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FOAM APPLICATION IN OFFSHORE GAS
FIELDS ENABLED BY PRODUCED WATER REINJECTION
Paula A. Bejarano
Production Technologist
ONEGas JDA, NAM
9th European Gas Well Deliquification Conference
Groningen, Netherlands, 22-24 September 2014
1
CONTENT
Background
Challenges with Continuous Foam (CF) injection
Environmental limitations for water disposal
Produced Water Re-Injection Well (PWRI)
O2-corrosion related issues
Gas blanketing system
Olga modeling
Implemented solution
CF injection vs. corrosion Inhibitor Injection
Key learnings
September 2014
2
DELIQUIFICATION OF OFFSHORE WELLS
Compression
Automated Intermittent Production
Velocity Strings
Foam batch trials
Continuous Foam Injection
September 2014
3
DELIQUIFICATION OF OFFSHORE WELLS
Compression
Automated Intermittent Production
Velocity Strings
Foam batch trials
Continuous Foam Injection
September 2014
4
CONTINUOUS FOAM INJECTION SYSTEM
Manual
CF is applied via a capillary
string inside the tubing.
Offshore
KW
Control line fluid
In 2009 a RENGATE system
implemented on first offshore
foam well.
Independent foam fluid entry
point just below the LMGV and a
bypass across the SSSV.
Actuated
SV
FWV
UMGV=SSV
LMGV Surfactant
REN-LMGV
FV=SSSV
Source: Offshore Engineer, Nov ‘11 issue
Design has the purpose of
minimizing repair frequency.
September 2014
5
103 WELL PERFORMANCE IMPROVEMENT
With Foam
Stable production
with CF injection
rate of 0.7 L/hr
No Foam
CF injected 2 days
prior to opening up
the well to fill up cap
string
Shell Map Library
April 2010
6
With Foam
106 WELL PERFORMANCE IMPROVEMENT
No Foam
Pressure build-up
prior to opening up
the well
Shell Map Library
September 2014
7
With Foam
108 WELL PERFORMANCE IMPROVEMENT
No Foam
Shorter build-up
period vs. longer
production
Shell Map Library
September 2014
8
With Foam
110 WELL PERFORMANCE IMPROVEMENT
No Foam
Well produces
steadily when CF is
injected
Shell Map Library
September 2014
9
Challenges
associated with
Foam Injection
Copyright of Shell Brands International AG
Shell Map Library
April 2010
10
ENVIRONMENTAL LIMITATIONS
Currently, all waste water is disposed overboard (O/B).
~200 m3/d
Environmental regulations in the North Sea dictate a maximum oil in
water concentration of 30 ppm, monthly average for water O/B.
Requirement restricts the CF injection to 24 L/d, insufficient to
deliquify more than 1 well.
CF injection only possible by liquid disposal into a Produced Water
Re-injection well.
September 2014
11
PWRI CHRONOLOGY
2003: all waste liquids re-routed from water over-board into PWRI.
2005: well integrity issues related to leaks.
2007: installed 2” Cr16 coiled tubing (CT) string.
2011: pulled out 2” Cr16 CT due to heavy corrosion.
2012: camera run revealed serious leaks in the Cr13 completion.
2013: well was work-overed with Cr-25 material.
5” Cr13 completion and remaining 2” Cr16 CT
2014: PWRI on-line to receive produced water from foam wells.
September 2014
12
PWRI CHRONOLOGY
2003: all waste liquids re-routed from water over-board into PWRI.
2005: well integrity issues related to leaks.
2007: installed 2” Cr16 coiled tubing (CT) string.
2011: pulled out 2” Cr16 CT due to heavy corrosion.
2012: camera run revealed serious leaks in the Cr13 completion.
2013: well was work-overed with Cr-25 material.
5” Cr13 completion and remaining 2” Cr16 CT
2014: PWRI on-line to receive produced water from foam wells.
Is the well safeguarded now?
September 2014
13
PWRI: JAN 2012 CAMERA RUN (CR-13 COMPLETION)
Shell Map Library
April 2010
14
PWRI WORK-OVER NOV 2013
Cr13 (old)
Cr25 (new)
2” Cr16 CT fish out (heavily corroded)
5” Cr13 tubing POOH
New completion material: Cr25, 5” size.
October 2013
15
CR25 CORROSION LIMITATION AGAINST O2
Cr25 may not be better than Cr13 against crevice corrosion.
Without proper oxygen control (<10 ppb), corrosion is expected at:
40°C @ 60 000 ppm Cl- (10wt.% NaCl)
30°C @ 150 000 ppm Cl- (25wt.% NaCl)
Injection water could warm up to above 30 degC.
Shell Map Library
April 2010
16
PWRI AND GAS BLANKETING SYSTEM
Risk:
Produced liquids
Blanketing gas
Cr25 completion at risk of O2related corrosion.
Well has not been safeguarded for
O2 levels < 10 ppb.
Mitigation:
Implement blanketing system.
Fuel gas is injected into wellhead as
soon as WHP<1 bar.
By avoiding vacuum conditions, O2
ingress from atmosphere into the
well is prevented.
