gulf of mexico exploration

7/24/2019 gulf of mexico exploration

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Development of EPS FPSO and Riser System for Deepwater Gulf of MexicoJ. Chung, and W.A. Dupont, Technip; C.F. Mastrangelo, and B.P. Hartman, Petrobras

Copyright 2008, Offshore Technology Conference

This paper was prepared for presentation at the 2008 Offshore Technology Conference held in Houston, Texas, U.S.A., 58May2008.This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed bythe Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or membersElectronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to anabstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract

This paper presents the functional description and conceptual design of an Early Production System FPSO and Riser system fordeveloping isolated, deepwater fields in the Gulf of Mexico. The main contributions and challenge to this work are harsh

environmental conditions including strong loop current and hurricanes, the regulatory compliances and design of a riser system in

7,000 feet of water. The EPS FPSO presented in this paper is capable of weathervaning 360 degrees using an internal turret and uses aDynamic Positioning System (DPS) during operation and offloading. Under hurricane conditions or other emergency situations such

as drive-off or drift-off, the vessel can disconnect from the riser system and sail to a safe location. The hybrid riser system which

decouples motions between the FPSO and Riser system is designed for 7,000 ft water depth, 10,000 psi shut-in pressure and a 25-yea

design life. Regulatory requirements specific to the EPS FPSO are identified using previous DeepStar works: Environmental ImpactStatement and Regulatory framework. Two presentation meetings were held with MMS and USCG to present the conceptual DWOP

(Deep Water Operations Plan) of EPS FPSO and riser system to identify any show stoppers in terms of regulatory requirements. Issues

discussed at these meetings are summarized in this paper. A qualitative risk assessment was performed to identify critical issues

regarding safety and environment during the entire field life including workover and well intervention. The main conclusions of thiswork are: (1) EPS FPSO is a technically sound, economically viable option for early production of deepwater GOM fields; (2) there isno major show stoppers in terms of regulatory requirements; and (3) a number of risks were identified which can be mitigated by

design.

Introduction

Recently discovered deepwater fields in the GOM can produce oil and gas using an early production system (EPS) until extendedwell testing is completed and a long term development plan is determined. This EPS can be re-deployed to another field at the end of

its task, which can be three to five years. An obvious option for vessel selection is to convert a shuttle tanker that has a DP system. In

this case, the station-keeping of such EPS FPSO can be achieved through the DP system which eliminates the need for a vessel

mooring system. A DP system also has advantages in that it enables the FPSO to self-propel to evacuate in advance of hurricanes as

well as mob/de-mob and re-deployment from field to field with minimal need for assistance from tugs and installation vessels.The proposed EPS FPSO is fitted with an internal turret for weathervaning capability which is an effective way to minimize

environmental loads and motions, especially lateral and roll motions. The main benefit of smaller lateral motions is the relaxation ofthe riser system design.

The riser system is designed to be disconnectable from the FPSO for the following reasons. First, it allows the vessel to disconnec

and sail to a safe location in advance of hurricane and severe storm conditions. This not only protects the vessel and crew from

dangerous weather conditions, but prevents the riser system from being damaged or overstressed. Secondly, it allows the FPSO to

quickly disconnect in case of emergencies such as DP system black out, drive-off or drift-off. The third reason is that the riser systemcan be used for the rest of the field life after the facility is replaced with a full field development platform. The disconnectable system

can also benefit non-production related operations such as work-over, well interventions or hull maintenance that requires drydocking.

The riser system selected in this work is the so-called free standing hybrid riser (FSHR) system which effectively decouples the

FPSO motions from the riser system, thereby significantly reducing the dynamic loads on the riser and subsea termination.


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An important aspect of this work is that the EPS FPSO concept and the design criteria were developed through collaboration

among the contractor, operators (represented by the DeepStar Subcommittee) and regulatory bodies. Most of them, if not all, have

expertise and a direct involvement with some parts of similar projects in the GOM using an FPSO. This ensures that the result of thiswork is in-line with real field development objectives. At the conclusion of this work, the conceptual Deep Water Operations Plan

(DWOP) of using an FPSO as an EPS was presented to a group of regulatory representatives for comments. While many invaluable

comments were received regarding the EPS FPSO concept, no show stoppers were identified. It is understood that all major

components are based on field proven technologies. CVAs for topsides and FPSO structural design as well as for risers will be needed

to comply with regulatory requirements. In particular, the FSHR will need a Certified Verification Agent (CVA).In 2001, the Environmental Impact Statement (EIS) on use of a more permanently moored FPSO in the GOM was approved by

the MMS. This EIS may be applicable to the EPS FPSO. However, the Conceptual Plan (CP) and a more detailed DWOP must besubmitted for review and approval for the final acceptance.

