Diagenesis of microbialites in the lower Cambrian Qingxudong Formation, South China: Implications for the origin of porosity in deep microbial carbonates J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-12 Qian Tan, Zejin Shi, XiuQuan Hu, Yong Wang, YaMing Tian, ChangCheng Wang
Understanding microbial carbonate is one of the most challenging issues in the field of carbonate sedimentology and reservoir. The biotic and abiotic processes that control microbial carbonate precipitation are becoming more established, but the influence of subsequent diagenesis on microbial carbonate reservoirs has not been adequately studied. Here, we describe microbial carbonate from the lower Cambrian Qingxudong Formation in southeastern Sichuan Basin to assess their formation, textures and subsequent diagenesis. Six stages of calcite cementation (Calcite-1 to Calcite-6) and four stages of dissolution (Dis-1 to Dis-4) were identified in microbialites of the Qingxudong Formation. Stromatolites and thrombolites have a different porosity evolution. Sedimentary processes are the fundamental controlling factors of creating pre-existing pores in stromatolites. For thrombolites, the formation of pre-existing pores is attributed to island dissolution and dolomitization in near-surface processes. Microbial metabolic activities contribute more to the dissolution and dolomitization than mixing water. Meteoric water dissolution (Dis-1) in synsedimentary processes and microbial dissolution (Dis-2) in near-surface processes are the fundamental control factors of porosity creation in microbial carbonate of Qingxudong Formation. Thermochemical sulfate reduction (TSR) is a double-edged sword for the porosity development. The destructive effect of TSR on microbial carbonate reservoirs is greater than the constructive effect. The microbial carbonate reservoirs, especially the fabric-destructive dolomite (Dol-2) evolved by thrombolites, have great potential for gas exploration in the Qingxudong Formation. This study is especially useful for further understanding deeply buried microbialite reservoir formation and development, and deep hydrocarbon exploration in this basin and elsewhere worldwide.
Quick approximate elastoplastic solutions of wellbore stability problems based on numerical simulation and statistical analysis J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-12 Chang Huang, Babak Akbari, Shengli Chen
Wellbore instability has been a chronic issue for well operators over several decades in petroleum industry. Traditional linear elastic models may sometimes fail to provide a proper mud weight window for drilling engineers. Elastoplastic models can better represent the rock behavior and, therefore, more accurately evaluate the risk of wellbore instability. However, elastoplastic models have failed to gain popularity in the industry because of the model complexity and computation cost. This work proposes an approximating method in a novel manner, incorporating both the validity of the elastoplastic constitutive model and the rapidity of the linear elastic model to predict wellbore behavior. The non-associative strain hardening Drucker-Prager elastoplastic model is used. The relationship between the yielded zone area calculated by the elastoplastic model and the pseudo-yielded zone area calibrated by the linear elastic model is statistically investigated. It is found that the two can be correlated with high confidence based on a set of common input parameters, like in-situ stresses, wellbore pressure, Young's Modulus, etc. Three correlation equations are provided according to the value range of the predicting terms and an application example is addressed at the end. In conclusion, this approach will help engineers make reliable wellbore stability decisions without resorting to sophisticated elastoplastic models. The equations can be directly used in simple spreadsheet functions or real-time data processing schemes to make faster and more efficient decision.
Numerical simulations of gas production from Class 1 hydrate and Class 3 hydrate in the Nile Delta of the Mediterranean Sea J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-12 Şükrü Merey, Sotirios Nik Longinos
Gas hydrate reservoirs are considered as near-future energy resources in the world. As well as the many places in the world, there is also gas hydrate potential in the Mediterranean Sea. In this study, by using the literature data, it was aimed to understand whether the Mediterranean Sea includes necessary parameters for producible gas hydrate reservoirs. It was shown that the Mediterranean Sea contains all of these parameters (source gas, appropriate pressure and temperature, coarse sand potential, etc.). The only bottom-simulating reflections (BSRs) were detected in the Nile Delta of the Mediterranean Sea. In the conditions of these BSRs, the gas production potentials from Class 1 hydrate and Class 3 hydrate were analyzed by applying depressurization method with and without wellbore heating at 50 °C with HydrateResSim numerical simulator. It was observed that both gas hydrate layer in Class 1 and gas hydrate in Class 3 hydrate dissociated fully. However, the contribution of free gas layer in Class 1 hydrate on cumulative gas production was enormous so it was stated much more exploration studies are necessary in the Mediterranean Sea to detect Class 1 hydrates and BSRs. During the simulations, ice formations along the wellbores were not detected for both Class 1 hydrate and Class 3 hydrate. Hydrate reformation at 3.5 MPa and below 3.5 MPa in Class 3 hydrate was observed along the wellbore but the wellbore heating at 50 °C was enough to avoid gas hydrate reformation along the wellbore. The warm temperature of the sediments of the Mediterranean Sea was advantageous for effective depressurization. However, it was proved that methane-carbon dioxide replacement method is not applicable for the potential Mediterranean Sea gas hydrates due to the warm seafloor temperature (∼14 °C) of the Mediterranean Sea.
Reconstruction of 3D porous media using multiple-point statistics based on a 3D training image J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 Yuqi Wu, Chengyan Lin, Lihua Ren, Weichao Yan, Senyou An, Bingyi Chen, Yang Wang, Xianguo Zhang, Chunmei You, Yimin Zhang
To date many methods of constructing porous media have been proposed. Among them, the multiple-point statistics (MPS) method has a unique advantage in reconstructing 3D pore space because it can reproduce pore space of long-range connectivity. The Single Normal Equation Simulation (SNESIM) is one of most commonly used algorithms of MPS. In the SNESIM algorithm, the selection of training image is vital because it contains the basic pore structure patterns. In the previous reconstructions of 3D porous media using SNESIM, a 2D slice was usually employed as the training image. However, it is difficult for a 2D slice to contain complex 3D pore space geometry and topology patterns. In this paper, a 3D training image is used in order to provide more realistic 3D pore structure features. Besides, a multi-grid search template is applied for the purpose of capturing the pore structures of different scales and speeding up the reconstruction process. Two sandstone cores are taken as test examples and the 3D porous media are reconstructed. The two-point correlation function, pore network structure parameters and absolute permeability are applied as the evaluation indexes to validate the accuracy of the reconstructed models. The comparison result shows that the reconstructed models are in good agreement with the real model obtained by X-ray computed tomography scanning in the pore throat geometry and topology and transport property, which justifies the reliability of the proposed method.
Numerical simulation of pipeline hydrate particle agglomeration based on population balance theory J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 GuangChun Song, YuXing Li, WuChang Wang, Kai Jiang, Zhengzhuo Shi, Shupeng Yao
In offshore operations, the agglomeration between hydrate particles is a significant reason that could lead to pipeline hydrate plugging. Dynamic modeling and numerical simulation of pipeline hydrate particle agglomeration are of great importance to offshore hydrate management. For this purpose, a dynamic model of hydrate agglomeration was proposed and then used to simulate pipeline hydrate particle agglomeration in this paper. The dynamic model was established based on population balance equation, which took both hydrate agglomeration and hydrate breakage into consideration. Collision frequency, agglomeration efficiency, breakage frequency and size distribution of the sub particles resulting from particle breakage are four key parameters that involved in the dynamic model. Combined with several traditional solid-liquid flow models, the dynamic model was solved by the CFD software FLUENT 14.5 to simulate the agglomeration process of hydrate particles in the pipeline at different conditions. The influences of flow rate and hydrate volume fraction on the agglomeration process were analyzed emphatically. The simulation results were also compared with the calculation results of hydrate particle growth model and hydrate rheological model. The conclusions of this paper can provide guidance for the development of deep water flow assurance.
Poroperm characteristics of high-rank coals from Southern Qinshui Basin by mercury intrusion, SEM-EDS, nuclear magnetic resonance and relative permeability analysis J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 Zheng Zhang, Yong Qin, Xinguo Zhuang, Guoqing Li, Xiaoming Wang
Poroperm characteristics (porosity and permeability) of a coal seam play crucial roles in exploration and recovery of coalbed methane (CBM). In order to comprehensively understand the poroperm characteristics of high-rank coals, a series of laboratory tests including water-saturated porosity measurement, high-pressure mercury intrusion porosimetry (MIP), low-field nuclear magnetic resonance (NMR), scanning electron microscope and energy dispersive spectrometry (SEM-EDS) analysis and relative permeability tests were performed on the selected high-rank coal samples from underground coal mines in Southern Qinshui Basin, China. The cleat size distribution index (λ) and cleat tortuosity (η) were derived from the relative permeability experimental data and the correlations between these two parameters and coal rank parameters were analyzed. The results shows that: adsorption pores account for a dominant percentage in the total pore volume, while seepage-pores and fractures are poorly developed; clay minerals fill most of the micro-fractures and have a strongly negative impact on the coal permeability; the relative permeability curves for the coal samples is characterized by a higher residual water saturation, a higher water saturation at cross point, a narrow span of two-phase flow region, and a lower gas relative permeability. The cleat size distribution index (λ) is positively related to the water and gas relative permeability, while the cleat tortuosity (η) has a negative effect on fluid flow in coals. A mathematical model was proposed to relate η and λ to coal rank parameters respectively, which can be used to evaluate the relative permeability of high-rank coals. The producible porosity is very low, ranging from 0.17% to 0.37% for the high-rank coal samples, but it plays a dominant role in determining the permeability of coal. A modified producible porosity (PP) model was proposed to evaluate the absolute permeability and the effective gas permeability under the residual water saturation of high-rank coals.
Charge characteristics of adsorbed natural gas storage system based on MAXSORB III J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 Kedar Haradas Patil, Satyabrata Sahoo
The present work deals with Natural gas (methane) adsorption onto super activated carbon (MAXSORB III) and graphite mixture in order to establish the reliability of this phenomenon as a valuable storage technique of natural gas. The objective of the subject work is to optimize different design and operating parameters of the adsorbed natural gas (ANG) system subjected to variable charge and the boundary conditions. The model duly considers the real gas properties of methane and variation of adsorbed phase properties as well as the heat of adsorption with adsorbate uptake. The storage capacities, storage efficiency as well as the filling time of activated carbon bed are studied for both constant inlet flow and constant inlet pressure charging conditions. The possibility of controlling length to width ratio (L/D ratio ranging from 0.35 to 7.8) is presented which will enable to optimize the geometry of storage tank for optimal storage efficiency. The effects of variation in inlet flow rates and variation in boundary conditions (natural convection, adiabatic wall, forced convection and constant wall temperature) on storage capacity as a function of other design and operating parameters are presented. From the study it is found that for suitable L/D ratio and external heat transfer coefficient it is possible to achieve a storage capacity of 150 V/V for constant pressure charging condition within 200 s. Addition of graphite powder for thermal enhancement of system resulted in 22%–27% (for different L/D ratios) rise in storage efficiency for model subjected to constant pressure charging and forced convection whereas 41.8%–50.4% rise in storage efficiency for model subjected to constant inlet flow and forced convection.
