Fractures In Tight Oil Reservoirs Research Articles

Research and Application of Temporary Blocking and Diversion Techniques for Fractures in Tight Oil Reservoirs

Research and Application of Temporary Blocking and Diversion Techniques for Fractures in Tight Oil Reservoirs

Numerical simulation study on propagation mechanism of fractures in tight oil vertical wells with multi-stage temporary plugging at the fracture mouth

The multi-stage temporary plugging and diverting fracturing technique stands as a pivotal method for enhancing production in tight oil reservoirs. At present, fracture propagation models in temporary plugging and diverting fracturing primarily focus on single-stage temporary plugging, disregarding intricate mechanisms influenced by multi-stage temporary plugging and inter-fracture interference on the redirection and propagation of artificial fractures. To address this gap, this study employs the extended finite element method and establishes a mechanical model for the propagation of multi-stage temporary plugging fractures in tight oil reservoirs based on the maximum circumferential stress criterion. Relevant numerical simulations are conducted, considering key factors such as horizontal stress differences, fracturing fluid viscosity, injection rate, and initial fracture angle, all of which influence the morphology of diversion fracture propagation. The study rigorously analyzes and compares characteristics such as the radius of diversion fractures, diversion angle, and fracture width profile corresponding to different numbers of temporary plugging stages. Numerical simulations reveal that the primary controlling factor influencing the extension of fractures is the horizontal stress difference. A smaller horizontal stress difference makes fracture diversion easier, resulting in larger redirection radii. The impact of fracturing fluid viscosity on the diversion radius and diversion angle of fractures can be deemed negligible. Larger injection rates during construction facilitate easier diversion, leading to larger diversion radii. Furthermore, when the initial fracture angle exceeds 90°, the diversion radius of fractures is significantly larger compared to cases where the initial fracture angle is less than 90°, indicating a more facile diversion of fractures.

A semi-analytical model for fractured horizontal wells production considering imbibition during shut-in periods

After hydraulic fracturing in tight oil reservoirs, part of the fracturing fluid is retained in the formation. Therefore, it’s essential to investigate the pressure and saturation distributions during and after fracturing to further understand the impact of fluid loss on productivity. Concerning the capillary pressure, fracture propagation, and fracture volume changes, a semi-analytical model was established innovatively. Comparisons between the model’s calculations and actual measurements demonstrate a high level of agreement, validating the model’s accuracy. Furthermore, the impacts of capillary pressure, shut-in time, injection rate, initial reservoir pressure, and initial water saturation on actual production performance were investigated. The results show that the effect of capillary pressure on production in the tight reservoir cannot be ignored. A reasonable shut-in operation should be carried out according to the actual situation. A smaller injection rate should be selected to achieve a larger fracture length and imbibition area. The proportion of oil produced by capillary pressure decreases with the increase of initial pressure. The initial water saturation is positively correlated with oil production and negatively correlated with water production. The imbibition effect of shut-in operation is more obvious in tight reservoirs with low initial pressure and low water saturation.

Numerical Simulation of Fracture Propagation during Temporary Plugging Staged Fracturing in Tight-Oil Horizontal Wells.

Fracture propagation with temporary plugging hydraulic fracturing in tight-oil reservoirs is simulated in this study. The research considers dynamic fluid redistribution, with stress differences among multiple fractures. The fracture morphology during temporary plugging staged fracturing (TPSF) is investigated by using a user-defined perforation element combined with a pore-pressure finite-element model. The precision of the integrated model is verified by using the standard finite-element approach. Then, case studies are presented to investigate the influence of cluster spacing, horizontal stress difference coefficients (SDC), injection rates, and barrier tensile strengths. The simulation results show that central cluster fractures are hampered by side-cluster fractures, while TPSF can alleviate the effect and lead to a more uniform propagation of all fractures. Stress interference weakens as cluster spacing increases, and propagation patterns are minimally influenced once spacing reaches 40 m. Higher injection rates can improve the injection pressure, enlarging fracture width, and potentially increasing the risk of fracture penetration. Barrier tensile strength and horizontal SDC can modify fracture geometries and determine the penetration behavior of multiple fractures.

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance.

