Fractured Cores Research Articles

Performance of delaying release and reducing adsorption of polyethyleneimine/poly(vinyl sulfonate) polyelectrolyte complex nanoparticles in polyacrylamide/polyethyleneimine gel system

Polyacrylamide/Polyethyleneimine (HPAM/PEI) is an environmentally friendly and promising gel system. However, inadequate gelation time and retention of the cross-linker (polyethyleneimine, PEI) during migration pose significant challenges for effective water control treatment in deep reservoirs. Polyelectrolyte complex nanoparticles (PECs) have demonstrated the ability to efficiently encapsulate PEI, facilitating for its gradual release. To achieve this, a cost-effective polyanionic complex, poly(vinyl sulfonate) (PVS), was employed to form PECs with PEI. By adjusting the mixing ratio of PEI and PVS, stable PECs suspensions with varying charges were successfully produced. These stable PECs exhibited spherical shapes with a particle size distribution ranging from 127.3–442.71 nm, and an average particle size of approximately 200 nm. The encapsulation efficiency of PEI by PECs varied from 64.56 % to 86.14 %. Under different conditions, 55.12 % to 90.26 % of PEI could be released from PECs. Increased temperatures, higher ionic strengths, and greater deviations in pH from the initial state of the PECs suspension all facilitated the release of PEI. The most stable PECs delayed the gelation time of the HPAM/PEI system to 9.5 days, which is twice the base gelation time of 4.5 days. The strength of mature HPAM/PEI (PECs) gels increased by 8.95 Pa in storage modulus (G′) compared to HPAM/PEI at the same concentration, albeit with a reduced linear viscoelastic region. And, the PECs-based delayed crosslinking method does not negatively affect the mechanical strength of the HPAM/PEI gel system, and thus its water control ability, under reservoir conditions. On the other hand, the static adsorption of PEI encapsulated by anionic PECs on sand decreased to one-fourth of that of free PEI (PEI solution). Additionally, the breakthrough of PEI encapsulated in anionic PECs in fractured sandstone cores was significantly advanced compared to free PEI.

Application of CO2-Soluble Polymer-Based Blowing Agent to Improve Supercritical CO2 Replacement in Low-Permeability Fractured Reservoirs.

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO2 is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO2-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO2-soluble blowing agents CG-1 and CG-2, the effects of the CO2 phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO2-soluble blowing agent in a fractured core.

Experimental Study on Factors Affecting Oil Recovery in Sandstone-Buried Hill Superimposed Reservoirs.

Sandstone-buried hill superimposed reservoirs, characterized by the coexistence of the sandstone matrix and the fracture pore matrix, present unique challenges in integrated development due to their connectivity and physical properties. Currently, research on the factors affecting the recovery of sandstone-buried hill superimposed reservoirs with both porous and fractured media is limited. In this study, a more realistic method for preparing fractured cores and calculating fracture permeability was proposed, and the effect of confining pressure on fracture permeability was investigated. Additionally, a three-tube experimental apparatus was designed to study the effects of connectivity, different permeability contrasts between sandstone and buried hills, and various development strategies on recovery. The results indicate that fracture permeability is significantly affected by the confining pressure. When sandstone and buried hills are not connected, the total recovery is the highest. As connectivity increases, the recovery from sandstone gradually decreases, while the recovery from the buried hill gradually increases, leading to a decrease in the overall recovery. The permeability contrast between sandstone and buried hill has a minimal impact on the overall recovery; however, a higher permeability contrast leads to increased sandstone recovery and decreased buried hill recovery. The highest overall recovery was achieved with injection solely into the sandstone, followed by general injection, with the lowest recovery from injection solely into the buried hill. This study provides new insights into the integrated development of sandstone-buried hill reservoirs.

