bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of an Online Soft Analyzer for the Continuous Analysis of BTEX Emissions from the Furnace of Sulfur Recovery Units
Authors: Dara Satyadileep , Ibrahim Salisu , Jagannath Anoop , Raj Abhijeet , Khan Ibrahim , Al Jenaibi Eisa 
Published: December 2021

Abstract
The oxidation of Benzene, Toluene, Ethylbenzene, and Xylenes (BTEX) in the furnace of SRUs at high temperature is an effective solution to prevent Claus catalyst deactivation in the downstream catalytic converters. However, the existing SRUs do not have the means to monitor BTEX emissions from Claus furnace due to lack of commercial online analyzers in the market. This often leads to excessive temperatures up to 1150 °C in the furnace to ensure BTEX destruction. Such high temperatures increase fuel gas consumption and CO emission and reduce sulfur recovery efficiency. To obtain continuous BTEX indication at the furnace exit, an online BTEX soft sensor model is developed to predict BTEX concentration at furnace exit. Subsequently, this soft sensor will be implemented in one of the SRUs of ADNOC Gas Processing. The BTEX soft sensor has been developed by constructing a compact kinetic model for aromatics destruction in the furnace based on the understanding of BTEX oxidation mechanisms derived using a detailed and well validated kinetic model developed previously. The kinetic model, including its rate parameters were incorporated into Hysys/Sulsim software, where both the reaction furnace and catalytic converters were simulated. The BTEX soft sensor has been validated with plant data from different ADNOC Gas Processing SRU trains under a wide range of feed conditions (particularly, with varying relative concentrations of H2S, CO2, and hydrocarbons in acid gas feed) in order to ensure its robustness and versatile predictive accuracy. The model predicts BTEX emissions from the reaction furnace under a wide range of operating conditions in the furnace with deviation not exceeding +/- 5 ppm. It also predicts the reaction furnace temperature (with a deviation of +/- 5%) and species composition from the furnace exit within a reasonable error margin. Presently, the model is in the process of being deployed in one of the SRUs of ADNO Gas Processing as an online soft sensor, where it can read the feed conditions, predict the BTEX exit concentration and write this value to the DCS. Thus, plant operators can monitor BTEX exit concentration on continuous basis and use it as a reliable basis to lower fuel gas co-firing rate in the furnace to achieve optimum furnace temperature that provide efficient BTEX destruction and low CO emission. The online soft analyzer, when deployed in SRU, will continuously predict BTEX emission from SRU furnace with high accuracy, which cannot be done experimentally in the plant or reliably using most of the existing commercial software. This approach can be used to seek favorable means of optimizing BTEX destruction to enhance sulfur recovery, while decreasing fuel gas consumption and carbon footprint in sulfur recovery units to reduce operating cost.
Understanding the Flow Dynamics of CO2 Plumes in the Subsurface
Authors: Bebb Florence Letitia , Evans Kate Clare Serena , Mukherjee Jagannath , Saeed Bilal , Christopher Geovani 
Published: December 2021

Abstract
There are several significant differences between the behavior of injected CO2 and reservoired hydrocarbons in the subsurface. These fundamental differences greatly influence the modeling of CO2 plumes.
Carbon capture, utilization, and storage (CCUS) is growing in importance in the exploration and production (E&P) regulatory environment with the Oil and Gas Climate Initiative (OGCI) making CCUS a priority. Companies need to prospect for storage sites and evaluate both the short-term risks and long-term fate of stored carbon dioxide (CO2).
Understanding the physics governing fluid flow is important to both CO2 storage and hydrocarbon exploration and production. In the last decade, there has been much research into the movement and migration of CO2 in the subsurface. A better understanding of the flow dynamics of CO2 plumes in the subsurface has highlighted a number of significant differences in modeling CO2 storage sites compared with hydrocarbon reservoir simulations. These differences can greatly influence reliability when modeling CO2 storage sites.
Prediction and Optimization of WAG Flooding by Using LSTM Neural Network Model in Middle East Carbonate Reservoir
Authors: Huang Ruijie , Wei Chenji , Li Baozhu , Yang Jian , Wu Suwei , Xu Xin , Ou Yajie , Xiong Lihui , Lou Yuankeli , Li Zhengzhong , Deng Ya , Zhang Chenjun 
Published: December 2021

