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1
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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Li, Qing, Xue Lian You, Wen Xuan Hu, Jing Quan Zhu, and Zai Xing Jiang. "Major Controls on the Evolution of the Cambrian Dolomite Reservoirs in the Keping Area, Tarim Basin." Advanced Materials Research 734-737 (August 2013): 377–83. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.377.
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The Cambrian dolomite reservoir is an important target in oil and gas exploration. The Penglaiba section in the Keping area is typically examined in studies dealing with the Cambrian dolomite reservoirs of northwestern Tarim Basin. Based on sedimentological, petrographic, and geochemical data, lithofacies and fluids are identified as the major factors that control the dolomite reservoir in the study area. Lithoacies are fundamental to reservoir evolution because they provide suitable channels for dolomitization and dissolution of fluids that, in turn, facilitate the formation of high quality reservoirs. The lithofacies which could form high-quality reservoirs in the study area are: slope slip (collapse) facies, gypsum related facies, and algae dolomite facies. The sources of fluids include seawater, meteoric freshwater, diagenetic/hydrocarbon fluid, and hydrothermal fluid. These fluids lead to dolomitization, penecontemporaneous meteoric dissolution, hypergene dissolution, organic acid dissolution and hydrothermal dissolution that result in secondary porosity, and as such, they have a significant contribution to reservoir evolution.
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Miotti, Fabio, Andrea Zerilli, Paulo T. L. Menezes, João L. S. Crepaldi, and Adriano R. Viana. "A new petrophysical joint inversion workflow: Advancing on reservoir’s characterization challenges." Interpretation 6, no. 3 (August 1, 2018): SG33—SG39. http://dx.doi.org/10.1190/int-2017-0225.1.
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Reservoir characterization objectives are to understand the reservoir rocks and fluids through accurate measurements to help asset teams develop optimal production decisions. Within this framework, we develop a new workflow to perform petrophysical joint inversion (PJI) of seismic and controlled-source electromagnetic (CSEM) data to resolve for reservoirs properties. Our workflow uses the complementary information contained in seismic, CSEM, and well-log data to improve the reservoir’s description drastically. The advent of CSEM, measuring resistivity, brought the possibility of integrating multiphysics data within the characterization workflow, and it has the potential to significantly enhance the accuracy at which reservoir properties and saturation, in particular, can be determined. We determine the power of PJI in the retrieval of reservoir parameters through a case study, based on a deepwater oil field offshore Brazil in the Sergipe-Alagoas Basin, to augment the certainty with which reservoir lithology and fluid properties are constrained.
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Chen, Mei Tao, Ning Yang, and Shang Ming Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tahong Uplift Tarim Basin, Western China." Advanced Materials Research 403-408 (November 2011): 1511–16. http://dx.doi.org/10.4028/www.scientific.net/amr.403-408.1511.
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Analyzing the discovered carbonate reservoirs in the Tazhong area, Tarim Basin indicates that the development of a reservoir is controlled by subarial weathering and freshwater leaching processes, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoirs, the hydrocarbon accumulation zones in the Tazhong area are classified into four types: buried hill and palaeoweathering crust, organic buildup reef-bank, dolomite interior, and deep fluid alteration. Different types of carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift. Because of the different mechanisms of forming reservoirs in different carbonate hydrocarbon accumulation zones, the reservoir space, reservoir capability, type of reservoir and distribution of reservoirs are often different.
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Xu, Yongqiang, Linyu Liu, and Yushuang Zhu. "Characteristics of movable fluids in tight sandstone reservoir and its influencing factors: a case study of Chang 7 reservoir in the Southwestern of Ordos Basin." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 5, 2021): 3493–507. http://dx.doi.org/10.1007/s13202-021-01250-x.
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AbstractAiming at the problem of complicated occurrence and flow state of the fluid in tight sandstone reservoir, this paper takes Chang 7 reservoirs in Southwestern of Ordos Basin as an example to analyze the occurrence characteristics of movable fluids by nuclear magnetic resonance experiment, while takes a series of microscopic experiments to analyze the influencing factors of difference of movable fluids. The results show that the T2 spectrum curves of fluid-saturated samples from Chang 7 reservoirs in the study area are dominated by the unimodal shape and the left-high-peak-right-low-peak bimodal shape. After centrifugation, the T2 spectrum curves are dominated by the left-high-peak-right-low-peak bimodal shape. The average movable fluid saturation is 33.27%, and the average T2 cutoff value is 13.61 ms. The movable fluids are mainly distributed in medium and large pores, and a small amount is distributed in small pores. The occurrence characteristics of movable fluids in tight reservoirs are complex and not controlled by a single factor. The size of throats and the connectivity of pore-throat have obvious effects on the saturation of movable fluids. The small size of throats and poor connectivity of pore-throat in tight reservoirs not only restrict the fluids in micropores, but also make the fluids in macropores difficult to flow under the control of small throats. The development of clay minerals will make the pore throats smaller, more complex and have poorer connectivity, and increase the fluid seepage resistance. On the other hand, it will make the specific surface area larger, which will cause a large number of fluids adsorbed on the clay surface and difficult to flow, resulting in the reduction of movable fluid saturation.
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Ting, P. David, Birol Dindoruk, and John Ratulowski. "Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data." SPE Reservoir Evaluation & Engineering 12, no. 05 (September 2, 2009): 793–802. http://dx.doi.org/10.2118/116243-pa.
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Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27°API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.
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Lee, Ji Ho, and Kun Sang Lee. "Multiphase, Multicomponent Simulation for Flow and Transport during Polymer Flood under Various Wettability Conditions." Journal of Applied Mathematics 2013 (2013): 1–8. http://dx.doi.org/10.1155/2013/101670.
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Accurate assessment of polymer flood requires the understanding of flow and transport of fluids involved in the process under different wettability of reservoirs. Because variations in relative permeability and capillary pressure induced from different wettability control the distribution and flow of fluids in the reservoirs, the performance of polymer flood depends on reservoir wettability. A multiphase, multicomponent reservoir simulator, which covers three-dimensional fluid flow and mass transport, is used to investigate the effects of wettability on the flow process during polymer flood. Results of polymer flood are compared with those of waterflood to evaluate how much polymer flood improves the oil recovery and water-oil ratio. When polymer flood is applied to water-wet and oil-wet reservoirs, the appearance of influence is delayed for oil-wet reservoirs compared with water-wet reservoirs due to unfavorable mobility ratio. In spite of the delay, significant improvement in oil recovery is obtained for oil-wet reservoirs. With respect to water production, polymer flood leads to substantial reduction for oil-wet reservoirs compared with water-wet reservoirs. Moreover, application of polymer flood for oil-wet reservoirs extends productive period which is longer than water-wet reservoir case.
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Warnecki, Marcin, Mirosław Wojnicki, Jerzy Kuśnierczyk, and Sławomir Szuflita. "Analizy PVT jako skuteczne narzędzie w rękach inżyniera naftowego. Pobór wgłębnych próbek płynów złożowych do badań PVT." Nafta-Gaz 76, no. 11 (November 2020): 784–93. http://dx.doi.org/10.18668/ng.2020.11.03.
