bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Micronized Cellulose Fibers to Protect Producing Formations
Authors: Verret Robin , Robinson Buck , Cowan Jack , Fader Philip , Looney Mark 
Published: December 2007

Abstract
Micronized cellulose fibers have become widely used for seepage loss control on a worldwide basis, in almost every type of drilling fluid system. Cellulose fibers have demonstrated the unique characteristic of quickly forming a seal at the formation face preventing entrance of damaging fluids or solids into producing formations.
The use of cellulose fibers has been restricted in producing formations because of their general lack of acid solubility. However, it has been demonstrated that cellulose fibers are highly soluble in strongly alkaline solutions. These alkaline removal solutions have proven to be as effective in removing cellulose fibers as conventional acid is in removing calcium carbonate. In addition, some of these alkaline solutions have been shown to increase the permeability of certain types of formations, particularly those involving shales and clays.
One major concern with the use of cellulose fibers in gravel pack or screened completions is the question of their flowback through gravel packs and the backside of the screen during completions.
This paper details experimental work that demonstrates: (1) the quick sealing characteristic of low concentrations of cellulose fibers as compared to conventionally used calcium carbonate, (2) the alkaline solubilization of cellulose fibers in a simulated gravel pack or screen completions, (3) the non-damaging aspect of cellulose fibers in gravel pack or screened completions, and (4) a discussion of the factors involved in using alkaline removal solutions versus conventional acids. This paper is an extension of early work on the alkaline solubilization of fibers discussed in SPE 38272.
Discrimination of Natural Fractures from Drilling-Induced Wellbore Failures in Wellbore Image Data—Implications for Reservoir Permeability
Authors: Barton Colleen A. 
Published: December 2007

Abstract
Natural fractures and drilling-induced wellbore failures provide critical constraints on the state of stress in situ and direct applicability to problems of reservoir production, hydrocarbon migration, and wellbore stability. Acoustic, electrical, and optical wellbore images provide the means to detect and characterize natural fracture systems and discriminate these from induced wellbore failures. We present several new techniques to measure and characterize attributes of natural and induced fractures in borehole image data. These techniques are applied to the characterization of fracture permeability in two case studies.
Flow Characterization--Critical for Efficiency of Field Operations and IOR
Authors: Campanella J. D. , Wadleigh E. E. , Gilman J. R. 
Published: December 2007

Abstract
Operational efficiency in highly heterogeneous (channelized or fractured) formations requires unique characterization methods. Reservoir characterization often is performed in sequence: 1) build the static 3D geologic model, 2) generate the saturation governing inputs (capillary pressure, relative permeability curves and PVT data), 3) upscale, and 4) modify the upscaled model to "history match" the dynamic performance data. There has been much recent emphasis on upscaling the static model to preserve appropriate heterogeneity within the simulator; however, during the history match the upscaled model may be substantially altered. This paper describes an alternative approach of incorporating both static and dynamic information at the beginning of the reservoir characterization process. This approach decreases both the modifications to the geologic and saturation inputs and the time required for history matching.
This paper provides an example from the Marathon operated Yates Field showing how flow data compiled by well, area, and total reservoir was used to assess the large scale "plumbing" of the reservoir. Tools developed for 3D geologic modelling have been deployed to distribute the connected secondary-porosity flow features (caves, solution-enhanced fractures, connected vugs, etc.) and barriers. Static geological data from the well scale is honored along with deterministic large-scale flow characteristics. These identified large-scale flow enhancements and barriers were incorporated into field operational planning and simulation construction early in the characterization process. The characterization efforts have lead to improved workover success in the Yates Field. Simulation and Yates Field examples demonstrating the value of simultaneous static and dynamic characterization are provided.
Joint Inversion of MWD and Wireline Resistivity Measurements
Authors: Chunduru R. , Mezzatesta A. , Meyer H. , McWilliams S. , Zhang Z. , Busch R. 
Published: December 2007

