Tulsa 15125

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


• 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


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


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


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


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


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


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


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


Gas

Oil

Water


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

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0.8

0 50 100 150 200 250 300 350 400 450 500

Time(days)

Ga

s R

ate

SimulationField

Results

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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

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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)


CR #2-15 Oil Results

re (ft) 1,206.23 n/a

Npmax (MSTB) 7.4469 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

)


CR #2-15 Gas Results

re (ft) 1,181.23 n/a

Gpmax (BCF) 0.14725 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

Tulsa 15125

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Transcript of Tulsa 15125