Development Of Tight Gas Reservoirs Research Articles

Optimization of tight gas reservoir fracturing parameters via gradient boosting regression modeling

In China, the exploitation of most unconventional oil and gas reservoirs is dependent on hydraulic fracturing, which is a key method employed when developing tight gas formations. Numerous scholars and field engineers, both domestically and internationally, have conducted extensive numerical simulations and physical experiments to study crack propagation and predict post-fracturing productivity in hydraulic fracturing. Although some progress has been reported in this regard, it is difficult to accurately predict the well productivity using mechanistic models owing to the vertical multilayered development of tight gas reservoirs. In this study, vertical fractured wells in a block of Sulige gas field were examined. The block relied on hydraulic fracturing to produce tight gases. However, as development progressed, the available reservoir environment deteriorated, large differences emerged between wells after fracturing, and the fracturing results did not meet the expectations. In this study, geological, construction, and generation data for this block that had been collected since 2007 were analyzed. After applying multiple machine-learning methods to filter outliers and fill in missing values, k-means clustering, classification enhancement, extreme gradient enhancement, and LightGBM algorithms were used to establish a regression model. The analysis results revealed that the regression accuracy of the cluster test set was as high as 70% and that the LightGBM model had the best regression effect among the 227 stripper wells in the block. After optimizing the fracturing construction parameters (fracturing fluid volume, proppant volume, liquid-nitrogen volume, and pumping rate), the average fracturing fluid and liquid-nitrogen volumes per well decreased, whereas the unit reservoir proppant and liquid-nitrogen volumes increased. The results also revealed that 182 wells showed an improved initial production capacity during fracturing. The average gas production index per meter increased by 22.04%. This approach enabled rapid and efficient production forecasting and construction optimization. Moreover, this represents a novel fracture design method that is applicable to onsite engineers in tight gas production fields in the Ordos region.

Characteristics of Tight Gas Reservoirs in the Xujiahe Formation in the Western Sichuan Depression: A Systematic Review

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration.

Tectonic movements of the Yanshan-Himalayan period in the northern Longmenshan and their impact on tight gas accumulation of the Shaximiao formation in the Qiulin structure, China

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Mitigating Interwell Fracturing Interference: Numerical Investigation of Parent Well Depletion Affecting Infill Well Stimulation

Abstract Frac hits were not unfamiliar in tight gas development. During the hydraulic fracturing process in infill well, due to closely spaced wells and parent well depletion, operators often encounter fracture interference between the parent well and infill well, resulting in frac hits. This phenomenon typically has a significant impact on the productivity of both infill and parent wells. However, effectively mitigating and minimizing the negative effects of frac hits continues to pose a formidable challenge. Therefore, we developed a new frac hits evaluation and management workflow, aiming to investigate the mechanism of frac hits between infill well and parent well and improve the performance of the infill well while avoiding frac hits. The results indicate that an increased extent of parent well depletion leads to higher surrounding rock pressure and stress depletion. The stress deflection region near the fracture tip of the parent well attracts the propagation of infill well fractures, resulting in frac hits and significantly affecting the performance of the parent well. Consequently, optimizing the timing of hydraulic fracturing in the infill well is beneficial to mitigate parent well depletion, controlling frac hits and enhancing gas well productivity. This research provides important insights for mitigating parent–infill well interference in the development of tight gas reservoirs and establishes a solid foundation for future studies.

Study on Economic and Efficient Completion Design of Tight Gas Reservoir

Tight gas reservoirs in Daqing Oilfield has the characteristics of deep burial, high temperature and high pressure, and the produced natural gas generally contains CO2. At present, the production casing and tubing of the tight gas reservoir are completed with 13Cr110 material, which has high cost, but the gas production is low, and it declines very fast, so the economic benefit is poor. In order to reduce cost and increase the efficiency, it is necessary to explore a new well completion method in tight gas reservoir. We study the corrosion law of different materials through laboratory experiments, and finally determine that the production casing adopts the assembly method, material of production tubing next to the production packer is 13Cr, other parts are ordinary carbon steel. The tubing and downhole tools are made of carbon steel, and the casing and tubing annulus are injected with annulus protection fluid for corrosion protection. With the comprehensive analysis, this completion method can meet the requirements of gas well corrosion prevention and production. After 20 years of development, the well construction cost of a single well has been reduced by 79% to 7.553 million RMB. The effective implementation of this design can provide reference for the subsequent development of tight gas reservoir in Daqing Oilfield.

Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation

The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry.

CO2-assisted technologies for the development of tight gas reservoirs: The implication on CCUS

OPINION article Front. Energy Res., 19 January 2023Sec. Carbon Capture, Utilization and Storage Volume 10 - 2022 | https://doi.org/10.3389/fenrg.2022.1102774

Morphological and petrophysical evaluation of tight gas resources and energy production in Pakistan

Tight gas is a highly potential source of energy that can meet the energy deficit in Pakistan. The production of gas from conventional gas reserves are continuously declining in a massive manner and increasing demand of hydrocarbons as an energy source is soaring at huge levels. Therefore, the energy deficit can only be met through tight gas unconventional sources of energy. Tight gas is a natural gas having very low permeability and marginable matrix porosity which extends diversely into the geological formations of Pakistan. That is the major reason of huge level of uncertainty for development of tight gas reservoirs. However, the production mechanism of tight gas reservoirs is too much difficult and complex as compared to conventional resources of hydrocarbons. Hence, the tight gas resources are equivocal and debatable regarding the sustainability and utilization. This paper provides a systematic study on the tight gas reservoirs through petro-physical evaluation of outcrop samples of tight rocks. In this regard, an experimental study is carried out on outcrops of tight gas near Chilton formation Indus basin trough and different techniques namely SEM (Scanning Electron Microscopy), AFM (Atomic Force Microscopy) have been employed to evaluate the permeability, porosity and fluid saturation. Furthermore, simulation studies on the core flooding in the close packed outcrop samples have been performed in order to estimate the permeability reduction caused by different phases.

Geochemical characteristics of diagenetic fluid and densification model of tight gas sandstone reservoirs in Linxing area, eastern margin of Ordos Basin, China

Quasi-continuous tight gas sandstone reservoirs have been discovered widely in the eastern margin of Ordos Basin (Linxing area) within the marine-continent transitional strata in the upper Paleozoic. Differences in formation water chemical properties, water-rock reactions, and diagenetic evolutions between the Taiyuan Formation and the Lower and Upper Shihezi Formations are attributed to various degrees of densification of sandstones, which significantly restrain the exploration and development of tight gas reservoirs. This study utilizes the petrographic features, electron probe, X-ray diffraction, and chemical properties of formation water to establish the diagenetic sequence of tight sandstone reservoirs and finds that the diagenetic systems of the Taiyuan Fm. were more closed than those of the Shihezi Fms., with enrichments in Ca2+and depletions in Mg2+ and Fe2+. Here, we suggest that the dissolution of feldspars and rock fragments, the siliceous cementation, and the transformation of clay minerals are controlled by the K+/H+ ratios of the formation water. In the Taiyuan Fm., the low K+/H+ ratios resulted in a complete illitization reaction in the closed CaCl2 type formation water, and the migration rate of K+ controlled the proportion of the illite contents in the open NaHCO3 type formation water. In the Lower Shihezi Fm., the rapid consumption of H+ caused the elevation of the K+/H+ ratios, leading to the cease of illitization reaction and preservation of kaolinites and K-feldspars. In the Upper Shihezi Fm., the illitization reaction was inefficient, and smectites were transformed to chlorites. Hence, differentiated sandstone densification models are established to characterize different water-rock reaction systems. Typically, clay minerals and ferrous carbonate cements could form seepage barriers around the thick sandstone layers and promote the formation of independent closed high-pressure micro-diagenetic systems. Consequently, the overpressured reservoirs that underwent relatively weak compaction, dissolution, and cementation (Type Ⅰ) and the chlorite-enriched overpressured reservoirs (Type Ⅱ) tend to preserve partially primary pores and form secondary pores, which should be treated as the “sweet spot” target area for the further exploration of tight gas.

Calculation Model of Relative Permeability in Tight Sandstone Gas Reservoir with Stress Sensitivity

During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.

