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Copyright 2000, Offshore Technology Conference

This paper was prepared for presentation at the 2000 Offshore Technology Conference held inHouston, Texas, 14 May 2000.

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 printis 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 was

presented.

AbstractTo maintain profitability in the development of marginal

fields, many new technologies and concepts have been

exploited. One of the most promising technologies has been

the Intelligent Well Concept, which allows the operator to

produce, monitor and control the production of hydrocarbons

through remotely operated completion systems. These

systems are developed with techniques that allow the well

architecture to be reconfigured at will and real-time data to be

acquired without any well intervention. This paper concerns a

case history in the Gulf of Mexico in which an operator was

able to justify completion of marginal wells based upon thecost savings generated from innovative technologies.

The completion methods chosen for this development were

successful because of careful preplanning for all phases of the

completion scenario and proved that close interaction among

all suppliers and parties involved in the actual equipment

purchasing, interface issues, and all operational strategies is

critical for project success. These topics will be discussed in

depth. Detailed test programs were implemented during the

design and manufacturing processes to eliminate field failures.

In this case, testing revealed system issues that ultimately led

to the use of an alternative design.

Also shown is the importance of allowing the proper

amount of time to adequately plan and test these systems for

their specific applications in order to assure delivery of a

design that can meet the functional requirements for that

application. In this case, although the system design was

changed, the original functional goals were met. Two wells in

this field were completed in April and July 1999. An

additional well may be completed in early 2000.

IntroductionThis case history is the first in the Gulf of Mexico in which

intelligent completion technology was used. The field is

located offshore in approximately 3300 ft of water. Fig. 1

indicates field location. The field is comprised of sand unit

that are vertically and laterally discontinuous across the

breadth of the field. With the need for multiple take points in

the layered reservoir system, the operator had developed a

depletion plan, which described the order in which the

different zones would be accessed to maximize both reserves

and upfront production.It had been recognized early on that there was a need for

lower overall cost solutions to develop this field because of its

marginal reserves. Many innovative techniques from the

incorporation of a mini-TLP platform to unique pipeline

systems were planned, and it was felt that the use of intelligen

completion systems could maximize field development. Fig. 2

shows an intelligent well configuration used in this field.

The wells were to be completed with stacked gravel packs

to produce two independent zones. The intelligent completion

would allow the operator to monitor pressure and temperature

from either zone and to produce from the lower zone, the

upper zone, both zones, or neither. The wells were also to be

completed in different sands to optimize current well location

and to maximize producing and sustainable production rates.The zones were completed simultaneously with the

intelligent completion system run as part of the production

tubing string. This was done to minimize and/or eliminate the

need for future well interventions to initiate changes in

production from either of the producing intervals.

Pre-PlanningAs stated earlier, the use of intelligent completion technology

requires a different and more involved type of pre-planning

than conventional completion work.1 The intelligen

completion directly affects the subsea interface, tubing hanger

the umbilical to the production vessel or platform, topsides

and the permanent completion itself. Thus, it is important tostart in-depth planning early in the life of the project to

effectively interface multiple systems.

In this case history, project planning for the intelligent

completion system began a year and a half prior to installation

The intelligent completion used was an electro/hyraulic

system. Although there are other types of intelligen

completion systems, the electro/hyraulic systems often require

more interface consideration than pure hydraulic or electrical

OTC 11928

Case Study: First Intelligent Completion System Installed in the Gulf of MexicoV. B. Jackson, SPE, Halliburton Energy Services, Inc. and T. R. Tips, SPE, Petroleum Engineering Services, Inc.

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2 V. B. JACKSON AND T. R. TIPS OTC 11928

systems. Following is a description of the equipment chosen

for the completion, and why it was chosen over other

alternatives.

Subsea Interface and Direct UmbilicalA seamless interface for control of subsea systems can be

created with the use of a direct umbilical with dedicated

electric and hydraulic lines from the production platform. Adirect hydraulic system was used, as the wells are a short

distance from the field surface facility. A direct umbilical

from the platform was connected to each template, and the

individual wells were then connected to the templates. The

direct umbilical requires less interface work than does a

subsea pod and is used in applications in which the wells are

clustered around one or several points, or all the wells are near

the production vessel or platform.

