Tulsa 15125
Content
Exploitation and Optimization of Reservoir
Performance in Hunton Formation, OK
Review of Budget Period I
DE-FC26-00BC15125
By
Mohan Kelkar
Partners in Project
•
•
•
•
•
•
The University of Tulsa
The Department of Energy
Marjo Operating Company
The University of Houston
Jim Derby and Associates
Joe Podpechan and Jason Andrews
Outline
•
•
•
•
Objectives of the project
Progress so far
Conclusions BP I
Future work
Objectives
• To understand the primary production
mechanism by which oil is being produced
from the West Carney field
• To develop procedures for extrapolating the
production methods to other wells and
other reservoirs exhibiting similar
characteristics
• To extend the life of the field beyond
primary production
Tools Used
•
•
•
•
•
Geological Description
Log Analysis
Flow Simulation
Rate-Time Analysis
Laboratory Data Collection and
Analysis
Location of West Carney Hunton
field
Lease Map of the West Carney Hunton
field
Characteristic Behavior
• Water oil ratio decreases over time
• Gas oil ratio first increases and then
decreases with time
• Increase in GOR when the well is reopened
after workover
• Some wells exhibit pressure drawdown
when the well is shut-in
• Association between oil and water
production
GOR after shut in
G O R (M SC F/ST B)
30
25
20
18.5
15
9.42
10
5
0
0
100
200
300
Time(Days)
400
500
Presence of Fractures
• Core photographs indicate the presence of
fractures
Presence of Fractures
• High permeability, in excess of 1000 mD
has been observed at some locations
• High water rates also indicate the presence
of fractures
• Communication between wells has been
observed
• Well test data also indicates fractures
Presence of Fractures
250
500
200
400
150
300
`
100
200
50
100
0
0
100
200
300
Time(Days)
400
0
500
Wilkerson#2
(STB/DAY)
Wilkerson#1 Oil Rate
Wilkerson#1
Wilkerson#2
Relation Between Oil and Gas
Production
• Wells that produce oil also produce gas
• Oil and gas exhibit the same production
trend
Relation Between Oil and Gas
Production
•Plot of oil rate vs gas rate for all the wells
suggest the same behavior
250
O il R a te
200
150
100
50
0
0
200
400
Gas Rate
600
800
Limited Aquifer
• Reservoir pressure has been declining in the field
1800
P re s s u re
1600
1400
1200
1000
800
600
400
200
0
0
100
200
Time (Days)
300
400
Limited Aquifer
• Water rate is also declining in the field
1400.00
600.00
1200.00
500.00
1000.00
400.00
800.00
300.00
600.00
200.00
400.00
100.00
200.00
0.00
0.00
100.00
200.00
Time(days)
300.00
0.00
400.00
M c B rid e S o u th
M c B rid e N o rth W a te r
R a te (S T B /d a y )
McBride North
McBride South
Bulk of the Hydrocarbon Production
is Through Water Zone
• Some wells have shown good
fluorescence but are bad producers
• These wells also produce less water
Bulk of the Hydrocarbon Production
is Through Water Zone
Water Rate
700
80
600
70
60
500
50
400
40
300
30
200
20
100
10
0
0
100
200
Time(days)
0
300
O il R a te (S T B /d a y )
W a te r R a te (S T B /d a y )
Oil Rate
Core Descriptions and Analysis
• Twenty seven wells have been cored, data from twenty two
wells was available for this study
• Cores have been analyzed at Stim Lab
• Fourteen cores have been described in detail
• Three lithologies; limestone, dolomite and partly dolomitized
limestone have been identified
• Fourteen facies types have been recognized
• Four pore types; vug, coarse matrix, fine matrix and fracture
have been recognized in each of the three litho types.
• Results from Conodont studies have been used to demarcate
the cochrane and clarita formations
Generalized lithofacies
distribution
T. 16 N.
NONPOROUS MUDSTONE
FACIES
T. 15 N.
FOSSILIFEROUS
LIMESTONE MACROFACIES
DOLOMITE
FACIES
R. 1 E.
R. 2 E.
R. 3 E.
Location of the cored wells
W. Carney Ext. SWDW Mary Marie
14-15N-1E
11-15N-2E
Bailey 2-6
6-15N-3E
Carney Townsite
15-15N-3E
100
ft.
WOODFORD
UNCONFORMITY
•
50 ft.
UPPER
CLARITA
C OCHR ANE
LOWER
C OCHR ANE
0 ft.
