bluuebunny/crossref_metadata_2025 huggingface dataset:
Advances for Improved Storage: Deliverability Enhancement and New Storage Facilities
Authors: Ammer James R. , Sames Gary P.
Published: December 2007

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

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

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

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

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

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

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.
New-Generation Retrievable MWD Tool Delivers Superior Performance in Harsh Drilling Environments
Authors: Hache Jean-Michel , Till Paul
Published: December 2007

As the search for recoverable oil reserves moves to smaller, deeper, and hotter wells, measurements while drilling (MWD) requirements have grown increasingly challenging. MWD tools must survive temperatures of up to 350°F (175°C), pressures of up to 22,000 psi, and a wide variety of mud conditions. Moreover, deeper wells cause higher attenuation of the MWD signals and therefore require more signal power downhole. This paper presents the development of a new-generation retrievable MWD tool that has been proven to deliver the reliability required by the industry, even in deep, high pressure, hot wells.

Four case studies illustrate the tool's reliability and performance under extreme conditions:

In the Villafortuna field in Italy, this new generation MWD tool drilled the deepest horizontal well in the world, at depths greater than 20,000 ft with a maximum circulation temperature of 356°F (180°C) and downhole pressures exceeding 20,000 psi. In the Gulf of Mexico, the tool enabled BP to complete a deepwater well at a depth of 26,442 ft with a flow rate as low as 62 gpm, extending the far reaching capabilities of slimhole MWD equipment. In the Austin chalk in Texas, the tool operated reliably in drilling muds containing 30% solids. The tool operating life was increased by a factor of three through design improvements. The final case study documents the benefits of a tool designed for extreme environments, when used in difficult but not extreme conditions. An exemplary run of 315 hours at 287°F (142°C) is discussed.

This new generation of slimhole MWD technology finally meets the challenges presented by the deeper and hotter wells at the leading edge of petroleum exploration.
Casing Drilling: An Emerging Technology
Authors: Shepard S. F. , Reiley R. H. , Warren T. M.
Published: December 2007

Casing Drilling, an innovative process for simultaneously drilling and casing a well, is emerging as viable technology for the twenty-first century. The concept builds upon experience gained drilling liners to bottom in troublesome holes. With the advent of dependable top drive systems, wireline retrievable bottom hole assemblies, PDC bits, and high torque connections, it is possible to simultaneously drill and case a complete well using casing as the drill-string.

BP used the Casing Drilling process in Wyoming to drill both the surface and production casing intervals for five gas wells. These wells range in depth from 8,200 to 9,500 feet. This paper provides a case history discussion of critical issues that were encountered and resolved during the planning and operations phases of the project.
Lost Circulation Control: Evolving Techniques and Strategies to Reduce Downhole Mud Losses
Authors: Bruton James R. , Ivan Catalin D. , Heinz Thomas J.
Published: December 2007

Owing to the economic, well control and drilling efficiency problems it propagates, preventing or curing lost circulation has evolved into a critical issue for the industry. Accordingly, a less expensive drilling fluid system often is selected for a particular interval because it will mitigate the economic ramifications of downhole losses. Conversely, fluid systems are also chosen solely for their capacity to minimize losses downhole. Regardless of the application, special analyses are required to not only determine specific preventative measures for drilling fluid loss, but also for devising an appropriate treatment program to cure losses should they occur. Recently, specialized and chemically activated cross-linked pills (CACP) designed to stop whole mud loss have been developed and have shown significant advantages over conventional loss circulation methods.

This paper describes the development and application of the specialized cross-linked pills for controlling downhole mud loss. The authors will detail the laboratory methods used to formulated appropriate formulations, the placement procedures, and the successful field applications of this latest generation lost circulation control mechanism.

As detailed in the paper, formulations of the new cross-linked pills normally are tailored to specific downhole conditions of temperature and pressure to create a barrier between the loss zone and the wellbore. Further, they have been specially formulated to enable pumping through narrow drill pipe, coil, or mud motor dimensions and to "set" in a specific time frame. Chemical activators or retarders to control setting times achieve this.

