Relevant bibliographies by topics / Reservoir oil pressure

Academic literature on the topic 'Reservoir oil pressure'

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Published: 4 June 2021
Last updated: 27 July 2024

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Journal articles on the topic "Reservoir oil pressure"

1

Chen, Wenxiang, Zubo Zhang, Qingjie Liu, Xu Chen, Prince Opoku Appau, and Fuyong Wang. "Experimental Investigation of Oil Recovery from Tight Sandstone Oil Reservoirs by Pressure Depletion." Energies 11, no. 10 (October 7, 2018): 2667. http://dx.doi.org/10.3390/en11102667.

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Oil production by natural energy of the reservoir is usually the first choice for oil reservoir development. Conversely, to effectively develop tight oil reservoir is challenging due to its ultra-low formation permeability. A novel platform for experimental investigation of oil recovery from tight sandstone oil reservoirs by pressure depletion has been proposed in this paper. A series of experiments were conducted to evaluate the effects of pressure depletion degree, pressure depletion rate, reservoir temperature, overburden pressure, formation pressure coefficient and crude oil properties on oil recovery by reservoir pressure depletion. In addition, the characteristics of pressure propagation during the reservoir depletion process were monitored and studied. The experimental results showed that oil recovery factor positively correlated with pressure depletion degree when reservoir pressure was above the bubble point pressure. Moreover, equal pressure depletion degree led to the same oil recovery factor regardless of different pressure depletion rate. However, it was noticed that faster pressure drop resulted in a higher oil recovery rate. For oil reservoir without dissolved gas (dead oil), oil recovery was 2–3% due to the limited reservoir natural energy. In contrast, depletion from live oil reservoir resulted in an increased recovery rate ranging from 11% to 18% due to the presence of dissolved gas. This is attributed to the fact that when reservoir pressure drops below the bubble point pressure, the dissolved gas expands and pushes the oil out of the rock pore spaces which significantly improves the oil recovery. From the pressure propagation curve, the reason for improved oil recovery is that when the reservoir pressure is lower than the bubble point pressure, the dissolved gas constantly separates and provides additional pressure gradient to displace oil. The present study will help engineers to have a better understanding of the drive mechanisms and influencing factors that affect development of tight oil reservoirs, especially for predicting oil recovery by reservoir pressure depletion.
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2

Valluri, Manoj Kumar, Jimin Zhou, Srikanta Mishra, and Kishore Mohanty. "CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding." Energies 13, no. 23 (November 26, 2020): 6215. http://dx.doi.org/10.3390/en13236215.

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Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.
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Jing, Wenlong, Aifen Li, and Yulong Cheng. "Mechanism of Bubble Point Pressure and Gas-oil Ratio Changing with Depth in Complex Structural Reservoirs." Journal of Physics: Conference Series 2381, no. 1 (December 1, 2022): 012065. http://dx.doi.org/10.1088/1742-6596/2381/1/012065.

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Abstract Reservoir bubble point pressure and gas-oil ratio are important parameters for the scheme design of oilfield development and calculation for reservoir elastic reserves. However, their change laws are complex. At present, there are few studies on the mechanism of bubble point pressure and gas oil ratio changing with depth, which is an urgent problem to be solved in the exploration and development of oil and gas fields. This study focuses on the variation mechanism of bubble point pressure and gas-oil ratio with depth under different tectonic movement conditions in the process of reservoir formation of complex structural reservoirs. When the buried depth of the reservoir is small, the crude oil from bottom to top will be in an unsaturated state (bubble point pressure is less than the formation pressure) to a saturated state (bubble point pressure is greater than the formation pressure), and there will be a gas cap at the top of the oil layer. When the buried depth of the reservoir is large, the formation pressure of the reservoir from bottom to top is greater than the bubble point pressure, and the crude oil of the reservoir is in a single-phase state. A series of tectonic movements will occur in the process of reservoir formation of complex structural reservoirs, which will affect the state of oil and gas in the reservoir. In this study, under the three conditions of complex structural reservoirs including no tectonic movement, tectonic uplift, and tectonic subsidence, the change in bubble point pressure and gas-oil ratio with depth was analyzed respectively. Finally, the mechanism of bubble point pressure and gas-oil ratio changing with depth in complex structural reservoirs is obtained. This study can provide theoretical guidance for reservoir reserve research and development scheme design.
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4

Amer, Manar M., and Dahlia A. Al-Obaidi. "Methods Used to Estimate Reservoir Pressure Performance: A Review." Journal of Engineering 30, no. 06 (June 1, 2024): 83–107. http://dx.doi.org/10.31026/j.eng.2024.06.06.

