bluuebunny/crossref_metadata_2025_split huggingface dataset:
Customized High Performance Water Based Mud Substituting Oil Based Mud to Drill Nahr Umr Shale and High Over Balance Reservoirs in Onshore Abu Dhabi
Authors: Saragi Raymond , Husien Mohammad , Mubiru Gerald Wilson , Mahrous Mostafa Fekry Elsaid , Atabany Hosam Gamal 
Published: May 2024

Abstract
In alignment with Abu Dhabi onshore operation's sustainability pillar to reduce carbon emission in the operation and identified significant waste management cost saving of oil-based mud cuttings, operator and fluids provider team collaborated to customize and conduct trial for using a high-performance water-based mud to drill Nahr Umr shales, substituting normal practice with oil-based mud. Extensive laboratory work was carried out i.e., cation exchange capacity, capillary suction time, XRF/XRD analysis, linear swelling test, accretion and erosion test using Nahr Umr shales’ cuttings to customize the fit for purpose high-performance water-based mud.
Both parties successfully used a high-performance water-based mud system to drill challenged wells. Trials evaluated the fluid performance for different well designs – where the subjected section size varies between 8½ in and 12¼ in. Trials-as well-included wells with expected severe to complete loss of circulation scenarios therefore, expanding the evaluation of fluid ability for stabilizing the shale under such tough operational conditions. The operation's success in achieving well objectives depended on appropriate mud formulation and maintaining the right concentration of shale inhibitors.
This paper describes the development and field trial of fit for purpose solution of high-performance water-based mud that enhances shale stabilization properties much like oil-based mud but without the associated waste management cost and it is an environmentally friendly system. Furthermore, other benefit is to overcome the logistic challenges of handling oil-based mud in the event of total losses that quite often happened across the high over balance formations below Nahr Umr shales as the rigs are remotely located in the desert.
Produced Water Management Integrated Workflow and Innovative Approach: Case Study from GUPCO/DO
Authors: Aboelhassan Mohamed Gamil , Mousa Hisham Elsaid , Shahin Eman Sayed , El-Shiekh Mahmoud Ibrahim , Elwan Mahmoud Attia 
Published: May 2024

Abstract
Excess water production is becoming a major problem in mature oil fields as the oil reservoir is subject to long water flooding process. As the oil field matures, producing more oil out of maturing reservoirs entails more water production. It is essential to have a robust water management process in place.
Gulf of Suez Petroleum Company (GUPCO) is a pioneer in Egypt and middle east when it comes to applying a very advanced water flood projects for secondary recovery, Starting from Morgan field, Ramadan, October and July field by injecting into different reservoir Lower Rudies, Upper Rudies and Cretaceous, these successful examples have been done and still running to recover great amount of oil.
Some of company reservoirs as Nubia Reservoirs produce under strong water aquifer drive mechanism other reservoirs like Morgan field where the majority of production comes from Kareem and Belayim reservoirs under depletion drive mechanism that's why water flooding was crucial to maintain reservoir energy and increase recoverability thus increasing total water production as well
The presence of water in the production stream can have several effects specially on GUPCO offshore production facilities, and managing water production is a critical aspect of offshore operations as it may affect several aspects of production oil cycle like; Increasing Operating Costs, Corrosion and Scaling, Wellbore Issues and Environmental and Disposal Challenges.
Produced water management is now under great concern from the company management that's why a multidisciplinary team consisting of Reservoir Engineers, Production Engineers and field engineers aiming to work on reducing water production by 30% as well as saving 30% from injection gas lift gas.
The team worked in an integrated and innovated approach with a detailed workflow with 3 phases of implementation, the output was an initiative plan, which includes actions in the high-water rate producers like direct water shut-offs for the water source zone, surveillance for future actions and Actions in the offset injectors that includes isolating perforation intervals or surveillance in addition to new water injection conformance.
In-Situ Generated Acid Stimulation for Productivity Enhancement – A North Sea Case Study
Authors: Smith F. T. , Forsyth J. 
Published: May 2024

