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The phase change of CO2 has a significant bearing on the siting, injection, and monitoring of storage. The phase state of CO2 is closely related to pressure. In the process of seismic exploration, the information of formation pressure can be response in the seismic data. Therefore, it is possible to monitor the formation pressure using time-lapse seismic method. Apart from formation pressure, the information of porosity and CO2 saturation can be reflected in the seismic data. Here, based on the actual situation of the work area, a rockphysical model is proposed to address the feasibility of time-lapse seismic monitoring during CO2 storage in the anisotropic formation. The model takes into account the formation pressure, variety minerals composition, fracture, fluid inhomogeneous distribution, and anisotropy caused by horizontal layering of rock layers (or oriented alignment of minerals). From the proposed rockphysical model and the well-logging, cores and geological data at the target layer, the variation of P-wave and S-wave velocity with formation pressure after CO2 injection is calculated. And so are the effects of porosity and CO2 saturation. Finally, from anisotropic exact reflection coefficient equation, the reflection coefficients under different formation pressures are calculated. It is proved that the reflection coefficient varies with pressure. Compared with CO2 saturation, the pressure has a greater effect on the reflection coefficient. Through the convolution model, the seismic record is calculated. The seismic record shows the difference with different formation pressure. At present, in the marine CO2 sequestration monitoring domain, there is no study involving the effect of formation pressure changes on seismic records in seafloor anisotropic formation. This study can provide a basis for the inversion of reservoir parameters in anisotropic seafloor CO2 reservoirs. [ABSTRACT FROM AUTHOR]

Abstract With the high yield of many wells represented by Well JT1 in the Maokou Formation, has catalyzed a surge in exploration activities along the platform margin facies of the Maokou Formation in central Sichuan and further showed the significant exploration potential of the Maokou Formation in the northern slope. However, the fracture cave body of the Maokou Formation exhibits a high degree of development, strong longitudinal and horizontal heterogeneity, large formation pressure differences, and drilling events such as gas kicks and lost circulation occur frequently, which seriously affects the efficient implementation of drilling. Understanding the spatial distribution of the three-pressure in the formation can help better deal with and solve the above problems. Therefore, in order to help the safe, high-quality and rapid drilling of the Maokou Formation in the study area, and enhance the efficiency of oil and gas development, this paper explores the research on the prediction method of the three-pressure of jointing well-seismic data based on the geomechanical experimental data and the actual drilling data. In the process of prediction of pore pressure, this study found that the pore pressure and formation velocity in the study area have an exponential relationship. In order to enhance the applicability of the Filippone’s method in the study area and improve the prediction accuracy of pore pressure, the linear relationship between pore pressure and formation velocity in the Filippone’s method is modified to an exponential relationship, and a pore pressure prediction model suitable for the work area was established. Based on the Mohr–Coulomb criterion and Huang's model, the prediction models of collapse pressure and fracture pressure applicable to the study area were established, respectively. Then, the elastic parameters were obtained through pre-stack inversion, and the three-pressure bodies were calculated based on the elastic parameter bodies. The results indicate that: (1) The three-pressure prediction method of the jointing well-seismic data in this paper can predict the formation's longitudinal and transverse pressure anomaly zones in advance. (2) The Maokou Formation in the study area is characterized by abnormally high pressure, to balance the pressure of the high-ground formation, high-density drilling fluid is necessary. (3) The prediction results of three-pressure in this paper are highly consistent with the actual drilling engineering events, which verifies the reliability of the three-pressure prediction results presented in this study. The results of the study can provide a basis for decision-making in drilling geological design, such as the determination of drilling fluid density, the evaluation of borehole stability and other engineering problems that require support from three-pressure data.

