bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Application of Robotic Drilling Systems in Extreme Environments
Authors: Watt Martin , Rafati Roozbeh , Hamidi Hossein 
Published: August 2016

Abstract
The oil and gas industry has always relied on the use of cutting edge technology right from its inception however, as years have progressed, oil and gas reserves around the world have become harder than ever to extract. The problem lies where unlike conventional drilling, the industry is beginning to explore extreme environments, where oil and gas reserves are plentiful, but in regions so inhospitable that humans cannot conduct and operate the drilling process on-site. A solution to this is to make use of autonomous robotic drilling systems.
The use of robotics in any industry presents a way of completing tasks that could be deemed too challenging or risky for humans to attempt in an accurate, safe and economically-sound manner. With these clear advantages of robotics in mind, it makes sense that oil operators and service companies around the world should choose to research more into how robotics can be utilised in advancing the industry and making the extraction of oil and gas in extreme environments safe and efficient in order to prevent any major incidents from occurring.
Robotic drilling systems have been identified as the key in ensuring drilling operations can be conducted in extreme environments in a safe and environmentally friendly manner. Robotic drilling systems have several key benefits compared to conventional drilling methods such as allowing for greater efficiency, improved HSE statistics, cheaper to operate and are capable of operating autonomously in inhospitable conditions.
It is paramount that if drilling is to commence in extreme environments, that it is done with caution and care with regards to the environment and safety of personnel. This paper found that robotic drilling systems, if researched and developed further, could hold the key to being able to explore extreme frontiers in a safe and efficient manner, which will allow for preservation of delicate environments whilst ensuring the worldwide energy demand can be met for years to come.
Collaborative BHA Design Optimization Modeling Leads to a Successful Run in a Challenging Formation
Authors: Noviasta Bonar , Awaliyah Siti , Hasudungan Boyke D. 
Published: August 2016

Abstract
An oil and gas operator in Indonesia had a second exploration well (L-2) in the L field located in Seram Island of eastern Indonesia. This field is known for its extremely harsh drilling environment. One of the challenging parts is the overpressured carbonate formation, which was planned to be drilled in the 8½-in section with 17-lbm/galUS water-base mud (WBM) mud density.
Based on the experience in the previous well (L-1) and looking at the challenges that could potentially happen in L-2, good prejob planning is required to improve the drilling performance. A collaborative modeling job was performed—involving well trajectory design, BHA design optimization, hydraulics modeling, and torque and drag modeling—which utilized static simulation as well as drillstring vibrations modeling utilizing finite element analysis (FEA) dynamic simulation. This collaborative modeling greatly improved the bit and bottom hole assembly (BHA) selection capability by eliminating the uncertainty. Additionally, the dynamics simulation was also capable of generating a stable drilling parameters roadmap as a guideline for the driller and directional driller onsite. Several drill bits and BHA options were modeled and simulated under different drilling conditions to determine the most stable configuration. The result shows that the combination of point-the-bit rotary steerable system (RSS) and a seven-blade, 16-mm-cutter bit is the optimal BHA in the 8½-in section to drill through the hard and overpressured carbonate interval within a certain stable drilling parameters window.
The result was satisfactory where the bit-BHA-parameters combination successfully delivered the service for drilling the 2,780-ft interval in 12 fewer days than the expected drilling time (as per AFE with motor BHA), drilling 18 days faster than the previous 8½-in section in L-1 well, and reduced the number of BHA runs by 50%. Such performance was translated into 18 days spread cost saving (USD 2,673,000) for the operator as compared with the previous well, and 12 days cost saving (USD 1,782,000) as compared with AFE days.
Drilling Competency Model, A Case Study of an Upstream Oil & Gas Company
Authors: Al-Daihani Eisa Hadi , Al-Otaibi Marzouk , Valdivieso Juan Pablo , Nandi Arun Kumar 
Published: August 2016

