bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrating the Fully Coupled 3D Geomechanical Modeling for Hydraulic Fracturing Optimization of Unconventional Resources
Authors: Cheng Leiming , Wang Yingwei , Zhao Haiyan , Li Jiacheng , Liu Xiao , Liu Qiyao , Huang Xingning , Singjaroen Thanapol , Kieduppatum Piyanuch 
Published: August 2022

Abstract
The unconventional oil and gas resources continuously discovered in China are mainly concentrated in the Junggar Basin, Ordos Basin, Sichuan Basin and Songliao Basin. However, the porosity and permeability of its shale reservoirs are extremely low, which brings relatively great difficulties and challenges to the economic development of shale oil reservoir. Long horizontal well section drilling and multi-stage hydraulic fracturing are the key technologies of unconventional resources development. The operations can increase the stimulated volume and ultimately achieve the goal of improving production. In addition, shale reservoirs natural fractures and horizontal bedding are developed, leading to shear slip and tensile failure during the fracturing propagation process. Moreover, the hydraulic fracture is no longer a single symmetrical two-wing fracture, and it is very likely to form a relatively very complex fracture network. This will bring many inconveniences to shale hydraulic fracturing design, fracture monitoring and interpretation, and post-fracturing productivity prediction. Geomechanics is the important influencing parameter that affects the design of hydraulic fracturing. This research is mainly based on the research results of 3D geomechanics to continuously optimize hydraulic fracturing design for horizontal wells. In addition, the implementation of hydraulic fracturing can significantly reduce the seepage resistance of fluids in the formation near the bottom of the well. This will be a very effective mean to increase well production for unconventional resources. Hydraulic fracturing optimization technique fully-coupling 3D geomechanical modeling was applied in the unconventional reservoir in the northeast of Junggar Basin. The shale oil reservoir of Permian Lucaogou formation is one of the main unconventional resources in China. This case study discusses the multi-stages fracturing optimization of horizontal well-A based on the fully coupled 3D Geomechanical modeling. The research result clearly characterizes the stress model variation and reduces the uncertainties in horizontal well-A1 for hydraulic fracturing operation. The uncertainty of the fracture modeling geometry was greatly reduced, and fracture geometry was verified by micro-seismic patterns. The geomechanical modeling helps to optimize the pressure pumping rate, the volume of proppant and fracturing fluids, eventually maximizes the increase of fracture flow conductivity and post-stimulation production.
First Slim Open Hole Standalone Screen Completion Offshore Malaysia – Performances, Lessons Learned and Way Forward
Authors: Kumar Suman , Hassan W M Faris W , Latif Nurlizawati , Roh Cheol Hwan , Madon Bahrom B , Sakdilah M Zaki B , Karim Aminuddin B 
Published: August 2022

Abstract
T field has very unconsolidated sand with high nonuniformity and high fines contents in H and I sands and require robust sand control, typically Internal gravel pack (IGP). Historically, around 90% wells have been completed with IGP completion and are producing sand free for the last 20-30 years. This paper describes on the first slim (3") open hole standalone screen (OHSAS) completion application and performance which can be utilized for replication in future infill wells.
Around 10% remaining wells have been completed with OHSAS completion across highly deviated wells in H and I sands in T field. The screens have been designed based on d10 sand particle size and sand retention test (SRT) and typically installed in 8 ½" open hole. The drill-in fluid (DIF) has been properly designed to create temporary filter cake across the wellbore and then it is designed to break by either lift-off pressure or by usage of mud cake breaker depending upon the type of DIF system.
The OHSAS wells are producing good with sand free production since last seven to fourteen years. The OHSAS performances for all wells in T field have been investigated. The investigation has provided suggestions for further improvement in future projects. Based on the investigation, OHSAS completions in T field has good OHSAS design and production performance, though further improvement can be done in its execution for future projects like monitoring total soluble clays using Methylene Blue Test (MBT) during drilling reservoir sections, maintaining its solubility more than 70% all throughout, use of proper mud cake breaker, etc. This paper explains details on the outcome of the investigation and recommendations, and data requirement to assess successful OHSAS completions with the help of tables and charts. The applicability of OHSAS has been re-studied in future infill wells and have been included in the next field development plans.
This paper presents on the OHSAS design, execution and performance, best practices, reviews and suggestions for further improvement in future infill wells, then its applicability and replication in future projects.
Development and Application of Digital Solutions for Automatic Hazard Identification During Well Planning Stage
Authors: Ruzhnikov Alexey , Saraiya Rasesh 
Published: August 2022