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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.
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5

Hoffman, Monty, and James Crafton. "Multiphase flow in oil and gas reservoirs." Mountain Geologist 54, no. 1 (January 2017): 5–14. http://dx.doi.org/10.31582/rmag.mg.54.1.5.

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The porous rocks that make up oil and gas reservoirs are composed of complex combinations of pores, pore throats, and fractures. Pore networks are groups of these void spaces that are connected by pathways that have the same fluid entry pressures. Any fluid movement in pore networks will be along the pathways that require the minimum energy expenditure. After emplacement of hydrocarbons in a reservoir, fluid saturations, capillary pressure, and energy are in equilibrium, a significant amount of the reservoir energy is stored at the interface between the fluids. Any mechanism that changes the pressure, volume, chemistry, or temperature of the fluids in the reservoir results in a state of energy non-equilibrium. Existing reservoir engineering equations do not address this non-equilibrium condition, but rather assume that all reservoirs are in equilibrium. The assumption of equilibrium results in incorrect descriptions of fluid flow in energy non-equilibrium reservoirs. This, coupled with the fact that drilling-induced permeability damage is common in these reservoirs, often results in incorrect conclusions regarding the potential producibility of the well. Relative permeability damage, damage that can change which fluids are produced from a hydrocarbon reservoir, can occur even in very permeable reservoirs. Use of dependent variables in reservoir analysis does not correctly describe the physics of fluid flow in the reservoir and will lead to potentially incorrect answers regarding producibility of the reservoir.
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6

Siripatrachai, Nithiwat, Turgay Ertekin, and Russell T. Johns. "Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior." SPE Journal 22, no. 04 (March 6, 2017): 1046–63. http://dx.doi.org/10.2118/179660-pa.

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Summary Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs. In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated. Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.
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Lubkov, M. V., and K. O. Mosiychuk. "Dynamics of the oil reservoir depletion." Geofizicheskiy Zhurnal 44, no. 5 (January 30, 2023): 134–42. http://dx.doi.org/10.24028/gj.v44i5.272333.

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In order to study the dynamics of depletion in heterogeneous oil reservoirs on the base of combined finite-element-difference method for the non-stationary problem of piezoconductivity we have carried out a numerical simulation of the pressure distribution in vicinity of the operating well. At that we have taken into account the heterogeneous distribution of filtration characteristics inside the reservoir and the oil infiltration parameters on the boundaries of the reservoir. The developed method for solving the non-stationary problem of piezoconductivity in deformed oil formations allows us adequately to describe the distribution of pressure near production and injection well systems in real operating conditions. We have shown that depletion processes in vicinity of the active well mainly depend on the intensity of oil production and the degree of oil infiltration at the boundaries of the reservoir’s area and to a lesser extent on the filtration parameters inside the reservoir. Therefore, in order to maintain the proper level of oil production in the reservoir’s area, it is necessary, for example, thanks to the use of modern technologies (system of injection wells), to ensure a sufficient inflow of the oil phase at the borders of the considered area. We have shown that in the cases of low oil infiltration at the boundaries of the reservoir area, the value of depletion is directly proportional to the production power of the well. At the same time, a decreasing of the reservoir permeability leads to a slow downing of depletion processes. The limiting value of the oil boundary infiltration coefficient, which allows achieving industrial oil production, is m. At that, the time of reaching of the stationary productive regime is directly proportional to the value of the oil permeability coefficient inside the reservoir. Before installing a system of production and injection wells in heterogeneous oil reservoirs, it is necessary to carry out a systematic analysis of the degree of depletion of the working reservoir’s areas in order to place them in such a way that would ensure the effective dynamics of filtration processes around these areas.
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Shokoya, O. S., S. A. (Raj) Mehta, R. G. Moore, B. B. Maini, M. Pooladi-Darvish, and A. Chakma. "The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery." Journal of Energy Resources Technology 126, no. 2 (June 1, 2004): 119–24. http://dx.doi.org/10.1115/1.1725170.

