Post on 31-Mar-2018
Norman Morrow Chemical & Petroleum Engineering
University of Wyoming
Improved Waterfloods: From Laboratory to Field
Enhanced Oil Recovery Institute 3rd Annual Wyoming IOR/EOR Conference Jackson, WY September 12-13, 2011
Oil Recovery : Waterflooding
Single 5-Spot Well Pattern
brine core
Laboratory Measurement of
Oil Recovery by Waterflooding
0
20
40
60
80
100
0 2 4 6 8 10 12
Oil
Rec
ove
ry, %
OO
IP
Brine Injected, PV
Target for Tertiary Recovery
Oil Recovery by Waterflood
Part I: Injection Brine Optimization -Low Salinity Waterflooding
Part II: Improved Recovery by Sequential Waterflooding- Proposed Single-Well Pilot Test
Low salinity waterflooding at Swi
First observations
Waterflood recovery vs. pore volume (PV) showing LSE for LSW at Swi. Connate and injected brine have identical ionic concentrations.
242 ppm
24,168 ppm
2,417 ppm
June 1995 – The British Petroleum Research Center sent their representative, Cliff Black, for a three day “think tank” session.
Necessary Conditions for LSE Tang and Morrow (1999)
• a significant clay fraction,
• the presence of connate water, and
• exposure of the rock to crude oil to create mixed-wettability.
These conditions are not sufficient; many outcrop sandstones meeting these conditions have not shown LSE recovery.
LSW at Swi for Berea sandstone
Dagang crude oil, and a matrix of connate and injected waterflood ionic compositions
(Tang and Morrow, 1997).
Oil Recovery (%OOIP)
Connate: HS MS LS
Injected:
HS 50 65 80
MS 50 71
LS 56 80
First applications of low salinity waterflooding have been for
watered-out reservoirs at residual oil saturation.
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30 35
Brine injected, PV
Oil
Re
co
ve
ry (
%O
OIP
)
HSW LSW
LSE
Distinct advantage of demonstrating LSE in a single piece of core.
Test of LSW on reservoir core at Sor after HSW
BP: All clastic reservoir systems studied to date have
shown an average of 14% additional oil recovery
Lager et al., 2006
100%o Hisal o Losal
oe
o initial o Hisal
S SS
S S
S o
e (%
)
0.20
0.25
0.30
0.35
0.40
0.45
Sor
Sor_HiSal Sor_LoSal
Residual Oil to Waterflood, % Pore Volume
2004 2005 2005/2006
9
11 17
LoSal
LoSal
LoSal
HiSal HiSal
HiSal
BP: Single Well Tracer Tests
Lager et al., 2006
Improved oil recovery observed - McGuire, P. et al., SPE 93903 (BP 2005)
- Seccombe, J. et al., SPE 113480 (BP 2008)
- Seccombe, J. et al., SPE 129692 (BP 2010)
No response
- Skrettingland, K. et al., SPE 129877 (Statoil 2010)
Corefloods were consistent with reservoir response
- encouraging with respect to use of laboratory screening
Reported Field Pilots
Low Salinity Effect - Mechanism
Many laboratories and organizations have grappled with identifying,
reproducing, and explaining LSE.
Interest in LSW has increased as indicated by the number of publications and presentations focused on LSE.
From review of LSW by Morrow and Buckley:
SPE Distinguished Author Series, JPT, May 2011.
Low salinity - mechanism
Despite growing interest in low salinity waterflooding, a consistent mechanistic
explanation has not yet emerged.
Wettability Alteration
Exposure of rocks to crude oil is known to cause wettability alteration towards decreased water-wetness.
Subsequent wettability alteration, usually towards increased water-wetness during the course of low salinity flooding, is the most frequently suggested cause of increased recovery.
Spontaneous Imbibition
The most direct, but less frequently used, measure of the wettability of rocks.
In addition to waterfloods, companion sets of spontaneous imbibition data were measured for
duplicate cores.