A risk assessment was performed to identify and rank the design-based risks associated with EPS FPSO. Focus was given to risk

not addressed previously in the 2001 EIS FPSO study. Distinctions are made identifying whether these hazards are unique to the EPS

or are common for the GOM or FPSO installations worldwide.From the results of this work, it is concluded that the DP FPSO with FSHR systems is a technically feasible and economically

viable solution for an early production system (EPS) in deepwater Gulf of Mexico.

Field Development Plan

For recently discovered oil fields in deepwater US GoM often no pipeline infrastructures exist to export produced oil. Therefore,

the use of a shuttle tanker for oil export is desired. Especially for short term developments the use a Floating Production Storage andOffloading Unit (FPSO) is an economically viable option.

In many cases of newly discovered wells, not enough data or knowledge regarding the reservoirs is available. For such fields it is

advantageous to design an FPSO Unit to produce oil for a few years, prior to requesting sanction for the full field development

concept. This will also allow time to design a fit-for-purpose system for the full field development which can optimize production

minimize risks and maximize potential recovery.The phased approach is one of the strategies commonly used in developing oil fields with high uncertainties, which require a more

cautious development. In this study, it is considered that conventionally compressed and treated gas will be exported through

pipelines. Further studies can be carried out to study the feasibility of a self sufficient FPSO with on-board and offshore uses for the

gas, such as fuel, GTL, CNG, etc.Major data required to define the hypothetical oil field are as follows:

Water depth with an associated subsea layout;

Reservoir conditions to define process characteristics, top-of-the-risers condition, fluid properties, throughput and vesselsizing;

Process and treatment required to determine minimum process plant characteristics on the vessel;

Subsea layout and boosting system to define interfaces with the FPSO and the number of risers in terms of flowassurance considerations;

Potential secondary recovery (although this is usually not a concern for an EPS);In addition to the above data, it is necessary to define boundary conditions, such as typical soil characteristics and metocean data.

The data selected is summarized in the design basis below and is typical of oil fields in ultra-deepwater US GoM. Those fields are

normally High Pressure and High Temperature (HP/HT) reservoirs in harsh environments with strong loop and eddy currents and

hurricanes. Although similar to existing oil fields, it must be noted that this data are not supposed to represent a specific field.

Conversion of a ship-shaped tanker into an FPSO is a preferred option to minimize construction time to meet the tight schedule of

a fast-track development plan. Therefore, a ship-shaped converted FPSO was selected for this study. Because a ship-shaped unit is nofavorable to riser design due to larger offsets and wave induced motions, a screening exercise for various riser configurations was

performed, and the FSHR was selected for this study.

It is important to note that the risers need to be designed for high pressures (due to HPHT reservoir condition) which means there

should be a spec break inside the turret. This piping spec break will prevent the swivel from being exposed to pressure higher than theexisting field proven design. For the selected field, due to the fluid and reservoir characteristics, an additional lift mechanism is

required. In this study, the use of subsea pumps is assumed. However, for future development, it is preferred to provide slots forsubsea pumps and spares, and make the decision to include the subsea pumps after further reservoir information is available.

The process plant has conventional process separation and treatment equipment with storage of the oil inside the FPSO tanks to be

exported by shuttle tankers.

The EPS stationkeeping is accomplished by a DP system that requires a disconnection system that enables the FPSO to disconnec

according to certain criteria, including emergency situations. An alternative to the DP system is a moored disconnectable systemwhose desirability depends on the number of risers and loads and requires additional studies. This latter option requires disconnection

only for hurricanes. However, it may still need a quick disconnect capability for emergencies such as sudden hurricanes. As a further

option, the FPSO can be designed to be permanently moored, without need for disconnection. Further studies can be done to evaluate


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and compare the permanently moored FPSO and the disconnectable FPSO. The threshold for the minimum number of risers and loads

such that the permanent moored FPSO is more attractive would need to be determined.

In the development concept studied there are four new technologies introduced to the Gulf of Mexico.

The principal facility is a floating, production, storage and offloading vessel (FPSO) with disconnectable, single pointturret buoy that has a light mooring system.

Crude transportation from the FPSO to shore is via a shuttle vessel.

Free standing hybrid risers (FSHRs) are used for production and gas export risers.

Subsea electric-driven booster pumps located on the seabed near the wells are used to increase production.Flow assurance was also considered to arrive at the subsea layout shown in Figure 3, which includes a number of mitigation

measures to maximize productivity and reserve recovery. Subsea boosting of the production stream is likely to provide a significant

benefit to the Field Developments in terms of recovering reserves. Important flow assurance issues to consider are:

Hydrate inhibition and mitigation through subsea flowline insulation

Chemical injection to mitigate the precipitation of wax and asphaltenes

Coil tubing interface on the top riser frame

Pigging operating procedures and

Formation of emulsion with increased water production in later field life.

