This document presents a Pseudo Dry Gas (PDG) separation technology that can significantly increase the distance that remote gas fields can be tied back to shore. The technology uses compact inline separators and small pumps to remove liquids from the gas stream, allowing larger diameter pipelines that experience lower pressure drops over long distances. A case study shows how applying this technology to a 170km trunkline could increase production by over 160 MMscfd and generate an additional $10 billion in revenue by reducing wellhead pressures. The system is presented as a lower-cost alternative to standard subsea tiebacks or using floating production vessels for fields located further than current tieback limits.

1. www.advisian.com
Pseudo Dry Gas System
An enabling technology for remote gas fields
www.intecsea.com
20th June 2018

2. Perceptions of a Problem
Quotation from Henry Ford
“If I’d asked my customers what they wanted, they’d have
said a faster horse”

3. Objective
• Present an innovative Pseudo Dry Gas (PDG) separation technology to demonstrate
that tie backs far in excess of the current threshold distance can be achieved.
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0 20 40 60 80 100 120 140 160
WaterDepth(m)
Tie Back Distance (Km)
Single Pipeline Dual Pipelines Subsea Existing / Planned Compression
Limit on dual pipeline
design envelope
Limit on single pipeline
design envelope

4. Underlying Problem
ΔP
Less ← Flowrate → More
ΔP
Smaller ← Diameter → Larger
• Gas pipelines diameter
choice is a compromise
between lowest well back
pressure Vs operability
driven by liquids
• More distance =
Greater Compromise =
Greater Back Pressure =
Less Revenue =
Lower NPV =
Stranded Gas Reserves
Fixed Flowrate
Gravitational
(Slugging)
Gravitational
(slugging)Frictional Frictional
Fixed Diameter

5. Solution
• Multiple compact (in-line) piggable
separators (PDG)
• Remove liquids via small ø liquid pipe
• Small single phase centrifugal pumps
(kW)
• Allows significantly larger pipeline
• Enable dry gas behaviour (lower back pressures)
• Plug and play units at each location
Gas Treatment Facility
Gas Pipeline
Manifold
Tree
Liquid Removal Unit
Liquid Pipeline
Mainline Pump

6. Coal Seam Gas - Overview
• Drain points are a proven solution for Coal Seam Gas gathering networks in
Queensland Australia

7. Coal Seam Gas - Overview
Pressure (KPa) Wet Gas Dry Gas Wet Gas
(LPDs)
P drop 133 18 22
Increased pressure drop is caused by water
Separators added to
simulate Drains

8. Case Study - Context
• Trunkline; 170km long
• WD 0-1800m, no escarpment
• Two manifolds and 9 satellite wells
DESIGN REQUIREMENTS
Design Flow Rate = 880 MMscfd
Turndown Rate = 380 MMscfd
Arrival Pressure Early Life = 60 bara
Arrival Pressure Late Life = 30 bara
LGR = 12 bbl/MMscf
Infield flowlines between 2-5 km
Onshore LNG

9. Case Study - Pipeline Sizing
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SurgeVolume(m3)
TrunklineInletPressure(bara)
Trunkline Size ("NPS)
Line Size Selection (LGR = 12 bbld/MMscf) - Shore P=60bara
Trunkline Inlet P at 880 MMscfd Trunkline Inlet P at 380 MMscfd Ramp-up Volume from 380 to 880 MMscfd
Turndown driving selection

10. Production Impact
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960
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GasFlowrate(MMscfd)
WellheadPressure(bara)
Time (Years)
Flow Rate
Accumulative
lost Production
Lost revenue at
US$10 billion
≈ US$6/MMbtu
End of production 60
bar arrival pressure
End of production 30
bar arrival pressure

11. PDG System Design Methodology
Standard subsea tieback approach:
• Liquid holdup dictates sizing
• Shortened plateau period
The solution is to mitigate the liquid phase
• Pipeline sizing no longer constrained by fluid management (30” + selected)
• Flow assurance used to determine optimal placement of PDG separators.
The design considers: - Temperature profiles (design and turndown)
- Terrain, liquid hold up and flow regime
- Transient cases, i.e. shutdowns and start-ups
- Installation constraints

12. PDGS Placement
• 6 PDGS units required in the configuration below
• Separation efficiency linked to separator design in relation to FA outputs
Infield flowlines between 2-5 km
Onshore LNG
Last unit 80km from LNG plant after which
gas no longer condenses liquid

13. PDGS Enabled Tie-back Hydraulics
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20
40
60
80
100
120
140
160
60 bara, 880 MMScfd 60 bara, Turndown 30 bara, 880 MMScfd 30 bara, Turndown
RequiredPipelineInputPressure
Standard FA (30") PDG System (36") Dry Gas (36")
• 55 to 80 bar reduction in wellhead back pressure across design cases
70-120+ bar in
actual studies 1
Bcf/d

14. PDGS Enabled Tie-back – Production Impact
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960
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GasFlowrate(MMscfd)
WellheadPressure(bara)
Time (Years)
Accumulative
increase in
Production
Increase of revenue
at US$6/MMbtu ≈
US$10 billion
Flow Rate
End of production 60
bar arrival pressure
End of production 30
bar arrival pressure

15. PDGS Enabled Tie-back Hydraulics
0.001
0.010
0.100
1.000
10.000
100.000
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TrunklineLiquidHoldup(%)
Horizontal Distance (km)
Std FA - 880MMscfd - 30in TL PDGS - 880MMScfd - 36in TL
% on log scale
Effective
Dehydration
No membranes
No consumables
No pressure loss
Suppression of
hydrocarbon phase

16. Economic Advantage
With PDG system implementation, CAPEX intensive structures can be removed without impacting
recoverable reserves and significantly reducing upfront cost, which improves the overall NPV / IRR of
the potential project
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3500
Development Options
CAPEX(US$'0000')
Standard Tie Back
PDG Tie Back
Floating Vessel and Tie
back
1.5bn
1.9bn
3.2bn

17. Liquid Removal Unit as an In-line Structure
• Installed as a pipeline in-line structure – low CAPEX
• Liquid Removal Unit performance meets requirements from ‘case study’
• Based on experimental data and CFD
• Gravity based with venturi aided flow separator
• No moving parts (passive) or consumables
• Piggable

18. System Readiness
Element TRL (API) Notes
Pipeline 7 Ultra-Deep Water Pipeline (Phase 1), Pipeline Research
Council Intuition (PRCI) and Projects
Power 6/7 Calculations and identified equipment (0.5 MW for reference
case Vs 36 MW for Compression)
Controls 7 Calculations and identified equipment
Liquid Removal
Unit
2→3 CFD aligned to experimental data - (passive within gas
stream)
Pumps 6/7 Multiple pump manufacturers identified for pump duties
PDG prototype testing scope to begin Q1 2019
One element remains before system integration testing

19. Conclusions - Increase in Tie back Distances
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WaterDepth(m)
Tie Back Distance (Km)
Single Pipeline Dual Pipelines Subsea Existing / Planned Compression PDG System

20. Conclusions – Applications – North Sea
Acreage that can be
developed at 50% less
CAPEX – (without floating
vessels) or loss of
production in reserves

21. Thank you – any questions?
lee.thomas@intecsea.com
terry.wood@intecsea.com