The impact of CO2 injection on steel balls embedment in shale rock – Experimental research J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-19 Danuta Miedzińska, Arkadiusz Popławski, Michał Kwietniewski, Marcin Lutyński
One of the most important phenomenon appearing during shale rock fracturing is the interaction between the proppant and fracture wall. The proppant's role is to keep the fracture open after the fracturing fluid is released and during gas recovery. However, the stress caused by the rock mass can act on proppant grains – they can be damaged or embed into fracture wall. This phenomenon, called embedment, was tested in this study with the use of an original testing device. The impact of CO2 injection on this phenomenon was presented. Special attention was paid to the change in properties of shale during the embedment process, i.e. saturation of rock with CO2 rather than proppant behaviour. As a model proppant steel balls were used for the tests. The obtained results show that the average embedment depth in the case of the steel balls in the non-CO2 environment was smaller than in the case of an average embedment depth in the case of the steel balls embedment in the CO2 environment. A significant impact of carbon dioxide on the surface of the shale rock was observed. The shale rock lost its strength after the CO2 interaction. Such phenomenon can be caused by the shale structure change connected with carbon dioxide sorption induced swelling.
3-D dynamic evolution analysis of coal-rock damaged field and gas seepage field during the gas extraction process J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-18 Hongmei Cheng, Ning Zhang, Yugui Yang, Yuxia Dong, Weihong Peng
Coal seam construction disturbances or gas depressurization and extraction can cause rupture damage of the surrounding coal and rock. The damage not only changes the structural property and mechanical behavior of the coal and rock, but also changes the physical parameters of the coal and rock. The gas migration not only changes the pore pressure, but also changes the effective stress and the adsorption and expansion deformation of coal seams, which resulted in the damage evolution and accumulation of coal and rock. The temperature change will not only affect the stress distribution of coal and rock, but also affect gas adsorption properties and diffusion capacity. In fact, the gas extraction is a multi-field coupling process of the coal-rock damaged field, temperature field and gas seepage field. In this paper, coal and rock is considered as a double medium of pore and crack. The damaged variable is defined in view of the damaged and failure characteristics of coal and rock. The damaged constitutive equations of coal and rock are established considering the effects of gas pressure and temperature. On this basis, the gas diffusion and seepage coupling equations in damaged coal and rock are derived. Based on the basic theory, the two development of the finite element source program is carried out by using the FORTRAN language. This program was developed to consider the temperature, gas seepage and deformation of coal and rock. Based on this program, the work process of gas drilling in coal mine is simulated and the dynamic evolution process of the damaged field of coal and rock and the permeability of the gas are quantitatively described. These achievements have extremely important theoretical guidance to guide the design of gas extraction in coal seams and improve the gas drainage rate.
On the Relationship between Effective Permeability and Stress for Unconventional Rocks: Analytical Estimates from Laboratory Measurements J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-18 Hui Hai Liu, Huangye Chen, Yanhui Han, Shannon L. Eichmann, Anuj Gupta
Permeability measurements show that unconventional rock is considerably stress sensitive because the matrix permeability is likely controlled by micro cracks and bedding structures in unconventional reservoirs. While there are a number of laboratory studies in the literature on the dependency of core-scale permeability on effective stress for unconventional rocks, how to determine the corresponding large-scale stress-dependency relationship (of more interest to practical applications) from the laboratory measurements has not been systematically investigated. This work proposes a method to estimate such a large-scale relationship from laboratory measurements. Based on the stochastic approach commonly used for parameter upscaling, we derived relationships between the large-scale effective permeability and the stress for the two- and three-dimensional isotropic porous media. The development is based on the empirical observation that at core scale permeability is an exponential function of effective stress. The developed large-scale relationships can be written in terms of the same mathematical form as the local-scale relationship except parameters in the large-scale relationships correspond to effective ones. The effective stress sensitivity parameter (that characterizes the stress-dependency) is simply the expected value of that at the local scale, or the arithmetic average of local values, for the two-dimensional flow problem and a function of effective stress for the three-dimensional problem. Because of its dominant two-dimensional flow along beddings (resulting from the fact that vertical permeability is significantly smaller than the horizontal one), the relationship for the two-dimensional flow case is valid for unconventional rocks. Nevertheless, we demonstrate that for typical local-scale parameter values from unconventional rocks (e.g., Barnett shale and a carbonate source rock), the relationships obtained for two- and three-dimensional problems give the essentially same results.
Effect of silica sand size and saturation on methane hydrate formation in the presence of SDS J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Zhen Pan, Zhiming Liu, Zhien Zhang, Liyan Shang, Shihui Ma
Abundant reserves of natural gas hydrates are hosted in the pores of sediment layers, and the hydrate-based technology could be widely used in industry. In this work, the formation kinetics of methane hydrate in a complex system containing silica sand and 300-ppm sodium dodecyl sulfate (SDS) solution were investigated at 275.15 K and 7 MPa. The hydrate was formed in different-saturated silica sand with particle sizes of 100, 150, 200, 300, and 400 mesh. The results indicated that in both the 50%- and 100%-saturated sand, a larger particle size exhibited a better methane storage capacity. In the complex system, the presence of SDS molecules significantly enhanced the hydrate formation process and weakened the effect of particle size on the hydrate formation rate. The difference in hydrate gas uptake formed in the differently saturated silica sand indicted that with an increase in saturation, the smaller-sized silica sands caused a more marked inhibitory effect. Finally, the different hydrate distributions in the 50%- and 100%-saturated silica sand revealed that a hydrate film formed quickly and preferentially on the surface of the silica sand, which was attributed to the adsorption of the SDS active groups and the presence of the silica sand surface. With the thickening of the hydrate film, the resulting volume expansion and stronger capillary force led to the migration of the liquid phase, which resulted in the hydrate distributions observed in the differently saturated silica sands.
Deep seawater intake for primary cooling in tropical offshore processing of natural gas with high carbon dioxide content: Energy, emissions and economic assessments J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Matheus de Andrade Cruz, Ofélia de Queiroz Fernandes Araújo, José Luiz de Medeiros
Characterization of shallow-marine reservoirs of Lower Eocene carbonates, Pakistan: Continuous wavelet transforms-based spectral decomposition J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Muhammad Tayyab Naseer, Shazia Asim
Evaluation of coupled machine learning models for drilling optimization J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Chiranth Hegde, Ken Gray
Drilling optimization can provide significant value to an oil and gas project, especially in a low-price environment. This is generally approached by optimizing the rate of penetration (ROP) of the well, which may not always be the best strategy. Two additional strategies (or models) can be used to optimize a well – torque on bit (TOB) response to reduce vibrations at the bit or mechanical specific energy (MSE) to reduce the energy used by the bit. This paper evaluates these three models for drilling optimization based on several criteria. Models for ROP, TOB and MSE are built using a data-driven approach with the random forests algorithm using drilling operational parameters such as weight-on-bit, flow-rate, rotary speed, and rock strength as inputs. The drilling models are optimized using a meta-heuristic optimization algorithm to compute the ideal drilling operational parameters for drilling ahead of the bit. Machine learning is used to develop these models since these models are coupled which enable calculation of interaction effects. Results show that optimizing the ROP model leads to a 28% improvement in ROP on average, however, this also increases the MSE and the TOB which is undesirable. Optimizing the MSE model results in a (smaller) increase of ROP (20%). This is accompanied by a decrease in MSE (by 15%) and decrease in TOB (by 7%) which may result in longer bit life and additional savings over time. Hypothesis testing has been used to ensure that all simulations conducted in this paper show statistically significant results.
The impact of coal macrolithotype on hydraulic fracture initiation and propagation in coal seams J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Yulong Liu, Dazhen Tang, Hao Xu, Song Li, Shu Tao
Macrolithotypes control the pore-fracture distribution heterogeneity in coal impacting stimulation via hydrofracturing and the coalbed methane (CBM) production. Given that it is affected by the discontinuities, hydraulic fracture geometry is complex in the vertical plane and is different from a simple fracture in a homogeneous reservoir. However, the initiation and propagation mechanism in the vertical plane is unclear. To clarify this, the cohesive zone finite element approach, with macrolithotype contributions included, was used to simulate and analyze the hydraulic fracture propagation. The experimental tests showed that, the bright and semi-bright coal usually have higher microfracture (cleat) density accompanied by the lower mechanical properties than that of the semi-dull and dull coals. The behavioral differences are likely to impact the geometry evolution of hydraulic fractures and which appears to vary when fracturing the different coal macrolithtypes. Thus, the cohesive zone finite element approach was used with two models to capture macrolithotype impacts. The result show that, when fracturing the dull coal (model 2), the overall propagation region rapidly displayed a simple plane in shape because of the less development of natural fractures. With the influence of the larger elastic modulus, the high-stress zone would be easy formed and suddenly release to generate pressure pulse when the hydraulic fracture penetrated the interface. As the hydraulic fracture initiates from the bright coal (model 1), the presence of the existing diverse cleat network contribute greatly to the increase of cracks number to form complex fractures. However, the opening of natural fractures will lead to the diversion of fracturing fluid, and the larger elastic modulus of the interlayer also plays a limiting role in the height of the hydraulic fracture. In addition, the monitoring of hydraulic fracture was carried out and shown that the height of the major fracture in model 1 was restricted and limited by the bright coal; and the height in model 2 is usually larger than the dull coal thickness, indicating that the hydraulic fracture has cut through the fracturing section (dull coal) and embedded into the upper and lower layers.