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The most important aspect of laboratory analysis is undoubtedly to acquire data of the highest quality. The worldwide trend of drilling into deeper reservoirs characterised by the high temperature and high pressure (HTHP) conditions makes the newly discovered reservoirs challenging because of bearing fluids with an unprecedented diversity of phase behaviour and variability of phase parameters over time. Due to the high temperature of the deep horizons constituting the reservoir rock, many individual components of the reservoir fluids are located in a region close to their critical temperatures, i.e. gas condensate (retrograde condensation region) or volatile oil. In particular, gas condensate reservoirs are challenging to analyse. They are highly prone to the errors resulting from phase behaviour testing when using samples that are incompatible with the original reservoir in-situ fluid that saturates the reservoir rock pores. Taking the representative samples of reservoir fluid is an essential requirement to obtain reliable data that can characterise such phase-variable multicomponent reservoirs. The primary purpose of hydrocarbon fluid analysis in case of new discoveries is to determine the type of reservoir fluid system. It should also be borne in mind that without a sufficiently long production process from several intervals and/or several wells, it can be challenging to classify the fluid with confidence, especially at the initial analysis stage. The paper presents issues related to sampling of the reservoir fluid (such as crude oil and natural gas) for the physical property and phase behaviour analyses (PVT), usually accompanied by chemical analyses. The importance of representativeness of the samples in performing reliable tests that have a significant impact on the hydrocarbon production was discussed. The data obtained from the PVT laboratory are widely used in economic reports concerning local, regional or finally national hydrocarbon reserves. Other applications of the PVT data include coordination of reservoir exploitation methods related to a particular fluid composition, as well as input to design requirements for the surface facilities development, and selection of the suitable technology for hydrocarbon fluid treatment prior to introduction to the market. Various techniques of downhole sampling were mentioned and characterised with an explanation of their applicability. The criteria for selection of a proper method were also presented.
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Li, Fang Fang, Sheng Lai Yang, Dan Dan Yin, Hao Chen, Hui Lu, and Xing Zhang. "Estimation of CO2-Oil Phase Equilibrium and CO2 Storage Capacity in Jilin Oil Field." Advanced Materials Research 524-527 (May 2012): 1802–6. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1802.
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The CO2EOR and Storage Project in Jilin oilfield is the first large CCS demonstration project in China for CO2geological storage into depleting oil reservoirs. It aims at enhancing the understanding of CO2EOR mechanisms, movement of CO2in the reservoir and relevant physical-chemical reactions involved in the storage process, meanwhile gaining practical experience of monitoring and verification of CO2storage technology in tight oil reservoirs. To have a better understanding of the naturally occurring and phase transformation between CO2and reservoir fluid and provide accurate data for designing an oil development plan, we must know the interactions between CO2and reservoir fluids. Hence, in the first part of this paper the CO2and reservoir fluid phase equilibrium is measured with laboratory experiment, then the collected data is used to calculate the theory and practical CO2Sequestration capacities.
10
Zhu, X., and G. A. McMechan. "Numerical simulation of seismic responses of poroelastic reservoirs using Biot theory." GEOPHYSICS 56, no. 3 (March 1991): 328–39. http://dx.doi.org/10.1190/1.1443047.
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Biot theory proSvides a framework for computing the seismic response of fluid‐saturated reservoirs. Numerical implementation by 2-D finite‐differences allows investigation of the effects of spatial variations in porosity, permeability, and fluid viscosity, on seismic displacements of the solid frame and of the fluids (oil, gas, and/or water) in the reservoir. The porosity primarily influences wave velocities; the viscosity‐to‐permeability ratio primarily influences amplitudes and attenuation. Synthetic crosswell, VSP, and surface survey seismograms for representative reservoir models contain primary and converted reflections from fluid as well as lithologic contacts, and they illustrate the distribution of information available for describing a reservoir.
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Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei, and Yu Ye. "Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China." Energy Exploration & Exploitation 36, no. 4 (February 22, 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.
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The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.
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Mehmood, Faisal, Michael Z. Hou, Jianxing Liao, Muhammad Haris, Cheng Cao, and Jiashun Luo. "Multiphase Multicomponent Numerical Modeling for Hydraulic Fracturing with N-Heptane for Efficient Stimulation in a Tight Gas Reservoir of Germany." Energies 14, no. 11 (May 26, 2021): 3111. http://dx.doi.org/10.3390/en14113111.
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Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed.
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Bon, Johannes, Hemanta Kumar Sarma, Jose Teofilo Rodrigues, and Jan Gerardus Bon. "Reservoir-Fluid Sampling Revisited - A Practical Perspective." SPE Reservoir Evaluation & Engineering 10, no. 06 (December 1, 2007): 589–96. http://dx.doi.org/10.2118/101037-pa.
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Summary Pressure/volume/temperature (PVT) fluid properties are an integral part of determining the ultimate oil recovery and characterization of a reservoir, and are a vital tool in our attempts to enhance the reservoir's productive capability. However, as the experimental procedures to obtain these are time consuming and expensive, they are often based on analyses of a few reservoir-fluid samples, which are then applied to the entire reservoir. Therefore, it is of utmost importance to ensure that representative samples are taken, as they are fundamental to the reliability and accuracy of a study. Critical to the successful sampling of a reservoir fluid is the correct employment of sampling procedures and well conditioning before and during sampling. There are two general methods of sampling—surface and subsurface sampling. However, within these, there exist different methods that can be more applicable to a particular type of reservoir fluid than to another. In addition, well conditioning can differ depending on the type of reservoir fluid. Sampling methods for each reservoir type will be discussed with an emphasis on scenarios where difficulties arise, such as near-critical reservoir fluids and saturated reservoirs. Methods, including single-phase sampling and isokinetic sampling, which have been used increasingly in the last decade, will also be discussed with some detail, as will preservation of the representatives of other components in the sample including asphaltenes, mercury, and sulfur compounds. The paper presents a discussion aimed at better understanding the methods available, concepts behind the methods, well conditioning, and problems involved in obtaining representative fluid samples. Introduction Reservoir-fluid samples are obtained for a number of reasons, includingPVT analysis for subsequent engineering calculationsDetermination of the components that exist in a particular reservoir to have an understanding of the economic value of the fluidKnowledge of the contents of certain components that exist in the reservoir fluid for further planning and future drilling programs, such as the content of sulfur compounds and carbon dioxide, and the corrosiveness of the fluid. This will have an impact on the material used for casing, tubing, and surface equipment that may be necessaryKnowledge of the fluid's ability to flow through production tubing, pipelines, and other flow lines, and possible problems that may arise because of viscosity changes because of precipitation of solids such as wax and/or of asphalteneDetermining the contaminating components that affect plant design, such as the mercury content, sulfur components, and radioactive componentsIf the saturation pressure is approximately equal to the reservoir pressure then a second phase may be present. This is particularly relevant for gas reservoirs, where further drilling may discover an oil or condensate leg. Mostly the samples are required to obtain a better knowledge of a combination of these effects; however, it must be kept in mind that often the sample is not required to resolve all of these issues.
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von Hohendorff Filho, João Carlos, and Denis José Schiozer. "Influence of well management in the development of multiple reservoir sharing production facilities." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 70. http://dx.doi.org/10.2516/ogst/2020064.
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Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells.
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Pitakbunkate, T., P. B. Balbuena, G. J. Moridis, and T. A. Blasingame. "Effect of Confinement on Pressure/Volume/Temperature Properties of Hydrocarbons in Shale Reservoirs." SPE Journal 21, no. 02 (April 14, 2016): 621–34. http://dx.doi.org/10.2118/170685-pa.
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Summary Shale reservoirs play an important role as a future energy resource of the United States. Numerous studies were performed to describe the storage and transport of hydrocarbons through ultrasmall pores in the shale reservoirs. Most of these studies were developed by modifying techniques used for conventional reservoirs. The common pore-size distribution of the shale reservoirs is approximately 1 to 20 nm and in such confined spaces that the interactions between the wall of the container (i.e., the shale and kerogen) and the contained fluids (i.e., the hydrocarbon fluids and water) may exert significant influence on the localized phase behavior. We believe this is because the orientation and distribution of fluid molecules in the confined space are different from those of the bulk fluid, causing changes in the localized thermodynamic properties. This study provides a detailed account of the changes of pressure/volume/temperature properties and phase behavior (specifically, the phase diagrams) in a synthetic shale reservoir for pure hydrocarbons (methane and ethane) and a simple methane/ethane (binary) mixture. Grand canonical Monte Carlo (GCMC) simulations are performed to study the effect of confinement on the fluid properties. A graphite slab made of two layers is used to represent kerogen in the shale reservoirs. The separation between the two layers, representing a kerogen pore, is varied from 1 to 10 nm to observe the changes of the hydrocarbon-fluid properties. In this paper, the critical properties of methane and ethane as well as the methane/ethane mixture phase diagrams in different pore sizes are derived from the GCMC simulations. In addition, the GCMC simulations are used to investigate the deviations of the fluid densities in the confined space from those of the bulk fluids at reservoir conditions. Although not investigated in this work, such deviations may indicate that significant errors for production forecasting and reserves estimation in shale reservoirs may occur if the (typical) bulk densities are used in reservoir-engineering calculations.
