Well and Flowline De-Liquifaction in European Gas Fields through Batch and Continuous Foamer Injection

Transcription

1 Gas Well De-Liquification Workshop March 1-3, 2004 Well and Flowline De-Liquifaction in European Gas Fields through Batch and Continuous Foamer Injection J.G.R. (Rob) Eylander, P.J. Mul, H. van Dijk and E.R. Bakker Shell Exploration & Production Europe

2 Shell Exploration & Production Europe Norway Ireland United Kingdom Denmark Netherlands Germany Austria EP Eu r o p e Italy 2

3 Major Assets 3

4 Liquid Loading Dimensions In Southern North Sea and on some land locations in The Netherlands, liquid loading in intra-field pipelines is a constraint on production. More than 100 wells (> 50% of total) suffer from liquid loading. Production capacity at risk is estimated at 3 5 million Sm 3 / day ( million Sft 3 / day) 4

5 Alternatives Considered Gas lift conceptually attractive for offshore wells, but constrained by economics and availability of gas supply wells. Plunger lift not feasible owing to the presence of SCSSV s and packer completions. Foamer injection viable option. Proven in the USA for 3½ and smaller size tubing. Unproven in larger diameter tubing / liner. 5

6 Trial Objectives To establish the feasibility of unloading fluid from wells through batch treatment with foaming agents. To establish the feasibility to prevent / reduce liquid loading in gas wells througth continuous downhole injection of foaming agents through a capillary chemical injection line. To establish the operating envelope for foam lifting (pressures, temperatures, liquid rate, gas rate, depth, well geometry). To establish the production improvements as a result of foam lifting for various production / well conditions. 6

7 Chemical Aspects Commercially available foamer chemicals are cationic, anionic or amphoteric surfactants in a solvent mixture. The performance of cationic and anionic foamers is affected by the nature of the solvent mixture (impacts on emulsion-forming tendency) and the presence of salt and / or condensate. Amphoteric foamers are less affected and will, in general, show a better efficacy. Thermal stability, winterization, elastomer compatibility and foam stability are crucial chemical selection criteria. 7

8 Batch Trial Evaluation Treatment design: Volumes: 50 L foam followed by 200 L brine (s.g. brine > s.g. liquid ). Larger volumes / ratio s also used. Shut-in well to allow settling (settling velocity 1000 ft/hr). Treated 21 wells (26 treatments) Costs: Chemicals approx. 12,000 Operators approx. 15,000 Gains: during 4 th quarter 2003 on average 28,000 Sm 3 /d capacity and 2.6 million Sm 3 produced gas. 8

9 Evaluation Criteria Daily production before / after treatment Cumulative production over ± 3 month period after batch treatment(s) compared to 3 month period before the trial (or other equal period before / after) Where possible quality of fluid returns: foam density, foam collapse time, WCR, emulsion, foamer concentration 9

10 WAV-11: 7 liner, 3.5 tubing 100,000 Production, Sm 3 /d 50,000 Volumes: Foam 50 L Brine 200 L (1.125) Closed-in time: 3 hrs Intermittent production Batch treatment carried out 29/9/2003 Cum. Gains Q4: ± 432,000 Sm 3 Continuous production

11 COV-28: 7 /4.5 liner, 3.5 tubing 140,000 Volumes: foam: 100 L brine: 400 L (1.125) Closed-in time after treatment: 6 hrs Batch treatment 1/10/2003. Gains (3 months before / after) : 1,670,000 Sm3 120,000 Production Sm 3 /day 100,000 80,000 60,000 40,000 20, Date

12 WAV-8: 7 liner, 3.5 tubing ,000 50,000 Volumes: foam 50 / 50 L brine 200 / 200 ltrs (1.125) Closed-in time: 24 / 20 hrs Batch treatments carried out 13/10 and 21/10/2003 Gains (85 days before / after treatment): 559,820 Sm 3. Production, Sm 3 /d 40,000 30,000 20,000 10, Date

13 Dal-4: 4.5 liner, tubing 70,000 60,000 Volumes: foam 50 L brine 200 L (1.1.25) Closed-in time: 5 hrs batch treatment 30/9/2003 NO gains over period 3 months before / after. 50,000 Production, S m 3 /d 40,000 30,000 20,000 10, Date

