High-pressure Reservoir Research Articles

Characteristics of Deep Coal Reservoir and Key Control Factors of Coalbed Methane Accumulation in Linxing Area

Deep coalbed methane (CBM, commonly accepted as >1500 m) has enormous exploration and development potential, whereas the commercial development of deep CBM exploration areas wordwide has been quite limited. The Linxing area, with coals buried approximately 2000 m deep, shows great development potential. Based on a basic geological analysis of structural and hydrodynamic conditions, combining field tests of reservoir temperature and pressure and indoor measurements of maceral composition, proximate analysis, thermal maturity, porosity and permeability, the factors controlling deep CBM accumulations were discussed. The results show that the present burial depth of the No. 8 + 9 coal seam, mainly between 1698 and 2158 m, exhibits a high reservoir temperature (45.0–64.0 °C) and pressure (15.6–18.8 MPa), except for the uplift area caused by the Zijinshan magma event (with coal depth approximately 1000 m). The maximum vitrinite reflectance (Ro,max) of the coal varies from 1.06% to 1.47%, while the magma-influenced areas reach 3.58% with a relatively high ash content of 31.3% (air-dry basis). The gas content calculated by field desorption tests shows a wide range from 7.18 to 21.64 m3/t. The key factors controlling methane accumulation are concluded from regional geological condition variations. The north area is mainly controlled by structural conditions and the high gas content area located in the syncline zones. The center area is dominated by the Zijinshan magma, with relatively high thermal maturity and a high gas content of as much as 14.5 m3/t. The south area is developed with gentle structural variations, and the gas content is mainly influenced by the regional faults. Furthermore, the groundwater activity in the eastern section is stronger than that in the west, and the hydrodynamic stagnant areas in the western are more beneficial for gas accumulation. The coals vary from 3.35% to 6.50% in porosity and 0.08 to 5.70 mD in permeability; thus, hydrofracturing considering high temperature and pressure should be applied carefully in future reservoir engineering, and the co-production of gas from adjacent tight sandstones also should be evaluated.

Study on Interaction Characteristics of Injected Natural Gas and Crude Oil in a High Saturation Pressure and Low-Permeability Reservoir

Natural gas injection is considered for enhanced oil recovery (EOR) in a high saturation pressure reservoir in block B111 of the Dagang oilfield, China. To investigate the interaction characteristics of injected natural gas and crude oil, the ability for dissolution–diffusion and miscibility–extraction of natural gas in crude oil was tested using a piece of high-temperature and high-pressure PVT equipment. The physical properties and minimum miscible pressure (MMP) of the natural gas–crude oil system and their interaction during dynamic displacement were analyzed using the reservoir numerical simulation method. The results show the following: (1) Under static gas–oil contact conditions, natural gas has a significant dissolution–diffusion and miscibility–extraction effect on the crude oil in block B111, especially near the gas–oil interface. The content of condensate oil in gas phase is 10.14–18.53 wt%, while the content of dissolved gas in oil phase reaches 26.17–57.73 wt%; (2) Under the reservoir’s conditions, the saturated solubility of natural gas injected in crude oil is relatively small. The effect of swelling and viscosity reduction on crude oil is limited. As the pressure increases with more natural gas dissolved in crude oil, the phase state of crude oil can change from liquid to gas; accordingly, the density and viscosity of crude oil will be greatly reduced, presenting the characteristics of condensate gas; (3) The MMP of natural gas and crude oil is estimated to be larger than 40 MPa. It mainly forms a forward-contact evaporative gas drive in block B111. The miscible state depends on the maintenance level of formation pressure. The injected natural gas has a significant extraction effect on the medium and light components of crude oil. The content of C2–C15 in the gas phase at the gas drive front, as well as the content of CH4 and C16+ in the residual oil at the gas drive trailing edge, will increase markedly. Accordingly, the residual oil density and viscosity will also increase. These results have certain guiding significance for understanding gas flooding mechanisms and designing gas injection in block B111.

