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Due to the instability of extracting elastic parameters from conventional elastic impedance variation with incident angle (EVA) pre-stack inversion and the fact that single-trace inversion does not consider the correlation between seismic traces and the lateral continuity of inversion results. An anisotropic total variation multitrace inversion method based on the L P norm constraint is proposed on the basis of EVA inversion. In this paper, the L P norm is used as the regularization constraint, the longitudinal and transverse difference operators are introduced, and the alternating direction multiplier algorithm and the 2D Sylvester equation solver algorithm are used as inversion algorithms to achieve a multitrace inversion of the elastic parameters. The feasibility of the method proposed in this paper is verified by making full use of the advantages of both methods and conducting trial calculations on some blocks of the Marmousi2 model. The method was further validated by applying it to actual data from marine shales of the Longmaxi-Wufeng Formation in the southern Sichuan Basin. The inversion results were validated using a combination of brittleness indices and microseismic monitoring to confirm the feasibility of the method in this paper. •Proposed anisotropic total variation multitrace inversion method based on Lp norm. •Multitrace inversions enhance the lateral continuity of inversion results. •Different noise tests demonstrate the noise immunity of the inversion method. •Validation of the method with brittleness index and microseismic events. [ABSTRACT FROM AUTHOR]

Due to the instability of extracting elastic parameters from conventional elastic impedance variation with incident angle (EVA) pre-stack inversion and the fact that single-trace inversion does not consider the correlation between seismic traces and the lateral continuity of inversion results. An anisotropic total variation multitrace inversion method based on the L P norm constraint is proposed on the basis of EVA inversion. In this paper, the L P norm is used as the regularization constraint, the longitudinal and transverse difference operators are introduced, and the alternating direction multiplier algorithm and the 2D Sylvester equation solver algorithm are used as inversion algorithms to achieve a multitrace inversion of the elastic parameters. The feasibility of the method proposed in this paper is verified by making full use of the advantages of both methods and conducting trial calculations on some blocks of the Marmousi2 model. The method was further validated by applying it to actual data from marine shales of the Longmaxi-Wufeng Formation in the southern Sichuan Basin. The inversion results were validated using a combination of brittleness indices and microseismic monitoring to confirm the feasibility of the method in this paper. •Proposed anisotropic total variation multitrace inversion method based on Lp norm. •Multitrace inversions enhance the lateral continuity of inversion results. •Different noise tests demonstrate the noise immunity of the inversion method. •Validation of the method with brittleness index and microseismic events. [ABSTRACT FROM AUTHOR]

The main target for hydrocarbon exploration of terrestrial strata in Sichuan Basin is the tight gas sandstone reservoir of the Upper Triassic Xujiahe Formation. Xujiahe Formation in YB area is a major discovery of hydrocarbon exploration in recent years, which is characterized as tight with ultralow porosity, ultralow permeability, and intensive heterogeneity. The tectonic fractures have important influence on accumulation and productivity of gas in the area. In the paper, analysis data of outcrop, core, imaging logging and other experiments were used to determine the characteristics, formation periods and genetic mechanisms of tectonic fractures. There are mainly high-angle and low-angle shear fractures in the area, which caused by tectonic stress. The length of the fractures is mainly 0–4 m from the outcrop and 10–20 cm from the cores and fracture frequencies (number per meter) is mostly 2-7 m−1, 2-4 m−1 respectively. The fracture fillings are mainly calcite, argillaceous and carbonaceous, about 60% of the fractures is unfilled or incompletely filled. Without considering the diagenetic fractures, there are three periods of the fractures: the middle-late Yanshanian tectonic movement, the early-middle Himalaya tectonic movement and the late Himalaya tectonic movement. The first period of the fractures are mainly filled with fine calcite, homogenization temperature of inclusion is 75–85 °C and the maximum effective principal stress of paleostress is 71.64 Mpa. The second period of the fractures are half-filled (or unfilled) with coarse calcite, homogenization temperature of inclusion is 150–175 °C and the maximum effective principal stress of paleostress is 74.91 Mpa. The third period of the fractures are low filling degree and cuts formed fractures clearly, the maximum effective principal stress of paleostress is 86.52 Mpa. For these tectonic movement, there are four sets of the plane "X" shear fractures in the area: NE strike fractures, NW strike fractures, NEE strike fractures, S N strike fractures. There are one set of the profile shear fractures of NWW strike. Finally, the complex fault system of nearly N S, NW and NE strike are formed in YB area. • A new method for comprehensive study of the fracture formation period is provided. • The main fracture formation dating of Xujiahe Formation in YB area as follows: 36–176 Ma and 0.2–36.4 Ma. • There are 3 periods tectonic fractures of Xujiahe Formation and formation period of different fracture types is identified. [ABSTRACT FROM AUTHOR]

In the process of hydraulic fracturing of shale gas horizontal wells in the Weiyuan area of Sichuan, China, casing deformation (CD) is a frequent problem that has seriously affected the benefits of shale gas development and remains to be solved for many years. In this paper, based on the analyses of Multi-finger Imaging Tool-24 (MIT-24) data, microseismic data, and the relationship between CD and engineering parameters, we confirm that the wellbore morphology in all CD sections in the Weiyuan area is consistent with shear deformation characteristics and clarify the cause of all CD: hydraulic fracturing leads to increased fluid pressure in well-intersecting faults and large fractures (F-Fs), inducing their shear slip, and eventually leads to asymmetric compression on the casing by strata on both sides of F-Fs, i.e., CD. On this basis, we propose a set of methods to control (or moderate) the shear slip of F-Fs by reducing the additional fluid pressure in target F-Fs during hydraulic fracturing to prevent CD, including multi-cluster perforations, temporary plugging F-Fs and fracturing fluid flowback. We also analyze the theoretical basis, feasibility and workflow of these methods. These methods have been tested in 44 horizontal wells in the Weiyuan area, of which the result is a radical decrease in the CD rate of the single well (from 54% to 9.1%), indicating that the slip of F-Fs and the resulting CD during hydraulic fracturing can be controlled and providing a reference for the prevention of hydraulic fracturing-induced earthquakes. • All CD during hydraulic fracturing of shale gas in the Weiyuan area is caused by induced shear slip of F-Fs. • Temporary plugging can reduce the additional fluid pressure in target F-Fs so as to prevent CD. • The integrated technical methods have been proved to be effective in preventing CD in field application. [ABSTRACT FROM AUTHOR]

