bluuebunny/crossref_metadata_2025_split huggingface dataset:
LEOPARD (Panthera pardus L.) IN PURWODADI, TEPUS, GUNUNGKIDUL, YOGYAKARTA, INDONESIA
Authors: Atmaja Edi Dwi , Dwisetiyani Budi 
Published: September 2015

<p>Indonesia is a beautiful archipelago country. It has many habitat type and ecosystem. The most interesting area is karst. By its special characteristics like high concentration of calcium (Ca), makes karst area has a specific and uniquely ecosystem. Gunungsewu is the largest karst area in Indonesia. The surface ecosystem of karst (eksokarst) in Indonesia is very dry, however we can find Leopard (Panthera pardus L), especially in Southern part of Karst Gunungsewu. That is why we are interested to study about it. In this study, we use observation and interview method. From the temporally result (research still on progress), we know that in Purwodadi, Tepus area live two sub-species of Leopards, those are Spotted Leopard (Panthera pardus pardus) and Javanese Black Leopard (Panthera pardus melas) with porcupine (Hystrix javanica), squirrel (Caloscurus notatus), Mongoose (Paradoxurus hermaphroditus), and other small mammals and some birds as their prey. In some cases, we find Leopard eats the dead human body but they rarely eat cattle although it takes in the middle of the farms. The habitat of Leopard was fragmented. Now they only life in five fragmented part of karst Gunungsewu and their habitat degrade slowly from year to year. From the results, we can conclude that conservation in Karst of Gunungsewu especially in Purwodadi, Tepus, Gunungkidul is badly needed. It must be done soon because Leopard becomes extinct. We can use local wisdom to conserve it because it has proven can make a good interaction between human and Leopards in their habitat. </p><p><strong>Keyword</strong>: predator, tropical, karst, Gunungsewu</p><p> </p>
Helicopter Load/Unload Operation Safety on Offshore Platform
Authors: Yonebayashi Hideharu , Collins Tim 
Published: September 2015

Abstract
On offshore oil/gas platforms that have no crane equipment, when a slick-line and/or an electrical wire-line job is required, helicopter load/unload operation is a common method for transporting materials such as winch units, power pack units, BOP units, lubricators, etc., from platform or offshore complex to the platform. A series of materials are separately transported by helicopter so that one lifted material can be within the helicopter maximum loading capacity. A package of transportation typically consists of 4-5 load/unload operations for a whole set of materials. Those frequent load/unload operations are done with a hovering action that has the highest risk among a series of helicopter actions (i.e. taking-off, cruising, and approach/landing). To achieve safety, all risk-mitigating factors are adequately incorporated into a plan that should be shared with all crews (pilot, company supervisor, slick-line/wire-line operators) in advance of the operation. In addition to summarizing general safety tips, this paper discusses mitigations from various point of views. As a result of considering ground crew's psychological response based on actual field experience, this paper recommends how to remove these mental factors that silently act on a helicopter marshaller's action. Moreover, fundamental measures are recommended to update marshalling methods and to use new generation helicopters that are designed for improved safety requirements.
Root Cause Analysis Solves Inoperability Problem with Downhole Flow Control Valves
Authors: Agarwal R. , Galiunas M. , Barrilleaux M. , Stewart C. , Burns M. 
Published: September 2015