To control subsea systems using direct hydraulic

umbilicals, it is important to note the type of umbilical being

specified. The density of the hydraulic fluid for the intelligent

completion system will affect the burst and collapse rating

required. The oil-based fluids, having a lower specific gravitythan the water-based fluids, require higher collapse resistant

umbilical passages. The other factor directly affecting the

intelligent completion system is the type of umbilical

flexible thermoplastic hose or stainless steel/incoloy type line.

The flexible umbilicals have non-linear expansion

characteristics and can make valve characterization and

precise movement more difficult, though adequate techniques

have been developed for the short umbilical lengths used in

the case described.

The use of a direct umbilical over long distances can be

both costly and inefficient as the line loss on the electric lines

becomes inhibiting, and the response time on the hydraulic

lines becomes unacceptable. In these instances or when the

wells are scattered over a large area, the use of anelectro/hydraulic subsea control system may be more cost

efficient and design effective.

Subsea Pod/Control ModuleAn alternative method for controlling an intelligent

completion is through the use of a subsea pod.2 An

electro/hydraulic umbilical is run from the master control

station (MCS) to a pod system subsea. Power (both electric

and hydraulic) and communication are transmitted subsea via

an electro/hydraulic umbilical before being split off to the

individual wellheads or production manifold.

Subsea control modules are used when the wells are

located far from one another or when the wellheads are farfrom the production vessel or platform. The use of a subsea

pod requires detailed interfacing with the subsea control

system. If the intelligent completion system is to be controlled

from the surface through the master control system on the

platform or production vessel, an interface at the pod will be

required to communicate with the downhole tools.

The added complication of communication protocol from

the MCS to the wellhead to the downhole intelligent well

completion system requires additional time for pre-planning

and interface development. If possible, the intelligent wel

completion system supplier should be involved prior to the

contract award of the subsea pod system. Detailed

engineering work may be required to develop a contro

interface to supply hydraulic and/or electric power and signa

to the downhole intelligent well system components.

If a subsea electro/hydraulic production control system hadbeen used instead of the direct umbilical, the modifications

made late in project life might not have been possible. The

control system integration, once complete, is fixed, and the

method of supply of hydraulic fluid to the intelligent

completion system cannot be altered.

There are additional problems during installation of the

system when its function is to be tested from the rig. The

direct hydraulic/hardwired system allowed for the intelligen

completion system to be completely function tested from the

rig prior to leaving the well.

Tubing Hanger

The field has been completed with horizontal subsea trees thaaccommodate eight tubing-hanger penetrations. The

intelligent completion system used is comprised of dual

hydraulic/electric encapsulated flatpacks between the tubing

hanger and the downhole equipment for redundant electric

control. The hydraulic system is not redundant due to design

modifications, which will be discussed later. Low reservoi

temperatures and the specific oil characteristics encountered

required the use of two chemical injection subs and a deep-set

tubing-retrievable subsurface safety valve (TRSSV). The

TRSSV is a hydraulically redundant system, using two

independent control lines. Thus, the tubing hanger required

eight penetrations six hydraulic and two electric.

The number of possible penetrations differs according to

tree manufacturers; therefore, this issue must be addressedearly in the process planning. This will allow the tree

manufacturer sufficient time to design the tubing hanger with

the necessary penetrations. Ideally, since the tubing-hanger

interfaces with the intelligent well completion equipment, the

interface requirements should be identified prior to obtaining

the bid for the tubing subsea trees as was done in this project

case.

Topsides/ElectricalIn the case of the hydro/electric intelligent completion system

used, the topsides interface involves electrical communication

via a surface control unit and a stand-alone computer in a 19-

in. rack mount system. The platform computer is linked via aModbusinterface to the MCS on the platform such that well

temperature, pressure, and sleeve position can be monitored

from the MCS. A PC Anywherecomputer software system

was also installed so that an engineer in an onshore office

could look at the platform computer and identify faults or

install minor system upgrades.

The electrical interface can be designed as per the specific

project. These modifications need to be addressed and

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OTC 11928 CASE STUDY: FIRST INTELLIGENT COMPLETION SYSTEM INSTALLED IN THE GULF OF MEXICO 3

specific requirements identified by the end user (i.e.

production manager, production engineer, or reservoir

engineer) early in project development as the process of

software and integration testing can be complex and time

consuming.

