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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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    Investigating heterogeneous distribution of fluid pressure in hydraulic fractures during pulsating hydraulic fracturing

    Yanan HouYan PengZhangxin Chen
    11页
    查看更多>>摘要：Pulsating hydraulic fracturing (PHF) has been proven to be a potential fracturing method. Compared with conventional hydraulic fracturing, the PHF can generate a more complex fracture network with lower breakdown pressure and less induced seismicity. A distribution of fluid pressure in hydraulic fractures determines the initiation and propagation of new fractures, which has not been fully investigated in the PHF. In this paper, a distribution of fluid pressure in pulsating hydraulic fractures is innovatively investigated through a transient flow model (TFM). This model is solved by the method of characteristics (MOC). This solution method is then verified against experimental data. Through this model, the mechanism of the pressure distribution is analyzed and the optimization method for PHF is proposed. The effects of input frequency, friction, fracture roughness and fracture length on the fluid pressure distribution during the PHF are investigated, respectively. Results show that the fluid pressure at each point along hydraulic fractures fluctuates in the same frequency, and the pressure fluctuation amplitudes are heterogeneously distributed in the hydraulic fractures during the PHF. This phenomenon results from the fact that a standing wave is formed in the hydraulic fractures during the PHF. Moreover, according to the number of wave nodes in the standing wave, the heterogeneous distribution of fluid pressure amplitudes can be divided into three categories for input frequency from 1 Hz to 20 Hz. The frequency ranges of these three pressure distribution categories are centered by three orders of resonance frequency, and the number of wave nodes for these three pressure distribution categories equals the order of resonance frequency. Although the standing wave in the hydraulic fractures is partially changed by a friction effect, the fluid pressure amplitude distribution is still heterogenous. In addition, the friction has a dissipation effect on a resonance amplitude. The increasing fracture roughness reduces the heterogeneity of a fluid pressure distribution in hydraulic fractures during the PHF. The first maximum fluid pressure amplitude near a fracture entrance may not exist for high fracture roughness. Finally, the effect of the heterogeneous distribution of fluid pressure on the initiation and propagation of new fractures during the PHF is addressed, and then a novel and effective design method of input frequency and amplitude for the PHF is proposed. Multiple initiations of new fractures can be obtained by optimizing an input frequency and amplitude.
      原文链接:
    • NSTL

    A criterion for a hydraulic fracture crossing a frictional interface considering T-stress

    Dijie ZhuWeisheng Du
    9页
    查看更多>>摘要：Hydraulic fracturing has been widely used to stimulate oil and gas production from low permeability reservoirs. However, the geologic discontinuities, such as natural fractures, joints, and bedding planes, can significantly affect the propagation direction of the hydraulic fracture. Considering the effect of the non-singular stress term of Williams' series expression for stress field near the fracture tip (i.e., T-stress), an analytical criterion for a hydraulic fracture crossing a frictional interface (such as the natural fracture and bedding plane under compression-shearing) was proposed. The present criterion was validated by comparing it to the published experiments, and the effect of T-stress on the propagation of the hydraulic fracture crossing a frictional interface was analyzed by comparing the present criterion to the published criteria. The results show that the accuracy of the present criterion depends on the difference in geomechanical properties of the rock on either side of the interface. The effect of T-stress on the hydraulic fracture propagation can be divided into the facilitation and the inhibition, which depend on the intersection angle between the hydraulic fracture and the frictional interface. No matter what the intersection angle between the hydraulic fracture and the frictional interface is, the effect of T-stress can inhibit the change of propagation direction when the hydraulic fracture crosses the interface.
      原文链接:
    • NSTL

    Productivity model with mechanisms of multiple seepage in tight gas reservoir

    Jingang FuYuliang SuLei Li
    13页
    查看更多>>摘要：The productivity model with unilateral threshold pressure gradient, real gas effect or non-Darcy effect has been documented in the research of tight gas reservoir. However, the multiple seepage mechanisms are poorly addressed in a productivity model, especially the application of gas-water relative permeability curve changing with the displacement pressure. A novel productivity model of multi-stage fractured horizontal wells with mechanisms of multiple seepage was proposed the present study. Results show that the stress effect has a negative effect on the effective permeability, while the Knudsen diffusion effect of gas has a positive effect. The water flow can inhibit the gas flow in the tight gas reservoir, whose effect is more significant with larger displacement pressure differences. The higher initial water saturation and reservoir temperature, whereas the lower gas well productivity, contribute to a high gas well productivity in the reservoir of high pressure.
      原文链接:
    • NSTL

