ALBERT

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Shuai Zhao, Wanfen Pu, Mikhail A. Varfolomeev, Chengdong Yuan, Shan Qin, Liangliang Wang, Dmitrii A. Emelianov, Artashes A. Khachatrian〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Because the thermal release correlates directly with the success of in-situ combustion (ISC) technology, this research performs a series of investigations concerning thermal behavior and kinetics of heavy crude oil during combustion using high pressure differential scanning calorimetry (HP-DSC) and accelerating rate calorimetry (ARC). The results obtained from HP-DSC profiles indicated that for oil alone and its mixtures with quartz sand/crushed core, the peak temperature was lowered, and the heat flow increased with increasing oxygen partial pressure. The heat enthalpy of low temperature oxidation (LTO) was higher than that of high temperature oxidation (HTO) under oxygen partial pressures of 0.5, 1 and 1.5 MPa, and the increase in heat enthalpy of LTO with oxygen partial pressure was more pronounced than that of HTO. Unlike the crushed core, the addition of quartz sand delayed exothermic oxidation reactions. Compared with oil only and oil + quartz sand, the LTO and HTO peak temperatures of oil + crushed core were considerably lowered, and the effect of crushed core on increasing heat release for LTO at oxygen partial pressure of 1.5 MPa was more prominent. It was observed that the heat enthalpy of LTO and HTO increased quasi-linearly with the oxygen partial pressure in both the presence and absence of quartz sand/crushed core. ISC might be considered as an appropriate candidate for Jiqi block, based on exothermic continuity of the ARC curves, with the near-wellbore zone of target block heated to 180 °C where the exothermic oxidation activity is notably intensified. The kinetic results showed that the LTO and HTO intervals were divided into 6 and 2 subintervals, respectively, which facilitated more precise modelling of the ISC process.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Zan Chen, Menglu Lin, Shuhua Wang, Shengnan Chen, Linsong Cheng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Studies have shown that the gas huff and puff injection potentially perform better than the continuous gas flooding in enhancing the hydrocarbon recovery in the liquid rich tight reservoirs. During the fracturing stimulation, only part of the induced hydraulic fractures is propped because proppants cannot be carried to the fracture tips. Moreover, some secondary and tertiary fractures may be too narrow to accommodate any proppants. The conductivity of the unpropped fractures is highly dependent on the variation of the in-situ pressure and may be open and close periodically during the huff-n-puff cycles. In this study, the stress-dependent fracture conductivity and its impact on the produced gas huff-n-puff performance are investigated in a liquid rich tight reservoir, considering the existence of the large amount of the unpropped fractures. The experimental data of stress-dependent fracture conductivity is employed first to simulate the dynamic conductivity during the depletion and the gas huff and puff cycles. A reservoir model is then constructed and history-matched based on the reservoir fluid samples and the field production data collected from the Montney liquid rich tight reservoir in Western Canada. Performance of the produced gas huff-n-puff is examined in the targeted reservoir and results show that contributions of the unpropped fractures cannot be ignored, which leads to 7.8% more condensate (i.e., oil) production and 2.8% higher in barrel of oil equivalent (BOE), compared to the case with propped fractures only. The effects of complex fracture geometry and the cluster completion are also investigated and results show that the unpropped fracture contributions towards the condensate production and BOE are even more pronounced in the complicated scenarios. The condensate oil and BOE are 42.0% and 22.9% higher in complex fracture geometry case and 12.4% and 5.6% higher in the fractures with multiple clusters than those scenarios with propped fractures only. This paper provides a better understanding on the potential performance of enhanced hydrocarbons recovery in liquid rich tight gas reservoirs via gas huff-n-puff operations.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Abdelrahman Elkhateeb, Reza Rezaee, Ali Kadkhodaie〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Traditionally, prediction of facies and permeability for a reservoir rock was one of many challenges in the industry that necessitates advanced and sophisticated evaluation for effective reservoir description. Three wells have been studied in the Perth Basin in Western Australia across the shaly sand of the Irwin River Coal Measures Formation, which contain a comprehensive suite of advanced and conventional logs. Due to the reservoir heterogeneity and the clay distribution, it is very challenging to resolve the effective pore volume, the reservoir facies and how the high permeability zones are distributed within the formation.〈/p〉 〈p〉In this paper, a new technique has been successfully tested on the Shaly Sand by integrating the nuclear magnetic resonance (NMR) and the conventional density log. The method allows the establishment of high-resolution facies classification for the reservoir using an Equivalent Flow Zone Indicator Index (EFZI). The studied core facies have been integrated with the EFZI into a new workflow to distribute facies on a larger scale in the uncored wells.〈/p〉 〈p〉Four hydraulic flow units (HFU) have been defined from one cored well using Flow Zone Indicator approach, with each has a unique FZI value and different permeability model based on core measurements. The EFZI-based high-resolution facies have been validated at several formation depths using the core thin sections to ensure the best calibration will be obtained for facies log, hence the permeability log-to-core match.〈/p〉 〈p〉The methodology will help running an advanced petrophysical analysis for the zone of interest and will reduce the parameters uncertainty. Application of this methodology in the uncored wells has shown very encouraging results, which is believed it can be used in the absence of any core data to resolve the rock typing from the well logs.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Atousa Heydari, Kiana Peyvandi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this work, the stainless steel mesh was used to study the effect of metallic porous media on the formation of methane hydrate and some parameters such as induction time, the kinetics growth and the mole of gas consumed have been investigated at a temperature of 3 °C (276.15 K) and a pressure of 760 psi (5.24Mpa). The metallic porous media was able to show better results on the methane hydrate formation relative to the silica gel. Hence the induction time and, eventually, the total time of the hydrate formation process decreased by about 60%. The kinetics growth and the amount of gas consumed increased significantly. Also, the effect of two types of anionic and nonionic surfactants as kinetics promoters studied in this porous media. The result of adding SDS and SDBS at a concentration near the CMC designated that the induction time lasted nearly zero and the total time of the process by SDBS was minimal. It should be noted that the non-ionic surfactant SPAN 80 could not have a positive effect on this porous media. In general, therefore, the results of this research attempts to show that the stainless steel mesh with SDBS possessed high potential in obtaining the industrial purpose of gas hydrate growth and also was significant in the field of energy storage and transport.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519306473-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Shuaishuai Jiang, Xuehua Chen, Yingkai Qi, Wei Jiang, Jie Zhang, Zhenhua He〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The frequency-dependent attenuation and velocity dispersion of seismic responses are closely related to hydrocarbon reservoirs. To further investigate the characteristics of seismic responses caused by pore fluid-bearing reservoirs, the role of gas saturation is analyzed in seismic responses of sand reservoirs characterized by the patchy saturation model. To this end, a novel wave extrapolation method is developed based on the diffusive-viscous wave equation (DVWE) as well as a scheme for an extended local Rytov Fourier (ELRF) approximation within the extrapolation depth interval. Our proposed method considers the presence of fluid mixtures in the porous media, resulting in seismic attenuation and dispersion by the mechanism generally known as wave-induced fluid flow (WIFF). This method enables an accommodation for the lateral variations in slowness, diffusion coefficient and viscosity. Subsequently, the extrapolation is adopted to model the synthetic seismic data of a distributary channel model. During this modeling, a gas-water saturated sand reservoir embedded into one of the channels was used to comparatively analyze the distinct features on its seismic synthetic data. We exhibited the numerical simulation results using the proposed wave extrapolation method here and the traditional acoustic wave equation (AWE) method. A comparison of the simulation results, demonstrates that our proposed numerical method can depict the seismic dispersion and frequency-dependent attenuation as well as the phase delay effects associated with gas-water-saturated sand reservoirs. Furthermore, we compare the seismic responses by changing the gas saturations of the sand reservoir. The gas saturation of the reservoir has significant effects on the seismic characteristics of the numerical modeling data. The numerical modeling method improves our understanding of the mechanisms of seismic frequency-dependent characteristics associated with gas saturations and potentially contributes to better insights into gas reservoir indicators derived from seismic field data.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Jingyi Zhu, Zhaozhong Yang, Xiaogang Li, Zhichao Song, Ziwei Liu, Shiyi Xie〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Liquid foam is an alternative to water-based fracturing fluid due to its great proppant suspension ability. In this work, theoretical and experimental investigations on the settling behavior of the proppants in viscoelastic foams were analyzed on bubble scale. Settling trajectory was captured over time by optical microscope to calculate proppant settling velocity. At room temperature, proppants kept suspended well, but noticeable changes in proppant position could be observed at 70 °C. We concluded that the sedimentation of the proppants at high temperature was divided into three stages, that were drainage-dominated, structure-dominated and fluid-dominated regimes. For the large proppants, quick settling velocity was seen at first due to fast drainage rate. Then bubble pressure force and network force served as drag force exerting on the proppants when the proppants stretched or squeezed the liquid films. During this regime, bubble distribution, the existence of nodes, the length and the orientation of Plateau border leaded to the fluctuation in settling velocity. Lastly, the proppants would also flow freely along Plateau border over time, and the properties of the foam fluid such as viscosity and elasticity provided the drag force to prevent the proppants from settling. It's more likely for small proppants to change to this stage called fluid-dominated regime, but elasticity also guaranteed their low settling velocity. Moreover, in the existence of proppants, the analysis into drainage rate and bubble structure demonstrated the high stability of viscoelastic foams. These results helped understand the sedimentation of proppants in wet foams and broadened the application of viscoelastic foams in hydraulic fracturing.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Zhong-Zhen Chen, Hong-Ze Gang, Jin-Feng Liu, Bo-Zhong Mu, Shi-Zhong Yang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A thermal-stable and salt-tolerant biobased zwitterionic surfactant 〈em〉N, N〈/em〉-Dimethyl-〈em〉N〈/em〉-[2-hydroxy-3-sulfo-propyl]-〈em〉N〈/em〉′-phenyloctadecanoyl-1, 3-diaminopropane (SPODP) was successfully obtained from modification of oleic acids which can be regenerated from waste cooking oils, and its structure was characterized using GC-MS, ESI-MS and 〈sup〉1〈/sup〉H NMR approaches. The biobased zwitterionic surfactant demonstrated a strong interfacial activity at high salinity and high temperature conditions at a very low surfactant dosage in formation brine. The ultralow interfacial tension (≤10〈sup〉−3〈/sup〉 mN/m) between crude oil and brine was reached at 0.5 g/L in brine with a wide range compatibility of NaCl up to saturation, Ca〈sup〉2+〈/sup〉 up to 500 mg/L, and temperature up to 95 °C. Meanwhile, it also exhibited strong wetting ability and resistance against adsorption on sands. All the results from this study suggest that the biobased zwitterionic surfactant is promising over varieties of traditional surfactants in applications in alkali free systems in enhanced oil recovery (EOR).〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Zhihua Wang, Ye Bai, Hongqi Zhang, Yang Liu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Waxy crude oil emulsions exhibit gelation behavior, with nucleation observed within a certain temperature range. A kinetic model was developed and validated based on the thermal parameters obtained from differential scanning calorimetry cooling thermograms, and the nucleation rates of various water-in-waxy crude oil emulsions were determined in the temperature range in which gelation occurs. Although temperature had a dominant effect on the gelation and nucleation behavior of waxy crude oil emulsions, the nucleation rate also increased as the water volume fraction in the emulsion increased. Emulsified water droplets with smaller radii can be completely covered by wax particles, inducing a greater nucleation rate. Subjecting the emulsions to a greater shearing strength also increased the nucleation rate. This study provided new insights into the nucleation processes that occur during the formation of waxy crude oil emulsion gels and, in particular, the role of the emulsification properties.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519306424-fx1.jpg" width="496" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Ulf Jakob F. Aarsnes, Nathan van de Wouw〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The present paper studies the effect of an axial elastic tool (known as a shock sub), mounted downhole in the drill-string, on the occurrence of axial and torsional self-excited vibrations. In particular, we evaluate the feasibility of stabilizing the axial dynamics, dominated by a bilateral (feedback) coupling between the bit-rock interaction and the drill-string wave-equations, through the insertion of a passive down-hole tool. We consider the problem of unwanted drill-string vibrations and explain how these vibrations relate to the so-called axial instability using a distributed parameter (infinite dimensional) model. The equations describing the feedback system causing this instability are derived and then extended to accommodate for the inclusion of the effect of the shock sub. Conditions for the design parameters of the shock sub needed to avoid axial instability are then derived and their practical feasibility are considered.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): S. Mohammadi, M. Papa, E. Pereyra, C. Sarica〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Mechanistic modeling is one of the most popular approaches for the prediction of flow pattern, pressure gradient and liquid holdup in multiphase flow problems. Mechanistic models utilize the mass and momentum conservative equations in combination with a set of closure relationships. These closures, which are developed based on specific experimental setups, considerably affect the performance of the mechanistic models. Moreover, new closure relationships continue to be developed to improve the current mechanistic models. Thus, there is a need for a tool that allows the selection of a set of closure relationships for a given set of conditions. In this direction, this paper presents a methodology that relies on a genetic algorithm to search and select a set of closure relationships for a given experimental (field data) that minimize the error between measured and predicted pressure gradient. The results show the applying the genetic algorithm can improve the performance of the mechanistic model by about 277% when compared to selections of closure relationships made by a subject matter expert for the given data set.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Chinedu I. Ossai〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉To advance the prognosis of progressing cavity Pumps (PCPs) used for artificial lifting, the pump-off need to be identified to forestall failure. This study developed a new technique for determining the Pump-off events Activation Times (PATs) of the PCPs using the transient Water Discharge Rates (WDRs) from coal seam gas producing wells. The Gaussian distribution function parameters of the rolling standard deviations of the water discharge rate (RSWR) and the transition probability of the rolling standard deviations of the water discharge rate (TP_RSWR) were used to build the model. By determining the anomalies in the RSWR signals with the bottom-up segmentation technique and computing the statistical characteristics at the changepoint locations, the steady-state of the WDR signals was established. This steady-state signal, which represents the Operation Transition Level (OTL) between the Normal Operation (NOP) and the Pump-off Event (POE) was used for monitoring the transition of the PCPs' operating status. An algorithm was developed in Python and tested it on field data from 36 coal seam gas wells. The performance of my technique was determined with precision, recall and F1 score, which gave an average value of 94.94%, 92.63%, and 93.56% respectively. It is expected that the implementation of this technique in the real-time estimation of PATs will be vital for reducing PCPs faults seeing that poor PATs detection results in PCPs running dry and consequently failures due to the extreme temperatures and abrasions.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Fuwei Yu, Hanqiao Jiang, Fei Xu, Zhen Fan, Hang Su, Junjian Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this paper, a new fabrication method was reported for establishment of a 2.5D reservoir micromodel, which incorporated 3D geometry of porous media and visualization of 2D microfluidic chips. Flow physics such as imbibition, rison and rheon were visualized in the new 2.5D reservoir micromodel through water flooding experiments in water-wet and oil-wet 2.5D reservoir micromodels. Corresponding results demonstrated the strong capacity of the presented 2.5D reservoir micromodel to mimic the real 3D porous media. Besides, four theoretical patterns concerning residual oil distributions were obtained based on water flooding, surfactant flooding and polymer flooding experiments. Furthermore, imbibition of a Winsor I type surfactant system was investigated, accompanied by explanation and visualization of two major enhanced oil recovery (EOR) mechanisms, namely microemulsion imbibition and residual oil solubilization, which confirmed the assumptions made based on core imbibition experiments.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Mohamed R. Shalaby, Liyana Nadiah Osli, Stavros Kalaitzidis, Md Aminul Islam〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Thermal maturity and palaeodepositional environment of the Taratu Formation has been studied by evaluating its geochemical properties and organic petrographical features. Geochemical properties of the Cretaceous-Palaeocene Taratu source rock that are identified through pyrolysis indicate that this formation has excellent organic matter quality, quantity and hydrocarbon generation potential. Only the Cretaceous-aged sequence from this formation is thermally mature, with Tmax values ranging from 429 °C to 459 °C, while Palaeocene samples are found to be thermally immature. Organic matter of the Taratu Formation comprises primarily of oil and gas prone kerogen type II-III and gas prone kerogen type III, which is reflected by high HI (165.0–327.5 mg HC/g TOC) and low OI (5.00–25.7 mg CO2/g TOC) values. Tissue Preservation Index (TPI) and Gelification Index (GI) indicates that the Taratu Formation was previously deposited in a limnic environment. Further assessment of the source rock's palaeodepositional environment through correlating cross-plots of various biomarker data and evaluation of organic petrography suggests that the formation was subjected to brackish water influx.