bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assisting Production Decision Technology in Gas Storage Operation Based on Digital Twin Technologies
Authors: Wang Peixian , Li Zunzhao , Wang Xiaolin , Wang Gang , Li Mingyi , Yao Shizhe 
Published: September 2022

Abstract
Underground gas storage (UGS) is a method to ensure safe and stable supply of natural gas in China. The digital twin technologies, also known as Industry 4.0 technologies, play a more and more important role in digital and intelligent development of UGS.
Based on digital twin technologies, the assisting production decision technology which contains data layer, model layer, logic layer, interaction layer, is constructed. The data layer covers data from SCADA, equipment detection, GIS, etc. Using laser point cloud scanning, oblique photography, and 3d design software, the 3D model in the model layer achieves one-to-one reduction of the ground process of UGS. The simulation model in the model layer integrates reservoir or reservoir boundary, wellbore, pipeline, ground process simulation model, which can realize the whole process simulation of UGS. The logic layer takes the data information stored in the data layer as input, and adopts programming language or algorithm model to analyze and evaluate the process and equipment of UGS. The interaction layer is the visual window of the system, which can realize the visualization and scenario-based interaction of data.
The assisting production decision technology fuses historical data, real-time data, and predicted data to track the past, monitor the present, and predict the future. Firstly, it integrates all the needed data with 3D models visually. Secondly, the total elements information perception technology, augmented reality technology, three-dimensional visualization monitoring technology, etc. are integrated to observe and study gas storage. Last but not least, the high fidelity model of gas storage digital twin also helps understand situation, monitor equipment energy consumption, and make optimization decision.
Integrating digital twin technologies into intelligent and digital management of gas storage, so as to facilitate the personalized management of gas storage.
Improved Well Spacing Decision Using RTA: Workflow to Translate RTA Half-Length to Actual Depletion
Authors: Muralidharan Vivek , Esmaili Soodabeh 
Published: September 2022

Abstract
Rate Transient Analysis (RTA) is widely used in the industry to understand the Stimulated Reservoir Volume (SRV) of horizontal wells for forecasting and for comparing well performance. However, significant well interferences are observed while using SRV dimensions obtained from analytical models in making well spacing decisions. The reason for that is the assumption of rectangular shape for SRV representation, which is not a realistic case. Upon drilling several pressure monitoring wells in the Permian Basin and comparing them with multiple diagnostic tools, we found that the actual SRV vertical drainage is not uniform. Inaccurate characterizations of fracture height and half lengths would result in either overcapitalizing the project or not draining the reservoir efficiently.
The objective of this study is to provide guidance for improving stacked development in the Permian Basin with the understanding of depletion patterns around individual wells both vertically and laterally. Pressure depletion profiles from several vertical monitoring wells in the Permian Basin are used to define the depletion patterns. Downhole microseismic data are also utilized to bridge any gaps. Several fully developed sections are used as case studies to validate the frac geometries and assumptions. The learnings from this study will be tremendously useful in applying RTA to optimize vertical and lateral spacing of unconventional wells across the Permian Basin.
Demonstration Numerical Simulation of Field-Scale CO2 Sequestration Project with Complex Faulting System in San Juan Basin, USA
Authors: Tu Jiawei , Ampomah William , Moodie Nathan , Ulmer-Scholle Dana , Martin Luke , Wells Elizabeth , Parwar Rajesh 
Published: September 2022