Abstract
A new approach to acidizing gas wells where an inert dry chemical hermetically was sealed inside a metal carrier and deployed downhole via slick-e-line. Once in place downhole, an exothermic chemical reaction was initiated which produces hot acid vapour. This method permits target acid placement in a heated vapour form. The well was a depleted deviated gas well in a sandstone reservoir at approximately 15000 ft MD with 4 1/2" tubing. Three unique intervals were treated using 5 runs using a combination of HCl and Mud Acid (12:3 HCl/HF mixtures). Post-treatment, the production and operational/up-time increase of 30% was sustained for over a year.
A process to determine the optimal tool quantity, placement and type was conducted by the operator and the service company. It was important to minimize total fluid pumped and to employ HF but also minimize the risk of handling live acid at surface. It was determined that one 2 ½" HCl tool, one 2 ¼" HCl/HF and three 2 ½" HCl/HF tools would adequately treat the interval. Another consideration was that a hold-up depth (HUD) was present half-way through the interval. It was decided to attempt to remove this deposit by spotting tools immediately above the HUD. The HUD was thought to comprise primarily of heavier solids originating from the formation combined with CaCO3.
The first two runs used a 2 ½" HCl tool and a 2 ½" HCl/HF to remove scale and stimulate the near well bore. The third and fourth runs were ignited immediately above the HUD to remove some of the HUD and to squeeze and treat the interval below the HUD. The final run was done on an interval roughly 20 feet above the HUD. After each run, a build-up test was performed that showed a progressive improvement in the build-up time. Prior to treatment, the well had been consistently producing at 1.9 MMscf/day with a 32% uptime. Post-treatment, the well produced at 2.0 MMscf/day with a 42% uptime which was sustained for a year. Each run from run in hole to laying out the tool post-treatment was approximately 6.5 hours. The tools were deployed on slick-e-line and temperature and pressure was recorded downhole. All tools were deployed and operated successfully maximizing the amount of acid generated in-situ.
Using this novel technique, the overall gas production and well up-time was markedly improved. The operation was conducted in an efficient manner with simplified logistics when compared to conventional acid treatments. The use of HF was identified in the selection process as being key to the success of the operation and the option to deploy in a safe manner that didn't expose personnel to acid was a key determinant in employing this novel technique in the field.
Sweet Spots in Coal Bed Methane (CBM): Major Controlling Parameters Identification Through Reservoir Modeling, Simulation, and Uncertainty Analysis to De-Risk Field Development
Authors: Parida B. P. , Sinharay R. 
Published: May 2024

Abstract
Sweet spots are the areas where reservoir parameters are suitable for maximum production with the least possible footprint and investment. The high complexity of reservoirs, absent or insufficient seismic data and the requirement of a great number of wells are the major challenges and hence, sweet spot identification during the exploration stage is key for the optimized appraisal of a Coal bed Methane (CBM) field. Identifying major controlling parameters that impact production is the first and foremost step towards demarcating the sweet spot.
A unique workflow consisting of reservoir characterization, modelling and simulation was used along with both short- and long-term uncertainty analysis. Different reservoir parameters analysis acquired from different sources like laboratory or field tests are critically analyzed to characterize reservoirs. Data were analyzed to define the range of variation of individual parameters to build reservoir models for uncertainty analysis. The single well models on each of the 50 cases were run in prediction mode in Eclipse as a dual-porosity system. The model results of estimated ultimate recovery (EUR) are plotted in a tornado plot to analyze the relative impact of each parameter.
From the analysis, it is found that Gas content, Permeability, thickness, and gas saturation are the dominant parameters for sweet spot demarcation although a few other parameters like bottom-hole pressure constraint, and relative permeabilities are also impacting the production, especially during early periods of production. As per plots, porosity also plays a role but as its range is very low, it could be ignored. It is interesting to note that the order of impacting parameters changes from long-term to short-term. In the long term, thickness and gas content i.e., resources play a bigger role than saturation, permeability, or relative permeability. But in the short term, which is important for the economic success of the field, permeability, saturation, and relative permeability plays a more important role. This helped in identifying sweet spots in this coal reservoir by shortlisting the areas where these dominant controlling parameters coexist and are well developed. Further, sweet spots are used to plan appraisal or pilot production test wells whose success ultimately leads to field-scale development.
The present study brings uniqueness in the form of an innovative workflow consisting of reservoir characterization, modelling, and simulation. This has been used along with both short and long-term uncertainty analysis that adds considerable value to the existing knowledge. This workflow can be applied in other reservoirs or basins which may help CBM exploitation time and cost effective and optimize the field development.
Innovative Modeling Maximizes Value from Smart Well Completion
Authors: Aljauydi H. S. , Winarno M. B. , Ciufu A. C. , Isichei O. L. 
Published: May 2024