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: September 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 180〈/p〉 〈p〉Author(s): Zulong Zhao, Yu Shi, Daoyong Yang, Na Jia〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A novel and pragmatic technique has been developed and validated to quantify gas exsolution of alkane solvent(s)–CO〈sub〉2〈/sub〉–heavy oil systems with consideration of interface mass transfer for each gas component under nonequilibrium conditions. Experimentally, constant composition expansion (CCE) tests of three alkane solvent(s)–CO〈sub〉2〈/sub〉–heavy oil systems are conducted with a visualized PVT cell under equilibrium and nonequilibrium conditions. The liquid height and pressure of the system are continuously monitored and recorded during experiments to measure, respectively, the bubblepoint pressure, pseudo-bubblepoint pressure, and the entrained gas volume. With the assumption of instantaneous nucleation, a mathematical model which integrates Peng-Robinson equation of state (PR EOS), Fick's second law, and nonequilibrium boundary condition has been developed to quantify not only the amount of the evolved gas and entrained gas, but also the dynamic composition of gas phase as a function of time. Once the deviations between the measured gas volumes and the calculated ones have been minimized, the mass transfer Biot number, individual diffusion coefficient, and interface mass transfer coefficient of each gas component as well as the gas bubble number are determined. Increases in experimental temperature and pressure are found to impose opposite effects on diffusion coefficient during gas exsolution processes. The diffusion of each gas component is found to be faster when the temperature becomes higher or the initial pressure becomes lower. Either CO〈sub〉2〈/sub〉 or C〈sub〉3〈/sub〉H〈sub〉8〈/sub〉 diffuses faster than CH〈sub〉4〈/sub〉 in the liquid phase under the same condition. In addition, the interface mass transfer coefficients, with an order of CO〈sub〉2〈/sub〉 〉 CH〈sub〉4〈/sub〉 〉 C〈sub〉3〈/sub〉H〈sub〉8〈/sub〉, obtained in this study are much higher than those collected in the literature since the nonequilibrium conditions greatly facilitate gas exsolution. The determined mass transfer Biot numbers in this study are large, indicating that the bulk resistance due to molecular diffusion inside the heavy oil dominates the gas exsolution process compared to the interfacial resistance.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Jingdong Liu, Tao Liu, Youlu Jiang, Tao Wan, Ruining Liu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The distribution, origin, and evolution of overpressure in the petroliferous basin are important problems that need to be addressed for oil and gas exploration. The distribution and origin of overpressure in the Shahejie Formation in the northern Dongpu Depression are analyzed based on geological studies, logs, and pressure data. The contribution ratios of different overpressure origins are quantified, and the evolutionary stages of overpressures of different origins are further divided. The results show that the formation pressure coefficients of Shahejie Formation in the Dongpu Depression are mainly within the range of 0.9–1.5. The overpressures are mainly distributed in the Sha-3 and Sha-4 Members of the Haitongji sag, the Central uplift belt and the Qianliyuan sag. From the sag to its surrounding area, the formation pressure coefficient gradually decreases. The high deposition rate and strong hydrocarbon generation are the main causes of overpressure formation in the Shahejie Formation in the Dongpu Depression. Based on the stress–strain characteristics of different origin overpressures and the log response parameters, two models, acoustic travel time-effective vertical stress and electrical resistivity-effective vertical stress, are established to identify and quantify the different origin overpressures. The calculation results for the area from the Haitongji sag and Qianliyuan sag to the Central uplift belt show that the main cause of overpressure gradually changes from both disequilibrium compaction and hydrocarbon generation to disequilibrium compaction as the main factor, with the contribution of disequilibrium compaction to overpressure in the Central uplift belt at about 87%. The Sha-3 Members of the Shahejie Formation in the Haitongji sag and the Qianliyuan sag are more strongly affected by hydrocarbon generation, which accounts for 42% and 47.5% of overpressure origin, respectively. There are five stages in the evolution of overpressure in the Shahejie Formation in the northern Dongpu Depression: normal compaction (before 35 Ma), mixed pressurization (35-27 Ma), uplift and pressure release (27-17 Ma), disequilibrium compaction (17-11 Ma), and secondary mixed pressurization (12 Ma-present).〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Zhiwei Zeng, Hongtao Zhu, Lianfu Mei, Jiayuan Du, Hongliu Zeng, Xinming Xu, Xiaoyun Dong〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Few studies have focused their attentions on the source-to-sink (S2S) system from a multiple-level perspective. We have proposed an effective multilevel S2S subdivision approach based on the integrated study of seismic geomorphology, well-based facies, seismic facies and multi-attribute. The inspiration of multilevel S2S subdivision method is drawn mainly from the modern Diancang Mountain- Lake Erhai S2S system with different-orders of drainage divides. The Paleogene Central Uplift system during the syn-rift stage in Xijiang Sag, Pearl River Mouth Basin, South China Sea, provides a suitable example to test the approach and analyze the multilevel S2S characteristics of an ancient uplift system. The result shows that the Central Uplift system can be divided into three second-level sub-S2S systems (R-A, R-B and R-C), and can be further sub-divided into twelve third-level sub-S2S systems (A1∼A5, B1∼B5 and C1∼C2). Generally, the A1∼A5 and B1∼B4 systems are developed at the gentle slopes and deposited a series of narrow-shaped braided deltas with higher exploration potential, whereas the B5 and C1∼C2 systems are developed at the relatively steep slopes and deposited a series of lobate shaped turbidite and fan deltas with lower reservoir quality. Based on the multilevel S2S analysis, the ancient uplift can be scientifically sub-divided and compared with each sub-S2S system, including the sediment-transport type and distance, sedimentary facies characteristics and stacking relationship with the hydrocarbon source rocks. These in-depth and detailed studies have practical significance for the exploration of favorable reservoir sandbodies and stratigraphic-lithologic traps.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Nabil M. Al-Areeq, Abubakr F. Maky, Ahmed S. Abu-Elata, Mahmud A. Essa, Salem S. Bamumen, Gamal A. Al-Ramisy〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The Masilah oilfields are rich-oil provinces in the Sayun-Masilah Basin. The petroleum system including essential elements and processes is a very important for understanding and development of oilfield to further explore hydrocarbons in the whole basin. Integrated geochemical, geological, petrological and petrophysical analyses were performed on the source and reservoir rocks in the Masilah oilfields to gives information about the complete petroleum system. The Masilah oilfields filled with syn- and post-rift sediments, including a self-contained source-reservoir system. The geochemical results indicate that the organic-rich shales of the Madbi Formation are considered as oil-source rocks, with high total organic carbon content of more than 5.0 wt% TOC and oil-prone kerogen Types II and I. The Madbi shales are currently characterized by thermally mature level, within the oil generation window. Geochemical biomarker correlations of oil-source rock indicate that there is a genetic link between the oils and the Late Jurassic Madbi shale source rock in the Masilah oilfields. Therefore, the geochemical characteristics of the Madbi source rock have been collaborated into basin models and illustrate that the Madbi source rock had passed the peak-oil generation window during the Late Cretaceous to present-day and that large amounts of oil were generated. The generated oil was expelled and migrated to the overlain Early Cretaceous Qishn clastic reservoir rocks through faults during the Oligocene-Middle Miocene. The oil was then accumulated and trapped into horst and tilted fault blocks that initial formed during the Late Jurassic-Early Cretaceous rifting.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Jeffrey O. Oseh, M.N.A. Mohd Norddin, Issham Ismail, Abdul R. Ismail, Afeez O. Gbadamosi, Augustine Agi, Shadrach O. Ogiriki〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉With increasing strict environmental laws, there is a need for operators to design a benign oil-based muds (OBMs). In this study, oil extracted from non-edible sweet almond seed (SASO) was used as the continuous phase to formulate biodiesel-based drilling mud (BBDM). Different properties of the BBDM including the economic viability were evaluated and compared with those of the diesel OBM to determine the applicability of these properties for drilling fluids and their level of toxicity to the environment. The results indicate that the rheology, filtration properties, electrical stability, thermal stability and shale swelling inhibition performance of the BBDM are comparable with those of the diesel OBM. The biodiesel has a significantly higher flash point of 169 °C than the diesel with 78 °C; demonstrating that it can supply better fire safety than the diesel. The data of the toxicity test indicate SASO to be safer and less harmful compared to diesel #2 type used. After the 28-day period of biodegradation tests, the BBDM and the diesel OBM showed 83% and 25.2% aerobic biodegradation with 〈em〉Penicillium〈/em〉 sp., respectively. The low branching degree and absence of aromatic compounds in the BBDM contributes for its higher biodegradation. The economic evaluation of the BBDM indicates low cost of formulation and waste management. The general outcome of the tests illustrates that SASO has the potentials of being one of the technically and environmentally feasible substitutes for the diesel OBM.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Bao Jia, Jyun-Syung Tsau, Reza Barati〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Molecular diffusion is an important EOR mechanism in naturally fractured reservoirs. However, the laboratory-measured diffusion coefficient in the fractured porous media is still limited; and grid sensitivity analysis is missing in the literature when the single-porosity system is applied to history match the pressure decline curve. We aimed to fill the gaps using Radial Constant Volume Diffusion (RCVD) method experimentally to investigate diffusion coefficients at different pressures in hydrocarbon saturated porous media. A special in-house cell is designed to hold the core sample in the center with the annulus around simulating the fracture. The core is initially saturated with oil while the annulus is filled with CO〈sub〉2〈/sub〉 at the same pressure. During the measurements, the system pressure declines as gas diffuses into the oil phase until it reaches chemical equilibrium. The pressure decline curve is history matched to determine the diffusion coefficient. The initial pressure is 597 psi, and the diffusion coefficient is determined in numerical models accordingly. Molecular diffusion coefficients are estimated at different experiment periods to reveal the pressure-dependency. A workflow is proposed to obtain effective diffusion coefficients in dual-porosity models that could be extended to multi-component systems. Besides, flow characteristics in the RCVD system are characterized and capillary pressure effect is investigated in this study.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): R. Farajzadeh〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉To mitigate the negative impacts of hydrocarbon fuels on climate change complementary decision tools should be considered when selecting or evaluating the performance of a certain production scheme. The exergy analysis can give valuable information on the management of the oil and gas reservoirs. It can also be used to calculate the CO〈sub〉2〈/sub〉 footprint of the different oil recovery mechanisms. We contend that the concept of exergy recovery factor can be used as a powerful sustainability indicator in the production of the hydrocarbon fields. The exergy-zero recovery factor is determined by considering exergy balance of full cycle of hydrocarbon-production systems and defines boundaries beyond which production of hydrocarbons is no longer sustainable. An example of the exergy analysis is presented in the paper.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Ahmad Ghasemi, Hossein Jalalifar, Saeid Norouzi Apourvari, Mohammad Reza Sakebi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Wellbore instability is a big challenge in shale formations. The objective of this study is to investigate the effectiveness of a natural additive as a shale inhibitor. The capability of this additive for reducing ion movement into shale and plugging its pore throats has been tested and compared with salts and nano particles. The ions and water movement into shale and resultant swelling was measured by modified gravimetric, swelling and modified immersion tests. The results showed that using Henna extract could reduce the ion and water movement into shale. In addition, the results of pore pressure tests showed that 3 wt % of Henna extract are more effective than nano particles and could completely plug the pore throats of shale while the mud rheological properties are still maintained. The findings of this study show that the Henna extract could be considered as a cost-effective and an environmentally-friendly shale inhibitor.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519306345-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Yongqiang Li, Jianfang Sun, Hehua Wei, Suihong Song〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Based on the analysis of the characteristics of modern karst and paleokarst outcrops, this study summarizes the features of subsurface reservoirs by using core, logging, seismic and production data, establishes the structural model of fault-controlled karst reservoirs, and points out the guiding significance of this structural model for development and production in the Tahe oilfield. Modern karst in southern China shows the three-component structural characteristics of fault-controlled karst which are fault core, damage zone, and host rock. The cavern is developed in the fault core and the fracture-vugs are fully developed. Paleokarst outcrops reveal the evolutionary process of fault-controlled karst reservoirs, the characteristics of caverns along the fault and the surrounding fracture-vuggy features. Seismic structure tensor attributes, ant-track attributes and amplitude spectrum gradient attributes are used to describe the external geometry, caverns, and large-scale fractures of fault-controlled karst reservoirs, and the small fractures and vugs can be described by using cores. According to the characteristics of modern karst, paleokarst and subsurface reservoirs, three architectural patterns of fault-controlled cavern complexes, fault-controlled caverns and fault-controlled vugs are summarized. Different architectural patterns of karst reservoirs lead to different production capacities. The architectural patterns have important guiding significance for new drilling and water or gas injection to improve oil recovery.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): M.E. Emetere〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Recently, significant reserves of oil were discovered off the coast of Lagos State, southwest Nigeria. The lateral situation or compositions of the oil-bearing deposits is not clear because these findings are based on a particular position of a single well. The conventional methods of oil exploration have shown a fundamental theoretical shortcoming that may not be resolved, hence scientists or professionals may have to keep modifying the theories to explore different geological terrain. In this study, the remote sensing technique was adopted. The dataset were adopted from MERRA, Landsat 8 OLI and ETM imagery. The temperature distributions (soil and geothermal temperature) over the research area were calculated using existing algorithms to compliment the satellite remote sensing results. A prospective hydrocarbon deposits was suggested for further research work.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): T.N. Phan, Y.M. Zapata, C.S. Kabir, J.D. Pigott, M.J. Pranter, Z.A. Reza〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO〈sub〉2〈/sub〉 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework.〈/p〉 〈p〉Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO〈sub〉2〈/sub〉 injections in hydraulically-fractured well.〈/p〉 〈p〉The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO〈sub〉2〈/sub〉, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO〈sub〉2〈/sub〉 disperses into the reservoir.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: September 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 180〈/p〉 〈p〉Author(s): Wanderson Lambert〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In this work, we propose a technique to solve the system of equations of mass balance for the salt solution and mass balance for salt in the solid phase introduced in the paper “Mathematical model of dissolution of particles of NaCl in well drilling: Determination of mass transfer convective coefficient”. In that paper, authors claimed that there is no technique to solve analytically the provided system of equations (actually, authors claimed that is possible an analytical solution for the “steady state” solution), however, from the mathematical viewpoint, the system of equations modelling this transport is a linear hyperbolic system of equations and it is possible to obtain the solution of this system by using the technique of characteristic waves. Since the model proposed in the paper cited can be used for several different transport equation models, it worth to present the general technique and solution that can be applied in other models in the context of transport phenomena.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Sheng Fu, Zhen Liu, Yi-ming Zhang, Xin Wang, Ning Tian, Ling Li, Hui-lai Wang, Tao Jiang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The Wulan-Hua Sag in the south of Erlian Basin has large oil and gas resource, whereas the source rocks genetic potential and oil-rock correlation in its Aershan Formation (K1ba) and First member of Tengge'er Formation (K1bt1) are still unclear. We performed organic geochemistry analyses of oil and mudstone samples to divide crude oil types, evaluate source rock potential, and establish relatively accurate oil-source correlation. The results indicate that the source rocks in K1ba and the Lower interval in First member of Tengge'er Formation (LK1bt1) belong to good source rocks, characterized by high organic matter abundance, oil-prone kerogen type, and relatively high thermal maturity. K1ba and K1bt〈sub〉1〈/sub〉 crude oil samples were divided into two types sourced from different Wulan-Hua source rocks. Type A oil is distributed in the K1ba and LK1bt1 of Saiwusu uplift and Hongjing uplift, and featured by a low gammacerane amounts (the majority of gammacerane/C〈sub〉30〈/sub〉H 〈 0.30), and high Pr/Ph (ranging from 0.18 to 1.18, with mean value of 0.78). It has high mature organic matter mainly originated from terrestrial plant and dominant terrestrial plant. This type of oil was sourced from the K1ba source rocks in the Saiwusu uplift. Type B oil occurs in the LK1bt1 of the Tumuer Uplift and north sub-sag, and have high gammacerane abundance (the majority of gammacerane/(C〈sub〉30〈/sub〉 〉 0.3), and low Pr/Ph (ranging from 0.38 to 0.76, with mean value of 0.63). Its organic matter includes dominant terrestrial plant source, and this oil type should be sourced from the LK1bt1 source rocks in the Saiwusu uplift.