OTC 24162 Cascade and Chinook Subsea Development – a Challenging and Successful Case History Sergio Porciuncula, Petrobras, Petrobras, Gus Cassity, John Weigle, Kazuhico Kochi and Michael O’Donnell, Petrobras America Inc., and Craig Masson, RiserTec Copyright 2013, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 6–9 May 2013. 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 by the 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 members. Electronic 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 an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.
Ab st rac t This paper is based on the subsea work performed during the design, implementation and operation of the Cascade and Chinook Field Development Project in ultra-deep ultra-deep waters of the U.S. U.S. Gulf of Mexico (USGoM). (USGoM). It describes the engineering, procurement, construction, installation, operation and integrity management phases of the subsea production system. This project required several innovative technologies and and solutions that resulted in several “firsts” and records for the industry: first of a kind and deepest deepest subsea boosting system with ESPElectric submerged pumps installed on the seabed at 8800 ft, non-conventional power umbilicals utilizing carbon fiber rods as the principal tensile strength elements, first subsea pull-in of umbilicals utilizing a submerged winch, deepest and highest pressure rated Free Standing Hybrid Risers (FSHRs), deepest pipe-in pipe flowline and deepest gas export pipeline. T his case history paper also describes the procurement strategies employed and the project management systems adopted to mitigate technical, time and cost risks. Introduction The C&C fields are located in the Walker Ridge Outer Continental Shelf (OCS) leasing area of the central USGoM. Both fields are situated near the base of the Sigsbee Escarpment on the the abyssal plain of the USGoM in ultra deep water. Cascade is located about 160 miles south of the Louisiana coast coast in 8,200 ft water depth and Chinook is about 15 mile s due south of Cascade in 8,800 ft water depth. The Cascade discovery was made in 2002 and Chinook was was discovered in 2003. The C&C reservoirs are in the the Lower Tertiary (Wilcox) Ultra-Deepwater trend. trend. After appraisal work the C&C was sanctioned in late 2007 based on a phased development concept. The initial project phase, the the subject of this this paper, is an early production scenario based on a limited number of wells and subsea infrastructure and the purpose of this initial phase is to gain reservoir information in order to optimize future development phases. The initial phase utilizes a leased, disconnectable, floating, production, storage storage and offloading (FPSO) vessel located between the fields. Produced oil is transported from the field in shuttle vessels and gas is exported through an export pipeline. The main reason for selecting the FPSO was safety, primarily with respect to hurricanes. The detachable turret mooring buoy provides a mooring point for the FPSO and during the approach of a hurricane the buoy enables the FPSO to disconnect in a short period period of time in order to depart the area. Future phases increase the amount of producing wells and subsea infrastructure and a definitive optimized permanent production facility is to to be installed in the last phase. Decisions on the type of and design basis of a definitive facility and number of wells will be finalized in 2013 and 2014. The position of the Cascade and Chinook fields is shown in Fig. 1 on 1 on the next page.
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Fig. 1 - Location of the Cascade and and Chinoo k Fields
Phased Development Concept After the discovery wells in Cascade in Chinook two more wells were drilled in Cascade in 2005 and field development concept studies were initiated in 2006. The C&C reservoirs are in the Lower Tertiary Tertiary (Wilcox) UltraDeepwater trend (Walker (Walker Ridge area). These fields are the first analogues for a mostly untested trend which is still projected to have significant production potential. potential. Currently, numerous oil & gas companies have several Wilcox fields, prospects, and plays in varying stages of development in the area. However, in early 2006 the situation facing the subsea team could be described in the following ways:
Very limited geological and well data; Lack of field analogues; Harsh environmental conditions (hurricanes and loop/eddy currents); Ultra-deep water (8100ft to 8900ft depth); Lack of existing pipeline infrastructure; FPSO regulations under development; Tight MMS Suspension of Production deadlines; Operator’s willingness to produce ASAP.
In short, the data available during the 2006 concept studies was insufficient to form the basis of a full field development program for C&C. However, there was sufficient data to implement a phased development plan and the initial phase would be an early production system based on a small number of initial wells and minimal subsea infrastructure. The subsea development concept, while minimal, minimal, is extremely extremely flexible and enables multiple development scenarios in future phases and production of up to 80,000 barrels of oil per day. The flexibility comes from utilizing standard modular equipment concepts that can easily be expanded as well as having adequate capacity in the production facility to handle the future future production potential. Well data will be gathered in the initial phase in order to verify the reservoir assumptions and to optimize the design basis of a full field development. As the subsea planning evolved, the initial phase grew to to two wells in Cascade and one well in Chinook connected to a leased common floating, production, storage and offloading (FPSO) vessel located between the fields. Produced oil is transported from the FPSO in shuttle vessels and gas is exported through an export pipeline.
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Subsea System Overview The primary elements of the subsea field architecture for the initial phase are shown in Fig.2 below. The fields lie in a north-south direction with Cascade being the northernmost field. Cascade East is approximately 15 miles from the Chinook drill center and about 2.5 miles from the FPSO. Cascade East is in about 8150 ft water depth and Chinook is in about 8857 ft water depth. The FPSO is in 8200 ft water depth.
