bluuebunny/crossref_metadata_2025 huggingface dataset:
Canyon Express - Qualifying for the Deepest Development
Authors: Nelson Stuart G. , Wells Hal C. , Huntoon George
Published: October 2008

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

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 (>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 (>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

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

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

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

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.
CNG Transportation Utilizing Composite Pressure Vessels
Authors: Campbell Steven
Published: October 2008

The Trans Ocean Gas CNG transportation method, which utilizes composite pressure vessels and modular cassettes to store natural gas, overcomes the safety, corrosion, excessive weight, and cost deficiencies of all other proposed CNG trans-portation methods. The method also has the ability to extract NGL's while on route, removing the requirement of stripping gas on an offshore structure.

Introduction

The following paper describes an innovative method of CNG transportation. The method utilizes composite pressure vessels which are derived from the national defense / aero-space, and natural gas vehicle industries. The method over-comes all of the deficiencies anticipated from other proposed methods of CNG transportation that propose to use steel based gas containment systems.

Existing container ships may be optimized through the use of the cassette gas containment system. The cassette system also isolates composite gas pressure vessels from ship-induced forces. Being modular, installation and removal of cassettes would be relatively easy. The cassette storage system will provide significant economic advantage over potential com-petitors commencing with a pilot project. This paper will conclude that The Trans Ocean Gas CNG Transportation Method, offers a high level of safety, reliabil-ity, and economic feasibility.

Background.

The first Compressed Natural Gas (CNG) pilot project using steel pressure vessels mounted on the deck of a ship was conducted off the coast of New Jersey in 1966. It was concluded as not being feasible since the weight of steel pressure vessels required would be too heavy for the host ship to carry. CNG development then stagnated for thirty years.

Over the past decade, the increased lucrative potential of CNG has renewed interest and spawned several innovative concepts. All but one proposed method use steel containment systems, which still have issues of safety, corrosion, excessive weight, and cost. All of the proposed methods using steel con-tainment systems are requesting factors of safety less than that of the ASME code.

In 1999, author, Mr. Steven Campbell developed a method of CNG transportation that overcomes all of these deficien-cies. This method, licensed exclusively to Trans Ocean Gas Inc. of St. John's Newfoundland, proposes to use composite pressure vessels (CPVs) to safely and cost effectively trans-port up to 1.7 Bcf of natural gas by ship.

CPVs have been successfully used in the national defense / aerospace industry since the early 1970's. About 10 years ago, the natural gas vehicle industry started using CPVs for busses, fleet vehicles, and automobiles. CPVs are also used as accumulator bottles for riser tensioning systems on oil and gas TLPs. The CPVs proposed for a ship-based CNG transporta-tion method are similar, but larger than those currently used for natural gas driven buses. Since CPVs have been success-fully used to store natural gas for fuel on public busses, they are well justified for use in a ship-based CNG transportation system.
New Build Generic Large FPSO
Authors: Le Cotty A. , Selhorst M.
Published: October 2008

The increasing demand for FPSOs and constant pressure for ever shorter delivery times has motivated SBM to design conversions and new-build hulls in a generic manner.

SBM has been designing successfully generic FPSOs using converted VLCC hulls, based on a rationalized deck layout with integrated power generation and process equipment.

Over a period of 3 years, this generic conversion design has been applied to a series of 7 FPSOs that will be briefly described in this paper.

In order to meet the increasing world-wide demand for large new-build hulls, SBM has designed a generic hull with a storage capacity of 2mmbbls or 2.4mmbbls, capable of supporting large topsides with a high level of flexibility in the process layout and using a similar philosophy to that developed for the generic hull conversions. Typical machinery and accommodation blocks are proposed permitting future modifications to be tailored to specific requirement.

This new-build hull design will permit fast track hull construction and FPSO delivery.

Introduction

FPSO designs, whether based on converted tanker or new-build hulls, are governed by a number of key technical factors:- typically the storage capacity, production capacity, export capacity, site environment and crew complement.

However, a key non-technical factor affecting the entire project organization and major technical decisions is time schedule which is a significant challenge for designers.

There is obviously a need for a fast track method for building or converting FPSOs. However, it is unreasonable to expect to simply squeeze indefinitely all project activities to achieve significantly reduced delivery times: this would result in unacceptable risks during design and construction, with commensurate risks to the performance of the unit.

Those conflicting requirements triggered an alternative approach to manage a fast track FPSO project, the so-called generic approach.

