Low-pressure Reservoir Research Articles

აზოტის გამოყენება ნავთობისა და გაზის ოპერაციებში

The article discusses several options for nitrogen application in the oil and gas industry. Nitrogen gas is useful in maintaining formation pressure in oil fields, expelling gas from the gas cap, stimulating steeply inclined formations, cyclic exploitation of gas condensate deposits, Completion of wells, Cleaning of wells with Coiled Tubing, Circulatimg low pressure reservoir wells with foam.Described experience of local oil and gas companies in Georgia utilizing nitrogen pumping in welltesting and stimulation.

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

The impacts of geothermal gradients on compressed carbon dioxide energy storage in aquifers

Compressed CO2 energy storage in aquifers (CCESA) is new low-cost large scale energy storage technology. To further improve the energy efficiency of CCESA, we propose to combine the geothermal system with CCESA. In order to study the influence of geothermal energy on CCESA, aquifers with large vertical interval and different geothermal gradients from 0.026–0.07 °C/m are designed. The 3d wellbore-reservoir grid of underground part of CCESA was established. The simulation covering 100 days of intermittent initial gas fill and 50 days of cyclic injection and production was conducted. The hydrodynamic and thermodynamic behaviors and energy efficiency of the system were analyzed, comparatively. In the gas fill period, the higher the geothermal gradient, the farther the front of CO2 plume diffuses in the target aquifer, and thus the smaller the pressure accumulation. The temperature, pressure and energy efficiency of produced CO2 increases with the increase of geothermal gradient, while the density of released fluid decreases. The energy efficiency is greater than 1.0 under 6 geothermal gradients. The average energy efficiency of high- and low-pressure reservoirs can reach 1.282 and 1.061 under the geothermal gradient of 0.07 °C/m, which is 21.79 % and 5.5 % higher than that of 0.026 °C/m. The total energy efficiency of the joint system finally can reach 95.1 %. This research well confirms that the geothermal energy can dramatically improve the efficiency of CCESA and can enhance its application.

Increasing productivity by using smart gas for optimal management of the gas lift process in a cluster of wells

In the face of the escalating global energy demand, the challenge lies in enhancing the extraction of oil from low-pressure underground reservoirs. The conventional artificial gas lift method is constrained by the limited availability of high-pressure gas for injection, which is essential for reducing hydrostatic bottom hole pressure and facilitating fluid transfer to the surface. This study proposes a novel ‘smart gas’ concept, which involves injecting a gas mixture with an optimized fraction of CO2 and N2 into each well. The research introduces a dual optimization strategy that not only determines the optimal gas composition but also allocates the limited available gas among wells to achieve multiple objectives. An extensive optimization process was conducted to identify the optimal gas injection rate for each well, considering the limited gas supply. The study examined the impact of reducing available gas from 20 to 10 MMSCFD and the implications of water production restrictions on oil recovery. The introduction of smart gas resulted in a 3.1% increase in overall oil production compared to using natural gas. The optimization of smart gas allocation proved effective in mitigating the decline in oil production, with a 25% reduction in gas supply leading to only a 10% decrease in oil output, and a 33% reduction resulting in a 26.8% decrease. The study demonstrates that the smart gas approach can significantly enhance oil production efficiency in low-pressure reservoirs, even with a substantial reduction in gas supply. It also shows that imposing water production limits has a minimal impact on oil production, highlighting the potential of smart gas in achieving environmentally sustainable oil extraction. Furthermore, the implementation of the smart gas approach aligns with global environmental goals by potentially reducing greenhouse gas emissions, thereby contributing to the broader objective of environmental sustainability in the energy sector.

Revitalizing Reservoirs Nitrogen Kick-off Techniques for Reactivating Inactive Wells

