ALBERT

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Yixiang Zhang, Jianming He, Xiao Li, Chong Lin〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Hydraulic fracturing using freshwater as fracturing fluid is regularly employed in commercial shale gas or oil production. Many problems are brought by the fracturing fluid of water, such as water shortages, swelling of clay mineral, and the pollution of flow-back water. Replacement of water by supercritical CO〈sub〉2〈/sub〉 (SC〈img src="https://sdfestaticassets-eu-west-1.sciencedirectassets.com/shared-assets/16/entities/sbnd"〉CO〈sub〉2〈/sub〉) in the hydraulic fracturing treatment of shale reservoir has meaningful potential for the improvement of gas production. Hydraulic fracturing experiments, under different injection rate and stress state, were carried out for studying the SC-CO〈sub〉2〈/sub〉 fracturing of shale considering anisotropy effects. Anisotropy of shale has a significant impact on the mechanical behavior and fracture propagation of shale in the experiment. There shows a downward tendency for breakdown pressure with the increase of bedding plane angle in general. Higher injection rate can lead to the higher breakdown pressure, while higher deviator stress can lead to the lower breakdown pressure instead. In addition, three patterns of fracture propagation can be observed in the experiment, relative to the bedding structures of shale specimen, including propagating along, propagating across and arresting. The maximum values of fracture width during experiment in shale with different bedding plane angle ranges from 0.29 mm to 1.05 mm, while the final fracture width after the fracturing experiment is kept within the range of 0.01 mm–0.04 mm under the injection rate of 0.3 ml/s.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Xueying Wang, Hongjian Ni, Ruihe Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Toolface control is an important issue when drilling directional wells with steerable motors. In this paper, a new experimental apparatus has been built to study the toolface behavior while slide drilling. In experiments, weight on bit and toolface orientation during the simulated slide drilling are recorded and analyzed. Experimental results indicate that axial stick-slip motion of the drillstring that occurs in the presence of large friction causes toolface disorientation. In addition, the phenomenon of toolface hysteresis in horizontal wells is identified. The asymmetric loading and unloading rates of weight on bit result in toolface hysteresis, and toolface hysteresis worsens toolface disorientation. A new method of correcting toolface by quickly eliminating toolface hysteresis is proposed. Four torque-related parameters are used in the method, and each has a specific implication. The proposed method has been examined using the experimental apparatus and has been proven to work. The experimental results and related analysis in this paper can help to further improve the efficiency of toolface control during slide drilling.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: Available online 31 October 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering〈/p〉 〈p〉Author(s): Vladimir A. Osinov, Stylianos Chrisopoulos, Theodoros Triantafyllidis〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The paper presents a numerical analysis of the dynamic deformation of the tunnel lining and the soil caused by a blast-induced pressure pulse of a moderate amplitude (several megapascals) inside the tunnel. The tunnel lining is circular and consists of individual concrete linearly elastic tubbings. The tunnel is located at a depth of 15 m in fully saturated granular soil. Effective-stress changes are described by a hypoplasticity model. The possibility of pore water cavitation at zero absolute pore pressure is taken into account. The problem is solved in a two-dimensional plane-strain formulation with the finite-element program Abaqus/Standard. Emphasis is placed on fine spatial discretization in order to obtain accurate solutions. Stresses and deformations in the lining and in the soil are analysed in detail. The solutions reveal an important role of the strong nonlinearity in the soil behaviour due to the pore water cavitation.〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Shilpa K. Nandwani, Mousumi Chakraborty, Smita Gupta〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Improved computational techniques have served as reliable tool in providing accurate reservoir characterisation and also predicting production of oil for a given EOR process. In the present study, COMPUTATIONAL FLUID DYNAMICS (CFD) has been used to simulate surfactant flooding experiments in a 3D geometrical model that replicates an actual artificially prepared calcite powder packed bed (a proxy of carbonate reservoir)) in which core flooding experiments have been carried out. The surfactant slug used in the study is a high salinity aqueous mixture containing surface active ionic liquid (C〈sub〉16〈/sub〉mimBr) and a nonionic surfactant (TERGITOL 15-S-9). ANSYS WORKBENCH 15.0 software is used to create the 3D geometry and ANSYS FLUENT 15.0 has been used for solving the governing equations for the system. A mixture model is considered as the multiphase model to study the flow of multiple phases in the porous bed. To take into account the mass transfer of the surfactant into the oil phase as well as the water phase, a species transport model is incorporated in the present simulation.〈/p〉 〈p〉Simulation results were confirmed by the experimental data such that the species transport model coupled with mixture model were found to fit in well to the multiphase flow dynamics. It was found that the mixed surfactants system showed higher efficiency in recovering oil due to minimal fingering effects, ultralow IFT between the surfactant solution and oil and low diffusion rates of surfactant species into residual oil and brine. A delayed water breakthrough time was observed during simulation which attributed to higher oil recovery. Also there was a good match in water breakthrough time for both simulation and experimental surfactant flooding process.〈/p〉 〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518309513-fx1.jpg" width="305" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Boyuan Li, Xiongqi Pang, Yuexia Dong, Junwen Peng, Ping Gao, Hao Wu, Chuang Huang, Xinhe Shao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Shale oil has gradually become the predominant target for unconventional hydrocarbon exploration in recent years. Unlike marine shales that have been extensively studied, lacustrine shales are not adequately characterized in the literature. In this study, we examined Shahejie Formation shales in the Nanpu Sag in the Bohai Bay Basin of China, and performed organic geochemistry, mineralogy, scanning electron microscopy (SEM), and N〈sub〉2〈/sub〉 and CO〈sub〉2〈/sub〉 gas adsorption analyses. The results show that the Shahejie shale can be divided into four lithofacies: siliceous shale, calcareous shale, argillaceous shale, and mixed shale. Calcareous shale was deposited in deep lacustrine environment, and usually has the highest total organic carbon (TOC) content with type I kerogen. Mixed shale, which was deposited in the transitional zone, has moderate TOC values. Argillaceous shale and siliceous shale were deposited in shallow lacustrine environment or near shore, and always have the lowest TOC values. Inorganic mineral pores are the dominant type of pore in all four shale groups. Argillaceous shale has a large amount of intraparticle pores with low average pore size and poor connectivity compared with calcareous shale. Limited organic matter pores are present in low matured lacustrine shales, whereas the porosity of some lacustrine shales may increase due to the occurrence of large number of organic pores leading to significant increase of total porosity. Micro-fissures within calcareous shale greatly improve reservoir quality. Overall, siliceous shale and argillaceous shale usually have low TOC, low residual hydrocarbon, relatively strong adsorption capacity, and poor connectivity of pores, which contain little free oil and are unfavorable for shale oil exploration. Calcareous shale has high TOC, high residual hydrocarbon, large pore size, and excellent fracturing nature, and should be the best target for lacustrine shale oil exploration.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Yang Wang, Luofu Liu, Huancheng Ji, Guangjian Song, Ximeng Wang, Yue Sheng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This study focuses on the qualitative and quantitative evaluation of the transporting capacity of a pre-Triassic unconformity and its influence on hydrocarbon migration in the Wuerhe-Fengnan area, Junggar Basin, China. Based on the lithological and geophysical characteristics of rocks and the geochemical parameters of formation water and hydrocarbon fluids from the unconformity, we identified the structure of the unconformity, analyzed the lithological assemblage through its vertical profile, calculated its transporting efficiency for oil in the Triassic Baikouquan Formation (T〈sub〉1〈/sub〉b), and tracked the direction of oil migration along it. Four conclusions can be drawn. First, the pre-Triassic unconformity has a complex three-layer structure, including a basal conglomerate, weathering crust, and leached zone from the top to the bottom. Second, different lithologic assemblages form different types of migration pathways, mainly comprising a dual-channel with a sealing layer and a single channel of basal conglomerate. Third, the relative transporting efficiency (RTE) of the basal conglomerate for T〈sub〉1〈/sub〉b oil migration is primarily controlled by its thickness and porosity. The RTE decreases from the northwest slope and uplifted area to the southeast sag area, with a mean value of 36%. Finally, the quantitative grain fluorescence, quantitative grain fluorescence on extract, and grain containing oil inclusion values confirm that the unconformity is an effective migration pathway for T〈sub〉1〈/sub〉b oils. Horizontal changes in the oil group components and pyrrolic nitrogen compounds indicate that the T〈sub〉1〈/sub〉b oils migrated from the southeast sag to the northwest slope and uplifted region along the pre-Triassic unconformity.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: Available online 31 October 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering〈/p〉 〈p〉Author(s): J. Machaček, Th. Triantafyllidis, P. Staubach〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Earthquake stability assessment of large opencast mine slopes are complex and non-linear problems, often addressed using pseudo-static approaches neglecting material-induced failures and the role of pore-fluids. In this study, a numerical approach is used to understand the dynamic response of saturated and partially saturated soils. For this purpose user-defined elements have been implemented in 〈em〉Abaqus/Standard〈/em〉 including user-defined material models. The governing equations involving coupled fluid flow and finite deformation processes in partially saturated soils are derived within the framework of the 〈em〉Theory of Porous Media〈/em〉. The stress-strain behavior of granular soils is represented by a 〈em〉hypoplastic〈/em〉 constitutive model and for clayey soils the 〈em〉ISA-Clay〈/em〉 model is used. The saturation-suction behavior is modeled using the 〈em〉van Genuchten〈/em〉 model. To account for the large scale of the finite element model, a scaling procedure of the system of equations is proposed to purge the influence of initial stress. The performance of the user-defined elements is tested by back analysis of a centrifuge test available in the literature. Finally, large-scale fully coupled finite element simulations are performed to study the response of a flooded opencast mine under earthquake loading. The paper illustrates the importance of accounting the pore-fluids as independent phases in the context of seismic analysis of slopes and the influence of simplifications on which the calculation is based are highlighted. The simulations show strong wave diffraction effects for inhomogeneous dump structures, resulting in smaller displacements in near-surface areas of the slope. Further it was found that large areas of the dump show a temporary decrease of effective stress. The initial strong differences in stiffness between the different materials may decrease with time after several seismic events due stress redistributions caused by earthquakes.〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 114〈/p〉 〈p〉Author(s): Yuanzheng Lin, Zhouhong Zong, Shizhu Tian, Jin Lin〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Most current baseline correction methods for near-fault ground motion records focus on eliminating and minimizing baseline errors and obtaining true ground motion records that are in accordance with GPS-measured coseismic displacements. Though these methods can recover true ground motions, the single value of ground permanent displacement cannot meet the requirement of seismic response analysis of fault-crossing bridge with the consideration of various levels of relative static displacements. Besides, the corrected final displacements are often too large which will cause an extremely large pseudo-static response and a relatively small dynamic response in bridge structures. To provide across-fault seismic excitations with a reasonable series of final displacements, a new baseline correction scheme based on the target final displacement is proposed in this study, in which an additional offset displacement is introduced based on the Iwan correction scheme. The new baseline correction scheme aims at modifying the pseudo-static displacement of ground motion records to facilitate the agreement between the achieved final displacement and the target final displacement. The correction scheme is then examined in three aspects including time histories, response spectra and bridge responses. The analysis results indicate that sets of the corrected time history records with a large range of final displacements can be well achieved with a minor influence on spectral characteristics. The seismic response analysis of a cable-stayed bridge crossing a dip-slip fault-rupture zone shows that the pseudo-static response can be controlled, meanwhile, the dynamic response remains almost intact by using the new baseline correction scheme. This work can be used as a reference for input excitations of bridge crossing fault-rupture zones.〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 114〈/p〉 〈p〉Author(s): Xinzheng Lu, Lei Zhang, Yao Cui, Yi Li, Lieping Ye〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Recently, seismic resilience has become a research frontier in civil engineering. The self-centering steel frame can effectively control structural damage and reduce structural residual deformation, which ensures rapid repair after an earthquake. Therefore, such a structural system has attracted extensive attention from researchers. One of the important research directions on self-centering steel frames is the development of high-performance energy-dissipating components. A new type of dual-functional replaceable stiffening angle steel (SAS) component is proposed here. It can effectively improve the stiffness and strength of beam-column connections and has sufficient energy-dissipating performance and ductility. Seven different energy-dissipating components were tested, including one angle steel component and six SAS components. The strength and deformation capacity of the components were compared based on monotonic loading tests. The SAS component with the highest out-of-plane stability and sufficient strength and initial stiffness was selected and subsequently tested under hysteretic loading to investigate its energy-dissipating performance. The theoretical analysis methods of the initial stiffness and the yield moment provided by the SAS components were proposed and validated by the finite-element (FE) models calibrated using experimental data.〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 114〈/p〉 〈p〉Author(s): Christos Giarlelis, Jared Keen, Evlalia Lamprinou, Victoria Martin, Gerasimos Poulios〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The recently constructed Stavros Niarchos Foundation Cultural Center (SNFCC), houses the National Opera and the National Library of Greece. In order for the structural design to meet the demanding architectural requirements as well as the high-performance seismic specifications that were set, a seismic isolation system was incorporated. SSI effects due to poor silty sands were an additional challenge. After presenting the design parameters and the choice of seismic isolation type, the paper focuses on the methodology for the seismic design. This, performed in three consecutive stages, includes simple analyses using single-degree of freedom model for initial scheming, dynamic response spectrum analyses for detailed design and non-linear time history analyses using two sets of selected earthquake records, semi-artificial and real ones, for verification of the response. The results demonstrate a good correlation between different analysis techniques and provide a valuable insight into the behaviour of two complex, seismically isolated structures under seismic loads. The problems and solutions resulting from the implementation of the seismic isolation are also briefly presented.〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 115〈/p〉 〈p〉Author(s): Joonsang Park, Amir M. Kaynia〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this study, we introduce and discuss features and improvements of the well-established stiffness matrix method that is used in simulation of wave propagation in layered media. More specifically, we present stiffness matrices for an acoustic layer and a vertically transverse isotropic (VTI) viscoelastic soil layer. Combining these stiffness matrices enables a straightforward technique for modeling of acousto-elastic wave propagation in layered infinite media. In addition, we propose a technique to simulate discontinuity seismic sources, which was not used earlier in the context of the stiffness matrix method. Finally, we propose a framework to derive a key parameter of the absorbing boundary domain technique Perfectly Matched Layer (PML). Numerical examples are presented in order to help understanding the features and improvements discussed in the study from the fields of geophysics and soil dynamics. It is believed that the features and improvements discussed herein will make the application of the stiffness matrix method even wider and more flexible.〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 115〈/p〉 〈p〉Author(s): Amin Rahmani, Mahdi Taiebat, W.D. Liam Finn, Carlos E. Ventura〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In the current state of practice, static/seismic soil-pile interaction is included in design calculations by a set of one-dimensional (1D) uncoupled springs. The guidelines of American Petroleum Institute (API) are often adopted to develop backbone curves for the lateral springs. The purpose of the paper is to assess the reliability of this practice. Twenty-seven static field and laboratory tests, and two dynamic centrifuge tests are simulated to evaluate the performance of the springs. More detailed elaboration on the performance of the springs is provided by simulation of one of the static tests and both of the dynamic tests using also three-dimensional (3D) continuum approach. The evaluation results indicate that API springs do not capture the major mechanisms involved in soil-pile interaction, and this results in erroneous estimation of pile deflections and bending moments. It is shown that the observed errors stem not only from the insufficient characterization of the spring properties (API backbone curves), but also from the inadequate simulation method in which three-dimensional continuum configuration of the supporting soil is represented by a 1D uncoupled spring.〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 115〈/p〉 〈p〉Author(s): Sajad Veismoradi, Amirhossein Cheraghi, Ehsan Darvishan〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Buckling-Restrained Braced Frames (BRBFs) are among the common seismic resistant systems with many beneficial characteristics such as stable cyclic behavior and high energy dissipation. However, recent studies have shown that BRBFs are susceptible to residual deformations during earthquakes which makes them vulnerable to aftershock events. The aim of the current study is to investigate the aftershock collapse capacity of BRBFs. In the first part of the paper, simplified procedures including IDA and collapse fragility analyses are carried out to gain more insight regarding the residual drift and collapse capacity of the intact frames. Then, aftershock fragility assessment is conducted for several damage states, to highlight the influence of post-mainshock residual drifts on the collapse of the structures. As for the second part, a detailed probabilistic framework is introduced and utilized to include the effects of upcoming aftershocks on the annual collapse probability of the structures. Results show that aftershock can highly intensify the structural response especially when the structure tolerates large residual drifts during the mainshock.〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Vincenzo Costanzo-Álvarez, Augusto E. Rapalini, Milagrosa Aldana, Marisel Díaz, Diego Kietzmann, María Paula Iglesia-Llanos, Ana Cabrera, Tomás Luppo, María D. Vallejo, Ana María Walther〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A combined study of rock-magnetism and electronic-paramagnetic resonance (EPR) was performed in core samples from an oil well in the Vaca Muerta Formation (SW Argentina). The aim of this work was to characterize the effects of hydrocarbon-related diagenesis on the magnetic signature of oil shales. Similar research has been previously conducted in near-surface sediments affected by oil and gas microseepage, so as to establish a relationship between micromagnetic anomalies and the underlying reservoirs. The EPR technique was employed to measure minute concentrations of organic matter free radicals (OMFRs), Fe〈sup〉3+〈/sup〉 and Mn〈sup〉2+〈/sup〉. These results, and the concentrations of extractable organic matter (EOM), were compared with mass-specific magnetic susceptibility (χ) and natural remanent magnetization (NRM). The reactive OMFRs, resulting from the thermal degradation of a kerogen that yields a slightly-biodegraded crude oil, seem to have acted on the primary Fe oxides and sulfides through two diagenetic stages. The first stage might have partially dissolved these minerals. Consequently, a number of depth levels show a decrease of both χ and NRM, against an increase of the OMFRs. On the other hand, for a core-interval between 2663 and 2695 m (P18/P24), a second diagenetic stage could have produced partial replacement of framboidal pyrite by authigenic pyrrhotite, as recognized by scanning electron microscopy (SEM), electron X-ray energy dispersion (EDX) experiments and the analysis of the thermomagnetic and IRM curves. Thus, within P18/P24, magnetic parameters increase in direct proportion with the amount of OMFRs. The lithologies encompassed by P18/P24 show small levels of Mn〈sup〉2+〈/sup〉, a proxy directly related to calcareous cementation. Moreover, Gamma Ray, resistivity and neutron porosity well logs reveal distinctive features for P18/P24, as well as an increase of hydrocarbon content, contrasting with the rest of the section analyzed. The hydrocarbon-induced magnetic anomalies in these oil shales seem to be conditioned mostly by their petrophysical properties.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Lanxiang Shi, Peng Liu, Dehuang Shen, Pengcheng Liu, Changfeng Xi, Yunjun Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The primary recovery of conventional heavy oil (with viscosity 〈150 mPa s) in deep reservoirs often has a low recovery factor (RF) and high-pressure drawdown. It is important to propose effective and economic recovery methods to enhance oil recovery of these reservoirs. A top-driving, carbon dioxide (CO〈sub〉2〈/sub〉)-assisted hot-water flooding method is developed and presented in this paper. Laboratory experiments, including CO〈sub〉2〈/sub〉 solubility and one-dimensional (1D) core flooding tests, were conducted based on oil samples from a deep and pressure-depleted conventional heavy oil reservoir. Numerical simulations were conducted to study and discuss the mechanisms. The results from laboratory experiments show that the dissolved CO〈sub〉2〈/sub〉 in the oil reduced the oil viscosity by 30% at 57 °C and 2.0 MPa, and the displacement efficiency of carbonated 120 °C hot-water flooding was comparable to that of 200 °C steam flooding. The CO〈sub〉2〈/sub〉-assisted hot-water flooding method requires substantially less energy input than the steam flooding method. Numerical simulation indicates that the CO〈sub〉2〈/sub〉 and hot-water co-injecting process results in viscosity reduction, increased pressure, increased sweeping volume, and, consequently, improved oil recovery. The top-driving and CO〈sub〉2〈/sub〉-assisted hot-water flooding method provides a technical and cost-effective method for enhancing oil recovery in the post-primary recovered heavy oil reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Zisis Vryzas, Lori Nalbandian, Vassilis T. Zaspalis, Vassilios C. Kelessidis〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Clay suspensions present complex microstructures in different environments and deep understanding of such microstructures is crucial to control their flow properties. Their rheological profile is closely linked with the structural association (3-D network) of bentonite particles. Nanomaterials are considered very good candidates for smart fluids formulation which can improve the performance of conventional drilling fluids. Their incorporation in water-bentonite suspensions endow complex microstructures and hence complex rheological behavior, which is still under investigation. This study aims to explore the micro-mechanisms involved on shaping this rheological behavior with samples of 7 wt% water-sodium bentonite suspensions containing 0.5 wt% each of, commercial Fe〈sub〉3〈/sub〉O〈sub〉4〈/sub〉, commercial SiO〈sub〉2〈/sub〉 NP and custom-made (bare or citric acid coated) Fe〈sub〉3〈/sub〉O〈sub〉4〈/sub〉 NP at alkaline pH. We tried to achieve this by combining macroscopic measurements (rheological measurements) with microscopic measurements (i.e. TEM). A comprehensive physico-chemical characterization of the materials and suspensions was performed using X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), N〈sub〉2〈/sub〉 adsorption-desorption isotherms and Fourier-transform infrared spectroscopy (FTIR). An effective drying process was adopted using freeze-granulation and freeze-drying (FG-FD) techniques in order to capture as accurately as possible the evolved microstructures of these aqueous bentonite suspensions at the different temperatures (25–60 °C). The results indicated that all samples exhibited a yield stress followed by a shear thinning behavior. The three parameter Herschel-Bulkley model provided excellent fit of the experimental data for all samples. HR-TEM images revealed that the association of the nanoparticles with bentonite particles in different configurations plays a crucial role in their rheological characteristics with the charge and the coating of the added nanoparticles being important factors in determining the magnitude of the effects observed. We hypothesize that attractive magnetic forces between the magnetite nanoparticles may suppress the electrostatic repulsions and thus they may play a key role in promoting the observed aggregation of the nanoparticles which in turn plausibly affected their rheological profile. A thorough examination and understanding of the evolution of such complex inter-particle structures may lead towards an optimal rheology control of such suspensions in a wide range of applications.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518309677-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: Available online 31 October 2018〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering〈/p〉 〈p〉Author(s): Montaser Bakroon, Reza Daryaei, Daniel Aubram, Frank Rackwitz〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The buckling of steel pipe piles during installation is numerically studied. Generally, numerical simulation of installation processes is challenging due to large soil deformations. However, by using advanced numerical approaches like Multi-Material Arbitrary Lagrangian-Eulerian (MMALE), such difficulties are mitigated. The Mohr-Coulomb and an elastic-perfectly plastic material model is used for the soil and pile respectively. The pile buckling behavior is verified using analytical solutions. Furthermore, the model is validated by an experiment where a pipe pile is driven into sand using vibratory loading. Several case scenarios, including the effects of heterogeneity in the soil and three imperfection modes (ovality, out-of-straightness, flatness) on the pile buckling are investigated. The numerical model agrees well with the experimental measurements. As a conclusion, when buckling starts, the penetration rate of the pile decreases compared to the non-buckled pile since less energy is dedicated to pile penetration given that it is spent mainly on buckling.〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Soil Dynamics and Earthquake Engineering, Volume 116〈/p〉 〈p〉Author(s): Payam Sotoudeh, Mohsen Ghaemian, Hamid Mohammadnezhad〈/p〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Seismic analysis of complex structures such as concrete dams has been the subject of numerous studies. One of the challenges in seismic analysis of such systems is proper modelling of massed foundation. Since concrete dams’ foundations are usually layered, this makes the homogenous half-space assumption relatively unrealistic. In this paper, the effects of massed layered foundation on seismic response of concrete gravity dams in dam-reservoir-foundation systems are investigated. Seismic finite element analysis of the system carried out using domain reduction method. This approach is compared with another available method named, free-field column. First set of analysis considers the effect of modular ratio between layers on seismic response of the gravity dam. Second set of analyses investigate the effects of layers’ geometry, location and orientation on obtained responses. Results highlight the considerable effects of massed layer foundation assumption against its homogenous counterpart. Besides, results show that layer properties dictate how severely they can affect the dynamic responses of the dam.〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Yanyong Wang, Shaoran Ren, Liang Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Air injection assisted cyclic steam stimulation (CSS) through horizontal wells is a new technique for the exploitation of ultra heavy oil reservoirs, which has an advantage over other gas or solvent injection processes from the economic point of view. Different from in-situ combustion (ISC) process, the dominating chemical reactions occurring underground in air injection assisted CSS process are low temperature oxidation (LTO) reactions, and owing to the complicated LTO reaction mechanism, this process is still not clearly understood. Therefore, an indepth learning of this process will be of great benefit to its field application and specific project design. In this study, a comprehensive numerical simulation model was established, which accounted for the LTO reactions of different oil components in terms of SARA fractions, as well as permeability reduction induced by coke deposition. A series of simulations were then performed to explore the production performance and elucidate the impacts of various factors. The simulation results demonstrate that air injection assisted CSS using horizontal wells can enhance ultra heavy oil recovery and reduce cSOR in comparison with steam injection alone, which can be attributed to the synergistic effect of steam and air coinjection. Injection of air along with steam can have the same effect as the initial solution gas in reservoir, and the potential of air injection assisted CSS to enhance oil recovery will be more pronounced in oil layers with lean solution gas. In addition, normal air injection can be a viable choice considering the free availability of air, and injection of oxygen-reduced air can become a good option for ultra heavy oils featured with poor LTO reactivity for the sake of safe production.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: March 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 174〈/p〉 〈p〉Author(s): Lin Yuan, Yanling Wang, Qiang Li, Kai Chen, Yongfei Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Acid fracturing is one of the common well stimulations techniques in carbonates. There are some limitations in conventional acid systems during the application, such as fast reaction of acid-rock, high leak-off rate and strong corrosion, that's why, the retarded acid systems, like gelled acids, are developed. In this work, a control-released in-situ generated acid matrix tablet is reported as a novel retarded acid system to overcome the above limitations. In the tablets, ammonium chloride and paraformaldehyde are used as active substances to generate hydrochloric acid (HCl), with high dissolving capacity of over 85% and excellent corrosion inhibition of more than 90% at 90 °C without inhibitors. A one-step and economic method is used to prepare the acid tablets by directly compacting the powder mixture of active substances. The dissolution rate of tablets is adjusted to control the release of acid, so that such form reduces the leak-off rate and slows the reaction of acid-rock. The simplicity of preparation process of the tablets along with excellent dissolution and corrosion inhibition makes the proposed acid tablets technique potential for the application in acid fracturing.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Jin Lai, Xiaojiao Pang, Qiyao Xiao, Yujiang Shi, Haitao Zhang, Taiping Zhao, Jing Chen, Guiwen Wang, Ziqiang Qin〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉The Majiagou Formation is an important gas-bearing stratigraphic unit in the Ordos basin of west China. The highly complex lithology and heterogeneous pore systems make it difficult to predict the reservoir quality via petrophysical and image logs. This study investigates the lithology, pore systems and well log responses of the Majiagou Formation Member 5 (Ma 5) carbonate reservoirs using a comprehensive analysis of cores, thin sections, routine core analysis, conventional and porosity spectrum derived from image logs. The results show that the lithologies of the Ma 5 are dominantly of mud-sized to silt-sized crystalline dolomite, and there are some dolomites containing gypsums mudstones and limestone. The pore systems include vugs, intercrystalline pores, dissolution pores and microfractures. The vuggy dolomites and the fractured dolomites are the best quality reservoir rocks, and the mud-sized to silt-sized crystalline dolomites containing intercrystalline pores are good quality reservoirs with high porosity and permeability.〈/p〉 〈p〉Open fractured zones are recognized as dark sinusoidal waves, and the vuggy dolomites can be recognized by the dark spots on the image logs. However, the fractured and vuggy dolomites are only occasionally detected, and most of the dolomite reservoirs in Ma 5 contain only intercrystalline pores, which are difficult to be recognized by image logs. In addition, good quality reservoirs have very similar log responses (low natural gamma-ray (GR), low-moderate bulk density (DEN), and moderate-high resistivity) with the poor reservoir quality intervals. By applying the Archie's formula to the flushed zone, a total of 150 porosity curves can be obtained from the XRMI image logs. Then the porosity spectrum is derived from the histogram of porosity distribution for a certain interpretation interval. The best quality reservoir rocks (fractured or vuggy dolomites) have very broad porosity spectrums with long tails due to the presence of vugs and fractures. The abundance of intercrystalline pores containing in the mud-sized to silt-sized crystalline dolomites also result in the broad porosity spectrums without any tails. In contrast, the very narrow porosity spectrums correspond to the poor reservoir quality intervals. The interpretation results are verified by core observations and thin section analysis. By using the porosity spectrum analysis derived from the image logs, the reservoir quality can be predicted. The results can help improve the understanding and prediction of the reservoir quality in carbonates using well logs.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Shaobin Guo, Yanxia Peng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Three shale samples, which were from MF-1 well (a) and MF-2 well (b) in the northern Ordos Basin of China and Yan'an Formation of Jurassic coal measure strata of J601 well (c) in the western edge of the Ordos Basin, were taken for thermal simulation and rock pyrolysis experiments. The rules of hydrocarbon generation production and S〈sub〉2〈/sub〉 varied with the increase in thermal maturity (〈em〉R〈/em〉〈sub〉o〈/sub〉), and the relationship between S〈sub〉2〈/sub〉 and gaseous hydrocarbon generation production were analyzed. The analytical results indicated that as the 〈em〉R〈/em〉〈sub〉o〈/sub〉 increased, the liquid hydrocarbon production of the shale samples first increased and then decreased, while the gaseous hydrocarbon production and total hydrocarbon production increased, and the S〈sub〉2〈/sub〉gradually decreased. Gaseous hydrocarbon production increased as S〈sub〉2〈/sub〉 decreased, and there was a two-stage negative linear correlation between S〈sub〉2〈/sub〉 and gaseous hydrocarbon production. The gaseous hydrocarbon production increased slowly when the 〈em〉R〈/em〉〈sub〉o〈/sub〉 value was below 0.8% and rapidly increased after this threshold was met. During the process of the hydrocarbon generation of the shale in the Ordos Basin, the evolution phase could be divided into three stages: the immature stage of producing liquid hydrocarbon, the mature stage of producing gaseous and liquid hydrocarbon, and the overmature stage of gaseous hydrocarbon thermal cracking. Considering the hydrocarbon expulsion efficiency of the shale samples, the total organic carbon (TOC) content had a positive logarithmic correlation with the shale gas content (the gaseous hydrocarbon production minus the expulsed gaseous hydrocarbon production). The hydrocarbon generation potential and gas content increased with the increase of TOC. With the knowledge of the shale samples' TOC content, the shale gas content of the sampling layer could be preliminarily determined based on the regression equations of TOC and gas content. The exploration potential of the shale layer could be evaluated according to the gas content calculation, after considering the standards for the shale gas favorable area and the target area gas content.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉After analyzing the rules of hydrocarbon generation production with the increase in thermal maturity (Ro), a corresponding mode of the process of shale hydrocarbon-generating was established and the maximum generated gas amount of shale samples could be calculated. Considering the hydrocarbon expulsion efficiency of the shale samples, the total organic carbon (TOC) content had a positive logarithmic correlation with the shale gas content. A new and reliable methods to estimate coal measures strata shale gas content was proposed which provided a reliable basis for the evaluation of shale gas resources and optimization of favorable areas.〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308660-fx1.jpg" width="302" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Meysam Naderi, Ehsan Khamehchi, Behrooz Karimi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Investment in the petroleum industry is usually faced with a high degree of risk due to uncertainty associated with economic factors. Typical factors include oil and gas price, interest rate, operational and capital expenditure. In addition, the investment risk increases as offshore exploration, drilling and production activities increase. Therefore, accurate prediction of economic factors is crucial in an upstream oil and gas sector in order to make better strategic decisions with minimized risk.〈/p〉 〈p〉In the present study, four methods of the least square support vector machine (LSSVM), genetic programming (GP), artificial neural network (ANN), and auto-regressive integrated moving average (ARIMA) were initially used to forecast monthly oil price (MOP), daily gas price (DGP), and annual interest rate (AIR). Next, the meta-heuristic bat algorithm (BA) was applied in order to optimally combine the four mentioned forecasting methods in an integrated equation as a novel approach. All required historical data to forecast oil price, gas price and interest rate were collected from the Central Bank of the Islamic Republic of Iran.〈/p〉 〈p〉Error analysis in terms of coefficient of determination (R〈sup〉2〈/sup〉), average absolute relative error percentage (AAREP), root-mean square error (RMSE), and cumulative probability distribution versus absolute relative error percentage were used to compare the prediction performance of forecasting methods.〈/p〉 〈p〉Error analysis proves that the BA optimized method is superior over all other forecasting methods in terms of highest R〈sup〉2〈/sup〉 and lowest RMSE. After the BA optimized method, construction of LSSVM, ARIMA, ANN, and GP has better prediction ability, respectively. The results indicate that the BA optimized method reduces RMSE at least by 6.61% in MOP forecast; by 18.33% in DGP forecast; and by 23.13% in AIR forecast over all other forecasting methods.