Deep Gas Reservoirs Research Articles

Pore scale investigation of hydrogen injection in sandstone via X-ray micro-tomography

The challenge associated with large-scale hydrogen storage is a pertinent one to achieve a hydrogen economy. The increasing global demand for clean and green energy is the driving force to propel such an economy. Furthermore, hydrogen is also considered an alternative energy source compared to fossil fuel as a clean energy alternative. Hydrogen geo-storage in a deep saline aquifer, depleted oil and gas reservoirs can resolve this challenge. We assess the potential of a saline aquifer in a sandstone formation to store hydrogen through first-of-its-kind x-ray micro-computed tomography miniature coreflood experiments. The investigation shows that ~65% of the sandstone's pore volume can be occupied by hydrogen when injected at a slow rate. Residual saturation of hydrogen upon brine injection can be ~41%.

Study on Formation Conditions and Distribution Characteristics of Deep Oil and Gas Reservoirs Based on Computer Software Analysis

Conventional reservoirs can be formed in the layers with relatively high quality reservoir sections, while unconventional reservoirs such as tight reservoirs can be formed in tight layers. This paper systematically studies and analyzes the formation conditions and distribution characteristics of deep oil and gas reservoirs by using the software analysis ability of computer. Oil and gas reservoir is the basic unit of oil and gas accumulation in the earth’s crust. A reservoir exists in an independent trap, in which oil and gas have a certain distribution law and a unified pressure system. Through the computer-aided understanding and calculation of the formation and distribution of oil and gas reservoirs, energy can be found more effectively, which helps to expand the national energy reserves [1].

Effective application of proppants during the hydraulic fracturing of coal seam gas reservoirs: Implications from laboratory testings of propped and unpropped coal fractures

Commercial production of coal seam gas is a significant proportion of the total Worldwide natural gas supply due to its high gas storage capacity at shallow extraction depths. Coal seam gas recovery may be enhanced by pure fluid-based or proppant based hydraulic fracturing – the decision whether or not to use proppants depends on coal seam characteristics – in particular stress-permeability characteristics. Although proppant application has been common in deep reservoir fracturing, its application on soft rocks such as coal should be carefully investigated. Higher concentrations of proppant are known to minimise proppant damage in deep reservoirs, with stiffness and flow tortuosity also impacting the response. We explored the impact of proppant loading, coal type and fracture roughness on fluid flow characteristics in propped fractures by conducting a series of triaxial permeability experiments combined with micro-CT imaging. The results reveal that proppant application in coal is only effective for deep coal seam gas reservoirs with effective stress greater than 6 to 8 MPa (~700 to ~900 m). Further, proppant application may cause up to 1–2 folds of fracture conductivity improvement in coal seam gas reservoirs located at over 1.2–1.4 km depths (effective stresses > 12 MPa). The impact caused by proppant embedment on fracture conductivity degradation is much significant compared to other proppant damage mechanisms. The effect, however, depends on the stiffness of the coal rock matrix and the proppant type implemented.

Surfactants are Ineffective for Reducing Imbibition of Water-Based Fracturing Fluids in Deep Gas Reservoirs

Minimizing loss of injected hydraulic fracturing fluids into shale along fracture-matrix boundaries is desired because imbibed water restricts gas production and wastes valuable water resources. This problem has motivated the addition of surfactants into water-based hydraulic fracturing fluids in order to reduce the capillary driving force for imbibition. Here, we show that reduction in interfacial tension and wettability alteration has negligible ability to reduce imbibition in deep gas reservoirs. The effectiveness of altering capillary forces acting at the wetting front also depends on the injection pressure acting at the fracture-matrix boundary. The pressure at the interface between the fracture and the shale matrix is constrained between the reservoir pore pressure and formation pressure (rock fracture pressure, also known as breakdown pressure of the rock) and increases with depth to magnitudes that greatly exceed that of capillary pressures. The analyses presented here show that even maximum alteration of interfacial properties that result in strongly hydrophobic interactions between the fracturing fluid and reservoir rock is incapable of significantly reducing imbibition in deep reservoirs. Instead of using surfactants, this analysis points to decreases in wellbore shut-in pressures and shut-in times as practical options for reducing imbibition losses of water-based fluids.

