Ptarmigan Resources Project Conceptual Engineering Study...

Ptarmigan Resources Ltd.

Ptarmigan Resources Project

Conceptual Engineering Study

August 2004

Ptarmigan Resources Project Conceptual Engineering Study – Final Report Table of Contents

TABLE OF CONTENTS

1.0 Executive Summary ........................................................................................ 1 2.0 Introduction ....................................................................................................... 3 3.0 Scope of Study................................................................................................... 4 4.0 Design Basis ....................................................................................................... 5 5.0 MetaOcean Data............................................................................................... 6

5.1 Wind.................................................................................................................... 6 5.2 Waves.................................................................................................................. 7 5.3 Temperatures....................................................................................................... 7 5.4 Currents............................................................................................................... 7 5.5 Seafloor Conditions ............................................................................................ 8 5.6 Ice Data ............................................................................................................... 8

6.0 Facilities Description/Requirements ................................................................. 12 6.1 General.............................................................................................................. 12 6.2 Oil Processing System ...................................................................................... 12

6.2.1 Introduction............................................................................................... 12 6.2.2 Liquid and Gas Separation ....................................................................... 12 6.2.3 Gas Processing System ............................................................................. 13

6.3 Water Injection System..................................................................................... 13 6.4 Chemical Injection Systems.............................................................................. 14 6.5 Utilities & Other Systems ................................................................................. 14

7.0 Concept Options............................................................................................. 15 7.1 FPSO................................................................................................................. 15

7.1.1 Description and Concept .......................................................................... 15 7.1.2 Mooring/Export Systems ........................................................................... 17 7.1.3 CALM Buoy............................................................................................... 17 7.1.4 SALM Buoy ............................................................................................... 18 7.1.5 Soft Yoke Tower ........................................................................................ 19 7.1.6 FPSO New Build Versus Lease................................................................. 21 7.1.7 Typical FPSO Operating Scenarios.......................................................... 22 7.1.8 Subsea Wells ............................................................................................. 23 7.1.9 Drilling...................................................................................................... 23 7.1.10 Typical Operating Cost – Lease FPSO..................................................... 23 7.1.11 Project Schedule ....................................................................................... 25

7.2 Jack-Up ............................................................................................................. 26 7.3 Bottom Founded Caisson.................................................................................. 27

7.3.1 General ..................................................................................................... 27 7.3.2 Production, Storage and Offloading......................................................... 30 7.3.3 Drilling...................................................................................................... 30 7.3.4 Seasonal Vs. Year-Round Production....................................................... 30 7.3.5 Typical Operating Cost – New Build Bottom Founded Caisson .............. 30

Pan Maritime Energy Services Inc. August 2004

7.3.6 Project Schedule ....................................................................................... 33

Ptarmigan Resources Project Conceptual Engineering Study – Final Report Table of Contents 8.0 Conclusion ........................................................................................................... 34 9.0 Appendix.............................................................................................................. 35


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 1 of 35

1.0 Executive Summary Ptarmigan Resources’ Offshore Newfoundland project is located near the West Coast of the province, 25km offshore in 40 meters of water. While the region can be deemed a hostile environment, the conditions are not nearly as severe as the better known Grand Banks area off the East coast, where the Hibernia, Terra Nova and White Rose projects are located. Firstly, there are no icebergs, secondly, the winter icepack covers the region for only one month per year and in some years, there is no icepack. Thirdly, the seastate conditions are less severe than the open Atlantic of the Grand Banks area. Three potential development options were evaluated for a 300 million barrel recoverable reserve case: • FPSO • Jack-Up • Bottom Founded Caisson However, other more costly “new build” development options, including gravity base structures and subsea tiebacks to onshore processing facilities may still be applicable to larger reserve cases. The FPSO with its production and storage facilities located on one vessel provides many advantages. However, with relatively shallow water, compared to the Grand Banks, an external mooring/export system is required. Two cases were evaluated, seasonal versus year-round production.

The second option, a combination Jack-Up drilling and production platform was evaluated as it is a proven concept for shallow water East Coast Canada. However, for a field of 300 million barrels recoverable with 20 wells producing a total of 160,000 barrels per day, a converted drilling Jack-Up is not a viable alternative. It is estimated that the Topsides process facilities required to support a field producing 160,000 barrels per day would weigh in the range of 12,500 tonnes. Secondly, the footprint of such a Topsides package would be significant and the concept would be further challenged with 20 producers and 8 well injection wells. The last option, a Bottom Founded Caisson, is capable of year-round operations but will be the most costly of the options and will require a longer start-up schedule. Typical all-inclusive costs for each concept are as follows: • FPSO – USD $878,700 per day • Caisson – USD $1,019,400 per day


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 2 of 35 Secondly, schedule requirements for each of the above are: • FPSO 24 months • Caisson 48 months It should be noted, that the budget allocated for this conceptual engineering study did not permit an in-depth analysis of the many engineering issues associated with seasonal versus year-round production, subsea versus land-type trees, flow assurance issues, and the like.