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Shuxian Jiang, Mehdi Mokhtari〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The Eagle Ford Formation in Texas, USA is composed of marl and interbedded limestone sequences with intermittent layers of volcanic ash. To optimize hydrocarbon recovery from such a heterogeneous formation, it is necessary to have a better understanding of the effects of each individual marl and limestone layer on reservoir properties. The objective of this paper is to characterize and quantify properties of marl and limestone layers in the Eagle Ford Formation, in terms of spectral core gamma ray, elemental concentrations, lithology and organic richness. Moreover, the differences between these layers in micro-scale level were shown through the scanning electron microscope (SEM) images. XRF results show that concentrations of Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, Fe〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, Mo, and Zr in marl layers were more than 40% higher than in the interbedded limestone layers. The Eagle Ford samples fall into two groups in the ternary plot. Limestone layers contain calcite content ranging from 55% to 90% and clay content ranging from 5% to 30%, while marl layers contain 30%–70% calcite and around 20%–50% clay. Marl layers have better generative potential than the limestone layers in the Eagle Ford Formation. Moreover, estimation of total organic carbon of the Eagle Ford Formation using Passey's Δlog R method with a correction factor was provided and validated with lab measured data.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Ehsan Ranjbar, Seyyed M. Ghaderi, Hossein Nourozieh, Anjani Kumar, Ali Takbiri-Borujeni〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉To improve the efficiency of Steam Assisted Gravity Drainage process (SAGD), a small amount of non-condensable gases can be added to steam. The non-condensable gas creates an insulation film at the top of the steam chamber as a result of gas accumulation. This could prevent heat loss to the overburden, increase steam chamber propagation in the lateral direction, and consequently improve the SAGD performance. Field-scale modelling and simulation of non-condensable gas injection in a hybrid SAGD process requires a comprehensive numerical model that includes variety of mechanisms involved in the processes. During the steam/non-condensable gas co-injection, the non-condensable gas may partially be dissolved in bitumen and water, accounting for a portion of gas production from the chamber. Therefore, in order to accurately model the non-condensable gas injection process, the partitioning of the gas among the phases (oleic and aqueous) must be well understood.〈/p〉 〈p〉The most significant challenge of modelling multi-phase equilibrium in gas/bitumen/water systems is the lack of three-phase equilibrium data. This study presents a methodology to generate two-phase and three-phase K-values from the experimental solubility data. The data for binary systems at certain temperatures and pressures is translated into equilibrium K-values. The K-values were calculated either from a correlation representing the phase behavior data or from an equation of state coupled with Henry's law. Then, the generated two-phase and three-phase K-values were directly implemented in reservoir simulators to account for component partitioning in different phases. The results indicate that the generated K-values would be applicable for different types of bitumen.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Afeez O. Gbadamosi, Radzuan Junin, Yassir Abdalla, Augustine Agi, Jeffrey O. Oseh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Effective cuttings transports and hole cleaning is crucial for obtaining an efficient drilling operation. Recently, the use of nanotechnology have been exploited to improve rheological and filtration properties of water-based mud. Herein, water-based mud (WBM) was formulated with nanosilica to enhance cuttings and solid particles transports from the wellbore to the surface. Different weight percent concentrations of nanosilica (0.001–1.5 wt%) at three different flow rates in litres/seconds (0.4, 0.6 and 1.0) and cuttings sizes (small, medium and large) were used to investigate the formulated water-based mud lifting capacity of the drilled cuttings. Experimental results show that addition of the nanosilica concentrations to the WBM enhances the viscosity, thereby increasing the muds carrying and circulating capacity. Moreover, nanosilica water-based mud (n-WBM) displays improved mud stability with high propensity to prevent intrusion of formation fluids. The effect of cuttings size on the wellbore cleaning is minimal. The large cuttings size shows a lower degree of cuttings transportation compared with the small and medium cutting size. Accordingly, the small cuttings size has higher cuttings recovery to the surface. Finally, though increase in flow rate leads to more cuttings recovery, there is every tendency that much fluid flow rate will cause an increase in frictional pressure losses and equivalent circulating density, high pump pressure requirement and potential hole erosion.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Dorval M.C. Neto, Cristina M.S. Sad, Mayara Silva, Francine D. Santos, Laíne B. Pereira, Rayane R.B. Corona, Samantha R.C. Silva, João F.P. Bassane, Eustáquio V.R. Castro, Paulo R. Filgueiras, Wanderson Romão, Valdemar Lacerda〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Unconventional oils (heavy and extra-heavy oils) represent approximately 55% of the oil reserves of the world. These oils are characterized for their high viscosity and gravity due to the high amount of resins and asphaltenes, natural emulsifiers, which combined with the presence of water and shear, in the production and transport of the oil in pipelines, may form the emulsions, usually water-in-oil (W/O). This study evaluated the rheological behavior of W/O emulsions of five heavy oils from the sedimentary basin of the Brazilian coast, with API gravity between 10.8 and 19.0. Factors related to the stability (temperature, amount of emulsified water, salt concentration) and rheological behavior of the W/O emulsions (dynamic viscosity, stress and shear rate) were evaluated and related to the oil chemical composition in terms of saturates, aromatics, resins and asphaltenes (SARA). The emulsions were prepared with deionized water, formation water (55 g L〈sup〉−1〈/sup〉 of NaCl) and water saturated with sodium chloride (270 g L〈sup〉−1〈/sup〉 of NaCl) under mechanical stirring at 5000 rpm. Rheological assays of the emulsions were performed at 30–80 °C, and the obtained data were treated using the Ostwald-de Waele equation. The results of the rheological evaluation showed that in stable emulsions there was a 1212% increase in the dynamic viscosity as a consequence of the amount of aqueous phase, while temperature minimized this effect, at 60 °C it was observed a reduction of more than 80% in the viscosity. In these emulsions the flow rate was positive, increasing as a function of temperature, and the inverse effect was observed when correlated to the amount of water. The unstable emulsions presented lower results for the dynamic viscosity if compared with the results of the dehydrated oils, caused by the presence of non-emulsified water. In general, the elevation of salt concentration and temperature aided in the stabilization of unstable emulsions. Oils with a total acid number minor 1.3 mgKOH·g〈sup〉−1〈/sup〉 and asphaltene/resin, aromatic/saturated and asphaltene/aromatic ratios higher 0.2 formed unstable emulsions, resulting in the appearance of non-emulsified water during the rheological tests.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308696-fx1.jpg" width="437" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Wesley P. do Carmo, Marcelo K. Lenzi, Ervin K. Lenzi, Montserrat Fortuny, Alexandre F. Santos〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The objective of this work was to propose a new model based on the theory of fractional calculus to predict the relative viscosity of petroleum emulsions. For this, stable emulsions with water content ranging from 10 to 65 wt% were prepared from three Brazilian crude oils: A (API 24.6), B (API 16.8) and C (API 13.5), with different contents of saturates, aromatics, resins and asphaltenes. Stable emulsions were prepared using an Ultra-Turrax homogenizer and the viscosity data were obtained from an Anton Paar Controlled Rheometer. The proposed fractional model was able to describe the experimental data very well, yielding a mean correlation coefficient 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈mrow〉〈mo stretchy="true"〉(〈/mo〉〈mrow〉〈mover accent="true"〉〈mrow〉〈msup〉〈mrow〉〈mi mathvariant="bold-italic"〉R〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msup〉〈/mrow〉〈mo stretchy="true"〉¯〈/mo〉〈/mover〉〈/mrow〉〈mo stretchy="true"〉)〈/mo〉〈/mrow〉〈/mrow〉〈/math〉 above 0.99 in all tests and mean deviations of the order of 6%. For comparison purposes, the models of Mooney (1951) and Pal and Rhodes (1989) were applied to the same experimental data and presented mean deviations of up to 21% and 18%, respectively. Finally, based on the formulated theory, it is shown that the fractional model parameters (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi mathvariant="bold-italic"〉k〈/mi〉〈/mrow〉〈mrow〉〈mn〉1〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉, 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si3.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi mathvariant="bold-italic"〉k〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉, 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si4.gif" overflow="scroll"〉〈mrow〉〈mi mathvariant="bold-italic"〉α〈/mi〉〈/mrow〉〈/math〉) may be related to the mass fraction of saturates, aromatics, resins and asphaltenes (SARA) existing in the crude oils.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Mumuni Amadu, Michael J. Pegg〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, 〈em〉G〈/em〉〈sub〉〈em〉T〈/em〉〈/sub〉. An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for 〈em〉G〈/em〉〈sub〉〈em〉T〈/em〉〈/sub〉 equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): W.A.M. Wanniarachchi, P.G. Ranjith, J.C. Li, M.S.A. Perera〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Foam-based hydraulic fracturing has been identified as a promising technique to extract unconventional natural gases such as shale gas and tight gas. However, due to the complex two-phase nature of foam, its use has been limited to a few field-scale applications. Therefore, precise understanding of foam-based hydraulic fracturing is essential in order to optimise fracture treatment processes. The aim of this numerical study is therefore to develop new models to predict and evaluate foam-based hydraulic fracturing. In order to achieve this, two models were developed: 1) a 3-D model to simulate the effect of perforation spacing and 2) a 2-D model to simulate the effect of dip angle on hydraulic fracturing. According to the results, perforation spacing has a direct influence on hydraulic fracturing, and a reduction of spacing from 100 to 25 m, increases the overall strain levels near the perforations by 350%. The numerical results also reveal that the dip angle directly influences the fracture network, and the fracture propagation is limited to only one direction. However, the results suggest that the effect of dip angle on fluid flow is negligible, and the pressure distribution remains almost the same in a direction perpendicular to the dip.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Fengpeng Lai, Zhiping Li, Tiantian Zhang, Anqi Zhou, Bao Gong〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N〈sub〉2〈/sub〉GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 μm to 1 μm in radius, followed by pores ranging from 1 μm to 10 μm. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Lashun Thomas, Hansong Tang, Dilhan M. Kalyon, Seda Aktas, J. Daniel Arthur, Jens Blotevogel, J. William Carey, Archie Filshill, Pengcheng Fu, Grace Hsuan, Thomas Hu, Daniel Soeder, Subhash Shah, Radisav D. Vidic, Michael H. Young〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Recent advances in hydraulic fracturing, in conjunction with horizontal drilling, have enabled large-scale extraction of natural gas and oil from shale formations. Despite its advances and enormous economic benefits, opportunities remain to increase hydraulic fracturing efficiency and minimize potential environmental impacts. This review specifically examines three key themes associated with development and utilization of hydraulic fracturing fluids: 1) characteristics and behavior of fracturing fluids, 2) understanding and predicting migration and fate of fracturing fluids, 3) technologies to reduce environmental impact of fracturing fluids. The paper discusses key and new techniques and findings on rheology of hydrogel-based fluids, high fidelity simulation of propagation transport, potential environmental impacts, geosynthetics in mitigating contamination, and greener fracturing fluids. It is indicated that future development relies on advances in understanding of physical processes, modeling capabilities, and monitoring techniques.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Qin Li, Wenling Chen, Yuan Lu, Qiangzhong Xiao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Etched surface morphology is the main cause of etched fracture conductivity. It would be helpful to optimize acidification fracturing design and improve the reservoir reconstruction effect by analyzing the rock etched surface during the acid-rock reaction process. The chemical mechanism involved in forming the etched carbonate surface and reasons for non-uniform morphogenesis are thoroughly analyzed in this paper. By applying different viscous acid-rock reaction kinetic parameters, a measuring device, and a 3D laser scanner, the acid-rock reaction rate and etched surface morphology are tested under different acid concentrations, reaction temperatures, and flow rates. The regularity of the surface morphology is also obtained under different acid-rock reaction rates. The results demonstrate that, with an increase in the acid concentration, reaction temperature, and acid flow, the acid reaction rate can be accelerated and the etched masses are positively related to the etched volume and acid-rock reaction rate. The main controlling factors of the acid-etched surface morphology in the parallel and vertical acid flow directions are the acid-rock reaction rate and mineral composition distribution, respectively. The increase in the acid-rock reaction rate contributes to drastic changes in the rock wavy surface, as well as the differences in and degree of inhomogeneity. In the acid flow direction, it is more conducive to form acid-etched holes and grooves by increasing the acid-rock reaction rate.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308180-fx1.jpg" width="234" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Xiaohu Hu, Wei Yu, Malin Liu, Mingwei Wang, Weihong Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Jiulong Wang, Hongqing Song, Vamegh Rasouli, John Killough〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This paper provides an integrated approach to simulate gas-water relative permeability in nanoscale porous media with interfacial effects using fractal theory. The calculation results with present model considering the interfacial effects match the laboratory results very well. The characteristics of relative permeability were analyzed under different values of Hydrogen bond (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉h〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉), Double layer repulsive force (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉e〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉), Long-range van der Waals force (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si3.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉w〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉) and Short-range structure repulsive force (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si4.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉s〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉). The result shows that the interfacial effects can promote the fluid flow in the nanoporous media and the relationship is as follows: 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si5.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉h〈/mi〉〈/mrow〉〈/msub〉〈mo〉〉〈/mo〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉e〈/mi〉〈/mrow〉〈/msub〉〈mo〉〉〈/mo〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉w〈/mi〉〈/mrow〉〈/msub〉〈mo〉〉〈/mo〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉s〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉. 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉h〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 and 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉e〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 improve spreading obviously, which are accounted for more than 70%.Then the 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si3.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mo〉∏〈/mo〉〈/mrow〉〈mrow〉〈mi〉w〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 affects spreading accounts for 1/5 nearly. In addition, the analysis of fractal dimension on relative permeability is carried out to indicate that the gas-water relative permeability decreases with the increase of the fractal dimension. While the capillary force has impact on relative permeability slightly. The new insight and theoretical basis could be obtained for CO〈sub〉2〈/sub〉 geological storage and shale gas extraction from nanoscale porous media.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): E. Papamichos, K. Furui〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Analytical sand onset models consider the tangential stress at the hole (wellbore or perforation) to compare with the strength of the formation. This simplified criterion does not consider the effect of axial and shear stress at the hole which in experiments have been shown to play a role. This paper presents the formulation of three analytical failure criteria for wellbore or perforation failure and sand onset under field conditions. The resulting analytical expressions are suitable for implementation in programs for sand onset and sand mass analyses. Expressions for critical formation strength, critical drawdown or critical depletion for sand onset are derived. The models can be calibrated on hollow cylinder hole failure strength data or eventually on the uniaxial compressive strength. The analytical model results are compared and validated on numerical simulations using a finite element program developed for sand production studies. The comparisons show that analytical models can reproduce satisfactory sand failure diagrams under various stress anisotropy and production conditions in the field. Finally, the effect of the wellbore on the perforation stresses is analyzed by comparing finite element and analytical results.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Weiji Liu, Xudong Qian, Tao Li, Yunlai Zhou, Xiaohua Zhu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Mechanical rock breaking in different forms have found wide applications in the mining and civil engineering industry such as drilling, tunnelling and grinding. A detailed understanding of the tool-rock interaction is essential to achieve high efficiency in rock breaking and to optimize the cutting parameters. The finite element simulation of the tool-rock interaction remains a challenging task due to the complexity caused by the physical rock properties, the crack initiation and propagation, as well as the chip generation phenomenon. This study has implemented the Drucker-Prager constitutive model with an isotropic damage model in a finite element analysis to examine the rock failure modes, considering the interaction of cutting tool and the rock. The material parameters for the rock derive from the uniaxial compressive strength (UCS) and Brazilian tensile strength (BTS) tests performed on rock specimens. This study includes an experimental program to examine the crack initiation, crack propagation and the chip generation in rock specimens. The results show the Drucker-Prager failure criterion with the calibrated material parameters and element sizes simulate closely the tool-rock interaction phenomenon. The mesh size imposes a great effect on the parameter selection of the rock model, particularly for the fully damaged plastic strain value. This study leads to an enhanced understanding of rock breaking mechanisms in the mechanical excavation, and provides the basis to improve the rock excavation machine design.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Luis Sánchez, Miguel Lapo, Octavio Zorrilla〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this work we propose a methodology based on sequential Monte Carlos techniques for the estimation of dynamic systems states arising from the torque and drag phenomena of a directional drill string. This methodology arises from the need to consider the various mechanical factors and the geological parameters that influence the drift deviation, which conduce to no vertical drilling and phenomena of torque and drag. The anticipated model will acquire importance for the evaluation with the different efforts for which it will be in the next stage of the drill string. The methodology is exposed through the reconstruction of states of the synthetic model states proposed by Johancsik, Friesen, and Dawson, using the Sequential Monte Carlo algorithms, the unscented Kalman filter (UKF) and the ensemble Kalman filter (EnKF), observing good adjustment of torsion and drag states estimated by the filters with respect to the real values. Filters performance was evaluated in terms of the mean square error, showing variability of the estimated errors 0.05 for EnKF and 0.01 for UKF and a fast execution of the algorithms 3.07 (seg) for EnKF and 0.48 (seg) for UKF.