bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study from 12 Successful Years of High Temperature Fracturing in Bach Ho Field Offshore Vietnam
Authors: Jain S. , Prestridge A. , Dellorusso P. , Nghi N. C. , Lam D. D. , Hung V. Q. 
Published: December 2007

Abstract
This paper presents the results of propped fracturing operations conducted in the past 12 years in the Bach Ho (White Tiger) field offshore Vietnam. High temperatures (&gt;275°F) and closure stress (&gt;8,000 psi) combined with the fact that fracturing has to be performed from a vessel make the execution of fracturing treatments operationally difficult and challenging. More than 60 treatments have been performed in over 40 wells placing over 3 million lbm of proppant with a success rate greater than 85%. The wells targeted were both injector and producer wells. The post treatment results have been excellent with an average increase in Productivity Index (PI) of greater than 5 times.
This study discusses the properties of the various hydrocarbon-producing zones in the Bach Ho field. A general discussion of reservoir properties and damage mechanisms is included, which demonstrates the potential for stimulation and the associated benefits. The methodology adopted in the design, execution and evaluation of the fracturing treatments is discussed. Discussion on the rig-up of the fracturing vessel and the necessary modifications for efficient operation is also included.
A review of the treatments indicates that the majority of them are conducted at a flow-rate of 20–25 bbl/min (bpm), with a maximum proppant concentration in the range of 8–10 ppa (lbm of proppant added to 1 gal. of clean fluid) and proppant quantities of 60,000 to 80,000 lbm per treatment. High leak-off limits higher proppant concentrations and volumes. Higher rates are desirable but are limited due to limitation of equipment on the fracturing vessel.
Zones targeted are both the Oligocene (sandstone) and the naturally fractured Basement. Propped fracturing has been found to be very successful in the Oligocene whereas different types of treatments like propped fracturing, acid fracturing and acidizing have been tried in the Basement with limited success. Finally the lessons learned and the experiences gained in this field are shared.
An Integrated System for Risk Assessment of Drilling Operations in Oil and Gas Wells
Authors: Khatlan A. , Jafari A. , Milani A. A. 
Published: December 2007

Abstract
In this paper, a general, hierarchical, structured and flexible drilling operation risk assessment system (DORA) is presented. The model, which is presented in this paper, is generated form the operator's point of view and it is applicable for different wells in a range form wild cat to reentry types. In order to completely define the risk assessment system, its operation model is developed, the tools and methods for each phase are specified and the inputs and outputs are determined. The developed model has four main phases of beginning, preliminary risk analysis, secondary risk analysis and support. The inter-related position of these phases and their sub-phases with respect to the drilling operation steps, are also specified.
Use of New Rate-Integral Productivity Index in Interpretation of Underbalanced Drilling Data for Reservoir Characterization
Authors: Suryanarayana P. V. , Vaidya R. N. , Wind J. A. 
Published: December 2007

Abstract
The prospect of dynamic reservoir characterization using flow and pressure data gathered during underbalanced drilling (UBD) is a powerful driver for implementation of UBD. The mathematical aspects of this complex, ill-posed, inverse problem have been the subject of research in the past decade. This paper focuses on practical, field implementation of UBD reservoir characterization, and the problems that consequently arise. Interpretation of data from UBD is made difficult by transducer errors, operational transients, and noise in data. It is therefore often very difficult to interpret the reservoir characteristics from the instantaneous productivity index (PI). In this paper, we introduce a parameter known as the Rate Integral Productivity Index (RIPI), which borrows from the theory of rate-transient analyses. The mathematical and physical basis of RIPI and its relationship to the instantaneous PI are presented. The behavior of RIPI and its implications for reservoir characterization are discussed. RIPI de-noises the data, and scales the problem such that the trends in data are more obvious, enabling robust interpretation of UBD data, and increasing the confidence in calls made regarding reservoir characteristics. Application of RIPI to field data is illustrated through several examples. Data acquisition, processing, and preparation for UBD reservoir characterization are discussed. In particular, the importance of filtering, de-noising, and identifying and excluding operationally induced transients is described. Limitations imposed by the data gathering methods are highlighted. It is shown that the ability of RIPI to reduce noise in raw PI data allows trends to be read more easily. The use of RIPI for static and dynamic characterization of supermatrix features (such as fractures, thief zones, etc.) is illustrated. The limitations of the approach and future trends are discussed.
Expandable Liner Hanger Resolves Sealing Problems and Improves Integrity in Liner Completion Scenarios
Authors: Williford James , Smith Pete 
Published: December 2007