Abstract
Traditionally, measurement-while-drilling (MWD) data are used primarily for geosteering purposes and drilling decisions such as monitoring of hole direction, deviation, and delineation of abnormally pressured zones. Wireline resistivity measurements, galvanic and induction, play a fundamental role in identifying and delineating oil- and gas-bearing formations. The availability of both MWD and wireline data at different times not only provides the interpreter with abundant information about subsurface formations but also poses a new challenge to generate a unique model(s) that better explains both data sets. Generally, MWD and wireline data are interpreted independently to estimate formation resistivities that may result in inconsistent earth models. In this study, we performed a joint inversion of MWD Multiple propagation resistivity (MPR), and wireline High Definition Induction log (HDIL) data to come up with an earth model that best explains both the data sets. An inversion strategy using a dual earth model, that describes the appropriate logging conditions of both wireline and MWD was also used in the inversion. Finally, the proposed algorithm was implemented on synthetic and the Gulf of Mexico data examples, and the results were compared with conventional MPR and HDIL processing results.
Transitory Criteria for Design and Requalification of Submarine Pipelines in the Bay of Campeche
Authors: Valdés V. M. , Lara L. , Bea R. G. 
Published: December 2007

Abstract
Hurricane Roxanne is marked in the history of Bay of Campeche as one of the most severe storms that hit the zone during this century, and therefore questioned the validity of the design criteria applied at that time. As a consequence, a newborn own risk based criteria was developed for design and assessment of submarine pipelines and platforms in Bay of Campeche. Petróleos Mexicanos (PEMEX) and Instituto Mexicano del Petróleo (IMP) developed and issued such criteria in 1998, named Offshore Pipeline Transitory Criteria. The Transitory Criteria is based on risk assessment and management approach.
It is intended in this paper to show the result obtained so far of that development. Safety and serviceability categories for pipelines are defined. Safety factors for design and reassessment of wall thickness by internal pressure are determined based on risk approach. Practice recommendations for the design and requalification for hydrodynamic stability of submarine pipelines and risers are established. Safety factors for hydrodynamic stability are obtained following this criteria, and oceanographic characterization of the Bay of Campeche are presented in easy-reading charts for design and requalification.
Drill-In Fluid Selection for High-Temperature, Sour Gas, Naturally Fractured Reservoirs
Authors: Krilov Z. , Domitrovic D. , Soric T. , Gracanin M. 
Published: December 2007

Abstract
The paper is based on laboratory research and field evaluation data incorporated in a study carried out to select a suitable drill-in fluid for use in naturally fractured HTHP sour gas reservoirs. Laboratory results were verified by monitoring drilling process and initial production of a particular well located at the gas condensate field in SW Pannonian Basin, Croatia.
Production zone, naturally microfractured limestone (21% porosity, 2 md matrix permeability) at 2500–2600 m (BHSTI150°C) was left openhole. Reservoir fluid contains 53% CO2 and 800 ppm H2S.
Two aspects of a drill-in fluid evaluation were considered: optimal drilling process performance, complicated by harsh reservoir conditions; and minimizing formation damage of plugging susceptible microfracture system.
Drilling data, using the selected drill-in fluid, showed a good ROP and borehole stability. Production tests after well completion indicated no damage.
Even under extreme downhole conditions, the balance between optimal drilling performance and minimal formation damage could be achieved using described laboratory testing procedure.
Numerical Modeling of a Large, Naturally Fractured Oil Complex
Authors: Gurpinar O. , List D. F. , Kalbus J. 
Published: December 2007

Abstract
The large, naturally fractured reservoir under investigation is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations are not only naturally fractured, but also have matrix and vuggy porosity. Special relative permeability, capillary pressure, and compressibility relationships were developed to simulated multi-phase flow in this triple porosity system. Well and interference tests were re-analyzed at several stages in the project to provide input to geology on fracture properties and later to condition the fracture properties coming from the geologic model. The calibrated model acceptably matched the historical pressure and the production of oil, water, and gas for the reservoir complex.
Evaluation of Horizontal Well Production
Authors: Leon-Ventura R. , Gonzalez-G. G. , Leyva-G. H. 
Published: December 2007

