Day 3 Am - Well Test Toward Reserve Evaluations
-
Upload
miguel-angel-toala -
Category
Documents
-
view
32 -
download
1
Transcript of Day 3 Am - Well Test Toward Reserve Evaluations
WELL TESTING TOWARD RESERVE EVALUATIONS
DAY 3 MORNING
FORMATION/RESERVOIR/WELL TESTING
• KEY ELEMENTS OF TECHNICAL EVIDENCE
– Reservoir Tank
– Hydrocarbon Column
– Reservoir/Formation Properties
– Fluid Properties
– Effective Drainage Area
– Economic Producibility (flow assurance)
– Recovery Factor
–Wells, Facilities and Operation Conditions
Well Test Toward Reserve evaluation 2
WHY WELL TESTING?
• Flow to the surface:
– Producibility
– Flow Potential (initial pressure, PI)
• Proved volume/Drainage Size
– Minimum connected volume
– Drainage area controlled by one well
– Depletion check
• Overall reservoir quality
– Potential impact of faulting and fractures (recovery factor)
– Reservoir surveillance to check connected reservoir size
• Fluid samples
– Hydrocarbons, water
Well Test Toward Reserve evaluation 3
• In its search for new oil and gas reserves the oil industry moves to more remote areas of the world and to technically challenging areas of deep water.
• To be economically viable, the newly discovered fields must be developed and exploited with very few wells.
• This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well.
• High costs prohibit extensive appraisal activity and drive development decisions based on very few wells.
• These limited reservoir penetrations are often logged extensively using modern formation evaluation tools. However, the acquired data cannot confirm that the wells will drain sufficient reserves.
• Well testing still remains the only method for direct evaluation of reservoir connectivity over large distance from the well.
SPE 102483
TO TEST OR NOT TO TEST: TRUE BELIEVERS
Well Test Toward Reserve evaluation 4
TO TEST OR NOT TO TEST
• ENVIRONMENTAL CONSIDERATION…
– Quick and accurate pressures? reliable?
– Environmentally friendly? no flaring, no spills?
Well Test Toward Reserve evaluation 5
Well Test Toward Reserve Evaluation
• Key Technical Procedures
– Design a well test to understand » To prove it flow to an minimal period of time and monitor a stabilized
flow rate and wellhead pressure
» To have proper sequences to detect reservoir limit, if assumable
» To integrate the geological model into the conceptual reservoir tank and make assumptions (distance from the well to all potential boundaries)
– Potential material balance in reservoir management » To use the same pressure gauge to detect a potential pressure
depletion in the reservoir
» To construct P/Z vs. cum gas plot and map IGIP
Well Test Toward Reserve evaluation 6
Well Test Toward Reserve Evaluation
• Fundamentals
– Reservoir Tank Model:
» Cheese cake, shoebox
– Material Balance
» Record produced volume at surface while watch what pressure loss at the downhole
» All concepts about reservoir limit test, average pool pressure, minimal connected volume, require such material balance assumption
Well Test Toward Reserve evaluation 7
AVERAGE RESERVOIR PRESSURE
• Three Possible Scenarios:
– Well test data show closed-reservoir effects » Only in this scenario, reservoir connected volume can be estimated
– Well test data show no evidence of reservoir limit or boundaries
– Well test data show evidence of some sort of boundary effect, but no conclusively closed-reservoir characteristics » In these two scenarios, you need to assume reservoir boundary dimensions,
and make assessments of the “minimum connected reservoir volume” with the test data
Note: All reservoirs have boundaries; if a well test does not see boundary evidence, one can NOT interpret the current (average) reservoir pressure
Well Test Toward Reserve evaluation 8
RADIUS OF INVESTIGATION
borehole
Pf
r
formation pressure
depth of investigation
Pdd
drawdown pressure
Well Test Toward Reserve evaluation 9
RADIUS OF INVESTIGATION
t
invC
tkr
948
(oilfield unit system)
Input Matrix 1 bbl = 5.6146 cf
net pay = 150 ft
wellbore radius = 0.1 ft
oil flow rate = 177 stb/day
porosity = 0.15
Skin = 0
permeability = 10 md
total compressibility = 0.00000703 1/psi
viscosity = 1 cp
water saturation = 0.2
FVF = 1.2 RB/STB
flowing radius of connected connected
timeinvestigation area volume
hrs ft acres bbl
0.0001 1 0.00 4.4
