study of imbibition mechanisms in the naturally fractured spraberry trend area yan fidra petroleum...
TRANSCRIPT
Study of Imbibition Mechanisms in the Naturally Fractured Spraberry Trend
Area
Yan Fidra
Petroleum and Chemical Engineering DepartmentNew Mexico Institute of Mining and Technology
Outline
• Introduction
• Laboratory Experiments
• Modeling
• Conclusions
• Recommendations
Outline
• Introduction– Problem statement– Literature review– Objectives– Overview of the study
• Laboratory Experiments• Modeling• Conclusions • Recommendations
Problem Statement
Lack in understanding of upscaling
laboratory imbibition experiments to
field dimensions
- Low rock permeability that represent real thing
- Static and dynamic process
- Reservoir conditions
Wetting behavior
Literature Review
rock characteristics (Mattax and Kyte, 1962; Torsaeter, 1984; Thomas 1984; Hamon and Vidal, 1988)
fluid properties (Iffly et al., 1972; Cuiec et al., 1990; Keijzer and De Vries, 1990; Ghedan and Poetmann, 1990; Schechter et al., 1991; Babadagli, 1995; Al-Lawati and Saleh, 1996)
low permeability of Chalk reservoir (Torsaeter, 1984; Bourbiaux and Kalaydjian, 1990; Cuiec et al., 1990)
wettability (Anderson, 1986; Hirasaki, et al, 1990; Zhou et al., 1995; Buckley, et al , 1995)
aging time and temperature and initial water saturations (Zhou et al., 1993; Jadhunandan and Morrow, 1991)
scaling of imbibition data (Mattax and Kyte, 1962; Lefebvre du Prey, 1978; Ma, 1995; Zhang et al, 1996)
Objectives
• To investigate wettability of Spraberry Trend Area at reservoir conditions.
• To upscale the laboratory imbibition results to field-scale dimensions.
• To investigate the contribution of the capillary imbibition mechanism to waterflood recovery.
• To determine the critical water injection rate during dynamic imbibition.
Overview of the Study
Static imbibition
Dynamicimbibition
Field dimension
Determine rock wettability
Upscaling Upscaling
Determine laboratory critical
injection rate
Fracture Capillary Number
Scaling equations
Capillary pressure curve
Outline• Introduction
• Laboratory Experiments– Static Imbibition Tests
• Verify the effect of P & T on recovery mechanisms• Determine rock wettability index
– Dynamic Imbibition Tests• Investigate the effect of injection rate on recovery
mechanism• Determine critical injection rate
• Modeling• Conclusions • Recommendations
Static Imbibition Experiments
• Materials• Experimental apparatus• Results
Porous Media
FluidsCrude Oil
Synthetic Reservoir Brine
(TDS = 130,196 ppm)
Berea sandstone
Low permeabilitySpraberry rock
Materials
Schematic Diagram of the Static Imbibition Process in Laboratory
coreoiloil
water
Imbibition model with one end closed
1.5” X 2.5 - 3.0”Core
Syntheticbrine
beaker
138oF
Experimental Set-up for Imbibition Tests under HPHT
BVBV
BV
NV
PR
Graduated Cylinder
Brine Tank HighPressure
ImbibitionCell
N2 Bottle(2000 psi)
Air Bath
BV = Ball ValveNV = Needle ValvePR = Pressure Regulator
Top View
Inlet for creatingtangential flow
Side View
core
Brine Pump Oil Pump
Air Bath
Core holder
Confining pressure gauge
Graduated cylinder
Oil tank Brine tank
Flooding Apparatus
0
10
20
30
40
50
60
70
0 1 100 10000Time, hours
Oil
Rec
over
y, %
IO
IP
B-13, P = 13.5 psiB-10, P = 13.5 psiB-11, P = 1000 psiReference
7 days aging
Texp = 138oFSwi = 0 %
Effect of Pressure and Temperature on Static Imbibition Rate and Recovery using Berea Sandstone
0
10
20
30
40
50
60
-100 400 900Time, hours
Rec
over
y, %
IO
IP
Increased to
temperature 138oF
No agingP = 13.5 psiSwi = 0%
Tres = 138oF
Troom = 70oF
0
5
10
15
20
25
0.1 10 1000 100000
Time, Hours
Oil
Rec
ove
ry,
% I
OIP
Core SPR-1HRCore SPR-12HCore SPR-13RCore SPR-14R
138oF
70oF
138oF
70oF
0
5
10
15
20
25
-100 400 900 1400 1900
Time, Hours
Oil
Rec
ove
ry,
% I
OIP
Core SPR-1HR
Core SPR-12H
Core SPR-15R
Extended to reservoir temperature
Effect of Temperature on Static Imbibition Rate and Recovery using Spraberry Reservoir Rock
Cleaning Spraberry core plugs
Dean Stark Extraction
