Subsea processing drivers, technical constraints

and production recoverability for longer and

deeper gas field developments

Session: New Trends in Flow Assurance

Terry Wood, Chief Engineer – Flow Assurance and ProcessPerth Convention Exhibition Centre, 11th March 2015

Objectives Modelling methodology Processing technologies Trends in recovery Commercial impact Review constraints Future direction Conclusions

Agenda

To compare and contrast current processing state of art (e.g. onshore compression) with emerging technologies (subsea separation) using integrated production modelling techniques

Objectives

Six processing arrangements were analysed:

1. Natural flow (baseline)2. Onshore compression3. Subsea separation only4. Subsea compression only5. Subsea separation and onshore compression6. Subsea separation and subsea compression

Each processing arrangement was tested against four variables:

1. Pipe slope (3°, 4°, 5°)2. Water depth (500m, 1000m, 3000m)3. Tieback distance (100km, 150km, 200km)4. Water/gas ratio (Low - 0.5bbl/MMSCF, Mid - 10bbl/MMSCF, High - 70bbl/MMSCF)

Number of simulations required to test all combinations: 486

Subsea Processing for Gas Field Developments

Constant parameters: Net to gross: 95% Porosity: 28% Water saturation: 25% Fixed draw down of 2e-5 GIIP = 5 TCF

Gas developed using maximum 10 wells through 5” tubing – max flow of 60 MMSCFD/well

Model Overview – Reservoir & Subsurface

Reservoir

Choke

Model Overview - Surface

Subsea compressorOnshore

compressor

Reservoir

Subsea 2-phase

separator

LNG terminal

Liquidoutput

Choke

Connectors activated/deactivated to construct different processing arrangements

Minimum turndown of 25% imposed on results

Lean gas composition with little hydrocarbon liquids condensing

Economics does not take into account amount of condensate in gas or loss in the reservoir

Cost of gas $10,270/MMSCFD

Discount rate of 0.1

Constraints on subsea processing units were not imposed initially

No additional volumetric flow rate associated with hydrate inhibitors was added to the water rates

Life of field simulations conducted for twenty years

Equipment associated with each case was operational from year 1

Key Assumptions

Each case contains data over a twenty year life of field simulation; the key data available includes:

Results

What is the Value?

What is the Value?

What is the Value?

What is the Value?

What is the Value?

$5B

Tie-back distance of 100km Mid WGR

Water Depth Trend

WGR Trend

Tie-back distance of 100km Water Depth of 3000m

Water Depth – 3000m High WGR

Tie-back Trend

Subsea Processing Poster in 2014 Offshore Magazine

Power Limit power to 36MW – 3 x 12

MW subsea compression trains No limit on onshore

compression Differential Pressure

Limit DP to 100 bar for subsea compression trains

No compression trains in series Limit DP to 200 bar for subsea

pumps Pipeline size

Evaluate Constraints

Tie-back distance of 100km Mid WGR

Water Depth Trend with Constraints

WGR Trend with Constraints

Tie-back distance of 100km Water Depth of 3000m

Water Depth – 3000m High WGR

Tie-back Trend with Constraints

Closing Thoughts Integrated production modelling with subsea processing plays an

important part in determining the value early in the development phase

Independence from equipment vendors is key to examine all potential options

Determines the small pre-investment in subsea layout to accommodate future processing requirement

Easy to add existing constraints on subsea equipment and determine significant OPEX costs (i.e. Power)

Future Direction Develop model to include CAPEX & OPEX and hence NPV for all

potential field development options

Closing Thoughts and Future Direction