Abstract
When drained volumes want to be increased or to reduce investments with additional drilling wells, we can use horizontal wells as a good alternative for optimum exploitation of the oilfields. This is supported because the horizontal wells productivity becomes higher than in a vertical, due to that they communicate a large area of the producing formation, cross natural fractures, reduce pressure drops and advances of water-oil or gas-oil contacts are delayed.
In Mexico, several horizontal wells have been drilled in different kinds of formations, which initially have responded with production expectantions. However, after a short production time, productivity conditions have been reduced significatively, which have practically condemned the use of this technology in the development of hydrocarbons exploitation.
Therefore, in this work a comparative evaluation of the initial productivity of horizontal wells with respect to vertical wells is made to know their behavior and to identify design parameters that govern the feasibility of obtaining successful horizontal wells.
Analysis of horizontal wells on Agua Fria, Cantarell and Abkatun fields (North, Northeast Marine and Southwest Marine Regions, respectively) are included in this study.
Abkatún-Pol-Chuc Integrated Study: The Value of Information
Authors: Rosales A. C. , Sánchez A. 
Published: December 2007

Abstract
This paper shows the methodology and results from the Integrated Study performed to the Abkatun, Pol and Chuc Reservoir Complex. These three fields, account for the largest light oil reserve in the Gulf of Campeche. Proven communication through the associated acquifer established the need of grouping the three fields in one simulation model.
The main producing formation is a fractured, vuggy carbonate breccia. The complex nature of porosity in the Breccia, received a special treatment. Vug percentage and vug connectivity maps were created to properly distribute vug porosity into matrix and fracture systems. Based on special core analysis and core flooding simulation, relative permeability and capillary pressure pseudo curves were developed to mimic the flow in the composite matrix + vug system.
Emphasis is made to show that this study is the result of a sustained effort to acquire data throughout the life of the reservoirs, its analysis and interpretation by geoscientists, reservoir, production and facilities engineers.
New PDC Bit Technology and Improved Operational Practices Saves $1M in Central North Sea Drilling Program
Authors: Mensa-Wilmot Graham , Booth Martin , Mottram Andrew 
Published: December 2007

Abstract
The improved performances of Polycrystalline Diamond Compact (PDC) bits have increased their acceptance in the industry as efficient drilling tools. In addition to drilling faster and longer, tremendous gains have also been made in performance consistency and predictability, especially in medium hard and homogeneous formations.
However, the performance of PDC bits in hard, abrasive, heterogeneous or multiple formation intervals leaves much to be desired. Although industry efforts have focused on the development of technologies and products to improve performance in these challenging environments, the results have lacked consistency, especially when bigger hole sizes are drilled.
This paper will describe the work done to identify the causes of PDC bit inefficiency in these demanding applications. It will describe the developmental concept and optimization cycle of a specialized PDC bit that was developed to address the challenges of hard, abrasive and heterogeneous formation drilling. Finally the paper will show how operational efficiency was improved, and the associated cost savings that were accrued as a result of the improved technology and processes.
The Blowout at CHK-140W
Authors: Grace Robert D. , Cudd Bob , Chen Jui-Shiang 
Published: December 2007

