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A benchtop humidity and temperature chamber was used to assess water vapor sorption in four US shale samples at 90 °C. Water sorption isotherms were measured at relative humidity ranging from 10 to 99% and temperature of 90 °C. Shale fractal properties were then evaluated, and capillary pressure (ranging from 1.70 to 386 MPa) was obtained using Kelvin relationship. The results show that Mancos shale, from the US, adsorbed more absorbed water due to its high clay concentration and low TOC. However, Wolfcamp shale, from the US, has the lowest TOC and clay concentration, adsorbing the lowest amount of water. There is little hysteresis between adsorption and desorption isotherms explaining water retention phenomenon in some shales. The obtained fractal dimension values ranged between 2.45 and 2.76 and average of 2.56 indicating irregular pore surface and complex pore structure. All shale sample's capillary curves were fitted to Brooks & Corey and van Genuchten models with nonlinear regression. The fitting coefficient, R2, which represents the proportion of variance for Brooks & Corey fits ranged from 0.90 to 0.97 for imbibition and 0.85 to 0.98 for drainage, while R2 for the van Genuchten model ranged from 0.94 to 0.99 for both imbibition and drainage. Thus, the proposed method can be used to measure capillary pressure–saturation relationships in gas shales.

Water-based fracturing fluids without an inhibitor promote clay swelling, which eventually creates wellbore instability. Several ionic liquids (ILs) have been studied as swelling inhibitors in recent years. The cations of the ILs are crucial to the inhibitory mechanisms that take place during hydraulic fracturing. Individual studies were carried out on several ILs with various cations, with the most frequently found being ammonium and imidazolium cations. As a result, the goal of this study is to compare these two cations to find an effective swelling inhibitor. A comparison and evaluation of the clay swelling inhibitory properties of tetramethylammonium chloride (TMACl) and 1-ethyl-3-methylimidazolium chloride (EMIMCl) were conducted in this work. Their results were also compared to a conventional inhibitor, potassium chloride (KCl), to see which performed better. The linear swelling test and the rheology test were used to determine the inhibitory performance of these compounds. Zeta potential measurements, Fourier-transform infrared spectroscopy, and contact angle measurements were carried out to experimentally explain the inhibitory mechanisms. In addition, the COSMO-RS simulation was conducted to explain the inhibitory processes and provide support for the experimental findings. The findings of the linear swelling test revealed that the swelling was reduced by 23.40% and 15.66%, respectively, after the application of TMACl and EMIMCl. The adsorption of ILs on the negatively charged clay surfaces, neutralizing the charges, as well as the lowering of the surface hydrophilicity, aided in the improvement of the swelling inhibition performance.

This study presents a model application for the evaluation of Effective Stimulated Reservoir Volume (ESRV) in shale gas reservoirs. This current model is faster, cheaper, and readily available for estimating ESRV compared to previously published models. Key controlling parameters for efficient ESRV modeling, including geomechanical parameters and time, are considered for the model development. The model was validated for both single and multi-stage fractured reservoirs. For the single fractured reservoir, an ESRV of 3.07 × 106 ft3 was estimated against 3.99 × 106 ft3 of ESRV-FEM field data. Whereas, 7.00 × 109 ft3 ESRV was estimated from the multi-stage fractured reservoir against 7.90 × 109 ft3 of fractal-based model results. Stress dependence, time dependence, and permeability dependence of shale gas reservoirs are found to be essential parameters for the successful calculation of ESRV in reservoirs. An ESRV determined using this method can obtain the estimated ultimate recovery, propped volume, optimal fracture length, and spacing in fractured shale gas reservoirs.

Polymers play a major role in developing rheology of fracturing fluids for multistage hydraulic fracturing horizontal wells in unconventional reservoirs. Reducing the amount of polymer adsorbed in the shale formation is essential to maintain the polymer efficiency. In this study, the ability of silica nanoparticles to minimize polymer adsorption in Marcellus shale formation at reservoir temperature was investigated. Partially hydrolyzed polyacrylamide polymers of varying molecular weights (1-12 MD), salinities (2500-50,000 ppm), polymer concentrations (100-2000 ppm), and silica nanoparticle concentrations (0.01-0.1 w/w) were used in the static adsorption experiments. Adsorption of the polymer in the Marcellus shale samples was contrasted with and without the silica nanoparticles at a Marcellus formation reservoir temperature of 65 °C, showing a significant polymer adsorption reduction of up to 50%. The adsorption and adsorption reduction were more sensitive to the variation of the polymer concentration than to the variation of the salinity within the tested conditions. The highest adsorptions were reported at the higher molecular weight of 10-12 MD. In addition, silica nanoparticles significantly improved polymer rheology at elevated temperatures. The results indicate that nanoparticles can play a significant role in reducing polymer adsorption in the fracturing fluid and improve its rheological properties and its efficiency, which will reduce the number of issues caused by the polymers in the fracturing fluid and making it more cost effective.

