Journal articles on the topic 'Reservoir oil pressure'
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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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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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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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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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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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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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Farouk, Ali Khaleel, and Ayad A. Al-haleem. "Integrating Petrophysical and Geomechanical Rock Properties for Determination of Fracability of the Iraqi Tight Oil Reservoir." Iraqi Geological Journal 55, no. 1F (June 30, 2022): 81–94. http://dx.doi.org/10.46717/igj.55.1f.7ms-2022-06-22.
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Tight oil reservoirs have been a concerned of the oil industry due to their substantial influence on oil production. Due to their poor permeability, numerous problems are encountered while producing from tight reservoirs. Petrophysical and geomechanical rock properties are essential for understanding and assessing the fracability of reservoirs, especially tight reservoirs, to enhance permeability. In this study, Saadi B reservoir in Halfaya Iraqi oil field is considered as the main tight reservoir. Petrophysical and geomechanical properties have been estimated using full-set well logs for a vertical well that penetrates Saadi reservoir and validated with support of diagnostic fracture injection test data employing standard equations and correlations. Subsequently, breakdown pressures are computed, and two fracturing models have been developed. The petrophysical analysis infers that the reservoir has poor properties, while the findings of the geomechanical properties indicate that the reservoir is brittle with ductile rock strata. These ductile strata underlay and overlay more brittle formations than the reservoir. The results from diagnostic fracture injection test DFIT are quite consistent with well logs results. The breakdown pressure reflects that this reservoir could easily be fractured by inserting pressure equal to 6250 psi. However, the fracturing model design parameters manipulates the fracture height confinement within Saadi Formation and its propagation to Hartha and/or Tanuma Formations. Therefore, the employment of petrophysical and geomechanical properties of the rocks assists in understanding the fracability of the formation and demonstrating the orientation and the fracture propagation direction.
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Mohammed Bashir Abdullahi, Shiferaw Regassa Jufar, Jang Hyun Lee, Tareq Mohammed Al-shami, Minh Duc Le, and Sunil Kwon. "Pore Pressure Diffusion Waves Transmission in Oil Reservoir." Journal of Advanced Research in Fluid Mechanics and Thermal Sciences 109, no. 2 (November 2, 2023): 49–65. http://dx.doi.org/10.37934/arfmts.109.2.4965.
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Recent studies on seismic wave excitation have revealed that mesoscopic wave-induced fluid flow (WIFF) is a process that attenuates the compressional (P) waves in reservoir rocks at seismic frequency bands. Fluid flow and Biot's slow diffusion (pressure) waves are produced when the P-waves create fluid-pressure gradients at mesoscopic-scale heterogeneities. Pore pressure continuity can be sustained by converting seismic energy into diffusion waves that diffuse away from the interfaces or boundaries. Biot’s diffusion waves fail to comply with a square-law approach because of their slow propagation velocity and higher attenuation. It is currently uncertain how to characterize reservoir fluids in mature oil reservoirs during seismic wave-based enhanced oil recovery (EOR). A simplified 1D two-layer reservoir model was investigated in this study. The findings demonstrate that diffusion wave propagation in oil reservoirs is frequency-dependent and affected by rock permeability and fluid viscosity. At a formation layer interface, it was discovered that diffusion waves obeyed the accumulation-depletion relationship rather than the reflection-refraction approach. Therefore, pore pressure diffusion waves can characterize reservoir fluid during seismic EOR and monitor the CO2 front in depleted reservoirs during storage for CCUS projects. It can also detect shale gas transport in low permeability layers and identify the propagation of fractures during gas/oil recovery.
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Smith, Nicholas M., Hossein Ebrahimi, Ranajay Ghosh, and Andrew K. Dickerson. "High-speed microjets issue from bursting oil gland reservoirs of citrus fruit." Proceedings of the National Academy of Sciences 115, no. 26 (June 11, 2018): E5887—E5895. http://dx.doi.org/10.1073/pnas.1720809115.
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The rupture of oil gland reservoirs housed near the outer surface of the citrus exocarp is a common experience to the discerning citrus consumer and bartenders the world over. These reservoirs often rupture outwardly in response to bending the peel, which compresses the soft material surrounding the reservoirs, the albedo, increasing fluid pressure in the reservoir. Ultimately, fluid pressure exceeds the failure strength of the outermost membrane, the flavedo. The ensuing high-velocity discharge of oil and exhaustive emptying of oil gland reservoirs creates a method for jetting small quantities of the aromatic oil. We compare this jetting behavior across five citrus hybrids through high-speed videography. The jetting oil undergoes an extreme acceleration to reach velocities in excess of 10 m/s. Through material characterization and finite element simulations, we rationalize the combination of tuned material properties and geometries enabling the internal reservoir pressures that produce explosive dispersal, finding the composite structure of the citrus peel is critical for microjet production.
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Khurshid, Ilyas, and Imran Afgan. "Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery." Energies 14, no. 22 (November 16, 2021): 7676. http://dx.doi.org/10.3390/en14227676.
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The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.
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Abdulwahid Al-Sudani, Jalal. "Analytical Model for Detection the Tilt in Originally Oil Water Contacts." Iraqi Journal of Chemical and Petroleum Engineering 15, no. 3 (September 30, 2014): 51–60. http://dx.doi.org/10.31699/ijcpe.2014.3.6.
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Many carbonate reservoirs in the world show a tilted in originally oil-water contact (OOWC) which requires a special consideration in the selection of the capillary pressure curves and an understanding of reservoir fluids distribution while initializing the reservoir simulation models.An analytical model for predicting the capillary pressure across the interface that separates two immiscible fluids was derived from reservoir pressure transient analysis. The model reflected the entire interaction between the reservoir-aquifer fluids and rock properties measured under downhole reservoir conditions.This model retained the natural coupling of oil reservoirs with the aquifer zone and treated them as an explicit-region composite system; thus the exact solutions of diffusivity equation could be used explicitly for each region. The reservoir-aquifer zones were linked by a capillary transition zone that reflected the pressure difference across the free water level.The principle of superposition theorem was applied to perform this link across the free water level to estimate the reflected aquifer pressure drop behavior that holds the fluid contacts in their equilibrium positions.The results of originally oil water contact positions generated by the proposed model were compared with data obtained from a carbonate oil field; the results given by the model showed full agreement with the actual field data.
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Semenova, T. V. "PROBLEMS OF COMPATIBILITY OF FORMATION WATER AND INJECTED WATER IN THE OIL FIELDS OF WESTERN SIBERIA." Oil and Gas Studies, no. 4 (September 1, 2017): 34–37. http://dx.doi.org/10.31660/0445-0108-2017-4-34-37.
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A method of maintaining reservoir pressure using a system for formation pressure maintenance of oil reservoirs in the oil fields of Western Siberia is extremely wide-spread. In oil fields as a system for formation pressure maintenance are widely used almost all types of water resources including surface water, groundwater and industrial wastewater. Different calculation methods for predicting the formation and precipitation of salts based on quantitative criteria are used to forecast possible precipitation of calcium carbonate in the flooded oil reservoir areas.
