Fractured Tight Reservoirs Research Articles

Identification and characterization of a proper gel system for large-volume conformance control treatments in a fractured tight reservoir: From lab to field

The existence of fractures in petroleum reservoirs can greatly reduce the sweep efficiency and subsequently limit the oil recovery during water flooding. Gel treatment is widely known as a cost-effective method for conformance control and water shutoff during water flooding in fractured reservoirs. In this study, we discuss the feasibility of three types of gel systems for conformance control in fractured reservoirs, aiming to select a proper one for field pilot applications in Huabei oilfield (China). Based on the gelation time and the gel strength, the water-soluble phenolic resin (WSPR) gel was chosen for field applications. This silica nanoparticle strengthened WSPR gel demonstrated high gel strength and long-term thermal stability in the lab. Furthermore, its plugging capability was studied by determining the rupture pressure of the gel-filled tubes. The results indicate that the plugging ability of WSPR gel is enhanced with increasing the polymer concentrations and decreasing the size of apertures. Besides, the WSPR gel exhibits high rupture pressure under low brine injection rate. For field applications, the pressure transient tests, tracer tests and the injection-production data were used collaboratively to determine the volume of the fractures in the reservoir. A large volume of gelant was designed for well treatment, and multiple gel slugs with different polymer concentrations were tailored to meet the operational conditions. After the gel treatments, the bottom hole pressure for each injector was significantly increased, indicating that the fractures were effectively plugged. Moreover, the oil production rates were notably increased, accompanied by a prominent decrease in water cut after the gel treatment. To date, the oil production rates of two well-connected production wells, HH55P56 and HH55P58, have been increased from 0.36 t/d to 0.9 t/d and from 0.19 t/d to 0.48 t/d, respectively. The oil production rate of well HH55P24 has been increased by 0.5 t/d.

A compositional numerical study in hydraulic fractured tight reservoir: Considering capillary pressure in phase behavior calculation

The compositional numerical simulator is a critical method for simulating the development of oil and gas production. In the simulation of conventional reservoir, capillary pressure is relatively small and often been ignored in phase behavior calculations. But In tight reservoirs, the capillary pressure is so large that can seriously affect the fluid phase behavior. The existing compositional numerical simulators cannot accurately calculate oil and gas production of tight reservoirs because the effects of capillary pressure on phase behavior are ignored. In this paper, we developed a full compositional numerical simulator that simulates the production in tight reservoirs with the consideration of capillary effect on the phase behavior of fluid. To compare the simulation results with and without considering capillary pressure in phase behavior calculations, we respectively set the capillary pressure as a function of gas saturation or zero in matrix and fractures. Three capillary pressure assignment methods for tight reservoirs were performed to illustrate the influence of capillary pressure on production. The simulation results indicate that the consideration of capillary pressure on phase behavior lead to more favorable for oil production, such as lower cumulative gas production and gas-oil ratio, accelerated pressure drop rate, increased oil saturation, and higher recovery compositions of heavy components. This study provides reasonable simulation results for the actual production of tight reservoirs, giving important insights into the evaluation of the production and development from tight reservoirs.

Study On Imbibition Fluid Preferred And Injection Parameters In Fractured Tight Reservoir— A Case From Daqing Toutai Oilfield

In the process of the development of fractured tight reservoir, there are some problems such as high injection pressure and poor effectiveness of production. At present, tight reservoirs mostly adopt fracturing development. When injection pressure is higher than fracture opening limit, connected oil wells show severe flooding, water-flooding efficiency is extremely poor. In order to solve the technical problems of fractured tight reservoir development, In this paper, based on the physical and chemical characteristics of surfactants, and by means of instrumental monitoring and numerical simulation, the optimization of the composition of the perming-absorbing liquid and the optimization of the injection process parameters in the tight oil reservoir in Daqing Toutai were studied and simulated. The results show that the capillary force is the main force in the process of osmosis and oil recovery, and the surfactant can change the rock into water wetness, which is beneficial to osmosis and absorption, and the oil washing effect of surfactant also improve the oil displacement efficiency. But it reduces the interfacial tension between oil and water, reduces the capillary force, and is not conducive to the imbibition. Therefore, it is necessary to choose a suitable concentration of the imbibition liquid to take account of both wettability and interfacial tension. Toutai oil field has poor sensitivity and stronger adaptability to solvent water mineralization. Nonionic surfactant solution(DWS, 0.2 %) is recommended for the imbibition in the target area of the Toutai oil field, injection process parameters range: the injection timing (water cut during injection) is 40 % to 60 %, the injection volume is 4000m3 to 5000m3, the well shut-in time is two months to three months, the cycle of huff and puff is 1.5 to 2.0 years, and the injection velocity is 30m3/d to 40m3/d. It provides the basis for the target reservoir technology decision and has important theory and application value.

