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The SPE Foundation through member donations and a contribution from Offshore Europe The Society is grateful to those companies that allow their professionals to serve as lecturers Additional support provided by AIME
Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
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“Smart Water” Flooding in Carbonates and Sandstones: A New Chemical Understanding of the EOR-potential
Tor Austad (
[email protected])
University of Stavanger, Norway
2
Example: “Smart Smart Water” Water in Chalk Spontaneous imbibition: Tres=90 90 oC; Crude oil AN=0 AN 0.5; 5; Swii=10% 10% Chalk: 1-2 mD
•Formation water: VB •Seawater: SW •Seawater Seawater depleted in NaCl •Seawater depleted in NaCl and spiked with 4x sulfate
3
Example: ”Smart Smart Water” 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 perm. 0.1 1-1 1 mD mD. 4
Example: “Smart Smart Water” Water in Sandstone L Low S li it EOR-effect Salinity EOR ff t under d forced f d displacement di l t 60
50
Recovery (%)
40
30
Low Salinity
High Salinity
B15-Cycle-2 20
10
0 0
2
4
6
8
10
PV Injection
HS: 100 000 ppm;
LS: 750 ppm 5
What is “Smart Smart Water Water”? ? • “Smart water” can improve wetting properties of oil reservoirs and optimize fluid flow/oil recovery in porous medium during production. y g the ion • “Smart water” can be made byy modifying composition. – No expensive p chemicals are added. – Environmental friendly.
• Wetting condition dictates: – Capillary pressure curve; Pc=f(Sw) – Relative permeability; kro and krw = f(Sw) 6
Water flooding •
•
• •
Water W t flooding fl di off oilil reservoirs i h has b been performed f d ffor a century t 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. I j i off the Injection h “S “Smartest”” water should h ld b be d done ffrom d day 1 1.
7
Outline • Discuss the conditions for observing EORy «Smart Water» in: effecets by – Carbonates – Sandstones
• A very simplified chemical explanation
8
Wetting properties in carbonates • Carboxylic acids, R-COOH – AN (mgKOH/g)
• Bases B ((minor i iimportance) t ) – BN (mgKOH/g)
-
-
Ca2+ C
Ca2+ C
Ca2+ C
+ + + + + + +
• Charge on interfaces – Oil-Water • R R-COO COO– Water-Rock • Potential determining ions – Ca2+, Mg2+, – (SO42-, CO32-, pH)
SO42-
-
- -
SO42-
- -
SO42-
-
9
Ekofisk •
Why is Wh i injection i j i off seawater such h a tremendous d success in i the h Ekofisk field? – Highly fractured – High temperature, 130 oC. – Low matrix permeability, 1-2 mD
Wettability:
20 028
20 024
20 020
20 016
20 012
20 008
0 20 004
2007: Goal 55 %
20 000
–
2002: 50%
19 996
NPD;
19 992
–
19 988
1976: 18% 2001: Goal: 46%
19 984
– –
19 980
Estimated recoveries
19 976
•
400
19 972
– Tor-formation: Preferential water-wet – Lower Ekofisk: Low water-wetness – Upper U Ek Ekofisk: fi k N Neutral t l tto oil-wet il t
S) OIL RATE, MSTBD (GROSS
•
10
Brine composition C Comp.
Ekofisk Ek fi k (mole/l)
Seawater S t (mole/l)
Na+ K+ Mg2+ Ca2+ ClHCO3SO42-
0.685 0 0.025 0.231 1.197 0 0
0.450 0.010 0.045 0.013 0.528 0.002 0.024
Seawater: [[SO42-]]~2 [Ca [ 2+] and [Mg [ g2+]]~ 2 [SO [ 42-] [Mg2+]~4 [Ca2+]
11
Effect of Sulfate in SW •Crude oil: AN=2.0 mgKOH/g •Initial brine: EF-water •Imbibing fluid: Modified SSW •Spontaneous S t imbibition i bibiti att 100 oC 60
Oil Recovery ,, %OOIP
50 40
SW4S at 100°C SW3S at 100°C SW2S t 100°C SW2S at 100°C SW at 100°C SW½S at 100°C SW0S at 100°C
30 20 10 0 0
10
20
Time, days
30
40
12
Is Ca22+ active in the wettability alteration? • • •
Crude oil: AN=0.55 mgKOH/g Swi = 0; Imbibing fluid: Modified SSW Spontaneous imbibition at 70 oC
Oil Recove ery , %OOIP
60 50 40 30 SW4Ca at 70°C SW3Ca at 70°C SW at 70°C SW½Ca at 70°C SW0Ca at 70°C
20 10 0 0
10
20
30
Time, days
40
50
60
13
Co-Adsorption of SO42- and Ca2+ vs. Temperature 1.00
C/Co SCN FL#7-1 SSW-M at 21°C 0.75
A=0.174
C/Co SO4 FL#7-1 SSW-M at 21°C
C/Co
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
0.50
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
0.25
A=0.402
C/Co SO4 FL#7-4 at 100°C
0.00 0.8
1.0
1.2
1.4
PV
A=0 A=0.547 547*(Extrapolert (Extrapolert 2.0
2.2
C/Co
0.6
C/Co SCN FL#7 FL#7-5 5 at 130°C 130 C 2.6PV) C/Co SO4 FL#7-5 at 130°C 1.6 1.8
Method: 1. Core saturated with SW without SO422. Core flooded with SW spiked with SCN- (Chromatographic 2) separation ti off SCN- and d SO42-
