Transcript Slide 1

Forensic Analysis
Why Did This Field Die?
Presented at
Western Australia Section of SPE
June 19, 2012
Perth, Australia
Dr. Bill Cobb
William M. Cobb & Associates, Inc.
Petroleum Engineering & Geological Consultants
Dallas, Texas
Why Did This Oil Field Die?
Every Field is Different!
Reservoir Drive Mechanism
 PRIMARY
 Rock & Liquid Expansion Above the Bubble
Point
 SOLUTION GAS DRIVE
 Initial Gas Cap Expansion - Size
 Aquifer Influx – Size
 WATERFLOODING
 CO2, Steam, Polymer, Other
PRIMARY RECOVERY VS WF
 Solution gas drive requires the reservoir pressure
to be constantly decreasing
 WF is a displacement process and is most efficient
when reservoir pressure is maintained or
increased
 When converting from primary to waterflooding or
any type of fluid injection, the reservoir recovery
mechanism changes.
 Consequently reservoir evaluation and reservoir
management procedures generally need to be
changed
THIS PRESENTATION IS THE FORENSIC
ANALYSIS OF A DEAD OR DYING
WATERFLOOD WHERE PRIMARY
PRODUCTION WAS FROM SOLUTION GAS
 Can we learn lessons that may help us resuscitate
the WF or guide us if we move to a tertiary
project?
 Why did the project die?
 Where do we start?
 What does the evidence say?
WHAT ARE THE KEY FACTORS THAT DRIVE
THE OUTCOME OF A WATER INJECTION
PROJECT?
NP
=
Cumulative Waterflood Recovery, BBL.
N
EA
EV
ED
=
Oil in Place at Start of Injection, BBL.
Areal Sweep Efficiency, Fraction
Vertical Sweep Efficiency, Fraction
Displacement Efficiency, Fraction
=
=
=
WATERFLOOD RECOVERY FACTOR
RF  E A * EV * ED



