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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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    Modeling study on supercritical CO2 fracturing applicability and capacity to stimulate reservoirs with different permeabilities

    Jianming HeZhaobin ZhangGuanfang Li
    14页
    查看更多>>摘要：Hydraulic fracturing (HF) using water-based fluids is an effective approach for reservoir stimulation in the exploitation of unconventional resources. Recently, supercritical carbon dioxide (S-CO2) has been proposed as a prospective fracturing fluid in reservoir stimulation because it exhibits higher fracturing capacity compared with water-based fracturing fluid. However, S-CO2 appears to have a distinct drawback of intensifying leak-off when used in reservoirs with relatively high rock matrix permeability (RMP). In this work, a modeling study on water fracturing and S-CO2 fracturing (SCF) was implemented in reservoirs with varied RMPs to assess their applicability. In the modeling, the natural fracture system in the reservoir was considered through the discrete fracture network method for simulating different reservoirs. The lower viscosity and density of S-CO2 compared with those of water enable the easier fracturing of reservoir rocks and allow the generation of more complex fracture networks. However, the intensifying leak-off of S-CO2 due to fracture propagation can hamper the build-up of hydraulic pressure and affect fracture propagation, especially in reservoirs with relatively high RMP. The inflection of fracture length development during HF can also reflect the impact of fluid leak-off Permeability determines the final fracture network of SCF, and the injection rate increase can offset the leak-off to a certain extent; however, the improvement in fracturing results becomes limited. The modeling results clearly demonstrate the importance of RMP, which can directly determine the applicability and capacity of SCF.
      原文链接:
    • NSTL

    Gas-phase production equation for CBM reservoirs: Interaction between hydraulic fracturing and coal orthotropic feature

    Zheng SunBingxiang HuangYisheng Liu
    11页
    查看更多>>摘要：The efficient development of coalbed methane (CBM) reservoirs entails the accurate evaluation of production behavior, particularly for the gas phase performance. However, subjected to complexity arising from the coal inherent heterogeneous properties and dynamic gas-water two-phase flow, pursuit of high prediction accuracy remains challenging. Although massive excellent contributions have been devoted to addressing this issue, several key factors fail to be captured, and in-depth analysis is lacking, involving coal orthotropic feature, as well as associated interaction with hydraulic fractures. In light of the current knowledge status, the research has developed a robust gas-phase productivity equation for CBM wells, putting the emphasis on the coupling influence from coal orthotropic feature as well as hydraulic fracture. Also, gas-water two-phase flow mechanism is captured by incorporating the relationship between pressure and fluid saturation in coal cleat system. Moreover, traditional factors are considered as well, including gas desorption, stress dependence, matrix shrinkage. Numerical simulation is utilized to clarify the reliability of the proposed equation at the stable state, and desirable agreements can be achieved. Results show that (a) Augment effect, induced by enlarging intersection angle, on gas production rate is evident, and the calculation case suggests the optimized angle is 90°, requiring further investigations; (b) The inherent orthotropic feature acts the detrimental role for gas production performance, and fortunately hydraulic fracturing, treated with suitable intersection angle, is able to alleviate the influence; (c) Gas desorption ability lays the profound basis for evaluation of the CBM development, supposed to be selected as the prominent index for the favorable target development area.
      原文链接:
    • NSTL

    Predicting fracture vertical growth containment using the width-induced net stress

    Vibhas J. PandeyVamegh Rasouli
    16页
    查看更多>>摘要：The vertical growth of hydraulic fractures in layered formations is important from treatment-placement and well performance perspective. Most numerical fracture simulators generate fracture geometries by accounting for the in-situ stress and rock mechanical properties, along with key parameters related to fracturing fluids such as rheology and leakoff behavior, amongst various other critical parameters that can influence the outcome. Although the results from various simulators are generally reasonable, the fracture height estimates can vary significantly even for identical input data sets as shown in the literature. Because of the limitations of these simulators, some of the field observations, such as containment of fracture height growth across certain interfaces of contrasting material properties or weak interfacial bonding, are not replicated effectively, unless such an interface is predefined. In this study, the influence of fracture width on resultant stresses is incorporated in the calculation process while solving for vertical growth of hydraulic fractures. For this purpose, a modified equilibrium height growth model previously developed by the authors is used. The effects of viscous fluid movement in the fracture are also included in the calculation scheme. The outputs from the model were compared with the field-derived fracture heights that were inferred from micro seismic (MS) surveys conducted on various fracturing treatments that included both vertical and horizontal wells completed in layered formations. The analysis revealed a close agreement between the model-predicted and observed values of fracture height. While the authors acknowledge that predicting the containment of vertical growth of fracture across a plane is a challenging task given the complex nature of the problem, the paper discusses a method that offers a simpler approach to predicting the sites that may act as a constraint to the fracture growth during the stimulation treatments. This can aid in well-placement planning, perforation strategy, and hydraulic fracturing treatment design. The model can be readily deployed or incorporated in existing simulators.
      原文链接:
    • NSTL