Ionic liquids (ILs) can play a vital role in clay swelling inhibition during hydraulic fracturing. Previous studies highlighted the effect of side-chain length attached to the cationic core and different anions possessing almost the same chemical properties on inhibition performance. However, polyatomic anions have the potential to superiorly inhibit swelling compared to monoatomic anions. In this study, three ILs, namely, 1-butyl-3-methylimidazolium chloride (BMIMCl), 1-butyl-3-methylimidazolium tetrafluoroborate (BMIMBF4), and 1-butyl-3-methylimidazolium hexafluorophosphate (BMIMPF6), were utilized to assess the effects of polyatomic anions on clay swelling inhibition. These performances were compared with the performances of a conventional inhibitor, potassium chloride (KCl). X-ray diffraction (XRD) testing was applied to check the mineral components present in the bentonite clay sample studied in this research. Clay swelling inhibition performance and rheological properties of these ILs were evaluated by the bentonite plate soaking test, linear swelling test, and rheological test. The swelling inhibition mechanisms were investigated through ζ-potential measurement, Fourier transform infrared (FT-IR) spectroscopy, and contact angle measurement. Moreover, COSMO-RS computer simulation was conducted to explain the inhibition mechanisms theoretically. The results demonstrated that BMIMPF6 showed superior inhibition performance and reduced the swelling by 21.55%, while only 9.26% reduction was attained by potassium chloride (KCl). The adsorption ability on the bentonite surface through electrostatic attraction, higher activity coefficient, and less electronegativity of PF6- anion played a vital role in attaining such superior inhibition performance by BMIMPF6.

A substantial amount of water used for fracking shale formations is trapped by capillary and interfacial forces. Such trapped water is detrimental to gas production because of its potential to obstruct gas’s desorption and, subsequently, its flow path. Surfactants are proposed to alleviate the problem; however, further insight is required to understand the underlying mechanism. In this study, a cationic surfactant, namely, cetyltrimethylammonium bromide (CTAB), and a clay-rich Marcellus shale are used to investigate and explain the mechanism. The study encompasses a series of systematic experiments and molecular simulations. First, laboratory measurements of CH₄–brine interfacial tension, CH₄ surface excess, and zeta potential at different CTAB concentrations were conducted. Then, we evaluated CH₄ adsorption in Marcellus shale before and after treatment with CTAB. Second, a molecular dynamics simulation by GROMACS software was used to explain the phenomenon at the molecular level. Experimental results indicated that CTAB reduced the CH₄–brine interfacial tension by up to 80%. The zeta potential data showed that shale’s dominant surface charge was altered from negative to positive after treatment with CTAB. Furthermore, the presence of CTAB has significantly influenced the distribution of CH₄ in the aqueous phase as indicated by the changes in the CH₄ surface excess concentration. Moreover, the adsorbed CH₄ amount decreased with increasing CTAB concentration when the CTAB concentration was kept below the critical micelle concentration (CMC). The reduction in adsorbed CH4 was explained by the molecular dynamics simulation results, which revealed a 62% shrinkage in vertical distances between CH₄ molecules and clays after introducing CTAB. Simulation findings also unfold that CTAB has reduced the density distribution of CH₄ molecules along with clay layers by 64%. One of the more significant result of this study is that surfactants injected at above CMC values can lessen fracking water trapping by reducing CH₄ brine interfacial tension, changing surface charges, and reducing molecular distances between CH₄ and hydrophilic clays.

The presence of swelling clays, namely, montmorillonite and illite-smectite mixed layer clays alike, significantly affects well stimulation processes, such as hydraulic fracturing. In this study, t...

As the conventional prediction methods for production of waterflooding reservoirs have some drawbacks, a production forecasting model based on artificial neural network was proposed, the simulation process by this method was presented, and some examples were illustrated. A workflow that involves a physics-based extraction of features was proposed for fluid production forecasting to improve the prediction effect. The Bayesian regularization algorithm was selected as the training algorithm of the model. This algorithm, although taking longer time, can better generalize oil, gas and water production data sets. The model was evaluated by calculating mean square error and determination coefficient, drawing error distribution histogram and the cross-plot between simulation data and verification data etc. The model structure was trained, validated and tested with 90% of the historical data, and blindly evaluated using the remaining. The predictive model consumes minimal information and computational cost and is capable of predicting fluid production rate with a coefficient of determination of more than 0.9, which has the simulation results consistent with the practical data. Key words: neural networks, machine learning, attribute extraction, Bayesian regularization algorithm, production forecasting, water flooding

