bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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.
Corrosion Mitigation Using Nonmetallic Piping for In-Plant Hydrocarbon Service
Authors: alghanim Abdullaziz Abdullah 
Published: December 2021

Abstract
The underground hydrocarbon metallic lines are usually subjected to severe corrosion due to several reasons such as high water table in the area and due to intermittent bi-directional crude service or similar environmental factors. To meet the challenge, non-metallic underground crude transfer lines may be considered to carry oil from/to the bulk storage sites. Since there are not many non-metallic applications in HC services, it may become a challenge to get the necessary approvals from the various stake holders in terms of concerns for asset integrity and the costs. This report details the conversion of metallic crude pipeline application to a non-metallic one.
Normally, the in-kind replacement will involve an internally coated CS line to reduce corrosion rate. However, engineering studies and assessments reveal that there are greater economic benefits when adapting to a non-metallic counterpart. For a generic case, hydraulics on a 1.7km crude transfer line with 48" diameter and the intermittent crude service revealed that 36" non-metallic version could do the job with less installation costs as minimal site activities will be required and there will be no requirements of non-destructive tests (NDT). Only a service test following the installation may be necessary to prove the operational integrity. Cost comparisons showed a 28% less project cost in using the non-metallic pipeline while meeting all other application requirements.
The introduction of non-metallic line would take away the problem of the external and internal corrosion from the equation. Especially in the aging facilities where fatigue becomes an issue, the carbon steel line always requires additional maintenance activities and there was always a chance to develop an underground pin hole. Therefore, an extensive inspection program had its own costs to maintain the line. With the non-metallic pipe usage, not only the construction costs can be lowered but it could avoid major inspection and maintenance program costs. The Nonmetallic line is considered low to maintenance free, and additional long-term savings are expected.
This application opens the door for the utilization of nonmetallic material in plant hydrocarbon processes. And given the size considered of this line (36 inches), this allows for further consideration to install nonmetallic piping on a wide range of applications. Also, non-metallics are especially effective for sluggish or intermittent flows and areas with high water table to avoid all sorts of erosion and corrosion issues internally due to process conditions or externally due to environmental conditions.
Integrated Logistics Solutions Provider Project
Authors: DeJonge Markus Alfred , Abdul Salam Mohammad , Ward Pete Miguel 
Published: December 2021

Abstract
The Integrated Logistics Solutions Provider concept was introduced to support offshore drilling and production operations, save 20% on logistic costs, increase operational efficiency to achieve Just-in-Time deliveries and enable the upstream portfolio to focus on core competencies, thus seeking an One-stop contractor for logistics.
This manuscript details how the logistics provider changed its operating model to an Integrated Logistics model, changed the status quo to become a competitive low-cost operating logistics provider and enabled operational and cost efficiency for Exploration and Production (E&P) customers. It also reflects on the technologies and commercial mechanisms used to drive the functioning of the operating model that meets the requirements of oil and gas operators.
Integrating Laboratory Testing and Numerical Modelling for a Giant Maturing Carbonate Field in UAE — II. Coupled Geomechanical Modelling of Stacked Reservoir Intervals
Authors: Noufal Abdelwahab , Nasreldin Gaisoni , Al-Jenaibi Faisal , Martin Joel Wesley , Guerra Julian , Al Sahn Hani , Muniz Eudes S. , Khan Safdar , Shehab Abdulla M. 
Published: December 2021

