Innovative Energy Technologies Program
Application 01-023
Taber S Mannville B
Alkaline-Surfactant-Polymer Flood
Warner ASP Flood
Annual Report
June 28, 2007
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Summary of Project
Introduction
Husky Oil Operations Limited (Husky) implemented the first field-wide Alkaline-SurfactantPolymer (ASP) Flood in Canada on May 17, 2006. Incremental oil production is expected to be
1 006 103m3 (6 332 MBO) from the Taber S Mannville B pool (Mannville B Pool), an
incremental oil recovery factor equal to 14.5% of the original-oil-in-place (OOIP).
This report is supplemental to the June 2006 Annual Report in which laboratory, geological, and
other applicable reservoir data was submitted.
The field is located in 7-16W4 and the project is proceeding satisfactorily to date.
Timeline
Table 1 outlines some of the major activities that were required as part of the Warner ASP
project in 2006.
Table 1: Chronology of major activities and operations
Activity
Description
EUB Applications
Procure chemical suppliers
Implement plan of
development
Etzikom refurbishment,
replacement and additions
Construction of ASP
Transfer Pipelines
Construction of 11-16
Injection Satellite
Construction of gathering
and distribution pipelines
Warner Oil Battery
Modifications
Existing Injection line
Cleanouts
Commissioning
ASP Injection
Surfactant Force Majeure
Caustic Force Majeure
Injection well timers
Polymer only injection
Husky Oil Operations Limited
Start
End
Directive 51&65 injection approvals
Solicit bids from chemical suppliers, award
chemical contracts, and finalize logistics.
Alter reservoir from 29 producers & 11 injectors
to 45 producers & 18 injectors by drilling 7,
reactivating 11, and converting 6 wells.
Refurbish and modify facility to prepare ASP
solution for EOR purposes.
6” poly lined pipeline to transfer produced water
& 8” poly lined pipeline to transfer ASP solution.
Build satellite for ASP injection pumps
September 2005
September 2005
March 2006
March 2006
October 2005
July 2006
November 2005
March 2006
November 2005
March 2006
February 2006
April 2006
Test satellites and 25 km of injection and
production pipelines for oil wells and injectors.
Modify facility to send higher quality produced
water to Etzikom ASP facility
Clean existing injection pipelines to remove solids
that could be released by surfactant injection.
Commission Warner Modifications, Etzikom, and
11-16 Injection Satellite.
30% Pore Volume of ASP injection
Declared due to raw material availability
Declared due to CN rail strike
Install timers to shut injection wells on/off
30% Pore Volume of Polymer injection
February 2006
May 2006
March 2006
April 2006
March 2006
May 2006
April 2006
May 2006
May 2006
October 2006
February 2007
April 2007
July2008
June 2008
February 2007
March 2007
September 2010
September 2010
Page 2 of 16
Annual Report – June 2007
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Pilot Data
The following data was submitted as part of the June 2006 Annual Report:
Geological Map
Laboratory Studies
Reservoir Data
Well information
The following data was submitted as part of the June 2006 Annual Report:
Well Layout
Plan of Development
Wellbore schematics
Spacing and Patterns
Drilling
Well operations
Well operations such as drilling, injection conversions and reactivations were submitted as part
of the June 2006 Annual Report. As production and injection rates were monitored, perforations
were added to the 10 wells listed in Table 2 as required to improve inflow or oil production. The
results are a comparison between tests before and after the production optimization. Often there
was an immediate benefit although the objective was long term well optimization.