    Determination of miscible CO2 flooding analogue projects with machine learning

    Tolu A. OlukogaYin Feng
    17页
    查看更多>>摘要：Using analogue reservoirs for comparison and benchmarking is a comprehensive method for ensuring accurate measurement and gaining a better understanding of potential oil recovery enhancement prospects. The approach of leveraging information from analogue reservoirs is extended to CO2 EOR project management in this study. We present a novel application of machine learning clustering algorithms to the rapid identification of analogues for new projects without having to sift through massive amounts of data. We use machine learning clustering methods to group successfully executed miscible CO2 flooding projects into clusters of projects with similar fluid/reservoir characteristics and to identify analogues for new target projects. Porosity, permeability, oil gravity and viscosity, reservoir pressure and temperature, minimum miscibility pressure (MMP), and depth were all input parameters. Data from nearly 200 miscible CO2 EOR projects around the world were clustered using the Agglomerative Hierarchical Clustering Algorithm (HCA), K-Means, and K-Median techniques. To reduce information redundancy in high-dimensional data, Principal Component Analysis was used as a pre-processing step. Three evaluation indices (the Davies Bouldin, Calinski Harabasz, and Silhouette Coefficient Scores) were used to compare the efficiency of the clustering algorithms and choose the best one for this dataset. A Principal Component-weighted Euclidean distance similarity metric was computed using three existing miscible CO2 flooding projects (Weyburn, Hansford Marmaton, and Paradis) as test cases to confirm the clustering results. The clustering analysis identified five different classes of miscible CO2 projects, each with its reservoir and fluid characteristics. Type 1 projects, in general, are those that are carried out primarily in shallow carbonate reservoirs at the lowest temperatures and pressures of any database project with typical porosity and permeability. More than 60% of Type 2 projects are in sandstone reservoirs. They are at shallower depths with lower temperatures, pressures, porosities, and permeabilities than project Type 4. Type 3 projects are typically undertaken in carbonate reservoirs with medium depths and temperatures but the highest reservoir pressures. This project type has medium porosity and permeability. In comparison to project Type 2, Type 4 primarily consists of projects conducted in sandstone formations at great depths with high reservoir temperatures and pressures. The porosity and permeability of these project types are average. Finally, Type 5 projects are typically undertaken in sandstone formations at average depths, temperatures, and pressures, but with the greatest porosity and permeability of all project types. In addition to the clustering analysis, the distance similarity metric used in this work identified projects that were most like the test miscible CO2 flooding project cases. Key rock and fluid properties, well types, and best infill drilling strategies, recovery improvement strategies, and production performance can all be learned from identified analogue projects. This data can be used to improve the operational, technical, field, and well-planning decisions for new CO2 flooding projects. The workflow demonstrated in this paper is easily adaptable to data sets from other flooding projects.
      原文链接:
    • NSTL

    Experimental study on the effect of different distributed interlayer on SAGD performance

    Shihao WeiYonggang DuanMingqiang Wei
    12页
    查看更多>>摘要：The Steam-Assisted Gravity Drainage (SAGD) technology is acknowledged in the development of heavy oils worldwide because of its high efficiency. This study is based on the Long Lake reservoir with large-scale interlayers in geovlogy. Firstly, a 3D experiment was built to evaluate the existence of different distributed interlayers on the performance of SAGD technology in consideration of its geology conditions. Our experiment investigated the effect of the equivalent area of interlayers on the behaviour of the steam chamber. The experiments were grouped into three scenarios, i.e., a) no interlayer, b) quarter-length-covered interlayer, and c) half-length-covered interlayer. The experiment observations demonstrate that the steam chamber expanding would be obstructed by the designed interlayers and then go around both sides of the interlayer to reach the top of the reservoir. The steam chamber would extend out along the top surface of the reservoir and go down until the end of production. It means that the existence of a different distributed interlayer can prolong the steady-production period and reduce the production of this period. Referring to scenario a, the EUR in scenarios b&c is decreased by 4.7% and 7.3%, respectively. Moreover, the longer distributed interlayer obstacle the propagation of the steam chamber significantly. The steady-production period in scenario c should be more extended than scenario b. Also, scenario c exhibited lower production and ultimate recovery. This study is helpful for the understanding of the effect of SAGD development on the different distributed interlayers and guiding the placing of wells on site.
      原文链接:
    • NSTL

