Academic literature on the topic 'Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics'
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Journal articles on the topic "Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics"
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Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei, and Yu Ye. "Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China." Energy Exploration & Exploitation 36, no. 4 (February 22, 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.
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The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.
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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.
Dissertations / Theses on the topic "Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics"
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Teimoori, Sangani Ahmad Petroleum Engineering Faculty of Engineering UNSW. "Calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs." Awarded by:University of New South Wales. School of Petroleum Engineering, 2005. http://handle.unsw.edu.au/1959.4/22408.
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This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.
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Lowden, Ben D. "A methodology for the quantification of outcrop permeability heterogeneities through probe permeametry." Thesis, Imperial College London, 1993. http://hdl.handle.net/10044/1/7588.
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Rogers, Anna Louise. "Poroelastic modeling of groundwater and hydrocarbon reservoirs : investigating the effects of fluid extraction on fault stability." Thesis, Massachusetts Institute of Technology, 2017. http://hdl.handle.net/1721.1/113792.
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Thesis: S.M. in Geophysics, Massachusetts Institute of Technology, Department of Earth, Atmospheric, and Planetary Sciences, 2017.Cataloged from PDF version of thesis.
Includes bibliographical references (pages 91-93).
The possibility of human-triggered earthquakes is critical to understand for hazard mitigation. This project was developed to better understand the stability of faults in areas with high amounts of fluid extraction, and was applied to both a groundwater and hydrocarbon basin. The theory of poroelasticity was used to calculate the stress changes resulting from fluid flow. Then, the resulting fault stability was evaluated with the the Coulomb Failure Function ([Delta]CFF). A COMSOL and MATLAB workflow was used to derive the results. Two applications were completed. The primary research focused on the extraction from a groundwater aquifer in Lorca, Spain, in relation to the M, 5.1, 2011 earthquake. A smaller project was completed for the production of an oil well in Wheeler Ridge, California, in relation to the Mw 7.7, 1952 earthquake. In Lorca, it was found that extraction from a local aquifer promoted failure on an antithetic fault to the major Alhama de Murcia Fault. Specifically, while the left-lateral portion of the slip was stabilized, the reverse component of the slip was promoted (depth -5 km). Published InSAR and focal mechanism results support a rupture plane aligned with the antithetic fault. The final stress change was ~0.03 MPa which is small but not negligible compared to the expected total stress drop (~2 MPa). In California, the production from Well 85-29 was of interest. It was found that oil extraction promoted failure on the White Wolf Fault. There was a region adjacent to but below the reservoir that tended toward destabilization after the production. However, there was a notably small stress change (~0.5 kPA). This project lends to some important conclusions, and demonstrates that the poroelastic deformation of an aquifer or reservoir can result in distinct zones of stabilization and destabilization on pre-existing faults.
by Anna Louise Rogers.
S.M. in Geophysics
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Dinske, Carsten [Verfasser]. "Interpretation of fluid-induced seismicity at geothermal and hydrocarbon reservoirs of Basel and Cotton Valley / Carsten Dinske." Berlin : Freie Universität Berlin, 2011. http://d-nb.info/1025510666/34.
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de, Carvalho Jacobina Andrade Deraldo. "Molecular Dynamics Study of Nano-confinement Effect on Hydrocarbons Fluid Phase Behavior and Composition in Organic Shale." Thesis, Virginia Tech, 2021. http://hdl.handle.net/10919/102912.
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The depletion of conventional oil reservoirs forced companies and consequently researchers to pursue alternatives such as resources that in the past were considered not economically viable, in consequence of the high depth, low porosity and permeability of the play zone. The exploration challenges were overcome mainly by the development of horizontal drilling and hydraulic fracturing. However, the extremely high temperatures and pressures, in association to a complex nanopore structure, in which reservoir fluids are now encountered, instigate further investigation of fluid phase behavior and composition, and challenge conventional macroscale reservoir simulation predictions. Moreover, the unusual high temperatures and pressures have increased the cost as well as the hazardous level for reservoir analyzes by lab experiments. Molecular Dynamics (MD) simulation of reservoirs can be a safe and inexpensive alternative tool to replicate reservoir pore and fluid conditions, as well as to monitor fluid behavior.
In this study, a MD simulation of nanoconfinement effect on hydrocarbon fluid phase and compositional behavior in organic shale rocks is presented. Chapter 1 reviews and discusses previous works on MD simulations of geological resources. With the knowledge acquired, a fully atomistic squared graphite pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that nano-confinement increases fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an alteration of oil in place (OIP) prediction by reservoir simulations, when nano-confinement effect is not considered.Master of Science
Petroleum sub products are present in the day to day life of almost any human. The list include gasoline, plastics, perfumes, medications, polyester for clothing. Petroleum is naturally encountered in the void space, known as pores, inside rocks at reservoirs thousands of feet underground. In the past, the pores of oil reservoirs in development were larger and interconnected, which facilitates its extraction and reserve predictions. Most of reservoirs being developed nowadays have pores in the nanoscale and with poor interconnection as well as higher reservoir temperatures and pressure. These "new conditions", instigates further investigation of fluid phase behavior and composition, and challenge macroscale reservoir simulation predictions. In this study, the effect of decrease in pore size, as well as higher temperature and pressure conditions, in fluid behavior and composition is studied. Chapter 1 reviews and discusses previous works on geological resources modeling and simulation. With the knowledge acquired, a fully squared shale pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that pores in the nanoscale region tend to increase fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an underestimation of reserves prediction by reservoir simulations, when the change in density is not considered.