1.0
05 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
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Affinities of Ca2+ and Mg2+ towards the chalk surface NaCl-brine; [SCN-] = [Ca2+] = [Mg2+]= 0.013 mole/l
T=23 oC
T=130 oC 2 00 2.00
1.00
1.75
1.50
0.75
0.50
1.25
C/Co
C/Co
C/Co SCN (Brine with Mg and Ca2+) at 23C [Magnesium] A 0 084 A=0.084 C/Co Mg2+ (Brine with Mg2+ and Ca2+) at 23°C
1.00
C/Co Ca2+ (Brine with Mg2+ and Ca2+) at 23°C
0.75
C/Co SCN (Brine with Mg and Ca2+) at 130°C
0.50
0.25
C/Co Mg2+ (Brine with Mg2+ and Ca2+) at 130°C 0.25
C/Co Ca2+ (Brine with Mg2+ and Ca2+) at 130°C
0.00
0.00 0.6
0.8
1.0
1.2
1.4
1.6 PV
1.8
2.0
2.2
2.4
2.6
0.6
0.8
1.0
1.2
1.4
1.6
1.8 PV
2.0
2.2
2.4
2.6
2.8
3.0
CaCO3(s) + Mg2+ = MgCO3(s) + Ca2+ 15
Effects of potential determining ions and temperature on spontaneous imbibition Imbibition at 70 & 100oC (with/without Ca & Mg)
Re ecovery, %OIIP
25:SWx0CaMg(+Mg@43days) 26:SWx0Sx0CaMg(+Mg@ 53 days)
60
27:SWx2Sx0CaMg(+Ca@43 days) 28:SWx4Sx0CaMg(+Mg@53 days)
40
70°C
20
100°C
130°C
0 0
20
40
60 80 Time, days
100
120
16
Suggested wettability mechanism
17
Can SO422- compensate for low Tres ? oil rec covery (%OOIP)
70 100°C (Oil A, AN=2.07) 60 130°C (Oil A, AN=2.07) 50
40
30
20
10
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 SO42- conc.). Oil: AN=2.07 mgKOH/g). 18
Ion composition in PW from Ekofisk PW contained 73.6 vol% SW and 26.4 vol%FW 0.06
(PW)calc*
0.05
Concentration (m mole/l)
(PW)exp 0.04
0.03
0.02
0.01
0 Ca2+
Mg2+
SO42-
Component
Fig. 3 Calculated and measured component concentration in PW linked to substitution of Ca2+ by Mg2+ at the rock surface, adsorption of SO42- onto the rock and precipitation of CaSO4. 19
Can modified SW be an even “Smarter” EOR-fluid Spontaneous imbibition: Tres=90 oC; Crude oil AN=0.5; Swi=10%
•Formation water: VB •Seawater: SW •Seawater Seawater depleted in NaCl •Seawater depleted in NaCl and spiked with 4x sulfate 20
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 21
Forced displacement using «Smart SW Water»
Recov very, % OOIP P
40
30
20 FW‐0S SW SW‐0NaCl
10
0 0
3
6
9
12
15
Injected PV
Oil recovery by forced displacement from the composite limestone reservoir core. Successive injection of FW, SW and SW‐0NaCl. Ttest: 100°C. Injection rate: 0.01 ml/min (≈0.6 PV/D). 22
Low salinity EOR-effects EOR effects in carbonates
SPE 137634 Ali A. Yousef et al. (Saudi Aramco) 23
Codition for observing low salinity EOReffects in carbonates • •
The carbonate Th b rock k must contain i anhydrite, h di C CaSO SO4(s) ( ) Chemical equilibrium: CaSO4(s) ↔ Ca2+(aq) + SO42-(aq) ↔ Ca2+(ad) + SO42-(ad)
•
The concentration of SO42-(aq) depends on: – Temperature (decreases as T increases) – Brine salinity (Ca2+ concentration)
•
Wettability alteration process: – Temperature (increases as T increases) – Salinity (increases as NaCl conc. decreases)
•
Optimal temperature window – 90-110 oC ? 24
Presence of CaSO4
Concentration profiles of Ca2+, Mg2+, and SO422‐ when flooding reservoir limestone core with DI water, after aging with FW. Ttest: 100°C, Injection rate: 0.1 ml/min. 25
Low salinity EOR-effect EOR effect 60
20
Sulfaate concentratio on, mM
Recovery, % O R OOIP
FW‐0S
18
50 40 22% of OOIP
30 20 10
FW‐0S
100× dil. FW‐0S
10× dil. FW‐0S
16
100× dil. FW‐0S
14 12 10 8 6 4 2
0
0
0
3
6
9
12
15
18
21
24
Injected PV
Oil recovery by forced displacement from a reservoir limestone core containing anhydrite. Successive injection of FW and 100× diluted FW. Successive injection of FW, and 100× diluted FW Ttest: 100°C. Injection rate: 0.01 ml/min (≈1 PV/D).
0
50
100
150
Temperature °C Temperature, C
Simulated dissolution of CaSO4(s) when exposed to FW‐0S, 10× and 100× diluted FW at different temperatures.
26
“Smart Smart Water 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 Ca2+ and Mg2+) 27
General information
Adsorption onto clay
Local increase in pH important Connate Brine Low Salinity Brine-1
NaCl (mole/l) 1.54 0.0171
CaCl2 .2H2O (mole /l) 0.09 0.0
KCl (mole /l) 0.0 0.0
MgCl2 .2H2O (mole /l) 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
30
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 31
Clay minerals • Clays are chemically unique – Permanent localised negative g charges g – Act as cation exchangers • General order of affinity: Li+ < Na+ < K+ < Mg2+ < Ca2+