Table 2: Production Optimizations in the Mannville B pool
Well
3/02-09-7-16W4
0/03-09-7-16W4
3/14-09-7-16W4
2/02-16-7-16W4
3/08-20-7-16W4
0/09-20-7-16W4
0/02-29-7-16W4
0/10-29-7-16W4
4/10-29-7-16W4
2/11-29-7-16W4
Date
6-Jun-07
2-Oct-06
26-Mar-07
16-Feb-07
11-Sep-06
26-Sep-06
14-Jun-07
9-Nov-06
31-Jul-06
4-Jun-07
Status
Producer
Producer
Producer
Producer
Producer
Producer
Producer
Producer
Producer
Producer
Results
Inflow increase 10 m3/d, +3.5m3/d oil
Inflow increase 6 m3/d, +2.5m3/d oil
10m3/d, 2% oil to 7m3/d, 7% oil +0.3m3/d
Inflow increase 20 m3/d, 0% oil cut
24m3/d, 2% oil to 52m3/d, 3% oil +1.1m3/d
48m3/d, 4% oil to 52m3/d, 4% oil +0.2m3/d
Still bringing well up to speed.
15m3/d, 5% oil to 23m3/d, 4% oil +0.2m3/d
34m3/d, 3% oil to 12m3/d, 0% oil -1.0m3/d
22m3/d, 30% oil to 33m3/d, 26% oil +2m3/d
Production Performance and Data
Warner ASP injection started on May 17, 2006. To the end of May 2007, the project produced 37
103m3 of oil, 1,239 103m3 of water with a corresponding cumulative voidage replacement ratio
(VRR) of 0.972. During this time period, the daily oil production increased from 50m 3/d at 1.5%
oil cut to 150m3/d at 4.4% oil cut.
Incremental oil from ASP flooding is on target and the forecast remains unchanged since last
year. Oil production due to ASP is expected to be 1.0 106m3 (6.3 MMBO), an incremental
recovery factor of 14.5% OOIP as summarized in Table 3.
Husky Oil Operations Limited
Page 3 of 16
Annual Report – June 2007
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Table 3: Reserve Summary for the Taber S Mannville B pool
Production Values as of May 2007
Original Oil in Place (OOIP)
Cumulative Production to date (CTD)
Waterflood Ultimate Oil Production
ASP Forecast Ultimate Oil Production
Incremental Production (CTD)
Remaining Incremental Production
Total Incremental Oil Production from ASP
Oil Volume
103m3 (MBO)
6,992 (44.0)
2731 (17.2)
2763 (17.4)
3769 (23.7)
23 (0.14)
983 (6.2)
1006 (6.3)
Percent of OOIP
(%)
39.1%
39.5%
53.9%
0.3%
14.2%
14.5%
The project has been performing satisfactorily. Oil and fluid production has closely matched the
original December 2005 prediction. Injection rates fluctuated somewhat between the fall of 2006
and the early spring of 2007 due to supply difficulties of surfactant and NaOH caused by the
Force Majeure, but VRR’s were kept at the acceptable level by adjusting production rates.
Based on predictions from the model, oil production is expected to increase from a waterflood
forecast of 42 m3/d in June 2006 to a peak oil rate of 519 m3/d approximately 4 years after ASP
injection begins. Oil cuts are expected to increase from 2% to 14.5% (Figure 1). Forecast
production rates as well as the oil production profile required to achieve an incremental 10%
recovery factor (4.4 MMBO) are also plotted. As of May 2007, the average daily production
was 150 m3/d. The forecast for May using a range of 10-14.5% incremental oil recovery requires
an oil production rate between 121-159m3/d.
Warner ASP Flood
Forecast vs Actual
Oil Rate, Fluid Rate (m³/d) and Oilcut (%)
10000.0
1000.0
100.0
10.0
1.0
Jan-05
May-06
Sep-07
Feb-09
Jun-10
Nov-11
Mar-13
Date
Oil Rate - Waterflood Forecast
Oilcut - Actual
Oilcut - Dec 05 ASP POS 100% Forecast
Oil Rate - Calender
Oil Rate - Average
Fluid Rate - Calender
Oil Rate - Dec 05 ASP POS 70% Forecast
Fluid Rate - Calender
Fluid Rate - Average
Fluid Rate - Dec 05 Forecast
Oilcut - Dec 05 ASP POS 75% Forecast
Figure 1: Comparison of production to waterflood and ASP predictions
Husky Oil Operations Limited
Page 4 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
ASP injection volumes are approximately 2 weeks behind due Force Majeure declared by two
chemical vendors. Plotting the predicted oil rate based on ASP volumes injected, the actual oil
rate is on forecast. For 1187 103m3 ASP solution injected (May volume), the oil rate was
expected to be in the range of 119-155 m3/d (using 10%-14.5% incremental recovery forecasts).