With the increasing of water injection activities especially for marginal or stranded fields, the well pair analysis in routine water injection surveillance is crucial to understand the reservoir performance and identify opportunities to improve the ultimate oil recovery. This article aims to propose an alternative technique to evaluate the communication strength between injector – producer well pairs based on statistical and machine learning algorithms. The proposed technique is applied to an offshore water injection field located in the North Sea from open-source data. A novel formulation to quantify the communication strength coefficient for an injector – producer well pair was derived from the Spearman's rank correlation coefficient. The calculation is controlled with injection/production rates pattern for each well pair. Subsequently, multivariate parametric regression is performed to model the communication strength coefficient as a function of injector – producer spacing, injection pattern (dip angle), and reservoir permeability-thickness. Monte Carlo technique is then applied to simulate 100 cases prepared using the uniform probability distribution. Afterward, the communication strength for all the well pairs in the field is classified based on K-means clustering. To identify opportunities to improve the effectiveness of water injection operation, random forest and support vector machine algorithms are used to evaluate the effect of the reservoir and operational parameters on the communication strength of the injector – producer well pair. It is identified that the communication strength for all the well pairs in the field varying from limited, intermediate, and good communication. Good communication strength shows the correlation coefficient of more than 0.50 which indicates there is a good correlation between injection and production rates pattern. It is also observed that reservoir permeability-thickness is the most variable importance that affects the communication strength between injector and producer well pair. It is followed by the injector-producer spacing and reservoir dip angle. The optimum condition has been identified to formulate the screening criteria in order to obtain the good communication strength between injector and producer well pair. This result help in identifying the producer with limited communication strength with the existing injector and low production rate to be converted as the injector well. Unlike reservoir simulation which is a very expensive and time-consuming process, this work provides a quick and inexpensive alternative to evaluate the communication strength of injector-producer well pair from widely available measurements of production and injection rates at existing wells. Application of this novel workflow provides insight for better decision-making and can be a prudent complementary tool to quantify the effectiveness of the water injection operation and identify opportunities.

Shale reservoirs, despite having abundance in hydrocarbon storage, offer significant challenges in terms of understanding the pore-scale and reservoir-scale phenomenon. Typically, hydraulic fracturing treatment is implemented to improve hydrocarbon productivity through the injection of fracturing fluid to induce the breakdown of the formation to create fractures, hence allowing a flow conduit for hydrocarbon to be produced at a higher flow rate of oil and/or gas. In this work, molecular dynamics (MD) simulation using GROMACS were utilized to create a 3D model comprised of methane (CH4), surfactant and graphite. Surfactant, as represented by the cationic cetyl trimethyl ammonium bromide (CTAB) was added along with water to represent water-based visco-elastic surfactant (VES) as an additive to reduce the surface tension of hydrocarbon to shale (represented by graphene). A realistic molecular model was created to examine the interaction of CTAB towards the adsorption pattern of methane onto graphene, in order to reveal the displacement efficiency of methane after wettability modification due to the effect of surfactant on the graphene on a nanoscale. The findings suggest that addition of CTAB as surfactant may enhance the production of methane though the reduction of IFT and adsorption capability of methane to the wall of shale. The result yielded consistent trends, where methane's tendency to stick to the adsorption site (at approximately 1.5 nm from the center of the system) was reduced and more methane molecules were accumulated at the center of the pore space. This study has uncovered the adsorption process and the effect of CTAB in altering the sorption behavior of methane towards shale. This would contribute to the enhancement of long-term shale gas production by providing more information on salinity and pressure sensitivity, enabling extraction to be done at a lower cost.

Summary An incomplete data set of flow rate and pressure is detrimental to reservoir management and operation. It has the potential to increase uncertainty and has the potential to unfavorably affect operational and managerial decisions. Such a data set might transpire because of failure in the flowmeters, pressure gauges, and/or unrecorded shut-in periods. This study proposes and evaluates unified physics and data-based analytics for “learning” the underlying behavior of a reservoir and reconstructing missing gas, oil, and water flow rates. The proposed workflow is evaluated using real field data obtained from a North Sea reservoir. Validation is done by using a whiteness test, a goodness-of-fit test, and a novel physics-based validation using material balance and pressure back-calculation. The outcome has shown the capability and flexibility of the selected machine-learning techniques in estimating the missing flow rate on the basis of pressure responses. The features that are extracted and expanded on the basis of physics have resulted in a high-fidelity model with less computation time.

Purpose This paper aims to examine the effect of wax, calcites and clay on the stability of petroleum emulsions. It proposes a proxy model that takes into cognizance the presence of solids other than asphaltene and resin. This study aims to investigate the combined effects of these solids on the stability of emulsions and show their relevance or otherwise in the creation of petroleum emulsions. Design/methodology/approach This paper used synthetic emulsions based on a response surface methodology using different weight concentrations of wax, calcites and clay. A Box–Behnken design model was adopted and the effects of the different variables on emulsion stability were analyzed. The conventional visual observation (batch testing) was augmented with a more robust technique of studying emulsion stability (Turbiscan) based on light backscattering or transmission. Analysis of variance and other statistics were used to analyze the results. Findings The paper makes an available proxy model that can predict the stability of petroleum emulsions in the presence of wax, calcites and clays. The findings suggest that in the presence of significant amount of wax (0.3 Wt.%), the presence of relatively lower concentration of clay (0.1 Wt.%) produces very stable petroleum emulsions. The results show that the most stable emulsion is obtained when significant amount of wax exists in the continuous phase and that a concentration of calcites more than wax (in a ratio of at least 2:1) produces an emulsion that separates very fast, indicating low stability. Research limitations/implications Due to the variations in the amount of asphaltene and resins in crude oils, the proxy model cannot generally predict the stability of every emulsion that forms in the presence of these solids. To have a more general model, it should include asphaltene/resin. This can be tested further. Practical implications This paper provides useful information to the oil industry, especially where formation of severely stable emulsion is a problem. It also establishes the relationship that exists between solids in emulsion stabilization. Originality/value This paper satisfies a demand on the effects of other surface-active materials in addition to asphaltene/resin in stabilizing petroleum emulsions.