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Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.
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9

Zhou, Qi, and Yan Yi Yin. "Analysis of Factors Affecting Productivity of Chang 4+5 Ultra-Low Permeability Reservoirs in Jiyuan Area." Applied Mechanics and Materials 318 (May 2013): 419–22. http://dx.doi.org/10.4028/www.scientific.net/amm.318.419.

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Productivity prediction is a technology for comprehensive evaluation of reservoir's oil-producing capacity, having important significance for early evaluation of oilfield and formulation of oilfield development plan. The percolation mechanism for ultra low permeability reservoirs is extremely complex, making productivity prediction difficult. The factors affecting oil productivity including reservoir parameters, production pressure difference and fluid property have been analyzed according to Chang 4+5 reservoir and production test data in Jiyuan area. Reservoir parameters have complex impact on oil productivity in production test: thickness of oil-bearing interval, electric resistivity, porosity, permeability and other factors all affect productivity in production test. The productivity in production test increases along with increase of production pressure difference under various thicknesses. The productivity is reduced with increase of crude oil viscosity. Reservoir parameter combination through comprehensive analysis is well related to productivity in production test, enabling the building of a regional productivity prediction model.
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Li, Yanlai. "Numerical Simulation of the Effect of Reservoir Properties on Oil Production from the Low-Permeability Formation by Extended Reach Wells." Geofluids 2023 (April 3, 2023): 1–21. http://dx.doi.org/10.1155/2023/4994087.

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At present, extended reach wells (ERWs) are widely applied on oil and gas exploitation in numerous reservoirs around the globe, and this is attributed to their superiority in the development of marginal oil and gas fields and cost-effectiveness. Identifying the effects of reservoir properties on production is significant to the operation of ERWs for oil and gas extraction. This work utilizes numerical modeling techniques to simulate the application of ERWs in low-permeability formations. The impacts of low permeability on the oil production and the pressure distribution of the reservoirs with different formation properties are analyzed, and the simulation results of the oil exploitation by ERWs are compared with the oil production and pressure distribution of that by horizontal wells (HWs). A test scheme is designed to analyze the effect of reservoir properties on oil extraction through ERWs and quantify the sensitivity of oil production to reservoir properties. The reservoir properties of formation rock compressibility, formation fluid compressibility, initial reservoir pressure, reservoir saturation pressure, formation porosity, and absolute permeability are studied through 66 ERW cases. The results illustrate that low permeability leads to a fast decrease of oil production rates and significantly uneven pressure distribution. The pressure is lower at the center of the ERW but is higher at both ends of the ERW, while the pressure is evenly distributed along the horizontal well in the HW cases. In addition, the oil production is in direct proportion with the initial reservoir pressure, formation rock compressibility, formation porosity, and formation fluid compressibility but is in an inverse ratio with the reservoir saturation pressure. Furthermore, the initial reservoir pressure has the largest impact on both the total cumulative oil production driven out by natural energy and the cumulative oil production after the development of ten years by natural energy; on the contrary, the absolute permeability has no effect on the total cumulative oil production driven out by natural energy.
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Dissertations / Theses on the topic "Reservoir oil pressure"

1

Xiao, Jinjiang. "Wellbore effects on pressure transient analysis /." Access abstract and link to full text, 1993. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/9325433.

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Onur, Mustafa. "New well testing applications of the pressure derivative /." Access abstract and link to full text, 1989. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/8917500.

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Serra, Kelsen Valente. "Well testing for solution gas drive reservoirs /." Access abstract and link to full text, 1988. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/8811978.

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Camacho-Velázquez, Rodolfo Gabriel. "Well performance under solution gas drive /." Access abstract and link to full text, 1987. http://0-wwwlib.umi.com.library.utulsa.edu/dissertations/fullcit/8720613.

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Van, Ruth Peter John. "Overpressure in the Cooper and Carnarvon Basins, Australia /." Title page, abstract and table of contents only, 2003. http://web4.library.adelaide.edu.au/theses/09PH/09phv275.pdf.

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Sathar, Shanvas. "Effect of oil emplacement on pressure solution in reservoir rocks : an experimental analogue study." Thesis, University of Liverpool, 2010. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.539512.

