首页期刊导航|Journal of Petroleum Science & Engineering
期刊信息/Journal information
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
正式出版
收录年代

    Classification methods of conglomerate reservoirs based on the adsorption and retention law of surfactant-polymer binary systems

    Fengqi TanWentao LiuChunmiao Ma
    10页
    查看更多>>摘要：Factors such as clay minerals and micropore structure can lead to the adsorption and retention of chemical agents when the components of surfactant-polymer systems enter porous media. This study aims to clarify the influence of adsorption and retention of surfactant-polymer components on reservoir permeability and oil displacement efficiency and then classify the reservoirs into types. The natural cores of conglomerate reservoirs from the Badaowan Formation in the 7th block are selected as research objects to reveal the adsorption law of surfactant-polymer components on different minerals and different micro pores through the dynamic oil displacement method based on physical model and the N element calibration method. Experimental results show that the adsorption capacity of clay minerals for surfactant-polymer components is significantly higher than that of carbonate and skeleton minerals, and different clay minerals differ in adsorption capacity for surfactant-polymer components depending on their cation exchange capacity and end surface adsorption activity. In addition, the adsorption and retention capacities of reservoirs for surfactant-polymer components are closely related to the type and content of clay minerals. The combination type of clay minerals controls the adsorption activity of surfactant-polymer components, and the values of polymer and the surfactant are quantitatively calculated to be 11.3 and 21.4 mg/g, respectively. The adsorption strength of surfactant-polymer components is controlled by the content of clay minerals. With increasing clay content, the adsorption strength of the polymer ranges from 0.5 to 2.5 mg/cm3, and that of the surfactant ranges from 1.0 to 4.5 mg/cm3. On this basis, the "N element calibration method" is used to determine the occurrence state and content of chemical agents in micropores for different permeability samples after surfactant-polymer binary flooding. Research results show that the polymer and surfactant components mainly have two types of occurrence form in micropores, including the complex pores accumulated by clay minerals and the intersections of small pores and throats. With decreasing reservoir permeability, the number and content of detected N element gradually increase, indicating an increase in the adsorption and retention of polymer and surfactant, and the influence on the reservoir seepage capacity also increases. Finally, the conglomerate reservoirs in the Badaowan Formation from the 7th block are divided into four types after considering the influence of clay minerals and micropore structure on the adsorption and retention of surfactant-polymer components, and the reasonable classification of reservoir types can effectively enhance the oil recovery of surfactant-polymer binary flooding.
      原文链接:
    • NSTL

    Reconstruction of oil charging history in the multi-source petroleum system of the Beidagang buried-hill structural belt in the Qikou Sag, Bohai Bay Basin, China;; Based on the integrated analysis of oil-source rock correlations, fluid inclusions and geologic data

    Chuanzhen ZhuWenzhe GangXianzheng Zhao
    16页
    查看更多>>摘要：The Beidagang buried-hill structural belt (BBHSB), located in the central part of the Qikou Sag, Bohai Bay Basin, hosts a multi-source and structurally complex petroleum system, in which the interpretation of oil-source relationships and the definition of hydrocarbon accumulation features are challenging due to the highly variable composition of oils and complex oil migration pathways. In this study, we use biomarkers, fluid inclusions, and geologic data to address the complexities of petroleum system analysis in BBHSB. Based on hierarchical cluster analysis, four genetic groups of oils (A, B, C and D) with distinct molecular compositions were identified. Group A, B, and C oils are originated from the source rocks in the third member (ES3) of the Eocene Shahejie Formation (Es), the lower (Es1~X) section of the first member (Es1) of Es, and the middle (Es1~Z) section of Es1, respectively. Group D oils are mixed oils contributed by the source rocks of Es1~X and the second member (ES2) of Es. Bounded by geological settings, the charging histories of the four groups of oils were different. Fluid inclusion analysis suggests that Group A oils have two charging stages, i.e., the late Oligocene and the Pliocene-present. During the first stage, Group A oils mainly accumulated in ES3 with relatively low maturity. During the second stage, the Group A oils vertically migrated along the fault in a large scale, resulting in its accumulation in the middle-shallow formations near the fault. Due to the late maturity of source rocks, Group B, C, and D oils have one accumulation stage that occurred during the Pliocene-present. Due to the blocking effect of the reverse drag anticline on the migration of oils to the fault, the accumulation of Group B and C oils were limited to inner source-layers and the distribution of Group D oils in the northeastern BBHSB was limited in Es1~X.
      原文链接:
    • NSTL

