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Multi-Rate Multi-Zone Pressure Transient Testing
Mehdi Azari, Ph.D., P.E.Senior Advisor, Reservoir Engineering
Wireline & Perforating ServicesNovember 8, 2007
Well Testing Network, MTM #5Houston, TX, 7-8 November 2007
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MRMZ Test Events
q = 0
PBU
Conduct flow after flow and pressure buildup in a multi-layered reservoir and monitor:• Layer flowrates and pressures downhole to detect flow stabilization• The corresponding fluid density, capacitance, and temperature • Surface flowrate and pressures
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Outlinea. Reservoir, well, and tools review
– Well geometry– Well completions and wellbore data– Reservoir parameters– PVT
b. Design of the pressure transient testing– Estimation of stabilized flow
c. Gradient surveys at the end of the final pressure buildup– Fluid density confirmation– Cross reference check of several log acquisition
d. Stationary pressure transient testing and data quality checke. Pressure and rate data
– Adjusting the stationary data to a common datum– Pressure and rate synchronization
f. Layer rates and SIP plots (Emeraude)– Surface and downhole data comparison and validation
g. Pressure transient testing modeling and analyses (Saphir)
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a. Reservoir, Well, and Tools Review
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The Location of the Two SandsMD, ft
21,360.64
21,422
21,503
21,572
21,348
21,340
21,332
21,036
21,434
TVD, ft
16,033.16
16,045.57
16,103.75
16,223.94
16,055.38
16,168.4
16,039.37
15,820.51
16,112.87
Layer 1
Layer 2
h2 gross = 120.19’ TVD
h1 = 12.42’ TVDh1 = 16’ MD
h2 perf = 138’ MD
Halliburton Gauge Location for Stationary Runs
Location of the Downhole Gauge
h2 gross = 150’ MD
h2 perf = 111.07’ TVD
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b. Pressure Transient Testing Design
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Design Criteria
• Stay above Pb by a safety margin of 200 psi– The lowest designed pressure encountered for the
four sensitivity cases studied is over 2,200 psi higher than the bubble point pressure
– Then use a two-phase flow model of saturated oil with water production
• The pressure drop around wellbore should stay below the cohesive strength of the formation rocks and fines to prevent sanding and formation damage
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Stabilization Time Determination
• The stabilization time for each flow period was assumed as when the designed flowing pressure reached to 2 psi of the final pressure
• A minimum of one hour of undisturbed pressure data for each flow rate change is required
• The stabilization time for the final pressure buildup was defined as when the infinite acting radial flow was established
• Minimum test duration for a homogeneous radial flow profile:
for pressure drawdown and injection
for pressure buildup and falloff
• A minimum of four hours of pressure buildup data is required
μ/khC)s(,t 111903503
2+
>Δ
μ/kheC00,t
s0.1425352 >Δ
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Designed Flowrate Schedule
FlowrateSchedule Duration qo qw qt
hr STB/D STB/D STB/D
q1 @ 10% 2 1,148.2 38 1,174.72
q2 @ 20% 2 2,296.4 76 2,349.43
q3 @ 30% 2 3,444.6 114 3,524.15
q4 @ 40% 2 4,592.8 152 4,698.87
PBU @ 0% 4 0 0 0
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MRMZ Design, History Plot
6700
6750
6800
k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5
0 2 4 6 8 10 12
0
2000
4000
History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])
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MRMZ Design, Log-Log Plot
1E-3 0.01 0.1 11
10
100
k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5
Log-Log plot: dp and dp' [psi] vs dt [hr]
K = 500 md
K = 1000 md
S = 5
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MRMZ Design, Semi-Log Plot
-4 -3 -2 -1
6680
6720
6760
6800
k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5
Semi-Log plot: p [psia] vs Superposition time
K = 1,000 md
K = 500 md
S = 5
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c. Gradient Surveys at the End of the Final Pressure Buildup
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Gradient Plot of P, T, Density, and Capacitance
Pay
zone
Inte
rval
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Density and Deviation Angle Cross Plot
Pay
zone
Inte
rval
Pay
zone
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Static Gradient Surveys
• Between 16,000’-7,000’ TVD the P gradient was 0.301 psi/ft
• The P gradient for the interval of 6,000’-1,000’ TVD was 0.28 psi/ft
• The density of a 31.5 oAPI oil with the given solution gas at the downhole P and T is 43.4734 lb/ft3
• This density is equivalent to 0.697 g/cc or 0.302 psi/ft
• At standard surface conditions the density for the 31.5 oAPI oil is 0.87 g/cc or 0.376 psi/ft
• The P gradient between the PL and the permanent downhole gauge after 5 hrs into the buildup is 0.303 psi/ft.