Caprock sealing ability is one of the key geological factors to ensure the stable and safe operation of the underground gas storage (UGS). Gypsum salt rock is the high-quality caprock for oil and gas reservoirs, however, the effect of cyclic stress on its sealing capacity is still unclear, which restricts the construction progress of this kind of UGS. Therefore, taking the H UGS in the Sichuan Basin in China as an example, this paper analyzes the initial sealing capacity of gypsum salt caprock using cast thin section, conventional physical property test, nuclear magnetic resonance and breakthrough pressure tests. On this basis, study the variation characteristics of physical and mechanical parameters of gypsum salt caprock under cyclic stress using cyclic stress loading and unloading experiment, and then analyze the evolution law of its sealing capacity. The results show that gypsum salt caprocks of H UGS can be used as a good tight caprock with the porosity less than 1.0%, permeability less than 0.005 mD, breakthrough pressure greater than 6.0 MPa and triaxial compressive strength greater than 210 MPa. In addition, the physical properties of gypsum salt caprock become worse and the sealing capacity increases under cyclic stress, and physical and mechanical changes of gypsum salt caprock mainly occur in the first 30 cycles accounting for about 75%. Moreover, with the increase of cycles, the Poisson's ratio increases by 88% while the change range of elastic modulus is only 6.4%, indicating that gypsum salt caprocks mainly expands laterally and still maintain good elasticity. However, when the cycle times reach a certain threshold of 1002, the cumulative plastic strain of gypsum salt rock will become larger and larger until fracture. And the gypsum salt caprocks can be effective cover in the 184 cycles of loading and unloading with the maximum pressure threshold of 18 MPa and minimum pressure threshold of 1 MPa. This research results can provide theoretical guidance for cap rock stability analysis and operation parameter design of gas reservoir. • The variation characteristics of physical and mechanical parameters of gypsum salt caprock under cyclic stress were analyzed • The gypsum salt caprock is dominant by the compaction of pores and microcracks and mainly occur in the first 30 cycles. • The damage variables are defined from the perspective of energy, and the fatigue life of gypsum rock is 1002 times. • The sealing capacity of the gypsum salt caprock gradually increases with the process of cyclic loading and unloading. [ABSTRACT FROM AUTHOR]

Breakthroughs in shale gas exploration in the Upper Ordovician-Lower Silurian strata of the Upper Yangtze Platform have attracted interest in its sedimentary-tectonic evolution, but the tectonic background of the northern margin of the Upper Yangtze Platform remains unclear. In this paper, the Wufeng-Longmaxi formations on the northern margin of the Upper Yangtze Platform were investigated. Based on geochemical and mineralogical analyses of the tuffs/K-bentonites of the Wufeng Formation and the barite in the Longmaxi Formation, as well as previous research results, it was concluded that the northern margin of the Upper Yangtze Platform was in an extensional tectonic background during the Late Ordovician-Early Silurian. Detailed analysis revealed that, (1) the U–Pb zircon age of the tuff in the Bajiaokou section in South Qinling is 443.91 ± 0.92 Ma. The Zr/TiO 2 –Nb/Y diagram of the tuffs/K-bentonites indicates that their protoliths were alkaline-subalkaline basalt and andesite series rock. Based on the Th–Hf/3-Ta, Th–Tb*3-Ta*2, and TiO 2 –Nb/3-Th diagrams, there are undiscovered intraplate tension calc-alkaline basalts in the northern Yangtze Platform or the southern Qinling region, which provided volcanic clastic materials to the Ziyang, Lan'gao, Chengkou, Yichang and other regions. (2) Scanning electron microscopy revealed that the barite crystals in the Longmaxi Formation exhibit dissolution features and have a large particle size. Energy spectrum analysis of these barite crystals revealed that they have C, O, S, and Ba contents of 8.48 wt%, 22.98 wt%, 13.09 wt% and 55.44 wt%, so they are speculated to have been formed via cold methane seep genesis in a weak extensional tectonic setting. The 87Sr/86Sr ratios of the barite revealed that different types of barite were simultaneously formed in this area under the influences of hydrothermal and cold methane seeps. (3) The analysis of the heavy minerals in the Lower Silurian strata in the Bajiaokou section revealed that the provenance in the South Qinling area changed significantly during the late Early Silurian. Based on the above analyses, the northern margin of the Upper Yangtze Platform was in an extensional tectonic setting during the Late Ordovician-Early Silurian. The distribution of the total organic carbon content indicated that the extensional tectonic background provided good conditions for the enrichment and preservation of organic matter. The results of this study provide an understanding of the regional sedimentary-tectonic pattern and evolution of the Yangtze Platform during this period, as well as a reference for future shale gas exploration in this region. • The tectonic background of the Late Ordovician-Early Silurian was studied. • The northern margin of the Upper Yangtze Platform is an extensional background. • The extensional tectonics caused the cold seepage events. • The extensional fault controlled the distribution of volcanic clastic sediments. • Organic matter accumulation was influenced by the extensional fault depression. [ABSTRACT FROM AUTHOR]