This study explores the use of nitrogen (N2) injection to rejuvenate inactive wells and enhance reservoir productivity. We analyze the mechanism of N2 injection and its effectiveness in stimulating production from dormant wells through case studies and field applications. Our findings highlight the cost-effectiveness and environmental benefits of N2 kickoff in extending the life of mature reservoirs and maximizing hydrocarbon recovery. By examining operational conditions such as gas injection rate and pressure, we identify optimal conditions using Wellflo® simulations. Key factors like water cut, reservoir pressure, gas oil ratio, and productivity index (J) are considered to predict production outcomes. A new metric, the Optimum Economic Factor (OEF), assesses the efficiency of each operation based on production rate, operation length, and nitrogen usage. Our decision matrix, incorporating all examined factors, reveals trends: higher gas injection rates are needed for wells with higher water cut, lower gas oil ratio, lower productivity index, and lower reservoir pressure. We also studied the effects of wellhead pressure, well depth, and coiled tubing size, finding increased frictional pressure gradients with larger coiled tubing. Optimizing nitrogen unloading operations can significantly reduce costs, particularly by paying for coiled tubing packages on an hourly basis instead of daily rates. Our decision matrix facilitates planning and execution, optimizing nitrogen usage and reducing manpower requirements. Overall, our study demonstrates that proper optimization can make nitrogen unloading economically viable in mature oil fields.

Pore throat distributions and movable fluid occurrences in different diagenetic facies of tight sandstone reservoirs in the Triassic Chang 6 reservoirs, Wuqi Area, Ordos Basin, China

The 6th member of the Triassic Yanchang Formation, hereafter referred to as Chang 6 reservoir, in the Wuqi area of the Ordos Basin presents formidable obstacles for efficient tight oil development. This reservoir is known for its tight lithology, strong heterogeneity, inadequate oil saturation, and abnormally low reservoir pressure, which collectively contribute to the highly differentiated mobility of tight oil within the formation. To overcome these challenges, a comprehensive understanding of the factors influencing oil mobility is essential. This study investigates the occurrence characteristics of movable fluids in different diagenetic facies and the corresponding influential factors by employing various microscopic experiments, including high-pressure mercury intrusion, constant-rate mercury intrusion, nuclear magnetic resonance test, scanning electron microscopy, pore-casted thin section analysis, and X-ray diffraction measurement. There is a weaker correlation between the pore-throat radius ratio and the movable fluid saturation in reservoirs of various diagenetic facies (R2 = 0.6104), whereas there is a stronger correlation between movable fluid saturation and throat radius (R2 = 0.9415). Among the seven types of diagenetic facies, chlorite membrane cementation-intergranular pore facies (Facies I) and chlorite and illite membrane cementation-intergranular pore facies (Facies II) have the best-developed throats and the highest coordination number. Illite cementation-intergranular pore facies (Facies III) and illite and chlorite membrane cementation-dissolution facies (Facies IV) demonstrate smaller pore-throat radii and moderate to poor reservoir connectivity. The other three facies, namely illite cementation-dissolution facies (Facies V), illite cementation facies (Facies VI), and carbonate tight cementation facies (Facies VII) exhibit underdeveloped pore structures and lower recovery rates. Pore-throat radius emerges as the principal factor influencing reservoir permeability and storage capacity. The distribution of favorable diagenetic facies is influenced by depositional environments, diagenetic processes, and microscopic pore-throat characteristics. This study significantly enhances our understanding of the differential occurrence characteristics of fluids in different diagenetic facies in the Chang 6 reservoir, providing valuable insights for future exploration and production endeavors aimed at optimizing oil recovery in tight sandstone reservoirs.

Technological efficiency of applying viscoelastic systems for temporary blocking of productive reservoir when completing wells under conditions of abnormally low formation pressures

The article examines the technical and economic aspects of well killing under conditions of abnormal low reservoir pressure (ALRP). The possibility of joint use of compositions for temporary blocking of a productive formation, having different functional abilities to plug fluid-conducting channels, has been studied. Requirements for blocking fluids (BF) for killing during repair works in wells with excess ALRP have been formulated. The results of research and technical solutions in the field of development of viscoelastic systems for temporary blocking of productive formations in wells in conditions above the ALRP are presented. The results of laboratory and bench studies on the development of a gel-forming destructuring polymer-based biosol and fillers are presented. The advantage of using a destructurable biological fluid for temporary blocking of a productive formation in conditions above the maximum pressure limit using chemical reagents belonging to the following groups: polymers, salts, surfactants, acids, alkalis and fillers has been analyzed. The results of determining the mechanical properties of the resulting BF gel are presented. A gel-forming composition has been proposed that has high blocking properties and an optimal formulation of an alkaline destructor that ensures the destruction of the gel based on gammaxan. Formulations of viscoelastic destructurable fluids for killing wells in conditions exceeding the ALRP have been recommended for practical use. Keywords: well; bottomhole formation zone; blocking; blocking fluids; viscoelastic compositions; destructuring; ALRP.

