Hydrocarbon Generation Potential and Evolution of Pore Characteristics of Mesoproterozoic Shales in North China: Results from Semi-Closed Pyrolysis Experiments J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-13 Dongjun Song, Jincai Tuo, Mingfeng Zhang, Chenjun Wu, Long Su, Jing Li, Yuhong Zhang, Dongwei Zhang
Xiamaling shale and Hongshuizhuang shale were used to study the potential for shale gas formation in the Mesoproterozoic shales from North China by semi-closed pyrolysis experiments. Nitrogen adsorption experiments were performed on the original samples and solid residues after pyrolysis at different simulated temperatures to characterize changes of pore characteristics in the studied shales. The results of semi-closed pyrolysis experiments showed that good potential of hydrocarbon gas generation in the studied shales. At temperature of 550 oC, yield of hydrocarbon gas generated from the Xiamaling shale was 223.31 mL/g TOC with initial TOC of 3.76 % and Tmax = 450 °C, while yield of hydrocarbon gas generated from the Hongshuizhuang shale was 364.79 mL/g TOC with initial TOC of 5.18 % and Tmax = 440 °C. The results of the lower pressure nitrogen adsorption experiments demonstrated that relatively larger-size pores would be dominated with the increasing temperature. Pattern of pore size distribution changed during the pyrolysis experiments. pore size distribution of original samples was unimodal with pore size of 2 nm, bimodal shape with peak apertures of 2 nm and 30 nm was beginning to dominated with the increase of pyrolysis temperature, and finally, shape of unimodal with aperture of 30 nm tended to more predominant at higher temperatures. In addition, evolutionary scenarios of nanopores for the two studied shales were composed by three stages with increasing of pyrolysis temperature, including pore decreasing, increasing and transforming stages. This study revealed the shales in the Mesoproterozoic of North China have good potential for the formation of shale gas.
A STUDY ON THE EFFECT OF GAS SHALE COMPOSITION AND PORE STRUCTURE ON METHANE SORPTION J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-13 Santanu Bhowmik, Pratik Dutta
Ten moist, powdered European shale samples were analyzed for their sorption properties by volumetric method. The adsorption capacities were correlated to the shale organic types and maturity. The pore-size distribution obtained from low-pressure CO2 micropore adsorption was also correlated with the porosity and shale organic types. Furthermore, pore volume and average pore width were taken into consideration to determine the dominant parameters controlling adsorption. To identify the discrepancy between available and actual pore space for adsorption, helium and krypton gases were used for void volume estimation. Methane adsorption isotherms follow Langmuir Type I behavior and, in general, showed a positive trend with Total Organic Content (TOC) and Hg-porosity although some deviations were also observed. Low to moderate level of hysteresis between adsorption and desorption isotherms for some samples was visible, which may be attributed to the experimental uncertainty and existence of heterogeneous pores for shale-methane interaction. The low-pressure micropore adsorption analysis indicated dominance of nanopore and very fine micropores in the shale matrix structure along with associated microporosity of the clay materials. The observed “negative” adsortion or “decline” in adsorption isotherm are related to the mismatch of the available pore spaces for helium and methane. In general, He-calibrated isotherms showed higher levels of adsorption than the corresponding Kr-calibrated isotherms although the unit void volume for all samples follow a negative trend with the maximum methane capacity.
Thermal cooling to improve hydraulic fracturing efficiency and hydrocarbon production in shales J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-12 Saeid Enayatpour, Eric van Oort, Tad Patzek
Unconventional hydrocarbon reserves contained in oil and gas shale formations are proving themselves to be abundant sources of current and future energy supply, unlocked through the technologies of horizontal drilling and hydraulic fracturing. Despite the various technology improvements that have buoyed the ”shale revolution” in the last decade, there remain very significant opportunities to further improve hydrocarbon recovery from shales by making hydraulic fracturing more efficient. In this paper, we look into the possibility of stimulating a rock matrix to a higher degree with hydraulic fractures by deliberately cooling down the rock. Cooling reduces in-situ thermal stress, which lowers initiation and propagation pressures of hydraulic fractures. Moreover, when a laterally confined solid undergoes temperature reduction induced by cooling, a thermal stress gradient is developed in the solid body. We perform sensitivity analyses to show that in an in-homogenous shale, this thermal stress gradient can lead to differential contraction of its various mineralogical constituents, which in turn may create thermal cracks. The opening of such cracks increases shale permeability and provides additional pathways for the flow of hydrocarbons, thereby enhancing productivity. Here, we solve the coupled equations of stress, heat transfer and flow using finite element techniques for hydraulic stimulation amplified by cooling. It is shown that thermal cracks in tight formations induced by thermal cooling have the potential to improve the productivity of horizontal wellbores placed in shale by an estimated 16% for the case of methane gas flow through thermally stimulated shale of micro-darcy permeability.
Theoretical evaluation and optimization of a cryogenic technology for carbon dioxide separation and methane liquefaction from biogas J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-11 Marco Spitoni, Mariano Pierantozzi, Gabriele Comodi, Fabio Polonara, Alessia Arteconi
The transport sector represents one of the major cause of air pollution and greenhouse gases emissions. For this reason, several measures have been taken: penalty and incentive schemes have been introduced worldwide to increase renewable energy sources and alternative fuels use. It is widely accepted that natural gas (NG) is a good alternative fuel, especially in its liquid form (LNG), and it can be produced using biogas as methane source to obtain renewable liquefied biogas (LBG). However raw biogas contains several impurities and it needs to be pre-treated. At present, several technologies allow biogas purification. In particular cryogenic separation represents a promising solution for simultaneous purification and liquefaction. It can achieve impurities removal and methane liquefaction by means of a single plant. In this work, a novel cryogenic separation process, based on CO2 cold recovery, is presented. The proposed plant is optimized and a sensitivity analysis is also performed. Results indicate that the proposed plant represents a valid option for LBG production. Indeed the specific energy consumption is 1.574 kWh kg−1 for a CO2 content in inlet biogas of 50%. Furthermore the energy use and operative costs are compared with those of standard technologies and they result respectively 23% and 22% lower, taking into account the influence of CO2 as by-product.
Liquid CO2 Behaviour during Water Displacement in a Sandstone Core Sample J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-07 Ebraheam Al-Zaidi, Xianfeng Fan
CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a potential strategy to reduce CO2 concentration in the atmosphere, enhance hydrocarbon production, or extract geothermal heat. CO2 injection is considerably influenced by the interfacial interactions, capillary forces and viscous forces. Any change in the subsurface conditions of pressure, temperature, and salinity is likely to have an impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have an influence on the injection, migration, displacement, and CO2 storage capacity. In this study, unsteady-state immiscible experimental investigations have been performed to explore the impact of fluid pressure, temperature, salinity (brine concentration and valency) and injection rate on the dynamic pressure evolution and displacement efficiency when CO2 as a liquid phase is injected into a water-saturated sandstone core sample. This study also highlights the impact of capillary forces and viscous forces on the two-phase flow properties and shows when capillary forces or viscous forces are dominant. The results reveal a moderate to considerable impact for the fluid pressure, temperature, injection rate, and salinity on the differential pressure profile, water recovery (WR), endpoint CO2 relative permeability (KrCO2), and cumulative produced volumes. Overall, increasing fluid pressure, CO2 injection rate and salinity (brine concentration and valency) cause an increase in the differential pressure profile; the highest increase occurred with the injection rate. In general, increasing temperature caused a reduction in the differential pressure profile. The WR is in range of around 61.6-69.3% while the KrCO2 is in range of 0.112-0.203, depending on the investigated parameters. Increasing fluid pressure and injection rate caused an increase in the WR; the highest increase occurred with the injection rate. On the other hand, increasing temperature and salinity caused a decrease in the WR; the highest reduction occurred with salinity. Nevertheless, the increase in fluid pressure, temperature, injection rate and salinity led to a reduction in the endpoint CO2 relative permeability; the highest reduction occurred with increasing temperature whilst the lowest occurred with increasing fluid pressure. The cumulative injected volumes decreased with fluid pressure and salinity but showed no noticeable change with temperature and injection rate. The capillary forces have less impact on the differential pressure profiles than viscous forces when fluid pressure, temperature and injection rate increase but the capillary forces have more impact when salinity increase.
Using rate based simulation, sensitivity analysis and response surface methodology for optimization of an industrial CO2 capture plant J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-07 Abbas Hemmati, Hamed Rashidi, Abdollsaleh Hemmati, Abolghasem Kazemi
Using optimum conditions in CO2 capture processes to maximize CO2 capture capacity and rich amine temperature leads to saving energy and reducing costs. In the present article, an industrial CO2 capture process with aqueous MEA was studied using the sensitivity analysis and an optimization method. The process was simulated using a rate-based model. The results were validated against four different industrial operational data. In the four different industrial situations, the average relative error was 1.38 % to 3.85 %. The liquid temperature profiles and CO2 absorption (%), calculated by the model agree with the real operational data. In the second part of the work, a sensitivity analysis of the absorption column’s important variables was carried out to determine sensitive parameters for CO2 absorption capacity and rich MEA temperature. The variables are gas flow rate, solvent flow rate, flue gas temperature, inlet solvent temperature, CO2 concentration in the flue gas, loading of inlet solvent, and MEA concentration. Based on the results, all of the operational parameters except the inlet solvent and the inlet liquid temperature are considered influential. In the third and final part of the article, the operational conditions are optimized to maximize CO2 absorption (%) and rich solvent temperature. Response surface methodology (RSM) is used as a statistical optimization tool. The experimental design data were analyzed by analysis of variance (ANOVA) and fitted to the second-order polynomial equation using multiple regression analysis. By applying the optimum operational conditions in the model, CO2 absorption (%) and rich solvent temperature of 95.63 % and 56.15 °C can be obtained, which indicate 13 % and 17 % increase, respectively compared to the base case. The results showed that the absorber’s energy consumption is decreased by 16 %, when applying optimum operational conditions. In contrary to previous studies, it is found that rich solution temperature is not a function of lean solution temperature. According to the results, the inlet gas flow rate is the most influential parameter in CO2 absorption and rich solution temperature.
Effects of water invasion law on gas wells in high temperature and high pressure gas reservoir with a large accumulation of water-soluble gas J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-07 Xiaoliang Huang, Xiao Guo, Xiang Zhou, Chen Shen, Xinqian Lu, Zhilin Qi, Qianhua Xiao, WendeYan
A high temperature and high pressure (HTHP) gas reservoir with a large accumulation of water-soluble gas contains a large amount of dissolved gas in formation water. The dissolved gas in the formation water will be released due to formation pressure depletion in the production process. At present, few researches have been done on water invasion law of gas wells regarding the released dissolved gas, especially when the change rule of water and gas is not clear in porous media after the release of water-soluble gas, which leads to the unclear water invasion law and the gas reservoirs cannot be developed efficiently. In this paper, a visualization sand filling tube is used to conduct experiments to study the effects of the dissolved gas on the law of the gas-water contact (GWC) changes in the water-soluble gas release process. The experimental results show that the release of dissolved gas leads to a GWC rise at the beginning of the depressurization process. After the pressure drops to a lower level, the GWC will decline due to a large amount of dissolved gas being released from formation water. Subsequently, numerical simulations are performed to study the effects of different solubilities of natural gas, the gas production rate, the aquifer size, and stress sensitivity on the water invasion law of the gas well. The simulation results show that a greater solubility of natural gas, a higher gas production rate, a larger aquifer size, and the existence of stress sensitivity all lead to stronger bottom water coning and an early water break-through. For the non-coning region, a greater solubility of natural gas will lead to a slower rise in the GWC. The simulation results show that the water invasion velocity with water-soluble gas is faster than the velocity without water-soluble gas.
