Shell Ex ploration & Production
Understanding and controlling fractured
w ater injection in the Pierce field, UK Central
N orth Sea
Jeroen Snippe, Shell UK Exploration & Production (presenting)
Copyright: Shell Exploration & Production Ltd.
Bernhard Hustedt, Shell Intnl. Exploration and Production B.V. (currently Brunei
Shell Petroleum Co. Sdn. Bhd.)
DEVEX, Aberdeen
13th May 2009
19 / 05 / 2009
File Title
By kind permission of the Pierce co-venturers: Oranje-Nassau Energie B.V. and
Nippon Oil Exploration and Production U.K. Limited
Special thanks go to Peter Schutjens and Hassan Mahani
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Contents
•
Pierce overview
•
Water injection behaviour
•
Understanding induced fracturing
– General principles
– Data analysis
– Simple Modelling
– Sophisticated Modelling
•
Conclusions and Implications
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Pierce field, general overvie w
Background
Central North Sea (East Central Graben)
265 km east of Aberdeen
Discovered:1975 (South), 1990 (North)
Historical operators: BP, Ranger, Enterprise
Operated by Shell (92.5172%).
Co-venturers: Oranje-Nassau (3.7284%),
NOEPUK (3.7544%)
Twin salt diapir, steep dips
Faults – radial, rarely seal (except in SE)
North Pierce
Deposition – Forties Fm. (palaeocene turbidite)
NTG ~ 60 %, porosity ~ 18%, perm ~15mD
Light Oil: 38 API with Primary gas caps
South Pierce
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Pierce field, development
Initial development (1999)
N
6 horizontal producers (+infill A9 in 2007)
2 gas injectors (all gas re-injected)
Successful, but little aquifer support
Water Injection (2005)
Needed for pressure support
Needed for recovery of downdip oil
4 water injectors (horizontal), South only
Early water breakthrough (this presentation)
Redevelopment
Currently being investigated
Find other way to recover downdip oil (e.g.
drill deep, artificial lift)
Water injection still plays a role
Gas Cap Blow Down
After end of economic oil production
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W ater injection beha viour
A8z injection rate
(m3 / hr)
A1 Pressure
(psi)
100 days
•
Good pressure support
•
Problematic sweep, A1 watered out quickly
•
Why did this happen? Understanding this is crucial for Pierce waterflood control and optimisation
•
Extensive integrated analysis, for all well pairs. Main data source: real-time injection pressures (THP)
•
Initial focus on A8z - A1 because of watering out of A1. Covered in this presentation.
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Ra w d ata analysis: H all plot
Injectivity suddenly decreases with rate while
injection pressure stays nearly the same:
clear sign of dynamic fracture behaviour
Hall curve
Rate
Inj. pressure
Injectivity
Cumulative water injected (bbl)
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Ra w d ata analysis: A 8z step-rate test
4000
Max rate of mud
pumps: 11,500 bbl/day
FIP (Fracture Initiation
Pressure): 3,100psi
3500
3000
THP [psi]
THP
(psi)
2500
2000
1500
Fractured injection
1000
Pressure (FPP) nearly rate
independent
Matrix
injection
500
0
0
2 000
4 000
6 000
Injection Rate [bbl/day]
8 000
Injection rate (bbl / d)
•
Again, clear sign of dynamic fracturing
10 000
12 000
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Dyna mic beha viour of induced fractures
Determines
magnitude of
Fracture
Propagation
Pressure
Fracture grows or
shrinks over time due
to rate changes,
reservoir pressure
increase, ...
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3D geomechanical model
•
Gives key input parameters: minimum
total principle stress S3 magnitude
and orientation
•
Magnitude of S3 consistent with FPP
from step-rate test
•
Orientation: S3 wraps tangentially
around salt diapir
•
So any induced fractures will grow
radially to & away from salt
minimum
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The key question
•
How big can these fractures grow in Pierce?
– Laterally? (is this what watered out A1, or was it e.g. due to a
high perm streak?)
– Vertically? (does fracture connect to entire reservoir thickness, or
only part of it thus reducing sweep efficiency?)