Reserve Estimation from Early Time Production Data in Geopressured Gas Reservoir: Gas Production of Cumulative Unit Pressure Drop Method

There is high uncertainty in reserve estimation during the early development of deep ultrahigh pressure gas reservoirs, largely because it remains challenging in accurately determining the formation compressibility. To overcome this, starting from the definition of compressibility, a novel gas production of cumulative unit pressure drop analysis method was established, of which the effectiveness was proven by applications in calculating the reserves of three gas reservoirs. It has been found that, in the limiting case, i.e., when the formation pressure dropped to the normal atmospheric pressure, the dimensionless gas production of the cumulative unit pressure drop was the reciprocal of the initial formation pressure. Besides, the relationship curve of the dimensionless gas production of the cumulative unit pressure drop and pressure drop was a straight line in the medium term, extending the straight line and intersecting the vertical line passing through the original formation pressure point, and the reserves can be determined according to the intersection point and the initial formation pressure. However, due to the influence of natural gas properties, the value needs further correction, and the correction coefficient depends on the pseudocritical temperature of natural gas. Specifically, when the pseudocritical temperature is given, the correction coefficient would be close to the minimum value of the natural gas deviation factor. When the pseudocritical temperature is more than 1.9 and less than 3.0, the minimum deviation factor would be between 0.90 and 1.0, and the higher the pseudocritical temperature, the closer the ratio is to 1.0.

Multiscale Formation Damage Mechanisms and Control Technology for Deep Tight Clastic Gas Reservoirs

Summary Severe formation damage often occurs during the drilling process, which significantly impedes the timely discovery, accurate evaluation, and efficient development of deep tight clastic gas reservoirs. The addition of formation protection additives into drilling fluid after diagnosing the damage mechanism is the most popular technique for formation damage control (FDC). However, the implementation of traditional FDC measures does not consider the multiscale damage characteristics of the reservoir. The present study aims at filling this gap by providing a complete and systematic damage control methodology based on multiscale FDC theory. First, the characteristics of multiscale seepage channels were described through petrology, petrophysics, and well-history data. Subsequently, based on laboratory formation damage evaluation experiments, the formation damage mechanism of each seepage scale was determined. Finally, based on the multiscale formation damage mechanism, a systematic multiscale FDC technology was proposed. Through the use of optimized drilling fluid based on multiscale FDC theory, high-permeability recovery ratio (PRR), high-pressure bearing capacity of plugging zone, and low cumulative filtration loss were observed by laboratory validation experiments. Shorter drilling cycle, less drill-in-fluid loss, lower skin factor, and higher production rates were obtained by using the optimized FDC drilling fluid in field application. This multiscale FDC theory shows excellent results in minimizing formation damage, maintaining original production capacity, and effectively developing gas reservoirs with multiscale pore structure characteristics.

Direct gas-in-place measurements prove much higher production potential than expected for shale formations

Shale gas exploitation has been the game-changer in energy development of the past decade. However, the existing methods of estimating gas in place in deep formations suffer from large uncertainties. Here, we demonstrate, by using novel high-pressure experimental techniques, that the gas in place within deep shale gas reservoirs can be up to five times higher than that estimated by implementing industry standard approaches. We show that the error between our laboratory approach and the standard desorption test is higher for gases with heavier compositions, which are of strongest commercial interests. The proposed instrumentation is reliable for deep formations and, provides quick assessment of the potential for the gas in place, which could be useful for assessing hydrocarbon reservoirs, and the potential for geological carbon sequestration of a given formation.

Sand Production Mechanism Analysis of Deep Tight Sandstone Gas Reservoir in Keshen Block

In order to provide reference and help for sand production control in deep tight sandstone gas reservoirs. Taking Keshen block as the research object, the sand production mechanism is analyzed and verified by experiments. The additional pressure difference, fracture development and reservoir reconstruction are considered. Through the establishment of rock mechanics model, hole additional pressure difference physical model experiment, acid rock test. It is concluded that the main sand production mechanism of this formation is shear failure, additional pressure difference of rock, sand production easily caused by natural fracture development, and rock strength decreases after acid fracturing. The rock strength decreases by 20%.