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Wei Liu, Wei David Liu, Jianwei Gu, Xinpu Shen〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The sedimentary rhythm of Chinese oilfields is complicated and the heterogeneity is extremely strong. Allocating water absorption of each sublayer by dividing coefficient or numeric simulation cannot accurately reflect the actual water injection of the reservoir. Calculation based on water absorption profile monitored on site is the most commonly used method in oil field. However, access to these type of data is limited due to its cost and time related to acquisition. In this study, a machine learning approach was adopted to predict water absorption in sublayer based on geologic and production parameters of injectors and producers. On the one hand, it can save test costs. On the other hand, it can continuously predict water absorption of sublayers, and make up for water injection wells with insufficient injection profiles. A handful of training observations are obtained from on-site monitoring. Interwell connectivity is first conducted to identify connected producers for injectors. Introducing interwell connectivity helps to constitute predictor variables and yield significant improvements in feature selection. Connectivities in the well group are represented by similarity between injection sequence and production sequence, which is computed by Dynamic Time Warping. Average importance of predictors are then measured based on Mean Decrease Impurity, Mean Decrease Accuracy, and Ridge regression. Some relative important features are selected to consist the final predictors. The Extreme Gradient Boosting model is developed and then trained for making predictions given any set of observations. The proposed approach is validated by using actual field case from SL oilfield, China. Results show a significant correlation between predictions and actual value from on-site monitoring.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Isty Adhitya Purwasena, Dea Indriani Astuti, Muhamad Syukron, Maghfirotul Amaniyah, Yuichi Sugai〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Microbial enhanced oil recovery (MEOR) is a proven tertiary recovery technique. Biosurfactant is a microbial bioproduct that plays an important role in MEOR applications. This study aimed to test biosurfactant stability using a design experiment based on response surface methodology. First, isolation and screening for potential biosurfactant-producing bacteria from crude oil samples was performed, followed by their characterization. A biosurfactant core flooding experiment was also conducted to examine bacterial activity on MEOR. Thirty-one sequential isolates of bacteria were screened based on qualitative and semi-qualitative parameters. One selected biosurfactant-producing bacterium was identified as 〈em〉Bacillus licheniformis〈/em〉 DS1 based on phylogenetic analysis of the 16S rRNA gene. This bacterium had the highest emulsification activity (E〈sub〉i24〈/sub〉 = 65.19%) in light crude oil and could reduce the interfacial tension between oil and water with an effective critical-micelle concentration of 157.5 mg/L. The biosurfactant was observed as a growth-associated metabolite type and the Fourier transform infrared spectrum revealed that the biosurfactant produced belonged to a group of lipopeptides. The biosurfactant has good stability in maintaining emulsification activity at pH 4–10, high temperatures up to 120 °C, and with an NaCl concentration up to 10% (w/v). Based on response surface methodology using the Box–Behnken experimental design, the optimum condition for the most stable biosurfactant is pH 12, a 40 °C temperature and 10% salinity, with an E〈sub〉i24〈/sub〉 value of 94.28%. Core flooding experiments with biosurfactant resulted in 5.4% additional oil recovery. Therefore, this biosurfactant shows a high potential application for MEOR.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Jiangfeng Cui〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The pre-Darcy flow phenomena in porous media is still not well understood, and the liquid slip mechanism in shales is controversial. Both issues need more exploration. In the field of microfluidic research, the concept of the slip length is widely employed to characterize the deviation from the no-slip flow, and it is recognized that the slip is rate-dependent. For the first time, the rate-dependent slip is proposed as an explanation for the pre-Darcy flow phenomena in porous media and the compromise between existing controversial views with regard to the liquid slip flow in shales based on careful analysis, and then such slip is incorporated in the one-dimension unsteady diffusion equation for liquids. The finite difference method is employed to numerically solve the equation, and detailed sensitivity analysis is conducted for the critical shear stress, the pore radius and the slip length. The results are summarized, and suggestions for future research are provided. This work can provide new insight into the pre-Darcy flow phenomena in the nanoporous media, and can compromise between existing controversial views regarding the liquid slip mechanism in shales. More importantly, this subject is also significant to research and develop EOR methods in shale reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Yongfei Yang, Yingwen Li, Jun Yao, Kai Zhang, Stefan Iglauer, Linda Luquot, Zengbao Wang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The incompatibility between workover fluid and reservoir rock is one of the causes of formation damage. Fines migration and clay swelling are considered as the major mechanisms responsible for formation damage, which results in declining productivity. However, there has been limited visualized evidence of pore structural changes during formation damage. This paper establishes a formation damage evaluation method for sandstone reservoirs based on X-ray micro-computed tomography (CT) analysis. We presented conclusive evidence for clay swelling and fines migration during workover fluid flooding and formation liquid flooding. Water sensitivity and flow rate sensitivity tests were performed on a Dongying sandstone (heterogeneous argillaceous sandstone) plug. In addition, the plug was micro-CT imaged before and after flooding with workover fluid and formation liquid at medium resolution (24 μm voxel size); the changes in core permeability and the associated changes in 2D and 3D pore space were analyzed. We found that the sandstone pore space was partially blocked by clay minerals and moving particles, leading to significantly decreased porosity (5.17%–4.19% for sample 1, 5.38%–2.76% for sample 2) and permeability (3.38 × 10〈sup〉−3〈/sup〉 μm〈sup〉2〈/sup〉 to 1.28 × 10〈sup〉−3〈/sup〉 μm〈sup〉2〈/sup〉 for sample 1, 13.30 × 10〈sup〉−3〈/sup〉 μm〈sup〉2〈/sup〉 to 3.15 × 10〈sup〉−3〈/sup〉 μm〈sup〉2〈/sup〉 for sample 2). This permeability decrease was caused by a decrease in the average pore radius and coordination number. Moreover, increased micro-CT intensity was measured by comparison of initial and final tomogram images, representing clay swelling & blockage of pores during the displacement and a generally lower porosity. This work visualized microscale formation damage, which reminds that incompatibility between workover fluid and reservoir rock damages formation seriously and the fluid injection rate should be lower than the critical flow rate when developing a reservoir with a strong water sensitivity and flow rate sensitivity.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519307776-fx1.jpg" width="245" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Xin Li, Deli Gao, Baoping Lu, Yijin Zeng, Jincheng Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Liang Mu, Hans Ramløv, T. Max M. Søgaard, Thomas Jørgensen, Willem A. de Jongh, Nicolas von Solms〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Antifreeze proteins (AFPs) are characterized by their ability to protect organisms from subfreezing temperatures. They constitute a class of promising candidates as environmentally kinetic hydrate inhibitors (KHIs). In this study, the effectiveness of an insect cell expressed novel monomeric streptavidin fusion protein version of 〈em〉Rhagium mordax〈/em〉 RmAFP1 antifreeze protein (mSA-RmAFP1), and four amino acids (histidine, lysine, tyrosine and proline), on CH〈sub〉4〈/sub〉 hydrate nucleation, growth and decomposition was investigated using a rocking cell apparatus, then compared with the commercial inhibitors Polyvinylpyrrolidone (PVP) and Luvicap Bio. It was found that CH〈sub〉4〈/sub〉 hydrate nucleation and growth exhibited good repeatable results under experimental conditions. The results showed that 2250 ppm mSA-RmAFP1 can inhibit CH〈sub〉4〈/sub〉 hydrate nucleation as effectively as PVP at the same concentration. The histidine, lysine, tyrosine and proline exhibited weak inhibition effect on CH〈sub〉4〈/sub〉 hydrate nucleation. The mSA-RmAFP1 decreased CH〈sub〉4〈/sub〉 hydrate growth rate and production in the fresh and memory solutions. The CH〈sub〉4〈/sub〉 hydrate formed in the solutions containing various tested KHIs present slightly lower onset decomposition temperatures than the non-inhibited system under experimental conditions. The promising performance of the insect cell expressed mSA-RmAFP1 could promote the further development of green hydrate inhibitors. The production of this protein through insect cell line fermentation provides a platform for the future production and optimization of AFPs for hydrate inhibition.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Chao Gan, Wei-Hua Cao, Min Wu, Xin Chen, Yu-Le Hu, Kang-Zhi Liu, Fa-Wen Wang, Suo-Bang Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Rate of penetration (ROP) prediction is crucial for the optimization and control in drilling process due to its vital role in maximizing the drilling efficiency. This paper proposes a novel intelligent model to predict the drilling ROP considering the process characteristics. First, the geological background and the drilling process of the case study are described. Based on the mechanism and frequency spectrum analysis, the strong nonlinearity and different low-frequency and high-frequency data noises between the data variables are detected. After that, the intelligent model is established via three stages. In the first stage, a wavelet filtering method is introduced to reduce these noises in the drilling data. In the next stage, the model inputs are determined by the mutual information method, which significantly decreased the model redundancy. In the last stage, a hybrid bat algorithm is proposed to optimize the hyper-parameters of the support vector regression model. Finally, the proposed model is validated by using the data from a drilling site in the Shennongjia area, Central China. The results demonstrate that the proposed method outperforms eight well-known methods and another three methods without different data preprocessing procedures in prediction accuracy.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Zheng Sun, Keliu Wu, Juntai Shi, Yuanhong Li, Tianying Jin, Qingyang Li, Xiangfang Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉A detailed study for production prediction methods under various drainage schedules for under-saturated coalbed methane wells is performed. In terms of the relationship between the value of average reservoir pressure and the critical desorption pressure, whole production life of under-saturated coalbed methane wells is divided into two periods, and the material balance equation in each period is derived respectively. Combining the two-period material balance equation and productivity equation under pseudo-steady state, a novel production prediction method is developed. Excellent agreements between predicted water/gas production rates from the proposed method and those from numerical simulator clarify the reliability successfully. Results demonstrate that (a) matrix shrinkage effect and effective permeable capability can significantly contribute to the production rise; (b) For the drainage schedule (FWFB), with the increase of the fixed water production rate, the drainage period will shorten; (c) For the drainage schedule (RDFB), sharp decrease of formation pressure will take place.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Matthew Morte, Berna Hascakir〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Candidacy of any reservoir as a microwave absorber is predicated on the complex permittivity of the sample. Modeling both the penetration and absorption dynamics of the electromagnetic wave in the reservoir is dependent on realistic estimation of this parameter. Therefore, it becomes necessary to understand the inherent intricacies of complex permittivity in the reservoir. Reservoirs are comprised of both a void space represented by the porosity parameter as well as the rock matrix and can be treated as a binary mixture of the two. Mixing rules can then be introduced and have been shown to be a viable means of estimating the dielectric response. The behavior of the bulk material is considered to be an extension of the isolated contribution of the separate parts. Therefore, by characterizing the response of the individual components of the mixture, the overall response can be estimated. Utilization of mixing rules enables efficient estimation of the dielectric properties anywhere in the reservoir as a function of the rock matrix, fluid saturation, and porosity. The absorptive capacity of the reservoir can then be described which is used to screen the efficacy of the material for microwave introduction. Both the real and imaginary components of complex permittivity are measured on nine consolidated core samples of varying lithology and fluid saturation over the frequency range of 400 MHz to 6 GHz. Experimental data is compared to various mixing rules commonly implemented to determine validity and viability of the estimation of complex permittivity for consolidated samples.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Qingsong Cheng, Min Zhang, Hongbo Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Test analyses such as pyrolysis, soluble organic matter extraction, group component separation and GC-MS were conducted to 22 source rock samples and 28 crude oil samples from deep lacustrine facies of Funing Formation in Subei Basin. Source rocks stayed at the low maturity-mature stage (Ro:0.58%–0.71%), while crude oil stayed at the mature stage (Rc:0.71%–0.88%). The Pr/Ph values of samples in the research area ranged between 0.16 and 0.62. These samples could be classified as Sterane/Hopane〉1 and Sterane/Hopane〈1. For all the samples, the C〈sub〉29〈/sub〉 Steranes content was high; had inverse “L” distribution in ααα20RC〈sub〉27〈/sub〉-ααα20RC〈sub〉28〈/sub〉-ααα20RC〈sub〉29〈/sub〉 regular sterane; αα20R-Sterane played a dominant role; abundances of ββ- and 20S-Sterane were low. As for samples of Sterane/Hopane〉1, G/C〈sub〉30〈/sub〉H ranged between 0.63 and 2.56, and the Sterane isomerization was very low. As for samples with Sterane/Hopane〈1, G/C〈sub〉30〈/sub〉H ranged between 0.04 and 0.46 and the Sterane isomerization was higher than the former. Abnormal distribution of Sterane isomerization was rarely influenced by thermal dynamic effects and sources, but was mainly influenced by the sedimentary environment. A lot of references reported Sterane isomerization with abnormally high abundance under the high-salinity environment. However, the finding obtained by the research that the higher water salinity corresponded to the lower degree of Sterane isomerization was discovered for the first time. The C〈sub〉29〈/sub〉 Sterane abundance was high and the C〈sub〉29〈/sub〉/C〈sub〉27〈/sub〉 regular sterane ratio was constant and would not vary with changes of environmental parameters and biological source parameters. Sterane content was not correlated with tricyclic terpene of algae sources, but was positively correlated with ETR of the aquatic organism source, while it had very good positive correlation with Gammacerane. In addition, samples with the high Sterane content had high abundance in Carotene, C〈sub〉24〈/sub〉+alkyl-cyclohexane and C〈sub〉21〈/sub〉+isoprenoid alkanes. Through profound analysis and reference survey, it is found that the abnormally high abundance of C〈sub〉29〈/sub〉 Sterane of samples in the research area may be correlated with halophilic protozoon in salinized deepwater lakes.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Ahmed Farid Ibrahim, Hisham A. Nasr-El-Din〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.〈/p〉 〈p〉Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of the leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.〈/p〉 〈p〉The results show that the regained permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regained permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regained permeability on shale cores was 15% of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.〈/p〉 〈p〉This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Arash Azamifard, Fariborz Rashidi, Mohammad Ahmadi, Mohammadreza Pourfard, Bahram Dabir〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Different sources of data are used to construct a reliable model of reservoir for oil/gas production. This model ought to be matched with the production history of reservoir and also show reliable predictions for future performance. To this end, permeability modeling (characterization of heterogeneity) is crucially important which is proved to be done by Multiple Point Statistics (MPS) recently. Furthermore, deep learning methods are massively used as a promising tool for regression applications. In this study, one MPS method is employed for generating the reservoir realizations. Realizations, alongside their simulation outputs, are utilized for training a convolutional deep network. In this manner, MPS is joined with deep learning to find the most appropriate realization(s) of the reservoir based on the fluid flow simulation. Moreover, unseen MPS realizations as well as another MPS realizations are used to verify the selection ability of trained network. The detailed architecture of convolutional network is illustrated in this study.〈/p〉 〈p〉The purpose of training this network and combination with MPS is to generate the matched realization(s) in history period that also show acceptable reservoir behavior in the future times of reservoir simulation. After training, the actual production data of selected realizations are obtained by simulation the reservoir for history and also future times. The results show that selected realizations efficiently capture the trend of reference behavior. Although these realizations lack identical permeability values, they have same texture of permeability (permeability heterogeneity). Meanwhile, they show acceptable match in reservoir simulation outputs. By proposed workflow, the uncertainty of permeability modeling is considered more exhaustively. It is done by selecting the realizations from enormous possible realizations dataset and providing a deep learning tool which is capable for screening quite large number of realizations. Interesting finding is satisfactory behavior of realization(s) in both history and future periods of reservoir performance.〈/p〉 〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519305467-fx1.jpg" width="351" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Chean Xing Liew, Raoof Gholami, Mehdi Safari, Arshad Raza, Minou Rabiei, Nikoo Fakhari, Vamegh Rasouli, Jose Varghese Vettaparambil〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Certain polymers are often used during water based mud (WBM) drilling to reduce the filtration loss in permeable intervals. Although they often provide a good performance but cannot totally stop the fluid loss and mud invasion into the reservoir may cause significant formation damage including unfavourable changes of surface wettability. As a result, the two phase relative permeability of the near wellbore region changes and production may face difficulties in the later stages. In this paper, a new mud design is proposed to reduce the surface wettability alteration posed by WBM in sandstone reservoirs. The results obtained from performing a series of contact angle measurements indicated that clean and dirty sandstones are strongly water wet systems but mud invasion can make them a weakly water wet surface. It was also found that Cetyltrimethylammonium bromide (CTAB), as a cationic surfactant, prevents surface alteration of rocks and reduce the formation damage, but it may isolate the clay and creates a huge mud cake around the borehole. It was also observed that the salinity of the mud has a great impact on the surface wettability and adding CaCl〈sub〉2〈/sub〉 can reduce the formation damage in the reservoir intervals during drilling, although caution must be taken to maintain the cost of the mud.