Smart Water as a Potential EOR Fluid in Clastic Oil Reservoirs: Possibilities and Limitations. Tor Austad.

Transcription

1 Smart Water as a Potential EOR Fluid in Clastic Oil Reservoirs: Possibilities and Limitations Tor Austad (tor.austad@uis.no) University of Stavanger, Norway 1

2 Example: Smart Water in Sandstone Low Salinity EOR-effect under forced displacement Recovery (%) High Salinity Low Salinity B15-Cycle PV Injection HS: ppm; LS: 750 ppm 2

3 What is Smart Water? Smart water can improve wetting properties of oil reservoirs and optimize fluid flow/oil recovery in porous medium during production. Smart water can be made by modifying the ion composition. No expensive chemicals are added. Environmental friendly. Wetting condition dictates: Capillary pressure curve; P c =f(s w ) Relative permeability; k ro and k rw = f(sw) 3

4 Water flooding Water flooding of oil reservoirs has been performed for a century with the purpose of: Pressure support Oil displacement Question: Do we know the secret of water flooding of oil reservoirs?? If YES, then we must be able to explain why a Smart Water sometimes increases oil recovery and sometimes not. If we know the chemical mechanism, then the injected water can be optimized for oil recovery. Injection of the Smartest water should be performed as early as possible.. 4

5 Outline Discuss the conditions/possibilities for observing EOR-effects by «Smart Water» in sandstone. Field cases and limitations Conclusions 5

6 Smart Water in Sandstone Some experimental facts Porous medium Clay must be present Crude oil Must contain polar components (acids and/or bases) Formation water Must contain active ions towards the clay (Ca 2+ and H + most important) 6

7 General information

8 Adsorption onto clay

9 Increase in ph important NaCl CaCl 2.2H 2 O KCl MgCl 2.2H 2 O (mole/l) (mole /l) (mole /l) (mole /l) Connate Brine Low Salinity Brine Low Salinity Brine Low Salinity Brine Low Salinity Brine

10 Suggested mechanism Proposed mechanism for low salinity EOR effects. Upper: Desorption of basic material. Lower: Desorption of acidic material. The initial ph at reservoir conditions may be in the range of

11 Chemical equations Desorption of cations by LS water (slow) Clay-Ca 2+ + H 2 O = Clay-H + + Ca 2+ + OH - Wettability alteration (fast) Basic material Clay-NHR OH - = Clay + R 3 N: + H 2 O Acidic material (fast) Clay-RCOOH + OH - = Clay + RCOO - + H 2 O 11

12 Active species versus ph The pk a values of protonated base and carboxylic acid are quite similar, pk a 4.5 BH + H + + B RCOOH H + + RCOO - The concentration of the active species (BH +, and RCOOH) will have a similar variation versus ph. 12

13 Clay minerals Clays are chemically unique Permanent localised negative charges Act as cation exchangers General order of affinity: Li + < Na + < K + < Mg 2+ < Ca 2+ << H + Kaolinite and Illite are non-swelling clays 13

14 Adsorption of basic material Quinoline Kaolinite Nonsweeling(1:1 Clay) Burgos et al. Evir. Eng. Sci., 19, (2002) Montmorillonite Swelling (2:1 clay, similar in structure to illite/mica) 14

15 Kaolinite: Adsorption reversibility by ph Quinoline Samples 1-6: 1000 ppm brine. Samples 7-12: ppm brine Adsorption (mg/g) 6,00 5,00 4,00 3,00 2,00 1,00 Adsorption ph 5 Desorption ph 8-9 Readsorption ph 5.5 Desorption ph 2.5 0, Sample no. 15

16 Adsorption of acidic components onto Kaolinite Adsorption of benzoic acid onto kaolinite at 32 C from a NaCl brine (Madsen and Lind, 1998) ph initial Γ max µmole/m Increase in ph increases water wetness for an acidic crude oil. 16

17 LS water increases oil-wetness Adsorption of Quinoline vs. ph at ambient temperature for LS (1000 ppm) and HS (25000 ppm) fluids. Ref. Fogden and Lebedeva, SCA (Colloids and Surfaces A (2012) Adsorption of crude oil onto kaolinite It is not a decrease in salinity, which makes the clay more water-wet, but it is an increase in ph 17

18 Oil: Acidic or Basic Total oil: Res 40: AN=0.1 and BN=1.8 mgkoh/g AN=1.9 and BN=0.47 mgkoh/g Recovery (%) B-15 TOATL Oil B-11 Res-40 Oil PV Injection 18

19 Lower initial ph by CO 2 increses the low salinity effect Core No. S wi % T Aging C T Floodin g C Oil LS brine Formation Brine B TOTAL Oil Saturated With CO 2 at 6 Bars B TOTAL Oil NaCl: 1000 ppm NaCl:1000 ppm TOTAL FW ppm TOTAL FW ppm Oil Recovery Factor (% OOIP) High Salinity Low Salinity High Rate B18-Cycle-1 CO2 Saturated Oil B14-Cycle-1 Reference Curve ph High Salinity Low Salinity B18-Cycle-1 CO2 Saturated Oi B14-Cycle-1 Reference Test PV Injection Brine PV Injected CO 2 + H 2 O H 2 CO 3 + OH - HCO H