A transient production prediction method for tight condensate gas wells with multiphase flow

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir, a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed, and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established. The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure. In the early stage of production or in areas far from the wellbore with high reservoir pressure, the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models. In the late stage of production or in areas close to the wellbore with low reservoir pressure, the condensate oil saturation can be calculated using the data of constant composition expansion test. In the middle stages of production or when reservoir pressure is at an intermediate level, the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure. Through simulation and field application, the new method is verified to be reliable and practical. It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Повышение эффективности глушения скважин на истощенных газоконденсатных месторождениях с сверх аномально низкими пластовыми давлениями

The problem is studied by the example of gas condensate fields at the final stage of development, where production wells have abnormally low reservoir pressures and their killing for repair work is a serious challenge requiring a search for new solutions. The work is motivated by the need to create a method for controlling hydrodynamic processes in a pre-blocked bottom-hole zone of the formation, for carrying out repair work in wells, preventing destruction of the reservoir formation and ensuring the preservation of its fluid-capacitance properties. The possibilities of an integrated approach to killing wells under conditions of extremely low formation pressures are considered, which includes controlling hydrodynamic processes in the “well-reservoir” system, previously blocked in the near-wellbore zone by special process fluids. It has been specified that the use of blocking fluids (with filler) helps to level the injectivity profile and form an insulating screen in the bottomhole zone of the formation, creating the necessary conditions for killing wells in order to carry out repair work in them. To control hydrodynamic processes, a mathematical model of the blocking process in the near-wellbore formation zone is proposed. It has a three-stage scheme that ensures equalization of the injectivity profile under conditions of extremely low formation pressures. The possibilities of using gel-forming blocking fluids with filler to create a temporary screen that prevents the penetration of killing fluid into highly permeable formations from abnormally low formation pressures have been explored. Based on the results of the study, we can conclude that the control of hydrodynamic processes in the near-wellbore zone of the formation at abnormally low formation pressures creates the necessary condition for effective blocking of the productive horizon in gas and gas-condensate wells, and due to the sequential treatment of the formation with a special liquid to level the injectivity profile and gel-forming blocking composition, allows one to kill the well and prevents the working fluid from penetrating into the depths of the formation during work.

Seismicity near Mayotte explained by interacting magma bodies: Insights from numerical modeling

Mayotte island experienced a large volcanic eruption 50 km offshore in 2018–2021, creating the submarine volcano “Fani Maoré”. The eruption was accompanied by intense seismicity at mantle depths (20–45 km), divided into a “proximal” and a “distal” cluster centered 10 and 30 km east from the island, respectively. Previous studies suggest that two separate magma reservoirs may lie at the top and bottom of the proximal cluster. Here, we assess whether two reservoirs are a mechanically viable explanation for the proximal cluster's truncated conical shape. We developed finite-element models of pressurized magma reservoirs in a 2D axisymmetric domain, modeling the reservoirs as compliant elastic ellipsoids embedded in an elastoplastic host rock. We find that, at these depths, extremely low friction is required to generate failure at realistically low reservoir pressures. This implies in turn that mechanical weakening must occur at these depths. The weakening could be induced by fractures or pore fluid overpressure in the volcanic system. We find that two superimposed reservoirs can generate a plastic domain between them, if they are spatially close enough. Several reservoir geometries (from spherical to sill-like) are plausible. A conical fracture domain is more likely to appear for reservoirs with opposite pressure loads (i.e. one inflating, one deflating). Given the geometrical match with the proximal seismicity cluster at Mayotte, we suggest that the shallower (Moho-depth) reservoir is inflating, creating a potential hazard for Mayotte island.

