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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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    Hydraulic fracturing design for shale oils based on sweet spot mapping: A case study of the Jimusar formation in China

    Chunhua LuHanqiao JiangShiyuan Qu
    14页
    查看更多>>摘要：Multistage fracturing horizontal well is the main method of shale oil development. However, significant differences are observed between fracturing stages productivity due to reservoir heterogeneity. Therefore, it is necessary to incorporate reservoir heterogeneity characterization in hydraulic fracturing design so that ineffective clusters can be minimized. Taking the Jimusar formation as example, we apply an integrated fracturing design workflow that considers reservoir heterogeneity characteristics through sweet spot mapping to arrive at the optimum fracturing treatment. The geological and geomechanics models are constructed utilizing logs and core laboratory tests, from which the geological sweet spot (GSS) and engineering sweet spot (ESS) mapping are obtained. The GSS and ESS are later classified with respect to three different levels: type I (good), type II (medium) and type III (poor), based on which four sweet spot combinations are selected for fracturing design. Unconventional fracture model (UFM) is applied for the generation of complex fracture network, and performs productivity evaluation through reservoir numerical simulation. The simulation results suggest that to maximize the fluid withdrawal within stimulated region by reducing the productivity difference between stages, the fracturing scale of the stage containing type I GSS combination should be smaller than that of type II/III GSS in jimusar formation. And for regions with the same type GSS, the fracturing scale containing the type I ESS combination should be kept smaller than that of the type II/III ESS. The workflow will be helpful for the reservoir engineers in developing a reasonable fracturing plan that maximizes production performance or economic benefit for shale oil in future operations.
      原文链接:
    • NSTL

    Excellent source rocks found along the margin of a large lacustrine basin: Case study from the Ordos Basin, China

    Yubin BaiJingzhou ZhaoYanjie Huang
    16页
    查看更多>>摘要：Whether the Chang 6 oil pools of the Triassic Yanchang Formation in the Ansai-Yanchang (AY) oil province on the Yishan slope of the Ordos Basin formed from near source rock or far source rock has long been debated. An understanding of the source rock's position will impact the formation mode and distribution of accumulations in this area. Based on the geochemical data of the Chang 7 source rock in six wells and 18 crude oil samples, the geochemical characteristics of Chang 7 source rock and its relationship with Chang 6 crude oil were studied There are two types of source rocks, namely, black shales and dark mudstones, present in the AY area. The gross thickness of the Chang 7 black shale is 3.0-19.7 m, with a distribution area of 5500 km~2. It has an average total organic carbon (TOC) content of 3.34%, with a chloroform bitumen 'A' content of 0.512%, indicating good to excellent source rock potential. The kerogen assessment with core samples shows mixed type I-II_1, and has reached peak oil generation, maximum pyrolysis temperatures (Tmax) ranging from 445 to 458 °C. In contrast, the average TOC content of the dark mudstone in Chang 7 is 0.91%, chloroform bitumen 'A' is 0.079%, the main type of kerogen is type II_2-II_1, and Tmax varying from 446 to 461 °C, indicating only fair source rock potential overall. The Chang 7 source rocks in the AY area have a gammacerane index of 0.07-0.38, with an average value of 0.21, which reflects a low-salinity fresh to brackish water environment. The relative abundances of C_(27), C_(28), and C_(29) steranes are 29.7%, 23.1% and 47.2%, respectively, indicating that terrestrial higher plants and aquatic organisms provide similar contribution in the Chang 7 source rocks. Oils produced from the AY area of the Chang 6 member have similar geochemical signatures, but are significantly different from the Chang 6 crude oils in the Daozhen (DZ) area of Ganquan County and the Huaishuzhuang (HSZ) area of Fuxian County, which are located in the center of the lacustrine basin. They differ in terms of the maturity of the oil samples and the microscale composition of the parent material type. The closer the wells are to the center of the lacustrine basin, the higher the maturity of the source rock and the greater the contribution of aquatic organisms. The variation of carbon isotopic composition of Chang 6 crude oil in AY area is consistent with that of Chang 7 shale locally, but opposite to that of Chang 6 crude oil in DZ area. The ratios of nC_(21)~-/nC_(22)~+, tricyclic terpane/hopane and C_(29) sterane ββ/(ββ+αα) biomarker parameters of Chang 6 crude oils in AY area are similar to those of Chang 7 shale in local area, but deviate from those of DZ and HSZ area. These data results reveal that the Chang 6 crude oils in the AY oil province are dominated by the local Chang 7 excellent source rocks rather than by the long-distance migration of oils from the basin center.
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    Scale, origin, and predictability of reservoir heterogeneities in shallow-marine carbonate sequences: A case from Cretaceous of Zagros, Iran

