bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Lithology Determination from Nuclear Logs in Complex Carbonate Environments
Authors: MacDonald Robin , Bradford Charles , Kersey David G. , Zhang Tianhua , Alsuhaibani Assim , Crary Steve 
Published: February 2010

Abstract
A multiwell study integrating mineralogy from core samples’ X-ray diffraction (XRD), standard openhole logs, and capture spectroscopy logging measurements was undertaken to understand differences between the log and core seen predominantly in anhydrite intervals. Determination of accurate lithology is important in oil and gas reservoirs because mineralogy affects the accurate determination of porosity, producibility, and reserve estimates.
The formation consists of calcite (limestone), dolomite, and anhydrite, which are common in many carbonate reservoirs around the world. Small amounts of pyrite, other sulfides, clay, and quartz are also found. Analysis of this complex mineralogy is further hampered by environmental complications that include high borehole and formation temperatures and heavy barite-weighted mud, which results in the photoelectric factor (PEF) not being a reliable measurement.
In this case study, a positive bias in the log-derived anhydrite volume was observed in tighter, nonproductive carbonate sections. As the anhydrite volume is determined directly from the capture spectroscopy sulphur measurement, this bias suggested a potential problem with the measurement. As the bias was small (0 to 3 weight percent) and the anhydrite distribution in the rock is very heterogeneous, the determination of the cause of this apparent problem was difficult.
A number of different potential causes of the bias were reviewed to determine if they adversely affected log-derived lithology. Capture spectroscopy data acquired at faster logging speeds demonstrated the bias at small volumes of anhydrite; the bias disappeared in zones with significant amounts of anhydrite. In addition, mineralogy and elemental analysis from veneer slabs improved the quantification of the sulphur and consequently, the anhydrite content of the formation, enabling accurate determination of anhydrite volumes, even in the heterogeneous sections. Proper averaging techniques of the core data with log data also verified the sulphur bias at low anhydrite levels. The results of this study confirmed that the apparent sulphur bias was the result of statistical precision. Improvements to the log data require slower logging speeds, modifications to data acquisition, processing, and better wellsite log quality control.
Barge Mounted Coil Tubing - An Operational Safety Case Study in South China Sea
Authors: Hairi M Hairi , Yusoff Afendy , Wibisono Rahmat 
Published: February 2010

Abstract
Petronas Carigali Sdn Bhd (PCSB) is one of major oil and gas companies in South East Asia. It has had years of experience operating coil tubing unit (CTU) on relatively large oil and gas field platforms. Vast of field experience and project lessons learned have been captured, refined and eventually embedded in the company’s CTU standard operating procedures. These have lead to zero lost-time incidents (LTIs) cases in 5 years of CTU operations particularly offshore Terengganu in South China Sea. The CTU operations are often complex and involve heavy lifting, weighty machineries, minimal deck space and long working hours. Hence, to achieve such a record through out the 12 months in a year with 2 units running concurrently is definitely something to be noted.
In February 2009, PCSB embarked on it first barge mounted CTU operation at offshore Terengganu. The option was choosen to access marginal field with small platform deck space and limited crane capacities. These include the process of lifting heavy equipment from workbarge with 60 degree angle to a 50 ft high platform during high swell, having to mobilize crews back and fourth from workbarge to platform and rigging up in dynamic condition. Furthermore, it was the first time the work barge crews experienced such operation and communication constraints due to remote and weather conditions further complicated the situation.
Knowing that field experience is almost zero for mounted barge CTU operations in PCSB fields, resources and time has been put to ensure that the HSE track record is intact. Starting with Project Risk Assessment (PRA) which involved all contractors and field operator personnel, the team then analyzed of the whole campaign chain. This paper will review PCSB project success experiences and lesson learns on how to do CT operation from Barge within small platform during moonson season with high level of safety.
Water Management and Production Enhancement: Case Studies of Greater Munga Field, Sudan
Authors: Bahuguna Ajay , Elbadri Mohd , Vazquez Alvarez Maria Leticia , Shaheen Tarek , Ahmed R. 
Published: February 2010

