Offshore platform treating facilities; voorstudie

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Technische Universiteit Delft

Vakgroep Chemische Technologie

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CONTENTS

1. Introduction

2. Summary and conclusions 3. Proposal to partners 4. Feasibility study 4.1 Objective 4.2 Overall approach 4.3 Reserves/Production forecast 4.4 Development schemes 4.4.1 4.4.2 4.4.3 4.4.4 4.4.5 4.5 Costs 4.5.1 4.5.2 4.5.3 4.5.4 Offshore facilities Evacuation schemes Onshore facilities

Schemes with Unit owned, dedicated facilities Schemes selected for economics

Cost basis Cost summary Tariffs

Costs of schemes selected for economics 4.6 Pre-selection 5. Economics 5.1 Economic assumptions 5.2 Revenues 5.3 Expenditures 5.4 Economic indicators 6. Comparison of schemes 6.1 Economics 6.2 Financial commitment 6.3 Conclusion 7. Uncertainties 8. Follow-up 8.1 Development plans/Budgets 8.2 Schedule 9. Appendices

2

-1. IHTRODUCTION

Following the oil price collapse in 1986 all work on the development of the F2/F3/F6 field was stopped. Changing circumstances have however led to renewed studies on the development of the field.

A stimulus to restarting development studies was the proposal made by

Unocal as partner in the F2/F3/F6 development to develop the field by means of an oil evacuation link to their existing oil transport system and a gas evacuation link to the NGT system.

The changing circumstances also include the potential development of a gas evacuation system to the Northern Dutch Offshore Area now taking shape. This evacuation system will offer the F3 field an attractive option for evacuation of the gas fraction. Another change was the considerably reduced investment cost level achieved by the oil industry in reaction to the oil price drop.

The study approach has been to build up the development options from their base. Data available from the Unocal proposal and from previous design work were used as much as possible. On process aspects new schemes were

developed. The cost basis for the development was re-established in line with present concepts and market prices.

The development schemes considered were all for Unit owned. dedicated facilities. Alternatives whereby either oil and/or gas would be evacuated by others and the F2/F3/F6 Unit would be charged a tariff were

superimposed. Both a two phase evacuation scheme and schemes whereby the oil and the gas are evacuated separately were considered. For the split evacuation options the alternatives tested for oil evacuation were offshore loading (Floating Storage Unit-FSU-with shuttle tanker). and evacuation via the proposed extension to the Union Oil Transport (UOT) system.

The results of the feasibility studies are set out in two parts: Part I - Comparison of alternatives and development proposal Part 11 - Technical feasibility and costs of development

alternatives

Part I summarises the results of the comparative studies and includes inforrnation on economics and tariffs. Part 11 documents the technical studies and the cost estimates in detail.

3

-2. SUMHARY AND CONCLUSIONS

3.

The studies show that at present oil and gas price levels and dollar exchange rate an economic development of the F3 field is feasible.

Comparison of the various development alternatives has shown that separate evacuation of oil and gas is more attractive than two phase evacuation via one pipeline. For the separate evacuation schemes, gas evacuation via the potential northern offshore gas evacuation system, with tariff charges to the F3 Unit, is more attractive than a Unit owned dedicated pipeline. NGT was also approached for a tariff indication. Though they have confirmed their interest, no quote has been received yet. For oil evacuation the offshore loading scheme is the best choice. It is, despite an improved indicative offer from UOT, more economical than the UOT pipeline route, the initial financial commitment the Unit will have to make is considerably lower and it has the benefit of being flexible viz. oil volumes to be transported.

Hence the most attractive development scheme is an offshore split of oil aod gas, with oil evacuation by means of offshore loading aod gas

evacuation via the potential northern offshore gas evacuation system. With this scheme F3 can be developed at an initial investment of about

Nfl. 700 x 106 (CVM 1.1.88, 50/50 estimate-implying

~

equal probability of overrun and underrun). This conclusion is based on a feasibility study only and will have to be reconfirmed as the project is further developed.

PROPOSAL TO PARTNERS

Based on the feasibility studies, NAM as operator of the field proposes to further develop F3 on the basis of separate evacuation of the oil and the gas. The development is proposed to be based on oil evacuation by offshore loading and gas evacuation via the potential northern offshore gas

evacuation system. As a next step a development plan is proposed to be made. This plan will be the basis for the detailed design work and project budgets. Project timing is proposed to be based on a late 1992 production start up, allowing time for a stepwise approach to the various project phases and an economie reconsideration af ter each phase.

4

-4 • FEASIBILITY STODY

4.1 Objective

The objective of this study was to determine how the F2/F3/F6 field can be developed most economically for the Unit. In order to meet this objective, it was required to review process options and compare the Capital and Operating expenditures of several schemes with related product yields. The cost data generated by this study were used as basic input data into the economie calculation ultimatel~ leading to a selection of the most

attractive scheme. The different schemes therefore had to be fully

comparable in terms of end product specifications, e.g. oil quality, gas quality, gas delivery pressure.

Only the Lower Graben Sand (LGS) reservoir was taken into account.

4.2 Overall Approach

The only market for crude oil in the Netherlands is located in the Botlek area near Rotterdam (refineries). All schemes assume oil transport to these refineries.

Since the emphasis was on low cost, all schemes exclude CO₂ removal facilities and means'to control the Wobbe index of the sales gas, on the

---assumption that the gas transporter, Gasunie, is able to accommodate this gas by the utilisation of their mixing, enrichment and/or N2 injection

facilities. It has also been assumed that Gasunie can accept the gas in the N.E. part of the Netherlands as weIl as in the N.W. part. Only single train process concepts (with adequate plant availability) have been considered. All schemes generate two sales products, oil and gas. Separate production of ~'s (from the C₃ 's and C

4's present in the wellstream) has been discarded since the product has a value per MJ comparable with gas but would involve high costs for production. These fractions have been used as process fueI.

-The implication of schemes generating two products (oil and gas) only, is that the process should be designed as a very sharp oil/gas splitter. This is reflected in each scheme, somewhere in the process system (being off- or onshore depending on the scheme particulars).

5

-All schemes addressed have been compared on the basis of full Unit owned, dedicated facilities. Selected schemes also were compared with parts of the facilities (e.g. evacuation systems) paid for by means of a tariff (joint gas or oil gathering systems).

The various schemes have been analysed by full process simulation of the

---~---r_rquipment and the~pelines. Some limited optimisation was carried out

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requirements of the overall comparative study, which can be ~

improved on in subsequent design.