    Hamzeh MehrabiBorhan Bagherpour
    18页
    查看更多>>摘要：This study presents an integrated reservoir heterogeneity analysis of an Iranian carbonate oil reservoir (Sarvak Formation) in the Zagros region. Both static and dynamic aspects of reservoir heterogeneities are considered by integration of routine-special core data and geological attributes (i.e., depositional facies and textures, diagenetic alterations, pore types, and sequence stratigraphic positions). Core porosity and permeability, mercury injection capillary pressure, and scanning electron microscopy data are used along with the results of petro-graphic studies to define petrographic rock types, pore types, hydraulic flow units, and reservoir to non-reservoir (baffle or barrier) zones in the studied reservoir. Spatial facies distribution (facies variability) and development of disconformable surfaces (sequence boundaries) controlled the large-scale reservoir heterogeneities. On the other hand, variations in microscopic characteristics of depositional facies (i.e., textures and structures) and diagenetic features (e.g., intensity of dissolution, cementation and compaction) formed the small-scale reservoir heterogeneities. The best productive zones of this reservoir are meteorically-dissolved reef-talus and shoal facies, accumulated within the regressive systems tracts of third-order sequences. Intensively compacted and cemented facies formed the effective vertical barrier/baffle zones in this reservoir, especially within the transgressive systems tracts and around the maximum flooding surfaces. Results of this study revealed that the stratigraphic modified Lorenz plot (SMLP) is a useful tool for the discrimination of large-scale reservoir heterogeneities, while hydraulic flow units and Winland rock typing approaches are applicable for the identification of small-scale heterogeneities. This study indicated that the large-scale heterogeneities of carbonate reservoirs are predictable in a sequence stratigraphic framework, especially in the third-order scale. Such a heterogeneity model calibrated in the sequence stratigraphic framework provides a reliable basis for reservoir modeling of heterogeneous carbonate reservoirs in the field-to regional scales.
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    • NSTL

    A novel approach by integrating the core derived FZI and well logging data into artificial neural network model for improved permeability prediction in a heterogeneous gas reservoir

    Nasser AlizdehNegin RahmatiAdel Najafi
    17页
    查看更多>>摘要：Predicting and extrapolating the permeability between wells to obtain the 3D distribution for the geological model, is a crucial and challenging task in reservoir simulation. Permeability is influenced by both digenetic characteristics and depositional factors like sorting and grain size. Hence, a reliable model should consider these characteristics for prediction of permeability. Grouping the rocks into different hydraulic flow units (HFU) or discrete rock types (DRT), improves the identity of the reservoir characteristics and provide a more accurate permeability prediction. Multi variable regression models and Artificial Neural Networks (ANN) were applied in this study to correlate core permeability and porosity with well logs to predict permeability logs. It was observed that the accuracy of the models diminished in heterogeneous reservoirs, where there is a wide permeability distribution. In this study, we are presenting a novel approach to predict permeability in heterogeneous oil and gas reservoirs. In this method the core permeability and porosity data are categorized using the concept of DRT and the probability density functions are used to investigate the relationships between the logs and DRT groups. The ANN model is applied to correlate the core derived flow zone indicator (FZI) with wire-line logging data with a single key well to predict K-logs. In this approach one single well, which contains all DRT groups is considered as a key well to develop and train the ANN model. It was observed that ANN model exhibits better prediction performance in heterogeneous reservoirs when it is developed and trained on single well data containing all DRT groups. This approach can capture heterogeneity in the reservoirs where it has been applied successfully to predict permeability in an actual heterogeneous carbonate gas reservoir.
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    • NSTL

    Effect of in-situ hydrocarbon generation over geochemical properties of the reservoired natural gas: A case study from the Ordos Basin, China

    Wenxue HanXia LuoShizhen Tao
    11页
    查看更多>>摘要：In a few wells, natural gas in the Permian Taiyuan Formation limestone (Pt-L) has the most depleted ethane carbon isotope. Saturated hydrocarbon gas chromatography (SH-GC), element and carbon isotope analysis of kerogen were conducted to investigate the source and sedimentation environment of the Pt-L, and its influence on the geochemical characteristics of gases. Compositions and carbon isotope values of gases produced in the Permian Taiyuan Formation limestone development area (Pt-LDA) were also studied for comparison with the Pt-L. The Pt-L is mixed source of marine and terrestrial provenance. The sedimentary environment is mainly reducing, which promotes the preservation of organic matter. Natural gas produced in the Pt-LDA is dominated by coal-derived gas generated from the Carboniferous-Permian coal strata. Gases from a few wells with more depleted carbon isotopic values may have generated from marine algae and bacteria in the Pt-L.
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    • NSTL

    Influence of the depositional environment on the formation of organic-rich marine shale: A case study of the first discovery of Anisian shale in the Sichuan Basin

