Oil Recovery In Tight Reservoirs Research Articles

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.

Self-growing biomimetic functional hydrogel particles for conformance control in tight reservoir fracture network

Hydraulic fracturing is gradually becoming a common approach for enhancing the oil production from tight reservoirs. Blocking agents such as soft particle systems are necessary as a means of conformance control to mitigate the side effect of reservoir heterogeneity due to hydraulic fracturing. In this work, a novel technique based on the mussel biomimetic concept is proposed to generate self-growing biomimetic functional hydrogel particles (SG-BFHPs). The fracture conformance control capacity of the products is evaluated, and the results show that multi-scale (0.5–3.0 mm) SG-BFHPs can cohere and grow at the reservoir condition, and the median agglomerated particle size can increase by 20–25 times. High flow resistance (Frr = 10.7–11.8), facilitated by the higher adhesion between the biomimetic particles and the pore walls, can be established by SG-BFHPs while maintaining a good injectivity. In the single-fracture model, the increased oil recovery by SG-BFHPs is about 12.2 %, and in the matrix-fracture model can be increased from 9.2 %–13.5 % to 25.8 %–28.8 %. AFM experiments show that SG-BFHPs has stronger adhesion between particles or rock surface than conventional hydrogel particles. After conformance control of SG-BFHPs, the particles are distributed in an irregular structure in the fractures and adsorbed on the fracture wall under the effect of inter-particle cohesion and adhesion, which can realize fracture channel adjustment by the particle self-growing. The SG-BFHPs studied in this paper provides valuable insights for the development of dispersed particle gel, which is of great significance in improving oil recovery in tight reservoirs.

Experimental investigation of CO2 huff-n-puff in tight oil reservoirs: Effects of the fracture on the dynamic transport characteristics based on the nuclear magnetic resonance and fractal theory

CO2 huff-n-puff is a promising method for enhancing oil recovery in tight reservoirs while simultaneously contributing to CO2 geological storage. However, the performance of this method is significantly affected by fractures resulting from hydraulic fracturing and natural fractures. The impact of fracture on oil transport behavior in different pores remains unclear and warrants further investigation. In this study, CO2 huff-n-puff experiments were conducted under induced fracture conditions. A new method for quantifying the relationship between transverse relaxation time T2 and pore radius was proposed by fitting the slopes of the T2 spectrum and the pore size distribution (PSD) curve derived from Micro X-ray computed tomography (Micro-CT). The impact of the fracture on the effective utilization limit was explored, and the fractal dimensions of different cycles were evaluated during CO2 huff-n-puff. The results showed that the oil recoveries of the fracture-free and the fractured samples were 19.97% and 31.16%, corresponding to the effective utilization limits of 1.52 μm and 0.96 μm, respectively. Moreover, based on the fractal characteristics of the whole process of CO2 huff-n-puff, the pore system was divided into micropores (<0.20 μm), small pores (0.20–0.63 μm), intermediate pores (0.63–2.00 μm), and large pores (>2.00 μm). Furthermore, the incremental recovery for each cycle mainly comes from large pores and gradually decreases as the fractal dimension is less than 2.85. The fracture has a significant impact on the migration characteristics of crude oil. The incremental oil in the intermediate pores of the fractured sample, caused by negative convection, was 2.88 times greater than that of the fracture-free sample. Finally, it was found that the gravity effect was more prominent, significantly affecting the remaining oil distributions in fractured reservoirs.