Abstract
Production prediction continues to play an increasingly significant role in reservoir development adjustment and optimization, especially in water-alternating-gas (WAG) flooding. As artificial intelligence continues to develop, data-driven machine learning method can establish a robust model based on massive data to clarify development risks and challenges, predict development dynamic characteristics in advance. This study gathers over 15 years actual data from targeted carbonate reservoir and establishes a robust Long Short-Term Memory (LSTM) neural network prediction model based on correlation analysis, data cleaning, feature variables selection, hyper-parameters optimization and model evaluation to forecast oil production, gas-oil ratio (GOR), and water cut (WC) of WAG flooding. In comparison to traditional reservoir numerical simulation (RNS), LSTM neural networks have a huge advantage in terms of computational efficiency and prediction accuracy. The calculation time of LSTM method is 864% less than reservoir numerical simulation method, while prediction error of LSTM method is 261% less than RNS method. We classify producers into three types based on the prediction results and propose optimization measures aimed at the risks and challenges they faced. Field implementation indicates promising outcome with better reservoir support, lower GOR, lower WC, and stabler oil production. This study provides a novel direction for application of artificial intelligence in WAG flooding development and optimization.
Monitoring of Methane Emissions in Oil and Gas from Space: Matching Needs with Satellite System Capability, and Advantages of High Resolution Monitoring
Authors: Gauthier Jean-Francois 
Published: December 2021

Abstract
Satellites are a powerful tool in monitoring methane emissions around the world. In the last five years, many new systems have been both announced and deployed, each with different capabilities and designed for a specific purpose. With an increase in options also comes confusion as to how these systems can and should be used, especially in meeting the needs of the oil and gas industry. This paper will examine the different satellite systems available and explain what information they are best suited to provide.
The performance parameters of several current and future satellite systems will be presented and supported with recent examples when available. For example, the importance of factors like frequency of revisit, detection threshold, and spatial resolution will be discussed and contrasted with the needs of the oil and gas industry in gaining a more complete understanding of its methane emissions and enabling action to mitigate them.
Results from GHGSat's second generation of high-resolution satellites displaying measurements of methane plumes at oil and gas facilities around the world will be presented to demonstrate some of the advantages of the technology. These two satellites, GHGSat-C1 and C2 (Iris and Hugo), were launched in September 2020 and January 2021 respectively and have started delivering a tenfold improvement in performance after incorporating the lessons learned from their predecessor, GHGSat's demonstration satellite Claire.
Finally, the ability of these systems to work together and complement each other's capabilities to provide actionable insight to the oil and gas industry will be discussed.
Mitigation of Gas Condensate Banking Using an Integrated Chemical Approach
Authors: Hassan Amjed Mohammed , Mahmoud Mohamed Ahmed , Al-Nakhli Ayman Raja 
Published: December 2021