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Choi, Jong-Won. "Geomechanics of subsurface sand production and gas storage." Diss., Georgia Institute of Technology, 2011. http://hdl.handle.net/1853/39493.
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Improving methods of hydrocarbon production and developing new techniques for the creation of natural gas storage facilities are critically important for the petroleum industry. This dissertation focuses on two key topics: (1) mechanisms of sand production from petroleum reservoirs and (2) mechanical characterization of caverns created in carbonate rock formations for natural gas storage. Sand production is the migration of solid particles together with the hydrocarbons when extracted from petroleum reservoirs. It usually occurs from wells in sandstone formations that fail in response to stress changes caused by hydrocarbon withdrawal. Sand production is generally undesirable since it causes a variety of problems ranging from significant safety risks during high-rate gas production, to the erosion of downhole equipment and surface facilities. It is widely accepted that a better understanding of the mechanics of poorly-consolidated formations is required to manage sand production; which, in turn, enables the cost effective production of gas and oil resources. In this work, a series of large-scale laboratory experiments was conducted in fully saturated, cohesionless sand layers to model the behavior of a petroleum reservoir near a wellbore. We directly observed several key characteristics of the sand production phenomenon including the formations of a stable cavity around the wellbore and a sub-radial flow channel at the upper surface of the tested layer. The flow channel is a first-order feature that appears to be a major part of the sand production mechanism. The channel cross section is orders of magnitude larger than the particle size, and once formed, the channel becomes the dominant conduit for fluid flow and particle transport. The flow channel developed in all of our experiments, and in all experiments, sand production continued from the developing channel after the cavity around the borehole stabilized. Our laboratory results constitute a well constrained data set that can be used to test and calibrate numerical models employed by the petroleum industry for predicting the sand production phenomenon. Although important for practical applications, real field cases are typically much less constrained. We used scaling considerations to develop a simple analytical model, constrained by our experimental results. We also simulated the behavior of a sand layer around a wellbore using two- and three-dimensional discrete element methods. It appears that the main sand production features observed in the laboratory experiments, can indeed be reproduced by means of discrete element modeling. Numerical results indicate that the cavity surface of repose is a key factor in the sand production mechanism. In particular, the sand particles on this surface are not significantly constrained. This lack of confinement reduces the flow velocity required to remove a particle, by many orders of magnitude. Also, the mechanism of channel development in the upper fraction of the sample can be attributed to subsidence of the formation due to lateral extension when an unconstrained cavity slope appears near the wellbore. This is substantiated by the erosion process and continued production of particles from the flow channel. The notion of the existence of this surface channel has the potential to scale up to natural reservoirs and can give insights into real-world sand production issues. It indicates a mechanism explaining why the production of particles does not cease in many petroleum reservoirs. Although the radial character of the fluid flow eventually stops sand production from the cavity near the wellbore, the production of particles still may continue from the propagating surface (interface) flow channel. The second topic of the thesis addresses factors affecting the geometry and, hence, the mechanical stability of caverns excavated in carbonate rock formations for natural gas storage. Storage facilities are required to store gas when supply exceeds demand during the winter months. In many places (such as New England or the Great Lakes region) where no salt domes are available to create gas storage caverns, it is possible to create cavities in limestone employing the acid injection method. In this method, carbonate rock is dissolved, while CO₂ and calcium chloride brine appear as products of the carbonate dissolution reactions. Driven by the density difference, CO₂ rises towards the ceiling whereas the brine sinks to the bottom of the cavern. A zone of mixed CO₂ , acid, and brine forms near the source of acid injection, whereas the brine sinks to the bottom of the cavern. Characterization of the cavern shape is required to understand stress changes during the cavity excavation, which can destabilize the cavern. It is also important to determine the location of the mixture-brine interface to select the place of acid injection. In this work, we propose to characterize the geometry of the cavern and the location of the mixture-brine interface by generating pressure waves in a pipe extending into the cavern, and measuring the reflected waves at various locations in another adjacent pipe. Conventional governing equations describe fluid transients in pipes loaded only by internal pressure (such as in the water hammer effect). To model the pressure wave propagation for realistic geometries, we derived new governing equations for pressure transients in pipes subjected to changes in both internal and external (confining) pressures. This is important because the internal pressure (used in the measurement) is changing in response to the perturbation of the external pressure when the pipe is contained in the cavern filled with fluids. If the pressure in the cavern is perturbed, the perturbation creates an internal pressure wave in the submerged pipe that has a signature of the cavern geometry. We showed that the classic equations are included in our formulation as a particular case, but they have limited validity for some practically important combinations of the controlling parameters. We linearized the governing equations and formulated appropriate boundary and initial conditions. Using a finite element method, we solved the obtained boundary value problem for a system of pipes and a cavern filled with various characteristic fluids such as aqueous acid, calcium chloride brine, and supercritical CO₂ . We found that the pressure waves of moderate amplitudes would create measurable pressure pulses in the submerged pipe. Furthermore, we determined the wavelengths required for resolving the cavern diameter from the pressure history. Our results suggest that the pressure transients technique can indeed be used for characterizing the geometry of gas storage caverns and locations of fluid interfaces in the acid injection method.
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Ong, Anthony. "Réservoirs silicoclastiques très enfouis : caractérisation diagénétique et modélisation appliquées aux champs pétroliers du Viking Graben (Mer du Nord)." Thesis, Université de Lorraine, 2013. http://www.theses.fr/2013LORR0065/document.