BASAL
CLARITA
COD
COD
SYMBOL DESCRIPTION
SYMBOL
DESCRIPTION
ARGILLACEOUS DOLOMITE
8
CORAL AND DIVERSE FAUNA
2
CRYSTALLINE DOLOMITE
9
CORAL AND CRINOID
GRAINSTONE/WACKESTONE
3
SMALL BRACHIOPOD
GRAINSTONE/PACKSTONE/WACKESTONE
10
SPARSE FOSSIL WACKESTONE
4
FINE CRINOID GRAINSTONE/PACKSTONE
11
CARBONATE MUDSTONE
12
FINE TO MEDIUM GRAINSTONE
13
SHALE
14
FINE SANDSTONE
6
COARSE CRINOID
GRAINSTONE/PACKSTONE
MIXED CRINOID-BRACHIOPOD
GRAINSTONE/PACKSTONE/
WACKESTONE
7
BIG PENTAMERID BRACHIOPOD
CODE
5
SYMBOL DESCRIPTION
CODE
1
SYMBOL
DESCRIPTION
1
INTERCONNECTED VUGGY POROSITY/
LIMESTONE
7
MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITE
2
COARSE MATRIX POROSITY/ LIMESTONE
8
FRACTURE/ DOLOMITE
3
FINE MATRIX POROSITY/ LIMESTONE
9
VUGGY OR MOLDIC POROSITY/
DOLOMITIC LIMESTONE
4
FRACTURE/ LIMESTONE
10
COARSE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
5
VUGGY OR MOLDIC POROSITY/DOLOMITE
11
MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
6
COARSE CRYSTALINE POROSITY/
DOLOMITE
12
FRACTURE/ DOLOMITIC LIMESTONE
90
80
West Carney Hunton Field:
Lithology & Pore Types
70
Limestone
Dolomitic Limestone
WOODFORD
SHAL E
UPPE R
C OC HRANE
C L ARITA
30
40
50
60
Dolomite
20
BASAL
C L ARITA
10
L OWE R
C OC HRANE
Correlation of Core data to Log
data
• Comparison of core derived porosity to
log derived porosity
• Making of core-log plots
• Reduction of pore types
• Use the vs Ln K relation to generate
K values at un-cored wells
Core Vs Log
Correlation Coefficients between core porosity and log porosity
Well Name
Density Log
Neutron Log
Crossplot
((D2+N2)/2)0.5
Boone 1-4
0.1016
0.7393
0.8066
crossplot
dolomitic limestone
Carney Townsite 2-5
0.8196
0.9437
0.9452
crossplot
dolomitic limestone
Carter 1-14
0.4771
0.6682
0.8862
crossplot
limestone
Danny 2-34
0.7259
0.5043
0.7791
crossplot
limestone
Henry 1-3
0.3592
0.6495
0.668
crossplot
limestone
Joe Givens 1-15
0.3017
0.1343
0.283
density
limestone
Mary Marie 1-11
0.7291
0.806
0.7803
neutron
limestone
McBride South 1-10
0.0753
0.6543
0.6192
neutron
limestone
Wilkerson 1-3
0.5775
0.8466
0.8271
neutron
limestone
Best Correlation
Dominant rock type
Log Evaluation
• Determination of Sw
Sw = Water Saturation
= {(D2+N2)/2}1/2
m = 1.77
a=1
n=2
Rw= 0.035
SW
a
m
Rw
Rt
• Determination of BVW
BVW = Bulk volume water
BVW * S w
1
n
Log Evaluation (contd)
• Determination of oil in place
7758 * h * Sw
BAF
Ht
BAF = barrels per acre foot
Sw = water Saturation
Ht = hunton thickness of each well
h = thickness of each data point
= porosity
Buckles Plot Approach
0.300
0.250
P o r s ity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
0.7
0.8
0.9
1
BUCKLES PLOT
0.300
0.250
w at e r zones
P o r o si t y ( - )
0.200
Transition
zones
0.150
0.100
0.050
Reservoir
zones
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.7
0.8
0.9
1
Buckles Plot
0.300
0.250
P o r o si t y ( - )
0.200
Invaded
zone
0.150
0.100
0.050
Oil zone
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.7
0.8
0.9
1
Electrofacies Analysis
• Electrofacies is a term used to describe
litho units that show similar response
on electric logs
• Principal component analysis
• Cluster analysis
• Discriminant analysis
Principal Component analysis
• Reduction of data to lower dimensions
• Minimal loss of information
• First few principal components explain
maximum variance
Cluster Analysis
• Method of clustering data into groups
• Partitioning algorithms that use a pure
mathematical criteria
• Number of clusters to be provided can be
determined from the clusplot
Discriminant Analysis
• Used for extending the cluster analysis to
the raw data
• Creates a discriminant function based on
groups
• Applies this function to group the raw data
Comparison of Electrofacies and Geological facies
100%
90%
fr pdol
80%
f pdol
cr pdol
70%
PercentageDistribution of Geological facies
vug pdol
fr dol
60%
f dol
50%
cr dol
vug dol
40%
fr ls
f ls
30%
cr ls
vug ls
20%
10%
0%
1
2
3
Electrofacies
4
5
BUCKLES PLOT for electrofacies #2
0.300
0.250
P o r o s ity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
2
0.7
0.8
0.9
1
BUCKLES PLOT w ith electrofacie s # 3
0.300
0.250
P o r s it y ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
3
0.7
0.8
0.9
1
BUCKLES PLOT with electrofacies #4
0.300
0.250
Porosity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
4
0.7
0.8
0.9
1
BUCKLES PLOT w ith electrofacies # 5
0.300
0.250
P o r o s it y ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
5
0.7
0.8
0.9
1
Correlation of static data to dynamic
data
• Production data for competitor wells
was collected from public domain
• Wells were declined at a rate of 50%
per year and cumulative production for
a six year time period was calculated
• Pickett plots for each well were
compared to the production data.