With the high yield of many wells represented by Well JT1 in the Maokou Formation, has catalyzed a surge in exploration activities along the platform margin facies of the Maokou Formation in central Sichuan and further showed the significant exploration potential of the Maokou Formation in the northern slope. However, the fracture cave body of the Maokou Formation exhibits a high degree of development, strong longitudinal and horizontal heterogeneity, large formation pressure differences, and drilling events such as gas kicks and lost circulation occur frequently, which seriously affects the efficient implementation of drilling. Understanding the spatial distribution of the three-pressure in the formation can help better deal with and solve the above problems. Therefore, in order to help the safe, high-quality and rapid drilling of the Maokou Formation in the study area, and enhance the efficiency of oil and gas development, this paper explores the research on the prediction method of the three-pressure of jointing well-seismic data based on the geomechanical experimental data and the actual drilling data. In the process of prediction of pore pressure, this study found that the pore pressure and formation velocity in the study area have an exponential relationship. In order to enhance the applicability of the Filippone's method in the study area and improve the prediction accuracy of pore pressure, the linear relationship between pore pressure and formation velocity in the Filippone's method is modified to an exponential relationship, and a pore pressure prediction model suitable for the work area was established. Based on the Mohr–Coulomb criterion and Huang's model, the prediction models of collapse pressure and fracture pressure applicable to the study area were established, respectively. Then, the elastic parameters were obtained through pre-stack inversion, and the three-pressure bodies were calculated based on the elastic parameter bodies. The results indicate that: (1) The three-pressure prediction method of the jointing well-seismic data in this paper can predict the formation's longitudinal and transverse pressure anomaly zones in advance. (2) The Maokou Formation in the study area is characterized by abnormally high pressure, to balance the pressure of the high-ground formation, high-density drilling fluid is necessary. (3) The prediction results of three-pressure in this paper are highly consistent with the actual drilling engineering events, which verifies the reliability of the three-pressure prediction results presented in this study. The results of the study can provide a basis for decision-making in drilling geological design, such as the determination of drilling fluid density, the evaluation of borehole stability and other engineering problems that require support from three-pressure data. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience 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.)

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum 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.)

In gas cap reservoirs underlain by bottom water, the connection between the reservoir and the aquifer leads to an increasing invasion of bottom water as reservoir development progresses. The average formation pressure of the reservoir will change, and the separated phase recovery of the gas cap reservoir with bottom water will be affected by the change in the average formation pressure. The traditional average formation pressure calculation formulas do not consider the water influx, so the accurate calculation of separated recovery cannot be obtained by those calculation methods. The development of gas cap reservoirs with bottom water presents several challenges, including the simultaneous production of oil and gas, undetermined rates of bottom water influx, and uncertain formation pressure and gas-to-oil ratios. These factors contribute to substantial discrepancies between theoretical calculations and actual observations. A more accurate and comprehensive approach is required to address these issues and enable a precise determination of the phase separated recovery in gas cap reservoirs with bottom water. The volume-deficit method is integrated with the Fetkovich quasi-steady state method for water influx. The water-influx prediction is incorporated into the material balance equation, which is further refined by introducing the Fetkovich model to enhance the estimation of the average formation pressure. The average formation pressure, once determined, is utilized in conjunction with the established relationships among this pressure, surface oil production, gas production, and the dissolved gas–oil ratio. Through the application of mass conservation principles, the varying degree of phase recovery, as influenced by fluctuations in the average formation pressure, is calculated. The precision of this refined method has been validated by a comparison with outcomes generated by simulation software. The results reveal a commendable accuracy: an error in the average formation pressure calculation is found to be merely 2.61%, while the errors in recovery degrees for gas cap gas, dissolved gas, and oil-rim oil are recorded at 2.73%, 2.94%, and 1.28%, respectively. These minor discrepancies indicate a good level of consistency and affirm the reliability of this advanced methodology, as demonstrated by passive assessments. This paper provides a method to accurately calculate the phase recovery without some oil- and gas-production data, which provides accurate data support for the actual production evaluation and subsequent development measures. [ABSTRACT FROM AUTHOR]