In this paper, the genesis of dolomite in Longwangmiao Formation is analysed through field investigation and geochemical methods, and dolomization model is established, which is very important for the next reservoir prediction in Longwangmiao Formation. According to the crystal size, the Longwangmiao Formation dolomite can be divided into two types: microcrystalline dolomite (MID) and macrocrystalline dolomite (MAD). Both types of dolomite have higher Al content than lime mudstone, indicating that during the deposition process of the Longwangmiao Formation, terrigenous materials are continuously mixed into the sediment, which significantly affects the geochemical characteristics of the Longwangmiao Formation. The rare earth element (REE) composition of the two types of dolomite is consistent with that of lime mudstone (LM), with an obvious δCe positive anomaly and no δEu anomaly, which is a typical distribution pattern of marine carbonate sediments. The microcrystalline dolomite has a higher Na element content, lower δ13C value, and higher δ18O value, suggesting that it is formed in a highly saline evaporation environment. Most of the macrocrystalline dolomite has a residual grain texture. The elements, as well as the isotopic geochemical characteristics of the dolomite, are consistent with those of lime mudstone, indicating that macrocrystalline dolomite is formed early and inherits the geochemical characteristics of the precursor limestone. We believe that the dolomitization model of the Longwangmiao Formation is an evaporative concentration + reflux seepage model. In the late sedimentary period of the Longwangmiao Formation, the sea level declined and a large area of lagoon appeared in the restricted and semi-restricted platform. As the evaporation and concentration continued, precursor minerals such as high-magnesium calcite and aragonite mud experienced chemical precipitation. In this process, a large amount of Ca2+ was consumed, resulting in an increase in the Mg2+/Ca2+ ratio. Then, the precursor minerals underwent dolomitization, and microcrystalline dolomite began to form. At the same time, owing to the difference in density between the high-salinity concentrated seawater and the pore water existing in the early limestone, the concentrated seawater flowed back and penetrated downward, causing the dolomitization of the underlying strata, and then the formation of macrocrystalline dolomite. The degree of dolomitization was mainly affected by the development degree of the granule beach and the thickness of the strata. • The highlights of this article are as follows: • This paper provides a case study of terrigenous clastic dolomite. • This paper analyses the genesis of the dolomites of Longwangmiao Formation and establishes a dolomitization model. • We analysed a large number of samples and provided basic geochemical data for Longwangmiao Formation. [ABSTRACT FROM AUTHOR]

Deep shale gas reservoirs, compared to shallow and intermediate shale gas reservoirs, usually exhibit lower fracture complexity, smaller stimulated volume, poorer conductivity, and faster production decline when the same injection scheme and construction parameters are used. As a result, specific injection scenarios for deep shale reservoirs must be investigated. In this paper, a series of laboratory fracturing tests were conducted to investigate the influence of injection scenarios on deep shale hydraulic fracture initiation and propagation. The black shale of the Lower Silurian Longmaxi formation in the Sichuan Basin was adopted, and four different injection schemes (constant fluid rate injection, cyclic injection, shut-in intermittent injection, and low-frequency pulse pressurization injection) were utilized in these experiments. The energy evolution during hydraulic fracturing with different injection schemes was analyzed by an array of acoustic emission (AE) sensors. Furthermore, the internal fracture geometry of the shale specimens after failure was determined using high-resolution CT scanning. Two parameters, fracture bulk density and fractal dimension were defined to quantitatively characterize the post-pressure fracture complexity. The results indicate that the rock breakdown pressure rises rapidly as the injection rate increases, for conventional monotonic rate injection. Although increasing the injection rate can serve the purpose of increasing the net pressure in the seam and enhancing the fracture complexity, it makes it easier to approach the equipment pressure limit. Unlike conventional hydraulic fracturing, which mainly induces tensile fractures near the wellbore, cyclic fracturing is more likely to cause fatigue damage to the rock, resulting in the formation of subcritical microcracks, which gradually grow into macroscale fractures. In addition, the cyclic injection method can reduce the rock breakdown pressure by approximately 24% compared with the conventional continuous injection method. The shut-in intermittent injection method can also reduce the breakdown pressure of shale by 22%, but this method is not conducive to enhancing the fracture complexity. Pulse fracturing creates the most complex fracture morphology among the four injection schemes tested. The rapid changes in wellbore pressure over a short time can easily result in the formation of multiple fractures around the borehole. Our experimental results and theoretical analysis can provide theoretical support for the optimization of injection schemes for deep shale hydraulic fracturing. • Laboratory tests were conducted to investigate the influence of injection scenarios on deep shale hydraulic fracturing. • All the experiments were monitored by an array of AE sensors. • The internal fractures geometry of the shale specimens after failure was determined by high-resolution CT scanning. • The cyclic fracturing can reduce the breakdown pressure by about 24% compared with the conventional continuous injection method. [ABSTRACT FROM AUTHOR]

High-quality reservoirs in the third member of Lower Triassic Feixianguan Formation in the Jiannan area are exclusively restricted to dolostone, which makes it essential to understand origin of porosity in dolostone. However, the studies on the porosity origin of the dolostone in the Jiannan area are rare, and its origin is still controversial. In the paper, the formation mechanisms of porosity in replacement dolostones ever proposed worldwide are summarized, and they can be divided into two main categories based on the formation time of porosity relative to the dolomitization process: syndolomitization and postdolomitization origin. Studies on well cores that have been dolomitized to varying degrees indicate that the porosity in dolostones in the Jiannan area is a syndolomitization origin which is intimately associated with the dolomitization process, depending mainly on the degrees of dolomitization. Four stages of porosity evolution, each with distinctive petrographic and petrophysical properties, were distinguished. In initial stage of dolomitization (stage I), dolomite was formed mainly by volume for volume replacement with porosity constant or slight decrease due to external carbonate source added. In the next stages of progressive dolomitization (stage II), only minor intercrystalline pores were developed and the porosity slightly increased. In more advanced stage (stage III), abundant intercrystalline, as well as some vuggy pores, were formed by selectively dissolution of residual microcrystalline calcites and micritized grains, and the porosity remarkably increased with increasing dolomite content. In the most advanced stage (stage IV), dolomite cements were precipitated in pre-exiting pores in dolostone, resulting in varying decrease in porosity and permeability. Carbonates that must proceed at least in the stage III have the high porosity, while the dolostones in the stage II-2 that display similar rock frameworks only have a minor increase in porosity. [ABSTRACT FROM AUTHOR]