Abstract
Having a good understanding of the offset wells is the key for successful planning and execution of any well, both from the risk management point of view as well as from equipment and operations planning. In both cases of congested or simple fields the amount of the manual work is significant, which further affected by potential human mistakes. The manuscript aims to provide the detailed explanation of the digitalization of the offset well risk analysis (ORA) implemented in several drilling projected, what lead to almost complete elimination of the manual work and allowed to improve the quality and the quantity of the offset data.
At the project kick-off the manual work performed by different parties (drilling engineer as well as drilling fluid, directional, bits engineers etc.) was mapped in the different detailed workflows. This allowed to understand the final result of every tasks. As next step the massive database of the end of well reports, post-job reports, daily drilling reports, etc was created with few tens of millions entry points. Further the artificial intelligence in combination with data analytics was used to replicate the previously mapped workflows.
As the result entire manual work was replaced by the digital, leading to receive higher number of outputs with superior quality. The direct benefit was a reduction of the time required to get the final result, when previously a detailed analysis was completed in 3 to 4 days, and now it is done within minutes, allowing to dedicate the man-hours to more other valuable tasks.
The manuscript provides the novel information on ability to use digital technologies to eliminate manual work and avoid costly human mistakes. The proposed solution can be implemented in any other drilling project worldwide, as well as in any other activity requiring performance of the repetitive tasks.
Drilling and Well Digitalization, A Journey of Transformation
Authors: Benjaboonyazit Veerawit , Durongwattana Nithipoom , Buapha Sompop , Wejwittayaklung Kittipat , Rangsriwong Phattarakorn 
Published: August 2022

Abstract
The Company's digital transformation project was started in 2018 to overcome the challenge from digital disruption, energy transition and hydrocarbon reserves declination. Drilling and well engineering cluster is a key player in operating cost optimization which requires digestion and analysis of tons of data generated through daily operational reports. Thus, several digitalization projects have been initiated to optimize drilling and well process to be better, faster, and safer. In this paper, we intend to share a successful journey of digitalization under drilling and well cluster.
The transformation journey started with identifying engineer's pain points in each process, among which the most common were redundant processes, manual data inputs/calculations, and time spent on collecting and analyzing unstructured data sources. Moreover, diversified practices on engineering programs and data analysis adversely affect well design standardization and optimizations. To counter those pain points, digital transformation projects were ideated by using digital solutions and technology which are grouped in 5 focus areas: centralized data platform, business intelligence, robotic process automation, digital assistant, and data analytics from fundamental to advance level respectively. Besides out-of-the-box solutions, many internally developed systems have been utilized throughout the journey which helps engineers to build their digital capability and awareness.
There are over twenty (20) drilling and well digital projects implemented since the transformation project has been started. And as a result, engineers’ workload has been reduced significantly using digital solutions such as data extraction, visualization, and in-depth analysis. For example, the first successful project under robotic process automation utilizes text analytic and Artificial Intelligence (AI) techniques to analyze well conditions and integrity status from unstructured data and to generate reports within a limited timeframe. Another successful case is well design automated workflow which saved around 40% planning cycle time and provides a better design quality which will lead to a lower well cost.
Total cost saving of over 40 mmusd has been recorded so far under the digital transformation project. Furthermore, there is an outlook for additional cost-saving through future new projects, integration, and scaling up plans across the company's international assets. The results and outcomes are very promising to this point. We believe that these initiatives will help the company to improve productivity, benefits, agility, and move beyond business disruptions.
Combination of drilling and well expertise with digital transformation solutions will significantly improve well design process, quality and operational efficiency which make industry stay competitive and resilient in the future.
Automated Workflows and Drilling Advisory Systems – The Cinderellas of Drilling Automation
Authors: Francis Paul 
Published: August 2022

