Internal microbiologically influenced corrosion (IMIC) is recognized as one of the primary reasons causing failures of natural gas pipelines. In this work, a critical review was performed to analyze the uniqueness of pipeline IMIC, including the corrosive environment, biofilm formation, mechanism, novel research methods, and scientific gaps to be filled in the further research activities. The IMIC of gas pipelines occurs in corrosive environments where a thin layer of water condensate presents on the internal surface of pipe wall. Corrosion occurs upon dissolution of gases such as CO2 and H2S. A biofilm generates to isolate the environment underneath the film from fluid flow to support microorganism population. Due to a limited volume of aqueous solution, the biofilm is mixed with corrosion products to affect the further IMIC. Challenges exist to measure and characterize the bacterial activity under the biofilm, and the localized nature of IMIC. The electron transfer process during IMIC has remained unclear, lacking convincing evidence to support proposed mechanisms. Novel research techniques are suggested investigating IMIC to develop mechanistic understanding for effective management of the problem.
Predicting gas saturation is critical for identifying gas zones in tight sandstones, but poroelastic behaviours of tight sandstones with low porosity and permeability lead to complex relationships between gas saturation and elastic attributes. Thus, gas prediction based on conventional seismic methods tends to be a challenging task. However, the frequency-dependence of elastic properties associated with fluid flow in tight sandstones allows the utilisation of seismic dispersion attributes for gas prediction. This study proposes a new inversion method to compute the bulk-modulus-related dispersion attribute DK for improved gas prediction by using the sensitivity of the bulk modulus to fluids in tight sandstones. Rock physical modelling and synthetic tests indicate that the proposed DK exhibits increased sensitivity to gas saturation compared to the conventional P-wave velocity dispersion attribute DP and the commonly utilised VP/VS ratio. Real data applications demonstrate that DK represents a preferable gas identification factor for the tight sandstone gas reservoir in the Ordos Basin. Results indicate that DK shows improved apparent anomalies to gas zones and better correspondence with the actual production status of drilled wells than DP and the VP/VS ratio. A combined factor, CF, is further proposed to improve the accuracy and robustness of gas prediction by considering the sensitivity of DK while simultaneously incorporating the VP/VS ratio as an essential constraint. A close correlation between the proposed CF and gas saturation measured in boreholes justifies the applicability of the CF for the reliable identification of gas-bearing tight sandstones. Gas zones identified by the CF provide essential information for gas exploration in the region of interest. The method proposed in this study extends the existing seismic dispersion inversion for improved gas prediction. The methodology to obtain the gas identification factor can inspire the development of other practical fluid indicators.
The phase behavior of confined fluid in nanopores of shale reservoirs deviates significantly from that of bulk fluid. Confined fluid refers to fluid whose thermal motion is affected by nanopores, since nanopores have a comparative size to the mean free path of fluid molecules. To describe deviated phase behavior in nanopores, Travalloni et al. proposed PR-C EOS by introducing empirical modifications to the canonical partition function. The modifications consider the two main mechanisms that cause nanopore phase behavior to deviate: the finite volume effect and the fluid-pore wall interaction effect. However, in addition to its weakness on a theoretical basis, PR-C EOS possesses imperfections when applied to predict nanopore phase behaviors. In this work, we propose a new EOS derived from statistical thermodynamics for slit-like nanopores, named PR-X EOS. The PR-X EOS has an extra term to represent the fluid-pore wall interaction effect and a modification to the cubic EOS parameter to represent the finite volume effect. PR-C EOS and PR-X EOS are non-cubic, and each has some new parameters. The new parameters can be determined by fitting adsorption isotherms. When pore size approaches infinity, PR-C EOS and PR-X EOS both degenerate into classic PR EOS. To apply these two non-cubic EOS in reservoir simulators, we improve gas-oil phase equilibrium calculation methods. The improved simulator can model chemical potential equilibrium between the nanopore grid and the bulk grid, with chemical potentials of the two grids calculated using the modified EOS and conventional EOS, respectively, so that bulk grid pressure can be obtained. As a consequence, we can plot the adsorption isotherm or phase diagram under bulk pressure, which is practically measurable pressure. Therefore, we can validate the modified EOS with experimental or molecular simulation data. Validations demonstrate that PR-X EOS can match type I and type IV adsorption isotherms; whereas, PR-C EOS fails to match the type IV adsorption isotherm. Moreover, the phase diagrams calculated using PR-X EOS consistently shrink as pore size decreases, while PR-C EOS cannot guarantee this consistency. These two facts show that PR-X EOS is superior to PR-C EOS in modeling phase behavior of confined hydrocarbons. Furthermore, shale oil reservoir simulation shows that considering the confinement effect would lead to lower GOR.