Sufficient time must be allowed for internal system testing

along with the MCS, subsea tree, or other systems in which

interfacing is required. Software testing and communicationprotocol is an ongoing process. After well completion and

platform commissioning, software upgrades and modifications

must be capable of being handled from the surface. Therefore,

all components of the intelligent well completion system

gauges, position sensors, solenoid valve controls, subsea pod

interface, MCS, etc. must be verified and checked. The

topsides interface must be compatible with all the equipment

in the system and be able to identify that each system is

functional.

HydraulicsHydraulic Fluid Selection. In addition to the effect on the

subsea umbilicals, hydraulic fluid has a direct impact on thetopsides configuration of the platform. If the intelligent

completion system uses the same hydraulic fluid as other

systems in the wellbore (i.e. TRSSV), the same fluid reservoir

can be used. However, if the hydraulic fluid to be used by the

intelligent completion system differs due to completion fluid

compatibility, reservoir fluid compatibility, specific gravity

requirements, environmental concerns of venting to the sea

floor, etc., separate fluid reservoirs, hydraulic power units

(HPU), and separate filtering systems will be required.

Hydraulic Power Unit (HPU). The hydraulic interface can

be integral and operated by the MCS, a separate HPU, or

manually operated valves in conjunction with the MCS. The

HPU provides hydraulic power from the platform to the

subsea tree, and eventually, to the intelligent completion

system.

The hydraulic system can be tied in directly to the MCS

such that the MCS controls the HPU for all systems on the

platform, including the intelligent completion system. With

integral MCS functioning, the system can be automated from

the platform. A subsea pod system will require integral HPU

functionality, and it can be implemented in a direct umbilical

installation as well.

The simplest method is an HPU solely dedicated to the

intelligent completion system. This requires manual

intervention to turn the HPU on prior to functioning the

equipment. This method can be implemented only with directumbilical or platform applications and eliminates the need for

interfacing the topside systems, though umbilical interfacing

may be required.

Downhole CompletionCompletion hardware size, weight, and grade of smallest

inner diameter of casing, liners, or gravel pack base pipe

dictates what types of intelligent completion equipment can be

used. As an example, the intelligent completion equipmen

installed in these GOM wells was set above the 7-in. liner

This was done to maximize flow area from both the upper and

lower zones and to allow clearance for the hydro/electrical

flatpacks connected at the top of the production packer.

The intelligent completion system is run on the production

tubing. The hydraulic and electric lines are clamped to the

tubing using over-the-coupling clamps. Clearance around theclamps is critical as it should not be too small, which might

crimp the lines or hinder production, or too large, which

would result in decentralized equipment.

The downhole completion usually requires interfacing

between numerous service companies and equipmen

providers. In the Gulf of Mexico completions, the projec

involved no less than 10 companies, each of which handled

significant portions of work. Different vendors were

employed for spooling, TRSSV equipment, gravel packing

intelligent well completion technology, tubing testing, the rig

perforating, subsea tree company, well testing, etc. A pre

spud meeting, which proved helpful in communicating

possible concerns regarding the equipment involved, was held

in October 1998.

Zonal IsolationMechanical. The operator used two types of zonal isolation

techniques to mechanically isolate the formations from the

kill-weight fluid in the wellbore. The lower-zone gravel pack

had isolation sleeve ports, which were to be opened by

slickline after the tubing was landed and the well-testing

commenced. To isolate the lower-zone production from the

upper zone, a flow tube was run through the upper gravel-pack

assembly and stung into the PBR of the lower-zone gravel-

pack packer. Flow from the lower zone produces up the flow

tube, around the slickline nipple in the intelligent completion

system, and into the flow ports of the dual-zone intervacontrol valve (DZICV) inside the shroud (Fig. 3).