The high dimensional, multimodal, and discontinuous well placement optimization is one of the main difficult factors in the development process of conventional as well as shale gas reservoir, and to optimize this problem, metaheuristic techniques still suffer from premature convergence. Hence, to tackle this problem, this study aims at introducing a dimension-wise diversity analysis for well placement optimization. Moreover, in this article, quantum computational techniques are proposed to tackle the well placement optimization problem. Diversity analysis reveals that dynamic exploration and exploitation strategy is required for each reservoir. In case studies, the results of the proposed approach outperformed all the state-of-the-art algorithms and provided a better solution than other algorithms with higher convergence rate, efficiency, and effectiveness. Furthermore, statistical analysis shows that there is no statistical difference between the performance of Quantum bat algorithm and Quantum Particle swarm optimization algorithm. Hence, this quantum adaptation is the main factor that enhances the results of the optimization algorithm and the approach can be applied to locate wells in conventional and shale gas reservoir. © 2020 by the authors. Licensee MDPI, Basel, Switzerland.

The influence of an anionic surfactant, a cationic surfactant, and salinity on adsorbed methane (CH4) in shale was assessed and modeled in a series of systematically designed experiments. Two cases were investigated. In case 1, the crushed Marcellus shale samples were allowed to react with anionic sodium dodecyl sulfate (SDS) and brine. In case 2, another set of crushed Marcellus shale samples were treated with cetyltrimethylammonium bromide (CTAB) and brine. The surfactant concentration and salinity of brine were varied following the Box-Behnken experimental design. CH4 adsorption was then assessed volumetrically in the treated shale at varying pressures (1-50 bar) and a constant temperature of 30 °C using a pressure equilibrium cell. Mathematical analysis of the experimental data yielded two separate models, which expressed the amount of adsorbed CH4 as a function of SDS/CTAB concentration, salinity, and pressure. In case 1, the highest amount of adsorbed CH4 was about 1 mmol/g. Such an amount was achieved at 50 bar, provided that the SDS concentration is kept close to its critical micelle concentration (CMC), which is 0.2 wt %, and salinity is in the range of 0.1-20 ppt. However, in case 2, the maximum amount of adsorbed CH4 was just 0.3 mmol/g. This value was obtained at 50 bar and high salinity (∼75 ppt) when the CTAB concentration was above the CMC (>0.029 wt %). The findings provide researchers with insights that can help in optimizing the ratio of salinity and surfactant concentration used in shale gas fracturing fluid.

Shale rocks are one of the world's most important unconventional gas resources today, thanks to technical advancements. Fluid adsorption in tight rocks like shale is critical for designing fracturing and treatment fluids. However, adsorption of fluids in shale is not fully understood, and quantifying it remains difficult. In addition, the complicated pore structure of shale rocks makes characterisation challenging. Wettability can be used to understand the affinity of a solid surface to adhere certain fluid. Shales present several basic problems when employing standard techniques because of their small grain size, low permeability, and reactive components. We assessed and compare the wettability of shale using contact angle and spontaneous imbibition methods in two shale samples. The findings showed no correlation between contact angle and imbibition curves. Such behaviour is due heterogeneity of shale surface. Contact angle produces local wetting characteristics, but shale sample is rather complex and contact angle is therefore not representative. Imbibition results might be more reliable since fluids contacts with the whole sample.

Usage of supercritical CO2 (Sc-CO2) as fracturing and displacing fluid is given much attention in recent years. It enables the prevention of issues related to hydraulic fracturing such as formation damage, clay swelling, capillary trapping, and consumption of a high volume of water. However, the low proppant carrying capacity, high frictional resistance, and fast filtration of Sc-CO2 are the challenges that require further research. Characterization of shale samples for implementation of Sc-CO2 as a fracturing fluid consists of imaging and qualitative analysis, identification of crystalline phases presents in material and determination of pore size distribution, surface area, micropore volume, porosity, and matrix density. Shale samples from Eagle Ford (EF-1. EF-2), Mancos (MC), and Wolfcamp (WF) shale formations have been characterized using field-emission scanning electron microscope (FESEM), X-Ray diffraction (XRD), surface area analyzer and porosimetry system (SAP) and Helium Porosimeter. From FESEM and EDX experiment, among all the samples, EF-1 has the highest carbon content (25.97%), EF-2 is mostly calcium dominant (33.17%) and WF has quartz having the presence of 3.37% of silicon. The existence of these elements and compounds are also validated by the qualitative and quantitative analysis of the XRD patterns. FESEM estimates that all these shale samples have the presence of mostly mesopores. Results from SAP experiment show that BJH adsorption average pore diameter of EF-1, MC and WF 30.8490, 8.5128, and 26.4318 nm respectively and it validates FESEM result. In terms of porosity, MC has the highest (7.4%), while EF-1 has the lowest (2.01%). For eradicating the problem of low proppant carrying capacity of Sc-CO2, thickening agents such as N-ethyl perfluorooctyl sulfonamide, a viscoelastic surfactant (VES) is used in this study. The molecular simulation study of N-ethyl perfluorooctyl sulfonamide to Sc-CO2 increases the viscosity of Sc-CO2.170 times than the actual viscosity of Sc-CO2. Although this an excellent result to derive yet the experimental validation of this result is needed to pave its implementation on real field scenarios.

