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1
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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Tagiyev, M. F., and I. N. Askerov. "Geologic-geochemical and modelling studies of hydrocarbon migration in the South Caspian basin." Azerbaijan Oil Industry, no. 10 (October 15, 2020): 4–15. http://dx.doi.org/10.37474/0365-8554/2020-10-4-15.
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Based on pyrolysis data an overview is given on the generative potential and maturity of individual stratigraphic units in the South Caspian sedimentary cover. Furthermore, the pyrolysis analyses indicate that the Lower Pliocene Productive Series being immature itself is likely to have received hydrocarbon charge from the underlying older strata. The present state of the art in studying hydrocarbon migration and the "source-accumulation" type relationship between source sediments and reservoired oils in the South Caspian basin are touched upon. The views of and geochemical arguments by different authors for charging the Lower Pliocene Productive Series reservoirs with hydrocarbons from the underlying Oligocene-Miocene source layers are presented. Quantitative aspects of hydrocarbon generation, fluid dynamics, and formation of anomalous temperature & pressure fields based on the results of basin modelling in Azerbaijan are considered. Based on geochemical data analysis and modelling studies, as well as honouring reports by other workers the importance and necessity of upward migration for hydrocarbon transfer from deep generation centers to reservoirs of the Productive Series are shown.
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Lobanova, Olga A., and Ilya M. Indrupskiy. "Modeling the effect of dynamic adsorption on the phase behavior of hydrocarbons in shale and tight reservoirs." Georesursy 22, no. 1 (March 30, 2020): 13–21. http://dx.doi.org/10.18599/grs.2020.1.13-21.
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It is known that in shale and tight reservoirs, adsorption significantly affects hydrocarbon reserves and the processes of their production. This fact is reflected in the methods for calculating reserves and evaluating the production potential of shale and tight deposits. To calculate the initial content of the components, multi-component adsorption models are used. The impact on hydrocarbon production is taken into account through special dynamic permeability models for shale reservoirs. According to laboratory studies, adsorption can lead to significant changes not only in volume, but also in the composition of the produced fluids and their phase behavior. Previously, this effect could not be reproduced on the basis of mathematical models. The method proposed in this article allows modeling the phase behavior of a hydrocarbon mixture taking into account the dynamic adsorption/desorption of components in the process of pressure change. The method is applicable in the simulations of multi-component (compositional) flow and PVT-modeling on real objects. The phase behavior of hydrocarbons with pressure depletion in shale reservoirs has been simulated. It is shown that the neglect of the dynamic effect of adsorption / desorption leads to significant errors in predicting the saturation pressure, as well as the dynamics of changes in the composition of the produced fluid and of hydrocarbon component recovery.
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Chen, Kai, Zhen Liu, and Jun Hui Zhang. "The Application Extension of the Four Key Controlling Factors for the Formation of Lithologic Pool in Hongliuquan Area, Qaidam Basin." Advanced Materials Research 616-618 (December 2012): 441–49. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.441.
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In order to research the application extension of the viewpoint of the four key factors controlling formation process of lithologic traps, the paper was dissected lithologic reservoir dynamically, mainly analyzing the paleo-fluid dynamics, paleo-hydrocarbon migration pathway, paleo-critical physical properties of reservoirs and paleo-sealing conditions of the traps in formation of hydrocarbon accumulation period. The results show that they recover the limited and most important factors for formation of lithologic traps and come back the formation process of lithologic traps availably, and it also can used to be evaluated low exploration basin dynamically, compositely analyzed key factors controlling formation process of lithologic traps and selected advantaged target area. The application of this methodology indicates that it could be widely used in the dynamic formation of lithologic traps and dynamical evaluation of low exploration basin in Hongliuquan area, Qaidam basin.
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Atwah, Ibrahim, Stephen Sweet, John Pantano, and Anthony Knap. "Light Hydrocarbon Geochemistry: Insight into Mississippian Crude Oil Sources from the Anadarko Basin, Oklahoma, USA." Geofluids 2019 (May 14, 2019): 1–15. http://dx.doi.org/10.1155/2019/2795017.
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The Mississippian limestone is a prolific hydrocarbon play in the northern region of Oklahoma and the southern part of Kansas. The Mississippian reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, phenols, and diamondoids in crude oils produced from Mississippian carbonate and Woodford Shale formations. A set of oil samples was examined for composition using high-performance gas-chromatography and mass-spectrometry techniques. The result shows a distinct geochemical fingerprint reflected in biomarkers such as the abundance of extended tricyclic terpanes, together with heptane star diagrams, and diamantane isomeric distributions. Such compounds are indicative of the organic matter sources and stages of thermal maturity. Phenolic compounds varied dramatically based on geographic location, with some oil samples being depleted of phenols, while others are intact. Based on crude oil compositions, two possible source rocks were identified including the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing reported. Variations in phenol concentrations reflect reservoir fluid dynamic and water interactions, in which oils with intact phenols are least affected by water-washing conversely and crude oils depleted in phenols attributed to reservoir water-washing. These geochemical parameters shed light into petroleum migration within Devonian-Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs.
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Madiba, Gislain B., and George A. McMechan. "Processing, inversion, and interpretation of a 2D seismic data set from the North Viking Graben, North Sea." GEOPHYSICS 68, no. 3 (May 2003): 837–48. http://dx.doi.org/10.1190/1.1581036.
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Simultaneous elastic impedance inversion is performed on the 2D North Viking Graben seismic data set used at the 1994 SEG workshop on amplitude variation with offset and inversion. P‐velocity (Vp), S‐velocity (Vs), density logs, and seismic data are input to the inversion. The inverted P‐impedance and S‐impedance sections are used to generate an approximate compressional‐to‐shear velocity ratio (Vp/Vs) section which, in turn, is used along with water‐filled porosity (Swv) derived from the logs from two wells, to generate fluid estimate sections. This is possible as the reservoir sands have fairly constant total porosity of approximately 28 ± 4%, so the hydrocarbon filled porosity is the total porosity minus the water‐filled porosity. To enhance the separation of lithologies and of fluid content, we map Vp/Vs into Swv using an empirical crossplot‐derived relation. This mapping expands the dynamic range of the low end of the Vp/Vs values. The different lithologies and fluids are generally well separated in the Vp/Vs–Swv domain. Potential hydrocarbon reservoirs (as calibrated by the well data) are identified throughout the seismic section and are consistent with the fluid content estimations obtained from alternative computations. The Vp/Vs–Swv plane still does not produce unique interpretation in many situations. However, the critical distinction, which is between hydrocarbon‐bearing sands and all other geologic/reservoir configurations, is defined. Swv ≤ 0.17 and Vp/Vs ≤ 1.8 are the criteria that delineate potential reservoirs in this area, with decreasing Swv indicating a higher gas/oil ratio, and decreasing Vp/Vs indicating a higher sand/shale ratio. As these criteria are locally calibrated, they appear to be valid locally; they should not be applied to other data sets, which may exhibit significantly different relationships. However, the overall procedure should be generally applicable.
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Kaufman, R. L., C. S. Kabir, B. Abdul-Rahman, R. Quttainah, H. Dashti, J. M. Pederson, and M. S. Moon. "Characterizing the Greater Burgan Field With Geochemical and Other Field Data." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 118–26. http://dx.doi.org/10.2118/62516-pa.
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Summary This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Jurassic Marrat reservoir and Cretaceous-Minagish, -Third Burgan, -Fourth Burgan, -Mauddud, and -Wara reservoirs. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity, sulfur, and pressure-volume-temperature (PVT) measurements. From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft-long hydrocarbon column which extends across the Burgan and Wara reservoirs. Oil composition varies with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10°API near the oil/water contact to about 39°API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense. The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is, therefore, related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults which act as seals on a geologic time frame. More tentative is the identification of production time frame barriers from the fluid composition data. The oil fingerprint data have been used to distinguish oils from the major producing reservoirs and evaluate hydrocarbon continuity within the reservoirs. Introduction This article describes a geochemical study of oils from the Greater Burgan field, Kuwait. During this study, we examined the compositional variation of oils within the field to evaluate reservoir continuity. This study is part of a larger project to describe the producing characteristics of the major reservoirs in the Burgan field en route to applying the best practices in the overall reservoir management program. In Phase I of this study,1 approximately 60 oils from the Burgan, Magwa, and Ahmadi areas of the Greater Burgan field were analyzed using oil fingerprinting. The objective was to determine if oils from the Wara, Third Burgan, and Fourth Burgan reservoirs had unique oil fingerprints and to evaluate oil mixing because of wellbore communications. In Phase II, a larger suite of wells was sampled to broaden the coverage of the field, both areally and stratigraphically, as shown in Fig. 1. Even though a considerably larger number of wells were sampled in Phase II, the sampling density still remains rather coarse in this supergiant field, spanning 320 sq mile. A variety of different techniques are available for reservoir geochemistry studies.2 The principle method used in this study is whole-oil gas chromatography; sometimes referred to as oil fingerprinting. This method has been described before3 and is, therefore, summarized only briefly here. Oil samples were collected at the wellhead, at atmospheric conditions, and analyzed using capillary gas chromatography. A standard of about 200 calibrated peak heights was developed and from this about 30 standard peak height ratios were calculated. These ratios were selected based on their ability to separate the oils into uniquely different groups. Two different multivariate statistical techniques were used to analyze the chromatography data: cluster analysis and principal components analysis. Both techniques were used to identify groups of similar oils based on the peak height ratios. Petroleum is a very complex natural product whose composition is controlled by various geologic processes which occur both before and after fluid accumulation. In our geochemical studies of the Burgan field, we have used the composition of the produced oil to study the hydrocarbon connectivity of different reservoirs. Some measurements, such as oil gravity, gas/oil ratio and bubblepoint data, characterize the bulk properties of the fluid. Other measurements, such as the hydrocarbon fingerprint, are based on the molecular composition of the fluid. Both types of data are necessary to completely characterize a petroleum reservoir, but the molecular composition data are frequently a more sensitive measure of the reservoir connectivity. Where available, both types of data have been used in this study of the Burgan field. The identification of reservoir compartments, both vertical and lateral, is a necessary component of efficient reservoir appraisal and management. Reservoirs are compartmentalized when barriers to fluid flow are present which prevent fluid communication between different parts of the reservoir. Smalley and Hale have discussed the need for early identification of reservoir compartments well in advance of dynamic production measurements.4 Some barriers are effective on a geologic time scale and frequently result in separate oil pools with unique oil/water contacts and initial pressure gradients. Other barriers may become effective on a production time frame. These are typically identified only after the field is put on production. Reservoir fluid composition data have most frequently been interpreted as indicators of geologic time-frame compartments, but it may provide an early indication of production time-frame compartments in some cases. The Greater Burgan Field The Greater Burgan oil field lies within the Arabian basin in the state of Kuwait. General reviews of the geology and producing history of the field are described by Brennan,5 Kirby et al.,6 and Carman.7 The field is subdivided into the Burgan, Magwa, and Ahmadi sectors based on the presence of three structural domes as shown in Fig. 1. The boundary between the northern Magwa/Ahmadi and the Burgan sectors is the Central Graben fault complex, as shown in Fig. 2.
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Claes, Steven, Fadi H. Nader, and Souhail Youssef. "Coupled experimental/numerical workflow for assessing quantitative diagenesis and dynamic porosity/permeability evolution in calcite-cemented sandstone reservoir rocks." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 36. http://dx.doi.org/10.2516/ogst/2018027.