Abstract
A mature field located in a gently dipping structure onshore Abu Dhabi has multiple stacked oil and gas reservoirs experiencing different levels of depletion. The average reservoir pressure in some of these intervals had declined from the early production years to the present day by more than 2000 psi. Coupled geomechanical modelling is, therefore, of the greatest value to predict the stress paths in producing reservoir units, using the concept of effective stress. This paper examines the implications for long-term field management—focusing primarily on estimating the potential for reservoir compaction and predicting field subsidence.
This paper takes the work reported in Noufal et al. (2020) one step further by integrating the results of a comprehensive geomechanical laboratory characterization study designed to assess the potential geomechanical changes in the stacked reservoirs from pre-production conditions to abandonment. This paper adopts a geomechanical modelling approach integrating a wide array of data—including prestack seismic inversion outputs and dynamic reservoir simulation results. This study comprised four phases. After the completion of rock mechanics testing, the first modelling phase examined geomechanics on a fine scale around individual wells. The goal of the second phase was to build 4D mechanical earth models (4D MEMs) by incorporating 14 reservoir models—resulting in one of the largest 4D MEMs ever built worldwide. The third phase involved determining the present-day stress state—matching calibrated post-production 1D MEMs and interpreted stress features. Lastly, the resulting model was used for field management and formation stimulation applications.
The 4D geomechanical modelling results indicated stress changes in the order of several MPa in magnitude compared with the pre-production stress state, and some changes in stress orientations, especially in the vicinity of faults. This was validated using well images and direct stress measurements, indicating the ability of the 4D MEM to capture the changes in stress magnitudes and orientations caused by depletion. In the computed results, the 4D MEM captures the onset of pore collapse and its accelerating response as observed in the laboratory tests conducted on cores taken from different reservoir units. Pore collapse is predicted in later production years in areas with high porosity, and it is localized. The model highlights the influence of stress changes on porosity and permeability changes over time, thus providing insights into the planning of infill drilling and water injection. Qualitatively, the results provide invaluable insights into delineating potential sweet spots for stimulation by hydraulic fracturing.
Success Implementation of Pressurized Mud Cap Drilling in Offshore East Java Prospect, Avoid Rig Flat Time During Loss Circulation and Continue Drilling with 400psi in the Annulus to Reach Target Depth Through Fractured Carbonate Formation in 2 Days
Authors: Fikri Irawan , Ali Ali , Airil Ismi , Andry Prasthio , Teguh Setiawan , Agung Pratama 
Published: December 2021

Abstract
The offshore East Java laid numerous carbonate formation, where depending on area, carbonate formation is exercised as the reservoir. The carbonate exploration drilling campaign, which is naturally fractured, risks the operation not just from safety aspect but also deliverability of well objective to explore uncovered reserve in the area.
In this well, total loss circulation was experienced while drilling, despite no record of similar event from offset wells data. The field operator determined to call out Rotating Control Device (RCD) and installed prior to drilling 12.25in. hole section. The Pressurized Mud Cap Drilling (PMCD) method is prepared in advance as mitigation plan to overcome the exploration uncertainties. PMCD is one of the Managed Pressure Drilling (MPD) variants used in oil and gas wells that experience severe to total loss circulation. PMCD method involves drilling with closing flowline valve completely while using RCD system to seal the annulus.
While drilling the 12.25in section, absence of return fluid observed as drill string penetrates the carbonate reservoir section (target formation). Activation of the annulus flooding system enables to pumps seawater through annulus, continued with pulling out the string to last casing shoe, and then installation of RCD bearing assembly to convert drilling strategy into PMCD method. As the PMCD components required such as RCD and drill string Non-Return Valve already equipped and all associated procedures prepared in advance, swift transition to PMCD mode results to lesser drilling flat time. After reaching target depth, the PMCD setup also assists in the deployment of open hole logging operation by installing RCD logging adaptor.
With the successful PMCD implementation, the field operator managed to reduce drilling risks, reach exploration target successfully, reduce flat times and increase in ROP. This paper present success story of PMCD well drilled and lessons learned as the operator evolves to improve PMCD execution further.
Innovative Solutions to Decarbonize Hydrogen Production
Authors: Pitcher Matt , van 't Hoff Martin , Basmajian Narik 
Published: December 2021