2.0 Introduction Ptarmigan Resources is the license holder of an offshore block located West of the Port au Port Peninsula on the West coast of the Province of Newfoundland and Labrador. The prospects are located approximately 25 kilometers offshore, in 40 meters water depth. Fully risked prospect potential has been estimated at over 600 million barrels of recoverable oil, from up to four prospective zones. In keeping with conservatism, this study is based on development options for recoverable reserves of half that size, or 300 million barrels. While the study focuses on an oil case, there is a strong possibility of significant gas. In May 2004, Pan Maritime Energy Services Inc. were retained to conduct a conceptual engineering study of production options.

Figure 1 – Map of Region



3.0 Scope of Study The scope of this Conceptual Engineering Study is as follows: a) Identify and evaluate various production options b) For each options, identify the advantages/disadvantages c) Seasonal versus year-round production d) Mooring/Export systems e) Identify facilities requirements f) Subsea versus dry completions g) Review metaocean data h) Identify project schedule for each option i) Provide ± 25% cost estimate for each option



4.0 Design Basis The Ptarmigan Project is located 25km offshore, West Coast Newfoundland, in 40m of water. The following are the design parameters, assumed for this study. Item No. Description Assumption 1 Field Location Co-ordinates Latitude: N48° 55’

Longitude: W58° 58’ 2 Water depth 40m 3 Distance Offshore 25km 4 Average planned well depth 3500m 5 No. of wells, two of six prospects, 300

million barrels 20 producers 4 gas injection 4 water injection

6 Well productivity 5,000 to 15,000 bopd

7 Estimated daily oil production 160,000 bopd 8 Total daily fluids production 200,000 bpd 9 Reserves estimate 300 million barrels oil

200 bcf gas 10 Estimated field size 40 to 75 Sq. km 11 GOR 300m3/m3

12 Water Production 15% water cut 13 Water Properties CL – 170,000 mg/l 14 FWHP

SWHP 750 psi 1900 psi

15 System Design Life 20/25 yr.



5.0 MetaOcean Data Metaocean data for this study has been gathered and compiled from the following sources: • Geological Survey of Canada (Seabed Conditions) • Environment Canada (Sea Ice Conditions, Wind, Waves) • Fisheries and Oceans Canada (Currents, Temperatures)

5.1 Wind Wind is a significant factor in the planning of any offshore development, in particular for floating production platforms. Table 1.0 is a summary of annual wind statistics for the Port au Port Region as recorded by Environment Canada.

Table 1.0 PORT AU PORT REGION

NEWFOUNDLAND & LABRADOR ANNUAL WIND STATISTICS – GULF PORT AU PORT

Direction % of the Time Month Mean

Speed (Knots)

Max Speed

(Knots) W SW N NW NE E SE S

Jan 17 51 24 19 10 23 7 5 5 7

Feb 14 46 22 17 13 20 8 6 6 8

Mar 13 47 16 14 15 16 14 7 7 11

Apr 12 38 12 13 15 13 17 10 9 11

May 10 38 11 19 11 11 10 8 10 19

June 10 37 11 26 8 9 8 7 9 22

July 9 33 13 32 4 7 4 6 8 26

Aug 10 37 19 31 8 8 5 5 6 18

Sept 13 42 22 25 8 13 6 5 6 15

Oct 15 45 21 20 11 16 8 5 7 12

Nov 17 45 22 16 10 20 7 6 7 12

Dec 18 49 22 13 13 22 8 6 7 9


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 7 of 35 The predominant wind direction for the study area is West to Southwest at a mean speed of 10 to 18 knots and maximum of 51 knots. Generally, West to Southwest winds prevail 25 to 50% of the time.

5.2 Waves While offshore Port au Port can be deemed a hostile environment, the weather is not as harsh as you would find on the Grand Banks. Table 2.0 is a summary of wave data. The mean wave height is 0.5 to 2.2 meters, maximum wave height is 10.5 meters.

Table 2.0 PORT AU PORT REGION

NEWFOUNDLAND & LABRADOR ANNUAL WAVE STATISTICS – GULF PORT AU PORT

Month Mean (m) Max (m)

January 1.5 10.5

February 0.5 7.1

March 0.5 7.7

April 0.9 8.0

May 1.0 6.6

June 1.0 5.2

July 1.0 4.6

August 1.1 5.2

September 1.4 6.0

October 1.7 8.5

November 2.0 8.7

December 2.2 9.7

5.3 Temperatures Temperatures in this region can vary from -15°C in winter to 28°C during summer. Seawater temperatures are typically -1°C during winter to +9°C during summer.

5.4 Currents Current data for the area is not abundant. Information from the Government of Canada, Department of Fisheries and Oceans database, indicates currents in this area to be relatively low, in the 0.5 to 1.0 knot range, predominantly from the North.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 8 of 35 5.5 Seafloor Conditions Like current data, seafloor data for the region is not abundant. The Geological Survey of Canada classifies the seafloor conditions as “comprised of reworked sand and gravel of glacial origin.” Any development planned for this area will require geotechnical sampling.