• comparable initial rates of imbibition are measured in all three cases • the extent of imbibition increases significantly with decrease in salinity.
Explaining the increases in the microscopic (pore level) displacement efficiency observed for both spontaneous imbibition and waterflooding is key to understanding the low salinity effect.
Low Salinity and Dissolution of Minerals
Increased recovery has been demonstrated for sandstone and
carbonate cores containing anhydrite
Studies on Wyoming Reservoirs using
Coal Bed Methane Water
(an abundant source of low salinity water)
Target Formations
• Minnelusa (Gibbs) and Tensleep (Teapot Dome) eolian sandstones
One half of Wyoming’s oil production
Abundant dolomite & anhydrite cement
Formation water salinity: 3,300 – 38,650 ppm
Low salinity water: Coalbed Methane Water (1,316 ppm)
• Phosphoria (Cottonwood) dolomite formation
Recovery factor as low as 10%
Patchy anhydrite
Formation water salinity: 30,755 ppm
Low salinity water: Diluted formation water (1,537 ppm)
Phosphoria Rock from Cottonwood Creek Field
100 mm
Dolomite Vug Dolomite
Mineralogy: Crystalline dolomite and patchy anhydrite
Porosity: 9.5 -19.6%
Permeability: 0.25 – 294 md Pu et al., 2010
0
5
10
15
20
25
30
0
10
20
30
40
50
60
70
80
90
100
0 5 10 15 20 25 30 35 40 45 50
Pre
ssure
dro
p,
psi
Oil
reco
very
, %
OO
IP
Brine injected, PV
PW30,755ppm
5% PW dilute1,537ppm
P1
Kg = 6.8 md, f = 9.5%Swi = 22.7%
+8.1%
Kwe1 = 2.1 md
Kwe2 = 1.1 md
Low Salinity Waterflooding for Phosphoria Rock
Pu et al., 2010
Summary of evidence for increased oil recovery through dissolution of anhydrite
Dry: P=7.7%; Q=79.6%; D+A=12.6% Wet: P=7.6%; Q=79.6%; D+A=12.7%
Lebedeva, E., Senden, T.J., Knackstedt, M., Morrow, N.R.
(2009)
Micro-X ray CT: Dissolution of anhydrite from
Tensleep sandstone by low salinity waterflooding
Summary - dissolution
• Tensleep and Minnelusa reservoir sandstones,
and Phosphoria reservoir dolomite all
contained anhydrite and all responded to low
salinity waterflooding
• Tensleep sandstone from an aquifer and
Silurian dolomite outcrop did not contain any
noticeable anhydrite and did not respond to low
salinity waterflooding
Low Salinity Waterflooding-Current Status Initial field studies concerned recovery of waterflood residual oil. Well-to-well field tests have given increased recovery. Low salinity flooding has now progressed to application in new reservoirs at the outset of water injection. ( can sometimes be planned in conjunction with treatment of brine by membrane separation to avoid reservoir souring)
Advances in Low Salinity Flooding and waterflooding in general
• Will result from development of broad understanding of the factors that determine waterflood recoveries for crude oil/brine/rock combinations for wide ranges of ionic strength and composition.
• Identification of the sufficient conditions for response to low salinity waterflooding and the circumstances under which there is little or no response remain as outstanding challenges.