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Some of the world best hydrocarbon reservoirs (carbonates and siliciclastics) are also believed to be valuable for subsurface storage of CO2 and other fluids. Yet, these reservoirs are heterogeneous in terms of their mineralogy and flow properties, at varying spatial-temporal scales. Therefore, predicting the porosity and permeability (flow properties) evolution of carbonates and sandstones remains a tedious task. Diagenesis refers to the alteration of sedimentary rocks through geologic time, mainly due to rock-fluid interactions. It affects primarily the flow properties (porosity and permeability) of already heterogeneous reservoir rocks. In this project a new approach is proposed to calculate/quantify the influence of diagenetic phases (e.g. dissolution, cement plugging) on flow properties of typical sandstone reservoir rocks (Early Jurassic Luxembourg Formation). A series of laboratory experiments are performed in which diagenetic phases (e.g. pore blocking calcite cement in sandstone) are selectively leached from pre-studied samples, with the quantification of the petrophysical characteristics with and without cement to especially infer permeability evolution. Poorly and heavily calcite-cemented sandstone samples, as well as some intermediate cemented samples were used. The results show a distinctive dissolution pattern for different cementation grades and varying Representative Elementary Volumes (REVs). These conclusions have important consequences for upscaling diagenesis effects on reservoirs, and the interpretation of geochemical modelling results of diagenetic processes. The same approach can be applied on other type of cements and host-rocks, and could be improved by integrating other petrophysical analyses (e.g. petroacoustic, NMR).
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Zhou, Feng, Mattia Miorali, Evert Slob, and Xiangyun Hu. "Reservoir monitoring using borehole radars to improve oil recovery: Suggestions from 3D electromagnetic and fluid modeling." GEOPHYSICS 83, no. 2 (March 1, 2018): WB19—WB32. http://dx.doi.org/10.1190/geo2017-0212.1.
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The recently developed smart well technology allows for sectionalized production control by means of downhole inflow control valves and monitoring devices. We consider borehole radars as permanently installed downhole sensors to monitor fluid evolution in reservoirs, and it provides the possibility to support a proactive control for smart well production. To investigate the potential of borehole radar on monitoring reservoirs, we establish a 3D numerical model by coupling electromagnetic propagation and multiphase flow modeling in a bottom-water drive reservoir environment. Simulation results indicate that time-lapse downhole radar measurements can capture the evolution of water and oil distributions in the proximity (order of meters) of a production well, and reservoir imaging with an array of downhole radars successfully reconstructs the profile of a flowing water front. With the information of reservoir dynamics, a proactive control procedure with smart well production is conducted. This method observably delays the water breakthrough and extends the water-free recovery period. To assess the potential benefits that borehole radar brings to hydrocarbon recovery, three production strategies are simulated in a thin oil rim reservoir scenario, i.e., a conventional well production, a reactive production, and a combined production supported by borehole radar monitoring. Relative to the reactive strategy, the combined strategy further reduces cumulative water production by 66.89%, 1.75%, and 0.45% whereas it increases cumulative oil production by 4.76%, 0.57%, and 0.31%, in the production periods of 1 year, 5 years, and 10 years, respectively. The quantitative comparisons reflect that the combined production strategy has the capability of accelerating oil production and suppressing water production, especially in the early stage of production. We suggest that borehole radar is a promising reservoir monitoring technology, and it has the potential to improve oil recovery efficiency.
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Liang, Tianbo, Xiao Luo, Quoc Nguyen, and David DiCarlo. "Computed-Tomography Measurements of Water Block in Low-Permeability Rocks: Scaling and Remedying Production Impairment." SPE Journal 23, no. 03 (December 14, 2017): 762–71. http://dx.doi.org/10.2118/189445-pa.
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Summary Fracturing-fluid invasion into the rock matrix can generate water block that potentially reduces hydrocarbon production, especially in low-permeability reservoirs. Here, we experimentally investigate the dynamics of water block under different flow scenarios (i.e., without shut-ins) and rock permeabilities through multiple coreflood experiments. A computed-tomography (CT) scanner is used to obtain the saturation profile within the core throughout the experiment, while the overall hydrocarbon productivity is measured from the overall pressure drop across the core. On the basis of the saturation and pressure measurements, we interpret the potential physical mechanism regarding the productivity reduction from water block and its self-mitigation facilitated by the capillary imbibition. Our interpretation also matches the observed scaling with rock permeability and the optimal shut-in time.
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Arafin, Sayyadul, and S. M. Mujibur Rahman. "Dynamical Properties of Omani Crude Oils for Flow Through a Vertical Annulus and a Cylindrical Pipe." Sultan Qaboos University Journal for Science [SQUJS] 16 (December 1, 2011): 102. http://dx.doi.org/10.24200/squjs.vol16iss0pp102-117.
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We have initially investigated the temperature dependence of density and viscosity of a number of crude oils, collected from various hydrocarbon reservoirs in Oman. The measured data are then utilized to investigate the flow dynamics of these hydrocarbon fluids under gravity and applied pressures at various temperatures. We have modeled the flow of the various crude oil samples through a vertical (a) annulus and (b) cylindrical pipe - all treated within the Newtonian fluid flow approximation of a laminar flow - to investigate the flow properties of these samples. A computer program is developed so that the temperature dependence of the fluid flow distinctly separates the laminar mode from a turbulent mode with respect to Reynolds numbers within the ranges Re<2000 and Re>2000. The adopted models of the velocity profiles, mass rate of flow and viscous force on the solid surface are not novel, but the present calculations aim to specifically use the various Omani crude oil samples with various AIP values; the calculated results shed some light on the dynamics of these specific samples within Newtonian approximation. The measured physical properties and the subsequent calculations of the relevant dynamical properties might be useful for various purposes e.g. extraction and transportation of crude oils through pipes.
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Heidari, Zoya, and Carlos Torres-Verdín. "Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements." GEOPHYSICS 77, no. 6 (November 1, 2012): D209—D227. http://dx.doi.org/10.1190/geo2012-0006.1.
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Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.
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Amini, Shohreh, and Shahab Mohaghegh. "Application of Machine Learning and Artificial Intelligence in Proxy Modeling for Fluid Flow in Porous Media." Fluids 4, no. 3 (July 9, 2019): 126. http://dx.doi.org/10.3390/fluids4030126.
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Reservoir simulation models are the major tools for studying fluid flow behavior in hydrocarbon reservoirs. These models are constructed based on geological models, which are developed by integrating data from geology, geophysics, and petro-physics. As the complexity of a reservoir simulation model increases, so does the computation time. Therefore, to perform any comprehensive study which involves thousands of simulation runs, a very long period of time is required. Several efforts have been made to develop proxy models that can be used as a substitute for complex reservoir simulation models. These proxy models aim at generating the outputs of the numerical fluid flow models in a very short period of time. This research is focused on developing a proxy fluid flow model using artificial intelligence and machine learning techniques. In this work, the proxy model is developed for a real case CO2 sequestration project in which the objective is to evaluate the dynamic reservoir parameters (pressure, saturation, and CO2 mole fraction) under various CO2 injection scenarios. The data-driven model that is developed is able to generate pressure, saturation, and CO2 mole fraction throughout the reservoir with significantly less computational effort and considerably shorter period of time compared to the numerical reservoir simulation model.
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Chen, Xu, Yao Wang, and Ao Su. "Coupling Relationship between Multistage Fluid Activity and Reservoir Abnormally High-Porosity Zones in the Songtao–Baodao Region, Qiongdongnan Basin." Geofluids 2021 (May 15, 2021): 1–17. http://dx.doi.org/10.1155/2021/5598069.
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An abnormally high-porosity zone (AHPZ) is beneficial for petroleum exploration, especially for the deep tight reservoirs in a petroliferous basin. Because of lacking effective research methods, it is hard to analyze the formation process of AHPZs in different geological periods. From the perspective of the diagenetic fluid type and activity history, geochemical characteristics and fluid inclusions of diagenetic minerals were utilized to reconstruct the diagenetic fluid type and dynamic evolution. The ultimate goal is to study the genetic process of AHPZs in the Songtao–Baodao region of the Qiongdongnan basin, South China Sea. It was found that there are three sections of AHPZs at different burial depths, which are generally favorable for high-quality reservoirs. Moreover, it can be concluded that the AHPZs are closely related to multiple actions of various diagenetic fluids. The meteoric waters, organic acid, and thermal fluids facilitated the enlargement of porosity by dissolving minerals to form secondary pore spaces. The hydrocarbon fluids have positive effects on the preservation of pores by preventing cement from filling the pore space.
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Fathi, Ebrahim, Fatemeh Belyadi, and Bahiya Jabbar. "Shale Poroelastic Effects on Well Performance Analysis of Shale Gas Reservoirs." Fuels 2, no. 2 (April 19, 2021): 130–43. http://dx.doi.org/10.3390/fuels2020008.
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The effect of poroelastic properties of the shale matrix on gas storage and transport mechanisms has gained significant attention, especially during history-matching and hydrocarbon production forecasting in unconventional reservoirs. The common oil and gas industry practice in unconventional reservoir simulation is the extension of conventional reservoir simulation that ignores the dynamic behavior of matrix porosity and permeability as a function of reservoir effective net stress. This approach ignores the significant impact of the poroelastic characteristics of the shale matrix on hydrocarbon production. The poroelastic characteristics of the shale matrix highly relate to the shale matrix geomechanical properties, such as the Young’s Modulus, Poisson’s ratio, bulk modulus, sorption behavior, total organic content (TOC), mineralogy and presence of natural fractures in the multi-scale shale structure. In this study, in order to quantify the effect of the poroelasticity of the shale matrix on gas production, a multi-continuum approach was employed in which the shale matrix was divided into organic materials, inorganic materials and natural fractures. The governing equations for gas transport and storage in shale were developed from the basic fundamentals of mass and momentum conservation equations. In this case, gas transport in organics was assumed to be diffusive, while gas transport in inorganics was governed by convection. Finally, a fracture system was added to the multi-scale shale gas matrix, and the poroelastic effect of the shale matrix on transport and storage was investigated. A modified Palmer and Mansoori model (1998) was used to include the pore compression, matrix swelling/shrinkage and desorption-induced deformation of shale organic matter on the overall pore compressibility of the shale matrix. For the inorganic part of the matrix, relations between rock mechanical properties and the pore compressibility were obtained. A dual Langmuir–Henry isotherm was also used to describe the sorption behavior of shale organic materials. The coupled governing equations of gas storage and transport in the shale matrix were then solved using the implicit finite difference approach using MATLAB. For this purpose, rock and fluid properties were obtained using actual well logging and core analysis of the Marcellus gas well. The results showed the importance of the poroelastic effect on the pressure response and rate of gas recovery from the shale matrix. The effect was found to be mainly due to desorption-induced matrix deformation at an early stage. Coupling the shale matrix gas production including the poroelastic effect in history-matching the gas production from unconventional reservoirs will significantly improve engineering completion design optimization of the unconventional reservoirs by providing more accurate and robust production forecasts for each hydraulic fracture stage.
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Lee, K., G. J. Moridis, and C. A. Ehlig-Economides. "A Comprehensive Simulation Model of Kerogen Pyrolysis for the In-situ Upgrading of Oil Shales." SPE Journal 21, no. 05 (April 5, 2016): 1612–30. http://dx.doi.org/10.2118/173299-pa.