    Comprehensive workflow to quantify diagenetic cement from wireline logs of deep water east coast of India wells and rock physics modeling

    Shantanu ChakrabortySamit MondalRima Charterjee
    12页
    查看更多>>摘要：Presence of diagenetic cement is common in deep-water siliciclastic reservoirs and largely affects reservoir quality. Hence, the quantification of cement volume is an integral part of the reservoir characterization workflow. Lab analysis of core samples provides the cement volume information used as input for rock physics modeling. In the absence of core sample analysis, use of analogous offset well information provides an approximate estimate of cement. In reality, most deep-water wells do not have core samples for lab analysis. Consequently, the availability of offset well information is sparse and sometimes unavailable. Hence, getting an accurate cement volume estimate for reservoir characterization is challenging. For a detailed analysis, it is desirable to have a continuous measurement of cement volume across the reservoir sand. Presence of a calibrated cement volume log for the entire reservoir improves rock physics modeling. In this work, petrophysical M-N lithology cross plot, which is widely used to identify lithologies, has been used to quantify the diagenetic cement present within the reservoir, where M is the density normalized sonic values and N is the density normalized neutron values. Here, the M and N has been used as M-Lithology (MLITH) and N-Lithology (NLITH). In estimating MLITH and NLITH values, compressional sonic, bulk density and neutron logs are used. Porosity estimated from neutron/density is useful to identify the type of cement. Whereas, sonic slowness values are more sensitive towards the amount of grain contact cements. Hence, the estimated values of MLITH and NLITH varies differently in the presence of diagenetic materials. These variations of MLITH and NLITH values are captured and converted to cement volume fractions. In the presence of core data, the lab analysis measurements are used to calibrate the cement volume log. Further, rock physics modeling results helps to validate the output. The results of the study add value by quantifying diagenetic cementation in the reservoir characterization process by mitigating the associated limitations due to absence of sufficient core data.
      原文链接:
    • NSTL

    A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran

    Shervin Bahramali Asadi KelishamiReza MohebianOmidreza Salmian
    15页
    查看更多>>摘要：Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poro-perm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro-porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 μm) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.
      原文链接:
    • NSTL

    The impact of thermal ageing on sealing performance of HNBR packing elements in downhole installations in oilfield wellhead applications

    Farzaneh HassaniRyan NishNadimul H. Faisal
    11页
    查看更多>>摘要：Hydrogenated nitrile butyl rubber (HNBR) elastomers are highly resistant to chemicals and degradation, and they are good candidates to be adopted in aggressive environmental conditions of high temperature and pressure. As these service parameters are common in oil and gas applications, HNBR is popular in applications such as elastomer packers in wellhead installations. This study investigated the thermal ageing behaviour of HNBR elastomers to better predict the long-term sealing performance of the packers. Elastomer compounds were thermally aged and FTIR-ATR and differential scanning calorimetry techniques were used to indicate dominant chemical reactions during ageing. Furthermore, the mechanical performance of the aged compounds were studied to investigate the effect of dominant ageing reactions on performance. It was indicated that crosslinking reaction was dominant in the ageing process of HNBR compounds up to 150 °C. This resulted in increased stiffness and alleviated elongational strains at the break. However, compounds behaved brittle at ageing temperatures above 150 °C, and from the thermal analysis, it was concluded that at those temperatures chain scission reactions overtook the ageing mechanism. Finally, an approach for life-long prediction of mechanical characteristics of the specimens showed while long-term ageing promotes elastic failure, ageing temperatures above 150 °C facilitate rupture because of the brittle response of the compounds.
      原文链接:
    • NSTL

