Geological conditions of deep coalbed methane in the eastern margin of the Ordos Basin, China: Implications for coalbed methane development J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-19 Song Li, Dazhen Tang, Zhejun Pan, Hao Xu, Shu Tao, Yanfei Liu, Pengfei Ren
Deep coalbed methane (CBM) resource potential is enormous in China, and has become a new field for unconventional natural gas exploration and development. This work discusses the geological conditions (reservoir pressure, formation temperature and ground stress) of deep coal reservoirs in the Eastern margin of the Ordos Basin and their implication on CBM development. Various field test data of CBM wells, including injection/drawdown test data, well temperature test data, and hydraulic fracturing test data were collected from this work and literature to describe the geological conditions of the deep CBM in the study area. From the results, it is found that deep CBM in this area is characterized by high reservoir pressure, high formation temperature, and high ground stress. However, there are diverse geological particularities in the different depth range: (1) Having a wide range of pressure gradient, vast majority of coal reservoirs in the study area are under abnormally low-pressure state, which is more significant in deeper coal seams. (2) Due to the impact of surface runoff, the distribution of geothermal gradient is discrete when the burial depth is less than 700 m, and relatively concentrated when the burial depth is greater than 700 m. (3) In shallow coal reservoirs, ground stress is strongest in the horizontal direction; while in deep coal reservoirs, the strongest ground stress is in the vertical direction. Because of the complex geological conditions associated with deep burial, the balance between CBM adsorption-desorption-seepage and the rheological behavior of coal reservoirs is complex, which has significant influence on the exploration and development of deep CBM in the study area. High pressure in deep coal reservoir often leads a long inefficient desorption stage and a long draining and depressurizing process, which increases production costs. Moreover, the negative temperature effect on gas adsorption indicates that CBM content decreases with increasing depth in deep conditions, and thus the evaluation of deep CBM resources needs to be reconsidered. In addition, different stress states govern fracture patterns, and in deep environments, high ground stress greatly reduces the fracturing improvement of the coal reservoir and significantly affects the deep CBM development.
Shale gas enrichment conditions in the frontal margin of Dabashan orogenic belt, south China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-19 Jianwei Kang, Yuanyuan Sun, Yupeng Men, Jingchun Tian, Qian Yu, Jianfei Yan, Jiashan Lin, Jun Liu
In this study, we carried out a survey on organic-rich mudstones of Wufeng-Longmaxi formations in the frontal margin of Dabashan orogenic belt where geological structure is complex, aiming to investigate the shale gas enrichment condition and their major controlling factors. Methods including optical microscope observation, Scanning Electron Microscopy (SEM), organic geochemistry and tests of porosity, permeability, gas-bearing property, and Specific Surface Area have been applied in this study. Based on these comprehensive information collected from both the field and the laboratory, the general geological characteristics and distribution of organic-rich mudstones of Wufeng-Longmaxi formations are summarized. In the Late Ordovician-Early Silurian epoch, organic-rich mudstones were probably deposited in the continental shelf, with the thicknesses ranging from 31.5 to 156.4 m in the frontal margin of Dabashan orogenic belt, and the averaged value of total organic carbon in these mudstones varies from 2.43 to 5.17 wt% in different localities. Values of BET specific surface area range from 1.57 to 29.15 m2/g. Thermal maturity is high because Ro values vary from 1.20 to 2.58% in this region. The mineral composition, i.e., low clay mineral content (16.14–27.88%) and relatively high brittle mineral content (larger than 72.12%), is proper for future fracturing. Although the permeability and porosity values are relatively low, respectively 0.0001–0.0472 × 10−3μm2 and 0.36–3.51% in average, they are still higher than the lower limit of favorable condition of shale gas accumulation. Based on the shale gas evaluation and exploration experience conducted in this geologically complex area, we suggest that the shale gas generation conditions are good in the Dabashan area, but the preservation conditions are quite different from place to place in the tectonically complex area. In general, the preservation conditions are of the utmost importance for shale gas enrichment in Dabashan area. A comparison of failed to the successful cases of exploration wells in the frontal margin of Dabashan suggests that relatively stable box-shaped anticlines, like Tianba and Manyue anticlines, are beneficial for shale gas storage. Information obtained from this study can be used as a good reference for shale gas reservoir evaluation and the selection of shale gas Sweet Spots in further study of this region. Furthermore, the research conducted in this area provides useful experience for shale gas exploration in the tectonically complex region in the world.
Investigating the relative impact of key reservoir parameters on performance of coalbed methane reservoirs by an efficient statistical approach J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-19 H. Akhondzadeh, A. Keshavarz, M. Sayyafzadeh, A. Kalantariasl
The complex and unique production mechanism of CBM has been examined extensively; however, production from such reservoirs requires more investigation to be well-understood, predicted and enhanced. This study is aimed at probing the significance of some controlling parameters on CBM performance by a statistical approach. The relative impact of five CBM reservoir parameters (reservoir pressure, cleat permeability and porosity, Young's modulus and Langmuir pressure) on the performance of natural depletion as well as Enhanced Coalbed Methane (ECBM) were numerically investigated. Recovery factor (RF) for primary depletion and ECBM, original gas in place (OGIP) and CO2 storage were the investigated responses. In order to conduct the research, a synthetic CBM reservoir model was constructed using a commercial reservoir simulator. Since the effects of reservoir parameters on CBM production are quite complicated, it was intended to explore the potential interaction effects between the parameters along with the relative impact of each parameter. Therefore, a professional statistical software, Design Expert, was selected to determine the parameters' effects. The results show that while recovery factor value in primary recovery has positive correlations with all of the five parameters, cleat permeability and Langmuir pressure play the most significant roles. For ECBM by CO2 injection, cleat permeability has the most significant effect on recovery factor measure, followed by cleat porosity. The predicted model for ECBM recovery factor suggests that Young's modulus, opposite to the primary recovery condition, has an adverse relationship with RF and the cleat porosity-permeability interaction has a considerable negative effect on RF measure. The predicted coalbed methane OGIP model proposes that in comparison with pressure and Langmuir pressure, the relative impacts of the other three parameters are negligible. Furthermore, results reveal that CO2 storage is positively affected by cleat porosity and permeability, and negatively affected by Young's modulus and Langmuir pressure.
Global mass conservation method for dual-continuum gas reservoir simulation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-16 Yi Wang, Shuyu Sun, Liang Gong, Bo Yu
In this paper, we find that the numerical simulation of gas flow in dual-continuum porous media may generate unphysical or non-robust results using regular finite difference method. The reason is the unphysical mass loss caused by the gas compressibility and the non-diagonal dominance of the discretized equations caused by the non-linear well term. The well term contains the product of density and pressure. For oil flow, density is independent of pressure so that the well term is linear. For gas flow, density is related to pressure by the gas law so that the well term is non-linear. To avoid these two problems, numerical methods are proposed using the mass balance relation and the local linearization of the non-linear source term to ensure the global mass conservation and the diagonal dominance of discretized equations in the computation. The proposed numerical methods are successfully applied to dual-continuum gas reservoir simulation. Mass conservation is satisfied while the computation becomes robust. Numerical results show that the location of the production well relative to the large-permeability region is very sensitive to the production efficiency. It decreases apparently when the production well is moved from the large-permeability region to the small-permeability region, even though the well is very close to the interface of the two regions. The production well is suggested to be placed inside the large-permeability region regardless of the specific position.
Three-dimensional hydro-mechanical model of borehole in fractured rock mass using discrete element method J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-15 Ehtesham Karatela, Abbas Taheri
Borehole stability, in heavily fractured rock mass has been a significant issue in deep earth resources exploration and extraction. In this study, a three-dimensional model using 3DEC is developed to simulate a borehole drilled in fractured rock mass. A model with overbalanced drilling conditions is simulated in this study. In doing so, different depths of a borehole, MB-1 borehole, in Northern Perth basin was simulated. The developed model was validated against log measurements of Caliper log and strength of rock is found as a governing factor in controlling the stability. Then, hydro mechanical modelling was carried out and it was observed that high mud flow rates and high pore pressure increased the instability around borehole. Furthermore, a parametric study was performed to investigate the influence of viscosity and fluid flow on the stability. Shear displacement linearly increase with an increase in flow rate while fluid pressure decreases due to increase in fractures aperture with an increase in flow rate. Similarly, increase in viscosity caused increase in fracture shearing and therefore instability around borehole.
Numerical simulation and experiment on the law of urban natural gas leakage and diffusion for different building layouts J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-13 Aihua Liu, Jian Huang, Zhiwen Li, Jieyun Chen, Xiaofei Huang, Ke Chen, Wen bin Xu
To provide a more reliable theoretical basis for emergency-management decisions following accidental natural gas leaks, a numerical simulation and an experiment were conducted in this study to investigate the effects of complex construction environments on natural gas leakage and diffusion laws. The design of a building was divided into an enclosed layout, a patch layout, and a street canyon layout, from the perspective of their impact on environmental winds. Natural gas leakage and diffusion in three layouts were simulated using a three-dimensional computational fluid dynamics (CFD) model, in which both the distribution of natural gas concentration and dangerous areas were determined through comparative analysis. The results of a small-sized experiment showed that the blocking function of an enclosed layout for environmental wind was the highest, its vortex effect was the strongest, and its range of high gas concentration was the widest among the layouts. A cavity among the buildings was the site of major gas accumulation, making it the most crucial area for the emergency management of accidental natural gas leaks. The proposed CFD model was demonstrated be able to be used to simulate and predict the diffusion of natural gas in cases of accidental leakage. And the results of this study can guide building layout planning and gas pipeline construction to prevent accidents.
A mechanism for generating the gas slippage effect near the dewpoint pressure in a porous media gas condensate flow J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-12 Baghir A. Suleimanov, Arif A. Suleymanov, Elkhan M. Abbasov, Erlan T. Baspayev
This paper presents an experimental study of gas condensate flow in porous media at pressures above the dewpoint pressure. Experimental studies of steady-state flows show that the gas flow rate starts to increase when the pressure significantly exceeds the dewpoint pressure (P = 1.74 P≿). The gas flow rate reaches its peak and is almost 30% higher than that near the critical point (P=Pc) at P = 1.5 P≿. Furthermore, the dependence of the gas flow rate on the pressure is non-monotonic and increased flow rates are reached when P = 1.4–1.74 P≿. The effect of wettability on the steady-state flow is considered. Changes in wettability do not increase the gas flow rate in the oleophobic porous media. A significant reduction of the hydraulic diffusivity of the porous medium occurs during unsteady-state flow when the pressure decreases. The observed effects are thought to be driven by formation of stable subcritical condensate nuclei, along with a slippage effect and changes in compressibility. The mechanism of stabilization of subcritical nuclei via combined action of the surface and electrical forces is considered and mathematical models that describe the experimental results are proposed.
