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ABSTRACTThis study investigates the effect of compartmentalisation in the Lower Cretaceous Zubair Formation in the Bahrah Field in Kuwait, with proven plays’ success ranging from 50 to 60% due to irregular trapping configurations and fluid retention resulting from reservoir compartmentalisation and heterogeneity. An integrated analysis was conducted, including facies mapping, core data, sedimentological and petrographic assessments, pressure measurements and fluid contacts correlated with the structure map that was subjected to cross-fault juxtaposition analysis to test fault sealing capability. It’s found that the main reservoir units Z10 and Z23 are trapped on the upper down-dip side of the Bahrah Anticline by a set of NW-SE trending faults exhibiting effective sealing. Vertically, the reservoirs are sealed by internal Zubair shales. The Z10 unit is highly compartmentalised by strong lateral sealing from the Ratawi shale, while the Z23 unit experiences some hydrocarbon leakage through fault planes. Core data indicate reservoirs have an average porosity of 14.2% (7.6–20%), shale volume of 12.8% (7.2–20.3%), water saturation of 42.2% (19.5–100%) and permeability of 1080 mD (.01–6180 mD). Pressure measurements, fluid contacts and sedimentological analysis support lateral heterogeneity. The traps are a combination of structural and stratigraphic mechanisms related to the fluvio-deltaic depositional environment and subsequent deformation.

In recent years, the volcanic–plutonic relationship has been a contentious topic among researchers. Based on this issue, they have delved deeper into the constraints of magma reservoir pressure and H2O on pre-eruptive melt accumulation and migration. We selected granodiorite, tonalite, and rhyolite in the Dehailonggang volcanic–plutonic complex to investigate the volcanic–plutonic connection and constraints of reservoir pressure and H2O on the pre-eruptive melt accumulation and migration in water-rich systems. Granodiorite, tonalite, and rhyolite exhibit temporal–spatial similarities (247 Ma) and the same magmatic origin consisting of ca. 75–80% enriched mantle materials mixed with ca. 20–25% lower crustal materials. TESCAN integrated mineral analyzer (TIMA) shows that both granodiorite and tonalite display a typical cumulate texture. The bulk–rock compositional complementary of the granodiorite, tonalite, and rhyolite, coupled with in situ geochemical signatures of feldspars and zircons, feldspar CSD, and rhyolite–MELTS modeling, indicate that (1) the granodiorite represents the crystal cumulate formed after crystal–melt phase separation of the original mush (OM) in the magma reservoir; (2) the interstitial melt of the OM was extracted, migrated, and ultimately erupted as the rhyolite; (3) the tonalite serves as an intermediate product resulting from the phase separation from the OM to the rhyolite. Rhyolite–MELTS modeling reveals that in water-rich environments, an increase in reservoir pressure (prior to reaching overpressure threshold) can lead to a reduction in melt viscosity. This, in turn, accelerates mechanical compaction and phase separation processes, ultimately shortening the pre-eruptive melt aggregation timescale. In contrast, it is noteworthy that H2O has a relatively minor influence on phase separation in such water-rich systems (> 4 wt. %). This study demonstrates the volcanic–plutonic genetic coupling and highlights the significance of reservoir pressure in controlling the dynamics of pre-eruptive melt within water-rich systems. [ABSTRACT FROM AUTHOR]

Currently, most of the wells in X Oilfield are self-flowing wells. In order to adjust the production system of oil wells in time according to the production requirements of oilfields, it is necessary to predict the ceasing-flowing time. Therefore, how to accurately predict the ceasing-flowing time is the main problem faced by the self-flowing well. As the conventional prediction methods only consider the influence of a single variable, the prediction results are not ideal. Combining the production prediction based on the long short-term memory (LSTM) neural network and the inflow and outflow dynamic curves, this study proposes a comprehensive method for predicting the ceasing-flowing time of a flowing well by considering multiple factors. Using the minimum wellhead pressure prediction method, the changes in bottom hole flowing pressure and reservoir pressure are also considered. The practical application results in X Oilfield show that the calculated and predicted results are highly consistent with the actual production data, verifying the reliability of this method. This study can provide a reference for the prediction of oil well ceasing-flowing in other oilfields. [ABSTRACT FROM AUTHOR]

Introduction. Small innovative enterprises are able to solve the problems of technological support of the construction sector. A special place is occupied by enterprises created on the basis of the results of intellectual activity (RIA) of higher educational institutions. The activities of small companies created with the participation of universities have a number of advantages. The scientific and educational environment creates additional opportunities for small businesses in conducting research and development, as well as opens up access to human resources. An example of the commercialization of RIA is the technological developments based on nanomaterial of St Petersburg University enterprises in solving the problem of abandonment of orphan wells, which contribute to the pollution of groundwater. Methods and materials. Abandoned wells are abandoned according to “standard designs” that provide for the abandonment of only the wellbore limited by the inner diameter of the casing pipes, and do not contain technical solutions for the elimination of behind-the-casing flows. Results. An ownerless well, after its abandonment according to the “standard project”, continues to contaminate groundwater, but on a permanent basis, since repeated abandonment of such wells is practically impossible. Each such “abandoned” well is an officially created channel for groundwater contamination in the long term. Discussion. The article contains an analysis of the existing technology of abandonment of wells, including ownerless ones, as well as the justification of the futility of its use to eliminate sources of groundwater pollution. An alternative solution based on the use of modern nanomaterials is proposed. Conclusion. Examples of successful application of the proposed technology with the use of cemented nanomaterials for the liquidation of emergency wells in the North-West region are given. Based on the study, conclusions and recommendations are made.

