A method for evaluating gas saturation with pulsed neutron logging in cased holes J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-21 Juntao Liu, Shucai Liu, Feng Zhang, Bo Su, Haijun Yang, Yongzhong Xu, Bin Miao, Hu Li
Tight gas reservoirs have been one of the most important field of gas exploration and development, and the dynamic monitoring of gas saturation is of great significance to the adjustment of oilfield development scheme. Pulsed neutron logging technology plays an important role in the evaluation of gas saturation in cased holes. The low porosity of tight gas reservoir presents a new challenge to the application of pulsed neutron logging technology. In order to further investigate the measurement information of pulsed neutron logs to improve the performance of gas saturation measurement, the Monte Carlo numerical simulation method is used to study the gas saturation responses of different parameters obtained by the pulsed neutron-gamma logging instrument with an extra gamma-ray detector added. The results show that the capture count ratio measured by the instrument is mainly affected by changes in the hydrogen index of the formation. The ratio of pure inelastic gamma rays is more sensitive to the variation of formation density. When the porosity of the reservoir is fixed, the gas layer has a low hydrogen index and low density relative to the water layer. By combining the response characteristics of the two ratios, a new gas saturation evaluation parameter (GSEP) is proposed to evaluate gas saturation. The new method displays a higher gas sensitivity compared with the conventional ratio method and macroscopic capture cross section (Sigma) method. In addition, the response characteristics of GSEP in different well logging environments are also studied. It displays GSEP is less affected by the variation of the formation water salinity and clay contents compared with the Sigma method. At last, field examples are presented to validate the effectiveness of the proposed method.
Numerical investigation on the critical factors in successfully creating fracture network in heterogeneous shale reservoirs J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-21 Chuang Liu, Xu Jin, Fang Shi, DeTang Lu, He Liu, HengAn Wu
The heterogeneous characteristics of shale formations play a significant role in creating a fracture network during stimulation treatments. The hydraulic fracturing in naturally fractured shale formations is investigated using an explicitly integrated discrete-finite element approach. Parametric studies are presented for the distribution of natural fractures, rock toughness, in-situ stress, the layers properties and the injection rate. Numerical results show that the distribution patterns of natural fractures determine the creation of a fracture network. The propagation of hydraulic fracture mainly along parallel distributed natural fractures results in several branch fractures. The weak interfaces between different layers will alter the propagation direction of hydraulic fractures to the horizontal plane, which facilitates to intersect with the far field of natural fractures. The initiation and opening of natural fractures are confined in large in-situ stresses and stress contrast formations, which is unfavorable to generate a large field of fracture network. The fracture complexity will be significantly improved in the reservoirs of axis-orientated natural fractures as simultaneous fracturing stimulation is implemented. The results presented in this paper provide some new insights into generating a fracture network to optimize hydraulic fracturing designs of shale gas reservoirs.
Experimental Investigation of Fe3O4 Nanoparticles Effect on the Carbon Dioxide Hydrate Formation in the Presence of Magnetic Field J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-19 Solmaz Rajabi Firoozabadi, Mohammad Bonyadi, Asghar Lashanizadegan
Characterization of microscopic pore types and structures in marine shale: Examples from the Upper Permian Dalong Formation, Northern Sichuan Basin, South China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-19 Jizhen Zhang, Xianqing Li, Zengye Xie, Jian Li, Xueqing Zhang, Kexin Sun, Feiyu Wang
We selected the Upper Permian Dalong shale in northern Sichuan Basin to qualitatively and quantitatively characterize the different types and sizes of pore system in marine shale. Field emission scanning electron microscopy, low-pressure N2/CO2 gas adsorption–desorption experiment, high-pressure mercury intrusion porosimetry experiment, and petrophysical model interpretation method were conducted. Results show that Dalong shales are rich in brittle minerals and organic matters (OMs). The pore system consists of four types of pores, namely, OM pores, intraparticle (intraP) pores, interparticle (interP) pores, and microfracture. OM pores and pores within brittle minerals dominate the pore system and account for 65.7% and 24.5% of the total porosity, respectively. Slit- and wedge-shaped pores are the major pore shapes in the shale pore system. These pores have good adsorbability and openness that can facilitate the storage and migration of shale gas. Pore size diameters are mainly distributed in the ranges of 0.40–0.90 nm, 200–600 nm and 20–80 μm. Both the specific surface area (SSA) and total pore volume (PV) decrease with the increasing average pore diameters. Micro- (< 2 nm), meso- (2–50 nm), and macropores (> 50 nm) contribute 78.23%, 6.18%, and 12.52%, respectively, of the total PV and 92.67%, 9.25%, and 1.15% of the total SSA. The pore diameter of < 10 nm is predominant in the pore system and account for 86.83% of the total PV and 99.89% of the total SSA. OMs together with clay minerals jointly influence the total PV and SSA development, whereas brittle minerals inhibit pore development. The total organic carbon (TOC), brittle minerals and clay minerals discriminatively control the development of micro-, meso-, and macropores, which are discretely provided by OM pores within kerogen, pores within brittle minerals, and clay minerals, respectively. Fractal dimensions D1 and D2 were 2.153–2.561 and 2.672–2.772, respectively. These values indicate that the pore surface is substantially irregular, and the pore structure is significantly complex and heterogeneous, which is positively correlated with total PV and SSA but negatively correlated with pore size diameter. TOC content, thermal maturity, and clay minerals are positively correlated to fractal dimension; whereas high brittle mineral content may reduce the fractal dimension.
An analytical model of wellbore strengthening considering complex distribution of cleat system J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-19 Lisong Zhang, Shiyan Zhang, Weizhai Jiang, Zhiyuan Wang, Linlin Wang
A wellbore strengthening model for CBM drilling was analytically established based on the fracture mechanics, considering the cleat system. In this model, the stress field induced by the multi-cleats opened was firstly solved based on the fracture mechanics and the principle of linear superposition. Especially, a failure criterion was introduced to judge whether the cleat is opening or closed. Then, the total stress was obtained by superimposing the stresses induced by the drilling fluid pressure, the formation pressure, the in-situ stress and the opened cleat. More importantly, the cleat-tip stress intensity factors before and after strengthening were calculated and compared to elaborate the validity of the wellbore strengthening. The results show that the cleat-tip stress intensity factors decreases obviously after the wellbore strengthening. Meanwhile, the analytical model shows an agreement to the finite element results for the stress distribution and the cleat-tip stress intensity factor. Finally, the parametric analysis was performed to reveal that: the smaller distance from the location of LCMs to the wellbore wall and the higher sealing efficiency of LCMs are positive for the wellbore strengthening; the larger number of cleats and the longer length of the opened cleat are harmful to the wellbore strengthening. This research has a contribution on how to establish the wellbore strengthening model that considers multi-cleats or multi-fractures.
Fractal Disposition and Porosity Characterization of Lower Permian Raniganj Basin Shales, India J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-19 Bodhisatwa Hazra, David A. Wood, Sumit Kumar, Sujan Saha, Suryendu Dutta, Priya Kumari, Ashok K. Singh
Pore structural parameters of organic-rich shales control their gas storage properties and gas transport behaviors. In this work, pore structural parameters of selected organic-rich shale samples belonging to the Lower Permian Barakar Formation from Raniganj basin (India) are studied using low-pressure nitrogen adsorption combined with field emission scanning electron microscopy (FE-SEM), Rock-Eval pyrolysis and energy-dispersive X-ray spectroscopy (EDX). The samples are predominantly mesoporous and in the early to peak range of thermal maturity, with one late mature sample affected by a nearby igneous intrusion. The Brunauer, Emmett, and Teller specific surface area (BET SSA) of the samples display no correlation with total organic carbon (TOC), and a positive correlation with Rock-Eval Tmax. The average pore radii of the shale samples display a negative relationship with the BET SSA and Rock-Eval Tmax values. As thermal maturity advances finer pores are formed, which progressively increases the SSA of shales. A novel fractal-discriminating parameter, ΔS [(slope of the linear segment at P/P0 of 0.5 to 1.0) – (slope of the linear segment at P/P0 of 0 to 0.5), where S= D-3] displays a minimum value for a silty-shale sample, and a maximum value for the intrusion-affected shales. The less distinct fractal dimensions for the silty-shale, and the most distinct fractal dimension for the intrusion-affected shales shows influence of both the mineral composition and thermal maturity on fractal dimensions of shales. Among the samples studied, the intrusion-affected shales exhibited the highest BET SSA, pore volume, least average pore radius, larger ΔS and fractal dimensions (D1 and D2), all signifying the impact of high thermal maturity (thermal stress) on pore structural parameters.