An integrated approach to simulate fracture permeability and flow characteristics using regenerated rock fracture from 3-D scanning: A numerical study J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-11 W.A.M. Wanniarachchi, P.G. Ranjith, M.S.A. Perera, T.D. Rathnaweera, C. Zhang, D.C. Zhang
Fluid flow in a rock fracture bounded by two rock surfaces with surface asperities is a complex phenomenon to study. However, precise knowledge of the flow characteristics through a real rock fracture is essential in order to design and estimate the efficiency and production of unconventional oil and gas exploration and geothermal energy extraction projects. The aim of this numerical study, is therefore to incorporate a rock fracture in the modelling platform using a pre-processing procedure and to couple it with the flow parameters. 3-D scanning technology was used to obtain the rock fracture surfaces and to generate the fracture profile in a grid matrix form. In addition, the generated fracture profile was imported in to the COMSOL Multiphysics software package to simulate the flow characteristics of the rock fracture. The COMSOL model was validated using experimental permeability results conducted under triaxial conditions. According to the results, the COMSOL numerical model can simulate the flow characteristics through the rock fracture with more than 90% accuracy compared to the experimental data. The numerical results also reveal that the pressure gradient through a rock fracture is nonlinear and depends on the fracture profile. Furthermore, the nonlinearity of pressure gradient varies on different sections of the fracture, confirming the heterogeneity nature of the fracture. In addition, the results illustrate that the entire fracture width does not contribute to the final flowrate and that it is essential to consider the effective fracture width in flow calculations.
Statistical grid nanoindentation analysis to estimate macro-mechanical properties of the Bakken Shale J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-09 Kouqi Liu, Mehdi Ostadhassan, Bailey Bubach, Kegang Ling, Behzad Tokhmechi, Dietrich Robert
Retrieving standard sized core plugs to perform conventional geomechanical testing on organic rich shale samples can be very challenging. This is due to unavailability of inch-size core plugs or difficulties in the coring process. In order to overcome these issues, statistical grid nanoindentation method was applied to analyze mechanical properties of the Bakken. Then the Mori-Tanaka scheme was carried out to homogenize the elastic properties of the samples and upscale the nanoindentation data to the macroscale. To verify these procedures, the results were compared with unconfined compression test data. The results showed that the surveyed surface which was 300 μm ×300 μm is larger than the representative elementary area (REA) and can be used safely as the nanoindentation grid area. Three different mechanical phases and the corresponding percentages can be derived from the grid nanoindentation through deconvolution of the data. It was found that the mechanical phase which has the smallest mean Young's modulus represents soft materials (mainly clay and organic matter) while the mechanical phases with the largest mean Young's modulus denote hard minerals. The mechanical properties (Young's modulus and hardness) of the samples in X-1 direction (perpendicular to the bedding line) was measured smaller than X-3 direction (parallel to the bedding line) which reflected mechanical anisotropy. The discrepancy between the macromechanical modulus from the homogenization and unconfined compression test was less than 15% which was acceptable. Finally, we showed that homogenization provides more accurate upscaling results compared to the common averaging method.
Numerical investigation of mineralogical composition effect on strength and micro-cracking behavior of crystalline rocks J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-09 Louis Ngai Yuen Wong, Jun Peng, Cee Ing Teh
Mineralogical composition has a great influence on the mechanical behavior and the micro-cracking process of crystalline rocks for CO2 and natural gas storage. This study numerically investigates the influence of mineralogical composition (i.e., quartz content) of a dominantly felsic phaneritic igneous rock with respect to rock strength and the associated micro-cracking behavior using a grain-based modeling approach in two-dimensional Particle Flow Code (PFC2D). First, numerical specimen models with different mineralogical compositions are generated. The generated numerical models have the same geometry of the assembled grain structure to minimize the effect of grain scale heterogeneity on the simulation results. Micro-parameters previously calibrated to match the macro-properties of the Bukit Timah granite are then assigned to the numerical models. In the numerical simulation of uniaxial compression tests, the strength and Young's modulus are found to increase with the increase of quartz content in the numerical model, while the Poisson's ratio and the maximum volumetric strain gradually decrease. The simulated strength behavior is in good agreement with the laboratory test results obtained from previous studies. However, the crack damage stress seems not to be affected by the quartz content. The total number of generated micro-cracks is also found to gradually increase as the quartz content in the numerical model increases. The rock strength shows a good correlation with the total number of generated micro-cracks. Two mechanisms are identified to initiate the nearly vertical macroscopic fractures which are generated in tension. At last, the influence of spatial distribution of mineral grains on the simulated strength property and micro-cracking behavior is discussed.
Numerical modeling of multiple fractures propagation in anisotropic formation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-07 Qingdong Zeng, Wenzheng Liu, Jun Yao
In this study, a fully coupled model is presented for simulating the propagation of multiple hydraulic fractures in anisotropic formation. Rock anisotropy is captured by using anisotropic constitutive relation to describe solid deformation and using modified maximum circumferential stress to determine fracture propagation. Besides, fluid flow in the wellbore is established to partition injection into each fracture for consideration of stress shadowing effect. The extended finite element method is used in the discretization of stress equation, and Newton’ iteration is proposed to solve the fully coupled problems. The numerical method is verified against other solutions for one fracture and two fractures propagation problems in the literature. The effect of rock anisotropy on hydraulic fractures is analyzed in the following aspects: material angle, ratio of Young's modulus and fracture toughness. If material angle is not aligned with fractures initiating direction, fractures would deflect towards the direction of material angle. Ratio of Young's modulus could enhance this effect, but it is in the opposite for ratio of fracture toughness. Results indicate that the simultaneous propagation of multiple hydraulic fractures in anisotropic formation is determined by two competing factors: stress shadowing and rock anisotropy.
Mass analysis of CH4/SO2 gas mixture by low-pressure MEMS gas sensor J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-07 M. Barzegar Gerdroodbary, D.D. Ganji, Iman Shiryanpour, Rasoul Moradi
The mass analysis of natural gas for the extraction and separation of the undesirable component such as sulfur dioxide is significant for industrial applications. In this research, numerical simulations are performed to investigate the capability of the Knudsen thermal force for the detection of sulfur dioxide in CH4/SO2 gas mixture. Recently, a new micro gas sensor (MIKRA) is introduced to apply this force for measurement of the pressure. In fact, this device operates due to temperature difference inside a rectangular enclosure with heat and cold arms at low pressure condition. In order to simulate a rarefied gas inside the micro gas detector, Boltzmann equations are applied to obtain high precision results. To solve these equations, Direct Simulation Monte Carlo (DSMC) approach is used as a robust method for the non-equilibrium flow field. This study has focused on the effect of various concentrations of the CH4/SO2 gas mixture and reveals the main mechanism of force generation inside the device. Our findings show that value of generated Knudsen force significantly changes when the fraction of SO2 in CH4/SO2 gas mixture is varied. This indicates that this micro gas sensor could precisely detect the concentration of sulfur dioxide gas inside a low-pressure CH4/SO2 gas mixture.
Lattice Boltzmann simulation of gas flow and permeability prediction in coal fracture networks J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-06 Yan-long Zhao, Zhi-ming Wang, Jian-ping Ye, Han-sen Sun, Jiao-yang Gu
The cleat or natural fracture system is a dominant factor controlling the permeability of coal seams. Gas permeability and porosity of coal samples with artificially generated fractures are measured under varying effective stress. Based on the experimental results and the Walsh model, fracture width and roughness are estimated. Considering the fracture aperture and roughness, we present a 3D geometry model to reconstruct coal fracture networks on the basis of the Voronoi tessellations. The lattice Boltzmann method (LBM) is applied to simulate fracture flows and to predict the associated permeability. For comparison purposes, simulations in a single fracture are carried out initially. For a single smooth fracture, the results of LBM simulations show a good agreement with the cubic law. For a single rough fracture, the cubic law overestimates the permeability, and it is two to four orders of magnitude higher than the laboratory measurement. The predicted permeability by LBM simulation is in acceptable agreement with laboratory measurement. Furthermore, the flows through the fracture networks with smooth fracture surfaces are simulated. By comparison to the matchstick model, simulation errors are mostly within 30%. Finally, the effects of structure, surface roughness and aperture on flows in fracture networks with rough fracture surfaces are investigated. The present study provides a promising approach to predict the associated permeability and transport characteristics in coal fracture networks.
Production behavior and numerical analysis for 2017 methane hydrate extraction test of Shenhu, South China Sea J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-01 Lin Chen, Yongchang Feng, Junnosuke Okajima, Atsuki Komiya, Shigenao Maruyama
As one promising energy resource, methane hydrate (MH) has extracted worldwide attention in recent years. In 2017, a new series of methane hydrate (MH) extraction tests was executed both in China (Shenhu Area, South China Sea) and Japan (Nankai Trough), which led to new round of intense scientific research and engineering developments toward the common goal of robust production technology. This study is focused on the production behavior analysis and numerical predictions for 2017 tests in Shenhu Area, South China Sea. Based on the open production data, the detailed production process, characteristics and future prospects are re-constructed and numerically discussed, so as to provide a general view of the production behaviors and potential prediction in this region. Numerical simulations on the mid-term (60 days) production process are designed and found good agreement with the real production tests, where the short-to mid-term production rate is estimated to drop from 3.5 × 104 m3/d to around 2.0 × 103 m3/d within 60 days, which is then extended for mid-to long-term (2–3 years) prediction of gas production. Parameter behaviors and field information such as the near-wellbore effects are also discussed into detail based on the numerical results. In addition, future concerns based on recent tests in China and Japan in 2017 are also included in this study, so as to provide a general viewpoint for oceanic methane hydrate extraction.
Computational investigation on effects of geo-mining parameters on layering and dispersion of methane in underground coal mines- A case study of Moonidih Colliery J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-01 Devi Prasad Mishra, Durga Charan Panigrahi, Pradeep Kumar
Managing methane and preventing methane layering is of paramount significance for safety in gassy underground coal mines. Methane layering behaviour and dispersion of methane in underground coal mines are influenced by several geo-mining parameters. In this paper, we investigate the effects of five important geo-mining parameters, such as air velocity, methane emission rate, width, surface roughness and inclination of mine gallery on methane layering and dispersion of methane in tailgate of a retreating longwall mine. The main objectives are to examine the effects of these parameters on variation of methane concentration and identify the critical parameters significantly affecting methane dispersion to a safer level in hard coal underground mines. Three-dimensional CFD simulations were performed using standard k-ε turbulence model taking into account the actual mine geometry and methane emission data of a gassy underground coal mine of India. The study revealed that air velocity plays a vital role on turbulent dispersion of methane and breaking methane layering in underground coal mines. Air velocity of 3.0 m/s was found adequate for dispersing methane to a safer level in the tailgate with 7.26 m3/min methane emission rate. Methane dispersion in the tailgate decreased with increase in methane emission rate and gallery width at a particular airflow rate. Increase in surface roughness and inclination of mine galley eased methane dispersion, nevertheless, their effects on methane dispersion found negligible.