4.3 Reserves/Production forecasts

The LGS wellhead fluid reserves figure carried in the study amounts to 12.53 x 109 m3

• The wellhead fluid product ion forecast (see Appendix 1) is based on production start-up with six predrilled welIs, another four wells drilled concurrently with production during the year af ter start-up and the final two wells in the year thereafter. The forecast has been phased in accordance with the wells coming on stream. The assumed date of first production start-up is 1/10/1992.

A revisit of the F3 compositional data was carried out leading to an initial reservoir fluid composition based on the measured composition of the F3-6 weIl sample. The weIl fluid composition will change with declining reservoir pressure. Constant volume depletion experiments, computer

simulation- and interpolation teehniques resulted in an expected weIl stream fluid compositions with time. These were used to establish product yields for each seheme.

A comparison of the product yields of each scheme has shown that there are no discernable differences in produot yields between the sehemes. At least 96% of the weIl stream energy can be recovered for sale. The resulting oil and gas forecast, which is valid for each scheme, has also been shown in Appendix 1.

In all schemes C3's and C₄'s are preferentially used as fuel gas, while the

excess (off) gas is flared. No Dutch law requires producers to recover off gas. For the proposed development alternative, no flaring is expected to be required with F3 gas commingled in a joint gas gathering system.

6

-4.4 Development Schemes

This section contains a narrative overview of the schemes considered for the development of the F2/F3/F6 field. For all the schemes, reference is made to Figure 1 below which shows an overview of the geography of the

field in relation to shore and possible product evacuation routes.

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Dedicated F2/F3/F6 Unit schemes were compared in order to establish the best on a Unit owned facilities basis. These are described in sections 4.4.1, 4.4.2 and 4.4.3, whilst an overview listing is given in section 4.4.4.

The most promising schemes were selected for project economics,

incorporating the advantage where appropriate of the opportunities given by tariffs for oil and gas evacuation. These schemes are listed in section

4.4.1

7

-Offshore facilities

Offshore, all schemes consist of a product ion and living quarters platform, bridge linked to a 24 slots wellhead platform. For all schemes the same wellhead platform, bridge and living quarters are used as these are not affected by the different process options. Also the same produetion platform substructure is used for all sehemes since the total production platform topsides weights are not

significantly different for each process option. This is beeause the process plant does not affect major parts of the product ion platform topsides, such as the living quarters, helideck and most of the utilities.

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On the offshore platforms, each scheme has only a differing production platform topsides, the remaining parts of the platforms are similar. A two platform concept has been adopted in line with previous proposals and allows the use of existing data to achieve a reasonably accurate eost comparison.

Costs were generated for several types of offshore process facilities producing different qualities of products, e.g.:

full treatment at the platform to sales speeification of both oil and gas, with separate product evacuation. No onshore treatment is required. (TOTAL TREATMENT).

Offshore treatment of the oil to sales specification, and of the gas to a pipeline transport specification with separate product evacuation. Onshore, further treatment of the gas is required.

(WET GAS, STABLE OIL).

Offshore treatment of the oil to a pipeline transport

specification for non stabilised oil, and of the gas to pipeline transport specification with separate product evacuation.

Onshore treatment of both streams is required. (DRY GAS, VOLATILE OIL).

Note: this offshore process scheme is in broad terms comparable to the Unocal proposed scheme.

Offshore treatment of both oil and gas to pipeline transport specification with commingling of the produets for evacuation through a single pipeline. Onshore treatment of the commingled stream to stabIe oil and sales gas specifieation is required.

4.4.2

8

-Evaeuation Sehemes

For oil evaeuation, the following sehemes have been eonsidered:

An offshore loading system with floating storage unit (FSU) and shuttle tanker, transporting the oil directly from offshore to the refineries. This seheme cannot be implemented for the volatile oil and two phase proeess sehemes.

A pipeline (10" diam., 310 km long) from F3 to Amsterdam (new "greenfield" terminal). Oil transport to the refineries from the terminal by means of small tankers. This route is not an option with the two phase proeess seheme.

Note: This evaeuation seheme was ineluded for eomparison purposes with a proposed tariff seheme for evacuation of the oil via an F3-Q1 line (10" diam., 225 km), to be laid by UOT and onwards via the existing UOT system Q1-Amsterdam.

Evaeuation eommingled with the gas in a single pipeline to an onshore terminal at Eemshaven for onward transportation to the refineries by small tankers.

The feasibility of an oil evaeuation seheme with offshore loading was studied by an outside speeialised consultant. Based on this

eonsultant's adviee, a system using a permanently moored storage tanker with a double elastie wishbone towermooring is proposed. This will provide a system availability similar to that of a

pipeline/onshore terminal seheme. A similar oil evaeuation system was reeently also proposed as an alternative for another Duteh offshore field.

The geographieal loeation of the field is sueh, that the distance to two possible gas delivery points onshore, being Eemshaven or Den Helder, is the same (230 km). Differences in Capital expenditure

therefore only depend on the diameter of sueh a line whieh relates to the product throughput. For all F2/F3/F6 dedicated sehemes, except the two phase seheme, the established pipeline diameter is 16". For the two phase seheme: 18".

4.4.3

4.4.4

9

-Onshore Facilities

The requirement for onshore facilities is depending on the products generated by the offshore process schemes.

For oil, a tankfarm (oil terminal) is required for the Total

Treatment, and StabIe Oi1 schemes (using oil evacuation pipelines) whereas a much more complicated treatment is required for the Volatile Oil scheme. No shore based facilities are required if the oil is

evacuated via an FSU/shuttle tanker system.

For gas treatment an onshore gas treatment plant is required for all process sehemes, except Total Treatment.

For the Two-Phase seheme a combined gas/oil treatment plant is required.

Schemes with Unit owned, dedicated facilities

As described above schemes were identified for the offshore platforms, evacuation routes and onshore facilities. These are summarised in table 1:

10

-Table 1: Unit owned, dedicated facilities schemes

OFFSHORE EVACUATION ONSBORE SCHEME

SCHEME PRODUCTS Gas 011 FAC's REQ'D HR.

