bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aligned Materials and Design Development of High ROP Drill Bits
Authors: Deen C. Aron , Kitagawa Casey , Schneider B. , King G. 
Published: August 2014

Abstract
At their advent, PDC bits were aimed at soft formation, fast drilling applications. However, as PDCs have come to dominate market share over roller cones, PDC bit development has shifted focus toward other goals such as durability and longevity which is often in conflict with high ROP. Returning focus to aggressive, high ROP drilling applications has required development of materials, design and manufacturing processes in alignment with that goal set.
A cross-functional team was assembled to understand and focus on the high ROP concerns of the end customer and was tasked to develop a PDC bit platform aligned with these goals. This paper discusses general and application specific challenges posed by high ROP drilling applications and how they have been addressed by the aligned development of a new system of materials, design, and manufacturing processes used in PDC drill bits. Formation to bit interaction simulations and computational fluid dynamic modeling analysis are presented in support of the development hypotheses. Field results from case studies and broad field data analysis summarizing the results of extensive testing are presented as well.
Driving ROP beyond the ceilings observed in many extreme ROP applications requires that energy be efficiently transferred not just to the bit, but focused on the cutters. To achieve this, an essential change to the base material of the bit body was made, exposing drastically new avenues – and hurdles – for design and manufacturing. However, the simulation and field results presented confirm that the new system is able to consistently achieve the goal set in high ROP applications.
A Novel Autonomous Inflow Control Device Design Based on Water Swelling Rubber
Authors: Sang Guangsen , Jiang Zhenhai , Zhang Qingjie , Wei Jianguang , Zhang Tianjun 
Published: August 2014

Abstract
In long horizontal wells, early water or gas may breakthrough into the wellbore due to imbalanced production profile caused by heel-toe effect, reservoir heterogeneity or fracture existing. Once coning occurs, oil production may be severely decreased due to limited flow contribution from the other regions. Inflow control devices (ICD) are usually installed to maintain the flow across production zones uniformly by creating an additional ICD pressure differential which cancels out the imbalanced production profile. This will lower startup production, however, unwanted fluids from breaking through are significant delayed, and total oil production is maximized. Unfortunately, once low viscosity fluid (water/gas) does break through, they will take over the well, significantly reducing oil production.
In this paper, a novel autonomous inflow control device (AICD) design is proposed based on the combination of nozzle-based ICD and water swelling rubber (WSR). The WSR installed in the nozzle swells once water breakthrough occurs, and the swell increment will be adjusted automatically according to water content, thus changing the minimum flow area and flow resistance rating (FRR) of the device. This autonomous function enables the well to continue producing oil for a longer time while limiting water. To highlight the excellent performance of the novel design, three other designs (nozzle-based, helical channel, and tube-type) with a same FRR of 0.8 were compared, with fluid property sensitivity, and structural parameter optimization researched. The results show that the device has a good performance for both oil producing and water restricting, which enables the well to continue producing oil for a longer time, and maximizing the total production.
Sustainable Safety Performance in Drilling Operation
Authors: Okoli Ejike , Amadi Amadi 
Published: August 2014

Abstract
This paper presents learnings and experiences gained in incident prevention within a Goal Zero framework where no one dies, no one gets hurt, and no leak to environment. Key HSE processes deployed that underpin sustained safety performance in SPDC Wells operations are highlighted in this paper for learning.
The ramp-up of rigs from two to eight in 2011, in an environment with restricted opportunity of optimally attracting skilled-labour from pool of global workforce due to operating environment, was a cause for concern.
Nigerian Content Development (NCD) regulations which mandated the use of contractors and employees from local communities, created a pool of first timers mainly Nigerians and Asian entrants. Work locations and terrains were difficult for rig moves involving narrow, poorly built/maintained roads, bridges, overhead cables, communities and meandering through unmaintained snaky creeks. Overall, the poor safety performance at that time could be attributed to above.
SPDC Drilling team operated for three (3) calendar years without lost time injury (LTI), without leaks to the environment, sustained strong focus on Wells Process Safety and BSi ISO14001 & 14064 certification. Example, five contractors moved from Amber rated (i.e. weaknesses in safety management) to Green (strong safety management).
Abandonment of 19 Subsea Wells in the Jabiru/Challis Fields
Authors: Clyne Iain , Jackson Neil 
Published: August 2014