Study on the mechanism of rupture and propagation of T-type fractures in coal fracturing J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 Yuwei Li, Zhenhua Rui, Wanchun Zhao, Yunhe Bo, Chunkai Fu, Gang Chen, Shirish Patil
Weak structures like cleats and fractures are abundant in coal rock. It can form a complex fracture system during hydraulic fracturing process. T-type fracture is generally defined as those intersected complex fractures of horizontal and vertical fractures during hydraulic fracturing of the coal bed. T-type fractures can occur during hydraulic fracturing, yet few present theory or experiments are established or carried out to figure out the underlying mechanism of T-type fractures. Compared with horizontal fractures, T-type fractures have a higher fracture conductivity, which is more conducive to the improvement of production. Therefore, it is necessary to establish theoretical models to analyze the initiation and propagation of T-type fractures. We have carried out laboratory simulation of hydraulic experiments on the one hand. On the other hand, we have observed the spatial development of T-type fractures and described the changing pattern of its propagation. The experiment results showed that hydraulic fracture initiated and extended along the vertical direction, and it formed T-type fracture when weak structures opened in the horizontal direction. According to Rupture Mechanics, we have established a calculation model to calculate the rupture and propagation of T-type fractures based on stress intensity factor and analyzed the factors that may affect fracture propagation. The findings of this paper showed that the lengths of vertical and horizontal fractures and the inclination of horizontal fractures can significantly influence the occurrence of T-type fractures. More specifically, longer horizontal fractures, shorter vertical fractures, and smaller horizontal inclination are favorable for the occurrence of T-type fractures. In the current literature, a complete theoretical model for the initiation and propagation of T-type fractures in coal bed hydraulic fracturing is still not available. This paper has established a new theoretical model for T-type fractures in hydraulic fracturing, the results of which serve as a complement and improvement for the extant mechanism study on coal hydraulic fracturing.
Polypyrrolone thermally rearranged polymeric membrane for natural gas separation applications in industry J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-11 Mohammad S. AlQahtani, Khaled Mezghani
The gas permeability performance of thermally rearranged polypyrrolone (PPL-450) membranes have been experimentally evaluated under similar industrial conditions of gas mixtures, pressures, and stage-cuts. The membranes were synthesized from 4,4'-(hexafluoroisopropylidene) diphthalic anhydride (6FDA) and 3.3′-diaminobenzidine (DAB). The thermal treatment of the PPL-450 was accomplished under vacuum at 450 °C. Several gas mixtures (binary, ternary and quaternary) were utilized to study the performance of the PPL-450 membranes for CO2 removal and helium recovery from natural gas streams. The quaternary feed gas-mixture was composed of 59% CH4, 30% N2, 10% CO2 and 1% C2H6, which represent a low quality natural gas. Three pressures (400, 600, and 800 psig) and five stage-cuts (1.2, 2.8, 4.2, 6.4, and 9.8%) were considered for the study. It was observed that the permeability values of all gases were decreased for mixed-gas experiments when compared to that of the single-gas permeability. On the other hand, CO2/CH4 permeability ratio was increased from 29, for pure gas, to 45 for quaternary gas-mixture. Likewise, the He/CH4 permeability ratio was increased from 33, for pure gas, to 46 for ternary gas-mixture. Furthermore, at 800 psig and 9.8% stage-cut, PPL-450 was able to remove 80% of CO2 from the quaternary gas-mixture. In another study of a very dilute helium-concentration (0.14%) more than 80% helium was recovered at 800 psig and 5% stage-cut. Moreover, in all gas mixtures containing CO2, the PPL-450 membrane demonstrated an outstanding resistivity to CO2-induced plasticization at high pressures.
Effect of casing surface roughness on the removal efficiency of non-aqueous drilling fluids J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-09 Zhidong Zhang, George W. Scherer, Robert K. Prod’Homme, Myoungsung Choi
The primary function of natural gas well cementing is to provide downhole zonal isolation. However, the residual non-aqueous drilling fluid in cement and on the surface of the casing can weaken the bond of hardened cement to the casing. In this paper, the amount of remaining drilling fluid both in cement and on the casing is quantified by the fluorescent dye method, which is verified by other two methods, mass difference and laser scanning. The essential factor - surface roughness that can significantly affect the amount of residual drilling fluid - is investigated. Results show good correlations between the thickness of the remaining drilling fluid and the surface roughness. The comparison of mud removal efficiency of two commercial spacers indicates that microemulsion can remove more drilling fluid than the common spacer, as pointed out in the literature; however, microemulsion is also apt to remain on the casing and thus reduce the bonding between cement and the casing.
Geochemical characteristics of the Paleogene-Neogene coals and black shales from Malaysia: Implications for their origin and hydrocarbon potential J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-08 Hassan Baioumy, Ahmed Mohamed Ahmed Salim, Mohd Hariri Arifin, Mohammad Noor Akmal Anuar, Ali Abdullah Musa
Paleogene-Neogene coals are widespread in Malaysia, cover a wide age spectrum and are considered the source rock of hydrocarbons in Malaysia. However, they have not been studied systematically up to now. Moreover, the black shales associated with these coals were not taken into consideration in previous studies. Therefore, this study presents systematic inorganic and Rock-Eval analyses of the Paleogene-Neogene coals and their associated black shales to examine their origin, depositional environment and hydrocarbon potential.With the exception of coals from the Tanjong Formation, Sabah, the Paleogene-Neogene coals are characterized by very low ash yields and low concentrations of trace and rare earth elements including hazardous trace elements. The black shales are composed of quartz, illite, kaolinite and traces of pyrite in some samples. Al2O3/TiO2 ratios in the coals (6–62) and black shales (16–34) suggest a mixture of felsic and intermediate igneous rocks as sources for their detrital fractions, which is supported by the Zr-Ti binary plot. V/(V+Ni) ratios average between 0.8 and 0.7, V/Ni between 13.5 and 3, and Ni/Co between 1.7 and 3.8 for coal and black shale samples; respectively, indicating suboxic to anoxic depositional conditions for both groups of samples. Rock-Eval analysis indicates that coal and black shale samples contain mixed Type II–III kerogens, which suggest similar organic input from terrestrial high plants. The samples also contain immature to mature organic matter and can produce gas and oil. These characteristics along with the high TOC contents (very good to excellent) indicate that the Paleogene-Neogene coals and black shales are potential source rocks for oil and gas fields in Malaysia. The coals and black shales from different ages and localities were shown to have similar source area composition, climate conditions during their deposition, terrestrial organic input as well as suboxic to anoxic depositional conditions. However, coals and black shales from the early-middle Miocene Tanjong Formation exhibit higher Al2O3/SiO2 ratios than the rest of coals and black shales suggesting a prevalence of wetter climatic conditions during formation. In addition, coals and black shales from the early-middle Miocene Tanjong Formation and upper Pliocene Liang Formation show higher values for redox proxies such as V/(V+Ni), V/Ni, Ni/Co and Ce* compared with other formations, indicating the dominance of reducing conditions during the deposition of these formations.
Biodegradation of light hydrocarbon(C5-C8) in shale gases from the Triassic Yanchang Formation, Ordos basin, China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-05 Qiang Meng, Xiaofeng Wang, Xiangzeng Wang, Yuhong Lei, Peng Liu, Lixia Zhang, Chengfu Jiang, Chao Gao
Evidence based on the molecular, carbon and hydrogen isotopic composition of shale gas has shown that the biodegradation level of the Yanchang Formation shale gas decreases markedly with increasing depth in some parts of the Ordos basin. The compositions of a suite of 30 shale desorbed gases from the Upper Triassic Yanchang Formation, Ordos basin, China, were analyzed in order to assess the effect of variable levels of biodegradation on the distribution of light hydrocarbons in the shale gas and to investigate the effect of biodegradation on common light hydrocarbon parameters. By comparison and analysis of the gas chromatograms of shale desorbed gas from different depths, a series of light hydrocarbon parameters reflecting biodegradation were established. The results indicate that the order of preferential biodegradation of light hydrocarbon fractions (C5-C8) is C5＞C6＞C7≈C8 and that the C6 fraction composition is n-Hexane (nC6)＞2-methypentane (2-MP) ≈3-methypentane (3-MP)＞ Methylcyclopentane (MCP)＞2,3-Dimethybutane (2,3-DMB)＞2,2-Dimethybutane (2,2-DMB)＞Cyclohexane (CH). There are three main controls on the susceptibility to biodegradation of light hydrocarbons: carbon skeleton, degree of alkylation, and position of alkylation. If the carbon skeleton is the same, a higher degree of alkylation represents a stronger ability to resist biodegradation. If the degree of alkylation is the same, those alkanes with larger carbon skeletons are more resistant to biodegradation. Finally, light hydrocarbon fractions with two methyl groups in the same position are more resistant to biodegradation than hydrocarbons with two methyl groups in different positions. Most of the light hydrocarbon parameters were influenced by biodegradation, except the Mango parameters K1and K2.
Variations in permeability along with interfacial tension in hydrate-bearing porous media J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-05 Jiaqi Wang, Lunxiang Zhang, Jiafei Zhao, Li Ai, Lei Yang
This study extends our previous studies on the effects of the IFT on the seepage characteristics in hydrate-bearing porous media using pore network model with X-ray computed tomography. The results indicate that the relative permeability to both methane gas and water decreases as IFT increases. And the influence of the IFT on the two-phase relative permeability increases along with the particle size of the porous media. Moreover, the variation in absolute permeability is always positively related to average pore/throat radii in all type of hydrate-bearing porous media. In addition, the capillary pressure decreases along with IFT.
Coal pores and fracture development during CBM drainage: Their promoting effects on the propensity for coal and gas outbursts J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-05 Zongqing Tang, Shengqiang Yang, Cheng Zhai, Qin Xu
This study explored the occurrence of coal-rock dynamic disasters during the low-temperature oxidation of coalbed methane (CBM) reservoirs for different coal ranks by investigating the dynamic development of pores in coal during low-temperature oxidation. This research monitored dynamic changes in the diameters and numbers of pores in different rank coals during low-temperature oxidation using nuclear magnetic resonance (NMR) and the P-wave rock measurement system. Microscopically, by utilizing industrial component analysis technology and gas chromatography, this study determined the dynamic changes occurring in the composition of coal and the concentrations of representative gases in the low-temperature oxidation of different rank coals. By adopting a new comprehensive index K, which is a combination of the coal-rock hardness (f) and the initial velocity (△p) of a gas emission, to predict a gas outburst, the authors predicted coal-rock dynamic disaster hazards in the low-temperature oxidation of different rank coals. The experiment showed that there are similarities and differences in pore development during the low-temperature oxidation of different rank coals. The similarities are illustrated in the consistencies underlying fracture development. Specifically, in the early stage of low-temperature oxidation of coal (30–130 °C), due to the evaporation of water, the dehydration of compounds containing crystalline water and the decomposition and volatilization of volatiles, micro-pores in coal expand and connect to form meso-pores. In the late stage of oxidation (130–230 °C), the macromolecular compounds and volatiles in coal oxidize and decompose such that meso-pores expand and connect to form macro-pores and micro-fractures. However, as the metamorphic degree of the coal increases, the oxidation resistance and thermal stability of the coal improves, and the initial temperature for the development of pores with the same diameter increases. Based on the concept of the comprehensive prediction index K, the probability of a coal-rock dynamic disaster occurring in a CBM reservoir gradually increases as the oxidation temperature increases. The lower the metamorphic degree of the coal, the faster the growth rate. Therefore, the oxidation temperature at which the probability of a coal-rock dynamic disaster increases by 50% is used as the critical temperature for taking fire prevention measures, i.e., 90 °C and 130 °C for lignite and bituminous coals, respectively.