Abstract
San Juan Basin (SJB) is a geologic structural basin located in northwest New Mexico. Comprehensive field-scale reservoir simulation work was performed in finely constructed basin-wide geologic models, targeting sequestering over 120 million metric tons of CO2 for a period of 20 years. Petrophysical properties were populated through well logs and measurements on core samples obtained from nearby wells within the study area. Various critical storage trapping mechanisms were considered. The threshold pressure in delineating AoR is formulated based on guidance provided by the Environmental Protection Agency (EPA) to ensure the safety of underground drinking water sources (USDW). Besides, a complex faulting system identified on the west side of the basin was modeled to preclude risks of CO2 migration. The faulting system at the northwestern SJB was identified through well log stratigraphy. A near-vertical faulting system was mapped that may pose uncertainties to the sealing capacities of the caprock layer. The preliminary structural map shows a relatively flat topography that deepens to the east; and a high area in the west-northwest that is produced by faulting within a Hogback Monocline. The relief on the fault/monocline averages around 4,000 to 4,500 feet. Our simulation results indicate that SJB has the potential to safely contain the proposed amount of CO2 and avoid the impact of faulting systems. Further, pressure build-up in the injection zone is the most influential factor that may endanger the drinking water aquifer through the active injection and post-injection site care phases compared to CO2 plume migration. Controlling the size of AoR will increase the overall storage capacity within the area of interest while cutting down the overhead for corrective action planning and site monitoring.
This work employed realistic reservoir characterization data from San Juan Basin CarbonSAFE Phase III project to construct the reservoir simulation model, including 3D seismic, well logs, core analysis, and fluid sampling. As the worldwide commercial CO2 geologic storage projects aiming for soaring storage capacity goals, the processes in this work demonstrated the workflow to manage a large-scale CO2sequestration project in complex geological structured reservoirs.
Unlocking Stimulation Solution for Heavy Oil Production in Bentayan Structure Pertamina Hulu Rokan
Authors: Alfajri Reza , Sipahutar Herbert , Parsaulian Sakti , Herusakti S Adhi 
Published: September 2022

Abstract
Producing heavy oil requires more efforts than usual. Low degree of API, High viscosity, and high pour point make producing wells with this oil type quite challenging. B Structure in Pertamina faces this challenge. Its oil has 15-200 API, 10-300 cp viscosity, and 1150 F pour point. Producing the wells results in either low production rate or water coning. Seeking optimal stimulation solution was the main activities in this structure for the last eleven years.
The search of suitable stimulation method for Bentayan structure has been started in 2010. There were four types of stimulation methods attempted during 2010 – 2020 before successfully unlocking the most suitable method in aromatic solvent stimulation. The previous methods were surfactant, microbial, mutual solvent (musol), and thermochemical stimulation. Surfactant stimulation can reduce IFT and change rock wettability by injecting surfactant chemical into reservoir. Microbial stimulation injects microbial bacteria into reservoir and let it produces enzymes that have the same effect as surfactant as well as shortens the length of hydrocarbon chain to make the oil lighter. Musol stimulation removes heavy hydrocarbon deposits, controls rock wettability and IFT, and prevents emulsion from happening. Thermochemical stimulation mixes two types of chemicals generate heat into the reservoir preventing heavy oil reaches its pour point. The last and most successful method is aromatic solvent stimulation that can dilute asphaltene and wax content of heavy oil.
Surfactant method was performed on total 12 wells in two separate occasions in 2010-2012 and 2019. This method was a success from 8 wells and generated production gain from 1 to 50 bopd. Microbial stimulation method was performed in 2017-2018 on 2 wells. Only one well contributed oil production gain. Musol stimulation was performed in 2016 on 3 wells, and 2 of them were successful with oil production gain of 10 and 77 bbls/d. Thermochemical was then performed in 2020 on 1 well, however the result was not satisfactory. No oil production gain generated from this stimulation method. The most successful stimulation that has been tried in this structure is aromatic solvent. It has been performed on 10 wells so far and 8 of them were successful and oil production gain ranges from 20 to 300 bbls/d. Not only generating high production gain, this method also opened the door for optimization because there is increase in pump submergence.
The results from these stimulation jobs shows provide a solution for heavy oil production in Bentayan Structure in Pertamina Hulu Rokan. As aromatic solvent stimulation method in this structure produces the most significant results, it is considered the unlocked solution and has been selected as the standard treatment in producing heavy oil in Bentayan
A Flexible Design Approach to Improve Economics of Shale Well Pads: A Case Study from the Appalachian Basin
Authors: Kumar Hemant , Bhinde Tej , Popa Andrei , Hopkinson David , De Neufville Richard 
Published: September 2022

