Transcript Produced Water Reinjection Performance Joint Industry Project

Produced Water Reinjection
Performance
Joint Industry Project
TerraTek, Inc.
Triangle Engineering
Taurus Reservoir Solutions (DE&S)
E-first Technologies
Advantek
Data analysis
– Data sets analyzed previously:
– Elf 3 Well 1 + 2, Statoil Heidrun, Marathon W. Brae
– Additional data sets:
– Phillips T field
– KMG G field
– Simple damage model applied to Elf 3
– Each dataset has unique interpretation problems
– Analysis of impairment of injectivity (k, S)
Methodology for analysis
1.
Convert THP to BHP
2.
Find and mark all significant events
(stimulations, transition matrix-frac,…)
3.
Conventional p,Q vs t and p vs Q plots
4.
Modified Hall plot (consider variations in pres)
5.
Check initial (or expected) injectivity by
analytical or numerical calculation
Methodology for analysis – cont’d
6.
If fracturing identified, check frac pressure from
all available sources
7.
Calculate II in matrix mode
8.
Calculate II in fracture mode
9.
If good data is obtained for number of datasets,
correlate II changes with basic parameters
10.
Try to develop general correlation (similar to
PEA23)
Phillips T field characteristics




Fractured chalk reservoir, production wells have
negative skins
Raw data processed through the BHP spreadsheet
tool - validation
Reservoir pressure increased with time from 2125
to 3000 psia (92-96). Pres vs t for analysis was
taken from reservoir simulator output
SW injection only (additional info -acid washes)
Phillips T field chalk Well 1
Phillips Chalk 1 - permeability damage calculation based on observed pressure
1000
3
Invaded (waterflooded) radius
Avg permeability in invaded zone
Input permeability
Equivalent skin
Measured skin
10 per. Mov. Avg. (Equivalent skin)
800
2
1
700
0
600
-1
500
-2
400
-3
300
-4
200
-5
100
-6
0
0.00
200.00
400.00
600.00
800.00
1000.00
time (days)
1200.00
1400.00
1600.00
1800.00
-7
2000.00
Equivalent skin
Invaded radius (ft), permeability in invaded zone (md)
900
Phillips T field Well 1 – reservoir pressure
Phillips well 1 - variable reservoir pressure
4500
4000
pressure at the drainage radius (psia)
3500
3000
2500
2000
pressure required for zero skin
pressure from Phillips res. model
1500
11 per. Mov. Avg. (pressure required for zero skin)
1000
500
0
0.00
500.00
1000.00
1500.00
time (days)
2000.00
2500.00
Phillips T field chalk Well 2
Phillips Chalk 2 - permeability damage calculation based on observed pressure
1000
40
Invaded (waterflooded) radius
35
Avg permeability in invaded zone
Input permeability
800
30
Equivalent skin
Measured skin
700
25
600
20
500
15
400
10
300
5
200
0
100
-5
0
0
200
400
600
800
1000
time (days)
1200
1400
1600
1800
-10
2000
Equivalent skin
Invaded radius (ft), permeability in invaded zone (md)
900
Phillips T field Well 2 – reservoir pressure
Phillips chalk 2 - reservoir pressure with time
5000
4500
reservoir pressure at drainage radius (psia)
4000
3500
3000
Required to maintain zero skin
2500
Provided from res. simulation
2000
1500
1000
500
0
0.00
200.00
400.00
600.00
800.00
1000.00
time (days)
1200.00
1400.00
1600.00
1800.00
KMG G field

3-10 D, 32 % porosity, 2 wells (W4 and W4A)

Mixture of PW and aquifer water from the start

OH+ gravelpack (W4) or excluder (W4A)

No fracturing? (no data on frac gradient either)

Almost exact analog to Harding (SPE ….UK DOE)

