Fractured Tight Reservoirs Research Articles

Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

Pore structure characterization and deliverability prediction of fractured tight glutenite reservoir based on geophysical well logging

Pore structure characterization and deliverability prediction of fractured tight glutenite reservoir based on geophysical well logging

Forward modeling of P- and S-waves response of fractures intersected with horizontal wells in tight reservoirs

Horizontal wells play an important role in expanding the drilling volume of reservoirs and oil production area, and are widely used in unconventional reservoirs. Fractures have a positive effect on reservoir permeability, but fractures can also cause accidents such as casing deformation and inter-well frac-hit. It is of great significance to identify and evaluate fractures intersected with horizontal wells in tight reservoirs. In this paper, a three-dimensional numerical model of horizontal wells and fractures in tight reservoirs is designed. The responses of monopole P-wave and dipole S-wave to fractures with different width, dip angle and filling medium are systematically studied, by using three-dimensional finite difference algorithm. The results show that when the fracture is filled with calcite, the amplitude attenuation of monopole P-wave and dipole S-wave has a monotonic exponential increase with the increase of fracture width and the decrease of fracture dip angle. In the real data processing, the amplitude attenuation of P- and S-waves can be used to jointly evaluate the fracture filled with calcite. When the fracture is filled with water, both P- and S-waves have prominent amplitude attenuation. P wave amplitude attenuation does not have a monotonic variation with the increase of fracture width but it has a monotonic increase with the decrease of fracture dip angle. S wave amplitude attenuation has a monotonic increase with the increase of fracture width and the decrease of fracture dip angle. The amplitude attenuation of P- and S- waves rises significantly when the fracture is filled with natural gas. This study is crucial for better understanding the response of P- and S-waves to fractures intersected with borehole in tight reservoirs, and it provides useful information for the inversion of fracture parameters by using P- and S-waves.

Nuclear magnetic resonance study of CO2 flooding in tight oil reservoirs: Effects of matrix permeability and fracture

The implementation of CO2 enhanced oil recovery (EOR) projects for tight reservoir development has the dual effects of economic benefits and carbon storage. Matrix permeability and fractures in tight reservoirs have a significant impact on the performance of CO2 flooding. In this study, CO2 flooding experiments were carried out using natural tight cores with different matrix permeabilities and artificial fracture conditions. The pore size range variation of oil-producing pores and the distribution of residual oil were explored by using nuclear magnetic resonance (NMR) technique. The results indicated that the increase of matrix permeability was beneficial to increase oil recovery, but it also reduced the displacement pressure and thus weaken the ability of CO2 diffusion into small pores. Specifically, with the matrix permeability increased from 0.1 to 0.2 mD to 0.4–0.5 mD and 0.8–0.9 mD, the oil recovery of fracture-free tight cores increased from 15.59% to 19.78% and 24.73%, and the pore size range of oil-producing pores decreased obviously. Conversely, the fractures aggravate the channeling flow of CO2 and reduce the swept area but facilitates the recovery of crude oil from smaller pores. In tight cores of 0.8–0.9 mD with single fracture and multiple fractures, the oil recovery decreased to 21.3% and 20.12%, but the oil-producing pore size range expands from 0.2-6 μm to 0.05–6 μm and 0.04–6 μm. The NMR imaging results showed that the residual oil content gradually increased from the injection end to the production end, and the distribution of the residual oil in the core with high permeability and non-fracture was more even.