Abstract
Eight downhole flow control (DHFC) valves were installed between 2007 and 2012, two in each of four deepwater wells in the Gulf of Mexico (GoM) by BP. Five of the eight valves failed to function correctly when the wells were subsequently commissioned within two to six month after installation. After the first three failures, down hole filters were implemented in the hydraulic control lines as a part of mitigations and remedial actions. The changes appeared to have solved the problem—until two further failures occurred in 2012. This paper presents the physics-of-failure (PoF) based root cause analysis (RCA) conducted to investigate the causes of the last two valve failures. Key elements of the investigation process are highlighted. These key elements can help to make any investigation efficient, effective, informed and objective. The investigation showed that even when a failed part is not available for failure analysis, symptoms of the failure can be used to identify the failed part(s).
The final two failed valves were in a single well that had been tested operable at the time of installation and shut in with completion brine in the tubing. Two months later, during commissioning of the wells, the valve sleeves failed to shift. Based on an examination of the few recoverable parts from the inoperable flow control systems and a careful review of the fluids to which they were exposed, the failure mechanism for the DHFC valves was identified as deposition of corrosion products on the sleeve that interfered with its sliding. The sleeves with surfaces hardened using quench-polish-quench (QPQ) nitriding process of 13% Chromium (13Cr) stainless steel corroded upon exposure to completion brine with trace oxygen and hydrocarbons with dissolved carbon dioxide from the pay zone.
The performance of DHFC valves with QPQ-nitrided 13Cr surfaces in deepwater wells can now be explained in light of the identified failure mechanism. Wells that were produced shortly after completion had operable DHFC valves since the produced hydrocarbon fluids were not sufficiently corrosive to attack the QPQ-nitrided 13Cr. However, wells which were not produced for at least two months after well completion had failed DHFC valves, since the completion brine along with hydrocarbons had sufficient time to corrode and impair the valves function.
Ten DHFC valves made from Inconel 718 have subsequently been installed, two each in five deepwater wells, and all ten have functioned satisfactorily. The recurrence of a similar incident has been systematically prevented. Further, use of QPQ-nitrided 13Cr equipment on other downhole applications has been reviewed for suitability.
Case History: First Lower Tertiary Multi-Zone Single-Trip Intelligent Completion in an Ultra-Deepwater Development
Authors: Joseph Kevin 
Published: September 2015

Abstract
Multi-zone single-trip (MST) technology is a completion method to perform sequential sand-control treatments to multiple zones in one trip down-hole. The primary advantage of the method is the operational efficiency and resultant cost-savings. The paper presents the challenges surrounding the latest one of five Gulf of Mexico wells installations in an Ultra-Deepwater project, describes the systems used and presents their key factors of success. For the first time, an intelligent well completion was successfully installed together with the MST system, further improving the producing capabilities to collect reservoir information and to manage fluid production.
The paper also discusses the technological advantages of the MST completion method, key lessons learned to date and the major success factors in the project specific to the completion operations. The paper is structured around well integrity, operational efficiency and completion excellence. Well integrity is accomplished by ensuring that completion components conform to the extreme downhole well conditions, maintain well control; and keep zone isolation during high-pressure frac-pack treatments. Operational efficiency was attained by clear guidelines, right personnel involvement, identifying and eliminating any possible operational risk. Completion excellence was achieved by system built-in redundancy features for flawless executions and software modeling to simulate downhole conditions from installation through production phases. The intelligent completions capability and the value added to the system are also presented.
Screen Erosion Guidelines for Sand Control Completion and Sand Production Management. Case Study West Delta Deep Marine (WDDM) Offshore Egypt
Authors: Mahmoud H. S. , Ali A. M. , Abdel Sayed A. A. , Zalam E. 
Published: September 2015

Abstract
The West Delta Deep Marine (WDDM) fields are a Pliocene gas fields located in offshore Nile Delta, approximately 120km North-East of Alexandria, Egypt. These fields are comprised of sandstone reservoirs which are dominated by unconsolidated sandstone.
Sand production has become one of the main issues in WDDM since the discovery of a hole in the body of a liquid outlet valve from the onshore slug catcher. On further inspection, it was discovered that the hole had developed due to the presence of sand/fines causing erosion at the interface in the liquid handling system. Scarab-Saffron field was the primary source of sand production in WDDM with screen failure as the cause of the problem.
This paper details a method for determining maximum safe production rates for sand control wells. This method was developed from a thorough compilation of data from around 51 sand control wells. As a result of this analysis, a simple function of screen erosion limit has proved to be very reliable at identifying wells operating safely from those resulting in damaged screens or unacceptable amounts of produced sand.
Minimum Facility Platform for Sub-Commercial Reservoirs in the Gulf of Thailand
Authors: Chanwith B. , Pheerasak P. , Thitinun S. , Natthawadi L. , Tanadcha T. , Taweepong M. , Yossaran P. , Wanvisa S. , Suchada P. , Pongpat H. , Ratchada L. , Supamittra D. , Vuthiphon T. , Warakorn K. , Wiwit S. , Penporn S. , Choosak K. , Saran U. 
Published: September 2015

