bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multilateral Technology in the Middle East: 25 Years of Evolution
Authors: Kelsey Matthew , Fanchin Thomas , Janzen Micah , Alharbi Bandar 
Published: October 2022

Abstract
For a quarter of a century sustained technological advances in multilateral technology have enhanced economics and extended the production life of fields in the Middle East. This was accomplished by evolving to meet the demands of increasingly complex applications.
Over this history, multilateral applications have evolved from standard Level 2 and Level 4 dual-laterals to dual-laterals with intelligent flow control, intervention capabilities, and improved junction integrity. The use of multilateral technology can deliver a significant increase in reservoir contact compared to single horizontal wells. A dual-lateral well can deliver twice the reservoir contact while eliminating the drilling, casing, and cementing of an additional vertical wellbore section. Operators are implementing multilateral field strategies to reduce overall development cost, cycle times, and carbon footprint. Further benefits include delivery of wells and facility systems using fewer in-field construction hours at a lower baseline cost.
This paper discusses several multilateral installations in the Middle East over a 25-year period. It highlights the continuous improvement of multilateral technology used in the region by demonstrating how a multilateral well strategy reduces time-intensive operations by eliminating additional vertical wellbore sections and utilizing existing infrastructure. The case study will include discussion of workover intervention operations, completions, and lateral creation systems.
The application of a multilateral strategy is a proven method to reduce time intensive operations by eliminating additional vertical wellbore sections and utilizing existing infrastructure.
This paper will focus on the continuous improvement of multilateral technology to consistently meet challenges faced by operators in the Middle East region for over two decades. Wells originally drilled as standard Level 4 dual-laterals are now drilled and completed using intelligent flow control and, in some cases, Level 5 installations with pressure-controlled junctions.
The paper focuses on a region and the technology used to increase efficiencies, enabling the delivery of increased reservoir contact in less operational days. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.
Success Journey Designing the First Gas Storage Application
Authors: Fallatah Mohammed Khalid , Al-Sulmi Mohammed Othman 
Published: October 2022

Abstract
The objective of this paper is to shed light on the engineering optimizations and environmental initiatives adopted on Hawiyah Gas Storage facility process design; in order to build a robust facility that would support Saudi Aramco to continue being the industry pioneer and sustainable energy supplier, and meet Saudi Arabia decarbonization targets and minimize environmental footprint.
Hawiyah Gas Storage facility is one of the recent projects built to support the Kingdom energy sector by transforming the power generation industry from crude oil burning to natural gas by addressing the natural gas seasonal supply and demand variation. Eventually, it will enable reducing the greenhouse gas emissions by deploying numerous environmental initiatives, such as attaining lesser fugitive emissions valves, installation of flare gas recovery solution, implementation of relief valves leaks monitoring technology and the installation of ultrasonic gas leak detection systems.
As far for the engineering optimizations; several innovative ideas and case studies were considered in the facility preliminary and detailed design; including the optimization of the Inlet Facility Manifold and the Reproduction Facility Bypass Mode Optimization. The implementation of above-mentioned initiatives had resulted in significant improvements in the facility safe operability, maintainability, and indeed construability at site.
Throughout this paper, the deployed initiatives will be described in details along with the applied methodology to complete the study evaluation, and conclude wit the result and discussion.
Application of Dynamic Models to Generate Optimal Injection Distribution to Maximize Condensate Recovery at Partial Recycle Voidage Replacement Scenarios
Authors: Arianto Muhammad Ali , Karamessinis Aristeidis , Almaazmi Juma Mohamed , Almenhali Salem Saleh , Al Sayegh Ahmed Ali , Al Muntheri Hiyam Hamed , Almansoori Shamma Hala 
Published: October 2022

Abstract
The reservoir A is a gas recycle reservoir which has been in production since 2000 with a cumulative VRR (voidage replacement ratio) of 95%, aiming at maximizing condensate recovery through pressure maintenance above dew point. As market demand for lean gas increases, lower operating VRR is expected. Historically, the reservoir A operated at near full recycle mode with injection gas distributed equally among available injectors. An assessment has been done aiming to maximize condensate recovery with available gas to reinject. From the exercise, it was found that sectorial based prioritization alone is not enough due to presence of inefficient injectors which affect the injection efficiency for that particular sector.
Well operation priority for injectors is not as straight forward as it would be for producers, which can be ranked based on CGR (condensate gas ratio) to achieve maximum condensate production from time to time, because the effect of injection cannot be seen immediately, particularly in a large reservoir. On the other hand, there are limited studies on gas recycle reservoir injection optimization in the literature.
To tackle this challenge, the reservoir team developed a workflow methodology with wider applicability of injection prioritization in gas line drive injection patterns. This paper will describe how to utilize the reservoir simulation model to come up with optimum injection rate range per well through setting up an assisted optimizer.
Holistic Performance Review of Through-Tubing Sand Screen as Remedial Sand Control: Best Practices and Lesson Learnt from Past Installations in Offshore East Malaysia Oil Fields
Authors: Tang Catherine, Ye Lin , Yeap Wei Jian , Zulkifli M Zin , Bt M Jeffry Suzanna Juyanty , Minggu Nur’ain , Chin Alvin, Zhi Siang , Kong Randy, Zheng Chen , M Yusof Aqil , Liew Paul Lyan , Azman Muhamad Syazwan , Praveen Kumar , Yusnawannie Ilyas , Fahmi Amni Mustafaal Bakeri , B Zainul Zaimi 
Published: October 2022

