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Applicability ranges for offshore oil and gasproduction facilities

Beverley F. Ronalds*'r

CSIRO Petroleum, Perth, Attstralia

Received 29 November 2003; accepted 20 June 2005

Abstract

In the early stages of the selection process for the hardware to exploit an offshore petroleum

reservoir, it is important to be able to identily rapidly which production facility type(s) are likely to

deliver the greatest value. This paper explores key features and constraints of the ten common fixed,

floating and subsea facility options. Both shallow and deepwater are considered, along with regional

variations. It is shown that facility applications may be categorised in a very simple matrix form, with

the water depth and well count being particularly important drivers of facility choice.

Crown Copyright €) 2005 Published by Elsevier Ltd. A11 rights reserved.

Keywortls: Petroleum productionr Facility selection; Floating platforms; Subsea tiebacks

1. Introduction

The concept-screening phase of an oil and gas'field development requires a working

knowledge of the offshore facilities employed around the world. This paper outlines and

compares the ten different production facilities in common use. Here a production facility

is defined as the equipment and its supporting structure at which the well fluid is initially

received. Surface facilities thus house the production risers while, for subsea satellites, the

production facility comprises the seabed equipment clustered at the field site upstream of

the export flowline(s).

*Tel . : +61 864368700; fax: r6 l 864368578.E-mail address: beverley.ronalds@csiro.au-

IAlso Distinguished Visiting Professor, School of Oil and Gas Engineering, The University of Western

Australia.

0951-8339/$-see ftont matter Crown Copyright O 2005 Published by Etsevier Ltd. All rights reserved.doi: 10. 101 6/j .marstruc.2005.06.00 1

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254 B.F. Ronalds / Marine Structltres 18 (2005 ) 251 263

Characteristics of the various facility types are presented in summary form in Table 1.

Table 1(a) gives selected statistics for the facilities. In Table l(b), key drivers for system

selection are listed, and relationships between their properties and the various facilities are

defined. Principal attributes of the different facilities that encourage or discourage their

selection according to the key drivers are compared in Table l(c). These features and

constraints, as well as the key drivers, are discussed in the following sections.Note that the semi-submersible is included twice in Table 1. This recognises that semi's

fall into two categories those with and without direct vertical well access. Semi's differ

from other facility types in that both permutations have been seen in significant numbers.

It is also convenient to categorise production facility types in another way "shallow

water" and "deepwater" with the division at 300m. There are thousands of shallow

water developments around the world. For the most part, a database of North Sea

facilities is used in this study to demonstrate shallow water trends. The North Sea

experience base is largely in shallow water and has the further benefits of being

comprehensive (around 750 facilities) and well documented (e.g. [1]); many innovationshave also occurred here. Deepwater facilities are much less prevalent and so a worldwidedatabase may be utilised [2 4].

Although many factors interact in determining the optimal production system, the

databases indicate simple "rules-of-thumb" that greatly facilitate the pre-selection process.

These are developed in turn in the following sections.

2. Subsea tiebacks

Avoiding a surface-piercing production facility through the use of a subsea tieback

to shore or to a remote host is an appealing field development option. Subsea techno-

logy has advanced extremely rapidly over the past decade, in particular. However,

Table 2

Comparison of minimum platform and subsea satellite functionality

Feature Surface satellite (minimum platform) Subsea satellite

Future Past

AccessDrillingIntervention

Flow assuranceSeparationBoostingWater/gas injection

Chemical injectionPigging

UtilitiesRemote controlPowerMetering

MODU/SatelliteSatellite + boat

Host/satelliteHost/satelliteHost/satellite

Flowline/boatSatellite launcher

LOS/satellite/cableDiesel/cable

Satellite MFM

MODUSpecialist vessel

HostHostHost

UmbilicalRound-trip

UmbilicalUmbilical

Test line

B.F. Ronalds / Marine Structures 1B (2005)251-263 2JJ

accessibility remains a major challenge for subsea satellites that precludes their use in manycircumstances-accessibility for equipment operations, and also for delivery of utilities andto aid flow assurance (Table 2)-although all are receiving active attention by the industry.Flow assurance is considered here, and the other aspects in a later section.