Chloroform Displacement
Drying (2 days) Evacuation (24 hours) Weight
Evacuated Spraberry brine Measure brine density and viscosity
Saturation of core samples
Ionic equilibrium (3 days) Porosity calculation
Brine permeability Recheck the porosity
Oil viscosity, density and
IFT measurementsOil floodingOil flooding
Establish Swi Establish Swi i
Aging core samples in oil
Aging time (days)Aging time (days)
0 3 7 14 21 30
at reservoir temperatureat reservoir temperature
Aging time (days)Aging time (days)
0 7 14
at reservoir temperatureat reservoir temperatureNo aging timeNo aging time
Imbibition tests (21 days)at reservoir temperature
Imbibition tests (21 days) at reservoir temperature
Imbibition tests (2 months)at ambient condition
Brine displacementBrine displacementat room temperatureat room temperature
Brine displacementBrine displacementat reservoir temperatureat reservoir temperature
Brine displacementBrine displacementat room temperatureat room temperature
Results
Experimental Procedures for determining WI using Spraberry Cores
DisplacementDisplacement
A
B
Static imbibitionStatic imbibition
Amott Wettability Index
WIRA
RA RB
0 1
Water-wetmoreless
0
2
4
6
8
10
12
14
16
18
20
0.01 0.1 1 10 100 1000 10000Time, Hours
Oil
Rec
over
y, %
IO
IP
Core SPR-1HR
Core SPR-2HR
Core SPR-6HR
Core SPR-5HR
Core SPR-7HR
Core SPR-3HR
No aging
7 days aging
14 days aging
21 days aging
30 days aging
Static imbibition
A
Oil Recovery Curves Obtained from Static Imbibition Experiments at Reservoir
Temperature
Spraberry cores
0
10
20
30
40
50
60
0 10 20 30 40
Aging Time, ta (days)
Oil
Rec
over
y, %
IOIP
Recovery from imbibition process
Total Recovery
DisplacementDisplacement
A
B
StaticStaticimbibitionimbibition
Total recovery vs aging time shows that 7 days aging time is adequate to start the
experiments
Spraberry cores
Displacement
A
B
Static imbibition Wettability index vs aging time
for different experimental temperatures
WIRA
RA RB
Spraberry cores0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
0 10 20 30Aging Time, ta (days)
Wet
tabil
ity I
ndex
to W
ate
r, W
I
Process A = 138F and Process B = 138F
Process A = 70F and Process B = 70F (without aging)
Process A = 138F and Process B = 70F
Dynamic Imbibition Experiments
•Schematic of displacement process
•Experimental apparatus•Results
MATRIX BLOCK
MATRIX BLOCK
FRACTUREWater Oil + Water
Oil saturated matrix
Imbibed water
Capillary imbibition
Viscous flow
Oil produced
Schematic Representation of the Displacement Process in Fractured Porous Medium
MatrixFracture
Artificially fractured core
Air BathAir Bath
Core holderBrine tank
Confining pressure gauge
Graduated cylinder
N2 Tank(2000 psi)
RuskaPump
Experimental Apparatus for Dynamic Imbibition Tests
0
10
20
30
40
50
60
70
0.001 0.01 0.1 1 10 100
PV Water Injected
Oil
Rec
over
y, %
IO
IP
Qinj = 1 cc/hr
Qinj = 2 cc/hr
Qinj = 4 cc/hr
Qinj = 8 cc/hr
Qinj = 8 cc/hr (repeated)
Qinj = 16 cc/hr
Qinj = 40 cc/hr
Oil Recovery from Fractured Berea Cores during Water Injection using Different Injection Rates
0
10
20
30
40
50
60
0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50
PV Water Injected
Oil
Rec
over
y
Unfractured core, Qinj = 0.2 cc/hr
Fractured core, Qinj = 0.2 cc/hr
Fractured core, Qinj = 0.5 cc/hr
Fractured core, Qinj = 1.0 cc/hr
Unfractured core
Fractured core
Oil Recovery from Fractured Spraberry Cores during Water Injection using Different Injection Rates
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
0 10 20 30 40 50 60
Injection Rate, cc/hr
Oil
Pro
du
ced F
rom
Matr
ix, P
V
Tota
l W
ate
r In
ject
ed, P
V
Experimental data from Berea cores
Experimental data from Spraberry cores
Critical Injection rate for Spraberry cores, 10 cc/hr
Critical Injection rate for Berea cores, 20 cc/hr
Injection rate versus oil-cut curve for Berea and Spraberry cores
Outline• Introduction• Laboratory Experiments
•Modeling– Static imbibition data
• Investigate Pc from matching of experimental data.• Scale up of static imbibition data.
