Natural Gas Development Based on Non-pipeline Options_technical Feasibility Study

NOI A

Natural Gas Development Based on NonPipeline Options - Offshore Newfoundland Technical Feasibility Analysis

065/07129 7-Dec-00 07129/G49-0003D

Worley International Inc. and Worley Engineers Worley International Inc. 13105 Northwest Freeway, Suite 200 Houston, Texas, 77040 Tel: +1 713 690 1131 Fax: +1 713 690 1981 Web: http://www.worley.org © Copyright 2001 Worley International Inc.

NOIA NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS - OFFSHORE NEWFOUNDLAND TECHNICAL FEASIBILITY ANALYSIS

Disclaimer and Limitation This report has been prepared on behalf of and for the exclusive use of NOIA, and is subject to and issued in accordance with the agreement between NOIA and Worley International Inc. Worley International Inc accepts no liability or responsibility whatsoever for it in respect of any use of or reliance upon this report by any third party. Copying this report without the permission of NOIA or Worley International Inc is not permitted.

PROJECT 065/07129 - NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS - OFFSHORE NEWFOUNDLAND REV

DESCRIPTION

A

Issued for internal review

0

1

2

3

4

5

ORIG

REVIEW

WORLEY APPROVAL

DATE

CLIENT APPROVAL

Richard A. Bresler

Catriona Duncan

N/A

18-Feb-00

N/A

Richard A. Bresler

Catriona Duncan

Richard A. Bresler

Richard A. Bresler

Catriona Duncan

Richard A. Bresler

Richard A. Bresler

Catriona Duncan

Richard A. Bresler

Richard A. Bresler

Steve Worley

Richard A. Bresler

Richard A. Bresler

Steve Worley

Richard A. Bresler

Richard A. Bresler

Steve Worley

Richard A. Bresler

Issued to Client

29-Mar-00

1-May-00

Issue to Client

Client comments incorporated

DATE

26-Jun-00

27-Sep-00

Final Revisions

2-Dec-00

Final Revisions

Final Revisions

7-Dec-00

aforest:desktop folder:natural gas studies:development & transportation:technical nonpipeline final.doc Page ii


CONTENTS 1.

PURPOSE ............................................................................................................................................1

2.

SCOPE .................................................................................................................................................2

3.

METHODOLOGY .................................................................................................................................4 3.1

Onshore Compressed Natural Gas .....................................................................................................4

3.2

Onshore Liquefied Natural Gas ...........................................................................................................4

3.3

Offshore Compressed Natural Gas .....................................................................................................4

3.4

Offshore Liquefied Natural Gas ...........................................................................................................4

3.5

Onshore and Offshore Gas to Liquids.................................................................................................4

4.

PRODUCTION SCENARIO SUMMARY.............................................................................................6 4.1

Offshore CNG .......................................................................................................................................6

4.2

Offshore LNG........................................................................................................................................7

4.3

Offshore GTL ........................................................................................................................................7

4.4

Onshore CNG .......................................................................................................................................8

4.5

Onshore LNG........................................................................................................................................8

4.6

Onshore GTL ........................................................................................................................................8

4.7

Gas Processing ....................................................................................................................................8

5.

TECHNICAL FEASIBILITY ISSUES................................................................................................. 10 5.1

Reliability............................................................................................................................................ 10

5.2

Technology Status Summary............................................................................................................ 12

6.

COST ANALYSIS SUMMARIES ...................................................................................................... 15 6.1

CNG Summary .................................................................................................................................. 16

6.2

Liquefied Natural Gas ....................................................................................................................... 18

6.3

Onshore Gas-to-Liquids .................................................................................................................... 19

6.4

Offshore Gas-to-Liquids .................................................................................................................... 21

7.

CONVERSION FACTORS................................................................................................................ 24

8.

GLOSSARY OF TERMS................................................................................................................... 25

technical nonpipeline final.doc

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Exhibits I – GAS PROCESSING…………………………………………………...……………………………………..EI-1 II – OFFSHORE CNG…………………………………………………………..……………………………….EII-1 III – ONSHORE CNG…………………………………………………………..……………………………….EIII-1 IV – ONSHORE LNG……………………….……………………………...…..…………………...………….EIV-1 V – OFFSHORE LNG…………………………………………………………..……………………………….EV-1 VI – ONSHORE GTL…………………………………………………………..……………………………….EVI-1 VII – OFFSHORE GTL…………………………………………………………..…………………………….EVII-1


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1.

PURPOSE

Prior to this phase of work, a Pre-Screening Review was conducted to identify the many possibilities for utilizing natural gas. From that list, it was agreed that eight (8) different developments would be investigated, three onshore and five offshore, for the Industry Benchmark Analysis. As a result of the Benchmark Analysis, the scope of the Technical Feasibility Analysis was agreed: • Onshore and offshore CNG. • Onshore and offshore LNG. • Onshore and offshore GTL. a) Methanol b) Fischer Tropsch (Diesel, Naphtha, etc.) c) Methanol to Gasoline (MTG) The purpose of the Technical Feasibility Analysis is to define and evaluate the technical feasibility of these non-pipeline options for Newfoundland’s offshore natural gas resources in terms of the resource, the market opportunities identified, the development scenarios, gas processing, transportation of the products, storage, and any other relevant technical considerations.


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2.

SCO PE

The options selected for the Technical Feasibility Analysis are as follow: a)

Onshore Compressed Natural Gas

b)

Onshore Liquefied Natural Gas

c)

Onshore Conversion of Gas to Liquids

d)

Offshore Compressed Natural Gas

e)

Offshore Liquefied Natural Gas

f)

Offshore Conversion of Gas to Liquids

Note that options a) through c) require that the gas be transported to shore prior to final processing. The CAPEX cost of the pipeline and upstream production facilities are excluded from these three analyses. For each of the options, the following key considerations were taken into account: • Production Profile − Gas production rates of 500 MMscfd − Multi-field, sequential vs. stand alone developments − Gas composition by field − Gas vs. oil production rates (current and anticipated), field life, re-injection requirements, etc. • Type of Production System − Gravity-based, floating and subsea alternatives − Reserve and financial implications of portable and modular production systems − Utilization possibilities for existing and planned offshore production facilities and shared services. • Processing Requirements − Offshore vs. Onshore processing − Composition of the raw natural gas • Mode of Transportation − Non-pipeline transportation; LNG, CNG, GTL − Field to market vs. field to onshore and onshore to market


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• Infrastructure Requirements − Site availability for landfall, storage requirements, and other infrastructure − Possible utilization of Newfoundland site-specific infrastructure • Cost Estimates • Employment Impacts and Capture Rates • Technology Status


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3.

MET HODOLO GY

3.1

Ons hore Compres sed Na tural Gas

Cran and Stenning has undertaken most of the available work on this concept, and the information presented is primarily based on their work and cost estimates. Information on two other CNG concepts have been reviewed. One utilizes carbon composite pressure vessels by Lorica Offshore Technology in Newfoundland, and the other is a concept which is based on dense phase CNG by Suction Mooring Technologies. Cran and Stenning have estimated costs for the CNG carriers, mooring systems, offloading berths, onshore equipment required to deliver the gas to market, and operating costs.

3.2

Ons hore L iquefi ed Nat ural G as

The Atlantic LNG facility in Trinidad, which was evaluated during the Benchmark Study, was used as the basis for the technical feasibility analysis. That facility was designed for an inlet gas rate of 475 MMscfd, which is nearly identical to the assumed Jeanne d’Arc basin gas rates. Considerations for Newfoundland productivity factors were taken into account based on the estimates and results of the Hibernia and Terra Nova projects, as furnished by the SGE Group. Additional cost information was supplied by Bechtel, ABB Randall, Black & Veatch, and by Worley from confidential projects undertaken in Europe, South East Asia and Australia.

3.3

Off shore Compre ssed Natural Gas

In addition to the information supplied by Cran and Stenning mentioned above, published information was gathered from the Terra Nova, Hibernia, and Sable projects. Cost data from previous Worley projects in South East Asia and Australia were also taken into account.

3.4

Off shore Liquef ied Na tural Gas

The facility that was evaluated is a proprietary ExxonMobil concept. Most of the information was gathered from published technical papers and those written for “Offshore”, “World Oil” and from websites. Cost estimates for this concept have not been provided by ExxonMobil. Worley has therefore estimated the costs based on ExxonMobil reported savings over conventional LNG developments.

3.5

Ons hore a nd Off shore Gas to Liqui ds

Worley Engineers have made several GTL proposals and have been a technical advisor to several offshore producers. They have technology secrecy agreements with ExxonMobil, Haldor Topsoe,


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Rentech, and ICI (Synetix) relating to non-published data for gas-to-liquids technologies. Using confidential information from these sources, several detailed cost estimates have been developed for potential offshore projects for the North Sea, South Ease Asia, and West Africa. These estimates have been revised for applicability to Newfoundland.


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4.

PRO DUCTIO N SCENARIO SUMMARY

For all of the following cases, the average Btu content of the gas was calculated to average around 1117 Btu/cubic foot. This was based on information and gas compositions supplied by C-NOPB and was influenced greatly by the gas cap reservoirs which would provide the majority of the produced gas.

4.1

Off shore CNG

For the CNG concept, the most likely development scenario’s for use in the Jeanne d’Arc Basis would be one of the following: • Combined Gas/Oil Hub There is substantial merit for considering an oil and gas hub to be located near any major gas / condensate reservoir. Any new facility could perhaps be located at a central point between the Hibernia, White Rose and Terra Nova developments, depending on the proximity to selected gas storage/reinjection reservoirs. From purely technical considerations, either a GBS or FPSO could provide the means for this type of development. The facility would gather available oil and gas from the various fields in the Jeanne d’Arc Basin, and condition the production to make it suitable for export to refinery’s and natural gas markets. Services such as field operations, gas processing, gas reinjection / gas storage could be provided from the facility. This type of infrastructure could allow nearby fields, which might otherwise be uneconomic as stand-alone projects, to become viable projects in the future. For this scenario, the production equipment would be sized for a minimum of 100,000 BOPD, injection of about 160,000 BWPD, and compression up to 250 MMscfd of gas to 5,600 psig for injection. Export of up to 500 MMscfd of gas would be compressed up to approximately 3,100 psig for loading CNG vessels or for delivery to a pipeline. • Gas Hub Similar to the Gas/Oil Hub mentioned above, either a strategically located GBS or FPSO vessel could be a hub for gathering only natural gas and associated liquids from wells tied-back directly to the hub. It could also possibly provide gas processing for the various developments in the Jeanne d’Arc Basin. • Existing GBS Hub There is the possibility that the Hibernia facility could be modified to allow the facility to gather natural gas and associated liquids from other developments in the Jeanne d’Arc Basin.


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4.2

Off shore LNG

An offshore LNG facility, as proposed by ExxonMobil for the Pacific Rim, would in essence be a floating gas gathering hub. It could be designed to process total wellstream production from fields in the Jeanne d’Arc Basin. The ExxonMobil concept was reportedly considered to handle from 500 MMscfd up to 1,750 MMscfd, with the primary focus on 1,000 MMscfd.

4.3

Off shore GTL

In the past, the primary offshore application considered for this concept has been for oil developments that have relatively small amounts of solution gas that can not be reinjected, can not be flared and is geographically stranded from a market. Nevertheless, this study considers the offshore conversion of natural gas into easily transportable liquid methanol, gasoline, or diesel plus naphtha products. By review of technical considerations and by comparison to the largest tankers and FPSO’s built to date, it is considered that the maximum practical size of conventional ship-shaped vessel for GTL application would be about 54 meters wide by 375 meters long. Any size vessel would require special design considerations to have minimum wave motions resulting from wave forces and for optimum freeboard in both loaded and unloaded conditions. It would also be desirable to have a higher than normal bow rise for operation in the Jeanne d’Arc Basin to prevent unacceptable deck damage from “green water” and to minimize operational downtime. The vessel would require additional reinforcement for ice considerations as is reported to have been done for the Terra Nova FPSO. The selected maxmum size vessel can accommodate up to about 100,000 BOPD, 160,000 BPD of water injection, and four (4) GTL trains that would consume about 177 MMscfd for conversion to GTL products. The GTL plant would produce about: Methanol

6,000 TPD

Gasoline

21,100 BPD

F-T (Diesel / Naphtha)

18,100 BPD

A dedicated GTL vessel, without GOSP facilities, could accommodate 6 GTL trains and would consume approximately 266 MMscfd of natural gas for conversion to GTL products. This volume of gas would produce about: Methanol

9,000 TPD

Gasoline

31,650 BPD


27,150 BPD

One each of the above described vessels could be deployed as a hub, capable of consuming 443 MMscfd of natural gas. The vessels could also be located at two separate sites, one at a new development that


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required oil and gas handling equipment, and one at an existing development utilizing the gas that had been previously injected.

4.4

Ons hore CNG

For this concept, it is assumed that a pipeline has been selected to bring the gas onshore, and that excess gas of approximately 490 MMscfd is available for transportation to markets in the U.S. or Nova Scotia. Onshore compression will consume approximately 2.0% of the inlet volume for fuel.

4.5

Ons hore L NG

For this concept, it is assumed that a pipeline has been selected to bring the gas ashore, and that 490 MMscfd of gas will be available at the plant fence for conversion into LNG. Since the LNG plant consumes about 11% of the inlet gas as fuel, only about 89% of the inlet gas is converted to LNG. Some of the product would be used for revaporization of the LNG at the delivery point.

4.6

Ons hore G TL

For this concept, it is assumed that a pipeline has been selected to bring the gas ashore, and that 490 MMscfd of gas are available for converting into liquids. There are no single existing plants of the size required to convert these huge volumes of natural gas to either of the three products. For this reason, the study is based on multiples of nearly the largest state-of-the-art syngas trains for making the syngas to be converted to liquids. Each train will consume 62.5 MMscfd. Eight trains would be used to consume 490 MMscfd. It is recognized that onshore plant design can be refined for greater thermal efficiency compared to offshore plants. Credit is not taken for the increased efficiency for this study. The eight train GTL plant would produce the following approximate volumes of products: Methanol

16,500 TPD

Gasoline

58,100 BPD


49,700 BPD

For the onshore cases, the analyses will consider only the costs for the onshore facilities required after delivery of the gas by the pipeline. The cost of the F-T plant will reflect the approximate cost forecast by Shell and ExxonMobil for a modernized plant using fluidized beds and slurry suspended catalysts.

4.7

Gas Proce ssing

This analysis reviewed the costs and expected margins of gas processing, the factors that can impact the processing margins, like gas, oil and NGL prices; transportation; operating costs; plant efficiency; and plant product recoveries.


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For this analysis, gas processing was not considered for offshore GTL on an FPSO, as there will not be enough space for the gas processing equipment and the gas can be utilized without extraction of NGL’s. For the same reasons, gas processing is considered unlikely for the offshore CNG and offshore LNG cases. There is the possibility that the major gas reservoirs are retrograde reservoirs, requiring gas processing and gas cycling for a number of years, prior to blow-down. Otherwise, potentially valuable natural gas liquids and condensate would not be recovered, and gas deliverability could be impacted, depending on how pronounced the liquid formation is around the wellbores. However, this is a reservoir management issue that is beyond the scope of this study, but could dictate the manner in which the offshore gas is produced and therefore impact the costs incurred to process and re-cycle the gas. See Exhibit I for gas processing reviews.


