bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Inside Fiberglass Casing, Wear Prediction and Management in Geothermal Wells
Authors: Aichinger Florian , Beddelem Marie-Helene , Germain Guillaume , Hirsinger Louis , Gerbaud Laurent , Studer Regis 
Published: August 2022

Abstract

Objectives/Scope
Due to corrosive fluids being expected in the geothermal wells planned for the Champigny (Paris) district heating, fiberglass casing was used. It was deemed beneficial, if drilling operations could be performed with an exposed fiberglass casing, despite high expected wear.
This paper will lay out how a feasible strategy was planned, utilizing advanced wear prediction techniques for drilling inside fiberglass casing.
The study was conducted by CFG (compagnie Française de Géothermie) and funded by ADEME (Agence de la transition écologique)

Methods
To achieve an accurate wear prediction three parameters are required: (1) Trajectory and actual tortuosity (2) Wear factors (3) Operations (number of rotations and distance slided).
Tortuosity was calibrated on offset wells (Aichinger, 2021) and expected operations were covered in scenario analyses.
Wear factors were determined using field calibration and laboratory testing. The field calibration was performed on three offset wells using an internal diameter interpretation method in which the wear is measured against the most probable elliptical casing shape and herby allowing wear measurement avoiding bias error. (Aichinger, 2016) The laboratory tests were conducted in Mines ParisTech / Armines including different fiberglass types, protectors, sideforce amplitude, rotation speed and lubricant.
Based on the derived parameters various drilling scenarios and the associated wear levels were simulated to decide on a drilling strategy.

Results, Observations, Conclusions
The main results are:
The main conclusions are:

Novel/Additive Information
This paper should provide help to Engineers who plan to perform drilling operations inside fiberglass casing, mainly by providing Wear Factors, but also general guidelines on wear prediction and mitigation techniques.
Innovative Monobore Solid Expandable Tubular System for Isolating Severe Losses
Authors: Zhan Guodong David , Aljohar Abdulwahab S , Xu Jianhui , Li Bodong , Guo Huijuan 
Published: August 2022

Abstract
The monobore solid expandable tubular (MSET) system, which maintains the same drift as the previous casing and enables the operator to maintain an original drilling plan to total depth, is the next generation solid expandable tubular technology - the most advanced expandable liner system available typically to isolate severe losses or trouble zones while drilling. To address the major technical challenges of a large expansion ratio required to meet MSET requirement, and able to deliver potential longer MSET liner without a concern of premature expansion problem, this paper presents an innovative solution consisting of a safe release mechanism (SRM) for running MSET incorporating a dual-stage expansion mechanism.
This paper presents an innovative approach to the reliability of this mechanism based on Finite Element Analysis (FEA) simulation and indoor tests, as well as a dual-stage expansion process. The dual-stage expansion offers the advantage of a relative ease on the expandable thread when undergoing a large physical expansion, and therefore leads to a less risk of thread failure during the expansion process. The new SRM transfers the weight of the MSET from the cone surface to a collet-finger type plug-in structure, which can be unlocked by hydraulic pressure when the MSET is run to the intended depth.
Based on the result of simulation, an indoor test was conducted and the load capacity of SRM was up to 109 tons, which is safe for at least 1,000 ft MSET. The newly developed tubular with proprietary expandable thread was successfully deployed with a better than expected quality, enabling a successful run of quite long 2,250 feet expandable liner with a steady expansion pressure, and post expansion pressure test without any problem, and as expected, delivered a designed post expansion pipe ID. Most importantly the deployment of expandable liner resolved the severe loss drilling problem, enabled to raise mud weight from 1.05g/cm3 to 1.78g/ cm3,met the requirement of allowing drilling with 190.5mm (7-1/2″) bit and enabled drilling operation to resume and continue drilling a horizontal section without any major problem.
This paper presents a combined (computer simulation and indoor tests for calibration) approach to conducting an advanced monobore solid expandable tubular technology development. The innovative safe release mechanism and dual-stage expansion process assures the application success of the MSET system in optimizing well casing designs for effectively addressing challenges in severe drilling losses.
High-Resolution Remote Mapping of Thin Sand Lobes with Novel Multilayer Mapping-While-Drilling Tool: A Case Study from Nong Yao Field Offshore Thailand
Authors: Thurawat Chaiyos , Teeratananon Wirot , Ampaiwan Tianpan , Carter Raweewan , Phaophongklai Wattanaporn , Vimolsubsin Pojana , Watcharanantakul Rattana , Wang Haifeng , Foongthongcharoen Trinant , Alang Khairul Anuar 
Published: August 2022