TOTAL

TREATMENT -sales gas pipeline to offshore -no treatment 1

-stabIe oil Eemshavenl loading Den Helder

pipeline to -oil terminal 2

Amsterdam -no !Zas plant

WET GAS,l) _{-transportable pipeline to offshore} -gas plant 3

STABLE gas Eemshavenl loading -no oil terminal

OIL -stabIe oil Den Helder pipeline to -gas plant

4 Amsterdam -oil terminal

DRY GAS,I) _{-transportable pipeline to} pipeline to -gas plant

5 VOLATILE

OIL

!WO PRASE

4.4.5

gas Eemshaven/ Amsterdam -oil

stabili--volatile oil Den Helder sation plant

-transportable two phase commingled -combined gast oil/gas pipeline to with the gas oi1 treatment

mixture Eemshaven plant

Notes: 1) Dry gas/wet gas (both transportable pipe1ine gas) difference: dry gas: no

He

liquid drop out in the pipe1ine to shore

6

wet gas: max. 20 m3_/I06 _m3 _{gas He liquid drop out in the pipeline}

to shore

Both gasses still require onshore treatment to sales spec. The dry gas scheme was included for comparison purposes (scheme compatible with Unocal proposal).

2) For schemes where the oil is made availab1e for sa Ie at points other than Rotterdam the scheme inc1udes transport of the oil by tanker to Rotterdam.

Schemes selected for economics

All Unit owned, dedicated faci1ities schemes listed in section 4.4.4 were compared on the basis of total costs. Due to their higher costs, some schemes were rejected for full economic evaluation. This pre-selection is described in section 4.6.

11

-The list of all schemes subjected to economics is shown below (tabIe 2).

Some of the schemes include tariffs, others are Unit owned, dedicated facilities schemes.

Table 2: Schemes subjected to

SCHEME OFFSHORE PR.ODUCTS a)

OFFSHORE -transportable

LOADING (WET gas

GAS, STABLE -stabIe oil OIL)

b)

UOT PIPELINE -transportable

(WET GAS, gas

STABLE OIL) -stabIe oil

c)

!WO PRASE -transportable oH/gas

mixture

d)

TOTAL TREAT- -sales gas

MENT -stabIe oil

4.5 Costs economic comparison EVACUATIOR GAS northern gas system (tariff payment) northern gas system (tariff payment) two phase pipeline to Eemshaven pipeline to Eemshaven/ Den Helder OIL offshore loading UOT oil line (tariff payment) commingled with the gas offshore loading ONSHORE FAC' 8 REQ'D -gas plant (tariff payment) -no oil terminal

-gas plant -oil terminal (both tariff payment) -Combined gas/ oil treatment plant -no tariffs

-no gas treatment -no oil terminal -no tariffs

Capital and Operating expenditures have been established for all the schemes. The basis for these and the estimates in detail are presented in Part 11. A summary is given below.

4.5.1 Cost Basis

The Capital cost estimates for offshore platforms were built up by making use of process equipment lists combined with NAM in-house cost data and unit costs for bulk materiaIs, fabrication, transportation, installation, etc. These unit costs were established from current and

'2/F3/'6

Develol" : nt

Product ion Forecast: Lover Graben Sand

Year 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 Totals Wellhead fluid 0.193 0.847 1.121 1.321 1.321 1.321 1.321 1.310 1.179 0.964 0.796 0.599 0.24 (109 mS) 12.533 Sales Dil (lOs mS ) Sales Gas (l09 mS ) 179.0 693.9 771.1 595.4 526.8 526.9 399.2 269.2 205.5 158.6 119.9 79.1 31.3 4555.9 0.166 0.723 0.989 1.200 1.209 1.209 1.225 1.233 1.112 0.910 0.752 0.567 0.224 11.519 > "Cl "Cl ID ::l

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F2/F3/F6 FIELD DEVELOPMENT

Technica! feaaibl1ity and casts of developaent alternatives.

CORTENTS

1. INTRODUCTION

2. RESERVOIR, WELLS AND DRILLING 1. Introduction

2. Reservoir production 3. Wells and Drilling 3. PRODUCT REQUIREMENTS

" ~. PROCESSING THE F3 WELL EFFLUENT

: , 1. 2. 3. 4. 5. Introduction

Total Treatment (sales specs. oil and gas) Wet gas, stabIe oil

Dry gas, volatile oil Two-phase

5. ENGINEERING SCHEMES 6. PRODUCTS FORECAST

1. Product yields 7. COSTS FOR THE SCHEMES

8. 9. 1. 2. 3. 4. 5. 6. 7. 8. Introduction Methods used

Summary CAPEX and OPEX

Analysis of cost differences Offshore Facilities

Pipelines Onshore Plants

Transportation Costs

WEIGHTS FOR THE OFFSHORE ALTERNATIVES RISKS

1. Introduction 2. Technical Risks 3. Start-up delays

4. Gas sales contract terms

. 10. SCHEDULE 11. REFERENCES

--- - - - -- - - -- - - -- - -- - - -- - - --

-SECTION 1

INTRODUCTION

As a direct result of the oil price collapse in 1986 the F2/F3/F6 field development project. at the time in its initial execution phase. was abandoned. Since that time the future of oil prices has become more clear albeit at a lower level (circa 15 $/bbl) with the industry responding by achieving significant cost reductions for similar developments. A review of the development potential was therefore initiated.

In order to establish the viability of the F2/F3/F6 development in this new economie climate. original concepts and assumptions had to be

abandoned or at least reviewed for their validity today. This process has taken place and the results are presented in the following as /principal concepts which guided the analysis.

~

The reserves

The F2/F3/F6 LGS (Lower Graben Sand) contains recoverable reserves of 12.5 milliard m3 _{wellhead fluid corresponding to produets of 4.5}

million m3 _{oil and 11.5 milliard m}3 _{sales gas. This represents}

157 milliard MJ oil equivalent and 586 milliard MJ gas equivalent. The hydrocarbons present in the LGS are close to their dewpoint.

The market

Although significant quantities of C3's and C4'sare present in the weIl effluent, the market for LPG's is saturated while costs to produce a commercial grade are high. Consequently only 2 products. oil and gas. are aimed for.

Oil produced at the rates forecasted for the F3 LGS, has only one market in the Netherlands: the refinery complexes in the Botlek area near Rotterdam. Access to this area is easiest by tanker. Pipelines to these refineries have. one way or the other, to cross one of the most densely populated regions of Europe.

Gas from the F3 LGS is very high calorific and its Wobbe-index exceeds the H-gas standard.

The gastransporter. Gasunie. has presently various gas accomodation facilities in the Netherlands: enrichment of Groningen-gas takes place near Oldenboorn and in Ommen, N₂-injection facilities are available in Ommen and the major Hical gasroute starts in Spijk running south. In view of all these facilities to accommodate high calorific gas. not available at the time the former F3 development was conceived, no limitation on calorific value of the sales gas was assumed.

