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UNIVERSITY OF WESTERN AUSTRALIA

Concept analysis of Gas Field

Marine Special Topic 1 OENA 8588

Krisitan Odland 21180174

5/24/2013

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CONTENTS

Contents ................................................................................................................................................................................ II

Figures ................................................................................................................................................................................... II

Table ....................................................................................................................................................................................... II

Introduction ......................................................................................................................................................................... 1

1 Sketch of two options ................................................................................................................................................... 1

Option A - Tieback from wellhead to topsides facilities................................................................................ 1

Option B - Subsea-to-shore tieback to LNG processing onshore ............................................................... 2

2 Advantages & Disadvantages .................................................................................................................................... 2

Option A Platform ...................................................................................................................................................... 2

Option B Subsea to Shore tie-in ........................................................................................................................... 3

3 Basic Carbon Steel vs Corrosion Resistant Materials ...................................................................................... 4

4 Cost estimate for option B .......................................................................................................................................... 2

Input data for corrosion calculations .................................................................................................................... 2

Carbon steel ..................................................................................................................................................................... 2

Carbon steel + Chemical Corrosion Control ....................................................................................................... 2

Cost estimate for option B .............................................................................................................................................. 2

References ............................................................................................................................................................................. 3

APPENDIX 1 ........................................................................................................................................................................... i

Cost estimate - Carbon steel pipe with anti-corrosive inhibitor ................................................................ i

Cost estimate - Corrosion resistant alloy (CRA) ................................................................................................ i

FIGURES

Figure 1 - Sketch of tieback from wellhead to topsides facilities ................................................................... 1 Figure 2 - Subsea-to-shore tieback to LNG processing facilities onshore ..... Error! Bookmark not defined.

TABLE

Table 1 - Platform advantages & disadvantages ................................................................................................... 3 Table 2 - subsea-to-tie in................................................................................................................................................. 3 Table 3 input data for corrosion calculations ........................................................................................................ 2 Table 4 calculation of corrosion allowance ......................................................................................................... 2 Table 5 - Corrosion resistant inhibitor...................................................................................................................... 2 Table 6 Cost estimate for option b .............................................................................................................................. 2 TABLE 7 - DETAILED COST ESTIMATE FOR CARBON STEEL PIPE INHIBITOR ......................... i

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INTRODUCTION

Two development options are explored for a new gas field:

Option A - Tieback from wellhead to topsides facilities Option B - Subsea-to-shore tieback with LNG processing onshore

In addition a cost estimate is performed for Option B, and through-life- factors regarding material selection for pipeline are discussed. There has been some uncertainty regarding dissimilar information given in lecture 4 and the assessment description. However, following the initial project description no calculations of corrosion rates & costs are done under section 3.

1 SKETCH OF TWO OPTIONS

Speaking for both concept developments factors regarding route length, technical feasibility, environmental impact, safety and economy have been important.

The following main aspects have been considered in pipeline route selection:

Seek level, smooth and stable seabed Avoid steepest area around the scarp Minimize total pipeline length (straight lines when possible). Minimize exposure-length of pipeline in shipping channel due to risk of dropped objects. Avoid mobile sand wave, even if pipeline needs to go in a steep area east of it. Use horizontal drilling or tunneling near shore due to cyclonic storms, low shelter along

shore and to obtain low environmental impact for people in the town using the beach. Select an area for shore approach which is favorable regarding depth and distance needed

for horizontal drilling (at a depth of circa 20 meters, erosion becomes little) Trench the entire length and reinforce pipe protection (if needed) over shipping channel. Maintain sufficient stability for the entire pipeline route.

OPTION A - TIEBACK FROM WELLHEAD TO TOPSIDES FACILITIES

FIGURE 1 - SKETCH OF TIEBACK FROM WELLHEAD TO TOPSIDES FACILITIES

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The platform is suggested to be located roughly 40 50 km southeast from gas field in a depth of approximately 450 meters (fig.1) for the following main reasons:

1. A safe distance to the gas field in occasion of a gas field blow out. 2. Avoid strong currents up the scarp and rough seabed 3. Be within an economically feasible distance from manifold to platform, regarding

cost of dual flow lines for multiphase gas, electricity supply etc. 4. Avoid having platform in shallow waters where cyclonic storms occurs(< 200m)

Because the location is in a deepwater area, floating production facilities are preferred. A TLP, SPAR or Semi-submersible could be used. Limiting the complexity of the platforms mooring system regarding water depth has been considered. The steep slope down slide (50-60 m depth) may be a challenge for pipelaying and intervention work due to high current velocities and should be carefully studied.

OPTION B - SUBSEA-TO-SHORE TIEBACK TO LNG PROCESSING ONSHORE

The pipeline route selection for OPTION B is suggested roughly the same as for OPTION A. Some short cuts may be made as there is no need to consider the platform location.