Shale instability due to hydration and swelling is an unavoidable problem during hydraulic fracturing or drilling with water-based fluids. In this study, 1-butyl-3-methylimidazolium chloride (BMIMCl) an ionic liquid was utilized as a clay swelling inhibitor. The performance of BMIMCl was evaluated by the bentonite plate soaking test and linear swelling test. FT-IR and zeta potential test was done to explain the swelling inhibition mechanisms. Moreover, XRD test was conducted for the characterization of bentonite (swelling clay). 2 wt.% BMIMCl reduced the swelling rate of bentonite by 19.38% while the conventional and mostly used inhibitor, 3 wt.% KCl reduced 13.84% compared with distilled water. These results showed that BMIMCl has better inhibitive properties than the most used clay stabilizer, KCl. This inhibitor showed better performance because of the presence of a hydrophilic head and hydrophobic tail in its structure. The hydrophilic positive head helped it to get adsorbed on the bentonite surface, forming hydrogen bonds, and reduced the surface negative charge. On the other side, the butyl chain may be made a hydrophobic shield that prevented water from entering into the interlayer space. The ability of BMIMCl to form bonds with bentonite and water was confirmed by FT-IR analysis. Therefore, BMIMCl has the potential to be an effective shale swelling inhibitor during drilling and hydraulic fracturing operations in the water-sensitive shale formation.

Many studies tied to adsorption on heterogeneous surfaces have been reported in the literature. However, finding an adsorption model that accurately describes the sorption mechanism in gas shales remains a challenge. This is due to the complex surface heterogeneity and the presence of multiple components in the formation. Modelling and simulation at reservoir conditions for adsorption studies are also computationally expensive. An optimized adsorption model is therefore essential because it can lead to an accurate estimation of the adsorbed gas amount and ultimately improve the production process. This work presents a review of the adsorption models that have been used in characterizing shale formation. Moreover, the mechanisms and factors that control adsorption in shale formation and their interaction are also analyzed. As observed from the current review, Langmuir is the most used adsorption model. However, like other existing models, it does not adequately represent the sorption phenomenon in shale formation where surface heterogeneity and the presence of multi-component are eminent. There has thus been works to improve and enhance it for use in shale formation. On the other hand, the advancement of molecular simulation presents an opportunity for better representation of the sorption mechanism.

Billions of tons of quarried material are globally produced per annum, generating siliceous solid cutting and powder waste which are usually disposed of in landfill sites. Herein, two cheap and distinct granite quarry waste cuttings have been reduced into microproppant dimensions. They were characterized for potential application in hydraulic fracturing as an economic alternative to siliceous commercially available microproppants. The particle size distributions, morphology, particle density, the mineralogy, microscale mechanical hardness, and modulus of the produced microproppants were evaluated to confirm their potential application as microproppants. Also, the split core fracture conductivity of the produced microproppants was measured. Laser diffraction revealed particle size distribution with d50 of about 11 μm suitable for common natural fracture widths. Morphological images showed low sphericity and roundness appropriate for channel fracturing proppant placement. A particle density of 2.6 and 2.9 g/cc was obtained for the produced microproppants. However, a review of most granite particle density indicated proximity to commonly used quartz-based microproppant. Their density and smaller sizes suggest good transport properties. Results of the mineralogy study showed high amounts of silica content with dominant crystal phases of albite, anorthite, and orthoclase which exhibited theoretical hardness between (5.2–7.2 GPa) and modulus between (77.8–98.0 GPa). Nanoindentation confirmed the micromechanical hardness and modulus determined by density functional theory. The hardness and modulus lie between class C Fly ash and Ottawa sand which have demonstrated good performance as microproppants. Hence granite microproppants have the potential to resist reservoir stresses. Granite microproppant pillars were able to improve the baseline permeability of a fractured shale core by a magnitude of ten. Granitic microproppants are cheaper sources of silica capable of maintaining microfracture width and preventing rapid production decline within unconventional shale reservoirs while contributing to the conservation of overly exploited natural sand deposits.

