back pressure while pigging.pdf

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Copyright 2003, Offshore Technology Conference

This paper was prepared for presentation at the 2003 Offshore Technology Conference held inHouston, Texas, U.S.A., 58 May 2003.

This paper was selected for presentation by an 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 waspresented.

AbstractA project engineer responsible for a topsides upgrade on a

subsea tie-back project, often faces challenges that may not be

apparent based on his or her experiences on typical new buildfacility type projects. This paper is intended to help that

engineer. It is a compilation of lessons learned from several

project engineers having relevant experiences on subsea tie-back projects.

IntroductionThe paper is comprised of lessons learned as presented by four

project engineers, each of whom have worked on several

subsea tie-back projects. It focuses on topsides facilities

issues on projects where there is a subsea tie-back to an

existing facility. The paper attempts to avoid technical issuesin the Subsea Teams scope and issues not specific to subsea

tie-back projects. The objective is to better prepare a project

engineer who is experienced with topsides new-build typefacilities for some of the project challenges associated with

subsea tie-backs.

In this paper, major issues are segmented into various

categories including flowlines, chemical injection, flow linepigging, slug control, flare, relief and blowdown systems,

metering, management of change, and subsea interfaces.

FlowlinesWhen the flowline comes on to the host platform, it becomesthe Topside Design Teams scope. There are several design

decisions that must be considered including the location of theflowline shutdown valves (SDV), the choice of flowline

material and the selection of the various flowline

instrumentation.

Location of Shutdown Valves. The location of the flowline

shutdown valves should be related to safety on the platform.

The concern is if there is a failure (loss of containment) in the

flowline / riser upstream of the shutdown valve, there would

be no way of stopping the leak. As a worst case scenario the

entire platform could be lost. Typically, there are three

options to mitigate this risk:1) Install a subsea shutdown valve. This option is very

expensive. Also, it may not be possible to install the

shutdown valve very close to the platform, which wouldincrease the volume of gas between the shutdown valve and

the platform.

2) Install the topsides shutdown valve where it would

minimize risk of failure in the riser / flowline upstream of thevalve. For instance, the shutdown valve could be located

below the lowest equipment deck on a fixed jacket type

platform where this was considered an issue. Some valves are

not easily accessible and may now be located in the platform

air gap or wave zone.3) Increase the integrity of the riser / flowline upstream of

the shutdown valve. This can be achieved by providing any o

the following:- Added wall thickness

- Insulation

- Corrosion protective coating- Explosion protection around flowline and SDV

- Corrosion monitoring- Leak monitoring

- Orient flowlines to minimize impact of jet fire

- Minimize connections upstream of SDV- Add a second SDV

Flowline Materials. Design pressures of 10-15,000 PSI in

large flowline diameters have become more common over the

last few years. These high pressures are especially common insubsea tie-backs. The selection of materials for the flowline

is dictated by code requirements.Typically upstream of the pig launcher/receiver, the

flowline design will be governed by ASME B31.8 - Gas

Transmission Systems And Distribution Piping. SinceASME B31.8 does not consider tensile strength in its

determination of allowable stress, an API 5L material, with ahigh yield strength but a relatively low tensile strength, is the

popular choice of material. Note that, if in Gulf of Mexico

(GOM) waters, a departure from the Minerals Managemen

Service (MMS) will need to be obtained to allow for using the

ASME B31.8 through the pig launcher. Also, the constructionfactor dictated by the Code of Federal Regulations (CFRs) is

lower than the construction factor dictated by the B31.8 code

The less stringent construction factor is sometimes allowed

but, again, will require a departure request.

OTC 15112

Topsides Lessons Learned from Subsea Tie-Back ProjectsRichard Livingston, David Tong, Eric Wensel, and Michael Whitworth: Mustang Engineering L.P.


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Downstream of the pig launcher / receiver, the flowline

design is dictated by ASME B31.3 Process Piping. Since

ASME B31.3 does consider tensile strength in itsdetermination of allowable stress, an API 5L material is

typically not adequate. Often, the material of choice is AISI

4130N or 4130Q&T material.