17
WHP OVER-PRESSURIZATION DUE TO GAS BLANKETING
Produced liquids
Blanketing gas
During water injection, fuel gas is
supplied to maintain 0.1 >WHP >1 barg.
At shut-in WHP = 13 barg
1) The falling water drags
gas down into tubing.
Design pressure of upstream
3) At shut-in gas
percolate through liquid
column and migrates up
to surface.
vessels = 5 barg
Gas is believed to travel downhole during
water injection and to migrate back up to
surface during shut-in.
This phenomena causes an overpressurization of the wellhead.
2) Gas travels downhole
and it is injected into the
reservoir
18
WATER INJECTION OBSERVED BEHAVIOR
Blue: wellhead pressure
maintained mostly with
a set pressure of 0,1
barg but not always
flowrates and wel l pressure trends
above 0 barg
400
Green: water
injection rate,
varying
Large variations
in rate lead to
high pressure at
surface
1
T OT AL INJECT ION FLOW OF WAT E
74,6643
350
K8FA1.81PI61.PV
7,57E-02
Barg
300
250
200
150
100
50
0
-1
20-2-2014 0:00:00
K81 WELL 107 PROD.CASING
18.00 days
10-3-2014 0:00:0 0
February 2010
19
OLGA MODELING: PWRI & BLANKETING GAS SYSTEM
September 2014
20
INJECTING AT STEADY WATER RATES
THP build-up takes ~45 mins independent of water rate prior to shut in.
September 2014
21
CAN A DOWNHOLE VALVE HELP REDUCE SHUT-IN PRESSURE?
Constant 200 m3/d water injection.
Shut in pressure = 11 bar
Down hole valve opens and closes even
after shut-in, but not very frequently.
September 2014
22
OLGA MODELING CONCLUSIONS
OLGA allowed better understanding of the mechanism that led to the
wellhead pressure rise due to gas blanketing.
Base case model (well as is)
Gas is taken downhole and injected into the reservoir.
Gas migrates back to surface in ~45 mins.
Shut-in pressures exceed 11 bar (also seen by Ops).
Deep-set downhole valve
Does not prevent gas from migrating back to surface. Injection of
gas into the reservoir continued.
Gas consumption was reduced when compared with same steady
water rate without downhole valve, but 11 barg shut-in pressure at
the wellhead was calculated.
September 2014
23
CURRENT SOLUTION: INSTALLATION OF RELIEF LINE SYSTEM
Fuel gas
scrubber
Gas supply line
Pressure
control valve
Produced liquids
Vent
Stack
Excess pressure
relief line
Vent gas
scrubber
Pressure
transmitter
Blanketing gas
A pressure relief line on the gas blanketing side
prevents wellhead pressure over-pressurization.
Relief system set WHP < 1 barg.
Liquid Train 1 and 2 is sent
overboard!
Gas is relieved through the vent stack.
September 2014
24
Corrosion
Inhibition Injection
Copyright of Shell Brands International AG
September 2014
25
FOAM VS. CORROSION INHIBITION (CI) STUDY
Foam and CI combinations
Foamers: Foamatron V502 and
Foamatron V505
Corrosion inhibitors: CK981
Foam dosage
WHT
Advised CI dose rate
Max 2000 ppm
< 50°C
No change
Max 2000 ppm
> 50°C
Double CI dosage
Max 5000 ppm
< 50°C
Double CI dosage
Max 5000 ppm
> 50°C
Quadruple CI dosage
Above 5000 ppm foam the integrity of production systems cannot be
guaranteed
Higher CF concentrations shows more impact on CI performance.
Higher CI dosage can partly compensate for reduced protection.
Temperature affects corrosion rate.
September 2014
26
CORROSION INHIBITION INJECTION
Max foam
Foam
FTHT WGR/CGR CI rate no
Well
(2000 ppm) in l/d
(°C) (m3/mln m3) foam (l/d) application
Based on LGR
Impact on CI Injection
101 < 50
15/11
5
Future
2.6
103 < 50
600/17
260
Yes
172.8
104 < 50
25/5
10
Future
4.2
--
106 > 50
32/5
25
Yes
15.5
Double CI injection
108 > 50
250/20
180
Yes
118.8
Double CI injection
109 > 50
15/27
65
No
--
110 < 50
45/17
20
Yes
11.8
-No change in CI injection
-No change in CI injection
September 2014
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KEY LEARNINGS
CF Injection has proven a reliable and efficient technology to restore
production on liquid loading wells.
PWRI
O2-related corrosion still represents a high risk for water injectors.
Cr13, Cr26, Cr25 completion run a potential risk of corrosion due to oxygen.
A wider selection of materials needs to be studied to determine which one would be
more suitable against corrosion.
Olga modelling of the water & fuel gas injection provided a better understanding of
the mechanism taking place.
Corrosion Inhibition Injection
CI to be doubled if foam dosage is 2000 ppm max (WHT > 50degC).
New foam will have the capability to also act as corrosion inhibitor as well as KHI-like
chemical (for hydrate protection).
September 2014
28

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