Theoretical and experimental study on the long-term conductivity of heterogeneous artificial fractures in tight reservoirs

Volume fracturing technology is used to achieve economic recovery of crude oil in tight reservoirs. Then, the fluid flows into the wellbore through artificial fractures in the fractured zone, and the reservoir permeability is improved. Therefore, the study of the conductivity of artificial fractures is the key link for the fracturing development of tight reservoirs. Presently, experimental and theoretical studies on conductivity are based on a homogeneous model, which cannot reflect the nonuniform distribution of proppants in actual artificial fractures. Experiments on the long-term nonuniform sand spreading of artificial fractures in tight reservoirs are carried out in this paper with different influencing factors. Then, the influences of the matrix of proppant performance, proppant concentration, reservoir lithology, reservoir permeability and closure stress on the long-term conductivity of artificial fractures are clarified. The calculation model of the long-term conductivity of heterogeneous artificial fractures considering the reservoir characteristics, fracturing technology and reservoir characteristics is established based on the conductivity loss mechanism. Finally, the conductivity model is applied to the 7th tight reservoir block in the Ordos Basin, and the productivity prediction results are compared. The results show that the average loss of the conductivity of the heterogeneous artificial fractures is 26.6% relative to the initial state, and the loss of the conductivity is mainly at the initial stage of closure, accounting for approximately 90% at the condition of 60MPa confining pressure. The calculation accuracy of the theoretical nonuniform conductivity model is 92.2%, which can describe the continuous depression of the artificial fracture conductivity after introduction into the tight reservoir numerical simulation.

Experimental study of sandstone stress sensitivity under different fluids: Characteristics and mechanisms

Stress sensitivity is the phenomenon of permeability variation that caused by pore throat changes, opening or closure of fractures under forces, which is an important parameter in reservoir evaluation. Fractured sandstones under various fluids will produce different stress sensitivity, which can greatly influence oil and gas development. However, little is known on this topic currently. Hence, in this study, characteristics and mechanisms were investigated based on a series of experiments and theoretical analysis. The results indicate that: I, compared with unfractured rocks, fractured rocks show a stronger stress sensitivity. The permeability shows an obvious “decrease initially steep and finally gentle” pattern with the increase of effective stress. II, from purified water to low NaCl/CaCl2 mineralization fluids, the permeability damage of fractured rocks decreases gradually with the increase of mineralization degree; however, it increases with mineralization degree when rocks are under high mineralization fluids, and the damage degree is also high. The permeability damage degree is generally low when fractured rocks are under the action of kerosene. Mechanism analysis indicates that: I, fractured rocks have both fracture and pore systems, whose opening and closure can produce stronger stress sensitivity and more obvious nonlinear variation of permeability than unfractured rocks. II, under purified water conditions, the expansion of clay minerals is an important indicator and reason for the permeability damage. III, under low fluid mineralization degree conditions, the reaction between fluids and minerals will destroy rock structures, increase fracture aperture, and produce secondary pores, and finally decrease the permeability damage to a certain extent. IV, under high fluid mineralization degree conditions, crystals may be deposited, blocking up pores/fractures and producing high permeability damage. V, there are no reactions between minerals and kerosene, hence, the permeability damage degree is generally low. The results are expected to provide references for the exploration and development of fractured tight reservoirs in Kuqa Depression.

Experimental study of surfactant-enhanced spontaneous imbibition in fractured tight sandstone reservoirs: The effect of fracture distribution

Spontaneous imbibition is an important phenomenon in tight reservoirs. The existence of a large number of fractures and micro-nano pores is the key factor affecting the spontaneous imbibition of tight reservoirs. In this study, based on high-pressure mercury injection and nuclear magnetic resonance experiments, the pore distribution of tight sandstone is described. The influence of fractures, core porosity and permeability, and surfactants on the spontaneous imbibition of tight sandstone are studied by physical fracturing, interfacial tension test, wettability test and imbibition experiments. The results show that: the pore radius of tight sandstone is concentrated in 0.01–1 μm. Fractures can effectively reduce the oil drop adsorption on the core surface, enhancing the imbibition recovery of the tight sandstone with an increase of about 10%. As the number of fractures increases, the number of oil droplets adsorbed on the core surface decrease and the imbibition rate increases. The imbibition recovery increases with the increase in pore connectivity, while the imbibition rate increases with the increases in core porosity and permeability. The surfactant can improve the core water wettability and reduce the oil−water interfacial tension, reducing the adsorption of oil droplets on the core surface, and improving the core imbibition recovery with an increase of about 15%. In a word, the existence of fractures and surfactants can enhance the pore connectivity of the reservoir, reduce the adsorption of oil droplets on the core surface, and improve the imbibition rate and recovery rate of the tight oil reservoir.