5.6 Ice Data While ice is a significant factor for any offshore Newfoundland development, the West coast of Newfoundland is generally iceberg free. The predominant ice feature in the region is winter pack ice. In January the Northern ice pack migrates down the Strait of Belle Isle. By February, it extends into the Gulf of St. Lawrence. However, the Port au Port Region remains ice free. It is not until March that the Port au Port area will see the ice pack. By April the area is again ice free. From a development point of view, the ice challenge is not as severe as previously thought. Essentially, the area planned for development is ice free 11 months per year and it is possible, some years, the area will be ice free. With respect to ice thickness, C-CORE, renowned St. John’s Ice Engineering Consultants, estimate ice thickness ranging from 0.5 to 1.0m. Environment Canada Ice data for West Coast Newfoundland over a thirty year period (1971 – 2000) are summarized in following figures:



Figure 2 – January Pack Ice

Figure 3 – February Pack Ice



Figure 4 – March Pack Ice

Figure 5 – April Pack Ice



Figure 6 – May Pack Ice



6.0 Facilities Description/Requirements 6.1 General This section provides a general overview of the topsides process and utility systems required in accordance with the Design Basis as set down in Section 4.0. To stay within the budget of this study, specific topsides layouts for various options i.e. FPSO, Jack-Up or Bottom Founded Caisson have not been generated. However, typical topsides layouts for an FPSO are enclosed in Appendix 1. The main purpose of the topsides facilities is to safely process the crude oil, to produce stabilized and dehydrated oil for storage and transport. A three stage separation process is used to separate the crude oil from its associated gas and water. The stable crude oil is stored, depending on the concept, on board the platform or remote for offloading to shuttle tankers. The associated gas is treated for use as fuel gas and lift gas. Any remaining gas can be disposed of by re-injection into the field. Produced water that has been separated from the crude oil will be re-injected unless reservoir planning dictates otherwise.

6.2 Oil Processing System 6.2.1 Introduction The basic purpose of the oil processing system is to stabilize and prepare the crude oil for tanker transport by removing impurities and reducing the vapor pressure. Produced water, separated in the system is for now assumed to be re-injected. However, technical, cost or reservoir consideration during the detailed engineering phase may for example, dictate treating the water for overboard disposal. 6.2.2 Liquid and Gas Separation The separation train will comprise three stabilization stages, high pressure (HP), medium pressure (MP) and low pressure (LP) separation followed by crude oil dehydration. The live crude when it arrives on the platform is directed to a HP production manifold and onto a two phase HP separator. Liquids from the HP separator are typically routed to the MP separator via intermediate heating. Gas from the HP separator is routed to a LP Gas Compressor. Crude from the HP separator is depressurized, heated and routed to a three phase MP separator. Here, produced water and gas is separated from the crude.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 13 of 35 During the final stage of LP separation, crude oil stability (vapor pressure) is achieved by removing light volatile components. Produced water from the proposed field is expected to contain chlorides in the range of 170,000 mg/l, therefore highly corrosive. This factor will have to be considered during material selection for tubing strings and down hole equipment versus down hole chemical injection of corrosion inhibitors. Secondly, it is assumed and recommended that produced water be re-injected, if reservoir engineering permits rather then treating and disposing overboard which can be very costly. 6.2.3 Gas Processing System A gas processing system is required to upgrade produced gas to conditions where it can be used for gas lift, fuel gas and re-injection. Typically, a gas processing system consists of: • Flash Gas Compression • LP Gas Compression • Gas Dehydration • Lift and Injection Gas Compression The Flash Gas Compression system enables pressurization of the low pressure and intermediate pressure gases from the LP and MP separators, respectively, to the inlet pressure of the Gas Re-injection Compression System. The LP Gas Compression System compresses the HP Separator and flash gas from the Flash Gas Compressor to a pressure level where it can be used as HP fuel gas, with further compression for gas lift/re-injection. A gas dehydration system will be required to prevent hydrate formation in the gas lift and gas re-injection lines. In addition, a gas lift/gas re-injection system is required to pressurize the dry gas from the gas dehydration pressure to the pressure required for gas lift and re-injection into the well.

6.3 Water Injection System It is anticipated that the topsides water injection system will be required to handle approximately 30,000 to 50,000 barrels per day of produced water with allowance for future increases. The purpose of the water injection system is to treat and condition produced water and possibly to condition seawater for injection into the reservoir for pressure maintenance.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 14 of 35 6.4 Chemical Injection Systems Due to the anticipated corrosive nature of formation water and the potential for paraffin, downhole chemical injection will be required. Secondly, if it is deemed more feasible, to produce the field on a seasonal basis, flow assurance issues will require that chemical injection and fluid inhibition be carefully considered.

6.5 Utilities & Other Systems Other systems which will be part of the overall topsides requirements include, but due to the nature of this study scope, will not be described in detail: • Flare System • Fuel Gas System • Heating System (Crude Oil Conditioning) • Cooling System • Seawater System (Injection & Cooling) • Nitrogen System (Blanket & Purge Gas) • Diesel System (Back-up Power Generation) • Freshwater System • Firewater System • Aviation Fuel System