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Dans les réservoirs silicoclastiques, la perte de porosité avec l'enfouissement est due à la fois à la compaction mécanique lors des 2-3 premiers kilomètres d'enfouissement, à la compaction chimique, et à la précipitation minérale (quartz, argiles, carbonates). Dès lors, la compréhension des processus responsables de l'inhibition de la compaction et/ou de la cimentation représente un triple enjeu: i) contribuer à la connaissance des mécanismes d'interactions eau-hydrocarbures-solides en milieu diagénétique profond; ii) apporter de nouveaux arguments pour reconstituer les chemins de migration des fluides à l'échelle du bassin iii) développer des guides de prospection pour l'industrie pétrolière. Les techniques analytiques telles que la pétrographie quantitative, les inclusions fluides ainsi que les modélisations diagénétiques et de bassin ont été couplées afin de comprendre les processus régissant le contrôle de la qualité du réservoir du Brent (Jurassique Moyen) à travers 8 champs pétroliers (et 11 puits) dans le bloc Q3 (Viking Graben, Northern North Sea). L'étude pétrographique quantitative du réservoir du Tarbert a permis de définir des compositions minéralogiques et des paramètres pétrophysiques (porosité) relativement similaires sur les 183 échantillons étudiés. Une paragenèse diagénétique commune à tous les champs étudiés a été établie, dominée par les ciments de quartz, de deux générations de kaolinite (K1, associée à la déstabilisation des micas et K2, associée à la dissolution des feldspaths potassiques), et de précipitation d'illite. L'approche comparative des ciments d'enfouissement n'a pas permis de rendre compte des larges gammes de porosité et perméabilité mesurées allant de 8 à 27 % et de 0,2 à 5000 mD. Contrairement au modèle diagénétique souvent évoqué, l'inhibition des ciments de quartz ne joue pas un rôle majeur dans la préservation de la porosité des réservoirs du bloc Q3. Les estimations P-V-T-X-t du piégeage des inclusions fluides couplées au modèle de bassin ont permis de reconstituer trois chemins de migration des fluides aqueux et hydrocarbonés associés à la mise en place de surpressions fluides au sein des réservoirs du Tarbert. 1) La partie Nord de la kitchen du Viking Graben alimente les champs de Hild, Jura et Islay en huiles légères très précocement (65-42 Ma) et en gaz à condensat à partir de 35-15 Ma. Ces deux migrations sont associées à une montée en surpression fluide du réservoir de 100 à 200 bar. 2) la partie Est de la kitchen de l'East Shetland alimente les champs d'Alwyn, Dunbar, et Grant en huiles lourdes à légères à partir de 42-35 Ma, associée à une faible surpression fluide (30-40 bar). 3) la partie Sud de la kitchen de l'East Shetland (longue distance de migration) alimente quant à elle les champs de Forvie Central et North très tardivement en gaz à condensat (> 15 Ma). Le timing relatif entre la mise en place de la surpression fluide et l'avancement de la compaction mécanique/chimique s'est révélé être le paramètre de premier ordre régissant la préservation de la porosité des réservoirs observée dans le bloc Q3. La présence d'inclusions hydrocarbonées atypiques HT-BP (haute température-basse pression) datées du Jurassique supérieur dans les champs proches du Viking Graben, pourrait être à l'origine d'une génération d?hydrocarbures très précoce sous un régime de pression hydrostatique. Bien que n'ayant aucun impact sur l'inhibition de la contrainte effective, cette migration fluide pourrait être attribuée aux anomalies thermiques du Nord-Ouest de l'Europe liée à l'ouverture de l'Atlantique Nord. Le couplage des outils de pétrographie quantitative, inclusions fluides et modélisation de bassin a donc permis de soulever l'importance d'intégrer une vision régionale à l'étude ponctuelle de la diagenèse dans le but de comprendre le rôle des migrations fluides sur la préservation de la qualité des réservoirs silicoclastiquesIn siliciclastic reservoirs, porosity loss is mainly due to the mechanical compaction in the first 2-3 km of burial, the chemical compaction and mineral precipitation (quartz, clays, carbonates). Therefore, understanding the processes responsible of the inhibition of compaction and/or cementation permits to: i) contribute to the knowledge of the water-hydrocarbon-solid interaction mechanisms in deep diagenetic environment, ii) give new arguments for the reconstruction of fluid pathways at the basin scale iii) assist the oil industry for the intensive exploration. Analytical techniques such as quantitative petrography, fluid inclusion and basin/diagenesis modelling were coupled across 8 oil fields (and 11 wells) located in the Q3 block (Viking Graben, Northern North Sea) in order to understand the processes driving the variation of the Brent reservoir quality (Middle Jurassic). Quantitative petrographic study of Tarbert reservoir allowed to define similar depositional settings (mineralogy, porosity) among the 183 studied samples. The common diagenetic paragenesis is dominated by quartz cement, two generations of kaolinite (K1, associated with the destabilization of micas and K2, associated with the dissolution of feldspars), and precipitation of illite. The petrographic data do not explain the wide range of measured porosity and permeability on plugs from 8 to 27% and from 0.2 to 5000 mD respectively. In contrast with the conventional diagenetic model, the present study shows that inhibition of quartz cements did not play a major role in the preservation of porosity in the Q3 block. P-V-T-X-t estimates of fluid inclusion trapping coupled with basin modelling allowed reconstruction of three fluid migration pathways, associated with fluid overpressures in the Tarbert reservoir. 1) The northern part of the Viking Graben kitchen supplies Hild, Jura and Islay fields with an early migration of light oils (65-42 m.y.) and condensate from 35-15 m.y. Both migrations are associated with a great fluid overpressure from 100 to 200 bar. 2) The eastern part of the East Shetland kitchen supplies Alwyn, Dunbar, Grant fields, with heavy to light oils from 42-35 m.y., associated with a low fluid overpressure (30-40 bar). 3) The southern part of the East Shetland kitchen (long distance migration) supplies Forvie North and Central fields with a very late gas condensate migration (> 15 Ma). The relative timing of the fluid overpressure build-up with the degree of mechanical and chemical compaction appears to be the first order parameter governing the preservation of reservoir porosity across the Q3 block. The presence of unusual HT-LP (high temperature-low pressure) hydrocarbon inclusions in the fields near the graben could indicate an early heavy oil generation under hydrostatic pressure conditions. Although having no impact on the inhibition of effective stress, this high-temperature fluid migration could be attributed to thermal anomalies in the Northwest of Europe related to the North Atlantic opening. The combination of quantitative petrography, fluid inclusion and basin modelling allowed to point out the impact of regional fluid migrations on the well scale diagenesis and on the siliciclastic reservoir quality preservation
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Gambús, Ordaz Maika Karen Torres-Verdín Carlos. "A field study to assess the value of 3D post-stack seismic data in forecasting fluid production from a deepwater Gulf-of-Mexico reservoir." 2005. http://repositories.lib.utexas.edu/bitstream/handle/2152/1548/gambusm78334.pdf.