Ranks of KH 1th Vs Water Rate
30
Anna 1-11
Bailey 2-6
Boone 1-4
Carney tow nsite
25
Carter 1-14
Carter ranch
Danny 2-34
Ranking of water rate(decreasing order)
20
Henry
Joe Givens
Mc Bride South
15
Wilkerson
Williams
cal
Franny
10
Tow nsend
geneva
Denney 1-31
5
Garret
Allan Ross
Lew is
Mc Bride North
0
0
5
10
15
20
Ranking of Kh 1st percentile (decreasing order)
25
30
Schw ake
Wilson
Recovery Factor calculations
• Rfoil =
N p * Boi * 100
N
Gp
• Rfgas =
N
* Rsi
Boi
* 100
Boi = Initial oil volume factor
Rsi = Initial solution gas oil ratio
Np = Oil produced
Gp = Gas produced
N = oil in place
RFoil VS Facies 1+2+3
16
14
12
Recover factor (%)
10
8
6
4
2
0
0
0.1
0.2
0.3
0.4
0.5
0.6
Proportion of facies 1+2+3
0.7
0.8
0.9
1
RFoil vs Facies 4+5
16
14
12
Recovery Factor (%)
10
8
6
4
2
0
0
0.1
0.2
0.3
0.4
0.5
Proportion of facies 4+5
0.6
0.7
0.8
0.9
1
Rf gas Vs facies 1+2+3
25
Recovery Factor (%)
20
15
10
5
0
0
0.1
0.2
0.3
0.4
0.5
0.6
Proportion of facies 1+2+3
0.7
0.8
0.9
1
Rf gas Vs Facies 4+5
25
Recovery factor (%)
20
15
10
5
0
0
0.1
0.2
0.3
0.4
0.5
0.6
proportion of facies 4+5
0.7
0.8
0.9
1
Single Well Numerical Model
Production characteristics to be reproduced
from numerical model
• Initial decline in GOR
• Association of oil production with that of
water production
• Decreasing water-oil ratio
• Increase in GOR after the well was shut-in
Single Well Numerical Model
Gas
Oil
Water
Single Well Numerical Model
Horizontal Permeability
Vertical Permeability
Porosity
Thickness
Grid size
Skin
Depth
Bubble Point
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Near well
Away from well
Height
Layer 1
Layer 2
Layer 3
0.1
0.005
100
75
75
75
1.60%
3%
6.50%
6
15
21
50 ft x 50 ft.
75 ft x 75 ft.
Same as layer thickness
0
-3.5
-3
4960 ft.
1600 psia
Results
Simulation
Field
0.2
0.18
0.16
Oil Rate
0.14
0.12
0.1
0.08
0.06
0.04
0.02
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
0.8
0.7
Gas Rate
0.6
0.5
0.4
0.3
0.2
0.1
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
14
12
GOR
10
8
6
4
2
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
1.2
1
W ater C ut
0.8
0.6
0.4
0.2
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Series2
1600
1400
1200
BHP
1000
800
600
400
200
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Horizontal
Permeability
(Near Well bore)
Horizontal
Permeability
(Away Well bore)
Vertical
Permeability
Pore Volume
(Near Well bore)
Pore Volume
(Away Well bore)
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Initial Value Final Value
0.1
1.8983
0.005
0.005
100
71.03
0.1
0.736
0.005
0.005
100
64.09
75
75
75
75
75
0.854
42.74
4.274
200.35
483.76
607.75
1605.8
96.17
9.617
450.8
708.02
1367.4
3102.8
Rate-Time Analysis
• Estimate permeability and skin factor for
wells using available production data
• Improve understanding of West Carney
Field which exhibits complex production
characteristics
• Develop procedures for estimating in
place reserves in the field.
