Husky Oil’s Hot Water Vapour Process (HWVP)

Field Trial Project

Final Technical Report for the SPRI Program (Saskatchewan Petroleum Research Incentive)

March 26, 2014

Table of Contents Table of Figures .

Introduction...................................................................................................................................................1

History of HWVP Technology Project ............................................................................................................ 1

BasicHWVP Technology Overview................................................................................................................ 1

ProjectSite Overview.................................................................................................................................... 2

Table 1: Reservoir Data for Husky Big Gully 10-4-50-24 ........................................................................... 2

Table 2: Fluid Data for Husky Big Gully 10-4-50-24................................................................................... 3

SurfaceEquipment Design ............................................................................................................................ 4

InjectionPhase - Cycle 1............................................................................................................................... 5

ProductionPhase - Cycle 1 ........................................................................................................................... 7

Table 3: Gas Sample Overview - Cycle 1................................................................................................... 8

InjectionPhase - Cycle 2............................................................................................................................... 8

ProductionPhase - Cycle 2 ......................................................................................................................... 10

Table 4: Gas Sample Overview - Cycle 2................................................................................................. 11

Table 5: Oil Sample Overview - Cycle 2 .................................................................................................. 12

ConcludingComments ................................................................................................................................ 12

Table of Figures Figure 1: Primary Production Chart........................................................................................................ 3

Figure2: General Process Flow.............................................................................................................. 4

Figure3: Site Photo .................................................................................................................................. 5

Figure 4: Injection Cycle I �Annular Measurements..........................................................................6

Figure 5: Injection Cycle 1 - Downhole Measurements...................................................................... 7

Figure 6: Production Cycle I - Production over Time......................................................................... 8

Figure 7: Injection Cycle 2 �Annular Measurements..........................................................................9

Figure 8: Injection Cycle 2 - Downhole Measurements....................................................................10

Figure 9: Production Cycle 2 - Production over Time.......................................................................11

Introduction In April 2012, Husky and the Government of Saskatchewan signed a project agreement under the

Saskatchewan Petroleum Research Incentive (SPRI) program. The agreement #7405-32 was assigned for

the project entitled Husky Heavy Oil: Hot Water Vapour Process Pilot. This pilot was designed to field

test the Hot Water Vapour Process (HWVP) technology.

This is the final technical report submitted by Husky in accordance with the SPRI project agreement.

Under the agreement a final technical report is to be submitted by March 30, 2014 and will address the

information outlined in Appendix A: Description of the Project.

As per Appendix A of the project agreement:

"The Technical report will provide a detailed summary of the pilot project, its operation (items

indicated in the Project monitoring section above), and results. The report will discuss Husky’s finding,

state any conclusions and report on the success of the project."

History of HWVP Technology Project The Hot Water Vapour Process was first proposed in a report issued by PTAC (Petroleum Technology

Alliance Canada) in 2008 and titled "Novel Low GHG Heavy Oil Recovery Process". The report describes

the opportunity and technical challenges of increasing heavy oil recovery in the Lloydminster are oil

fields. After reviewing a number of potential enhanced oil recovery approaches that had or could be

tried, the report suggests designing and testing a novel EOR process that was called at the time "Flue

Gas and Steam Stimulation". The process has since been re-named HWVP and was further described in

subsequent PTAC reports to industry sponsors.

In 2010 a consortium was put together to field test the HWVP technology. In 2011 the consortium was

finalized and funding agreements were signed. The consortium consists of: PTAC, PTRC (Petroleum

Technology Research Centre), Devon Canada, and Husky Oil Operations Limited (Husky). Husky was

thereafter retained as the main contractor for the project.

In March 2011 the well (10-04-050-24W3) was selected for the field test. Construction of the facility

began in October 2011. First injection into the well was on March 21, 2012. The production phase for

the first cycle started on July 13, 2012 and ended on December 22, 2012. The second injection phase

began July 9, 2013. The production phase for the second cycle ran from September 27, 2013 to

December 31, 2013.

