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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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    Fatigue acid fracturing;; A method to stimulate highly deviated and horizontal wells in limestone formation

    Kunpeng ZhangMian ChenBing Hou
    13页
    查看更多>>摘要：As a fundamental technique to stimulate limestone formations, acid fracturing is now facing the problem of high fracture pressure. The fatigue damage in steel is a powerful strategy to reduce strength. And acidizing is the key step of acid fracturing and a useful tool to minimize limestone fracture pressure. Therefore, the combination of acid fracturing and fatigue treatment was investigated in this study. In addition, the interaction between acid fractures and calcite veins and weathering zones is still unclear. And the geometry of acid fractures in highly deviated wells hasn't been investigated in detail. Hence, there are three primary aims of this study;; 1. To investigate the specific performance of fatigue acid fracturing in the limestone. 2. To ascertain the interaction between acid fractures and calcite veins and weathering zones. 3. To clarify the acid fractures morphology in highly deviated wells. Based on the tri-axial acid fracturing system, a sequence of conventional acid fracturing and fatigue acid fracturing experiments were carried out in vertical, highly deviated, and horizontal wells. The experimental results demonstrate that fatigue acid fracturing effectively reduced the fracture pressure and weakened stress shadow effect. And the inclination degree is an influencing factor of fracture morphology complexity. The weathering zone and the calcite blocks had a noticeable impact on fracture propagation process. According to the experimental results, the fatigue acid fracturing will generate fresh insight into limestone formation stimulation treatments.
      原文链接:
    • NSTL

    A new correlation for accurate prediction of oil formation volume factor at the bubble point pressure using Group Method of Data Handling approach

    Mohammed Abdalla AyoubA. ElhadiDiab Fatherlhman
    15页
    查看更多>>摘要：Pressure-Volume-Temperature (PVT) crude oil properties play a significant role in reservoir evaluation and field planning. PVT properties are usually determined through laboratory experiments on representative fluid samples. However, during the preliminary stages of exploration and appraisal, such data might not be available;; hence, it is frequent to use empirical correlations to predict PVT properties. Oil formation volume factor (FVF) is one of the PVT properties used to convert the measured oil flow rate from surface conditions to reservoir conditions. In this paper, the Group Method of Data Handling (GMDH) has been used to predict the oil FVF at the bubble point pressure as a function of gas solubility, reservoir temperature, oil API gravity, and gas specific gravity. A total of 625 data sets were collected from published literature. Then, the data were divided into four sets;; training, validation, testing, and deployment, with the ratio of 2:1:1:1. The results of the proposed correlation are compared against seven other correlations used in the petroleum industry. Also, trend analysis has been performed to confirm that the proposed correlation is physically sound. From the results, the proposed correlation is proven to accurately predict the oil FVF at the bubble point pressure with an average absolute percentage error AAPE of 1.333% and correlation coefficient of 0.995 for the deployment set.
      原文链接:
    • NSTL

    Microscopy and image analysis of the micro-fabric and composition of saline rocks under different phaseCO2-Brine states

    Ameh PeterXiaoqiang JinXianfeng Fan
    17页
    查看更多>>摘要：Using different phaseCO2-brine, the effect of stress corrosion on the micro-fabric, topology of the minerals and the elemental composition of saline rock was evaluated, to understand how this affect transport properties of rocks. Image analysis was used to evaluate changes in micro-fabric, topology of mineral and elemental composition from SEM images. The micro-fabric of all the CO2 bearing samples changed significantly according to the different phaseCO2-brine. Grain roundness, grain smoothness, and pore smoothness increased after compression while the roundness of pores reduced. There was a significant change in the weight percentage of silicon, carbon and oxygen in the CO2-bearmg samples compared to the brine sample. Change in the shape, solidity and roundness of the pores led to a change in permeability of rocks by altering the tortuosity of the pores. This study provides an understanding of changes in micro-fabric and elemental changes occurring in saline CO2 storage sites under different possible phaseCO2~brine and highlights their implication for storage and properties of the rock.
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    • NSTL

    Capturing dynamic behavior of propped and unpropped fractures during flowback and early-time production of shale gas wells using a novel flow-geomechanics coupled model