These pills also contain controlled concentrations of particulate sealing agents that can be used selectively to either to bridge the loss zone at the formation face or allow deeper penetration into the fracture.
Case History of the Removal of a Hydrate Plug Formed During Deep Water Well Testing
Authors: Reyna E. M. , Stewart S. R.
Published: December 2007

The potential for gas hydrate production is always present in deep water operations. The negative impact of gas hydrate formation on both drilling and completions activity in deep water has been documented previously1,2. Another speciality operation that holds equal hazardous potential is drill stem testing in deep water. This paper describes the cause and solution to a hydrate plug that formed during a deepwater well test operation off the UK Continental Shelf, West of Shetlands. During well test operations in a water depth of 2750', an 800' hydrate plug formed in the string inside the riser above the mud line, prohibiting communication with the well below the SSTT. Diagnostic tests were carried out to determine the source of the blockage, and two potential culprits were initially identified - paraffin or hydrates. Coiled Tubing was mobilised to attempt removal using a heated glycol / brine solution. After several diagnostic operations, a coiled tubing jetting assembly and finally a mill and mud motor was successful in safely removing the hydrate blockage.

This paper will discuss: ➢How hydrate formation was masked by other aspects of the well test➢The technical and operational issues considered while developing the procedure for removal of the hydrate plug➢The outline of the final procedure➢The result of the execution➢The lessons learned
Integrated Borehole Stability Studies: Key to Drilling at the Technical Limit and Trouble Cost Reduction
Authors: van Oort E. , Nicholson J. , D‘Agostino J.
Published: December 2007

Drilling the Limit (DTL ™) is a powerful initiative to drill wells at minimum time and cost using best-in-class technology. Pre-requisite to drilling at the technical limit, however, is that the borehole is "perfect", i.e. the borehole is stable enough to eliminate downtime from stuck pipe and lost circulation incidents, the annular clearances are sufficiently free from cuttings to minimize wiper trips etc. This requirement is nontrivial when drilling challenging wells, e.g. wells drilled at high deviation and extended reach in reactive formations, wells in tectonically active areas, wells in deepwater environments with very small drilling margins etc. Achieving the "perfect" borehole for such wells is facilitated by including an integrated borehole stability (IBS) study in the well planning phase and by implementing its guidelines during well execution. A review of the IBS process is presented in this paper with actual examples of IBS results that were used to enable DTL ™ and minimize trouble costs on challenging wells.
Cost Effective Composite Drill Pipe: Increased ERD, Lower Cost Deepwater Drilling and Real-Time LWD/MWD Communication
Authors: Leslie J. C. , Jean Mr. Jeff , Truong Mr. Lee , Neubert Mr. Hans , Leslie II Mr. James C.
Published: December 2007

Extended Reach and Deep Water Drilling are constrained by the weight of the steel drill pipe. Transfer of data between the bottom hole assembly and the well head is currently cumbersome, slow, and less precise than desired. Recognizing these limitations, the U.S. Department of Energy, National EnergyTechnology Laboratory, has funded a three-year program to develop and qualify a cost-effective composite drill pipe (CDP). This pipe will provide enabling capability in all three of these areas. The program was started on September 30, 1999 and has the goal of having composite drill pipe approved and commercially available by September 30, 2002.

This paper reviews the first year of the program, presents specifications for the proposed composite drill pipe, and represents work-in-progress.
Solid Expandable Tubular Technology – A Year of Case Histories in the Drilling Environment
Authors: Dupal Kenneth K. , Campo Donald B. , Lofton John E. , Weisinger Don , Cook R. Lance , Bullock Michael D. , Grant Thomas P. , York Patrick L.
Published: December 2007

Maximizing hole conservation while optimizing well economics in both conventional and deepwater wells is a continual challenge. Addressing these challenges with new technology has provided some significant solutions, but the uncertainty when utilizing new technology with no proven track record must be risk-weighted.

Solid Expandable Tubulars (SETs) have been installed in both openhole and cased-hole wellbores from November of 1999, in a variety of environments in wells on land, offshore and in deepwater to solve a range of drilling and completion challenges.