Laboratory Evaluation of Electrically Enhanced Oil Recovery in Tight Reservoirs

Laboratory Evaluation of Electrically Enhanced Oil Recovery in Tight Reservoirs

Study on Surfactants for Replenish Energy before Fracturing in Tight Reservoir

Tight reservoir in the periphery of Daqing oilfield is abundant. However, due to tight lithology, poor physical properties, and insufficient formation energy, water injection is not effective, development effect is not ideal, and utilization degree is low. Therefore, it is proposed to implement energy replenishment before fracturing, integral fracturing, and energy storage after fracturing. In the energy replenishment stage, surfactants with good compatibility with the formation and strong oil washing ability are selected as injection medium to play the dual role of energy replenishment and oil washing, and improve the recovery rate of tight sandstone reservoirs. Surfactants are evaluated by established method; LH anionic surfactant and KR anionic non-ionic surfactant are preferred. Under alkali free condition, interfacial tension of two surfactants maintain at order of 10-3. Recovery degree of surfactants in natural cores reach more than 15%. Field application conducted in 30 wells in Block P, including 27 vertical wells and 3 horizontal wells. Oil is seen in vertical wells at 7.8% flow back rate. The average daily liquid production of the 20 wells that have been pumped is 7.5 tons per day, with a daily oil production of 1.3 tons, and a cumulative oil increase of 223.8 tons per well. The average daily oil increase of a single well in the three months after fracturing a qualified oil well is 5.2 tons, 1.6 times and 2.2 times that of dessert fracturing and overall fracturing in the same period. The average daily liquid production of 3 horizontal wells is 24.2 tons, and the daily oil production is 9.6 tons. The test results show that the overall design of the fracturing energy supplement scheme is reasonable, and the selected surfactant can supplement the formation energy while improving the oil washing efficiency, which will provide technical support for exploring new ways to improve oil recovery in tight reservoirs.

Dynamic contact angle effect on water-oil imbibition in tight oil reservoirs

Imbibition is one of the best methods for developing tight oil reservoirs. However, the dynamic contact angle (DCA) on imbibition is still unclear and limits the enhanced oil recovery of tight reservoirs. Here, the DCA effect is successfully coupled with two-phase seepage formulas, and a model of the DCA effect on imbibition for tight reservoirs is proposed. The results showed that: the influence of DCA on imbibition recovery with time has four stages (first increasing, then decreasing, then stabilizing, and finally decreasing). The DCA effect reduces the imbibition velocity of the first stage, but increases the imbibition velocity of the second stage. The AFO, TEC, TEO, and OEO boundaries have the same recovery enhancement rate of −27.7% at 26 s. The DCA effect on imbibition is proportional to the friction of a contact line, viscosities and interfacial tension, and wettabilities, while it is inversely proportional to an imbibition area. With a decreasing permeability or pore radius from 200.0 to 28.3 nm, the DCA effect on recovery first decreases from 44% to 38% and then increases to 41%. This work revealed the DCA effect on imbibition and provided insight into the enhanced recovery of tight reservoirs by imbibition.

Spontaneous Imbibition and Core Flooding Experiments of Enhanced Oil Recovery in Tight Reservoirs with Surfactants

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study.

A novel method for evaluation of the spontaneous imbibition process in tight reservoir rocks: Mathematical model and experimental verification

Spontaneous imbibition driven by capillary forces is essential for the development of oil and gas resources because it can significantly influence the oil recovery of tight reservoirs. But limited by traditional experimental methods, the existing mathematical models lack applicability to complex tight reservoir rocks. Therefore, to better predict water imbibition in tight reservoirs, this paper proposes a new spontaneous imbibition model based on modifications of the classical Handy model. Two important parameters, the average capillary pressure, and the imbibition permeability are derived using a nuclear magnetic resonance spectroscopy method to quantify the macroscopic driving force and percolation ability of the complex pore network. Furthermore, combined experiments of co-current spontaneous imbibition experiments and transverse relaxation time analysis on four shale core plug samples are conducted to verify the new model. Results show the imbibition process can be modeled successfully before the imbibition volume reaches 85% of the maximum imbibition volume, and two continuous stages: the early/free imbibition stage and the later/limited imbibition stage, are then subdivided according to the applicability of our model. Considering the heterogeneity of the pore network in shale samples, it can be inferred that an uneven imbibition front occurred during the imbibition process. In all, this model enriches the classical imbibition theory and provides a new approach to analyzing the imbibition of fracturing fluids in complex tight reservoirs.