2 ADVANTAGES & DISADVANTAGES

OPTION A PLATFORM

Advantages Disadvantages Facilities Location Floating production facility offers mobility and

possibility for re-use. Floating topsides facilities have limitations on payload/storage.

Economics Lower CAPEX compared to CAPEX of subsea solution, in general.

Offshore crew, accommodation facilities and transport needed

Materials selection & Corrosion

Processed gas offers lower corrosion risk & less hydrate formation, thus lower material costs, compared to a subsea-to-shore tie-in.

Complex deepwater mooring system & flexible risers. Riser prone to external sheath damage during installation.

Hydrate Inhibition Less exposed to hydrate accumulation in export pipeline.

Flowline -distance is 40-50 km, thus still exposed to hydrate formation in area of HP/LT.

Ease of Inspection

Physical Inspection is easier. Dry trees may be used with TLPs & Spars, giving well access at surface Easy access to flowlines with surface processing

Still requires inspection at seabed with ROV/AUV. Wet Trees may also be favorable.

Controls

Most control facilities are located at topside. Power supply may be provided from platform.

Route Selection

In some cases route selection is quite similar to a subsea-to-shore tie-in solution.

Need to consider depth for mooring system on platform. Extra step due to vertical fluid transportation to platform

Environmental considerations

Emerging riser technology trends Vulnerability regarding platform motion& operability and production riser system exposed heave motion and VIV Interference with shipping traffic, fisheries etc.

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Construction Less complex installations at seabed required with platform facilities

Platform installation & transportation is complex. Specialized vessels needed

Reliability

Low downtime during maintenance Better flow assurance in pipeline due to processing offshore

Production can be limited by weather conditions

TABLE 1 - PLATFORM ADVANTAGES & DISADVANTAGES

OPTION B SUBSEA TO SHORE TIE-IN

Advantages Disadvantages

Facilities Location No need for permanent offshore surface facility & optimal location of wells & manifolds can be achieved

Distance may create difficulties regarding power supply and electrical communication

Economics

The 10 n rule: Num of Wells (6)*10 < Depth (1200m) suggests -> Subsea Solution Large production capacity

High CAPEX Multiphase flows has higher pressure drop than single phase

Materials selection

& Corrosion

New technology and industrial research today provides new alternatives

Equipment at seabed needs to resist HP/LT, thus higher material costs May need: 1) thermal insulation to avoid hydrate formation & 2) thicker wall to allow corrosion

Hydrate Inhibition Increased knowledge on how to prevent hydrate accumulation

MEG injection required & multiphase may need to be heated up to avoid hydrate formation

Ease of Inspection

New technology and deepwater equipment makes it possible/feasible with deepwater intervention.

High maintenance - and repair costs & low availability Difficult to access flowlines for intervention and inspection.

Controls

Complex control assembly and is dependant on the use of wet-mate high-power and/or optical connectors

Route Selection

Little or no interference with offshore constructions/ship traffic (flexible alternatives). Pipelines may be used for other projects(tie-in).

Route still needs to be protected against fish trawlers, dropped objects etc.

Environmental considerations

Less exposed to environmental forces than a platform.

Big subsea modules at seabed may be exposed to

high currents and loads.

Construction

Installation of large subsea modules possible with a specialized vessel & good weather conditions.

Uncertainty of regulations regarding abandonment

of subsea pipelines.

Installation of large subsea modules complex and

may need heavy lift vessels.

Reliability

Tree and well access at the seabed isolated from people Wet Trees gives simplified riser/vessel interfaces

Additional pressure to reservoir likely to be needed

and electric submersible pumps (ESPs) currently

has a lifetime of around 2 years from installation.

Hydrate formation may plug production lines, stop production and is difficult to remove.

Must incorporate inaccessibility & design for high

redundancy in system

Liquid slugs may damage onshore facilities

TABLE 2 SUBSEA TO SHORE TIE-IN

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3 BASIC CARBON STEEL VS CORROSION RESISTANT MATERIALS

Basic Carbon Steel CRA

Safety, reliability and security of

production

Positive Few hazards that cant be addressed Good standards (DNVs ALARP) Cost of safety grossly disproportionate to increased safety

Negative

Inspection, transport and use of inhibitor gives increased risk of failure Availability of injection system < 100% leading to downtime in operation and high cost

Positive No corrosion (generally), thus more reliable and may have higher safety Less complex system (no inhibitor system needed) Easier to predict maintenance expenses

Negative Less experience with CRAs Fabrication Defects (Selection based on published corrosion/cracking resistance envelopes)

Hazards

Negative Exposed to many types of corrosion: Bottom line corrosion Sulphide corrosion Top of the line corrosion, Internal oxygen corrosion Galvanic corrosion Microbial induced corrosion

Negative More susceptible to failure modes like: cracking, embrittlement, fatigue and poor welds Stainless steel impacts: break in film due to chloride concentration, oxidizing species etc. gives pits, narrow mouthed and deep.