This paper will discuss the drilling case histories in depth including: Descriptions of drilling challenges surrounding the use of SETs and their next best alternativesRisk analysis leading to the use of SETsDiscussion of the advantages and disadvantages of using SETsOperational lessons learned during installations of SETs
Breakthroughs in Casing Running Efficiency Utilizing Modern Pipe Handling Technology
Authors: Woelfel S. R. , Vollands P. T.
Published: December 2007

As the Drilling Industry demands continuous improvement in both safety and efficiency, many newbuild rigs in the recent newbuild cycle have turned to automation in the form of Varco Systems advanced Pipe Racking Systems (PRS). This paper will focus on one key area of the drilling process – casing running, and will address the significant operational effect that the additional casing strings required for deepwater pose to the well construction process. Recent operational performance of Pipe Racking Systems on the Transocean Sedco Forex ultradeepwater drillship Discoverer Enterprise will be reviewed.

The paper will also discuss the technical hurdles that were overcome in the design of an offline pipehandling system used to build 135-ft stands of triples of casing and rack them back in a dynamic application.

The technical discussion will be complemented by a review of how planning and execution of tubular operations have changed to maximize rig efficiency and safety. Results over the last year on the Discoverer Enterprise indicate running speeds of over 40 joints of range III casing per hour are attainable.
The Technical Limit - Illusion and Reality
Authors: Marshall David W.
Published: December 2007

The Technical Limit is a means of achieving a step-change in drilling performance the application of which has resulted in an improvement in operational performance against previous benchmarks. This is the reality. However, this paper will endeavour to demonstrate that the Technical Limit does not, by itself, optimise well construction costs since a significant proportion of this cost is not impacted directly by the Technical Limit approach. This is the illusion.

The paper examines the cost structure of the well as complementary to the Technical Limit's analysis of the time structure. It further emphasises the importance of the application of project management techniques to the well construction process and the necessity to include the typically ancillary functions of finance, contracting and procurement within the core well construction team in addition to the traditional operational skills. Competence assurance of these ancillary functions is as important as the core engineering function in order to optimise the well construction costs.
Evolution Toward Simpler, Less Risky Multilateral Wells
Authors: Pasicznyk Adam
Published: December 2007

This paper discusses a paradigm shift in multilateral technology. The new focus is away from increasingly complex completion installations and toward simple yet highly functional multilateral completions.

This paper reviews the TAML multilateral classification system, then traces Level 3 multilateral completion technology from original to current configurations. This latest iteration retains simplicity while adding full reentry functionality into both the main bore and lateral completions. The discussion then addresses pre-engineered Level 6 multilateral solutions that, by definition, uniquely embrace simplicity while providing optimal functionality.

Following this discussion, case studies from Venezuela, Nigeria, and the United States illustrate installation procedures, operational issues, resulting efficiencies and economies, and opportunities to further improve the technologies.
A New Approach to Borehole Trajectory Optimisation for Increased Hole Stability
Authors: Awal M. R. , Khan M. S. , Mohiuddin M. A. , Abdulraheem A. , Azeemuddin M.
Published: December 2007

Borehole instability due to stuck pipe, hole pack-off, and lost hole during drilling has been a major problem, which causes the industry to lose millions of dollars.

In the last two decades, various rock mechanics principles have been tried, and experience has been shared in the literature as to the efficacy of these principles to minimize the problem. The commercial software, rich in such analytical and numerical models, however, have not mitigated the problem.

We have found that this failure is attributable to:lack of full utilization of the classical Kirsch equations that represent the state of stresses around a borehole;negligence/ignorance of the complete in-situ stress field and the Biot's constant; and improper calibration of the rock mechanics parameters; andlack of translating the findings of mathematical models in an appropriate form that can be readily used for field deployment.

We have addressed these shortcomings by utilizing more relevant solutions to the Kirsch equations by incorporating poro-elastic behavior of rock. Further, we have utilized hitherto neglected aspects of the geomechanical stability equations, and presented graphical solutions that can be used by field engineers having a minimal knowledge of rock mechanics.