Notwithstanding the Wobbe-index exceeding the H-gas standard, the CO2

content exceeds the H-gas export quality limit for CO2 • The fact that

Gasunie presently operates a~ 'off-spec' Hical system. suggests that the CO₂ content of the F3-gas can be accommodated.

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The product ion facilities

A viabIe development scheme for the F3 LGS can, af ter the oilprice collapse of 1986, only be hoped for if concepts are developed and

adhered to that eliminate superfluous expenditures. As argued, there is no incentive to produce other products than gas and oi1. This implies that the process, heart of the production facilities, should be

designed as a very sharp oi1/gas splitter, Traditional series of single stage separators, including some recycle loops, do not meet the

requirement of sharpness of split without undue loss of product. This study introduces therefore a fractionation column as a new and

expenditure reducing element.

An early assessment of availability of the overall product ion facilities concluded that a 95% availability can be achieved with single train production facilities on- and offshore. The single train production facilities concept is therefore adhered to throughout this study.

Analysis of offshore staff requirements concludes that offshore accommodation should be limited to 34 beds.

Transport routes and -modes

By identifying the productmarkets in Botlek (oil) and N.E.-Netherlands (gas) shortest transportation routes can easily be established. In addition to 'shortest routing, the elimination of connecting dissimilar means of transportation will, for the oil stream, eliminate superfluous.

expenditures

The minimum costs for oil can be achieved by transporting the oil product, meeting sales specifications, by tanker from an offshore located (floating) buffer directly to Botlek.

As far as the gas product stream is concerned the validity of the

common oilpatch wisdom 'do the least offshore' was tested: F3 LGS sales gas produced offshore can be injected direct1y in Gasunie's transport system.

The following Sections describe the ana1Y6is of the feasibility and the cost impact of various development alternatives in detail.

SECTION 2

RESERVOIR, WELLS AND DRILLING

1 INTRODUCTION

In th is Section an outline is given of all assumptions in respect of: - expected reservoir fluid production

- number and size of wells

- techniques of drilling the wells

2 RESERVOIR PRODUCTION

A reservoir production forecast has been made for 12 wells drill§d on the Lower

6Graben Sand with wellhead fluid reserves of 12.53 x 10 m

3

(559 x 10 Kmoles) 9n the F2/F3/F6 Lower Graben sand while the small

lOOi. NAM (0.67 x 10 m3

) Upper Graben Sand has been ignored. The forecast, underlying this study is shown in Table 1.

No changes to previous assumptions have been made apart from the introduction of concurrent drilling and production for the last six wells. The forecast has been phased accordingly for the wells coming on stream. Six wells are drilled initially, four more during the following year and the final 2 wells in the year thereafter.

The composition of the well fluid changes throughout the field's life as the reservoir pressure declines. The expected change in fluid composition versus the drop in reservoir pressure was laboratory modelled in constant volume depletion experiments.

For this production forecast the expected yearly wellhead fluid compositions wer extrapolated from these labo ra tory data using the expected average

reservoir pressure during the year in question. The composition is split-up into the product streams using a process simulation of surface facilities. The same wellhead fluid forecast has been used for all alternatives considered. The compositional data set used can be summarised as follows:

Reservoir initial Composition Production Forecast Wellhead Composition Project phase - Start-up

- Start of gas plateau - End of gas plateau - Tail-end of project

Based on measured composition of well F3-6 sample (ref. table 2).

For Lower Graben Sands see table 3.

At 4 reservoir pressures (table 4), with heavy end characterisation as follows:

Reservoir Pressure Composition -Remarks

400 bar Table 5 Peak FTHP's

350 bar Table 6 Peak Production

Min. GOR

160 bar Table 7 Peak Production

Max. GOR

80 bar Table 8 Turn down

YEAR 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 WELLHEAD FLUID (Milliard m3 ) 0.193 0.847 1.121 1.321 1.321 1.321 1.321 1.31 1.179 0.964 0.796 0.599 0.24 TOTAL 12.53

Table 1: F3 Wellhead Fluid Production Forecast

Component mol i. Methane 65.80 Ethane 9.39 Propane 7.05 Iso-butane 1.15 N-butane 2.25 Iso-pentane 0.75 N-pentane 0.95 Hexanes 1.12 Heptanes plus 7.86 Carbon dioxide 3.40 Nitrogen 0.28 TOTAL 100.00 Molecular weight of the C 7

+

fraction 177.00 Molecular weight of

the total effluent 36.10

Table 2: Initial reservoir Fluid Composition LGS (Pressure 399.10 bar abs.)

Reservoir Fluid Production Forecast Production Year 1 (*) 2 3 4 5 6 7 8 9 10 11 12 13 Production (million Kmol) 8.61 37.79 50.01 58.90 58.90 58.90 58.90 58.45 52.60 43.01 35.51 26.72 10.57

*

Production start in October that year. Table 3: Production Forecast F3-FB LGS

Pressure, bar abs. 399.10

Methane , mol% 65.80 Ethane , mol% 9.39 Propane , mol% 7.05 Iso-butane , "mol7. 1.15 N-butane , mol7. 2.25 Iso-pentane , mol7. 0.75 N-pentane , mol% 0.95 Hexanes , molk 1.12

Heptanes plus , mol% 7.86

Carbon dioxide , mol% 3.40

Nitrogen , mol% 0.28 Total , mol%: 100.00 Molecular weight of the C 7+ fraction 2) 177.00 Molecular weight of

the total effluent 3) 36.10

Reservoir Pressure (Bar) 353.10 66.39 9.74 7.17 1.16 2.24 0.75 0.93 1.06 6.67 3.57 0.32 100.00 162.00 33.20 402 375 330 284 249 216 187 163 143 124 105 90 86 158.60 72.66 9.69 6.82 1.04 1.96 0.60 0.73 0.72 1. 73 3.67 0.38 100.00 119.00 24.70

Table 4: ComEosition of the effluent uEon constant-volume of the reservoir fluid at 127°C

1) Gas phase displaced at constant volume.

80.40 70.91 10.51 7.52 1.15 2.16 0.66 0.79 0.76 1.30 3.86 0.38 100.00 111.00 24.70 deEletion

2) Obtained from the molecular weight of the liquid recovered from the effluent; corrected for the pressence of C

7

+

in the gaseous fraction of the effluent. The amount of C

6- in the liquid was neglected.

1)

3) Calculated from the composition of the effluent and the relevant molecular weight of the C₇+ fraction.