An experimental investigation on flow pattern map and drift-flux model for Co-Current upward liquid-gas two-phase flow in narrow annuli J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-05 Ruixuan Guo, Yuanhang Chen, Paulo J. Waltrich, Wesley C. Williams
This study explored flow patterns and void fraction prediction models for co-current upward liquid-gas two-phase flow in narrow annular spaces. Experiments on two-phase flow in both narrow and wide annular conduits were performed in a 4-inch (0.102 m) outside-diameter test section, with 3.5-inch (0.089 m) and 2-inch (0.051 m) inner pipes as representations of different annular geometries. Flow patterns and liquid holdup were recorded while flowing air and water upward through the test sections. The experimental results showed that the two-phase flow pattern maps in narrow annulus and wide annulus are with different major regime transition lines. A new drift-flux model for water-air two-phase flow in narrow annuli was developed using experimental data collected in this study. The new model was compared against previous models that were developed for wide annuli, and the results showed a better match in void fraction predictions for two-phase flow in narrow annuli with experimental data. The understanding of two-phase flow in narrow annuli is vital for real-time prediction of void fraction and annular pressure loss in wells with gas influx during casing/liner/slimhole drilling operations. An enhanced prediction can ensure delivery of safer wells with lower non-productive time and associated trouble encountered during well control operations.
Effects of slick water fracturing fluid on pore structure and adsorption characteristics of shale reservoir rocks J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-05 Zepeng Sun, Hailong Zhang, Zhifu Wei, Yongli Wang, Baoxiang Wu, Shengguang Zhuo, Zhe Zhao, Jing Li, Lewei Hao, Hui Yang
The shale-fracturing fluid interaction and its effects on the pore structures and adsorption characteristics of shale are the key factors affecting shale gas exploration. To address this problem, the black shale samples obtained from the Lower Silurian Longmaxi Formation in Sichuan Basin, China were exposed to slick water fracturing fluid at the simulation conditions of 100 °C and 50 MPa for 72 h through a fluid-rock interaction simulation instrument. The slick water fracturing fluid contained 0.2 wt.% friction reducer, 1 wt.% clay control agent, 0.15 wt.% cleanup agent and 0.05 wt.% demulsifier. The mineral composition, pore structure and methane adsorption capacity of shale samples before and after slick water fracturing fluid treatment were measured by X-ray diffraction (XRD), field emission scanning electron microscope (FE-SEM), low-pressure nitrogen adsorption and methane isothermal adsorption experiments using the gravimetric method. The results showed that the carbonate minerals were dissolved during treatment, and as a result, the samples developed many dissolution pores measuring 2–5 μm in diameter, while the other minerals remained relatively undisturbed. The specific surface area and total pore volume of shale sample were reduced after the reaction, and the shale-fracturing fluid interaction exhibited a stronger influence on the mesopores. However, the average pore diameter of nanopore was enlarged after the reaction, increasing from 4.29 nm to 4.78 nm. The changes of fractal dimensions suggested an increase in the roughness of pore surfaces, and the pore structure became more regular. The methane adsorption capacity in shale treated with fracturing fluid was reduced from 1.23 mmol/g to 0.95 mmol/g. The changes in the pore structure and adsorption characteristics of shale could affect the gas flow and gas adsorption capacity. These results indicated that the slick water fracturing fluid may play an important role in shale matrix stimulation.
Experimental and statistical investigation of drilling fluids loss in porous media–part 1 J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-02 Chinedum Peter Ezeakacha, Saeed Salehi
Drilling fluids Invasion and mud filtration is a complex process that is influenced by several variables, and has NPT (Non-Productive Time) implications. Most of these variables are either within operational control limits (mud type, LCM type/concentration, and rotary speed) or pre-existing limits (temperature, fracture width, and rock type/permeability/porosity. It is unclear which of these variable(s) have significant positive or negative impact on dynamic fluid loss, filtration patterns, invasion rates, and plastering effect. The primary objective of the study presented in this paper is to quantify the contributing effects of temperature change, lost circulation material (LCM) type, concentration, size (particle size distribution), and variation in porous media on dynamic drilling fluids invasion. Statistical methods were used to determine the magnitude and significance of these independent variables. The fluid loss experiments reported herein were performed with dynamic-radial system that accounts for rotary speed, eccentricity, torque, pressure, and temperature. The effects of the three variables mentioned above were studied using cylindrical wellbore-shaped ceramic filter tubes, Limestones, Sandstones, and Chalk formations. The results from the experiments showed that change in temperature significantly affects fluid loss. The importance of rock mineralogy, porosity, and permeability in dictating dynamic fluid loss profiles, mud invasion rates, and plastering effects were also revealed by the fluid loss results. The results from the ceramic filter tubes, often undermines the effect of rock type which can be misleading. Statistical analyses showed no significant impact on the two treatment levels (low and high) pore throat sizes that were investigated. These results cannot represent the actual porous media complexities. In the cases where vertical fractures were created and sealed, the combined effects of LCM and low permeability were defined in the reduced dynamic mud filtration results and filter cake plastering effects.
Key aspects of numerical analysis of gas hydrate reservoir performance: Alaska North Slope Prudhoe Bay Unit “L-Pad” hydrate accumulation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-02 Taiwo Ajayi, Brian J. Anderson, Yongkoo Seol, Ray Boswell, Evgeniy M. Myshakin
In previous work, we reported the development of the 3D geostatistical hydrate reservoir model of "L-Pad" (Myshakin et al., 2016). In this paper, gas production sensitivity on key reservoir parameters are studied. Hydraulic communication with an aquifer and optimal depressurization strategies are subjects of investigation. Uncertainty in initial in situ permeability within 0.1–10 mD range leads to 2.0 × 108–3.5 × 108 ST m3 of gas produced over 10 years. Accounting for reservoir quality and irreducible water saturation leads to noticeable change in productivity. Sequential depressurization of hydrate-bearing units was found to be more attractive versus simultaneous depressurization.
Interaction of anionic surfactant-nanoparticles for gas - Wettability alteration of sandstone in tight gas-condensate reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-02 Maribel Franco-Aguirre, Richard Zabala, Sergio H. Lopera, Camilo A. Franco, Farid B. Cortés
Experimental study of permeability behaviour for proppant supported coal fracture J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-29 Yanting Wu, Zhejun Pan, Dingyu Zhang, David I. Down, Zhaohui Lu, Luke D. Connell
Proppants are typically added in the hydraulic fracture to maintain the fracture aperture and increase conductivity for gas production from coal seams. However, the presence of proppants complicate the permeability behaviour of the coal. Understanding permeability evolution of proppant supported fractures under dynamic stress conditions are necessary to predict the production of coalbed methane. In this work, a series of laboratory experiments were conducted on a cylindrical coal core from Chongqing, China, under hydrostatic condition. Permeabilities at various gas pressures and confining stresses were measured on the original sample, as well as the sample with a proppant supported fracture. Gas adsorption, matrix swelling behaviour were also investigated by injecting non-adsorbing (He) and adsorbing (CH4) gases. The results show that proppant supported fracture has little effect on adsorption capacity, as well as the swelling behaviour due to gas adsorption. However, the proppant supported fracture can significantly enhance permeability about 2-3 orders of magnitude higher than original sample depending on proppant type and its distribution in the fracture. Fracture compressibility may be decreased by 1 order of magnitude, suggesting that the permeability for the proppant supported fracture is less sensitive to stress. It was also found that sparsely placed monolayer proppant can have comparable permeability with densely packed multilayer proppant.
A review on the effect of confinement on phase behavior in tight formations J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-27 Shadi Salahshoor, Mashhad Fahes, Catalin Teodoriu
Unconventional resources, including tight oil and gas formations and shale plays, have become a vital source of energy all over the world. The unique characteristic of these reservoirs, which has made their development challenging, is the low-to ultra-low- permeability due to the abundance of nano-scale pores. In these tiny pores and pore-throats, phase behavior and saturation pressures of the confined fluid are shifted from those of the bulk fluid within larger pores of the conventional medium-to high-permeability reservoirs. During the past few decades, many scholars attempted to compare this alteration in fluid phase behavior inside the tiny pores of tight formations to that of the bulk by studying the fundamentals behind this behavior through mathematical models, simulations, and experimental studies. Reduced pore size and pore structure, mineralogy, adsorption, and capillary condensation phenomena have been addressed in different studies as the source of this deviation in properties. Attempts to model fluid phase behavior in narrow pores started by applying the knowledge of classical thermodynamics in molecular simulations of the confined fluid, which has an inhomogeneous distribution inside the narrow pores. This was followed by modifying different types of equations of state to capture the difference in saturation pressures and temperatures of the confined fluid and that of the bulk. Experimental efforts in this area cover a wide range of non-visual approaches and precise visual approaches using the lab-on-a-chip techniques. However, conducting experiments at the nano-scale, specifically less than 100 nm, is rare due to many experimental limitations. This review provides a comprehensive summary of the theoretical and experimental studies in this area, highlights the advantages and disadvantages of each method, and indicates a lack of data at the challenging range of pore scales, less than 10 nm, for simulation validation purposes.
Hydraulic fracturing in a penny-shaped crack. Part I: Methodology and testing of frozen sand J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-25 Jun Lin Too, Arthur Cheng, Boo Cheong Khoo, Andrew Palmer, Praveen Linga
Molecular investigation of the interactions of carbon dioxide and methane with kerogen: Application in enhanced shale gas recovery J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-24 Manas Pathak, Hai Huang, Paul Meakin, Milind Deo
Even with technological advancements such as hydraulic fracturing and horizontal drilling, only 20% of the original gas in shales is recoverable through current industry practices. This low recovery factor is attributed to very low permeability and sorption of much of the gas by solid organic matter. Enhanced gas recovery through carbon dioxide sequestration could be performed either by cyclic injection (huff and puff) of carbon dioxide or fracturing/re-fracturing the formation with a viscosified, foamed or energized carbon dioxide hydraulic fracturing fluid. This work employs molecular modeling to conduct a fundamental investigation of the interactions between carbon dioxide and the solid organic part of the shales, the majority of which is kerogen. In the current work, more realistic molecular models for Type II kerogen in oil-gas window, with active sites were used instead of the graphite based carbon models used in many previously published works. Both adsorption onto kerogen surfaces and absorption within it contribute to its high sorption capacity. Previously, researchers have shown through modeling and experiments that kerogen has a higher affinity and adsorption capacity for carbon dioxide than for methane. The current work studies the sorption of carbon dioxide and methane using quasi equilibrium Molecular Dynamics (MD) simulations. The MD simulations of ternary system of methane, carbon dioxide and kerogen revealed that the carbon dioxide is more strongly retained than methane in the bulk kerogen matrix. The self-diffusion coefficient of carbon dioxide (Dself = 10- 10 m2/s) in the kerogen was found to be an order of magnitude smaller than that of methane (Dself = 10-9 m2/s) in the kerogen. The MD simulations revealed that in the process of carbon dioxide - methane 1:1 exchange in the kerogen matrix, the kerogen matrix shrinks in volume. This may lead to disturbance in the fluid pathways that contribute to fluid flow in shales. The molecular investigation performed in this fundamental work is relevant to any carbon dioxide enhanced gas production from shale gas resources.