Abstract
Conventional liner-hanger systems typically rely upon the primary cement job as the main method of sealing the liner/casing overlap, and liner-top packers are run either integrally with the liner hanger or separately in a second trip. In certain applications, however, cementing the complete liner may not be feasible or obtaining a primary cement seal at the liner top may not be achievable; in these situations, a liner-top packer must be used as the primary seal. In cases where the top of cement is above the overlap but below the hanger, the liner top packer is used as a back-up seal for the overlap.
Almost all liner-top packers that are run integrally to the liner hanger are set through the application of weight applied through the drill-pipe or landing string. The capability of the liner-top packer to seal with a single element at the maximum pressure rating requires that a sufficient setting force of up to 100,000 lbf be applied through the drill pipe to the packer mechanism. Work performed in Latin America recently showed the limitations of this process and how shallow liner-top installations might not have the string weight to apply a sufficient setting force to the liner-top packer.
A conventional alternative to an integral packer design is a secondary tie-back packer, but this alternative requires at least two extra trips into the wellbore and picking up of a string of large drill collars to supply the significant force required.
A solution was found that was capable of resolving this problem, and the innovative technology applied will be the focus of this paper. An expandable liner hanger that allows a hydraulic setting force to be applied locally to the hanger was used. The setting force for the packer was measurable and consistent. With the success experienced on the first well, the expandable liner hanger was used in subsequent jobs, and in all of them, the operator saved several days of rig time in addition to experiencing a successful completion.
Success of Hybrid Fracs in the Basin
Authors: Coronado Juan Antonio 
Published: December 2007

Abstract
In recent years waterfracs have increased in popularity, providing relatively long fracture lengths without the polymer damage of conventional crosslinked gelled fracture treatments. The major disadvantages of waterfracs are proppant settling and bridging, which limits waterfracs to high pump rates and low sand concentrations. These disadvantages gave way to the creation of the hybrid fracture stimulation, which is a combination of a waterfrac prepad followed by a crosslinked gelled fluid.
This paper will compare the use of hybrid fracture treatments in the deep, high pressure, high temperature, tight gas formations of the Anadarko Basin in Oklahoma to the more conventional waterfrac and crosslink frac. Also the fracture geometry, cooling effects and cost savings of the hybrid will be discussed.
Plunger Lift Application and Optimization in the San Juan North Basin—Our Journey
Authors: Oyewole Peter O. , Garg Divyakumar 
Published: December 2007

Abstract
Plunger lift technology has been applied systematically and successfully to unload liquids from marginal tight gas and coalbed methane wells in San Juan North Basin. This article presents the recommended practices, case studies, and results of excellent plunger lift application and optimization.
A production increment of over 4 MMcfd has been achieved and sustained on about 40 plunger lift installations. Most wells that were chosen for plunger installations were either on a plug and abandon (P&A) list or on temporary abandon (TA) status. Neither gas production nor anticipated production uplift from wells could justify installation of a more costly artificial lift system such as sucker-rod pump to de-water wells. Amazingly, production uplift of more than 200 Mcfd, and/or production increment of over 300%, was realized on some wells. It important to note that many operations use the practice of surfacing plungers by auto-venting, thereby releasing greenhouse gas (GHG) into the atmosphere. Plungers were operated successfully in San Juan North operations without this practice.
All these results were achieved through applications of new plunger lift technology, efficient plunger type selection, monthly and quarterly reviews, proper maintenance, optimization and monitoring, i.e. effective utilization of plunger lift data.
The strong alliance that was formed with the plunger equipment provider was one of the important inputs to our plunger lift journey. This new approach is a significant departure from the conventional ways of operating plungers, whereby service companies traditionally supply plunger hardware to the producing companies to operate with little "service" involved. Also, the field operations' teams, with their perseverance, offered a very important contribution to this successful venture.
Intelligent Prediction of Reservoir Fluid Viscosity
Authors: Hajizadeh Yasin 
Published: December 2007

Abstract
Accurate information on phase behavior and properties of fluids is an essential element in proper management of petroleum reservoirs. These fluid properties which are usually determined by laboratory experiments performed on samples of actual reservoir fluid or using empirically derived correlations provide the information required to properly understand the phase behavior, evaluate various production scenarios, optimize reservoir production and IOR schemes, and to maximize ultimate recovery and optimize production economics. One of these properties is the petroleum reservoir fluid viscosity. Crude oil viscosity is an important physical property that controls and influences the flow of oil through porous media and pipes.
This paper introduces a new application of fuzzy logic and neural networks in petroleum engineering. Artificial intelligence techniques such as neural networks, fuzzy logic and genetic algorithms for data analysis and interpretation are an increasingly powerful and reliable tool for making breakthroughs in the science and engineering and it is becoming clear that our industry has realized the immense potential offered by intelligent systems. The introduced model in this paper can predict the reservoir fluid viscosity data with neural networks and fuzzy logic approach. We can use these techniques in order to recognize the pattern between the given data sets where this pattern may not be understood clearly or no precise mathematical relationship exists
Prediction of the proposed model has been tested against the measured reservoir fluid viscosity data. Results indicate that the proposed prediction model with recognizing the possible patterns between input and output variables can successfully predict and model reservoir fluid viscosity.
Investigation of Explosion Occurrence in Underbalanced Drilling
Authors: Shahbazi K. , Mehta S. A. , Moore R. G. , Ursenbach M. G. , Fraassen K. C. V. 
Published: December 2007

