why is it getting harder to inject – is it just skin damage or is the disposal neighborhood...
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Why Is It Getting Harder To Inject – Is It Just Skin Damage Or Is The Disposal
Neighborhood Becoming Too Crowded?
Presented by:Ken Johnson
Environmental Engineer(214) 665-8473
EPA Region 6
May 6, 2015
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What Makes Injection Well Pressure Change When Injecting?
Total Well Bottom Hole Pressure Response =
Static Reservoir Pressure
+ Wellhead Pressure
+ ∆Phydrostatic wellbore column
- ∆Pwellbore friction loss
- ∆Pcompletion skin factor pressure drop
-∆Preservoir rock pressure drop
+ ∆Preservoir boundary pressure increase
Think about it as a dynamic system of pressure responses with some taking longer to influence well behavior than others!
The “Inner” and “Outer” Limits
Outer Limits Occur out in the
reservoir away from the well
Examples Offset injection and
production wells Drastic change in
reservoir rock and fluid properties
Faults or pinchouts Natural fractures
Inner Limits At or around the
wellbore Examples:
Wellbore friction loss
Completion skin factor
Wellbore hydrostatic column
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Injection Well / Disposal Zone “System” – “Inner Limits”
Have an immediate impact on injection pressure Tubing Friction Loss
• Combination of injection rate, tubing ID, and tubing roughness or friction factor
• Smaller tubing means more friction loss Skin effect (S) due to completion conditions
• Changes from test to test• Shows up as any pressure drop downstream of gauge location but
upstream of reservoir rock• Negative skin factor means a “system enhancement”
Gives the effect of a larger wellbore Examples - hydraulic fracture, acid treatment, coiled
tubing cleanout, or reperforating• Positive skin factor means a “system restriction”
Results in a smaller effective diameter for wellbore Examples - clogged perforations, invaded zone
immediately around the wellbore by dirty fluid, partial penetration, well fill, or poor perforating job
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Injection Well / Disposal Zone “System” – “Inner Limits” cont.
Wellbore hydrostatic column Contolled by wellbore fluid density and depth
of completion zone
Wellhead injection pressure Constrained by permit conditions Constrained by plant disposal needs, site
storage capacity and pumping equipment
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Inner Limit Pressure Losses
Tubular Friction Loss- Hazen-Williams Correlation Several other options – empirical correlation
from well-specific testing, Colebrook equation ∆Pfriction= 0.433*L*(4.52*Q1.85)/(C1.85*d4.87) in psi
• Q is rate in gpm, L is pipe length in ft, C is pipe roughness coefficience, d is inside pipe diameter in inches
Skin Factor, S ∆Pskin = 0.87*m*S = 0.87*(162.6*Q*β*µ/k*h)*S in
psi• Kh/µ is transmissibility in md-ft/cp, Q is rate in bpd
Skin pressure drop is rate dependent!
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Injection Well/Disposal Zone “System” – “Outer Limits”
Have a long term impact on injectivity A. Pressure drop through reservoir rock
• Long term timeframe – hours, days, months or years• Function of:
o permit conditions and actual operational needso reservoir nature and rock and fluid properties
B. Reservoir boundaries or restrictions• Make it more difficult to inject long term – months or
years• Offset injection wells
o Can be any class of injector completed in the same reservoir
o Influence depends on a combination of reservoir properties (k, h, φ, ct, μw), distance, and injection rate
• Fault or pinchout or reduced net thickness 7
Two Kinds of Pressure Buildup Reservoir Models – Analytical or Finite Difference
Analytical Describe reservoir fluid behavior with
single analytical equation E.g., Radial diffusivity equation;
Hydraulic vertical fracture; and dual porosity
Reservoir properties’ variability limited or constant
Easier to set up and run Allow for combinations of various
inner (at well) and outer (in reservoir) boundary conditions E.g., skin, fracture, sealing fault
(from
SPE 10043)
Finite Difference Use a grid to break reservoir up into discrete
reservoir volume “blocks” Differential equations describing fluid flow
between blocks solved with numerical solution methods
Handle complex reservoir geology, fluid and rock properties and well conditions in more detail
More difficult to set up Can be computationally intensive
(From
SWIFT
Manual)
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Analytical Modeling for Long Term Reservoir Pressure Behavior
May be easier to set up and run than a finite difference (gridded) model No issues with computational demands for a large
number of grid blocks Assumes constant reservoir rock and fluid properties
K, h, viscosity, compressibility, and porosity are all constant
Flat or constant dip reservoir Faults usually modeled as sealing and infinitely long
Can use streamlines for faults Can be run with or without skin effects at primary injection
well Available as a stand alone tool or as part of well test
analysis software Examples – Pansystem, TRANS II, SAPHIR, PIE,
PHIST/Interact, DuPont Pressure Buildup Model, ect
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10
Analytical Reservoir Model: “Kitchen Sink” Equation for Pressure Buildup at any Reservoir Point
N
j
n
iji
jjtji
ji
N
j
jjtj
o
j
ttk
yyxxcEi
hk
tk
yyxxcEi
kh
qptyxp
1 1
22
1
1
22
1
1 5.396.70
5.396.70),,(
• Accounts for reservoir properties, multiple wells, boundaries, and rates at any point in the reservoir at any time!