Relevance. Control of energy state of reservoirs is an integral part of the overall system for monitoring the development of hydrocarbon deposits. The traditional way to control the energy state of reservoirs is to build isobar maps, while the input data are the materials of well tests in unsteady conditions. In the current technical and economic conditions, it should be considered impossible even conditionally simultaneous shutdown of the entire well stock for the actual determination of reservoir pressure. This shortcoming is devoid of indirect methods for determining reservoir pressure. In this regard, it seems relevant to compare direct and indirect methods for determining reservoir pressure when using their data to analyze the energy state of hydrocarbon deposits. Aim. Comparative assessment of direct and indirect methods for determining reservoir pressure in the analysis of the energy state of deposits (when constructing isobar maps). Object. Tournaisian-Famenian carbonate deposits of oil from the fields of the Perm Krai. Methods. Well tests, analysis of production history by wells (module Topaze (Kappa Workstation)), machine learning methods (modular service Data Stream Analytics (DSA)), mapping, correlation analysis. Results. Well tests carried out at different times do not allow a reliable assessment of the current energy state of reservoirs, in contrast to indirect methods for determining reservoir pressure, the practical implementation of which allows obtaining the desired value for any date. However, with conditionally the same high predictive ability of indirect methods, the considered methods of machine learning should be considered a priority. This is due to their advantageous characteristics, such as low duration of computational operations, a minimum set of initial data, an integrated mapping service.

The current formation pressure prediction methods based on the undercompaction theorv are essentiallv empirical models, which are not generalizable, and the prediction accuracy is constrained bv various factors. For this reason, the quantitative study of anomalous formation pressure was carried out from the perspective of rock pore volume and fluid volume. According to the theorv of elastic mechanics of porous media, the quantitative evaluation model of anomalous formation pressure and pressure coefficient under the effect of undercompaction was established by comprehensivelv considering the factors such as temperature, stress, fluid composition, and depth change. The model is applicable to the evaluation of anomalous formation pressure with undercompaction as the main genesis, and has high accuracy. The simulation results show that the formation pressure increases under the effect of the undercompaction, but the pressure coefficient mav increase, remain unchanged or decrease due to the increase of bur-ial depth, and the influence of the increase of burial depth on the pressure coefficient shall not be neglected; the undercompaction can form both anomalous high pressure and anomalous low pressure; the changes of the formation pressure and the pressure coefficient are related to the physical properties of the fluid and the rock, and the incre-ment of the formation depth as well as the initial depth; the influences of the compression coeficient of the fluid and the increment of the formation depth are relativelv significant, while the influences of other factors are relativelv weak. The research results break through the previous knowledge of the relationship between undercompaction and anomalous high pressure, and enrich and develop the theorv of undercompaction. [ABSTRACT FROM AUTHOR]

Huge and thick black shale was deposited in the Mianyang-Changning intracratonic sag of the Sichuan Basin, which is a favorable target for shale gas exploration in the future. Taking the paleofluid preserved in the Qiongzhusi Formation shale as the research object, based on the petrological and optical characteristics of fracture veins observed in cores and thin sections, the source and origin of the paleofluid were analyzed by carbon and oxygen isotope testing, the formation pressure evolution of shale gas was simulated by using BasinMod software, and the preservation conditions of Qiongzhusi Formation shale gas in the central portion and surrounding areas of the Mianyang-Changning intracratonic sag were discussed. The results show that fracture vein rarely appears in the Qiongzhusi Formation shale of wells GS17 and MX9. While multiple groups of bed-parallel and high-angle fractures appear in Well W201, which are filled with mesocrystalline to coarse crystalline calcite, fibrous calcite, saddle dolomite, barite, and quartz. Carbon and oxygen isotopes indicate that fracture veins were generated by fluids of hydrothermal solution or organic matter decarboxylation. Hydrocarbon generation, particularly the crude oil cracking, induced the strong overpressure in the Qiongzhusi Formation of the intracratonic sag and the Gaoshiti-Moxi area, and the overpressure has been preserved thus far. Although overpressure was also developed in the Weiyuan structure, it dissipated in the late tectonic movement. Compared with the intracratonic sag and Gaoshiti-Moxi area, the late preservation conditions of shale gas in the Weiyuan area were relatively harsh, but some local overpressure areas need to be focused on.