Condensate Blockage Alleviation around Gas-Condensate Wells using Wettability Alteration J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-07 Seyed-Ahmad Hoseinpour, Mehdi Madhi, Hamidreza Norouzi, Bahram Soltani Soulgani, Amir H. Mohammadi
In the current survey, a novel fluorocarbon-based wettability modifier chemical is proposed to alter the wettability of sandstone rock surface from liquid wetting to preferentially gas wetting condition. Several experimental tests describing wettability condition of the rock surface including static contact angle measurements, spontaneous imbibition and dynamic core flooding using water and n-decane fluids were conducted on untreated and treated sandstone rock to investigate the effect of the proposed chemical on surface wetting behavior. Adsorption of fluorinated chemical on sandstone surfaces was characterized using FTIR and SEM. Elemental analysis of rock surface after treatment was determined by EDX analysis and EDX map. After chemical treatment of sandstone thin section, contact angles of water and n-decane in air-liquid-rock system were altered from 0° and 0° to 151° and 101°, respectively. Spontaneous imbibition of water and n-decane as imbibing liquid fluids into the core sample saturated with dry air at room temperature on untreated and treated core showed that the ultimate amount of liquid imbibition was decreased to a factor of 0.03% and 0.16%, demonstrating wettability alteration from strongly condensate-and water-wet to preferentially gas-wet condition, respectively. Also, the results of core flooding experiments demonstrated the improvement of liquid phase mobility as a result of treatment with proposed chemical fluid by factors of 3.85 and 3.5 for water and n-decane, respectively. The outcome of this integrated study proposes that fluorochemical agents can be considered as a promising candidate for possible field applications to alleviate both condensate and water blockage in gas condensate reservoirs by wettability alteration technique.
A comparative study of different mass transfer and liquid hold-up correlations in modeling CO2 absorption with MEA J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-08 Abbas Hemmati, Hamed Rashidi, Kourosh Behradfar, Abolghasem Kazemi
Although CO2 absorption processes have been widely studied in both laboratory and industrial scales, the viability of different relations for the estimation of mass transfer coefficients has not been studied for industrial units. In this paper, the accuracy of different various equations for the estimation of mass transfer coefficients were are evaluated and compared, on the basis of according to the results of an industrial CO2 absorption unit. Therefore, the relations proposed by Onda, Bravo and Billet-Schules were are selected. Also, in some parts of the column pall ring packing was is used. in these parts the Hanley mass transfer coefficients were also used. In addition, Hanley mass transfer coefficients are used for those parts of the column in which pall ring packing is used. Based on the results of rate-based modeling of the column, obtained results show that the Onda equations show have higher accuracy compared to the other mass transfer equations. The comparison was is carried out based on CO2 absorption capacity, temperature profile and rich solvent concentration. The average errors of Onda’s mass transfer correlations and Billet & Schultes’s liquid holdup correlations in estimating CO2 absorption (%), temperature of rich solvent’s temperature, temperature of outlet water’s temperature and loading of rich solvent’s loading were are 1.153, 2.923, 6.99 and 1.163 % respectively. Onda and Billet & Schultes correlations exhibited the most accurate results. Also additionally, liquid film discretization shows indicates that the reaction occurs almost rather instantaneously at liquid-vapor interface and diffusion is the controlling step in the absorption process.
Thermal stability and corrosion of tertiary amines in aqueous amine and amine-glycol-water solutions for combined acid gas and water removal J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-08 Usman Shoukat, Eva Baumeister, Diego D.D. Pinto, Hanna K. Knuutila
Thermal stability and corrosion of seven tertiary amines (20 wt.%) solutions in water and water-glycol [ethylene glycol (MEG)/tri-ethylene glycol (TEG)] loaded with CO2 in stainless steel reactors has been studied for combined acid gas removal along with hydrate control. The pKa of the tested amines varied from 7.85 to 9.75. Titration and inductivity coupled plasma mass spectrometry (ICP-MS) are used to quantify the remaining alkalinity and metal concentrations in amine solutions respectively. The presence of MEG and TEG profoundly influenced the amine stability. Triethanolamine had the highest thermal stability. Furthermore, the results also show that an increase in pKa generally decreases corrosion. 3-(Diethylamino)-1,2-propanediol (DEA-1,2-PD) has the lowest corrosion in water and water-TEG solutions while 2-(Diethylamino)ethanol (DEEA) has the least corrosion in water-MEG solutions.
Application of horizontal wells to the oceanic methane hydrate production in the Nankai Trough, Japan J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-07 Tao Yu, Guoqing Guan, Abuliti Abudula, Akihiro Yoshida, Dayong Wang, Yongchen Song
Due to the complicated reservoir conditions in the oceanic methane hydrate (MH) reservoir in the Nankai Trough, Japan, the gas production rate for the economical extraction had not been achieved during the current field production tests in 2013 and 2017 using vertical wells. Therefore, this study aimed at the application of the horizontal wells to the oceanic MH production in the Nankai Trough. Since there existed three sub-hydrate-bearing layers with different physical properties (i.e., initial hydrate saturation, porosity, and intrinsic permeability) in the reservoir, some possible well configurations including single horizontal well patterns and dual horizontal well patterns were designed based on a multilayered geological model simulating the real oceanic MH reservoir in the Nankai Trough. Then, the effectiveness of these two kinds of well designs was verified via long-term simulations of the oceanic MH production by simple depressurization, and the optimal well configuration for each design was recommended. Furthermore, a combined method of depressurization and hot water injection was also tested based on the dual horizontal well pattern, and the sensitivity analyses indicated that a favorable gas production rate of 8.64×105 m3/day could be obtained within the first year, even under a relatively low injection temperature of 40°C and a relatively small injection rate of 2 kg/s/m of well.
Real-time risk assessment of a fracturing manifold system used for shale-gas well hydraulic fracturing activity based on a hybrid Bayesian network J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-03 Xin Zhang, Laibin Zhang, Jinqiu Hu
A fracturing manifold system used in the shale-gas hydraulic fracturing process involves significant risks, which result from its unique and harsh working conditions, such as high pressures of up to 105 MPa and a large displacement, along with the continuous erosion and corrosion of high-speed solid particles. Considering the high- or low-frequency demand modes of the components and the effect of any deviation in the state indicators on the real-time risk of the fracturing manifold system, we propose a real-time risk assessment method based on a hybrid Bayesian network (HBN) to provide decision support for supervisors that will prevent accidents. The proposed approach can be utilised to calculate the probability of each potential consequence in real time. The built HBN model was quantified by using the historical failure-related data of various components, specific monitoring data of multiple state indicators and expert judgment. An extensive case study focused on the real-time risk of a real-world fracturing manifold system and demonstrated the practical application of the presented methodology. We show by application that the proposed model can improve the situational awareness among operators, which is an effective method to control and reduce risk.
Design of a Neural Network Based Predictive Controller for Natural Gas Pipelines in Transient State J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-04 Ali Pourfard, Hamidreza Moetamedzadeh, Reza Madoliat, Esmaeel Khanmirza
In a natural gas network the gas pressure decreases continuously due to friction. The compressor stations are placed in strategic locations of networks to make up for the lost pressure. This ensures the delivery of time-varying costumer demands in desirable pressure. Howbeit, the compressor’s operational costs constitute the major portion of a network costs.Different approaches can be used to find the optimum operation of the gas network compressor’s when the demand profiles are known from the historical data. However, the demand profiles may become different from their long time average. For this case, a novel on-line predictive control scheme is presented in this work. This scheme finds the near optimum operation of the compressor more easily and in much less computational time, while eliminating the necessity of re-solving the optimization problem.The proposed strategy utilizes two multi layered neural networks (MLNNs) for on-line prediction and control tasks. The NN predictor is used for on-line prediction of highly nonlinear dynamics of the gas network in transient state. The on-line NN controller uses the prediction information to find the near optimum control inputs (rotational speeds of the compressors) to provide the new desired demands. This can be achieved by tracking the previously obtained optimum outlet pressures of the network.The controller results are validated with another controller which uses the particle swarm optimization (PSO) algorithm as the optimizer. To investigate the controller operation in performing the optimization task, its simulation results are compared with global optimum results, which assert its suitable performance.To investigate the robustness of the control scheme, the network outlet demand flow rates are changed in two different scenarios. Moreover, the performance of the controller is evaluated in the presence of noise and disturbances, which confirms its efficiency and accuracy.
Characterization of wellbore microannuli J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-12-04 Serafin Garcia Fernandez, Edward N. Matteo, Mahmoud Reda Taha, John C. Stormont
Wellbores are comprised by a steel casing surrounded by a cement sheath. The microannulus is the typically very small annular or degraded space that may develop between cement and casing that has been identified as a common leakage pathway in wellbore systems. Although data regarding the actual size and character of wellbore microannuli are limited, the hydraulic aperture of the microannulus can be estimated from pressure build up or flow measurements at the wellhead. Such information can be misleading, however, as it represents microannuli as uniform annular gaps along the wellbore. This study aims to provide a quantitative measure of the variability of the microannuli. We generated wellbore-based samples with microannuli between the steel casing and cement, and calculated their hydraulic aperture and permeability by flowing gas through the microannuli. We then injected dyed epoxy into the microannuli, cut the specimens into five circumferential sections per sample, and used microphotographs to measure microannulus aperture size and contact between the steel and the cement to generate microannulus profiles for each section. These measurements are unique as they provide a quantitative measure of the variability of the microannulus with a resolution as low as 3 μm. Aperture sizes were fitted to different statistical distributions, most frequently lognormal and gamma. Capillary entry pressure (CEP) for gas displacing brine in the microannulus was estimated from measured aperture size. CEP estimated from actual aperture size was generally much greater than that estimated from the hydraulic aperture of the entire specimen, resulting in a wide range of values. Measured aperture sizes were used to evaluate possible microannulus repair by estimating the penetration of cementitious materials. The data showed that the repair using cementitious materials is unlikely to be effective for microannuli with a hydraulic aperture <50 μm.
