l EOR Etat dans le monde et Chez TOTAL

Transcription

1 l EOR Etat dans le monde et Chez TOTAL 06/02/2009

2 Why EOR (enhanced oil recovery) EOR : an an element of the evolving technical portfolio allowing the renewal of reserves. Other elements : Exploration Technology (ex : deep offshore, complex wells) Historically, the other elements, mainly exploration, have been sufficient EOR was applied as a niche technique. 2

3 Why EOR If (when?) exploration is not sufficient for reserves replacement, then a larger use of EOR techniques may be needed. Potential is huge,, if we consider the amount of oil left undergroud. 3

4 The EOR global stakes (all figures are worldwide) Oil cumulative production, current = 1.07 Gbbls Remaining conventional oil reserves = 1.1 Gbbls (ca. 40 years production at today s rate) Reserves yet to be found = 1.3 Gbbls (ca. 40 years production) Increasing the average recovery factor from 35% to 45 % = 1.0 Gbbls (ca. 40 years production). This is the EOR and IOR target 4

5 TERMINOLOGY EOR (Enhanced Oil Recovery) mobility control: polymer, foam, chemical: surfactants, alkaline agents, Miscible or near miscible gas injection thermal: steam, in-situ combustion others: microbial, non-miscible CO 2 IOR Improved Oil Recovery Technologies Smart wells Reservoir management Reservoir characterization down hole separation,.. etc. EOR will act on the reservoir recovery mechanisms IOR technologies will change versus time with different standards across the world and among the various companies 5

6 Displacement efficiency (secondary recovery) Displacement (recovery) efficiency is mainly ruled by: permeability and heterogeneity distribution mobility ratio between injected/in place fluid M=(kr inj /m inj ) *(m o /kr o ) residual oil saturations wettability 6

7 EOR, to achieve what? Improve the macroscopic efficiency for the displacement of oil by another fluid. 1 by decreasing the oil viscosity (thermal methods, Air Injection, CO 2 injection). by increasing the water viscosity (polymer injection). by making more stable gas injection (WAG). 7

8 EOR, to achieve what? Improve the microscopic efficiency of the oil displacement (decrease Sor). 2 by decreasing interfacial forces (miscible gas, surfactants, ASP). by playing with wettability (fresh water injection, alkaline flooding ). by taking advantage of 3 phase effect (WAG, SWAG). 8

9 Main EOR methods Thermal methods Chemical methods Gas injection steam injection (flood/huff Puff/SAGD) in-situ combustion polymer flooding surfactant /microemulsion flooding alcaline flooding CO 2,,H 2 S, N2 HC Flue Gas Miscible,Immiscible tertiary Air injection, WAG Others: microbial. 9

10 Which EOR technique? Oil viscosity Immiscible gas (HC, N 2 ) Surfactant flooding Polymer Flooding Steam Other Thermal methods Miscible gas (HC) CO 2 N 2 miscible depth 10

11 EOR contribution to global production EOR vs World production EOR prod bpd % of world prod year EOR prod % of World prod «long history» review some countries not enough documented (China- CEI Algeria - Middle East..) 11

12 EOR worldwide, 2006 (bbls/d( bbls/d) Thermal Gas inj. Chemical USA Canada Rest of the world Total Total EOR Production : 2.3 Mbbls / d 12

13 EOR: activity worldwide Thermal Processes Steam Injection USA (California) Canada Venezuela (Maracaibo) Indonesia In Situ Combustion USA (ND, SD) Romania Aera (Shell / Exxon) Chevron Imperial Shell - Total PDVSA Chevron Continental OMV (Petrom) 13

14 EOR : activity worldwide Gas Injection HC miscible CO 2 USA (Alaska) Algeria USA (Texas) BP Sonatrach Exxon Mobil Oxy N 2 Mexico Pemex WAG USA (Alaska) USA (Texas) BP Oxy 14

15 EOR : worldwide activity Chemicals Polymers China CNPC CNOOC ASP China CNPC MEOR MEOR Norway Statoil 15

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17 TOTAL EOR experience and activity 17

18 Total World Wide Experience in EOR MISCIBLE GAS NON MISCIBLE GAS GRAVITY, SWELLING, HUFF & PUFF ETC NITROGEN GAS AIR INJECTION CO2 GAS CHEMICAL INJECTION 18 HEAVY OIL

19 Example # 1: Surmont (Canada) Bitumen (viscosity cp) with very low mobility in the reservoir Shallow reservoir 19

20 Cold Production Proven technology Fair productivities with horizontal wells (Venezuela) or with CHOPS (Canada) Limited investments Limited operating costs (2 to 4 US$/bbl) Available artificial lift technologies: PCP, rod pumps No GHG emissions Sand + Oil BUT : CHOPS Poor recovery factors (# 5 to 10%) Unsuitable for bitumens (too viscous) Unsuitable for reservoirs with active aquifer 20

