bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsurface Data Acquisition and Operational Excellence in ADNOC’s First CCS Well in the UAE
Authors: Karim M. , Farmer R. G. , Parra H. , Al Neyadi A. , Xu S. , Vantala A. , Arbadov G. 
Published: November 2024

Abstract
As a key milestone in ADNOC’s sustainability initiatives and to support the UAE’s net-zero goals, a major CCS project was initiated, focused on permanent CO2 storage in deep carbonate saline aquifers in onshore Abu Dhabi (Abu Dhabi Environment Report, 2017). Following a comprehensive feasibility study (Xu et al, 2022), a combined appraisal and injection site was selected and the first commercial CO2 injection well was completed in 2023.
This paper reports the outcomes of a comprehensive operational data driven acquisition program across two major saline aquifer reservoirs; Formation A and Formation B as well as across caprocks overlying these reservoirs. Data analysis involved the combination of wireline logs, core data and formation pressures and fluid sampling.
Iterative cross discipline involvement in the well design for the first CCS well was critical to achieve the data acquisition goals of the well (Figure 1). Key challenges involved integrating well data outcomes and conducting mini frac tests to evaluate the seal integrity of the overlying formations and confirm the reservoir rock quality and variability in A and B formations, which are under-explored in this part of the UAE.
The cap rock integrity was assessed by conducting multiple mini-frac tests in the Caprock and A formations. Drilling and logging programs were designed to ensure that reliable micro-frac tests and image log pre-post frac could be conducted. The results showed that the breakdown pressure in the caprock formation indicates a strong sealing capacity.
Quantification of reservoir quality and characterizing the heterogeneity was important, so core analysis was fast tracked and then matched with NMR results from the data acquisition. This dataset, combined with dynamic information, will be a crucial source for validating future CCS wells performance in UAE.
Once primary data acquisition was achieved across the reservoir and caprock intervals, all subsurface data analysis was carried out simultaneously and fast-tracked to ensure effective and reliable information was available to optimize decisions for the well to deliver on UAE’s net-zero aspirations strategy.
Advanced Phase Behavior Analysis of CO2-Rich Streams with Innovative ThermoQuartz ResoSense Technology
Authors: Hoopanah M. , Joonaki E. , Tohidi B. , Mozaffar H. , Vatandoost A. 
Published: November 2024

ABSTRACT
Advancing monitoring instruments specifically designed for detecting water condensate or hydrate formations is crucial for ensuring the safe and efficient production of gas and transportation of impure CO2 within specific pressure and temperature ranges. The prevention of water condensation and subsequent corrosion remains a major challenge in the energy industry, especially within the burgeoning Carbon Capture, Utilisation, and Storage (CCUS) sector. As the industry increasingly moves towards multiphase transportation, the need for advanced flow assurance monitoring technologies becomes necessary. These technologies are essential for accurately evaluating risks associated with water condensation, corrosion, and hydrate plugging, thereby facilitating the secure and efficient transportation of CO2. Significant issues arise due to changes in phase behaviour in CO2-rich streams. Even small amounts of polar impurities can alter the dew point and phase envelope, leading to the formation of corrosive aqueous solutions at temperatures well above the dew point of pure water. Impurities such as methanol and Triethylene Glycol are particularly concerning in CCUS networks. Currently, no off-the-shelf solutions effectively address these CO2-induced flow assurance challenges, underscoring the issue's complexity and importance.
This study aims to validate and improve our innovative sensor-based technology, ThermoQuartz ResoSense, which monitors phase behaviour and determines the dew point/vapor-liquid equilibrium in CO2 -rich streams. Several High-Pressure-High-Temperature-QCM experiments were conducted under stable pressure conditions, maintained either by pump operation or pressure suspension once the target was reached. The system was pre-conditioned at peak temperature, followed by controlled cooling through distinct cycles, with a corresponding heating cycle raising the temperature at the same rate.
Transformation of Concept Evaluation Studies with Cloud Native Digital Twins
Authors: Tran A. , Knight D. , Gaader A. 
Published: November 2024

