economics of gas gathering and processing in the...

P: \WK_AREA\REPT_BK\OLDRBS\CONV\RB97_034.DOCECONOMICS OF GAS GATHERING AND PROCESSING IN THE COOPER BASIN

RICHARD MCDONOUGH

ECONOMICS OF GASGATHERING AND PROCESSING

IN THE COOPER BASIN

Richard McDonough

Revised VersionJuly 1997

(Original Version Released July 1996)

PETROLEUM DIVISIONSA Department of Mines and Energy Resources191 Greenhill RdPO Box 151Eastwood SA 5063

Telephone: National (08) 8274 7680International +61 8 8274 7680

Facsimile: National (08) 8373 3269International +61 8 8373 3269

Web Page http://www.mines.sa.gov.au/petrol/index.html

Report Book 97/34SR 28/1/202/1

Front Cover: Aerial View of Cooper Basin Gas Satellite (MESA Photo 043790)Ian Oswald-Jacobs Aerial Photography, Apsley, Victoria 3319

E C O N O M I C S O F G A S G A T H E R I N G A N D P R O C E S S I N G I N T H E C O O P E R B A S I NR E V I S E D V E R S I O N J U L Y 1 9 9 7 ( O R I G I N A L L Y R E L E A S E D J U L Y 1 9 9 6 )P E T R O L E U M D I V I S I O N , M I N E S A N D E N E R G Y S AP R I N T E D 1 / 0 4 / 9 9

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TABLE OF CONTENTS

TABLE OF CONTENTS iLIST OF TABLES iLIST OF FIGURES iLIST OF APPENDICES iiSUMMARY 1INTRODUCTION 3DISCUSSION 4

Study Overview 4Existing Facilities Toll Calculation 4Methodology 5Results 7USA Practices 9

ACKNOWLEDGMENTS 10REFERENCES 11

LIST OF TABLES

1. Summary of Results for Field 50 km from Moomba - Original Gas in Place

2. Summary of Results for Field 50 km from Moomba - Recoverable Raw Gas

3. Summary of Results for Field 50 km from Moomba - Recoverable Sales Gas

4. Comparison of Stand-Alone and Facilities access

LIST OF FIGURES

1. South Australian Petroleum Production and Pipeline Licences

2. Small Gas Fields Development Study, Processing Options

3. Oil and Gas Fields of the Cooper and Eromanga Basins, South Australia

3a. Schematic of Limiting Field Sizes under Various Composition and ProcessingScenarios (assumes 10% OGIP depletion rate).

4. Single Field, Stand-Alone Facilities, No LPG Recovery, (max depletion rate = 5% ofOGIP/yr)

5. Single Field, Stand-Alone Facilities, No LPG Recovery, (max depletion rate = 10%of OGIP/yr)

6. Single Field, Stand-Alone Facilities, LPG Recovered at Port Bonython, (maxdepletion rate = 5% of OGIP/yr)

7. Multiple Field, Stand-Alone Facilities, No LPG Recovery

8. Multiple Field, Stand-Alone Facilities, LPG Recovered at Port Bonython

9. Single Field, access to Existing Facilities @ $600/mmscf raw gas




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14. Single Field, access to Existing Facilities @ $1000/mmscf raw gas (max fielddepletion rate = 10% of OGIP/yr)



17. Multiple Field, access to Existing Facilities @ $600/mmscf raw gas





LIST OF APPENDICES

1. GPA Report “Cooper Basin Gas Field Development Study” - updated version, March1996.

2. Addendum to “Cooper Basin Gas Field Development Study” - Additional data forStand-Alone LPG removal.

3. MESA Memo “Economics of Stand-Alone LPG Recovery for Small Fields”. - RichardMcDonough, 14 May 1996.

4. GPA Report “Moomba and Port Bonython Replacement Study” - January 1996.

5. MESA Memo “Moomba / Pt Bonython Processing Tolls based on Deprival ValueApproach - Update”. - Richard McDonough, 24 May 1996.