Caprocks/ CO 2 interfacial tension ( γ sc ) is an essential parameter that helps to provide insights into the interaction between CO 2 and caprocks. Lower values of γ sc suggest stronger CO 2 - caprocks interaction (lower CO 2 capacity is inferred) and vice versa. Rocks/CO2 interfacial tension also explains why different minerals have different wettability to CO2 at the same pressure and temperature. Two caprock samples acquired from a potential CO 2 storage site in New South Wales in Australia were used in this work. All the laboratory measurements were conducted at varying pressure from 5 MPa to 20 MPa and a temperature of 343 K. Our findings suggest that solid/ CO 2 interfacial tension ( γ sc ) in caprocks is highly dependent on total organic carbon (TOC) percentage, pressure, and quartz content. γ sc in sample-2 of higher TOC and quartz (TOC =0.11 wt%, quartz = 62%) is lower than γ sc in sample-1 of lower TOC and quartz (TOC =0.081 wt%, quartz = 31%. The higher percentage of TOC and quartz increases the hydrophobic sites available in the sample, allowing stronger affinity towards CO 2 . Lower interfacial tension implies a stronger affinity of CO 2 towards caprock surface (the high chance that CO 2 will enter through caprocks and causes leakage). Therefore, it can be inferred that high TOC caprocks offer a lower CO 2 trapping integrity, hence reducing their CO 2 storage capacity. A remarkable relationship between solid/ CO 2 interfacial tension and CO 2 density–which is easy to determine – at different pressures (up to 20 MPa) and 343 K temperature was also demonstrated in this work. This insight can significantly enhance Carbon Geosequestration processes' fundamental understanding.

There is an urgent need to store millions of tons of CO2 in deep underground formations to reduce anthropogenic emissions in the atmosphere. Basaltic rocks are recently depicted as feasible and safe candidates for storing CO2 in mineralized form. The leakage of stored C O 2 in basaltic rocks could be minimized due to the mineralization process reported to occur in timescales magnitude shorter than those predicted for sandstone reservoirs. Rock/ C O 2 interfacial tension and wettability are essential factors to understand the interaction between C O 2 and basalt rocks. Low values of rock/ C O 2 interfacial tension suggest stronger C O 2 -rock interaction, thus lower CO2 capacity is inferred, and vice versa. In other words, low values of rock/ C O 2 interfacial tension indicate stronger adhesion of CO2 molecules onto the rock surface. In this study, we have experimentally investigated basalt/ C O 2 interfacial tension under various pressures ranged from 4 MPa to 20 MPa and at temperatures of 308o K and 333o K. Our findings suggest that, as expected, Basalt/ C O 2 interfacial tension decreases as the pressure increases and increases as the temperature increases; solid/water interfacial energy decreases with increasing the temperature. The results also revealed that Basalt's CO2 sealing capacity is reduced as the contact angle (pressure) and temperature increases. The CO2 sealing capacity was reduced by up to 50% as the contact angle became ~80° or when the pressure reached 17 MPa. We also found that there is a remarkable relationship between Basalt/ CO 2 IFT and CO 2 density (ρ) at 308 K and 333 K. The introduced relationship could serve as a handy tool to give a quick prediction of IFT CO 2 /basalt in basaltic formation or other CO 2 /solid systems. Determining solid/gas surface energy helps explain why minerals/rocks offer different wettability at certain pressure and temperature, leading to a better understanding of geological CO2-storage processes.

Well placement optimization is one of the major challenging factors in the field development process in the oil and gas industry. This chapter aims to survey prominent metaheuristic techniques, which solve well the placement optimization problem. The well placement optimization problem is considered as high dimensional, discontinuous, and multi-model optimization problem. Moreover, the computational expenses further complicate the issue. Over the last decade, both gradient-based and gradient-free optimization methods were implemented. Gradient-free optimization, such as the particle swarm optimization, genetic algorithm, is implemented in this area. These optimization techniques are utilized as standalone or as the hybridization of optimization methods to maximize the economic factors. In this chapter, the authors survey the two most popular nature-inspired metaheuristic optimization techniques and their application to maximize the economic factors.

This paper proposes a modified crow search algorithm with local search and niching technique. The primitive crow search algorithm is a newly developed population-based algorithm which gained attention from the researchers of many fields as it needs only one parameter to be tuned. Despite its easy implementation, crow search algorithm has weakness to find global optima and suffers from slow convergence rate in multi-modal optimization problems. The search agent of the primitive crow search algorithm does not always follow the best solution obtained so far. Another disadvantage is that the search agents updates its location randomly. In order to enhance its searching capacity, a global search operator is introduced. Also, The proposed method modifies the search techniques and incorporates niching method to increase exploration capacity. The proposed technique is tested on 23 benchmark functions. The results of the proposed method demonstrated faster convergence rate and better solution in most cases when compared with the standard crow search algorithm.