At the end of 1999 SBM and Gusto invested time in screening all aspects of tanker conversion; defining a basis of design suitable for a wide range of applications and carried out an internal engineering study in preparation for expected future FPSO conversion projects.

This investment proved to be very fruitful. The design was used in several projects including the FPSOs Falcon, Atlantic and Serpentina for ExxonMobil, FPSO Espadarte, Brasil and Marlim Sul for Petrobras and FPSO Mystras for Agip. The design is also currently proposed on many other projects.

Despite the success of generic conversions, new-build hulls may be required for FPSO projects.

This paper will first address FPSO conversion background and explain the main drivers for new build hulls.

Then, the generic hull, including the basis of design, the structure, the hull systems and the interfaces with topsides plant, will be presented.

Finally, construction phase and operational feed-back will be addressed briefly based on the experience gained as both prime contractor and leased vessel operator.
Consideration of Collision and Contact Damage Risks in FPSO Structural Designs
Authors: Wang Ge , Jiang Dajiu , Shin Yung
Published: October 2008

FPSOs have a risk profile different from fixed platforms and commercial trading tankers. Being stationed in one location and routinely visited by supply boats and shuttle tankers. FPSOs can be collided by these ships. In addition, passing ships also pose a collision risk if an FPSO is close to a sailing route.

This paper presents a systematic approach to address the risk of collision and contact damage. It is aimed to propose a framework that can be applied in structural designs and risk assessment schemes. The focus is placed on accident scenarios, evaluation approaches and acceptance criteria, the three major issues for a risk assessment and also for a relevant design standard.

Accident scenarios and the associated occurrence frequency may be determined through statistics from historical data, expert opinions, and risk analysis, depending on different situations.

A spectrum of tools has been developed in recent years that predicts the structural damage of collisions, including simple formulae, simplified analytical methods, simplified FEM, and non-linear FEM simulations. Those based on the advanced structural crashworthiness theory provide powerful and practical tools, and are well suited for design evaluations and risk analysis.

Contact damage is more likely to occur than accidents resulting in rupture of shell plating. However, this type of accident has received very limited attention. An analytical approach is presented for analyzing contact damage that can be used during earlier design stage.

Acceptance criteria for collision and contact accidents are discussed. The emphasis is on structural integrity including local strength and hull performance.

Introduction

FPSOs have a risk profile different from fixed platforms and commercial trading tankers. Being stationed in one location and routinely visited by supply boats and shuttle tankers. FPSOs can be collided by these ships. In addition, passing ships also pose a collision risk if an FPSO is close to a sailing route.

A collision accident can lead to costly consequences in loss of lives, damage to property and/or environment. As past accidents have demonstrated, the indirect cost of compensation and bad publicity can be even higher. This has been the driving force in recent years for developing standards for design against collision accidents for trading oil tankers.

A collision with low kinetic energy can result in permanent deformations of side structures instead of rupture of side shell. This low-energy collision is sometimes called "contact accident". Usually, contact damage is not catastrophic and does not pose a threat to the safety of the installation and the protection of environment. Contact damage receives little attention.

This paper presents a systematic approach to address the risk of collision and contact damage. It proposes a framework that can be applied in structural design and risk assessment. Discussion is given to accident scenarios and acceptance criteria.
Wireless Transfer Successfully Transmits Bottomhole Data During Drill-Stem Testing in a Multi-Well Program Offshore Gabon
Authors: Dunkel Michael , Leonard Paul , Carpenter Don , Murray Chris
Published: October 2008

Conducting a drill stem test (DST) to gather data to evaluate the potential of a new field is a common practice in the oil and gas industry. In the past, gathering this data was performed by running a surface read-out tool in the drill string. Then, wireline would be used to deploy a tool into the well and latch it into a surface readout (SRO) tool downhole. Bottomhole data could then be generated during well shut in. This method worked satisfactorily for shut-in periods; however, this scenario was difficult to achieve while flowing the well.

This paper will discuss an innovative real-time subsurface data acquisition solution that uses a state-of-the-art Acoustic Telemetry System (ATS) to gather data both during the flow period as well as when the well is shut in, thus allowing realtime readout at the surface. The new system distinguishes itself from conventional surface readout (SRO) systems because it sends data through the tubing wall using acoustic energy rather than running a probe using wireline to latch into the gauges as is the case with traditional systems.

Pioneer Natural Resources successfully used the acoustic telemetry system to transmit bottomhole pressure and temperature data to the surface in real time during four separate drill stem tests in three different exploratory wells offshore Gabon. This was the first time this new technology had been used on a multi-well project. The data that were transmitted from down hole matched the data that were downloaded from the downhole memory gauges that were retrieved when the DSTs were ended.

