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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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    The comparison of interface properties on crude oil-water and rheological behavior of four polymeric nanofluids (nano-SiO2, nano-CaO, GO and CNT) in carbonates for enhanced oil recovery

    Wenyue TangChangjun ZouHao Liang
    15页
    查看更多>>摘要：Nanoparticles (NPs) are currently being used in different areas of petroleum exploration and production, such as drilling, well logging, reservoir management, and enhanced oil recovery (EOR). Nanofluids, prepared from NPs, have been used as a novel flooding for EOR due to the excellent performance in altering interfacial properties and improving rheological behaviors. The properties of nanofluids vary with the structure of nanofluids. Nonetheless, most of the previous studies have focused on a particular type of nanofluid, the interfacial properties of various polymeric nanofluids and their flow behaviors under harsh and challenging reservoir conditions have been rarely reported or compared in literature. In this study, four polymeric nanofluids, prepared by mixing nano-silica (nano-Si02), nano-CaO, carboxyl functionalized graphene oxide (GO) and amino modified carbon nanotube (CNT) with partially hydrolyzed polyacrylamide (HPAM), were characterized through XRD, FT-IR, UV-Vis and SEM to confirm that the materials were successfully prepared. Then, the colloidal stability, interfacial tension (IFT) reduction, rheological behavior, and wettability on calcite surface of these polymeric nanofluids were also studied in comparison. The experimental results of CNT-NH2/HPAM nanofluid showed that the overlap degree of BS and ABS curves was high, oil/brine IFT reduced from 35.84 mN/m to 18.11 mN/m and the contact angle on calcite surface reduced from 139.69° to 47.985°, indicating that the nanofluids were colloidally stability, and both reduce the IFT and alter wettability effectively. Furthermore, the addition of SiO2 and CNT NPs enhanced the network structure significantly, and showed excellent rheological behavior of polymer solution with improved viscoelasticity. Finally, the CNT-NH2/HPAM nanofluid increased the additional oil recovery from 13.8% to 21.6% in core flooding experiments, with the oil displacement mechanism explained in detail. Therefore, the findings of this study can help for better understanding of the effect of NPs on polymeric nanofluids, and set the stage for future investigation into EOR application in carbonate reservoirs.
      原文链接:
    • NSTL

    Petroleum exploration portfolios generated with different optimization approaches: Lessons for decision-makers

    William C.P. LaCostaAlexei V. Milkov
    19页
    查看更多>>摘要：Petroleum explorers recognize the value of portfolio management, but many have not seen it effectively applied in the industry or do not understand how subsurface assessments by geoscientists link to portfolio analysis and decision-making by managers. Here, we constructed a fictitious but realistic inventory of 50 prospects distributed across plays of various maturity and then generated portfolios with rank and cut, efficient frontier and portfolio filtering approaches. Different analysis and optimization techniques have varying degrees of use and success in aligning portfolio selections with specific strategic goals and available drilling budget. Portfolios ranked and cut by mean risked volumes, economic probability of success (PoS) and expected monetary value can deliver good exploration results. However, they are sub-optimal when compared with similar efficient frontier portfolios optimized for expected total recoverable resource volume and its standard deviation. Portfolios ranked and cut by geological PoS values can deliver the greatest geological success rate among all portfolios, but not much resources and monetary value when the low-risk prospects have relatively small success-case volumes. Portfolio filtering helps find suitable alternative portfolios. Better portfolios include prospects from the emerging play setting characterized by greatest geological and economic PoS values and success-case volumes, but exclude high-risk prospects from frontier play settings. The formal portfolio optimization approaches are blind to the fact that companies have to drill high-risk frontier prospects to de-risk plays and provide access to prospects in emerging plays. Portfolio analysis and optimization techniques must be coupled with good understanding of exploration business and long-term strategy to deliver excellent sustainable exploration results.
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    An iteratively coupled model for flow, deformation, and fracture propagation in fractured unconventional reservoirs

