bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Integrated Reservoir interpretation using the Gas While Drilling (GWD) data
Authors: Kandel D. , Quagliaroli R. , Segalini G. , Barraud B. 
Published: December 2007

Abstract
The acquisition of gas in mud data while drilling for geological surveillance and safety is an almost universal practice. This source of data is only rarely used for formation evaluation due to the widely accepted presumption that they are unreliable and unrepresentative. Recent developments in the mud logging industry to improve gas data acquisition and analysis has led to the availability of better quality data. Within a joint ELF/ENI-Agip Division research program, a new interpretation method has been developed following the comprehensive analysis and interpretation of gas data from a wide range of wells covering different types of geological, petroleum and drilling environments.
The results, validated by correlation and comparison with other data such as logs, well tests, PVTs etc, enable us to characterise:
lithological changes, porosity variations and permeability barriers, Seal depth, thickness and efficiency, Gas diffusion or leakage, gas/oil and hydrocarbon/water contacts, vertical changes in fluid over a thick mono-layer pay zone, vertical fluid differentiation in multi-layer interval, biodegradation.
The comparison between surface gas data, PVT and geochemistry data clearly confirms the consistency between the gas show and the corresponding reservoir fluid composition.
The near real time availability, at no extra acquisition cost, of such data has led to:
the optimisation of future well operations (logging, testing, ….), a better integration of while drilling data to the well evaluation process, a significant improvement both in early formation evaluation and reservoir studies especially for the following applications where traditional log analysis often remains inconclusive: very low porosity reservoirs, thin beds, dynamic barriers and seal efficiency, low resistivity pay, light hydrocarbons.
Examples show both wellsite quicklook with simple lithological and fluid interpretations and more complex reservoir and fluid characterisation applications in varied geographical and geological contexts that demonstrate how GWD data is integrated with more standard data sets.
Case Study: Redevelopment of the Ebughu Field
Authors: Clark R. A. , Afemari A. A. , Ezeukwu T. E. , Awi H. 
Published: December 2007

Abstract
The Ebughu field, located offshore in the eastern Niger Delta, has produced from a thin viscous oil rim at very low rates since 1988. Production has run at 10% of platform potential. Following a change in operatorship, the field was successfully redeveloped during 1999 in less than 10 months. From a standing start, the field was reviewed, new wells were drilled and the platform facilities were filled to capacity. The field is now believed to be ten times larger than originally mapped. Key to this fast tracked success was the adoption of a streamlined redevelopment process.
Key results and conclusions are as follows:
The pooling of knowledge from outside contractors, consultancies and operators, has allowed a small integrated project team to review and redevelop a poorly performing offshore field in 10 months. Application of 3D seismic and horizontal well technology has transformed the development of a thin viscous oil rim, with both production levels and STOIIP potential being raised ten fold. Redevelopment of this sparsely explored field was significantly3accelerated through the adoption of an aggressive appraisal-development process. Seven low cost pilot wells were batch drilled up front from two slots and interpreted in real time. This allowed four horizontal development wells to be targeted and drilled in the same drilling program and a successful appraisal well completed for reservoir information. Effective selection of drilling resources reduced drilling costs substantially and resulted in horizontal wells which were among the fastest, cheapest and longest ever drilled in Nigeria. The adoption of the "all-in-one" completion concept allowed an 8,200ft well including a 2,100ft horizontal section to be drilled and completed from a new slot in 9.4 days for US$ 2.1million.
Application of Horizontal Well Technology in Colombia
Authors: Saavedra N. F. , Joshi S. D. 
Published: December 2007

Abstract
To date, 20 horizontal wells have been drilled in Colombia, 16 in sandstone and 4 in carbonate reservoirs. In carbonate, the economical success rate is 50% but in sandstone it is 88%.
In general, wells in Colombia are expensive. The vertical well cost varies from 2 million dollars to 11 million dollars, depending upon the reservoir depth. Horizontal well costs vary from 1.5 to 2.5 times the vertical well costs. Initially, most of the wells were completed with slotted liners. Now, new wells are completed with cemented and perforated liners to control water and gas production. The range of True Vertical Depth (TVD) is between 3000 and 16000 ft.
This paper presents three brief field histories and the lessons learned to date. In cases where production is less than expected the principal causes are: A horizontal well has commingled production from zones of high contrast in permeability, reducing considerably the producing length of a horizontal well.Production of unwanted fluid such as water and gas. With slotted liner completion, it is not only difficult to identify gas and water producing zones but it is also difficult to isolate them effectively.Geological uncertainty which results in drilling a well through a zone which is geologically different than expected.
New horizontal wells are planned as short length wells in high permeability zones and long ones in low permeability zones.
Also, re-entry wells are now used in mature reservoirs to reduce drilling costs.
The method used to analyze the well performance is discussed in the paper. To determine the producing length, gamma ray analysis, log information, production tests and/or PLTs were used. A productivity analysis using analytical equations was also conducted to define if the well was damaged or had a small producing length. Then decline curve analysis was used to forecast rate and reserves and well production histories were matched for rates and cumulative production over time. Depending upon the problem, and considering feasibility and cost effectiveness, a corrective action was designed to improve well productivity.
In summary, horizontal wells in Colombia have been successful and a large potential exists to drill many more wells.
Coiled-Tubing Drilling with Supercritical Carbon Dioxide
Authors: Kolle J. J. 
Published: December 2007