Upstream of the pig launcher, flowline changes of

direction will often require five diameter (5D) bends.Consideration should be given to specifying and sourcing

these 5D bends, especially if using high grade material. Also,consideration should be given to the ability to bend various

high strength materials. Some materials, such as AISI 4130

steel, are difficult to bend and yet still maintain its original

characteristics.

Flowline Instrumentation. Due to the high pressures, large

diameters and high velocities associated with subsea tie-back

flowlines, some unique instrument requirements are presented.

Some of the instrument issues that should be addressed areas follows:

- Consider using a non-intrusive pig signal.- Make thermowells short and check for vibration-

induced failure.

- Consider chloride stress cracking in stainless steel

instruments especially if flowline is warm.

- If a flowline heater is required, consider using arupture disk in addition to a smaller relief valve to

protect against tube failure. Note An MMS

departure is required for GOM applications.

- Locate a manual isolation valve upstream of theboarding SDV so the SDV can be tested.

The location of the flowline Pressure Safety High/Low

(PSH/L) should be given some discussion. The MMS requiresthat the PSH/L be located upstream of the boarding SDV. If

the small PSH/L instrument connection broke, there would beno way to stop the flow. If a manual isolation valve was

located upstream, the flowline could be isolated, but

consideration should be given to how the valve can be closedif the failure resulted in a fire. For example, on one project, a

fail safe actuator was put on the isolation valve along with a

remote control station. This provided a way to close the valve.

Chemical InjectionTypical topsides chemical requirements for sub-sea projectsinclude:

- Hydrate Inhibitors (Methanol, LDHI, etc.)

- Corrosion Inhibitor

- Paraffin Inhibitor- Asphaltene Inhibitor- Scale Inhibitor

Hydrate Inhibitor. Generally, topsides will need to provide

hydrate inhibitor injection to protect the wells, jumpers,subsea manifold, etc., from hydrate formation. The

requirements are dictated by the subsea configuration and are

usually defined by the Subsea or Flow Assurance Team.Hydrate inhibitor designs can be broken into two categories.

Non-Continuous Hydrate Inhibitor Injection. Under

normal flowing conditions, if the production fluid temperature

stays above the hydrate formation temperature, continuous

hydrate inhibitor injection may not be required. However

even if continuous hydrate inhibitor injection is not required

typically methanol injection is still needed during well start-upor pressurized shut-in conditions. The Flow Assurance Team

should develop procedures for start-up and planned and

unplanned shut-ins of the subsea wells.Continuous Hydrate Inhibitor Injection. If, under norma

flowing conditions, the production fluid temperature dropsbelow the hydrate formation temperature, continuous hydrate

inhibitor injection is necessary. Typically these hydrateinhibitors are methanol, glycol, or various low dosage hydrate

inhibitors (LDHIs).

Injection Equipment. (Based on methanol injection)Hydrate inhibitor injection systems usually include on-loading

facilities, storage facilities, coarse and fine filtration, booster

pumps, injection pumps, meters and distribution manifolds

Some facilities may also require either methanol or glyco

reclamation due to the significant injection quantities. Thesesystems are beyond the scope of this paper.

Pumps. High rate, high pressure, and high integritymetering pumps are typically required for hydrate inhibitor

injection pumps. Often, high quality diaphragm metering

pumps are used. These pumps offer the advantage of having

no mechanical seals and have minimal contact with the

injected fluid. If the injection is not continuous, plunger typepumps may be considered.

Typically, each injection point has a dedicated pump or

pump heads; thus removing the requirement to split flow using

control valves on the pump discharge. However, directingflow using flow control valves may still be considered if there

are significant footprint or cost limitations. A flow splitter

panel can then be used.Consider designing the pump piping to allow for starting

the pump in an unloaded condition. This may increasepump life.

The pump availability must also be determined. Shouldthe pumps be available on loss of main power? The Flow

Assurance Team must answer this question. If so, the pumps

may require power supplied by the emergency power system

On one such project, a pump was powered by the emergencypower system, allowing batch pumping of methanol in case of

a topsides loss of main power.