6. Example Cashflow Table

7. Purvin & Gertz Report “Gathering and Processing Practices in the Permian Basin”(USA) - June 1996


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SUMMARY

The Petroleum Division of Mines and Energy South Australia (MESA) engaged GPAEngineering to provide cost estimates to feasibility study level for processing andtransporting products from new gas discoveries in the Cooper Basin (Figure 1), both on astand-alone basis and assuming access to current facilities.

The results have been used by MESA to generate cash flow analyses for a number ofcases in order to develop minimum economic field sizes for the different developmentoptions. These include developing stand-alone facilities (which are independent fromexisting infrastructure), and tolling through existing facilities.

It should be noted that the study does not necessarily imply that spare capacity isavailable at existing facilities. However, the study does provide an indication of the likelylimits of negotiated tariffs where capacity is made available. If plant capacity is available,the negotiated toll will fall between the marginal cost (when there is plenty of sparecapacity) and the deprival value cost (when there is minimal spare capacity).

MESA chose the deprival value approach as the basis for calculating maximum tariffs,not because it is necessarily MESA’s preferred approach, but rather because it has astrong theoretical basis and places a ceiling above which tariffs are unlikely to extend.Minimum tariffs were calculated on the basis of marginal (operating) costs.

• A reasonable toll based on deprival value (“replacement” cost) for access to existingCooper Basin facilities (ie. satellite / trunkline / Moomba Plant / Liquids Pipeline / PortBonython Plant) is estimated to be in the range $1200-$1700/mmscf of raw gasprocessed. A marginal cost toll (equal to operating costs estimated in GPA 1996c5) isestimated to be of the order of $380/mmscf of raw gas processed.

• The cost of processing liquids through the Liquids Pipeline and Port Bonython facilitiesalone, calculated using the deprival value approach, is estimated to vary between $65-$80/m3 ($10.30-$12.70/bbl)

• Assuming a toll in the deprival value range, it is always more economic to access theexisting facilities than build stand-alone facilities for the range of field sizes studied (upto 80 bcf recoverable). The corollary of this is that if facilities access is provided,smaller discoveries are economic. This conclusion is entirely to be expected, aseconomies of scale dictate that larger plants will always be more economic if they arefully utilised

• If existing facilities access is provided on the above basis, liquids rich fields withrecoverable raw gas exceeding 4-8 bcf will be economic, (if situated within 20 km ofexisting satellites, which are assumed to be 50 km from Moomba).

• If stand-alone facilities are used to develop a field, liquids rich fields with recoverableraw gas exceeding 10-15 bcf will be economic, (if situated within 50 km of a sales gaspipeline).

• The minimum economic field size with access to existing facilities is typically at leasthalf of the minimum economic field size for stand-alone facilities, (assuming similarprocessing requirements).

• Access to current facilities is more desirable on economic, resource conservation andenvironmental grounds. For liquids-rich fields with an Original Gas-in-Place (OGIP)as large as 35 bcf (Recoverable Gas-in-Place (RGIP) approx. 25 bcf), it isuneconomic to develop fields on a stand-alone basis unless LPGs are flared.However, if facilities access is provided, the economics of the development aresignificantly improved and LPGs are recovered.

• The economic viability of any discovery is highly dependent on the CO2 and liquidscontent of the raw gas stream. Fields rich in liquids and low in CO2 are the most


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economically attractive. The minimum economic field size increases by a factor asmuch as four if the raw gas composition is high in CO2 and low in liquids.

A copy of all financial data provided in this report is available from MESA in Quattro Profor Windows spreadsheet format. Other organizations can therefore use these data tocalculate minimum economic field size using their own cost data if desired.


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INTRODUCTION

In 1995, the Petroleum Division of MESA undertook to investigate the options for thedevelopment of new discoveries in the Cooper Basin (Figure 1) by parties independent ofthe current Cooper Basin Joint Venture.

The purpose of the study was two-fold:

1. To provide indicative costings for the benefit of prospective explorers when theCooper Basin Petroleum Exploration Licences 5 and 6 expire in 1999.

2. To provide information on the cost of gas field developments for the current debate onthe de-regulation of the gas industry and access to essential facilities.

