EOR in Fractured Carbonate Reservoirs – low salinity low temperature conditions By Aparna Raju Sagi, Maura C. Puerto, Clarence A. Miller, George J. Hirasaki Rice University Mehdi Salehi, Charles Thomas TIORCO April 26, 2011

Outline EOR strategy for fractured reservoirs Evaluation at room temperature (~25 °C) o Phase behavior studies – surfactant selection o Viscosity measurements o Imbibition experiments o Adsorption experiments Evaluation at 30 °C and live oil o Phase behavior experiments o Imbibition experiements Conclusions 2

3 EOR strategy

Reservoir description o Fractures – high permeability paths o Oil wet – oil trapped in matrix by capillarity o Dolomite, low salinity, 30 °C Recover oil from matrix spontaneous imbibition o IFT reduction Surfactants o Wettability alteration Surfactants Alkali EOR strategy 4 Ref: Hirasaki et. al, 2003

Current focus – IFT reduction – surfactant flood Surfactant flood desirable characteristics o Low IFT (order of mN/m) o Surfactant-oil-brine phase behavior stays under- optimum o Low adsorption on reservoir rock (chemical cost) o Avoid generation of viscous phases o Tolerance to divalent ions o Solubility in injection and reservoir brine o Easy separation of oil from produced emulsion 5

6 Phase behavior studies at ~ 25 °C

Parameter Salinity Surfactant blend ratio Soap/surfactant ratio Optimal parameter Winsor Type - I Winsor Type - II Varying parameter Winsor Type - III micro Procedure 7 Pipette (bottom sealed) Brine + surfactant Oil Initial interface Seal open end 24 hr

Phase behavior, IFT, solubilization parameter 8 Reed et al Salinity, wt% NaCl IFT, mN/m Solubilization parameter momw Vo/Vs Vw/Vs middle upper lower

Phase behavior Purpose of phase behavior studies o Determine optimal salinity, Cø transition from Winsor Type I to Winsor Type II o Calculate solubilization ratio, Vo/Vs and Vw/Vs o Detect viscous emulsions (undesirable) Parameters o Salinity – 11,000 ppm (incl Ca, Mg) o Surfactant type, Blend ratio (2 surfactants) o Oil type – dead oil vs. live oil o Water oil ratio (WOR) o Surfactant concentration 9

4wt% Brine2 S13D Salinity scan (Multiples of Brine2) WOR ~ 1 0.5wt% 0.25wt% optimal salinity Vo/Vs~ 10 at reservoir salinity 10

11 Viscosity studies at ~ 25 °C

Viscosities of phases – function of salinity Multiples of Brine 2 Optimal salinity reservoir salinity optimal salinity Oil 0.5 wt% S13D

13 Imbibition studies at ~ 25 °C

Imbibition results – S13D reservoir cores (1”) 14 S13D 0.5wt% 126md S13D 0.25wt% 151md Mehdi Salehi, TIORCO

S13D candidate for EOR o under-optimum at reservoir salinity o stays under-optimum upon dilution o Vo/Vs~10 (at 4wt% surfactant concentration) indicative of low IFT o No high viscosity phases at reservoir salinity o ~ 70% recovery in imbibition tests 15

16 Adsorption studies at ~ 25 °C

Dynamic adsorption – procedure Sand pack o Limestone sand ~ mesh o Washed to remove fines & dried in oven Core holder o Core cleaned with Toluene, THF, Chloroform, methanol o Core holder with 400 – 800psi overburden pressure Vacuum saturation (~ -27 to -29 in Hg) o measure pore volume Permeability measurement 17

Dynamic adsorption - setup 18 Sample collection Bromide concentration reading Bromide electrode Pressure transducer Pressure monitoring Core holder/ Sand pack Syringe pump/ ISCO pump

Limestone sandpack ~ 102D Injection solution: Brine 2 with 1000ppm Br wt% S13D Flow rate: 12.24ml/h Pore volume: 72 ml, Time for 1PV ~ 6hrs 19 1PV =.38 ft 3 /ft 2 Lag ~ 0.14 PV Adsorption 0.26 mg/g sand 0.12 mg/g reservoir rock 1PV2PV

Reservoir core – 6mD 20 Injection solution: Brine 2 with 1000ppm Br wt% S13D Flow rate: 2ml/h Pore volume: ~12 ml, Time for 1PV ~ 6hrs 1PV =.035 ft 3 /ft 2 Effective pore size = 26.8 m Lag ~ 0.54PV to 1.25PV Adsorption 0.12 mg/g rock to 0.28 mg/g rock 3PV4PV day 1day 3 2PV1PV

Reservoir core – 6mD plugging 21 Expected pressure 15ml/hr Expected pressure 2ml/hr Absence of surfactant Presence of surfactant – dyn ads exp day 1 day 11day 3 – no data 1PV2PV3PV4PV5PV

