bluuebunny/crossref_metadata_2025_split huggingface dataset:
Expert Advisory System for Production Surveillance and Optimization Assisted by Artificial Intelligence
Authors: Mata Carlos , Saputelli Luigi , Mohan Richard , Rubio Erismar , Al Selaiti Iman , Badmaev Dorzhi 
Published: December 2021

Abstract
Petroleum Engineers are usually responsible for 50-200 wells. The wells in highly instrumented fields generate 10-20 measurements every few seconds. This makes it difficult to be on top of every well, every day. This challenge carries a significant opportunity cost, therefore the surveillance process requires automation by implementing surveillance-by-exception. Faster identification of problems is great, but not enough unless the required activities are executed in a timely manner. The ability to execute quickly and safely requires a well-structured coordination effort between the different disciplines involved in field operations.
In line with ADNOC Digital Transformation strategy, the solution described in this paper intends to couple surveillance by exception (a Petroleum Engineering workflow) with field operations execution (a multi-disciplinary set of workflows in the field). The integration is achieved by creating a simple yet robust action tracking system, and feeding it automatically with new opportunities, so that it is kept up to date. Automatic diagnosis becomes opportunities. Opportunities become activities. Activities are assigned, executed and closed. All activities are tracked on a high level, which provides insights and visibility to all parties on who is doing what, when and how to close the opportunity.
The surveillance by exception engine consumes real time measurements from the historian. It then runs a set of soft sensors using full physics, reduced order models, proxy and data driven machine learning models, which utilize most of the measurements. The measured and calculated values are then fed to an expert system, which automatically diagnoses the wells and creates tickets with recommendations to the production engineer. The engineer reviews the ticket and forwards to field operations for execution. The log of activities enables a direct measure of operational effectiveness.
This paper describes the philosophy of the system, how it works, lessons learned and the results of implementation across 6 oilfields and 600+ wells in Abu Dhabi.
Case History: Hydraulic Workover Unit Utilized to Recover Highly Corroded 30-Year Old Completion from a Live Gas Well in the United Arab Emirates
Authors: Avila Aurelio Marcano , Raji Abimbola , Ottolina Renny , Jimenez Jose 
Published: December 2021

Abstract
In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface.
This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered.
The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides.
This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section.
In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production.
The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.
Compressor Upgrade on Existing Platform: A Study on Vibration from Structural Perspective
Authors: Teh See Yee , A Rahman Ahmad Rizal , Raja Badrol Raja Sharifuddin Ahmad , Muhammad Daud Mohd Hafis 
Published: December 2021

Abstract
Due to an increase in gas lift demand on an existing field in Sarawak, an existing Gas Lift Compressor (GLC) on the processing platform requires to be upgraded to meet incremental oil production requirement. These sets of compressors consist of 2x100% reciprocating compressors that were designed for 1.5 MMscfd each, with discharge pressure of 55.1 barg (800psig). The gas from these compressors is used mainly for gas lift at the processing platform as well as gas lift, instrument gas and utility gas at adjacent wellhead platforms. From the Conceptual Study, the existing compressors are not able to be retrofit for upgrade and is to be replaced with 2 × 100 % new gas engine driven compressor that capable of delivery 3.0 MMscfd of compressed gas each.
During the engineering stage of GLC package, Skid Dynamic Analysis has been carried out to evaluate the GLC skid structural design due to the operating dynamic load cases. The study recommended that the skid to be welded to the platform where the compressor is located to prevent the risk of high vibration. With the recommendation from Contractor's study, project team proceeded to carry out Structural Dynamic Analysis to assess the dynamic effect of the GLC skids to the platform deck. The Finite Element Analysis (FEA) results revealed that there are several modal modes mainly at the drilling deck and extension deck non-compliance to PTS guideline. Structural Dynamic Modification (SDM) and optimization was performed to dynamically stiffens the structures to shift the modal modes away from the operating range to fulfil PTS criteria. However, the SDM results was still unable to comply thus the need of Anti-Vibration Mounts (AVMs) is considered. Prior to application of AVMs, Structural Forced Response Analysis needs to be carried out to evaluate the risk of the system and confirm the requirement of the AVMs. Without the forced response analysis, the effect of AVMs, locations and numbers of AVMs cannot be addressed during the design study.
This paper will discuss the issues concerning vibration from reciprocating compressors upgrade on an existing platform, changes in the existing operating and design philosophy, challenges in addressing compressor installation and utilization of AVM from the perspective of Project Team. The paper will also provide key lessons learn and recommendation for future considerations in Compressor upgrades on existing facilities from a Structural Engineering point of view.
The project is currently at its detail design finalization and installation is expected to be completed by November 2021.
Investigation of Oil Presence and Wettability Restoration Effects on Sulfonated Polymer Retention in Carbonates Under Harsh Conditions
Authors: Alfazazi Umar , Chacko Thomas Nithin , Al-Shalabi Emad W. , AlAmeri Waleed 
Published: December 2021