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519306333-fx1.jpg" width="134" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Ning Li, Yushi Zou, Shicheng Zhang, Xinfang Ma, Xingwang Zhu, Sihai Li, Tong Cao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Evaluating the brittleness of rock is significant for strategy determination of hydraulic fracturing, such as candidate selection and parameter optimization. A series of definitions and indices of brittleness have been proposed to characterize the mechanical behavior rock failure. However, these existing indices failed to consider the residual state and the confinement effect. Based on the analysis of energy evolution during the whole process of rock failure, the brittleness was redefined in this study as the comprehensive capability of dissipating little energy during the pre-peak stage and self-sustaining complete failure during the post-peak stage. Accordingly, a new energy-based brittleness index 〈em〉B〈/em〉 was proposed in terms of the complete stress-strain curve to quantify this capability from following three aspects: the ratio of accumulated elastic strain energy and total absorbed energy during the pre-peak stage (〈em〉B〈/em〉〈sub〉1〈/sub〉); the proportion of elastic strain energy in all energy source consumed for sustaining rock failure (〈em〉B〈/em〉〈sub〉2〈/sub〉); and the dissipation extent of accumulated elastic strain energy during the post-peak stage (〈em〉B〈/em〉〈sub〉3〈/sub〉). To verify the reliability of the new method, uniaxial and triaxial compression tests were performed on different types of rock samples. The application and comparison of various indices showed that the new brittleness index precisely characterized the stress-strain curves and failure behavior of rock samples under different confinement levels. The variation trends of brittleness with confining pressure were obviously distinct among different rock types. Three independent brittleness indices 〈em〉B〈/em〉〈sub〉1〈/sub〉, 〈em〉B〈/em〉〈sub〉2〈/sub〉, and 〈em〉B〈/em〉〈sub〉3〈/sub〉 were helpful for analyzing sensitivity difference of brittleness to confining pressure among different rock types. Accordingly, this new energy-based method can provide reliable evaluation of rock brittleness.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Xin Sun, Zhibin Gao, Mingwei Zhao, Mingwei Gao, Mingyong Du, Caili Dai〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Based on the situation of the freshwater shortage during the large scale hydraulic fracturing on offshore-platform, a novel seawater-based viscoelastic fracturing fluid system was developed. The system was composed with a commercial anionic – nonionic viscoelastic surfactant named Fatty Methyl Ester Sulfonates (FMES) with the concentration of 60 mmol/L, the South China Sea simulated seawater with the TDS of 32500 mg/L and Na〈sup〉+〈/sup〉 with the concentration of 1320 mmol/L. On the basis of this fracturing fluid system, a series of performances have been evaluated through extensive experiments. Analysis of laboratory tests indicated that the new fluid has good viscosity stability, low fluid loss and high proppant suspending ability under 75 °C. This fluid always appeared as a pseudoplastic fluid at various shearing speeds. After high speed shearing, the viscosity recovered quickly which means the fluid has remarkable self-repairability. This fluid breaks rapidly once oil injected. The observed permeability return rate achieved through core flooding experiment was over 70%, which indicated low formation damage after fracturing. Furthermore, the vermicular micelle and microstructure of fluid system has been discovered through Cryogenic Transmission Electron Microscope (cryo-TEM), which well explained the mechanism of excellent performances of fluid system.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Iman Nowrouzi, Abbas Khaksar Manshad, Amir H. Mohammadi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Using smart nano-fluids with respect to enhanced oil recovery (EOR) is an emerging technology, which is normally studied in combination with other methods. Nano-fluid performance depends on type, size and concentration of the dispersed nano-particles in it. In the current work, effects of size and concentration of seawater-based nano-fluid of TiO〈sub〉2〈/sub〉 in different salinities (resulted from dilution) on enhanced oil recovery parameters including contact angle, wettability and interfacial tension (IFT) have been investigated using the pendant drop method. Eventually, effect of TiO〈sub〉2〈/sub〉 nano-particles in nano-fluids on recovered quantity has been investigated using imbibition experiment mechanism, which is one of the most important mechanisms in oil production from fractured reservoirs. Results of the experiments show that using higher concentration and smaller particle sizes of TiO〈sub〉2〈/sub〉 would decrease the IFT and contact angle. Higher concentration and larger particle sizes of TiO〈sub〉2〈/sub〉 in nano-fluid would increase the viscosity. Imbibition experiments show that the nanofluids containing smaller TiO〈sub〉2〈/sub〉 nanoparticles are more efficient.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519307788-fx1.jpg" width="273" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Gene Mask, Xingru Wu, Kegang Ling〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The determination of flow patterns is a fundamental problem in two-phase flow analysis, and an accurate model for gas-liquid flow pattern prediction is critical for any multiphase flow characterization as the model is used in many applications in petroleum engineering. We developed a new model based on machine learning techniques via dimensionally analyzing more than 8000 laboratory multi-phase flow tests. As shown in the test results, the flow pattern is affected by fluid properties, in-situ flow rates of liquid and gas, flow conduit geometry and mechanical properties. Applying hydraulic fundamentals and dimensional analysis, three upscaling numbers are developed to reduce the number of freedom dimensions. These dimensionless variables are easy to use for upscaling and have physical meanings. Machine learning techniques on the dimensionless variables significantly improved their predictive accuracy. Until now the best matching on these laboratory data was approximately 80% using the most recently developed semi-analytical models. The quality of the matching is improved to 90% or greater on the experimental data using machine learning techniques.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Richard O. Afolabi, Esther O. Yusuf, Chude V. Okonji, Shalom C. Nwobodo〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Modelling the flow of nanoparticle modified drilling mud (or nano-drilling muds) requires the use of existing generic time-independent models with the addition of nanoparticle terms having a number of parameters incorporated. These parameters quantify the uncertainties surrounding nanoparticle contributions to drilling mud rheology. However, when the parameters in the overall model become too large, the tuning of each parameter for proper flow description can be challenging and time-consuming. In addition, the predictive capability of known models for the different regimes associated with the flow of nano-drilling muds is limited in scope and application. For example, computational analysis involving nano-drilling muds have been described using Herschel-Buckley, Power-Law, Bingham Plastic, Robertson-Stiff, Casson, Sisko, and Prandtl-Eyring. However, these models have been shown over time to have limited predictive capability in accurately describing the flow behavior over the full spectrum of shear rates. Recently, a new rheological model, the Vipulanandan model, has gained attraction due to its extensive predictive capability compared to known generic time-independent models. In this work, a rheological and computational analysis of the Vipulanandan model was carried out with specific emphasis on its modification to account for the effects of nanoparticles on drilling muds. The outcome of this novel approach is that the Vipulanandan model can be modified to account for the effect of interaction between nanoparticles and clay particles. The modified Vipulanandan show better prediction for a 6.3 wt% mud with 〈math xmlns:mml="http://www.w3.org/1998/Math/MathML" altimg="si1.svg"〉〈mrow〉〈msup〉〈mrow〉〈mtext〉R〈/mtext〉〈/mrow〉〈mrow〉〈mn〉2〈/mn〉〈/mrow〉〈/msup〉〈/mrow〉〈/math〉 of 0.999 compared to 0.962 for Power law and 0.991 for Bingham. However, the R〈sup〉2〈/sup〉 value was the same with Herschel Buckley model but the RMSE value show better prediction for the Vipulanandan model with a value of 0.377 Pa compared to the 0.433 Pa for Herschel Buckley model.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Yizhong Zhang, Maolin Zhang, Haiyan Mei, Fanhua Zeng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉For the tight gas reservoir with high salinity formation water, the flow of formation brine may cause salt precipitation and thus promote scale formation. Salt deposition and the accompanying scale formation as well as swelling and shrinkage of clay minerals may cause blockage of the pore and throats, which will significantly reduce permeability and the subsequent gas production rate. In this study, the influence of salt precipitation/dissolution on the physical properties of a tight gas reservoir is studied. Core analyses, core flooding tests, core evaporation tests, and microscopic visual flooding inspections are carried out on core samples extracted from the Shahejie Formation. To simulate the depletion production process in the subsurface, brine flow characteristics are studied by core flooding tests with pressure reduction at a formation temperature of 115 °C and with the change of pressure ranging from 30 to 1 MPa. The potential changes in physical properties including permeability, porosity, pore radius, pore size distribution, and surface area are analyzed by core evaporation tests. To show the brine flow and geometry of salt deposits in the pore structure, visual brine flooding is observed under high magnification microscope. Photos of the pore structure at different stages of salt precipitation are recorded. The results reveal that salt dissolution/precipitation has a significant impact on flow-through characteristics, and it can be divided into three stages during the depletion process. The damage of salt to the core permeability could reach more than 90%, and it increases gradually with the reduction of porosity and initial permeability and the increase of specific area. The maximum formation damage caused by salt precipitation is realized when the salt crystal size and pore throat diameter are close in size. The semi-empirical Carman-Kozeny equation together with porosity and grain diameter is used to estimate the permeability after precipitation.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Mohammad Reza Mahdiani, Ehsan Khamehchi, Amir Abolfazl Suratgar〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉In the gas lift, gas injection rate has an optimum value and increasing or decreasing its amount decreases the oil production rate. This optimum point changes in production time and creates an optimum trajectory. There has previously been much research in this area, but none have used a powerful tool in a dynamic model to find a good optimal path for maximizing the production or NPV in a gas-lifted field. In addition, gas allocation in a time step changes the production of different wells and the pattern of fluid flow and also reservoir pressure decline in the reservoir. This can affect the optimum gas allocation of the next time step, but this has not been analyzed in any of the previous works. In this paper, first, a model of reservoir and well of a gas lift well is developed and using some experimental data points the best-fitted correlations are selected. Then, two common and famous heuristic algorithms (genetic algorithm, simulated annealing), and two recently introduced optimization algorithms (Moth Swarm Algorithm and Grasshopper Optimization Algorithm) are used to find the optimal path of the injection lift gas rates of the wells. Finally, the results of these four algorithms are compared with each other and some other allocation scenarios. In addition, different aspects of the injection and production rates of the different wells and their cumulative rates and NPV paths are analyzed. The results illustrated that using MSA has an optimum point with higher production. In addition, MSA finds a specific control path with a need for lower lift gas and also a smaller compressor. It also has a really different control path with other optimization algorithm paths. In addition, in this paper, a new long term instability in flow is observed, which was explained by the drainage area of each well. This control path of each well was discussed and it was concluded that GA can find the most stable path.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Shaobin Guo, Wenjing Mao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This research analyzed the pore evolution and diagenesis in a Permian Shanxi shale from the Ordos Basin. Thermal simulation method simulated the thermal evolution of organic matter in a sample from mature (R〈sub〉o〈/sub〉 = 0.96%) to overmature (R〈sub〉o〈/sub〉 = 3.05%). Gas adsorption and mercury intrusion capillary pressure techniques were used to analyze pore-size distribution across a maturation gradient. X-ray diffraction, Focused Ion Beam-Scanning Electron Microscopy and rock pyrolysis techniques were used to divide the stages of diagenesis and pore evolution. Results showed that mesopores and macropores dominate pore volume while micropores and mesopores dominate surface area. Pore volume and surface area initially decreased and then increased with maturity. Kaolinite is converted to illite and illite-smectite mixedlayer in the middle to late diagenesis stage. Pore evolution and diagenesis can be divided into four stages in a sample from mature to overmature. Factors influencing pore-size distribution are different in four stages.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Feng Tian, Xiaodong Wang, Wenli Xu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Most gas reservoirs are not homogeneous in practice. Due to the influences of the nonlinearity and heterogeneity, little work has focused on the behavior of multiple-fractured horizontal wells (MFHWs) in heterogeneous gas reservoirs. In this study, a semi-analytical model based on a detailed analytical method for MFHWs in heterogeneous gas reservoirs is established. The source functions, boundary element method and Green's solution are used to build the model in Laplace space. To solve the problem that the combination of the pseudo-function approach with the material balance equation describing homogeneous gas reservoirs cannot be effectively linearize the nonlinearity in heterogeneous gas reservoirs, a multi-region material balance equation for heterogeneous gas reservoirs is derived. Then, the performance of an MFHW in a two-block gas reservoir is calculated. The pressure behavior and the flux distribution are influenced by the crossflow coefficient, fracture conductivity, size of the gas reservoir, fracture half-length and storage ratio. A high crossflow coefficient increases the flux of the interface and the difference in flux between fractures in different blocks. The effects of the crossflow can be weakened by a high fracture conductivity and large fracture half-length. This study provides a theoretical basis for MFHWs in heterogeneous gas reservoirs.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Jinming Zhang, Xiaosen Li, Zhaoyang Chen, Qingping Li, Gang Li, Tao Lv〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Gas production from low-permeability hydrate reservoirs is characterized by very low efficiency. In this work, the enlarged well wall with good permeability was first proposed to improve the gas production performance from low-permeability hydrate reservoir in Liwan 3 area of the South China Sea. The gas-water production behaviors, the spatial distributions and evolutions of hydrate reservoir parameters and gas-water flow characteristics, induced by constant-depressurization, were investigated and evaluated by numerical simulations under different radius of permeable well wall. Results show that the enlarged well wall provides a high-permeability channel around the production interval and increases the contact area between the production interval and hydrate layer, so the pressure drop propagation speed and distance, i.e. the depressurization efficiency in the hydrate-bearing sediments is increased. Both gas and water production performances are significantly improved, and the gas and water production rates, cumulates and gas to water ratio increase with the increase in permeable well wall radius. The cumulative CH〈sub〉4〈/sub〉 and water produced increase by 〈em〉ca.〈/em〉 4 and 3 times, respectively, when the permeable well wall radius increases from 0 to 5 m. However, the heat supply by heat convection of geothermal water is still limited.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Herson Oliveira da Rocha, Jéssica Lia Santos da Costa, Antonio Abel Gonzaléz Carrasquilla, Alfredo Moisés Vallejos Carrasco〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉One of the most significant problems in the characterization and recovery of Aptian carbonate reservoirs, especially the Brazilian pre-salt, has been the lack of precise estimates of permeability. The heterogeneity of the permeability of the carbonate reservoirs occurs owed great different of the pore form occurred mainly by diagenetic processes. In this study, propose a joint and integrated methodology to estimate the permeability in the reservoir. To achieve this goal, porosity-permeability core data, image logs, applying the Rock Types concepts, analysis of the results of well log Nuclear Magnetic Resonance (NMR), modeling the well logs resistivity (laterolog and induction), as well as estimating the specific surface of the rock using images of section 2D from the pugs, to quantitatively estimate the permeability of the reservoir based on the petrophysical properties of the rocks. In the study it was possible to identify different pore systems distributed in eight Hydraulic Flow Units (HFU) determined from the pore groove radii. The Nuclear Magnetic Resonance (NMR) log it served to separate area of the spectrum corresponding to the small pores from the area corresponding to the large pores. The resistivity logs were analyzed with the purpose of estimating the direction (vertical, horizontal and dipping) and thickness of the fractures, which were also modeled with the purpose of identifying the invasion of the drilling fluid. The specific surface area was obtained by image processing algorithms. The results showed an acceptable precision of this methodology to estimate the permeability in carbonate reservoirs that have in their composition fragments of stromatolites and associated bioclastics, found partially or totally dolomitized.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Qing He, Tian Dong, Sheng He, Gangyi Zhai〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Factors influencing the methane adsorption capacity (MAC) of marine-continental transitional facies shales have been identified applying a variety of techniques (e.g., total organic carbon (TOC) content, X-ray diffraction mineralogy, low-pressure CO〈sub〉2〈/sub〉 and N〈sub〉2〈/sub〉 adsorption, and methane adsorption analyses) on samples from the Upper Permian Longtan Formation, northern Guizhou Province, Southwest China. The TOC contents of the Longtan shale samples ranged between 1.2 and 9.9 wt% (average = 3.5 wt%). The results of the bulk XRD analysis suggested that the mineralogical composition of the studied samples was different from that of typical marine shales: the samples primarily consisted of clay minerals, followed by quartz and feldspar. The Langmuir volumes (V〈sub〉L〈/sub〉) of the 14 shale samples ranged from 1.02 ml/g to 5.25 ml/g (average = 2.52 ml/g); moreover, their MAC was positively correlated with the pore volume, surface area, and TOC content, suggesting that organic matter and pore structure were the most critical factors influencing the adsorption capacity of these transitional shales. Our results showed that the MAC was not positively with the clay content; additionally, the MAC tended to increase with increasing pressure, but to decrease with increasing temperature. The presence of moisture greatly reduced the MAC. Overall, the MAC of the transitional Longtan Formation shales resulted to be quite different from that of typical marine shales (e.g., the Lower Silurian Longmaxi Formation in the Sichuan Basin) in terms of mineralogical component and abundance of organic pores. The particularly high abundance of (hydrophilic) clay minerals in the Longtan Formation transitional shales resulted in a higher number of adsorption sites occupied by water molecules than in the Longmaxi Formation and a lower MAC. Finally, the abundance of organic pores in marine shales resulted in a higher MAC than that of transitional shales.