2.1. Flow assurance

The challenge of delivering multiphase reservoir fluids to the host with high availabilityis now commonly known as flow assurance. Fig. 1 illustrates how maximum subsea tiebacklengths have increased over time. Gas- and oil-dominated tiebacks are reported separately,because of the considerable differences between them. In particular, gas-dominated subseatiebacks of up to 160 km are under development, whereas most oil-dominated tiebacks areless than 30km in length.

Technical and economic considerations interact in determining a feasible tieback length.With low reservoir energy, the distance the fluid can flow at a practical pressure andproduction rate is limited without boosting. Enhanced oil recovery (EOR) mechanisms arealso commonly employed to increase production-such as water or gas injection or gas

lift-which require additional import flowlines to the satellite field. The temperature dropdown a long multiphase export flowline encourages the formation of solids such ashydrates and paraffins. This may be managed through different combinations ofinsulation, pipe-in-pipe construction, active heating, chemical injection, pigging and freewater removal. A corrosive fluid may require steel alloy pipe. These various complexconfigurations and exotic materials bring increasing difficulties and expense over longerdistances. As a result, it is often economic to choose a surface facility to perform thefunctions required at the field location.

Recent record tieback lengths for oil-dominated satellites in Fig. I have been achieved inpart through the placement of additional equipment on the seabed. This has includedsubsea or downhole multiphase flow metering (MFM) and sub-sea pig-launchers, whichenable a single export flowline rather than the dual flowpaths commonly employed for oil

150

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B.F. Ronalds I Marine Strudltres 18 (2005) 251-263

tiebacks. Subsea multiphase pumping, water-driven from the host, has also been adopted.Further technology advances of this type may be anticipated in future (Table 2).

Gas satellite fields, in contrast, have simpler tiebacks for two reasons: they are generally

exploited by natural depletion, and fluid export is less problematic. Longer tieback lengthsare thus possible, although there are ongoing hardware challenges associated with thedelivery of utilities to the subsea wellheads.

3. Shallow water

Fig.2(a) shows the distributions of jackets and remote subsea tiebacks installed in the

North Sea since 1980. A distinct demarcation is apparent, with subsea tiebacks beingemployed in deeper water and for lower well counts in comparison with platforms.

Intuitively, jacket costs are expected to increase strongly with water depth, whereas subseasatellite costs are more transparent to water depth, but increase steadily with well count.

=430o7zo

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1010

100 200Water Depth, d (m)

100 200

Water Depth, d (m)

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(c) Water Depth, d (m)

Fig.2. Shal lowwaterfaci l i t ies:(a)relat ionshipbetweenjacketsandsubseasatel l i tes-NorthSea,(b)relat ionshipbetween fixed and floating platforms-North Sea and (c) relationship between fixed and floating platforms and

subsea satellites Australia.

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B.F. Ronalds I Marine Structures IB (2005)251 263 257

3.L Access

A second important factor here is ease of access. To aid the discussion, the platform data

are divided into two categories in Fig. 2(a); those that operate in a normally unattended

mode are marked with a cross. In Fig. 2(b) the platforms are distinguished according to

whether or not they support a drilling rig.The figures show that platforms with 20 or more wells are nearly always manned and

have drilling and workover equipment. These facilities are also likely to have fullproduction and processing capabilities. Such features are more affordable with the larger

production rate generally associated with a high well count and can bring substantial

economic returns in greater reliability, productivity and ultimate recovery.North Sea platforms with less than 20 wells generally do not have drilling capability;

unmanned operation is also common. A significant proportion of these production

platforms perform first stage separation prior to export to a central processing hub or to

shore. Even minimum platforms retain access advantages over subsea satellites because

they frequently support light intervention equipment such as wireline and coiled tubing,

and periodic visits for inspection, maintenance and repair are relatively straightforward.