3D Printed Bio-Inspired Sealing Disc of pipeline inspection gauges (PIGs) in Small Diameter Pipeline J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-28 Jinhui Dong, Hang Zhang, Shuhai Liu
PIGs (pipeline inspection gauges) have been the main equipment for pigging, inner inspecting operations in oil and gas pipelines. Due to the insurmountable shortcomings of conventional sealing discs, it is impossible to actively control the PIG when it is running on the pipeline, which leads to no way when the PIG is stuck. In this study, a new type of bio-inspired sealing disc was designed in combination with the webbed foot structure of animals (e.g., bird, frog, duck), soft robot technology and the conventional sealing disc, adding a new way to the mechanical pigging method. And the 3D printing technology was used to print the sample of the bio-inspired sealing disc, taking into account the new direction of manufacturing the PIG. Then, effects of the interference (δ), clamping rate (ζ), webbed foot thickness (tw) and the number of webbed foot (N) of the bio-inspired sealing disc on the contact force and stress were studied using MSC Marc 2016 when the PIG was in pipe. The simulation results show that the contact force and stress on the bio-inspired sealing disc are not uniform, showing a great difference in the uniform contact force and stress on the conventional sealing disc. The effect of interference and clamping rate on the maximum contact force, stress on the bio-inspired sealing disc and the influence on the conventional sealing disc are basically the same, but the impact on the minimum stress and contact force is different. The thickness of the webbed foot has the greatest influence on the contact force, stress on the bio-inspired sealing disc, and the number of the foot has the least influence.
Comparison of Micro- and Macro-Wettability Measurements and Evaluation of Micro-scale Imbibition Rates for Unconventional Reservoirs: Implications for Modeling Multi-Phase Flow at the Micro-Scale J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-26 H.J. Deglint, C.R. Clarkson, A. Ghanizadeh, C. DeBuhr, J.M. Wood
Significant advances have been made in the evaluation of micro- and nano-scale variations of pore structure in low-permeability (unconventional) reservoirs using imaging techniques. In parallel, digital rock physics (DRP) methods have been advanced so that pore structure information extracted from these images may be used, in combination with pore-scale modeling, to predict critical petrophysical rock properties such as porosity and permeability. Recent work using DRP applied to multi-phase flow of unconventional reservoirs has suggested that wettability variations at the micro-scale caused by mineralogical heterogeneity or aging can have a profound effect on simulated capillary pressure and relative permeability curves. However, wettability is typically measured at the macro-scale, with the resulting contact angles used for populating DRP models. Further, fluid imbibition rates are usually measured at the macro-scale to compare, for example, the impact of fracturing fluid additives on oil recovery. This study compares water contact angle measurements made at the micro-scale, using an environmental field emission SEM combined with innovative procedures for contact-angle extraction, with a conventional macro-scale approach (sessile drop) for low-permeability samples obtained from the Montney Formation in Western Canada. For the first time, quantification of imbibition rates at the micro-scale is demonstrated. Two micro-wettability evaluation procedures developed previously are applied to these samples to evaluate water micro-contact angles: 1) imaging of condensation/evaporation experiments and 2) imaging of injected fluids using a micro-injection system. Micro contact angles were first estimated by extracting sessile droplet profiles (with user-guided software developed in-house) and then fitting a parameterized Young-Laplace equation to the droplet profile. For some of the micro-injection experiments, the geometry of the micro-droplet, as captured with the parameterized Young-Laplace equation, was used to compute the volume of the micro-droplet at different stages of imbibition, which in turn was used to evaluate imbibition rates at this scale. Macro contact angles were evaluated using the parameterized Young-Laplace equation and commercial software. This study suggests that laboratory-derived macro-droplet contact angles cannot be confidently and consistently applied at the micro-scale for use in DRP models for tight heterogeneous formations such as the Montney. Significant errors in simulating fluid displacement processes, fluid saturation distributions, capillary pressure and relative permeability curves using DRP methods will result if micro-scale variations in wettability are not taken into account. Finally, the study demonstrates that fluid imbibition measurements may be performed at the micro-scale, enabling fine-scale rock composition/pore structure controls on fluid imbibition to be explored.
Finite Element Solution of a New Formulation for Gas Flow in a Pipe with Source Terms J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-22 M. Behbahani-Nejad, A. Bermúdez, M. Shabani
A new formulation for isothermal gas flow in a pipeline with gravity and friction source terms is introduced and solved by finite element methods using FEniCS open-source computing platform. The proposed formulation can be easily adapted to simulate different types of real boundary conditions and involves only one scalar unknown instead of two ones (typically mass flux and pressure or density). The main motivation for presenting the work is to find a compact formulation which is able to be solved with a high order accuracy scheme just by changing the type of elements. Also, it can be extended to gas network easily. In order to check the performance of the numerical method, it has been applied to several test problems. At first, with the purpose of finding the order of accuracy, two manufactured tests for different types of boundary conditions are solved. The results show that, for nodal finite elements of degree one, the order of accuracy in space is more than two and for time is between two and three. Then, two test cases with step boundary conditions are solved. The corresponding numerical results show that, even with large time-step and coarse mesh, they are in good agreement with those obtained with a fine mesh. Finally, a real pipe from the Spanish gas network is solved and the results compared with on-line measurements.
Utility of inclusions for interpreting reservoir thresholds for tight sandstone gas accumulation in the Longfengshan and Dongling sags, Southeast China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-22 Wei Wang, Youlu Jiang, Rudy Swennen, Jing Yuan, Jingdong Liu, Shaomin Zhang
To better understand the thresholds for hydrocarbon migration in tight sandstone, we studied the gas migration and accumulation processes in the Longfengshan and Dongling sags in the Songliao Basin by determining the ancient pore pressure evolution and gas fractionation. The trapping pressure of coeval aqueous inclusions can be used to identify systematic overpressure trends, which increase during gas charging. Early formation of overpressure and a maximum surplus pressure greater than 6 MPa in reservoirs adjacent to high-quality source rocks (total organic carbon > 1.2%) indicate that the formation of surplus pressure is related to the gas generation capacity. The gas-bearing inclusion distribution and systematic geochemical trends suggest that dynamic gas migration was accompanied by gas fractionation. The results indicate that dissolved gas mainly accumulated in reservoirs with a maximum surplus pressure greater than 6 MPa and that the free gas diffused toward reservoirs with maximum surplus pressures less than 6 MPa. The gas saturations were generally stable and greater than 50% in the high surplus pressure zone. However, in the low surplus pressure zone, the gas saturation was less than 25%, although this value was relatively higher in reservoirs where the maximum surplus pressure was less than 3 MPa. Our results demonstrate that the resistance thresholds for the migration of dissolved gas and free gas differ in tight sandstone reservoirs. The surplus pressures greater than 6 MPa are advantageous for dissolved gas accumulation. An obvious resistance threshold is not observed for free gas migration, although the migration of this gas was relatively inefficient and occurred mainly via diffusion in the direction of decreasing surplus pressure. The results of this study confirm the importance of considering the driving force for natural gas in different phases as a key factor when determining optimal exploration targets.
Characteristics of Oat Hull Based Biosorbent for Natural Gas Dehydration in A PSA Process J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-22 Saeed Ghanbari, Catherine H. Niu
Temperature swing adsorption is currently one of the methods used for the dehydration of natural gas; however, several operating problems including high operating cost, pollution, low selectivity and the thermal degradation of adsorbents need to be addressed. In this work, pressure swing adsorption was investigated for the dehydration of natural gas using a cost effective biosorbent. Oat hulls, a byproduct from the agricultural industry, were used as a representative of cellulose materials for the first time to develop the biosorbent for the pressure swing adsorption process. The morphology, surface functional groups and thermal stability of the biosorbent were investigated by FE-SEM, XPS and TGA. The effects of the key operating parameters including temperature, pressure, gas flow rate, feed concentration, and biosorbent particle size on the process were analyzed by a full factorial experimental design. The results demonstrated a higher water adsorption capacity at room temperature and a higher selectivity towards methane than those of commercial adsorbents. Furthermore, the biosorbent showed stable performance after being used for fifty adsorption-desorption cycles. Though the biosorbent was regenerated at room temperature, the TGA results showed that biosorbent was stable at temperatures up to 210 °C. Additionally, the analysis of adsorption and desorption rates revealed that a cyclic adsorption-desorption process is possible. Adsorption equilibrium and kinetics were investigated, and the experimental equilibrium data was analyzed by the Anderson, and Toth models, and kinetic data by the Thomas model. The monolayer adsorption capacity, surface affinity and mass transfer coefficients were determined. The results indicate that this high-performance and environmental friendly process has potential for natural gas dehydration industry.
Adaptive finite element–discrete element analysis for the multistage supercritical CO2 fracturing and microseismic modelling of horizontal wells in tight reservoirs considering pre-existing fractures and thermal-hydro-mechanical coupling J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-22 Yongliang Wang, Yang Ju, Jialiang Chen, Jinxin Song
Compared with conventional water-based fracturing, the supercritical CO2 (SC-CO2) fracturing technology can potentially improve the fracturing effect and gas production in unconventional tight reservoirs. To comprehend the key mechanical mechanism of this technology, some governing issues, such as the heat transfer between the injected SC-CO2 and rock matrix, multistage fracturing, pre-existing fractures, and fracturing-induced damaged, and contact slip events, need to be properly simulated via numerical approaches. However, the challenge of characterizing the complex structure of natural fractures and the physical properties of SC-CO2 that significantly affect fracturing and heat transfer in porous rock matrix have not been satisfactorily solved. To overcome the shortcomings of the conventional finite element methods that impede the automatic remeshing to fit the simulation of fracture propagation, in this study, we introduce an adaptive finite element–discrete element method and local remeshing strategy to simulate the propagation of fracturing fractures. The proposed numerical model involves the crucial governing issues of a multistage SC-CO2 fracturing, such as heat transfer, thermal-hydro-mechanical coupling, the interaction between the fracturing fractures and the embedded pre-existing fractures, leak-off of fracturing fluid, proppant transport, and gas production prediction. Based on the changes of the computed stresses, the distribution and magnitudes of microseismic damaged and contact slip events can be identified, allowing us to predict the microseism caused by fracturing. The fracture network and consequent heat transfer and fluid flow induced by slick water and SC-CO2 fracturing in engineering-scale unfractured and naturally fractured models are compared in the same manner to evaluate the influence of SC-CO2 on multistage fracturing behaviour, thermal effects, gas production, and microseismic effects. Numerical results show that SC-CO2 fracturing can improve the fracturing effect as well as increase the production rates but may not simultaneously induce additional microseismic events.
Experimental investigation of the behavior of methane gas hydrates during depressurization-assisted CO2 replacement J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-22 Chen Ye, Gao Yonghai, Chen Litao, Wang Xuerui, Liu Kai, Sun Baojian
CO2 replacement with depressurization assistance is a crossover concept that has been proposed in recent years for natural gas hydrate development. It combines the merits of two traditional methods to improve production and reduce risks. To verify the feasibility of this new method and evaluate the corresponding efficiency, experimental apparatus has been designed to simulate the horizontal interface between a CO2 injection well and a CH4 production well based on the independent extraction mechanism and well structure design. To prepare natural gas hydrate-bearing samples under conditions that conform to actual field conditions, silica sand is packed into a core-holding tube with methane gas and distilled water at appropriate pressures and temperatures. Then a horizontal extraction process with an injection well and a production well are simulated, and the parameters influencing the pressure system, such as inlet pressure (pressure of injection well), outlet pressure (pressure of production well), and confining pressure (pressure of the overburden layer), are controlled as variables and analyzed. The ratio of generated methane and injected CO2 is used to evaluate the corresponding utilization efficiency (UE) in this work. Results indicate that all these pressure parameters have certain effects on CO2 replacement behavior. Generally, the fluid flow driven by pressure differences, and the special phase equilibria properties are the essence of their influence. The feasibility of enhancing CO2 utilization efficiency with depressurization assistance is verified based on experimental data. In consideration of time and cost, the relative pressure parameters should be optimized comprehensively to maximize commercial efficiency before field application.