Experimental and numerical simulation study on enhanced oil recovery by N2-Assisted water huff-n-puff in a tight oil reservoir

The water huff-n-puff (WHP) method is widely used for improving oil recovery in tight reservoirs. However, the poor flow conductivity and low sweep efficiency of the matrix restrict the oil recovery performance of this method. Herein, N2-assisted water huff-n-puff (NAWHP) was proposed to improve oil recovery under reservoir conditions. First, the feasibility of NAWHP for tight reservoirs was investigated by comparing the enhanced oil recovery (EOR) performance with that of WHP and N2 huff-n-puff (NHP). The core flooding experimental results revealed that NAWHP facilitated oil recovery improvement, outperforming the existing practice of water or N2 huff-n-puff injection. Thereafter, with the aid of nuclear magnetic resonance (NMR) technology, the application of NAWHP could significantly enhance oil recovery in fractured tight cores, which mainly increased oil recovery from micro- and nanopores in the matrix. Specifically, for submicron pores and micropores, after three cycles of NAWHP, the recovery efficiency increased by 21.35% and 36.19%, respectively, while the recovery only increased by 14.34% and 24.8%, respectively, during WHP. For nanopores and micro/nanopores, the use of WHP increased the total oil recovery by only 4.71%, while the use of NAWHP increased the total oil recovery threefold. Finally, a series of numerical simulations were conducted to explore the effects of different parameters on oil recovery by NAWHP. The results illustrated that a high N2–water ratio (NWR) positively affected the overall oil recovery, but the higher the NWR was, the more difficult to extract the oil below the injection layer. By injecting 13,000 m3 of N2, the maximum swept volume was achieved for the matrix, and water filled the major fractures after injecting 11,000 m3, effectively accomplishing this task. Increasing the soaking time positively influenced oil recovery, N2 diffusion within the matrix led to an even distribution over 50 days, and water imbibition caused a significant increase in the oil saturation in hydraulic fractures within 30 days. The application of NAWHP increased the number of huff-n-puff cycles of water from a maximum of 3–5.

Influence of Shale Mineral Composition and Proppant Filling Patterns on Stress Sensitivity in Shale Reservoirs

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m2 is 3.61 times that of cores with a proppant concentration of 0.3 kg/m2. Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages.

Experimental investigation of CO2 foam flooding-enhanced oil recovery in fractured low-permeability reservoirs: Core-scale to pore-scale

Fractured low-permeability reservoirs are characterized by poor reservoir physical properties, strong interlayer heterogeneity and the existence of natural and artificial fractures, resulting in significant water or gas channeling during flooding development. CO2 foam can effectively control the mobility of CO2 and ensure a more stable flooding front. In this study, taking into account the imbibition effect of the flooding process, the flooding performance under different injection methods and the influencing factors of foam pre-injection volume, back pressure and fracture complexity on CO2 foam flooding were systematically analyzed using fractured low-permeability core flooding experiments. In addition, the mechanism of CO2 foam flooding enhanced oil recovery (EOR) in low-permeability fractured reservoirs was obtained in combination with microscopic flooding experiments. The results show that the maximum recovery of 59.36 % can be obtained by soaking the core samples for 12 h with pre-injection of 0.4 PV CO2 foam followed by CO2 foam flooding, which adequately considers the imbibition effect during the flooding process. The pressure difference and oil recovery increases with increasing foam pre-injection amount, and the oil recovery with back pressure (2 MPa and 4 MPa) is significantly higher than that without back pressure; however, a further increase in back pressure has less impact on the recovery. The oil recovery rate of the fracture-free core is lower than that of the multiple fracture core during CO2 foam flooding but higher than that of the single fracture core, and the fracture complexity of the fractured cores has less impact on the final oil recovery. Microscopic experiments show that CO2 foam can effectively prevent channeling and improve the sweep efficiency. Soaking during the CO2 foam flooding process makes foam enter the matrix through the fracture, and CO2 dissolves after the foam breaks to increase the mobility of the crude oil, while the surfactant solution emulsifies the crude oil and changes the rock wettability. The unbroken foam can increase the sweep range, and the crude oil that flows into the fracture is carried by the subsequent injected foam to be recovered as foamy oil.