Abstract
The recent development drilling campaign at Mubadala Petroleum's offshore Nong Yao field faced many challenges, one of which is the complexity of the reservoir which consists of mixed sand-shale sequencies with thin sand lobes of varying thicknesses. To tackle these challenges and to maximize recovery, Mubadala Petroleum planned four horizontal wells for this campaign. However, the conventional methods of geosteering have limitations. For instance, the distance-to-boundary mapping tool typically does not provide large enough depth-of-investigation for the operator to see through the interbedded shale layer to identify the multiple target sand lobes, which could pose limits on the production optimization and ultimately on the final recovery rate.
Fortunately, a new technology emerged at the start of the campaign with a potential for a much larger depth of investigation and a better mapping resolution. This multilayer mapping-while-drilling tool was an extension of the previous tool with additional sensors that could read deeper into the formation. Coupled with a new advanced automatic inversion process which utilizes powerful Cloud computing, the subsurface formation resistivity profiles around the wellbore could be mapped clearly up to 25 ft away from the tool, while providing a multilayer mapping with up to 8-layer mapping capability.
This new technology was evaluated and applied in two wells in this campaign to resolve the above-mentioned challenges. The result was a resounding success for the Mubadala led drilling team. In this paper, the authors explain the technology, the process of evaluating and applying it to operation, and the results from applying it.
This was the first time that this technology was used in Thailand and this case study summarizes a successful outcome. The mapping results from the tool will also be used to update the reservoir model during the post-job phase and provide improvements of the overall reservoir characterization of the field.
Challenges of a HPHT Completion Design with Extreme H2S and CO2 in a Carbonate Gas Development
Authors: Grant CW Graham , Piyakunkiat Nuttapon , Bandyopadhyay Parthasarathi , Wejwittayaklung Kittipat , Ong Swee Hong Gary , Manson James , Konganuntragul Pornchuda , Abdul Rashid Khairul , Toempromraj Wararit , Chanpen Chakrit , Bin Hamdan Mohamad Kamal , Jantasuwanna Prapaporn , Lewis David 
Published: August 2022

Abstract
Field-X is a large offshore gas structure located 50 nautical miles from Miri City, Malaysia. The reservoir is a High-Pressure High-Temperature (HPHT) carbonate formation with high contaminants i.e., 1.8% mol of Hydrogen Sulfide (H2S) and 18% mol of Carbon Dioxide (CO2). This paper dwells on the completion design for the high-rate wells planned for this development. Exploration and appraisal wells showed severe reservoir properties that are "unique" as compared to other HPHT developments around the world. A multidisciplinary engineering team including HPHT drilling and completion specialists, production technologists, reservoir engineers, external specialist consultants, and facilities engineers are all working with a One Team One Goal mindset to address the challenges of completing this carbonate reservoir.
Some of the completion design challenges addressed in this paper are Annular Pressure Management (APM) systems, perforation strategy for long intervals, well intervention philosophy, compaction and subsidence loading, thermal well interference due to the proximity of the platform well slots, HPHT monobore completion equipment design, qualification, and availability due to a very limited number of suppliers with long lead times. Another critical challenge addressed in this paper is an extensive material selection process to withstand the extremely corrosive well fluids, high temperature, and potential material cracking that historically has led to catastrophic consequences.
As a result of the environment, exotic tubular materials are proposed based on intensive laboratory tests and computer simulations. Three-dimensional time history geomechanical and reservoir models explicitly detail the displacement compaction field which the downhole tubulars will be exposed in their lifetimes. Any annular pressure build-up will be handled by an APM system addressing the A, B, and C annuli with a permanent downhole gauge (PDG) installed for pressure and temperature monitoring tubing and annuli. These are some examples of the well design challenges tackled and resolved.
The project is currently at the design phase, and all the thought process and design philosophies would be tested in this field. The authors wish that the lessons learned, engineering approaches, and design results will be useful in future sour HPHT completion developments.
The First Application of Permanent Tubing Patch Milling With Very Narrow Clearance in a Slimhole well with a Newly Engineered Pilot Mill Bit Design for Coiled Tubing, Offshore Thailand
Authors: Nimsuk Monchai , Tipapong Treepun , Somjai Surapong , Kreethapon Thanawee , Jiemsawat Nophadol , Daohmareeyor Tuanangkoon , Kangsadarn Arweephan , Wattanasuwankorn Reawat , Phayakrangsee Prapas 
Published: August 2022