Sequential Storage and In-situ Tracking of Gas in Geological Formations by a Systematic and Cyclic Foam Injection- A Useful Application for Mitigating Leakage Risk during Gas Injection J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-23 Abdulrauf Rasheed Adebayo
Geological storage of Carbon Dioxide (CO2) can safely and permanently store a huge amount of anthropogenic greenhouse gases. However, the possible leakage of mobile gases through the cap rock that confines them within the reservoir is a cause of safety concerns. Residual and solubility trapping of the injected gas in the pores of the rock can reduce the amount of mobile gas lying below the cap rock. These trapping mechanisms will only begin at the end of several decades of gas injection, which implies that there is an imminent risk of discharge of large amount of gas in the event of a leak. This paper presents a method to fast-track and enhance residual and solubility trapping process while gas injection is in progress, such that only a fraction of the injected gas will migrate and be trapped beneath the cap rock after injection ceases. The method involves cyclic injection of gas and water (containing small amount of foaming agent). Foams are known to have gas trapping characteristics during flow in porous medium. A series of laboratory experiments was conducted on representative rock samples at different reservoir conditions. The results show a sequential and cumulative growth in trapped gas during cyclic injection of gas and foam based on in-situ and real time measurements of gas saturation in the samples using electrical resistivity tool. The amount of trapped (residual) gas depends on the type of gas (N2 or CO2), water salinity, concentration of the foaming agent, and temperature. The highest residual gas saturations (50% – 70% of reservoir pore volume) occurred at a temperature and water salinity typical of a deep saline aquifer (450C and 58,000 ppm water). At a high water salinity of 242,000 ppm, the residual gas saturation was significantly lower (27% – 30%). Similarly, at a high temperature of 90 0C, the residual gas saturation reduced to 27%. Residual gas could not be sustained when CO2 is injected compared to N2 because of the low interfacial tension between CO2 and water, which reduces the foam quantity and strength. The importance of foam stabilizing agents (e.g. polymers and nanoparticles) in addressing the observed shortcomings in CO2 foam and for foam injection in high salinity - high temperature reservoirs is discussed. A field scale application of this method is also highlighted.
A Data Analytic Workflow to Forecast Produced Water from Marcellus Shale J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-23 Amin Ettehadtavakkol, Ali Jamali
Water and gas production and potential water treatment facility requirements for the Marcellus formation are discussed using data analytic methods. These methods aim to handle dataset diversity and scale, and apply data analytics for statistical imputation, estimating future drilling activity, fluids production, and the optimization of water recycling facility locations and size. The objective of this study is to quantify and predict the volumes of produced fluids in the short- and medium-term for the Marcellus shale. The paper accomplishes this objective for the Pennsylvania section comprising 10,000 wells. The application of data analytics to large-scale, data-intensive, low-integrity public environmental databases is illustrated, and challenges of implementation methods are discussed and resolved. In addition, a special class of data analytic tools and workflows for spatiotemporal analysis (spatially correlated variation of parameters with time) is discussed and implemented. The results quantify the prospect of future drilling activity, and water and gas production for all Pennsylvania counties in the Marcellus. Finally, several practical problems of interest on applications of predictive analytics and management support are proposed and solved. The limitations of the proposed workflow are briefly discussed.
A new modeling approach for a CO2 capture process based on a blended amine solvent J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-20 Jisook Lee, Junghwan Kim, Huiyong Kim, Kwang Soon Lee, Wangyun Won
The modeling procedure of an absorption-based carbon capture process using a blended amine solvent is presented. Semi-empirical correlation equations were developed for modeling the CO2 vapor-liquid equilibrium (VLE) and absorption rate in the ternary aqueous amine solvent used in this study. To reflect the non-ideality of the blended amine solvent in a CO2 loaded state, correction terms based on the fresh amine and free amine concentrations were added to the CO2 VLE and CO2 absorption rate models, respectively. The developed model was implemented in the commercial software PRO/II® by means of a user-added subroutine. Both the absorber and stripper were represented by rate-based models. The process behavior predictions by the proposed simulation model were compared with the pilot plant operation data. A quite satisfactory agreement between the model and data was obtained, which verifies the effectiveness of the proposed solvent modeling techniques.
Investigation the Efficiency of Corrosion Inhibitor in CO2 Corrosion of Carbon Steel in the Presence of Iron Carbonate Scale J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-18 Mehdi Javidi, Reza Chamanfar, Shima Bekhrad
In this work, the inhibition efficiency of an imidazoline derivative corrosion inhibitors in CO2 corrosion of carbon steel was investigated in the presence of iron carbonate scale and hydrogen sulfide. The use of corrosion inhibitors is one of the most common controlling techniques for CO2 corrosion of carbon steel in oil and gas industry. One of the imidazoline derivatives was used as a corrosion inhibitor which protects the surface through the film formation mechanism. The investigation material was API 5L X65 carbon steel which was cut from a wet gas transmission pipeline. The internal surface of the pipe was covered with iron carbonate as corrosion product. In order to investigate the inhibitor efficiency, Tafel polarization and electrochemical impedance spectroscopy were done in CO2-saturated 3.5 wt.% sodium chloride solution. According to the results, the existence of iron carbonate film reduced the inhibition efficiency. Furthermore, it was found that in the presence of H2S gas, the inhibition efficiency was decreased due to the decrease in inhibitor adsorption on the surface.
Adsorption Separation of Oxidative Coupling of Methane effluent gases. Mini-plant Scale Experiments and Modeling J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-14 Leonel García, Yuly A. Poveda, Gerardo Rodríguez, Erik Esche, Hamid Reza Godini, Günter Wozny, Jens-Uwe Repke, Álvaro Orjuela
This work explored the use of a zeolite molecular sieve as adsorbent material in the separation of effluent gases from an oxidative coupling of methane (OCM) process. The molecular sieve granules were synthesized, characterized, and evaluated as adsorbent material at the mini-plant scale. Dynamic adsorption experiments were performed at different feed temperatures (298, 308, 328 K), with pure and mixed gases (ethylene, ethane, oxygen, nitrogen and carbon dioxide), and at different absolute pressures (2 and 6 bar). The breakthrough curves and the corresponding dynamic temperature profiles from the adsorption system were obtained under the different experimental conditions. According to results pressure swing adsorption can be used as a de-methanizing alternative during the OCM downstream separation, and even as an ethane/ethylene separation alternative. The adsorption capacities for the different gases, per unit mass of adsorbent, at 303 K and 5 bar were: 0.138 kgCO2/kg, 0.094 kg C2H4/kg, 0.082 kgC2H6/kg, and 0.020 kgCH4/kg. A model of the process was implemented within Aspen Adsorption® software, and the transport parameters were adjusted to fit experimental observations. The computer model agreed with experimental results, and it can be used for further process up-scaling and techno-economic evaluation.
The effect of saturation conditions on fracture performance of different soundless cracking demolition agents (SCDAs) in geological reservoir rock formations. J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-13 V.R.S. De Silva, P.G. Ranjith, M.S.A. Perera, B. Wu
Fracture stimulation using soundless cracking demolition agents (SCDAs) is a potential alternative technique to induce high-density fractures in sedimentary reservoir-rock as an auxiliary technique to improve the efficiency of enhanced oil and gas recovery efficiencies. However, to date, its application has been limited to fracture stimulation in dry rock masses. Therefore, using modified SCDAs, which can be used for underwater rock fracturing, a series of experiments was conducted to investigate the fracturing performance of SCDAs in saturated rock masses. 18 coarse-grained sandstone specimens were saturated in water, oil, and NaCl brine and fractured using three different SCDA types: a standard SCDA (S1), and two modified for underwater application (S2) and accelerated reaction rate (S3). Then, the fractured samples were scanned in the Australian Synchrotron, and the fractures were quantified using Avizo 9.0.1. The fracture initiation time and the total fracture network length and volume were found to be dependent on the saturated pore fluid of rock. Water saturation of samples increased the fracture initiation time by 16.5%, 24.1% and 13.68% for S1, S2, and S3 type SCDAs respectively and reduced the fracturing potential of SCDA by 59.5%, 32.49% and 66.67% compared to dry samples. This reduction was less apparent in oil-saturated samples as the high pore fluid viscosity of oil-saturated samples aid fracturing, which is explained by the Poiseuille equation. Increasing salinity in the saturation fluid from 0% to 12.5% was favourable for the fracturing efficiency of SCDAs because of the formation of CaCl2 in the pore fluid, which accelerates the reaction of SCDA. Fracture orientation also changed depending on the saturation fluid, which was again governed by the variation in reaction rate in SCDAs under different saturation conditions.
Energy and exergy analysis of acid gas removal processes in the LNG production chain J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-13 Laura A. Pellegrini, Giorgia De Guido, Valentina Valentina
In the energy transition towards a zero-carbon energy sector, natural gas grows much faster than either oil or coal, since it is an environmentally-friendly fuel supported by the continuing expansion of LNG, increasing the availability of gas globally. In recent years, the substantial growth in the world energy demand has increased the interest in the exploitation of natural gas reservoirs previously deemed undesirable due to their high acid gas content. Existing technologies for natural gas purification, such as chemical absorption with alkanolamine solvents, may be not suitable for treating highly contaminated natural gas due to the required higher solvent circulation rate and, consequently, to the energy demand for solvent regeneration. Over the last decades attention has been devoted to the study and development of low-temperature CO2 removal processes. With these new technologies, CO2 is separated as a high-pressure liquid making it easier to be pumped underground for sequestration or utilization in Enhanced Oil Recovery (EOR) projects.The aim of this work is to analyze natural gas purification technologies and liquefaction schemes for the production of LNG starting from the same acid natural gas stream. In particular, two CO2 removal technologies are considered to bring CO2 concentrations down to levels suitable for LNG production: the conventional chemical absorption technology with activated-MDEA (aMDEA) as solvent and the recently patented Dual Pressure Low-Temperature (DPLT) distillation technology. Different commercial technologies are taken into account for the liquefaction of the purified natural gas: Propane-Mixed Refrigerant (C3MR), Mixed Fluid Cascade (MFC), and Single Mixed Refrigerant (SMR). However, since these liquefaction processes are designed for a sweet gas obtained using a conventional acid gas removal technology, some adjustments have been made for their application to a low-temperature sweet gas. The choice to compare a conventional technology with a novel low-temperature one has been made to understand if the synergy between a CO2 removal technology operated at low-temperature and the downstream liquefaction process is advantageous, despite the need for refrigeration also in the CO2 removal step.The different process schemes resulting from the combination of the two CO2 removal technologies with the liquefaction ones have been simulated in Aspen HYSYS® V10 and their performances are assessed and compared by means of energy and exergy analyses, respectively based on the “net equivalent methane” approach and on the exergy efficiency concept.Results suggest that, although the aMDEA absorption process and the DPLT distillation one with downstream separation of NGLs recovery have about the same specific energy consumption when applied to the natural gas stream taken into account in this work considering the CO2 removal step only, the overall process (including the liquefaction of the purified natural gas stream) involving the DPLT distillation technology is characterized by lower consumptions and a higher exergy efficiency.