Abstract
The CHK Gas Field, located approximately 2 hours south of Taipei, is one of the largest and oldest gas fields on the island of Taiwan. Beautiful, steep mountains covered with dense jungle like growth characterize Taiwan. Average annual rainfall is high. Landslides are common. As a result, drilling locations are small, confined to the valley floor, have limited access and are in very close proximity to the general population.
The CHK-140W was dually completed in 1993 with a combined open flow potential of approximately 22 mmscfpd. During routine production in July 1996, the CHK-140W blew out at the surface. The primary broach was approximately 25 meters from the wellhead. By December of 1996, surface recovery operations by the original well control contractor included several failed kill attempts. A new prime contractor was selected. Surface recovery operations were resumed in early March 1997. A new recovery plan was adopted involving challenging snubbing objectives and innovative fluid dynamics.
Several airplane loads of equipment and materials were air lifted to Taiwan. The CHK-140W was successfully controlled on 21 May 1997 according to plan and procedure. The success of the project is a tribute to the cooperation between the employees of the Chinese Petroleum Corporation and her international service providers.
Simultaneous Drill and Case Technology-Case Histories, Status and Options for Further Development
Authors: Hahn Detlef , Van Gestel Wilhelmus , Fröhlich Norbert , Stewart Glenn 
Published: December 2007

Abstract
Drilling liner technology has become a standard for entering depleted reservoirs in areas of the North Sea and Southeast Asia and interest continues to increase for use of drilling liners to overcome other drilling problems. Marketing analyses have shown that further development of drilling liner technology and application has been rated with high priority.
Based on experience gathered during the last five years, this paper covers possible further Drilling Liner applications, new challenges, and requirements for new systems. "Drill and Case" systems will be introduced and benefits shown by means of case histories of jobs carried out in Norway and Indonesia.
High-Power Slim-Hole Drilling System
Authors: Cohen J. H. , Leitko C. E. , Long R. C. 
Published: December 2007

Abstract
Recent field tests showed that a reliable high-power slim-hole motor developed for the U.S. Department of Energy (DOE) drills twice as fast as conventional systems. This slim-hole drilling motor has the potential to significantly reduce drilling costs by reducing drilling time, mud, cementing and casing costs and minimizing environmental impact. The DOE slim-hole drilling system consists of a double-length, high-power PDM motor that delivers twice the torque and power of conventional motors, and hybrid PDC/TSP bits that can operate at these high power levels. Laboratory dynamometer and drilling tests confirmed the high-power output of the motor while field tests conducted at the GRI Catoosa test facility in Oklahoma showed that these motors drill twice as fast as conventional motors. These motors should stimulate increased use of slim-hole drilling while taking advantage of the resulting 30 to 50 percent cost savings associated with these smaller diameter wells.
Central Graben Extreme Offshore High-Pressure/High-Temperature Cementing Case Study
Authors: North John , Brangetto Martial P. , Gray Elizabeth 
Published: December 2007

Abstract
This paper presents the cementing case histories of six wells in two offshore high-pressure, high-temperature (HPHT) fields in the Central Graben area of the North Sea. Well depths averaged 6000 m true vertical depth (TVD), temperatures were greater than 200°C, the fracture/pore-pressure margin was small, and the bottomhole pressure exceeded 1,100 bar. The well deviation varied from near vertical to a maximum of 35°. These downhole conditions are the most extreme yet experienced in a field development in the North Sea.
Because of the extreme HPHT conditions, all aspects of cementing operations had to be carefully evaluated. In addition, new and enhanced equipment, processes, and materials had to be developed. Even though the potential for gas influx of the cement was high, the cement slurry formulation and placement techniques for resisting gas migration were successfully designed through the use of materials with a low environmental impact. Because the formations were weak and unconsolidated, a special cement blend was used at the top of the well. The mixing equipment was modified to withstand the high-density fluids required for the liner section.
For job success, both a well-defined top-of-cement (TOC) and good casing support had to be obtained without exceeding the allowable equivalent circulating density (ECD) limit. Therefore, effective mud displacement, correct slurry placement, and precise rheology measurement were required.
No remedial HPHT cementing operations were necessary during these operations, which was an important objective. Remedial operations could have posed extreme risks and high associated costs.
This paper describes how the cementing process was optimized for HPHT field development, thereby minimizing risk and costs. Considerable emphasis is placed on the production liner cement job, because it was the most critical string on the well.
Improvements to equipment, slurry testing, placement, and bond logging procedures are also described.
Anglia In-Fill Drilling Campaign: Drill-In Fluid Design and Application
Authors: Marshall David S. , Haywood David 
Published: December 2007