Evaluation of rock-fluid interaction in a carbonate reservoir: Backflow test and reactive transport simulations

Water injection is one of the most used secondary oil recovery methods. However, when injected into a carbonate reservoir, it disturbs the equilibrium between the porous rock and the formation water, altering the geochemical system. The aim of this work is to evaluate the rock-fluid chemical interaction associated with seawater injection into a carbonate reservoir, based on field flow tests and flow simulations using COORES™ and ARXIM. Though previous studies were carried out under laboratory conditions, in this work, for the first time, rock-fluid interaction was observed and quantified during a field test in a high-temperature and high-pressure reservoir. Chemical analysis of produced water during the flow test showed that calcium and alkalis concentrations were higher than those calculated by the simple mixture of injected and formation waters, confirming the existence of chemical reactions under reservoir conditions. Reactive transport simulations were used to determine kinetic parameters related to calcite dissolution and dolomite precipitation in the reservoir. The results of this study enhance the understating of chemical interactions between injected fluids and carbonate reservoirs and provide data for more reliable simulations. These could lead to more accurate predictions regarding produced water composition and pH, anticipating the likelihood of reservoir collapse and scaling issues.

Synthetic polymer fracturing fluid weighted by sodium formate enables fracture stimulations in Ultra-High pressure and High-Temperature reservoir

Weighted fracturing fluid was considered to be one of the key technologies to deal with the challenge of abnormally high pressure and ultra-high temperature reservoir stimulation in the case of existing fracturing equipment. In this work, a thickener polymer Pt-Fb that meets the requirements of fracturing fluid weighting by HCOONa was synthesized. And HCOONa- weighted fracturing fluid with delayed crosslinking characteristics and good friction reduction performance was developed based on the polymer Pt-Fb. It is much cheaper than CHKO2-weighted guar gum fracturing fluid. The density of HCOONa-weighted fracturing fluid was up to 1.3 g/cm3. The fracturing fluid proposed in this study meets the temperature resistance and shear resistance requirements of 170 °C and 170 s−1. Besides, a complete gel breaking was obtained by using NaBrO3, and the internal mechanism was investigated from both experimental and theoretical aspects. It was revealed that a mild multi-step oxidation reaction enables NaBrO3 to break the HCOONa-weighted fracturing fluid.

Study on the Performance of Polyurea Anti-Seepage Spray Coating for Hydraulic Structures

The surfaces of hydraulic structures are vulnerable to damage and cracking, which can result in high-pressure reservoir water entering cracks and endangering the safety of the structures. Therefore, it is necessary to strengthen the anti-seepage treatment and protection on the surfaces of the structures. In this paper, we explore the tensile and high-water-pressure breakdown resistance properties of polyurea coating material. To do so, we independently designed and manufactured a high-water-pressure breakdown test device for coating. Our experimental results indicated that the thickness of the polyurea coating decreased with an increase in elongation. Furthermore, we found that the breakdown resistance of the polyurea coating was related to the coating thickness and the bottom free section width. We then fitted the stress–strain curve obtained from the experimental test using the Ogden constitutive model. Based on this, we numerically simulated the high-water-pressure breakdown performance of the polyurea coating using the finite element software ABAQUS 2022. We obtained the relationships among maximum displacement, free section width, and coating thickness under high water pressure. Our numerical findings indicated that the vertical displacement of the midpoint increased linearly with width in the case of the same coating thickness under water pressure load. Conversely, for the same free section width, the vertical displacement decreased with increasing coating thickness.

Simulative Quantification of the Supersonic Discharge Process of Cold Gas Airbag Inflators

Abstract A simulative method for quantifying the discharge process of cold gas airbag inflators is presented. The pressure, mass flow and the influences of the flow field are relevant to a robust and predictive airbag deployment. Simulations in this regard are compared and validated with experimental data. It turns out that simulated mean pressures inside the inflator deviate by 5–10% from measured data. A complex and highly turbulent flow field with supersonic and subsonic flow emerges. An influential longitudinal vortex forms in the cold gas inflator, leading to a highly dynamic discharge process. This vortex would not be found with the current state-of-the-art methods, such as the simple tank test or analytical models. It is shown that a simple turbulence model such as the k−ω shear stress transport predicts the flow field with sufficient accuracy in comparison with the large eddy simulation. Real gas effects must be taken into account inside the high-pressure reservoir, leading to a faster discharge compared to the ideal gas, due to faster moving expansion waves in the reservoir. Real gas effects outside the high-pressure reservoir seem to be negligible. A simplified simulation model was developed that uses only part of the whole cold gas inflator model and serves as a good practical approach for airbag deployment simulations, with less computational effort. Thus, the method presented here can provide high-quality inflow data for airbag deployment simulations.

