bluuebunny/crossref_metadata_2025 huggingface dataset:
Success Factors of an Enterprise-Wide Digital Twin Strategy
Authors: Parvin Steve
Published: December 2021

While many companies have embarked on their digital transformation journeys implementing different forms of "Digital Twins" to cover specific business processes and challenges, their main challenge has been integrating these disparate Digital Twin projects into one single combined view to create significant new value and competitive advantage for the business.

To be effective, the Digital Twin needs to be capable of supporting the entire asset lifecycle from the early phases of a capital project to operations and maintenance up to asset retirement, leveraging the same data in a platform able to support the end-to-end process.

This paper looks at several approaches, which large owner operators at different levels of organizational information management maturity have used to build their Enterprise Scale Digital Twin strategies.

It uses the lessons learned to highlight the successes and failures of these strategies and recommended approaches going forward. The results observed, identify that whilst there is a reasonably standard roadmap for approaching the development of Digital Twins most customers begin at different points along that journey.

It also highlights that the end goal may not be the same across an Enterprise and that by taking the development of a Digital Twin as a series of incremental steps, independent of the starting point, serves to accelerate the journey by driving an increase in the organizational maturity in terms of People, Process and Technology and an improvement in data quality. One of the key components in any strategy was the ability to manage the information standard for the Digital Twin at an Enterprise level, for both greenfield and brownfield organizations and assets.

The paper concludes the benefits of technical and commercial scalability and the requirements to get a solid manageable and trustworthy core of information should be at the heart of any Enterprise-wide Digital Twin strategy. This is contrary to the common approach of building a single detailed Proof of Concept (PoC) addressing as many use cases as possible and then templatizing that as an approach to repeat around the Enterprise, which often leads to failure on additional deployments where the maturity and challenges are different.
Correlation of Mechanical Parameters in a Giant Carbonate Field, UAE
Authors: Noufal Abdelwahab , Altameemi Ibrahim , Shehab Abdulla , Al Shehhi Hamda
Published: December 2021

The rock properties in the reservoir rocks represent stiffness and strength properties, while the unexpected variation in the dense intervals varies with the fabric and other sedimentological and rock types. The purpose of this paper is to present the mechanical rock testing parameters of Lower Cretaceous reservoirs, including the tight intervals in a giant field of Abu Dhabi. In order to enable the evaluation of the mechanical parameters, there is a need to assess the reservoir rocks, as well as the stress configuration around and away from the wells.

This paper introduces a workflow that integrates multidisciplinary data to develop a geomechanical model aiming to reduce drilling risks and optimizing reservoir appraisal. Cores, wireline logs, CT scans, SEM and thin sections were used to characterize the fracture systems and build the robust seismic driven geomechanical model. A conceptual model has been firstly developed, where reservoir heterogeneity has been quantitatively described in relation to tectonic deformation events, followed by incorporating a 1D-MEM's (Mechanical Earth Model), which used to calibrate the seismic based elastic properties.

Results indicate good correlations developed between dynamic and static Young's Modulus, Biot's coefficient, Friction Angle and Unconfined Compressive Strength by incorporating the results of rock mechanics testing, leading to create a dynamic YME-driven correlation. Good correlations were also obtained between Effective Porosity, and Static Young's modulus, Biot's coefficient, Friction angle and Unconfined compressive strength, leading to create a Porosity-driven correlation. In addition, friction angle correlation increases if proper data is considered, making feasible to build a correlation in both dynamic YME and Effective Porosity.

Finally, the presence of several partially conductive fracture sets within the reservoir, including both sub-vertical and moderately dipping conjugate sets, with gently dipping/bed-parallel fractures. They have been developed under a predominant strike-slip regime that swaps a normal faulting stress regime at depth. Fracture porosity is related to micro- and meso-scale fractures, and fracture permeability is more significant compared to the storage capacity of the matrix porosity. Rock fabrics are varied in different zones, which likely explains differences in the mechanical behaviour.
Block 61 Drilling Fluids Optimization Journey
Authors: Jan Mohammad Majda , Al Noumani Muneer , Cameron Iain , Al Masoudi Younis
Published: December 2021

BP operates Khazzan & Ghazeer fields in the Sultanate of Oman with the aim to deliver safe, reliable and efficient wells. Efficiencies within drilling fluids design form part of a greater continuous improvement cycle to well delivery cost. With fluids spend contributing to a significant portion of the executed well cost (typically 15 % in Oman), fluids design changes hold the potential to yield positive cost savings (where well performance is maintained).

This paper presents the areas of fluids design which were explored to reduce fluids spend as part of the continuous improvement cycle. Combined, the changes to fluids design evolved to reduce the fluids cost of Barik vertical wells to 6% of total well cost.