Abstract
High-pressure fluid jet-assisted drilling is attractive for drilling horizontal holes because of the potential for high penetration rate in hard formations using low-cost, small-diameter tools. Unfortunately, the threshold pressure for water-jet erosion of most sedimentary rocks is much higher than the pressure capacity of conventional coiled tubing. Recent experiments have demonstrated that supercritical carbon dioxide (SC-CO2) jets will cut hard shale, marble and granite at much lower pressure than water. SC-CO2 was also shown to enhance mechanical drilling rates. The use of SC-CO2 to drill ultra-short-radius lateral well completions is evaluated here. SC-CO2 is a dense, low-viscosity fluid with excellent hole cleaning capabilities. Conventional under-balanced drilling equipment can be used to control formation pressures while drilling with SC-CO2. SC-CO2 is a non-damaging fluid that should provide enhanced production from completions relative to holes drilled with water-based fluids. The use of SC-CO2 for jet assisted drilling would allow fast drilling of small-diameter, ultra-short radius laterals using low-cost, small diameter coiled tubing equipment.
Use of Networked Geosteering Software for Optimum High-Angle/Horizontal Wellbore Placement: Two U.K. North Sea Case Histories
Authors: Lott Simon J. , Dalton Christopher L. , Bonnie Jos. H. M. , Roberts Martin J. , Cooke Graham P. 
Published: December 2007

Abstract
This paper presents two case histories that demonstrate the effectiveness of an active geosteering approach using computer networking between rig site and operator office. A satellite link was used to update well trajectory and LWD data in StrataSteer™ geosteering software located within the operator’s asset group. This link provided the key advantage of allowing subsurface staff to become an integral part of the geosteering process.
The geosteering software enables a geological / petrophysical model to be created based on offset well log data and seismic profiles. The LWD log responses are modeled along the planned well trajectory and then compared to the actual LWD log responses (gamma, multi-depth resistivity, neutron, and density). The responses are then used to adjust the geological model and take geosteering decisions.
The amended geological situation enabled immediate and enhanced decision-making regarding adjustments to the well path in order to remain within the optimum reservoir zone. Good communication between all parties involved, both onshore and offshore, undoubtedly contributed to the success of both operations.
The two example wells, "A" and "B", present different challenges. In both cases, it was clear prior to drilling that active geosteering would be necessary. Well A was planned as a horizontal oil producer. The vertical thickness of the pay section was estimated at 13 ft, and the bed dip was expected to vary between 0 and 2 degrees in the direction of drilling. Following successful landing of the well, a total of 1300 ft of target reservoir was drilled using the geosteering software to actively guide the well path. Production rates from this well were significantly above pre-drill expectations.
The objective in Well B, a deviated sidetrack, was to drill through four reservoir zones, two on either side of a major fault. Recognition of the fault in real-time was critical due to different reservoir thickness and bed dips across the fault and significant uncertainty regarding the position of the fault. The use of geosteering software enabled the fault to be quickly recognized when it appeared — some 450 ft along hole earlier than expected. The geological model was quickly revised and the well path adjusted to optimize placement in the final two targets.
Advances for Improved Storage: Deliverability Enhancement and New Storage Facilities
Authors: Ammer James R. , Sames Gary P. 
Published: December 2007