Abstract
In gas reservoirs, the well production can be reduced due to the development and accumulation of condensate in the near-wellbore zone. Various techniques are used to minimize the condensate damage and maintain hydrocarbon production. Hydraulic fracturing and wettability alteration techniques are the most effective methods. However, these techniques are expensive, especially in deep gas reservoirs. This paper introduces a new approach for mitigating condensate accumulation by integrating the hydraulic fracturing and wettability alteration treatments. The efficiency of two chemicals that can generate multiple fractures and alter the fracture surfaces to less condensate status is investigated in this work. Thermochemical fluids and chelating agent solutions are used to mitigate the condensate damage and improve gas production for the long term. Several laboratory measurements were carried out to study the performance of the proposed approach; coreflooding, zeta potential, and nuclear magnetic resonance (NMR) experiments were conducted. The chemicals were injected into the tight rocks to recover the condensate and improve the flow conductivity. Zeta potential was performed to assess the rock wettability before and after the chemical injection. Moreover, the changes in pores network due to the chemical treatments as analyzed using the NMR technique. Thermochemical treatment removed around 66% of the condensate liquid, while the chelating agent reduced the condensate saturation by around 80%. The main mechanism for condensate removal during thermochemical flooding is the generation of micro-fractures that increase the rock permeability and improve the condensate flow. On the other hand, chelating agents can alter the rock wettability toward less oil-state, leading to considerable recovery of the condensate liquid utilizing a wettability alteration mechanism. Finally, an integrated approach is suggested to injecting thermochemical fluids followed by chelating agent solutions. The proposed technique can lead to generating micro-fractures of less oil-wet surfaces, consequently, the condensate bank can be removed by more than 90%.
A Comprehensive Study Developing and Maximizing the Recovery of Gas Condensate from a Giant Onshore Abu Dhabi Gas Field Utilizing Advanced Condensate Tracking, Gas Injection and Drilling Strategies in Next-generation Commercial Numerical Simulator
Authors: Bernadi Bondan , Mohamed Ihab Nabil , Bairaq Ahmed Mohamed Al , Hosani Mariam Ahmed Al , Abdullayev Azer , Roopal Allen 
Published: December 2021

Abstract
A comprehensive study of a giant onshore Abu Dhabi gas field using a next-generation commercial numerical simulator has been conducted. The objective was to identify the distribution and track the movement of the gas condensate in the reservoir, and to develop strategies to minimize the condensate drop-out and improve condensate recovery from the field.
The field contains a large gas cap and an oil rim. We have identified the distribution of the gas condensate throughout the reservoir and were able to track its movement using the advanced fluid tracking option in the simulator. Once the gas condensate drop-out regions in the reservoir are identified, sensitivity runs with localized changes are carried out to improve the recovery from the reservoir. The strategies to mitigate drop-out include adding infill wells, drilling multi-lateral wells, reinjecting CO2 and dry gas into the reservoir, and hydraulic fracturing near the well bore.
We were able to track the distribution of the condensate throughout the reservoir and identified key condensate drop-out regions. Adding infill wells improved the recovery of the condensate. Implementing multi-lateral wells also showed improved condensate recovery in the field. Hydraulic fracturing near the wellbore reduced condensate banking near the wellbore. Injecting dry gas improved the condensate recovery by a re-vaporization process where the liquid condensate is absorbed by dry gas.
This paper discusses a comprehensive study on tracking the condensate distribution in a giant onshore field using a commercial simulator. The authors have performed a thorough investigation to identify an optimal condensate recovery strategy for the field, by comparing various recovery strategies using the full field reservoir simulation model.
Cost-Efficient De-Bottlenecking of Produced Water Treatment Systems through the Application of a Single Technology, Eliminating the Need for Hydrocyclones and Degassing Drums
Authors: Asdahl Steinar , Jansen van Rensburg Johann , Waag Martin Einarson , Glenna Nilssen Rune 
Published: December 2021