Water-in-oil petroleum emulsions were prepared using response surface methodology (RSM) based on box-Behnken design (BBD). The emulsions were prepared using a treated Malaysian offshore crude oil, where the saturates, aromatics, resins and asphaltenes (SARA) of the crude oil were extracted using a modified SARA analysis. Other native solids, wax and asphaltenes extracted from oilfield emulsions and other crude oils were used as the emulsifying agents. In this paper, we focus on the characterization of some oilfield solids extracted from Malaysian offshore fields and further investigated their potentials to stabilize petroleum emulsions. The effects of the solids alone, and in combination with asphaltene/resin and wax were studied using statistical methods and the stabilities of the emulsions examined using a Turbiscan optical analyzer. The main advantage of Turbiscan is to obtain a faster and more accurate detection of destabilization phenomena in non-diluted emulsion than can be detected by the naked-eye (observation), especially for an opaque and concentrated dispersion system. The sample characterizations were conducted with FTIR, TGA, FESEM/EDX, XRF and XRD. Results showed that the major native solids present in the samples were paraffins and calcium carbonate. Further analysis revealed that the solids by themselves do not significantly contribute to emulsion stability. However, in the presence of asphaltene/resin compounds, the prominent solids such as paraffins and calcium carbonate enhance the stability of the emulsion irrespective of asphaltene/resin concentrations.

The environment is a prime concern in the mining industry because of its adverse impact on the solid, liquid, and gaseous surroundings. These three parts of the environment are directly connected to agricultural production. As the Barapukuria coal mine is located in the agricultural zone, its effects can be crucial. Previously, the impacts of the subsidence of the Barapukuria coal mining area were studied. So far, there is no significant study regarding its effects on agriculture. This research has focused on the impacts of the disposed water from the Barapukuria coal mine on the nearer aquaculture and agricultural fields. Therefore, the BOD, COD, DO, TDS, TSS, SS, residual chloride, hardness, alkalinity, carbon, sodium, calcium, magnesium, iron, potassium, sulphate, etc., being present in the disposed-water were analyzed in this study. The values of BOD, COD, DO, pH, TSS, TDS, and TS were lied in the best optimum range to cultivate crops and fisheries. It is also found that the disposed-water of the Barapukuria coal mine is tolerable for agriculture.

The cost and environmental effects of most conventional surfactants have increased the search for a greener and cheaper alternative for enhanced oil recovery (EOR) applications. The natural L-amino acids are amphoteric compound with excellent surface properties that have found versatile applications in the pharmaceutical, cosmetic, and food industries. These amino acids exhibited amphipathic nature due to their hydrophobic alkyl chain and charged head. Hence, they could form contacts with both polar and non-polar surface ligands simultaneously. In this study, four amino acids, namely L-arginine, L-lysine, L-methionine, and L-tryptophan, were investigated to access their ability to reduce the interfacial tension (IFT) and alter the wettability of oil-wet sandstone rock. The pendant/rising drop and sessile drop method were employed in IFT and contact angle measurements. The stability of amino acids in brine and the compatibility with other EOR chemicals were tested through visual observation of the precipitates and cloudiness. With the exception of L-tryptophan, the compatibility and stability results revealed that all the amino acids have high salt tolerance above 25 wt% sodium chloride (NaCl). The solutions of amino acids and chemicals such as cetyltrimethylammonium bromide (CTAB), sodium dodecyl sulfate (SDS), hydrolyzed polyacrylamide (HPAM), alkali, and alkali-polymer were transparent even at 80 °C. The IFT test results showed that the amino acids significantly reduced the crude oil-water IFT compared to the IFT of n-decane-water system. The IFT between deionized water and crude oil decreased by 76.61% and 55.24%, 24.79%, 45.23% in the presence of L-arginine, lysine, methionine, and tryptophan solutions, respectively. Addition of 0.01 wt% L-arginine, L-lysine and L-methionine to 0.1 wt% SDS reduced the IFT by 28.3%, 15.6%, and 10.97% respectively. The contact angle test showed that L-amino acids have great potential as wettability modifying agents. The contact angles reduced with the decreasing pH (potential of hydrogen) and with increasing brine concentrations from 1 to 4 wt%. Specifically, the contact angle reduced from 92.3°, 91.42°, 89.81° and 92.95 to 47.24°, 53.9°, 58.9° and 59.0° for L-arginine, L-lysine, L-methionine and L-tryptophan, respectively at a pH of about 3. The study suggests that the L-amino acids could be a potential EOR agent in a high saline environment, mainly as a wettability modifier, as well as additives to improve the surface activity of the conventional surfactant and EOR chemicals.

Stimulated reservoir volume (SRV) seldom provides an actual producible reservoir volume in gas shale reservoirs. It is determined by analysing microseismic events induced by a network of hydraulic fracture and reopened natural fractures. However, the occurrence of noncontributory microseismic events leads to an overestimation while the presence of natural fractures leads to an underestimation of producible reservoir volume. A relatively new concept used to quantify actual producible reservoir volume is the effective stimulated reservoir volume (ESRV). ESRV is essential in estimating ultimate recovery, propped volume, optimal fracture length, and spacing. This paper presents an outlook on the evolution and development of various models used to evaluate ESRV. The respective advantages and limitations of the various methods are discussed. It is observed that integrated modelling approaches, such as by using rate transient analysis and discrete fracture network modelling, are more efficient to characterise and describe the ESRV. Such an integrated approach should consider the stress/pressure dynamics, reservoir permeability, flow and fracture geometry which are vital for accurate ESRV characterisation.