    Fei HuoHuaguo WenLiang Li
    19页
    查看更多>>摘要：The Leikoupo Formation, which was deposited during the Anisian stage in the central Sichuan Basin, has produced significant amounts of conventional gas but there have been few studies on its unconventional resources. Organic-rich shale in the Leikoupo Formation was discovered for the first time in the wells of CT1 and JY1 in the central Sichuan region, but information on its sedimentary environment and climate evolution is scarce. A series of lithofacies, organic geochemistry and inorganic geochemistry analyses were used to analyse core samples of CT1 and JY1 to estimate their vertical changes. The organic matter characteristics, the sedimentary environment and the factors controlling the Leikoupo Formation shale in the Sichuan basin were revealed. The organic-rich shale of the Lei3-2 sub-member was formed in a semi-restricted lagoon environment. The sedimentary environment was dysoxic-anoxic, wifh high palaeoproductivity, a warm and humid to semi-arid and semi-humid climate. The vertical sea level decreased for a short period, led to an increase in oxygen content in the mixed shale, clayey shale and calcareous shale that were sequentially deposited from bottom to top. In the vertical direction, the palaeo-productivity and aridity decreased, and there was an increase in the salinity and terrigenous debris input. All of these corresponded well with TOC. According to Mo-TOC and Mo-U patterns, the mixed shale was characterised by the highest values of Mo_(EF), U_(EF) and Mo_(EF)/U_(EF), followed by clayey shale and calcareous shale, which indicated mixed shale was deposited in a moderately restricted water condition, which progressively became more restricted during the deposition of clayey shale and calcareous shale with the fall of relative sea level. Biomarker compounds (steranes, terpanes), Tmax and other pyrolysis parameters indicated that the organic matter had reached the stage of high-to over-maturity. The gammacerane to C_(30) hopane in the ratio indicated that it was the bottom water in which it was deposited was sratified.
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    • NSTL

    Injectivity and plugging characteristics of CO2-responsive gel particles for enhanced oil recovery in fractured ultra-low permeability reservoirs

    Dai-jun DuBin-yang ZouWan-fen Pu
    9页
    查看更多>>摘要：Although CO2-responsive gel particles (CRGP) injection appears to be a viable strategy for delaying CO2 breakthrough in fractured ultra-low permeability reservoirs, few studies have been conducted to thoroughly evaluate the injectivity and plugging characteristics of CRGP. In the present work, the swelling kinetics of the CRGP at various temperatures and salinities were first characterized through the change in CRGP volume. The rheology properties of CRGP dispersion solution were then evaluated. And then, taking the resistance coefficient, residual resistance coefficient and plugging rate as indexes, the effect of matching coefficient, injection rate, and injection concentration on CRGP injectivity and plugging characteristics was investigated using simulated artificial fractures. Finally, the empirical correlations of injectivity and plugging characteristics parameters were established. According to experimental result, the equilibrium swelling ratio of CRGP was greater than 40-fold at varied salinity conditions. The shear-thinning capabilities of the CRGP dispersion solution, as well as its favorable storage modulus, endowed CRGP with favorable in-depth migration and plugging properties. In addition, in terms of fracture plugging by CRGP, the plugging ratio of CRGP in fractures was higher than 90% when the matching coefficient ranged from 1.0 to 2.0, the injection rate was less than 0.5 mL/min, and CRGP concentration was larger than 3000 mg/L. The acquired empirical relationships were expected to guide the selection of CRGP size, injection concentration, and injection rate for fracture plugging.
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    Experimental investigation on the recovery performance and steam chamber expansion of multi-lateral well SAGD process

    Xiaohu DongJian WangHuiqing Liu
    12页
    查看更多>>摘要：Multi-lateral well SAGD process is a newly proposed recovery process in recent years, in which a multi-lateral well is applied to replace the horizontal well in classic SAGD process. In this paper, a three-dimensional physical model is applied to simulate the recovery performance of multi-lateral well SAGD process in heavy oil reservoirs. First, on the basis of Pujol-Boberg similarity criterion, the Forchheimers law is introduced to deal with the similarity of model permeability in 3D experiment. Thus, from the actual properties of Long Lake heavy oil reservoir, the lab scale experimental parameters are obtained. Then, by using a multi-lateral wellbore model, four scaled 3D SAGD experiments are performed, including one conventional dual horizontal well SAGD experiment (base case) and three multi-lateral well based SAGD experiments. From the experimental observation, the advantages of multi-lateral well are discussed from liquid production and steam chamber expansion. Finally, by the collected images, the distribution of residual oil saturation after SAGD process is also discussed. Results indicate that the introduction of Forchheimer's law can effectively handle with the problem of kinetic similarity damage caused by high permeability during a 3D experiment. Compared with the conventional dual horizontal well SAGD process, the application of multi-lateral well can increase the oil recovery factor by above 15%. To some extent, the application of multi-lateral well can increase the duration time of plateau stage or wind down stage. Simultaneously, compared with the single application of multi-lateral well in SAGD well pair, a dual multi-lateral well SAGD process has a higher expansion rate of steam chamber and a shorter recovery time. For steam chamber, under the dragging mechanism of branch wellbore, the shape of steam chamber is a 'inverted trapezoid' shape instead of the 'inverted triangle' shape for conventional dual horizontal well configuration. Under the effect of branch wellbore, steam chamber can effectively reach to the reservoir boundary and increase the volume of steam chamber. The residual oil saturation mainly distributed around the reservoir boundary, which is far from the main wellbore and branch wellbore. This paper further clarifies the EOR mechanisms and steam chamber expansion rules of multi-lateral well SAGD process.
      原文链接:
    • NSTL