The upper-zone gravel pack contains integral pressure-

actuated valves3 to isolate the upper zone while running

tubing, landing the hanger, circulating packer fluid, and setting

the production packer. This was necessary because the flow

tube described above isolates the upper zone from any

slickline manipulation of sliding sleeves, etc. The upper zone

is produced around the flow tube, between the OD of the

shroud and the ID of the production casing, and into the flow

ports of the DZICV. (Fig. 4)

Hydraulic. The other viable means of zonal control and

isolation is maintaining kill weight fluid without independenisolation between the two zones. If the zones are of similar

pressure regimes, a kill weight fluid can be optimized to

decrease the damage created by the fluid. However, if the

zones are at significantly different pressures, the zone of lesser

pressure may experience significant damage and costly fluid

loss may result.

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The Intelligent Well Completion SystemSystem OverviewThe original system design contained a single DZICV to

isolate production from either zone or to produce from both

simultaneously or neither. The valve was to be actuated

through a redundant system utilizing actuator electronic

modules (AEMs). As the downhole control system, the AEM

responds to information and command requests from thesurface control unit and reacts accordingly. The AEM also

communicates to the solenoid valves, which are used to

control valve movement and to set the packer.

Hydraulic Set Retrievable PackerThe production packer is a hydraulic set (minimal lateral

motion while setting) retrievable packer. The packer

incorporates five feed-through ports to pass -in-OD

hydraulic or electrical lines through the packer. It is not

necessary to terminate the lines at the packer as they are fed

through the top of the packer, between the slips and elements,

and the packer body. The pass-through sections then seal the

annulus above the packer from the annulus below the packerwith proprietary connections.

The original design of the system had incorporated a

solenoid valve to allow hydraulic pressure to reach the packer

setting chamber to set the packer. This function is fully

automated and the only method by which the packer can be set

is with direct hydraulic communication into the packer setting

chamber. The packer sets through realization of differential

pressure between the packer setting chamber and the annulus.

The packers require 4,500 psi differential to set.

Dual Zone Interval Control Valve (Fig. 5)A four-position thermoplastic sliding sleeve, the DZICV,

allows the following production options with production from

the bottom-most position to the top-most position 1) lower

zone only, 2) both zones closed, 3) upper zone only, and 4)

both zones open. The 2ndposition both zones closed was

designed to allow an intermediate position between zones such

that the operator could be assured that crossflow could not

occur. This position may also be important if the reservoir

liquids prove to be incompatible with one another. The

implications of these four positions and the order in which

they exist in the valve became significant when problems

arose with the hydro/electronics package.

The intermediate position of both zones closed is also

critcal if there is a large pressure difference between the two

zones. This position allows the pressure in the tubing to be

altered from the platform to within the acceptable operatinglimits for DZICV function of 1500 psi differential.

Solenoid ValvesIn the system as originally designed, in order to operate the

valves and set the packer, solenoid valves are used to direct

hydraulic fluid to the open or closed side of the actuated

piston. Power and command functions are sent via the

instrumentation wire in the flatpack. The system contains five

solenoid valves two normally open (to provide hydraulic

communication to additional tools), two normally closed (to

actuate the valve), and a fifth normally closed (to provide

hydraulic power to an auxiliary mechanism such as a packer)

Unlike the systems installed in other areas, the two normally

open solenoid valves were not necessary as there was only one

DZICV in the system.4

A system containing solenoid valves, though noinherently less reliable, is more complex than one withou

solenoid valves. It was suggested in July 1998 that an option

be developed to actuate the DZICV by directly connecting to

the open and closed sides of the actuated piston housing. (See

Figs.6and 7) Due to time constraints and delivery schedules

this option was not fully pursued at that time. However, the

idea would eventually be adopted for these completions. The

advantages and disadvantages to the direct hydraulic option

are:

Advantages:

With the solenoid system, several single point electrical

failures render the valves inoperable without slicklineintervention.

The direct hydraulic system is not dependent on electricalcomponents for actuation. The direct hydraulic system

requires at least two electrical failures to prevent

actuation.

The direct hydraulic system is less complex, and thus, canbe more cost effective.

Disadvantages:

Production from more than two indepenedent zones willrequire additional hydraulic lines, as the system is no

longer multiplexed.

The hydraulic supply to the intelligent completion system

is no longer redundant. If a subsea pod is used, a direct hydraulic system becomes

much more complex than the standard electro/hydraulics

module as hydraulic steering would have to be designed

to take place in the pod system. While the intelligent

completion equipment would be simpler, the intelligent

system would be more complex.