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Kaibo Zhou, Shuo Zhang, Zhen Huang, Jianyu Zhang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Reservoir porosity obtained from time-domain induced polarization (TDIP) well logging plays a vital role in estimating the hydraulic properties and obtain the reservoir parameters in a water-flood oil-field. Improving the inversion accuracy of the reservoir porosity can enhance the oil recovery in the water-flood oil-filed. Evaluating reservoir pore size distribution through induced polarization decay curve is confronted with the problems of poor applicability of data pre-processing, low accuracy and lacking of evaluation criteria for inversion results of pore size distribution. The basic principles of TDIP are introduced and the relationship between pore relaxation time and pore diameter is given. Combining the mathematical characteristics of polarization decay curve data, the performance and the limitations of existing pre-processing algorithms are analyzed and pointed out, respectively. An improved data pre-processing algorithm using the spatial characteristics of linear transformation based on migration Hankel matrix is proposed, and this method improves the inversion accuracy of pore size distribution greatly. In the engineering application, 2-logarithmic sampling method is proposed to sample the polarization decay data for more efficient petroleum exploration with less sample points. The different regularization methods, regularization matrix and regularization parameter determination methods are compared and analyzed for the inversion of the pore size distribution. The numerical simulation experimental results show that the stability and accuracy of Truncated Singular Value Decomposition - Generalized Cross Validation (TSVD-GCV), Truncated Singular Value Decomposition - L Curve (TSVD-L) and Tikhonov-I-L are appropriate for the inversion of pore size distribution. Because of the truth that the pore size distribution of rock is unknown, Backus-Gilbert (BG) theory is introduced to evaluate the inversion results of rock polarization decay curve data of a mining area in Jilin Province. The rock sample experiment shows that the TSVD-GCV inversion algorithm has the best performance.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Refaat G. Hashish, Mehdi Zeidouni〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Injection profiling in multilayer (stratified) reservoirs is essential for successful water flooding and effective reservoir management. When possible, injection profiling may be achieved via production logging tools (PLT). An alternative approach is to utilize real-time temperature obtained e.g. via fiber optic distributed temperature sensing (DTS) to obtain the injection profiles. Development of modelling tools is required to enable analyzing temperature data to obtain the injection profiling.〈/p〉 〈p〉In this work, an analytical solution is developed to determine the transient temperature distribution in the reservoir during the warm-back period that follows cold fluid injection. The analytical model is used to introduce a temperature inversion approach to obtain the injection profile. The analytical solution is developed for single- and multi-layer reservoirs considering single-phase flow at constant rate over the injection period. The solution considers heat transfer by conduction and convection during the injection period. Warm-back is attained during the subsequent shut-in period through heat transfer by conduction in the reservoir (thermal equilibration) as well as the heat exchange between the completed layers and the surroundings. Heat transfer with the surrounding layers affects the warm-back rate the most for relatively thin layers. The analytical solution is verified through comparison against numerical simulation results obtained using a thermally coupled numerical simulator for single- and multi-layer reservoir cases. Graphical interpretation techniques are introduced by recasting the analytical solution into convenient forms. The graphical techniques are applied to synthetic warm-back data to illustrate their reliability and accuracy in obtaining the injection profile and the thermal front extent (per layer) during the injection period.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Licong Jin, Lei Tao, Decai Li〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Petrocedeño is located in the southeast of Venezuela, which is an onshore heavy oil field with average viscosity about 5000 cP. In order to increase the oil recovery, polymer injection is planning in the pilot. The fall-off test, one approach to analyse the polymer properties in reservoirs directly, is also planned after polymer injection. In order to investigate whether fall-off test could provide sensible data for injection of Non-Newtonian fluids in horizontal wells and hence establish an optimal strategy for implementing such test, simulation work and analytical studies have been performed in this paper. The aim of this paper has been to analyse polymer fall-off interpretation method in Petrocedeño, and then to provide feasible suggestion or guidance for polymer fall-off implementation in the real pilot where the injection wells are horizontal.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Qi Chu, Ling Lin, Yukun Zhao〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Hyperbranched polyethylenimine modified with a silane coupling agent (Si-HPEI) as a shale inhibitor was synthesized by the Michael addition reaction of hyperbranched polyethylenimine (HPEI) and methacryloxypropyltrimethoxysilane. The structure of Si-HPEI was characterized by Fourier transform infrared spectroscopy and proton nuclear magnetic resonance. The inhibitory properties of Si-HPEI in comparison with currently available inhibitors were evaluated using linear swelling tests, cuttings dispersion tests, and bentonite inhibition tests. The inhibitory mechanism was investigated via X-ray diffraction measurements, adsorption measurements, and atomic force microscopy observations. The results indicated that Si-HPEI effectively inhibited the hydration and expansion of shale and exhibited excellent temperature resistance in comparison with HPEI and traditional shale inhibitors. The shale cuttings recovery in the case of Si-HPEI remained above 68% up to a hot rolling aging temperature of 140 °C, which demonstrated an excellent ability to inhibit hydration and dispersion that was significantly less affected by the hot rolling aging temperature than in the cases of other inhibitors. In addition, Si-HPEI inhibited the formation of a bentonite slurry more effectively at high temperatures. A mechanistic analysis showed that the siloxane groups present in the molecular chains of Si-HPEI caused strong and stable chemical adsorption of Si-HPEI on water-sensitive clay minerals, which thus hindered the penetration of water molecules and ultimately inhibited the hydration expansion and dispersion of water-sensitive clay minerals. In field application, Si-HPEI was successfully applied on Su 4-4HF well.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: Available online 21 August 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering〈/p〉 〈p〉Author(s): Hao Chen, Yi Hu, Yong Kang, Can Cai, Jiawei Liu, Yiwei Liu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Supercritical carbon dioxide (SC-CO〈sub〉2〈/sub〉) fracturing has attracted considerable attention on exploiting shale gas and tight gas. This study investigated the influence of the perforation orientation on fracture initiation and propagation induced by SC-CO〈sub〉2〈/sub〉 fracturing through a series of laboratory fracturing experiments under tri-axial stress states and water was also used as a fracturing fluid to compare with SC-CO〈sub〉2〈/sub〉. It was found that breakdown pressure increases with the increase of perforation angle according to the pressure curves in SC-CO〈sub〉2〈/sub〉 fracturing and hydraulic fracturing. AE energy characteristic has shown that AE energy release rate of SC-CO〈sub〉2〈/sub〉 fracturing is larger than that of hydraulic fracturing, indicating that fractures induced by SC-CO〈sub〉2〈/sub〉 fracturing are more complex. Fracture geometry and energy surges verified that there were more fractures induced by SC-CO〈sub〉2〈/sub〉 fracturing with increase of the perforation orientation angle. It was observed that hydraulic fracturing mainly induced a bi-wing fracture while SC-CO〈sub〉2〈/sub〉 fracturing induced bi-wing and tri-wing fracture. At low perforation angle (〈em〉α〈/em〉 ≤ 45°), perforation orientation has little influence on fracture propagation direction and fracture extends along the direction of the maximum principle direction in SC-CO〈sub〉2〈/sub〉 fracturing. At high perforation angle (〈em〉α〈/em〉 ≥ 60°), fracture propagation shows an independence of loading stress, fractures may extend in three directions. The findings are beneficial for further understanding the mechanism of SC-CO〈sub〉2〈/sub〉 fracturing and optimizing perforation parameters in SC-CO〈sub〉2〈/sub〉 field fracturing.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: Available online 21 August 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering〈/p〉 〈p〉Author(s): Pengju Chen, Meng Meng, Rui Ren, Stefan Miska, Mengjiao Yu, Evren Ozbayoglu, Nicholas Takach〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉When cutting a saturated rock under pressure, the PDC cutter is not only fragmenting the rock matrix, but also driving the pore fluid ahead of it. Because of the solid-fluid coupling in rock, different pore pressures induced by cutter will affect rock failure and lead to different MSE. The fact that cutting process is influenced by the pore pressure response in the rock is referred to as 〈em〉poroelastic effects〈/em〉 in this paper.〈/p〉 〈p〉This paper continues the research in our previous work (Chen et al., 2018) and gives more insights into the poroelastic effects during rock cutting process. The influences of rock diffusivity coefficient and cutter speed are studied. The results show that the two parameters will affect pore pressure response in rock and further affect rock failure and MSE during cutting process. Based on the results, the cutting process can be identified as three conditions: undrained, drained and a transition zone between undrained and drained condition. In undrained and drained condition, MSE will be independent of cutter speed; while in transition condition, MSE decreases with increasing cutter speed. The transition boundaries for the three conditions are given. Cavitation in intact rock during cutting process is also studied. The results show that cavitation is easy to occur when cutting a hard rock with low original pore pressure.〈/p〉 〈p〉Cutting tests were conducted on Torrey Buff sandstone and Carthage marble to verify the poroelastic effects in cutting process. A good agreement between the model results and experiments is found. In general, the results in this paper can give a good understanding on the combined influence of formation permeability, depth of cut and RPM on cutting rock during drilling.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Bona Prakasa, Khafiz Muradov, David Davies〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Forecasts of the performance of waterflooded oil-field have been prepared for many years using fractional flow models, such as those by (Buckley-Leverett, 1942) (BL), (Welge, 1952) and (Dykstra-Parsons, 1950) (DP), to estimate the vertical sweep efficiency between wells. These methods, and their later modifications, formed the theoretical basis for designing a water-flooded oil-field. Advanced Well Completions (AWC) incorporating downhole flow control device (FCD) technology have become a proven method for modifying a production well's inflow profile, delaying water breakthrough, improving sweep efficiency and enhancing recovery.〈/p〉 〈p〉This manuscript extends the fractional flow model describing the performance of a waterflooded, stratified-reservoir with an AWC installed in the production well. The piston-like behaviour of the water-front described by previous, semi-analytical models is extended here to the linear and radial flow modelling of more realistic displacement profiles.〈/p〉 〈p〉This paper describes the theoretical basis and application workflow along with several case studies illustrating their performance and value. The accuracy of the new, semi-analytical models are verified by comparison against the results from a numerical reservoir simulator. Model limitations and possible future extension are also discussed.〈/p〉 〈p〉The workflow can be implemented as either a production forecast or a diagnostic tool for an AWC well in a waterflooded oil-field. It provides one missing link between today's AWC design workflows and the long-term value evaluation of a specific AWC design when a commercial numerical simulation software is either not available or too time consuming.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Olujide S. Sanni, Ogbemi Bukuaghangin, Thibaut V.J. Charpentier, Anne Neville〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Injecting chemical inhibitors is the most common method to mitigate mineral scaling in the oil industry. As such, the effectiveness of the techniques employed to evaluate performance of chemical scale inhibitors and apply the appropriate dosage is a very important aspect to be considered during the design of a scale prevention treatment. In this paper, the kinetics of scale formation and its inhibition are studied using a conventional bottle test, a dynamic tube blocking rig and a recently developed 〈em〉in-situ〈/em〉 flow visualization rig. Calcium carbonate scaling brine was prepared at two saturation indices (SI) of 2.1 and 2.8 at 50 °C and run through the rigs at flow rate of 20 ml/min. The conventional polphosphinocarboxylic acid (PPCA) inhibitor was used for the inhibition study at concentration ranging between 0.5 and 10 ppm. The MIC〈sub〉bulk〈/sub〉 determined from bottle test and supported with the 〈em〉in-situ〈/em〉 turbidity MIC〈sub〉bulk〈/sub〉 for SI of 2.1 and 2.8 are 1 ppm and 8 ppm respectively. For the same SI values, a considerably lower concentration of PPCA, 0.5 ppm and 4 ppm for the surface inhibition test using the capillary rig were obtained compared to MIC〈sub〉surface〈/sub〉 of 4 ppm and 8 ppm from the 〈em〉in-situ〈/em〉 visualization technique. The surface visualization technique enables the range of concentration of inhibitors at which both bulk and surface scaling are completely controlled to be determined. The different techniques are shown to give complementary information for different stages of crystallization process and inhibition.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: October 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 181〈/p〉 〈p〉Author(s): Siyamak Moradi, Saeed Amirjahadi, Iman Danaee, Bahram Soltani〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Asphaltene deposition in the wellbore during natural depletion and EOR processes causes severe problems and increases the cost of the incremental oil recovery. Investigation of coatings as a preventive approach for operational problems during well production seems mandatory due to economic, environmental and technical limitations involved in mechanical and chemical treatment approaches. In this work, the anti-asphaltene performance of different coatings namely epoxy resin, polyurethane, phosphate, and two fluoropolymers (PTFE and PFA) was investigated by using a flow loop experimental setup. The wettability characteristics of the coated coupons were also studied by contact angle measurements to explore the correlation between asphaltene adherence tendency and wettability of the treated surfaces. Experimental results showed that despite the hydrophilicity of carbon steel, an intense increasing trend in asphaltene deposition occurred due to intrinsically high surface energy of carbon steel. An anti-asphaltene deposition ratio (R〈sub〉aa〈/sub〉) was defined to describe the anti-stick performance of different coatings compared to the uncoated carbon steel. It was observed that hydrophobic polyurethane and epoxy resin coatings showed weak anti-asphaltene performance with low R〈sub〉aa〈/sub〉 values where they have reduced asphaltene deposition 10% and 48.34%, respectively. Super-hydrophilic phosphate coating reduced the asphaltene deposition by 91.25% via formation of a water film on the coated surface. Finally, the fluoropolymer coatings showed the best performance among investigated samples by anti-asphaltene deposition ratios of 99.89% and 99.94%. The low surface energy of these coatings introduces them as non-reactive surfaces compared to other coatings, hence accepting much less asphaltene deposition.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519305005-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Wei Tian, Peichao Li, Yan Dong, Zhiwei Lu, Detang Lu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉With the large-scale commercial exploitation of shale gas around the world, the multi-interval fracturing technique in horizontal well has played an important role to stimulate shale gas reservoirs. The commonly used fracturing methods in reservoir stimulation are the sequential fracturing, the alternate fracturing, and the latest proposed modified zipper fracturing (MZF), which has improved the shale gas production significantly. However, the mechanism of stimulation has not been well understood yet. This paper presents some numerical simulation results for the three different fracturing patterns by use of extended finite element method (XFEM). The numerical solution mainly considers the influences of the in-situ stress difference and the fracturing spacing on fracture propagation. The analytical parameters include the maximum principal stress, the principal stress direction and the fracture width distribution. The numerical results indicate that the induced stress from adjacent fractures is the key factor affecting the fracture configuration. And the stress interference becomes significantly serious when fracture spacing decreases or fracture number increases. Moreover, the in-situ stress difference can counteract the effect of stress interference on the fracture deviation and reduce the extent of deviation. Compared with the other two fracturing techniques, MZF generates larger maximum induced stress, but less change of the principal stress direction, which ensures a desired propagation path. Therefore, the optimal fracture spacing of MZF is smaller than that of sequential fracturing and alternate fracturing. Under the same stress difference and fracture spacing, MZF generally achieves better formation fracturing effects. The results obtained in this paper are of benefit to guide the high-efficient practices of hydraulic fracturing in horizontal wells.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Yogesh B. Singh, Kim C. Ng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Scale deposition in the thermal process for desalination is quite inevitable. This study is about scale formation, crystal modification, and prevention mechanism of a tetrapolymer based antiscalant on Red Seawater. Red seawater at concentration factors (CF) of 1.5 and 2.5 was studied under reflux condition at 70 °C and 98 °C respectively for seven hours with 1 ppm, 2 ppm, and 4 ppm concentration of the antiscalant. Eventually, the mechanism of inhibitory action of the antiscalant has been reconnoitered after seawater analysis and imaging the morphological changes in the crystal formation patterns with Scanning electron microscope (SEM). The changes in the values of pH, turbidity and alkalinity (both phenolphthalein alkalinity (PA) and total alkalinity (TA)) were measured to apprehend various fluctuations happening as a result of the addition of antiscalant. The variations in the pH of seawater with antiscalant were in concurrence with the changes in alkalinity and was also reflected in turbidity. These changes explicitly demonstrated the threshold mechanism of scale inhibition. SEM micrographs exhibited distorted round shaped depositions supporting crystal modification mechanism as well. The efficiency and dominance of inhibitory mechanism varied from 2 h to 6 h for the antiscalant and was observed to be directly related to CF of seawater used, the temperature applied, and a dose of antiscalant added.