Abstract
Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that have commingle production from the Aradeiba, Bentiu-1 and Bentiu-2 formations. These formations are highly variable in terms of the reservoir properties, oil types and pressure regimes. Because of the contrast properties of different layers, the water cut phenomenon is relatively fast and severe which hampers the productivity and ultimate recovery of the individual well as well as the field.
For effective Reservoir Management and to limit the declining trend of the field, Water Management Techniques are applied in some of the wells of this field. Information obtained in the process was used for reservoir model calibration, well productivity prediction, low productivity diagnosis, and generation of new drainage points and remedial action for water management.
This paper discusses the technical details of three cases corresponding to the wells Munga-XX and Umm Sagura South-XX (USS-XX) and Munga-XY in which, a multidisciplinary approach has been implemented in order to determine depletion profile, produced oil and remaining reserves, locate any "by-passed" oil zones, determine oil and water contributions from each zone and shut off the excess water production while maintaining or increasing oil production.
The source of water entry was identified in multi-rate production logging using Production Services Platform and electrical probes through Y tool-ESP completion. Vx meter was carried out at surface to real time monitoring the well production during the production logging survey. The well depletion profile was determined using Cased Hole Formation Resistivity (CHFR*) tool. A multidisciplinary team processed and interpreted the logging data and based on the results remedial jobs were carried out
The general outcome of the remedial jobs based on this approach was a considerable reduction in water production in both Munga-XX and USS-XX wells as well as oil production gain, making this a successful job.
Lessons Learned from Drilling Horizontal Wells on Didon Field; Offshore Tunisia
Authors: Jardine P.. , Chaaouri M , Guyard A , Di Pasquale M.. 
Published: February 2010

Abstract
The Didon field is located offshore Tunisia in the Pelagian Basin. It was discovered in 1976, and first production began in 1998. Following a decline in production from initial development wells, the latest phase of development drilling began upon commissioning of the production platform in 2006. Horizontal wells drilled in this latest development phase have resulted in production benefits. To date, six horizontal wells have been drilled on the field using various drilling techniques to optimize drilling efficiency and wellbore placement. Using wells drilled to date, this paper outlines the challenges involved in developing the Didon field. It describes lessons learned from application of the different drilling technologies together with the value of pre-well geological modelling and real-time geosteering techniques.
Developing and Helming Competent Engineers in Production Operations, Peninsular Malaysia Operations, PETRONAS Carigali Sdn Bhd
Authors: Hadi Sriyanta , Osman Azmee 
Published: February 2010

Abstract
Peninsular Malaysia Operations (PMO) is one of three domestic regions of PETRONAS Carigali Sendirian Berhad (PCSB) located in offshore of Peninsular Malaysia. The operations cover six of main operation areas namely PPD-D, PPD-F, PPD-L, PPD-P, PPD-S and PPD-T. Those operation areas have a wide operation ranges: from green to brown fields, from single to multiple products, from onshore terminal to offshore Floating Storage and Offloading (FSO) and Floating Production Storage and Offloading (FPSO), from heavy crude to light crude and from big to small fields. PPD-D area is gas producer; PPD-F, PPD-L, PPD-P and PPD-S areas are crude and gas producers while PPD-T area is onshore crude and gas terminals. PPD-F area is scatter small fields facilitated with one unit of FPSO and one unit of FSO; PPD-L area is a big oil field facilitated with water alternating gas (WAG) injection facilities, gas lift infrastructure and one unit of FSO; PPD-P area is scatter medium to small brown oil and gas fields facilitated with processing plant, water injection facilities, gas compression, gas lift infrastructures, crude pipeline and gas pipeline and PPD-S areas is a big oil and gas fields, facilitated with integrated gas and oil processing plant, water injection facilities, gas lift infrastructure, crude pipeline and gas pipeline. In some oil fields, water injection is applied for reservoir pressure maintenance while water flooding and Enhanced Oil Recovery (EOR) technologies are implemented to maximize oil recovery. Some fields are still producing naturally while in most brown fields, gas lift is suitable to assist the crude production. Production operations comprises of three functions: production planning, field production operations and production logistics. The main scope is crude and gas production and evacuation from the well up to the terminal or exporting point. As the think tank in production operations, production planning consists of three functions: production analyst, field and integrated production planning and hydrocarbon accounting and allocation. In day to day works, production planning is focusing on crude and gas production achievement. Field production operation as the heart of production operations, handles day to day offshore routine activities, process performance improvement, process plant upgrade and new production facility installation. Considering the importance and urgency of capability building, production operations has taken significant measures in developing and helming competent engineers in order to achieve and maintain excellent production operations as well as to sustain technical talent development. Analysis presented in this paper describes important keys in competency development; they are 1) capability mapping, 2) skill development process and 3) measurement and feedback.
Brownfield Facilities Upgrading for ESPs
Authors: Salim Muzahidin M , Saenz Dan , Pattay Patrick , Symic Ryan , Anang Nazaruddin 
Published: February 2010