The characteristics and effects of Huff-n-Puff in shale with brine, aqueous surfactant solutions and CO2

In this study, we evaluated the permeability damage and throughput potential of shale cores, focusing particularly on the damage water inflicts on shale permeability and the potential for hydrocarbon extraction using various injection media. Nuclear magnetic resonance (NMR) was utilized to analyze the distribution of crude oil across different pore sizes and to determine the limits of their utilization under varied media injection cycles. The results indicate that the Shengli Oilfield FY shale possesses abundant inorganic pores, primarily composed of intergranular and intragranular pores. Organic matter is dispersed and contains numerous micro-fractures. While formation water has only a minor impact on the permeability of fractured cores, it significantly impairs matrix permeability. Moreover, when the formation water content exceeds 10%, the degree of damage will decrease. In contrast to formation water, distilled water causes serious damage to both matrix and fractured cores. Therefore, anti-swelling measures are essential to ensure effective development in subsequent stages. After five injection cycles, the final recovery rates for brine, surfactant, and CO2 injection are 11.5%, 29.3%, and 45.9%, respectively. CO2 injection demonstrates the best production enhancement, followed by surfactant injection. CO2 is particularly effective in each cycle, primarily due to its expansion and extraction mechanism. Surfactants enhance production mainly by reducing interfacial tension and altering wettability, resulting in significant improvement in the first cycle. Meanwhile, brine injection primarily augments production through improved wettability and capillary pressure, resulting in a moderate production improvement. Based on NMR experiments, the minimum pore size for CO2 injection is estimated to be around 10–15 nm, Surfactant injection necessitates pore sizes with a minimum of 30–40 nm and brine injection requires pore sizes of approximately 60–70 nm. This research provides valuable experimental data for on-site shale oil development and deepens our understanding of the mechanisms involved in hydrocarbon recovery from shale using different injection media.

Permeability reduction techniques: Plain and fiber HPAM gels in fractured cores

The aim of this study is to investigate how fibers influence the ability of polymer gels to resist washing out from fractures. For this purpose, synthetic and mineral wool fibers were integrated into polymer gels. These fiber-gels were compared to plain gels using bottle tests, viscosity measurements, and fractured core flooding experiments.The bottle tests show no effect of 13-mm-long synthetic fibers on gel strength. However, inside a constricted fracture, the polymer-synthetic fiber gel exhibited 8.4 times higher resistance to the flow of brine compared to the plain gel. This is explained by the retention of the fibers at the constriction point. In low salinity brine, mineral wool fibers allowed a substantial improvement in gel strength, while, at the same time, a reduction in the concentration of chemicals by 40% was made possible.Furthermore, with the addition of 0.6 wt.% mineral wool fibers, the viscosity of the 0.3 wt.% polymer gel increased from 560.5 to 106,920 cp. In fact, in a 1-mm-wide fracture, a gel containing 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber achieved a post-flush pressure gradient that was 58 times higher than a 0.75 wt.% plain polymer gel. Unfortunately, the choice of a makeup brine with an increased salinity resulted in the deterioration of fiber-gel strength. Nonetheless, a substantial improvement of gel strength can be achieved by adding 0.6 wt.% mineral wool fibers, even if the salinity is as high as 143 g/L. Moreover, in experiments in which the permeability of the adjacent matrix was very low, 0.018 mD, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber prepared in 242.6 g/L brine, was still superior to a 0.75 wt.% plain gel prepared in low salinity brine.Experimentation with large fracture widths of 2.55 mm and 4 mm was also done to confirm gel effectiveness. For example, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber, prepared in 14 g/L brine, provided a 1.46 times higher post-flush pressure gradient in a 2.55-mm-wide fracture, as compared to that of a 0.75 wt.% plain polymer low salinity gel in a 1-mm-wide fracture. With an increase in the salinity, to 234.6 g/L, of the makeup brine used with a fiber-gel, the resistance to the flow of brine in a 2.55-mm-wide fracture became comparable to that of a plain gel in a 1-mm-wide fracture. In a 4-mm-wide fracture, a gel with 0.3 wt.% polymer prepared in 234.6 g/L brine and one of 0.5 wt.% polymer prepared in 14 g/L brine, each with 0.6 wt.% mineral wool fiber, provided maximal post-flush pressure gradients equal to 12–14 psi/ft. This is the same range usually expected from a 0.5 wt.% relatively low molecular weight plain polymer gel in a 1-mm-wide fracture.Although, fibers improved the ability of gels to resist washing out from fractures, in a 4-mm-wide fracture such a fiber-gel could not provide notable resistance to the flow of brine with an increase in the superficial flow velocity higher than 1,000 ft/d. Discovering formulas that would increase the resistance of gels to being washed out of wide fractures must continue.