To date, out of a target 30% pore volume (PV), approximately 14.5% PV of ASP solution has
been injected. Final ASP injection is expected to be completed in June 2008 and will be
followed by 30% PV of polymer solution.
Warner ASP Flood - Rate vs Cum Inj
Forecast vs Actual
Oil Rate, Fluid Rate (m³/d) and Oilcut (%)
1000
100
10
1
0
500
1000
1500
2000
2500
3000
3500
4000
Cum Injection (10³m³)
Oil Rate - Average
Oilcut - Actual
Oil Forecast P100
Oil Cut Forecast P70
Oil Cut Forecast P100
Oil Rate - Calender
Oil Forecast P70
Figure 2: Oil production based on ASP volumes injected.
Daily oil production and oil cuts for each well are provided in electronic Attachment # 1 – Monitoring -
Warner Production DOE 2007. Calendar daily oil production and oil cuts are summarized in
Figure 3 which reflects producer and injection downtime.
200
10.0
180
9.0
160
8.0
140
7.0
120
6.0
100
5.0
80
4.0
60
3.0
40
2.0
20
1.0
0
0.0
Oil Cut, %
Oil Prod, m3/d
Daily Oil Production vs Oil Cut
Warner ASP
7/16/07
6/25/07
6/4/07
5/14/07
4/23/07
4/2/07
3/12/07
2/19/07
1/29/07
1/8/07
12/18/06
11/27/06
11/6/06
10/16/06
9/25/06
9/4/06
8/14/06
7/24/06
7/3/06
6/12/06
5/22/06
5/1/06
DD-M M -YY
Oil, m3/d
Oil Cut, %
Figure 3: Daily Oil Production and Oil Cut of the Mannville B pool
Husky Oil Operations Limited
Page 5 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Another positive indication the flood is working throughout the reservoir is the observed oil cut
response (Table 4). When the project started, 56% of the wells had oil cuts greater than 2% and
only 6 wells had oil cuts greater than 10%. Currently, 81% of the wells have oil cuts greater than
2% and the number of wells with an oil cut greater than 10% has doubled to 12 wells.
Table 4: Oil cut response in the Mannville B pool.
Injection Performance and Data
The target injection rate for the Mannville B pool is 3300 m3/d but it is only since April 2007
that this target rate has been achieved for an extended period (Figure 4), mostly due to nontechnical reasons. First the ASP transfer line has to be shut down for 3 days. The pipeline did
not fail (it is lined) but there was a leak in the liner on the stub end where the liner fused to the
flange. This likely occurred during liner installation due to the load placed on the liner prior to
fusion. Next a Force Majeure was declared by the surfactant manufacturer in October 2006 due
to a Force Majeure that was declared by a raw material supplier for the surfactant. Fortunately
the surfactant supplier was able to maintain 50% of the normal deliveries and there was a high
level of inventory on Husky’s site and in transit. Injection rates were decreased to 3000 m3/d in
October and then to 2500 m3/d in December before returning to 3300 m3/d in early February
2007. On February 21, 2007, the caustic manufacturer declared Force Majeure due to the CN
rail strike. Injection rates had to be reduced to 2500 m3/d again until mid March when the rail
strike ended. Average wellhead injection pressure decreased from 14 MPa before ASP injection
to 9 MPa when new injection wells were tied in and added to the injection scheme. As a higher
viscosity fluid is injected further into the reservoir, the injection pressure has steadily increased
to the current average injection pressure of 13.5MPa. There have also been corresponding
injection pressure decreases when total injection rates were decreased. Injection rates at the
wells can not be controlled using chokes as pressure drop shears the polymer reducing solution
viscosity in the reservoir. In April 2007, timers were installed on injection wells so that fluid is
only injected for a certain length of time each day which has also increased injection pressures
recently. In addition, producing wells are sped up or slowed down to ensure chemicals are
placed in the reservoir efficiently and performance is maximized. Injectors have been divided
into groups shown in Table 5, each group with a separate injection pump.