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Luo, Yutian, Zhengming Yang, Zhenxing Tang, Sibin Zhou, Jinwei Wu, and Qianhua Xiao. "Longitudinal Reservoir Evaluation Technique for Tight Oil Reservoirs." Advances in Materials Science and Engineering 2019 (January 6, 2019): 1–8. http://dx.doi.org/10.1155/2019/7681760.
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Reservoir evaluation is a method for classifying reservoirs and the description of heterogeneity quantitatively. In this study, according to the characteristics of longitudinal physical properties of tight oil reservoirs, advanced experimental techniques such as nuclear magnetic resonance, high pressure mercury intrusion, and X-ray diffraction were adopted; the flow capacity, reservoir capacity, ability to build an effective displacement system, and the ability to resist damage in reservoir reconstruction were considered as evaluation indexes; average throat radius, percentage of movable fluid, start-up pressure gradient, and the content of clay minerals were taken as the evaluation parameters. On the above basis, a longitudinal evaluation technique for tight oil reservoirs was established. The reservoir was divided into four categories by using this method. The reservoirs with a depth 2306.54 m–2362.07 m were mainly type I and II reservoirs, and the reservoirs with a depth of 2362.07 m–2391.30 m were mainly reservoirs of type II and III. The most effective development was water injection in the upper section and gas injection in the lower section.
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Han, Yu, Peiru Wanyan, Haoli Wang, Mengfei Qu, Hanlie Cheng, and Fahim Theon. "Effectiveness of Oil Filling in Tight Sandstone Reservoirs of Yancheng Formation in Ordos Basin." Journal of Chemistry 2022 (October 4, 2022): 1–8. http://dx.doi.org/10.1155/2022/9907772.
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The Ordos basin is one of the important oil-bearing basins in China, with abundant tight sandstone oil resources, wide distribution, and large thickness. It is the most realistic field of unconventional oil and gas exploration in China, and it is also an important oil and gas replacement resource at present. Oil accumulation in tight reservoirs is obviously different from conventional oil and gas accumulation, and the key lies in studying the effectiveness of oil filling in tight reservoirs. In order to solve this problem, this paper takes the tight sandstone reservoir of Member 7 of the Yancheng Formation in Ordos Basin as the research object, introduces the geological characteristics of this area after sorting out the previous research results, carries out the physical simulation experiment of oil filling, studies the relationship between the filling pressure and the lower limit of the filling throat, analyzes the effective accumulation space of the tight sandstone reservoir, defines the oil filling mechanism of the tight sandstone reservoir, and discusses the effectiveness and reservoir-forming effect of oil filling in different types of reservoirs. The results show that the rock types of tight sandstone reservoirs in the 7th member of the Yancheng Formation are mainly lithic feldspathic sandstone and feldspathic lithic sandstone, and the reservoirs have experienced strong compaction and carbonate cementation. The late iron-bearing carbonate cementation has further strengthened the degree of reservoir densification, and the reservoirs have been densified at the time of large-scale oil and gas filling. Through the simulation experiment of oil filling with natural cores with different physical properties, the relationship model between filling pressure and effective accumulation space of different types of tight sandstone reservoirs in Member 7 of the Yancheng Formation is established. With the change in filling pressure, the change trend and range of effective accumulation space of different types of tight sandstone reservoirs are obviously different. According to the relationship model between the filling pressure and the lower limit of the effective filling pore throat, the oil filling effectiveness of different types of tight sandstone reservoirs in the 7th member of the Yancheng Formation is determined. Class I and class II1 reservoirs are effective reservoirs for oil filling of tight sandstone reservoirs, which constitute the main oil-bearing section of tight sandstone reservoirs in member 7 of the Yancheng formation, while class II2 reservoirs are poor tight reservoirs, and class III reservoirs are basically oil-free, which are noneffective reservoirs for oil filling of tight sandstone reservoirs. The results provide theoretical data support for the next step of oil exploration and exploitation in tight sandstone reservoirs.
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Hou, Dali, Yang Xiao, Yi Pan, Lei Sun, and Kai Li. "Experiment and Simulation Study on the Special Phase Behavior of Huachang Near-Critical Condensate Gas Reservoir Fluid." Journal of Chemistry 2016 (2016): 1–10. http://dx.doi.org/10.1155/2016/2742696.
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Due to the special phase behavior of near-critical fluid, the development approaches of near-critical condensate gas and near-critical volatile oil reservoirs differ from conventional oil and gas reservoirs. In the near-critical region, slightly reduced pressure may result in considerable change in gas and liquid composition since a large amount of gas or retrograde condensate liquid is generated. It is of significance to gain insight into the composition variation of near-critical reservoir during the depletion development. In our study, we performed a series ofPVTexperiments on a real near-critical gas condensate reservoir fluid. In addition to the experimental studies, a commercial simulator combined with the PREOS model was utilized to study retrograde condensate characteristics and reevaporation mechanism of condensate oil with CO2injection based on vapor-liquid phase equilibrium thermodynamic theory. The research shows that when reservoir pressure drops below a certain pressure, the variation of retrograde condensate liquid saturation of the residual reservoir fluid exhibits the phase behavior of volatile oil.
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Liu, Yishan, Zhewei Chen, Dongqi Ji, Yingfeng Peng, Yanan Hou, and Zhengdong Lei. "Pore Fluid Movability in Fractured Shale Oil Reservoir Based on Nuclear Magnetic Resonance." Processes 11, no. 12 (December 4, 2023): 3365. http://dx.doi.org/10.3390/pr11123365.
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Gulong shale oil is found in a typical continental shale oil reservoir, which is different from marine shale oil reservoirs. The Gulong shale oil reservoir is a pure shale-type oil reservoir with abundantly developed nanoscale pores, making it extremely difficult to unlock fluids. Pressure drive does not easily achieve fluid unlock conditions; thus, it is necessary to utilize imbibition to unlock nanoscale pore fluids. In this study, experiments were conducted on oil displacement by high-speed centrifugal pressure and imbibition under different conditions, respectively, and simulations were used to evaluate the effects of pressure differential drive and imbibition efficiency on the utilization of crude oil following fracturing. Combined with the mixed wettability of the reservoir, the imbibition efficiency was analyzed, and the imbibition efficiency at different soaking stages was evaluated. When the fracturing pressure was higher than the matrix pore pressure, the imbibition efficiency was the most obvious, which was 27.9%. Spontaneous imbibition depending solely on capillary force had poor efficiency, at 16.8%. When the fracturing pressure was lower than the matrix pore pressure, the imbibition efficiency was the lowest, at only 1.3%. It is proposed that strengthening fracture pressure and promoting pressurized imbibition are the keys to improving shale oil development.
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Yang, Min, Sen Wang, Qihong Feng, and Yanguang Yuan. "Numerical Investigation of a Novel Bottom-Up Assisted Pressure Drive Process in Oil Sands Reservoirs with Shale Barriers." Applied Sciences 12, no. 22 (November 17, 2022): 11666. http://dx.doi.org/10.3390/app122211666.