Abstract
Traditionally, produced water from production separators is handled by multiple steps and different technologies in order to meet the required quality for either discharge or reinjection of the water.
The development of the latest Compact Flotation Unit (CFU) technology has unlocked the potential for savings on cost, complexity, footprint and weight for the produced water treatment system.
The developed CFU technology has proven applicable through field testing as a single treatment technology for reducing Oil-in-Water (OiW) content directly from tie-in at separator and still meet stringent requirements for outlet OiW quality.
Field tests were conducted with inlet OiW concentration ranging from 200-2000 ppm, achieving results in the range 2.5 to 21 ppm only with a two-stage latest generation CFU.
Compared to a traditional produced water system setup consisting of de-oiling hydrocyclones and a horizontal degassing vessel, the savings in footprint and operational weight is estimated to 54 % and 53 % respectively utilizing a two-stage CFU for a system with a design capacity of 76.000 BWPD.
Furthermore, the development of the latest generation CFU technology has enabled the retrofit concept, incorporating the developed CFU internals into existing gravity separation based produced water vessels, converting them to more efficient flotation vessels with increased capacity. For brownfield and debottlenecking applications, operators are challenged by increasing water cut from maturing wells, and as a result exceeding the facilities design capacity for produced water treatment. This challenge is often further reinforced by increasingly stricter environmental legislation for OiW content for discharge or re-injection. The retrofit concept will offer a highly cost-, footprint- and weight-efficient solutions to these challenges utilizing existing vessels.
Benefits of the retrofit concept: Bring proven and unique performance of the technology to other produced water separation vessels helping the operators improve the separation efficiency and increase throughput while meeting discharge requirementsShort execution time compared to installation of new process equipmentLow cost compared to installation of new process equipmentUtilization of existing equipment saves valuable footprint.
Migration to Cased Hole Petrophysics: Are We Ready?
Authors: Bustos Ulises , Duran Carlos , Duarte Alexander , Salguero Alfonso , Vasquez Yira , Chapellin Alvaro , Quinapallo Erika 
Published: December 2021

Abstract
In the present Oil & Gas business context, the uncertainties reduction for hydrocarbon production increase in an operational costs and risk reduction scheme, are among the main drivers in several operating companies in the northern region of South America (Colombia & Ecuador). Electrical logging and drilling tools stuck events due to differential pressures, fishing operations, high wellbore tortuosity, difficult geometries and unconsolidated formations affecting wellbore stability, are among the main problems increasing non-productive time and operating costs. Minimizing open hole operations with a full migration to cased hole data acquisition, providing inputs for petrophysical uncertainty reductions without jeopardizing well completion decisions or initial reservoir characterization, would constitute an attractive solution for operators. Following those initiatives, we start by achieving a complete open hole formation evaluation and then migrating to case hole data acquisition and petrophysical assessment while benchmarking against open hole results. Low and variable formation water salinity, complex mineralogy's affecting resistivity and radioactive minerals, are common petrophysical challenges in our reservoirs. We had to implement Archie and salinity-independent formation evaluation solutions with cased hole technologies and in absence of open hole logs.
The open hole petrophysics consist on simultaneous assessment of matrix and fluids saturations, while evaluating the oil mobility and water cut with the incorporation of multi-depth of investigation sensors in single logging runs (spectroscopy, dielectric dispersion, and magnetic resonance). We then moved to cased hole formation evaluation, with spectroscopy & nuclear-based petrophysics in gas, light oil, and heavy oil-bearing reservoirs. By implementation of non-archie fluids volumetric computation (that relies on conversion of dry weight total carbon to oil saturation and fast neutron cross section to gas saturation- done through a simultaneous inversion by solving matrix-porosity-fluids volumes into an elemental analysis), we obtained a representative formation saturation range behind casing. We then discussed on the different scenarios were migrating to cased hole is sustainable and its potential limitations.
Geo-Thermo-Mechanical Modeling of Pre-Drilled Wellbores to Extract Geothermal Energy from Subsurface to Produce Cleaner Energy for United Arab Emirates
Authors: Ansari Ubedullah , Soomro Najeeb Anjum , Narejo Farhan Ali , Baloch Shafquat Ali , Talpur Faiz Ali 
Published: December 2021