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Barreto, Filho Manuel de Almeida. "Estimation of average reservoir pressure and completion skin factor of wells that produce using sucker rod pumping /." Full text (PDF) from UMI/Dissertation Abstracts International, 2001. http://wwwlib.umi.com/cr/utexas/fullcit?p3008273.

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Hossein, Zadeh Ahmad. "Optimization of Well Spacing and CO2 Miscible Flooding Startup Time in an Ultradeep, High Pressure Oil Reservoir." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2014. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-27152.

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Exploitation of ultradeep, high pressure oil reservoirs is always associated with numerous risks, challenges, and obstacles. One of the most pronounced constraints in development of such fields is the number of wells, which is imposed by massively high cost of drilling. Low number of wells may lead to high pressure isolation regions left after primary production (pressure depletion) of the reservoir. Ultradeep reservoirs with high pressure are more prone to such leftover high pressure isolation regions due to their low permeable characteristic. These high pressure isolation regions can, subsequently, deteriorate the efficiency of enhanced oil recovery (EOR) as the injected fluid cannot access the residual oil in these regions. Therefore, well placement and inter-well spacing optimizations is of greater importance in ultradeep, high pressure oil reservoirs to ensure higher ultimate oil recovery at lower costs. Furthermore, due to high cost of development of ultradeep, high pressure oil reservoirs, the EOR strategy and commencement time for the selected EOR strategy are very critical. The objective of this thesis is to demonstrate how optimization of well placement, well spacing, and startup time for miscible CO2 flooding can enhance the incremental and ultimate oil recoveries in an ultradeep, high pressure oil reservoir. To do this, a synthetic grid model was made to run different simulation scenarios on it. The model was initialized with rock and fluid properties within the range of those in the ultradeep, high pressure Wilcox formation in the Gulf of Mexico to ensure that it mimics an ultradeep, high pressure oil reservoir.The obtained results showed that optimization of well placement, well spacing, and commencement time for any EOR strategy such as miscible CO2 flooding is very critical in the course of making a Field Development Plan (FDP) for an ultradeep, high pressure oil reservoir.The results, discussions, and conclusions were finally used by the author to shed light on potential further work on each of the aforementioned challenges in ultradeep, high pressure oil reservoirs such as Wilcox formation in the Gulf of Mexico.
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Teca, Dário Bokiló Machado. "Correction of the anisotropy in resistivity: application to pore pressure prediction." Master's thesis, Faculdade de Ciências e Tecnologia, 2014. http://hdl.handle.net/10362/13132.

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Dissertação para obtenção do Grau de Mestre em Engenharia Geológica (Georrecursos)
This dissertation is based on a curricular training period done at company Total EP Angola between July and December 2013. The data presented relate to a real case study of an exploration block, which for reasons of confidentiality is designated by Block Michocho. The fluids pressure measurement in the geological formations can be inferred from the formation resistivity log. In not perpendicular wells to the layers, resistivity curves show higher values than the expected due to the anisotropic effect of the formation thus the inference of the pressure of fluids from resistivity logs can lead to unrealistic values. Most of the developments wells drilled on Block Michocho in Angola are highly deviated, if not sub-horizontal, in the reservoir section. The objective of this work is to correct the anisotropic effect of the resistivity of Block Michocho due to non-perpendicularity of the wells when intersect the geological formations. In this study, the correction of the resistivity is based on the formula proposed by Moran and Gianzero in 1979 and involves the dipping angle of the induction logging tool and the coefficient of anisotropy of the rock formation. Prior to application of this formula for the corrections of resistivity of the Block Michocho wells logs, a set of validation tests were made. Due to lack of data on development wells (highly inclined wells) the validation test was carried out in five exploration wells where resistivity is available in the two principal directions. It was assumed that the formula would be approved for resistivity corrections if the horizontal resistivity obtained by the formula had a good correspondence with the horizontal resistivity obtained by the induction logging tool. After this validation step, the coefficient of anisotropy to be used in the formula was calibrated as well as the correction of the curves of resistivity of the remaining development wells, those much more diverted regarding the rock layers. The corrected resistivity can be applied for pore pressure prediction in low permeability rock formations, in which the main objective is to identify regions where fluid pressure is higher than normal pressure, i.e. overpressure regions. For illustration purposes, a resistivity curve from an exploration well was chosen and the pressure of the fluids in low permeability rocks was computed by using the formula proposed by Eaton in 1975. With this well data, a potential overpressure region was identified and should be avoided in drilling activities.
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Samadov, Hidayat. "Analyzing Reservoir Thermal Behavior By Using Thermal Simulation Model (sector Model In Stars)." Master's thesis, METU, 2011. http://etd.lib.metu.edu.tr/upload/12613336/index.pdf.