Abstract
The objective of this paper is to optimize the production contributions of each lateral in oil wells using smart well completion (SWC). This includes enhancing sweep efficiency, increasing oil production, and minimizing water production. The paper also aims to address the challenges that arise when the SWC system is installed with Electric Submersible Pumps (ESPs).
Lateral pre-testing is conducted to assess the contribution of each producing zone, and this data is combined with reservoir information to build and optimize SWC physical models. The approach involves adjusting Inflow Control Valves (ICV) positions based on the calibrated model to achieve an optimum production rate across the laterals and restrict water production. For ESP systems, the production rate is optimized by adjusting surface Flow Control Valve (FCV) positions while maintaining the pressure above the bubble point to avoid gas lock. The valve settings are optimized to ensure the ESP operates within the best efficiency range and extends the pump's lifespan. This novel approach has been thoroughly tested on representative samples of producing wells.
The study utilized the physical model with the most efficient ICV and FCV positions. Evaluation of the results demonstrated the contribution and behavior of the laterals under isolated and commingled flow configurations at various ICV settings. After optimizing the wells, an average oil increment of 25% and a decrease in water production by 10% per well were observed. By restricting highly fractured laterals, there was further reduction in water contribution and prevention of the water coning phenomenon. The flow contribution across all laterals was optimized, leading to improved sweep efficiency and enhanced ESP run life and performance. These results build confidence in the long-term potential of smart well completions.
This paper presents a novel approach to optimizing oil wells production using SWC technologies. The integration of reservoir data, lateral pre-testing, and calibrated models to adjust ICV and FCV positions ensures optimum production rates and addresses the challenges posed by ESP systems. The results demonstrate the effectiveness of this approach in enhancing sweep efficiency and extending the ESP pump's lifespan. This paper adds to the existing body of literature by providing valuable insights into the optimization of well productivity and ESP performance in the context of smart well completions.
An Investigation of Core Plug Heterogeneity Effect on Estimated Relative Permeability
Authors: AlMansour Osama , AlSaud Moataz Abu , Ayirala Subhash , Cinar Yildiray 
Published: May 2024

Abstract
A numerical study is presented to explore the impact of core plug heterogeneity on the interpretation of relative permeability (kr) curves from steady-state (SS), unsteady-state (USS), and centrifuge core-floods (CF). We consider a homogeneous core plug model and several heterogenous core plug models, where theaverage permeability of the heterogeneous models is equivalent to that of the homogeneous model. Simulation results of the heterogenous plug models are compared to equivalent homogenous models (representing the base case) to systematically evaluate the effect of core plug heterogeneity on interpreted kr curves. Any difference between the results of the heterogeneous and homogenous models should therefore be solely attributed to the heterogeneity effect. The investigation reveals that core plug heterogeneity has a significant impact on kr curves depending on how the heterogeneous portions are distributed within the rock sample. The effect may become significant in core plugs with unique characteristics such as high permeability streaks or composite nature. A composite core of varying permeability has a major effect especially on the kro curve. In core plugs with randomly distributed porosity and permeability, heterogeneity appears to have negligible impact on interpreted kr curves. The practice of selecting homogeneous plugs for special core analysis (SCAL) tests is a challenge and often becomes difficult to satisfy in core analysis studies. Instead, characterizing plug heterogeneity and including it in the interpretation of core-flood data for estimating kr curves offers an attractive and easy solution for obtaining more representative kr curves.
Unlocking Reservoir Potential in Low Reservoir Pressure Through Efficient CO2 Foamed Acid Fracturing
Authors: Asel Sultan , Alabdulmuhsin Ali , Ashby Scott , Hoong Marcus Chan Choon 
Published: May 2024

Abstract
Acid fracturing in challenging gas wells imposes multiple areas for improvement. The objective is to implement effective acid fracturing treatment with combination of CO2 foam and the use of dissolvable plugs to maximize diversion across the net pay and to improve overall operations efficiency. The scope of the paper shows improved well production and operations efficiency using CO2 foamed acid fracturing and dissolvable frac plugs compared to conventional acid fracturing.
The area of improvement for acid fracturing is to ensure effective fluid diversion across target pay. Effective stimulation is through shorter interval with multiple stages using temporary isolation rather than through single stage and longer interval. The choice of dissolvable frac plugs for temporary isolation is to eliminate coiled tubing milling operations.
The use of CO2 foamed technique provides good acid retardation for effective diversion and extended reaction with formation. CO2 foamed acid fracturing treatment uses lower stimulation fluid volume compared to conventional treatment. Volume reduction and the energized foam accelerates flowback for effective well cleanup.
The combination of CO2 foamed fracturing technique and the use of dissolvable frac plugs were applied in gas Well-A, having high temperature and low reservoir pressure. Well (A) was completed with two stages treatment with temporary isolation using a dissolvable plug to ensure good stimulation across the pay.
CO2 foam lowers the formation temperature which reduces acid reactivity on sand face resulting in deeper etched fracture length. Foaming agents are included in the stimulation fluid to maximize CO2 entrainment producing stable foam for effective diversion and energizing the fluid to accelerate well flowback. Reduction of flowback time and enhanced clean-up can be attributed to the CO2 energize assist and significant fluid volume reduction, up to 50% reduction compared to conventional treatment. The use of dissolvable frac plugs coupled with CO2 stimulation, eliminates the need of coiled tubing milling and N2 lifting intervention as a result of reducing the wellbore hydrostatic column.
The effectiveness of this technique can be proven from higher production in gas rate compared to other reference wells that were not treated similarly. Overall operations efficiency is improved due to reduced logistics, reduced fluid mixing, enhanced flowback rate and eliminating the need of Coiled Tubing intervention.
Multilateral Technology Innovations Ready to Maximize Field Development
Authors: Kelsey Matthew , Fanchin Thomas 
Published: May 2024