Quantitative assessments on fluid flow through fractures embedded in permeable host rocks: Experiments and simulations

An accurate understanding on hydraulic behaviors of fluid flow through fractured rocks is of central importance for both underground resources exploitation and CO2 geological sequestration. Despite its importance, fluid flow through fractures surrounded by permeable matrix is rarely investigated. Here, this study aims to explore fluid flow through fractures surrounded by permeable host rocks using a combined experimental and numerical approach. In particular, core-flooding experiments were sequentially conducted on both intact and fractured cores subjected to different rock types, under varying confining stress and fracture roughness. According to the experimental results, fracture permeability decreases rapidly with increasing confining stress and fracture roughness, while matrix permeability is less affected by confining pressure, resulting in an increment in contributions of matrix flow to the overall flow with increased confining pressure. In addition, numerical simulations were performed on digital fractured rocks with a broadened range of roughness from 2.58 to 18.2, and under confining pressure ranging from 2 MPa to 53 MPa. The fluid flows within matrix and fracture were assumed to follow linear Darcy's law and nonlinear Forchheimer's law, respectively. The simulated results also show that Km/Kf increases with the increase of confining pressure, reflecting the enhancement in contributions of matrix permeability to the overall transportation. If Km/Kf = 0.1 is defined as a threshold over which matrix permeability should not be ignored, then the critical confining pressure of 18 MPa, 20 MPa, and 46 MPa is determined for mudstone, sandstone and limestone, respectively. In addition, the fluid flow through rough-walled fractures is observed to be susceptible to normal loading and fracture roughness, which directly alters flow paths within the fractures. With an increment in confining pressure and fracture roughness, the contact area between rough fracture surfaces grows, promoting flow tortuosity and generating eddies inside fracture, which consequently increases flow resistance and hence weakens fracture permeability. Ultimately, by fitting the simulated data, an empirical equation linking fracture permeability with confining stress, fracture roughness and hydraulic gradient is provided. This study provides quantitative characterizations on fluid flow through fractures accounting for permeable matrix, and thus can potentially improve the accuracy in predicting hydraulic properties of fractured rocks.

Synthesis and performance evaluation of multi-crosslinked preformed particle gels with ultra-high strength and high-temperature and high-salinity resistance for conformance control

