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Copyright 2001, Offshore Technology Conference
This paper was prepared for presentation at the 2001 Offshore Technology Conference held inHouston, Texas, 30 April–3 May 2001.
This paper was selected for presentation by the OTC Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Offshore Technology Conference and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Offshore Technology Conference or its officers. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the writtenconsent 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. Theabstract must contain conspicuous acknowledgment of where and by whom the paper waspresented.
AbstractThis paper presents an overview of the subsea systems for the
ExxonMobil Diana Project located in the East Breaks Area of
the Gulf of Mexico. The development is located 160 miles
offshore in water depths ranging from 4,500 feet to 4,700 feet.
The system features two, 4-well manifolds at remote drill
centers connected via a looped flowline system, capable of
producing 100,000 BOPD and 325,000 SCFD from the
Hoover host facility located 16 miles away in 4,850 feet of
water. The project was successfully installed and started up in
May 2000, with a number of equipment designs utilized byExxonMobil as an “ExxonMobil first” as well as the
establishment of several industry records.
IntroductionThe Diana field, located 160 miles offshore Texas (Fig.1),
consists of a four block unit in East Breaks (EB945, 946, 988
and 989). Equity is fixed at 66.67% ExxonMobil and 33.33%
BP, with ExxonMobil serving as the designated operator. The
discovery well (EB945#1) was drilled in 1990, a gas appraisal
well (EB945 #2) was drilled in 1996 and an oil rim appraisal
well (EB946 #1) was also drilled in 1996 (Fig. 2). Diana is a
gas and oil development. To develop this resource, the oil rim
is being exploited first using five horizontal wells (Phase 1 of program). Following oil rim depletion in approximately 2005,
some of the oil rim wells will be recompleted as horizontal gas
completions and several new drill wells will make up the 6-
well Diana Phase 2 program.
Diana features two 4-well manifolds located 2.3 miles
apart and connected by a single 10” flowline. Each manifold is
connected to the Hoover host facility, a deep draft caisson
vessel (DDCV), via an un-insulated 10” flowline. A single un-
insulated 6” flowline is also connected from the central drill
center (CDC) to Hoover and functions as a test/prod
flowline. A steel tube umbilical between Hoover a
northern drill center (NDC) and an infield umbilical b
the northern and central drill centers provide the com
electrical and hydraulic requirements to control the
Hydraulic and electrical flying leads are used to conn
umbilical termination assembly to each well an
manifolds. The wells are located around each manifo
clustered arrangement and connected to the manifol
flowlines using steel pipe inverted “U” jumpers (Fig. 3)
The installation operations of the Diana manifolds
and jumpers were all performed from the dynam
positioned Multi-Service Vessel (MSV) Uncle John.
some of these activities may have been on the threshold
capabilities of the vessel under certain conditions,
planning and execution by all parties enabled the pro
achieve significant cost reductions and schedule flex
over the traditional installation scenarios.
Development History
In January 1997, the Diana project kickoff meeting wwith ExxonMobil, BP and a number of outside engin
support teams to officially begin the execution of a F
Production and Subsea Tieback System. By the end
meeting the late breaking news of the oil discovery at
Hoover quickly turned the focus of the project fr
execution mode to that of a concept screening. Since th
had been formed and was prepared to move ahead
preliminary engineering for the FPS, the same teams b
4-month exercise of concept screening and selectio
number of concepts were evaluated (Fig. 4). These incl
• The development of the Hoover/Diana fields utiliz
Floating Production System (FPS) located betwe
two fields.• A Floating Production Storage Offloading (
concept located between the two fields.
• A Tension Leg Platform (TLP) at Hoover with a
tieback to Diana.
• A DDCV initially located at Hoover to drill w
subsea wells then re-locating to Diana and complet
Diana wells as dry tree wells.
.
OTC 13082
Diana Subsea Production System: An OverviewGregory N. Gist, Subsea Engineering Services
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2 GREGORY N. GIST OTC
During the activities of concept screening, a discovery well
at South Diana was made which ultimately had an impact on
the Diana system configuration. The southern well located in
the southern tip of the Diana reservoir and the South Diana
well are now planned for development as part of the Phase 2
program.
The subsea tieback to a new build deep draft caisson vessel
(DDCV) was ultimately selected as it provided the most cost-effective solution based on NPV and capex utilization.
Further, it offered the best chance to accelerate development
timing.
Reservoir CharacteristicsThe Diana field is a plio-pliestocene deep-water turbidite
sandstone reservoir with a large gas cap and narrow oil rim.
The A-50 reservoir is located at a depth of approximately
10,500 feet subsea with dips of 5-10 degrees and an average
gross thickness of 100'. The initial reservoir pressure is
approximately 5,350 psi and the reservoir temperature is
approximately 125 degrees.
