bluuebunny/crossref_metadata_2025_split huggingface dataset:
Genesis Project: Development Well Planning
Authors: Barton D.R. , Clark W.Y. , Howard W.J. , Hudson T.A. , Newhouse C.C. , Martin B.H. , Naquin C.J. , Waltman R.B. 
Published: October 2008

Abstract
This paper discusses the development well planning for the Genesis Project which is a deepwater development project using a floating spar for simultaneous drilling and production operations. Included are geological and reservoir overviews, major equipment systems overviews, and well planning considerations for drilling and completion operations.
Others involved in development well planning for deepwater developments can use the results of this work, and in particular, those developments considering utilization of a floating spar.

Introduction
The Genesis Project is the first deepwater development project in the world to use a floating spar with simultaneous drilling and production capabilities. The field is located in Green Canyon Blocks 160, 161, and 205 in the Gulf of Mexico. The development wells will be drilled and completed from the spar located in Green Canyon Block 205 in 2590 feet of water.
The discovery well was drilled in 1988 and several delineation wells followed in the early 1990's. Development funding was approved in early 1996.
A semi-submersible rig was used to batch set 36, 26, and 20 inch casing strings on 19 wells. The seafloor well pattern included locations for 20 wells and two export riser bases. One of the well locations in the pattern is actually one of the early delineation wells and was not included in the batch set program. Spacing between locations is 20 feet in a 140-foot diameter circle.
A shallow water flow zone was successfully isolated on all batch set wells. The 26-inch casing was set just above the shallow water flow zone. Deepwater foam cementing was used to cement the 20-inch casing, set below the shallow water flow zone. A wellhead isolation system was also used to shut off the shallow water flow zone.
In addition to the batch setting operations, the semisubmersible rig was used to drill the first two development wells with 9-5/8 inch production casing set at total depth. The batch setting and drilling of these first two wells was completed in the summer of 1997.
The spar was installed in early summer of 1998 followed by topsides and rig installation. Hook up work commenced and the first rig operations, running the export risers, began in November, 1998.

Geological Overview
The Genesis Field is a major Plio-Pleistocene oil accumulation with five major sands (N1, N2, N3, 14,200', and 14,800') targeted for primary development. These sands were deposited as turbidites in bathyal water depths on the middle to lower continental slope. An eastward dipping series of combined structural and stratigraphic traps hold oil in columns up to 1400 feet in height. Small faults and stratigraphic barriers near or below the limit of seismic resolution may be an indication of significant reservoir compartmentalization.
Information Management for the Genesis Development Project
Authors: Saines J.M. , Goulding A. 
Published: October 2008

Abstract
This paper describes the fundamental strategies, technologies and processes used to address the Information Management needs of Chevron's first deepwater spar facility, the Genesis Development Project. It includes enabling and supporting the Project's information sharing needs during project execution, and its capture for handover and use by the post-project phase customer: the Asset Management Team. The following four areas will be covered:Infrastructure,Communications,Data Management, andDocument Management This paper will also describe the specific solutions employed, problems encountered and lessons learned.
Utilization of current technology to provide electronic access to key project information is now considered essential and provides opportunities for cost savings. Overviews of the key strategic goals in each of the four areas will be highlighted, as will examples of the technology solutions employed in support of those strategies. High level overviews of the specific Data and Document Management System solutions and their functionality will be included. The solutions employed for Genesis have evolved from and leveraged off previous solutions utilized on other major Chevron projects in the North Sea and Canada.
As offshore projects become more complex the ability to apply technology solutions to the mountain of information generated becomes critical to enable more accurate and timely decisions. In addition to supporting decision making, technology can also support the management of change process by ensuring access to and control of the latest key project information.

Purpose and Introduction
Effectively managing a project's critical information is a challenge. This challenge only increases with the scope of the project. The Genesis Project is Chevron's first deepwater Gulf of Mexico spar facility. Key project information was supplied from numerous Project Team and contractor locations around the world (New Orleans, LA., Houston, TX., Pori, Finland, Morgan City, LA. and Corpus Christi, TX.). In addition to these locations, the Project had over 150 major equipment vendors and suppliers located throughout the world.
This paper will highlight the strategies used to implement Information Management for the Genesis Development Project.
A Winning Approach for Technology Transfer
Authors: Pugh David 
Published: October 2008

