bluuebunny/crossref_metadata_2025_split huggingface dataset:
Securing Business Processes Using Blockchain Technology: A Case Study of Hydrocarbon Accounting Processes.
Authors: Odachi Kenechukwu 
Published: February 2022

AbstractThis research addresses the problems associated with hydrocarbon accounting reconciliation and allocation from the production facility to the export terminal. This paper further discusses the security of the hydrocarbon accounting database and the overall automation of the production value chain, providing transparency to the joint venture partners involved in the crude oil export agreement to avoid revenue loss. It also provides a system that is not prone to malware or data alteration and promotes hydrocarbon allocation among the injectors, production data management and production data security.The existing system mostly in the sub-saharan Africa lacks trust and greater transparency. A new technology will be devolped using Blockchain Hyperledger which is a distributed ledger technology. For the purpose of this research Javascript, PHP, MySQL on Apache virtual machine was used to design and simulate the blockchain network. The web interface of the system was tested using katalon web test framework using Agile methodology. The system will have to integrate with the Lease Automation Custody Transfer (LACT) and Supervisory Control and Data Acquisition (SCADA), A LACT-SCADANode synchronized system will be implemented in the custody transfer point in the export pipeline, so all the oil and gas Exploration and Production (E&Ps) companies injecting crude oil can view what each company in the network injected and also the quantity that got to the export terminal daily.This will be achieved by having all the custody transfer nodes of the E&Ps and export terminal node in a network of consensus. Production data will be distributed at strategic points during the transportation among the nodes uniformly at the same time, making it impossible for cyber-invasion on all the nodes at the same time. The outcome of this research will achieve an advanced secured transparent system to store production data for accurate hydrocarbon allocation, in which the consensus attribute of the implemented blockchain technology will give each node autonomy. Hence, making the production data highly reliable and reconciliation will be achieved at real-time.This innovation further presents a new knowledge in the application of mechatronics engineering to the oil and gas sector, with its multidisciplinary focus on electronics, mechanical and computer systems. It is the integration of a software system to a LACT and sensors on the crude oil pipelines to acquire data, compute in a Hyperledger fabric network and display at real-time for hydrocarbon allocation settlement
Data Science Adoption and Operationalization in the O&G Industry: Challenges and Solutions
Authors: Zouch Mariem 
Published: February 2022

Abstract
The Oil and Gas (O&G) industry is used to cycles of lows and highs due to different challenging economic and political situations. Yet the challenges caused by the sanitary crisis due to the covid-19 pandemic are certainly like no others. The shutdown of a large number of social activities had a direct impact on energy consumption. Many studies [1], [2] and [3] have been published at the beginning of the covid-19 pandemic to predict impacts of the restrictions imposed on a global scale: decline in global oil demand, saturation of storage capacities and delay of exploration and production projects. Companies facing this unprecedented crisis had no option but to adopt innovative ways of driving costs lower and maximizing operational efficiency. As a consequence, the pace at which Data Science (DS) is finding its way to O&G applications has been noticeably accelerated although the O&G industry is one of the latecomers to digitalization [4]. The adoption of DS and data-driven solutions has moved from gaining acceptance in the industry to becoming a necessity to many companies. According to a Gartner survey [5], the O&G industry commitment to investment in digital transformation in general had become the first priority in 2021 while it was third-highest priority in 2019 and not even funded in 2014. This involves investments in data acquisition techniques through innovative sensing technologies but also investments in advanced data aggregation and analytics platforms. AI/ML/analytics are listed in the same survey [5] as "top game-changing technologies in 2021". The 2021 survey also states that 50% of the O&G companies have plans to increase their investments in AI/ML and related fields such as cloud-computing.
But adoption and operationalization of DS does not come with no challenges. Acceptance and reliance on data-driven models need a favorable cultural and technical environment that is not necessarily compatible with the conventional corporate-like outlook of O&G companies: Data privacy and ownership regulations can diminish DS efforts. Security restrictions can prevent deployment of ML models to end users. All of these challenges are accentuated by the absence of a clear process model to implement and manage DS projects. In this paper, we survey the actual challenges the O&G industry is facing and present a number of corresponding solutions. The paper is structured as follows. The first section explores the state of the art of data-driven models in the O&G industry. The second section lists the challenges DS is facing within the O&G industry and proposes a classification of these challenges into three main classes, namely: human, data and infrastructure related challenges. The paper also proposes an O&G specific framework for DS projects to overcome these identified challenges.
A Holistic Approach to Rank Unconventional Reservoir Prospects led to Pakistan's First Successful Shale Formation Testing
Authors: Shah Syed Muhammad Usman , Araque-Martinez Aura N. , Ahmad Naveed , Ali Rahmat , Chaudhary Muhammad Saqib , Abbas Javed 
Published: February 2022