Remote subsea satellites, in contrast, require a mobile offshore drilling unit (MODU) or

specialist intervention vessel and subsea equipment for workover (Table 2). Subsea

tiebacks are thus more suitable for low well counts where little drilling and intervention is

anticipated and a lower recovery factor is acceptable.The largest jack-up MODUs can operate in cantilever mode over a fixed platform in

water depths of up to around l20m in the North Sea; hence, the jack-up is the drilling

system of choice within the lower left corner in Fig. 2. Jack-up drilling is often not suitable

for high well counts because of the need to relocate the unit around the platform to reach

all the wells. In deeper water, a platform with dry trees must support a derrick, which is

expensive for a low well count. Thus the combination of few wells and a water depth

d>120m is not conducive to a fixed platform solution, but favours a subsea satellite.

Furthermore, the expenditure profile typical of subsea solutions suits the lowerproduction rate, greater uncertainty and shorter field life that often accompanies a low well

count. Features include lower CAPEX and reduced cycle time, with a trade-off of greater

OPEX in intervention activities after revenue has started to flow.Two dividing slopes k: dlw are included in Fig. 2(a), where ru is the well count. In the

region above the upper line with k - 8 m, platforms are chosen, with subsea tiebacks being

the solution for k>20m. Subsea tiebacks are also common between the two boundaries,

especially for oil-dominated fields. However, there is also a number of jackets in this

intermediate zone. It is interesting to note that the majority of these are recent

developments, commonly being high pressureihigh temperature (HPHT) gas-dominated

fields serviced by a minimum platform. Subsea trees bring challenges for the control of

HPHT wells. Platforms have also been preferred for gas sales contracts requiring high

availability and when first stage processing is of benefit.

3.2. Utilities

A final factor is that the adoption of a minimum platform rather than a subsea tieback

may simplify or even avoid the umbilical from the host, which is advantageous for long

gas tiebacks or when considerable satellite functionality is required. As indicated in

258 B.F. Ronald.s I Marine Structures l8 (2005)251-263

Table 2, this is achieved by using line-of-sight (LOS) or space satellite communications and

control, by generating power onboard, and by transporting injection chemicals by boat. In

deeper water, a control buoy could perform these functions (e.g. East Spar offshore

Australia).

3.3. Floaters

In addition to fixed platforms and subsea satellites, Fig. 2(b) indicates floaters to be a

viable solution in moderately shallow North Sea waters. These are clustered in the region

of low-to-intermediate well counts, together with water depths where cantilevered jack-up

MODUs are either infeasible or very expensive-here it is an advantage for floaters to not

have dry wells.For d>kw, floaters compete for selection against subsea tiebacks, with the former likely

to be chosen for long oil-dominated tiebacks. The FPSO is particularly suitable here as it

even allows the oil export line to be eliminated.In cases where d<kw, the choice is between a fixed platform and a floater. A short

service life or a dispersed well pattern favours a FPSO or semi-submersible, and an FPSO

is again likely to be chosen when a very long oil tieback suggests in-field storage and tanker

export. Conversely, a jacket may enable the facility to be unmanned, which brings

considerable safety benefits; this option is currently not possible for floaters due to their

operational complexity. Jackets are also preferable when frequent well intervention is

anticipated.