Copyright of Journal of Engineering (17264073) is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Velocity string (VS) is one of the most common methods to unload water in gas-producing field. In order to understand the behavior affecting production rate, we obtained several parameters including well completion, gas well production data, gas liquid ratio (GLR) and pressure data at tubing and casing head pressure, flowing bottom hole pressure. We then explore the relationship between these parameters against reservoir pressure and perform sensitivity analysis using multiphase steady-state flow simulator to analyze the parameters are the most sensitive to gas production rate. The results show that: (1) at larger inner diameter of the VS, there is a certain increase trend of gas production of gas wells. However, the production rate does not show a linear increase relationship with the larger internal diameter. It will reach certain inflection point before it decreases; (2) the gas production of the VS well is mainly driven by the reservoir pressure, the higher the reservoir pressure, the greater the gas production; (3) the root cause of relatively low initial production rate after small inner diameter coiled tubing VS installation is categorized as an abnormal well startup. This study provides theoretical support for selecting the optimum size and depth of VS to maintain well productivity. [ABSTRACT FROM AUTHOR]

Reservoir pressure reduction due to continuous production from oil and gas wells affects the sand production rate. An increase in drawdown pressure and/or a decrease in reservoir pressure increases the sand production rate. Since the problem of sand production is one of the main issues in the Asmari sandstone formation located in one of the oilfields in the southwest of Iran, therefore, in this research, the variations in the sand production rate due to the changes in the reservoir and drawdown pressures were investigated. So, for the first time, a hybrid numerical model of finite difference method (FDM)—discrete element method (DEM)—finite element method (FEM)—computational fluid dynamics (CFD) was developed. This numerical model investigated the increase in the sand production rate due to variations in reservoir pressure with a constant bottom-hole flowing pressure. Then, by performing an extensive sensitivity analysis on different values of reservoir pressure and drawdown pressure, the changes in the sanding rate, the critical drawdown pressure, and the safe drawdown line were determined. The results showed that, if the production flow rate of the well is constant, increasing the drawdown pressure can change the sand production rate only to a certain extent, and more than that, will be produced at a constant rate. Also, adjusting the drawdown pressure within a safe range does not necessarily keep the sand production rate constant at a permissible value for a long time, while by keeping the bottom hole flowing pressure constant within an acceptable range, the sand production rate can be controlled for a longer period. [ABSTRACT FROM AUTHOR]

Currently, most of the wells in X Oilfield are self-flowing wells. In order to adjust the production system of oil wells in time according to the production requirements of oilfields, it is necessary to predict the ceasing–flowing time. Therefore, how to accurately predict the ceasing–flowing time is the main problem faced by the self-flowing well. As the conventional prediction methods only consider the influence of a single variable, the prediction results are not ideal. Combining the production prediction based on the long short-term memory (LSTM) neural network and the inflow and outflow dynamic curves, this study proposes a comprehensive method for predicting the ceasing–flowing time of a flowing well by considering multiple factors. Using the minimum wellhead pressure prediction method, the changes in bottom hole flowing pressure and reservoir pressure are also considered. The practical application results in X Oilfield show that the calculated and predicted results are highly consistent with the actual production data, verifying the reliability of this method. This study can provide a reference for the prediction of oil well ceasing–flowing in other oilfields.

The occurrence and output of coalbed methane (CBM) are controlled by the occurrence geological conditions of coal reservoirs, such as stress, pressure, and temperature. The correct analysis of the occurrence geological conditions of coal reservoirs and their impact on permeability is a key issue of concern for an effective development of CBM. Based on the test data of 63 CBM wells in the southern part of the Qinshui Basin, the ground stress, pressure and temperature conditions of coal reservoirs in the study area are systematically analyzed, the variation law of coal reservoir stress, pressure and temperature with burial depth is revealed, and the relationship between the minimum horizontal principal stress and the vertical principal stress and the pressure of coal reservoir is established. Using the triaxial seepage test system, the experiment of CBM seepage under different stress, pressure and temperature conditions is carried out, and the variation law and control mechanism of coal sample permeability under different temperature, stress and pressure conditions are revealed. The results show that the maximum and minimum horizontal principal stresses of the coal reservoirs in the study area are 6.62−42.06 MPa and 3.30−26.40 MPa, respectively, with the gradients of 1.20−5.26 MPa/hm and 0.99−2.95 MPa/hm, respectively. The coal reservoir pressures and their gradients are 0.99−12.63 MPa and 0.23−1.18 MPa/hm; the coal reservoir temperatures and their gradients are 19.36−38.84 ℃ and 1.98 ℃/hm, respectively. The coal reservoir stress, pressure and temperature increase linearly with the increase of depth. With the increase of effective stress, the permeability of the coal reservoir decreases continuously, the permeability decreases greatly in the initial pressurization stage, but decrease slows down with the increase of effective stress. Under the same stress conditions, the permeability of coal samples and the decrease rate of permeability decrease continuously with the increase of temperature. With the increase of effective stress and temperature, the permeability of coal reservoir decreases according to the law of negative exponential function. With the decrease of pore pressure, the effective stress increases, but the permeability of coal reservoir decreases. In the initial depressurization stage, the permeability of the coal reservoir decreases sharply, and with the reduction of pore pressure, the decrease rate of permeability gradually slows down. When the pore pressure is less than 0.6 MPa, the permeability of the coal reservoir increases with the decrease of pore pressure. Under the condition of high pore pressure, the permeability decreases with the increase of temperature in a negative exponential function, while under the condition of low pore pressure, the permeability of coal reservoir decreases linearly with the increase of temperature. Based on the above results, the relationship model between coal reservoir permeability and stress, pressure and temperature is established. Also, the law and control mechanism of coal reservoir permeability decrease according to negative exponential function with the increase of stress, pressure and temperature stress are expounded.

