Extending The Life Of Subsea Wells With Long Tiebacks By Foamer Injection 18 May 2016 Obinna Ugoala – Presenter Andrew McMahon, Gatsbyd Forsyth, Jishnu BordoIoi, Jon Bradley, Liam Newson, Kevin McNamee (Nalco-Champion) Subsidiary of Royal Dutch Shell

2

Introduction: Armada Hub Located in the Central Northsea – 250km NE of Aberdeen Discovery:1980 Start of Development:1994 Start of Production:1997 Originally Gas field Development – Subsequent tie-in of Oilfields (subsea) –Maria (2008) –Rev (2009) –Northwest Seymour (2011) –Gaupe or Pi (2012) –Varg (2013) – All fields Productions are by Depletion drive Water Depth: 90m Platform – block 22/5b 3

Armada Hub Fields Layout 4

Challenge: Overcoming Liquid Loading Issues During Late Life Problem Location in the Flow Conduit ManifestationConsequence WellboreHydrostatic Column GrowthRate Reduction / Well dying Flowline and/or PipelineSlugging Process Upset (Separation Challenge) Additional BackpressureRate Reduction 5 Late Field/Well Life Production Challenge – Increase in Liquid-to-Gas Ratio (LGR) and associated low reservoir pressure Prod. ChokeFTHT Wellbore DeltaP FL DeltaP FTHP Wellbore Liquid Loading Prod. Choke FTHT FL DeltaP FTHP Flowline/Pipeline Loading

Remediation: Options to Overcome Liquid Loading 6 System Natural Lift Improvement – Well Focussed –Well interventions (e.g: stimulation – where opportunity exists to improve IPR ) –Workover (e.g: sidetrack, velocity string) – where potential exists and cost justifiable – Flowline/Pipeline Focussed –Increase in well count (where opportunity and economics agree) –Third party gas (where opportunity exists) Artificial Lift Options – Gas lift system – Pumps –Rod pumps, hydraulic jet pumps, electrical submersible pumps, subsea multiphase pumps, – Foaming –Application of foaming agents (possibly most cost-effective, having the right setup)

Subsea Wells Foaming Application: Areas For Consideration Identification of Problem Location – Wellbore, flowline/pipeline or both –While a pipeline liquid loading problem can be resolved via wellbore foamer injection; wellbore liquid loading problem may not be resolved via flowline/pipeline foamer injection Identification of The Right Type of Foaming Agent – Suitability for gas well, oil well or both –Foam stability in any combination of the three phases (gas, oil and water) – Ionic state of the foaming agent –compatibility with the formation rock wettability (core testing if unsure) Identification of Foaming Agent (Foamer) Conveyance Path – Umbilical Availability –Spare umbilical(s) – Maria case –Umbilical for Injected Chemical that is no-longer required (Chemicals Compatibility check and/or flushing) - Gaupe case –Mixing (or Simultaneous injection) of foamer and other injected chemical (Chemicals Compatibility check and minimum effective concentration/loading for each chemical necessary) – Wetted Path Compatibility Check –Compatibility with piping and completion components material(s) 7

Determination of Foamer Loading (Concentration/Rate Requirement) – Dosage/Volume for batch Treatment –Start-up of well might require batch dosing followed by periodic/continuous foaming – Injection Rate for periodic or continuous foamer application –Minimum foamer rate/concentration to maintain stable foam in the production conduit (Lab tests and field iteration) –Determination of minimum injection rate to maintain stable downhole flow; very vital (modelling and field trials) Determination of the Foaming Strategy (this will be Well condition/stage dependent) – Periodic (Intermittent) –Used for well kick-offs (sometimes) –Support well flow when rate (or FTHT) falls below a set limit and stop after a period of injection – Continuous injection –Used for well kick-off –Inject foamer so long as the well is open Foam Handling at Surface – Selection of appropriate Anti-foam (Lab. tests and field trials) – Guidance on Anti-foam injection rate (Lab. tests and field iteration) – Selection of appropriate Anti-foam injection point (preferably upstream of the Separator to allow for some mixing time) 8 Subsea Wells Foaming Application: Areas For Consideration