    Pin JiaMing MaChong Cao
    20页
    查看更多>>摘要：Hydraulic fracturing has been widely used to exploit unconventional oil and gas resources for decades. The fracture closure during flowback and early production may be characterized by fluid dehydration and pressure drop in oil and gas production. In this paper, a fully coupled flow and geomechanics model is proposed to capture the dynamic behavior of key fracture parameters for flowback and early-time production. In this coupled model, the controlled volume method is used to numerically simulate the fracture flow, which can consider the geometry and conductivity distribution of the propped and unpropped fractures. For the fracture geomechanics, the joint-closure relationship is introduced to describe the fracture aperture of unpropped fracture. The empirical formula of effective normal stress and proppant parameters is applied to characterize fracture conductivity. The fracture aperture can be calculated coupled with the discontinuous displacement method (DDM) and the matrix transient linear flow. The coupled geomechanically model can consider the flow of the propped and unpropped fracture system, which is easy model-setup and convenient for practical application due to its excellent computational performance. Detailed flow behavior analysis shows that the aperture of the unpropped fracture is relatively slow during the fracture closure process. Compared with the fracture section opening under higher normal stress condition, the fracture section opening under lower normal stress condition has larger initial aperture and faster attenuation of aperture. The crucial fracture parameters, including fracture permeability and fracture length, can be well interpreted by matching flowback and production data. Furthermore, the relationship between fracture conductivity and effective stress for both propped and unpropped fractures can be explored. These new findings can also be applied to interpret reservoir/fracture properties from ChangNing shale fractured wells in China during flowback and early production.
      原文链接:
    • NSTL

    A new fluidics method to determine minimum miscibility pressure

    Frode UngarSourabh AhitanShawn Worthing
    9页
    查看更多>>摘要：Micro and nano-fluidic devices have attracted increasing attention in the oil industry. In this study, we designed a new slim-tube method to determine MMP on a microfluidic chip. Tlie design is significantly different from previous efforts on fluidics chips with an open flowing tube. The new design contains porous media similar to that found in the slim-tube apparatus. The objective is to produce a true multi-contact process in the gas displacement. We tested the new fluidics device at reservoir conditions with three reservoir oils displaced by two hydrocarbon gases and CO2 gas. For pressure lower than MMP, we observed noticeable reservoir oil remained after the injection gas had passed. For pressure higher than MMP, the miscible displacement front was developed. Behind the miscible displacement front, the oil saturation became negligible. We used a camera to detect the oil saturation after gas flooding for each pressure. MMP was determined at the high-resolution transition between miscible and immiscible pressures (similar to the slim-tube determination of MMP from the linear trendline intersection of miscible and immiscible pressures). The new fluidics method is a miniaturization of the slim-tube method on a microfluidic chip. All three microfluidic MMP tests of the selected oils displaced by hydrocarbon and CO2 mixtures generated very close results as that of the slim-tube tests with the same fluids. The new method has imminent business potential due to its reliability, visualization, low cost, low sample requirement, and fast turnaround. The MMP test threshold will be much lower than before, which will significantly benefit many gas-based EOR projects.
      原文链接:
    • NSTL

    A high-resolution numerical well-test model for pressure transient analysis of multistage fractured horizontal wells in naturally fractured reservoirs

    Hui LiuXinwei LiaoXiaoliang Zhao
    17页
    查看更多>>摘要：In this study, a high-resolution numerical well-test model based on hybrid discrete fracture methods for pressure transient analysis of multistage fractured horizontal wells in naturally fractured reservoirs is proposed. Given the complexity of gridding for a numerical transient model, a new type of hybrid grid system honoring complex geometries of high-velocity transient flow near wellbore and hydraulic fractures is developed. Meanwhile, the methods of identifying fracture intersections in 3D unstructured space, transmissibility corrections and stochastic fracture network generation algorithm are proposed to greatly improve the accuracy and efficiency of capturing the pressure transients in complex fracture networks. After comparison with the well-test software KAPPA, it shows that the model can not only accurately reproduce the complex 3D convergence of flow regimes but also has a much better computational performance. Then, the type curves of a multistage fractured horizontal well with complex fracture networks and the sensitivity analysis of nonuniform properties of fracture networks are developed and analyzed in detail. The results show that the early-time horizontal radial flow and dip are positively related to the properties of natural fractures, and the fluid contribution and pressure distribution mainly depend on fracture connectivity rather than fracture number. The orthogonal fracture connections can result in stronger fluid supply and less fracture interference. Besides, the fracture linear flow and first/second bilinear flow are mainly affected by hydraulic and natural fractures, respectively. Finally, it proves that the proposed model can be much more efficient than KAPPA in history match for well-test data by an actual fractured field case.
      原文链接:
    • NSTL

    Optimal waterflooding management using an embedded predictive analytical model

    Jadier AristizabalSergio CabralesAstrid X. Rodriguez
    12页
    查看更多>>摘要：In the petroleum industry, there is an ever-increasing interest in oil recovery processes with high hydrocarbon extraction rates. One of the most common oil recovery processes is waterflooding, which involves the injection of water into a reservoir. This process is often challenging, as there is uncertainty in the reservoir's properties. In this paper, we propose an optimal waterflooding management methodology for setting the producer and injector wells conditions to maximize the net present value (NPV). Our methodology integrates a predictive analytical model, which models the reservoir performance and forecasts the production rates based on the producer and injector well operating conditions. We applied the methodology in an illustrative example with rock and fluid properties representative from a Colombian oil field. We compared the proposed methodology against two benchmark scenarios in which the bottom-hole pressure of the producer wells is kept low and constant over time, as it is a common operational practice in the oil fields. With the proposed methodology, the profit increases by 27.02%, the oil recovery factor increases by 12%, and the water cut reduces by 4%, over a ten-year planning horizon.
      原文链接:
    • NSTL