Abstract
The adoption of cloud native digital twin platforms has, in the past 3–4 years, begun to alter completely the execution and delivery model for offshore concept and pre-FEED studies. When stakeholders visualize the field development concepts in 1D/2D/3D, ensure appropriate project data is shared seamlessly, and understand the remaining tasks needed to close the study considerable efficiencies will be attained. The early evaluation of these novel execution methods show project delivery time reductions of 45–55%.
Time spent by valuable staff finding and assembling the necessary data to conduct concept selection and Pre-FEED studies is better spent creating and evaluating a larger concept catalog. The digital twin platform streamlines gathering and the sharing of the 3D surveys, WMS data, legacy data stored in GIS, and even data in Excel files. Critical project data no longer is shared by staff via "electronic" files, email. The digital twin platform has unleashed secure project data via novel workflows inside the secure data platform in real time via the cloud. The team generates many more concept variants than ever before and by using the platform's APIs delivers concept data into external tools needed (cost, risk, engineering) for their screen processes.
Early phase project teams typically spend over 50 or 60% of their time working on a project just locating and assembling the various datasets that are needed to begin their workflows. The digital twin platform can easily ingest data from a wide variety of sources and build the background 3D model. The reported time savings for concept study workflows are: Build 3D background models – 40%; layout production equipment – 30%; route pipelines and umbilicals – 50%; create Concept Selection Report (Cost Estimates, MELs, 2D maps, 2D schematic of system) - 60%; Equipment Datasheets – 60%
Teams have reported that when major inputs to or requirements for the concept study have changed, such as well count or well location, the required effort to build the new concept catalog can be up to 70% less than without the use of the digital twin platform.
Traditional early phase project delivery methods are inefficient, creating unnecessary risk and uncertainty for front end teams from both operators and suppliers. Teams adopting a cloud-based, digital twin platform have created transformative workflows for the delivery of concept and Pre-Feed phases. These efforts have shown to boost productivity by nearly 50% and, more importantly, are allowing a deeper concept catalog to be studied which ultimately reduces the risk when executing the project in the EPCI phase.
Model-Informed Reservoir Appraisal Strategy to Reduce Reservoir Performance Uncertainty for Unconventional Development in Delaware Basin, New Mexico, United States
Authors: Alqallabi S. A. , Hehmeyer O. J. , Krishnamurthy J. K. , Bello R. O. , Forcina A. V. , Lopez C. , Miller N. M. 
Published: November 2024

Abstract
This study discusses an integrated reservoir assessment, including reservoir surveillance and analysis, fracture modeling, and reservoir simulation, carried out for an unconventional development prospect located in the Delaware Basin of New Mexico, United States. The objective was to assess reservoir performance, estimate the potential for vertical and lateral communication between reservoir intervals, and determine optimal well density. The assessment enabled the development of a fit-for-purpose appraisal strategy, grounded in modern reservoir data collection, which will effectively reduce uncertainty in the development plan.
This study used data from offset wells as a reference to conduct the analysis. The logs and reservoir data were used to develop reservoir and geomechanical property inputs for hydraulic fracturing and simulation modeling. Reservoir stress maps were created, and multiple stress scenarios, including isotropic and anisotropic, were generated and used as input to fracture simulation. Mechanistic fracture models were constructed for different reservoir intervals based on analog stimulation recipes and stress curve sensitivities. The resulting fracture geometries were input to reservoir simulation to determine the economically optimum well density.
The geomechanics analysis shows lateral variation in stress properties through the prospect area with limited stress barriers observed in some reservoirs. The hydraulic fracture models suggest limited vertical interaction between intervals. Simulation results suggest an optimum well spacing that is tighter for the shallower 2nd Bone Spring interval vs. the deeper Wolfcamp. Simulation results are supported by offset analogues which show well performance degradation at tighter spacing. Simulation shows reservoir performance is most affected by matrix permeability and fracture half-length. The models suggest significant remaining uncertainty. To reduce uncertainties, a robust, tailored data collection plan is proposed, including vertical and slanted horizontal monitoring wells instrumented with fiber and gauges, quad combo logs, core sampling, time lapse geochemistry sampling on ten wells, and six PVT samples.
The study highlights the significance of effective data integration from different subsurface domains to enhance field uncertainty understanding and avoid unnecessary costs during appraisal data collection.
First Successful Application of a Plug Set in a 4400-ft Lateral Section of a Horizontal Well Using the Electrical Power-Delivering Capability of the Longest Ever (28,000 ft) Real-Time Hybrid Coiled Tubing: Case Study From Oman
Authors: Gaur Rishika , El-Shepani Walid , Pert Mark , Amin Mohamed , Travesso Joshua , Barrera Romeo , Gomes Deylla , Al Jabrim Hoor Nasser , Al Barwani Mohsin , Al Jahwari Khalifa Hilal Khalifa 
Published: November 2024