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5.

TECHNICAL FEASI BILITY ISSUES

5.1

Rel iabili ty

Gas supply reliability is critical for the success of a natural gas industry. Reliability applies to each entity in the gas supply chain; producers, gas transporters, and the end-users. If the development is not considered reliable, with virtually no interruption in the gas supply, capital equity required to develop the natural gas infrastructure may be very difficult to secure. PROD UCER RELI ABILIT Y The producers must be able to deliver the agreed amount of gas for a specified period of time. AG (associated gas or solution gas) would be the most likely initial source of gas. However, as the AG delivery rates decline, additional sources of gas must be ready and able to be delivered into the infrastructure. If required, depending on cost and long term supply requirements, NAG (non-associated gas) could provide “swing” volumes necessary to make up insufficient short term AG volumes. GAS GATH ERER A ND TRAN SPORTE R RELI ABILIT Y The gas gatherer must likewise be able to receive gas from the producers at all times. If the gas gatherer is unable to take possession of the gas for any reason, all NAG production would have to be shut-in, and the AG would have to be flared while oil is produced. Otherwise, the oil wells would also have to be shut-in if flaring is not allowed. The producers may not tolerate frequent shut-ins. END-USE R RELI ABILIT Y Similar to the gas transporter reliability issue above, if the end-users can not take delivery of their allocated share of the gas, then the gas transporter must find an alternative use or costly storage for the gas to avoid forcing the producers to shut-in production. GAS STOR AGE AN D SECU RITY O F SUPP LY Gas storage will become a very important issue as it is very important to have flexibility in the gas supply chain. This is often times taken for granted in the oil supply chain, as oil developments have oil storage available all along the supply chain. For example, at Hibernia there is storage in the GBS, there is storage at the Transshipment Terminal, and there is storage at the refineries. Without supply flexibility, nuisance shutdowns may occur too often to be tolerated by the producer, gas transporter, and end-users. The important thing to realize is that if any one entity has a problem, it will effect all other supply chain entities, unless there is adequate supply flexibility.


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There are a several potential solutions to increase supply flexibility and thus improve gas supply reliability: • Gas reservoir storage • Underground gas salt storage • Peak-shaving NAG gas supply • Line-pack • Artificial Storage If reservoir storage is available, either onshore or offshore, gas supply reliability is increased tremendously. For example, if the end-user or transporter must shutdown, the operators can still continue to produce oil by injecting the associated gas instead of flaring or shutting in. Conversely, if the oil production is shut-in, the gas transporter and end-user can continue to operate by withdrawing gas from storage. Salt dome storage is more commonly used when onshore. This is storage created by washing out a cavern with fresh water deep underground, creating a void space that can be used for gas storage. Salt storage is in the planning stages at Point Tupper by Statia Terminals, and could be very useful in regards to use of the CNG concept. Salt storage is typically analogous with high deliverability and high injection capabilities. This would be ideal when offloading CNG vessels, whose instantaneous rate could be as much as 1bcfd, which is probably more than a pipeline system or end-user could take. Aquifer reservoirs are also commonly used for gas storage, under the right conditions. Depending on the local geology, this may or may not be an option for Newfoundland. The same concepts apply with NAG gas, or what the authors like to refer as “swing gas”, “security of supply” or “back-up” gas. When onshore gas demand is reduced, gas from NAG sources can be reduced with less financial consequences than from AG sources. Ample amounts of NAG gas can be produced when the AG gas volumes are low or depleted. In some cases, the NAG gas supply and gas storage can be one and the same. The North White Rose reservoir may prove to be an ideal reservoir to provide for both flexible delivery rates and variable gas injection rates. The Hibernia gas cap may also be well suited to supplement AG volumes and to provide for gas injection when needed. Line-pack is commonly associated with long pipelines. Typically, if the downstream users can not take delivery of the gas, the pipeline operator can temporarily continue to take gas from producers by increasing the pipeline pressure. This is considered “packing the line”, or “line pack”. Depending on the operating conditions and parameters of the pipeline, this could provide from a couple of hours to as much as a day of storage. Artificial storage can be built using vessels, pipe, etc., similar to the CNG concept. A 500 MMscf storage facility could help the producers stay on-line for a day or two when the end users can not take full


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delivery. Conversely, if the producer has scheduled downtime, the storage facility could be filled ahead of time, allowing the end-users to continue operations.

5.2

Tec hnolog y Stat us Summary

FPS O H U B An FPSO is being used as a hub in the North Sea on the Triton project. Three fields will be tied into an FPSO that can process 105,000 BOPD and 200 MMscfd. The vessel is located in 91 meters of water. and is positioned 20 km from the Bittern field and 12 km from the Guillemot West field. All production is piped subsea to the FPSO. A gas pipeline to shore exists 12 km from the FPSO and is to be connected to the FPSO via a 10-inch spur line. The vessel has 15 riser slots. The project has taken 3 _ years to complete. The technical challenge is to limit the number of risers required. When one considers production lines, test lines, water injection, gas lift, gas injection, umbilicals, and gas export lines, the capacity of a disconnectable turret may be exceeded. Optimization of the subsea facilities and the turret design would be required. GRAV ITY BASE D STRU CTURE There are no technical issues as this is proven technology based on the Hibernia GBS and about 15 other structures in the North Sea like Troll A GBS. However, water depth and iceberg size present significant site-specific challenges that can not be taken lightly. HIBE RNIA HUB Adding gas risers to the Hibernia GBS is reported to be a concern, but the authors feel that a satisfactory solution can be found. COMP RESSED NATU RAL GAS The CNG concept is an integration of various existing technologies for a new transport method. Although this concept has not been utilized offshore, there are no other foreseeable technical reasons preventing the concept to work except for the weight of the coselles, which is a concern. A 500 MMscfd ship would contain 180 coselles, each weighting 445 tonnes. Including the weight of the piping manifolds, compression, fire and safety equipment, etc., the total weight of the equipment and coselles, excluding the ship, will be in excess of 81,000 tonnes. The ability to dry dock a ship with this dense weight is a concern. Other means of inspection would have to be agreed with certification authorities prior to fabrication, which is a realistic expectation.


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O F F S H O R E LNG As with the coselle CNG carrier, the offshore LNG concept is a new way of bringing existing technologies together for a new solution. ExxonMobil has done a considerable amount of work to develop the concept, both from a technology and a safety point of view, including LNG offloading systems. Several other companies are also active in developing new equipment for offshore LNG offloading applications. It is expected that a practical way can be established to safely avoid the threat of icebergs. Risers from the sea-bed to the floating structure must be able to be quickly disconnected as is planned for the Terra Nova development. O F F S H O R E GTL The processes for conversion of natural gas to synthesis gas then to methanol, gasoline, or a mixture of diesel and naphtha are very mature when using fixed catalyst beds. Cost reducing methods using catalyst slurries have been proven onshore with the high possibility of being proven for offshore applications very soon. Offshore cryogenic separation of oxygen from air that is needed to prepare synthesis gas is reported by Air Products to be proven by model tests on floating vessel motion simulators. Similar methods can probably be used for successful distillation of GTL products but model tests will be required. An alternative would be to transport the GTL products to an onshore location for distillation. Floating structures to provide for lower wave induced motions, such as ExxonMobil’s LNG floater, and others, are being proposed for maximizing production up-time leading to better economics. OFFS HORE GAS PROC ESSING Offshore gas processing has been done on several fixed platforms and on near-shore barges. However, the authors are not aware of gas processing being performed on an FPSO. There is one FPSO project that has a debutanizer as part of the equipment to remove the heavier hydrocarbons from the gas prior to reinjection. A complete gas processing plant would require a deethanizer, and in some cases a depropanizer. The existing debutanizer was proven for that service by model tests on a vessel motion simulator. Several companies are considering gas processing on FPSO’s, with the performance of the fractionation columns being a major concern in rough seas. However, if the fractionation column manufacturers will make model tests and warrant the performance of their process vessels on an FPSO, then the major obstacles will have been removed. Producing a Y-grade product (i.e., a combined propane, butane and condensate liquid product under pressure) for fractionation at an onshore facility like Point Tupper may be more practical than offshore


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fractionation. Many such applications exist, including the 1.6 bcfd North Rankin platform to landfall offshore the Northwest coast of Australia. The complexity issues with regards to offshore storage and offloading of the various products, along with the performance of the columns, will drive these decisions. SUBS EA DEVE LOPMEN TS Due to the extreme ambient temperatures in the Jeanne d’Arc Basin, pipeline flow assurance and prevention of blockage in the flowlines due to hydrates and/or waxes is critical to the success of tie-back projects. So long as fluid properties such as cloud point, pour point, etc., are known, it will be possible to design the subsea facilities to minimize flow assurance problems, e.g., by a combination of insulation, chemical injection and routine pigging. For the purpose of this study, it has been assumed that all the producing pipelines will be insulated and chemical injection facilities will be installed. OTHE R FACT ORS For producers to discontinue gas injection, the modifications required to reconfigure facilities and possibly drill additional water injection wells can be a costly proposition if not planned for at the design stage.


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6.

COST ANAL YSIS SUMMARI ES

For all cases, where applicable, the capital and operating costs include the “all-in” costs for a project. In this way the total costs to be incurred by the producers can be reviewed and established so that an accurate economic analysis can be conducted in the future. The challenge in estimating total costs is that there are so many options to consider, such as: • Floating vs. fixed facilities. • Concrete vs. steel structures. • Phased vs. all-at-once developments. • Tie-back vs. stand-alone developments. • Lease vs. purchase of facilities. • Utilizing existing vs. new resources (i.e., helicopters, tugs, supply boats, transshipment, storage, etc.). • Wet vs. dry wells. • Flow assurance solutions. The capital costs include: • FPSO or GBS cost. • Turret, mooring. • Topsides. • Shuttle tankers. • Supply boats. • Well costs; both “dry” and “wet” trees, glory holes, manifolds, etc. • Subsea flowlines, pipelines, chemical injection, pigging, etc. • Onshore berthing and equipment for CNG ship deliveries. The operating costs include: • FPSO/GBS operating: fixed, variable, logistics, staffing, etc. • Shuttle tanker crew, fuel and maintenance. • Supply boat crew, fuel and maintenance. • Product transportation and storage.


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6.1

CNG Summa ry

The offshore CNG concepts considered three basic scenarios: 1. FPSO or GBS oil and gas development hub, delivering compressed gas to CNG carriers. 2. FPSO or GBS gas hub delivering compressed gas to CNG carriers. 3. Modifying the Hibernia GBS to be a gas hub, and delivering compressed gas to CNG carriers. In each case, the offshore facility would furnish high pressure gas up to 3,000 psig to the CNG carriers for transport to market. The analysis was based on CNG ships being built, owned and operated by a third party. CNG ship charter rates from offshore to the U.S. are estimated at C$36.43 million per ship per year. This equates to a transportation fee of approximately C$1.27 per MMBtu. The onshore CNG concept is based on a gas pipeline being built from the Grand Banks area to Newfoundland. Once the gas reaches Newfoundland, except for a portion of the gas that can be utilized in Newfoundland, the excess gas would still be stranded and would require a means to be monitized. For the onshore CNG concept an additional 2% of the inlet gas volume is used as fuel to compress the gas to 3,000 psig from an assumed pipeline delivery pressure of 750 psig. The CNG charter rates to the U.S. would equate to a transportation fee of approximately C$1.09/MMBtu since only six ships would be required. A summary of the results of the Technical Feasibility are shown below:


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Table 6.1 Compressed Natural Gas (CNG) SummaryNote 1 Offshore FPSO Oil & Gas Hub

Offshore FPSO Gas Hub

Offshore GBS Oil & Gas Hub

Offshore GBS Gas Hub

Offshore Hibernia Hub

Onshore CNGNote 2

500

500

500

500

500

490

Oil/ Condensate Capacity (BOPD)

100,000

25,000

100,000

25,000

Existing

None

Water Injection Capacity (BWPD)

160,000

None

160,000

None

Upgraded

None

Gas Processing Potential

No

Yes

No

Yes

No

Yes

Total CAPEX: (C$ MM)

4,583

3,308

4,716

3,570

2,578

297

Production OPEX Average (C$ MM/YR)

140.2

115

123.8

103

33.5

29.0

CNG Charter Rate (C$ MM/YR) for first 20 yrs

255

255

255

255

255

219

Gas Revenue (C$ MM/YR)

810

810

810

810

810

755

Liquid Revenue (C$ MM/YR)

393

121

393

121

121

0

Inlet Gas Capacity (MMscfd)

Note 1: The above numbers do not include the costs of gas for feedstock. Note 2: The onshore CNG case does not include the cost for a pipeline to shore.


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6.2

Liq uefied Natural Gas

ONSH ORE The onshore LNG concept is based on the possibility of a gas pipeline being built from the Grand Banks area to Newfoundland. However, except for a portion of the gas being utilized in Newfoundland, the excess gas will still be stranded, and will require a means for monitization. This Onshore LNG option evaluates a method of transporting the excess gas from Newfoundland to markets in the northeast U.S. or to other economic markets. OFFS HORE The offshore LNG concept is based on the assumption that an FPSO or GBS can be replaced with an integrated floating concrete LNG plant, pioneered by ExxonMobil for applications in Southeast Asia and Australia. The floating LNG concept was considered to withstand typhoon environments and to handle feed rates ranging from 500 MMscfd up to 1,750 MMscfd. The major focus and detail design was for a 1,000 MMscfd size facility. This analysis assumes a transportation and regasification cost of C$ 0.65/MMBtu (Based on the ICF market report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland”, page 47) to markets in the Northeastern U.S. This is also based on the current spare capacity of LNG transportation and regasification facilities. However, as increasing world-wide LNG developments come onstream, surplus transportation and regasification capacity may disappear, resulting in increased transportation costs.


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Table 6.2 Liquefied Natural Gas (LNG) Summary Offshore LNG

Onshore LNG

500 MMscfd

490 MMscfd

100,000

None

Yes

Yes

6,030

1,553

LNG Plant OPEX (C$ C/YR)

162

65

LNG Transportation (C$ C/YR)

176

141

Gas Revenue ($C MM/YR)

721

693

Liquid Revenue ($C MM/YR)

393

0

Inlet Gas Capacity (MMscfd) Inlet Condensate / Oil Capacity (BCPD) Gas Processing Potential CAPEX (C$ MM)

Note: The above numbers do not include the cost of gas for feedstock. LNG plants consume approximately 11% of the inlet gas as fuel. This is reflected in the revenue streams above.