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Summary Oil shale, which is composed of abundant organic matter called kerogen, is a vast energy source. Pyrolysis of kerogen in oil shales releases recoverable hydrocarbons. Here, we describe the pyrolysis of kerogen with an in-situ upgrading process, which is applicable to the majority of oil shales. The pyrolysis is represented by six kinetic reactions resulting in 10 components and four phases. Expanding the Texas A&M Flow and Transport Simulator (FTSim), which is a variant of the TOUGH + simulator (Moridis 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media and includes physical and chemical phenomena of reservoir systems. The simulator involves a total of 15 thermophysical states and all transitions between them and computes a simultaneous solution of 11 mass- and energy-balance equations per element. The simulator solves the equations in a fully implicit manner by solving Jacobian matrix equations with the Newton-Raphson iteration method. To conduct a realistic simulation, we account for geological structure of oil-shale reservoirs and physical properties of bulk-oil shale rocks by considering phases and components in the pores. In addition, we involve interaction between fluids and porous media, diverse equations of state (EOSs) for computation of fluid properties, and numerical modeling of fractured media. We intensively reproduce the field-production data of Shell In-situ Conversion Process (ICP) implemented in the Green River formation by conducting sensitivity analyses for the diverse reservoir parameters, such as initial effective porosity of the matrix, oil-shale grade, and the spacing of the natural-fracture network. We analyze the effect of each reservoir parameter on the hydrocarbon productivity and product selectivity. The simulator provides a powerful tool to quantitatively evaluate production behavior and dynamic-system changes during in-situ upgrading of oil shales and subsequent fluid production by thoroughly describing a reservoir model, phases and components, phase behavior, phase properties, and evolution of porosity and permeability.
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Carpenter, Chris. "Static Measurements Enhance Saturation and Permeability Interpretation." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 46–47. http://dx.doi.org/10.2118/0821-0046-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202683, “Marrying the Static and Dynamic Worlds: Enhancing Saturation and Permeability Interpretation Using a Combination of Multifrequency Dielectric, Nuclear Magnetic Resonance, and Wireline Formation Testers,” by Hassan Mostafa, Ghassan Al-Jefri, SPE, and Tania Felix Menchaca, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Accurate water saturation evaluation and permeability profiling are crucial factors in determining volumetrics and productivity of multiple, stacked carbonate reservoirs offshore Abu Dhabi and derisking reservoir management. The case study presented in the complete paper illustrates how the integration of static measurements, such as dielectric dispersion and nuclear magnetic resonance (NMR) with dynamic measurements improves understanding of reservoir properties and supports more-accurate reservoir evaluation. Sampling and downhole fluid analysis (DFA) performed by wireline formation tester (WFT) identifies the fluid and rock properties in various flow units. Field Background and Challenges Optimal field development requires accurate estimations of water saturation and permeability. In this greenfield, the hydrocarbon is generally oil (medium to light) with very low asphaltene content. Overall, the reservoir quality is controlled by a combination of depositional environment, sequence stratigraphy, and diagenesis. Some reservoirs have good porosity, but reconciliation of log-based water saturation results with well-test results has been an issue. The objective in this case study was to drill a pilot hole for data gathering in a poorly characterized field location. Phase I included drilling a hole with a 55° deviation to cover all reservoirs for data gathering only, with the openhole reservoir section then being plugged and abandoned. Phase II of the plan was to sidetrack and complete the well as dual water-injector boreholes. In the reservoir section of the pilot borehole, a variety of logs was acquired for evaluation, including both logging-while-drilling and wireline measurements. While drilling, triple- combination data were acquired, consisting of gamma ray, resistivity, and nuclear logs (density neutron) along with resistivity images. The wireline-logging program was carried out in two stages to avoid differential sticking. In the first stage, the WFT was used to acquire 10 pressure points, seven points in the first reservoir and three points in the second. Two DFA stations were also recorded in Zone 1 to confirm whether the oil/water contact was deeper than expected. Logging was conducted using a high-tension wireline cable, which facilitates quicker accessibility to the openhole sections. In the second stage, multiple wireline runs were performed for the formation evaluation of the complete section, followed by the WFT pressure and fluid-sampling run on the drillpipe conveyance. Another critical challenge was to obtain accurate water saturations in the heterogeneous, minor, thin reservoirs, which are bounded by dense layers above and below and cause shoulder-bed effects. The third challenge in this well was to obtain an accurate, continuous, and representative permeability profile for the multiple reservoirs. WFT mini-drillstem test (DST) stations along with NMR logs were used to address this important requirement.
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Odumosu, Tobiloluwa B., Carlos Torres-Verdín, Jesús M. Salazar, Jun Ma, Benjamin Voss, and Gong Li Wang. "Estimation of Dry-Rock Elastic Moduli Based on the Simulation of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs." SPE Reservoir Evaluation & Engineering 12, no. 06 (September 2, 2009): 898–911. http://dx.doi.org/10.2118/109879-pa.
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Summary Reliable estimates of dry-rock elastic properties are critical to the accurate interpretation of the seismic response of hydrocarbon reservoirs. We describe a new method for estimating elastic moduli of rocks in-situ based on the simulation of mud-filtrate invasion effects on resistivity and acoustic logs. Simulations of mud-filtrate invasion account for the dynamic process of fluid displacement and mixing between mud-filtrate and hydrocarbons. The calculated spatial distributions of electrical resistivity are matched against resistivity logs by adjusting the underlying petrophysical properties. We then perform Biot-Gassmann fluid substitution on the 2D spatial distributions of fluid saturation with initial estimates of dry-bulk (kdry) modulus and shear rigidity (µdry) and a constraint of Poisson's ratio (?d) typical of the formation. This process generates 2D spatial distributions of compressional and shear-wave velocities and density. Subsequently, sonic waveforms are simulated to calculate shear-wave slowness. Initial estimates of the dry-bulk modulus are progressively adjusted using a modified Gregory-Pickett (1963) solution of Biot's (1956) equation to estimate a shear rigidity that converges to the well-log value of shear-wave slowness. The constraint on dynamic Poisson's ratio is then removed and a refined estimate of the dry-bulk modulus is obtained by both simulating the acoustic log (monopole) and matching the log-derived compressional-wave slowness. This technique leads to reliable estimates of dry-bulk moduli and shear rigidity that compare well to laboratory core measurements. Resulting dry-rock elastic properties can be used to calculate seismic compressional-wave and shear-wave velocities devoid of mud-filtrate invasion effects for further seismic-driven reservoir-characterization studies.
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Ahmed, Barzan I., and Mohammed S. Al-Jawad. "Geomechanical modelling and two-way coupling simulation for carbonate gas reservoir." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 10, 2020): 3619–48. http://dx.doi.org/10.1007/s13202-020-00965-7.
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Abstract Geomechanical modelling and simulation are introduced to accurately determine the combined effects of hydrocarbon production and changes in rock properties due to geomechanical effects. The reservoir geomechanical model is concerned with stress-related issues and rock failure in compression, shear, and tension induced by reservoir pore pressure changes due to reservoir depletion. In this paper, a rock mechanical model is constructed in geomechanical mode, and reservoir geomechanics simulations are run for a carbonate gas reservoir. The study begins with assessment of the data, construction of 1D rock mechanical models along the well trajectory, the generation of a 3D mechanical earth model, and running a 4D geomechanical simulation using a two-way coupling simulation method, followed by results analysis. A dual porosity/permeability model is coupled with a 3D geomechanical model, and iterative two-way coupling simulation is performed to understand the changes in effective stress dynamics with the decrease in reservoir pressure due to production, and therefore to identify the changes in dual-continuum media conductivity to fluid flow and field ultimate recovery. The results of analysis show an observed effect on reservoir flow behaviour of a 4% decrease in gas ultimate recovery and considerable changes in matrix contribution and fracture properties, with the geomechanical effects on the matrix visibly decreasing the gas production potential, and the effect on the natural fracture contribution is limited on gas inflow. Generally, this could be due to slip flow of gas at the media walls of micro-extension fractures, and the flow contribution and fracture conductivity is quite sufficient for the volume that the matrixes feed the fractures. Also, the geomechanical simulation results show the stability of existing faults, emphasizing that the loading on the fault is too low to induce fault slip to create fracturing, and enhanced permeability provides efficient conduit for reservoir fluid flow in reservoirs characterized by natural fractures.
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Paul, Pijush K., Mark D. Zoback, and Peter H. Hennings. "Fluid Flow in a Fractured Reservoir Using a Geomechanically Constrained Fault-Zone-Damage Model for Reservoir Simulation." SPE Reservoir Evaluation & Engineering 12, no. 04 (July 6, 2009): 562–75. http://dx.doi.org/10.2118/110542-pa.
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Summary Secondary fractures and faults associated with reservoir-scale faults affect both permeability and permeability anisotropy and hence play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in damage zones adjacent to large faults. Because there are usually inadequate data to fully incorporate damage-zone fractures and faults into reservoir-simulation models, this study uses the principles of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir-scale faults. We include geomechanical constraints in our reservoir model and propose a generalized workflow to incorporate damage zones into reservoir-simulation models more routinely. The model we propose calculates the extent of the damage zone along the fault plane by estimating the volume of rock brought to failure by the stress perturbation associated with dynamic-rupture propagation. We apply this method to a real reservoir using both field- and well-scale observations. At the rupture front, damage intensity gradually decreases as we move away from the rupture front or fault plane. In the studied reservoir, the secondary-failure planes in the damage zone are high-angle normal faults striking subparallel to the parent fault, which may affect the permeability of the reservoir in both horizontal and vertical directions. We calibrate our modeling with both outcrop and well observations from a number of studies. We show that dynamic-rupture propagation gives a reasonable first-order approximation of damage zones in terms of permeability and permeability anisotropy in order to be incorporated into reservoir simulators. Introduction Fractures and faults in reservoirs present both problems and opportunities for exploration and production. The heterogeneity and complexity of fluid-flow paths in fractured rocks make it difficult to predict how to produce a fractured reservoir optimally. It is usually not possible to fully define the geometry of the fractures and faults controlling flow, and it is difficult to integrate data from markedly different scales (i.e., seismic, well log, core) into reservoir-simulation models. A number of studies in hydrogeology and the petroleum industry have dealt with modeling fractured reservoirs (Martel and Peterson 1991; Lee et al. 2001; Long and Billaux 1987; Gringarten 1996; Matthäi et al. 2007). Various methodologies, both deterministic and stochastic, have been developed to model the effects of reservoir heterogeneity on hydrocarbon flow and recovery. The work by Smart et al. (2001), Oda (1985, 1986), Maerten et al. (2002), Bourne and Willemse (2001), and Brown and Bruhn (1998) quantifies the stress sensitivity of fractured reservoirs. Several studies (Barton et al. 1995; Townend and Zoback 2000; Wiprut and Zoback 2000) that include fracture characterizations from wellbore images and fluid conductivity from the temperature and the production logs indicate fluid flow from critically stressed fractures. Additional studies emphasize the importance and challenges of coupling geomechanics in reservoir fluid flow (Chen and Teufel 2000; Couples et al. 2003; Bourne et al. 2000). These studies found that a variety of geomechanical factors may be very significant in some of the fractured reservoirs. Secondary fractures and faults associated with large-scale faults also appear to be quite important in controlling the permeability of some reservoirs. Densely concentrated secondary fractures and faults near large faults are often referred to as damage zones, which are created at various stages of fault evolution: before faulting (Aydin and Johnson 1978; Lyakhovsky et al. 1997; Nanjo et al. 2005), during fault growth (Chinnery 1966; Cowie and Scholz 1992; Anders and Wiltschko 1994; Vermily and Scholz 1998; Pollard and Segall 1987; Reches and Lockner 1994), and during the earthquake slip events (Freund 1974; Suppe 1984; Chester and Logan 1986) along the existing faults. Lockner et al. (1992) and Vermilye and Scholz (1998) show that the damage zones from the prefaulting stage are very narrow and can be ignored for reservoir-scale faults. The damage zone formed during fault growth can be modeled using dynamic rupture propagation along a fault plane (Madariaga 1976; Kostov 1964; Virieux and Madariaga 1982; Harris and Day 1997). Damage zones caused by slip on existing faults are important, especially when faults are active in present-day stress conditions because slip creates splay fractures at the tips of the fault and extends the damage zone created during the fault-growth stage (Collettini and Sibson 2001; Faulkner et al. 2006; Lockner and Byerlee 1993; Davatzes and Aydin 2003; Myers and Aydin 2004). In this paper, we first introduce a reservoir in which there appears to be significant permeability anisotropy associated with flow parallel to large reservoir-scale faults. Next, we build a geomechanical model of the field and then discuss the relationship between fluid flow and geomechanics at well-scale fracture and fault systems. To consider what happens in the reservoir at larger scale, we use dynamic rupture modeling to theoretically predict the size and extent of damage zones associated with the reservoir-scale faults.