All avenues of fluids design and the costs associated with the fluids operation in Oman were viewed as being in scope for change to maintain overbalance hydrostatic pressure on fluids spend.

The methodology employed to reduce fluids spend can be described in four steps as per continuous improvement roadmaps; identify the cost saving project, the key enablers which allow the cost saving to be realized, risk/reward analysis where low risk/high reward projects were accelerated as priority and placed to the front of the queue for field trial and where a trial outcome is positive, the change is introduced permanently to the operation. This process worked well in continuously pushing fluid performance and reducing the fluids spend in Oman.

The scope of change to fluids design was wide, with each ‘value adding project’ providing its own cumulative cost benefit. The projects which contributed to significantly reducing the overall fluids spend in Oman focused on personnel, fluid type selection, fluids formulation optimization, wellbore strengthening, fluid consumption and recycling, drilling fluids practice and brine selection.

Reductions in fluids spend were accompanied with an improved well performance. Well delivery times being continuously observed to improve throughout the campaign (63 days vs 42 days). Whilst the fluids design is not directly responsible for this outcome, it does highlight that the changes made to fluids design positively influenced the improved well delivery performance.

The drilling fluids optimization initiatives resulted in significant time and cost saving thus reduction in overall Barik vertical well drilling cost. Drilling fluids cost is reduced by over 55% without impact on safety and drilling performance.
User Generated Content for Site Based Training in Virtual Reality
Authors: Mayhorn Ivory , Daughtry Kyle R. , Dhanormchitphong Athicha , Bray Mitchell B.
Published: December 2021

Objectives/Scope

Through a partnership with Global Projects and the ExxonMobil IT, we set out to change the way enabling enhanced site specific operator training and model reviews are done on large complex models. The concept was to have the ability to view and navigate complex green-field 3D CAD models in VR (virtual reality) technology to aid in training, model reviews, procedure development, rounds development, maintenance planning and execution, emergency response planning / drills, and project planning. The automated toolset can be used to conduct model reviews followed by training and preparing operators for commissioning before and after site construction is completed.

Methods, Procedures, Process

Leveraging the 3D CAD files from Engineering Procurement & Construction (EPC) contractors, the feature set allows the ability to create a fully textured 3D Model walk-through (annotated model review), and a content creation application to easily create user generated training scenarios (similar to PowerPoint drag and drop). In the past few months, 20 onsite stations were setup and over 100 first and second line supervisors and operators leveraged the toolset. Baseline metrics were captured with an overwhelming success. Ongoing metrics collections will continue for several months to drive further adjustments on the toolset to ensure high value capture. This toolset, once fully refined, will allow other capital & global projects the ability to train operators prior to the unit being built and ongoing for operations activities bringing pieces of the Digital Twin concept to life.

Results, Observations, Conclusions

Technical Benefits

Business Benefit

Novel/Additive Information
Smart Digital Monitoring Tool
Authors: Al Sharif Bandar Abdulaziz , Al Qurooni Faisal Anwar , Alqamous Mohana Essa
Published: December 2021

Smart Digital Monitoring Tool

As the world is currently going through a wave of rapid digital transformations, finding digital solutions in the oil and gas industry today is more important than ever. Not only is digital transformation one of the main pillars needed to embrace the Fourth Industrial Revolution (IR 4.0), but it is also indispensable to achieve operational excellence. By connecting process parameters and physical assets with digital monitoring tools, more accurate insights can be gained, which enables real-time responses to challenges and proactive corrective actions.

Different tools and multiple dashboards have been employed to monitor different focus areas such as crude quality, environmental performance, energy consumption, and critical process parameters and chemicals consumption. In spite of the several available tools to monitor and summarize the facilities performance and key performance indicators (KPIs), taking quick and proactive actions to resolve the issues and improve the performance remains challenging sometimes. This is because for digital transformation to have a stronger impact, it better be integrated across the whole business focus area. This means that a single and comprehensive tool will help identify areas for improvement — timely and quickly by the Operations, Maintenance and Engineering (OME) team.