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Yijin Zeng, Peiqing Lu, Shiming Zhou, Laiyu Sang, Rengguang Liu, Qian Tao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Accurate prediction of the change in slurry column pressure during cement slurry weightlessness is important in eliminating the problem of gas channeling in a cemented annulus. However, the factors that incur cement slurry weightlessness are complex and diverse, and the hydrostatic pressure reduction prediction model based on gelling suspension and volume shrinkage needs to be further improved. Therefore, for the new anti-gas channeling cement slurry system, over 120 sets of cement slurry pressure change data have been collected by using a precise pressure conduction measurement device. Based on the experimental data, a multiple regression fitting method was used to establish a nondimensional model for the hydrostatic pressure reduction of cement slurry. The calculation model is easy to use and has a high fitting accuracy (the average prediction error is 〈11%). This model comprehensively considers the influence of the anti-gas channeling agent content, gas formation pressure, borehole temperature and geometric parameters on the pressure reduction rate of the cement slurry. This modeling process provides a new solution to establish a more practical and effective prediction model for the hydrostatic pressure reduction of cement slurry.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Rafael J. de Moraes, Rahul-Mark Fonseca, Mircea A. Helici, Arnold W. Heemink, Jan Dirk Jansen〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉We present an efficient workflow that combines multiscale (MS) forward simulation and stochastic gradient computation - MS-StoSAG - for the optimization of well controls applied to waterflooding under geological uncertainty. A two-stage iterative Multiscale Finite Volume (i-MSFV), a mass conservative reservoir simulation strategy, is employed as the forward simulation strategy. MS methods provide the ability to accurately capture fine scale heterogeneities, and thus the fine-scale physics of the problem, while solving for the primary variables in a more computationally efficient coarse-scale simulation grid. In the workflow, the construction of the basis fuctions is performed at an offline stage and they are not reconstructed/updated throughout the optimization process. Instead, inaccuracies due to outdated basis functions are addressed by the i-MSFV smoothing stage. The Stochastic Simplex Approximate Gradient (StoSAG) method, a stochastic gradient technique is employed to compute the gradient of the objective function using forward simulation responses. Our experiments illustrate that i-MSFV simulations provide accurate forward simulation responses for the gradient computation, with the advantage of speeding up the workflow due to faster simulations. Speed-ups up to a factor of five on the forward simulation, the most computationally expensive step of the optimization workflow, were achieved for the examples considered in the paper. Additionally, we investigate the impact of MS parameters such as coarsening ratio and heterogeneity contrast on the optimization process. The combination of speed and accuracy of MS forward simulation with the flexibility of the StoSAG technique allows for a flexible and efficient optimization workflow suitable for large-scale problems.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Ye.A. Golubev, O.V. Martirosyan, D.V. Kuzmin, S.I. Isaenko, B.A. Makeev, I.V. Antonets, A.A. Utkin〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The results of studying the structural and chemical transformations of natural bitumens of different degrees of metamorphism under heating at a low vacuum (∼8 kPa) in the temperature range 400–1000 °C are presented. Reducing of the size of supermolecular particles during heating was recorded. A sequent step-by-step transformation of the graphite-like phase in bitumen structure up to shungite stage according Raman spectra characteristics is shown. The samples acquire electrical conductivity through eliminating the hydrocarbon component, before their graphite-like structure of carbon was ordered up to the stage of the higher anthraxolite.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Kexing Li, Xueqi Jing, Dan Qu, Wanfen Pu, Bing Wei〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A good understanding of pore-level oil displacement mechanisms is of great significance for the application of viscoelastic surfactants (VES) in enhanced oil recovery (EOR). The focus of this paper is on the pore-level events that happen when VES displaces residual oil in porous media. Attention was placed on the displacement dynamics and the relation with the bulk solution properties of VES. Hence, direct measurements of interfacial tension (IFT), contact angle and relative permeability were first performed. The results showed that the tested VES could reduce the oil-water IFT to a 10〈sup〉−2 〈/sup〉mN/m level and reverse an initially oil-wet surface to water-wet state. In the visual micromodel experiments, a series of displacement scenarios were created, in which the residual oil was respectively displaced by brine, glycerol, KPS (a common surfactant) and VES aiming to identify the differentiations. The recorded images showed that glycerol was mainly to correct the mobility of the displacing phase via increasing the viscosity. In contrast, KPS was able to strip the adsorbed oil film on pore walls in the water swept zone corresponding to the effect wettability alteration. The EOR mechanism of VES when flow through the porous media can be described as two effects: "dragging" the oil film from the pore wall surface by electrochemical action, and "scretching" the residual oil out of the pore throat by the viscoelastic effect. These observations proved microscopically that the EOR mechanisms of the VES were contributed to synergistic effect of reducing interfacial tension, wettability alteration, mobility correction and viscoelastic flow.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Omogbolahan S. Ahmed, Ahmed A. Adeniran, Ariffin Samsuri〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Application of artificial intelligence in the accurate prediction of the rate of penetration (ROP), an important measure of drilling performance, has lately gained significant interest in oil and gas well drilling operations. Consequently, several computational intelligence techniques (CITs) for the prediction of ROP have been explored in the literature. This study explores the predictive capabilities of four commonly used CITs in the prediction of ROP and experimentally compare their predictive performance. The CIT algorithm utilizes predictors which are easily accessible continuous drilling data that have physical but complex relationship with ROP based on hydro-mechanical specific energy ROP model. The four CITs compared are the artificial neural network (ANN), extreme learning machine, support vector Regression and least-square support vector regression (LS-SVR). Two experiments were carried out; the first experiment investigates the comparative performance of the CITs while the second investigates the effect of reduced number of predictors on the performance of the models. The results show that all the CITs perform within acceptable accuracy with testing root mean square error range (RMSE) of 18.27–28.84 and testing correlation coefficient (CC) range of 0.71–0.94. LS-SVR has the best predictive performance in terms of accuracy with RMSE of 18.27 and CC of 0.94 while ANN has the best testing execution time at 0.03 s. Also utilizing the specific energy concept in chosen drilling parameters to be included among the predictors shows improved performance with five drilling parameters showing an improvement of 3%–9% in RMSE for LS-SVR in the two well studied. The utilization of the specific energy concept in the selection of the predictors in this study has demonstrated that the easily accessible drilling parameters have immense value to provide acceptable performance in the development of ROP model with CITs.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518307824-fx1.jpg" width="261" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Zhilin Cheng, Zhengfu Ning, Qing Wang, Yan Zeng, Rongrong Qi, Liang Huang, Wentong Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Non-Darcy flows associated with high Reynolds numbers often occur in the near-wellbore regions of gas reservoirs or hydraulic fractures and thus should not be ignored. However, investigating non-Darcy flow in these porous rocks through laboratory experiments is always expensive and time-consuming. As such, this article sought an alternative method, and a lattice Boltzmann study of non-Darcy flow in various porous models was performed. The applicability of two non-Darcy correlations in porous media and the effect of pore structure on non-Darcy flow were examined. In addition, the reasons for the deviation from the linear Darcy flow and different flow patterns related to inertial effects of the fluid were also studied. The results showed that the characterization of non-Darcy flow in porous media with the cubic law can only be valid in a narrow range of Reynolds number beyond the Darcy regime, outside of which the strong inertia-dominated flow yields to the quadratic correction. On the whole, representing the non-Darcy flows using the quadratic correction is acceptable, especially for porous media with a higher complexity. The features of non-Darcy flow greatly depend on the pore structure of a porous medium, and more heterogeneous pore models always have a faster cessation for Darcy flow and a higher 〈em〉β〈/em〉 factor. Furthermore, for simple porous media a small amount of parameters may be adequate for the prediction of the 〈em〉β〈/em〉 factor; while the correlations involving more parameters would be needed to determine the 〈em〉β〈/em〉 factor for more intricate porous models, although such correlations may not be widely used in various industries. Besides, the non-Darcy flow that occurs in porous media is collectively controlled by different mechanisms. At elevated velocities, the inertial core effect in a large channel will lead the flow to be more homogeneous and less tortuous, while in porous models with complicated pore space, the steady eddy and reversal flow resulting from drag force will make the flow paths more tortuous. As such, it is the hope of this study to provide some new insights into the non-Darcy flow in porous media.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Hadi Bagherzadeh, Zahra Mansourpour, Bahram Dabir〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In the present paper, a Discrete Element Method-Computational Fluid Dynamics (DEM-CFD) approach along with a new coalescence model is adopted to study agglomeration and fragmentation of asphaltene particles, thoroughly. The collisions of asphaltene particles are investigated in three categories: collisions between individual primary particles (P-P collisions), individual primary particles and flocs (P-F collisions) and between flocs (F-F collisions). In addition, corresponding collision efficiencies have been determined based on the proposed coalescence model. Moreover, the importance of three different fragmentation modes including binary flocs fragmentations (binary fragmentation), detachment of a primary particle from floc (erosion) and splitting of floc into smaller flocs (large-scale fragmentation) is comparatively assessed. Eventually, the effect of fluid velocity and primary particles concentration on the aforementioned processes as well as asphaltene flocs properties are examined. Simulation results reveal P-P collisions contribution decreases continuously to reach a plateau in steady state condition while the contribution of P-F collisions increases initially and then it shows a gentle downward trend. F-F collisions contribution grows constantly up to steady state condition. The P-P and P-F collision efficiencies approximately remain constant whereas F-F collision efficiency continuously increases. In terms of fragmentation modes, contributions of binary fragmentation and erosion gradually decrease while large-scale fragmentation contribution constantly increases before steady state condition.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): V.K. Premanadhan, V. Hernandez-Perez, Wan Thiam Teik, Nguyen Dinh Tam, Ove Bratland, W.L. Loh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉The increasing use of commercial flow simulators in the oil and gas industry provides the impetus to accurately model multiphase flows in pipelines. The current work investigates stratified oil-water flows in horizontal pipelines by experimentally measuring interfacial deformations, correlating them to interfacial friction. The derived interfacial model is then implemented into the two-fluid model to predict pressure losses in pipelines.〈/p〉 〈p〉An experimental campaign was undertaken using process oil (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈mi〉ρ〈/mi〉〈mo〉=〈/mo〉〈mn〉845〈/mn〉〈mi〉k〈/mi〉〈mi〉g〈/mi〉〈mo〉/〈/mo〉〈msup〉〈mrow〉〈mi〉m〈/mi〉〈/mrow〉〈mrow〉〈mn〉3〈/mn〉〈/mrow〉〈/msup〉〈/mrow〉〈/math〉, 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈mi〉μ〈/mi〉〈mo〉=〈/mo〉〈mn〉0.03〈/mn〉〈mi〉P〈/mi〉〈mi〉a〈/mi〉〈mo〉.〈/mo〉〈mi〉s〈/mi〉〈/mrow〉〈/math〉) and water as the test fluids in acrylic pipes of 40 mm diameter, with objectives of capturing interfacial deformations via image processing techniques, while also measuring pressure gradients in the pipe. The interfacial deformations were seen to increase with increasing flow velocities, plateauing with wave amplitudes of 3 mm. Further tests with identical fluids, conducted on larger diameter pipes (54.8 mm and 108.4 mm) also showed similar trend. Wave aspect ratios were correlated with a modified Froude number, linking the interfacial deformations to input flow variables.〈/p〉 〈p〉An empirical equation, utilizing the amplitude of interfacial deformations as roughness heights is derived for the interfacial friction factor. Incorporating the derived equation into the one dimensional two-fluid model, pressure losses were calculated and compared against experimental pressure drop measurements conducted in current work, as well as with those in literature. The performance of this model is also compared with existing prediction models and is found to provide improved accuracies across wide range of viscosity ratios and pipe diameters.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Shenglai Guo, Yuhuan Bu, Yao Lu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The setting time of the cement containing retarder at high temperature is longer than that at low temperature, which is an abnormal phenomenon and is adverse to the safety of cementing operation. Several kinds of retarders were chosen to demonstrate the abnormal phenomenon and to select the retarder with the ability to eliminate the abnormal phenomenon. Tartaric acid was found to be the only retarder which did not show the abnormal phenomenon. Moreover, it could eliminate the abnormal phenomenon of the cement containing a copolymer retarder. In addition, tartaric acid may also eliminate the abnormal phenomenon in cement containing other retarders, and it may be used with other retarders together to develop a compound retarder without the phenomenon of slow setting at high temperature. The elimination mechanism of the abnormal phenomenon was studied by comparing the hydration products of the cement containing AMPS-IA with the cement containing tartaric acid using XRD. Based on the results, there was a reduction in the hydration rate difference of tetra calcium aluminoferrite (C〈sub〉4〈/sub〉AF) between low and high temperatures after introducing tartaric acid, which could be the reason why tartaric acid could eliminate the abnormal phenomenon.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Mao Sheng, Shouceng Tian, Zhen Cheng, Hongkui Ge〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Fluid imbibition is a recognized strong phenomenon in tight shale that could greatly influences the dynamic failure behaviors. An experimental study was carried out to account for the influences of three typical drilling fluids (Air, Oil-based, and Water-based) on dynamic mechanics of tight shale. The collected samples were separated into three groups by the treatment of the distilled water saturation, white oil saturation, and drying, respectively. The dynamic properties involving Young's modulus, Compression strength, and specific energy consuming were experimentally measured by using Split Hopkinson Pressure Bar (SHPB). Results confirm that the fluid imbibition phenomena perform a promising influence on dynamic rock mechanics of tight shale. There are very different responses induced by air dry, oil, and water imbibition on dynamic rock strength, cutting size, and energy consuming. Oil imbibition is capable to enhance the strength, achieve uniform size of cutting, and consume less specific energy to break unit volume of rock. Comparatively, water imbibition sharply reduces the strength and consumes much less specific energy. Air dry condition makes much bigger and non-uniform cuttings and consumes the most specific energy. Those observations are no longer the same with obtained knowledge from sandstone and concrete, which attribute to the nanoscale pore distribution and fluid sensitivity of tight shale.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Ammar Al Helal, Adam Soames, Stefan Iglauer, Rolf Gubner, Ahmed Barifcani〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉One of the most discussed topics related to the effects of external magnetic fields (MF) on aqueous solutions is the influence on the scale formation of calcium carbonate (CaCO〈sub〉3〈/sub〉). However, the extent of the effect of these forces on the scale formation in the non-aqueous solutions has not been investigated so far. So MFs will be applied to non-aqueous mixtures to find out the behavior of scale formation. This study presents the results of inorganic scale formation within MEG solutions containing Ca〈sup〉2+〈/sup〉 and HCO〈sub〉3〈/sub〉〈sup〉−〈/sup〉 ions, which has been investigated using both static and dynamic scale loop (DSL) evaluation techniques. Furthermore, the influence of MFs on scale formation using the dynamic technique has also been studied. Results were generated using brine/MEG solutions exposed to an external MF produced by a 0.65 T Neodymium magnet for 2.5 s. The degree of scale formation was examined by measuring the pressure build-up across a capillary coil as scale was developed. Moreover, differences in CaCO〈sub〉3〈/sub〉 morphologies were evaluated for the exposed and blank trials via the DSL technique and compared with the results obtained from the static scale evaluation method.〈/p〉 〈p〉The results of this research have demonstrated that the short exposure (2.5 s) to a powerful MF can significantly reduce scale-formation in the rich MEG solutions within the capillary coil. This is due to the alteration of the proton spin inversion in the field of diamagnetic salts. Furthermore, a significant difference in CaCO〈sub〉3〈/sub〉 morphology was observed for the scale formed during dynamic and static conditions. The generating results help to reduce the use of chemical scale inhibitors with MEG solution during the gas hydrate treatments, especially when the concentration of MEG in formation water is low and scale formation is more likely to occur.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Bolivia Vega, Anthony R. Kovscek〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A two-dimensional Hele-Shaw cell was created to study and visualize hydrocarbon source rock (i.e., shale) elastic-brittle fracture and fracture network propagation mechanisms triggered by internal gas generation and gas build up during maturation of organic components. An analog immature source rock was created using a mixture of gelatin, sugar, and live yeast in pre-determined proportions. This mixture was poured into the Hele-Shaw cell and allowed to gel. The internal gas generated as a result of sugar fermentation by yeast caused pressure build up within the gel that ultimately resulted in the activation of dissipation mechanisms such as gas diffusion and deformation of the gel matrix. These mechanisms are analogous to shale maturation and fluid generation. Image analysis was employed to study and characterize key events such as fracture nucleation, propagation, and coalescence versus time. Derivative parameters such as fracture growth rate, fracture tip pressure, and fracture spatial distribution, among others, were calculated using the image-sourced data and applying Linear Elastic Fracture Mechanics (LEFM) principles. Results showed that the experiments are repeatable within a consistent response range and additional parameters were identified to be useful input for numerical modelling, including nucleation sites, fracture merging angle, merging to nucleation ratio, and fracture connectivity. For a volume of about 100 cm〈sup〉3〈/sup〉 of 11.6% wt. food-grade gelatin solution with 0.25% wt. yeast and a sugar/yeast ratio of 3, measured average total gas production was 35 cm〈sup〉3〈/sup〉 (at standard conditions). On an average gelatin matrix area of 400 cm〈sup〉2〈/sup〉, the average total fracture length and fracture density are 106 cm and 0.15 fractures/cm〈sup〉2〈/sup〉, respectively. Average maximum calculated fracture tip pressure and maximum fracture velocity are 0.92 psi and 5.85 × 10〈sup〉−4〈/sup〉 cm/s, respectively. Fracture connectivity was more frequent in the second half of the gas generation process and greater for the older and longer fractures. Average final fracture spacing was 4.42 cm. Connection angles between fractures tended to be closer to 0° than to 90°. Photoelasticity imaging techniques were applied to the experimental setup to visualize the stress field within the sample. The difference of principal stresses was estimated at 3.70 × 10〈sup〉3〈/sup〉 Pa for the tested material late in the maturation process. Results suggest interdependence of gas pressure, gas diffusion, and transient stress field states. The range of laboratory-scaled data are useful as benchmarking parameters for numerical modelling of source rock maturation including geomechanics.