Table 5 – Injection well groups.
Group A
Group B
2/3-9
0/8-9
2/9-9
0/11-9
0/3-16
Husky Oil Operations Limited
0/2-16
3/7-16
0/14-16
Group C
2/13-16
2/5-21
2/9-20
Group D
3/16-20
0/1-29
2/2-29
Page 6 of 16
2/10-29
2/15-29
3/11-29
4/6-29
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Even though the average injection pressure is 13.5 MPa, injection pressures in each group varies.
In May 2007, the average injection pressure for Group A is 16 MPa, Group B is 9 MPa, and
Group C & D are 13 MPa. Injection group and individual well information is included in tabular
and chart format in electronic Attachment #2 – Monitoring - Warner Injection Rates DOE 2007.
18.0
4500
17.0
4000
16.0
3500
15.0
3000
14.0
2500
13.0
2000
12.0
1500
11.0
Field Inj Rate
Field Inj Pressure
Avg Inj Press
Avg Inj Rate
1000
500
Injection Pressure (MPa)
Injection Rate (m³/d)
Inj Rate and Pressure
5000
10.0
9.0
20/Jun/07
2/Dec/06
12/Mar/07
Date
24/Aug/06
16/May/06
5/Feb/06
28/Oct/05
8.0
20/Jul/05
0
Figure 4: Taber South Mannville B pool injection rates and average wellhead pressure
The pool was divided into 7 areas (Figure 5)
for performance monitoring purposes and
efforts are continuously being made to ensure
the best possible distribution of injection
fluids and VRR in each area and that both
production and injection rates are optimized.
Voidage Replacement Ratio
Cumulative VRR by area ranges between 1.18
and 0.77 with an average of 0.972 (Figure 6
and Table 6). Efforts are being made to
increase injection into the low cumulative
VRR areas (3 and 4) to above 1.0 and reduce
injection into the high cumulative VRR areas
(1 and 6) to just below 1.0 by adjusting
individual well injection targets as well as reallocating injection pump outputs. Excessive
ASP fluid has been injected into areas 6, but
the total over injection is expected to be small
due to its small pore volume.
Husky Oil Operations Limited
Page 7 of 16
Figure 5: Warner Region Map
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Warner ASP - VRR by Area
1.6
1.4
1.2
VRR
1.0
0.8
0.6
0.4
0.2
0.0
Cum
May-07
Apr-07
Mar-07
Feb-07
Jan-07
Dec-06
Nov-06
Oct-06
Sep-06
Aug-06
Jul-06
Jun-06
May-06
MM-YY
Area 1 (Sec 9 - S)
Area 2 (Sec 9 - N)
Area 3 (Sec 16)
Area 4 (Sec 21 - S)
Area 5 (Sec 21 - N & Sec 20)
Area 6 (Sec 29 - E)
Area 7 (Sec 29 - W)
Pool Total
Figure 6: Warner Voidage Replacement Ratio by Area
Table 6: Mannville B Pool VRR
VRR by Area - Warner ASP
AREA
4
1
2
May-06
Jun-06
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Cum
1.148
1.002
0.849
0.910
0.888
1.035
0.776
0.822
0.761
0.859
0.831
0.825
0.834
0.889
0.606
0.533
0.764
0.946
0.845
1.207
1.293
1.223
0.979
0.868
0.972
1.142
1.250
0.918
1.453
1.274
1.344
1.110
0.956
0.839
0.814
0.722
0.744
0.889
0.938
0.918
0.888
0.939
0.447
0.650
0.977
1.033
0.859
0.884
0.818
0.928
0.885
1.012
0.968
0.977
0.834
0.881
% PV Inj
% Target
% Pool Cum
Injected
25.7
85.7
6.5
17.9
59.7
13.4
11.5
38.2
26.0
12.4
41.2
15.9
PV, m3
30% PV, m3
% Total
3
5
Total
Pool
6
7
1.117
1.160
0.939
1.227
1.244
1.182
1.294
1.509
1.216
1.241
1.202
1.242
1.004
1.185
1.221
1.214
1.082
0.923
0.917
0.898
0.892
1.042
1.008
1.261
1.248
1.154
1.062
1.064
0.029