Abstract Reservoir pressure reduction due to continuous production from oil and gas wells affects the sand production rate. An increase in drawdown pressure and/or a decrease in reservoir pressure increases the sand production rate. Since the problem of sand production is one of the main issues in the Asmari sandstone formation located in one of the oilfields in the southwest of Iran, therefore, in this research, the variations in the sand production rate due to the changes in the reservoir and drawdown pressures were investigated. So, for the first time, a hybrid numerical model of finite difference method (FDM)—discrete element method (DEM)—finite element method (FEM)—computational fluid dynamics (CFD) was developed. This numerical model investigated the increase in the sand production rate due to variations in reservoir pressure with a constant bottom-hole flowing pressure. Then, by performing an extensive sensitivity analysis on different values of reservoir pressure and drawdown pressure, the changes in the sanding rate, the critical drawdown pressure, and the safe drawdown line were determined. The results showed that, if the production flow rate of the well is constant, increasing the drawdown pressure can change the sand production rate only to a certain extent, and more than that, will be produced at a constant rate. Also, adjusting the drawdown pressure within a safe range does not necessarily keep the sand production rate constant at a permissible value for a long time, while by keeping the bottom hole flowing pressure constant within an acceptable range, the sand production rate can be controlled for a longer period.

Copyright of Coal Geology & Exploration is the property of Xian Research Institute of China Coal Research Institute and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The study examines the application of dry gas injection technology (cycling process) in different depletion stages (25%, 50%, 75%, 100% of the initial reservoir pressure, and the dew point pressure) at a gas condensate field. The injection took place with varying numbers of injection wells relative to production wells (4:1, 3:1, 2:1, 1:1, and 1:2). The study assessed the impact of dry gas injection periods, ranging from 1 to 3 years, on increasing the condensate recovery factor in a real gas condensate reservoir named X. A hydrodynamic model was used and calibrated with historical data, resulting in a comprehensive approach. Compared to the traditional depletion development method, this approach led to a significant 9% rise in the condensate recovery factor. The results indicate that injection has a positive effect on enhancing the recovery factor of condensate and gas when compared to primary development methods based on depletion. As a result, these findings facilitate a rapid evaluation of the possibility of introducing similar measures in gas-condensate reservoirs in the future for reservoir systems that have a low and moderate potential for liquid hydrocarbons C5+. The optimised multidimensional hydrodynamic calculations, utilising geological and technological models, are crucial in determining the parameters for the technological production and injection wells. [ABSTRACT FROM AUTHOR]

Reservoir pressure plays a significant role in all reservoir and production engineering studies. It is crucial to characterize petroleum reservoirs: by detecting fluid movement, computing oil in place, and calculating the recovery factor. Knowledge of reservoir pressure is essential for predicting future production rates, optimizing well performance, or planning enhanced oil recovery strategies. However, applying the methods to investigate reservoir pressure performance is challenging because reservoirs are large, complex systems with irregular geometries in subsurface formations with numerous uncertainties and limited information about the reservoir's structure and behavior. Furthermore, many computational techniques, both numerical and analytical, have been utilized to examine reservoir pressure performance. This paper summarizes the concepts and applications of traditional and novel ways to investigate reservoir pressure changes over time. It provides a comprehensive review that assists the reader in recognizing and distinguishing between various techniques for obtaining an accurate description of reservoir pressure behavior during production, such as the reservoir simulation method, material balance equation approach, time-lapse seismic data, and modern artificial intelligence methods. Thus, the central concept of these procedures and a list of the authors' research are discussed.

In this paper we present the results of studies of the Botuobin, Talakh, and Khamakin reservoirs of the Vendian period in the Chayanda hydrocarbon field (Eastern Siberia). Based on an analysis of variations in the petrophysical parameters of reservoirs upon an increase in effective pressure from 37 to 57 MPa, i.e., under conditions simulating the development of a field for depletion, changes in the volume and compressibility of the pore space are estimated. In this case, the porosity coefficient decreases by 0.043 abs. %, while the compressibility of the pore space decreases by 0.228 1/GPa. The average volumetric compression strain increases by 0.096%, which means a reduction in the volume of developed reservoirs by almost 0.1% relative to the beginning of development. A deformable formation model developed by Yu.O. Kuzmin based on the geodynamic history of the development of deposits is applied to estimate the magnitude of possible subsidence of the ground surface during development. The maximal values of possible surface subsidence (drawdowns) upon a decrease in reservoir fluid pressure by 5 MPa are estimated to be 0.33 m with allowance for the dynamics of petrophysical parameters and 0.335 m with no allowance for it. The maximal drawdowns are already estimated at 0.60 and 0.65 m upon a decrease in reservoir pressure by 10 MPa and 0.78 and 0.83 m upon a complete depletion of reservoir energy, respectively. The results of the studies show that taking into account the changes in petrophysical characteristics caused by the field development processes alters the estimate of the deformation state of the rock massif and the ground surface above the deposit and, consequently, the estimate of the level of geodynamic risk of oil-and-gas complex objects. [ABSTRACT FROM AUTHOR]

To study the influence of different drainage methods on the production performance of coal measure gas wells, the interbedded reservoir composed of coal and shale in the Longtan Formation of the Dahebian block was used as the research object. Considering the influence of coal and shale matrix shrinkage, effective stress, and interlayer fluid flow on reservoir properties such as fluid migration behavior and permeability, a fluid–solid coupling mathematical model of coal measure superimposed gas reservoirs was established. Numerical simulations of coal measure gas production under different drainage and production modes were conducted to analyze the evolution of reservoir pressure, gas content in the matrix, permeability, and other characteristic parameters of the superimposed reservoir, as well as differences in interlayer flow. The results showed that, compared to single-layer drainage, cumulative gas production increased by 33% under multi-layer drainage. Both drainage methods involve interlayer energy and substance transfer. Due to the influence of permeability, porosity, and mechanical properties, significant differences exist in reservoir pressure distribution, preferential flow direction, gas content in the matrix, and permeability ratio between coal and shale reservoirs under different drainage and production modes. Multi-layer drainage effectively alleviates the influence of vertical reservoir pressure differences between reservoir layers, facilitates reservoir pressure transmission in shale reservoirs, enhances methane desorption in shale matrices, promotes matrix shrinkage, and induces the rebound of shale reservoir permeability, thus improving overall gas production. [ABSTRACT FROM AUTHOR]