Advancements in drilling technology are pivotal to optimizing the production and sustainability of oil and gas wells. One of the emerging innovations is the application of a specialized fluid known as "Fuzzy-ball" fluid. This paper comprehensively reviews the historical evolution and advancements in the utilization of fuzzy-ball fluid in drilling and well-repair processes. Fuzzy-ball fluid has been discovered to bolster a formation's pressure-bearing capabilities and systematically augment resistance against oil, gas, and water flow. These attributes have been instrumental in the phased integration of fuzzy-ball fluid into procedures aiming to enhance production in oil and gas wells. This paper bridges the knowledge gap in the industry regarding the application of fuzzy-ball fluid, thereby circumventing the challenges of inadequate understanding and suboptimal designs. However, the study acknowledges the potential limitation of information loss despite the extensive data collection from diverse sources, such as articles, patents, and reports. As a future direction, this paper emphasizes the need for a more encompassing and critical evaluation of fuzzy-ball fluid's performance and applications. This will enable a more informed decision-making process, fostering the expanded use and understanding of this fluid's mechanism within the industry. [ABSTRACT FROM AUTHOR]

The in-situ stress and formation pressure are important parameters in shale gas development. They directly affect the well wall stability, the direction of horizontal well drilling, and the fracturing effect during the shale gas development process. There are abundant shale gas resources in the southeastern Chongqing-Sichuan area, but the structure in the area is complex, and it is difficult to predict the in-situ stress and formation pressure. Therefore, in this paper, a finite element simulation model was established based on a large number of seismic, logging, and experimental rock mechanics data and the prediction accuracy of the stress field simulation was effectively improved. The construction of the stress field was based on the combined spring model, as well as the data related to the measured in-situ stress and the formation pressure obtained during drilling. The coupling relationship between the in-situ stress, the formation strain, and the formation pressure were derived to carry out the prediction of the distributions of the formation pressure and the formation pressure coefficient. The prediction results showed that the present-day maximum principal stress direction in the study area was about NE65°–110°, and the present-day maximum principal stress was 56.12–93.79 MPa. The present-day minimum principal stress direction was about NE335°–20°, and the present-day minimum principal stress was 48.06–71.67 MPa. The formation pressure was 2.8–88.25 MPa, and the formation pressure coefficient was 0.74–1.55. The formation pressure distribution was greatly affected by fault, tectonic location, in-situ stress and rock petrophysical properties, and the overpressure areas of the formation were distributed in the synclines and the deeply buried areas. This study shows that the finite element based formation pressure prediction method is effective.

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu 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.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency 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.)

In recent years, breakthroughs have been made in deep shale gas exploration in the Wufeng-Longmaxi formations in the complex tectonic region of the Sichuan Basin and southeastern margin, indicating promising prospects for exploration and development. This study focuses on the Nanchuan area of the complex tectonic region of the southeastern Sichuan Basin margin, using data from drilling wells and experimental analysis tests to investigate deep shale gas enrichment characteristics, particularly the effects of changes in the formation environment such as formation temperature and pressure on deep shale gas enrichment. The study concludes that: (1) The dominant sedimentary phase zone is the basis for hydrocarbon formation in shale gas reservoirs, with the Wufeng Formation--the first member of Longmaxi Formation in the study area--formed in a deep-water shelf sedimentary environment with high-quality shale development, which provides favorable material conditions for the formation of shale gas reservoirs. (2) Organic carbon content controls the degree of development of nanoscale organic matter pores, and the high-pressureultra- high-pressure environment helps maintain pores and improve the physical properties of deep shale. (3) Deep shale gas exhibits typical geological characteristics of high temperature, high ground stress, and exceptionally low permeability. The study finds the influence of temperature on the adsorption capacity of shale is more significant than that of pressure, and deep shale gas is primarily free gas. High pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (4) Gas diffusion is complex, with high temperature increasing the diffusion of gas, aggravating the migration and escape of gas, while high pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (5) The burial depth and pressure coefficient show a positive correlation, and the burial depth has a more significant effect on the pressure coefficient of syncline shale gas, indicating that preservation conditions of deep syncline shale gas reservoirs are becoming better. Residual syncline core with larger depths, inner-sag uplift, and slopes with reverse faults can be favorable targets for shale gas exploration in complex tectonic zones. [ABSTRACT FROM AUTHOR]