Environment Negative Chemical Injection storage & disposal

Positive Low environmental impact

Maintenance & Inspectability

Negative High initial cost of injection system (tanks, pumps, umbilical) Cost of chemicals for maintenance (in addition shipping/ handling costs) Compatibility problems regarding other pipeline chemicals Operator & Operation costs of injection system Regular inspection & repair due to corrosion. intelligent pigging, change of anodes etc.

Positive No corrosion in general (low maintenance)

Negative Inspection of failure modes like cracking embrittlement and fatigue needed.

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Fabrication & materials

Negative Corrosive material

Positive Easy to weld Material is cheap compared to CRA

Negative Expensive and limited materials available for pipelines by welding Special weld procedures. Lower yield strength in heat affected zone, regaining strength by cold working, aging etc. cannot be applied. Have to increase thickness Single alloying minimizes material costs, but chromium has poor weldability. Need a blend of chromium, nickel & iron

Positive

New alloys intermediate in price between carbon steel and duplex steels. Weldable and suitable for HT sweet & sour service, limited by chloride content of product AISI 316 Stainless Steel immune to CO2- corrosion

4 COST ESTIMATE FOR OPTION B

In order to give a cost estimate for Option B, a material selection has to be executed. Material selection is based on corrosion numbers and economical feasibility. Carbon steel without a corrosion resistant inhibitor is found unfeasible due to a high corrosion number (see tab 4). A cost estimate is then executed for two material alternatives:

1. Carbon Steel with corrosion inhibitor 2. Corrosion Resistant Alloy

INPUT DATA FOR CORROSION CALCULATIONS

Temperature 393,15 kelvin

Pressure 300 bar

Amount of CO2 0,06 -

f CO2 18 bar

pH actual 6 -

TABLE 3 INPUT DATA FOR CORROSION CALCULATIONS

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CARBON STEEL

The results presented, using deWaard and Lotz equation shows that carbon steel is not a feasible solution without an anti-corrosion inhibitor. Over a 20 year design life we need a corrosion allowance equal to 30, 4 mm. All hazards except bottom line corrosion are ignored.

CARBON STEEL + CHEMICAL CORROSION CONTROL

By using a corrosion resistant inhibitor, corrosion allowance is reduced to 3, 4 mm for the design period of 20 year. This is within a feasible corrosion allowance of 10 mm.

Reliability of injection 95 % V inhibited (lab tested) 0,1 mm/yr V unhibited corrosion rate 1,52 mm/yr V average 0,171 mm/yr Corrosion allowance 20 year 3,4 mm

TABLE 5 - CORROSION RESISTANT INHIBITOR

COST ESTIMATE FOR OPTION B

From the cost estimate (tab 6) it is clear that material costs and installation cost related to CRA pipes overrules the fact that you dont need chemical injection and inspection during operation.

The following assumptions are made:

Survey time of 3 months (Lecture 2) 10 km onshore pipe installed (from map) Corrosion inhibitor skid (5 mill) included in injection system & installation costs (50 mill ) Carbon Steel + Inhibitor needs intelligent pigging every 10 years (Lecture 4)

Total cost estimates for the two materials are as followed:

Carbon Steel + Inhibitor CRA Materials & Fabrication $154,2 mill $700,0 mill Survey & Installation $291,0 mill $591,0 mill Maintenance & Inspection $1 mill - Chemical Injection $77,3 mill - Total Cost $523,5 mill $1291,0 mill

TABLE 6 COST ESTIMATE FOR OPTION B

A more detailed cost estimate is presented in the next in Appendix 1.

deWaar and Lotz Equation for F scale 0,045 - pH saturated 3,583 - pH actual 6 - F pH 0,169 - Uncorrected V - corrosion 201,42 mm/yr Uninhibited Corrosion Rate V un 1,52 mm/yr 20 yr lifetime 30,4 mm

TABLE 4 CALCULATION OF NEEDED CORROSION ALLOWANCE

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REFERENCES

Woodgroup Kenny (2013) Lecture slides in the unit Special Topic 1 (OENA8588) at UWA

Lee (2009) - Introduction to Offshore Pipelines and Risers Owe (2011) - Slide presentation - SUBSEA COMPRESSION - APPLICATION ON ORMEN LANGE Shell Exploration & Production (2012) - Overview of Ormen Lange Project http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGupta2012.pdf [22.05.13]

peter osmundsen

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APPENDIX 1

COST ESTIMATE - CARBON STEEL PIPE WITH ANTI-CORROSIVE INHIBITOR

TABLE 7 - DETAILED COST ESTIMATE FOR CARBON STEEL PIPE INHIBITOR

COST ESTIMATE - CORROSION RESISTANT ALLOY (CRA)

TABLE 8 - DETAILED COST ESTIMATE FOR CRA