In addition to injection pumps, injection booster pumpsmay be required if the pumps net positive suction head

(NPSH) requirement is greater than the pumps available

NPSH. Like the injection pumps, operations may desire that

these pumps not have mechanical seals.Injection Metering. For high rate injection, such as

methanol injection, on-line metering may be necessary. Due

to the high pressure and pulsating service, meter selection is

critical. Turbine meters, often used in liquid service, are

usually not effective. Positive displacement type meters areoften preferred in this service.

Piping & Tubing. The chemicals are delivered to the

subsea wells and manifold via umbilicals provided by theSubsea Team. These umbilicals usually have one or more

injection tubes per injection point. Typically a manifold i

provided on the topsides to allow for lining pumps or pump

heads to different subsea injection points. Depending on the


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desired flexibility, this manifold can be simple or quite

complicated. The Flow Assurance and/or Subsea Team will

typically dictate the flexibility desired. One option is to usehydraulic type hoses and bulk heads in lieu of a valved

manifold.

The piping system on the injection pump discharge is

dependent on the injection pressures and injection line sizes.

Stainless steel tubing is often used; however, standardcompression type fittings may not meet the required pressure

ratings. At higher pressures, either coned and threaded tubingconnection systems or welded and flanged piping systems are

required. Note that coned and threaded systems are relatively

difficult to install and may leak if installed in a vibrating

environment.Overall system cleanliness before startup will be dictated

by the Subsea Team. Determine the cleanliness requirement

for each part of the system early in the design process.

Consider making provisions for flushing the system by

strategically placing valves and bypasses.Filters & Strainers. Selection and placement of filters and

strainers should be determined by the requirements of bothoperations and the Subsea Teams. Often a coarse strainer or

filter is required at the methanol loading point to catch large

solids. Filters may be placed upstream of the injection pumps.

Also, a fine filter may be placed upstream of the umbilical

connection. Finally, some subsea tie-back projects haveused a recirculation filtering system to continuously clean

the methanol.Storage. The amount of methanol storage is first

determined by whether injection is continuous or used forbatch treating. For continuous injection, the storage tank is

sized to minimize the frequency of reloading. For high rate

injection requirements, typically a one to two week supply isused. For batch treating, storage capacity for two batch

treatments is often required. The storage capacity should begiven careful consideration based on operational requirements,

risk, and safety.

The type of tank must also be considered. The storagetank could be a pressure vessel or an atmospheric tank-type

design. The decision is typically a function of safety and cost

considerations. On some installations, methanol storage canbe put inside the hull or even a well conductor.

The tank material is usually stainless steel or internally

coated carbon steel. For large tanks, stainless steel may beimpractical. Internally coated carbon steel tanks have proven

to be effective. Consult the coating manufacturer for a coating

suitable for methanol service.

Methanol and Chemical Onloading. Bulk loading ofmethanol is one of the more dangerous activities associatedwith methanol injection. Loading is often done by pumping

methanol from a boat to the platform storage tank. Special

considerations should be given to this procedure. Features can

be designed into the system to minimize risks, i.e., bettercommunication between platform and boat, high tank level

alarms, break away hoses, etc.

Flowline PiggingWax buildup in the flowline can be mechanically removed by

pigging with scraper pigs. If flowline pigging is required,

flowline and topsides equipment design should allow for the

scraper pigs to be run periodically through the production

flowlines. Pigging is usually achieved with oil or gas.

Oil Pigging. Oil Pigging Systems usually include pig

launcher and receiver, pigging pumps, oil buyback facilities

metering and flow control.Pig Launcher & Receiver. Pig launchers and receivers are

preferably installed horizontally to facilitate removal ocollected paraffin following a pig run.

Pigging Pumps. In some cases, hydraulic calculationsmight indicate the required pigging pump discharge pressures

are within the capability of the existing sales oil expor

pipeline pumps. Hence, instead of installing a new pigging

pump, one or more of the existing oil pipeline pumps could beused. Even if a new pump is required, typically the existing

charge pumps can be used to pump oil to the pigging pump.

When using oil as the pigging medium, the operation is

simply a non-compressible fluid volume displacement; the

pigs location and speed can be controlled at all times. Sizethe pump to achieve the desired pig velocity. Typically, a

velocity of 3 ft/sec is recommended (15,000 bpd in an 8 IDpipeline). This rate is most effective for wax removal and

adequate sweep of liquid at the low spots.