7.0 Concept Options Initially, the following concepts were identified as potential development options, these included: • Gravity Base Structure (GBS) • Subsea Tie-back to Onshore Processing Facility • FPSO • Jack-Up • Bottom Founded Caisson Following a discussion of the above, Ptarmigan and Pan Maritime agreed to eliminate the GBS and Subsea Tie-back options from the scope of this study. This is not to say that these are not options for development. In larger case reserves, as estimated by Ptarmigan they most certainly would be. For conservatism, it was decided to investigate lower cost options, with lease scenarios, under a smaller reserve case to test economic viability. The main reason for eliminating the GBS is that at 150,000 to 300,000 barrels of oil recoverable, the project would be challenged to support the cost of a GBS. Similarly, the Subsea Tie-back to Onshore Facilities was eliminated but for different reasons. From a flow assurance point of view, the wells may require frequent intervention due to high wax content and with anticipated low flowing wellhead pressures, boosting will be required to deliver the fluids to an onshore facility. Once processed onshore, there is no market or transportation infrastructure to ship the product to market. A pre-requisite for this study was that only proven technology in similar environments would be considered with the smaller reserves case. From this starting point, the FPSO and Jack-Up concepts have been proven in the Atlantic Canadian offshore, namely the Terra Nova FPSO, White Rose FPSO (under construction) and the COPAN Jack-Up Production Platform. With respect to a Bottom Founded Caisson, the Gulf Molikpaq, previously built for the Canadian Beaufort Sea as a mobile drilling unit is now part of the Sakhalin Island Offshore Development Project, a similar but more hostile environment.

7.1 FPSO 7.1.1 Description and Concept The FPSO is a proven concept for harsh environments and Newfoundland in particular. One FPSO is currently in operation on the Grand Banks for Petro Canada (Figure 6) and a second FPSO is in the final construction stage at Marystown, Newfoundland for Husky Energy. Pan Maritime Energy Services Inc. August 2004


Figure 7 - Terra Nova FPSO

Some of the advantages of an FPSO are, the topsides process facilities and storage are located on the same platform. Secondly, being a mobile platform, the facility can be moved if required during severe ice conditions and re-deployed at a future date. The Grand Banks operating environment is more severe than the offshore Port au Port region of Western Newfoundland. The Grand Banks is more exposed to the open North Atlantic, therefore, seastates, wind and ice conditions are more severe. In addition, there is the presence of icebergs. The Grand Banks does have one advantage over the offshore Port au Port location and that is water depth. The Grand Banks with typically 100 – 120m. water depths is more favourable for internal turret FPSO mooring systems. At 40m water depth, neither the Terra Nova nor White Rose FPSO with internal turret arrangement will work. The vessel draft combined with the bending radius requirements for flexible risers would rule out this type of FPSO mooring configuration for the West Coast, 40 meter water depths. The FPSO is however, still an excellent concept for West Coast Newfoundland but will require an external, bow mounted turret, mooring or yoke arrangement. Initially, a bow mounted turret with spread mooring arrangement (Figure 8) was considered but upon evaluation of metaocean data, in particular winds, the spread moored FPSO concept was ruled out due to the variable direction of winds in the study area.



Figure 8 – Spread Moored FPSO

7.1.2 Mooring/Export Systems While it is quite possible that we can achieve year-round production, we must plan for the possibility of a disconnect. In such an event, the FPSO sails safely away but the loading and mooring system will be left behind. In our review of suitable FPSO mooring systems, we evaluated the • CALM BUOY • SALM BUOY • SOFT YOKE TOWER 7.1.3 CALM Buoy The CALM Buoy (Catenary Anchor Leg Mooring System, Figure 9) is a proven loading/offloading mooring concept. A CALM Buoy was used to moor and load the FSO Nordic Apollo supporting the Panuke Cohasset Project for Pan Canadian in Nova Scotia. This field while on production, produced 40,000 bopd. The CALM buoy is typically used in more benign environments and compared with other mooring/loading systems is relatively inexpensive. There are several manufacturers of the CALM buoy, including SBM IMODCO and Bluewater Offshore Production Systems. A new CALM buoy is typically in the US $5 million range but frequently “used” CALM buoys can be found for US $1.0 – 2.0 million. It should be noted however, that the CALM buoy does have seastate limitations, typically 3.5 to 4.0 meters significant wave height. Secondly, in the event of a disconnect, the CALM buoy could become “sacrificial”.



Figure 9 – CALM Buoy / FSO

7.1.4 SALM Buoy The SALM buoy (Single Anchor Leg Mooring, Figure 10 and Figure 11) is a proven concept for hostile environments. At Sakhalin Island, a SALM Buoy/FSO combination is being used to support production from the Bottom Founded Caisson platform, Molikpaq. The Sakhalin environment is much more severe than West Coast Newfoundland. At Sakhalin, during the Winter months, the SALM buoy is ballasted and layed down on the seafloor, while the FSO sails away. Once the pack ice recedes, the FSO returns, the SALM Buoy is retrieved and hooked-up.

Figure 10 – SALM Buoy / FSO



Figure 11 – SALM Buoy

In our evaluation of ice data for the region, two facts are noteworthy, a) the ice pack is generally not more than 1.0m in thickness, typically 0.5m (Source: C-CORE) and b) the pack ice is present for only 1 month per year. The SALM has an advantage over the CALM Buoy. Should the FPSO have to disconnect and leave the site, the SALM can be ballasted and laid on the seafloor where it is protected from pack ice. Once the ice threat disappears, the SALM can be de-ballasted, refloated and reconnected to the FPSO. While it is possible that the SALM could be designed to withstand a typical west coast ice pack, this is outside the present study scope and is speculation at this time. Therefore, at this time, we make the assumption that a SALM system would result in 2 months downtime per year. Typical cost for a SALM Buoy would be in the US $14 – 15 million range. 7.1.5 Soft Yoke Tower The Soft Yoke Tower mooring system (Figure 12) is similarly a proven concept and there are several companies, including SBM and Bluewater capable of engineering and constructing such a system. The tubular Soft Yoke Tower is pile driven to the seafloor, to resist environmental forces and to provide a solid base to which one can moor and load an FPSO or FSO.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 20 of 35 Soft Yoke Towers are currently being used on the following projects: • Selat Lalang, Indonesia • Adanga/Akam/Ebughu, Nigeria • Bozhong, China • Bohai, China • Suizhong, China • Shell EA, Nigeria