Introducing optimized validated meshing system for wellbore stability analysis using 3D finite element method J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-03-01 Babak Ravaji, Sohrab Mashadizade, Abdolnabi Hashemi
Finite element method (FEM) as a powerful tool for studying stress and strain status is being extensively employed in geotechnical studies. As the initial and boundary conditions, element type, and meshing system heavily affect the accuracy and precision of the results obtained from FEM, in this research we present a novel approach which is optimized and validated by the results obtained from reality. At first a mechanical earth model (MEM) was constructed using different well logging data, results of core analysis, and drilling reports for one of the central Iranian carbonate reservoirs. Then, a depth range was selected in the pay zone of a vertical well for FEM simulation. The selected depth range consists of two different zones: the upper zone with normal faulting regime and the lower zone with strike-slip faulting regime. After studying different model sizes, mesh densities, element types, and boundary conditions, a cylindrical model consist of a combination of regular and irregular hexahedral elements for far-field region, and fine-grained tetrahedral elements for near-wellbore region was obtained. Two different approaches were selected for FEM modeling, in the first approach a pre-drilled well was considered in the model, and in the second approach the model geometry before drilling without a pre-drilled well was subjected to an initial state of stress, removal of the elements, and loading which simulate the drilling process using a certain mud weight. The results of simulating the state of strains around the wellbore using this meshing system in both FEM approaches had acceptable adoption with drilling data.
Crushing characteristics of four different proppants and implications for fracture conductivity J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-28 Wenbo Zheng, Suyanne Costa Silva, Dwayne D. Tannant
Proppants are widely used during hydraulic fracturing in the oil and gas industry. This paper compares the crushing characteristics of four different types of proppant with three different size ranges that are widely used for hydraulic fracturing in North America. The proppant properties were evaluated using data obtained from a modified crush test. The grain shape before the test, the grain breakage pattern, the stress-strain response of the proppant pack, and the change in particle-size distribution caused by compressive stresses of up to 40 MPa were measured. At the higher compressive stresses, significant differences were observed between the various proppant types as well as for different size ranges for a given proppant type. The results show that the constrained moduli of resin-coated sand and ceramic proppant are 30% higher than those for Jordan sand and Genoa sand. Genoa sand exhibits more grain crushing than Jordan sand, while resin-coated sand and ceramic proppant experienced only minor fracturing at compressive stresses of 40 MPa. The grain shape and size distribution measurements were used to empirically estimate and compare the permeability and fracture conductivity for different proppant packs. Mesh 20/40 and 30/50 ceramic proppants, and mesh 20/40 resin-coated sand are predicted to have twice the permeability of the other proppants at 40 MPa. A good agreement was found between the estimated permeability and published laboratory results for fracture conductivity. This indicates that careful characterization of the particles obtained from a crush test can provide a fast and reliable approach for evaluating proppant pack permeability and fracture conductivity as well as changes in these properties under different compressive stresses without the need to conduct elaborate conductivity tests. Empirical equations quantifying permeability change for four types of proppant with three different sizes are derived with the effect of proppant embedment on fracture conductivity considered. These equations can be incorporated into hydrocarbon production simulations to select proppant types and sizes.
Stochastic generation of virtual porous media using a pseudo-crystallization approach J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-28 Meysam Rahmanian, Apostolos Kantzas
A new algorithm is proposed to generate virtual porous media based on predefined porosity and particle size distribution (PSD). Synthetic packings of different porosities, sphericities, and PSD curves are numerically constructed using the proposed approach. Based on these virtual porous material empirical correlations are tuned for estimation of permeability and formation factor as functions of porosity and median grain size. The proposed procedure is inspired from crystallization concept addressing the capability of dealing with tight media with no porosity limitation and the flexibility to easily control the grain sphericity. The post-processing results, including estimation of permeability, formation factor and electrical resistivity, are compared with experimental data. Besides, a sensitivity analysis is conducted to elucidate the impact of grain irregularity (sphericity) on permeability.
Modeling of curving hydraulic fracture propagation from a wellbore in a poroelastic medium J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-28 Yongcun Feng, K.E. Gray
Understanding near-wellbore hydraulic fracture behaviors is vital for hydraulic fracturing treatments and other injection-related operations in the petroleum industry. This paper presents a fully coupled fluid flow and geomechanics model for growth of hydraulic fractures in the near-wellbore region. The model is developed within the framework of the extended finite element method (XFEM). Fracture initiation and propagation, fracturing fluid flow, rock deformation, and pore fluid flow are coupled into the XFEM framework. The model is validated against experimental results in the literature. Capabilities of the proposed model for capturing fracture geometry, fluid flow, and local stress and pore pressure distributions are illustrated with numerical examples. A parametric study is carried out using the model to investigate a few operational parameters’ effects on near-wellbore fractures. Some recommendations are provided for reducing fracture tortuosity and breakdown pressure based on the results of the parametric study. The XFEM model proposed in this paper provides an efficient tool to predict arbitrary hydraulic fracture growth in the wellbore vicinity. It can be used to aid designs of various hydraulic fracturing related operations in the petroleum industry, such as fracturing stimulations, injectivity tests, waterfloods, and waste injections.
Impact of non-linear transport properties on low permeability measurements J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-26 Yuan-Yun Lin, Michael T. Myers
The results of modeling nonlinear transport properties on a plug scale for steady state, unsteady state, pulse decay and sinusoidal pressure measurements are presented. We include the gas slippage (Klinkenberg corrections) and pressure dependent density effects. To validate the modeling, we compare it to analytical calculations based on an assumption of constant mass flow once the transients have dissipated for steady state models. Validation of the other measurement protocols is performed by comparison to finite difference calculations. For low permeability samples, significant pressure drops must be modeled to obtain large enough flow rates to allow accurate measurement in the laboratory. We limited ourselves to 100 psi pressure differences because of the large influence of effective stress on gas density that would be present for larger pressure differences. Flowing pressures of this magnitude imply significant pressure dependent density effects, which reduce the flow rates. In contrast, gas slippage increases the transport of gas. The result is that nearly identical fits are obtained for widely varying magnitudes of permeability and gas slippage. This result is obtained for all of the modeled measurement protocols. We introduce a new technique to interpret the modeled data, the ”k0-b plot”. The method allows the values of k0 and b to be extracted if multiple measurements are performed at different mean pressures. The technique is also compared to laboratory data to demonstrate that the effects occur in the measurements. The influence of the non-linearities predicted on the measured chamber pressures are presented for each of the measurement protocols (other than steady state in which there are no chambers). In particular, sinusoidal pressure variation of the upstream chamber results in an increased average downstream chamber pressure and the introduction of harmonic distortion. These effects have not been discussed in the literature and give a motivation for development of this measurement for low permeability samples. The modeling indicates that plug scale measurements are practical, but multiple mean pressures must be used to separate the competing effects of permeability and gas slippage. We recommend performing unsteady state measurements at reservoir stress at multiple mean pressures, supplemented with sinusoidal pressure and pulse decay to calibrate the nonlinear and adsorption effects.
Study on the pore structure and fractal characteristics of marine and continental shale based on mercury porosimetry, N2 adsorption and NMR methods J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-26 Zhiqing Li, Xin Shen, Zhiyu Qi, Ruilin Hu
Shale gas, as one kind of unconventional gas, is an important energy supplement. The pore structure characteristic is an important index using to measure and evaluate shale reservoir quality. The Weiyuan marine shale (1#), Jiaoshiba marine shale (2#), Yaoqu tuff (4#) and Yaoqu continental shale (5# and 6#) were selected and subjected to mercury porosimetry (MP), N2 adsorption (NA) and nuclear magnetic resonance (NMR) tests. The relationships between fractal dimensions and pore structure have been investigated by MP, NA and NMR to characterize the pore anisotropy. The results illustrate that the fractal dimensions of continental sample 5# and 6# are bigger than that of marine sample 2# in the pore range between 0.1 and 100 μm based on MP method. The fractal dimensions of marine sample 2# is bigger than those of continental sample 5# and 6# in the holes range between 2 and 200 nm based on NA method. In contrast, the fractal dimensions max(DNMR) of marine sample 2# is the largest among all the samples in the holes range between 10 nm and 10 μm based on NMR method. Especially, the fractal dimensions of Jiaoshiba marine sample 2# are biggest among all summarized samples in the holes range between 2 and 100 nm using NA and NMR method. That is to say the micropores of Jiaoshiba marine shale are the most development. Maybe it is one of the important reasons to obtain a great success of shale gas exploration in China. Therefore, the fractal dimension, as an important parameter, can be used to evaluate the fracturing effect of shale reservoir.
An experimental study of the anisotropic permeability rule of coal containing gas J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-26 Dengke Wang, Ruihuan Lv, Jianping Wei, Ping Zhang, Chong Yu, Banghua Yao
To examine the characteristics of the anisotropic seepage of the coal containing gas, a study of the anisotropic seepage rule of the coal containing gas was carried out based on the tri-axial seepage experimental system with raw coal samples. The calculation method determined the principal value and the azimuth of the anisotropic permeability of the coal containing gas. Also, the permeability anisotropic ratio of the coal containing gas was defined. The permeability anisotropic dynamic variation rule and the phenomenon of the change of the dominant flow direction of the coal containing gas were thoroughly analyzed. The results showed that the flow of the methane in the coal had very obvious characteristics of anisotropy. The calculation method of anisotropy permeability of the coal containing gas proposed in this study was found to be simple and effective. The coal containing gas displayed strong stress-sensitivity. The variation rule between the permeability of the methane in the coal and the effective stress was determined to be in accordance with the negative exponential function. The change of the permeability anisotropy of the gases in the coal with effective stress showed an obvious dynamic change law of development, and changes were observed in the dominant flow direction of the gas in the coal.
On the fundamental difference of adsorption-pores systems between vitrinite- and inertinite-rich anthracite derived from the southern Sichuan basin, China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-26 Changan Shan, Tingshan Zhang, Xing Liang, Zhao Zhang, Meng Wang, Kun Zhang, Haihua Zhu
To further understand the fundamental difference of adsorption-pores systems between vitrinite- and inertinite-rich anthracite, six coal core samples with >85% vitrinite and three samples with >80% inertinite were collected from coalbed methane wells in the southern Sichuan basin, China, by macerals analysis method. The differences of pore genetic types, pores shapes, pore surfaces roughness, pore-size distribution, specific surface area, total pore volume, physical properties, and CH4 adsorption capacity between vitrinite- and inertinite-rich samples, were studied via ESEM observation, low-temperature N2 adsorption experiments, NMR tests, and CH4 isothermal adsorption experiments. Results show that plant tissue holes are easier to observe in inertinite than vitrinite, and blowholes, breccia pores and broken pores are all common in vitrinite and rare in inertinite of the study coals. Both vitrinite- and inertinite-rich coal samples exhibit complex nano-pore structures, and pore shapes in inertinite-rich coals are more special than those in vitrinite-rich samples. Fractal dimensions analysis from the N2 adsorption isotherms indicates that inertinite-rich coals have the higher surfaces roughness of irregular pores than vitrinite-rich coals in the P/Po intervals of 0.5–1. In addition, it can be predicted that pores of D2 and D3 type hysteresis loops with diameters of <2.76 nm each are almost semi-closed pores, and the narrow neck in “ink bottle” pores generally measure 2.76 nm. Nano-pores measuring <4 nm comprise the largest proportion among all adsorption-pores. The proportion of pores with diameters of <0.64 nm each in inertinite-rich coals is greater than that in vitrinite-rich coals. NMR porosities, permeabilities, and irreducible water saturations between vitrinite- and inertinite-rich coals are all similar, and the porosities display a good exponential positive correlation with the permeabilities. Vitrinite- and inertinite-rich samples are both characterized by a large VL, and there are positive relationships of VL with vitrinite and inertinite, indicating the CH4 adsorption capacity of organic macerals is much stronger than that of inorganic minerals in anthracite.
