bluuebunny/crossref_metadata_2025_split huggingface dataset:
Horizontal Well Design and Completion Optimization in the Greater Burgan Field for Heterogeneous Thin Sands, A Case Study
Authors: Al-Samhan Amina , Jilani Syed Zeeshan , Al-Nemran Shahad , Muhammad Yaser 
Published: May 2023

Abstract
The Greater Burgan field has been on production for over 75 years mainly from the homogenous massive sands of the Burgan clastic sequence. Given the increasing field water cut from these sands, it is now a matter of strategic focus for the asset to target the generally untapped thin, laminated low quality sands to sustain target production. This paper focuses on a case study for a horizontal well design and completion optimization using sector modeling.
An updated dynamic model, covering the area of interest, was developed. This is an extremely important tool to achieve the study objectives. A sector model was cut out from the full field dynamic model. Grid refinement was performed on the sector, in both vertical and horizontal dimensions. Newly drilled wells were used to update the model horizons, petrophysical data from offset wells in the sector, including geosteering data from the pilot hole, were upscaled and properties populated across the model.
The dynamic model calibration was conducted successfully by including all available well events, workovers, production data, static and flowing bottom hole and well head pressures including all other surveillance data from offset wells. To better match the historical field pressure and water-production, sensitivities were conducted to determine the model response to various parameters including the aquifer strength and faults conductivity. Adjustment of the aquifer strength enhanced the field pressure match, invariably improving the calibration of the model.
After model calibration, the horizontal well was implemented in the model, in line with the design scope from the asset. The biggest uncertainty was the oil-water contact (OWC) in the sector near the planned well. Although offset wells gave a reasonable estimate of the OWC, it was used as sensitivity parameter to cover the uncertainty. This was taken forward into the model prediction simulation work. The modeling study provided immense insights into the probable outcomes in terms of actual horizontal well production deliverability. Multiple rate sensitivities were conducted mimicking the different choke sizes which were planned. These were used as a guide for the asset to set reasonable production target rates for the well.
The study also provided a technical justification for completion recommendations and optimization with a view to maximizing the well's production over time. The horizontal well has been drilled, completed, and tested in the field. The production test rates were encouragingly consistent with the model predictions. The workflow methodologies adopted in this work have now been extended to other wells being drilled in the field.
Sensitivity Analysis and Cost Analysis for Casing Designs (Case Study)
Authors: Abbood Husam Raad , Khalil Dr.Ethar , Miftah Karrar Riyad , Khalaf Amgad Hamad , Abdullah Ibrahim Salim , Khudhaier Muhammed Adnan , Jaber Ali Hassan , Hamad Zamzam Neama 
Published: May 2023

Abstract
The oil and gas industry is witnessing an increasing demand for more cost-effective well design and operations. Thus, the scope of the operator company's planned new processing capacity aims to attain a competitive cost and schedule. In this work, slim versus fat casing designs are evaluated in price and technical challenges, including removing rig/skidding, drilling, and ensuring well suspension.
Data from ten (five slim design and five fat design) wells in southern Iraq was quantitatively analyzed. Attaining the project's target requires that the well be drilled as a deviated well (S-type). The analysis includes the cost of CSG, lost circulation, lost curing, lost circulation materials, volume of the cement plugs to cure losses, non-productive time, stuck pipe and differential sticking, and cement bond quality. Moreover, a cost analysis is conducted by considering all of a project's relevant factors—including economic and technical considerations—to ascertain the likelihood of completing the project.
The finding emerged that the amount of lost mud and the average cost of addressing losses were higher in slim than fat designs. The slim design is associated with higher volumes of cement plugs for curing losses than the fat design. As per NPT analysis, the time required to fix losses emanating from slim design was 62% higher than fat design. A critical observation emerged from the study that while differential sticking failed to occur in both designs, stuck pipes happened in some of both designs. The cost analysis of slim and fat designs focused on the cost of drilling, CSG, wellhead, diesel, and fueling is also done. The total cost of the fat design amounted to approximately 53.67%, while the total cost of the slim design was about 46.33%. This made the slim design's cost savings ratio of roughly 7.34%. Meanwhile, given that similar issues may occur in the proposed well design, the following measures have been isolated to help tackle such problems. (1) Optimize mud design to inhibit Tanuma formation Clay swelling issues (2) Reduce OH time to avoid Tanuma's time-dependent clay swelling. (3) Reduce the inclination across Tanuma to 20 degrees.
Finally, this paper describes how two casing designs are successfully engineered and executed and serves as a guide for selecting proper candidates for this design. Also, it is an operational guide for two casing designs, slim and fat, to ensure that these challenging long open holes will be successfully and economically drilled while minimizing risks and ensuring compliance with the well delivery process.
Motor Wired Power Section as a Solution for Efficient Downhole Torque and RPM Transmission in Long Horizontal Well. Case Study, Onshore Abu Dhabi, UAE
Authors: Baruno Agung , Rizky Amin Muhammad 
Published: May 2023

