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.

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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

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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