Abstract
Pakistan holds significant volumes of unconventional hydrocarbon reserves. In 2013 EIA report, the Sembar Formation of the Lower Indus Basin has 101 Tcf shale gas with 5.8 billion barrels shale oil resource as the risked & technically recoverable hydrocarbons over an area of about 81,000 km2. However, the EIA report has highly risked the prospective areas and the likelihood of development success. Thus, the main barrier for unconventional reservoirs development in the country is to reduce the associated uncertainty in a more rigorous manner and to decide, if and where to plant a flag in this vast area. A robust integrated approach was used to delineate and rank the unconventional reservoir prospect of Shale Gas, Shale Oil, and Tight Gas of Upper, Middle, and Lower Indus Basin of Pakistan by using multi hierarchy Shale Analysis Framework. This workflow spans the lifecycle of unconventional resource development by integrating petrophysical modeling, lab data, geologic and geophysical modeling, geomechanical modeling, stimulation modeling, drilling, reservoir and production engineering, and project management. Each of the workflow components is weighted as a function of their relative importance, and prospects in the study area are preliminary ranked according to how well they fulfill the criteria. Finally, the pilot area was selected/ranked by exhaustive uncertainty analysis using reservoir simulation and integrated with economic indicators such as Net Present Value (NPV), Return on Investment (ROI) & Rate of Return (ROR).
Initially, 27 prospective unconventional focused areas were identified and ranked among Upper, Middle & Lower Indus Basin. The top-ranked areas belong to the Sembar Formation of the Lower Indus Basin, in which further detailed assessment was carried out by extensive Shale Analysis Framework. Finally, the pilot areas were categorized based on integrated uncertainty and techno-economic evaluation. Based on outcomes, the top pilot area was tested by a mini-frac job as the first step. The Formation was successfully broken down within the estimated pressure range and produced hydrocarbons during the flow back period. The adopted framework proved to be successful in Pakistan's first shale formation testing and helps to reduce the number of appraisal or experimental wells needed to evaluate the resource potential and shorten the field development planning cycle and/or maximize the economic value of the resource via an efficient integrated approach.
Aramco Nano Permeameter ANP: A New Laboratory Technology for Accurate and Efficient Measurements of Stress-Dependent Source Rock Permeability
Authors: Liu Hui-Hai , Zhang Jilin , Boudjatit Mohammed 
Published: February 2022

Abstract
In an unconventional reservoir, rock matrix has a much larger storage capacity for hydrocarbon and significantly lower permeability than the natural and hydraulic fractures. It acts as a bottleneck for hydrocarbon flow from the reservoir to the production well during production and is a key parameter for controlling the well performance over a long period of time. A new laboratory technology is developed to accurately and efficiently measure the matrix permeability.
We have developed the Aramco Nano Permeameter (ANP), a new laboratory technology for measuring the stress-dependent source rock permeability. While the conventional laboratory methods can only measure one permeability data point with one test run, ANP, based on the nonlinear solution to the gas flow equation, measures the rock matrix permeability for a non-fractured sample as a function of stress using a single test run and thus is very efficient.
Permeability as a function of pore pressure at a given confining stress is measured with ANP for several Eagle Ford rock samples without fractures. The permeability curve shows complex behavior: permeability initially decreases with increasing pore pressure, as a result of Knudsen diffusion effect, and then increases with pore pressure owing to the mechanical deformation. The measured permeability curves are verified by comparing them with permeability values measured with other methods for selected pore pressures. The high measurement efficiency of ANP is also demonstrated.
In summary, ANP is a laboratory method that is based on a theoretical idea that is significantly different from those currently used by the industry and thus provides a high measurement efficiency that the conventional methods cannot achieve.
Machine Learning Empowered Well Placement in a Large Unconventional Tight Gas Field in China
Authors: Yu Ting , Wang Xiangzeng , Carrillat Alexis , Du Kuifu , Liang Quansheng , Grossmann Tino , Zhu Ming , Wang Gaige , Feng Lijun , Xue Jie , Quan Min , Saraiya Rasesh Krishnaraj 
Published: February 2022