0.01 10 0.01 438.0
1 100 0.72 43795.2
100 1000 72.16 4379518.2
1000 3163 721.62 43795181.5
10000 10002 7216.21 437951815.4
Well Test Toward Reserve evaluation 10
RADIUS OF INVESTIGATION
g
ets
k
rCt
2948
If we want to know how long it takes to reach the boundary of a fix-sized reservoir and arrives stabilization (pseudo-steady state flow)
gas gravity = 0.6
temperature = 210oF
pressure = 3500 psi
viscosity = 0.02 cp
total compressibility = 0.000247 1/psia
porosity = 0.1
Stablization Time vs Drainage Area
A = 40 A = 640
(acres) (acres)
K ts ts
(md) (hours) (years) (hours) (months) (years)
0.01 25946.53 2.962 415144.56 576.59 47.39093
0.1 2594.65 0.296 41514.46 57.66 4.739093
1 259.47 0.030 4151.45 5.77 0.473909
10 25.95 0.003 415.14 0.58 0.047391
100 2.59 0.000 41.51 0.06 0.004739
1000 0.26 0.000 4.15 0.01 0.000474
0.01
0.1
1
10
100
0 1 10 100 1000 10000 100000 1000000stabilization time (hrs)
reserv
oir p
erm
eabili
ty (
md
)
40 acres
640 acres
Well Test Toward Reserve evaluation 11
RESERVOIR CONNECTED VOLUME
tt
invC
tkt
C
ktr
94844
tSC
hkShrV w
t
winvinv )1(4)1(2
wwoort SCSCCC
Note: the connected volume under investigation during a well test has a lot to do with pore volume decompression as a result of the removal of certain reservoir fluids. Oil reservoirs (saturated or undersaturated) are more difficult than gas reservoirs for reservoir engineers to get right the total compressibility
Well Test Toward Reserve evaluation 12
t
invC
tktr
9484
1.6 km
1.6
km
800 m
640 acres / section
Wabamun Dolomitized Rock Cretaceous Tight Rock
viscosity = 0.02 cp viscosity = 0.017 cp
porosity = 15 % porosity = 8 %
Ct = 0.00025 1/psi Ct = 0.0005 1/psi
distance = 1600 m distance = 800 m
k (md) hours days k (md) hours days
1 19591.6 816.3 0.01 444075.4 18503.1
10 1959.2 81.6 0.05 88815.1 3700.6
50 391.8 16.3 0.1 44407.5 1850.3
100 195.9 8.2 0.5 8881.5 370.1
200 98.0 4.1 1 4440.8 185.0
A Devonian well, Leduc, Wabamun, Nisku, Swanhills, could take days for the pressure perturbation to travel across one section and reach the next spacing unit, through high-k conduit. It means that we could see well rate/pressure interference once the gas is onstream, & exercise gas material balance to estimate IGIP from all single wells, or from the entire pool
If we do not hit any permeable streaks in a Cretaceous formation, a transient flow will last from 1 year to possibly more than 10
years before any attempt to deplete the pressure of any one of the other three wells
within the same section
DRAINAGE AREA & DOWNSPACING
Well Test Toward Reserve evaluation 13
WELL TEST TOWARD RESERVE EVALUATION
• Only multi-well communication tests (interference or pulsing) give the most reliable assessment of effective drainage size.
– Deigned interference test: one active well (injector/producer) emitting pressure pulses to another adjacent monitor well whose downhole gauge receives pressure changes.
– Pulsing Test: a series of pressure up/down sequences from the active well is supposed to be “seen” from the monitor well.
– Hydrodynamics/Production: a new drill in the existing field allows to assess the initial pressure data
producer
monitor
R
Bookable Drainage Area: (depends on the drawdown at the monitor well & reservoir simulation results) • proved: 1.25 A ~ 1.5 A • probable: 2 A
2RπA
Well Test Toward Reserve evaluation 14
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
15:00 04:00 20:15 05:30 02:30 17:30 03:30 13:00
Time of day (hrs)
Tubin
g P
ressure
(psia
)
0
2
4
6
8
10
12
14
16
Gas R
ate
(m
mscf/
d)
Clean-up
Sulphur
Sampling
Initial flow
Attempt
10 mmscf/d
10 mmscf/d
Flow for 6
hrs
14 mmscf/d
Flow for 12 hrs
4083 psi
(6hrs)
4094 psi
(8hrs)
4092
(17hrs) 4076 psi
FIELD EXAMPLE: GAS WELL-1
FIRST PBU SECOND PBU THIRD PBU
Well Test Toward Reserve evaluation 15
FIELD EXAMPLE: GAS WELL-1
Two Lakes BP Two Lakes 3-3 AOF
10-4 10-3 10-2 10-1 100 101 102
10
-510
-410
-310
-2
Delta Pseudo-T (hr)
DP
& D
ER
IVA
TIV
E (
MP
SI2
/CP
/MS
CF
/D)
2006/09/01-0511 : GAS (PSEUDO-PRESSURE)
Linear-Composite 2-Zone
** Simulation Data **
well. storage = 0.0566 BBLS/PSI
Skin(mech) = 26.6
permeability = 5.58 MD
X-Interface(1) = 1310. FEET
Mob.ratio(1) = 0.00579
Stor.ratio(1) = 0.0111
Turbulence = 0. 1/MSCF/D
Initial Press. = 5914.36 PSI
Skin(mech)+DQ = 26.6
Smoothing Coef = 0.,0.