In line with Saudi Aramco's Operational Excellence (OE) program, and to produce oil and gas in an efficient, cost-effective, reliable and responsible manner, a comprehensive and creative smart tool has been developed to deliver energy with better quality, enhanced safety, improved reliability, continuous sustainably, and increased efficiency.
Unlock Condensate Reserves by Peripheral Development of Giant Condensate
Authors: Al Yaaqoubi Nouf Sulaiman , Al Agbari Zainah Salem , Sudarev Maxim , Latypov Eduard , Mohamed Ihab Nabil , Al Ferdan Fatimah , Hosani Mariam Ahmed , Al Bairaq Ahmed Mohamed
Published: December 2021

This paper addresses the development of peripheral area in order to maximize the condensate production in a giant Recycle Gas-Condensate Reservoir in UAE. The condensate reservoir is producing many years under recycling mode to maintain the pressure and maximize the gas condensate recovery. The producers and injector wells are in a line drive pattern where the injected fluid is lean gas to maintain 100% VRR. The condensate production declined through the years due to gradual pressure decrease as well as injected lean gas/N2 breakthrough. Several studies were done to increase condensate recovery and extend gas production plateau.

The methodology adopted for this study is the developing of the peripheral area in the giant recycle reservoir as part of its full field development plan (FFDP) in order to provide more pressure support initially and to increase the sweep efficiency for more condensate recovery. In addition; it is worth to mention that peripheral wells will provide production relaxation from some gas produces which have lean gas and N2 breakthroughs. Pilot wells were drilled to examine and confirm the strategy assumed by analyzing the performance of those wells in terms of location, condensate production, CGR values and trajectory. Simulation modeling was as well used for matching purposes and future prediction and forecasting.

Pilot wells were drilled in deferent peripheral area in the reservoir and completed as horizontal gas producers. By analyzing the current wells performance it has been approved that the wells are producing high condensate about (2000-2500) MMstb and producing high CGR values about (80-100). Simulation modeling were utilize for future prediction and confirmed that the development of peripheral area by drilling additional wells enhances the sweeping efficiency and participated in expected gain a multimillions of barrels of additional condensate with maintaining the same business plan gas production target. It was promising to have more incremental in case of ramping up the production.

The paper discussed in detail about methodology adopted in order to unlock the condensate reserves by peripheral development and confirmed the results of the gain of condensate production and CGR from actual data and simulation modeling. The provided information is quite informative to be widely used and applied in similar reservoirs.
Standardized Development Planning for Satellite Fields in the South of the Sultanate of Oman
Authors: in ‘t Panhuis Peter , El Sabagh Adel , Coppes Hilde , Meyers John , Van der Werff Niels , Al Jadeedi Faiza , Suryanto Doddy , Al Habsi Kauthar
Published: December 2021

This article will show how a standardized rule-based approach was used by Petroleum Development Oman (PDO) to shorten the cycle time required to mature the opportunity of implementing waterflood developments in small-to-medium sized satellite oil fields in the South of the Sultanate of Oman. The standardized concept relies on a common development strategy for a portfolio of satellite fields with similar reservoir and fluid characteristics that are still under depletion or in the early stage of waterflood. The targets are early monetization, driving cost efficiency through standardization & replication, and increasing recovery factor through the accelerated implementation of field-wide waterflood. This is achieved by leveraging excess capacity in existing facilities, applying analytical workflows for forecasting, standardizing well design and urban planning, and by applying the learnings and best practices from nearby fields that already have mature developments.
Digital Ways of Working: PDO Knowledge Management Program
Authors: Aufi Saif Al , Lawati Hussain Al , Ismail Asif , Lawati Sajad Al , Koepchen Christian , Sabahy Salma Al
Published: December 2021

Petroleum Development of Oman (PDO) has grown rapidly over the past few years and is seen as an innovative organization and a leading company within the Middle East when it comes to applying best practice, adding value to the economical and societal development of the Sultanate of Oman through many Knowledge Management (KM) activities. As the Sultanate's leading Oil and gas exploration and production company it is the central engine of the Sultanate's economy. Key to the success of our Digital KM Program has been focus on the importance of developing the human intellectual capital elements to nurture, develop and sustain our people as key assets.

PDO is aware of the potential value of the Enterprise Information and the robust data as showcased In the Figure-1 which can be transformed into knowledge that can be turned and can be used to gain the business benefits such as a competitive advantage, cost minimization, innovation.
The Overlooked Intricacies of Wellbore Cleanout in Sub-Hydrostatic Conditions with Coiled Tubing: Lessons Learned Toward an Effective Approach
Authors: Hamid Saad , Abulhamayel Nahr M. , Ahmed Danish , Hamidon Zahaezuani Rafiq
Published: December 2021

This study focuses on horizontal wells completed with pre-perforated liners installed in open holes, and which produce under sub-hydrostatic conditions. During workover operations, loss circulation materials (LCM) are routinely pumped, thus requiring coiled tubing (CT) cleanout interventions to enable well production afterwards. The sub-hydrostatic nature of the reservoir makes it challenging to maintain optimum bottomhole pressure (BHP) and have the ideal downhole conditions, without significant losses and with sufficient annular velocities, for an effective cleanout.