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Steam-assisted gravity drainage (SAGD) is widely applied to recover bitumen and heavy oil resources. Reservoir heterogeneity, especially the presence of shale barriers, continues to challenge the performance of SAGD. A novel enhanced oil recovery process, bottom-up assisted pressure drive, is proposed to improve the oil production in the reservoirs with shale barriers. In this work, numerical simulation is applied to investigate the feasibility of a bottom-up assisted pressure drive process. A reservoir model with typical oil sand reservoir properties is developed considering shale barriers. The performance of bottom-up assisted pressure drive and SAGD is compared under the same reservoir conditions, including steam chamber development, oil production rate, cumulative oil production, and the pressure difference between injector and production. The inherent mechanisms associated with the bottom-up assisted pressure drive are also well understood and confirmed. In the bottom-up assisted pressure drive, a flat steam chamber is developed from the bottom of the reservoir in the early stage of the process and grows upward with the injection of steam. The large volume of the steam chamber and the huge contact area between steam and bitumen contribute to a high oil production rate. The peak oil production rate in the bottom-up assisted pressure drive is approximately three times that in the SAGD process. The cumulative oil production in the bottom-up assisted pressure drive is 20% higher than that in the SAGD process. The effect of shale barriers on bottom-up assisted pressure drive is less, indicating one advantage of this novel process over SAGD in oil sands reservoirs with shale barriers. The pressure difference in the bottom-up assisted pressure drive is greater than that in the SAGD process. The pressure drive is another mechanism for improving oil production. The calculated net present value (NPV) in the bottom-up assisted pressure drive process is 27% higher than that in the SAGD process. This is mainly attributed to the high oil production rate in the early stage of the process and high cumulative oil production. The simulation study in this work provides technical support for the future field applications of this novel recovery process.
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Baker, Hussain Ali, Dunia Abdulsaheb Al-Shamma'a, and Emad Abdulhussain Fakher. "New Correlation for Predicting Undersaturated Oil Compressibility for Mishrif Reservoir in the Southern Iraqi Oil Fields." Journal of Engineering 19, no. 9 (June 5, 2023): 1158–68. http://dx.doi.org/10.31026/j.eng.2013.09.09.
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Reservoir fluids properties are very important in reservoir engineering computations such as material balance calculations, well testing analyses, reserve estimates, and numerical reservoir simulations. Isothermal oil compressibility is required in fluid flow problems, extension of fluid properties from values at the bubble point pressure to higher pressures of interest and in material balance calculations (Ramey, Spivey, and McCain). Isothermal oil compressibility is a measure of the fractional change in volume as pressure is changed at constant temperature (McCain). The most accurate method for determining the Isothermal oil compressibility is a laboratory PVT analysis; however, the evaluation of exploratory wells often require an estimate of the fluid behavior prior to obtaining a representative reservoir sample. Also, experimental data is often unavailable.Empirical correlations are often used for these purposes.This paper developed a new mathematical model for calculating undersaturated oil compressibility using 129 experimentally obtained data points from the PVT analyses of 52 bottom hole fluid samples from Mishrif reservoirs in the southern Iraqi oil fields. The new undersaturated oil compressibility correlation developed using Statistical Analysis System (SAS) by applying nonlinear multiple regression method. It was found that the new correlation estimates undersaturated oil compressibility of Mishrif reservoir crudes in the southern Iraqi oil fields much better than the published ones. The average absolute relative error for the developed correlation is 7.16%.
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Khuzin, R. R., R. N. Bakhtizin, V. E. Andreev, L. S. Kuleshova, V. V. Mukhametshin, and Sh Kh Sultanov. "Oil recovery enhancement by reservoir hydraulic compression technique employment." SOCAR Proceedings, SI1 (June 30, 2021): 98–108. http://dx.doi.org/10.5510/ogp2021si100522.
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Industrial experiment works (IEW) were carried out to study the mechanism of filtration and reservoir properties changes (FRP) in the process of wells swabbing. Based on the hydrodynamic studies, the results of the works are analyzed. A method for oil production enhancing by reservoirs hydraulic compression has been worked out. In the process of well swabbing the barograms were recorded, pressure recovery curves were taken with the determination of hydraulic conductivity and piezoconductivity values, potential productivity coefficients, well flow rate, reservoir pressure before and after exposure. The interpretation of hydrodynamic studies was carried out by the deterministic analysis with subsequent modeling of the situation. The reservoir, opened by the perforation interval, is of complex structure, as a result of which the liquid was absorbed by the interlayer located above the area with newly formed microcracks. Keywords: hard-to-recover reserves; swabbing; carbonate reservoirs; filtration reservoir properties; pressure recovery curve.
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Jassim, Ayat Ahmed, Abdul Aali Al-dabaj, and Aqeel S. AL-Adili. "Water Injection for Oil Recovery in Mishrif Formation for Amarah Oil Field." Iraqi Journal of Chemical and Petroleum Engineering 21, no. 1 (March 29, 2020): 39–44. http://dx.doi.org/10.31699/ijcpe.2020.1.6.
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The water injection of the most important technologies to increase oil production from petroleum reservoirs. In this research, we developed a model for oil tank using the software RUBIS for reservoir simulation. This model was used to make comparison in the production of oil and the reservoir pressure for two case studies where the water was not injected in the first case study but adding new vertical wells while, later, it was injected in the second case study. It represents the results of this work that if the water is not injected, the reservoir model that has been upgraded can produce only 2.9% of the original oil in the tank. This case study also represents a drop in reservoir pressure, which was not enough to support oil production. Thus, the implementation of water injection in the second case study of the average reservoir pressure may support, which led to an increase in oil production by up to 5.5% of the original oil in the tank. so that, the use of water injection is a useful way to increase oil production. Therefore, many of the issues related to this subject valuable of study where the development of new ideas and techniques.
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Meisingset, K. K. "Uncertainties in Reservoir Fluid Description for Reservoir Modeling." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 431–35. http://dx.doi.org/10.2118/57886-pa.
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Summary The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea. Introduction Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions. The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API). Fluid Parameters in the Reservoir Model The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:densities at standard conditions of stabilized oil, condensate, gas, and water;viscosity (?O) oil formation volume factor (B O) and gas-oil ratio (RS) of reservoir oil;viscosity (?G) gas formation volume factor (B G) and condensate/gas ratio (RSG) of reservoir gas;viscosity (?W) formation volume factor (BW) and compressibility of formation water; andsaturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas. The actual input is usually slightly more complex, with saturation pressure given as a function of depth, with RS and R SG defined as a function of saturation pressure, and with oil and gas viscosities and formation volume factors given as a function of reservoir pressure for a range of saturation pressure values. However, minor changes in saturation pressure versus depth are usually neglected, and the oil dissolved in the reservoir gas can also be neglected (RSG=0) when the solubility is small. Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir. In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model. Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3). Prospect Evaluation Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same. The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by). For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate. From Discovery to Production After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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Novruzova, S. H., and I. N. Aliyev. "Determination of Reservoir Characteristics Oil Well Producing Non-Newtonian Oil, Taking into Account the Temperature Situation in the Reservoir." Oil and Gas Technologies 150, no. 1 (2024): 40–42. http://dx.doi.org/10.32935/1815-2600-2024-150-1-40-42.