GPA Engineering (GPA) were engaged to provide cost estimates for a number ofscenarios, upon which the MESA study is based. GPA were chosen for theirconsiderable practical experience in developing similar facilities for fields such asKatnook (SA) and Beharra Springs (WA), and their general experience in the CooperBasin.

Costs were provided to feasibility study level for the following development scenarios:

• Gas field development totally independent of the current processing facilities.

• Gas field development with access to the Liquids Pipeline and Port Bonython facilitiesonly, (ie. excluding the Moomba Plant and satellite facilities).

GPA based their studies on gas field production profiles provided by MESA, whichaccounted for field size, deliverability, raw gas composition and distance from the head ofthe Moomba-Adelaide and Moomba-Sydney gas pipelines

GPA were also asked to provide costs for the replacement of the existing facilities(satellite, trunkline, Moomba Plant, Liquids Pipeline and Port Bonython facility), based oncurrent technology.

The results of these studies have been used to provide the estimates of:

• Indicative tolling costs through the existing facilities using the deprival value approach,(ie. replacement cost using modern technology and future estimated throughputs).

• Minimum economic field size based on either stand-alone development or access toexisting facilities.

This revised version updates the original version released in July 1996, by correctingsome minor inconsistencies. The original version quoted the minimum economic fieldsize for stand-alone development as being 35 bcf (RGIP). This value applies to a rich-liquids, high CO2 field. For a rich-liquids low CO2 field, the minimum economic field sizeis 25 bcf (RGIP). Some minor revisions to the table in the Results section have beenmade and Figure 3a has been updated.


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DISCUSSION

Study Overview

This study is an update of the previous study entitled “Cooper Basin Gas FieldDevelopment Study - Results” (McDonough 1996a1). McDonough (1996a1) estimated theminimum economic field size (expressed in terms of OGIP) if Cooper Basin gas fieldswere developed on a stand-alone basis.

Since that time, an updated version of the GPA report “Cooper Basin Gas Field2, Appendix 1) has been produced.

GPA were also engaged to review the cost of developing stand-alone facilities whichrecover LPGs:

1. In the first case, the total liquids stream (LPG and condensate) are transported to thehead of the Liquids Pipeline (from Moomba to Port Bonython) and processed throughPort Bonython, (see Figure 2(2)). The study “Cooper Basin Gas Field DevelopmentStudy - Addendum No 1” (GPA 1996b3, Appendix 2) forms an addendum to GPA1996a2.

2. In the second case, stand-alone facilities include load-out facilities for propane, butaneand condensate, which are then trucked to Adelaide (see GPA 1996b3, Appendix 2,also Figure 2(3)). This case is totally independent of existing facilities, (ie. tollingthrough Liquids Pipeline/Port Bonython is not required). The results arising from thisstudy form Appendix 3 “Economics of Stand-Alone LPG Recovery for Small Fields”,(McDonough 1996b4).

The results of the GPA study “Moomba and Port Bonython Replacement Study” (GPA1996c5, Appendix 4) have been used to develop indicative tolling costs through theexisting facilities, based on the deprival value approach, (see “Moomba / Pt BonythonProcessing Tolls based on Deprival Value Approach - Update”, McDonough 1996c6,Appendix 5). These results have been used to estimate the minimum economic field sizeif there is access to the existing facilities.

The current report synthesizes the results of all these studies. This revised version datedJuly 1997 tidies up some minor inconsistencies in the July 1996 version.

Existing Facilities Toll Calculation

GPA Engineering were engaged to develop cost estimates for facilities to replace theprocessing capability of existing facilities to feasibility study level. The results arepresented in GPA 1996c5, (Appendix 4).

The results of the GPA study have been used to develop tolling costs through existingfacilities, (McDonough 1996c6, Appendix 5). The toll calculation is based on the deprivalvalue concept, in which the cost of constructing new facilities to provide the sameprocessing service is estimated, based on current technology and costs. This is notequivalent to replacement of existing physical facilities, as the current facilities do notnecessarily provide the most cost-effective processing based on current technology.Furthermore, the deprival value calculation uses net present value concepts rather thanarbitrary accounting techniques.

The deprival value approach was used as the basis for maximum tariff calculationbecause it has a strong theoretical basis and places a ceiling above which tariffs areunlikely to extend. The minimum tariff was assumed to be the marginal (operating) cost.