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308593-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Damian Janiga, Robert Czarnota, Jerzy Stopa, Paweł Wojnarowski〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉One of the most crucial tasks in hydrocarbon field development, it is an optimal wells placement. Simulation-based well placement optimization can be intricate to implement or computationally expensive. In this paper, a novel approach for the reduction of computational challenges by combining population-base optimization algorithm with self-adapt reservoir clusterization method to determine initial well placement position for the similar producing zones is presented. The developed methodology supported initial well placement location and allowed to shrink search space area. As a result, the computational time was decreased by 18% for particle swarm optimization and by 21% for genetic algorithm. Additionally, the project profitability was increased by 0.24% in case of genetic algorithm utilization and 0.59% for particle swarm optimization, what confirms the necessity for precise well placement localization. The average convergence factor for the employed algorithms increased from 18.43% to 60.78% for genetic algorithm and from 41.71% to 46.96% for particle swarm algorithm. An additional advantage of the developed clustering method is a notable reduction in time to reach high solution diversity in particle swarm algorithm. Increasing SOM training time for the large data set is negligible in comparison with full reservoir simulation run. The proposed methodology is based on the typical numerical model without requirement of additional dataset or streamline and can be easily transferred from field to field. The power and the workflow utility are demonstrated by the results of significant improvement for the algorithm's convergence rate and time.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Qingbang Meng, Zhongxian Cai, Jianchao Cai, Feng Yang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Oil production by spontaneous imbibition from matrix block can occur in both co- and counter-current modes when matrix block was partially covered by water. In this paper, oil recovery from partially water-covered matrix blocks with different boundary conditions was studied by numerical calculation. The boundary conditions were categorized and named according to the number of water-cover- and oil-covered-faces and relative position between water-covered- and oil-covered-faces. The numerical models with different boundary conditions were established. The water saturation distribution and direction of fluid flow in the matrix blocks were presented. In addition, the imbibition recovery curves of oil recovery versus imbibition time for different boundary conditions were presented and the effect of different factors on the rate of oil production was discussed. The calculated results showed that the area of water-covered-face has more significant effect on the rate of oil production than that of oil-covered-face. The distance travelled by fluids from water-covered-face to oil-covered-face is another important factor that affects the rate of oil production. The water imbibed from a certain water-covered-face preferentially displaces oil towards the closest oil-covered-face. Accordingly, three criteria for calculation of characteristic length for co-current imbibition is proposed and the close correlation of imbibition curves was obtained in the early stage of imbibition process by use of the proposed characteristic length to calculate the dimensionless time.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Xiankang Zhong, Wenjun Lu, Huaijun Yang, Min Liu, Yang Zhang, Hongwei Liu, Junying Hu, Zhi Zhang, Dezhi Zeng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉High pressure air injection (HPAI) is an effective and economic improved oil recovery process, however, the corrosion of tubing and casing in the injection well is one of the serious safety concerns which have limited its widely application. Until now the structure and composition of corrosion products formed in HPAI condition are still not fully clear because of the difficulty in simulating such a harsh environment in laboratory. In this work, the corrosion rates of N80 steel under laboratory conditions with different oxygen content (21–5% vol%), total pressure (50–20 MPa) and temperature (120–70 °C) simulating HPAI in Dagang oil field in China were investigated using weight loss measurement. The corrosion products on N80 steel surface were analyzed using scanning electron microscopy coupled with energy dispersive spectroscopy (SEM + EDS), X-ray diffraction (XRD) and transmission electron microscopy (TEM). The results show that the corrosion rate decreased with the decreasing oxygen partial pressure and temperature. Furthermore, for all the conditions, the corrosion rate was incredibly high in the simulating HPAI environment, consequently, large amount of corrosion products were formed. The corrosion products showed a two-layer structure: outer layer and inner layer. The outer layer was porous, brittle and easily flaked off, while the inner layer was more compact than outer layer. However, both layers could not effectively lower the corrosion rate of N80 steel in HPAI environment. The corrosion products were composed of hematite (α-Fe〈sub〉2〈/sub〉O〈sub〉3〈/sub〉), goethite (α-FeOOH), magnetite (Fe〈sub〉3〈/sub〉O〈sub〉4〈/sub〉) and trace amounts of Ca(OH)〈sub〉2〈/sub〉 and CaO. In addition, the structure and composition of corrosion products did not change with the temperature and oxygen partial pressure in the simulating HPAI conditions.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Kewei Zhang, Xiang Zhou, Xiaolong Peng, Fanhua Zeng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Steam injection is one of the major recovery methods to exploit heavy oil reservoirs. Replacing steam with hot solvent is an innovative idea to immensely decrease environmental pollution and energy consumption in steam-based recovery methods. The current hot solvent injection method attracts attention to the vapor solvent extraction (VAPEX) process. In comparison with the VAPEX process, cyclic solvent injection (CSI) process has been acknowledged as a high oil rate method due to the driving force of foamy oil flow. Hot solvent injection method is potentially applicable in the CSI process, which may increase the oil production rate and avoid the disadvantage of the VAPEX method. In this study, two experiments have been conducted to compare the production performance between the hot solvent-based CSI method and the hot solvent-based VAPEX method. The hot solvent-based CSI method is named the cyclic hot solvent injection method (CHSI). The hot solvent-based VAPEX method refers to the N-Solv method. N-solv is a patented method where the solvent is injected at the dew point temperature under the reservoir pressure condition. Due to the temperature difference between the reservoir and injected solvent, the injected solvent will condense in the reservoir and the condensed solvent will generate latent heat that can heat the reservoir chamber and thus reduce the oil viscosity (Nenniger and Gunnewiek, 2009). In this study, the N-Solv method has been studied in a laboratory test for the first time in N-Solv research history (Cao, 2011; Nenniger, 2005; Nenniger and Gunnewiek, 2009).〈/p〉 〈p〉According to experimental results, either of the two methods demonstrates some advantages in comparison with the other method from various aspects. From the production performance point of view, the recovery factor of the CHSI method is nearly 10% higher than that of the N-Solv method. The longer high oil rate period of the CHSI method in contrast with the N-Solv method indicates that the foamy oil behavior is more beneficial to the oil production compared with the gravity drainage and the solvent diffusion effect. In addition, it is shown from the solvent chamber growth difference that the gas flooding effect can enhance oil production in the CHSI process because the oil from gas-flooded area in the reservoir is clearly extracted out. However, according to the production GOR data, CHSI is a solvent-consuming method where a tremendous volume of free gas tends to be trapped in the solvent chamber as a result of gas flooding, which may offset the positive effect of gas flooding due to large consumption of solvent. The phenomenon of free gas trapping has not been found in the N-Solv process.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Alexandre Lavrov, Mohammad Bhuiyan, Anna Stroisz〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Bonding between cement and steel is currently believed to be of key importance in well integrity since it prevents the development of microannulus. Push-out test is often used to quantify the bonding strength between cement and steel in laboratory. Our experiments reveal a strong size-dependency of the push-out strength measured in these tests: the strength decreases with pipe diameter. This means that the push-out strength is not an intrinsic material parameter ("bonding strength") and therefore cannot be applied to field conditions before a proper correction is introduced. Such correction should take into account the large difference in diameter between the casing and the pipes typically used in laboratory tests. Finite-element simulations show that the experimentally-observed size-dependency could be, at least partially, explained by cement shrinkage that creates initial normal stress at the interface. The observed push-out strength is then not an intrinsic property of the interface between two materials (which would be an adhesive shear strength) but rather a result of interfacial friction. As the pipe diameter increases, the shrinkage-induced normal stress at the interface decreases, the frictional resistance decreases, and thus the measured push-out strength decreases, too, as observed in the lab tests. Simulations show, however, that shrinkage-induced decrease in push-out strength cannot fully explain the size-dependency since the decrease is much larger in the experiments than in the simulations. Another mechanism that could be at play is the common size effect: interfaces become weaker as their size increases because it is more likely that a larger interface contains an initial flaw of a given size. The decrease of push-out strength with pipe diameter has at least two practical implications: (i) the concept of bonding strength is misleading (unless it is specified explicitly that this parameter refers to frictional resistance at the interface rather than to an inherent adhesive strength) and (ii) the results of push-out tests can be used in well design only if a proper correction for the pipe diameter is introduced.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Xin Du, Zhiwei Lu, Dongmei Li, Yandong Xu, Peichao Li, Detang Lu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Fractured vuggy carbonate reservoirs consist of matrix, fractures, and vugs. The existence of vugs in fractured vuggy carbonate reservoirs has long been observed. The volume of a vug is an important parameter owing to the large contribution of vugs to oil reserves. However, there are no reliable well test methods to estimate the volume of a vug yet. In this study, a new analytical well test model considering the coupling between oil flow and wave propagation is proposed. First, the mathematical model is established. Then, combined with the seepage equations in the outer formation, the analytical solutions of transient pressure in the wellbore are obtained through Laplace transformation and inversion. Second, based on the above analytical solutions, the standard log-log type curves are plotted to recognize the flow characteristics. It was found that, the flow in the wellbore and large vug can be divided into six distinct flow regimes. The volume of the large vug can be obtained by pressure transient analysis. Considering the coupling between oil flow and wave propagation, there will be one more V-shaped segment than typical triple-continuum pressure derivative curve. Third, a comparison with the triple-continuum model is performed to verify the validity and reliability of the proposed model in this study as well as a reservoir study. Finally, sensitivity analysis of some key parameters on the pressure derivative are carried out. Through the sensitivity analysis of different parameters for the well test type curves, it is found that the change in these well test curves is in accordance with the findings of the theoretical analysis. The curve behaviors are influenced by the friction coefficient, fluctuation coefficient, damping coefficient, storage ratios, and inter-porosity flow coefficients. The depth of the first V-shape segment is mainly affected by the friction, fluctuation, and damping coefficients. The depths and locations of the second and third V-shape segments are mainly influenced by the storage ratios of the fracture and vug, and inter-porosity flow coefficients within the matrix, fracture, and vug.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Xinxin Zhang, Shaohe Zhang, Yongjiang Luo, Dongyu Wu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Rotary-percussion drilling with mud as the energy carrier is a competitive method for the production of drill-holes. Fluidic hammer is a type of rotary-percussion drilling tool actuated by a fluidic oscillator based on the Coanda effect. By using a fluidic hammer, penetration rate can be significantly improved. With few movable or deformable parts, fluidic hammers are resistant to high temperatures, high pressure, corrosive and other extreme environments. Moreover, drilling through soft or inter-bedded formations need not stop to change bottom-hole assembly and can continue even though the fluidic hammer fail to operate. Given these advantages, fluidic hammers are convinced to be popular in the coming years and deserve being better known in the rotary-percussion drilling. In this work, a sequence of experimental investigations focused on the operability and effectiveness of a newly designed fluidic hammer under different sets of operational and physical parameters were performed. Some important impacting performance parameters in terms of impact velocity, impact frequency and impact force were obtained from the experimental results to evaluate the working performance of the fluidic hammer and the effect on bit life. An exponential function model was proposed to describe the piston motion. Comparison between the predicted values of the impact period obtained from the theoretical model and the experimental results reveals the rebound effect of the piston-hammer as it strikes the anvil or cylinder on the impact performance of the fluidic hammer. Furthermore, a field trial using a fluidic hammer was conducted in a horizontal directional well drilling to evaluate its effectiveness. An average improvement of 32.7% in penetration rate was recorded.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): N. Farah, M. Delorme, D.Y. Ding, Y.S. Wu, D. Bossie Codreanu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Due to their initial low permeability, unconventional plays can be economical only through hydraulic fracturing. This process, in order to be controlled needs to rely on a solid representation of the natural fracture geometry, an accurate stimulation model which considers the interaction with natural lineaments, and a physical reservoir model which can account for the different flow regimes occurring during production. The stimulated volume drainage can be evaluated using either Decline Curves Analysis/Rate Transient Analysis (DCA/RTA) techniques or reservoir simulation. In both cases, the geometry of the final Discrete Fracture Network (DFN) issued from the natural characterization and the stimulation, is very important, and for practical purposes is either overly idealized (Warren & Root approach) or oversimplified (Bi-wing). The models have shown their limitations when confronted with measurements in the field, opening up ways to use DFN geometries within integrated reservoir studies.〈/p〉 〈p〉The present work addresses some of the issues above, developing a hierarchical Discrete Fracture Model (DFM) based on the “filtering” of a stimulated DFN, realistically obtained by the characterization step and the stimulation process. This leads to a triple-continuum representation, consisting of: (1) the matrix media, (2) a high conductive stimulated fracture network and (3) a low conductive stimulated fracture network.〈/p〉 〈p〉The method consists in homogenizing low conductive networks, keeping a user defined backbone of high conductive fractures as the main “reservoir” DFN. One of the main advantages of this DFM relies on the way we compute the well-known Multiple Interacting Continua (MINC) approach, using a “proximity function” formalism, able to simulate transient effects. Using practical examples, this paper demonstrates applicability capacities of this method, enabling the integration of more complex geometries within a “quick” simulation framework.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Scott H. McKean, Jeffrey A. Priest〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes.〈/p〉 〈p〉The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed.〈/p〉 〈p〉The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve – an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Hatice Tombul, A. Murat Ozbayoglu, M. Evren Ozbayoglu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In multi-phase flow, the gas phase, the liquid phase and the particles (cuttings) within the liquid have different flow behaviors. Particle velocity and particle direction are two of the important aspects for determining the drilling particle behavior in multi-phase flows. There exists a lack of information about particle behavior inside a drilling annular wellbore. This paper presents an approach for particle velocity and direction estimation based on data obtained through Particle Image Velocimetry (PIV) techniques fed into computational intelligence models, in particular Artificial Neural Networks (ANNs) and Support Vector Machines (SVM). In this work, feed forward neural networks, support vector machines, support vector regression, linear regression and nonlinear regression models are used for estimating both particle velocity and particle direction. The proposed system was trained and tested using the experimental data obtained from an eccentric pipe configuration. Experiments have been conducted at the Cuttings Transport and Multi-phase Flow Laboratory of the Department of Petroleum and Natural Gas Engineering at Middle East Technical University. A high speed digital camera was used for recording the flow at the laboratory. Collected experimental data set consisted of 1080 and 1235 data points for 15° inclined wellbores, 1087 and 1552 data points for 30° inclined wellbores and 885 and 1119 data points for horizontal (0°), wellbores respectively to use in estimation and classification problems. Results obtained from computational intelligence models are compared with each other through some performance metrics. The results showed that the SVM model was the best estimator for direction estimation, meanwhile the SVR model was the best estimator for velocity estimation. The direction and speed of the particles were estimated with a reasonable accuracy; hence the proposed model can be used in eccentric pipes in the field.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Kuilin Huang, Zhijiu Ai, Yingxin Yang, Zongliang Xie〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉To solve a major problem faced by drilling technicians, that of how to improve rock breaking efficiency in complex strata, this paper introduces a polycrystalline diamond compact (PDC) drill bit with a special structure. Static-pressure breaking tests show that the breaking work ratio of a single tooth on a ridge is much smaller than that on flat rock samples, and the effect of ridge height on breaking work ratio is greater than that of ridge width. Single-tooth scrape tests show that the tangential force, axial force, and breaking work ratio of PDC teeth when scraping on a ridge are greatly reduced compared with flat rock samples, and the ridge width has a greater influence on the breaking work ratio than ridge height. A test bit with a diameter of 215.9 mm and the possibility of zero, one, or two annular grooves is designed and manufactured. Compared with the conventional, full-coverage PDC bit, the specific energy of the double-groove bit is reduced by 26.9%. The annular-groove PDC bits achieve large-scale cuttings when breaking the ridge created by the bit, and the rock breaking efficiency is greatly improved. At the same time, the raised ridges of the bottomhole increase the stability of the drill bit, providing a feasible solution for rock breaking when drilling complex strata.