3.4. Rellionul influences

Several further observations may be made in connection with Fig. 2(b). First, there are

very few platforms in the region with w>20 and d<70m. In shallow water depths it is

often more cost-effective to develop a large field with multiple small production platforms

rather than extended reach wells from a single drilling centre. This philosophy is

demonstrated frequently in the Southern North Sea.It is noted that floaters are confined to d270m in Fig. 2(b). They cannot be employed in

very shallow water in harsh environments as there is then insufficient compliance in the

risers to accommodate the considerable motions.There is a tendency for concrete gravity structures (CGS$ to be employed rather than

jackets in deeper waters and for higher numbers of wells. North Sea jackets have fatigue

challenges in these conditions. Large CGSs also allow inshore mating and integration of

the topside and substructure; the alternative of a sequence of offshore lifts followed by

extensive hook-up and commissioning is problematic for large topsides. Production jack-

ups have a similar self-installing capability. CGS construction requires less specialised

equipment and expertise than for jackets, and jack-ups may be readily converted from

other duties or reused from another field. Both may thus be cost-effective shallow water

solutions in regions with little construction infrastructure, with CGSs having the

additional advantage of oil storage.As mentioned, the various boundaries of applicability in Fig. 2 relate to the North Sea,

and might be expected to differ for other petroleum provinces due to the many natural and

man-made regional variations that influence life-cycle economics. They may also vary over

time. By way of example, data for Australasian facilities are presented in Fig. 2(c). Although

B.F. Ronalds I Marine Structures 18 (2005) 251-263

Table 3Influence of water depth and well count on facility selection

Water Depth d

Shallow<120m

Mod Shallow Mod Deep300-500m

Deep I Vcry Deep I Ultm-deeP

500-1350m11350-l800ml>1800m

U

Very High>36

... J5dd :esi ile,#ia*it'ii

,l*t**"*i" , :

High20,16

;;;i#lrtemediate

c;20

Jqckct (unmanned?)ccg [wtoteJ

Idck.ilp IrenoteJ

: : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : : I ]Jne\zr tcAal l

I $$Mod Low

5-9

sm$Tlt lSriar . I

<c Subsa ., ** : D$D$ealul$i"nh'ls

'' = l'-'l:i:';,,": 8m < * < 2om

'.:;'i:l:i:;#;fl Resolse*i| | FPSO lbenign net-ocecurl

I Platform drilling dg fordry trees

the subsea tieback database, in particular, is very small, the general trends for jackets and

FPSOs are in fact quite similar to those for the North Sea in Fig. 2(a) and (b). Severalproduction jack-ups and CGSs and have also been employed recently in this region.

In contrast, the Gulf of Mexico (GOM) exhibits different trends. FPSOs have not yet

been deployed here. However, with several thousand lightweight jackets and topsides, fixed

platform construction is cheap. In addition, standardised equipment including portable

drilling packages and process skids is commonplace. For these reasons, jackets are

frequently used for low-to-intermediate well counts in moderate water depths, rather than

floaters or subsea tiebacks; this is indicated in Table 3.

4. Deepwater dry-tree platforms

North Sea fixed platforms are combined with a worldwide database of deepwater

platforms with dry trees in Fig. 3(a); the majority of the latter are located in the GOM and

have full processing capability. It is apparent that the different platform types ale again

clustered into distinct groups according to their water depth and well count. The various

water depth and well count ranges are classified further in Table 3.

As already discussed, for shallow water depths and k<20m, fixed platforms are

adopted. Both fixed platforms and compliant towers are employed in moderate water

depths and for very high or high well counts (w>20). With these platforms having a

braced substructure extending through the water column, conventional well conductors

may be used, supported laterally at points along their length. The conductors can then be

set at a close spacing without risk of interference under extreme environmental loading.

For deepwater (500 1350m) and high well counts (20(w{36), the dry-tree platform of

choice is the "large" tension leg platform (TLP). The upper water depth is limited by the

tendon mooring and the risers: the tension forces in these elements increase rapidly in

deepwater, resulting in a large hull buoyancy requirement, and then greater tendon

tensions. This design spiral becomes more acute with larger numbers of wells and in more