One of the important findings of these computer generated, graphical solutions is that the optimized trajectory can be vertical, inclined, or horizontal. This depends on whether the region is tectonically quiet or active. It also depends on whether or not, the prevailing insitu stress regime is normal, overthrust/reverse, or strike-slip type. Thus, the principal insitu stresses, in both magnitude and directions, are a fundamental data set that is needed in designing the safe borehole trajectory. For the deviated hole, further optimization is obtained by determining the best azimuthal direction to reach the target zone. What is more interesting, the optimized trajectory requires a much less mud weight to drill a stable borehole, thereby reducing drilling cost significantly.

We have applied our method in a case study in an offshore field, where frequent borehole collapse has been reported in drilling through shale/sand stringers. The successful application of the proposed method would not only save millions by preventing borehole instabilities, but also cut drilling cost significantly by replacing the expensive and environmentally unsafe oil-based mud.
Acid Stimulation Optimization in Horizontal and Vertical Gas Wells
Authors: Rocha G. , Hanbouly H. H.
Published: December 2007

A gas development program was kicked off in 1998 with the objective of boosting gas production in excess of 1 billion scfd by 2001. The project included drilling 51 wells in Zone I, Zone II, and Units A & B limestone formations. Vertical cased and perforated completions were utilized in the more permeable Zone I while the tighter Zone II and Unit A & B intervals were completed horizontally with ~3000’ open hole lateral drains.

Historically, acid (HCL) stimulation has been routinely carried out after running the completion string. Assessing the added value of this practice was required as horizontal stimulations are inherently more complex and expensive when compared to vertical treatments. This complexity is compounded by recent environmental initiatives which target minimizing acid flowback and eliminating flaring in all field operations. The potential to compromise future horizontal hole access is also significantly greater if acid is not uniformly distributed across the lateral section. Use of "Non Damaging" fluids in addition to other drilling practices also help minimize effects causing near wellbore damage.

The assessment was carried on a number of wells selected according to specific criteria. Conventional coiled tubing acid placement techniques were used and all wells were production tested pre and post HCL acid stimulation. The primary conclusions drawn from this work were;Insignificant productivity improvement is realized in open hole horizontal wells.Considerable productivity improvement was realized in the vertically cased and perforated wells.

Based on these findings, only Zone I vertical wells will be acid stimulated.
Comparative Seismo-Stratigraphic Architecture of Two Cretaceous Carbonate Platform Sequences: Influence of Local Tectonics and Sea-Level Fluctuations on Development of Reservoir Architecture
Authors: Cortis A. L , Asyee W. H. , Borgomano J. , Foster K. A. , Godfrey S. , Harris K. , Lawati M. , Massaferro J. L. , van Konijnenburg J. H , Vizamora A.
Published: December 2007

The seismo-stratigraphy of two Cretaceous carbonate plat-forms was compared. Distinct seismic facies packages, with diagnostic geometries, reflect differing accommodation space evolution, depositional environments and reservoir architecture. These are used to guide static reservoir models and ultimately assist in field development planning.

The E-member of the Natih Formation of Oman represents parts of two, 3rd order sequences with a regional unconformity near the top. Seismic facies reflect changes in accommodation space and water energy. Parallel to sub-parallel loopsets at the base and top of the Natih E represent the transgressive phases of the sequences. Combinations of seismic geometries with mounded, clinoforming and planar loopsets in the Middle Natih-E represent highstand complexes. These probably developed over palaeo-topographic highs. Abrupt lateral truncations of parallel reflectors near the top of the Natih-E (E1-E2) are caused by incised channels - probably formed during lowstands near the end of Natih-E deposition. Reservoir is best developed in the mounded seismic facies, followed by the incised channel facies and finally the by the planar facies.