Abstract
Drilling long horizontal wells in mature fields in UAE are common and challenging. Some of the associated challenges are; lateral length, geological complexity and rig capabilities. One of the challenges in this case is to provide high RPM and torque to the bit and not to increase the maximum make up torque for the existing drill pipes. Powered rotary steerable systems (RSS), applied within the optimum drilling environment, can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can decrease drilling costs. Using through motor telemetry technology, a wired motor with a hollow rotor and flex shaft, allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole tools. A conductor passes power and communication through the motor to operate and steer the RSS. It delivers higher rev/min and torque directly to the RSS and bit. Using the motorized RSS not only has improved ROP but has also mitigated stick-slip vibration and reduced NPT. The NPT improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string torque variations and rig equipment failures. To run the Motorized RSS on the UAE oil and gas fields the early planning and risk assessment have been conducted. Experience across the worldwide Halliburton locations, both on and offshore, have been presented to show the benefits of Motorized RSS. With improved performance as a result of increased torque and bit speed, and reduction of the stick-slip vibrations, this motor-driven RSS has delivered superior performance and improved ROP in challenging medium and hard formations. At least two horizontal wells with lateral exposure more than 8400 ft was completed shoe-to-shoe with outstanding average ROP using wired power section. It helps to exceed benchmarks by bringing greater horsepower to the rock destruction process with longer runs and higher ROPs. Implementation of wired power section technology for RSS tools will reduce failure risks either for Haliburton either for Customer rig equipment and allows to extend the lateral section footage to develop targets which was unable to hit before. The technology gives opportunity to use the existing capabilities and reduces costs for purchasing the new drillpipes and maintenance of the rig itself.
First Deployment of Expandable Liner Hanger and Tie-Back System with Metal-To-Metal Seal in Gas Well, Offshore Abu Dhabi
Authors: Yudhia D. P. , Seyfetdinov R. , Alhaj M. , Aziz M. Abdel , Rabis P. , Al Ameri S. M. , AlMarzooqi A. , Barbera R. , Sallam S. , Omar H. 
Published: May 2023

Abstract
Liner hanger operations and well integrity across the liner overlap have been always a challenge in the gas well. Conventional liner hanger relies on elastomeric devices as the primary sealing mechanism to isolate the liner lap strings, with two trips required to deploy the liner hanger, top packer and tie-back seal. This paper will introduce an expandable liner hanger/packer and tie-back system to isolate high pressure reservoir and problematic shale in Offshore Abu Dhabi.
The selected single-trip expandable XPak liner hanger/packer and tie-back system offers a metal-to-metal seal throughout the complete liner stack, with 17 to 24 inches of an expandable section on the hanger/packer body that generate sufficient metal-to-metal contact area between the liner and the host casing achieving a robust sealing device that is to be considered as a primary isolating barrier. Feasibility review of technology was then conducted, covering review of running procedure, risk assessment and success criteria (covering HSE, performance, integrity, and efficiency). Business case was issued to install the 13-3/8″ × 9-5/8″ system. The system was deployed in a gas well drilled in 2021. Cementing job of 9 5/8″ liner was conducted smoothly with liner string rotated at 10 rpm while pumping & displace cement. Liner hanger/packer was set with 4,400 psi, hanger setting was then confirmed with 70 klbs overpull and the setting tool was released by slacking off the drill string with 120 klbs.
The operation was conducted safely and with zero NPT. The system was successfully demonstrated by the effectiveness of the offered features and its running procedure. Liner and tie-back casing integrity was achieved and confirmed through successful pressure tests. Based on the trial result, the selected single-trip expandable liner hanger/packer and tie-back system achieved the defined success criteria. The actual time saving from deployment of single-trip expandable liner hanger/packer and tie-back system compared to conventional liner hanger in this application is 2.54 rig days. The detailed analysis and operation feedback will be beneficial to assess the suitability of this technology to overcome future drilling and integrity challenges.
An Optimized Approach to Reduce Well Duration in Re-Entry Wells with the Utilization of a Dual Objective Single Motorized RSS Run in 8.5in Deviated Sections in Onshore Concessions, Abu Dhabi
Authors: Akinlosotu Akintunde Olaniyi , Quintero Fernando , Baruno Agung , Al Rahma Rahma , Al-Jabery Razan , Al-Reyami Mazin , Bin Shamlan Abdulla , Ali Al-Bunni M , Yehia Mahmoud Mohamed , Ud Duja Badar , Arshad Hafiz 
Published: May 2023

