bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling Well Control Practices and Equipment Considerations for Deepwater Operations Plans
Authors: Montgomery Michael E. , Leach Colin P.
Published: October 2008

Everyone recognizes the higher costs and technical challenges associated with drilling in deeper waters. As more information about operating in this frontier becomes known, planning and preparation can improve, reducing costs and risks. This paper will discuss well control issues associated with drilling. It will compare and contrast the requirements of the US MMS (Minerals Management Service), the UK and Australian Safety Case and Verification Schemes, and the Regulations and Guidelines of the NPD (Norwegian Petroleum Directorate). Of particular interest is hazard and risk analysis.

For effective risk analysis, one must first identify the magnitudes and type of events that may occur during a drilling or well control operation. Then, the operational capabilities and limitations of the equipment used to deal with such events can be explored to ensure they are fit for purpose. The net result is that not only can hazards be identified, but also their potential consequences estimated - the very essence of a good hazard analysis. As a result, the operator generates information that will improve the safety of his operation as well as his drilling effectiveness and (as a by-product) meet regulatory mandates.

Introduction

Every drilling program includes risk analyses, completed either explicitly or implicitly. As such, they are conducted for many reasons, including regulatory and prudent business practice. Although more comprehensive analyses undoubtedly reduce risk to a greater level, the expected fruit must be balanced against cost.

For the complete drilling process, assessing risks and consequences associated with well control and blowouts is a complex procedure. Fig. 1 (courtesy RF Rogaland) indicates some of the complexities of the procedures and the issues that must be addressed (1).

Fig. 1: Example of a comprehensive kick risk analysis (Available in full paper)

The results shown in the figure are in the form of probabilities of a kick occurring. The figure is included simply to indicate the scope of a complete analysis. No attempt is made in this paper to show how this complete analysis is carried out. It is only possible to quantify the risks and consequences if sufficient analysis is carried out to allow a process to be broken down into simple steps that then allows for a quantitative (or semi quantitative) assessment of failure on the part of an expert.
Installation of the Baldpate Compliant Tower
Authors: de Koeijer D. , Renkema D. , Edel J.C. , Willis C.H. , Payne D.
Published: October 2008

The Baldpate compliant tower, in Garden Banks block 260 in the Gulf of Mexico, is the first free standing, non-guyed compliant tower. Situated in 1,648 ft of water, it measures 1,900 ft. from the flare tip to the sea floor. The tower is a 19-slot drilling/production platform set over a 9-slot drilling template, has production facilities for 60,000 BOPD and 200 MMSCFD, and supports two steel catenary export risers. The tower was installed in the spring of 1998.

The tower has four basic structural components; the foundation piles, jacket base section (JBS), jacket tower section (JTS) and deck. Load-out weights for these were approximately 5,000 s. tons, 9,000 s. tons, 20,000 s. tons, and 4,000 s. tons respectively. This paper focuses on the installation of these components and also on the installation of the drilling template (Installed in 1994) and the docking and leveling piles (installed in 1996). Unusual aspects of the installation included the use of leveling piles instead of mud mats, deep lowering operation for the massive jacket base section; handling 530-feet long single-piece foundation piles and driving them with a single underwater hammer; launching of the jacket tower section from a launch barge that it exceeded in length by some 750 feet; and vertical mating of the two sections of the jacket at a depth of 1,300 feet.

Introduction

The Amerada Hess Baldpate compliant tower is located in the Gulf of Mexico in Garden Banks block 260 at a nominal water depth of 1648 feet. Particulars of the docking and leveling piles, the jacket base section, the skirt piles and the jacket tower section are;

Docking Piles (2 no.)

Dimensions : 84 inches O.D. × 206 feet Weight (dry) : 175 short tons (each)

Leveling Piles (4 no.)

Dimensions : 60 inches O.D. × 250 feet Weight (dry) : 125 s. tons (each)

Jacket Base Section (JBS)

Dimensions : 355 feet high, bottom 140 × 140 feet to leg centerlines, top 90 × 90 feet Weight (dry) : 9,000 s. tons

Foundation Piles (12. no)

Dimensions : 84 inches O.D., 531 feet Weight (dry) : 480 s. tons (each)

Jacket Tower Section (JTS)

Dimensions : 1410 feet high (including stabbing pins), bottom 90 × 90 feet, top 90 × 90 feet Weight (dry) : 20,000 s. tons

The contract for the transportation and installation of the platform components was awarded in February 1996 to HeereMac. Installation of the docking and leveling piles was completed in September 1996. Installation of the other platform components was completed in June 1998.
Numerical Prediction of VIV on Deepwater Risers Subjected to Shear Currents and Waves
Authors: Dalheim Joar
Published: October 2008