During CT cleanout operations, the LCM plugging the formation may falsely create a perception that the well is able to sustain a column of fluid. However, as the LCM is cleaned out and the wellbore starts communicating with the reservoir, sudden fluid losses may occur, causing solids in the annulus to fall and leading to a stuck pipe scenario. Constant control of the balanced downhole conditions is therefore critical in such operations—yet frequently overlooked during job design. The use of real-time downhole pressure sensors thus not only ensure effective cleanout but also act as a stuck pipe prevention measure.

Based on job executions in similar wells, several lessons learned were compiled. The ability to maintain optimum downhole conditions by adjusting liquid and nitrogen rates during cleanout has proven to be key to a successful cleanout. Additionally, in one of the wells where CT did get stuck, the team was able to prevent debris from falling, thus addressing the root cause, and facilitating the implementation of an effective contingency plan to get the pipe free.

The need for live downhole monitoring is even more important when operating in the pre-perforated liner sections that are exposed to the open hole. Common designs calculate annular velocities based on the internal diameter of the liner, but in reality, the much bigger openhole diameter shall be taken into consideration, which result in much lower values of annular velocities in reality.

Additionally, selection of the right bottomhole assembly (BHA) is critical for the overall system performance. In the presented case, the motor and mill configuration was observed to be more effective compared to a high-pressure rotary jetting tool. However, as the motor and mill combination creates significant vibrations while operating, it becomes critical to use a ruggedized version of the live downhole CT acquisition system to ensure maximum reliability.

The observations compiled throughout operations enabled the development of best practices. Risks involved in a cleanout operation are often underestimated, especially in a well with a depleted reservoir. As more reservoirs face depletion in mature fields globally, the ability to clearly understand the downhole dynamics during such operations makes the difference between a successful job and a catastrophic failure.
API Process Safety Site Assessment Program PSSAP®: Significant Program Updates and Future Focus
Authors: Frazier Colin M. , Burr Alexa S. , Meng Ryan D.
Published: December 2021

The American Petroleum Institute (API) and the U.S. oil and natural gas industry have long been committed to protecting the health and safety of our workers, contractors and neighbors. For more the 75 years, API has led the development of industry standards, sharing lessons learned as well as the establishment of training and certification programs.

In recent years, despite safety improvements by the refining industry, incidents have increased attention on process safety by industry, governments, non-government organizations (NGOs), and the media. Recognizing these concerns, API and our memebrs are working collectively to improve or develop new programs improve process safety performance.

As part of the industry's ongoing commitment, API, in collaboration with industry partners, has developed a Process Safety Site Assessment Program (PSSAP®), an assessment program focused on evaluating higher risk activities in a refining, petrochemical, or chemical facility. This program is intended to:

Promote process safety performance improvement industry wide; Promote learnings from industry practices; Provide benchmarking through the consistent use of industry-developed good practice protocols; Serve as a feedback mechanism for an analysis of industry performance; and, Encourage safety collaboration among participating sites and industry experts.

PSSAP benchmarking, a key aspect of the program, allows sites to judge their performance against that of their peers in a blinded fashion. In addition to this benchmarking, the consistent use of our good-practice protocols enables API to analyze where companies may still be working to improve. Taking that information, API has implemented other programs to assist industry in those areas. Further, it has allowed API to quantify PSSAP protocol scoring improvements across the industry, seeing positive momentum in benchmarking scoring across the life of the program.

PSSAP® is also a primary resource to support API Energy Excellence® implementation. API Energy Excellence is another critical API program in which all API members commit to enhance the integrity of operations across the industry by applying standards, implementing workforce training programs, and participating in performance initiatives. Downstream and petrochemical operators can use these PSSAP protocols to help demonstrate conformance to their API Energy Excellence requirements.

PSSAP® is flexible so that sites can tailor assessments to specific needs and operations. It provides options for smaller sites that do not have on-site internal assessment capabilities or do not think a full PSSAP General Assessment is warranted. It is intended that assessments focus on higher risk activities and includes an evaluation of both the quality of written programs at a site and the effectiveness of field implementation of those programs.
A Novel Approach to Drilling Through Challenging Formations With Complex Logging Bottomhole Assembly in an Exploration Well, North Sea
Authors: Kallhovd Anders , Kelsall Neil R , Haaland Erik , Haugestaul Jon , Akutsu Erik , Veiberg Tormod , Oreskovic Antonio , Nagy-Korodi Istvan , Vestergaard Anders
Published: December 2021

The southern part of the North Sea continental shelf is known for large intervals of hard, compact, cretaceous chalk formations that historically have proven to be challenging to drill through in one run. In recent years technology has been developed to drill specifically through these types of sedimentary successions as effectively as possible to be durable and competitive in similarly challenging drilling settings. Formations that previously would require multiple bit runs are now being drilled in one. The exploration well 2/9-6 S Eidsvoll, operated by MOL Norge AS, was drilled in this area of the North Sea continental shelf, with this specific type of chalk being drilled in the 12 ¼-in. section.

