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Journal of Petroleum Science & Engineering
Elsevier Science B.V.
Journal of Petroleum Science & Engineering

Elsevier Science B.V.

0920-4105

Journal of Petroleum Science & Engineering/Journal Journal of Petroleum Science & Engineering
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    Development of a method for adjusting rock compaction parameters and aquifer size from production data and its application to Nam-Su fractured basement reservoir of Vietnam

    Le Ngoc SonPhan Ngoc TrungMasuda, YoshihiroMurata, Sumihiko...
    12页
    查看更多>>摘要：The Nam-Su is a major naturally fractured basement reservoir (FBR), offshore Vietnam. To date, simulation models of Nam-Su FBR have failed to give an adequate history match without invoking the presence of large aquifers. In a previous study (Son et al., 2007), the authors investigated several possible alternatives to achieve a satisfactory history match. They modeled porosity reduction by compaction along with the change of aquifer size and produced an improved history match that is consistent with the geological nature of the system. The key to such modeling is reservoir rock compressibility. Estimating the values of rock compressibility from cores is a challenge in FBR's due to the failure of coring from a naturally fractured interval, and thus reliable values are not available. We developed a computer-assisted history matching method to resolve these two problems together and save significant time compared to the manual trial-and-error methods used to adjust these parameters generally used in Vietnam. The methodology developed has been applied successfully to determine rock compaction coefficients and adjust aquifers' sizes of the Nam-Su FBR. Comparisons between our adjusted model and the existing model show considerable improvement between computed and measured values. Simulators can always be adjusted to obtain a history match even with geologically unrealistic values. The approach outlined here is more physically realistic than existing approaches and hence should provide/provides better production and other forecasts.
      原文链接:
    • NSTL
    • Elsevier

    Geological storage of CO2 and acid gases dissolved at surface in production water

    Pearce, J. K.Khan, C.Golding, S. D.Rudolph, V...
    14页
    查看更多>>摘要：During geological CO2 storage traditionally CO2 is injected subsurface into a high permeability reservoir capped by a low permeability seal to trap the buoyant supercritical plume. Wastewater from oil and gas production is also currently disposed of by subsurface injection into suitable reservoirs, most notably in the USA and Canada. Injection of CO2 dissolved in water may both increase storage security by reducing vertical migration and enhancing dissolution and mineral trapping. There is potential for surface dissolution of CO2 into wastewater that is already being stored subsurface. CO2-water-rock reactions in different sandstone or limestone reservoir rocks with either saline coal production water or low salinity water were geochemically modelled. The geochemical potential for mineral trapping of CO2, and associated changes to pH for potential reservoirs is compared. For a mineralogically clean quartz-rich saline sandstone reservoir only 0.18 and 0.20 kg/m3 CO2 was mineral trapped as ankerite and calcite over 30 or 1000 years. Feldspars, clays and carbonate minerals were converted to kaolinite, calcite, ankerite and smectites, as pH increased to 5.65. The specific silicate minerals present controlled mineral trapping potential e.g. with an Fe-rich chlorite present rather than a clinochlore chlorite 6.3 and 6.8 kg/m3 CO2 was trapped at 30 and 1000 years respectively as siderite and ankerite. Disso-lution trapping dominated in the low salinity or limestone reservoirs with minor mineral trapping. The presence of small amounts of SO2 or H2S in the CO2 stream resulted in dissolved S sequestered as elemental S, pyrite, barite, and anhydrite. The effects of low CO2 content or potential reservoir cooling induced by injection fluids were also investigated. The low pH of the injection fluid could potentially corrode legacy wellbores, one solution is a form of amendment such as liming to neutralise pH.
      原文链接:
    • NSTL
    • Elsevier

    Modeling of microflow during viscoelastic polymer flooding in heterogenous reservoirs of Daqing Oilfield