Fig. 2 - C&C Layout
In the initial phase there is one drill centers with 2 wells in Cascade and one drill center with one well in Chinook. Additional drill centers and subsea architecture will be required as the well count exceeds the capacity of the manifolds within the drill centers. The flexibility of the subsea modular equipment concepts enables several production expansion scenarios. Dual flowlines were selected to enable round-trip pigging and flowline displacement from the disconnectable FPSO and to provide the ability to comingle production wells with similar pressure profiles. Flow diagrams for Cascade and Chinook are shown in Fig. 3 and Fig. 4 respectively on the next page. As can be seen in Fig 2, Fig. 3 and Fig 4 the production wells are located in the drill centers and are clustered around 4-slot manifolds within the drill centers. The subsea trees on the wells are attached to the manifolds by rigid steel jumpers and production from the wells is comingled with other producing wells at the manifold. The combined production is then directed down dual flowlines to subsea electric boosting pumps located on the seabed flowlines. The boosting pumps increase the pressure in the flow and direct the product down the flowlines to Free Standing Hybrid Risers (FSHRs) that connect the seafloor flowlines to the surface facility (FPSO). In the flow diagrams shown below only the subsea boosting pump cartridges and power umbilicals from the FPSO to the pump stations have not been installed.
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Tree
FSHRS
Boosting Pump Manifold
Fig. 3 - Cascade Subsea Productio n Flow Diagram
Tree
Chinook Riser Bases
Chinook
CH01-Q-AY-01
CH01-J-WJ-01
MP FM
Riser To Turret
CH01-J-FJ-01
CH01-F-PLT-02
CH01-J-FJ-03
FSHRS CH01-R-PLT-01
CM PT
CM CM
CH01-F-PLT-01 CH01-F-01
Riser To Turret CH01-J-RJ-01 CH01-F-PLT-04
CH01-J-FJ-02
CM PT
CM CM
CH01-J-FJ-04
CH01-F-PLT-03 CH01-F-01 CH01-J-RJ-01
CH01-G-AY-01
Boosting Pump CH01-P-AY-01
CH01-R-PLT-02
To Turret
Manifold CH01-U-CD-01 (UCD-CHK-01)
Fig. 4 - Chinook Subsea Productio n Flow Diagram
Trees The FMC supplied subsea production trees are 5”x 2”x 15,000 psi, guidelineless, horizontal trees mounted directly on the marine drilling wellheads. Typical shut-in pressures at the trees are about 12,400 psi. The tree, connectors and structure are designed to withstand all life-cycle loads, including the high riser loads during drilling, completion and workover operations resulting from water depth and environmental conditions. Adequate erosion allowance is provided in the pipe bends and other areas where erosion/corrosion could be expected. There is provision for dosed injection of scale inhibitor, asphaltene inhibitor, corrosion inhibitor and low dosage
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hydrate inhibitors (LDHI) through 4 chemical metering valves locate on the tree. There are also multiple points for injecting methanol (MEOH). Multiphase flow meters are positioned on the tree to manifold jumper. Manifolds Each drill center, is equipped with one 4-slot 2-header subsea manifold. The manifolds are production gathering points for the production wells with the capability for up to 4 wells clustered in the vicinity of the manifold. The wells are attached to the manifold with steel pipe jumpers. The lighter weight of the 4-slot manifold when compared to 6 or 8 slot manifolds enabled a higher number of installation vessels to be considered for installation of the manifolds.. The two headers in each manifold are connected by a retrievable pigging loop. By removing the pigging loop, two new flowlines can be attached in order to piggy-back additional production from future drill centers while maintaining full functionality to pig and displace the flowlines. Individual wells can be directed into either header on the manifold which allows the segregation of wells for test purposes or for pressure and water cut issues. Free Standing Hybrid Risers (FSHRs) The seabed flowlines and gas export pipeline are connected to the FPSO by free standing hybrid risers (FSHR). There are 5 FSHRs in total. Each riser consists of a section of vertical line pipe tensioned at the top by a nitrogen filled buoyancy can and anchored to the seabed by a deep-piled foundation. In the case of the production FSHRs, the pipe is 9.625 in. O.D. X 1.32 in wall thickness. The gas export FSHR pipe is 7.5 in O.D. X 0.75 in wall thickness. The riser is connected to the host FPSO mooring buoy by flexible pipe jumpers allowing vessel motions to be substantially decoupled from the FSHR. The production flexibles have a design pressure rating of 10,000 psi. The gas export flexible has a design pressure of 3,565 psi. A picture of the elements of the FSHR is presented in Fig. 5 on the next page.
The advantages of an FSHR in this field configuration with a disconnectable turret buoy system at the FPSO are:
Isolation from vessel motions; Significant reduction in hang off loads on the mooring buoy thus greatly reducing the size of the mooring buoy; Ability to pre-install the risers off project critical path.