Abstract
The advancements in drilling technology have led to rapid and sustained improvements in drilling operations. This gradual development of tools and techniques has resulted in time savings and safety improvements. The number of directional and horizontal wells is growing every year and many of these are being drilled in more challenging oilfield environments such as deep gas fields, carbonate reservoirs and high pressure-high temperature zones. There is also an increasing demand for precision directional and horizontal drilling in mature oil fields. Such advancement of technology and tools require an appropriate approach of developing the available technical manpower with related drilling competencies. Therefore, a competency based model becomes essential for National Oil Companies (NOCs) to develop their technical manpower to keep pace with the technology development.
Effective competency development is a combination of awareness, knowledge, skills and attitude that must be demonstrated to meet the performance standards required for their jobs. The paper emphasizes the need for a customized competency model for a drilling engineer in order to meet the major challenges as mentioned above. The Drilling Competencies in an Upstream National Oil Company needs to be categorized in three main disciplines which are Drilling Engineering, Drilling Operations and Drilling Techno Commercial. Therefore, exposure to these core competencies is essential for an effective drilling engineer. A case study of an Upstream Oil & Gas Company has been illustrated in this regard.
The implementation of the Drilling competency model will result in improved job satisfaction, better talent management and employee retention. Such approach of competency modeling of different job families in upstream NOCs will empower them to achieve their goal with admirable clarity, better hydrocarbon discovery index cum increase in production and field management expertise. The proposed Drilling Competency Model can serve as a guide for other National Oil Companies in their endeavor to achieve excellence.
GeoSteering in Complex Channel Sand Architecture, a Reality Now with High Definition Deep Directional Multi Boundary Detecting Technology: Case Study From Greater Burgan Field, Kuwait
Authors: Hussain Bahman , Gazi Naz H. , Al-Sabea Salem , Al-Zankawi Omran , Ali Farida , Aqeel Anfal M. , Keot Chandan Jyoti , Juyal Mukul , Wenang Martine 
Published: August 2016

Abstract
The primary reservoirs in the Greater Burgan Field in Kuwait is the Lower Cretaceous Burgan Sands. Burgan sands are divided into five major units which consist of stacked, massive fluvial channels and some units mostly consist of delta distributary channels and bays in a tidal delta setting grading to shallow marine. These are discontinuous both laterally and vertically. Channel sand geometry in geosteering perspective often sums up to discontinuous patches of sand lenses at differing stratigraphic levels. Maximizing net pay in a channel sand reservoir is known to be a very challenging task for the geosteering domain. Navigating a drainhole through such geometry requires precision geosteering technologies that can map multiple reservoir boundaries with high accuracy enabling precise forward designing wellbore trajectory with respect to the dynamic reservoir geometry. Deep directional distance to boundary "DTB" technology revolutionized the whole concept of geosteering in this regard by enabling proactive geosteering for the first time in industry. Introduced in 2005, it features the capability of detecting reservoir boundaries up to 15ft around the wellbore and achieved great success all over the world through proactive geosteering in thin reservoir layers and maximizing the percentage reservoir contact. However, this technology is limited to mapping only 2 layers, above and below the tool, up to a distance of 15ft around wellbore. It cannot detect a third layer beyond the two layers surrounding it.
High definition deep directional multi boundary detecting technology is a noble advancement on the first generation Distance to Boundary technology. With significantly improved signal to noise ratio, supported by a robust and new multilayer stochastic inversion algorithm that incorporates a whole gamut of measurements, principally from 3 firing frequencies (100kHz, 400kHz and 2Mhz), this technology extends its capability by mapping multiple boundaries up to 20ft around the wellbore.
This paper examines a case study from the Greater Burgan Field, Kuwait where the extended capability of this technology has yielded exemplary results in navigating wellbores through very complex channel sand geometry with very sharp local dip changes and varying thicknesses. Extreme geosteering is finally made possible with this fit-for-purpose technology in complex subsurface environments, lowering construction risk while maximizing net pay for each well drilled.
Field Tests of Drill Bits With Enhanced Hydraulic Design
Authors: Moslemi Ali , Cunningham Jason , Wang Alan , Garcia Alexis 
Published: August 2016

Abstract
This paper aims to report the field test results of several drill bits with enhanced hydraulic design features including optimum nozzle orientation and blade height as well as new patent-pending flow guide. These drill bits were developed based on numerous experimental and numerical tests. Computational Fluid Dynamics (CFD) was used to model the effect of various design features on bit hydraulics and then they were tested in Pressurized Drilling Lab (PDL). After the encouraging results of the experimental bits, several bits with enhanced hydraulic design were manufactured and sent to the filed for the final tests. The drilled formations were mostly soft to medium hard and ranged from shale to limestone. In most of reported cases, these bits outperformed the competition bits with Rate of Penetration (ROP) improvement ranging from 24% to 108% resulting in cost and time savings for operating companies.
Integrating Software for Improved Well Planning
Authors: Ponsonby M. C. , Andersen O. J. , Mathisen P. 
Published: August 2016