Modeling and control of natural gas bypass odorizer J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-23 Mohammad Negaresh, Mohammadreza Farrokhnia, Nasir Mehranbod
Natural gas odorization is a safety critical issue in natural gas distribution industries enabling early detection of leakage that lead to prevention of fatal accidents. Usually inefficient manually controlled bypass odorizers are used in most town border stations used in gas distribution networks. In this study, a feedforward control system is proposed for that comprises of three elements. A mass transfer model, correlation for bubble diameter estimation, and SVM-based model of final control element are the elements. The mass transfer model predictions are profoundly affected by bubble diameter estimation. Bubble size measurements are used to develop a correlation for bubble diameter estimation. A motor-actuated precision needle valve is used as the final control element of the control system. The valve characteristic curves were determined and used to develop an input-output model based on the support vector machine. Different experiments were conducted to evaluate the performance of the three elements separately. To assess the effectiveness of the control system, the operating conditions of a town border station was simulated experimentally for the duration of 24 h. Experimental data and controller calculations for odorant cumulative mass transfer showed a minimum and maximum relative absolute error of 0.4% and 9.10%, respectively that indicates the controller to be effective.
Numerical investigation for simultaneous growth of hydraulic fractures in multiple horizontal wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-21 Xiyu Chen, Yongming Li, Jinzhou Zhao, Wenjun Xu, Dongyu Fu
Recently developed multi-well fracturing technologies are widely used in unconventional low-permeable reservoirs for enhancing production. In this paper, we have implemented a three-dimensional numerical model, which couples the rock deformation, fluid flow and the dynamically flux partition in multiple wellbores, to simulate the simultaneous growths of hydraulic fractures in multi-well fracturing at unconventional reservoirs. To resolve the fully-coupled problem, a numerical scheme with four-layer loops is adopted in this model. The numerical simulations reveal that the asymmetric fracture propagations occur in multi-well fracturing, and the lateral growths of interior fractures are suppressed due to the intense inter-well stress interference. Results show that higher inlet pressure loss, achieved by limited entry design, is able to promote the lateral propagation of interior fractures. Then, case studies are performed to investigate the influences of fracture spacing, well spacing and fracturing scheme on fracture growths in multi-well fracturing. The results reveal that, when decreasing fracture spacing to a certain degree, the fracturing efficiency will not be promoted further by increasing fracture number. The case studies also indicate that, for successful fracturing treatment, a possible lower limit of well spacing should be considered in design, to avoid a sharp reduction of effectiveness in treatment. Compared to simultaneous fracturing scheme, study results demonstrate that zipper fracturing scheme has a better performance in promoting the fracture complexity and increasing the fracture surface area, which is favorable to enhance hydrocarbon production.
Investigating the effects of gas type and operation mode in enhanced gas recovery in unconventional reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-21 C.J.S. Santiago, A. Kantzas
A model that combines the Dusty-Gas approach and Darcy's Law is used to investigate the dynamics of production enhancement by gas injection in unconventional reservoirs. A comparison between CH4, N2 and CO2 injection in both Huff-n-Puff and Flooding operation modes is performed. The mechanism of production enhancement for each gas is different. CO2 can be injected to preferentially adsorb into the shale matrix, releasing hydrocarbons. In this case, the dominant mechanism is competitive adsorption. Due to stronger affinity with adsorption sites, CO2 injection would suggest high cumulative production. In spite of that, frontal displacement is very slow in this case, resulting in poorer short-term production when compared to N2 and CH4. N2 injection induces the release of hydrocarbons solely by partial pressure reduction. Frontal velocities are fast, resulting in high short-term production. Yet, since N2 is deemed inert, it does not replace components retained in the adsorbed phase. CH4 injection also prompts desorption of heavier hydrocarbons by partial pressure reduction. However, as heavier fractions are desorbed, CH4 molecules occupy the vacant sites. In this case, combined mechanisms of partial pressure reduction and uptake by the adsorption sites results in efficient release of heavier hydrocarbons. In this work, we demonstrate the impact of the presence of heavier hydrocarbon fractions in modeling gas transport during enhanced gas recovery processes. Multicomponent gas flow affects average reservoir pressure, produced gas composition and natural gas liquids (NGLs) yields, which is relevant for development of wet-gas and dry-gas unconventional reservoirs. Moreover, we demonstrate that injection gas composition significantly influences transport behavior of chemical species through the porous medium, and we highlight the relevant transport mechanisms during enhanced gas recovery in tight reservoirs.
Analytical modeling of linear flow with variable permeability distribution in tight and shale reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-21 M. Sadeq Shahamat, Hamidreza Hamdi, Christopher R. Clarkson
Horizontal wells with multiple fractures, producing from tight and shale reservoirs, may exhibit linear flow for long periods of time. Majority of the available analytical solutions that model this flow behaviour assume uniform permeability, which most likely is an over-simplification of the unconventional reservoirs. Non-homogeneous shear or tensile failure away from the main induced (primary) hydraulic fractures can lead to a non-uniform permeability distribution that depends on the distance away from the hydraulic fractures. In this work, linear flow in a reservoir with non-uniform permeability adjacent to the primary hydraulic fracture is modeled rigorously using perturbation theory. The diffusivity equation is solved for the pressure response of a fractured well located in a reservoir of infinite extent with permeability as an arbitrary function of position. For constant terminal rate (CTR) or constant terminal pressure (CTP) conditions, the linear flow parameter ( L F P = x f k ) is calculated from the slope of the square-root-of-time plot (plot of rate-normalized pressure vs. square root of time). It is demonstrated herein that the calculated LFP corresponds to a weighted average of permeabilities (and fracture half-lengths); different parts of the reservoir contribute differently to the LFP at different production times. The LFP is influenced most strongly by permeabilities at a distance y = 0.056 ( k t ) ϕ μ c t . The derived weighting functions during CTR and CTP production can be applied in inverse mode for determining LFP distribution near the hydraulic fractures. This is particularly useful in evaluating the effectiveness of hydraulic fracturing operations and assessing the performance of different fracturing techniques in unconventional reservoirs. In addition, this work gives significant insight into the concept of distance of investigation (DOI) in tight and shale reservoirs, and the differences when producing under CTR and CTP conditions.
Effects of early oil emplacement on reservoir quality and gas migration in the Lower Jurassic tight sand reservoirs of Dibei gas field, Kuqa Depression, western China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-21 Hui Shi, Xiaorong Luo, Ganglin Lei, Hongxing Wei, Liqiang Zhang, Likuan Zhang, Yuhong Lei
It is common for many tight sandstone reservoirs saturated with gas to have experienced an early oil charge before gas invading. To determine the effects of early oil emplacement on reservoir quality and gas migration has important role in predicting “sweet spots” of gas production in tight sand reservoirs. We investigated the palaeo and current fluids contacts accurately due to parameters from quantitative grain fluorescence in the Lower Jurassic Ahe Formation of Dibei gas field. The porosity and permeability values in palaeo-oil leg are totally higher than in palaeo-water leg, especially there being a wide gap of permeability with an order of magnitude. The variation of reservoir quality derives from the early oil emplacement, which restrained clay conversions from kaolinite or illite-smectite mixed-layer into fibrous illite that dramatically increasing flow-path tortuosity in sandstones, according to core analysis and X-ray diffraction. The early oil preserved penetrating quality of palaeo-oil leg, but the sandstones that never experienced early oil emplacement contains much more fibrous illite. It made most of early oil pathways subsequently act as the migration pathways for late gas and less than 50% of the migration pathways for gas were caused by microfractures due to quantitative grain fluorescence. Only the sandstones with medium early oil saturation did become sweet spots for gas in the tight sand reservoirs. Too much and too little oil once saturated in pores maybe adverse to the late gas migration and accumulation.
Inversion of gas permeability coefficient of coal particle based on Darcy's permeation model and relevant parameters analysis J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-20 Wei Liu, Chao He, Yueping Qin, Peng Liu
Permeability is an important indicator for predicting gas drainage yield and preventing mine gas disasters. Gas permeability coefficient derived from the permeability is introduced in this work to develop a model of methane adsorption of coal particle based on Darcy's permeation, which is solved by our self-developed software, and then the methane isothermal adsorption of six granular coal samples are measured by quasi-constant pressure adsorption experiments. A new inversion approach for gas permeability coefficient of coal particle is performed by matching simulation results with experiment data. Meanwhile, the impacts of adsorption pressure and coal rank on gas permeability coefficient are also analyzed quantitatively. The results show that (i) a suitable gas permeability coefficient of coal particle can be determined by adjusting simulated curve to match with experimental data, which verifies the feasibility and effectiveness of the inversions; (ii) the gas permeability coefficient of coal particle decreases exponentially as the adsorption pressure or volatile matter content grows. This research provides an alternative approach to determine the permeability of granular coal samples and we hope it will bring some references to researchers.
Numerical simulation of pore-scale formation of methane hydrate in the sand sediment using the phase-field model J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-20 Ayako Fukumoto, Kentaro Kamada, Toru Sato, Hiroyuki Oyama, Honoka Torii, Fumio Kiyono, Jiro Nagao, Norio Temma, Hideo Narita
Methane hydrate is considered as a promising energy resource for the near future. To predict the gas productivity from the methane hydrate in the subsea sand-sediment, it is important to know absolute permeability accurately of the sediment bearing methane hydrate. Hence, the hydrate morphological distribution: namely, what is the shape and morphology of hydrate, in the sediment should be elucidated, because the permeability is strongly affected by the hydrate distribution. In this study, to know where hydrate is formed in the pore of porous media, we proposed a numerical model for estimating the microscopic distribution of methane hydrate in sand sediment, using the classical nucleation theory and the phase-field model. The former theory gave the probabilities of hydrate nucleation positions in the gas-water-sand three-phases and the latter method provided the mobility of the front of the hydrate formation. A necessary hydrate formation rate constant was determined by history-matching with an experiment in the literature. Using the obtained rate constant, we numerically simulated hydrate formations within the microscopic computational domains.
