bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Workover Unit Utilization for New Well Openhole Drilling with Directional Motor and Logging-While-Drilling Bottom-Hole-Assembly in M Area
Authors: Rachman Buna Rizal , Noviasta Bonar , Wijayanto Timora , Mardiana Ramadhan Yoan , Taufik Esa , Saputra Rangga , Styward Boris 
Published: December 2021

Abstract
Achieving a number of well targets in M Area is an important objective for MK, one of the oil and gas operators in Indonesia. An economic challenge is present due to marginal gas reservoirs in shallow zone. The conventional swamp rig unit requires significant costs for site preparation work and in some cases no longer fulfils the economic criteria. The objective was to drill the same one-phase well (OPW) architecture as the swamp rig normally drills, but at lower costs using a hydraulic workover unit (HWU).
Drilling the 8½-in hole section OPW architecture using HWU was challenging, not only on the equipment rating and capability, but also on the deck space limitation part. The fit-for-purpose directional and logging-while-drilling (LWD) system was utilized in this project consisting of customized low-torque excellent hydraulics drill bit design, a positive displacement motor (PDM) with aggressive bend setting to achieve directional objective (with max 3.8°/30-m dogleg severity), annular-pressure-while-drilling (APWD) measurement to ensure equivalent circulating density (ECD) is maintained, and combined electromagnetic propagation resistivity and sonic slowness measurement coupled with high-speed telemetry measurement-while-drilling (MWD) tool to get an accurate and timely formation evaluation. The HWU deck space limitation was solved by implementing a single combined directional drilling (DD), MWD, mudlogging cabin, in addition to the remote operation control implementation to further reduce carbon footprint.
Five wells were drilled safely and successfully in this campaign. Drilling efficiency improved with up to 109% ROP increase as compared to the first well, showing the progressive learning curve and excellent teamwork from all involved parties. The directional bottom hole assembly (BHA) was capable of delivering up to 4–5°/30-m dogleg, not only achieving the directional objective, but also penetrating the reservoir targets with tight tolerances. The drill bit delivered very good ROP, reaching 60.4 m/h (about 66% of average OPW ROP achieved by swamp rig). This campaign also successfully reduced the overall site preparation cost by up to 30%, enabling MK to drill wells that were initially not feasible to be drilled using swamp rig within the time frame and budget. Thanks to the success, this new method is currently under study for industrialization. The HWU drilling campaign provided a valuable learning experience, is considered as a proven drilling method, and served as a benchmark for other operators in Indonesia.
HWU drilling has proven to be an efficient drilling method and capable of delivering the one-phase-well. This paper presents a unique case study of new well open hole drilling with the HWU and its applicability in M Area. Most studies in the past were HWU drilling in re-entry or sidetrack cases.
A Novel Approach to First in the World Retrieval of Open Water Vertical Xmas Tree
Authors: Liew William Sin Yoong , Heboul El Khalil , Bin Allapitchai Mohamad Shahril Majid , Sellapan Sattiyaraju , Bin Johan Ahmad Luqman , Bin Ahmad Zaini Ahmad Hafizi , Bin Abdul Razak Mohd Hairi , Binti Dharma Dian Puteri Dharmilla Syafawati , Bin Abdullah Ahmad Zharif , Zomerdijk William 
Published: December 2021

Abstract
Wells plug & abandonment was carried out in a deepwater field (Field C) offshore West Africa. There were 15 deepwater subsea wells in this field. Thirteen of the wells were completed with Open Water Vertical Xmas Tree (OXT) while remaining two were completed with Enhanced Vertical Xmas Tree (EVXT). In the wells with Open Water Vertical Xmas Tree (OXT), the upper completion tubing and hanger were ran together with the Xmas Tree in a single run. This posed challenges to Operator in retrieving the Xmas Tree. This paper will discuss the novel approach used by Operator in the OXT retrieval.
Due to the design of OXT which was different from most of the vertical Xmas Trees (XT) in the world, there were a few challenges in the process of XTs retrieval. If the XTs and upper completion tubing were retrieved in reversal of the way it was completed, it will exposed the well to prolonged duration of single barrier until a BOP can be latched on for subsequent activities. On top of that, the Original Equipment Manufacturer's Completion Workover Riser (CWOR) system and Support Landing Structure (SLS) was not available in full package to be utilized in this project. Furthermore, there were constraints on the rig moonpool space, handling of OXT on surface and clashes between the rig's BOP and existing subsea structures.
In managing the risk of well exposure to single proven and monitored barrier during the process of OXT retrieval, Operator has evaluated a few options and came out with a novel approach in the OXT retrieval which managed to minimize exposure time and reduce risk in operations. In contrary to the original principle of well completion here, after a barrier was established in the well, the OXTs was retrieved separately from the upper completion tubing to allow rig BOP to be latched onto wellhead in shortest possible time. To achieve this objective, operations was planned to be carried out on a dual activity derrick rig. Meanwhile, a non-OEM rental CWOR system was used together with Tree Running Tool from the OEM CWOR system to access the wells for intervention work and subsequently retrieve the OXTs. By doing this, the combined CWOR stack exceeded the height limitation at the rig's moonpool. Some modifications were carried out to allow the operations to happen. A novel approach was also used to handle the OXT on surface without the OEM Support Landing Structure - which simplified the operations and reduced HSE risks. Solution was also put into place to enable latching of the rig BOP onto wellheads on Drill Centre although there were risk of clashing initially.
Troubleshooting Gas Dehydration Systems Using Data Analysis
Authors: Al-Aiderous Abdullah 
Published: December 2021

