Development Of Tight Oil Reservoirs Research Articles

Quantitative evaluation methods of tight reservoirs based on multi-feature fusion: A case study of the fourth member of Shahejie Formation in Liaohe Depression

The formation and development of tight oil reservoirs in the fourth member of the Shahejie Formation (Es4) in the Leijia region of the western sag of the Liaohe Depression are highly heterogeneous and influenced by several factors. The relationship between these variables is extremely complex. In order to avoid deviations caused by single factors and logging data for less drilling when regional tight oil reservoirs have been assessed, quantitative evaluation methods for tight reservoirs based on multi-feature fusion have been proposed. Hand-drawn maps of brittleness index, carbonate rocks thickness, fracture density, mean permeability, and mean porosity are gridded by the Kriging model accompanied by k-means clustering to determine the types of reservoir and classification interval. After that, two quantitative evaluation methods, the overlapping favourability method (OFM) and the principal component analysis (PCA), were used to analyze the five influence factors of the tight oil reservoirs. Finally, reservoir evaluation maps were generated by dividing the interval values into classes. Results show that the weights of the five variables calculated by the hybrid weight method (HWM) are 0.1100,0.4929, 0.0803, 0.2889, and 0.0279. The reservoirs in the study area are finally divided into four types, with the best reservoir types primarily distributed in well areas, such as A99, A82, A91, A78, and A9. At the same time, the main controlling factors for the creation of the reservoir have been analyzed; however, the thickness of carbonate rock in the study area plays a decisive role in the development of high-quality reservoirs. The brittleness index and fracture density can significantly improve the efficiency of the reservoir. Quantitative approaches can effectively and scientifically evaluate the tight reservoirs, which can be widely used.

Review on Phase Behavior in Tight Porous Media and Microscopic Flow Mechanism of CO2 Huff-n-Puff in Tight Oil Reservoirs

The successful development of tight oil reservoirs in the U.S. shows the bright future of unconventional reservoirs. Tight oil reservoirs will be the main target of exploration and development in the future, and CO2 huff-n-puff is one of the most important methods to enhance oil recovery factor of tight oil reservoirs in North America. To improve the performance of CO2 huff-n-puff, injection and production parameters need to be optimized through numerical simulation. The phase behavior and microscopic flow mechanism of CO2 huff-n-puff in porous media need to be further investigated. This paper presents a detailed review of phase behavior and microscopic flow mechanism in tight porous media by CO2 huff-n-puff. Phase behavior in tight porous media is different from that in a PVT cylinder since the capillary pressure in tight porous media reduces the bubble point pressure and increases the miscibility pressure and critical temperature. The condensate pressure in tight porous media and nonequilibrium phase behavior need to be further investigated. The microscopic flow mechanism during CO2 huff-n-puff in tight porous media is complicated, and the impact of molecular diffusion, gas-liquid interaction, and fluid-rock interaction on multiphase flow is significant especially in tight porous media. Nuclear magnetic resonance (NMR) and molecular simulation are efficient methods to describe the microscopic flow in tight oil reservoirs, while the NMR is not cost-effective and molecular simulation needs to be improved to better characterize and model the feature of porous media. The improved molecular simulation is still a feasible method to understand the microscopic flow mechanism of CO2 huff-n-puff in tight oil reservoirs in the near future. The microscopic flow model in micropore network based on digital core is worth to be established, and phase behavior needs to be further incorporated into the microscopic flow model of CO2 huff-n-puff in tight porous media.

Characteristics and EOR mechanisms of nanofluids permeation flooding for tight oil