Evaluation of a robust Gel System for Water Shutoff in Large Aperture Fractures

Polymer gels for water shutoff usually base on high concentration and high molecular weight of hydrolyzed polyacrylamide (HPAM). It would lead to a high injection pressure during blocking the large aperture fractures in tight reservoirs. The in-situ polymerization of monomer gel (IPMG) has been investigated in this study. The properties of high strength and long-term thermal stability could greatly extend gel conformance control duration. The gelation time of IPMG can up to 24 hours at the temperature of 65°C. In addition, the gel strength with formulations based on Na montmorillonite (Na-MMT) was much better than that without it. The flooding experiments have shown that the robust gel has a high rupture pressure when blocking the fractures. Another benefit of the gel is a long-lasting decrease permeability of the fracture even after experiencing long time flooding.

Research on Formation and Control Method of Volume Fracturing Network in Tight Reservoir Based on Computer

With the maturity and application of the concept of volume fracturing, the development of tight reservoirs has gradually become a strategic goal of unconventional oil and gas resources development. However, there are still some difficulties and problems in the theory of volume fracturing fracture opening. Based on this, this paper first studies the feasibility evaluation of volume fracturing in tight reservoir, then analyses the formation mechanism of volume fracturing network in tight reservoir, and finally gives the formation control method of volume fracturing network in tight reservoir based on computer.

Case Study: Effect of Natural Fracture on Stimulation Strategy in Keshen Tight Gas

Aimed at problems of poor fracturing effects of fracture-network acid fracturing in three wells in the Keshen 5 block, a fractured and tight gas reservoir in Tarim Oilfield, the mechanical activity of natural fractures was studied. The fractures in this block were divided into three types: fully-filled, semi-filled, and unfilled. The analysis of the correlations showed that the correlation of the number of fully-filled fractures and absolute open flows (AOF) is poor, while the correlation between the number of unfilled and semi-filled fractures and AOF is the best. Core samples with different types of fractures were tested using conventional triaxial compression methods, and the experimental results showed that the friction coefficient of the fully-filled fracture is close to that of semi-filled fracture, while the cohesion of fully-filled natural fractures is close to that of intact rocks, which is much greater than that of semi-filled fractures. The effective stress test results shows that the effective stress coefficient of fully-filled natural fracture rock samples is lower than that of semi-filled fractures. Using Mohr–Coulomb theory to calculate the natural fracture mechanics of high-production wells and low-production wells, the results show that low-production wells are mainly fully-filled fractures, most of which are not activated, so the production is low; while high-production wells are semi-filled and unfilled fractures, most of which can be activated, so the production is high. Based on this, for a well dominated by fully-filled fractures, it is recommended to use conventional gel fracturing to replace the fracture-network acid fracturing process. The stimulation practice of two wells has proven the validity of this strategy. The filling degree of natural fractures affects the increasing production and choice of stimulation process. This may be a relatively new understanding and may provide insights to stimulation strategy decisions for other fractured tight reservoirs in the world.