0.314
0.722
1.124
1.043
0.846
0.739
0.668
0.744
0.684
0.818
0.793
0.805
0.767
0.933
0.892
0.975
1.056
0.967
0.968
0.946
0.958
0.908
0.985
1.005
1.022
0.940
0.969
16.3
54.2
24.3
40.9
136.3
7.6
17.1
57.1
6.2
15.1
50.5
100.0
300,512 880,439 2,680,000 1,520,000 1,760,000 219,653 429,756 7,790,360
90,154 264,132
804,000
456,000
528,000
65,896 128,927 2,337,108
3.9%
11.3%
34.4%
19.5%
22.6%
2.8%
5.5%
100.0%
Husky Oil Operations Limited
Page 8 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Composition of Production Fluid
Each production well is sampled monthly and detailed analysis of the water is preformed by a
laboratory and reviewed internally to monitor if there is a change in the properties of the
produced fluid. Areas of the Mannville B pool are monitored and detailed produced water
analysis are provided in electronic Attachment #3 - Monitoring Warner Produced Water
Analysis DOE 2007 including composition, TDS, density, pH, and polymer concentration. ASP
flood performance to the end of May 2007 in terms of produced water polymer concentrations
and produced water pH levels is described in this report.
Produced water polymer production:
Warner ASP - Average Polymer Concentration by Area
600
Polymer Concentration, ppm
500
400
300
200
100
0
May-07
Apr-07
Mar-07
Feb-07
Jan-07
Dec-06
Nov-06
Oct-06
Sep-06
Aug-06
Jul-06
Jun-06
May-06
MM-YY
Area 1
Area 2
Area 3
Area 4
Area 5
Area 6
Area 7
Figure 7: Average produced polymer concentration by area
Polymer production essentially started in September 2006, about 3.5 months after ASP injection
started. Currently only 2 wells are producing polymer in areas 3 and 4. In the other areas, 4 to 5
wells are producing polymer. The number of wells producing polymer appear to be influenced
by the level of pore volume (PV) injected and the inter-well distances. Polymer concentration in
the produced water ranges between 100 ppm in area 3 to about 450 ppm in area 2 with a typical
concentration of about 300 ppm. Polymer concentration levels in the produced emulsion have
been increasing steadily since first appearing in September 2006 as expected.
Husky Oil Operations Limited
Page 9 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Table 7: Well count of oil producers with presence of polymer in produced water
Polymer Producing Well Count - Warner ASP
Area 1
May-06
Jun-06
Jul-06
Aug-06
Sep-06
Oct-06
Nov-06
Dec-06
Jan-07
Feb-07
Mar-07
Apr-07
May-07
Area 2
0
1
2
1
2
2
3
3
3
6
6
5
5
Area 3
0
0
0
2
3
4
5
4
4
4
4
4
5
Area 4
0
0
0
0
0
0
0
1
1
2
2
3
2
Area 5
0
0
0
0
0
1
1
1
1
1
1
1
2
Area 6
0
0
0
0
0
3
4
4
4
5
5
5
5
Area 7
0
1
2
1
2
4
3
3
4
5
4
4
4
Total
0
2
0
2
2
2
6
5
5
5
5
6
5
0
4
4
6
9
16
22
21
22
28
27
28
28
Produced water pH:
Due to caustic injection, pH of produced water is expected to increase. From the pre-ASP base
pH level of 8.0, pH levels have increased to about 9.0 (Figure 8). In areas 2 and 5 the average
pH is 9.5 but the pH still remain at below 8.5 in areas 3 and 4. In area 7, pH levels were at 9.5
for a few months due to excessive injection at one injector, but have declined to just above 8.5
after the injection rates were successfully reduced to the target rate.