The optimization of methods for the quantitative evaluation of risks in drilling engineering is an effective means to ensure safety in situations where high temperature and high pressure blocks are considered. In such a context, this study analyzes the complexity of the drilled wells in such blocks. It is shown that phenomena such as well kick, loss, circulation, and sticking, are related to the imbalance of wellbore pressure. A method for risk quantitative evaluation is proposed accordingly. The method is used to evaluate the risk for 9 drilled wells. By comparing the predictions of the method with actual historical data related to these wells, it is found that the coincidence rate is about 95%. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Shenzhen University Science & Engineering is the property of Editorial Department of Journal of Shenzhen University Science & Engineering 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 Upper Triassic Xujiahe Formation in the Xinchang structural belt of the Western Sichuan Depression is an important exploration target for tight sandstone hydrocarbon in the Sichuan Basin. Several studies are carried out in this paper to improve the effectiveness of exploration and development including the characteristics of oil and gas movement with a view of dynamic point combining with fluid dynamics, determine the distribution characteristics of oil and gas in combination with static research results, and study the relationship between hydrocarbon enrichment and formation pressure. Overpressure is developed in the study area, and the degree of overpressure in the third member of Xujiahe Formation is the highest. Whilst the formation pressure of the main gas producing layer, the second member of Xujiahe Formation, is generally between 60-80 MPa with the maximum residual pressure reaches 40 MPa. The residual pressure gradients in most areas distribute between 0-3 MPa/km and up to 10 MPa/km as the highest. According to dynamic hydrocarbon enrichment theory and the relevant research on residual pressure and residual pressure gradient, it is considered that it has an important relationship with faults, fluids, hydrocarbon distribution and production performance. The area with higher residual pressure gradient (1-2 MPa/km) both improves fluid migration capacity and provides favorable reservoir, which is conducive to long-term high-yield and stable production.

The reasons for decreasing the well operating parameters of depleted gas condensate fields have been analysed. A new approach has been proposed, which involves restoring the wells productivity by creating foam by means of a device developed for removing liquid from the well bottom. The expediency of using foam has been experimentally investigated for gas condensate wells to be completed and their productivity to be recovered. Techniques for removing liquid contaminants from wells have been developed, which involve injecting non-explosive gas mixtures and foams of various volumes into wells. Computational fluid dynamics modelling of the operation of the device for the wells completion with foam was carried out. The influence of the mass flow rate of an aqueous solution at the inlet to the device on the distribution of volume fraction of the gas and liquid phases, and the quality of the foam has been investigated. The understanding of the regularities of foam destruction processes by hydrocarbon condensate was obtained, and a device design was developed for the complete foam destruction.

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.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience 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.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu 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.)

Copyright of Steel Pipe is the property of Steel Pipe Magazine 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.)

Determining formation pressure in the well extraction zones is a key task in monitoring the development of hydrocarbon fields. Direct measurements of formation pressure require prolonged well shutdowns, resulting in underproduction and the possibility of technical problems with the subsequent start-up of wells. The impossibility of simultaneous shutdown of all wells of the pool makes it difficult to assess the real energy state of the deposit. This article presents research aimed at developing an indirect method for determining the formation pressure without shutting down the wells for investigation, which enables to determine its value at any time. As a mathematical basis, two artificial intelligence methods are used – multidimensional regression analysis and a neural network. The technique based on the construction of multiple regression equations shows sufficient performance, but high sensitivity to the input data. This technique enables to study the process of formation pressure establishment during different periods of deposit development. Its application is expedient in case of regular actual determinations of indicators used as input data. The technique based on the artificial neural network enables to reliably determine formation pressure even with a minimal set of input data and is implemented as a specially designed software product. The relevant task of continuing the research is to evaluate promising prognostic features of artificial intelligence methods for assessing the energy state of deposits in hydrocarbon extraction zones.