Performance Evaluation of Nanocellulose-Engineered Robust Preformed Particle Gel upon Extrusion Through 1 to 1.5 mm Bead-Packed Porous Media

Summary Preformed particle gel (PPG) holds promising potential for conformance control in fractured tight reservoirs as it enables mitigation of fracture channeling with insignificant leak off to matrix. However, conventional PPG is very susceptible to shrinkage, breakage, fatigue, and even degradation when extruding through narrow fractures due to its weak and brittle network. This hampers its development and application in the oilfields. This paper presents a comprehensive laboratory evaluation of a new kind of nanocellulose (NCF)-engineered robust particle gel (N-PPG) for this application. The results demonstrated that the presence of NCF noticeably improved the mechanical properties of N-PPG. The swelling kinetics and swelling ratio (SR) of N-PPG were almost independent of salinity. We packed porous media using millimeter-sized glass beads to replicate proppant-filled fractures after hydraulic fracturing. As anticipated, N-PPG exhibited a greater resistance factor (Fr) and residual resistance factor (Frr), and its plugging efficiency reached more than 99.3%. N-PPG was hardly broken even after extruding from pore-throat geometries with Dg/Dp up to 21.4, whereas the control PPG was notably ruptured at Dg/Dp = 14.7. Herein, this tough N-PPG could provide a solution to conformance control of fractured tight reservoirs.

Comparison between double caliper, imaging logs, and array sonic log for determining the in-situ stress direction: A case study from the ultra-deep fractured tight sandstone reservoirs, the Cretaceous Bashijiqike Formation in Keshen8 region of Kuqa depression, Tarim Basin, China

The tight sandstone in the Tarim Basin has the characteristics of large burial depth and development of nature fractures due to concentrated in-situ stress. Identifying the present-day in-situ stress orientation is important in hydrocarbon exploration and development, but also a key scientific question in understanding naturally fractured reservoirs. This paper presents a case study where we integrate various methods using wireline and image-log data, to identify present-day in-situ stress direction of ultra-deep fractured tight sandstone reservoirs, in the Kuqa depression. We discuss the formation mechanism of the elliptical borehole, compares the advantages and applicable conditions of the double caliper method, resistivity image logs and array sonic logs method. The well borehole diameter is measured orthogonally, then the ellipse is fitted, and the in-situ stress orientation is identified by the azimuth of the short-axis borehole, but it fails in the borehole expansion section, the fracture development section and the borehole collapse section. The micro-resistivity image logs method reveals the borehole breakouts azimuth, and also the strike of induced fractures, which are used to determine the orientation of in-situ stress. However, under water-based mud conditions, it's hard to distinguish natural fractures from induced fractures by image logs. Under oil-based mud conditions, the induced fractures are difficult to identify due to the compromised image quality. As for the sonic log, shear waves will split when passing through an anisotropic formation, shear waves will split during propagation, and the azimuth of fast shear waves is consistent with the orientation of in-situ stress. However, it is usually affected by the anisotropy caused by the excessively fast rotation of the well log tools, so that the azimuth of fast shear wave cannot effectively reflect the orientation of the in-situ stress. Based on comprehensive assessment and comparison, in this paper we propose a method integrating various logging data to identify the orientation of in-situ stress. Among various types of logging data, the breakouts azimuth identified by image logs is proved to be the most credible in identifying the orientation of in-situ stress, while using the direction of induced fractures under water-based mud conditions is also viable. However, the azimuth of the fast shear wave is consistent with the orientation of maximum in-situ stress only when the rotation speed of the logging tool is low. The caliper method can be used as a reference for verifying the other two methods. Using this integrated method to study the orientation of in-situ stress in the Keshen 8 trap, the results show that faults are an important factor affecting the direction of in-situ stress, while multi-level faults will produce superimposed effects that cause the current direction of in-situ stress to change.