Abstract
Intervention work is often necessary in field development with deep wells to enhance well performance. To improve this, acquisition of the flow profile data in these wells is vital for decision making. The use of rigless solutions to monitor production zones in extended-reach wells involves both technical and economic challenges attributed to the tortuous nature of these wells with high dogleg severity, considerable variations in azimuth, hole inclination, and general hole conditions.
The unique solution presented in this paper includes the longest real-time hybrid coiled tubing (RTHCT) technology deployment ever used in a high-pressure/high-temperature (HP/HT) extended-reach well. This approach enabled the operator to perform logging and plug setting operations to improve well performance with precision and reliability.
A robust hybrid cable design within the coiled tubing (CT) enabled continuous transmission of high-quality downhole data to the surface during the logging run. Based on the logging run diagnosis, an electrically controlled plug setting tool, casing collar locator (CCL), and gamma ray (GR) sensors were integrated into the plug setting bottomhole assembly (BHA). This setup provided dynamic control of the BHA from the surface to successfully set a plug to isolate watered-out layers in the well.
Previous issues reaching target depth (TD) with a wireline tractor BHA and the limitations of memory-based logging at high bottomhole temperature (BHT) necessitated the deployment of the longest 2 3/8-in. RTHCT. This approach effectively resolved these challenges.
The use of real-time data to enable accurate logging at the desired intervals and successful plug setting in one of Oman's longest laterals are detailed. Additionally, it marked the first successful deployment of 28,000 ft of 2 3/8-in. RTHCT in Oman.
Innovative and Cost-Effective Approach to Deal with the Challenges of Trapped Gas and Flashing in Produced Water System
Authors: Haider F. , Ali H. Al , Ketbi A. Al , Maeeni M. Al , Aslam M. , Ahmed S. M 
Published: November 2024

Abstract
The purpose of this paper is to present a case study on the challenges faced in handling produced water expansion project due to trapped gas and flashing which may lead to process safety event. This case study explains how the problem was solved during the integrated field development project at one of Company onshore's largest oil fields, which enabled the timely start-up of an extra 200,000BWPD capacity for handling produced water.
Oil production facilities are equipped with a produced water system, which includes primary and secondary treatments to ensure the produced water meets the necessary standards for reservoir reinjection and water disposal. In the context of integrated field development, two new disposal tanks and their associated pumping systems were added. However, during the commissioning phase of these tanks, high back pressure was noted, affecting the performance of all running five gas oil separation processing trains.
Produced water is not fully stabilized liquid, therefore dissolved gases flashed out once exposed to low pressure system plus the flashing that occurs along the line creates gas trapped in the highest point of the header which increases the back pressure in the header. This was finally crossed check with the piping network simulation. Based on field trail and dynamic simulation the successful implementation of the highest point close loop flash gas removal to low-pressure system indicates how trapped gas can be efficiently removed to secure the additional throughput of the water disposal system to cater to the future expansion demand of the oil and gas fields. Oil and gas producers may consider this provision in the inherent safety design of the produced water handling system.
This paper presents a case study of how Company solved the problem of trapped gas and flashing in the produced water handling system at one of its largest oil fields. The remedial exercise involved installing a close loop flash gas removal system at the highest point of the header, which reduced the back pressure and improved the performance of the gas oil separation trains. Early stage identification & evaluation of such instances can avoid disturbance in process safety events and timely commissioning of new facilities This solution enabled the timely start-up of an extra 200,000BPWD capacity for handling produced water and improved the process safety and reliability of the facility.
Optimizing Exploitation Strategies for UAE Unconventional Oil Resources: A Case Study on Integrating Rock Quality & Completion Quality Aspects
Authors: Rana Rakesh Roshan , Othman Abdelfatah , Kumar Gulshan , Sharma Sakshi , Shama Vaibhav , Baig Muhammad Zeeshan , Vantala Aurifullah , Blooshi Hamid Al 
Published: November 2024

Abstract
Exploration in the Shilaif formation, one of the unconventional reservoirs in the UAE, is challenging due to its complexities in lithology and its rock mechanics. Shilaif comprises bituminous, dark, fine-grained wackestones to packstones (Al-Zaabi and Taher et al., 2010), which inherently possess high heterogeneity in their petrophysical and geomechanical properties. This heterogeneity significantly complicates the identification of optimal zones for hydrocarbon exploitation, despite the formation's substantial hydrocarbon potential.
To address these challenges, a comprehensive, integrated approach is required to delineate the best reservoir intervals based on Reservoir Quality (RQ) and Completion Quality (CQ) metrics. This study leverages various methodologies, including petrography, petrophysical analysis including advanced Magnetic Resonance data, core analysis such as Routine Core Analysis (RCA) and Special Core Analysis (SCAL). Key techniques like Mercury Injection Capillary Pressure (MICP) for pore throat distribution and Self-Organizing Maps (SOM) for rock typing are also included. Additionally, geochemical and detailed geomechanical studies are integrated to identify perforation zones for efficient hydraulic fracturing (hydrofracture) initiation for flowable hydrocarbon evaluation.
For this integrated study, a well targeting the unconventional Shilaif was analyzed. Data collection included acquiring conventional core, wireline logs, mud logs, lithocuts etc. All the data corroborated and interpreted to prepare a working model that honors all data acquired through multiple sources/operations. This comprehensive data integration was crucial for the planning and design of hydrofracturing and subsequent well testing operations.
Geophysics Promotes the Large-Scale Development of Shale Gas in Sichuan Basin
Authors: Li M. , Zhu Y. , Yang X. , Wu F. , Deng X. , Wang X. , Chen M. 
Published: November 2024