A numerical procedure to solve the coupled motion of a flexible riser and a viscous incompressible fluid is developed. In this study, the former is solved by a multi-modal response model and the latter is solved by a sectional solution (strip theory) method. In every fluid section the 2D-vorticity equation is solved by a Vortex-in-Cell method and the different fluid sections are coupled through the boundary conditions from the motion of the riser. This procedure is used to solve the vortex-induced vibration (VIV) response of flexible risers. Both vertical risers and steel catenary risers are predicted by the present method. The method can also be used to solve the coupled motion of two or more flexible risers. A fatigue analysis module is included in the numerical package. The present method is validated against experimental tests and other numerical tests, and the riser response and fatigue life is found to be in good agreement. The numerical results are visualized to obtain better understanding of the computed results and the phenomenon.

Introduction

As the oil industry is moving into deeper and deeper waters, the structures are becoming more and more slender and hence prone to vortex induced vibrations and large displacements. When one or more risers are exposed to a sheared current there will almost always be induced some kind of vortex-induced vibration. In order to be able to predict the fatigue damage caused by these transverse vibrations it is crucial to know which modes that will dominate the response of the risers and at what amplitudes they are responding. In addition, if more than one riser is analyzed, it is important to be able to predict the coupled response of the riser system. And numerical tools with this feature included will be of great support to the oil industry. In order to help the engineer to understand the motion of long and flexible cylinders (e.g. risers and anchoring cables) in fluid flow, a computer program with the capability of visualizing these motions is developed. A modal analysis is used to predict the cylinder motion, and the fluid domain is solved by the vortex in cell method. General physical equations are utilized in order to make an effort of making the computer program general and being able to solve a number of different classes of VIV problems (such as collision of multiple risers, steel catenary risers, deepwater risers, surface waves, etc.).

The remainder of this paper can be outlined as follows: the next section describes the fluid solution procedure, then the structural response prediction is reviewed, and then the fluidstructure interaction procedure is discussed. This is followed by some numerical results and some concluding remarks.

The Fluid Solver

The fluid domain is modeled by a so-called strip theory in which the fluid is divided into 2D sections (Fig. 1) along the span of the riser. On each of these sections the fluid flow is found by solving the vorticity equation.
Highly Compliant Rigid (HCR) Riser Model Tests and Analysis
Authors: Grant Robert G. , Litton Richard W. , Mamidipudi Partha
Published: October 2008

A 1998 Joint Industry Project performed large-scale model tests and analysis of three Highly Compliant Rigid (HCR) riser configurations. The tests were conducted in about 800 ft of water. The objective was to reduce operator cost and risk by improving and verifying riser analysis methods. This was accomplished by a 3 step sequence of pre-test analysis, physical model tests and comparison of analysis with test results. The pre-test analyses were performed by 13 independent organizations using 11 riser analysis computer programs. The subsequent model test results were used to improve and verify the analysis procedures. The model tests taught many lessons including the importance of the seafloor soil and intermittent vortex induced vibration (VIV) to the overall riser response. Riser analysis programs available today have very limited capability to model the soils, and are unable to model intermittent VIV.

Introduction

The cash flow from industry's future "billion dollar" deepwater field developments will depend on risers. In very deep water, complex steel/polymer flexible risers ("flex risers") may not be technically or economically feasible, especially in larger diameters, because of their relatively high weight and cost. A reliable alternative would be attractive.

"Flex risers" are typically specified because of their capability to bend in response to floating platform wave motions without incurring excessive fatigue damage. Their bending flexibility also simplifies installation. However, in deep water where vessel motions are a relatively small fraction of water depth, simple rigid pipe can be configured into overall shapes that provide the compliance needed to absorb platform motions. Their key design basis parameters are diameter, internal/external pressure, water depth, platform motion characteristics (e. g., ship, spar, semisubmersible, TLP) and wave environment.

HCR risers have clear benefits over "flex risers" but present new design and analysis challenges. One of these challenges derives from the cyclic tension introduced by platform heave motions which makes bending stiffness highly variable and makes the problem highly non-linear. The cyclic tension can produce short periods of compression and negative bending stiffness that causes difficulty for some solution schemes. While there are several riser analysis programs available to the industry that address these computational requirements, there is little model or full-scale test data available for their validation.