C7PLUS V1.0 HEAVY ENDS CHARACTERISATION PROGRAM DATE Time

Tit1e: F3iRESERVOIR PRESSURE

=

399.1 BARA

Option: Program generated components Input specifications: Distribution: Name Molw 1 C7+A 86.8 2 C7+B 106.7 3 C7+C 131.1 4 C7+D 161.1 5 C7+E 197.9 6 C7+F 243.0 7 C7+G 298.3 8 C7+H 366.1 9 C7+I 448.9 10 C7+J 602.2 Table 5: Start-up molar flow of C7+

₌

ave rage mol.weight =

average spec. gravity =

number of components

=

distribution parameter

=

lower limit mol.weight

=

lower limit spec.grav.

=

7.8600 177.00 0.8200 10 Mole Spgr Fraction 0.714 0.166123 0.748 0.166982 0.775 0.160263 0.799 0.145327 0.823 0.122916 0.847 0.095446 0.872 0.066744 0.898 0.041051 0.926 0.021579 0.970 0.013570 Molar Flow 1. 306 1. 312 1.260 1.142 0.9661 0.7502 0.5246 0.3227 0.1696 0.1067 1. 0000 78.11 0.6640 0/00/00 00:00:00

C7PLUS Vl.0 _{HEAVY ENDS CHARACTERISATION PROGRAM DATE} Time

Title: F3;RESERVOIR PRESSURE = 353.1 BARA

Option: Program generated components Input specifications: Distribution: Name Molw 1 C7+A 86.4 2 C7+B 105.2 3 C7+C 128.2 4 C7+D 156.1 5 C7+E 190.0 6 C7+F 231.2 7 C7+G 281. 3 8 C7+H 342.1 9 C7+I 415.9 10 C7+J 548.3 molar flow of C7+

₌

average mol.weight

=

average spec. gravity

=

number of components =

distribution parameter =

lower limit mol.weight

=

lower limit spec.grav.

=

6.6700 162.00 0.8100 10 Mole Spgr Fraction 0.711 0.184509 0.746 0.179525 0.773 0.166295 0.797 0.145095 0.821 0.117712 0.846 0.087410 0.871 0.058293 0.897 0.034117 0.925 0.017043 0.968 0.010000 Molar Flow 1.231 1.197 1.109 0.9678 0.7851 0.5830 0.3888 0.2276 0.1137 1. 0000 78.11 0.6640 O.6670E-Ol

Table 6: Start of gas plateau

0/00/00 00:00:00

C7PLUS Vl.0 HEAVY ENDS CHARACTERISA~ION PROGRAM DATE Time

Title: F3:RESERVOIR PRESSURE = 158.6 BARA

Option: Program generated components Input specifications:

m~lar flow of C7+

₌

1. 7300

average mol.weight = 119.00

average spec. gravity

=

0.7700

number of components

=

10

distribution parameter

=

1.0000

lower limit mol.weight

=

78.11

lower limit spec.grav.

=

0.6640

Distribution:

Mole Molar

Name Molw Spgr Fraction Flow

1 C7+A 83.5 0.695 0.243462 0.4212 2 C7+B 95.7 0.726 0.207043 0.3582 3 C7+C 109.6 0.752 0.168592 0.2917 4 C7+D 125.6 0.777 0.130626 0.2260 5 C7+E 143.8 0.801 0.095613 0.1654 6 C7+F 164.7 0.825 0.065574 0.1134 7 C7+G 188.6 0.850 0.041744 0.7222E-Ol 8 C7+H n5.9 0.876 0.024403 0.4222E-Ol 9 C7+I 247.1 0.904 0.012941 0.2239E-01 10 C7+J 307.3 0.952 0.010000

o

.1730E-Ol

Table 7: End of gas plateau

0/00/00 00:00:00

C7PLUS Vl.0 HEAVY ENDS CHARACTERISATION PROGRAM DATE Time

Title: F3;RESERVOIR PRESSURE = 80.4 BARA

Option: Program generated components Input specifications: Distribution: Name Mo1w 1 C7+A 82.8 ~ C7+B 93.3

..

3 C7+C 105.2 4 C7+D 118.5 5 C7+E 133.5 6 C7+F 150.4 7 C7+G 169.4 8 C7+H 190.8 9 C7+I 214.9 10 C7+J 262.5 mo1ar flow of C7+

=

average mo1.weight

=

average spec. gravity

=

number of components

=

distribution parameter

=

lower limit mo1.weight

=

lower limit spec.grav.

=

1.3000 111. 00 0.7600 10 1.0000 78.11 0.6640 Mo1e Mo1ar Spgr Fraction Flow 0.691 0.260830 0.3391 0.722 0.213413 0.2774 0.747 0.167663 0.2180 0.771 0.125829 0.1636 0.795 0.089690 0.1166 0.819 0.060326 0.7842E-Ol 0.844 0.038009 0.4941E-Ol 0.870 0.022250 0.2892E-Ol 0.897 0.011990 0.1559E-Ol 0.946 0.010000

o

.1300E-Ol

Table 8: Tail-end of project

0/00/00 00:00:00

3 WELLS AND DRILLING

For the 12 weIl development of the F2/F3/F6 field (UGS not included) a jack-up rig will be used for drilling and future workover operations. Permanent kill facilities are not considered necessary on the F3 platforms.

In view of the waterdepth of 43 meters (LAT) and the environmental conditions at F3, a jack-up of the Neddrill IV class or similar will be needed for year round drilling.

For this study, the use of the Neddrill IV is assumed throughout. Significant reduction in drilling eost and time are expected due to: - a reduction in the contract rate for the Neddrill IV of

Dfl 35.000,-/day agreed for the years 1987-1989. For later years a reduction of Dfl 15.000,-/day is still expected. Furthermore the costs of drilling materials in general have fallen.

- State-of-the-art drilling techniques (better bits, mud moters, use of oil based mud, etc.) will be used, resulting in more effieient

drilling and hence in reduction of drilling time.

- A low eost easing scheme with straight conductors has been designed: maxi~um 18 7/8 inch casing.

Estimated total drilling time is therefore now 870 days for 12 wells (contingency wells excluded).

SECTION 3

PRODUCT REQUIREMEHTS

1 INTRODUCTION

2 2.1

All production and evacuation schemes analysed aim at producing two sales products:

- (light) hydrocarbon oil, - gas.

The schemes differ mainly in respect of the location (off- or onshore) where the sales point specifications are to be met. This leads to the

introduction of requirements for intermediate products in order to ensure a firm basis for comparison. Besides a description of the weIl known sales point specifications for oil and gas, this section reports on requirements set for transportation of intermediate products.