Figure 12 – Soft Yoke

In consultation with SBM IMODCO, suppliers of the above noted Soft Yoke Towers, we are confident that a similar Soft Yoke Tower with an ice deflection shield can be designed to withstand the ice pack and metaocean conditions of West Coast Newfoundland. The Soft Yoke Tower mooring system offers many technical advantages: a) Year-round mooring/loading operation b) Can be designed to resist ice pack c) Permit use of steel risers versus flexible risers from seafloor to swivel loading system Typical cost for a Soft Yoke Tower mooring system will be in the US $25 – 30 million range.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 21 of 35 7.1.6 FPSO New Build Versus Lease An FPSO can be deployed in two ways: • Operator owned and operated (or managed under contract) • Leased (Bareboat or with Management contract) There are dozens of FPSO’s in service around the world. Therefore, Ptarmigan, depending on timing can elect for a new-build, used vessel or lease a vessel. A new-build while providing the advantages of tailoring the vessel and systems to fit the field will be a costly scenario. Typical new build costs, for a 160,000 bopd FPSO with 900,000 barrels of storage can run up to US $450 million. Depending on timing, Ptarmigan may find “a vessel of opportunity” i.e. a used FPSO which could be modified to suit the project. This will depend largely on market conditions at the time and one’s knowledge of the FPSO market. However, the FPSO lease option is one which we would recommend. Under this scenario, the owner can establish fixed capex/opex costs related to the operation of the FPSO and the contractor can bring the FPSO operations experience that Ptarmigan may not have. FPSO lease costs can be quite variable. There are several FPSO contractors who can lease and also operate an FPSO, including: • SBM • Bluewater • Modec • Vanguard Floating Production SBM, Bluewater and Modec are the world’s largest and leading suppliers of FPSO’s for purchase or lease. Consequently, they serve the higher end market and will be the most expensive. A typical bareboat lease cost for a 160,000 bopd FPSO with 900,000 barrels of storage will be in US $175,000/day range. Operating (contractor) costs will be in the US $25,000 – $30,000/day range. Depending on field size, project economics, one should not rule out smaller FPSO contractors such as Vanguard Floating Production. Vanguard specializes in smaller projects and typically deploy, used tanker conversions. Vanguard could probably offer an FPSO solution in the US $100,000 – $125,000/day range or less depending on the unit.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 22 of 35 7.1.7 Typical FPSO Operating Scenarios In summary, these are the typical FPSO operating scenarios envisioned for offshore Port au Port, West Coast Newfoundland: a) FPSO with CALM Buoy b) FPSO with SALM Buoy c) FPSO with Soft Yoke FPSO with CALM Buoy The FPSO with a CALM Buoy mooring system will be the least expensive FPSO solution but will have operating and other limitations. The CALM Buoy is firstly, seastate limited, typically you cannot discharge cargo in seastates greater than 3.5-4.0 meters. This means, based on the environmental data for the area, you may experience downtime, any month of the year. Secondly, it would not be feasible to design the CALM Buoy mooring system to resist pack ice. Therefore, in the event of a disconnect, the CALM Buoy mooring system may be in jeopardy. Having stated the above, in spite of limitations, the FPSO CALM Buoy configuration should not be ruled out and should be the subject of further study during a Front End Engineering phase. The upside of a CALM mooring system is that there are hundreds in service around the world and “used” CALM Buoys are cheap and readily available. Further ice studies may show that with ice management/ice breaking, one may be able to remain on station with a CALM Buoy. FPSO with SALM Buoy The SALM Buoy offers operational advantages over the CALM Buoy. As a proven mooring/loading system in hostile, ice environments, the FPSO/SALM Buoy combination should permit the FPSO to operate at least 11 months per year, possibly 12 depending on pack ice conditions. As noted previously, at Sakhalin where the ice conditions are more severe, the SALM Buoy is laid on the seafloor during the Winter season. This feature is a plus. If it is deemed not feasible for technical or economic reasons to design a SALM capable of permitting the FPSO to operate year-round, offshore Port au Port then it is possible to ballast down the SALM, lay it on the seafloor, thereby protecting the mooring system for future re-connect. FPSO with Soft Yoke Tower A Soft Yoke Tower Mooring System, specifically designed to resist the ice and metaocean forces will permit year-round mooring/loading of an FPSO or FSO. This feature offers a significant advantage over the CALM or SALM Buoy. As the Soft Yoke Tower is a rigid structure, pile driven into the seafloor, we believe, with an ice shield