6.3

Ons hore G as-to- Liquid s

The basis for sizing the inlet gas rate to the Methanol plant was the largest single ATR syngas train built to date, which is for 2,400 tonnes per day of methanol. Thus, eight (8) near full size trains would be required to process 490 MMscfd of inlet gas. The same number of trains would be required for the MTG (via TIGAS) process. The syngas portion of a Fischer Tropsch would be the same as for a methanol or gasoline product. The total Fischer Tropsch plant cost is assumed to be the current projected cost of US$ 30,000 per bbl/day plant capacity, plus adjustments for construction camps, labor rates, and winterization of the plant being located in a cold environment. The plant would use the latest fluidized bed and/or slurry catalyst contact reformers/synthesis process vessels as has been proven primarily by ExxonMobil, Shell and Sasol. These technologies can be used onshore where there is no motion and where very heavy and tall process vessels can be handled.


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Although it is recognized that the methanol and TIGAS/MTG processes can also benefit from the same or similar technologies, especially in producing syngas, they were not considered for this study. The decision resulted from the fact that no one is known to be proposing their use for methanol and TIGAS/MTG and no published or private plant costs are available for this analysis except for reference to reported CAPEX in US$ per Bbl of product for Fischer Tropsch plants. Table 6.3 is based on available technical and cost data from prior studies where the feed gas and gross heating value was 1,288 BU/ft3. This is greater than for Jeanne d’Arc gases. The data was modified to reflect the reported values for the average 1,117 BTU/ft3 quality gas reported for the Jeanne d’Arc Basin gas. Adjustments to plant feed gas volumes would be required for each significant change in the heating value of feed gases from Jeanne d’Arc reservoirs in order to maintain the design product volumes. Onshore GTL plants require less fuel gas than offshore plants. This results from a need to simplify equipment, operations and maintenance on a crowded and sometimes violently moving FPSO vessel. Use of fuel to drive compressors and generate electricity for electric motors on FPSO vessels is much safer than the use of waste heat to generate and use steam at the many required locations as is common practice onshore. The increased use of fuel offshore is normally of less concern because the stranded gas has a low or negative value when the alternative is to reinject this gas at a cost. The use of high BTU/ft3 feed gas is less efficient from the standpoint of BTU/tonne of product. This results from the fact that a pre-reformer is used to convert C2 and heavier gases to C1 and CO2 in order to prevent soot from forming on the catalyst. The best BTU conversion efficiencies result when most of the C3 and heavier components are removed by gas processing prior to the feed gas entering the syngas production equipment. If gas processing were performed upstream of the GTL plant, only seven trains would be required for the methanol and MTG plants due to the “Btu shrinkage” of approximately twelve percent (12%).


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Table 6.3 Onshore Gas-to-Liquids Summary Onshore Methanol

Onshore MTG

Onshore F-T

Inlet Gas Rate (MMscfd)

490

490

490

CAPEX GTL Plant(C$ MM)

2,186

2,990

2,494

67

101

75

Product Rate Design

16,500 TPD

58,100 BPD

49,700 BPD

Product Selling Price (2005)

C$ 171/tonne

C$ 27/bbl

C$ 30/bbl

Equivalent Value on a Btu Basis

C$ 7.97/MMBtu

C$ 5.29/MMBtu

C$ 5.56/MMBtu

Revenue Average (C$ MM/Yr)

944

549

539

OPEX:GTL Plant (C$ MM/YR)

Note: The above numbers do not include the cost of gas for feedstock.

6.4

Off shore Gas-to -Liqui ds

The offshore GTL gas rates are limited by the size and weight of equipment that can be placed on an FPSO and then operate in all but the most severe sea states. For the GOSP / GTL (gas oil separation plant / gas-to-liquids plant) cases, it is has been established that four methanol trains, each with a capacity of 1,500 tonnes per day, can be placed on an FPSO that also contains oil and gas separation equipment. This equates to three trains of MTG or three F-T trains. It has also been established that an FPSO without the gas/oil separation plant can have sufficient plot area for six methanol trains, six MTG trains or six F-T trains. The GOSP facilities can process 100,000 BOPD and inject 160,000 BWPD. The offshore GTL FPSO case (Table 6.5) is based on six trains of 1500 tonne/day methanol product for methanol and TIGAS/MTG. The F-T plant would use the same volume of syngas as for a six train methanol plant. The GOSP/GTL FPSO includes the costs for all production and injection wells, subsea costs, two shuttle tankers and a supply boat. Tables 6.4 and 6.5 CAPEX values are based on a more rich-feed gas than exists in the Jeanne d’Arc Basin. Adjustments were made to account for the lower BTU/ft3 gas from Jeanne d’Arc fields. Volumes


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of feed gas would have to be adjusted to maintain design product volumes as the BTU/ft3 values vary. The data has been adjusted for 1117 Btu/scf of gas and includes the decreased efficiency effect of having significant C3 and heavier gases and the choice of using more fuel gas instead of generating and using steam in an offshore environment. Table 6.4 Offshore GOSP / GTL FPSO (4 Trains) Offshore Methanol

Offshore MTG

Offshore F-T


177

177

177

CAPEX Note 3 (C$ MM)

1744

2268

1601

OPEX (C$ MM /Year)

33.6

43.8

38.4

GTL Production

6,000 Tonnes/Day

21,100 Bbls/Day Note 1

18,100 BPD

C$ 171/Tonne

C$ 27/Bbl

C$ 30/Bbl

C$ 7.97/MMBtu

C$ 5.29/MMBtu

C$ 5.56/MMBtu

GTL Revenue (C$ MM/YR)

359

199

190

Oil Revenue (C$ MM/YR)

700 Note 2

700 Note 2

700 Nte 2

Product Selling Price (2005) Equivalent Value on a BTU Basis

Note 1: With light ends and LPG used as fuel gas. Note 2: First six (6) years average. Note 3: Does not include well costs and subsea pipeline/equipment costs.

The GTL FPSO does not include CAPEX costs for wells, shuttle tankers or supply boats. It is assumed that the oil development has paid for these and that only a share of the OPEX for the shuttle tankers and supply boats are incurred.


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Table 6.5 Offshore GTL FPSO (6 Trains) Offshore Methanol

Offshore MTG

Offshore F-T


266

266

266

CAPEX Note 4 (C$ MM)

1,835

2,616

1,619

OPEX (C$ MM /Year)

33.6Note 2

43.8

38.4

GTL Production

9,000 Tonnes/Day

31,650 Bbls/Day Note 1

27,150BPD

Product Selling Price (2005)

C$ 171/Tonne Note 3

C$ 27/Bbl

C$ 30.59/Bbl

Equivalent Value on a Btu Basis

C$ 7.97/MMBtu

C$ 5.29/MMBtu

C$ 5.56/MMBtu

539

303

313

Revenue Average – GTL (C$ MM /Year) Note 1: With light ends and LPG used as fuel..

Note 2: Does not include C$24.25 /tonne for methanol transportation to U.S. Gulf Coast markets. Note 3: Based on U.S. Gulf Coast long term contract prices. Note 4: Does not include well costs or subsea pipeline/equipment costs.


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7.

CONVERSIO N FACT ORS

C$

=

US$ 0.70

1 MMscf

=

1,117 MMBtu

1 cubic foot

=

1,117 Btu

29.6 MMBtu

=

1 tonne methanol (excluding fuel)

10 MMBtu

=

1 barrel F-T product (including fuel)

8.42 MMBtu

=

1 barrel MTG product (excluding fuel)


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8.

GLO SSARY OF TERMS

AG

Associated Gas, sometimes referred to as “solution gas”

ATR

Autothermal Reformer

Bbl

Barrel

BBtu

Billion British thermal units

Bcf

Billion cubic feet

Bcf/yr

Billion cubic feet per year

Btu

British thermal unit

BOE

Barrel of Oil Equivalent

BPD

Barrels per day

cf

cubic feet

C$

Canadian dollar

ºC

degrees Centigrade

CAPEX

Capital expenditures

C-NOPB

Canada-Newfoundland Offshore Petroleum Board

d

day

DME

Dimethylene

EIA

Energy Information Administration

FPSO

Floating production, storage and offloading vessel

F-T

Fischer-Tropsch

GJ

Gigajoule

GOSP

Gas/Oil Separation Plant

GPM

Gallons of Natural Gas Liquids per Mcf

GTL

Gas-to-Liquids

GW

Gigawatts

Henry Hub

A location in South Louisiana where a number of natural gas pipelines converge

ICF

ICF Resources Incorporated


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kWh

Kilowatt hour

LNG

Liquefied Natural Gas

LPG

Liquefied Petroleum Gas – propane and butane

MFPSO

Methanol floating production, storage and offloading vessel

MM

Million

MMcf

Million cubic feet

MMscfd

Million standard cubic feet per day

MMBtu

Million British thermal units

MMBtu/d

Million British thermal units per day

MT

Metric Ton

MTG

Methanol to gasoline

MW

Megawatts

NA

Not Available

NAG

Non-Associated Gas (not associated with oil production)

NGL

Natural Gas Liquids – ethane, propane, butane and pentane plus

OPEX

Operating expense

Offshore Nova Scotia

Sable Island, Laurentian Sub Basin and the deepwater plays

SMR

Steam methane reforming

Tcf

Trillion cubic feet

US$

U.S. Dollar


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Exhibit I Gas Processing


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1.0

GAS PROC ESSING

Gas processing margins were evaluated based on the following assumptions: Assumption

Parameter Gas Price

:

Varied from US $0.0 to $3.00 per MMBtu’s

Oil Price

:

Varied from US $15 to $30 per barrel

Propane Price

:

Based on 75% of oil price

Butanes Price

:


Pentanes Plus Price

:


Plant Fuel Consumption

:

1.5% of inlet gas volume

LPG Transportation Costs

:

4 cents per gallon

Operating Costs

:

Based on 3 cents per inlet MCF

Ethane Recovery

:

None

Propane Recovery

:

95%

Butanes Plus Recovery

:

99.5%

Gas Composition

:

1116.7 Btu/scf based primarily on White Rose – Ben Nevis Gas Cap N-22

All of these assumptions have an effect on processing margins. The gas processing margin is the difference between the value of the inlet BTU’s compared to the value of plant liquids and the residue gas. In this study the value of the gas was varied from US$0.00 - $3.00/MMBtu, with a constant oil price of $US 19.60/bbl to demonstrate the effect that gas pricing has on the processing margin. The results, based on an inlet plant volume of 500 MMscfd are as follows:


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Table EI.1 Effect of Gas Pricing on Processing Margin Gas Price (US$/MMBtu)

Processing Margin (US$/MCF)

Annual Revenue (US$ MM)

0.0

0.429

78.2

1.0

0.279

51.0

2.0

0.13

23.7

3.0

-0.019

-3.5

As can be easily seen, the higher the value of the gas, the lower the gas processing margin. Similarly, the oil price has a dramatic effect on processing margins. Based on the same assumptions above, except to vary the oil price (i.e., varying the LPG prices) and holding the value of the gas constant at US$2/MMBtu, the processing margins vary as follows: Table EI.2 Effect of Oil Pricing on Processing Margin Oil Price (US$/Bbl)

Processing Margin (US$/MCF)

Annual Revenue (US$ MM)

15

0.01

1.8

20

0.141

25.7

25

0.271

49.5

30

0.402

73.4

Sensitivities can be run on the many variables to see the effect they have on processing margins. For example, plant fuel consumption may be as high as 3.0% of the plant inlet, operating costs could be 4 cents per inlet MCF (Sable plant OPEX is 3.8 cents/Mcf), and LPG transportation may be as high as 5 cents per gallon. If these three variables are realized, it could result in increased annual costs of US$ 10.2 MM/yr. Another very important variable is the gas composition. In comparison to the Sable gas compositions (SOEP website) the White Rose compositions are very similar. However, if the inlet gas stream is more like Terra Nova, which has a Btu value of 1263 Btu/scf, the additional plant profit (based on $19.60/bbl oil price and $2.00/MMbtu gas price) is approximately US$ 39 MM/yr. Normally, all but two of the variables can usually be fixed, controlled or contractually agreed to at the beginning of a project. The two variables that typically can not be controlled are the gas price and the liquid prices, which are dictated by the market.


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Exhibit II Offshore CNG


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Offshore Compressed Natural Gas 1.0

OVER VIEW For the Compressed Natural Gas (CNG) concept, the development scenarios considered for the Jeanne d’Arc Basis are as follows: • Combined Gas/Oil Hub There is substantial merit for considering an oil and gas hub in the Jeanne d’Arc Basin. From a technical standpoint, either a GBS or FPSO could provide the means for this type of development. This facility would gather available oil and gas from the various fields in the Jeanne d’Arc Basin, and process the production to make them suitable for export to refinery’s and natural gas markets. Services such as field operations, gas processing, gas reinjection / gas storage could all be provided. This type of infrastructure could allow the smaller fields which might otherwise be uneconomic, to become viable projects in the future. For this analysis, the hub facility would be capable of handling 100,000 BOPD, injection of 160,000 BWPD, and gas injection compression for 250 MMscfd (up to 5,600 psig) and gas sales compression for 500 MMscfd (up to 3,000 psig). • Gas Hub Similar to the Gas/Oil Hub mentioned above, either a strategically located GBS or FPSO could be a hub for gathering only natural gas and/or gas condensate, with the option of providing gas processing. • Existing GBS Hub There is the possibility that Hibernia could make the necessary modifications that would allow this facility to gather natural gas from other developments in the Jeanne d’Arc Basin. This would require rigorous evaluations and studies to determine if this is possible, and when it would be possible. Hibernia may not be ready to make modifications until 2010 or later. • CNG Carriers This analysis was based upon the Cran and Stenning Coselle CNG concept. Other options are Lorica’s Composite Fiber Vessel concept which has the advantage of significant weight savings, and the SMT dense phase concept. The Coselle CNG carrier is essentially a double-hulled bulk carrier with its holds filled with “Coselles”. A Coselle is a huge carousel made up of 9.9 miles of 6.625-inch diameter pipe,


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rolled up in the shape of a compact cylinder. Each Coselle has a diameter of 50 feet , a height of 11.25 feet and weighs 445 tonnes. A Coselle CNG carrier capable of transporting 330 MMscf of gas would require 108 Coselles loaded into a Panamax (60,000 DWT) sized ship. This is the size of carrier on which Cran and Stenning have conducted most of their detailed work. A CNG carrier capable of transporting 540 MMscf of gas would require 180 Coselles and a vessel of approximately 100,000 DWT would be required. 2.0

PROD UCTION PROF ILE

2.1

THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS The production profile indicates that daily production of approximately 500 MMscfd can be expected for the next 15 to 20 years. In addition, the CNG carrier concept may be reaching its practical upper limit capacity of 180 Coselles, or 540 MMscfd per carrier, in a 100,000 DWT vessel. Theoretically, the CNG carrier could be installed on a larger 200,000 DWT vessel, but no work has been done on anything of this size, and the dry weight of such a vessel would be a major concern.