The Cogollo Group, Venezuela is divided into - from bottom to top - the Apon, Lisure and Maraca Formations. The Apon Formation, a thick, upward cleaning, transgressive to highstand system, forms complex loopsets with variable character. Planar seismic facies, diagnostic of laterally continuous grainstone sheets, are developed in areas with less accommodation space. Mounded and onlapping seismic facies occur across a regional hinge line. These delineate depositional bodies that probably developed in deeper water. The Lisure Formation comprises interbedded shale and limestone deposited in a low energy environment. These form a planar continuous loopset. The Maraca Formation forms part of a 3rd order transgressive system tract. It is the thinnest unit, but hosts the largest proportion of hydrocarbons. It forms a laterally continuous high-energy grainstone sheet, manifested as a continuous, single loop. Subtle changes in the loop reflect variations in reservoir quality.
Economic and Envionmental Impacts of using Natural Gas vs. Petroleum Products In Egypt (1981/82 – 1998/99)
Authors: Alnakeeb Hani , Ibrahim Adel , Kamal Osama
Published: December 2007

Egypt’s main energy resources are petroleum, natural gas, hydropower, and some limited quantities of coal. Also, Egypt enjoys good potential of renewable energy resources specially wind and solar energy. Crude oil and natural gas account for about 92% of total commercial energy consumption.

With the increasing reserves of natural gas, compared to those of crude oil, it become the petroleum sector’s policy to maximize the use of natural gas to supply the local energy needs in the different economic sectors.

A natural gas substitution policy has been adopted and implemented to promote the use of natural gas in electricity generation, industry, residential and commercial sectors. Within the same policy framework, the petroleum sector has taken the lead to use natural gas in transport sector. Natural gas has several advantages, economically and environmentally, which enhances its penetration in different energy consumption sectors.

This paper will focus on the economic and environmental advantages of using natural gas vs. petroleum products, at both sectoral and macro levels, showing how such substitution policy secured the petroleum energy supply for different economic sectors and contributing in sustainable development in Egypt.
Nitrogen Injection for Simultaneous Exploitation of Gas Cap
Authors: Tiwari Sanhita , Kumar M. Suresh
Published: December 2007

A compositional study has been carried out for evaluation of nitrogen injection in the large gas cap of a light oil reservoir (GS-4) as a low cost replacement gas. GS-4 is one of the major hydrocarbon bearing reservoirs in Gandhar field with oil in place of 6.37 MMt overlain by a large gas cap of 8.682 BCM. The gas reserves therefore represent a significant portion of the reservoir’s total economic value. The timing of production, from both the oil zone and the gas zone, is an important factor in optimum plan of exploitation for maximising the economic returns in addition to the goal of optimising oil recovery from this reservoir.

The existing exploitation scheme for this reservoir focuses mainly on the optimum exploitation of the oil reserves. This scheme restricts the exploitation of the large gas cap. The gas cap can be blown down only after the exploitation of oil zone. This paper discusses the strategy of early exploitation of rich gas cap gas and associated natural gas liquids by replacing it with low cost gas like nitrogen. Cryogenic air separation method can generate nitrogen in large volumes at a fraction of the cost of natural gas and thus provide large economic benefits. This strategy can advance the gas cap gas sales by 15–20 years ahead of the currently planned blowdown stage.

The paper presents the results of sectional study in GS-4 to evaluate the feasibility of nitrogen vis-à-vis lean gas injection. A detailed compositional study was carried out using a seven component equation of state (EOS) model. The paper discusses the key issues in fluid characterisation of GS-4 and its phase behaviour effects in contact with nitrogen. GS-4 gas cap presents production potential of around 1.5 MMm3/d for 10 years. The study indicates very attractive economic benefits for nitrogen injection as a replacement of gas cap gas.
Scale Removal by Milling and Jetting With Coiled Tubing
Authors: Enerstvedt Eirik , Boge Henning
Published: December 2007

This paper describes scale cleanout jobs performed with Coiled Tubing offshore in the North Sea on 7 well for Phillips Petroleum Company Norway

The cleanout has been done by first perform milling runs with a standard PDM motor, then the completions jewelry has been cleaned by use of a jetting nozzle head with a metal to metal seal motor as a drive mechanism.

In some of the wells multi-finger caliper has been run both before and after the cleanout. The caliper has confirmed a clean well. In others drift run has been performed and gas lift valves has successfully been replaced. An increased oil production from the wells is also achieved

Both Weatherford CTD PDM motors and the metal to metal seal Weatherford MacDrill motor together with the Weatherford MacJet head has proved to be strong and reliable tools for this kind of operations.
Coiled Tubing Innovation Advances New Completion Concept
Authors: Morrison Dan W. , Brake Sean C. , Martch Eddy
Published: December 2007

This case-history paper focuses on the evolution of a novel completion concept. The concept resulted from improvements in through-tubing vent-screen technology and the invention of a wireless casing collar locator (CCL) for coiled tubing (CT) operations. This completion method provides the following: reduced completion costsimproved completion efficiencyextended completion lifereduced mechanical riskimproved reserve recovery rate

The invention of the wireless CT CCL was a key development that advanced this completion technique.

