EOR in Fractured Carbonate Reservoirs

1
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

2
Outline

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

3
EOR strategy
4
EOR strategy

• Reservoir description
• Fractures high permeability paths
• Oil wet oil trapped in matrix by capillarity
• Dolomite, low salinity, 30 C
• Recover oil from matrix spontaneous imbibition
• IFT reduction
• Surfactants
• Wettability alteration
• Surfactants
• Alkali

Ref Hirasaki et. al, 2003
5
Current focus IFT reduction surfactant flood

• Surfactant flood desirable characteristics
• Low IFT (order of 10-2 mN/m)
• Surfactant-oil-brine phase behavior stays
  under-optimum
• Low adsorption on reservoir rock (chemical cost)
• Avoid generation of viscous phases
• Tolerance to divalent ions
• Solubility in injection and reservoir brine
• Easy separation of oil from produced emulsion

6
Phase behavior studies at 25 C
7
Procedure

• Parameter
• Salinity
• Surfactant blend ratio
• Soap/surfactant ratio

8
Phase behavior, IFT, solubilization parameter
lower
middle
upper
9
Phase behavior

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

10
S13D Salinity scan (Multiples of Brine2) WOR 1
optimal salinity
Vo/Vs 10 at reservoir salinity
0.5wt
optimal salinity
0.25wt
optimal salinity
11
Viscosity studies at 25 C
12
Viscosities of phases function of salinity
0.5 wt S13D
13
Imbibition studies at 25 C
14
Imbibition results S13D reservoir cores (1)
S13D 0.5wt 126md
S13D 0.25wt 151md
Mehdi Salehi, TIORCO
15

• S13D candidate for EOR
• under-optimum at reservoir salinity
• stays under-optimum upon dilution
• Vo/Vs10 (at 4wt surfactant concentration)indica
  tive of low IFT
• No high viscosity phases at reservoir salinity
• 70 recovery in imbibition tests

16
Adsorption studies at 25 C
17
Dynamic adsorption procedure

• Sand pack
• Limestone sand 20-40 mesh
• Washed to remove fines dried in oven
• Core holder
• Core cleaned with Toluene, THF, Chloroform,
  methanol
• Core holder with 400 800psi overburden pressure
• Vacuum saturation ( -27 to -29 in Hg)
• measure pore volume
• Permeability measurement

18
Dynamic adsorption - setup
19
Limestone sandpack 102D

• Injection solution Brine 2 with 1000ppm Br -
  0.5wt S13D
• Flow rate 12.24ml/h
• Pore volume 72 ml, Time for 1PV 6hrs

• 1PV .38 ft3/ft2
• Lag 0.14 PV
• Adsorption0.26 mg/g sand0.12 mg/g reservoir
  rock

20
Reservoir core 6mD

• Injection solution Brine 2 with 1000ppm Br -
  0.5wt S13D
• Flow rate 2ml/h
• Pore volume 12 ml, Time for 1PV 6hrs

• 1PV .035 ft3/ft2
• Effective pore size 26.8??m
• Lag 0.54PV to 1.25PV
• Adsorption0.12 mg/g rock to0.28 mg/g rock

21
Reservoir core 6mD plugging
21
22
HPLC analysis of effluent
HPLC sample
23
Reservoir core 15mD

• 2 micron filter _at_ inlet pressure monitored
• Injection solution Brine 2 with 1000ppm Br -
  0.5wt S13D
• Flow rate 1ml/h, Pore volume 30 ml, Time for
  1PV 1.25 days

• 1PV .103 ft3/ft2
• Effective pore size 11.8??m
• Lag 0.67PV
• Adsorption0.29 mg/g rock