The time-space prediction model of surface settlement for above underground gas storage cavern in salt rock based on Gaussian function J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-24 Jing Wenjun, Zhao Yan, Kong Junfeng, Huang Chenchen, Khalil Moh'd Khalil Jilani, Li Haoran
Research shows that the volume shrinkage of the underground storage cavern in salt rock is the basic reason why surface settlement appears above storage caverns. In order to further study the quantitative relationship between cavity volume shrinkage and surface settlement, this paper starts from the form of the reservoir surface settlement curve, selects Gaussian function to match the profile curve of the surface settlement basin above the single cavity gas storage, proposes a settlement prediction method that is similar to the Peck curve of tunnel surface settlement and establishes a space prediction model of surface settlement for storage cavern which can reflect directly the relationship between cavity shrinkage of storage cavern and surface deformation. Then with the consideration of surface settlement changing over time, and through introducing the analytical formula of volume shrinkage of the cavern in the stage of steady creep, the predicting analytical formula of annual subsidence rate in the reservoir is obtained and the time-space prediction model of surface settlement above gas storage cavern in salt rock is established. Finally, the paper takes a storage cavern in Yunying salt mine as an example, compares the result of prediction model with the result of numerical simulation to verify the accuracy of this prediction model and proves its feasibility. This research provides a simple and reliable prediction method for the surface settlement prediction during the operation of underground storage cavern in salt rock and has an important guiding significance for the long-term safe operation of underground storage caverns and environmental protection in mining areas.
Investigation of fracture propagation characteristics caused by hydraulic fracturing in naturally fractured continental shale J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-24 Zhiheng Zhao, Xiao Li, Jianming He, Tianqiao Mao, Guanfang Li, Bo Zheng
Continental shale from the Ordos Basin, China, is naturally fractured and characterized by silty laminae and interbeds that is different from marine shale. To investigate the hydraulic fracture propagation in this kind of shale, hydraulic fracturing experiments were performed in cylinder continental shale samples under different stress ratio conditions, and propagation characteristics of the visible surface fractures, the main fractures as well as the main fracture surfaces were observed and discussed. The results reveal that the visible induced fractures on the sample surfaces primarily extend along natural fractures, bedding planes and interbeds, and situation of crossing beddings and interbeds can be found, which is different from fractures in marine shale that are mainly vertical to bedding planes with some branches. Besides, the main fractures were observed and measured through electronic microscope. They are wavelike and tortuosity tends to increase as stress ratio decreases. Moreover, three dimensional scanner was employed to study the main fracture surfaces, and Area Ratio and Standard Deviation were used to evaluate the roughness. With the decrease of stress ratio, partial vertical fractures can be found on the main fracture surface, and Area Ratio and Standard Deviation get higher, which indicates that the roughness of the main fracture surfaces becomes higher. Therefore, hydraulic fracture propagation characteristics of continental shale are strongly influenced by the stress and some its own properties, including natural fractures, beddings and interbeds. And the result contributes to understanding the mechanism of hydraulic fracture propagation in continental shale formation.
Foam flow in porous media: Concepts, models and challenges J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-24 Hamed Hematpour, Syed Mohammad Mahmood, Negar Hadian Nasr, Khaled Abdalla Elraies
This paper aims to elaborate foam concepts and foam flow modeling approaches in porous media. Furthermore, this review summarizes and compares all existing foam models approaches including Mechanistic, Semi-Empirical and Empirical. Finally, it discusses foam models in different reservoir simulators in detail and presents different approaches for obtaining models’ parameters in simulators. The comparison results showed that Emprical models are more suitable for simulation study due to less required paramters and faster calculation; however, these models might not be a appropriate in transient foam flow. Moreover, the challenges about he results of this review provide an valuble insight about foam behaiviour.
Numerical simulation and parametric analysis for designing High Energy Gas Fracturing J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-24 Feipeng Wu, Xuemei Wei, Zhixi Chen, Sheik S. Rahman, Chunsheng Pu, Xiaojun Li, Yanyu Zhang
This paper presents a new comprehensive approach to model High Energy Gas Fracturing (HEGF) process. This coupled model consists of 6 sub-quantitative modules, including (1) loading build-up due to propellant deflagration, (2) gas-liquid interface displacement caused by killing liquid column movement, (3) stress distribution around the casing wellbore and the perforation holes, (4) fluid penetration through the perforation holes, (5) rate dependent critical pressure of fracture initiation and (6) hydro-mechanical coupled fracture propagation. The solution to the coupled model is obtained combining the analytical method and finite difference method, which solves the mass conservation equation and energy conservation equation with the subsystem pressure and temperature as the main variables. Subsequently, The single pulse and the multi-pulse HEGF processes are simulated. The dynamic changes of the loading built-up of propellant deflagration, the movement of killing liquid column as well as the dynamic propagation of fracture are further studied. Meanwhile, in-depth analysis has been applied on the affect sensitivity of the five key parameters to the single pulse HEGF results as well as the mechanism of multi-pulse HEGF. The results indicate that the final lengths of fractures generated by single pulse HEGF can be extended with the increase of the perforation density, the diameter of perforation holes, the thickness of propellant column and the total propellant quality. However, the effect of the height of killing liquid column is insignificant. It also demonstrates that the multi-pulse HEGF could bring multiplier fractures length by concatenating series propellants with different burning rates. This coupled model could add new dimensions to the understanding of the coupled mechanism of single pulse and multi-pulse HEGF. In addition, the model could be applied as a parameters quantitative design tool to assist the field implementation of these technologies.
Permeability characteristics of remolded tectonically deformed coal and its influence factors J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-24 Jianting Zhai, Jilin Wang, Guanwen Lu, Xiupei Qin, Weizhong Wang
The characterisations of Tectonically deformed coals (TDCs) are different from those of undeformed coals. Permeability characteristics of TDC and its influence factors should be studied deeply. In this paper, five samples of TDCs in various degrees of deformation and one undeformed coal were selected. The microstructure was observed by using scanning electron microscope. The pore structure characteristics were analyzed through a mercury injection experiment. Permeability was tested by steady flow. In TDCs, the crumpled and cracked microstructures are well developed and the mesopores and macropores account for large proportions. The permeability of TDC is mainly controlled by structural deformation degree, effective stress (or effective confining pressure), adsorption swelling effect and slippage effect. On the premise of only effective stress increasing, the internal space of deformed coal is compressed and the slippage effect is weakened. The both factors contribute to the permeability reducing in an exponential form. On the premise of only pore pressure increasing, the gas seepage channels are narrowed and obstructed because of the adsorption swelling effect and the slippage effect is also weakened. In this case, the permeability will also be reduced. In TDCs, the pores and fractures are strongly developed, the gas seepage channels are markedly unobstructed and the slippage effect is enhanced. Thus, the permeability of TDC is much larger than that of undeformed coal. Generally, the permeability change rate of TDCs is larger than that of undeformed coal and shows a negative correlation with effective confining pressure. The stress sensitivity coefficient of permeability also shows a negative correlation to the deformation degree of coals.
Experimental investigation of in situ stress relaxation on deformation behavior and permeability variation of coalbed methane reservoirs during primary depletion J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-23 Ruimin Feng, Satya Harpalani, Suman Saurabh
Dynamic evolution of coal deformation and permeability, induced by changes in in situ stresses with continued depletion in coalbed methane (CBM) reservoirs, has been extensively investigated both experimentally and theoretically. However, the impact of stress-/strain-controlled mechanics on permeability variation is somewhat unclear. To examine this behavior, gas flow experiments were conducted under best replicated in situ conditions. Considering that coal anisotropy may lead to changes in deviator stress and coal failure behavior during primary depletion, core flooding experiments were carried out to investigate the anisotropic behavior of coal. Using the experimental results, Mohr's circle of strain was first employed to facilitate the process of analyzing the dynamic deformation behavior of coal. Next, a strain-based failure criterion was developed to analyze the failure tendency of CBM reservoirs in order to explain the sudden increase in permeability observed during experimental work. The results show that the abrupt increase in permeability can be attributed to shear failure of coal due to increased deviator stress resulting from in situ stress redistribution after significant depletion. This study sheds light on the influence of stress relaxation on coal deformation behavior, failure tendency and permeability evolution, with practical implication for gas flow modeling of CBM reservoirs.
Metals and radionuclides (MaR) in the Alum Shale of Denmark: Identification of MaR-bearing phases for the better management of hydraulic fracturing waters J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-22 Jérémy G. Lerat, Jérôme Sterpenich, Régine Mosser-Ruck, Catherine Lorgeoux, Isabelle Bihannic, Claire I. Fialips, Niels H. Schovsbo, Jacques Pironon, Éric C. Gaucher
Hydraulic fracking is used to enhance the production of tight gas reservoirs. Because shale reservoirs can contain toxic elements (metals and radionuclides), the release rates of these elements must be quantified in order to determine the possible environmental impact of fracking. This paper is devoted to the complete and precise determination of the mineralogy of the Alum Shale in Denmark, which is known for its high content of gaseous hydrocarbons. Its metal-bearing phases are identified and quantified using complementary analytical techniques (i.e., X-ray diffraction, electron microscopy and electron probe analysis, and X-ray tomography). A detailed quantitative mineralogical composition is calculated using three different approaches (i.e., matrix inversion, quantitative X-ray diffraction, and the MQ program), which is then used to determine the quantity of polluting elements in each phase. Pyrite (FeS2) is the major metal-bearing phase (e.g., As, Cu, Co, Ni, Pb, Zn, V, U). Elements such as V, Ra, Cs, Be, Cr, Ba are trapped in clay minerals, whereas U, Cd, Mo, and Hg are present in organic matter. It is essential to better identify toxic element-bearing phases to formulate fracking fluids with the lowest possible chemical reactivity in order to avoid the release of pollution by flowback waters.