    Simulation and experimental investigation of dielectric and magnetic nanofluids in reduction of oil viscosity in reservoir sandstone

    Surajudeen SikiruHassan SoleimaniAfza Shafie
    11页
    查看更多>>摘要：High demand in the reduction of viscosity of heavy oil from reservoir sandstone has been a great interest with the applications of electromagnetic (EM) assisted for the enhanced oil recovery. Therefore, the conversion of EM waves properties into the reservoir region must be taken into consideration and the interaction between the reservoir fluids and the solid phases. In this study, the rheological and adsorption effect of Fe3O4, ZnO, Al2O3 SiO2 and CuO at high temperature and pressure on reservoir sandstone have been simulated using Biovia material studio and experimentally investigated with the effect of electromagnetic waves. The measurement of the viscosity are at a different shear rate for dielectric and magnetic nanofluids. The viscosity of the crude oil varies over a range of shear rates (100~(-2)000 s~(-1) ) and temperatures (25~(-1)20 °C), the crude oil exhibited extremely high viscosity at a low shear rate and low temperature, and gradually drifts to lower viscosity at the reservoir conditions (2000 s~(-1) ~(-1)19 °C). It was revealed from the result that Fe3O4 Nanofluid exhibits better performance compares to ZnO, and AI2O3 at a high shear rate (2000,1500, and 1000 s~(-1) ) at reservoir condition. Nanofluid shows Newtonian behavior with an increase in shear rate and the viscosity of the oil decrease with an increase in temperature. As the dispersion of the particles increases, the interactions between the components of sandstone crude Oil and nanoparticles also increased, that favors viscosity reduction which in turn increase the fluid mobility.
      原文链接:
    • NSTL

    An innovative graphene-supercapacitor for the treatment of crude oil viscosity at low temperatures

    Amna M. Al-MuftiRaheek I. IbrahimManal K. Oudah
    7页
    查看更多>>摘要：The key idea is to reduce the Iraqi crude oil viscosity, and enhance its rheological properties during its pipeline transportation at low temperatures. To achieve this objective, four different graphene supercapacitor designs are tested, by the application of various electric field intensities as;; 14 V cm~(-1) ,18 V cm~(-1), and 22 V cm~(-1), and the addition of three different graphene concentrations as;; 0 wt%, 25 wt%, and 50 wt%, at temperatures;; 1.5 °C, 0 °C, and-3 °C performed on 31 °API crude oil. The optimum conditions are found using Statistica software as;; 22 V cm~(-1) for electric field intensity and 36.9 wt% for graphene addition. The results at these optimum conditions showed a dynamic viscosity reduction by 54.6%, 64.8%, and 73.7%, at 1.5 °C, 0 °C, and-3 °C respectively. While causes mass flow rate improvement by 26.7%, 37.5%, and 55.3%, at 1.5 °C, 0 °C, and-3 °C respectively. The viscosity reduction lasts for about 11 h before the viscosity builds up again.
      原文链接:
    • NSTL

    Experimental insight into the silica nanoparticle transport in dolomite rocks;; Spotlight on DLVO theory and permeability impairment