The FSHRs reduce the loading on the vessel mooring system and thus helps to enable the improved hurricane safety case by reducing the overall size of the disconnectable turret mooring buoy of the FPSO. The Cascade and Chinook production FSHRs are the highest pressure rated (10,000psi) and deepest free standing hybrid riser (8200 ft/ 2500 m) in the world. One of the Chinook Production FSHRs failed in 2011 and this resulted in project delays at both Cascade and Chinook. This failure is described in more detail in the Execution Chapter of this paper. Flowlines The dual production flowlines in both fields are looped at the drill center manifolds to allow round trip pigging and displacement of fluids from the FPSO. The Cascade production flowlines are 9.625 in. nominal O.D. X 0.995 in. wall thickness and thermally insulated with 3.386 in. inches thick multiple-layer polypropylene. The Chinook flowlines are pipe-in-pipe (PIP) with the outer pipe 14 in. O.D. X .756 in wall thickness and the product carrier pipe 9.625 in. O.D.X 1.211 in wall thickness. An Aerogel nano porous material is enclosed in the pipe-in-pipe annulus for additional insulation. The thermal performance of the flowlines and risers allows 24 hours for displacement and disconnection in a hurricane event.
Beyond the Sigsbee Escarpment, which marks the edge of the Outer Continental Shelf, extensive regions of the seabed are furrowed and the furrows necessarily imply high bottom currents. One of these furrowed regions is located between the Chinook drill center and the FPSO location. There are almost 9 miles of furrows with the widest being 174 ft peak to peak and up to 30 ft deep. This necessitated the straking of almost the entire length of the two Chinook PIP flowlines (23 miles of straked flowlines) and this is illustrated in Fig. 6, on the next page, which shows a picture of the straked flowline being laid across one of the furrow peaks. From a procurement perspective and according to the manufacturer, it was the largest single order for flowline strakes in history.
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Fig. 5 - Free Standing Hybrid Riser System Config uration
Fig. 6 - As Laid Chinoo k PIP Flowl ines Showing Furrow Peak and Strakes
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Control System The FMC supplied subsea control system uses standard electro-hydraulic multiplexed (E-H MUX) techniques. The subsea control system is comprised of five subsystems:
Subsea Power and Communication Unit (SPCU) and Master Control Station (MCS), located on the FPSO; Hydraulic Power Unit (HPU), located on the FPSO; Umbilicals, Umbilical Termination Assemblies (UTAs), and Flying Leads; Subsea Control Modules (SCMs); Subsea and downhole instrumentation.
During normal production, control of the subsea system is done from the MCS on the FPSO. In addition the MCS is interconnected with the FPSO Process Control System (PCS) to exchange alarms and interlock signals. The MCS equipment use standard topsides control equipment modules, software and communications techniques to the extent practical. Control Umbilicals The MCS interfaces with the subsea control equipment via the hydraulic, electric and fiber optic components of the control umbilicals These are and is used to actuate valves and chokes and to retrieve sensor data for display on the PCS. These control umbilicals also provide chemical injection services to each well.
Each control umbilical’s subsea end is terminated in an Umbilical Termination Assembly (UTA). From the UTA, services are distributed to the trees, pumping stations and manifolds through infield umbilicals and electric and hydraulic flying leads. The Cascade control umbilical overall length is 25,085 ft. and the Chinook control umbilical overall length is 74,237 ft. The control umbilical is shown in cross-section in Fig. 7 below:
Fig. 7 - Control Umbil ical Cross Section
The following design features are incorporated in the umbilical:
The control umbilical contains16 super duplex tubes for chemical and high and low pressure hydraulic
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distribution. These tubes also provide a high degree of axial stress resistance and eliminates the need for other axial tensile elements in the umbilicals; The interior of the umbilicals incorporates a PVC interlocking matrix which provides individual conduits for the functional elements of the umbilical There are 6 electrical quads in each umbilical with 10mm2 conductors. This size was required in order to minimize conductor resistance A low lazy wave configuration was selected to reduce the combined bending and compression loads at the touch down point Lateral excursions of the umbilical is limited by a tether attached to a clump weight The touchdown point is unpinned and allowed to move
Fig. 8 below depicts the control umbilical arrangement for Cascade and Chinook. Refer also to Fig. 2 for a more
complete depiction of the field’s arrangement. Also note that Fig.2 shows 2 FSHRs for the Chinook flowline system what Fig. 8 only shows 1 reflecting the FSHR failure in 2011.
Fig. 8 - Control Umbil ical Arrangement
Power Umbilicals
The two power umbilicals will be installed in 2013. The umbilicals will be utilized to provide power for up to two pump cartridges in each field. The umbilicals connect the FPSO turret to the power/pump interface in the drill centers. Each umbilical consists of three triads, one of which is considered spare. The umbilicals from each field are terminated at the surface in the FPSO detachable mooring buoy. The power umbilical is shown in crosssection in Fig. 9 on the next page: Design features of the power umbilical are shown below:
Flex fatigue - life service of 25 years with a factor of safety of 10. Crush - umbilical design is highly resistant to crushing loads (installation). Can deliver over 1.4MW of three phase electrical power to the subsea boosting pumps.