Investigate on mechanism of nanofluid drainage gas recovery in tight gas reservoir

Conventional drainage gas recovery and water-controlled gas recovery technologies are difficult to meet the needs of tight gas reservoirs. In order to solve this problem, nanofluid for drainage gas recovery was proposed to improve the effect of tight gas reservoir development. In this paper, the phase inversion method was used to prepare nanofluid with small particle size. Nanofluid could change the core surface characteristics, improve the drainage effect, and prolong its validity period. The influences of nanofluid on the gas-water flow in tight core and core surface properties have been systematically investigated by the experiments. The mechanism of the drainage gas recovery was discussed. The results showed that nanofluid with different mass concentrations can shift the isotonic point of gas-water relative permeability to the left (58.65%→54.78%@6.25 wt%, 56.49→54.66%@100wt%), reduce the irreducible water saturation (38.35→29.51%@6.25 wt%, 51.75→47.01%@100wt%), greatly increase the water relative permeability (63.79%@6.25 wt%, 100%@100wt%) and slightly reduce gas relative permeability (9.80%@6.25 wt%, 13.04%@100wt%), which has a significant drainage effect. A dense hydrophobic film was formed on the tight core surface to change its microstructure and wettability, which can achieve drainage gas recovery. Nanofluid will have a broad application in tight oil and gas reservoir stimulations.

Key Technologies for Drilling and Completing Horizontal Wells with Ultra Long Horizontal Section of Sulige Tight Gas Reservoir

Aiming at the technical difficulties such as high circulating pump pressure, high friction torque, low ROP, difficulty in hole cleaning and running in completion casing string running in the ultra-long horizontal section of tight gas reservoir in Sulige Gas Field, this paper analyzes the drilling technical difficulties in the ultra-long horizontal section from the aspects of safe extension of the long horizontal section, hole cleaning, friction and drag reduction and safe running of the completion string, such as optimized allocation of high-efficiency drilling equipment, optimized design of well trajectory, optimized application of drilling acceleration tools, RSS technology, high-efficiency, strong inhibition lubrication water-based drilling fluid and rotary guide shoe + casing floating running technology. The key technologies of drilling and completing ultra long horizontal well for tight gas reservoir in Sulige Gas Field have been formed, which have been applied in 2 wells, with an average well depth of 7 027 m, an average horizontal section length of 3 719.5 m, and drilling cycle of 50.93 d. Between them, Jing50-26H1 Well, TD depth is 7 388 m with horizontal section length of 4 118 m, created two records of the deepest well in Changqing Oilfield and the longest horizontal section of onland oil and gas wells in China. The research and application show that the key technologies provide technical support for efficient exploration and development of tight gas reservoir in Sulige Gas Field, and also provide reference for safe and efficient drilling of ultra long horizontal section well in domestic tight gas field.

Effect of Geological Heterogeneity on the Production Performance of a Multifractured Horizontal Well in Tight Gas Reservoirs

AbstractMultifractured horizontal wells are widely used in the development of tight gas reservoirs to improve the gas production and the ultimate reservoir recovery. Based on the heterogeneity characteristics of the tight gas reservoir, the homogeneous scheme and four typical heterogeneous schemes were established to simulate the production of a multifractured horizontal well. The seepage characteristics and production performance of different schemes were compared and analyzed in detail by the analysis of streamline distribution, pressure distribution, and production data. In addition, the effects of reservoir permeability level, length of horizontal well, and fracture half-length on the gas reservoir recovery were discussed. Results show that the reservoir permeability of the unfractured areas, which are located at both ends of the multifractured horizontal well, determines the seepage ability of the reservoir matrix, showing a significant impact on the long-term gas production. High reservoir permeability level, long horizontal well length, and long fracture half-length can mitigate the negative influence of heterogeneity on the gas production. Our research can provide some guidance for the layout of multifractured horizontal wells and fracturing design in heterogeneous tight gas reservoirs.

Fluid distribution in a tight gas reservoir using the saturation-height model

The development of tight gas reservoirs requires detailed knowledge of gas volumes and their distribution in three-dimensional space. This information can be obtained using a Saturation Height Model (SHM) developed by combining mercury injection capillary pressure analysis and well logging data. The SHM is constructed using core data from two wells in the tight gas reservoir of Amin formation in Oman.The saturation-height model is represented by a tangent line function linked with porosity. The developed SHM accurately simulates water saturation from well logs in seven wells. The curve fitting procedure determines three baselines, designated as free water levels (FWL), increasing with depth in the order of FWL0, FWL1 and FWL2.In three wells, the best match for the water saturation curve is obtained using FWL1 for Upper Amin formations and FWL2 for Low and Middle Amin formations. Different FWLs in the wells indicate differences in well placement within blocks and depending on tectonic history.The described tight gas reservoir can rather be characterized as a composite type because gas accumulations are not only found in high positions, but they also exist deeper over a wide range of depths.The developed SHM and the determined FWLs can be used for 3D reservoir modeling, in situ gas volumetric analysis and Sw calculation in undrilled areas to formulate a field development plan and fracturing program. This information makes it possible to estimate the consumption of water and chemicals required for hydraulic fracturing operations, which, in turn, makes it possible to estimate the required capacities for treatment of produced water and gas and to identify the places of possible contamination and gas losses.