Reservoir Model Description
• Three layer-no cross
flow
• Analysis should
give:
3 external radius
values
3 permeability values
3 skin factor values
CR #2-15 Water: qDdL vs. QDdL
1.2
1
qDdL
0.8
0.6
0.4
0.2
0
0
0.1
0.2
0.3
0.4
0.5
QDdL
0.6
0.7
0.8
0.9
1
CR #2-15 Water: q vs. t
Water Rate (STB/day)
1000
100
10
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Water Results
Param eter
Calculated Value
Confidence (+/-)
r e (ft)
4,222.65
n/a
Npmax (MSTB)
58.3291
n/a
Recovery Factor
0.71%
n/a
k (m d)
17.687
2.932
sf
-4.827
0.558
CR #2-15 Oil: qDdL vs. QDdL
3.5
3
2.5
qDdL
2
1.5
1
0.5
0
0
0.1
0.2
0.3
0.4
0.5
QDdL
0.6
0.7
0.8
0.9
1
CR #2-15 Oil: q vs. t
Oil Rate (STB/day)
100
10
1
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Oil Results
Param eter
r e (ft)
Calculated Value
Confidence (+/-)
1,206.23
n/a
Npmax (MSTB)
7.4469
n/a
Recovery Factor
1.52%
n/a
1.046
0.117
-5.856
0.138
k (m d)
sf
CR #2-15 Gas: qDdG vs. QDdG
1.6
1.4
1.2
qDdG
1
0.8
0.6
0.4
0.2
0
0
0.1
0.2
0.3
0.4
0.5
QDdG
0.6
0.7
0.8
0.9
1
CR #2-15 Gas: q vs. t
GasRate (Mscf/day)
1000
100
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Gas Results
Param eter
Calculated
Value
Confidence (+/-)
r e (ft)
1,181.23
n/a
Gpmax (BCF)
0.14725
n/a
Recovery Factor
92.26%
n/a
0.475
0.032
-5.637
0.077
k (m d)
sf
Summary of Field Cases
Well
Layer h (ft)
Oil
15.34
McBride South Gas
5.00
Water 15.36
re (ft)
2,316
2,308
5,342
0.684
0.052
6.405
0.077 -5.145 0.186
0.043 -6.629 0.524
0.479 -7.269 0.082
10.3
0.3
62.0
72.5
120.0
Oil
10.25 1,206
Carter Ranch Gas
6.15 1,181
Water 11.60 4,223
7.447 1.52% 1.046
0.147 92.26% 0.475
58.329 0.71% 17.687
0.117 -5.856 0.138
0.032 -5.637 0.077
2.932 -4.827 0.558
10.7
2.9
205.2
218.8
665.9
Oil
28.69 1,839
Gas
12.00 1,766
Water 24.80 7,467
23.772 1.00%
3.6
0.207 87.77% 5.566
134.919 0.47% 29.454
0.308 -6.534 0.120
0.785 -1.279 0.953
5.200 -4.081 0.943
103.3
66.8
730.5
900.5
n/a
Boone
Franny
Oil
15.00
551
Gas
4.87
567
Water 9.68 2,279
Np (Mstb) or
Total kh kh Core
Gp (Bscf)
RF
k (md) (+/-) md
sf
(+/-) kh (md-ft) (md-ft) (md-ft), air
25.734 1.98% 1.747
0.125 -5.397 0.189
26.8
40.6
0.312 94.33% 5.075
2.123 9.090 7.313
25.4 247.7
87.123 0.92% 12.727
1.667 -5.886 -0.389
195.5
2.496
n/a
46.044
2.07%
n/a
0.96%
Results
• Generally, consistent with field
observations
Wells acid fractured, so negative skin
expected
Wells drain more than 160 acres
Oil and Gas layers have much lower
permeability than the Water layer
Lab Work Methodology
•CT Scan
• Wettability using standard Amott
wettability test
•Unsteady state relative permeabilities
•Dean Stark analysis
•Correlation between wettability and
relative permeabilities
•Wettability alteration tests
Experimental Procedure
5
1.
Pc
4
2.
3
Water Saturation, Sw
Mary Marie#4968.6/4968.7
•
•
•
•
•
Porosity=9.7%
Absolute Perm =1.32 md
Water index = 0.15
Oil index = 0.11
Amott Wettability index=0.04
Imbibition Relative
Permeability
Mary Marie 4967.7, 4967.8
1
0.8
0.6
0.4
0.2
0
Krw
Kro
0
0.2
0.4
0.6
Sw
0.8
1
Mercury Capillary Pressure
1: Carter 4995.2, 2: Wilkerson 4974.9, 3: Mary Marie 4968.6
K(md),porosity %
Correlations
15
12
9
6
3
0
-0.4
-0.3
-0.2
-0.1
K
Porosity
0
0.1
AI
•As porosity and absolute permeability increase
rock becomes more oil-wet.
Correlations
Krw, end
1
0.8
0.6
0.4
0.2
0
-0.4
-0.3
-0.2
-0.1
0
0.1
Amott Wettability index, AI
•As rock becomes more oil-wet end point
relative permeability increases.
Conclusions
• Reservoir is highly heterogeneous; karst and
fractures affect well performance
• Dual permeability system seems to exist
• Fine matrix rock seems to be better connected to the
high permeability component
• Low recoveries from the coarse matrix and vuggy
rock suggests that these are isolated pores
• Decrease in reservoir pressure and water production
confirms a limited aquifer
Conclusions (contd)
• Oil and gas co-exist in the field
• Electrofacies analysis successfully
differentiate between the oil zones and the
invaded zones
• Wells with high proportions of electrofacies
# 4 & 5 are good producers
• Wells calculating high oil in place from log
data are not necessarily good producers
Conclusions (Contd.)
•
•
•
Study confirms that the field is highly
heterogeneous and wells are in communication
with each other through fractures
It is possible to determine drainage radius from
material balance and use automatic type-curve
matching to determine permeability and skin.
Skin factor results provide a useful tool to
determine completion effectiveness
Conclusions (Contd.)
• Hunton rocks are found to be neutral wet to
oil-wet.
• In rocks studied ,oil wettability increases as
absolute permeability and porosity increase.
• The end point water relative permeability
increases as oil wettability of rocks increase.