The volcanic rock with developed pores is important reservoir for oil and gas, but its complex pore-fracture structural characteristics lead to the hydration reaction when the volcanic strata is invaded by drilling fluid or fracturing fluid, which brings great challenges to the drilling operation and oil and gas production in volcanic rock reservoir. In order to understand the influence of clay hydration on the pore characteristics and permeability of different types of volcanic reservoirs. In this paper, we selected distilled water as the imbibition solution, and obtained the variation law of pore structure and physical properties of Permian tuff and basalt in Sichuan Basin during pressurized imbibition through a series of indoor test methods. The results show that the clay content of tuff is high, and the clay hydration produces new cracks during soaking, which leads to the increase of nuclear magnetic porosity of tuff after soaking. At the same time, it also makes some unconnected pores connected with each other, resulting in the increase of rock permeability in the later stage of soaking. During soaking, mineral particles peel off, and some clay minerals are transported to pores and fractures under hydrodynamic action, resulting in the reduction of effective porosity of tuff. The basalt is dense with poor physical properties. There are almost no cracks in the rock soaked for 0–24 h. After soaking for 48 h, new cracks are generated in the rock, which may be caused by the increase of pore pressure in the rock. The mineral particles around the crack obviously fall off and block the pore throat, resulting in the reduction of rock permeability after soaking. This study provides not only helps for avoiding the occurrence of lost circulation, well collapse and other accidents, efficient and safe drilling, but also a theoretical basis for the development of hydraulic fracturing in volcanic reservoirs. • The pore structure and physical properties of volcanic rocks with different soaking time were studied. • The influence of complex pore structure and rock type on the hydration of volcanic rocks is considered. • According to the experimental analysis, the hydration of volcanic rocks is divided into three stages. • The hydration of volcanic rock will produce cracks, accompanied by the spalling of minerals. [ABSTRACT FROM AUTHOR]

An appropriate shut-in after fracturing can dramatically enhance performance of wells in shale gas reservoirs. In this study, a novel wettability index and mineral content curve based shut-in time optimization approach was proposed. First, a new experimental device for spontaneous imbibition of fracturing fluid under the conditions of formation temperature and confining pressure was designed. Then, we conduct a set of experiments on shale samples from the Longmaxi Formation (LF) in the Sichuan Basin to measure the water-wet index and determine the critical value of clay content. Finally, the low-field nuclear magnetic resonance (NMR) equipment was used to monitor the water flow in shale micro-pores, based on this, the shut-in time for different shale reservoirs was optimized. The experimental results show that LF shale hydration can induce new micro-fractures, and the fractures shape is mainly shale bedding fractures, with obvious directionality. The clay content is the key factor affecting water wettability of shale and the critical clay content value of type I and type II shale reservoirs was about 39.5%. The optimal shut-in time of type I and type II shale reservoirs are about 20 days and 15 days respectively. Field application of three wells showed that the average daily gas production was increased by 2–3 times. The research results can guide the development of shale gas reservoirs effectively. • In this paper, the water imbibition experiment of shale under the condition of formation temperature and pressure of shale reservoir was carried out, and the critical clay content affecting the imbibition capacity of shale was determined. • On this basis, the shut-in-time of different reservoirs types was further optimized. • The research results play an important guiding role in understanding the flow law of fracturing fluid in shale reservoirs. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition phenomenon caused by capillarity plays an important role in the production of tight sandstone gas. Understanding the effects of bedding direction on liquid imbibition is important as it can give insights into water block phenomena that can negatively impact gas production. In this paper, four tight sandstone specimens were cored from Sichuan Basin, China with different bedding directions (i.e., the angles between the bedding plane and the horizontal plane of four specimens are 0°, 45°, 60° and 90°, respectively). Nuclear magnetic resonance (NMR) technique was used to monitor the fluid distribution changes during the spontaneous imbibition processes of these specimens. The results show that such tight sandstone exhibited strong hydrophilicity with the small pores dominating throughout the imbibition process. The T 2 spectra for all four rocks specimens not only increased upward but also shifted to larger relaxation times due to brine intake along the minerals surface (further indicating the hydrophilic characteristics of this rock). For such tight sandstone, capillary force and friction resistance between the fluid (brine) and mineral surfaces controlled the imbibition processes. For the 0°, 45° and 60° specimens, "stop illusion" phenomena which the imbibed brine volume had a tiny increase during a long period occurred. However, this was not observed in the 90° specimen (where the bedding direction and fluid flow direction are parallel). This is largely attributed to the significant tortuosity in the flow for the 0°, 45° and 60° specimens compared to the 90° specimen, leading the smallest friction resistance existed in the 90° specimen. Among these four specimens, the 0° specimen had the slowest imbibition rate and lowest imbibition efficiency, while the 90° specimen exhibited the fastest rate and highest efficiency. With the aim of maximizing gas production, this work provides some guidance for the selection of directional fracturing and injection-production methods in the exploitation and production of tight sandstone gas field. [Display omitted] • Rock specimens with different bedding directions were used to conduct the spontaneous imbibition experiments monitored by NMR. • Different imbibition behaviors of four specimens were compared and analyzed. • Driving and resistance forces on the fluid during the experiment were summarized and compared. • The "stop illusion" phenomenon was observed and analyzed. [ABSTRACT FROM AUTHOR]

The Longmaxi Formation has abundant shale gas resources. High-yield wells have been obtained in medium-shallow and deep areas in the Sichuan Basin. Quantitative research on the brittle-ductile change in rocks is a basic geological component for caprock evaluation, and it can also be applied to shale gas exploration. This paper fully considers the difference between the lower shale (N1) and upper shale (N2) of the Longmaxi gas-bearing shale. Through total organic carbon (TOC), mineral components, field emission scanning electron microscopy (FE-SEM), and triaxial mechanics experiments, the two groups of shale samples, N1 and N2, were compared and analyzed, and the brittle-ductile transition was quantitatively studied. Based on previous work, a method for the fast calculation of the key over consolidation ratio (OCR) was proposed. The results show that N1 is mainly organic-rich siliceous shale, N2 is primarily organic-poor clay shale and mixed shale, and N1 is generally more brittle than N2. The key OCRs of N1 and N2 are 2.16 and 2.60, respectively. The key confining pressures at which N1 and N2 become fully ductile are 87.87 MPa and 70.28 MPa, respectively. Therefore, the key depths of the brittle zones of N1 and N2 (H b1 and H b2) and the key depths of the ductile zones of N1 and N2 (H d1 and H d2) are obtained. On this basis, a comprehensive model for the Longmaxi shale gas' brittle-ductile transition exploration zone in the Sichuan Basin and H b1 and H b2 maps of the Longmaxi gas-bearing shale have been established. Through comprehensive vertical and horizontal analysis, Longmaxi shale gas exploration risks in different blocks of the Sichuan Basin have been clarified. Therefore, this study of the variation in the brittle-ductile transition has an important guiding role in refining the exploration of Longmaxi shale gas in the Sichuan Basin. • There are obvious differences between the lower shale and the upper shale. • Difference of brittle-ductile transition makes shale gas exploration more complicated. • The new method can quickly calculate the threshold value of over consolidation ratio. • The new model provides more comprehensive guidance for shale gas exploration. [ABSTRACT FROM AUTHOR]