A New Experimental Approach for Hydraulic Fracturing Fluid Damage of Ultradeep Tight Gas Formation

The unconventional resources from an ultradeep tight gas reservoir have received significant attention in recent decades. Hydraulic fracturing is the main method for tight gas reservoir development because of its extremely low permeability and porosity. During hydraulic fracturing, high hydraulic fracturing fluid (HFF) that invaded the zone near the fracture face may reduce gas relative permeability significantly and impede gas production. The sources of this damage can be the high capillary pressure (HCP) and the presence of water-sensitive clays (PWC). For tight rock, it is usually infeasible to identify the primary damage mechanism using the traditional steady-state measurement method due to long measurement time and gauge accuracy. In this paper, we present a new experimental approach to identify the primary mechanism of the fracture face damage (FFD) through the application of the pressure transmission method and pressure decay method. Both rock matrix and naturally fractured tight samples (depth 18,000 ft, Tarim field, China) were tested. The experimental results showed that the average high capillary pressure damage indexes ( D HCP ) of rock matrix cores and naturally fractured cores are 94.9% and 92.4%, respectively, indicating severe damage caused by HCP. The average clay-swelling and mobilization (CSM) damage indexes ( D CSM ) of rock matrix cores and naturally fractured cores are 29.6% and 38.4%, respectively, indicating that the damage caused by CSM is lighter than that by HCP. HCP is the primary damage mechanism for the tight sandstone. And the damage degree of the rock matrix cores is higher than that of the naturally fractured core. The proposed procedures can be applied to identify the FFD mechanism of other tight and shale formation and provide insightful fundamental data for HFF optimization.

Tectonic controls on Permian tight gas accumulation: Constrains from fluid inclusion and paleo-structure reconstruction in the Hangjinqi area, northern Ordos Basin, China

The development of tight gas reservoirs within the Ordos basin is closely related to the tectonic evolution. In this study, homogenization temperature of aqueous inclusions and the burial and thermal history of single well were combined to determine the tight gas charging time in the Permian Lower Shihezi sandstones in the Hangjinqi area, northern Ordos Basin. The paleo-structural characteristics and tectonic evolution, and their controls on source rock, gas migration and accumulation were discussed based on detailed 3D seismic interpretation. Results show that the natural gas was charged during the Middle Jurassic to the Early Cretaceous (170-140 Ma) in the southern part of the Porjianghaizi fault, while in the northern part, the gas charging time was the Early Oligocene to the Late Miocene (31-8 Ma). Paleo-topography in the Late Paleozoic controlled the coal beds thickness with generally decreasing trend to northward. Different burial depths led to the variation of thermal evolution, hydrocarbon generation time and intensity of source rocks between the northern and southern part. The results of this study indicate that the Hangjinqi area was evolved into a tectonic pattern with higher elevation in the south than the north in the Late Jurassic. The gas reservoirs in the southern part were mainly distributed in the paleo-slopes and paleo-highs, where were favorable areas for the gas accumulating in the Late Jurassic. Afterwards, the study area began to uplift since the late Early Cretaceous and made the Hangjinqi area a southwest inclined monocline. The rapid tectonic uplift event since the Early Oligocene in the northern Ordos Basin destroyed and reallocated the primary gas reservoirs in the southern part and prompted the gas migrating and accumulating into the structural traps in the northern part. The variation of natural gas compositions in both northern and southern parts verified the gas migration process.

Effect of connate water on stress sensitivity of tight gas reservoirs

ABSTRACT The current research on stress sensitivity was mainly focused on reservoirs without connate water. But the connate water exists in tight gas reservoirs widely. Thereby research of stress sensitivity with connate water is meaningful for reasonable development of tight gas reservoirs. The micro-pore structure and clay minerals of core samples selected from tight gas reservoirs were analyzed through mercury injection experiment, X-ray diffraction analysis, and scanning electron microscope (SEM) technologies. For tight gas reservoirs, the clay content was high which is an important factor leading to strong stress sensitivity, and the characteristic of pore structure belonged to pore-matrix type. In view of the above, the mechanical capillary model considering connate water was established in this paper, which was used to analyze the influence of connate water on stress sensitivity. Core samples under different connate water saturations were adopted for the experiments of stress sensitivity. Results show that stress sensitivity of tight gas reservoirs with connate water is strong, and increases with decrease of permeability and increase of connate water saturation, which is consistent with the conclusion from the forced capillary model. Relationships between stress-sensitivity coefficients, absolute permeability, and connate water saturation were studied through experiments and a numeric expression used to quantificationally characterize stress sensitivity with connate water was obtained. On this basis, a productivity model considering stress sensitivity with connate water was established. By calculating the productivity of gas well of different connate water saturation, it can be found that productivity damage occurs due to stress sensitivity, and productivity damage increases with the increase of connate water saturation. Therefore, if the pressure drawdown rate is controlled and connate water saturation is decreased, productivity damage caused by stress sensitivity will decrease.