Wellbore breakouts: Mohr-Coulomb plastic rock deformation, fluid seepage, and time-dependent mudcake buildup J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-21 Xiaorong Li, Hamza Jaffal, Yongcun Feng, Chadi El Mohtar, K.E. Gray
Borehole breakout is a time-dependent failure process which includes breakout initiation, propagation, and stabilization. Plastic rock deformation, fluid seepage, and time-dependent mudcake buildup on the wellbore wall affect the near-wellbore stress state and, therefore, the breakout behavior. In this paper, a hydro-mechanical model was developed for breakout prediction taking into account these factors. Filtration tests were conducted to obtain time-dependent permeability and thickness of mudcake, and the experimental testing results were incorporated to embody the dynamic mudcake buildup process. A sensitivity analysis was performed to investigate the effects of horizontal stress anisotropy, drilling mud pressure, and time-dependent fluid flow and mudcake buildup on breakouts in a vertical borehole. The simulation results show increased possibility of breakouts with larger horizontal stress anisotropy. Additionally, fluid seepage between the wellbore and the surrounding formation makes the breakout a time-dependent process. For low mud pressure, the initial breakout shape immediately after drilling is very similar to the final breakout shape after reaching steady state seepage. However, for high mud pressure, the wellbore may experience significant breakout propagation after drilling, owing to considerable fluid seepage associated with the larger differential pressure between the wellbore and the formation. Time-dependent mudcake buildup on the wellbore wall can effectively reduce the likelihood of borehole breakout by acting as a low-permeability barrier that mitigates fluid seepage across the wellbore wall and reduces changes in formation pore pressure. Disregarding the mudcake or considering a perfectly impermeable mudcake can lead to overestimating or underestimating the risk of borehole breakout, respectively. The proposed model provides a useful approach to understand and assess borehole breakout for drilling design.
Synergistic management of flowback and produced waters during the upstream shale gas operations driven by non-cooperative stakeholders J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-21 Li He, Yizhong Chen, Lixia Ren, Jing Li, Lei Liu
Shale gas has been denoted as one of alternative energy sources for meeting future energy demands and received global attention, especially with aid of technological advances in horizontal drilling and hydraulic fracturing. This study focuses specially on synergistic optimization of the Marcellus shale-gas-water supply chains with consideration of economics and pollutants mitigation through a mixed-integer bi-level programming model. This model could account for conflicting objectives and interactions between different stakeholders. Operational decisions regarding well drilling schedule, production planning, freshwater withdrawals, wastewater disposal and infrastructure expansion would be provided for both leader and follower in a sequential manner. Moreover, comparative analyses among the bi-level model and the two single-level models disclose that the bi-level decisions would increase nearly 8.6% of shale gas production, 12.3% of economic benefits, 8.0% of water consumption, as well as 4.5% of pollutants discharge as compared with the environmentally-aggressive policies. By contrary, the bi-level decisions would lead to 8.5% decrease of shale gas production, 6.1% decrease of economic benefits, 7.3% decrease of water usage, and 6.0% decrease of pollutants discharge when compared with the economically-aggressive solutions. These findings could assist the stakeholders in resolving of conflicts among pollutants reduction, economic performance, and water supply security.
Porosity estimation in kerogen-bearing shale gas reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-21 Hongyan Yu, Zhenliang Wang, Reza Rezaee, Yihuai Zhang, Tongcheng Han, Muhammad Arif, Lukman Johnson
Porosity is a fundamental petrophysical parameter in shale gas reservoirs that governs the space for hydrocarbon storage, and directly determines the free gas amount and absorbed gas capability. Technically, in kerogen-bearing shales, well-log derived porosity may yield inaccurate results as the porosity tools in response to both the kerogen and the liquid-filled pore spaces that are often undifferentiated. In this paper, we propose a new method for porosity estimation in kerogen-bearing shales, where porosity is assumed to be composed of both matrix porosity and kerogen porosity. The kerogen responses of density, sonic and neutron logs are first calculated from experimental data to calibrate porosity logs with the kerogen volume. The matrix porosity is then computed using the improved Wyllie equation based on the calibrated logging data with the kerogen influence removed. The kerogen porosity is estimated by a mass-balance relation based on the original total organic carbon (TOCo) and kerogen maturity characterized by the percentage of convertible organic carbon (Cc) and the transformation ratio (TR). Application of the new method to a shale gas reservoir in the Ordos Basin, China shows that the estimated porosity matches the core derived porosity satisfactorily well. Furthermore, the results also indicate that the shale kerogen porosity is relatively higher than the shale matrix porosity when the kerogen amount and maturity are high. The results of the study lead to a better understanding of the shale formation and thus contribute towards the better evaluation of shale gas reservoirs.
Modeling injection-induced seismicity through calculation of radiated seismic energy J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-21 Z. Khademian, M. Nakagawa, U. Ozbay
Seismicity induced by the injection of fluid into the fractured ground is one of the most challenging issues facing geothermal and deep wastewater disposal industries. This paper introduces an energy-based numerical methodology to study the role of injection pressure in triggering rupture (seismic slip) along preexisting faults. The methodology is developed in the Universal Distinct Element Code (UDEC) using its quasi-static and dynamic schemes and calculates the total seismic energy radiated by a rupture when more energy is made available in the system than can be stored or consumed. We study the effects of fluid injection on rupture dynamics by pressurizing a single fault surrounded by impermeable rock, representing a simplified analogy for the injection process in deep wastewater disposal and geothermal activities. Along with developing the methodology, we study effects of raising the fluid pressure on initiating rupture over well-oriented (or critically loaded) and misoriented faults. Results show that fluid injection can trigger a rupture along both well-oriented and misoriented faults although the notion of seismicity may be observed along the well-oriented fault as early as the beginning of the injection process. The well-oriented fault generates higher seismic energy magnitude as more energy is available for rupture due to the higher peak shear stress and stress drop on the fault. Making simplifying assumptions, this study also found that fluid can be injected under a high-pressure increment before and after the fault initial activation while the radiated seismic energy remains relatively insignificant. However, gradually increasing the fluid pressure at the onset of rupture reduces the radiated seismic energy by 30%. Comparing the seismic moment and radiated seismic energy for each event reveals that while radiated seismic energy varies between different values of pressure increment, the calculated seismic moment stays constant, showing the possible ineffectiveness of the seismic moment in representing the intensity of injection-induced ruptures.
Permeability evolution of anthracite coal considering true triaxial stress conditions and structural anisotropy J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-21 Yubing Liu, Minghui Li, Guangzhi Yin, Dongming Zhang, Bozhi Deng
It is critical to understand the gas flow behavior in coal under a reservoir stress condition for coal bed methane production, underground coal mining, and CO2-sequestration in deep coal seams. With respect to coal seams, the in-situ stress is anisotropic and generally exists under true triaxial stress (σ1 > σ2 > σ3) conditions. Additionally, the flow channels determining the permeability of coal are also anisotropic. This dual anisotropy produces difficulties in replicating the gas transport characteristics of coal at the laboratory scale, and there is a paucity of relevant studies. In this study, we performed a series of permeability measurements using cubic anthracite coal samples and changing the principal stresses and flow directions under various true triaxial stress conditions. The coal permeability exhibited greater anisotropy in the vertical direction as a result of the presence of minerals in cleats across the bedding plane. After each principal stress compression at a differential stress of 20 MPa, the permeability in each direction decreased by an order of magnitude. With an increase in the intermediate stress parameter, the permeability values of two horizontal cleats experienced higher decreasing rates compared with the vertical bedding permeability. This increased the significance of the horizontal permeability anisotropy. With respect to the true triaxial stress condition with a higher horizontal principal stress (σH > σh > σv), a higher permeability reduction was observed during the principal stress loading period. The butt cleat plane was more sensitive to changes in the principal stress because of the lower connectivity of the flow channels induced by the closure of the face cleat that acted as a cross-linked pathway. The anisotropic permeability data measured under true triaxial stress conditions were well expressed by an exponential equation containing different mean cleat compressibility and stress terms. The cleat compressibility values in different directions were obtained by data fitting.
Comparison of huff-n-puff gas injection and solvent injection in large-scale shale gas condensate reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-20 Sharanya Sharma, James J. Sheng
A compositional simulation approach is utilized to compare huff-n-puff gas and solvent injection in a shale gas condensate reservoir. Each injection process is analyzed in terms of the least cost, shortest payback period, smallest injected pore volume and maximized recovery of the condensate components. Two gases (methane and ethane) and two solvents (methanol and isopropanol) are chosen for the comparison. The reservoir model is calibrated based on available published rock and fluid properties, and history matching is carried out with production data. The model consists of heterogeneities representative of a shale reservoir such as a stimulated rock volume (SRV) and a non-stimulated rock volume (NSRV) that is intersected by a network of natural fractures. The reference model is used to understand and establish the basic recovery mechanisms of the four injection fluids while highlighting the principal differences between them. The effects of injection pressure, initial reservoir pressure, injection and production time, the gas-condensate composition and nanopore confinement are evaluated. Analysis of the performances of the four injection fluids are based on the total hydrocarbon recovery factors, combining the liquid and gas phases, calculated within the same operation time. Results demonstrate ethane to be a superior injection fluid with a high recovery factor for most scenarios, accompanied by a relatively higher profit to investment ratio and shorter payback period. Ethane injection recovers the heavy condensate components more efficiently compared to methane and solvent injection for a given gas condensate composition. This advantage is complemented by ethane's capability to equally recover all of other hydrocarbon components from the reservoir. The recovery performance of solvent huff-n-puff for a leaner gas condensate fluid is significantly greater than that for the richer gas-condensate reservoir fluid. The main difference in the optimization of gas and solvent performance is highlighted. Gases require longer injection and production time, whereas solvents perform better with shorter injection time and longer production time.
Investigating the potential of carbon dioxide utilization in a gas-to-liquids process with iron-based Fischer-Tropsch catalyst J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-19 Hadi Fazeli, Mehdi Panahi, Ahmad Rafiee
A Gas-to-liquids (GTL) process with two different synthesis gas (syngas) production configurations including steam methane reformer (SMR) and auto-thermal reformer (ATR) was optimized to maximize wax production rate and carbon efficiency. The kinetic model used was the one given by Van Der Laan for an iron-based Fischer-Tropsch (FT) reactor (Van Der Laan and Beenackers, 2000). In this paper, Wang's correlation (Wang et al., 2003) was used to calculate chain growth probability (α). It was assumed that there exists a 300 MW coal-fired power plant with a downstream post-combustion CO2 capturing unit nearby the GTL plant and all the captured CO2 is available to be utilized in the GTL process. The optimization results suggested that the ATR- and SMR-based GTL processes could produce 68.17 and 101.4 tons/h of wax, respectively. Furthermore, about 166.4 tons/h of CO2 was optimally imported from the power plant to the SMR, while there was no potential for CO2 utilization in the ATR-based configuration. The GTL process with either SMR or ATR reformers is net CO2 emitter and respectively releases ca. 194.1 and 131.3 tons/h of CO2 to the atmosphere.