Design Basis

Environmental Data / Metocean

The Walker Ridge area is located in the Gulf of Mexico in 7000 feet of water 200 miles from shore. The extreme environmenta

data for the FPSO facility is based on the data provided in [1], except 100-year loop and cold eddy current 1velocities. The proposed

extreme and operating environmental conditions for this study are summarized in Table 1 and Table 2. It is important to note that inthis study, generic data are used for investigating the feasibility of an EPS FPSO and riser system and that specific metocean data

would be considered for any specific project.

Table 1 Extreme Metocean Design Criteria for GOMDesign condition 1000-year

Hurricane(estimated)

100-year Hurricane 100-year Loopcurrent

100-year cold eddy

Wave

Hs (m) 17.0 13.4 1.2 1.7

Tp (sec) 16 14.9 6 6

Hmax (m) 30.0 23.6 2.7 3.1

Tmax (sec) 14 13.4 5.2 5.7

Wind

Vw (m/s), 1 hr 60.0 38.6 6.2 6.2

Current speed (m/s)

0 2.5 0 1.8 0 2.20 0 0.16

5 2.0 100 1.8 100 1.72 100 0.16

20 1.8 150 1.0 150 1.31 150 0.82

50 1.2 200 0.2 200 1.19 200 1.72

60 1.0 250 0.1 250 0.98 340 1.80

70 0.1 340 0.0 340 0.73 350 1.56

150 0.1 3048 0.0 350 0.49 400 1.39

200 0.0 400 0.33 500 0.16

3048 0.0 500 0.16 600 0.08

800 0.16 1000 0.081000 0.08 2134 0.0

Depth (m) / Vc(m/s)

2134 0.00

1Current thinking in API group is that cold eddy currents are overestimated


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Table 2 Operating Environmental ConditionDesign condition 10-year Hurricane 100-year Winter

Storm10-year WinterStorm

Wave

Hs (m) 8.5 8.0 6.0

Tp (sec) 13.0 13.0 11.5

Hmax (m) 13.5 14.0 11.0

Tmax (sec) 11.0 11.5 10.5

Wind

Vw (m/s), 1 hr 27.0 23.0 20.0

Current speed (m/s)

0 0.8 0 0.5 0 0.3

10 0.6 75 0.5 75 0.3

17 0.4 75+ 0 75+ 0.1

20 0.3

Depth (m) / Vc(m/s)

25+ 0.1

Design Premise

The design life of this EPS FPSO is 5 years continuous service on location without the need for dry-docking. The design life of the

riser system and light mooring system is 25 years.

A disconnectable turret buoy was chosen for this study which allows the vessel to weathervane 360 degrees. The FPSO is assumedto stay connected to the riser system up to 100-year Winter Storm, 100-year loop current and 100-year cold eddy current conditions.For environmental conditions exceeding the 100-year Winter Storm, the FPSO will disconnect from the riser system and sail away to a

safe area.

The disconnect criteria for the EPS FPSO are summarized in Table 3. The excursion limit for the FPSO to disconnect the risersystem will be determined based on the final configuration of riser system including all critical components such as stress joints and

bend-stiffeners. This excursion limit is also called Point of Disconnection (POD). From the drift-off analysis, Red Alert offset and

Yellow Alert Offset can be calculated periodically (typically every 12 hours) taking into account the current environmental

condition. Should the prevailing environment change significantly between periods, the simulation should be re-run. The Yellow

Alert Offset is when the operator needs to start preparing riser and critical equipment for Emergency Disconnect. The Red Alertoffset is when the Emergency Disconnect needs to be activated to ensure the riser is physically disconnected from the EPS FPSO

before the vessel offset exceeds the POD.

Table 3 Riser Disconnect Criteria

Sea State Operating condition Watch circle DP Equipment Status Riser and Light Mooringsystem design

FPSO Excursiolimit

Robustness check

(1000-yr hurricane)

Disconnected

(Non-emergency)

N/A N/A Riser stand alone

(Riser allowable stress =1.0)

N/A

Survival conditions(100-yr hurricane)

Disconnected(Non-emergency)

N/A N/A Riser Stand alone(Riser allowable stress =0.8)

N/A

100-yr Winter Storm / 100-yr Loop current

Production if vessel

motions are acceptable forsafe operation

R = 15 m for

HS8 m Normal / Full Power FPSO connected condition R = 15 m

Extreme Operating

condition

Production suspended and

riser ready for EmergencyDisconnect

R = 15 m for

HS8 m

Power or Control

Failure resulting inDrift-off or Drive-off

Stand alone condition

(include 1 mooring linebroken case)

Red Alert POD(TBD)

10-yr Winter Storm / 10-yr Loop current

Full Production R = 10 m for

HS6 m

Normal / Full power FPSO connected condition

R = 10 m

Normal Operating

condition

Production suspended andriser ready for EmergencyDisconnect

R = 10 m forHS6 m

Power or ControlFailure resulting inDrift-off or Drive-off

Stand alone condition(include one mooring line

broken case)

Yellow alert ReAlertPOD(TBD)