GENERALIZATION OF PROSPECTIVE TECHNOLOGIES FOR INCREASING HYDROCARBON EXTRACTION FROM NATURAL GAS FIELDS

The vast majority of hydrocarbon fields in Ukraine are at the final stage of development, characterized by complicated conditions for hydrocarbon production. The difficulty of extracting residual hydrocarbon reserves is associated with low reservoir pressures, high water cut, destruction of the bottomhole formation zone, and corrosion of underground and surface equipment. The depletion of the main fields in terms of production and reserves leads to a decrease in hydrocarbon production levels. The fields discovered in recent years are characterized by a complex structure, large depths of productive reservoirs, insignificant reserves and cannot significantly affect the maintenance of hydrocarbon production. Therefore, the main potential reserve for increasing production levels is the residual reserves of depleted fields. The raw material base of such reservoirsis characterized by a deterioration in the quality and structure of reserves over time and is accompanied by an increase in the share of hard-to-extract reserves. To increase the efficiency of development of proven hydrocarbon reserves, existing approaches have been improved and new approaches have been developed for the extraction of hydrocarbons from watered formations, the extraction of retrograde condensate that fell during the development of gas condensate fields for depletion, and the cleaning of bottomhole zones of gas and gas condensate wells and wells. Negative influence of complicating factors during their operation. However, increasing the efficiency of oil and gas field development is possible by investing in the implementation of developed technologies, which will increase their production capabilities in conditions of a significant shortage of hydrocarbon raw materials in Ukraine. Due to the high technological efficiency of secondary technologies for the development of hydrocarbon fields, which is also confirmed by industrial data, their implementation in the fields of Ukraine is recommended.

Gas lifting design and application in geothermal wells: A case study from West Anatolia, Turkiye

The gas content of the producing fluid has crucial effects on the production performance of geothermal wells. The decline of non-condensable gases (NCG) could result in significant performance reduction of the wells. Artificial production techniques such as pumps (i.e., Line Shaft Pump and Electrical Submersible Pump) and gas lifting are the widely known methods for enhancing the production performance of wells. Due to the high-temperature working environment and the well's inclination, pumps might be inconvenient for geothermal wells. Continuous injection of gases such as nitrogen (N2) and carbon dioxide (CO2) serving as gas lifting might be the appropriate method to enhance production from geothermal wells suffering from low gas content and reservoir pressure. This study investigates production enhancement with gas lifting in a geothermal field in Turkiye. The study aims to fill the gap of gas lifting in the geothermal industry as an alternative to downhole pumps such as ESP and LSP. The sensitivity analyses were performed on the design parameters such as injection depth, rates, tubing size, number of valves, and injectate gas type influencing the production performance of gas lifting. The study found that gas lifting is an optimization problem that needs to be solved by considering gas sources, infrastructure sizes, wellbore geometry, and operating parameters.

COMPARISON OF THE EFFECT OF DIFFERENT DIRECT EMULSION EMULSIFIERS ON SYSTEM STABILITY

The use of classical systems on both water and hydrocarbon bases is limited by a number of factors and technological features of such solutions. Hydrocarbon-based drilling muds are non-ecological, have a strong dependence of rheological parameters on temperature, and have a high cost. At the same time, water-based fluids do not have sufficient inhibitory and lubricating properties and increase the risk of problems during well construction. For environmental and economic applications, there is also a type of drilling fluid represented by an oilin- water emulsion of the first type (m/v). Such systems have high technological efficiency compared to abnormally low reservoir pressures, and environmental and economic advantages compared to hydrocarbonbased solution. The initial use of such systems was determined by their use under waterbased solution conditions in order to reduce reservoir repression during drilling. However, such systems also have good hydrophobizing and inhibiting properties, low water loss to the formation and greater environmental friendliness compared to hydrocarbon-based solutions. Such characteristics allow to consider the system refinement to solve the current technological problems in the field of well construction. Experience in the development and use of similar systems is reflected in the works, based on the results of laboratory and field tests, a formulation of a stable emulsion of the 1st type is presented, which includes an aqueous phase saturated with chloride. To determine the possibility of using the systems, pilot tests are carried out for the stability of the system based on various emulsifiers

Efficiency of gas preparation technology using a block drying plant

The object of research is the technology of gas drying using a mobile block installation. The task to ensure compliance of the composition of natural gas with the values of a number of basic characteristics before its supply to main pipelines has been solved. The results of a complex analysis of the gas preparation technology of the deposit, which is located in an agricultural area and is at a late stage of exploitation, are reported. It was established that in order to ensure the supply of conditioned gas to the system of main gas pipelines under the conditions of low gas pressures, the construction of gas treatment plants is required, first of all, for its drying. The method of ensuring gas quality considered in the current paper involves the use of a block-type gas drying installation as part of a low-temperature separation installation and a source of artificial cold. As the latter, it is envisaged to use a freon-refrigerating unit. The study shows that the proposed block gas drying units can be unified for different gas productivity and are characterized by relatively low capital and operating costs. The main advantages of the introduction of gas preparation block installations and the scheme of connecting the installation to the existing line are presented. Based on the results of the economic efficiency indicators, it was established that the use of a block gas drying unit is a profitable project with the value of the accumulated reduced free cash flow of almost 843 thousand conditional units; the investment payback period is 3 years. The results could be effectively used in the gas distribution sector, provided that the gas is extracted from a field close to exhaustion, which is characterized by low reservoir pressures