When pipeline steels are exposed to hydrogen-rich environments during service, this can lead to a degradation in mechanical properties and premature failure. These steels are often susceptible to hydrogen embrittlement and hydrogen-induced cracking (HIC) and contain very sensitive microstructures for HIC formation. This work aims to find a suitable hydrogenation methodology that allows to charge pipeline steel specimens without inducing any hydrogen related damage during the charging process. Therefore, different electrochemical hydrogen charging methodologies are evaluated. The susceptibility to HIC and blisters of two pipeline steels (API 5L grades X70 and X56), is first investigated in a sulfuric acid electrolyte. Both grades are prone to HIC in the mid-thickness section of the pipeline wall. For X56, significant blistering occurs as well, and hydrogen-induced damage could be linked to elongated MnS inclusions. For the X70 steel, hard bands are found to be vulnerable to HIC. The electrochemical charging conditions are modified for the X56 steel, where the extent of the damage is greatest due to its prone microstructure, as revealed by scanning electron microscopy. Lowering the sulfuric acid concentration and applied charging current density does lead to some reduction of blistering. However, changing to a different, sodium hydroxide-based electrolyte is more effective in mitigating the extent of the hydrogen-induced damage and the time at which it appears.
Wellbore instability in fractured formation is a major challenge in drilling engineering, especially in the oil and gas energy sector. This study aims to analyze wellbore stability in fractured formation using discrete element method. A novel fractures modeling method by using formation microscanner images (FMI) and image processing was proposed. Three wellbore models with different fracture structures, and a no fracture model are developed to simulate the wellbore drilled in X well, Tarim Basin, China. Different drilling fluid densities are applied to the four models. Failures and deformation of wellbore models are investigated. Large amounts of displacement and yielded zones around the wellbore were observed in the high and low dip intersecting fractures models. And fluid density has few effects on the wellbore stability. High dip fracture is considered a major factor in wellbore instability. The high drilling fluid density performed better in the low dip fracture model, and the low drilling fluid density performed better in the vertical fracture model and intact model. The proposed modeling method and findings have important implications for understanding the wellbore instability in fractured formation.
This paper presents a review of the current state of scientific understanding of the corrosion phenomenon known as Hydrogen-Induced Cracking (HIC). HIC is defined as cracking in low-to medium-strength steels where cracking is driven by the precipitation of gaseous hydrogen molecules within the crack, which typically occurs in sour (H2S containing) environments. It is a complicated phenomenon, encompassing a surface reaction for hydrogen uptake, hydrogen diffusion to vulnerable microstructural sites, hydrogen gas precipitation creating an incipient crack, and crack growth driven by hydrogen gas pressure within the crack. While HIC has been studied for decades, understanding of the critical factors controlling each step of the phenomenon has been elusive. The maturation of many characterization techniques gives hope that a full mechanistic understanding may occur in the near future.
In this study, frontal chromatography experiments have been conducted with hydrocarbon gases (methane and ethane) on selected stationary phases (quartz, 3 angstrom, 5 angstrom and 13X molecular sieves, activated carbon, coal and shale) to study compositional and carbon isotope fractionation during adsorption process. The results show that the diffusion process cannot leads to obvious isotopic fractionation larger than similar to 1.5 per mil in a relatively short distance. However, carbon isotope fractionation varies in different adsorption matrix. Gas molecules transporting in a relatively short distance can cause the isotopically light molecules weakly enriched in the front part of the alkane gases flows. The pore size distribution acts as the leading factor influencing the isotopic fractionation during hydrocarbon gases adsorption. In adsorption matrix with relatively low pore radius (i.e., activated carbon, 5 A molecular sieve and coal), the isotopically light molecules can occupy the adsorption site preferentially and almost cannot be replaced due to the strong adsorption force. Hence, isotopically heavy molecules flow out of the system preferentially. To contrast, in adsorption matrix with relatively high pore radius (i.e., 13X molecular sieve and shale), the isotopically light molecules can occupy the adsorption site and desorb preferentially. Hence, isotopically light molecules flow out of the system preferentially after repeated adsorption and desorption. In addition, physical selectivity on isotopologues of gaseous alkanes by pore network also can occur in natural shale gas system. The Niutitang shale mainly is contributed by micropore. Whereas, Wufeng-Longmaxi shale mainly is contributed by mesopore. In general, initial adsorbed gases (residual gases) in natural shale samples from Niutitang shale were of more negative isotopic compositon in CH4 and C2H6 compared to Wufeng-Longmaxi shale.