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Gambús, Ordaz Maika Karen. "A field study to assess the value of 3D post-stack seismic data in forecasting fluid production from a deepwater Gulf-of-Mexico reservoir." Thesis, 2005. http://hdl.handle.net/2152/1548.
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Lu, Bo 1979. "Iteratively coupled reservoir simulation for multiphase flow in porous media." Thesis, 2008. http://hdl.handle.net/2152/3880.
Full textBooks on the topic "Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics"
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Kerimov, V. I︠U︡. (Vagif I︠U︡nus ogly) and Gorfunkel Michael V, eds. Fluid dynamics of oil and gas reservoirs. Hoboken, New Jersey: Scrivener Publishing/Wiley, 2015.
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1955-, Spivey John Paul, and Lenn Christopher P, eds. Petroleum reservoir fluid property correlations. Tulsa, Okla: PennWell Corp., 2010.
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Ahmed, Tarek H. Working guide to reservoir rock properties and fluid flow. Amsterdam: Elsevier, 2010.
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V, Panfilova I., ed. Osrednennye modeli filtrat͡s︡ionnykh prot͡s︡essov s neodnorodnoĭ vnutrenneĭ strukturoĭ. Moskva: "Nauka", 1996.
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Kuchuk, Fikri. Convolution and deconvolution in pressure transient formation and well testing. Amsterdam: Elsevier Science, 2010.
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Cope, P. J. (Patricia J.) and Lisk M. (Mark), eds. Hydrocarbon migration and entrapment in potential Lower Cambrian reservoirs, vines 1, Officer Basin, Western Australia. Perth: Western Australia Geological Survey, 2004.
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The physics of reservoir fluids: Discovery through downhole fluid analysis. Sugar Land, Tex: Schlumberger, 2008.
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Rachinsky, M. Z., and V. Y. Kerimov. Fluid Dynamics of Oil and Gas Reservoirs. Wiley & Sons, Incorporated, John, 2015.
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G, Jones, Fisher Q. J, Knipe R. J. 1952-, and Geological Society of London, eds. Faulting, fault sealing and fluid flow in hydrocarbon reservoirs. Bath: Geological Society, 1998.
Find full textBook chapters on the topic "Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics"
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"Hydrocarbon Generation, Migration and Accumulation in the South-Caspian Basin." In Fluid Dynamics of Oil and Gas Reservoirs, 365–95. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2015. http://dx.doi.org/10.1002/9781118999004.ch6.
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Doveton, John H. "Saturation-Height Functions." In Principles of Mathematical Petrophysics. Oxford University Press, 2014. http://dx.doi.org/10.1093/oso/9780199978045.003.0012.
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As observed by Worthington (2002), “The application of saturation-height functions forms part of the intersection of geologic, petrophysical, and reservoir engineering practices within integrated reservoir description.” It is also a critical reference point for mathematical petrophysics; the consequences of deterministic and statistical prediction models are finally evaluated in terms of how closely the estimates conform to physical laws. Saturations within a reservoir are controlled by buoyancy pressure applied to pore-throat size distributions and pore-body storage capacities within a rock unit that varies both laterally and vertically and may be subdivided into compartments that are not in pressure communication. Traditional lithostratigraphic methods describe reservoir architecture as correlative rock units, but the degree to which this partitioning matches flow units must be carefully evaluated to reconcile petrofacies with lithofacies. Stratigraphic correlation provides the fundamental reference framework for surfaces that define structure and isopach maps and usually represent principal reflection events in the seismic record. In some instances, there is a strong conformance between lithofacies and petrofacies, but all too commonly, this is not the case, and petrofacies must be partitioned and evaluated separately. Failure to do this may result in invalid volumetrics and reservoir models that are inadequate for fluid-flow characterization. A dynamic reservoir model must be history matched to the actual performance of the reservoir; this process often requires adjustments of petrophysical parameters to improve the reconciliation between the model’s performance and the history of production. Once established, the reservoir model provides many beneficial outcomes. At the largest scale, the model assesses the volumetrics of hydrocarbons in place. Within the reservoir, the model establishes any partitioning that may exist between compartments on the basis of pressure differences and, therefore, lack of communication. Lateral trends within the model trace changes in rock reservoir quality that control anticipated rates and types of fluids produced in development wells. Because the modeled fluids represent initial reservoir conditions, comparisons can be made between water saturations of the models and those calculated from logs in later wells, helping to ascertain sweep efficiency during production.