Abstract
In the field of drilling automation, most attention is usually focussed on the automating the mechanical side of the business and yet vast amounts of time and energy are spent by well engineers on designing and executing wells that may involve redesigns during the execution of the well due to subsurface uncertainty. This effort involves many people in the organisation, creates large amounts of documents and data that usually reside in different silos. The effort involved in pulling the right data together from different sources and checking that it's correct involves a lot of drudgery, hence it called be a ‘Cinderella’ task. There is a maxim that says that "If you can't measure you can't manage", but it's equally true that "if you can't analyse your measurements effectively and efficiently then you can't optimize", either for ROP or energy efficiency. This paper discusses the essential requirements for workflow optimization and drilling advisory systems, both as a business case in itself, but also as a reassuring steppingstone to full drilling automation.
Significant advances in AI and Cloud Computing in the last decade have led to the ability to better automate the workflow process and allow real-time drilling advisory systems that allow a human-in-the-loop to react to and modify the drilling process. The essential parts of such are a workflow/optimisation system, no matter how good the AI, is that it should be intuitive, easy to use, vendor neutral, have robust data cleansing, be backed by 24/7 support, be customisable to the particular needs of the operation and flexible enough to work on different platforms yet allow expansion as new requirements are added. Operators are consistently wanting to centralise, then standardise, data flows for greater automated analysis and management.
Using such a system, ROP improvements of over 18% have been seen in land operations, flat time reductions of 20% have been seen on offshore wells, weight to weight connection times have been reduced by over 35%, costly trips out of hole have been avoided due to MWD failure by directly comparing hole depth with offset well data in real time.
With cloud-enabled, real-time AI, there is currently no limit on how ‘joined-up’ the drilling process can be, from rig scheduling through to production. Once confidence is gained by operators with drilling advisory systems and data quality then the next steps would be to hook these systems directly to drive rigs and tools with the human now as the monitor.
Complete MPD Rig: Time for Jack-Ups Now
Authors: Gedge Benjamin , Binh Cao , Vuong Trinh , Hai Nguyen , Yaw Norman , Mardon Jeff , Frohlich Herbert , Gooding Neil , Santos Helio 
Published: August 2022

Abstract
Four years ago (IADC/SPE-191099) the move was clear on floating rigsâ€‹; to have them fully equipped with a Complete MPD package, the economic justification was very strong. Currently, there are around 20 floating rigs with a Complete MPD package, permanently installed. For Jack-Ups, however, the same move started only recently, with a few rigs now equipped with a Complete MPD package, using the same philosophy applied to a floating rig. The paper initially describes the success obtained by the Complete MPDâ€‹ floating rigs, not only from an economic, but also from a technical point of view, with operations in Australia, Brazil and the Gulf of Mexico. Having the MPD package permanently installed and ready to use, operators are now deploying MPD for the total well construction process, with a rig crew competent in running the MPD system, from spud to the T.D. of the well. This includes running casing/liner, cementing and, also, completions. The paper outlines the benefits and advantages for both the operators and drilling contractors, showing they are significant. Companies are taking advantage of having the MPD system on the rig and being able to maximise the full benefits.
With all the success seen on floating rigsâ€‹, operators startâ€‹ed to realize the benefits of using the same approach for Jack-Ups, building on previous experience with temporary MPD installations on Jack-Ups, â€‹learning from what worked and what did not work. The paper deâ€‹scribes the recent Complete MPD Jack-Up installation in Norway â€‹(implemented under the new MPD NORSOK requirements, which made it even more challengingâ€‹), the success achieved with the first wells drilled, and how the economics will work for the Jack-Up market, in the same way it works for the floater market. The technical benefits are the same, as the system used on the Jack-Up is equivalent and has the same features of the systems used on the floating rigs.
The paper finally addresses the Asia Pacific market, which is dominated by Jack-Up rigs over floaters. The economic, technical, HSE and logistical benefits make it an appealing proposition to have a Complete MPD Jack-Up rig, and they are all discussed in detail. An example is used with a Jack-Up operating in the region, clearly demonstrating its similarity to a floating rig when adopting the same Complete MPD Rig approach.
Successfully Application of RPM in Sand Control Treatments for Offshore Field: Challenges, Results and Improvements
Authors: Choodesh Attawit , Chantarataneewat Wiwan , Ramirez Cristian , Rosdi Mohd Hisyam 
Published: August 2022

Abstract
One of the offshore gas fields, the formations are comprised of mixed deltaic and young shallow marine clastic sediments, which are considered among the shallowest unconsolidated and poorly sorted formations, with a high percentage of fines. Along with the sand production issue is the multiple stacked reservoirs that consist of interbedded sand-shale and laminations having undergone gas-water contact (GWC). The proximity of a water leg to the gas column also indicates likelihood of early water production. Water breakthrough can cause significant reserve loss in the gas reservoir and can be even more serious in the sand control completion, which creates a challenge when the two problems combine water and sand.
Typical sand control treatments were high-rate water packs (HRWPs) and Extension packs (ExtPacs) or fracture for placement of proppant (FPP). The use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear thinning rheological properties and efficiently suspends sand in static condition. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with laboratory testing using reservoir cores to validate return permeability values). The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time using effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water shutoff treatment stage later as part of well life
Applying the RPM process has not only reduced water production in these areas but has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application. Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid, consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of the RPM technique in sand-control completions also an option to treat wells after sand-control treatments and control water production resulting from nearby GWC
Combination of Side Entry Sub, Pad Eye Sub, and Swivel Sub Prevents Damage to Wireline Cable and Allows Heave Compensation on a Semi-submersible Rig for Pipe Recovery Operation
Authors: Pinprayong Verapich , Htet Myo , Seleman Mohd Al-Amin , Lim Annie , Riaz Kevin 
Published: August 2022