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 23 of 35 around the structure, it can provide a year-round mooring/export system for an FPSO or FSO. Year-round operations versus seasonal is preferred. From a seasonal perspective, even if the downtime is 1 or 2 months, there are many logistics and costs issues to deal with, such as: • Lost revenue due to lost production • Lost revenue during demob and remob. • Crewing considerations. • Flow assurance issues when wells have been shut-in for 2 months. • Effects of lost production and interruption of supply to your customers. 7.1.8 Subsea Wells If an FPSO is chosen as the production concept, subsea completed wells will be required. With twenty (20) producers and eight (8) injectors planned, manifolding on the seafloor will be the preferred option, so as to limit the number of lines coming into the FPSO. Two lines are suggested for producers as there should be provision for pigging, and one each for gas injection and water injection. 7.1.9 Drilling As there is no provision for drilling on a typical FPSO, a mobile drilling unit will be required to drill and complete the subsea wells. 7.1.10 Typical Operating Cost – Lease FPSO Assuming that both the FPSO and Bottom Founded Caisson are technically acceptable, the selection of an “optimum solution” depends also on economics, an option which will provide the greatest return with the least amount of risk. While a case can probably be made for using less expensive equipment and accepting seasonal production which would be the case for say an FPSO hull which is not ice strengthened, moored via a CALM or SALM Buoy, there is a greater element of risk presented to the project. Any time you connect or disconnect an FPSO, CALM or SALM Buoy, you introduce risk into the equation. Risk can never be fully eliminated but can be managed by sound engineering and operating practices. An FPSO moored via a Soft Yoke can be engineered for year-round operation. In this case, the risk is mitigated by sound engineering. However, under emergency conditions the FPSO can be released by a quick connect/disconnect (QC/DC) feature. For the purpose of this study, we have assumed year-round operation, based on a leased FPSO.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 24 of 35 Table 3.0 is a summary of typical operating costs for a leased FPSO. Table 3.0 - Typical Operating Costs – Leased FPSO (For 28 Well Scenario) Item Description Cost per Day

(USD) 1 FPSO (Bareboat)

160,000 bopd, 900,000 bbl storage 175,000

2 FPSO (Opex) 30,000 3 Shorebase Support

• 30 persons, $2,250,000 • office, $300,000 • Warehousing, forklifts, craneage, $750,000 • Marine Base, third party, $2,000,000 • Overheads, 35% (personnel, travel, vehicles, etc),

1,600,000 • Misc. (insurance, etc), $2,000,000 • Total, $7,500,000 ÷365 = 20,550/day

20,550

4 Logistics Support • Helicopter, $4,000,000 ÷ 365 = $10,100/day • Supply Boats, 2 x $40,000 = $80,000/day (with lubes

& fuel) • Ice Management, 1 boat, 3 mo., $45,000 x 90 days

÷365 = $11,100 • Weather forecasting, ice watch, $250,000 ÷ 365 =

700 • Total = $101,800

101,800

5 Drilling, 28 wells @ $25,000,000 ea. + 20% contingency = $840,000,000, amort. 10 yr., 10% = $11,100,000/mo x 12 ÷ 365 = $365,000/day

365,000

6 Completions • 28 wellheads, $125,000 x 28 = $3,500,000 • 28 SS Trees, 4 Manifolds, jumpers, hoses, flowlines,

$30,000,000 • Flexible risers/umbilicals/offloading hoses,

$30,000,000 • Running tools, spares, $5,000,000 • Total, $68,500,000, 10 yr., 10% = $905,100/mo x 12

÷ 365 = $29,750/day

29,750

7 Subsea Installation • 4 Manifolds, umbilicals, risers, flowlines, jumpers, 45

days • Pile drive & install Soft Yoke Mooring Sys, 21 days

9,050



• 1 Offshore installation/contruction vessel, 1 workboat • Mob/demob, $1,000,000 • Dayrate, $300,000, both vessels • $300,000 x 66 = 19,800,000 + $1,000,000 =

$20,800,000 • $20,800,000 amort. 10 yr., 10% = $274,900/mo x 12

÷ 365 = 9,050/day 8. Soft Yoke Mooring System, 30,000,000, 10 yr., 10% =

$396,500/mo x 12 ÷ 365 = $13,000/day 13,000

9 Engineering & Project management, 50,000,000, 10 yr., 10% = $660,700 x 12 ÷ 365 = $21,750

21,750

10 Maintenance & Repair • 7.5% of Capital Cost of Assets • FPSO, $450 million; Soft Yoke $30 million, Subsea

$69 million • 549,000,000 x 7.5% = 41,175,000 ÷ 365 =

$112,800/day

112,800

Total $878,700 7.1.11 Project Schedule If an FPSO solution is chosen for this project, the overall schedule from project sanction to first oil can be affected by many issues such as regulatory, engineering and construction time. Putting the regulatory time frame aside, the FPSO schedule will depend largely on whether a “new build” or “used” FPSO is deployed. Typically, a “new build” FPSO will add 12 to 18 months to a project schedule assuming you can secure a construction slot in a shipyard without great difficulty.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 26 of 35 The following schedule (Figure 13) is typical for a FPSO conversion.