HPLC sample
24
HPLC analysis of effluent
diff in area 25
By Yu Bian
25
Adsorption results comparison
Experiment Material Equivalent adsorption on reservoir rock (mg/g) Residence time (hrs)
Dynamic Limestone sand 0.12 6
Dynamic Dolomite core 6mD 0.12 0.28 6 - overnight
Dynamic Dolomite core 15mD 0.29 30
Static (by Yu Bian) Dolomite powder 0.34 24
26
Phase behavior studies at 30 C
27
S13D phase behavior
S13D 1wt _at_ 30 C Type II microemulsion
S13D 1wt _at_ 30 C with live oil (600 psi) Type
II microemulsion
S13D 1wt _at_ 25 C Type I microemulsion
28
S13D/S13B blend scan 30C
Brine 2 salinity 2 wt aq WOR 1
Optimal blend
29
Phase behavior S13D/S13B blend With dead oil _at_
30 C
Aqueous stability test of S13D/S13B blend
30
S13D/S13B (70/30) dead vs live crude _at_ 30 C
Dead oil UNDER-OPTIMUM
Live oil OVER-OPTIMUM
After mixing settling for 1 day
Before mixing
After mixing settling for 1 day
31
Imbibition studies at 30 C
32
Imbibition results reservoir cores (1)
S13D 0.5wt 126mD, 25 C
S13D/S13B 70/30 1wt 575mD, 30 C
S13D 0.25wt 151mD 25 C
S13D/S13B 60/40 1wt 221mD, 30 C
Mehdi Salehi, TIORCO
33
Conclusions
34
Conclusions

• Dynamic adsorption experiments (absence of oil)
• Effluent surfactant concentration plateaus at
  80 injected concentration
• Higher PO components are deficient in the
  effluent sample (in plateau region)
• Increase in pressure drop with volume throughput
• Sensitivity of phase behavior to temperature and
  oil (dead vs. live)
• S13D/S13B 70/30 _at_ 30 C performance poor compared
  to S13D _at_ 25 C

35
Questions
36
Back up slides
37
S13D surfactant flood additional experiments

• Analysis of plugging behavior
• HPLC analysis of dynamic adsorption effluent
  samples determine missing components
• Determine pore size distribution of Yates core
  samples by NMR and Mercury porosimetry for cores
  of different permeability
• Determine surfactant micelle size
• Presence of anhydrite measure Ca2
  concentration in dynamic adsorption effluent by
  ICP
• Quantify effect of S13D on
• wettability calcite slab contact angle
  measurements
• IFT spinning drop measurements

38
NI blend - 41 N67-7PO IOS 15-18

• N67-7PO Neodol C16-17 7Propoxy Sulfate
• IOS 15-18 C15-18 Internal Olefin Sulfonate
• Optimal salinity 5 NaCl 1 Na2CO3
• Na2CO3
• Generation of soap
• optimal salinity function of soap to surfactant
  ratio
• Wettability alteration
• Reduced adsorption

Liu et.al 2008 (SPE99744)
39
NI blend

• Unsuitable conditions for Alkali Surfactant
  flooding
• Presence of divalent ions in injection fluid
• Precipitation of CaCO3 in presence of Na2CO3
• Presence of 600 psi CO2
• Na2CO3 ? NaHCO3 ? lower pH
• Low pH no soap generation

40
N67- 7PO and IOS 20-24

• IOS 20-24 C20-24 Internal Olefin Sulfonate
• More lipophilic than IOS 15-18
• reduce optimal salinity
• Salinity scan NaCl brine, WOR1
• Blend scan at 3 NaCl salinity, 2wt surfactant
• Optimal blend ratio between 14(NI) - IOS

N67 IOS concentration (aqueous) optimal salinity NaCl
41 1wt 4 - 4.5

N67 IOS concentration (aqueous) optimal salinity NaCl
41 1wt 4 - 4.5
11 2wt, 4wt 3.5 - 4
NI blend optimal salinity 5 NaCl 1 Na2CO3
41
Salinity scan
Blend scan
NI20-24 (41 blend) 1 wt aq
NI20-24 (11 blend) 2 wt aq
3 NaCl salinity 2 wt aq
42
IOS 2024
N67-7PO
43
Replacing IOS15-18 with IOS 20-24 reduces
optimal salinity Not sufficient to reduce
optimal salinity to reservoir salinity