Abstract
Technology-no matter how advanced or "cutting edge"- doesn't communicate itself and, if poorly communicated, may be partly or totally rejected. In fact, well-communicated good technology will usually be better accepted than poorly communicated great technology. The reason is twofold:The message simply got through more effectively, giving the customer understandable and substantive reasons to want that technology, andAll the customer truly understands about the so-called superior technology is that it's profoundly more expensive.
Most technology professionals would rank sales communication, especially writing, as one of the least savory parts of their work. But the painful truth is that written documents, more than any other form of communication, stimulate and sustain interest throughout the sales cycle. Oral and visual communication certainly have their place in the process, but it makes both legal and common sense to understand that messages don't truly exist until they're recorded, set down in a common language for all parties to examine and consider. This means that technology-based solutions get funded, built, or otherwise adopted only when decision-makers have clear and compelling reasons to endorse your written messages (as opposed to your competitors') about those solutions.
Thus designing and writing the most persuasive proposal becomes a critical step in moving technology to the marketplace. Yet technical people who contribute to proposals typically want to sell their technology by attempting to establish technical superiority in technical terms. Problem? Relatively few people in the customer's buying chain care about technical superiority and even fewer understand the technical nuances that establish superiority. What they do care about is getting the job done the right way with the right technology for the right price to achieve the right business goals as the right return on their investment. Right?
In today's fiercely competitive marketplace, then, one of the key success factors in selling technology is not just having a great message, which all the technology leaders do, but getting that message through better than anyone else. In other words, winning business today means competing with communication. For today's bottom-line customers, it's not enough to know in some technically elegant sense what the solution is; they need to know why they should buy it, and that crucial message may be anything but technical.
Fortunately, learning to compete with communication rather than the never-ending technology shootout on State-of-the-Art Avenue gets very simple very fast. It also gets results. Therefore, those who develop, sell, and/or deliver technology can build their business by addressing three basic questions:What is our technology and/or technical approach for this customer?Where does the customer perceive, or need to perceive, that we are differentiated from our competitors?
Morpeth SeaStar Mini-TLP
Authors: Kibbee Stephen E. , Leverette Steven J. , Davies Kent B. , Matten Richard B. 
Published: October 2008

Abstract
The Morpeth project is the world's first application of a SeaStar®1 Mini-TLP and establishes that mono-column TLP's can be used to economically develop deepwater fields. This paper discusses the evolution and development of SeaStar technology and its niche in the deepwater platform market. Specifics of the Morpeth SeaStar platform are presented along with a discussion of some execution challenges that arose during the execution of this prototype project.

Introduction
The inventory of undeveloped deepwater discoveries is evidence that the offshore industry's ability to discover deepwater hydrocarbons exceeds its ability to economically exploit them. This inventory, which grew as deepwater wells were drilled, pointed out the need to develop more economic field development solutions for large and small deepwater fields.
The Morpeth Field provides a specific example of discovery, deferral, and development of a deepwater discovery. Although discovered reserves were potentially substantial, proven reserves were not sufficient, or near enough to existing platform and pipeline infrastructure, to become a development priority in comparison to other opportunities in the operator's portfolio. Consequently, after the discovery was made, development was deferred.
After a long offset subsea tie-back solution was deemed sub-optimal for this field, British-Borneo proposed a standalone SeaStar oil and gas production facility in the Morpeth Field to process oil and gas to pipeline specifications. This strategically located platform simplified the subsea system, improved flow assurance, increased recovery, and improved the economic attractiveness of future subsea developments in the area.
The Morpeth Field development project was sanctioned in February 1997 and the SeaStar platform was fully installed by August 10, 1998. First production was achieved on October 11, 1998 despite interruptions in offshore hook-up operations by three named tropical storms, including a direct hit by Hurricane Earl in September 1998. Successful production operations at Morpeth prove that mono-column TLP's can be used to successfully develop fields in deepwater areas.
Until Morpeth cost and schedule performance demonstrated otherwise, tension-leg mooring technology was widely believed to only be applicable to platforms that supported large numbers of dry trees. The Morpeth project demonstrates that tension-leg moorings provide reliable, cost-effective, stable, and expeditious means for mooring small deepwater platforms.
The Morpeth project also achieved several other industry firsts including the first TLP hull fabricated in the USA, and the first TLP classed by a Classification Society.
Cantarell Oilfield Automation
Authors: Villegas Ricardo , Montes Francisco , Ruiz Jaime 
Published: October 2008

Abstract
The current demand of the International Consumption Markets has created the need for a Productive Plant that responds to the increasing demand for quality products. It also has obliged that these industrial processes be endowed with state of the art technology, in its different fields of application, in order to respond to these requirements and be competitive on a world level. Related to the Oil Industry, concretely in the crude and gas extraction and production, the enterprise Petroleos Mexicanos, in its offshore installations located in the Gulf of Mexico, is currently developing the modernization and optimization of the Campo Cantarell infrastucture. It is applying the most avant-garde technologic developments and control criteria, through the arrangement of the mutual interrelation of mechanisms which conform specific patterns of behavior, allowing for an automatic operation of its different processes within a safety framework for operative personnel, the installations and the environment. Maintaining at all times the productive indexes demanded by domestic consumption and the export commitments established by the Mexican Government.