Evaluating the Performance of Hydraulic-Fractures in Unconventional Reservoirs Using Production Data: Comprehensive Review J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-13 Dheiaa Alfarge, Mingzhen Wei, Baojun Bai
Understanding the performance of the reservoir productivity in the post-stimulation conditions has recently gained an extensive emphasis from the specialist researchers and operators. Although there have been different tools used to evaluate the fracturing process and to predict the well performance, using production data as an indirect tool to calibrate the fracturing design and to forecast the reservoir performance has been considered the most potential technique. However, different methods with a high ambiguity have been used in this area of research over the last decade. Therefore; developing, screening, and specializing different methods and techniques to diagnose and evaluate the post-fracture reservoir performance by using flowback data has a significant priority. Determining the performance of hydraulic fractures from flowback data is considered the actual calibration to estimate the effective volume, length, height, conductivity, and width of hydraulic fractures. This paper presents a comprehensive review on most of the approaches, which have been recently introduced in this area of research, including their applicability, pros and cons. Furthermore, this study explains how each method can be valid at a specific time range. The potential tools, which could be more successful to be used in this direction of research, have been extensively discussed and recommended.
Optimal Cost and Design of an Underground Gas Storage by ANFIS J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-12 Primož Jelušič, Stojan Kravanja, Bojan Žlender
We present an optimal cost and design prediction of an underground gas storage (UGS) system, which is proposed to be constructed from one or more lined rock caverns. The adaptive network based fuzzy inference system ANFISUGS was generated to predict minimal investment costs and optimal UGS design. Since a safe and impermeable UGS system requires a rigorous calculation, three steps were proposed to solve this task: the first is solving the geotechnical engineering problem for different UGS designs, the second is the cost/design optimization of the UGS structures, and the last is the generation of an ANFIS system for optimal cost and design prediction of the UGS. While the geotechnical problem was solved with a series of finite element analyses in order to define special geotechnical constraints to be put into the optimization models, a parameter non-linear programming (NLP) optimization approach was used for a variety of different UGS design parameters. The ANFISUGS system was then constructed on the basis of data sets defined from previous NLP optimization results. A case study demonstrates the effectiveness and the prediction capability of the proposed ANFISUGS system.
Improving Hole Cleaning using Low Density Polyethylene Beads at Different Mud Circulation Rates in Different Hole Angles J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-10 Wong Jenn Yeu, Allan Katende, Farad Sagala, Issham Ismail
In oil and gas exploration and development, drilling a hole is one of the first and most expensive operations. The continuous demand from industry to reduce costs and operational problems has resulted in numerous innovative drilling technologies that allow us to drill directionally. Nevertheless, hole cleaning has become a problematic issue in directional drilling because drill cuttings tend to be deposited on the lower side of the deviated hole. Excess accumulation of cuttings significantly reduces the rate of penetration and indirectly increases the operational cost. To improve the cuttings transport efficiency in a deviated hole, low-density polyethylene (LDPE) beads were introduced into water-based mud for hole cleaning. LDPE beads travel rapidly through the mud column due to buoyancy and move the cuttings forward by drag and collision. The interaction between the LDPE beads and cuttings facilitates the cuttings transport process and prevents the cuttings from settling. In this study, different concentrations of LDPE beads (i.e., 1% to 5% by volume) and different flow rates (i.e., 0.4 L/s, 0.6 L/s, and 1.0 L/s) were used to determine the effects on cuttings transport efficiency. In addition, the hole angle was varied from vertical to horizontal to evaluate the significance of LDPE beads in assisting in transporting cuttings. The results denote that more cuttings can be removed from a hole with higher concentrations of LDPE beads in water-based mud. This finding is due to the higher frequency of collisions, which in turn produces larger impulsive force. In addition, the improvement in cuttings transport efficiency enabled by LDPE beads is more significant in a vertical hole than in a highly deviated hole. In summary, LDPE beads are a promising additive for drilling mud to effectively remove drilled cuttings from a hole.
Pore characterization and the controls of organic matter and quartz on pore structure: Case study of the Niutitang Formation of northern Guizhou Province, South China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-10 Zhaodong Xi, Shuheng Tang, Jin Li, Zhongyao Zhang, Heqi Xiao
Quartz and organic matter (OM) are two important components in marine shales that have significant effects on shale gas reservoir quality, particularly on pore structure. However, a limited number of in-depth studies exist on characterizing the OM and quartz. In this study, types of quartz and OM in the organic-rich marine Niutitang shales and their impacts on pore structure were investigated using X-ray diffraction analysis, scanning electron microscopy, nitrogen adsorption, and geochemical analyses. Three OM types (scattered OM, stripped OM, and interstitial OM), four types of OM pores (primary OM pores, convoluted OM pores, shrinkage OM pores, and thermogenic OM pores) and two quartz types (detrital quartz and authigenic quartz) were identified. The Lower Member (LM) and Upper Member (UM) of the Niutitang Formation have different types of OM and quartz, resulting in the differences of pore structure characteristics. Scattered OM and convoluted OM pores and extrabasinal detrital quartz are widespread in the UM, whereas interstitial OM and thermogenic OM pores and authigenic quartz are common in the LM. Quartz in the LM shales positively correlated with TOC, as well as TOC positively correlating with excess-Si, which may indicate that quartz may be mostly biogenic in origin. The biogenic authigenic quartz can act as a rigid framework, which can resist compaction and preserve the internal pore structure and provide enough space to be in-filled by OM. Abundant OM filled inter-particle pores formed by authigenic quartz is the principal matrix for OM pore development. There are positive correlations among TOC and quartz with pore structure parameters and shale with higher contents of TOC and quartz lead to preservation of some primary pores and development of OM pores, indicating that the pore structure in the Niutitang shale may be mainly controlled by OM and quartz. This study suggests that the shale in the LM would more likely contain better pore systems and provide favorable reservoir spaces for shale gas due to its high content and favorable types of OM and quartz.
Variation of mechanical properties of bituminous coal under CO2 and H2O saturation J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-10 X.G. Zhang, P.G. Ranjith, A.S. Ranathunga, D.Y. Li
CO2 injections into coal seams can boost the recovery of coalbed methane (CBM), while simultaneously sequestering a greenhouse gas. However, alteration of the mechanical attributes of coal is observed during CO2 injection. Most studies to date have focused on the influence of single-fluid saturation on coal, and few investigations have been dedicated to various and coupled-fluid saturations on the geomechanical attributes of coal. This work therefore examines the effect of CO2, water and water+CO2 saturation on bituminous coal. It was found that the average uniaxial strength of the untreated coal samples is 46.07MPa and it reduces after CO2 and water saturation, this reduction increases with increasing CO2 saturation pressure, especially for supercritical CO2, as the much higher adsorption affinity of supercritical CO2 results in greater structural alteration. Further 5.29% and 9.69% strength reductions were found for water+6MPa CO2 and water+8MPa CO2 (supercritical) saturated samples, from 26.33MPa and 19.00MPa to 23.90MPa and 14.53MPa, respectively, compared with the corresponding single CO2 saturations, because of the enhanced structural alteration and mineral dissolution observed in SEM images. The coal structure is relaxed with increased Young’s modulus after exposure to CO2 or water. More progressive strain development was found for the water+CO2 treated sample, which showed a more ductile collapse compared with the shear-dominated failure of the untreated sample. The weakening effect was further evidenced by acoustic emission (AE) results, according to which the AE energies decreased considerably after CO2 or water saturation, and this reduction intensified for the water+CO2 saturated sample with increase of crack initiation stress and reduction of stable crack propagation. The findings highlight that while single CO2 or water saturation weakens coal strength, the coupled influence of water+CO2 saturation, which is the most likely scenario in actual field operations, induces greater strength alteration and threatens the overall stability of the system.
Pore-scale lattice Boltzmann simulation of two-component shale gas flow J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-10 Junjie Ren, Qiao Zheng, Ping Guo, Song Peng, Zhouhua Wang, Jianfen Du
Shale gas is usually a multi-component gas mixture dominated by CH4. Moreover, CO2 sequestration in shale reservoirs and CO2-enhanced shale-gas recovery also result in multi-component gas flow in shale reservoirs. Therefore, compared with single-component gas flow, multi-component gas flow is more often encountered in practice. Furthermore, shale rock contains a lot of nano-pores in which the micro-scale effect makes the multi-component gas flow become more complex. In this paper, the lattice Boltzmann method is employed to simulate the two-component shale gas flow in a two-dimensional micropore under different conditions. The pore-scale transport mechanism of the two-component shale gas is investigated and the gas separation phenomenon for the shale gas flow is discussed in detail. It is found that the molar fraction of each species in shale gas does not distribute uniformly along the micropore and the gas separation phenomenon exists in the two-component pressure-driven shale gas flow. The molar fraction distribution of each species along the micropore is affected by the Knudsen number, pressure ratio, shale gas composition and molar fraction of each species for the pressure-driven gas flows. In particular, we find that the molar fraction distribution and pressure distribution for two-component shale gas along the micropore are related to the pressure ratio and are unrelated to the pressure gradient. With increasing the molar fraction of CH4 in shale gas, both the gas-mixture velocity at the outlet and the slip velocity along the micropore become larger. Both the Knudsen number and pressure ratio affect the molar fraction distribution of CO2 for the CH4-CO2 mixture in the micropore during CO2 injection, while the influence of them works oppositely. Furthermore, the concentration diffusion without the external force is affected by the micropore width and the concentration difference between the gas mixtures.
In situ stress distribution and its impact on CBM reservoir properties in the Zhengzhuang area, southern Qinshui Basin, North China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-08 Saipeng Huang, Dameng Liu, Yidong Cai, Quan Gan
In situ stress is crucial for hydraulic fracturing during enhanced coalbed methane (CBM) recovery. The study is an attempt to get a better idea of fine evaluation of the stress distribution, and to clarify the stress distribution near the fault zone. The in situ stresses and formation pore pressure of coal seams at depths of 300–1300 m in the Zhengzhuang area of the southern Qinshui Basin were systematically analysed using well test data. The research area was divided into three partitions based on formation pore pressure gradient and regional geological structure. The three partitions present various petrophysical properties. Moreover, a 3D simulation was conducted to evaluate the effects of faulting on the stress state. Excellent relations exist among the pore pressure, minimum horizontal stress (Po and σh) and depth of the target coal seam, which can be used to predict the distribution of in situ stresses in the research area where few well test data exist. A lower lateral stress coefficient (κ) suggests a higher permeability in the extensional southern Qinshui Basin. Lower horizontal tectonic stress coefficients and relative stress factors suggest a higher permeability area. The simulation and microseismic fracture monitoring results show that the horizontal principal stress direction obviously changes near the fault zone, suggesting the existence of a complex in situ stress state. Faulting has a great influence on σH orientation. The stress simulation could be a means to detect faults and predict the direction and magnitude of σH for areas without adequate well test data. Therefore, these results may have significant implications for the permeability evaluation of coal seams during safety mining and CBM production.