Solutions to increase the C-2P well production performance at X oil field, Block 09-2

The well C-2P had its first oil production in July 2008, the initial production rate is 3,000 barrels/day. Due to the reservoir pressure depletion in 2017-2018, the well faced difficulties in kicking off to open the well for production. In November 2018, when the C-5PST2 well was put into production, the C-2P well was not produced by natural flowing. The kicking off has been attempted many times but the well still won't flow. The main reason the well couldn’t flow is due to low reservoir pressure which has not enough energy to push all the fluid in the well to the surface after each well shutdown. The flow assurance study shows, at the reservoir pressure of 3,000 Psi, and tubing head pressure of 950 Psi, the well can’t flow naturally. In addition, with the reservoir pressure of 3,000 psia and applying the gaslift injection rate of 1.0 MMscf/d, injection point at 3,030 mTVD, the well flowed. The continuous gaslift pump helps maintain the well's production in case the reservoir pressure drops even lower to 2,000 psi, and at the same time, optimizing the gaslift pump flow helps to increase the well production by 100-300 barrels of oil/day. When the reservoir pressure drops lower, it is necessary to lower the gaslift valve deeper to continue kicking off the well and maintain the well production performance. On the other hand, due to the lack of a gaslift valve for the original design of C-2P well so it's necessary to have gaslift tubing pack off in order to bring the well back to production, maintain stability and improve production. This paper, therefore, presents the results of the research on the solution to increase the production output of the C-2P well located in X oil field used gaslift valve combining with the tubing pack off. Results of the research on the application of solution show that the well's production output has increased significantly (0.354 million barrels) in the first year of applying the solution.

CO2 storage in organic nanopores with varying widths: Molecular simulation and simplified local density model

Accurately characterizing CO2 adsorption behavior in organic nanopores is a prerequisite for estimating CO2 storage capacity in shale reservoirs with complex pore structures. This study employs grand canonical Monte Carlo (GCMC) molecular simulations to investigate the CO2 adsorption characteristics in organic nanopores with varying widths over a wide range of temperatures and pressures. Based on GCMC simulations, the pore width in the simplified Local-Density (SLD) adsorption model is related to key adsorption parameters, enabling the SLD model to evaluate CO2 storage density rapidly and accurately in organic nanopores under complex reservoir conditions. The research findings suggest that the features of CO2 excess adsorption curves are mainly influenced by temperature and the number of adsorption layers. Higher temperatures and increased adsorption layers result in higher pressure requirements to achieve the CO2 excess adsorption peak. Under high pressures, the number of adsorption layers plays a critical role in enhancing the adsorption capacity. Due to the constraints of pore size, there are fewer adsorption layers in micropores, leading to higher CO2 excess adsorption in mesopores than in micropores under high pressures. In the SLD model, the key parameter Λb decays exponentially with the increase of pore width. The average density of CO2 in the nanopores calculated by the modified SLD model is in good agreement with the simulation results. Finally, the research reveals that smaller organic nanopore widths result in higher CO2 densities, with limited sensitivity to temperature and pressure variations. Low pressure and high temperature reservoir conditions are unfavorable for CO2 storage, but adsorption significantly enhances CO2 storage density in nanopores, particularly in micropores.

Analysis of Well Performance Based on Bottom Hole Pressure Calculations for Gas Lift Application