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Smith, G. C., M. A. Rayfield, D. R. DePledge, and R. Gupta. "THE CHINGUETTI DEEPWATER TURBIDITE FIELD, MAURITANIA: RESERVE ESTIMATION AND FIELD DEVELOPMENT USING UNCERTAINTY MANAGEMENT AND EXPERIMENTAL DESIGNS FOR MULTIPLE SCENARIO 3D MODELS." APPEA Journal 44, no. 1 (2004): 521. http://dx.doi.org/10.1071/aj03022.
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The Chinguetti Field was discovered in 2001 offshore Mauritania in 800 m of water. It comprises deepwater, mid-slope turbidite reservoirs, trapped in a dome over a salt diapir. The hydrocarbons are compartmentalised by concentric radial faults, in a low net:gross sequence, with oil mainly in channel sands. The large number of uncertain variables requires a structured approach and a rigorous assessment of the potential sub-surface scenarios. The field is of moderate size and risks in this deepwater environment need to be managed carefully.The main sub-surface uncertainties were identified by uncertainty framing and are briefly described in the paper. They include:structure;hydrocarbon contacts;fault seal;distribution of the channel systems;frequency and amalgamation of channel sands;shale drape;internal channel heterogeneity;effective pressure support;rock-fluid interaction;rock compaction;fluid composition/properties; androck properties.A statistical experimental design determined 27 scenarios should accurately model the probability distribution of reserves. A 3D model was made for each and run through the dynamic simulator to estimate economic ultimate recovery (EUR). Multivariate statistical analysis produced a response equation for EUR and the probability distribution. This is more rigorous than the standard method which produces mid, high and low case models, for which there is no adequate way to assign their probability of occurrence.
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Salazar, Jesús M., and A. Jeff Martin. "Rock quality assessment using the effect of mud-filtrate invasion on conflicting borehole resistivity measurements." GEOPHYSICS 77, no. 3 (May 1, 2012): WA65—WA78. http://dx.doi.org/10.1190/geo2011-0276.1.
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Unexpected borehole measurements are often inaccurately interpreted due to limited knowledge of the formation, particularly in tight-gas unconventional reservoirs. A novel method was applied to determine reservoir quality and the reliability of borehole array-induction resistivity measurements in a tight gas sandstone reservoir. Four exploration wells drilled with synthetic oil-based mud showed conflicting resistivity profiles. The discovery well showed a conductive invasion profile, but the appraisal wells showed resistive profiles. Simulation of oil-based mud-filtrate invasion was coupled with forward simulation and inversion of array-induction resistivity measurements to determine the difference in such resistivity profiles. Laboratory measurements on rock core and fluid samples were used to calibrate a log-based petrophysical model that was necessary to simulate the physics of fluid-flow mud-filtrate invasion. The dynamic process of invasion was simulated with a multicomponent formulation for the hydrocarbon phase and rock wettability alteration effects due to surfactants present in the mud. Simulated borehole-resistivity measurements were compared to field logs, and the rock properties were modified to secure a close agreement between simulated and field logs. The different invasion profiles corresponded to variable rock quality and mud composition. In the discovery well, good rock quality and thick surfactants in the mud caused a low mobility ratio between filtrate and native fluids, which created a water bank that moved ahead into the formation. This effect created a conductive annulus in the near-wellbore region. In turn, the deep invasion and high resistivity are due to excellent rock quality that is typical of a conventional sandstone reservoir. The shallower invasion and resistive profiles in the delineation wells suggest the tight gas sandstone reservoir we expected to find throughout the formation.
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Hyman, J. D., J. Jiménez-Martínez, H. S. Viswanathan, J. W. Carey, M. L. Porter, E. Rougier, S. Karra, et al. "Understanding hydraulic fracturing: a multi-scale problem." Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 374, no. 2078 (October 13, 2016): 20150426. http://dx.doi.org/10.1098/rsta.2015.0426.
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Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO 2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages. This article is part of the themed issue ‘Energy and the subsurface’.
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Rizzo, Pietro, Antonio Bucci, Anna Maria Sanangelantoni, Paola Iacumin, and Fulvio Celico. "Coupled Microbiological–Isotopic Approach for Studying Hydrodynamics in Deep Reservoirs: The Case of the Val d’Agri Oilfield (Southern Italy)." Water 12, no. 5 (May 22, 2020): 1483. http://dx.doi.org/10.3390/w12051483.
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The studies upstream of the petroleum industry include oil and gas geological exploration and are usually focused on geological, structural, geophysical, and modeling techniques. In this research, the application of a coupled microbiological–isotopic approach was explored to assess its potential as an adequate characterization and monitoring tool of geofluids in oilfield areas, in order to expand and refine the information acquired through more consolidated practices. The test site was selected within the Val d’Agri oilfield, where some natural hydrocarbon springs have been documented since the 19th century in the Tramutola area. Close to these springs, several tens of exploration and production wells were drilled in the first half of the 20th century. The results demonstrated the effectiveness of the proposed approach for the analysis of fluid dynamics in complex systems, such as oilfield areas, and highlighted the capacity of microbial communities to “behave” as “bio-thermometers”, that is, as indicators of the different temperatures in various subsurface compartments.
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MANICA, RAFAEL, ROGERIO DORNELLES MAESTRI, and ANA LUIZA DE OLIVEIRA BORGES. "Modelagem Física de Correntes de Turbidez: Descrição do Processo e Implicações no Estudo dos Depósitos Turbidíticos." Pesquisas em Geociências 33, no. 2 (June 29, 2006): 19. http://dx.doi.org/10.22456/1807-9806.19510.
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The turbidity currents are responsible for the formation of the major hydrocarbon reservoirs around the world; however the fundamentals of such currents, both in theory and practice, are still unexplored to exhaustion nowadays. The description of initialization, transportation and deposition mechanisms of this process is surrounded by uncertainty. These uncertainties had inspired the accomplishment of a three series of experiments, in order to investigate it using two different physicals models. It were analyzed the geometrical, dynamical and depositional features of a turbidity current attempting to match the results of physical modeling to those found in natural outcrop. Granular materials are tested and grain size ranges for simulation are evaluated. Density currents with different densities, grain sizes, fluid injection rate and volume were generated. Therefore density current evolution, current velocity, geometric features, and bed forms were registered. The results show that velocity increases for larger current densities or smaller grain sizes and that the height of the current head increases when the current density decreases. The deposition volumes present a general tendency of exponential decline; the grain size range of the deposits decreases towards the distal portion of the channel. The results also show that advancing velocity and bed forms (it was observed the successive development of planar upper flow regime surfaces, low sinuous-ripples, middle sinuous-ripples, meandering channels and linear channels) depend basically of the flow oscillations identified in the fluid injection rate. The simulations presented intended to collaborate with the understanding of the natural phenomena, relating the current behaviour (flow parameters) with the generated deposit (turbidites), as well as indicated the applicability of physical modelling on the field of deep-water sedimentation and its reliability as a tool for hydrocarbon reservoir prediction.
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Alpak, Faruk O. "Robust Fully-Implicit Coupled Multiphase-Flow and Geomechanics Simulation." SPE Journal 20, no. 06 (December 18, 2015): 1366–83. http://dx.doi.org/10.2118/172991-pa.
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Summary Material nonlinearity, boundary and arching constraints, nonuniform reservoir flows, sliding along material interfaces, or faults are among the causes of shear deformation or changes in the total stresses and the resulting stress redistribution in hydrocarbon reservoirs. Previous studies have demonstrated that shear or nonuniform deformation and stress redistribution in subsurface formations may have significant effects on reservoir fluid flows. Thus, a two-way coupled analysis is the required approach under circumstances where the shear deformation or changes in total stresses in the reservoir cannot be neglected. A coupled multiphysics simulator is developed for the dynamic modeling of multiphase thermal/compositional flow, and poroelastoplastic geomechanical deformation. The equations that govern multiphase flow in permeable media, heat transport, and poroelastoplastic geomechanics together lead to a highly nonlinear system. Finite-volume and Galerkin finite-element methods are used for the numerical solution of thermal/compositional multiphase fluid-flow and geomechanics equations on general hexahedral grids, respectively. Because of its improved stability and rapid convergence characteristics, the resulting multiphysics system of equations is solved with a fully-implicit formulation by use of an effective implementation of the Newton-Raphson method in the default mode. The coupled simulator is by design maximally modular with self-contained flow and geomechanics modules that can be operated in a two-way coupled mode with explicit-, iterative-, and fully-implicit-coupling options. The coupled-modeling system lends itself naturally not only to near-wellbore coupled flow and geomechanical deformation problems where poroplasticity may play a more prominent role, but also to reservoir-scale simulations where both poroelasticity and poroplasticity are relevant. The coupled simulator is validated against analytical solutions for simple cases, by use of published data in the open literature. Validation results demonstrate the robust, fast, and accurate predictive capabilities of the multiphysics modeling protocol.
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Romine, K. K., J. M. Durrant, D. L. Cathro, and G. Bernardel. "PETROLEUM PLAY ELEMENT PREDICTION FOR THE CRETACEOUS-TERTIARY BASIN PHASE, NORTHERN CARNARVON BASIN." APPEA Journal 37, no. 1 (1997): 315. http://dx.doi.org/10.1071/aj96020.
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A regional tectono-stratigraphic framework has been developed for the Cretaceous and Tertiary section in the Northern Carnarvon Basin. This framework places traditional observations in a new context and provides a predictive tool for determining the temporal occurrence and spatial distribution of the lithofacies play elements, that iss reservoir, source and seal.Two new, potential petroleum systems have been identified within the Barremian Muderong Shale and Albian Gearle Siltstone. These potential source rocks could be mature or maturing along a trend that parallels the Alpha Arch and Rankin Platform, and within the Exinouth Sub-basin.A favourable combination of reservoir and seal can be predicted for the early regressive part of the Creta- ceous-Tertiary basin phase (Campanian-Palaeocene). Lowstand and transgressive (within incised valleys) reservoirs are more likely to be isolated and encased in sealing shales, similar to lowstand reservoir facies deposited during the transgressive part of the basin phase, for example, the M. australis sand play.The basin analysis revealed the important role played by pre-existing Proterozoic-Palaeozoic lineaments during extension, and the subsequent impact on play elements, in particular, the distribution of reservoir, fluid migration, and trap development. During extension, the north-trending lineaments influenced the compart mentalisation of the Northern Carnarvon Basin into discrete depocentres. Relay ramp-style accommodation zones developed, linking the sub-basins, and acting as pathways for sediment input into the depocentres and, later in the basin's history, as probable hydrocarbon migration pathways. The relay accommodation zones are a dynamic part of the basin architecture, acting as a focal point for response to intraplate stresses and the creation, modification and destruction of traps and migration pathways.
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Zhu, Ziming, Chao Fang, Rui Qiao, Xiaolong Yin, and Erdal Ozkan. "Experimental and Molecular Insights on Mitigation of Hydrocarbon Sieving in Niobrara Shale by CO2 Huff ‘n’ Puff." SPE Journal 25, no. 04 (May 7, 2020): 1803–11. http://dx.doi.org/10.2118/196136-pa.