Dual bilinear cohesive zone model-based fluid-driven propagation of multiscale tensile and shear fractures in tight reservoir

PurposeHydrofracturing technology has been widely used in tight oil and gas reservoir exploitation, and the fracture network formed by fracturing is crucial to determining the resources recovery rate. Due to the complexity of fracture network induced by the random morphology and type of fluid-driven fractures, controlling and optimising its mechanisms is challenging. This paper aims to study the types of multiscale mode I/II fractures, the fluid-driven propagation of multiscale tensile and shear fractures need to be studied.Design/methodology/approachA dual bilinear cohesive zone model (CZM) based on energy evolution was introduced to detect the initiation and propagation of fluid-driven tensile and shear fractures. The model overcomes the limitations of classical linear fracture mechanics, such as the stress singularity at the fracture tip, and considers the important role of fracture surface behaviour in the shear activation. The bilinear cohesive criterion based on the energy evolution criterion can reflect the formation mechanism of complex fracture networks objectively and accurately. Considering the hydro-mechanical (HM) coupling and leak-off effects, the combined finite element-discrete element-finite volume approach was introduced and implemented successfully, and the results showed that the models considering HM coupling and leak-off effects could form a more complex fracture network. The multiscale (laboratory- and engineering-scale) Mode I/II fractures can be simulated in hydrofracturing process.FindingsBased on the proposed method, the accuracy and applicability of the algorithm were verified by comparing the analytical solution of KGD and PKN models. The effects of different in situ stresses and flow rates on the dynamic propagation of hydraulic fractures at laboratory and engineering scales were investigated. when the ratio of in situ stress is small, the fracture propagation direction is not affected, and the fracture morphology is a cross-type fracture. When the ratio of in situ stress is relatively large, the propagation direction of the fracture is affected by the maximum in situ stress, and it is more inclined to propagate along the direction of the maximum in situ stress, forming double wing-type fractures. Hydrofracturing tensile and shear fractures were identified, and the distribution and number of each type were obtained. There are fewer hydraulic shear fractures than tensile fractures, and shear fractures appear in the initial stage of fracture propagation and then propagate and distribute around the perforation.Originality/valueThe proposed dual bilinear CZM is effective for simulating the types of Mode I/II fractures and seizing the fluid-driven propagation of multiscale tensile and shear fractures. Practical fracturing process involves the multi-type and multiscale fluid-driven fracture propagation. This study introduces general fluid-driven fracture propagation, which can be extended to the fracture propagation analysis of potential fluid fracturing, such as other liquids or supercritical gases.

Imbibition Characteristic of Fractured Tight Sandstone Reservoir

“Fracture network stimulation + imbibition replacement” is a new attempt to effectively develop tight sandstone reservoirs, and the fractures provide conditions for fluid imbibition replacement. On the basis of nuclear magnetic resonance and pseudo-color processing technology, combined with the imbibition experiments, this paper studies the imbibition process of fractured tight sandstone reservoirs, clarifies the effect of each level of pore-throat on imbibition, and realizes the visualization of the imbibition process. The results show that, in fractured tight sandstone reservoirs, the fluid displacement occurs in fractures first, followed by pore-throat. Most of the imbibition recovery is contributed by the macropore, the contribution of the mesopore to imbibition recovery is very weak, and the contributions of the micropore and the pinhole are even less. In the process of imbibition, capillary force and gravitational force are key parameters controlling fluid flow in pores and fractures. The replacement of fluid normally takes place in the early stage of imbibition, especially on the first day of imbibition, then the imbibition rate gradually decreases and finally tends to be stable.

