Summary of the Snorre Foam History Force Workshop on Foam, NPD, Stavanger
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1 Classification: Statoil internal Status: Draft Summary of the Snorre Foam History Force Workshop on Foam, NPD, Stavanger 29 th September 2006 Idar Svorstøl, Statoil
2 Outline 2 Introduction Gas-shut-off by foam in well P-18 (producer treatment) Foam Assisted WAG (FAWAG) in well pair P-32 / P-39 Experimental work Foam strength as a function of oil saturation Foam propagation Conclusions
3 Snorre field summary 8 3 Production start: NFB STOOIP: 520 MSm 3 1 Reserves: 234 MSm 3 NWFB B Statfjord and Lunde formation Permeabilites: md 34/4 34/7 2 9S NCFB NEFB C-2H 4 7 Initial Reservoir Pressure: 383 bar 4 9 UPA A-10H ECFB Reservoir Temperature: 90 C WFB 1 No gas cap Limited aquifer support Pressure maintenance: WI, WAG Introduced smart wells for better GSO and WSO (shut off) control and zone injection control E E-4H 7 A 3 P-11B P-11A 6 CFB P-2 10 B EFB C Kart Snorre ETj rev
4 Snorre: WAG in a complex reservoir Schematic picture of WAG behaviour and sleeves 4 Injector Producer Sliding sleeves Gas Oil _21 Water Shale
5 WAG and foam treatment Schematic outline 5 WAG Foam producer treatment FAWAG Injection well Production well Injection well Production well Injection well Production well _22 Gas Oil Foam Objective: Objective: Reduced GOR Reduce gas mobility Divert gas into unswept areas
6 Snorre Field Foam Pilots 6 tion tion Mobility Control P - 32 mation ell / planned / planned l path pinchout 6 NFB Gas shutoff Production well P - 18 NWFB B NEFB Mobility Control P - 25A S 1152 A-3H 4 WCFB A-2H A-8H ECFB A-1H A-4H 1101 A-17H A-10HT-A 9 ECFB 4 A-9H A-5H A-5AH A-6H P L-CFB P-45 1 P-38 P EFB3 P-23 P-19 P-40 P-32 P-34 WFB P-37 CFB 1260 P-20 P EFB2 P-22 P-21 7 P-28 P-29 P-9 TLP EFB4 EFB 851 P-31A P-24 P-25A P-18A P Injection test P - 25A SWFB 102 P-12 3 P-17 P-13 P-7 P-8 P-14A P-36A WFB1 13 SCFB P B-1H
7 7 Gas shut-off by foam in well 34/7-P-18
8 Snorre WAG pilot area in Statfjord Formation Lunde Formation (L06-L12) 6 Production well Drilled production well Injection well Drilled injection well Horizontal production well Horizontal injection well P P-34 P P-37 P P-28 P TLP P-25 P P-8 P-13 P P-17 P-12 P A-10H T-A A- 2H 1601 A-3H A-1H A-4H A- 5H A- 9H 1 A-6H P /4 34/7 P-28 6 TLP P-18 P-34 P-8 P-13 P-38 P-40 P km
9 Snorre Foam before foam, P-18 9 S10 S12 S20 S21 S31 S4 & S5 _2 Gas Oil Shale
10 Snorre Foam 10 Well status P-18 Gas breakthrough in S-10 observed 1 month after gas injection in P-25 Mechanical zone isolation (straddle packer) did not succeed P-18 shut-in due to high GOR The production potential in P-18 was 2000 Sm 3 /d if isolaton of S-10 succeeded
11 Snorre Foam 11 The purpose of the field test Transfer the laboratory technology to the field Test the ability of foam to reduce GOR Gain experience in handling surfactant on an offshore platform Get the well back on production
12 Snorre Foam - 34/7-P-18 foam pilot - schematic outline 12 S10 S12 S20 S21 Plug S31 _7 Gas Oil Shale Water Foam
13 Fluid placement in S10 13 Surfactant/gas (foam) 2nd gas slug 1st gas slug Reservoir gas Reservoir oil _8
14 34/7-P-18 foam pilot injection pressure 14 Bottomhole pressure (bar) 380 Grafi sk _ Co-inj Preflush water Preflush gas st slug 2nd slug Time (hrs)
15 Snorre Foam - 34/7-P-18 foam pilot design 15 pre pilot test pre-flush slug injection PLT ( PBU) _9 install plug Days PT 2000 Sm 3 seawater * Tracer injection PT Production test PFO PFO PFO Sm 3 gas * * 150 Sm 3 surfactant PLT PFO PBU Sm 3 gas * * 150 Sm 3 surfactant Sm 3 gas coinjection ** 300 Sm 3 surfactant Production log Sm 3 gas post pilot test Remove plug PT PLT PFO PBU Sm 3 gas Pressure fall off test Pressure build up test 14 Preflush of water and gas: To reduce S or around well Test two foam generating processes: Alternating slugs Co-injection of surfactant and gas Comprehensive data aquisition: Production logging and testing Transient pressure testing Tracer injection Facilities/chemicals to control: Gas hydrate formation Process emulsion Discharged water foaming