Preformed particle gels (PPGs) have been identified as an effective method to control conformance and mitigate excessive water production. However, the weak strength of swollen PPGs makes them susceptible to shear failure during formation migration in harsh reservoir conditions. To address this issue, a novel type of multi-crosslinked preformed particle gels (MC-PPGs) with ultra-high strength, exceptional temperature and salinity resistance has been developed. Vinyl silica nanoparticles (VSNPs) were first prepared and used as nano crosslinking agents and enhancing agents in constructing multiple cross-linking structures with macromolecules, functional monomers, and crosslinking agents. MC-PPGs have an elastic modulus up to 110,000 Pa, which is significantly higher than other existing PPGs. Additionally, when exposed to high-salinity environments (e.g., 20 % NaCl and 10 % CaCl2 + 10 % MgCl2), MC-PPGs remain for an extended period at elevated temperatures (80 °C for 24 months, 120 °C for 13 months, and over one month at 160 °C). Furthermore, the degradation products of MC-PPGs have minimal impact to reservoir permeability, with a core damage rate below 5 %. MC-PPGs are pH-adaptable (1 < pH < 12), which makes them a promising candidate for reservoirs with supercritical CO2 flooding. Laboratory coreflooding tests have demonstrated that MC-PPGs provide excellent plugging efficiency (>99.9 %) for fractured cores and ultra-high breakthrough pressure gradients (>14 MPa/m) at varying test temperatures (20 °C, 80 °C, and 120 °C). Considering these unique features, MC-PPGs are ideally suited for oilfield applications.

Experimental and EOR Mechanism Study of Water Shutoff Effects on Fractured Tight Sand Gas Reservoirs Using Fuzzy Ball Fluids

In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water shutoff process for sustainable development. In order to solve this dispute, the Linxing He-2 reservoir matrix core and a core with artificial fractures were used to simulate interlayer water, artificial fractures, and water output channels from the side and bottom. Simulated formation water and nitrogen were used as the two-phase flow phase. The breakthrough pressure of the air and water phases was tested after plugging with fuzzy ball fluid in order to simulate and analyze the water shutoff effect of the fuzzy ball fluid and its ability to achieve air establishment and water control. The results of this study show that for the core matrix, the breakthrough pressure gradient for water and gas varied from 0.200 MPa/cm to 0.210 MPa/cm and 0.015 MPa/cm to 0.025 MPa/cm, and for artificial fractured cores, the breakthrough pressure gradient of water and gas varied from 0.035 MPa/cm to 0.040 MPa/cm and 0.015 MPa/cm to 0.020 MPa/cm. These results prove that fuzzy ball fluid can block small-scale water output channels, such as matrix pores, through the polymer film-forming structure, and plug the artistic cracks and large-scale water output channels of the water flowing into the sides and bottom through the accumulation of a large number of fuzzy balls, which greatly improves the flow resistance of water. The amount of fuzzy ball fluid should be carefully adjusted with consideration of the water output and formation conditions. For large-scale water output channels and side and bottom water shutoff operations, it is recommended that the amount of fuzzy balls be increased along with the number of fuzzy balls in the system in order to increase the breakthrough pressure of water and achieve the stable control of air and water. It is believed that the fuzzy balls would quickly change their shapes to match the sizes of fracture channels to enter into fractured reservoirs and that an active hydrophobic membrane would form on the surface of fractured rocks, with macromolecules and surfactants being dispersed in the fluid system. In addition, the interface between the fuzzy balls is also hydrophobic, which would slow down the flow of water and provide a continuous gas percolating channel after aggregating and entering into the fractures. This increases the persistence of water intruding into the formation and does not affect the percolation of the gas of fractured tight sandstone gas reservoirs. This research is of great significance for the EOR of tight sand gas reservoirs and the sustainable development of oil and gas resources in China.

Experimental study on CO2 flooding characteristics in low-permeability fractured reservoirs