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Field Requirements and Production Rate

The following tables summarize the assumed well fluid properties, field requirements and production rate for the study EPS FPSO

Table 4 Field Requirements and Fluid Properties

Design Data Values

Design Pressure 10,000 psi (690 bar)

Working Pressure 5,000 psi (345 bar)

Design pressure downstream of spec break 740 psi (ANSI Class 300)

Design Temp < 225F (107C)

Working Temp < 176F (80C)

Production rate 50,000 bopd / 15 mmscfd

Fluid Density 850 to 890 kg/m3

OHTC Requirements based on pipe ID 1.0 BTU/ft2.Hr.F (5.7 W/m2.K)

pH >4.5

Salinity Cl-


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Rules and Regulations

The vessel, including hull, machinery, equipment, and outfitting, shall be constructed in accordance with the applicable Code ofFederal Regulations (CFRs). The use of Classification Society Rules and Regulations, to get a Class Notation, is recommended to

avoid potential misalignment between current regulation and latest FPSO regulation A1 (Maltese Cross) Floating Production, Storage

and Offloading System. The Flag State Registry shall be as per operators requirement. If registered to a Flag State, the FPSO has to

comply with all applicable Flag State Regulations. If flag state requirement is different from the US, the departures from the CFR are

to be addressed and discussed on a case by case basis.The FPSO will be designed and built in compliance with the lates tapplicable Class and International Regulatory Bodies Rules

and regulations. The list of those rules can be found in [2].

Figure 1 EPS FPSO General Arrangement

The vessel will have positive intact stability in all service conditions and a defined scantling draught complying with therequirements of the relevant regulatory bodies. Damage stability will satisfy the requirements of MARPOL and ICLL.

Dynamic Positioning System

This study is based on the assumption that the DP system requirements of the MMS will be met by the use of a DP-2 class system

The system will be capable of meeting the operating criteria in the maximum environmental conditions described in the Design BasisFurther studies are recommended to better define criteria for emergency disconnection and the needed reliability of the disconnectionsystem as well as the redundancy system to ensure disconnectability.

Free Standing Hybrid Riser Description

The hybrid risers consist of a vertical rigid riser attached to a base at the seabed and to a near-surface, submerged buoyancy can. A

flexible pipe jumper connects the top of the vertical riser to the FPSO turret buoy. The configuration and major components of the

Free Standing Hybrid Riser (FSHR) are shown in Figure 2 and described below.

Flexible Jumper

An un-bonded flexible pipe jumper provides the fluid path from the vertical riser to the FPSO. Polyurethane bend stiffeners at

each end termination prevent over-bending of the flexible pipe at the connections.

Frame Assembly and Gooseneck

The gooseneck provides a fluid path from the vertical riser to the flexible jumper. During installation the jumper-gooseneckassembly is attached to the vertical riser using an ROV actuated connector. The riser frame is a structural steel framework that

connects the flexible jumper, vertical riser and buoyancy can. The frame and chain connection method isolates most of the motion of

the buoyancy can from the vertical riser and minimizes the bending loads transmitted to the vertical riser.


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Buoyancy Can

The buoyancy can is a steel cylinder that provides tension to support the vertical riser. The upward force is transferred to the riserusing a chain and frame assembly. The size of the buoyancy can is determined by the upward force required to limit the deflection of

the vertical riser during extreme current events and by the minimum tension needed to limit VIV fatigue. The buoyancy can is divided

into multiple compartments. One compartment is considered to be flooded during normal operation. This compartment is a spare to be

emptied of water in the event of failure of another compartment. Note that the buoyancy can is not a pressure vessel. During

installation and service the can is pressure balanced with nitrogen to resist hydrostatic forces.

Chain Tether

A tether chain connects the buoyancy can to the top of the vertical riser. Universal joints are included at each end of the chain to help

reduce bending and fatigue. A load cell link is also included to monitor the buoyancy can uplift and changes in riser load during

service. The bottom of the chain is connected to the frame assembly using a hydraulic connector.

Tapered Stress Joint

A tapered stress joint of high strength steel is utilized at the top and bottom connections of the vertical riser to help reduce bending

stress. The base of the stress joint is a flange and is connected to the frame assembly at the upper end and to the offtake spool at thelower end. The tip of the stress joint includes a length of standard riser pipe. The standard riser pipe end avoids an offshore weld

directly to the stress joint. Alternatively the stress joint can be attached to the riser using a compact flange connection.

Standard Riser Pipe

The main section of the vertical riser consists of standard API Spec 5L X65 line pipe joints in 40ft lengths. Welded pipe joints will be

used for the design. Design and analysis of the riser pipe is according to API RP 2RD and API RP 1111. The rigid riser pipe ismodeled with a positive weight tolerance of ten percent. The internal corrosion allowance for the production riser pipe is considered.

No corrosion allowance is included for the export riser. For stress analysis purposes the corrosion allowance is subtracted.