    Rheological study of CO2 foamed chelating stimulation fluids under harsh reservoir conditions

    Murtada Saleh AljawadIbrahim KadafurAhmed BinGhanim
    11页
    查看更多>>摘要：Foamed acid is usually an HCl acid-based stimulation fluid applied to carbonate reservoirs. However, this study investigates the rheology of a CO2 foamed chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA), that acts as less corrosive, environmentally friendly, and more stable foamed acid. Foam rheometer and analyzer were used to study the foam rheology, quality, size and structure, and half-life. Five different commercial surfactants with different chemical structures were investigated. The study was conducted at 100 °C, 1000 psi, 3.5 pH level, and various water salinity, resembling harsh reservoir conditions. The general trend showed that the higher the water salinity, the higher the effective viscosity. It also showed that the chelating agent improved the effective viscosity of the high total dissolved solids (TDS) water samples. The highest viscosity (76 mPa ? s) was attained by mixing GLDA with a cationic alkyl diamine derivative surfactant in formation water at a 100 1/s shear rate. The prolonged constant shear rate experiments revealed that some formulations are stable for more than 8 h. The study revealed that higher surfactant concentrations did not result in improved performance. For the first time, the study reveals that chelating agents could be used as a stable stimulation foamed fluid at harsh reservoir conditions.
      原文链接:
    • NSTL

    Multi-task learning for digital rock segmentation and characteristic parameters computation

    Siqi JiRongang CuiDanping Cao
    15页
    查看更多>>摘要："Image-and-compute" is the key paradigm of digital rock physics (DRP), the two main processes are relatively independent. Deep learning algorithm has been well applied in the field of digital rock image processing and numerical computation, but the models of different tasks are lack of correlation, and there is still a large space to improve the accuracy and efficiency. Multi-task learning algorithm can integrate image processing and numerical computation technology into the same model and share effective information of different tasks, which has great significance to simplify the workflow of DRP and improve the computation accuracy of the model. A distributed multi-task learning neural network (DMTNN) is designed by simulating the working sequence of DRP, which can accomplish digital rock image segmentation, petrophysical and elastic parameters computation simultaneously. DMTNN adopts the strategy of series connection and parallel connection between tasks, the segmentation and petrophysical parameters computation tasks provide intuitive low-level features as auxiliary information to improve the accuracy of abstract high-level targets. Moreover, a dynamic weight strategy is applied to solve the problem of unbalanced convergence caused by mutual interference between tasks in the training process. In order to verify the effectiveness of the proposed method, six different open source sandstones are used to form the training-set and testing-set. The results show that the average pixel accuracy (PA) of DMTNN's segmentation task is 0.97, the R2-score of porosity, shear modulus and bulk modulus can reach 0.92, 0.74 and 0.79 respectively. Furthermore, another completely untrained digital rock data is selected as the cross-dataset, in order to verify the robustness of the proposed model. The results show DMTNN in cross-dataset;; the PA of segmentation task can reach more than 0.95, and the relative error of the elastic parameters computation tasks are lower than the traditional CNN.
      原文链接:
    • NSTL

    Spontaneous generation of stable CO2 emulsions via the dissociation of nanoparticle-aided CO2 hydrate