Plans are to develop Diana in two phases; phase one targets oil
rim depletion while phase two is anticipated to produce the
gas cap reserves. Five horizontal wells have been drilled and
completed in the oil rim. Because the A-50 reservoir is
stratified, these wellbores cut the entire stratigraphy to contact
all internal flow units. (Fig. 2).
Drilling and CompletionIn order to achieve the goal of having five Diana wells
completed and ready for production prior to the installation,
hook-up and commissioning of the host facility, the drilling,
tree installation and completion of the Diana wells was
performed by a combination of three vessels. The Discoverer
Seven Seas performed batch setting operations starting inAugust of 1998 and initiated the casing strings in all five
wells. Starting in August 1999, the primary drilling vessel, the
Marine 700, was used to complete the drilling program and
initiate the completion program of the five wells. Prior to the
M700 initiating drilling and completion operations at Diana,
the MSV Uncle John was used to batch install the five subsea
trees. Pre-installed parking stumps at each drill center allowed
the flexibility to “hop-scotch” trees from a wellhead to a
parking stump as needed, and avoid costly trips of the BOP
stack. The overall drilling and completion program for the five
Diana wells took less than 15 months.
The Diana wells feature horizontal open-hole gravel packs.
The wells have 5-1/2” - 13 chrome tubing materials and eachwell has dual, 4-1/2” domed charged Surface Controlled
Subsurface Safety Valves (SCSSV) with dual hydraulic
actuators and wireline lockout capability. The SCSSV’s are set
at approximately 2,200 feet sub mudline, just below the
hydrate formation depth with a chemical injection point just
above it. Downhole pressure and temperature (DHPT) gauges
were installed in each well just above the packer and have
been able to provide valuable data at a 100% reliability to
date.
System DescriptionThe Diana subsea systems configuration was selec
provide maximum installation and operational flexibilit
wide range of installation programs and production sce
The resulting configuration of two 4-well clusters allo
round trip pigging between the host facility and the tw
centers, with the capability to direct production into any
3 flowlines. The wells are located around each mranging from 45 to 60 feet from the manifolds. The fl
sleds were installed in target areas located approxima
feet from the manifold. Flying lead lengths range from
160 feet from the umbilical terminations to the tre
manifolds. Final as-built layouts at both drill centers
Phase 1 oil rim development are shown in Figure
Figure 6.
The following systems describe the individual subs
in more detail.
Suction Pile and Manifolds
The manifold systems consist of two separate ma
schematically shown in Figure 7 and Figure 8 for the Pand Phase 2 developments respectively.
The manifolds are supported on identical piles, w
larger central manifold design setting the design basi
suction piles are 12 feet in diameter and 45 feet in lengt
piles were designed to allow immediate installation
manifolds onto the piles without having to wait fo
consolidation. A 30” conductor housing with radial
grooves provides guidance and alignment of the manifo
the pile. Pile orientation was not an issue during insta
due to the multiple indexing slots machined in 30” h
that allowed an installation tolerance of +/- 15 degrees.
The 4-well northern manifold is the smaller of th
manifolds and configured with a single 10” header hydraulic isolation valve. The manifolds are rated to 50
and are not insulated. Each well slot is configured with
valve block with hydraulically operated isolation valve
from each well is directed into one of the two smaller
headers, and then into either the 10” flowline to th
facility or the 10” flowline to the central manifo
pressure/temperature transducer and chemical inject
each branch header and all other hydraulic valv
controlled via a control pod located on the manifol
overall size and weight of the northern manifold is
16’W x 15.5’H and 125,000 lbs.
The 4-well central manifold is a larger manifo
configured with a single 10” header and a single 6” head
a crossover valve connecting the two headers. Three
branch headers and triple valve blocks with hydraulic is
valves allow for each well to be directed into any one
three flowlines. The 6” and 10” headers come togeth
wye block to connect the central manifold to the 10” fl
back to the host facility. A 5” and a 9” hydraulically op
valve provide the isolation between the two h
Pressure/temperature transducers are located on each
and chemical injection is also provided. All hydraulic
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
are controlled via a control pod located on the manifold. The
overall size and weight of the central manifold is 28’L x 24’W
x 17’H and 192,000 lbs.
The manifold system will allow for individual testing of
each well with flexibility to group certain wells into any one
of the three flowlines. A dedicated test line was selected
during front-end engineering because of the aggressive project
schedule and limited subsea experiences with multi-phaseflow meters at the Diana depth.
The production flowlines, test line and the infield flowline
connecting the two manifolds are configured for round trip
pigging. The configuration requires that two pigging runs be
made to pig all three lines. The 6” flowline is pigged from
Hoover to the central drill center and dumped into the 10”
flowline, and then a pigging run from Hoover to the northern
drill center, across to the central drill center, sweeps the 6” pig
back to Hoover. Total system pigging runs average
approximately 1 day.