Study Quantifies Stress Sensitivity of Fractured Tight Reservoirs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 20260, “Stress Sensitivity of Fractured Tight Reservoirs,” by Gang Han, SPE, Aramco, and Kirk Bartko, SPE, Consultant, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Wells in unconventional reservoirs can experience sharp rate declines in the early stage of production, especially when experiencing aggressive drawdown. One key factor affecting rate decline is rock sensitivity to increasing compressive stress. The complete paper describes and quantifies the stress-dependence of compaction and permeability for anisotropic rock matrices, natural fractures, and hydraulic fractures, based on comprehensive rock tests of a fractured tight reservoir. Stress Sensitivity and Drawdown Laboratory data show that rock permeability can be reduced by 10 to 99% with increasing confining stress. Controlling factors include rock characteristics such as authigenic cementation, pore structure, clay content, natural fractures, and pore volume compressibility. Additional factors include pore throat size and shape. Low-permeability rocks are more sensitive to stress changes than are high-permeability rocks. A direct link exists between stress-dependent permeability reduction and production decline, especially in unconventional reservoirs in which production declines rapidly during the first year. As production starts and bottomhole pressure is lowered, the effective stress on the rock near the wellbore, defined as the difference between total stresses and pore pressure, increases. Higher loading stress reduces the permeabilities (or conductivities) of induced fractures, natural fractures (or laminations), and the matrix. The increase in effective stress can lead to proppant embedment and crushing, formation spalling, fines migration, rock compaction, and closing of natural fractures. Many of these processes are irreversible and lead not only to rapid production decline but also to reduction of estimated ultimate recovery (EUR). In 2011, analysis of a shale consortia database found that wells with restricted rate (limited drawdown) have 2 to 3 bcf higher EUR than wells with open rate (unlimited drawdown). The analysis also observed that the decline of stress-dependent permeability in propped fractures (millidarcy) is not as severe as the reduction in unpropped fractures (microdarcy) and matrix (nanodarcy).

Analytical and experimental study of stress sensitivity effect on matrix / fracture transfer in fractured tight reservoir

In fractured tight reservoirs, the stress sensitivity effect has important impacts on the law of pressure diffusion as well as the matrix/fracture transfer flow, which is the main fluid migration way. In this paper, the stress sensitivity effect is considered to establish the matrix/fracture transfer flow model, and the transfer shape factor and transfer function are deduced. According to the characteristics of the simplified model, the 1D and 2D matrix/fracture transfer flow experiments considering the stress sensitivity effect are designed, and the theoretical model is verified. Then, the stress sensitivity tests and transfer flow experiments are carried out, the influences of stress sensitivity factors (lithology, initial permeability and effective stress) on transfer flow are studied. The experiment results show that the average errors of matrix average pressure, transient transfer flow and cumulative transfer volume flux are 3.6%, 4.8% and 5.2% respectively, and the calculation accuracy is high. The stress sensitivity of the Glutenite is the strongest, the Turbidite the middle and the Beach bar sand the weakest; the smaller the initial value of permeability is, the stronger the stress sensitivity is; the bigger the effective stress is, the more the permeability loss is. Due to the differences of stress sensitivity effect, the stronger the stress sensitivity is, the faster the transient transfer flow rate drops, and the fewer the cumulative transfer volume flux is. The new transfer flow model is applied to the well test interpretation theory, and the fitting results of the real pressure build-up data show that the new well test type curve has better fitting effect on the unsteady matrix/fracture transfer stage with an error of 4.2%, which is 25.6% lower than that of the classic theory.

A novel material evaluation method for lost circulation control and formation damage prevention in deep fractured tight reservoir

Lost circulation induced by working fluid loss into formation fractures often leads to safety, environmental and economic issues, which has hindered the exploitation of oil, gas and geothermal resources for years. Fracture plugging with loss control materials is the most commonly used method for lost circulation control. However, traditional material selection is mainly guided by trial-and-error method. This paper proposes a novel material evaluation method for the systematic and scientific selection of loss control material. The new method consists of four steps: key material parameters determination, parameter weight calculation, parameter experimental evaluation, and material quantitative scoring. Fracture plugging strength model is analyzed to determine the key material parameters accounting for fracture plugging strength and the requirement of plugging removal before production. Analytic hierarchy process is adopted to calculate the material parameter weight. Experiments are designed to evaluate the material parameter levels. Quantitative scoring model is proposed to finally determine the material integrated score for the quantitative evaluation and scientific selection of loss control material. The reliability of the proposed evaluation method is validated by fracture plugging experiments. High-score materials are selected to form loss control formula based on the proposed evaluation method and successfully applied to gas field in Tarim Basin, China.