ABSTRACT CO2 flooding in oil reservoir is a complex process, which includes fluid flow in fractured sandstone and interaction of CO2 and displaced oil. In order to thoroughly understand the CO2 flooding characteristics in low-permeability fractured reservoirs, a series of CO2 flooding experiments were conducted based on the multi-field coupling experimental system. Considering the difference of the fractured cores, pore cores and pore-fracture model, the effect of fracture, injection pressure, CO2 phase, and heterogeneity of horizontal composite on the CO2 flooding were analyzed. The results show that the oil recovery of fractured core was 46.96%, 7.13% higher than that of pore core, and there was no relatively stable gas-oil ratio (GOR) stage. For the pore-fracture model, the final recovery of two models increased from 49.45% to 45.86% at 2 MPa to 78.83% and 77.35% at 8 MPa, and the pore core was the main contributor to enhance oil recovery. The supercritical CO2 (sc-CO2) enhanced the oil recovery in post-gas breakthrough state, which accounted for final recovery 65.02%. Compared with the vertical layered heterogeneity, the horizontal composite heterogeneity had less influence on the final oil recovery, with differences of below 2%, and the highest CO2 utilization rate was occurred at the permeability model of Low-High-Low. The work provides insight on oil recovery improvement of CO2 flooding in low-permeability fractured reservoirs.

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).

NMR and CT characterizing the influence of O2 in air injection performance in shale oil cores

BackgroundThe primary objective of this paper is to evaluate the performance of extracting shale oil resources by air injection experiments. In this paper, the shale cores were acquired from Xinjiang Permian Lucaogou formation, with an average porosity of 14% and an average permeability of 0.3mD. 2) Method: The remaining oil distribution and mobilization of oil saturation was characterized by online NMR spectra and X-ray CT scanner. Nitrogen, 8% oxygen of air and 16% oxygen of air injection were evaluated for their enhanced shale oil recovery performance. 3) Significant findings: With the increase of oxygen concentration in the air, a higher oil recovery factor was yielded. Under different O2 concentration, oil recovery factor by nitrogen drive is 45.31%, and the highest (16% oxygen) is 69.81%. Most of hydrocarbons were produced from the 1～5 μ m pore size. Approximately 50% of oil was recovered by the first 0.6 PV of air injection. Oil recovery efficiency is remarkably declined for successive 0.6 PV of air injection. From the CT images of air injection into the fractured shale cores, air injection has the potential to recover incremental oil in the presence of fractures.

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.

The Development and Deployment of Degradable Temporary Plugging Material for Ultra-Deepwater Wells

The fractured granite reservoir is well developed in Yongle block, which leads to severe drilling fluid loss-circulation. To solve the technical problem of both plugging and reservoir protection, on the basis of comprehensive literature research and laboratory tests at home and abroad, a polymer with an appropriate molecular weight, an organic crosslinking agent and other auxiliary materials were screened. In addition, a kind of high-temperature resistant loss-circulation plugging gel, which could be formed by timing and self-degradation, was developed. The high-strength gel loss-circulation system can be established by the development of a dynamic covalent borate ester bond crosslinking agent, which can crosslink with polyvinyl alcohol and xanthan gum. This system is of formidable strength and can be used for loss-circulation control in a fractured formation. The dynamic covalent borate ester bond tends to break due to the peroxide glue breaker under low pH levels, which can accelerate the degradation of the plugging gel into small molecules. The degradable temporary plugging material can ensure high-performance sealing and self-degradation capabilities of the fractured granite reservoir. The laboratory results showed that the high-performance degradable gel system was of adjustable gelling time, high gelling strength and high sealing capability. Its pressure-bearing could reach 5.8 MPa under 110 °C with 3.5 mm width of fractured granite core. Before crosslinking, the system also boasted promising thixotropy and rheology. The gel breaking time of the system was short, which could be completely broken with 6.1 h in 6% peroxide solution with pH of 4. The gelation time was related to the type of crosslinking agent, the amount of crosslinking agent and temperature. With the increase of temperature, the gelation time of gel system decreased. With the increase of the amount of the agent, the gelation time of gel system decreased. The gelation time was 105 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 72 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 71 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 65 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 72 min when using a 1% chromium crosslinking agent at 80 °C; the gelation time was 63 min when using a 2% chromium crosslinking agent at 80 °C; and the gel system had good reservoir protection performance. The permeability recovery rate was introduced to evaluate reservoir protection performance. The permeability recovery rate of using the dynamic covalent borate ester bond crosslinking agent was superior to that of using the chromium crosslinking agent. Using the dynamic covalent borate ester bond crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 90.32%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 84.53%. Using the chromium crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 59.58%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 45.65%. The viscosity of the residual solution was low and was helpful for reservoir protection during loss-circulation control under the fractured granite reservoir condition. The novel degradable temporary plugging material can solve the loss-circulation problem of the ultra-deepwater fractured granite reservoir. In addition, the material can pave the way for the exploration and development of a vast amount of hydrocarbon resources in the South China Sea.