Abstract
Unconventional oil and gas projects are long-term, capital-intensive investments with significant risks due to various unknowns. The main uncertainties include reserves, reservoir quality, expected production, and commodity prices. Operating companies need to make decisions at the start of the project to design wells/facilities that impact production and economics throughout the project life. The system may be severely constrained at the start of production and have excess capacity in late field life based on design decisions often taken at the beginning with limited information. A novel approach to improve economic returns from shale pads is presented here using a flexible design concept. A physics-based integrated model is coupled with an economics model to demonstrate the system via a field example from the Appalachian Basin.
A typical pad in Appalachia has fixed capacity gas processing units (GPUs) installed for each well. The current design does not allow for expansion or reduction of processing capacity if the reservoir quality or commodity prices are different from expectations. A flexible design allows operators to redeploy processing capacity to other pads under favorable technical and market conditions (reservoir conditions and product prices), thus, decreasing average costs and increasing profitability.
An integration platform was used to couple an economic model with a physics-based integrated production model consisting of a pad's reservoir, well and surface network. The coupled models were used to generate short-term forecasts (2-3 years). Scenarios were run on the integrated model based on defined uncertainties such as reservoir characteristics and economics.
We evaluated two flexible options, rental GPU and in-house GPU augmentation which were compared with the current fixed design. The results demonstrate that flexible designs result in higher (&gt;5%) net present values (NPVs) for the project compared to fixed designs. Also, the flexible designs reduce the economic risk if the future market and operating conditions turn out to be unfavorable.
Optimizing Focused Reservoir Fluid Sampling Using a Deterministic Causation Artificial Intelligence Intuition Technology
Authors: Chakraborty Rabindra , Dong Chengli , Elshahawi Hani , Smith Jeroen , Ramaswami Shyam 
Published: September 2022

Abstract
Samples collected using Wireline Formation Testing (WFT) provide vital information throughout the lifetime of the reservoir. Contaminated samples can lead to erroneous fluid analysis results with potentially huge economic consequences. On the other hand, sampling operations need to be optimized to minimize the cost without compromising the quality of the collected fluid samples. Today the success of an operation depends on real time human interpretations of the fluid cleanup based on in-situ fluid properties as measured by insitu downhole sensors. There is a need for an application that can assist engineers to accurately infer the state of fluid contamination as well as recommend actions when an operation has gone astray.
We have developed and patented Intuition Technology, which is an advanced causation-based artificial intelligence framework designed to forewarn complex, hard to detect state changes in chemical, biological and geological systems. This paper describes the development of a WFT contamination forewarning application based on the Intuition Technology framework which de-risks the formation sampling process by advising real time decisions regarding the state of fluid contamination and recommending rate schedule or other changes that will help optimize the WFT operation. This application has potential to save millions of dollars per annum through operational optimization, value assurance, and risk mitigation.
History Matching and Forecasting Production Rate and Bottomhole Pressure Data Using an Enhanced Physics-Based Data-Driven Simulator
Authors: Li Ying , Alpak Faruk Omer , Jain Vivek , Lu Ranran , Onur Mustafa 
Published: September 2022

Abstract
For situations where performing reservoir management studies based on developing and running a full-scale reservoir simulation model is not plausible, physics-based and/or data-driven surrogate (or proxy) models may provide an attractive alternative. Recently, we developed a new physics-based data-driven model referred to as INSIM-BHP for reservoir flow and transport as a replacement for a reservoir simulator. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. INSIM-BHP delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. In this study, we present and investigate the application of INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and BHP data acquired daily in multi-perforated wells. Previous versions of INSIM were never used to history match such data sets. INSIM-BHP represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual time steps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new development is the use of time-variant well indices and skin factors within INSIM-BHP's well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. A novel modification has been made to the well-head term calculation better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut-in. We compare the history-matched oil rate and BHP data and forecasted results by INSIM-BHP with those from a commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells’ oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules. Besides, INSIM-BHP can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that INSIM-BHP simulations run more than ten-fold faster than a conventional reservoir simulator. Application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.
Stampede Digital Twin: An Advanced Solution for Process Equipment Condition Monitoring
Authors: Rodriguez Dryonis , Clare Paul , Srikonda Rohit , Suvarna Monika 
Published: September 2022