A key objective was to determine if the buckling predicted by some analysis programs is an artifact of the modeling or if it really occurs. If it does occur, then it was an objective to assess the accuracy of programs in predicting the onset of buckling. Another objective was to determine the magnitude of the effect of sea floor soils on riser response.
Load Monitoring at the Touchdown Point of the First Steel Catenary Riser Installed in a Deepwater Moored Semisubmersible Platform
Authors: Edwards Roderick Y. , Machado Remo Zauli , Hennessy William F. , Campman Craig R. , Bailon Hector
Published: October 2008

A 10-inch Steel Catenary Riser (SCR) was installed in the Petrobras XVIII semi-submersible production platform, moored in 910 meters water depth in the Marlim field, Campos Basin, offshore Brasil. This is the first SCR ever installed on a floating moored platform.

In order to evaluate and verify the methodologies and to calibrate the numerical models used in the riser, mooring system, and platform design, it was necessary to establish a monitoring program for all the relevant parameters (environmental, platform positions and motions, riser loads and stresses at the top and at the touch down point (TDP), and vortex induced vibrations).

The TDP monitoring system consists of several strain-gage collars in pipe sections close to the TDP, subsea strain conditioning, control and data storage electronics, and an acoustic telemetry data transmission system. Mobilising this complex system required several innovative solutions.

The paper describes the monitoring system developed to measure tension and moments at the Touch Down Point (TDP) region of an SCR, its installation and operational aspects, and its performance to this date.

Introduction

As part of its continuing effort to develop hydrocarbons in deep water responsibly and cost effectively, Petrobras initiated a project to assess the feasibility of using Steel Catenary Risers (SCR) on moored, floating production platforms in deep water. Numerical analyses to predict the stress history in the touch down region of the SCR sometimes presented different results depending on the numerical model used. Accordingly, Petrobras considered it essential to obtain full-scale data from a prototypical 10 inch SCR installed in the PXVIII, a semisubmersible FPSO moored in 910 meters of water. The experiment was outlined by the Petrobras R&D Center's Exploitation Projects Division. Its Subsea Engineering Group prepared Technical Specifications for the Environmental, Platform Positions and Motions, Top Loads, TDP Loads and Vortex Induced Vibrations Monitoring Systems and its processing, and is conducting this monitoring project. The measurement of the stresses in the touch down point of an SCR in deep water had never been done before and presented several difficulties. This paper describes the development of a monitoring system to do that.
Performance Record for FPSOs and Shuttle Tankers
Authors: Wallace Kimberly M. , Zaner Stacy A.
Published: October 2008

Industry interest in tanker-based floating production systems in the Gulf of Mexico (GOM) has brought forth the need to evaluate the worldwide performance of these systems regarding oil spill safety. This paper discusses the incidence of oil spills from Floating Production, Storage and Offloading (FPSO) systems and shuttle tanker operations throughout history, based on public data and a recent industry survey. Oil spill statistics are presented considering the following factors:Geographical locationVessel type and sizePrimary operation in progress at the time of the incidentCause of SpillSpill volume

Results indicate that oil spills from FPSOs and shuttle tankers are very rare, and the industry can continue its aggressive pursuit for utilization of an FPSO in the Gulf of Mexico.

Introduction

During the past 22 years, tanker-based floating production systems (FPSOs) have been utilized in a wide variety of water depths, weather conditions and field types. These systems are among the most flexible options for developing offshore oil fields. Generally, a newbuild FPSO is designed for a field life of 20-25 years and a tanker converted for FPSO service is designed for a field life of 10-15 years. However, Walter Winkworth, Manager of Offshore Services for Lloyd's Register of Shipping, states in an OCS report that FPSOs can be designed for a field life of up to 50 years (for a shallowwater, nearshore FPSO)1. FPSOs can also be used on a shortterm basis for an Extended Well Test (EWT), an Early Production System (EPS), or can be relocated for use on multiple fields. They can be designed to operate in water depths as shallow as 50 feet to extreme deepwater, and a wide range of weather conditions.

FPSOs are suitable for several scenarios that are applicable to the GOM, as listed below:In a marginal field, an FPSO can provide full-scale production operations without the expense of a purpose built fixed facility. The FPSO can then be re-used elsewhere, thereby saving money for the field owner.EWT or EPS operations require a temporary installation such as an FPSO.Ultra deepwater fields can be developed with the use of an FPSO. With an FPSO, a massive structure is not required in order to develop the field, as is the case with a Tension Leg Platform (TLP) or other fixed structure, since an FPSO is not sensitive to topsides weights or space restrictions. Note: Reserves totaling more than 4 billion barrels of oil have been located in water depths ranging from 1600 feet to 5900 feet (500m to 1800m) in the Gulf of Mexico in just the last six years.2An FPSO can be designed to stay on location during a hurricane or be able to eave the operating site during thes torm.Remote field locations, far from existing platforms or pipelines, can be developed with an FPSO since it provides its own storage and offloads to shuttle tankers. This eliminates the necessity of an oil sales pipeline.
Overview of Britannia Subsea Corrosion-Control Philosophy
Authors: Kolts J. , Joosten M. , Salama M. , Danielson T.J. , Humble P. , Belmear C. , Clapham J. , Tan S. , Keilty D.
Published: October 2008

The overall corrosion control and sand production management philosophy for the Britannia subsea development is outlined. The philosophy includes the materials selection for wells, manifolds, and flowlines, corrosion control by inhibition, and sand erosion prediction and monitoring. Comprehensive corrosion and erosion monitoring systems have been installed to assure the integrity of the subsea system. Finally, the corrosion control philosophy was developed and integrated into the operating philosophy and practice.