Similarity-based laboratory study of CO2 huff-n-puff in tight conglomerate cores

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO2 huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO2 huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO2 injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO2 and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO2 injection volume and soaking time. The lower oil recoveries under excess CO2 injection and soaking time were attributed to limited CO2 dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO2 huff-n-puff in tight reservoirs with high formation pressure.

Experimental Investigation on the Imbibition Behavior of Nanofluids in the Tight Oil and Gas Reservoir through the Application of Nuclear Magnetic Resonance Method

Tight oil and gas resources are widely distributed and play an important role in the petroleum industry. Due to its nanoscale pore-throat characteristics, the capillary effect is remarkable, and spontaneous imbibition is very beneficial to the development of low-permeability reservoirs. In this study, the imbibition experiments of 2D nano blackcard, nanoemulsion, and water were carried out, respectively. The pore-throat fluid distribution characteristics before and after core imbibition were analyzed with nuclear magnetic resonance technology, and the enhanced oil recovery effects of 2D nano blackcard nanoemulsion, and water were comprehensively evaluated. The results show that the final recovery factors of cores soaked in 2D nano blackcard (0.005 ωt%) and nanoemulsion (0.02 ωt%) or imbibed in water are 32.29%, 26.05%, and 7.19%, respectively. It can be found that 2D nano blackcard is the fluid with the best imbibition effect. In this work, a new type of 2D nano blackcard was proposed and identified as a functional imbibition fluid for enhanced oil recovery in tight reservoirs, providing a practical reference for the effective development of tight, low-permeability oil and gas reservoirs.

Oil drop stretch and rupture behavior at throat and pore junction during imbibition with active nanofluid: A microfluidic approach

Imbibition is an effective method to recover oil from small pore and throat. Here we report the formation of oil drop at pore and throat junction during spontaneous imbibition with active nanofluid. A T-channel microfluidic model combined with high-speed camera was used to observe the stretch and rupture process of oil discharged from throat to pore. When oil drop was discharged from throat gradually, its width/length was kept deceasing before rupturing. With more active content in the aqueous phase, the interfacial tension decreased from 33.8 to 8.7 mN/m, and the oil recovery increased by 12.4% by spontaneous imbibition. The oil drop rupture frequency increased by 3.0 times, but the length and width of the oil drop decreased by 32.2% and 28.0%, respectively. The reduced size of the oil drop would benefit the oil transportation in porous media. Higher flow rate in pores and throat would all intensify rupturing of the oil drop. Moreover, small throat could further reinforce the rupturing process. From combination of fluid flow rate, interfacial tension, and viscosity, higher capillary number reduced the maximum dimensionless width and length of the oil drop by 44.3% and 42.7%, respectively. The reduced size of oil drops ruptured at pore and throat junction contributes to the transportation of oil in porous media. Overall, this study provides a basic theory for active nanofluid to enhance imbibition oil recovery in tight reservoirs.

NMR characterization of fluid mobility in low-permeability conglomerates: An experimental investigation of spontaneous imbibition and flooding

Understanding fluid mobility during spontaneous imbibition (SI) and flooding is important for the enhancement of oil recovery. Many researches on SI, water flooding (WF), and N2 flooding (NF) have been published, but an in-depth understanding of the oil mobility at the pore scale is still inadequate in low-permeability reservoirs. To solve this problem, SI, WF, and NF experiments were performed on the low-permeability conglomerates of the Baikouquan Formation and the Urho Formation in the Mahu Sag. Moreover, online NMR was introduced to monitor the oil volume in pores with different sizes in real-time. Considering the wettability, mineral compositions, and pore structure, we established a schematic diagram to reveal the fluid mobility mechanism. The results show that the micropores in the low-permeability conglomerates are more hydrophilic, whereas the other pores are more lipophilic. During SI, the movable oil is mainly distributed in the micropores in the form of clay-bound oil (CBO), which is discharged from the rock through the meso/macropores. High hydrophilicity contributes to a high imbibition rate and oil recovery from SI, while the pore structure only affects the imbibition rate. During WF, the movable oil is contributed by CBO in the micropores and free oil (FO) in the pores controlled by throats >0.3 μm. During NF, the movable oil is mainly distributed in the pores controlled by > 0.1 μm throats, existing as FO and part capillary-bound oil (CAO). The results demonstrate that NF is effective to enhance the oil recovery of tight reservoirs, while WF is only effective for tight reservoirs with better pore structure (high Vr > 0.3 μm).