The ATS was capable of providing accurate surface readout data from the beginning of the test, allowing Pioneer to better understand the downhole conditions, and consequently, execute a DST that could meet all the objectives for testing in these zones. In addition, since there were risks that sand production, paraffin deposition, and low pour-point crude could impair the integrity or stick the wireline if it were used for data transmission in these wells, the ATS enabled the needed information to be retrieved without compromise to safety or the environment.

Introduction

The scope of a DST can range from a basic test (such as an openhole test in an onshore area in which there is no flow to the surface) to a complex, cased-hole test (such as one that would be run in the North Sea flowing at surface for many days).1,2,3,4 Analysis of the DST data is used for making decisions concerning completion/field development or drilling continuation. The data acquisition is defined by the test parameters, which generally require both surface and downhole inputs. Usually, bottomhole data acquisition has been performed by a surface read-out (SRO) system, and wireline in some form (braided or slickline) is needed. The traditional drill stem testing procedures use wireline to deploy probes to acquire whatever information from downhole is needed to obtain the information required.
Field Trials Scheduled for New Compact Dehydration Technology
Authors: Sams Gary W. , Wallace Harry G.
Published: October 2008

Significant improvements in the capacity and performance of existing oil dehydrators and desalters are expected from an improved, patent pending, transformer and controller system. This electrostatic system is now ready for a field trial in South America. Production at the selected facility is currently at 45,000 bopd per unit on a medium gravity crude oil. This oil is currently being processed by five 10-ft. diameter × 45 ft. long electrostatic dehydrators using combined AC/DC electrostatic technology. Pilot studies utilizing the improved transformer / controller have demonstrated capacity improvements exceeding 30% above existing technology or outlet BS&W reductions between 10 to 30%.

To confirm these results and define the limits of this new technology, a series of scheduled field trials has been planned. In addition, several other vessel modifications will include upgrading the inlet spreader design, and installing new high voltage electrodes.

Once these improvements are made and the new compact electrostatic technology is implemented, it is estimated the vessel capacity will increase significantly, while maintaining the required oil specification. If successful, this electrostatic transformer and controller may provide producers and refiners with a new technology to process highly conductive, viscous oils.

Testing Objective

Utilizing a South American oil facility, a new electrostatic dehydration technology is scheduled to be field tested. The objective of these tests is to quantify improvements to the oil dehydration process, demonstrate the robustness of the equipment and establish confirmation of the laboratory test results.

Facility

The production facility shown in Figure 1 has five oil dehydration vessels operating in parallel. Each horizontal dehydrator is 10 ft OD × 45 feet long × 125 psig with Dual Polarity® electrostatic technology, open bottom spreaders, either steel or composite high voltage electrodes and pipe collectors. The Dual Polarity transformers are 480 volt, single phase rated for 150 kVA. Following an upgrade of three vessels to improve performance, a fourth vessel is scheduled to be retrofitted with a new electrostatic transformer including step/start switchgear and PC-based process controller. The facility has the capability to increase the oil flow to the test vessel so the limits of the technology can be investigated.

Application

The facility is currently processing a 27.1 API oil at flow rates varying between 45,000 bopd to 60,000 bopd per vessel. The operating temperature is maintained at 140 F and the operating pressure is 80 psig. At operating temperature the dry oil viscosity is 8.9 cp. The inlet water cut typically ranges between 20 to 30%. The outlet specification is less than 1% BS&W and is routinely met by the dehydration process.
The Use of Scatter Diagrams in the Selection of Design Current Profiles for a Riser Experiencing Vortex-Induced Vibration
Authors: Donnelly Jessica Mary , Vandiver J. Kim
Published: October 2008

This paper describes a scatter diagram approach for the classification of large numbers of current profiles for use in the prediction of riser fatigue damage due to vortex-induced vibration. Scatter diagrams have long been used to characterize the probability of various combinations of wave height and period, which are then used to assess wave forces. To predict VIV fatigue damage the designer needs to know which current profiles have the combined property of long regions of relatively constant velocity and relatively high speed. A sorting algorithm is proposed which searches every current profile for long regions of relatively constant flow speed. The probability of each length and speed combination is assessed and the data is used to populate the bins of the scatter diagram. The designer need only select relatively few representative profiles for detailed VIV analysis from those bins that would account for the most damage. The method is tested by making comparison to a brute force approach in which each of many thousands of profiles is evaluated for fatigue damage by running it in the SHEAR7 VIV response prediction program.