Deep shale gas in China: Geological characteristics and development strategies

Deep shale gas reservoir (3,500 ∼ 4,500 m) of Wufeng–Longmaxi Formation in southern Sichuan Basin in China has great potential for exploration and development, with resource of 16.31 × 1012 m3, counting 84% of the total resources in this area. And the deep shale gas wells in Luzhou and west Chongqing have achieved good development results in the past two years. We systematically summarized the geological characteristics of deep shale gas reservoir of Wufeng–Longmaxi Formation, and discussed the facing challenges and proposed some corresponding strategies. The deep shale gas reservoir in southern Sichuan Basin has six major characteristics. The reservoir is concentrated in depositional center and deep-water shelf environment. The reservoir is rich in silica and organic carbon while low in calcium and clay. Organic pores, inorganic pores, and microfractures are developed and well interconnected to form networks. Surface porosity is generally > 5% and increasing with depth. The gas content is 4.7 ∼ 7.5 m3/t, higher than that in Changning, Weiyuan, and Zhaotong area. The deep shale gas pressure coefficient is greater than 2.0 and is the highest in the southern Sichuan Basin, indicating its best preservation condition. Up to now, deep shale gas exploration is still encountered with many problems and challenges, including great difficulty in accurately obtaining reservoir parameters, unclear of high production mechanism, urgent need for optimal and quick drilling technology, great difficulty in reservoir fracturing, and unclear of hydro-fracture expansion rules. We proposed two strategies corresponding to the challenges, including deepen the delicate reservoir evaluation and clarify the rules of high production and enrichment of shale gas wells, and strengthen field experiments and explore effective and applicable technologies for drilling and fracturing of deep shale gas in China.

Review of 3D digital core reconstruction methods for deep shale gas reservoir

Conventional digital core reconstruction methods are not suitable for deep shale gas reservoirs with low porosity and permeability, anisotropy and complex mineral composition, and conventional single resolution three-dimensional digital core structure model cannot fully describe the core structure of shale gas reservoirs of different scales. In this paper, the advantages and disadvantages of different digital core reconstruction methods are summarized by analyzing examples. It is found that MCMC core reconstruction method is more suitable for image reconstruction of 3D digital structure model core of deep shale gas reservoir in China; Finally, in view of the problems existing in conventional digital core reconstruction methods, combining CT imaging with ion beam focused electron microscopy (FIB-SEM) imaging technology, a 3D digital core structure model with multi-scale, multi-component and corresponding macro pore and micro pore of the corresponding reservoir is proposed. The micro spatial distribution structure of the model is similar to that of real shale gas reservoir core, it overcomes the difficulty that the resolution of single scale 3D digital gas reservoir core model and the micro size characteristics of gas reservoir core cannot be perfectly considered. It can not only accurately describe the micro pore space distribution structure of real core gas reservoir, but also accurately describe the macro heterogeneity of deep shale gas reservoir core.

A novel mineral composition inversion method of deep shale gas reservoir in Western Chongqing

The mineral composition of shale gas reservoir is complex and diverse and a universal mineral composition model is not available. In this study, the organic framework was introduced to construct petrophysical volume model of double skeleton mineral components in a sample of shale gas reservoir from Western Chongqing. This was done considering the XRD of core and thin section analysis. The volume contents of organic- and inorganic-skeleton mineral components in the shale gas reservoir were calculated with the least squares-singular value decomposition optimization inversion method based on the three porosity curves (AC, DEN and CNL) correction by argillaceous and kerogen volume content. This optimization inversion method was done using the XRD of core as the convergence condition. The calculation results showed that the correlation coefficient R2 between the mineral volume content calculated with the optimized inversion method and the X-ray diffraction measurement results was between 0.80 and 0.89, which was higher than those of the multiple regression model based on core data and the interpretation result of element capture spectrum logging (ECS) data. The novel model had been verified and applied in several wells, displaying the wide application potential since only need conventional logging data. The study provides a solid basis for the accurate evaluation of deep shale gas reservoirs.