20 BP: Endicott field tests SPE Produced water observations: Increase in alkalinity, i. e. HCO 3 - CO 2 (g) + H 2 O [H 2 CO 3 ] H + + HCO - 3 H + + OH - = H 2 O Decrease in H 2 S(g) H 2 S + OH - H 2 O + HS - Increase in Fe 2+ FeS(s) + OH - [FeOH] + + S 2- K 1 = Decrease and increase in Mg 2+ 20

21 Solubility of Mg(OH) 2 vs. ph [Mg 2+ ] mol/l 10-3 ph 8 ph 8 ph>9 Low Salinity Fig. 11. Schematically change in Mg 2+ concentration in the produced water during a low salinity flood. The concentration of Mg 2+ is suggested to be quite similar for the initial FW and low saline brine. Mg 2+ : 10-3 M, 100 o C: mol Mg2+ or Ca E-05 1E-06 1E-07 1E-08 1E-09 1E-10 1E-11 Mg2+ 50 C Mg C Ca2+ 50 C Ca C ph Modeling solubility of Mg(OH) 2 and Ca(OH) 2 versus ph at 50 and 100 o C in a ppm NaCl brine and 6 bars. At ph< 8: No precipitation of Mg(OH) 2 At ph >8: Precipitation: Mg OH - = Mg(OH) 2 (s) HS brine: Clay-H + + Ca 2+ = Clay Ca 2+ + H + 21

22 LS EOR effects regarding: Temperature Salinity/concentration of Ca 2+ Initial wetting condition f (Temp., Salinity/Ca 2+,.) Talisman: Varg, Yme, Gyda T res >100 o C; FW: Salinity> ppm; Ca M (very high) Varg and Ymes: Clay content wt% 22

23 No LS EOR effect at high T res and FW salinity FW SW 50x diluted SW 60 Oil recovery (% OOIP) YME FW SW 50X Diluted SW Injected PV Fig. 6. No LS EOR effects were observed when flooding the Yme Core RC3b (depleted in anhydrite) successively with FW1 SW SW-50xD (50x diluted SW) at 110 C. FW: ppm 23

24 LS EOR effect at high T res and low FW salinity Fig. 11. Oil recovery test of Yme RC 24. The core was flooded successively with FW2, SW and Sw50x-D brine at a rate of 4 PV/D. At the end the rate was increased to 16 PV/Day. T res =110 o C; FW salinity ppm. 24

25 Varg field: SPE Reservoir temperature: 130 o C Salinity ppm Brine composition; Ca M (very high) T a =90, T f =130 o C T a =130, T f =130 o C 25

26 Static adsorption of Quinoline onto Illite LS: 1000 ppm; HS ppm, CaCl ppm, FW ppm 25 o C 130 o C LS HS CaCl 2 FW LS HS CaCl 2 FW Adsorption [mg base/g illite] Ads ph~5 Des ph~8 Re-Ads ph~5 Adsorption [mg base/g illite] Ads ph~5 Des ph~8 Re-Ads ph~ Sample no Sample no. 26

27 Relationship: T and ph Wettability alteration of clay by LS water: Clay-Ca 2+ + H 2 O Clay-H + + Ca 2+ + OH - + heat Desorption of active cations from the clay surface is an exothermic process, H<0. Divalent cations (Ca 2+, Mg 2+ ) are strongly hydrated in water, and as the temperature increases the reactivity of these ions increases, and the equilibrium is moved to the left. The change in ph should decrease as the temperature increases. Dissolution of anhydrite, CaSO 4 (s), will move the equilibrium to the left. Gamage, P., Thyne, G. Systematic investigation of the effect of temperature during aging and low salinity flooding of Berea sandstone and Minn, 16th European Symposium on Improved Oil Recovery, Cambridge, UK, April,

28 Temperature ph screening ph C 90 C 130 C Injected PV Change in effluent ph versus PV injection fluid in core RC2 at temperatures 40, 90, 130 C. The brine flooding sequence was HS-LS-HS. HS: ppm, LS: 1000 ppm. Desorption of Ca 2+ Adsorption of Ca 2+ slow process fast process 28

29 Presence of anhydrite Reservoirs at high T res and salinity my contain anhydrite, CaSO 4 (s) Offshore reservoirs at high T res and salinity flooded by SW may also contain precipitated anhydrite, CaSO 4 (s) 29

30 Yme RC1: ph HS LS scan C 40 C (2nd test) 90 C 130 C ph Injected PV Fig. 2. ph versus PV injected for RC1. The flooding sequence was HS2-LS2-HS2, and the switching of fluids is marked by dashed lines and marked points. Brines: HS2: ppm (CaCl 2 and NaCl) LS2: 1000 ppm (NaCl) 30