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It is observed that the flowing bottom-hole temperature (FBHT) changes as a result of production, injection or shutting the well down. Variations in temperature mainly occur due to geothermal gradient, injected fluid temperature, frictional heating and the Joule-Thomson effect. The latter is the change of temperature because of expansion or compression of a fluid in a flow process involving no heat transfer or work. CMG STARS thermal simulation sector model developed in this study was used to analyze FBHT changes and understand the reasons. Twenty three main and five additional cases that were developed by using this model were simulated and relation of BHT with other parameters was investigated. Indeed the response of temperature to the change of some parameters such as bottom-hole pressure and gas-oil ratio was detected and correlation was tried to set between these elements. Observations showed that generally FBHT increases when GOR decreases and/or flowing bottom-hole pressure (FBHP) increases. This information allows estimating daily gas-oil ratios from continuously measured BHT. Results of simulation were compared with a real case and almost the same responses were seen. The increase in temperature after the start of water and gas injection or due to stopping of neighboring production wells indicated interwell communications. Additional cases were run to determine whether there are BHT changes when initial temperature was kept constant throughout the reservoir. Different iteration numbers and refined grids were used during these runs to analyze iteration errors
however no significant changes were observed due to iteration number differences and refined grids. These latter cases showed clearly that variations of temperature don&rsquo
t occur only due to geothermal gradient, but also pressure and saturation changes. On the whole, BHT can be used to get data ranging from daily gas-oil ratios to interwell connection if analyzed correctly.
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Books on the topic "Reservoir oil pressure"

1

H, Fertl Water, Chapman Richard E, and Hotz Rod F, eds. Studies in abnormal pressures. Amsterdam: Elsevier, 1994.

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Sahay, Bhagwan. Origin and evaluation of formation pressures: Bhagwan Sahay and Walter H. Fertl. Dordrecht: Kluwer Academic Publishers, 1988.

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Aleksandrov, B. L. Anomalʹno-vysokie plastovye davlenii͡a︡ v neftegazonosnykh basseĭnakh. Moskva: "Nedra", 1987.

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Dobrynin, V. M. Geologo-geofizicheskie metody prognozirovanii͡a︡ anomalʹnykh plastovykh davleniĭ. Moskva: Nedra, 1989.

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S, Kabir C., ed. Pressure transient analysis. Englewood Cliffs, N.J: Prentice Hall, 1990.

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Steffy, David A. Abnormal formation pressures in the Navarin Basin, Bering Sea, Alaska. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1991.

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Steffy, David A. Abnormal formation pressures in the Navarin Basin, Bering Sea, Alaska. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1991.

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Bhagwan, Sahay. Origin and evaluation of formation pressures. Ahmedabad: Allied Publishers, 1988.

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H, Fertl Walter, ed. Origin and evaluation of formation pressures. Dordrecht: Kluwer Academic Publishers, 1989.

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Mikhaĭlov, I. M. Potent͡sialʹnai͡a ėnergii͡a plastovykh fli͡uidov. Moskva: "Nauka", 1987.

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Book chapters on the topic "Reservoir oil pressure"

1

Nekrasov, Aleksandr, and Lev Pleshkov. "Oil Reservoir Geometrization Based on Universal Capillary Pressure Curve." In Lecture Notes in Networks and Systems, 320–28. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-89477-1_32.

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Tian, Xiao-feng, Xian-hong Tan, Li-jun Zhang, Xu-gang Yang, Yu-jia Jiao, Hao-chuan Ling, Lu Zhang, and Dong Han. "Study on Minimum Miscible Pressure of CO2 in Low Permeability Oil Reservoir." In Springer Series in Geomechanics and Geoengineering, 4042–51. Singapore: Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-99-1964-2_348.

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Na, Xue-fang, Hong-jun Yin, Hong-ge Liang, Chun-quan Fu, Gang Wen, and Ming-de Zhou. "Pressure Buildup Test Analysis for Hydraulic Fractured Horizontal Well with Stimulated Reservoir Volume in Tight Oil Reservoirs." In Springer Series in Geomechanics and Geoengineering, 522–33. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_48.