14 Batch treatment observations Strong reaction: WAV-11 from IP to continuous flow WAV-8 two treatments; delayed reaction from IP to continuous flow COV-28 from IP to continuous flow OSH-5 liquid / foam handling problems Some reaction: COV-33 IP but higher up time WYK-5 IP but still poor performance No reaction: SCH-447/-537, TUM-1/-2, WAV-12/-13/-18, DAL-4 14

15 Batch treatment observations (cont.) Performed Delta Analysis to identify critical parameters. No clear correlation found to explain success / not success None of the high sour wells was successful Results not far off from results in industry (Canada). Strongly varying conditions (temperature, pressure, depth, H 2 S, CGR, WGR, etc.) 15

16 Continuous Injection Evaluation (not straightforward: SCSSV) COV-55: 5 liner, 5 tubing (monobore) Duration Costs Production from intermittent / unstable to ± stable 50,000 Sm 3 /day. Well not cleaned up properly. HBG-8: 7 liner, 7 tubing (monobore) Duration Costs Able to produce as a result of foamer injection; formation water production resulted in well quitting WSO required. 16

17 HBG-8 Hardenberg 8 foam trial (capillary string) gas production (km3/d) foamer inj. (0.1* ltr/h) depth coil ( mahort) density water (+1000 kg/m3) downhole pressure (bar) wellhead pressure (bar) /11/ :00 01/12/ :00 06/12/ :00 11/12/ :00 16/12/ :

18 Learning points Batch treatments: No correlation success or failure cases. Some failures due to insufficient shut-in time. Uncertainties: impact CGR / CWR; sour wells; mixing and downhole agitation; shut-in times. Continuous injection: Sufficient time to produce the well clean. Hang-off depth injection nozzle. Amphoteric foamer showed best performance. 18

19 Pipeline Deliquifaction PL Average Export Pressure over the last year 37 Barg Average Daily Rate 2.69 MCM/Day (103.8 Tj/Day) Average CGR 0.73 Bbl/Mmscf 4.13 M 3 /MCM PL unmanned platform 8 producing wells 19

20 Trial Risks Water Carry-over to Compression. Evaporation of saline water droplets in compressors leads to deposition of Halite salts in compression barrel and reduction in compression head / efficiency. Mitigation: De-Foamer injection facilities provided. Well sized Separators with high efficiency cyclone internals up-stream of compressors. Produced Water. Reduction in surface tension of condensate droplets in produced water system could lead to increased concentration of oil-to-sea. Mitigation: Risk management. Prepared to abandon test if major impact encountered. Carry-over to Bacton (MEG system). Reduction in surface tension of condensate droplets in glycol regeneration system could lead to foaming in reboilers and threaten regeneration capacity. Mitigation: No liquids from the test would commingle with MEG System. 20

21 Trial Procedure Injection rates : Modelling had identified that 2000 ppm w.r.t to water cut would be sufficient. This took into account high salinity formation water. Injection into production manifold on Barque PL. Contingencies De-foamer identified from Laboratory testing contingent to inject up stream Barque Pl slugcatcher on Clipper, if level control of carry-over became a concern. 21

22 Trial Results Measuring Impact of Flow Improver On Pipeline Operation Original Operation Pressure Factor Back to Original Operation Transition Back to Original Operation Improved Operation BaseLine (15th-31st March) With Flow Improver (1st-4th April) With Flow Improver (4th - 7th April) Flow Improver Switched off (12th - 16th April) Flow Improver Switched off (22nd -26th April) Flow Factor 22

23 Way Forward Foam trials succesful and the transition to routine application of both batch and continuous injection currently ongoing. SCSSV problem being solved through re-design / QRA. Full implementation possibly by Q Do we understand well response to foamers and can it be modelled dynamically, taking into account well geometry, pressure / temperature regimes, etc? Well candidate selection: try batch treatment first, or do we have better tools? 23

24 With thanks to the TEAM Eelco Bakker Hans van Dijk Rob Eylander Luke Jackson Matt Kedian Paul Mul Rene Schutte Rob Smeenk Gert de Vries Gerrit Wigger 24