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The article investigates the problem of determining the reservoir properties of non-Newtonian oil reservoirs developed in the depletion mode, the rocks of which are subjected to elastic deformation. Various methods (identification and graphic-analytical) for determining the reservoir properties of non-Newtonian oil reservoirs are proposed, takinginto account the temperature situation. The determined reservoir properties of the formations are: porosity and permeability of the formations, the initial pressure gradient, as well as the current well drainage radius.
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Al-Mahasneh, Mehaysen, Hussam Elddin Al-Khasawneh, Kamel Al-Zboon, Marwan Al-Mahasneh, and Ali Aljarrah. "Water Influx Impact on Oil Production in Hamzeh Oil Reservoir in Northeastern Jordan: Case Study." Energies 16, no. 5 (February 22, 2023): 2126. http://dx.doi.org/10.3390/en16052126.
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This paper was conducted to delimit the water influx in the Hamzeh oil reservoir, located in northeastern Jordan approximately 150 km east of Amman. Petroleum reservoirs are frequently encompassed by water aquifers that back up the reservoir pressure through water inflow. When the pressure declines in a petroleum reservoir, the water aquifer responds by providing an influx of water. Gradually, the damage is reduced and then eliminated, and more oil is produced from the reservoir. The material balance equation (MBE) is used as the fundamental method for this study, predicting reservoir performance for a period of 11 years. The results for this study prove that the reservoir has a water drive mechanism and that the original oil in place (OOIP) was 24,958,290 m3. The projected oil recovery factor ranges from 10.9 to 25 percent for the Hummar and Shueib formations, respectively, depending on the areal efficiency assumed in the calculations. The water influx for the 11-year period was predicted by an MBE, an unsteady-state model, and the results of the performance reservoir.
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Mukhametshin, V. Sh, and R. F. Yakupov. "Features of well hydrodynamic studies to increase the geological exploration status of hydrocarbon deposits." SOCAR Proceedings, no. 1 (March 31, 2023): 59–67. http://dx.doi.org/10.5510/ogp20230100805.
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The article shows the results of planning and conducting hydrodynamic studies in producing wells analysis, which states that the pressure recovery curve (PRC) is an effective tool for solving problems of increasing the informativeness and knowledge of the reservoir energy state. The high degree of equipment with telemetry systems sensors (TSS) at the pump suction makes it possible to significantly increase the coverage of the field with estimates of reservoir parameters in the zones of drilling new wells. The depth sensors employment makes it possible to better succeed in reservoir pressure estimation and, as a result, eliminate an error in pressure recalculation. A large number of TSS sensors at producing wells allows us to digitalize the deposit, reduce losses in oil production by optimizing the research program and operational data using. The technology of express reservoir pressure estimation in the production and pressure analysis according to the data from the TSS sensor is considered in the article, which does not require a stop on the level recovery curve (LRC) or PRC, which thereby eliminates oil and liquid losses. This technique of reservoir pressure estimating allows to increase the coverage of research in fields with low-permeability reservoirs and in areas with high oil debits. Keywords: hydrodynamic studies of wells; oil field development; pressure recovery curve; permeability; telemetry system sensor; digitalization; oil production; reservoir parameters.
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Xia, Zhizeng, Xuewu Wang, Rui Xu, and Weiwei Ren. "Tight oil reservoir production characteristics developed by CO2 huff ‘n’ puff under well pattern conditions." Journal of Petroleum Exploration and Production Technology 12, no. 2 (January 9, 2022): 473–84. http://dx.doi.org/10.1007/s13202-021-01446-1.
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AbstractTight oil reservoirs have poor physical properties, and the problems including rapid oil rate decline and low oil recovery degree are quite common after volume fracturing. To obtain a general understanding of tight oil reservoir production improvement by CO2 huff ‘n’ puff, the high-pressure physical properties of typical tight oil samples are measured. Combining the typical reservoir parameters, the production characteristics of the tight oil reservoir developed by the CO2 huff ‘n’ puff are numerically studied on the basis of highly fitted experimental results. The results show that: (1) during the natural depletion stage, the oil production rate decreases rapidly and the oil recovery degree is low because of the decrease in oil displacement energy and the increase in fluid seepage resistance. (2) CO2 huff ‘n’ puff can improve the development effect of tight oil reservoirs by supplementing reservoir energy and improving oil mobility, but the development effect gradually worsens with increasing cycle number. (3) The earlier the CO2 injection timing is, the better the development effect of the tight reservoir is, but the less sufficient natural energy utilization is. When carrying out CO2 stimulation, full use should be made of the natural energy, and the appropriate injection timing should be determined by comprehensively considering the formation-saturation pressure difference and oil production rate. The research results are helpful for strengthening the understanding of the production characteristics of tight oil reservoirs developed by CO2 huff ‘n’ puff.
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Escobar, Freddy Humberto, Angela Patricia Zambrano, Diana Vanessa Giraldo, and José Humberto Cantillo. "Pressure and pressure derivative analysis without type-curve matching for thermal recovery processes." CT&F - Ciencia, Tecnología y Futuro 4, no. 4 (December 1, 2011): 23–35. http://dx.doi.org/10.29047/01225383.226.
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In recent years, a constant increase of oil prices and declining reserves of coventional crude oils have produced those deposits of lights to be considered economically unattractive to be produced as an alternative way to keep the world´s oil supply volume.
Heavy oil deposits are mainly characterized by having high resistance to flow (high viscosity), which makes them diffi-cult to produce. Since oil viscosity is a property that is reduced by increasing the temperature, thermal recovery techniques -such as steam injection or in-situ combustion- have become over the years the main tool for tertiary recovery of these oils.
Composite reservoirs can occur naturally or may be artificially created. Changes in reservoir width, facies or type of fluid (hydraulic contact) forming two different regions are examples of two-zone composite reservoirs occurring naturally. On the other hand, such enhanced oil recovery projects as waterflooding, polymer floods, gas injection, in-situ combustion, steam drive, and CO2 miscible artificially create conditions where the reservoir can be considered as a composite system. A reservoir undergoing a thermal recovery process is typically idealized as a two-zone composite reservoir, in which, the inner region represents the swept region surrounding the injection well and the outer region represents the larger portion of the reservoir. Additionally, there is a great contrast between the mobilities of the two zones and the storativity ratio being different to one.