Tight oil reservoir development is faced with the key technical problem that “water cannot be injected and oil cannot be produced” yet. With the diphenyl ethers water-soluble (gemini) surfactants as water phase shell and C 10 –C 14 straight-chain hydrocarbon compounds as oil phase kernel, a nanofluids permeation flooding system was prepared by microemulsion technology, and its characteristics and EOR mechanisms were evaluated through experiments. The system has the following five characteristics: (1) “Small-size liquid”: the average particle size of the system is less than 30 nm, which can greatly reduce the starting pressure gradient of water injection, and effectively enter and expand the sweep volume of micro-nano matrix; (2) “Small-size oil” : the system can break the crude oil into “small-size oil” under the flow condition, which can greatly improve the percolation ability and displacement efficiency of the crude oil in the micro-nano matrix; (3) Dual-phase wetting: the system has contact angles with the water-wet and oil-wet interfaces of (46±1)° and (68±1)° respectively, and makes it possible for capillarity to work fully under complex wetting conditions of the reservoir; (4) High surface activity: the interfacial tension between the system and crude oil from a tight oil reservoir in Xinjiang is 10 −3 –10 −2 mN/m, indicating the system can effectively improve the displacement efficiency of oil in fine pore throats; (5) Demulsification and viscosity reduction: the system has a demulsification and viscosity reduction rate of more than 80% to inversely emulsified crude oil from a tight oil reservoir in Xinjiang, so it can improve the mobility of crude oil in the reservoir and wellbore. The system can be used to increase oil production by fracturing in tight reservoirs, replenish formation energy by reducing injection pressure and increasing injection rate, and enhance oil recovery by displacement and cyclic injection, providing key technical support for effective production and efficient development and recovery enhancement of tight reservoirs.

Study of massive water huff-n-puff technique in tight oil field and its field application

Based on the characteristics of horizontal oil wells in tight reservoirs during their late stage, which are exploited by elastic drive of natural energy and stimulated by large-scale volume fracturing; the massive water huff-n-puff technique is proposed for the use of supplementing the energy of the depleted formations, which can effectively increase the productivity of single horizontal oil well in addition to its financial benefits. In this paper, the massive water huff-n-puff technique is defined and discussed from the following aspects of the mechanism, reservoir engineering, laboratory experiments and so forth. Additionally, comprehensive analyses of the advantages of applying this technique in the development of tight oil reservoirs are provided. By the studies of the pressure composition diagram and the definition of residual injection pressure (RIP) in reservoirs, a massive water huff-n-puff mathematical model was established and the critical parameters for water-flooding were calculated. Laboratory experiments of this technique have shown that it can induce a certain number of micro-fracture networks and its application in actual oilfields also shown positive results. The pilot tests have achieved remarkable increases in productivity and economic benefits. For example, the average daily oil production from a single well is increased by 4.5 t/d (0.8 → 5.3 t/d), the formation pressure has increased by 9.3 MPa (6.9 → 16.2 MPa), accumulated oil production has reached 1,987t, and its input-output ratio has shown an enhancement in the range of 1.00:1.74–1.00:4.06. The research results of this technique provide a new way and an important model for efficient development of horizontal wells in tight oil reservoirs.

A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

Supplementary energy development boundaries of staged fracturing horizontal wells in tight oil reservoirs

Staged fracturing horizontal well technology is an important means of improving tight reservoir development efficiency. Taking a typical tight oil block in the Oilfield A as the studied area, the vertical well–horizontal well joint arrangement pattern is adopted in this study. The energy supplementary development effects of multiple permeability scales, different arrangement spacing, and different media (H2O, CO2) are discussed through the numerical simulation method. Combined with the principles of petroleum technology economics, the economic evaluation model for staged fracturing horizontal wells in tight oil reservoir development is proposed, thereby determining the technical boundary and economic boundary of supplementary energy development with different media. Studies indicate that the technical boundary and economic boundary of water-flooding development in the Oilfield A are 0.4 and 0.8 mD, respectively, and the technical boundary and economic boundary of CO2-flooding development are 0.1 and 0.4 mD, respectively. This study provides theoretical support for field operation of Oilfield A and guidance for selection of development mode for tight oil reservoirs.

CO2 huff and puff pilot with staged-fracturing horizontal well in tight oil reservoirs

CO2 huff and puff has been considered as one of the most successful processes to increase oil recovery, however, this stimulation technology is yet to be widely used in tight oil reservoirs. In this paper, a production model is developed to describe the CO2-soak process in tight oil reservoirs, providing a guidance to optimize the production parameters for CO2-soak pilot in the staged-fracturing horizontal well. The result shows that the CO2 huff and puff process helps to improve the reservoir energy, the fluid mobility, and thus the reserves-to-production ratio. To be specific, the recovery factor of tight oil reservoirs stimulated with CO2 huff and puff technology is 2.0% higher than that produced with natural energy. The success in CO2 soak pilot is of importance significance to the effective development of tight oil reservoirs.