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Yuan, Shan, Juan Wang, Yong Hu, Ping Guo, Yu Luo, Juan She, and Yi Jiang. "Determination Method of Reasonable Production Pressure Difference in Depletion Development of Tight Oil Reservoir." In Proceedings of the International Field Exploration and Development Conference 2021, 3543–51. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_332.

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Yao, Chuan-jin, Zhe Wang, Hao-shuang Xu, and Lei Li. "Study on Pressure Conduction Law and Oil Displacement Ability of Fracture-Flooding in Low Permeability Reservoir." In Springer Series in Geomechanics and Geoengineering, 5601–17. Singapore: Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-99-1964-2_479.

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Xue, Linrui, Dechun Chen, Biao Feng, Yifei Cheng, Weidong Gu, Feng Chang, and Dong Jiang. "Study on Production Pressure Difference Upper Limit of Oil Well in Low Permeability Reservoir Based on Ensemble Learning." In Advances in Energy Resources and Environmental Engineering, 353–61. Cham: Springer International Publishing, 2024. http://dx.doi.org/10.1007/978-3-031-42563-9_34.

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Ayoub, M. A., Mysara Eissa Mohyaldinn, Alexy Manalo, Anas M. Hassan, and Quosay A. Ahmed. "A New Model for Predicting Minimum Miscibility Pressure (MMP) in Reservoir-Oil/Injection Gas Mixtures Using Adaptive Neuro Fuzzy Inference System." In Advances in Material Sciences and Engineering, 527–45. Singapore: Springer Singapore, 2019. http://dx.doi.org/10.1007/978-981-13-8297-0_55.

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Xu, Maolin, Dongyan Fan, and Jun Yao. "Pressure Transient Analysis Considering Geo-mechanic Effects in Deep Oil Reservoirs." In Computational and Experimental Simulations in Engineering, 1329–48. Cham: Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-44947-5_100.

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Yang, Limin. "Numerical Study of the Effect of Dynamic Capillary Pressure on Oil–Water Flow in Tight Reservoirs." In Lecture Notes in Civil Engineering, 13–24. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-4067-5_2.

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Zhang, Hong-yan, Xiao-cui Xu, Li Ban, Chun-hui Zhang, Jin-you Wang, Xiu-hong Chen, Qing-bo Mao, and Mu-lin Cheng. "Research and Application of Pressure Balanced Sliding Sleeve Fracturing Technology with Casing Cementing in Low Permeability Oil Reservoirs." In Springer Series in Geomechanics and Geoengineering, 119–27. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_13.

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Conference papers on the topic "Reservoir oil pressure"

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Aly, Ahmed, Her-Yuan Chen, and W. J. Lee. "Pre-Production Pressure Analysis of Commingled Reservoir With Unequal Initial Pressures." In Permian Basin Oil and Gas Recovery Conference. Society of Petroleum Engineers, 1994. http://dx.doi.org/10.2118/27661-ms.

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Igbokoyi, Alpheus Olorunwa, and Djebbar Tiab. "Estimation of Average Reservoir Pressure and Drainage Area in Naturally Fractured Reservoirs." In International Oil Conference and Exhibition in Mexico. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/104060-ms.

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Atashbari, Vahid, and Mark Robert Tingay. "Pore Pressure Prediction in a Carbonate Reservoir." In SPE Oil and Gas India Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/150836-ms.

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Al Hamad, Mohammed, Denis Klemin, Mark Ma Shouxiang, and Wael Abdallah. "Digitally Derived Capillary Pressure Data for Reservoir Evaluation." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213776-ms.