Introduction

Britannia is a corrosive gas-condensate field in the North Sea. The general concept for corrosion control in the subsea system was to use corrosion resistant materials in the wells, jumpers, and manifold, and carbon steels with corrosion inhibition in the subsea flowlines. In addition to the corrosivity of Britannia, the system was designed to control erosion. To ensure the integrity of the production and process systems, erosion at high flowrates, sand settling, and inhibitor effectiveness under sand beds were addressed.

The Britannia conditions subsea will be to temperatures of 115°C and CO2 partial pressures in flowlines to about 6 bar (85 psi). For pure water, this relates to a pH of 3.9. The velocity in the subsea flowline may be up to 18 m/s (60 ft/s). This could be higher if the platform arrival pressure is lowered. Recent production rates are 350 MMSCFD. The high temperatures and flow rates were considered in the design against corrosion and erosion.

The production contains about 100 bbl of hydrocarbon condensate and 2-3 bbl of water per mmscf. Table I displays the calculated condensate volumes used for flow modeling. The actual production on Britannia confirms these values.

The primary areas of focus in the design were corrosion inhibition of the subsea flowlines, corrosion/erosion resistance of the manifold and flowlines, selective weld corrosion resistance of the flowlines, and sulfide cracking resistance of the downhole tubulars. Each will be discussed.

TABLE I TOTAL LIQUID IN EQUILIBRIUM WITH 1 MMSCF BRITANNIA GAS, HYDROCARBON (WATER), BBL (Available in full paper)

METALLURGY OF DOWNHOLE EQUIPMENT

Typical conditions for these gas condensate wells would include up to 15 ppm hydrogen sulfide, 2.6 mole % carbon dioxide and 50,000 ppm chlorides. Therefore, type 13% Cr alloys were chosen to provide adequate corrosion resistance. Depending upon tubing design requirements, both API 5CT Grade L-80 13% Cr and proprietary modified 13% Cr with a 110 ksi SMYS were selected.
Friction Welding - Technology for the New Millennium
Authors: Blakemore Gordon R.
Published: October 2008

This paper describes the process of friction stud welding and how it has been developed for use in the North Sea. Attention is given to explaining why friction welding does not suffer the inherent problems associated with conventional welding techniques, (particularly when used underwater), how superior metallurgical integrity can be achieved, and how (unlike any other welding method) the process can be used at ANY water depth without any change to weld parameters or weld quality.

Following this, the paper describes the hyperbaric trials and then the work carried out in executing the deepest LIVE friction welding operation in the world to date. The work was carried out in 395 metres of water West of Shetland and involved the friction welding of anode continuity tails to riser base piles using a work-class ROV (Remotely Operated Vehicle).

The paper documents the work currently being carried out by a Consortium of European Companies funded by a European Community grant for the development of a friction welding system using a process known as Friction Stitch Welding and the associated deployment equipment to carry out crack repairs on vessels, platform structures, and pipelines.

Finally the paper outlines the proposed development to be carried out in extending the crack repair technology to enable the joining of pipe up to 42 inches outside diameter at extreme water depths.

In summary, with the constant search for resources in ever deeper water this technology will provide the Engineer with a reliable and cost effective method of joining materials at extreme depths for construction, repair, maintenance, salvage, corrosion protection and many other tasks. - TECHNOLOGY FOR THE NEW MILLENNIUM.

Introduction

The process of friction welding has been available forworkshop use on a commercial basis since the 1950's.

It is used extensively in the automotive and aerospace industries because of its reliability, repeatability, weld integrity and ease of automation.