Abstract
Wireline pipe recovery operation on a floater type offshore rig such as a semi-submersible or drillship can be challenging when heave motion affects the wireline cable, depth accuracy, cable tension, rig-up equipment positions, and well control. The heave motion compensator (HMC) unit connected on top of the top-drive system (TDS) has a narrow gap that allows a wireline cable to pass through and could cause damage to the wireline cable. Conventional processes in performing pipe recovery operations only permit operations to occur on the open end of the drillpipe while on the rotary table. With a long bailer arm, the cable will have enough clearance to pass through the elevator then enter the TDS body, but this process also prevents the operator from establishing a barrier for well control situations because the top of the drillpipe remains open. The other issue is depth accuracy, where heave motion causes both upward and downward movement on the cable while wireline is being run in hole (RIH) or pulled out of the hole (POOH). The depth shifts due to heaving motion could cause a back-off string shot to be fired off at depth.
To overcome these issues, the Smart Sub system—a combination of a special side-entry sub (SES), pad eye sub, and a swivel sub—allows heave motion to be compensated to the top sheave and enables the wireline cable to be positioned in front of the TDS unlike the conventional method where the cable remains in contact with the TDS. The real result of this combination is studied from the pipe recovery operation performed on semi-submersible rig in Myanmar.
Reducing Drilling Risk Associated with Running Casing through Challenging Borehole Conditions with the Adoption of a Scalable Ultra-High Speed Hydraulically Actuated Reamer Shoe Technology
Authors: Nkwocha Chimerebere , Yimyam Nipatsin 
Published: August 2022

Abstract
This paper presents lessons learned and best practices using a scalable hydraulically actuated reamer shoe system for casing deployment. The technology was used in a few wells to successfully run 7 inch casing through problematic geological horizons where it had been impossible to do so with conventional float shoes.
A scalable and customizable high speed reamer shoe technology was deployed in three wells right after a well in which the 7 inch long-string could not be deployed to objective depth and had to be set prematurely, leaving a lengthy rathole below the casing shoe. Consequently, the production zone had to be drilled and completed in 4 ½ inch. This ultra-high speed scalabe reamer shoe technology was then deployed in subsequent wells in an attempt to address this concern. Three 7 inch reamer shoes with two different configurations were deployed. Two were configured for LCM tolerance, whilst the third tool was tuned towards more optimal performance at lower circulating rates. The 7 inch casing strings were successfully deployed and cemented in all three wells.
Tools with two variants of a new scalable, dual-chamber drive mechanism from the manufacturer were used. The major difference being in the flow pattern between the chambers. The LCM tolerant tools were the latest variant of the drive mechanism with a minimum restriction of 15mm, while the tool with the earlier variant of the scalable drive chamber, had a minimum restriction of 8 mm and a by-pass valve arrangement made up of 4 x 20mm ports. Activation flow rates were low though significantly different. The earlier tool activated at +/- 60 gpm whereas the more recent drive mechanism in the latest variant, activated at 26 gpm, indicative of a significant improvement in tool performance though configured for higher flow rates. Operating pressures were significantly higher in the earlier variant compared to the more recent drive mechanism. The differences in activation flow rates and operating pressures are due to how flow is altered and channeled through the drive mechanism as configured in each tool. All three tools were used to run 7 inch casing at low circulation (&lt; 180 gpm) and successfully reamed through any obstructions encountered and cemented at target depth.
The use of this technology was instrumental in successfully deploying all three 7 inch casing strings to objective depth. Due to its low flow capbilities (&lt;180 gpm), PTTEP was able to successfully manage the tight pressure margin required to land casing and displace cement. Furthermore, the tool was evidently effective at circulating rates as low as 100 gpm and low operating pressures, making it ideal for most tubular deployment applications.