• Requires a method for calculating Ei, the exponential integral• Skin factor has no impact on pressure buildup away from the injection
well!• Multiple offset injectors have a “stacking” or group impact on reservoir
pressure buildup• Faults are modeled as “image” wells and have the effect of an offset
injection well
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Finite Difference Modeling for Reservoir Pressure Behavior
Handle geology and fluid and rock property issues more rigorously than an analytical model Structural dip allowed Varying net thickness Varying permeability (if data available) Can place faults in model as mapped with limited extents Adjusts for reservoir fluid property changes with
temperature and pressure (sometimes) May handle multiphase conditions
• CO2, natural gas, brine, oil injection or withdrawal Can handle many offset wells
Examples – SWIFT, ECLIPSE, BOAST, Sensor, INTERSECT, GEM, IMEX, ect.
Finite Element Models used as part of well test analysis software can also do some of this PanMesh, SAPHIR, ect.
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Injection Well Data “Clues” Without the Fancy Models
Review of Disposal Zone Geology – Know the “neighborhood” Are faults present and if so, how far away? Is reservoir thickness thinning away from the well? What other injectors are within 10 miles of yours in the same
interval? Are new injectors being completed in your disposal zone?
Review Pressure Transient Tests – Falloffs and Injectivity Look at skin factor
• Is it becoming more positive?• Identify sources of positive skin
Is kh/u changing or remaining consistent?• Flow profile change due to fill or completion modifications
Are boundaries present on test plots? Plot flowing and static bottom hole pressure measurements
yearly to identify trends• Correct flowing bottom hole pressures for skin effects• Use a common subsea datum for plotting
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Injection Well Data “Clues” Without the Fancy Models cont.
Review Radioactive Tracer Surveys Is fill depth rising and covering portions of completed interval? Is flow profile consistent from year? Is fluid staying in the injection interval?
Review Operational Data Injection Pressures and Volumes can be used to assess behavior
• Continuous monitoring for Class I wells• Monthly program reported operating data available for Class II
wells Prepare Operational Data Diagnostic Plots
• 4 types of plots:o Raw Data (pressure and volume); Operating Gradient; Hall
Integral and Derivative; and Silin Slope Ploto Fits operational data to a flow behavior model
Identify skin changes, induced fracturing, boundarieso Can be done in Excel
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Monitoring Plots
Raw Operational Data Plot daily volume and average pressure versus date Look at trends
Hall Plot with Derivatives Requires measure, estimate or assumption of static
reservoir pressure Can show increased ease of or difficulty of injection Can show long term boundary effects or increasing
skin effects
Operating Gradient Plot More useful for Class II wells to see if fracture
gradient is being exceeded
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Example Operational Data Plots
Oct
-07
Feb-08
Jun-0
8
Oct
-08
Feb-09
Jun-0
9
Oct
-09
Feb-10
Jun-1
0
Oct
-10
Feb-11
Jun-1
1
Oct
-11
Feb-12
Jun-1
2
Oct
-12
Feb-13
Jun-1
3
Oct
-13
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
Monthly Operating Data
Average Tubing Pressure Maximum Tubing Pressure
Monthly Injection Volume
Tu
bin
g P
res
su
re (
ps
ig)
Mon
thly In
jection V
olum
e (bb
ls)
Operating Gradient Plot
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1/1/
2009
4/11
/200
9
7/20
/200
9
10/2
8/20
09
2/5/
2010
5/16
/201
0
8/24
/201
0
12/2
/201
0
3/12
/201
1
6/20
/201
10.500
1.500
2.500
3.500
4.500
5.500
6.500
7.500
8.500
9.500
10.500
Operating Gradient Plot
Operating gradient
Op
era
tin
g G
rad
ien
t (p
si/f
t)
How to Build a Hall Integral with Derivatives Plot