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Summary In nanoporous rocks, potential size/mobility exclusion and fluid–rock interactions in nanosized pores and pore throats can turn the rock into a semipermeable membrane, blocking or hindering the passage of certain molecules while allowing other molecules to pass freely. In this work, we conducted several experiments to investigate whether CO2 can mitigate the sieving effect on the hydrocarbon molecules flowing through Niobrara samples. Molecular dynamics (MD) simulations of adsorption equilibrium with and without CO2 were performed to help understand the trends observed in the experiments. The experimental procedure includes pumping liquid binary hydrocarbon mixtures (C10 and C17) of known compositions into Niobrara samples, collecting the effluents from the samples, and analyzing the compositions of the effluents. A specialized experimental setup that uses an in-line filter as a minicore holder was built for this investigation. Niobrara samples were cored and machined into 0.5-in. diameter and 0.7-in. length minicores. Hydrocarbon mixtures were injected into the minicores, and effluents were collected periodically and analyzed using gas chromatography (GC). After observing the sieving effect of the minicores, CO2 huff ‘n’ puff was performed at 600 psi, a pressure much lower than the miscibility pressure. CO2 was injected from the production side to soak the sample for a period, then the flow of the mixture was resumed, and effluents were analyzed using GC. Experimental results show that CO2 huff ‘n’ puff in several experiments noticeably mitigated the sieving of heavier components (C17). The observed increase in the fraction of C17 in the produced fluid can be either temporary or lasting. In most experiments, temporary increases in flow rates were also observed. MD simulation results suggest that for a calcite surface in equilibrium with a binary mixture of C10 and C17, more C17 molecules adsorb on the carbonate surface than the C10 molecules. Once CO2 molecules are added to the system, CO2 displaces C10 and C17 from calcite. Thus, the experimentally observed increase in the fraction of C17 can be attributed to the release of adsorbed C17. This study suggests that surface effects play a significant role in affecting flows and compositions of fluids in tight formations. In unconventional oil reservoirs, observed enhanced recovery from CO2 huff ‘n’ puff could be partly attributed to surface effects in addition to the recognized thermodynamic interaction mechanisms.
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Er, V., and T. Babadagli. "Miscible Interaction Between Matrix and Fracture: A Visualization and Simulation Study." SPE Reservoir Evaluation & Engineering 13, no. 01 (February 4, 2010): 109–17. http://dx.doi.org/10.2118/117579-pa.
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Summary CO2 injection has been applied in naturally fractured reservoirs (NFRs) for the purpose of enhanced oil recovery (i.e., the Wey-burn and Midale fields, Canada; the Wasson and Slaughter fields, USA; and the Bati Raman field, Turkey). The matrix part of these types of reservoirs could potentially be a good storage medium as well. Understanding the matrix/fracture interaction during this process and the dynamics of the flow in this dual-porosity system requires visual analyses. We mimicked fully miscible CO2 injection in NFRs using 2D models with a single fracture and oil (solute)/hydrocarbon solvent pairs. The focus was on the visual pore-scale analysis of miscibility interaction, breakthrough of solvent through fracture, transfer between matrix and fracture, and the dynamics of miscible displacement inside the matrix. First, matrix/fracture interaction was studied intensively using 2D glass-bead models experimentally. The model was prepared using acrylic sheets and glass beads saturated with oil as a porous medium while a narrow gap of 1-mm size containing filter paper served as a fracture. The first contact miscible solvent (pentane) was injected into the fracture, and the flow distribution was monitored using an image-acquisition and -processing system. The produced solvent and solute were continuously analyzed for compositional study. The effects of several parameters, such as flow rate, viscosity ratio (oil/solvent), and gravity, were studied. Next, the process was modeled numerically using a commercial compositional simulator, and the saturation distribution in the matrix was matched to experimental data. The key parameters in the matching process were the effective diffusion coefficients and the longitudinal and the transverse dispersivities. The diffusion coefficients were specified for each fluid, and dispersivities were assigned into gridblocks separately for the fracture and the matrix.
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Høier, Lars, and Curtis H. Whitson. "Compositional Grading—Theory and Practice." SPE Reservoir Evaluation & Engineering 4, no. 06 (December 1, 2001): 525–35. http://dx.doi.org/10.2118/74714-pa.
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Summary This paper quantifies the potential variation in composition and pressure/volume/temperature (PVT) properties with depth owing to gravity, chemical, and thermal forces. A wide range of reservoir fluid systems has been studied using all of the known published models for thermal diffusion in the nonisothermal mass-transport problem. Previous studies dealing with the combined effects of gravity and vertical thermal gradients on compositional grading have been either (1) of a theoretical nature, without examples from reservoir fluid systems, or (2) proposing one particular thermal-diffusion model, usually for a specific reservoir, without comparing the results with other thermal-diffusion models. We give a short review of gravity/nonisothermal models published to date. In particular, we show quantitative differences in the various models for a wide range of reservoir fluid systems. Solution algorithms and numerical stability problems are discussed for the nonisothermal models that require numerical discretization, unlike the exact analytical solution of the isothermal gradient problem. We discuss the problems related to fluid initialization in reservoir models of complex fluid systems. This involves the synthesis of measured sample data and theoretical models. Specific recommendations are given for interpolation and extrapolation of vertical compositional gradients. The importance of dewpoint on the estimation of a gas/oil contact (GOC) is emphasized, particularly for newly discovered reservoirs in which only gas samples are available and the reservoirs are near-saturated. Finally, we present two field case histories—one in which the isothermal gravity/chemical equilibrium model describes measured compositional gradients in a reservoir grading continuously from a rich gas condensate to a volatile oil, and another example in which the isothermal model is grossly inconsistent with measured data and convection or thermal diffusion has apparently resulted in a more-or-less constant composition over a vertical column of some 5,000 ft. Introduction Composition variation with depth can result for several reasons:Gravity segregates the heaviest components toward the bottom and lighter components like methane toward the top. [1-3]Thermal diffusion (generally) segregates the lightest components toward the bottom (i.e., toward higher temperatures) and heavier components toward the top (toward lower temperatures). [3,4]Thermally induced convection creating mixed fluid systems with more-or-less constant compositions is often associated with very high permeability or with fractured reservoirs.[5-7]Migration and equilibrium distribution of hydrocarbons is not yet complete because the times required for diffusion over distances of kilometers may be many tens of millions of years. [8]Dynamic flux of an aquifer passing by and contacting only part of a laterally extensive reservoir may create a sink for the continuous depletion of lighter components such as methane.Asphaltene precipitation (a) during migration may lead to a distribution of varying oil types in the high- and low-permeability layers in a reservoir [9] and (b) in the lower parts of a reservoir (tar mats) caused by nonideal thermodynamics and gravitational forces. [10,11]Varying distribution of hydrocarbon types (e.g., paraffin and aromatic) within the heptanes-plus fractions. [2,12]Biodegradation varying laterally and with depth may cause significant variation in, for example, H2S content and API gravity.Regional (tens to hundreds of kilometers) methane concentrations that may lead to neighboring fields having varying degrees of gas saturation (e.g., neighboring fault blocks that vary from saturated gas/oil systems to strongly undersaturated oils).Multiple source rocks migrating differentially into different layers and geological units. These conditions and others, separately or in combination, can lead to significant and seemingly uncorrelatable variations in fluid composition, both vertically and laterally. For a given reservoir, it is impossible to model numerically most of these complex phenomena because (a) we lack the necessary physical and chemical understanding of the problem, (b) boundary conditions are continuously changing and unknown, and (c) we do not have the physical property data and geological information necessary to build even the simplest physical models. One purpose of this paper is to evaluate simple 1D models of vertical compositional gradients caused by gravity, chemical, and thermal effects, with the fundamental simplifying assumption of zero component mass flux defining a stationary condition. We show that the gravitational force usually results in maximum compositional variation, while thermal diffusion tends to mitigate gravitational segregation. Published field case histories13–17 and a number of fields where we have studied vertical compositional gradients show that (a) the isothermal model describes quantitatively the compositional variation in some fields; (b) some fields show almost no compositional variation, even though the isothermal model predicts large variations; (c) a few fields have compositional variations that are larger than predicted with the isothermal model; and (d) some fields show variations in composition that are not at all similar to those predicted by zero-flux models. Another purpose of this study was to compare quantitatively the various thermal-diffusion models for a wide range of reservoir fluid systems. Such a comparison was not available, and we were unsure whether the available models showed significant differences. Finally, we wanted to give guidelines for how to use measured field data for defining initial fluid distribution, and how simple gradient models can be used to assess measured data and to extrapolate compositional trends to depths where samples are not available. Compositional Grading—Zero-Mass-Flux Model Calculating the variation of composition with depth is usually based on the assumption that all components have zero mass flux—existing in a stationary state18–21 in the absence of convection. To satisfy the condition of zero component net flux, a balance of driving forces or flux equations are used. The driving forces considered include:Chemical energy.Gravity.Thermal gradient.
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Moradi, Mojtaba. "Autonomously Controlling the Conformance of Injection-Well Fluids." Journal of Petroleum Technology 73, no. 06 (June 1, 2021): 38–40. http://dx.doi.org/10.2118/0621-0038-jpt.
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As production declines over time, the injection of fluids is required to enhance oil recovery and/or maintain the reservoir pressure. Whether applied at field startup or as a secondary recovery technique, waterflooding can boost oil recovery from less than 30% to 30–50%. The common problems associated with waterflooding include loss of injectivity, premature injector failure, and injection conformance. This can also lead to issues around insufficient voidage replacement, which can result in lower reservoir pressure and the production of fluid with a higher gas/oil ratio. In total field recovery, this ultimately means lower production and oil left untapped in the well. To remediate the issue of conformance, costly and often complex interventions and redrills were traditionally used to restore water-injection capability. Also, passive outflow-control devices have been used successfully to somewhat improve the fluid conformance from injection wells. However, they may fail in reservoirs with complex/dynamic properties including propagating/dilating fractures. Advanced Wells in Injection Wells There are a number of considerations when planning a water-injection completion, particularly around both the rock and fluid properties, as well as the credible risks that could occur, namely: - Uneven displacement of hydrocarbon - Fracture growth short-circuiting injectant-proximal wells - Fracture growth breaching caprock/basement seal - Crossflow, plugging, and solids fill Advanced completion options include deploying passive flow-control devices. For example, inflow-control devices (ICDs) are unable to react to dynamic changes in reservoir/well properties. This often requires production-logging-tool (PLT) logs, distributed temperature sensors, and/or tracers to be run and, if available, to apply the sleeve option. Alternatively, active (intelligent) completions, such as inflow-control valves, can be used, but they tend to be expensive and complicated and are limited to the number of zones. This technique also requires frequent analysis of data from the well to perform such actions. Tendeka, a global specialist in advanced completions, production solutions, and sand control, has developed FloFuse, a new and exclusively autonomous rate-limiting outflow-control device (AOCD) (Fig. 1). Using the analogy and inspiration of a home fuse box, which contains many individual fuses to control various parts of a building, the AOCD can control the excessive rate that passes through a specific section of a well, causing tripping once the threshold is reached. By almost shutting, i.e., significantly choking, the injection fluid into the fractures crossing the well, the AOCD autonomously prevents growth and excessive fluid injection into the thief/fracture zones and maintains a balanced or prescribed injection distribution. Like other flow-control valves, this device should be installed in several compartments in the injection well. Initially, devices operate as normal passive outflow control, but if the injected flow rate through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific compartment to be distributed among the neighboring compartments.
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Perez, Felipe, and Deepak Devegowda. "A Molecular Dynamics Study of Soaking During Enhanced Oil Recovery in Shale Organic Pores." SPE Journal 25, no. 02 (January 10, 2020): 832–41. http://dx.doi.org/10.2118/199879-pa.