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Bernard, Sylvain, Leon Brown, Richard Wirth, Anja Schreiber, Hans-Martin Schulz, Brian Horsfield, Andrew C. Aplin, and Eliza J. Mathia. "FIB-SEM and TEM Investigations of an Organic-rich Shale Maturation Series from the Lower Toarcian Posidonia Shale, GermanyNanoscale Pore System and Fluid-rock Interactions." In Electron Microscopy of Shale Hydrocarbon Reservoirs. American Association of Petroleum Geologists, 2013. http://dx.doi.org/10.1306/13391705m1023583.
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LUCIA, F. JERRY, CHARLES KERANS, and FRED P. WANG. "FLUID-FLOW CHARACTERIZATION OF DOLOMITIZED CARBONATE-RAMP RESERVOIRS: SAN ANDRES FORMATION (PERMIAN) OF SEMINOLE FIELD AND ALGERITA ESCARPMENT, PERMIAN BASIN, TEXAS AND NEW MEXICO." In Hydrocarbon Reservoir Characterization, 129–53. SEPM (Society for Sedimentary Geology), 1995. http://dx.doi.org/10.2110/scn.95.34.0129.
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Gingras, Murray K., S. George Pemberton, Floyd (Bo) Henk, James A. MacEachern, Carl Mendoza, Ben Rostron, Riley O’Hare, Michele Spila, and Kurt Konhauser. "Applications of Ichnology to Fluid and Gas Production in Hydrocarbon Reservoirs." In Applied Ichnology. SEPM Society for Sedimentary Geology, 2007. http://dx.doi.org/10.2110/pec.07.52.0131.
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Doveton, John H. "Fluid Saturation Evaluation." In Principles of Mathematical Petrophysics. Oxford University Press, 2014. http://dx.doi.org/10.1093/oso/9780199978045.003.0006.
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In his treatise on electricity and magnetism, Maxwell (1873) published an equation that described the conductivity of an electrolyte that contained nonconducting spheres as: . . . Ψ = co/cw = 2Φ/(3-Φ) . . . where the “meaning” of Ψ (psi) has been most commonly interpreted as some expression of tortuosity, Co and Cw are the conductivity of the medium and the electrolyte, respectively, and Φ is the proportion of the medium that is occupied by the electrolyte. Since that time, considerable efforts have been devoted to elucidation of the electrical properties of porous materials, particularly with the advent of the first resistivity log in 1927, which founded an entire industry focused on estimating fluid saturations in hydrocarbon reservoirs from downhole measurements. To some degree, spirited discussions in the literature reflect two schools of thought, one that considers the role of the resistive framework from a primarily empirical point of view, and the other that models the conductive fluid phase in terms of electrical efficiency. Clearly, the two concepts are intertwined because resistivity is the reciprocal of conductivity and the pore network is the complement of the rock framework. If the solid part of the rock is nonconductive, then the ability of a rock to conduct electricity is controlled by the conductive phase in the pore space, which should make the case for equations to be formulated from classical physical theory. This approach is typically developed using electrical flow through capillary tubes as a starting point. Unfortunately, the topological transformation of a capillary tube model to a satisfactory representation of a real pore network is a formidable challenge, so that mathematical solutions may not be acceptable, even though they are grounded in basic physics. The most successful model along these lines has been proposed by Herrick and Kennedy (1994), who maintain that while the Archie equation is a useful parametric function, it has no physical basis. Some of their conclusions are reviewed at the end of this chapter.
Conference papers on the topic "Hydrocarbon reservoirs Hydrocarbon reservoirs Fluid dynamics"
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Kayode, B., F. Al-Tarrah, and G. Hursan. "Methodology for Static and Dynamic Modeling of Hydrocarbon Systems Having Sharp Viscosity Gradient." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21184-ms.
