bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview of the Canyon Express project, business challenges and "industry firsts"
Authors: Rijkens Frederik , Allen Marcus , Hassold Thomas 
Published: October 2008

Abstract
The paper presents an overview of the Canyon Express project, with the "industry firsts" and some of the pitfalls encountered in project execution. The project is the first of a new kind of joint development that allows otherwise un-economic fields to be developed profitably, thanks to subsea multiphase metering and unprecedented cooperation between field owners. The paper then describes how the business challenges were met to create a novel business structure between the owners of the three fields that participate in the Canyon Express development.
Figure 1 depicts the progression in the deep water frontier immediately proceeding Canyon Express. Canyon Express is the world's deepest development at 7200 ft/2200 m. water depth, with a record flowrate for subsea tieback at 500 MMSCF/d, and takes commingled flow from three fields with different owners, Operators and royalty obligations.

Introduction:
By Fall of 1999, three neighboring and moderate size gas discoveries had been made in water depths up to 7200 ft. in the Mississippi and Desoto Canyon areas of the US Gulf of Mexico, located approximately 150 miles southeast of New Orleans.
These discoveries are owned by different joint ventures, operated by TotalFinaElf, BP and Marathon respectively for the Aconcagua, King's Peak and Camden Hills fields. The two remaining Working Interest Owners are Nippon with ownership in Aconcagua and Pioneer Natural Resources with ownership in Aconcagua and Camden Hills. All five Working Interest Owners (WIOs) became owners in the TotalFinaElf operated Canyon Express (CE).
The size of the fields did not justify stand-alone development, in view of the water depth and the distance of some 50 miles to existing facilities. If combined in one development, however, the sharing of costs and risks while combining the reserves of the three fields would allow favorable overall project economics. The success of the Project then became dependent on each component (Individually operated Fields, Shared Canyon Express subsea infrastructure and third party Canyon Station production processing) being incorporated physically and commercially into one venture, which has become known as the Canyon Express Project. Major challenges of the Project were:Agreement on a novel business structure to share in a subsea system infrastructure (common flowline and control system), while field Operators retained risk and responsibility for the wellsAgreement on the decline of system pressure over time and the sharing of declining system capacityThe need for deepwater multiphase wet gas metering for fiscal allocation, because of subsea comminglingThe technical challenges of installing and operating a long tieback in world record water depth of 7200 ft.The coordination and system integration of a third-party processing facility for Canyon Express production.The need for intelligent well technology for the completions to produce from two zones in record ater depth
Canyon Express - Qualifying for the Deepest Development
Authors: Nelson Stuart G. , Wells Hal C. , Huntoon George 
Published: October 2008

Abstract
In the Canyon Express Project, the oil and gas industry faced one of its greatest challenges to date. There were a number of 'firsts' along the path to first gas. Not least of these was the challenge of being the deepest development to date. The reason for the development being made at all lies in the geography and size of the fields.
This paper addresses the gaining of confidence; the confidence to develop the fields; and the confidence to work together to achieve the goal economically. The paper describes how the task was developed in three parts: qualifying the equipment, monitoring its design and manufacture, and testing the completed units in integrated assemblies.

Introduction

Confidence.
A feeling needed by everyone, but which often eludes us.
At the conceptual stage of the project, all operators focused on the fact that each field alone was too small to be economically viable. However, the fields were conveniently close to each other so that one shared pipeline and controls system could suffice. But to share facilities meant that all field operators had to work together. Figure 1 shows the field architecture schematically.
Failure of equipment could lead to shut-in of a well, a field, or even of the whole system. Failure of equipment in any one field could cause the shut-in of the other fields. This was inadmissible and required some degree of separation of the fields from the common system. Strategies for individual well intervention were developed. However, there are items, which are part of the Common System that could not be isolated. For these components, reliability is essential.
To understand this problem, the Project Team embarked on a Reliability, Availability and Maintenance (RAM) Study at an early stage. Such studies require everyone to focus on the failure of individual components, and what that means to the overall system. The system was developed to ensure that availability for the whole gathering system could be optimized. However, it was the effect of failure and the cost of intervention that were most revealing.
In the departure from the shore to the deep waters of the Gulf of Mexico, the fields become less and less accessible. The fields are further from the shore bases. The cost of even the simplest intervention becomes very expensive, very quickly. The resources to work on these fields are not always immediately available. Their cost is high. A simple intervention to turn a tree valve may require up to 7 days of vessel time including mobilization, weather, and sailing time. Thus, one intervention cost could easily be in the order of $0.6 million, and that does not include any material costs.
Technical Feasibility of Tubing Risers
Authors: Gu George Z. , Myers Rod , Sokoll Robert , Jin Joe Z. , Huang Kevin 
Published: October 2008