Proppant-packed fractures in shale gas reservoirs: An in-situ investigation of deformation, wettability, and multiphase flow effects J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-20 Maziar Arshadi, Mohammad Piri, Mohammed Sayed
The results of a systematic, micro-scale experimental investigation on two-phase gas/brine flow through proppant-packed fractured shale samples under increasing effective stresses of up to 5000 psi are presented in this paper. We use a miniature core-flooding apparatus integrated with a high-resolution X-ray micro-CT scanner to perform the flow experiments. Geomechanical deformation and its impact on displacement mechanisms governing fluid transport within the packed fractures are studied at the pore scale under certain flow and stress conditions. These conditions were carefully designed to represent reservoir depletion and transport of water through such media. Since proppant grains are placed to maintain the long-term conductivity of the induced fractures, they significantly influence the geomechanical and multi-phase flow behavior of these conduits during reservoir depletion. We particularly examined the effectiveness of modified resin-coated sand (compared to a basic white sand) in maintaining the hydraulic conductivity of induced fractures. Significant bullet-like embedment and proppant crushing under severe stress conditions were found to be the shortcomings of these proppants, respectively. We then developed a methodical framework to design improved proppants with a similar mechanical strength to the host shale rock to withstand these drawbacks.Sphericity, roundness, and size of the proppant grains also impacted the critical properties of the constructed pore space such as pore size distribution and pore-throat aspect ratio. Such parameters control pore-scale gas-to-brine and brine-to-gas displacements within the hydraulic fractures. We specifically studied the non-wetting phase trapping and its subsequent impact on reduction of available pore space for other fluids to flow. It was found that trapped gas globules are very likely to deform within the medium and redistribute/reconnect under a higher effective stress. For the first time, wettability alteration of the proppant pack from water-wet to oil-wet was observed in a gas/brine fluid system. Wettability alteration occurred non-uniformly and was thought to be due to deposition of the shale organic matter released after significant proppant embedment. Such wetting characteristics aggravate multi-phase trapping within the fractures, which in turn leads to dramatic reductions in effective gas permeability. This study is concluded with a set of recommendations that can be used to effectively maintain the productivity of propped fractures for extended period of time.
The Effect of Carbonate Reservoir Heterogeneity on Archie’s Exponents (a and m), an Example from Kangan and Dalan Gas Formations in the Central Persian Gulf J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-17 Maziyar Nazemi, Vahid Tavakoli, Hossain Rahimpour-Bonab, Mehdi Hosseini, Masoud Sharifi-Yazdi
Transient liquid leakage during plunger lifting process in gas wells J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-14 Kunpeng Zhao, Bofeng Bai
Plunger lift is an economical method to solve the liquid loading problem in wells. Following our previous research (Zhao et al., 2018), which focused on the steady-state process of liquid leakage during lifting, the transient variations of plunger velocity, liquid leakage and stress conditions during plunger lifting process are investigated theoretically and experimentally in this paper. Based on the force analysis and finite difference method, the transient physical model for the mass and gas volume fraction of gas-liquid column above plunger is proposed. Combining the similarity experiments and infrared measuring technology, the proposed transient model is verified quantitatively with the relative deviation less than ±10%. The results show that both the liquid leakage and the gas volume fraction of gas-liquid column above plunger cannot be neglected during plunger lifting. The transient change rules of lifting differential pressure, plunger velocity, gas volume fraction of gas-liquid column and liquid leakage flow rate during lifting process are obtained. The influences of liquid loading condition and gas production rate on transient plunger lifting process are discussed. Through the dimensionless analysis, a dimensionless correlation for transient gas volume fraction of gas-liquid column is developed.
Insights into Interactions and Microscopic Behavior of Shale Gas in Organic−rich Nano−slits by Molecular Simulation J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-14 Yaxiong Li, Zhiming Hu, Xiangui Liu, Shusheng Gao, Xianggang Duan, Jin Chang, Jianfa Wu
Shale gas is a potential substitute for the gradually depleted conventional oil and gas resources. Since studies on microscopic behavior of shale gas in nano−slits and the exact mechanical mechanisms behind it are still in urgent demand, this paper uses the model of graphite layers to describe microscopic details of shale gas occurrence behavior in organic−rich nano−slits from the viewpoint of molecular interactions by molecular simulation. “Dual adsorption mechanisms” and the consistency theory of gas distributions affected by wall effects under the condition of no overlapped wall force field are proposed to clarify the formation mechanisms of shale gas in the nano−slits. Results also show the critical channel width for all gases to be affected by the nano−scale effects is between 1 and 2 nm, and the regions (counted from the gas zone) for overlapped wall force field in 0.5 and 1 nm slits are about 0.32 and 0.42 nm, respectively. Furthermore, the effects of overlapped wall forces, channel size and pressure variations on gas aggregation and its movability etc., interaction mechanisms inside the nano−slits and their causalities, the development enlightenment for Knudsen layer (KL) and the whole gas have been explicitly depicted and clarified, which is expected to be a useful reference not only for shale gas evaluation and exploitation, but also for widespread research of gas occurrence phenomena in carbon−based materials in the field of industry.
Relationship between the stress sensitivity and pore structure of shale J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-14 Zhang Wentong, Wang Qing, Ning Zhengfu, Zhang Rui, Huang Liang, Cheng Zhilin
The pore structure of shale changes with variations in the effective stress, greatly affecting the gas production of shale. The relationship between pore structure and stress sensitivity has remained unclear to date. The porosity sensitivity exponent and pore compressibility are two crucial parameters for describing the stress sensitivity and relate to the pore structure of shale. In this study, expressions of the porosity sensitivity exponent and pore compressibility were deduced based on a dual-porosity model. The results show that the scale and quantity of the micro-fractures and matrix pores play an important role in determining the porosity sensitivity exponent and pore compressibility. Regarding the pore structure of shale, a low ratio of the porosity of the matrix pores to the porosity of the micro-fractures causes the porosity sensitivity exponent to be low and the pore compressibility to be high; consequently, the shale shows strong stress sensitivity. The results regarding the porosity sensitivity exponent and pore compressibility indicate that the pore compressibility is the dominant factor influencing the stress sensitivity. The pore compressibility is affected by not only the pore structure of shale but also the mechanical properties of shale. Young's modulus is negatively correlated with pore compressibility, while Poisson's ratio shows a positive relationship and can be neglected. The effect of tortuosity on the stress sensitivity was also studied. The fitting results for the Walsh model illustrate that the tortuosity increases the degree of stress sensitivity. The results of this study identified the relationship between stress sensitivity and pore structure of shale, which will enable reservoir engineers to accurately predict stress sensitivity and investigate the permeability and porosity of shale based on its pore structure.
Evolution of organic pores in marine shales undergoing thermocompression: a simulation experiment using hydrocarbon generation and expulsion J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-15 Miao Shi, Bingsong Yu, Jinchuan Zhang, Huang Huang, Ye Yuan, Bo Li
To evaluate the evolution and significance of organic pores in marine shales, samples with high organic matter and low thermal maturity were collected from the Mesoproterozoic Xiamaling Formation in the Xiahuayuan region, Hebei province, northern China. Samples underwent a thermocompression simulation experiment. Scanning electron microscope (SEM) observations, N2 / CO2 gas adsorption analyses, and statistical calculations assured the qualitative and quantitative characterization of organic pores during kerogen maturation. Results demonstrated that pores largely evolve from macro- and meso- sizes to meso- and micro- sizes along with increasing pore volumes. As the total proportion of organic pores reached over 50% from the maturation (345°C and 375°C) to high maturation stages (440°C), they provided the main space for gas storage. Organic pore types changed from hydrocarbon shrinkage cracks to hydrocarbon bubble pores and hydrocarbon dissolution pores. Additionally, organic porosity sharply increased initially followed by as low decrease as the samples were heated to the post maturation (500°C) stage.
Analysis method of pulse decay tests for dual-porosity cores J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-15 Guofeng Han, Liang Sun, Yuewu Liu, Shangwen Zhou
Homogeneous models are typically used to analyze the results of pulse-decay tests for low permeability cores. However, this poses a problem because some samples are dual-porosity media with microcracks/macropores and micropores. In this study, numerical simulations were conducted and the results showed that the pulse decay curves of the dual-porosity models are different from those for the homogeneous model. The results indicated that the volumes of the upstream and downstream vessels play an important role in identifying dual-porosity media and the early time and late time are mainly influenced by the storativity ratio and interporosity flow coefficient, respectively. A pressure derivative method was proposed in this work in order to identify dual-porosity media at the early time and distinguish the interporosity flow models. This method is applicable for vessel volumes within one-tenth to ten times the pore volume. The proposed method was verified against the experimental data of other researchers.
Local Asymmetric Fracturing to Construct Complex Fracture Network in Tight Porous Reservoirs during Subsurface Coal Mining: An Experimental Study J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-12 Delei Shang, Guangzhi Yin, Yuan Zhao, Bozhi Deng, Chao Liu, Xiangtao Kang, Jun Lu, Minghui Li
Hydraulic fracturing to enhance permeability of tight reservoirs is meaningful but difficult in constructing of complex fracture network. This study aimed to examine the effectiveness of tight porous reservoir stimulation in the context of hydraulic fracturing to increase the fracture complexity as much as possible. The simulation experiments were performed to reasonably establish the relation between the laboratory results and the field fracturing operations. Large size stratified and intact samples were casted to resist the size and boundary effects by mixing river sand and/or pulverized coal with concrete cement and freshwater in specific proportions. The samples with artificial slot orienting was casted to understand the fracture initiation, orientation, and deflection mechanisms considering the influence of caprock structure and re-fracturing without temporary plugging. The samples were tested under the scaled geostress conditions of corresponding in-situ stress with a true triaxial loading system, and the reasonable dimensionless groups derived from the literatures. Consequently, this study proposed an asymmetric fracturing method based on the experimental results considering the scaling structure of overburden-reservoir-underburden in porous reservoirs. The local asymmetric fracturing is a type of small scale high-pressure fluids jet cutting slot and perforation aiding for orientation. Hydraulic fractures were influenced by the fracture-induced stress shadow and ratio of the maximum to minimum horizontal stress. The validation and comparative results showed that compared with re-fracturing that typically generated few new fractures, asymmetric fracturing significantly increased the complexity of fracture network. Although determining the applicability of asymmetric fracturing depended on engineering pilots, the derived method efficiently addressed the properties of the strata structure of the reservoirs. Therefore, it has a high potential for application in local underground coal seam and special-trap type oil gas reservoirs fracturing to construct fracture network.