By Yu Bian diff in area ~ 21 % 3PV4PV day 1day 3 2PV1PV HPLC sample HPLC analysis of effluent 22 3PV4PV2PV1PV

Reservoir core – 15mD 23 2 micron inlet – pressure monitored Injection solution: Brine 2 with 1000ppm Br wt% S13D Flow rate: 1ml/h, Pore volume: ~30 ml, Time for 1PV ~ 1.25 days 1PV =.103 ft 3 /ft 2 Effective pore size = 11.8 m Lag ~ 0.67PV Adsorption 0.29 mg/g rock Surfactant Pressure Bromide 1PV2PV3PV4PV5PV day HPLC sample

HPLC analysis of effluent 24 diff in area ~ 25 % By Yu Bian

Adsorption results comparison 25 ExperimentMaterialEquivalent adsorption on reservoir rock (mg/g) Residence time (hrs) DynamicLimestone sand0.126 DynamicDolomite core 6mD 0.12 – overnight DynamicDolomite core 15mD Static (by Yu Bian) Dolomite powder0.3424

26 Phase behavior studies at ~ 30 °C

S13D phase behavior 27 S13D 25 °C Type I microemulsion S13D 30 °C Type II microemulsion S13D 30 °C with live oil (600 psi) Type II microemulsion

S13D/S13B blend scan 30°C 28 10/0 9/1 8/2 7/3 6/4 5/5 4/6 3/7 2/8 1/9 0/10 S13D S13D/S13B ratio S13B Brine 2 salinity;2 wt% aq; WOR = 1 Optimal blend

S13D S13B % C s °C S13D S13B Phase behavior S13D/S13B blend With dead 30 °C Aqueous stability test of S13D/S13B blend

S13D/S13B (70/30) – dead vs live 30 ° C 30 Dead oil – UNDER-OPTIMUMLive oil – OVER-OPTIMUM After mixing & settling for 1 day Before mixing After mixing & settling for 1 day

31 Imbibition studies at ~ 30 °C

Imbibition results –reservoir cores (1”) 32 S13D 0.5wt% 126mD, 25 °C S13D 0.25wt% 151mD 25 °C Mehdi Salehi, TIORCO S13D/S13B 70/30 1wt% 575mD, 30 °C S13D/S13B 60/40 1wt% 221mD, 30 °C

33 Conclusions

Dynamic adsorption experiments (absence of oil) o Effluent surfactant concentration plateaus at ~80% injected concentration o Higher PO components are deficient in the effluent sample (in plateau region) o Increase in pressure drop with volume throughput Sensitivity of phase behavior to temperature and oil (dead vs. live) S13D/S13B 30 °C performance poor compared to 25 °C 34

35 Questions

36 Back up slides

S13D surfactant flood – additional experiments Analysis of plugging behavior o HPLC analysis of dynamic adsorption effluent samples – determine missing components o Determine pore size distribution of Yates core samples by NMR and Mercury porosimetry for cores of different permeability o Determine surfactant micelle size o Presence of anhydrite – measure Ca 2+ concentration in dynamic adsorption effluent by ICP Quantify effect of S13D on o wettability – calcite slab contact angle measurements o IFT – spinning drop measurements 37

NI blend - 4:1 N67-7PO : IOS * N67-7PO – Neodol C Propoxy Sulfate IOS – C15-18 Internal Olefin Sulfonate Optimal salinity ~ 5% NaCl + 1% Na 2 CO 3 Na 2 CO 3 o Generation of soap optimal salinity function of soap to surfactant ratio o Wettability alteration o Reduced adsorption 38 * Liu et.al 2008 (SPE99744)

NI blend Unsuitable conditions for Alkali Surfactant flooding o Presence of divalent ions in injection fluid Precipitation of CaCO 3 in presence of Na 2 CO 3 o Presence of 600 psi CO 2 Na 2 CO 3  NaHCO 3  lower pH Low pH – no soap generation 39

N67- 7PO and IOS IOS – C20-24 Internal Olefin Sulfonate o More lipophilic than IOS o reduce optimal salinity Salinity scan – NaCl brine, WOR=1 Blend scan at 3% NaCl salinity, 2wt% surfactant o Optimal blend ratio between 1:4(N:I) - IOS 40 NI blend optimal salinity 5% NaCl + 1% Na 2 CO 3 N67: IOS concentration (aqueous) optimal salinity % NaCl 4:11wt% N67: IOS concentration (aqueous) optimal salinity % NaCl 4:11wt% :12wt%, 4wt%

41 Salinity scanBlend scan NI (4:1 blend) 1 wt% aq NI (1:1 blend) 2 wt% aq 3% NaCl salinity 2 wt% aq

IOS 2024N67-7PO 42

43 Replacing IOS15-18 with IOS reduces optimal salinity Not sufficient to reduce optimal salinity to reservoir salinity