Abstract
This paper describes the pre-planning and execution of Australia's largest subsea well abandonment campaign to date. The Jabiru/Challis Fields are located in the Timor Sea 640km from Darwin, Australia. The fields were discovered in 1983/84 with first production in 1986 and reached the end of their economic life in 2010. The fields consisted of 13 subsea producers and 6 suspended/partially abandoned wells making it a 19 subsea well abandonment programme.
A semi-submersible rig was selected over a jack-up primarily based on water depth and subsea hardware handling capability considerations. Abandonment solely using a construction vessel was discounted due to the age and condition of the wells and associated risks of using coiled tubing.
The condition of the wells required detailed barrier management. The main challenge was to maintain adequate barriers throughout the abandonment programme when some of the standard barriers did not exist to begin with. A number of the barriers that were in place during the well construction were no longer present. The Drilling Contractor was fully engaged to ensure single barrier operations were acceptable. Drawing on the experience gained in the North Sea, the Oil & Gas UK Guidelines for the Suspension and Abandonment of Wells were adopted.
With numerous known well issues and more potential unknown issues, coupled with significant logistical challenges, contingency planning was vital. By the end of the campaign, problems encountered included corroded casing, corroded/parted/collapsed tubing, iron sulphide scale, naturally occurring radioactive material (NORM), H2S, non-functioning tubing retrievable surface controlled subsurface safety valves (TRSCSSVs) and blocked perforations.
Significant use of construction vessels was made pre and post rig activities. A programme change during the campaign resulted in the storage of subsea hardware assemblies on the seabed for later retrieval by a construction vessel. This was a safer and lower cost option than recovery to the rig.
This paper is of use to engineers and managers commencing the planning of a subsea well abandonment campaign. It describes actual experience in a relatively uncommon operation in the industry and includes learnings which can be applied to future development planning.
LPG-Based Fracturing: An Alternate Fracturing Technique in Shale Reservoirs
Authors: Soni Tanmay M 
Published: August 2014

Abstract
A novel stimulation technique named Liquefied Petroleum Gas (LPG) based fracturing which can be an alternative to conventional water based fracturing technique or hydraulic fracturing.
In conventional hydraulic fracturing treatments, it is observed that effective fracture length contributing to the production is fraction of the propped fracture length. In LPG fracturing effective fracture length is more than conventional fracture length hence increasing productivity. If we use gelled LPG as a fracturing fluid, it is highly soluble with the formation hydrocarbon. If natural gas formations are present, then propane and methane will combine to create unique liquid vapour saturation and returns to the surface at ambient conditions which can be separated easily. LPG fracturing eliminates the need of flowback water disposal, which is currently major problem in hydraulic fracturing. In LPG fracturing, a stream of gelled LPG or a mixture of propane and butane is injected into the well. Proppant is supplied in this stream and carried into the formation at frac pressures causing fractures though some precautions are must for the safety issues. It has been observed that with less viscosity, less surface tension and less density, LPG can rapidly and efficiently clean up while reducing the pressure needed to mobilize fracturing fluids.
In this paper, effective fracture lengths and rapid cleanup are demonstrated with the help of post fracture pressure transient analysis. Comparison of LPG fracturing with conventional fracturing has been explained critically. Complete recovery of the LPG has also been demonstrated here. Major advantages and disadvantages of this technique along with economics are included in this paper. We can use this technique in order to protect the environment and to increase the productivity. This paper briefly reviews the previous work and explains an overview and applications of LPG fracturing.
Understanding Excessive Water Production in Highly Faulted Mature Gas Condensate Field: From Well Operations to Revival of Integrated History Matching
Authors: Fayzullin Maksim , Tippel Philipp , Gonzalez Jose , Egger Stefan 
Published: August 2014