Abstract
The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to operate a TEG dehydration system optimally and reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature.
In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.
Doubling its Production in One Year: Reviving a Brown Field in South of Oman
Authors: Suut Suria Amalia , Al Kalbani Mahmood Khamis , Quseimi Issa , Gahaffi Abdullah , Wielaard Arjen , Hamouda Rady Abdel Samiee , Al Abri Abdullah Zahir , Hasani Hanaa 
Published: December 2021

Abstract
This paper summarises a ONE development success story of reviving a mature brownfield in South of Oman, Field β, just within ONE year through collaboration between different disciplines, comprehensive data analysis, optimising and recompletion of existing wells. Field β, comprised of multi-stacked clastic reservoirs, was put on stream in 1980s and peaked in early 1990s. Pilot water injection started in 1993 and full field water flooding continued in 1997. After more than 35 years since start of production, one can say the field was already in the tail end of its life. It had been stabilizing at low rate after 25 years and starting to decline further and at some point was one of the potential candidates to be decommissioned. A new FDP (FDP18) for part of the field was delivered in 2018 with the first well drilled at the end of that year. In 2019, despite drilling further wells on the FDP18, production was declining and was at 2018 rate towards the year end. Intensive data analysis and integrated reservoir reviews per reservoir layers were actively performed and new opportunities and data gathering were identified. FDP18 wells from 2019 onwards were then deepened to also acquire log data over deeper than the target reservoirs. Further synergy between asset and exploration teams also instigated in new discoveries including oil in shallower carbonate reservoirs, which were logged and sampled when drilling the FDP18 wells. Declining production, low oil price and COVID-19 crisis that hit 2020 challenged the team to be more resilient and with ONE development mindset between development and WRFM team, also between asset and exploration team, existing long-term closed in and very low productivity wells were utilised to tap these new opportunities. As a result, the field production has been increased by more than double, highest since 10 years ago, with a potential of triple its production rate, all achieved through optimizing and recompletion of existing wells within 1 year, at a very attractive low UTC.
Liverpool Bay Area CCS: An advanced Case Study to Achieve UK's Carbon Neutrality
Authors: Becker Bruce William , Baldino Francesco , Aleandri Alessandro 
Published: December 2021

Abstract
The Liverpool Bay Asset Carbon Capture and Storage (LBA CCS) project is being developed in parallel with, and as an integral part of, the HyNet North West integrated project, which is aimed at decarbonizing the important industrial region of North-West England and North Wales. The Liverpool Bay Asset (100% Eni UK Limited) is approaching the end of its production life and would be progressively decommissioned over the period 2023 to 2025 without the prospect of re-configuring to a CCS project. Eni plans to reuse and repurpose the depleted hydrocarbon reservoirs of the Hamilton, Hamilton North and Lennox fields together with their associated infrastructure to transport and store carbon dioxide (CO2) emissions captured upstream by the HyNet NW partners. A Carbon Dioxide Appraisal and Storage Licence was awarded to Eni by the UK Oil & Gas Authority (OGA) in October 2020 for this purpose.
The project has now completed the Concept Selection Phase and the paper describes the multidisciplinary work covering subsurface, facilities and drilling engineering, flow assurance and project management that has been completed to select the development concept for advancement into the concept definition phase. It demonstrates the viability and benefits of re-using depleted fields and existing infrastructure originally installed for hydrocarbon production to reduce the unit cost of storage, a key metric for all CCS projects.
Unifying of Steady State and Transient Simulations Methodologies for Increasing Oil Production of Integrated Network of Wells, Pipeline and Topside Processing Equipment
Authors: Ali Zalina , Anuar Astriyana , Grippo Nicolas , Ramli Nurshahrily Emalin , Rahim Najmi 
Published: December 2021