Future Work
• Improve reservoir and fluid description for
history matching
• Improve logging analysis
• Include multi-phase flow in rate-time
Analysis
• Investigate tertiary recovery mechanisms to
improve the recovery
• Conduct technical workshops
Performance in Hunton Formation, OK
Review of Budget Period I
DE-FC26-00BC15125
By
Mohan Kelkar
Partners in Project
•
•
•
•
•
•
The University of Tulsa
The Department of Energy
Marjo Operating Company
The University of Houston
Jim Derby and Associates
Joe Podpechan and Jason Andrews
Outline
•
•
•
•
Objectives of the project
Progress so far
Conclusions BP I
Future work
Objectives
• To understand the primary production
mechanism by which oil is being produced
from the West Carney field
• To develop procedures for extrapolating the
production methods to other wells and
other reservoirs exhibiting similar
characteristics
• To extend the life of the field beyond
primary production
Tools Used
•
•
•
•
•
Geological Description
Log Analysis
Flow Simulation
Rate-Time Analysis
Laboratory Data Collection and
Analysis
Location of West Carney Hunton
field
Lease Map of the West Carney Hunton
field
Characteristic Behavior
• Water oil ratio decreases over time
• Gas oil ratio first increases and then
decreases with time
• Increase in GOR when the well is reopened
after workover
• Some wells exhibit pressure drawdown
when the well is shut-in
• Association between oil and water
production
GOR after shut in
G O R (M SC F/ST B)
30
25
20
18.5
15
9.42
10
5
0
0
100
200
300
Time(Days)
400
500
Presence of Fractures
• Core photographs indicate the presence of
fractures
Presence of Fractures
• High permeability, in excess of 1000 mD
has been observed at some locations
• High water rates also indicate the presence
of fractures
• Communication between wells has been
observed
• Well test data also indicates fractures
Presence of Fractures
250
500
200
400
150
300
`
100
200
50
100
0
0
100
200
300
Time(Days)
400
0
500
Wilkerson#2
(STB/DAY)
Wilkerson#1 Oil Rate
Wilkerson#1
Wilkerson#2
Relation Between Oil and Gas
Production
• Wells that produce oil also produce gas
• Oil and gas exhibit the same production
trend
Relation Between Oil and Gas
Production
•Plot of oil rate vs gas rate for all the wells
suggest the same behavior
250
O il R a te
200
150
100
50
0
0
200
400
Gas Rate
600
800
Limited Aquifer
• Reservoir pressure has been declining in the field
1800
P re s s u re
1600
1400
1200
1000
800
600
400
200
0
0
100
200
Time (Days)
300
400
Limited Aquifer
• Water rate is also declining in the field
1400.00
600.00
1200.00
500.00
1000.00
400.00
800.00
300.00
600.00
200.00
400.00
100.00
200.00
0.00
0.00
100.00
200.00
Time(days)
300.00
0.00
400.00
M c B rid e S o u th
M c B rid e N o rth W a te r
R a te (S T B /d a y )
McBride North
McBride South
Bulk of the Hydrocarbon Production
is Through Water Zone
• Some wells have shown good
fluorescence but are bad producers
• These wells also produce less water
Bulk of the Hydrocarbon Production
is Through Water Zone
Water Rate
700
80
600
70
60
500
50
400
40
300
30
200
20
100
10
0
0
100
200
Time(days)
0
300
O il R a te (S T B /d a y )
W a te r R a te (S T B /d a y )
Oil Rate
Core Descriptions and Analysis
• Twenty seven wells have been cored, data from twenty two
wells was available for this study
• Cores have been analyzed at Stim Lab
• Fourteen cores have been described in detail
• Three lithologies; limestone, dolomite and partly dolomitized
limestone have been identified
• Fourteen facies types have been recognized
• Four pore types; vug, coarse matrix, fine matrix and fracture
have been recognized in each of the three litho types.
• Results from Conodont studies have been used to demarcate
the cochrane and clarita formations
Generalized lithofacies
distribution
T. 16 N.
NONPOROUS MUDSTONE
FACIES
T. 15 N.
FOSSILIFEROUS
LIMESTONE MACROFACIES
DOLOMITE
FACIES
R. 1 E.
R. 2 E.
R. 3 E.
Location of the cored wells
W. Carney Ext. SWDW Mary Marie
14-15N-1E
11-15N-2E
Bailey 2-6
6-15N-3E
Carney Townsite
15-15N-3E
100
ft.
WOODFORD
UNCONFORMITY
•
50 ft.
UPPER
CLARITA
C OCHR ANE
LOWER
C OCHR ANE
0 ft.
