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Shale reservoirs have gained the attention of many in recent years due to their potential as a major gas resource. Production from this kind of formation, however, requires an accurate estimation of brittleness and employments of hydraulic fracturing. There have been many studies as to how brittleness can be estimated, but few research works were carried out so far indicating how brittleness indices vary in gas shale formations. The aim of this paper is to evaluate the variation of brittleness in one of the gas shale reservoirs located in the north Perth Basin of Australia. The results obtained indicated that the lower part of the Carynginia shale should be selected for a hydraulic fracturing job due to a high brittleness index, although a careful analysis of Total Organic Content (TOC) might be required before initiating any plans. The mineralogical report and interpretations revealed that the space created by cross-plotting the elastic parameters is able to identify dominant minerals contributing into brittleness. Performing a series of true triaxial tests, which are capable of simulating the real field condition by applying three independent principal stresses, implied that as the stress anisotropy increases, a transition takes place from brittle towards the ductile behaviours. However, when this anisotropy becomes significant, samples regain their strength. This study, therefore, recommends more studies to get a practical conclusion on brittleness under true triaxial conditions. [ABSTRACT FROM AUTHOR]

Coiled tubing technology (CTT) showed its capabilities in oil and gas (O&G) drilling in many cases. Some of the advantages of CT drilling are rapid mobilization/demobilization and rig up/down times, faster tripping in and out of the hole, small hole size capability, faster drilling operation, and less environmental footprint. Because the CT does not rotate, a down-hole motor/turbine, which needs high flow rate, is required to rotate the drill-bit. The cuttings transport in the small size annulus space is the core part of this research study. This was done through both laboratory experiments using a flow loop and numerical modeling. The results of flow loop experiments determined the minimum transportation velocity (MTV) to effectively bring all the cuttings to the surface. Directional boreholes were tested and the effect of cuttings size as well as mud properties was investigated. Testing actual cuttings in CT drilling presented different results than those observed in the literature for conventional O&G drilling. The different outcomes, for instance on the effect of rheology on cuttings transportation, necessitates conducting this research to develop a model for cuttings transportation in CT drilling. Computational fluid dynamics numerical simulation with Eulerian Granular approach was applied in this study to investigate the effect of different parameters in cuttings transportation. The simulation results were validated against the experimental results of the flow loop. Various flow patterns were simulated by changing different parameters. [ABSTRACT FROM AUTHOR]

Abstract: When in-situ stresses are disturbed around large scale fractures, typically faults, the direction of principal stresses can deviate from the regional trend to a completely new direction. This can have a great impact on engineering design and planning. In a gas field offshore Australia, a number of drilling difficulties and wellbore instability were reported at lower depths of one of three wells, while two wellbores in the field did not encounter similar problems. A detailed geomechanics study performed on the wellbore of interest indicated that it approached one of four major fault planes in the area as it was drilled deeper. This caused large stress anisotropy between the two horizontal stresses at lower depths, leading to a stress regime change from a normal to a strike/slip regime. The large contrast between the minimum and maximum horizontal stresses induced a number of shear failures in the form of breakouts around the wellbore, which we also observed on caliper and image logs. Accordingly, after performing sensitivity analysis on wellbore trajectory, we developed a mechanical earth model (MEM) to examine the planned well trajectories for the development campaign. The results demonstrate that the existence of natural fractures at any scale may have significant influence on in-situ stresses and stresses induced during construction of an opening. [Copyright &y& Elsevier]

