exploitation and optimization of reservoir performance in hunton formation, ok review of budget...
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Exploitation and Optimization of Reservoir
Performance in Hunton Formation, OKReview 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
9.42
18.5
0
5
10
15
20
25
30
0 100 200 300 400 500
Time(Days)
GO
R(M
SC
F/S
TB
)
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
0
50
100
150
200
250
0 100 200 300 400 500
Time(Days)
Wilk
ers
on
#1
Oil R
ate
(S
TB
/DA
Y)
0
100
200
300
400
500
Wilk
ers
on
#2
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
0
50
100
150
200
250
0 200 400 600 800
Gas Rate
Oil R
ate
Limited Aquifer
• Reservoir pressure has been declining in the field
0
200
400
600
800
1000
1200
1400
1600
1800
0 100 200 300 400
Time (Days)
Pre
ss
ure
Limited Aquifer
• Water rate is also declining in the field
0.00
200.00
400.00
600.00
800.00
1000.00
1200.00
1400.00
0.00 100.00 200.00 300.00 400.00
Time(days)
Mc B
rid
e N
ort
h W
ate
r
Ra
te (
ST
B/d
ay)
0.00
100.00
200.00
300.00
400.00
500.00
600.00
McB
rid
e S
ou
th
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
0
100
200
300
400
500
600
700
0 100 200 300
Time(days)
Wa
ter
Ra
te (
ST
B/d
ay)
0
10
20
30
40
50
60
70
80
Oil R
ate
(S
TB
/da
y)
Water Rate
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
FOSSILIFEROUS LIMESTONE MACROFACIES
NONPOROUS MUDSTONE FACIES
DOLOMITE FACIES
R. 1 E. R. 2 E. R. 3 E.
T. 1
5 N
. T
. 16
N.
Location of the cored wells
110000 fftt..
5500 fftt..
00 fftt..
WW.. CCaarrnneeyy EExxtt.. SSWWDDWW 1144--1155NN--11EE
MMaarryy MMaarriiee 1111--1155NN--22EE
BBaaiilleeyy 22--66 66--1155NN--33EE
CCaarrnneeyy TToowwnnssiittee 1155--1155NN--33EE
WWOOOODDFFOORRDD UUNNCCOONNFFOORRMMIITTYY
UUPPPPEERR CCOOCCHHRRAANNEE
LLOOWWEERR CCOOCCHHRRAANNEE
• CCLLAARRIITTAA
BBAASSAALL CCLLAARRIITTAA
CO
DE
SYMBOL DESCRIPTION C
OD
E
SYMBOL DESCRIPTION
1 ARGILLACEOUS DOLOMITE 8 CORAL AND DIVERSE FAUNA
2 CRYSTALLINE DOLOMITE 9CORAL AND CRINOID
GRAINSTONE/WACKESTONE
3SMALL BRACHIOPOD
GRAINSTONE/PACKSTONE/WACKESTONE 10 SPARSE FOSSIL WACKESTONE
4 FINE CRINOID GRAINSTONE/PACKSTONE 11 CARBONATE MUDSTONE
5COARSE CRINOID
GRAINSTONE/PACKSTONE 12 FINE TO MEDIUM GRAINSTONE
6
MIXED CRINOID-BRACHIOPOD GRAINSTONE/PACKSTONE/
WACKESTONE 13 SHALE
7 BIG PENTAMERID BRACHIOPOD 14 FINE SANDSTONE
CO
DE
SYMBOL DESCRIPTION CO
DE
SYMBOL DESCRIPTION
1INTERCONNECTED VUGGY POROSITY/
LIMESTONE 7MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITE
2 COARSE MATRIX POROSITY/ LIMESTONE 8 FRACTURE/ DOLOMITE
3 FINE MATRIX POROSITY/ LIMESTONE 9VUGGY OR MOLDIC POROSITY/
DOLOMITIC LIMESTONE
4 FRACTURE/ LIMESTONE 10COARSE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
5 VUGGY OR MOLDIC POROSITY/DOLOMITE 11MEDIUM TO FINE CRYSTALINE POROSITY/
DOLOMITIC LIMESTONE
6COARSE CRYSTALINE POROSITY/
DOLOMITE 12 FRACTURE/ DOLOMITIC LIMESTONE
WWeesstt CCaarrnneeyy HHuunnttoonn FFiieelldd:: LLiitthhoollooggyy && PPoorree TTyyppeess
Limestone
Dolomitic Limestone
Dolomite
10
20
30
40
50
60
70
80
90
LOWER COCHRANE
UPPER COCHRANE
WOODFORD SHALE
CLARITA
BASAL CLARITA
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
Well Name Density Log Neutron Log
Crossplot
((D2+N2)/2)0.5Best Correlation Dominant rock type
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