Abstract
Traditionally, the standard procedure employed by ADNOC Onshore for re-entry wells sidetracked from a cased hole involved milling a window in the casing and followed by a dedicated elongation run with a mud motor bottom hole assembly (BHA) for kick-off and to achieve desired separation from the original casing/wellbore before pulling out of hole with the motor drilling assembly. This is then followed up with a rotary steerable plus measurement/logging while drilling (M/LWD) assembly to continue drilling the 8-1/2″ deviated section to target landing point (LP). The main reasons for having the dedicated motor elongation run are to get enough separation from the main wellbore (not tracking the original hole) within the shortest distance to avoid the magnetic interference to the M/LWD tools from the casing and to assure not following the previously drilled well. However, associated with this practice are some negative impacts operationally which can be summarized as below
– High localized dogleg severity (DLS) during the sliding interval with the motor – Requirement to make-up and round-trip two separate BHAs before drilling to planned LP – Potential hanging of the motor assembly at the window during sliding interval – Additional cost due to utilizing 2 different types of drilling bit (Initially TCI for the motor run and then PDC to drill the section)
The only way to avoid those cons is by doing one trip with RSS to exit the window and drill away from the whipstock. The main challenge doing this will be to have enough rat hole to accommodate the BHA (including smart tools with electronics parts) and avoid damaging the BHA components during rotating it inside the casing. This can and has been achieved with a high build rate RSS by some operators but however, use of this technology still exposes the delicate components of the M/LWD tools to possible damage due to contact with the window while rotating the string with the tools still within the parent casing.
The introduction of the motorized rotary steerable system (MRSS) in the suite of steerable drilling assemblies has opened additional window of opportunities. Ability to combine some of the benefits of using a mud motor with that of a rotary steerable system all in one bottom hole assembly without doubt offers the potential of pushing further the limit of performance and productivity. With the MRSS BHA, with a minimum required rathole drilled with the whipstock milling assembly, the rotating part of the BHA will be out of the window prior to start circulation. This paper presents the success achieved with a MRSS system with Near bit Gamma-ray sensor requiring only 18ft rat hole delivered in ADNOC Onshore re-entry wells sidetracked from whipstock window.
Positive Impact of V0 Multi-Stage Cementing Tool on the Long Term Well Integrity
Authors: Hussain M. Q. , ALRashdi A. A. , ELMahdy M. M. , Mwansa P. L. , Amorocho A. , Ibrahim A. M. , Naga H. , Kaddoura I. 
Published: May 2023

Abstract
Weak formations which require isolation from elevated hydrostatic pressures during cementing operations have always been a challenge in the oil and gas industry. This paper will discuss the impact of deploying V0 Multi-Stage Cementing tool in terms of cement quality, well integrity and cost optimization.
The losses experienced throughout the extended 9-5/8" casing strings resulted in reduction of the cement quality exposing the full well integrity to higher risks. Meetings have been held between engineering, material, production optimization and operation teams to evaluate the current performance and identify methods for improvement. V0 Multistage cementing tool was introduced as a unique solution which would assure reaching expected well integrity, overcoming hydrostatic pressure challenges, and eliminating risks of poor cement quality in the corrosive environment gas well applications.
V0 Multistage cement tool has been successfully deployed for cases where elevated hydrostatic pressure was considered an issue, showing success in providing the required cement quality. Alternative methods to provide similar quality would be Liner hanger system followed by a tie back which would involve more associated cost, rig time and equipment.
Wells with high differential pressures due to fluid losses have been successfully resolved avoiding risks of performing single stage cementing, compromising zonal integrity of weaker formations and poor cement quality.
Qualified V0 Multistage cementing tool as per (ISO) 14310 V0 standard has been deployed, where gas-tight mechanical packer has enabled more reliable multistage cementing jobs for deep gas applications which ensured consistent and reliable gas-tight well integrity.
V0 Multistage tool was considered an economical solution reducing the cost by 70% compared to alternative solutions, reducing average of 3 rig days.
The paper will introduce the optimum economic solution for recurrent cementing challenges in both onshore and offshore operations. Utilizing latest technologies to retain wellbore integrity, eliminate unnecessary costs and reduce rig time.
Integrated Logistics Cost Optimization Through Automated Forecasted Drilling Operations Report
Authors: Hussain M. , AlRashdi A. , El-Mahdy M. , El-Kasrawi A. , Ibrahim A. , Mizukami A. , Zherelyev A. , Varga S. 
Published: May 2023