~

,

t.A

, .. ;l SALES PRODUCT SPECIFICATIONS

Sales Gas Specification: - Delivery pressure

- Delivery temperature 40°C max. O°C min.

- water dewpoint _~

Hydrocarbon liquid

-8°C at delivery pressure 5 mg/m3 _{max above -3°C at}

below delivery pressure no limit

all pressures \ ~~ ">:

. ) ,..,v" .

- CO2 content

- Gross Heating value - Wobbe number

following for each concept following for each concept 2.2 Refinery Specification for Sales Oil:

- Reid Vapour Pressure - Water content

- Salt content

12 psi

0.5 vol % max. 100 ppm. 3 ADDITIONAL SPECIFICATIONS PER CONCEPT 3.1 Two-phase pipeline concept

3.1.1 Transportation specification

Temperature max. inlet 60°C

O°C

•

Quality min. ambient Water dewpoint-gas Water content-oil

-5°C at max. pipeline press. 100 ppm. max.

(*).

3.1.2 Onshore oil storage and loading requirements (transportation by ship). - 2 X 13500 m3 floating roof tanks giving 9 to 10 days storage at peak

rate.

- Transfer pump to marine loading facilities - capacity 280 dm3_/s. - Ballast water tank: 4370 m3

• 3.2 Volatile Oil/Dry gas concept 3.2.1 Transportation Specification: Gas

Temperature Quality .. max. inlet min. ambient Water dewpoint Hydrocarbon dewpoint: 60°C O°C

-5°C at pipeline inlet pressure. no liquid drop-out in the

pipeline. 3.2.2 Transportation Specification: Volatile oil

Temperature Pressure Quality max. inlet min. ambient min. operating no hydrate formation at 40 barg and 4 °c cloud point water content 60°C 2°C

vapour pressure of oil ex platform.

2°C

'*

100 ppm • max. or min. velocity 1 mis. Notes: (*) Water to remain dissolved at min. temperature. 3.3 StabIe oil/transportable gas concept

3.3.1 Transportation Specification: Gas Temperature Quality max. inlet min. ambient Water dewpoint Hydrocarbon dewpoint: 60°C O°C

-5°C at gipeline inlet pressure. 20 m3_{/10 m}3 _max.

3.3.2 Transportation Specification:Oil via pipeline Temperature

Quality

max. inlet min. ambient

Reid Vapour Pressure: Water content Cloud point 20°C 2°C 12 psi max. ** 0.5 vol % max 2°C

3.3.3 Transportation Specification: Oil to offshore Loading As per oil sales specification.

3.4 Stable Oil/Sales Specification Gas produced offshore (Evacuation via pipeline or offshore loading).

3.4.1 Transportation Specification: Gas

As per sales Specification - Section 2.1 - except temperature ex. platform 60°C.

3.4.2 Transportation Specification: Oil As sections 3.3.2, 3.3.3.

**

Relaxed during the study when the corrosivity of the oil was better defined.

SECTION 4

PROCESSING mE F3 WELL EFFLUENT

1 INTRODUCTION

Schemes for transporting sales q~ality produets or intermediate

produets from the offshore platform to a shore terminal are analysed by full process simulation of the equipment and the pipelines. All schemes were optimised within the requirements of the overall comparative

study: first order trade-offs were implemented. This means that in subsequent design studies further economies could be achieved. All process simulations were carried-out with the Sim-Sci 'PROCESS' package.

Hydrate expectency predictions and requirements for hydra te suppression were based on SIPM's 'HERCULES' package. This uses a five phase flash algorithm to determine the equilibrium situation between gas,

condensate liquid, aqueous liquid and two different hydrate modifications.

Pipeline hydraulics were determined by SIPM's '!WO PRASE' package, which uses methods developed by KSLA for steady-state two-phase anrl single phase flow in hilly terrain pipelines with heat transfer to and from the environment.

The following contains a brief description and flow schematic of the process plant(s) involved in each scheme studied. A glossary of the equipment tags used is included.

2 TOTAL TREA~mNT

Overview: All treating is performed on the offshore platform. Gas production is water and hydrocarbon dewpointed to sales specification and th en compressed for export. Liquid production is stabilised to 12 RVP and loaded into a

floating storage tanker (FSU). Intermediate condensates are treated in a fract10nation column to produce a 12 RVP liquid for sale, a fuelgas side stream and a gas stream to flare or for further treatment.

Wellstream fluids are separated in a production separator operating at 95 bara, nominally the upper limit of ANSI 600 class piping. Liquid production is stabilised to 12 RVP by 2 stages of flash separation: first at 15 bar a then at 1.2 bara. No heating is required. The liquid is then pumped to a floating storage tanker. These 2 separators are designed as 3 phase FWKO separators to remove bulk water. No deep water removal is required. Flash gas, recompressed by screw and the

reciprocating compressors, together with the bulk ga production, is water dewpointed to _8°C. Hydro~bon dewp~. ng to -3°C is

achieved by autorefrigeration at (5°bLand-Yz-bara in an LTS separator prior to export compression at 120 bara.

Condensed liquids from the LTS separator, recompression train scrubbers and dehydration prescrubber are fed into a fractionation column. Here a sharp component split is performed to minimise the quantity of

intermediate components (C

3, C4) that cannot be accommodated in the two product streams. This stream is used for fuel. Stable 12 RVP liquid is produced directly to the FSU and a 'wet' gas top product is recycled via the recompression train.

When wellhead pressures fall below 95 bara, it is allowed to follow down to 80 bara in order to delay booster compression. Once this

pressure is reached, the product ion pressure is dropped to 50 bara and booster compression to 80 bara started.

WELLS 1", I

"

r-

-

--I BK ; I . / ...1-- --r I I

,"'"

\ 1 , - - - '

I H

AIR6 f---- -156 I L _ _ _ _ J I 1/:""><::) \ )

'

r

I I I I I

I

1 I I SEP 54 I I

L _______

-1

F 3 _ PROCESS FLOWSCHEME

:

SALES GAS AND STABLE OIL

.---___

j~K

~ ,. SALES GAS HE L ----I~.FUEL GAS SI ...,14__.----, W • ~ STABLE L -_ _ _ _ _ _ _ ~, ~ OIL

w

P_l

3 WET GAS, STABLE OlL

Overview: The offshore process is exactly the same as for the 'Total Treatment' scheme, except that the gas is hydrocarbon dewpointed to the less stringent pipeline transport specification. Thus an onshore gas plant is required to complete dewpointing down to sales gas quality.

