Evaluating Shale Gas Wells Using
Rate and Flowing Surface Pressure Data
February 6, 2013
[email protected]
214-9695401
OUTLINE
1. Shale Gas Production - What made it possible?
2. Flowing Material Balance - Estimating Contacted OGIP
3. PI Method - Estimating Recoverable Gas
Page 2
Shale Gas Production
What Made It Possible?
Flow Rate  Permeability x Area / Distance
So which of these three parameters
did the industry work on?
Tight Gas Reservoir
Conventional Reservoir
Good K
Small Area = rw h
Large Distance
Radial Flow
Low K
Increased Area = 2Lh
Large Distance
Linear Transient Flow
How about ALL THREE!
Shale Gas Horiz Multi-Stage Frac
Enhanced K in SRV
Significantly Increased Area
Significantly Decreased Distance
Complex Flow with Early BDF
SPE 7490
SPE 136696 and 145080
Page 3
Flowing Material Balance
Page 4
Flowing Material Balance (FMB)
WHAT IS IT?
•
Dynamic (performance-based) estimate of contacted OGIP
HOW DO WE DO IT?
•
Estimate FBHP from rate and flowing tubing pressure
•
Estimate SIBHP from FBHP, rate and productivity index (PI)
•
Perform gas material balance
DOES IT WORK?
•
Have seen very “linear” FMB trends across numerous wells with
as little as 3 months of data for the Haynesville (little longer for the
shallower plays)
•
Estimated connected OGIP volumes appear reasonable
•
Estimated RF’s are typically 50-60% of contacted OGIP
Page 5
FMB – What is it?
18
8000
16
7000
14
6000
12
5000
10
SIBHP estimated from
• Rate
4000
8
• FTP, FBHP
3000
6
• PI
4
2000
P/Z
FBHP
1000
2
Rate
0
0
0
1
2
Cumulative Gas (BSCF)
Page 6
3
4
Gas Rate (MMSCFD)
P/Z and FBHP (PSIA)
FMB Illustration
9000
Stress Dependent K
•
FMB analysis requires a PI model
•
A stress-dependent decline in K is used for shale wells
•
Stress dependency must be determined independent of
FMB analysis – need SIBHP from subject well or analog
Stress Dependent Permeability Relationship
1.0000
Initial BHP =11,000 psia
K/Ki = 1.0
Yilmaz and Nur
K/Ki
0.1000
0.0100
0.0010
0
2,000
4,000
6,000
BHP (PSIA)
Page 7
8,000
10,000
12,000
Rate and FTP vs Time – Example 1
Historical Gas Rate and FTP
12000
1000
Rate is constrained
by high FTP
Good pressure build-up indicating
SRV effective K is 0.1 md (not
nanodarcies!)
10000
Gas Rate (MMSCFD)
6000
4000
10
2000
Gas Rate
FTP
0
1
0
2
4
6
8
10
12
14
16
Months
Page 8
18
20
22
24
26
28
30
FTP (PSIA)
8000
100
FMB Method – Example 1
Flowing Material Balance Analysis
9000
0.45
P/z Ramagost
SIBHP survey confirmed
OGIP trend line from FMB
8000
0.40
P/z Ramagost - Calculated from PI
Stress Normalized PI
0.35
Plotted points are NOT dependent on
OGIP. They point to OGIP!
6000
0.30
Solution algorithm is iterative.
5000
0.25
4000
0.20
3000
0.15
OGIP = 15 BSCF
Normalized PI data
plot on straight line
2000
0.10
1000
0.05
0
0.00
0
2
4
6
8
10
12
Cumulative Gas (BSCF)
Page 9
14
16
18
20
Normalized PI
P/Z (psia) with Ramagost Correction
7000
Rate and FTP vs Time – Example 2
Historical Gas Rate and FTP
12000
1000
10000
Early rate profile very
“flat” due to decline in
FTP from opening choke
8000
6000
10
4000
2000
Gas Rate
FTP
1
0
0
2
4
6
8
10
Months
Page 10
12
14
16
18
20
FTP (PSIA)
Gas Rate (MMSCFD)
100
FMB Method – Example 2
Flowing Material Balance Analysis
0.09
9000
P/z Ramagost
Straight line (BDF) reached at Gp
< 0.5 BSCF (< 3 mths)
0.08
P/z Ramagost - Calculated from PI
Stress Normalized PI
7000
0.07
6000
0.06
5000
0.05
4000
0.04
3000
0.03
OGIP = 18 BSCF
2000
0.02
1000
0.01
0.00
0
0
2
4
6
8
10
12
Cumulative Gas (BSCF)
Page 11
14
16
18
20
Normalized PI
P/Z (psia) with Ramagost Correction
8000
Rate and Pressure – Example 3
Historical Gas Rate and FTP
12000
1000
10000
Profile impacted by multiple large choke changes.