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Sparks, R. S. J., C. Annen, J. D. Blundy, K. V. Cashman, A. C. Rust, and M. D. Jackson. "Formation and dynamics of magma reservoirs." Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 377, no. 2139 (January 7, 2019): 20180019. http://dx.doi.org/10.1098/rsta.2018.0019.
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The emerging concept of a magma reservoir is one in which regions containing melt extend from the source of magma generation to the surface. The reservoir may contain regions of very low fraction intergranular melt, partially molten rock (mush) and melt lenses (or magma chambers) containing high melt fraction eruptible magma, as well as pockets of exsolved magmatic fluids. The various parts of the system may be separated by a sub-solidus rock or be connected and continuous. Magma reservoirs and their wall rocks span a vast array of rheological properties, covering as much as 25 orders of magnitude from high viscosity, sub-solidus crustal rocks to magmatic fluids. Time scales of processes within magma reservoirs range from very slow melt and fluid segregation within mush and magma chambers and deformation of surrounding host rocks to very rapid development of magma and fluid instability, transport and eruption. Developing a comprehensive model of these systems is a grand challenge that will require close collaboration between modellers, geophysicists, geochemists, geologists, volcanologists and petrologists. This article is part of the Theo Murphy meeting issue ‘Magma reservoir architecture and dynamics’.
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Finecountry, S. C. P., and S. Inichinbia. "Lithology and Fluid discrimination of Sody field of the Nigerian Delta." Journal of Applied Sciences and Environmental Management 24, no. 8 (September 9, 2020): 1321–27. http://dx.doi.org/10.4314/jasem.v24i8.3.
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The lithology and fluid discrimination of an onshore Sody field, of the Niger Delta was studied using gamma ray, resistivity and density logs from three wells in the field in order to evaluate the field’s reservoir properties. Two reservoir sands (RES 1 and RES 2) were delineated and identified as hydrocarbon bearing reservoirs. The petrophysical parameters calculated include total porosity, water saturation and volume of shale. The results obtained revealed that the average porosity of the reservoir sands, range from 21% to 39%, which is excellent indicator of a good quality reservoir and probably reflecting well sorted coarse grain sandstone reservoirs with minimal cementation. Water saturation is low in all the reservoirs, ranging from 2% to 32%, indicating that the proportion of void spaces occupied by water is low, and implying high hydrocarbon saturation. The crossplot discriminated the reservoirs lithologies as sand, shaly sand and shale sequences, except well Sody 2 which differentiated its lithologies as sand and shale sequences and distinguished the reservoirs’ litho-fluids into three, namely; gas, oil and brine. These results suggest that the reservoirs sand units of Sody field contain significant accumulations of hydrocarbon.
Keywords: Reservoir, porosity, net-to-gross, impedance, lithology
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Hanshi, Zhang, Jiang Guancheng, Bi Hongxun, and Zhu Kuanliang. "Research on Protecting Formation Low-Damage Workover Fluid in Low Permeability Reservoir." International Journal of Nanoscience 18, no. 06 (January 29, 2019): 1850049. http://dx.doi.org/10.1142/s0219581x18500497.
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During the workover treatment process, poorly compatible workover fluids infiltrating into reservoir could cause serious formation damage. To tackle the aformentioned issues, in this work, low-damage workover fluid was systematically studied. By investigating reservoir damage mechanisms, chemical property study, compatibility evaluation test and core flow test, we obtain three kinds of workover fluids suitable for different blocks in Nanpu oilfield. Attractively, JRYL workover fluid which contains antiswelling agents can effectively prevent water sensitivity, and the permeability recovery values of JRYL workover fluid to NP1-5 and PG2 core are 95.3% and 86.9%, respectively. JRYD workover fluid which contains antiswelling agents and anti-waterblocking agent can prevent both water sensitivity and water blocking damage, and the permeability recovery value of JRYD workover fluid to NP403X1 core is 89.4%. JRYJ workover fluid suitable for high pressure formation can prevent water sensitivity and water blocking damage, and the permeability recovery value of the JRYJ workover fluid to NP403X1 core is 95.1%. The actual field application in Nanpu oilfield indicates that these workover fluids can not only reduce the oil well recovery time after workover treatment, but also increase production recovery rate. These results display great potential to efficiently develop low permeability reservoirs.
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Yuan, Bin, Zhenzihao Zhang, and Christopher R. Clarkson. "Improved Distance-of-Investigation Model for Rate-Transient Analysis in a Heterogeneous Unconventional Reservoir With Nonstatic Properties." SPE Journal 24, no. 05 (July 2, 2019): 2362–77. http://dx.doi.org/10.2118/191698-pa.
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Summary The concept of distance of investigation (DOI) has been widely applied in rate– and pressure–transient analysis for estimating reservoir properties and for optimizing hydraulic fracturing. Despite its successful application in conventional reservoirs, significant errors arise when extending the concept to unconventional reservoirs. This work aims to clearly demonstrate such errors when using the traditional square–root–of–time model for DOI calculations in unconventional reservoirs, and to develop new models to improve the DOI calculations. In this work, the following mechanisms in unconventional reservoirs are first incorporated into the calculation of DOI: (1) pressure–dependency of rock and fluid properties; (2) continuous/discontinuous spatial variation of reservoir properties. To achieve this, pseudopressure, pseudotime, and pseudodistance are introduced to linearize the diffusivity equation. Two novel methods are developed for calculating DOI: one using the concept of continuous succession of steady states, and the other using the concept of dynamic drainage area (DDA). Both models are verified using a series of fine–grid numerical simulations. A production–data–analysis workflow using the new DOI models is proposed to analytically characterize reservoir heterogeneity and fracture properties. The new DOI models compensate for the inability of the traditional square–root–of–time model to capture spatial and temporal variations of reservoir and fluid properties. The pressure–dependency of fluids and reservoirs (i.e., fluid density, fluid viscosity, rock permeability, and rock porosity) and reservoir heterogeneities (i.e., deterioration of reservoir quality from the primary fracture to the reservoir) can significantly retard the propagation of the DOI. Another important outcome of this work is to provide a practical and analytical approach to directly estimate the spatial heterogeneity from the production history of field cases.
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Li, Long, Ying Min Li, Yu Ping Yang, and Cha Ma. "Application of Nanomaterials in Reservoir Protection." Applied Mechanics and Materials 204-208 (October 2012): 699–702. http://dx.doi.org/10.4028/www.scientific.net/amm.204-208.699.
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Nanomaterials are of great importance to improving mudcake quality, reducing lost circulation, enhancing borehole stability, and protecting reservoir. Some nanomaterials, including nanometer plugging materials, nano-sized MMH drilling fluids, nanocomposite super-short fibers, water-based film-forming drilling fluids, nano-based drilling fluid, and so on, are introduced, and all of them have significantly influence on reservoir protection. As a result, the application of nanomaterials in the field of reservoir protection is very useful for maintaining borehole stability and protecting reservoir.
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Kalla, Subhash, Sergio A. Leonardi, Daniel W. Berry, Larry D. Poore, Hemant Sahoo, Ryan A. Kudva, and Edward M. Braun. "Factors That Affect Gas-Condensate Relative Permeability." SPE Reservoir Evaluation & Engineering 18, no. 01 (December 1, 2014): 5–10. http://dx.doi.org/10.2118/173177-pa.