Full textAbstract:
Summary In this work we use molecular dynamics simulations to investigate the interactions during soaking time between an organic solvent (pure ethane) initially in a microfracture and a mixture of hydrocarbons representative of a volatile oil, and other reservoir fluids such as carbon dioxide and water, originally saturating an organic pore network with a predominant pore size of 2.5 nm. We present evidence of the in-situ fractionation in liquid-rich shales and its implications in enhanced oil recovery (EOR) projects. We also discuss the behavior of the larger and heavier molecules in the fluid mixture while the solvent interacts with them. Notably, prior to solvent invasion of the pores and further mixing with the reservoir fluids, the heavier hydrocarbons in the mixture are initially adsorbed onto the pore surface and pore throats surface, partially clogging them. We show that the porous structure of kerogen and the presence of adsorbed molecules of asphaltenes and resins in the pore throats act as a molecular sieve and may be one of the reasons for the fractionation of the reservoir fluids. The differing ability of the solvent to desorb and mix with different hydrocarbon species is another reason for the fractionation occurring during soaking. Our simulations show that the production of reservoir fluids occurs due to a countercurrent diffusive flow from the organic pore network to the microfracture driven by the concentration gradient between the two regions.
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Hassan, Amjed, Mohamed Mahmoud, and Shirish Patil. "Impact of Chelating Agent Salt Type on the Enhanced Oil Recovery from Carbonate and Sandstone Reservoirs." Applied Sciences 11, no. 15 (July 31, 2021): 7109. http://dx.doi.org/10.3390/app11157109.
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In this paper, chelating agents were introduced as standalone fluids for enhancing the oil recovery from carbonate and sandstone reservoirs. Chelating agents such as glutamic acid di-acetic acid (GLDA), ethylene-diamine-tetra acetic acid (EDTA), and hydroxyl-ethylethylene-diamine-tri-acetic acid (HEDTA) were used. Chelating agents can be found in different forms such as sodium, potassium, or calcium salts. There is a significant gap in the literature about the influence of salt type on the hydrocarbon recovery from carbonate and sandstone reservoirs. In this study, the impact of the salt type of GLDA chelating agent on the oil recovery was investigated. Potassium-, sodium-, and calcium-based high-pH GLDA solutions were used. Coreflooding experiments were conducted at high-pressure high-temperature (HPHT) conditions using carbonate and sandstone cores. The used samples had porosity values of 15%–18%, and permeability values were between 10 and 75 mD. Seawater was injected as a secondary recovery process. Thereafter, a GLDA solution was injected in tertiary mode, until no more oil was recovered. In addition to the recovery experiments, the collected effluent was analyzed for cations concentrations such as calcium, magnesium, and iron. Moreover, dynamic adsorption, interfacial tension, and contact angle measurements were conducted for the different forms of GLDA chelating agent solutions. The results of this study showed that incremental oil recovery between 19% and 32% of the Original Oil in Place (OOIP) can be achieved, based on the salt type and the rock lithology. Flooding carbonate rocks with the calcium-based GLDA chelating agent yielded the highest oil recovery (32% of OOIP), followed by that with potassium-based GLDA chelating agent, and the sodium-based GLDA chelating agent yielded the lowest oil recovery. The reason behind that was the adsorption of the calcium-based GLDA on the rock surface was the highest without reducing the rock permeability, which was indicated by the contact angle, dynamic adsorption, and flooding experiments. The outcome of this study will help in maximizing the oil recovery from carbonate and sandstone reservoirs by suggesting the most suitable salt type of chelating agents.
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Hashem, M. N., E. C. Thomas, R. I. McNeil, and Oliver Mullins. "Determination of Producible Hydrocarbon Type and Oil Quality in Wells Drilled With Synthetic Oil-Based Muds." SPE Reservoir Evaluation & Engineering 2, no. 02 (April 1, 1999): 125–33. http://dx.doi.org/10.2118/55959-pa.
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Summary Determination of the type and quality of hydrocarbon fluid that can be produced from a formation prior to construction of production facilities is of equal economic importance to predicting the fluid rate and flowing pressure. We have become adept at making such estimates for formations drilled with water-based muds, using open-hole formation evaluation procedures. However, these standard open-hole methods are somewhat handicapped in wells drilled with synthetic oil-based mud because of the chemical and physical similarity between the synthetic oil-based filtrate and any producible oil that may be present. Also complicating the prediction is that in situ hydrocarbons will be miscibly displaced away from the wellbore by the invading oil-based mud filtrate, leaving little or no trace of the original hydrocarbon in the invaded zone. Thus, normal methods that sample fluids in the invaded zone will be of little use in predicting the in situ type and quality of hydrocarbons deeper in the formation. Only when we can pump significant volume of filtrate from the invaded zone to reconnect and sample the virgin fluids are we successful. However, since the in situ oil and filtrate are miscible, diffusion mixes the materials and blurs the interface; as mud filtrate is pumped from the formation into the borehole, the degree of contamination is greater than one might expect, and it is difficult to know when to stop pumping and start sampling. What level of filtrate contamination in the in situ fluid is tolerable? We propose a procedure for enhancing the value of the data derived from a particular open-hole wireline formation tester by quantitatively evaluating in real time the quality of the fluid being collected. The approach focuses on expanding the display of the spectroscopic data as a function of time on a more sensitive scale than has been used previously. This enhanced sensitivity allows one to confidently decide when in the pumping cycle to begin the sampling procedure. The study also utilizes laboratory determined PVT information on collected samples to form a data set that we use to correlate to the wireline derived spectroscopic data. The accuracy of these correlations has been verified with subsequent predictions and corroborated with laboratory measurements. Lastly, we provide a guideline for predicting the pump-out time needed to obtain a fluid sample of a pre-determined level of contamination when sampling conditions fall within our range of empirical data. Conclusions This empirical study validates that PVT quality hydrocarbon samples can be obtained from boreholes drilled with synthetic oil-based mud utilizing wireline formation testers deployed with downhole pump-out and optical analyzer modules. The data set for this study has the following boundary conditions: samples were obtained in the Gulf of Mexico area; the rock formations are unconsolidated to slightly consolidated, clean to slightly shaly sandstones; the in situ hydrocarbons and the synthetic oil-based mud filtrate have measurable differences in their visible and/or near infrared spectra. Specifically, this study demonstrates that during the pump-out phase of operations we can use the optical analyzer response to predict the API gravity and gas/oil ratio of the reservoir hydrocarbons prior to securing a downhole sample. Additionally, we can predict the pump out time required to obtain a reservoir sample with less than 10% mud filtrate contamination if we know or can estimate reservoir fluid viscosity and formation permeability. Extension of this method to other formations and locales should be possible using similar empirical correlation methodology. Introduction The high cost of offshore production facilities construction and deployment require accurate prediction of hydrocarbon PVT properties prior to fabrication. In the offshore Gulf of Mexico, one method to obtain a PVT quality hydrocarbon sample is to use a cased hole drill stem test. However, this procedure is usually quite costly due to the need for sand control. Shell has been an advocate of eliminating this costly step by utilizing openhole wireline test tools to obtain the PVT quality sample of the reservoir hydrocarbon. The success of this approach depends upon the availability of a wireline tool with a downhole pump that permits removal of the mud filtrate contamination prior to sampling the reservoir fluids, and a downhole fluid analyzer that can distinguish reservoir fluid from filtrate. One such tool is the Modular Formation Dynamics Tester (MDT).1 The optical fluid analyzer module of the MDT functions by subjecting the fluids being pumped to absorption spectroscopy in the visible and near-infrared (NIR) ranges. Interpretation of these spectra is the subject of this paper. Tool descriptions and basic theory of operations were presented in an earlier text.2 The concept of using visible and/or NIR spectroscopy to characterize the fluids being sampled while pumping is straightforward when there are measurable differences in the spectra of the mud filtrate and the reservoir hydrocarbons. As shown in Fig. 1, there are well known areas3,4 of the NIR spectrum (800-2000 nm) that are diagnostic of water and oil. The optical fluid analyzer module (OFA) of the MDT has channels tuned at 10 locations as indicated in Fig. 1, and thus the response in channels 6, 8, and 9 can be used to discern water from hydrocarbon. Another section of the OFA is designed to detect gas by measuring reflected polarized light from the pumped fluids, but we do not discuss its operation further except to say that it is a reliable gas indicator.
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Da Prat, Giovanni, Carlos Colo, Ramon Martinez, Guillermo Cardinali, and Gustavo Conforto. "A New Approach To Evaluate Layer Productivity Before Well Completion." SPE Reservoir Evaluation & Engineering 2, no. 01 (February 1, 1999): 75–84. http://dx.doi.org/10.2118/54672-pa.
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Summary This work presents a new methodology to identify fluid in formation layers and estimate individual reservoir parameters using openhole formation testing techniques. Real-time pressure and fluid identification data are obtained from a new wireline formation testing tool. The tool's dual packer module is needed to isolate individual zones. Field cases from wells located in the San Jorge Gulf basin and in the Neuquen basin illustrate the validity of testing methodology. The reservoir permeability (vertical and horizontal) and formation damage are calculated from pressure transient analysis of buildup and interference pressure data taken from several wells. The results obtained using this technique is consistent with those obtained from testing after well completion (cased hole drillstem test). Evaluation results can be used to decide whether to complete or abandon the tested zone. Fluid type is identified in real time using an optical fluid analyzer. Evaluation of anisotropy on a productive zone scale from the vertical interference test is presented. Introduction The main objective of formation evaluation at openhole conditions is the identification and description of hydrocarbon reserves with the best degree of resolution possible to assist in deciding whether to abandon or complete the tested interval. Equally important is obtaining the reservoir pressure and reservoir parameters to compute formation permeability and transmissibility. These are usually measured using well logging and testing techniques both at open- and cased-hole conditions. However, success in identifying the correct fluid rarely exceeds 60% for reservoirs such as the one in the San Jorge Gulf basin, located in the central Patagonia region in southern Argentina, although in many cases a complete set of logs is used. This leads to completing, perforating, and testing all prospective intervals, which has proven to be an expensive evaluation and completion process. The main reason for the unpredictable results is the multilayer nature of the gross prospective producing interval. The interval thickness of interest in a typical well is between 800 and 1200 m, with approximately 40 lenticular reservoirs ranging from 1 to 10 m thick. As shown in the San Jorge Gulf basin stratigraphic sequence in Fig. 1, the upper intervals are laminated sands with a high clay content. The bottom layers are tuffaceous sands of a variable, complex lithology. The sands are highly laminated, with a variable, high water saturation. In addition, the layers are laterally discontinuous (1 to 3 km wide) and heterogeneous. The initial oil production rate is about 30 m3/d (usually obtained by fracturing) and most of the wells are produced by rod pumping. The major challenges in the San Jorge Gulf basin for the past 60 years have been to identify the potential oil layers in a multilayer system and to determine the expected production rate, reservoir permeability, and formation damage (mainly for fracture design) for each potential layer prior to completing the well or zone. Early reservoir evaluation is necessary to provide these answers and because wells are put on rod pumping, which limits the subsequent use of direct evaluation methods. Our research over the past 2 years in formation evaluation and testing techniques has focused on determining the applicability of new methods that may optimize current evaluation practices. As a result, a methodology based on application of the new-generation wireline modular formation dynamics tester (MDT) tool for evaluating layer productivity before well completion was implemented. In this paper, we present several field cases showing the independent evaluation of a given layer in a multilayer system. In these examples, formation fluid identification (besides mud and filtrate) is accomplished in real time, which assists in pressure-volume-temperature (PVT) analysis. Layer anisotropy is obtained and validated for the layer thickness scale. The values of permeability and formation damage are determined from pressure transient analysis of drawdown and buildup data obtained by isolating the layer using the tool's dual packer module. Testing time per layer is less than 1 h. Evaluation is done in real time, hence, the decision whether to abandon or complete the particular layer can be made at the wellsite. Even though the methodology presented here was applied mainly to the San Jorge Gulf Basin reservoirs, it is not limited to this basin, but it is valid for any laminated, multilayer, thick reservoir. A field case of a well completed in multilayer reservoir located in the Neuquen basin, Neuquen province, Argentina is presented to illustrate the validity of the method in a completely different formation geological environment. Formation Evaluation and Testing A typical formation evaluation and testing program in the San Jorge Gulf basin consists of running an appropriate suite of logs (usually including a conventional formation tester) to identify the layer's reserves. Openhole drillstem tests (DSTs) are also run as necessary. Completion of the well is based on the evaluation results. Casing is set, and all the prospective intervals are shot separately. Following a pressure buildup test of about 8 to 10 h duration [(TST) test], swabbing is conducted for 6 to 8 h in selected layers. The main objectives are to obtain fluid type, production rates, reservoir permeability, and formation damage (skin). These parameters are important for fracture design and equally important to define candidate zones for fracture treatments. Layer point pressures obtained with the conventional formation tester are an important measurement but limited in the case of a heterogeneous layer, such as a naturally fractured layer. The number of layers present in a well (up to 40) limits an exhaustive evaluation for economic reasons. For example, it would require a long time (days) to perform a cased hole DST for each layer present in a well. A brief summary of formation and testing evaluation limitations, based on experience, is as follows.The heterogeneous nature of the lithology usually requires conducting conventional testing on a very small vertical scale (centimeters), which limits the application of openhole DSTs.Verification of fluid identification using log techniques is usually done after a well or particular interval is completed, that is, cemented and perforated.