Three-dimensional physical simulation of water huff-n-puff in a tight oil reservoir with stimulated reservoir volume

Water huff-n-puff has been considered as a cost-effective method to enhance oil recovery in tight reservoirs. However, the physical simulation method for water huff-n-puff is still lacking up to now, so that the production behaviors of actual tight reservoirs cannot be reproduced and the EOR potentials cannot be evaluated directly by scaled models in the laboratory. In this study, mathematical models for water huff-n-puff processes in tight oil reservoirs with stimulated reservoir volume (SRV) were established, then the corresponding scaling criteria were proposed and verified. Taking the tight reservoir ZMY in the Ordos Basin as a prototype, three groups of three-dimensional physical simulations of water huff-n-puff under different conditions (PSM-1, PSM-2 and PSM-3) were designed based on the scaled parameters respectively, then performed favorably and compared comprehensively. The experimental results show that oil recovery of PSM-1 can be increased by 20.16% within 8 cycles, which shows great EOR potentials for the tight reservoir ZMY. Compared with PSM-1, oil recovery of PSM-2 reduces by 8.23%, which indicates that forced imbibition is quite a helpful and promoting mechanism, and oil recovery enhancement will be greatly limited if no imbibition effect is given play between the matrix and fractures. Comparatively, oil recovery reduces by 3.39% for PSM-3, which can be inferred that if fracture density relatively increases and all fractures are well connected, the matrix imbibition effect can be further strengthened, the high pressure can propagate faster, the elastic energy can supplement into the matrix deeper, and the effect of gravitational differentiation can be better utilized as well. It is found that cumulative oil production of the three physical simulations in the first several cycles is always relatively high, which implies that sufficient oil supply in physical models can be maintained. As oil-water interface rises, less oil and more water will be produced and different dynamic characteristics of cumulative oil and water production are shown. It is also found that all three groups of water cut curves have the same upward trend and the Sigmoidal-Logistic model can be employed to accurately depict the dynamic characteristics of water cut at different cycles. This study aims to establish a physical simulation method for water huff-n-puff in tight oil reservoirs with SRV based on the three-dimensional scaled model, which will be greatly helpful to understand the EOR mechanisms and production characteristics of water huff-n-puff. • Scaling criteria of water huff-n-puff in tight oil reservoirs with SRV were proposed and verified. • Three-dimensional physical simulation method for water huff-n-puff was established. • Oil recovery of physical simulation model can be increased by 20.16% within 8 cycles for a case study. • Forced imbibition and large-scale fracture network can greatly enhance oil recovery during water huff-n-puff. • The Sigmoidal-Logistic model can depict the dynamic characteristics of water cut at different cycles.

Experimental study of oil recovery from pore of different sizes in tight sandstone reservoirs during CO2 flooding