System integration during which the valve section

(DZICV) is attached to the position sensor and the electronics

module containing the solenoid valves, gauges, and position

sensor feedback began in January 1999. The hydro/electronic

modules had been fully tested in late 1998 to 16,000 ps

absolute pressure and 235F. System integration involve

connection of the appropriate hydraulic outlets to the pistonhousing and the appropriate electrical outlets to the position

sensor. The system is then function tested at 120% o

reservoir pressure and temperature.

The first integrated DZICV left Houston on January 12

1999. The tools were shipped to Houma, Louisiana for fina

stack-up and function testing. Stack-up involves incorporating

the DZICV, the packer, necessary slickline nipples, pup joints

and other miscellaneous equipment for installation offshore

During stack-up testing, an anomaly was noted with the

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solenoid valves. It was confirmed that power and

communication were reaching the hydro/electric module, but

it was not possible to move the sleeve into the closed position.

It became apparent after additional testing that one of the

normally closed solenoid valves was not functioning correctly.

The tools were shipped back to Houston to identify

whether the problem involved a single-point failure, or

whether the solenoid valve problem was inherent in all of thesolenoid valves being used for the equipment. Design

modification had been done on these solenoid valves to

increase pressure rating and improve corrosion resistance

through the use of CRA material. While investigative testing

was being conducted on the first of the three sets of

equipment, the second set of equipment began experiencing a

similar problem.

While integrating the second set of equipment, a similar

but not identical problem arose with one of the normally

closed solenoid valves. While the first experienced a problem

in which the solenoid ball would not come fully off-seat, the

second set experienced a problem in which the ball acted as if

it was not fully off-seat or fully on-seat. The ball was floating

in the chamber such that the solenoid valve could not supply

pressure to the actuated piston housing, or would not fully

close. When the valve was instructed to close, fluid would

continue to bleed back through the inlet port.

Design modifications were considered as well as whether

sufficient time remained prior to the delivery date to design,

qualify, and build new solenoid valves. Given the time

constraints on delivery, it was decided that alternative

solutions would need to be devised. The option of connecting

directly to the piston housing with the hydraulic lines in the

flatpacks was revisited. It was recognized at the time that the

direct hydraulic option was feasible in this application because

1) direct hydraulic umbilicals would be used, and 2) a single

DZICV could still be controlled with the two availablehydraulic lines.

A test was conducted to attempt to control the valve with

hydraulic pressure and the information obtained from the

position sensors. It was not known whether the valve could be

stopped at a discrete position with direct hydraulic control.

The test was conducted through approximately 5500 ft of

flexible umbilical and 10,300 of -in. 0.049-in. wall thickness

hydraulic line per side of the actuated piston housing.

Testing concluded that the valve could be stopped at an

intermediate position with the use of position sensors.

Attempts were made to quantify the accuracy of volumetric

displacement. A specific volume of fluid was bled from the

open or closed side of the piston, and valve motion wasmeasured. The exact distance of valve travel was found to be

inconsistent with the volume of hydraulic fluid removed. (i.e.

50 ml may equate to 2-in. of valve motion or it can equate to

2.25-in. of valve motion) The 4-position position sensors such

as are used in these tools have a finite distance of travel to be

on position. The volumetric displacement was neither exact

nor repeatable. This is due to the flexible subsea umbilical

and the static friction pressure of the actuated piston.

Testing concluded that the only means to verify position in

this application is with the use of position sensors. A position

of full up or full down can be obtained by monitoring

pressure response or the cessation of bleed fluid on the drain

side of the piston. The intermediate positions both zones

closed or the upper zone open require position sensors to

indicate to the operator of the valve when to equalize the

pressure and stop the motion.

At the conclusion of the test, the decision was made to usethe direct hydraulic solution. This option required the

development of other devices, such as the packer setting sub

These devices were subsequently developed and tested.

It is important to note that although the aforementioned

solenoid valve-control issues were subsequently solved, the

operator elected to continue using the direct hydraulic solution

for subsequent well completions. This choice was primarily

made to maintain compatibility throughout the field and for

the technical advantages stated earlier.