Transient, sandface temperature solutions for horizontal wells and fractured wells producing dry gas J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-11 Akindolu Dada, Khafiz Muradov, David Davies
Measured, bottom-hole transient temperature has been proven to be a valuable source of information. Similar to transient pressure (i.e. well testing) the temperature can also be used to estimate formation properties like permeability-thickness or to be used for flow rate allocation. Moreover, transient temperature has the unique advantages being sufficiently sensitive to identify the properties of the near-wellbore zone properties and/or the flowing fluid composition.That is why in the past decade, following the introduction of the modern in-well temperature sensing technology, the value of Temperature Transient Analysis (TTA) has been widely recognised and a number of useful solutions and workflows developed and tested, mostly for the vertical wells due to the reduced complexity of their TTA mathematical problem in the radial flow conditions. TTA requires the installation of high--precision, real-time temperature gauges/sensors close to the sandface. They are most frequently found in intelligent wells, the majority of which are either horizontal or highly deviated. Such high deviation well designs introduces the additional complexity to the data analysis, such as a wider range of flow regimes observed or the magnified impact of formation anisotropy on the reservoir response.There are currently very few published TTA solutions for oil producing horizontal wells and none for the horizontal wells producing gas. This work aims to fill this gap by developing analytical and semi-analytical solutions for the transient, sandface temperature of a gas producing horizontal well.This work first develops transient sandface temperature solutions assuming linear flow into a planar sink as a representation of a horizontal well (or a fractured well). Simplified forms of these equations are developed, making the application of TTA easier. Finally, the effects of heat transfer between the formation and the surroundings, and the effects of flow convergence into horizontal wells are considered. The combination of these for TTA in a horizontal gas well when combined with the existing TTA solutions for a liquid producing horizontal well lays the basis for a comprehensive transient analysis framework for multi-phase production, horizontal wells.
A Novel Well-Testing Model to Analyze Production Distribution of Multi-Stage Fractured Horizontal Well J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-06 Jiazheng Qin, Shiqing Cheng, Youwei He, Yang Wang, Dong Feng, Guan Qin, Haiyang Yu
The sharp decline in oil or gas production has been observed in many multi-fractured horizontal wells (MFHW) within only one or two years’ development. How to determine production rate distribution of MFHW becomes significant for enhancing hydrocarbon productivity. However, the effect of non-uniform production distribution of horizontal sections and fractures on pressure-transient response are hardly considered for the available well-testing models of MFHW, leading to erroneous interpretation results.The aim of this work is to present a novel approach to investigate the non-uniform production distribution along horizontal wellbore in a relatively economical way. An analytical model was developed to better characterize flow in fractures and horizontal wellbore. To better calculate the pressure drops in hydraulic fractures, we modeled the fluid flow in fractures with finite conductivity by considering variable-mass-linear flow for fluid far from wellbore and radial flow for fluid near wellbore. Meanwhile, horizontal wellbore was divided into multiple horizontal sections, and each segment is considered as a cylindrical source. As a result, an analytical pressure solution was developed. The analytical solution was further compared with numerical model in Saphir to verify the accuracy. A new horizontal line before pseudo-radial flow was observed (the second radial flow)) on pressure-derivative curves. It would lead to incorrect interpretation results of parameters if the new regime is regarded as the pseudo-radial flow.
Electromagnetic Thermal Stimulation of Shale Reservoirs for Petroleum Production J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-07 Jin-Hong Chen, Daniel T. Georgi, Hui-Hai Liu
Light hydrocarbons produced from unconventional tight shale reservoirs with matrix permeability in nano-Darcy range accounts for more than half of the petroleum production in the United States in the past several years. This has been enabled mainly by the drilling of long horizontal wells coupled with extensive hydraulic fracturing. A typical fracturing job for a horizontal well requires two to five million gallons of water which imposes significant challenges in many areas of the world that lack water resources. In addition, treatment and disposal of produced fracturing fluids can be expensive and may negatively impact the environment. Here we show a ‘water-free’ stimulation method to produce light hydrocarbons from the extremely tight reservoirs using electromagnetic (EM) waves to heat the formation and elevate pore-water pressure. We demonstrated in the laboratory that microwave heating pulverized shales and other tight rocks without confinement and generated extensive fractures within shales with 15 MPa isotropic confinement pressures. Our calculation indicates that for typical shale reservoirs pore-water pressure can increase to 90 MPa or higher that is sufficient to stimulate the formation for production with a less than 100oC temperature increase of the reservoir. Using a simplified coupled model of EM heating and thermal diffusion, we estimated that with practically reasonable amount of power input the EM heating can stimulate a sufficiently large volume of tight reservoirs to produce light hydrocarbons.
Deep Desulfurization of Natural Gas by a Commercial ZnO Adsorbent: A mathematical Study for Fixed-bed Reactors J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-04 Mohammad Sadegh Parandin, Hamed Rashidi
Research on Evaluation Method of Wellbore Hydrate Blocking Degree during Deepwater Gas Well Testing J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-05 Wenyuan Liu, Jinqiu Hu, Xiangfang Li, Fengrui Sun, Zheng Sun, Yunjian Zhou
Although considerable advances have been achieved in recent years, there is still a long way to go for hydrate prediction and prevention during deepwater gas well testing. Well hydrate blockage is a time-dependent continuous process, and evaluation of wellbore blockage is critical for hydrates prevention and control. In this work, the authors presented a novel wellbore blocking degree evaluation model for deepwater gas-well testing. Firstly, a new evaluation model consisting of mass, momentum and energy balance equations considering hydrates formation was proposed. Secondly, considering hydrate phase equilibrium, the finite difference method and iterative technique were used to obtain the model results. Finally, the model was applied to the deepwater gas wells in the South Sea of China for verification and was subjected to sensitivity analysis. The predicted results were in good agreement with field test results. According to the sensitivity analysis, gas output, methanol concentrations, water production rate have different degrees of influence on hydrate blocking. The length of the hydrate stability region (HSR), the position of largest plugging point, and the distribution of wellbore inner diameter are the key to hydrate prevention and control. Meantime, combining the model evaluation results, optimizing the testing process can achieve the purpose of preventing-controlling gas hydrates economically and effectively.
Experimental study on movement characteristics of bypass pig J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-05 Jianheng Chen, Xiaoming Luo, Hailong Zhang, Limin He, Jianping Chen, Kaiyue Shi
In order to investigate the movement characteristics of bypass pigs, experimental variables of pressure fluctuation, average and instantaneous pig velocity and pig generated liquid volume were studied by a large experimental pigging system with horizontal, up-and-down, riser pipeline structures. Results obtained in this study show that there are multiple peaks at pressure fluctuation curves and each peak represents a pig pause state. Compared with conventional pigs, bypass pigs which eliminate the significant fluctuation of peak pressure have better adaptability for the variations of liquid loading. Differential pressure at the front and rear ends of the pig, which is self-regulated until a force balance is achieved, is independent of bypass fraction, but hinges on the resistance force. The average pig velocities decrease linearly with the increase of bypass fraction. The instantaneous pig velocities are generally low and less sensitive to the variations of gas flow rates at the bottom of the riser pipe, while it is much higher and exhibits the most obvious downtrend as bypass fraction increases at the top of the riser. When increasing bypass fraction, the duration of terminal liquid outflow is prolonged, indicating bypass pigging is conducive to reducing the pig generated liquid volume.
In-situ stress distribution and its influence on the coal reservoir permeability in the Hancheng area, eastern margin of the Ordos Basin, China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-05 Junlong Zhao, Dazhen Tang, Wenji Lin, Yong Qin, Hao Xu
During the coalbed methane (CBM) exploration and development, in-situ stress and permeability are two vital reservoir evaluation parameters. In this work, with the injection/falloff well test and in-situ stress data of 11 CBM wells in the Hancheng area, eastern margin of the Ordos Basin, China, the distribution of in-situ stress and its influence on the coal reservoir permeability were investigated. Results show that the maximum (SH, 10.80–53.84 MPa) and minimum horizontal (Sh, 9.96–31.88 MPa), and vertical principal stresses (Sv, 14.37–36.46 MPa) increase with the increasing burial depth. However, the coal reservoir permeability (0.01–0.54 mD) shows a decreasing tendency accompanied by increasing stresses. Three stress fields (I, II, and III) between 532.28 and 1350.55 m could be divided: I is in a compression zone (〈700 m, SH〉Sh ≈ Sv, reverse or strike-slip stress regimes); II is in a tension zone (700–850 m, Sv > SH > Sh, normal stress regime); III is in a compression zone again (>850 m, SH > Sv > Sh, strike-slip stress regime). The top-down in-situ stress regimes result in a “decreasing - increasing - decreasing” permeability variation. Meanwhile, the lateral stress coefficient, stress ratios decreased slowly while the reservoir pressures and temperatures show a positive correlation with increasing burial depth.
Influence of Calcium and Magnesium Ions on CO2 Corrosion of Carbon Steel in Oil and Gas Production Systems - A Review J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-05 H. Mansoori, D. Young, B. Brown, M. Singer
Calcium and magnesium ions are major constituent species in produced brines associated with oil and gas production. Existing literature is often contradictory and unclear as to whether the presence of such ions accelerates or retards general corrosion. Furthermore, their influence on initiation and propagation of localized corrosion remains ambiguous. This review presents state-of-the-art knowledge concerning how Ca2+ and Mg2+ influence the CO2 corrosion mechanism. In addition, a best way forward is proposed in order to bridge the existing literature gaps in studying the influence of these alkaline earth cations on CO2 corrosion.