Study of Controlling Factors on Productivity of Keshen Gas Field: A Deep Tight Sandstone Reservoir in Kuqa Depression

The Keshen gas field in the Kuqa depression of the Tarim Basin with characteristics of deep buried depth, tight matrix and developed fracture, has great differences in gas well productivity within different parts of the structure, which bring difficulties to the gas field development and deployment. Based on the study of the reservoir matrix property, fracture characteristics and individual well productivity of the Keshen ultra-deep gas reservoirs, combined with reservoir geostress research, the difference between high and low efficiency wells in Keshen2 block is analysed, and the main geological factors influencing productivity are revealed. It is found that the effectiveness of reservoir fracture is a necessary condition for high production of gas well. Further study shows that there is a negative correlation between the open flow of gas well and the effective normal stress of fracture. The larger the effective normal stress of fracture is, the more difficult it is to achieve high production with reservoir reconstruction. According to study of the productivity influencing factors of the fractured tight sandstone reservoirs, some suggestions on well deployment and well perforation are given in the paper, which are beneficial to increase production and efficiency of this kind of reservoirs.

Analysis of the Static and Dynamic Imbibition Effect of Surfactants and the Relative Mechanism in Low-Permeability Reservoirs.

Establishing an effective displacement system for conventional water flooding development in low-permeability reservoirs is difficult, with generally low liquid and oil production and a worse water flooding effect. Imbibition oil recovery technology has received increasing attention from oil development workers because of its simple operation, low cost, and good oil increase effect. To explore the method and mechanism to further improve the effect of imbibition oil recovery, we study the imbibition and oil recovery effect and its influencing factors in a low-permeability reservoir in the Dagang Oilfield based on evaluation indexes of the adhesion work reduction factor, ratio of capillary force to gravity NB–1, regression analysis of the recovery rate of imbibition, proportional relationship with spontaneous imbibition, and dynamic imbibition effect in crack rocks. Results show that reducing the interfacial tension of the surfactant on the imbibition process has a dual effect. The selection of the surfactant for fractured tight reservoirs should not excessively pursue ultralow interfacial tension, and it should consider the surface wettability environment favorable for imbibition to ensure that a sufficient driving force can be provided. In the initial imbibition stage, the capillary force is large, the velocity of water imbibition in pores is fast, and the oil recovery rate is high; the holding time of the imbibition process is important to imbibition recovery. With the increase in imbibition time, the capillary force weakens, and the imbibition speed decreases to zero. With the increase in injection volume, reservoir pressure, pressure holding time, and imbibition cycles, the oil recovery increases, but the amplification of oil recovery decreases. From the technical and economic viewpoints, the optimal slug size, throughput cycle, and pressure holding time of the target reservoir are recommended as follows: 0.5 PV,three3 rounds, and greater than 96 h, respectively.

Numerical simulation on natural gas migration and accumulation in sweet spots of tight reservoir

Although the exploration and development of tight gas have made great progress, the quantified study on gas migration and accumulation in sweet spots of tight gas reservoir is still limited. In this work, a computer program is developed to conveniently describe the different shape of sweet spots and the fractures in tight reservoir. Then, gas migration and accumulation processes are simulated, and the numerical simulation results are visualized and quantified. Based on the simulation results, the mechanism of gas migration and accumulation in sweet spots is revealed. The results indicate that the migration and accumulation of gas are two relatively independent processes. The gas migration process is determined by the permeability of rocks. The critical condition of gas accumulation in sweet spots is mostly determined by the capillary pressure difference between sweet spots and surrounding rock. The two migration patterns are clearly observed during the numerical simulations. When surrounding rock has seepage capacity for gas, the migration pattern tends to be piston-like displacement; when surrounding rock is impermeable for gas, the gas can only migrate into sweet spots through connected fractures. As a result, the migration pattern for this situation tends to be fingering displacement.

Fracture Types and Its Control Factors in Tight Oil Reservoirs

Fractures are well developed in tight sandstone reservoirs, which are the main reservoir space and important seepage channel. Fractures control the migration, accumulation, preservation and single well productivity of tight oil and gas, and affect the drilling and completion methods, fracturing reconstruction measures and production effect of tight oil exploration and development. This paper mainly studies the genetic type, development characteristics and control factors of fractures in tight reservoirs. According to the geological origin of fractures, there are two types of structural fractures and diagenetic fractures in the study area, among which high angle structural fractures are the main one, and it is layer controlled fracture. The degree of fracture development is controlled by lithology, formation thickness, sedimentary micro and other rock heterogeneity factors.