16 Snorre Foam Pilot surface facilities 16 Seawater Water Tracer TFL Tank Steamgenerator Gas Tracer Surfactant Tanks (38 wt %) Booster Pump Main Pump (2 wt % surfactant) Gas Wellhead P-18 _10 Surfactant Pump
17 Water foam component slug rates 17 Water foam slug rate (Sm 3 /hr ) 5 _14 4,5 4 3,5 Slug 1 Slug 2 Co-inj. Preflush 3 2,5 2 1,5 1 0,
18 Gas foam component slug rates 18 Gas foam slug rate (Sm 3 /hr ) 400,00 350,00 300,00 _15 Slug 1 Slug 2 Co-inj. 250,00 200,00 150,00 100,00 50,00 0,
19 Snorre Foam - 34/7-P-18 foam pilot performance 19 Before foam, P-18 After foam, P-18 Positive S10 S12 S20 S21 Strong foam generated in-situ large increase in FBHP Gas Oil Shale S31 S4 & S5 Water Foam _13 GOR reduced from 460 to 240 Sm 3 /Sm 3 contribution from other layers Oil Water GOR Before foam After foam Year Well returned to production status Negative Foam break-down due to high dp limited ageing influence of oil
20 Snorre Foam - P-18 pilot results 20 Cash flow, MNOK Total cost : 9 mill NOK Data acquisition 25 % Surfactant 7 % Operation 36 % Foam pilot cash flow Planning 32 % _ Strong foam generated Well returned to production status Foam break-down due to high dp Economically successful: cost: 9 mill NOK NPV: 35+ mill NOK pay back: 12 days Large potential for improvement: avoid break-down reduced cost -10 Days of production, day
21 21 FAWAG in well pair P-32/ P-39
22 WAG and foam treatment Schematic outline 22 WAG Foam producer treatment FAWAG Injection well Production well Injection well Production well Injection well Production well _22 Gas Oil Foam Objective: Objective: Reduced GOR Reduce gas mobility Divert gas into unswept areas
23 23 Snorre Foam - FAWAG in well pair P-32/P-39 in WFB FAWAG Period: Autumn Autumn 2000 NWFB B WFB - NNN Objective: 2 9S Reduce gas mobility Improve sweep Increase oil rate in P-39 Reduce GOR in P-39 34/4 34/7 WFB - NN WFB - NS 4 WFB - Main Increase storage of gas in WFB WFB 7 Performance: A SAG injection (2 slugs) SWFB Surfactant volume ~720 m 3 (23%) Surf. conc. ~0.5% and ~0.2% Kart Sn WFB_N WFB ETj 1 rev
24 Snorre Foam - FAWAG logistics 24 Large quantity of surfactant needed to cover flooded area (2000 tons) Excess storage capacity in Snorre A ballast tanks Transported by ship to coast centre base in Florø and Snorre
25 34/7-P-32 injection performance Water WHP Gas The gas injection rate during summer 2001 was lower than during autumn 2000 due to lower gas compressor pressure 60 m straddle installed, autumn 2001 (0-hull campaigne) Tubing change-out due to corrosion 2.5 Water Injection Rate (Sm 3 /d) WHP (bar) Reduced gas injection rate due to 1. and 2. surfactant slug in FAWAG FAWAG 2003: Start surf.: 16. march Start gas: 3. april Gas Injection Rate (Mm 3 /d) feb.96 jan.97 jan.98 jan.99 jan.00 jan.01 jan.02 jan
26 26 Snorre Foam - GOR in P-39 and gas injection in P GOR P-39 Gas injection in P-32 GBT 60 days GBT 30 days GOR (Sm 3 /Sm 3 ) FAWAG Gas injection rate (Sm 3 /day)
27 Snorre Foam - P-39 production performance: Cumulative oil estimates from WI, WAG and FAWAG Cum oil from water: 3.7 MSm 3 Cum oil from WAG: 0.55 MSm 3 Cum oil from FAWAG: 0.25 MS 3 Incr. Gas storage (FAWAG): 100 MSm 3 Oil production (Sm 3 /d) Q oil WAG Start FAWAG WAG+FAWAG jul-96 jan-97 jul-97 jan-98 jul-98 jan-99 jul-99 jan-00 jul-00 jan-01
28 Conclusions FAWAG 28 An immediately reduction in P-32 gas injectivity during FAWAG followed by a slow increase, is interpreted as a sign of foam generation GOR development in P-39 during FAWAG is different compared to other periods with gas injection in P-32: Maximum GOR before FAWAG was 400 Sm 3 / Sm 3 Maximum GOR during FAWAG was 250 Sm 3 / Sm 3 (in spite that larger volumes of gas was injected during FAWAG) Rate of GOR increase was slower during FAWAG than before Production data: 33% of injected gas was back produced (65.3% before FAWAG) Total storage of gas in the reservoir during the FAWAG period: ~100 MSm 3 Increased gas storage gives an IOR effect and accelerated oil production Gas BT after FAWAG ~7 months, compared to ~1 month before FAWAG The expenses for FAWAG on WFB was 1 M USD, and the additional oil recovery was ~ M USD (at year 2000 oil prices)
