Diana Subsea Production System An Overview.pdf

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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



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



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.




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




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.




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




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




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.




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




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




Diana Subsea

Development

Hoover Host

CENTRAL

DRILL CENTER

NORTHERN

DRILL CENTER

Figure 3 - Diana \ Hoover Development




Figure 4 - Concept Screening Options




Figure 5 - Northern D rill Center

Figure 6 - Central Drill Center




Figure 7 - Manifold Flow Diagram

Figure 8 - Manifold Flow Diagram




Figure 9 - Tree Schematic




Figure 10 - Exxon Diana Umbilical System 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




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




Figure 15 Central Manifold Float Under

Figure 16

Tree Installation Through DSV Moonpool




Figure 17 10” Jumper Installation

Figure 18

Umbilical Termination Assembly - Infield Umbilical




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

Documents

Diana Subsea Production System An Overview.pdf