A 12 RVP liquid is also produced.

LTS pressure is higher than for total treatment and hence export compression power is lower. Due to the higher capacity for heavy components in the gas stream less fuel gas is produced by the fractionation column.

The wet gas P50duction arrives onshore containing no more than 20 mS liquid per 10 mS gas. Gas and liquid are separated in a horizontal K.O. vessel (slugcatcher).

The gas is cooled to about -5°C by external refrigeration to meet sales gas hydrocarbon dewpoint specification, before being exported at about 70 bara.

Liquid from the LTS and slugcatcher are heated by a hot oi1 exchanger and then flashed at 35 bara and 5°C prior to fractionation at 20 bara. A 12 RVP 1iquid is produced and gas produets are compressed and

WELLS 1" ... I ... , I BK

r

-

-

-

-I ~J r _{Y //} I I

,

...

,

I I r -IS6

rL~R

6

-

1--

-

-

-I ___ J

\, )C __ ..

~.:::::) r I

I

_I I

I

I

I I SEP

l--_____

J

F 3 _ P ROCESS FlOWSCHEMl

WET GAS AND STABlE Oll

HU

W

EXK r----I .. ~ WET GAS

c::><::) LTS J.T 2°(,62 BARA - - - -... FUEL GAS S 1 ... 1-41----... OS 2 , .. STABlE '---~,~

'i

OIL W P_1

r-

.

-1

AIR (

~

'

-c}

'

ï

I C><J

I

I FREON I' • COHp ·

L

.

_

.

_

.

_

.

,

!

I..---Ï

1 - - - - < _{' )} i _{I ~I} !(DNO

i

~._._._ . .J

t-

.

-i

I

i

i I

i

i

r -• . 11\ A I i

i

_{L._}

_.

_~J

_.~._._. t'-lT.

i

i

i

F 3 - PRO (ESS FLOW SCHEME .

WET GAS ANO STABLE OIL

&

VOLATILE Ol L, ONSHORE GAS PLANT

SALES GAS

I

I

•

L

.

_

.

1

i

!

I

i

i

I j FUEl - - - 1 •• GAS

'

LSTABLE

Dil

4 DRY GAS, VOLATILE DIL

Overview: Gas production is treated to a simi1ar degree as the 'Wet Gas, Stab1e Dil' scheme and hence has the same onshore gas plant.

Liquids are stabilised to 51 RVP maximum and pumped to shore. An onshore oil plant stabilizes the liquid in a single fractionation column with the gas used for fuel. Due to the wider component range for both products there is no problem with unfittable components and so no need for offshore fractionation. All liquids are stabi1ised in 2 preheated flash separators at 30 bara and 5 bara, to produce a 51 RVP product. This volatility limit is dictated by the need to keep outside the hydrate forming zone.

The onshore gas plant is identical to that for the 'Wet Gas, Stable Dil' scheme.

Vo1atile oil arrives onshore at a separate location to the onshore gas plant. Pipeline pressure is maintained above the bubb1e point,

therefore no gas breakout occurs. The liquid is pumped from a surge vessel into a fractionation column at 10 bara which produces a 12 RVP product and a fuel gas stream.

Note: During the development of this alternative two additional constraints were identified (ref.: 11.6, 11.7):

- Potential hydrate formation in the vo1atile oi1 1ine and - Potential internal corrosion in the same line.

As solution to both 'deep' water removal by gas stripping was introduced, but is not shown on the flow schema tic.

F3-PROCESS FLOWSCHEME

:

VOLA TILE OIL

OYHO. I \ I ~

f'"

~--

~

--~WHK~ C><)

r

,

__

1,--I

I

"L

r

L-

-[AII~-S}--~ ' Cl _ _ ; :

r~r

I :..: I _XI (::'--J C><) I ~I \ I

l

I

I

I

I

W

=t~

I

I

I

I

\'1ELLS

L _____

~x

_'1

W

I

IPK 1 F ' - ' AIR 4 C>-<> SALES GAS FUEL GAS .. STABLE Oll

,

'

-1

AIR (

r·-cJ·,

I C>-<) i FREON • _{L ._ ._ ._ . ..,} (OHP.

i

!(ONO ~I

F 3 - PRO (ESS flOW SCHEME

_

WET GAS

MlO STABlE Oll & VOlATllE Oll,

ONSHORE GAS PLANT

SALES GAS ,-. _______ .J

_t-

_.

_{- ,._}

_.

_{_}

_{.-._}

_-

_{_}

_.

_{_--}

_-

_-

_,

_-

_-

_-

_'

_-

_'

_-

_-

₁

i

!

I

i

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i

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I i I

!

~T

L._·-

·

~

·

-·-

·

r-

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.J

H . ,

i

i

i

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L. _

_

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i FUEL ---t.~ GAS STABLE OIL

5 !WO PRASE

Overview: The offshore process is required solely to remove sufficient water from both gas and liquid phases in order to prevent pipeline corrosion. The onshore plant performs essentially the same duty as the Total Treatment scheme except that hydrocarbon dewpointing is by external refrigeration.

Af ter primary separation at 95 bara the gas stream is water dewpointed to -5°C in a glycol contactor and thereafter compressed for export. No af ter cooler is required. due to the low compression duty. The liquid stream has bulk water removed in an oil/water split flow platepack separator.

Deep water removal to 100 ppm is achieved in a gas stripping column. Dry liquid and dry gas are combined in the same pipeline.

The two phase stream is received onshore in a finger type slugcatcher (700 m3_{) . Liquid production is stabilised to 12 RVP in two preheated} flash separators at 15 bara and 3 bara. Sales gas quality is achieved by external refrigeration to

_BoC.

This is more severe than the -5°C required for hydrocarbon dewpointing in order to meet the water content specification. A glycol injection and recovery package is required to prevent hydrate formation in the LTS separator.

As in the previous stabIe oil schemes. intermediate condensates are treated via a fractionation column.

UJ L UJ I w Vl ~ o -J u.. Vl . Vl UJ UJVl w<t O I era.. a.. 0 ""';3 u..'-UJ V'I <3 :r_o 0....1 0 ....

~~---,

r-Ll n

I I \/ I ,...., I X IUJI" L..T...J \.)

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/'4---I ~\ / ,...., \ / I....J \ J:---~ I I I I .- ____ .... L __ -( ;;

r-,

~--_______ ~_-__ ~ -~ 1

~

,1~,....,

t---..jo.