Basic HWVP Technology Overview In thin heavy oil producing areas there is no proven enhanced oil recovery technology. In the

Lloydminster area most of the heavy oil production uses a process known as CHOPS (Cold Heavy Oil

Production with Sand). The CHOPS process encourages the production of sand from the reservoir which

results in streaks of high permeability in the reservoir which are commonly referred to as wormholes.

The CHOPS process has allowed for greater economic production in the region, but it is generally

accepted that only 10% of the PIIP (Petroleum Initially In Place) will be recovered. As a result new

technologies are required to increase the recovery factor in thin heavy oil reservoirs.

The core idea of HWVP technology is the injection of a non-condensable gas (NCG) together with hot

water vapour (in other words relatively low temperature and pressure steam) into heavy oil formations.

HWVP generates hot water vapour using surface facilities and uses an available NCG (nitrogen for this

test) to carry it into the formation. By utilizing the HWVP technology in a CHOPS well, we can take

advantage of the wormholes (high permeability trends) in the reservoir to more efficiently deliver the

hot vapour deeper into the reservoir. HWVP is therefore a thermal stimulation technology to be used

for EOR in heavy oil reservoirs partially depleted by primary recovery. The thermal energy is conveyed

to the reservoir by the enthalpy of evaporation of the water vapour. This thermal energy raises the

temperature of the stimulated zone and reduces the heavy oil viscosity.

A non-condensable gas is required to carry the water vapour as the temperature/ pressure operating

envelope is outside the steam envelope. The non-condensable gas has the added benefit of raising the

currently depleted reservoir pressure towards initial reservoir conditions. The combination of hot water

vapour combined with a non-condensable gas as an injection fluid has not been previously used. The

injection fluid will provide incremental oil as this technology is to be used with wells which have no

remaining primary reserves.

Project Site Overview The well that was selected for the testing of the HWVP technology is located at 10-04-050-24W3M. The

well was rig released on January 3, 1997. It was initially completed in the GP and then Sparky

formations prior to being completed in the McLaren formation, which is the formation that was tested

with the HWVP. Table 1 below details the reservoir parameters for the McLaren formation in the 10-04-

050-24W3M well.

Table 1: Reservoir Data for Husky Big Gully 10-4-50-24

Well 11/10-04-050-24W3/C

Formation Lower McLaren

Net Thickness 1 m

Porosity 33%

SW 25%

OOIP (1 LSD) 39,600 m 3

OOIP (9 LSD) - 1 Lsd

surrounding 10-4

475,200 m 3

Initial Reservoir Pressure 3,500 kPa - average for area

Reservoir Pressure at end of

Primary Production

1000 kPa

Page 2

The fluid properties of the reservoir are included in Table 2.

Table 2: Fluid Data for Husky Big Gully 10-4-50-24

Well 11/10-04-050-24W3/C

Formation Lower McLaren

Density @ 15 °C 977.8 kg/M 3

Density - API 13.10 API

Viscosity @ 20 °C 7,710 cP

Viscosity @ 50 °C 557 cP

In July 2001 11/10-04-050-24W3 was completed in the McLaren formation. Initial rates from the

McLaren were: 8.4 rn 3 opd and 0.9 rn 3 wpd. 11/10-04 continued to produce from the McLaren

formation until December 2004. The well was then shut-in after cumulative production of 7,185 m 3 oil

and 1,314 m 3 water from the McLaren. Final rates (3 month average) at shut-in were 2.2 m 3 opd and 0.4 m wpd. A plot of the primary production rates for the McLaren is shown in Figure 1.