Abstract
The Anglia gas field was originally developed in the late 1980s with the first wells being drilled with mineral oil-based mud in the reservoir sections. In most cases, production from the original wells was below expectation and only five years later, plans were being made to re-develop the field in order to maintain its economic viability as a gas producer, and meet gas delivery commitments. Well-bore placement and drilling fluid selection were determined to be critical factors in ensuring the success of planned in-fill wells. This paper reports on the planning and testing which was conducted during the selection of the drilling fluid for the reservoir phase of the new wells, changes in drilling practice and the subsequent production obtained from utilising this new approach, in comparison to the production from the original wells. Reasons for the poor production from the first phase of the development are discussed. Due to the more complex trajectories and longer well-paths required by the well design team, additional difficulties were created for the drilling fluid, notably that of lubricity. Further testing is described in the paper, where the best combination of good lubricity and minimal formation damage was sought. Final production data on three wells drilled during 1997-9 are reported. The overall experience confirms that a detailed drilling fluid selection process which takes into account key reservoir-specific factors, combined with a holistic approach to the drilling and completion of the reservoir section of a well can significantly enhance its resultant productivity.
A New Selective Lateral Re-Entry System
Authors: Rivenbark W. Mark , Al-Sowayigh Mohammed I. , Al-Furaidan Yousef A. 
Published: December 2007

Abstract
Since the mid-1990's, a major Middle Eastern operator has been exploiting short-radius horizontal technology to maximize oil recovery from existing wells. Although the use of this technology has resulted in significant production increases, the operators recovery efforts were somewhat hampered by not having through-tubing access to the short-radius lateral. This problem has been solved with the introduction of a new selective lateral re-entry system.
Short-radius recompletion involves reentering an existing well, opening a window through the casing, and recompleting the well as a horizontal well within 100 ft (lateral displacement) of the re-entry point. This technology is typically used in wells that still contain zones with thin oil columns in place but are no longer able to flow because of high water cut. In wells in which this technology has been applied, production rates have generally been higher, water cut has been reduced, and recovery has improved.
The new system allows for re-entry into the lateral via wireline or coiled tubing. Utilizing isolation and commingling sleeves, the operator can control production from both the main bore and the lateral. Re-entry whipstocks (deployed by wireline or coiled tubing) allow logging, acidizing, and any other coil tubing intervention to be accomplished in the lateral with relative ease.
This paper describes the deployment and operation of the new system and presents field examples of its use. The paper also discusses applications under development that will require entry into multiple laterals within the same main bore.
Feedback Is Not Enough - An Innovative Safety Culture Improvement Case Study
Authors: Richardson Ross , Watkiss Richard , Brown Megan 
Published: December 2007

Abstract
Having a positive Safety Culture is central to good health and safety management. It is an indication of an organisation's determination and competence to control hazards at work. This paper describes an innovative project undertaken both to measure and to improve Safety Culture within a platform drilling contractor operating in the North Sea.
In this context, safety culture is defined as ‘the product of individual and group values, attitudes, perceptions, competencies and patterns of behaviour that determine the commitment to, and the style and proficiency of, an organisation's health and safety management’.
The project in itself was innovative, not in that the company recognised the problem and sought to assess it through the use of a Safety Culture survey, but that they also committed to using their entire workforce to help solve or improve upon issues highlighted by the survey. The process used in this project is one that other drilling contractors and operators within the Oil and Gas Industry should consider as a method for developing solutions to break the safety cycle and achieve continuous safety improvement.
This paper describes the process of assessment and the results obtained. The successes and pitfalls of the approach and project are discussed in an attempt to guide others through the process.