Packer Setting MechanismsThe intelligent completion system uses a hydraulic-set

minimal-vertical-motion-during-setting, retrievable packerAs mentioned previously, the original design involved use of a

solenoid valve to provide hydraulic force to the packer setting

chamber. Due to the system modifications discussed above

an alternative solution was required.

A slickline setting sleeve was developed to allow the

operator to set the packer through application of tubing

pressure. The setting sleeve is pressure balanced while

running in the hole to avoid premature packer setting and is

isolated from the packer setting chamber to allow the tubing to

be tested during the completion.

PreparationA focused effort on project engineering for the intelligent

completion portion of this project began in November 1997

Detailed scheduling and requirement documentation was

started at this time to reconcile any differences and develop a

design basis for the equipment. The DZICV, packer, the filte

mandrel (which eventually would not be used), the particular

version of the electro/hydraulic module, and the contingency

size packer, were all first-time builds that required prototype

design and testing. Three sets of intelligent completion

equipment were ordered one for each well and one backup

system.

The long lead-time (greater than a year in this instance)

required the operating company, the service companies, and

all other equipment suppliers to become involved early in the

process. A representative of the intelligent well system wamade a member of the operators drilling and completions

team and served to coordinate efforts and resolve interface

issues for more than a year, through the time of installation

With current installations still essentially one of a kind per

every field design, intelligent completion projects can not be

completed in a couple of months. The many issues and

interface questions should also be considered as an ongoing

effort with all concerned throughout the project planning.

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DesignDetailed design work began in March 1998 on the DZICV, the

packers, and the modifications to the then current model of the

electro/hydraulic module. Various sizes of this packer style

had been developed, tested, and successfully installed, though

the two sizes discussed above were new developments.

TestingIntegration. As mentioned previously, the equipment must be

tested several times. The first systemtest is conducted after

make-up of the electro/hydraulic module to the DZICV. The

system is function tested at ambient conditions, pressure tested

to 7500 psi (internal-external differential), and then, the

system is put into a test element and heated for 12 hours at

120% reservoir temperature. 120% of reservoir pressure is

applied, and a full hydraulic and electrical function test is

conducted. At the conclusion of this environmental test, the

equipment is pressure tested to 7500 psi to verify seal

integrity.

Stack-Up. The DZICV assembly is shipped for final make-upin the district office. The packer, DZICV w/shroud, and pupjoint with slickline nipple to divert flow are made up and

tested to 7500 psi differential. A full function test is

conducted, and the make-up of the full assembly begins. (Fig.

8).

After pulling the lines through the packer, the hydraulic

lines are made up to the piston housing and the electric lines

are made up to the inlet ports of the electro/hydraulic module.

The connections are externally tested for 15 minutes at 10,000

psi. The hydraulic lines are then tested to 7500 psi working

pressure, thus testing the piston seals. An electro/hydraulic

splice sub was used so that the lines could be fed through the

packer in the workshop, decreasing rig make-up time. A body

test was again performed to verify seal integrity and to test theslickline nipple and plug.

The stack-up testing is critical to ensuring field success.

The extensive function testing is beneficial not only in

verifying equipment integrity, but also as a means to

familiarize the operations personnel with the particular

installation. The personnel who will be performing the job are

also responsible for making sure the equipment is fully

checked and tested prior to shipping.

Installation. As with other phases of the project, extensive

pre-planning was required prior to installation. Multiple pre-

spud meetings and rig visits allowed all service companies and

suppliers the necessary interfacing to coordinate efforts. Bestpractice documentation for the intelligent completion system

was coordinated with other installation teams in the North Sea

to ensure the best installation possible.

The first intelligent completion system in the Gulf of

Mexico was installed in April 1999 with a six-man crew

splitting the work into roughly two shifts. The equipment was

shipped offshore as a full assembly as described above. A

complete function test was again completed on the deck, and

the body test was repeated. The slickline lock and plug were

removed, and the assembly was visually inspected prior to

picking up in the rotary table.

After picking up into the rotary table, the hydro/electric

splice sub was connected to the flatpacks. The two electric

and two hydraulic terminations were made up and tested

followed by the make-up of the packer setting sub located

approximately 40 ft above the packer. Cross-couplingprotectors were used to protect the control lines and to hold

tension on the flatpacks at each tubing joint. Specia

provisions were made by the chemical injection manufacturer

and the TRSSV manufacturer to protect the flatpacks around

the equipment. Function testing of the intelligent completion

system was ongoing while running the completion.