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Abstract This paper describes a methodology for delineating tar surface, incorporating it into a geological model, and the process for numerical modeling of oil viscosity variation with depth above the tar surface. The methodology integrates well log data and compositional fluid analysis to develop a mathematical model that mimics the oil's property variation with depth. While there are a good number of reservoirs that fit this description globally, there is a knowledge gap in literature regarding best practices for dealing with the peculiar challenges of such reservoirs. These challenges include; (i) how to delineate the top-of-tar across the field, (ii) modeling of Saturation Height Function (SHF) in a system where density and wettability is changing with depth, and (iii) the methodology for representing the depth-dependent oil properties (especially viscosity) in reservoir simulation. Nuclear magnetic resonance (NMR) logs were used to predict fluid viscosity using a technique discussed by Hursan et al. (2016). Viscosity regions are identified at every well that has an NMR log, and these regions are mapped from well to well across the reservoir. Within each viscosity region, the analysis results of fluid samples collected from wells are used to develop mathematical models of fluid composition variation with depth. A reliable SHF model was achieved by incorporating depth-varying oil density and depth varying wettability into the calculation of J-Function. A compositional reservoir simulation was set-up, using the viscosity regions and the mathematical models describing composition variation with depth, for the respective regions. Using information obtained from literature as a starting point, residual oil saturation was modeled as a function of oil viscosity. Original reservoir understanding places the top of non-movable oil (tar) at a constant fieldwide subsurface depth, which corresponds to the shallowest historical no-flow drillstem test (DST) depth. Mapping of the NMR viscosity regions across the field resulted in a sloping tar-oil contact (TOC), which resulted in an increase of movable hydrocarbon pore volume. The viscosity versus depth profile from the simulation model matched the observed data, and allow the simulation model better predict well performance. In addition, the simulation model results also matched the depth-variation of observed formation volume factor (FVF) and reservoir fluid density. Some wells that have measured viscosity data but no NMR logs were used as blind-test wells. The simulation model results also matched the measured viscosity at those blind-test wells. These good matches of the oil property variation with depth gave confidence, that the simulation model could be used as an efficient planning tool for ensuring that injectors are placed just-above the tar mat. The use of the simulation model for well planning could reduce the need for geosteering while drilling flank wells, leading to savings in financial costs. This paper contains a generalized approach that can be used in static and dynamic modeling of reservoirs, where oil changes from light to medium to heavy oil, underlain by tar. It contains recommendations and guidelines to construct a reliable simulation model of such systems.
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Zhang, Fengyuan, and Hamid Emami-Meybodi. "Two-Phase Type-Curve Analysis of Flowback Data from Hydraulically Fractured Hydrocarbon Reservoirs." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206312-ms.
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Abstract This study presents a new type-curve method to characterize hydraulic fracture (HF) attributes and dynamics by analyzing two-phase flowback data from multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs.The proposed method includes a semianalytical model, as well as a workflow to estimate HF properties (i.e., initial fracture pore-volume and fracture permeability) and HF closure dynamics (through iterating fracture compressibility and permeability modulus).The semianalytical model considers the coupled two-phase flow in the fracture and matrix system, the variable production rate at the well, as well as the pressure-dependent reservoir and fluid properties. By incorporating the contribution of fluid influx from matrix into the fracture effective compressibility, a new set of dimensionless groups is defined to obtain a dimensionless solution for type-curve analysis. The accuracy of the proposed method is tested using the synthetic data generated from six numerical simulation cases for shale gas and oil reservoirs. The numerical validation confirms the unique behavior of type curves during fracture boundary dominated flow and verifies the accuracy of the type-curve analysis in the characterization of fracture properties. For field application, the proposed method is applied to two MFHWs in Marcellus shale gas and Eagle Ford shale oil.The agreement of interpreted results between the proposed method and straight-line analysis not only demonstrates the practicality in field application but also illustrates the superiority of the type-curve method as an easy-to-use technique to analyze two-phase flowback data. The analysis results from both of the field examples reveal the consistency in the estimated fracture properties between the proposed method and long-term history matching.
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Bravo, Maria Cecilia, Yon Blanco, Mauro Firinu, Tosi Gianbattista, Eriksen Martin, Brondbo Erik, Scott Paul, Jules El-Khoury, Mathias Horstmann, and Shahid Haq. "Reservoir Fluid Mapping While Drilling: Untapping the Barents Sea." In IADC/SPE Asia Pacific Drilling Technology Conference. SPE, 2021. http://dx.doi.org/10.2118/201019-ms.
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Abstract In complex and sensitive environments such as the northern Barents Sea, operations face multiple challenges, both technically and logistically. The use of logging while drilling (LWD) technology mitigates risks and assures acquisition of formation evaluation data in a complex trajectory. All data gathering was performed in LWD and provided the kernel for interpretation; alternate scenarios utilizing pipe conveyed wireline elevated risk factors as well as higher overall costs. Novel technology was required for this data acquisition, including fluid mapping while drilling (FMWD) that allows fluid identification with the use of downhole fluid analysis (DFA) using optical spectrometry as well as the retrieval of downhole fluid samples and a unique sourceless multifunction LWD tool delivering key data for the petrophysical evaluation. This paper presents a case study of the first application of a combination of FMWD and a petrophysical LWD toolstring in the Barents Sea. An excellent contribution to the operator of the PL229 that have pushed the boundaries of the formation sampling while drilling and set the basis to challenge the potentiality of this technique and improve the knowledge of the methodology that are the ultimate goals of this paper. Methods, procedures, process Hydrocarbon exploration, production, and transport in the Barents Sea are challenging. The shallow and complex reservoirs are at low temperature and pressure, potentially with gas caps. The Goliat field is the first offshore oil development in this environment, producing from two reservoirs: Realgrunnen and Kobbe. As part of the Goliat field infill drilling campaign with the aim of adding reserves and increase production, PL229 license operator drilled a highly deviated pilot hole to confirm hydrocarbons contacts in the undrained Snadd formation, which lie between two producing reservoirs. A successful data acquisition would not only provide information on the structure of the reservoir but would also assess the insitu movable fluid: type of hydrocarbon or water. FMWD allowed insitu fluid identification with the use of DFA, enabling RT evaluation of hydrocarbon composition as well as the filtrate contamination prior to filling the sampling bottles for further laboratory analysis. All data was acquired while drilling and using a comprehensive real-time visualization interface. Results, observation, conclusion Extensive prejob planning was conducted to optimize the operation. Dynamic fluid invasion simulations were used to estimate the required cleanup times to reach low contaminations. Simulations showed there was significant advantage in cleanup times when sampling soon after drilling. Honoring the natural environment, a unique sourceless multifunction LWD tool was used to acquire data for petrophysical evaluation-GR, resistivity, radioisotope-free density and neutron porosity, elemental capture spectroscopy, and sigma. Fluid mapping in a single run was key to efficiently resolve the insitu fluid type and composition. Critical hydrocarbon samples were collected soon after the formation was drilled to minimize mud filtrate invasion and reduce cleanup times. Multiple pressure measurements were acquired and six downhole fluid samples at low contamination (∼3% confirmed by laboratory) collected at several stations in variable mobilities. One scanning station was done at a zone were a physical sample was not required to confirm absence of gas cap. The DFA capabilities and ability to assess composition and control the fluid cleanup from surface allowed critical decisions to complete the acquisition program in this remote complex environment, all while drilling. In conclusion, FMWD results facilitated the placement decisions of the horizontal drain in this reservoir. This green BHA is unique in the LWD world. It eliminates radioactive source-handling and all related environmental risks to provide a comprehensive reservoir characterization. FMWD contributes formation pressure and fluid characterization and enables the physical capture of fluid samples in a single run. The combination of these two technologies completed the formation and fluid evaluation needs in this remote and environmentally sensitive area while drilling.
