Smart Water Flooding in Carbonates and Sandstones: A New Chemical Understanding of the EOR-potential Tor Austad (tor.austad@uis.no) University of Stavanger, Norway Presented at the FORCE Education Seminar, NPD, Nov. 6-7., 2013. 1
Example: Smart Water in Chalk Spontaneous imbibition: T res =90 o C; Crude oil AN=0.5; S wi =10% Chalk: 1-2 md Formation water: VB Seawater: SW Seawater depleted in NaCl Seawater depleted in NaCl and spiked with 4x sulfate 2
Example: Smart Water in Limestone Spontaneous imbibition at 130 C of FW and SW into Res# 4-12 using crude oil with AN=0.50 mgkoh/g. Low perm. 0.1-1 md. 3
Example: Smart Water in Sandstone Low Salinity EOR-effect under forced displacement Recovery (%) 60 50 40 30 20 High Salinity Low Salinity B15-Cycle-2 10 0 0 2 4 6 8 10 PV Injection HS: 100 000 ppm; LS: 750 ppm 4
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) 5
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 done as early as possible. 6
Outline Discuss the conditions for observing EOReffecets by «Smart Water» in: Carbonates Sandstones A very simplified chemical explanation 7
Wetting properties in carbonates Carboxylic acids, R-COOH AN (mgkoh/g) Bases (minor importance) BN (mgkoh/g) Charge on interfaces Oil-Water R-COO - Water-Rock Potential determining ions Ca 2+, Mg 2+, (SO 4 2-, CO 3 2-, ph) - - - - Ca 2+ Ca 2+ Ca 2+ + + + + + + + - - - - SO 2-4 SO 2-4 SO 2-4 - - - - - 8
Ekofisk Why is injection of seawater such a tremendous success in the Ekofisk field? Highly fractured High temperature, 130 o C. Low matrix permeability, 1-2 md Wettability: Tor-formation: Preferential water-wet Lower Ekofisk: Low water-wetness Upper Ekofisk: Neutral to oil-wet Estimated recoveries 1976: 18% 2001: Goal: 46% NPD; 2002: 50% 2007: Goal 55 % OIL RATE, MSTBD (GROSS) 400 0 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012 2016 2020 2024 2028 9
Brine composition Comp. Ekofisk Seawater (mole/l) (mole/l) Na + 0.685 0.450 K + 0 0.010 Mg 2+ 0.025 0.045 Ca 2+ 0.231 0.013 Cl - 1.197 0.528 HCO - 3 0 0.002 SO 2-4 0 0.024 Seawater: [SO 4 2- ]~2 [Ca 2+ ] and [Mg 2+ ]~ 2 [SO 4 2- ] [Mg 2+ ]~4 [Ca 2+ ] 10
Oil Recovery, %OOIP 60 50 40 30 20 10 Effect of Sulfate in SW Crude oil: AN=2.0 mgkoh/g Initial brine: EF-water Imbibing fluid: Modified SSW Spontaneous imbibition at 100 o C SW4S at 100 C SW3S at 100 C SW2S at 100 C SW at 100 C SW½S at 100 C SW0S at 100 C 0 0 10 20 30 40 Time, days 11
Is Ca 2+ active in the wettability alteration? Oil Recovery, %OOIP 60 50 40 30 20 10 0 Crude oil: AN=0.55 mgkoh/g S wi = 0; Imbibing fluid: Modified SSW Spontaneous imbibition at 70 o C SW4Ca at 70 C SW3Ca at 70 C SW at 70 C SW½Ca at 70 C SW0Ca at 70 C 0 10 20 30 40 50 60 Time, days 12
Co-Adsorption of SO 4 2- and Ca 2+ vs. Temperature C/Co C/Co 1.00 0.75 0.50 0.25 C/Co SCN FL#7-1 SSW-M at 21 C A=0.174 C/Co SO4 FL#7-1 SSW-M at 21 C C/Co SCN FL#7-2 SSW-M at 40 C A=0.199 C/Co SO4 FL#7-2 SSW-M at 40 C C/Co SCN FL#7-3 at 70 C A=0.297 C/Co SO4 FL#7-3 at 70 C C/Co SCN FL#7-4 at 100 C A=0.402 C/Co SO4 FL#7-4 at 100 C C/Co SCN FL#7-5 at 130 C A=0.547*(Extrapolert 0.00 2.6PV) C/Co SO4 FL#7-5 at 130 C 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 PV 1.0 Method: 1. Core saturated with SW without SO 4 2-2. Core flooded with SW spiked with SCN - (Chromatographic separation of SCN - and SO 2-4 ) 0.5 C/Co Ca2+ Test #7/1 SW at 23 C C/Co Ca2+ Test #7/2 SW at 40 C C/Co Ca2+ Test #7/3 SW at 70 C C/Co Ca2+ Test #7/4 SW at 100 C C/Co Ca2+ Test #7/5 SW at 130 C 0.0 0.5 1.0 1.5 2.0 2.5 PV 13
C/Co 1.00 0.75 0.50 Affinities of Ca 2+ and Mg 2+ towards the chalk surface NaCl-brine; [SCN - ] = [Ca 2+ ] = [Mg 2+ ]= 0.013 mole/l T=23 o C T=130 o C C/Co SCN (Brine with Mg and Ca2+) at 23C [Magnesium] A=0.084 C/Co Mg2+ (Brine with Mg2+ and Ca2+) at 23 C C/Co 2.00 1.75 1.50 1.25 1.00 0.25 0.00 C/Co Ca2+ (Brine with Mg2+ and Ca2+) at 23 C 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 PV 0.75 0.50 0.25 0.00 C/Co SCN (Brine with Mg and Ca2+) at 130 C C/Co Mg2+ (Brine with Mg2+ and Ca2+) at 130 C C/Co Ca2+ (Brine with Mg2+ and Ca2+) at 130 C 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0 PV CaCO 3 (s) + Mg 2+ = MgCO 3 (s) + Ca 2+ 14