Are the amino acids thermodynamic inhibitors or kinetic promoters for carbon dioxide hydrates? J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-19 Pinnelli S.R. Prasad, Burla Sai Kiran
This study deals with the carbon dioxide (CO2) hydrate formation in aqueous solutions, containing 0.5 wt% amino acids (L-valine, L-phenylalanine, L-cysteine, L-methionine and L-threonine) under isochoric conditions. Systematic experiments were conducted in both stirred (300 rpm) and non-stirred configurations. The hydrate formation requires higher sub-cooling than the pure CO2 system. The gas uptake in the hydrates, formed under stirred conditions, in l-val, l-cys and l-met systems is ∼20% higher than the pure system, while in other two (l-phe & l-thr) it is comparable to the pure system. Further, there is no appreciable gas uptake in pure, l-phe and l-thr systems under non-stirred conditions. On the other hand, the gas uptake is higher and faster, similar to stirred conditions, in other three systems, i.e., l-val, l-cys and l-met. Thus, the aqueous solutions consisting of these three amino acids are useful in the CO2 gas capture and storage applications.
Experimental study and isotherm models of water vapor adsorption in shale rocks J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-17 Weijun Shen, Xizhe Li, Xiaobing Lu, Wei Guo, Shangwen Zhou, Yujin Wan
The understanding of water vapor adsorption and equilibrium in the low permeability matrix of gas shale is crucial for predicting and optimizing gas productivity in shale gas reservoirs. In this study, water vapor adsorption isotherms for gas shale samples from the Lower Silurian Longmaxi Formation in Southern China were measured gravimetrically at two temperatures (30 °C and 50 °C) under the relative humidity ranging from 11.1% to 97.0%, and four different isotherm models were used to fit the experimental data and to analyze water vapor adsorption on shale rocks. The experimental results showed that water vapor adsorption for shale rocks followed a typeⅡsigmoid shape over the humidity range. At the lower humidity range, the monolayer-multilayer adsorption was the dominant process while capillary condensation and temperature effects became significant with relative humidity increasing. As the amount of total organic carbon increases, water adsorption weakens while calcite has an inhibitory effect. Through quantifying the average relative error (ARE), coefficient of determination (R2) and chi-square (χ2) of the isotherm models relative to data, the GAB isotherm model was identified to be the best-fitting isotherm to describe the water adsorption process in shale rocks. Moreover, the FHH plot was used to analyze and distinguish the states of water retention by adsorption and capillary condensation.
Simplified modeling of plunger-lift assisted production in gas wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-17 G.M. Hashmi, A.R. Hasan, C.S. Kabir
Liquid loading has been an issue for mature gas wells due to declining reservoir energy. In older fields, one of the methods used to mitigate this problem is plunger lift. However, the optimum design of a plunger lift is nontrivial. This paper presents a simplified modeling approach for the design of plunger lift for wells in gas reservoirs with significant water production. The proposed model allows for an efficient design of plunger lift by incorporating energy balance in the wellbore. The wellbore/reservoir model presupposes the presence of some liquid in the tubing and in the tubing/casing annulus, but most of the tubing and annular space is assumed to be filled with gas. Closure of the tubinghead valve initiates recuperation of reservoir energy, thereby allowing fluid influx to occur in the tubing and annulus. Eventually, accumulation of sufficient pressurized gas in the annulus lifts the plunger along with the liquid and gas on top of it. The model accounts for the pressure-volume (pV) work done by the pressurized gas in the annulus, including the energy needed to lift the liquid and gas on top of the plunger, and friction during the plunger movement. Because the dimensions and trajectory of the wellbore have such profound impact on the operability of plunger lift, operators can use this model by just providing the known input parameters to determine the design variables, target casing pressure, and duration of the plunger cycle.
Coal seam gas associated water production in Queensland: Actual vs predicted J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-17 J.R. Underschultz, S. Vink, A. Garnett
Coal Seam Gas (CSG) development in Queensland is currently going through a transition from less than 300 billion cubic feet/year (∼315 PetaJoules/year (PJ/yr)) for domestic consumption to ∼1400 bcf/yr (nearly 1500 PJ/yr) by about 2019 driven by additional Liquid Natural Gas (LNG) export contracts. Prior to this ramp up in production, industry, government and academia have been forecasting not only gas but associated water production (produced water) for the various purposes of financial investment decisions and field development planning, prudent governance and regulatory planning, and estimation of potential environmental impacts for planning management, monitoring and mitigation strategies. During the course of resource development, prediction methodologies and model sophistication has varied greatly as more data becomes available and uncertainty is reduced. In Queensland, now that all 6 LNG trains are running and at various stages of ramping up to full production, there is a substantial and growing data inventory to history match numerical models and improve forward forecasting. We review the historical forecasting of CSG water production in Queensland leading up to the development and operation of CSG to LNG export, and compare that to the current actual produced volumes now that the projects have come on stream. The latest available measured produced water from CSG development (December 2016) equates to ∼60.5Giga Litres/year (GL/yr) with combined operator forecasts defining a peak projected to occur for about 10 years at 70–80 GL/yr. When this is converted to cumulative water volumes over the life of the industry (based on combined operator forecasts), just over 1700 GL of water is expected to ultimately be produced. Current estimates of water and salt production in Queensland are about 25% of those made by government and academia prior to the expansion of CSG to LNG export and ∼70% of the 2010–11 industry estimates. We show that this discrepancy can be attributable to a combination of the following factors: 1. Gas industry conservatism (over-estimation) driven by the bias to reduce project risk and achieve gas delivery targets; 2. Government conservatism driven by a bias for prudent forecasting i.e. to assure that a credible worst case can still be managed within the regulatory framework; 3. Academia conservatism driven by a bias for understanding worse case scenarios of environmental impact; 4. The use of numerical models for basin scale impact assessment that do not take account of near-well multi-phase flow characteristics of saturation and relative permeability; and 5. A systemic underestimation of the cumulative effects on depressurization of the coal resource where one operator's asset requires less water production to reach target reservoir pressures due to neighbouring operator production. This is mainly because each operator only has access to its own development plans.
Discussion of “a semi-empirical model for peak strain prediction of buried X80 steel pipelines under compression and bending at strike-slip fault crossings” by Liu et al. (2016) J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-17 Mahdi Shadab Far
In the paper presented by Liu et al. (2016), herein referred to as the original paper, a regression model was developed to estimate the compressive strain induced in X80 steel pipes crossing strike-slip faults. Later, a corrigendum (2017) was written by the original authors to correct the problems with the proposed equation and Fig. 14 of the original paper. However, there is still one problem remaining with the paper that limits the application of the proposed equation and makes it difficult for readers to understand the content. In this short paper, the discusser points out the issue and provides the readers with an explanation of the problem that exist with the proposed model.
Maximizing fracture productivity in unconventional fields; analysis of post hydraulic fracturing flowback cleanup J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-16 H.R. Nasriani, M. Jamiolahmady
Hydraulic fracturing, is a promising stimulation technique which is also known as hydrofracturing, hydrofracking and fracking. During the hydraulic fracturing (HF), the rock is cracked, i.e., fractured, by a high pressure injection of a fluid which is known as fracturing fluid (FF). The FF is mainly water, carrying suspended sand or another type of proppants into the well to initiate fractures in the reservoir rock, and consequently, hydrocarbon and FF will move towards the well more easily through fractures. Hydro-fracturing is extensively used to increase the well productivity index, particularly in unconventional, tight and ultra-tight reservoirs. This expensive procedure, though, sometimes fails to meet expectations regarding the production enhancement. The leading explanations for this reduced performance is fracture clean-up inefficiency of the fracturing fluid (FF) that was primarily injected. In this study, a parametric investigation of FF clean-up effectiveness of fractures was performed with 143360 simulations (in 35 different sets) including injection, shut-in and production stages. Because of the vast number of simulation runs which was required to be implemented by a reservoir simulator, a computer code was developed and utilised to routinely read input data, implement the simulation runs and produce output data. In each set (which consists of 4096 runs), instantaneous impacts of twelve different parameters (fracture and matrix permeability (i.e., Kf and Km) and capillary pressure (Pc), end points and exponents of gas and FF in the Brooks-Corey relative permeability correlation in both fracture and matrix) were investigated. To sample the domain of variables and to study the results, full factorial experimental design (two-level FFS) and linear surface methodology explaining the dependency of the loss in gas production, compared to the case there is no loss (i.e., 100% clean-up) to the related parameters at different production stages were investigated through he tornado charts of the response surface models, frequency of simulation runs with obtained Gas Production Loss, GPL, and saturation distribution maps of FF. Results pointed out that in general, factors that control the mobility of FF inside the fracture had the most significant impact on cleanup efficiency. Conversely, in tight and ultratight sets, particularly when the applied pressure drawdown for the duration of production stage was small, the impact of fluid mobility within the matrix on gas production loss was more noticeable, i.e., it is crucial how fluids flow inside the matrix rather than how fast fracture is cleaned. In lower permeability matrix, in general, more gas production loss was detected and clean-up was slower. The impact of Pc on GPL minimisation was stronger when pressure drawdown was small and/or shut-in time was prolonged. As the formation becomes tighter, this observation was more pronounced, in other words, for such formations, the impact of a change in pressure drawdown and/or shut-in time on Pc and GPL was more noticeable. Additionally, the results showed that as the length of the fracture reduced the impact of fracture pertinent parameters (i.e., fracture permeability and fluid (gas and FF) mobility pertinent parameters of Corey correlation in the fracture) on GPL reduced and the impact of those pertinent parameters in the matrix on GPL increased. The impact of Pc on minimising GPL is less noticeable in shorter fractures and vice versa. As the length of fracture reduced, quicker fracture clean-up was detected compared to those for longer fracture. These discoveries help us to better understand the hydraulic fracturing process and can be used to settle issues regarding the performance of hydraulic fracturing and to improve the design of hydro-fracturing operations, which is an expensive but popular stimulation method for tight and ultra-tight reservoirs.
The characteristics of low permeability reservoirs, gas origin, generation and charge in the central and western Xihu Depression, east China sea basin J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-14 Ao Su, Honghan Chen, Xu Chen, Cong He, Hongping Liu, Qian Li, Cunwu Wang
Apart from conventional gas in the middle-shallow formation in the Xihu depression in the East China Sea Basin, low permeability gas sandstone layers in the middle-deep formation have recently been discovered. On the basis of integrated analysis of reservoir petrology and diagenesis, geochemistry of gas and source rocks, basin numerical modeling, gold-tube pyrolysis experiment of rocks and fluid inclusion, a comprehensive investigation of the characteristics of low-permeability reservoirs, gas origin, generation and charge in the sub-structural belts (West Slope Belt and West Sub Sag) has been performed. Strong mechanical compaction, filar authigenic illite, siliceous and carbonate cements are key factors for the formation of low permeability reservoirs. The comprehensive analysis of molecular components, stable carbon isotope compositions of gases and light hydrocarbons indicated that the low permeability gases in the WSB are mainly coal-derived and can be divided into two types: (1) mature gases sourced from local coal-measure rocks in the Pinghu Formation, (2) exogenous highly mature gases sourced from the coal-measure rocks in the Pinghu Formation in the WSS. Mature gases were injected into the low permeability reservoirs in the middle-lower Pinghu Formation at approximately 2.8Ma∼0Ma. In the meantime, partial highly mature gases generated from source rocks in the WSS also migrated to the WSB. On the whole, the gas charge in the WSB is characterized by dual-sourcing and late-stage. The low permeability gases in the WSS almost are highly mature and composed of most coal-derived gases generated from local coal-measure rocks in the Pinghu Formation and a small amount of oil-derived gases generated from local dark mudstones containing sapropelic-type organic matters in the Pinghu Formation. In addition, mature coal-derived gases generated from source rocks in the lower Huagang Formation are also present but very limited. The charge of highly mature gases in the low permeability reservoirs in the lower Huagang Formation in the WSS occurred at approximately 3.9Ma∼0Ma.