Laboratory and field-scale parameter optimization of CO2 huff–n–puff with the staged-fracturing horizontal well in tight oil reservoirs

With the help of large-scale physical simulation experiment technology, the physical simulation experiments of the CO2 huff–n-puff with the staged-fracturing horizontal well could be acheived. We studied the production process of CO2 huff–n–puff and influence of different parameters affect oil recovery during the CO2 huff-n-puff procedure, ultimately, the operation parameters were optimized by numerical simulation. The results show that CO2 can quickly enter the deep formation through the horizontal well and the fracture during the huff period and staged-fracturing horizontal well can greatly increase the contact area between CO2 and crude oil, which improves the efficiency of extraction, dissolution, reduction of viscosity between CO2 and crude oil. During the puff period, the horizontal well and fractures can reduce the flow resistance effectively, so as to improve the flow capacity of crude oil. After 3 cycles of CO2 huff and puff, the oil recovery can be enhanced by 11.13%~21.39% compared with that obtained by elastic flooding, which indicates that the exploitation method of CO2 huff–n–puff can improve the development effects of tight oil reservoirs. CO2 huff-n-puff injection parameters are optimized, the results show that the optimum time of injection is 1 year, the optimum soaking time is 30d, and the optimal injection pore volume is 0.18HCPV. This research can provide a certain technical support for effective development of tight oil reservoirs.

Research Advances in Tight Oil and Its Prospect

Tight oil has broad prospects for exploration around the world. There have been achieved success exploration and development of tight oil reservoirs in some foreign basins. China has a large area of unconventional oil and gas resources, of which coalbed methane and shale gas have been well studied, but tight oil is still in its infancy, and its evaluation basis is still weak. By analyzing the control factors of tight oil accumulation, the accumulation process and the accumulation dynamiction, it is believed that the basic theoretical work of tight oil accumulation should be carried out as soon as possible. Especially, there is an urgent need for breakthroughs in the study of the time relationship between tight oil accumulation and reservoir densification and formation mechanism of tight oil reservoir-forming dynamiction.

Investigation of imbibition areas during well shut-in based on mercury injection experiment and BP neural network

Hydraulic fracturing appears to be an important and efficient method in the development of tight oil reservoirs. Well shut-in process after hydraulic fracturing enables the capillary imbibition process in leak-off area thus improving the production in tight oil reservoirs. Therefore, leak-off area is also the imbibition area. However, the range of leak-off area has not been fully understood for production engineers due to the complexity and dynamics of fracturing. In this work, we applied fractal theory to derive the matrix permeability in tight oil reservoirs, which can better describe the microscopic characteristics of reservoirs and manage the reservoir performance. Subsequently, we developed an analytical model to calculate pressure distribution at leak-off areas during the fracturing and well shut-in processes. To avoid solving nonlinear equations, we used Newton-Raphson iterative method to calculate the correlation of time and pressure. The effects of six parameters (e.g., permeability, shut-in time, viscosity, half-length of fracture and height of fracture) on the leak-off area were examined using BP neural network, and a two-dimensional distribution grid of fracturing leak-off was developed. Moreover, we computed pressure distribution of fracturing fluid leak-off area numerically to verify the reliability of the new model. Our results show that the leak-off area of fracturing fluid increases with shut-in time. Based on the BP neural network, permeability and shut-in time play significant influences in the leak-off area of fracturing fluid. This work provides insights to examine the process of hydraulic fracturing and shut-in in tight oil reservoirs, and the proposed model is a useful tool to quantify the leak-off area of fracturing fluid after shut-in stage.

Feasibility study of improved unconventional reservoir performance with carbonated water and surfactant

For unconventional reservoirs, water flooding performs poorly because of low displacement efficiency; gas flooding shows limited enhanced oil recovery (EOR) capability due to gas breakthrough. Carbonated water injection (CWI) and active CWI (ACWI) are promising EOR methods which combine advantages of water and gas flooding. This paper provides experimental and numerical studies of carbonated water and surfactant injection based on a case study in Changqing Oilfield, China, which is the first time to investigate the feasibility of CWI and ACWI for tight oil reservoirs. This study compares performances of active water injection (AWI), CWI, Water altering gas (WAG), and ACWI. Experimental results reveal that the oil recovery of CWI is 2.7% more than WAG. ACWI achieves the highest incremental oil recovery (9.43%) among four methods. The sensitivity analyses of ACWI + WAG is further implemented experimentally, which demonstrates that ACW as a pre-flood improves 7% of oil recovery during WAG process. For Changqing tight reservoir cores, the optimal injection volume of ACW is 0.8 pore volume. Numerical simulations are conducted to validate the capability of cubic Equation-of-State coupled with Henry's law (EOS/H model) for CWI in tight oil reservoirs, indicating EOS/H model is applicable to correlate phase behavior of carbonated water and oil system. This paper, for the first time, investigates the EOR performance of ACWI in tight oil reservoirs. These results explore the feasible application of using CWI/ACWI in tight oil reservoir development.