Riser Pipe Coating and Insulation

All riser pipe is coated with an anti-corrosion layer of 0.01 inch thick fusion bonded epoxy (FBE). Production riser pipe is also

coated with 2.875 inches of syntactic polyurethane insulation (56.2 lbs/ft3). This thickness is based on an overall heat transfercoefficient of 1.0 BTU/hr ft2F (ID based).

Riser Strakes

Riser analysis was performed with strakes on the upper one-third of the vertical riser lengths.

Offtake Spool

The offtake spool provides the flow path from the vertical riser to the rigid base jumper and has an upward facing receptacle for

connection of the rigid base jumper. The offtake spool has flanged connections to the lower tapered stress joint and to the riser

connector.

Riser Connector

A hydraulic connector connects the offtake spool to the riser base assembly. This connector enables ROV actuated connection ofthe riser to the riser base during installation.

Riser Base and Foundation Pile

The riser base platform supports the lower riser connector and is mounted on a foundation pile. The riser base can also support astab guide to aid installation of the vertical riser. Alternatively, a sheave or pulley mounted on the riser base can be used to pull the

vertical riser into the riser base.


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Figure 2 FSHR Description

Riser Disconnect System and Turret Buoy

Concept of Riser disconnect system

The riser system includes the turret system on board the FPSO and also the entire riser system including the turret buoy and itsequipment. The selected field consists of four producing wells that are connected through a single loop daisy chain configuration asshown in Figure 3. Three single-line Free Standing Hybrid Risers (FSHR), two production risers and one gas export riser, are

connected to the FPSO through the turret. One control umbilical and two power umbilicals are connected through the turret to subsea

manifolds.

The mooring lines are designed to keep the turret buoy in position when disconnected from the FPSO to avoid over-stress/over-bending of the riser system and also to prevent clashing between FSHRs, umbilicals and mooring lines. The turret buoy is designed to

be neutrally buoyant at approximately 165 feet below the surface when disconnected from the FPSO. At this depth the buoy is below

the wave affected zone.


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Figure 3 Field Layout and Flowline Routing

As shown in Figure 4, the turret buoy consists of a main body, a buoyancy module, I-tubes for flexible jumpers and umbilical(s),

lifting lugs (not shown) and a QC/DC system. The flexible risers are fitted with end-fittings which connect to the hard piping inside

the buoy. The top end of the I-tube is flanged, so that, after the flexibles end-fitting passes through the I-tube, a set of split flangescan be installed to support the loads from the flexible. Alternatively, the flexible jumper can be connected directly to the hard piping

underneath the buoy by flange and bend stiffener without an I-tube. Further technical description of this turret buoy can be found in

Reference [2].

Figure 4 Turret Buoy with QC/DC System


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Disconnection Philosophy

As summarized in Table 3, the following criteria can be used to activate or initiate disconnection.Planned for disconnection (Non-emergency)

Gradual deterioration of vessel positioning

Environmental conditions exceeding 100-yr winter storm, 100-yr cold eddy or 100-year loop current. They includehurricanes and tropical storms.

Non-scheduled maintenance or repairs that require dry docking or transportation to shore. Decommissioning or re-deployment after service life

Emergency disconnection

Failure of critical equipment such as power generation, propulsion, DP equipment or software that causes drive-off ordrift-off.

Sudden change of weather.

Emergencies such as a fire or collision with other vessels.

Accidents.

Design Methodology

Light Mooring System

The purpose of a light mooring system is for station-keeping of the turret buoy when it is disconnected from the FPSO. Eachmooring line is composed of chain, polyester rope and chain sections. The preliminary design of the EPS mooring system consists of 6

mooring lines arranged in 3 groups of 2 that are 120 apart (more information can be found in Reference [2]). Due to the nonlinear andvisco-elastic characteristic of the polyester ropes, three stiffness (EA) values are defined. The design criteria for the light mooring

system are given below;

Mooring system shall provide suitable restoring force to the turret buoy so that the turret buoy will not over-stress thejumpers in extreme operating and survival conditions.

Mooring system shall not interfere with the jumpers, risers or umbilicals.

Max line tension < 60% BS at maximum offset limit (connected condition).

Max line tension < 60% BS in disconnected condition.

Max line tension < 80% BS in one-line damage case for disconnected condition for both extreme operating and survivalconditions.

The polyester sections shall not touch the seabed during installation, operation or any extreme conditions.

The safety factors given in Table 6, are based on API RP 2SK for chain and ABS guidelines for synthetic ropes.

Table 6 Safety Factor for Mooring Lines

Design Condition Chain Safety

Factors

Polyester Safety

Factors

Extreme

intact

1.67

(60% MBL)

1.84

(55% MBL)

Extreme

One-line damaged

1.25

(80% MBL)

1.43

(70% MBL)

Time-domain dynamic analysis was used for FPSO motion and mooring analysis. The mooring system was first designed to meethe strength requirement and to have a proper stiffness range. The mooring system was then combined to form the coupled numerica

model with all the risers, jumpers and umbilicals properly modeled to check the interference and other major responses.