Introduction
The installations of the Cantarell Oil Field, comprehended by the AKAL-J, AKAL-C, NOHOCH-A, AKAL-N COMPLEXES AND THEIR SATELLITE PLATFORMS, is located 90 km NE offshore Ciudad del Carmen, in the Gulf of Mexico. The current operation of extraction and production processes is based on a platform control with pneumatic technology, relays and discrete electronics, which impedes handling the processes and necessary information volumes automatically, in order to take the decisions which may allow its optimization. The facilities also have a SCADA system, which is operatively limited to monitoring the operational conditions of the extraction and production processes, without exercising any digital control or continuous analogue phases.
For all of the above and due to the creation of new oil installations, comprehended within the AKAL-L, AKAL-B, AKAL-G, AKAL-P COMPLEXES AND THEIR ASSOCIATED SATELLITE PLATFORMS, which shall be integrated in the quoted field, the need to modernize its control processes was established. This would be achieved by equipping it with a state of the art digital system, operating under the concept of an "Open System", through which the control systems of each and every one of the installations are integrated by implementing intelligent instruments, directed by appliiince software. These are: gas lift optimization, monitoring the operating conditions of all the systems in order to maintain an updating, in real time, of the maintenance programs, the appliance of security systems with technologies which guarantee the integrity levels required by risk analysis. This includes the control of nitrogen gas injection to the said field, in order to maintain the adequate pressure conditions, allowing for the extraction of gas and crude.
Deep Water Development Drilling from a Spar
Authors: Leach C.P. , Stanton P.N. 
Published: October 2008

Abstract
This paper describes the design of a well system for development drilling from a Spar(1). In particular, the paper gives results of realistic well control modeling which has been used to confirm the design specifications for a system consisting of a surface BOP, pressured riser and partial seabed BOP (split BOP). Details of the pressures that would be expected from typical Gulf of Mexico (GOM) deep water well kicks will be given. The results of the work show:Most kicks that will be encountered can be dealt with using a pressured riser and a surface BOP if this riser is rated to 3000 psi for surface holes and 6500 psi for deeper hole sectionsA seabed choke and seabed BOP may be used under certain circumstances to limit riser pressures
The well control system as conceived also allows for:More effective deep water drilling when compared to a "conventional" subsea drilling system - casing strings can be pushed furtherA dual barrier such that failure of the riser during drilling does not result in a blow-outMany areas for potential cost savings when compared with a "conventional" subsea drilling system
The system is designed to fit the capabilities of a Spar. The paper also shows how the design of the well system leads to some cost savings for the Spar system as a whole.

Introduction
Up until now, drilling operations in the ultra deep waters of the Gulf of Mexico have generally been carried out using a "conventional" drilling system consisting of a seabed (subsea) BOP and a non-pressured marine drilling riser. If a kick occurs, the seabed BOP is closed. The kill circulation path is through the drillstring to the bit, up the well annulus to the seabed and then through the choke or kill line (or both) to the choke manifold located on or close to the drilling rotary table.
This type of system has its merits but also its drawbacks which include:Significant friction pressures which are transmitted back through the well when circulating through the long choke and kill linesComplex seabed equipmentPotential high gas rates at the surface resultant from small undetected swabbed kicks (subsequently circulated through the riser) when synthetic oil base mud (SOBM) is in use(2)
The work described in this paper used a realistic well control simulator (RF Kick)(3) and an underbalanced drilling simulator (RF Dynaflodril)(4) to examine an alternative well system that could be used from a Spar and that would:eliminate (for the most part) the drawbacks of the "conventional" systemprovide all required well control capabilitiesallow for cost effective drilling.
Several key requirements had to be met. These were:Ability to deal with the pressures and other conditions that are likely to occurAbility to be able to deal with a catastrophic event (for example, evacuation of the wellbore following a well flow that has gotten out of control)Provision of a back up such that a single point failure does not cause the loss of the well
Large Bore 'HPHT' WeWieads and Christmas Trees
Authors: Chiasson Glenn , Smith Craig , Stewart Dave 
Published: October 2008