Natural fractures in carbonate-rich tight oil reservoirs from the Permian Lucaogou Formation, southern Junggar Basin, NW China: Insights from fluid inclusion microthermometry and isotopic geochemistry

Natural fractures within tight reservoirs form preferred pathways for hydrocarbon charge and provide space for hydrocarbon preservation. However, the mechanism that controls the formation of natural fractures in tight reservoirs remains controversial. This study investigates natural fractures within carbonate-rich tight oil reservoirs from the Permian Lucaogou Formation in the Jimsar Sag, southern Junggar Basin. Drill core and image log observations show that fractures in the Lucaogou Formation can be categorized into two types: bedding-parallel fractures and inclined fractures. The carbon and oxygen isotopic compositions of calcite cements in the bedding-parallel fractures range from 0.6‰ to 6.0‰ (δ13CPDB), and from −15.5‰ to −8.9‰ (δ18OPDB), respectively, which are similar to those of the organic-rich host rock. This suggests that the bedding-parallel fractures likely formed in a closed fluid system. Fluid inclusion analyses of the aqueous inclusions in calcite cements from the bedding-parallel fractures record homogenization temperatures of 91.5 °C–130.4 °C, indicating that they formed at the Cretaceous to Cenozoic, during when the Lucaogou Formation reached peak oil generation stage. Therefore, the bedding-parallel fractures were most likely generated by hydrocarbon generation overpressure. The presence of hydrocarbon inclusions in bedding-parallel fracture cements supports natural fracturing by high pore-fluid pressure. The δ13CPDB and δ18OPDB of calcite cements within the inclined fractures vary from 3.6‰ to 9.6‰, and from −11.0‰ to −2.9‰, respectively, which are close to those of the carbonate-rich parent rock. This also supports a closed fluid system scenario. The relatively lower fluid inclusion trapping temperatures (70.5 °C–109.7 °C) suggest that they were likely generated by decrease of confining stress during uplift processes. Therefore, both an increase in pore-fluid pressure and a decrease in confining stress contribute to the formation of natural fractures in the Lucaogou Formation tight oil reservoirs.

Transient transfer shape factor for fractured tight reservoirs: Effect of the dynamic threshold pressure gradient in unsteady flow

AbstractIn fractured tight reservoirs, the seepage capacity of the matrix is poor, and fluid migration mainly depends on matrix/fracture transfer. An accurate understanding of the matrix/fracture flow is the basis of well tests and numerical simulations for tight reservoirs. In this paper, the unsteady flow equation for tight reservoirs is deduced based on the boundary layer theory, which can reflect the effect of the dynamic threshold pressure gradient, and the theoretical flow equation is verified by seepage experiments. Based on the study of the flow equation, the approximate semi‐analytical solution of the matrix/fracture unsteady transfer shape factor and the transfer function for tight reservoirs are established considering the early stage of matrix/fracture transfer (pressure does not propagate to the matrix center) and the late stage of matrix/fracture transfer (pseudo‐steady state). The results show that the shape factor of the tight reservoir is mainly affected by three factors (minimum threshold pressure gradient, static boundary layer thickness, and sensitivity coefficient of the fluid boundary layer), and the theoretical curves show that the intermediate transfer enters the pseudo‐steady state when the dimensionless time reaches approximately 0.14. The higher the minimum threshold pressure gradient is, the larger the transfer shape factor. The larger the static boundary layer thickness is, the larger the transfer shape factor; additionally, the larger the sensitivity coefficient of the fluid boundary layer is, the faster the change rate of the shape factor. Finally, the transfer shape factor is applied to a well test interpretation. Examples prove that the fitting accuracy of the new curve type is improved by 34.2% compared with the curve type for the conventional well test interpretation method.