21 SAGD : an emerging technology in Canada High Recovery Factor Several pilots since 1980's in Alberta and elsewhere Mature enough for medium scale field tests Upside: ES-SAGD (Expanded solvent SAGD) BUT : Huge need of energy : 1500 MW for 100,000 bopd!! "Killing factor" : steam oil ratio (has to be < 3 vol./vol.) Large GHG emissions : up to 15,000 Tons/day of CO 2 for 100,000 bopd Requires technologies adapted to high temperatures (artificial lift, metering, surface pumping, ) Fuel options for steam Natural Gas High OPEX (up to 3 gas price ± 3 US$/MMbtu) Other Fuels High investments : specific boilers (CFB, PC, ) heavier BFW treatment flue-gas depollution higher CO2 emissions 21

22 Surmont SAGD Project ConocoPhillips 50% - Total 50% Pilot (< 1 kbopd) now N LSD 13 ob22 LSD 12 LSD 5 ob28 ob23 ob17 ob24 ob25 Meadow Creek ob38 Pair B ob41 ob18 ob36 ob26a Pair A ob37 Pair C ob20 LSD 14 LSD 11 LSD m Phase 1 (27 kbopd) Q4/2006 2AE 2AF 2AN 2AG 2AM TRUNK LINE 2A Approximate scale 5 km 100 or 200 kbopd? AD 2R 2S 2AL 2AJ ID TRUNK LINE 1B 2Q 2AI 2O IE 2AK 2K 2J 2AH 2N IF * 2P 2B II 2A IG 2I * 2C IJ IC 2L IA TRUNK LINE 4 2T TRUNK LINE 2B 2G 2D IH 2E 2F IB TRUNK LINE 1A 2M 2H CENTRAL PLANT IL IK * 2V 2U 2AA 2W 2X TRUNK LINE 3 * 2Y 2AB * * * 2AC 2Z PIPELINE INSTALLATION SCHEDULE BOOSTER STATION REQUIRED AT YEAR AND LOCATION SHOWN SURMONT PROJECT GATHERING AND DISTRIBUTION PIPELINES GAS LIFT AND ESP CASE LSD 4 ob39 22

23 Surmont: SAGD project - initial pilot Objectives: Confirm commercial oil-rates & Steam/Oil ratio Test high temperature (# 200 C) artificial lift Phase 1 (25 kb/d) preparation before FFD decision with upgrader (100 kb/d) LSD 13 LSD 12 LSD 5 well pairs Meadow Creek ob17 Pair B Pair C Pair A ob22 ob23 ob41 ob36 ob20 ob24 ob37 ob25 ob26a ob28 LSD 14 LSD 11 LSD 6 N ob m 23 LSD 4 ob39

24 SAGD TECHNICAL CHALLENGE Dynamic gridding(front tracking) Fine cells amalgamated when the T gradients are small CPU times divided by 2 (even 3) with no loss of accuracy 24

25 Application of ES-SAGD to Sincor Preliminary results (10% of solvent C4-C10 same steam injection) Injection/Production rates Oil production cumulatives SAGD ES-SAGD later decline ES-SAGD: production by 20% RF: 47% 55% CSOR: ES-SAGD temperatures: flattening of the chamber SAGD temperatures 25

26 Other production technologies Combustion front Mobile oil zone (MOZ) Cold Heavy Oil In-situ combustion already applied to light or viscous oils Air & Water not yet tested on bitumen Should provide partial in-situ upgrading of the oil Solvent injection Producer well less mature than SAGD (TOTAL partner of a DOVAP pilot test in Canada potential advantages / SAGD: more energy efficient much lower CO2 emission would avoid expensive water treatment facilities (for steam generation) Solvent flows to interface 26 Capillary mixing Solubilization Swelling Solvent Molecular diffusion Convective dispersion Viscosity reduction Asphaltene precipitation g Oil

27 Perspectives for SAGD oil recovery Stepwise implementation, in order to have very low risk; full field in the very near future «Improved» SAGD under investigation: enriched with solvent Mitigation of GHG emissions to be addressed; a pilot for geological CO2 storage underway in S.W. France (injection to start Q1 2009) 27

28 Example # 2: Chateaurenard field Chemical flooding (surfactant + polymer); project completed Sand reservoir, good permeability Poor performance of water drive, due to adverse mobility ratio (oil viscosity = 40 cp) 28

29 The Chateaurenard field Industrial S/P pilot Research microemulsion pilot Chuelles Courtenay Extension m St. Firmin Courtenay Polymer flood Châteaurenard Chateaurenard Polymer flood (R1) 29

30 The Industrial Surfactant Polymer Pilot Wells pattern CHU.7 bis N CHU.19 bis 1 1,5 2 2,5 3 3,5 182 CHU ,5 4 3, CHU CHU ,5 2 1, CHU.31 CHU ,5 CHU.6 CHU.3 Fig. 2 RESERVOIR ISOPACH MAP 30

31 The Industrial Surfactant Polymer Pilot Results 0.4 CHU CHU CHU 18 B Oil Cut (Fraction) CHU CHU CHU CHU CHU CHU 5 Monthly Rate (m 3 / month) Oil cut Cumulated Injection (Fraction P.V) Predicted Performance Field Performance 100 Jan. Dec. Jan. Dec. Jan. Dec Oil & water production Injection Oil production Oil - cut Fig. 7 OIL CUTS IN WELLS PRODUCTION Fig. 8 PILOT MONTHY INJECTION AND PRODUCTION RATES. OIL - CUTS 31