A comparative analysis of the effect of nanoparticles/surfactant assisted foam injection on the gas mobility control at different heterogeneities

Foam flooding is a popular method for increasing oil recovery in reservoirs with varying levels of heterogeneity. One common foam flooding technique is surfactant-assisted foam flooding (SF), which uses surfactants to create stable foam. However, SF is limited in high-pressure, high-temperature, and high-salinity reservoirs. To overcome these limitations, researchers have proposed a new approach called nanoparticles-assisted foam flooding (NAF), which involves adding nanoparticles to improve surfactant properties. While SF has been shown to improve sweep efficiency in heterogeneous reservoirs, the potential benefits of NAF are not fully understood. In this study, researchers investigated the performance of SF and NAF in controlling gas mobility in reservoirs with different levels of heterogeneity. They defined heterogeneity levels using sequential Gaussian simulation with varying standard deviation values. They also included a gas–water flooding (GW) scenario as a baseline. The results showed that SF effectively delayed breakthroughs and improved recovery factors in highly heterogeneous reservoirs. The researchers also compared normalized values of breakthrough time, breakthrough recovery factor, and recovery factor after 50 years for SF and NAF, which were normalized by corresponding GW results. Simulation results showed that SF and NAF could increase the normalized breakthrough time (SF: 10–17%, NAF: 12–42%), breakthrough recovery factor (SF: 11–20%, NAF: 16–53%), and recovery factor after 50 years (SF: 0–4%, NAF: 0–23%) compared to GW, depending on the heterogeneity level and NP concentration. The benefits of NAF compared to SF and GW were due to a significant decrease in gas mobility and saturation in the topmost layers, which facilitated the piston-wise movement of the front, resulting in higher sweep efficiency and recovery factor.

Оптимизация процессов разделения в технологии сепарации пластового газа высокого давления

The oil and gas sector is one of the leading branches of industry in our country. Millions of tons of oil and gas are produced every year in the Russian Federation. Part of the extracted natural resources is put on the international market, the rest is processed domestically providing the population with energy and other useful substances: sulfur, gasoline, oils, bitumen, and so on. Oil and gas processing is a complex process that requires a large amount of human, energy and technical resources. In the modern world, there are different types of oil and gas processing equipment: separators, reactors, furnaces, coagulators, distillation columns, etc. Separators are used for the primary separation of the reservoir gas from impurities, which are based on the separation process. The raw material for the separation plants is high-pressure reservoir gas, as well as gas for stabilization and purging of wells that consists of gaseous and liquid hydrocarbons, reservoir water and organosulfur compounds. These plants are designed to separate high-pressure reservoir gas produced at the production site into gas, gas condensate and associated water. Possible options for upgrading the design of an oil and gas separator for deep oil degassing are being explored. A final stage separator of the NGS-II-6-3000-09G2S type used in oil treatment plants was adopted as a basic model. The disadvantages of the separator design are listed. Design solutions have been developed in order to eliminate the identified shortcomings. The scheme of the modernized design of the oil and gas separator is illustrated. A detailed description of the principle of operation of the proposed design is presented. Calculations have been carried out to improve the efficiency of oil-gas separation.

Detailed investigation on the oxidation behavior and kinetic triplet of tight oil via TG-DSC-PDSC analyses

It remains some barriers for continental tight oils to enhance oil recovery owing to low or ultra-low permeability in China. Whether low temperature combustion mode (or deflagration fracturing) could be employed to expand the fracture, is an interesting but debatable topic in consideration of the not well-understood oxidation behavior and kinetic mechanism for the tight oil. This study initiated a comprehensive characterization on the oxidation behavior and kinetic triplet for the Mahu tight oil via the combination of atmospheric and pressurized thermal analyses (TG/DTG, DSC/DDSC, PDSC) and unconventional Popescu method. Threshold, peak, and end temperatures were shifted to higher temperature ranges following lower cumulative heat emission (from 13.21 to 9.15 kJ·g−1) with the heating rate increment from 5 to 15 K·min−1. Inversely, a more thorough oxidation process with higher cumulative heat releases (8.69 kJ·g−1 for LTO, 4.48 kJ·g−1 for HTO) was presented under elevated pressure condition. In order to elucidate the latent reaction mechanism, seven sequential temperature subzones were divided to acquire the most probable mechanism function G(α) and corresponding kinetic parameters. The results indicated that, owing to the high reservoir pressure, generated enormous heat in LTO stage had a significant acceleration to initiate and sustain the low temperature combustion process, which in some degree was conducive to update and expand the understanding of the low temperature in-situ combustion mode of air injection in low permeability and tight oil reservoirs via fracturing reservoir matrix.