Oil migration in nanometer to micrometer sized pores of tight oil sandstone during dynamic surfactant imbibition with online NMR

Dynamic imbibition is an imbibition phenomenon considering fluid flow around the surface of porous media and plays an important role in the development of tight oil reservoirs. In this paper, the behavior of oil migration in nanometer to micrometer sized pores during dynamic imbibition was studied using nuclear magnetic resonance (NMR). Firstly, the basic properties of surfactant and core samples were characterized. The boundary of cores were semi-sealed to simulate practical conditions. The dynamic imbibition experiments were carried out in the core flooding system using low-field NMR. The T2 spectrum and magnetic resonance imaging (MRI) were scanned, and the T2 relaxation time was converted to pore sizes using the mercury injection curve. The oil recovery factor and capillary number in nanopores and macropores were calculated. Four characteristic points of T2 spectrum were selected, and the recovery of these characteristic pores (0.3, 0.6, 18.3, and 116.7 μm) were found to be 20.0%, 19.8%, 11.9%, 30.1%, respectively. Furthermore, the effects of injection rate, interfacial tension (IFT), soaking time, and permeability on oil recovery from different typical pore sizes were investigated in detail. The recovery factor ratio (r), which was defined as the ratio of oil recovery in nanometer pores to that of macrometer pores, increased with the increase in soaking time, IFT, and permeability, while it decreased with the increase in flow rate.

Application of cumulative-in-situ-injection-production technology to supplement hydrocarbon recovery among fractured tight oil reservoirs: A case study in Changqing Oilfield, China

Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery.In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP’s superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field.Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP’s good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development.

The effects of the boundary layer and fracture networks on the water huff-n-puff process of tight oil reservoirs

Application of multi-fractured horizontal wells has led to significant progress in the development of tight oil reservoirs. However, oil production rapidly decreases and the estimated ultimate recovery is still low when the well is in production and approaching depletion. Water huff-n-puff is regarded as a useful measure to improve oil recovery due to oil-water imbibition and drainage. Additionally, complex fracture networks consisting of natural fractures (NF) and hydraulic fractures can significantly enhance oil recovery in the process of water huff-n-puff after multi-stage hydraulic fracturing. However, there is a non-flowing thin film on the solid-liquid wall surface in the pore-throats of the matrix, and the so-called boundary layer effect (BLE) is quite significant at the nano-scale. This effect reduces the effective flow space and effective permeability of the reservoir, leading to production damage. To date, few numerical simulation studies have considered the impact of the BLE and complex fracture networks in water huff-n-puff process simulation studies. In this study, the process of water huff-n-puff is evaluated considering complex fracture networks and formation damage in a matrix. The embedded discrete fracture model (EDMF), validated by local grid refinement (LGR), is applied to describe the distribution of hydraulic fractures and NF. The well performance considering the BLE is analyzed by a vectorization programming. The results show that the BLE reduces production and accelerates the production decline, so the BLE should be considered in reservoir simulations and productivity evaluations of water huff-n-puff processes. A certain degree of natural fracture development is conducive to improving the sweep efficiency of the water huff-n-puff, which could significantly improve oil recovery compared to depletion. By considering the impact of the BLE in water huff-n-puff simulations in tight oil reservoirs, it is possible to accurately evaluate the well performance and provide a theoretical basis for the optimization of water huff-n-puff.