Study on migration and plugging performance of polymer gel in fractured cores using nuclear magnetic resonance technology

In situ cross-linked polymer gels (ISCPGs) are widely used for conformance control and enhanced oil recovery (EOR) in heterogeneous petroleum reservoirs. However, the mechanisms behind their migration and plugging in fractured cores remain unclear. In this study, changes in the injection pressure difference before and after the treatment of HPAM/phenolic resin gel was monitored by core displacement experiment. The gel was injected with two different gelation states, i.e., gelant and pre-crosslinked gel. Meanwhile, we analyzed the nuclear magnetic resonance (NMR) T2 signal and imaging of the cores that were treated with the polymer gel system during various injection stages. Results indicated that NMR technology can effectively analyze the migration and plugging performance of polymer gels in fractured cores at a microscopic level, both before and after gelation. The gelant effectively plugged the fracture when the injection rate was low, but a great amount of the gelant entered the matrix and damaged the matrix. In contrast, it formed a plugging layer at the inlet face and also caused damage at high injection rates. For conformance treatment of pre-crosslinked gels, the gel did not easily enter the matrix. When the injection rate of pre-crosslinked gels increased, its plugging efficiency for the fractured cores enhanced. Therefore, engineers should optimize gel state, injection rate, and injection pressure according to the specific reservoir conditions before oilfield operations. This study can help researchers understand the microscopic migration and plugging mechanism of polymer gels in cores at the microscopic level. It will also help researchers to pay more attention to the NMR technique to further understand its application in petroleum reservoir conformance improvement.

Microscopic Production Characteristics of Pore Crude Oil and Influencing Factors during Enhanced Oil Recovery by Air Injection in Shale Oil Reservoirs.

High-pressure air injection (HPAI) is one of the effective methods to improve shale oil recovery after the primary depletion process. However, the seepage mechanisms and microscopic production characteristics between air and crude oil are complicated in porous media during the air flooding process. In this paper, an online nuclear magnetic resonance (NMR) dynamic physical simulation method for enhanced oil recovery (EOR) by air injection in shale oil was established by combining high-temperature and high-pressure physical simulation systems with NMR. The microscopic production characteristics of air flooding were investigated by quantifying fluid saturation, recovery, and residual oil distribution in different sizes of pores, and the air displacement mechanism of shale oil was discussed. On this basis, the effects of air oxygen concentration, permeability, injection pressure, and fracture on recovery were studied, and the migration mode of crude oil in fractures was explored. The results show that the shale oil is mainly found in <0.1 μm (small pores), followed by 0.1-1 μm (medium pores), and 1-10 μm (macropores); thus, it is critical to enhancing oil recovery in pores less than 0.1 and 0.1-1 μm. The low-temperature oxidation (LTO) reaction can occur by injecting air into depleted shale reservoirs, which has a certain effect on oil expansion, viscosity reduction, and thermal mixing phases, thereby greatly improving shale oil recovery. There is a positive relationship between air oxygen concentration and oil recovery; the recoveries of small pores and macropores can increase by 3.53 and 4.28%, respectively, and they contribute 45.87-53.68% of the produced oil. High permeability means good pore-throat connectivity and greater oil recovery, and the production degree of crude oil in three types of pores can be increased by 10.36-24.69%. Appropriate injection pressure is beneficial to increasing the oil-gas contact time and delaying gas breakthrough, but high injection pressure will result in early gas channeling, which causes the crude oil in small pores to be difficult to produce. Notably, the matrix can supply oil to fractures due to the mass exchange between matrix fractures and the increase of the oil drainage area, and the recoveries of medium pores and macropores in fractured cores increased by 9.01 and 18.39%, respectively; fractures can act as bridges for matrix crude oil migration, which means that proper fracturing before gas injection can make the EOR better. This study provides a new idea and a theoretical basis for improving shale oil recovery and clarifies the microscopic production characteristics of shale reservoirs.