A new surface-modification agent (SMA) is at the core of this completion process. The SMA is a water- and oil-insoluble, resinous liquid additive that does not harden or cure under reservoir conditions. This additive is applied to proppant during the sand-control portion of the completion process to increase the cohesive forces between the proppant grains. The SMA provides the following advantages: It can help increase pack permeability and porosity by up to 30%.It helps control fines migration.It decreases mechanical risk by helping stabilize the annular pack.

Tests have shown that using of SMA increases the critical flow velocity of the annular pack. It (1) allows the well to produce at higher rates without producing the sand from the annulus or (2) allows the operator to shorten the completion blank length at a given production flow rate, and (3) allows the length of the completion assembly to be reduced, providing flexibility that allows the completion method to be used on wells with closely stacked pay zones.

Before the development of CT CCL, operators had to use CT rigs with an electric line in the tubing to power downhole tools with perforating collar locators or gamma ray (GR) perforators. This system could triple or quadruple job costs. Wireless CCL allows accurate depth measurements with CT, making it possible to run guns and packers on CT with an existing GR CCL log as a reference. The CT CCL eliminates the need for e-line and reduces the completion time and daily spread cost. When the space limitations and the time required for repositioning the equipment for different phases of the operation are considered, the time associated with spotting equipment in offshore operations can be substantial. The CT CCL reduces completion time.

The following case histories describe economically successful jobs performed with these integrated services.
New Biopolymer for Coiled Tubing Applications
Authors: Navarrete R. C. , Shah S. N.
Published: December 2007

Xanthan gum has been used extensively as a viscosifier in coiled tubing due to its unique friction reduction properties. In this paper we describe the friction pressure properties of a new, previously introduced, biopolymer for use in coiled tubing applications. The name of the polymer is diutan. Diutan yields higher low shear rate viscosities at lower polymer concentrations than xanthan gum due to its higher molecular weight. Diutan is more shear thinning that xanthan gum. As a consequence, the high shear rate viscosities of diutan are lower than those of xanthan gum at comparable low shear rate viscosities.

Large scale friction pressure tests in coiled and straight tubing were conducted to observe if the lower high shear rate viscosities of diutan translated into lower friction pressures. The results of these tests showed that both xanthan and diutan exhibited significant drag reduction. However, the percentage drag reductions of diutan were larger than those of xanthan gum.
Application and Design of Unbalanced-Drilling With Formation Fluid Injection
Authors: Zhou Lei , Zhou Kaiji
Published: December 2007

In the broad sense, unbalanced-drilling is not only an effective technology of exploiting low pressure and low permeability formation and exhausted formation, but also a drilling and completion technique for finding and exploiting formations which are different pressure systems. Unbalanced-drilling pressure difference can be obtained by use of single-phase fluid, aerated fluid, tiny glass bead, and tiny plastic bead. If unbalanced-drilling pressure difference is obtained by different ways, drilling cost will be much variable. Under allowable formation pressure, single-phase and low-density fluid was injected from surface. When it was circulated in the annular space, it can stimulate formation fluid into annular space so that we can obtain the designed unbalanced-drilling pressure difference, working-on process, and theory of annular pressure system. How to select single-phase fluid injected from surface, and to obtain of initial unbalanced-drilling pressure difference, calculation and control technique of characteristic factor of annular multiphase fluid dynamics, control and calculation of injection quantity of formation fluid, control technique of unbalanced-drilling casing pressure and standpipe pressure, were discussed and analyzed in this study in detail. This technology has been applied to Northern China Oil Field successfully.
Sources and Uses of Non-Propriety Economic Data: What Every Evaluation Engineer Should Know
Authors: Miller Richard J.
Published: December 2007

This paper builds upon previously reported prior work using data from fair market value sales of oil and gas properties and from capital market analysis to (a) examine the relationships among certain market valuation parameters and the ways in which those relationships may correctly or incorrectly influence evaluation practice and decision making and (b) to summarize and compare the results obtained from three recognized studies of evaluation data.