Experimental investigation of mini supersonic wind tunnel for flow visualization

The present study proposes to design, fabricate and investigate a miniature supersonic wind tunnel at an affordable cost, safe to operate, and reliable for education purposes. The configuration consists of a high pressure reservoir, and mini tunnel which will be used for providing the supersonic flow over aerodynamic models. To design the mini supersonic wind tunnel, the method of characteristics is used to ensure that any shocks that arise in contact with the surface do not impact the uniformity and velocity of the flow through the duct. To achieve the supersonic flow, the nozzle contour of the supersonic portion of the wind tunnel is built in such a way that the shocks nullify each other and have zero effect on the velocity of the flow. For compressible flow visualization, an affordable Schlieren setup consisting of a torch, mirrors, and a mobile camera is used for flow visualization. Finally, the visualization results of the present study is in good relation with the theoretical calculations. The present facility is also calibrated by measuring the oblique shock angle in the test section, in the range of Mach number 1.6 to 1.8.

Optimal design of inter-state hydrogen fuel cell vehicle fueling station with on-site hydrogen production

With about 28% of all energy-related carbon dioxide emissions in 2018, the transportation sector is one of the major contributors to carbon dioxide production. Hydrogen fuel appears to be a promising alternative to fossil fuels in the direction of green transportation. As a result, one of the most important aspects of achieving this technology is developing an appropriate infrastructure to fuel this energy source. In this research, we plan to study and evaluate a hydrogen-releasing system (HRS) located in the middle of the road. This system is powered by the clean energy of the solar panel, generates hydrogen locally with the help of an electrolyzer, and contains both low-pressure and high-pressure reservoirs. TRNSYS software was used to model this system. Therefore, utilizing the trial-and-error method, the dimensions and operating parameters of each component of this system have been determined depending on the state of the energy supply from the panel and refueling in the three cascade reservoirs. Based on the modeled panels from existing catalogs, the findings demonstrate that the modeled system with 28 series panels and 100 parallel panels would be able to supply electricity to the entire system while maintaining a stable pressure in the high-pressure reservoirs. The percentage of hydrogen emitted to the environment based on this system was nearly equal to 15.5%, which was an appropriate amount for the system.

Laboratory installation for simulating and investigating the performance of built-in thermal protection at the first stage of manufacturing energy-efficient shells for high-pressure reservoirs

In this work, we aim to validate the efficiency of the previously created and patented laboratory test installation for simulating the high-pressure operation of a thermal barrier of high-pressure reservoirs and for determining the thermal conductivity of thermal barrier materials. Simulation of thermal barrier operation in the test installation was carried out under elevated pressures (up to 50–70 MPa). The pressure on the thermal barrier layer was created and regulated by an Instron 5989 test machine as part of the installation. Control of temperature changes and evaluation of the thermal insulation performance were performed by a calculation method based on temperature readings in the control points of the upper and lower rods of the installation. These values were obtained by contact (using thermocouples of surface temperature control) or non-contact (using thermal imaging equipment) methods. A pilot study into the performance of a thermal barrier material “tennesite” was carried out at different pressures. At pressures of 30, 40 and 50 MPa, the thickness of the tested samples comprised 4.64 mm, 4.35 mm and 4.00 mm, respectively. Variations in pressure were established to have a negligible effect on the thermal conductivity of the studied material. Thus, at pressures of 30, 40 and 50 MPa, the temperature drop in the samples comprised 198°С, 188°С and 190°С, respectively. The installation showed high efficiency in simulating the thermal protection of the studied material. Thus, at a layer thickness of 4 mm under the internal pressure of 50 MPa and the working temperature inside the equipment housing up to 300°С, the material is capable of reducing the thermal impact on the protected part of the structure by about three times (from 298.6°С to 108.4°С). The presented design can be used when investigating the behavior of various thermal barrier materials operated under elevated pressures. The results obtained confirm the efficiency of the proposed laboratory installation.