2.2

GAS QUAL ITY The gas quality is of little concern to the CNG carrier. The richer and cooler (i.e., denser) the gas the better as far as the amount of BTU’s the CNG carrier can transport. However, quality of the gas is very important to the gas purchaser. If the gas is being sold into a pipeline grid, there are possible restrictions on the quality of gas. Typically the gas must meet the following minimum requirements: Maximum BTU/scf

<

1,180, but many pipelines do not stipulate

Minimum BTU/scf

>

975

Water Content

<

7 lbs/Mcf

CO2 Content

<

2%

H2S Content

<

4 ppm or 1/4 grain

N2

<

3%

O2

<

0.1%

The dehydrated NF gas would seem to have no problems meeting the gas quality specifications for most pipelines and transmission lines. The NF gas is sweet (i.e., virtually no H2S and low


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CO2) and has low nitrogen and oxygen content. With possible gas processing upstream of the CNG loading facilities, this gas will be ideal for export into virtually any gas market. 2.3

GAS VS. O IL PROD UCTION RATE S Based on production profiles from the Jeanne d’Arc Basins, the gas rates of approximately 500 MMscfd are expected, with corresponding oil and condensate production rates up to approximately 92,000 barrels per day based on a simultaneous oil and gas development. These rates were based on recoverable reserve and GOR (gas to oil ratio) estimates published by the C-NOPB with the production profile estimated by Worley in lieu of no other forecasts being available. This excludes oil and condensate production from Hibernia, Terra Nova, Hebron, and other developments with little or no estimated gas reserves. For this study, only the liquid production associated from wells tied back to the “hub”, and not part of a main oil development, will be credited towards the economics.

3.0

TYPE OF PROD UCTION SYST EM Either a fixed gravity-based structure (GBS) or a floating production, storage and offloading vessel (FPSO) could be used for the development of natural gas, offshore Newfoundland. Precedence has been made with both options, although the use of FPSO’s as hubs is limited. The most recent FPSO “hub” project is the Triton FPSO that is nearing completion in the North Sea. Three (3) fields approximately 35 kilometers apart will be processed at a centrally located FPSO, with gas sales via a 12 kilometer export line to a main gas trunkline. In addition to the options for a new FPSO or GBS, there is potential to use the Hibernia GBS as a natural gas hub. Extensive modifications would have to be made, and there has been little, if any, work done to determine the extent of the modifications, or when the modifications could start taking place. An estimate has been made for the cost of the modifications, but without further work this cannot be confirmed. The CNG carrier concept is based on an APL (Advanced Production and Loading AS, Norway) STL mooring system. The CNG ships are proposed to be equipped with dynamic positioning suitable for EC operations. In addition, the CNG vessels do have the flexibility to be deployed to other locations offshore NF or around the world. Dual mooring systems at each site would be required to provide continuous production.

4.0

PROC ESSING REQU IREMEN TS The need for gas processing is based on either (1) gas quality specifications required by the gas purchaser, (2) the economic benefits of recovering the ethane, propane, butanes and condensate


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from the gas, or (3) the need to process a retrograde reservoir. Since the NF gas, after dehydration, is pipeline quality, the only reason for gas processing is for economic benefits or retrograde processing. Based on the ICF market report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland” (Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 per MMBtu in the Northeast U.S., and that crude oil prices reach C$ 26.71/bbl, a “net” processing margin loss of C$ 0.001 /MCF would be realized. This margin would not be enough to justify a gas processing facility. If the gas were valued at C$ 0.0 (i.e., had no value) the net processing margin would be in the range of C$ 0.56/MCF. 4.1

FPS O G A S P R O C E S S I N G Offshore gas processing has been done on several fixed platforms and near-shore barges. However, the authors are not aware of gas processing being performed on an FPSO. There is one FPSO project that has a debutanizer to remove the heavier hydrocarbons in the gas prior to reinjection, but this is only a small part of a complete gas processing plant. Several companies are considering gas processing on FPSO’s, with the performance of the fractionation columns being a major concern in rough seas. However, if the fractionation column manufacturers will warrant their performance on an FPSO, then the major obstacles will have been removed. Producing a Y-grade product (i.e., a combined propane, butane and condensate liquid product) for fractionation at an onshore facility like Point Tupper may be more practical than offshore fractionation. The complexity issues with regards to storage of the various products, offloading various products, along with the performance of the columns, will drive this decision.

4.2

FIXE D STRU CTURES Gas processing on fixed structures can be done, provided there is enough deck space for the gas plant and storage for the LPG.

4.3

ONSH ORE GAS PROC ESSING Onshore gas processing, based on offloading the CNG carriers and then processing the gas prior to delivery of gas into a pipeline grid, will not be practical, unless offloading into a gas storage facility. The reason for this is to minimize the number of ships required by depressurizing the CNG carriers as quickly as possible, possibly in as little time as 12 hours. In many instances, there may not be a full CNG carrier to immediately succeed behind an empty one. Thus, flow


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rate variations of 0 – 1,000 MMscfd could be common place. These “batch” operations would make gas plant operations impractical. 5.0

TRAN SPORTA TION MODE S Each CNG ship would have a cruising speed of 15.5 knots. The distance from the Grand Banks to Boston is approximately 955 nautical miles. Thus, it takes 2.5 days to travel each way, and it takes 24 hours to load a ship, and 12 hours to off-load. The analysis assumed that the CNG carriers would take the gas directly to the Northeast U.S. Thus, this case would require seven ships and receive a gas price of approximately C$ 4.00/MMBtu’s. This would result in a CNG charter rate (i.e., transportation) of C$ 255 MM/year, which equates to approximately C$ 1.27/MMBtu’s. If an eighth ship is required, the charter rate would increase to approximately C$ 1.57/MMBtu. Another option is to supply NF with gas. One additional ship would be required initially, supplying gas to the North Atlantic Refinery at approximately 50,000 MMBtu/d. This would require approximately 11 days to de-pressure a CNG ship, assuming there is no gas storage. This would result in a transportation cost of approximately C$ 2.00 /MMBtu for the extra CNG ship required to supply gas to the refinery. However, this cost would come down with the growth of a gas industry. In addition, if gas storage was available, the transportation cost could fall to C$ 1.27/MMBtu’s. Since there is no known salt or reservoir storage nearby the Placentia Bay, ground storage would have to be built. Another alternative would be to deliver the gas to Nova Scotia into the Maritimes and Northeast Pipeline, for transport to markets in Canada and the northeast U.S. The distance from the Grand Banks area to Point Tupper is approximately 625 miles, requiring only five (5) ships, and lowering the transportation cost to C$ 0.91/MMBtu’s. Of interest is the possibility of gas storage being available in Point Tupper by Statia Terminals. Gas storage bundled with firm gas capacity through the Maritimes and Northeast Pipeline stakeholders could be an attractive alternative to landing gas in the U.S.

5.1

NEWF OUNDLA ND GAS SUPP LY The NF gas market would demand a reliable fuel gas supply, capable of handling load swings throughout the day and night. With an estimated average residential, commercial, industrial, and electric utility load of approximately 100 MMscfd (ICF market report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland” (page 2)) by 2010, it would take each ship approximately five days to completely deliver its gas supply. If gas storage is available, the gas could be off-loaded in 12 hours, dramatically increasing the utility of the CNG ships, and increasing the reliability of supply to the natural gas consumers.


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5.2

U.S . G A S S U P P L Y The CNG deliveries to the U.S. can be accommodated in several ways. CNG deliveries could be handled much like LNG deliveries, either into the U.S. pipeline grid or into “niche” markets, depending on what kind of sales contracts can be negotiated. However, due to the approximate 1,100-mile distance from the Grand Banks to the U.S. markets, it is not possible to deliver gas at a constant rate, or supply gas on a peaking basis, without gas storage or more CNG vessels. The gas will most likely have to be “batch” delivered to unload each ship as fast as possible in order to minimize the “turnaround” time and thus minimize the number of ships required. If ships are detained and can not return to the Grand Banks on a seven day turnaround, either additional ships will be required, or the produced gas will have to be flared, shut-in, or reinjected (the cost estimates provide for gas reinjection capability).

6.0

NEWF OUNDLA ND INFR ASTRUC TURE REQU IREMEN TS There are two potential locations that may be suitable in Placentia Bay for a gas development. Both are in the general vicinity of the Newfoundland Transshipment Facility and North Atlantic Refining. Adams Head is a deep water site that was initially scheduled to be the site for construction of the Gravity Based Structure for Hibernia. As such, it would have the same general characteristic as Bull Arm. Rough grading of this site would probably cost in the order of C$150,000 per acre. An approximate 50 acre site would be required. Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. It would not require a lot of grading prior to development. To create a gas market in Newfoundland, both industrial and residential, a pipeline and distribution network would have to be installed to the main users. In addition, homes and businesses would have to be modified to receive natural gas and appliances replaced that can burn the natural gas. These costs have not been considered.

7.0

COST ING

7.1

C A P I T A L E X P E N S E (CA PEX) For each of the three production options, Capital Cost (CAPEX) estimates were prepared. For the “oil and gas” hub options, it was assumed that two new shuttle tankers and two new supply boats would be required. However, for the “gas only” hub options, it was assumed that existing field shuttle tankers were available nearby, and that the gas projects would only share in a portion of those operating expenses (OPEX).


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Well costs were included for both the “oil and gas” hub and “gas only” hub options. For the “oil and gas” hub cases, all wells from a primary development (16 producers and 8 injectors), plus fourteen (14) well tie-backs from satellite fields like Springdale (4 producers), Ben Nevis (2 producers), North Ben Nevis (2 producers), North Dana (4 producers), and South Mara (2 producers) were included. Six (6) of the primary development wells are assumed to be from the non-associated gas (NAG) reservoir. This gas would be the “swing” gas, necessary to make-up for the difference between the solution gas from oil wells and the 500 MMscfd required field rate. In addition, it was assumed that the NAG gas wells could be used for gas injection when required to keep the oil well gas from being flared during periods when gas exports were curtailed. For the “gas only” hub, the assumption was made that a GBS or FPSO would be located near the gas field, and only 6 additional gas wells were included in the well costs, plus the fourteen (14) gas wells from fields like Springdale , Ben Nevis, North Ben Nevis, North Dana, and South Mara as mentioned above. As mentioned earlier, the gas wells will provide “swing” gas to make-up for the difference between the solution gas from oil wells and the 500 MMscfd required field rate, and can also be used for gas injection. It was assumed that the gas wells from Springdale, Ben Nevis, North Ben Nevis, North Dana, and South Mara could be completed subsea and would produce at a high enough pressure to be flowed back to either the GBS or FPSO for handling. Costs for these remote wells were estimated to be C$51.4 MM each, based on the fact that there is not the same synergy as drilling many wells in a major oil and gas field. Wells drilled from a GBS were considered “dry wells”, with estimated costs of C$18 MM each. Estimated costs to drill a “wet” well, at a primary development for an FPSO were estimated at C$36 MM each. An additional C$120MM was included in the FPSO Oil and Gas case to account for the costs of a turret or system capable of accommodating the high number of risers required.


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• FPSO Gas Hub Gas Hub FPSO, turret, mooring, etc.

:

C$

671,400,000

Well Costs (From various fields)

:

C$

936,000,000

CNG Vessels (7)

:

C$

Chartered

Subsea Costs (flowlines, glory holes, etc.)

:

C$

907,500,000

Topsides Equipment

:

C$

550,500,000

CNG Mooring, Offloading Berths, etc.

:

C$

172,900,000

Supply Boats

:

C$

70,000,000

:

C$

3,308,300,000

Oil and Gas FPSO, turret, mooring, etc.

:

C$

671,400,000


:

C$

1,536,000,000

CNG Vessels (7)

:

C$

Chartered


:

C$

1,140,700,000

Topsides Equipment

:

C$

761,500,000


:

C$

172,900,000

Shuttle Tankers

:

C$

230,000,000

Supply Boats

:

C$

70,000,000

:

C$

4,582,500,000

GBS Structure

:

C$

927,100,000


:

C$

874,300,000

CNG Vessels (7)

:

C$

Chartered

Subsea Costs (flowlines, umbilicals, etc.)

:

C$

810,200,000

Topsides Equipment

:

C$

715,700,000


:

C$

172,900,000

Supply Boats

:

C$

70,000,000

:

C$

3,570,200,000

Total • FPSO Oil and Gas Hub

Total • New GBS Gas Hub

Total


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• New GBS Oil and Gas Hub Oil and Gas GBS

:

C$

927,100,000


:

C$

1,236,000,000

CNG Vessels (7)

:

C$

Chartered


:

C$

1,140,700,000

Topsides Equipment

:

C$

939,500,000


:

C$

172,900,000

Shuttle Tankers

:

C$

230,000,000

Supply Boats

:

C$

70,000,000

:

C$

4,716,200,000

Total 7.2

O P E R A T I N G E X P E N S E (OP EX) The OPEX for the various options are based on operating costs for Sable, Terra Nova and Hibernia as reported on the project websites, and based on other projects that Worley has been involved with. These costs do not include the value of any gas consumed as fuel. The OPEX for an FPSO and a GBS is assumed to be about the same, except for the marine crew and well intervention costs. The “dry” wells are less expensive to workover than “wet” wells. Well intervention costs for subsea wells are estimated based on a rig with a rate of C$ 400,000 per day. For the “gas hub” cases, 30 days per year were assumed for well intervention work. For the “oil and gas hub” cases, it was assumed that well intervention work would be required 60 days per year due to the higher number of wells. For the new GBS, approximately half of the wells are assumed to be dry and can be worked over by a platform rig. The costs allocated to well intervention are therefore only for the workover of the subsea gas wells and is assumed to be 15 days per year. The CNG Charter Party rates of C$36.43 MM/yr were furnished by Cran and Stenning, who obtained their estimates from Maersk, and were verified by calculating the unit cost based on an 8% financing rate. The charter party rate was based on (1) CNG ship cost estimates of C$267 MM each, and (2) annual operating costs for each ship estimated to be C$4.96 MM, assuming a Canadian crew, based on LPG ship operating costs.

A possible 25% duty was not considered in the economics.


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• FPSO Gas Hub (average yearly OPEX) FPSO

:

C$

48.8 MM/yr

Shuttle Tankers

:

C$

13.9 MM/yr

Supply Boat

:

C$

14.6 MM/yr

Transshipment Terminal

:

C$

2.4 MM/yr

CNG Charter Rate

:

C$

232.5 MM/yr

Well Workover Estimate Average

:

C$

15.8 MM/yr

CNG U.S. Delivery Cost (C$0.10/MMBtu)

:

C$

19.8 MM/yr

:

C$

347.8 MM/yr

Total

• FPSO Oil and Gas Hub (average yearly OPEX) FPSO

:

C$

51.1 MM/yr

Shuttle Tankers

:

C$

18.9 MM/yr

Supply Boat

:

C$

14.6 MM/yr


:

C$

8.0 MM/yr

CNG Charter Rate

:

C$

232.5 MM/yr


:

C$

27.8 MM/yr


:

C$

19.8 MM/yr

:

C$

372.7 MM/yr

GBS

:

C$

44.6 MM/yr

Shuttle Tankers

:

C$

13.9 MM/yr

Supply Boat

:

C$

14.6 MM/yr


:

C$

2.5 MM/yr

CNG Charter Rate

:

C$

232.5 MM/yr


:

C$

7.6 MM/yr

Total • GBS Gas Hub


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CNG U.S. Delivery Cost (C$0.10/MMBtu) Total

:

C$

19.8 MM/yr

:

C$

335.5 MM/yr

• GBS Oil and Gas Hub (average yearly OPEX) GBS

:

C$

46.7 MM/yr

Shuttle Tankers

:

C$

18.9 MM/yr

Supply Boat

:

C$

14.6 MM/yr


:

C$

8.0 MM/yr

CNG Charter Rate

:

C$

232.5 MM/yr


:

C$

15.8 MM/yr


:

C$

19.8 MM/yr

:

C$

356.3 MM/yr

Total 7.3

ANNU AL EMPL OYMENT • CNG Carrier Each carrier would require a crew of 20, so that on an annual basis, 40 people would be required. Considering the need for seven ships plus administration, the CNG Carrier operation would require a staff of around 300. In addition, service requirements for maintenance, catering, tugs, and the like would have a cascade effect on personnel required. • FPSO Operation FPSO: The marine crew is estimated at 40 employees on an annual basis. Oil and gas operations and catering is estimated at another 70 annual employees. Shuttle Tankers: For the cases that require shuttle tankers, an estimated 80 employees would be required to man the two (2) shuttle tankers on an annual basis. Supply Vessel: An estimated 48 employees would be required to man the two supply vessels on an annual basis. Support Staff: Management staff, secretarial, accounting, procurement, engineering support, etc. would be estimated at 25 annual employees.