Warner ASP - pH by Area
10.0
9.5
pH
9.0
8.5
8.0
7.5
7.0
May-07
Apr-07
Mar-07
Feb-07
Jan-07
Dec-06
Nov-06
Oct-06
Sep-06
Aug-06
Jul-06
Jun-06
May-06
MM-YY
Area 1
Area 2
Area 3
Area 4
Area 5
Area 6
Area 7
Figure 8: Average produced water pH by area
Husky Oil Operations Limited
Page 10 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
The chemical analysis data of the produced water to date has confirmed that the ASP chemical
system being used in Warner is excellent and that it is working in the reservoir as designed.
Composition of the Injection fluid
Injection is monitored daily to ensure the correct concentration of ASP is injected in the
reservoir. The fluid viscosity as measured at the plant and at a B pool injection well in each
region. Values range between 20-26 cp with screen factors equal to 55-65. There is very little
difference between the values at the plant and at the injection wells. During initial design
meetings there was a concern that the polymer would degrade after being pumped through up to
20 km of pipeline but this was not observed. Figure 9 shows daily fluid composition and
viscosity.
Warner ASP - Injection Fluid Chemical Concentration
(Targets: 1200 ppm, 20~26 cp, 0.75 wt%, 1.5 wt%)
Polymer @ Plant( ppm), Viscosity (cp), NaOH (wt%), Surfactant(wt%)
10000
1000
100
10
1
0.1
0.01
6/29/07
6/15/07
6/1/07
5/18/07
5/4/07
4/20/07
4/6/07
3/23/07
3/9/07
2/23/07
2/9/07
1/26/07
1/12/07
12/29/06
12/15/06
12/1/06
11/17/06
11/3/06
10/20/06
10/6/06
9/22/06
9/8/06
8/25/06
8/11/06
7/28/06
7/14/06
6/30/06
6/16/06
6/2/06
5/19/06
MM/DD/YY
Polym er, ppm
Viscosity @ Etzikom , cp
NaOH, w t%
Polym er Vis @ Warner, cp
Surfactant, w t%
Figure 9: ASP injection fluid composition
Pilot Economics to date
A description of the project costs was provided in the last annual report. Capital, operating costs
and production are all very close to the values presented in the economics in 2006. The project
started May 2006 and approximately 23 103m3 of incremental oil has be produced to date which
was forecasted. The expected revenue, capital, operating costs, and royalties are included in
Husky Oil Operations Limited
Page 11 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Appendix A – IETP Project Economic Tables in the same format as the March 2005 IETP
application. The final capital cost is expected to be $71.6 million, or one million dollars above
AFE estimates as shown in Table 8.
Table 8: Comparison of actual costs to original estimates
Operating costs
Operating costs as presented in the IETP tables in the June 2006 Annual report last year were
budgeted to be $981 M in 2006. Since May 2006 when ASP injection began, actual incremental
operating costs in 2006 were $985M (Table 9). In the updated pilot economics submitted as part
of the indicated operating costs in 2007 will be $1 700M, slightly higher than the annualized
costs from 2006 due to increasing oil production rates
Husky Oil Operations Limited
Page 12 of 16
Annual Report – June 2006
Innovative Energy Technologies Program
Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Table 9: Warner ASP 2006 Incremental Operating Costs.
Facilities
A description of the major capital items was provided in the June 2006 Annual Report.
Operational Issues – Facilities
The ASP facility has operated quite well to date. The water treating, chemical preparation, and
ASP solution blending processes are operating without major issues. The main problems that
have occurred are related to the final ASP injection part of the process, specifically, the 11.4 km
distance between the ASP plant at 6-13-6-17W4 and the injection satellite at 11-16-7-16W4.
Two low pressure transfer pumps located at the ASP plant pump ASP injection fluid to 4 high
pressure pumps located at 11-16. Some difficulties were experienced after the facility was down
(power fail, planned shut down, etc) and was started up again. One issue is that there have been
seal leaks on the transfer pumps caused by a high suction pressure. While starting the transfer
pumps, the fluid is recycled through the first pump while waiting for the suction pressure at 1116 to reach the minimum pressure permissive to start the high pressure injection pumps. To
rectify the problem a few sequence changes were made:
1. Originally, the second transfer pump started after the first pump was transferring 1800
m3/d fluid and the same RPM as the first pump. The sequence was modified to start
when the first ASP transfer pump was at a rate of 500 m3/d, started at a slower speed than
the first pump and radually ramped up.