Abstract
An undisclosed tight-gas field produces gas from a large heterogenous fluvial reservoir with limited well control in margins and appraisal areas, as well as sparse advanced logs (formation micro-imaging, magnetic resonance, or sonic tools, etc). The principal goal of this study is to provide a novel solution using machine-learning (ML) techniques to predict sandstone distribution and to some extent automate the process of optimizing well placement. This workflow overcomes low data quality, scaling, and inconsistency, and builds the bridge between geoscience and artificial intelligence (AI) software platforms.
This newly proposed solution provides a combination of ML and geological studies to optimize well placement. The key steps of this technology are:
Use unsupervised seismic waveform classification together with well logs to define sand body distribution and generate a reservoir risk map to support well planning. Construct a 3D grid with multiple variables to extract and integrate well logs and seismic attributes from existing 2D seismic lines for data organization and analysis. Set up the data transform mechanism to unlock restrictions of data analysis between subsurface domain and AI software platforms. Test multiple ML algorithms by carrying out a deep search to find seismic attributes that are the most sensitive to reservoir parameters and form the decision trees for quantitative analysis. Evaluate and select the high-performance results, export them into the subsurface software platform, and make the final property model available for integration and visualization to support well placement.
Multiple tests have been completed to date in this gas field, and the results showed that the technique can improve well placement, add potential reserve and also improve the efficiency of the workflow by reducing the execution time by 240 times. The results provide solid support to achieve more reliable and accurate well placement.
This new solution generates an improved reservoir risk map with flexibility of using many secondary variables or their combinations. It produces results with higher resolution and focuses on improving efficiency. It also reduces turnaround time and increases collaboration over conventional approaches by improving the accuracy of fast predictions as the data flow enriches the database rapidly, which unleashes big data potential. This innovative solution can be applied to other projects especially ML empowered well placements in complex geological settings.
A Novel Semi-Analytical Model for the Multiwell Horizontal Pad with Stimulated Reservoir Volume
Authors: Chu Hongyang , Ma Tianbi , Gao Yubao , Zhu Weiyao , Lee John 
Published: February 2022

Abstract
Recently, there have been many attempts to model the stimulated reservoir volume in unconventionls. However, most researches only focused on the intersecting hydraulic or natural fractures and the effects of stimulated reservoir volume are ignored. In this study, we developed a new method that uses an effective semi-analytical method to model the stimulated reservoir volume in unconventional reservoirs.
Large-scale hydraulic fracturing not only forms hydraulic fractures but also activates a large number of natural fractures in the near-well region. To the best of our knowledge, most of the multiwell horizontal pad modeling methods ignore the physics of stimulated reservoir volume. Our semi-analytical model has the ability to simulate the behaviors of a multiwell horizontal pad with irregular shaped stimulated reservoir volume and impermeable boundary. Results show that the transient pressure behavior of the multiwell horizontal pad with stimulated reservoir volume is significantly different from that of a single isolated well. The linear flow among wells, the pseudo radial flow of multiwell in stimulated reservoir volume, and transitional flow, and final pseudo radial flow of multiwell correspond to completely different transient pressure response. The high flow ability in stimulated reservoir volume means a faster rate of pressure diffusion and it lead to the appearance of these flow regions in advance. The results also confirm that as the scale of stimulated reservoir volume increase, the flow duration influenced by the stimulated reservoir volume is longer. The stimulated reservoir volume and offsetting wells makes the pseudo-radial flow feature insignificant. The pressure and the pressure derivative exhibit a gradual rise feature. For the pseudo-radial flow in stimulated reservoir volume, the horizontal line value is related to the total production of the well pad. For the unstimulated region, this value is also related to the mobility ratio.
Comprehensive Study on Newly Developed Diffusion-Desorption Models Based on Knudsen and Langmuir Models in Tight Gas Reservoirs
Authors: Alkuwaiti Hamda , Belhaj Hadi , Aldhuhoori Mohammed , Ghosh Bisweswar , Fernandes Ryan 
Published: February 2022

Abstract
Fluid flow in unconventional porous media is extremely complex due to the many physical processes and forces that governs fluid flow, such as diffusion, inertia, viscous flow, and sorption. Furthermore, modeling fluid flow in poor porous media often disregards the mentioned forces, assuming viscous transport is the predominant controller. This work introduces a new comprehensive flow model suitable for tight unconventional reservoirs, including viscous, inertia, diffusion, and sorption forces, to account for fluid transport in the three scales. The new model addresses 1-D linear flow in tight unconventional reservoirs and has been mathematically derived and numerically solved using MATLAB software and tested against a synthetic case study. The new models have been numerically solved and analyzed using synthetic data with previously published models that cater to the same phenomena and analyzed. In addition to studying the flow regimes effecting gas flow in porous media. It has been observed that the diffusion system becomes more prominent in regulating flow velocity with low permeability of the formation rock and low viscosity of the flowing fluid. Additionally, as a result, the sorption mechanism contribution to the flow increases with low permeability of the medium and low viscosity of the flowing fluid as it affects the concentration of gas, leading to release gas from being trapped in pores and rock surfaces.
Novel Multi-Stage Fracturing Sand Control Technology to Improve Completion Efficiency, Early Production and Reduce Well Cost
Authors: Gomez Ricardo , Khan Parvez , Stolboushkin Eugene 
Published: February 2022