Key parameters and dominant EOR mechanism of CO2 miscible flooding applied in low-permeability oil reservoirs

CO2 miscible flooding is a prospective production method to enhance oil recovery (EOR), especially in low-permeability reservoirs. However, there is a lack of comprehensive and systematic understanding of the key parameters and dominant EOR mechanism of CO2 miscible flooding. In this work, the sensitivity of key parameters, such as oil viscosity, permeability, permeability ratio, and pressure, is analyzed by CO2 flooding physical simulation experiments. The adjuvants for CO2 miscible flooding of the Changqing crude oils are evaluated and optimized. The production performance of overpressure CO2 miscible flooding is studied by CO2 core flood test, and the oil micro-distribution before and after CO2 miscible flooding is characterized using nuclear magnetic resonance (NMR), and the micro EOR mechanism of CO2 miscible flooding is revealed. The results show that CO2 immiscible flooding is suitable for the development of low-viscosity crude oil (<50 mPa s), especially for oil viscosity of less than 10 mPa s. CO2 miscible flooding is advisable for low-permeability and medium and high-permeability reservoirs, especially for reservoir permeability of higher than 10 mD. Above the MMP, the oil recovery factor is over 85% and the increase rate slows down with pressure, CO2 miscible flooding is preferred for the high-pressure reservoir. CO2 miscible flooding is applicable for reservoirs with a permeability ratio of less than 2.5, especially for a permeability ratio of less than 2. Compared with 0.8 times MMP pure CO2 flooding, the time of gas channeling, and oil recovery for CO2 miscible flooding is delayed from 0.69 PV to 0.76 PV, and enhanced to 93.04% from 72.61%, respectively, with the help of adjuvants for CO2 miscible flooding, NP-9. The adjuvants for CO2 miscible flooding could effectively promote the realization of miscible flooding for CO2 and crude oils with an injection pressure of less than the MMP. CO2 has excellent oil displacement ability in low-permeability reservoirs, especially for miscible flooding, and the core oil saturation is obviously reduced. Overpressure CO2 miscible flooding could expand the swept volume and more efficiently displace oil in low-permeability reservoirs compared to an injection pressure of 1.0 times MMP. After overpressure CO2 miscible flooding, the residual oil in the low-permeability cores is distributed more evenly.

Microbiome of High-Rank Coal Reservoirs in the High-Production Areas of the Southern Qinshui Basin.

To study the distribution features of microorganisms in distinct hydrological areas of the southern Qinshui Basin, C-N-S microorganisms were studied using 16S RNA sequencing, metagenome sequencing and geochemical technologies, showing the high sensitivity of microorganisms to the hydrodynamic dynamics of coal. The hydrodynamic intensity of the #3 coal gradually decreased from the runoff areas to the stagnant areas. The stagnant zones have higher reservoir pressure, methane content, δ13CDIC and TDS and lower SO42-, Fe3+ and NO3- concentrations than the runoff areas. C-N-S-cycling microorganisms, including those engaged in methanogenesis, nitrate respiration, fermentation, nitrate reduction, dark oxidation of sulfur compounds, sulfate respiration, iron respiration, chlorate reduction, aromatic compound degradation, denitrification, ammonification and nitrogen fixation, were more abundant in the stagnant areas. The relative abundance of C-N-S functional genes, including genes related to C metabolism (e.g., mcr, mer, mtr, fwd and mtd), N metabolism (e.g., nifDKH, nirK, narGHI, nosZ, amoB, norC and napAB) and sulfur metabolism (e.g., dsrAB and PAPSS), increased in the stagnant zones, indicating that there was active microbiological C-N-S cycling in the stagnant areas. The degradation and fermentation of terrestrial plant organic carbon and coal seam organic matter could provide substrates for methanogens, while nitrogen fixation and nitrification can provide nitrogen for methanogens, which are all favorable factors for stronger methanogenesis in stagnant areas. The coal in the study area is currently in the secondary biogenic gas generation stage because of the rising of the strata, which recharges atmospheric precipitation. The random forest model shows that the abundance of C-N-S microorganisms and genes could be used to distinguish different hydrological zones in coal reservoirs. Since stagnant zones are usually high-gas-bearing zones and high-production areas of CBM exploration, these microbiological indicators can be used as effective parameters to identify high-production-potential zones. In addition, nitrate respiration and sulfate respiration microorganisms consumed NO3- and SO42-, causing a decrease in the content of these two ions in the stagnant areas.