B.F. Ronalds I Marine Structures lB (2005) 251-263

Table 3Influence of water depth and well count on facility selection

Water Depth d

Shallow<120m

Mod Shallow Mod Deep300-500m

Deep I Very Deep I Ultn-deep

500-1350m11350-l800ml>1800m

(J

Very High>36

.. Jiaf€t iec1 ii,i*n,,iii ilr,Rir

High20-36

J."l*t i

lntemediatccf20 ""i:;:,i:f::i[f ' I ;;, ;;;,']l :::i,$

Mod Low5,9

srlsiLPi**- ,

Subsea I So** :, ..Slorea--l!fldi-noal€r

c . = d/k and c .<20: 8m < * < 20m

=5 forr l>500m..:;,::ii:;ff:ffi resolseni| | FPS) [b?niin tilero(eul]

I Plrr furm dr i l l ing r ig fordry trees

the subsea tieback database, in particular, is very small, the general trends for jackets and

FPSOs are in fact quite similar to those for the North Sea in Fig. 2(a) and (b). Several

production jack-ups and CGSs and have also been employed recently in this region.

In contrast, the Gulf of Mexico (GOM) exhibits different trends. FPSOs have not yet

been deployed here. However, with several thousand lightweight jackets and topsides, fixed

platform construction is cheap. In addition, standardised equipment including portable

drilling packages and process skids is commonplace. For these reasons, jackets are

frequently used for low-to-intermediate well counts in moderate water depths, rather than

floaters or subsea tiebacks; this is indicated in Table 3.

4. Deepwater dry-tree platforms

North Sea fixed platforms are combined with a worldwide database of deepwaterplatforms with dry trees in Fig. 3(a);the majority of the latter are located in the GOM and

have full processing capability. It is apparent that the different platform types are again

clustered into distinct groups according to their water depth and well count. The various

water depth and well count ranges are classified further in Table 3.

As already discussed, for shallow water depths and k<20m, fixed platforms are

adopted. Both fixed platforms and compliant towers are employed in moderate water

depths and for very high or high well counts (w>20). With these platforms having a

braced substructure extending through the water column, conventional well conductors

may be used, supported laterally at points along their length. The conductors can then be

set at a close spacing without risk of interference under extreme environmental loading.

For deepwater (500 1350m) and high well counts (20(u.,(36), the dry-tree platform of

choice is the "large" tension leg platform (TLP). The upper water depth is limited by the

tendon mooring and the risers; the tension forces in these elements increase rapidly in

deepwater, resulting in a large hull buoyancy requirement, and then greater tendon

tensions. This design spiral becomes more acute with larger numbers of wells and in more

oJackeVCGSoCompliant Tower! TLPA SparxDril l ing

B.F. Ronakls / Marine Structures 18 (2005) 251 263

Water Depth, d (m) Water Depth (m)

00 1000 2000 3000

(c, Water DePth' d (m)

3. Worldwide deepwater facilities: (a) dry-tree platforms, (b) floaters and (c) subsea satellites

severe met-ocean conditions. Although a large TLP has a roomy moonpool, the riser count

may also be limited by the substantial spacing required to accommodate their top-

tensioning equipment and to avoid harmful clashing in deepwater. Unlike other deepwater

dry-tree platforms, the large TLP has the benefit of enabling inshore topside integration.

Moderately low to intermediate well counts (5<u'{20) and deep to very deepwater

(500-1800m) is the domain of the spar. The spar's taut catenary mooring is relatively

insensitive to water depth, and the risers are generally self-supported with large air cans so

their tension loads are not transferred to the hull. However, these air cans become large in

very deepwater, which limits the number that may be accommodated within the spar's

single column.Finally, a second category of "small" TLPs has proved to be economic for 5-9 well slots.

These may have a lighter hull than the spar, although sometimes at the expense of inshore

integration.

4.1. Drilling

The platforms in Fig. 3(a) are further distinguished according to their drilling

philosophy. In the same way as for shallow water platforms in Fig. 2(b), deepwater

platforms with 20 or more well slots support a drilling rig, whereas drilling capability is

much more unusual for w<20.