Static-Data and Constants
Volume-Factor = 0.6647 RB/MSCF
Thickness = 90.00 FEET
Viscosity = 0.02771 CP
Total Compress = .9155E-04 1/PSI
Rate = -10650. MSCF/D
Storivity = 0.0004944 FEET/PSI
Diffusivity = N/A FEET^2/HR
Gauge Depth = N/A FEET
Perf. Depth = N/A FEET
Datum Depth = N/A FEET
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
PFA Starts: 2006-09-01 00:03:18
PFA Ends : 2006-09-01 10:12:12
Two Lakes BP Two Lakes 3-3 AOF
0. 100. 200. 300. 400. 500. 600.
-5000.
5000.
Time (hours)
MS
CF
/D
Two Lakes BP Two Lakes 3-3 AOF
0. 100. 200. 300. 400. 500. 600.
0.
1000.
2000.
3000.
4000.
5000.
PS
I
2006/09/01-0511 : GAS (PSEUDO-PRESSURE)
SELECTION OF PRESSURES DATA (PSI)
Gauge-Data ID: GAU001
Analysis-Data ID: GAU001
Total Raw points = 86212
Set 7 rates (max=100000)
Loaded 638 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 2107759.00 BBLS
Static-Data and Constants
Volume-Factor = 0.6647 RB/MSCF
Thickness = 90.00 FEET
Viscosity = 0.02771 CP
Total Compress = .9155E-04 1/PSI
Storivity = 0.0004944 FEET/PSI
Gauge Depth = N/A FEET
Perf. Depth = N/A FEET
Datum Depth = N/A FEET
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
TEST SEQUENCE DERIVATIVE PLOTS FOR ALL 6 TRANSIENTS
Well Test Toward Reserve evaluation 16
FIELD EXAMPLE: GAS WELL-1
TL3-3 All Three
10-4 10-3 10-2 10-1 100
10
-510
-410
-310
-2
Delta Pseudo-T (hr)
DP
& D
ER
IVA
TIV
E (
MP
SI2
/CP
/MS
CF
/D)
106/09/01-0511 : N/A
Linear-Composite 2-Zone
** Simulation Data **
well. storage = 0.0566 BBLS/PSI
Skin(mech) = 26.6
permeability = 5.58 MD
X-Interface(1) = 1310. FEET
Mob.ratio(1) = 0.00579
Stor.ratio(1) = 0.0111
Turbulence = 0. 1/MSCF/D
Initial Press. = 5914.36 PSI
Skin(mech)+DQ = 26.6
Smoothing Coef = 0.,0.
Static-Data and Constants
Volume-Factor = 0.6647 RB/MSCF
Thickness = 90.00 FEET
Viscosity = 0.02771 CP
Total Compress = .9155E-04 1/PSI
Rate = -10650. MSCF/D
Storivity = 0.0004944 FEET/PSI
Diffusivity = N/A FEET^2/HR
Gauge Depth = N/A FEET
Perf. Depth = N/A FEET
Datum Depth = N/A FEET
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
PFA Starts: 2006-09-01 00:03:18
PFA Ends : 2006-09-01 10:12:12
TL3-3 All Three PBU
10-4 10-3 10-2 10-1 100 101 102
10
-510
-410
-310
-2
Delta Pseudo-T (hr)
DP
& D
ER
IVA
TIV
E (
MP
SI2
/CP
/MS
CF
/D)
106/09/03-1658 : N/A
Linear-Composite 2-Zone
** Simulation Data **
well. storage = 0.0566 BBLS/PSI
Skin(mech) = 26.6
permeability = 5.58 MD
X-Interface(1) = 1310. FEET
Mob.ratio(1) = 0.00579
Stor.ratio(1) = 0.0111
Turbulence = 0. 1/MSCF/D
Initial Press. = 5914.36 PSI
Skin(mech)+DQ = 26.6
Smoothing Coef = 0.,0.
Static-Data and Constants
Volume-Factor = 0.6647 RB/MSCF
Thickness = 90.00 FEET
Viscosity = 0.02771 CP
Total Compress = .9155E-04 1/PSI
Rate = 14200. MSCF/D
Storivity = 0.0004944 FEET/PSI
Diffusivity = N/A FEET^2/HR
Gauge Depth = N/A FEET
Perf. Depth = N/A FEET
Datum Depth = N/A FEET
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
PFA Starts: 2006-09-01 00:03:18
PFA Ends : 2006-09-28 19:19:06
THREE DRAWDOWNS THREE BUILDUPS
WE HAVE DEMONSTRATED A GREAT RATE – PRODUCTIVITY BUT WE GOT NO UNAMBIGUOUS ANSWER TO PROVED VOLUME!
Well Test Toward Reserve evaluation 17
GAS WELL-2 FROM THE SAME POOL
0
2
4
6
8
10
12
14
16
18
0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00
Date
Ra
w G
as R
ate
(m
mscfd
)
3h45m3h
3h45m
18.5h
Well Test Toward Reserve evaluation 18
GAS WELL-1 FROM THE SAME POOL
0. 200. 400. 600. 800.
-50
00.
5000.
15000.
Time (hours)
MS
CF
/D
0. 200. 400. 600. 800.
0.
1000.
2000.
3000.
4000.
5000.