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas. Nevertheless, due to the lack of engineering and geologic data, as well as the limitations of the existing empirical methods, the current production forecasting methods cannot make reasonable predictions for EUR. Therefore, Duong method is used as the prototype in this paper, a rapid and accurate empirical model for improved production prediction is proposed based on the historical production profile analysis of mass producing wells in Sichuan Basin. The accuracy and universality of the new model are verified by production examples in the Weiyuan, Changning, Luzhou and Yuxi blocks of the Sichuan Basin. The examples illustrate that the new model can be applied well in typical wells, and has no limitation of flow regimes for the production prediction of gas wells. In order to solve the problem of production data fluctuation and decline curve deviation caused by stimulation measures in the production process, a multi-segment production prediction model analysis method is proposed based on the improved model in this study and has been well applied in the field. Most importantly, the new model has clear physical parameters and is easy to operate. Performance of the new model based on production data is as reasonable as the modern production decline methods (including analytical model), which is better than existing empirical methods. • Proposing an improved empirical model, which is rapid and accurate. • Less parameters were selected, the new model still has clear physical meaning. • Application condition of the new model is not limited by the flow regime. • Performance of the new model based on production data is as reasonable as the analytical model. • Multi-segment production prediction model is well applied to gas wells with production data fluctuation. [ABSTRACT FROM AUTHOR]

The ultra-deep dolomite reservoir of the Permian Qixia Formation in northwest Sichuan is important for hydrocarbon reservoirs, but the mechanism of dolomite genesis is complex and has long been controversial, thus requiring further elucidation. By studying the dolomite with different types in the Permian Qixia Formation, northwest Sichuan Basin, this paper, based on outcrop sections observation and core description, seeks to find out the dolomitizing fluids' source and the dolomite's genetic mechanism by analyzing the dolomite's rock-mineral and geochemical characteristics. Various technologies are applied, including rock thin section observation, cathode luminescence, carbon and oxygen isotope analyses, laser ablation-inductively coupled plasma-mass spectrometry (LA-ICP-MS), and inclusion homogenization temperature and salinity. Results show that the dolomite is mainly classified into silty-fine dolomite (Md1), fine-medium dolomite (Md2), medium-coarse dolomite (Md3), and saddle dolomite (SD) filled in the pores. Md1 is formed in the early shallow-burial stage; the dolomitizing fluids are mainly derived from the early seawater sealed in carbonate sediments; and the penesaline seawater is formed by the seepage reflux under a moderate evaporitic environment. Md2 and Md3 are formed in the middle and late shallow-burial stages. Of these two types, Md2 is formed earlier, and the dolomitizing fluids are primarily derived from the seawater sealed in the early stage and partially derived from the residual evaporated seawater and hydrothermal fluids. In contrast, Md3 is formed later, and the dolomitizing fluids are the mixture of the seawater sealed in the early stage and the hydrothermal fluids formed in the late stage. In addition, Md3 was affected by the hydrothermal process more significantly during the formation. SD is deposited and formed when the saturated hydrotherm upwells along with the fracture system in the late stage. This study provides a significant reference for understanding the source and action mechanism of multi-stage dolomitizing fluids and expands the exploration field of the deep dolomite reservoir. • The precise microanalysis is conducted on the dolomite of different grain sizes by the LA-ICP-MS technology. • The geochemical characteristics of dolomites show the trend of continuous and progressive. • Dolomite fluids come from the normal seawater, penesaline seawater. and hydrothermal fluids. [ABSTRACT FROM AUTHOR]

The upper Permian Longtan Formation (LTF) shale is a new shale gas exploration and development focus in China, which was formed in a transitional depositional environment. Because of the difference in the sedimentary environment between marine-continental transitional shale and marine shale, the enrichment characteristics and mechanism of organic matter (OM) are very different. Because of a weak research foundation, the enrichment mechanism of OM in the LTF shale in the Sichuan Basin is still unclear. In this paper, shale samples of the upper Permian LTF from the Well F5 were collected, and the abundance, source and sedimentary environment of organic matter were studied by using paleoclimate, detrital input, redox, paleoproductivity and sedimentation rate parameters. The results show that the TOC content of the LTF shale is high (average = 3.04%) and reaches the high to overmature stage (average = 2.46%), indicating a favorable source rock. The LTF shale was deposited in a humid and hot climate, which was conducive to the growth and prosperity of a large number of plants. The source of organic matter was mainly terrestrial plant fragments. The sedimentary environment of the LTF shale was oxic, it had a high sedimentation rate, which reduced the oxidation rate of OM, promoted the rapid deposition of OM, and ensured the preservation of organic matter. In summary, the enrichment of OM of LTF shale in the Sichuan Basin was affected by the sedimentary environment, which was complicated. The main controlling factors were detrital input, redox conditions and sedimentation rate. • The geochemical characteristics of Permian Longtan Formation (PLTF) shale in eastern Sichuan are analyzed. • The sedimentary paleoenvironment of PLTF shale in eastern Sichuan is reconstructed. • The main controlling factors of organic matter enrichment of PLTF in eastern Sichuan are studied for the first time. [ABSTRACT FROM AUTHOR]