Molecular simulation enjoys a high preference for use in adsorption studies. However, modeling and preparing a realistic shale topology remains a constraint. Majority of studies are performed using a single component, such as kerogen or montmorillonite, to represent shale surface. Where more than one component is used, they are not mixed but are at different ends of the nanopores. These surfaces do not bear similitude to actual shale surfaces in terms of heterogeneity and multiplicity of minerals. Moreover, disparities have been observed between simulation and experimental results. In this work, we propose a molecular shale model prepared from montmorillonite, type IID kerogen, quartz, and illite clay minerals. The results from the adsorption simulation studies on the shale model show that the model has higher adsorption capacity and surface area than the individual molecular models of kerogen, illite, or quartz. It was also observed that the proposed model had less free gas than adsorbed gas which is the actual situation in shale formations. The current model shows increased adsorption capacity up to about 48% more than other models used in this study. This new realistic model can serve to enhance the accuracy of adsorption simulations and thus present a better understanding of adsorption behaviors. Such improvement can also lead to increased accuracy in estimating the gas in place.

In recent years, directional drilling becomes more popular in petroleum industry due to its more exposure to reservoir. During wellbore trajectory design for directional drilling, more importance should be given on safety issues. Well-profile energy is the key parameter which can assure a safe and efficient wellbore trajectory through proper optimization. In this work, the Spotted Hyena Optimizer (SHO) is proposed and implemented for optimizing the well-profile energy and compared with another state of art method named Particle Swarm Optimization (PSO) algorithm. The trajectory is mathematically formulated by using radius curvature method (RCM) considering 17 variables on which well-profile energy is depended. The SHO successfully obtained the optimum values of the 17 design variables which eventually given the minimum well-profile energy. The optimum well-profile energy obtained by SHO is 207.00 which is 18.28% better than PSO. Additionally, the sensitivity of the algorithm has been analysed by changing different operational parameter of SHO. It is observed that the efficiency of SHO increased with the increment in the number of search agents (hyenas). The minimum well-profile energy achieved through SHO ensure a less complex and safe wellbore trajectory.

In this study, previous literature that discussed CO2/brine interfacial tension and wettability of rock/CO2/brine systems were critically reviewed. Using a shale core from Malaysian formation, laboratory experiments were conducted to extend the scope of available data for CO2/brine interfacial tension (IFT) and contact angles of shale/CO2/brine system, as well as shale/oil/brine system to elevated pressures (8 MPa–22 MPa), temperatures (80 °C–180 °C), and NaCl concentrations (0 wt% - 7 wt %), that are representative of downhole conditions. HPHT (high pressure, high temperature) drop shape analyzer (DSA100) instrument was employed for the contact angles and IFT measurements. The CO2/brine IFT was measured using the pendant drop method while the sessile drop/captive bubble techniques were used to measure the advancing and receding contact angles respectively. Correlations were developed for predicting changes in contact angles and CO2/brine IFT as a function of changing temperature, pressure and salinity. Results showed that the crude oil advancing and receding contact angles for shale/oil/brine system decreased with increasing temperature and salinity, but slightly increased with pressure. The brine advancing and receding contact angles of shale/CO2/brine system increased with increasing pressure and salinity, but decreased with increasing temperature. Conversely, the CO2/brine IFT increased with increasing temperature and salinity, but decreased with increasing pressure. The simulated and experimental values showed reasonable consistency with R2 values of 98% and 99% gotten from the statistical fits of the contact angles values. Precisely, at 80 °C and 7 wt% NaCl concentration, the shale surface became strongly CO2-wet, with brine advancing contact angles of 139.92°, 156.06°, and 162.63° when the pressure reached 18 MPa, 20 MPa, and 22 MPa respectively. At similar salinity conditions and 10 MPa, significant increment in CO2/brine IFT from 36.50 mN/m to 47.54 mN/m occurred with increasing temperature from 80 °C to 180 °C. Such wettability modification of the rock surface and change in IFT at elevated temperature, pressure and salinity will greatly influence hydrocarbon recovery, as well as CO2 containment security in Malaysian unconventional shale formation.

External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.

Proppants have evolved from their primary role of preventing fracture closure to performing technically functional roles within reservoirs. This paper presents an extensive review of recent advances in functional proppant technology. Multifunctional proppant roles, such as the enhancement of multiphase flow of reservoir fluids, delivery of CO2 for enhanced gas recovery, detection of fracture geometry, removal of contaminants, fracture moderation, treatment of flowback water, as well as proppant flow back retardation are presented. Advances in proppants with good transport and placement properties, such as, self suspended proppants and in-situ generated proppants were further addressed. Recent field and laboratory works suggested that conventionally sized proppants (