Characterization of coal porosity and permeability evolution by demineralisation using image processing techniques: A micro-computed tomography study J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Guanglei Zhang, P.G. Ranjith, M.S.A. Perera, Asadul Haque, Xavier Choi, K.S.M. Sampath
The permeability of coal is the key parameter both in primary and enhanced coalbed methane recovery. The natural cleat system in coal serves as the primary pathway for gas flow in coal seams though mineralisation in cleats and is known to significantly reduce coal permeability. This paper reports on a numerical simulation of the pore network evolution of coal subject to cleat demineralisation. A high-resolution micro-computed tomography scanner was used to characterize the micro-structures of three anthracite coal samples. The mineral phases available in the coal samples were selectively removed to different extents (20%, 40%, 60%, 80% and 100%) and merged into the pore space using image processing techniques. In this way, the coal demineralisation process could be simulated and its impact on porosity and permeability studied. Comprehensive pore structure characterizations, including porosity, connectivity and tortuosity, were then conducted on the reconstructed pore network using Avizo software. Pore network models were also extracted to investigate changes in the pore and throat attributes. The lattice Boltzmann method was adopted to identify the absolute permeability changes with cleat demineralisation. The results reveal that demineralisation can increase coal porosity and permeability up to a percolation threshold. Although porosity was enhanced prior to the percolation threshold, the coal permeability was not enhanced due to poor pore connectivity. The permeability changed rapidly close to the percolation threshold, depending on the degree of demineralisation, and an exponential relation was observed between permeability and the amount of demineralisation. According to the observations, complete removal of the mineral phase can significantly increase the connected porosity while reducing the pore tortuosity, resulting in several orders of magnitude increase in coal permeability. This study shows that cleat demineralisation is an effective permeability enhancement technique for coalbed methane recovery, if very high demineralisation can be achieved.
Black Powder Formation by Dewing and Hygroscopic Corrosion Processes J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Martin Colahan, David Young, Marc Singer, Ricardo P. Nogueira
The presence of black powder in natural gas pipelines can lead to equipment erosion, valve failure, instrumentation malfunction, and increased pressure drop. However, despite its impact on downstream and midstream operations, black powder production is poorly understood. In the present work, black powder formation as a result of corrosion was investigated by simulating sales gas conditions in a glass cell. Steel specimens were systematically exposed to a range of CO2, H2S, and O2 partial pressures at differing water condensation rates. The potential for hygroscopic material assisting black powder formation was also investigated. Friable corrosion products found in dewing conditions consisted of siderite, mackinawite, and hematite. The expected mass of corrosion products, as determined from experimental corrosion rates, are in line with the high levels of black powder that can be experienced. The presence of hygroscopic NaCl crystals facilitated corrosion at relative humidities as low as 33%.
Production performance analysis for deviated wells in composite carbonate gas reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-15 Fankun Meng, Qun Lei, Dongbo He, Haijun Yan, Ailin Jia, Hui Deng, Wei Xu
The strong heterogeneity of carbonate gas reservoir makes the formation exhibit composite properties. The inner region adjacent to deviated well is full of matrix, natural fractures and vugs, while the outer region contains matrix only. It is very challenging to incorporate geological features of carbonate reservoirs and evaluate the production performance of deviated wells. This paper presented a semi-analytical model to study the pressure behavior and production performance of slanted wells in composite, anisotropic and stress-sensitive carbonate gas reservoirs. In inner region, the interaction between matrix, vugs and fractures can be described by triple-porosity/single permeability model, in which primary flow occurs only through the fractures, and the outer region can be represented by single porosity media. The stress-sensitive power exponent is proposed and estimated through laboratory experiments and curve fitting, and pseudo-pressure and pseudo-time are introduced to consider this effect. Laplace transformation, Fourier transform and inverse, Stehfest inversion algorithm and point source function are used to calculate the well bottom-hole pressure and production rate. When the inclination angle is equal to 0° approximately, the rate-transient curves of this model match very well with the conventional vertical well model. In addition, the accuracy of the model is validated by comparing the pressure response with monitoring data collected from a deviated well in Gaoshiti-Moxi carbonate gas reservoir. A synthetic case is utilized to analyze the effects of stress-sensitive power exponent, inner region radius, fracture horizontal permeability, horizontal-vertical permeability ratio and inclination angle on gas well production performance. Through the sensitivity analysis of relevant factors, we come to some conclusions that a large stress-sensitive power exponent has negative impact on well performance; a large inner radius, a high fracture horizontal permeability and a large inclination angle can heighten gas production rate in a short period, while it also leads to the drastic declination of production rate; a large horizontal-vertical permeability ratio which means the formation has strong anisotropy can significantly decrease gas production rate. With its high efficiency and simplicity, this semi-analytical approach will serve as a useful tool to evaluate the well productivity and pressure behavior for carbonate gas reservoirs.
Occurrence features and gas content analysis of marine and continental shales: A comparative study of Longmaxi Formation and Yanchang Formation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-14 Qianwen Li, Xiongqi Pang, Ling Tang, Gang Chen, Xinhe Shao, Nan Jia
To study the occurrence state and content of shale gas in different depositional environments, 15 marine shale samples from Longmaxi Formation in the Sichuan Basin and 15 continental shale samples from Yanchang Formation in the Ordos Basin were sampled. Then a series of experiments, including X-ray diffraction analysis, TOC content analysis, Ro measurement, NMR measurements, FE-ESEM observation, low-pressure N2 adsorption, and CH4 isothermal adsorption were conducted. In general, shale gas in Yanchang formation has the characteristics of primary adsorbed gas, moderate free gas, and non-ignorable dissolved gas, whereas shale gas in Longmaxi formation has the characteristics of joint dominated free gas and adsorbed gas, as well as negligible dissolved gas. Both macroscopic accumulation pattern and microscopic occurrence model show four stages in the whole thermal evolution, that is, adsorption, pore filling, fracture filling and accumulation. By analyzing the affecting factors of shale gas adsorption, conclusions can be drawn that geological characteristics, mineral compositions, pore structure features and formation conditions have influence on adsorbed gas content to various degrees. Cause analyses reveal that differences in occurrence state and gas content between marine and continental shales are immediately affected by the differences of organic matter type, thermal maturity, brittle minerals content, carbonate content, SSA, PD, porosity, gas saturation, residual oil quantity, as well as T&P, indirectly controlled by sedimentary environment and tectonic movement.
Multiple geochemical proxies controlling the organic matter accumulation of the marine-continental transitional shale: A case study of the Upper Permian Longtan Formation, western Guizhou, China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-07 Shunxi Liu, Caifang Wu, Teng Li, Haichao Wang
The organic-rich shale of the Longtan Formation of the Upper Permian in western Guizhou formed during the marine-continental transitional facies depositional environment. With a high total organic carbon (TOC) content and a large cumulative thickness, it is thought to be the superior source rock for shale gas development. The depositional environment of marine-continental transitional shale is significantly different from marine shale, which leads to the various accumulation characteristics of the organic matter. In this paper, shale samples were collected from the Longtan Formation of the Upper Permian, which is typical marine-continental transitional shale. The TOC, major elements and trace elements were measured, and the formation and preservation conditions were investigated using multiple geochemical proxies, including paleoclimate, detrital influx, redox parameters, paleoproductivity and sedimentation rate. The TOC decreases first and then increases from the bottom to the top of the Longtan Formation shale, and the TOC for the lower Longtan Formation is higher than the upper Longtan Formation. For the lower Longtan Formation, the positive correlations between TOC and redox indicators (V, U and V/Cr) demonstrate that the dysoxic bottom water environment was the key factor that controlled the accumulation of organic matter. For the upper Longtan Formation, there are positive correlations between the TOC and the paleoclimate and sedimentation rate, which suggests that the enrichment of the organic matter was influenced by both a warm and humid paleoclimate and the high sedimentation rate of an oxic environment. However, the high detrital influx (aluminosilicate) occurred as the diluent decreased the concentration of organic matter. The paleoproductivity has a poor correlation with TOC for the Longtan Formation, suggesting that it was inferior to the gathering of organic matter. The sedimentary models built for the upper and lower Longtan Formation shale can reproduce the enrichment of organic matter.
Revamping existing glycol technologies in natural gas dehydration to improve the purity and absorption efficiency: Available methods and recent developments J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-07 Zong Yang Kong, Ahmed Mahmoud, Shaomin Liu, Jaka Sunarso
The glycol purity limit in conventional absorption-based natural gas dehydration process has led to the significant water vapour presence in the supposedly dry product gas. Several alternative processes have been developed to overcome this limitation that includes stripping gas injection using nitrogen, a portion of dry product gas, or volatile hydrocarbon (DRIZO process), stripping gas modified with Stahl column, and Coldfinger technology. This review summarises these different processes and elaborates on their mechanisms, process flow diagram, advantages, drawbacks, and current statuses. Relevant works from 1991 to 2017 were compiled and the existing gaps were highlighted as recommendation for future work.
Factors affecting received signal intensity of electromagnetic measurement-while-drilling during underground in-seam horizontal drilling J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-06 Chun Shao, Lin Xu, Xiaojun Chen, Zhiwei Chu, Baolin Yang
Electromagnetic measurement-while-drilling (EM-MWD) is a real-time monitoring technology for bottom-hole engineering parameters, and applied to underground in-seam horizontal drilling to obtain high accuracy borehole trajectories for enhancing the output of coal bed methane. However, the received signal intensity of EM-MWD is affected significantly by many factors. In this study, a finite-element model for simulating the signal transmission was proposed based on the quasi-static electric field theory, and the reliability of the model was proved by performing a sensitivity analysis and scale-model experiment. Then, factors including full-dimension signal channel, coal seam resistivity and thickness, surrounding rock resistivity, borehole location, electrode location, and bit drilling into surrounding rock were investigated. Results indicate that higher resistivities of coal seam and surrounding rock imply stronger intensity of the received signal, and the coal seam resistivity is the primary influencing factor. When the resistivity of coal seam is less than that of surrounding rock, the intensity of received signal increases with rising the receiving distance and decreasing the distance between borehole and surrounding rock. The received signal intensity of electrode in surrounding rock is higher than that in coal seam under the above condition. Moreover, a sudden change in the received signal intensity will be observed as the bit drills from coal seam into surrounding rock, which is an indicator for determining whether the bit has drilled into surrounding rock. The finite-element model and the findings in this research are helpful for the design, feasibility evaluating and application of the EM-MWD in coal mines.