In this work, the models and techniques developed and implemented by other authors have been enhanced. Therefore, the interpretations of the well tests can be done in an easier way, without using type-curve matching. A methodology which utilizes a pressure and pressure derivative plot is developed for reservoirs subjected to thermal recovery so that mobilities, storativity ratio, distance to the radial discontinuity or thermal front and the drainage area can be estimated. The precedence of the heat source (in-situ combustion or hot injected fluids) does not really matter for the application of this methodology; however, this was successfully verified by its application to synthetic and field examples of in-situ combustion. The point of comparison was the input data used for simulation for the synthetic case and the results from simulation matching and from previous studies for the field cases.
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Ke, Wenqi, Wei Luo, Shiyu Miao, Wen Chen, and Yaodong Hou. "A Transient Productivity Prediction Model for Horizontal Wells Coupled with Oil and Gas Two-Phase Seepage and Wellbore Flow." Processes 11, no. 7 (July 5, 2023): 2012. http://dx.doi.org/10.3390/pr11072012.
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Capacity prediction is the basis for the optimization of oil and gas well production work systems and parameter optimization design. Horizontal wells are becoming increasingly popular for oil and gas extraction. However, the seepage law of reservoirs produced with horizontal wells is more complicated than that of reservoirs produced with vertical wells, especially when the bottom hole flowing pressure or formation pressure is less than the saturation pressure of crude oil in the reservoir. Oil and gas two-phase seepage can occur in a part or all areas of the wellbore and reservoir. Because the oil and gas two-phase seepage characteristics of reservoir oil well production will be reduced—possibly greatly reduced—the formation seepage law is complex. Thus, it is very important to better predict the horizontal well capacity. To address this, a method and process of establishing a transient calculation model of two-phase flow in horizontal wells are introduced in detail from three aspects: fluid physical properties, reservoir oil and gas two-phase seepage, and the coupling model of the inflow performance and flow in the wellbore. The model is found to be reliable through verification with production data from five wells in two oilfields. The established model simplifies the reservoir model, does not involve very complex meshing, and only simulates one well. Therefore, the calculation speed will be faster than that of other reservoir numerical simulation methods under the same conditions.
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Nan, Chong, Xiankang Xin, Gaoming Yu, Zexuan Lei, and Ting Wang. "Comprehensive Study of Development Strategies for High-Pressure, Low-Permeability Reservoirs." Processes 11, no. 12 (November 26, 2023): 3303. http://dx.doi.org/10.3390/pr11123303.
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Currently, there is no well-established framework for studying development patterns in high-pressure, low-permeability reservoirs. The key factors influencing development effect typically include the reservoir properties, well pattern, well spacing, and the rate of oil production. Reservoir A is a representative of this type of reservoir. Starting from its physical properties, a study of the development mechanism was conducted using the tNavigator (22.1) software. A total of 168 sets of numerical experiments were conducted, and 3D maps were innovatively created to optimize the development mode. Building upon the preferred mode, an exploration was carried out for the applicability of gas flooding and the optimization of water flooding schemes for such reservoirs. All experimental results were reasonably validated through Reservoir A. Furthermore, due to the high original pressure in such reservoirs, the injection of displacement media was challenging. Considering economic benefits simultaneously, a study was conducted to explore the rational utilization of natural energy. The research proved that for a reservoir with a permeability of about 10 mD, the suitable development scheme was five-point well pattern, a well spacing of 350 m, water–gas alternating flooding, and an initial oil production rate of 2%. When the reservoir underwent 8 months of depleted development, corresponding to a reduction in the reservoir pressure coefficient to 1.09, the development efficiency was relatively favorable. Over a 15-year production period, the oil recovery reached 29.98%, the water cut was 10.31%, and the reservoir pressure was maintained at around 67.18%. The geology of the newly discovered reservoir is not specific in the early stage of oilfield construction, and this research can help to determine a suitable development scheme.
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MOLDABAEVA, G. J., A. Х. AGZAMOV, S. A. ABBASOVA, R. T. SULEIMENOVA, and H. M. MUKHAMMADIEV. "FACTORS AFFECTING THE GAS RECOVERY COEFFICIENT AT GAS CONDENSATE FIELDS WITH ABNORMALLY HIGH RESERVOIR PRESSURE." Neft i Gaz 129, no. 3 (June 15, 2022): 66–83. http://dx.doi.org/10.37878/2708-0080/2022-3.06.
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The results of numerical experiments to assess the influence of abnormally high reservoir pressure on the dynamics of pressure reduction at the bottom and the supply circuit, flow rate and life of wells are presented. It is shown that the growth of the anomaly coefficient of reservoir pressure has a positive effect on the dynamics of the considered indicators. It has been established that in hydrocarbon deposits with abnormally high reservoir pressures, the rock pressure of up to 75% is balanced by the pressure of saturating hydrocarbons. High rates of gas extraction, achieved due to large depressions on the reservoir in producing wells, lead to reservoir deformation, which in fractured and fractured-pore reservoirs leads to the closure of hydrocarbon filtration channels. Using the example of the Severny Nishan gas condensate field, it is shown that the deformation of the reservoir is the main reason for the low efficiency of development and the abandonment of half of the gas reserves in the reservoir. Hydraulic fracturing technology is recommended for the extraction of residual gas reserves. With an increase in the depth of the productive horizons, the proportion of hydrocarbon deposits with abnormally high reservoir pressures is steadily increasing. As it is known, the energy potential of productive layers is largely determined by the activity of the legal aquifer area. There are elision and infiltration natural water pressure systems. The experience of developing hydrocarbon deposits with AVPD shows that this factor, depending on the geological and physical conditions of the deposits, can affect the oil and gas recovery coefficient as a positive (increasing) and negative (decreasing) factor. At the same time, as positive factors, there is a higher concentration of reserves in the specific volume of the deposit, relatively high well flow rates, ensuring the gushing of wells for a long time, maintaining high reservoir properties of reservoir rocks, and as a negative factor, a decrease in stability and susceptibility of oil and gas saturated reservoirs to deformation processes.
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Song, Li Yang, Jian Cheng Wei, Xiang Min Xu, and Ting Gao. "Optimization of Black Oil Model-CO2 Flooding in Low Permeability Reservoir." Applied Mechanics and Materials 580-583 (July 2014): 2502–7. http://dx.doi.org/10.4028/www.scientific.net/amm.580-583.2502.
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This paper mainly studied the influence of starting pressure gradient in CO2flooding. The capillary pressure of low permeability reservoir is much larger than the ordinary reservoir, so that the influence of starting pressure gradient can not be ignored. Since CO2flooding will be widely used in the development of low permeability reservoirs, it is necessary to study the influence of starting pressure gradient. This paper mainly used Runge Kutta Fehlberg Method and Adams Fourth-order Predictor-Corrector to solve the black oil model, which was founded to study the process of CO2flooding. These two methods considered the starting pressure gradient during the CO2flooding, and the influence of reservoir permeability and crude oil density were studied by founding black oil model and use these two methods to solve the model. We have compared the production rate with staring pressure gradient and without starting pressure gradient.