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Yegin, Cengiz, Cenk Temizel, and Mustafa Akbulut. "Solvent-Loaded Microspheres for Permeability Enhancement in Heavy Crude Oil Reservoirs." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205991-ms.
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ABSTRACT With their abundancy and high-quality, it is predicted that fossil fuels will remain as the main resource that will meet the global energy demand in the several upcoming decades. Developments in hydrocarbon recovery technologies, both from conventional and unconventional reservoirs, have substantially contributed to the overall production levels in recent years. However, recovery factors obtained by using the current methods are still considered to be insufficient, and the companies have been looking for new materials and methods to enhance the efficiency and amount of recovery. One of the major issues related to low recovery factors is low permeability of reservoirs. Existence of blockages in pore throats and high level of heterogeneity lowers the mobility of hydrocarbons. In this study, we discuss development of an innovative material to be used as an additive in reservoir injection fluids to remove pore blockages in order to enhance the recovery levels. This additive material is made of pressure-sensitive microspheres loaded with solvents, which can (i) easily disperse in the injection fluid and travel to the low-permeability regions, (ii) break under pressure and confinement to release solvents, and (iii) remove blockages by targeting surroundings, especially asphalt-based particles and grains. This approach relies on the breakage of microcapsules in the confined region and release of the solvents to target blockages in porous media. In other words, the developed microspheres improve permeability of reservoirs as a result of pressure- and confinement-dependent breakage and release of solvents. Preparation of these microspheres was achieved by the encapsulation of solvent (toluene) emulsions in silica-based solid shells. Structure and stability of the solvent-loaded microspheres were examined using a variety of analytical techniques including UV-vis spectroscopy, optical microscopy, scanning electron microscope (SEM) and dynamic light scattering (DLS). It was found that the prepared microspheres possessed smooth surfaces with shell thicknesses in the range of 100-150 nm. Additionally, sand column tests were performed to evaluate the recovery potential of injection fluids in presence of solvent-loaded microspheres. It was shown that the use of solvent encapsulated in microspheres doubled the recovery factor of heavy oil compared to that of free solvent dispersed in the injection fluid. Such enhancement in the recovery factor was related to the release of solvents in localized areas, i.e., confined regions, as a consequence of breakage of microspheres. This novel approach of delivering solvents to low-permeability regions provides a significant driving force to eliminate pore blockages to facilitate mobilization of hydrocarbons trapped in confined spaces.
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Silveira de Araujo, Isa, Archana Jagadisan, and Zoya Heidari. "A GEOCHEMISTRY-ORIENTED WORKFLOW FOR WETTABILITY ASSESSMENT AT RESERVOIR CONDITION USING MOLECULAR DYNAMICS SIMULATIONS." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0079.
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Reliable quantification of wettability is critical in assessment of fluid distribution, capillary pressure, relative permeability, and flow properties of fluids in reservoirs. Wettability of reservoirs can be affected by chemical composition of rock-fluid system, salinity, and reservoir temperature. Experimental assessment of wettability under reservoir conditions, while gaining control on the aforementioned parameters, may be tedious and challenging. Several published researches have used experimental studies to focus on determining the impact of individual factors on wettability of rock. However, studies on the combined effects of these factors are limited, although critical, for better understanding of wettability of hydrocarbon reservoirs. In this paper we introduce a workflow for assessment of wettability of rocks at reservoir condition using molecular dynamics (MD) simulations. The outcomes include (i) quantifying the wettability of pure minerals, (ii) quantifying the impact of reservoir temperature on wettability of pure mineral. The inputs to the simulation include molecules of pure minerals (quartz, calcite, albite) packed in a cubical simulation box. The molecules are condensed to form a flat surface. Subsequently, water and oil (hexane) molecules are placed on the surface of the mineral. We then perform simulations with constant number of particles, temperature and volume (NVT) on the system till equilibrium is reached. At equilibrium, the contact angle formed by the water droplet is measured. Contact angle is simulated for temperature conditions in the range of 300 to 380 K. The results showed that the contact angle between water-mineral for quartz, calcite, and albite at room temperature (300 K) ranges from 30º to 45º, indicating that the surface of these minerals is hydrophilic, with different degrees of hydrophilicity. This information is essential for reliable fluid flow simulations, which are often overlooked in conventional approaches. We also found that the temperature has a measurable impact on the contact angles formed by water droplet. We found that increase in temperature from 300 to 380 K decreases the contact angles by approximately 30% on quartz surfaces, 20% on albite surfaces, and 24% on calcite surfaces. The results for the hexane-mineral system show that the hexane behaved similarly in the three minerals surface. A thin film of hexane is formed at the surface corresponding to a contact angle of 0º. The method introduced in this paper has application for reliable evaluation of wettability at any reservoir of interest by knowing the molecular structure of clay and non-clay minerals as well as fluid content. Moreover, the challenges of wettability determination under high temperature and pressure conditions can also be efficiently addressed by using molecular dynamics simulations.