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519308010-fx1.jpg" width="409" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Yang Su, Ming Zha, Xiujian Ding, Jiangxiu Qu, Changhai Gao, Jiehua Jin, Stefan Iglauer〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The Lucaogou Formation contains significant amount of shale oil and tight oil resources in China, and the target strata studied here is located in the Jimsar Sag, Junggar Basin. A combination of mudstone, silty mudstone, dolomite mudstone and limy mudstone from this formation was investigated for the organic petrology and organic geochemistry and thus organic matter origin, thermal maturity and depositional condition were evaluated. Source rocks indicate good potential in hydrocarbon generation, which were featured by high TOC, S〈sub〉2〈/sub〉 and HI. T〈sub〉max〈/sub〉 and biomarker ratios reveal that source rocks are mature and have enter oil generation window. Microscopical analyses reveal that liptinitic organic matter are dominant components, especially the amorphous components, which are commonly accompanied with advanced plant fragments. Organic matter assemblages indicate organic materials originated from aquatic organisms and terrestrial plants, which is evidenced from the discrimination diagrams of Pr/nC〈sub〉17〈/sub〉-Ph/nC〈sub〉18〈/sub〉 and C〈sub〉27〈/sub〉–C〈sub〉29〈/sub〉 regular steranes. Vertical variations in the abundance of organic matter from the bottom up reflect the changes of the depositional conditions, which are consistent with the indications of organic geochemical parameters. In the lower Lucaogou (LLF), the depositional conditions varied from the relatively shallow water, moderate-energy, proximal suboxic/dysoxic-anoxic condition to the deeper, low-energy, distal suboxic-anoxic condition, as endorsed by the enhanced OM degradation and the preservation of palynomorphs. In the upper Lucaogou (ULF), the conditions changed gradually from a brackish, stratified, suboxic-anoxic condition to fresh, aerobic condition, followed by a stratified oxygen-depleted setting with a relatively higher saline upwards, as supported by the variation in the organic components. Overall, the conditions of LLF are more reducing than that of ULF, which is demonstrated by Pr/Ph ratios, gammacerane index and ETR. The understanding of the redox conditions and their evolution of the Lucaogou Formation is crucial to expound the formation of source rocks and evaluate the hydrocarbon-generating potential.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Luís Felipe F.M. Barbosa, Andreas Nascimento, Mauro Hugo Mathias, João Andrade de Carvalho〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Drilling wells in challenging oil/gas environments implies in large capital expenditure on wellbore's construction. In order to optimize the drilling related operation, real-time decisions making have been put in place, so that prediction of rate of penetration (ROP) with accuracy is essential. Despite many efforts (theoretical and experimental) throughout the years, modeling the ROP as a mathematical function of some key variables is not so trivial, due to the highly non-linearity behavior experienced. Therefore, several researches in the recent years have been proposing to use data-driven models from artificial intelligence field for ROP prediction and optimization.〈/p〉 〈p〉This paper presents an extensive review of the literature on ROP prediction, especially, with machine learning techniques, as well as how these models can be used to optimize the drilling activities. The ROP models are classified as traditional models (based on physics-models), statistical models (e.g. multiple regression), or machine learning methods. This review enables to see that machine learning techniques can potentially outperform in terms of ROP-prediction accuracy on top of traditional or statistical models. Throughout this work, an extensive analysis of different ways of obtaining ROP models is carried out, concluding with different strategies adopted in literature to perform data-driven model optimization.〈/p〉 〈p〉Despite the saving potential which can be achieved with real-time optimization based on data-driven ROP models, it is noticeable that there is a lack of implementation of those techniques in the industry, as per literature review. To take a step forward in real implementations, the petroleum industry must be aware that yet no rule of thumb already exists on this specific area, but still, good and very reasonable results can be achieved by following the best practices identified in this review. In addition, the modern practices of machine learning provide promising guidelines for implementing projects in oil and gas industry.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Arjun Janamatti, Yingda Lu, Sriram Ravichandran, Cem Sarica, Nagu Daraboina〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Operating temperatures have major impacts on wax deposition. Although significant research efforts have been expended on this topic, no satisfactory agreement has been achieved in the available literature. In the present work, we conducted cold-flow flow-loop wax deposition experiments using a waxy condensate with 9.5% wax content to investigate the influence of operating temperatures on wax deposition. To achieve a closer representation of field operation, we varied the oil temperature while keeping the initial wall temperature constant and conducted the tests up to 72 h. It was observed that the deposit forms more slowly but contains higher wax content as the difference between oil temperature and wall temperature increases, and these trends hold at both 48 and 72 h. Moreover, we calculated the diffusive mass flux at different operating conditions using the prevailing theory of molecular diffusion and found that the predicted trends are opposite to experimental observations. These results, along with findings from recent publications, collectively suggest that the long-standing modeling approach based on molecular diffusion is insufficient to completely describe wax deposition phenomenon, and that wax deposit morphology and other deposition mechanisms deserve further attention to close this knowledge gap.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: December 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 183〈/p〉 〈p〉Author(s): Xin Li, Xuehai Fu, Jijun Tian, Weiming Guan, Xueliang Liu, Yanyan Ge, P.G. Ranjith, Wenfeng Wang, Meng Wang, Shun Liang〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉High volatile bituminous coal (HVBC) reservoirs are now regarded as one of the most important targets for coalbed methane (CBM) exploration and development in northwestern China. Water invasion during coalbed methane reservoir fracturing can induce water blockage damage, leading to decreased relative permeability of gas and reduced production of CBM well. To study the influences of heterogeneities of seepage pore and fracture on water invasion degree (WID), water flooding experiment using HVBC core was conducted to simulate water invasion; magnetic resonance imaging and gray calculation were applied to quantitatively determine WID; heterogeneous parameters of seepage pore and fracture were extracted based on micro-CT and fractal characterization; finally implications of seepage pore and fracture heterogeneities on WID were discussed, and water invasion mechanism was analyzed.〈/p〉 〈p〉The results show that fracture porosity, connected fracture porosity, minerals’ filling porosity, displacement pressure, efficiency of mercury withdrawal, and fractal dimension as well as tortuosity of seepage pore, are closely correlated with WID. As fracture porosity increases, WID initially increases then tends to be unchanged. Minerals’ filling can be dominated factor resisting water invasion when severe filling occurs. Seepage pores with good connection and permeability are beneficial for water invasion, while those with complex structure and tortuosity are detrimental to water invasion. Reservoirs developing connected fractures and homogeneous seepage pores are not only beneficial for water invasion, but also beneficial for water elimination. Reservoirs developing unconnected fractures and homogeneous seepage pores are beneficial for water invasion while detrimental to water elimination. Reservoirs lacking fractures’ development but developing complex structural seepage pores are detrimental to both water invasion and elimination.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Milinkumar T. Shah, Harisinh B. Parmar, Lee D. Rhyne, Chris Kalli, Ranjeet P. Utikar, Vishnu K. Pareek〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Removal of solids is a critical step in the treatment of produced water generated by offshore hydrocarbon exploration. Present work evaluates a new design of a settling tank that can be used for continuous separation of fine particles from produced water. The novelty of the design lies in its ability generate swirling flow that promotes the settling of fine particles. The tank was investigated by conducting CFD simulations and experiments. The CFD model was initially validated using the experimental data measured in a lab-scale replica of the tank by using particle image velocimetry (PIV) technique. The validated model was then used to investigate flow patterns and settling behavior of different sized particles at varying operating flow rates and with different inlet-outlet configurations. Simulations revealed that the angled entry of water in to the bulk of the tank caused rotational flow that transported the suspended particles towards wall, where downward axial velocity resulted in the settling of particles. The flow patterns showed inward flow at the bottom, which caused the accumulation of settled particles near the center hatch. The flow patterns also indicated an upward flow and the lifting of the settled particles near the hatch at the bottom. The impact of the lifting of particles was mitigated by adjusting the size of inlet openings and operating flowrate. For inlet openings of 40 × 20 cm〈sup〉2〈/sup〉, simulations predicted capture of more than 80% of particles having a size range of 30–1000 μm at 30000 barrels per day operating flow rate. The settling tank has no moving element, rotating part or filtering medium; and its settling ability is solely governed by the induced hydrodynamics. Due to its simplicity and high efficiency, the settling tank could be used in continuous operation with high operating flowrate, and for both onshore and offshore operations.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519307739-fx1.jpg" width="415" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: Available online 20 August 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering〈/p〉 〈p〉Author(s): Alexander Anya〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Thirty-five cement samples were tested in an Ultrasonic Cement Analyzer (UCA) at varying curing conditions and for varying curing times, and then uniaxially compressed to failure in a hydraulic press. An attempt was made, using the ultrasonic transit time data measured with a UCA and the uniaxial compressive strength data measured using a hydraulic press, to derive an empirical model capable of accurately predicting uniaxial compressive strength from the ultrasonic transit time. Using the Levenberg-Marquardt algorithm, the experimental data was fit to two models. In addition to the transit time dependence, the first model presented incorporates a term that accounts for the curing time while the second model contains terms that account for both the curing time and cement composition. The results obtained illustrate the complexity of deriving a correlation with general applicability to all well cements. The best performing model based on both curve fit error and prediction performance for the samples tested was the model that accounted only for the curing time dependency of the cement strength development rate in addition to the measured transit time, indicating that the transit time measurement history is sufficient as a tool for characterizing well cement strength development.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Denis Orlov, Dmitry Koroteev〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉One of the most significant issues of petroleum engineering nowadays is a decline in productivity and injectivity of wells due to formation damage, which is typically associated with the migration and retention of fines. The prediction of formation damage is a challenging problem due to the lack of information about concentrations and localizations of potential mobile fines in the reservoir. To solve this problem different algorithms of machine learning and data mining were tested: linear regressions, decision trees, random forest, gradient boosting and artificial neural networks. We developed the predictive model of permeability reduction in Vendian deposits (Russia) based on the analysis of rock properties and flooding conditions. This model allowed to describe the dynamic of permeability reduction as a multi-parametric function of injected pore volumes of water. Three defining parameters in the model were unique colmatation characteristics which have been predicted for each core sample. All the features of the self-colmatation process were studied and arranged by their importance. To build the model of permeability reduction we used two approaches. The first one was to discover all possible 2D cross-plot correlations between colmatation characteristics and features (manual analysis). The second is applying machine learning algorithms where all features were taken into account simultaneously. The benefits and disadvantages of both approaches were discussed in details.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519307272-fx1.jpg" width="272" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Eric M. Takam Takougang, Mohammed Y. Ali, Youcef Bouzidi, Fateh Bouchaala, Akmal A. Sultan, Aala I. Mohamed〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Jintong Liang, Hongliang Wang, Mike J. Blum, Xinyuan Ji〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Demarcation and correlation of stratigraphic sequences are particularly significant in hydrocarbon exploration, in which signatures of well logs are commonly used in conventional interpretation methods. In this study, an intelligent and effective way of sequence stratigraphic analysis is proposed through combining the continuous wavelet transform (CWT), the discrete wavelet transform (DWT), and the Hilbert-Huang transform (HHT) together. By using MATLAB software, these mathematical methods (CWT, DWT, and HHT) are applied on GR logs to interpret sequence surfaces and cycles in the Agbada Formation, Niger Delta Basin. Within the context of base-level and A/S variation, the studied interval is interpreted as a long-term (3rd-order) base-level stratigraphic cycle and three middle-term base-level (4th-order) stratigraphic cycles regarding individual well and cross-section. The comparative results indicate that the CWT and DWT, compared with the HHT, have better resolution in identifying base-level cycles and their periodicity. By contrast, the HHT is more suitable to interpret specific positions of sequence surfaces. Generally, together with conventional interpretation methods, the exploratory methods of this study provide a relatively objective and acceptable way in high-resolution (4th-order or lower rank) sequence stratigraphic analysis at scales of hundreds of meters. Besides, a source to sink depositional model is presented as an example to illustrate multiple well log (GR) interpretations. The idea of this study aims to be extended to more studies to reduce subjective uncertainties in model-driven interpretations.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Shibin Wang, Fuhu Chen, Jianchun Guo, Yang Li, Feng Zhao, SiYan Zhou〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Hydroxypropyl guar gum (HPG) is widely used in the hydraulic fracturing of sand rock gas reservoirs. The HPG residue can severely damage the rock surface of the reservoirs owing to the interaction between the HPG molecular chain and the rock surface, which results in adsorption and retention of HPG. To confirm the interaction between HPG and rock, the adsorption properties of HPG on a rock surface were investigated. The dependence of HPG adsorption on HPG concentration, pH, and temperature is discussed, and the adsorption force between HPG and quartz is also studied. With an increase in HPG concentration and pH, the amount of adsorbed HPG increases. The amount of adsorption increases first with temperature and then decreaseds. According to infrared spectroscopy and Zeta potential results, there is a weak chemical bond between HPG and quartz particles. Hydrogen bonding is the main force, which results in the adsorption and retention of HPG in porous media.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): A. Shabib-Asl, T. Plaksina〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Petroleum production from unconventional resources (specifically, tight and shale reservoirs) has become a significant portion of the supply in North America which led operating companies to look for more accurate methods for reserve evaluation and production forecasting. Typically, the operators resort to Decline Curve Analysis (DCA) to determine the Estimated Ultimate Recovery (EUR) of hydrocarbon reserves in both conventional and unconventional reservoirs. In shale wells, the best DCA model fitted to the transient flow regimes followed by Boundary Dominated Flow (BDF). Therefore, in this study, we propose a novel framework for systematic DCA model selection using a quantitative measure of goodness of production data fit from shale wells. For this purpose, we selected seven different, most frequently applied DCA models to evaluate large number of wells from the Montney Formation. To collect production data from the Montney wells, we used the GeoSCOUT package. Then, we fed these data into the DCA model selection workflow powered by the Nelder-Mead simplex algorithm and implemented using a computer programming language. The quantitative measure that helps identify the best fit of the data and the model is derived from the Information Theory (IT) and is known as Akaike Information Criterion (AIC). The obtained results show that our DCA model selection framework can identify the most appropriate DCA model for a given production history. Moreover, it gives a specific quantitative measure (AIC) of the fit that can be used for model ranking. The results show that more accurate values of b are necessary in Arps’ DCA models to match production data from the Montney shale wells, and identify the Logistic Growth Analysis Model (LGM) is the best fit for the majority of the selected wells followed by Extended Exponential Decline Model (EED), Duong, and Power Law Exponential Model (PLE).〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S092041051930748X-fx1.jpg" width="245" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Huihuang Fang, Shuxun Sang, Shiqi Liu, Yi Du〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Analysis of the three-dimensional (3D) visualization and reconstruction methods of nanopores, and its morphology and connectivity are the key to explore the storage and migration mechanism of coalbed methane (CBM). The Bofang (BF) sample collected from the Qinshui basin was scanned by the focused ion beam scanning electron microscopy (FIB-SEM), which can simultaneously image the nanopores through 2D slice image and 3D reconstruction image. Firstly, the 2D morphology and development characteristics of nanopores were analyzed. Secondly, the 3D visualization and reconstruction of nanopores were carried out. Then, the pore connectivity, permeability, and geometric characteristics were discussed. Finally, the effect of pore structure on the storage and migration of CBM was emphatically analyzed. The results show that the organic pores, inorganic pores, shrinkage-induced pores and micro-fractures were developed in coal, and their morphology and connectivity were significant differences. The pores and throats can be extracted from the digital cores with sub-volume of 4.9 × 4.9 × 4.5 μm〈sup〉3〈/sup〉, the pore number and throat length (avg.) of BF sample are 21951 and 18.2789 nm, respectively, the porosity and permeability of BF sample is 2.004% and 4.405 × 10〈sup〉−3〈/sup〉 mD, respectively, which all indicates the BF reservoir has good storage and connectivity capacity. For pores 〈50 nm, the number, volume and area indicate that the BF sample has good storage capacity. For pores 〉200 nm, the pores are all interconnected, which indicates the BF sample can provide effective channels for CBM migration. The distribution of pores and throats and their geometric and topological structures indicate that the BF sample has good migration ability. This study on the methodology of 3D visualization and quantitative characterization of nanopores using FIB-SEM can broaden the research method of pores, and lay good foundations for studying the storage and migration of CBM.