Abstract
Major studies completed by the U.S. Department of Energy/ National Energy Technology Laboratory (NETL) have documented or demonstrated advances for improved storage deliverability and new storage facilities. These technological advances are very important for maintaining the reliability of the natural gas infrastructure since energy forecasts predict that the Nation’s demand for natural gas is likely to exceed 30 Tcf per year by 2015. The anticipated growth in electricity generation demand for natural gas will require the delivery system to be re-optimized to meet larger off-peak swing loads as well as peakday requirements that could increase from 111 Bcf per day (1997) to 152 Bcf per day by 2015.
Four new and novel fracture stimulation technologies - liquid CO2 with proppant, propellant, tip-screenout, and extreme overbalanced fracturing - were tested in eight different storage fields. In total, 29 fracture treatments were performed as part of the project. Several of these new and novel stimulation technologies provided attractive deliverability enhancement results and addressed the special concerns of gas storage operators. Three new projects were started in the fall of 1999 to investigate improved remedial treatment technologies.
Studies of the technical and economic merits of four advanced storage concepts were also completed. Three of these new or improved storage methods can provide storage in areas where conventional storage is not available or does not meet the requirements of end-users. The large-scale projects, lined rock caverns and refrigerated-mined caverns, have been shown to be superior to LNG storage when using several cycles. A feasibility study of storing gas as hydrates found that a single formation and decomposition cycle could be achieved within 24 hours in a 2.25-MMcf process. Using an advanced constitutive model developed for nuclear waste isolation in salt, the fourth study found that minimum working gas pressure in most existing salt cavern storage facilities can be lowered 10 percent without compromising cavern stability. Extrapolating these results across the salt cavern industry would result in a 17-Bcf increase in storage capacity with no changes to existing infrastructure. A fifth study, initiated in 1999, is investigating the feasibility of storing gas in basalt aquifers.
Gas Turbine NOx Reduction Retrofit
Authors: Seebold James , Bloomquist James , Christy Roger 
Published: December 2007

Abstract
Chevron's Eastridge Cogeneration Plant, located in the San Joaquin Valley in the Kern River Field near Bakersfield, California, produces steam for thermally enhanced oil recovery and electricity to the utility grid. To meet San Joaquin Valley Air Pollution Control District NOx emissions rules, two General Electric LM2500 combustion gas turbines needed the addition of selective catalytic reduction (SCR) flue gas treatment systems. This "major surgery" retrofit project sets a benchmark for effective decision analysis, front-endengineering and safe, smooth field execution. Looking to the future beyond the current rules, the equipment is sized and ready to go to comply easily with future reductions. This paper briefly describes the process from beginning to end. Those who may face such retrofits in the future but lack experience or who would like to improve their previous performance may benefit from Chevron Eastridge's learnings. With good planning, gas turbine SCR retrofits can be accomplished at reasonable cost and with minimal disruption to energy operations. The project's identification and qualification of a full-service domestic SCR catalyst supplier, fully capable of supplying all catalyst services importantly including catalyst activity testing (anybody's catalyst), benefits all Chevron operations both upstream and downstream with existing or future SCRs; no longer must service be provided from Japan. Thus, the project is pleased not only to have met and exceeded its own goals but also to have been of service to the entire corporation. Shutdowns limited to a stunning 5 days for major field modifications minimized the disruption to electricity and steam supply and kept both external and internal customers happy. Completed ahead of schedule and under budget, the 11-month project and 63-day construction spans were remarkable by any standard!
Ultra Clean Fuels for the 21st Century
Authors: Hartstein Arthur M. 
Published: December 2007

Abstract
Tighter emissions standards, volatile energy markets, and global climate change issues are putting increasingly more strain on automobiles. To achieve the most beneficial solutions, a systems approach must be employed to create the technological advancements necessary to develop the next generation of fuels, engines, and emissions control devices. In response to these challenges, the Department of Energy (DOE) has conceived a program called the Ultra Clean Transportation Fuels (UCTF) Program. The program seeks to leverage government and industrial resources in the most effective manner to rapidly commercialize and deploy advanced fuels and vehicle technologies. The program anticipates that ultra clean fuels developed from both petroleum and non-petroleum sources will initially be used as blending stocks with conventional fuels. These fuels will then transition from blending agents to fully utilized alternative fuels. The Offices of Fossil Energy and Energy Efficiency and Renewable Energy within DOE jointly lead the UCTF Program. Co-management provides integration and coordination of office resources and goals. DOE has implemented the program by soliciting industry to partner with government on research projects to develop the next generation of fuels and vehicular systems. Successful program implementation will enhance national security, improve the environment, reduce the cost of oil imports, and increase domestic employment.
An Integrated and Structured Approach to the Management of Exploration and Development Risks
Authors: Corbett J. S. 
Published: December 2007

Abstract
There are many elements of risk which need to be identified and managed to ensure the optimum exploration or development option is selected and successfully executed. In practice, the explicit assessment and management of all risk elements is very rare and generally only the legislated requirements of Safety and Environmental Risk management are considered.
Established risk management techniques developed for safety and environmental risk management can also be readily applied to technical and economic risk elements to establish the overall risk exposure profile for each option. These techniques provide a structured and systematic process for identifying, assessing, reducing and accepting risk and contingency planning. The value of this process is not merely the establishment of the overall risk profile, but rather an explicit understanding of all elements of risk undertaken by all of the stakeholders.
This paper presents an integrated and structured approach to the management of exploration and development risks. All elements of risk are addressed: Drilling strategy/technique used to exploit the field, company Reputation (in the event of a major safety, environmental, technical or economic incident), Asset (drill rig/reservoir) loss, Safety, Target zone definition, Environmental and overall project Cost. These elements are collectively known in this paper by the acronym "DRASTEC" Risk management.
To complete the risk management process, this paper distinguishes between risks which are within the control of the organization and those which are not. Where an organization has influence, risk control measures can be identified and implemented to prevent, mitigate and minimize the risk. The DRASTEC Risk management process may also applied to the risk elements in the other life cycle phases (i.e. Conceptual, Detail Design, Construction, Commissioning, Operations and Abandonment). The benefits of applying an integrated and structured approach to the management of all exploration and development risks are fully described.
Geologic Sequestration: Modeling and Monitoring Injected CO2
Authors: Brinks John , Fanchi John 
Published: December 2007