    Fast-running model for high-volume hydraulic fracturing

    Aleksandra Peshcherenkollmir BekerovDimitry Chuprakov
    35页
    查看更多>>摘要：We develop a rapid simulator of hydraulic fracture growth in complex geologic layered conditions and extensively drilled multistage fractured wells in a reservoir. The simulator allows running independent simulations for thousands hydraulic fractures within a minute on modern personal computers. The model is meshless and has a simplified rectangular fracture shape; however, coupling all conventional hydraulic fracture mechanics equations makes the model accurate enough. We demonstrate it via comparison with exact analytical solutions in limiting toughness-, viscosity-, and leakoff-dominated regimes, as well as via comparison with other commercial simulators on real field cases. Field validation of the model by temperature log measurements is also provided. To demonstrate the practical implications of the model for reservoir engineering, we show several examples of numerical simulations for a huge number of hydraulic fractures in a reservoir, which interact with each other due to the closeness of stimulated wells and perforation clusters. Rapid simulations allow obtaining the field-scale simulations of fracture growth in the range of a minute and efficiently building distributions of asymmetric fracture growth both in length and in height. We show that the stress shadow effect causes undesired outbreaks to adjacent gas-or water-saturated geological layers if the fracture placement in a reservoir is dense enough. Even small spatial misalignment of stages in the offset wells may result in changes of geometry of transverse fractures growing from neighbored wells. Vertical true vertical depths mismatch in offset wells; their deviations in the dip and azimuth angles are shown to cause the asymmetry of fracture growth as well, which hardly can be predicted in field development workflows without rigorous fracture simulations. Examples of longitudinal fracturing in horizontal wells demonstrate the strongest distortion of conventionally assumed lateral symmetry and height growth similarity of fractures created in one horizontal well. Our simulations also show that these results are affected by the viscosity of pumped fracturing fluids. The presented model of field-scale interactive fracture growth in a reservoir enables finding the best fracture placement characteristics and pumping schedule for the needs of field development with hundreds to thousands of fractures in a short time frame.
      原文链接:
    • NSTL

    Architecture of strike-slip fault zones in the central Tarim Basin and implications for their control on petroleum systems

    Ziyi WangZhiqian GaoTailiang Fan
    19页
    查看更多>>摘要：The strike-slip fault zones (SSFZs) of the central Tarim Basin have great potential for hydrocarbon exploration and development. They can both serve as hydrocarbon migration paths and host hydrocarbons. However, the complexity of SSFZ varies significantly along the fault strike, and strike-slip fault-controlled deeply buried carbonate reservoirs are often extremely heterogeneous, increasing exploration risks. Here, we reconstructed the architecture and setting of the SSFZ of the central Tarim Basin and analyzed the complex and heterogeneous hydrocarbon system that characterizes this exploration area. The integrated seismic and well datasets show that the development of SSFZs has led to the fracturing of tight carbonates and enhancements in the karstification process, secondary porosity and permeability due to the presence of open fractures. Based on the vertical height of the fault in the section and continuity, the SSFZs in the central Tarim Basin have been classified as 1st-order or 2nd-order faults. The 1st-order faults are found in the repeatedly reactivated vertical SSFZ, which is composed of sub-vertical strike-slip faults in the Paleozoic strata and en-echelon normal faults in the shallow layer. The 2nd-order faults develop only in Paleozoic strata without reactivated features. Continuous through-going, hard-linked lst-order faults are a more valuable target for future exploration than soft-linked 2nd-order faults because lst-order faults control larger-scale fracture-cavity reservoirs, and their fault activity periods correspond to hydrocarbon accumulation periods. We classified damage zones as wall-, and linking-damage zones, based on their location around the fault. There are two types of linking-damage zones, extensional steps and contractional steps, which develop in the extensional and contractional quadrants of the fault segment, respectively. Linking-damage zones are associated with more structural complexity than narrow and straight wall damage zones. Fractures in the contractional steps are generally closed and have low conductance, which is not suitable for fracture -cavity trap formation and hydrocarbon migration. Because opening-mode fracture development and permeability enhancement are greatest at the extensional steps, these locations are more likely to be important foci for strike-slip fault-controlled carbonate reservoirs. Our findings, in combination with previous research, indicate that fault zones in the central Tarim Basin, act as combined conduit-barrier systems, with damage zones typically featuring highly conductive fracture networks and fault cores acting as seals, resulting in heterogeneous reservoir distributions.
      原文链接:
    • NSTL