A new model for improving the prediction of liquid loading in horizontal gas wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-06 Ruiqing Ming, Huiqun He, Qiangfa Hu
There are great differences in predicting the onset of liquid loading among vertical, directional and horizontal gas wells. To date, most models for predicting the critical gas rate in horizontal wells are based on a liquid-droplet model, and the corresponding predictions deviate significantly from the actual status and are considerably controversial. Experimental results (Xiao et al., 2010; Wang, 2014) show that the liquid-film model is more reasonable. By respectively analyzing the force state of the gas core and the liquid film, we developed a new liquid-film model for predicting the critical gas rate in horizontal wells. Subsequently, a correction term is introduced for a convenient comparison between the new model and the popular models (Turner et al., 1969; Nosseir et al., 2000; Li et al., 2002). In addition, we carefully conducted a sensitivity analysis of the correction term related to the three parameters: liquid viscosity, Bond number and lift force factor. Well data from Liao (2012) were employed to verify the new model. The prediction results show that the new model demonstrates a significant improvement over conventional models in matching the field data in the Sebei gas reservoirs in China.
Droplet flux measurements in two-phase, low liquid loading, horizontal pipe flow using a high-density gas J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-06 Netaji R. Kesana, Roar Skartlien, Morten Langsholt, Roberto Ibarra, Murat Tutkun
Entrained fraction is one of the essential parameters needed for the prediction of frictional pressure drop and efficient design of downstream facilities. In the literature, there are very few entrained fraction datasets focused on low liquid loading flows, and even less datasets obtained from high pressure systems. This paper provides experimental entrained fraction data for low liquid loading gas-oil flows in a 100-mm diameter horizontal PVC and carbon steel pipe. High-density sulphur hexafluoride (SF6) gas and Exxsol D60 oil are used as the fluid phases to mimic actual field conditions. Superficial gas and oil velocities are varied between 5 m/s to 15 m/s and 1 mm/s to 7 mm/s, respectively. Local drop flux along the vertical diameter of the pipe cross-section is measured using the isokinetic sampling approach. Effects of several parameters such as system pressure (gas density), gas and liquid flow rates, and pipe material on the entrained fraction are studied. As expected, the entrained fraction increases with either the gas density or the gas velocity. The effect of liquid flow rate on the entrainment is not obvious; results show either a constant level or a decrease in entrainment with an increase in liquid flow rate, depending on the gas flow rate. The measurements conducted using two different pipe materials (PVC and carbon steel) demonstrated that surface material can cause significant differences in the entrainment. Therefore, the near-wall film behavior will have considerable influence on the entrainment mechanism, especially when the thickness of the liquid film becomes very thin. Finally, this paper also provides an evaluation of the existing correlations and/or models available in the literature against the acquired entrainment data using the high-density gas test facility.
Quantitative phase field modeling of hydraulic fracture branching in heterogeneous formation under anisotropic in-situ stress J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-06 Jianchun Guo, Qianli Lu, Hu Chen, Zhuo Wang, Xuhai Tang, Lei Chen
Unconventional reservoir hydraulic fracturing is often characterized with diverting and branching. A fundamental understanding of the fracture branching mechanism remains elusive due to the complicated fusion of geo stress, formation heterogeneity and pre-existed complex natural fracture topologies. Existing sharp fracture models such as, finite-element method (FEM) and its modified versions, often suffer in complex fracture topologies owing to the computationally expensive remeshing when fracture diverts and/or branches. In this paper, phase-field modeling (PFM) is proposed to quantitatively investigate the hydraulic fracture branching condition in heterogeneous formation under anisotropic in-situ stress. The PFM is featured with the diffusive interface, enabling it to automatically capture the fracture branching and diverting without the need of tracking the fracture interface. The model is first verified in predicting the fracture width, stress distribution and fracture propagation via benchmark examples, followed by the comprehensive investigation on hydraulic fracture branching in a heterogeneous formation where a rock strip is laid across the shale main formation with anisotropic in-situ stress. Parametric study shows no branching occurs when the hydraulic fracture propagates towards soft strip (e.g. soft shale), while fracture branches when it propagates towards stiff strip (e.g. hard shale or sandstone) as long as the Young's modulus ratio (ER = Estrip/Emain) exceeds a critical value. Such a critical value increases as the principal in-situ stress difference (Sd) goes up. Finally, the hydraulic fracture branching is quantified in terms of the deviation distance and reentry angle, both of which are found to rise as the ER increases, and as Sd decreases, which indicates relatively low Sd and high ER are in favor of increasing the fracture complexity and drainage area. These results could provide valuable insights in predicating and creating complex reservoir hydraulic fracturing patterns.
Foam generation, characterization and breakup in pipes J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-06 Mehmet Karaaslan, Ramin Dabirian, Ram Mohan, Ovadia Shoham
Experiments were conducted utilizing a 0.025 m diameter Foam Characterization Rig (FCR) skid. Aqueous foam was used in the experimental program, utilizing both Drill Foam F-450 and SI-403 surfactants to generate the foam. Foam generation and characterization experiments were conducted with different foam generation devices, with the aim of identifying the optimal configuration, which generates the most stable foam. A comparison between the foam quality and inlet gas volume fraction (IGVF) demonstrates that these variables are close to each other at 90% IGVF (vsg = 0.09 m/s) owing to the occurrence of homogenous flow for this condition. The data also confirm that the foam generation configuration with two 125 μm mesh size and 3 mm beads generates the most stable foam.Three different flow patterns were observed in the pipe, namely, stratified, dispersed and slug flow, exhibiting different foam quality. Foam flow in pipes experiments revealed that the gas shear effect on foam break-up depends on the existing flow pattern in the pipe. For stratified wavy flow, increasing the superficial gas velocity can lead to either increasing or decreasing foam breakup efficiency, which depends on the gas velocity. On the other hand, in slug flow, generally increasing the superficial gas velocity results in slightly decrease in the foam breakup efficiency.
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.
Stimulation of high temperature carbonate gas reservoirs using seawater and chelating agents: Reaction kinetics J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-06-27 Khaled Z. Abdelgawad, Mohamed Mahmoud, Ibnelwaleed Hussein
The use of hydrochloric acid (HCl) in gas well stimulation of high temperature reservoirs is currently facing different challenges. These challenges include rapid corrosion of the well tubulars, face dissolution, very high and uncontrolled reaction rate, and formation damage in high clay content and iron-rich reservoirs. In this study, water-soluble diethylene triamine penta acetic acid (DTPA) chelating agent is introduced as alternative to eliminate the risk associated with HCl at high temperatures. In addition, the potential of using seawater to replace fresh water in the stimulation process is explored to save the cost of fresh water transportation to deep offshore oil and gas wells. The effect of seawater on the reaction kinetics of DTPA with carbonate rocks under high pressure and high temperature conditions is investigated using the rotating disk apparatus. The reactions of DTPA solution diluted with fresh water (DTPA/DI) and seawater (DTPA/SW) with carbonate rocks were carried out at the same conditions. In the case of fresh water, the reaction is controlled by the surface reaction regime. Adding HCl to adjust DTPA pH did not turn the reaction into a mass transfer controlled reaction like the case of using HCl alone. The heavy matrix of seawater increased the resistance of ions diffusion, which resulted in a low reaction rate and transformed the reaction into a mass transfer limited regime. Corrosion tests were carried out on production and coiled tubing coupons obtained from the gas wells and the results of the new DTPA/SW formulation is compared to the standard HCl formulation. DTPA showed very low corrosion rate of 0.0034 g/cm2 without adding corrosion inhibitors compared to 0.205 g/cm2 of 15 wt% HCl with 3% corrosion inhibitors while the industry limit is 0.0244 g/cm2 in 6 h. The reaction regime of DTPA chelating agent with calcite is identified to be mass transfer limited in seawater and surface reaction limited in fresh water. The rate expression for the dissolution of Ca2+ in DTPA/SW solution is obtained. Coreflooding experiments were performed to determine the optimum injection rate using low permeability Indiana limestone core samples. The optimum injection rate required to stimulate a very deep carbonate gas well was found to be 1.4 bbl/min after scaling up the coreflooding results to field scale. The application of the new DTPA/SW formulation in treating deep gas wells is expected to save the cost of fresh water and eliminate the cost of corrosion inhibitors.
Integration of computational modeling and experimental techniques to design fuel surrogates J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-08-17 H.A. Choudhury, S. Intikhab, S. Kalakul, R. Gani, N.O. Elbashir
Conventional gasoline comprises of a large number of hydrocarbons that makes it difficult to utilize in a model for prediction of its properties. Modeling is needed for a better understanding of the fuel flow and combustion behavior that are essential to enhance fuel quality and improve engine performance. A simplified alternative is to develop surrogate fuels that have fewer compounds and emulate certain important desired physical properties of the target fuels. Six gasoline blends were formulated through a computer aided model based technique “Mixed Integer Non-Linear Programming” (MINLP). Different target properties of the surrogate blends for example, Reid vapor pressure (RVP), dynamic viscosity (η), density (ρ), Research octane number (RON) and liquid-liquid miscibility of the surrogate blends) were calculated. In this study, more rigorous property models in a computer aided tool called Virtual Process-Product Design Laboratory (VPPD-Lab) are applied onto the defined compositions of the surrogate gasoline. The aim is to primarily verify the defined composition of gasoline by means of VPPD-Lab. ρ, η and RVP are calculated with more accuracy and constraints such as distillation curve and flash point on the blend design are also considered. A post-design experiment-based verification step is proposed to further improve and fine-tune the “best” selected gasoline blends following the computation work. Here, advanced experimental techniques are used to measure the RVP, ρ, η, RON and distillation temperatures. The experimental results are compared with the model predictions as well as the extended calculations in VPPD-Lab.