The relevance of the study is related to the growing need for efficient production of hydrocarbons in the difficult geological conditions of western Turkmenistan to ensure energy security and economic development of the region in the changing global oil and gas market. The purpose of the study is to conduct a comprehensive analysis of the geological, technical, and economic aspects of drilling ultra-deep wells in difficult geological conditions of western Turkmenistan to assess their potential feasibility and contribution to the energy infrastructure of the region. The study used analytical, functional, and statistical methods, classification, and synthesis. The prospects for drilling wells in difficult and extreme geological conditions of western Turkmenistan were identified. The analysis of the current state of prospecting and exploration in this region was carried out, while the main attention was paid to the investigation of the main difficulties faced by drillers when working with deep horizons of the reedbeds. As a result of the conducted research, general principles and recommendations aimed at overcoming these problems were developed. Despite the successful introduction of modern technical and technological innovations that meet international standards when drilling deep and ultra-deep wells in the West Turkmen depression, the study emphasized that the existing drilling problems have not yet been eliminated. This study will provide valuable recommendations and information for making informed decisions when developing and implementing projects for drilling ultra-deep wells in difficult geological conditions, contributing to effective resource management and development of the oil and gas industry in western Turkmenistan. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Hydraulic fracturing is an effective way to stimulate oil production, which is currently widely used in various conditions, including complex carbonate reservoirs. In the conditions of the considered field, hydraulic fracturing leads to a significant differentiation of technological efficiency indicators, which makes it expedient to study in detail the crack formation patterns. For all affected wells, the assessment of the resulting fractures spatial orientation was performed using the developed indirect technique, the reliability of which was confirmed by geophysical methods. In the course of the analysis, it was found that in all cases the fracture is oriented in the direction of the development system element area, which is characterized by the maximum reservoir pressure. At the same time, reservoir pressure values for all wells were determined at one point in time (at the beginning of hydraulic fracturing) using machine learning methods. The reliability of the used machine learning methods is confirmed by high convergence with the actual (historical) reservoir pressures obtained during hydrodynamic studies of wells. The obtained conclusion about the influence of the formation pressure on the patterns of fracturing should be taken into account when planning hydraulic fracturing in the considered conditions.

Since artificial intelligence has become increasingly prevalent in the oil industry, it is relevant to this study since it is being used for exploration, development, production, field design, and management planning to improve decision-making, reduce costs, and speed up production. For establishing relationships between complex non-linear datasets, machine learning has proved superior to regression methods in petroleum engineering when it comes to highdimensional data prediction errors, processing power, and memory. In this article, machine learning is compared with conventional statistical models of oil and gas engineering for determining and predicting reservoir pressure values in the development of oil fields. The effectiveness and potential of machine learning to determine reservoir pressure values was analysed. Using non-parametric multivariate model that link well performance over time, a new method is proposed for predicting reservoir pressure using machine learning. According to the proposed method, the predicted reservoir pressure correlates well with values measured by hydrodynamic studies of wells based on the dynamics of indicators describing well performance. Machine learning method based on random forest algorithm tends to provide better prediction reliability for reservoir pressure than linear regression method (absolute deviation: 0.86; relative deviation: 6.8%) [ABSTRACT FROM AUTHOR]

Despite minimal formation damage or water-cut, the majority of oil wells in brown oil fields cease to flow naturally. The current study looks into and analyses what caused a self-flowing well in the upper Assam basin to become non-flowing. The non-flow condition of the well was investigated in the current work as a function of water cut, reservoir pressure, reservoir rock permeability, and GOR. The effect of WHP and WHT on these functions was investigated. This work incorporates innovative methodology that uses the PROSPER simulation model for assessing the possibility of establishing flowability in a dead well based on inflow (IPR) and vertical lift performance (VLP). Subsequent analysis was carried out to examine the scope of producing this dead well under continuous flow gas lift. For this, the current work first examined the tubing diameter and reservoir temperature as standalone parameters to find out if they have any role to play in the flowability of the dead well. Following this, sensitivity analysis was done taking four parameters into account, i.e., reservoir pressure, reservoir rock permeability, water cut, and total GOR. In the current work, surface equipment correlation was established using Beggs and Brill correlation, while vertical lift performance was established using correlation from Petroleum Expert. The results of the current work highlight that a well's production rate under continuous flow gas lift can be enhanced by employing an optimised gas injection rate. The findings of this work conclude that higher reservoir pressure enables an oil well to produce with a high water cut under a continuous flow gas lift system, provided there are no formation damage issues on the well.