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Wang, Xinghao, Kui Xiang, Yuanyuan Luo, Gongxian Tan, and Jiaju Ruan. "Experimental Study of Complex Resistivity Characteristics of a Sandstone Reservoir under Different Measurement Conditions." Geofluids 2023 (February 4, 2023): 1–18. http://dx.doi.org/10.1155/2023/4123836.
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Due to the variability of fluid properties and saturation of reservoirs, large differences in formation temperature and pressure, and the diversity of rock and mineral compositions, the petrophysical response of reservoirs is often complex. This study explored a new method of reservoir fluid identification and evaluation based on the complex resistivity response characteristics of sandstone reservoirs under different measurement conditions. The complex resistivity of the five sandstone samples was measured under normal temperature and pressure and variable pressure, temperature, and formation conditions and under different oil saturations. Furthermore, the reservoir was comprehensively analyzed and evaluated based on the mineral composition, porosity, and permeability parameters. The results show that the resistivity of the sandstone increases logarithmically with pressure and oil saturation but decreases logarithmically with temperature and depth. The polarizability decreases slightly with increasing pressure and increases slightly with increasing temperature. With increasing depth, the polarizability decreases obviously, and with increasing oil saturation, the polarizability decreases moderately. Under different measurement conditions, the complex resistivity data for the sandstone reservoir and the IP parameters extracted through inversion are regular. The results of this study provide a new method for the identification and evaluation of complex reservoir fluids and have important reference value.
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Kozhevnikov, Evgenii, Evgenii Riabokon, and Mikhail Turbakov. "A Model of Reservoir Permeability Evolution during Oil Production." Energies 14, no. 9 (May 8, 2021): 2695. http://dx.doi.org/10.3390/en14092695.
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In this paper, we present a mathematical model to predict the evolution of rock permeability depending on effective pressure during oil production. The model is based on the use of the results of well testing data from wells operating in the oil fields of the Perm–Solikamsk region in the north of the Volgo Ural oil and gas province. Dependences of the change in flow characteristics in the reservoir on the effective pressure were established. We performed a comparative assessment using permeability and effective pressure data that were normalized to dimensionless forms of k/ko and P/Po. The factors and their influence on the nature of the change in permeability from the reservoir pressure were determined. Depending on the type of rock, its composition, initial permeability, and bedding conditions, we determined the limits of variation of the constants in empirical equations describing the change in the permeability of rocks from the effective pressure. The mathematical model we developed enables the prediction of the change in permeability of rocks during oil production from reservoirs on the basis of reservoir properties such as initial permeability, initial reservoir pressure, average bedding depth, net-to-gross ratio, and initial effective rock pressure.
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Zakharov, Lev A., Inna N. Ponomareva, and Dmitriy A. Martyushev. "Digital graphic monitoring of energy condition of oil reservoirs." Bulletin of the Tomsk Polytechnic University Geo Assets Engineering 335, no. 5 (May 29, 2024): 131–41. http://dx.doi.org/10.18799/24131830/2024/5/4328.
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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.
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Hasan, Hiba, and Sameera Hamd-Allah. "Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test." Iraqi Geological Journal 56, no. 2A (July 31, 2023): 247–59. http://dx.doi.org/10.46717/igj.56.2a.19ms-2023-7-28.
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The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.
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Xiao, Zeng Li, Jun Bin Chen, and Wen Long Qin. "Experiment of Driving Oil by Low Frequency Hydraulic Pulse of Low Permeability Reservoirs." Applied Mechanics and Materials 675-677 (October 2014): 1490–94. http://dx.doi.org/10.4028/www.scientific.net/amm.675-677.1490.
Full textAbstract:
The fine grain, poor sorting and high cement content in low permeability reservoirs lead to poor reservoir property, low porosity and permeability and have strong damage to the reservoir .The conventional way of low permeability oil mining is mainly fracture and chemical flooding, which cost is relatively high and will cause serious irreparable damage to formation. People are in favor of physical oil production technology because it is no harm and pollution to the reservoir, more flexible to operate and it has wide range of application and low cost. By using high frequency pulse pressure servo system and ZC-type I, this paper examines the low-frequency vibration oil recovery indoor simulation test device hydraulic pulse oil displacement effect of low permeability cores. The experiment selecting the artificial core (permeability are less than 50), examines the effects of different hydraulic pulse parameters (frequency, static pressure and dynamic pressure) on low permeability core permeability and recovery factor. The results showed that only when the three parameter ,hydraulic pulse frequency, static pressure and dynamic pressure, suitably combined will greatly increase the reservoir recovery efficiency and reduce residual oil saturation.
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Liu, Kai, Daiyin Yin, and Yong Wang. "Pressure-Predicting Model for Ultralow-Permeability Reservoirs considering the Water Absorption Characteristics of Mudstone Formations." Geofluids 2020 (June 14, 2020): 1–13. http://dx.doi.org/10.1155/2020/6531254.
Full textAbstract:
The injection-production ratio of ultralow-permeability reservoirs is generally higher in the early stage of development because of the water absorption characteristics of transition layers and mudstone formations. In this paper, the water absorption characteristics of mudstone are experimentally studied, and the empirical function of the water absorption process is established. A new mathematical model of the whole lithology is established by applying the research results of mudstone water absorption characteristics. Combining the material balance method and finite difference method, the space terms in the basic differential equation are replaced by the material balance equation, and the finite difference in the time term is obtained. Then, the analytical solutions of the average pressures of the reservoir oil well area, reservoir water well area, transition layers, and mudstone formations are solved. Based on the static parameters of the reservoir in the Chaoyang Gou Oilfield of the ultralow-permeability reservoir in China, the new pressure prediction model is verified by the ideal model of numerical simulation and production data of the oil field. The experimental results show that the saturation water absorption rate of mudstone is 1.54-2.55%, and the water absorption process of mudstone cannot be described by the seepage equation of sandstone. The verification results of the numerical simulation show that the pressure of the transition layers and mudstone at the end of the water well gradually increases, while the pressure at the end of the oil well basically remains unchanged, which is consistent with the assumptions of the model. The verification results of the oilfield production data show that the water well static pressure and oil well static pressure calculated by the new model are highly consistent with the actual values, which well explains the phenomenon of the low reservoir pressure level under the condition of a high injection production ratio in an ultralow-permeability reservoir.
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Zhang, Heng, Mibang Wang, Wenqi Ke, Xiaolong Li, Shengjun Yang, and Weihua Zhu. "Study on Micro-Pressure Drive in the KKM Low-Permeability Reservoir." Processes 12, no. 3 (March 14, 2024): 571. http://dx.doi.org/10.3390/pr12030571.
Full textAbstract:
Kazakhstan has abundant resources of low-permeability oil reservoirs, among which the KKM low-permeability oil reservoir has geological reserves of 3844 × 104 t and a determined recoverable reserve of 1670 × 104 t. However, the water flooding efficiency is only 68%, and the recovery efficiency is as low as 32%. The development of the reservoir faces challenges such as water injection difficulties and low oil production from wells. In order to further improve the oil recovery rate of this reservoir, our team developed micro-pressure-driven development technology based on pressure-driven techniques by integrating theories of fluid mechanics and artificial intelligence. We also combined this with subsequent artificial lift schemes, resulting in a complete set of micro-pressure-driven process technology. The predicted results indicate that after implementing micro-pressure-driven techniques, a single well group in the KKM oilfield can achieve a daily oil production increase of 32.08 t, demonstrating a good development effect.