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Influence of Well Angle and Flowrate on Density and Capacitance Reading
• Temperature is a “Fullbore Sample Tool” and well angle would not influence its data records
• Pressure readings are from the hydrostatic head of the fluids above it. Small amounts of water in the oil stream will not affect the values recorded
• Density, Capacitance, and Spinner readings are location dependent; well angle and fluid type disturb their values
• Stagnant or stratified water may exist on the low side of a highly deviated wellbore (trough) at low flowrates
• If the Density and Capacitance tools are not well centered they could read from the trough at low flowrates
• The accuracy of the Density and Capacitance readings should improve with flowrate in highly deviated wellbores
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e. Pressure and Rate Data
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Synchronized Pressure Data For All the Gauges and the Corresponding Flowrate Values
5600
5800
6000
6200
Shell Gauge
Halliburton Gauge
0 10 20 30 40
0
5000
History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])
Firs
t PL
Sur
vey
Sec
ond
PL
Sur
vey
Third
PL
Sur
vey
Four
th P
L S
urve
y
Fina
l PB
U
Gra
dien
t Sur
vey
Shu
t-in
PL
Sur
vey
Permanent Downhole
Gauge
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The P, ΔP, and q for Both PL and the Downhole Gauges
6000
6100
6200
6300 Halliburton Gauge
Shell Gauge
Pre
ssur
e [p
sia]
85
Pre
ssur
e (d
iffer
ence
) [ps
i]
0
2500
5000
Rat
e [S
TB/D
]
20 24 28 32 36 40
Pressure [psia], Pressure [psi], Liquid Rate [STB/D] vs Time [hr]
Stabilized ΔP
Permanent Downhole
Gauge
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Stabilized Pressure Difference Between the Two Gauges at Different Flowrates
70
75
80
85
90
95
0 1,000 2,000 3,000 4,000 5,000
Stabilized Flow Rate, STB/D
ΔP,
psi
Stabilized DP & q
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f. Layer Rates and SIP Plots (Emeraude)
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Emeraude Plots for the Shut-in Survey with CFS
• Geothermal T Grad. above Top
• Const T profile between Top & Bottom
• Layer 2 does not show any production
• T & q show downward Flow
• Velocity profile shows Layer 2 is taking fluid Layer 1
Layer 2
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Emeraude Plots for the First Flowrate with CFS
• Geothermal T Grad. above Top
• Layer 2 show some production over entire payzone
• T & q show upward Flow
Layer 1
Layer 2
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Emeraude Plots for the Fourth Flowrate with CFS
• Geothermal T Grad. above Top
• Velocity profile shows Layer 2 has higher flowrate
• T & q show upward Flow
Layer 1
Layer 2
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Emeraude Data Used in Saphir Multilayer Analysis
Zone Rates from Production Logging Passes
1st PBU 1st Flow 2nd Flow 3rd Flow 4th
FlowTotal Combined
Flow, STB/DCFS 6 1,581 2,615 3,751 4,611ILS 5 1,525 2,610 3,682 4,533
Stabilized Separator
Flowrate, STB/D0 1,569.2 2,629.2 3,707.68 4,642.1
% Difference Downhole &
Surface+0.8 +0.53 +1.2 -0.7
Spinner type and flowrate validation
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SIP Plot of the Total Liquid Production for CFS
Layer 1 Layer 2
Layer Pressure, psi
PI, RB/D/psi
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g. Pressure Transient Testing Analyses (Saphir)
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1E-4 1E-3 0.01 0.1 11
10
100
Log-Log plot: dp and dp' [psi] vs dt [hr]
Homogeneous Radial Flow Model Influenced by One Nearby No-flow Boundary, Log-Log Plot