The relevance of the research is caused by the need to take into account the effects of sandstone reservoir rocks deformations and changes in reservoir permeability for predicting oil wells productivity under conditions of varying values of reservoir and bottomhole pressures. The main aim of the research is based on the results of laboratory experiments, to identify relationships of changes in the sandstone reservoir core samples permeability with changes in reservoir and bottomhole pressures and to assess the degree of these effects influence on the oil well productivity. Objects: sandstone reservoir rocks of the oil fields located in the south of the Perm Region. Methods: laboratory research of the core samples permeability using the laboratory equipment at various values of pore pressure and sample compression pressure; numerical simulation of the near-wellbore zone by the finite element method using the basic relationships of the Biot theory of poroelasticity to determine the magnitude of effective stresses and their effect on the reservoir rocks permeability and oil well productivity. Results. The authors have obtained the analytical relationships that describe the change in permeability with a decrease and recover of reservoir and bottomhole pressure, which showed a decrease in the permeability of core samples by 20,6 % with a limiting decrease in pore pressure from 14,5 to 5 MPa. When the pressure is recovered to the initial value, the permeability is restored only by 84,5 %, which indicates a significant role of rocks irreversible plastic deformations. The results of numerical modeling of the effective stresses distribution in the near-wellbore zone showed that in case of creating the maximum bottomhole pressure drawdown of 9,5 MPa the productivity factor decreases by 10 %. If the drawdown is reduced and the bottomhole pressure is recovered, then the productivity factor recovers just to 92 % of the initial value, which again indicates the negative role of plastic deformations of the reservoir rock. If the reservoir pressure drops to 8,5 MPa, then the reducing in the productivity factor is 13 % compared to the maximum value.

During oil and gas fields development, a decrease in reservoir and bottomhole pressure has often a detrimental effect on reservoir properties, especially permeability. This study presents the results of laboratory tests conducted to determine the response of terrigenous reservoir core-sample permeability to changes in the effective stresses and a decrease in the reservoir pressure. The considered samples were exposed for a long time to a constant high effective stress for a more reliable assessment of the viscoplastic deformations. According to these experiments, the decrease of the core samples permeability may reach 21% with a decrease in pressure by 9.5 MPa from the initial reservoir conditions. Numerical simulations have been also conducted. These have been based on the finite element modeling of the near-wellbore zone of the terrigenous reservoir using poroelasticity relations. The simulation results show a limited decrease in reservoir permeability in the near-wellbore zone (by 17%, which can lead to a decrease in the well productivity by 13%). [ABSTRACT FROM AUTHOR]

The relevance of the study is caused by the fact that at present there are practically no pure oil fields left on the territory of Western Siberia. A huge share of reserves is concentrated in oil rims, reservoirs with high gas pressure or the presence of a gas cap. The development of such oil fields by simple methods (for example, a rigid water pressure mode) is difficult, since there is a sharp decrease in reservoir pressure on them and the impossibility of its recovery by these mechanisms. It is necessary to consider alternative methods of influence to involve hard-to-recover hydrocarbon reserves in the development. The article discusses the combined use of water-gas treatment with the utilization of associated oil gas. The technique is caused by the fact that, first of all, a mechanism for gas compression and mixing with liquid has been developed to maintain reservoir pressure. The joint methodology of water-gas impact will allow effectively influencing reservoir with high gas pressure, and will also eliminate the need for utilization of associated oil gas due to technological processes. The main aim is to research and suggest a method for using water-gas impact with the recycling of associated oil gas for areas with a rate of reservoir pressure drop. Object: reservoir with high gas content under development. Methods: theoretical methods to substantiate the way of increasing gas pressure and the ability to mix gas with liquid to maintain reservoir pressure, analytical and computational methods. Results. The authors obtained the technique for compressing and mixing associated oil gas. The paper considers the technique for applying water-gas treatment using software. The effectiveness of the method was proved.

A complete understanding of the mechanism and characteristics of the migration and output of coalbed methane (CBM) is of great significance for CBM development. For the coal reservoir in a micropore overpressure environment, the "Reservoir inner surface desorption-micropore diffusion-natural fracture seepage" cannot completely describe the CBM production process. To this end, starting from the three stages of CBM production, based on the microporous overpressure environment of coal reservoirs to reveal CBM's migration and production mechanism. The results show that: (1) In the stage of saturated single-phase water flow, CBM was transported by "solution mass transfer"; (2) At the single-phase unsaturated water flow stage, CBM become "microporous drainage"; (3) At the two-phase gas-water flow stage, CBM is transported and produced traditionally. [ABSTRACT FROM AUTHOR]

On the basis of modern ideas about the structural organization of the geological shell of the Earth, the authors substantiate the geofluid dynamics patterns of the localization of hydrocarbon systems (and their elements) at great depths. According to the authors, under conditions of high compressive loads exerted by overlying deposits, reliable all-round lithological shielding of reservoirs, hydrodynamic stagnation in deep-seated complexes of evaporite basins, a special type of hydrocarbon system, that is, autoclaved, can be developed. The authors predict that in the Pricaspian oil-and-gas province in the subsalt oil and gas bearing stage (in the Lower Devonian–Lower Permian deposits), an autoclave hydrocarbon system could have formed due to the sealing of a salt-bearing complex of significant thickness (i), the unrealized generation potential of oil and gas source strata represented by deep-water deposits 4–6 km and deeper (ii), and hydrodynamic stagnation of the water drive system (iii). Under the control of these conditions, paleo-drive objects and intra-basin carbonate structures near contact with oil and gas source rocks act as high-capacity reservoirs for the products of catagenic fluid generation and the segregation of a single-phase fluid with phase separation of hydrocarbons during periods of a sharp decrease in reservoir pressure completes the formation of unique and large hydrocarbon fields. [ABSTRACT FROM AUTHOR]

In the processes of oil-and-gas accumulation at the lower stages of salt basins, the authors of this paper substantiate the leading role of special, autoclave type of hydrocarbon systems (HCSs). According to the authors concept, autoclave hydrocarbon systems are multiscale, tectonically and lithologically screened fluid-saturated areas of the lithosphere, which are characterized by spatiotemporal conjugation of the processes of generation, primary migration, and accumulation of hydrocarbons (HC) in an environment of hydrodynamic stagnation, age identity of fluids and fluid host rocks. The paper discusses the place of autoclave hydrocarbon systems in the hierarchical series of oil and gas localizing objects of different ranks: uvosphere → oil-and-gas bearing level → hydrocarbon system → oil-and-gas complex → oil and gas bearing horizon. The main attention is paid to the kitchen (focal) autoclave hydrocarbon systems. The general conclusion of the authors is that under the conditions of autoclave kitchen hydrocarbon systems, the segregation of hydrocarbons (when the temperature-baric threshold of phase separation of oil, condensate, and gas is reached) from a single-phase fluid is confined to zones of low hydrodynamic potentials and the localization of free hydrocarbons mainly occurs in situ. [ABSTRACT FROM AUTHOR]