Analysis of physical properties and influencing factors of middle-rank coal reservoirs in China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-20 Miao Zhang, Xuehai Fu, Hongdong Wang
Middle-rank coal mainly refers to bituminous coal with the vitrinite maximum reflectance (Ro,max) between 0.65% and 2.0%. Based on the results of a proximate analysis, maceral composition, high-pressure mercury intrusion porosimetry (MIP) experiments and isothermal adsorption experiments, combined with gas content and permeability derived from well test, the pore size distribution (PSD), adsorption characteristics and the evolutionary paths of middle-rank coal were analyzed, and the influencing factors of the gas-bearing property and permeability were discussed. The results indicated that as Ro,max increases, the porosity shows first decreasing and then increasing, with the minimum values reached when Ro,max = ∼1.0%. The volume and specific surface area of the total pores have the same evolutionary paths with each class of pores, first decreasing and then increasing with the increases of Ro,max. The minimum value appears when Ro,max is between 1.2% and 1.3%. As Ro,max increases, VL increases while PL first increases and then decreases, the maximum value is again reached at near Ro,max = 1.3%. The gas content increases with the increases of Ro,max, first increasing and then decreasing with the increases of buried depth, and the buried depth at 950 m is the critical depth of gas content. There is a positive correlation between gas content and gas saturation; the permeability decreases with the increases of buried depth, and increases with the increases of coal reservoir porosity. Ground stress is the main controlling factor of reservoir permeability.
Experimental investigation on the mechanical and acoustic emission characteristics of shale softened by water absorption J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Dongqiao Liu, Zhuo Wang, Xiaoyun Zhang, Yang Wang, Xiulian Zhang, Dong Li
Shale is a fine-grained, clastic sedimentary rock composed of clay minerals and other minerals. The water-shale interaction plays an important role in the borehole drilling and hydraulic fracturing during the process of shale gas exploitation. In this study, laboratory experiments, including water absorption experiments and uniaxial compression tests, were used to investigate the mechanical behaviours of the water-absorbing shale specimens. From the laboratory experiments, the following statements can be drawn: a) the water-absorbing shale specimens experience longer compaction and crack closure stages than the natural shale specimen; b) the mechanical properties of the water-absorbing shale specimens, such as uniaxial compressive strength, Young's modulus and peak strain, are less than those of the natural shale specimens; c) the apertures of the failure cracks in the water-absorbing shale specimens are greater than those in the natural shale specimens under uniaxial compression loading. The acoustic emission technique was also used to capture the acoustic emission events of the shale specimens during the uniaxial compression tests. By the acoustic emission analysis, it is concluded that the water absorption stimulates the AE events in the shale specimens.
A semi-analytical model to evaluate productivity of shale gas wells with complex fracture networks J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Huang Shijun, Ding Guangyang, Wu Yonghui, Huang Hongliang, Lan Xiang, Zhang Jin
With the increasing of clean energy demands and the maturing of shale gas extraction technology, multiple fractured horizontal well (MFHW) has become the most key technology for shale gas development. After hydraulic fracturing, fracture networks, which consist of natural fractures, hydraulic fractures and secondary fractures, are formed around the wellbore. Compared to conventional gas reservoirs, shale gas reservoirs are characterized by the complex fracture networks and gas adsorptions in shale matrix. Therefore, it is essential to propose a new productivity evaluation method for shale gas wells to handle these characteristics. In this paper, to account for special characteristics of MFHW, a complex fracture model for shale gas reservoirs is established. With the new method, shale reservoirs are depicted by De Swaan dual porosity model, where the secondary fractures and hydraulic fractures are characterized by discrete units. Therefore, together with micro-seismic data, fracture networks can be exactly described using this new model. With a well-depicted facture network, Green function and superposition method are then adopted to model the flow in the reservoir, and finite difference method is used to solve the equations of one-dimensional flow in fracture system. Besides, to deal with the complex flow in the fracture intersection, star-delta transformation is applied Finally, the equations of reservoir and fracture system, the solution in Laplace domain is obtained, which can then be transferred to real domain using the Stehfest algorithm. Comparisons were made between the results of the proposed model and that of a numerical model accomplished by commercial simulator Eclipse for a specific case to verify the accuracy of the model. Results show that the semi-analytical method is more efficient than numerical method by reducing the computing time without losing accuracy. Moreover, the semi-analytical productivity evaluation method can describe fracture networks more exactly. Then, a field case from Sichuan Basin of China is applied in the analysis. The results shows that desorption gas takes up 10%-30% of the total production in this case. Besides, the effects of storage capacity ratio and inter-porosity flow coefficient on type curves were analyzed based on the production decline curves. In addition, pressure profiles of different production times are obtained by the superposition of pressure potential.
Empirically assessing the potential release of rare earth elements from black shale under simulated hydraulic fracturing conditions J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Jon Yang, Circe Verba, Marta Torres, J. Alexandra Hakala
Rare earth elements (REEs) are economically important to modern society and the rapid growth of technologies dependent on REEs has placed considerable economic pressure on their sourcing. This study addresses whether REEs could be released as a byproduct of natural gas extraction from a series of experiments that were designed to simulate hydraulic fracturing of black shale under various pressure (25 and 27.5 MPa) and temperature (50, 90, 130 °C) conditions. The dissolved REEs in the reacted fluids displayed no propensity for the REEs to be released from black shale under high pressure and temperature conditions, a result that is consistent across the different types of fluids investigated. Overall, there was a net loss of REEs from the fluid. These changes in dissolved REEs were greatest at the moment the fluids first contacted the shale and before the high temperature and high pressure conditions were imposed, although the magnitude of these changes (10−4 μg/g) were small compared to the magnitude of the total REE content present in the solid shale samples (102 μg/g). These results highlight the variability and complexity of hydraulic fracturing systems and indicate that REE may not serve as robust tracers for fracturing fluid-shale reactions. Additionally, the results suggest that significant quantities of REEs may not be byproducts of hydraulically fractured shales.
A new genetic type of natural gases and origin analysis in Northern Songnan-Baodao Sag, Qiongdongnan Basin, South China Sea J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Wenjing Ding, Dujie Hou, Weiwei Zhang, Dashuang He, Xiong Cheng
Unlike the typical coal-type gas of neighboring Lingshui and Ya'nan Sags in the Qiongdongnan Basin and farther Yinggehai Basin, most gases in the Songnan-Baodao Sag have much lighter δ13C1 and δ13C2 values, which are in the range of −54.68‰∼-33.68‰ and −31.03‰∼-23.50‰, respectively. The differences are attributed to the following aspects: (1) lighter gas from the preferential cracking of 12C-12C bond in aliphatic acid decarboxylation and polycondensation under catalysis of clay minerals in lower temperature, and (2) greater proportion of sapropelinite in strata overlying 1st member of Lingshui Formation with corresponding Ro less than 0.6%. The natural gases are classified into three genetic types: (1) Bio-thermocatalytic Transition Zone Gas generated from shale overlying 1st member of Lingshui Formation, (2) Thermal Catalytic Gas generated from lower Lingshui Formation and Yacheng Formation, (3) Mixed gas. Bio-thermocatalytic Transition Zone Gas shows lighter δ13C1 (δ13C1<−44‰), a wider range of δ13C2 (>-31‰), a relatively lower dry coefficient (0.65–0.91), and abundant organic CO2 with δ13CCO2 ranging from −28.9‰ to −7.61‰. Thermal Catalytic Gas is typical coal-type gas (δ13C2>−28‰) with higher maturity and dominating inorganic CO2. Mixed gas is mixture of above two gases. Compared with the condensate in the Yinggehai Basin, n-alkane mono-isomer and whole oil of condensate in study area are isotopically lighter, which are similar to the lighter Bio-thermocatalytic Transition Zone Gas. Attributed to mixed input of increasing proportion of alga and decreasing terrigenous higher plants in low-mature shale, contents of terrestrial biomarkers such as oleanane, cadinane, bicadinane, etc, are very low. Oil-source correlation analyzed from characteristics of mass chromatograms and C7 system, n-heptane, isoheptane value of light hydrocarbons of Bio-thermocatalytic Transition Zone Gas and Mixed gas show genetic relation with abundant sapropelinite in the low-mature shale in study area. This study provides a new insight to recognize potential gas and condensate resources generated from the previously neglected low-mature shale overlying 1st member of Lingshui Formation of Songnan-Baodao Sag and adjacent deep waters in Qiongdongnan Basin.
Selective adsorption of supercritical carbon dioxide and methane binary mixture in shale kerogen nanopores J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Tianyu Wang, Shouceng Tian, Gensheng Li, Mao Sheng
The adsorption of carbon dioxide and methane binary mixture in shale kerogen nanopores and the underlying mechanism significantly affect the supercritical carbon dioxide enhanced shale gas development project. In this study, we investigated the adsorption properties of carbon dioxide and methane in shale kerogen using grand canonical Monte Carlo (GCMC) method. Shale kerogen was fabricated based on Ungerer molecular model and its parameters were validated. The effects of temperature, pressure, mole fraction on the adsorption isotherms, average isosteric heat, potential energy distribution, and adsorption selectivity of binary mixture were discussed. The results show that the absolute adsorption capacity of methane in binary mixture decreases as temperature increases, but increases as mole fraction increases. Compared with methane, carbon dioxide is in lower energy absorption sites, which indicates the adsorption capacity of carbon dioxide in shale kerogen is stronger than that of methane. The adsorption selectivity of carbon dioxide over methane first decreases as pressure increases until pressure reaches critical pressure (7.38 MPa for carbon dioxide), and then stays at around 3.8 as pressure continues to rise. Adsorption selectivity and desorption quantity are used to reveal that the optimal injection depth for supercritical carbon dioxide enhanced shale gas development project is 1000–2500 m. This study will reveal the mechanism of the adsorption of methane in kerogen and provide some fundamental data for supercritical carbon dioxide enhanced shale gas development project.
Experimental study of sodium chloride aqueous solution effect on the kinetic parameters of carbon dioxide hydrate formation in the presence/absence of magnetic field J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Hossein Moeini, Mohammad Bonyadi, Feridun Esmaeilzadeh, Ali Rasoolzadeh
The main purpose of this study is to experimentally elucidate the hydrate formation of carbon dioxide in both of deionized water and sodium chloride solution in the presence and absence of the magnetic field with regard to bad and harmful influence of carbon dioxide on the environment and climate. The experimental tests were performed in the equilibrium cell at the initial pressures of 30.5 and 35.5 bar and temperatures of 0, 2 and 4 °C with different concentrations of sodium chloride in water 0–5 wt%. Additionally, the effect of sodium chloride concentration, temperature, pressure and magnetic field on the gas hydrate kinetic parameters including the amount of gas consumption, induction time and pressure drop during the hydrate formation were examined. It is evident from the results that changing the concentration of sodium chloride aqueous solution from 1 to 3 wt%, leads to increase the induction time and hence considerably decreases the gas consumption rate and pressure drop. The results were also shown that changing the sodium chloride aqueous solution from 3 to 5 wt% has a slight effect on the induction time, gas consumption and pressure drop. Moreover, it was observed that the presence of magnetic field with 550 gauss strength has no considerable effect on the kinetic of carbon dioxide hydrate formation.