Foam Impact on Separators/Separation Process (Poor OiW/ WiO) – Spill/Carry Overs –Increased transient liquid returns (especially at start-up) – Impaired interface level (poor level control) –Possible improvement in level control with nucleonic devices – Increased solids (fines, sand, organics and/or sludge) returns into the separators that might reduce residence time/efficiency –Strategy for possibly more vessel monitoring (thermographics)/cleaning frequency Consideration of Prevailing Logistical and/or Operational Constraints/Requirements – Export Route Waiver (where applicable) – Chemical Permits – foamer and anitfoam (e.g DECC, FPS or other authorities; where applicable) – Material shipment requirements – Platform space availability –Stocking of additional chemical inventories 9

Some Field Results 10

Gaupe South Well Type: Subsea Horizontal well with smart completion (ICVs) – Separate ICVs for Oil and Gas legs Pipeline: 8 inch diameter by 7.4 Km length Oil Rate: stb/d Gas Rate: mmscf/d Water Rate: 20 – 50 stb/d Reservoir Pressure: 65 barg Reservoir Temperature: 127 degC Reservoir Depth: 3280m / 3475m (MD) 11 DHCI Line (Foamer Path) Gaupe South Foaming Project Liquid Loading LocationWellbore Foaming StrategyPeriodic and later changed to Continuous Foamer SelectionNonionic surfactant and suitable for both Gas and Oil well conditions (Foaming Agent A) Foamer loading Foamer diluted in 4% KCl (initially MEG). Batch dosing plus Periodic/continuous foamer loading for well restart. Periodic/Continuous injection Foamer: 100 ml/min KCl: 200 ml/min 2015 Production Gain Approximately 40%

Gaupe South Foaming – Periodic Injection 12 First Prod. With Foamer (Aug 01, 2015) Well Kick-off with Foamer: Batch Foamer Dosage + Periodic Injection FTHP Prod. Choke FTHT Well Kick-off with foamer Periodic Injections

Gaupe South Foaming – Continuous Injection 13 Foamer Turned off for 1.5 days FTHP Prod. Choke FTHT

Maria Terrace Well Type: Subsea Horizontal well with Slotted liners Pipeline: 12 inch diameter by 11 Km length Oil Rate: stb/d Gas Rate: mmscf/d Water Rate: 1 – 20 stb/d Reservoir Pressure: 130 barg Reservoir Temperature: 149 degC Reservoir Depth: 4140 m (MD) 14 Maria Terrace Foaming Project Liquid Loading LocationPipeline Foaming StrategyPeriodic to deliquify pipeline Foamer SelectionNonionic surfactant and suitable for both Gas and Oil well conditions (Foaming Agent A) Foamer loading Foamer diluted in 4% KCl (Initially MEG). (Not required for well restart) Periodic injection Foamer: 100 ml/min KCl: 200 ml/min 2015 Production Gain Approximately 90% DHCI Line (Foamer Path)

Maria Terrace Foaming – Periodic Injection 15 Start of FL Foaming (April 17, 2015) Foaming Episodes for additional FL clearing Foaming Episodes for FL Clearing FTHP FTHT

Lessons Learnt 16

Lessons Learnt Better Chance of Success if Foamer is Injected Downhole (DH) – Both wellbore and flowline/pipeline liquid loading can be simultaneous managed as shown in Maria and Gaupe case histories –Consider the benefit of installing DH chemical injection lines in new wells that can be used later in the well/field life to maximise recovery Increased Activity in Sand Monitors (more sand production alerts) – Although more solids are returned, sand erosion risk is lower as foamed systems lack velocity necessary for erosion due to the artificially high viscosity of foams Caution with Transient Time of the Flow Conduit – Be ready to manage possible large slug arrivals (This can strain vessels capacity) – Ensure to have an estimate of the arrival time for each well foam –Important when more then one well is foamed as not to overwhelm the vessels with the high foam concentration; especially, in the case of well start-ups with batch doses (Best to stager restarts) 17