Worst case pump discharge pressure is generally a

function of line losses, pigging friction and back pressure on

the return flowline. The Flow Assurance or Subsea Teamshould be able to calculate the discharge pressure

requirements.

It is desirable to keep back-pressure on the return riser

The return riser is typically circulated to an inlet separator tomaintain a back pressure on the pigging pumps. If the back

pressure on the flowline is too low, the pressure in the inle

riser could fall below the bubble point of the black oil, i.evacuum, allowing gas to break out. This could adversely

affect the pump, and the pig velocity will vary substantiallywithout control.

Oil Buyback Facilities. The source of pigging oil must bedetermined. Oil for the pigging operation may be supplied

from one of two possible sources:

1) Other production not dependent upon the subsea system

This typically takes discharge off of the existing crude oibooster pumps.

2) A new sales oil buyback system installed to allow

purchase of crude oil from the facilitys oil export pipelines (iavailable produced oil volumes are insufficient). If an oi

export pipeline check valve is in-place, a contingency plan

shall lock it open prior to any pigging operation.

A large dry oil storage tank filled prior to a piggingexercise is usually unreasonable (approximately 300 barrels

per mile in an 8 ID line).Meters. If the subsea produced oil is metered separately

from the platform produced oil, the oil used for pigging must

be metered as it goes into the flowline. See section onmetering for more details.

Gas Pigging. Gas pigging serves as an alternative to oipigging. It can have the advantage of requiring less capita

cost than oil pigging option as it does not require a

pigging pump.


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The source of gas should preferably be the dry gas from

the gas dehydration system. Therefore, the flowline will stay

in the safe zone of the hydrate formation curve, both duringthe pigging operation or if the pigging gas is required to

remain in the flowline for some time.

When produced gas is not available, a sales gas pipeline

buyback system could provide a high pressure gas source for

the pigging operation.The pigging gas rates vary based on the flowline size,

length, and system configuration. For a 6 I.D. x 1 1/2 milelong flowline loop, 5 MMSCD gas rate is adequate to make a

round trip in less than 2 hours, with a target pig velocity of 3

ft/sec. Due to the nature of gas pigging, however, the pig

velocity is difficult, if not impossible, to control.The pigging circuit could line up the outlet of the receiver

to the inlet separator. Because gas is a compressible medium,

the pig velocity will vary erratically, and its position is

extremely difficult, or impossible, to locate. Once the pig

passes the base of the return riser, the pig exit velocity alongthe ascend of the riser is also impossible to control by

the flowrate.A flow restriction device is recommended on the outlet of

the receiver to control the liquid and gas arrival rates, and the

pig velocity. Without this flow restriction, the exit liquid / gas

instantaneous peak rates could easily overwhelm the process

system and cause an upset. Figures 1 and 2 show a gas piggingsimulation with and without restrictions on the return

flowline, respectively.

Slug ControlThe handling of slugs is another topsides design issue. The

Subsea Team will perform steady-state and transient modeling

of the subsea production system to determine the likelihoodand magnitude of slugging in the flowlines. The simulations

will require input from the Topsides Design Team for designdata, such as the back pressure on the flowline.

Modeling results will suggest the impacts of terrain-

induced or hydrodynamic slugging, which will be expectedand will need to be accommodated on the topsides. Based on

the simulations, the Subsea Team should be able to provide a

rate versus time graph. The slug catcher volume requirementis a function of the allowable dumping rate of the vessel and

the rate and period of the slug(s).

The Topsides Design Team will need to determine whetherthe inlet separator will absorb the incoming slug or if the inlet

separator will pass the slug to downstream equipment. If the

downstream equipment can handle slugs, it may be possible to

minimize the inlet separator size. However, considerationshould be given to the effect the slug will have on meteringand separation.

Flare, Relief and Blowdown SystemsDue to a number of characteristics specific to subsea tie-backsystems, the flare and relief system on the host platform may

not be adequate for the subsea tie-back. Challenges include

high relief rates if a topside choke is used, low relief gastemperatures, and flowline blowdown requirements.