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Utkarsh Sinha, Birol Dindoruk, Mohamed Y. Soliman〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉One of the important challenges in the oil industry is to transport high viscosity heavy oils through pipelines while minimizing potential transport issues due to implications of asphaltenes. After evaluation of what is available in the literature (Pal and Rhodes, 1989; Krieger and Dougherty, 1959), we have developed a new correlation for relative viscosity of heavy oils which is not only simpler with easy to obtain input data but also more accurate than the leading correlations published in the literature. For example, the proposed correlation requires the incorporation of only one fluid-specific parameter where the structure and size of unsolvated asphaltene nanoaggregate was taken based on the “Yen-Mullins” (Mullins et al., 2012) model. To check the accuracy and validity of the correlation along with the assumptions utilized, calculated values of the relative viscosity were cross-plotted against the available experimental data from the literature. The results were also compared with the results obtained from some of the leading published correlations, such as “Pal - Rhodes” (Pal and Rhodes, 1989) and “Krieger - Dougherty” (Krieger and Dougherty, 1959) correlations. The R〈sup〉2〈/sup〉 (R-squared) along with the other statistical parameters obtained for our model were shown to be superior to the other correlations considered, indicating that our correlation is able to explain the relative viscosity variations with respect to the selected parameters better than the subject set of correlations. In addition, we have also developed a methodology to predict the value of maximum packing volume fraction of asphaltene particles dispersed in deasphalted oils that can also be used in calculating the relative viscosity using “Krieger - Dougherty” (Krieger and Dougherty, 1959) and “Brouwers” (Brouwers, 2010) models.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Frank Male〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This study attempts to characterize the uncertainties in production forecasting for unconventional gas wells through hindcasting. The analysis focuses on how results from decline analyses change as the well population ages. The study is based on publicly available and subscription-based production data on 34,000 shale gas wells in the Marcellus, Fayetteville, Haynesville and Barnett plays. A hindcasting analysis was performed on wells, where production has been forecast using a physics-based decline curve analysis. This allows the accuracy of decline methods to be tested and the nature of errors to be assessed. Based on this analysis, the study identified systematic and random errors that impact estimates of ultimate recovery. Fields where few wells have entered boundary-dominated flow show higher uncertainty for field-wide production forecasts. Uncertainty decreases as more production history is accumulated. The physics-based approach for decline curve analysis is shown to be robust through hindcast analysis. The uncertainty in per-well recoveries for the fields studied are in the range 4–8%. The uncertainty in field-wide average ultimate recovery is less than 4% for three of the fields and 5.6% for the Marcellus. Understanding the sources and magnitudes of errors and uncertainties in estimated ultimate recovery values for unconventional gas wells allows operators to account for these in determining economic outcomes and performing financial planning of wells.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Jian Tian, Yili Kang, Pingya Luo, Lijun You, Dujie Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Displacement pressure difference and initial water saturation are two key factors of evaluating water phase trapping (WPT) damage under a given reservoir situation. Requiring a high displacement pressure to drive liquid through a tight rock, the conventional method has difficulty in measuring very small liquid flow rates. Besides, it exists a strongly advantageous flow path selectivity phenomenon, causing a situation that the water existing in those thinner pores cannot be moved effectively. As a result, the irreducible water saturation is high after oil displacing water, thus leading to an overestimated oil permeability damage from WPT. This paper would have presented a high back pressure displacement method (HBPD) for the establishment of initial water saturation and measurement of liquid permeability of core samples from tight oil reservoirs. Then the damage of WPT using this new method was compared with the results obtained by the conventional method. According to the reservoir fluid flow situation, pore pressure and downstream pressure were simulated by the operation of back pressure. Results showed that an average initial water saturation (〈em〉S〈/em〉〈sub〉〈em〉wi〈/em〉〈/sub〉) of 46.2% was established by the conventional method. However, the 〈em〉S〈/em〉〈sub〉〈em〉wi〈/em〉〈/sub〉 established with the use of this new method was only 29.9%, which was consistent with the results from sealed core data of the reservoir. The oil permeability damage derived from water phase trapping was estimated as an average of 37.0% with the conventional method while that of 21.8% by the new method respectively. The conventional method overestimated the damage of water phase trapping at 41.4%. Our research appears to have an insight into analyzing oil-water flow behaviors and investigating the reservoir forming process of tight oil reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Sadra Rostami, Fariborz Rashidi, Hossein Safari〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Relative permeability of multiphase flow through porous media plays a vital role in the petroleum industry, especially in enhanced oil recovery (EOR) processes. In this study, models were developed based on a combination of Least-Square Support Vector Machine and Couple Simulated Annealing (CSA-LSSVM) algorithm to predict oil-water relative permeability in sandstone and carbonate porous media. Comparing the model to thousands of experimental data resulted in overall squared correlation coefficients (R〈sup〉2〈/sup〉) of 0.9866 and 0.9965, and minimum squared errors (MSEs) of 0.0014 and 0.000143 for K〈sub〉ro〈/sub〉 and K〈sub〉rw〈/sub〉, respectively. In addition, Model predictions were found to agree excellently with experimental data. The results of CSA-LSSVM model were compared with some of the well-known mathematical equations including the Purcell, Burdine, Brooks and Corey, Corey, and some empirical correlations for predicting the oil-water relative permeability in a heterogeneous carbonate core sample. The models developed in this study outperform the mathematical equations and empirical correlations yielding an overall squared correlation coefficients of 0.9987 and 0.9994, and minimum squared errors of 0.0003 and 0.0049 for K〈sub〉ro〈/sub〉 and K〈sub〉rw〈/sub〉, respectively. Finally, leverage value was introduced to analyze the whole dataset from which 19 points were diagnosed as possible outlier experimental data.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Taimoor Asim, Rakesh Mishra, Antonio Oliveira, Matthew Charlton〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Control valves are an integral part of a number of energy systems, such as those used in chemical and nuclear industries. These valves are used to regulate the amount of fluid flow passing through these systems. A key component of a control valve is its trim, which in case of a multi-stage continuous-resistance trim consists of a staggered arrangement of columns. Flow passing through the channels formed between adjacent columns (also called as flow paths), loses a significant amount of its energy and regulates the pressure field. As the geometrical features of these flow paths dictate the flow capacity of the trim, systematic investigations have been carried out to analyse the complex flow behaviour within these flow paths. Well-verified computational fluid dynamics based solver has been used to investigate the effects of the geometrical features of flow paths on the flow capacity of the trim, at various valve opening positions. It has been noticed that reducing the size of flow paths increases the flow capacity of the trim, however, at a critical flow path size, the inherent opening characteristics of a trim have been observed to alter. In order to recover the original opening behaviour of the trim, careful manipulation of the flow paths is required, which has been successfully achieved in the present investigation.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308052-fx1.jpg" width="268" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Bingqiang Dong, Meng Meng, Zhengsong Qiu, Zhaohui Lu, Ye Zhang, Hanyi Zhong〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet. This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Daihong Gu, Daoquan Ding, Zeli Gao, Leng Tian, Lu Liu, Cong Xiao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Based on fractal theory (FT) and fractional calculus (FC), a new fractally fractional diffusion model (FFDM) of composite dual-porosity has been developed to evaluate performance of multiple fractured horizontal wells (MFHWs) with stimulated reservoir volume (SRV) in tight gas reservoirs (TGRs). More specifically, FT is used to characterize the complex and heterogeneous fracture network (FN) both inside and outside of SRV, while anomalous behavior of diffusion processes both inside and outside of SRV is quantified by applying the temporal fractional derivatives. The FFDM is then solved by the Laplace transformation, line source function, the numerical discrete method, and superposition principle. The transient pressure responses are then inversely converted from Laplace domain into real time domain with the Stehfest algorithm, and the FFDM is also validated, and type curves are generated as well. Flow stages are subsequently identified together with analysis on characteristics of the type curves, especially the anomalous features different with those generated from the conventional Euclidean model. Sensitivity analyses of some related parameters have also been discussed as well. And the FFDM is then also matched with the real field well-testing data of a MFHW with SRV in a TGR. The proposed FFDM provides a new understanding of the performance of MFHWs with SRV in TGRs, which can be used to interpret the field pressure data more accurately and appropriately.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉The SRV includes the main hydraulic fractures, the Euclidean matrix, and the fractal micro-fractures, while the USRV contains the Euclidean matrix and the fractal natural fractures. The flow of the gas in SRV and USRV follows the temporal fractional anomalous diffusion. By discretizing the main hydraulic fractures and applying the Laplace transformation, line source function, and superposition principle, we can obtain the pressure responses of a MFHW with SRV in a tight gas reservoir. Flow regime diagnostics and the characteristics analysis of type curves are accomplished, especially the anomalous characteristics.〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308647-fx1.jpg" width="437" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Fengrui Sun, Yuedong Yao, Guozhen Li, Shikun Zhang, Zhengming Xu, Yu Shi, Xiangfang Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Shale oil reserves are becoming more important with the development of oil & gas industry. However, the transport mechanisms of oil in nanopores of kerogen remain a mystery. The understanding of the multiple transport mechanisms of oil in nanopores is crucial in the successful development of shale oil reservoirs. In this paper, a new model for flow enhancement of oil transport in nanopores of kerogen is proposed. Both boundary slip and physical adsorption are taken into consideration in the analytical model. Based on the previous experimental and theoretical studies, the model is validated.〈/p〉 〈p〉Results show that: (a) Covering the Hagen–Poiseuille flow, specific oil flow and the water flow, the new model is more universal in practice; (b) When the radius of the nanotube is equal to 1 nm, the value of slip factor is between 24081 and 48161 (the corresponding correction factor is between 0.7 and 1.4); (c) the flow enhancement is negligible when the radius is larger than 10 nm under various values of correction factor conditions. Besides, the flow enhancement increases with the increasing of the correction factor; (d) when the correction factor is small, the section of the curve higher than zero is characterized with short and low; (e) when the correction factor is smaller than 0.007, the normalized velocity increases slowly with increasing of the correction factor. When the correction factor is higher than 0.07, the normalized velocity increases rapidly when the transport length in nanopores is increased from 10 nm to 200 nm.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Xianbo Su, Shun Yao, Jinxing Song, Qian Wang, Feng Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Slug flow, which can cause severe velocity sensitivity damage to coalbed methane (CBM) reservoirs, tends to happen at the gas-liquid two-phase flow stage during the CBM production process. However, little attention has been paid to this phenomenon. This paper investigates the factors which can influence the forming of slug flow in CBM reservoirs systematically via a series of laboratory experiments and production data from two CBM wells. Results show that a slug flow is more likely to be formed under the conditions of high reservoir permeability, high fluid surface tension and high producing differential pressure. This is because that both the high permeability and high production differential pressure would lead to a high fluid flow velocity that can cause strong Kelvin-Helmholtz instability effect of the interface wave. Then, the strong Kelvin-Helmholtz instability effect will cause the slug flow. Meanwhile, a high fluid surface tension means that the liquid will form slug flow more easily. The most effective way to restrain slug flow is to utilize a fracturing fluid with low surface tension in combination with continuous, slow and stable productions.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Lanxiang Shi, Desheng Ma, Pengcheng Liu, Xiuluan Li, Changfeng Xi, Chao Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Steam-Assisted Gravity Drainage (SAGD) has been demonstrated as an effective process for recovering extra-heavy oil. However, large volumes of steam are required to heat the viscous oil, resulting in high consumption of natural gas and water, which affects its economic benefit. Therefore, research has long focused on improving the SAGD performance. In this study, a viscosity reducer (VR) assisted SAGD (VR-SAGD) process is systematically examined by experiment and numerical simulations based on an extra-heavy oil sample from a commercial SAGD block in Xinjiang oil fields, China. A scaled two-dimensional (2D) VR-SAGD experiment is carried out using a scale model to study the mechanisms of production dynamics and to observe the steam chamber development phases of the VR-SAGD process. A history match is conducted based on the 2D experimental data, and the recovery mechanisms of VR-SAGD are discussed. Heterogeneity in terms of barriers sandwiched in the pay zone is studied, and operational parameters are optimized based on the history match results. The 2D physical simulation results show that VR-SAGD accelerates the oil rate by a factor of 1.74 and reduces the instantaneous steam-to-oil-ratio by 49.7%. The VR co-injected with steam propagates in advance and accumulates at the front of the steam chamber and around the barriers to accelerate the effect of viscosity-reduction and reduce the heat loss to the overburden. Numerical simulation results indicate that the optimum time for VR injection is during and after the phase when the steam chamber expands sideways. The optimized VR/steam volume ratio and production/injection volume ratio are 1:9 and 1.2:1, respectively. The VR-SAGD process shows good potential to improve post-SAGD performance and reduces steam consumption in extra-heavy oil reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Shang Xu, Fang Hao, Changgui Xu, Huayao Zou, Xintao Zhang, Yi Zong, Yuanyin Zhang, Fuyun Cong〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉An important exploration breakthrough has been achieved in the western subsag of the Bozhong subbasin, but the hydrocarbon accumulation mechanism was not clear. The hydrocarbon migration and accumulation mechanism of the western subsag of the Bozhong subbasin is discussed based on the modeling of hydrocarbon migration pathways and the study of late-stage reactivation of neotectonic faults. Three processes for lateral petroleum migration and accumulation can be recognized in the studied area: 1) migration and accumulation along the T8 unconformity; 2) migration and accumulation within the Guantao Formaiton (N〈sub〉1〈/sub〉g); and 3) interaction of migration and accumulation along the T8 unconformity and Guantao Formation (N〈sub〉1〈/sub〉g). The reactivation of faults in the studied area began 5.1 Ma. Following hydrocarbon lateral migration, late-stage reactivated neotectonic faults serve as effective vertical conduits for hydrocarbon migration and accumulation into the shallow Minghuazhen Formation (N〈sub〉1〈/sub〉m) reservoirs.〈/p〉 〈p〉The modeling results of preferential petroleum migration pathways (PPMPs) and favorable accumulation areas are consistent with the actual exploration results. Two kinds of potential exploration targets can be predicted in the northwestern Bozhong subbasin: the first kind is hydrocarbon accumulation areas near or within generative kitchens (e.g. Target 1); the other kind is hydrocarbon accumulation areas removed from the generative kitchens, but with hydrocarbon sourcing from multiple generative kitchen and numerous PPMPs (e.g. Target 2). Studying preferential petroleum migration pathways will help reduce exploration risk.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Hao Zhang, Hui-qing Lan, Nan Lin〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Internal corrosion of pipeline is often observed at the pipe bottom, especially at the pipe elbow, which may bring great threat to personnel safety and cause serious environmental pollution once the pipeline perforation happens. The pipe wall will get thinned by corrosion when it is wetted by produced water dissolved with various corrosive media. Therefore, it is essential to predict the water distribution in pipelines and determine the continuous phase that wets the pipe wall when analyzing the internal corrosion of crude oil pipelines. This paper aims to study key parameters, such as water cut, mixture velocity, oil viscosity and inclination angle of pipes, that dominate water distribution and the phase that wets the wall of pipe bottom by applying computational fluid dynamics. The results of numerical simulation are proved to coincide well with the available experimental results.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Qing Yuan, Jingfa Li, Hongfei Liu, Bo Yu, Dongliang Sun, Yajun Deng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The waxy crude oil exhibits a time- and shear-dependent non-Newtonian behavior called thixotropic behavior below the gelation temperature. This behavior can be quantitatively described by using a thixotropic model. However, many parameters are commonly contained in a thixotropic model with good-description capacity, and it still remains challenging to obtain high fitting precision and reasonable physical interpretation simultaneously in the process of parametric regression. In this study, based on a representative multiparameter thixotropic model, a multiobjective regression strategy is put forward. The fitting precision and physical interpretation are taken into account in this regression strategy, and their importance can be adjusted dynamically with the structure breakdown of waxy crude oil. In order to successfully achieve the multiobjective regression strategy, a self-adaptive nondominated sorting differential evolution algorithm (self-adaptive NSDE) is proposed. This regression algorithm is independent on the expressions of the regression model, and thus it can also be applied to the multiobjective parametric regression of other complex models including thixotropic models in rheology field and even other models in different fields. Based on experimental data, the parametric regression of a thixotropic model is performed, and the obtained results are analyzed and discussed in detail. It is found that the regressive data exhibit a small deviation at the starting stage of structure breakdown and the equilibrium flow curve can be ensured at the ending stage of structure breakdown. This finding well verifies considerations of multiobjective regression strategy. Compared with previous three regression strategies in the literature reports, the multiobjective regression strategy exhibits advantages in the fitting precision and physical interpretation.