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Each of the 3 electrical circuits in the power umbilicals is a three phase triad and each conductor is sized at 150mm2 to minimize conductor resistance to the possible 230 amp current. Carbon fiber rods are utilized in the design in order to create a strain limiting structure. Increased frictional coupling points are integrated into the umbilical structure to promote load sharing. The Insulation is a water tree resistant cross linked polyethylene (TRXLPE).
Fig. 9 - Power Umbilical Cross Section
Boosting System
Subsea boosting pumps are utilized in the project to maintain a drawdown in the reservoirs by adding energy to the produced fluids to overcome the static head of the 8,200 ft depth column in the FPSO location. The concept is an electrical submersible pump (ESP) mounted within a cartridge that is further connected to a pump manifold base attached to the flowlines on the seafloor. The Cascade pump manifold base is located in the Cascade West drill center and the Chinook pump manifold base is located in the Chinook drill center. The pumps will operate with a maximum gas void fraction (GVF) in the range of 5% to 10%. Pump cartridges are installed on the pump manifold bases located in the drill centers. Pump cartridges are installable and retrievable by cable and were designed so that they could be installed by medium multi service vessels of which there are many operating in the USGoM. The concept is illustrated in Fig.10 on the next page. In the initial phase, one 25,000 bopd pump cartridge is installed on one flowline from Cascade and one 25,000 bopd pump cartridge is installed on one flowline from Chinook. Each pump manifold base incorporates a bypass feature that in the bypass mode allows continued production if the pump cartridge requires repair and during pigging operations. Each pump station requires approximately 1.4 MW of electrical power in three phase form when operating with 2 pump cartridges. Up to 2 pump cartridges can be installed on the pump bases. The electrical power is direct (21km) with no transformers via a variable frequency drive located at the FPSO. To illustrate the relative size of the pump cartridge, the 110 ton 92 ft long electrical submersible pump cartridge is depicted in Fig. 11 on the next page. Note that the pump cartridges have not been installed and are scheduled for installation in late 2013.
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Fig. 10 – 2 Retrievable Pump Cartridges Installed On the Pump Base
Fig.11 - ESP Pump Cartridge Being Low ered onto Transpor tation Skid
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Variable Frequency Drive (VFD)
Each electrical subsea boosting pump is connected via the power umbilical to a variable frequency drive (VFD) located in the FPSO VFD module. The VFD provides speed control for the operation of the pump. The electrical power is transferred through the turret of the FPSO via an electrical swivel (slip-ring) in the turret. The VFD module shown in Fig. 12 below is located on the FPSO and contains four Siemens Gen 3E VFDs. Each VFD is rated to deliver up for 3,000kVA and provides electrical power in 3 phases.
Fig.12 - VFD Modu le
Flow Assurance
The overall C&C flow assurance strategy considers using continuous inhibitor injection as well as insulation and thermal energy to prevent hydrates and wax formation during normal operations. This strategy is used due to the long flowline tieback distances making it difficult to keep the temperatures above hydrate formation temperatures in case of a production interruption. This strategy provides a cool down time of typically over 12 hours. Hydrate blockage concerns are therefore limited to stabilization of wet flowlines and wet equipment following a shut-in, and prevention of hydrate blockages during subsequent restart (warm-up) events. The trees, jumpers, manifolds, flowlines and risers are thermally insulated to provide an adequate time for intervention before cooling down to the hydrate formation temperature. Blowdown and diesel circulation are planned to prevent hydrate formation in the flowlines, risers, and manifold during prolonged shut downs. Methanol injection will be used to prevent hydrate formation in the wellbore, trees and well jumpers upon shut-in. Low dosage hydrate inhibitors will be used for system start-up and restart. Contracting Strategies and Procurement
C&C subsea development is extremely complex due to water depth and environmental concerns, high pressure and high temperature concerns, and new product development concerns. As a result of this complexity the decision was made to go with an EPC commercial strategy for the major subsea scopes of equipment supply and a lump sum commercial strategy for the major subsea installation contracts. Potential service providers were also limited to world class contracting companies as these commercial strategies put the majority of the responsibility onto the contractors, who are the experts. This contracting strategy freed up the subsea project team to concentrate on project management (HSE, cost, schedule, interface control and quality) as well as checking on a
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robust qualification process for the new technologies and components. Contract Packages for subsea equipments and services were carefully planned to mitigate interface risks (between packages and also wells and FPSO) and simultaneous operations (between installation vessels, service vessels and drilling rigs). In the second half of 2007 and the first half of 2008 eleven major contracts were awarded for project goods and services and these are shown in Table 1 below: Table 1 - Cascade and Chinook Project Major Contracts Contract Type
Scope
Provider
EPC
Trees and Manifolds,
FMC Technologies
EPC
Controls System
FMC Technologies
EPC
Subsea Boosting Pumps
FMC Technologies
EPC
Control and Power Umbilicals
Aker Solutions
EPC
Line Pipe and Bends
Tenaris
EPC Supply
Technip
Lump Sum Installation
Free Standing Hybrid Risers supply and FSHR, Manifold and Pump Installation