Abstract
Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effect of oil presence and wettability restoration on polymer retention under harsh reservoir conditions of high temperature and high salinity (HTHS). An ATBS-based polymer was used for this study. Polymer single- and two-phase dynamic retention tests as well as bulk- and in-situ rheological experiments were conducted on Indiana limestone outcrops and in the presence of high salinity brine of 243,000 ppm at temperature of 50 °C. A total of four coreflooding experiments were conducted on core samples with similar petrophysical properties.
Bulk rheology tests showed that the polymer is stable at HTHS conditions. Also, polymer retention and in-situ rheology tests highlighted the significance of oil presence in the core samples where retention was found to be around 40-50 and 25-30 μg/g-rock in the absence and presence of oil, respectively. An additional 50% reduction in retention was further observed on a restored wettability (aged) core sample. Polymer inaccessible pore volume (IPV) was found to be high in the range of 23 to 28%, which was supported by the 1D saturation profiles obtained from the CT scanner. The ATBS-based polymer shows excellent results for applications in carbonates under harsh conditions without considerable polymer loss or plugging. This paper also provides valuable insights into the impact of oil presence and wettability restoration on polymer retention. Furthermore, this study shows that careful consideration of the latter factor is necessary to avoid unrepresentative and inflated polymer retention values in oil reservoirs.
Underground Gas Storage Process Optimization Using Integrated Subsurface Characterization, Dynamic Modeling and Monitoring - A Case Study
Authors: Li Longxin , Zhou Yuan , Li Limin , Tinnin* John , Peng Xian , Cranfield Colin , Luo Yu , Guises Romain , Zhao Yuchao , Wang Xia , Gui Feng , Burns Christopher , Yu Huijuan , Younessi Sinaki Ahmad Reza 
Published: December 2021

Abstract
Underground gas storage (UGS) will be key to addressing supply and demand dynamics as natural gas consumption grows during the coming decades in response to cleaner energy initiatives. The XGS facility began UGS operations in a depleted gas field located in SW China in 2013. Following this initial period of utilization, the site was reassessed to safely increase deliverability during winter months to meet future peak gas demand.
The XGS field is located in a high tectonic stress region and has a structurally complex and highly faulted geological setting. The carbonate reservoir is heterogeneous and naturally fractured. Initial assessment steps involved determination of maximum storage capacity and estimation of required working gas and cushion gas volumes using fully integrated geological, geophysical, petrophysical frameworks. Geomechanical modeling was embedded into the analysis to determine the long-term impact inferred by cyclical variations of pressures on the reservoir performance and cap rock containment and evaluate both safe operating pressure limits and monitoring requirements.
The coupling of complex reservoir and geomechanical parameters was required to create a dynamic model within the stress regime that could be history-matched to the early gas depletion phase and subsequent gas storage cycles. Such a holistic approach allows the operator to optimize the number of wells, their placement, trajectories and completion designs to ensure safe and efficient operations and develop strategies for increasing withdrawal rates to meet anticipated future demand. Additionally, tight integration of subsurface understanding with surface requirements, such as turbo-compressors, is critical to meet the UGS designed performance and deliverability objectives and ensure sufficient flexibility to optimize the facility usage.
A further important task of the final phase of UGS facilities design involves enablement of sustainable operation through a Storage Optimization Plan. The results of the analyses serve as a basis for the design of this plan, in combination with fit-for-purpose surveillance systems of the reservoir and cap-rock seal recording pressure, rock deformation and seismicity in real time, along with regular wellbore inspection.
Unconventional Drilling and Creative Solutions Delivered World Record a Multi-Laterals Fishbone all Legs Drilled, Accessed and Stimulated First Attempt - Case Study from Kuwait
Authors: Farhi Nadir , Abdel Samie Mohamed Ahmed , Nouh Walid Saher , Ibrahim Hamdi Saber , Al-Ajmi Hadi Saad , Khan Youcef Mohammed , Merza Abdullah Jaffar , Hussain Talal Abdulhameed 
Published: December 2021