– Dynamic imbibition data• Obtain Pc curves from matching of experimental data.• Scale up of dynamic imbibition data.
• Conclusions • Recommendations
Modeling of Static Imbibition
• Numerical Analysis of Static Imbibition Data
• Scaling of static imbibition data
• Results
Matching between Laboratory Experiments and Numerical Solution
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
1.0E+00 1.0E+02 1.0E+04 1.0E+06 1.0E+08
Time (Sec)
Volu
me
Oil
(cc
)
Numerical Solution
SPR-8H
SPR-9H
SPR-7HR
SPR-11H
Capillary Pressure Curve Obtained as a Result of Matching
Experimental data
0.000
0.005
0.010
0.015
0.020
0.025
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Water Saturation, Sw (%PV)
Capil
lary
Pre
ssure
, Pc (p
si)
Numerical Analysis of Static Imbibition Data
Scaling of Imbibition Data“Concept of Imbibition Flooding Process”
( Brownscombe, 1952 )
WaterWaterMatrixMatrix
FractureFracture
InvadeInvadedd
zonezone
Oil productionOil production
Oil production by water imbibitionOil production by water imbibition
water
oil
Capillary force
fracture matrix
Matrix fracture fluidexchange mechanism
Viscous force
To investigate the contribution of a static imbibition process to waterflood recovery
Imbibition
A
Complete Oil Recovery Curves Obtained from Imbibition Experiments
0
2
4
6
8
10
12
14
16
18
20
0.01 0.1 1 10 100 1000 10000Time, Hours
Oil
Rec
over
y, %
IO
IP
Core SPR-1HRCore SPR-8HCore SPR-9HCore SPR-12HCore SPR-10HCore SPR-2HRCore SPR-6HRCore SPR-5HRCore SPR-7HRCore SPR-3HRCore SPR-11HSPR-13SPR-14SPR-15
No aging
7 days aging
14 days aging
21 days aging
30 days aging
70oF
Spraberry cores
No aging
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
1 10 100 1000 10000
Dimensionless Time
Nor
mal
ized
Rec
over
y Reservoir Condition
Ambient Condition
Without aging
With aging
Oil Recovery Curves in Terms of Dimensionless Variables
t C tk
LD
m
g c
cos( )2
RR
Rnimb
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
0.01 1 100 10000 1000000
Dimensionless Time, tD
Norm
ali
zed R
ecovery
SWW Core"reference curve"(Ma & Morrow, 1995)
Spraberry Coresat Reservoir Condition
= 0.0053
Spraberry Coresat Ambient Condition
= 0.0015
Aranofsky Eq. : R n = 1 - exp (-t D)
Averaging of imbibition curves
Equations for Scaling of Static Imbibition Data
t Ct yeark md dyne cm
cp L ftD
m
g c
( )( ) ( / )
( )
cos( )
( )
2 2
R R timb D 1 exp
g b o
q V eo ot
C = 10.66;
0 00532
.cos( )
Ck
Lm
g c
0.000
0.020
0.040
0.060
0.080
0.100
0.120
0.140
0.160
7080 7082 7084 7086 7088 7090 7092 7094 7096 7098
Depth in Shackelford 1-38A, feet
Poro
sity
, fr
act
ion
0.01
0.10
1.00
10.00
Abso
lute
Perm
eabil
ity, m
d
Porosity
Absolute Permeability
Non-pay muddy zone
Flourescing pay zone
Rock Properties of Upper Spraberry 1U Unit
7080
7082
7084
7086
7088
7090
7092
7094
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
Calculated Recovery Based on Imbibition Model, % IOIP
Dep
th in
Wel
l Sha
ckel
ford
1-3
8A, f
eet
1 year 5 year > 10 year
Ls = 3.79 ft
h = 10 ft
Recovery Profile
Upper SpraberryUpper Spraberry1 U Formation1 U Formation
(Shackleford-138)(Shackleford-138)
1U
0
2
4
6
8
10
12
14
0 5 10 15
Time, Years
Calc
ula
ted O
il R
ecover
y, %
IOIP
Parameters : IOIP = 712,404 - 735,957 rb Rimb = 13% Porosity = 10.02% Bo = 1.294 rb/STB
Fracture spacing, Ls = 2.86 ft
Swi = 0.2 + 0.13e-0.6(k-0.1)
k = 0.3 md
k = 0.1 md
k = 0.03 md