9- qoo=

20

60=st

frzd)

=20

I5

0 3000

(a)

i

-d 40o=

20

Fig

l lo

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Dalia (206)t

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(2m5)+

Greabr Huhia

Gtassd (m1)i

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omba A (2004) a Mini-floaterx Drii l ing

epo (2008) + Spread Moorin((2N7)t| +Agbami (20ffi)

a Foncador P52 (2006)idor P36) :hunder HoBe (2005)

a Ailantis {206)- - l .I Independencr

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(2007)

| (2ffi)BT.E+

rrrE;- ;o ' _

B.F. Ronalds / Marine Stntctures 18 (2005 ) 251 263

Table 4Drilling options lor dry-tree wells

261

Well counl Water depth Platform Drilling

<20

>20

<120m500-l 800 m

< 1350 m

JacketSparSmall TLP

Any dry-tree

Jack-up rig through platform

Floating ri g-trar.rslate platlbnn

Floating ri g-pre-drilling

Platform-mounted rig

The various ways in which surface wells may be drilled are summarised in Table 4. A

MODU may be employed after the platform is in-place in just two circumstances: for jackets

in shallow water, as discussed earlier, and for spars in deep or very deepwater; the latter is

achieved by translating the spar hull on the catenary mooring. This again helps to explain the

few dry-tree platforms in moderate water depths with intermediate well counts in Fig. 3(a).

The only remaining alternative to a platform drilling rig is to pre-drill all wells by

MODU prior to platform installation. The adoption of small TLPs shows pre-drilling to

be cost-effective for moderately low well counts. However, for a higher well count, this

approach would generate considerable up-front cost and delay in first oil not only in

development drilling, but also because of the additional appraisal effort required to

commit to a final well plan prior to gaining any reservoir production data.In comparison to moderate water depths, deepwater dry-tree platforms are seen to be cost-

effective for rather small numbers of well slots. In part, this is due to the rrlative transparency

of buoyant hulls to water depth. However, a very important feature here is that deepwaterplatforms remote from other infrastructure become production hubs, with their life extended

by tying back subsea satellite wells that would not otherwise have been developed.

5. Wet trees

5.1. FPSOs and semi-submersibles

The worldwide database of floaters is plotted in Fig. 3(b) to the same scale as Fig. 3(a).

Unlike deepwater dry-tree platforms, floaters are deployed in many petroleum provinces

and across a very wide range of water depths and well counts.In particular, production semi's and FPSOs are utilised in deep to ultra-deepwater and

for very high well counts-a combination for which no dry-tree platform is currently

suitable. These recent and ongoing developments are labelled in Fig. 3(b). Floaters are

suited to ultra-deepwater with their catenary mooring system. Semi's may support a very

high well count as the risers hang off the deck edge or pontoon in catenaries without the

requirement for tensioning. Furthermore, manifolding the wells at the seabed may reducethe number of risers considerably. For FPSOs, the riser count may be constrained by the

turret. However, in benign environments, FPSOs may be spread-moored, making very

high riser counts possible. The spread-moored FPSO is the processing platform of choicefor the large fields in deep to very deepwater currently coming on-stream in West Africa,

and has also been adopted offshore Brazil.In addition to these major developments, Fig. 3(b) indicates that floaters are very

commonly employed in moderate water depths and for low-to-intermediate well counts.

262 B.F. Ronalds I Marine Structures 18 (2005) 251-263

6 FPSO. Semi

aa a

aa

o t r lu

200Oil Production (k.bbl/d)

Fig. 4. Oil and gas export rates lor deepwater FPSOs and semi's.