100
8000
6000
10
4000
2000
Rate is increasing or flat
Gas Rate
FTP
1
0
0
2
4
6
8
10
12
14
16
Months
Page 12
18
20
22
24
26
28
30
FTP (PSIA)
Gas Rate (MMSCFD)
Would the method still work?
FMB Method – Example 3
Flowing Material Balance Analysis
9000
0.90
P/z Ramagost
8000
0.80
P/z Ramagost - Calculated from PI
Stress Normalized PI
0.70
Good straight line trend despite
multiple choke changes
6000
0.60
5000
0.50
4000
0.40
Workover resulted in
contribution from previously
“plugged” perforations
3000
0.30
OGIP = 19 BSCF
2000
0.20
1000
0.10
0
0.00
0
5
10
15
Cumulative Gas (BSCF)
Page 13
20
25
Normalized PI
P/Z (psia) with Ramagost Correction
7000
FMB Method – Multiple Examples
MULTIPLE WELLS
FMB Analysis
9000
P/Z (psia) with Ramagost Correction
8000
7000
6000
5000
4000
3000
2000
0
1
2
3
4
Cumulative Gas (BSCF)
Page 14
5
6
7
8
Observations/Questions?
• FMB method seems to work across multiple shale plays
including Haynesville, Eagleford, Niobrara and Marcellus
• Is it a surprise the method still works with shallow, normally
pressured shale plays?
• FMB trends have thus far remained straight suggesting

GIIP is not increasing
 Negligible contribution from outside of SRV (so far)
 Free GIIP appears to be key, especially in early years which dominate
recovery and NPV
• Will the lines stay straight?
• Will there be material contribution from outside SRV?
Page 15
PI Method
Page 16
The Motivation
•
•
•
•
Shale gas wells are often rate-constrained during the early
years of production
Production rates can sometimes be near constant or even
increasing as a result of choke changes
Decline curve analysis methods that rely only on rate data
are not reliable in such circumstances
Thousands of US shale wells need to be analyzed each
year. We wanted a simple forecast method that gave reliable
estimates.
 Was there a straight line out there somewhere?
Page 17
The Search
Page 18
STRAIGHT LINES
Sheep, Engineers and Pseudo-Scientist’s
“Lets apply a little science to
understand why the line is straight
so we can more confidently predict
the future and avoid any cliffs”
Scott Rees – NSAI CEO, March 2011
Page 19
The PI Method
Why?
•
Restricted rate and variable choke settings prohibit DCA
•
Productivity Index (PI) trends are predictable
•
Can address future operations (e.g. line pressure impact)
•
Diagnostic of problems/issues (e.g. offset interference, well damage etc)
•
EUR can be observed directly from the plot
How?