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Shi, Xiaoying, Huajiao Guan, Hui Zhao, Yali Jiang, Yuying Li, and Zhao Xue. "Research on improving development effect of high-saturated reservoir in the late stage of water-flooding." E3S Web of Conferences 271 (2021): 01016. http://dx.doi.org/10.1051/e3sconf/202127101016.
Full textAbstract:
High-saturated reservoir is characterized by high saturation pressure and high gas-oil ratio. The effects of water flooding are easily influenced by the formation pressure and GOR, especially at the late stage. This article presents the relationship between the reasonable pressure maintenance level and GOR as well as water cut based on the actual characteristics of high-saturated reservoir. Then, the reservoir numerical simulation method is used to analyse the influence of pressure recovery rate and water cut rise under different injection-production ratios and injection-production methods. Research results show that the pressure maintenance level of high-saturated reservoir is larger than normal reservoirs. Bigger injection-production ratio results in not only faster pressure recovery rate but also higher water cut. Cyclic injection and production method under the maximum injection rate and liquid extraction amount can enhance oil recovery rate and control water cut rise at the same time, which plays a significant role in improving the development effect of water-flooding in high-saturated reservoirs at the late stage.
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Karakas, Metin, Zachary Paul Alcorn, Fred Aminzadeh, and Arne Graue. "Pressure Measurements for Monitoring CO2 Foam Pilots." Energies 15, no. 9 (April 21, 2022): 3035. http://dx.doi.org/10.3390/en15093035.
Full textAbstract:
This study focuses on the use of pressure measurements to monitor the effectiveness of foam as a CO2 mobility control agent in oil-producing reservoirs. When it is applied optimally, foam has excellent potential to improve reservoir sweep efficiency, as well as CO2 utilization and storage, during CO2 Enhanced Oil Recovery (EOR) processes. In this study, we present part of an integrated and novel workflow involving laboratory measurements, reservoir modeling and monitoring. Using the recorded bottom-hole pressure data from a CO2 foam pilot study, we demonstrate how transient pressures could be used to monitor CO2 foam development inside the reservoir. Results from a recent CO2 foam pilot study in a heterogeneous carbonate field in Permian Basin, USA, are presented. The injection pressure was used to evaluate the development of foam during various foam injection cycles. A high-resolution radial simulator was utilized to study the effect of foam on well injectivity, as well as on CO2 mobility in the reservoir during the surfactant-alternating gas (SAG) process. Transient analysis indicated constant temperature behavior during all SAG cycles. On the other hand, differential pressures consistently increased during the surfactant injection and decreased during the subsequent CO2 injection periods. Pressure buildup during the periods of surfactant injection indicated the development of a reduced mobility zone in the reservoir. The radial model proved to be useful to assess the reservoir foam strength during this pilot study. Transient analysis revealed that the differential pressures during the SAG cycles were higher than the pressures observed during the water-alternating gas (WAG) cycle which, in turn, showed foam generation and reduced CO2 mobility in the reservoir. Although pressure data are a powerful indicator of foam strength, additional measurements may be required to describe the complex physics of in situ foam generation. In this pilot study, it appeared that the reservoir foam strength was weaker than that expected in the laboratory.
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Hassan, Omar F., and Dhefaf J. Sadiq. "New Correlation of Oil Compressibility at Pressures Below Bubble Point For Iraqi Crude Oil." Journal of Petroleum Research and Studies 1, no. 1 (May 5, 2021): 22–29. http://dx.doi.org/10.52716/jprs.v1i1.24.
Full textAbstract:
Oil compressibility represents a significant character in reservoir simulation, design of surface facilities and the analysis of well tests, specifically for systems below the bubble point pressure.
Oil compressibility is not directly measured in the laboratory. It is usually gained indirectly from experimental data recorded in PVT reports. The relative volume from the flash test is used to calculate oil compressibility at pressures above the bubble point pressure. At pressures below the bubble point, the reservoir behavior is simulated by the differential liberation test. The solution gas-oil ratio and the oil formation volume factor from the differential liberation test are employed in the estimation of oil compressibility at pressures below the bubble point pressure This paper purposes new correlation for calculating isothermal oil compressibility coefficient at and below bubble point pressure. The formulation of oil compressibility correlation is very difficult as it depends on many variables. This property is a function of many variables such as bubble point pressure, reservoir pressure, reservoir temperature, solution gas-oil ratio, oil formation volume factor, stock-tank oil gravity, specific gravity of gas and gas formation volume factor.
Standing’s (1), McCain et al. (2) and Al-Jarri's (3) correlations were submitted for testing their validity to evaluate their performance with Iraqi crude oils and to compare their results with the results of the new correlation.
The achievement of the new correlations has been done using two hundreds and nine data points from twenty PVT tests that were collected from Southern Iraqi fields. The evaluation of the previous correlations has achieved with graphical and statistical methods. These checking methods show a poor agreement between the observed and the calculated values.
The checking methods (graphical and statistical) explain that the new correlation that was achieved in this paper is suitable to calculate oil compressibility below bubble point pressure for Iraqi crude oils.
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Tanzharikov, P. A., Zh T. Turymbetova, and A. R. Tashtemirov. "IMPROVEMENT OF THE TECHNOLOGICAL PROCESS OF THE RESERVOIR PRESSURE MAINTENANCE SYSTEM." Техника ғылымдары және технология 4 (2023): 3–13. http://dx.doi.org/10.52081/tst.2023.v04.i4.021.
Full textAbstract:
When preparing Wells, the technology of pumping the produced water into the well is used to maintain pressure.from the point of view of Occupational geology, all waters in oil and gas fields are divided into different categories. Own waters, or otherwise residual waters, are pressurized waters that form in the oil and gas reservoir. This type of reservoir water is the main type of groundwater. To maintain the pressure in the oil and gas reservoir, natural (fresh or weakly mineralized) and flowing(drainage) waters, mainly in the reservoir (85%), fresh ( 10 %) and Storm (5 %) waters, can be pumped. More than 1 billion m3 of water flows into the layer, including 700-750 million m3 of fresh water. Field location projects should take into account the fact that in parallel with the growth of oil production in oil production wells, there is an increase in waterlogging, therefore, the water supply system should be designed and built taking into account the 100% utilization of all professional wastewater from Field oil treatment plants in the reservoir pressure maintenance system (CPF). The pumped water must be in harmony with the layer. The presence of mechanical impurities is sometimes associated with a violation of water stability. This can be a consequence of irreversible chemical reactions, accompanied by the ingress of solid salts from saturated solutions.