Abstract
This case study illustrates a methodology adopted by an operator to reveal the dominating mechanism behind dramatic watering-out sequence, prevailing production from a mature gas condensate field in Eastern Europe. A production restoration project was triggered to understand and remedy the adverse effect of water. Finally, its source could be solely verified with the help of numerical simulation.
Many attempts to isolate or handle excessive water production fail, because remediation activities are deployed in the trial- and-error manner, without prior water source identification. Possible reasons that operators simplify their approach by reverting to the best practices/analogs, not accounting for individuality of the problem. Furthermore, ineffective water shutoff jobs are not always analyzed for their pitfalls and consequently fed to the next well. Thereby, the process lacks true insight of the nature of water appearance and, in turn, the right remediation strategy from start, if it exists.
The field development showed that, after water breakthrough, the gas rate dropped by a factor of 4 or 5, thus leading to huge production losses. First, water production occurred in the crest of the structure followed by a sequence of wells being watered-out. The past experience to isolate the invading zone accompanied with extensive logging and misleading choking-back, revealed the necessity of thorough water diagnostics. The well-known categories of problems were analyzed tying them to subsurface uncertainties and vast reservoir information. Simple types were gradually replaced by complex processes, or even by the combination of the following: faulting, multilayered channeling, system of fractures etc. The formed concepts were reviewed in the simulation model honoring available buildup/per-interval pressures, casedhole production/saturation logs and repeated openhole logs to obtain the historical water/gas ratio (WGR) evolution. Finally, the strategy was refined giving ideas for deepening of the wells and downdip sidetracking in the less invaded zones.
Novel Lubricant - Bridging Agent Combination Cures Differential Sticking Problems in High Pressured North Kuwait Wells
Authors: Al-Muhailan M. S. , Al-Foudari Saud Jumah , Debroy Amalendu , Rajagopalan Arun , AbouElkhair M. , McNaughton P. 
Published: August 2014

Abstract
Deep wells drilled into the Jurassic formations of North Kuwait pose a drilling challenge due to the existence of low pressure reservoirs separated by an extremely high pressure salt zone. Currently, the seven string casing design in these wells leaves no further option for zonal isolation. As a result, a wide range of pore pressures are encountered while drilling these formations. Depleted zones/reservoirs in these wells suffered multiple instances of differentially stuck pipe and side tracks. The end result has been a significant loss of expensive rig days. These sections are drilled using oil based mud (OBM) with a high oil/water ratio and mud densities ranging from 10 to 17 ppg.
To prevent a reoccurrence of the differential sticking problems, extensive laboratory work was undertaken to determine how to negate the effects of high differential sticking force while drilling depleted zones. Laboratory tests and fracture modelling based on historical data were carried out to develop a suitable fluid formulation to address these challenges. This work indicated that a novel combination of glycolic polymer lubricant and sized marble bridging agent provided the optimum combination of lubricity and filtration control to minimize differential sticking tendency.
A fluid formulation based on the laboratory results was utilized to drill subsequent wells in this field. The depleted intervals were drilled using a similar OBM treated with a combination of unique lubricant and sized marble bridging agent to reduce differential pressure transmission across the depleted zones. The intervals were drilled and logged without the occurrence of any problems of differential sticking. The troublesome sections were completed incident free resulting in huge savings in cost and rig time.
This paper describes the historical challenges in this field and present case studies demonstrating how the solution was successfully implemented in the field.
Improved Calculation of Multiple Annuli Pressure Buildup in Subsea HPHT Wells
Authors: Yin Fei , Gao Deli 
Published: August 2014