Abstract
High pressure stimulation of tight sandstone formations is occasionally combined with flowback of proppant and formation sand during the onset of production. This is generally attributed to characteristics of unconsolidated sandstones and their response to high pressure hydraulic stimulation. This brings an additional challenge to openhole multi-stage completion systems that now require a filtration mechanism as part of the completion design, to introduce a sand exclusion technology alongside the multi-stage ball activated frac sleeves.
A novel openhole multistage fracturing system was developed combining the operational efficiency of ball activated frac sleeves with sand control efficiency of multi-membrane filtration sand screens. This combination of technologies deliver a robust completion design and a unique intervention-less solution to enable stimulation at high pressures and provide sand exclusion on production. The system comprises of a series of incrementally sized high strength disintegrating frac balls to activate and close stimulation frac sleeves while simultaneously also opening production sand control screens. The design allows for several production sand control screens in one stage to maximize reservoir contact for unrestricted production. The system allows to efficiently complete the frac treatment and start sand-free production of the well without any intermediate manipulation of downhole tools with coiled tubing (CT) or wireline.
This technology brings substantial value by not only early sand-free production, but also flexibility to add additional sand screens within the stage without compromising stage count. The intervention-less design of the tools eliminates the need for coiled tubing (CT) manipulation of downhole tools and hence associated high intervention costs. Keeping in mind the increased need of high-pressure stimulation for unconventional and tight reservoirs, the system is designed to 15,000 psi rating. The sand screens are designed to be isolated from stimulation pressure while maximizing inflow area without compromising on sand control. Further, to enable full efficiency, the system includes high-strength disintegrating frac balls to enable an early production of the well.
This paper encapsulates the design, functionality, and development testing of the intervention-less multistage fracturing sand control system. This novel technology is designed keeping in mind operator challenges associated with high cyclic stimulation pressure on completion tools, undesirable well intervention and associated high production costs.
The Impact of Horizontal Bedding Plane Fractures on Reservoir Fluid Production in Shale Oil Plays with High Pore Pressure
Authors: Arias Ortiz Daniela , Klimkowski Lukasz , Finkbeiner Thomas , Patzek Tadeusz W. 
Published: February 2022

Abstract
Massive hydraulic fracturing stimulation generates complex induced fracture systems in shale reservoirs. The complexity increases in mudrock plays characterized by overpressure and associated small differential stresses. Such conditions favor interactions between induced vertical hydraulic fractures and mechanically weak bedding planes. When these planes delaminate easily, they may hydraulically stimulate large horizontal fracture components. In such situations, weak bedding planes are critical during hydraulic fracture propagation, impacting the fracture geometry and associated hydrocarbon production. We examine the effect of stimulated mechanically weak horizontal bedding planes on reservoir fluid production in multilayered mudrock plays distinguished by high pore pressure. We propose two idealized but viable geometries (‘fracture scenarios’) reported to occur in some overpressured shale plays. Our reference scenario comprises only vertical and planar hydraulically induced fractures. In the second geometry, we add stimulated horizontal bedding plane fractures that intersect the vertical hydraulic fractures. Next, we integrate the predetermined fracture geometries into a commercial reservoir simulator (CMG-IMEX) and assess the wellbore flow performance. Finally, we perform sensitivity analyses on horizontal fracture closure-mechanism, position and number of horizontal fractures, and reduced vertical fracture permeability. The results reveal that large horizontal fractures compromise hydrocarbon production. We conclude that horizontal fracture compressibility and vertical hydraulic fracture permeability are critical parameters during reservoir simulation. Compared with the reference scenario, the unpropped (i.e., highly compressible) and large stimulated horizontal fractures may reduce the initial oil production by 13% and the cumulative oil production at 15 years by 10%, assuming the highly conductive vertical hydraulic fractures. In contrast, horizontal fracture propagation results in shorter and narrower vertical hydraulic fractures. Thus, the lowered vertical hydraulic fracture conductivity predicts that initial oil production may decline by up to 77%. Finally, we show that vertical and planar hydraulic fractures geometry is not always an accurate assumption. This assumption may lead to an overestimation of hydrocarbon production during shale reservoir simulation studies. Our unique reservoir simulations show a numerical justification for the massive stimulation jobs and the unexpectedly low hydrocarbon production obtained in several mudrock plays worldwide. Consequently, we demonstrate that massive fracturing treatments may not always be a successful development method in mudrock plays.