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Drilling, Workover, Production Operations: Unknown • GBS Operation GBS: Production operations and catering is estimated at 60 annual employees. Shuttle Tankers: For the cases that require shuttle tankers, an estimated 80 employees would be required to man the two (2) shuttle tankers on an annual basis. Supply Vessel: An estimated 48 employees would be required to man the two (2) supply vessels on an annual basis. Support Staff: Management staff, secretarial, accounting, procurement, engineering support, etc. would be estimated at 25 annual employees. •

Gas Plant Operations If a gas plant were justified, an estimated additional 20 annual employees would be expected for operations.

7.4

CAPT URE RATE S •

Vessels: FPSO, Shuttle Tankers, CNG Vessels, Supply boats The ships would most likely be built in Asia, as they seem to be the most competitive ship builders in the world. However, the authors feel that Bull Arm modifications could be made that would allow the construction of several vessels to occur. An investment of C$100 MM or more would be required, but the long term payoffs could be well worth the investment if numerous new ships were to be required for offshore, and hat they could be built competitively. The smaller ships could be built at Irving Shipbuilding, if they were competitive.

•

GBS Construction The GBS could be built at Bull Arm.

•

Topsides Equipment Most of the topsides equipment could be built at Bull Arm.

•

CNG Coselles or Composite Vessels The coselles would most likely be fabricated near the pipe manufacturers, but could be built in Newfoundland at a slight cost premium. Cran and Stenning estimated that Canadian fabrication of the Coselles would add approximately 20% to the cost of each CNG carrier


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If composite vessels were utilized, a new facility would have to be built capable of producing large quantities of vessels. This facility could be built at Bull Arm or other locations in Newfoundland. 8.0

TECH NOLOGY STAT US

8.1

CNG C A R R I E R S The technology is patented and has tremendous potential for worldwide commercial application. However, there is no commercial application to date. This concept applies existing technology in a new and creative way. The technology involved is basically the same as one would find on a FPSO and a pipeline. The high-pressure swivels, flexible pipe, quick connects, etc. all have been designed and are commercially available. The design of a CNG carrier is relatively “low tech”. Cran and Stenning have had DNV and ABS examine the concept. DNV, who carried out the safety study, concluded that “a (Coselle) CNG ship is at least as safe as other gas ships” and can be classed and allowed to trade as other gas ships (i.e., LNG and LPG). ABS provided the classification guidelines for the vessel, which means that the Coselle CNG ship can be classed and registered as an ABA A1 E “Gas Carrier”. The only new technology is the way in which the pipe is wound. It is a spiral style versus a reel style, which would be typically found on a pipelay ship. However, this is of minor significance.

8.2

G A S P R O C E S S I N G O N FPS O’ S As mentioned previously (Exhibit II, Section 4.1), there are currently no FPSO’s with full gas processing (fractionation) capability. However a debutanizer column is installed and operating successfully on the Laminaria-Corallina in Australia, and Air Products have installed facilities for cryogenic distillation of oxygen from air for the North Sea severe sea states with very good results. Further work will be required to prove this concept is acceptable in the sea states in the Jeanne d’Arc Basin.

8.3

FLOW ASSU RANCE The subsea production to the FPSO, and future gas production tie-backs from Ben Nevis, Springdale, etc. would need dehydration or methanol injection to keep hydrates from forming. Oil production would be of more concern depending on the cloud point and pour point of the crude. The dehydrated gas from Terra Nova and Hibernia is not considered to be an issue.


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Exhibit III Onshore CNG


Page EIII - 1

065/07129 : Rev 5 : 7-Dec-00


Onshore Compressed Natural Gas 1.0

OVER VIEW The onshore CNG concept is based on the possibility of a gas pipeline being built from the Grand Banks area to Newfoundland. Once the gas reaches Newfoundland, except for a small portion of the gas being utilized in Newfoundland, the excess gas will still be stranded and will require a means to be monitized. The Onshore CNG option evaluates a method of transporting the excess gas from Newfoundland to markets in the northeast U.S. or other markets. The Coselle CNG carrier is essentially a double-hulled bulk carrier with its holds filled with “Coselles”. A Coselle is a huge carousel made up of 9.9 miles of 6.625-inch diameter pipe, rolled up in the shape of a compact cylinder. Each Coselle has a diameter of 50 feet and a height of 11.25 feet and weighs 445 tonnes. A Coselle CNG carrier capable of transporting 330 MMscf of gas would require 108 Coselles loaded into a Panamax (60,000 DWT) sized ship. This is the size of carrier that Cran and Stenning have conducted most of their detailed work around. A CNG carrier capable of transporting 540 MMscf of gas would require 180 Coselles, and a vessel of approximately 100,000 DWT would be required. Costs for a project of this size have been scaled up from the 330 MMscf CNG carrier cost estimates, with the help of Cran and Stenning.

2.0


2.1

THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS The production profile indicates that daily production of approximately 500 MMscfd can be expected for the next 15 to 20 years. In addition, the CNG carrier concept may be reaching its practical upper limit capacity of 180 Coselles, or 540 MMscfd per carrier, in a 100,000 DWT vessel. Theoretically, the CNG carrier could be installed on a larger 200,000 DWT vessel, but no work has been done on anything of this size, and the dry weight of such a vessel would be a major concern.

2.2

GAS QUAL ITY The gas quality is of little concern to the CNG carrier. The richer and cooler (i.e., denser) the gas the better in regards to the amount of BTU’s the CNG carrier can transport. However, the quality of the gas is very important to the gas purchaser. If the gas is being sold into a pipeline grid, there are possible restrictions on the quality of gas. Typically, the gas must meet the following minimum requirements:


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Maximum BTU/scf

<

1,180, but many pipelines do not stipulate

Minimum BTU/scf

>

975

Water Content

<

7 lbs/Mcf

CO2 Content

<

2%

H2S Content

<

4 ppm or 1/4 grain

N2

<

3%

O2

<

0.1%

The dehydrated NF gas would seem to have no problems meeting the gas quality specifications for most all pipelines and transmission lines. The gas is sweet (i.e., virtually no H2S or CO2) and has low nitrogen and oxygen content. With possible gas processing upstream of the CNG loading facilities, this gas will be ideal for export into virtually any gas market. 2.3

GAS VS. O IL PROD UCTION RATE S For this case, the gas is coming from a pipeline and oil production is not applicable.

3.0

TYPE OF PROD UCTION SYST EM The type of production system is not applicable for this case.

4.0

PROC ESSING REQU IREMEN TS The need for gas processing is based on either (1) gas quality specifications required by the gas purchaser, or (2) the economic benefits of recovering the ethane, propane, butanes and condensate from the gas. Since the NF gas, after dehydration, is pipeline quality, the only reason for gas processing is for economic benefits. Based on the ICF market report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland” (Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 per MMBtu in the Northeast U.S., and that crude oil prices reach C$ 26.71/bbl, a “net” processing margin loss of C$ 0.001 /MCF would be realized. This margin would not be enough to justify a gas processing facility. If the gas were valued at C$ 0.0 (i.e., had no value) the net processing margin would be in the range of C$ 0.56/MCF.

5.0

TRAN SPORTA TION MODE S The analysis assumed that the CNG carriers would take the gas directly to the Northeast U.S. This case would require six (6) ships and receive a gas price of approximately C$


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4.00/MMBtu’s. This would result in a CNG Charter Party rate (i.e., transportation) of C$36.4 MM per year per CNG carrier, which equates to C$ 1.09/MMBtu’s. CNG deliveries could be handled much like LNG deliveries, either into the U.S. pipeline grid or into “niche” markets, depending on what kind of sales contracts can be negotiated. However, due to the 910-mile distance from NF to the U.S. markets, it does not seem practical to build enough ships to deliver a constant rate of 500 MMscfd, or supply gas on solely a peaking basis. The gas will most likely have to be “batch” delivered to unload each ship as fast as possible after arrival in order to minimize the “turnaround” time and thus minimize the number of ships required. Another alternative would be to deliver the gas to Nova Scotia into the Maritimes and Northeast Pipeline, for transport to markets in Canada and the northeast U.S. The distance from Argentia to Point Tupper is approximately 380 miles, requiring only four (4) ships, and lowering the transportation cost to C$ 0.73/MMBtu’s. Of interest is the possibility of gas storage being available in Point Tupper by Statia Terminals. Gas storage, along with favorable firm gas capacity and transportation rates from the Maritimes and Northeast Pipeline stakeholders could be an attractive alternative to landing gas in the U.S. 5.1

NEWF OUNDLA ND GAS SUPP LY The estimated average residential, commercial, industrial, and electric utility load will be approximately 100 MMscfd (ICF market report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland” (page 2)) by 2010. The NF gas market would demand a reliable fuel gas supply, capable of handling load swings throughout the day and night, and handling varying rates from summer to winter. A long pipeline system, via its unique “line pack” capability, offers needed flexibility with regards to gas delivery rates. Gas consumption on NF will likely increase with the assurance of a guaranteed, long term, gas supply. Other commercial ventures (i.e., methanol plants, ammonia or fertilizer plants, steel plants, etc.) utilizing large amounts of natural gas may be attracted to NF once the major infrastructure is in place and the commodity price is attractive.

6.0

INFR ASTRUC TURE REQU IREMEN TS Two potential locations that may be suitable for a gas development are in Placentia Bay. Both are in the general vicinity of the Newfoundland Transshipment Facility and North Atlantic Refining: Adams Head is a deep water site that was initially scheduled to be the site for construction of the Gravity Based Structure for Hibernia. As such, it would have the same general


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characteristic as Bull Arm. Rough grading of this site would probably cost in the order of C$150,000 per acre. An approximate 50 to 60 acre site would be required. Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. It would not require a lot of grading prior to development. To create a gas market in Newfoundland, both industrial and residential, a pipeline and distribution network would have to be installed to the main users. In addition, homes and businesses would have to be modified to receive natural gas and appliances replaced that can burn the natural gas. These costs have not been considered. 7.0

COST ING

7.1

C A P I T A L E X P E N S E (CA PEX) It is assumed that the CNG vessels would be built, owned and operated by a third party ship owner on a lease or charter basis. Therefore, the only capital costs would be what is required for the onshore facility in Newfoundland and the off-loading berth and equipment at the delivery site in the U.S. The Newfoundland onshore facilities would require compression equipment to compress the gas from approximately 720 psig to 3,100 psig, gas metering equipment, and miscellaneous equipment to handle small amounts of liquid, rain water run-off, chemical storage, utilities, fire and safety equipment, etc. In addition, a CNG vessel loading terminal capable of berthing two vessels would be required. If a gas plant is warranted, an onshore gas plant is estimated at C$330 MM (US$231 MM). The CNG delivery site would require an off-loading terminal for one ship, plus equipment for gas heating, metering, compression, chemical storage, safety equipment, etc. See page A3-56 for CAPEX cost details.


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• Onshore CNG NF Onshore Berthing Facilities

:

C$

28,571,000

U.S. Onshore Berthing Facilities

:

C$

28,571,000

Miscellaneous Onshore Equipment/Civil

:

C$

42,857,000

Additional Compression

:

C$

157,143,000

Project Management, Engineering, Overhead

:

C$

40,000,000

:

C$

297,142,000

Grand Total 7.2

O P E R A T I N G E X P E N S E (OP EX) The OPEX for the various offshore facilities are based on operating costs for the Sable, Terra Nova and Hibernia as reported on the project websites. These costs do not include the value of any gas consumed as fuel. The CNG Charter Party rates were furnished by Cran and Stenning, who obtained their estimates from Maersk, and verified by calculating the unit cost based on a 8% financing rate. CNG Charter Party – 6 ships

:

C$

218.6 MM/yr

CNG Onshore OPEX

:

C$

6.7 MM/yr

Gas Compression OPEX

:

C$

3.6 MM/yr

CNG U.S. Delivery Cost

:

C$

18.7 MM/yr

:

C$

247.6 MM/yr

Total 7.3

ANNU AL EMPL OYMENT • CNG Carrier Each carrier would require a crew of approximately 20 per rotation. Considering the need for six ships plus administration, the CNG Carrier operation would require a staff of around 260 on an annual basis. In addition, service requirements for maintenance, catering, tugs, and the like would have a cascade effect on personnel required. • Onshore Facilities Each facility would require approximately 20 people on an annual basis, totaling 40 people per year.


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•

Gas Plant If a gas plant were required, the gas plant would require approximately 40 annual employees.

• CNG Carrier Fabrication The most competitive shipbuilders are located in Asia. The pricing for the CNG Carriers are based on Asian fabrication. However, the authors feel that Bull Arm modifications could be made that would allow the construction of several vessels to occur. An investment of C$100 MM or more would be required, but the long term payoffs could be well worth the investment if numerous new ships were to be required for offshore, and if the ships could be built competitively. The Coselles could be built in Newfoundland. Cran and Stenning estimated that Canadian fabrication of the Coselles would add approximately 20% to the cost of each CNG carrier. 7.4

CAPT URE RATE S •

CNG Tanker Construction Again, the ships would most likely be built in Asia, however, some of the ships could be built at Irving Shipbuilding if they were competitive. The coselles would have to be fabricated near the pipe manufacturers, and this could be done in Newfoundland.

•

Onshore Facilities Most all of the operations could be manned from the people in Newfoundland. The capture rate for gas production and gas processing equipment could be very high as most of the equipment could be sourced and built within Canada. Compression equipment would most likely have to be built outside Canada, however.

8.0

TECH NOLOGY STAT US

8.1

CNG C A R R I E R S The technology is patented and has tremendous potential for worldwide commercial application. However, there is no commercial application to date. This concept applies existing technology in a new and creative way. The technology involved is basically the same as one would find on a FPSO and a pipeline. The high-pressure swivels, flexible pipe, quick connects, etc. all have been designed and are commercially available.