High stability polymer gel for lost circulation control when drilling in fractured oil and gas formations

When drilling in fractured oil and gas formations, drilling fluid loss is prevalent, and polymer gels are commonly utilized as lost circulation materials to plug fractures in loss zones. A high stability polymer gel was synthesized in this study employing acrylamide as the polymerizable monomer, a self-synthesized microsphere containing active ethylene groups as the cross-linker, laponite as both a flow pattern regulator and a physical filler, and ammonium persulfate as the initiator. This polymer gel's complex network structure considerably adds to its mechanical and thermal resilience, and its best gelation time is 12 h at 248°. Rheological properties of the gel were studied under various conditions. When the experimental temperature is 284°, the Na+ concentration is 100,000 ppm, or the Ca2+ concentration is 1000 ppm, the G′ and G″ of the polymer gel exceeded 1000 Pa and 200 Pa, suggesting that this gel has good thermal and salt stability. Contamination resistance studies reveal that the polymer gel has adequate contamination resistance for drilling fluid and formation water penetration, with G′ and G″ exceeding 1500 Pa and 400 Pa when the volume ratio of external fluids to gellant is 6:4. Furthermore, the density of the polymer gel may be adjusted to 2.0 g/cm3 by employing barite as a weighting agent, and the addition of the barite contributed to improving the structural stability of the gel due to the filling effect in the gel's network structure. Using fractured steel cores and a visible fracture model, the dynamic filling and plugging capabilities of this polymer gel in fractures were measured. When compared to frequently used polymer gellants, the high stability polymer gellant entirely fills the fracture area and exhibits a little gravity differentiation effect in large-scale fracture. After gel formation, it exhibits outstanding plugging capability for various fracture scales at 248°. Three successful field tests in the Tarim Basin, Xinjiang, China, demonstrated that the high stability polymer gel may be used to control lost circulation in fractured formations at high temperatures.

In-situ flow visualization with Geo-Positron-Emission-Tomography in a granite fracture from Soultz-sous-Forêts, France

We investigate the fluid flow field in a fractured granite core sample. Sequential imaging with Positron-Emission-Tomography (PET) allows direct reconstruction of flow streamlines, thus providing a unique insight into the fluid dynamics of complex fractured crystalline materials. Pulse migration experiments using the positron-emitting radionuclide 18F− as tracer were conducted on a fractured granitic drill core, originating from a depth of 1958 m of the Enhanced Geothermal System (EGS) reference site at Soultz-sous-Forêts, France. The flow field was analyzed as a function of in- and outlet positions across the fracture, as well as applied flow rates. Different flow path characteristics were identified. Both the fracture aperture variation and the topography of the fracture surface affect the flow field with consequences on flow channeling and preferential flow paths. Furthermore, pulse migration experiments were also numerically simulated with a 2.5D model using COMSOL Multiphysics®.While the higher flow rate experiments show wider and higher dispersion of the flow path, lower velocity results in more localized flow and channeling behavior. This type of study thus yields enhanced experimental insights into the hydrodynamics of fracture flow and its relation to the rough structure of a single fracture, compared to input-output experiments. It can help to validate model simulations and experimentally determine hydrodynamic parameters needed for reactive transport modeling that are otherwise estimated with a high degree of uncertainty.