Because the 12 ¼-in. section consisted of several different lithologies, it was vital to design the bottom hole assembly (BHA) to handle the diversity of rock formations to be drilled. Lithologies ranging from soft, swelling clay to hard compact chalk with an Unconfined Compressive Strength (UCS) as great as 20,000 psi were expected. In addition to managing the challenging drilling environment, determining the casing setting depth was of the highest priority because a pressure ramp was expected near the planned setting depth. This pressure ramp is located in the Base Cretaceous Unconformity (BCU), which is a well-known seismic reflector in the area. The top of this reflector had an uncertainty of ±75 m, which is not ideal following a decision to set the 9 ⅞-in. casing as near as possible to the reservoir. Seismic-while-drilling technology was applied to reduce this uncertainty and better tie-in the acoustic velocities to the pre-drilling seismic model. In addition, a geomechanics team was tasked with creating and updating the prognosed pore pressure estimation model. This information was important in making the mud-weight decision when drilling the 8 ½-in. section.
Improved Safety: The Importance of Aggregated Safety System
Authors: Hendi Farshad , Rashed Mohamed Hassan
Published: December 2021

In this paper we review why there is a need not just for persistent monitoring and validation of critical safety KPI's at an individual safety-related system level, but an aggregate view of safety performance across units, plants, sites and even regions. Can providing a holistic view of risk at the enterprise layer be the answer to eliminating the events that jeopardize a more sustainable performance and future?

New technologies and the Digital Transformation enable operator companies to control and manage their process safety risks in real or near-real time. Imagine something like a process safety risk meter: a digital device that collects, analyzes, and provides data from processes, equipment assets and protection layers. In essence, this tool would allow visualization of past, present and future operating risks so decision makers can make better, faster operating and business decisions in real time. As the world and global economy becomes more digital, market changes and pressures are becoming more dynamic. First, the speed of business continues to increase at a remarkable rate, which means business risks and variables, everything from fluctuating energy and feedstock costs to cybersecurity threats, are changing almost daily. Second, global policy initiatives and regulations that strive to create a more sustainable world mean companies now need to operate more efficiently, reliably, and safely than ever. But despite the trends driving a more dynamic operating and business environment, many companies still rely on static process hazard analysis—PHA—to identify and evaluate their process safety risks. While it's a trusted and reliable approach, PHA does not meet the needs of today's real-time business environment.

Identifying, mitigating, and managing business, operating and environmental risks in real time or near-real-time has become essential for the short- and long-term success. With that in mind, it is time to revisit risk-management strategies, particularly the strategies used to mitigate process safety risks, and explore how they can help you optimize your operations for a more sustainable performance.
Human Factors in HSE Performance – Role of User-Friendly HSE Documentation
Authors: Al Hammadi Saud Mohamed , Akula Ramakrishna
Published: December 2021

Organizational Multi layered documentation frameworks, complex document writing styles, cross referencing, poor document integration, end user language barriers and psychological factors for searching relevant information under pressure complicates the understanding of a technical document. Complex technical documents intimidate the end user and shrinks the user understanding. Document engineering or Usability mapping of documents is proven scientific method for writing technical documents in a simplified and user-friendly manner. The document engineering concepts are based on human psychology, that helps the user to navigate through document content rather searching for specific keyword or information. Safety intensive industrial sectors such as Aviation industry, Oil and Gas are already adopting the document engineering concepts in their technical documentation. It is proven in many organizations that the usage of document engineering concepts simplifies the document complexity and the end users feel much comfort in understanding the documents in their work.

In this paper an attempt has been made suggest adoptable user engineering concepts to simplify technical HSE documents. Also, the paper discusses some of the in-built hidden readability features in Microsoft word for checking reading ease and reading grade levels to improve simplification of documents. The paper discusses the psychological aspects behind document reading, understanding, cognitive linking for reaching the required information. Also, the paper discusses some of the best practices to be considered for technical document writers.
Evaluation of Hydrocarbon Producability Below FWL Onshore Abu Dhabi Oil Field Case Study
Authors: Eriavbe Francis , Vadakkeveetil Abdurahiman , Alkhatib Mohamad , Khattak Iftikhar , Lazar Raffik
Published: December 2021

Objectives / Scope

This paper addresses the field development planning challenges of a green onshore South East Abu Dhabi oil field with limited production data. Tectonic movements have created strike slip faults dissecting the structure and uplifting the main body. Tilting of the flanks has resulted in the accumulation to leak some of its initial hydrocarbon and a rebalancing showing a titled FWL.