The propagation characteristics and influencing factors of hydraulic fractures can be analyzed through fracturing experiments. However, there are almost no fracturing experiments in which acid fluids were considered, for the acid resistance of the equipment is always imperfect. In this paper, a physical modeling experimental equipment for acid fracturing was designed and introduced, in which corrosion protection and alternate injection were realized. The carbonate rock for acid fracturing experiment was collected from Sichuan Basin, China, which was tight with a little cavity developed. Acid fracturing experiments, in which HCL, guanidine gum and guanidine gum with an acid fluid were used as the fracturing fluids, were conducted to analyze the characteristic of acid-etched fractures. The results showed that: Acid fluid etched the fracture surface, especially in the near-wellbore area; Acid fluid would open microfractures and pores easily, and leaked into these spaces, which decreased the propagation distance of the primary acid-etched fracture; High viscosity guanidine gum was first injected and then with low viscosity acid fluid, then the latter one was transported to distal area by viscous fingering, which would lead to a better fracturing effect; Due to the acid-rock reaction, the morphology of acid-etched fracture was obviously different from hydraulic fracture, and two kinds of acid-etched fracture morphology were proposed according to the sequence of acid fluid and guanidine gum. In this paper, the characteristics of acid-etched fractures were investigated by four groups of acid fracturing experiments, which could provide a reference to optimize acid fracturing effect. • An improved acid fracturing physical modeling experimental equipment in which acid injection is allowed is developed. • Peculiar mechanical characteristics in acid fracturing are investigated and compared with hydraulic fracturing. [ABSTRACT FROM AUTHOR]

The lamellation fractures in marine shales are important to the accumulation and preservation of shale gas, whose characteristics and controlling factors are still unclear. This paper focus on the characteristics descriptions and controlling factor analyses based on core observations, thin sections, and scanning electron microscope (SEM) experiments. The marine shales of Paleozoic Wufeng Formation and Longmaxi Formation in the Fuling Area of Eastern Sichuan Basin are taken as an instance. The lamellation fractures are occurring along the direction of the lamellations, partially of them curved, bifurcated, and converged. The apertures of fractures typically range from 1 to 500 μm. Only a few (<1%) lamellation fractures are filled with quartz, calcite, pyrite, and bitumen. After a series of analyses, developments of lamellation fractures are controlled by total organic carbon (TOC), brittle minerals, laminae, and pyrite. (1) The organic matters control the formation and evolution of lamellation fractures by generating gas and resulting in overpressure. An increase in the TOC content of 1% can increase the lamellation fracture density by 0.26 cm-1. (2) Brittle minerals, especially authigenic quartz, is also an important controlling factor to the development of lamellation fractures. When BI increases by 10%, the lamellation fracture density increases by 19%. (3) Besides, siliceous and carbonate laminae in the shale are more suitable for lamellation fractures to develop. When the laminae density is smaller than 4 cm−1, it is easier to develop lamellation fractures with higher laminae density. However, too densely-distributed laminae will suppress the formation of lamellation fractures. (4) Higher pyrite content is good for the development of lamellation fractures. Lamellation fracture density will increase by 9%, with pyrite content increased by 1%. For the shale at the bottom of the Wufeng Formation - Longmaxi Formation, lamellation fractures develop extensively due to the high TOC and pyrite content, great brittleness, and moderate laminae density. The density of lamellation fractures decreases from the bottom to the top. • Quantitative characterize about development characteristics of the lamellation fractures. • The lamellation fractures is controlled by brittle mineral, TOC, laminae and pyrite. • TOC is the main one that affects the development of lamellation fractures. • Clarify vertical distribution characteristic of lamellation fractures in the Wufeng-longmaxi Fm. [ABSTRACT FROM AUTHOR]

In this paper, the original nature of organic matters is introduced for the first time to reevaluate the lower Permian (P 1) source rocks. The carbonate rocks in Maokou Formation (P 1 m) whose high organic carbon values were caused by external asphalt have poor hydrocarbon generation ability, but the argillaceous rocks in P 1 m have some, especially the recent discovered black shale in Gufeng deep-water facies in the north have good hydrocarbon generation ability. The black shale is 5–20 m thick and the measured average value of organic carbon can reach up to 7.24 wt%, which can greatly increase the hydrocarbon generation capacity in the north; The studies of natural gas sources of the lower Permian in eastern Sichuan basin show that the contribution of gas source is mainly Silurian. In the north, the lower Permian source rock is supplemented, while in the south, it's greatly affected by the coal-measure source rocks of Longtan Formation (P 2 l); Take the Wutan-1 well in Tanmuchang as an example to dissect the reservoir in syncline area. The Wutan-1 well has a tested daily production of more than 80 × 104 m3, and the paleotectonic evolution history shows that it was in the high position of the structure during the generation and expulsion peak of hydrocarbon. The fracture-vuggy lithologic reservoir of Wutan-1 well is favorable for hydrocarbon capture and later preservation. According to the above, the Tanmuchang syncline has a good spatio-temporal matching relationship, which is the key to hydrocarbon accumulation and exploration. This knowledge has expanded the exploration area of the Lower Permian Maokou Formation in eastern Sichuan, and more importantly, it brings much enlightenment to the exploration of the syncline areas in Sichuan basin and other basins at home and abroad. • The original nature of organic matters is introduced for the first time to reevaluate the lower Permian source rocks. • The black shale in Gufeng deep-water facies has hydrocarbon generation capacity in the north of the eastern Sichuan Basin. • The sources of natural gas in Maokou Formation are different between the north and the south in the eastern Sichuan Basin. • The syncline area of the Lower Permian Maokou Formation in eastern Sichuan has the potential for gas accumulation. [ABSTRACT FROM AUTHOR]

The Northwestern Sichuan Basin is a hot spot for natural gas exploration, and in recent years, many wells have obtained high-yield commercial gas flows in the Qixia Formation. However, due to the influence of foreland orogeny, the oil and gas in the Qixia Formation often have the characteristics of multisource filling, multistage accumulation and multistage transformation, which results in an unclear understanding of the gas source and the accumulation process. This paper uses the concept of sub-block research through carbon isotope and biomarkers analyses, to carry out gas-gas, gas-source and bitumen-source rock comparisons in different structural belts to determine the natural gas sources. On this basis, basin simulation and fluid inclusion analysis technology are used to determine the stage of hydrocarbon accumulation, and then the accumulation process is determined. Studies have shown that the gas source of the Qixia Formation are different in the different structural belts: (1) The natural gas from the Qixia Formation in the thrust nappe belt mainly originates from the Qiongzhusi Formation source rock; (2) The natural gas from the Qixia Formation in the hidden fault belt is a mixture of the source rock of the Qixia Formation and the source rock of the Qiongzhusi Formation; and (3) The natural gas from the Qixia Formation in the gentle belt mainly originates from the Middle Permian source rock and the Upper Permian Longtan Formation source rock. The Indosinian, Yanshania, and Himalayan movements all have great influence on the formation of the Qixia Formation reservoir in northwestern Sichuan, and the accumulation process of the different structural belts is quite different, but generally, the accumulation process of the different structural belts have experienced three stages: a primary oil pool stage, gas pool stage and reformation and definition stage. • Through sub-block research, gas source of the foreland thrust belt is studied. • Different gas sources cause differences in carbon isotopes. • Accumulation process of each structural belt is distinct. • The results have implications for exploration in complex tectonic areas. [ABSTRACT FROM AUTHOR]