In 1983 the world's first "portable" equipment was built for use in the North sea and was used to great effect for making anode attachments at 150 metres water depth. This was documented and presented at previous OTC.1

Since then equipment has become truly portable, and the development of computer technology has provided the facility of much smaller and more accurate control/monitoring systems with in-process proof testing.2

Thus the equipment has now attained an extensive track-record for use both topside and underwater for repair, maintenance, construction and many other applications in the offshore, marine, defence, construction and nuclear industries.
Developments in Proposed ISO Guidelines for Design of Offshore Platforms to Resist Earthquakes
Authors: Bea R.G. , Craig M.J.K. , Gudmestad O.T. , Karthieghian V. , Pradayana G.
Published: October 2008

This paper summarizes current developments in the International Standards Organization (ISO) proposed guidelines for design of offshore platforms to resist earthquakes. These developments include updated evaluations of seismic exposures in the U.K. and Norwegian Sectors of the North Sea, offshore Japan and Indonesia, and in the Bay of Campeche Mexico. Guidelines have been developed to permit design analyses based on either 100-year or 200 year bases. Recent results from measurements and analyses of the effects of local soil and geologic conditions are used to update the proposed ISO guidelines. Updated developments also address steel and concrete elements in offshore platforms. Both 'fixed' and 'information sensitive' load and resistance factors for steel and concrete elements have been developed to increase the ease of use of these guidelines. The updated guidelines in this paper provide important improvements in development off reliability based criteria for design and requalification of fixed offshore platforms. These improvements are in characterizations of seismic exposure, effects of local soil and geologic conditions on ground motions, performance characteristics of steel and concrete elements and pile and mat foundations subjected to earthquake loading effects, and in characterization of dynamic loading effects in fixed offshore platforms subjected to ultimate limit state earthquakes.

Introduction

A first-generation LRFD ISO guideline for design of steel, pile supported, template-type platforms to resist earthquake induced loading has been developed.1 This guideline was based on the API RP 2A LRFD guideline and on the collective experience and judgment of the ISO TCG7-WG3-P5 committee members. During the first generation developments, limited verification studies of the entire process were performed, there was limited documentation of the background for some of the key developments, and there were additional topics that needed to be addressed. Three general topics are addressed in this paper:seismic exposure characteristics,design response spectra characteristics,concrete gravity base structure characteristics.
Atlantic Crossing Film
Authors: Moore N.A.
Published: October 2008

This film is a 30-minute, illustrated, seismic profile cross...section of the deep ocean floor and sub-bottom sedimentary layering from the island of Trinidad, B.W.I. to the port of Monrovia, Liberia. The survey program was initiated in June, 1967. The traverse to Liberia was completed in 14 days at an average vessel speed of 10 knots. The seismic profiling system was Teledyne Exploration's 120,000 Joule SSP System. Seismic data was recorded on a facsimile recorder, the detector streamer cable was Teledyne's 100 sensor, single-channel Hydrostreamer. The actual traverse length was about 3,500 miles.. Our film will show perhaps two thirds of the actual field sections. The data has not been processed in any manner.

The data shown consist of essentially continuous seismic profile records, with the vertical scale of the record a 4-second [from top to bottom] time scale, and a horizontal distance scale [across the screen] of approximately 15 miles. This produces a vertical-horizontal scale ratio of approximately 1:8. While this ratio could be altered by changing either the firing interval of the underwater seismic source or the vessel speed, the parameters selected were considered optimum for this traverse. Thus, we will see an unfolding of the .subsea bottom geology with the water surface at the top of the record. The first major event is the sea floor, followed by numerous reflector events which detail the sedimentary layering below the sea floor. One may estimate the depth of the sea floor by remembering that each second [one fourth of the vertical record length] from the top of the record down toward the sea floor, covers a distance of 800 fathoms; i.e., if the sea floor is seen at about 2 seconds, the water depth is approximately 1,600 fathoms.

Throughout the film, inserts have been added illustrating the equipment and the manner and methods of usage aboard ship. Geological interpretation is based on data in current publications. Positioning was by dead reckoning and celestial navigation except at the origination and termination of the seismic profile. As mentioned earlier, portions of the profile were edited out because of monotonous geology, and the need to limit the film to 30 minutes. One breakdown occurred near the halfway point of the traverse [mid-Atlantic rise] and about 300 miles of data were lost. The vessel used on the program was a typical work boat, 136 ft long and 26 ft wide [M/V Stranger]. The first film cut shows a similar survey vessel rigged with the same seismic profiler system. The vessel is shown leaving Port Arthur through the Sabine Channel. Illustrations of the deck rigging detail the 20-ft outrigger booms, from which the arcer electrodes are towed. This scene shows a wire dispenser for the Teledyne wire explorer [WASSP] attachments. Each boom is lowered into position and two electrical cables are released into the water. The cables are approximately 18 ft apart and extend about 150 ft astern of the vessel. The Teledyne crew is shown lowering one of the cables over the side. Cable pullers are used to simplify retrieving the cables while underway.
Chemical Overlays for Seafloor Sediments
Authors: Roe Thorndyke , Williams John S. , Migliore Herman J.
Published: October 2008

Various materials and methods have been investigated to control the turbidity caused by the disturbance of seafloor sediments. The method selected as the most promising consists of the formation of plastic film over the sediments by casting from a compatible solvent system.