Development, characterization and performance evaluation of a swelling resistant membrane for CO2/CH4 separation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-14 Malik Shoaib Suleman, K.K. Lau, Y.F. Yeong
Swelling in polymeric membranes due to the humid feed is a major issue in gas separation applications at offshore conditions. To ensure the integrity of the polymeric membrane, a high capital cost dehydration system is typically installed together with the membrane system. Hence, to minimize the dehydration requirement, a swelling resistant membrane was developed by film casting of polydimethylsiloxane (PDMS) over polysulfone (PSF). The PSF/PDMS composite membrane exhibited higher contact angle as compared to PSF membrane. Performances of the developed membranes were evaluated with and without water in the feed gases at the pressure of 2–10 bar. Separation performance in the PSF membrane was affected by swelling in the membrane; however, the composite membrane with the PDMS film resisted the water swelling in membrane and CO2/CH4 selectivity increased from 21.6 to 27.7 at 10 bar. Under wet feed conditions, the PSF/PDMS composite membrane exhibited stability for 24 h with stable permeance and selectivity. Based on the permeation results and the stable performance of a PSF/PDMS membrane, it can be concluded that the developed composite membrane demonstrates a potential to be used in an offshore membrane system with the minimum dehydration requirement for CO2/CH4 separation.
Wellbore stability model for horizontal wells in shale formations with multiple planes of weakness J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-09 Yi Ding, Pingya Luo, Xiangjun Liu, Lixi Liang
Wellbore collapse is a common problem during drilling operations in the Longmaxi shale formation, which vastly restricts drilling efficiency and shale gas development. For a horizontal well in particular, the long period of drilling increases the possibility of collapse. The central reason for the frequent wellbore collapses in shale formations is that shale has abundant planes of weakness, that is, bedding planes and fracture planes. These weak planes reduce shale strength and increase the anisotropy of the shale, complicating the wellbore instability issue. Therefore, this paper extends results of previous work and presents an attempt to establish a new model to investigate the influence of multiple groups of weak planes on wellbore stability in shale formation. By using this model, the influences of weak planes on stress distribution and shale strength are analysed respectively. It is shown that the anisotropy of shale formation makes stress distribution variable. Besides, the presence of weak planes decreases shale strength and this reduction of strength becomes larger with the increasing number of groups of weak planes. In particular, with more than four groups of weak planes, shale strength is entirely controlled by the weak plane. Based on the analysis of shale strength and effective stress at the wall of borehole, the investigation on influence factors of wellbore stability in shale formation has been conducted. The results indicate that collapse pressure has increment with increasing anisotropy of shale formation. Additionally, different occurrence and number of weak planes cause variation in collapse pressure. For a horizontal well, the selection of appropriate drilling azimuths can reduce the effect of weak planes on the borehole. The interaction between drilling fluid and shale leads to incremental collapse pressure, and this increment is higher in the multiple groups of weak planes and strong anisotropy condition. Finally, this model was applied to a field case in the southern Sichuan Basin, China. The model was consistent with field experience, proving its practicability in drilling operations.
A comparative study of predictive models for imbibition relative permeability and trapped non-wetting phase saturation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-08 Sh Aghabozorgi, M. Sohrabi
The hysteresis in two phase relative permeability occurs when the saturation history of the flow changes from drainage to imbibition or vice versa. The imbibition relative permeability is a strong function of initial non-wetting phase saturation from which the imbibition process starts. Hence, it is very time-consuming to conduct many experiments for measuring all possible imbibition relative permeability (kr) data. An alternative approach is to predict the imbibition relative permeability using the measured Land trapping coefficient and primary drainage relative permeability. Some predictive models, found in the literature, such as that of Land, Carlson and Killough are available in commercial simulators. For prediction of imbibition data, these models require the primary drainage kr data and one set of imbibition kr data to calculate the corrected Land trapping coefficient. However, the imbibition relative permeability is not always available and the inappropriate use of these models can introduce significant errors in the calculations. In this study, the limitations of the available models are discussed and a modified method is suggested, which only requires the primary drainage kr data and the measured Land trapping coefficient. The available models for prediction of imbibition kr data are based on the calculations of trapped non-wetting saturation (Snwt S n w t ). Therefore, in this study, a modified method was introduced which improved the estimations of trapped non-wetting phase saturation. The predicted values of imbibition relative permeability using this improved method were in good agreement with the experimental data. It was shown that this method can be used for both gas and oil as non-wetting phases in a water-wet medium. However, the trapped non-wetting phase is a function of capillary number and the Land trapping coefficient changes as the capillary number changes. Hence, the measured Land trapping coefficient cannot be assumed as constant in cases where severe changes in pressure result in changing interfacial tension (IFT) and fluid viscosity.
Relationship between tight sandstone reservoir formation and hydrocarbon charging: A case study of a Jurassic reservoir in the eastern Kuqa Depression, Tarim Basin, NW China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-08 Song Guo, Xiuxiang Lyu, Yan Zhang
The Kuqa Depression in the Tarim Basin is a prolific tight sandstone gas-producing area in China. In the eastern part of the depression, the assessed tight sandstone gas resource is approximately 1 × 1012 m3. To more accurately analyse the accumulation process of tight sandstone gas reservoirs, based on a comprehensive investigation of the characteristics and porosity evolution of the sandstone reservoir and hydrocarbon charging history, the relationship between hydrocarbon charging and tight sandstone reservoir formation is analysed. Collective evidence indicates that the Lower Jurassic Ahe Formation tight sandstone reservoir in the eastern Kuqa Depression is strongly heterogeneous, and the reservoir space is predominantly intergranular and intragranular dissolution pores. The development of fractures could improve reservoir properties, whereas compaction mainly led to the formation of the tight reservoir. The evolution in reservoir porosity shows that the Ahe Formation was compacted (porosity was less than 10%) at circa 12 Ma. Fluid inclusion analysis shows that there were two charge peaks with characteristics of “early oil and late gas”. The first oil charge peak occurred during 23–12 Ma, and the second gas charge peak occurred during 5–2 Ma. The Ahe Formation tight sandstone reservoirs in the eastern Kuqa Depression had higher porosities during the period of oil charge than those during natural gas charge because the sandstone reservoirs had experienced strong compaction and caused the formation of tight sandstone reservoirs, which means that the period of reservoir densification was earlier than the period of large-scale natural gas charging. Abnormal pore fluid pressure is the major driving force of gas migration rather than buoyancy in the tight reservoir. The mechanism whereby the natural gas completely displaced the pore water in the tight reservoir created the current distribution of "upper gas and lower water". Since the Quaternary, intense tectonic movement has destroyed the tight gas reservoirs in the structural high and adjusted the tight gas reservoirs in the structural low, forming the present distribution of oil and gas.
The origin and secondary alteration of dissolved gas in oil: A case study from the western Tu-Ha Basin, China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Gang Gao, Shangru Yang, Hao Liang, Zhiyong Wang, Xinning Li
The Tu-Ha Basin is a typical Jurassic coal-derived petroliferous basin in western China. Seventeen natural gas samples were collected from the Jurassic Sanjianfang and Qiketai Formations, the Cretaceous Tugulu Formation, and the Paleogene Shanshan Formation to analyze the source and secondary alteration of natural gas. The natural gas samples were characterized by molecular and stable carbon (δ13C) and hydrogen (δD) isotope compositions. The results indicate that the natural gases are wet gases, in which methane is the main alkane component. Nitrogen (N2) and carbon dioxide (CO2) are the two non-hydrocarbons. The N2 values (>12%) are relatively higher, which increase rapidly at the burial depth of 1500–2000 m. Some natural gases have suffered secondary alteration at this depth. The natural gases are thermal genetic coal-derived gases (humic gas), coming from the Jurassic coal measure source rocks, which are chiefly in the low mature to early mature stage. Nitrogen in the shallow is chiefly derived from the atmosphere, while nitrogen at the deeper burial depth is mainly derived from the thermal decomposition of organic matter (OM). The shallow natural gas samples have the heaviest carbon isotope composition of ethane (δ13C2) and a carbon isotope sequence of (δ13C1 < δ13C2 > δ13C3 > δ13n-C4 < δ13i-C4), which is mainly caused by the biodegradation. The higher nitrogen content illustrates that a large amount of surface water is running into the reservoirs. Water washing occurs in the reservoirs, which decreases the molecular methane content and increases the amount of heavier hydrocarbons at 1500–2000 m depth.
A simulation method based on energy criterion for network fracturing in shale gas reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Haifeng Zhao, Xiaohua Wang, Wei Wang, Erfei Mu
The fracture network in shale gas reservoirs has a plurality of extending frontiers and the propagation paths of fractures are difficult to predict in advance. When the network fracturing is simulated by the extended finite element method (XFEM) based on stress intensity factors, the computation is arduous and time-consuming, which limits the application of XFEM in field fracturing design. Therefore, a simulating method of crack propagation based on energy criterion is proposed. Based on the principle of energy balance, the energy criterion for controlling crack frontiers extending is established by the fluid injection energy, the rock strain energy, the surface energy, the seismic energy and the friction loss energy. The criterion only needs to calculate the energy distribution in the crack frontiers to judge whether the fracture could expand, avoiding the fussy calculation of the stress intensity factor. Based on the proposed energy criterion, the fluid solid coupling effect and the fractures interaction, an energy method is established for network fracturing simulation in shale gas horizontal well. The results show that the fracture network morphology obtained by simulation is basically consistent with micro-seismic monitoring result, and the computational efficiency of this simulation method is 10000 times higher than that of XFEM. The energy method provides an idea and basis for the simulation and design of shale reservoir fracturing.
Discrete fracture modeling of shale gas flow considering rock deformation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Chunyuan Xu, Peichao Li, Zhiwei Lu, Jianwu Liu, Detang Lu
Rock deformation is an important mechanism in shale reservoirs and occurs simultaneously with gas flow during the production period. It may not only result in production variation, but also have an impact on reservoir flow behaviors. Accurate simulation of gas flow in deformable reservoirs is challenging considering dual porosity structure of shale reservoirs. Besides, the complex fracture network topology and interactions further complicates the simulation of the fracture system. In this work, we implement a discrete fracture model (DFM), in which the reservoir is divided into the matrix and fracture system. The DFMs use flexible Delaunay triangulation to represent individual fractures, hence they could handle complex fracture network. Based on the comprehensive study of the deformation of matrix and fracture, a flow model that considers rock deformation is presented to predict well production and reservoir dynamics. Numerical simulations are conducted to investigate the influence of rock deformation on a reservoir with complex fracture network. Results under no deformation (ND) condition and integrated deformation (ID) condition show that rock deformation has an obvious impact on the gas production and the pressure distribution. The percentage of production loss increases with reservoir pressure, while decreases as matrix permeability or fracture conductivity increases. Comparisons of production loss caused by the individual deformation depict that the natural fracture deformation (NFD) is dominant, the hydraulic fracture deformation (HFD) is minor, while the matrix deformation (MD) is negligible. Less percentage of production loss caused by the ID is observed than the sum caused by the NFD, the HFD, and the MD.