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Tang, Ying, Ruifei Wang, and Shuai Yin. "Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China." Energies 17, no. 2 (January 11, 2024): 370. http://dx.doi.org/10.3390/en17020370.
Full textAbstract:
With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.
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Wang, Haochen, Yafeng Ju, Kai Zhang, Chengcheng Liu, Hongwei Yin, Zhongzheng Wang, Zhigang Yu, Ji Qi, Yanzhong Wang, and Wenzheng Zhou. "Saturation and Pressure Prediction for Multi-Layer Irregular Reservoirs with Variable Well Patterns." Energies 16, no. 6 (March 14, 2023): 2714. http://dx.doi.org/10.3390/en16062714.
Full textAbstract:
The well pattern and boundary shape of reservoirs determine the distribution of the remaining oil distribution to a large extent, especially for small-scale reservoir blocks. However, it is difficult to replicate experiences from other reservoirs directly to predict the remaining oil distribution because of the variety of irregular boundary shapes and corresponding well patterns. Meanwhile, the regular well pattern can hardly suit irregular boundary shapes. In this paper, we propose a well placement method for undeveloped irregular reservoirs and a multi-step prediction framework to predict both oil saturation and pressure fields for any reservoir shape and well pattern. To boost the physical information of input characteristics, a feature amplification approach based on physical formulae is initially presented. Then, 3D convolution technology is employed for the first time in 3D reservoir prediction to increase the spatial information in the vertical direction of the reservoir in the input. Moreover, to complete the two-field prediction, the concept of multi-task learning is adopted for the first time, improving the rationality of the forecast. Through the loss-based ablation test, we found that the operation we adopt will increase the accuracy of prediction to some extent. By testing on both manually designed and real irregular-shape reservoirs, our method is proven to be an accurate and fast oil saturation prediction method with its prediction loss less than 0.01 and calculation time less than 10 s in the future one year.
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Poplygin, Vladimir Valerievych, Irina Sergeevna Poplygina, and Viktor Antonovich Mordvinov. "Influence of Reservoir Properties on the Velocity of Water Movement from Injection to Production Well." Energies 15, no. 20 (October 21, 2022): 7797. http://dx.doi.org/10.3390/en15207797.
Full textAbstract:
To maintain reservoir pressure, water is injected into oil reservoirs. In carbonate rock, water quickly breaks through fractures and highly permeable formations to production wells. This study analyzes the effect of the permeability, oil viscosity, pressure drop, and distance on the water velocity from an injection well to a production well. In the Tempest MORE hydrodynamic simulator (Roxar), a three-layer model of an oil reservoir was created, and water flow from an injection well to a production well was simulated with various values of the permeability, oil viscosity, and bottom hole pressure. The water velocity in the reservoir was estimated based on the mobility factor (k/µo). The results showed that at a mobility factor of less than 2 μm2/Pa s at a distance of 100 m in the reservoirs, the time of water migration from the injection well to the production well increased sharply, and at a mobility factor of more than 2 μm2/Pa s, it became shorter. An analysis of the time of water migration in fields with high-viscosity oil was conducted. The watering time turned out to be shorter than that predicted by the simulation. The permeability of the reservoir and the viscosity of the oil had the greatest influence on the water velocity. To a lesser extent, the time of water migration was affected by the distance between the wells and the difference in the bottomhole pressures. The average migration time for water with a mobility factor of more than 2 µm2/(Pa s) was 6.3 years. Based on the regression analysis of the field data, a linear equation for the time of water migration was obtained. The resulting equation makes it possible to predict the water cuts of wells and optimize oil production.
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Kamal, Ibtisam, Namam M. Salih, and Dmitriy A. Martyushev. "Correlations between Petroleum Reservoir Fluid Properties and Amount of Evolved and Dissolved Natural Gas: Case Study of Transgressive–Regressive-Sequence Sedimentary Rocks." Journal of Marine Science and Engineering 11, no. 10 (September 28, 2023): 1891. http://dx.doi.org/10.3390/jmse11101891.
Full textAbstract:
It is well recognized that PVT data are essential in oil and gas production facilities as well as in the determination of the reservoir fluid composition in reservoir engineering calculations. In the current work, the studied borehole is located in Tawke oilfield in the High Folded Zone. The structural geology and lithological facies of rocks are studied and found to comprise fine crystalline dolomite and anhydrite interbedded with claystone and dolomite. In addition, the practical PVT data of black oil from Tawke oilfield, Zakho, from reservoirs to transgressive–regressive cycles, are studied. The PVT data are investigated to derive the empirical models that rule and correlate the properties of the reservoir fluids in terms of the amount of natural gas (methane, ethane, and propane) dissolved in reservoir fluids and evolving from the wells. The characteristics of the reservoir fluid, including °API, viscosity at reservoir pressure and bubble-point pressure, reservoir pressure and temperature, gas–oil ratio (GOR), coefficient of compressibility at reservoir pressure, gross heating value, and sample depth, are correlated. The lithological part reveals that the carbonate and some clastic rock facies are conducive to enhancing natural gas adsorption. The reservoir fluid properties show adverse effects on the amount of natural gas constituents evolving from the wells, while it shows positive effects on the dissolved reservoir fluids. The estimated empirical correlations can help indicate the quantity of natural gas that is dissolved in reservoir fluids and liberated from the wells depending on the characteristics of the reservoir. In addition, they can be used in numerical simulators to predict oil well performance.
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Hu, Wen Ge, Xiang Fang Li, Xin Zhou Yang, Ke Liu Wu, and Jun Tai Shi. "Energy Control in the Depletion of Gas Condensate Reservoirs with Different Permeabilities." Advanced Materials Research 616-618 (December 2012): 796–803. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.796.
Full textAbstract:
Energy control (i. e. pressure control) has an obvious effect on development effect in the depletion of gas condensate reservoir. Phase change behavior and characteristics of the relative pemeability in gas condensate reservoirs were displayed in this paper, then pressure and condensate distribution were showed through reservoir simulation. Finally, the influence of the pressure drop on condensate distribution and condensate oil production in gas condensate reservoirs with different permeabilities was studied. Results show that: First, in high / moderate permeability gas condensate reservoirs, the pressure and the condensate blocking will extend to further reservoir, while the pressure and condensate just appear in the vicinity of wellbore in low permeability gas condensate reservoirs. Second, the influence of pressure drop on condensate distribution in high permeability gas condensate reservoirs is obvious, the condensate blocking extends with the increasing of the pressure drop, and condensate extent can be controlled by optimizing a rational pressure drop, while the influence is inconspicuous in low permeability gas condensate reservoirs. Third, the influence of pressure drop on condensate oil production in high / moderate permeability gas condensate reservoirs is conspicuous, a rational pressure drop exists, while the influence is indistinct in low permeability or tight gas condensate reservoirs, before the retrograde condensation, a low pressure drop should be adopted in a long term until the bottom hole flowing pressure drops below the dew point pressure, when the condensate blocking forms, well stimulation is advised before developing by pressure control.