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Xiao Wang, Sheng He, Stuart J. Jones, Rui Yang, Ajuan Wei, Changhai Liu, Qiang Liu, Chunyang Cheng, Weimin Liu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Bohai Bay Basin is a Meso-Cenozoic terrestrial sedimentary basin in eastern China. Its offshore regions, including Bozhong and Liaodongwan Depressions, are favourable exploration targets which provide near a half of the petroleum reserves in the basin. Eocene Shahejie (Es) Formation and Oligocene Dongying (Ed) Formations are two important exploration targets in Bozhong Depression, and overpressure is commonly seen in Es and Ed Formations in this area. Our research examined the distribution characteristics of overpressure in the formations and suggest the main mechanism of overpressure is compaction disequilibrium due to the rapid sedimentation rates (~500 m/Ma) of fine-grained sediments in this area. Also, oil and gas generation within the thick mudstones of the two formations has added the magnitude of overpressure. We investigated the reservoir quality especially primary porosity in Es and Ed formations, and their relationship with overpressure. The positive effect of overpressure on reservoir porosity preservation was validated through microscopic observations and vertical effective stress (VES) analysis. We established a quantitative model for evaluating the relationship of overpressure, pore structures, porosity, and VES. The result suggests the overpressure in the targeted formations were primarily originated from undercompaction. The overpressure kept VES from increasing and helped preserve the primary intergranular porosity. The porosity preserved by overpressure can be significantly higher than normally compacted porosity under the same condition of depth and temperature.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Zhu Xiaomin, Liu Qianghu, Ge Jiawang, Dong Yanlei, Zhu Shifa, Tan Mingxuan, Yang Yong〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Reconstruction of sediment-dispersal patterns not only provides insight into paleogeographic evolution, but also sheds light on facies and reservoir prediction. By integrating core, wireline logs, and 3D seismic data, seismic sedimentologists have discovered several advantages to sediment-dispersal reconstruction and paleogeographic-environment analysis. We have subdivided the third member of the Shahejie Formation (Es3) of the southeastern Zhanhua Sag (Sanhecun Block) into three third-order sequences, namely SQ1, SQ2, and SQ3 from bottom to top. The facies architecture was analyzed by using the seismic sedimentology approach based on 3-D seismic data. Seismic RMS-amplitude stratal slices reveal different characteristics of the lobes among the southwest gentle slope, southern slope-break belt and north fault-controlled slope from source to sink. On the basis of an integrated analysis of well log, core data, seismic facies based on RMS attributes, three depositional environments (e.g., “fan-delta”, “turbidite” and “lacustrine” facies) have been recognized. Seismic RMS-amplitude stratal slices indicate that the depositional environments of these sequences evolved from medium-sized gravel-rich fan-delta and turbidite-fan deposits to small-scale mud-rich fan-delta deposits, and lastly to large-scale sand-rich fan-delta deposits. The changes of relative lake level and sediment supply rate control the lithology and size of different depositional systems. This study also suggests that the temporal and spatial evolution and distribution of depositional systems are influenced significantly by paleotopography and slope break in the systems tracts of different sequences of the Es3 in the southeast Zhanhua Sag, Bohai Bay Basin. In addition, fan-delta-front deposits could also be considered as future potential exploration targets because they are relatively sand- or gravel-rich, given the reconstruction of the sediment-dispersal pattern.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Olusiji Ayoade Adeyanju, Layioye Ola Oyekunle〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Experiments were performed to simulate the deposition of wax in the flow of crude oil emulsions in subsea pipeline using a validated flow facility. Two crude samples and their respective formation water from two oil fields in southern Nigeria were used to synthetize two different emulsified crude oil samples (A and B). The trapping of the water globules in the wax deposits dominates the wax deposition rate initially but later the shear removal and the molecular diffusion dominate leading to decrease in the wax deposition rate. As the water (BS&W) composition in the emulsion increases from 10 to 40%, the pour point temperature (PPT) increases from 30 to 41 °C, and the viscosity increases from 40 mPas to 142 mPa at a crude oil temperature of 26 °C. The addition of 45 ppm of long chain acrylate ester co-polymer as pour point depressant depressed the dimensionless wax thickness by 37.5% and 34.3% for the blank emulsified crude oil A and B respectively. The effect of the commercial demulsifier to reduce the wax deposition rate was more successful in crude oil A reducing the wax dimensionless thickness by 58.9% and 43.0% when mixture of 25 ppm of the demulsifier and 45 ppm of long chain acrylate ester co-polymer were added to blank emulsified crude oil A and B respectively. The used demulsifier is more effective in crude oil A compared to crude oil B. Efforts should be made to study the effectiveness of different demulsifiers on each emulsified crude oil before their application for water separation.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): P. Sharma, M. Salman, Z. Reza, C.S. Kabir〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉This paper explores the relationship between the natural form of pressure buildup/falloff response to Arps hyperbolic formula in conventional reservoir systems. The primary motivation stems from the fact that semianalytical proof exists for obtaining average-reservoir pressure from either pressure buildup or falloff response with the rectangular hyperbola method (RHM), whereas the Arps hyperbolic relation is anchored in empiricism. Despite its origin, the hyperbolic relationship has served the industry very well in performance predictions under diverse reservoir-drive mechanisms since its inception in 1945. Most reserves estimation in conventional reservoirs is anchored in Arps decline-curve analysis (DCA) to meet regulatory guidelines.〈/p〉 〈p〉We show that the Arps hyperbolic parameters 〈em〉b〈/em〉 and 〈em〉D〈/em〉 can be estimated from the RHM, thereby giving credence to its basis. Note that the RH method is a semianalytical proof of pressure-buildup/falloff relation. We also show that Arps hyperbolic parameter 〈em〉b〈/em〉 is tied to the energy support available for production and can be estimated using a type curve instead of the parameter-regression approach. Besides, we point out that well shut-in periods need to be collapsed to obtain valid 〈em〉b〈/em〉 and 〈em〉D〈/em〉 parameters; otherwise, optimistic 〈em〉b〈/em〉 values are estimated, leading to performance overprediction. Synthetic examples verified the approach presented here, and several field examples with diverse 〈em〉b〈/em〉-factors validated the overall methodology as espoused here.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Hakan Alkan, Martina Szabries, Nicole Dopffel, Felix Koegler, Roelf-Peter Baumann, Ante Borovina, Mohd Amro〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉This paper explores the potential of spontaneous imbibition (SI) induced by wettability alteration to improve incremental oil recovery during microbial enhanced oil recovery (MEOR). A laboratory work is presented that consists of SI and contact angle (CA) tests on reservoir and outcrop sandstone cores. The SI and CA measurements were conducted with aqueous phases with/without MEOR to assess the incremental recovery mechanism triggered by the wettability alteration during MEOR. It was observed that the oil recovery in the SI experiments with the MEOR nutrient solution reached a plateau at 0.62 ± 0.05% of original oil in place (OOIP) while it was 0.32 ± 0.02% of OOIP with the non-MEOR reference SI experiment conducted in outcrop sandstone cores. The CA of the oil droplet measured on polished reservoir rock sample decreased from 120° to 60° when exposed to the MEOR nutrient solutions. The observed changes occurred in parallel to the growth process of the bacteria in both SI and CA tests.〈/p〉 〈p〉The experimental data shows that the wettability alteration needs cell growth because SI experiments performed only with metabolites and without microbial cells exhibited negligible incremental recovery. Numerical models calibrated with SI experiments demonstrated the wettability alteration as one of the potential MEOR mechanisms. The bacterial network that forms a biofilm at the oil-water interface, and hence, creates a viscoelastic layer is thought to be the main cause of wettability alteration, which is supported by the oscillating pendant drop measurements.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Zikang Xiao, Wenlong Ding, Shiyan Hao, Arash Dahi Taleghani, Xinyu Wang, Xuehui Zhou, Yaxiong Sun, Jingshou Liu, Yang Gu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Of the characteristics of tight sandstone reservoirs, heterogeneity is one of the most difficult characteristics to analyze. Heterogeneity is mainly manifested in three properties: lithology, porosity and electricity. The Chang 7 reservoir in the Dingbian oilfield is a tight sandstone reservoir controlled by delta front deposits. In this sedimentary environment, the underwater distributary channel oscillates frequently, resulting in considerable heterogeneity of the Chang 7 formation in the study area. The rescaled range method can calculate the fractal dimension 〈em〉D〈/em〉 of logging curves, thus quantitatively characterizing reservoir heterogeneity. After analyzing the relationship between average wave number and IMF number by EMD method, the reservoir heterogeneity can be quantitatively characterized by 〈em〉ρ〈/em〉 value. By comparing 〈em〉D〈/em〉 value, 〈em〉ρ〈/em〉 value and 〈em〉F〈/em〉 value of different heterogeneous types, it is found that F value can distinguish different heterogeneous types. The order of 〈em〉F〈/em〉 value also satisfies the actual situation of formation heterogeneity. The new heterogeneity coefficient is used to study the heterogeneity of Chang 7 reservoir, it is found that the relationship between the lithological heterogeneity represented by the natural gamma (GR) log and oil production is a quadratic function that initially increases and then decreases, that the relationship between the pore heterogeneity represented by the interval transit time (AC) log and oil production is linear, and that the relationship between the reservoir electrical heterogeneity represented by the deep induction log (LLD) and oil production is linear too.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Jian Wang, Yingchang Cao, Keyu Liu, Yang Gao, Zhijun Qin〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The tight reservoir property and oil accumulation are greatly affected by the complexity and heterogeneity of pore structure. Fine-grained, mixed sedimentary formation samples from the Permian Lucaogou Formation in the Jimsar Sag were systematically studied focusing on their fractal characteristics and effects on the storage space, minerals and diagenesis, and its implication for tight oil accumulation. Fractal dimensions were calculated by the MICP model equation. The lacustrine fine-grained, mixed sedimentary samples are characterized by single and multi-fractal structures. Compared with the multi-fractal reservoir, the pore-throat structure of single fractal reservoir is more uniform and the pore throat size is relatively smaller. Minerals and diagenesis have apparent influences on fractal characteristics of the lacustrine MSR tight oil reservoir. The enrichment of terrestrial minerals can increase the heterogeneity of storage space and might be the reason for the multi-fractal pore structures. The enrichment of tuff in mixed sedimentary rock (MSR) can greatly improve the property and reduce the fractal dimension of tight reservoirs through dissolution. Large-pore filling calcite has dual effects on destroying reservoir space and reducing heterogeneity, which makes the weak correlation between calcite and fractal dimension. Fractal characteristics implicate that pore structures play a very significant role in controlling the accumulation of tight oil. MSRs with 〈em〉D〈/em〉 or 〈em〉D〈/em〉〈sub〉e〈/sub〉 more than 2.586 and porosity (average pore-throat radius) less than 6.3% (0.05 μm) are mostly incapable of effectively accumulating oil.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Afeez O. Gbadamosi, Radzuan Junin, Muhammad A. Manan, Augustine Agi, Jeffrey O. Oseh, Jamilu Usman〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO〈sub〉2〈/sub〉) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF were compared to the widely reported SiO〈sub〉2〈/sub〉 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 NP which gives rise to the highest viscosity on the rheological characterization. Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Zhengjian Xu, Luofu Liu, Shu Jiang, Tieguan Wang, Kangjun Wu, Yanjun Feng, Fei Xiao, Yingying Chen, Yiting Chen, Chenyang Feng〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step- or “Z”-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J〈sub〉1〈/sub〉b, K〈sub〉1〈/sub〉q, N〈sub〉1〈/sub〉s〈sub〉1〈/sub〉, and N〈sub〉1〈/sub〉s〈sub〉2〈/sub〉 have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J〈sub〉1〈/sub〉b, K〈sub〉1〈/sub〉q, and N〈sub〉1〈/sub〉s, respectively.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Xiaoxu Ren, Jiagen Hou, Suihong Song, Yuming Liu, Depo Chen, Xixin Wang, Luxing Dou〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Effective identification of lithology using well logs is one of the most important steps for reservoir characterization. A lot of methods have been developed to identify lithology automatically by analyzing the value or patterns of well logs. However, the response characteristics of log curves for some different lithologies are similar and indistinguishable. As a result, we may obtain results which do not follow the general geologic rules if we only use values or patterns of well logs as the criteria to identify lithology. In this paper, we propose an alternative automatic method to identify lithology by integrating both well logs and sedimentary patterns. First, we obtain the probability of lithology by applying the artificial neural networks (ANN) to the well logs. Then, we obtain the vertical combination patterns of different lithologies by applying a probabilistic statistical method to the cores. Finally, we produce an integrated lithology probability by combining the lithology probabilities calculated using ANN and lithology probabilities computed using sedimentary pattern. We validated our method by applying it to a real case study from China. The results indicate that the accuracy of lithology identification using the proposed method is much higher (91%) than that using neural networks method (83%).〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Shuaibing Song〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Based on the morphological information obtained from 2D slice images of real porous media, an improved simulated annealing algorithm (SAA) was proposed to reconstruct 3D large-scale porous media, which are intractable to handle for conventional SAA. Three different statistical functions were introduced to characterize the morphological information of real sandstone, including the one-point probability function, the two-point probability function and the lineal-path function. By changing the update method of the two-point probability function and the lineal-path function, i.e., using incremental calculation instead of conventional global calculation, the efficiency of reconstructing 3D large-scale porous media was greatly improved. Besides, in the later stage of reconstruction that the basic structure of porous media had been formed, the pixel selection algorithm was performed to speed up the reconstruction process. To evaluate the accuracy of the improved SAA, the similarity between the 3D reconstructed volume and the reference image of prototype sandstone was examined. The results showed good agreement between the reconstructed model and the references. The efficiency of the improved SAA was verified by comparison with the conventional SAA, the results of which indicated that the improved SAA can significantly shorten the reconstruction time of 3D large-scale porous media.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): H. Ali Marefat, Muhammad A. Ashjari Aghdam, Knut-Andreas Lie〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Within reservoir management, there is a growing demand for highly accurate and fast reservoir simulators. So-called multiscale methods are designed to preserve fine-scale information accurately in an accelerated coarse-scale computation of fluid flow. In many cases, this requires that coarse partitions are meticulously adapted to prominent geological features that determine flow paths. Partitions that seek to preserve the vorticity from a representative fine-scale flow simulation can be particularly effective to this end. We describe how to incorporate such partitions in the state-of-the-art multiscale restriction-smoothed basis (MsRSB) method, and present a series of two-phase test cases to validate and demonstrate the effectiveness of the resulting method. Our results show that using a nonuniform vorticity-based partition improves the accuracy of the MsRSB solver compared with uniform partitions and nonuniform partitions with a similar number of coarse blocks that adapt to permeability or velocity.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Akshaya Kumar Mishra, Ashutosh Kumar〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Guo et al. (2001) equation of state based viscosity model is simple and is able to predict viscosity for lower carbon n-alkane components reliably. However, it loses its reliability when extended to higher carbon number hydrocarbon components. In this work, Guo et al. viscosity model has been modified to improve its predictive capability and its application to heavier components. First modification has been done to improve component level viscosity prediction and then binary interaction parameters have been developed to improve viscosity prediction for hydrocarbon mixtures.〈/p〉 〈p〉New set of correlations for parameters in Guo et al. (2001) model for each of three main hydrocarbon groups paraffins, naphthenes, and aromatics, have been developed as function of carbon number of the components. Correlation for binary interaction parameters has also been developed for paraffinic hydrocarbon components.〈/p〉 〈p〉Four thousand viscosity data points for n-alkanes, 850 points for naphthenes, and 608 points for aromatics have been used to modify correlations for improving the reliability of Guo et al. model. The modified Guo et al. viscosity model has AARDs of 8.3%, 6.89%, and 9.09% in viscosity prediction as compared to 33.95%, 19.6%, and 48.9% from Guo et al. model for paraffinic, naphthenic, and aromatic groups of hydrocarbons respectively. The AARD in viscosity prediction for liquid hydrocarbon mixtures from modified Guo et al. with optimized binary interaction parameter is 3.95% whereas that from Guo et al. model with default binary interaction parameter is 24.6%. The modified Guo et al. model has significantly better predictive capability for pure components and their mixtures. It has potential for use in viscosity model for crude oils in wider specific gravity range.