Abstract
The development of mature fields has led operators to use underbalanced drilling to benefit from advantages such as reducing formation damage and increasing penetration rate. In gasified liquids, a light oil can be used as the liquid phase and nitrogen with almost 5 percent oxygen as the gas phase. Due to the simultaneous presence of oil and oxygen in the drillstring, safety considerations are a major concern in these operations.
To study and simulate the occurrence of explosions, oil base liquids were aged at 150°C and 14 MPa initial pressure in rocking and stationary reactors for 2.5 and 5 days in the presence of a gas with different concentrations of oxygen. The presence of drilling cuttings was simulated by addition of calcium carbonate to the base liquids. To cover the real penetration rates encountered in the drilling industry, volume percentages of 0.3, 0.6, 1.2, 2.4, and 4.8 of calcite were employed.
The experimental results of the samples that experienced explosions show that a delay time of approximately 0.5 hours was observed. In the period leading up to an explosion, the vapor phase temperature remained relatively constant while the liquid phase temperature first increased gradually and then more rapidly. At the time of the explosion, a rapid rise in the vapor phase temperature accompanied by a sudden increase in the reactor pressure was observed. This behavior indicates that the explosion was triggered by liquid phase oxidation reactions but that the sudden energy release event was associated with combustion reactions in the vapor phase.
This study signifies the important impact of the liquid phase temperature on explosion occurrence. The liquid phase acts as an initiator or an ignition source for explosions. Furthermore, it can be used as a parameter to warn of an impending explosion.
Focused Oilfield-Specific Training Reduces Accident Costs by Over 10 Times
Authors: Chedsey George , Kaminski Donald , Kaufmann Jeff 
Published: December 2007

Abstract
In the fall of 2004, BJ Services Rocky Mountain Region (Colorado, Wyoming, Utah and Northern New Mexico) identified the need to grow their driver/equipment operator ranks to meet the growing demand of the oil and gas industry in the Rocky Mountain west. Although new hire safety training programs, detailed driving safety programs and training resources were in place, the volume of drivers/equipment operators needed could not be accommodated in a timely, efficient and effective manner. Working with Center for Transportation Safety, the two groups developed, implemented and successfully operated a program that trained 315 Equipment Operators (as of October 2006) to obtain their commercial drivers license (CDL) and safely operate BJ Services heavy vehicles. The training focused on creating a safer oil service industry driver and specifically;
Included use of driving simulators; Introduced and reinforced BJ Services driving, fatigue management and journey management policies; Included driver training in areas that replicate oil field conditions (mountains, tight oil well locations, dirt roads, etc.); and Included vehicles similar to oil field equipment, i.e., heavy equipment and bulk tankers.
This case study documents the training of the heavy vehicle driver/equipment operator and compares accident statistics and cost of two groups of drivers. "Existing Drivers" are drivers/equipment operators trained prior to 2004 or who joined BJ Services after October 2004 with a CDL, and a "New Program Driver" who were trained for their CDL in the new program. The data shows that even when new program trained drivers had a vehicle accident, the accident was less severe and even though new program drivers comprised approximately 40-43% of the total drivers, their cost of accidents represented only 2-4% of the total accident cost.
Making Personal Responsibility for Safety Work to Create Change
Authors: Lang Kenneth A. , Allan Derek , Adam Tracey , Chew Vanessa 
Published: December 2007