BASAL
CLARITA
COD
COD
SYMBOL DESCRIPTION
SYMBOL
DESCRIPTION
ARGILLACEOUS DOLOMITE
8
CORAL AND DIVERSE FAUNA
2
CRYSTALLINE DOLOMITE
9
CORAL AND CRINOID
GRAINSTONE/WACKESTONE
3
SMALL BRACHIOPOD
GRAINSTONE/PACKSTONE/WACKESTONE
10
SPARSE FOSSIL WACKESTONE
4
FINE CRINOID GRAINSTONE/PACKSTONE
11
CARBONATE MUDSTONE
12
FINE TO MEDIUM GRAINSTONE
13
SHALE
14
FINE SANDSTONE
6
COARSE CRINOID
GRAINSTONE/PACKSTONE
MIXED CRINOID-BRACHIOPOD
GRAINSTONE/PACKSTONE/
WACKESTONE
7
BIG PENTAMERID BRACHIOPOD
CODE
5
SYMBOL DESCRIPTION
CODE
1
SYMBOL
DESCRIPTION
1
INTERCONNECTED VUGGY POROSITY/
LIMESTONE
7
MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITE
2
COARSE MATRIX POROSITY/ LIMESTONE
8
FRACTURE/ DOLOMITE
3
FINE MATRIX POROSITY/ LIMESTONE
9
VUGGY OR MOLDIC POROSITY/
DOLOMITIC LIMESTONE
4
FRACTURE/ LIMESTONE
10
COARSE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
5
VUGGY OR MOLDIC POROSITY/DOLOMITE
11
MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
6
COARSE CRYSTALINE POROSITY/
DOLOMITE
12
FRACTURE/ DOLOMITIC LIMESTONE
90
80
West Carney Hunton Field:
Lithology & Pore Types
70
Limestone
Dolomitic Limestone
WOODFORD
SHAL E
UPPE R
C OC HRANE
C L ARITA
30
40
50
60
Dolomite
20
BASAL
C L ARITA
10
L OWE R
C OC HRANE
Correlation of Core data to Log
data
• Comparison of core derived porosity to
log derived porosity
• Making of core-log plots
• Reduction of pore types
• Use the vs Ln K relation to generate
K values at un-cored wells
Core Vs Log
Correlation Coefficients between core porosity and log porosity
Well Name
Density Log
Neutron Log
Crossplot
((D2+N2)/2)0.5
Boone 1-4
0.1016
0.7393
0.8066
crossplot
dolomitic limestone
Carney Townsite 2-5
0.8196
0.9437
0.9452
crossplot
dolomitic limestone
Carter 1-14
0.4771
0.6682
0.8862
crossplot
limestone
Danny 2-34
0.7259
0.5043
0.7791
crossplot
limestone
Henry 1-3
0.3592
0.6495
0.668
crossplot
limestone
Joe Givens 1-15
0.3017
0.1343
0.283
density
limestone
Mary Marie 1-11
0.7291
0.806
0.7803
neutron
limestone
McBride South 1-10
0.0753
0.6543
0.6192
neutron
limestone
Wilkerson 1-3
0.5775
0.8466
0.8271
neutron
limestone
Best Correlation
Dominant rock type
Log Evaluation
• Determination of Sw
Sw = Water Saturation
= {(D2+N2)/2}1/2
m = 1.77
a=1
n=2
Rw= 0.035
SW
a
m
Rw
Rt
• Determination of BVW
BVW = Bulk volume water
BVW * S w
1
n
Log Evaluation (contd)
• Determination of oil in place
7758 * h * Sw
BAF
Ht
BAF = barrels per acre foot
Sw = water Saturation
Ht = hunton thickness of each well
h = thickness of each data point
= porosity
Buckles Plot Approach
0.300
0.250
P o r s ity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
0.7
0.8
0.9
1
BUCKLES PLOT
0.300
0.250
w at e r zones
P o r o si t y ( - )
0.200
Transition
zones
0.150
0.100
0.050
Reservoir
zones
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.7
0.8
0.9
1
Buckles Plot
0.300
0.250
P o r o si t y ( - )
0.200
Invaded
zone
0.150
0.100
0.050
Oil zone
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.7
0.8
0.9
1
Electrofacies Analysis
• Electrofacies is a term used to describe
litho units that show similar response
on electric logs
• Principal component analysis
• Cluster analysis
• Discriminant analysis
Principal Component analysis
• Reduction of data to lower dimensions
• Minimal loss of information
• First few principal components explain
maximum variance
Cluster Analysis
• Method of clustering data into groups
• Partitioning algorithms that use a pure
mathematical criteria
• Number of clusters to be provided can be
determined from the clusplot
Discriminant Analysis
• Used for extending the cluster analysis to
the raw data
• Creates a discriminant function based on
groups
• Applies this function to group the raw data
Comparison of Electrofacies and Geological facies
100%
90%
fr pdol
80%
f pdol
cr pdol
70%
PercentageDistribution of Geological facies
vug pdol
fr dol
60%
f dol
50%
cr dol
vug dol
40%
fr ls
f ls
30%
cr ls
vug ls
20%
10%
0%
1
2
3
Electrofacies
4
5
BUCKLES PLOT for electrofacies #2
0.300
0.250
P o r o s ity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
2
0.7
0.8
0.9
1
BUCKLES PLOT w ith electrofacie s # 3
0.300
0.250
P o r s it y ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
3
0.7
0.8
0.9
1
BUCKLES PLOT with electrofacies #4
0.300
0.250
Porosity ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
4
0.7
0.8
0.9
1
BUCKLES PLOT w ith electrofacies # 5
0.300
0.250
P o r o s it y ( - )
0.200
0.150
0.15
0.14
0.13
0.12
0.11
0.10
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.100
0.050
0.000
0
0.1
0.2
0.3
0.4
0.5
0.6
Water saturation ( - )
0.0065
5
0.7
0.8
0.9
1
Correlation of static data to dynamic
data
• Production data for competitor wells
was collected from public domain
• Wells were declined at a rate of 50%
per year and cumulative production for
a six year time period was calculated
• Pickett plots for each well were
compared to the production data.