Correlation Coefficients between core porosity and log porosity
Log Evaluation
• Determination of Sw
Sw = Water Saturation = {(D2+N2)/2}1/2
m = 1.77a = 1 n = 2
Rw= 0.035
• Determination of BVWBVW = Bulk volume water
n
t
wmW R
RaS
1
wSBVW *
Log Evaluation (contd)
• Determination of oil in place
BAF = barrels per acre foot
Sw = water Saturation
Ht = hunton thickness of each wellh = thickness of each data point = porosity
tH
hBAF
wS**7758
Buckles Plot Approach
0.010.020.030.040.050.060.070.080.090.100.110.120.130.140.15
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
rosit
y (
- )
0.0065
BUCKLES PLOT
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
ros
ity
( -
)
Reservoir zones
Transition zones
wa
ter
zo
ne
s
Buckles Plot
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
ros
ity
( -
)
Invaded
zone
Oil zone
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
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 2 3 4 5
Electrofacies
Perc
enta
ge D
istri
butio
n of
Geo
logi
cal f
acie
s
fr pdol
f pdol
cr pdol
vug pdol
fr dol
f dol
cr dol
vug dol
fr ls
f ls
cr ls
vug ls
BUCKLES PLOT for electrofacies #2
0.010.020.030.040.050.060.070.080.090.100.110.120.130.140.15
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
ros
ity
( -
)
0.0065 2
BUCKLES PLOT w ith electrofacies # 3
0.010.020.030.040.050.060.070.080.090.100.110.120.130.140.15
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
ros
ity
( - )
0.0065 3
BUCKLES PLOT with electrofacies #4
0.010.020.030.040.050.060.070.080.090.100.110.120.130.140.15
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Poro
sity
( - )
0.0065 4
BUCKLES PLOT with electrofacies # 5
0.010.020.030.040.050.060.070.080.090.100.110.120.130.140.15
0.000
0.050
0.100
0.150
0.200
0.250
0.300
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Water saturation ( - )
Po
rosit
y (
- )
0.0065 5
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
0
5
10
15
20
25
30
0 5 10 15 20 25 30
Ranking of Kh 1st percentile (decreasing order)
Rank
ing
of w
ater
rate
(dec
reas
ing
orde
r)
Anna 1-11
Bailey 2-6
Boone 1-4
Carney tow nsite
Carter 1-14
Carter ranch
Danny 2-34
Henry
Joe Givens
Mc Bride South
Wilkerson
Williams
cal
Franny
Tow nsend
geneva
Denney 1-31
Garret
Allan Ross
Lew is
Mc Bride North
Schw ake
Wilson
Recovery Factor calculations
• Rfoil =
Boi = Initial oil volume factor
Np = Oil produced
N = oil in place
• Rfgas =
Rsi = Initial solution gas oil ratio
Gp = Gas produced
N
BN oip 100**
100** si
oi
p
RB
N
G
RFoil VS Facies 1+2+3
0
2
4
6
8
10
12
14
16
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Proportion of facies 1+2+3
Rec
over
fact
or (%
)
RFoil vs Facies 4+5
0
2
4
6
8
10
12
14
16
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Proportion of facies 4+5
Reco
very
Fac
tor (
%)
Rf gas Vs facies 1+2+3
0
5
10
15
20
25
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
Proportion of facies 1+2+3
Rec
over
y Fa
ctor
(%)
Rf gas Vs Facies 4+5
0
5
10
15
20
25
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
proportion of facies 4+5
Rec
over
y fa
ctor
(%)
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
Layer 1 0.1Layer 2 0.005Layer 3 100Layer 1 75Layer 2 75Layer 3 75Layer 1 1.60%Layer 2 3%Layer 3 6.50%Layer 1 6Layer 2 15Layer 3 21
Near well 50 ft x 50 ft.Away from well 75 ft x 75 ft.