Assumed high completion skin:
 S=100 for gravelpack (W4)
 S=250 for excluder screen (W4A)
KMG G field well W4
400
10000
300
1000
200
100
100
Invaded (waterflooded) radius
10
Avg permeability in invaded zone
Equivalent skin
Completion skin
0
0
200
400
600
800
1000
time from 28/09/98 (days)
1200
1400
1
1600
Permeability in invaded zone (md), equivalent skin
Invaded radius (m)
KMG G field Well W4 - permeability damage calculation based on observed pressure
KMG G field W4 – injectivity decline
KMG G field Well W4 - injectivity index plot (matrix flow)
10
10
9
7
1
6
5
4
Series1
0.1
Series2
3
2
1
0.01
0
200
400
600
800
time from 28/09/98 (days)
1000
1200
1400
0
1600
Injectivity index (m3/kPa/day)
Injectivity index (m3/kPa/day) - log scale
8
KMG G field well W4A
KMG G field Well W4A - permeability damage calculation based on observed pressure
Assumes large completion skin for the excluder screen
120
800
Invaded radius (m)
90
600
500
Invaded (waterflooded) radius
Avg permeability in invaded zone
60
400
Equivalent skin
Completion skin
300
30
200
100
0
0
100
200
300
400
time from 28/09/98 (days)
500
600
0
700
Permeability in invaded zone (md), equivalent skin
700
KMG G field well W4A – injectivity decline
KMG G field Well W4A - injectivity index plot (matrix flow)
1
0.7
0.5
0.4
0.1
0.3
Series1
Series2
0.2
0.1
0.01
0
100
200
300
400
time from 28/09/98 (days)
500
600
0
700
Injectivity index (m3/kPa/day)
Injectivity index (m3/kPa/day) - log scale
0.6
KMG G field – injectivity comparison with BP field D
KMG G field comparison with BP field D - injectivity index plot (matrix flow)
10
KMG G field W4
BP Field D
Injectivity index (m3/kPa/day) - log scale
KMG G field W4A
1
0.1
0.01
0
100
200
300
time from 28/09/98 (days)
400
500
600
Summary
Detailed data and results of analysis (preliminary)
Data set
Injection Water type
Water quality (ppm) Injection regime
period
TSS TSS
(days)
surf DH
AW,GW,SW,PWOIW
0 - 384 SW (coarsely
0?
?
Marathon 2 (W. Brae)
filtered)
(sanitized name)
7.
385-970 SW (coarsely
filtered)
0-921 SW (clean)
11. Statoil 1 (Heidrun) B3H
922-1592 SW (clean)
Inj. Index
Inj Index
Reservoir Perm in Comments
invaded
zone
(analysis)
expected perm
(radial
from res.
(md)
flow)
perm
Matrix + possibly 16 bbl/psia/d 1066 bbl/psia/d 2000
30 Higher injectivity at higher average rates, but inj
slight fracturing?
pressures are not higher - therefore it is unlikely
Matrix
13 bbl/psia/d 1066 bbl/psia/d 2000
25 due to fracturing. Perhaps rate-dependent
damage?
0?
?
0?
?
fracture
1 m3/kPa/d
3.699
438
0?
?
matrix
.25 m3/kPa/d
3.699
438
12. Elf 3 Well 1
0-2300 PW
100-300
0 100+? matrix+fracture
0.1-1
m3/kPa/d
Elf 3 Well 2
0-413 PW
100-300
0 100+? mixed?
413-613 PW
100-300
0 100+? matrix
02-0.7
14.8
m3/kPa/d
m3/kPa/d
0.15
14.8
613-1556 PW
100-300
0-1948 SW
0 100+? fracture after
about 750 days
0 <5
matrix
0-1553 SW
0 <5
Phillips T1 Well 1
Phillips T1 Well 2
PW+AW
KMG G Well W4
PW+AW
KMG G Well W4A
0.26
20-40
bbls/psia/d
matrix
10-50
bbls/psis/d
matrix early,
0.22-1.5
fracture late time m3/kPa/d
matrix, possibly 0.25-0.5
frac late
m3/kPA/d
23.52
m3/kPa/d
14.8
19
bbls/psia/d
26.7
bbls/psia/d
25.7
m3/kPa/d
25.7
m3/kPa/d
1700
4000
90 Interpretation depends on wellbiore friction. With
any amount of friction BHP in frac regime
decreases with rate - unresolved. Initial res
27 pressure interpreted from shut ins (25,000 kPa)
and p-Q plot (29,000) are inconsistent with
28,000 value given
5 to 50 Severe reduction in perm after each acid job.
Because of THP limitation, interpretation of
fracturing not clear.
40-100 Severe reduction in perm in all periods.
35 Consistent interpretation requires assuming hor
stress increased due to injection
4000
60 Period 613-1121 suggests transition from matrix
to frac regime
100 100-200 Fractured chalk, strong effect of variable res
pressure with time on analysis, production wells
250 100-600 have negative skins. Well 2 scatter caused by
uncertain res. pressure
4000
3000 25-250
3000 25-250
Gravel pack, assumed compl skin=100. Large
gap in data (455-1178 days)
Excluder screen, assumed compl skin=200. Gap
in data (123-474 days)
Conclusions
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All data sets show significant reduction of injectivity
compared to theoretical
Perm reduction and skin plots help visualize the
problem
Completion skin included as a separate item now
Each case must be processed very carefully,
assembly line approach will give misleading results
Simple damage model looks promising, can
incorporate dynamic changes (p(t), stimulations, …)