Inlet Choke & Maximum Relief. If a topsides inlet choke is

used on a multi-well subsea tieback, the topside relief system

worst-case relief scenario will probably be dictated by the

failure (or blowby) of this choke. The gas blowby rate is

proportional to the size of the valve and the maximumpressure in the flowline or flowline pressure safety high (PSH

setting. The choke must be large enough to minimize it

pressure drop under normal flowing conditions. The PSH

setting must be set high enough to avoid trips due to varying

flowline pressures during normal operation. Both of thesefactors lead to high gas blowby rates. An example of the relie

rate introduced by a sudden inlet choke failure is shown inFigure 3.

Cold Temperature Issues. Low temperature relief system

design may be a concern due to Joules-Thompson coolingacross pressure safety valves (PSVs), flare valves and

blowdown valves. The low arrival temperatures associated

with tie-backs, as opposed to the warmer temperatures

associated with platform wells, requires a close look at relief

system temperatures.A relief header built using standard ASTM A-106 Grade B

material is rated for a minimum design metal temperature(MDMT) of (-)20F. Furthermore, the relief vessel often is

rated for temperatures even higher.

For instantaneous, short term relief, the heat capacity of

the steel pipe and vessel may be adequate to keep the metal

temperature above the MDMT. In this case, only a shorlength of piping downstream of the relieving device needs to

be made of low temperature material. This length can be

calculated based on a model that measures temperature change

in the gas and pipe as a function of time and distance.The more difficult low temperature problem in tie-back

relief systems is when a flowline blowdown is required. I

operating criteria dictates a controlled blowdown of theflowline, more than just a short distance of pipe may need to

be designed for low temperatures.A possible solution could be found in ASME B31.3 and

API 579 Recommended Practice for Fitness for Servicewhich have some qualifications for preexisting piping system

that allow for as low as -50F (MDMT) in ASTM A-106

Grade B piping.

Flowline Blowdown. An additional problem associated with

flowline blowdown is liquids handling. The facilities must be

able to handle the liquids condensed out downstream of theblowdown valve or that are swept from the flowline up to the

platform due to high gas velocity. This may not be a problem

if the blowdown is planned in advance (e.g. platform

evacuation due to a hurricane) and the liquids can be pumpedout of the inlet separator into the pipeline or a large storagetank, but during a platform shutdown there is rarely a means

of removing the accumulated liquids.

HIPPS. Relief system design is a common concern with tie-backs. Typically, the existing relief system is only designed

fit-for-purpose for the original platform production

requirements. The tie-back often creates pressure, liquid carryover, radiation and temperature inadequacies in the existing

host platform relief system.

One alternative to consider for subsea tie-backs is the High

Integrity Pressure Protection System (HIPPS). The HIPPS


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system is a high reliability instrumented safety shutdown

system featuring dual shutdown valves on the incoming

flowline. The basis for the HIPPS system is that the inletSDVs must be able to close in less time than it takes for the

flowline pressure to increase from pressure safety high (PSH)

to the downstream systems maximum allowable working

pressure (MAWP). As a rule of thumb, the time allowed for

the SDVs to close should be approximately one second perinch of line size. Furthermore, the HIPPS system, when

provided with extensive maintenance, testing and verification,should be as reliable or more so than the standard relief

valve installation.

A HIPPS installation requires extensive safety analyses,

and should be considered only when modifications to theexisting relief system are unreasonably difficult. Even when

installing a HIPPS system, consideration should be given to

installing a full flow relief valve anyway.

MeteringMetering on subsea tie-back projects can often be more

complicated than first assumed. The complexity arises whenthe subsea tie-backs hydrocarbon production comes from a

different lease than production on the existing host facility.

If the host owner and the tie-back owner are different,

metering can be even more complicated. Before commingling

the host and tie-back production, the tie-back and host facilityowners may dictate a metering accuracy near that required for

custody transfer. Depending on the level of processing, i.e.,

separation, stabilization, etc., accurate metering can be

difficult. The need to meter production before comminglingmay dictate adding a separator, changing a two phase

separator to a three phase separator, adding new meters to host

separators, etc.In addition to metering host and tie-back production before

commingling, buyback meters often are required, such asthose for fuel gas or pigging fluids.