Nanocellulose-regulated robust particle-gel for conformance improvement in fractured tight reservoirs: A mechanistic investigation of transport behavior and EOR performance in fracture models

Owing to the interpenetration of high-modulus nanocellulose into polyacrylamide (HPAM), the mechanical properties of particle gel were substantially improved. Five transport patterns in fractures were demonstrated as defined by particle/aperture ratio. The pressure drop (ΔP) generated by nanocellulose-regulated particle gel (NPG) depended on particle/fracture ratio, followed by NPG content and strength. A numerical model was established to correlate the stable ΔP of NPG with four critical operating parameters. The placement of NPG significantly remedied the conformance of the fractured cores; therefore, the subsequent CO2 and ultralow IFT surfactant injection processes produced additional oil recoveries of 4.7% and 7.1% original oil in place (OOIP), respectively, with the ultimate oil recoveries of 10.8% and 12.2% OOIP. However, the matrix oil was hardly mobilized during brine injection even after conformance treatment due to the adverse wettability and high capillary pressure.

Techniques for improving fracture-controlled stimulated reservoir volume in ultra-deep fractured tight reservoirs: A case study of Kuqa piedmont clastic reservoirs, Tarim Basin, NW China

Based on analysis of the reasons for low efficiency and low production after fracturing of some wells in the ultra-deep fractured tight reservoirs of the Kuqa piedmont zone, Tarim Basin and the matching relationship between the in-situ stress field and natural fractures, technological methods for creating complex fracture networks are proposed. Through theoretical study and large-scale physical simulation experiments, the mechanical conditions for forming complex fracture network in the Kuqa piedmont ultra-deep reservoirs are determined. The effectiveness of temporary plugging and diversion, and multi-stage fracturing to activate natural fractures and consequently realize multi-stage diversion is verified. The coupling effect of hydraulic fractures and natural fractures activating each other and resulting in “fracture swarms” is observed. These insights provide theoretical support for improving fracture-controlled stimulated reservoir volume (FSRV) in ultra-deep tight reservoirs. In addition, following the concept of volume fracturing technology and based on the results of fracture conductivity experiments of different processes, fracturing technologies such as multi-stage fracture-network acid fracturing, “multi-stage temporary plugging + secondary fracturing”, fracturing of multiple small layers by vertically softness-and-hardness-oriented subdivision, and weighted-fluid refracturing are proposed to increase the FSRV. New environment-friendly weighted-fluid with low cost and new fracturing fluid system with low viscosity and high proppant-carrying capacity are also developed. These techniques have achieved remarkable results in field application.

Experimental study on the controlling factors of frictional coefficient for lost circulation control and formation damage prevention in deep fractured tight reservoir

Working fluids loss is a major contributor to low productivity during production process of fractured tight reservoirs. Lost circulation control effect directly related to the tribological behavior between fracture surface and lost circulation materials (LCMs). In this study, the friction coefficient (FC) was investigated using typical clastic rocks and LCMs by considering multiple effect factors divided into external condition and internal condition. The results show that normal load had a relatively high effect on sliding model. A positive correlation was observed between FC and asperities heights. FC decreased induced by particle size degradation of rigid LCMs. Elastic LCMs manifested higher FC compared with rigid LCMs. Under the lubrication condition by working fluid, FC of rigid LCMs was mainly controlled by their surface wettability. FC of organic LCMs is more sensitive to high temperature aging than inorganic LCMs. Fracture plugging experiments show that LCMs optimized based on the research results can effectively improve the efficiency and strength of fracture plugging. • Friction coefficient tests between the fracture surface and LCMs. • The influence of multiple effect factors on the friction behavior between the fracture surface and LCMs. • The optimization of loss control formula based on laboratory experiments.