Height Same as layer thicknessLayer 1 0Layer 2 -3.5Layer 3 -3
Depth 4960 ft.Bubble Point 1600 psia
Vertical Permeability
Horizontal Permeability
Skin
Grid size
Thickness
Porosity
Results
0
0.02
0.04
0.06
0.08
0.1
0.12
0.14
0.16
0.18
0.2
0 50 100 150 200 250 300 350 400 450 500
Time(days)
Oil
Ra
te
Simulation
Field
Results
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0 50 100 150 200 250 300 350 400 450 500
Time(days)
Ga
s R
ate
SimulationField
Results
0
2
4
6
8
10
12
14
0 50 100 150 200 250 300 350 400 450 500
Time(days)
GO
R
Simulation
Field
Results
0
0.2
0.4
0.6
0.8
1
1.2
0 50 100 150 200 250 300 350 400 450 500
Time(days)
Wa
ter
Cu
t
SimulationField
Results
0
200
400
600
800
1000
1200
1400
1600
0 50 100 150 200 250 300 350 400 450 500
Time(days)
BH
P
SimulationSeries2
Results
Initial Value Final ValueLayer 1 0.1 1.8983Layer 2 0.005 0.005Layer 3 100 71.03Layer 1 0.1 0.736Layer 2 0.005 0.005Layer 3 100 64.09Layer 1 75 75Layer 2 75 75Layer 3 75 0.854Layer 1 42.74 4.274Layer 2 200.35 483.76Layer 3 607.75 1605.8Layer 1 96.17 9.617Layer 2 450.8 708.02Layer 3 1367.4 3102.8
Pore Volume (Away Well bore)
Horizontal Permeability
(Near Well bore)Horizontal
Permeability (Away Well bore)
Vertical Permeability
Pore Volume (Near Well bore)
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
0
0.2
0.4
0.6
0.8
1
1.2
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
QDdL
qD
dL
CR #2-15 Water: q vs. t
10
100
1000
1 10 100 1000
Time (days)
Wat
er R
ate
(STB
/day
)
Real Production Matched Production
CR #2-15 Water Results
re (ft) 4,222.65 n/a
Npmax (MSTB) 58.3291 n/a
Recovery Factor 0.71% n/a
k (md) 17.687 2.932
s f -4.827 0.558
Parameter Calculated Value Confidence (+/-)
CR #2-15 Oil: qDdL vs. QDdL
0
0.5
1
1.5
2
2.5
3
3.5
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
QDdL
qD
dL
CR #2-15 Oil: q vs. t
1
10
100
1 10 100 1000
Time (days)
Oil
Rat
e (S
TB/d
ay)
Real Production Matched Production
CR #2-15 Oil Results
re (ft) 1,206.23 n/a
Npmax (MSTB) 7.4469 n/a
Recovery Factor 1.52% n/a
k (md) 1.046 0.117
s f -5.856 0.138
Confidence (+/-)Calculated ValueParameter
CR #2-15 Gas: qDdG vs. QDdG
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
QDdG
qDd
G
CR #2-15 Gas: q vs. t
100
1000
1 10 100 1000
Time (days)
Gas R
ate
(Msc
f/day
)
Real Production Matched Production
CR #2-15 Gas Results
re (ft) 1,181.23 n/a
Gpmax (BCF) 0.14725 n/a
Recovery Factor 92.26% n/a
k (md) 0.475 0.032
s f -5.637 0.077
ParameterCalculated
Value Confidence (+/-)
Summary of Field Cases
Oil 15.34 2,316 25.734 1.98% 1.747 0.125 -5.397 0.189 26.8Gas 5.00 2,308 0.312 94.33% 5.075 2.123 9.090 7.313 25.4Water 15.36 5,342 87.123 0.92% 12.727 1.667 -5.886 -0.389 195.5
Oil 15.00 551 2.496 2.07% 0.684 0.077 -5.145 0.186 10.3Gas 4.87 567 n/a n/a 0.052 0.043 -6.629 0.524 0.3Water 9.68 2,279 46.044 0.96% 6.405 0.479 -7.269 0.082 62.0
Oil 10.25 1,206 7.447 1.52% 1.046 0.117 -5.856 0.138 10.7Gas 6.15 1,181 0.147 92.26% 0.475 0.032 -5.637 0.077 2.9Water 11.60 4,223 58.329 0.71% 17.687 2.932 -4.827 0.558 205.2
Oil 28.69 1,839 23.772 1.00% 3.6 0.308 -6.534 0.120 103.3Gas 12.00 1,766 0.207 87.77% 5.566 0.785 -1.279 0.953 66.8Water 24.80 7,467 134.919 0.47% 29.454 5.200 -4.081 0.943 730.5
McBride South
Boone
Carter Ranch
Franny
40.6
120.0
665.9
n/a
247.7
72.5
218.8
900.5
kh Core (md-ft), airRF k (md) (+/-) md sfWell (+/-) kh (md-ft)
Total kh (md-ft)Layer h (ft) re (ft)
Np (Mstb) or
Gp(Bscf)
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 MethodologyLab 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
1.
2.
3
4
5
Pc
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 Imbibition Relative PermeabilityPermeability
Mary Marie 4967.7, 4967.8
00.20.40.60.8
1
0 0.2 0.4 0.6 0.8 1Sw
Krw
Kro
Mercury Capillary PressureMERCURY CAPILLARY PRESSURE SATURATION
Mercury Pressure: 0 - 60000 psia
1
10
100
1000
10000
100000
0102030405060708090100
Pore Volum e Filled, percent
Inje
ctio
n Pr
essu
re, p
sia
Sample 1 - 4995.20 ft
Sample 2 - 4974.90 ft.
Sample 3 - 4968.60 ft.
Sample ID: All
PTS Labs International, Inc. University of Houston
File No.: 22031
1: Carter 4995.2, 2: Wilkerson 4974.9, 3: Mary Marie 4968.6
Correlations
0369
1215
-0.4 -0.3 -0.2 -0.1 0 0.1
AI
K(m
d),p
oros
ity %
K
Porosity
•As porosity and absolute permeability increase rock becomes more oil-wet.
Correlations
00.20.40.60.8
1
-0.4 -0.3 -0.2 -0.1 0 0.1
Amott Wettability index, AI
Krw
, end
•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