k = 0.01 md
0
2
4
6
8
10
12
14
0 5 10 15
Time, Years
Parameters : IOIP = 712,404 - 735,957 rb Rimb = 13% Porosity = 10.02% Bo = 1.294 rb/STB Matrix permeability = 0.1 mD
Swi = 0.2 + 0.13 e-0.6(k-0.1)
Ls = 1.62 ft
Ls = 2.86 ftLs = 3.17 ft
Ls = 3.79 ft
Effect of Matrix Permeability and Fracture Spacing on Oil Recovery
Modeling of Dynamic Imbibition Data
• Numerical analysis of dynamic imbibition data to obtain capillary curves.
• Concept of fracture capillary number.
• Upscaling of dynamic imbibition data to determine critical water injection rate.
Matching Between
Experimental Data and
Numerical Solution
Berea Core
Spraberry Core
Cumulative water production vs. time Cumulative oil production vs. time
Cumulative water production vs. time Cumulative oil production vs. time
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
0.0 0.5 1.0
Water Saturation, Sw (%PV)
Pc
for
Bere
a C
ore
, (p
si)
0
1
2
3
4
5
6
7
8
9
10
Pc for
Spra
berr
y C
ore
, (p
si)
0
5
10
15
20
25
30
0.0 0.2 0.4 0.6 0.8 1.0
Water Saturation (PV)
Capil
lary
Pre
ssure
(psi
g)
Pc detemined experimentally at roomtemperature
Pc determined by numerically at reservoirtemperature
Drainage
Imbibition
Pc Curves Obtained as Result of Matching Experiment Data
Spraberry core
Berea core
Pc from Numerical Model and Laboratory
Experiment
NViscous Forces
Capillary Forces
v A
Af caw f
m, cos
Nq cc hr cp
P psi
J SA cm
k mdf cainj w
c
wim
m
m
,,max
. ( / ) ( )
( )
( )( )
( )
0 0127
2
Nq STB day cp
P psi
J SA ft
k mdf cainj w
c
wim
m
m
,,max
. ( / ) ( )
( )
( )( )
( )
0 0905
2
Field Units :
Lab Units :
Fracture Capillary Number
Am
w
dz
Af
Capillary force
( cos Am)
Viscous force
(v w Af )
h
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
0 10 20 30 40 50 60
Injection Rate, cc/hr
Oil
Pro
du
ced F
rom
Matr
ix, P
V
Tota
l W
ate
r In
ject
ed, P
V Experimental data from Berea cores
Experimental data from Spraberry cores
Critical Injection rate for Spraberry cores, 10 cc/hr
Critical Injection rate for Berea cores, 20 cc/hr
2 Capillary and viscous forces dominant
1 Capillary force dominant
3 Viscous force dominant
Injection Rate versus Oil-cut
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
0 0.0001 0.0002 0.0003 0.0004 0.0005 0.0006
Fracture Capillary Number, Nf,ca
Oil
Pro
duce
d F
rom
Matr
ix, P
V
Tota
l W
ate
r In
ject
ed, P
V
Experimental data from Berea cores
Experimental data from Spraberry cores
Series3
Power ( Experimental data from Bereacores)
Nf,ca = 0.0001
Nf,ca = 0.00028
Spraberry cores
Berea cores
Dimensionless fracture capillary number versus oil-cut
Porousmedium
Berea sandstone Spraberry
Dimension Core size Field scale Core size Field scale
Nf,ca 0.00028 0.00010
Area - 80 acre - 80 acrewater 0.68 cp 0.68 cp 0.68 cp 0.68 cp
L inj-prod 7.12 cm 1320 ft 6.8 cm 1320 ft
h 3.63 cm 10 ft 3.7 cm 10 ft
Am 25.81 cm2 13200 ft2 24.8 cm2 13200 ft2
k 63.41 md 63.41 md 0.1 md 0.1 md 16.6 % 16.6 % 10% 10%
Pcmax 1.2 psi 1.2 psi 7 psi 7 psi
J (Swi) 0.99 0.99 0.2 0.2
Critical WaterInjection Rate
20 cc/hr 1435 bbl/day 10 cc/hr 751 bbl/day
Upscaling of Critical Injection Rate
1000 0 1000 3000 2000 4000 5000 FEET
3
16
1-4
15
6
1A
1
1
5
14
9
1 13
14
10
4
7
1
28
23
2
1C
36 4
37
25
21
29 1
3
4
1B
PROPOSED CO2 INJECTION WELL
PROPOSED LOGGING OBSERVATION
WATER INJECTION WELL
PLUGGED AND ABANDONED
ACTIVE PRODUCER
SHUT IN WELL46
45
47
41
42
44
40
39
38 4