31 Presence of anhydrite in RC C C Concentration, mm Ca2+ SO Injected PV Concentration, mm Ca2+ SO Injected PV (a) (b) C C 2 nd test Concentration, mm Injected PV Concentration, mm Ca2+ SO42- Ca2+ SO Injected PV (c) (d) Fig. 3. Concentration of Ca 2+ and SO 4 2- in the effluent versus PV injection fluid in RC1. The flooding sequence was HS2-LS2-HS2. The temperature ranged from 40 C to 130 C. 31

32 Plagioclase as reservoir mineral Anionic poly silicate which is charged balanced mainly with Al 3+, but also with Ca 2+ or Na +. Albite, NaAlSi 3 O 8, is a common member of the Plagioclase group. Na + may be exchangeable with H + and will have impact on the ph of the brine. 32

33 Chemical equilibrium: Albite as example Chemical equilibrium: NaAlSi 3 O 8 + H 2 O HAlSi 3 O 8 + Na + + OH - Initial FW conditions Low saline FW (Alkaline solution ph>7) Equilibrium moved to the right High saline FW (May have acidic solution ph<7) Equilibrium moved to the left, i.e. no cation exchange Impact on initial wetting conditions and the potential for LS EOR effects 33

34 Snorre field Lab work Negligible tertiary low salinity effects after flooding with SW, on average <2% extra oil. T res =90 o C Single well test by Statoil Confirmed the lab experiments Question: Why such a small Low Salinity effect after flooding Snorre cores with SW? 34

35 New study at UoS: Lunde formation Table 1. Mineral composition Core Quartz Plagioclase Calcite Kaolinite Illite/mica Chlorite [wt%] [wt%] [wt%] [wt%] [wt%] [wt%] Table 5. Properties of the oil. AN [mgkoh/g oil] BN [mgkoh/g oil] Density (20 C) [g/cm 3 ] Viscosity (30 C) [cp] Viscosity (40 C) [cp] Salinity of FW: ppm PS!! The oil was saturated with CO 2 at 6 bar. The core was flooded FW diluted 5x and the ph of the effluent stayed above 10. Plagioclase gives alkaline solution: ph: 7.5 to

36 Snorre (Lunde) Core 13 CO 2 was added Fig. 3. Recovery vs. injected PVs for Core 13. Flooding rate of 2 PV/D; T res = 90 o C. Low salinity EOR effect of about 3-4 % of OOIP with SW Initially, too water wet due to ph>7 for obtaining LS EOR effects 36

37 Excellent LS EOR conditions (Quan et al. IEA EOR Symposium 2012, Regina, Canada) Minerals: Plagioclase 22%, Total clay 25% (mostly Illite and kaolinite) FW: Ca 2+ : mole/l, Total salinity ppm T res = 65 o C k = 1-2 md, Φ= % LS EOR-effect 37

38 Outcrop core containing Plagioclase Recovery (%) High Salinity Low Salinity B15-Cycle PV Injection Excellent outcrop material for parametric LS-studies Fresh water has passed through the sandstone for many years. NaAlSi 3 O 8 has been partly transformed to HAlSi 3 O 8. In the presence of high salinity brine, ppm, acidic conditions are obtained: HAlSi 3 O 8 + Na + NaAlSi 3 O 8 + H + 38

39 Outcrop: ph-hs-ls scan ph Injected PV 40 C 90 C 130 C Fig. 6. Change in effluent ph versus PV injection fluid in core OC1 at 40 C, 90 C and 130 C. The brine flooding sequence was HS2-LS2- HS2. The switches of injection fluids are indicated by the dashed lines. PS!! ph not sensitive to the temperature due to Eq. (1): (1) NaAlSi 3 O 8 + H 2 O HAlSi 3 O 8 + Na + + OH - (2) Clay-Ca 2+ + H 2 O Clay-H + + Ca 2+ + OH - + heat 39

40 Screening of LS EOR-potential Accepting that the ph is the key factor in the LS process, and that ph is obtained by switching from HS to LS brine in the presence of clay minerals. ph = f(t res, brine salinity/composition, Albite, Anhydrite,.) The ph/hs/ls scan at actual reservoir temperature can give valuable information about: Initial ph of FW (linked to initial wetting properties) Desorption rate related to the type of clay. Desorption rate should be fast to establish a new oil bank Possible ph gradient Presence of minerals like Plagioclase and Anhydrite. 40

41 Summary «Smart Water» EOR effects in Sandstone Formation water: ph < 6.5 Reasonable high Ca 2+ and total salinity. Clay must be present (Illite and kaolinite) Combination of high T res (>100 o C) and high conc. of Ca 2+ can make the formation too water-wet. Presence of anhydrite, CaSO 4 (s), as a reservoir mineral can affect the LS EOR potential in a negative way Plagioclase/Albite can affect the ph both in a positive and negative way. The LS EOR effects is depending on initial salinity A ph/hs/ls scan can give valuable information of the potential for LS-EOR effects, initial ph and ph gradient. 41

42 Acknowledgement Statoil, ConPhil, NFR Total, Talisman, BP, Maersk, Shell, Saudi Aramco, DNO International. 42

43 EOR-group at UoS,