bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful CWD Campaign in Turnkey Project with Potential Utilisation for Well Construction Optimisation
Authors: Frederic Antoine Champain Louis , Zahoor Ullah Syed , Ruzhnikov Alexey 
Published: March 2021

Abstract
Drilling and completion of the surface and intermediate sections in some fields is extremely challenging due to wellbore instability, especially accomplished with complete losses. Such circumstances lead to several time-consuming stuck pipe events, when existing standard ways of drilling did not lead to a permanent resolution of the problems. After exhausting the available conventional techniques without sustainable success, unorthodox solutions were required to justify the well delivery time and cost. Here comes the Casing While Drilling (CwD), being the most time and cost-effective solution to wellbore instability.
CwD is introduced at full throttle aiming at the well cost reduction and well quality improvement. The implementation plan was divided in three phases. The first phase was a remedial solution to surface and intermediate sections drilling and casing off to prevent stuck pipe events and provide smooth well delivery performances.
After successful implementation of CwD first phase, CwD was taken to the next level by shifting it from a mitigation to an optimization measure. Each step of CwD shoe-to-shoe operations was analysed to improve its performances: drill-out (D/O) of 18⅝-in shoe track with CwD, optimum drilling parameters per formation and CwD bit design. Implemented in 19 wells, CwD shoe-to-shoe performances have been brought up or even above standard rotary bottom hole assembly (BHA) benchmark.
Planning for third phase is undergoing whereby CwD is aiming to optimize a well construction to reduce well delivery time, by combining surface and intermediate sections thus eliminating one casing string. Numerous challenges are being worked on including open hole (OH) isolation packer which conform to and seal with the borehole uneven surface. Special "for purpose built" expandable steel packer and stage tool have been manufactured and qualified for the specific application. A candidate well has been chosen and agreed for first trial.
The key areas of improvement include, drilling and casing off the surface and intermediate sections while competing with standard rotary BHA performances and slimming down the well profile towards tremendous time and costs savings.
This paper encompasses details of constructions of various wells with sufficient contingencies to combat any expected hole problems without compromising the well quality while keeping the well within budget and planned time. It also provides an analysis of the well trials that were executed during the implementation of first and second phases of CwD implementation and the captured lessons learnt which are being carried forward to the next phase.
This paper provides the technique on how CwD can be used to help with three aspects of drilling, successfully mitigating holes problems by reducing OH exposure time and to eliminate drill string tripping and modifying conventional casing design to reduce well time and cost by eliminating one casing string.
Evaluating Mud Weight Options in Managed Pressure Drilling for Improved Risk Management and Maximised Drilling Advantage
Authors: Arathoon Mark , Yusof Syahmi , Makri Hafiz 
Published: March 2021

Abstract

Objective/Scope
The objective of this paper is to highlight the fact that while in conventional drilling there can sometimes be no mud weight solution for drilling a particular narrow margin section without either exceeding the Leak Off Test value at the shoe, or falling below the Pore Pressure at section TD. In Managed Pressure Drilling (MPD) there is often a range of mud weight solutions that can be used to drill the section, but usually one optimum mud weight that should be used, based on different risk criteria that can be evaluated. The consequences of this are that when using MPD, it could be that the section risks have not been minimised and therefore more risk than necessary has been imported into the methodology. Whereas if all MPD mud weight solutions have been evaluated, together with their associated Surface Back Pressures, and the optimum selection made, then the mitigations can be specially tailored so that the remedial actions to any system failure are clearly planned in advance, reducing the overall risk level of the operation.

Methods, Procedures, Process
The methodology described in this paper demonstrates the process for choosing the optimal mud weight for drilling any well section using MPD, with worked examples. This process is especially applicable for drilling very narrow margin sections, for example with only 0.2 ppg window between Pore Pressure and Fracture Gradient. By enumerating the safety margins both at the previous casing shoe and at the proposed section TD, or any other point of interest, it is possible to rank the risks of kicks and losses in that section across a range of proposed mud weights and use this information to choose the optimal mud weight.

Results, Observations, Conclusions
The process of evaluating the options and outcomes of using different mud weights in MPD can not only lead to the best drilling solution for the section, but can also be used as a discussion tool between the drilling team and the subsurface team, to help elucidate the most likely risks to the operation and thereby mitigate those risks in the most appropriate way.