Abstract
Oil and gas companies continuously invest on digital transformation, to economically improve logistics workflow and enhance service providers interaction. A unique digital solution has been designed to automate business processes and reduce unexpected deviations from drilling operation execution process; to avoid unplanned costs and delays affecting overall drilling performance. The manuscript will focus on drilling process modifications and performance impact resulted from implementing drilling forecasting approach for materials and services.
Company and Software Provider jointly developed and implemented drilling forecast Report on top of existing reporting system to support drilling operations execution as per short- and long-term plans set earlier. Overall workflow and interconnection logic of steps were defined based on current Company's Standard Operating Procedures detailing Drilling Operation Policies and Instructions. Which ensured the software solution to be fully compliant with Company requirement. The developed automated Report passed a series of comprehensive tests in real conditions and after proven success; was decided to be implemented in Production environment to be efficiently utilized.
Following the specific logic of Company's drilling operations execution, the automated forecast report improved planning procedures and automated the information exchange between Company and respective Service Providers to support smooth logistics of materials and personnel that required to be delivered to rig sites or removed from it. Implementation of first phase required strong dedication of drilling engineers, the developed report was designed to eventually lighten the current workload and release additional man-hours in future to analyze and optimize existing procedures. As a digital solution, the report was designed to gather required information from different data sources and automatically compare it with current drilling operations status; to evaluate current phase and predict accordingly the next 10 days of forecast for drilling operations, materials to be prepared and personnel to be located. Which helped to assure materials and field engineers availability on rig site on time. Assuring cost saving and avoiding unplanned logistics costs due to potential deviation and optimized overall Company's financial burden.
The forecast report is being developed to be auto generated and shared on daily basis for all rigs to be available for all suppliers on daily basis.
Automated forecast Report implanted on top of existing database is enriching current reporting system. Utilizing a digital and automated approach for forecasting daily operation and planning tool for services and materials ahead of time would improve drilling performance efficiency, eliminate any unwanted delays and complement Company's digital strategy.
Drilling Beyond the Extended Boundaries of Complex Extended Reach Well
Authors: Hashmi Muhammad Asef , Al Suwaidi Muna , Salem Gamal , Al Yamani Sultan 
Published: May 2023

Abstract
Well was drilled in Al Nouf field with the objective to support the pressure sustainability of multiple producer wells across SH formation based on MRC / ERD approach. This paper presents the challenges faced in planning and drilling of subject well with departure of above 15,000ft and soft landed above the reservoir and later drilled 8.5" hole section to total measured depth of above 37,605ft (11.642 km) with having horizontal section of above 20,000ft with directional difficulty index (DDI) of 7.541 using heavy casing design.
Planning of this well commenced by meetings and collaboration with subsurface operation and reservoir team with the common objective of drilling a well of over 15,000 ft of departure and keep the well smooth for drilling long eMRC horizontal section. New technology was used with a common objective to achieve the goal and make trajectory smooth to provide max chance for lower completion to reach the max TD of the well.
All the associated risks were highlighted and mitigated by proper planning and engineering analysis such as trajectory, collision risks, BHA, hydraulics and casing design.
This eMRC/ERD well of above 37,605ft MD (4.12 ERD H:V ratio) is the first well in the region to successfully completed even with directional difficulty index (DDI) of 7.541
This paper will explain the innovative and novel approach of mitigating the challenges faced while drilling a complex well of 15,000ft departure and have an extended horizontal section of over 20,000ft with 8.5" drainage. A few challenges like drilling across the faults across horizontal hole section and collision risk at deviated and horizontal section were major concern but successfully catered with advanced engineering analysis and innovative technologies like torque reducer, turbo caser and swivel master etc.
Results from this well have proven that having lower completion in MRC / ERD wells have significantly improved the well accessibility and well performance and enhanced the reservoir management and significantly reduced the field development cost.
This paper summarizes the practice and technology used to successfully drill the MRC / ERD well in artificial island.
The challenges and its mitigation explained in this paper will support the idea to plan and drill the well beyond the reservoir boundaries to gather more data and to enhance more production. Also, this paper will provide novel approach of having lower completion in MRC/ERD wells which helps to attain more control on injectivity / productivity of reservoir because of proper isolation by swell packers and have maximum well accessibility across ERD horizontal section.