This paper focuses on optimizing gas lift techniques in four wells located in the North Sea to overcome the common issue of low reservoir pressure. Gas lift is a common artificial lift technique used in wells with low reservoir pressure where the natural pressure of the reservoir is insufficient to bring the oil to the surface. The success of gas lift optimization depends on identifying the deepest injection point, gas injection rate, and pressure of the gas injected. The paper proposes the deepest injection points for wells A-03, A-09A, A-10T2, and A-12BT2 as 3809.38 ft, 6649.7 ft, 3559.88 ft, and 3979.04 ft, respectively. The injection rates analyzed in this paper range from 1-10 mmscf/day, and injection pressures of 500 psia, 1000 psia, and 1500 psia were used. The response of each well to gas lift was analyzed, and increasing injection rate and pressure were found to increase oil production rate. The optimal gas injection rate and pressure for wells A-03, A-09A, and A-12BT2 were found to be 10 mmscf/day and 1500 psia, while for well A-12BT2, the best oil recovery was obtained at an injection rate of 3 mmcsf/day and injection pressure of 1500 psia. Tubing size within the range of 1-5.5 inch was examined, and it was found that increasing tubing size enhances oil flow rate. The optimal tubing size for the wells was found to be 5.5 inch, taking into consideration factors such as flow rate, pressure, temperature requirements, and fluid type.

Practical experience of heat treatment of an oil carbonate reservoir

The majority of reserves of small oil companies of the Republic of Tatarstan are represented by carbonate reservoirs with low filtration and capacitance properties, low reservoir pressures and high oil viscosity. All this leads to a rapid decrease and a low level of current oil flows. The Akan oil field of Predpriyatie Kara Altyn CJSC is one of the examples. Thermal methods are considered as the most effective technologies for deposits with high-viscosity oil. According to the results of laboratory study of various variants of thermal methods and geological and hydrodynamic modeling, the steam-cyclic method of development was determined as the most effective at the Akan field. Two producing directional wells and two horizontal wells have been selected for experimental work on steam injection. The article considers the downhole equipment used for injection heat carrier, describes the process of steam injection with the dynamics of controlled parameters, production indicators and efficiency after heat treatment of wells. Conclusions are presented for the completed works on wells.

On the 3D fluid behavior during CBM coproduction in a multi pressure system: Insights from experimental analysis and mathematical models

To investigate the dynamic response characteristics of coalbed methane (CBM) reservoirs with multi pressure system induced by coproduction, physical simulation experiments were conducted on CBM coproduction under both conventional and constant-rate coproduction modes using a self-built experimental platform. The results showed that constant-rate coproduction can significantly extend the stable coproduction period of CBM compared to conventional coproduction, but it may have an inhibitory effect on certain reservoirs, which is negatively correlated with the initial reservoir pressure. Constant-rate coproduction can cause disturbance effects on reservoir pressure, leading to an increase in the expansion resistance of the pressure-reduction funnel during coproduction, and even the appearance of the pressure-buildup funnel of low-pressure reservoirs. A calculation principle for the 3D fluid flow parameters was developed by considering the dynamic permeability and the pressure gradient of the reservoir. The 3D fluid flow parameters were employed to quantitatively characterize the spatial and temporal evolution of fluid relative flow velocity and deflection angle in the reservoir during coproduction. Near the far end of the wellbore, the fluid flowed nearly horizontally, while near the wellbore, the fluid flowed towards or away from the wellbore center due to different levels of disturbance.

A laboratory observation for gases transport in shale nanochannels: Helium, nitrogen, methane, and helium-methane mixture

Mudstones are widely distributed in sedimentary basins with abundant nanopores and has very low fluid mobility. It is widely accepted that gas migration in micro-nanochannels no longer follows Darcy's law and the Hagen-Poiseuille equation and that molecular kinetic features profoundly influence gas migration in micro-nanochannels. Here, we characterize the nanochannel sizes of Longmaxi Shale cores under different overburden pressure and pore pressure conditions. And the apparent permeabilities of individual component gases (helium, nitrogen, and methane) in different size nanochannels are compared. Then the variations for components and methane carbon isotope values of the overflowing helium-methane mixture are analyzed. The results show that the molecular slippage effect contributes significantly to the transport of the three gases, especially at low pore pressures; helium has the largest apparent permeability because of its largest molecular mean free path (or Knudsen number). Methane has the smallest molecular mean free path, and the adsorption effect reduces channel size and increases surface roughness, which inhibits the molecular slip effect and therefore results in methane having the smallest apparent permeability. Helium has a transport advantage in the helium-methane mixture due to its Knudsen number advantage, and the larger Knudsen number of 12CH4 likewise leads to a transport advantage over 13CH4. This study suggests that the molecular slippage effect may be an important molecular dynamics mechanism for the efficient development of shale gas. Pressure gradient-driven transport of helium-bearing gas in nanochannels is an essential mechanism for helium enrichment, and high-grade helium reservoirs should occur in secondary low-pressure reservoirs in the basin.