The article is devoted to determining the properties of reservoir fluids and gases, as well as performing calculations to determine the dependence of the volume of dissolved gas in oil, the volume coefficient of dynamic viscosity and density on saturation pressure, determining the compressibility coefficient and other necessary indicators for the development of the multi-layer Altyguyi field by dual completion (DC). This work can be used to determine the heterogeneity of oil and gas in productive horizons for the development of multi-layer deposits by the DC method. [ABSTRACT FROM AUTHOR]

Numerical simulation is an efficient method to quantitatively describe the reservoir dynamics of coalbed methane (CBM) reservoirs. The ideal steeply inclined model (ISIM), assumed to be a steeply inclined plate, has been widely applied in steep coalbed methane reservoir modeling, although the ISIM cannot accurately reflect the actual reservoir geological conditions. In this paper, the dynamics of CBM production and reservoirs using the ISIM and actual steeply inclined model (ASIM) were compared, taking the steep coal in the Fukang mining area located in northwestern China as an example, with the purpose of revealing the differences and applicability of the ASIM and ISIM. The ASIM and ISIM were established by Petrel software, and CBM production was matched and predicted by Eclipse software. Data reflecting reservoir dynamics, such as water saturation, reservoir pressure, and gas content, were extracted. The dynamic changes in the reservoir physical properties of the ASIM and ISIM were also compared. The results showed that: 1) multiple gas production peaks occurred in both ASIM and ISIM. The maximum daily gas production of ASIM occurred earlier than the maximum daily gas production of ISIM. The peak gas production and cumulative gas production of ASIM were both greater than the peak gas production and cumulative gas production of ISIM. 2) Due to the variations in grid shape and dip angle with each grid in the ASIM, the production effect of the ASIM was better than the production effect of the ISIM in the third stage (4–10 years) of drainage. 3) In the third stage (4–10 years) of drainage, the decrease rate of reservoir pressure of ASIM was larger than the decrease rate of reservoir pressure of ISIM because of the relatively better production performance of ASIM. 4) Differentiation of gas and water dominated the variation trend of gas content, and in the third stage (4–10 years) of drainage, the ASIM has higher recovery efficiency compared with ISIM. Compared with ISIM proposed by previous scholars, the ASIM was more helpful to monitor the dynamic behavior of coal reservoirs, and ASIM can provide a more reliable basis for guiding coalbed methane development.

Geological hydrogen storage in depleted gas fields represents a new technology to mitigate climate change. It comes with several research gaps, around hydrogen recovery, including the flow behavior of hydrogen gas in porous media. Here, we provide the first‐published comprehensive experimental study of unsteady state drainage relative permeability curves with H2‐Brine, on two different types of sandstones and a carbonate rock. We investigate the effect of pressure, brine salinity, and rock type on hydrogen flow behavior and compare it to that of CH4 and N2 at high‐pressure and high‐temperature conditions representative of potential geological storage sites. Finally, we use a history matching method for modeling relative permeability curves using the measured data within the experiments. Our results suggest that nitrogen can be used as a proxy gas for hydrogen to carry out multiphase fluid flow experiments, to provide the fundamental constitutive relationships necessary for large‐scale simulations of geological hydrogen storage. Plain Language Summary: Developing a hydrogen economy depends on safe and economically viable terawatt hour interseasonal storage and recovery of hydrogen around the world. As such, storage in geological formations is vital for transitioning to the hydrogen economy successfully. Here, we present a combined experimental and modeling study on the flow behavior of hydrogen in porous media at high‐pressure high‐temperature conditions representative of potential storage reservoirs. We investigate the effect of different influencing parameters and compare the flow behavior of hydrogen with other gases. This work provides essential relative permeability data for hydrogen under a range of conditions typical of hydrogen storage and extraction. Key Points: Drainage relative permeability is measured for H2‐brine at reservoir conditionsThe rocks' effective porosity has the most evident impact on H2‐brine relative permeabilityN2 gas can be used as a safer proxy for hydrogen to undertake fluid flow experiments [ABSTRACT FROM AUTHOR]

Background: The arterial pressure waveform reflects the interaction between the heart and the arterial system and carries potentially relevant information about circulatory status. According to the commonly accepted 'wave transmission model', the net BP waveform results from the super-position of discrete forward and backward pressure waves, with the forward wave in systole determined mainly by the left ventricular (LV) ejection function and the backward by the wave reflection from the periphery, the timing and amplitude of which depend on arterial stiffness, the wave propagation speed and the extent of downstream admittance mismatching. However, this approach obscures the 'Windkessel function' of the elastic arteries. Recently, a 'reservoir-excess pressure' model has been proposed, which interprets the arterial BP waveform as a composite of a volume-related 'reservoir' pressure and a wave-related 'excess' pressure. Methods: In this study we applied the reservoir-excess pressure approach to the analysis of carotid arterial pressure waveforms (applanation tonometry) in 10 young healthy volunteers before and after a 5-week head down tilt bed rest which induced a significant reduction in stroke volume (SV), end-diastolic LV volume and LV longitudinal function without significant changes in central blood pressure, cardiac output, total peripheral resistance and aortic stiffness. Forward and backward pressure components were also determined by wave separation analysis. Results: Compared to the baseline state, bed rest induced a significant reduction in LV ejection time (LVET), diastolic time (DT), backward pressure amplitude (bP) and pressure reservoir integral (INTPR). INTPR correlated directly with LVET, DT, time to the peak of backward wave (bT) and stroke volume, while excess pressure integral (INTXSP) correlated directly with central pressure. Furthermore, Δ.INTPR correlated directly with Δ.LVET, and Δ.DT, and in multivariate analysis INTPR was independently related to LVET and DT and INTXSP to central systolic BP. Conclusion: This is an hypothesis generating paper which adds support to the idea that the reservoir-wave hypothesis applied to non-invasively obtained carotid pressure waveforms is of potential clinical usefulness. [ABSTRACT FROM AUTHOR]