Lump Sum Installation
Cascade Infield Flowlines and Gas Export Pipeline
Technip
Lump Sum Installation
Chinook Infield PIP Flowlines
Heerema
Lump Sum Installation
Control Umbilicals
Subsea 7
Rental
IWOCs (Integrated Workover and Control System)
Aker Solutions
Day rate
Provision of general use Multi-Service Vessel
Veolia
The subsea commercial and contracting strategies were a success on the Cascade and Chinook Development Project as all subsea equipment and installation scopes were delivered on time and within budget, with HSE excellent results. Subsea team and management were able to overcome unexpected problems (that are expected to happen in such complex projects) as the failure of one of the Chinook production FSHRs (which is described in the Execution Chapter) and the late delivery of the FPSO. During the procurement cycle equipment was manufactured in 21 different countries around the world as can be seen in Fig. 13 below:
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Fig.13 – C&C Project Worl dwide Constru ction Sites
Execution Timeline Through Subsea Commissioning Cascade was discovered in 2002 and Chinook in 2003. Two more wells were drilled in Cascade in 2005. Development concept selection started in 2005. During concept selection several trade-off analyses were performed to choose the technologies and components to be used in the subsea system. The use of “fieldproven” equipment and equipment requiring product development were carefully balanced to ensure the system met the functional requirements within project schedule, cost and regulatory constraints. Schedule and technical flexibility were the key drivers for most of the decisions made during the concept phase. After the concept was defined, a short FEED was performed in 2006 to further define the system and prepare the subsea bid packages. In parallel to the FEED execution, a large campaign of soil and metocean data collection was started to complement and confirm the data previously acquired. Also in parallel to the FEED phase, the commercial and contracting strategies and project schedule were defined. After FEED the project moved into a challenging “fast track” procurement phase. During the procurement phase, the main challenges were:
Ensuring everything was fit for purpose Assure timely delivery of all the system and components to maintain schedule flexibility and reduce SIMOPS Manage the interfaces between subsea vendors, the subsea system and the production facility
The subsea installation campaigns began in the 2nd quarter of 2009 and ended in the 2nd quarter of 2010. The successful execution of these campaigns was recognized early on as a key to overall project success and several project management tools were implemented to help control SIMOPS (simultaneous operations) between the various installation and drilling vessels in the fields. At one time during this phase there were 5 major installation vessels and two drilling rigs in the field simultaneously. Considering the entire project, there has been only 1 lost time SIMOPS of about 1 day which is a fairly remarkable achievement. Subsea commissioning was complete in the first quarter of 2010.
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SIMOPS
There was early recognition that with the complexity of the subsea installation S.PS risk is that one vessel would interfere with the operations of the other vessel causing delays and costs. One of the internal studies conducted at the time determined that there was about $200 million of potential risk resulting from SIMOPS for vessel costs alone. A management tool was developed internally to define the SIMOPS and assign vessel priorities for each SIMOP. This tool is shown below in Fig. 14. What is shown is a matrix with the primary project tasks listed both across the top and left side of the matrix. SIMOPS definition and vessel priority is shown in the matrix for each task. Risk mitigation involved changing schedules to delay or eliminate the SIMOPs After the installation campaigns were finished a review of the SIMOPS performance was made and it was estimated that SIMOPS had resulted in about $750 k costs. This cost resulted from a conflict between drilling operations in the Cascade East drill center and the need to initiate a flowline lay within the drill center.
Fig. 14 - SIMOPS Control Tool
Control Umbilical Pull in
One of the interesting SIMOPS concerned the installation and pull in of the Cascade and Chinook control umbilicals. The original SIMOPS was between the FPSO and the Control Umbilical Installation Vessel. The method for attaching the umbilical to the FPSO mooring buoy involved utilizing a winch located on the FPSO with the winch line run through I- tubes in the connected mooring buoy. The umbilical installation vessel was to perform a subsea handoff of the umbilicals to the FPSO winch wire that would then pull the umbilical into the buoy, after which divers would connect the bend stiffener latching mechanism at the bottom of the I-tube and topside personnel would affect the hang-off of the pull head of the umbilical on top of the buoy inside the FPSO. To avoid the risk of the FPSO delivery schedule, the decision was made to decouple both the mooring buoy
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installation campaign and the control umbilicals installation campaign from the FPSO delivery. The decision involved using a submerged winch affixed to the top of the FPSO mooring buoy and operated by ROVs to pull in and attach the umbilicals to the mooring buoy. The technology of the subsea pull in involved using a specifically designed subsea winch and adapter frame that would interface with guide posts positioned in the unused I-tubes in the top of the mooring buoy located which was located at about 180 ft water depth. The frame and the winch are shown during SIT in Fig. 15 and Fig. 16 below:
The previous role of the FPSO in the pull in of the umbilical was replaced by a multi service vessel (MSV) with a 250 ton crane. Fig. 17 shows the winch adaptor frame being installed on top of the submerged mooring buoy by the MSV.