In summary, McDonough 1996c6 shows that:


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• Based on the deprival value approach, the cost of tolling through the entire CooperBasin processing system (satellite, trunkline, Moomba Plant, Liquids Pipeline and PortBonython), will be in the range $1200-$1700/mmscf of raw gas.

• The marginal cost of processing raw gas is of the order of $380/mmscf.

• The deprival value cost of processing liquids through the Liquids Pipeline and PortBonython facilities alone varies between $65-$80/m3 ($10.30-$12.70/bbl).

It should be noted that although indicative tolling costs are calculated, this does not inferthat there is capacity available for third party access. However, the study does providean indication of the likely limits of negotiated tariffs where capacity is available. If plantcapacity is available, the negotiated toll will fall between the marginal cost (when there isplenty of spare capacity) and the deprival value cost (when there is minimal sparecapacity).

Methodology

The following scenarios have been investigated:

1. Stand-Alone Processing - NO LPG RECOVERY

See Figure 2(1).

All gas fields developed on a stand-alone basis, with no LPG recovery (ie. LPG is flared)and condensate trucked to Moomba. In this case, the heating value of the sales gas isrelatively high (around 43 MJ/m3) as some LPGs remain in the sales gas stream.

2. Stand-Alone Processing - LPG RECOVERY FOR RICH FIELDS

See Figure 2(3).

For rich gas fields (gas fields with high liquids content), the field is developed on a stand-alone basis, but with all liquids removed, (ie. LPG and condensate). The heatingvalue of the resultant sales gas is slightly less than the previous case (generallyaround 41 MJ/m3), as less LPGs are slipped to sales gas. A separate pipeline isconstructed to transport the liquids to the head of the Moomba-Port Bonython LiquidsPipeline, transported to Port Bonython, processed and sold. A toll of $70/m3($11.10/bbl) is charged for the liquids processing.

LPG recovery for lean fields is not considered, as minimal liquids are produced.

Note:

The case for which LPG is recovered and trucked to Adelaide (Figure 2(2)) was notincluded in the complete analysis. McDonough 1996b4 shows that, for a given fieldsize and gas composition, this is clearly the least economic option. In fact, if a fieldhas an OGIP of 50 bcf or less (about 35 bcf of recoverable raw gas), thedevelopment is uneconomic and will not reasonably proceed, (see Appendix 3).

3. Existing Facility Access - LPG RECOVERY FOR ALL FIELDS

See Figure 2(4).

All gas fields are tied into the existing facilities, including satellite facilities, processingthrough the Moomba Plant, and liquids processing through Port Bonython. Sales gasis sold into the Moomba-Adelaide or Moomba-Sydney Pipeline, while liquids are soldex-Port Bonython. The cash flow for a range of tolls is calculated, ($600, $1000,$1400, $1800, $2200/mmscf of raw gas). Note that the range of tolls chosen for thisanalysis is well outside that which is considered reasonable based on the deprivalvalue concept of $1200-$1700/mmscf, (see above, also Appendix 5). The tolls applyto the entire processing operation, (ie. satellite / trunkline / Moomba Plant / LiquidsPipeline / Port Bonython). No attempt has been made to apportion tolls based on raw


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gas composition, although this is discussed briefly in the “Results” section of thisreport.

In broad terms, raw gas compositions are characterized as follows:

Low CO2 CO2 less than 15% (mol%)

High CO2 CO2 greater than 30% (mol%)

Lean (low) Liquids C5+ < 1%, LPGs & C5+ < 5% (mol%)(ie. C5+ < 4 bbls/mmscf, LPGs & C5+ < 25 bbls/mmscf)

Rich (high) Liquids C5+ > 4.5%, LPGs & C5+ >10% (mol%)(ie. C5+ > 50 bbls/mmscf, LPGs & C5+ > 100 bbls/mmscf)

For each of the above scenarios, both single and multiple field cases are examined.Single field OGIPs investigated are 5 bcf, 10 bcf, 50 bcf and 100 bcf. Capex and opexfor the 5 bcf case were not obtained. Rather, capex and opex from the 10 bcf case wasused, (ie. assumes these costs will not fall below a minimum level). Multiple field casesconsider clusters of 2 to 5 fields, each with an OGIP of 10 bcf. Using the capex and opexfor a 20 bcf cluster of fields, a case with two 5 bcf fields (ie. 10 bcf total) was alsoinvestigated.