The Phase 2 development of the Southern Diana well and
the South Diana well is accommodated by one of the central
manifold well slots being outfitted with a 6” connection hubfor future connection to a 6” infield flowline. These wells are
gas producers and aside from commissioning, this flowline
will not be designed for routine or round trip pigging. During
commissioning of this line, an ROV actuated diverter installed
in the central manifold piping will be used for pig runs to/from
the southern end of the field. Pigging may be in either
direction (Fig. 8).
Jumper Connection System
A vertical jumper system is used for connecting the manifolds
to the flowline termination skids, as well as to each subsea
tree. The jumper connectors are all collet type, hydraulically
actuated with mechanical overrides. Well jumpers areconstructed of 5” carbon steel pipe in an inverted U
configuration and used to connect the trees to the manifolds.
Both 6” and 10” carbon steel pipe piggable jumpers are used
for the connection between the manifolds and the flowline
termination skids. The jumper systems feature soft landing
systems integral to the connector and ROV interface panels for
actuating these functions as well as the connector and test
functions. A combination of both acoustic and taut-wire
measurement processes were used to determine subsea
metrology. A total of 10 jumpers were installed and 9 of the
10 jumpers tested successfully the first time. One jumper
required two seal change outs before achieving a successful
test due to a damaged seal.
Subsea Horizontal Tree
The subsea trees selected for the Diana Project are 4” x 2” –
5,000 psi horizontal guidelineless designs. The selection and
utilization of the horizontal tree was an Exxon first (pre
Exxon/Mobil merger) and was arrived at after a long,
extensive tradeoff, and life cycle cost comparison of the two
major tree suppliers. Key issues in the evaluation process
involved running and completion times, workover riser system
costs and availability, rig equipment logistics, tree insta
flexibility and well control & and safety. The suc
installation of the Diana trees in July of 1999 establi
depth record for horizontal trees, eclipsing the previous
of 3,400 feet.
Some of the key features of the Diana tree system i
dual SCSSV’s, dual Underwater Safety Valves (USV
dual chemical injection valves at injection points veconventional single valve with check valve barrier (F
All these features are primarily a result of the plans to
trees, complete and shut-in live wells as much as 18 mo
advance of the DDCV arriving on location, t
necessitating added tree security. Additionally, any equ
or test failures (SCSSV, USV & DHPTs) may not be re
therefore the redundancy in the extra valves was justifie
Further detailed design, construction and insta
information on the tree system is provided in v
companion papers listed in the Reference section.
Flowlines
The flowlines for Diana were engineered and managedflowlines group that functioned as a separate engin
group from the Subsea Systems group, although both re
to a Subsea Manager. A brief description of the Diana fl
and export systems is provided below.
The infield flowlines, main flowlines and steel ca
risers (SCRs) are carbon steel, un-insulated. The flowli
inhibited from corrosion by means of chemical injection
subsea manifold. The flowlines extend from the manif
the vicinity of the host facility, and lay unburied
seafloor. Flowline termination sleds are attached to the
the main flowlines and infield flowlines at the Dian
centers for connecting to the manifolds using stee
jumpers. The main flowlines transition directly to thportion of the flowline at the DDCV. The exact location
transition from flowline to SCR riser was determined ba
water depth, angle of approach to the hull hang-off poi
the DDCV vessel excursion offsets; no transition struc
connection was required. Each riser is a single
terminating with a flex joint and electrically insulated
flex joint. The incoming flowlines pass through a shu
valve (SDV) in route to the pig launcher/receiver and th
a production manifold located on the cellar deck of the H
facility.
Coiled tubing access on the DDCV has also been pr
for in the design in the event access is required to remo
liquid column in the Diana SCR’s if a hydrate plug oc
any one of the three Diana flowlines. Provisions ha
been made for coil tubing access for all future prod
SCR’s that may be hung-off in the spare porches.
removal of the liquid column allows the pressure to drop
flowlines such that the hydrate plug will melt, restorin
flowing production. The round trip pigging capability
system also allows for depressurization on the backside
potential hydrate plug.
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4 GREGORY N. GIST OTC
A number of hydrate mitigation strategies were evaluated
during the Diana preliminary engineering phase to address the
hydrate formation associated with increasing water cuts during
the oil rim production and gas cap blowdown. A few key
techniques evaluated included insulated flowlines and risers,
heated fluid, kinetic inhibitors, glycol injection, and injection
and recovery of methanol. The insulating of the flowlines and
risers proved to be unattractive because of the limited oilreserves after water production begins, and the effect of Joule-
Thompson cooling in the risers also diminished the
effectiveness of the insulation.