Fractures gradually open under the action of fluid pressure in drilling shale gas reservoirs because of the existence of shale natural fractures, which leads to the leakage of expansible fractures. Induced fracture leakage is difficult to find and control in the early stage of drilling, resulting in great economic losses. The current model of induced fracture leakage pressure model is based on takes rock fracture criterion, which can only be used to judge whether the fracture is fractures created or not but cannot analyze the influence of fracture width change on leakage pressure after natural fracture of shale cracking. In addition, the model cannot control the occurrence of leakage. In this paper, the calculation method of fracture's width change under induced pressure is established. According to the field leakage rate data, a dynamic model of leakage pressure is established based on the parameters of time, leakage rate, fracture's width, fluid viscosity, and wellbore radius. The model is applied to calculate the dynamic change of leakage pressure on the Sichuan Shale Gas Field site and control the induced fracture's change to control leakage. Results show the following observations. (i) The fracture's width and leakage velocity of induced fracture increase with the increase of leakage pressure. Blocking the leakage when any leakage is found on the site is not advisable because it can increase the fracture's width artificially and increase leakage. (ii) The critical value of the fracture's width may cause severe leakage. When the leakage's differential pressure remains unchanged, the relationship between the fracture's width and leakage velocity refers to the power exponent change. The method of controlling the leakage pressure and reducing the fracture's width that is less than the critical leakage fracture degree is adopted for the leakage of the shale gas drilling in the Longmaxi Formation field Jiaoshiba, which effectively reduces the leakage amount. Taking a particular project, for example, controlling leakage pressure of induced fracture is given to verify the feasibility of the method. • The calculation method of fracture's width change under induced pressure is established. • A modal of leakage pressure is established based on time,leakage rate,fracture's width,and fluid viscosity. • The method of controlling the pressure to reduce the fracture's width to control the leakage is established. [ABSTRACT FROM AUTHOR]

The prediction of pore pressure in subsurface formations is important for the estimation of hydrocarbon accumulation and for safe drilling activities. Typically, pore pressure is estimated from either well logs (e.g., P-wave velocity, resistivity) or seismic data (seismic velocities, acoustic impedance) using empirical relations based on compaction laws. Due to the high density and extremely heterogeneous physical properties, it's not feasible to calculated pore pressure in carbonate rocks with these empirical methods. The result of ultrasonic velocity measurements in carbonate rocks shows that velocity is affected by multiple factors, e.g., stress condition, porosity, rock composition, fluid composition, and other rock properties. It's practicable to predict pore pressure with velocity when other factors are kept constant or evaluated quantitatively. In this paper, a quantitative model to compute the elastic attributes as a function of pressure and petrophysical properties is proposed. The model as a rock physical model is based on the poroelasticity theory and describes the effect on the elastic property of stress conditions. The model is validated using laboratory measurements. A case study for this model application from the northeastern Sichuan Basin, including a set of well logs and borehole measurements is also presented. The pore pressure gradient in carbonate reservoirs is ranging from 0.99 to 2.13 MPa/100 m. The predicted result shows the relative error between model predictions and observations measured while drilling is from 0.60% to 10.22%. The method proposed in this study is effective for pore pressure prediction in carbonate formation. • Pore pressure in carbonate rocks is estimated by a new rock physical model. • The model is validated by laboratory measurements and tested using well-logging data. • The model can be considered as a new tool to predict overpressure in carbonate rocks. [ABSTRACT FROM AUTHOR]

The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudo-gamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system. • The high energy dolomitic facies is the best reservoir in the ultra-deep giant Yuanba Gas Field. • The tight reef-shoal reservoir are successfully characterized using integrated method. • Pseudo-acoustic impedance inversion is an effective tool identifying the best reservoir body. [ABSTRACT FROM AUTHOR]

The multilayered deposition is the main feature of the XC gas reservoir in the northwestern Sichuan Basin. The boundaries among layers of the XC gas reservoir is different. In this paper, we propose an extended pressure transient analysis model for vertical commingle well, considering different boundary radii and boundary types, to capture the Vertical Combined Boundary (VCB) effect on the pressure transient behavior and flow regime characteristics. The analytical solution is yielded by the Laplace transform, Bessel functions, Duhamel's superposition principle, and Stehfest inversion algorithm, and new flow regimes under different boundary combinations are identified by the pressure derivative curve. Taking the dual-layer VCB model as a type example, nine combinations of boundaries are analyzed. Compared with the current vertical commingled well model with the same boundary radii or single boundary types, this model has novel flow regimes controlled by the VCB. The research results indicate that the pressure derivative type curve during the novel flow regimes stage can diagnosis the VCB type. On the one hand, there are quantitative linear relationships between the pressure derivative feature value and interlayer heterogeneity of the VCB model with the same boundary radii. These linear relationships provide a new perspective to quickly capture interlay heterogeneity through the of the pressure derivative feature value. One the other hand, the pressure behavior and flow regimes of the VCB model with different boundary radii obey the successive superposition rule. This rule provides a method to recognize the VCB type with different boundary radii based on that of the VCB with the same boundary radii. Finally, a field case from the northwestern Sichuan Basin gas reservoir is discussed in detail to exhibit the workflow of our model application and validate the capability of our model. • An extended PTA model of vertical layered commingled reservoir with Vertical Combined Boundary (VCB) is established. • The novel VCB flow is identified and mathematical relation between pressure behavior and vertical-heterogeneity are found. • The quantitative mathematical relationships provide a fast way to capture the vertical-heterogeneity. [ABSTRACT FROM AUTHOR]