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The design of a CNG carrier is relatively “low tech”. Cran and Stenning have had DnV and ABS examine the concept. DnV, who carried out the safety study, concluded that “a (Coselle) CNG ship is at least as safe as other gas ships” and can be classed and allowed to trade as other gas ships (i.e., LNG and LPG). ABS provided the classification guidelines for the vessel, which means that the Coselle CNG ship can be classed and registered as an ABA A1 E “Gas Carrier”. The only new technology is the way in which the pipe is wound. It is a spiral style versus a reel style, which would typically be found on a pipelay ship. However, this is of minor significance. The CNG concept is an integration of various existing technologies for a new transport method. Although this concept has not been utilized offshore, there are no other foreseeable technical reasons preventing the concept to work except for the weight of the coselles, which is a concern. A 500 MMscfd ship would contain 180 coselles, each weighting 445 tonnes. Including the weight of the piping manifolds, compression, fire and safety equipment, etc., the total weight of the equipment and coselles will be in excess of 81,000 tonnes. The ability to dry dock a ship with this dense weight is a concern. Other means of inspection would have to be agreed with certification authorities prior to fabrication, which is a realistic expectation. Another possible solution to reduce the overall weight is to consider Lorica’s offshore technology patented Carbon Composite Pressure Vessels, in lieu of the coselles.


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Exhibit IV Onshore LNG


Page EIV - 1

065/07129 : Rev 5 : 7-Dec-00


Onshore Liquefied Natural Gas 1.0

OVER VIEW The onshore LNG concept is based on the possibility of a gas pipeline being built from the Grand Banks area to Newfoundland. However, except for a small portion of the gas being utilized in Newfoundland, the excess gas will still be stranded, and require a means for monitization. This Onshore LNG option evaluates a method of transporting the excess gas from Newfoundland to markets in the northeast U.S. or other economic markets. The LNG plant analysis has been fashioned around the Atlantic Liquefied Gas Plant (ALNG) in Trinidad. Details from other LNG projects have been utilized where appropriate.

2.0


2.1

THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS This analysis will be based on an LNG plant with capacities of 490,000 MMscfd. LNG plant capacities have virtually no limit as additional “LNG trains” can be added as required.

2.2

GAS QUAL ITY Upstream gas processing may be economic and may be necessary to extract out the butane and/or heavier components, if their concentration is high enough to cause freezing problems. Gas treating for CO2 and mercury removal is also required.

2.3

GAS VS. O IL PROD UCTION RATE S For this exercise, the 490 MMscfd of gas is coming from an offshore pipeline, and oil production is not applicable.

3.0

TYPE OF PROD UCTION SYST EM For this exercise, the gas is coming from an offshore pipeline, and the type of production system is not applicable.

4.0

PROC ESSING REQU IREMEN TS The need for gas processing is based on either (1) potential for the heavier components to cause freezing problems, or (2) the economic benefits of recovering the ethane, propane, butanes and condensate from the gas. Based on the ICF report “Market Analysis of Natural Gas Resources Offshore Newfoundland” (Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 per MMBtu in the


Page EIV - 2

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Northeast U.S., and that crude oil prices average around C$ 26.71, a “net” processing margin loss of C$ 0.001 /MCF would be realized. This margin would not justify a gas processing facility. If the gas was valued at C$ 0.0 per MMBtu (i.e., had no value) the net processing margin would be in the range of C$ 0.56/MCF. See the Gas Processing Section for more details. 5.0

TRAN SPORTA TION MODE S With gas delivery points in the northeast United States approximately 1,100 miles away, LNG carriers may be an attractive alternative to laying a pipeline to these markets. An LNG ship would be required approximately every 4-5 days, based on 137,500 m3 LNG ships for inlet gas rates of 490 MMscfd. LNG ships and regasification facilities are often times supplied by the LNG purchasers. Based on the ICF report “Market Analysts of Natural Gas Resources Offshore Newfoundland”, estimated LNG and re-gasification costs are C$0.65/Mcf (US$0.45/Mcf) to U.S and Europe. It was assumed that these costs were based on existing LNG ships and re-gasification facilities. However, there is a real concern that these costs could increase significantly if new LNG ships and new re-gasification facilities are required. The cost of a 137,500 m3 LNG ship is in the US $175 – 200 MM range (Oil & Gas Journal, Dec. 6, 1999, pg. 62). At the point of delivery, re-gasification facilities are required. If a gas purchaser must build these facilities, reported costs of US$300 - 500 MM can be expected for deliveries of 500 MMscfd (3 MMTPA), depending to a large extent on the required port and site improvements necessary. For the purpose of this study, regasification and transportation costs of C$ 1.00/MMBtu were assumed.

6.0

INFR ASTRUC TURE REQU IREMEN TS Two potential locations may be suitable in Placentia Bay for a gas development. Both are in the general vicinity of the Newfoundland Transshipment Facility and North Atlantic Refining: Adams Head is a deep water site that was initially scheduled to be the site for construction of the Gravity Based Structure for Hibernia. As such, it would have the same general characteristic as Bull Arm. Rough grading of this site would probably cost in the order of C$150,000 per acre. An approximate 50 - 60 acre site would be required. Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. It would not require a lot of grading prior to development. Due to millions of manhours required


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to construct an LNG facility, a construction camp would be required to support the estimated 3,600 man construction crew. For gas use in Newfoundland, a pipeline and distribution network would have to be installed to the main users. These costs have not been considered. 7.0

COST ING

7.1

C A P I T A L E X P E N S E (CA PEX) The cost of an LNG plant that can liquefy 490 MMscfd of gas is summarized as follows: • LNG Plant Costs LNG Plant – 490 MMscfd

:

C$

1,174,750,000

Construction Camp

:

C$

164,250,000

Project Management, Finance, etc.

:

C$

214,000,000

:

C$

1,553,000,000

LNG Total These costs do not include the following: • LNG ships (will be chartered).

• LNG re-gasification facilities (shown as OPEX based on cost per MMBtu’s). 7.2

O P E R A T I N G E X P E N S E (OP EX) The OPEX for the various options are based on the operating costs of the ALNG plant. These costs do not include the value of any gas consumed as fuel.

LNG Plant LNG Plant OPEX

:

C$/yr

64,286,000

LNG Transportation and Regasification

:

C$/yr

173,000,000

:

C$/yr

237,286,000

LNG Total OPEX 7.3

ANNU AL EMPL OYMENT • Gas Plant Facilities A gas plant, if justified, could require an additional 40 annual employees.


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• LNG Plant Based on employment levels at the 3 MMTPA (475 MMscfd) ALNG plant in Trinidad, plant employees numbered 75, and the administration staff numbered 25. 7.4

CAPT URE RATE S The capture rate on development expenditures should be over 90% for operating expenses. Most all of the operations could be by Newfoundland employees. The capture rate for gas production and gas processing equipment could be very high as most of the equipment could be sourced or built in Canada. Compression equipment would most likely have to be procured from outside Canada. The capture rate for LNG plant construction should be very high. An estimated 14 million man-hours will be required to design and construct a 3 MMTPA plant.

8.0

TECH NOLOGY STAT US

8.1

LNG P L A N T S Onshore LNG plants have been in operation around the world for many years. There are several LNG processes, the most notable being the Phillips Optimized Cascade, Air Products LNG process, Black & Veatch Pritchard’s Prico process, and ABB Randall’s LNG.


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Exhibit V Offshore LNG


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Offshore Liquefied Natural Gas 1.0

OVER VIEW A number of floating LNG facilities have been proposed during the past few years. Most use dedicated vessels for the cryogenic facilities where the gas and condensate production facilities are on a separate structure, which may be piled, gravity base or floating. Although no LNG plants have yet been put offshore, the industry generally accepts that it is technically feasible to place them on ship-shaped vessels or on a fixed position, moored floating structure provided that the onboard equipment will operate properly with the expected motions of the structure. The ExxonMobil Floating LNG Plant is the focus of this analysis for the following reasons: • The plant details are available and the design includes co-production facilities for a gas/condensate field similar to N. White Rose. • Design confidence results from the fact that ExxonMobil has a long history of onshore LNG production and experience with the use of massive offshore concrete production facilities. • The concrete structure is designed so that the processing plant can continue to operate in very high sea states associated with a typhoon. The number of oil and gas discoveries, plus the potential for more discoveries offshore Newfoundland provides an opportunity for such a facility to be considered for producing gas condensate reservoirs and to use re-injected oil associated gas when it becomes available.

2.0

DESC RIPTIO N The hull structure is very large and made of concrete providing a great mass and proper dimensions for muting motions resulting from wave forces. The concrete structure is an excellent material to resist the effect of very cold temperatures associated with stored LNG. It measures 540 feet by 540 feet. It resembles a square doughnut where the central hole is used as a moon pool to receive risers from the seabed for delivery of produced gas and condensate. The facility is designed to separate gas, condensate and water, then condition the gas prior to its liquefaction. This procedure includes the removal of hydrogen sulfide, carbon dioxide and some NGL's. The gas is then dehydrated to a very low water content to prevent natural gas hydrate formation as it is cooled to minus 260°Fahrenheit. The C5+ portion of the NGL’s can be mixed with the produced condensate. The plan was reported to provide for liquefying of the LPG portion with methane and ethane for a specific client. The processing equipment was selected by ExxonMobil to minimize any effects of motion, so that production would seldom, if ever, be interrupted for weather reasons. The hull structure


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was designed for a maximum roll or pitch motion of 8 degrees single amplitude in 100-year return storm conditions including hurricanes West of Australia or at other Pacific Rim locations. This condition equates to a wave height of about 70 feet, which is similar to many wave heights in the Grand Banks area. The basic hull design type can tolerate larger wave heights in both operational and survival modes with little or no design modifications. It can be moored in water depths of up to 4,000 feet without consideration of redesign. Model tests in simulated sea state design conditions indicated a maximum roll or pitch motion of only 6.2 meters for the 100-year typhoon condition. Hull motions in predominant operating conditions will range between about 1 and 3 degrees single amplitude. The structure provides for warehousing, chemical storage and maintenance equipment. Necessary facilities are included for one day maintenance of complex areo-derivative engines, which are used for processing, that occurs only once each three years. Space is provided for gas booster compressors as field pressures decline. A 250-bed accommodation module is included, for 206 staff personnel. A basic double wall hull design provides for internal prefabricated LNG storage tanks having a total capacity of 250,000 cubic meters. The hull also provides for storage of 650,000 bbls of condensate. It provides for water for ballast, cooling and potable. Two LNG offloading facilities are supplied at opposite corners of the concrete structure to facilitate offloading of product in variable wind and wave directions in order to minimize LNG tanker delays and production down time. 3.0


3.1

THRE SHOLD VALU E OF GAS AND GAS LIQU IDS The facilities that were studied and designed by ExxonMobil can accommodate 500, 750, 1,000 and 1750 MMscfd size plants. The primary focus was 1,000 MMscfd of gas for 6 million metric tons per year of LNG. Their studies indicated that when scaling down to a 500 MMscfd facility, it should maintain near the same storage volumes of condensate and LNG for tanker shipping considerations. However, these precise storage volume features should be revisited at the final design stage to accommodate optimum offloading schedules for intended destinations and the selected LNG production rate. A 500 MMscfd size unit would allow for up to 20 days storage of condensate at about 55 bbls per MMscf production characteristic, which usually covers most gas condensate reservoirs. However, if necessary, the condensate storage can be modified at the time of final design to accommodate anticipated needs for any size facility.


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3.2

GAS QUAL ITY Facility sizing for the floating LNG unit included consideration of variable gas/condensate qualities and usual product specifications. Nevertheless, if something very unusual were to become known prior to fabrication, adjustments could very likely be made without a problem and would be handled in the normal course of final design activities. The initial use would likely be for a gas/condensate reservoir, which inherently contains less NGL's than oil associated gas. If the facility is subsequently used for large quantities of reinjected oil associated gas, relatively minor modifications to the gas processing equipment may be desired to accommodate more NGL extraction prior to liquefaction. The condensate storage provision for a gas condensate application will likely suffice for an oil-associated gas feed mode of operation.

3.3

GAS VS. O IL PROD UCTION RATE S The gas rate would not be predominately and directly related to simultaneous oil production. The initial gas feed would most likely come from a gas and condensate reservoir, where the condensate and gas would always be in a fairly constant proportion. Subsequent feed gas would likely come from one or more oil associated reservoirs from re-injected gas, such as Hibernia or Terra Nova. The gas would be produced when it is no longer needed for pressure maintenance of the reservoir for oil production, or when it can be replaced with water injection. Oil production would therefore not suffer from meeting optimum gas production rates. The ExxonMobil design basis was for up to 55 bbls of condensate per MMscfd of produced gas, which is greater than for most condensate production rates. If the actual condensate content of the gas is greater, adjustments could be made at the design phase of the project. If somewhat larger volumes of condensate were encountered after the facility is fabricated, the off-take of condensate would have to be more frequent than initially planned.

4.0

TYPE OF PROD UCTION SYST EM The production system is a floating concrete structure for fixed position mooring near gas production wells at a gas/condensate reservoir or from a reservoir where oil associated gas has been stored. The facility provides for onboard processing, liquification, storage and offloading of LNG and condensate. Provision could be made for storage and offloading LPG, if needed.


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4.1

R E S E R V O I R R E S E R V E S A N D F I N A N C I A L I M P L I C A T I O N S O F P O R T A B L E LNG PROD UCTION The floating LNG plant use must be for in excess of about 15 consecutive years to provide for optimum CAPEX utilization. The gas reserves suggest that a 500 MMscfd plant could operate at near full capacity if the reservoirs could produce at expected rates.

4.2

U T I L I Z I N G E X I S T I N G F A C I L I T I E S (H I B E R N I A GBS , T E R R A N O V A FPS O) Existing facilities like Hibernia and Terra Nova could supply gas at high enough pressures such that inlet compression for these gas streams would not be required.

4.3

U T I L I Z I N G S H A R E D S E R V I C E S (S U P P L Y B O A T S , H E L I C O P T E R S , S U P P L Y B A S E , PERS ONNEL) There is nothing unique with the floating LNG facility that would prevent operators from sharing services for shuttle tankers, supply boats, helicopter transportation, etc.

5.0

PROC ESSING REQU IREMEN TS

5.1

OFFS HORE V S. O NSH ORE PROC ESSING All the usual contaminants that must be removed from the gas that is to be liquefied, such as hydrogen sulfide, mercury, carbon dioxide and water vapor, can be easily removed offshore. NGL's can also be easily removed offshore where the C5+ fraction can be mixed with produced condensate. If more LPG's are removed than can be used as fuel, this potential can be established at the final design stage where provision can be made for them on the LNG facility before construction begins.

5.2

G A S C O M P O S I T I O N (GP M C O N T E N T ) If the gas has a high GPM (Gallons of Natural Gas Liquids per Mcf) content, as will possibly be the case when the facility is using oil-associated gas, it can be handled as indicated above.

6.0

TRAN SPORTA TION MODE S

6.1

F O R LNG A N D O T H E R L I Q U I D S LNG requires very specially designed cryogenic liquid carriers for transport from the floating unit, as is the case for onshore production of LNG. This fact is taken into account when establishing the economic viability of a LNG product. In the event that surplus propane and butane (LPG) is extracted, it can be transported to shore or to markets in pressured vessels of in refrigerated tankers, in the conventional manner.