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Ihwiwhu, Christian, Ibi-Ada Itotoi, Udeme John, Nnamdi Obioha, Precious Okoro, Maduabuchi Ndubueze, Edward Bobade, Adedeji Awujoola, Oghenerunor Bekibele, and Sola Adesanya. "Targeting and Developing the Remaining Pay in an Ageing Field: the Ovhor Field Experience." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/207089-ms.
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Abstract Understanding the complexity in the distribution of hydrocarbon in a simple structure with flow baffles and connectivity issues is critical in targeting and developing the remaining pay in a mature asset. Subtle facies changes (heterogeneity) can have drastic impact on reservoir fluids movement, and this can be crucial to identifying sweet spots in mature fields. This study evaluated selected reservoirs in Ovhor Field, Niger Delta, Nigeria with the objective of optimising production from the field by targeting undeveloped oil reserves or bypassed pay and gaining an improved understanding of the selected reservoirs to increase the company's reserves limits. The task at the Ovhor field, is complicated by poor stratigraphic seismic resolution over the field. 3-D geological (Sedimentology and stratigraphy) interpretation, Quantitative interpretation results and proper understanding of production data have been used in recognizing flow baffles and undeveloped compartments in the field. The full field 3-D model was constructed in such a way as to capture heterogeneities and the various compartments in the field. This was crucial to aid the simulation of fluid flow in the field for proper history matching, future production, prediction and design of well trajectories to adequately target undeveloped oil in the field. Reservoir property models (Porosity, Permeability and Net-To-Gross) were constructed by biasing log interpreted properties to a defined environment of deposition model whose interpretation captured the heterogeneities expected in the studied reservoirs. At least, two scenarios were modelled for the studied reservoirs to capture the range of uncertainties. This integrated approach led to the identification of bypassed oil in some areas of the selected reservoirs and an improved understanding of the studied reservoirs. Dynamic simulation and production forecast on the 4 reservoirs gave an undeveloped reserve of about 3.82 MMstb from two (2) identified oil restoration activities. These activities included side-tracking and re-perforation of existing wells. New wells have been drilled to test the results of our studies and the results confirmed our findings.
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Masoud, Mohamed, W. Scott Meddaugh, Masoud Eljaroshi, and Khaled Elghanduri. "Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205971-ms.
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Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.
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Tegelaar, Erik, Peter Nederlof, Chakib Kloucha, Osemoahu Omobude, and Haifa Al Harbi. "Reservoir Architecture and Fluid Connectivity in an Abu Dhabi Oil Accumulation." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206214-ms.
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Summary Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry. Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity. As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper: Assessment of vertical compartmentalization and fault transmissibility of four stacked reservoirs in a highly fractured zone. Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. Identify opportunities for production monitoring. Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas and water injection schemes that are simultaneously applied to this reservoir. In addition, fluid surveillance will help to predict water and/or gas breakthrough.
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Anshariy, A. "The Importance of Identifying the Evidence of Hydrodynamic Trapping for New Well Placement in Mature Offshore Stupa Field." In Digital Technical Conference. Indonesian Petroleum Association, 2020. http://dx.doi.org/10.29118/ipa20-g-93.
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To predict the hydrocarbon limit and new well placement for future development in the mature Stupa field, hydrodynamic trapping analysis is carried out to find a solution of “tilted” contact hypothesis. The static and dynamic data of 6 exploration wells and 12 development wells were used to recognize the evidence of hydrodynamic trapping. There are multiple pieces of such evidence for hydrodynamic trapping such as variation in fluid contacts, lateral reservoirs drainage and variation of water pseudo potential. This paper will describe identification of tilted gas – water contacts related to hydrodynamic trapping mechanism plays, to predict and map the tilted contact using “u” map as a limit of the field and how a tilted gas-water contacts map leads for opportunity to identify future well development. It is concluded that the hydrodynamic trapping is working in the Stupa field. A new limit of hydrocarbon accumulation as a result of tilted contact mapping using “U” map has significantly changed the field development strategy in the Stupa field. The West Stupa Panel has now become the new target location of future field development for prolonging the production life of the mature Stupa field. At the end of 2019, one development well was drilled at the north flank of West Stupa Panel and showed very good results, which unlocked the remaining gas potential of this panel. Following this positive result, 3 other wells are proposed to develop the remaining stakes in this panel. Identifying the evidence of hydrodynamic trapping and mapping the tilted gas – water contacts had opened new opportunities for further field development in flank areas of the mature gas Stupa field.
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Telmadarreie, Ali, Christopher Johnsen, and Steven L. Bryant. "A Novel Hybrid Solvent-Based Complex Fluid for Enhanced Heavy Oil Recovery." In SPE Western Regional Meeting. SPE, 2021. http://dx.doi.org/10.2118/200857-ms.
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Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).