Abstract
Development of shale gas in Sichuan basin, China, is challenging as the target is thinner than 10 m, the burial depth is deeper than 3500 m, and the structure and stress systems are complex. To promote the large-scale development of shale gas in Sichuan basin, dedicated geophysical techniques have been developed, and a framework integrating geophysics, geology, and engineering has been formed. In the integrated framework, geophysics works closely with geology and engineering from resource appraisal, well planning, to drilling and fracturing of horizontal wells. Application of this integrated framework coupled with geophysics, especially high-quality 3D seismic, can make significant contributions to the large-scale development of shale gas by reducing risk and cost while improving efficiency and profit. Also, the geophysical techniques described in this paper can be beneficial for the development of other cost-sensitive or risky conventional and unconventional resources.
Saving Massive Gas and Condensate Losses of Gas Producers Losses Due to the Nearby Well Drilling Requirement
Authors: Sudarev M. , Al Bairaq A. , Al Yaaqoubi N. , Alawadhi F. , Alhammadi S. , Al Shamsi A. , Mengal S. , Douglas M. , Sarsekov A. 
Published: November 2024

Reservoir pressure refers to the force that the fluids and gases in the underground rock layers apply on the surrounding environment. This force is an important factor that influences how well the drilling process can perform, how safe it is, and how efficient it is. Having accurate information about the reservoir pressure while drilling is crucial for choosing the right density of the drilling fluid and avoiding problems such as kicks, losses, or wellbore instability that can increase the drilling risks and costs. For this reason, there are some rules to follow to close nearby wells that can change the reservoir pressure while drilling. The current rules for Gas Condensate Reservoir suggest closing the gas producers that are less than 500 meters away and the gas injectors that are less than 2000 meters away from the drilling point.
By conducting a careful and continuous observation, it was noticed that one of the elements that affect the achievement of the delivery goal is the amount of gas and condensate that are lost as a result of the need to shut in the wells during the drilling process. This has a considerable impact especially in the case of the large-scale reservoir that requires a high level of drilling activity. The purpose of this study was to review and modify the criteria for shutting in the wells in order to decrease the losses that are caused by this requirement and consequently reduce the number of wells that are not in operation in the gas condensate reservoirs
Successful Deployment of New Generation Specialty Lost Circulation Material in Highly Fractured Formation, Offshore Abu Dhabi - Case Study
Authors: Goncalves Fabio , Zaheer Babar , Kulkarni Neeraj , Dangelo Giulio , Al Menhali Mahroos , DeBarros Adelson , Nasrallah Mena , Bashandy Tamer 
Published: November 2024

Abstract
Drilling through faults and fractured formations has always been a challenge. In most cases wells have either been re-drilled as sidetracks or trajectories modified to avoid faults and fractures altogether. New technology products have been engineered and tested to overcome this challenge specifically to achieve a Techno-economic, safe operation. In this case deployment of a new generation Mult-Modular lost circulation material (LCM) was customized to effectively cure losses in these fractured formations, thus enabling drilling the well to the target reservoir zone.
The loss mitigation plan for the subject well was prepared well in advance. Rigorous lab testing was performed on regular as well as larger slots to ascertain the plugging efficiency of the LCM. Formulations for both conventional LCM and Multi-Modal Composite LCM pills were optimized for this well based on lab tests. A clear decision tree was prepared with initial preference being to utilize conventional LCM pills first. LCM mixing and pumping procedures were detailed and discussed during the planning stage. Sufficient LCM inventory was made available for multiple pills to counter losses.
The results of the careful planning were evident. A total of six LCM pills were pumped in different loss zones encountered in the 20 inch section at various depths. Compared to the conventional LCM pills, the Multi-Modal pills containing composite particles combined with the reticulated foam showed superior performance in curing the losses from 150-230 bbl/hr down to 10 bbl/hr in all the loss zones encountered. All combinations of conventional Lost Circulation Material (LCM) with high concentrations proved to be ineffective once severe or total losses were encountered in these formations (Saragi et Al, 2021). Each pill pumped cured losses ranging from total losses reducing to full return. The 12 ¼ inch section also saw similar loss behavior where a total of ten specialty Multi-Modal LCM pills were pumped at various depths which were successful in completely curing the losses. As a result both the 20 inch and 12 ¼ inch hole sections were successfully drilled to target depths.
Multi-Modular LCM material including new technology foam material were implemented and successful in both lab and field trials in curing total losses. These pills were produced stable plugs able to withstand the pressure required for a successful solution. Proper design of the LCM can help avoid or at least minimize the impact of losses when drilling thief zones and improve wellbore integrity during the well's life cycle.