Abstract
In subsea HPHT wells, annular pressure buildup caused by thermal expansion of fluid endangers well integrity. The conventional well design is not secure for subsea HPHT wells. It is significant to assess the risk from annular pressure buildup and provide solutions. Considering the interactions and pressure changes of different annuli, the calculation model of annular pressure buildup in multiple casing annuli is established. This model expands the scope of application of existing models. In view of temperature-dependent coefficient of thermal expansion and compressibility, the calculation method based on temperature increment is adopted to improve the calculation precision of annular pressure buildup. Research results show that the annular pressure buildups are various under the condition of different temperature ranges and same temperature change, and the annular pressure buildup in high temperature range is greater than that in low temperature range. The casing load arising from annular pressure buildup reaches or even exceeds the casing load according to conventional design. The research methodology is applied to a subsea HPHT well. The potential risk is discovered in the conventional casing design when annular pressure buildup occurs, and the casings are optimized design to deal with the issue. Furthermore, the mitigation measures for annular pressure buildup are recommended to ensure the well integrity of subsea HPHT wells. The research in this paper provides the reasonable calculation approach and mitigation measures of annular pressure buildup.
Novel Drilling Fluids Enable Record High-Temperature, Deep-Gas Exploration Well Offshore Peninsula of Malaysia
Authors: Witthayapanyanon A. , Nasrudin K. A. , Wahid F. , Pepple M. M. , Abshar M. , Dollah A. B. , Chandramouleeswaran K. , Kongsawast A. , Bland R. G. , Clapper D. K. 
Published: August 2014

Abstract
Increased global energy demand has forced the oil and gas industry to search for hydrocarbons in increasingly challenging locations such as high temperature, high pressure (HTHP) reservoirs. This paper presents the field performance of a new fit-for-purpose synthetic-based mud (SBM) used to drill an ultra-HTHP deep gas exploration well offshore Malaysia. The well was drilled to a total depth (TD) of 14, 380 ft (4, 383 m) and reached the highest recorded bottomhole temperature (BHT) of 488°F (253°C) in Southeast Asia. To overcome the anticipated drilling challenges in the extreme environments, the operator and service company collaborated to identify a thermally stable, high-density drilling fluid that met the operator's needs. The drilling fluid was formulated for a maximum density of 18 lb per gallon (ppg), but reached the Southeast Asia record of 19.1 ppg mud weight at TD. The use of dual weighting materials (barite and manganese tetraoxide) yielded lower plastic viscosity (PV) for the high-density mud, leading to improved hydraulics and lower equivalent circulating density (ECD). The drilling fluid encompassed excellent temperature stability with no weighting agent sag and no high-temperature gelation observed after remaining static for five days at BHT during wireline logging. In this respect, it eliminated the rig time spent for additional circulating or conditioning of drilling muds and fluid treatment cost. Moreover, the fluid also provided good wellbore stability with no non-productive time (NPT) from drilling fluid performance. Comparison of field data and laboratory results highlighted the benefits of competent drilling fluid design and testing. As a result of thorough planning and comprehensive laboratory testing, desirable drilling fluid properties were maintained despite extreme HTHP conditions, minimizing trips and operational costs.
First Conformance System to Fix Leaking Downhole Packer and Enhance Hydrocarbon Production in Gulf of Thailand
Authors: Wattanasuwankorn Reawat , Limniyakul Vorasak , Dunlop Tyson , Chayraksa Wichanee 
Published: August 2014