Evaluating Single-Parameter parabolic failure criterion in wellbore stability analysis J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Seyedalireza Khatibi, Azadeh Aghajanpour, Mehdi Ostadhassan, Oveis Farzay
Shear (breakout) and tensile (breakdown) rock failures are the most common wellbore instability challenges that may occur during drilling operations. In order to prevent these problems, stress concentration on borehole wall should be calculated using an accurate mechanical earth model (MEM). A comprehensive MEM should incorporate a failure criterion in order to predict the safe mud window. Thus far, several failure criteria have been utilized and discussed for the wellbore stability analysis in literature, but there is not any commonly accepted one in petroleum industry that generates the most reliable results. In this study, first, Single-Parameter parabolic failure criterion was evaluated by reproducing unconfined compressive strength (UCS) from available triaxial tests. The results were then compared with measured uniaxial tests as well. It was found that Single-Parameter parabolic failure criterion is more accurate in reproducing UCS values than Mohr-Coulomb and Hoek-Brown. In the next step, Single-Parameter parabolic failure criterion was used in mechanical earth modeling of a real case study in Persian Gulf, Iran. Results indicated that Single-Parameter parabolic failure criterion overestimates the rock strength in a very low confining pressures, making it inapplicable for effective confining pressures of zero or very low. It also reflects higher breakout limits in very high UCS values which led to a misleading narrower safe mud weight window compared to other failure criteria.
Influence of acid-rock reaction heat and heat transmission on wormholing in carbonate rock J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Heng Xue, Zuxi Huang, Liqiang Zhao, Hehua Wang, Bo Kang, Pingli Liu, Fei Liu, Yi Cheng, Jun Xin
Matrix acidizing is one of the most important technologies to recover or enhance oil/gas recovery by injecting acid fluids to dissolve rocks and increase the permeability near the wellbore. The wormholes with different patterns are generated in the dissolution process. In addition to the injection parameters, acid types and physical properties of rock, the temperature is one of the potential factors to affect wormholing performance, especially for some temperature dependent diverting acids. However, few works concentrated on the influence of reaction heat on wromholing. In this work, the acid-rock molar reaction heat considering comprehensive impact of temperature, pressure and volumetric work of CO2 was introduced into the heat transfer model, and combined with two-scale model. The models were numerically simulated to highlight the influence of different factors on reaction temperature profiles, wormhole patterns and breakthrough curves under isothermal and non-isothermal conditions with radial coreflood simulations, and the modeling results are in good agreement with the experiments. The simulation results illustrate that molar reaction heat influences the reaction temperature profile to some extent, and can affect wormholing on macro-scale under certain conditions. During the reaction, the highest reaction temperatures are observed at the wormhole tips, which are over 11 K in our simulations. Under isothermal conditions, the temperature and acid concentration strongly affect the wormhole propagation progress, but pressure does not. The field application condition of matrix acidizing considering non-isothermal Influence is also systematically studied. It was found that a colder acid injection or a lower rock temperature will promote the acidizing efficiency when the injection rate is within the appropriate range.
The horizontal dispersion properties of CO2-CH4 in sand packs with CO2 displacing the simulated natural gas J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Shuyang Liu, Yongchen Song, Changzhong Zhao, Yi Zhang, Pengfei Lv, Lanlan Jiang, Yu Liu, Yuechao Zhao
CO2 sequestration with enhanced gas recovery (CO2-EGR) is a promising technology, especially in the case of re-injecting the separated CO2 from natural gas into the same gas reservoir. The description of dispersion between these two gases benefits for understanding of this miscible displacement and the related reservoir simulation. Here the dispersion properties of CO2-CH4 were studied in short and long sand packs through CO2 horizontally displacing natural gas, both CH4 and one kind of simulated natural gas - SNG (composed of 0.90 CH4 + 0.10 CO2 in mole fraction). We evaluated the effect of gravity and CO2 impurity in SNG on the horizontal dispersion. The gravity effect affected the entry/exit effect and jointly caused the considerably larger dispersion coefficients in the long core than that in the short core. Due to the existence of CO2 impurity, SNG makes itself diffuse into CO2 more easily. Effectively it results in the larger dispersion coefficients. Simultaneously, the horizontal dispersivity of the sand pack calculated as about 0.0161 m in this work, was comparatively larger than the vertical one, resulted from the gravity effect.
Determination of dissociation front and operational optimization for hydrate development by combining depressurization and hot brine stimulation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Yurong Jin, Shuxia Li, Daoyong Yang, Xingxing Jiang
Techniques have been developed to determine dissociation front (i.e., the boundary where hydrate saturation is decreased to 0) for hydrate development by combining depressurization and hot brine stimulation. Experimentally, hydrate dissociation is determined with a one-dimensional (1D) model by gradually injecting hot brine to examine gas and water production. Theoretically, simulation techniques are employed to determine the decay rate and relative permeability by fitting the experimental measurements. Subsequently, the numerical techniques are well matched with field test data and then extended to field applications by applying two different development methods (i.e., depressurization and combining it with hot brine injection). It is found that the combination method greatly improves gas recovery by approximately 35.00%, higher water production rate, and lower gas water ratio compared with those of depressurization alone. The orthogonal design method is then used to perform sensitivity analysis and optimize operational parameters by maximizing energy efficiency as the objective function. The most sensitive parameters are found to be the brine temperature, producer bottomhole pressure, brine injection rate, and injection time. Two dissociation fronts are formed separately near the producer and injector, while the dissociation front of the producer is found to move slower than that of the injector due to the different driving mechanisms for the movement of two dissociation fronts.
Experimental research into the relationship between initial gas release and coal-gas outbursts J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Dingding Yang, Yujia Chen, Jun Tang, Xiaowei Li, Chenglin Jiang, Chaojie Wang, Chaojie Zhang
Coal and gas outbursts are a rapid and powerful energy-releasing process. The damage to coal and the release of gas in the initial stage play key roles in the occurrence of outbursts. Existing studies have mainly focused on the gas desorption processes in coal under specific conditions such as particle size, specified mass and exposure time of pulverized coal. However, these studies have focused less on the gas release during the initial stage, and the quantitative relationship between the outburst risk level and the test results. Seven coal samples with different metamorphic degrees were chosen for use in outburst simulation experiments to investigate trends in gas release from pulverized coal in the presence of N2 and CO2. The results demonstrate a strong correlation between the gas release capacity during the first 10 s and natural desorption gas content of the onset of coal exposure during the first 120 min. In general, the higher the gas content, the larger the released gas volume, and thus the larger the limiting amount of desorptive gas. The gas release from an outburst coal sample is larger than that from a non-outburst coal sample within the first 10 s. There is a good linear relationship between the initial volume of released gas (in the first 10 s) and the initial expansion energy of released gas (IEERG), which can reflect the risk of coal outburst. Thus, according to the outburst critical value (42.98 mJ/g) of IEERG, the critical value of initial volume of released gas could be calculated to be 1.113 cm3/g. The results can provide a reference for further study of the effect of gas on outbursts and the investigation of coal and gas outbursts disasters.
Dehydration of low-pressure gas using supersonic separation: Experimental investigation and CFD analysis J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Pouriya H. Niknam, H.R. Mortaheb, B. Mokhtarani
Supersonic nozzles are recently applied for carrying out water separation from natural gas streams and dew pointing in early stages of gas processing. This paper represents an experimentally and numerically study on a novel low-pressure two-phase driven supersonic nozzle constructed based on a new annular design. The nozzle includes a set of tilted fixed blades at the entrance and a swirling stabilizer along with a convergence-divergence nozzle. The liquid phase is separated from the primary gas phase by decompression and compression happening accompanied with the centrifugal effect induced by the swirling of the gas stream. The phase change happens by gradual drops in temperature and pressure upstream of the shockwave position, and an abrupt change at the shockwave position followed by a subsequent gradual increase in temperature and pressure. The pressure, temperature, and moisture level of the gas are measured to investigate the performance of the supersonic separation unit. The computation is carried out by a 2D approach capable of two-phase heat and mass transfer modeling. For the first time, the analysis uses high order of discretization schemes in order to well capture the shockwaves in a low-pressure supersonic nozzle and find out their effects on separation. An assessment is carried out focusing on the effect of operational conditions on the nozzle performance. The experimental data for dehydration efficiencies are in good agreement with the simulation results within 3%. The shockwave position is found in the range of 0.3–0.5 of non-dimensional nozzle length. The positions of both shockwave and initiation of condensation are shifted toward the exit side when the nozzle pressure ratio decreases. Reducing the pressure ratio from 0.8 to 0.6 will enhance the dehydration efficiency by about 5%.
Extended finite element simulation of fracture network propagation in formation containing frictional and cemented natural fractures J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 XiaoLong Wang, Fang Shi, Chuang Liu, DeTang Lu, He Liu, HengAn Wu
Shale gas reservoirs often need hydraulic fracturing treatments to create complex fracture network to enhance production. Frictional and cemented natural fractures are often contained in shale formations. The interactions between the hydraulic fractures and these two types of pre-existing natural fractures are different. In this study, we established a two-dimensional fluid-solid coupled hydraulic fracturing model using the extended finite element method (XFEM) to simulate the interactions between hydraulic fractures and natural fractures, and further the formation of fracture network. The results show that when a hydraulic fracture intersects with a natural fracture, the hydraulic fracture may be arrested and propagate along the direction of natural fracture, or cross the natural fracture without being affected. For the frictional natural fractures, the intersection angle, frictional coefficient, stress anisotropy and rock tensile strength have a significant influence on creating fracture network. It is found that decreasing stress difference and interfacial friction, or increasing rock tensile strength may lead to more complex fracture network. For the cemented natural fractures, the intersection angle and the ratio of cement toughness and rock toughness play critical roles in the creation of fracture network. Smaller intersection angle and cement toughness of NFs and larger rock fracture toughness often lead to more complex fracture network. In addition, for the same initial geometrical configuration of natural fractures, hydraulic fracturing often leads to more complex fracture network in formations containing frictional natural fractures compared with formations containing cemented natural fractures. These findings offer new insights into the nature and degree of fracture complexity, helping to optimize hydraulic fracturing design in shale gas reservoirs.