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Homogeneous Radial Flow Model Influenced by One Nearby No-Flow Boundary, Simulation Plot
5600
6000
6400
0 10 20 30 40
0
5000
10000
History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])
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Homogeneous Radial Flow Model Influenced by One Nearby No-Flow Boundary, Semi-log and Layer Rates
-5 -4 -3 -2 -1
6100
6200
6300
Semi-Log plot: p [psia] vs Superposition time
0 10 20 30 40
0
4000
8000
12000Layer Rates 1 - (Stab)Layer Rates 2 - (Stab)Layer Rates 3 - (Stab)Layer Rates 4 - (Stab)Layer Rates 5 - (Stab)Layer Rates 6 - (Stab)Layer Rates 7 - (Stab)Layer Rates 8 - (Stab)Layer Rates 9 - (Stab)Layer Rates 10 - (Stab)M1 SandM2 Sand
Layer Rates plot: Downhole Rate [B/D] vs Time [hr]
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Homogeneous Radial Flow Model Influenced by One Nearby No-flow Boundary, First & Final PBU Periods
1E-3 0.01 0.1 1 101
10
100
A14-Entire Data.ks3 - Shell-R-3F (ref)A14-Entire Data.ks3 - Model1-R-3FA14-Entire Data.ks3 - Shell-1st PBU
Compare files: dp and dp' normalized [psi] vs dt
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Example 2
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The Three Layer Example
Shale Shale
MD, ft
17,772
17,800
17,740.76
17,652
17,625
17,598
17,850
17,828
17,910
17,880
TVD, ft
15,918.54
16,011.70
16,059.23
16,147.28
16,036.79
16,099.29
15,940.26
15,896.82
16,081.67
16,123.31 h3 = 60’ MD
h2 perf = 54’ MD
h2 gross = 56’ MD
h1 perf = 52’ MD
h1gross = 54’ MD
Layer 3
h3 = 47.98’ TVD
Layer 2h2 perf = 43.27’ TVDh2 gross = 44.88’ TVD
Layer 1
h1 gross = 43.44’ TVD
h1 perf = 41.83’ TVD
Deviation
Halliburton Gauge Location for Stationary Runs
36.92
36.74
36.3
22 ft
120 ft
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Gradient Plot of Density, Capacitance, and Wellbore Deviation
0
5
10
15
20
25
30
35
40
0 2 4 6 8 10 12 14 16
TVD, 1,000 ft
Incl
inat
ion
Ang
le
0.25
0.35
0.45
0.55
0.65
0.75
0.85
Den
sity
, g/C
C
Inclination Angle
Capacitance for Plotting
Density g/C C
Ocean Floor
Some Water
Temperature Effect
Phase Change
Pay
zone
P
ayzo
ne In
terv
al
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The Synchronized Pressure and Flowrate Data
5600
5800
6000
Pre
ssur
e [p
sia]
0
2500
5000
7500
Rat
e [S
TB/D
]
06:00:00 11:00:00 16:00:00 21:00:00 02:00:0011/24/2006
Pressure [psia], Liquid Rate [STB/D] vs Time [ToD]
Firs
t PL
Sur
vey
Sec
ond
PL
Sur
vey
Third
PL
Sur
vey
Four
th P
L S
urve
y
Fina
l PB
U
Gra
dien
t Sur
vey
Shu
t-in
PL
Sur
vey
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The SIP Plot for the Total Liquid Production Based on Average of the Two Spinners
y = -0.0952x + 6105.9y = -0.5544x + 6537
y = -0.1911x + 6154
5,550
5,650
5,750
5,850
5,950
6,050
6,150
6,250
6,350
6,450
6,550
-1,000 0 1,000 2,000 3,000 4,000 5,000
Downhole Flowrate, RB/D
Stab
ilize
d pr
essu
re, p
si
N SandO1 SandO2+ShaleLinear (O1 Sand)
Linear (N Sand)Linear (O2+Shale)
N:
O1:
O2:
Layer 1
Layer 2
Layer 3
Layer Pressure,
psi
PI, RB/D/psi
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38
The Log-Log Plot of the Data and the Analysis Match for the Final Pressure Buildup
1E-4 1E-3 0.01 0.1 11
10
100
Log-Log plot: dp and dp' [psi] vs dt [hr]
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The Plot of the Entire Pressure Data and the Analysis Match
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History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])
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The Semi-Log Plot and the Layer Flowrate Data Match
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Semi-Log plot: p [psia] vs Superposition time
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Layer Rates plot: Downhole Rate [B/D] vs Time [hr]