Image analysis of the pore structures: an intensive study for Middle Bakken J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-09 Kouqi Liu, Mehdi Ostadhassan, Thomas Gentzis, Hallie Fowler
Pores with sizes ranging from nanometers to micrometers are widely distributed in shale gas and shale oil formations. These pores are the sites for hydrocarbon accumulation and provide the flow paths for hydrocarbons during production. The Middle Bakken member is the main production zone of the Bakken Formation in North Dakota. In order to reveal the pore structures of the Middle Bakken, we employed field emission scanning electron microscopy (FE-SEM). After segmentation of the SEM images, we calculated the surface area and shape of the pores using image analysis and then quantified the complexity and heterogeneity of the pore structures by applying both fractal and multifractal analyses. Finally, we employed the fractal permeability model to estimate the permeability of the samples. The results showed that different pore types, such as interparticle and intraparticle pores exist in the Middle Bakken samples. Even under the same scale of the same sample, the pore parameters could be different. Sample 2 has the largest average porosity, followed by Sample 1 and Sample 3. The mean pore size of these samples is less than 31 nm indicating that the pores in Middle Bakken samples are very small. The pore structures in the Middle Bakken exhibited fractal and multifractal behavior. The fractal dimension from the entire size range of pores is the largest compared with the fractal dimension of the subdivided groups. The pore size distribution in Sample 2 is the most heterogeneous.
Environmentally friendly techniques for high gas content thick coal seam stimulation─multi-discharge CO2 fracturing system J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-09 Xuelin Yang, Guangcai Wen, Haitao Sun, Xuelong Li, Tingkan Lu, Linchao Dai, Jie Cao, Lei Li
Almost all the coal seams in China are characterized by high gas content, extremely low permeability, complicated geological structure, thus, natural disasters such as gas explosive and outburst easily occur. At present, gas extraction is an effective approach for preventing such disasters. In this paper, in order to improve gas extraction efficiency, the Multi-discharge CO2 fracturing system (Multi-CO2-Frac) was proposed and tested in Changping coal mine. Through analysis of the waveforms from the explosions of 0.5 and 1 kg TNT dynamites and 1 kg liquid CO2, it can be obtained that the TNT equivalence of 1 kg CO2 is about 400-430g, that is, the explosion of 1 kg liquid CO2 has same fracturing ability as 400-430g TNT dynamites. Besides, field test shows that the effective drainage radius caused by Multi-CO2-Frac technique is about 12.5m, regardless of the number CO2 discharging sets. However, the gas extraction concentration increases with the number of CO2 discharges. This phenomenon indicates that more cracks will be created along the axial direction in coal seam drilling boreholes by Multi-CO2-Frac techniques. By comparing gas concentration before and after fracturing, it can be concluded that the Multi-CO2-Frac techniques can change and maintain the uptrend of gas concentration at a higher level in a long period of time. Therefore, in order to extend the duration of high efficiency gas extraction, Multi-CO2-Frac techniques can be used periodically at different position of coal seam. Meanwhile, after gas extraction, the maximum gas emission of coal seam was reduced from 5.5m3/min to 3.48m3/min and the driving footage was enhanced from 2.4m/d to 5.7m/d. In summary, Multi-CO2-Frac techniques can effectively improve the coal seam permeability and further enhance the gas drainage efficiency, which can meet the requirement of gas extraction in high gas content thick and soft coal seam. Therefore, this technique has a promising application prospect because of its advantages of safety, environmental protection and economy.
Investigation on the Catalytic Conversion of Hydrogen Sulfide to Methyl Mercaptan as a Novel Method for Gas Sweetening: Experimental and Modeling Approaches J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-09 S.A.M. Khaksar, M. Zivdar, R. Rahimi
The conventional method for gas sweetening is the conversion of hydrogen sulfide to solid sulfur. Although this method has some advantages, researchers are trying to come up with more beneficial technologies. In light of this requirement, a modified experimental method based on the method previously proposed by Yermakova and Mashkina in 2004 is used in the current study. The main idea of this method is modified as the novelty of this investigation which is utilization of mixture of H2S, propane and butane, as a sour gas instead of pure hydrogen sulfide. Modified mathematical approach based on the model previously proposed by Yermakova and Mashkina in 2004 is used to convert the hydrogen sulfide to methyl mercaptane. In this way, in the first stage of this study, experimental investigation is performed to investigate the possible effect of three different parameters of molar ratio, mass flow rate and inlet temperature. After that the obtained results are utilized to mathematically model the proposed sweetening method. The overall results demonstrated that although application of H2S mixtures leads to lower conversion rate of H2S to methyl mercaptane due to lower partial pressure of H2S regarding the presence of impurities of propane and butane, the catalytic conversion of H2S to valuable chemicals can be an applicable and feasible tool for industrial purposes.
Unexpected formation of sII methane hydrate in some water-in-oil emulsions: Different reasons for the same phenomenon J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-02 Andrey S. Stoporev, Andrey G. Ogienko, Artem A. Sizikov, Anton P. Semenov, Dmitry S. Kopitsyn, Vladimir A. Vinokurov, Lidiya I. Svarovskaya, Lubov’ K. Altunina, Andrey Yu. Manakov
The structures of methane hydrate obtained from water emulsions in oils of four types, n-heptane and n-decane were studied. Surfactant Span 80 was used to stabilize emulsions of water in n-heptane and n-decane. Hydrate synthesis was carried out by two methods, namely rapid cooling of a water-in-oil emulsion saturated with methane and long-term isothermal holding of this emulsion. It was shown that different methods of hydrate preparation may result in formation of gas hydrates with different structures. Rapid cooling of three of these emulsions (in two oils and n-heptane) saturated with methane to a temperature below -35°C leads not only to the formation of the expected methane hydrate of cubic structure I (sI) but also to the cubic structure II (sII) hydrate. In case of oils, the formation of the hydrates in the emulsions seemed to occur at a temperature below the pour point of the corresponding oil. Experiments were carried out with the cooling rate about 14°C/min at initial methane pressures near 12, 10 and 7 MPa. More detailed investigation showed that in two of these emulsions (in one oil and n-heptane) only sI hydrate is formed during long-term synthesis at 1°C and methane pressure of 12 MPa. The formed sII hydrate must be metastable. In the case of the emulsion in second oil, the formation of sII hydrate can be related either to the kinetic factor (the formation of metastable hydrate) or to the presence of propane and butanes in the corresponding oil in rather high concentrations. The reason of the metastable phase appearance in the systems under consideration is most likely to be that Span 80 and some kinds of crude oil can inhibit nucleation of sI gas hydrate at the oil – water interface. Thus, some emulsions saturated with methane can be overcooled to a temperature at which the nucleation of sII hydrate is preferable. The data obtained are of interest to understand mechanisms of gas hydrate inhibition / promotion and may provide fresh insight into the influence of crude oils and surfactants on gas hydrate nucleation in water – oil – gas systems.
Production performance analysis for horizontal wells in gas condensate reservoir using three-region model J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-03 Zhang Wei, Cui Yongzheng, Jiang Ruizhong, Xu Jianchun, Qiao Xin, Jiang Yu, Zhang Haitao, Wang Xiaoguo
Gas condensate reservoir is a special kind of oil and gas system that involves two-phase flow during production, because oil condensation occurs when reservoir pressure drops below the dew point pressure. It is of great importance to develop some well testing models for the gas condensate reservoir, yet there exists no analytical well-testing model for horizontal well in such formations. This paper proposes an analytical model for the production performance analysis of horizontal well in gas condensate reservoir. The three-region model is employed to characterize the flow and production of gas condensate, and the three regions are: region-1 in which oil and gas are both mobile, region-2 in which only gas is mobile whereas the oil cannot flow, and region-3 in which only the gas phase exists. To solve the proposed model, Laplace transformation and Cosine transformation are applied to change the partial differential equations to ordinary differential equations. Then, Stehfest numerical inversion technique is used to convert the solution of the proposed model into real space. Afterwards, the pressure response type curve is obtained and nine flow regimes are identified. Subsequently, sensitivity analysis is carried out to investigate the influence of several factors on production performance. Finally, field application is carried out to validate the accuracy of our model, and it is shown that the model prediction result is in accordance with the real production data. The proposed model provides some insights toward the production behavior of horizontal well in gas condensate reservoir, and can be used to evaluate the horizontal well productivity of the such reservoirs.
A Review of Gas Hydrate Nucleation Theories and Growth Models J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-01 Wei Ke, Thor M. Svartaas, Daoyi Chen
Assessment of hydrate blockage risk in long-distance natural gas transmission pipelines J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-11-01 Wenyuan Liu, Jinqiu Hu, Xiangfang Li, Zheng Sun, Fengrui Sun, Hongyang Chu
Hydrate generation and pipe blockage in long-distance natural gas transmission pipelines has always been a major issue affecting the transmission safety. Although considerable progress have been made in recent years, there is still a long way to go in the study of the hydrates generation and plugging prediction in the gas pipelines. Hydrate plugging and accumulation is a gradual process. However, the previous studies have focused only on the prediction of whether hydrates are formed. Actually, the research on hydrate formation rate and pipelines blockage degree at different times is also important for the hydrate prevention and control. In this work, the authors proposed a novel risk assessment method for hydrate blockage in long-distance natural gas transmission pipelines. Firstly, considering the hydrate formation process, a new model consist of mass, momentum and energy balance equations was established. Secondly, the model results are solved by the iterative method and finite difference method. After comparison, the calculation results and the field data are in good agreement. Finally, the sensitivity analysis were performed on the important parameters of our model. According to the sensitivity analysis, transmission rate, inlet temperature, and natural gas dew point temperature have different effects on the hydrate generation, the location of the largest plugging point, and the degree of blockage. Meanwhile, considering the actual gas transmission process and the hydrate plugging characteristics, the proposed hydrate prevention and control measures can be taken to achieve safe and efficient natural gas transmission.
Experimental investigation into the damage-induced permeability and deformation relationship of tectonically deformed coal from Huainan coalfield, China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-31 Qingquan Liu, Kaizhong Zhang, Hongxing Zhou, Yuanping Cheng, Hao Zhang, Liang Wang
Knowledge of the mechanical behavior and permeability evolution of tectonically deformed coal (TDC) is the foundation for the successful design of enhanced gas drainage. However, our understanding of the effect of progressive damage on the fluid flow in TDC is limited due to its unique structure and low visibility. We report measurements of the deformation, strength and permeability evolution during triaxial compression of soft coal samples made by TDC. According to the experimental results, the soft coal can generate an obvious nonlinear-elastic deformation before the yield strength, leading to the formation of unique features of the fracture volume evolution of soft coal. The closure of the existing microcracks in soft coal continues until the reversal of the total volume when the confining pressure is greater than or equal to 8 MPa. The fracture compressibility constants of the three soft coal samples were 4.71E-2 MPa-1, 4.63 E-2 MPa-1 and 4.89 E-2 MPa-1, which are much smaller than the literature values reported for other intact coals, which range from 6.21E-2 MPa-1 to 2.71E-1 MPa-1, indicating that the stress sensitivity of TDC is weaker than that of the intact coal. During the progressive deformation of soft coal, the permeability only reverses when the stress state exceeds the fracture damage stress. The study's achievements show that the simplification of the pre-failure behavior as a perfectly elastic mode is not applicable to the soft coal and would lead to mistakes in further permeability calculations. Further work should be extended to develop a more appropriate constitutive model and a permeability model to describe the pre-failure non- linear (elastic) deformation and the corresponding permeability evolution of soft coal.