Abstract
According to PTTEP reservoir data for the Gulf of Thailand, some of its prospects contain small amounts of reserves that cannot be developed commercially based on the current Conventional Wellhead Platform (CWP) design. In order to profit from these sub-commercial gas reservoirs, a Minimum Facility Platform (MFP) with lean facilities and optimum size must be selected to ensure worthwhile preliminary economic results in such marginal reservoir production. Compared to employing a conventional wellhead platform, in this case, a project team has to achieve a target cost saving of approximately 20% more than would be gained from use of a conventional design. Regarding projecting a production profile, the MFP should be installed in early 2017.
This MFP is to be designed for 5 years of production life. Maximum production capacities are 40 MMSCFD gas, 1,400 BOPD and 2,000 BWPD. The production is for sour service with a maximum export of 50% CO2 and 50 ppmv of H2S
The following are featured as new characteristics of the MFP design: Reduced number of wellhead slots from 16 to 9-15Commingled flow lines to reduce the number of actuated on-off valvesCombined and integrated functions of test separator to booster compressor packageUse of 100% solar power with battery backup and removal of Thermal Electric Generator (TEG)Reduced export pipeline size from 12”/16” to 10”/12”Reduction of overall deck area by 20%, resulting in wellhead platform structural weight reductionOptimized material selection and corrosion inhibitor systemOptimized equipment specification to align with manufacturer's standardRemoval of closed drain system, drainage to be handled by export gas pressurization
With the development governed by the MFP concept, 24% of the sub-commercial field volumes could be potentially recovered to support the added sustainability of the energy supply in Thailand. In other words, these previously sub-commercial prospects could be re-evaluated and re-integrated into new field development plans. Furthermore, the MFP could replace future Conventional Wellhead Platforms for the further improvement of the overall NPV project.
Human Factors Risk Programs Implementation at Drilling Material Dispatch Unit and Well Equipment Repair Workshop
Authors: Al-Dhamen Fahad , Gopaul Garry , Al-Shatti Ahmad , Al-Khaldy Ali 
Published: September 2015

Abstract
This paper looks at two operations vital to the Drilling Operations at Kuwait Oil Company (KOC) –the Drilling Material Dispatch Unit and Well Equipment Repair Workshop. Both support the entire Drilling and Work-over Program in Kuwait Oil Company (KOC), and significantly affect not only the daily oil production but also future projected growth objectives.
It examines in depth the various human factors categories -individual, job and organizational factors that adversely affect HSE performance in these operations, and looks at solutions to these unique problems. The paper is unique in its approach, in that it offers a practical insight into the many human factors challenges, some which require long term solutions, that have emerged in a highly growth oriented E&P environment.

Applications
The paper compares the human factors identified in these areas, to industry recognized “Performance Influencing Factors”. These are factors that adversely affect human performance and increase the likelihood of accidents, and illustrates that human factors is a common issue faced by others in the industry. Control Measures to reduce risks due to human factors are presented, which will be useful for implementation in many similar operations supporting the drilling function or maintenance workshop type environment.

Results & Conclusions
Mismatches between job requirements and people's capabilities provide potential for human error and accidents. This is particularly important when dealing with the issues of unskilled labor combined with workforce literacy challenges in an industrial setting.
Physical match includes the design of the workplace and the working environment, while mental match includes perception of tasks and risks. Both physical and mental matches must be considered in one's specific work environment, through risk assessments and subsequent implementation of control measures.