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Ning Ye, Shaonan Zhang, Hairuo Qing, Yingtao Li, Qingyu Huang, Di Liu〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The deeply buried dolostones (〉6000 m) of the Lower Ordovician Penglaiba Formation are currently the key targets of hydrocarbon exploration in the Tarim Basin. Petrographic, isotopic, and fluid inclusion microthermometric data were obtained in an attempt to determine the origin of dolostones and its effect on porosity development. Based on the petrography examination, three matrix dolomites and two dolomite cements were identified: very finely to finely crystalline, nonplanar-a to planar-s (D1) dolomite; finely to medium crystalline, planar-s to planar-e (D2) dolomite; medium to coarse crystalline, nonplanar-a (D3) dolomite; medium to coarse crystalline dolomite cements (Cd and Sd). D1 dolomite, which commonly occurs widely distributed throughout the study area, is characterized with δ〈sup〉13〈/sup〉C〈sub〉VPDB〈/sub〉 values of −2.4 to −0.1‰, δ〈sup〉18〈/sup〉O〈sub〉VPDB〈/sub〉 values of −8.1 to −4.1‰, and 〈sup〉87〈/sup〉Sr/〈sup〉86〈/sup〉Sr ratios of 0.70899–0.70979, inferring the seawater origin. D2 dolomite, merely confined to one side of the stylolite, has δ〈sup〉13〈/sup〉C〈sub〉VPDB〈/sub〉 values of −1.8 to −0.4‰, δ〈sup〉18〈/sup〉O〈sub〉VPDB〈/sub〉 values of −8.3 to −3.7‰, and 〈sup〉87〈/sup〉Sr/〈sup〉86〈/sup〉Sr ratios of 0.70871–0.70955, suggesting that D2 is precipitated in shallow-middle burial conditions and the dolomitizing fluids is derived from the residual primitive seawater in the formation. D3 dolomite is considered to be formed at higher temperatures under deep burial conditions considering its crystal textures and the δ〈sup〉18〈/sup〉O〈sub〉VPDB〈/sub〉 values of −9.0 to −6.8‰. The two dolomite cements, Cd and Sd dolomites, are characterized with the inclusion T〈sub〉h〈/sub〉 values of 119–163 °C and 〈sup〉87〈/sup〉Sr/〈sup〉86〈/sup〉Sr ratios of 0.70941–0.70993, inferring the hydrothermal origin. Based on the distribution, petrography and geochemistry data of D1, the mainly hydrological system for dolomitization in the Penglaiba Formation is interpreted to be the seepage-reflux model. Intercrystalline pores and vugs are two types of pores associated with dolomitization, the latter being the most dominant type that is related to hydrothermal dolomitization.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Abhay Patil, Shyam Sundar, Adolfo Delgado, Jose Gamboa〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Fluctuations in oil prices have negatively affected the petroleum industry, prompting to look for innovative ways to optimize oil recovery. One of the current approaches to optimize oil production is to employ high-speed ESPs with Permanent Magnet Motors (PMM) that allow reducing the pump size while increasing the operating envelop. Standard affinity laws are a useful tool to provide a preliminary estimate of common pump performance. However, there is a need to understand the detailed variation in the flow variables and losses incurring due to fluid-geometry interactions at high rotational speeds. To evaluate the hydraulic performance of a mixed flow pump, Computational Fluid Dynamics (CFD) simulations were performed at rotational speeds ranging from 3600 rpm to 20000 rpm using fluids with different viscosities. Fluid behavior is studied by observing the change in flow parameters with rotational speed. Similitude analysis is utilized to characterize the pump performance. The numerical results yielded improved pump hydraulic performance with an increase in rotational speeds which is attributed to reduced separation losses mainly in the diffuser section. Research is concluded with further evaluation of the complete stage including secondary leakage flow path on flow variables and axial thrust forces.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Gabor Takacs〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉This paper presents a review of the three most significant inventions that will enable future ESP installations to be more efficient and use less power while handling extreme well conditions better than today's systems. It will be shown how these revolutionary ideas will expand the application ranges of future ESP systems and why they soon become part of the daily routine.〈/p〉 〈p〉The novel method of making pump stages using powder metallurgy techniques, instead of the universally used sand molded casting, allows producing pump stages with more complex geometries, improved tolerances, and surface finishes. Such stages provide higher pump efficiencies and are dynamically more balanced as well.〈/p〉 〈p〉The conventional ESP motor is a 3-Phase AC induction motor; the permanent magnet motor introduced recently provides 3–4 times greater power in a shorter constructional length. With motor efficiencies above 90% and extremely high power factors, PMMs develop much lower heat. If driving ESP pumps, the required number of pump stages is much reduced and the use of as smaller downhole cables is possible. Therefore, PMMs will surely be the future prime movers for ESP installations providing greater system efficiencies than the AC motors currently used.〈/p〉 〈p〉The recently patented V-Pump can replace the ESP centrifugal pump; it is a helico-axial pump whose rotor and stator are fitted with an extremely big gap. The produced fluid spirals upward in the rotor channels while a fluid seal is created in the radial gap between the rotor and stator. Pump efficiency is not affected by the size of the gap and the pump can easily handle the most detrimental conditions for conventional ESP pumps: high fluid viscosities, extremely high solid concentrations, and high gas-liquid ratios. Having these desirable features, it can be predicted that usage of the V-Pump will become more and more popular in the future.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Rasoul Mokhtari, Shahab Ayatollahi, Mobeen Fatemi〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉This study aims to investigate the role of fluid-fluid interactions during low salinity water flooding, using crude oil from an Iranian oil reservoir. To minimize the effects of mineral heterogeneity and wettability alteration, a synthetic sintered glass core was utilized and all coreflooding experiments were performed at low temperatures without any aging process. The effect of fluid-fluid interactions were investigated in both secondary and tertiary injection modes. pH measurements as well as UV-Vis spectroscopy and interfacial tension (IFT) analysis were performed on the effluent brine samples.〈/p〉〈/div〉 〈div〉 〈h6〉Results〈/h6〉 〈p〉show that fluid-fluid interactions, mainly the dissolution of crude oil polar components into the brine, significantly affect brine physical and interfacial properties. In secondary injection scenario, two times diluted seawater (2SW), which has the lowest IFT value, exhibits the highest (81%) oil recovery factor. While the lowest recovery factor (60.75%) was observed for the case of formation water (FW) injection. To explore the effect of contacting time, after 48 h soaking, brine injection was resumed. The effluent pH measurement at this stage showed a reduction, where the UV-Vis spectroscopy and IFT measurements confirmed dissolution of the crude oil polar components into the brine. The results showed that as brine salinity decreases, the amount of dissociated polar components increases. pH value of ten times diluted sea water (10SW) was reduced from its initial value of 7.45 to 4.22, while FW exhibits minor pH variation. Consequently, 10SW, which dissolved highest amount of polar components, depicts the highest recovery factor (6%) after soaking. Contrary to this, in tertiary injection mode, the high amount of saline brine in the core (because of FW injection at secondary stage) hinders the potential for more production for SW, 2SW and 10SW injection as all resulted to lower recovery factor compared to their secondary counterparts.〈/p〉 〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519306060-fx1.jpg" width="500" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Chaohua Guo, Hongji Liu, Liying Xu, Qihang Zhou〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉For the shale gas transport model in nanopores, researchers recently pay more and more attention to the existence of water phase. However, the effect of water film on the gas transport is still not clearly understood. In this paper, we considered the existence of water film on inorganic shale pore surface and introduced the adsorption mechanism of methane-water film-shale clay three-phase (gas-liquid-solid) to the shale gas transport model. Then, we modified the expression of porosity and derived a new transport equation of shale gas considering the adsorption mechanism of three-phases in nanopores. Using the finite element method, we solved the equation and analyzed the effect of water film. Finally, the range of water film effect was analyzed by defining the offset ratio. The results show that: (1) The existence of water film has negative effects on physical quantities, such as effective porosity and apparent permeability. When the water molecular coverage ratio reaches to 1, the decrease of porosity can be about 18.1%; (2) The existence of water film reduces the gas production rate and accumulative gas production. When the water molecular coverage ratio reaches to 1, the gas accumulative production decreases about 49.6%; (3) The pore radius which has significant water film effect is very small. Furthermore, the smaller of the pore size, the more significant the water film effect is. Also, it can be found that the effect of water film on porosity can be ignored with when pore radius exceeds 29 nm. When the pore radius is larger than 11 nm, the effect of water film on 〈em〉k〈/em〉〈sub〉〈em〉app〈/em〉〈/sub〉〈em〉/k〈/em〉〈sub〉〈em〉d〈/em〉〈/sub〉 can be ignored.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Liming Wan, Bing Hou, Han Meng, Zhi Chang, Yeerfulati Muhadasi, Mian Chen〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The multi-layered coal strata in Lin-Xing block of China is rich in tight sandstone gas and the coalbed methane (CBM). The feasibility of multi-gas production and the optimal layer for fracturing in multi-layers requires a better understanding of fracture vertical extension mechanism through sandstone coal interbedding. To analyze the problems, six true tri-axial experiments were conducted on the multi-layered specimens of sandstone and coal outcrops. The transition zone was simulated by the cement with certain strength and thickness. In the experiments, the perforation position, fluid viscosity, and lithological difference were discussed. The results showed that the effect of viscosity exhibited a stepped manner as a function of fracture complexity. High-viscosity fluid significantly improved the fracture penetration ability when fracturing in coal layer. The results also show that when indirectly fracturing in sandstone, low-viscosity fluid was under the risk of natural fracture activation near wellbore to cause fracturing failure. When both layers were perforated, complex fracture network was easily formed as multi-layers were fractured. Perforation in both sandstone and coal layers were the best method based on the fracture penetration ability and the overall fracture complexity. T-shaped and step-wise fractures were found in the interface. The transition zone made it easier for fracture vertical extension through layers. The field production data was in good agreement with the experimental results. These results provide a guideline for the optimal perforation position selection and fracturing parameters in coal strata.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Wenjuan Miao, Xiangguo Li, Yingbin Wang, Yang Lv〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The pyrolysis of oil-field sludge (OS) has the appeal of resource recovery for this kind of waste disposal. In this paper, we investigate the pyrolysis kinetics of OS with Coast-Redfern (CR) and Flynn-Wall-Ozawa (FWO) methods in a wide temperature range (305–1223 K). The pyrolysis process of OS mainly includes light organics vaporization (Stage-2), middle and heavy organics and carbonates decomposition (Stage-3), coke reduction and other inorganics decomposition (Stage-4). The kinetic analysis manifests that Stage-2 meets well with the reaction order mechanism, and the reaction order (n) is 2 and in the range of 1.3–1.9 obtained by CR and FWO, respectively. The divergence of the two methods mainly appears in Stage-3, where E〈sub〉a〈/sub〉 calculated by FWO method is much higher than that by CR method. CR method gives D〈sub〉1〈/sub〉 model for this stage, while FWO method picks D〈sub〉3〈/sub〉 model to describe this stage. The simulation plots indicate that the results of CR method are more credible. As for Stage-4, both methods select G(α) = α as the mechanism, but CR method performs better agreement and a smaller discrepancy than FWO method does. Thus, FWO method is considered less accurate for OS analysis.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Christian A. Paternina, Alexandra K. Londoño, Miguel Rondon, Ronald Mercado, Samuel Muñoz〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉The injection of surfactants as the active component of Enhanced Oil Recovery (EOR) formulations is the current chemical method with the more promising potential because it produces substantial reduction of oil/water interfacial tension. However, the molecular arrangements depending on salinity and hardness, is not well understood. This is a key factor when trying to understand the solubilization of oil and the retention of surfactant during EOR processes. Nevertheless, the formation of micelles is one of the phenomena most affected by the salt concentration but, usually, this parameter is not considered. In this work, the micellization of a commercial extended surfactant at different concentrations and several salinities and hardness is studied. Results showed that size, shape and/or number of micelles are affected by the salinity and hardness. The explanations for this fact include the formation and re-solubilization of calcium soaps, salting-out phenomena and the electric charge shielding, which affect the micellar packing factor. The re-arrangement of molecules, depending on the electrolytes in solution, could favor the formation of spherical, rod-like micelles, and eventually the co-existence of both, or even other types of aggregates and it could be inferred by the analysis of set of data obtained from simple and cheap technique as turbidimetry and complimentary verified by a more sophisticated technique such like DLS.〈/p〉〈/div〉 〈/div〉 〈h5〉Graphical abstract〈/h5〉 〈div〉〈p〉〈figure〉〈img src="https://ars.els-cdn.com/content/image/1-s2.0-S0920410519307211-fx1.jpg" width="324" alt="Image 1" title="Image 1"〉〈/figure〉〈/p〉〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Shahin Kord, Aboozar Soleymanzadeh, Rohaldin Miri〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Asphaltene precipitation and subsequent deposition on the rock surface during natural depletion and Enhanced Oil Recovery (EOR) methods are two challenging flow assurance issues, causing a sudden decline in oil production. Different precipitation mechanisms and absence of an appropriate generalized characterization parameter have questioned the predictive potential of numerous available thermodynamic models. To overcome the complexity of using available thermodynamic models, different scaling equations were developed to represent a simple yet accurate estimation of the amount of asphaltene precipitation. Nonetheless, most of the proposed correlations are not generalized and are best suited to a specific scenario such as addition of a precipitant or gas injection.〈/p〉 〈p〉In this study, several asphaltene precipitation experiments were conducted on different real oil samples to investigate the amount of precipitated asphaltene due to the compositional changes cause by injection of Methane and Water and also due to pressure variations representing natural depletion mechanism. Besides performing the experiments, the collected literature data for precipitant dilution and gas injection were used to propose a new generalized scaling equation by developing the idea suggested by Kord and Ayatollahi to model all types of asphaltene precipitation phenomena. The results indicated that the new generalized scaling equation can successfully model all types of asphaltene precipitation scenarios. The amount of precipitation can be estimated at different thermodynamic conditions for four precipitation phenomena. The results illustrated that the new generalized scaling equation can successfully model all factors triggering asphaltene precipitation at various stages of production, demonstrating its potential for use as an efficient tool to identify, assess and mitigate risk of asphaltene deposition.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Sayantan Ghosh, Seth Busetti, Roger M. Slatt〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20–25 miles (32–40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters.〈/p〉 〈p〉Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5 × 10〈sup〉−6〈/sup〉) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Jie Zou, Reza Rezaee, Quan Xie, Lijun You〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉With a significant amount of methane stored in shales in the form of adsorbed gas, it is important to understand the controlling factors of the methane adsorption capacity. Under actual reservoir conditions, the high temperature and moisture are always coexisting which can affect gas adsorption capacity. This paper studied the methane adsorption of shale at different temperatures in dry and wet conditions. The adsorption results indicated that the moisture and high temperature can reduce the adsorbed gas content in shales individually, and the two factors have a synergistic-negative effect on methane adsorption in shales. Thermodynamic parameters showed that the heat of adsorption shows a decreased tendency and the entropy of adsorption becomes less negative after moisturizing the samples. The combined effect of the two factors is sufficiently important in the evaluation of gas adsorption capacity in shale gas systems.〈/p〉〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Afshin Amini, Erik Eberhardt〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉 〈p〉Hydraulic fracturing is today the primary means of initiating, increasing, and maintaining well productivity in unconventional shale gas reservoirs. However, hydraulic fracturing is attracting public concern over its rapid growth in use and environmental footprint, including potential hazards such as induced seismicity. To mitigate these concerns, there is a need to better understand the level of hazard present with respect to the magnitudes of the events possible, recognizing that these are not equal across different shale gas plays due to regional differences in the geological conditions or even within the same shale gas play due to local differences.〈/p〉 〈p〉An empirical study is presented here along with a series of numerical simulations to investigate the influence of the tectonic stress regime on the magnitude and magnitude distribution of induced seismicity events related to hydraulic fracturing practices. A database of determined earthquake focal mechanisms was first used to determine the tectonic stress regime for different North American shale gas basins. Next, induced events associated with hydraulic fracturing operations were identified to determine the magnitude distributions and b-values for these different shale gas basins. To support these empirical analyses, 3-D numerical modelling was performed to further investigate the mechanistic responses and event magnitudes under different simulated stress regimes. The empirical analysis results show that thrust faulting stress regimes have lower b-values than strike-slip stress regimes and therefore are more susceptible to larger induced seismicity events. The numerical simulations show that this is related to the stresses acting on a thrust fault (relative to the fault dip angle) being higher and more concentrated across a larger slip area. Slip in this case, and the stored strain energy being released, was observed to occur as a single large magnitude event. In contrast, numerical simulations for the other faulting types showed the stresses to be more distributed across the fault plane. This results in multiple slip events involving smaller slip areas and therefore with smaller event magnitudes, assuming all other factors are kept the same.〈/p〉 〈/div〉 〈/div〉

Description: 〈p〉Publication date: November 2019〈/p〉 〈p〉〈b〉Source:〈/b〉 Journal of Petroleum Science and Engineering, Volume 182〈/p〉 〈p〉Author(s): Xuetao Hu, Lei Chen, Lin Qi, Zhian Lei, Yue Luo〈/p〉 〈div xml:lang="en"〉 〈h5〉Abstract〈/h5〉 〈div〉〈p〉Based on the total organic matter (TOC) content, brittle minerals (quartz + feldspar) content, total gas content, porosity and production data of eight vertical and twenty-three horizontal shale gas wells in the Sichuan Basin, a new reservoir evaluation method for the marine shale reservoirs of the Sichuan Basin is developed. In this study, based on the analytic hierarchy process (AHP) and deviation method, a comprehensive evaluation index (CEI) was proposed to evaluate the marine shale reservoir. According to the CEI and the production data, three type marine shale reservoirs were proposed. The CEI was applied to evaluate the Wufeng-Longmaxi marine shale of the B201 well. The results show that the Wufeng-Longmaxi marine shale is the low quality shale reservoir. The comprehensive evaluation criteria proposed in this study can also be applied to evaluate the marine shale reservoirs in other areas in the Sichuan Basin through the verification of several other shale gas wells in the Sichuan Basin.〈/p〉〈/div〉 〈/div〉