X axis is Wi, cumulative water injection in units of barrels
Y axis has 2 functions associated with it: Hall integral, Hi = Ʃ(Pwf-Pstatic)*Δt where
• Pwf is average bottom hole injection pressure over a time increment of Δto The time increment can be hours, days, weeks, or
months• An injection volume associated with the time
increment is added to obtain a Wi value on the X axis
Hall derivative, Di1= (Hi2-Hi1)/(Ln(Wi2)-Ln(Wi1))• Hi2-Hi1represents the difference between successive
Hall integral values• Ln(Wi2)-Ln(Wi1) represents the difference between
successive cumulative water injection values17
Anatomy of a Hall Integral with Derivatives Plot
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• Ease of injection increases when Hall Derivative response falls below the Hall Integral response• Ease of injection decreases when derivative is above integral
enhancedinjectivity
From Yoshioka et al2008
Example Hall Integral with Derivatives Plot
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0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,0000
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
0
5
10
15
20
25
30
Hall Integral Hall Derivative
Wi, Cumulative Injection (bbls)
Ha
ll In
teg
ral (
ps
i-d
ay
) a
nd
De
riv
ati
ve
: Hall integral and Derivative Plot
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Let’s Look at 2 Hypothetical Injection Well Situations
Reservoir Conditions: Pstatic = 1500 psi k = 100 md; h = 100 ft; Φ = 30%; μ = 0.5 cp; ct = 6x10-6 psi-1
Scenario 1: “THE OPEN RANGE NEIGHBORHOOD” Permit life = 10 years; Maximum Q = 300 gpm (10,285 bpd); S=
0; rw = 0.292 ft (7 in. casing) Annual 100 hour falloffs at end of each year No other injectors in the neighborhood, No faults present
Scenario 2: “THE OVER DEVELOPED NEIGHBORHOOD” Injector 1 same conditions as scenario 1 1 sealing fault 2 miles away from injector 1 4 offset injectors on opposite side of injector 1 from the fault
• All offset injectors at 200 gpm• i2 starts after 2 years 2 miles away; i3 starts after 3 years
at 3 miles away; i4 starts at 5 years 4 miles away; and i5 starts at 6 years and 7 miles away
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Scenario 1 – Injector 1 Flowing and Static Pressures from Falloffs over 10 Years
0 10000 20000 30000 40000 50000 60000 70000 80000 900001600
1700
1800
1900
2000
2100
2200
2300
2400
2500Scenario 1 - Flowing and Static Pressures Over 10 Years
Injecting Bottom Hole Pressures Static Bottom Hole Pressures
Operating Time (hrs)
Inje
cto
r B
ott
om
Ho
le P
res
su
re (
ps
ia)
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Scenario 1 – Hall Plot
0.0E+00 5.0E+06 1.0E+07 1.5E+07 2.0E+07 2.5E+07 3.0E+07 3.5E+07 4.0E+070
10,000,000
20,000,000
30,000,000
40,000,000
50,000,000
60,000,000
70,000,000
80,000,000
90,000,000
Hall Integral and Derivative for Scenario 1
Hall Integral Hall Derivative
Cumulative Injection (bbls)
Ha
ll In
teg
ral a
nd
De
riv
ati
e Ip
si-
hr)
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Scenario 2 Layout – Lots of “Neighbors”
2 miles
8 miles
I2
I3
I4
I5
FacilityInjector
1 mile
1 mile
SealingFault
3 miles
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Scenario 2 – Injector 1 Flowing and Static Pressures from Falloffs over 10 Years
0 10000 20000 30000 40000 50000 60000 70000 80000 900001600
1800
2000
2200
2400
2600
2800
Scenario 2 - Injecting and Static Bottom Hole Pressures over 10 Years
Injecting Bottom Hole Pressure Static Bottom Hole Pressure
Operating Time (hrs)
Bo
tto
m H
ple
Pre
ssu
re (
psi
a)
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Scenario 2 – Hall Plot
0 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 40,000,0000
20,000,000
40,000,000
60,000,000
80,000,000
100,000,000
120,000,000
Hall Integral and Derivative Plot for Scenario 2
Hall Integral Sc 2 Hall Derivative Sc 2
Cumulative Injection, Wi (bbls)
Ha
ll In
tefg
ral a
nd
De
riv
ati
ve
(p
si-
hr)
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So How Far Away Does An Offset Injector Have To Be To Affect My Well?