Organo-mineralogical Insights of Shale Gas Reservoir of Ib-River Mand-Raigarh Basin, India J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-09-04 Vinod Atmaram Mendhe, Susheel Kumar, Alka Damodhar Kamble, Subhashree Mishra, Atul Kumar Varma, Mollika Bannerjee, Vivek Kumar Mishra, Sadanand Sharma, John Buragohain, Balram Tiwari
In the present study, Permian shale beds of Ib-River Mand-Raigarh Basin have been evaluated for insights of depositional conditions, organic, clay and mineral composition allied to shale matrix. The shale core samples were obtained during exploratory drilling and analysed for the properties like proximate, petrography, Rock-Eval, Total organic content (TOC), X-ray diffraction (XRD) and X-ray fluorescence (XRF). The values of vitrinite content and TOC varies from 2.00 - 16.20 (vol.%) and 1.88 - 6.99 wt. % with an average value of 10.34 (vol.%) and 3.75 (wt.%) respectively, suggesting fair to excellent source rock potential of shale for gas. Whereas, results of the Rock-Eval pyrolysis indicated fair to very good source rock potential (S1: 0.04 - 0.22 and S2: 0.57 - 39.45). The indicator of thermal maturity parameters like Tmax (423 - 470 ᵒC) and VRo (0.64 - 0.96 %), counsels moderately matured shales. The plot of hydrogen index (HI) vs oxygen index (OI), Tmax vs HI and TOC vs HI illustrated the presence of type II and III kerogen in studied shales. The uniformity in carbon conversion elucidates negligible effects of intrusive and basin tectonics on shale reservoir which is validated from the passive stable tectonic setting of Ib-River Mand-Raigarh basin which favours deposition of organic matter. The high percentage of quartz (26.30 - 57.60 vol.%) signifying the resistive nature of SiO2 towards erosion and weathering. However, the negligible or typical absence of K-feldspar and a large percentage of kaolinite (16.80 - 53.30 vol.%) attributed to the strong weathering process. Consequently, the instantaneous reduction condition supported the preservation and transformation of organic matter.The paper focuses on the significance of various essential parameters like depositional conditions, organic richness, the degree of maturation, clay types and mineral constituents on the gas genesis and storage. The parameters interpreted through facies and evolution history of the basin to evaluate the prospects of shale gas resource development in Ib-River Mand-Raigarh Basin, India.
A Data-Driven Modeling Approach to Zonal Isolation of Cemented Gas Wells J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-31 Shobhit Misra, Michael Nikolaou
Gas leakage through the cemented section of a gas well, from a producing zone to other zones or to the open air, poses serious threats to safety and the environment. A number of design variables during drilling and cementing jobs may possibly contribute to such leakage. Decisions on these variables are best made during the design and well construction phase, as remedial operations after the well begins production have limited success rate. Therefore an approach that avoids the problem by ensuring robust zonal isolation during well construction jobs is more suitable. Such an approach involves decisions on a fairly large number of design variables. Building a model based on first principles to predict the effect of all of these variables on leakage is a formidable task. An alternative examined in this paper relies on using multivariate statistics to build an empirical model from available data. The model can then be used to make decisions on design variables such that leakage is avoided. The proposed approach is explained using data from 105 gas wells. The model built predicts leakage with about 75% accuracy in cross-validation tests. In addition, it ranks decision variables in the order of importance and suggests which ones need to receive more attention. The approach presented can be extended to include additional variables for which data is available.
Design and implementation of an effective system for catalytic degassing of Claus-derived sulfur over monometallic and bimetallic nanosilica-based catalysts and optimization via RSM-CCD J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-29 F. Tari, M. Shekarriz, S. Zarrinpashne, A. Ruzbehani
In this article, molten sulfur containing 170ppmw of total hydrogen sulfide was subjected to catalytic degassing by monometallic and bimetallic heterogeneous catalysts. Accordingly, iron oxide/nanosilica catalyst showed excellent degassing outputs, as the cyclic catalytic degassing processes revealed that activity of this catalyst did not change significantly. This could be attributed to generation of iron sulfide species in the catalyst. The structured catalysts showed high surface area (365m2/g) and proper mechanical strength (0.81 MPa). Using RSM-CCD, residual content of hydrogen sulfide in molten sulfur at optimum catalytic degassing conditions by iron oxide/nanosilica (1ppmw) was located at 1.51 (weight percent of iron oxide in catalyst), 245 (time, min) and 12.850 (weight of charged catalyst in 1kg of sulfur, g). At these conditions, residual content of hydrogen sulfide in molten sulfur was also traced by application of cerium oxide/nanosilica and molybdenum oxide/nanosilica catalysts as about 54ppmw and 47ppmw, respectively. It was shown that addition of iron oxide to cerium oxide/nanosilica and molybdenum oxide/nanosilica catalysts improved their catalytic behavior and decreased the residual hydrogen sulfide content in molten sulfur to about 25ppmw and 35ppmw, respectively. The catalysts were subjected to characterization analyses including AAS, FESEM, EDS and BET.
Analytical Dual-Porosity Gas Model for Reserve Evaluation of Naturally Fractured Gas Reservoirs Using a Density-Based Approach J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-28 Zhenzihao Zhang, H.Luis F. Ayala
The development of naturally fractured gas reservoirs often requires deployment of rigorous techniques for production data analysis incorporating dual-porosity gas behavior. It has been a prominent problem to linearize and analytically solve the governing equations for dual-porosity gas systems. This study applies a pseudo-pressure-based interporosity flow equation to derive a density-based rate-transient analysis method to accurately predict the gas production rate and estimate the amount of original gas in place (Gi) for the systems. The methodology also predicts the gas production rate by transforming the response of its liquid counterpart via a decoupling of the pressure-dependent effects using dimensionless depletion-driven parameters.For the first time, the density-based flowing material balance method is derived for dual-porosity gas reservoir. More than that, an innovative fracture productivity equation that was missing for dual-porosity system is derived as well. This study provided detailed derivations for the model and relationship used in past density-based dual-porosity rate-transient analysis. The dual-porosity productivity equation and the relationship between average matrix pseudopressure and average fracture pseudopressure are rigorously derived. The rescaling relationship between dual-porosity liquid solution and dual-porosity gas solution is also demonstrated in detail. An appropriate interporosity flow equation for gas is used. Based on that, the results show that the density-based approach is able to successfully capture dual-porosity behavior of gas for constant bottomhole pressure condition.
A discrete model for apparent gas permeability in nanoporous shale coupling initial water distribution J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-28 Tao Zhang, Xiangfang Li, Xiangzeng Wang, Jing Li, Zheng Sun, Dong Feng, Liang Huang, Tianfu Yao, Wen Zhao
Understanding and predicting gas transport in gas-shale reservoirs matrix containing abundant nanopores have tremendous implications for the development of gas-shale reservoir. However, there are many literature focusing on establishing gas transport models in a single nanopore, which is too ideal for the heterogeneous nanoporous shale. Besides, the water film and capillary water that existed on the inorganic pore and its effect on gas transport capacity are usually overlooked. In this work, based on the SEM (scanning electron microscope) images, the nanopores in OM (organic matter) are assumed as circular cross section shape, while that in inorganic are slit-like shape. The Beskok's model are employed to quantify the bulk-gas transport, and the additional flux contribution by surface diffusion in organic pore are also imbedded. The apparent gas permeability (AGP) model in a single nanopore is upscaled to sample scale with Monte Carlo sampling method, which successfully represents the heterogeneities of shale matrix including pore size distribution, total organic carbon (TOC) content, and water distribution. The proposed model fully takes into account the gas transport mechanisms, the complex flow boundary and the significant heterogeneity of the nanoporous shale. The reliability of the present model is successfully verified with the experimental data from different literature. Results show that Knudsen diffusion and surface diffusion are the two key transport mechanisms dramatically enhancing the AGP of shale matrix when the pressure is less than 6 MPa. The AGP of shale matrix containing abundant organic micropores (<2 nm) is possibly higher than that with larger pores because of the surface diffusion. The initial water saturation in the form of water film or capillary water in the IOM (inorganic matter) have significant impacts on the AGP. Although the pore size within OM are universally smaller than IOM, the AGP of shale matrix is still possibly enhanced with the increase of TOC content when accounting for the surface diffusion and water distribution.
An improved evaluation method for the brittleness index of shale and its application — A case study from the southern north China basin J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-27 Zhipeng Huo, Jinchuan Zhang, Pei Li, Xuan Tang, Xue Yang, Qinglun Qiu, Zhe Dong, Zhen Li
The brittleness index (BI) is an important indicator used to characterize the brittleness and fracability of shale reservoirs. The BI calculation methods based on the brittle mineral and mechanical parameters content of shale are widely used, but there are still some limitations, such as the separation of minerals and mechanics, the inconsistent viewpoints regarding brittle minerals of different scholars, and the equivalent treatments of the brittleness of each mineral. By taking the Permian Shanxi and Taiyuan Formation in the Southern North China Basin (SNCB) as an example, this paper improved the BI calculation method, then examined and applied it. The results show that the weight coefficients of brittleness contributions of various minerals are different because of their marked differences in mechanical properties. By multiplying and summing the mineral contents and their weight coefficients, an improved evaluation method for a shale's BI is proposed. The new BI has more reasonable physical significance and avoids the equivalent treatment of various minerals on the rock brittleness. Applications indicate that when compared with the original mineral BI, most of the new BI decrease, which reduces the artificial optimization of the shale brittleness. The new BI of limestone reduces significantly, which reveals that the brittleness and fracability of limestone should be less than those of shale and sandstone. The roof and floor limestone of shale will prevent induced fractures from propagating across the interfaces between the limestone and shale, and can thus be used as an effective barrier bedding to help the fracturing and formation of the complex fractures in shale sections. The improved BI method is able to evaluate shale brittleness and selecting a favorable fracturing shale section more accurately.