Abstract
Despite being the first area for oil to be found in Kuwait in mid 1930's, Bahra's oil production remained largely unexploited until 2015, when a major development campaign targeting one of its tight carbonate reservoirs through horizontal drilling and multi-stage frack completions was commissioned. Nonetheless, with the development and exploration initiatives underway, surface congestion is the primary challenge. As the number of wells increased the need for unconventional well profiles became more demanding. The multi-lateral fishbone approach was designed to have a total of four laterals with approximately 3000 ft each. Lessons learned from previous level-1 multi-laterals drilled in North Kuwait indicated that the primary challenge remained to be the ability to drill a smooth bore hole profile across the junctions to successfully re-access and stimulate all the drilled legs with coil-tubing to maximize production.
Kuwaiti Operator Reservoir and study team were looking for an alternate solution to increase the production in Bahra using multi-laterals technics in the same reservoir to stimulate and sustain production in calcite reservoir. Historically only three wells were drilled experimenting challenges and failures to open hole sidetrack leading to have long time to complete the wells with maximum 3 legs as record including the mother hole. RST team asked to drill a well with 4 legs, each leg following the same azimuth with the condition to be 300 ft apart. The thorough planning exercise completed and the close follow-up to the approved design of service during execution phase resulted in the successful delivery of the first four legs fishbone in Kuwait with Zero Non-Productive Time. In addition to achieving all the geological targets, the smooth borehole profile helped ensure successful re-entry and stimulation of all four legs in the same run achieving the well challenge using the unique
Case Studies of Digitalized Locate the Remaining Oil Workflows Powered by Hybrid Data & Physics Methods
Authors: Kuzmichev Dmitry , Moradi Babak , Mironenko Yulia , Hadian Negar , Lazar Raffik , Alessio Laurent , Rahmat Faeez 
Published: December 2021

Abstract
Mature fields already account for about 70% of the hydrocarbon liquids produced globally. Since the average recovery factor for oil fields is 30 to 35%, there is substantial quantities of remaining oil at stake. Conventional simulation-based development planning approaches are well established, but their implementation on large, complex mature oil fields remains challenging given their resource, time, and cost intensity. In addition, increased attention towards reduce carbon emissions makes the case for alternative, computationally-light techniques, as part of a global digitalisation drive, leveraging modern analytics and machine learning methods.
This work describes a modern digital workflow to identify and quantify by-passed oil targets. The workflow leverages an innovative hybrid physics-guided data-driven, which generates historical phase saturation maps, forecasts future fluid movements and locate infill opportunities. As deliverables, a fully probabilistic production forecast is obtained for each drilling location, as a function of the well type, its geometry, and position in the field. The new workflow can unlock remaining potential of mature fields in a shorter time-frame and generally very cost-effectively compared to the advanced dynamic reservoir modelling and history-match workflows.
Over the last 5 years, this workflow has been applied to more than 30 mature oil fields in Europe, Africa, the Middle East, Asia, Australia, and New Zealand. Three case studies’ examples and application environments of applied digital workflow are described in this paper. This study demonstrates that it is now possible to deliver digitalized locating the remaining oil projects, capturing the full uncertainty ranges, including leveraging complex multi-vintage spatial 4D datasets, providing reliable non-simulation physics-compliant data-driven production forecasts within weeks.
Assess Digital Maturity to Set Digital Transformation Strategy in Oil and Gas
Authors: Torre Mario , Azancot Analyn , Florez Fabián , Zhou Wei 
Published: December 2021

Abstract
This paper presents a structured methodology for an oil company to embark on a digital transformation. It was implemented in several JVs with a NOC that includes three producing blocks with dozens of mature fields.
The methodology has several key unique strengths: One is the ability to isolate the core-money-making processes and build a digital strategy around them. This shows early gains and at the same time becomes a buy-in support for management. Another advantage is the simplicity to define the "desired" digital maturity level using direct input from the final stakeholders. This is achieved by using the process enhancement method, a SIPOC technique (Supplier, Input, Process, Output, Customer analysis). Also, an important strength is the methodology does not ignore the existing IT infrastructure, nor the field systems (i.e., SCADA) and re-uses them, as much as possible, giving enough time for a transition or an upgrade when needed.
Several tools are provided in this paper that makes the methodology consistent, auditable, and strong to support the designed digital strategy to any management level with high chance of approval. The methodology is flexible enough to be run on various types of contracts, hydrocarbon phase or operational environments.
As with any method, it relies on commitment from the top and base line in the organization, requiring open and honest evaluation of current inefficiencies and, equally important, resources (budget and people).
In summary, a digital transformation is not a sudden leap from a company's current analog status to an instantaneous digital state of being. Rather, it is a progressive, step-by-step transition of core processes and user-centric workflows that requires careful planning and a thoughtful methodology to find the most suitable scenario for each company.
Fulfillment of Maintenance and Reliability Key Performance Indicators of Offshore Sites During Covid-19 Pandemic
Authors: Hussein Huda , Al Blooshi Shamsa , Saeed Waled , Al Salami Abdulla , Al Rais Masab , Herzallah Mohamed , Al Wahedi Mohamed 
Published: December 2021