Abstract
Well pressure integrity is a primary concern during offshore operations. Without proper control, barriers can significantly impact safety and production activities. Once a well barrier is unable to deliver pressure control, correcting the pressure integrity problem as quickly as possible becomes a priority. This paper describes a case where, in a conventional gas lifting oil well, a downhole packer leaked during production and significantly reduced hydrocarbon production.
A conformance system was introduced to a Gulf of Thailand operator. The conformance system's rigid setting fluids are a new generation solution for plugging or temporarily isolating specific zones. The system was engineered to help ensure conformance would set at the right angle and temperature under specific well conditions. High-pressure resistance, low solution viscosity, and zero shrinkage are advantages of using the system to recover well pressure barriers.
The conformance operation was performed using an electric line (e-line) punched target below the downhole packer inside production tubing to help establish conformance injectivity. Once the rate was confirmed, the conformance solution was squeezed to target the zone using coiled tubing (CT). CT was an important component of the solution necessary for cleaning as thoroughly as possible. Conformance pressure was confirmed under controlled conditions. The design only allowed a few hours for the solution to build up compressive strength, so a pressure test was performed from the "A" annulus, and the well could hold 1,500 psi.
The recovery of well pressure integrity successfully addressed the well control issue for the entire life of the well and restored hydrocarbon production from an inability to produce to production of 200 B/D. Using this system, a workover of the rig was not necessary to recomplete the well by replacing the downhole packer and risking hydrocarbon exposure during workover operations. This conformance solution was ideal for correcting the packer leaking problem.
Openhole Tractor and High-Tension Conveyance Package Reduces HSE Risk and Saves 3 Days of Rig Time for Formation Fluid Sampling in a Highly Deviated Well
Authors: Akue Michel , Delaval Fabien , Crevoisier Lois De , Hermes Amir , Tchieji Yves , Sarian Serko , Bozzolan Philippe , Reid Martin , Andrew Mike , Bahmudov Kamil 
Published: August 2014

Abstract
To better understand their reservoir in a highly deviated offshore well, the operator required advanced measurements in an appraisal well over and above those normally recorded with basic LWD measurements. The data required to better characterize the reservoir were electrical image logs, dipole shear sonic imaging, high-resolution magnetic resonance measurements, and formation pressure tests as well as pressure/volume/temperature (PVT) fluid samples, all to be collected in oil-base mud. The Operator and Service Company were looking for efficient alternatives to a pipe-conveyed logging operation.
After a thorough study of well details, modelling of required tractor force, and close collaboration between the operational teams of both the operator and service company, it was determined that a conveyance system including the latest generation all-terrain tractor and high-strength cable would be suitable for this operation. Compared to running on drillpipe, tractor conveyance offered benefits for this operation in terms of rig time, flexibility, and safety. The 50-m and 4,513 lbm fluid sampling toolstring used for the operation included six pairs of tractor drives, all required logging equipment, and an electronically controlled weakpoint deployed with an 18,000 lbf high-tension conveyance package.
Petrophysical measurements as well as downhole formation testing and sampling were all achieved successfully using the all-terrain tractor conveyance in four logging runs, with a total tractored distance of 6,800 m in a formation with unconfined compressive strength ranging from below 5,000 psi to as low as 600 psi. The data and samples were acquired in five logging runs across the entire reservoir interval with a maximum tension of 10,500 lbf. The total operational time of 70 hr represented a time saving of approximately 72 hr compared to a pipe-conveyed operation with the same logging equipment in this setting. Successful deployment of this tractor technology offers alternatives to operators in the region for formation evaluation.
Arachnophobia: A Case on Impairment and Accounting Ethics
Authors: Persellin Julie S. , Shaub Michael K. , Wilkins Michael S. 
Published: August 2014

ABSTRACT
This case requires students to apply accounting and ethical decision making within the context of a potential land impairment decision. Students are required to research the relevant professional literature and provide appropriate FASB codification references and IAS cites as they investigate the significant uncertainties that frequently are associated with valuation and impairment analyses. Students also are required to evaluate the ethical implications of the decisions that could be made regarding the necessity of impairment. The case provides an opportunity for students to extend their research and financial accounting abilities, to consider the consequences associated with a set of potentially reasonable accounting alternatives, and to begin to appreciate how the significant uncertainties that are present in many accounting and auditing situations require consistent technical and ethical decision making. The case could be used in Intermediate Accounting I, as well as in undergraduate and graduate Auditing or Ethics classes.