Advancements in drilling technology are pivotal to optimizing the production and sustainability of oil and gas wells. One of the emerging innovations is the application of a specialized fluid known as “Fuzzy-ball” fluid. This paper comprehensively reviews the historical evolution and advancements in the utilization of fuzzy-ball fluid in drilling and well-repair processes. Fuzzy-ball fluid has been discovered to bolster a formation’s pressure-bearing capabilities and systematically augment resistance against oil, gas, and water flow. These attributes have been instrumental in the phased integration of fuzzy-ball fluid into procedures aiming to enhance production in oil and gas wells. This paper bridges the knowledge gap in the industry regarding the application of fuzzy-ball fluid, thereby circumventing the challenges of inadequate understanding and suboptimal designs. However, the study acknowledges the potential limitation of information loss despite the extensive data collection from diverse sources, such as articles, patents, and reports. As a future direction, this paper emphasizes the need for a more encompassing and critical evaluation of fuzzy-ball fluid’s performance and applications. This will enable a more informed decision-making process, fostering the expanded use and understanding of this fluid’s mechanism within the industry.

Salt precipitation is an important issue for CO2 sequestration in deep aquifers.At present, most numerical simulations ignore the feedback effect of the changes in the porosity and permeability caused by the salt precipitation on fluid flow.In this paper, taking Liujiagou Formation in Ordos Basin as an example, a two-dimensional model is established using TOUGH2 code.By modifying the source code of the program, the model can consider the feedback effect of salt precipitation on fluid flow.The simulation results show that after the CO2 injection into the Liujiagou Formation for 20 years, salt precipitation makes the formation pressure near the injection well increase by 0.87MPa and the corresponding injectivity loss of the formation is 7.17%.The salinity has the greatest influence on salt precipitation and its feedback, followed by CO2 injection rate, and permeability has the least influence.When the salinity is high, solid salt saturation increases significantly, resulting in a great decrease in the permeability.In this study, when the salinity was 0.24, the salt precipitation caused an injectivity loss by 45.32% and the pressure buildup up to 12.14 MPa.Therefore, special attention should be paid to the salt precipitation caused by high salinity and its feedback effect during CO2 storage.

The article examines the problem of processing microseismic noise (MN) to identify and evaluate occurrence depth of contrasting geological objects – intersalt interlayers with a potentially high formation pressure. If it is impossible to use artificial wave sources, statistic processing of passive seismic data becomes critical. Due to the accumulation of power spectral density (PSD) during a long-term recording of MN the deterministic medium effect on a random signal spectrum is identified. PSD modulation when the surface or the bottom of the layered medium is exposed to white noise is expressed in terms of the Green’s function (GF) of a wave equation. Relevant GF variations corresponding to the layers form the basis for accumulated PSD approximation, and indicate the depth and contrast of the target features.

Copyright of Journal of Harbin Institute of Technology. Social Sciences Edition / Haerbin Gongye Daxue Xuebao. Shehui Kexue Ban is the property of Harbin Institute of Technology 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.)

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office 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.)