Significance of subject matter
Successful human factors integration can bring benefits not only to Health, Safety & Environment (HSE) performance, but also to productivity in companies, by proactively identifying and rectifying human performance issues related to the organization, job and the individual.
Proving the Concept of Unconventional Gas Reservoirs in Saudi Through Multistage Fractured Horizontal Wells
Authors: Al-Momin Ali , Kurdi Mohammed , Baki Sohrat , Mechkak Karim , Al-Saihati Ali 
Published: September 2015

Abstract
Saudi Arabia has embarked on an exploration journey for its unconventional gas resources by recently targeting three different areas across the Kingdom. The targeted formations include tight sandstone, shale and tight carbonate with a permeability range of 200 nano-darcy to 0.1 MD. Extensive exploratory work has been performed in each of the areas through drilling vertical wells to identify and characterize potential targets through coring and open-hole logging along with flow potential testing of those targets after placing vertical fractures, which is beyond the scope of this paper. This paper highlights the progress of the unconventional program through drilling horizontal mono-bore wells and stimulating them with multistage fracturing using Plug-N-Perf technique. Three case studies, one from each targeted formations, are presented in this paper. The subjects addressed are: Well completion including the selection of tubing and liner sizes, metallurgy and grades along with performing stress and thermal analysis simulating the expected loads during proppant fracturing to determine the maximum safe loads at each stage.Proppant fracturing design including the number of stages and clusters, the spacing of stages, proppant type, size and volume, and fracturing fluid systems. The design is based upon the geomechanical and petrophysical interpretations of the openhole logs together with onsite calibrations and measurements.Plug-N-Perf and fracture stimulation operations and executionFracture fluid clean up and flow testing
The paper summarizes the workflow adopted, the lessons learned and challenges overcome after drilling, completing, fracturing and flow testing of several unconventional gas wells in Saudi Arabia.
Drilling Through Layers of Unstable Shale Formations and Depleted Sand Sequences, the Managed Pressure Drilling / Wellbore Strengthening Approach to Successfully Drill Offshore Development Wells. A Case History
Authors: Henry I. , Hernandez J. , Ngan A. , Arnone M. , Boutalbi S. , Lagrandeur C. 
Published: September 2015

Abstract
Two hole sections (12-1/4″ × 14-3/4″ and 10-5/8″ × 12-1/4″) were planned to be drilled through sequences of unstable shale and depleted sand packages with no drilling windows, which are defined by the shale Wellbore Stability Gradient (WBSG) delimited by the “intact wellbore wall zero failure degree” and the depleted sand fracture gradient criteria. Historically, significant non-productive time (NPT) associated with wellbore instability and lost circulation had resulted in sidetracks and other costly remediation in both hole sections. The operator and the service provider have identified the Constant Bottomhole Pressure (CBHP) variant of Managed Pressure Drilling (MPD) and wellbore strengthening as the necessary technology approach to safely drill through both challenging hole sections. Dynamic and static wellbore strengthening were applied to increase the near wellbore stresses across the depleted sands to create a drilling window, whilst the MPD CBHP was used to mitigate bottom hole pressure fluctuations and cyclic stress across the shale packages.
The MPD well evaluated in this paper had just four hours of non-productive time related with downhole problems and wellbore stability, a minimal fraction when compared to the 980 hours lost in the previous conventional offset well. The MPD well did not require any back reaming operation, whereas the offset well in the area required 7 back-reaming events to get a good quality wellbore. A total of 533 hours were required to drill the 2 hole sections in MPD compared to the 2,410 hours required to drill the same sections conventionally in a previous offset well in the area.
This paper summarizes the key MPD planning, engineering, results obtained and lessons learned that delivered a successful campaign of producer wells.
Tractor-Conveyed Magnetic Fishing in an Extended-Reach Lateral Completion
Authors: McMullen Chris , Hathaway W. Ephraim 
Published: September 2015