The investigation of tight oil reservoirs has become a significant area of interest in unconventional oil development. CO 2 flooding is considered an effective oil recovery method for tight oil reservoirs as it can significantly increase oil recovery when it reaches supercritical condition and becomes miscible with oil. Although extensive research has been conducted on CO 2 flooding, the oil recovery from pore of different sizes in tight sandstone reservoirs at different pressures has not been thoroughly investigated. In this study, we analyzed the petrology features and the pore structure of a reservoir using casting section and scanning electron microscope (SEM) images. Subsequently, three cores with different permeability from the reservoir were subjected to CO 2 flooding experiments at different pressures. A nuclear magnetic resonance (NMR) spectrometer was used to quantify the oil recovery. Amott-Harvey index was measured to study the effect of CO 2 flooding on core wettability. Results indicate that the total oil recovery and the oil recovery of smaller pores increase as the pressure increasing. The oil recovery of the larger pores does not increase continuously. The oil recovery of the smaller pores is more dependent on pressure than that of the larger pores, and the total oil recovery is related to the oil recovery of smaller pores. Meanwhile, the supercritical and miscible CO 2 has a positive effect on oil recovery. After CO 2 becoming supercritical and miscible, the cores still have potential to produce more oil with the pressure increasing. As the pore structure is playing a significant role in oil recovery, the core with a higher proportion of the volume of larger pores is relatively easy to produce more oil at low pressure. Amott-Harvey index shows CO 2 flooding can significantly reduce the hydrophilicity of cores. This study reveals the mechanism of pressure effect on oil recovery during CO 2 flooding in tight sandstone reservoirs. The results can be used to improve the efficiency of reservoir development. • The features and the pore structure of a tight sandstone reservoir were analyzed using casting section and SEM images. • NMR was used to quantify the oil distribution before and after CO 2 flooding to explain the oil recovery of tight reservoirs. • The oil recovery of tight oil reservoir is strongly related to pore structure as well as CO 2 injection pressure. • CO 2 flooding can significantly reduce the hydrophilicity of cores with the increase of pressure.

On the application of surfactant and water alternating gas (SAG/WAG) injection to improve oil recovery in tight reservoirs

Tight reservoirs are considered one of the unconventional hydrocarbon reservoirs with low permeability and porosity, directly affecting the oil production rate rather than conventional reservoirs. Thereby, optimum enhanced oil recovery methods would help petroleum industries produce more oil volumes from these reservoirs. In this study, different chemical and thermal enhanced oil recoveries methods such as surfactant alternating gas (SAG), water alternating gas (WAG), surfactant and foam flooding, and carbon dioxide (continuous and cyclic) were experimentally investigated to measure oil recovery factor. According to the results of this study, 3.5% of surfactant concentration, 0.15 PV of surfactant slug size, and 0.75 PV was selected as the total surfactant injection volume was selected as the optimum concentration for the injectivity performances. SAG scenario provided the highest oil recovery factor among all injectivity scenarios. It is about 54% that indicated the best efficiency of enhanced oil recovery methods in tight reservoirs rather than conventional recovery methods. The second highest oil recovery factor is dedicated to the WAG injectivity scenario regarding the feasibility of CO2 phase through porous media. It is about 46%. Moreover, due to the -gas phase in WAG and SAG, water cut had fluctuated as the water and gas had been alternatively injected into the core samples.

Novel Method for Studying, the, Imbibition Production Mechanism Using NMR

Tight volcanic reservoirs, characterized by strong heterogeneity and a well-developed fracture network, are usually difficult to develop. The development of effective ways to enhance production in such reservoirs is an important task in research work for oil and gas field development. The method of enhancing production by imbibition is a promising technology for oil recovery in tight reservoirs. In this paper, based on the production data of horizontal wells in tight volcanic reservoirs, we have studied the imbibition mechanism during fracturing fluid flowback. Nuclear magnetic resonance (NMR) technology was used for analysis. First, the wire-cutting technique was used to simulate fractures generated by hydraulic fracturing in the core. Then the core was filled with quartz sand. Then the migration of fluid between small pores and macropores during the imbibition process was studied by low-field NMR analysis. The research results show that the imbibition displacement of fracturing fluid under high pressure can effectively increase the recovery rate, while the soaking time can affect the imbibition exchange of fluid between crack and matrix. Due to the small pore radius and high capillary resistance of the volcanic rock, the imbibition stability time is longer. The pore size distribution of volcanic rock was analyzed quantitatively by NMR and mercury intrusion porosimetry. The results show that the dynamic imbibition process occurs mainly in pores less than 2 im.