Taking the fractured gas constant volume body as the research unit, considering the boundary conditions such as the height of the constant volume body, the cross-sectional area of the constant volume body, the initial formation pressure, the initial bottom hole pressure and the initial overflow, a mathematical model of the average pressure of the fractured formation of the constant volume body varying with the overflow time is proposed; With the help of programming language, the model is solved. Taking well ST1 as an example, the results show that with the increase of fracture dip angle, the fracture width increases and the fracture permeability also increases; The permeability of fractured gas reservoir is most affected by matrix stress, followed by dip angle and fracture spacing. With the constant volume overflow, the overflow flow decreases rapidly in the initial stage, and then remains stable for a long time until it decreases again in the end; With the increase of throttle back pressure and gas influx, the annular gas holdup increases. The mathematical model of average pressure of fractured formation with constant volume can calculate the change value of average pressure with time, and can guide the design of kill fluid density and the loading of backpressure target value in the process of circulating exhaust. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering 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.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu 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 Ledong area is a typical high temperature and high pressure area in the South China Sea's Yinggehai Basin. The geological structure of this basin is complex, with high formation temperature gradient and multiple formation pressure steps. Therefore, accurate evaluation of formation pressure is facing great difficulties. Based on geological and logging data, the genetic mechanism of abnormal high pressure in the Ledong area is as follows. Abnormal high pressure in the Yinggehai Formation and upper strata is caused primarily by under compaction, whereas abnormal high pressure in the Huangliu Formation and lower strata is caused primarily by hydrothermal pressurization and hydrocarbon generation. At the same time, according to the rock strength, mineral composition and rock physical parameters of the unloading mechanism layers in the Ledong area, the influence of effective stress, porosity and shale content on acoustic velocity was obtained by collecting field cores from the Ledong area and conducting rock acoustic testing experiments in laboratory. The acoustic velocity decreased exponentially with decreasing effective stress, and it had a linear relationship with porosity and the square root of shale content, according to the experimental results. Based on the principle of linear superposition, an improved Bowers unloading model for formation pressure evaluation was established. The original model was modified to overcome the shortcomings of the traditional Bowers unloading model, and the effects of effective stress, porosity and shale content on acoustic velocity were considered comprehensively. The improved Bowers unloading model was applied to evaluate the formation pressure of high temperature and high pressure wells in the Ledong area. The results showed that the improved Bowers unloading model had good applicability in the Ledong area, with average error less than 3% in formation pressure. This model will serve as a technical reference for determining formation pressure in the Yinggehai Basin's high temperature and high pressure region. [ABSTRACT FROM AUTHOR]

Usually there are multiple injection-production blocks in large depleted gas reservoirs, and too high formation pressure difference between blocks can destabilize the reservoir. In order to achieve balanced variation of formation pressure during the injection and production, an optimization model was established with the minimal variance value of formation pressure between periodic blocks as the objective function. The model combined the mathematical optimization technology with the safety and stability of the gas storage, and takes the number of production wells in each block and the injection and production volume of single well as the decision variables, and takes the total amount of gas injection and production of the gas storage, the maximum injection and production volume of single well, and the maximum formation pressure of the block as constraints. The optimization model was applied to Wen23 gas storage based on a large depleted gas reservoir, and the optimized injection-production solution for the gas storage was successfully solved under the condition of an annual gas working volume of 30x108 m³/a. The results of the study showed that the optimized injection-production scheme can not only reduce the formation pressure difference between blocks and achieve a balanced change in the overall formation pressure in the gas storage, but also effectively avoid the occurrence of extremely high pressure blocks and further guarantee the safe and stable operation of the gas storage, on the premise of meeting the requirements of gas injection-production rate in the gas storage. There is much for reference of the study results for the design of the injection- production solution of the gas storage. [ABSTRACT FROM AUTHOR]

Alkali-activated copper tailings based-pastes (AACTP) were synthesized using 90 wt% copper tailings and 10 wt% coal fly ash as the precursors, and water glass with sodium hydroxide as the alkaline activator. The effects of the formation pressure, the liquid/solid mass ratio of water to precursor materials, and the partial substitution of CaO for NaOH as the alkaline activator were investigated. The highest compressive strength of 40.9 MPa was obtained using a formation pressure of 20 MPa, a liquid/solid of 0.15, and a substitution of 20% CaO for NaOH as the alkaline activator. The characterization using a Mercury Intrusion Porosimeter (MIP) indicated that the formation pressure affected the pore structure, as well as the amount of the gel formed. XRD, FTIR, SEM and 29Si NMR showed that a 20% CaO substitution for NaOH promoted the dissolution of raw materials and led to more [AlO4]− being incorporated into the tetrahedron [SiO4] backbone. Additionally, the gel formed in the AACTP was predominantly a N-A-S-H gel. Partial substitution of CaO for NaOH as alkaline activator did not lead to the formation of a C-S-H gel.