Abstract
A tubing riser is a type of top tensioned production riser (TTR), which has only the production tubing running through the water column. As a result, the top tension required to support a tubing riser is much less than for a traditional casing riser. This means that for ultra-deepwater structures (&gt;5000 ft), riser payload and hull costs can be significantly lowered.
For deepwater Tension Leg Platforms (TLPs), where TTRs are supported directly by the deck, lower top tension normally translates into payload and buoyancy reductions. For deepwater Spars, where air cans support most TTRs, lower top tension normally translates into reductions in air can and hull sizes.
During Phase 1 of the Magnolia Development Project (ConocoPhillips and Ocean Energy), a Tubing Riser Design study was carried out to determine the feasibility of using tubing riser for all TTRs on the Magnolia ETLP. The results showed that the tubing riser concept is technically feasible. However, there are a number of areas needing additional study to make the concept more robust.
In this paper, the technical feasibility of tubing risers is examined from the aspects of strength and fatigue (analysis), VIV and galloping (analysis and model testing), riser interference and stroke (analysis). In addition, general arrangement, composition and configuration will be described.

Introduction
Traditional top-tensioned production risers (TTR) have either one or two layers of casing outside of the production tubing. The primary function of the casing(s) is to prevent leaks to the environment and maintain pressure integrity in case of an internal tubing leak. As the weight of the casing is much greater than that of the tubing, it normally requires a significant amount of top tension to support a single or dual cased riser. For deepwater TLPs, the top tensions of traditional TTRs are a large percentage of the total payload and it requires a significant amount of hull steel to support the TTRs.
The tubing riser is a type of top tensioned riser, which has only the production tubing running through the water column. As there is no additional casing to support, the top tension required to support tubing riser is much less than for traditional casing riser. The result of using tubing riser on ultra-deepwater structures (&gt;5000 ft) is a significant reduction in riser payload.
The effective payload for TLPs would increase without increasing the displacement by using tubing risers. As a result, the amount of hull steel could be reduced without sacrificing production capacity. And, this would significantly reduce the cost of the hull.
Using tubing risers would reduce the size of air cans, most commonly used to support TTRs on Spars. Reducing air can size would significantly reduce the size of the moon pool and would, therefore, reduce the size of the hull. Even for the tensioner-supported Spar TTRs, reducing TTR top tensions would significantly reduce hull costs. The same can be said about other floating production systems using dry trees and TTRs.
Fundamentals of Buoyancy Can Riser Tensioner Systems: Performance Characterization and Redundancy Philosophy Development
Authors: Karayaka Metin 
Published: October 2008

Abstract
Buoyancy Can Riser Tensioner Systems (BCRT) are designed to provide tension to Top Tension Risers (TTRs). BCRT systems do not transfer the riser weight to the floater and minimize the interaction between the floating platforms and the riser systems. For deepwater field developments, this attractive feature allows efficient design of the floaters as well as the riser systems. A number of deepwater fields have been developed with Classic and Truss Spar floaters utilizing this class of riser tensioning systems.
The design philosophy and performance characterization of BCRTs are rapidly maturing. Recent technology advances pushed the net buoyancy capacity of BCRTs up to 1,550 kips for dual casing riser applications at 5,400 ft water depth (Mad Dog and Horn Mountain Truss Spars).
This paper presents an overview of the current state-of-theart in BCRT design and addresses some of the challenges in development of larger tensioner systems for deepwater applications.