Investigation of a high temperature gel system for application in saline oil and gas reservoirs for profile modification

The deeper the burial of the oil and gas reservoir, the higher the temperature of the oil and gas reservoir. When profile adjustment of water injection wells, plugging of oil production wells (gas production wells) and temporary plugging or killing of oil production wells (gas production wells) are required, the higher the temperature resistance of the plugging agent (above 150 °C) is required. In addition, high temperature resistant plugging agents should also be used in profile control or water plugging in reservoirs (120°C–200 °C) that are thermally recovered by steam injection or in situ combustion. It is of great importance to develop a high-temperature-resistant gel plugging system to fulfill the requirements of deep buried high-temperature oil or gas reservoirs or thermal recovery high-temperature oil reservoir operations.A gel system formed by the terpolymer (L-1) and a new cross-linking system (HB-1) was developed, and its properties were systematically studied in the condition of extremely high temperature. Studies have shown that the gel system could form stable continuous 3D network structures in high temperature (120°C–200 °C) and thus have an excellent long-term thermal stability.The gel system can adjust the strength by changing the concentration of the terpolymer (0.05%–1%) and the crosslinker (0.05%–1%), which can achieve different construction requirements. Compared with the conventional high-temperature-resistant gel, the cross-linking system HB-1 contains 4 hydroxyl groups (–CH2OH), it can crosslink with 4 amide groups (–CONH2) on the terpolymer. Therefore, this gel system can form a smaller grid size of 3D network structures (less than 5 μm), so it has stronger temperature resistance and better long-term thermal stability. When the temperature is 200 °C, the grid size of network structure is about 10 μm, but the strength of the gel system can still be maintained at code F-G. When the salinity of the water solution is 200,000 mg/L, the gel system on the contact surface can still maintain a small grid size of 3D network structures (about 10 μm). The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. A gel system with strength F can still be formed after shearing by the pore media of 10 sand-packed tubes, and the plugging rate of each sand-packed tube exceeds 97%. It can be found by scanning electron microscope pictures that the gel system can be very firmly attached to the pore media, which can achieve profile adjustment of the formation. The gel system could have great potential in the application of high temperature oil or gas reservoirs.

Fine numerical simulation of deep carbonate gas reservoir in northwest Sichuan

Qixia Formation in northwest Sichuan has a complex structure, ultra-deep burial, high temperature and high pressure, thin reservoir and fractures development, and it is difficult to simulate the gas reservoir numerically. Based on existing geological understanding, in this paper, the tracking attribute parameters of three-dimensional seismic data bodies are optimized by ant tracking technology. Through the automatic extraction crack system of differential bodies, a three-dimensional geological model considering natural fractures is established. Using embedded discrete cracks and MRST numerical simulation open-source program, a numerical simulator of deep carbonate gas reservoirs in northwest Sichuan has been formed, and the development mechanism of Qixia Formation in northwest Sichuan is demonstrated. The research work in this paper has a certain theoretical guiding significance for the efficient development of deep carbonate gas reservoirs in northwest Sichuan.

Study on the groundwater quality and its influencing factor in Songyuan City, Northeast China, using integrated hydrogeochemical method

Clean groundwater resources are important for the health of human. In Songyuan City, Northeast China, anthropogenic activities have led to changes in groundwater circulation, thereby depleting the aquifer system and causing water quality deterioration. To evaluate the genesis of water quality, we analyzed the hydrochemical and stable isotope compositions of shallow and deep groundwater. According to drinking water quality standards, the concentrations of Ca2+, Mg2+, and NO3− in 23.0, 30.2 and 35.4% of the samples, respectively, exceeded the acceptable ranges. The groundwater chemistry in these samples was related to geochemical processes and agricultural pollution. The hydrochemical analysis explained the reaction mechanisms in each aquifer, showing that the main source of ions in both deep and shallow groundwater is the weathering of silicate rock. In addition, the dissolution of carbonate minerals and artificial pollutants is greater in the shallow groundwater. The stable isotope results showed that long-term extraction is the cause of the diffusion of pollutants in shallow aquifers. Moreover, because most of the well-drilling techniques are backward, the aquifer structure is destroyed, and the deep groundwater is mixed with the shallow groundwater during the process of artificial extraction. The study also analyzed the conditions of the water-rock reaction. Combined with the geological background, it was found that the deep CO2 gas reservoir could provide the necessary material source for the reactions. Owing to frequent tectonic activities, deep CO2 could be discharged to the surface through the fault zone, which promotes the water-rock reaction in this area.