Abstract
For a quarter of a century sustained technological advances in multilateral technology have enhanced economics and extended the production life of fields in the Middle East.
Multilateral well construction, once considered to be complex, costly and a higher risk when compared to the drilling of a single wellbore, has been widely adopted in the Middle East as a robust, reliable and value adding method of field development or field rejuvenation. Having established confidence in existing multilateral technology and methods, operators in the region have challenged multilateral technology providers to expand and evolve to address more challenging reservoir needs and enable more advanced multilateral wells delivering even greater value.
Multilateral applications have evolved in capabilities from simple dual laterals to the addition of allowing intervention capabilities, along with improved junction integrity, and the integration of lateral flow control and monitoring. The use of multilateral technology can deliver a significant increase in reservoir contact compared to single horizontal wells. A dual lateral well can deliver twice the reservoir contact while eliminating the drilling, casing, and cementing of an additional vertical wellbore section. Operators are implementing multilateral field strategies to reduce overall development cost, cycle times, and carbon footprint and providing a new lease of life to existing fields. Further benefits include delivery of wells with more production with less surface facility systems requiring less in-field construction hours and maintenance at a lower baseline cost and risk over the life of the field.
This paper discusses the latest multilateral technology developed for operators in the Middle East. It highlights the continuous improvement of multilateral technology used in the region by demonstrating how application of multilateral well strategy is a proven and reliable method to reduce time-intensive operations by eliminating additional vertical wellbore sections and utilizing existing surface infrastructure. Case studies will include discussion of workover intervention operations, completions, infill drilling and lateral creation systems.
This paper will focus on how the latest multilateral technology options enable operators in the Middle East to consistently meet challenges and maximize asset value. Wells originally planned as a single wellbore or a simple dual lateral are now drilled and completed using intelligent flow control and, in some cases, installations with pressure-controlled junctions.
The paper focuses on a region and the technology used to increase efficiencies, enabling the reliable delivery of increased reservoir contact in less operational days. The paper also provides insights as to the methodology adopted to continually improving reliability of multilateral installations and to maximize efficiencies.
Accelerated Mobilisation in a Month for Plug and Abandonment Project - Resolving Gas Leak on a Well
Authors: Hamid A. Abdul , Razak M. N. Abdul , Zawawi A. , Khalid M. , Shah S. Masroll , Ezani F. , Sellapan S. , Jamal J. 
Published: May 2024

Abstract
An incident of a gas leak was reported on an offshore platform in Malaysia. Observers noticed a gas cloud emerging from a well on the platform, accompanied by water and mud returning to the conductor and surface casing of the wellhead. At the same time, a drilling rig was operating on an adjacent platform. As a result of this incident, an immediate evacuation was carried out on the platform, and well control measures were implemented on the drilling rig. The management made the decision to address the gas leak problem by plugging and abandoning (P&A) the well before resuming production and drilling activities on the platform. Production was halted, and drilling operations were suspended until the well was secured, causing financial and production losses for the company.
Within a month of preparation, the HWU Rig, along with well services, was mobilized to an offshore location. This paper discusses on the comprehensive planning, challenges, steps, and arrangements involved in the execution of the plug and abandonment (P&A) project. The topics covered range from rig readiness and acceptance to engineering planning, contracts, manpower, services, governance, and more. Various stakeholders, such as Facilities, Production, Intervention, and others, collaborated to make this endeavour feasible. All these parties were brought together as a cohesive team to ensure its success.
The traditional approach to project execution, which has been widely accepted in the industry for many years, is being strongly challenged by fast-track projects. This project demanded added flexibility in decision-making processes, without compromising governance and safety. The project team encountered various challenges and devised solutions to achieve project success. Some of these challenges and solutions include: HWU Rig Readiness and Acceptance - Partial acceptance was conducted at different locations to meet the project timeline. Acceptance requirements were innovatively engineered to suit the time constraints.Stakeholder Management - Multiple stakeholders were integrated to enable concurrent activities and resource sharing, thereby minimizing costs and improving efficiency.Engineering & Technology - Offline jobs were performed on the well to gather more information and optimize time. New technologies ( First In the world Technology Application – Perf, Wash & Bismuth) were explored and deployed to enhance assurance and ensure the secure P&A of the well.
This paper highlights the significance of meticulous planning, engineering, and an innovative approach in successfully executing a time and cost-constrained fast-track project. The collaborative efforts of numerous stakeholders were essential in ensuring that the project was accomplished while upholding governance and safety standards. This approach facilitated the implementation of cutting-edge technology at each stage, setting a benchmark for excellence.