PS
I
2006/10/22-1003 : GAS (PSEUDO-PRESSURE)
SELECTION OF PRESSURES DATA (PSI)
Gauge-Data ID: GAU001
Analysis-Data ID: GAU001
Total Raw points = 113615
Set 13 rates (max=100000)
Loaded 4116 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 2848957.00 BBLS
Static-Data and Constants
Volume-Factor = 0.9529 RB/MSCF
Thickness = 98.00 FEET
Viscosity = 0.01900 CP
Total Compress = .7799E-04 1/PSI
Storivity = 0.0004586 FEET/PSI
Gauge Depth = N/A FEET
Perf. Depth = N/A FEET
Datum Depth = N/A FEET
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
Well Test Toward Reserve evaluation 19
10-3 10-2 10-1 100 101
10
-31
0-2
Delta-T (hr)
DP
& D
ER
IVA
TIV
E (
PS
I/S
TB
/D)
PD=1/2
2006/01/27-0200 : OIL
CONNECTED RESERVOIR VOLUME
SPE 102483
Well Test Toward Reserve evaluation 20
• The test sequences that are not suited for evaluation of connected reservoir volume in reservoir appraisal:
– Reservoir limits tests
– Single-PBU tests
• The test sequence tailored for evaluation of reservoir volume is based on material balance considerations:
– Extract a certain volume of fluid from the reservoir
– Measure the change of reservoir pressure resulting from this production
– Given compressibility of rock-fluid system, translate the cumulative volume produced and the pressure change into the reservoir volume
CONSIDER PROVED CONNECTED VOLUME
SPE 102483
Well Test Toward Reserve evaluation 21
• Well Test Objective For Proved Volume:
– Prove that the well is connected to the reservoir volume Vt
• Well Test Design Goals:
– Design a well test that will provide sufficient information to conclude that the connected reservoir volume is indeed at least Vt
– Do not over design the test. Achieve this objective with minimum test duration, fluid production and flaring
• Input To Well Test Design:
– The reservoir volume to be proved by test Vt
– The targeted reservoir pressure change dP
– Expectations of reservoir, rock and fluid properties SPE 102483
WELL TEST DESIGN FOR PROVED VOLUME
Well Test Toward Reserve evaluation 22
• The volume of fluid to be produced during Main Flow Period:
• The duration of Main Flow Period
• The duration of Final PBU
PVCV tt
SPE 102483
wq
Vt
kSH
CVt
o
tt
4
WELL TEST DESIGN FOR PROVED VOLUME
Well Test Toward Reserve evaluation 23
SPE 102483
PTA ANALYSIS FOR PROVED VOLUMES
• Well test design to prove connected volume revolves around the following considerations:
– Produce appropriate volume of fluid
– Quantify the reservoir pressure change caused by this production
– Translate this pressure change into the connected reservoir volume
• Analysis of well test data does not normally follow this sequence directly.
– The reason: there is no simple way to translate the bottom-hole pressure into the average reservoir pressure needed to determine the reservoir volume
Well Test Toward Reserve evaluation 24
PTA ANALYSIS FOR PROVED VOLUMES
• An alternative approach – honor all the relevant test pressure data with a model that simulates the fluid flow in the reservoir during the test.
• The model is calibrated to reproduce:
– The relevant pressure transient behavior during each of the PBU’s
– Simultaneously reproduce the late time pressure data during the PBUs before and after the Main flow period
• This model then correctly reflects the volumetric properties of the part of the reservoir investigated by the test and is used to quantify the connected reservoir volume supported by the test data.
Well Test Toward Reserve evaluation 25
GAS WELL-1 FROM THE SAME POOL
4-9 fi fth buildup derivative
10-3 10-2 10-1 100 101 102
10
510
610
710
8
Delta Pseudo-T (hr)
DP
& D
ER
IVA
TIV
E (
KP
A2
/PA
S/M
3/D
)
106/10/25-1557 : N/A
Smoothing Coef = 0.,0. Static-Data and Constants
Volume-Factor = 5.351 M3/KM3
Thickness = 29.87 METRE
Viscosity = 0.01900 uPS.S
Total Compress = .1131E-04 1/KPA
Rate = 320000. M3/D
Storivity = .2027E-04 METRE/KPA
Diffusivity = N/A METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
PFA Starts: 2006-10-22 16:27:29
PFA Ends : 2006-11-30 09:05:59
Well Test Toward Reserve evaluation 26
GAS WELL-1 FROM THE SAME POOL
4-9 all buildup derivative
10-3 10-2 10-1 100 101 102
10
510
610
7
Delta Pseudo-T (hr)
DP
& D
ER
IVA
TIV
E (
KP
A2
/PA
S/M
3/D
)
UNIT SLP
ENDWBS
STABIL
HALF SLP
FAULT
2006/10/25-1557 : GAS (PSEUDO-PRESSURE)
well. storage = 0.00355 M3/KPA
Skin(mech) = -3.83
permeability = 0.970 MD
Perm-Thickness = 29.0 MD-METRE
Half.Length = 60.5 METRE
Turbulence = 0. 1/M3/D
P-extrap. = 38092.6 KPA
+x Distance = 115. METRE
R(inv) at 0.7890 hr = 25.1 METRE
Smoothing Coef = 0.,0.