The examination of relationships portion will focus on two specific areas; (1) the relation of the discount rate to the rate of price and/or cost escalation used in an evaluation and (2) the relation of the discount rate to the performance of selected capital markets for debt and equity, and inflation. This part of the work examines some of the many questions and issues which are often raised regarding the use of market data for valuing properties and also regarding the selection of appropriate evaluation parameters.

The summary and comparison will contrast the construction, data analysis methods, and results obtained by three commonly used studies: (a) the SPEE Annual Parameter Survey, (b) the annual study done by the Texas Comptroller of Public Accounts for the appraisal of oil and gas properties, and (c) the Western States Petroleum Association annual study of oil and gas property sales and oil industry cost-of-capital. These studies are often cited in evaluation reports and in publication which discuss evaluation procedures. The three studies are found to have significant similarities of objective and results while starting from differing data sources and using different methods to achieve the reported results. The paper will show that the three studies, each with a 10-15 year history can be used together to define a continuum of evaluation information which provides a source of discount rate, price/cost escalation, and risk consideration data for knowledgeable persons involved in valuing oil and gas properties.
High Rate Formation-Pack a Technique for Sand/Water-Control
Authors: Sachdeva Surinder S. , Johari Anil , Patel Hasmukhbhai R.
Published: December 2007

The oil industry continues to face the problem of sand production /movement along with the oil/gas due to migration of fine sand. The most common method for sand control is mechanical method of sand-control by gravel packing with installing a assembly in the well, before commencement of oil/gas production. The gravel-pack results in slightly lesser productivity due to pressure-drop across the pack / liner. This also sometimes results in complicated fishing in case of deep / inclined wells. An innovative idea of packing the formation with suitable gravel at high rate has been tried in-all 30 wells to arrest the movement of sand. It has been termed as "High Rate Formation-Pack".
Correction of the Non-Darcy Coefficient for Completion Effects: Impact on the Prediction of Tangguh LNG Gas Well Deliverability
Authors: Zulfikri Zulfikri , Abdassah Doddy , Seno Adjie Bugi Umar
Published: December 2007

The Tangguh LNG gas fields are situated in the Berau Bay, Irian Jaya, Indonesia. An extensive exploration and appraisal program was performed from1994 to 1998 which resulted in the discovery of 14.4 TCF of proved gas reserveswith substantial upside reserve potential. The fields are currently at thedevelopment planning stage in support of the Tangguh LNG project, Indonesia'sthird major LNG center.

The objective of this work was to obtain a more accurate skin and non-Darcycoefficient (D) from exploration and appraisal well tests by accounting forcompletion effects. The impact of corrected D coefficient on welldeliverability reduced the number of forecasted development wells.

In Tangguh pressure transient analyses, skin and D coefficient from welltests were first calculated based on pressure data from gauge depth. Most ofthe gauges were placed in gauge carriers integral to the test string andanywhere from 125 to 300 feet above the mid-point of producing interval.Because the pressure drop in the completion from the perforations to the gaugeappears as additional skin, the deliverability of the formation could beunderestimated if this effect were not considered in the analysis.

After the pressure drop in the completion was correctly accounted for, thenon-Darcy coefficient decreased in all wells. The D coefficient correction wasparticularly significant in high transmissibility reservoirs and agreed withtheoretical D coefficient calculations. This increased the predicted gas welldeliverability.
Rotary Steerable Drilling Fluid
Authors: Bland R. G. , Reeve J. W. , McNair G. A.
Published: December 2007

New mud chemistry is shown to improve the efficiency of directional drilling with a rotary steerable drilling system. Full-scale (8½-in. bit) drilling results using a rotary steerable drilling system drilling to horizontal at an experimental test site and an application in the Huizhou 21-1 field, offshore Hong Kong in the South China Sea are presented documenting the effectiveness of this technology.