Abstract
Low oil prices, coupled with operational challenges in offshore environment due to COVID-19 restrictions, have driven oil and gas operators to implement low-cost technological solutions to optimize fields’ production. For mature oil fields in offshore East Malaysia, sand production has become one of the onerous challenges that requires this approach. Sand production is known to adversely affect the well deliverability and it also contributes to safety concerns due to surface flowline leak and equipment failure. Hence, it is of upmost importance for operators to address the sand production downhole. To achieve this, through-tubing sand screens (TTSS) installation is opted due to its ease of installation and low-cost slickline operation. Although there have been many TTSS installations to date, there is still limited understanding of the factors that affect TTSS lifespan, and this has led to frequent TTSS changeout. Based on the operator's experience, TTSS lifespan can vary significantly across different wells ranging from just a few days to years of production. To improve the understanding of TTSS performance with the aim to increase TTSS longevity, a comprehensive study on potential contributing factors has been conducted by analyzing the past TTSS installations.
Over the years, there were more than 75 TTSS installations performed in oil fields offshore East Malaysia. Lookback analysis was conducted to evaluate the effectiveness of TTSS as remedial downhole sand control and investigate the factors affecting TTSS performance such as TTSS type, well production rates, TTSS deployment method, installation depth relative to perforation interval and well interruption frequency. Several criteria identified as the key performance indicators have been investigated to evaluate the performance of each TTSS installation, including the well flowing parameters, production uptime and sand production trend.
Thorough study across different TTSS installations has concluded that TTSS lifespan varies according to well properties and well operating parameters. This paper presents best practices and lessons learnt from past installations to predict and improve the mean time between failures (MTBF) for TTSS. Case studies for several wells have been scrutinized to highlight the learnings for further enhancement of TTSS lifespan. Additionally, recommendations for further research and development of erosion resistant TTSS technology are also discussed.
Accelerated FDP Reservoir Studies in Challenging Brownfields Utilizing Digital Could Technologies
Authors: Abdullah Anas Bin , Seah Yong Han , Chuah Stefanie Mei Mei , A Wahi M Saiful Nizam Bin 
Published: October 2022

Abstract
PETRONAS Baronia field is a mature oil field with over 45 years of production history, located offshore Sarawak, Malaysia. It consists of several vertically stacked clastic sandstone reservoirs, namely two major reservoirs: S and V2 reservoirs. Both reservoirs have been on production since 1970's with the production strategy evolving over the years to maximize recovery. Natural depletion, infill drilling, water and gas injection, and recently Immiscible Water-Alternating-Gas (IWAG) IOR/EOR strategies have been implemented. All these elements combined with the subsurface uncertainties pose challenges to history match and to conduct probabilistic forecast studies on the dynamic models. Conventionally, the development scenarios for subsurface investigation are limited due to finite computing resources. As PETRONAS is shifting its portfolios to develop more complex and challenging fields, the need for transformation in development concept evaluation is evident. This is key for proper risk and uncertainties quantification. The notable challenges are a) limited number of development scenarios being investigated, evaluated, and compared; b) limited software licenses and infrastructure availability; c) lack of data and decisions traceability.
These limitations are addressed by the PETRONAS LiveFDP digital transformation initiative commenced in 2019, through deployment of digital cloud technologies and solutions with scalable High- Performance Computing (HPC) environment. The cloud-based native and Petrotechnical applications enable remote work, ensure full data traceability and auditability, enable multi-realization ensemble analysis, and streamline the automated integration from the reservoir engineering ensemble workflow to economic analysis. Unlimited cloud computing power and licenses facilitate a broader spectrum of reservoir simulation cases to be investigated in a fast-tracked manner.
The cloud HPC infrastructure has shortened the history matching cycle from 3 months to 1.5 months. The team has also observed over 5 times speed enhancement on simulation run performance using cloud computing compared to virtual machine and on-premise infrastructure. Utilizing the cloud solutions and ensemble probabilistic approach, the team has achieved over 90% of history match quality through 300 realizations per ensemble running concurrently and completed within 2 hours. The optimized IWAG injection resulted in 2% (~1MMStb) higher oil reserves with 37% less gas injection and 40% shorter injection cycles. This has improved gas sales and prioritization in the field while also monetizing the oil
reserves. The ensemble analyses are then visualized using cloud-based data analytics system whereby key realizations and uncertainty parameters are further reviewed and highlighted across various disciplines collaboratively at real time.
AI Assisted Well Performance Prediction Based on Production Profiles Clustering
Authors: Badmaev Dorzhi , Mata Carlos , Braik Fahed , Saputelli Luigi Alfonso 
Published: October 2022