Novel/Additive Information
A further benefit of this approach is that the narrowest possible drilling windows can also be evaluated and as a result, options for extending TD and potentially eliminating casing strings can be considered, leading to considerable savings, which are highly prized at all times, but especially so in a low oil price environment.
Appraising the Development Potential of Ekofisk Over Tor Formation in the Halfdan Field, using a Multi-Disciplinary Approach to Well Planning and Applying Advances in Technology to Enhance Well Placement, Completion, Productivity and Recovery
Authors: Andreev Anton , Pitts Michael , Hoover Andrew , Elhassan Eyad Mohamed , Bexkens Felix Sebastian , Datta Sudipto , Singh Amit , Lund Espen , Panos Gomez Luis 
Published: March 2021

Abstract
Demonstrating a viable development for the Ekofisk reservoir directly above the producing Tor reservoir in the Halfdan Field (Danish North Sea) has historically been challenging. A recent well shows the value of cross-disciplinary collaboration and new technology to maximize recovery and mitigate reservoir and drilling risks. Specifically, 4D seismic was utilized when planning the well, while placement was optimized by using advanced geosteering tools. Well optimization was further enhanced by adopting novel completion and stimulation technologies.
Pressure data and 4D seismic show that Tor and Ekofisk are in dynamic communication, but the degree of communication varies locally. The integration of 4D seismic with other disciplines’ input succeeded in optimizing the well placement and narrowed the significant pore pressure uncertainty along the 12,000-ft reservoir section.
To maximize well length within the target zone and reduce the risk of being faulted out of the target reservoir deep resistivity was used to steer the well in the optimal layers. This contributed to 99% of the reservoir section being placed in the target zone.
Lessons learnt from an earlier appraisal well and modest production experience in this part of the Ekofisk reservoir helped to justify the choice of selective completion zones (Sliding Side Door) in the inner part of the horizontal drain in order to minimize the impact of potential water or premature water breakthrough from high-rate injection wells located in the underlying Tor reservoir. This decision was validated after drilling the inner part of the well, where water-swept zones were encountered in the heel, followed by a long gas pay zone in line with 4D seismic signal in the remainder of the inner well section.
To mitigate the risk of an unwanted fracture connection and increase contact with the tight oil-saturated reservoir, a novel stimulation and completion technology was successfully deployed in the outer 6-inch open-hole section of the well. The acid needles completion, deployed across a 3,000-ft reservoir interval and comprising 224 needles deployed by pumping acid, was the first installation of its kind in the Danish North Sea. For the acid needles completion, this installation holds two distinctions: the largest number of acid needles installed in a well, and the combination of the acid needles completion with a different completion system in a single lateral for the first time.
Holistic Approaches in Achieving Best in Class BIC Detailed Well Design and Operation Execution — The New Norm
Authors: Mhd Yusof Muhammad Hatta , Khalid M Zulfarid , A. Halim Rahimah , Ahmad Fauzi Nurfaridah , Sella Thurai Ahgheelan , Omar Ahmad Faiz , Alwi M Fairuz , Sulaiman M Zarkashi , Muslim Fadhli Adlan , Fabian Oka , A. Bakar Mohd Faiz , Lee Magdelene Jia 
Published: March 2021

Abstract
This paper will discuss the case study of two (2) projects in Malaysia that were stretched-to-limit and optimized ‘on-paper’ all the wells’ related engineering design and construction, operation activities pre and during drilling campaign as well as logistic arrangement, which led to significant cost reduction in wells and thus improving the overall project economics. This significant savings achieved with full compliance to technical standards as well as with the betterment to improve HSE during offshore execution.
Precise Bottom Hole Pressure Management to Reach Target Depth in a Narrow Windowed Ultra HP-HT Well: A Case for Automated Managed Pressure Drilling
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj Moussa Ayoub , Ghulam Nabi Agha , Ahmed Baig Umair 
Published: March 2021