A novel workflow was used to address the challenging reservoir physics including hydrocarbon below FWL. The paper takes a holistic approach in integrating multiple domains data such as Drilling, Petrophysics, Geology and Reservoir / Production Engineering.

Methods, Procedures, Process

An integrated approach was adopted to address the complexity and challenges of characterizing and modelling the field with hydrocarbon below FWL. Extensive range of data was collected to contribute to better understanding and evaluation of the field. The producibility of hydrocarbon below FWL have a significant impact on field development planning.

The used workflow was specifically suitable to drive subsurface team right reservoir characterization:

Improve fluid contacts understanding Explain the log responses The discrepancies between dynamic and static responses De-risk the volumetric uncertainties

Results

Following an extensive multi-disciplinary technical analysis of all available datasets, the most robust, accurate and reliable reservoir characterization, that can be seamlessly integrated into dynamic reservoir modelling phase.

A systematic approach was adopted starting from core measurement and lab visits, drilling data such as mud logs, Petrophysical evaluation of multiple complex physics such as hydrocarbon presence below FWL, micro porous intervals, Micritic minerals and imbibition effect, geological regional understanding of faulted reservoirs, and dynamic data such as formation well tests.

The study demonstrated that multi-domain integration played a key role in addressing the complex and challenging reservoir dynamics.

Novel / Additive Information

Large subsurface uncertainty combined with an extensive domain integration required cutting-edge reservoir de-risking and data gathering to provide the optimal reservoir characterization. These unique workflows can be readily used in similar green fields and will be described in full details in the paper.
Enhance the Plant Operating Capacity - Maximize the Revenue/Asset Utilization
Authors: Javed Atif
Published: December 2021

To explore the opportunity for maximum utilization for a Sales Gas Compression Facility (SGCF) in line with ADNOC strategy to enhance profitability and asset utilization. A technical study was conducted to increase the processing capacity up to 133% of its design limit by utilizing the available design margins. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options (if bottlenecks are there).

The Technical study covered the following activities:

Simulation:

Process simulation was performed and H&MB (Heat and Material Balance) was generatd.

Engineering: Compressor adequacy checks on increased plant throughputs. Static Equipment rating and adequacy checks performed with the concurrence of original equipment menufacturerers. Line sizing adequacy checks and detailed evaluation of the piping. Adequacy check for In-line instruments like control valves, flow elements/transmitters (Note 1) Relief, blowdown and flare system adequacy check. Utilities adequacy checks. Risk assessment workshop was conducted before the capacity test run. Preparation of Test Run procedure before the actual test run. Actual plant capacity test run to verify the study findings.

Note 1: Adequacy check of thermowells had been peformed separately prior to the study. It had already been established that the thermowells were adequate for the increased plant throughputs.

The study has concluded the following observations for processing 133% of the design capacity

Theoratically, the Sales Gas Compression Plant is adequate to handle the sales gas throughput up to 600 MMSCFD (2 running machines) considering the facts that Sales Gas Compressor suction pressure must always be kept at 32 barg through close monitoring by the operaters.If compressor suction pressure starts dropping below 32 barg, the study outcome would no more valid and the plant throughput would be reduced back to the original design capacity of 450 MMSCFD.

Moreover, it was recommended to perform a field test run to validate the study outcome by following the Manageement of Change Procedure as applicable.

Based on the successful 48 hours test run, it was established that the facility could handle the increased plant throughput of 600 MMSCFD by following the instructions given in the adequacy study.
Zohr Field Process Safety Operative Self-Assessment
Authors: Lisandrelli Vincenzo , Pozzi Niccolo'
Published: December 2021

Zohr field has developed a smart tool for the Process Safety compliance self-assessment. Scope of the tool is to evaluate field Process Safety Management system performance as well as driving a step change in field culture by making Process Safety a transversal target for all departments, not only HSE.

To reach this scope, an internal Field multidisciplinary team has been created with the scope to verify the Process Safety pillars compliance through a simplified check list and scoring model.

The initial 8 key elements are:

ESDs Alarm management Safety Critical Elements Overrides Loss of Primary Containment Management of Change Permit to Work Manuals/Procedures

For each elements a weighted scoring model from 0 to 5, composed by multiple questions, has been defined; a detailed guidance is supporting and assisting the team during the assessment.