Simulation of wellbore construction in offshore unconsolidated methane hydrate-bearing formation J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-31 Tsubasa Sasaki, Kenichi Soga, Mohammed Elshafie
The unconsolidated nature of offshore methane hydrate-bearing formation poses challenges to sustainable methane gas production as the weak formation is susceptible to disturbance during wellbore construction. This could contribute to loss of well integrity which could manifest as sand production and error in the interpretation of downhole tests such as mini-frac tests. In this study, a simulation methodology of wellbore construction process is proposed. A finite element model adopting this methodology is developed in order to assess the effect of wellbore construction process on the integrity of the unconsolidated methane hydrate-bearing formation in the Nankai Trough, Japan. The main objectives are (i) to develop a modelling methodology of well construction process for numerical simulations, (ii) to assess the zone and magnitude of well construction-induced stress/strain disturbance in the formation and (iii) to evaluate relative impact of each well construction stage on the integrity of the formation. The results from this study show that the zone of horizontal stress disturbance from the geostatic state due to wellbore construction could extend to more than three times the radius of the wellbore. Following the wellbore construction, the deviator stress is concentrated in the hydrate reservoir sublayers with high hydrate saturation while plastic deviatoric strain has accumulated in the sublayers with low hydrate saturation. The results also show that modeling of cement shrinkage process is crucial in predicting the concentration of deviator stress in the high hydrate saturation layers.
Characteristics and controlling factors of pore structure of the Permian shale in southern Anhui province, East China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-31 Taotao Cao, Mo Deng, Zhiguang Song, Houyong Luo, Andrew S. Hursthouse
The Permian shale reservoir in southern Anhui province, East China is regarded as a promising target for shale gas exploration. In order to investigate the characteristics of shale pore structures and their controlling factors, total organic carbon (TOC), Rock-eval, organic petrology, X-ray diffraction (XRD), scanning electron microscopy (SEM), field emission scanning electron microscopy (FE-SEM), nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP) and helium pycnometry were conducted on the Permian shales collected from two shale gas parameter wells. The results indicate that the BET surface areas determined by N2GA method vary between 1.05 and 49.25 m2/g. The porosities derived from MIP and helium pycnometry tests are in the range of 0.68%-8.9% and 1.15%-9.79%, respectively. FE-SEM reveals that organic matter (OM) pores and cracks are well developed in the Permian shales, though some OM grains contain few pores, which might be related to the maceral composition. At a high maturity stage, vitrinite do not develop secondary OM pores, and sapropelinite generally develop abundant OM pores. However, solid bitumen occupies interparticle space between minerals grains, and generally contains a small amount of pores documented in studied samples. The TOC contents have a positive relationship with the BET surface areas, suggesting OM is a primary factor in micropore and fine mesopore (<10 nm) development. TOC content has a positive relationship with porosity for samples with TOC<6.16%, but samples with TOC>6.16% usually have a low porosity probably due to compaction and/or different organic fractions. Residual bitumen (S1) is weakly and negatively correlated with Hg-porosity, due to residual bitumen filling in OM and mineral pores and reducing the total porosity. In addition, BET surface area decreases with increasing clay mineral content and Hg-porosity decreases with increasing quartz content, illustrating that clay mineral is unfavorable to the development of micropores and fine mesopores and high content of quartz may reduce macropore space. Finally, the shales of the Gufeng and Dalong Formations display a higher TOC content and a better physical property than the Longtan Formation shales and appear to be superior prospective shale gas exploration potential.
Fractal characteristics of low-permeability gas sandstones based on a new model for mercury intrusion porosimetry J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-26 Penghui Su, Zhaohui Xia, Liangchao Qu, Wei Yu, Ping Wang, Dengwei Li, Xiangwen Kong
Studying pore structure characteristics is essential for understanding and evaluating the storage and seepage properties of low-permeability reservoirs. Fractal geometry has been widely employed to study fluid flow in porous media. Although numerous fractal models have been proposed for determining the fractal dimensions from mercury intrusion curves, these models just considered the fractal dimension for pore space and did not consider the fractal characteristic of tortuous pore length, which has been demonstrated to exist in pore structures and been adopted by many investigators. Herein, a new model for calculating the fractal dimensions from mercury intrusion curves is developed by considering both the fractal dimension for pore space and tortuosity. The new model more accurately characterizes the pore geometries of fractal porous media. The sum of the fractal dimensions for pore space and tortuosity is obtained from the slope of log (SHg) vs. log (Pc), where SHg is the mercury saturation and Pc is the capillary pressure. The fractal characteristics and relations between the sum of fractal dimensions and pore structure parameters were examined. The results revealed that the inflection point divides the fractal curves into two segments with different slopes and thus two fractal dimensions were obtained at different pore size ranges. D1 reflects the seepage properties of pore structures, whereas D2 characterizes the storage capacity. D1 exhibited no correlation with D2. In comparison with D1 and D2, Dsw, which was obtained from the saturation-weighted mean of D1 and D2, exhibited better correlation with pore structure parameters than do D1 and D2. Dsw has a good correlation with rapex (pore throat radius corresponding to the apex of the plots of mercury saturation vs. mercury saturation divided by intrusion pressures), demonstrating that the segmentation feature in fractal curves is related to the intrinsic physical pore structure. The increase of the Dsw is accompanied by an increase in the displacement pressure and a decrease in the pore diameter, porosity, and permeability, thereby exhibiting poor physical properties. Dsw was found to be a more appropriate parameter than D1 or D2 for evaluating the complexity and heterogeneity of pore structures.
Evaluation of Productivity Index in Unconventional Reservoir Systems: An Extended Distributed Volumetric Sources Method J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-27 Mohammad Bagher Asadi, Sohrab Zendehboudi
Exploring a Mechanistic Approach for Characterizing Transient and Steady State Foam Flow in Porous Media J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-26 Abdulrauf Rasheed Adebayo, Mazen Y. Kanj
Foam model parameters are often derived from laboratory coreflood data at a steady state foam flow regime, which makes them unsuitable for simulating transient foam flow. Since significant foam trapping occurs during transient flow regime, foam trapping process is inadequately covered in most models. In this study, a coreflooding procedure is presented that allows for estimation of multiple foam model parameters in both transient and steady state foam regimes. Surfactant alternating gas (SAG) method of foam injection was modified such that at the end of each SAG cycle, mobile and trapped foams saturations were measured using a coreflood apparatus equipped with in-situ saturation measuring tool. Multiple SAG cycles were then conducted to generate a dataset as a function of water saturation and capillary pressure. The dataset includes trapped and mobile foam saturation, gas mobility reduction factor, flow rate of mobile foam, limiting capillary pressure, critical water saturation below which foam ruptures, and minimum pressure drop to propagate foam across a porous media, all in a single coreflood experiment. This dataset allowed both capillary pressure and initial-residual gas saturation curves to be generated for foam flow in a representative rock sample. Such curves, which are generated for the first time for foam transport, allow the physics of foam flow in the transient and steady state flow to be captured. The behavior of the curves is also dependent on the properties of the foam and porous medium. The possible application of such curves for modelling and planning CO2 sequestration is also discussed. The method is promising for upscaling to field scale in the sense that the test may be conducted in an actual well in the field. More insight on foam transport in porous media as revealed by this method are discussed in details.
Dilatancy and tensile criteria for salt cavern design in the context of cyclic loading for energy storage J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-26 P. Labaune, A. Rouabhi
Sedimentology and Lithofacies of lacustrine shale: A Case Study from the Dongpu Sag, Bohai Bay Basin, Eastern China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-25 Chuanyan Huang, Jinchuan Zhang, Wang Hua, Jiaheng Yue, Yongchao Lu
This paper analyzes the sedimentology and lithofacies of the lacustrine shale from the third member of the Eocene Shahejie Formation (Es3) in the Dongpu sag, Bohai bay basin, eastern China. The results show that lacustrine shale is heterogeneous in its sedimentary structure, lithology, mineralogy, lithofacies, and oil content. From the margin of the lake to its center, the depositional environment progresses from delta front to prodelta to deep water lake, and the primary sedimentary lithologies changes from interbedded mudstone and sandstone to mudstone with siltstone to mudstone with evaporite and carbonate rocks. The major deep water deposits are laminated shales. From the lake margin to the center, felsic mineral content decreases gradually, and clay mineral and pyrite content increases gradually. Felsic mineral content is the highest in the delta front shale, and clay mineral and pyrite content is highest in the deep water lake. Shale lithofacies also change with the depositional environment. The lithofacies of the delta front shale are primarily felsic-rich lithofacies: clay-rich carbonate-poor felsic shale (S-4) and a clay-rich, carbonate-poor felsic-rich mixed shale (MS-2). The lithofacies of the prodelta shale are primarily a carbonate-poor felsic-rich muddy shale (M-2), S-4, and MS-2. The lithofacies of deep water lake shales are primarily clay mineral-rich lithofacies: M-2, MS-2, and the clay-rich, carbonate-rich, felsic-rich mixed shale (MS-3). The TOC and the types of organic matter also change with the depositional environment in the Dongpu sag. The results of this study show the sedimentary structures, lithology, mineral content, lithofacies, and spatial distribution of the lacustrine shale was not only controlled by the macro depositional environment and the local depositional environment, but also controlled by the source and transport (or the sediment transport path), water depth, and accommodation space.
Hydraulic Fracturing for Improved Nutrient Delivery in Microbially-Enhanced Coalbed-Methane (MECBM) Production J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-24 Sheng Zhi, Derek Elsworth, Jiehao Wang, Quan Gan, Shimin Liu
Microbially enhanced coalbed methane (MECBM) recovery is a novel method to increase gas production by injecting nutrients, either with/without microorganisms, in depleted CBM wells. However, to be effective, methanogens require that the nutrient must be delivered efficiently by aqueous solution to a maximally large reservoir volume for microbial colonization. This study seeks to improve understanding of solute transport and microbial gas generation in naturally fractured reservoirs that are both pristine and hydraulically fractured. We complete a field-scale numerical simulation using an equivalent multi-continuum method to define the effectiveness of nutrient delivery. The complex pre-existing fracture pattern in the coalbed is represented by an overprinted discrete fracture network (DFN) to capture the natural heterogeneity and anisotropy of fracture permeability. A simplified PKN model is adopted to simulate hydraulic fracture propagation based on linear elastic fracture mechanics (LEFM). The hydraulically stimulated case is compared to the untreated control case, both without and with a network of natural fractures. Saturated cleat area, cumulative injection volume and prediction of methane yields are systematically modeled and analyzed for all three cases. We show that hydraulically stimulated fracture pathways, especially when connecting with a natural fracture network, optimally deliver nutrient remotely from the injection well, thereby increasing nutrient delivery and improving methane production and potential recovery. However, large magnitudes of proppant embedment and related permeability loss in the hydraulic fractures may reduce MECBM recovery. In the optimal production scenario, the methane production rate may reach 31 ft3/ton, an approximately 5-fold increase over that from the pristine unstimulated case.