Transient Coupled Flow Model for Matrix-Fracture in High-Pressure Gas Reservoirs Opened by Gas Drilling

Gas drilling technology is an effective method to protect low permeability tight sandstone reservoirs from damage. However, using this technology to drill high-pressure fractured reservoirs, the fluid flow characteristics are extremely complex, leading to drilling safety challenges. Therefore, based on the conservation equations of mass, momentum, and energy, a new transient coupled flow model in matrix-fracture is established for high-pressure gas reservoirs opened by gas drilling, considering convection term and energy equation, to research the pressure and flow velocity transient behaviors. This model is solved by Shaher Momani’s algorithm and CyabJiBe format, and the type curves of the pressure and flow velocity are plotted. The three flow stages are developed, and the impact of parameters and equation terms on the transient flow behavior is analyzed and discussed, such as the energy equation, the matrix permeability ( k ), the fracture aperture ( L f ), and the fracture outlet pressure. It is found that the energy equation term of the model has a great influence on the transient characteristics such as velocity and pressure, which cannot be ignored. In the first flow stage, the flow velocity characteristics are not affected by the matrix parameters being extremely unstable, but in the second and third stages, the influence of the gas supplied to fracture cannot be ignored. The proposed transient coupled flow model provides a new understanding of the transient flow behavior in matrix-fracture for high-pressure reservoirs during gas drilling, which can be used to interpret the characteristics of pressure and velocity more realistically, to provide support for safe drilling of gas drilling.

Prediction method for methane solubility in high-temperature and high-pressure aqueous solutions in ultra-deep drilling

During ultra-deep oil and gas exploration and development, overflow can easily occur when drilling in high-temperature (≤473.15 K) and high-pressure (≤150 MPa) reservoirs. The invaded methane gas is more soluble in the drilling fluid under high temperature and pressure, and the concealment is enhanced. Low temperature and pressure at the wellhead cause rapid expansion and precipitation of the dissolved gas, thereby increasing the risk of blowout. Therefore, the safe development of the ultra-deep oil and gas drilling process is critical to accurately determine the solubility of natural gas under alternating high- and low-temperature and high-pressure conditions in ultra-deep drilling wellbores. In this study, considering the presence and absence of hydrates at low temperature, and the conditions of high temperature and high pressure, the phase equilibrium prediction fugacity–fugacity model of methane and the aqueous solution is established. At the same time, the solubility experimental data of existing CH4 in aqueous solution are counted. The prediction model is established according to the particle swarm optimization support vector machine (PSO–SVM) algorithm. The new thermodynamic fugacity–fugacity model can be applied to predict the methane solubility and water content in the gas phase under the following ultra-deep drilling conditions: temperature from 273.15 to 473.15 K, pressure up to 150 MPa, and salinity from 0 to 5.4 mol kg−1. The prediction errors for the presence and absence of hydrate at 273.15–293.15 K and 273.15–473.15 K are within 8%. The calculation error from the PSO–SVM machine learning model for the interactive solubility of methane and water is maintained within 10%, but the prediction error at atmospheric pressure exceeds 10%. The machine learning model strongly depends on abundant statistical experimental data. The prediction of gas dissolution in ultra-deep oil and gas development should be based on thermodynamic models.

Well Kill Simulation of Gas Drilling When Drilling into Gas Reservoir

Aiming at the situation of encountering high-pressure gas reservoir in gas drilling, a well-kill mathematical model is established using multi-flow theory. Then the simulation of bottom hole pressure and casing pressure during well kill is demonstrated under different good kick parameters. The results show that the successful well kill only depends on a reasonable combination of initial casing pressure, kill rate and kill mud density. As the maximum initial casing pressure can be determined, the other two well-kill parameters can be changed. A combination of low kill rate and low kill mud density may lead to a failure in well kill due to the impossibility of forming an annular mud column. A reasonable combination of kill rate and kill mud density can guarantee the success of well kill, which contains two cases. One is that the formation pressure is balanced with no casing pressure after a period of well kill, and the other is the formation pressure can only be balanced with a certain casing pressure. Over-weight kill mud may fracture the formation, which can cause complicated well control risk. This simulation is instructive for the design of well kill in gas drilling.

Modeling a Multi-Parameter Interaction of Geophysical Controls for Production Optimization in Gas Shale Systems.