After picking up the tubing hanger, the intelligen

completion system was functioned prior to terminating the

lines. The tubing hanger was made up and run to the mudline

There was no electric communication until after the tubing

hanger was hard landed. This is a critical test of the

equipment to verify that the DZICV would not move from

position and that electric communication would be restored

The first verification that the sleeve had remained in the

closed position was a positive test of the seal assembly in the

lower gravel-pack packer. Electric communication was

reestablished with all equipment.

The valves were moved to the upper-zone open position to

allow for packer fluid circulation. The DZICV was closed

and a slickline plug was set in a back-up slickline-accessible

sliding sleeve, which had been run below the DZICV. A

slickline trip opened the packer setting sub. The tubing wa

pressurized, and the packer set. The final process for the

completion was to flow test each zone independently.

Functionality. The original design of the intelligen

completion system used an electro/hydraulic module withintegral solenoid valves, pressure and temperature gauges, and

position sensors. While system testing was being conducted

the solenoid valves began experiencing erratic behavior

System modification began in January 1999 to modify the

design and take the solenoid valves out of the system.

For this particular application a direct subsea umbilica

(similar to platform completion for this discussion) with a

single valve controlling two zones the change to a direc

hydraulic solution was both functional and appropriate. If a

subsea pod had been used or if the design had not allowed two

hydraulic lines to control all valve positioning, an alternative

solution would have been required.

Conclusions1. Several intelligent completion systems have successfullybeen installed in the Gulf of Mexico, expanding on the

installation experience in the North Sea and Adriatic. The

elimination of planned well intervention has allowed the

operator to additionally enhance field economics.

2. The fully integrated intelligent completion system placesthe responsibility and control of each portion of the projec

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under the onus of the responsible individual or company and is

an ongoing committment. This allows for system

modification and design review when necessary.

3. The coordination of all parties involved with thecompletion is critical to project success. Without early and

constant involvement, critical interface issues may be missed.

The operator, all service companies, and other suppliers must

work as a team to insure that project goals are met.4. In these completions, the flexibility of the team allowedthe intelligent completion system to be modified late in the life

of the project. Without this flexibility, project delays would

have occurred, as the equipment would not have been

delivered on time.

AcknowledgementsThe authors would like to thank Halliburton Energy Services,

and PES, Inc. for support and permission to publish this paper.

The authors would also like to thank all the people involved in

this project for their support in bringing the project to a

successful conclusion.

References

1. Robison, C.E. Overcoming the Challenges Associated with the LifeCycle Management of Multilateral Wells: Assessing MovesTowards the Intelligent Well,paper OTC 8536, presented at the

1997 Offshore Technology Conference held in Houston, Texas, 5-

8 May 1997.2. Botto, G., Giuliani, C., Maggioni, B., Rubbo, R. Innovativ

Remote Controlled Completion for Aquila Deepwater Challenge,paper SPE 36948, presented at the 1996 SPE European Petroleum

Conference held in Milan, Italy, 22-24 October 1996.

3. Worlow, D.W., Grego, L.V., Walker, D.J., Green, G.R., SmithB.E., Harris, M.E. Pressure-Actuated Isolation Valves for FluidLoss Control in Gravel/Frac-Pack Completions, paper SPE

58778, presented at the 2000 SPE International Symposium on

Formation Damage held in Lafayette, Louisiana, 23-24 February2000.

4. Lie, O.H., Wallace, W. Intelligent Recompletion Eliminates theNeed for Additional Well, IADC/SPE Paper No. 59210 presented

at the 2000 IADC/SPE Drilling Conference held in New Orleans

Louisiana, 2325 February 2000.

SI Metric Conversion Factorsin x 2.54* E + 01 = mm

psi x 6.894 757 E + 00 = kPa

ft x 3.048* E - 01 = m

F (F 32)1.8 = C

Conversion factor is exact

Modbusis a registered trademark of Modicon, Inc.

PC Anywhereis a registered trademark of Symantec, Inc.