Capex and feasibility questions eliminated most others and
the recommendation to utilize methanol injection and recovery
to control hydrates was carried forward. A methanol
injection/recovery system on the Hoover facility provides up
to 2000 barrels/day of methanol injection, with the MeOH
recovery system designed for an 80% recovery factor.
The export pipelines for Diana include an 18” /20” gas
pipeline and SCR with a destination to the High Island
Offshore System (HIOS) with a tie-in point at High Island
573. The oil pipeline and SCR is also an 18” /20” thatconnects the Hoover facility to a Freeport, Texas oil
processing facility. The pipelines depart from Hoover with
initial sizes of 18”, then expand to 20”. Dual diameter and soft
pigs are used during pigging operations.
Production Control SystemDiana is controlled by means of an electrohydraulic control
system with operations from the Hoover DDCV facility. The
primary functions of the control system are to operate the
hydraulically actuated valves on the trees and subsea
manifolds, and to provide chemical injection. Dedicated
methanol injection lines are provided to each tree as well as
each manifold for continuous injection once required. In
addition, the Diana control system provides data readback
from the downhole instrumentation and the pressure and
temperature indicators on the subsea trees and manifolds.
The control system is a uni-pressure control system,
another ExxonMobil and industry installed first. The system is
designed for 5,000 psi with a normal operating pressure of
4,000 psi. As opposed to the conventional dual pressure
systems that operate with high and low pressure systems, all
Diana trees, manifolds and SCSSVs operate at a common
pressure. Special design features and considerations impacted
by the selection of the uni-pressure system were the
qualification of the direct control valves (DCV) and the
addition of a special circuit in the control module circuit to
prevent SCSSV closure before tree valves during hydraulicbleed down.
The decision of the project to install the subsea control
modules (SCMs) with the trees and manifolds with the
intention of leaving them subsea for up to 18 months before
connecting and operating the SCMs had to be properly
addressed. Recent history has not been kind to control
modules left subsea. Great pains were taken to ensure that the
SCMs were free of any entrained air prior to installation and to
ensure that they were fully flushed after arriving subsea to
ensure no salt water had entered the hydraulics. No pr
occurred during startup, 10 months after being placed su
The decision to use the uni-pressure system was
primarily on cost reduction opportunities associated wit
design and manufacturing, fewer hydraulic control line
umbilical and reduction in corresponding couple
hydraulic junction plates and lines in flying leads. The
uni-pressure system to date has operated flawlessly.
UmbilicalsThe design and installation of the Diana super duple
tube umbilical established a world record for applicati
dynamic steel tube umbilical connected to a floating str
Extensive umbilical analysis, design verification and
programs were performed to ensure the success of the
and application.
The project utilized two (2) umbilicals consistin
17.6mile (28.2 km) main umbilical and a 2.4 mile (3
infield umbilical. The main umbilical consists of a
meter long dynamic section and a static section 26,324
long. All tubes in the umbilical were ¾” ID super steel tubes rated to a working pressure of 5,000 psi. Th
umbilical consists of 13 hydraulic and chemical injectio
with 4 - 6mm electrical quads. The infield umbilical c
of 9 hydraulic and chemical injection lines and three (3)
quads. An umbilical system level drawing is provi
Figure 10.
The dynamic portion of the main umbilical is termin
a hang-off system at the DDCV topsides. At the keel
floater, the umbilical exits through a bend stiffener attac
the lower end of the I-tube. From there the umbilical
free in the water, down to the touchdown point at the s
The umbilical continues along the seabed to a transitio
and onward to the Umbilical Termination Assembly
located at the Northern Drill Center. The transition
provides the interface where the dynamic umbilical tran
to the static umbilical as well as allowing for changes
umbilical cross sections/control line quantities. The
umbilical connects the Northern and Central Drill Cent
a UTA is provided on each end of the infield umbilica
main umbilical is connected to the infield umbilical via
flying leads, which were supplied by the production c
contractor.
The Umbilical Termination Assemblies (UTAs) p
the interface points for connecting and distributin
hydraulic and electrical supplies to the subsea tree
manifolds. A couple of items used in the UTAs we
issued to the umbilical contractor for integration into thdesigns. These items included electrical connecto
hydraulic connection plates.
Other components supplied by the umbilical con
included a bend stiffener and connector, platform h
equipment, bend restrictors, spare dynamic and static s
with storage reels and umbilical splice kits.
Lessons learned from previous projects resulted
comprehensive Quality Assurance program and ri
quality control and inspection processes. Two fu
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
inspectors and an inspector from the umbilical contractor were
on location full time.