Fully coupled fluid-solid numerical simulation of stimulated reservoir volume (SRV)-fractured horizontal well with multi-porosity media in tight oil reservoirs

A mutual coupling effect exists between the flow and stress fields in tight oil reservoir development. In terms of the characteristics of multi-porosity media (the matrix, natural fractures and network fractures) for stimulated reservoir volume (SRV)-fractured horizontal wells in tight oil reservoirs, considering the dual porosities of matrix and natural fractures, and based on the flowing feature of a discrete-fracture mode (DFM) fracture network stimulated system, a numerical simulation method based on fully coupled fluid-solid is introduced. According to the effective stress principle and regional flow characteristics, the fully coupled fluid-solid mathematical model considering the multi-porosity media characteristics of complex fracture networks is presented. The fully coupling numerical solution for the stress and flow fields is solved by the finite element method. The accuracy of this model is verified by comparing the finite differential model, non-coupled model and actual production data, respectively. And analyzing the computational time needed to solve the model under different solution methods and complexity levels. The variation of stress-strain and reservoir physical property parameters is revealed. For the non-coupled and fully coupled model, the productivity and formation pressure differences are compared and analysed. The results show that when considering the stress field, the initial production rate of an SRV-fractured horizontal well is large but declines quickly, and it has fundamentally different characteristics from the traditional flow model. Our research provides theoretical and technical guidance for the efficient development of unconventional resources.

Experimental Investigation of Oil Recovery from Tight Sandstone Oil Reservoirs by Pressure Depletion

Oil production by natural energy of the reservoir is usually the first choice for oil reservoir development. Conversely, to effectively develop tight oil reservoir is challenging due to its ultra-low formation permeability. A novel platform for experimental investigation of oil recovery from tight sandstone oil reservoirs by pressure depletion has been proposed in this paper. A series of experiments were conducted to evaluate the effects of pressure depletion degree, pressure depletion rate, reservoir temperature, overburden pressure, formation pressure coefficient and crude oil properties on oil recovery by reservoir pressure depletion. In addition, the characteristics of pressure propagation during the reservoir depletion process were monitored and studied. The experimental results showed that oil recovery factor positively correlated with pressure depletion degree when reservoir pressure was above the bubble point pressure. Moreover, equal pressure depletion degree led to the same oil recovery factor regardless of different pressure depletion rate. However, it was noticed that faster pressure drop resulted in a higher oil recovery rate. For oil reservoir without dissolved gas (dead oil), oil recovery was 2–3% due to the limited reservoir natural energy. In contrast, depletion from live oil reservoir resulted in an increased recovery rate ranging from 11% to 18% due to the presence of dissolved gas. This is attributed to the fact that when reservoir pressure drops below the bubble point pressure, the dissolved gas expands and pushes the oil out of the rock pore spaces which significantly improves the oil recovery. From the pressure propagation curve, the reason for improved oil recovery is that when the reservoir pressure is lower than the bubble point pressure, the dissolved gas constantly separates and provides additional pressure gradient to displace oil. The present study will help engineers to have a better understanding of the drive mechanisms and influencing factors that affect development of tight oil reservoirs, especially for predicting oil recovery by reservoir pressure depletion.

Investigations on spontaneous imbibition and the influencing factors in tight oil reservoirs

Spontaneous imbibition has become a role on the development of tight oil reservoirs. Many oilfield cases have confirmed the validity of soaking to produce oil depending on imbibition. Considerable yield has been recovered from soaking for a period of time after hydraulic fracturing by fracturing fluid. In order to study the spontaneous imbibition and its influencing factors in tight oil reservoir with stimulated reservoir volume (SRV), we first conducted wettability and imbibition experiments with/without surfactant treatment using different tight cores. Then, we established a mechanism model of imbibition including the influencing factors in tight oil reservoirs based on the experiments. The model was also validated using the published results. After that, numerical simulation was employed to study the impacts of some essential factors on the effects of spontaneous imbibition. The results indicate that no matter mixed-wet or water-wet tight cores, water can be spontaneously imbibed into the tight cores, and consequently expel the oil. The wettability alteration agent has slight influence on contact angle and imbibition recovery for the water-wet core, but it has a distinct influence on those of the mixed-wet or oil-wet core. Natural fractures in tight rock can promote the imbibition. The size of the tight rock after hydraulic fracturing is a significant factor of imbibition recovery. Interfacial tension is crucial to imbibition in tight reservoir because capillary force becomes more significant in tight rocks than that in conventional reservoirs. Wettability intensely decides the imbibition recovery, and it is indispensable to add modifying agents to enhance imbibition for mix-wet or oil-wet rocks. The reduction of temperature in tight oil reservoir due to fracturing and huff-n-puff may decrease the recovery by more than 1% after 5–6 cycles.