Buoyancy Can Riser Tensioner System Components
A BCRT is primarily a passive tensioning method for TTRs. Figure 1 illustrates a TTR system tensioned by a BCRT. The BCRT is designed to have relative vertical movement with respect to the hull while transferring horizontal loads at hull contact locations. The BCRT system consists of three main segments: upper stem, buoyancy can, and lower stem. The main functions of the BCRT components are as follows:

Upper Stem.
The upper stem transfers the tension provided by the BCRT to the riser. The surface wellhead and work platform are connected to the top of the upper stem. The elevation of the top of the upper stem is selected to locate the well equipment at a favorable elevation for easy access under normal operating conditions. The stem-to-wellhead interface and all other stem-to-stem interfaces can be sealed off to provide additional buoyancy.
Figure 1 - An illustration of the BCRT components and critical elevations of a Truss Spar floater. (Available in full paper)
The upper stem is equipped with up and down stops. The stops are designed to make contact with the deck stopper and have three main functions:provide a support location to rest buoyancy can during installation operations,provide a potential barrier for riser parting, andlimit total stroke to prevent damage to the production trees and riser system.
The deck stopper is secured at the Spar deck level and restricts the lateral and rotational motions of the BCRT relative to the hull.

Buoyancy Can.
The buoyancy can provides the tension required by the riser system. It is composed of individual chambers to ensure that the failure of any one of the chamber will not compromise the riser operations. The buoyancy can chambers are filled with air or nitrogen gas.
The Use of Expandable Tubular Technology to Enhance Reservoir Management and Maintain Integrity
Authors: Innes Gareth , Craig Joe , Lavan Scott 
Published: October 2008

Abstract
In mature fields, particularly in waterflood operations, well bore maintenance and waterflood effectiveness are critical issues. Many problems can occur over the lifetime of a well that can inhibit the flood performance and create severe maintenance challenges: Some common examples of problems associated with injection wells are:Thief zones developing which take most of the injected water and which resist remediation by squeeze cementing.Heavily corroded areas of the casing string.Changes in the casing profile, such as ovalling, which can create tight spots and hinder remedial work. Conventional "patch" techniques, when applied to these situations, can result in greatly reduced thru-bores inhibiting access and restricting flow to lower zones.
A solution to these problems can be provided by the use of expandable tubular technology. In a recent field trial program, a 20 year-old water injection well in the Ventura Field in California was selected for a test of the technology. This well was chosen as it exhibited all of the above problems. A 250 feet section of 5.7" running OD expandable casing, with integral expandable hanger, was run inside 7" casing and expanded across the desired interval. The expansion was accomplished by use of a compliant rotary expansion tool. This expansion system allowed the expanded clad to conform to the irregular contouring of the corroded and ovalled casing thus enabling competent anchoring, clad to casing sealing, maximum reinforcement of the damaged section and a large thru-bore to the lower perforations. Subsequent injection logs indicated that the injected water was once again entering the desired zones both above and below the clad.
In this paper the authors will review the problems posed and present details of the planning and installation operations, particularly of the compliant rotary expansion system. They will continue with an analysis of the results achieved and conclude that expandable tubular technology is a powerful tool in remedial work for prolonging the life and improving the performance of mature wells.

The Objective
The subject well was drilled in 1981, and had been utilized as an injector for several years. The subject contained 1,300' of net perforations, from 4742' to 6577'. Injection surveys revealed that 79% of the injected water was entering a 26' section of the perforations located at 5562'. The remaining 21% of injection water was going into various perforations below the 26' thief zone. This injection profile greatly diminished the effectiveness of the sweep.
Numerous attempts to cement squeeze the thief zone had been performed over several years, only to degrade, and allow the injection profile to revert back to the previous status. A remedial solution was required to permanently alter the injection profile. A number of conventional solutions exist which attempt to address this common problem. These include casing patches, scab-liners and retrievable straddles.
New Flow Assurance Solutions to Work Out Hydrate and Paraffin Blockage Problems in Deepwaters
Authors: Marques Luiz C.C. , Pedroso C.A. , Paixão L.C.A. 
Published: October 2008