Static-Data and Constants
Volume-Factor = 5.351 M3/KM3
Thickness = 29.87 METRE
Viscosity = 0.01900 uPS.S
Total Compress = .1131E-04 1/KPA
Rate = 320000. M3/D
Storivity = .2027E-04 METRE/KPA
Diffusivity = 267.4 METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU001
Based on Gauge ID: GAU001
PFA Starts: 2006-10-22 16:27:29
PFA Ends : 2006-11-30 09:05:59
Well Test Toward Reserve evaluation 27
GAS MATERIAL BALANCE USING WELL TEST
• Only for gas reservoirs/wells, days of flow tests can be analyzed for “minimum volume”
• Record BHP pressure data when at least days of flow production are carried (single downhole gauge minimizes pressure reading errors)
• Compare the final buildup pressure with the initial pressure, construct P/Z vs. cum gas volume plot, estimate IGIP
• Caution: – Low perm reservoirs do not work
– Hours of flow do not work
– Low rate flows do not work
Pi
cleanup main flow
main buildup
Pave
Gp
Pi
cleanup main flow
main buildup
Pave
Gp
P/Z
IGIP gas volume Gp
Well Test Toward Reserve evaluation 28
• Evaluation of connected reservoir volume through the use of well testing requires an appropriately designed well test. The volume of fluid production during the test must be correlated with the reservoir volume targeted to be proved by the test.
• As a minimum, the test sequence must include two pressure buildup periods immediately before and after the main production period. These two pressure buildups provide the information that reflects the volume of the part of the reservoir investigated by the test.
• The PBU immediately following the main production period should be the longest of the two PBUs. It provides main data for pressure transient analysis.
WELL TEST FOR PROVED VOLUME
Well Test Toward Reserve evaluation 29
• The reservoir volume proven by the test is not a uniquely defined characteristic. The main uncertainty is associated with total compressibility. Non-uniqueness of test interpretation is also a contributing factor to this uncertainty.
• Evaluation of connected reservoir volume through well testing is most suitable for high quality reservoirs where materially significant reservoir volume may be proved in a test of reasonable duration.
• The use of well testing for evaluation of connected volume and reservoir connectivity discussed here is limited to single phase reservoir conditions.
• An appropriately designed and executed well test that confirms good reservoir connectivity may potentially decrease the number of wells required for appraising the field and reduce the overall cost of the reservoir appraisal program.
WELL TEST FOR PROVED VOLUME
Well Test Toward Reserve evaluation 30
• Non-uniqueness of PTA interpretations
– Turn it into an iteration procedure with geologic/geophysical pictures
– Minimize estimated parameters
– Create one major flow/buildup event
• Key assumptions
– Reservoir models: Shoe-box or cheese cake
– Total compressibility
• Other Important Considerations
– One gauge at the entire test event close to perf-depth (surface readout possible)
– Softwares with good features (Saphir, PanSystem, PIE)
WELL TEST CHALLENGES
Well Test Toward Reserve evaluation 31
virgin pressure
p1
p2
p3
p5
p4
TRANSIENT FLOW & MATERIAL BALANCE
Low permeability prohibits pressure perturbation waves to travel fast enough to influence the other wells
Well Test Toward Reserve evaluation 32
Wolverine Structure Well Testing to Map IGIP
WELL TEST TOWARD RESERVE EVALUATION Devon Wolverine d-66-D Production History
100
1000
10000
9-Nov-04 17-Feb-05 28-May-05 5-Sep-05 14-Dec-05 24-Mar-06 2-Jul-06 10-Oct-06
Cum Gas (mmcf)
Raw
Gas R
ate
(m
cfd
)
0
100
200
300
400
500
600
700
Cum
Gas (
mm
cf)
Well Test Toward Reserve evaluation 34
10-3 10-2 10-1 100 101 102 103 104
10
510
610
710
8
Delta-T (hr)
DP
& D
ER
IVA
TIV
E (
KP
A2
/PA
S/M
3/D
)
2000/11/18-0905 : GAS (PSEUDO-P with Mat.Bal.)
Smoothing Coef = 0.,0. Static-Data and Constants
Volume-Factor = 4.998 M3/KM3
Thickness = 28.40 METRE
Viscosity = 0.02040 uPS.S
Total Compress = .1940E-04 1/KPA
Rate = 84970. M3/D
Storivity = .3306E-04 METRE/KPA
Diffusivity = N/A METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU003
PFA Starts: 2000-11-12 16:55:00
PFA Ends : 2004-05-11 08:00:00
-9000. -8500. -8000. -7500.
-20
000
.40
000
.80
000
.
Time (hours)
M3
/D
-9000. -8500. -8000. -7500.
-10
000
.10
000
.20
000
.30
000
.40
000
.
KP
A
2000/11/18-0905 : GAS (PSEUDO-P with Mat.Bal.)