Abstract: Due to low permeability of tight gas shale, production in commercial quantities requires effective hydraulic fracturing and horizontal drilling technologies. Therefore, understanding rock properties and earth''s stresses is an important step toward reservoir evaluation and ultimately development of these kinds of resources. Furthermore, successful production from such a complex formation is heavily dependent on selection of appropriate completion technology which requires having sufficient knowledge of borehole shape or say enlarged zones. Borehole enlargements or specifically breakouts provide valuable information for evaluation of in-situ stresses and verification of geomechanical models. Customarily used methods to identify breakouts, i.e., caliper and image logs, suffer from several limitations. In addition, good quality image logs are not usually available in shaly formations due to requirement of using oil-based mud. This led to the need for developing a new technique to identify borehole enlargement zones using petrophysical logs which are often acquired in majority of the wells. This study proposes a new multi-variable approach to identify borehole enlargement zones in tight gas shale using some petrophysical logs, mud weight and overburden stress data. This approach employs number of data processing techniques including Bayesian classification, wavelet decomposition and data fusion to determine borehole intervals with maximum likelihood of enlargement. This paper explains the methodology and presents its results in four study wells in Barnett gas shale. The study confirms the applicability and the generalization capability of the approach in shaly formations with a significant accuracy. [Copyright &y& Elsevier]

Abstract: Petrophysical logs are usually acquired in most of the drilled wells and some of them have good correlations with mechanical properties of the rock. In this paper, a new multi-variable workflow is proposed in order to identify the location of borehole enlargements along the wellbore in correlation with some of the petrophysical logs acquired using wireline or logging while drilling tools in addition to mud weight and in-situ vertical stress data. This approach employs number of data processing techniques including Bayesian classification, wavelet de-noising, and data fusion to determine borehole intervals with maximum likelihood of enlargement. The application of the proposed method is to identify enlargement zones and does not provide information about stresses orientations and magnitudes. This paper explains the methodology and presents its results in five study wells in a carbonate field. The study confirms the applicability and the generalization capability of the method in carbonate formations with a significant accuracy. [ABSTRACT FROM AUTHOR]

The vertical growth of hydraulic fractures in layered formations has been a topic of interest amongst researchers because of its critical influence on well performance. The analytical solution to the fracture vertical growth in layered formations is primarily based on force balance amongst various formation layers of segments that the vertical fracture intersects. The pressure associated with fluid movement in the vertical direction in a hydraulic fracture is generally ignored in most semi-analytical solutions to height-growth problems, especially if the vertical growth occurs at a slow pace. For a slow advancing vertical fracture, the tips are assumed to be near stationary, and the assumption is termed as equilibrium-height model. The model was first conceptualized for a simple 3-layered problem and later extended to multi-layered applications. The available literature shows model-derived solution for simple cases but lack in-depth study of real-world examples, which in doing so could highlight some of the model limitations. The semi-analytical model presented in the study, was first benchmarked by replicating the data published in the existing literature, and then applied to the field cases to compare its output with the observed data. Unlike the typical approach taken in the literature where the location of one of the tips of the fracture is assigned and the position of other tip is determined, the current model determines the most suitable position for a fracture of given height and stress profile. Additionally, new features were added to the model when evaluating the field cases. These include, incorporating calculation procedures that provide accurate fracture placement for given conditions, handling layered property inputs up to 100 layers, and the ability to include variable fracture pressure as opposed to a constant pressure approach. The model was applied on several cases from the field, four of which are presented here. The analysis showed that there is a close agreement between the predicted and the observed fracture heights. The hybrid feature of the model with inclusion of non-uniform pressure drop profile in the fracture, also helped in calibrating a case where a mismatch was observed. It was concluded that this model can predict fracture height growth with reasonable accuracy for cases with low injection rates where low viscosity fluid is used and requires calibration in cases where high net pressures are expected. The newly developed model is simple to program and can assist in making quick estimates of fracture vertical growth in vertical wells with low-rate fracture stimulation treatments. • A 100-layer fracture height growth model was developed to predict fracture growth behavior in layered formations. • Reasonable agreement between the modeled and field-observed fracture heights were observed in most of the case histories analyzed. • Non-linear pressure distribution in foamed fractures resulted in nearly 30% difference between observed and predicted values. • The model was modified to allow for uneven pressure distribution inside the fracture and successfully tested on well C. • Using this model, height growth was accurately predicted for most treatments and likewise for special case, after modification. [ABSTRACT FROM AUTHOR]