Abstract
As operators in the Appalachia basin explore the Utica formation that underlies the previously-developed Marcellus shale, economic and environmental drivers have pushed drilling rigs to their limits in delivering wells that are both deeper and have longer lateral sections. These extended-reach lateral wells, with total measured depths (TMD) exceeding 18,000 ft, impose new completions challenges stemming from technical limits and the utilization of new technologies. This paper will demonstrate the need to adapt while dealing with new constraints. Specifically, this paper will report on the successful use of e-line, a tractor, and a magnet to retrieve a fish from plug-and-perf operations in an extended-reach lateral.
One major challenge in performing a plug-and-perf completion on the extended-reach lateral in this case study was that the toe of the well extended further than could be cost-effectively cleaned out with a service rig or coiled tubing. Therefore, large-bore cast iron permanent frac plugs, which are designed to be produced through, were used to isolate frac stages in the toe. Before pumping a subsequent stage, a dissolvable ball was seated on the plug to isolate the previously fractured stages.
While plugging and perforating, the wireline adapter kit of the plug setting tool backed off the toolstring, creating a fish above the plug. It was unclear if the adapter kit was still whole or had broken into multiple components. The challenge in recovering the fish was that if it had disassembled, smaller components of the assembly could potentially slip through the bore of the recently set plug. If this occurred, the plug would need to be milled before a fishing attempt could be made. Therefore, it was concluded that the fishing tools needed to be able to delicately engage the fish but still achieve a sufficient bite to hold the fish as it was dragged up the lateral. An overshot tool conveyed on coiled tubing was deemed too aggressive. Similarly, pumping down a wireline fishing tool was dismissed as the force from the pump down could potentially push the fish through the bore of the frac plug. Therefore, the decision was made to tractor-convey a rare earth magnet on e-line. This method successfully retrieved the fish on its first run, saving at least 3 days compared to the next-best recovery method.
This paper will detail the planning and execution of this fishing operation in order to provide insights for planning other extended-reach lateral completions. Specifically, this paper will show that existing technologies can be employed to overcome the challenges associated with fishing in extended-reach laterals.
Implementation of Drilling Systems Automation - Halifax Workshop Summary: Industry Standards, Business Models and Next Steps
Authors: Florence Fred , Chapman Clinton , Macpherson John , Cavanaugh Martin 
Published: September 2015

Abstract
The SPE Drilling Systems Automation Technical Section (DSATS) is a committee tasked with supporting the growth and implementation of drilling automation. In September 2014, DSATS held a dual-stream workshop in Halifax, NS, Canada with focus on both the technical and business issues relating to implementation of this new technology. The workshop identified key business issues, both blockers and enablers and, for the first time, proposed a step towards a potential industry technical guideline that allows the machines and models used in drilling to communicate in real time. Workshop participants identified future actions that will continue to advance the development of drilling automation. This paper summarizes both the topics presented and the actions identified as necessary to advance the implementation of drilling systems automation.
The workshop used two parallel tracks: a technical track dealing with the communications technology needed for drilling systems automation, and a business track focused on technology implementation issues. This novel format spurred a crosspollination of ideas since attendees were free to attend either track and switch between tracks during the conference, thereby contributing to topics of interest.
The technical track included work to define a common interface for equipment control based on the OPC-UA communications protocol and a rig information model, or data dictionary, which is necessary for modeling the process of drilling a stand using normal drilling machinery. The business track examined issues surrounding the use of large data sets, sensors and problems encountered when using them, reliably, in real time. Participants discussed their concerns with existing drilling contracts which do not always cover the legal responsibilities of all parties involved in the construction of a well using an automatic drilling system.
The workshop developed a rig information model as a guideline for data communications in the automation of drilling a stand. This model will be the basis for developing an open standard that all interested parties can use in creating drilling automation products. Additionally, the workshop initiated the work on transferring drilling automation technology into the open business arena. DSATS working groups and future planned workshops will further explore critical topics, such as data quality, modeling, and simulation.