Permeability prediction using hybrid techniques of continuous restricted Boltzmann machine, particle swarm optimization and support vector regression J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-27 Yufeng Gu, Zhidong Bao, Guodong Cui
How to obtain reliable permeability data is universally considered as one of the critical work that guides geologists to explore oil-gas accumulation zones underground. Many significant researches related to permeability prediction have revealed that permeability can be directly calculated from logging data under usage of some complex non-linear equations. In this way, the key of permeability prediction is how to establish relational expression between permeability and logging data. Support vector regression is one of the best mathematical models using to explain complex mapping relationship between independent and dependent variables, and thus it can be viewed as an ideal approach to predict permeability. However, such model cannot be effective when different kinds of input data have high correlation or network parameters are not evaluated well. Then other two mathematical models, continuous restricted Boltzmann machine and particle swarm optimization, are referred to use to support the application of SVR. CRBM is functional to make a new data separation from the raw data, and network parameters can be optimized after PSO process. Therefore a new data-driven permeability prediction model CRBM-PSO-SVR is provided in this article. Data source used for method validation derives from five coring wells of the IARA oilfield, Santos Basin, Brazil. In two self-designed experiments, the accuracy rates of new method are respectively 67.34% and 76.67%, both of which are higher than those of other comparison methods. Experiment results well demonstrate the effectiveness of new method in permeability prediction when only logging data is available.
Integrated prediction of deepwater gas reservoirs using Bayesian seismic inversion and fluid mobility attribute in the South China Sea J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-27 Yaneng Luo, Handong Huang, Yadi Yang, Yaju Hao, Sheng Zhang, Qixin Li
In recent years, many important discoveries have been made in the marine deepwater exploration in the South China Sea, which confirms the abundant natural gas resources in this area. However, the prediction of deepwater reservoirs is very challenging because of the complex depositional system and the low exploration level with sparse wells in deepwater areas. To reduce the exploration risks, we develop an integrated prediction strategy for the deepwater gas reservoirs using the Bayesian adaptive seismic inversion and the frequency-dependent fluid mobility attribute. In the seismic inversion, an automatically adjusted prior stabilizer is derived to balance between the vertical resolution and the inversion stability according to the noise level, and the trace-by-trace recursive inversion process, using the inversion result of previous adjacent trace as the initial model for the next, is adopted to ensure the lateral continuity. In the gas detection, the fluid mobility attribute is calculated by the high precision matching pursuit algorithm to directly indicate the gas reservoirs, with no need to use the well-log or horizon data. We then combine the stratigraphic seismic inversion result with the gas indication fluid mobility attribute to comprehensively predict both the distribution and thickness of gas reservoirs. Synthetic data tests on a well model and a designed seismic signal verify the performances of the seismic inversion and the matching pursuit algorithm. The real data fluid mobility attribute gas detection results of two borehole-side seismic traces show good consistency with the well log interpretation results. Finally, the feasibility of the proposed integrated prediction method is demonstrated by a deepwater application in the South China Sea.
The role of fault gouge properties on fault reactivation during hydraulic stimulation; an experimental study using analogue faults J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-27 A.C. Wiseall, R.J. Cuss, E. Hough, S.J. Kemp
During the hydraulic stimulation of shale gas reservoirs the pore pressure on pre-existing faults/fractures can be raised sufficiently to cause reactivation/slip. There is some discrepancy in the literature over whether this interaction is beneficial or not to hydrocarbon extraction. Some state that the interaction will enhance the connectivity of fractures and also increase the Stimulated Reservoir Volume. However, other research states that natural fractures may cause leak-off of fracturing fluid away from the target zone, therefore reducing the amount of hydrocarbons extracted. Furthermore, at a larger scale there is potential for the reactivation of larger faults, this has the potential to harm the well integrity or cause leakage of fracturing fluid to overlying aquifers.In order to understand fault reactivation potential during hydraulic stimulation a series of analogue tests have been performed. These tests were conducted using a Bowland Shale gouge in the Angled Shear Rig (ASR). Firstly, the gouge was sheared until critically stressed. Water was then injected into the gouge to simulate pore fluid increase as a response to hydraulic stimulation. A number of experimental parameters were monitored to identify fracture reactivation. This study examined the effect of stress state, moisture content, and mineralogy on the fault properties.The mechanical strength of a gouge increases with stress and therefore depth. As expected, a reduction of moisture content also resulted in a small increase in mechanical strength. Results were compared with tests previously performed using the ASR apparatus, these showed that mineralogy will also affect the mechanical strength of the gouge. However, further work is required to investigate the roles of specific minerals, e.g. quartz content. During the reactivation phase of testing all tests reactivated, releasing small amounts of energy. This indicates that in these basic conditions natural fractures and faults will reactivate during the hydraulic stimulation if critically stressed. Furthermore, more variables should be investigated in the future, such as the effect of fluid injection rate and type of fluid.
Gas Phase Dehydration Using Hydrogels J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-25 Thevaruban Ragunathan, Xingguang Xu, Colin D. Wood
Hydrogels are cross-linked networks of water soluble polymers that have the potential to be used in the dehydration of wet gas. In this work, the uptake of hydrogels and molecular sieves were assessed in controlled humidity environments including in the presence of steam (100% relative humidity) and under pressurized conditions (6 MPa). The recyclability of the hydrogels and molecular sieves at 115ºC was also studied. At 98% humidity, the hydrogel was able to absorb twice its own mass while molecular sieves were only able to adsorb 0.3% of their mass. In the presence of steam (100% relative humidity), hydrogels absorb a maximum of approximately 23 times the absorbent's own mass while the molecular sieves merely adsorb an average of 0.4 times the adsorbent's mass under the identical experimental condition. Under pressurized conditions, hydrogels were able to absorb a maximum of approximately 6 times the absorbent's initial mass and an approximate of 0.25 times the adsorbent's initial mass. In terms of the recyclability, regeneration time and temperature the hydrogels show improved performance compared to molecular sieves. The superior uptake is due to the fundamentally different mechanism of dehydration of the hydrogel which results from swelling of the particles. This creates issues in terms of swelling and blocking of a dehydration column so methods to overcome this were explored by supporting the hydrogel. Owing to the outstanding water uptake performance, fast and complete regeneration, and readily available commercial supply, the hydrogel is considered as a viable and economical alternative to the commonly applied molecular sieve for gas phase dehydration.
Mathematical model of fractured horizontal well in shale gas reservoir with rectangular stimulated reservoir volume J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-25 Zhao Yulong, Zhang Liehui, Shan Baochao
Production performance analysis of shale gas development has posed a great challenge for scientific researchers owing to the complex percolation mechanisms and massive hydraulic fracturing. The unique accumulation and transporting mechanisms in multiscaled shale pores, such as adsorption, desorption, diffusion, and slippage, lead to gas seepage behaviors deviating from Darcy flow. Compared to previous studies, this paper presents a comprehensive mathematical model incorporating all the above percolation mechanisms for multistage fractured horizontal wells, in which rectangular stimulated reservoir volume (SRV) is taken into account. A numerical solution for such a complex model is obtained by extending the boundary element method to application. The verification of our method is confirmed by comparison to semi-analytical results of a simplified model. From the well testing type curves, nine flow regimes were identified, most of which are not observed in conventional linear flow models. The effects of sensitive parameters, such as fracture number, size and permeability of the SRV, and formation permeability, on pressure type curves were investigated. The comprehensive model in this paper provides another method to guide the development of shale gas reservoirs, including interpretation of formation properties, guiding fracturing design, and conducting post-fracture evaluation.
Gas-condensate flow modelling for shale reservoirs J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-24 Ismail Labed, Babs Oyeneyin, Gbenga Oluyemi
Condensate banking is the most challenging engineering problem in the development of gas-condensate reservoirs where the condensate accumulation can dramatically reduce the gas permeability resulting in impairment of wells productivity. An accurate assessment of condensate banking effect is important to predict well productivity and to diagnose well performance. Traditionally, Darcy law, combined with relative permeability models, has been used for modelling condensate banking effect in conventional reservoirs. This approach is also widely adopted in reservoir engineering commercial tools. However, for shale gas-condensate reservoirs, the gas flow deviates from Darcy flow to Knudsen flow due to the very small pore size in shale matrix (3–300 nm), compared to conventional reservoirs (10–200 μm). This gas flow is highly dependent on pore size distribution and reservoir pressure. In this paper, the effect of condensate saturation on Knudsen flow in shale matrix kerogen is investigated using a 3D pore network with a random pore size distribution. The Knudsen flow is incorporated at the pore level and gas permeability is evaluated for the whole network. In addition, the pore distribution effect in terms of log-normal mean and standard deviation is investigated. The concept of relative permeability in Darcy flow is extended to Knudsen flow by defining a new parameter called relative correction factor ξ r e l to evaluate the effect of condensate banking on Knudsen flow. This parameter can be employed directly in reservoir engineering tools. Simulation results showed that the relative correction factor is not only dependent on condensate saturation but also on pressure. This is due to the impact of pressure on the contribution of pore size ranges into the gas flow. In addition, results showed the effect of the pore size distribution where the standard deviation controls mainly the behaviour of Knudsen flow under condensate saturation. Disregarding this effect can lead to an overestimation of Knudsen flow contribution in well production under condensate banking effect.
