Flow Assurance Technology Options & Pipe Sizing for Deep-Water & Long Distance Oil & Gas Transport.

Agenda Introduction Flow Assurance Challenges. Flow Assurance Solution Options. Technologies- GTLA. Design Process Through an Integrated System Approach. Multiphase Pipe sizing Charts Summary

Flow Assurance “The ability to produce fluids economically from the reservoir to a production facility, over the life of field in any environment “ Deepstar. “The term Garantia de Fluxo” Coined by Petrobras in the early 1990’s, and translates literally as Guarantee the Flow.

Flow Assurance ? Costly and conservative FA Engineers – Trouble makers “ A structural engineering analysis process that utilizes the in-depth knowledge of fluid properties and thermal hydraulic analysis of the system to develop strategies for control of solids such as hydrates, waxes, asphaltenes and scale” OTC #13123 To produce and transport fluids from the pore throat of reservoir to the host facility Throughout life cycle of field Under all operating conditions In a cost-effective way Forget flow assurance Industry needs performance assurance Costly and conservative FA Engineers – Trouble makers Typical Subsea Engineer Keep the flow path open! Goals: Reduce risk of lost or reduced production Enhance production rate FA strategies must be integrated into overall systems design and field operations SL-Shell The broadest link throughout the production system Cross-Functional, Cross-Team Discipline From Project Conception to Operations

Flow Assurance Challenges Blockages Gas Hydrates Paraffin / Ashphaltenes Scales Liquid Slugging Low Temperatures Sand / Erosion Corrosion Emulsion/ Foam Flow Assurance Integrity Operational

Gas Hydrates: Formation & Structure Solid Ice-like crystal Hydrocarbon molecules trapped inside water “cages” Hydrate Formation occurs when Water + light HC Formation temperature (higher than freezing) depends on pressure, can form > 15 °C Approximately 85% water, 15% HC Gas volume – 150-200 scf/ft3 hydrates

What Problems Can Hydrates Cause? Blockage of pipeline and flowline Block line completely Plugs up to 6 miles Plugs in up to 40” pipe Production downtime Time and cost of remediation Serious safety issues During drilling or completion Plug blow out preventers Collapse tubing and casing Worsens as water depth increases Spans life cycle of field Courtesy of Petrobras

Compositional Tracking Normally Based on Hydrate Dissociation Curve Reservoir Composition is usually used. However the composition varies with Shut Down Compositional Tracking of Benefit Increased cool down time Reduced Insulation Requirements Precious additional time prior to hydrates

Pipeline / Riser System during Shut Down Oil/Wat Gas

Case Example Hydrate Curves for Pipeline Shut Down (GOR=3000scf/stb) 20 40 60 80 100 120 140 160 180 5 10 15 25 30 Temp.(C) Pressure (Bara) 29 Barg Shutdown 95 Barg Shutdown 95 Barg Flowing

Cool Down at Riser Mid Point 10 20 30 40 50 60 0.3 1.4 2.5 3.6 4.7 5.8 6.9 8.1 9.2 10.3 11.4 12.5 13.6 14.7 15.8 16.9 18.1 19.2 20.3 21.4 22.5 23.6 24.7 25.8 26.9 28.1 29.2 Time (Hrs) Temp.(C) 24788 30709 36491 42131 47632 52991 58210 63289 Reservoir Composition Shut in Composition (bopd)

Cool Down at Pipeline Inlet

Pipeline & Riser Slugging Insufficient gas velocity in riser Liquids accumulate at bottom of riser Upstream pressure builds sufficiently to overcome hydrostatic head in riser Slug of liquid is expelled, followed by gas which has packed behind blockage Liquid accumulation at riser base seals off gas flow Flow out of riser stops Slugging Types: Hydro-dynamic Terrain Riser induced Liquid continues to accumulate at the riser base Riser begins to fill with liquid Pressure builds upstream of the blockage

FA – Consequences of Slugging Safety to personnel and equipment Unstable production Equipment trips Total field shutdown Loss of revenue e.g. 100mbpd field shutdown: loss of $5m /day @ $50/bbl & $10m @ $100/bbl

Asphaltenes Polar components in crude oil Stable in presence of resins Resins diluted by gas release and injection Flocculate in wells and topside equipment Prediction via SARA analysis Saturates, Aromatics, Resins and Asphaltene fluid property analysis. Asphaltene content: amount of material insoluble in n-heptane (or n-pentane) but soluble in toluene Precipitation is induced by pressure decrease and/or changes in the solvency of crude oil (by low MW n-paraffins, CO2, acids, etc) Minimum solubility at bubble point S.L&B.E-2000

Emulsions Consequences Tight emulsion between water and oil causes inversion viscosity High pressure drop in pipelines Separation efficiency impaired Shut-in conditions can cause rheology change to Non-Newtonian behaviour High yield stress at low shear rates require very high pressure to start up pipeline. Viscosity at Low Shear Rate (cPoise) 10 20 5 100 10,000 Newtonian Non-Newtonian Shear Stress Shear Rate S-1

FA – Sand Erosion Consequences: Material Loss Pipeline leaks Separator Efficiency Erosion Velocity Limits Requirement for CRA materials

FA – Corrosion Issues: Development of Anti-Corrosion Strategies Integrating Multi- Phase Flow De-Ward Milliums

Low Temperatures – Well Start-Up Issues: Prod. Hydrates S/U Material Integrity Prod. Loss System S/D Safety Mitigation: Flowline Insulation Operational

Un-necessary Operating Problems Potential Flow Path Blockage FA Consequences Incorrect System designs Un-necessary Operating Problems Potential Flow Path Blockage Resulting Production Shut down Consequential Revenue Loss In the extreme: Loss of Asset.