The recent introduction of infrared spectroscopy gas logging technology is of great significance for the timely discovery of oil and gas, the prediction of well kicks, the prevention of blowout and gas invasion, and the comprehensive evaluation of reservoirs. However, the accuracy and stability of the current quantitative analysis methods for gas logging measurement data are limited by the severe overlap of infrared absorption spectra and the difficulty of sample preparation. In this paper, a novel hybrid method based on particle swarm optimization split peak fitting and a support vector machine (PSS) is presented to address this issue. The method uses a single peak that satisfies a specific absorption line to fit the mixed spectrum and classifies and identifies the parameters of a fitted single peak to complete the "mathematical separation"of the overlapping spectrum. The IR spectral data of 761 samples for methane, ethane, propane, n-butane, iso-butene, n-pentane, iso-pentane and carbon dioxide were collected for quantitative analysis experiments. Repeated comparison experiments of different feature extraction methods under the same partial least squares (PLS) regression method show that the PSS model established with fewer samples still has better analytical accuracy and stronger robustness. At the same time, PSS can significantly improve the model accuracy under different regression methods to a similar level, reducing the dependence on regression methods. PSS combined with PLS can simultaneously measure the contents of eight components in a multicomponent mixture, and the predicted average root mean square error is 0.7242% for 60 mixed experimental gas samples and 0.2534% for 3 industrial standard gas samples. The proposed method has a high practical application value for popularizing IR spectroscopy gas logging technology and provides a new concept for the quantitative detection of substances with high molecular similarity.
Shale gas wells often experience shut-in. However, the positive and negative effects of shut-in are not yet clear. The success or failure of shut-in is focused on the effects of fracturing fluid and its function in the subsurface. The current studies on the hydration of shale and fracturing fluid and the imbibition of residual fracturing fluids have ignored the fact that hydration and imbibition of fracturing fluids can occur simultaneously and affect each other. With full consideration of the interaction between the spontaneous imbibition and hydration of fracturing fluid, this paper innovatively reveals the fracture initiation through the synergy of spontaneous imbibition and hydration of residual fracturing fluids in shale gas reservoirs and puts forward suggestions for improving the recovery of shale gas. The results show that the imbibition of shale can weaken the mechanical strength of shale and produce micro-fractures and defects in shale. The energy required to destroy the micro-fractures is reduced, which will promote the initiation and propagation of micro-fractures, change the spontaneous imbibition path, expand the volume of spontaneous imbibition, and carry out continuous micro-stimulation of shale gas reservoir. The fracturing fluid can dissolve soluble salts filled in the pores and fractures, resulting in more induced fractures along the direction of beddings and natural fractures. The induced fracture reduces the water saturation of the hydraulic fractures and natural fractures. The fluid in pores can disperse under the action of capillary force, which can further reduce the water saturation of the imbibition intrusion zone, thus greatly restoring the permeability of the shale gas reservoir.
Gas drainage using underground boreholes is an important method for the prevention of coal gas mine accidents. To study the influence of the increase in the number of boreholes on the gas drainage effect using a self developed device for gas drainage, pressure sensors and branch boreholes were installed in a coal body. Four groups of physical simulation experiments of gas drainage were conducted. The results revealed that with an increase in the number of boreholes, the attenuation rate of the gas pressure is accelerated; the decrease in the gas pressure accelerates in the form of a natural logarithmic function. The effective drainage area, with characteristics of dynamic expansion and variations, has an approximately circular expansion with the borehole as the center. It gradually increases with the advancement of drainage. The relationship between the effective drainage area and the extraction time is in the form of a power function. With an increase in the number of boreholes, the effective drainage area increases more rapidly, and the regional outburst elimination occurs earlier. The effective stress and matrix shrinkage effect exhibit a coupled influence on the permeability, which causes the permeability evolution to exhibit periodic variations. At the early stage of drainage, the effective stress plays a major role, which reduces the permeability. At the middle and late stages of drainage, the matrix shrinkage effect plays a major role, which increases the permeability. With an increase in the number of bore holes, the attenuation rate and recovery amplitude of the permeability increase.