Model of Effective Width and Fracture Conductivity for Hydraulic Fractures in Tight Reservoirs

Hydraulic fracturing technology is widely used in the development of tight reservoirs. Hydraulic fracture closure highly impacts oil and gas production in tight reservoirs, and a quantitative description of the effective width and fracture conductivity has a guiding significance for fracturing design and productivity prediction. In this paper, based on the mechanical characteristics of proppants in hydraulic fracturing, a fracture width model is first established for sandstone and shale reservoirs, and the effect of the closing pressure on the rock mechanics parameters of proppants is considered. Then, by the changes in fracture width and proppant permeability, a fracture conductivity model is built. Finally, the models are verified with existing experimental data, and are applied to analyze the influence of relevant parameters on the effective width and fracture conductivity of hydraulic fractures. Fracture closure is primarily affected by proppant deformation and embedment. An increase in the proppant elastic modulus can reduce proppant deformation and avoid fracture closure. A fracture containing large proppant more readily closes during the production process, and the closing pressure has a considerable effect on the proppant rock mechanical parameters, which can prevent the fracture from closing to maintain its conductivity. In this study, fracture closure and its conductivity are predicted, which is conducive to the production of tight reservoirs.

Study on the Interference Law of Staged Fracturing Crack Propagation in Horizontal Wells of Tight Reservoirs.

Horizontal well multistage fracturing technology is a high-efficiency method for tight oil and gas production, which increases the contact area between the wellbore and stratum by forming multiple transverse hydraulic fractures (HFs). The stress interference caused by the created HFs will affect the propagation geometries of the subsequent HFs, and then affect the overall fracturing treatment performance. In order to study the distribution of HFs and law of interference among multiple fractures during horizontal well multistage fracturing in tight reservoirs, in this paper, the effects of horizontal stress difference, perforation spacing, and net pressure in the created fracture on the initiation and propagation of multiple cracks were specially studied through large-scale hydraulic fracturing experiments and numerical simulation. The results showed that under high horizontal stress difference, multiple HFs with small spacing tended to coalesce at a place where the length has extended to a certain level. It was also found that the initiation pressures of HFs within subsequent stages increase with the rise of net pressure in created HFs, which causes the subsequent fractures to deviate from the direction perpendicular to the horizontal wellbore and then to gradually deflect toward it. Moreover, the ratio of fracture spacing to fracture height, and the net pressure are the key parameters to determine the deflection degree of HFs for multistage fracturing. In addition, the deflection degree of subsequent HFs was expected to enhance with the decreasing ratio of fracture spacing to fracture height and increasing net pressure in created HFs. It was useful for mitigating stress interference to lengthen the stage spacing, control the fracture height, and reduce the net pressure. The research results have a reference value for the optimal design of the fracture spacing for multistage fracturing.

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.

Application of horizontal well multi-cluster network fracturing in tight reservoir

GD14H, a horizontal well drilled in tight reservoir of Dagang Oilfield, reveals complex lithology, large burial depth, and poor physical properties. In order to improve its fracturing performance, a new technique of multi-cluster network fracturing was adopted based on a series of optimized multi-cluster perforation parameters and fracturing treatment parameters, and the 15-cluster fracturing was determined. Field test has demonstrated outstanding stimulation results. Moreover, the horizontal well fractures monitoring via the stable electric field/potential method shows that the measured results match well with the results of physical model for GD14H. The successful application of this technique in Dagang Oilfield implies a great breakthrough in the fracturing of tight oil horizontal wells in Dagang Oilfield, and lays a valuable foundation for stimulation of other similar tight oil and gas reservoirs.

Study on Water Displacing Gas Relative Permeability Curves in Fractured Tight Sandstone Reservoirs Under High Pressure and High Temperature.

Water–gas relative permeability is an important parameter for the rational development of gas fields. Conventional measurement methods are carried out at normal temperature and pressure without considering the actual conditions of high temperature and high pressure. The water displacing gas process in fractured tight sandstone reservoirs, under formation condition (116 MPa and 160 °C), was simulated by the self-manufactured displacing apparatus. The results show that cores under formation condition have the larger residual gas saturation, the smaller two-phase coexisting area, the lower water/gas relative permeability, and the lower displacement efficiency than that under normal conditions. The relative permeability declines slowly and the residual gas saturation is high, making the process of replacing the gas more difficult. The number and the interconnection quality of fractures affect the shape and the position of the displacing curves. It provides a reference for the rational development and further research of fractured tight sandstone reservoir.