Fig. 1 Field Location

Intelligent Completion System Installation

Gulf of Mexico

Louisiana

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Fig. 2Intelligent Well Completion

7" 38.00#

RKB - MSL -- 99.0'

PBTD - Cmt Retainer

9-5/8" 53.50#

Water Depth -- 3,226'

CI

CI

SCSSV

7" 26-38# Sump Pkr

4" 13Cr, 0.008 ga prepack screen2-3/8" 4.70# isolation assembly

w/1.875" ID sliding sleeves

7" 32-38# GP Pkr

4" 13Cr, 0.008 ga screen w/3 PAVs per jt2 - 2.813" ID sliding sleeves

7" 32-38# GP Pkr

DZICV w/integral DHPT

9-5/8" HF-1 Pkr

Chem Inj Mandrel

Chem Inj Mandrel

DZICV OperationPosition Lower Zone Upper Zone 1 open isolated 2 isolated isolated 3 isolated open 4 open open

9-5/8" 53.50#, Tie-back

Production Tubing

3-1/2" 10.20#, 13Cr85, VAM Ace

10K SpoolTree @ 3,311'

SCSSV

2-3/8" 4.70# Isolation Tubingw/ATR seals

PSSPacker Set Sub

11-3/4"

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Fig. 3Lower-Zone Production

SCSSV Control Line

Chemical Injection Line

PES FlatpackControl Umbilical

SCSSV

Dual Splice Sub

Cross-Coupling Protector

Hydraulic Set Packer

Electro/Hydraulic Module

Sliding Sleeve (DZICV)

Plug

Upper Zone Gravel Pack

Lower Zone Gravel Pack

PBR IsolatesUpper and Lower Zones

Methanol Injection Valve

Chemical Injection Valv e

Shroud

Position Lower Zone Upper Zone

1 open closed

2

3

4

Sleeve Operation

Packer Setting Sub

closed closed

closed open

openopen

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Fig. 4Upper-Zone Production

SCSSV Control Line

Chemical Injection Line

PES FlatpackControl Umbilical

SCSSV

Dual Splice Sub

Cross-Coupling Protector

Hydraulic Set Packer


Sliding Sleeve (DZICV)

Plug

Upper Zone Gravel Pack

Lower Zone Gravel Pack

PBR IsolatesUpper and Lower Zones

Methanol Injection Valve

Chemical Injection Valve

Shroud

Position Lower Zone Upper Zone

1 open

2

3

4

SleeveOperation

Packer Setting Sub

closed

closed

open

closed

closed

open

open

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Fig. 5Dual-Zone Interval Control Valve (DZICV)

Upper Actuator Seal(UA)

Lower Actuator Seal(UA)

Upper Isolation Seal(UI)

Middle IsolationSeal (MI)

Lower Isolation Seal(LI)

mingle Position

Upper Zone Only Position

Closed Position

Lower Zone Only Position

Com

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Fig. 6Electro/Hydraulic Module and ICV w/Solenoid Valves

Fig. 7Hydraulically Actuated ICV

Hydraulically Actuated ICVTUBINGHANGER

HF-1PACKER

SSSV

TUBING

INTERVAL CONTROLVALVE

SUBSURFACE

SAFETY VALVE

PACKERSETTINGPISTON

PACKER SETTING SUB

Hydraulic Piston Up

Hydraulic Piston Down

Electro/Hydraulic Module and ICV w/Solenoid ValvesTUBING

HANGER

HF-1

PACKER

Hydraulic Line #1

ANNULUS

SSSV

TUBING

SOLENOID VALVE

SOLENOID VALVE

INTERVAL CONTROLVALVE

SUBSURFACESAFETY VALVE

PACKERSETTINGPISTON

Hydraulic Line #2

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Fig. 8Direct Hydraulic Stack-Up

Through Tubing Hydraulic

Set Retrievable Packer

Direct Hydraulic Sleeve for

Dual Zone Control

Shroud for Dual Zone Control

Slickline Plug

Dual Flatpack Splice Sub w/

two pass through slots for

packer-set-sub lines.

Clamps on filter mandrel at topof packer.


Permits Control and

transfer of Downhole datatelem try, Gauges, Position

sensor and Solenoid Valve

Activation.

Position Sensor

Indicates Sleeve positionvia communications with

the electro/hydraulic

module.

e

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