32 RESULTS (summary) Before chemical flooding RF = 44% Water cut in producing wells = 91% (avg.) Surfactant/Polymer flood An oil bank was formed: water cut decreased down to 48% Final RF = 67% 32

33 Perspectives for Surfactant/Polymer flooding Good upside to water injection: huge potential. Large resources identified after careful inventory. Domain of application now wider: Chemicals adapted to saline/warmer conditions Addition of Alkali (ASP) improves robustness: wider optimal zone and lower adsorption May be OK for carbonate reservoirs Companion process available for fractured reservoirs (dilute surfactant injection) Economics have improved: Lower chemical consumption with ASP technology Surfactants: no longer petroleum sulfonates, now synthetic (cheaper, and cost not strongly linked to crude oil) 33

34 Example # 3 : Dalia (Deep offshore, West Africa) Chemical flooding (polymer injection) Project in the engineering phase 34

35 General data about the field Deep offshore, subsea development High permeability sandstone reservoir; medium viscosity oil (7 cp) Water injection started early, adverse mobility ratio: early breakthroughs anticipated Viscosifying the water with polymers, to make favourable the mobility ratio, is the selected EOR technique 35

36 Water Injection Development W09 1G02 Lower Main Channel 5W01 1W10 Line kbpd 5W02 2W07 1W line 1W04 1W05 1W06 1W07 2W line 1W02 1G01 1W03B 1W03 2W06 2W08 Lower Flanks Line kbpd 2W line 1W01 D3W line D2W01 3WG08 Block 17 limit 3W09 3W05 Upper Main Channel 763 line 3W07 2W02 4W05 D3W01 D3W06 4W03 Line kbpd Drilling hazard Area Line 763 4W01 4W04 Camelia kbpd 764 line 4W Design : plateau bopd water injection: desulfated sea water and produced water bwpd Subsea lines Gas reinjection waiting for storage/lng

37 Oil Production Rate Typical profiles 1,2 1 0,8 0,6 0,4 0,2 0 Plateau extension and slower decline Water Injection Polymer Injection 0 0,2 0,4 0,6 0,8 1 Time Cumulative Oil production 1,4 1,2 1 0,8 0,6 0,4 0,2 0 Water Injection Polymer Injection 0 0,2 0,4 0,6 0,8 1 Time Lower water cuts Watercut 1 0,9 0,8 0,7 0,6 0,5 0,4 Water Injection 0,3 Polymer Injection 0,2 0, ,2 0,4 0,6 0,8 1 Time 37

38 Perpectives for chemical EOR in deep offshore environment Generally, very favourable reservoir conditions for chemical flooding: high permeability, low temperature, seawater injection Limited number of wells, limited access to wells (subsea): not forgiving! Economics attactive, phased deployment to mitigate risks A new development, now underway, will include (for the first time) space for EOR facilities in the production vessel (FPSO) EOR NOW POSSIBLE EVEN IN DEEP OFFSHORE 38

39 A few remarks 39

40 A few remarks about the various processes Steam Injection historically, invented and developed in California. now faces the dramatic increase of natural gas price in North America. potential for innovation/improvement improvement (combination with other processes). Gas Injection key parameter for success: : an effective gravity control If gravity control is good, advantage of miscibility may be small. main driver for air or nitrogen injection (case of light oils): natural gas savings. 40

41 A few remarks (cont d) CO 2 injection a source of pure CO2 is needed (not( flue gas) WAG (and( derivatives) Two types of situations, with different objectives. improve the micoscopic efficiency of waterflooding ( triphasic effect). control an unstable gas flooding Chemical processes salinity/temperature temperature limitations. but this technology has been greatly improved over the past decade. 41

42 CONCLUSIONS IOR/EOR is more expensive than primary or secondary recovery. Contractual incentives may play a role IOR/EOR are applicable on mature fields, but not only. For new developments, IOR/EOR scenarios should be considered early EOR is technically complex and needs to be carefully prepared to reduce risks of failure: Project type organization Stepwise implementation Continuous monitoring In today s world, EOR is becoming increasingly attractive 42

43 IOR /EOR Planning The IOR phase : an intermediate phase between the primary/ secondary phase and the EOR phase Field rejuvenation: infill drilling with high-tech completions, recompletions optimized reservoir management Preparation of the EOR phase: selection of EOR technique run the appropriate tests (lab work, 1D to 3D simulations, field pilot) well architecture secure the source of fluids to be injected possible reservoir pressure restoration 43

44 Typical project phasing Phase 0 Integrated studies Phase 1 Field rejuvenation & EOR preparation Phase 2 EOR implementation 44

45 IOR /EOR Planning IOR/technologies implementation has a positive impact on field performance within a few years (1 or 2) Field response to EOR/mechanism is usually longer (4-5 years for the impact of the injected fields to be visible on the production side) EOR/mechanisms+IOR/technologies to be associated for a fast response 45

46 Enhanced Oil Recovery Prepare it well, do it right, and you can Expect Outstanding Results 46