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Sun, Minwei, Khosrow Naderi, and Abbas Firoozabadi. "Effect of Crystal Modifiers and Dispersants on Paraffin-Wax Particles in Petroleum Fluids." SPE Journal 24, no. 01 (September 10, 2018): 32–43. http://dx.doi.org/10.2118/191365-pa.
Full textAbstract:
Summary Petroleum fluids from shale light-oil and gas/condensate reservoirs generally have a high content of normal paraffins. Paraffin-wax deposition is among the challenges in shale gas and oil production and in offshore flow assurance. Low-dosage chemical additives can be effective in paraffin-wax mitigation because of their high efficiency and economics. These additives are divided into broad categories of crystal modifiers and dispersants with vastly different molecular structures and mechanisms in wax-crystal-particle stabilization and wetting. This investigation focuses on the understanding of the differences in the aggregate size and morphology of chemical additives, and it centers on (1) wax-particle sedimentation from diluted petroleum fluids in vial tests, (2) wax-crystal-particle-size distributions and morphology by dynamic light scattering (DLS) and polarized-light microscopy, and (3) the wetting state from the effect of water. In two of the three petroleum-fluid samples used in this work, there is no visible precipitation at the bottom of the vials at temperatures below the wax-appearance temperature (WAT). The microscopic image of fluids along the length of the tube shows that the wax-particle size and intensity increase from top to bottom. To observe precipitation, we dilute the crude with a hydrocarbon such as n-heptane. The sedimentation of wax is then observed. The petroleum fluids used in this work have very low asphaltene content, and there is no complication from asphaltene precipitation. Our study shows that a small amount of crystal modifier and dispersant can reduce crystal-particle size to the submicron scale, and change the crystal morphology. We investigate the differences in the mechanisms of dispersants and crystal modifiers in bulk. Water, which is often coproduced with petroleum fluids, can increase the effectiveness of dispersants significantly by altering the wetting state of the wax-particle surface. Such enhancement is not found in crystal modifiers. Both additives affect the rheology of petroleum fluids.
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Bui, Khoa, I. Yucel Akkutlu, Andrei S. Zelenev, W. A. Hill, Christian Griman, Trudy C. Boudreaux, and James A. Silas. "Microemulsion Effects on Oil Recovery From Kerogen Using Molecular-Dynamics Simulation." SPE Journal 24, no. 06 (July 12, 2019): 2541–54. http://dx.doi.org/10.2118/191719-pa.
Full textAbstract:
Summary Source rocks contain significant volumes of hydrocarbon fluids trapped in kerogen, but effective recovery is challenged because of amplified fluid/wall interactions and the nanopore–confinement effect on the hydrocarbon–fluid composition. Enhanced oil production can be achieved by modifying the existing molecular forces in a kerogen pore network using custom–designed targeted–chemistry technologies. The objective of this paper is to show that the maturation of kerogen during catagenesis relates to the qualities of the kerogen pore network, such as pore size, shape, and connectivity, and plays an important role in the recovery of hydrocarbons. Furthermore, using molecular–dynamics (MD) simulations, we investigated how the transport of hydrocarbons in kerogen and hydrocarbon recovery can be altered with the delivery of microemulsion and surfactant micelles into the pore network. New 3D kerogen models are presented using atomistic modeling and molecular simulations. These models possess important chemical and physical characteristics of the organic matter of the source rock. A replica of Type II kerogen representative of the source rocks in the Permian Basin in the US is used for the subsequent recovery simulations. Oil–saturated kerogen is modeled as consisting of nine different types of molecules: dimethyl naphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane, and methane. The delivered microemulsion is an aqueous dispersion of solvent–swollen surfactant micelles. The solvent and nonionic surfactant present in the microemulsion are modeled as d–limonene and dodecanol heptaethyl ether (C12E7), respectively. MD simulation experiments include two stages: injection of an aqueous–phase microemulsion treatment fluid into the oil–saturated kerogen pore network, and transient flowback of the fluids in the pore network. The used 3D kerogen models were developed using a representative oil–sample composition (hydrogen, carbon, oxygen, sulfur, and nitrogen) from the region. Simulation results show that microemulsions affect the reservoir by means of two different mechanisms. First, during the injection, microemulsion droplets possess elastic properties that allow them to squeeze through inorganic pores smaller than the droplet's own diameter and to adsorb at the kerogen surfaces. The solvent dissolves in the oil phase and alters the physical and transport properties of the phase. Second, the surfactant molecules modify the wettability of the solid kerogen surfaces. Consequently, the recovery effectiveness of heavier oil fractions is improved compared with the recovery effectiveness achieved with surfactant micelles without the solubilized solvent. The results indicate that solubilized solvent and surfactant can be effectively delivered into organic–rich nanoporous formations as part of a microemulsion droplet and aid in the mobilization of the kerogen oil.
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Vargas-Silva, Diego Armando, Maika Gambús-Ordaz, and Zuly Calderón-Carrillo. "Assessment of causes of overpressure different from sub-compaction: Application in unconventional reservoir." CT&F - Ciencia, Tecnología y Futuro 9, no. 2 (November 11, 2019): 5–14. http://dx.doi.org/10.29047/01225383.177.
Full textAbstract:
The necessity for hydrocarbon-producing countries to increase their reserves has led to companies exploring the deposits available in source rocks that might be over-pressured and thus, strict rules are required for their development. Overpressure, which may result in wellbore stability problems, could result from several causes such as mechanical effects, dynamic transfer, chemical stress, thermal stress, among others, in which undercompaction is frequently the main cause, generated when the sediment deposition velocity exceeds the fluid ejection rate.The expansion of fluids generated by thermal stresses and the reduction of porosity caused by chemical stresses may be among the other causes of overpressure in shales.
The new methodology presented in this paper makes it possible to determine the pressure due to thermal stresses caused by the cracking of kerogen and oil in shales. In addition, petrophysical and geochemical models are considered in order to precisely ascertain the increase in pore pressure due to temperature andfluid expansion. An increase of 20% in pressure is seen when compared with undercompaction. As a result of this methodology, the mud window was optimized and the hydrocarbons, generated under subsurface the conditions (pressure, temperature) analyzed, were quantified.
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Katterbauer, Klemens, Ibrahim Hoteit, and Shuyu Sun. "History Matching of Electromagnetically Heated Reservoirs Incorporating Full-Wavefield Seismic and Electromagnetic Imaging." SPE Journal 20, no. 05 (October 20, 2015): 923–41. http://dx.doi.org/10.2118/173896-pa.
Full textAbstract:
Summary Electromagnetic (EM) heating is becoming a popular method for heavy-oil recovery because of its cost-efficiency and continuous technological improvements. It exploits the relationship that the viscosity of hydrocarbons decreases for increasing temperature; the heavy-oil components become more fluid-like, and hence easier to extract from the reservoir. Although several field studies have considered the effects of heating on the viscosity of the hydrocarbons, there has been very little research on the long-term effects of field production and the forecasting of the development of the reservoir. Increased flow rates within the reservoir render the moving fluids less viscous, implying fast-changing fluid-propagation patterns and increased uncertainty about the state of the oil displacement. This means, in the long term, strongly varying production projections, strong dependence on the permeability of the reservoir, and potentially undesirable fluid migration. To improve the forecasting of production in heavy-oil fields and to accurately capture the dynamics of the fluid movements, we present a history-matching framework incorporating well data and seismic and EM crosswell-imaging techniques. The incorporation of seismic and EM data into the history-matching process counteracts the changing reservoir dynamics caused by increased fluid velocity caused by heating and is shown to significantly improve reservoir matching and forecasts for a variety of different heating scenarios.
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Holford, Simon P., Nick Schofield, and Peter Reynolds. "Subsurface fluid flow focused by buried volcanoes in sedimentary basins: Evidence from 3D seismic data, Bass Basin, offshore southeastern Australia." Interpretation 5, no. 3 (August 31, 2017): SK39—SK50. http://dx.doi.org/10.1190/int-2016-0205.1.
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There is growing evidence that intrusive magmatic bodies such as sills and dikes can influence the migration of fluids in the deep subsurface. This influence is largely due to permeability contrasts with surrounding sedimentary rocks or because of interconnected open fractures within and around intrusions acting as conduits for migrating fluids. The role of buried volcanoes in influencing crossstratal fluid migration in sedimentary basins is less well-established. However, several studies have highlighted spatial linkages between extinct hydrothermal vent complexes and fluid seepage, suggesting that buried extrusive features can also influence subsurface fluid-flow pathways, potentially leading to migration of hydrocarbon fluids between the source and reservoir. We have developed 3D seismic reflection data from the Bass Basin in offshore southeastern Australia that image an early Miocene volcanic complex with exceptional clarity. This volcanic complex is now buried by [Formula: see text] of younger sediments. The largest volcano within this complex is directly overlain by a vertical feature interpreted to be a fluid escape pipe, which extends vertically for approximately 700 m across the late Miocene-Pliocene succession. We suggest that the buried volcanic complex was able to focus vertical fluid migration to the base of the pipe because its bulk permeability was higher than that of the overlying claystone sequence. The fluid escape pipe may have initiated through either (1) hydraulic fracturing following fluid expulsion from a deep, overpressured subvolcanic source region, (2) differential compaction and doming of the overlying claystones, or (3) a combination of these processes. Our results suggest a hitherto unrecognized role for buried volcanoes in influencing dynamic subsurface processes in sedimentary basins. In particular, our study highlights that buried volcanoes may facilitate cross-stratal migration of hydrocarbons from source to reservoir, or through sealing horizons.
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Ahammad, Mohammad Jalal, Mohammad Azizur Rahman, Jahrul Alam, and Stephen Butt. "A computational fluid dynamics investigation of the flow behavior near a wellbore using three-dimensional Navier–Stokes equations." Advances in Mechanical Engineering 11, no. 9 (September 2019): 168781401987325. http://dx.doi.org/10.1177/1687814019873250.