Experimental Investigation of the Damage Mechanisms of Drilling Mud in Fractured Tight gas Reservoir

Mud pollution seriously restricts the development of tight gas reservoirs. For the Dabei tight gas field in Tarim Basin, lots of wells show a higher skin factor on the pressure buildup test curves after drilling. Little researches on mud damage have been conducted for the fracture gas reservoir. Based on the previous researches, a dynamic filtration experimental method utilizing full diameter cores is established for fracture-porous cores under reservoir temperature. Twelve sets of dynamic filtration tests with full diameter cores (D = 10 cm) on the established device and some cuttings microscopic analysis on environmental-scanning-electron microscope/energy dispersive X-ray detector (ESEM/EDX) have been conducted. The effects of core type, fracture width, pressure difference, and mud type on mud damage are all investigated. The results show that the fractured cores suffer a more serious damage degree and exhibit lower return permeability ratio, compared with the porous cores. And the damage degree of fractured cores is proportional to the fracture width and pressure difference. The solids invasion is the key factor damaging the fractured cores, while the porous is mainly impaired by the filtrate invasion. This paper provides a scientific, in-depth understanding of the behaviors, laws, and characteristics of mud damage in fractured and porous cores.

Lattice Boltzmann Model for Gas Flow through Tight Porous Media with Multiple Mechanisms.

In the development of tight gas reservoirs, gas flow through porous media usually takes place deep underground with multiple mechanisms, including gas slippage and stress sensitivity of permeability and porosity. However, little work has been done to simultaneously incorporate these mechanisms in the lattice Boltzmann model for simulating gas flow through porous media. This paper presents a lattice Boltzmann model for gas flow through porous media with a consideration of these effects. The apparent permeability and porosity are calculated based on the intrinsic permeability, intrinsic porosity, permeability modulus, porosity sensitivity exponent, and pressure. Gas flow in a two-dimensional channel filled with a homogeneous porous medium is simulated to validate the present model. Simulation results reveal that gas slippage can enhance the flow rate in tight porous media, while stress sensitivity of permeability and porosity reduces the flow rate. The simulation results of gas flow in a porous medium with different mineral components show that the gas slippage and stress sensitivity of permeability and porosity not only affect the global velocity magnitude, but also have an effect on the flow field. In addition, gas flow in a porous medium with fractures is also investigated. It is found that the fractures along the pressure-gradient direction significantly enhance the total flow rate, while the fractures perpendicular to the pressure-gradient direction have little effect on the global permeability of the porous medium. For the porous medium without fractures, the gas-slippage effect is a major influence factor on the global permeability, especially under low pressure; for the porous medium with fractures, the stress-sensitivity effect plays a more important role in gas flow.

Experimental Study on Stress Sensitivity Considering Time Effect for Tight Gas Reservoirs

Stress sensitivity is a crucial engineering problem in the process of tight gas reservoir development. In this work, the experiments about tight gas reservoirs are performed by confining pressure for a long time to simulate tight gas reservoirs under pressure for a long time during production process. The cores used in the test were from Ordos Basin, which is a typical tight gas reservoir. The results show that the stress sensitivity is increasing with compression time extended. Evaluation method for stress sensitivity about tight reservoirs was established based on time scale. The stress sensitivity for tight gas reservoirs was divided into two feature segments from time scale, which were named instantaneous stress sensitivity and delayed stress sensitivity. The conventional evaluation method for stress sensitivity about tight reservoirs has only considered the instantaneous stress sensitivity, and the delayed stress sensitivity has been ignored. The new method can more accurately simulate the stress sensitivity for tight gas reservoir, which has great guiding significance in rational development for tight gas reservoir. DOI: http://dx.doi.org/10.5755/j01.mech.24.6.22462