An improved response equation of dual laterolog in dual porosity reservoirs and its solution scheme and applications in fractured reservoirs

Many fractured reservoirs are dual porosity reservoirs including matrix pores and fractures, which both contribute to the porosity. However, previous studies either ignored the effect of pores or fractures on dual laterolog, or had special application conditions. Considering the joint contribution of pores and fractures, a response equation of dual laterolog in dual porosity reservoirs is established. First, based on a borehole model with a vertical fracture in dual porosity reservoirs, fracture porosity equations are established in the investigation depths of deep and shallow laterologs, respectively. Using Archie's equations, the response equations of deep and shallow laterolog resistivities are derived, respectively. Then, the response equation, which is similar to the traditional equation of dual laterolog in fractured tight reservoirs, is established. It contains three unknown parameters, i.e. fracture width, fracture cementation exponent and matrix cementation exponent. To solve the equation, a virtual core model is proposed to estimate the fracture cementation exponent by fracture width. The estimation method of matrix cementation exponents is established by empirical formulas. Then, the response equation can be transformed into a nonlinear equation with one unknown parameter of fracture width, and conventional iterative methods can be employed to solve it and obtain the fracture width. Using the response equation and the solution scheme, the change characteristics of fracture cementation exponents in different fractured reservoirs are first analyzed. It shows that the fracture cementation exponents increase with the fracture widths, and they decrease with the increase of the ratio of formation water resistivity to unfractured reservoir resistivity. The applications indicate that the equation and solution scheme can obtain relatively accurate fracture widths quickly in dual porosity reservoirs, and they are recommended for dual porosity reservoirs with high fracture angel (>70°) and low fracture density (<1/3.78 m-1). The findings of this study can help better understanding of the different contributions of fractures and pores to dual laterolog responses in dual porosity reservoirs, and they can provide an alternative solution for evaluating dual porosity reservoirs.

Quantitative Evaluation of Well Performance Affected by Fracture Density and Fracture Connectivity in Fractured Tight Reservoirs

Understanding the relationship between petroleum recovery and characteristics of hydraulic fracture network is a key component of economic development of tight reservoirs. Owing to the limitations inherent in current reservoir simulators, optimization of fracture network has been simply focused on the parameters of fracture conductivity, fracture number, aperture, and so on. Deeper insight into the effect of decisive parameters, such as fracture density and fracture connectivity on the well production in tight reservoirs, is now required to maximize the petroleum recovery. In this work, a newly developed discrete fracture simulator is applied to comprehensively study the effect of fracture density and fracture connectivity in tight reservoirs. Conceptual models with different fracture densities and different fracture connectivity are firstly designed and simulated to explore how these two parameters affect the reservoir behavior and establish the equations for effect measurement. Then, we simulate models with different well placement strategies and a fixed set of natural fractures to determine the optimal strategy. Finally, simulations are performed on a field-scale reservoir with three long fractured horizontal wells. Results demonstrate that increases in either fracture density or fracture connectivity can significantly improve well production. However, an optimal value exists considering the economic profit. Compared to the fracture density, fracture connectivity plays a more important role in affecting the well production. In a tight reservoir with abundant natural fractures, making the horizontal well parallel to the direction of natural fractures is determined to be the optimal well placement strategy. The heterogeneous distribution of remaining oil in real tight oil reservoirs is mainly caused by the heterogeneous distribution of fracture density and fracture connectivity.

Experimental Study on Connection Characteristics of Rough Fractures Induced by Multi-Stage Hydraulic Fracturing in Tight Reservoirs

The well spacing for the development of tight reservoirs by multi-stage fracturing is continuously narrowed. Consequently, interwell interference during fracturing is more and more serious, accompanied by a host of issues in fracturing design and oil and gas production. However, the mechanism of interwell interference during fracturing is not explicit. The corresponding laws of the connectivity of rough fractures during fracturing, which plays a critical role in interwell interference, are not fully understood. In this study, on the basis of characterizing the roughness of fractures, a laboratory evaluation method for fracture connectivity was established. The connectivity characteristics of rough fractures and factors affecting the fracture connectivity are studied. The time and scale effects of fracture connectivity were discussed and their application in interwell interference was analyzed. The results show that the connectivity performance of rough fractures can be characterized by the time for pressure decay. The upstream pressure gradually decreases over time, and the decline rate is related to the fracture aperture, the fracture surface roughness, the contact area of the closed fractures, and liquid properties. Specifically, the decrease in fracture aperture and the increase in fluid viscosity leads to a significant reduction in fracture connectivity. While larger fracture surface roughness and contact area can make fracture connectivity better. The connectivity of the fracture system is one of the significant mechanisms causing interwell interference during fracturing. The connectivity of rough fractures formed during fracturing has remarkable scale and time effects. This study can effectively guide the fracturing design and the evaluation of the impact of fracture connectivity on production.