    Geochemistry and accumulation of petroleum in deep lacustrine reservoirs: A case study of Dongying Depression, Bohai Bay Basin

    Rongzhen QiaoZhonghong ChenChenyi Li
    18页
    查看更多>>摘要：Numerous volatile oil reservoirs and condensate gas reservoirs were discovered in the Member 4 of Shahejie Formation in the Paleogene system, northern Dongying Depression of Bohai Bay Basin, eastern China. Deep reservoirs were examined thoroughly, including biomarker, light hydrocarbon, and diamondoid in oil; composition and carbon isotope in natural gas; fluid inclusion: and thermal history. Based on diamondoid parameters, the equivalent vitrinite reflectance (EqVRo) of the crude oil ranges from 1.55% to 1.82%, indicating a state of high to over maturity, while the low absolute concentration of methyl diamantanes indicates that the oil is still in the early cracking stage. The deep gas is a mixture of kerogen degradation gas generated from hydrocarbon source rocks and oil cracking gas produced from the reservoirs. The EqVRo of gas is mostly between 0.8% and 1.3%, which is in a moderately mature state. The oil and gas are sourced from Member 4 of the Shahejie Formation, which was formed in a saline and reductive environment with a main input of I-II algal organic matter. The kerogen degradation gas was generated in the late sedimentary period of Member 2 of the Shahejie Formation, which was the first stage of petroleum charging. The early oil and gas reservoirs underwent noticeable evaporative fractionation due to the invasion of oil cracking gas after entering the late period of the Guantao Formation in the Neogene, resulting in the formation of the present volatile and condensate oil and gas reservoirs.
      原文链接:
    • NSTL

    Sedimentological and diagenetic impacts on porosity systems and reservoir heterogeneities of the Oligo-Miocene mixed siliciclastic and carbonate Asmari reservoir in the Mansuri oilfield, SW Iran

    Elnaz KhazaieYaser NoorianMojtaba Kavianpour
    20页
    查看更多>>摘要：The Asmari Formation is largely affected by some diagenetic processes such as dolomitization. fracturing, and dissolution in the Mansuri oilfield. These features have commonly caused the development of different types of porosities, resulting in various pore throats throughout the reservoir rock units. In this study, the porosity system and pore throat radius were considered as the main characteristics to separate the reservoir rocks into different units with distinct petrophysical attributes. Consequently, two petrophysical methods that have the direct link with pore throat and geometry including pore throat radius at 35% of non-wetting saturation using Winland equation (R35) and hydraulic flow units using flow zone indicator (FZI) were employed to define different rock types (RT) based on their pore system. The results of the current study show that the contribution of dolomitizing fluids to precipitation of dolomite crystals and dissolution of precursor limestone compositions resulted in prevailing various porosities and pore types. This study reveals that reservoir quality decreases from rock units dominated by dolomitization and dissolution overprints (e.g., RT-1) due to improvement in connectivity between pore networks, while some particular diagenetic features such as cementation (evaporite and calcite) occluded pore throats and then decline reservoir quality in their host rock units (e.g., RT-4 and RT-5). Afterward, distribution of RTs, throughout reservoir zones proposes that the middle part of the reservoir demonstrates higher reservoir quality compared to the upper and lower part of it. Occurrence of selective (e.g. intercrystalline and intergranular) and non-selective (fracturing and vuggy) porosities in middle parts promoted reservoir quality, while domination of isolated pores (e.g., moldic and intraparticle) in upper part decreases reservoir quality.
      原文链接:
    • NSTL

    Evaluation of tight waterflooding reservoirs with complex wettability by NMR data: A case study from Chang 6 and 8 members, Ordos Basin, NW China