Figure 1: Primary Production Chart

Primary Production Chart: 10-04 12.0 12.0

10.0 A Cumulative Oil Production: 10.0

7,185m3

Cumulative Water Production:

8.0 1,314 rn3 8.0

i 6.0 -----i 6.0

C 0

4.0 4.0 -

2.0 - 2.0

0.0 0.0 May-2001 Nov-2001 May-2002 Nov-2002 May-2003 Nov-2003 May-2004 Nov-2004 May-2005 Nov-2005 May-2006 Nov-2006

�*�Daily Oil Rate (m3/d) � 4146-Daily Gas Rate (e3m3/d) �X--Daily Water Rate (m3/d)

Page 3

Surface Equipment Design The surface facility that was put in place for the HWVP test consisted of a number of pieces of

equipment. The general process flow of the equipment is shown on the following page in Figure 2 along

with a picture of the equipment in the field in Figure 3. Fresh water was brought to site from one of

Husky’s thermal projects and stored in a 1000 bbl tank where it was pre-heated. A Husky owned

Nitrogen Generation plant was on site and produced Nitrogen through a membrane technology. The

pre-heated fresh water and Nitrogen were mixed in a static mixer and then sent through a line heater to

bring it up to temperature (120� 140 °C). The heated water vapour and Nitrogen mixture was then sent

through a water separator where liquid water was removed and sent back to the storage tank for later

use. The hot water vapour and Nitrogen was injected into the well.

During the production phase of the HWVP test, the surface equipment used consisted of a typical heavy

oil single well battery. This included a hydraulic pumping unit and single production tank. A small pop

tank was placed in-line with the gas vent to ensure no liquids were discharged with the produced

Nitrogen gas.

Figure 2: General Process Flow

HWVP � N2 Unit General Layout

it N2 Water icurto Veil J

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Figure 3: Site Photo

Injection Phase - Cycle 1 The initial injection cycle began on March 21, 2012. Initial injection rates were set at 23 e3m3/d

Nitrogen, 2.5 m3/d water, at a line heater temperature of 185 °C. The well was responding as expected

(annular pressure and temperature were slightly elevated) when injection had to be shut down due to a

vibrational issue in the surface equipment on March 29, 2012. A decision was made to shut down

injection until this issue was resolved in order to ensure safe of operational staff and to maintain

equipment integrity.

Once the vibrational issue was resolved with the surface equipment, the well was placed back on

injection on May 23. During this part of the injection cycle the annular temperature rose quicker than

was predicted from the numeric simulations. Work was done to understand this phenomenon and it

was determined that a small amount of liquid water was in the annular space. Attempts to blow this

water to surface were unsuccessful. A well workover was conducted on June 9 to blow the water into

the formation and this drastically reduced the annular temperature for the duration of the injection

cycle. The annular temperature and pressure during the injection phase is shown in Figure 4.

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Figure 4: Injection Cycle I - Annular Measurements

Annular Pressures and Temperature 80 3000 -- -------- ---

- -----

I 2500 ------ ------ -------- -------- -------------- ---

- 6C

2000 ----- - --------------------- -------------------------- -

OW

CL

I::: I L L

500

:° 0 - -- _____________ ________- 03/19/12 33131/12 04/12/12 04/24/12 05/06/12 05/18/12 05/30/12 06/11112 06/23/12

�Annua Press (kPa): PromorePressi �Anrular Temp (C>: PromoreTempi I

The injection cycle was completed on June 22, 2012 after having injected 85 m 3 cold water equivalent

and 487 e 3m 3 of Nitrogen at an average temperature of 115°C. A maximum downhole pressure of 3269

kPa and a maximum downhole temperature of 136°C was achieved. The downhole temperature and

pressure during the injection phase is shown in Figure 5.

Page 6

Figure 5: Injection Cycle I - Downhole Measurements

HWVP Injection Cycle 1: Downhole Pressure and Temperature - 140 3530

120 30J0

2530 100

2030 30

I- 0 V

60 1530

40 1030

-20 530

- 0 -- S

03/31/12 04117117 04/74/1? 05/06/17 05/13/17 05/30/12 06/11/1? 06/73/12

-Downhole Press (kPa): PromorePress2 -Total In) rate (m3/hr): F1T908 Downhole Temp (C): PromoreTemp2

Production Phase - Cycle 1 After a soak period which allowed the well to cool slightly in order to remove the injection packer. The

well was placed on production on July 13, 2012. A conventional PC pump and rod system was installed

in the well. At the time production was initiated the downhole temperature was 33 °C.