Requires a combination of time, reservoir conditions, rate, and distance
Let’s look at an example:An injector is located 5 miles from my facility, has operated for 10 years, and generally injects around 5000 bpd (145.8 gpm)
How long before it impacts my well?Reservoir conditions:
k= 100 md, 100 ft net thickness, ct = 8 x 10-6 psi-1, μ= 1cp, Ф=30%, offset rw=0.3 ft, and 10 years of offset well operation
Using a dimensionless variable approach from SPE Monograph 5, Appendix C to calculate pressure buildup effects:
tD=0.0002637*k*Δt/(Ф*μ*ct*rw2)
tD=0.0002637*(100 md)*(87,600 hrs)/(0.30*1 cp* 8 x 10-6 psi-1*(0.3 ft)2) = 10,069,450,000
Offset Injector Effects cont.
rD=r/rw
rD=(5 miles*5280 ft/mile)/(0.3 ft)=88,000
tD/rD2=10,069,450,000/(88,000)2=1.381
PD=1/2(Ln(tD/rD2)+0.80907)
PD=1/2(Ln(10,069,450,000/(88,0002))+0.80907)
PD=1/2(Ln(1.381)+0.80907)=0.5659
Offset Injector ΔPat your injector=141.2*Q*β*PD*μ/(k*h)
Offset Injector ΔPat your injector=141.2*5000 bpd*1 STB/RB*0.5659*1cp/(100md*100ft)
Offset Injector ΔPat your injector=39.9 psi
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How Do I Monitor My Injector’s “Neighborhood?”
Know the geology of your well’s “neighborhood” Identify faults – where, orientation, and how far away
Know who your injector “neighbors” are Monitor who else is completing injectors in the same
correlative interval within several miles of the facility “Neighborhood extent” is a function of time, rate,
distance, and reservoir conditions Know your petition pressure buildup demonstration value
Plot and track falloff annual injection and static bottom hole pressures• Used to verify petition compliance with pressure
buildup model• Can identify upward trend in static reservoir
pressure
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How Do I Monitor My Injector’s Condition cont.
Review recent annual radioactive tracer surveys to identify changes at wellbore Profile change Change in fill levels
Review recent annual falloff results Assess any changes in kh/u and S
• Note if S is increasing
Use operational data to assess well behavior Hall Integral with Derivatives plot can identify
changes in ease of injectivity• Can reflect impact of both boundary effects and skin
factor changes
Summary
An injection well’s injection pressure is the net of several responses Some are at the wellbore and others out in the reservoir
Reservoir or “outer limit” pressure response components can take weeks, months, or years to impact a well’s injecting bottom hole pressure Faults Offset wells
Wellbore or “inner limit” pressure response components have an immediate impact on bottom hole injection pressure Skin factor change Increased tubing size Additional net thickness perforated
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Summary cont.
Use Available Tools and Information to Assess Injectivity Changes Falloffs for static and injection pressures
• Critical for active petition compliance• Know the pressure buildup limit in the petition model
Tracer surveys for profile conditions Operational data diagnostic plots for long term
injection behavior Area geology to identify faults Monitor offset injection well activity in same
injection zone for several miles around facility• Can lead to need for a reissuance
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References
“Transient Well Testing,” SPE Monograph 23, Medhat Kamal, 2009
“Advances in Well Test Analysis,” SPE Monograph 5, R.C. Earlougher Jr., 1977
“Well Testing,” SPE Textbook Series Vol.1, John Lee, 1982 “Real Time Performance Analysis of Water-Injection
Wells,” SPE Paper 109876-MS, Izgec and Kabir, 2007 “Identification and Characterization of High-Conductive
Layers in Waterfloods,” SPE Paper 123930-PA, Izgec and Kabir, 2011
Cameron Hydraulic Data: Ingersoll-Rand Company, Westaway, C.R. and A.W. Loomis, 1977
Managing and Minimizing Potential Impacts of Injection-Induced Seismicity From Class II Disposal Wells: Practical Approaches, EPA UIC NTW Report, February 2015, http://www.epa.gov/r5water/uic/ntwg/pdfs/induced-seismicity-201502.pdf
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