Simulation of Fracturing and Well Pattern Optimization of Fractured Tight Sandstone Reservoirs

The fracturing and well pattern optimization of fractured reservoirs is a hot spot in petroleum engineering. In this study, taking the tight oil reservoirs of the Yanchang Formation in the Ordos Basin as an example, an optimized plan of hydraulic fracturing and well pattern deployment of the fractured tight reservoir were systematically studied using a fluid-solid coupling model. The results show that the Chang 6 Member of Yanchang Formation mainly develop feldspar sandstone. A large number of vertical fractures are developed in Chang 6 Member, and they have significant shearing properties. The target sandstone reservoir is in the mid-diagenetic A stage. Natural fractures have a significant effect on the extension of hydraulic fractures. When the fracturing direction is parallel to the main strike of natural fractures, the extension distance of the hydraulic fractures is long and the fracturing scale is large; however, when the fracturing direction is orthogonal or oblique to the main strike of natural fractures, the extension distance of the hydraulic fractures is limited. Statistics show that the average length of hydraulic fractures when fracturing parallel to natural fractures is 1.3 times of that when fracturing perpendicular to natural fractures. In addition, after optimization of fracturing parameters, we found that the displacement should be controlled at 2–3 cubic meters/min, and the sand ratio should be controlled at 25%. The smaller the horizontal minimum principal stress difference between the fracturing layer and the shielding layer, the lower the elastic modulus, and the easier it is to control the fracture height. Microseismic monitoring results show that the half-fracture length and fracture height are mainly distributed in 80–140 m and 15–25 m, respectively. The optimized fracture half-length was 120 m and the half-fracture height was 20 m. Finally, the well pattern of the target layer is optimized considering natural fractures. Through this study, we found that the reverse five-spot well pattern is suitable for the efficient development of tight oil reservoirs of the Chang 6 Member in this area.

Physical plugging of lost circulation fractures at microscopic level

Drilling fluid loss into formation fractures is one of the most common and costly problems encountered during the exploration and development of oil and gas resources. At present, the most extensive solution is to use physical lost circulation materials (LCMs) to form high-strength plugging zone in fractures. However, it is still unclear how the plugging is initiated and formed in the fracture. In this paper, a microscopic visualization experimental device for the formation of plugging zone is used to observe the dynamic plugging performance of spherical materials, flaky materials and fibers in fracture. Experimental results show that the formation of fracture plugging zone can be divided into retention stage and plugging stage. Spherical materials have three main retention modes: single-particle straining, dual-particle bridging and multi-particle bridging. Flaky materials assist the retention and plugging of spherical materials through three modes: embedded, intercepted and supported. Fibers take part in the retention of spherical materials through three ways: forming a net at the entrance of the fracture, forming a net after bridging the particle materials, and transverse filling in the fracture. The results achieved in this work provide a basis for the selection and design of LCMs for lost circulation control in deep fractured tight reservoir.

Hydro-mechanical coupling numerical simulation method of multi-scale pores and fractures in tight reservoir

In the fracturing, injection and production of unconventional tight reservoirs, the change of fluid pressure will cause significant changes in effective stress, which will greatly affect the dynamic characteristics of the reservoir. On the basis of the adaptive seepage numerical simulation method for different scale medium of tight oil in the early stage, through the study of the deformation mechanism and deformation law of natural / artificial fractures and matrix pores during the whole life cycle including hydraulic fracturing, production and fluid injection to supplement energy, the dynamic variation models of multi medium geometry, physical properties, conductivity and well index are established, and the multi medium fluid solid coupling dynamic simulation technology is formed. The integrated dynamic simulation of multi-media complex seepage and hydro-mechanical coupling is realized.