Characterization of tight-gas sand reservoirs from horizontal-well performance data using an inverse neural network J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-24 B. Kulga, E. Artun, T. Ertekin
Characterization of a tight-gas sand formation using data from horizontal wells at isolated locations is challenging due to the inherent heterogeneity and very low permeability characteristics of this class of resources. Furthermore, characterizing the uncontrollable hydraulic-fracture properties along the horizontal wellbore requires financially demanding and time consuming operations. In this study, a reservoir characterization model for tight-gas sand reservoirs is developed and tested. The model described is based on artificial neural networks trained with a large number of numerical-simulation scenarios of tight-gas sand reservoirs. The model is designed in an inverse-looking fashion to estimate the reservoir and hydraulic-fracture characteristics, once known initial conditions, controllable operational parameters, and observed horizontal-well performance are input. Validation with blind cases by estimating reservoir and hydraulic-fracture characteristics resulted in an average absolute error of 20%. The model was also tested successfully with published data of an average-performing well in the Granite Wash Reservoir. A graphical-user-interface application that enables using the model in a practical and efficient manner is developed. Practicality of the model is also demonstrated with a case study for the Williams Fork Formation by obtaining probabilistic estimates of reservoir/hydraulic-fracture characteristics through Monte Carlo simulation that incorporates the ranges of observed production performance.
Theoretical overview of hydraulic fracturing break-down pressure J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-24 K.H.S.M. Sampath, M.S.A. Perera, P.G. Ranjith
The precise prediction of the break-down pressure is imperative to define the pumping schedule and the relevant stimulation parameters of a hydraulic fracturing process. A number of theoretical models have been derived based on different approaches to predict the break-down pressure, under various field/in-situ conditions. Although, the analytical models have been evolved over time, disagreements exist between the theoretical predictions and the laboratory/field results. This paper comprehensively reviews the derivations, evolutions and limitations of most of the existing break-down models and provides suggestions for further improvements. Among a number of theoretical approaches, stress intensity factor-based approach and the energy release rate-based approach give more reliable predictions, which are in line with most of the laboratory and field results. The tensile strength-based approach is commonly used to derive break-down models, but often provides slightly over/under estimations. Shear-based approach is an oversimplified approach and rarely used for the theoretical predictions. The approaches share many similarities, thus advanced models have been developed by combining the theories to precisely predict the break-down pressure. The actual hydraulic fracturing operation is rather a complex process, which involves a number of governing factors including reservoir and fracking fluid properties. Derivation of a global theoretical model is beyond the bound of possibility, as the modelling of break-down pressure for a given reservoir requires specific details of the particular operation and the in-situ conditions. The fracking with non-aqueous or mixture of fracturing fluids can be much complex due to multifaceted fluid properties, interactions, flow behaviour and phase change, thus requires more analytical, numerical simulations and laboratory/field experiments prior to implementation of large scale field projects.
Determination of stimulated reservoir volume and anisotropic permeability using analytical modelling of microseismic and hydraulic fracturing parameters J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-23 Yew Kwang Yong, Belladonna Maulianda, Sia Chee Wee, Dzeti Mohshim, Khaled Abdalla Elraies, Ron CK. Wong, Ian D. Gates, David Eaton
The concept of stimulated reservoir volume (SRV) provides a link between well productivity, the observed distribution of microseismic events and fracture networks that are created or enhanced during well completion. The SRV dimensions are affected by both reservoir geomechanical properties and hydraulic fracturing parameters. This research focuses on the determination of anisotropic permeability and the estimation of the SRV dimensions by refining the existing 3D linear diffusivity partial differential equation (PDE). The anisotropic permeability and the SRV are both calibrated using the analytical solution, based on determination of microseismic events that are inferred to be connected back to the horizontal wellbore. An improved analytical 3D linear diffusivity PDE model is proposed to simulate the anisotropic permeability and the SRV dimension with higher percentage of microseismic events. In a case study from western Canada, the proposed approach yields improved the prediction of the SRV dimension that consists 90% of microseismic events within the SRV, compared to the existing analytical solution predicts the SRV dimension that consists 70% of microseismic events within the SRV. The SRV anisotropic permeability is also estimated using the proposed model with the average values of 0.1897 mD (SRV length direction), 0.1112 mD (SRV width direction), and 0.0138 mD (SRV height direction) from 12 stages hydraulic fracturing. The simplicity of the proposed model allows the SRV dimensions estimation before hydraulic fracturing operations.
Fiber Optic Distributed Sensing Technology for Real-time Monitoring Water Jet Tests: Implications for Wellbore Integrity Diagnostics J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-23 Yankun Sun, Ziqiu Xue, Tsutomu Hashimoto
Distributed fiber optic sensing (DFOS), a rapidly evolving fiber-optic based technology for permanent well-based and geophysical monitoring for CO2 geological storage (CGS) has attracted more attentions to investigate in multiple scales. In this study, two field trial wells were drilled, one well with 300 m depth in Mobara and the other well with 880 m in Ichihara, Japan and DFOS cables were deployed behind well casings. High-pressure water jet tests are performed at constant location of 127 m depth and at changeable jet locations with 1.33 m/min and 0.51 m/min pulling speeds in the 300 m well. Then, this DFOS system was utilized to monitor the water jet along the entire length of the 880 m well with 1.2 m/min descending speed. The temperature profiles induced by water jet could be real-time monitored and analyzed the cementing quality to further evaluate the wellbore integrity. The results show that the temperature abnormal zones have a good reverence with poor cementing in the two wells, which compared well with geophysical well logging data. Therefore, permanently installed DFOS wells will enable an efficient and simpler tool to diagnose the wellbore integrity for the CGS monitoring projects via the field water jet tests.
Separation performance of CO2 by hybrid membrane comprising nanoporous carbide derived carbon J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-22 Musa O. Najimu, Isam H. Aljundi
Experimental and numerical investigations of permeability in heterogeneous fractured tight porous media J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-22 Bao Jia, Jyun-Syung Tsau, Reza Barati
Analyzing gas flow behavior is important for production prediction in heterogeneous fractured shale reservoirs, which is complex due to the presences of nanopores and high-degree heterogeneity in these complex flow network. First, we applied the discrete fracture model to simulate gas pulse-decay experiments in core plugs with different configurations. The effective permeability ratio was proposed to evaluate the effects of heterogeneity, fracture, and vug on the flow behavior. Second, we performed pulse-decay experiments on one intact fractured shale core to examine the effects of pore pressure and effective stress on permeability variations. The measured pressure profiles were history matched by numerical methods to obtain the porosity and permeability of matrix and fracture. The matching degree is evaluated by the Global Matching Error (GME). Our results highlight the positive impact of dense fracture network to improve flow capacities in the tight reservoir: effective permeability of the fractured core with 8 pairs of 1.3-cm connected fractures increases 4.07 times that of the un-fractured core. Vugs might be important as well if they connect adjacent fracture networks, but their own contribution to flow capacity is negligible: effective permeability increases only 1.00 to 1.02 times when the number of vugs increase from 3 to 35. The GME ranges from 0.04% to 0.2% for history matching of the fractured core. Core heterogeneity is exhibited more obviously when gas flows through under low pressure than under high pressure, which can be used to guide the design of pulse-decay experiment properly depending on the purpose. The main contributions of this study are that we constructed the finite-element based numerical model to simulate the pulse-decay experiment, proposed a methodology to upscale core permeability when fractures and vugs are present, and measured porosity and permeability for the matrix and fracture simultaneously in one fractured core over a wide range of pressure and effective stress.
A Transient Simulation Model to Predict Hydrate Formation Rate in both Oil- and Water-Dominated Systems in Pipelines J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-21 Yan Wang, Carolyn A. Koh, J. Alejandro Dapena, Luis E. Zerpa
Carbon isotopic characteristics of CH4 and its significance to the gas performance of coal reservoirs in the Zhengzhuang area, Southern Qinshui Basin, North China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-21 Junyan Zhang, Dameng Liu, Yidong Cai, Yanbin Yao, Xu Ge
To better understand the law of gas generation, migration and accumulation of the No. 3 coal seam in the Zhengzhuang (ZZ) area, Southern Qinshui Basin, North China, isotopic geochemical experiments, including determination of the molecular and isotopic compositions of coalbed gas and the hydrogen and oxygen isotope decompositions of the coalbed methane (CBM) co-produced water, as well as the geological and hydrogeological surveys, were conducted. The results reveal that CBM from the No. 3 coal seam is dominated by CH4 (46.5 - 99.54vol%) and the carbon isotope ratio of the produced CH4 (δ13C1) ranges from -28.7‰ to -57.2‰. Secondary thermogenic CH4 caused by a tectonic thermal event in the Yanshan Epoch is the main gas source, with a small amount of secondary biogenic gas generated from methyl-type fermentation. The carbon isotope is fractionated due to the terrain change of the No. 3 coal seam, a discrepancy in internal structures of basin and the flushing of the groundwater. Geological and hydrogeological information shows that fluid pressure traps for gas preservation will easily form in the northern and eastern deep stagnation areas, or local syncline in the central part. Based on the experimental data and CBM well data, the gas content and gas saturation have a logarithmic correlation with δ13C1. These investigations may serve the exploration of favorable zones for gas accumulation and exploitation of CBM with the geochemistry and carbon isotope composition of CH4 in the study area.