Abstract
Hydrate and paraffin blockages are the major causes of oil production losses in deepwater scenarios like the ones existing in Campos Basin area.
This paper is aimed at describing two new applications of a thermochemical method (SGN method) which has been extensively used by Petrobras (in 200+ jobs) to unplug subsea flowlines by organic deposits, viz,- to dissociate a gas hydrate buildup in a subsea christmas-tree, - and to melt a massive wax deposit accumulated in a subsea flowline ahead of a stuck pig. Both successful jobs were performed in Campos Basin, offshore Rio de Janeiro.
Hydrate formed in the pistons chamber of the christmastree- cap's locking-pins was the cause of the operational failure to re-entry a subsea well (The well's christmas-tree is at 601 m water depth). This paper describes in details the designed "tailor-made" solutions to work out the problem. It encompassed the following points: development of environmental-friendly SGN formulation, - heat-exchange simulations, mechanical modifications of the regular tree-cap releasing tool, job planning and safety procedures.
Along a routine pigging job, excessive wax was allowed to accumulate ahead (downstream) of a foam pig in the flowline of a well. This well produces to an FPSO. So, the pig got stuck. Our attempts to release it by means of standard procedures were fruitless. Therefore, an innovative engineering solution had to be developed. A sonic method was used to pinpoint the wax blockage. It also entailed spotting the thermochemical SGN fluid - with the aid of a coiled tubing unit - to melt the wax blockage ahead of the pig. There were some drawbacks we had to face to perform this job. For instance, there is no room enough in the FPSO turret area to place a regular coiled tubing(CT) unit out there. So, mechanical modifications had to be carried out to attach the CT's injection head to the FPSO's turret and to safely operate the CT unit from outside the revolving turret area. The paper also describes the kind of approach engineered to release the pig on a step-by-step basis.
To our best understanding both approaches used to work out the two described problems are sound technology innovations. They surely are unique flow assurance solutions for deepwater scenarios.

Introduction
Over the last quarter century Petrobras has concentrated most of its E&P activities in the prolific Campos Basin area, offshore Rio de Janeiro State (Figure 1). Nowadays, around 82 % of all Brazilian domestic crude output come from this province. Out of this total, production facilities located at deep (1,000+ ft water depth, 300 m) and ultra-deepwaters (4,921+ ft water depth, 1,500 m) contribute with circa 84 % of the total Basin production. It is well known that deepwater production environments bring with it additional challenges to assure maximum productivity of the wells.
Bombax Pipeline Project: Anti-Corrosion and Concrete Weight Coating of Large Diameter Subsea Pipelines
Authors: La Fontaine John , Smith Derek , Deason Gary , Adams Gary 
Published: October 2008

Abstract
The BP Bombax Pipeline Project in Trinidad involved the design and installation of a 48-inch diameter subsea gas trunk line. This line is the largest subsea pipeline operated by BP in the world. The immense scale of this pipeline and associated appurtenances provided many design and construction challenges, among these was the selection and application of the anti-corrosion and concrete weight coating systems. Compounding this challenge was the requirement that the system have a design life of 50 years.
Coatings are the primary method of protecting the external surface of metallic structures from the corrosive effects of seawater and sediment. Typically the coating system is supplemented by a cathodic protection system.
Concrete weight coating is commonly employed on large diameter pipelines to increase on-bottom stability. A number of concrete coating application methods were evaluated and two such methods were employed. Wire reinforcement is required within the concrete to minimize spalling. Due to the unprecedented size of the main trunkline, common reenforcement practices were analyzed to ensure success.
Bonding between the concrete weight coating and the corrosion coatings is of paramount concern on large subsea pipelines to prevent slippage due to the high lay-tensions imposed on the pipeline during installation. In order to select the optimal system, several bonding methods were tested for use on the project.

Introduction
In response to the increasing demand for energy in the form of natural gas, BP Trinidad and Tobago has started expanding its offshore fields and gas transportation system to supply new LNG trains at Point Fortin on the West side of Trinidad as well as the increased local domestic market. There are two projects currently underway to expand production and transportation of gas from 1.5 bscfd to 3.0 bscfd, the Kapok Project and the Bombax Project. The Kapok Project comprises a new 2.6 BCFPD production platform, Cassia 'B' that is bridge connected to the existing Cassia 'A' platform and a new drilling platform Kapok. The Bombax Pipeline Project includes 63 km of 48-inch offshore pipeline from Cassia 'B' to landfall at Rustville, on the East Coast of Trinidad. From the landfall, the pipeline extends 1.8 km onshore to the existing Beachfield slug catcher and production facility for onward transportation of gas to the various industries on the island including the LNG facilities on the West Coast. The offshore end of the 48-inch pipeline is connected to the existing 40-inch pipeline via a 20-inch subsea jumper. This jumper facilitates looping of approximately 2/3's of the existing 40-inch pipeline thereby expanding the transportation system capacity.
Additional gas production to meet the growing industrialdemand will be supported by a new wellhead platform located at the Kapok field along with continued development of existing fields.