Figure 13 - FPSO Conversion

Months 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24Project Sanction FEED Engineering Detailed Engineering Procure Long Lead Items FPSO Conversion Commissioning (FPSO) Procure Mooring / Export Sys. Install Mooring Sys. Drill Wells & Complete First Oil

7.2 Jack-Up A Jack-Up drilling rig modified to serve as a production facility is a proven East Coast Canada offshore production concept. The Lasmo Panuke Cohasset project (Figure 14), offshore Nova Scotia over a 6 year period, produced 49 million barrels of oil at an average rate of 40,000 barrels per day. The overall production concept consisted of the following elements: • Modified Rowan Gorilla III Jack-Up drill rig with production facilities. • CALM Buoy with moored FSO tanker. First oil was achieved June 3, 1992, 18 months following project sanction. However, for a 300 million barrel field, with 20 producers and 8 injectors, a converted drilling Jack-Up is not deemed feasible solution. Firstly, at a production rate of 160,000 bopd, the Topsides process facilities with water and gas re-injection is estimated to weigh 12,500 tonnes. Secondly, the variable deckload capacity of a typical drilling Jack-Up would be challenged to accommodate such a large process facility while at the same time maintaining a drilling package. Last but not least, 28 wells would prove to be a challenge for a Jack-Up while trying to maintain the disconnect option.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 27 of 35 Figure 14 – Jack-Up Drilling & Production Platform

7.3 Bottom Founded Caisson 7.3.1 General A third option for the shallow water Port au Port region is a Bottom Founded Caisson which is essentially a Gravity Base System. When one speaks of a Gravity Base System or GBS it is generally implied that the structure is constructed of concrete, for example the Hibernia GBS. However, over the past decade, engineering and construction advances have produced a new generation of GBS structures, less bulky and more cost effective than the early North Sea GBS and Hibernia GBS structures. An example of this new generation of GBS structures is the Aker Kvaerner PA-B Gravity Base Structure for the Sakhalin Phase II development in 30 meters of water, but the cost is still relatively high, in the US $900 million to $950 million range. Therefore, probably not feasible for this project. The Bottom Founded Caisson in its most simplistic form can also take the form of a barge. In Canada, the concept was first pioneered in the early ‘80’s by Gulf Canada and Dome Petroleum in the shallow waters (20-25m) of the Canadian Beaufort Sea. There, Gulf Canada deployed a mobile arctic caisson, octagonal in shape, namely the Molikpaq. Dome on the other hand deployed a bottom strengthened barge, the SSDC (Single Steel Drilling Caisson), which when ballasted sat on a submerged purpose built sand/gravel berm.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 28 of 35 A Bottom Founded Caisson generally constructed of steel can take on virtually any shape. The guiding principle is that its ultimate, ballasted in-place mass is sufficient to withstand ice and metaocean forces. In examining a Bottom Founded Caisson as an option, we studied the previously Gulf owned and built Molikpaq, now operating in the Russian archipelago of Sakhalin under new owners. The Molikpaq (Figure 15 & 16) is of steel construction and purpose built to withstand an ice-pack, hostile arctic environment. As a bottom founded structure, weight restrictions are typically not a problem and with ample footprint or deck space, drilling and production facilities can be accommodated. While there is no reason why oil storage capacity cannot be designed into the structure, the Molikpaq does not have internal storage, as it was initially designed as a drilling unit only, and therefore, oil storage was not required. As it is outside the scope of this study, we will assume that sand ballast is required to keep the Bottom Founded Caisson stable under ice-pack forces and that for now no internal oil storage is available.



Figure 15 – Bottom Founded Caisson – Molikpaq

Figure 16 – Cross section of Molikpaq


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 30 of 35 7.3.2 Production, Storage and Offloading Whether oil storage can or cannot be accommodated in a Molikpaq type Bottom Founded Caisson, a remote external export/loading system is still required. Such a loading system can be the SALM or Soft Yoke Tower. If internal oil storage is available in a Bottom Founded Caisson, the Export/Loading Buoy will serve as mooring/loading terminal for a shuttle tanker. If no storage is available within the Caisson, the Buoy will serve as a mooring/loading system for a permanently moored FSO with loading of a shuttle tanker via the stern of the FSO. Either the SALM Buoy or Soft Yoke Mooring/Export system discussed previously are options for the Bottom Founded Caisson concept. The SALM is more limiting but less costly. The Soft Yoke, while more costly, will ensure the year-round capability of loading/offloading. 7.3.3 Drilling An advantageous feature of a purpose built Bottom Founded Caisson is the ability to incorporate drilling facilities. By locating drilling and production on a common platform, there are obvious cost savings associated with crewing, logistics support and the sharing of common facilities such as power generation, utilities and the like. In addition, a purpose built Caisson with drilling facilities will provide an opportunity to design in sufficient slots plus spares for the drilling of the necessary development and injection wells. This is a significant advantage over the Jack-Up where wells slots can be limited. 7.3.4 Seasonal Vs. Year-Round Production A Bottom Founded Caisson is capable of year-round operations in an ice infested hostile environment. These systems are now well proven in the Canadian Arctic and offshore Sakhalin. However, logistics and loading/export systems such as the Soft Yoke Tower will require careful planning and engineering to ensure that they are not the weak links in a year-round system. 7.3.5 Typical Operating Cost – New Build Bottom Founded Caisson If a Bottom Founded Caisson was chosen as the preferred production option, it is unlikely that a “used” Caisson such as the Molikpaq would be available. For shallow to mid-depth water production worldwide, the most popular concept is a Jack-Up or some form of steel jacket. Bottom Founded Caissons have been popular mainly in hostile Arctic environments and as such not many units have been built. A Molikpaq type Caisson could be built at Bull Arm Newfoundland where the Hibernia GBS was built. Alternatively, it could be built in Asia as was the case for Molikpaq.


