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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.

[Display omitted] • MD simulation was used to study the mechanism of effect of pressure on foam stability. • Zero-shear viscosity and yield stress of foam can be improved by rising the pressure. • The increasing pressure promotes piston-propulsion of foam through the saline aquifer. • Elevated pressure increases CO 2 storage efficiency in meso- and micropore spaces. CO 2 foam flooding technology is one of the important methods to improve the efficiency of CO 2 sequestration in saline aquifers. This article explores the influence rules of pressure on CO 2 foam stability and its micro-mechanisms, and its effect on the efficiency of CO 2 foam to enhance CO 2 sequestration. Increasing pressure is conducive to delaying the foam drainage and inhibiting CO 2 diffusion between the liquid films, micro-mechanisms showed that the binding effect of surfactants on water and CO 2 molecules was enhanced due to increased pressure. Then core-nuclear magnetic resonance was used to study the effect of pressure on CO 2 sequestration characteristics from core scale, the bubble population accumulation in the macropores increased with the enhanced pressure, promoting the diversion effect of foam to the meso- and micropores. In addition to enhancing the CO 2 sequestration potential of the macropores, the utilization of storage space of meso- and micropores was improved. [ABSTRACT FROM AUTHOR]