One problem that did occur was related to the manufacture
of the super duplex tubes and problems associated with failed
G48 corrosion tests. A large number of tubes had to be
scrapped due to this problem and other large quantities had to
go through additional testing before being accepted for use in
the project. On line Positive Material Identification (PMI)was also implemented at the tube supplier’s facility as a result
of mixed up tubing materials and since has now become a
standard practice.
PROJECT EXECUTION
Organization
The Diana/Hoover Project was a multi-disciplined project with
an Integrated Project Team (IPT) consisting of ExxonMobil,
BP and contract engineering firms. The IPT consisted of seven
(7) major disciplines/organizations reporting to a Project
Executive. These included administrative support to the
Project Executive, Subsea, Technical, Construction, Systems,Drilling, and Quality (Fig. 11).
The Subsea Systems organization consisted of six (6)
disciplines reporting to the Subsea Manager (Fig. 12). These
included administrative support to the Subsea Manager and
the group, Quality Assurance, Pipelines and Flowlines, Top
Tension Riser and Steel Catenary Riser Engineering, DDCV
Well Systems, and Subsea Systems.
The Subsea Systems group was organized as a functional
team with a Lead Subsea Project Engineer and dedicated Lead
engineers. The core team was relatively small in number,
which necessitated that each coordinating engineer handle
multiple areas of responsibility, with significant time demands
on each individual. Weekly team meetings were conducted toensure all Team members were kept up-to-date on project
needs, timing, priorities, and progress, as well as to ensure that
interface activities between Lead engineers were effectively
communicated and executed.
The Subsea Systems group consisted of functional Leads
for Subsea Trees, Downhole Equipment, Interfaces, Controls,
Umbilicals, Manifolds & Jumpers, Flow Assurance and
Drafting/Design.
Two key functional disciplines, an Operation and Flow
Assurance engineer, were new additions to the traditional
Subsea Group organization and these provided invaluable
input into the system design and operability. An Operations
representative was assigned to the Controls group to provideoperational input and serve as a liaison between the Subsea
Systems group and Operations. The role also served to bridge
the gap between Subsea and Topsides concerning matters of
operations, commissioning, hook-up and start-up. This was
beneficial to involve the operations personnel in the project as
early as possible such that a complete understanding of system
technology is achieved such that ownership of the system can
be more thoroughly transferred from Design/Technology to
Operations after start-up.
A Flow Assurance representative was also included
group to address early flow assurance tasks and in
between the reservoir engineers, third party consultan
internal resources utilized at Exxon Production Resear
key early deliverable was the development of the
Diana Operating Strategy that was used by the Ope
group in developing detailed operating procedures. Th
area which all to often has been overlooked on projebrought onto a project after key decisions in equ
designs and operability have already been set.
Contracting StrategyThe Diana Project contract strategy was based on comp
bidding of both major contracts and purchase orders f
issue equipment.
The Trees and Controls contract award was a re
early FEED and design competition and a follow-
process for the trees and control as a single package.
Another key strategy employed on the Diana Proje
the decision of the Project Team to design the manifo
the jumper systems in-house. Key components ofsystems were then procured by ExxonMobil and free-is
a manifold fabricator. Fabrication of the manifol
negotiated with the successful supplier of the valv
connection systems, thereby reducing interfaces and po
construction errors and delays. Two primary reasons we
the Diana team felt that it could maintain better contr
the multiple interfaces involving hardware supplie
internal interfaces involving drilling and installation a
technical expertise to do the design work was availa
house.
Quality AssuranceThe planning and execution of the Quality Program (Q
the Diana project had a number of challenges to ove
with the key challenge for the Subsea Systems group
that of extreme geographical spread of contracto
vendors in the USA, Norway, Germany, Sweden,
Republic, and UK.
The quality assurance (QA) philosophy at the start
project was to rely on project's contractors existing
programs, based on ISO-9001 and the development of
specific Quality Plans, which included production, insp
and test procedures (PITP). The role of QA/QC w
function more as a monitoring one initially, but unfortu
increased levels of surveillance were required as the
progressed.
The Quality Team of the Subsea Group for the project consisted of a QA Coordinator and a Quality En
(QE), reporting to the Subsea Manager. The responsi
of the QA Coordinator were to develop and overs
implementation of the QP and associated procedur
conduct internal and external quality audits. The
Engineer was responsible for the daily interface wit
party inspectors and the monitoring of contractor and
Inspection and Test Plan (ITP) implementation.
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6 GREGORY N. GIST OTC
Third party inspectors were selected based on the Vendor
Inspection Execution Plan criteria jointly by the Discipline
Lead Engineers and the QE. The basic inspection personnel
contracting philosophy was to employ cognizant and capable
inspectors by geographic area instead of blanket agreement
with an inspection agency.