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Abstract Capillary pressure (Pc) is one of the fundamental parameters in formation evaluation. Currently, three methods are routinely used for Pc measurement; i.e., mercury injection, centrifuge, and porous plate. All three methods require testing of fluid displacement at capillary equilibrium conditions, an often-challenging condition to obtain, especially in low-quality rock samples. In this study, the ability to derive Pc data was investigated using digital rock (DR) physics techniques. Two sister carbonate outcrop samples were prepared. The samples were initially analyzed using thin-section analysis technique. The Pc measurements were then performed using methods of porous plate and mercury injection capillary pressure (MICP). After that, the samples were sub-cored, mounted in a unique computed tomography (CT) cell, scanned with a high-resolution micro-CT device at a confining stress of 800 psig, and analyzed digitally with a scanning electron microscope for data interpretation. Comparing the physically measured to the digitally simulated data, matches of pore throat sizes in terms of trends and peaks were obtained, including entry pressure, which validated and confirmed the quality of the constructed DR models. Using the established digital models of the rock samples, the Pc behavior was simulated. The results showed trend and connate water saturation matches with the experimental measurements. The results of this study demonstrate that the digitally generated Pc data obtained using the unique micro-CT polyetheretherketone (PEEK) high-pressure cell match the experimental data, opening new ways of generating Pc data quickly and reliably. With the developed DR technologies, performing special core analysis tests much faster becomes a reality without concerns for test equilibrium conditions, while also providing informative insights into the pore structure of the rock samples.
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Djatmiko, Wahyu, and Vinit Hansamuit. "Pressure Buildup Analysis in Karstified Carbonate Reservoir." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/132399-ms.

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Esmaily, Abdollah, Afonso Cesar Rodrigues Nogueira, Pedro Tupã Pandava Aum, Cláudio Regis Dos Santos Lucas, José Bandeira, Joelson Lima Soares, Rômulo Simões Angélica, Lorena Cardoso Batista, and Maryam Dehghani. "Minimum Miscibility Pressure Prediction For An Oil Reservoir." In ANAIS DO 11º CONGRESSO BRASILEIRO DE PETRóLEO E GáS. Galoa, 2022. http://dx.doi.org/10.17648/pdpetro-2022-159452.

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Gibrata, Muhammad A., Giamal Ameish, Yanfidra Djanuar, Mohammad Lamine, and Jose Lozano. "An Integrated Reservoir Characterization in Overpressure and Complex Sandstone Reservoirs for Hybrid Reservoir Modeling and Oil Productivity." In Gas & Oil Technology Showcase and Conference. SPE, 2023. http://dx.doi.org/10.2118/214258-ms.

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Abstract A Reliable reservoir characterization and model are useful for reservoir development in overpressure and complex reservoirs. The field has overpressure, multi fluid contacts, multi reservoir subunits, structural and stratigraphic sand discontinuities. The reservoir properties and quality decrease with increase of depth due to overburden compaction. However rock quality is useful for oil in place and productivity. Therefore, reliable reservoir characterization in deep reservoirs and estimation of fluids in place requires an integrated subsurface data approach. Overpressure reservoir has been observed and evaluated in some reservoirs, it tends to preserve porosity and has sufficient permeability for oil productivity from the deep reservoirs. Image resistivity/density log and chromatography data have been used to identify minor fault, gas/fluid evaluation and update the reservoir model. An integrated petrophysical evaluation has been implemented in reservoir characterization. A reliable in-house permeability log has been developed from porosity, clay bound, pore size, core and mobility data. It has used the of hybrid saturation height model that based on SCAL data including capillary pressure and Relative Permeability data for every reservoir rock type and fluid contacts for subunits. The advanced evaluation approach of subsurface and well test data has been used to provide reliable and good of reservoir properties and results on porosity, permeability, fluid contacts, reservoir rock type and initial water saturation in deep and overpressure reservoirs. The saturation height model (SHM) has been used, a quasi-SHM for unavailable core data in deep reservoir and PVT data have been used in the evaluation. The suitable open and cased hole logs data such as image resistivity/density, chromatography, pulse-neutron capture and production logs have been used to verify fault, fluid contacts, contribution, water saturation changes and production optimization. For every reservoir subunits, the formation pressure has been used to identify an initial oil water contact, reservoir subunits evaluation and thus it has provided SHM for complex reservoir modeling. The study has provided reliable reservoir characterization, reservoir modeling and for the development for multi-layers, over pressure and complex sandstone reservoirs. The high overpressure deep reservoirs have contributed for good oil productivity. It provides support to improve oil recovery from reservoirs and future plan for reservoir development target. Therefore the integrated reservoir evaluation approach has provided reliable assurance and important benefits for reservoir characterization, optimization and reservoir management. The integrated hybrid approach in this paper shows the value of advanced reservoir characterization in overpressure and faulted complex reservoirs. It has utilized the integration updated open and cased-hole data, gas/fluid contacts, stress direction, advanced permeability, saturation height model and gas-fluid evaluation. The evaluation also has provided the reliable for reservoir modeling, oil in place volume and field development purposes.
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Al Khamees, Ali, Rodolfo Phillips Guerrero, and Meshari Alodah. "Assessment of Condensate Banking Growth Using Advanced Pressure Transient Analysis." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213388-ms.