Experimental and numerical simulation research on counter-current imbibition distance in tight oil reservoirs

Counter-current imbibition behavior is an important mechanism for exploiting oil recovery during shut-in periods after hydraulic fracturing in tight oil reservoirs. However, most researches mainly focused on imbibition recovery and its influencing factors in tight oil reservoirs, while experimental investigations to quantitatively characterize the imbibition distance is still inadequate. In this work, counter-current imbibition experiments under one end open (OEO) boundary condition were conducted, and the dynamic imbibition process in porous media were monitored in real-time by nuclear magnetic resonance (NMR) pulse sequences and NMR imaging to quantify the range of counter-current imbibition and the reduction of oil saturation in-situ. In addition, a one-dimensional (1D) imbibition numerical model with OEO boundary condition at core scale was developed, and the influencing factors on oil production was further discussed in detail. The experimental results illustrated that the overall oil recoveries of nanofluid and deionized (DI) water were 25.37 % and 5.19 %, respectively. Moreover, the advancing distance of nanofluid was 4.44 cm, while DI water advanced only 2.38 cm along the core sample. Nanofluid considerably reduced residual oil saturation and increased movable fluid saturation, making the crude oil to be highly mobilized in micro- and mesopores. The simulated results well verified the counter-current imbibition experimental data, and indicated that the influences of core permeability and fluid viscosity on imbibition performances were more significant than that of core length. The purpose of this work is to provide a new method to determine the extent of counter-current imbibition.

A comprehensive mathematical model for spontaneous imbibition in oil-saturated fractured tight sandstones: Incorporating fracture distribution, displacement pressure, gravity, and buoyancy effects

This paper presents a generalized mathematical model that comprehensively characterizes the flow behavior of matrix nanopores and natural/hydraulic fractures in tight oil reservoirs during spontaneous imbibition. The model incorporates various influencing factors such as fracture distribution, displacement pressure gradient, gravity, and buoyancy. The complex pore structure of tight oil reservoirs, including nanopores and natural microfractures, presents a challenge in developing an accurate mathematical model for predicting flow behavior. The proposed model considers the fractal characteristics of pores and fractures and accounts for many factors to predict cumulative oil production, oil flow rate, and oil recovery factor during imbibition flow. Experimental data on fractured tight sandstones are used to validate the model, and sensitivity analyses are conducted to assess the influence of pore structure parameters, fracture distribution, and fluid properties on imbibition behavior. The findings reveal that gravity and buoyancy effects become more prominent under low interfacial tension. Fracture distribution significantly impacts imbibition behavior, with critical values for fractal dimensions, fracture numbers, and apertures determining the extent of their influence. Higher contact angles and increased oil phase viscosity result in reduced imbibition efficiency. In pressure-driven displacement processes, larger fractures preferentially produce crude oil, and the higher pressure gradients result in shorter imbibition processes. The proposed model offers insights into the imbibition oil recovery mechanism in tight oil reservoirs and can contribute to improved recovery factors.

Study on the Optimal Volume Fracturing Design for Horizontal Wells in Tight Oil Reservoirs

The application of horizontal well volume fracturing technology is an important method for enhancing oil recovery in tight oil reservoirs. However, the influence mechanism of the fracture placement scheme (FPC) on postfracturing productivity is still unclear. Based on the theory of the black oil model, combined with the reservoir stimulation characteristics of horizontal well volume fracturing in tight oil reservoirs, this paper established a postfracturing reservoir production simulation model. History fitting was used to verify the accuracy of the production model simulations. A series of numerical simulations was carried out to study the influence mechanisms of the fracture parameters and FPC on productivity. The simulation results show that compared with the fracture conductivity, the fracture length and number are the main parameters affecting tight oil reservoir productivity. Selecting a reasonable fracture length and number can realize the economical and efficient production of tight oil reservoir volume fracturing. Compared with the traditional fracture equal-length scheme, an FPC with an uneven fracture length can increase the cumulative oil production of oil wells. Under the condition of the same total fracture length, the scheme with a staggered distribution of long fractures and short fractures has the largest cumulative oil production over five years. A reasonable well spacing can greatly reduce the impact of interwell interference on postfracturing dual branch horizontal well productivity. When dual branch horizontal well fractures are alternately distributed, the postfracturing productivity is higher. The production simulation model established in this paper provides a method to accurately evaluate the productivity of horizontal wells after volume fracturing, which can provide guidance for the optimization of hydraulic fracturing operation parameters.