Abstract
With the energy sector in crisis the worldover, oil and gas operators continue to seek more effective and efficient methods to reach potential prospects. With sharply declining oil prices, it is imperative that operators minimize the non-productive time in the drilling of all wells.
Many operators are actively seeking riskier exploration to establish a strong foothold in this volatile market. One such area of interest to operators is HPHT and beyond wells. An HPHT prospect carries a high-risk high-reward potential, therefore newer and advanced methods are being deployed to successfully drill and complete HPHT wells.
The Makran Coastal belt in south western Pakistan is one such area containing a potential Ultra-HPHT prospect. Many operators had attempted to drill about 9 wells in the locality but never managed to reach target depth due to drilling operations being plagued with a large number of problems. The drilling problems included high pressure influxes, stuck pipe while controlling influxes, circulation losses with high mud weights and ECD’s, differential sticking against permeable formations, inefficient bottom hole pressure control due to mud weight reduction with high temperatures and swabbing from the formation due to having an insufficient trip margin.
The operator was facing an extremely narrow drilling window in the target section. The maximum formation pressure was estimated to be around 2.29 SG while the maximum fracture pressure of the formation was estimated to be around 2.35 SG in EMW. It was abundantly clear that drilling with a conventional mud system would be impossible and impractical on all forthcoming wells.
As it was of paramount importance to precisely manage the wellbore pressure profile, the operator decided to apply managed pressure drilling on a candidate well. By applying managed pressure drilling techniques the operator expected to drill the section with an underbalanced mud weight and maneuver the bottom hole pressure just above the pore pressure line and thereby avoid circulation losses, detect influxes early on and control influxes without the need of ever shutting in the well, account for mud density variations with temperatures by executing an advanced thermal hydraulics model in real time, mitigate swabbing from the formation again by maintaining a constant bottom hole pressure while tripping, and finally ascertain the downhole pressure environment by conducting dynamic formation pressure tests.
The successful application of MPD enabled the operator to reach target depth for the first time in the history of the area. The paper studies the planning, design, and execution of MPD on the subject well.
A Client's Fit for Purpose Solutions in Well Abandonment
Authors: Yap Yun Thiam , Kumar Avinash Kishore 
Published: March 2021

Abstract
Typically, most of the well abandonment practice is reference to the recognized industry standards i.e. NORSOK, UK Oil & Gas and etc, and this is how the wells abandonment was carried out in the past. These practices however evolved/changed over time with lessons learnt and experiences and turn into a fit for purpose solutions for the Client.
The shift in international and local standards and regulations for a robust plug and abandonment approach has placed the need for a better and long lasting permanent P&A methodology.
Adhering to the existing industry standards in well abandonment is somehow not practical and not cost effective to be implemented in different part of the well, where there are major differences in local regulations, reservoir conditions, caprock thickness, well design philosophy and etc. The magnitude of abandonment cost increase is not at par with the risk reduction in long term hydrocarbon leakage. A fit for purpose solutions is recommended in closing the gap between cost and risk.
Due to the extremely varied well architecture between wells, the approach to permanent abandonment varies depending on casing sizes, presence of packers and no of casings present to the caprock area. On top of that, identifying the highest depth for a placement of cement plug will reduce on the amount of plugs to be placed, saving rig time and operational time. So far, 16 idle wells have since been permanently abandoned with the systematic approach of applying caprock restoration concept and reinstating the poor isolation across caprock areas with cement with the assistance of technology to the likes of perf-wash-cement, and hydro mechanical casing cutter. These wells have successfully been abandoned as per host authority standards.
This paper will explore a major local oil company’ approach to decommissioning of wells, in line with local regulations enforced, while ensuring a cost effective approach is applied in line with the available technologies.
Casing While Drilling Application: Changing Mitigation to a Performance
Authors: Ruzhnikov Alexey , AlHosni Fahad , Echevarria Edgar Garnica , Varela Rodrigo 
Published: March 2021

Abstract
Well construction process through the unstable formations prone to total losses, pack-off and water influx is challenging. The manuscript describes the casing while drilling (CwD) combined with stage-cementing tool as introduced solution, when the challenge was to ensure that torque limit is not reached while drilling and estimate the effect of CwD on curing total losses and bring the casing while drilling performance to the level of conventional drilling.
Introduction of CwD required extensive study of the potential torque while drilling as existing stage-cementing tools have low torque rating. Additionally, the casing fatigue may be a factor affecting the operations what lead to an introduction of magnetic particle casing inspection. The CwD bit design was adopted to the geological conditions based on best performance of the PDC bit, and originally selected drilling parameters were further optimized based on the result of the first runs. As the drilling of the well required utilization of mud cap for well control purposes, the mud recipes were adjusted to optimize the drilling performance and minimize the cost implication.
The proposed solutions allowed to eliminate the problem with wellbore instability and related stuck pipe events. Further the proper engineering of the drilling process allowed significantly increase the rate of penetration since the beginning of the implementation, when the drilling torque never reached the limit even at 7,000 ft depth.
The manuscript describes in detail the approach to make a proper design of CwD process focusing on prevention of existing problems and aiming to convert mitigation tool to a performance tool. Additionally, in details described the studied effect of CwD on curing total losses in highly fractured environment.
Cementing Solutions for Monobore Challenges
Authors: Loh Thien Yu , Duong Anh Tuan , Chong Woon Phin 
Published: March 2021