    Harun RashidaOlufemi OlorodeChukwudi Chukwudozie
    17页
    查看更多>>摘要：The accurate and efficient modeling of hydraulic fracture propagation is required to design optimal hydraulic fracture jobs in fractured tight rocks. To this end, we propose and demonstrate the first fixed-stress coupling of pEDFM with XFEM to model hydraulic fracture propagation in naturally fractured reservoirs. This addresses the limitation of EDFM to low-conductivity fractures and is much faster than DFM and fully coupled schemes, which have mostly been applied to the modeling of fracture propagation in fractured reservoirs. The validation studies presented indicate the accuracy of our model at reproducing the analytical solutions to coupled geomechanics and fracture propagation problems. We show that the iterative coupling of pEDFM with XFEM accounts for the interaction between the propagating hydraulic fracture and low-conductivity natural fractures in its vicinity, whereas EDFM does not. This is important when modeling hydraulic fracturing and the subsequent production from multiply fractured hydraulic wells. The iterative coupling approach used in this work provides the flexibility and simplicity needed to model complex fluid and rock behaviors in unconventional oil and gas reservoirs.
      原文链接:
    • NSTL

    Modeling of subsurface sedimentary facies using Self-Attention Generative Adversarial Networks (SAGANs)

    Mei ChenShenghe WuHeather Bedle
    11页
    查看更多>>摘要：Understanding subsurface distribution features is crucial for reliable sedimentary facies modeling. Obtaining the distribution feature of complex subsurface sedimentary facies is challenging, especially non-stationary sedimentary facies which are location-specific, well-ordered, facies sequence (e.g., deltas). The application of machine learning algorithms has potential to assist with this imaging problem, particularly using the Generative Adversarial Networks (GANs) method. Recently, GANs have proven to be outstanding for unsupervised learning on complex distributions of training images. However, in most GAN-based model convolution processes, the information in a local area is computationally invalid for reproducing the global features of training images. To remedy this, we introduce an advanced Self-Attention Generative Adversarial Network (SAGAN) for subsurface geological facies modeling. Compared with the basic GANs, SAGANs introduce a self-attention mechanism to attain details from a long distance in the image, reproducing global features of training images. SAGAN case studies involve stationary channels and non-stationary delta facies. We use probability maps, variograms, connectivity functions, and visualization results to evaluate and compare our simulation realizations. For channel cases, SAGANs' realizations can reproduce different distributions of channels and point bars in different river systems. For the delta case, the SAGAN method shows a better ability to reproduce delta non-stationary characteristics than the MPS and basic GAN methods. All results are of high quality and diversity, reproduced the known geological sedimentary patterns, and compared with the basic GANs, SAGANs can better reproduce the global features of non-stationary training images. It is demonstrated that our first proposed SAGANs for geological facies modeling represent a powerful method for reproducing depositional facies distribution pattern.
      原文链接:
    • NSTL

    Reactivity of clay minerals of the Eocene Esmeraldas Formation rocks of the Middle Valley Magdalena Basin (Colombia) in brines and alkaline solutions

    Diana Carolina Lopez-SerranoEdgar Ricardo Perez-CarrilloCarlos Alberto Rios-Reyes
    16页
    查看更多>>摘要：The present work focused on understanding the interaction between clay minerals with alkaline fluids used in the oil industry. For this, a comparative study was conducted where the reaction of three rocks belonging to the Eocene Esmeraldas Formation was observed under two experiments. One of these tests consisted of a hydrothermal treatment at static conditions solutions with different concentrations of sodium hydroxide at different interaction times and constant temperature. In parallel, core-flooding tests were carried out, where the original conditions to which these rocks are subjected in the well were considered. Both the original and treated samples were examined by X-ray powder diffraction (XRPD) and Scanning Electron Microscopy (SEM) and the standard test method for Methylene Blue Index to determine the changes that these minerals underwent upon contact with high pH alkaline fluids. As a result, zeolite Linde Type A (LTA), sodalite (SOD) and cancrinite (CAN) formed after alkaline hydrothermal treatment under static conditions, which coincided with the dissolution of kaolinite and smectite. In contrast, core-flooding tests did not show the appearance of zeolites; but dissolution of smectite and kaolinite was observed, in addition to the appearance of an unidentified crystalline phase. The concentration of the alkaline solution and reaction time influenced the dissolution of clays. On the other hand, the cation exchange capacity (CEC) increased at lower concentrations and short reaction times in hydrothermal treatments, which is explained by the appearance of zeolite LTA. Core-flooding tests did not yield the same results as alkaline hydrothermal treatments. It is due to the continuous flow of the alkaline solution through the core plugs that did not allow the polymerization of dissolved aluminosilicate material.
      原文链接:
    • NSTL