SELECTION OF PRESSURES DATA (KPA)
Gauge-Data ID: GAU003
Analysis-Data ID: GAU002
Total Raw points = 130090
Set 15 rates (max=100000)
Loaded 494 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 7887224.00 M3
Static-Data and Constants
Volume-Factor = 4.998 M3/KM3
Thickness = 28.40 METRE
Viscosity = 0.02040 uPS.S
Total Compress = .1940E-04 1/KPA
Storivity = .3306E-04 METRE/KPA
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU003
A 2001 PBU test showed 6-7 log cycles: very low permeability
The current PBU test may not able to answer the drainage size question
WELL TEST TOWARD RESERVE EVALUATION
Well Test Toward Reserve evaluation 35
-200. 0. 200. 400. 600.
-10000.
10000.
30000.
Time (hours)
M3
/D
-200. 0. 200. 400. 600.
-5000.
5000.
15000
.25
000
.
KP
A
2006/04/08-1300 : GAS (PSEUDO-P with Mat.Bal.)
SELECTION OF PRESSURES DATA (KPA)
Gauge-Data ID: GAU002
Analysis-Data ID: GAU002
Total Raw points = 83623
Set 5 rates (max=100000)
Loaded 204 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 22925526.0 M3
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Storivity = .1374E-04 METRE/KPA
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
-200. 0. 200. 400. 600.
-10
000
.10
000
.30
000
.
Time (hours)
M3
/D
-200. 0. 200. 400. 600.
50
00.
10
000
.15
000
.20
000
.25
000
.
KP
A
2006/04/08-1300 : GAS (PSEUDO-P with Mat.Bal.)
SELECTION OF PRESSURES DATA (KPA)
Gauge-Data ID: GAU002
Analysis-Data ID: GAU002
Total Raw points = 83623
Set 5 rates (max=100000)
Loaded 204 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 22925526.0 M3
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Storivity = .1374E-04 METRE/KPA
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
WELL TEST TOWARD RESERVE EVALUATION
Well Test Toward Reserve evaluation 36
WELL TEST TOWARD RESERVE EVALUATION
TRSC (South of the River) Cum Production
0
5
10
15
20
25
30
35
40 0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
105
110
115
120
125
130
135
140
145
150
Bcf
Freq
uen
cy
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Ba
se
Up
Mo
de
l
P50 ~12 Bcf
Well Test Toward Reserve evaluation 37
WELL TEST TOWARD RESERVE EVALUATION
TRSC Initial Rate South of the River (<= 2160 Hrs)
0
2
4
6
8
10
12
14
16
18
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
34
36
38
40
42
44
46
48
50
52
54
56
58
60
Mo
re
MMcf/day
Fre
qu
en
cy
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100% B
ase
Up
Model
P 50 ~ 14 MMcf/day
Well Test Toward Reserve evaluation 38
WELL TEST TOWARD RESERVE EVALUATION
• four scenarios: OGIP RR RF
– Scenario 1: re-drill d-66-D, 15 bcf 10 bcf 68%
– Scenario 2: infill well 22.5 bcf 14 bcf 67%
– Scenario 3: south well 31 bcf 19 bcf 61%
– Scenario 4: north well 22 bcf 12 bcf 56%
• same reservoir parameters assumed; volumetric OGIP/IP rates from analogies
• key sensitivity analysis:
– k, IP rate, HZ length, recovery factor
• simulation results:
– RF ranges from 30% ~ 60%
– Controlling factor is permeability
– RF approaches 60% when k > 5 md
– RF stays in lower 30% if k < 1 md
– Horizontal wellbore (up to 1200 m) does help RF
– Real challenge: HZ wellbore to intersect frac swarms (to increase overall k)
Well Test Toward Reserve evaluation 39
WELL TEST TOWARD RESERVE EVALUATION
K=0.1 md +/- 1000 m HZ OGIP=30 bcf RF=56% OGIP=14 bcf RF=43 % OGIP=10 bcf RF=35%
-2000
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
22000
24000
26000
28000
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Date
W ell 1 "wel1"
W olverine d-66-D redrill
W ell Data For W ell 1 "wel1"
Well Test Toward Reserve evaluation 40
WELL TEST TOWARD RESERVE EVALUATION
K=0.1 md +/- 1000 m HZ OGIP=30 bcf RF=56% OGIP=14 bcf RF=43 % OGIP=10 bcf RF=35%
-2000
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
22000
24000
26000
28000
0 2000 4000 6000 8000 10000 12000 14000 16000 18000
Cumulative Production, MMscf
W ell 1 "wel1"
W olverine d-66-D redrill
W ell Data For W ell 1 "wel1"
Well Test Toward Reserve evaluation 41
WELL TEST TOWARD RESERVE EVALUATION
