1. www.eni.it Dewatering Flowlines with Foamers C. Passucci, K.C. Hester, A. di Lullo Flow Assurance: Ensuring Production Today, Creating Solutions for Tomorrow 13 – 14 October 2015

2. 2 Fluid-dynamics issues in mature gas fields  The typical scenario: production decline  Gas production decline due to reservoir depletion  Water  Water rate tends to increase  Field designed for maximum expected gas rates oversized for current production  Result is oversized for current production.  Consequence:  Water tends to accumulate both into wells and pipelines

3. 3 Overview on liquid removal technologies  Traditional method:  Mechanical (swabbing, plunger lift, periodical pigging) surfactantFOAMER  Injection (in gas wells or flowlines) of a surfactant (FOAMER)  Removes progressively accumulated liquids by a stable and persistent foam.  Main advantages from water removal:  Increase the production rate  Increase the production rate of gas wells (plus 5 - 25%)  Removing liquid load occurring in the wellbore without shut-in of the wells  Increase the production  Reducing pressure drops along flowlines and trunklines  Simplify operations  Such as ramp-up, well restart, production changes  Reducing risk of severe slugging which can jeopardize process  Reduce internal corrosion  Limiting and/or avoiding any occurrence of stagnant flow

4. 4 Foamer Applications into Gas Wells and pipelines  Continuous Well Injection  Into open annulus  Into annulus above packer  Via small capillary tubing  Batch Well Treatment  Chemical dropped/bullheaded  Continuous or batch flowline injection  Flowline/trunkline inlet  via HP dosing pumps

5. 5  The foamers agent are commercially available as:  Solid sticks (outdated technology)  Gel  Powder  Liquid  Liquid (best)  Liquid foamers  Liquid foamers are recommended:  Avoid any risk of well obstruction  Safer handling and storage (i.e. unmanned operation)  Injection rate can be easily controlled and optimized by dosing pumps  Suitability for application in flowlines Types of Foamer DEFOAMER Remember: for each Foamer application You need to break the foam with a DEFOAMER

6. Pipeline deliquefaction techniques PIGGING Advantages  Removes almost all settled liquids  Able to remove solids  Proven technologyDrawbacks  Operator reluctance (stuck pigs)  May be unfeasible  Unpiggable lines  Geometric constraints  Absence of pig traps  Induces a sudden liquid surge FOAMING Advantages  Not intrusive  Done at normal production rate  Limited liquid slug riskDrawbacks  Less efficient than pigging  Limited remove of deposited solids  Proven for wells  Limited pipeline applications  Need of defoamer at arrival  Prevent foam carryover to process 6

7. 7 Foamers proven successful for wells However, very limited field applications in flowlines to date Jan Feb Mar Apr May - The production of gas was increased by 12% during field trial

8. Field Trial Late-life gas field 8

9. Field Altimetric Profile 9 C1 C2 C3 C4 C5 CPF

10. Field Configuration  Gas contributions into the network from each cluster  Initial Survey Performed in the Field  Overall Pressure Drop  Around 1.1 bar 10 6”8” 10”

11. Modeling Results Between Limits of No Water:Water-Filled 11 ΔP largely attributed to gravitational effect i.e., water hold-up Around 20-25 m3 water potentially in trunkline Holdup

12. Field Trial: Pressures along the Network during Foamer Injection 12

13. Field Trial: Overall dP Decreased due to Foamer Effect 13

14. Inlet Flow Rate Increased after Foamer Injection (C1) 1 st Foamer Injection Compressor Stop Foamer effect equivalent to compressor+ 2 Compressor Production 1 Compressor Production 2 nd Foamer Injection

15. Increase in Gas Rate following Foamer 15

16. Duration of Foamer Effect Based on Inlet Water Rate 16 C3 C1 7 days of full effect

17. Conclusions  Field Survey linked with modeling ensured field was good candidate  For a foamer intervention  Foamer was able to increase gas production  Due to reduced dP in the main trunkline  Effect similar to a compressor  Treatment fully effective for around one week  With a continuing contribution for an additional week 17

18. Discussion Points  Potential foamer applications shown for gas flow lines  Shown effective not only in small diameter wells but larger diameter lines  Competitive technology versus other ‘routine’ approaches  e.g., compressors.  Evaluation should be done on a field-by-field basis  Both batch and continuous applications possible  Potential to consider foamer not only for late life fields  Possible consideration in the design phase? 18