    Prediction of major source rocks distribution in the transition from depressed to rifted basin using seismic and geological data: The Guyang to Linhe Formations in the Linhe Depression, Hetao Basin, China

    Chenxi LiZhen LiuShaochun Wang
    28页
    查看更多>>摘要：Source rock prediction in the Linhe Depression is exceptionally difficult owing to inadequate data, while the process by which depressed-rifted conversion influences source rock distribution remains unclear. Thus, this study aimed to predict source rock distribution and demonstrate its influencing factors. Based on outcrop, geochemical, well log, and seismic information, a seismic methodology involving the prediction of organic facies distribution using seismic facies analysis and mudstone thickness via a seismic velocity-lithology model was applied to predict source rocks. Our study showed the suitability of this method for early exploration in basins with inadequate data. The correlation coefficient between the predicted and borehole values of mudstone was 0.94, and the relative error was <14.6%. The optimal source rocks in the second member of the Guyang Formation were encountered in new wells JHZK9, LHC1, and JH14 and accurately predicted, thereby validating our methodology. Furthermore, optimal source rocks transitioned from broad to limited distributions, moved closer to the boundary fault, and transferred from gentle slopes to deep sags during the depression to rift period. This transition dominated the distribution of source rocks. The basin type restricted the location of source rocks, and the transfer of lacustrine centers played a leading role in the distribution and differential superimposition of source rocks. Additionally, differential compression influenced source rock thickness in the second member of the Guyang Formation, while segmented variations in the boundary fault style and activity rate influenced the thickness in the second member of the Linhe Formation.
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    • NSTL

    Characteristics of Cambrian tectonic-lithofacies paleogeography in China and the controls on hydrocarbons

    Zonngquan HuZhiqian GaoZhongbao Liu
    19页
    查看更多>>摘要：In early Cambrian, the earth was in a state of active super-continental disintegration, ocean basin expansion, and seawater transgression. It was a critical period for hydrocarbons source rocks development on a global scale. In China for example, hydrocarbons reservoirs, including conventional and unconventional, have been discovered in the Cambrian rocks. By using regional tectonic analysis, stratigraphic correlation, and lithofacies comparison, we compiled a tectonic-lithofacies paleogeographic map and determined the lithofacies paleogeographic characteristics of the main plates of the early Cambrian period in China. Our results show that although the North China Plate was deposited in shallow-water shore facies, it was later uplifted and exposed to long-term denudation; and thus, lacked the depositional conditions necessary to form hydrocarbon source rocks. In contrast, both the South China and the Tarim Plates contain the complete platform-slope-basin facies sequence, which is the required depositional conditions to promote the formation of hydrocarbon source rocks. Furthermore, our results demonstrate that, during the period of Meishucun and Qiongzhusi formations, South China Plate was composed of deep-water sediments. Correspondingly, during the sedimentation of the Yuertusi Formation, several areas such as the Kalpin, Tabei, and Taxinan in the Tarim Basin, formed a gentle-sloping continental shelf sedimentary sequence of phosphorous siliceous rocks, muddy shales, marlstones, and doloarenite. In addition, we demonstrate that (1) abundant nutrients provided by the hydrofhermal and coastal upwelling events, combined with the 'periodic anoxic' bottom water conditions, resulted in the formation of high-quality hydrocarbon source rocks in the Yuertus Formation in the Tarim Basin; and (2) the intracratonic sag and continental shelf edge slope settings controlled the deposition of hydrocarbon source rocks in the Sichuan Basin.
      原文链接:
    • NSTL

    Controlling factors of tight sandstone gas accumulation and enrichment in the slope zone of foreland basins: The Upper Triassic Xujiahe Formation in Western Sichuan Foreland Basin, China