Abstract
Electrical Submersible Pumps (ESP) are commonly employed in brownfield wells where watercut has increased and gas lift is no longer an efficient production strategy. Much attention is rightly paid to the impact this strategy will have on the reservoir and careful planning is given to the workover operation. However, often the challenge of implementing ESPs is not below the wellhead, but at the facilities level.
One such example is the Bokor Field offshore Sarawak where, in 2008, the first production ESPs in Malaysia were installed. Initially, an in-depth power study was performed. A holistic plan was then developed to distribute the available power to the ESPs via the existing electrical infrastructure. Various locations were considered for the placement of ESP control equipment and ultimately the project team chose a location near to the wellheads. This choice of location required less structural re-design but did involve laying a subsea cable for power transmission and consideration of IP Area Classification Codes for Installations Handling Flammable Fluids.
The ESP power and control equipment was installed inside a customized Local Electrical Room (LER) and, because of space constraints, small deck extensions were required. Safety systems such as fire and gas detectors and individual well sensors for downhole status and flowline pressure monitoring were also included. The electrical systems were tied into the wellhead control panel to allow for automatic process and emergency shutdown actuation. Finally, the surveillance system needed upgrading to incorporate these sensors and allow remote operation since the object platforms were to remain unmanned.
For the Bokor field, the preparation of facilities for ESPs ultimately became its own project much larger and more complex than the workovers themselves. A field designed for gas lift with minimal power needs was successfully transformed to increase and efficiently distribute power along with allowing safe, remote pump operation and surveillance.
Advanced Horizontal Well Model
Authors: Kuznetsov D. S. , Cheremisin A. N. , Chesnokov A. A. , Golovin S. V. 
Published: February 2010

Abstract
A new semi-analytical model developed allows making fast modeling of the heterogeneous reservoirs, drained by a single horizontal well with multiple transverse hydraulic fractures. It is assumed that: –the flow in the reservoir obeys Darcy law;–the fluid contains only one phase;–the reservoir permeability tensor is a function of the variable, directed along the horizontal wellbore;–the well trajectory is not a straight line;–the wellbore has finite conductivity
The proposed model is fast in terms of the execution time and the time required to build a new case.
In the first section of this article a description of the solution method is given.
The second part is dedicated to validating the proposed model. The recognized finite-difference hydrodynamic simulator (FDS) was used as reference software, though fhe model and FDS are not competitors because of their differing applicability. For this reason the execution times of the FDS and the Advanced Horizontal Well (AHW) model are not compared with one another. More significant is that using this model one can generate a new case in fifteen minutes even when the properties of the reservoir are complex and when there are multiple fractures.
The primary focus of the AHW model is a single well productivity index analysis, and candidate selection for stimulation.
Hydraulic Fracturing Makes the Difference: New Life for Old Fields
Authors: Martin A. N. , Rylance M.. 
Published: February 2010

AbstractAn increasing percentage of worldwide hydrocarbon production is being achieved from mature fields, as new discoveries prove elusive and technically challenging to bring to market. In this environment, robust and efficient enhanced recovery from these mature assets will play an increasingly important role in production operations. Often used as an initial completion approach or selective remedial stimulation method, hydraulic fracturing is increasingly applied as the method of choice to bolster and improve such declining fields to restore and maintain higher production levels.Hydraulic fracturing is finding increasing application as a widespread approach to mature field redevelopment. This paper will explore the various factors that should be considered when proposing hydraulic fracturing for this purpose, given the very specific nature and condition of mature fields.Techniques that can be applied to determine various aspects of mature field fracturing operations will be discussed, together with approaches related to all areas of fracturing implementation; this will provide the reader with an ability to perform a first-pass assessment of the pros and cons of various approaches. In addition, there will be significant discussion related to the potential pitfalls associated with ill-prepared and inappropriate campaigns.Case histories will provided examples of mature field redevelopment utilising hydraulic fracturing as the principal approach. Candidate selection and pre- and post-frac production behaviour will be discussed, together with the lessons learned and improvements realised during the execution of these programmes.
North Africa Case Histories of a New Wireline Logging Method for Determination of Free Point to Assist Pipe Recovery Operations
Authors: Kessler Calvin , Weiser Jerry , Hill Jim 
Published: February 2010