The QP was intended to cover all aspects of the Subsea
System group's involvement in the project, and complimentthe general Quality Management System (QMS) established
by Project Services and the Management of Change guidelines
followed by the Diana/Hoover Project.
Lessons learned from our experiences continued to show
that while overall the quality of the delivered equipment was
excellent, end results clearly indicate that sub supplier
programs required extensive independent follow-up by the
operator.
Systems Integration TestingThe Diana Systems Integration testing (SIT) program was
executed over a period of two months. The test program was
designed to be thorough, with the objective of testing eachinstallation and operational feature on land, before going
offshore. The high degree of testing resulted in an efficient
installation and a smooth start-up.
The Diana SIT was conducted at the manifold fabricator's
yard and was essential completed in two phases. The first
phase consisted of performing all the mechanical interfaces
between the pipeline end manifolds (PLEMs), suction piles
and manifolds and subsea trees. One size of each flowline and
well jumper was fabricated and tested with maximum or
worst-case tolerance stack-ups confirmed (Fig. 13 and Fig.
14). The second phase of the SIT involved the integration of
the production control system with the manifolds, trees and
flying leads.
The overall planning and execution of the SIT was the
responsibility of the Diana Subsea Systems group. The Diana
planning effort involved the development of an SIT Plan
which identified the scope of work, detailed test procedures,
equipment testing and handling requirements, personnel
requirements, schedule and cost controls and safety practices.
The selection of the SIT site was made based on the fact
that the manifold and jumpers were being fabricated at this
facility, as well as the water access provided by the adjacent
bayou. During execution of the SIT, the fabricator essentially
provided services only (labor, equipment and facilities), with
all detailed procedures, schedules, control budgets and day to
day activities provide and directed by the Diana IPT, and
executed by the Diana SIT coordinator. The contractor scopeof work was executed under a time and material contract. The
SIT was staffed with a full time Subsea Systems team and
peaked at four individuals during execution of the SIT.
During the course of the SIT program, representatives
from the Installation and Drilling groups, installation
contractors and Operations personnel were invited to witness
and participate in the actual SIT tests. This helped to
familiarize the various parties with the equipment and allow
for hands on training to occur.
The Diana team was fortunate to have a significant a
of expertise within the Subsea group that helped in pl
and executing a successful SIT program. It is ext
important to have the right personnel involved duri
execution of the SIT (Subsea, Operations and Instal
and get as early a start as possible in the planning
Overall, the SIT program was one of the project hi-lig
minimal issues arose from the SIT program and both scand costs were on time and under budget.
InstallationThe installation of the subsea equipment was the
responsibility of the Installation group that functione
sub-group in the Construction group, as per the Diana/H
Project Team organization shown previously in Figure
The Installation group responsibilities consisted pri
of negotiating, contracting, coordinating, schedulin
budget control of the various contractors to perform the
installation activities. This organization captured the syn
of optimizing vessel utilization, field safety, and
construction management across the entire twinstallation campaigns. Technical responsibility still r
within the Subsea group for providing technical input,
and endorsement of contractor installation procedur
detailed testing instructions.
Overall, the new organizational structure was succes
installing the subsea equipment with significant cost s
realized by the project. Identifying and selectin
installation contractors as early as possible allowed fo
constructibility into subsea equipment designs as well
development of early installation options and detail
identifying issues/risks of each installation pr
Installation Risk Assessments were also conducted f
primary components that proved invaluable in the pl
phase, as key issues and potential gaps were identifi
resolution plans implemented prior to the offshore exe
of the work.
The subsea components and their method of insta
are identified below:
Subsea Manifolds/Piles. Two manifolds were installe
the Multi-Service Vessel ( MSV ) Uncle John. The n
suction pile and manifold were installed separately by
hauling the suction pile foundation and the ma
transferring them to the main block, and installing th
drillpipe. The central suction pile was installed by the
haul method identical to the northern suction pile a
manifold was installed by floating it underneath the John, and then transferring it to the drillpipe running
(Fig. 15).
Subsea Trees. The subsea trees were installed throu
moonpool of the Uncle John and placed on wellheads th
been previously completed to 9-5/8" production cas
parked on "parking" stumps if the wellhead still re
drilling of the 9-5/8" production casing string. Trees we
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
on bottom prior to the arrival of the drilling MODU, with the
SCMs installed and fully tested (Fig. 16).
Flowline and Well Jumpers. All jumpers were installed over
the port side of the Uncle John using a double drum winch,
spreader bar and lowering lines (Fig. 17).
Flying Leads.
Several vessels were involved in theinstallation of the electrical and hydraulic flying leads,
depending on what equipment had been previously installed
and the timing of the installation activities with other on-going
activities. The Uncle John, MODU ( Marine 700) and the
Seaway Eagle all performed flying lead installation.