Experimental and numerical study on influencing factors of replacement capacity and slickwater flowback efficiency using pre-CO2 fracturing in tight oil reservoirs

CO2 as pre-fracturing fluid technology, with dual advantages of CO2 fracturing and water fracturing, has broad application prospects in the development of unconventional oil and gas, and it is also one of the important ways of carbon utilization and carbon storage. In this paper, an accurate experiment was designed first time to explore the replacement capacity of CO2 under different discharge pressure gradients using cores with different sizes. The fracturing fluid flowback law and enhance oil recovery ability were also studied by the self-designed experiment. Before the test, the core was split axially from the center and the core fracture was filled with mixed 40–70 mesh quartz sand and AB glue to simulate the actual formation fracture. Then a dual-permeability compositional model was established to explore the field scale fracturing fluid flowback. The performances of slickwater fracturing and pre-CO2 fracturing were compared. The effects of flowback pressure gradient, CO2 injection volume, and soaking time on the flowback efficiency and oil recovery were also analyzed. The results show that the efficiency of CO2 replacement of oil increases with the increase of flowback pressure difference and is 15% higher than that of slickwater. CO2 pre-fracturing can significantly improve the flowback efficiency of slickwater and enhance oil recovery. As the pressure gradient increases, the flowback efficiency of slickwater increases, which shows that the flowback pressure gradient needs to be higher than 10 MPa to achieve economic output. With the proportion of CO2 injection increased from 20% to 58%, the CO2 flowback efficiency increased from 37.5% to 44.1%, and the oil recovery factor increased from 11.2% to 14.7%. With the increase of soaking time, slickwater imbibed into matrix pore throat according to the capillary force, meanwhile, CO2 diffused into deep formation. The degree of slickwater and CO2 backflow decreased accordingly. Considering the pressure change, stimulation effect and flowback efficiency during the soaking period, the optimal soaking time is 6 h in experiment and 15 d in field production. This study is expected to provide theoretical guidance for CO2 pre-fracturing in tight oil reservoirs.

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Investigation on Invasion Depth of Fracturing Fluid During Horizontal Fracturing in Tight Oil Reservoirs with Experiments and Mathematical Models

Investigation on Invasion Depth of Fracturing Fluid During Horizontal Fracturing in Tight Oil Reservoirs with Experiments and Mathematical Models

Identification of fractures in tight-oil reservoirs: a case study of the Da'anzhai member in the central Sichuan Basin, SW China

The Da'anzhai Member of the Jurassic Ziliujing formation in central Sichuan is a typical tight-oil reservoir with porosity and permeability less than 2% and 0.1 × 10–3 μm2, respectively. Fractures in this formation are well developed in micro- and nano-scale. However, the factors that control the fracture distribution are unclear. Additionally, the uncomprehensive and ineffective identification and evaluation of fractures in the early stage of tight-oil development makes it difficult to meet the requirements of tight-oil development. In our work, we used cores, thin sections, and a scanning electron microscope (SEM) to study the influence of the microscopic rock composition, including the shelly grains, calcite grains, and clastic grains, on the fracture development. We found that the microscopic composition of shelly grains and calcite grains separately control the development of inter-shelly fractures and shelly fractures, and intergranular fractures, and tectonic fractures. Except for a small number of dissolution fractures found in mudstone, the fractures are not well developed in the formations with clastic grains. According to the characteristics of the development degree of fracture and the resolution of the well-logs, the fractures are divided into large scale, small scale, and micro-scale. By a newly established level-by-level constraints method, we systematically identified the scale, occurrence, filling characteristics, and development degree of fractures in the Da'anzhai member by well-logs. Moreover, a quantitative model is also proposed for identifying the angles and development degree of fractures. The results show that the scale of fractures can be effectively identified by the shapes and values of resistivity logs; the occurrence, development, and filling characteristics of fractures can be semi-quantitatively evaluated by the relative amplitude difference between the matrix resistivity (Rb) and formation resistivity (RT). The results are consistent with the interpretation results by formation micro-resistivity imaging (FMI) log, which further demonstrates that the level-by-level constraint method by conventional well-logs can be used to systematically and effectively predict the fracture characteristics in tight-oil reservoirs.