    Amin KeykhosraviMohammad SimjooPavel Bedrikovetsky
    12页
    查看更多>>摘要：Nanoparticles (NPs) have been proposed as a promising agent for groundwater aquifer remediation, greenhouse geological storage, and enhanced oil recovery (EOR) applications. Nevertheless, in many of these cases, NPs applications require long transport distances, which may be limited by NPs retention in porous media, especially at high saline conditions as is the case with some oil reservoirs, causing a reduction in rock permeability and subsequent formation damage. Therefore, understanding of NPs transport through porous media and their stability behavior are significant challenges before their large-scale applications, which has been less explored in previous works. This paper investigates silica NPs transport through dolomite rocks, which are the host rocks of many sub-surface reservoirs. To this end, the stability of silica nanofluids with different concentrations in the presence of different ionic strength and ion types was explored by zeta potential measurement and particle size analysis. NPs adsorption on rock surface was examined by SEM images. The DLVO analysis was conducted to determine the interaction energies between NPs and the rock, and investigate the reversibility of NPs adsorption on the rock. Single-phase coreflooding experiments aided by NPs effluent analysis were performed to obtain breakthrough curves. Results indicated that increasing silica NPs concentration from 0.1 to 0.5 wt% leads to a reduction in nanofluid stability in which the average size of silica NPs increased from 110 to 220 mn. Higher ionic strength (50,000 ppm) decreased nanofluids stability and this negative effect was more pronounced for nanofluids containing MgCl2 salt. It was found that less stable nanofluids showed higher NPs retention through porous media. Highly stable nanofluids exhibited a higher probability of NPs to be detached during the brine post-flushing stage. As to the results of silica nanofluid injection in dolomite rock, increase of the silica NPs concentration and decrease of their stability in suspension were two causes of the rock permeability impairment;; a 10% reduction in rock permeability was observed by 0.1 wt% salt-free silica nanofluid, whereas it decreased by 87% using 0.5 wt% of saline nanofluids prepared by 50,000 ppm MgCl2. According to the interpretations based on the deep bed filtration model, the higher salinity of nanofluid is, the higher filtration coefficient would be, meaning that the higher rate of particle capture at higher salinities. Also, no internal/external filter cake was formed and instead, the pore filling process was found to be the major mechanism of the permeability impairment by silica NPs.
      原文链接:
    • NSTL

    Distribution of a water film confined in inorganic nanopores in real shale gas reservoirs

    Jingang FuYuliang SuZhangxing Chen
    12页
    查看更多>>摘要：Distribution of the water film and initial water saturation within inorganic nanopores of shale are key problems for the evaluation and prediction of recoverable gas resources. Numerous research on the distribution and quantitative characterization of water film confined in nanopores have been conducted to the present. However, quantitation of water confined in inorganic nanopores of shale gas reservoir still remains challenging due to the complexity of porous media and reservoir conditions. In the present study, a novel model with disjoining pressure, interfacial tension and real gas effect taken into consideration, was proposed to disclose the distribution of water film confined inside circular or elliptic pores. In addition, the phenomena of capillary condensation and partial condensation have been revealed in elliptic pores. The proposed model was verified by comparing the calculation results with data from previous paper. Results show that the capillary condensation behavior of the water film is remarkably affected by the real gas effect. Water condenses easily into water films under the actual gas reservoir conditions, especially for small pores. However, the interfacial tension and high temperature can inhibit the formation of the water film in the confined space at a nanometer scale. Finally, the partial condensation is more likely to occur at both ends of elliptic pores.
      原文链接:
    • NSTL

    Partial fractional differential model for gas-liquid spontaneous imbibition with special imbibition index;; imbibition behavior and recovery analysis

    Chenggang XianCaoxiong LiYinghao Shen
    12页
    查看更多>>摘要：Hydraulic fracturing technology is widely used for developing hydrocarbons in tight unconventional formations, such as tight sandstone and shale. A considerable amount of liquid is imbibed spontaneously into the matrix during and after hydraulic fracturing. Unlike the strongly water-wet matrix, the gas-liquid spontaneous imbibition behavior in tight matrix is special, that the volume/mass of imbibed liquid is not always proportional to the imbibition time's power of 0.5. Thus, providing a new model is important to meet the special imbibition behavior in tight matrix. This work extends the previous gas-liquid spontaneous imbibition model on strongly water-wet matrix (such as Handy's model) and provides a new model considering special liquid imbibition and diffusion behavior when the imbibition index is not equal to 0.5. Typical solutions for imbibed liquid volume and saturation distribution are provided. The solutions can match well with experimental data. The results indicate that typical influencing factors, such as viscosity, imbibition index, and the style of imbibition front have special influence on imbibition process. Some possible mechanisms about the specialty on imbibition index in tight matrix are discussed. This work provides a more general imbibition model for describing spontaneous imbibition with special imbibition index, which may be helpful for imbibition analysis within shut-in period after hydraulic fracturing in tight formation in field.
      原文链接:
    • NSTL