For connected condition, the FPSO hull and turret buoy were numerically modeled. The turret buoy was positioned on the FPSOcenterline toward vessel bow. A frequency domain program was used to obtain vessel motion RAOs and wave forces (1 st and 2n

order). The turret buoy RAO was also calculated by a frequency domain program and input to riser analysis.

Vessel Motion and Mooring System Analyses

Since the FPSO is fully weather-vaning, the FPSO will maintain a head sea most of the time. For the maximum tension case, the

wave is assumed to come from the direction of one of the mooring line groups - 180. For maximum offset case, the wave is assumed

to come from in-between two groups of mooring lines 0. The numerical model of the mooring system is shown in Figure 5. Fordisconnected condition, a fully coupled model was used.


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Figure 5 Mooring System Numerical Model

X

Y2000 ft

OrcaFlex 9.0a: FPSO _drift_100coldeddy_colinear.dat (modified 5:43 PM on 1/10/2007 by OrcaFlex 9.0a) (azimuth=270; elevation=90)Reset

Free Standing Hybrid Riser

The riser configuration is designed to accommodate the relative distance between the turret buoy (either connected or disconnected

from the FPSO) and the top of the vertical risers which are designed to meet API 2RD requirements. Load cases are examined withFPSO static offsets that include a target vessel position offset and a vessel position tolerance offset. The target vessel position is the

location at which the FPSO DP thrusters will attempt to position the vessel. This position moves with buoyancy can positions as the

cans are deflected by strong loop and eddy currents. Buoyancy can positions are measured continuously and transmitted to the FPSOThe vessel position tolerance offset accounts for the vessel movement relative to the target vessel position. Vessel position tolerance

offset was initially assumed to be 200 ft.

Based on a preliminary assessment, polyurethane VIV suppression strakes were included on the upper one-third of the vertical

risers. VIV suppression strakes were also included on the buoyancy can. Strakes were included by increasing the hydrodynamic dragcoefficient based on data obtained from SPAR model testing. Buoyancy can depth was selected to minimize deflection during the 100

year loop current and the 100 year cold eddy current. Selected can depth is at an elevation between the 100 year loop current peak at

the surface and the 100 year cold eddy current peak at mid-depth. Without the cold eddy current, the can depth could be increased todecrease the can deflections.

FSHR design load cases are described in Table 7.

Table 7 Riser Design Load CasesLoad

CategoryEnvironment

Turret

ConditionNote

Hydro-Test 10 Yr Winter Storm Connected 1.25 x design pressure

Operating 10 Yr Winter Storm Connected

Extreme100 Yr. Winter Storm100 Yr. Loop Current

100 Yr. Cold Eddy

Connected

Extreme

100 Yr. Hurricane

100 Yr. Loop Current

100 Yr. Cold Eddy

Disconnected

Survival

100 Yr. Hurricane


100 Yr. Cold Eddy

Disconnected

Damaged mooring line or

One damaged buoyancy can

compartmentSurvival -

Drive-Off

Calm sea

No currentConnected

Uncontrolled vessel motion

determine maximum vessel offset

Survival -

Drift-Off

100 Yr. Winter Storm


100 Yr. Cold Eddy

Connected

Vessel power failure determine

maximum vessel offset for turret

release

Turret BuoyRelease

100 Yr. Winter Storm


100 Yr. Cold Eddy

DisconnectSimulation


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While not examined as part of this study the accidental case of the flexible jumper disconnected from the turret and hanging from

the vertical riser may be considered as a load case. This case may be a governing load case.

Results

Light Mooring System

Based on the methodology described above the preliminary mooring analysis was performed. It must be noted that only a limitednumber of cases were considered to obtain a conceptual design. Those load cases as summarized in Table 8.

Table 8 Mooring System Design Load CasesLoad Case Turret buoy

Condition

Wave / Current

Condition

Mooring System DP status

1 Max offsetConnected

Connected 100-Yr Winter StormMax Loop Current

100-Yr Cold Eddy

Intact /one-lineBroken

Full power, vessel follows the riserbuoy cans

2 Drift-off Connected 100-Yr Winter Storm

Max Loop Current100-Yr Cold Eddy

Intact Power or control failure

3 Drive-off Connected Calm Sea Intact Control failure

4 Max offset

Disconnected

Disconnected 100-year Hurricane

Max Loop Current

100-Yr Cold Eddy

Intact/ One-line

Broken

Not applicable

Load case 1 is normal operation in extreme weather condition. Load cases 2 and 3 are for vessel drift-off and drive-off cases. Theturret buoy will be disconnected when the vessel excursion reaches Point of Disconnect (POD). Load case 4 is a riser design case.