Multi-component fractal representation of multi-scale structure of natural gas hydrate-bearing sediments J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-24 Haitao Zhang, Xianqi Luo, Jinfeng Bi, Gaofeng He, Zhuomin Li
Fractal is a set owning an infinitely fine structure in a self-similar or self-affine way covering all scales, and is widely used to model the structure of porous media. Hydrate-bearing sediments belong to porous media, so this paper attempts to construct a structure model of hydrate-bearing sediments with the three-component fractal extended from the two-component fractal. The three-component fractal is capable to display structural details at arbitrarily small scale. Additionally, in the three-component fractal, any parameter defined as the ratio (such as porosity and hydrate saturation) of two different volumes approaches a determined value when considering the infinitesimal scale. The interface between hydrate elements and pore elements is suggested to be a potential way to classify the hydrate-bearing sediments. Using the proposed three-component fractal model to calculate the interface between one arbitrary hydrate particle and surrounding pores, we obtain the theoretical solutions of the amount of substance, the dissociation rate and maximal dissociation time of one arbitrary hydrate element in sediments. It is found that the effective reacting surface of one hydrate element in sediments could be equal to even greater than that of the pure hydrate element in the late period of hydrate dissociation, during which the amount of substance of one hydrate element in sediments is still greater though. Finally, we further extend the three-component fractal to any-component fractal, and show how to model more complex porous media by using a suitable generator.
Experimental investigation on the impact of connate water salinity on dispersion coefficient in consolidated rocks cores during Enhanced Gas Recovery by CO2 injection J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-22 Muhammad Kabir Abba, Athari Al-Othaibi, Abubakar Jibrin Abbas, Ghasem Ghavami Nasr, Abdulkadir Mukhtar
Connate water salinity is a vital property of the reservoir and its influence on the displacement efficiency cannot be overemphasised. Despite the numerous analytical literatures on the dispersion behaviour of CO2 in CH4 at different parametric conditions, studies have so far been limited to systematic effects of the process while parameters such as connate water salinity of the reservoir has not been given much attention and this could redefine the CO2-CH4 interactions in the reservoir. This study aims to experimentally determine the effect of connate water salinity on the dispersion coefficient in consolidated porous media under reservoir conditions. A laboratory core flooding experiment depicting the detailed process of the CO2-CH4 displacement using Grey Berea sandstone core sample at a temperature of 50 °C and at a pressure of 1300 psig was carried out to determine the optimum injection rate, from 0.2 to 0.5 ml/min, for the experimentation based on dispersion coefficients and methane recovery in the horizontal orientation. This was established to be 0.3 ml/min. At the same conditions, the effects of connate water saturation of 10% and a salinity of 0 (distilled water), 5, and 10% wt. with a CO2 injection rate of 0.3 ml/min on the dispersion coefficients was investigated. The results from the core flooding process indicated that the dispersion coefficient decreases with increasing salinity, hence the higher the density of the immobile phase (connate water) the lower the dispersion of CO2 into CH4. This is a significant finding given that the inclusion of the connate water and its salinity have an effect on the mixing of the gases in the core sample and should be given importance and included during simulation studies for field scale applications of Enhanced Gas Recovery (EGR). This is the first experimental investigation into the relationship between the connate water salinity and the dispersion coefficient in consolidated porous media.
Whole wellbore liquid loading recognition model for gas wells J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-22 Zhennan Zhang, Baojiang Sun, Zhiyuan Wang, Yonghai Gao, Shujie Liu, Zhiming Yin
Liquid loading is a serious issue in the production of gas wells. In order to recognize liquid loading, the flow regime and the transition criteria of the gas-liquid two-phase in the wellbore were obtained by theoretical analysis. The prediction correlation for the size of the entrained droplet was given for every flow pattern. Based on the force balance condition of the largest droplet in the gas core, the dimensionless critical gas mass flow rate was defined to recognize liquid loading along the whole wellbore. The influence of different factors on liquid loading was analyzed by an example. The results show that there are three kinds of flow regime in the wellbore, which are co-current annular flow with disturbance wave torn off, co-current annular flow with bag breakup and churn-annular flow with wave under-cut. The maximum size of the droplet in the gas core depends on the droplet breakup process under co-current annular flow and droplet entrainment process under churn-annular flow. The dimensionless critical gas mass flow rate decreases with the increase of gas flow rate and the decrease of tube diameter, which reduces the possibility of liquid loading. Liquid loading can be avoided by the decrease of surface tension. The viscosities of the gas and liquid phases have slight influence on the dimensionless critical gas mass flow rate.
Enhancing coal seam gas using liquid CO2 phase-transition blasting with cross-measure borehole J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-23 Guozhong Hu, Wenrui He, Miao Sun
The efficiency of gas drainage in deep coal seams is generally poor because of their typically low-gas permeability and high-geostress characteristics. Therefore, we conducted a test study on the permeability enhancement of cross-measure boreholes using liquid CO2 phase-transition blasting (LCPTB) to identify an effective method for enhancing coalbed methane reservoir. Through a numerical simulation of LCPTB, the fracture propagation in the coal seam after blasting was analysed. Subsequently, a field test arrangement for boreholes of LCPTB was designed, and the range of enhanced permeability after blasting as well as the efficiency of gas drainage were investigated. The results indicate a significant increase in the permeability of the coal seam and the efficiency of gas drainage following LCPTB. The amount of gas extracted from the blast holes was 1.8–8 times greater than that extracted from boreholes without LCPTB. The practical spacing between boreholes was deemed to be 2.5–3 m. In addition, with decreasing measuring distance from the blast hole, the efficiency of LCPTB was improved by increasing the permeability of the coal mass surrounding the observation hole. The observation holes arranged around the blasting holes could increase the efficiency of gas drainage. In summary, this technology uses the energy released by LCPTB to increase the permeability of the coal surrounding the blast hole, and to displace methane in the coal seam, thereby improving the efficiency of gas drainage and providing economic and environmental benefits.
Quantifying the induced fracture slip and casing deformation in hydraulically fracturing shale gas wells J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-18 Fei Yin, Yang Xiao, Lihong Han, Xingru Wu
Hydraulic fracturing induces the shear failure of natural fracture which contributes to complex fracture network. The magnitude of fracture slip potentially causes some undesirable consequences including wellbore instability, casing deformation and fault reactivation. Therefore, it is important to predict the fracture slip induced by hydraulic fracturing for a safe and efficient stimulation. In this paper, we used a 2D hydro-mechanical coupled model to predict the injection-induced slip. The hydraulic and natural fractures are embedded in formations with cohesive zone model. The fracture propagation, rock deformation and wellbore slip displacement are captured in the 2D model. The wellbore slip displacement is input into a small-scale 3D mechanical model of casing in slip rock to simulate casing behavior. Casing curvature is also introduced to assess casing integrity. Results indicate that the rock deforms asymmetrically with respect to the wellbore after the shear failure of natural fracture. Particularly, there is a shear slip along the natural fracture. The simulation result shows that the casing failure mechanism is shear deformation induced by the fracture slip during hydraulic fracturing. The curvature of deformed casing is larger than that of directional well trajectory. The predicted results are validated by the logging and operation data from the field. This work provides a novel quantitative method for predicting fracture slip and evaluating well integrity during hydraulic fracturing.
A unit cell model for gas-liquid pseudo-slug flow in pipes J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-17 Auzan Soedarmo, Yilin Fan, Eduardo Pereyra, Cem Sarica
Pseudo-slug flow is a subset of intermittent flow which has not been properly understood and modeled. However, this flow pattern is widely encountered in oil and gas production and transportation, driving the needs for proper modeling efforts. A new pseudo-slug unit cell model is proposed in this paper. The proposed model modifies the existing slug unit cell model by accounting the continuous gas passage, slippage, and interfacial momentum exchange in the pseudo-slug body. Pseudo-slug characteristics (length, velocity, and body holdup) reported in literature are incorporated through ad-hoc closure relationships. These closures remain to be improved in the future. Overall, the proposed model produces more accurate pressure gradient and film holdup (HLF) predictions compared to two state-of-the-art models which generally treat pseudo-slug as slug flow (TUFFP Unified model and OLGAS 7.3.5®).
Stochastic convergence in US disaggregated gas consumption at the sector level J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-11 Mehdi Abid, Mohsen Alimi
In order to assess how seasonality affects disparities in natural gas consumption among sectors, this paper aims to study the pattern of convergence in natural gas consumption in a sample of 11 sectors in the United States between January 1973 and February 2017. In addition to the full sample, the existence of convergence is also examined in five subsets of sectors: residential, commercial, industrial, transport and electric power. By using various types of unit root tests, empirical results provide significant support for the convergence of disaggregated natural gas consumption across sectors in the United States. Another important finding of this paper is that natural gas consumption, despite being convergent, is very persistent.
Effect of coalification jumps on petrophysical properties of various metamorphic coals from different coalfields in China J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-11 Sandong Zhou, Dameng Liu, Zuleima T. Karpyn, Yidong Cai, Yanbin Yao
The effect of coalification jumps on petrophysical properties, and the evolution of porosity and permeability of metamorphic coals are poorly understood, which significantly influences coalbed methane extraction. We estimated pore throat diameter, specific surface area, connectivity, moveable fluid space, heterogeneity, porosity and permeability in a series of 41 coal samples (maximum reflectance of vitrinite in 0.34-4.24%) over six coalification jumps, by processing low temperature nitrogen adsorption, mercury intrusion porosimetry and nuclear magnetic resonance (NMR) measurements. Each coalification jump generally leads to abrupt change of petrophysical properties from dehydration to graphitization. Connectivity parameters (efficiency mercury withdrawal and the ratio of movable fluid to bounded fluid) and fractal dimensions (DNA1, DNA2, DMIP, DNMRS and DNMRM) present binomial function with vitrinite reflectance. Generations of thermogenic gas and fractures growth are attributed to increasing pore-fracture connectivity in bituminization and debituminization. Fractures begin healing and compaction, as well as reduced connectivity, at the fourth jump in graphitization. Heterogeneous pore-structures (high DMIP and DNMRM) usually have low connectivity. Moveable fluid space and its porosity from NMR are negatively correlated with the increase in coal rank. The evolution and origin of porosity and permeability (<1 mD) during coalification is proposed. Coal permeability (>1 mD) has no relation with coal rank and is related to fracture characteristics. Unlike the origin of porosity, which intrinsically inherits from progressive coalification, the origin of permeability is attributed to both progressive coalification and tectonic stresses. This study reveals the complex pore-fracture structures variation and the effect of stages in coal maturation on petrophysical properties of coalbed methane reservoirs.
Intrinsic and apparent gas permeability of heterogeneous and anisotropic ultra-tight porous media J. Nat. Gas Sci. Eng. (IF 2.803) Pub Date : 2018-10-12 Lefki Germanou, Minh Tuan Ho, Yonghao Zhang, Lei Wu
Some contents have been Reproduced by permission of The Royal Society of Chemistry.
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