29 29 Lab. experiments
30 Snorre foam Experimental work 30 Solubility Tests (bulk) Rock Characterization Chemical Loss Studies Core Floods (Effect on Gas Blocking and Mobility Reduction) Seawater (5-90 C) Mineralogy Adsorption Surfactant concentration Pore size distribution Precipitation Flow rate Specific surface area Ion exchange Foam quality Wettability Partition into oil Oil saturation Sacrificial agent Gas type Temperature Permeability Ageing and foam propagation
31 Snorre Foam - Gas Mobility with and without Foaming Agent (Co-Injection Mode) 31 Gas mobility (relative scale) Gas GR1080 B1333 C 12 AOS C 14 AOS T = 90 C P = 300 bar = 80 % Sorg = 7 % C14/16 AOS C 16 AOS Snorre reservoir conditions _6
32 Description of Corefloods 32 Core characteristics: Core length: cm Porosity: % PV Permeability: md Temperature: 90 C Pressure: 300 bar Oil Saturation: 8-42 % PV Surfactant conc.: wt % Foam quality: % Velocity: m/d Type of gas: HC, N 2, CH 4 Experimental modes: Mode A Mode B Mode C Mode D Mode E Gas blocking Foam injection Gas Injection Oil blocking Gas/Oil co-inj.
33 Apparent foam viscosity as a function of oil saturation 33 Apparent viscosity (cp) miscible gas S org _29 T = 90 C P = 300 bar k abs : 140 md Baseline: 0.7 cp after first gas/oil inj. after second gas/oil inj. after waterflood and foam inj Oil saturation (%)
34 Apparent foam viscosity as a function of oil saturation 34 Apparent viscosity (cp) Core I, 0.5 wt% Core I, 2 wt% Core I, 1 wt% Core II, 2 wt% _5 100 T = 90 C P = 300 bar = 80% v = 1.2 m/d Oil saturation (% PV) 40 50
35 Pressure transducer configuration 35 transducer leads common 1/3 2/3 full core inlet core outlet ÐP 1/3 ÐP 2/3 ÐP full _10
36 Pressure trace, foam flooding at S org = 0% [1] [2] [3] [4] [5] [5] [6] [7] [8] [9] [10] [11] Time (days) [11] [12] [13] [14] [15] [16] [17] [18] [19] Time (days) Full core 2/3 core 1/3 core _37
37 Pressure trace, foam flooding at S org = 13% [1] [2] [3] [4] [5] [6] [7] [8] [9] Time (days) [10] [11] [11] [12] [12] [13] [14] [15] [16] [17] [18] [19] Time (days) Full core 2/3 core 1/3 core _36
38 Pressure trace, foam flooding at S org = 19% [1] [2] [3] [4] [5] [6] [7] [8] [9] Time (days) 80 [10,11] [12] [14] [13] [15][16] [17] [18] [19] [20] [21] [22] Time (days) _32 Full core 2/3 core 1/3 core
39 Conclusions 39 The Snorre Foam history during the years succeeded due to a small, enthusiastic and optimistic foam team was given the possibility to develop its idea. Thanks to Saga Petroleum.
40 40 Back up
41 Influence of foam quality on apparent viscosity 41 Apparent viscosity (cp) _ m/d 1 m/d 3 m/d 1000 T = 90 C P = 300 bar C s = 2 wt % Sorg = 8 % Gas fractional flow 1
42 Blocking experiments, gas rates 42 V g /k ((m/d)/darcy) bar 0.5 bar 1 bar 2.5 bar/surfactant T = 90 C P = 300 bar C s = 2 wt% S org = 8% _ Time (hrs)
43 Foam screening results 43 Blocking test (aýd incr. ÐP) AOS foamers most attractive w.r.t. vg/k 60 _33 T = 90 C P = 300 bar producer treatment (blocking) injector treatment (mobility) C16 AOS price a) b) Time (hrs) c) d) C14 AOS C14/16 AOS GR 1080 B 1333 availability environmentally sound System identified for pilot testing
44 Snorre Foam Planned activities during autumn 2006 / Review the pilots carried out, and include these for a design of a producer treatment and injector treatment in 2007 and Issues to consider in particular: - Evaluate well candidates with regard to reservoir characteristics, injection / production potentials, risk issues, and operation plan - Establish diagnose, and a well-defined monitoring program, giving possibility for interpretation of the treatment - Simulations (STARS and Eclipse) - Surfactant OK related to safety and environmental issues? - Injectivity aspects? - Should another foamer be selected for injector treatment? => Weaker foamer gives better injectivity and sweep improvement => Lower adsorption - Offshore aspects - Clarify eventually bottlenecks (pumps, other activities) - Mature and include the offshore organization 44
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