The surge avoidance control plays a pivotal role in a centrifugal compression process to maintain safety and high efficiency. In the literature, MPC-like schemes have shown promise for use in such tasks given that they can systematically deal with several process constraints. However, to obtain a good performance in the compression process with a significant deviation of gas ideality, the model used in MPC formulations has to be able to predict the process behavior correctly. This paper proposes surge avoidance feasible optimization-based MPC schemes for non-ideally modeled natural gas compression systems. Its pivotal contributions are: (i) extension of the isothermal and ideal gas thermodynamic behaviors commonly adopted in models of surge prevention MPC schemes to a non-isothermal flow and non-ideally behaved gas-like more realistic compression system; (ii) formulation of a proposed nonlinear model-based MPC control law with surge protection being managed by slacked nonlinear constraints; (iii) synthesis of an adaptive infinite horizon MPC-based surge avoidance scheme that relies upon the successive linearization of the proposed rigorous model for the compression system. From simulations carried out with a plant-model mismatch oriented by distinct equations of state, results obtained from the proposed rigorous model-based surge avoidance NMPC strategy are favorably compared to those obtained with the simplified model widely used in the literature. Finally, the proposed adaptive MPC-based surge prevention scheme showed convergence towards the corresponding NMPC with a drastically reduced computational cost.
Combined perforation and well test system is commonly used in oil and gas fields, especially in reservoirs with low energy and transmissibility. For the conventional inversion method in a combined perforation and well test system, only the pressure data are used to perform the type curve matching, with the variation in temperature being neglected. This may complicate the matching procedure and result in errors in the inversion results. Thus, we proposed a new inversion method in this study, where the gas volume and flow rate terms substituted the pressure and pressure derivative terms to perform type curve matching. This was because the variation in gas volume coupled the variations in pressure and temperature. To make the type curve matching feasible, on the one hand, we need the type curves that depict dimensionless gas volume and flow rate; on the other hand, the field data of pressure and temperature should also be transformed into gas volume and flow rate data, which are the core contents of this paper. A corresponding mathematical model is established and the analytical solutions of gas volume and flow rate are derived with the Laplace transformation. Based on the solutions, the flow regimes analysis and sensitivity analysis on controlling parameters are conducted. Next, a workflow that can convert the pressure and temperature data into gas volume and flow rate data is proposed. Last, the application on a well from Puguang gas field is presented to show the feasibility of our method. Results show that our method successfully interpret the field data comparing to the conventional method that only uses the pressure data. Moreover, comparisons between the results of our method and other field data calibrate the reliability and accuracy of our method.
With the development of exploration and exploitation technologies, deep shale gas systems are gradually becoming an important target for the future petroleum industry. However, there is still a lack of systematic geological studies for deep shale gas systems, which restricts further exploration. In this paper, the deeply buried shales (more than 4000 m in depth) of the first member of Silurian Longmaxi (S(1)l(1)) at the southeastern margin of the Sichuan Basin are selected as the research object, and thin sections, scanning electron microscope (SEM) observations, total organic carbon (TOC) testing, nitrogen adsorption (NA), and major and trace element analyses are used to systemically identify the different lithofacies and delineate geological and geochemical features. Moreover, we reconstruct the paleoenvironment, summarize the controlling factors and mechanisms of organic matter accumulation and pore formation, and finally reveal the favorable exploration lithofacies. Our results show that there are four lithofacies that can be identified in deep S1l1 shale, namely, laminated organic-rich siliceous shale (S), laminated organic-rich mixed shale (RM), banded organic-lean mixed shale (LM), and banded organic-lean argillaceous shale (CM). Organic matter-hosted pores are the primary type in their pore system. The S and RM shales were mainly deposited under dysoxic to anoxic conditions with moderate watermass restriction, low terrestrial detrital influx, and high paleoproductivity, and the silica mainly originated from the diagenesis process (biogenic quartz); the LM and CM shales were sedimented under oxic conditions with high terrestrial detrital influx and low paleoproductivity, and the silica mainly originated from terrestrial detrital influx. Redox conditions, paleoproductivity, and terrestrial detrital influx together controlled the organic matter enrichment in the deep S(1)l(1) shale, and the TOC content further influences the physical properties of the shale, thus determining the exploration potential of different lithofacies. Moreover, the significant impacts of lithofacies on the geological and geochemical features of the deep shale gas system are demonstrated. Compared with the middle-shallow shale gas system in the study area, due to less tectonically uplifted and tectonically active shale, the deep shale has more extraordinary preservation conditions, overpressure inheritance development, and higher gas amounts. The S and RM in S(l)l(1) in the study area have better resource potential and should be given more attention in the future.