Mechanism of Permeability and Oil Recovery during Fracturing in Tight Oil Reservoirs

In this study, the effect of fracturing fluid on the permeability of tight oil reservoirs is analyzed through oil absorption. The mechanism of permeation and absorption in tight oil reservoirs was studied using the molecular dynamics simulation of fluid flow through fractures in porous media containing crude oil. The influence of surfactants on the adsorption characteristics of crude oil formations on rock walls was also examined. The research results show that the introduction of the appropriate surfactant to the fracturing fluid could accelerate the rate of percolation and recovery as well as improve the recovery rate of absorption. The optimal concentration of polyoxyethylene octyl phenol ether-10 (OP-10) surfactant in the fracturing fluid was 0.9%. When the percolation reached a certain stage, the capillary forces in the crude oil and percolation medium in the pore stabilized; accordingly, the crude oil from the pore roar should be discharged at the earliest. The fluid flow through the fracture effectively carries the oil seeping out near the fractured wall to avoid the stability of the seepage and absorption systems. The surfactant can change the rock absorbability for crude oil, the result of which is that the percolating liquid can adsorb on the rock wall, thus improving the discharge of crude oil. The results of this study are anticipated to significantly contribute to the advancement of oil and gas recovery from tight oil reservoirs.

Formation Applicability Analysis of Stimulated Reservoir Volume Fracturing and Case Analysis

Stimulated Reservoir Volume (SRV) fracturing is a key technology of unconventional oil and gas exploration and development. To gain a deeper understanding of tight sandstone reservoirs and draw on the development experience of hydraulic fracturing, the authors conduct a large number of detailed investigations of geological characteristics in the regions that have implemented SRV fracturing. Based on the data of rock mechanics parameters, in-situ stress characteristics, brittleness characteristics and natural fractures, the influencing factors of SRV fracturing in tight oil reservoirs were analyzed. The results show that the SRV fracturing is suitable for geological reservoirs with the characteristics of medium to high elastic modulus, low to medium Poisson’s ratio, low stress difference, medium to high brittleness and naturally fractured reservoirs, where natural fractures have a significant impact. Region A, a tight sandstone region, has moderate elastic modulus, low Poisson’s ratio, low ground stress difference and medium brittleness, and has the feasibility of volume fracturing. The field case of the Y325 well shows that SRV fracturing technology has obvious effect on increasing production. This technology is applicable to the Region A.

Effects of diagenesis on natural fractures in tight oil reservoirs: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, NW China

Compared with conventional reservoirs, tight reservoirs experience more intense diagenesis; thus, their properties are extremely poor. Nevertheless, natural fractures with high‐strength can appear in these reservoirs and could play an essential role in the accumulation and production of tight oil. In this study, we focused on the effects of different diagenetic processes in the formation and transformation of natural fractures to determine the effects of natural fractures on tight reservoirs. Various observation techniques and analysis methods were applied (i.e., observations of cores, cast thin sections, scanning electron microscopy; field emission scanning electron microscopy; and X‐ray diffraction analysis). We clarified characteristics of the fractures and distribution patterns based on core descriptions and microscopic observations and explained the diagenetic stage and evolution sequence of reservoirs. Past studies regarding carbon and oxygen isotope analysis and basin simulation were considered. This study also reviewed the fracture formation time, source of fracture fillings, and oil charging time. We obtained insight into the coupling relationship of fracture states, diagenetic sequences, hydrocarbon charging, and, in particular, the controlling effect of diagenesis on natural fractures. The results revealed that formation, preservation, and destruction of natural fractures in tight reservoirs were closely related to diagenesis. Compaction and cementation in the reservoirs decreased the porosity and altered the petrophysical properties of the reservoir. They also provided favorable conditions for the development of tectonic fractures, while dissolution did not. The influences of dissolution and cementation on natural fractures depended on the duration for which these processes were active. Compaction and cementation formed related types of diagenetic fractures, while dissolution increased the effectiveness of natural fractures. The purpose of this study was to evaluate the influence of diagenesis on the formation, controlling effects, and effectiveness of natural fractures, as well as the effects of natural fractures on tight reservoirs through geological history. This study is expected to provide guidance for future exploration and development of tight oil and gas with similar geological origins.