• In fluence of stress shadow on multi-clusters fracturing was analyzed. • The proppant transport and placement were considered in the model. • Multiple cluster hydraulic fracturing in multiple horizontal wells was simulated. Multiple cluster hydraulic fracturing is widely used in the development of shale reservoir. The morphology of multiple fractures propagating from multiple cluster is complex due to the stress shadow effect. The design and operation of multiple cluster hydraulic fracturing in horizontal wells require adequate knowledge of the effect of different factors, including rock properties, in-situ stresses and fluid properties on the fracture morphology. In this paper, lattice simulation, a new particle based computational method was used to investigate the multiple cluster hydraulic fracturing in shale. The results showed that stress anisotropy and cluster spacing play an important role on geometry of the propagating fracture. The middle hydraulic fracture is restricted to propagate when cluster spacing is decreased. Simultaneous, two-step and sequential fracturing scenarios in a single horizontal well were simulated. The simultaneous and sequential fracturing showed to mainly affect the fracture propagation morphology with little effect on fracture length, while the middle fracture is shorter than its two side fractures in two-step fracturing. In two horizontal models, the simultaneous and sequential fractures showed similar morphology during multiple cluster hydraulic fracturing. In term of stimulated reservoir volume (SRV), zipper fracturing showed the largest SRV during multiple cluster hydraulic fracturing in two horizontal wells. [ABSTRACT FROM AUTHOR]

A novel integrated approach that couples hydraulic fracturing and production simulation was proposed for Marcellus shale gas reservoir. A discrete element method based hydraulic fracturing simulator was utilized for multi-stage hydraulic fracturing simulation. Moving tip clustering (MTC) and linear regression clustering (LRC) algorithms were proposed to characterize the complex fracture geometry. Embedded discrete fracture model method was used to transfer the complex geometry of multiple fractures into a third-party reservoir simulator for history matching of shale gas production and production forecasting. It was observed that the LRC algorithm can generate smooth fracture geometries and detect overall fracture paths reasonably. The MTC algorithm, however, can capture more branches of microcracks and recover zig-zag fracture paths with larger apparent fracture lengths. The zig-zag fractures contribute to larger stimulated reservoir volume and result in an extra shale gas production of 5.2% compared to the smooth fractures. The gas slippage effect increases apparent matrix permeability to 4.6 times of intrinsic permeability. Reduction of fracture conductivity and matrix permeability due to decreasing bottomhole pressure leads to 9.25% and 9.28% decrease of gas production respectively in 30 years and should be taken into account for long-term production prediction. • A novel coupled model was proposed for multi-stage hydraulic fracturing and production. • Moving tip clustering algorithm generates zig-zag fractures with larger SRV. • Linear regression clustering algorithm detects smooth fractures for major paths. • Gas slippage, matrix shrinkage, and fracture closure affect shale gas production. [ABSTRACT FROM AUTHOR]

This study provides a critical review of Underground Hydrogen Storage (UHS), emphasizing its potential as a viable energy storage option despite several associated challenges. These challenges include microbial degradation, chemical reactivity, unique thermophysical characteristics, and geomechanics considerations. Effective and secure UHS operation requires careful site selection, management, and a thorough understanding of hydrogen's behavior under various geological and operational conditions. Our review examines the significance of hydrogen's physical properties, H 2 -fluid-rock dynamics, redox-driven geochemical interactions, microbial activities, and geomechanical risks influencing UHS performance, safety, and containment. Additionally, we discuss the importance of optimal material selection and operational strategic development to maximize UHS efficiency and minimize associated risks. While global projects and ongoing research form a solid foundation for UHS development, ensuring UHS effectiveness and safety requires further investigation. This article also identifies the main knowledge gaps and future research directions for effective deployment of UHS projects. [Display omitted] • Assessment of geological formations suitable for UHS, including salt caverns, depleted reservoirs, and saline aquifers. • Insights derived from global UHS projects inform best practices. • H 2 physical properties and the complex H 2 -fluid-rock dynamics are crucial for ensuring UHS efficiency and safety. • Geochemical reactions, microbial activities, and geomechanics may affect UHS performance and integrity. • Geologic and operational parameters are keys to achieving optimal UHS performance. [ABSTRACT FROM AUTHOR]