Abstract
As "Large Bore" and "HPHT" (High Pressure/High Tempemture) type completions are becoming a more common occurrence around the world, operators such as Shell are going a step further and are requiring a combination of both technologies thus creating new challenges for the industry. The use of 'Large Bore' and "HPHT" type completion equipment can reduce the number of wells drilled, depending on field architecture, which has significant cost savings for the operator considering the cost of "HPHT" well construction. One project which is using Large Bore "HPHT'"equipment is Shearwater, which is located in the Central Graben Area of the North Sea and operated by Shell UK Exploration and Production. The wells for this project are being completed with 6.3/8" bore 15,000 psi 350°F Christmas Trees with full metal to metal sealing wellheads. This paper will review the challenges that were experienced during the design phase which included, but not limited to, operational issues, such as manual versus remote valve actuation, tree configuration, qualification testing requirements, API scaling rules, thermal analysis and material selection of qualification test equipment. This paper will also review the use of this technology for subsea applications, which is another milestone for both "HPHT" and subsea wells.

Introduction
In late 1996 Cameron began working with Shell on the Shearwater Development Project. Shearwater is iocated in Ccntrat Graben Area of the North Sea east of Aberdeen (Fig. 1). This project required the development of a large bore high pressure/high temperature christmas tree and wellhead/tubing hanger system to integrate with the 7" × 5.1/2" completion philosophy. The use of field proven technology was of the utmost importance to reduce the risk to both parties, taking into consideration the project was underway and only a limited amount of time was available for development work and qualification testing.
The use of large bore completions can reduce the total number of wells required to complete a field. For example, on Shearwater the use of 7" completions eliminated three wells. Considering one "HPHT" well may take several months to drill and complete, there are significant cost savings, especially taking the current rig rates into consideration.
The majority of the development effort was centered around the christmas tree and the tubing hanger system. The wellhead required only minor design modifications as 13.5/8" 15,000 psi metal sealing wellheads have been in use for several years. The wellhend selected was a field proven two stack 21.1/4" 5000 psi × 13.5/8" 15,000 psi full metal to metal sealing, split compact type used in conjunction with a mudline casing support and adjustable surface hanger system. The tubing hanger for this wellhead, however was only designed for 4.1/2" completions, therefore required further development for a large bore completion. The casing program for these wells is 30" × 20" × 14" × 10.3/4" × 7" tubing.
DEEPSTAR: Harsh Environment Flow Assurance Test Facility
Authors: Milliken Mark , Schulte Ralph , Chitwood James 
Published: October 2008

Abstract
In 1998, Deep Star and the Rocky Mountain Oilfield Testing Center (RMOTC) began planning a field-scale, multi-phase flow loop at Teapot Dome Field, Wyoming. In August 1998, the Department of Energy and Texaco, Inc. jointly approved $3.2 million in funding for the project. The field's low ambient temperatures, terrain character, and existing oil field infrastructure attracted Deep Star and their technical advisor, Southwest Research Institute. RMOTC can simulate the harsh conditions typical of deep-water environments, where flow line hydrates pose risks to productivity and pipeline integrity.
Flow assurance R&D opportunities on land-based test facilities have typically been limited by pipeline length, terrain, and ambient temperature constraints. The RMOTC Deep Star facility includes a five mile long, 3600, 6" diameter test loop with additional pre-test cooling and post-test heating jacketed loops, multi-stage separation, natural gas and NGL supplies, and a large liquid storage capacity. Being located at a producing oil field, RMOTC presents minimal environmental risks during testing. The facility allows high pressure, high rate, multi-phase flow testing at low temperatures. State-of-the-art data collection and processing are critical to the facility's highly automated and round-the-clock operational capability.
DeepStar is planning for two to three years of paraffin and hydrate deposition testing. Several companies have expressed interest in testing chemicals and subsea hardware during the DeepStar testing period. Interested testing partners need not be DeepStar consortium members. After DeepStar's commitment, the RMOTC hydrate flow loop will continue to fulfill the research needs of DeepStar members, industry at large, and academia. All types and scales of flow assurance research will be encouraged to take advantage of this facility.

Introduction
Deepstar is an industry cooperative effort organized and managed by Texaco, Inc. on behalf of 21 offshore operators (participants) and some 35 contributing engineering, manufacturers, and service companies (contributors) supporting deep water producing activities. Deep Star's work was started in 1992 and is currently in the Phase IV development phase.
RMOTC is an oil field testing center based at Teapot Dome field near Casper, Wyoming (Figure 1).
Figure 1. Location map of NPR-3 (RMOTC). (Available in full paper)
The field, owned by the U. S. Government and operated by the U. S. Department of Energy, has been in production since the 1920s, and is now approaching the end of its economic life.