The current fluid imbibition models used in shale usually assume a pore shape to be circular, whereas the pore shapes significantly deviate from that. One approach to correct this deviation is to introduce a pore shape factor into the models although it is challenging. This paper provides a way to calculate the specific shape factors of irregular inorganic and organic pores in shale based on SEM images analyses. Then, combining with the percentages of the organic and inorganic pores, a group of weighted-average pore shape factors of Longmaxi shale samples was calculated (0.587～0.667). Another group of pore shape factors (0.359～0.615) was also matched from the shale fluid imbibition curves, close to the previous values, which confirmed the validity of the proposed method. This work may provide an effective support in exploring the fluid imbibition or flow mechanisms in shale, especially considering the strong pore wall effects under nano-scale. • A method is provided to calculate the shape factors of irregular inorganic and organic pores. • The pore shape factor of organic pores is commonly higher than that of inorganic pores. • Ignoring the pore shape factor may cause an overestimation in fluid imbibition volume prediction. [ABSTRACT FROM AUTHOR]

The Lower Paleozoic Ordovician Wufeng Formation and the Silurian Longmaxi Formation shale in the southeastern part of Sichuan Basin in China are the key strata for shale gas exploration. In this paper, based on a large number of outcrops, cores and natural gamma spectroscopy logs combined with scanning electron microscopy, geochemical parameter testing and mineral component analysis, the geological conditions and exploration potential of shale gas accumulation were studied in this area, and the relationship between structure and shale gas preservation is discussed. The vertical reduction in the U/Th ratio measured in the outcrop sandstone lenses and core horizontal bedding and observed in the energy spectrum logs indicates that the sedimentary water body transformed from a low-energy anoxic reducing environment to a high-energy oxidizing environment. The TI index and the kerogen carbon isotope indicate that the organic matter type of the shale is mainly type I kerogen. The TOC content of high-quality shale is generally above 2.50%, and the R o value is between 2.00% and 3.08%. High organic matter abundance, moderate thermal evolution and a large thickness of high-quality shale ensure an adequate supply of hydrocarbon resources. Multiple types of inorganic pores, primary organic pores and pores formed during hydrocarbon generation provide abundant reservoir space for the enrichment of shale gas. The tectonics have an important influence on the preservation of shale gas. Moderate fracture development, a late tectonic uplift time, small-scale tectonic uplift, and high formation pressure coefficient are conducive to the preservation of shale gas, and the gas content and productivity will be higher. Overall, a structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. • Comprehensive analysis the sedimentary environment based on three scales: outcrop, core and energy spectrum logging. • Later and small-scale tectonic uplift, moderate fracture development, good roof preservation are conducive to gas enrichment. • A structural stability zone with a high formation pressure coefficient is a favorable area for shale gas exploration. [ABSTRACT FROM AUTHOR]

The initial water saturation of shale reservoirs is in general lower than the irreducible water saturation. However, the hydraulic fracture network region is highly saturated by fracturing fluid, which results in a two-phase flow inside fractured region. A long-time two-phase flow period is always observed in the fields even after a high flowback rate, which cannot be explained by existing models. In this paper, we develop a 2D gas-water flow model coupling multi-scale discrete fractures and continuum framework to describe the flowback process of a multi-stage fractured horizontal well in shale gas reservoirs. The model considers the non-linear flow mechanism of free gas, desorption of adsorbed gas and the co-existence of single gas flow and gas-water flow. The capillary pressure model and relative permeability model are both employed with different parameter values for matrix and fractures, respectively. The permeability of naturally fractured shale is described using a fractal model. To overcome non-convergence problem of finite element method for solving two-phase flow in cross fractures, the model is solved by finite element method and finite volume method. The model is verified through a simple two-phase flow simulation and a single gas phase simulation with some simplifications. Then the model is used for history matching as well as production prediction of a well in Changning block, Sichuan, China. The simulation results show that the high water saturation induced "skin factor" in the vicinity of hydraulic fractures significantly delays the gas production for a long time because some of the fracturing fluids become irreducible water and lower the gas phase permeability. Due to the great influence of fracture interference on water flow, the fracturing fluids concentrate on regions near hydraulic fractures and their junctions. The long-term gas production of the complex fracture network is slightly higher than that of the simple fracture network, which is different with the simulation results of single gas flow model. • A physical model where the gas-water coexists with single gas flow is built. • The viscous flow, Knudsen diffusion and adsorption / desorption phenomenon are considered of the gas flow in shale matrix. • The finite element method (FEM) and the finite volume method (FVM) are employed to solve the mathematical model. • The flowback and production process can be simulated continuously. [ABSTRACT FROM AUTHOR]

Permeability jails in tight rocks correspond to saturation values where no phase is mobile. This can lead to severe impacts on hydrocarbon production. However, although this is a severe and significant problem, there is a limited understanding of the mechanisms behind the concept of a permeability jail, its dependence on pore size distributions, saturations and pressure. In a previous work, we describe a model to compute the flow resistance during two-phase flow in tight rocks. In this paper, we extend our work to propose a model for the permeability jail in tight rocks to calculate relative permeabilities during two-phase flow. The rock is assumed to be characterized by a bundle of capillary tubes with non-uniform radii where the fluids are present as discontinuous phases. The pore-scale flow resistance is calculated which takes into account the capillary pressure induced by the Jamin effect as well as the water and gas viscous forces. The model is validated by experimental data of gas-water relative permeability tests and Nuclear Magnetic Resonance (NMR) experiments on tight cores from the Sichuan Basin in Southwest China. According to the model, the pressure drop between the inlet and outlet sides of the core should be higher than the maximum capillary pressure to maintain flow during the experiments. We also observe that the relative permeability curves are pressure-sensitive. An increase in the pressure drop leads to a reduction of gas relative permeability and an increase of water relative permeability. However, the influence of this pressure drop is somewhat limited. Once trapped in a permeability jail, fluids generally cannot regain flow capability by changing the pressure drop over a small range of values. This necessitates a careful consideration of the factors contributing to the permeability jail in order to avoid loss of well productivity. • We propose a mathematical model of the permeability jail that can predict relative permeabilities for two-phase flow. • The model is validated using data from gas-water relative permeability tests and NMR experiments.. • The formulation allows for easy calculation of the pressure-sensitivity of the relative permeability curves in tight rocks.. [ABSTRACT FROM AUTHOR]