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Summary When the pressure in a gas-condensate reservoir falls below the dewpoint, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements were conducted on reservoir rock at a variety of conditions. The goal was to determine the sensitivity to interfacial tension (IFT) (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an IFT sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that are applicable to a specific reservoir, we conclude that laboratory measurements must be conducted at reservoir conditions with actual reservoir fluids. The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium.
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Gozalpour, F., A. Danesh, D. H. Tehrani, A. C. Todd, and B. Tohidi. "Predicting Reservoir Fluid Phase and Volumetric Behavior From Samples Contaminated With Oil-Based Mud." SPE Reservoir Evaluation & Engineering 5, no. 03 (June 1, 2002): 197–205. http://dx.doi.org/10.2118/78130-pa.
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Summary The impact of sample contamination with oil-based mud filtrate on phase behavior and properties of different types of reservoir fluids, including gas condensate and volatile oil, has been investigated. Two simple methods are used to determine the uncontaminated fluid composition from contaminated samples. The capability of the methods is demonstrated against highly contaminated samples. An equation-of-state (EOS)-based method also has been developed to predict the phase and volumetric properties of the retrieved composition. The method determines the required parameters of the EOS for the uncontaminated fluid using the developed phase-behavior models from contaminated-sample data. The method has been examined against experimental data of different types of reservoir fluids with successful results. Introduction Accurate reservoir fluid composition and properties are essential for reservoir management and development. Reliable reservoir fluid samples are therefore required; however, major challenges can render the fluid analysis limited in value. The reservoir fluid samples for pressure/volume/temperature (PVT) tests can be collected by bottomhole and/or surface sampling techniques as appropriate. During the drilling process, owing to overbalance pressure in the mud column, mud filtrate invades the formation. If an oil-based mud is used in the drilling, it can cause major difficulties in collecting high-quality formation fluid samples. Because the filtrate of oil-based drilling mud is miscible with the formation fluid, it could significantly alter the composition and phase behavior of the reservoir fluid. Even the presence of a small amount of oil-based filtrate in the collected sample could significantly affect the PVT properties of the formation fluid. Oil-based mud is used widely in the petroleum industry. Contamination with oil-based mud filtrate could affect reservoir fluid properties such as saturation pressure, formation volume factor, gas/liquid ratio, and stock-tank liquid density. Because collecting a reservoir fluid sample is expensive, and accurate reservoir fluid properties are needed in reservoir development, it is highly desirable to determine accurate composition and phase behavior for the reservoir fluid from contaminated samples. This study investigates the impact of sample contamination with oil-based mud filtrates on composition and phase behavior properties of different types of reservoir fluids, including volatile oil and gas condensate samples. The samples were purposely contaminated with a known amount of oil-based mud filtrates in the laboratory. The methods developed in this study were then applied to determine the original composition of the reservoir fluid from contaminated samples. The phase behavior of the contaminated samples was also investigated by performing constant composition expansion (CCE) tests at reservoir and surface conditions. The measured experimental data were used to tune EOSs by adjusting their parameters. The determined parameters of EOS tuned to the contaminated samples were used to calculate the parameters of EOS for the uncontaminated sample. EOS EOSs are used extensively to simulate the volumetric behavior and phase equilibrium of petroleum reservoir fluids. Among different types of EOSs, cubic EOSs have enjoyed considerable success in modeling because they are simple and give reliable results in phase equilibrium calculations. Two EOSs, the Valderrama1 modification of the Patel-Teja (VPT) EOS and a modified Peng-Robinson2 (mPR) EOS, were used in this study to perform phase equilibrium calculations. All binary interaction parameters (BIP) in the mixing rule were set to zero, and the temperature dependency of the attractive term was used as the tuning parameter to fit the measured data.3 Extended compositional analyses (up to C20+) of fluids were used in phase equilibrium calculations. The required critical properties of petroleum fractions to calculate parameters of EOS were determined by perturbation expansion correlations.4 The required boiling-point temperatures were calculated from the Riazi- Daubert5 correlation using the molecular weight and specific gravity of petroleum fractions. The Lee-Kesler6 correlation was used to calculate the accentric factor of compounds. Contaminated Reservoir Fluids Hydrocarbon-based fluids (natural or synthetic oils) are generally used in oil-based drilling muds. Because these fluids are soluble in the reservoir fluid, they can render the fluid analysis limited in value. Determination of the original fluid composition from the analysis of a contaminated sample is feasible, but isolating the properties of the reservoir fluid free from contamination is not easily accomplished. Despite the recent improvements in sampling reservoir fluids,7,8 obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Therefore, modeling techniques are required, along with the laboratory studies, to determine the composition and PVT properties of the uncontaminated fluid. We have demonstrated, as have other investigators,9,10 that an exponential relationship exists between the concentration of components in the C8+ portion of real reservoir fluids and the corresponding molecular weights. For example, if the molar concentration of single carbon number groups is plotted against their molecular weights, it will give a straight line on a semilogarithmic scale. Based on this feature of natural fluids, two methods have been developed in this study to retrieve the original composition of reservoir fluid from contaminated samples. The composition of the C8+ portion of contaminated sample is plotted against molecular weight on a semilogarithmic scale. The plotted data will show a departure from the line over the range affected by the contaminants (see Fig. 1). The concentrations of the contaminants are then skimmed from the semilog straight line, presumed to be valid for the uncontaminated reservoir fluid. The fitted line is used to determine the composition of the uncontaminated fluid. The above method, referred to as the Skimming method, gives a reliable composition of the uncontaminated fluid if the contaminant comprises a limited hydrocarbon range. MacMillan et al.11 developed a similar method. They fitted a gamma distribution function to the composition of the C7+ portion of contaminated oil samples, excluding the composition of contaminants from the datafitting procedure.
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Ziolkowski, Anton. "Multiwell imaging of reservoir fluids." Leading Edge 18, no. 12 (December 1999): 1371–76. http://dx.doi.org/10.1190/1.1438216.
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Yu, J. M., S. H. Huang, and M. Radosz. "Phase behavior of reservoir fluids." Fluid Phase Equilibria 93 (February 1994): 353–62. http://dx.doi.org/10.1016/0378-3812(94)87018-7.
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Knai, Tor Anders, and Guillaume Lescoffit. "Efficient handling of fault properties using the Juxtaposition Table Method." Geological Society, London, Special Publications 496, no. 1 (2020): 199–207. http://dx.doi.org/10.1144/sp496-2018-192.
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AbstractFaults are known to affect the way that fluids can flow in clastic oil and gas reservoirs. Fault barriers either stop fluids from passing across or they restrict and direct the fluid flow, creating static or dynamic reservoir compartments. Representing the effect of these barriers in reservoir models is key to establishing optimal plans for reservoir drainage, field development and production.Fault property modelling is challenging, however, as observations of faults in nature show a rapid and unpredictable variation in fault rock content and architecture. Fault representation in reservoir models will necessarily be a simplification, and it is important that the uncertainty ranges are captured in the input parameters. History matching also requires flexibility in order to handle a wide variety of data and observations.The Juxtaposition Table Method is a new technique that efficiently handles all relevant geological and production data in fault property modelling. The method provides a common interface that is easy to relate to for all petroleum technology disciplines, and allows a close cooperation between the geologist and reservoir engineer in the process of matching the reservoir model to observed production behaviour. Consequently, the method is well suited to handling fault property modelling in the complete life cycle of oil and gas fields, starting with geological predictions and incorporating knowledge of dynamic reservoir behaviour as production data become available.
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Xu, Peng, and Mingbiao Xu. "Damage Mechanism of Oil-Based Drilling Fluid Flow in Seepage Channels for Fractured Tight Sandstone Gas Reservoirs." Geofluids 2019 (June 26, 2019): 1–15. http://dx.doi.org/10.1155/2019/2672695.