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Daniel R. Nolansnyder, John Parnell〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Primary and secondary porosity in sandstones possess different pore geometry characteristics, but these are not well quantified. The pore surface area in 2 suites of sandstones exhibiting only primary porosity (Permo-Triassic, Northern Ireland) and only secondary porosity (Cambrian, England) were measured using JMicrovision software. The data show pore surface areas per unit pore volume ∼2.5 times as great in the secondary porosity compared to the primary porosity. This difference is great enough to have a significant impact on properties dependent on pore surface area, including oil production and capacity for microbial colonization in the deep biosphere.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Solmaz Karimi, Ehsan Firouzfar, Mohammad Reza Khoshchehreh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In the current paper, the effect of various concentrations of polyethylene glycol (PEG) on properties of PEG-blended polysulfone (PSU) gas separation membranes was investigated. Scanning electron microscopy (SEM), Fourier-transform infrared spectroscopy (FTIR), and x-ray diffraction analysis were applied to assess membrane morphology as well as chemical and phase structure, respectively. The obtained results confirmed the dense asymmetric structure in membrane cross sectional morphology. Moreover, the PSU/PEG membranes were found to be consisted of amorphous regions without any crystalline structure. In addition, gas permeability and selectivity of obtained membranes were investigated with respect to pure gases of N〈sub〉2〈/sub〉, O〈sub〉2〈/sub〉, CH〈sub〉4〈/sub〉, and CO〈sub〉2〈/sub〉 and membrane CO〈sub〉2〈/sub〉 plasticization was studied at varying pressures. According to the results, CO〈sub〉2〈/sub〉 accounted for the highest gas permeability at all PEG concentrations while CH〈sub〉4〈/sub〉 and N〈sub〉2〈/sub〉 represented the lowest gas permeability through the pure PSU and PEG-blended PSU membranes, respectively. CO2 permeability was found to decrease and then increase with increasing feed pressure at various PEG concentrations with the highest variation of permeability at 20 wt % PEG.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Bin Pan, Yajun Li, Liujuan Xie, Xiaopu Wang, Qingkun He, Yanchao Li, Seyed Hossein Hejazi, Stefan Iglauer〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Hydrocarbon recovery and reserves estimation largely depend upon the hydrocarbon-water-mineral wettability. However, wettability is a complex parameter and experimental measurements are still open to large uncertainty. We thus demonstrate here that quartz wettability correlates with the density of the non-aqueous fluid, e.g. oil, CO〈sub〉2〈/sub〉, N〈sub〉2〈/sub〉, etc. – which can be in a liquid, gaseous or supercritical form. This insight significantly simplifies wettability assessments, thus enhancing fundamental understanding of wettability and the related fluid dynamics in siliciclastic hydrocarbon reservoirs. Furthermore, this observed correlation may promote hydrocarbon recovery and reserves prediction in siliciclastic reservoirs.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S092041051830843X-fx1.jpg" width="296" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Ping Zhang, Zhang Zhang, Yuan Liu, Amy T. Kan, Mason B. Tomson〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Mineral scale deposition is a water-associated production threat for oil and gas productions. Scale deposition can lead to pipe throughput reduction and change in facility surface properties. Scale inhibitors are widely used in oilfield operations to control scale deposition. Fe(II) (ferrous) species is commonly encountered in oilfield produced waters and it is widely recognized that the presence of Fe(II) can impact the performance of scale inhibitors. However, the existing experimental results of Fe(II) impact on scale inhibitors are controversial, especially in barium sulfate system. This is partially due to the difference in dissolved oxygen level among different studies since a trace amount of dissolved oxygen can readily oxidize Fe(II) into Fe(III). In this study, a rigorously-maintained laser-based anoxic experimental setup was adopted to evaluate the impact of Fe(II) species on scale inhibitor performance in controlling barium sulfate scale. The anoxic setup utilized argon gas purging and reducing chemical addition and can maintain a dissolved oxygen level in μg L〈sup〉−1〈/sup〉 (ppb) level. The experimental results suggest that at an anoxic condition, the presence of Fe(II) has a detrimental impact on the performance of scale inhibitors and such impact varies with different types of scale inhibitors. Solution pH and temperature can also affect the Fe(II) impact on scale inhibitors. In addition, two common oilfield chelating chemicals, i.e., EDTA and citrate, have been evaluated for their roles in reversing the detrimental impact of Fe(II) on scale inhibitors. It shows that at the experimental condition only citrate can effectively reverse the adverse impact of Fe(II) on scale inhibitor. This study provides the experimental approach and technical insights for evaluation of scale inhibitor performance in an anoxic condition.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308246-fx1.jpg" width="257" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Anna M. Radovanovic, Adolfo P. Pires, Alvaro M.M. Peres〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Enhanced Oil Recovery (EOR) is a process that extends reservoir life through field operations that aim to increase reservoir displacement efficiency. Injection of polymeric solutions, which is a chemical EOR process, improves sweep efficiency by decreasing the mobility of the injected fluids. One challenge in polymer flooding is to model the non-Newtonian rheological behavior of the injected solutions due to the complex interdependence between fluid flow velocity, fluid viscosity and shear rate. Proper reservoir management requires a thorough understanding of non-Newtonian fluid flow behavior through porous media, thus the need for new and improved mathematical models that describe the transient pressure behavior in wells. In this work we consider the flow of non-Newtonian pseudoplastic fluids in homogeneous isotropic porous media. To describe the rheological polymer behavior, we used the well-known power-law model, which leads to a nonlinear problem. In this paper, a novel semi-analytical solution is obtained by combining spatial domain discretization with pseudotime, so the flow problem is rewritten as a system of linear equations in Laplace domain. We also presented a variation of the proposed solution by assuming a pseudostationary behavior of the non-Newtonian velocity. Both approaches are compared to previously published approximated analytical solutions. One interesting aspect of our work is that it can be extended to more realistic polymer rheological models.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Hanyi Zhong, Guangcheng Shen, Zhengsong Qiu, Yongxue Lin, Lijun Fan, Xiaodong Xing, Jia Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Filtration control of drilling fluid plays an important role in the process of wellbore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 °C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 °C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Hui Gao, Chen Wang, Jie Cao, Mengqing He, Liangbin Dou〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉For tight sandstone reservoirs, the pore structure is sensitive to the stress variations during the production process. The alternation of pore structure influences the petrophysical properties and therefore the dynamic flow of tight sandstone reservoirs. In this research, Nuclear Magnetic Resonance (NMR) technique is employed to quantitatively study the pore volume variation under different confining pressures. Not only during the compression process, this research also investigated the sandstone pore sensitivity to stress during the recovery process of rock samples, which is equally important and happens during the production process when the formation pressure is building up due to the temporary well shut-in or water injection. The core samples selected from Ordos basin are first tested routinely for basic parameters like porosity, permeability and detrital components, and then through both compression and recovery processes where the pressure decreases and increases, respectively. It is found that the core samples with high permeability show stronger stress sensitivity of pores than those with low permeability due to the higher content of large pores. Besides permeability, detrital components and interstitial material can also affect the stress sensitivity of pores. During the recovery process, the low recovery degree of pore volume is related to the recoverable pore size (mainly smaller size pores) and the narrow distribution range of recovered pores. Furthermore, the power function relationship and the exponential relationship are suggested to evaluate the variation of pore volume in compression and recovery process, respectively. The results demonstrated that the compressibility of larger pores is bigger than that of smaller pores. During the compression process, the higher permeability rocks, containing a higher content of larger pores, are easier to be compressed, and has a greater decrease in permeability. Besides, the recoverability of the total pore volume after compression is mainly controlled by smaller pores, which results in the lower recoverability of the total pore volume and the permeability for the higher permeability core samples.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Hailong Jiang, Gonghui Liu, Jun Li, Tao Zhang, Chao Wang, Kai Ren〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A gas kick may occur when drilling with narrow pressure margin, which can lead to significant non-productive time. This paper proposes an early gas kick detection method applicable to water-based mud (WBM), which integrates a transient pressure and temperature coupling model into an unscented Kalman filter (UKF) algorithm. Three pressure factors and a flow rate factor are estimated with the UKF algorithm using updated measurement data in a detection estimator, and a generalized likelihood ratio test (GLRT) is employed to automatically detect changes in the pressure factors and flow rate factor for prediction of the gas kick. Simulated results show that the estimated pressures and outlet flow rate trace synthetic measurements very well with continuous inversion of the pressure factors and flow rate factor. All of the estimated pressure factors and flow rate factor fluctuate to a little extent around a base value under normal drilling condition, while the pressure factor in annulus and flow rate factor both deviate from the base value when the gas kick occurs. Performances of the proposed method, pit gain monitoring method and delta flow monitoring method are contrasted. The kick detection times are gradually reduced for all the methods with the increase of gas kick rate. Moreover, the proposed method herein shows a much better performance than the pit gain and delta flow monitoring methods, especially at small gas kick rate.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Bo Zhang, Zhichuan Guan, Nu Lu, A. Rashid Hasan, Qing Wang, Boyue Xu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Trapped annular pressure is caused by thermal expansion due to heat transfer and has become one of the serious challenges to well safety. In order to assess and mitigate this risk, this paper reviews the engineering background, prediction approaches, and mitigation measures for trapped annular pressure. It is well understood now that heat source and trapped space filled with liquid are the two basic preconditions for trapped annular pressure to occur. The accurate prediction is precondition of risk analysis and foundation for the mitigation design. The risk analysis determines the mitigation necessity and mitigation goal. To enhance prediction accuracy, temperature change, wellbore fluid properties, annulus and annular liquid volume change must be considered. Additionally, experiments are also needed to calibrate and validate theoretical models. The risks are mainly reflected in the reduction of casing reliability and integrity of wellbore seal. A number of mitigation approaches are available that vary in cost, effectiveness and operational difficulty. Encouragement is needed to develop novel measures to improve mitigation effect with low cost. The decision-making system are divided into four steps and can help to prevent potential risk of trapped annular pressure with low cost and high effectiveness.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Carina Nogueira Sondermann, Renan Martins Baptista, Felipe Bastos de Freitas Rachid, Gustavo Cesar Rachid Bodstein〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The analysis of two-phase flows through numerical simulations is a very useful tool to design and operate long pipelines. It is also important for monitoring the flow during adverse situations, such as the formation of hydrates and wax deposition that may occur due to temperature variations in the fluids along the pipe. The present work aims to validate a model along with a numerical technique for analyzing non-isothermal stratified-pattern two-phase flows that occur in typical gas-gathering offshore pipelines. The mathematical model is one-dimensional and based on a two-fluid model that comprises two mass and two momentum conservation equations, one for each phase, along with one energy conservation equation for the mixture. The system of equations is discretized in a conservative form within a finite-difference framework and is solved by the flux-corrected transport (FCT) numerical method. Because an ill-posed mathematical problem is obtained if the system of equations is not hyperbolic, a hyperbolicity analysis is performed for all cases simulated in this work, which also indicates how to impose the boundary conditions adequately and avoids the production of non-physical output. The results obtained for the distribution of pressure, fluid velocities, holdup and temperature along the pipeline demonstrated that even relatively small temperature differences between the fluids and the external environment at the pipe inlet cause significant thermal effects on the entire flow. The simulations also predicted results in good agreement with those of a commercial software used for comparison, for steady-state regime, and significantly different results from those produced by an isothermal-flow model, which emphasizes the importance of considering the heat transfer in the problem. In summary, the results showed that the mathematical model and the numerical method form together a reliable tool of second-order accuracy in space that perform accurate numerical simulations of two-phase flows in long pipelines that are subject to non-isothermal conditions.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Xin Zhao, Zhengsong Qiu, Baojiang Sun, Shujie Liu, Xijin Xing, Mingliang Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6–19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000–45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Hongwen Luo, Haitao Li, Xiaojing Zhou, Ying Li, Yahui Li, Xiaoping Zhu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This study aims to study the temperature behaviors and quantitatively diagnose water exits for multi-fractured horizontal wells (MFHWs) in low-permeability gas reservoirs (LPGRs) with two-phase flow. Firstly, a transient temperature prediction model is developed on the basis of mass, momentum and energy conservation with consideration of a variety of subtle heat effects (e.g. Joule–Thomson effect, thermal expansion etc.). Subsequently, synthetic cases are simulated to illustrate the temperature behaviors of a two-phase MFHW with identical/non-identical fractures. The sensitivity analysis indicates that the existing of Non-Darcy flow and gas-phase slippage effect reduces the wellbore temperature. The wellbore temperature shows significant sensitivity to reservoir permeability and fracture half-length. Then, by simulating the temperature profile of MFHWs with different water/gas ratio (WGR) of each fracture, the unique characteristics of wellbore temperature variation under each WGR situation are observed. That provides the potential to diagnose the water exits of MFHWs from temperature measurement. Finally, we apply the model to a field case and the results validated the feasibility of the developed model to simulate the temperature behavior of MFHWs in LPGRs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: March 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 174〈/p〉 〈p〉Author(s): Pouria Behnoudfar, Mohammad Bagher Asadi, Alireza Gholilou, Sohrab Zendehboudi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Coalbed reservoirs are considered as suitable media for injection operations, especially for geological sequestration of carbon dioxide (CO〈sub〉2〈/sub〉). This type of reservoirs might be stimulated to enhance the efficiency of injection as the permeability of these formations is usually low (0.1–10 mD). The hydraulic fracturing technology is one of the effective methods to attain a greater injectivity. To design an efficient hydraulic fracture, it is vital to systematically investigate important changes (e.g., pressure and stresses) occurring over the injection process on the fracturing performance. An increase in the reservoir pressure is an inevitable occuerrence during the fracturing operation. In situ stresses will also vary due to the fluid injection. As a consequence, the permeability of coalbed will be altered during the reservoir life. In this research study, a novel model for the hydraulic fracture design is introduced to consider the changes in the reservoir permeability during the injection process. A Direct Boundary Element Method (DBEM), which is a fundamental concept in the Unified Fracture Design (UFD), is employed to determine the fracture injectivity. In this study, the pressure change is estimated based on the injectivity. The variations of in situ stresses are determined using a model, which uses the Boundary Element Method (BEM) and theory of inclusions. Permeability is then updated based on the new values of stresses and the design dimensions of the fracture for the new time steps. Therefore, the model presents a suitable design of hydraulic fracture by considering the reservoir pressure changes during the injection. The proposed method is implemented on Latrobe Valley brown coal. The results suggest that the reservoir life is an important parameter to optimize the hydraulic fracturing design. Fractures with the same width and different penetrations yield very different efficiencies during the injection. The highest amount of cumulative injection can be achieved after 10 years using a fracture, which seems to be not optimum at the initiation stage of the injection process. This study proposes that it is necessary to take into account the stress changes in the design of a hydraulic fracture system in a coalbed to attain the effective injection operation regardless of high penetrations.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Hamed Jafarpour, Jamshid Moghadasi, Azizollah Khormali, D.G. Petrakov, Rahman Ashena〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Matrix acidizing is a common practice in the oilfield for minimizing formation damage through dissolution of the reservoir rocks and making appropriate wormholes. For obtaining the highest performance in the acidizing and stimulation treatments, the injecting fluid should be placed in the damaged zones of the reservoir layers, after which the easy flowback could fully improve the formation damage. In multi-layered oil reservoirs the fluid diversion becomes of paramount importance where preferential flow paths are adopted in most of the stimulation fluid and the zones, which have the lower values of the rock permeability, remain untreated.〈/p〉 〈p〉We develop an optimal multi-bached acid system in two steps by determining the diverter formulation and investigating the diverting characteristics of the acid system through core flood tests. The interfacial tension tests were conducted to determine the diverter (fluid packer) formulation. The effects of different concentrations and mixtures of organic acids, HCL and surfactant were investigated to find the most effective main batch (active batch) of the stimulation fluids. In the second experimental phase, the ability of the selected emulsified acid system as a fluid packer and diverter was investigated using the multi-bached acid system in a parallel core flood test. The results showed the efficiency of the emulsified acid system in diverting the second batch (active batch) of the stimulation fluid from the core with the higher permeability to the lower permeability one.