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6.2

F I E L D - T O -M A R K E T V S . F I E L D - T O -O N S H O R E A N D T H E N O N S H O R E - T O -M A R K E T ExxonMobil's study indicated that the comparative cost for offshore liquefaction of gas was about 25% less than to first take the gas to shore. Their study basis was offshore West Australia where the cost of getting the gas to shore would probably be less than from the Grand Banks to Newfoundland because of weather factors.

7.0

INFR ASTRUC TURE REQU IREMEN TS No onshore facilities are needed other than for minimum requirements for movements of personnel and supplies.

8.0

COST ING

8.1

CAP EX V S . O PEX Receipt of specific information from ExxonMobil is pending. However, the costs used in the analysis are listed below. The costs were estimated by taking 75% of the estimated cost of the total facilities that would be required offshore Western Australia for 1 billion scfd of 1,116 BTU/ft3 gas. • CAPEX LNG Facility

:

C$

3,053,000,000

Well Cost

:

C$

1,536,000,000

Subsea Costs

:

C$

1,141,000,000

Shuttle Tankers

:

C$

230,000,000

Supply Boat

:

C$

70,000,000

:

C$

6,030,000,000

Total


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• OPEX LNG Facility

:

C$ MM/YR

92.3

Shuttle Tanker

:

C$ MM/YR

18.9

Supply Boat

:

C$ MM/YR

14.6

LNG Transportation and Regasification

:

C$ MM/YR

176.3

Well Workover

:

C$ MM/YR

24.0


:

C$ MM/YR

16.3

:

C$ MM/YR

342.4

Total 8.2

ANNU AL EMPL OYMENT Approximately 300 persons for a 500 MMscfd plant, including personnel for production.

9.0

TECH NOLOGY STAT US

9.1

EXIS TING, DESI GN OR CONC EPTUAL The processing technology is very mature. The ability to design massive concrete structures has been well proven. The ExxonMobil concrete structure has been modeled and tested in a marine basin for the effect of wave induced motions using well proven methods. The conceptual design was made from in-depth knowledge of process equipment operating onshore and with the knowledge gained from multiple large concrete GBS structures. Several oil operators, including ExxonMobil, as well as several reputable equipment suppliers have been involved in the detail design and testing of cryogenic LNG offloading mechanisms. The LNG facility would have to be designed to disengage and avoid an oncoming iceberg. The conceptual work has not been performed for this specific concept, but has been successfully engineered for other concepts, such as ship-shaped FPSO’s. As a result, the industry would likely consider the concept of a concrete floating LNG plant to be sufficiently proven to proceed while taking the customary precautions at the detail design stage.


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Exhibit VI Onshore GTL

TECHNICAL NONPIPELINE FINAL.doc

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Onshore Gas-to-Liquids • • • • 1.0

Methanol Syncrude Gasoline Diesel and Naphtha

OVER VIEW In the event that gas is delivered to onshore Newfoundland by pipeline, CNG or hydrates, a world scale methanol plant can be an option to provide onshore value added activities for a product to be exported. A portion of the product could be used as feedstock for potential secondary industries. A new plant located at Tjeldbergodden, Norway was selected for focus because of several similar circumstances to those for stranded gas offshore Newfoundland and because it represents a recent state-of- the-art plant. It also addresses current environmental issues that may escalate worldwide. Feed for the plant is oil-associated gas from a large offshore facility near the Arctic Circle. It is 200 km from shore but a 250 km pipeline route was selected to a landfall area where adequate infrastructure exists nearby and where a protected harbor with deep water exists. Due to the Gulf Stream, the harbor and adjacent seas are clear of ice. The gas could not be re-injected into its reservoir and re-injection into a nearby reservoir was found to be too costly. The gas could have been piped to the northern extremity of an extensive gas gathering pipeline system by adding about 400 km to the pipeline. Instead, a decision was made to use the relatively small portion of Norwegian gas for an onshore methanol plant. The pipeline was sized for about three times what was needed for the methanol plant. There is no significant local use for methanol. However, the shipping time to a central methanol market at Rotterdam, The Netherlands is only 50 hours. This shipping time is much less than from competitive plant locations in Russia, Libya, Chile, Venezuela and Trinidad. Competition for methanol from Newfoundland will probably be mostly from the U.S. Gulf Coast, where old plants convert gas at costs up to approximately US$ 2.70 per MMBTU’s. Most of those still operating are predicted to shut down when local gas costs reach about US$ 3.00 per MMBTU’s. Raw gasoline and Fischer-Tropsch products can be sold as high quality crude. Distilled gasoline, diesel and naphtha can be marketed in Eastern Canada and Eastern U.S.


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2.0

DESC RIPTIO N

2.1

METH ANOL The plant feed gas is compressed and heated, then passed through a purifier where any sulfurcontaining gases are removed. The gas is then saturated with water from a source within the process. Steam is added to the feed gas prior to entering a pre-reformer where C2 and heavier hydrocarbons are converted to methane and carbon dioxide. The gas and steam mixture then enters an ATR reformer vessel. Oxygen that has been separated from air is injected into the reformer vessel through a burner. A small portion of the gas is burned to attain the desired temperature. The hot gas passes over a catalyst where hydrogen and carbon monoxide are formed in a ratio of nearly two parts hydrogen to one part carbon monoxide. The resulting mixture, called syngas, is then cooled to condense most of the injected steam and water vapor. The syngas is then reheated and passed over a catalyst in a methanol synthesis reactor. The gas is cooled to condense and remove the methanol that is formed. The syngas is then heated and repeatedly recycled over the catalyst until most of the syngas has been converted to methanol. The product is then distilled to meet specified methanol specifications.

2.2

MTG (M E T H A N O L T O G A S O L I N E ) A raw methanol product is heated and passed over a catalyst to convert a portion of the methanol to dimethyl ether. The mixture is then passed over another catalyst, developed by ExxonMobil, where a portion is converted to hydrocarbons, having a maximum carbon count of 13 per molecule. The vapor mixture of methanol and dimethyl ether is cooled to remove produced gasoline. The mixture is then repeatedly recycled until most is converted to gasoline. The product is approximately 80% gasoline and 18%, by weight, propane and butane. The LPG portion can be used for fuel, be recycled to the feed gas stream ahead of the pre-former vessel, or sold as a separate product.

2.3

TIG AS/MTG This is an integrated process where a mixture of methanol and dimethyl ether is produced, instead of methanol. It is then passed over a specific catalyst and the mixture is converted to gasoline using the ExxonMobil-developed MTG catalyst. The TIGAS process was developed by Haldor Topsoe in conjunction with ExxonMobil at about the same time that ExxonMobil was building an MTG plant in New Zealand in the mid-1980’s. The product is substantially the same as that produced by the MTG process.


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The advantage of this process is that considerable equipment is eliminated and some equipment is reduced in size because of the reduced need for recycling of the gas and vapors. As a result, CAPEX is substantially reduced. 2.4

F I S C H E R -T R O P S C H H Y D R O C A R B O N S The Fischer-Tropsch method of converting natural gas to liquid hydrocarbons starts with a syngas that is very similar to the syngas for methanol. It differs only by a slightly higher ratio of hydrogen to carbon monoxide. It has a ratio of 2 to 1, instead of nearly 2 to 1 for a methanol product. The syngas is heated and contacted with an iron or cobalt catalyst. The product is mostly paraffin hydrocarbons that can have a wide range of components. For maximum conversion efficiency to liquid hydrocarbons, the raw product is about half heavy wax and half diesel plus naphtha. Most, if not all, owners of the technology produce the waxy mixture then hydrocrack the wax to produce more diesel and naphtha.

2.5

SYNC RUDE Both raw gasoline and raw diesel plus naphtha Fischer-Tropsch products may be mixed with crude oil as "syncrude”.

3.0


3.1

THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS The threshold volume of gas can be virtually any volume that is available in excess of about 80 MMscfd. This results from varying the size of the equipment and the number of parallel trains. A volume of 500 MMscfd was used for this analysis, requiring seven trains of syngas production equivalent to 2400 tonnes/day of methanol, the largest ATR reformer that has been made to date. This volume of gas is satisfactory for methanol, TIGAS/MTG and F-T liquids. It would be advisable to recover C5+ and LPG from the gas stream prior to conversion of the gas to liquid if markets exist for economical extraction and transport.

3.2

GAS QUAL ITY The use of a pre-reformer ahead of the primary reformer will allow all three processes to utilize gas from any of the Jeanne d’Arc reservoirs without creating soot to foul catalysts, although there will be a moderate decrease in conversion efficiency when the gas contains any gas heavier than methane.


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3.3

GAS VS. O IL PROD UCTION RATE S The feed gas for an onshore methanol plant should not directly affect the offshore production of oil or condensate.

4.0

TYPE OF PROD UCTION SYST EM Not applicable since the plant is onshore.

5.0


5.1

ONSH ORE VS . O FFS HORE GAS PROC ESSING The gas that reaches the onshore plant will likely be adequate for feed stock for all three GTL products. If excessive NGL’s are present in the gas, the heavier components can be easily removed. The lighter NGL’s can be extracted as LPG product or be converted to methane and carbon dioxide in the pre-reformer at a moderate expense due to lost conversion efficiency. The decision for selecting processing methods offshore should not be influenced by the fact that the gas will go to a methanol plant onshore.

5.2

GAS COMP OSITIO N The feed gas to a methanol plant can contain about 17 % or more C2+ content with little effect on the plant operation. If higher than normal quantities of C5+ are present, it would usually be more profitable to remove the excess liquid vapors for marketing and replace them with lighter gases from the supply. The removal equipment is not capital intensive and can usually be paid out in a year or two from the value of C5+ liquids and LPG.

6.0


6.1

F O R M E T H A N O L /F- T L I Q U I D S / MT G Methanol is transported by small dedicated chemical tankers since it is essential that no contaminants or water is contained in the tankers’ storage tanks. Some major producers are beginning to use larger dedicated methanol tankers to reduce transportation costs. The MTG and F-T liquids can be transported with the same shuttle tankers available in the field, or if justified, transport with separate shuttle tankers to take advantage of potential premium pricing.

6.2

F I E L D - T O -M A R K E T V S . F I E L D - T O -O N S H O R E A N D T H E N T O -M A R K E T The cost of gas to be converted to liquids is affected by the unit cost of getting the gas to the GTL plant. As a result, offshore GTL processing has a cost advantage over that made onshore


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for small gas volumes. Nevertheless, the Norwegian plant was justified with a pipeline in relatively deep water to deliver the gas onshore. For large volumes of gas, an onshore facility would be required due to the size of the plant. Alternatively, more than one methanol FPSO vessel would be required offshore. 7.0

INFR ASTRUC TURE REQU IREMEN TS

7.1

SITE AVAI LABILI TY FOR LAND FALL, S TOR AGE REQU IREMEN TS, ETC . The pipeline land-fall will be the responsibility of the pipeline owner. It is not anticipated that a GTL plant could justify a dedicated pipeline for only gas for a GTL plant. It will be necessary to locate an onshore plant at a site that would allow reasonable storage volumes for flexibility of supply to markets. It will also require a nearby deep water port for export of the liquid product using ever increasing size carriers. The plant site should ideally include additional nearby space for potential secondary industries that could possibly use the liquids for its feed stock and perhaps to share utility requirements. Fresh cooling water is desirable.

8.0

COST ING Some total cost information for the Norwegian methanol plant was provided by Statoil, but company policy prevented them from providing a breakdown. The total cost of the 250 km, 16 inch pipeline was 1.8 billion NoK (US$ 252 MM). The total cost of the plant and plant site was an additional 4.5 billion NoK (US$ 630 MM). However, the total plant and plant site cost included many items that should not be included in an estimated cost for the Newfoundland study. The 4.5 billion NoK (US$ 630 MM) included: • Gas Receiving Station. • Oxygen Plant. • Methanol Plant. • A Bio-Protein Plant. • A Small LNG Plant. • Site and Extensive Site Preparation for the Future. Another problem with trying to use the available total cost was the fact that the currency exchange rate between the NoK and US$ varied substantially over the construction period resulting in variations from this factor of about ± 25% depending on the date used for the comparison.


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For these reasons the basic methanol plant cost estimate presented is based on total costs obtained from Halder Topsoe for a similar plant to be built at another site. The cost was reported to have been confirmed by two major contractors. A list of estimated processing plant and site costs follows: Gas Receiving Station

:

US$

10,000,000

Oxygen and Processing Plant

:

US$

225,000,000

Site and Site Preparation

:

US$

50,000,000

Storage (MeOH)

:

US$

20,000,000

Project Management (excluding process plant)

:

US$

20,000,000

:

US$

325,000,000

Total

This compares favorably to the costs Worley has developed for onshore plants based on the detailed estimate developed for offshore, allowing for technical modifications that are practical onshore, but not so offshore. Based on seven trains of 2,400 MTPD methanol plant to process 490 MMscfd, or the equivalent for MTG and F-T, the conservative plant costs are as follows:

MeOH

F-T

Plant Cost

(C$ MM)

1886

2690

2194

3000 MM Camp

(C$ MM)

164

164

164

Other NF Factors

(C$ MM)

135

135

135

2186

2990

2494

Total 8.1

MTG

ANNU AL EMPL OYMENT One train would employ 100 persons. An additional 40 persons would be required for each additional train for methanol or TIGAS/MTG. The F-T plant for 490 MMscfd would require about 300 persons. An additional 40 to 50 persons would be required for maintenance support for each of the three products.


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8.2

CAPT URE RATE S Approximately twelve (12) million man-hours are required to construct a plant of this size. Most all laborers could be from Newfoundland, if they have the resources. This would require a workforce peaking at approximately 3,600 people. Much of the equipment, valves, pipe, etc., could be procured in Canada.

9.0

TECH NOLOGY STAT US Methanol plants are very mature. There are several process options that differ primarily in the specific equipment design for making the syngas that is used to synthesize methanol. No significant unproven elements exist. The TIGAS/MTG plant was proven in the mid-1980’s at the La Porte, Texas demonstration plant. The major reduction in oil prices that occurred in early 1986 caused the process to be set aside. Haldor Topsoe has optimized several equipment items for application with TIGAS that should allow further economics and smooth operations. The basic Fischer-Tropsch process is 76 years old. However, newly developed unit operations methods have been developed by several companies. Demonstration plants have proven fluidized bed catalytic reformers to be very efficient for making syngas onshore. Slurry catalytic reactors have also been proven in both demonstration plants and fully commercial plants. It is anticipated that slurry catalytic reactors will be proven for offshore services very soon, allowing greater economy of scale. The fluidized bed reformer technique should equally apply to methanol and TIGAS/MTG operations onshore.


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Exhibit VII Offshore GTL


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Offshore Gas-to-Liquids 1.0

OVER VIEW Depending on local and nearby market circumstances, the most desirable gas-to-liquids (GTL) product would be one of the following: − Methanol. − Syncrude. − Gasoline. − Diesel and Naphtha. This analysis will primarily focus on a methanol plant placed on an FPSO and integrated with an oil production plant. The similarity of the four GTL process operations results in them being applicable to basically the same reservoir and field circumstances. For this reason, comments will be made about the other three processes only as warranted.