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Oil-based drilling fluids (OBDFs) have a strong wellbore stabilization effect, but little attention has been paid to the formation damage caused by oil-based drilling fluids based on traditional knowledge, which is a problem that must be solved prior to the application of oil-based drilling fluid. For ultradeep fractured tight sandstone gas reservoirs, the reservoir damage caused by oil-based drilling fluids is worthy of additional research. In this paper, the potential damage factors of oil-based drilling fluids and fractured tight sandstone formations are analyzed theoretically and experimentally. The damage mechanism of oil-based drilling fluids for fractured tight sandstone gas reservoirs is analyzed based on the characteristics of multiphase fluids in seepage channels, the physical and chemical changes of rocks, and the rheological stability of oil-based drilling fluids. Based on the damage mechanism of oil-based drilling fluids, the key problems that must be solved during the damage control of oil-based drilling fluids are analyzed, a detailed description of formation damage characteristics is made, and how to accurately and rapidly form plugging zones is addressed. This research on damage control can provide a reference for solving the damage problems caused by oil-based drilling fluids in fractured tight sandstone gas reservoirs.
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Luo, Sheng, Jodie L. Lutkenhaus, and Hadi Nasrabadi. "Effect of Nanoscale Pore-Size Distribution on Fluid Phase Behavior of Gas-Improved Oil Recovery in Shale Reservoirs." SPE Journal 25, no. 03 (March 13, 2020): 1406–15. http://dx.doi.org/10.2118/190246-pa.
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Summary The improved oil recovery (IOR) of unconventional shale reservoirs has attracted much interest in recent years. Gas injection, such as carbon dioxide (CO2) and natural gas, is one of the most considered techniques for its sweep efficiency and effectiveness in low-permeability reservoirs. However, the uncertainties of fluid phase behavior in shale reservoirs pose a great challenge in evaluating the performance of a gas-injection operation. Shale reservoirs typically have macroscale to nanoscale pore-size distribution in the porous space. In fractures and macropores, the fluid shows bulk behavior, but in nanopores, the phase behavior is significantly altered by the confinement effect. The integrated behavior of reservoir fluids in this complex environment remains uncertain. In this study, we investigate the nanoscale pore-size-distribution effect on the phase behavior of reservoir fluids in gas injection for shale reservoirs. A case of Anadarko Basin shale oil is used. The pore-size distribution is discretized as a multiscale system with pores of specific diameters. The phase equilibria of methane injection into the multiscale system are calculated. The constant-composition expansions are simulated for oil mixed with various fractions of injected gas. It is found that fluid in nanopores becomes supercritical with injected gas, but lowering the pressure to less than the bubblepoint turns it into the subcritical state. The bubblepoint is generally lower than the bulk and the degree of deviation depends on the amount of injected gas. The modeling of confined-fluid swelling shows that fluid swelled from nanopores is predicted to contain more oil than the swelled fluid at bulk state.
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Chen, Ganglin, Gianni Matteucci, Bill Fahmy, and Chris Finn. "Spectral-decomposition response to reservoir fluids from a deepwater West Africa reservoir." GEOPHYSICS 73, no. 6 (November 2008): C23—C30. http://dx.doi.org/10.1190/1.2978337.
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We study the spectral-decomposition response to reservoir fluids from a deepwater West Africa reservoir through a systematic modeling approach. Our workflow starts from selecting the seismic data (far-angle seismic images) that show more pronounced fluid effect based on amplitude-versus-offset (AVO) analysis. Synthetic seismic forward modeling performed at the control well established the quality of the seismic well tie. Reservoir wedge modeling, spectral decomposition of the field and synthetic seismic data, and theoretical analyses were conducted to understand the spectral-decomposition responses. The reservoir fluid type is a main factor controlling the spectral response. For this deepwater reservoir, the amplitude contrast between oil sand and brine sand is higher at low frequencies [Formula: see text]. In addition, synthetic modeling can help identify the possible frequency band where the amplitude contrast between hydrocarbon sand and brine sand is higher. When properly included in a comprehensive direct-hydrocarbon-indicator (DHI)–AVO evaluation, spectral decomposition can enhance the identification of hydrocarbons.
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Yu, Xinan, Xiaoping Li, Shuoliang Wang, and Yi Luo. "A Multicomponent Thermal Fluid Numerical Simulation Method considering Formation Damage." Geofluids 2021 (January 14, 2021): 1–15. http://dx.doi.org/10.1155/2021/8845896.
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Multicomponent thermal fluid huff and puff is an innovative heavy oil development technology for heavy oil reservoirs, which has been widely used in offshore oilfields in China and has proved to be a promising method for enhancing oil recovery. Components of multicomponent thermal fluids contain many components, including carbon dioxide, nitrogen, and steam. Under high temperature and high pressure conditions, the complex physical and chemical reactions between multicomponent thermal fluids and reservoir rocks occur, which damage the pore structure and permeability of core. In this paper, the authors set up a reservoir damage experimental device, tested the formation permeability before and after the injection of multiple-component thermal fluids, and obtained the formation damage model. The multicomponent thermal fluid formation damage model is embedded in the component control equation, the finite difference method is used to discretize the control equation, and a new multielement thermal fluid numerical simulator is established. The physical simulation experiment of multicomponent thermal fluid huff and puff is carried out by using the actual sand-packed model. By comparing the experimental results with the numerical simulation results, it is proved that the new numerical simulation model considering formation damage proposed in this paper is accurate and reliable.
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Mullins, Oliver C., Julian Y. Zuo, Andrew E. Pomerantz, Julia C. Forsythe, and Kenneth Peters. "Reservoir Fluid Geodynamics: The Chemistry and Physics of Oilfield Reservoir Fluids after Trap Filling." Energy & Fuels 31, no. 12 (December 4, 2017): 13088–119. http://dx.doi.org/10.1021/acs.energyfuels.7b02945.
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Kaviany, M., and M. Reckker. "Performance of a Heat Exchanger Based on Enhanced Heat Diffusion in Fluids by Oscillation: Experiment." Journal of Heat Transfer 112, no. 1 (February 1, 1990): 56–63. http://dx.doi.org/10.1115/1.2910364.
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The results of a study on the performance of a heat exchanger that takes advantage of enhanced heat diffusion in oscillated fluids are presented. In this heat exchanger, the fluid occupies a bundle of capillary tubes that connects two reservoirs at different temperatures; a piston in each reservoir drives the oscillation. The experimental findings are compared with predictions based on the assumptions that (a) a capillary tube does not exchange heat with the neighboring tubes, (b) the pressure in the reservoirs undergoes an ideal sinusoidal motion, and (c) each reservoir has an infinite heat capacity such that the fluid entering the tubes is at a constant temperature. Good agreement has been found between the actual performance of the heat exchanger and the idealized analysis for low and high frequencies. However, around the frequency corresponding to optimum performance, i.e., where the thermal boundary layers occupy the entire cross section of the capillary tubes, agreement is only fair. The measurements show that there is a temperature variation across the bundle and that the fluid entering the tubes has a nonsteady temperature due to weak, nonuniform mixing within the reservoirs (therefore, a spatial/temporal average was taken). This lateral and temporal variation in the temperature distribution appears to be the leading cause of the difference between the experimental and predicted results. As with any heat pipe, the reduction in the resistance to heat flow in the pipe must be accompanied by a similar ease of heat flow to and away from the ends of the pipe. Therefore, the reservoir fluid dynamics is of paramount importance in these heat exchangers. Some numerical modeling of the fluid flow in the reservoirs, as well as some velocity measurements (using a laser-Doppler anemometer), are also presented.
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Wei, Shuijian, Michael V. DeAngelo, and Bob A. Hardage. "Advantages of joint interpretation of P-P and P-SV seismic data in geothermal exploration." Interpretation 2, no. 2 (May 1, 2014): SE117—SE123. http://dx.doi.org/10.1190/int-2013-0084.1.