A correlation to quantify hydrate plugging risk in oil and gas production pipelines based on hydrate transportability parameters J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-20 Piyush Chaudhari, Luis E. Zerpa, Amadeu K. Sum
Solid gas hydrate particles may form in oil and gas pipelines in the presence of water at high pressures and low temperatures; typical conditions of subsea hydrocarbon pipelines used in offshore facilities. Gas hydrate particles that form within these pipelines may create blockages following a complex multi-physics phenomenon involving emulsification, hydrate formation and subsequent hydrate particle agglomeration and bedding. Here we present a conceptual model depicting different hydrate plugging risk levels associated with oil-dominated systems, developed based on observations from high-pressure flowloop experiments. Using experimental measurements from these experiments, we develop a mathematical correlation to classify and quantify hydrate plugging risk in oil and gas pipelines. The correlation is based on assessable parameters that govern hydrate transportability in pipelines, such as, liquid loading, mixture velocity, fluid properties, and hydrate amount. A parametric study is performed using the proposed hydrate plugging risk correlation showing the plugging risk increasing with decrease of liquid loading and fluid velocity. The hydrate plugging risk estimation approach using the proposed correlation is illustrated for steady-state and transient operations of a long subsea tieback facility based on numerical transient multiphase flow simulations. The hydrate plugging risk is found to evolve over time as a function of hydrate volume fraction along the pipeline length. The hydrate plugging risk quantification presented, in terms of Hydrate Risk Evaluator, in this study represents an advancement in the area of hydrate risk assessment, as it can be used to assess hydrate plugging risk and consequently operational safety of hydrocarbon transport pipelines from the flow assurance perspective.
Gas Flow Field Evolution around Hydraulic Slotted Borehole in Anisotropic Coal J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-18 Yang Zhao, Baiquan Lin, Ting Liu, Qingzhao Li, Jia Kong
Amine wetting evaluation on hydrophobic silane modified polyvinylidene fluoride/silicoaluminophosphate zeolite membrane for membrane gas absorption J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-18 N.A. Ahmad, C.P. Leo, A.L. Ahmad
Experimental investigation of the influence of strain rate on strength; failure attributes and mechanism of Jhiri shale J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-14 Bankim Mahanta, T.N. Singh, P.G. Ranjith, Vikram Vishal
The modern improved engineering technologies in the field of rock mechanics and the successful identification of the hydrocarbon potential of gas shales have turned the tight shale formations as a profitable resource for the natural gas. In the current study, Jhiri shale was tested for its strength; deformational failure attributes and mechanism at different strain rates in order to understand the dependence of the deformation rate upon various geomechanical properties. The rock samples were subjected to varied strain rates during loading and the resultant geomechanical properties such as uniaxial compressive strength (UCS), tensile strength (σt), Young's modulus (E), failure strain ( ε f ), mode I and mode II fracture toughness (KIC and KIIC) and brittleness index (B1 and B2) were determined in each case. The stress-strain behaviour of the Jhiri shale was estimated at four different strain rates that varied from 1.7 x 10-2 s-1 to 7.9 x 10-5 s-1. It was found that all of the mechanical parameters of the rock that are mentioned above, except for the failure strain, increased with increasing strain rates. Such behaviour of the rock due to the strain rates may be due to stress redistribution during grain fracturing. At a strain rate of 7.9 x 10-5 s-1, UCS, tensile strength, mode I fracture toughness and mode II fracture toughness of Jhiri shale were found to be 25.45 MPa, 7.71 MPa, 0.171 MPa m1/2 and 0.083 MPa m1/2, respectively, which increased up to 50.57 MPa, 13.06 MPa, 0.565 MPa m1/2 and 0.467 MPa m1/2, respectively, at a strain rate of 1.7 x 10-2 s-1. Critical and appropriate empirical equations have been proposed to evaluate the strain-rate dependency of the mechanical properties of the rock.
Cost-Effective Alkylammonium Formate-Based Protic Ionic Liquids For Methane Hydrate Inhibition J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-11 Tausif Altamash, Majeda Khraisheh, M. Fahed Qureshi, Mohammad Ali Saad, Santiago Aparicio, Mert Atilhan
Leak Detection in Low-Pressure Gas Distribution Networks by Probabilistic Methods J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-08 Payal Gupta, Thaw Tar Thein Zan, Mengmeng Wang, Justin Dauwels, Abhisek Ukil
The presence of leaks is a prevalent issue for aging gas distribution systems across the globe. These events, if not detected in time, may bring about environmental and health hazards, besides economic losses. Therefore, the development of efficient detection, quantification, and localization methods is crucial to all gas companies worldwide. In this paper, we present a leak monitoring system, called Leak Analytics System (LAS) using a probabilistic approach to determine the location and the rate (severity) of leakage in low-pressure gas distribution networks. This work aims to develop a robust, cost-effective, and real-time online monitoring system for low-pressure gas distribution networks. The leakage events are estimated using pressure and flow data obtained from steady-state modeling of the gas network. The robustness of the methodology is illustrated by analyzing gas networks in the presence of measurement errors, which account for unavoidable sensor noise in flow and pressure data. The feasibility of the proposed method is demonstrated on a small artificial gas network. Moreover, the method is applied to a section of the Singapore gas distribution network for a single as well as multiple leak scenarios. It is also experimentally shown that the severity of the leak and the location for a single leak scenario can be determined within an accuracy of 95% and 80% respectively, even in the presence of strong noise.
Film former corrosion inhibitors for oil and gas pipelines - A technical review J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-07 M. Askari, M. Aliofkhazraei, S. Ghaffari, A. Hajizadeh
Pipelines play a significant role in production and transportation of oil and gas. The use of film-former corrosion inhibitors is one of the most economical and reliable methods of controlling internal corrosion of sour oil, sweet oil and gas pipelines. In this paper, the general mechanisms of internal corrosion in oil and gas pipelines, formulation and chemical structure of film-forming organic corrosion inhibitors and their different types were reviewed. The mechanisms of film formation of these corrosion inhibitors are also reviewed based on electrochemical techniques. In addition, the selection process of corrosion inhibitors for pipelines is discussed.
Parameter Determination for A Numerical Approach to Undeveloped Shale Gas Production Estimation: The UK Bowland Shale Region Application J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-02 Ukadike Nwaobi, Gabrial Anandarajah
The estimation of production potential provides the foundation for commercial viability appraisal of natural resources. Due to uncertainty around production assessment approaches in the unconventional petroleum production field, an appropriate production estimation methodology which address the requisite uncertainty at the planning stage is required to guide energy policy and planning. This study proposes applying the numerical unconventional production estimation method which relies on geological parameters, (pressure, porosity, permeability, compressibility, viscosity and the formation volume factor) as well as the rock extractive index (a measure of technical efficiency). This paper develops a model that estimates the appropriate values for four of these parameters based on a depth correlation matrix while a stochastic process guides two based on known data range. The developed model is integrated with a numerical model to estimate gas production potential. The developed framework is eventually applied to undeveloped shale gas wells located in the Bowland shale, central Britain. The results account for below ground uncertainty and heterogeneity of wells. A sensitivity analysis is applied to consider the relative impacts of individual parameters on production potential. The estimated daily initial gas production rate ranges from 15,000scf to 319,000scf while estimated recovery over 12 years is approximately 1.1bscf in the reference case for wells analyzed.
A pragmatic approach for identifying effective lacustrine shale payzones J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-01 Hucheng Deng, Xiaofei Hu, Tingting Huang, Zakaria Belmir, Bo Bi, Huazhou Andy Li
Design of experiments for optimising acceptance calibration criteria for pressure and temperature transmitters of gas flowmeters J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-08-01 Matheus J.P. Guerra, Elcio Cruz de Oliveira, Maurício N. Frota, Rui Pitanga Marques
Calibration acceptance criteria for pressure and temperature measuring devices used in orifice plate gas flowmeters were specified. The study was motivated by the introduction of a Brazilian regulation that specifies technical and legal requirements for in-field measurements of oil and gas flows. In compliance with international best practices, the applicable regulation, which establishes uncertainty levels for flow measurements (1.5% for fiscal/custody transfer measurements and 2% for appropriation measurements), did not set up limits of acceptance of uncertainties associated with pressure and temperature measuring devices. The effects of these uncertainties in measurements were evaluated. By making use of the Design of Experiments and Response Surface Method (RSM), acceptance criteria were sought to comply with the applicable regulation. The use of the methodology proved to be very useful as low uncertainties were obtained in all ten metering stations investigated. In the worst cases (in three stations only), uncertainties were lower than 0.2% of the correspondent full-scale reading. The response surface methodology also showed that the minimum measuring capacity to meet the regulatory uncertainty requirements are 0.05% for differential pressure calibrators and 0.01% for the static pressure (relative to the full-scale reading).
Permeability Evolution in Natural Fractures and their Potential Influence on Loss of Productivity in Ultra-Deep Gas Reservoirs of the Tarim Basin, China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-31 A.P.S. Selvadurai, Dujie Zhang, Yili Kang
This article examines the influence of working fluids on stress-induced permeability alteration in an ultra-deep tight sandstone gas reservoir. Permeability alteration during hydrostatic compression and infiltration of oil-based drilling fluids and acidizing fluids was investigated in a laboratory setting. The laboratory results indicated that the permeability of fractures in the tight sandstone was influenced by both the alterations in the stress state and type of fluid treatment. In general, the permeability alterations in the fractures are irreversible and cannot be completely eliminated. The stress sensitivity coefficient of the rock samples that were untreated, treated with drilling fluids or treted with acidizing fluids were, on average, 0.45, 0.58 and 0.67, respectively. The high lithic fragment content, multi-scale natural fractures and the rock property changes induced by the working fluids are thought to be the factors controlling the permeability stress sensitivity. A computational procedure was used to assess the influence of various fracture permeability evolution models on the well performance. Simulation results show that the deeper the invasion depth of working fluids and unsuitable drawdown pressures have a significant negative influence on the cumulative production. Finally, a control strategy for addressing stress-sensitivity damage and the influence of production fluids in ultra-deep tight sandstone gas reservoirs is proposed.