Effects of potential determining ions and temperature on spontaneous imbibition %OIIP60 Recovery, 40 20 Imbibition at 70 & 100 o C (with/without Ca & Mg) 25:SWx0CaMg(+Mg@43days) 26:SWx0Sx0CaMg(+Mg@ 53 days) 27:SWx2Sx0CaMg(+Ca@43 days) 28:SWx4Sx0CaMg(+Mg@53 days) 70 C 100 C 130 C 0 0 20 40 60 80 100 120 Time, days 15
Suggested wettability mechanism 16
Can SO 4 2- compensate for low T res? oil recovery (%OOIP) 70 60 50 40 30 20 10 100 C (Oil A, AN=2.07) 130 C (Oil A, AN=2.07) 0 SSW-US SSW-½S SSW SSW 2S SSW 4S Imbibing fluids Maximum oil recovery from chalk cores when different imbibing fluids were used (SW with varying SO 4 2- conc.). Oil: AN=2.07 mgkoh/g). 17
Ion composition in PW from Ekofisk Concentration (m mole/l) PW contained 73.6 vol% SW and 26.4 vol%fw 0.06 0.05 0.04 0.03 0.02 0.01 (PW)calc* (PW)exp 0 Ca2+ Mg2+ SO42- Component Fig. 3 Calculated and measured component concentration in PW linked to substitution of Ca 2+ by Mg 2+ at the rock surface, adsorption of SO 4 2- onto the rock and precipitation of CaSO 4. 18
Can modified SW be an even Smarter EOR-fluid Spontaneous imbibition: T res =90 o C; Crude oil AN=0.5; S wi =10% Formation water: VB Seawater: SW Seawater depleted in NaCl Seawater depleted in NaCl and spiked with 4x sulfate 19
Effect of Salinity and Ion concentration The access of potential determining ions to the calcite surface is affected by the concentration of non active ions in the double layer 20
Forced displacement using «Smart SW Water» Recov very, % OOIP 40 30 20 10 0 0 3 6 9 12 15 Injected PV FW-0S SW SW-0NaCl Oil recovery by forced displacement from the composite limestone reservoir core. Successive injection of FW, SW and SW-0NaCl. T test : 100 C. Injection rate: 0.01 ml/min ( 0.6 PV/D). 21
Low salinity EOR-effects in carbonates SPE 137634 Ali A. Yousef et al. (Saudi Aramco) 22
Codition for observing low salinity EOReffects in carbonates The carbonate rock must contain anhydrite, CaSO 4 (s) Chemical equilibrium: CaSO 4 (s) Ca 2+ (aq) + SO 4 2- (aq) Ca 2+ (ad) + SO 4 2- (ad) The concentration of SO 4 2- (aq) depends on: 4 Temperature (decreases as T increases) Brine salinity (Ca 2+ concentration) Wettability alteration process: Temperature (increases as T increases) Salinity (increases as NaCl conc. decreases) Optimal temperature window 90-110 o C? 23
Presence of CaSO 4 Concentration profiles of Ca 2+, Mg 2+,and SO 4 2- when flooding reservoir limestone core with DI water, after aging with FW. T test :100 C,Injectionrate:0.1ml/min. 24
Recovery, % OOIP 60 50 40 30 20 10 0 Low salinity EOR-effect 20 FW-0S 22% of OOIP 100 dil. FW-0S Sulfa ate concentration, mm 0 0 3 6 9 12 15 18 21 24 Injected PV 18 16 14 12 10 8 6 4 2 FW-0S 10 dil. FW-0S 100 dil. FW-0S 0 50 100 150 Temperature, C Oil recovery by forced displacement from a reservoir limestone core containing anhydrite. Successive injection of FW, and 100 diluted FW. T test : 100 C. Injection rate: 0.01 ml/min ( 1 PV/D). Simulated dissolution of CaSO 4 (s) when exposed to FW-0S, 10 and 100 diluted FW at different temperatures. 25
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 (Especially divalent ions like Ca 2+ and Mg 2+ ) 26
General information
Adsorption onto clay
Local 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 1.54 0.09 0.0 0.0 Low Salinity Brine-1 0.0171 0.0 0.0 0.0 Low Salinity Brine-2 0.0034 0.0046 0.0 0.0 Low Salinity Brine-3 0.0 0.0 0.0171 0.0 Low Salinity Brine-4 0.0034 0.0 0.0 0.0046 29
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 6 30