Abstract
The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well.
CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production.
CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body.
This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.
Digitalization and Automation of the Planning and Execution of Well Construction Process
Authors: Ruzhnikov Alexey , Echevarria Edgar , Phan Choon Kit 
Published: August 2022

Abstract
Well construction process can be presented as a set of the routine and repetitive actions which should be repeated at the planning, execution and evaluation stages. The manuscript describes how in the effort with major operating company the well planning stage was converted to a complete digital path; and how the digitalization of the planning was further transferred to the automated execution.
Planning a well normally done with different computer software, where the data gathered from different engineering software should be input, as well as required drilling fluid, cementing and directional job plans and limits etc., followed by the written operational sequence. In the reviewed case all the planning was shifted to the cloud environment, including all simulations and reviews, where no "merge" of the data was required. All the required simulations are performed automatically, flagging those with the results out of the limit. The operational steps were detailed, and further connected to the rig Variable Frequency Drives (VFD) system, where multiple operations started to be performed in automatic mode, without any intervention from the rig crew (like survey, drilling parameters automatically adjusted to the sock and vibration, stick and slip, seeking for the best rate of penetration, driller's tasks while drilling, backreaming of stand etc.).
The implementation of the digital planning allowed to align all stockholders involved during design stage, minimize human mistakes, and significantly decrease the planning time. The noticeable side effect is absence of any physical paper and as well as higher transparency during preparation. At the execution stage at the begging of the implementation the main benefit came from the standardization of the practices at the rig, what lead to absence of discrepancies. It further resulted in delivery of the all the wells under the same time with very minimum difference. And the final positive result came from the absence of any major service quality event (like stuck pipe) during automated operations. As of now the different levels of digitalization are implemented in 16 rigs, with further current expansion.
The manuscript provides the novel information on the digitalization and automation of the well construction process. The explained methodology can be implemented at any project worldwide.
A Successful Water Shut Off using a Thixotropic Treatment in a Sub Hydrostatic and Highly Aromatic Well, Results in Increased Gas Production of 30% and Reduced Water Production of 63%, Vietnam
Authors: Daohmareeyor Tuanangkoon , Nguyen Tran Thang , Wattanasuwankorn Reawat , Kim Young Sig , Nguyen Tan Khoa 
Published: August 2022

Abstract
An offshore operator in Vietnam faced high water production in a sub-hydrostatic and highly aromatic gas well. In addition to low productivity, the high water cut also strained the water treatment facility. Previous treatment attempts to shut off the high water-producing zones have been unsuccessful due to challenging well conditions.
[EB1]With the treatment facility reaching maximum capacity, and expansion of the water treatment capacity being a time-consuming and costly option, a subsurface well intervention was chosen as the most effective way to reduce water production from the well. The well had complex reservoir characteristics due to highly depleted zones that made treatment placement even more complicated, increasing the risk for the operation. The well produces aromatics, and using packers for isolation reduces the packer element sealing performance. Due to the high deviation angle, a Thixotropic Organically Crosslinked Polymer (TOCP) was designed and pumped for the high water-producing zones.
A customized solution using a TOCP with extensive laboratory testing was found to be the most suitable treatment design for this well. The new placement technique provided prevention of losses to the depleted zones. The thixotropic treatment provided higher viscosity when pumping stopped, allowing the polymer to seal off at the target zone. As a result of the treatment, the well responded positively. The operator significantly reduced produced water from 5,000 BPD to 2,000 BPD, accommodating the capacity of the water treatment facility. Meanwhile, gas production also increased from 4.6 M SCFD to 6.1 M SCFD, reducing the possibility of the well getting loaded up during platform shutdown.
The careful engineering design and laboratory testing played a significant part in the successful campaign, with collaboration from the operator and service company leading this campaign to be a successful project. This approach and solution can help enhance production performance and reduce the cost associated with water production.
Gulf of Thailand 4-String Well Design Transformation Using MPD System – Cost Saving, Operational Challenges and Learnings
Authors: Dalgit Singh Harpreet Kaur , Sammat Essam , Kleawyothatis Thakornpol , Niracharopas Kittikun , Kiani Nassab Kazem 
Published: August 2022