Enhancing gas loading and reducing energy consumption in acid gas removal systems: A simulation study based on real NGL plant data J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-09-01 Ahmed Abotaleb, Muftah H. El-Naas, Abdukarem Amhamed
Amine scrubbing with absorption and desorption is the most established technology for Acid Gas Removal (AGR) systems, but suffers from high regeneration energy requirements and, hence offers a good opportunity for more development. A simulation study has been carried out based on a local NGL plant data to evaluate the performance parameters for AGR systems along with energy and utility consumptions for all single alkanolamines (Primary, Secondary and Tertiary) as well as the MDEA/PZ amine blend with different concentrations. The ultimate aim of the study is to address the critical industrial limitations in AGR systems, understand the individual performance for each amine under the same conditions and to investigate the Benchmark amine blend (MDEA + PZ) to optimize the absorption process in terms of enhancing acid gas loading and lowering the regeneration energy consumption. Ten cases have been investigated under the same conditions, where MDEA/PZ with 20/10 wt% has shown a better performance among single amines and benchmark amine blend 29/1 wt%; it could save 8% in steam consumption, 45% in cooling water, 62% in Lean Amine Air cooler, 45% in pumping power and 38% in solvent circulation rate, in addition to enhancing acid gas absorption by 67%.
An interactive software tool for gas identification J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-09-08 Hamza Djelouat, Amine Ait Si Ali, Abbes Amira, Faycal Bensaali
This paper presents the design of an interactive graphical user interface (GUI) to monitor and quantify a developed electronic nose (EN) platform for gas identification. To this end, an EN system has been implemented using a multi-sensing embedded platform comprised of a data acquisition unit, an RFID module and a signal processing unit. The gas data are collected using two different types of gas sensors, namely, seven commercial Figaro sensors and in-house fabricated 4×4 tin-oxide gas array sensor. The collected gas data are processed for identification by means of dimensionality reduction algorithms and classification techniques where the software implementation and the quantification of these algorithms have been carried out. Subsequently, the GUI was designed to enable several operations. The GUI allows the user to visualize the sensors responses for any selected gas at any point of the acquisition process as well as visualizing the data distribution. Beside, it provides an easy approach to evaluate the EN system performance in terms of data identification and execution time by computing the classification accuracy using a 10-fold cross validation technique. Furthermore, the GUI, which is freely distributed, grants the users the privilege to upload other types of data to enable different pattern recognition applications.
Numerical investigation of two-phase fluid flow in a perforation tunnel J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2017-11-03 M.J. Ahammad, M.A. Rahman, L. Zheng, J.M. Alam, S.D. Butt
The reservoir productivity index depends on the performance of fluid flow through the perforation tunnels. Experimentally, it is observed that higher fluid flow rate occurs in perforation by drilling (PD) technique than the traditional shooting technique. This behavior is favorable for the increased hydrocarbon production from a formation. The better understanding of formation damage mechanisms for various reservoir conditions can be optimized for the economic benefits and managerial decision. The perforation by drilling technique is proposed as an alternative perforation technique since this technique induces less formation damage. Experimental and numerical investigations are ongoing research in this regards. The primary results of the two-phase fluid flow through a perforation tunnel of porous media are modeled using ANSYS CFX-15.07 platform. The numerical data are validated with the experimental data. The effects of different petro-physical properties such as permeability, porosity, fluid viscosity, flow rates, and injection pressure are analyzed in the simulations.
Synthesis, characterization and performance of Pd-based core-shell methane oxidation nano-catalysts J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-01-31 Sardar Ali, Mohammed J. Al-Marri, Amina S. Al-Jaber, Ahmed G. Abdelmoneim, Mahmoud M. Khader
In this paper, a comparative investigation of the catalytic performances of Pd@TiO2 and Pd@CeO2, core-shells nanocatalysts supported over functionalized alumina, for application to methane oxidation is presented. The results indicated that the Pd@CeO2/SiO2.Al2O3 core-shell nanocatalyst exhibited higher activity and stability than the Pd@TiO2/SiO2.Al2O3 nanocatalyst. Complete combustion of methane over the Pd@CeO2/SiO2.Al2O3 nanocatalyst was achieved at about 400 °C. By contrast, the maximum combustion of methane over the Pd@TiO2/SiO2.Al2O3 nanocatalyst was only attained at ∼550 °C. The Pd@TiO2/SiO2.Al2O3 nanocatalyst experienced deactivation, and a transient dip in methane conversion in the temperature region between 580 °C and 750 °C was also observed. The exceptional activity of the Pd@CeO2/SiO2.Al2O3 nanocatalyst was attributed to the intimate interaction between palladium (Pd) and ceria (CeO2) and efficient oxygen back-spillover at Pd and CeO2 interface resulting from the core-shell structure.
Inhibition of structure II hydrates formation by salt-tolerant N-vinyl lactam-based terpolymers J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-06-01 Joel Reza, Arturo Trejo, María Esther Rebolledo-Libreros, Diego Guzmán-Lucero
Validation of in-line inspection data quality and impact on steel pipeline diagnostic intervals J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-31 Maciej Witek
An improved permeability evolution model and its application in fractured sorbing media J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-31 Gang Wang, Ke Wang, Shugang Wang, Derek Elsworth, Yujing Jiang
In this paper, we consider fractured sorbing media (e.g., gas shale and coal bed methane reservoirs) as either dual porosity media comprising matrix-fracture or as triple porosity media comprising separate organic and inorganic matrix components and fractures. We accommodate the combination of mechanical deformation and desorption induced matrix shrinking in conditioning the evolution of fracture aperture and effective stress difference between each medium. These considerations result in an improved permeability evolution model (IPEM) for both dual porosity and triple porosity fractured sorbing media. Then we have simplified the model for triple porosity fractured sorbing media by reducing the geometry configuration from three dimensional to one dimensional, marked as SIPEM1. Specifically, SIPEM1 is a model simplified from the IPEM, and consider that when the size of the REV and the volumetric strain is small, replacing the volume with the side length of each layer medium in defining the model will bring relatively small error. This model is further simplified to SIPEM1-1 by assuming that the effective stress of each medium is the same. Then we have validated the models with field data. Finally, we compared prediction results from these models under different conditions. This study has found that IPEM is the most accurate model, especially for fractured sorbing media with a larger compressibility. SIPEM1-1 does not consider the difference of the effective stress of each medium and thus it is relatively less accurate in describing the evolution of permeability compared with SIPEM1 that considers this difference. This gap increases with the increase of permeability difference between fracture and matrix.
Study on the characteristics of matrix compressibility and its influence factors for different rank coals∗ J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-31 Pei Shao, Xiao Wang, Yu Song, Yong Li
To thoroughly understand the mechanism of permeability change and improve production in coalbed methane development, it is important to clarify the evolution characteristics and influencing factors of matrix compressibility for various coal ranks. This paper presents calculations of matrix compressibility coefficients of different rank coals through mercury intrusion porosimetry (MIP) and N2 adsorption. Furthermore, the evolution of coal material and pores based on coal rank is analyzed to study their effect on matrix compressibility coefficients. The results show that the relationship between matrix compressibility coefficients and coal rank is a cubic polynomial function, in which two inflection points are situated in the maximum vitrinite reflectance (Ro,max) = 1.3% and 2.5%. For coals with Ro,max < 1.3%, matrix compressibility coefficients increase as vitrinite and volatile matter contents increase, which may be related to the lower microhardness of vitrinite and the more random structure of aromatic carbon micells surrounded or linked by carbon functional groups, such as aliphatic chains, methoxyl and carboxylic functional groups. Moreover, the regular change of moisture content with coal rank is similar to matrix compressibility coefficients and it also plays a positive role in matrix compressibility. However, the inertinite and mineral content has a rather opposite effect on matrix compressibility. For the pore structure, the larger porosity and micropore volume in coals, the greater matrix compressibility. The coals Ro,max < 1.0%, which have a loose chemical structure and high micropore volume, can bear a greater intrusion pressure than the coals with Ro,max > 1.0%, in which the micropore structure will be broken when pressure exceeds 150 MPa. The coals with greater fractal dimension are more sensitive to stress. The matrix compression can lead to reduction of micropore volume and can make the micropore structure more irregular. It indicates that the increasing of effective stress with gas discharge could reduce the permeability of the reservoir and enhance the adsorption of micropore.
Experimental and numerical investigation of the strain response of a dented API 5L X52 pipeline subjected to continuously increasing internal pressure J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-31 Yi Shuai, Jian Shuai, Xiao Zhang
A dent is a common type of defect that occurs during pipeline service. A dented region on a pipe usually creates a strong stress concentration that may become a threat to the safety and integrity of the pipeline. Therefore, such issues are major concerns for pipeline managers. To investigate the strain history behaviour of a dented steel pipeline subjected to increasing internal pressure, a full-scale experimental burst test was performed, and a nonlinear finite element method was used to compare the numerical and experimental results in this study. The paper first discusses the test specimens and test results. Then, the finite element numerical results are verified using the experimental measurement results. Subsequently, the strain behaviour at measurement points and the deformation behaviour of the test pipes were analysed in detail. Furthermore, a sensitivity analysis of strain in the axial and circumferential directions from the dent centre was performed. Deformation analysis reveal that an outward convex phenomenon occurred in axial shoulders on both sides of the dent when the Pipewall Yield Pressure reached. Test results and finite element analysis show that the strain in the dented regions changes rapidly and sharply with a large range, which can easily lead to fatigue under operation pressure for an unconstrained dent.