A formulation has been developed, and equipment to dispense it has been designed, fabricated, and is being evaluated.

INTRODUCTION

Poor visibility is one of many problems which man encounters when he carries out undersea operations. It has been reported that under ideal conditions, and at shallow depths, divers have been able to see clearly for 200 feet in all directions1 but generally the limit of visibility off the Southern California coast is fifty feet. This limit is drastically reduced if seafloor sediments are disturbed so that an undersea "dust cloud" is created. Material of this type can remain suspended for hours with the result that work must be greatly curtailed or suspended. In salvage operations, any prolonged delay could result in partial or complete failure of the mission. As man begins to place permanent structures on the sea floor, sediment stabilization is a problem which will have to be solved during construction and operation of these installations.

CHEMICAL METHODS

Three methods were considered as approaches toward solving the sediment stabilizing problem:use of flocculating agents,stabilization of the soil mass,formation of an overlay to cover the sediment.

Flocculating agents are effective in increasing the settling rate of suspended material. However, if the settled material is disturbed, an additional waiting period is required for it to settle again. Stabilization of the soil mass would require that rather large quantities of binding materials be injected into the sediment with a minimum of disturbance. This technique should be considered only when a permanent or semi-permanent foundation is required.

Formation of an overlay to cover the sediment was selected as the best of the three methods to solve the present problem.

Three methods were considered as possible solutions to the production of an overlay:the formation of a polymer gel by chemical reaction at the site,the formation of a gel by increasing the viscosity of a liquid because of low ambient temperature at the site,the formation of a plastic film at the site by casting from a compatible solvent system.

Roe and Williams2 and Epstein and Widman3 have reported on one or more of these methods, and the information can be summarized as follows:Formation of a polymer gel. Acrylamide can be polymerized in a soil formation4 and a proprietary product is sold for this purpose. Oceanographers have used this chemical grout in high concentrations in taking seafloor core samples.5 Polyacrylamide forms a tough gel under water, but the monomer is slightly neurotoxic and would not be suitable for diver use.
Hybrid Riser for Deepwater Offshore Africa
Authors: des Déserts Loïc
Published: October 2008

As hydrocarbon production is now contemplated for larger and larger water depths, the technical issues related to the import of the fluid stream onboard the floating production facility have to be well resolved. The hybrid riser concept, as developed today, brings a technically and commercially viable solution to this problem. The purpose of the present paper is to describe the latest developments achieved on the hybrid riser technology. The concept presented here is different than that developed for the Girassol field located offshore Angola as it incorporates improvements which have been made after the detailed design of the Girassol unit was completed. The paper gives details on overall geometry and governing criteria for the sizing of the system. Overall fabrication and installation procedures are also presented as well as the main results of the dynamic behaviour of the system when installed on its final location.

Introduction

When developing hydrocarbons in deep waters or ultra deep waters, that is to say from 1000 m to 3000 m, one of the biggest technological challenges that has to be overcome by the developers comes from the riser system. Indeed, raising the production stream from the sea bottom to the surface is the only feature, together with the mooring system, if not using a dynamic positioning system, which really depends on the actual water depth. The size of the floating unit supporting the production equipment does not vary with the water depth but mainly with the production throughput level and the amount of required storage. Likewise, the sub-sea equipment suitable for 1000 m is very similar to that suitable for 2500 m or even 3000 m, and the water temperature is the same at all these depths. At these depths the water temperature is closed to 4° C. This is rather cold when compared to the hydrate formation temperature, generally around 20° C, or to the wax appearance temperature that could be close to 30 or 40° C. When considering also that most of the reservoirs located in deep waters offshore the West coast of Africa lie in relatively shallow soil depth and are therefore relatively cold, the importance of the thermal properties of the riser system becomes quite obvious. This is why the riser system described in the present paper has been developed for particular applications in deep waters located offshore the coasts of West Africa.

Description Of The Tower

The tower described here-below has been designed for an application located in the Gulf of Guinea and in 1500 m of water. It is designed to allow the production of 150,000 bpd from 24 wells to be brough to the surface. This layout involves 12 flowlines arranged in 6 piggable loops, plus 2 water injection lines and 1 gas injection line. All these lines are gathered in 2 towers, each one incorporating 6 producing lines, 1 water injection line and 1 gas injection line.
Life-Cycle-Cost-Based Design Criteria for Gulf of Mexico Minimum Structures
Authors: Botelho Dirceu , Petrauskas Chuck , Vannan Mani , Mackey Vance , Lang Buddy
Published: October 2008

Chevron engineered four different structural concepts for two fields in different locations and different field economics, and for three different design criteria: 100-, 50-, and 25-year return periods. The structural concepts considered are primarily used in the offshore industry for marginal field development. The objective of the study was to evaluate the impact of designing these structures based on field economics by maximizing the expected net present value (NPV) of the project revenue streams over the life of the field, or equivalently, by minimizing the total cost of the project over the life of the field. In either case not only initial capital costs are considered, but also costs associated with maintenance during the project life, and costs associated with a potential failure of the structure.