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Fig. 17 - Subsea Installation of th e Winch Frame on the Mooring buo y
The procedures to make the pull in are bulleted below:
Install adapter frame guideposts atop I-tubes during Mooring Buoy Fabrication Install Adapter Frame and Subsea Winch on Top the Buoy Transfer Umbilical via ROV to Winch Pull-in Rope ROV Activate Winch and Commence Umbilical Pull-in to I-Tube Latch Umbilical bend stiffener mechanism to I-Tube via ROV Continue Umbilical Pull-in Through Buoy ROV operate temporary hang-off mechanism to lock umbilical pull head in place atop I-tube.
Fig. 18 depicts ROV actuation of the subsea winch during Umbilical pull in operations. This was the world’s first umbilical pull in using a submerged winch.
Fig. 18 - ROV Actuation of Subs ea Winch Durin g Control Umbilical Pull In
Chinook Production Riser Failure
On March 23, 2011 and just prior to initiating production of the Cascade field the Chinook 01 FSHR buoyancy can chain tether failed and FSHR collapsed. The chain failure was due to non authorized weld repair during its fabrication. The resulting damage to the FSHR can be seen in Fig. 19 through Fig. 22 below. Refer also to Figure 5 for the original location of the various elements of the FSHR. There were neither injuries to personnel nor spills of any type.
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Fig. 19 - Failed 6 ¾ inch 862 lb FSHR chain tether link as found in 8,209 feet water depth
Fig. 20 – This is one of the first pictures of the Top Riser Ass embl y o f t he FSHR taken after the incident. Note the TRA and Riser are suspended by the 2400 ft long flexible jumper that is attached at its oppo site end to the FPSO moorin g buoy. The bend restrictor on the flexible jumper is seen broken but the jumper and flowline system was h ydraulically intact. Further note broken chain tether hanging at left side of figure.
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Fig. 21 – The Chinook Flowline PLET, Riser Jumper and Sections of the FSHR are shown. In spite of the bent riser pipe the flowli ne was still hydraulically intact.
Fig. 22 - FSHR Buoyancy Can being towed to beach. The end of the buoyancy can where the tow line is attached is weighted down by 2 links of chain tether and a universal joint (part of the chain tether) and rides lower in the water than the other end.
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Since the incident the failed FSHR has been removed from the seafloor leaving the Chinook field with one intact flowline to produce through. Temporary synthetic back up tethers comprised of synthetic grommets were installed on the remaining 4 FSHRS (2 for Cascade, 1 for Chinook and 1 for Gas Export) to mitigate the risk of similar FSHR failures and to enable the replacement of the original chain tethers with new chain tethers. After installation of the temporary back up tethers the original chain tethers were successfully removed and replaced with new chain tethers. Permanent pretensioned back up tethers have also replaced the temporary back up tethers on each of the FSHRS. The tether arrangement, with the new chain tethers and permanent synthetic back up tethers, is illustrated in Fig. 23 below. Reference also Fig. 5 to understand the relative position of the components. This new configuration eliminates the single point failure mode that existed prior to the installation of the backup tethers.
Fig. 23 - Chain and Synthetic Back up Tether Arrangement
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Production Start Up on Cascade
The Chinook FSHR failure did result in start up delays to both the Cascade and Chinook fields. On Cascade, the delays resulted from the need to mitigate the risk of similar riser failures. The mitigation involved replacing the original FSHR chain tethers with new chain tethers and adding permanent back up synthetic tethers. First oil was achieved without further incident at Cascade in February 2012. Production Start Up on Chinook
The production situation on Chinook was different from Cascade. With the loss of the FSHR it was not possible anymore to pig the flowlines or to displace the flowlines with diesel prior to FPSO disconnection. The decision was made to install a diesel supply flowline from the Cascade flowline system to the Chinook flowline system that would enable pigging. Subsea pigs would be introduced into the Chinook flowline subsea by a uniquely designed subsea pig launching system deployed with the new flowline. The new diesel supply flowline is attached to the Cascade flowline system by a flexible jumper hooked-up to an unused pump cartridge attachment hub located at the Cascade West pump base manifold. The diesel supply flowline then runs to a subsea pig launcher located near to the Chinook flowline PLET at the failed FSHR base as shown schematically below in Fig. 24. This diesel line and subsea pig launching system is a temporary stop gap measure to bring Chinook on line until the replacement of the FSHR takes place.