... I

I

0. ~ ___ I ____ L -________________ ~

L ___________ _

V'I >--- ~ 3 N >

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1 - 1 I' '< ~ \ , IIa.. ... , ... J

,

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E11

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L._

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E2 ~Vl E5

F 3_PROCESS FLOW SCHEME:

TWO PHASE,ONSHORE PLANT

fGl~(OL - '....Hor OIL

I

REGEN'N

I ..

PACKAGE I --~ C > < ) ~IV5 P1

En

V11 STABLE OIL FUEL GAS

EQUIPMENT GLOSSARY

EQUIPMENT SALES GAS WET GAS VOLATILE OIL TWO PHASE

OFFSHORE OFFSHORE OFFSHORE OIL PLANT GAS PLANT OFFSHORE ONSHORE

1 Primary separator SEP SEP WHSP VI VI

2 Glycol contactor DEHYD DEIIYD DYHD V3

3 Glycol/condensate separator V4 Vl2

4 Low temperature separator LTS LTS LTS SEP V2

5 Joule Thompson valve J.T J.T J.T J.T

6 Process Air Cooler AIR4,AIR6 AIR4,AIR6 AIR3,AIR5 COIL El E6

7 Export Compressor EXK EXK EXKl C2

8 Compressor Suction Scrubber Sl,S2,S3,S4 Sl,S2,S3,S4 IPKO,HPKO V6,V7 V5,V6,V7

S6 S6 WHKO V8

9 Compressor Aftercooler AIR1,AIR2 AIR1,AIR2 AIRl,AIR2 AIRI E3 E7,E8,E9

AIR3,AIR5 AIR3,AIR5

10 Offgas Compressor LPK1,LPK2 LPK1,LPK2 LPK1,IPK1 OFC1,OFC2 Kl,K2,K3

IPK1,IPK2 IPK1,IPK2

11 Booster Compressor BK BK HPKI C3

12 Export Pump PI PI P2

13 Process Pump PUMP Pl,P3,P4 Pl,P2

14 Hot oil preheater SlHX,S2HX STBH E15,E4,E5

15 Process heatexchanger HEI, HE2 HE1,HE2 GGX PRHX GGX EI,E3,E14

16 Stabilisation Flash Separator OS1,OS2 OS1,OS2 STGI,STG2 STB1 V3,V4

17 Fractionation Column FRAC FRAC COL COL VIl

18 Column Feed Drum DRUM DRUM VlO

19 Reboiler REB E12

20 Condenser CCON E13

21 Stripping Column \75

22 Gas Blower Cl

23 Water/Condensate Separator V2

24 Freon Compressor FREON COMP K4

25 Freon Air Cooler AIR ElI

26 Freon Condenser COND EIO

27 Freon Chiller CHIL E2

SECTION 5

ENGINEERING SCHEKES

1 INTRODUCTION

Process studies (ref. Section 6) have proved that the energy yields of various process options for F3 are the same. For the same availability of process plant, the income from hydrocarbon produets consequently is a1so the same for each scheme.

Engineering efforts therefore concentrated on the lowest cost schemes, with each scheme delivering separate, marketab1e oil and gas streams as outlined previously (Figure 1).

In order to fully eva1uate the differences between the engineering schemes, firstly concepts with Unit owned, dedicated, evacuation routes to the sel1ing points (Rotterdam area for oi1 and the N.E or N.W. of the Netherlands for gas) are considered.

The alternatives comprise cases whereby oil and/or gasstreams are going into common gathering systems owned by others for which tariffs are paid by the Unit.

All process facilities have been sized to accommodate the peak

production from the LGS reservoir. The additional product ion from the UGS reservoir is not expected to have any significant inf1uence on the process faci1ities.

All gas processing facilities have a capacity of 3.5 all oil production facilities have a capacity of 3.5 Further details of the process schemes are presented section. 6 x 10 3 m 3_{/day and} x 10 m3_/day. in the previous

Contrary to the original two-phase concept, none of the new schemes include provisions for the production of LPG nor any CO2 removal

facilities. To minimise costs single train concepts with adequate plant availability have been considered.

All pipelines are carbon steel. In view of the lengths being in excess of 200 km, the use of stainless steel pipelines would incur such large cost increases that these could not be offset by the reduction in

process facilities offshore. Hence stainless steel pipelines are ~ further considered.

2 DESCRIPTION OF THE ENGINEERING SCHEMES 2.1 General Description

In line ~~th the previous NAM two-phase concept all engineering schemes consist of a production and living quarters platform, bridge linked to a 24 slot wellhead platform (Figure 2).

For all schemes the same wellhead platform, bridge and living quarters are used as these are not affected by the different process options.

Also the same product ion platform substructure is used for all schemes: it appeared that the total product ion platform topsides weights are not significantly different for each process option. This is due to the fact that the process plant does not affect major parts of the

product ion platform topsides, such as the living quarters, helideck and most of tne utilities (platform crane, F&S, etc.). The influence of the

resulting process plant differences on the production jacket is

marginal in the context of the overall cost comparisons.

For each engineering seheme only the production platform topsides, the evacuation routes and the onshore plants (where required) are different. The two platform concept has been adopted in line with previous

proposals and allows the use of existing data to achieve a reasonably accurate cost comparison.

2.2 Wellhead Platform

The wellhead platform configuration is based on Unocals proposal for the development of the F2/F3/F6 field. In line with the existing field development plan, it allows drilling of up to 24 wells by a cantilever jack-up type of drilling riga

The wellhead deck is a six legged structure constructed with two bays, each containing 12 conductors slots. The two bays are separated by a fire wall. Although the present drilling schedule is based on

consecutive drilling of the 12 wells needed for the LGS, it may be possible to use two cantilever jack-up rigs simultaneously to drill these welIs.

Workover will be do ne using a jack-up riga No permanent weIl kill facilities are foreseen on this wellhead platform other than a connection for each individual weIl enabling the use of the jack-up kill -facilities.

A crane is positioned on the centre deck leg located at platform's North in order to allow continuous operation regardless of drilling or workover activities.

The deck carries two manifolds only.

The resulting total dry weight of the wellhead deck and equipment is 800 tonnes and has an operating weight of 850 tonnes.

The wellhead jacket, originally designed as a launch jacket as it could not be lifted by the previous generation heavy lift barges, would today be liftable. This concept, proposed by Unocal, is also adopted for this study and the same wellhead jacket configuration is used: a six legged jacket with four horizontal framing levels (Fig. 3). The dry weight of the jacket and piles is 4000 tonnes.