Introduction: Vacuum assisted venous drainage (VAVD) requires the sealing of the hard-shell venous reservoir, thereby creating circumstances where reservoir pressurization may occur. Manufacturers utilize integrated pressure relief valves (IPRV) to mitigate pressurization risk; however, accidents have been reported even with these devices. We have undertaken a performance evaluation of IPRV's in a large number of hard-shell venous reservoirs. Methods: Reservoirs were sealed and gas insufflated while measuring reservoir internal pressure. Linear regression models were developed to depict the association between internal pressure and gas inflow rate. External secondary one-way valves (ESOV) were assessed for pressure mitigation performance. An assisted venous drainage survey was circulated to Canadian Clinical Perfusionists. Results: The reservoirs tested were adult (n = 9, 64%) and pediatric (n = 5, 36%) designs. Significant variability (p < 0.001) in internal reservoir pressures (range: 0.04–161.41 mmHg) was observed across the titrated gas inflow rate (0.5–10.0 l/min). The regression models demonstrate excellent predictive performance (SE: 0.008–0.309). ESOV's reduce the reservoir pressure below that of the IPRV; however, they cannot eliminate reservoir pressurization. The survey showed a majority (91%) of respondents use VAVD, and reservoir pressurization events occur regularly (18%). Conclusions: Significant variability among reservoir's IPRV to mitigate reservoir pressurization exists. The predictive models are extremely accurate at estimating the internal pressure. ESOV performance limitations moderate their utility as a backup pressure mitigation technique. A significant number of reservoir pressurization events are occurring with the use of VAVD. As a result, standardized communication from manufacturers on the purpose and performance of IPRV is recommended in order to delineate the limitations of these devices. [ABSTRACT FROM AUTHOR]

At different stages of oil and gas field development, a reservoir undergoes various stress-strain states. The change of reservoir pressure during development results in the change in physical and mechanical properties of the reservoir. In terms of geochemistry, the fluids also affect the properties of the host rocks. The process of reservoir fluid extraction can clog flow channels with washed-out rock particles and deposited paraffins and salts, but also decrease the strength and elastic characteristics of the rock. The article provides a brief analysis of operations affecting the causes of changes in the physical, mechanical, porosity and permeability properties of formations during drilling and oil-field development. The method of theoretical calculation of changes in the formations’ porosity and permeability is provided. To establish the convergence of theoretical calculation methods with real data, the tests to determine the uniaxial compressive strength and the filtration experiments on terrigenous samples of a West Siberian field were carried out. Water and kerosene in different proportions were used as saturating fluids in the experiment to determine physical and mechanical properties. Based on the data obtained, the dependencies of the modulus of elasticity and the uniaxial compressive strength on different types of saturation were derived, with diagrams and calculating formulas given. In the filtration experiment, the influence of effective pressure on permeability of samples at volumetric compression was determined. The dependencies of permeability decline on the sample axial load were established. The obtained dependencies can be used to work out geological and engineering procedures for well stimulation and field development management during the entire operational life cycle.

BackgroundThe arterial pressure waveform reflects the interaction between the heart and the arterial system and carries potentially relevant information about circulatory status. According to the commonly accepted ‘wave transmission model’, the net BP waveform results from the super-position of discrete forward and backward pressure waves, with the forward wave in systole determined mainly by the left ventricular (LV) ejection function and the backward by the wave reflection from the periphery, the timing and amplitude of which depend on arterial stiffness, the wave propagation speed and the extent of downstream admittance mismatching. However, this approach obscures the ‘Windkessel function’ of the elastic arteries. Recently, a ‘reservoir-excess pressure’ model has been proposed, which interprets the arterial BP waveform as a composite of a volume-related ‘reservoir’ pressure and a wave-related ‘excess’ pressure.MethodsIn this study we applied the reservoir-excess pressure approach to the analysis of carotid arterial pressure waveforms (applanation tonometry) in 10 young healthy volunteers before and after a 5-week head down tilt bed rest which induced a significant reduction in stroke volume (SV), end-diastolic LV volume and LV longitudinal function without significant changes in central blood pressure, cardiac output, total peripheral resistance and aortic stiffness. Forward and backward pressure components were also determined by wave separation analysis.ResultsCompared to the baseline state, bed rest induced a significant reduction in LV ejection time (LVET), diastolic time (DT), backward pressure amplitude (bP) and pressure reservoir integral (INTPR). INTPR correlated directly with LVET, DT, time to the peak of backward wave (bT) and stroke volume, while excess pressure integral (INTXSP) correlated directly with central pressure. Furthermore, Δ.INTPR correlated directly with Δ.LVET, and Δ.DT, and in multivariate analysis INTPR was independently related to LVET and DT and INTXSP to central systolic BP.ConclusionThis is an hypothesis generating paper which adds support to the idea that the reservoir-wave hypothesis applied to non-invasively obtained carotid pressure waveforms is of potential clinical usefulness.