Umbilicals. The main umbilical and the infield umbilical
were both installed from the Seaway Eagle, a vessel that was
used to load out and transport the umbilicals from Norway to
the Gulf of Mexico (Fig. 18).
Further detailed design, construction and installation
information on the installation of the Hoover/Diana project
equipment is provided in various companion papers listed inthe Reference section.
ScheduleWhile the Diana subsea systems and Hoover DDCV were in
essence two projects within one, each with different schedule
and delivery requirements, the number of equipment and
system level interfaces and offshore installation execution
issues/logistics, necessitated a close coordination between the
two sub-projects. The result was the early development of a
common, key milestone schedule identified at the start of the
project. Overall, these milestones remained constant
throughout the project with minor adjustments to maintain
schedule flexibility with offshore drilling and installation
activities.
The subsea equipment was procured starting in the last
quarter of 1997 starting with trees, controls, manifold and
jumper system equipment, and ending with the procurement of
umbilicals in May 1998. All required equipment was delivered
to the SIT site in November 1998, approximately 13 months
after contract award. The balance of trees and control
modules were delivered by May 1999. A Diana subsea project
schedule is shown in (Fig. 19).
The prime schedule driver for the delivery of the subsea
equipment was the potential for drilling and completions
operations to start as early as November 1998. The new build
Marine 700 drilling rig was originally scheduled for
completion in late 1998 but as it's schedule slipped, alternativeways of drilling the wells at both the Diana Central and
Northern Drill Centers were pursued. The use of the
Discoverer Seven Seas to drill and batch set casing helped
significantly in reducing the remaining drilling program at
Diana, placing more emphasis on the completion aspect of the
project when the Marine 700 (M700) arrived. This ultimately
impacted the jumper installation plans as these were originally
planned for installation from the M700. The delay prevented
the development of the jumper installation platform and
winches and lead to jumper installation from another
the MSV Uncle John. With the reduced drilling win
Diana, this in essence reduced the planned jumper insta
window of activities since the base plan was to install ju
during drilling operations, with no activities plann
during completion/flowback periods. In the end, the r
drilling program allowed the project to pursue
alternatives which resulted in the jumper installation pusing a dedicated vessel that provided schedule flexibil
minimal interface issues at both drill centers.
The overall delay of the M700 from its original
completion date resulted in the subsea equipment not b
critical path component(s). This allowed the subsea gr
focus on maintaining contractor schedules that the v
vendors had committed to, and working closely w
Installation Group to have the subsea equipment rea
installation per the Offshore Installation Execution Sch
The Offshore Installation Execution Schedule coordina
the offshore activities, available vessels and logistics a
day by day changes. The subsea equipment was insta
time and the Diana project milestone of “first oiachieved on May 31, 200, two months ahead of schedule
ConclusionsThe Diana Project key objectives of safety, enviro
quality, costs, schedule and teamwork were all succe
achieved.
• Overall Hoover/Diana safety standards and
exceeded industry norms for onshore and offshore w
• Overall quality, with exception to some contractor
related to sub-contractor management, has been ex
resulting in no cost or schedule impacts. Con
operator presence and involvement is howeve
recommended.
• Costs for the Diana project were under budget an
can be primarily attributed to early and clear defini
scope of supply as a result of front-end engineeri
competitive studies and detailed costs estimates.
• The on-time delivery of the Diana subsea equipm
SIT and offshore installation to achieve first o
achieved providing schedule flexibility. The suc
and quick execution of the SIT by ExxonMobil per
was a hi-light of the project and allowed the projec
to better familiarize themselves with the technical
of the equipment design and better control the sc
and budget.
• The coordination of all offshore activities for a
project (Diana & Hoover) organization through a
Installation organization, allowed the group to ma
vessel utilization, minimize vessel standby and
manage overall logistics, clearly providing the
with increased schedule flexibility, project cost s
and consistent safety performance.
• The relative small size of the Diana Subsea System
demonstrated that a project of this size could be ex
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8 GREGORY N. GIST OTC
with limited personnel. However, this was only done as a
result of the experience, dedication and initiative of all
members, and management support in decision making.
The Integrated Project Team approach was also
successful in achieving the goal of “One Team, no
Surprises” by working closely together in a true team
spirit.
The ExxonMobil “firsts” and world record applications for
horizontal tree, steel tube dynamic umbilical and the uni-
pressure control system, demonstrated that with good
engineering, qualification and testing, items of new or
extended technologies can be readily adapted to increased
water depth applications.