Initial production rates were erratic due to issues with balancing the gas vent rates to ensure fluid in the

well. Production was stabilized on July 22 and the well began to produce steadily until August 20.

Production had been steadily inclining to a rate of 10-1rn 3 fpd with a BS&W of 36%. The net

cumulative production was 95 m 30il and 105 m 3 water. All of the injected water was recovered and

approximately 27% of the N 2 . Table 3, shows the gas composition at various times during the

production cycle. On August 201h the well suddenly lost inflow. A number of well interventions were

then taken to regain production.

After limited success regaining inflow a decision was made to shut-in the well on December 22 nd and to

evaluate the potential for a 2’ cycle of injection.

__________ _______ ______

0 -----

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Table 3: Gas Sample Overview - Cycle 1 Mole Fraction

Date Sampled Nitrogen (%) Methane (%) CO2 (%) 02(%)

21-Jul-12 63.13% 35.76% 0.44% 0.57%

10-Aug-12 56.78% 41.81% 0.46% 0.78%

27-Aug-12 79.01% 18.98% 0.61% 1.23%

3-Nov-12 21.78% 77.21% 0.62% 0.12%

Total net production from the 1st phase of the HWVP project was 147 m 3 oil (925bbls), 144 m 3 water

(902 bbl), 13 m 3 solids, and 142 e 3m3 N 2 . Figure 6 shows the well production during the production

phase.

Figure 6: Production Cycle I � Production over Time

10-04 Production Plot - Time 14.0 700

12.0 -

500 .10.0 ----------------------------- ------------ ----------

E a,

E m

400

a,

C o

I II C

4.0

NO

sly sp ALA ct’ ’ -’ P .. .

r 4V.. ’.

�Average. fliIyOiI Rate �Average flaily Water Rate �A,gDaiIy N2 cas Rate Remainiflglfljected Gas

Injection Phase - Cycle 2 The second injection cycle began on July 9, 2013. A different injection strategy was used for cycle 2

compared to cycle 1. In order to slow down the pressure build-up and have the heat in the reservoir

Page 8

longer, the injection rate was slowed down to 13 e3m3/d, 3.5 m3/d water, and a line heater

temperature of 185 C.

The well was responding as expected when injection had to be shut dwon on July 13, 2013 due to the

annular pressure increasing. After some exploration and pressure testing of the downhole and surface

equipment, it was determined that a faulty wellhead installation (a bent tubing hanger) was allowing the

pressure to build-up behind in the annulus. The wellhead was repaired and the injection system was put

back online July 22, 2013. Injection was initially stopped Aug 22, 2014 with the well being allowed to

soak. Due to delays in getting a service rig to site, it was decided to inject one more week starting Sept

11-15, 2013. The well was then allowed to soak. The annular temperature and pressure during the

injection phase is shown in Figure 7.

Figure 7: Injection Cycle 2 - Annular Measurements

Annular Pressures and Temperature - 50 4500 -_____________________________________________

r 4000

40 3500

11 3000 - & ______________________________ 30

250O -- U 1 2509

2000

F- 20

1500

_ F 15

1000 in 10

L...4 500 ---- --

5

0 0 --- ------V----

07/05/13 07119/13 08/02/13 08/16/13 08/30/13 09/13/13

I -Annular Press (kPa): PromorePressi -Annular Temp (C): PromoreTempi I

The injection cycle was completed on Sept 15, 2013 after having injected 84 m 3 cold water equivalent

and 665 e 3m3 of Nitrogen at an average temperature of 131°C. A maximum downhole pressure of 3527

kPa and a maximum downhole temperature of 133°C was achieved. The downhole temperature and

pressure during the injection phase is shown in Figure 8.