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Conventional P-P seismic images of geothermal reservoirs are often of poor quality because P-P data tend to have a low signal-to-noise ratio across geothermal prospects. Fracture identification, fluid prediction, and imaging inside subsurface areas influenced by superheated fluids are some of the challenges facing the geothermal industry. We showed that multicomponent seismic technology is effective for addressing all of these challenges across geothermal reservoirs, even when P-P data are of low quality. Although multicomponent seismic technology has advantages in geothermal exploration, there are not many published examples of multicomponent seismic data being used to characterize geothermal reservoirs. We evaluated data examples that illustrate advantages of multicomponent seismic technology for imaging within and below zones having superheated fluids, estimating fracture attributes, analyzing reservoir trapping structures, differentiating lithologies, and predicting spatial distributions of pore fluids. All examples we tested are from the Wister geothermal field in Southern California.
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Gozalpour, Fathollah, Ali Danesh, Adrian Christopher Todd, and Bahman Tohidi. "Application of Tracers in Oil-Based Mud for Obtaining High-Quality Fluid Composition in Lean Gas/Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 10, no. 01 (February 1, 2007): 5–11. http://dx.doi.org/10.2118/94067-pa.
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Summary Oil-based drilling fluids are used extensively in drilling activities worldwide. During the drilling process, because of overbalance pressure in the mud column, the filtrate of oil-based mud invades the formation. This hydrocarbon-based filtrate mixes with the formation hydrocarbon, which can cause major difficulties in obtaining a representative reservoir-fluid sample. Despite the recent improvements in sampling, obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Depending on the type and conditions of the reservoir, the oil-based-mud filtrate is totally or partially miscible with the formation fluid. Oil-based-mud filtrate dissolves completely in reservoir oil; therefore, the captured sample contains the true reservoir oil with added filtrate. Gas condensate (lean gas condensate in particular) is often not fully miscible with mud filtrate. In this case, the mass exchange between gas condensate and mud filtrate makes the sample unrepresentative of the reservoir fluid. In this study, the impact of sample contamination with oil-based-mud filtrate on different types of reservoir fluids, including gas condensate and volatile-oil samples, is investigated. Two simple methods are suggested to retrieve the uncontaminated composition from a contaminated sample in which mud filtrate is totally dissolved in the formation fluid (i.e., reservoir-oil samples). A tracer-based technique is also developed to determine the composition of an uncontaminated reservoir-fluid sample from a sample contaminated with oil-based-mud filtrate, particularly for those cases in which the two fluids are partially miscible. The tracers are added to the drilling fluid, with the additional cost to the drilling-mud preparation being negligible. The capability of the developed techniques has been examined against deliberately contaminated reservoir-fluid samples under controlled conditions in the laboratory. The results indicate the reliability of the proposed methods. Introduction Historically, most drilling in the North Sea has used water-based muds; however, drilling certain formations with water-based muds can be difficult, primarily because of the hole instability caused by the swelling of water-absorbing rock. Problems of this type can be greatly alleviated by using mud suspended in an oil (rather than water) base. These oil-based muds also provide better lubrication and achieve significant increases in drilling progress (Davies et al. 1984). In recent years, oil-based drilling fluid has been used extensively in drilling activities in the North Sea. During the drilling process, because of overbalance pressure in the mud column, the mud filtrate invades the reservoir formation. Using an oil-based mud in the drilling, the mud filtrate can mix with the formation fluid. This can cause major difficulties in obtaining high-quality formation-fluid samples. Depending on the type and conditions of the reservoir, the mud filtrate can be totally or partially miscible with the formation fluid. This can alter the composition and phase behavior of the reservoir fluid significantly. Hence, the measured data using the collected formation-fluid samples need to be corrected for the contamination. In this study, contamination of different types of reservoir fluids with oil-based-mud filtrate, where the two fluids are partially or totally miscible, is discussed. Practical decontamination techniques are proposed to retrieve the original fluid composition from contaminated samples.
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Balogun, Adetayo S., Hossein Kazemi, Erdal Ozkan, Mohammed Al-kobaisi, and Benjamin Ramirez. "Verification and Proper Use of Water-Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs." SPE Reservoir Evaluation & Engineering 12, no. 02 (April 14, 2009): 189–99. http://dx.doi.org/10.2118/104580-pa.
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Summary Accurate calculation of multiphase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a very crucial issue. In this paper, we will present the viability of the use of a simple transfer function to accurately account for fluid exchange resulting from capillary and gravity forces between fracture and matrix in dual-porosity and dual-permeability numerical models. With this approach, fracture- and matrix-flow calculations can be decoupled and solved sequentially, improving the speed and ease of computation. In fact, the transfer-function equations can be used easily to calculate the expected oil recovery from a matrix block of any dimension without the use of a simulator or oil-recovery correlations. The study was accomplished by conducting a 3-D fine-grid simulation of a typical matrix block and comparing the results with those obtained through the use of a single-node simple transfer function for a water-oil system. This study was similar to a previous study (Alkandari 2002) we had conducted for a 1D gas-oil system. The transfer functions of this paper are specifically for the sugar-cube idealization of a matrix block, which can be extended to simulation of a match-stick idealization in reservoir modeling. The basic data required are: matrix capillary-pressure curves, densities of the flowing fluids, and matrix block dimensions. Introduction Naturally fractured reservoirs contain a significant amount of the known petroleum hydrocarbons worldwide and, hence, are an important source of energy fuels. However, the oil recovery from these reservoirs has been rather low. For example, the Circle Ridge Field in Wind River Reservation, Wyoming, has been producing for 50 years, but the oil recovery is less than 15% (Golder Associates 2004). This low level of oil recovery points to the need for accurate reservoir characterization, realistic geological modeling, and accurate flow simulation of naturally fractured reservoirs to determine the locations of bypassed oil. Reservoir simulation is the most practical method of studying flow problems in porous media when dealing with heterogeneity and the simultaneous flow of different fluids. In modeling fractured systems, a dual-porosity or dual-permeability concept typically is used to idealize the reservoir on the global scale. In the dual-porosity concept, fluids transfer between the matrix and fractures in the grid-cells while flowing through the fracture network to the wellbore. Furthermore, the bulk of the fluids are stored in the matrix. On the other hand, in the dual-permeability concept, fluids flow through the fracture network and between matrix blocks. In both the dual-porosity and dual-permeability formulations, the fractures and matrices are linked by transfer functions. The transfer functions account for fluid exchanges between both media. To understand the details of this fluid exchange, an elaborate method is used in this study to model flow in a single matrix block with fractures as boundaries. Our goal is to develop a technique to produce accurate results for use in large-scale modeling work.
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Ayala, Luis F., Turgay Ertekin, and Michael A. Adewumi. "Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multimechanistic Flow Domains." SPE Journal 11, no. 04 (December 1, 2006): 480–87. http://dx.doi.org/10.2118/94856-pa.
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Summary A multimechanistic flow environment is the result of the combined action of a Darcian flow component (the macroscopic flow of the phase caused by pressure gradients) and a Fickian-like or diffusive flow component (diffusive flow caused by molecular concentration gradients) taking place in a hydrocarbon reservoir. The present work presents the framework needed for the assessment of the impact of multimechanistic flow on systems where complex fluid behavior—such as that of retrograde gas-condensate fluids—requires the implementation of compositional reservoir simulators. Because of the complex fluid behavior nature of gas-condensate fluids, a fully-implicit (IMPISC-type) compositional model is implemented and the model is used for the study of the isothermal depletion of naturally fractured retrograde gas reservoirs. In these systems, especially those tight systems with very low permeability (k < 0.1 md), bulk fluid flow as predicted by Darcy's law might not take place despite the presence of large pressure gradients. The use of an effective diffusion coefficient in the gas phase—which accounts for the combined effect of the different diffusion mechanisms that could take place in a porous medium—and its relative contribution to fluid recovery is discussed. The compositional tracking capabilities of the model are tested, and the conditions where Fickian flow can be the major player in recovery predictions and considerably overcome the flow impairment to gas flow posed by the eventual appearance of a condensate barrier—typical of gas-condensate systems—are investigated. Finally, a mapping that defines different domains where multimechanistic flow can be expected in compositional simulators of retrograde gas-condensate reservoirs is presented. Introduction In typical natural-gas reservoirs, all hydrocarbons exist as a single free gas phase at conditions of discovery. Depending on the composition of the initial hydrocarbon mixture in place and their depletion behavior, we recognize up to three kinds of natural gas reservoirs: dry gas reservoirs, wet gas reservoirs, and retrograde gas or gas-condensate reservoirs. The latter is the richest in terms of heavy hydrocarbons, and thus it is very likely to develop a second heavier hydrocarbon phase (liquid condensate) upon isothermal depletion. This situation is illustrated by Fig. 1. In contrast, dry gases and wet gases do not undergo phase changes upon reservoir depletion, as their phase envelope's cricondentherms are found to the left of the reservoir temperature isotherm.