Pore structure alteration induced by CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs

CO2 energetic fracturing is an important technique for developing tight oil resources by creating complex fractures and enhancing formation pressure. The physical properties of host rocks may be changed by CO2–brine–rock interaction in the soaking stage of CO2 energetic fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic fracturing are still unclear. To address this problem, this work conducted static soaking experiment under reservoir temperature-pressure conditions and employed multiple techniques to comprehensively characterize the pore structure. The results show that CO2–brine–rock interaction generated many large pores (10–50 μm) due to the dissolutions of carbonate and feldspar, numerous tiny intragranular pores (1–6 μm) and some microfractures in clays. The T2 distribution could be applied to characterize the pore size distribution of tight sandstones when the pores saturated with brine. Some secondary clay particles and debris dispersed into the brine caused by CO2–brine–rock interaction. These particles may block extremely small pore throats during flowing back. These blockages weakened the exchange between the small and the large pores, characterized by single-peak and insignificant three-peak T2 distributions transformed into apparent dual-peak T2 distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 °C, the maximum pore throat radius increased four-fold, and the average pore throat radius increased by 86.5% from 0.089 μm to 0.166 μm, indicating a significant increase in the pore connectivity. Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and can open bedding planes significantly, thus increasing the porosity and permeability of tight sandstones.

Application of Discrete Fracture Network Model in the Simulation of Massive Fracturing in Tight Oil Reservoir

Massive fracturing technology can form a complex fracture network and a large drainage area by multi-stage/multi-cluster perforation and injection of low viscosity fluids such as silckwater.the traditional bi-wing planar model is not applicable in the simulation of massive fracturing, and a new network model is needed. The pseudo-three-dimension (P3D) Discrete Fracture Network (DFN) model are based on self-similar solution methodology, and the fracture characteristics are then calculated numerically. we performed a comparison between DFN model and Cluster Facture model through the integration of rock mechanics, well logging and micro seismic detection technology. After the mini-fracture analysis and closure analysis, parameters like instantaneous shut-in pressure (ISIP), closure pressure and reservoir permeability were obtained. Based on these parameters, pressure history match and SRV match were performed, the result shows that DFN model works better than the Cluster Fracture model in the matching. The research proves the feasibility of DFN model in the simulation of massive fracturing in tight oil reservoirs.

Analytical modelling of wettability alteration-induced micro-fractures during hydraulic fracturing in tight oil reservoirs

Hydraulic fracturing technique is of vital importance to increase fuel energy, in particular to unlock the unconventional resources (e.g., tight oil, shale oil and shale gas reservoirs). However, low recovery of hydraulic fracturing fluid has been in the centre of attention from both technical and environmental perspectives in the last decade. To gain a deeper understanding of controlling factor(s) over low recovery of hydraulic fracturing fluids, we hypothesized that hydraulic fracturing fluid (usually low salinity water) increases hydrophilicity of reservoir rocks, thus stress intensity factor, which in return facilitates in-situ micro-fractures extension. To test this hypothesis, we developed a physical model with consideration of capillary pressure which is associated with wettability. Moreover, we calculated stress intensity factor using our previous contact angle results with presence of low salinity and high salinity water [Xie et al., The low salinity effect at high temperatures, Fuel, 200 (2017) 419–426]. Furthermore, we examined the effect of tip width of in-situ micro-fractures, distance from main hydraulic fractures on micro-fractures extension at different wetting systems.Our results demonstrate that low salinity water indeed increases stress intensity factor as compared to high salinity water due to the wettability alteration. Our results also show that the length of micro-fracture extension increases up to 15 times than the original micro-fracture length due to the wettability alteration when the tip width of in-situ micro-fracture reaches 10 nm. This likely explains the extension of micro-fractures due to water uptake by shale. Moreover, micro-fracture extension is more pronounced for micro-fractures located nearby a wellbore, suggesting that a huge amount of hydraulic fluids likely remains at the vicinity of the wellbore. Knowing wettability thus stress intensity factor, the disappearance of hydraulic fracturing fluids and EOR potential in tight sandstone and shale reservoirs can therefore be quantified.