Mathematic modelling of the debrining for a salt cavern gas storage J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-19 Tongtao Wang, Shuanglong Ding, Huimeng Wang, Chunhe Yang, Xinlin Shi, Hongling Ma, J.J.K. Daemen
Debrining is one of the key steps to complete the construction of a salt cavern gas storage, which determines whether the cavern can transfer to underground gas storage (UGS) and the effective volume of a salt cavern UGS. A mathematical model is proposed based on the change characteristic of the dynamic depth of the interface between gas and brine and the pressure equilibrium principle to predict the parameters of the debrining. The calculating equations of debrining parameters, such as, total debrining time, gas injection pressure, gas injection volume per day, and cumulative gas injection volume, are deduced. A calculating program is developed based on the deduced equations by using Visual Basic computer language. To verify the proposed mathematical model, MZ-1 cavern of Jintan salt district, Jiangsu province, China, is simulated as an example. Based on the calculating results, the debrining parameters of MZ-1 cavern are optimized. These parameters were used in the debrining of MZ-1 cavern. By comparing the analytical results with field monitoring data, the proposed mathematical model is shown to have a high accuracy. The error between the predicting results and the field monitoring data is less than 5%, which can satisfy the requirement of actual debrining prediction. Research results can provide the parameter optimization and prediction for the debrining of salt caverns used for gas storage in Jintan salt district and some other places with similar conditions.
A semi-analytical model for the relationship between pressure and saturation in the CBM reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-05 Zheng Sun, Xiangfang Li, Juntai Shi, Tao Zhang, Dong Feng, Fengrui Sun, Yu Chen, Jiucheng Deng, Liujie Li
At present, analyzing and predicting CBM production performance remains challenging, which can be attributed to the complex gas-water two phase flow and dynamic nature of petro-physical properties. For the sake of simplicity, the saturation distribution in coal seams is generally overlooked and characterized by average water saturation in previous literature, which one can easily handle analytically, semi-analytically, and numerically. However, average water saturation is inadequate to obtain the precise value of pseudo pressure for water/gas phase, which may generate large deviation compared with actual production behavior. To our best knowledge, the relationship between pressure and saturation in coal seams is still lacking in the petroleum industry. Thus, the main objective of this research is to gain a clear understanding of this issue. In this work, on the basis of rigorous derivation, a semi-analytical model for the relationship between pressure and saturation is developed, which comprehensively accounts for the presence of free gas at the early production stage, matrix shrinkage and gas desorption. Notably, the stress dependence effect is incorporated during the entire production process of CBM wells. Subsequently, employing the gas-water two phase relative permeability data, we present an iterative numerical algorithm to solve the model. Moreover, the proposed semi-analytical model is successfully verified against a numerical reservoir simulator. After that, we shed light on the influences of physical parameters upon the saturation distribution versus pressure and achieve a variety of new insights. This research, for the first time, presents a semi-analytical model to quantify the relationship between pressure and saturation, which fills the gap for the theory of gas-water two phase flow in CBM reservoirs. The proposed model is less data-intensive than performing a numerical simulation and turns out to be simple and powerful in the application. In addition, the new model can significantly contribute to the obtainment of precise pseudo pressure for water/gas phase, therefore lays the theoretical basis for the accurate production prediction for CBM wells.
Elastic parameters from constrained AVO inversion: Application to a BSR in the Mahanadi offshore, India J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 K.P. Arun, Kalachand Sain, Jitender Kumar
We have estimated P-wave velocities (VP) and thicknesses from traveltimes data, and S-wave velocities (VS) and densities (ρ) from amplitudes versus offset (AVO) data by constraining the VP for a set of seismic reflection data including a bottom simulating reflector or BSR (marker for gas hydrates) in the Mahanadi offshore. The elastic parameters (VP, VS and ρ) of the whole-layered model have been derived simultaneously using the genetic algorithm global optimization technique that converges into a global minimum. The result shows a low velocity (1506 m/s) free-gas zone below the BSR that lies at 241 m below the sea floor. The presence of underlying free-gas is further corroborated by the observation of increasing negative reflection coefficients with angles. The VP and VS for gas hydrates bearing sediments above the BSR are estimated to be 1655 and 468 m/s respectively, and match reasonably with the sonic log at site NGHP-01-08A passing through the seismic line. Gas-hydrates and free-gas have been qualitatively estimated as 7.0% and 0.9% using three-phase weighted equation of Lee and Gassmann equation respectively. The combined usage of VP and VS corresponding to a Poisson ratio of 0.4565 provides a better estimation of gas hydrates, which shows comparable result that has been estimated using the Simandoux equation to the resistivity log data at site NGHP-01-08A.
A numerical investigation on the effects of rock brittleness on the hydraulic fractures in the shale reservoir J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Zhichao Li, Lianchong Li, Ming Li, Liaoyuan Zhang, Zilin Zhang, Bo Huang, Chun'an Tang
Hydraulic fracturing is an extensively used technique for development of oil and gas resources. In the shale reservoir, rock brittleness plays an important role during hydraulic fracturing. In this paper, a numerical code known as RFPA (Rock Failure Process Analysis) is introduced and the embedded digital-image-based (DIB) technique is illustrated in detail. Based on this integration, the effects of rock brittleness on the failure mode and stress-strain characteristic of the shale specimens are numerically investigated. It is found that the brittle shale specimen is more likely to rupture with multi crossed failure planes while the ductile specimen is more likely to rupture with a penetrating failure plane, from which we deduce the brittle shale is easier to develop more natural fractures than the ductile shale. The influence of natural fractures on complex hydraulic fracture network is further investigated through numerical simulation and the positive effect of rock brittleness is indirectly verified. It is found that hydraulic fractures are preferable to propagate in brittle minerals, i.e. the hydraulic fractures always choose the brittle minerals as the favorite path to propagate or choose a thin or weak part of ductile minerals to penetrate and is blocked by the ductile minerals. Moreover, the hydraulic fractures generated in the brittle shale are tortuous and appear with multi branches, which is much beneficial to form hydraulic fracture network in contrast to the smooth hydraulic fracture generated in the ductile shale. This is probably one of the causes of that the required treatment pressure in ductile shale layer is higher than that in brittle shale layer.
Investigation on the kinetics of carbon dioxide hydrate formation using flow loop testing J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Shidong Zhou, Yuhong Yan, Di Su, Seetharaman Navaneethakannan, Yuandao Chi
As a potential replacement for CH4 C H 4 hydrates in the petroleum industry and as an environment-friendly secondary refrigerant in the chemical industry, CO2 C O 2 hydrates are proven for several industrial applications. Most of the studies on CO2 C O 2 hydrates are mainly conducted in bench top facilities with very limited research work in the flow loop. A newly built high-pressure flow loop was used to investigate the effect of four parameters (initial pressure, temperature, flow rate, and liquid loading) on CO2 C O 2 hydrate formation. The process of hydrate formation and its morphological evolution in the flow loop were observed visually and analyzed. The experimental results revealed that the gas consumption increased as the initial pressure increased; however, it decreased with the increase of the temperature, flow rate, and liquid loading. The effect of the induction time on CO2 C O 2 hydrate formation was also analyzed in detail.
Mechanical mechanisms of T-shaped fractures, including pressure decline and simulated 3D models of fracture propagation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Dali Guo, Shu Zhang, Tiejun Li, Xiao Pu, Yunxiang Zhao, Biao Ma
Successful hydraulic fracturing (HF) operation requires an accurate model for simulating the propagation of fractures. In this paper, a novel mechanism for the formation of T-shaped fractures and a three-dimensional propagation simulation for predicting their dimensional parameters prior to HF treatment are presented. Furthermore, a pressure decline analysis model (PDA) is also developed for calculating the dimensional parameters after HF treatment. Experimental results show that the two models can accurately simulate the T-shaped fractures and provide a valid data for the optimization and evaluation of HF treatments.
Multi-objective optimization of a multi-layer PTSA for LNG production J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Masood Sheikh Alivand, Fatola Farhadi
In this work, a novel multi-layer pressure-temperature swing adsorption (PTSA) process was designed for efficient simultaneous water and mercaptans removal from natural gas (NG) to less than 0.1 ppmv and 3 ppmv in a mini liquefied NG unit. The proposed multi-layer PTSA consists of a three-layer fixed bed including activated alumina, molecular sieves 4A and 13X. To gain in-depth insights about the process, a descriptive model considering mass, energy and momentum balances, along with the kinetic and equilibrium equations was developed. After validating the model with the experimental and operational data from the literature, the total energy requirement and long-term operational requirements (e.g. maximum water and mercaptan removal during regeneration process) were optimized. Results of the multi-objective optimization revealed that substitution of present series of dehydration and mercaptan removal columns with an integrated multi-layer PTSA for NG purification can decrease 5.1% of energy consumption, which is approximately equivalent to 137 GJ each year. The outcomes of this study can be used as an innovative design strategy for NG purification (i.e. the combination of dehydration and mercaptan removal columns in a single multi-layer PTSA bed) and can also provide process engineers with a cost-effective tool for the optimization of regeneration parameters in the present PTSA systems.
A new numerical investigation of cement sheath integrity during multistage hydraulic fracturing shale gas wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Xi Yan, Li Jun, Liu Gonghui, Tao Qian, Lian Wei
Volume fracturing of shale gas wells has been observed to lead to the failure of cement sheath and to sustained casing pressure (SCP). This paper presents a new numerical investigation aimed at understanding the failure mechanism of the cement sheath during volume fracturing. A wellbore temperature model was established to obtain the required input parameters for the dynamic temperature boundary. The numerical model considers the coupling of casing, cement sheath, and formation rock to calculate the radial and tangential stresses in the cement sheath. In addition to the cement mechanical properties, the influencing factors considered include the casing pressure, fracturing fluid displacement, and initial temperature. The cement sheath integrity was evaluated using the Mohr-Coulomb failure criterion. The results show that the temperature of cement sheath changes drastically during fracturing. The radial and tangential stresses in the cement sheath change continuously with time. Lowering the internal wellbore pressure can effectively reduce the radial and tangential stresses in the cement sheath. Reducing the fracturing fluid displacement can significantly lower the radial and tangential stresses in the cement sheath. Increasing the initial fracturing fluid temperature will cause the radial stress of cement sheath to increase and the tangential stress to decrease. The use of cements with low Young's modulus values can significantly reduce the radial and tangential stresses in the cement sheath. The use of cements with low Poisson's ratio values can lower the tangential stress. The results obtained using the model were verified by field data that demonstrated no occurrence of casing pressure when using a cement with a low elastic modulus, as suggested by the model.
Fast method for the hydraulic simulation of natural gas pipeline networks based on the divide-and-conquer approach J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Peng Wang, Bo Yu, Dongxu Han, Dongliang Sun, Yue Xiang
To apply an implicit method to simulate a natural gas pipeline network, all involved components should be solved in a coupled manner. Therefore, the computation burden and time sharply increase with the network size and complexity rise. To solve this problem, a fast method, which is the decoupled implicit method for efficient network simulation (DIMENS) based on the divide-and-conquer approach, is proposed. In this method, first, the hydraulic variables of all multi-pipeline interconnection nodes are solved; next, the pipeline network is divided into several independent pipelines, and the equations for all pipelines are solved. Compared with the Stoner Pipeline Simulator (SPS), which is a well-known commercial pipeline simulation software worldwide, the DIMENS method yields comparable calculation accuracy with 2.5 times the calculation speed of the SPS. The DIMENS method has strong adaptability to the simulation of the pipeline network, and the computing time in the test example depends linearly on the number of grid nodes or number of pipelines.