Maximum Mooring Line Tension with DP Control

When the vessel is controlled by the DP system, the FPSO is assumed to move with the buoyancy cans in order to maintain the

position that is most favorable to the riser system. The design limit for vessel excursion when driven under the DP system is 7% of

the water depth. The results show tensions in chain and polyester rope for the maximum offset are all within the allowable values

defined by safety factors provided in Table 6

The polyester rope bottom clearance was also checked for the minimum tension case. For the minimum tension case, the vessel ismoved 7% toward one group of the mooring lines. The results show sufficient clearance between seabed and polyester rope at the

minimum tension case.

Drive-off/Drift-off

The following four cases were simulated for drive-off and drift-off cases:

vessel drift-off in 100-year Winter Storm,

drift-off in Maximum Loop Current,

drift-off in 100-year Cold Eddy,

and drive-off in calm sea with a constant thruster force of 400kips.For drift-off cases, collinear environment was assumed. For drive-off analysis, a constant drive force of 400 kips was applied. The

simulations for 100-year Winter Storm and Drive-off cases are shown in Figure 6 and Figure 7, respectively. The simulations for the

other two cases are not shown here because they are not controlling conditions.


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OTC 19679 13

Figure 6 Drift Off Analysis - 100 year Winter Storm

Distance

Time

Drift Off Analysis - 100Year Winter Storm

POD

Red Alert

Figure 7 Drive-off Simulation

Distance

Time

Drive Off Analysis

POD

Red Alert

The POD for each condition was determined by solving riser loads and configurations at increasing offsets until the design limit

was exceeded by one or more parameters. For the 100year winter storm case, the POD and the Red-alert offset are illustrated inFigure 6. Similarly, for drive-off condition, the POD and the Red-alert offset are shown in Figure 7. The maximum mooring line

tensions at the POD are also calculated are found acceptable for both conditions.

Free Standing Hybrid Riser System

Analysis results show minimal buoyancy can deflection for non-loop/eddy current conditions. Therefore the nominal FPSO

position was used and the target vessel offset was zero for these cases. The target vessel offset for the extreme current cases waschosen to give optimal jumper configurations for both far and near vessel offsets.

For non-loop/eddy current cases the current and waves were assumed collinear and the vessel position tolerance was taken in the

same direction as the target vessel offset. For the 100 yr loop current and 100 yr cold eddy cases the current direction was assumed

independent of wind and wave. For these cases the vessel position tolerance was taken in the same direction as the target offset andalso in the opposite direction of the target offset. The opposite direction resulted in over-bending of the jumper with a 200 ft offset for

non-collinear 100 yr loop current and 100 yr cold eddy. For these cases an offset of 190 ft was found acceptable.

The maximum excursion limit for the FPSO, requiring turret disconnection before exceeding design parameters, also called the

Point of Disconnection (POD) was also determined. The POD is the point when the riser must be physically disconnected from FPSO.

For each design load case, tension, bending and stress for the production risers and gas export riser were calculated and compared


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14 OTC 19679

to allowable values. Results show that the hybrid riser design is driven significantly by the 100 year loop current and by the 100 year

cold eddy current environments. The 100 year loop current results in maximum deflection of the buoyancy cans and also in maximum

jumper deflection for the connected condition. The 100 year cold eddy current results in the maximum deflections of the disconnectedturret buoy.

Maximum angles at the jumper ends occur during the 100 year loop current when the turret is connected to the FPSO. Similar

maximum angle deflections are seen during the 100 year cold eddy current when the turret is disconnected. These cases will determine

the preliminary bend stiffener size (prior to fatigue analysis of the flexible jumper). Analysis also showed that emergency release of

the turret buoy is also a governing case for bend stiffener design.Maximum tensions in the jumper occur at the turret connection in the connected condition during the 100 year winter storm.

Jumper tensions at the frame connection (and tension variations) are significantly less than those at the turret connection. The stormanalysis did not find any compression in the jumper. Minimum bending radii in the jumpers occur at the turret connections.

Regulatory Requirement

The objective of the regulatory task was to provide an overview of the high level requirements of rules and regulations that are

applicable to an EPS FPSO in the Gulf of Mexico. Specifically,

To identify rules and regulations which are applicable to EPS and riser in comparison with the FPSO used in theEnvironmental Impact Statement in 2001 [3].

Check high level compliance of EPS FPSO by reviewing the status of gaps identified in regulatory frame work [4].

To discuss key issues with regulatory bodies on the EPS FPSO concept design and specification

Status of Gaps

The status of gaps identified in the Regulatory Model [5] is as follows. The two MMS items were closed. Out of seven items unde

the USCG, five were closed and two remain open. There are also four items that are under their joint-responsibilities all of whichneed to be resolved. Finally, two items that are the responsibility of industries have been closed, but six items remain unresolved.