Ranks of KH 1th Vs Water Rate
30
Anna 1-11
Bailey 2-6
Boone 1-4
Carney tow nsite
25
Carter 1-14
Carter ranch
Danny 2-34
Ranking of water rate(decreasing order)
20
Henry
Joe Givens
Mc Bride South
15
Wilkerson
Williams
cal
Franny
10
Tow nsend
geneva
Denney 1-31
5
Garret
Allan Ross
Lew is
Mc Bride North
0
0
5
10
15
20
Ranking of Kh 1st percentile (decreasing order)
25
30
Schw ake
Wilson
Recovery Factor calculations
• Rfoil =
N p * Boi * 100
N
Gp
• Rfgas =
N
* Rsi
Boi
* 100
Boi = Initial oil volume factor
Rsi = Initial solution gas oil ratio
Np = Oil produced
Gp = Gas produced
N = oil in place
RFoil VS Facies 1+2+3
16
14
12
Recover factor (%)
10
8
6
4
2
0
0
0.1
0.2
0.3
0.4
0.5
0.6
Proportion of facies 1+2+3
0.7
0.8
0.9
1
RFoil vs Facies 4+5
16
14
12
Recovery Factor (%)
10
8
6
4
2
0
0
0.1
0.2
0.3
0.4
0.5
Proportion of facies 4+5
0.6
0.7
0.8
0.9
1
Rf gas Vs facies 1+2+3
25
Recovery Factor (%)
20
15
10
5
0
0
0.1
0.2
0.3
0.4
0.5
0.6
Proportion of facies 1+2+3
0.7
0.8
0.9
1
Rf gas Vs Facies 4+5
25
Recovery factor (%)
20
15
10
5
0
0
0.1
0.2
0.3
0.4
0.5
0.6
proportion of facies 4+5
0.7
0.8
0.9
1
Single Well Numerical Model
Production characteristics to be reproduced
from numerical model
• Initial decline in GOR
• Association of oil production with that of
water production
• Decreasing water-oil ratio
• Increase in GOR after the well was shut-in
Single Well Numerical Model
Gas
Oil
Water
Single Well Numerical Model
Horizontal Permeability
Vertical Permeability
Porosity
Thickness
Grid size
Skin
Depth
Bubble Point
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Near well
Away from well
Height
Layer 1
Layer 2
Layer 3
0.1
0.005
100
75
75
75
1.60%
3%
6.50%
6
15
21
50 ft x 50 ft.
75 ft x 75 ft.
Same as layer thickness
0
-3.5
-3
4960 ft.
1600 psia
Results
Simulation
Field
0.2
0.18
0.16
Oil Rate
0.14
0.12
0.1
0.08
0.06
0.04
0.02
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
0.8
0.7
Gas Rate
0.6
0.5
0.4
0.3
0.2
0.1
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
14
12
GOR
10
8
6
4
2
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Field
1.2
1
W ater C ut
0.8
0.6
0.4
0.2
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Simulation
Series2
1600
1400
1200
BHP
1000
800
600
400
200
0
0
50
100
150
200
250
Time(days)
300
350
400
450
500
Results
Horizontal
Permeability
(Near Well bore)
Horizontal
Permeability
(Away Well bore)
Vertical
Permeability
Pore Volume
(Near Well bore)
Pore Volume
(Away Well bore)
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Layer 1
Layer 2
Layer 3
Initial Value Final Value
0.1
1.8983
0.005
0.005
100
71.03
0.1
0.736
0.005
0.005
100
64.09
75
75
75
75
75
0.854
42.74
4.274
200.35
483.76
607.75
1605.8
96.17
9.617
450.8
708.02
1367.4
3102.8
Rate-Time Analysis
• Estimate permeability and skin factor for
wells using available production data
• Improve understanding of West Carney
Field which exhibits complex production
characteristics
• Develop procedures for estimating in
place reserves in the field.