Effect of silica sol on the sealing mechanism of a coalbed methane reservoir: new insights into enhancing the methane concentration and utilization rate J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-28 Congmeng Hao, Yuanping Cheng, Jun Dong, Hongyong Liu, Zhaonan Jiang, Qingyi Tu
Abstract The low efficiency of coalbed methane (CBM) extraction not only causes a great waste of energy resources and environmental pollution but also poses potential safety risks during coal mining. The main reasons for these issues are the weak borehole sealing effect and serious air leakage that occur during CBM extraction. Seeking an effective sealing material is the key to improve the efficiency of CBM extraction and to protect the environment. In this paper, to explore ways to break through this bottleneck, the feasibility of silica sol (S.G325) as a sealing material for the boreholes used in CBM extraction was theoretically demonstrated. Scanning electron microscopy (SEM) was used to compare the surface morphological characteristics of S.G325 and some commonly used sealing materials. The performance of these materials after sealing the pores/fractures in the methane reservoir was also evaluated using mercury intrusion, an helium porosimeter and methane seepage tests. The experimental results indicate that S.G325 has obvious advantages over other materials because of its greater compactness, stability and performance after sealing. Evaluation of the effects of enhancing CBM extraction showed that S.G325 increased the initial concentration of CBM from 60% to 73.5% - 82.9%, the amount of time the CBM that can be utilized from 54 d to 99 d - 132 d, the volume of utilizable CBM from 3421 m3 to 4951 m3 - 5773 m3, and the utilization rate of CBM increased by 44.7% - 62.8% compared with the original utilizable methane volume. In this paper, new insights into the improvement of energy resource utilization and protection of the environment are shown.
Thermal wellbore strengthening through managed temperature drilling – Part II: Chemical system design and laboratory testing J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-28 Eric van Oort, Besmir Buranaj Hoxha, Arthur Hale
This paper is the second part of a two-part series introducing a new and innovative managed temperature drilling technique for thermal wellbore strengthening of challenging oil and gas wells. It describes the development of heat-releasing (“exothermic”) coated particles designed to release heat at exactly the right circulating time to increase near-wellbore formation temperature and thermal stress in potential lost circulation zones, such as depleted reservoir zones in deepwater wells. The increase in thermal stress directly elevates the near-wellbore tangential stress, which translates into an increase in the effective fracture gradient. This may lower the risk of lost circulation, and also improve the chance of successfully cementing casing and achieving zonal isolation. In the latter application, a treatment can be executed as an integral part of the cement job by using it in an extended spacer train for mud displacement, pumped directly prior to cement placement to thermally strengthen a formation. The coated exothermic particles, which were based on the hygroscopic calcium and magnesium salts with chlorine and bromine, were designed such that they could release their “payload” via an extended time-release mechanism, to ensure that the heat release reaches the appropriate target location in the wellbore at exactly the right time. The chemical candidate systems were found to effectively heat up the wellbore and increase temperature up to 90 °C. This, in turn, will elevate the fracture gradient by several hundred psi, depending on formation properties. The particles need to be transported to the target formation and their reaction products need to be carried away from the target formation by a suitable carrier fluid that can handle the exothermic dissolution of a large amount of salt without any instability. Details regarding the formulation and testing of non-coated and coated particles and their carrier fluid are discussed here, as well as considerations for field application of thermal wellbore strengthening. The developed managed temperature drilling technique, enabled by the chemical system described here, can be used to minimize lost circulation events and associated well trouble time and cost during drilling, cementing and completion operations.
Performance of mixture of ethylene glycol and glycine in inhibiting methane hydrate formation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-26 Zhen Long, Xuebing Zhou, Yong He, Dongliang Li, Deqing Liang
This study investigates synergistic hydrate inhibition performance of conventional thermodynamic hydrate inhibitors (THIs) combined with amino acids. For this purpose, hydrate-liquid-vapor equilibrium (HLVE) data for methane were measured in the presence of mixed ethylene glycol and glycine using 1:1 mixtures at concentrations of 1wt% (0.5 wt% ethylene glycol +0.5 wt% glycine), 5 wt% (2.5 wt% ethylene glycol +2.5 wt% glycine), 10 wt% (5 wt% ethylene glycol +5 wt% glycine), 20 wt% (10 wt% ethylene glycol +10 wt% glycine), and 30 wt% (15 wt% ethylene glycol +15 wt% glycine) by the isochoric pressure search method. Thermodynamic inhibition efficiency has been investigated by observing the shifts in the hydrate equilibrium curves and trends of the calculated hydrate suppression temperatures at various concentrations and pressures. The results were also obtained for ethylene glycol, glycine and ionic liquids for comparison. An improving inhibition performance by mixing ethylene glycol and glycine was observed, indicating the potential of amino acids as inhibition synergists in hydrate exploitation, oil/gas transportation and flow assurance. Molar hydrate dissociation enthalpies were calculated by using the Clausius-Clapeyron equation and showed that the interaction of ethylene glycol and glycine has no impact on the hydrate structure.
Absorption performance of carbon dioxide in 4-Hydroxy-1-methylpiperidine + aminoethylethanolamine aqueous solutions: experimental measurement and modeling J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-25 Nima Maleki, Kazem Motahari
In this study, new experimental data was obtained for the solubility and absorption rate of carbon dioxide in 2, 3 and 4 M of 4-Hydroxy-1-methylpiperidine (HMPD) aqueous solution and the effect of addition of 0.5 and 1.5 M aminoethylethanolamine (AEEA) on it. Experimental data was measured in a bath reactor within the temperature range of 303.15-373.15 K and pressure range of 28.3-1980.3 kPa. The solution viscosity was measured at different temperature and concentration conditions. Response surface methodology (RSM) was used for modeling and optimization of the CO2 loading and absorption rate. The results of RSM showed that AEEA concentration and partial pressure of CO2 have the maximum impact on absorption rate and CO2 loading, respectively. The maximum absorption rate and CO2 loading occurred at 2M HMPD+1.35M AEEA in 320.15K and 1980.3 kPa. The measured experimental values revealed that HMPD+AEEA solution has a more desirable absorption rate, CO2 loading and oxidative degradation in comparison to methylediethanolamine(MDEA) + piperazine(PZ) aqueous solution.
Fines Surface Detachment and Pore-Throat Entrapment due to Colloidal Flow of Lean and Rich Gas Condensates J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-25 B. Kanimozhi, Jaya Prakash, Venkat Pranesh, Vivek Thamizhmani, R.C. Vishnu
This paper describes about the lean and rich gas condensate effects on fines migration in porous rocks. Fines detachment from rock surface and pore throat entrapment are frequent causes of formation damage and well productivity loss. In condensate reservoirs, there is a large volume of liquid formation during reservoir pressure depletion. This will result in liquid loading and production decline. In this work, we critically discuss the fines migration and the permeability decrease mechanism in the gas condensate reservoir. For this purpose, we numerically simulated a condensate reservoir, which is capable of undergoing a phase transition from gas to liquid as a function of pressure depletion, temperature, and time. We have implemented CFD modeling to simulate this retrograde condensation process. The major results revealed that there is a high amount of heat release during phase transition. This heat release and condensed liquid flow detached the fines from the rock surface and finally, get trapped in the pore-throat. Our models have been validated against the experiments and showed good agreement. Overall, this work may serve as a base to re-examine the gas condensate reservoir behavior with fines transport in porous rocks.
A new method for production data analysis in shale gas reservoirs J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-24 Qingyu Li, Peichao Li, Wei Pang, Daolun Li, Haibo Liang, Detang Lu
For most shale gas wells, frequent shut-ins and nozzle size changing often occur, leading to significant discontinuities in production data. This study proposes a new production data analysis (PDA) method to address the abrupt change issue based on the virtual equivalent time. With the virtual equivalent time, the qualities of type curve matching and production data analysis can be improved when there are abrupt changes in production data. The mathematical model with a variable flow rate provides new definitions of normalized pseudopressure and pseudotime with consideration of the pressure dependent permeability for multi-fractured horizontal wells in shale gas reservoirs. Subsequently, the virtual equivalent time is calculated based on the average formation pressure to consider the abrupt changes of the production data, which also can reduce the time of superposition principle calculations. Duhamel's principle, Laplace transform and inversion, and Newman's method are employed to solve the PDA model, which is validated by analytical and numerical solutions. Then sensitivity analysis are performed on the dimensionless constrained axial modulus, which shows that the larger the dimensionless constrained axial modulus, the lower and later the curves. Finally, a field case study is carried out using the proposed method. The results show that by using the virtual equivalent time, the matching qualities are good, and the issue caused by abrupt changes is satisfactorily addressed. Therefore, it has great potential for estimating the formation parameters and predicting the well production performance more effectively and practically.
Field data provide estimates of effective permeability, fracture spacing, well drainage area and incremental production in gas shales J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-23 Behzad Eftekhari, M. Marder, Tadeusz W. Patzek
About half of US natural gas comes from gas shales. It is valuable to study field production well by well. We present a field data-driven solution for long-term shale gas production from a horizontal, hydrofractured well far from other wells and reservoir boundaries. Our approach is a hybrid between an unstructured big-data approach and physics-based models. We extend a previous two-parameter scaling theory of shale gas production by adding a third parameter that incorporates gas inflow from the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find that on average stimulation fractures are spaced every 20 m, and the effective permeability of the unstimulated region is 100 nanodarcy. We estimate that over 30 years on production the Barnett wells will produce on average about 20% more gas because of inflow from the outside of the stimulated volume. There is a clear tradeoff between production rate and ultimate recovery in shale gas development. In particular, our work has strong implications for well spacing in infill drilling programs.