    Seunghee KimAmin Hosseini ZadehMichael Nole
    8页
    查看更多>>摘要：This study finds that CO2 hydrate dissociation spontaneously generates fine-textured emulsions or foams, and that the phase state of CO2 which was used to form hydrate determines the stability of the emulsion or foam when hydrate is dissociated in an aqueous dispersion of hydrophilic silica nanoparticles. This process suggests an energy-efficient method of generating stable emulsions for high-pressure applications without a need for mechanical energy input. We proved experimentally that the CO2 hydrate phase could be used to generate foams and emulsions because the hydrate formation process naturally disconnects a hydrate guest molecule phase from the bulk water phase. During dissociation, easy adsorption of nanoparticles at CO2-water interfaces hinders the coalescence of bubbles. As a result, CO2 emulsions or foams were generated upon the completion of hydrate dissociation. The CO2 emulsions generated remained fairly stable, while the CO2 foams generated became unstable and the buoyant force of the CO2 bubbles led to their coalescence. The concepts experimentally proven here could be applicable to any suitable clathrate compound undergoing a solid to a liquid phase transition.
      原文链接:
    • NSTL

    Zoeppritz-equations-based amplitude variation with angle inversion for Russell fluid factor in a gas-bearing reservoir

    Zijian GeXinpeng PanJianxin Liu
    15页
    查看更多>>摘要：Fluid identification is vital to the characterization of gas-bearing reservoirs. From the perspective ofporoelasticity, Russell fluid factor is sensitive to the conventional (sand gas) and unconventional (shale gas, or tight gas) reservoirs. In a saturated isotropic medium, however, most amplitude-variations-with-offset/angle (AVO/AVA) inversion methods based on the approximate formulas affect the estimation of Russell fluid factor due to the low accuracy of the approximations in the range of moderate to large incidence angles. We first introduce a saturated seismic wave velocity associated with Russell fluid factor into the Zoeppritz equations to describe the saturated porous media. Combining perturbation theory and Taylor expansion, we solve the objective function by dealing with the gradients of derived reflection coefficient. Using an iterative reweighted least-squares algorithm, we propose a joint multi-wave Bayesian AVA inversion to estimate Russell fluid factor. Test results of synthetic data with moderate random noises show that the elastic and fluid parameters can be reliably predicted in saturated porous rock. Tests on field data sets verify the robust estimation of Russell fluid factor to realize the fluid identification in a shale gas reservoir. Both of cases indicate that joint multi-wave inversion can improve prediction accuracy of model parameters compared with single PP-wave inversion when the amplitude quality of converted wave data is better.
      原文链接:
    • NSTL

    Aqueous imbibition further investigation on contact area penetration enhancement for hydrocarbon extraction from tight rocks

    Jin ZhangDongmei Wang
    14页
    查看更多>>摘要：The rapid decline of production and low oil recovery in shale and other tight formations have been identified in practice. Surfactant EOR has been considered as one of the best options for those challenging formations. Many studies indicated that the oil recovery was improved by surfactant spontaneous imbibition in a huff-n-puff mode. However, the slow oil extraction rate and the limited penetrating area into the rock matrix by laboratory experimental results indicated it might be impractical for real-time extraction. To address this problem for the carbonate-rich tight formations, a new approach of forced surfactant imbibition process coupled with enhanced contact area stimulation (acidizing, for instance) was proposed. In this paper, samples from the Middle Bakken were used for the laboratory studies. A chemical formulation (CF) consists of surfactant, organic acid, and other components was designed to evaluate the effects on carbonate-rich rocks, rock microstructure and petrophysical properties (porosity and permeability). Oil recovery was also examined by forced imbibition with chemical formulation. Research results demonstrated that CF treatment could dissolve the carbonate minerals in the Bakken rocks resulted in the microstructure changes. These changes led to the injected fluid deeply imbibe into the rock matrix and therefore enlarge the rock-fluid contact area. Rock porosity and permeability were increased and oil recovery was significantly improved with the designed chemical formulation through forced imbibition. In a summary, this laboratory study of combination of acid stimulation and forced surfactant imbibition process may serve as a possible approach for a field application to improve the hydrocarbon recovery from well to well besides of huff-n-puff method.
      原文链接:
    • NSTL