This scatter diagram method could reduce the cost of risers by reducing the over-conservatism that is introduced by using an envelope design current profile. It also reduces analysis time by helping the designer choose a small number of profiles to examine, rather than having to consider the tens of thousands of profiles contained in a typical data set.

Introduction

Motivation

Before a riser can be designed and deployed in a new location, information on the local currents must be obtained. Because this data often consists of tens of thousands of measured current profiles, it is difficult to know which ones are important for riser design. To overcome this difficulty, current industry practice is to prescribe a conservative design profile, based on the data set. One type of design profile is the envelope of maximum values. This profile is found by plotting the maximum velocity found in the data set at each measured depth, and incorporating these points into a single "envelope profile". Therefore, at any point along the riser, the greatest velocity to be found at that depth in the entire data set will be used. Sometimes a "slab" of constant velocity is drawn in the region of the peak of the envelope profile (the area of highest velocities). An example of this method is shown in Figure 1. In this case, the envelope and slab were produced using 1000 profiles gathered over the course of one current ring event. These conservative design profiles don't actually occur in nature, and usually result in much higher damage rates due to vortex-induced vibration (VIV) than any measured profile. So any riser designed to this specification will be built far more conservatively than the actual currents in the region require.
Probabilistic Fault Displacement Hazard Assessment For Flowlines and Export Pipelines, Mad Dog and Atlantis Field Developments, Deepwater Gulf of Mexico
Authors: Angell M.M. , Hanson K. , Swan F.H. , Youngs R. , Abramson H.
Published: October 2008

Seafloor faults having strong geomorphic expression and evidence for late Quaternary activity (i.e. < 150,000 years) are common geologic features associated with the Sigsbee Escarpment. Waterbottom maps derived from exploration 3D multichannel seismic data provided an early indication that several zones of seafloor faults are in the vicinity of the Mad Dog and Atlantis prospect areas. As part of the site investigation activities for field development BP initiated a study to characterize the potential hazard due to fault displacement. The fault displacement hazard study consists of five components:a site-wide structural geologic characterization of the style and origin of active faulting and fault-related deformation;development of a late Quaternary stratigraphic model to evaluate the history, recency, and rate of fault activity at the site;detailed characterization of faulting within limited study areas designated to capture fault behavior in areas of potential facilities development;a general description of the relationship between Quaternary active faulting and slope failure processes within the field area; anda probabilistic fault displacement hazard analysis (PFDHA) of the potential for fault rupture within the designated study areas that relates annual frequency of recurrence of faulting events to the size of the event.

Changes in the style and origin of faulting and deformation of shallow (suprasalt) sediment across the individual field areas primarily is due to differences in the depth, geometry, and movement history of the underlying Sigsbee Salt Nappe. These relationships and the resulting geologic model for structural evolution of the suprasalt section has been used effectively to assess the site-wide geohazards not only for faulting, but also indirectly for slope failure and mass-gravity flows.

Hazard from potential seafloor offset at fault crossings is judged to be moderate to low. Fault offsets of the shallowest horizons (less than 15 thousand years old) are typically less than ten meters to several tens of meters. Fault slip rates are on the order of tenths to several tens of metersper- thousand-years (m/kyr, also millimeters-per-year, or mm/yr), with most values in the range of 2-10 m/kyr Similarly, the probabilistic annual recurrence of 1-meter events is typically less than 10−3.

These studies demonstrate that the presence of potentially active faults does not preclude safe development of seafloor facilities. To evaluate risk associated with potential seafloor faulting, integrated hazard studies can and should be conducted in the early stages of project development, with an underlying intent to understand the causative processes and quantitatively and explicitly evaluate the locations, magnitude and recurrence potential of displacement events.
Optimization of Stable Platform Characteristics
Authors: Horton E.E. , McCammon L.B. , Murtha J.P. , Paulling J.R.
Published: October 2008

A procedure termed "hydrodynamic synthesis" was described in several earlier papers and has proven successful in predicting the wave-induced motions and anchoring forces for semisubmersible stable platforms. Such a platform responds as a resonant oscillating system to a forcing term whose amplitude and phase vary with frequency. The variation of force amplitude stems from the variation of phase of the forces on various members of the structure. The possibility is explored of exploiting both the frequency response characteristics and the force amplitude characteristics to design platforms of minimum motion or anchor line forces. Several examples are worked out by the hydrodynamic synthesis procedure from which it is concluded that resonant detuning is more important than force minimization in optimizing the heave motion of a floating platform. For the tension leg platform, however, the minimization of wave forces on the structure provides the best means of optimizing anchor cable loads.