Effective Evaluation of Shale Gas reservoirs by Means of an Integrated Approach to Petrophysics and Geomechanics for the Optimization of Hydraulic Fracturing: A case Study of the Permian Roseneath and Murteree Shale Gas Reservoirs, Cooper Basin, Australia J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-29 Omer Iqbal, Maqsood Ahmad, Askury abd Kadir
Brittleness and in-situ stress states are known critical indicators for screening prospected layers during hydraulic fracturing in unconventional reservoirs. Brittleness can be inferred from mechanical parameters and mineralogical data, primarily using empirical relations, although an incomplete dataset limits their use. Therefore, a dataset with a systematic framework was designed based on well logs, and which details core data spudded in the Permian Roseneath and Murteree shales from the Cooper Basin, Australia. Petrophysical and geomechanical models were designed to indicate shale mineralogy, total organic richness, porosity, in-situ stress conditions, brittleness index, pore pressure, and fracture pressure gradient. After a review of various definitions of brittleness index (BI) in recent literature, it will be argued that the definition of a brittleness index is with reference to either elastic parameters, mineralogical composition, or strength parameters. Consequently, a higher brittleness index is assigned to quartz and siderite rich rocks than to clay, organic matter, and porosity rich rocks. Some recent definitions of BI are therefore useful for indicating rock types, but brittle/ductile behavior is not necessarily any indicator of brittle/ductile failure during stimulation. It is therefore proposed that an accurate BI must be incorporated into a geomechanical model. This new model will comprise the following properties: elastic and strength parameters, in-situ stress state, fracture pressure gradient, and pore pressure. Such an integrated model can be used to find 1) Fracture barriers (the layers hindering fracture growth); 2) Potential layers that enhance fracture growth, and; 3) Direction of induced fractures on the bases of the stress regime.
Experimental and Modeling Studies on the Prediction of Liquid Loading Onset in Gas Wells J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-26 Yonghui Liu, Chengcheng Luo, Liehui Zhang, Zhongbo Liu, Chunyu Xie, Pengbo Wu
Liquid loading is a major problem that limits production of gas wells. When liquid loading occurs, the gas well will suffer a rapid decrease in gas flow rate and eventually cease. An accurate prediction of liquid-loading onset is vital for operators to optimize production or take other measures in time. Through a careful review of previous studies, it's more reasonable to relate liquid-loading onset to liquid-film reversal rather than liquid-droplet reversal. However, few mechanistic approaches based on liquid-film reversal are available to predict the critical gas velocity. Furthermore, these models have complicated calculation and conservative results. This paper develops a more comprehensive and simpler analytical model for prediction of liquid-loading onset on the basis of liquid-film-reversal criterion. To reach this goal, experimental investigation has been conducted to analyze the effect of inclined angle and liquid velocity on the critical gas velocity. The Belfroid et al. (2008) angle-correction term has been adopted in the new model to predict critical gas velocity in inclined pipes. After validation against laboratory and field data from the published literature, this model has better performance compared with other models. Considering its simple form and high accuracy, the new model can provide a convenient approach for gas production engineers to predict critical gas flow rate.
Study of the Deformation Characteristics and Fracture Criterion of the Mixed Mode Fracture Toughness of Gypsum Interlayers from Yunying Salt Cavern under a Confining Pressure J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-26 Tao Meng, DongHua Zhang, Yaoqing Hu, Xie Jianlin, Song Sufang, Li Xiaoming
Based on the project background of salt caverns used for oil and gas storage in laminated salt rock, this study examined the combined mode fracture toughness, the fracture pattern, the morphological evolution of fracture surfaces, and the fracture criterion of gypsum interlayers under confining pressure. Series of laboratory tests, including fracture strength tests and scanning electron microscopy tests, were performed at four confining pressures. The results indicate that the failure load of gypsum increased with the increase of confining pressure. By contrast, the failure load of specimens first decreased and then increased with the increase of pre-existing flaw inclination angle. As the confining pressure increased, the residual energy gradually decreased and the brittleness index gradually increased. Although increasing the confining pressure (i.e., 1–7 MPa) shifted the behaviour of a specimen from brittle to ductile, the major failure mechanism still fell within the brittle failure regime. For the case where the confining pressures are 1 MPa and 3 MPa, cleavage fractures characterized by cleavage steps, river lines, and tearing ridges were observed on the surface, indicating that typical brittle failure occurred in the specimens. However, typical ductile failure occurred in the specimens subjected to confining pressures of 5 MPa and 7 MPa. Subsequently, the size of the fracture process zone at varying confining pressures was obtained using a modified maximum tangential stress criterion to optimally fit the experimental results. The results of this study can be used to evaluate the safety of salt caverns in bedded salt formations.
Numerical Simulation of Black Powder Removal Process in Natural Gas Pipeline Based on Jetting Pig J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-26 Hang Zhang, Qianyue Zheng, Dongliang Yu, Na Lu, Shimin Zhang
Black powder is a common contamination problem for natural gas pipeline all over the world. In this study, a method based on the jetting pig is proposed to remove the black powder in natural gas pipeline. Numeric simulations based on the computational fluid dynamics method, were conducted to investigate the dynamic migration process of black powder particles in the jetting field by using the multiphase flow model. Diameter of black powder particles, initial stacking concentration, stacking height and the inlet pipeline pressure were taken into consideration to study the black powders jetting cleaning effect. By using discrete phase model, considering the coupling between solid and gas, the path of black powder with different diameters was traced, and the movements of black powder in horizontal and vertical directions were analyzed, which reflect the diffusion law of black powder. Our results show that the higher the initial stacking concentration and larger the particle diameter, the lower the cleaning efficiency of black powder. The horizontal position of black powder with particle diameter of 20 μm were obviously ahead of other kinds of particle, and the horizontal velocity decreased slowly. The vertical velocity of black powder with particle diameter of 20 μm were also obviously lower than other kinds of particle. While other five kinds of particle with particle diameter over 20 μm would gradually stick to the wall until they stop moving and secondary settlement will occur. Our results can contribute to the mechanical design of jetting pig and optimal design of pigging process for black powder cleaning in natural gas pipeline.
Tracing and Prediction Analysis of an Urban Pipeline Leakage Accident based on the Catastrophe DBN Model J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-25 Ze yang Qiu, Wei Liang, Laibin Zhang
With trends in urbanization, many underground pipelines have been constructed, forming a huge spider web-like network, and accidents in such systems can lead to disastrous consequences, as observed in the Qingdao and Kaohsiung gas explosion accidents. For such a complex system, questions related to identifying the accident causes and predicting the evolving trends represent research challenges. Such accidents are often catastrophic and dynamic, and traditional methods are only appropriate for static accident analyses. Based on the above problems, an accident tracing and prediction method based on the bow-tie model and the catastrophe theory dynamic Bayesian network (DBN) model (C-DBN) is proposed in this paper. First, a fishbone diagram (FD) is used to analyze all possible causes of the accident, and the bow-tie and Bayesian network (BN) models are established according to the logical relationship. The conditional probability tables (CPTs) of the BN are obtained using the transformation rule and catastrophe theory. Dynamic analyses of the accident causes and development trends can be conducted using the powerful reasoning ability of the DBN, which can supply guidance for emergency response and rescue. Finally, the Kaohsiung gas explosion accident is used as an example to verify the feasibility of the method. The results show that the analysis results are highly consistent with the real scenario.
Preparation of MIL-101-nanoporous carbon as a new type of nanoadsorbent for H2S removal from gas stream J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-24 Mohammad Kooti, Alimohammad Pourreza, Alimorad Rashidi
In the present study, based on hydrothermal reaction, new hybrids containing metal organic frameworks MIL-101 (Cr) and nanoporous carbon (GCKP2) in different ratios from 10-50% were synthesized. The common methods such as Fourier transform infrared (FT-IR), thermogravimetric analysis (TGA), Field Emision Scanning Electron Microscopy (FE-SEM) and N2 adsorption-desorption were used for characterization of these hybrids. The prepared materials were accordingly employed as adsorbent for H2S removal process and the results showed adsorption of 10, 6.2, 7.9, 6.0 mmol/g at pressure around 9 bar for MIL-101, hybrids containing 10%, 30%, and 50% of nanoporous carbon, respectively. Furthermore, the adsorption equilibrium isotherms were used to describe the experimental data and the Langmuir-Frendlich equation appeared to provide a better fit for the H2S adsorption by all synthesized hybrids. Relatively high H2S adsorption capacity, easy and safe handling, and scalable use are some of the advantages of the present nanoadsorbents.
An innovative model to evaluate fracture closure of multi-fractured horizontal well in tight gas reservoir based on bottom-hole pressure J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-07-19 Jiazheng Qin, Shiqing Cheng, Youwei He, Yang Wang, Dong Feng, Dingyi Li, Haiyang Yu
Due to formation damage and fracture closure, the effective fracture half-length is usually much shorter than the designed half-length. However, available pressure transient analysis (PTA) models of multi-fractured horizontal wells (MFHWs) hardly consider the effect of non-uniform fracture closure of double-segment fractures (DSF) on transient pressure characteristics, which could bring about incorrect results since conductivity and flux density of fracture segment near wellbore are much larger than those of fracture segment far from wellbore. To fill this gap, this paper aims at presenting a novel approach to evaluate effective fracture properties through PTA more accurately. This new model allows each hydraulic fracture of MFHW consists of two individual segments with their own properties (e.g. length, conductivity and flux density, etc). Pressure and its derivative curves are developed for flow-regime analysis. The solution is validated with numerical results in Saphir. Sensitivity analysis further seek the feasible application on interpretation of effective fracture properties. The field application demonstrates the practical use of the proposed model in estimating fracture half-length with different conductivity during production stage to identify the extent of fracture closure using pressure data.
Some contents have been Reproduced by permission of The Royal Society of Chemistry.
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