High-pressure CO2-CH4 selective adsorption on covalent organic polymer J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Siew-Pei Lee, N. Mellon, Azmi M. Shariff, Jean-Marc Leveque
Most of the newly discovered gas reservoir has high CO2 content (up to 70%), thus pose critical challenges to gas separation process due to the limitation of current acceptable technology. Recent report on COP-1 showed its potential as sorbent for CO2 capture due to its high adsorption capacity, low cost sorbent with good water resistance. However, scarce data on the potential of COP-1 and its selectivity for CO2/CH4 adsorbent for high pressure operation were reported. In this study, the adsorption isotherms were gravimetrically measured using magnetic suspension balance (MSB) within the range of 50–100 bar, at isothermal temperatures of 298, 318, 328 and 338 K. Langmuir and Sips isotherm models were correlated to the adsorption equilibrium data at critical and supercritical conditions. The ideal adsorption selectivities for CO2/CH4 separation were also predicted using Ideal Adsorbed Solution Theory (IAST). The ideal selectivity obtained (∼22) shows good separation performance for CO2 from CH4 onto COP-1. Furthermore, isosteric heats of adsorption calculated from Clausius-Clapeyron equation reveals that physisorption is the dominant factor for the interaction between adsorbates and surface of COP-1. Results also showed that the isostearic heat of COP-1 is a strong function of temperature and adsorbed amount. Nevertheless, the adsorption behaviour of COP-1 found in this work gives a good indication on the utilization of COP in CO2/CH4 separation for unexploited natural gas reservoir with high CO2 content.
CO2 sequestration in depleted methane hydrate sandy reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Yu Liu, Pengfei Wang, Mingjun Yang, Yuechao Zhao, Jiafei Zhao, Yongchen Song
CO2 sequestration technology is crucial for carbon capture and storage (CCS). This study explores the sequestration behavior of CO2 as a hydrate in depleted methane hydrate (MH)-bearing sediments. MH formation and dissociation, CO2 injection, and water injection processes are experimentally simulated using glass beads to evaluate the entire technological process. The effects of different parameters on CO2 hydrate formation are analyzed to evaluate hydrate-based CO2 sequestration technologies. The aqueous water distribution minimally changes during the gas hydrate formation and dissociation in this study. For all the cases considered, local hydrate formation channels are not generated at the axis or wall of the vessel during the CO2 injection process. The saturation of the CO2 hydrate and residual water after the CO2 hydrate formation is proportional to the initial reservoir water saturation. This is the first study to propose water injection to promote the formation of CO2 hydrates, which are beneficial for CO2 sequestration. The amount of injected water decreases as the CO2 hydrate saturation increases before the water injection. A qualitative analysis indicates increased formation of CO2 hydrates during the water injection and promotion of the CO2 sequestration.
Incorporation of thermally labile additives in carbon membrane development for superior gas permeation performance J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 N. Sazali, W.N.W. Salleh, A.F. Ismail, N.A.H.M. Nordin, N.H. Ismail, M.A. Mohamed, F. Aziz, N. Yusof, J. Jaafar
Incorporating thermally labile polymer additives into carbon membrane development is highly practical due to its process simplicity and effective approach. In this study, different polymer composition of thermally labile additives such as polyvinylpyrrolidone (PVP), microcrystalline cellulose (MCC) and nanocrystalline cellulose (NCC) were introduced into the BTDA-TDI/MDI (P84-copolyimide) polymer solution. The P84-copolyimide based carbon tubular membranes were fabricated using dip-coating method and characterized in terms of its thermal stability, structural morphology and gas permeation properties. Initially, the NCC was introduced as a pore performing agent in the carbon membrane fabrication for carbon dioxide (CO2) separation. Our finding indicated that the use of NCC as pore performing agent significantly promoted an increment of pore structure channel in carbon membrane. As a result, the high permeance as well as high selectivity was demonstrated in this study. Pure gas permeation tests were performed using CO2, CH4, O2 and N2 at room temperature. The increment of both gas permeance and selectivity were observed in the NCC-containing carbon membranes prepared with a composition of 7 wt%. The promising CO2/CH4 selectivity of 68.23 ± 3.27, CO2/N2 selectivity of 66.32 ± 2.18 and O2/N2 selectivity of 9.29 ± 2.54 with respect to neat carbon membrane were presented. Thus, upon further investigation, the potential of NCC as thermally labile additive in carbon membrane was assured.
A new openhole multistage hydraulic fracturing system and the ball plug motion in a horizontal pipe J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Benchun Yao, Qingxin Ding, Yue Hou, Shuhai Liu, Shimin Zhang
Gas well stimulation based on a ball-drop fracturing system is a widely adopted operation in the oil & gas industry. The flow resistance of a multistage fracturing pipe string increases as the number of stages grows, which is a major problem for the traditional graduated ball-drop multistage fracturing system, as it can increase the load of the pump and may ultimately result in a high-cost operation. A new openhole multistage hydraulic fracturing system, which has unlimited multistages, activated by ball plugs is proposed to improve the operation efficiency. In this system, all the downhole sliding sleeves are a single size, and a group of ball plugs activate them to achieve full-inner-diameter pipe access. As a key part of the fracturing system, the approximate cylinder-shaped ball plugs would suffer from a larger resistive force in the horizontal pipe than that of the sphere-shaped fracturing ball. Therefore, a simplified miniature indoor experiment setup is built to investigate the motion of the ball plug. The physical dimensions of the cylinder models and the velocities of the pumping flow vary in the experiment. In addition, the motion in the cylinder models are observed with a high-speed camera. Finally, the experimental data are analysed by a combination of dimensional analysis and the empirical equation method, and the results can help to determine the pumping rate during operations.
Influence of organic and inorganic content on fractal dimensions of Barakar and Barren Measures shale gas reservoirs of Raniganj basin, India J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Subhashree Mishra, Vinod Atmaram Mendhe, Atul Kumar Varma, Alka Damodhar Kamble, Sadanand Sharma, Mollika Bannerjee, M.S. Kalpana
The carbonaceous shale beds of Barren Measures and Barakar Formations of Raniganj basin have been investigated for organic and inorganic content influence on the matrix containing micro, meso, macropores, structures and related fractal dimensions. The significant amount of TOC suggests slow suspension during the consolidation of the sediments in an abundant river channel owing to low energy environmental conditions. The adequate thermal maturity indicates shale beds of both the Formations are good to excellent source rock for dry hydrocarbon genesis. The plot of ln(ln(P/P0)) versus ln(V) have shown three distinct straight line sections within the whole relative pressure range (0.0000–1.0000), further denoted as Region I (P/P0 = 0.0002–0.0090; D1), Region II (P/P0 = 0.0090–0.3000; D2) and Region III (P/P0 = 0.3000–1.0000; D3) and the linear fitting equations were obtained with different slopes. The values of D1, D2, D3, signifying the complexity of micro-, meso- and macropores, providing supplementary sites for gas adsorption. Fractal dimensions have shown a positive correlation with clay content, whereas negative correlation with total organic content indicates that inorganic content plays a vital role in the rugged surface formation useful for gas storage. The positive linear correlation of fractal dimensions (D1 and D2) with Langmuir volume accentuated that smaller pores (micro and meso) contains ideal rugged surfaces suitable for gas adsorption due to heterogeneity, irregular pore surfaces, complex pore openings and structures. Furthermore, D3 shown negligible negative correlation with VL specifies the larger pore size do not provide sites for adsorption space, because of the altered smooth surfaces formed during diagenesis. An empirical method for estimation of sorption capacity (ESC) has been proposed taking into account of the positive and negative influence of the fractal dimensions, clay, minerals and total organic content. The strong positive linear relationship of Langmuir volume (VL) with an empirically estimated sorption capacity (ESC) (R2 = 0.86) and about 90% curves match, signifies the proposed empirical formula can be used as an indirect method for estimation of sorption capacity of shale samples.
Shale oil and gas resources in organic pores of the Devonian Duvernay Shale, Western Canada Sedimentary Basin based on petroleum system modeling J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Pengwei Wang, Zhuoheng Chen, Zhijun Jin, Chunqing Jiang, Mingliang Sun, Yingchun Guo, Xiao Chen, Zekai Jia
Shale-hosted hydrocarbons is regarded as an important unconventional resource around the world. So far, huge emphasis has been put on the contribution of organic pores to self-source and self-reservoir hydrocarbon systems. This study systemically reveals the contribution of organic pores to hydrocarbon potential in the Duvernay Shale through restoring thermal maturity evolution, modeling hydrocarbon generation and expulsion in the Duvernay Formation, analyzing absorption capacity variation with TOC and modeled pore pressure, determining free-gas storage capacity with calculated organic porosity and correction of adsorbed gas, and calculating in-place shale oil and gas volumes with volumetric method. The Duvernay Shale reached “oil window” and “gas window” about 70–80 Ma and 50 Ma ago, respectively. Significant hydrocarbon generation (20% TR) began and terminated (95% TR) at Ro of 0.65% and 1.85%, respectively. Gas generation rates increased dramatically from Ro of 1.1%, while the instantaneous HC1-4 expulsion reached peak at Ro of 1.66%, the difference between which indicates considerable retained gas resource in Duvernay Shale. The gas storage capacity, including absorption capacity and free gas capacity, varies significantly in the Duvernay Shale, specifically, the former rangs from 8 to 30scf/ton, and the latter from 40 to 140scf/ton. The estimated median value of total in-place natural gas (GIP) and in-place oil resource (OIP) in organic pores of Duvernay shale are 404.8 TCF and 81420 MMbbl, respectively. Thus, the organic porosity is one of the keys to make the Duvernay Shale a successful play.
Analysis of the wellhead growth in HPHT gas wells considering the multiple annuli pressure during production J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-12-02 Weibiao Qiao, Han Wang
In high-temperature and high-pressure (HPHT) gas wells, the wellhead growth caused by temperature and pressure effects during production might damage the well integrity. A calculation model of the wellhead growth produced by temperature and pressure effects was built. For the case well, the maximum pressures of annulus A, B and C are 64 MPa, 48 MPa and 38 MPa, respectively. The maximum production and intervention time are 114.5 × 104 m3/d and 540 d, respectively. Based on the calculation process, the maximum wellhead growth is 412.7 mm. The axial load caused by the multiple annuli pressure is second only to that caused by the casing axial temperature difference. Wellhead growth increases with the annulus fluid thermal expansion coefficient and decreases with the annulus fluid isothermal compression coefficient. The increasing annulus temperature difference might aggravate the effect of annulus fluid thermal properties on the wellhead growth. Selecting the casing with greater wall thickness and lower thermal expansion coefficient can reduce the wellhead growth. The annulus width has little effect on the wellhead growth while the annulus length will significantly change the wellhead growth. The wellbore multiple annuli pressure can increase the wellhead growth prominently. The annulus pressure management shall be introduced into the production. Optimizing the well structure and production plan and installing the wellhead monitoring equipment contribute to mitigating the wellhead growth.
Some contents have been Reproduced by permission of The Royal Society of Chemistry.
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