Abstract
This paper addresses the challenging situation that was faced by Maintenance Teams in Offshore Sites to maintain and ensure the optimal conditions of the plants, conducting Routine Preventative Maintenance (RPM) as planned, achieving Company and Operational Excellence KPIs in the midst of COVID-19 pandemic. A brief description of how the sites defined a new normal given the circumstances to ensure all work was met while tackling the numerous obstacles in order to keep operations running smoothly is iterated below.
Identification of Patches of Bitumen in a Carbonate Reservoir: A Case Study
Authors: Igogo Arit , El Sahn Hani , Khan Sara Hasrat , Bhushan Yatindra , Al Mazrooei Suhaila Humaid , Lehmann Christoph , Alwahedi Mohamed Abdulhameed 
Published: December 2021

Abstract
Carbonate reservoir X has varying levels of maturity in terms of development. The South/West is highly matured; development activities have recently kicked-off in the Crestal part while the areas towards the Far North is not fully developed and posed the largest uncertainty in terms of reservoir quality, fluid contacts, oil saturation, well injectivity/ productivity, area potential and reserves due to poor well control. In reservoir X with segmented development areas, patches of bitumen have been found in the Far North. The extent of this Bitumen was unknown. In order to expand the CO2 development concept to achieve production target from the Far Northern flank, an understanding and mitigation of the area uncertainties is crucial.
Reservoir bitumen is a highly viscous, asphaltene rich hydrocarbon that affects reservoir performance. Distinguishing between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity and density contrast between the reservoir bitumen and light oil makes it difficult, if not impossible, to make such differentiation using only conventional logs such as neutron, density, and resistivity.
This paper highlights the utilization and integration of advanced logging tools such as nuclear magnetic resonance and dielectric, in conjunction with routine logs, pressure points, RCI samples, vertical interference test and core data to differentiate between reservoir bitumen and other hydrocarbon types in the pore space.
The major findings from the studies shows bitumen doesn't form as a single layer but occurs in different subzones as patches which is a challenge for static modelling. When high molecular weight hydrocarbons are distributed in the pore space and coexist with light and producible hydrocarbons, reservoir bitumen is likely to block pore throats. The Bitumen present in this reservoir have a log response similar to conventional pore fluids.
The outcome of this study has helped in refining the bitumen boundary, optimize well placement, resolved the uncertainties associated with deeper fluid contacts and provided realistic estimate of STOIIP.
Inline Drilling Fluid Property Measurement, Integration, and Modeling to Enhance Drilling Practice and Support Drilling Automation
Authors: Roy Sanjit , Kamal Saiyid Z. , Frazier Richard , Bruns Ross , Hamlat Yahia Ait 
Published: December 2021

Abstract
Frequent, reliable, and repeatable measurements are key to the evolution of digitization of drilling information and drilling automation. While advances have been made in automating the drilling process and the use of sophisticated engineering models, machine learning techniques to optimize the process, and lack of real-time data on drilling fluid properties has long been recognized as a limiting factor. Drilling fluids play a significant function in ensuring quality well construction and completion, and in-time measurements of relevant fluid properties are key to automation and enhancing decision making that directly impacts well operations.
This paper discusses the development and application of a suite of automated fluid measurement devices that collect key fluid properties used to monitor fluid performance and drive engineering analyses without human involvement. The deployed skid-mounted devices continually and reliably measure properties such as mud weight, apparent viscosity, rheology profiles, temperatures, and emulsion stability to provide valuable insight on the current state of the fluid. Real-time data is shared with relevant rig and office- based personnel to enable process monitoring and trigger operational changes. It feeds into real-time engineering analyses tools and models to monitor performance and provides instantaneous feedback on downhole fluid behavior and impact on drilling performance based on current drilling and drilling fluid property data. Equipment reliability has been documented and demonstrated on over 30 wells and more than 400 thousand ft of lateral sections in unconventional shale drilling in the US. We will share our experience with measurement, data quality and reliability. We will also share aspects of integrating various data components at disparate time intervals into real-time engineering analyses to show how real-time measurements improve the prediction of well and wellbore integrity in ongoing drilling operations. In addition, we will discuss lessons learned from our experience, further enhancements to broaden the scope, and the integration with operators, service companies and other original equipment manufacturer in the domain to support and enhance the digital drilling ecosystem.