    Experimental and numerical studies of rich gas HufF-n-PufFinjection in tight formation

    Desmond Batsa DorhjieElena MukhinaEvgeny Shilov
    17页
    查看更多>>摘要：Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huft-n-Puft experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huft-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diftusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Hufl-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.
      原文链接:
    • NSTL

    Characteristics of fluid inclusions and hydrocarbon accumulation period of Huoshiling-Yingcheng Formations in Wangfu fault depression, Songliao Basin, China

    Renxing LouLiwu WangLixian Wang
    9页
    查看更多>>摘要：With the advancement of technology and the improvement of the level of understanding, deep hydrocarbon exploration in the Songliao basin has become one of the key objects. Wangfu fault depression is a typical oil-gas fault depression with a high degree of deep hydrocarbon exploration in the southeast of the Songliao basin. Finding out the oil-gas accumulation period of the deep hydrocarbon exploration is of great practical significance. The aim of the study is to find out the period and time of deep hydrocarbon accumulation in Wangfu fault depression, so as to provide an important theoretical basis for deep hydrocarbon exploration. The objective is to reveal the process and track of deep hydrocarbon accumulation of Huoshiling-Yingcheng Formations based on the lithofacies characteristics and the homogenization temperature distribution characteristics of fluid inclusions, combined with the burial history and thermal history simulation of strata in Wangfu fault depression. The results show that the reservoir of Huoshiling-Yingcheng Formations in Wangfu fault depression have experienced at least two periods of oil and gas filling events and two periods of oil filling events. The first hydrocarbon filling event was formed in the middle of Quantou period (about 95.4-97.5 Ma). Being influenced by the hydrocarbon expulsion from the source rocks of Huoshiling Formation, a large-scale oil and gas migration was formed. The second filling event occurred in the early Qingshankou period (about 93.6-92.0 Ma). During this period, the lake of the Songliao Basin expanded extensively, and the oil migrated and recharged through the opening fault on a large scale. The third filling event occurred in the late Qingshankou period (about 88.9-90.8 Ma), during which the source rocks of Shahezi Formation were in the peak of hydrocarbon generation and a large number of hydrocarbon migration occurred. The last large-scale filling event occurred in the early Nenjiang period (about 85.8-84.0 Ma). Affected by the rapid expansion of the lake basin in this period, the fault fractures reopened, resulting in the secondary migration and filling of oil.
      原文链接:
    • NSTL

    Relationship between tight reservoir diagenesis and hydrocarbon accumulation;; An example from the early Cretaceous Fuyu reservoir in the Daqing oil field, Songliao Basin, China

    Chuang ErJingzhou ZhaoYangyang Li
    15页
    查看更多>>摘要：It is crucial to determine the sequence of reservoir tightening and hydrocarbon accumulation for analyzing the accumulation dynamics, oil migration mode, and oil distribution pattern of tight oil reservoirs. The tight sandstone reservoirs in the Fuyu reservoir occur in both the Daqing Anticline (DA) and Sanzhao Sag (SS), which were used as examples for the qualitative and semiquantitative analyses conducted herein. By integrating the porosity and permeability data, thin section imaging, cathode luminescence, scanning electronic microscopy, and energy dispersive spectra, the diagenesis processes including compaction, calcite cementation and replacement, illite precipitation, quartz overgrowth, and dissolution were analyzed. Typical diagenetic processes and successive orders were established to have occurred in the following sequence;; (1) compaction, early calcite cementation, and chlorite coating; (2) dissolution, quartz overgrowth, and kaolinite filling pores;; (3) late calcite cementation, calcite replacing feldspar, and quartz;; and (4) late illite (feldspar unitization). Utilizing fluid inclusion, isotopic analysis of C and O, and burial history, calcite cementation was determined to be related to the thermal decarboxylation of organic matter, showing that the dominant forming-temperature spanned 60°C~(-1)00 °C and that a large amount of calcite cement formed before the Middle-Nenjiang stage (the Early Campanian). Illite precipitation was determined to be related to feldspar illitization with a dominant forming temperature spanning 120°C~(-1)40 °C. The illite was mainly developed in the Late-Mingshui stage (the Late Campanian) in the DA. In the SS, illite was formed between the Late-Nenjiang stage (the Middle Campanian) and Late-Mingshui stage. The Fuyu reservoir experienced three-four periods of hydrocarbon charging, with the main charging period occurring in the Late Cretaceous (Late-Mingshui stage). The Fuyu reservoir became tight (porosity <12%) in the DA and SS in the Late-Mingshui and Late-Nenjiang stages, respectively. The formation of calcite and illite cementation and the tightening of the Fuyu reservoir occurred before the main hydrocarbon charging period, indicating that tightening occurred before oil accumulation.
      原文链接:
    • NSTL