Abstract
Each company has its own method of capturing data during the Drilling and Well Construction process, and these methods will vary from simple spreadsheets to more complex systems that captures the live data and stores it. Each company will also have a method of capturing the lessons learned, usually in the form or an End of Well Report or wash up meeting with all of the service companies. Turning this data into useful information and thence to knowledge is at the moment a difficult problem
This transition process had been brought about by combining two specialist pieces of software. The first has the ability to take in date from all sorts of sources ranging from spread sheets via daily reporting systems to historical log data or real time data stream, mud logs etc. and then to present that data in a form that is useful to the drilling engineer in designing a well. The software also allows storage of experiences, both positive and negative, and links them to wells, rigs, specific types of equipment or operations.
This central store of data and the ability to transition it into useful information gives the engineer designing a well the ability to identify the risks and also the spread of times taken for various operations.
The second piece of software uses probabilistic calculations and the ability to place branches into the process that take into account the risks identified using the data storage software. Once a risk is identified then the mitigation steps are identified: how it will be addressed, what is needed and when.
All this information is taken into account when calculating the time and cost, giving a spread from Technical Limit through to Worst Case. More importantly all of the steps, and assumptions are stored in one place rather than the traditional multiple spreadsheets that generate the "Excel Hell" scenario.
By following a simple process with only two pieces of software the accuracy of well costing and scheduling can be increased additionally the understanding and mitigation of risk improves and lessons learned are no longer lost as personnel move within the company or the industry.
First Implementation of a Resilient and Self-Sealing Cementing System to Optimise Long-Term Zonal Isolation in Challenging Offshore Wells - Review of 3 Case Histories in Malaysia
Authors: Brandl A. , Alegria A. E. , Ismail M. , Dean G. , Mohd Mahaiyudin A. R. 
Published: August 2016

Abstract
Three consecutively drilled, highly deviated, high-temperature offshore wells in Malaysia with multiple thin payzones and planned close perforation distances required the use of a self-sealing cementing technology with optimized mechanical properties to minimize the risk of unwanted fluid communication that would necessitate immediate abandonment. This paper reviews the successful implementation of the corresponding cementing system starting from its development, through the jobs' planning phases, to the operational executions and evaluation with results. A pre-job study was executed to design a suitable cementing system, including thorough lab tests, CFD simulations for optimized fluid displacement efficiencies, and cement sheath stress modelling to optimize the cement mechanical properties. A novel HPHT multi-function test cell (MFTC) was used to measure in-situ ability of fractured cement specimens to seal hydrocarbon flows under the given simulated downhole conditions. Yard tests were conducted to ensure quality and field applicability of the engineered cementing system.
With the help of the simulations and lab tests, the mud-spacer-cement fluid trains could be optimized for fluid friction and density hierarchies during each 7-in. liner cementing job for effective synthetic oil-based mud removal and cement slurry placement covering the desired &gt;1,000 m annular length in highly deviated wells with low frac gradients at temperatures up to 300 °F. Combining the self-sealing additive with a mineral fiber in the tested cement designs significantly reduced the Young's modulus of the set cement while the tensile strength and the Poisson's ratio improved, resulting in a higher resilience of the cement sheath to survive the anticipated downhole stresses from the completion program. The crack-and-seal tests demonstrated the cement system could repeatedly seal cracks or micro-annuli up to at least 0.15 mm (0.006-in.) due to the swelling of the self-sealing additive in the presence of a hydrocarbon flow at differential pressures below 1,000 psi and temperatures up to at least 300 °F. The expansion of the set cement was also optimized to enhance the bond to formation and pipe. The evaluation of the pre-job planning, job execution as per program, post-job simulated pressure matches, positive ultrasonic cement logging results, and the fact that no issues have been observed during or after the job indicated well-isolated intervals. The novel cementing concept combines several advanced design features (self-sealing in the presence of hydrocarbons, expansion, resilient mechanical properties) that improve long-term zonal isolation in critical well scenarios.
Common Incident Reporting and Tracking Platform
Authors: Ponsonby M. C. , Andersen O. J. , Mathisen P. 
Published: August 2016

Abstract
The objectives was to investigate the present systems used for QHSE reporting and suggest how these may be combined in to an industry standard that is independent of the size and specific area of our industry. The system would allow tracking and comparison of incidents across companies and reduce the element of humane error.
The process involved researching the systems used in different industries such as IT and Car manufacturing and the systems used in the Oil and Gas industries. For the Oil and Gas industries the focus was on the Norwegian Continental Shelf and included Operating and Service companies as well as Government agencies.
The research confirmed the theory that there was a huge amount of variation between all of the companies on how their process worked. An additional finding was the amount of variation internally in some of the larger companies. This variation makes any collaboration between companies or Government agencies to track trends or follow up on the incidents extremely difficult. Historical lessons cannot be utilised across different companies or geographical regions resulting in the same incidents occurring as the learnings have been lost due to movement of personnel (especially important in the current industry climate) or the difficulty of finding the information.
Our conclusion is the development of a system that allows learning, not only from within our own industry but also from other industries. The system allows learnings to migrate from other industries and within our own industry gives a simple process for recalling, sharing, and collaborating on the incidents not only for safety but also for quality.
A Unique ICD's Advance Completions Design Solution with Single Well Dynamic Modeling
Authors: Goh G. , Tan T. , Zhang L. M. 
Published: August 2016