Apparent permeability model for gas transport in shale reservoirs with nano-scale porous media J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-19 Shan Wang, Juntai Shi, Ke Wang, Zheng Sun, Yanan Miao, Chenhong Hou
Understanding mechanisms of gas transport in shale matrix pores is of great importance for more accurate production prediction of shale gas wells. Shale matrix is generally considered to be composed of organic matrix and inorganic matrix, and the gas transport mechanisms in different types of matrix pores are different. To date, most of the gas transport models assume that the gas transport channels in shale porous media are cylindrical capillaries or slits with uniform pore size, which ignore the effect of pore size distribution (PSD) on gas transport capacity. In addition, there are few transport models considering the presence of water in inorganic matrix, and the gas transport capacity will be overestimated ignoring this factor. Therefore, a real gas transport model for shale matrix pores is proposed so that the shale gas transport behavior can be analyzed more accurately. First, the nanopores in shale matrix is represented by cylindrical capillaries, and a logarithmic normal distribution function is utilized to characterize the PSD in shale organic and inorganic porous media. Then, the gas transport models are constructed for organic porous media and inorganic porous media, respectively. The total transport model can be obtained by coupling the two types of models. What is more, the influence of stress dependence and real gas effect are taken into account in the models. After that, the models are validated, which show that the proposed models fit well with published experimental data. Finally, the influence of multiple factors on gas transport capacity is analyzed, the results show that the total apparent permeability increases with the increase of total organic carbon (TOC) when the pressure is higher than 5 MPa, and it decreases with TOC as the pressure is lower than 5 MPa. The adsorption and desorption of gas in organic nanopores cannot be neglected, and its influence on slip flow is greater than that on Knudsen diffusion. The apparent permeability of inorganic nanopores decreases with relative humidity (water film thickness), and it decreases more rapidly when the relative humidity is higher than 0.5. The PSD has a great influence on shale gas transport capacity of porous media, especially for inorganic porous media.
Using Embedded Discrete Fracture Model (EDFM) in numerical simulation of complex hydraulic fracture networks calibrated by microseismic monitoring data J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-19 Mahmood Shakiba, Jose Sergio de Araujo Cavalcante Filho, Kamy Sepehrnoori
Hydraulic stimulation of unconventional shale and tight reservoirs often creates a complex induced fracture network, which requires a comprehensive characterization for successful exploitation and development. One of the major technologies applied over the past decade to image hydraulic fractures is microseismic monitoring, which analyzes seismic information recorded during hydraulic stimulation to locate the rock deformation. Results of the microseismic data interpretation are then used to generate and calibrate a model of the hydraulic fracture network. However, because of the complexity of the fracture model and the shortcomings of reservoir simulators, direct application of these complex fracture networks has been very limited. Instead, oversimplified models are used to assess the efficiency of the hydraulic fracturing treatment. Such assessment techniques, without further modeling and simulation of hydrocarbon production and pressure drainage, fail to represent an accurate view of the connectivity and complexity of the fracture system. In this paper, we present the application of an Embedded Discrete Fracture Model (EDFM) in numerical simulation of realistic geometry of fractures. With EDFM, each fracture plane is embedded inside the computational matrix grid and is discretized by cell boundaries. We have implemented EDFM in The University of Texas at Austin (UT) in-house reservoir simulator UTCOMP. We discuss the implementation approach using non-neighboring connections. Using the developed simulator, we studied gas production from hydraulic fracture networks calibrated from actual microseismic monitoring data. We investigated the impact of fracture network geometry on the overall performance of these hydraulic stimulations. Simulation results indicate that the efficiency of well treatment is primarily controlled by the interconnectivity of hydraulic fractures and the distribution of conductivity within the fracture network. For a given microseismic cloud, a wide range of production responses was observed by changing the degree of connectivity in the calibrated model. Moreover, the study showed that taking into account the role of aseismic deformations (such as tensile openings) significantly increased cumulative production forecasts. Neglecting the effect of these fractures may lead to underestimation of ultimate recovery.
Integration of microseismic data, completion data, and production data to characterize fracture geometry in the Permian Basin J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-19 Ross Patterson, Wei Yu, Kan Wu
Understanding how fractures propagate during multi-stage hydraulic fracturing enables better prediction for production and increases reserves. Fracture complexity due to fracture interaction makes it challenging to accurately quantify fracture geometry. Some solutions like proppant tracers and microseismic data acquisition may give a rough representation of fracture geometry, but they cannot provide complete information for fracture geometry without separate model verification. Through data synthesis from microseismicity, stimulation treatment, and production, calibrated models increase reliability in determining fracture geometry. The Permian Basin's unique lithology contains a high degree of vertical heterogeneity, accentuating the complexity that makes fracture modeling difficult. Microseismic data give gross fracture dimensions, including fracture height, length, and azimuth, and the direction of maximum horizontal stress while also providing a baseline for calibrating stimulation and reservoir simulators. Our stimulation model indicates that initiating fractures inside the Wolfcamp B2 formation results in propped height growth being contained by the Wolfcamp B1 and Wolfcamp B3 layers. Furthermore, the reservoir model also suggests that contributing reservoir volume comes mainly from the Wolfcamp B2 formation. In addition, from the microseismic analysis, the slurry stages initiated more events closer to the heel of the wellbore than the toe, which mimics the results from the fracture propagation simulator, where the fracture closest to the heel is wider since more fluid enters during the treatment than the other fractures.
Thermal shale fracturing simulation using the Cohesive Zone Method (CZM) J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-17 Saeid Enayatpour, Eric van Oort, Tad Patzek
Extensive research has been conducted over the past two decades to improve hydraulic fracturing methods used for hydrocarbon recovery from tight reservoir rocks such as shales. Our focus in this paper is on thermal fracturing of such tight rocks to enhance hydraulic fracturing efficiency. Thermal fracturing is effective in generating small fractures in the near-wellbore zone - or in the vicinity of natural or induced fractures - that may act as initiation points for larger fractures. Previous analytical and numerical results indicate that thermal fracturing in tight rock significantly enhances rock permeability, thereby enhancing hydrocarbon recovery. Here, we present a more powerful way of simulating the initiation and propagation of thermally induced fractures in tight formations using the Cohesive Zone Method (CZM). The advantages of CZM are: 1) CZM simulation is fast compared to similar models which are based on the spring-mass particle method or Discrete Element Method (DEM); 2) unlike DEM, rock material complexities such as scale-dependent failure behavior can be incorporated in a CZM simulation; 3) CZM is capable of predicting the extent of fracture propagation in rock, which is more difficult to determine in a classic finite element approach. We demonstrate that CZM delivers results for the challenging fracture propagation problem of similar accuracy to the eXtended Finite Element Method (XFEM) while reducing complexity and computational effort. Simulation results for thermal fracturing in the near-wellbore zone show the effect of stress anisotropy in fracture propagation in the direction of the maximum horizontal stress. It is shown that CZM can be used to readily obtain the extent and the pattern of induced thermal fractures.
Experimental and DEM investigations of temperature effect on pure and interbedded rock salt J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-15 Wenjing Li, Cheng Zhu, Chunhe Yang, Kang Duan, Wanrui Hu
Rock salt is considered as a favorable host rock material for natural gas storage due to its low permeability, fast self-healing ability and unique creep behavior. Characterizing engineering properties of rock salt especially interbedded salt under complicated geological storage conditions associated with temperature variations remains challenging. This research integrates physical and numerical experiments to investigate the temperature effect on the engineering behavior of pure and interbedded salt. Thermo-mechanical coupled triaxial compression tests are carried out on both pure (Ash-grey Rock Salt and Charcoal-grey Rock Salt) and impure (Rock Salt with Mudstone interbedded) rock salt specimens. To reveal the underlying mechanism of thermal-induced deformation and cracking of salt at grain scale, we configure a discrete element model and incorporate smooth-joint contacts to capture the interfacial behavior in the bedded salt. Experimental results indicate that the compressive strength and failure mode of rock salt is highly susceptible to temperature. The increasing temperature enhances the ductility of salt whereas lowers its peak compressive strength. Numerical results provide a micromechanical explanation that the attenuated compressive strength of salt under high temperature is attributed to the evolution of micro-cracks. The presence of the mudstone layer increases the overall material strength, confines the crack propagation orientations, and therefore limits the transverse deformation of the bedded salt. This study is expected to bring new insights into the micro-mechanical study of bedded salt and improve the long-term assessment of geological storage facilities.
Raman spectrometer for field determination of H2O in natural gas pipelines J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-12 Illiya Chibirev, Claudio Mazzoleni, Dennis D. van der Voort, Jacek Borysow, Manfred Fink
X-ray μCT investigations of the effects of cleat demineralization by HCl acidizing on coal permeability J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-09 Reydick D. Balucan, Luc G. Turner, Karen M. Steel
Demineralization of coal cleats via HCl acidizing is a potential stimulation strategy for improving the productivity of coal seam gas (CSG –also known as coalbed methane or CBM) wells. This preliminary study measured structural changes that HCl acidizing can produce in small-scale core samples, and investigated the mineral characteristics that control the extent of these changes. This is the first time sister cores have been explored in detail to unravel the mechanisms influencing the permeability changes. In this study, the acid-induced physicochemical changes in core samples from CSG producing coals were investigated to gain improved understanding of permeability enhancement in the vertical flow direction. In particular, this work was undertaken to explain the variability in permeability improvements when calcite from coal cleats was removed by 1% HCl. X-ray microcomputed tomography (μCT) image analyses were used to reveal the mechanisms influencing permeability changes. There was clear evidence for cleat opening via mineral dissolution as well as mineral mobilization-accumulation. Mineral dissolution improved the overall porosity of coal by opening mineralised cleats resulting in improvements in vertical permeability. Cleaned-out master cleats afforded greater permeability enhancement compared to the demineralised orthogonal cleats within bright band layers of the coal samples. Image analysis revealed that HCl-insoluble minerals were mobilised and subsequently accumulated at pre-existing bottleneck regions. The mineral build-up in these bottleneck regions limited the extent of the permeability enhancement by acidizing. Flow simulations of the digitised coal materials indicated that acidizing could enhance permeability not only in the vertical direction but also in the lateral or horizontal direction. Overall, this study concluded that improving the flow path continuity was achievable by HCl acidizing, whereby calcite-filled master cleats were particularly attractive targets for maximising vertical flow enhancements. Further research is required to assess application at larger scales, consider economic feasibility, and investigate environmental performance.
