaking after CO2 continuous injection increased incremental oil recovery, such increase was limited due to concurrent soaking during low-rate CO2 injection. (2) In WAG injection, CO2 and brine slug sizes and ratios were optimized: increasing the cycle size performed better than adjusting the slug ratio for favorable mobility control and efficient CO2 EOR. (3) For cyclic CO2 injection, the total CO2 injection volume was the most important factor, followed by the number of cycles, to allow CO2 diffusion into tight core to maximize the swept pore volumes. The history-matched simulations suggest that both WAG and cyclic CO2 injection can achieve high displacement effectiveness for the tight reservoir, compared with that achieved with slight soaking after CO2 continuous injection. The injected brine slugs in the WAG injection reduced the CO2 needed at the expense of reduced storage capacity. Compared to WAG, cyclic CO2 injection, though realizing the highest oil recovery and gas storage, requires more CO2.

Research on the seepage mechanism and influencing law of shale oil fracturing

In order to clarify the characteristics of oil and water seepage during shale oil fracture, the tight reservoir in Jimsar Basin, Xinjiang Province was an example to get the characteristics of two-phase seepage between fracturing fluid and shale oil during fracture through the core experiment during injection. Effects of initial water saturation, viscosity ratio of oil to water, injection pressure, core permeability about imbibition displacement efficiency of fracturing fluid were systematically studied by using an improved one-dimensional core displacement device from Xinjiang tight sandstone artificial core under indoor conditions. The research results show that under constant pressure of 1 MPa, initial water saturation of the core is 43%, permeability is 0.12 md, and oil-water viscosity ratio between shale oil and fracturing fluid is 3:1, drive efficiency about fracturing fluid was about 23.5%. At the same time, results indicated at certain injection conditions, when initial water saturation increases, the permeability gradually decreases, and the viscosity ratio of oil to water gradually increases, the lower drive efficiency of fracturing fluid was, the worse its effect is. This conclusion could be used in the process of shale oil tight reservoirs.

Physical Property Analysis and Sensitivity Damage Evaluation of Tight Sandstone Gas Reservoirs

Tight sandstone reservoirs are widely distributed in China, because tight reservoirs have the characteristics of low porosity and low permeability, high clay mineral content, etc., it is easy to cause reservoir damage during hydraulic fracturing and is not easy to recover. X-ray whole-rock diffraction analysis was carried out through tight sandstone reservoir core, and the proportion of sensitive minerals in tight sandstone gas reservoir was clarified, and water sensitivity and flow velocity sensitivity damage experiments were carried out based on the test results. The experimental results show that the flow velocity sensitivity damage rate of tight sandstone reservoir is 28.02%, and the critical flow rate is 0.75ml/min, which is a weak flow rate sensitivity injury. The water-sensitive injury rate was 63.98%, which was moderately strong water-sensitive injury.

Research on non-Newtonian characteristics of crude oil flow at micro-nano scale

The characteristic scale of flow in micro–nanochannels is generally in the range of 0.01 μm∼1 μm. When crude oil passes through micro-nano channels and tight reservoirs, it shows obvious nonlinear seepage characteristics, which does not conform to the continuity assumption of fluid. Therefore, a non-Newtonian model of crude oil flowing in micro-nano channels and tight reservoirs under the action of shear stress is established, and the relationship between flow rate and apparent viscosity and shear rate is analyzed. The experiment of crude oil flow in micro-nano channels and tight oil reservoir cores shows that the model can be used to describe the nonlinear seepage law of liquid through the nonlinear fitting. The power law index of the oil-phase power-law non-Newtonian fluid is greater than 1 at the micro-nano scale, which conforms to the flow characteristics of the expansive fluid, thus verifying the effectiveness of the non-Newtonian model. In addition, the study of apparent viscosity and shear rate of non-Newtonian fluid shows that the increasing and decreasing trends of flow rate and shear rate and the changing trends of flow rate and pressure gradient are consistent, and shear rate can be used to describe the characteristics of fluid instead of the pressure gradient.