Part II
Improved Recovery by Sequential
Waterflooding-Proposed Single-Well
Pilot Test
including application to natural
residual oil zones
Sequential waterflooding Technology arose from further observations
related to investigation of low salinity
waterflooding involving re-use of individual
reservoir cores
Cyclic flooding with cleaning, re-aging and change in salinity
Ta = 75oC
Combination of low salinity and seawater flooding without cleaning and re-aging between flood
1,500 ppm seawater
Baselines for assessment of
improved oil recovery
No previous study of reproducibility of
recovery of crude oil by waterflooding
Test of repeat flooding on a companion LK 2 reservoir core
with only initial cleaning and no change in salinity
This process will be referred to as
sequential waterflooding
0 2 4 6 8 10 12 14 160
20
40
60
80
100
kg = 886 md
R1/C1 : Swi
= 11% : Sor = 32%
LK 2
Ta = 75
oC
Td = 60
oC
Rw
f (%
OO
IP)
PV Brine Injected0 2 4 6 8 10 12 14 16
0
20
40
60
80
100
kg = 886 md
R1/C1 : Swi
= 11% : Sor = 32%
R1/C2 : Swi
= 11% : Sor = 27%
LK 2
Ta = 75
oC
Td = 60
oC
Rw
f (%
OO
IP)
PV Brine Injected0 2 4 6 8 10 12 14 16
0
20
40
60
80
100
kg = 886 md
R1/C1 : Swi
= 11% : Sor = 32%
R1/C2 : Swi
= 11% : Sor = 27%
R1/C3 : Swi
= 21% : Sor = 15%
LK 2
Ta = 75
oC
Td = 60
oC
Rw
f (%
OO
IP)
PV Brine Injected0 2 4 6 8 10 12 14 16
0
20
40
60
80
100
kg = 886 md
R1/C1 : Swi
= 11% : Sor = 32%
R1/C2 : Swi
= 11% : Sor = 27%
R1/C3 : Swi
= 21% : Sor = 15%
R1/C4 : Swi
= 23% : Sor = 13%
LK 2
Ta = 75
oC
Td = 60
oC
Rw
f (%
OO
IP)
PV Brine Injected
Sequential floods with seawater of friable reservoir sandstone
without cleaning/re-aging between cycles (Loahardjo et. al., 2008)
Loahardjo, et al., Energy & Fuels, 2010
Sequential waterfloods of outcrop
sandstones and carbonates
• No initial cleaning needed
(the notorious problems of cleaning reservoir
cores are avoided)
• No change in salinity
• No cleaning or re-aging between floods
Can a water flood be reproduced?
Outcrop Berea Sandstone
• Ta = 75oC
• ta = 14 days
• Td = 60oC
• WP Crude Oil
Sequential flooding of sandstone
Outcrop Bentheim Sandstone (very low clay content)
• Ta = 75oC
• ta = 14 days
• Td = 60oC
• WP Crude Oil
Sequential flooding of Bentheim sandstone (Bth 01) with seawater
Outcrop Limestone (EdGc)
• Ta = 75oC
• ta = 14 days
• Td = 60oC
• WP Crude Oil
Sequential flooding of Limestone with crude oil at 60oC
Summary of change in Sor for
sequential waterflooding (Td = 60oC)
Residual oil for sequential waterflooding for LK reservoir, limestone and
sandstone cores at Td = 60oC at 6 PV of seawater injection
Limestone
Bentheim Sandstone
Berea Sandstone (BS) Reservoir
Confirmation of Reduction in Residual
Oil Saturation
by Sequential Waterflooding
Magnetic Resonance Imaging (ConocoPhillips Facility)
Residual oil for sequential waterflooding
for displacement of WP crude oil at 60oC
Limestone
Bentheim Sandstone
Berea Sandstone (BS) Reservoir
BS/MRI/2D
BS/MRI/3D
Conclusion
Sequential waterfloods for recovery of
crude oil without core cleaning and
restoration between floods and without
change of salinity,
usually exhibit large reductions in
residual oil.