2. Changed the start up sequence at 11-16 and also slowed the VFD start time down.
a. The first pump with target injection rate of 1000 m3/d starts
b. The second pump with target injection rate of 600 m3/d starts
c. The third pump with target injection rate of 1000 m3/d starts
d. The fourth pump with target injection rate of 700 m3/d starts
Also, when injection wells opened or closed on timers, the discharge pressure changed which
originally caused some operational problems.
The other main issue was at 11-16. All 4 motors had to be replaced in the first year. One motor
was balanced incorrectly and failed due to excessive vibrations but all eventually failed. The
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Taber S Mannville B Alkaline-Surfactant-Polymer Flood
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manufacturer’s recommendation was to insulate the housing to protect the bearings but this was
not done. The housing were insulated when the motors were repaired and to date there haven’t
been any problems. Husky is also investigating the electrical design of the power to the pumps.
Specifically there is a review of the loads that were put on the pumps.
.
Operational Issues - Wells
The main issue is controlling the volume of fluid that is injected into each injector. Timers and
actuated valves have been installed to help achieve established targets. The operators manually
set the timer clock and continually adjust the length of time the injector is shut in until the target
is achieved.
A reverse PCP pump has also been ordered to test at one injection well. The objective is to
increase the injection rate in a low injectivity well and increase the control of the well so that the
target rate can be achieved.
Scale has been observed on the stator of four producing wells: 102/14-16-7-16W4, 100/10-9-716W4, 104/10-29-7-16W4, and 100/13-29-7-16W4. Production problems seem to correlate
with the presence of polymer in the produced water but these are the only wells with scale
problems even though 28 wells have evidence of polymer in the produced fluid. The issue will
be monitored but may not be as widespread as originally feared. 102/14-16 and 0/10-9 are high
volume wells (greater than 200 m3/d fluid) with foamy oil. Since de-foam was started in
December 2006, there have been less problems. Therefore, part of the problem may have been
producing the well with too low of fluid level. When the tubing for 00/13-29 was pulled it was
described as looking like a honeycomb. After analysis of the scale it was determined it was a
mixture of sand and polymer. Sand production is not common in this reservoir so this type of
scale is not expected to be a problem for the remaining wells but again, will be monitored
because the potential implications would be severe it all producers experience this problem. The
scale from 2/14-16 is being analyzed and a recommendation for inhibiting the scale is currently
being developed by Core labs and Baker Chemical. To date, acid, benzene, bleach, and xylene
have been tried in the laboratory with no positive results.
Environmental/Regulatory/Compliance
Regulatory
A Conservation and Reclamation Study was completed for the ASP Transfer Lines from Warner
to Etzikom and from Etzikom to the Injection Satellite. A post-construction reclamation
assessment was conducted in August 2006 on 15.1 km of right-of-way to ensure construction
practices were conducted accordingly. This included evaluation of slumping and erosion,
monitoring for weed populations, topsoil depths, subsoil salinity, and the identification of any
problem areas. The conclusion of the report, issued in November 2006, was that “…pipeline
construction practices were adequate to achieve appropriate reclamation success in the first
growing season following construction.”1 In 2008, a Land Capability Assessment will be
conducted to compare the land capability and vegetation success following pipeline reclamation
along the pipeline ROW compared to off the ROW.
1
Husky Warner-Etzikom Pipeline Post-Construction Monitoring Project, Golder Associates Ltd., November 2006
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Taber S Mannville B Alkaline-Surfactant-Polymer Flood
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The injection wells were approved under Directive 51 with a Maximum Wellhead Injection
Pressure of 16 200 kPag. No injection wells have exceeded this pressure. Average injection
pressure is currently 13 500 kPag. The project received Directive 65 Approval (Approval
10418B) to inject ASP into the Taber South Mannville B pool with the following requirements:
 The ASP solution will be 0.75wt% NaOH, 0.15wt% surfactant, and 0.12wt% polyacrylamide
polymer
 The polymer solution will be polyacrylamide polymer between 0.06 and 0.12 wt%.