Experimental Investigation of the Pressure Decay Characteristics of Oil Reservoirs after Fracturing Operations.

Field experience shows that extending shut-in periods are conducive to increasing tight oil production after fracturing operations. Understanding the regularity of pressure decay is helpful to establish an appropriate shut-in time. However, the characteristics and influencing factors of pressure decay are unclear. This paper studies the porosity, permeability, mineral composition, and pore structure of samples in six different blocks. The pressure decay regularity is tested according to an independently designed indoor shut-in experimental device, and the oil distribution of experimental samples is monitored using nuclear magnetic resonance technology. The results show that the fracturing fluid enters the matrix pores under the action of percolation to slowly drive out the oil, causing the well pressure to decay over time. There are three types of pressure decay characteristics: concave type, fluctuation type, and quadratic type. Compared with conventional sandstone, the pressure decay rate of tight reservoirs is slower, and the pressure decay characteristics are more complicated. Clay mineral-rich reservoirs will swell when exposed to water. As a result, the strength of the framework will be weakened and collapsed. What’s more, it will cause blockage of the throat, blocking the flow of oil and the decay of pressure. In addition, the rate of pressure decay is also related to the volume of fracturing fluid, initial borehole pressure, and formation closure stress. At a certain proppant thickness (fracture width), the larger the fracturing fluid volume, the larger the fracture surface area and the faster the pressure decay rate; Moreover, the greater the initial shut-in pressure, the greater the pressure difference and the faster the decay rate; the formation closure stress causes the core porosity and the permeability to decrease, resulting in a decrease in the decay rate. The experimental results are of great significance for establishing a proper shut-in time and enhancing the oil recovery of tight reservoirs.

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

The preparation and spontaneous imbibition of carbon-based nanofluid for enhanced oil recovery in tight reservoirs

In this work, carbon-based nanofluid was prepared composed of hydrophilic carbon nanoparticles (CNPs) and Tween-80 to enhance oil recovery through spontaneous imbibition in tight reservoirs. The CNPs were characterized by transmission electron microscopy (TEM), dynamic light scattering (DLS), 1HNMR, interfacial tension and wettability measurements. The particle size of CNPs was <10 nm and CNPs nanofluid showed excellent stability at high temperature and high salinity. CNPs nanofluid exhibited a stronger ability to reduce interfacial tension and change wettability than brine. The 1HNMR imaging showed that CNPs had seeped into the core. The spontaneous imbibition tests showed that the spontaneous imbibition oil recovery of CNPs nanofluid can reach 24%, compared with 11% oil recovery of NaCl solution. CNPs nanofluid can efficiently enhance oil recovery, which was ralated to capillary force and structural disjoining pressure. CNPs nanofluid has great potential for enhancing oil recovery, especially in tight reservoirs.

Mechanistic study of cyclic water injection to enhance oil recovery in tight reservoirs with fracture deformation hysteresis

As an effective enhanced oil recovery (EOR) technique in tight reservoirs, cyclic water injection has been extensively studied recently. However, very few studies have considered the impacts of loading-path dependent fracture deformation, i.e. deformation hysteresis. In this study, an efficient coupled two-phase flow and geomechanics model is developed to simulate cyclic water injection in a tight oil reservoir with the consideration of fracture deformation hysteresis. The embedded discrete fracture model (EDFM) is applied to handle complex fracture geometries. Different loading-path dependent constitutive models are used to describe the deformations of hydraulic fractures and natural fractures, respectively. Then simulation studies are performed to demonstrate the impacts of deformation hysteresis of hydraulic fractures and natural fractures on EOR performance. The sensitivities to injection rate, depletion pressure and soaking time are examined. The results show that the deformation hysteresis of hydraulic fracture has significant effect on oil production, while that of natural fracture has negligible impact. The effects of fracture deformation hysteresis are more pronounced under high injection rate and depletion pressure, but less sensitive to soaking time.