This reinforces the trend shown in Fig. 2(b) that floaters fill an important niche in this zone

where dry-tree platforms have limitations. Fig. 3(b) further illustrates that FPSOs (but not

semi's) have been adopted in very shallow water; this is only feasible where met-ocean

conditions are benign.Floaters thus demonstrate versatility across the complete spectrum of field sizes and

service lives. Both FPSOs and semi's have a large deck area and support inshore

integration, making them very suitable for large topsides. This is aided for FPSOs by their

large displacement. However, conversions and reuse of the facilities is also very common,

and the reduced CAPEX and development schedule in such cases is advantageous for small

fields and early production systems. This versatility is indicated in Table l(b) for the

relevant key drivers using the term " Various" .FPSOs cannot yet support drilling. Around one-third of semi's have drilling capability

(Fig. 3(b)), which makes the semi a competitor to deepwater dry-tree platforms when direct

vertical well access is desired. However, systems with subsea wells but without drilling offer

an advantage over dry-tree platforms in their well versatility: the wells may be distributed

optimally around the field(s) with all through-life drilling, completion and workover

operations performed by MODU.For floaters without drilling capability, the choice between FPSOs and semi's may be

influenced by the field's gas-to-oil ratio (GOR). The oil and gas export rates for deepwater

FPSOs and semi's are compared in Fig. 4. It is seen that semi's have achieved large gas

export rates whereas FPSOs are commonly used for oil-dominated fields. This is a function

of both the latter's oil storage, and also gas processing and export/disposal challenges for

FPSOs located in harsh environments. Hull availability is also a very important aspect of

facil i ty choice for conversions.

5.2. Subsea tiebacks

The combined database of North Sea and deepwater remote subsea tiebacks is presented

in Fig. 3(c). Subsea satellites successfully fill the gaps left by dry-tree platforms in Fig. 3(a)

at low well counts over the complete water depth range. A very recent trend is for subsea

E==-- 20oCLxluo(t

B.F. Ronakls I Marine Strltctures IB (2005) 251 263 263

tiebacks to also be selected for several developments with intermediate well counts; these

are labelled in the figure.

5.3. Mini-floaters

Finally, Fig. 3(b) also includes data points for four mini-floaters. The mini-floater categorycomprises cell spars, mono-column TLPs and other proposed hull forms that support only a

low number of subsea wells and a small topside (Table 1(a)). They thus have a very

lightweight hull, making them a cost-effective alternative to the subsea tieback for small,

deepwater fields with flow assurance challenges or where it is advantageous to develop a hub.

6. Discussion and conclusions

The key drivers for facility selection outlined in the foregoing discussion are summarisedin Table 1(b). However, the specific trends in water depth and well count demonstrated in

Figs.2 and 3 may be formulated with more clarity in the format of Table 3. This table is

sub-divided into six water depths and five well count ranges. The shading indicates that

FPSOs and semi's are found in most combinations of well count and water depth. Otherproduction systems have much more specific applications, as itemised in the table, and

there is a number of zones where no dry-tree platform is suitable. Some recognition ofregional variations is made in the table using italics.

By virtue of how Tables 74 are derived, they are largely a reflection of currentpractice forthcoming technology innovations are not incorporated. Nonetheless, the

tables and the background discussion should be of use in the preliminary stages of the

facility selection process for a particular field, in rapidly pin-pointing the likely optimalproduction system(s) or highlighting any challenges where the limits of current experience

are being approached. They also indicate gaps in the current suite of options where futureinnovation might be of particular benefit; several of these are explored elsewhere [5].

The water depth and the well count are seen to be very important drivers of concept

selection. Both are variables: the well count is an output of the chosen production plan,

while in some situations the water depth may be adjusted by moving the platform location.

This suggests the value of integrating facilities and subsurface considerations in the systemselection process. For example, overlaying plausible well count and water depth ranges on

Table 3 may point to a different solution than stipulating a particular number of dry well

slots, which will contain in-built (and perhaps unquantified) conservatism.

Acknowledgement

This work was supported by BHP Billiton Petroleum.

References

[ ] The North Sea Field Development Guide,8th ed. Oi l f ie ld Publ icat ions;2001.

[2] Proc. OTC, Houston, various years.

[3] Offshore. PennWel l . var ious jssues.

[4] Offshore Engineer, Atlantic Communications, various issues.

[5] Ronalds BF. Deepwater lacility selection . O-lC 14259, Proceedings of OTC 2002.