Numerical simulation on near-wellbore temporary plugging and diverting during refracturing using XFEM-Based CZM J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-09 Bo Wang, Fujian Zhou, Daobing Wang, Tianbo Liang, Lishan Yuan, Jia Hu
Refracturing can effectively enhance hydrocarbon production from hydraulically fractured wells. Using self-degradable diverting agents, people can temporarily plug previously generated fractures, and generate a new pair of fractures perpendicular to the direction of the original maximum principle stress (i.e., near-wellbore temporary plugging and diverting technique). To simulate the plugging and diverting process, a numerical model is established using the cohesive zone model (CZM) based on the extended finite element method (XFEM). After this model is verified by the published laboratory testing results, it is applied to understand the influences of stress contrast, formation permeability, rock tensile strength, Young's modulus and injection rate, so as to improve the applicability of temporary plugging and diverting technique under various reservoir conditions. Furthermore, “deflection angle” is proposed to quantitatively analyze the simulation results. This new concept enables the comparison among various cases without the restrictions of fracture length and simulation time. Simulation results indicate that: (1) with increases of stress contrast, rock permeability and Young's modulus, the diverting fractures reorient to the direction of the preferred fracture plane (PFP) more rapidly, which reduces the effectiveness of this technique; (2) propping previously-formed fractures can create higher defection angles of the diverting fractures, which enhances the effectiveness of this technique; (3) enhancing the injection rate can also enhance the effectiveness of this technique, yet there is one optimal injection rate for a given reservoirs. This study provides a systematic guideline for optimizing the temporary plugging and diverting technique under different reservoir conditions.
Laboratory visualization of fracture initiation and propagation using compressible and incompressible fracturing fluids J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-09 Murtadha J. AlTammar, Deepen Gala, Mukul M. Sharma, James McAndrew
Homogeneous, rock-like materials are fractured in this experimental study using a viscous liquid (glycerin) and nitrogen gas to provide a fundamental insight on the effect of using compressible gases compared to hydraulic fracturing fluids. The fracturing process in the experiments are captured using sequences of high resolution images as well as a novel application of Digital Image Correlation for crack detection. We show that fractures propagate through test specimens in a gradual manner when induced by glycerin at various injection rates. In contrast, nitrogen injection induces instantaneous fractures, which we attribute to its compressible nature and ultralow viscosity. The specimen breakdown pressure is also shown to be markedly lower for nitrogen fractures compared to glycerin fractures. The significantly higher pore pressure distribution and induced tensile stresses associated with nitrogen injection are demonstrated through numerical simulations of the laboratory experiments. Moreover, an experimental evidence of fluid lag when fractures are induced with viscous fluids is provided.
Fractal dimensions of pore spaces in unconventional reservoir rocks using X-ray nano- and micro-computed tomography J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-09 Mayka Schmitt Rahner, Matthias Halisch, Celso Peres Fernandes, Andreas Weller, Viviane Sampaio Santiago dos Santos
The wellbore instability control mechanism of fuzzy ball drilling fluid for coal bed methane wells via bonding formation J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Lihui Zheng, Guandong Su, Zhonghui Li, Rui Peng, Le Wang, Panfeng Wei, Shuxin Han
As a novel drilling fluid, Fuzzy-ball Drilling Fluid has been successfully utilized to control the collapse and lost circulation in approximately 1000 coal bed methane wells. However, in terms of current research, its mechanism of controlling wellbore instability has not yet been revealed clearly enough to satisfy the requirement from field applications. In order to achieve further understanding, (1) First, fuzzy-ball drilling fluid is prepared in the laboratory with 2.0% fuzzy-ball coating, 0.5% fuzzy-ball floss, 0.4% fuzzy-ball cores, and 0.4% fuzzy-ball membrane blended by Warring Blender with 7000 rpm, whose density and apparent viscosity are 0.85 and 40 mPa·s mPa · s ., respectively, close to the in-situ reality.(2) Secondly, both uniaxial and triaxial compressive tests under confining pressure 5 MPa MPa . are conducted to measure the strengths and obtain the stress-strain curves of different coal samples after the separate injections of 2% potassium chloride solution, low solid-phase polymer drilling fluid and fuzzy-ball drilling fluid, as well as the coal plunger (Φ50) without any treatment serving as the control group for three times, respectively. (3) Next, the mechanical parameters which influence the collapse pressure are figured out with regards to sampling cores acquired from the coal reservoir. Through aforementioned experimental procedures, incorporating with a classical collapse pressure prediction mathematical model that contains these mechanical parameters, the collapse pressures corresponding to coal seams subject to different types of drilling fluids are calculated. (4) Finally, two cases, Hancheng and Qinping are employed to verify the results in the laboratory. That is, collapse and loss simultaneously took place in sites where both issues were tackled in the same wells. The findings are, (1) uniaxial compressive tests show that the strength of natural coal cores after the injection of fuzzy ball drilling fluid rises from 2.6 to 3.6 MPa MPa . in average while that after the injection of KCl displays a decline and that after the injection of polymer witnesses a modest alteration. (2) The calculation results based on the stress-strain curves illustrate that the Young's modulus (E E ), Poisson ratio (υ υ ) and cohesion (Cm C m ) of the cores being injected with fuzzy ball drilling fluid change from 3.0665 to 3.9385 GPa GPa ., 0.229 to 0.318 and 0.5 to 0.9 MPa MPa . respectively, whereas those mechanical parameters being injected with other fluids manifest only slight changes. Similar results can be observed in the experiments with reconstructed artificial coal cores. (3) The in-situ application demonstrates that fuzzy ball drilling fluid is capable of overcoming the dilemma brought by collapse and loss taking place in the same well at the same moment. In conclusion, the wellbore instability control mechanism of CBM fuzzy ball drilling fluid lies in that through bonding formation, CBM fuzzy ball drilling fluid changes the rock mechanical parameters, enhancing the strength of rocks microscopically and thereby magnifying the safety density windows macroscopically so as to realize the control of wellbore instability.
Particles in fuel-grade Liquefied Natural Gas J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Aron Hakonen, Anders Karlsson, Lena Lindman, Oliver Büker, Karine Arrhenius
The utilization of Liquefied Natural Gas (LNG) in the heavy-duty transport sector is a convenient and cost-effective step towards a sustainable future. However, there are questions regarding LNG fuel quality and destructive particles for engines. Basically nothing is known about particles in the commercial LNG being fueled today. The gravimetric and SEM-EDX results here demonstrates that there are precarious metal and silicon dioxide particles in fuel-grade LNG that can clog and erode engine parts. Considering these results further research in the direction of this study, including standardized method development, is highly motivated.
A leakage diagnosis testing model for gas wells with sustained casing pressure from offshore platform J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Shengnan Wu, Laibin Zhang, Jianchun Fan, Ximing Zhang, Di Liu, Deguo Wang
Sustained casing pressure (SCP) caused by tubing leakage is mostly considered as the dangerous situation in gas wells, which is more likely to pose a serious threat to well integrity and environmental protection. In order to assess the downhole risk in early time and further provide maintenance strategies to optimize well performance, it is necessary to diagnose the source of downhole leakage accurately. This paper presents a pressure-balance-based approach for capturing two types of dynamic annulus pressure behaviors in a gas well with SCP caused by tubing leakage in different well depth. The approach includes models that take into account the influence of temperature and pressure distributions of tubing and annulus fluid, which are used to determine tubing leakage points. In addition, such an approach involves the calculation of maximum annulus pressure at the wellhead in a gas well with SCP under four main cases, representing the effects of the leakage location, bottom hole pressure, annulus liquid level and gas production rate on wellhead pressure. Afterwards, an integrated diagnostic testing system has been developed to monitor the synthetic state of annulus fluid and liquid level parameters, ultimately identifying the source of SCP correctly. In contrast to previous works, leakage diagnostic testing can be performed from an offshore platform, and it meets the requirements of offshore field testing and works without a shut-in condition, which is capable of overcoming limitations of downhole detection. A case study focused on a offshore gas well with SCP is presented to illustrate the feasibility of the proposed approach, and also to demonstrate that leakage diagnosis contributes to the mechanism investigation of SCP and improves the design of gas wells integrity.
Effect of cage-specific occupancy on the dissociation rate of a three-phase coexistence methane hydrate system: a molecular dynamics simulation study J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Zhixue Sun, Haoxuan Wang, Jun Yao, Zhilei Sun, Kelvin Bongole, Xuchen Zhu, Lei Liu, Jianzhong Wang
Molecular dynamics simulation is used to study the dissociation behavior of methane hydrate with different composition in a three-phase coexistence of liquid water + hydrate + methane gas. Five hydrate systems with various cage emptiness capacity and composition distribution are built and studied. In hydrate system with empty cages, an abnormal dash response occurred in the dissociation process compared to a stepwise respond observed in the fully occupied system. The effect of large/small cage-specific occupancy is considered in this simulation with energy evolution used to describe the dissociation rate. Hydrates with similar occupancy differ in dissociation behavior depending on the type of empty cages (small or large). Hydrate system with empty small cages show higher stability than system with larger empty cages. Ab initio calculation is used to explain this phenomenon, stability decrease of large cages loss of guest molecule is found to be higher than small cages from the calculation of stabilization energy. The differences in cage-specific occupancy effect between CO2 and CH4 hydrate is also discussed to compared with perivous researches. It has been found that the presence of CO2 molecules in small cages has less influence in stability compared to CH4 molecules. As for the stability of large cages, the existence of CO2 molecule and CH4 molecule has a similar contribution.