Abstract
A dynamic digital twin solution has been implemented to enable process equipment condition monitoring on key topsides equipment such as gas compressors, compressor suction and discharge coolers, seawater lift pumps, cooling medium coolers, and various filters. Equipment condition monitoring is enabled by performing virtual measurements, equipment degradation assessment and detection of anomalous process conditions.
The existing Stampede Multi-Purpose Dynamic Simulation model was repurposed as a real-time performance monitoring model. This model was connected to a historian to read real-time data enabling virtual measurement and equipment performance analysis. Dynamic online clustering of the process variables measured from field and rolling regression on the performance monitoring model output is performed to estimate the remaining useful life and detect anomalous process conditions.
Virtual measurements from the real-time digital twin gives more insight into the performance of the production facility, which helps operators and engineers more efficiently troubleshoot equipment issues. The proposed data analytics methodology is implemented on a Boost Gas Compressor (BGC) installed on the Stampede facility. Two years of historic data from the Stampede facility has been used for this case study to estimate remaining useful life and detect anomalous operation conditions that result in damage to the system eventually requiring a replacement or causing a shutdown. For the BGC case study presented, we were able to detect the anomalous operating conditions for the BGC about 6 days prior to a defect being detected by the maintenance crew on the discharge cooler. It is possible to avoid damage to the gas compression system if we can detect when the BGC is being operated in an anomalous operating condition and prevent early replacement of expensive equipment.
The proposed dynamic digital twin provides better insights for condition monitoring of equipment in an oil and gas facility using both the field sensor data and the physics-based models. In addition to performance deviation measurements, integration of field sensor data with physics-based models provides virtual measurement at locations where actual field sensors are not available. Dynamic clustering helps tackle the lack of information about gas molecular weight in real-time.
Methodology to Estimate Low Grade Enhanced Geothermal System (EGS) Reserves Using Heat Extracted from Depleted Wells in High Temperature Shale Gas Formations
Authors: Ehlig-Economides Christine , Nikolaou Michael , Khan Murtaza Ahmed 
Published: September 2022

Abstract
Eventually there will be low-production gas wells in the Haynesville and Eagle Ford shale formations that are no longer monetized. The objective of this study is to assess the potential for repurposing multiple transverse fracture horizontal wells (MTFHWs) in these formations as low-grade enhanced /engineered geothermal systems.
We use DrillingInfo and other available data, including formation temperature, to categorize existing gas wells as active, depleted, and still on production or abandoned, and to estimate an abandonment time for those still on production. Once the categorization is done, further study applies machine learning to quantify the current and future EGS potential of these wells. Finally, the results from the preceding studies are used to evaluate how best to distribute power plants for effective use of these resources, and to estimate how much power generation is possible.
The result of this research is a methodology for forecast of EGS power generation potential of low-grade EGS reserves in the Eagle Ford and Haynesville shale gas formations. This forecast addresses both technical and economic aspects. In effect, this work also provides a methodology for assessing the economic potential of EGS from existing MTFHWs in other formations having sufficiently high temperature for low-grade geothermal heat extraction.
This research provides input to support potential EGS development in Texas that could provide clean and affordable continuous (unfluctuating) power for small municipalities or industrial applications and/or as a contribution to the regional grid power supply.
Managing the High-Temperature Drilling Challenges of Deepwater HP/HT Wells: A Gulf of Mexico Case Study
Authors: Tchagop Alfred , Oyelami Opeyemi 
Published: September 2022

Abstract
High-pressure/high-temperature (HP/HT) drilling operations have unique challenges, which need to be carefully addressed. The need to address these challenges is because the search for additional hydrocarbon reserves is increasingly in the direction of frontier drilling.
Frontier drilling has more and more become an attractive option in the search for new hydrocarbon exploration and production. This drilling activity has been driven by the maturing of existing fields, the growing world demand for hydrocarbons, and technological advances. As proven fields are being depleted and because discoveries of giant fields have peaked, the greatest potential for new oil and gas discovery is in the frontier areas.
Frontier areas, defined as remote, hostile, and undrilled regions, are characterized by harsh climates or difficult environments. These environments include water depths greater than 2,000 ft, and downhole pressures and temperatures exceeding the equipment and tool ratings required to explore or develop those reservoirs.
The HP/HT environment limits the availability of equipment employed to operate safely and efficiently. The energy industry is constantly designing and developing equipment and operational workflows capable of operating in these HP/HT conditions.
This paper presents a systematic approach, which includes workflows and processes, to overcome the HT challenges in Gulf of Mexico (GOM) deepwater wells. The goal of these efforts is to enable safe and efficient drilling operations at temperatures greater than 302°F circulating bottomhole temperature.