Abstract
Inflow control devices (ICD) completion is a downhole flow control solution that is designed to balance influx contributions across wellbore horizontal section, to delay water breakthrough or coning hot-spots and to increase ultimate cumulative oil recovery. This paper illustrates a novel and successful systematic workflow to implement this technology in order to effectively manage the marginal green reservoir uncertainties while achieving field development requirements. In general, this production-upsides justification and design process started from an early stage full field ICD completion feasibility study; followed by single well pre-drill ICD design through dynamic simulation as preparation for real time drilling operation support. Subsequently, ICD nozzle-configuration optimization and packer placement design fine-tuning were performed before run in hole during real time operation. The final optimized design for ICD and tracer tally can then be proposed for on-site execution. The key enabler of this process is a novel and time-efficient single well dynamic simulation method, which is compiling the dynamic time-lapse production responds with various ICD nozzle and packer design optimisation workflow. The sensitivities of various design scenarios were applied as a working range to guide on-site ICD installation.
This paper highlight the design and optimization workflow from the perspective of dynamic modeling against the conventional nodal-based or single time-step production scenario simulation carried out. In illustrating the more ‘down-to-earth’ production upside results when time-lapse impact are considered, single well dynamic modeling can provide a more realistic real-time design especially in marginal oilfield application and critical decision-making during real-time. Against the typical over-optimistic production upsides analysis result portrayed by conventional single time-step production scenario simulation, some actual design cases as conservatively predicted by dynamic modeling single well will be demonstrated to influence decision-making when ICD's upsides is marginal . This crucial differentiation in due dilligence upside analysis will guide towards most optimal ICD's configuration RIH or reciprocally applying standalone screen (SAS) instead against the ICD's RIH minimal production benefits against its cost value. The results showed that the uncertainties and production repercussion that are affecting the decision of either running ICD's or SAS during real-time ICD's modeling updates are handled more inclusively and objectively with time-lapse based dynamic prediction.
Application Focused Drill Bit Engineering Delivers Consistent Improvement in Efficient Drilling Performance
Authors: Agawani Waleed , Al-Ajmi Abdulla M. , Taha Mohamed , Gohain Ashish , Omar Marwa , Al-Haj Hussain Ali , Abdelhamid Atef 
Published: August 2016

Abstract
Balancing aggressiveness, stability and durability bit behaviours is the principal engineering challenge when designing an application-specific PDC bit. The application this paper addresses is a directionally drilled interbedded abrasive formation that generates dysfunctional drilling torque. This paper demonstrates the engineering process of designing a bit that balances the three major bit behaviours, thereby optimizing drilling efficiency to meet the goals of successfully drilling the required interval while improving rates of penetration.
West Kuwait's 12.25" section primarily involves interbedded abrasive sandstone and hard shale sublayers that induce torque fluctuations. The combined result is impact and abrasion wear on cutters causing mid-run reduction in rates of penetration, prematurely terminating the run. The section involves a J-type directional profile drilled using an adjustable-bend mud motor or a rotary steerable system. It starts off drilling vertically till the kick off point followed by building up to the tangent section and holding angle to section end. The high torque and vibrations faced in this application make steering difficult for any directional drive type; further compounding the challenge to achieve higher rates of penetration.
Building a solution to match the application involved:
Reviewing bit dulls and studying locations of extensive wear on the bit body Comparing current design performance against success metrics in the target application Bit design requirements for specific rotary steerable systems and mud motors to build a universal design that works with all major drive types Consideration of different torsional stability technologies and their appropriateness for our application Field trials across different drive types
The engineering process concluded with a seven bladed PDC bit with aggressive cutting structure that successfully completes the interval while improving rates of penetration by over 50%. Trials were implemented across several wells involving the major drive types to verify the new design's effectiveness versus previous designs. Most trials proved the bit was more efficient in directing mechanical specific energy into the formation rather than squandering drilling energy on damaging vibrations. This resulted in rates of penetration higher than the field average through better bit stability and smoother steerability on all directional drive types used in the application.
This paper highlights the engineering process and the technology invested in developing a PDC bit for drilling directional runs through mixed abrasive and impact prone formations.