I. Introduction

In two earlier papers, Paulling (1970), and Paulling and Horton (1971) have described a procedure which has proven to be quite successful in predicting the wave-induced motions and anchor cable forces for stable floating platforms. This procedure, termed "hydrodynamic synthesis" utilizes a linearized hydrodynamic analysis for predicting the wave forces on the structure. The principal assumptions made in the procedure are as follows:The motion amplitudes for the platform and waves are small.The structure is composed of an assemblage of either cylindrical "members" whose cross sectional dimensions are small compared to their lengths and to the wave length, or small volumes all of whose dimensions are small.The forces are computed for an individual member of the structure as though other members were not present, i.e., hydrodynamic interference between members is ignored.The forces associated with wave motion are computed independently of the forces associated with the absolute motion of the structure.

The structure is then treated as a rigid body having six degrees of freedom for which the equations of motion take the form(Available In Full Paper)

The equations of motion are solved to obtain the × j (t) which describe the motion of the body as a function of time. For an anchored structure, a knowledge of this motion may be then used to deduce the anchor cable forces. If some of the restoring force terms, c ij, are nonzero, the structure will respond to the exciting force as a multidegree of freedom oscillating system. For small values of the damping coefficients, b ij, it is well known that the response, defined as the ratio of the amplitude of motion to the amplitude of the incident waves, becomes large for wave frequencies in the vicinity of the undamped natural frequencies of the system. These natural frequencies, wn are computed by finding the eigenvalues of the system of homogeneous equations corresponding to the undamped free motion of the system,
Semisubmersible Based Dry Tree Platform with Compliant Vertical Access Risers
Authors: Mungall Chris , Haverty Kevin , Bhat Shankar , Andersen David , Sarkar Indranil , Wu Jack , Mårtensson Houston Nils
Published: October 2008

It is shown in this paper that a semisubmersible-FPS can be used as a dry tree platform in ultra-deep water Gulf of Mexico when designed with Compliant Vertical Access Risers (CVARs). The Technical feasibility of the proposed dry tree semi concept is demonstrated by an example application in 8,000 ft water depth. Riser extreme response, interference and fatigue have been analyzed. Installation schemes have been considered. It is concluded that the proposed dry tree semi concept is technically feasible and that it can provide an attractive lower cost solution for dry trees in the ultra-deep parts of the Gulf of Mexico.

Introduction

Dry tree platforms have been used in the Gulf of Mexico in water depths up to 5,400 ft. Studies have shown that it becomes expensive to extend the application of conventional dry tree platform concepts (TLPs and Spars) to ultra-deep water depths such as 8,000 or 10,000 ft. We propose an alternate dry tree platform concept to provide operators with the benefits of direct access to wells from lower cost floating systems such as the semisubmersible-FPS (henceforth 'semi- FPS'). Dry tree wells are tied back to the semi-FPS using Compliant Vertical Access Risers (see Figure 1). The CVAR is attached rigidly to the semi-FPS (see Figure 2) via a flexjoint or a tapered stress joint avoiding the need for flexible jumpers and simplifying deck layout. Unlike a Spar or a TLP, there is no relative motion between the riser top and the vessel in operation, simplifying access to the dry trees and well access during workovers. At the sea floor the CVAR is attached to the wellhead in much the same manner as a Top Tensioned Riser (TTR).

The CVAR, like Spar or TLP TTRs, has the benefit that the riser is vertical at its top and bottom - permitting vertical access. TTRs obtain their compliancy by virtue of relative motion at their tops which is accommodated by tensioner or buoyancy can stroke. CVARs obtain their compliancy from excess riser length. Since the buoyancy is distributed approximately in the middle portion of the riser CVARs have the characteristic shape shown in Figure 1.

Background

The idea of the CVAR dates back (at least) to 1988 when a patent was awarded to Pearce et al [1] for a flexible riser and associated equipment that could be used to obtain vertical access to a subsea well. (The patent belongs to Halliburton/KBR.) KBR carried out a number of early studies in the late 1980s and early 1990s on the feasibility of using CVARs as production and workover risers from floating production systems in 3,000 to 6,000 ft depths. Brinkmann and Whooley [2] describe the use of CVARs with a Spar (also known as Deep Draft Caisson Vessel or DDCV) in 4,800 ft of water in the Gulf of Mexico. However, a study on this subject has not been reported so far.