Abstract
The identification of the free point in drill collars, drillpipe, tubing, or casing is critical for successful drilling recovery or abandonment operations. A new logging tool, available in the wireline service sector, has been developed and field tested that will help to cost-effectively identify a free point. The tool uses the property of steel called the magnetostrictive effect. When stress is applied to steel, the magnetization of the steel is modified. The procedure using the new tool requires two logging passes. The first logging pass records magnetization information about the pipe with the pipe in a neutral weight condition. The second logging pass records magnetization information with tension or torque applied to the pipe. When torque or tension is applied to pipe that can be stretched or torqued, its magnetostrictive properties change. If a section of the pipe cannot be stretched or torqued, magnetization effects remain unchanged. On this basis, the free point (the transition from pipe that can be stretched or torqued to pipe that cannot) is easily detected by comparing two logging passes. Previous free point determination methods required a series of stationary measurements with the pipe in a neutral weight condition, the application of stretch or torque, and the presence of a highly skilled pipe recovery expert on location. The new method simply involves an overlay of two logging passes before and after the pipe has been stretched or torqued. The tool has been successfully tested in steel alloys with minimal magnetic properties.
This new logging tool has significant advantages. First, from a safety standpoint, the application of pipe stretch is applied for only a few minutes between logging passes, whereas legacy methods required numerous station measurements with the pipe being stretched. Secondly, because the determination of a free point requires a comparison of logging passes, real-time operations with constant satellite communications readily permits remotely-based operator and service company pipe recovery experts to be involved with plans for freeing the pipe. The new technology is independent of a highly skilled on-site pipe recovery expert and the delays associated with waiting for the expert to arrive on location.
The tool is small in diameter, run centralized, and does not require weight bars added to the tool for slip engagement. These features shorten the length of the tool string and simplify e-line rig-up procedures. The short tool length has advantages in deviated well conditions in which pump down free point tool deployment may be required.
Detailed Compositional Modeling of Gas Injection Pilot in Giant Carbonate Reservoir in the Middle East
Authors: Obeida Tawfiq , Gibson Adrian , Al-Hashemi Hussain , Baruah Bikram 
Published: February 2010

Abstract
The objective of this paper is to address the challenges that are frequently encountered in simulation studies when using local grid refine (LGR) within upscaled models. The difficulties mainly arise due to the unreliability of populating the fine grids with reservoir properties and attributes.
Dynamic modeling of a pilot is an important task to predict fluid flow and reservoir behavior which is a major step of pilot design. Dynamic models usually have many limitations when it comes to geological description due to the upscaling of fine-grid static model. Using local grid refinement (LGR) alone for the pilot area within a coarse dynamic model also would not enhance reservoir description of the pilot area without a realistic reservoir description. This work was aimed to provide an improved method for the proper simulation of pilot project in order to optimize the design of the pilot injector, borehole location and length. Furthermore, the model would be used to plan an efficient reservoir monitoring program including an optimized well data gathering with sponge coring for defining the remaining oil saturation.
To overcome these limitations, the proposed method introduces a special fine scale LGR covering the pilot area within the upscaled dynamic model. Whereas the upscaled model has 36 layers, the LGR contains exactly the same fine-scale layering scheme and reservoir properties as the static model with 160 layers. Thus, it eliminates the upscaling process within the LGR. This process will ensure a better quality history match, for example the TDTs and RSTs derived saturations when compared against the fine layer LGR from the dynamic model.
The dynamic model in this study is a large sector model (Nx 167, Ny 98 and Nz 36) with a detailed LGR (Nx 130, Ny 145 and Nz 160). The fluid properties were calculated from a 10-components equation of state (EOS). After the addition of the LGR, the model history match was updated. Several prediction cases were then studied to optimize well location (injector and observation wells) in order to convert the existing inverted five-spot gas pattern into water injection line-drive. Several saturation maps and profiles were generated to predict the breakthrough time for each observer and utilized to design the future pilot monitoring program. The new data will be utilized for future updates of the history match and performance of pilot under the optimum scheme of sweep and thus well spacing.
Embedded Knowledge-Management Systems Increase Cost Efficiency of an Organization: A Case Study
Authors: Jaripatke Omkar , McElroy Monty 
Published: February 2010

Abstract
In the global marketplace, considering the bleak outlook for the economy, successful companies must tailor their business model to continually increase efficiency for proven revenue-generating processes by reducing costs associated within operations, technology, manufacturing, and logistics. Focusing on economics can never be detrimental to health, safety, and operational-efficiency standards, which remain at the forefront for all operations. A knowledgeable and competent workforce is necessary to sustain efficient "cost-savings driven" operations. Knowledge-management systems (KMS) and concepts are tools that integrate divisions or units within a corporation effectively to achieve the business goals and shared vision of the corporation as a whole.
Much has been written on the knowledge-management (KM) concept, but most of it discusses in detail only the concept and vision. This paper discusses the KM concept model, challenges, and the successful integration and implementation of KM in a company. This includes where KM communities have been implemented in each major product-service line (PSL) of the company and in support-position job functions where knowledge workers service multiple PSLs. It discusses how the scope of the KM teams has expanded from the original intent to how the KM portals are involved in diverse projects on a daily basis to bring together different ideologies and functionalities within a company to achieve the business objectives discussed above. In addition, it discusses the future vision for KM within a large multinational service company to share and embed collaborative concepts weaved into the fabric of the company by networking people throughout the whole organization.
The book on KM within the energy industry is still being written; it is a work in progress, virtual, and the editing is ongoing.