    Jian DengMingjie LiuYongcheng Ji
    17页
    查看更多>>摘要：The accumulation and enrichment of hydrocarbon reflect different degrees of hydrocarbon charging, which is important for hydrocarbon exploration. In this study, we discuss the controlling factors of tight sandstone gas accumulation and enrichment of Xujiahe Formation in Jinhua-Zhongtaishan area, the slope zone of the Western Sichuan Foreland Basin, Southwest China, based on the analysis of the characteristics of the area's source rock, reservoir, and fault, combined with the tectonic background. This study shows that the accumulation and enrichment of tight sandstone gas in the slope zone of foreland basins are controlled by different factors. The natural gas derived from Xul Member is easily accumulated in Xu2 Member sandstone reservoir by vertical migration. The high quality source rock generated a large number of natural gas, which preferentially charge into the high quality sandstone reservoir and finally accumulate at the structural high position. The accumulation of tight gas is controlled by high quality source rock (source rock coefficient >10), high-quality reservoir (reserve coefficient >110), and favorable structure (high position of the local structure). When tight sandstone gas meets all prerequisites above for hydrocarbon accumulation, high content of total organic carbon (TOC) benefits enrichment of tight sandstone gas. In addition, the type I faults could be in favor of the natural gas from Xul Member to migrate to the upper part of Xu2 Member high quality sandstone reservoir, especially when the natural gas is generated by the middle and lower part of Xu1 Member high quality source rock, which could significantly improve the gas accumulation efficiency and promotes the gas enrichment and high production. In that case, the enrichment of tight gas is controlled by organic matter abundance of source rock (TOC >1.1%) and favorable source-reservoir communication conditions (the development of Type I faults). As a result, the areas with high-quality source rock and sandstone reservoir, favorable structure and migration pathway will be potential targets of tight sandstone gas in the slope zone of foreland basin.
      原文链接:
    • NSTL

    Aggressive ability improvement of self-resonating cavitating jets with double-hole nozzle

    Boshen LiuYang GaoFei Ma
    13页
    查看更多>>摘要：The aggressive ability of cavitating jets generated by a double-hole nozzle was investigated under an ambient pressure condition to improve the erosion efficiency for potential applications such as underground drilling. The erosion damage was experimentally investigated for a series of pitch-hole ratios to understand the erosion mechanism of the double-hole cavitating jets. The flow characteristics of various erosion patterns were numerically investigated using two-phase computational fluid dynamics (CFD) calculations. The stages of erosion suppression in the pitch-hole ratio range ω_p ∈ [1.25, 3] and erosion enhancement in ω_p ∈ [3.5, 6] were observed based on the mass loss △m across the entire range of standoff distance ratio l_s. Two erosion patterns were identified according to the erosion features, designated as A and B, with increasing standoff distance ratio l_s. Erosion occurs in multiple scattered regions in pattern A and which appears as two symmetric D-shaped regions in pattern B. In contrast to the single-hole jet, the aggressive ability was significantly improved a ω_p = 4.5 with higher △m peaks. Double-hole cavitating jets at the optimum pitch-hole ratio achieve the highest streamwise velocity and the weakest interaction between the two jets. The cavitation clouds in the impinging jets generated by the optimum pitch-hole nozzle primarily collapse in the D-shaped main erosion region, which enhances the erosion damage of the double-hole cavitating jets at the optimum standoff distance ratios.
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    • NSTL

    Research on well selection method for high-pressure water injection in fractured-vuggy carbonate reservoirs in Tahe oilfield

    Xin MaHaiTao LiHongWen Luo
    12页
    查看更多>>摘要：Carbonate fractured vuggy reservoir in Tahe oilfield belongs to fractured vuggy reservoir with strong heterogeneity. After a period of production, the elastic energy of the cave formation weakens caused insufficient liquid supply, It is faced with a series of problems in some single wells, such as low water injection efficiency, high water cut, short production period, and so on. The introduction of high-pressure water injection technology can greatly restore the productivity of single wells and improve reservoir recovery. It is one of the effective new technology to develop fractured vuggy carbonate reservoirs. At present, this technology is still in the initial stage, with no clear guide method that selecting wells for high-pressure water injection. Among them, the determination of the high-pressure water injection well selection method is particularly important for the development effect of a single well. Based on the analysis of the mechanism of high-pressure water injection and combined with the field data, this paper formulates the well selection method of high-pressure water injection from three aspects: Karst Characteristics, reservoir structure and reservoir parameters:①Karst geological data show the characteristics of oil-increasing substances such as many abnormal bodies around the well and wide lateral distribution; ②The reservoir structure has multiple sets of connected karst caves with connectivity potential; ③After the failure of conventional water injection, the fracture passage effect is poor and the energy of the remote well is insufficient. The independent high-pressure water injection development method can reduce the channel seepage resistance, expand the scope of the injected water, and realize increased production. Up to now, Tahe oilfield has used the method to implement high-pressure water injection 41 well, achieving an average single well cumulative incremental oil production of 3211 tons, with an effective rate of 85.4%, which has a satisfactory application value.
      原文链接:
    • NSTL