For each case, the resultant cash flow is generated. When the annual cashflow falls tozero the project is terminated. The NPV of this cashflow is calculated using a realdiscount rate of 12.5% (before tax).

For the period in which the cash flow is positive, the annual raw gas (used to calculaterecovery factor), sales gas, LPG and condensate is recorded. Note that while annualcash flows are positive, they may never be sufficient to repay the initial capitalinvestment, rendering the NPV of a project negative. In such cases, the recovery ofproduct streams is still recorded. The recovery factors should be regarded as “positivecash flow recovery factors”. An example cashflow table is included as Appendix 6.

Under each processing scenario and raw gas composition, the NPV of the project isplotted against field size. The minimum economic field size is determined to be that forwhich the NPV is zero, (see Figures 4-21).

For all scenarios, the following assumptions are used:

NPV Discount Rate

NPV is calculated on before tax cashflow, reported in A$1995 at a 12.5% real discountrate, (ie. 12.5% above inflation).

Royalty

Ten percent wellhead royalty is taken into account in accordance with the relevantprovisions of the Petroleum Act 1940.

Sales Gas, LPG and Condensate Price

Sales Gas price at the head of the Moomba to Adelaide and Sydney Pipelines(MASPs) = A$2.00/GJ. This is significantly lower than current sales gas prices(approximately $2.30/GJ in 1995), but has been discounted to account for thepossibility that prices will be lower in a deregulated market.

It is assumed that all LPG will be sold onto the domestic market. For the purposes ofthis exercise, a price of $335/tonne is assumed for LPG delivered to Adelaide.

Condensate price at Adelaide refinery is assumed to be A$25/bbl


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Drilling Costs and Well Opex

The average drilling cost is assumed to be $1.1m and completion costs assumed tobe $0.35m. In most cases wells will need to be fracture stimulated. A further $0.3mhas been allowed for this. Therefore, total drilling and completion cost = $1.75m/well.

Allowance is also made for annual downhole operating costs. This accounts forregular testing and any workovers required over the life of the well. $45k/yr/well hasbeen assumed.

Exploration Costs

Seismic costs are ignored. This assumes that seismic costs are sunk.

In addition, the economic analysis does not account for exploration failures (ie.unsuccessful wildcats). Prospective explorers would have to factor this into any oftheir considerations, (ie. NPV would have to be sufficient to bear the cost ofunsuccessful exploration).

Distance from Moomba

It is assumed that the gas development is situated 50 km from Moomba (the head ofthe Moomba-Adelaide and Moomba-Sydney pipelines - see Figure 3). Obviously, forfields which are a greater distance from the MASPs, associated trunkline capex andopex increases.

For the case of access to existing facilities, a 20 km trunkline must be constructed toaccess an existing satellite.

Timing of development

It is assumed that a field discovered in one year will be brought on line in the followingyear. It may be argued that the time to bring on a field may be delayed by a year ortwo while contracts are negotiated and approvals obtained. In this case, minimumeconomic field size will increase slightly, and the effect will be more significant wherethe well cost dominates.

All other assumptions regarding the field development are set out in Attachment 1 of GPA1996a2, (Appendix 1).

This report provides indicative rather than definitive numbers. The study can only provide abroad indication of the types of scenarios that may be encountered, rather than fine detail.Accordingly, costings have been developed on a preliminary “broad brush” basis.

Results

The minimum economic field size expressed in terms of BCF of RECOVERABLE RAW GASfor each of the cases investigated is shown below. It should be noted that minimum economicfield size is quoted as a range to reflect the fact that the values presented are subject touncertainty, depending on exploration company costs and rates of return, reservoir and gasproperties, timing of developments, etc. As previously stated, the numbers presented shouldbe viewed as indicative rather than definitive. However, they do provide an indication ofrelative economic field sizes for a given range of processing options, (see also Figure 3a).