Issues discussed with USCG and MMS

Two meetings were held to present the EPS concept to the USCG and the MMS. The issues discussed include: requirement formarker buoy, disconnectable turret, QC/DC and their components, the FSHR system and custom issues when the FPSO is

disconnected. Other topics of discussion include shut-in device (or HIPPS), dry-docking requirement, polyester rope, offloading hose

ESP technology, and Rules applicable to FPSO.A preliminary conclusion is that there are no major regulatory issues that would prevent the use of an EPS FPSO in the Gulf of

Mexico. However, the detailed design and the complete field development plan must be submitted for a final approval.

Qualitative Risk Assessment

A risk assessment was conducted to ensure that all design-based risks associated with the EPS, specifically those not previously

addressed in the EIS FPSO study [3], were clearly defined and ranked. Distinctions were made, identifying whether these hazards are

unique to the EPS or are common for the Gulf of Mexico or other FPSO installations worldwide.One high level risk scenario (Level 4) and nine medium level risk scenarios (Level 5) were identified for the EPS system. The high

level risk is not EPS specific and applies to all deepwater umbilical applications. The risk is leak/blockage of the umbilical used for a

continuously injected chemical due to particulate buildup, incompatibility etc. If the continuously injected chemicals cannot reach theproduction stream, many flow assurance problems can result. Furthermore, repair or replacement of the umbilical may be necessary

depending on the amount of damage sustained.

Medium and lower level risks are considered manageable through further engineering. Therefore, it is preliminarily concluded tha

no additional risks are identified for the use of EPS FPSO in the GOM, which is in-line with what was previously concluded for theprogrammatic permanent FPSO in the GOM. More details of this risk study can be found in [2].

Conclusion

From this study, a preliminary conclusion is that a DP FPSO with Free Standing Hybrid Risers (FSHR) for production and gasexport is a technically feasible option for early production of newly discovered deepwater fields in the Gulf of Mexico. It is also a

cost-effective solution for isolated fields which have no existing pipeline infrastructure in the vicinity for transporting oil and gas. It isalso an attractive option if extended well testing is required to justify the huge cost of installing new production facilities and

pipelines.


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OTC 19679 15

The FPSO will be of double hull construction to comply with OPA 90 having a minimum oil storage capacity of 0.5 mmbbls. The

stationkeeping of the FPSO is achieved by a full DP-2 system with an internal turret located at approximately 15% of vessel length

from the bow. The optimum location of turret, however, needs to be determined during detail design. The light mooring system inthree groups of two lines is considered for the buoy disconnected condition consisting of chain-polyester rope-chain connected to a

suction pile

The single leg Free Standing Hybrid Riser (FSHR) has been used for two production risers and one gas export riser. The load cases

selected to design the riser system include hydro-testing condition, operating condition, extreme operating condition, survival

condition and accidental shut-in case. Both riser connected and riser disconnected conditions are considered. Fatigue of the verticalriser has been analyzed for the production riser to confirm that the fatigue life is acceptable. Through this study, the preliminary

conclusion is made that the FSHR, which has been field proven in other regions of the world, is a technically viable and cost effectivesystem to be used with an FPSO in the deepwater regions of GOM. However, it is recommended that further studies be performed for

a specific development to evaluate the best alternative of mooring system for site specific conditions.

Acknowledgement

The authors wish to thank DeepStar, especially 8403 Subcommittee for their support and permission to publish this paper. The

authors also wish to extend thanks to representatives from MMS, USCG, and Dept of Homeland Security-US Custom for the

discussion on the regulatory issues.

Nomenclature

CFR: Code of Federal Regulations

CNG: Compressed Natural Gas

CP: Conceptual Plan

CVA: Certified Verification Agents

DPS: Dynamic Positioning SystemDWOP: Deep Water Operations Plan

EIS: Environmental Impact Statement

EPS: Early Production System

FPSO: Floating Production Storage and OffloadingFSHR: Free Standing Hybrid Riser

ESP: Electric Submersible Pump

GOM: Gulf of MexicoGTL: Gas to Liquid

MMS: Minerals Management ServiceQC/DC: Quick Connect Disconnect System

USCG: United States Coast Guard

References

[1] DeepStar, CTR 7404 and CTR 7405, Design Basis, Rev 1 (March 2004)[2] DeepStar Final Report DSVIII CTR8403-1, Specification of Early Production System and Riser System in the Gulf of Mexico, (Sep

2007).[3] DeepStar Final Report CTR 4109-1, Proposed Use of FPSO System on the GOM OCS, Final Environmental Impact Statement, MMS,

(January 2001).

[4] DeepStar CTR 4109-3, Regulatory Framework FPSO Systems, (September 2000)

[5] DeepStar CTR 4109-4, FPSO Regulatory Model, (September 2000)

[6] MMS & USCG, Memorandum of Agreement between the Minerals Management Service U.S. Department of the Interior and the U.S.Coast Guard U.S. Department of Homeland Security, (September 2004)

gulf of mexico exploration

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