Reservoir Model Description
• Three layer-no cross
flow
• Analysis should
give:
3 external radius
values
3 permeability values
3 skin factor values
CR #2-15 Water: qDdL vs. QDdL
1.2
1
qDdL
0.8
0.6
0.4
0.2
0
0
0.1
0.2
0.3
0.4
0.5
QDdL
0.6
0.7
0.8
0.9
1
CR #2-15 Water: q vs. t
Water Rate (STB/day)
1000
100
10
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Water Results
Param eter
Calculated Value
Confidence (+/-)
r e (ft)
4,222.65
n/a
Npmax (MSTB)
58.3291
n/a
Recovery Factor
0.71%
n/a
k (m d)
17.687
2.932
sf
-4.827
0.558
CR #2-15 Oil: qDdL vs. QDdL
3.5
3
2.5
qDdL
2
1.5
1
0.5
0
0
0.1
0.2
0.3
0.4
0.5
QDdL
0.6
0.7
0.8
0.9
1
CR #2-15 Oil: q vs. t
Oil Rate (STB/day)
100
10
1
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Oil Results
Param eter
r e (ft)
Calculated Value
Confidence (+/-)
1,206.23
n/a
Npmax (MSTB)
7.4469
n/a
Recovery Factor
1.52%
n/a
1.046
0.117
-5.856
0.138
k (m d)
sf
CR #2-15 Gas: qDdG vs. QDdG
1.6
1.4
1.2
qDdG
1
0.8
0.6
0.4
0.2
0
0
0.1
0.2
0.3
0.4
0.5
QDdG
0.6
0.7
0.8
0.9
1
CR #2-15 Gas: q vs. t
GasRate (Mscf/day)
1000
100
1
10
100
Time (days)
Real Production
Matched Production
1000
CR #2-15 Gas Results
Param eter
Calculated
Value
Confidence (+/-)
r e (ft)
1,181.23
n/a
Gpmax (BCF)
0.14725
n/a
Recovery Factor
92.26%
n/a
0.475
0.032
-5.637
0.077
k (m d)
sf
Summary of Field Cases
Well
Layer h (ft)
Oil
15.34
McBride South Gas
5.00
Water 15.36
re (ft)
2,316
2,308
5,342
0.684
0.052
6.405
0.077 -5.145 0.186
0.043 -6.629 0.524
0.479 -7.269 0.082
10.3
0.3
62.0
72.5
120.0
Oil
10.25 1,206
Carter Ranch Gas
6.15 1,181
Water 11.60 4,223
7.447 1.52% 1.046
0.147 92.26% 0.475
58.329 0.71% 17.687
0.117 -5.856 0.138
0.032 -5.637 0.077
2.932 -4.827 0.558
10.7
2.9
205.2
218.8
665.9
Oil
28.69 1,839
Gas
12.00 1,766
Water 24.80 7,467
23.772 1.00%
3.6
0.207 87.77% 5.566
134.919 0.47% 29.454
0.308 -6.534 0.120
0.785 -1.279 0.953
5.200 -4.081 0.943
103.3
66.8
730.5
900.5
n/a
Boone
Franny
Oil
15.00
551
Gas
4.87
567
Water 9.68 2,279
Np (Mstb) or
Total kh kh Core
Gp (Bscf)
RF
k (md) (+/-) md
sf
(+/-) kh (md-ft) (md-ft) (md-ft), air
25.734 1.98% 1.747
0.125 -5.397 0.189
26.8
40.6
0.312 94.33% 5.075
2.123 9.090 7.313
25.4 247.7
87.123 0.92% 12.727
1.667 -5.886 -0.389
195.5
2.496
n/a
46.044
2.07%
n/a
0.96%
Results
• Generally, consistent with field
observations
Wells acid fractured, so negative skin
expected
Wells drain more than 160 acres
Oil and Gas layers have much lower
permeability than the Water layer
Lab Work Methodology
•CT Scan
• Wettability using standard Amott
wettability test
•Unsteady state relative permeabilities
•Dean Stark analysis
•Correlation between wettability and
relative permeabilities
•Wettability alteration tests
Experimental Procedure
5
1.
Pc
4
2.
3
Water Saturation, Sw
Mary Marie#4968.6/4968.7
•
•
•
•
•
Porosity=9.7%
Absolute Perm =1.32 md
Water index = 0.15
Oil index = 0.11
Amott Wettability index=0.04
Imbibition Relative
Permeability
Mary Marie 4967.7, 4967.8
1
0.8
0.6
0.4
0.2
0
Krw
Kro
0
0.2
0.4
0.6
Sw
0.8
1
Mercury Capillary Pressure
1: Carter 4995.2, 2: Wilkerson 4974.9, 3: Mary Marie 4968.6
K(md),porosity %
Correlations
15
12
9
6
3
0
-0.4
-0.3
-0.2
-0.1
K
Porosity
0
0.1
AI
•As porosity and absolute permeability increase
rock becomes more oil-wet.
Correlations
Krw, end
1
0.8
0.6
0.4
0.2
0
-0.4
-0.3
-0.2
-0.1
0
0.1
Amott Wettability index, AI
•As rock becomes more oil-wet end point
relative permeability increases.
Conclusions
• Reservoir is highly heterogeneous; karst and
fractures affect well performance
• Dual permeability system seems to exist
• Fine matrix rock seems to be better connected to the
high permeability component
• Low recoveries from the coarse matrix and vuggy
rock suggests that these are isolated pores
• Decrease in reservoir pressure and water production
confirms a limited aquifer
Conclusions (contd)
• Oil and gas co-exist in the field
• Electrofacies analysis successfully
differentiate between the oil zones and the
invaded zones
• Wells with high proportions of electrofacies
# 4 & 5 are good producers
• Wells calculating high oil in place from log
data are not necessarily good producers
Conclusions (Contd.)
•
•
•
Study confirms that the field is highly
heterogeneous and wells are in communication
with each other through fractures
It is possible to determine drainage radius from
material balance and use automatic type-curve
matching to determine permeability and skin.
Skin factor results provide a useful tool to
determine completion effectiveness
Conclusions (Contd.)
• Hunton rocks are found to be neutral wet to
oil-wet.
• In rocks studied ,oil wettability increases as
absolute permeability and porosity increase.
• The end point water relative permeability
increases as oil wettability of rocks increase.
Future Work
• Improve reservoir and fluid description for
history matching
• Improve logging analysis
• Include multi-phase flow in rate-time
Analysis
• Investigate tertiary recovery mechanisms to
improve the recovery
• Conduct technical workshops