K=0.1 md +/- 1000 m HZ OGIP=30 bcf RF=56% OGIP=14 bcf RF=43 % OGIP=10 bcf RF=35%
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Date
W ell 1 "wel1"
W olverine d-66-D redrill
W ell Data For W ell 1 "wel1"
Well Test Toward Reserve evaluation 42
WELL TEST TOWARD RESERVE EVALUATION
K=0.1 md +/- 1000 m HZ OGIP=30 bcf RF=56% OGIP=14 bcf RF=43 % OGIP=10 bcf RF=35%
2000
2200
2400
2600
2800
3000
3200
3400
3600
3800
4000
4200
4400
4600
4800
0 2000 4000 6000 8000 10000 12000 14000 16000 18000
Cumulative Production, MMscf
Field Avg. Pressure/Z W ell BHP/Z
W olverine d-66-D redrill
W ell Data For W ell 1 "wel1"
Well Test Toward Reserve evaluation 43
RATE VS. RESERVE
q1
G1
q2
G2
q3
G3
Although the entry rates for the three wells
are the same, the performances indicate
completely different reserves:
q1 = q2 = q3
G1 < G2 < G3
High entry rate wells may not be deliver
good reserves
Well Test Toward Reserve evaluation 44
RATE VS. RESERVE
q1
G1
q2
G2
q3
G3
Although the entry rates for the three wells
are different, the decline pattern and rate
may lead to the same reserve delivery:
G1 = G2 = G3
q1 < q2 < q3
Low entry rate wells may not be a bad well
and may deliver good reserves
3%
36% 70%
Well Test Toward Reserve evaluation 45
WELL TEST TOWARD RESERVE EVALUATION
• Wolverine d-66-D Input Parameters
Initial Reservoir Pressure Pi= 33,289.7 kPaa
Reservoir Temperature T=100 oC
Pay Thickness H=15 metres
Porosity PHI=5%
Water Saturation Sw=25%
Z-factor Z=0.985
Production Time = 20 month = 14,400 hrs
Raw Gas Rate = 1.3 mmcfd = 38 e3m
3d
Skin Factor = -5 Perm = 0.16 md
Well Test Toward Reserve evaluation 46
WELL TEST TOWARD RESERVE EVALUATION
• SCENARIO 1
13.3 bcf
259 ha
Scenario 1 640 acres
(1 DSU)
baseline
1726 x 2 metres
750 m
Buildup Time
3 wks 2 months 6 months 12 months 3 years
(500 hrs) (1440 hrs) (4320 hrs) (8760 hrs) (26280 hrs)
Average Reservoir Pressure 30343.9 30343.9 30343.9 30343.9 30343.9
Gauge Pressure at the end of buildup 23922 25774 27678 28776 30049
Well Test Toward Reserve evaluation 47
WELL TEST TOWARD RESERVE EVALUATION
• SCENARIO 2
30 bcf
Scenario 2 582.4 ha
1440 acres
3895 x 2 metres
750 m
Buildup Time
3 wks 2 months 6 months 12 months 3 years
(500 hrs) (1440 hrs) (4320 hrs) (8760 hrs) (26280 hrs)
Average Reservoir Pressure 31956.4 31956.4 31956.4 31956.4 31956.4
Gauge Pressure at the end of buildup 23789 25640 27536 28624 30162
Well Test Toward Reserve evaluation 48
WELL TEST TOWARD RESERVE EVALUATION
• SCENARIO 3
Scenario 3 60 bcf
2880 acres
1164.9 ha
7766 x 2 metres
750 m
150 m
600 m
Buildup Time
3 wks 2 months 6 months 12 months 3 years
(500 hrs) (1440 hrs) (4320 hrs) (8760 hrs) (26280 hrs)
Average Reservoir Pressure 32615.2 32615.2 32615.2 32615.2 32615.2
Gauge Pressure at the end of buildup 23764 25617 27514 28605 30148
Well Test Toward Reserve evaluation 49
WELL TEST TOWARD RESERVE EVALUATION
• MODERN PRESSURE GAUGE ACCURACY AND RESOLUTION
– Accuracy: » Strain: +/- 0.1% of Full Scale
» Quartz: +/1 (2 psi + 0.01% of reading)
– Resolution (Precision): » Strain: 1~ 5 psi (practically, not gauge calibration/specs)
» Quartz: 0.1 ~ 0.5 psi (practically, not gauge calibration/specs)
– Repeatability:
What we need to see in a buildup test is to see a meaningful change of no less
than 100 kPa or 15 psi, for estimating the average reservoir pressure of the pool in this size
Well Test Toward Reserve evaluation 50
WELL TEST TOWARD RESERVE EVALUATION
-15000. -10000. -5000. 0.
-10
000
.10
000
.30
000
.
Time (hours)
M3
/D
-15000. -10000. -5000. 0.
0.
50
00.
10
000
.15
000
.20
000
.
KP
A
2006/04/04-1739 : GAS (PSEUDO-P with Mat.Bal.)
SELECTION OF PRESSURES DATA (KPA)
Gauge-Data ID: GAU002
Analysis-Data ID: GAU002
Total Raw points = 83623
Set 5 rates (max=100000)
Loaded 204 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 22925526.0 M3
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Storivity = .1374E-04 METRE/KPA
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
Well Test Toward Reserve evaluation 51
WELL TEST TOWARD RESERVE EVALUATION
-1000. -500. 0. 500.