The injection of fluids into a compartmentalized formation induces pore pressure buildup and may result in reactivation of sealing faults. Among other variables, the pore volume compressibility (PVC) can affect the amount of pore pressure change during injection. PVC has been traditionally measured with isotropic loading compressibility tests. However, long and thin reservoirs subjected to depletion or injection typically follow a uniaxial strain stress path, rather than an isotropic stress path. Furthermore, injection unloads the reservoir rock by reducing effective stress, whereas depletion causes loading. This paper reports experimental measurements of the uniaxial strain unloading compressibility of Frio sand, a member of Tertiary strata in the Gulf of Mexico Basin. The uniaxial strain unloading compressibility increases nonlinearly from 0.29 to 1.45 GPa−1 (2 to 10 µsip) as the mean effective stress is reduced from 26 to 5 MPa. The uniaxial strain unloading compressibility of Frio sand is about one third of the uniaxial strain loading compressibility at comparable levels of effective stress. The uniaxial strain compressibility of Frio sand is roughly one half of the isotropic compressibility. Reservoir simulation highlights that using incorrect pore compressibility values considerably underestimates the expected increase of pore pressure in a compartmentalized formation during injection. Uniaxial strain unloading compressibility of target reservoir rocks should be accurately estimated or measured to prevent excessive pressure build up in target storage formations during injection of CO2 or any other fluid. [ABSTRACT FROM AUTHOR]

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Underground gas storage (UGS) is an important facility to overcome the imbalance between natural gas supply and demand. In this paper, an optimization model of injection-withdrawal scheduling for UGS in a depleted gas reservoir is established to find the optimal operating state of the gas storage facility. Faults are widely developed in reservoir, which can divide a full reservoir into several pressure disconnected reservoir blocks (RB). Considering that the unbalanced pressure distribution of reservoir will significantly affect the stable operation of UGS, the optimization model aims to minimize the deviation degree of pressure between RBs under the condition of satisfying the gas injection-withdrawal requirements. The decision variables are the number of operating wells and the flow rate of a single well of each RB. A series of equality and inequality constraints are developed, including maximum inventory of RB, maximum pressure of RB and maximum flow rate of a single well. To verify the validity of the proposed method, the optimization model is applied to an actual UGS in a depleted gas reservoir in China. The GAMS modeling system and DICOPT solver are adopted to solve the optimization problem. The results show that the deviation degree of pressure between RBs of the optimized scheme is about 75% lower than that of the empirical scheme. In the empirical scheme, there is an extremely high-pressure RB with a maximum pressure of 43.98 MPa, which exceeds the pressure limit of 5.38 MPa. However, all RBs meet the pressure requirement in the optimized scheme. Overall, the optimized scheme can effectively reduce the deviation degree of pressure between RBs and avoid the occurrence of extremely high-pressure RB. [ABSTRACT FROM AUTHOR]

This study aims to evaluate Kharita gas reservoir to enhance the production. The increase in water-cut ratio reduces the left hydrocarbons' amount behind pipe. Accurate determination of pore throats, pores connectivity and fluid distribution are central elements in improved reservoir description. The integration of core and logging data responses is often used to draw inferences about lithology, depositional sequences, facies, and fluid content. These inferences are based on petrophysical models utilizing correlations among tools' responses as well as rocks and fluids properties. Upper Kharita Formation produces gas and condensate from the clastic sandstone in Badr-3 field, western desert of Egypt. It consists mainly of sandstone with shale intercalations. It is subdivided into three sub-units Kharita A, Kharita B and Kharita C that are in pressure communication. Hence, a new further investigation and review for the previously calculated GIIP (gas initially in place) was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation; subsequently, a new unconventional petrophysical evaluation approach was performed. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. Reservoir shale cutoff of 55% by using cross-plot between shale volume and porosity (Toby Darling concept) was utilized to discriminate the reservoir from non-reservoir sections. The porosity model was used to calculate reservoir porosity, using the density log. The Archie and saturation/height function models were used to calculate the water saturation and used to calibrate the water saturation in the transition zone. The porosity–permeability (POR-PERM) transform equation was used to estimate the reservoir connectivity (absolute permeability) for the four petrophysical facies (High Quality Reservoir, Moderate Quality Reservoir, Low Quality Reservoir and Highly Shale Reservoir). Core data have shown variations in reservoir quality parameters (porosity and permeability) from one well to the other. Integration of all the reservoir pressures indicated that there are different fluid types (oil, gas and water) in the Upper Kharita Formation level. The saturation/height function model was used to calibrate the saturation in the transition zone. The integration of geological core and geophysical log data helped to conduct a comprehensive petrophysical assessment of Upper Kharita Formation for a better estimation of the reservoir and to achieve a better understanding of the water encroachment in the Upper Kharita reservoir. The big challenge is the determination of the most correct model for calculating porosity, permeability and water saturation in this reservoir of different quality sand. The new petrophysical evaluation resulted in doubling the volumes in Upper Kharita reservoir and so a perforation campaign was performed to confirm the new volumetric calculations, which showed a good match with the model results. Hence, a new well was drilled targeting the low quality sand and found them with high pressure almost near virgin pressure. [ABSTRACT FROM AUTHOR]

Background: Right ventricular (RV) coupling to the pulmonary circulation influences the response of the RV to the increased afterload caused by pulmonary hypertension (PH), which ultimately determines prognosis. A methodology that accounts for pulsatile flow is required when assessing ventriculo-arterial coupling. We applied wave intensity analysis (WIA) methods to assess the compliance of the main pulmonary artery (PA) in patients with or without PH and compared this to PA distensibility, RV function and clinical outcomes. Methods: High-fidelity blood pressure and Doppler flow velocity tracings were obtained simultaneously during cardiac catheterisation for suspected PH. RV volumes, main PA distensibility and ventriculo-arterial coupling (Emax/Ea) were analysed using cardiovascular magnetic resonance. Results: The study included 17 ​PH patients and 6 controls. Wave speed, reservoir and excess pressure were higher in PH patients compared to controls (p ​