Abstract
Gulf of Thailand (GoT) or Gulf of Siam is mainly offshore development gas wells in Thailand. Well C and well H were originally designed with GoT 4-string standard template. However, Managed Pressure Drilling (MPD) solution was then selected to save one (1) casing string provided that the maximum expected formation pressure to be within the range of 1.46-1.50SG as per geological prognosis. Both wells were drilled to plan TD with 3-casing strings as planned to result in a cost-saving from the design transformation (4-strings to 3-strings) using the MPD system.
There is always a risk of lost circulation and ballooning in intermediate/high-pressure wells (Pore Pressure (PP) &gt; 1.45SG) when drilling conventionally with 3-casing strings (instead of GoT 4-string standard design). Required high mud weight imposes an overbalance during drilling and tripping operations that exceed formation integrity at shallower depths below the 7" casing. MPD is a proven technology for maintaining Constant Bottom Hole Pressure (CBHP) that enables precise control on wellbore pressure to mitigate ballooning and kick/loss hazards, narrow margin drilling window, and formation pressure uncertainties. The 6-1/8" hole sections of both wells were drilled with the MPD technology to mitigate the loss of circulation and ballooning while drilling.
MPD system worked for this project to drill the wells to TD successfully according to the plan and without any major issue. The MPD solution enabled drilling with the lowest and safest underbalanced mud weight to allow a reduction in Bottom Hole Pressure (BHP) and consequently eliminated ballooning while drilling. Surface back pressure (SBP) on connections was increased (compared to the plan) based on connection gas reading caused by pore pressure uncertainties. MPD dynamic formation integrity test (DFIT) and static pore pressure tests (PPT) have established a baseline for heavy kill mud weight estimations and displacing before tripping out of the hole. Observations and learnings from well C confirmed the study’s preliminary conclusions that the 4-strings transformation is quite challenging for PP greater than 1.55SG, and 4-string transformation is not recommended if PP exceeds 1.60SG. The wells were completed with 3-casing strings however, no NPT related to well design and MPD was encountered. The technology was proven and allowed to drill the well with 3-strings design. The solution can save some cost in intermediate pressure wells (1.46-1.54SG PP), and it is proposed for the next trials with more focus on wellbore conditioning and tripping practices.
Unlock Regulatory Requirements for Drill Cuttings Waste Utilisation Pilot
Authors: Wattana Piyarat , Wondee Jutharat , Chonchirdsin Surasak 
Published: August 2022

Abstract
Drill cuttings waste was recycled into new use and pilot project to utilize drill cutting waste in road and construction application were carried out. This work describes strategy and best practice to engage regulator in order to unlock regulatory requirements for the pilot on drill cutting waste utilization.
Characterization of drill cuttings waste was carried out and its regulatory requirements as indicated in waste management plan and EIA were investigated in parallel to the study on technical feasibility to utilize drill cuttings waste. Equally important is investigation on the rule and regulation relevant to areas and/or industries that the drill cuttings waste will be used for. These regulatory requirements must be clearly identified in an early stage of the pilot project as it will indicate necessary analytical tests to be carried out and will provide information for designing of an environmental impact assessment and monitoring program.
Drill cuttings waste is classified into two groups based on type of drilling mud used. Drill cuttings from upper section of well contaminated with water-based mud, called top-hole drill cuttings, is classified as non-hazardous waste while drill cuttings from lower section of well contaminated with synthetic-based mud, called bottom-hole drill cuttings, is classified as hazardous-minor waste. Physical properties of the drill cuttings waste such as pH, conductivity, salinity, chemical properties on chloride contents as well as heavy metal contents must be analyzed and identified to be within the standard limit. These analytical results provide necessary technical information for regulator to make decision based upon in order to support the drill cuttings waste utilization pilot. Based on characteristic of road usage and potential wear and tear of the pilot recycled drill cuttings road, environmental impact assessment and monitoring program on soil, surface water, and subsurface water on areas closed to the pilot site were performed prior and after construction of the pilot road. This environmental impact assessment and monitoring program provides track record of technical analytical data which is essential supporting information for regulator's consideration and endorsement on the future modification of EIA's regulatory requirements.
This work demonstrates that good understanding on classification of the drill cuttings waste, its regulatory requirements, characteristic of application the drill cuttings waste will be used for, and its relevant legislations are essential. This information indicates necessary technical analyses required to be performed in order to obtain important technical data to unlock regulatory requirements. Drill cuttings waste utilization not only save waste management cost, but also reduce environmental footprint. This approach can be applied to utilization of other type of waste as well.