Two patents filed by UW:
1. Field wide application
2. Single well testing and diagnostics
Covers both waterflood and natural residual oil
zones
Sequential waterflooding has potential
application as a new improved recovery
technique
water
oil
Free water surface
Pc = 0
depth
Water saturation
0 100%
aquifer
Oil distribution after
waterflooding
oil
upper transition zone
transition zone
oil
Free water surface
Pc = 0
depth
Water saturation
0 100%
Wate
rflo
od r
esid
ual oil
aquifer
Conventional view of oil
distribution in a reservoir
water
oil
Pc = 0
depth
Water saturation
0 100%
oil
natural residual
oil (NROZ)
upper transition zone
transition zone
Oil reservoir with residual oil
retained in aquifer
oil depth
Water saturation
0 100%
WROZ
NROZ
water
Distribution of residual oil
above and below transition
zone after waterflooding
oil depth
Water saturation
0 100%
WROZ
VROZ
NROZ water
NROZ Only
any oil once held in
reservoir has spilled
Single-Well Tests of
Sequential Floods
Calculations are based on a simple
piston-like displacement model
f =20.9%, 30 ft reservoir oil-zone thickness
Increased Oil Recovery by Oil
Injection Followed by Water Injection
• Sor reduction taken from laboratory data :
Bth 01 3D MRI
WF1 50 36
WF2 37 29
WF3 20 24
Reservoir at residual oil saturation after waterflood
(WF1)
SOR (WF1)=36.2% target zone radius = 45 ft
Day 0 0 10 20 30 40 50 ft
Injection of oil into the target zone
SOR (WF1)=36.2% target zone radius = 45 ft
SOR (WF1)=36.2%
oil injected = 100 bbl
Day 1
SO=64.9%
0 10 20 30 40 50 ft
START WATER INJECTION
SOR (WF1)=36.2%
oil bank minimum radial length= 4.5 ft
oil bank volume = 406 bbl
Displacement of injected oil by injection of brine
(WF2)
inner radial distance
oil bank radial length
Day 1 Day 2
Radial length of oil reaches minimum before
growing upon more injection of brine
0 10 20 30 40 50 ft
SOR (WF1)=36.2%
Continuation of oil bank displacement by
injection of brine (WF2)
oil bank radial length= 5.9 ft oil bank volume = 1,149 bbl
SO=64.9% SOR (WF2)=28.8%
Day 2 Day 3 Day 4 Day 5 Day 6 0 10 20 30 40 50 ft
The well is put on production and the oil bank
grows in volume and radial length
SOR (WF1)=36.2%
Day 6 Day 8 Day 9 Day 10 0 10 20 30 40 50 ft
SOR (WF1)=36.2% SOR (WF2)=28.8% SOR (WF3)=24.0%
Day 10 Day 11 Day 12 Day 13 Day 14
The well is put on production and the oil bank
grows in volume and radial length
0 10 20 30 40 50 ft
Single Well Field Test
4,000 bbl oil in 62 days (as high as 15,000 bbl optimistically)
900 bbl oil in 14 days (as high as 3200 bbl optimistically)
2,000 bbl brine
100 bbl oil
10,000 bbl brine 100 bbl
oil
Many possibilities exist for other approaches to
improved recovery by injection of small
volumes of oil
• Example 1 : Inject multiple oil banks
• Example 2 : Improve recovery of sequential floods by displacing injected oil with low salinity brine.
• Example 3 : Pre-injection of oil will convert a tertiary mode low salinity flood into a much more effective secondary mode low salinity waterflood.
• Example 4 : Pre-inject low salinity brine
• Example 5 :Develop connectivity of oil phase in a natural residual oil zone
Field test : advantages/diagnostics
• Low cost: Injected brine and oil are directly available: Required oil volume is small
• Single well test gives direct volumetric measure of oil production
• Tracers added to the injected oil and brine will allow monitoring of mixing of injected oil and brine with reservoir oil and brine
• Oil/brine production ratios will indicate heterogeneity and viscous fingering
• Flow reversal will tend to counteract rock heterogeneities and phase distribution effects
Conclusions
• Sequential waterflooding without change in salinity
and without cleaning or re-aging between cycles
showed reductions in residual oil saturation
• NMR imaging confirmed the effect of sequential
waterflooding
• Single-well field testing of sequential waterflooding
for recovery of oil from waterflood and natural
residual oil zones is justified
Acknowledgements
• University of Wyoming Enhanced Oil
Recovery Institute
• BP, Total, StatoilHydro, ARAMCO,
ConocoPhillips, Chevron
• The Wold Chair