Abstract
Production forecast is an important part of field development planning using for business planning and economic evaluation of an oil and gas field. The conventional approach to production forecasting includes a bunch of methods from decline curve analysis to hydrodynamic modeling; however, these methods have certain limitations of use. The objective of the study is to investigate the possibility of application AI/ML methods in classification of wells by their historical behavior, and to use this information to predict performance of existing and future wells.
The core method of the tool is K-means clustering based on wells production profiles. There are several parameters which values have been taken at the certain time-steps, for example, oil rate, watercut, GOR, flowing bottom-hole pressure, etc. Each parameter's monthly record is combined with reservoir properties to define the input vector for each well. These vectors are assigned to a specific cluster number. The defined clusters can then be assigned to wells with shorter production history in order to predict their future performance. The proposed using pattern recognition of production is useful for the identification of possible neighbor wells influence and tunes production prediction.
The method was tested on an oil field in Abu Dhabi with over 50 wells. The results have shown that there is a good predictability for tested dataset. The obtained clusters identified the production performance in existing wells and the production forecast in the nearest future.
The method introduces a new approach to wells clustering based of production profiles only. The approach is tested on Abu Dhabi field first time and practical implementation of the method is showcased.
The limitation is that it is applicable to wells that have long production history with stable reservoir performance.
Calibration of Numerical Reservoir Models Permeability Using Correlated Seismic Amplitude with Pressure Transient Data
Authors: Shams Mohamed , El-Banbi Ahmed , Yehia Islam , Capra Laura 
Published: October 2022

Abstract
Effective reservoir characterization approaches aim to integrate all available and reliable sources of data to mitigate the effects of uncertainty of reservoir parameters and have a robust reservoir model(s). Reservoir permeability is one of the most critical, and usually, uncertain parameters in reservoir simulation models. The permeability model has a direct impact on production forecasts and consequently the economics of decisions made based on reservoir models. Having a calibrated permeability model is a challenging task. In most cases, the permeability model undergoes several modifications to achieve a history-matched reservoir model that honors the historical pressure and production data.
The objective of this work is to show a workflow that integrates two different types of data sources to help calibrate the permeability of reservoir models. The proposed approach relies on adjusting the permeability of reservoir models by integrating seismic amplitude values and data from wells’ pressure transient analyses. The seismic amplitude data in the vicinity of a candidate well is correlated with permeability obtained from recorded pressure transient data in a systematic way. The generated correlation is then applied to the entire reservoir model in order to calibrate the permeability value of each grid block in the model. The application of the proposed approach on actual field data is also presented. As a result, the seismic and pressure transient data both can make valuable contributions towards calibrating geo-cellular 3D reservoir models at their respective and different scales.
Multidisciplinary Data Integration for Artificial-Intelligence-Assisted Well Placement and Trajectory Design Optimization Under Uncertainty
Authors: Su Shi , Tahir Sofiane , Ghorayeb Kassem , Ramatullayev Samat , Garcia-Teijeiro Xavier , Mohamad Hussein Assef , Kada Kloucha Chakib , Mustapha Hussein 
Published: October 2022