Liquid Metering. One metering challenge is handling ratefluctuations at the meter. For instance, if a turbine meter is

used, rates should remain within 25 to 85% of the selected

meter capacity. For subsea tie-backs, liquid flow rates oftenvary dramatically during normal operations or worse during

start-up or rate changes. On one project, a combination of

snap-acting and throttling liquid dump valves was used tomaintain rates within an acceptable range.

Another problem with metering liquid directly out of the

separator is that the gas and liquid phases are at equilibrium in

the vessel. Any pressure drop below separator pressure leadsto flashing gas and inaccuracies in metering. One option, aswas done on an oil production tie-back project, is to locate the

meter as far below the separator outlet as possible, even on a

lower deck. Also, consider using larger pipe upstream of

the meter.

Methanol in Oil. Another oil sales issue is the presence of

methanol. Since methanol is used heavily in the subseaproduction for hydrate inhibition, a substantial amount of

methanol will dissolve in the oil phase. Methanol presence in

crude often has negative implication on the final sale of

that oil.

To solve this problem, a number of subsea tie-back

projects have been required to install water wash facilitie

(like those used for crude desalting) to remove the methanolfrom the crude. Typically, produced water from a non-subsea

source (usually the host platform dry tree production) is used

as this source is free of methanol contamination. On one

project, for 15,000 BPD of contaminated oil, it took

approximately 3,000 BPD of clean water to achieve a finamethanol concentration of 120 PPM. Although the process is

similar to crude desalting, the methanol is somewhat solublein oil, and the water is more difficult to remove.

Process Handling Agreement. Typically on a project where

the operator/owners of the producing field and the hosplatform are different, there will be an agreement between the

two parties explaining how they will operate. The Projec

Team designing the facilities does not typically write this

document; however, this document often will have significan

impact on the facilities design, especially metering designThe document is often missing the technical detail required to

go straight to detail design and, depending upon who isreading the document, can be interpreted in different ways.

It is a common mistake for the Project Team to assume

that what the document meant to say was one thing, only to

find out late in the project that something else was required

Hence, when the Process Handling Agreement is issued, theProject Team should assign a person or persons to translate the

document into a design basis-type format with significan

detail. This design basis-type document should be reviewed

and approved by metering specialists, asset managers, etc.both parties having an ownership of the Process Handling

Agreement. Where there are vague statements, the Projec

Team should try to obtain and document a consensus from allparties as soon as possible.

Management of ChangeManagement of change, specifically document changemanagement, associated with a major platform upgrade, such

as a subsea tie-back, is a significant task that should be given

careful thought and up-front planning. A poor managemen

system can lead to design mistakes and loss of integrity of theplatforms definition documents.

At the beginning of the project, the Project Team should

take inventory of all the platform documents to determine theistatus (quality). The Project Team should determine which

documents will be needed to execute the project, i.e., approva

documents, construction documents or permitting documents.

The Project Team should also determine which documentsoperations wishes to keep evergreen and which documentsthey do not. The Project Team should develop a procedure fo

modifying existing documents and adding new documents

How to handle platform documents when other modifications

to the platform are taking place concurrently with the SubseaTie-back Project must be addressed.

Subsea InterfaceOn a typical subsea tie-back project, the Topsides Team may

be required to interface with a number of different entities.

- Subsea and Flow Assurance

- Riser & Flowline


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- Installation / Construction

- Various Owners

- Platform Operations- Regulatory (MMS, ABS, USCG)

- Health, Safety & Environmental (HS&E)

Of those listed above, the subsea/topsides interface is

unique to subsea tie-back projects and is given attention in this

paper. Since subsea tie-back projects have many similarities, alarge number of the subsea/topsides interfaces can be

established by looking at other subsea tie-back projects.

Design Basis Data. As soon as possible, the Subsea Team

should provide the Topsides Team with critical design

information that will impact process design.- production rates

- arrival pressures

- arrival temperatures

- slugging volumes and rates

- chemical injection requirements- pigging requirements

- flow control (choke) requirements

Tracking Interfaces. Early in the project, as many interfaces

as possible should be identified, while information needs and

need dates should be established. An interface register or

action item list should be started and maintained. If possible,each team should assign an engineer to interface with the other

team. Regularly scheduled interface meetings should be

established early on and maintained throughout the project.