 RF
EVOL
N
Np
EA
= f (MR, Pattern, Directional Permeability,
Pressure Distribution, Cumulative Injection &
Operations)
EV
= f (Rock Property variation between
different flow units, Cross-flow, MR)
EVOL = Volumetric Sweep of the Reservoir by
Injected Water
ED = f (Primary Depletion, So, So, Krw & Kro, μo & μw)
TO MAXIMIZE WATERFLOOD OIL RECOVERY
 Recognize the recovery mechanism has
changed.
 The driver of the waterflood is the injection
well.
 The injector is the Quarterback of the
operation.
 Efficient utilization of the injector maximizes
volumetric sweep. (The fraction of the
reservoir contacted by the injected water).
THE QUARTERBACK OF ALL INJECTION
PROJECTS IS THE INJECTION WELL
Properly located injection wells are A significant key to
A successful waterflood:
 They deliver the water where it needs to be
injected
 They deliver the water at the correct time
 They deliver the water in the proper volume
 Effective utilization of injection wells is an
important key to optimizing the WF by allowing EA
and EV values and RF to be maximized
 Failure to properly locate and manage the
injectors will result in a less efficient injection
project and could lead to failure.
DID THIS WATERFLOOD DIE AND FAIL TO
PRODUCE EXPECTED WF OIL?
 Did this project meet a premature high water cut
death? If the answer is yes, some of the reasons
for failure are likely due to:
 Lack of significant movable oil saturation at the
start of injection – low ED
 High initial free gas saturation leading to a small
or negligible oil bank and long gas fill-up time
 Floodable net pay is overstated (same porosity
cutoff used for WF as used for primary depletion)
 Poor volumetric sweep – low EVOL
NORTH AMERICA
LIQUID EXPANSION - SOLUTION GAS DRIVE
Pi = 4400 Psi
Pbp = 4000 Psi
P = 400 Psi
Sg = 36%
RF = 1%
So = 76%
RF = 19%
So = 76%
So = 40%
Swc = 24%
Swc = 24%
Swc = 24%
Boi = 1.75
Bobp = 1.78
Bo = 1.15
OOIP = 100 MMSTBO
*L.P. Dake – Fundamentals of Res Eng. – Eq. 3.22 Pg. 86
OIP = 80 MMSTBO
NET PAY
 Static OOIP
 Dynamic OOIP
 Drive mechanism – primary vs secondary
 Waterflood net pay cutoffs controlled by:
 Water Cut Economic Limit
 Permeability Distribution between Flow Units
(Dykstra-Parson Coefficient)
 Oil/Water Relative Permeability
 Mobility Ratio (Oil and Water Viscosity)
 Fluid Saturations at Start of Injection (So, Sg, Swc)
* See SPE #48952 and SPE #123561
WF VOLUMETRIC SWEEP USING OIL
PRODUCTION DATA SINCE START OF
INJECTION
𝐸𝑉𝑊
* See SPE #38902
𝑁𝑃𝐵𝑂
+ 𝑆𝑔
𝑉
𝑃
=
𝑆𝑊 − 𝑆𝑊𝐶
Cont'd – WATERFLOOD FAILURES MAYBE
DUE TO:
 VRR less than 1.0 and pressure declines
 High variation in permeability between geological
layers causing the high permeability layers to water
out the producing wells before the lower perm layers
Contribute meaningful waterflood production
 Failure to develop a pattern
 Failure to recognize and honor KX and KY trends
 Failure to keep fluid levels pumped off in producing
wells
 Mechanical integrity of injection wells to control
vertical distribution of injected water
ASIAN WATERFLOOD
SOLUTION GAS DRIVE (WEAK WATER INFLUX)
Pi = Pbp = 2250 Psi
P = 2100 Psi - At Start Of
Injection
Rsi = 550 SCF/STBO
Swc = 29%
Boi = 1.39 RB/STB
Sg = 3%
µoi = 0.44 CP
MR = 0.30
WATER INJECTION RESPONSE
PRF W/O H2O
AREA
%
1
15-18
2
3
4
15-18
15-18
15-18
Current RF
%
18
EUR
%
27
VRR Since
Start of Inj.
0.51
21
25
31
31
33
44
0.63
0.71
1.09
SCHEMATIC CROSS SECTION
WF WAS NOT SUCCESSFUL
WHAT SHOULD BE CONSIDERED?







Compute So and Sg at start of waterflood
Compute WF volumetric sweep efficiency
Re-evaluate net pay cutoffs
Check for high permeability thief zones
Check VRR since start of injection
Consider infill drilling
Realign pattern – this could violate the 11th
commandment
 Is it a candidate for horizontal producers?
SUMMARY OF LESSONS LEARNED
WATERFLOOD LESSONS LEARNED
1)
2)
3)
4)
5)
Every field is different
There are almost no analogy floods
Need high movable oil saturation
Need low free gas from solution
Prefer low oil viscosity (high viscosity oils can be
produced by cycling large volumes of water).
6) Pattern highly desirable
7) Honor KX/KY
8) Effective VRR since injection start equals 1.0 or more
for each pattern and key geological zones
LESSONS LEARNED Cont'd
9) Careful attention given to selection of net pay cutoffs.
NET PAY FOR WATERFLOOD IS LESS THAN NET PAY FOR
PRIMARY DEPLETION.
10) Keep fluid levels in producing wells pumped off
11) Accurately test each producing well monthly for oil,
water and gas.
12) Maintain production plots on a well by well basis.
Combining wells into groups is equivalent to combining
“The Good, The Bad and The Ugly”.
LESSONS LEARNED Cont'd
13) Forecasting the future production should be performed on
a well by well basis.
 Typical plots of oil rate vs time or oil rates vs cumulative
oil produced should be used with extreme caution
because oil rates are directly related to injection rates
and injection rate changes and stratification.
 Semi-log plots of WOR vs cumulative oil produced are
likely to be more reliable because WOR is largely
independent of injection rate and injection rate
changes.
 Analysis of WOR plots is most reliable when forecasts
are made using WOR values which exceed 2.0 to 3.0
14) Reliable well forecasts require accurate well tests
LESSONS LEARNED Cont'd
15)Conduct regular injection profiles to monitor the
amount of water going into various zones.
16)Thief zones must be identified and isolated or oil
production will occur at high water cuts.
15) REMEMBER THE QUARTERBACK
HONOR THE DATA