Wettability alteration using benzoxazine resin: A remedy for water blockage in sandstone gas reservoirs

As a low carbon fuel, natural gas is leading the transition to a cleaner energy system. However, water blockage is seen to reduce gas deliverability significantly in many gas producing wells. We have developed an environmentally friendly and cost-effective non-fluorinated chemical treatment using a new benzoxazine monomer as a wettability modifier to combat water blockage. This chemical would adhere to silicate surfaces through a silane moiety followed by the application of a thermally accelerated ring-opening polymerization of the benzoxazine moiety. The performance of the treatment has been evaluated using contact angle measurements, spontaneous imbibition tests, and core-flooding experiments at 60 °C and 10.35 MPa. After chemical treatment, the contact angle shifts from almost 0° to 90°, implying that the treatment alters the wettability from strongly water-wet to an intermediate gas-wetting state. Spontaneous imbibition measurements show about 65% reduction in the volume of water imbibed into the rock sample after chemical treatment, suggesting a substantial increase in hydrophobicity of rock pore surfaces. Core-flooding experiments indicate that the chemical treatment increases gas relative permeability (by up to 22%) whilst decreasing residual water saturation (by up to 10%). Taken together, we demonstrate that this novel non-fluorinated benzoxazine monomer can successfully shift wettability of sandstone rocks from a strongly water-wet to an intermediate-wet state and thus aid to mitigate water blockage at relatively low cost and in an environmentally friendly manner. Furthermore, this chemical can withstand extra high temperatures encountered in many deep low permeability gas reservoirs where water blockage may be highly pronounced.

Simulation of geodynamic processes

To select an optimal and environmentally friendly technology for oil and gas development, it is necessary to estimate in advance the likely disfigurement processes of the surface terrain. To this end, it is recommended to develop predictive geodynamic models prior to start of field development, taking into consideration the geological characteristics and tectonic activity of the area under investigation, as well as the specific features of the reservoir. Research methods. In this paper, two models of subsidence of the ground surface in a hydrocarbon field are considered: a parametric spatial model developed at Delft University of Technology and a model based on the Knote influence function developed at the Canadian Center for Geodetic Engineering. The first method is more suitable for describing a smooth and gradual subsidence in deep gas reservoirs and allows you to assess the spatial-temporal pattern of movement of the ground surface. In the second method, geodynamic processes are modeled based on the functional relationship between reservoir compaction and subsidence of the day surface, taking into account the location of the oil reservoir, physical and mechanical properties of rocks, changes in reservoir pressure and the results of surface disfigurement monitoring and is recommended for oil fields. Research results. A comparative analysis of these methods is carried out on the example of the Tengiz oil and gas field in Western Kazakhstan. An evaluation of the developed model accuracy is carried out by comparing the calculated values ​​of soil subsidence with the data of radar interferometry, and estimates obtained by other researchers. Recommendations are given on the application of the considered methods in the generation of predictive models of oil and gas fields, the necessity of calculating the transfer coefficient of the reservoir compaction to the position of the day surface, taking into account the depth of the reservoir and the physical and mechanical properties of the rock massif, is indicated.

The North Pyrenean Frontal Thrust: structure, timing and late fluid circulation inferred from seismic and thermal-geochemical analyses of well data

During orogenesis, large-scale thrusts as orogenic fronts can act as conduits and/or barriers for fluid flow. Unravelling the timing and modes of tectonic activation of large-scale faults is crucial to understanding the relationship between fluid flow and deformation. The North Pyrenean Frontal Thrust (NPFT) corresponds to a major basement-involved thrust responsible for the northward overthrust of the pre-orogenic sediments on top of the Aquitaine Foreland Basin. This study questions the timing of activation of this thrust, its geometry, the nature of the last fluids, which circulated there, and its role on the circulation of fluids. The structural study confronted to published thermochronology data led to determine the timing of the two tectonic activations during the NPFT compression phase and to relate them to the fluid circulations. We constrain the first activation at Campanian times and link it to the leak of the deep gas reservoir present in depth, as the NPFT acted as a conduit. Then the NPFT acted as a barrier, probably due to the breccia consolidation during the Paleocene quiescence period. Finally, the Eocene-Oligocene reactivation led to fluid circulation of high salinity fluids from the Triassic evaporites leaching. This latter event is associated with a fracturing event and the late generation of calcite veins studied here. This is the first study in the Pyrenees directly applied to the NPFT which uses the association between fluid inclusions study, seismic and thermochronological data. It highlights that the NPFT may be an important structure responsible of the leakage of deep hydrocarbons reservoirs. It also shows the importance of the determination of the activation steps of large-scale faults to decipher the origin of fluid circulations in space and time.