 ASP injection will be not less than 2480 103m3 followed by not less than 2480 103m3
polymer solution
 Must maintain a VRR = 1.0 on a project basis
 Shall target a VRR = 1.0 on a monthly basis
 Monthly sampling of produced water to determine ASP breakthrough
 Presentation to the EUB required annually with the first to occur before June 30, 2007.
Husky is satisfying the requirements of Directive 65.
Environment and Safety
Husky has a management system that contains elements such as auditing, incident reporting,
contacting residents, and site maintenance. Issues identified comprising of these elements will
be managed and acted on appropriately.
Shut down and Environmental Clean Up
The facility will be in operation until at least 2010. Reclamation of the ASP Plant and injection
site will meet all Alberta Environment requirements. At the time of abandonment a Phase I
Environmental Assessment will be completed. If any issues are identified following this, a Phase
II Environmental Assessment will be completed. Remediation will be conducted if necessary.
The site will be reclaimed and a Reclamation Certificate will be applied for.
Future Operating Plan
Injection and production rates are continually being monitored and adjusted to meet targets.
Targets will be review regularly as additional production results and produced water analysis are
obtained. 30% pore volumes (PV) of injected ASP fluid is expected to achieved by June 2008
followed by 30% PV of polymer only solution. It is estimated this will occur by the end of 2010.
Husky is currently reviewing the economics of injecting greater than 30% PV polymer solution
which could mean the plant is in operation for as many as 3 more years. In light of this, the
salvage value of the facility has not been determined.
Conclusions
Although there were many challenges designing the plant due to the available human and capital
resources in the industry, ASP start-up went smoothly and the facility is effectively treating and
softening the produced water. Alkali, surfactant, and polymer are being blended in correct
concentrations. Dedicating one pump to one region of the reservoir is proving to be a cost
effective method of controlling injection rates without using well chokes that would shear
polymer. The installation of timers on injection wells has improved control significantly.
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Taber S Mannville B Alkaline-Surfactant-Polymer Flood
(Warner ASP Flood)
Husky is pleased with the project to date as it is on budget for oil production, operating costs,
and capital costs. Demonstration that the technology is working is observed through water
analysis and oil cut changes of oil production wells. The oil production rate is currently 150m3/d
which is above the 33 m3/d the pool would have had if the ASP project was not implemented.
The results are encouraging but the December 2007 target oil rate is 289 m3/d and the peak
forecast oil production rate in June 2010 is 519 m3/d. There is still a long way to go before the
technology can be proven. Although only 23 103m3 (0.14 MMBO) incremental oil has been
produced to date, representing only 2% of the final incremental oil volume forecast, the project is
on trend to achieve incremental oil production due to ASP flooding between 700-1000 103m3
(4.4 to 6.3 MMBO).
The fact remains that there are very few enhanced oil recovery methods for medium crude oil
reservoirs after waterflooding despite the fact that a sizable target of oil remains trapped in the
reservoir. The advantage with tertiary recovery, compared to exploration, is that the target is
often known to a high degree of certainty. The challenge is to understand the technical risk of
this tertiary recovery process.
Husky and the Alberta Department of Energy have invested resources to increase understanding
of ASP technology in anticipation of a successful project. Interest in the technology has
increased over the last year as demonstrated through increased products from chemical vendors
and the announcement of a junior oil and gas company that will be implementing an ASP flood
in a southern Alberta reservoir in the second quarter of 2008. This is very encouraging news as
greater application of ASP flooding will help develop new technologies.
Husky intends to continue to technically and economically advance the process to help justify
additional ASP floods in suitable reservoirs in Alberta by increasing oil recovery and reducing
costs through facility optimization and ASP chemical system improvements.
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Annual Report – June 2006