Quantitatively understanding thermodynamic properties of confined fluids in nanoporous media is of great significance to the development of shale gas. Due to the complex intermolecular forces in the nanopore, it is difficult to accurately predict the thermodynamic properties of fluid molecules. Focusing on the fluid-fluid and fluid-wall molecules interactions in shale reservoir system, the thermodynamic model of fluid molecules in pores is constructed, and a modified equation of state is proposed by systematically coupling the original Soave-Redlich-Kwong equation of state with Tjatjopoulos-Feke-Mann potential model in this work. The advanced EoS could facilitate a good prediction on thermodynamic properties of confined fluids without any introduction of new empirical parameters. For verification, fluid density as the important thermodynamic property was targeted and pure methane at a wide pressure range was employed to represent the fluid. The results indicated that the calculated densities accord well with the reported ones in the free gas zone. The deviation of discrete density ranges from 0.239% to 1.7329%. The fluid density distribution in the nanopores is found to be nonuniform, exhibiting a greater value near the wall than that in the pore center, which would be ascribed to the more dominant fluid wall molecule interaction. For example, the local density is 16.90 kg/m3 in the pore center, while it increases to 26.67 kg/m3 in the region which is 0.76 nm to the wall at 350 K, 3 MPa, and 5 nm (radius). Moreover, effects of other critical factors on fluid density distribution were also conducted, and it was indicated that higher pressure, lower temperature, and smaller pore size could be favorable for the occurrence of confined fluid. In general, the novel EoS could provide a quantitative and simple method in predicting the thermodynamic properties of confined fluids relating to applications of shale gas storage and exploitation.
In quest of unconventional energy as shale gas, lower Gondwana shale-heterolith litho-assemblages of Mohuda sub-basin of Jharia Coalfield have been explored to envisage their potentiality for shale gas generation. A comprehensive approach has undertaken through measurement of in-situ gas content, petrography, rock-eval pyrolysis, proximate analysis, TOC, adsorption isotherm, SEM-EDX and XRD of selected drill core samples to establish potential shale horizons in Barren Measure and Barakar Formations. The in-situ gas content varies from 0.15 to 3.69 m 3/t with increasing depth. High palaeo-geothermal gradient in order of 5.57-6.19 degrees C/100 m is established where emplacement of intrusive played a dominant role. Interrelation of palaeodepth and vitrinite reflectance points to erosion of 2500 m strata in Mohuda sub-basin. Average TOC content of 9 to 17 wt% indicates excellent organic richness of source rock, while other parameters like S1, S2 and PY derived from rockeval pyrolysis indicate fair to very good/excellent source condition for hydrocarbon generation. HI, OI, S2, TOC, VRo and Tmax values and their inter-relationships reveal Type III and Type IV kerogens coming under gas window zone of mature to post mature stage. Increase in volatile matter and fixed carbon and decrease in moisture content with depth suggest enhanced gas generation and retention capacity. Quartz dominated mineralogy in shale beds account for suitable hydrofracturing process. GIP of about 7.5 BCM of gas has been assessed and categorized depth wise and formation-wise for Raniganj, Barren Measure and Barakar formations. Experimentally calibrated adsorption isotherm data reveals favourable parameters like gas saturation level (GSL), reservoir pressure to be dropped for initiation of production (Delta P), critical desorption pressure for gas yield (PCR) and abandonment pressure (PAB) in respect of potentiality for production with an average gas recovery factor of 94.5% for all three studied shale zones, which strongly recommends the convenient reservoir characteristic for future exploitation.
In many oilfield applications, gas-liquid (GL) flow modeling is required. One of these applications is predicting the uncontrolled hydrocarbon flow through a wellbore after a blowout, referred to as the worst-case discharge rate (WCD rate). It is common to see annular flow patterns in a wellbore during a blowout, especially when the superficial gas velocity (Vsg) is high and the superficial liquid velocity (Vsl) is low to moderate. As a result, accurate predictions of WCD rates require a better understanding of annular flow characteristics. Thus, this study is conducted with an annular flow pattern, maintaining Vsg between 8 and 120 m/s and Vsl between 0.25 and 0.96 m/s. The analysis of the experimental measurements shows the establishment of an annular flow pattern with pressure drop (Delta p) that increases with the in-situ Vsg at a constant Vsl. Moreover, the liquid holdup (HL) reduced sharply with the Vsg at a constant liquid rate. Furthermore, a new mechanistic GL flow model is formulated based on an existing model and correlations. Finally, measurements are compared with the forecasts of the new and existing models and commercial software. It is shown that the new model provides a more precise forecast of Delta p than the existing software and models.