NomenclatureBOP = blowout preventer
BOPD = barrels of oil per day
CDC = central drill center
DCV = direct control valve
DDCV = deep draft caisson vesselDHPT = downhole pressure and temperature gauges
FPS = floating production vessel
FPSO = floating production offloading vessel
GOR = gas to oil ratio
IPT = integrated project team
MBOE = million barrels oil equivalent
MCFD = million cubic feet per day
MSV = multi-service vessel
NDC = northern drill center
NPV = net present value
PLEM = pipeline end manifold
QA = quality assurance
QE = quality engineer
QP = quality plan
ROV = remotely operated vehicle
SCFD = standard cubic feet per day
SCM = subsea control module
SCR = steel catenary riser
SCSSV = surface controlled subsurface safety valve
SDV = shut-down valve
SIT = systems integration testing
TLP = tension leg platform
UTA = umbilical termination assembly
USV = underwater safety valve
AcknowledgementsThe author thanks ExxonMobil management for
confidence in and support of the Diana Subsea Systems
and for allowing the team the opportunity to succeed.
thanks and recognition are also well deserved for the
Systems team members for their initiatives, dedicatio
many hours of hard work. Thanks are also affor
ExxonMobil for approval to present this paper.
References1. M. Moyer Paper #13081 Hoover / Diana A Dia
Project and Success Story.
2. D. Deeken Paper #13086 World-Record HorizoTrees for Diana.
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Alaminos Canyon
Bullwinkle
Diana
Houston
CorpusChristi
Auger
Mars
New Orleans
Mobile
Ram-
Neptu
Mensa
Genesis Spar
Hoover DDCV
Garden Banks
East Breaks
Green Canyon Atwater
Miss. Canyon
Neptune
Galveston
Mica
Diana 160 miles (200 km) South of Galveston
and ESE of Corpus Christi
100 - 500 mdepth line
Figure 1 - Diana Project Location Map
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10 GREGORY N. GIST OTC
EB 944
EB 988
EB 945 EB 946
EB 989 EB 990
AC 21 AC 22
1 mile
DIANAA-50 Sand
EB 945 #2
EB 946 #1
EB 945 #1
• Depth: 10,500’ subsea
• Reservior Pressure: 5350 psi
• Gross Sand Thickness: 100’ Average
- Net to gross: 50-90%
• Rock Properties: 19-28% porosity, 50-2000 md permability
• Fluid Characterization: 26° gravity crude, 1,000 GOR , no H 2S
Figure 2 - Reservoir Map
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Diana Subsea
Development
Hoover Host
CENTRAL
DRILL CENTER
NORTHERN
DRILL CENTER
Figure 3 - Diana \ Hoover Development
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12 GREGORY N. GIST OTC
Figure 4 - Concept Screening Options
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Figure 5 - Northern D rill Center
Figure 6 - Central Drill Center
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14 GREGORY N. GIST OTC
Figure 7 - Manifold Flow Diagram
Figure 8 - Manifold Flow Diagram
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Figure 9 - Tree Schematic
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16 GREGORY N. GIST OTC
Figure 10 - Exxon Diana Umbilical System Overview
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Project Executive
Support
Construction
Manager
GOM Field Driling
ManagerSubsea M anager Systems M anager
Technical
Manager Quality Ma
Figure 11
Diana/Hoover Integrated Project Team Organization
Subsea Manager
Quality Support
Coordinator Qual i ty Engineer
Subsea Design Verification
TTR/SCR
Engineering An alysisPipeline/Flowlines Well Systems Subsea Systems
SCR/Pipel ine Advisor SCR Design Pipelline Design Intec Engineering EPRCo. Onsho re Facilities Planning Operations Coord.
Analyst Stress Engine ering
TTR Design Subsea Trees Interfaces Controls Umbilicals Manifold/Jumpers
Drafting/Design
Flow A ssurance
Figure 12
Diana Subsea Systems Organization
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18 GREGORY N. GIST OTC
Figure 13
Systems Integration Testing
Jumper fabrication and Connection Tests with Central Manifold
Figure 14Systems Integration Testing
Well Jumper Connection Tests with Northern Manifold and Tree
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Figure 15 Central Manifold Float Under
Figure 16
Tree Installation Through DSV Moonpool
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20 GREGORY N. GIST OTC
Figure 17 10” Jumper Installation
Figure 18
Umbilical Termination Assembly - Infield Umbilical
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OTC 13082 DIANA SUBSEA PRODUCTION SYSTEM: AN OVERVIEW
Activity
Description
1997 1998 1999 2000
Concept Selection
IPT Prel. Eng./Design
Procurement & MajorContract Awards
Trees & Controls
Manifold Valves & Connectors
Chokes
Manifold Fabrication
Umbilicals
Detail Engineering
Manufacturing, Assy & Test
SIT Program
Manifold & Tree Installation
Drilling Program
First Oil
Figure 19Diana Subsea Systems Execution Schedule
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