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FieldType

MaximumDepletion Rate

CO2Content

LiquidsContent

Minimum Economic Field Size(Recoverable Raw Gas - bcf)see notes 1,2,3 & 6 below

Stand Alone Facilities Facilities access (LPG Recovered)(see Fig 2(4))

LPG NOTRecovered

(see Fig 2(1))

LPGRecovered4,5

(see Fig 2(3))

@$1000 /mmscf

@$1400 /mmscf

@$1800 /mmscf

single 5% of OGIP/yr low

low

lean

rich

25-30

15-20

na

25-30

15-20

4-8

unecon.

4-8

unecon

4-8

single 10% of OGIP/yr low

low

lean

rich

17-22

10-15

na

15-20*7

10-15

4-8

unecon.

4-8

unecon

4-8

single 5% of OGIP/yr high

high

lean

rich

70-75

27-32

na

35-40

18-23

4-8

unecon.

4-8

unecon

4-8

single 10% of OGIP/yr high

high

lean

rich

50-55**8

18-23

na

30-35*7

12-17

4-8

unecon.

4-8

unecon

4-8

multiple9 2.5 bcf/yr low

low

lean

rich

30-35

10-15

na

20-25

marginal10

7-15

unecon.

7-15

unecon

7-15

multiple9 2.5 bcf/yr high

high

lean

rich

unecon.

33-38

na

42-49

marginal10

7-15

unecon.

7-15

unecon

7-15

NOTES:

1. Based on project NPV calculated at 12.5% real discount rate

2. Gas price at head of pipeline = $2.00/GJ, LPG price delivered to Adelaide = $335/tonne, Condensate price atAdelaide Refinery = $157/m3 ($25/bbl).

3. Gas field is 50 km from Moomba and 20 km from nearest satellite.

4. For “Stand-Alone - LPG Recovered Case”, condensate and LPG is tolled through the Liquids Pipeline and PortBonython at $70/m3 ($11.10/bbl).

5. For the case in which LPG is recovered by Stand-Alone facilities and then trucked to Adelaide (Figure 2(2)),fields with an OGIP of 50 bcf or less will not be economic (see Appendix 3). Results for this processing optionare therefore not included on this table.

6. Recoverable Raw Gas based on recovery factor from nearest profitable case, (generally 50 bcf case).

7. (*) indicates estimate based on “LPG Not Recovered” case.

8. (**) indicates estimate based on “low CO2, lean liquids” case.

9. For multiple field cases, individual field OGIP is 10 bcf each.

10. “Marginal” implies that at a 12.5% discount rate, multiple fields of all sizes are close to economic, (see Figure18). For multiple field case with lean compositions, minimum economic recoverable raw gas >15 bcf if projectNPV is evaluated at a 10% real discount rate, with facilities access = $1000/mmscf.

Given the assumptions listed above, the following conclusions may be drawn:

• The economic viability of any discovery is highly dependent on the CO2 and liquidscontent of the raw gas stream. Fields rich in liquids and low in CO2 are the mosteconomically attractive.

• If access to existing facilities (ie. satellite / trunkline / Moomba Plant / Liquids Pipeline /Port Bonython Plant) is provided, liquids rich fields with recoverable raw gas greaterthan 4-8 bcf will be economic, (if situated within 20 km of existing an existing satellite,which is assumed to be 50 km from Moomba Plant).

• If stand-alone facilities are used to develop a field, liquids rich fields with recoverableraw gas exceeding 10-15 bcf will be economic, (if situated within 50 km of a sales gaspipeline).


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• Assuming the toll will fall in the range $1200-$1700/mmscf, it is always moreeconomic to access the existing facilities than build stand-alone facilities. Thecorollary of this is that if facilities access is allowed, smaller discoveries are economic.This conclusion is entirely to be expected, as economies of scale dictate that largerplants will always be more economic if they are fully utilised.

• As a rule, the minimum economic field size with access to existing facilities is at leasthalf of the minimum economic field size for stand-alone facilities, (assuming similarprocessing requirements).

• Other factors which impact on economic viability are field size, deliverability and,distance from existing facilities.