Fracture half-length Xf
Water
injector
Oil
Producer
Fracture height h
Reservoir height H
Xf
Conformance = h / H
h
H
Salt
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Tools used for understa nding fracture gro wth
Increasing sophistication
Incorporation of fracture
growth physics
PWRI-FRAC
[Shell]
1D
FRAC-IT
[Shell]
3D
in
g
u
l
p
O
F
I
ll]
e
h
[S
Hall Plot
Saphir
(Kappa)
1D
Incorporation of reservoir detail
Shell Ex ploration & Production
Xf and h from P WRI-FRAC callibrated
to step-rate test
12 000
3500
10 500
3000
9 000
2500
7 500
2000
6 000
1500
4 500
Injection rate
(bbl / d)
Rate, bpd
Pressure (psi)
Pressure
(psi)
4000
Surface Pressure [Rigfloor]
1000
3 000
THP [PWRI-FRAC ]
Rate [Rigfloor]
500
1 500
Rate [PWRI-FRAC]
0
00:00
01:12
02:24
03:36
04:48
06:00
Time
07:12
08:24
09:36
10:48
0
12:00
12 hours
•
PWRI-FRAC predicts THP (match quality indicator) and fracture sizes as function of time
•
Good match over relatively short time duration of step-rate test
•
At end of injection fracture starts becoming vertically constrained (h = 48 ft, 2*Xf = 60 ft)
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Prediction over full injection history
Step-rate test
Pressure
(bar)
2.5 years
•
PWRI-FRAC cannot match THP over full injection history
•
Need better reservoir description to model fracture dynamics on this timescale!
•
Can we get Xf and h over this time scale using a different method?
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Xf and h from PTA on pressure fall-offs
•
•
Pressure Transient Analysis
(PTA) analyses shut-in periods
rather than flowing periods
THP (data)
THP (model)
Main parameters to be
extracted:
–
perm * fracture height kh
[not h itself]
–
Fracture half-size Xf
–
Fault distance L
THP
THP derivative
Injection
rate
Saphir
Xf, L
kh
2.5 years
Saphir
Saphir + IFO plugin
40 days
10 hours
Change in kh and Xf,L over time
Similar results between the two methods
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PTA summ ary
•
Difference in fall-off signals over time indicates vertical shrinkage
and horizontal growth, and possibly fracture re-initiation
•
Consistency between the two methods increases confidence in
interpretations...
•
But proximity to a sealing fault leads to some ambiguity (Xf vs. L)
•
Can we get confirmation of Xf and h from an independent
method?
– As we have seen, not with PWRI-FRAC on 2.5 year timescale
– But we can if we incorporate a better reservoir description: FRAC-IT
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Fully integrated fracture model FRAC-IT
3D reservoir simulation grid
•
Full-physics fracture propagation
calculation
•
Full-physics reservoir simulator (coupling to
in-house reservoir simulator)
•
3D integration of geomechanics, wells,
geology, reservoir engineering
For details on FRAC-IT see SPE 95726 (Hustedt et. al.)
Producer
fracture
Injector
•
THP (model)
THP (data) •
•
1.5 years
Match to THP over full injection history much
better than with simpler tool PWRI-FRAC
Assuming re-initiation of the fracture gives a
further improved match (not shown here)
3D model allows full analysis within the
reservoir simulator of 3D sweep pattern etc.
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Consistency betw een methods?
•
Yes! (assuming re-initiation)
•
Both methods indicate length growth over time, despite lowering of rates
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Conclusions and Implications
Technical conclusions
•
Simple data analysis proves dynamic element (fracture growth / shrinkage)
•
Determination of fracture size (Xf and h) over time is possible from real-time pressure data (THP)
•
Multiple analysis / modelling tools lead to consistent results
•
Only the sophisticated, fully integrated 3D model is capable of modelling the dynamics over a longer
time period (years)
Implications for Pierce field management
•
Water injection rates need to be limited in order to avoid fractures growing into producers
•
Due to limited vertical conformance, some layers will not be swept efficiently
•
With another spatial configuration of water injectors (and / or better injection control along the
completion), a better areal and vertical water sweep efficiency might be possible, but will remain
challenging
For more details see IPTC 12533 (accepted for publication in SPERE journal)
Shell Ex ploration & Production
Understanding and controlling fractured
w ater injection in the Pierce field, UK Central
N orth Sea
Thank you for your attention.
Q uestions ?
Presenter’s
biography
Shell Ex ploration
& Production
Jeroen Snippe is a Reservoir Engineer at Shell. He started his career in
1997 in the Shell reservoir simulator development team in The
Hague, and then moved to Aberdeen in 2003. He has worked on
several North Sea fields, since 2007 on the Pierce field. Jeroen
obtained a PhD in physics prior to joining Shell.