Abstract
Aging facilities and increasing complexity in operations (e.g., increasing water cut, slugging, sand or wax production) continue to widen the gap between actual production and the full potential of the field. To enable production optimization scenarios within an integrated system comprises of reservoirs, wells and surface facilities, the application of an integrated network modelling has been applied. The highlight of this paper is the synergy of Integrated Production Network Modelling (IPNM) utilizing Steady State Simulator (PROSPER-GAP) and the Transient Simulator (OLGA) tools to identify potential quick gains through gaslift optimization as well as mid and long-term system optimization alternatives. The synergy enables significant reduction in transient simulation time and reduced challenges in OLGA well matching, especially in selecting accurate modelling parameters e.g., well inflow performance (validated well (string) production data, reservoir pressure, temperature and fluid properties and the Absolute Open Flow (AOF) of each well). The paper showcased the successful production gain achieved as well as the workflows and methodologies applied for both Steady State Integrated Production Modelling (IPM Steady State) and Integrated Transient Network Modelling (IPM Transient) as tools for production enhancement. Even though IPM Steady State shows promising results in term of field optimization potential, to increase accuracy and reduce uncertainties, IPM Transient is recommended to be performed to mimic the actual transient phenomena happening in the well to facilities
Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field
Authors: Al Shehhi Hajar Ali Abdulla , Bernadi Bondan , Belal Al Shamsi Alia Belal Zuwaid , Al Hammadi Shamma Jasem , Alawadhi Fatima Omar , Mohamed Ihab Nabil , Al Bairaq Ahmed Mohamed , Al Hosani Mariam Ahmed , Abdullayev Azer , Roopal Allen 
Published: December 2021

Abstract
Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity.
The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore.
The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs
This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.
Elimination of Tight Emulsions
Authors: Ellingsen Haakon , Jaouhar Hikmat , Hannisdal Andreas 
Published: December 2021

Abstract
Maturing oil fields can pose a severe challenge for separation of oil and water. Increasing water production and tie in of new fields into existing infrastructure may result in separators struggling to meet performance specifications. Operational challenges are particularly experienced when the facilities are processing cold feedstock and tight emulsions. Typical solutions for overcoming separation challenges would be increasing operating temperature, injecting an increased quantity of demulsifier chemicals, or installing new larger separators. These alternatives may not be economically attractive or feasible for other reasons. The ability to successfully operate existing plants with tight and water-rich emulsions without incurring significant added operating expenditure is perceived as a major advantage.
This paper will share the results from testing on a separator operating with Flotta Gold crude oil. The oil is known to produce particularly tight emulsions at low temperatures. The ePack technology has been tested to study its capability of separating water and crude oil from tight emulsions by means of electrical forces.
The force generated by the high electrical field can break even tight emulsions, and the test results shown have proven the ability to go from very low separation efficiency without the ePack, to more than 90% water removal with the ePack turned on. Testing with residence times of up to 19 minutes without the ePack was not able to surpass the performance of a three minutes residence time with the ePack energized.
Full Waveform Inversion for the Near Surface Characterization, Onshore UAE, Case Study
Authors: Dixit Rahul , Vasilyev Pavel , Mihaljevic Ivica , Tham Michelle , Vigh Denes , Zarkhidze Alexander , Cambois Guillaume Marie , Mahgoub Mohamed 
Published: December 2021

Abstract
Full-waveform inversion (FWI) has become a well-established method for obtaining a detailed earth model suitable for improved imaging, near-surface characterization and pore-pressure prediction. FWI for onshore data has always been challenging and has seen limited application (Vigh et al, 2018). It requires a dedicated data processing approach related to the lower signal-to-noise ratio, accounting for variable topography and complex near-surface related effects.
During the past few years, ADNOC has been acquiring and processing one of the world's largest combined 3D onshore and offshore seismic surveys in the Emirate of Abu Dhabi. The modern acquisition parameters that were implemented enabled the acquisition of broadband onshore seismic data rich in low frequencies that could benefit the initial stages of the FWI workflow.
Sand dunes and sabkha layers at the surface, and high-velocity carbonate and dolomite layers in the subsurface pose a significant challenge for near-surface modeling in the UAE. The purpose of this work is to evaluate FWI application onshore UAE for near-surface characterization. We will compare the FWI results with conventional approaches for the near-surface model building that has been used routinely on land datasets in UAE, such as data-driven image-based statics (DIBS, Zarubov et al, 2019).
One of the main challenges is data preconditioning, as onshore seismic data typically exhibits high levels of noise. It is imperative to denoise gathers sufficiently prior to the FWI process. A well sonic velocity function with large smoothing was used to build the starting velocity model for FWI. The process aims to minimize the least-squared difference between predicted and observed seismic responses by means of updating the model on which the prediction is based. As the predicted and seismic responses are functions of model parameters as well as source signature, a good estimate of the source wavelet is important for update and convergence in FWI. During this FWI work, source wavelet inversion was done as a separate step and used in subsequent FWI passes.
FWI inversion started with adjustive FWI (Kun et al, 2015) on lower frequencies, moving to higher frequencies where both adjustive and least square objective functions were used. We will further show assessment of the anisotropy, initial conditions, usage of geological constraints, and comparisons to the conventional solutions. A comparison of results shows that FWI has successfully added velocity details to the near-surface model that follow the geological trend and conforms to well information while producing a plausible static solution.
We have demonstrated the application of FWI onshore UAE for near-surface modeling. Although turnaround time (TAT) has increased compared to the conventional approach, the learning that was gained during this trial will decrease TAT for the future FWI work.