348
5U (N32E)
5U (N80E)
1U (N42E)
Fracture orientation
O’Daniel Pilot Layout
I njectionWell
Distanceto well-39
(ft)
Critical waterinjection rate
(STB/ D)w-45 1420 807
w-47 1450 824
w-48 1460 830
W-25 1450 824
Estimate Critical Water Injection Rates for Wells in O’Daniel Pilot Area
Outline
• Introduction• Laboratory Experiments
• Modeling
•Conclusions
• Recommendations
Conclusions• Wettability Determination
– Performing the imbibition tests at reservoir temperature and displacement tests at room temperature indicate that WI is 0.3 to 0.4.
– Performing both imbibition and displacement tests at the same temperature (i.e., reservoir temperature or at room temperature) lowers the WI in the range of 0.20 to 0.25; thus, the temperatures during the experimental sequence affect wettability index determination.
– Comprehensive experimental data clearly demonstrates that Spraberry reservoir rock is a very weakly water-wet system.
Conclusions (cont’d)
• Static Imbibition
– Effect of pressure is much less important than the effect of temperature on imbibition rate and recovery.
– Performing the imbibition tests at higher temperature results in faster imbibition rate and higher recovery due to change in mobility of fluids, expansion of oil, and change in IFT.
– The final recovery due to imbibition using Spraberry cores varies from 10% to 15% of IOIP, depending on aging time.
Conclusions (cont’d)
• Scaling of static imbibition data
– The contribution of the imbibition mechanism to oil recovery is up to 13% IOIP, depending on rock properties and wettability.
– Degree of heterogeneity in the matrix and natural fracture system controls the efficiency of Spraberry waterflood performance.
Conclusions (cont’d)
• Dynamic Imbibition– As the flow rate increases, contact time
between matrix and fluid in fracture decreases causing less effective capillary imbibition.
– The capillary pressure curve obtained from dynamic imbibition experiments is higher that of the static imbibition experiments due to viscous forces during the dynamic process.
• The limiting value of fracture capillary number for an efficient displacement process in this study was found to be 0.0001 and 0.00028 for Berea and Spraberry cores, respectively. Beyond this range, the displacement process is inefficient due to high water-cut.
Conclusions (cont’d)
Outline
• Introduction• Laboratory Experiments
• Modeling
• Conclusions
•Recommendations
Recommendations
• Necessary to correlate the static and dynamic tests in order to achieve proper upscaling.
• The capillary pressure curve obtained from dynamic imbibition experiments using artificially fractured core can be used as input data in naturally fractured reservoir simulations instead of using mercury injection capillary pressure curves.
Acknowledgement
I would like to express my sincere appreciation and gratitude to my advisor Dr. David S. Schechter and My committee members Dr. Robert L. Lee, Dr. H.Y. Chen and Dr. Donald Weinkauf for their advice and time spent on this thesis.
To PRRC for the financial support through research assistantship grant.
To my fellow students and the entire staff of the PRRC for their kindness and assistance.
Thank You…
Happy Thanksgiving
1000 0 1000 3000 2000 4000 5000 FEET
15
1
28
4
37
2546
45
47
41
42
44
40
39
38 4
348
5U (N32E)
5U (N80E)
1U (N42E)
Fracture orientation