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Abstract Condensate banking is a process that occurs in gas wells when the reservoir pressure goes below the dew point. The depletion process introduces an additional fluid complexity, which complicates reservoir dynamics and reduces ultimate recovery. In addition, it hinders well performance and productivity due to its growth over production time. Estimating the current extent of condensate banking and predicting its progression over time plays a major role in optimizing well performance. Using single-phase pressure transient analysis to account for different mobility regions is widely practiced across the industry. However, a non-linear model must be utilized for the conditions where more than one phase exists, such as in gas condensate reservoirs. The model should consider non-linearities such as relative permeability curves for multi-phase systems, and pressure-dependent PVT properties such as viscosity, condensate gas ratio, and fluid compressibility. Non-linear modeling provides an accurate estimation of the different characteristic regions caused by condensate banking in terms of distance, mobility, and saturation variations, ensuring proper reservoir characterization. Additionally, with the utilization of test design function, non-linear modeling predicts condensate banking development, giving a precious indication of future well and reservoir conditions. The deployment of the advanced non-linear model in the pressure transient analysis (PTA) results in reasonable estimations of condensate banking distance from these wells. Finally, the results of the non-linear method highlighted the difference when compared to single-phase models, showcasing the importance of mimicking actual well and reservoir multi-phase conditions properly. In this study, we will illustrate pressure transient analysis test designs in condensate reservoirs, highlighting the condensate banking effect on the well performance and the extent estimation of the fluid bank utilizing a non-linear modeling approach as an aid in optimizing well performance.
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Furuya, M., and S. Takahashi. "Transient Pressure Data Interpretation of Horizontal Wells in a Multilayered Reservoir." In Middle East Oil Show. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/29896-ms.

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Almehaideb, R. A., K. Aziz, and O. A. Pedrosa. "A Reservoir/Wellbore Model for Multiphase Injection and Pressure Transient Analysis." In Middle East Oil Show. Society of Petroleum Engineers, 1989. http://dx.doi.org/10.2118/17941-ms.

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Reports on the topic "Reservoir oil pressure"

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Almutairi, Hossa, and Axel Pierru. Assessing Climate Mitigation Benefits of Public Support to CCS-EOR: An Economic Analysis. King Abdullah Petroleum Studies and Research Center, June 2023. http://dx.doi.org/10.30573/ks--2023-dp12.

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By storing carbon dioxide CO2 captured from the atmosphere or point sources into oil fields, carbon capture and storage with enhanced oil recovery (CCS-EOR) increases the fields’ output by raising reservoir pressures. Since CO2-EOR has been experimented with for decades and the revenues from the additional oil production improve projects’ economics, CCS-EOR is the most readily deployable CCS technology. However, public support for CCS-EOR projects is sometimes contested on the grounds that the resulting increase in oil production undermines their environmental benefits. Addressing this concern requires determining the effects of implementing CCS-EOR on global CO2 emissions. This note presents a simple approach based on a marginal reasoning consistent with economic decision-making. It produces analytical formulas that account for the effects on the global oil market of incentivizing CCS-EOR. In addition, we quantify the volume of oil that can be decarbonized by storing a tonne of captured CO2 through EOR from different perspectives. We produce numerical results based on a first-cut calibration. Results suggest that, from an economic perspective, CCS-EOR is a technology that mitigates global emissions. However, after accounting for the need to decarbonize the EOR oil, the reduction in emissions is significantly less than the stored quantity of CO2. If fully allocated to oil production, the environmental benefits of capturing a tonne of CO2 and storing it through conventional EOR can allow the oil producer to decarbonize 3.4 barrels on a well-to-wheel basis and 14.4 barrels when offsetting its oil-upstream emissions only. Fiscal incentives granted by governments to support CCS-EOR as a climate-change mitigation technology should be sized accordingly. We compare our findings to the size of the subsidy in the revised Section 45Q of the 2022 United States Inflation Reduction Act.
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