Abstract
The middle eastern countries including United Arab Emirates (UAE) have enjoyed the energy production from hydrocarbon resource for a very long period. Indeed, now various countries in this region has shifted to alternative resources of power generation with cheaper and cleaner sources. Geothermal is the top of the list among those sources. Therefore, this study presents an ultimate model converting abandoned oil and gas wells into subsurface geothermal recovery points.
Fundamentally, this study offers a geo-thermo-mechanical model of abandoned wellbore which can help in developing an optimistic geothermal energy not only from subsurface thermal reserve but also from abandoned casing and pipes installed in Wellbores. In this approach the source of heat is thermally active rock formations and the metallic pipes that are present in wellbores drilled through hot dry rocks. In the model the already drilled wells are incorporated as medium of heat flow in which water in injected and brought back to surface along with thermal impact.
The results of this study revealed that, at the depth of 6000 m of high temperature wellbore the temperature is above 85°C and at this temperature the metallic casings further rise the reserve temperature thus the conversion of water into steam can be processed easily. Moreover, at high depths the stability of wellbore is also issue in high temperature formation, so mechanical model suggests that injection of water and conversion into steam in already cased wellbore can sustain up to 6 MPa stress at around 100C. Thus, the geo-thermo-mechanical model of wellbore will illustrate the possibility of converting water into steam and it will also reveal the average amount of heat that can be generated from a single well. henceforth, the thermal recovery from abandoned wells of UAE is best fit solution for clean energy.
The abandoned wells are used as conduit to transport heat energy from subsurface by using water as transport medium, as water at surface temperature is injected in those wellbores and let thermal energy convert that water into steam. Later the steam is returned to surface and used as fuel in turbines or generators.
Using Seismic Data to Predict Shale Pore Pressure and Overpressure Sweet Spots: A Case Study from the Lower Silurian Longmaxi Formation in Sichuan Basin, China
Authors: Chen Sheng , Zeng Qingcai , Wang Xiujiao , Yang Qing , Dai Chunmeng , Li Wenke , Jiang Ren 
Published: December 2021

Abstract
Practices of marine shale gas exploration and development in south China have proved that formation overpressure is the main controlling factor of shale gas enrichment and an indicator of good preservation condition. Accurate prediction of formation pressure before drilling is necessary for drilling safety and important for sweet spots predicting and horizontal wells deploying. However, the existing prediction methods of formation pore pressures all have defects, the prediction accuracy unsatisfactory for shale gas development. By means of rock mechanics analysis and related formulas, we derived a formula for calculating formation pore pressures. Through regional rock physical analysis, we determined and optimized the relevant parameters in the formula, and established a new formation pressure prediction model considering P-wave velocity, S-wave velocity and density. Based on regional exploration wells and 3D seismic data, we carried out pre-stack seismic inversion to obtain high-precision P-wave velocity, S-wave velocity and density data volumes. We utilized the new formation pressure prediction model to predict the pressure and the spatial distribution of overpressure sweet spots. Then, we applied the measured pressure data of three new wells to verify the predicted formation pressure by seismic data. The result shows that the new method has a higher accuracy. This method is qualified for safe drilling and prediction of overpressure sweet spots for shale gas development, so it is worthy of promotion.
Petroleum Development Oman Forecasting Management System
Authors: Al Riyami Hilal Mudhafar , Al Sheibani Hilal Mohammed , Al Subhi Hamed Ali , Al Ajmi Hussain Taqi , Zohny Zeinab Youssef , Al Kindy Azzan Qais 
Published: December 2021

AbstractProduction performance forecasting is considered as one of the most challenging and time consuming tasks in petroleum engineering disciplines, it has important implications on decision-making, planning production and processing of facilities. In Petroleum Development Oman (PDO), which is the major petroleum company in Oman, production forecast provides a technical input basis for the economic decisions throughout the exploration and production lifecycle. Reservoir engineers spend more than 250 days per year to complete this process. PDO Forecast Management System (FMS) was introduced to transform the conventional forecasting of gas production. Employing the latest state-of-the-art technologies in the field of data management and machine learning (ML), PDO FMS aims at optimizing and automating the process of capturing, reporting, and predicting hydrocarbon production. This new system covers the full forecast processes including long and short-term forecasting for gas, condensate, and water production. As a pilot project, PDO FMS was deployed on a cluster of 272 wells and relied on agile project management approach to realize the benefits during the development phase. Deployment of the new system resulted in a significant reduction of the forecasting time, optimization of manpower and forecasting accuracy.