Abstract
As part of the process of attaining accident free operations, the UK Step Change in Safety organization has suggested that ‘Personal Responsibility for Safety’ (PRFS) (1) will build on the existing safe plant and equipment in addition to the safe systems that hitherto have been the mainstay of safety improvements creating a change in our safety behaviour and ultimately performance.
This paper demonstrates one organization's innovative approach to engaging staff in PRFS. It addresses the challenge faced in moving the nine key elements of PRFS from a paper based work pack to an inherent behaviour exhibited by the organization and our colleagues
PRFS is composed of a template of ideal behaviours by which the individual and the organization can assess their performance leading them to self evaluation and hence to improvement. Personal Responsibility for Safety cannot be a short term programme but must be undertaken as a continuing long term process of improvement or culture change.
It must be stressed that PRFS is not simply a programme for laying complete responsibility on those in the front line in the work place.
The methodology employed used a combination of live theatre, based on the elements of PRFS, and mirrored existing business processes. Through this the leadership team was introduced to their own behaviours and those of the PRFS model. The participants were invited to self evaluate their PRFS maturity before being given independent assessment based on the PRFS maturity matrix.
More traditional approaches of engagement had been previously rejected as they were not believed to be effective enough in communicating and involving the appropriate staff.
A number of important initial lessons can be learnt from this process which will be valuable even outwith the UK and for those wanting to stimulate change. These are shared regarding the engagement process and the participant's own preconceptions of their performance versus the independent assessment are discussed.
Surface Reactive Fluid's Effect on Shale
Authors: Grieser Bill , Wheaton Bill , Magness Bill , Blauch Matt , Loghry Ray 
Published: December 2007

Abstract
In general shale is thought to be relatively nonreactive to low pH or acidic fluids. This is because of the general belief the clay, silt, and organic materials comprising the major components of shale formations exhibit insignificant bulk solubility in acid. What we find however is that shale units are highly laminated and contain acid-soluble minerals homogenized in the shale bulk matrix and natural fractures. XRD analysis and SEM images of shale samples show a great diversity and distribution of soluble material in the shale producing unit. SEM images of the shale fracture face before and after exposure to certain reactive fluids show a remarkable amount of surface texture disruption and micro-etching of the fractured surface. Based on these observations, it is concluded that reactive fluids are capable of (1) enhancing gas diffusion into and through narrow-aperture induced fractures, and (2) increasing surface area for flow of gas from the shale matrix. Such fluids are also capable of enhancing flow through mineral-filled microcracks or other secondary porosity. Initial production response from wells treated with reactive low pH fluids has been promising.
This paper documents X-ray and SEM analyses of many shale plays in Oklahoma. Production enhancement mechanisms are proposed to explain the observed physical effects of these fluids on shale.
Working Hard To Work Hard Safely
Authors: Mode Nicolle , Conway George A. 
Published: December 2007

Abstract
The shortage of qualified rig workers, and the desire of workers to earn high wages, is pushing drilling companies to increase the number of overtime hours. The trend in this growing industry of increased demand with limited numbers of workers is likely to continue. Unfortunately, another trend in this industry is an increasing number of work-related fatalities – with the Bureau of Labor Statistics reporting 98 fatalities in the oil and gas extraction industry in 2005. Historically, increases in the number of fatalities has followed the number of actively drilling rigs, even more so than the number of current employees. Working typical 12-hour shifts for 7 to 14 days in a row can lead to fatigue, resulting in mistakes in judgment and handling of equipment. Mistakes on a drill rig can be costly, both financially and in worker injuries. Fatigue is not unique to the drilling industry, and lessons learned from other areas can help identify and alleviate some of the potential hazards. Companies can schedule shifts and breaks to minimize fatigue, put in place policies and practices for identifying and managing fatigued employees, and help employees learn how to plan their off-time to minimize work-time tiredness. A summary of findings from research and practices in the oil and gas drilling industry as well as other industries will be presented with practical recommendations for safety management. The conclusions in this presentation have not been formally disseminated by CDC/NIOSH and should not be construed to represent any agency determination or policy.
Treatment of Hydrocarbon-Based Drilling Waste Using Supercritical Carbon Dioxide
Authors: Street C. G. , Tesche C. , Guigard S. E. 
Published: December 2007

Abstract
Non-aqueous drilling fluids are essential in challenging drill operations. Their use, however, requires special treatment and disposal because of their potential for environmental damage. In light of increasing costs for common treatment technologies and ever tightening environmental legislation, alternative treatment technologies are being sought by the drilling industry. Supercritical fluid extraction is one such technology which employs a substance above its critical pressure and temperature as a solvent.
In this paper, the results of a study using supercritical carbon dioxide to treat synthetic based drilling waste are presented. Unlike typical supercritical fluid extraction studies where the process is optimized using changes in pressure and temperature, this study was undertaken to improve the extraction of hydrocarbons from drilling waste by increasing the supercritical fluid solvent to waste ratio. Efforts focused on improving supercritical fluid/drilling waste contact, eliminating system clogging with waste solids and minimizing solids carryover. Alterations to the waste using additives and alterations to the vessel both led to an increased amount of waste being treated effectively using the same amount of solvent. Optimization of the process has yielded efficiencies as high as 97%. Also, it has been determined that the extracted hydrocarbons are unchanged by the supercritical fluid extraction process. This result suggests that the collected hydrocarbons may be reused in the drilling process, resulting in significant cost savings to the industry.