The study concludes that, depending on the economics of the field, the optimum design criteria may be more or less stringent than the current 100-year criteria recommended in the 20th edition of API RP2A1.

Introduction

In order to improve the economics of developing small/marginal fields, Chevron carried out a study to identify and select, among existing production platform concepts, the ones that would optimize the development of fields in 130 ft. and 200 ft. of water. The study aimed not only at selecting the concept with the lowest initial capital cost among existing concepts, but also at defining the optimum platform design criteria on the basis of maximizing the expected NPV of the field development over a range of different production scenarios.

The study was divided into three main phases:Information gathering and selection of four alternatives;Preliminary design of alternatives and narrowing choices to two alternatives;Risk-based economic analyses and selection of the preferred alternative.

Phase 1 Results

In the first phase of the study the development scenarios and production requirements were defined. In addition several different criteria were defined to help weigh the strengths and weaknesses of each of the concepts being considered. At a minimum each structure would have to support:5 wells;a small deck with enough space to handle a coil tubing or wireline unit;a test separator and a well header;a small crane;a boat landing; anda minimum helideck.

The locations considered were Eugene Island Block 238 in 130 ft. of water, for which a 7 year development scenario was considered, and Main Pass Block 133 in 200 ft. of water, for which a 5 and a 22 year development scenarios were considered. Table 1, summarizes the production schedules for each of these scenarios, and Table 2 provides information on the economic assumptions.

A total of 29 platform concepts were considered, with the selected top four concepts being:Mantis II,LINX,STAR, andTripod.

The tripod considered here differs from traditional tripods in that one of the legs is vertical, and considered to hold one of the five wells. Figures 1 depicts three of these concepts.
Six years experience with an erosion based sand monitoring system at the Tordis field.
Authors: Braaten Nils A. , Johnsen Roy
Published: October 2008

The production of sand particles in oil wells can result in severe problems with regard to erosion in valves or bends as well as possible collapse of the reservoir, and filling up of separators. This paper will discuss the erosion based sand monitoring system, and how this has helped the Tordis field operator to operate within optimized, but safe production limits to avoid these problems. The system has operational experience from the last seven years and field data will be presented. The paper will also show data from laboratory tests. And a new temperature and pressure gauge which is included with the probe is also discussed. Finally, the latest erosion correlation model developed together with the Norwegian oil company Norsk Hydro will be discussed. This model gives the correlation between the probe erosion and other critical components in the system, e.g. bends.

INTRODUCTION

The production of sand and solids in oil and gas can represent a major problem in terms of erosion damage. Sand production can also lead to a degradation, or in the worst case, a collapse of the reservoir. Unexpected breakdown of the reservoir and water breakthrough can occur, resulting in increased sand content of the well fluid. Process equipment could also fill up due to the settling of sand. In addition to the safety and production technical aspects of unwanted/uncontrolled sand production, the active use of proper on-line sand monitoring equipment will also have a cost reducing impact since piping tolerances with respect to erosion may be reduced.

Sand control has in the past been sought mainly through downhole techniques like screens/gravel packs. A gravel pack will, however, limit the production capacity from the reservoir, and it has also been seen to fail with drastic consequences. In addition, the cost of a gravel pack operation can make it desirable to seek other solutions. The system presented in this article allows continuous monitoring of the status of sand production and erosion in any type of well, and will serve both as a safety device, and as a tool for optimizing and controlling the oil/gas production. An on-line sand monitoring system can also lower capital expenditures.

By reducing the production system tolerance with respect to erosion. During testing before a well is put into normal production, and at later stages, maximum sand free rate (MSFR) tests with on line sand monitoring can be performed to establish the maximum acceptable production rates. However, downhole conditions can change over time resulting in sand production. This leads to a requirement for continuous sand monitoring.

This paper describes experience from use of an erosion based sand detection and monitoring system. Due to the high sensitivity of the device, any significant sand concentration in the produced fluid/gas will be detected. In addition, the erosion rates read directly from the probe elements can, using direct correlations, be used to quantify the erosion in the piping system itself.
Khazzan Dubai 1: Design, Construction and Installation
Authors: Chamberlin R.S.
Published: October 2008

In early August, 1969, a 15,000-ton, bottomless offshore oil storage tank was completed on the shore of the Trucial Coast of the sheikdom of Dubai. The successful launching, towing and submerging of the tank were spectacular operations receiving world-wide attention. These operations, however, were preceded by extensive research and development programs to answer the many questions surrounding a new or different structure. These include tests of crude and salt water, handling of sludge, model test work and development of construction and installation techniques.