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring. The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies. [Display omitted] • Novel gas injection scheme designed for multi-pad wells is proposed. • Alternating gas injection into a four well-pad for enhanced oil recovery is investigated via numerical simulation. • The impact of operational parameters on the process efficiency is analyzed. • It is shown that the method can be a cost-effective EOR application in low-permeability and depleted reservoirs. • Alternating gas injection may potentially eliminate the flaring routings from wells connected to gas gathering networks. [ABSTRACT FROM AUTHOR]

Determination of the total organic carbon (TOC) from well logs is an important step in formation evaluation of shale reservoirs. The ΔlogR model is one of the most commonly used methods in determining the TOC of the source rocks. Wang et al. (2016) made three revisions on ΔlogR model to enhance the prediction accuracy, one of which is to use a changeable slope of log 10 R t versus porosity logs to replace a fixed value. Based on the original ΔlogR model and Wang's revision, we propose an improved model for a better TOC estimation in this paper. Specifically, the approximate linear baseline is replaced by a theoretical one. Under this condition, both the slope and resistivity and porosity log values of the baselined rocks vary from depth to depth. The determination of theoretical baseline is presented, and the varied baseline log values are obtained by a simple mathematical technique. In addition to the shale play of Western Canada Sedimentary Basin, two study areas of Sichuan Basin and Ordos Basin in China, were used to assess the applications of the proposed model and its improvement over the original model. The analysis and discussions presented in this paper indicate that the improved model offers more reliable results in shale plays with large lithological variations. Also, the TOC content of the three study areas was estimated using the proposed model. The results showed that the TOC values estimated from well logs and core analysis are in good agreement. [ABSTRACT FROM AUTHOR]

Abstract: Fracture detection as applied to reservoir characterization is a key step towards modeling of fractured reservoirs. While different methods have been proposed for detection and characterization of fractures and fractured zones, each is associated with certain shortcomings that prevent from their full use in different related engineering application environments. In this paper a new method is proposed for detection of fractured zones and fracture density in which water saturation log data is utilized. For detection of fractures, we have used wavelet transform and properties of wavelets that are highly suitable for detection of changes and local features of data. To choose the optimum mother wavelet, we have used energy matching strategy in which a wavelet with the highest energy match between spectral energy of the signal at the dominant frequency band and the coefficient energy at the same band of wavelet decomposition of the signal is selected. We have used wavelet packet for a more narrow frequency band selection and enhanced results. Decomposing the water saturation data using wavelets showed that the majority of information of the original log is hidden at low frequency bands. As a result, approximated section of wavelet transform of data was used for fracture detection, while shale volume (or gamma ray) log data was used to filter part of the errors in prediction and identification of the uncertain zones. This increased the accuracy of the results by 70%. Finally, a linear relation was derived between energy of approximated section of water saturation log and fracture density, allowing us to estimate the number of fractures in each fractured zone. The method was applied to four wells belonging to one of the Iranian oilfields located in the southwest region of the country and the results are promising. The use of large volume of data and the subsequent analysis increased the generalization ability of the proposed method. [Copyright &y& Elsevier]