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Wang, Ying, Guozhi Li, Min Li, and Jing Zhang. "The Applicability of Different Fluid Media to Measure Effective Stress Coefficient for Rock Permeability." Journal of Chemistry 2015 (2015): 1–11. http://dx.doi.org/10.1155/2015/391851.
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Effective stress coefficient for permeability (ESCK) is the key parameter to evaluate the properties of reservoir stress sensitivity. So far, little studies have clarified which ESCK is correct for a certain reservoir while rock ESCK is measured differently by different fluid media. Thus, three different fluids were taken to measure a fine sandstone sample’s ESCK, respectively. As a result, the ESCK was measured to be the smallest by injecting nitrogen, the largest by injecting water, and between the two by brine. Besides, those microcharacteristics such as rock component, clay mineral content, and pore structure were further analyzed based on some microscopic experiments. Rock elastic modulus was reduced when water-sensitive clay minerals were encountered with aqua fluid media so as to enlarge the rock ESCK value. Moreover, some clay minerals reacting with water can spall and possibly block pore throats. Compared with water, brine can soften the water sensitivity; however, gas has no water sensitivity effects. Therefore, to choose which fluid medium to measure reservoir ESCK is mainly depending on its own exploitation conditions. For gas reservoirs using gas to measure ESCK is more reliable than water or brine, while using brine is more appropriate for oil reservoirs.
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Magoba, Moses, and Mimonitu Opuwari. "Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa." Journal of Petroleum Exploration and Production Technology 10, no. 2 (November 7, 2019): 783–803. http://dx.doi.org/10.1007/s13202-019-00796-1.
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Abstract The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.
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Meng, Chunfang, and Michael Fehler. "The role of geomechanical modeling in the measurement and understanding of geophysical data collected during carbon sequestration." Leading Edge 40, no. 6 (June 2021): 413–17. http://dx.doi.org/10.1190/tle40060413.1.
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As fluids are injected into a reservoir, the pore fluid pressure changes in space and time. These changes induce a mechanical response to the reservoir fractures, which in turn induces changes in stress and deformation to the surrounding rock. The changes in stress and associated deformation comprise the geomechanical response of the reservoir to the injection. This response can result in slip along faults and potentially the loss of fluid containment within a reservoir as a result of cap-rock failure. It is important to recognize that the slip along faults does not occur only due to the changes in pore pressure at the fault location; it can also be a response to poroelastic changes in stress located away from the region where pore pressure itself changes. Our goal here is to briefly describe some of the concepts of geomechanics and the coupled flow-geomechanical response of the reservoir to fluid injection. We will illustrate some of the concepts with modeling examples that help build our intuition for understanding and predicting possible responses of reservoirs to injection. It is essential to understand and apply these concepts to properly use geomechanical modeling to design geophysical acquisition geometries and to properly interpret the geophysical data acquired during fluid injection.
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Ivakhnenko, Oleksandr P., and David K. Potter. "Magnetic susceptibility of petroleum reservoir fluids." Physics and Chemistry of the Earth, Parts A/B/C 29, no. 13-14 (January 2004): 899–907. http://dx.doi.org/10.1016/j.pce.2004.06.001.
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Hirasaki, George J., Sho-Wei Lo, and Ying Zhang. "NMR properties of petroleum reservoir fluids." Magnetic Resonance Imaging 21, no. 3-4 (April 2003): 269–77. http://dx.doi.org/10.1016/s0730-725x(03)00135-8.
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Carpenter, Chris. "High-Density Brine Used in Oil-Based Completion Fluid Deployed Offshore Norway." Journal of Petroleum Technology 73, no. 03 (March 1, 2021): 67–68. http://dx.doi.org/10.2118/0321-0067-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199243, “First Use of a Newly Developed High-Density Brine in an Oil-Based Screen Running Fluid in a Multilateral Extended-Reach Well: Fluid Qualification, Formation Damage Testing, and Field Application, Offshore Norway,” by Bjarne Salmelid, Morten Strand, and Duncan Clinch, Halliburton, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19–21 February. The paper has not been peer reviewed. When used for running sand-control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid has been limited by fluid density. The complete paper discusses the design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit. Field History This new field’s well forms part of the greater Alvheim area located in the central part of the North Sea, close to the UK sector. The formations discussed present excellent reservoir characteristics but also significant drilling challenges. The intruded country rock tends to have a high shear failure gradient (SFG) combined with a relatively low fracture gradient. Furthermore, because these reservoirs are exploited using long horizontal and multilateral wells, the drilling window is relatively narrow. For the presented case, the SFG was anticipated to be 1.39 specific gravity (SG) equivalent mud weight with an equivalent circulating density limit of 1.49 SG and stretch limit of 1.53 SG. The fluid density chosen to drill the well was 1.40 SG, and the density for the screen running fluid was planned to be 1.45 SG. Fluids Qualification Laboratory Testing Matrix. An extensive laboratory test matrix was initiated for the qualification of reservoir fluids. The reservoir fluid and drill-in fluid (RDIF) qualification is not detailed in the paper, only the LSOBCF and the novel brine used to prepare this fluid. The test matrix included tests such as rheology performance, long-term stability, production screen on 275 µm screen coupons, standard fluid-loss and filter-cake repair capabilities, reservoir fluid and RDIF compatibility tests, true crystallization temperature (TCT), and corrosion rate. The ultimate test was to check for formation and completion damage performance.
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Shapiro, Serge A., Susanne Rentsch, and Elmar Rothert. "Characterization of hydraulic properties of rocks using probability of fluid-induced microearthquakes." GEOPHYSICS 70, no. 2 (March 2005): F27—F33. http://dx.doi.org/10.1190/1.1897030.
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The use of borehole fluid injections is typical for exploration and development of hydrocarbon or geothermal reservoirs. Such injections often induce small-magnitude earthquakes. The nature of processes leading to triggering of such microseismicity is still not completely understood. Here, we consider induced microseismicity, using as examples two case studies of geothermal reservoirs in crystalline rocks and one case study of a tight-gas sandstone reservoir. In all three cases, we found that the probability of induced earthquakes occurring is very well described by the relaxation law of pressure perturbation in fluids filling the pore space in rocks. This strongly supports the hypothesis of seismicity triggered by pore pressure. Moreover, this opens additional possibilities of using passive seismic monitoring to characterize hydraulic properties of rocks on the reservoir scale with high precision.
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Wang, Jiuxin, Yutian Luo, Zhengming Yang, Xinli Zhao, and Zhongkun Niu. "Research on Prediction of Movable Fluid Percentage in Unconventional Reservoir Based on Deep Learning." Applied Sciences 11, no. 8 (April 16, 2021): 3589. http://dx.doi.org/10.3390/app11083589.