• For fields which are low in liquids, processing through existing facilities is generallyuneconomic in the range $1200 - $1700/mmscf, (the expected toll range). However, itmay be argued that lean fields would attract a lesser toll, as they would not requireprocessing through Liquids Pipeline/Port Bonython. (NB: conversely, one could thenargue for a higher toll on rich fields to ensure the return on total investment isconstant).

• For liquids-rich fields as large as 35 bcf (OGIP, recoverable raw gas approx 25 bcf), itis uneconomic to develop fields on a stand-alone basis unless LPGs are flared.However, if facilities access is granted, the economics of the development aresignificantly improved and LPGs are recovered. Therefore, access to existing facilitiesis desirable on both economic and resource conservation grounds (see Appendix 3).

• Access to existing facilities is also desirable on environmental grounds, as it removesthe requirement for a proliferation of independent facilities, thereby minimizing theimpact of new discoveries.

• For multiple fields clustered within a 10 km radius with OGIP = 10 bcf each(recoverable raw gas = 7-8 bcf for each field), between 2 and 5 fields can bedeveloped economically on a stand-alone basis. Again, the actual number isdependent on the composition, with low CO2, high liquids field being most economic.

Tables 1-3 show the minimum economic field size for the various cases considered.Table 1 shows minimum economic field size expressed as OGIP (bcf). Table 2 showsminimum economic field size expressed as recoverable raw gas (bcf). Table 3 showsminimum economic field size expressed as recoverable sales gas (PJ).

The results in Tables 1-3 are based on the information in Table 4, which is plotted inFigures 4 to 21. Note that that the recovery factors listed on Table 4 should be regardedas “positive cash flow recovery factors”, (see previous discussion).

USA Practices

Appendix 7 contains a report prepared by Purvin & Gertz Inc for Mines and Energy SAentitled “Gathering and Processing Practices in the Permian Basin”. The area covered bythe report is the Permian Basin of the United States, which includes the western part ofTexas and the eastern part of New Mexico. The report provides insight into the operationof a gas market in a highly competitive environment.

Some costing data is provided in the report. However, direct comparison with costs usedfor this report should not be attempted, as the cost of installing plants in remote locationsin Australia are significantly greater than those in well populated and highly servicedareas of the US. For instance, the Purvin & Gertz study refers to the capital cost of apackaged turboexpander plant as being about US$5.7m (A$7.2m). The GPA studyindicates an estimated installed cost of a complete turboexpander plant being aboutA$13m. The latter includes the packaged plant plus de-ethaniser, recompression,transport, insurance, additional utilities, high pressure liquids storage, high pressurepumps and Engineering Procurement and Construction Management (EPCM). It also


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includes installation of the facilities. It is not clear whether the Purvin & Gertz estimateincludes these items and therefore a direct comparison is not realistic.

ACKNOWLEDGMENTS

This report has been written with the assistance and constructive comment of Terry Aust(Chief Petroleum Engineer) and Kristi Shore (Petroleum Engineer) of the PetroleumEngineering Branch and Bob Laws, Director of the Petroleum Division, MESA

Richard McDonoughSenior Petroleum Engineer


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REFERENCES

1. McDonough R, 1996a, “Cooper Basin Gas Field Development Study - Results”,unpublished MESA report, (File: SR 28/1/202/1), February 1996.

2. GPA 1996a, “Cooper Basin Gas Field Development Study” - updated version, March1996, GPA Engineering Report No 95001-7.

3. GPA 1996b, “Cooper Basin Gas Field Development Study - Addendum No 1”, May1996, GPA Engineering Report No 95001-9.

4. McDonough R, 1996b, “Economics of Stand-Alone LPG Recovery for Small Fields”,internal MESA memo, (File: SR 28/1/202/1), 14 May 1996.

5. GPA 1996c, “Moomba and Port Bonython Replacement Study” - January 1996. GPAEngineering Report No 95187-05.

6. McDonough R, 1996c, “Moomba / Pt Bonython Processing Tolls based on DeprivalValue Approach - Update”. internal MESA memo, (File: SR 28/1/202/1), 24 May 1996.

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