2.0

DESC RIPTIO N

2.1

METH ANOL The plant feed gas is compressed, heated and passed through a purifier where any sulfurcontaining gases are removed. The gas is then saturated with water from a source from within the process. Steam is added to the feed gas prior to entering a pre-reformer where C2 and heavier hydrocarbons are converted to methane and carbon dioxide. The gas and steam mixture then enters an ATR reformer vessel. Oxygen that has been separated from air is injected into the reformer vessel through a burner. A small portion of the gas is burned to attain the desired temperature. The hot gas passes over a catalyst where hydrogen and carbon monoxide are formed in a ratio of nearly two parts hydrogen to one part carbon monoxide. The resulting mixture, called syngas, is then cooled to condense most of the injected steam and water vapor. The syngas is then reheated and passed over a catalyst in a methanol synthesis reactor. The gas is cooled to condense and remove the methanol that is formed. The syngas is then heated and repeated recycled over the catalyst until most of the syngas has been converted to methanol. The product is then distilled to meet specified methanol specifications.

2.2

MTG (M E T H A N O L T O G A S O L I N E ) A raw methanol product is heated and then passed over a catalyst to convert a portion of the methanol to dimethyl ether. The mixture is then passed over another catalyst (developed by ExxonMobil), whereby a portion is converted to hydrocarbons having a maximum carbon count


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of 13 per molecule. The vapor mixture of methanol and dimethyl ether is then cooled to remove produced gasoline. The mixture is then repeatedly recycled until most is converted to gasoline. The product is approximately 80% gasoline and 18%, by weight, propane and butane. If it is not economical to separate the LPG portion for a market, it can be used for fuel and/or be recycled to the feed gas stream ahead of the pre-former vessel. 2.3

TIG AS/MTG This is an integrated process where passing a mixture of methanol and dimethyl ether is produced, instead of methanol. It is then passed over a specific catalyst where the mixture is converted to gasoline using the ExxonMobil developed MTG catalyst. The TIGAS process was developed by Haldor Topsoe in conjunction with ExxonMobil at about the same time that ExxonMobil was building an MTG plant in New Zealand in the mid-1980’s. The product is substantially the same as that produced by the MTG process. The advantage of this process is that considerable equipment is eliminated and some equipment is reduced in size due to the reduced need for recycling of the gasoline vapors. As a result, CAPEX is substantially reduced.

2.4

F I S C H E R -T R O P S C H H Y D R O C A R B O N S The Fischer-Tropsch method of converting natural gas to liquid hydrocarbons starts with a syngas that is very similar to syngas for methanol. The syngas is heated and contacted with either an iron or cobalt catalyst. The product is mostly paraffin hydrocarbons that can have a wide range of components. For maximum conversion efficiency to liquid hydrocarbons, the raw product is about half-heavy wax and half diesel plus naphtha. Most, if not all, owners of the technology produce the waxy mixture then hydrocrack the wax to produce more diesel and naphtha.

2.5

SYNC RUDE Both raw gasoline or raw diesel plus naphtha Fischer-Tropsch products may be mixed with crude oil as “syncrude”.


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3.0


3.1

THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS Generally, about 29,600 MMBtu of associated gas is required for the production of 1,000 tonnes/day of methanol, excluding fuel which is approximately 12.7% of the inlet gas for an offshore application. Offshore GTL plants require more fuel gas than onshore plants. This results from the need to simplify equipment, operations and maintenance on a crowded and sometimes violently moving FPSO vessel. Use of fuel to drive compressors and generate electricity for electric motors is much safer than using waste heat to generate and use steam at the many required locations on an FPSO vessel. The increased use of fuel offshore is normally of less concern because the stranded gas has a low or negative value when the alternative is to reinject the gas at a substantial cost. The use of high BTU/ft3 feed gas is less efficient from the standpoint of BTU/tonne of product. This results from the fact that a pre-reformer is used to convert C2 and heavier gases to C1 plus CO2. The best BTU conversion efficiencies result if most of the C2 and heavier components are removed by gas processing prior to the feed gas entering the syngas production equipment. The best economics for GTL plants result from sharing deck and storage space with a GOSPFPSO vessel. Accordingly, a large tanker shaped vessel was selected for a case to include oil production and gas-to-liquids production on one GOSP / GTL FPSO vessel. The selected size has 54m x 375m deck dimensions. This size vessel will allow four trains of syngas for 1,500 tonnes/day methanol each. The same volume of gas can be converted to gasoline or F-T liquids. The selected oil production facility has a capacity for 80,000 Bbl/day and 160,000 Bbl/day water injection. With no GOSP facilities on board the same size vessel will allow six trains of syngas for 1,500 tonnes/day methanol each. The same volume of gas can be converted to gasoline or to F-T products on the selected large vessel. The volume of GTL feed gas will vary with the BTU content of the gas, but will be approximately 177 MMscfd for four trains or 236 MMscfd for six trains of syngas when the feed gas has 1,117 BTU/ft3. Multiple vessels may be used if warranted. Ideally, for a floating methanol plant, there should be sufficient gas reserves for at least ten years operation at full capacity to typically meet minimum economic hurdles.


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3.2

M U L T I -F I E L D O R S T A N D -A L O N E D E V E L O P M E N T Because of its portability, a floating methanol or similar GTL plant can be applied in multifield, sequential or stand-alone developments.

3.3

G A S Q U A L I T Y (C O M P O S I T I O N ) The composition of normal produced gas is not critical, since heavy ends in associated gas is usually pre-reformed to methane and some carbon dioxide prior to entering the synthesis gas process. Dehydration of the wet gas in not required. Produced water vapor, nitrogen and carbon dioxide inerts can generally be accommodated by the process without any detrimental effect. Water vapor combines with steam that is required by the process. Nitrogen passes through the entire process as an inert, the only effect being the increase in size of the piping, vessels, exchangers and compressors to accommodate the additional volume. Carbon dioxide joins with that which is generated in the process. Hydrogen sulfide and organic sulfur tend to poison catalysts, and must be removed prior to entering the synthesis gas loop. Almost all methanol plants have desulfurisers at the beginning of the process to remove any traces of hydrogen sulfide and organic sulfur that may be present in the feed gas stream.

3.4

G A S V S . O I L P R O D U C T I O N R A T E S (C U R R E N T A N D P R O J E C T E D , R E -I N J E C T I O N R E Q U I R E M E N T S , F I E L D L I F E , E T C .) For the GOSP/GTL case, the analysis is based on the assumption that these facilities would be installed at a future discovery similar to the White Rose Field. The solution gas from the development would have priority, and the remaining gas would be supplied from the nonassociated gas. The oil and gas production is expected to peak at 80,000 BOPD and 41.1 MMscf/d respectively. A gas field, like the N. White Rose gas, is expected to produce 33 barrels of condensate for each MMscf/d of gas produced. Peak oil and condensate production is approximately 83,000 BPD. Other gas volumes can be selected for similar field conditions that may be discovered in the future. For the 9,000 tonne/day case, it is assumed that circa 268 MMscfd of gas is available from nearby oil and gas fields. This case assumes all the production is handled at another facility(s) and the gas is sent to the GTL FPSO. In this case, there would be no oil or condensate production to consider.


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4.0

TYPE OF PROD UCTION SYST EM

4.1

G R A V I T Y -B A S E D , F L O A T I N G S Y S T E M , S U B S E A O P T I O N S This evaluation is limited to floating systems. A floating system can be either a dedicated system, or integrated with oil production facilities (GOSP) on an FPSO.

4.2

RESE RVE AN D FINA NCIAL IMPL ICATIO NS OF PORT ABLE A ND MODU LAR PROD UCTION SYST EMS Floating GTL plants are, by their nature, very portable. Little, if any, modifications to the process system would be required to relocate the system to another field. The expected useful life of such a system is at least twenty years.

4.3

U T I L I Z A T I O N O F E X I S T I N G F A C I L I T I E S (H I B E R N I A GBS , T E R R A N O V A FPS O) Dedicated, floating methanol plants can be positioned adjacent to existing facilities, with the feed gas supplied by subsea pipeline.

4.4

U T I L I Z I N G S H A R E D S E R V I C E S (S U P P L Y B O A T S , H E L I C O P T E R S , S U P P L Y B A S E , PERS ONNEL) In the case of a floating GTL plant being integrated on an FPSO with oil production systems, there could be full sharing of logistical support equipment and services. In addition, there would be no requirement for duplicated marine support, housekeeping and maintenance personnel. In the case of a dedicated floating methanol plant located adjacent to other oil production facilities (either GBS or floating) logistical support equipment and services could also be shared.

5.0


5.1

OFFS HORE V S. O NSH ORE PROC ESSING Gas processing to remove LPG would not be practical for several reasons: there is not enough space for the gas processing equipment; the performance of the process towers (de-ethanizers, etc.) in rough seas is not yet proven; and this would be the first time for both GTL and gas processing to be done on an FPSO under the rough sea-states in the Jeanne d’Arc Basin. It would be very challenging to undertake just one of these processes, let alone both at the same time. This activity can be considered at a future date after offshore use of structural packing fractionation towers is proven for FPSO applications.


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5.2

GAS COMP OSITIO N The syngas plant for methanol and F-T applications can accommodate varying quantities of C3+ because of the use of a pre-reformer to convert the heavier gaseous hydrocarbons to methane and carbon dioxide prior to reaching the syngas reformer. The presence of heavier gases causes a moderate reduction in conversion efficiency. In some cases, where the associated gas includes a high percentage of heavy hydrocarbons, it is economical to knock out the liquids prior to entering the synthesis gas loop in a refrigerated liquid recovery unit and recombine the heavy liquids with the produced crude oil. Removal of LPG may be profitable in some circumstances.

6.0


6.1

FOR METH ANOL, S YNT HETIC CRUD E, O THE R LIQU IDS Methanol is usually transported by small dedicated chemical tankers since it is essential that no contaminants or water is contained in the tankers’ storage tanks. Some major producers are beginning to use larger dedicated methanol tankers to reduce transportation costs. The MTG and F-T liquids can be transported with the same dedicated shuttle tankers available in the field, or if justified, transport with separate shuttle tankers to take advantage of potential premium pricing.

6.2

F I E L D - T O -M A R K E T V S . F I E L D - T O -O N S H O R E A N D T H E N O N S H O R E - T O -M A R K E T It is more economical to transport liquids directly to market instead of transport to onshore and then to market because of the additional cost of tanker offloading/reloading and storage facilities.

7.0

INFR ASTRUC TURE REQU IREMEN TS

7.1

SITE AVAI LABILI TY FOR LAND FALL, S TOR AGE REQU IREMEN TS, ETC . Generally, no onshore site availability or storage is required in support of floating GTL plants.

7.2

POSS IBLE UTIL IZATIO N OF EXIS TING INFR ASTRUC TURE Existing logistical infrastructure, delivery systems and personnel can be shared.


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8.0

COST ING

8.1

C A P I T A L E X P E N S E (CA PEX) The following cost estimates are based on a typical 6-train 9,000 tonne/day dedicated floating methanol system producing Federal Grade AA methanol, a 31,650 BPD MTG syncrude plant, and a 27,150 BPD Fischer Tropsch plant with the same feed gas quantity. Six (6) Train GTL FPSO CAPEX – Millions C$

Methanol

54 m x 375m FPSO, including turret, mooring and marine systems GTL Topsides, including Installation and commissioning Total - Dedicated Facility

MTG

F-T

652

652

652

1,183

1,964

967

1,835

2,616

1,619

The following cost estimates are based on a stand alone GOSP/GTL FPSO that can consists of a typical 4-train 6,000 tonne/day dedicated floating methanol system producing Federal Grade AA methanol, or a 21,100 BPD MTG syncrude plant, or a 18,100 BPD Fischer Tropsch plant with the same feed gas quantity. In addition, full production facilities capable of processing 80,000 BOPD and 160,000 BWPD for injection are included, and the well costs and subsea equipment. CAPEX – Millions C$

Methanol

MTG

F-T

46.5 m x 375m FPSO, including turret, mooring and marine systems

807

807

807

GOSP + GTL Topsides, including Installation and commissioning

937

1,461

794

Initial Well Costs

816

816

816

Initial Subsea Costs

428

428

428

Shuttle Tankers

230

230

230

70

70

70

1,433

1,433

1,433

4,721

5,245

4,578

Supply Boats Future Wells and Subsea Costs Total - Dedicated Facility


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There are cost and design optimization opportunities that could help bring the MTG CAPEX down by 10% or more by integration of the syngas and MTG processes as proposed by Haldor Topsoe for their TIGAS process. 8.2

O P E R A T I N G E X P E N S E (OP EX) OPEX costs for the GTL FPSO are as follows: Daily Operating Expense (OPEX) –C$/d FPSO Operating Cost

Methanol

MTG

F-T

92,143

120,000

105,357

32,676

27,152

20,000

20,000

20,000

0

15,774

13,575

188,450

166,084

Shuttle Tanker Supply Boats Transshipment Terminal Methanol Transportation / Price Adjustment Total - Dedicated Facility

221,714 333,857

The OPEX for the various options do not include the value of the feed gas. OPEX costs for the GOSP/GTL FPSO are as follows: Daily Operating Expense (OPEX) –C$/d

Methanol

MTG

F-T

FPSO Operating Cost

92,143

120,000

105,357

Shuttle Tanker

25,928

25,928

25,928

Supply Boat

20,000

20,000

20,000

0

52,111

49,859

141,000

0

0

279,071

218,039

201,144

Transshipment Terminal Methanol Transportation / Price Adjustment Total - Dedicated Facility

The OPEX for the various options do not include the value of the feed gas. 9.0

ANNU AL EMPL OYMENT Staffing of the floating methanol plant will be about 75 persons per operating tour, or a total of about 150 persons per vessel, excluding shore based logistical and administrative personnel. To process 500 MMscfd, two FPSO’s would be required, resulting in employment of 300 people.


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9.1

CAPT URE RATE S The capture rate on development expenditures should be over 90% for operating expenses. Most all of the operations could be by Newfoundlanders. The capture rate on CAPEX will be less than 10% for the production/process facilities and the floating platform as these vessels will most likely be built in Asia due to the price and schedule advantages. The topsides could be built at Bull Arm.

10. 0

TECH NOLOGY STAT US

10. 1

EXIS TING DESI GN STAG E OR CONC EPTUAL The design of the necessary marine and mooring equipment is both existing and mature. Likewise, the design of methanol production/processing equipment is proven and is available from a number of suppliers of this technology. The TIGAS/MTG process is available from Haldor Topsoe. The F-T process can be supplied by several companies.

10. 2

I D E N T I F Y A D D I T I O N A L R&D W O R K R E Q U I R E D The only technology that needs additional work is the distillation of methanol to Federal Grade AA specifications. Structured packing will be used and is a proven technology, however, vessel motion simulation studies need to be carried out to prove the distillation column design for placement on a floating vessel.


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Natural Gas Development Based on Non-pipeline Options_technical Feasibility Study

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