Abstract
Infill well placement performed as part of field-development planning is traditionally performed by identifying areas of high remaining mobile hydrocarbons and good reservoir rock quality to be targeted. The identification of hotspots was also largely performed on single-model realizations and, therefore, not robust considering the reservoir characterization uncertainties. Increasing efforts were put into incorporating the uncertainties as a key element of the infill well placement workflow by computing probability maps to identify the hotspots with higher chances of success for infill production. The maps were still generated solely based on dynamic reservoir-simulation model results.
In this paper we present an intelligent workflow that integrates the opportunity index probability maps concept derived exclusively from dynamic reservoir simulation models, with drilling risk maps derived from drilling data analysis and completions quality maps derived from geomechanical studies, and artificial-intelligence-driven reservoir target classification. The integration provides more depth in the hotspot selection by identifying the most productive and feasible locations for infill drilling.
The locations are then used for well placement and trajectory design optimization. The well trajectories optimize factors in the hotspot locations, locations of existing drilling centers, surface topology for new drilling centers to be designed, numbers of available slots on each drilling center, and capital costs such as drilling economics and drilling center cost. Infill injection wells are placed in conjunction with the infill production wells either following a pattern-type of design or peripheral injection.
The designed wells are evaluated via an automated pipeline using reservoir simulation where the set of wells will be tested against the ensemble of realizations under uncertainty. A probabilistic approach is taken for the infill well performance and the economics evaluation for candidate screening and selection for the field-development plan optimization.
This approach provides higher confidence in the decision making through the early integration of drilling risks and geomechanics data, and provides a more robust assessment of the technical and economic performance of the proposed infill wells under uncertainty.
The solution combines various concepts including opportunity index, advanced ML methods for target identification, as well as multidisciplinary integration for well target identification. Well trajectory design evaluation considering both production and injection wells and the evaluation of the performance of the proposed candidates under uncertainty in this context provides more robust results under uncertainty compared to widely used industry practices that lack integration and uncertainty considerations.
Challenges in High Sour Gas Field Development and Non-Metallics Opportunities in Upstream Processes
Authors: Almuhammadi Khaled H. , Parvez Anwar Md. , Buali Mustafa S. , Salazar Vidal Oscar D. , Bukhamseen Ahmed Y. 
Published: October 2022

Abstract
High sour fields beyond 10% H2S concentration are considered one of the severe environments that require suitable tubular components and accessories in upstream environment to ensure sustainable production. Such environments represent a challenging operating envelop where durability and safety are the top concerns due to higher H2S concentration at a higher partial pressure and higher temperature (HPHT). The risk is amplified for the wells with higher than 10% H2S concentration, namely the High H2S wells, and those exceeding 25% H2S concentration which are typically labeled as Ultra-High H2S wells. Corrosion in gas operations can be aggravated in downhole where high H2S at higher temperatures pose additional challenges. Selection of proper material to ensure a sustainable well condition is one of the important elements for the development of these HPHT gas wells. Various challenges were identified, including the selection of cost-effective material which is capable of withstanding short and long term H2S and CO2 partial pressures as well as control generalized CO2 corrosion, sulfide stress cracking (SSC), and stress-oriented hydrogen induced cracking (SOHIC).
With the advancement of Non-Metallics (NM) materials in several applications across the O&G sector, it holds a promise to provide an alternative material solution in lieu of CRA alloy material for the HPHT downhole applications. NM materials are lightweight and they can be designed to withstand higher strength capability in addition to their outstanding corrosion resistance properties in a high H2S environment. Moreover, they can be engineered to fulfill the intended application due to their high design flexibility and durability. In the downhole applications, there is a number of NM products that have been implemented in sour environments, including sealants as well as downhole accessories and tools, where the list of NM technologies is considerably growing.
This paper highlights the concept of using NM products such as coiled tubulars, pressure control equipment and elastomers as well as the challenges on the development and deployment of these key components in high sour fields.
Operational & Social Challenges of Sour Gas Well Testing Operation in Brown Field
Authors: Ahmad Zeeshan , Al Hosini Abdullah Alhaj , Al Janahi Mohammed Ibrahim , Al Marzouqi Abdulla Mohammed , Siddiqui Muhammad Ali , Ahmad Mubashir , Agarwal Anubhav 
Published: October 2022

Abstract
Well testing operation of sour wells by flaring or flowing through existing pipe line network with limitations always consider as highly challenging in brown field. In this paper operational and social challenges considered during critical well testing operation during different phases.
For initial performance evaluation, completion and surface facilities were not designed as per expected well fluids specially in consideration of H2S, CO2 and elementary Sulphur. These wells located in congested developed field and special consideration regarding social risk analysis and mitigation were considered. Extensive H2S and SO2 dispersion modeling conducted to develop EPZ & EAZ for safe operation by utilizing latest safety equipment's.
Special scale treatment and down hole chemical injection adopted to cater tubing accessibility due to elementary Sulphur and other scale issues to improve flow assurance during well testing operation. Case study of condensate storge tank utilization with improved safety precaution will highlight the consideration of reservoir fluids for any well testing operation. High volatile Condensate handling at well site always be serious challenge and can be utilized with extensive HAZOP and better process safety controls.
Well intervention operation with High H2S for gas wells in presence of water aggravate corrosion and H2S cracking significantly for any type of metallic material. Special down hole plugs, wire line, E-line and sealing elements of pressure control equipment's designed and utilized during intervention operation along with utilizing of special chemical.
Well control is serious concern while flowing such wells due to catastrophic asset and environment impact. Special well control consideration needs to be in place for any well control scenario, this paper will cover all type of surface and subsurface consideration to improve the well & reservoir integrity.