-10000.
10000.
30000.
Time (hours)
M3
/D
-1000. -500. 0. 500.
0.
10000.
20000.
30000.
KP
A
2006/04/04-1739 : GAS (PSEUDO-P with Mat.Bal.)
SELECTION OF PRESSURES DATA (KPA)
Gauge-Data ID: GAU002
Analysis-Data ID: GAU002
Total Raw points = 83623
Set 5 rates (max=100000)
Loaded 204 points (max=100000)
Pressure Select Mode: MANUAL
Rates Cum. Prod.= 22925526.0 M3
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Storivity = .1374E-04 METRE/KPA
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
Well Test Toward Reserve evaluation 52
0. 2000. 4000. 6000. 8000.
0.1
0E
+1
40.1
5E
+1
40.2
0E
+1
40.2
5E
+1
40.3
0E
+1
4
Superposition(T)
M(P
) K
PA
2/P
AS
480. HR 12. HR 0.30 HR 0.0071 HR 480. HR 12. HR 0.30 HR 0.0071 HR
SLOPE
2006/04/08-1300 : GAS (PSEUDO-P with Mat.Bal.)
slope of the line = -.12E+11 KPA2/PAS/cycle
extrapolated pressure = 31304.8 KPA
extrapolated pressure = .561E+14 KPA2/PAS
R(inv) at 449.8 hr = 160. METRE
R(inv) at 564.9 hr = 179. METRE
prod. time=15720. hr at rate=35000.00 M3/D
Skin(mech) = -5.63
permeability = 0.0884 MD
Perm-Thickness = 1.33 MD-METRE
Turbulence = 0. 1/M3/D
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Rate = 35000. M3/D
Storivity = .1374E-04 METRE/KPA
Diffusivity = 19.70 METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
PFA Starts: 2004-08-12 17:39:57
PFA Ends : 2006-05-03 12:23:00
10-4 10-3 10-2 10-1 100 101 102
10
410
510
610
710
8
Delta-T (hr)
DP
& D
ER
IVA
TIV
E (
KP
A2
/PA
S/M
3/D
)
PD=1/2
2006/04/08-1300 : GAS (PSEUDO-P with Mat.Bal.)
Infinite Conductivity Vertical Fracture
** Simulation Data **
well. storage = 0.00580 M3/KPA
permeability = 0.0700 MD
Half.Length = 80.0 METRE
fracture-skin = 0.00500
Perm-Thickness = 1.05 MD-METRE
Initial Press. = 33289.7 KPA
Smoothing Coef = 0.,0.
Static-Data and Constants
Volume-Factor = 7.404 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.01740 uPS.S
Total Compress = .1832E-04 1/KPA
Rate = 35000. M3/D
Storivity = .1374E-04 METRE/KPA
Diffusivity = 15.60 METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU002
PFA Starts: 2004-08-12 17:39:57
PFA Ends : 2006-05-03 12:23:00
WELL TEST TOWARD RESERVE EVALUATION
Well Test Toward Reserve evaluation 53
10-4 10-3 10-2 10-1 100 101 102 103 104 105
10
410
510
610
710
8
Delta-T (hr)
DP
& D
ER
IVA
TIV
E (
KP
A2
/PA
S/M
3/D
)
2000/11/18-0905 : GAS (PSEUDO-P with Mat.Bal.)
Smoothing Coef = 0.,0. Static-Data and Constants
Volume-Factor = 4.998 M3/KM3
Thickness = 15.00 METRE
Viscosity = 0.02040 uPS.S
Total Compress = .1830E-04 1/KPA
Rate = 84970. M3/D
Storivity = .1373E-04 METRE/KPA
Diffusivity = N/A METRE^2/HR
Gauge Depth = N/A METRE
Perf. Depth = N/A METRE
Datum Depth = N/A METRE
Analysis-Data ID: GAU002
Based on Gauge ID: GAU003
PFA Starts: 2000-01-15 13:13:13
PFA Ends : 2004-05-11 08:00:00
2006 buildup
2004 buildup
A 2006 well shut-in for pressure buildup was done to estimate the current average pressure level for OGIP estimation. The data was not conclusive, but gave some indication
WELL TEST TOWARD RESERVE EVALUATION
Well Test Toward Reserve evaluation 54
Wolverine d-66-D Material Balance Reserve Estimate
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
Cum (bcf)
P/Z
likely estimate
lower P*
higher P*
final shut-in
min reservepotentiallikely estimate
maxreservepotentialfinal shut-in
the final shut-in pressure of 22,900 kPa
after 3-wk PBU gives 3 bcf reserves
extrapolated pressures
likely reserves
15 bcf
min 11 bcf
max 21 bcf
8,500 kpa line pressure
It appears that d-66-D/b75-D, after on production for 18 months, may be seeing a larger volume
WELL TEST TOWARD RESERVE EVALUATION
Well Test Toward Reserve evaluation 55
Class Exercise: Design A Well Test for Certain Volume Check