Petrophysical properties of deep Longmaxi Formation shales in the southern Sichuan Basin, SW China

Abstract Deep shale layer in the Lower Silurian Longmaxi Formation, southern Sichuan Basin is the major replacement target of shale gas exploration in China. However, the prediction of “sweet-spots” in deep shale gas reservoirs lacks physical basis due to the short of systematic experimental research on the physical properties of the deep shale. Based on petrological, acoustic and hardness measurements, variation law and control factors of dynamic and static elastic properties of the deep shale samples are investigated. The study results show that the deep shale samples are similar to the middle-shallow shale in terms of mineral composition and pore type. Geochemical characteristics of organic-rich shale samples (TOC > 2%) indicate that these shale samples have a framework of microcrystalline quartz grains; the intergranular pores in these shale samples are between rigid quartz grains and have mechanical property of hard pore. The lean-organic shale samples (TOC

Genesis and accumulation process of deep natural gas in the Altun foreland on the northern margin of the Qaidam Basin

Deep natural gas in the northern margin of the Qaidam Basin is characterized by low exploration degree and large resource potential, but the genesis of deep gas reservoirs is complex. In particular, Jurassic source rocks do not develop in west of Altun foreland. The mechanism of deep accumulation is unknown, which restricts the exploration of deep gas reservoirs. Using gas components, isotopes and other data, combined with the geological characteristics of the Altun foreland, this study analyzes the genesis and source of deep gas in this area, and establishes the accumulation procesess of the deep gas reservoirs. Analysis shows that the gas in the Altun foreland is dominated by coal-type gas with the characteristics of oil cracking gas in deep reservoirs. The Jurassic source rocks in the Qaidam Basin are mainly lacustrine mudstones, with black mudstones and oil shale developed, which have the material basis for forming large oil reservoirs. The deep reservoir has experienced the process of long-term deep burial and high-temperature cracking, and has the conditions to form oil cracked gas. Accumulation in deep bedrock gas reservoirs is characterized by early oil filling, later high-temperature cracking into gas, and late adjustment. Reservoirs formed in early stage can be deeply cracked into gas reservoir under high temperature in the process of deep burial. The ancient uplifts along the basin margin and large anticline traps in the late tectonic zone are favorable exploration areas for deep gas. The exploration area for natural gas in the Qaidam Basin has been expanded by the discovery of deep oil cracking gas in the Altun foreland, which has crucial significance for guiding and intensifying deep gas exploration in the Qaidam Basin.

An Overview of the Common Water-Based Formulations Used for Drilling Onshore Gas Wells in the Middle East

The proper selection of drilling fluids formulations and its treatment has always been a challenge and requires a great effort to ensure optimum drilling performance. The objective of this paper is to assist the mud engineer in selecting the water-based drilling fluid formulations that are best suited for a certain application. To achieve this target, the field practices were combined with the literature to study the most practiced water-based drilling fluid recipes used for onshore gas applications in the Middle East (i.e., spud mud, high-bentonite spud mud, salt/polymer mud, and high-overbalanced mud). From both field practices and deep literature review, it is recommended that both spud mud and high-bentonite spud mud be prepared and pre-hydrated for 4–6 h before a well spud. Also, it is important to add detergents with high-viscosity sweeps to avoid the bit balling and maintain the gel strength. While for salt/polymer mud, the regular addition of sodium sulfite is necessary for polymers stabilization, and the efficient solids control equipment performance is essential. To avoid the solids sagging issues associated with drilling high-pressure high-temperature deep gas reservoirs, it is recommended to either uses sag resistance materials, micronized weighting materials, or a combination of different weighting materials. The high-overbalanced mud is the most effective and efficient type when drilling a combination of natural fractured depleted gas reservoirs with high-pressure gas reservoirs.