Once completed the scoring model a traffic lights system integrated with a spider diagram will automatically represents the field compliance with the elements.

A quick and immediate graphic representation identifies then the main gaps for each elements.

Based on those results the multidisciplinary team defines an Action Plan to be addressed to the relevant dpt for improvement and follow-up.

The assessment frequency has been set to 6 months and the multidisciplinary team is appointed on rotation basis by Zohr Field General Manager and the relevant Department General Manager.

The first PS self-assessment performed in Zohr in September 19 showed the PTW system and SCE management as the main points of strength while the Management of Change implementation and the ESD tracking as the elements to be improved.

In particular Zohr has already set a robust system for the PTW management through a dedicated technical process team SIMOPS and developed a robust override and leak management system across the related departments.

As all the plant modifications have been managed so far thorough a DCN (Design Change) System with project support, as action plan was foreseen to implement a dedicated system for the electronic management of the MoC.

The first assessment highlighted also the need to improve the actions monitoring to keep traced all the findings coming from the RCA of the plant ESD and PSD.

Moreover as additional benefit the interactive self-assessment tool effectively contributed to spread across all the departments the Process Safety terminology and culture in order to allow the team to get familiar with the pillars with a smart and user friendly approach.
Big Data Analytics Maximizes Value from Smart Well Completions
Authors: Al-Hajri Nasser M. , Javed Muhammad Imran , Barghouti Akram R. , Al-Shuwaikhat Hisham I.
Published: December 2021

This paper presents a workflow based on big data analytics to model the reliability of downhole Inflow Control Valves (ICVs) and predict their failures. The paper also offers economic analysis of optimum ICV stroking frequency to maintain valves functionality at the lowest possible cost to the oilfield operator.

Installing an ICV in a petroleum well is a costly process and is done by a drilling or workover rig. As such, maintaining a fully functional ICV throughout the lifecycle of a well is important to ensure proper return on investment. ICVs are known to malfunction if not periodically stroked/cycled. The action of stroking ensures that each valve opening is free from obstructing material that would prevent the ICV from operating between one valve opening step to another. When an ICV malfunctions, a costly functionality restoration operation is sometime required without guaranteed results. In other cases, the valve is declared no longer useful and the asset cannot be further utilized due to malfunction.

In this paper, an analytical decision making model to predict failures of ICVs is presented that is based on rigorous big data analytics. The model factors in the frequency of stroking before a valve fails. Then, an economic analysis accounting for the CAPEX & OPEX of an ICV is included to optimize the stroking frequency. The utilized techniques include ICV failure and stroking records and classifying the data into pre-defined criteria. Cumulative probability distribution functions are defined for each data set and used to generate failure probability functions. The probability equations are factored into an asset management cost scheme to minimize expected maintenance costs and probability of ICV failure.

The results of applying this novel methodology to any smart well clearly showed maximized ICV service life and proper return of investment. The results demonstrate that ICVs lifecycle was prolonged with low maintenance cycling cost. Methodologies similar to the one presented in this paper are true manifestation of the fruitful impact IR4.0 technologies have on oilfields day-to-day operations.
Optimizing Gas Production from Giant Multi-Reservoir Onshore Abu Dhabi Gas Field by Introducing Wellhead Compressors and Reconfiguring the Surface Network Using an Integrated Asset Model IAM
Authors: Bernadi Bondan , Douglas Mahmood M. , Bin Jaber Hamad Easa , Al Bairaq Ahmed Mohamed , Mohamed Ihab Nabil , Hosani Mariam Ahmed , Abdullayev Azer , Roopal Allen
Published: December 2021

The giant onshore gas field in this study consists of six stacked reservoirs and has been producing for over three decades. The field has more than 150 gas producing wells and has several wells which have low-intermittent gas production rates. The low production is attributed to weak wells sharing common trunk lines with prolific wells. This study investigates the impact of choke optimization, surface network reconfiguration and wellhead compression to improve the gas production from weak wells after performing detailed analysis of possible root causes from the surface network by using an Integrated Asset Model (IAM) as the digital twin of the field.

The investigation begins by identifying weak producers and involves studying the integrated surface network and determining the root causes for backflow and unstable hydraulics. After surface network issues have been recognized, remedial modification will be implemented. The impact of different choke settings on the wells are studied. The final step will be to introduce wellhead compressors on the weak producers. Extensive sensitivity scenarios are performed to identify the optimum compressor inlet pressure for each individual wellhead compressors and the wells which benefit most from the application of wellhead compressors are ranked.