•
Convert FTP to FBHP using tubing flow equation
•
Calculate PVT properties including Pseudo Pressure m(p)
•
Calculate PI as follows
PI = Qgas / [m(pi) – m(pwf)]
•
Plot Log(PI) versus Gp
Page 20
PI Method – Example 1
Historical Gas Rate and FTP
1000
12000
10000
Rate restricted by high FTP
8000
6000
10
FTP (PSIA)
Gas Rate (MMSCFD)
100
4000
2000
Gas Rate
FTP
1
PI versus Cumulative Production
0
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
0.10000
30
Months
Transient increase in
PI following shut-in
PI (MMSCFD / (10^6 psia^2/cp)
0.01000
0.00100
EUR can be “seen” from plot
0.00010
0.00001
Page 21
0
1
2
3
4
5
Cumulative Gas (BSCF)
6
7
8
PI Method – Example 2
Historical Gas Rate and FTP
1000
12000
10000
8000
6000
10
FTP (PSIA)
Gas Rate (MMSCFD)
100
4000
2000
Gas Rate
FTP
PI versus Cumulative Production
1
0.10000
0
0
2
4
6
8
10
12
14
16
18
20
Months
Good straight line trend reached
after < 0.5 BCF (< 3 mths)
PI (MMSCFD / (10^6 psia^2/cp)
0.01000
0.00100
0.00010
0.00001
0
Page 22
1
2
3
Cumulative Gas (BSCF)
4
5
6
PI Method – Example 3
Historical Gas Rate and FTP
1000
12000
10000
Profile impacted by
large choke changes
8000
6000
10
FTP (PSIA)
Gas Rate (MMSCFD)
100
4000
2000
Rate increasing!
Gas Rate
PI versus Cumulative Production
FTP
1
0.10000
0
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
Months
Good straight line trend despite
multiple choke changes
PI (MMSCFD / (10^6 psia^2/cp)
0.01000
0.00100
0.00010
0.00001
0
Page 23
2
4
6
Cumulative Gas (BSCF)
8
10
12
PI Method – Multiple Examples
MULTIPLE WELLS
PI versus Cumulative Production
0.10000
PI (MMSCFD / (10^6 psia^2/cp)
0.01000
0.00100
0.00010
0.00001
0
1
2
3
4
Cumulative Gas (BSCF)
Page 24
5
6
7
8
Rate vs Time Forecast – Example 3
FBHP forecast
Min. FBHP (line conditions)
100.00
0.10000
10.00
0.01000
Gas Rate (MMSCFD)
1.00000
Gas forecast
1.00
0.00100
PI forecast
0.10
0.00010
0.01
Page 25
0.00001
0
10
20
30
40
Qgas (history)
50
60
PI (history)
70
PI(forecast)
80
90
100
PI (MMSCFD /10^6 psia^2 /cp)
Historical and Forecast Gas Rate and PI
1000.00
Reservoir Simulation
Page 26
RESERVOIR SIMULATION
K Layout and BHP distribution
DEHAN15
DEHAN15
DEHAN15
Page 27
RESERVOIR SIMULATION
BHP Match – Haynesville Well
HAYNESVILLE WELL
ECLIPSE Simulation History Match
12,000
11,000
BHP (psia) and G as Rate (Mcfd)
10,000
9,000
8,000
7,000
Gas Rate
6,000
BHP - Actual
BHP - Simulated (NSAI)
5,000
Feb-10
Page 28
Mar-10
Apr-10
May-10
Jun-10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
RESERVOIR SIMULATION
Pressure Build-up Match – Haynesville Well
BRIARWOOD 35-1
ECLIPSE MATCH OF SIBHP SURVEY
10,200
10,100
10,000
SIBHP (psia)
9,900
9,800
9,700
9,600
Actual
9,500
Simulated
9,400
9,300
1.0
10.0
Shut-in Time (days)
Page 29
100.0
RESERVOIR SIMULATION
Rate Forecast – Haynesville Well
Gas Rate and Cumulative Gas
ECLIPSE versus PI Method
10
10
9
8
7
6
5
4
0.1
ECLIPSE and PI model
are in good agreement.
3
Actual
2
ECLIPSE
1
PI Model
0.01
0
J-08 J-10 J-12 J-14 J-16 J-18 J-20 J-22 J-24 J-26 J-28 J-30 J-32 J-34 J-36 J-38 J-40 J-42 J-44 J-46 J-48 J-50 J-52 J-54 J-56 J-58 J-60
Page 30
CUM GAS (BCF)
GAS RATE (MMCFD)
1
Observations
• PI method seems to work across multiple shale plays including
Haynesville, Eagleford, Niobrara and Marcellus
• Method advantages

Incorporates both rate and pressure data
 Simple to implement - only need Rate, FTP and Initial BHP data
 Provides EUR estimates with limited production history
 Easy to convert to rate versus time forecast

Will the lines stay straight?
Page 31
Happiness is
a Straight
Line!
Page 32