Abstract
CO2 Sequestration has been proposed as a possible means of achieving sustainable development objectives and calls upon petroleum industry technology and expertise. Commercial application of long-term CO2 sequestration depends in large part on the ability to effectively model and verify the movement of injected gas. Software has been developed to both simulate CO2 migration and to predict seismic responses as a function of time. The co-simulation of fluid flow and reservoir geophysical parameters during the life of the reservoir provides useful information about the feasibility and optimal timing of 3D time-lapse (4D) seismic surveys. When CO2 sequestration is combined with EOR processes, the integrated flow model has the potential to help locate bypassed reserves, and to aid the reservoir characterization process by decreasing seismic processing time. The purpose of this paper is to demonstrate the applicability of the integrated flow model to CO2 sequestration. An example using a dome-structured aquifer illustrates the technology.
Addressing the Skills Gap in Deepwater Drilling Through Competency-Based Training
Authors: Tuedor F. E. , Osisanya S. O. , Cuvillier G. C. 
Published: December 2007

Abstract
A recent survey shows that the demand for ultra deepwater drilling is expected to increase from a worldwide total of 28 rig years in early 2000 to 47 rig years in 2001, with an ultra deepwater fleet of 58 rigs capable of drilling in more than 5,000 feet of water (Fig.1). Expenditure in the global deepwater oil and gas market is expected to exceed $20 billion per annum by 2004 (Fig.2).
Ultra-deepwater drilling is known to be extremely expensive, with rig spread rates exceeding an estimated $ 300,000 per day in a number of cases.1 Current ultra-deepwater drilling costs can be as high as $ 2,500 to $ 3,000 per foot drilled, as compared to an average drilling cost of $ 134 per foot (onshore and offshore combined). Reducing these costs is an absolute necessity to render many deepwater oil and gas developments economically viable.
Cost reduction can be achieved through the application of appropriate technology, improvement in drilling performance and the minimization of competency-related problems using a structured competency management process. Such a process will ensure that technical and operational job requirements are defined and drilling personnel have the necessary skills and knowledge that are required to carry out their functions competently. Frequently, drilling personnel with minimal training, experience and competence in deepwater technology are assigned to these technically challenging operations.
This paper presents a methodology for developing drilling personnel operating in technically challenging environments using competency-based training and performance support programs. It shows a systematic way of mapping course objectives to competency at the workplace and to well and project objectives.
Improving Safety Performance Through Rig Mechanization
Authors: Hansen Mark D. , Abrahamsen Egill 
Published: December 2007

Abstract
Safety is continuing to evolve as a worldwide driving force in rig operations and, as a result, is a major consideration in all drilling rig operations and planning. Therefore, designing hazards out of the system is the key goal in safety engineering, one which has resulted in rig mechanisation. Rather than wholesale automation, rig mechanization involves taking existing hardware and "mechanizing" it for modularity and, preferably, remote control. Traditional automation concepts often required complete re-design of certain rig components, even derrick structures were modified to fulfill the requirements of a completely automated process. This resulted in automation concepts becoming very expensive and cost prohibitive, to the point where they were being eliminated from consideration.. Rig mechanization is a much more cost-effective approach which achieves safety goals by distancing the rig personnel from the hazardous location.
This paper will present the latest developments in rig mechanization and their effect on improving safety and operational performance. It will also compare the safety performance of mechanized rig operations with previous methods of conducting the same tasks. Specific items whose role in rig mechanisation will be addressed are:
Soft PLC Control Systems. These systems use software, microprocessors and fiber-optics to remotely control the equipment. Power Frame System. This system is designed to run on rails and is modularized to handle the suspending of any Power Tong to run casing and tubing. Mechanized Casing and Tubing Tongs. These tongs come complete with Free Floating Hydraulic Backups and remote operating capabilities. Stabberless System. This system engineers much of the hazard out of the stabbing operation by removing personnel from the derrick.
Finally, this paper will present and discuss the four major driving forces that are serving to promote the development of this type of equipment. They are Safety, Economics, Legislation and Industry Trends.