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 + 31
Kaolinite Nonsweeling(1:1 Clay) Montmorillonite Swelling (2:1 clay, similar in structure to illite/mica) Adsorption of basic material Quinoline Burgos et al. Evir. Eng. Sci., 19, (2002) 59-68. 32
Kaolinite: Adsorption reversibility by ph Adsorption (mg/g) 6,00 Adsorption ph 5 5,00 4,00 3,00 2,00 1,00 Quinoline Samples 1-6: 1000 ppm brine. Samples 7-12: 25000 ppm brine Desorption ph 8-9 Readsorption ph 5.5 Desorption ph 2.5 0,00 0 5 10 15 Sample no. 33
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 2 5.3 3.7 6.0 1.2 8.1 0.1 Increase in ph increases water wetness for an acidic crude oil. 34
Oil: Acidic or Basic Recovery (%) Total oil: AN=0.1 and BN=1.8 mgkoh/g Res 40: AN=1.9 and BN=0.47 mgkoh/g 60 50 40 30 20 10 B-15 TOATL Oil B-11 Res-40 Oil 0 0 2 4 6 8 10 12 14 PV Injection 35
Lower initial ph by CO 2 increses the low salinity effect Oil Recovery Factor (% OOIP) 80 70 60 50 40 30 20 10 High Salinity Core No. B18 Low Salinity S wi % 19.7 6 T Aging C T Floodin g C 60 40 Oil TOTAL Oil Saturated With CO 2 at 6 Bars B14 19.4 60 40 TOTAL Oil High Rate B18-Cycle-1 CO2 Saturated Oil B14-Cycle-1 Reference Curve ph 10 9 8 7 6 5 LS brine NaCl: 1000 ppm NaCl:1000 ppm High Salinity Formation Brine TOTAL FW 100000 ppm TOTAL FW 100000 ppm Low Salinity B18-Cycle-1 CO2 Saturated Oi B14-Cycle-1 Reference Test 0 0 2 4 6 8 10 12 14 16 PV Injection 4 0 2 4 6 8 10 12 14 Brine PV Injected CO 2 + H 2 O H 2 CO 3 + OH - HCO 3- + H 2 0 36
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 2011-15 (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 37
Lab work Snorre field 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? 38
New study at UoS: Lunde formation Table 1. Mineral composition Plagioclase Quartz Calcite Kaolinite Illite/mica Chlorite Core [wt%] [wt%] [wt%] [wt%] [wt%] [wt%] 13 28.2 32.1 1.4 2.6 9.3 3.6 14 36.0 35.2 2.4 3.9 7.4 2.9 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] 0.07 1.23 0.83653 5.6 4.0 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 9.5 39
Plagioclase Anionic polysilicates give alkaline solution Albite as example: NaAlSi 3 O 8 + H 2 O HAlSi 3 O 8 + Na + + OH - At moderate salinities, the ph of FW will be above 7, which means low adsorption of polar components onto clay; negligible LS EOR-effect. Due to buffer effects, the ph of FW was not decreased significantly by adding CO 2. 40
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 effect of about 3-4 % of OOIP with SW as low salinity fluid 41
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+ : 0.061 mole/l, Total salinity 57114 ppm T res = 65 o C k = 1-2 md, Φ=0.11 14.5% LS EOR-effect 42
Varg field: SPE 134459 Reservoir temperature: 130 o C Salinity 201 000ppm Brine composition; T a =90, T f =130 o C T a =130, T f =130 o C 43
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, 12-14 April, 2011. 44
ph Temperatur ph screening 11 10 9 8 7 6 5 40 C 90 C 130 C 0 4 8 12 16 20 24 Injected PV Change in effluent ph versus PV injection fluid in core RC2 at temperatures ranging from 40 C to 130 C. The brine flooding sequence was HS-LS-HS. 45
Summary «Smart water» EOR in Carbonates Optimal brine composition Modified SW: Depleted in NaCl and spiked with SO 2-2- 2+ 2+ 4 : Active ions SO 4, Ca, Mg T res >70 o C Conditions for LS EOR-effects Formation must contain dissolvable anhydrite, CaSO 4. 46
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) Plagioclase can affect the ph both in a positive and negative way LS EOR effects depending on initial salinity. Combination of high T res (>100 o C) and high conc. of Ca 2+ can make the formation too water-wet. A ph-hs/ls scan can give valuable information of the potential for LS-EOR effects. 47
Acknowledgement Statoil, ConPhil, NFR Total, Talisman, BP, Maersk, Shell, Saudi Aramco, DNO International. 48