Fig. 24 - New Diesel Supply Flowli ne for Chino ok
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The subsea pig launcher is located on the diesel line PLET and is connected to the Chinook flowline with a steel pipe jumper. ROVs will be utilized to load and launch the pigs as required by operations. In operation, after the ROV has loaded a pig into the pig launcher, the hydrostatic overpressure of the seawater relative to the flowline pressure during pig launching (approximately 550 psi) is used to collapse a 1000 gallon ethylene glycol (MEG) bladder attached to the pig launcher. The MEG is used to push the pig from the launcher into the steel pipe jumper where the pig is parked until needed. Approximately 100 gallons of MEG is used to push the pig into the jumper each time a pig is launched. No subsea pump is required for this operation. Pig location can be verified by external detection of radioactive elements placed in the pig. When flowline pigging is required, diesel will be supplied from one of the Cascade flowlines routed through the diesel flowline into the Chinook flowline system. The pig which was previously parked in the steel pipe jumper from the pig is then pushed around the Chinook flowline system into a pig trap located on the FPSO. Once a pig is used, a ROV operation will again be required to launch and park another pig. The MEG bladder will be replenished on an as required basis. This arrangement is shown in cartoon form in Fig. 25. The subsea pig launch system has been used successfullyseveral times since installation. First oil was achieved at Chinook in September 2012 utilizing the new diesel line and pig launch system.
Fig. 25 - Cartoon of Subsea Pig Launch er Arrangement
Subsea Integrity Management
The Cascade and Chinook reservoirs have the potential to produce in commercial quantities for over 40 years. Petrobras recognize that the only means of ensuring equipment availability over the life of the field is through an aggressive integrity management program. The Cascade and Chinook Subsea Integrity Management Program is a hybrid system that integrates Risk Based Inspection (RBI) standards/accepted practices (API/DNV), Reliability Centered Maintenance (RCM) principles and guidelines and professional experience from Subject Matter Experts (SME) for the numerous specialized subsea assets that make up the entire subsea system. The program adheres to a traditional interpretation of the Integrity Management (IM) life cycle in that the IM discipline provides input for all phases of the field development from the initial conceptual study and front end engineering design through to operations and ultimately to decommissioning of the field and assets.
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The intent and ultimate objective of the program is to ensure the safe and reliable operation of the subsea system and to maintain regulatory compliance. This is achieved through the continuous identification and mitigation of risks and anomalies to As Low As Reasonably Practicable (ALARP) all while ensuring the use of Best Available Safest Technologies (BAST) throughout the field development life cycle. A unique attribute of the program to be highlighted in this paper is the rigorous upfront initial baseline inspection and monitoring regime established and currently in operation. The uniqueness of the inspection and monitoring regime is that the baseline inspection for the entire subsea system consists of a minimum of four (4) separate inspection campaigns spread across the first two (2) years of operation. The benefit of this approach is to obtain multiple data points as to the behavior of the subsea system as a whole and as individual assets early on in the operational phase. The inspections have been categorized, for purposes of this paper, as either "internal" or "external" inspections. Internal inspections are those inspections that can be performed from the topsides facility. External inspections are all inspections that are performed subsea via construction vessel and ROV. The listing provided is by no means exhaustive and is onl y intended to illustrate the various inspections performed. Internal Inspections: Water analysis - Monthly: potential indicator of internal corrosion based on metals in the water as well as inhibitor residuals and PH level. Oil analysis - Annual: providing information on metal content and PH level. Bacteria sampling during pig runs from pig receivers as well as from water samples: indicator of possible wall loss in stagnate or l ow flow areas Pigging – Biannual: for pipe cleaning and batch chemical treatments Corrosion probes monitoring - Continuous: both subsea and as the product boards the FPSO: provides corrosivity data both subsea and at the top of the FSHR. Sand detector monitoring - Continuous: near the well to evaluate erosion potential of the produced fluids and solids Pressure and temperature sensor trending - Continuous: for flow assurance purposes Pressure testing of Flexible Risers - Biannual: testing the internal annulus of the flexibles for an outer sheath breach in or near the splash zone.
External Inspections: General visual inspection - Biannual: for all subsea assets to verify existence of gross anomalies Close visual inspection - Biannual: for all subsea assets to monitor identified anomalies Pipeline specific visual inspection - Biannual: analysis of spans in excess of allowable spans for VIV Pipeline specific visual inspection - Biannual: pipe displacement caused by thermal expansion Pipeline specific close inspection - Biannual: multi beam survey for Gas export and Chinook pipelines to monitor potential growth in furrows region. Ref Fig. 26 below.
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Fig. 26 - Multi Beam Survey Data Results
Coating specific close inspection - Biannual: for all subsea assets to verify condition of applied coatings, coating repair, field joints Valve position visual inspection - Biannual: verification of valve position for actuated and manual valves Cathodic protection inspection - Biannual: verification of electrical potential for all anodes on all subsea assets via cathodic probes to ensure an active CP system providing electrical continuity Redundant Tether System – Biannual: close visual inspection Tether chain inspection – Biannual: photogrammetry verification via high definition camera for each riser buoyancy module tether chain link to verify inter grip integrity for wear and metal loss
Fig. 27 through Fig. 29 display some of the tools used in the IM work.