Abstract
The Energy Transition mandates durable long-term solutions for reducing greenhouse gas (GHG) emissions by addressing future energy needs in terms of generation, storage and utilization.
Hydrogen is essential to low-carbon energy solutions, particularly in the "difficult-to-decarbonize" segment of energy markets. Deeply decarbonized, cost-effective hydrogen production solutions are already accessible at industrial scale, for both new plants and for retrofits. For newly built plants we easily arrive at deeply reduced carbon footprints, and KPI's comparable to the most competitive green solutions. Retrofitting existing hydrogen plants to "blue plants" is not only feasible, but is a particularly cost-effective carbon reduction measure.
This paper addresses carbon intensity of various hydrogen production routes: ranging from traditional grey hydrogen (itself with proven options for carbon mitigation) through blue hydrogen with various schemes and capture depths, as well as green hydrogen (generally by electrolysis).
Advanced Engineering Solutions to Achieve Best in Class Performance in Drilling Extended Reach Dual Lateral Wells in the Sultanate of Oman
Authors: Al Amri Yahya Badar Nasser , Al Rawahi Qasim , AL Adawi Humaid , Al Maashari Badar , Soden Ludovic , Al Kaifi Ahmed , Al Hussaini Marwan 
Published: December 2021

Abstract
A Large Omani Operator successfully achieved best in class performance in drilling extended reach dual-lateral wells in Oman. Turning the legs to achieve the required separation distance and continue drilling to the required depth through a thin fractured reservoir resulted in complex well trajectories and harsh drilling environment. This paper will focus on the newly innovative designs, engineering optimizations and utilizing lean methodology to overcome drilling risks and achieve best in class performance.
Rotary Steerable system was utilized to drill the extended reach drilling (ERD) in 3D with continuous proportional steering technology. Advance modeling including lateral shocks, Torque and Drag and BHA design were as well key enablers. Logging while drilling tools supported reservoir mapping and real-time well placement decisions. To excel in lateral applications and overcome harsh drilling
environment, a shallow cone tip profile with High Performance cutter bit technology was selected. A focus optimization project using lean tools was performed to map out the undercut process, visualize possible waste, perform root causes analysis and implement countermeasures to eliminate the process waste
Regional benchmark showed that the performance of 11 wells drilled since the start of the campaign is located within the best 10% of the benchmark data which is marked as best in class performance. Due to the continues improvement, the campaign manages to reach a learning curve of 30%. Furthermore, the actual production from the wells was 300% more than the forecast. Using the advanced RSS and bit technologies resulted in reducing the Torque values in the lateral section by 30% which effectively increased the reservoir drilled interval by 22%. The designed BHA also managed to complete wells including multi undercuts (up to 6) in one run. One trip Whipstock System for creating the second leg is used as part of the well design. The Whipstock system which is uniquely set in the horizontal tangent section has achieved 100% success rate in setting and retrieving operations. The undercut activities have improved by 50% as a direct result of the optimization Lean project. In addition, utilizing lean methodology resulted in reducing the cost impact of the additional sidetracks (undercuts) which enabled having best reservoir quality and achieving savings over the total cost of ownership TCO.
Extended Reach Dual lateral well design was utilized for the first time in PDO operations during this drilling campaign. This paper will present how advance modelling can enable the industry to deliver complex well designs. Additionally, it will introduce the company innovation in implementing the Lean philosophy to optimize the drilling operation.
Safety 4.0 for the Most Dangerous Industrial Objects
Authors: Razuvaev Igor 
Published: December 2021

Abstract
Isothermal Storage Tanks (IST) contains tens thousands tons of the liquefied gases (propane, ethane, ethylene, etc.) at very low temperatures. These are the most dangerous industrial objects. In the report the Integrated Structural Health Monitoring (ISHM) Systems for the management of the integrity of these tanks in real time is considered. The structure of the ISHM Systems, NDT methods, technical characteristics, data verification procedures, a decision-making algorithm and practical results are described.