    Zhong, HuiyingHe, YuanyuanYang, ErlongBi, Yongbin...
    10页
    查看更多>>摘要：Viscoelastic polymer flooding has been extensively used in oilfield development as an enhanced oil recovery method. Understanding the microflow mechanism is necessary to promote the polymer displacement effect and design the polymer flooding scheme. Previous studies have investigated polymer flooding mechanisms, such as a favorable mobility ratio and increasing sweep efficiency; however, the elasticity effect on displacement efficiency is still unclear, particularly in a heterogeneous reservoir. Class II reservoirs, which have an effective thickness between 1 and 4 m and a permeability greater than 100 mD, have recently become the target zones of polymer flooding in the Daqing Oilfield. Class II reservoirs are subdivided into type A and B oil layers. Compared with the type A oil layer, type B has a larger permeability contrast, more severe heterogeneity, and worse connectivity. There are considerable differences between types A and B in the actual development of polymer flooding as well as between type B oil layers of different oilfield blocks. Thus, it is necessary to investigate the factors that influence the micro-oil displacement mechanism. In this study, local and global micro-pore models are established based on a computed tomography scan slice of Class II reservoir cores, and mathematical models of the viscoelastic polymer and oil two-phase flow in porous media are established. The log conformation method is used, which can effectively enhance convergence, owing to a high relaxation time inducing high non-linear of equation. The volume-of-fluid method is used to track the interface between the two phases. The governing equations are solved using the OpenFOAM platform, which is open-source software written in C++. Then, the influences of pore structure and polymer elasticity on displacement characteristics are studied. The simulation results revealed that owing to the pore structure, the micro-oil displacement efficiencies of B_GI and B_PII, which belong to the type B oil layer, are lower than that of A_SIII, which belongs to type A, by 26.8% and 10.9%, respectively. The oil displacement efficiency of a commingled production comprising B_PII and B_GI is 4.0% and 15.6% lower than that of single-layer productions of B_PII and B_GI, respectively. The oil displacement efficiency increases by 6.45% when the relaxation time increases from 0.5 to 2 s and decreases when the relaxation time increases from 2 to 10 s. Therefore, by combining the micro-oil displacement efficiency and injectivity of a high-molecular-weight polymer, the optimum relaxation time is determined to be 2 s. The obtained results are significant for the design strata of a commingled production scheme and the optimization of polymer solutions in the type B oil layer of the Daqing Oilfield.
      原文链接:
    • NSTL
    • Elsevier

    Oil-water interactions in porous media during fluid displacement: Effect of potential determining ions (PDI) on the formation of in-situ emulsions and oil recovery

    Shapoval, ArturAlzahrani, MohammedXue, WenjiaQi, Xiang...
    10页
    查看更多>>摘要：Emulsification is a naturally occurring phenomenon during the multiphase flow. The amount of emulsion, its composition and rate of degradation can significantly affect the flow properties and subsequent oil recovery. In addition, fluid-fluid interactions were suggested as a controlling mechanism for enhancing the oil recovery by modified salinity brines. In this study, we have used high-resolution microtomography to visualise emulsions formed in heterogeneous carbonate rocks by seawater and ion-tuned brines. Additionally, interfacial tension and emulsion stability were studied in a laboratory environment to develop further understanding of the effect of naturally occurring (in absence of surfactant agents) in-situ emulsions on Enhanced Oil Recovery (EOR) at porescale. Our results show that emulsions that are formed in pores have varying compositions depending on pore geometries, wetting properties of the rock surface and ionic composition of the injected brines. In-situ emulsification has shown to be a contributing factor to the oil recovery enhancement, however, other mechanisms, such as wettability alteration plays an important role. Emulsion cluster sizes show log bimodal distribution and injection of ion tuned brines mostly contribute to improving the connectivity between the clusters and subsequent sweep efficiency of the waterflooding.
      原文链接:
    • NSTL
    • Elsevier

    Investigation of pore-throat structure and fractal characteristics of tight sandstones using HPMI, CRMI, and NMR methods: A case study of the lower Shihezi Formation in the Sulige area, Ordos Basin

    Wu, YupingLiu, ChenglinOuyang, SiqiLuo, Bin...
    15页
    查看更多>>摘要：The evaluation of pore-throat structure is essential for the exploration and exploitation of tight oil and gas reservoirs. In this study, various experiments such as casting thin section (CTS), scanning electron microscope (SEM), mercury intrusion porosimetry (MIP), and nuclear magnetic resonance (NMR) are used to investigate the pore-throat structure and fractal characteristics of the tight sandstone from the Permian Shihezi Formation in the Sulige area, Ordos Basin. The type and size of tight sandstone pores and throats are qualitatively analyzed by using CTS and SEM. However, the structural parameters such as the size and distribution of tight sandstone pores and throats are quantitatively calculated by HPMI, CRMI, and NMR. According to the advantages and disadvantages of each method, the HPMI and NMR are combined to characterize the full-size pore-throat distribution (PSD) of tight sandstone. Based on the fractal theory, the fractal dimensions (D) of pore-throat of tight sandstone are evaluated by HPMI, CRMI, and NMR. The result shows the pores in the tight sandstone are mainly residual intergranular pores, dissolution pores, and inter-crystalline pores. There are few micro-cracks developed, and the throats are mainly tubular and curved sheets. The full-size PSD curve of tight sandstone presents the characteristics of the bimodal and unimodal distribution. It has a good agreement with petrophysical properties and movable fluid saturation. Different experimental methods can get different D. HPMI and NMR have different detection ranges and diverse principles for pore-throat evaluation, making sandstone's diverse fractal characteristics. The CRMI is more representative for studying the fractal characteristics of the throat. Moreover, there are two different types of throats: large throat and small throat. These throats have a double fractal feature. The relationship between D and the physical properties analyzes the parameters of the pore-throat structure, suggesting larger the D, the worse the physical properties of the reservoir. The development of the throat (especially the larger throat) controls the storage and fluid flow-ability of tight sandstone reservoirs. Mercury saturation, movable fluid saturation, and D are negatively correlated, indicating that the complicated pore-throat structure will reduce permeability and destroy the free fluid storage space.
      原文链接:
    • NSTL
    • Elsevier