• Generative voluntary safety reporting culture (GVSRC) leads to proactive reporting of precursors of safety events. • Aviation Safety Action Program (ASAP) promotes GVSRC in U.S. airlines and can be adopted in the oil and gas sector. • Validated GVSRC factors are Safety Reporting Policy Fundamentals, Organizational Support and Process Engagement, and Safety Reporting Benefits. • Top management provision of resources for safety reporting programs significantly improves safety reporting processes. • Despite the different operating environments and processes, an ASAP prototype has safety value in the oil and gas sector. Generative voluntary safety reporting culture (GVSRC) fosters proactive reporting of hazards, near-misses, potential violations, and operational errors that are precursors of accidents. The Aviation Safety Action Program (ASAP) has been effective in sustaining a GVSRC in the U.S commercial airline industry. To assess the potential cross-disciplinary application of an ASAP-style initiative in the Gulf of Mexico (GOM) oil and gas (O&G) sector, a GVSRC model was developed from employee perceptions of ASAP attributes using structural equation modeling. Hypothesized underlying factors of GVSRC: safety reporting policy fundamentals (SRPF), organizational support, personnel engagements in voluntary safety reporting processes (OSPE), and safety reporting benefits (SRB) were validated. The GVSRC model had a good fit index (RMSEA = 0.031). All underlying factors had significant predictive relationships with GVSRC, with high effect sizes. The GVSRC model has utility in gauging the levels of understanding and acceptance of ASAP attributes in the O&G sector. There were significant linear relationships between the factors and OSPE significantly mediated the relationship between SRPF and SRB. Results suggest that top management support for voluntary safety reporting programs through resource provision can motivate personnel to engage in safety reporting processes. In terms of voluntary reporting propensity, younger respondents significantly underreported safety issues than older personnel, highlighting the need for better hazard identification, safety risk management training, and effective mentoring for younger personnel. Implication for policy is that despite different operating environments and processes, an ASAP-styled initiative has positive value for safety management and engendering a proactive safety reporting culture in the O&G sector. [ABSTRACT FROM AUTHOR]

[Display omitted] • We demonstrate a combinatory approach that circumvents the known disadvantages of catalytic materials. • Prussian blue analogs demonstrate to be excellent support or host materials. • The excellent catalytic activity are attributed to the availability of multiple electron transfer pathways. Prussian blue analogs (PBAs) exhibit potential as low-cost and eco-friendly nanocatalysts that can be fabricated with ease. However, the PBA framework structure suffers from poor electronic conductivity, which limits the catalytic efficiency for this class of materials. Noble metals represent an alternative class of materials that display inherent catalytic activity but suffer from aggregation, ultimately reducing the amount of accessible catalytic sites. Herein, we demonstrate a combinatory approach that circumvents the known disadvantages with these classes of catalytic materials in which PBA-supported nanocatalysts were synthesized. These composite materials exhibit excellent catalytic activity for the reduction of nitroaromatics to aminoaromatics while displaying long-term cycling stability, which is attributed to the availability of multiple electron transfer pathways. Overall, this work opens the study on the assembly of PBA-supported heterogeneous nanocatalysts and potentially paves the way toward future applications. [ABSTRACT FROM AUTHOR]

Certain polymers are often used during water based mud (WBM) drilling to reduce the filtration loss in permeable intervals. Although they often provide a good performance but cannot totally stop the fluid loss and mud invasion into the reservoir may cause significant formation damage including unfavourable changes of surface wettability. As a result, the two phase relative permeability of the near wellbore region changes and production may face difficulties in the later stages. In this paper, a new mud design is proposed to reduce the surface wettability alteration posed by WBM in sandstone reservoirs. The results obtained from performing a series of contact angle measurements indicated that clean and dirty sandstones are strongly water wet systems but mud invasion can make them a weakly water wet surface. It was also found that Cetyltrimethylammonium bromide (CTAB), as a cationic surfactant, prevents surface alteration of rocks and reduce the formation damage, but it may isolate the clay and creates a huge mud cake around the borehole. It was also observed that the salinity of the mud has a great impact on the surface wettability and adding CaCl 2 can reduce the formation damage in the reservoir intervals during drilling, although caution must be taken to maintain the cost of the mud. Image 1 • A new mud design was proposed to reduce formation damage in sandstone reservoirs. • Cation surfactants can favorably alter the surface wettability of mud/rock system. • CaCl 2 is a good choice to reduce the formation damage posed by wettability alteration. • NaCl can help to maintain the surface wettability but may increase the viscosity of the mud. • Combination of CaCl 2 and NaCl can be a good choice to reduce the cost of the mud design. [ABSTRACT FROM AUTHOR]