Lessons Learnt Possible Excursions in Topside Separation Performance ( Particularly OiW ) – Requires careful monitoring by operations team – Armada benefits from ancillary media-based water polishing unit –Labour and running cost implications Watch out for Umbilical/Downline Content Siphoning (can lead to failed restart) – Hydrostatic Difference in wellbore and Downline of the Injection Path 18 FTHP Prod. Choke FTHT DHCIV Closed DHCIV Opened Foamer injected but well failed to restart; period used to refill umbilical content Foamer Batch Dosing

Lessons Learnt In Foamer Injection System with Simultaneous Injection of Foamer and Diluent; Always Remember that Concentration Change(s) will take Umbilical/Downline Volume/time to Effect (reach DH) – Allow enough time to implement change(s) and monitor response Some Well Kick-offs (Restarts) with Foamer can Take Longer Time / be More Challenging than Others (Driven by) – Prevailing well LGR and remaining reservoir energy – Foamer loading (Concentration/Rate) 19 FTHP Prod. Choke FTHT DHCIV Opened FTHP Prod. Choke FTHT DHCIV Opened FBHP Fast Restart Response Slow Restart Response

20 Best Practice

Best Practices Foaming Implementation – Consider having a Pilot (or Test) phase before setting up a permanent system or scheme –This will help in fine turning of the system (foaming) and also provide input data for the permanent setup. Well Kick-off with Foamer – Batch Dose Well and Soak for 12 to 24 hours prior to Restart –The batch dosing allows for sufficient foamer quantity to match the standing column of liquid in the wellbore following Well SI (target 0.2% foamer concentration). Necessary for stable foam generation at start-up. –Soak period allows for reasonable mixing of the foamer and standing liquid column by diffusion (short period Well agitation can enhance the mixing process) 21

Best Practices Start Continuous Foamer Injection Ahead of Well Opening – 1 to 2 hours prior to opening the Well to ensure the foamer is available on demand at the wellbore entry point –Siphoning of some of the umbilical content has been experienced to occur (leads to failed well restart) Avoid Neat Foamer Injection (where possible) – Deliver the Foamer with a Diluent (e.g x% KCl) – Achievement of DH minimum stable injection rate at manageable foamer volumes – Cost management – Management of umbilical content freezing risk (geographical region dependent) 22 Test LabelDescription IncumbentNeat Foaming Agent A (with MEG/Water mix) Sample 3Foamer A with 2% 75:25 mixture ratio Sample 6Foamer A with 4% 75:25 mixture ratio Sample 11Foamer A with 4% 50:50 mixture ratio Sample 12Foamer A with 4% 75:25 mixture ratio Viscosity vs Temp. Trend of Foaming Agent A Dilutions with KCl or NaCl

Best Practices Revise Well Beanup Procedure – Target slightly aggressive Tree choke opening whilst the Topside choke is used to manipulate the Riser as Slug-catcher (where slug-catcher is not available) –Small choke increments (5 – 10%) every (5 -15 min); where possible –Focus on maintaining liquid momentum in the wellbore during Well restarts Shut-in Well for Couple of Days of Pressure Buildup (PBU) – Might be necessary in cases of repeated failed restart attempts –5 days to 2 weeks might be necessary depending on well’s LGR – Allows some wellbore liquids to drain back into the reservoir –Re-establishes static equilibrium 23

Acknowledgements / Thank You / Questions The authors would like to thank the management of BG Group (Royal Dutch Shell Subsidiary), Centrica, Lundin and Nalco-Champion for support and permission to share this document/knowledge 24