Fig. 27- Chain Measurement Tool
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Fig. 28– Muti-Camera view of Chain Measurement Tool deplo yed subsea
Fig. 29 - 3-D Modeling - Tether Chain Inter Grip Derived from Chain Measurement Tool Data.
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Firsts
The Cascade and Chinook Development Project has been very challenging and in many ways can be described as a project of “firsts” and “mosts”. Some of the significant project “firsts” and “mosts” are pointed out below:
First FPSO in the USGoM; Deepest floating production system (8,200 ft); First use of purpose-built Jones Act shuttle tankers in the US; First pull-in of umbilicals using subsea winch operated by ROV; Deepest and highest pressure rated free standing hybrid risers (8,200 ft at 10,000 psi); Deepest pipe-in-pipe flowline (8,800 ft); Deepest subsea boosting system (8,800ft); Deepest gas export pipeline (8,200 ft); First single trip multi-zone – frac pack system application (3 zones) in deep wells (27,000 ft).
Conclusions 1. The Cascade and Chinook subs ea development has been very challenging but was successful ly implemented. In many ways can be described as a project of “ firsts” and “ mosts” . A balanced equilibrium of field proven and new technologies was applied with success, associated to a robust q ualification proc ess developed in parallel. 2. The development is phased due to the limited reservoir data available. The purpose of the initial phase of the development is to gain reservoir information in order to op timize future development phases. The initial phase subsea infrastructu re is extremely flexible and enables multiple development scenarios in fut ure phases and producti on of up to 80,000 barrels of o il per day. 3. The commercial strategies for the major subsea scopes of equipment supply and installation freed up the Petrobras subsea project team and management to concentrate on project management (HSE, cost, schedule, interface control and quality) as well as i n the development o f new technologies and components. 4. An aggressive subsea integrity management system has been implemented to help ensure equipment availability over th e life of the fi eld. 5. An experienced and capable subsea project team is essential to overcome the unexpected problems (that are expected to happen in such a complex pr oject as Cascade and Chinook). 6.
The Cascade and Chinook subsea development opens new fro ntiers for ultra-deep water projects all around th e world. It paves the way to the development of th e Lower Tertiary in the US GoM and brings important kn owledge and expertise to the development of Pre-salt provinc es in Brazil.
Ac kn ow led gem ent The authors would like to thank Petrobras and TOTAL E&P USA, INC. for authorizing this publication as well as several members of the Cascade and Chinook Integrated Project Team for their contribution throughout this paper.
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References Weigle, J., Porciuncula, S., O’Donnell, M. 2010. Diverless Subsea Pull-In and Hand-Off of Umbilicals to a Submerged Turret Production Buoy: A World First. Paper IBP3534_10 presented at the Rio Oil & Gas Expo and Conference, Rio de Janeiro, Brazil, 13-16 September.
Porciuncula, S., Ribeiro, O., Cassity, G. 2010. Cascade and Chinook Development: Subsea Overview. Paper IBP3535_10 presented at the Rio Oil & Gas Expo and Conference, Rio de Janeiro, Brazil, 13-16 September.. Moody, R., Kochi, K., Porciuncula, S. 2010. Cascade and Chinook Power Umbilicals A Chall enging Development. Paper IBP3539_10 presented at the Rio Oil & Gas Expo and Conference, Rio de Janeiro, Brazil, 13-16 September. Palagi, C.L., Ribeiro, O.J., Mattos, D.M., Matta Jr. S. 2013. The Development and Production of Cascade and Chinook Fields in the Gulf of Mexico – an Overview. Paper OTC 24156 submitted for presentation at the Offshore Technology Conference, Houston, Texas, 6-9 May. Daniel, G. 2013. First Floating, Production Storage and off loading vessel in the US Gulf of Mexico. Paper OTC 24112 submitted for presentation at the Offshore Technology Conference, Houston, Texas, 6-9 May. De Moraes, F.D., Moreira, O., Haddad, Z., Ogier, S., Shipley, J., Rebelo, M., Gama, F. 2013. Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History .Paper OTC 24179 submitted for presentation at the Offshore Technology Conference, Houston, Texas, 6-9 May. Watkins, E. A., Fernandez, A.F.N., Syrio, J., Riera, L. A., Nguyen,N., Da Cruz, P. S., Leite, R., Becker, M.R. 2013. Cascade and Chinook Fields: Integrated Overview of the Reservoirs. Paper OTC 24163 submitted for presentation at the Offshore Technology Conference, Houston, Texas, 6-9 May. Barros, D., Daniel, J., Souza, E., Hibbert, O., Souza, M., Mastrangelo, C. 2013. Shuttle Tankers in the Oil Export of Cascade and Chinook Fields. Paper OTC 24202 submitted for presentation at the Offshore Technology Conference, Houston, Texas, 6-9 May.