Overpressure prediction using the hydro-rotary specific energy concept J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Olalere Oloruntobi, Sunday Adedigba, Faisal Khan, Raghu Chunduru, Stephen Butt
Pore pressure predictions from the drilling parameters have experienced little improvement since the inception of the d-exponent concept. Applications of the d-exponent method to pore pressure predictions have produced mixed results, especially in deviated wells and under drilling conditions where bit hydraulic energy has significant influence on the rate of penetration (ROP). In this paper, a new energy-based pore pressure prediction technique using the concept of hydro-rotary specific energy (HRSE) is presented. The HRSE approximates the total energy required to break and remove a unit volume of rock. Overpressure prediction using the HRSE method is based on the principle that overpressure intervals with lower effective stress will require less energy to drill than the normally pressured intervals at the same depth. The new technique is tested using a recently drilled deep vertical exploratory gas well in the Tertiary Deltaic System in the central swamp region of the Niger Delta in Nigeria. The pore pressure estimates from the HRSE concept are compared to: (1) the pore pressure estimates derived from the d-exponent and shale compressional velocity, (2) the actual pore pressure measurements taken in the reservoir sands of interest. An excellent agreement is observed in magnitude and trend between the pore pressure estimates derived from the HRSE concept and the actual pore pressure measurements. This clearly demonstrates the applicability of the HRSE concept in predicting the onset of overpressure and estimating the formation pore pressure. The HRSE method of overpressure prediction has the potential to be more accurate in some drilling environments where the d-exponent method may have produced erroneous results.
A predictive filtration model considering mudcake compressibility and non-uniform properties’ profiles J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 H.A. Jaffal, C.S. El Mohtar, K.E. Gray
Mudcake buildup has a direct impact on expensive drilling and production problems, such as wellbore instability, pipe sticking, formation damage, and impairment of wellbore logging interpretation. Therefore, a better understanding of filtration and mudcake buildup is very valuable. This paper presents a predictive filtration model that accounts for the mudcake compressibility and captures non-uniform filtercake properties profiles. The model solves for the effective stresses acting across the mudcake thickness, based on which mudcake properties profiles are calculated. The mudcake is modeled as a stack of thin sub-layers, with each having its own properties. The porosity and permeability relations with effective stress are determined using the Odometer test, which is analyzed based on Terzaghi's theory for 1D consolidation. A detailed derivation of the model's equations is presented. Also, a computationally efficient pseudo-code solving the model's equations is suggested. Finally, the derived model is validated using experimental filtration results.
Porosity-preserving mechanisms of marine shale in Lower Cambrian of Sichuan Basin, South China J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-08 Xin Li, Zhenxue Jiang, Pengfei Wang, Yan Song, Zhuo Li, Xianglu Tang, Tingwei Li, Gangyi Zhai, Shujing Bao, Chenlu Xu, Fan Wu
Porosity preservation is of great significance in the capacity of gas shale reservoir. Whether pore space can be preserved at the later diagenetic stage controls the capacity of shale reservoir. In this study, porosity-preserving mechanisms of marine shale from Lower Cambrian, both inside and at the margin of Sichuan Basin, South China, were investigated via a combination of the X-ray diffraction (XRD), organic geochemistry analysis, gas adsorption analysis and focused ion beam milling-scanning electron microscopy (FIB-SEM) in both two-dimension (2-D) and three-dimension (3-D). The results showed that there was little difference in mineralogical compositions between samples of Qiongzhusi shales and Niutitang shales that brittle minerals and clay were predominate components. The mean value of the total organic carbon (TOC) of Qiongzhusi shales was 1.44 wt% lower than that of Niutitang shales (4.37 wt%), whereas Qiongzhusi shales were at relatively lower thermal maturity stage with equal-vitrinite reflectance (Ro) ranging from 2.66% to 2.8% compared with Niutitang shales (3.06%
5.0 wt%) or over thermal maturity (Ro>3.3%) is detrimental to pore preservation; moreover, poor sealing ability of shale systems might deteriorate pore preserving ability through losing overpressure environment or stress supporting mechanism.
Removal of mercaptan from natural gas condensate using N-doped carbon nanotube adsorbents: Kinetic and DFT study J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-03 Seyyed Salar Meshkat, Alimorad Rashidi, Omid Tavakoli
Nitrogen-doped carbon nanotube (N-CNT) adsorbents were prepared through the chemical vapor deposition method at 1000 °C by using camphor and urea. The desulfurization of liquid stream by using CNT and N-CNTs was investigated. The effects of various adsorption parameters, including time, temperature, adsorbent loaded mass, and initial concentration of tertiary butyl mercaptan (TBM), on adsorptive desulfurization were studied. N-CNTs were characterized by field emission scanning electron microscopy, X-ray diffraction, Fourier-transform infrared spectroscopy, elemental analysis (CHN), and N adsorption/desorption. Kinetic studies were carried out, and kinetic data were fitted using a pseudo-second-order model. The adsorption equilibrium data and their isotherm models were in good agreement with the Freundlich model. The sulfur concentration after adsorption was evaluated using a total S analyzer. Finally, this study demonstrated that the incorporation of N into the CNT structure resulted in an adsorption capacity of approximately 63.1 mg/g, which was 45% higher than that of pristine CNT. Density functional theory calculations were also performed to understand the effects of TBM adsorption on the N-CNTs.
Alginate-pyrolyzed porous carbon as efficient gas phase elemental mercury scavenger J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-03 Anjali Achazhiyath Edathil, Fawzi Banat, K. Suresh Kumar Reddy, C. Srinivasakannan, Ahmed Shoaibi
The present research work demonstrates the potential of porous carbon (PC) fabricated through facile one-step method from calcium alginate biomass as a low cost and efficient scavenger for gas phase elemental mercury (Hg°) from natural gas. Performance of the prepared PC at different temperatures (500, 700 and 900 °C) using fixed-bed setup mimicking the plant conditions revealed that PC-900 demonstrated to be a promising adsorbent for removing Hg°. The excellent sorption performance of PC-900 could be attributed to its BET surface area and large pore volume which rendered easy sorption of Hg° into the porous network. The equilibrium adsorption results further confirmed that sorption capacity decreased from 1236 to 1089 μg/g with increase in temperature from 30 to 50 °C, indicating exothermic nature of adsorption. The sorption isotherms well fitted the Langmuir model, with maximum adsorption capacity of 1236 μg/g at 30 °C. A comparison of the sorption capability of bio-derived PC-900 with sulfur impregnated carbon (SIC) at 50 °C affirmed that the uptake capacity of PC-900 (1089.6 μg/g) was much higher than SIC (887.2 μg/g). These results reveal the promising solutions offered by alginate pyrolyzed PC for scavenging Hg° from natural gas, by not only reducing the environmental problems associated with gaseous mercury emissions but also by making the process more economical.
Expandable Proppants to Moderate Production Drop in Hydraulically Fractured Wells J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-03 Livio Santo, Arash Dahi Taleghani, Guoqiang Li
Hydraulic fracturing is recognized as the primary technique to achieve economic oil and gas production from low permeability reservoirs like shale and tight-sand formations. One of the main challenges facing the oil and gas industry is maintaining the proppant functionality in the subsurface to guarantee a sustainable production rate and higher ultimate recovery. Proppant crushing and proppant embedment may diminish production from stimulated wells especially when bottomhole pressure is reaching low flowing pressures in soft and deep formations like Haynesville or Tuscaloosa Marine Shales. Experimental measurements and field observations have shown the strong impact of proppant stress and proppant embedment on reducing fracture conductivity. In this work, we introduce a novel material developed in order to achieve higher fracture conductivities at a minimum cost. The new type of proppants, so called "Expandable Proppants" (EP), is able to remotely control the expanding force and maintain the functionality of placed proppants. The presented proppants are made out of thermoset shape memory polymers which are activated by formation’s in situ temperature to effectively maintain or even increase fracture’s width. A fully coupled numerical model is developed to study the effectiveness of expandable proppants and evaluate fracture conductivity enhancement for different combinations and distributions of EP. In addition, a series of experiments were conducted in a modified API conductivity cell to verify the increase in fracture conductivity. Numerical and experimental results demonstrate that proppant expansion can increase the permeability up to 100%. Different conditions of confining stress and proppant sizes are studied to verify the optimum proppant design. This product can extend the lifetime of the fracture and ensure lasting production.
Enhancement of CO2 solubility in a mixture of 40 wt% aqueous N-Methyldiethanolamine solution and diethylenetriamine functionalized graphene oxide J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-03 Amin Maleki, Vahid Irani, Ahmad Tavasoli, Mehdi Vahidi
Graphene oxide functionalized by diethylenetriamine (DETA) was prepared and characterized with SEM, XRD, BET, TGA and IR spectroscopy techniques to find out its morphology, crystalline building, porous structure, thermal stability and functional groups. The CO2 solubility in 40 wt% aqueous amine solution, 40 wt% aqueous amine solution +0.1 wt% GO, and 40 wt% aqueous amine solution +0.1 wt% DETA-GO is determined. The solubility measurements were performed at three temperature (303.15, 313.15 and 323.15 K) and CO2 partial pressures up to 2200 kPa. Addition of GO and DETA-GO to MDEA (N-Methyldiethanolamine) solution enhanced the CO2 adsorption capacity of the aqueous amine solution up to 7.5% and 12.5%, respectively. Increasing CO2 partial pressure and decreasing temperature enhanced the CO2 solubility.
Monitoring gas hydrate formation and transport in a flow loop with acoustic emission J. Nat. Gas Sci. Eng. (IF 2.718) Pub Date : 2018-05-02 A. Cameirao, E. Serris, A. Melchuna, J.M. Herri, P. Glenat
Experimental studies on flow loop allow estimating the amount of formed hydrate and their transport during time. The amount of hydrates formed spatially during flow is unknown together with the location of the beginning of sedimentation and plug. This experimental study was carried on to verify the use of acoustic emission (AE) to spatially follow the formation of hydrates but also sedimentation and agglomeration. The AE energy variations allowed to follow the emulsification, to identify the beginning of the crystallization and to follow the crystallization, agglomeration and plug/sedimentation in the flow loop.
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