    Zhihao JiangZhidi LiuPeiqiang Zhao
    11页
    查看更多>>摘要：After long-term water injection, many developed oilfields in the Ordos Basin, China, have entered a period of the high water-cut stage. In waterflooded layers, formation water is a mixture of injected water and primary formation water. The variation of formation water salinity will significantly affect the evaluation of reservoirs using resistivity logging curves while having little effect on the NMR response. It lays a foundation for identifying fluid type and evaluation of waterflooding grade by NMR logging. However, in waterflooding layers with mixed wettability, the NMR T2 responses are still complicated and unclear. In this paper, the tight sandstone samples with different wettability of Chang 6 and Chang 8 members of Triassic Yanchang Formation in the Ordos Basin are used to investigate the NMR experiments under three saturation states: water-saturated state, oil displacing to bound water state (abbreviated as oil flooding) and water flooding to the residual oil state (abbreviated as water flooding). Results show that the distributions of standard T2 spectra, without an external gradient magnetic field, of the water-saturated state in mix-wetted samples is very close to that of after oil flooding. Thus, the standard T2 spectra will be hard to distinguish the oil layer, water layer, and waterflooded layer of mix-wetted reservoirs. The diffusion coefficients of water and oil in pores differ, resulting in different shift T2 spectra results under gradient magnetic field. Therefore, the shift T2 spectra with the external gradient magnetic field and different echo time TEs were calculated and measured. When the echo time TE = 3.6 ms is adopted, the T2 signal of water-saturated tight rock samples will be nearly distributed less than 100 ms with magnetic field gradient G = 18 G/cm, rather the T2 signal greater than 100 ms is the oil signal. This characteristic makes the shift T2 spectra outstanding in the fluid identification of tight reservoirs with complex wettability. Finally, based on this experiment, a residual oil index based on the shift T2 spectrum is constructed to evaluate the flooded grades of tight waterflooding reservoirs. The evaluation results are consistent with the core description and oil test results in the study infilled wells.
      原文链接:
    • NSTL

    The mechanism analysis for hemiwicking on spontaneous imbibition in tight sandstone based on intermingled fractal model

    Caoxiong LiChenggang XianHongkui Ge
    12页
    查看更多>>摘要：Tight sandstone has relatively low permeability, with various mineral pores. Hemiwicking on micro-nano pore walls is special, which will finally influence the imbibition behavior. Commonly, in traditional strongly water-wet-matrix-based imbibition model ignored the important influence of hemiwicking on imbibition process. In this work, intermingled fractal method is introduced to represent the tight sandstone based on the experiment data. Then a novel imbibition model is built considering hemiwicking, main meniscus imbibition and dynamic wetting in matrix. The model is verified by experiment data. Finally, the mechanisms of hemiwicking is discussed. It shows that hemiwicking is very important when investigating the special imbibition behavior in tight sandstone. This work provides a novel revised imbibition model for gas-liquid spontaneous imbibition, which may be helpful for imbibition analysis within shut-in period after hydraulic fracturing in tight formation in field.
      原文链接:
    • NSTL

    Al-driven foam rheological model based on HPHT foam rheometer experiments

    Ahmed BinGhanimMurtada Saleh AljawadZeeshan Tariq
    16页
    查看更多>>摘要：Foam has many applications in the oil and gas industry, either in hydraulic fracturing, enhanced oil recovery, or drilling operations. The success of these operations depends largely on understanding the behavior of foam rheology, which is complex. The literature contains many models used to estimate the effective bulk foam viscosity: most were based on fitting parameters estimated from limited-experimental data. Nevertheless, the fitting parameters are not valid at different operating conditions such as temperature, pressure, and shear rate. This results in models with limited applicability as the laboratory conditions are hardly replicated. In this study, we generated 360 data points of effective bulk foam viscosity using the high pressure high temperature (HPHT) foam rheometer device. A wide range of conditions was examined, such as temperature, pressure, shear rate, foam quality, and composition. The gas-phase consisted of either CO2 or N2, while four types of water representing different salinities were used in the liquid phase. The foam was generated using seven different commercial surfactants at different concentrations. Also, low pH chelating agent and corrosion inhibitor were added in some experiments. The data pool was analyzed using four machine learning techniques: Artificial Neural Network (ANN), Decision Trees (DT), Random Forest Regressor (RFR), and K-Nearest Neighbor (KNN). ANN showed the highest accuracy with R~2 of 0.972 and 0.985 on the training and testing datasets, respectively. Also, the relative importance of features was examined using Pearson. Spearman, and Kendall correlation coefficients. The most significant parameters in reducing foam viscosity were temperature, corrosion inhibitor, and shear rate, respectively. On the contrary, foam quality positively impacted the foam viscosity, where 80% foam quality was the maximum tested condition. The impact of pressure, surfactant concentration, water type, and chelating agents were complex. This paper provides a simplified ANN-based model which can be used on the fly to predict the effective bulk foam viscosity in both laboratory and field conditions.
      原文链接:
    • NSTL