Flow Assurance – Solution Options Fluids Handling Mix Chemicals – Thermodynamic, Kinetic, THI, AA Heat Retention – Insulation (Passive) Provide Heating : Fluids / Circulation, Electrical, Other Active Methods Remove Heat – Change Rheology (Cold Pipe Slurry) Separate Fluids Re-Combine Fluids – Subsea GTLA Others

Enabling Technologies Subsea Processing Separation Multiphase Pumping Metering Subsea Gas Compression Oil Gas Water Reservoir Separator/Boosting FPSO Tanker Tree To FPSO Multiphase Transport Coselles Pipeline Thermal Management Raw Sea Water Injection Gas to Liquids Conversion Gas to Liquids Absorption Other Emerging Technologies

Technology- FA Cost Vs Benefit Map Risk Cost (Capex / Opex / Intervention) Chemicals Microbes ? Slurry Transport Active Heating Electrical Induction Trace Liquid Circulation Down Hole Processing (ESP/HSP) Subsea Processing PIP Draining Systems Multiphase Pumping Pigging Slug Control Subsea G-T-L-A Low Cost Insulation Liquid Boosting Intelligent Slug Control Simplicity Chemicals Benefit

What is GTLA ? Gas to Liquid Absorption. Process of Gas Absorption of C1-C3,, CO2,H2S by high gas solubility liquids. Fluids Phase Equilibrium Change. Recovery of Oil Light End Components (C3-C8). Multiphase to Liquid Only Transport. Considerable Benefits (Capex / Opex). Innovation / Value.

What is GTLA ? 3 Components to GTLA: Subsea Achitecture & Absorption. Transportation. Host Facilities Processing. System configurations – Reservoir fluids characteristics.

Hydrate Blockage Risks Conventional Production Rates Gas Water GTLA Oil 5 10 15 Years

Wax Blockage Risks Conventional GTLA Years Production Rates Gas Water Oil 5 10 15 Years

Marginal Field Development GTLA Floating Processing Power/Umbilical G-T-L-A Absorber Liquid Pump No Manifold No Well to Manifold lines No PIP / insulation Single Production Line Water Injection

Impact of GTLA Technology on Hydrate Dissociation. Hydrate Envelopes 20 40 60 80 100 120 140 -60 -52 -44 -35 -27 -19 -11 -2.3 -0.1 0.01 0.32 1.54 7 10 12 14 16 18 Temperature (C) Pressure (Bara) Normal GTLA Water Temperature 2000m - Angola

GTLA Technology Benefits Technical No Slugging No Hydrates or Wax Reduced Corrosion Reduced Scale Reduced pipe wt, expansion & stress, upheaval buckling, expansion joints and burial. Reduced Riser fatigue Increased Safety, Availability, Reliability & Recovery Pressure Boosting via Liquid Pumps. Economic One Production Pipeline No Pipeline Insulation No Manifold 60% Pipeline Capex reduction (no insulation and use of CS rather than CRA) Use of SCR’s Smaller Umbilical Size No Hydrate or Wax inhibitors Reduced Interventions.

Integated System

Integated System- General Basis Sizing of Subsea Infrastructure: System Data: Reservoir Pressure = 200bara & Host Pressure = 15bara. Reservoir temperature = 60deg.C. Well Tubing = 5” & 1500m length. Sea bed and sea surface temps. = 5 & 15deg.C. Oil Viscosity = 15, 20 & 30 degrees. Water Depth =100-2000m Tie-back Distance = 10-50km. U = 3W/m2.K Constraints: Erosion Limit = C factor of 150 carbon steel pipe. Hydraulic Limit = Based on max Well Head pressure (150bara)

Integated System Infrastructure

Integated System-Charts

Integated System-Charts

Integated System-Charts

Integated System-3D Chart

Integated System-3D Chart

Flow Assurance Technology Options & Pipe Sizing for Deep-Water & Long Distance Oil & Gas Transport.Transport Requires: Innovative Flow Assurance Solutions Better use of existing & New Technologies Overcoming Fear to Change Offer Value Added Benefits Low Risks Beware: Operators are queuing up to be 2nd or 3rd to use new technology. Cost of Change Opportunity to Change Detailed Design Exploration Appraisal / FEED Operations

I would be happy to answer any easy Thank You I would be happy to answer any easy questions Cost of Change Opportunity to Change Detailed Design Exploration Appraisal / FEED Operations