Every field is different
The reservoir speaks to us – are we listening?
Data costs money
Lack of quality geological, reservoir and production data
usually leads to inefficient operations or early failure.
 Lack of relevant data puts the geoscientist, reservoir or
operational analyst into a position where he/she must
trust experiences, instincts, hunches and wishful thinking.
 “People are not always truthful – the evidence does not
lie.” – from Gil Grissom of CSI
 Become an OFI – Oil Field Investigator – follow the
evidence
WHEN ALL ELSE FAILS, A POTENTIAL
WATERFLOOD ANALYSIS METHOD IS:
YES
NO
DOES IT
FUNCTION?
DON’T CHANGE IT
YES
DID YOU
TRY TO FIX IT?
YOU IDIOT!
NO
DOES ANYBODY
KNOW ABOUT IT?
NO
HIDE IT
YES
YOU POOR BASTARD!
YES
ARE YOU
GOING TO BE IN
TROUBLE?
NO
NO
CAN YOU
BLAME SOMEONE
ELSE?
YES
THEN, THERE IS NO PROBLEM
PRETEND YOU
DON’T KNOW ABOUT
IT!
Forensic Analysis
Why Did This Field Die?
Presented at
The Dallas E & P Forum
December 13, 2011
Sponsored By SIPES and SPE
Dr. William M. Cobb
William M. Cobb & Associates, Inc.
Petroleum Engineering & Geological Consultants
Dallas, Texas
TWO ADDITIONAL POINTS
DECLINE CURVE ANALYSIS
Assume
 Gas fill-up has been achieved
(reservoir Contains oil and water
 Reservoir pressure is approximately constant
(Bo is constant)
 Steady state flow prevails (approximately)
Conclusion
 Effective Water Injection = Liquid Production
(at Reservoir Conditions)
DECLINE CURVE ANALYSIS
iw * f o
iw (1  f w )
qo 

Bo
Bo
qw
iw * f w

Bw
Conclusion
Oil and Water Production Rates are directly related
to injection rates. Therefore, DCA of qo vs t or qo vs
NP must be evaluated only after giving consideration
to historical and projected water injection rates.
BOPD
10000
WATERFLOOD EXPONENTIAL
DECLINE
Start Water Injection
1000
EL
100
OIL RATE VS CUMULATIVE OIL
PRODUCED
10000
9000
8000
Start Water Injection
7000
BOPD
6000
5000
4000
3000
2000
EUR 53 MMBO
EUR 49 MMBO
1000
0
0
5
10
15
20
25
30
35
40
45
Cumulative Oil Production (MMBbls.)
50
55
60
OIL RATE VS CUMULATIVE OIL
PRODUCED
10000
20000
9000
18000
Start Water Injection
8000
16000
14000
6000
12000
5000
10000
4000
8000
3000
6000
BOPD
7000
EUR 53 MMBO
2000
EUR 49 MMBO
1000
4000
2000
0
0
0
5
10
15
20
25
30
35
40
45
Cumulative Oil Production (MMBbls.)
50
55
60
WOR IS INDEPENDENT OF INJECTION RATE
WOR 
qw
q0
WOR 
iw * f w
iw * (1  f w )
WOR 
fw
(1  f w )
(WOR ) STD .COND . 
fw
B
* o
(1  f w ) Bw
Conclusion
 WOR is independent of injection rate
Other Points
 WOR should be applied to individual wells and
not field
 WOR should be applied using values greater
than 2.0
WATER OIL RATIO VS CUMULATIVE
OIL
100
49
WOR
10
1
EUR 55 MMBO
0.1
0
5
10
15
20
25
30
35
40
45
Cumulative Oil Production (MMBbls.)
50
55
60