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 31 of 35 Table 5.0 – Typical Operating Cost – New Build Bottom Founded Caisson (USD) Cost Per Day 1. Molikpaq type Caisson New build cost USD $675 million, incl. Installation, transportation from Bull Arm, Commissioning. Amort. 10 yr., 10% = $298,000/day

$298,000

2. OPEX $30,000 3. Shorebase Support

• 30 persons, $2,250,000 • office, $300,000 • Warehousing, forklifts, craneage,

$750,000 • Marine Base, third party,

$2,000,000 • Overheads, 35% (personnel, travel,

vehicles, etc), 1,600,000 • Misc. (insurance, etc), $2,000,000 • Total, $7,500,000 ÷365 =

20,550/day

$20,550

4. Logistics Support $101,800 • Helicopter, $4,000,000 ÷ 365 =

$10,100/day • Supply Boats, 2 x $40,000 =

$80,000/day (with lubes & fuel) • Ice Management, 1 boat, 3 mo.,

$45,000 x 90 days ÷365 = $11,100 • Weather forecasting, ice watch,

$250,000 ÷ 365 = 700 • Total = $101,800

5. Drilling, 28 wells @ 25 million ea. + 20% contingency, $840 million, 10yr., 10% = $365,000/day

$365,000

6. Completions • 28 wellheads, $125,000 ea. x 28 =

$3,500,000 • 7 Trees (Land type) + access.,

$300,000 x 28 = $8,400,000 • Total $11,900,000, 10 yr., 10% =

$5,200/day

$5,200

7. Soft Yoke Tower, $30 million • $30 million, 10 yr., 10% =

$13,000/day

$13,000


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 32 of 35 8. Subsea Flowlines (2) from Caisson to

Soft Yoke Tower, Loading Hose FSO/Shuttle tanker & spare, $4.5 million, 10%, 10 yr. = $59,461/Mth. X 12 ÷ 365 = $1,950/day

$1,950/day

9. Installation of Soft Yoke Tower, Flowlines • MOB/Demob conversion vessel

with pile driver, $1.0 million • Install Soft Yoke Tower , 21 days • Install flowlines tower, 5 days • 1 construction vessel, 1 workboat • Dayrate, $300,000 bath vessels • $300,000 x 26 days = $7,800,000 • $7,800,000, 10%, 10 yr. =

$103,065/Mth. • $103,065/Mth. X 12 ÷ 365 =

$3,400/day

$3,400

10. Engineering & Project Management • $75 million, 10%, 10 yr. =

$991,000/Mth. • $991,000/Mth x 12 ÷ 365 =

$32,500

$32,500

11. Maintenance & Repair • 7.5% of capital cost of assets • $675 million + 12 million + 30

million + 4.5 million = 721.5 million x 0.075 = $54.1 million

• $54.1 million ÷ 365 = $148,000/day

$148,000

Total $1,019,400


Ptarmigan Resources Project Conceptual Engineering Study – Final Report Page 33 of 35 7.3.6 Project Schedule If a Bottom Founded Caisson is chosen, the overall project schedule from engineering through to construction and commissioning will be 48 months.

Figure 17 – New Build Bottom Founded Caisson

Months 1 2 3 4 Project Sanction FEED Engineering (6 Mth) Detailed Engineering (18 Mth) Procure Long Lead Items (12 Mth) Construct & Outfit Caisson (24 Mth) Tow-out & Install (3 Mth) Procure Soft Yoke Tower (12 Mth) Install Tower & Flowlines Procure & Modify FSO Install FSO Drill Wells & Complete First Oil



8.0 Conclusion During the course of this Study, we examined several potential options for offshore development and looked at current and past East Coast Canada Offshore projects such as Hibernia, Terra Nova, White Rose, Panuke Cohasset and international projects such as Sakhalin Island. Early in the Study, we eliminated further investigation of the GBS for cost reasons and the Subsea Tie-back for technical challenges in flow assurance. In keeping with the guideline of examining only “proven technology”, we investigated the FPSO, Jack-Up and Bottom Founded Caisson. The Jack-Up was subsequently deemed not feasible for a 300 million barrel recoverable reserves case producing at 160,000 bopd. A typical converted Jack-Up could not accommodate the estimated 12,500 tonnes of Topsides required to support 160,000 bopd and the platform would be challenged to accommodate 28 wells. It is the Conclusion of this Study that the FPSO or Bottom Founded Caisson represents the best alternatives for Ptarmigan’s Offshore West Coast acreage. There are pros and cons for each option with the merits of each clearly identified in the Study. The FPSO represents a smaller investment, shorter overall project schedule but slightly more risk in terms of achieving year-round production. The Bottom Founded Caisson on the other hand presents less production risk, but is more costly and has a much longer project implementation schedule. In closing, we feel both options are viable alternatives and in making a final selection, you would need to conduct an in-depth risk analysis and more detailed costing. You may well find that the FPSO’s year-round ability to maintain full production is a manageable risk in which case its cheaper cost and reduced project schedule will give it an edge over the Bottom Founded Caisson.




9.0 Appendix

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