Monitoring of elemental mercury in ambient air around an Egyptian natural gas processing plant J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 A.A. El-Feky, W. El-Azab, M.A. Ebiad, Mohamed B. Masod, S. Faramawy
New insight into origin, accumulation and escape of natural gas in the Songdong and Baodao regions in the eastern Qiongdongnan basin, South China Sea J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Ao Su, Honghan Chen, Xu Chen, Hongping Liu, Yanhua Liu, Mingzhu Lei
The found gas pools in the Songdong and Baodao regions in the eastern Qiongdongnan basin, South China Sea have almost failed to realize expected commercial value due to either low reserve abundance or high carbon dioxide (CO2) content. To assist in further exploration, the genetic type, source and accumulation history of natural gas have been investigated based on the analysis of the chemical compositions, carbon isotopes and light hydrocarbons in gases, isotope compositions of rare gas, basin numerical modeling and fluid inclusion analysis. The results indicate that there are three representative types of gases. The first type distributed in the BD13 and ST24-1 areas consists of biogenic and oil-derived gases from the Songdong sag. The second type distributed in the BD19-2 area is composed of coal-derived and oil-derived gases from the Baodao sag. The third type distributed in the BD15-3, BD19-4 and BD19-2 areas consists of significant amounts of volcanic mantle-derived CO2 and few organic hydrocarbon gases. The charge of oil-derived gas and formation of biogenic gas are close to the deposition stage of overlying thick mudstones. This may be a critical factor for current gas pools with low reserve abundance in the Songdong region. Intense activity of the No.2 fault and absence of overlying thick mudstones gave rise to the escape of a large quantity of oil and gas from the middle Oligocene to middle Miocene. Besides, due to volcanic activity in the Quaternary, mantle-derived CO2 was injected into the reservoirs via No.2 fault. The previous accumulative hydrocarbon gases were driven off by CO2 in various degrees, which may be mainly responsible for current situation that most gas pools have high CO2 content in the Baodao region.
Hydraulic fracturing in a penny-shaped crack. Part II: Testing the frackability of methane hydrate-bearing sand J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Jun Lin Too, Arthur Cheng, Boo Cheong Khoo, Andrew Palmer, Praveen Linga
Techno-economic and life cycle assessments of the natural gas supply chain from production sites in Canada to north and southwest Europe J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Krishna Sapkota, Abayomi Olufemi Oni, Amit Kumar
In recent years, the need for energy security strategies through liquefied natural gas (LNG) import has occupied an unprecedented spot in the European Union's foreign policy agenda. The availability of abundant natural gas resources in Western Canada, making this region a potential supplier, has, therefore, received significant attention. In order to ensure a competitive spot in the global natural gas market, it is important for Canada to supply its natural gas both at a competitive price and with lower emissions. In this study, a comparative assessment of the delivered costs and life cycle greenhouse gas (GHG) emissions of the natural gas supply chain from production sites in Canada to north and southwest Europe is conducted through the development of techno-economic and life cycle analyses models. Two possible supply chain routes to Europe were explored, one from the west coast and the other via the east coast of Canada, and included recovery, processing, transmission, liquefaction, shipping, and re-gasification. Two sources of Canadian natural gas reserves, Montney and Horn River, are investigated. The results show that the delivered cost ($/GJ) of Canadian LNG (including recovery, processing, transmission, liquefaction, and shipping cost) to Europe is 8.9–12.9, depending on the resources and pathway. The total well-to-port (WTP) GHG emissions (including emissions from recovery, processing, transportation, liquefaction, shipping and re-gasification at the destination port) from the Canadian production sites to Europe is 22.9–42.1 g-CO2eq/MJ, depending on the resources and pathway followed. The costs and GHG emissions values reported in the literature for the delivery of natural gas from the major exporting countries were lower than those for the Canadian LNG supply chain. Finding other sources of natural gas in Eastern Canada might provide a cheaper and less GHG-intensive alternative to the Canadian LNG supply chain.
Failure probability assessment of gas transmission pipelines based on historical failure-related data and modification factors J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Ke Shan, Jian Shuai, Kui Xu, Wei Zheng
Evaluation of failure probability is one of the core contents of quantitative risk assessment. An assessment model of gas transmission pipelines failure probability based on historical failure-related data and modification factors is established, which combines a quantitative part to integrate available historical failure-related data, with a qualitative analysis to compensate for a potential lack of precise crisp statistical data. The main idea is to use the modification factors to modify the baseline failure frequency. The baseline failure frequency is estimated from the statistical historical failure-related data. The modification factors are calculated from the segment attributes of the target pipeline using algorithms developed from the analysis of statistical data and analytical models supplemented by pipeline evaluation criteria and expert judgment. The constructed model is applied to a long-distance gas transmission pipeline so that the effectiveness of the proposed model could be demonstrated. The prospect is for more efficient risk management by acting both on historical failure-related data and modification factors of gas transmission pipeline systems.
Effect of casing rotation on displacement efficiency of cement slurry in highly deviated wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Yuhuan Bu, Leiju Tian, Zhibin Li, Rui Zhang, Chunyu Wang, Xucai Yang
Rotating casing is helpful to improve cementing quality. In the case of casing rotation and non-rotation, the influence of density difference and casing eccentricity on displacement efficiency and displacing interface in highly deviated wells have been numerically simulated based on Herschel-Bulkley model. The simulation results indicate that the displacement efficiency increases first and then decreases as the density difference or casing eccentricity increases. Under the same displacement conditions, rotating casing can improve displacement efficiency. In order to visually observe the casing rotation change the fluid flow state, the displacement process and displacing interface are experimentally simulated by using substitute drilling fluid and cement slurry. To select reasonable casing rotation speed while cementing, the impact of casing rotation speed on displacement efficiency is analyzed by combining experiments and simulations. Considering cementing requirements and operating risks, the casing rotary speed is recommended at 20–30 r/min in highly deviated wells.
Application of fast analytical approach and AI optimization techniques to hydraulic fracture stage placement in shale gas reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-07 Hamid Rahmanifard, Tatyana Plaksina
In the last decades, natural gas from unconventional reservoirs has become a major portion of total gas supply due to advances in horizontal well drilling and multi-stage hydraulic fracturing as well as reduction of operational costs and capital expenditures. However, hydraulic fracturing technique is a still costly and resource intensive production strategy that requires optimal planning to conform to the best safety practices and to obtain the highest returns on investments. Thus, the proposed fast and reliable hydraulic fracture (HF) placement optimization technique based on physics and analytical equations is the key tool to balance between gas production costs and anticipated revenues. In this study, we develop an analytical model in which the modified Wattenbarger slab model with the pseudo-pressure approach are integrated into the Net Present Value (NPV) as the objective function. We consider four decision variables including number of HF stages, HF spacing, HF half-length, and wellbore spacing and use three stochastic gradient-free optimization methods (i.e., genetic algorithm (GA), differential evolution (DE), and particle swarm optimization (PSO)) to optimize the objective function on a synthetic shale gas reservoir model with the Barnett Shale properties. To verify the accuracy of the obtained optimal solutions, we conduct four trials for each stochastic optimization method with 100 generations and the population size of 20. The results show that the best overall value of the NPV found by PSO are 1.7% and 7.6% higher than those obtained by DE and GA, respectively. Moreover, PSO has the fastest convergence rate (in 50 generations), saves at least 10% of the computational time in comparison to those required by other methods, and results in the same optimal solution in all trials. Finally, considering bilinear flow at the early stages of the production period, nonlinear flow at the late production time, and gravitational effects in the analytical model are still open areas for future research in this field.
A model for pseudo-steady and non-equilibrium sorption in coalbed methane reservoir simulation and its application J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-02-02 Myong Guk Yun, Myong Won Rim, Chol Nam Han
Coalbed methane (CBM) reservoir simulation is vital in CBM development. Production of CBM is controlled by a three-step process: gas desorption from the coal matrix, gas diffusion to the cleat system, and gas flow through fractures. This process follows the Langmuir's law, Fick's first law and Darcy's law. In this work, we suggested a three-dimensional, dual-porosity, two-phase, pseudo-steady, non-equilibrium sorption mathematical model for overall progresses from desorption to flow by the help of petroleum reservoir numerical simulation method and this complex mathematical model is approximated and solved by finite-difference and fully implicit method. The CBM reservoir simulation software, CBMRS 1.0 in Korean interface was developed by C++. It was compared with COMET 3D and evaluated and it could be exclusive software for CBM reservoir simulation.
Effect of CO2 adsorption on enhanced natural gas recovery and sequestration in carbonate reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-04-25 Mohammed Eliebid, Mohamed Mahmoud, Reyad Shawabkeh, Salaheldin Elkatatny, Ibnelwaleed A. Hussein
In this study, CO2 injection for the purpose of Enhanced Gas Recovery (EGR) and sequestration after primary recovery is investigated on Pink Desert limestone from Edwards Plateau formation in central-west Texas. In this paper, competitive adsorption of CH4 and CO2 is studied in the temperature range 50 °C–150 °C using a mixture of CO2 and CH4. Methane adsorption on the surface of the carbonate rock reduced from 50 mg/g at 50 °C to 12.4 mg/g at 150 °C due to exothermic nature of physical adsorption of methane on calcite. Addition of 10% CO2 to methane has enhanced the adsorption from 12.4 mg/g for pure methane to 18.3 mg/g for the 10% CO2 gas mixture at 150 °C. Adding CO2 to methane will compete with CH4 on the adsorption sites and due to CO2 high adsorption affinity the total uptake of the system is increased depending on CO2 partial pressure. The adsorption experiments have shown that the adsorption of CO2 on Pink Desert limestone is four times higher than that of CH4 at the same pressure and temperature due to the high affinity of CO2 to the calcite rocks derived from strong electrostatic attraction between CO2 molecules and calcite. The thermodynamic analysis confirmed the high natural selectivity of carbonate toward CO2 with lower heat of adsorption for CO2 and the adsorption is spontaneous at low temperatures. The adsorption-desorption experiments showed that CO2 content of injected gas has a strong influence on natural gas desorption from the rocks. The CO2 content and rock mineralogy influence the desorption isotherm model. The potential of using CO2 in EGR and sequestration applications especially in low temperature reservoirs is discussed. A model that explains the contribution of the desorption of natural gas to the total gas production is proposed.
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