Also, an Interface Responsibilities Schematic should begenerated. An example of this diagram is provided in Figure

4. This diagram will assist in identifying the various areas

where attention is needed. This information may be presentedin more than one drawing. It is recommended that all

connections, cabling, utility requirements, and other interfacesbe shown on a schematic. The schematic should identify

connection size and type (this can get complicated with more

and more global sourcing, i.e. European threads, etc.), who isresponsible for providing the interconnecting material

(electrical cable, piping, tubing, hydraulic hose, etc.), and who

will be responsible for making the actual connections.Interfaces and responsibilities may be shown on typical

project drawings as well, such as Piping and Instrument

Diagrams. In addition to defining responsibility for providingor installing various equipment, responsibility for start-up and

commissioning of each system must be identified.

Flowline, Riser and Umbilical. The Topsides Team willhave a physical interface with the flowline, riser andumbilical. Typical interfaces with each of these items include:

Flowline and Riser

- Number of lines

- Size, material and wall thickness- Bend requirements is pigging required, if so, what

type of pigs?

- Design pressure and temperature requirements (specbreaks)

- Hydrotesting and dewatering requirements

- Connection location and type

- Riser supports

- Installation impact on offshore hookup

- Venting requirements (flexible risers)

Umbilical

- Structural support (I-tube, J-tube, etc.)

- Interface location

- Installation impact on offshore hookup

Topsides Equipment. Subsea equipment will require supporequipment to be located on the topsides facility. Often the

equipment is supplied by the Subsea Team, hooked up by theTopsides Team and then commissioned by either or both

teams. Some of the equipment typically installed on subsea

tie-back projects includes the Umbilical Termination Unit

Hydraulic Power Unit, Automation and Controls System(MCS), etc. Typical interfaces with each of these equipmen

items include:

Hydraulic Power Unit (HPU)

- Footprint and weight

- Need to be on emergency power- Normal control requirements

- Power requirement- Number of motors

- ESD interfaces

- Additional hydraulic fluid storage requirements

- Utility requirements

- Cleanliness / flushing requirements- Drain connections

Umbilical Termination Unit (UTU)

- Footprint and weight

- Upstream filtration requirements- Utility requirements

- Normal control requirements

- ESD interfaces- Fitting and tubing types

- Drains- Cleanliness / flushing requirements

- Location relative to umbilical requirement

Master Control Station (MCS) and Instrumentation

- Location of master control station

- I/O from the subsea control system.

- Power requirements for the subsea control station- Utility requirements for the subsea control station

- Integration with other control systems

- Provide weight, footprint and height of the equipment- Will a separate control building be required?

- Is UPS required? What are UPS requirements?

ConclusionThe information presented in this paper is based onexperiences from project engineers who have completed

subsea tie-back projects. This paper only addresses a limited

scope of issues. Furthermore, each project has differen

circumstances and requirements and the solutions presented inthis paper may not be applicable to all subsea tie-back

projects. Nevertheless, many of the issues mentioned in this

paper will need to be addressed on future subsea tie-backprojects. It is hoped that the project engineer can use the

lessons learned presented here to better plan and prepare for

upcoming subsea tie-back projects.


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2 00

3 00

4 00

5 00

6 00

7 00

8 00

1 90 0 2 0 0 0 2 1 0 0 22 0 0 2 3 0 0

A r r i v a l P r e s s u r e ( p s i g )

ReliefCapacity(mmscfd)

3 0 , 0 0 0 B P D , 85 M M S C F D

2 5 , 0 0 0 B P D , 70 M M S C F D

2 0 , 0 0 0 B P D , 55 M M S C F D

F lo w l in e P S H S e t a t 3 5 0 0 p s ig

In le t S e p a r a to r O p . a t 1 9 0 0 p s ig

FIGURE 1

FIGURE 2

FIGURE 3


8/8

8 OTC 15112

FIGURE 4

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