Waterflooding Huff-n-puff in Tight Oil Cores Using Online Nuclear Magnetic Resonance

Given the difficulty in developing waterflooding in tight oil reservoirs, using waterflooding huff-n-puff is an effective method to improve oil recovery. Online nuclear magnetic resonance (NMR) can detect the change in internal oil and water during the core displacement process, and magnetic resonance imaging (MRI) in real time. To improve the tight oil reservoir development effectiveness, cores with different permeability were selected for a waterflooding huff-n-puff experiment. Combined with online NMR equipment, the fluid saturation, recovery rate, and residual oil distribution were studied. The experiments showed that, for tight oil cores, more than 80% of the pores were sub-micro- and micro-nanopores. More than 77.8% of crude oil existed in the sub-micro- and micropores, and movable fluids mainly existed in the micropores with a radius larger than 1 μm. The NMR data and the MRI images both demonstrated that the recovery ratio of waterflooding after waterflooding huff-n-puff was higher than that of conventional waterflooding, and, therefore, residual oil was lower. Choosing two cycles’ of waterflooding, huff-n-puff was more suitable for tight oil reservoir development. The production of crude oil increased by 22.2% in the field pilot test, which preliminarily proved that waterflooding huff-n-puff was suitable for tight oil reservoirs.

Well test mathematical model for fractures network in tight oil reservoirs

Well test, especially build-up test, has been applied widely in the development of tight oil reservoirs, since it is the only available low cost way to directly quantify flow ability and formation heterogeneity parameters. However, because of the fractures network near wellbore, generated from artificial fracturing linking up natural factures, traditional infinite and finite conductivity fracture models usually result in significantly deviation in field application. In this work, considering the random distribution of natural fractures, physical model of fractures network is proposed, and it shows a composite model feature in the large scale. Consequently, a nonhomogeneous composite mathematical model is established with threshold pressure gradient. To solve this model semi-analytically, we proposed a solution approach including Laplace transform and virtual argument Bessel function, and this method is verified by comparing with existing analytical solution. The matching data of typical type curves generated from semi-analytical solution indicates that the proposed physical and mathematical model can describe the type curves characteristic in typical tight oil reservoirs, which have up warping in late-term rather than parallel lines with slope 1/2 or 1/4. It means the composite model could be used into pressure interpretation of artificial fracturing wells in tight oil reservoir.

Analytical model for production performance analysis of multi-fractured horizontal well in tight oil reservoirs

The combination of horizontal well drilling and reservoir stimulating via multiple fracturing has been proved to be an effective technology to exploit low permeability unconventional tight oil reservoirs. Through multiple fracturing, the very-complex fracture network called the stimulated reservoir volume (SRV) around primary fractures can be generated, which is expected to affect well performance significantly. The pores in tight oil reservoirs with multi-fractured horizontal wells (MFHWs) can be roughly divided into three major types: matrix, natural fractures and hydraulic fractures, which lead to multi-scaled flow during the development of tight oil reservoirs. Furthermore, non-Darcy flow and stress sensitivity make the fluid flow in such reservoirs become more complicated. So it is very difficult to accurately determine the productivity of MFHWs in these reservoirs. Various analytical models have been established to analyze the transient performance of MFHW fast and accurately. However, the typical seepage characteristics in tight oil reservoirs are seldom considered in these models, such as non-Darcy flow and stress sensitivity.This paper presents a new analytical model for MFHW in tight oil reservoirs, where the reservoir is subdivided into five continuous flow regions: the unstimulated reservoir volume (USRV) regions 1 and 2, the stimulated reservoir volume (SRV) regions 3 and 4, and the hydraulic fracture (HF) region 5. The effects of non-Darcy flow and stress sensitivity are both considered. Laplace transformation, perturbation method and Stehfest numerical inversion are employed to solve the model comprehensively. The model solution is verified with analytical and numerical methods. The effects of related influential parameters on well production performance are investigated. Field example is conducted to show the applicability of the new model, history matching curve and results are obtained according to real production data. The research results summarized in this paper can provide some significance for production performance analysis of MFHW in tight oil reservoirs.