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Abstract The equivalent circulation density (ECD) is a very important parameter in drilling high-pressure high-temperature and deepwater wells. ECD is a key parameter during drilling through formations where the margin between the pore pressure and the fracture pressure (FP) is narrow. In these critical formations, the ECD is used to control the formation pressure and prevent kicks. Recent approaches in oilfields to determine ECD depend mainly on using expensive downhole sensors for providing real-time values of ECD. Most of these tools have operational limitations such as high pressure and high temperature which may prevent using these tools in downhole conditions. The objective of this paper is to develop a new approach for predicting ECD using artificial intelligence (AI) techniques from surface drilling parameters [mud weight, drill pipe pressure, and rate of penetration (ROP)]. 2376 data points were used to develop the AI models. The data were collected during the drilling of an 8.5″ vertical hole section. Two AI models were used to estimate the ECD: artificial neural network (ANN) and adaptive neuro-fuzzy inference system (ANFIS). An empirical correlation for ECD was derived from the optimized ANN model by extracting the weights and biases. The developed ANN and ANFIS models were able to calculate ECD with a correlation coefficient (R) of 0.99 and average absolute percentage error of 0.22% for ANN and ANFIS models, respectively. The developed empirical correlation for the ANN model can be used during well design to choose a correct mud weight to safely drill the well based on the expected drilling parameters. It will also minimize the drilling problems related to ECD such as losses or gains especially in critical situations where the margin between the pore and fracture pressure is very narrow. In addition, using this technique will save cost and time by reducing the need for expensive, complicated downhole tools.

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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.)

In using the method of pulse testing of formations, a pressure pulse is generated in an active well by changing the regime of its operation; the pulse propagates across the formation and is registered in an observation well. Based on the results of processing the obtained dependence of pressure in the well shaft on time equated with formation pressure dependence on time at the point of location of the observation well, the formation parameters are determined by comparison with certain analytical relations. It is taken into consideration that the pressure in the well shaft of the observation well follows the variation of the formation pressure in the vicinity of the observation well with some delay due to the processes of filtration mass transfer of liquid between the well shaft and its wellbore area. Mathematical analysis of this mass transfer process presented in this paper shows that the delay time may be 4–5 h or more, depending on the parameters of the formation and formation fluid, which determines the marked difference between the curves of the pressure in the shaft of the observation well and the formation pressure. In this investigation, we obtained an analytical expression of delay time making it possible to correctly reproduce the dependence of formation pressure on time and, accordingly, to raise the reliability of data from the analysis of the results of formation pulse testing. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu 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 expediency of using multicomponent brines extracted together with oil (gas) as the raw material for obtaining lithium products and products required for oil fields has been shown. After the lithium concentrate is obtained, the brine is used for obtaining bromine, calcium bromide, magnesium oxide and chloride, and sodium chloride for the electrochemical obtainment of reagents for technological processes. These products are used for the preparation of drilling fluid and magnesite cement, as well as for the tamping of mixtures. Most of the brine (~80%) is supplied for oil pool flooding to maintain the formation pressure. [ABSTRACT FROM AUTHOR]

Paleo-pressure reconstruction in sedimentary basins is one of the most important aspects of hydrocarbon accumulation research. In view of the advantages and disadvantages of the current methods for paleo-pressure research, a new method to reconstruct the paleo-pressure is presented in this paper. According to the geological background, quantitative analyses of the factors that might control overpressure were first conducted to clarify the contributions of each mechanism during different geological periods. Pressure evolution was reconstructed by fluid-compaction modelling with constraints imposed by the paleo-pressures obtained from fluid inclusions or differential stress methods. Determining the mechanisms responsible for overpressures during geological history is the basic prerequisite for paleo-pressure research. Thus, quantitative studies were conducted of the contributions of disequilibrium compaction, gas charging, oil cracking, temperature reduction, and tectonic uplift and subsidence to overpressures. Three case studies of paleo-pressure reconstruction were performed for the Sinian strata in the Sichuan Basin, Ordovician strata in the north uplift in the Tarim Basin and the Permian strata in the Sulige Gas Field in the Ordos Basin, where these three study sites are normally pressured, weakly over-pressured and abnormally low pressured at present, respectively. The new method developed in this paper is very important for the practical reconstruction of the paleo-pressure in marine strata and ancient strata in deep basins. [ABSTRACT FROM AUTHOR]