Well bottomhole pressure optimization issue has been a significant concern for efficiently developing unconventional systems due to strong stress sensitivity. Therefore, it is of practical interest to clarify influence mechanisms involved in stress sensitivity for gas shale, which is further included in the production model to determine main controlling factors for bottomhole pressure strategy optimization for long term hydrocarbon extraction. Currently, many production models were limited in exploring stress sensitivity mechanisms but adopted common empirical equations regarding net pore stress instead. In addition, geophysical control analysis for unconventional systems optimization was mostly conducted using local sensitivity qualitative analysis, which should be validated to be reliable and applicable to fields using multi-parameter interaction influence. As a result, in this paper, an efficient workflow to rationally optimize gas well production system was provided by combining the production model, orthogonal design approach, and response surface method. To be specific, the compound flow model for shale gas reservoirs, incorporating multiple stress sensitivity mechanisms, was proposed to function as a theoretical basis for production optimization simulation. Last but not least, local sensitivity analysis was conducted to qualitatively analyze the impact of influencing factors on 20 year-production of gas wells under different bottomhole production methods. The simulation results showed that the managed pressure drawdown scheme can be adopted for reservoirs with high reservoir pressure and tight matrix properties, while the high-pressure drawdown scheme is suitable for reservoir with better fracturing effect and high external water content. Finally, based on the proposed gas flow model and orthogonal design experiments, response surface design and single factor analysis as well, an optimization mathematical model for shale gas multi-parameter interaction was established, which intuitively quantified the effects of multi-geophysical controls on EUR increase in different production durations, including matrix properties, fracture properties, and production system indicator parameters. These findings provide a more reliable reference for production system optimization based on a series of mathematical approaches to improve overall long-term recovery from shale gas reservoirs.

Modelling reinjection of two-phase non-condensable gases and water in geothermal wells

Steam production from high enthalpy geothermal systems is frequently accompanied by the emission of non-condensable gases (NCGs), initially dissolved in the liquid phase or mixed in the vapour phase at depth in the reservoir. Capturing and reinjecting geothermal gases (CO2, CH4, NH3, H2S, H2, …) together with condensed steam leads to a significant improvement of the environmental profile of geothermal power systems and helps with reservoir recharge and pressure support. Nowadays, there are several ongoing projects targeting the minimalization of the environmental impact of geothermal exploitation through reinjection of the NCGs. For low NCG content, the gases can be fully dissolved into the condensed water and reinjected. However, for a high concentration of NCGs, the dissolution is only partial, and a two-phase mixture needs to be reinjected to achieve this goal. We present here the numerical results for the reinjection process in two different geothermal sites and for two different injection scenarios, focusing on the case of two-phase (liquid–gas) flows. Three commercial software (UniSim®, PIPESIM, and OLGA) and one in-house developed code (GWellFM) were used, and their results were compared. The injection should always take place inside a liquid column in the well to avoid degassing and accumulation of the NCGs. When targeting high pressure reservoirs or when injecting high ratios of water to NCGs flow rates, mixing of the two phases should take place on the surface. Whereas for low pressure reservoirs or for high gas contents mixing must occur deep in the well through one or several mixing points to ensure either complete dissolution of the gas or the downward flow of a two-phase mixture with minimum compression on the surface. The uncertainties of two-phase downward flows and water/NCGs mixtures characterisations introduce additional complexities in the modelling of the reinjection process.

Investigation of pore structure characteristics in marine deep-water high-temperature and high-pressure sandstone: A comprehensive characterization combining various experimental techniques

Marine deep-water high-temperature and high-pressure (HTHP) reservoirs have excellent potential for future oil and gas exploration. Because reservoir quality is often influenced by pore structure, understanding the characteristics of pore structures is essential for efficient exploitation. Therefore, it is necessary to conduct a comprehensive study of the pore structures in HTHP reservoirs. This study selected samples of the Enping Formation in the South China Sea as the research target and investigated the reservoir pore structures based on scanning electron microscopy, casting thin section, nuclear magnetic resonance, and mercury intrusion (e.g., high-pressure, constant-rate). The results show that the pore geometry and throat radius of different pore types in these reservoirs can lead to pore system heterogeneity. A comprehensive experimental method combining NMR and mercury injection was used to determine pore structure characteristics. In addition, a new pore size classification scheme was developed for marine deep-water HTHP reservoirs, and the controlling effect of pore type on percolation flow capacity was analyzed. This study systematically used a comprehensive pore structure characterization method that combined various experimental techniques to present the pore structure and develop a new pore size classification scheme for deep-water HTHP sandstone reservoirs, providing insight into the reservoir quality of marine deep-water HTHP sandstone reservoirs.