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In order to improve the measurement speed and prediction accuracy of unconventional reservoir parameters, the deep neural network (DNN) is used to predict movable fluid percentage of unconventional reservoirs. The Adam optimizer is used in the DNN model to ensure the stability and accuracy of the model in the gradient descent process, and the prediction effect is compared with the back propagation neural network (BPNN), K-nearest neighbor (KNN), and support vector regression model (SVR). During network training, L2 regularization is used to avoid over-fitting and improve the generalization ability of the model. Taking nuclear magnetic resonance (NMR) T2 spectrum data of laboratory unconventional core as input features, the influence of model hyperparameters on the prediction accuracy of reservoir movable fluids is also experimentally analyzed. Experimental results show that, compared with BPNN, KNN, and SVR, the deep neural network model has a better prediction effect on movable fluid percentage of unconventional reservoirs; when the model depth is five layers, the prediction accuracy of movable fluid percentage reaches the highest value, the predicted value of the DNN model is in high agreement with the laboratory measured value. Therefore, the movable fluid percentage prediction model of unconventional oil reservoirs based on the deep neural network model can provide certain guidance for the intelligent development of the laboratory’s reservoir parameter measurement.
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Wang, X., G. L. Wang, H. N. Gan, Z. Liu, and D. W. Nan. "Hydrochemical Characteristics and Evolution of Geothermal Fluids in the Chabu High-Temperature Geothermal System, Southern Tibet." Geofluids 2018 (2018): 1–15. http://dx.doi.org/10.1155/2018/8532840.
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This study defines reasonable reservoir temperatures and cooling processes of subsurface geothermal fluids in the Chabu high-temperature geothermal system. This system lies in the south-central part of the Shenzha-Xietongmen hydrothermal active belt and develops an extensive sinter platform with various and intense hydrothermal manifestations. All the geothermal spring samples collected systematically from the sinter platform are divided into three groups by cluster analysis of major elements. Samples of group 1 and group 3 are distributed in the central part and northern periphery of the sinter platform, respectively, while samples of group 2 are scattered in the transitional zone between groups 1 and 3. The hydrochemical characteristics show that the geothermal waters of the research area have generally mixed with shallow cooler waters in reservoirs. The reasonable reservoir temperatures and the mixing processes of the subsurface geothermal fluids could be speculated by combining the hydrochemical characteristics of geothermal springs, calculated results of the chemical geothermometers, and silica-enthalpy mixing models. Contour maps are applied to measured emerging temperatures, mass flow rates, total dissolved solids of spring samples, and reasonable subsurface temperatures. They indicate that the major cooling processes of the subsurface geothermal fluids gradually transform from adiabatic boiling to conduction from the central part to the peripheral belt. The geothermal reservoir temperatures also show an increasing trend. The point with the highest reservoir temperature (256°C) appears in the east-central part of the research area, which might be the main up-flow zone. The cooling processes of the subsurface geothermal fluids in the research area can be shown on an enthalpy-chloride plot. The deep parent fluid for the Chabu geothermal field has a Cl− concentration of 290 mg/L and an enthalpy of 1550 J/g (with a water temperature of 369°C).
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Barreto, Abelardo B., Alvaro M. M. Peres, and Adolfo P. Pires. "A Variable-Rate Solution to the Nonlinear Diffusivity Gas Equation by Use of Green's-Function Method." SPE Journal 18, no. 01 (December 28, 2012): 57–68. http://dx.doi.org/10.2118/145468-pa.
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Summary The hydraulic diffusivity equation that governs the flow of compressible fluids in porous media is nonlinear. Although the gas-well test analysis by means of the pseudopressure function has become a standard field practice, the effect of viscosity and gas-compressibility variation with pressure is often neglected. Moreover, in field operations, the gas well is submitted to a variable rate production to determine well/reservoir properties and an estimation of the absolute open flow (AOF). For slightly compressible fluids, variable rate can be properly handled by superposition in time. Unfortunately, superposition cannot be casually justified for gas reservoirs because of its nonlinear behavior. In this paper, a general solution that properly accounts for both fluid property behavior and variable rate is presented. The proposed solution, which is derived from the Green's-function method by recasting the effect of the viscosity-compressibility product variation as a nonlinear source term, can handle variable gas rate for several well/reservoir geometries of practical interest. From the general solution, an analytical expression for variable-rate tests of a fully penetrating vertical well in an infinite gas reservoir is derived. This expression is applied to a synthetic data set to calculate the pressure response for a buildup test in an infinite homogeneous reservoir. The results compared with a commercial finite-difference numerical simulator show close agreement for both drawdown and buildup periods. It is also shown that the dimensionless pseudopressure converges to the slightly compressible fluid solution for long shut-in times. Thus, during those long times, Horner analysis and log-log derivative plot can be applied to obtain good estimation of reservoir parameters, as discussed previously in literature.
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Riney, T. D. "Pleasant Bayou Geopressured-Geothermal Reservoir Analysis—October 1991." Journal of Energy Resources Technology 114, no. 4 (December 1, 1992): 315–22. http://dx.doi.org/10.1115/1.2905959.
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Many sedimentary basins contain formations with pore fluids at pressures higher than hydrostatic value; these formations are called geopressured. The pore pressure is generally well in excess of hydrostatic and the fluids are saline, hot, and contain dissolved methane. The U.S. Department of Energy (DOE) has drilled and tested deep wells in the Texas-Louisiana Gulf Coast region to evaluate the geopressured-geothermal resource. Geological information for the Pleasant Bayou geopressured resource in southeast Texas is most extensive among the reservoirs tested. Testing of the DOE well (Pleasant Bayou No. 2) was conducted during 1979–1983; testing resumed in May 1988. A numerical simulator is employed to synthesize and integrate the geological information, formation rock and fluid properties data from laboratory tests, and well data from the earlier (1979–1983) and the ongoing testing (1988–1991) of the well. A reservoir simulation model has been constructed which provides a detailed match to the well test history to date.
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Knapik, Ewa, and Katarzyna Chruszcz-Lipska. "Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland." Energies 13, no. 23 (December 6, 2020): 6456. http://dx.doi.org/10.3390/en13236456.
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Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.
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Basafa, Mahsan, and Kelly Hawboldt. "Reservoir souring: sulfur chemistry in offshore oil and gas reservoir fluids." Journal of Petroleum Exploration and Production Technology 9, no. 2 (August 4, 2018): 1105–18. http://dx.doi.org/10.1007/s13202-018-0528-2.
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Lü, Xiuxiang, Weiwei Jiao, Xinyuan Zhou, Jianjiao Li, Hongfeng Yu, and Ning Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China." Energy Exploration & Exploitation 27, no. 2 (April 2009): 69–90. http://dx.doi.org/10.1260/0144-5987.27.2.69.
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Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.
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Lu, Xuefei, Fengjuan Dong, Xiaolong Wei, PengTao Wang, Na Liu, and Dazhong Ren. "Analysis of Microscopic Main Controlling Factors for Occurrence of Movable Fluid in Tight Sandstone Gas Reservoirs Based on Improved Grey Correlation Theory." Mathematical Problems in Engineering 2021 (August 20, 2021): 1–8. http://dx.doi.org/10.1155/2021/3158504.
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Tight sandstone reservoirs have the characteristics of poor physical properties, fine pore throats, and strong microheterogeneity compared with conventional reservoirs, which results in complicated movable fluid occurrence laws and difficult mining. Taking the tight sandstone gas reservoir of He 8 formation in Sulige gas field as an example, based on physical property test analysis, constant velocity mercury injection, and nuclear magnetic resonance experiments, an optimized gray correlation calculation model is established by improved gray correlation theory, which quantitatively characterizes the influence of microscopic pore structure parameters of different types of tight sandstone gas reservoirs on the occurrence of movable fluids, and the main controlling microgeological factors for the occurrence of movable fluid in tight sandstone gas reservoirs with close/similar physical properties are selected. The results show that the occurrence of movable fluid in Type I reservoirs is mainly affected by the effective pore-throat radius ratio, the saturation of mercury in the total throat, and the effective pore radius, and the occurrence of movable fluid in Type II reservoirs is mainly affected by the effective throat radius per unit volume and total throat mercury saturation and mainstream throat radius. Moreover, the occurrence state of movable fluids in Type II reservoirs is controlled by the throat radius stronger than that of Type I reservoirs. It has important guiding significance for the efficient development of tight sandstone gas reservoirs.