The multi-reservoir gas field contains six stacked reservoirs which are producing under depletion mode and share a common surface network. Root causes of weak or shut-in wells due to backflow or hydraulic issues are successfully identified by using an IAM simulation tool. The investigated remediations were simple optimization of the choke settings, reconfiguration of the surface network, and application of wellhead compressors to improve the gas production from the problematic wells. It is observed that the addition of wellhead compressors resulted in the most significant increase and more sustainable production from the weaker wells. Furthermore, the final selection of candidate wells for wellhead compressors can be dictated according to the highest gain from the ranking. The study revealed that the implementation of wellhead compressors will significantly increase the cumulative gas production from the selected wells at the end of field life and will result in positive production acceleration from the field perspective.

This study shows that adding wellhead compressors to weak producers can mitigate the production bottlenecks and backflow issues and that higher and more sustainable gas production can be achieved from the weak wells after understanding the primary causes for low/intermittent production from the IAM which is acting as the digital twin of the field.
Problem-Solving in a Pandemic: How the Creation of a New Workflow Improved the Quality and Timeliness of Remote Core Descriptions
Authors: Mills William Stephen , Al Tameemi Kate , Cole Grant , Gill Claire , Manifold Lucy , Petrie Graeme , Dietz Jonathan
Published: December 2021

The COVID-19 pandemic limited global travel and access to core facilities. However, by adopting an innovative remote core description workflow, potential delays to an important reservoir characterisation study were avoided and mitigated.

Over c.1700ft of middle Miocene core from an Onshore well in Abu Dhabi was described using high-resolution core photos, CT scans and CCA data. Detailed (1:20ft scale) descriptions of heterogeneous, mixed lithology sediments from a gas reservoir were produced.

The aim when developing the workflow was not to try and replicate the process of in-person core description, but to create a workflow that could be executed remotely, whilst maintaining technical standards. Ideally, we wanted to find a solution that also had the potential to improve the overall quality of core description, by integrating more data from the onset.

The workflow used a matrix to generate a confidence score for the description of each cored interval. Factors such as core condition were considered, which highly influences the extractable core information. The confidence score was used to make decisions, such as whether an in-person review of the core was necessary, especially where core condition was below a reasonable threshold. This helped prioritise cored intervals for review, ensuring time in the core store was focused, and allowed accuracy and reliability of the remote description to be assessed.

The 4-phase workflow is summarised as:

Image extraction of white light (WL), ultraviolet (UV) and computed tomography (CT) core images. Digital chart creation, core-to-log shifts and sample selection: Wireline data, CCA data and core images loaded Core images used to determine core-to-log shifts Thin section, SEM and XRD samples selected Remote core description: Conducted using all core imagery, CCA and wireline data Thin section, SEM and XRD data were used to refine the description when they became available A confidence score was given to each cored interval QC and finalization: Using the results from phase 3, a selection of cored intervals for in-person review was made. Intervals included those with a poor match between remote description and petrographic data, or areas with a low confidence score. Following the review, charts were finalised and quality-checked for data export

Using this workflow, ensured work on an important study could continue during the pandemic. Such an approach has continued value for future studies as it increases efficiency and accounts for more data to be considered in core description prior to viewing the core in-person; it has been used on recent studies with great success.

Another benefit to this approach is that less time in the core store is required, reducing potential HSE risks and helping to manage core store availability in busy facilities.
Design Considerations for Over-Water Microwave Radio Links - A Case Study
Authors: Chozhiyattel Yunus , Affan Iman
Published: December 2021

Arabian Gulf region with its hot, humid and prolonged summer is known to be one of the most challenging environments for radio-wave propagation. Over-the-sea microwave radio links here face degradation and unpredictability in performance due to anomalous propagation, ducting and reflective effects of large water bodies. This paper presents microwave radio link design challenges in an offshore environment and the methods implemented to overcome these challenges in the context of specific project experience in offshore field areas.

A baseline design for the links was established initially which was optimized during the course of the project and during on-site implementation. Several design changes to achieve the desired performance were evaluated and implemented in the field. Required microwave link availability and performance objectives were achieved as a result of collaborative efforts between the operating company, contractor and radio manufacturer over a multi-year period.

Use of quadruple diversity, optimal selection of frequencies, judicious use of ATPC (Automatic Transmit Power Control) and use of optimal signal polarisation were some of the methods used to achieve the desired link availability and performance. While these are well-known methods in radio engineering, the particular combination(s) employed to realize the desired performance objectives are identified in the paper as a lessons-learnt exercise which can be of wider application in the petroleum industry in the Gulf region. Over-water wideband microwave links are generally considered unreliable in terms of performance for utilization in process control applications involving remote shutdown and other critical operations. However, the links referred to in this paper continue to serve the field control system applications till date.