Abstract
Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well.
To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off.
This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing.
The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool.
We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.
Integration of Multiple Data to Improve Condensate Yield Prediction in Pailin and Moragot Field, Pattani Basin, Gulf of Thailand
Authors: Kawphoy Rampueng , Thatmali Phanat 
Published: March 2021

Abstract
The objective of this study was to improve the accuracy of condensate gas ratio (CGR) prediction in the Pailin and Moragot areas. Conventional method to predict liquid component reserves used only long-life condensate gas ratio (long-life CGR) from near-by production platform(s). The long-life CGR data are available in the mature production platforms which commonly takes 1-2 years to observe the decline trend so that there is no available data in the new drilled area and non-production area. This might cause inaccurate prediction of liquid reserves in the future platform especially in the platform locates far away from the mature production area. Multiple data which are basin modeling, geochemical data, drill-stem test, and batch-level production were analyzed and integrated to improve the accuracy of CGR prediction and understand geological reasons of high or low liquid production platform. These data can improve the confident level for CGR estimation in the non-production area and help identify potentially high liquid production platforms. The results show that the high liquid production in Pailin and Moragot fields related with the differentiation of source rock and migration process. There are three (3) separated trends in Pailin field and two (2) trends in Moragot field using geochemical data and basin modeling data. The local DST data has been integrated to confirm the extent of potentially high liquid production in several future platforms which locates in non-production area. Also, the updated production data has been re-visited to estimate the new CGR for the project located near-by production platform.
Saving 2.2 Days from Drilling in Hard and Abrasive Sandstone Formation with Innovative 360 Rolling Diamond Element Bit Technology
Authors: Ngo Vi Lan , Khobchit Wanwarang , Teerachotmongkol Teerawat , Mohammad Zayyan , Abbasgholipour Ali , Jiratawaree Sanyapong , Tungperachaikul Thanakorn , Amranand Sorawit , Soontarerat Apimuk , Akeratchataphun Yindee , Udomsak Adiruj , Chantimapong Atthawat 
Published: March 2021

Abstract
This project drilled in Sin Phu Horm field. The main challenge in this field is the formation. The 8.5-in section is designed to drill through the hard and abrasive sandstone formation (known as Nam Phong formation) with unconfined compressive strength (UCS) between 6,000 and 24,000 psi and peak up to 55,000 psi. Multiple bit runs and heavy set of Polycrystalline Diamond Compact (PDC) bits were observed in the offset wells with slow rate of penetration (ROP) and short intervals, which resulted in a high drilling cost. In the offset runs, the average interval was observed between 200 and 300 meters and average on-bottom ROP ranged from 2 to 8 m/hr. Worn cutters were the main dull characteristic in the offset PDC bits and the bits were pulled out of hole due to slow ROP. Due to the challenging formation, the goal was to increase the interval per bit run and ROP which resulted to reduce the number of bit trips and drilling cost.
Looking at the dull grading of the offset PDC bits, it was obvious that the slow ROP was caused by the cutters worn by the abrasive and hard Nam Phong formation. The fixed-cutter PDC bits were run in the offset wells and worn cutters were observed in the shoulder area. The worn portion of the cutter occurred only in the exposed side, while the portion in the cutter pocket remained intact. Utilizing the portion in the cutter pocket helps to prolong cutter life, increase the ROP, and bit life longevity. Thus, it can help to reduce undesired bit trips.
Based on the worn cutter observation, the new design of the 8.5-in PDC bit equipped with innovative 360 rolling cutter (RC) bit was proposed.
A comprehensive vibration simulation drilling parameters roadmap were provided to minimize shock and vibration.
Two bits were run with rotary steerable BHA to drill Nam Phong formation in the field. The first bit drilled 431 meters at an average ROP of 6.8 m/hr and the second bit drilled 391 meters at an average ROP of 5.5 m/hr. Two runs using the 360 RC bits drilled 822 meters in total of 1,236 meters entire interval of Nam Phong formation, which was equivalent to 66%, achieving the operator's goal while saving 2.2 days solely from two runs of RC bit. This success increased the operator's confidence to run 360 RC bits in the subsequent wells to reduce the number of bit trips and increase the ROP.
This paper will discuss the application and evolution of 360 RC bit, along with the result achieved by the bit fitted equipped with this cutter in Thailand onshore.