Full textAbstract:
The analysis of fluid flow near the wellbore region of a hydrocarbon reservoir is a complex phenomenon. The pressure drop and flow rates change in the near wellbore with time, and the understanding of this system is important. Besides existing theoretical and experimental approaches, computational fluid dynamics studies can help understanding the nature of fluid flow from a reservoir into the wellbore. In this research, a near wellbore model using three-dimensional Navier–Stokes equations is presented for analyzing the flow around the wellbore. Pressure and velocity are coupled into a single system which is solved by an algebraic multigrid method for the optimal computational cost. The computational fluid dynamics model is verified against the analytical solution of the Darcy model for reservoir flow, as well as against the analytical solution of pressure diffusivity equation. The streamlines indicate that the flow is radially symmetric with respect to the vertical plane as expected. The present computational fluid dynamics investigation observes that the motion of reservoir fluid becomes nonlinear at the region of near wellbore. Moreover, this nonlinear behavior has an influence on the hydrocarbon recovery. The flow performance through wellbore is analyzed using the inflow performance relations curve for the steady-state and time-dependent solution. Finally, the investigation suggests that the Navier–Stokes equations along with a near-optimal solver provide an efficient computational fluid dynamics framework for analyzing fluid flow in a wellbore and its surrounding region.
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Liang, Tianbo, Rafael A. Longoria, Jun Lu, Quoc P. Nguyen, and David A. DiCarlo. "Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-Ins and Surfactant Additives." SPE Journal 22, no. 04 (May 17, 2017): 1011–23. http://dx.doi.org/10.2118/175101-pa.
Full textAbstract:
Summary Fracturing-fluid loss into the formation can potentially damage hydrocarbon production in shale or other tight reservoirs. Well shut-ins are commonly used in the field to dissipate the lost water into the matrix near fracture faces. Borrowing from ideas in chemical enhanced oil recovery (CEOR), surfactants have potential to reduce the effect of fracturing-fluid loss on hydrocarbon permeability in the matrix. Unconventional tight reservoirs can differ significantly from one another, which could make the use of these techniques effective in some cases but not in others. We present an experimental investigation dependent on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production from hydraulically fractured reservoirs. We compare the benefits of shut-ins and reduction in interfacial tension (IFT) by surfactants for hydrocarbon permeability for different initial reservoir conditions (IRCs). From this work, we identify the mechanism responsible for the permeability reduction in the matrix, and we suggest criteria that can be used to optimize fracturing-fluid additives and/or manage flowback operations to enhance hydrocarbon production from unconventional tight reservoirs.
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de Andrade, Deraldo de Carvalho Jacobina, and Bahareh Nojabaei. "Phase Behavior and Composition Distribution of Multiphase Hydrocarbon Binary Mixtures in Heterogeneous Nanopores: A Molecular Dynamics Simulation Study." Nanomaterials 11, no. 9 (September 18, 2021): 2431. http://dx.doi.org/10.3390/nano11092431.
Full textAbstract:
In this study, molecular dynamics (MD) simulation is used to investigate the phase behavior and composition distribution of an ethane/heptane binary mixture in heterogeneous oil-wet graphite nanopores with pore size distribution. The pore network system consists of two different setups of connected bulk and a 5-nm pore in the middle; and the bulk connected to 5-nm and 2-nm pores. Our results show that nanopore confinement influences the phase equilibrium of the multicomponent hydrocarbon mixtures and this effect is stronger for smaller pores. We recognized multiple adsorbed layers of hydrocarbon molecules near the pore surface. However, for smaller pores, adsorption is dominant so that, for the 2-nm pore, most of the hydrocarbon molecules are in the adsorbed phase. The MD simulation results revealed that the overall composition of the hydrocarbon mixture is a function of pore size. This has major implications for macro-scale unconventional reservoir simulation, as it suggests that heterogenous shale nanopores would host fluids with different compositions depending on the pore size. The results of this paper suggest that modifications should be made to the calculation of overall composition of reservoir fluids in shale nanopores, as using only one overall composition for the entire heterogenous reservoir can result in significant error in recovery estimations.
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Baek, Seunghwan, and I. Yucel Akkutlu. "Enhanced Recovery of Nanoconfined Oil in Tight Rocks Using Lean Gas (C2H6 and CO2) Injection." SPE Journal 26, no. 04 (March 15, 2021): 2018–37. http://dx.doi.org/10.2118/195272-pa.
Full textAbstract:
Summary Organic matters in source rocks store oil in significantly larger volume than that based on its pore volume (PV) due to so-called nanoconfinement effects. With pressure depletion and production, however, oil recovery is characteristically low because of the low compressibility of the fluid and amplified interaction with pore surface in the nanoporous material. For the additional recovery, CO2 injection has been widely adopted in shale gas and tight oil recovery over the last decades. But its supply and corrosion are often pointed out as drawbacks. In this study, we propose ethane injection as an alternative enhanced oil recovery (EOR) strategy for more productive oil production from tight unconventional reservoirs. Monte Carlo (MC) molecular simulation is used to reconstruct molecular configuration in pores under reservoir conditions. Further, molecular dynamics (MD) simulation provides the basis for understanding the recovery mechanism of in-situ fluids. These enable us to estimate thermodynamic recovery and the free energy associated with dissolution of injected gas. Primary oil recovery is typically below 15%, indicating that pressure depletion and fluid expansion are no longer effective recovery mechanisms. Ethane injection shows 5 to 20% higher recovery enhancement than CO2 injection. The superior performance is more pronounced, especially in nanopores, because oil in the smaller pores is richer in heavy components compared to the bulk fluids, and ethane molecules are more effective in displacing the heavy hydrocarbons. Analysis of the dissolution free energy confirms that introducing ethane into reservoirs is more favored and requires less energy for the enhanced recovery.
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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.
Full textAbstract:
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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Lawrence, H. M., L. E. Armstrong, K. Ashton, A. D. Jones, and I. E. Mearns. "The Jasmine Field, Blocks 30/06 and 30/07a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 498–510. http://dx.doi.org/10.1144/m52-2018-53.
Full textAbstract:
AbstractThe high-pressure–high-temperature Jasmine Field lies 270 km east of Aberdeen in the UK Central North Sea and forms part of Chrysaor’s J-Area. Hydrocarbons were discovered at Jasmine in 2006, in Middle–Late Triassic fluvial sandstones of the Joanne Sandstone Member of the Skagerrak Formation. Appraisal proved a greater than 2000 ft hydrocarbon column and, in 2010, the Jasmine Field development was sanctioned. Five development wells were pre-drilled between 2010 and 2013, and the field was brought on line in November 2013, after which one further appraisal and three additional production wells were drilled. Jasmine infrastructure comprises an accommodation platform and a wellhead platform tied back to a riser platform adjacent to the Judy processing and export facility.Rapid early pressure depletion, a highly layered fluvial reservoir, structural complexity and variable fluid types present significant challenges for both static and dynamic modelling. Following production start-up, acquisition of new post-production reservoir pressure and flow data, and incorporation of allocated well production data, have been used to address these modelling challenges, and to provide encouragement for future infill and near-field exploration drilling opportunities.
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Robertson, John O., and George V. Chilingar. "Faulting, fault sealing and fluid flow in hydrocarbon reservoirs." Journal of Petroleum Science and Engineering 25, no. 1-2 (January 2000): 93. http://dx.doi.org/10.1016/s0920-4105(00)00002-4.
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Salazar, Jesús M., Carlos Torres-Verdín, and Gong Li Wang. "Effects of Surfactant-Emulsified Oil-Based Mud on Borehole Resistivity Measurements." SPE Journal 16, no. 03 (March 29, 2011): 608–24. http://dx.doi.org/10.2118/109946-pa.
Full textAbstract:
Summary We quantify the influence of oil-based mud (OBM)-filtrate invasion and formation-fluid properties on the spatial distribution of fluid saturation and electrical resistivity in the near-wellbore region. The objective is to appraise the sensitivity of borehole resistivity measurements to the spatial distribution of fluid saturation resulting from the compositional mixing of OBM and in-situ hydrocarbons. First, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. A second approach consists of adding water and surfactant to a multicomponent OBM invading a formation saturated with multiple hydrocarbon components. Simulations also include presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion because oil viscosity and oil density are both dependent on component concentrations. Presence of surfactants in the OBM is simulated with a commercial adaptive implicit compositional formulation that models the flow of three-phase multicomponent fluids in porous media. Simulations of the process of OBM invasion yield 2D spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity. Subsequently, we simulate the corresponding array-induction measurements assuming axial-symmetric variations of electrical resistivity. We perform sensitivity analyses on field measurements acquired in a well that penetrates a clastic formation and that includes different values of density and viscosity for mud filtrate and formation hydrocarbon. These analyses provide evidence of the presence of a high-resistivity region near the borehole wall followed by a low-resistivity annulus close to the noninvaded resistivity region. Such an abnormal resistivity annulus is predominantly caused by high viscosity contrasts between mud filtrate and formation oil. The combined simulation of invasion and array-induction logs in the presence of OBM invasion provides a more reliable estimate of water saturation, which improves the assessment of in-place hydrocarbon reserves.
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Neff, Dennis B. "Incremental pay thickness modeling of hydrocarbon reservoirs." GEOPHYSICS 55, no. 5 (May 1990): 556–66. http://dx.doi.org/10.1190/1.1442867.
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The one-dimensional convolution model or synthetic seismogram provides more information about the seismic waveform expression of hydrocarbon reservoirs when petrophysical data (porosity, shale volume, water saturation, etc.) are systematically integrated into the seismogram generation process. Use of this modeling technique, herein called Incremental Pay Thickness (IPT) modeling, has provided valuable insights concerning the seismic response of several offshore Gulf of Mexico amplitude anomalies. Through integration of the petrophysical data, comparisons between seismic waveform response and expected reservoir pay thickness are extended to include estimates of gross pay thickness, net pay thickness, net porosity feet of pay, and hydrocarbons in place. These 1-D synthetic data easily convert to 2-D displays that often show exceptional waveform correlations between the synthetic and actual seismic data. Anomalous observed waveform responses include complex tuning curves; diagnostic isochron measurements even in unresolved thin-bed reservoirs; and extreme variations in the seismic expression of hydro-carbon-fluid contacts. While IPT modeling examples illustrate both the variability and nonuniqueness of seismic responses to hydrocarbon reservoirs, they often show good seismic predictability of pay thickness if the appropriate choice of amplitude-isochron versus pay thickness is made (i.e., peak amplitude, trough amplitude, or average amplitude versus gross pay thickness, net pay thickness, net porosity feet of pay, or hydrocarbons in place).
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Houck, Richard T., Adrian Ciucivara, and Scott Hornbostel. "Accuracy and effectiveness of three-dimensional controlled source electromagnetic data inversions." GEOPHYSICS 80, no. 2 (March 1, 2015): E83—E95. http://dx.doi.org/10.1190/geo2014-0142.1.
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Unconstrained 3D inversion of marine controlled source electromagnetic data (CSEM) data sets produces resistivity volumes that have an uncertain relationship to the true subsurface resistivity at the scale of typical hydrocarbon reservoirs. Furthermore, CSEM-scale resistivity is an ambiguous indicator of hydrocarbon presence; not all resistivity anomalies are caused by hydrocarbon reservoirs, and not all hydrocarbon reservoirs produce a distinct resistivity anomaly. We have developed a method for quantifying the effectiveness of resistivities from CSEM inversion in detecting hydrocarbon reservoirs. Our approach uses probabilistic rock-physics modeling to update information from a preexisting prospect assessment, based on uncertain resistivities from CSEM. The result is an estimate the probability of hydrocarbon presence that accounts for uncertainty in the resistivity and in rock properties. Examples using synthetic and real CSEM data sets demonstrate that the effectiveness of CSEM inversion in identifying hydrocarbon reservoirs depends on the interaction between the uncertainty associated with the inversion-derived resistivity and the range of rock and fluid properties that were expected for the targeted prospect. Resistivity uncertainty that has a small effect on hydrocarbon probability for one set of rock property distributions may have a large effect for a different set of rock properties. Depending on the consequences of this interaction, resistivities from CSEM inversion might reduce the risk associated with predictions of hydrocarbon presence, but they cannot be expected to guarantee a specific well outcome.