〈/p〉 〈p〉We find that the developed multi-batch acid stimulation system is an advantageous technique to use for stimulating the multilayered wells where there is a big difference between the permeabilities of the producing formations. The permeablity improvement in a more uniform manner in both the layers proves the efficiency of the developed stimulation system and emulsion which used as a diverter. In addition, we detect that the mixture of 15%HCL and surfactant (GF – 15 MPS) with 0.5% concentration has provides the optimal reaction rate and dissolution rate in comparison with other mixtures studied by increasing the neutralization time.〈/p〉 〈p〉In short, firstly, in this work the acid distribution rate mechanism (pathway) between the reservoir layers was investigated by simulating the executed actual matrix acidizing operation in the considered well. Then, The self-diverting emulsified acid SDEA (which can be used as a diverter) was developed. Moreover, the main batch of stimulation fluid was developed by analyzing different acid mixtures with various concentrations. Lastly, the efficiency of the developed multi-bached acid system was evaluated by conducting the core-flood experiment. The results show that the developed multi-batch acid stimulation system is significantly efficient for stimulation of the heterogeneous carbonate reservoirs where there is a big difference between the permeabilities of the producing formations so that the stimulation of both layers (with different permeability values) can be accomplished in a more uniform manner.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Haitang Yu, Qi Li, Fengrui Sun〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Abandoned oil and gas wells are proved to be effective in geothermal energy extraction, especially when the wellbore is located at a perfect geothermal reservoir. In this paper, CO〈sub〉2〈/sub〉 is selected as the working fluid and a model is proposed to simulate the CO〈sub〉2〈/sub〉 flow in the retrofitted wellbores. The CO〈sub〉2〈/sub〉 is injected into the inner tube (injector) and then flows out through the annuli (producer) to surface. The proper length of the insulation layer installed outside the casing is predicted. Results show that: (a) when the CO〈sub〉2〈/sub〉 flows from well-bottom to well-head in the producer, its temperature has an increase at first and then turns to decrease. An insulation layer outside the casing is an efficiency way to prevent CO〈sub〉2〈/sub〉 from transferring heat to the stratum. (b) From the temperature point of view, a smaller mass flow rate is recommended to obtain a higher CO〈sub〉2〈/sub〉 temperature at outlet of the producer. (c) A higher mass flow rate leads to a higher geothermal energy extraction rate but a lower temperature. (d) A small increase in temperature or the geothermal energy extraction rate need a large pressure increase, which can be high-cost for field practice.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Lei Gong, Bo Liu, Xiaofei Fu, Hadi Jabbari, Shuai Gao, Wenting Yue, Hongqi Yuan, Rongzhi Fu, Zijie Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Sub-seismic faults are the key factors that control the reservoir quality, hydrocarbon accumulation, and water injection development. In this paper, we developed a method to predict the number, size, orientation and location of sub-seismic faults based on the analysis of fault fractal growth patterns and three-dimensional (3-D) geo-mechanical simulation. This work also discussed the influence of sub-seismic faults on water injection development and remaining oil distribution from analyzing the dynamic oilfield development data. In the methodology developed in this study, the geometrical features of large-scale seismic faults were thoroughly explained based on 3-D seismic data. Based on fractal geometry theory, the number, length and throw of the sub-seismic faults were predicted by extrapolating the power law distribution of seismic fault parameters. According to the distribution of seismic faults, we established the 3-D geo-mechanical model and simulated the disturbed stress field near the seismic fault zone during faulting. By combining the simulation results with the failure criterion, the preferred failure orientation grids and maximum Coulomb shear stress grids were then established. Using these two grids and the parameters of sub-seismic faults constrained by the power-law distribution, we determined the stochastic model to predict the distribution of sub-seismic faults. This work shows that the distribution of sub-seismic faults can be effectively predicted by the combination of fractal theory and 3-D geo-mechanical simulation. Both key parameters in a typical waterflood process, namely the residual oil saturation and the performance of water injection, can be impacted by the size (throw) and the orientation of sub-seismic faults.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Changwei Liu, Kewen Li, Xiaoming Tian, Guoxiang Zhao, Youguang Chen, B.M. Mahlalela〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Water coning is a major problem in oil reservoirs with bottom water. It reduces the oil production and overall oil recovery. Excessive water production causes corrosion problems in production facilities and increases the cost of water disposal. This may cause the early shutdown of oil wells. In this study, an experimental apparatus has been designed and developed to physically model an oil reservoir with bottom water. The reservoir model was transparent and the change in water coning could be visualized. Many water-flooding tests were conducted at different pressures and oil viscosities ranging from 22 to 260 mPa s. The effects of production pressures and oil viscosity on oil production were investigated. The results indicated that for a medium oil viscosity of 74 mPa s, the optimal production pressure was about 0.054 bar. For minimum and maximum oil viscosity (22 mPa s and 260 mPa s), the smaller the production pressure, the larger the water breakthrough time and oil recovery. Five types of flooding characteristic curves were used to characterize the water-cut variation, and their applicability were compared and analyzed. The water drive curves were fitted using the water-cut models and the oil “reserves” (originally placed in the reservoir model) were predicted using the mathematical models with the experimental data. The results indicated that the Maksimov model of water-drive characteristic curve is more suitable to match the water production performance. Most interestingly, when applying the most suitable model Maksimov water-drive characteristic curve to predict oil reserves, the cases with optimal production pressures have a greater accuracy.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Yuming Liu, Bo Zhang, Yue Dong, Zhipeng Qu, Jiagen Hou〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Building a reliable numerical geological model is critical in reservoir development and management. Inferring a stable 3D variogram is one of the most important processes in the building of numerical geological model. We usually can obtain a well-defined vertical variogram from wells in most cases due to the regular sampling in the vertical direction. The quality of horizontal variogram highly depends on the number of wells, geometric of the well locations, and the trajectory of wells. Horizontal wells usually have preferred trajectory directions due to the geological and geomechanical consideration. As a result, it is very difficult to obtain a reliable horizontal variogram by using the data of horizontal wells. We proposed a three-step procedure to infer the horizontal variogram by integrating geological, seismic, and horizontal well data. We first use the geological information and P-impedance to infer the approximate major azimuth of horizontal variogram. We then obtain the range of the variogram for each horizontal well using the data of horizontal section. We finally determine the major, minor direction and corresponding ranges by least-square fitting the ranges computed using each horizontal well. We illustrate our workflow by applying it to a conglomeratic reservoir modeling, East China. The modeled reservoir properties have a very good correlation with the production data.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Mohammad Heidary, Ezatallah Kazemzadeh, Ali Moradzadeh, Ali Mohammad Bagheri〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Identification of pay zones is as a challenging topic in the reservoir characterization. Various methods have been employed to tackle this prominent task. Well logs are one of the most useful means for identifying pay zones, chiefly resistivity logs. However, resistivity measurements in some complex environments such as mixed lithology reservoirs, low resistivity and low contrast pay zones may fail to unveil productive zones. As an essentially lithology-independent tool, nuclear magnetic resonance (NMR) log may be the only approach to deal with detecting such subtleties. Using wavelet analysis technique and the NMR log data, this paper was aimed at identifying hydrocarbon bearing zones in two carbonate reservoirs. Discrete wavelet transform (DWT) was applied to the spin echo train at each depth to extract transverse relaxation time (〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉). By comparing the generated 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log and resistivity log, a striking similarity was found between them. The 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log manifested strong correlation with porosity log. Therefore, the DWT was repeatedly applied to the 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log so as to remove the correlation. Various wavelets were adopted to remove the effect of porosity from the 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log, leading to achieve pore fluid transverse relaxation time, referred to as 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈mi〉f〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉. Scrutinizing the 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈mi〉f〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log demonstrated that this log is not only highly functional in detecting productive zones but also highly capable of highlighting the subtle changes of pay zones. Consequently, the 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si2.gif" overflow="scroll"〉〈mrow〉〈msub〉〈mrow〉〈mi〉T〈/mi〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈mi〉f〈/mi〉〈/mrow〉〈/msub〉〈/mrow〉〈/math〉 log revealed the latent pay zones unseen by resistivity log.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): ZhaoLiang Zhu, Zheng Liang, Yang Hu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This paper describes a new analytical model for predicting the buckling behavior of coiled tubing (CT) with initial curvature in an inclined well. In addition, the contact force and the axial force transfer are solved using the new model. The new model is built based on the beam-column method and is solved using the method of weighted residuals. Using the proposed model, the CT's mechanical behaviors are found to be strongly affected by its initial curvature. The critical sinusoidal buckling and critical helical buckling load are both increasing with increasing 〈em〉A〈/em〉〈sub〉〈em〉0〈/em〉〈/sub〉. When CT is undergoing sinusoidal buckling, the contact forces are affected by both axial force and it's initial configuration whereas when CT is in helical buckling, the contact force is primarily affected by the axial force. In general, under the same axial force, the contact force of CT is larger than that of a straight pipe. Compared with 〈em〉A〈/em〉〈sub〉〈em〉0〈/em〉〈/sub〉, 〈em〉OD〈/em〉 and 〈em〉u〈/em〉 are the primary parameters to affect the axial force transmission. The CT's residual bent appears to have a stronger effect on its buckling load and to be less effective on its axial force transfer based on the new model presented in this paper.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Hao Yu, Arash Dahi Taleghani, Zhanghua Lian〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In the dogleg section of directional wells, casing strings bend to fit the borehole trajectory, which may lead to complicated contact areas with the borehole. The severity of dogleg in combination with casing properties may make the formed annulus space so complex that cement may not displace mud remnants very well. While current simulation methods only consider constant eccentricity, we propose a model for a more general geometry defined by the well trajectory and casing properties. We have developed a three-dimensional finite element model (FEM) to simulate large-deformations of the casing while running into the dogleg. The casing deformation determines the annulus geometry that is supposed to be filled with cements. We utilized a computational fluid dynamics (CFD) model to simulate cement-mud displacement in the resultant annulus space. The effects of density ratio and rheology on the displacement efficiency are analyzed here. The obtained numerical results show the complicated contact geometry of the casing and borehole at the dogleg, which may worsen in casing strings with small thickness and large curvature doglegs. Results show that the magnitude of the stress developed along the casing can considerably increase due to friction. Complicated geometry of the annulus induced by casing deformation makes mud displacement by cement in the dogleg difficult. Continuous drilling mud pockets are formed due to the cement reverse flow. However, increasing density difference helps development of a steady and shorter displacement interface. We also noticed the phenomenon of reverse flow occurred during the cementing, which prevents sweeping or perfect displacement of the cement in the annulus space. The outcome will help us to prevent any potential damage that might happen due to large pressure fluctuations during fracturing through casing by minimum costs and avoid such potential integrity problems by setting a packer and tubing or using more appropriate cement recipes.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Danial Abooali, Mohammad Amin Sobati, Shahrokh Shahhosseini, Mehdi Assareh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Detailed understanding of the behavior of crude oils and their interactions with reservoir formations and other in-situ fluids can help the engineers to make better decisions about the future of oil reservoirs. As an important property, interfacial tension (IFT) between crude oil and brine has great impacts on the oil production efficiency in different recovery stages due to its effects on the capillary number and residual oil saturation. In the present work, a new mathematical model has been developed to estimate IFT between crude oil and brine on the basis of a number of physical properties of crude oil (i.e., specific gravity, and total acid number) and the brine (i.e., pH, NaCl equivalent salinity), temperature, and pressure. Genetic programming (GP) methodology has been implemented on a data set including 560 experimental data to develop the IFT correlation. The correlation coefficient (R〈sup〉2〈/sup〉 = 0.9745), root mean square deviation (RMSD = 1.8606 mN/m), and average absolute relative deviation (AARD = 3.3932%) confirm the acceptable accuracy of the developed correlation for the prediction of IFT.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Saebom Ko, Chun Huh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉When synthesized in a specific size range and with a special surface coating tailored to achieve certain desired functionalities, nanoparticles exhibit unique properties with tremendous application potentials. Accordingly, explosive advances have been made in development of functional nanoparticles and their novel use in a wide variety of medical, biological, engineering and other applications. The upstream oil industry is now vigorously catching up to adapt those technologies to develop its own unique applications. The first unique application is that specially surface-coated nanoparticles used as stabilizers, CO〈sub〉2〈/sub〉 foams, and emulsions with cheap, low molecular weight hydrocarbons can be improved mobility under harsh reservoir conditions and formulated as an “intelligent” additives for drilling, cementing and other downhole applications. The second application can be as a detection instrument of fluid and rock properties of producing reservoir zone because nanoparticles can flow easily long-distance deep in the reservoir. Nanoparticles have extraordinary mechanical strength, electrical and thermal conductivity, which can be applied to enhance performance, reliability and durability of structural materials used by the upstream oil industry. In this comprehensive review on the use of nanoparticles for oil production applications, the current status of the nanoparticle applications development in the areas of (i) drilling and completions; (ii) production operation and flow assurance; (iii) reservoir sensing; (iv) enhanced oil recovery; and (v) heavy oil recovery is provided in details. The basics of nanoparticle physics and chemistry is also first introduced.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Serveh Naderi, Mohammad Simjoo〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The combination of low salinity water with gas in the form of water alternating CO〈sub〉2〈/sub〉 injection (CO2-LSWAG) is a promising EOR method that could simultaneously benefit from gas mobility control and also rock wettability alteration to more water-wet as consequence of geochemical interaction between rock and reservoir fluids. This paper aims to investigate the EOR potential of CO〈sub〉2〈/sub〉-LSWAG under miscible conditions in a sandstone oil reservoir by coupling fluid flow and geochemical modeling. The wettability alteration of the rock surface was described by a series of relevant geochemical reactions between rock and low salinity water in a compositional simulator. The concept of ion equivalent fraction was used as the wettability index during CO〈sub〉2〈/sub〉-LSWAG injection. It consists mainly of the effects of ion exchange and clay properties on oil-water relative permeability functions. Also, the effect of calcite mineral dissolution was studied as result of interaction with low salinity water and CO〈sub〉2〈/sub〉 gas using relevant geochemical reactions. Results showed that salinity difference between injected and formation water triggers ion exchange processes between water and rock. Also, the rate of calcite dissolution increased due to the CO〈sub〉2〈/sub〉 partitioning into the aqueous phase. The calcite dissolution caused the increase of calcium ions in the reservoir leading to more water-wet condition. However, results indicated that the rate of calcite dissolution decreased far from the injection well most likely due to reduced interaction time between low salinity water with dissolved CO〈sub〉2〈/sub〉 and the reservoir rock. The oil recovery results showed that CO〈sub〉2〈/sub〉-LSWAG is capable of producing incremental oil as much as 10% of the initial oil in place on top of high salinity CO〈sub〉2〈/sub〉-WAG. The results of this numerical study support the potential application of CO〈sub〉2〈/sub〉-LSWAG as an efficient EOR method in sandstone reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: February 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 173〈/p〉 〈p〉Author(s): Amina Islam, Titly Farhana Faisal, Sylvie Chevalier, Mohamed Soufiane Jouini, Mohamed Sassi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Digital Rock Physics (DRP) is a field that makes use of recent advances in imaging technology and computational methods to determine several rock properties by running numerical simulations on 3D rock images. In this work, DRP tools were used in a novel multi-scale approach that combined micro and macro computations to determine permeability for comparison with lab experiments of 2 different samples at 2 different sizes; 0.5 inch diameter and the standard 1.5 inch diameter. The Lattice Boltzmann Method (LBM) was used to perform micro-scale computations on subvolumes of images at high-resolution images. This was done to determine the permeability, and extract porosity-permeability trends. Then, a macro-scale computational grid was set to have porosity and permeability values from the micro-scale simulations in order to compute the upscaled effective permeability which could then be compared to experimental results. The workflow was first applied to a standard Silurian Dolomite to validate it and then applied to a carbonate sample from an Abu Dhabi reservoir that exhibited a higher level of heterogeneity.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: January 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 172〈/p〉 〈p〉Author(s): Debotyam Maity, Jordan Ciezobka〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earth's surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naïve-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410518308179-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