INTRODUCTION

Khazzan Dubai #1, a 500,000barrel oil storage tank, placed in service December, 1969, is located sixty miles offshore in154 feet of water. The structure, the first of its kind, stores oil produced from the Fateh Field. Dubai Petroleum, a wholly owned subsidiary of Continental Oil Company, operates the field for its partners, Dubai Marine Area Ltd. (Compagnie Francaise des Petroles and British Petroleum), Deutsch Erdol-Aktiengesellschaft, Dubai Sun Oil Company and Continental Oil Company. Hispanoil has now replaced British Petroleum as a partner of the DUMA group.

The 15,000-ton structure (Figure 1) is 270 feet in diameter and over 200 feet in height. It has no bottom and operates on the water displacement principle. It is always full with either water or oil or a combination of the two. Filling is accomplished by placing oil in the tank above water. The additional weight of the oil on the water creates an imbalance in pressure which forces the water out of the tank through openings in the wall.

The unusual structure requires special construction techniques which enable it to be built onshore, launched and towed some sixty miles to its offshore location. The launching, towing and submerging were spectacular operations that created worldwide interest throughout the industry. Behind the success of the structure, however, were many years of meticulous study and research.

A new structure such as this brings up unique and special operating conditions which must be considered. These include salt pickup by the oil and sludge buildup at the oil/water interface.

Gaging techniques must be used to remotely monitor the oil/water interface, divert the incoming stream once the tank is filled or shut down the pumps once the tank is empty. Certain operating advantages are expected: free water will automatically precipitate to the water below the oil/ water interface, decreasing the salt content of the crude, and large buildup of wax or heavy ends at the interface can be removed by pumping when the tank is stripped out.

The open sea location where the tank is installed gives ample opportunities for wind to generate large waves (over 39 feet in height with 10-second periods). Coupled with storm-driven currents, these waves create tremendous forces on the oil storage tank. These large forces are resisted by an anchorage system consisting of 36" ? steel piles cemented into the sea floor.
Wave Theoretic Approaches to Multiple Attenuation: Concepts, Status, Open Issues and Plans, Part 1
Authors: Berkhout A.J. , Verschuur D.J. , Weglein A.B.
Published: October 2008

Surface-related and internal multiple removal can be applied in a model driven and a data driven way. A unified description has been proposed that relates both types of wave theory based algorithms. Special attention is given to the removal of internal multiples.

Introduction

A multidimensional inversion algorithm for the removal of surface-related and internal multiples was proposed by Berkhout (1982). Essential in his formulation is that any subsurface model can be handled and, above all, that the data acquisition properties are taken into account. The latter turns out to be an absolute necessity for success on field data.

In his doctoral thesis, Verschuur (1991) successfully demonstrated on field data that the inverse source wavelet can be estimated by making use of a least-squares subtraction process. Recently, Weglein et al. (1997) proposed an algorithm to remove internal multiples with the aid of the multiple scattering theory. Important in this proposal is that no knowledge of the subsurface is required.

Model for surface-related multiple reflections

We start with the basic equations for surface-related multiples in terms of the matrix-vector notation (Berkhout, 1982):

(Mathematical equations available in full paper)

Figure 1: Forward model for primaries (z>z0) and surface-related multiples, the multiple-generating surface being defined by z0=z0 (x,y). (Available in full paper)

Model for the multiple removal process

From equation (1b) it follows that the surface-related multiples are given by

(Mathematical equations available in full paper)

From equations (2a) and (3b) we may conclude that the prediction filter for surface-related multiples is a complex one:It is not only a multi-channel filter, it is also a multi-record filter;Each trace of the multi-record filter represents a scaled primary response of the subsurface.

Hence, for complex subsurfaces the filter may become very complex. In Figure 2 the prediction of surface multiples for one specific source-receiver pair is visualized:

(Mathematical equation available in full paper)

where the source is at xj and the receiver at xi. The inner product of the two vectors in equation (4) describes a summation of the two wavefields along the surface locations. Note that the receiver locations of the data are combined with source locations of the prediction operator. Note also that the prediction lag of Fpr is given by the shallowest multiplecontributing reflector.

Figure 2: Prediction of surface multiples in a data driven approach: the data is used as multiple prediction operator in a spatial convolution along the surface coordinates. (Available in full paper)