Integrated optimization design for horizontal well placement and fracturing in tight oil reservoirs

Hydraulically fractured horizontal well technologies, which combine hydraulically fractured technology with horizontal well technology, is widely used to enhance oil recovery in tight reservoir production. Although there are many advantages to this method, it requires more investment in drilling and completion. Most academic literature to date has treated the optimization of well placement and fracturing as two separate problems. Computationally expensive numerical simulation techniques are often involved both in well placement and fracturing design optimization processes, but only suboptimal solutions are achievable. In order to achieve co-optimization for horizontal well placement and fracturing, an optimal model has been constructed, with an objective function targeted at maximizing the net present value (NPV), which is a function of location, direction and length of a new horizontal well, the number of fractures, half-length of the fracture etc. Due to the large number of optimization variables, investigating the impacts of horizontal well parameters on the objective function must utilize repetitive runs of numerical simulations involving large computation times for evaluating possible well placement and fracturing scenarios. Aiming to address this challenge, a new method, called the Multipoint Adaptive Gaussian Process Surrogate Model with Important Design Domain (MAGPSM-IDD), is proposed. Then MAGPSM-IDD were applied to a synthetic field and a real reservoir, and our results showed that MAGPSM-IDD could obtain better results with higher efficiency than the popular optimization method, Hybrid Genetic Algorithm (HGA).

CO2, Water and N2 Injection for Enhanced Oil Recovery with Spatial Arrangement of Fractures in Tight-Oil Reservoirs Using Huff-‘n-puff

Tight oil has been effectively developed thanks to artificial fracture technology. The basic mechanism of effective production through fractures lies in the contact between the fractures (both natural and artificial) and the matrix. In this paper, the natural tight cores from J field in China are used to conduct experimental studies on the different fluid huff-‘n-puff process. A new core-scale fracture lab-simulation method is proposed. Woven metallic wires were attached to the outer surface of the core to create a space between the core holder and core as a high permeable zone, an equivalent fracture. Three different injecting fluids are used, including CO2, N2 and water. The equivalent core scale reservoir numerical models in depletion and huff-n-puff mode are then restored by numerical simulation with the Computer Modeling Group—Compositional & Unconventional Reservoir Simulator (CMG GEM). Simulation cases with eight different fracture patterns are used in the study to understand how fracture mechanistically impact Enhanced Oil Recovery (EOR) in huff n puff mode for the different injected fluids. The results showed: Firstly, regardless of the arrangement of fractures, CO2 has mostly obvious advantages over water and N2 in tight reservoir development in huff-‘n-puff mode. Through EOR mechanism analysis, CO2 is the only fluid that is miscible with oil (even 90% mole fraction CO2 is dissolved in the oil phase), which results in the lowest oil phase viscosity. The CO2 diffusion mechanism is also pronounced in the huff-‘n-puff process. Water may impact on the oil recovery through gravity and the capillary force imbibition effect. N2, cannot recover more crude oil only by elasticity and swelling effects. Secondly, the fracture arrangement in space has the most impact on CO2 huff-‘n-puff, followed by water and finally N2. The fractures primarily supply more efficient and convenient channels and contact relationships. The spatial arrangement of fractures mainly impacts the performance of CO2 through viscosity reduction in the contact between CO2 and crude oil. Similarly, the contact between water in fractures and crude oil in the matrix is also the key to imbibition. In the process of N2 huff-‘n-puff, the elasticity energy is dominant and fracture arrangement in space hardly to improve oil recovery. In addition, when considering anisotropy, water huff-‘n-puff is more sensitive to it, while N2 and CO2 are not. Finally, comparing the relationship between fracture contact area and oil recovery, oil production is insensitive to contact area between fracture and matrix for water and N2 cases.