Page 9

’ 2000

9L 29

0 9 Id 1500

U

3500

3000

2500

1000

500

0 - I I flI� - � - ...j. -__-

1-Jul-13 13-Jul-13 25-Jul-13 6-Aug-13 18-Aug-13 30-Aug-13 11-Sep-13 23-Sep-13

DownhOle Press (kPa): PromorePress2 - Total Inj rate (m3/hr): P11908 - Downhole Temp (C) Promoreiemp2

- -r :llI11 II

’t’ ’3U i1d .iiI

�: I Ut II IIIU1 I

* iii �i I I il I ii #IlI� I I

mr 0 A 4 ’ � .1

�I : :::? It

so

60

40

140

0

120

100

20

*1 CL E

Figure 8: Injection Cycle 2� Downhole Measurements

HWVP Injection Cycle 2: Downhole Pressure and Temperature

Production Phase - Cycle 2 After a soak period which allowed the well to cool slightly in order to remove the injection packer. The

well was placed on production on September 27, 2013. A conventional PC pump and rod system was

installed in the well. At the time production was initiated the downhole temperature was 37 C.

The well began to produce steadily until November 22, 2014 where production started to fluctuate due

to fluctuating casing pressure. Production had been steadily inclining to a rate of 10-12m 3 fpd with a

BS&W of 65%. A number of well interventions were taken to regain production from mid-December

2013 to mid-January 2014. After limited success regaining inflow a decision was made to shut-in the

well on February 20nd, 2014. The net cumulative production was 305 m 30il and 367 m 3 water, 40 m 3

solids, and 239.5 e 3m 3 N 2 . All of the injected water was recovered and approximately 36% of the

N 2 . Table 4 shows the gas composition at various times during the second production cycle. Figure 9

shows the well production during the production phase. Table 5 shows the oil density and viscosity of

three samples taken during this production cycle.

Page 10

Table 4: Gas Sample Overview - Cycle 2 Mole Fraction

Date Sampled Nitrogen (%) Methane (%) CO2 (%) 02(%)

22-Jul-13 96.28% 0.06% 0.26% 3.37%

24-Sep-13 91.26% 3.56% 0.21% 4.76%

1-Oct-13 91.35% 6.51% 0.32% 1.81%

7-Oct-13 84.59% 13.88% 0.45% 1 1.08%

15-Oct-13 78.17% 20.67% 0.45% 0.61%

22-Oct-13 72.89% 25.89% 0.51% 0.59%

14-Nov-13 61.69% 1 36.95% 0.63% 0.54%

29-Nov-13 58.39% 1 40.36% 0.63% 1 0.46%

Figure 9: Production Cycle 2- Production over Time

Cycle 2: 10-04 Production Plot - Time 700 14.0

:: 8.0 400

_____ ________________ 30

’vflhII__ _________ ____ a V VY - _____ 200 40

rTTI t"E :H °° :

,t.

-Average Duly 01 Rite -Average DaityWater Rate -Avg Daily N2 Gut Rite -Remaining Injected 112 Gut

Page 11

Table 5: Oil Sample Overview - Cycle 2

Date Sampled

Density

(kg/M 3)

Viscosity at 20 °C

(cP)

Viscosity at 20 °C

(cP)

07-Oct-13 989.6 7,030 663

15-Oct-13 973.8 5,480 448

22-Oct-13 973.7 5,710 449

Total net production from the both cycles (1st & 2 ) of the HWVP project was 452 m 3 oil (2,843 bbls),

511 m 3 water (3,214 bbl), 53 m solids, and 382 e 3m 3 N 2 .

Concluding Comments The HWVP project is one of the many innovative projects to benefit from the Saskatchewan Petroleum

Research Incentive. Significant learning’s and technological progress have been made as a direct result

of the financial partnership of the Government of Saskatchewan and Husky Oil.

The intent of this project was to demonstrate that the HWVP project could recover sufficient

incremental oil to be viewed as an economically viable EOR technique. Despite achieving the goal of

producing incremental oil (452 m) it was not in sufficient volumes to proclaim the process economically

viable at this time. Continued innovation and refinement of the HWVP technology will be needed to

take this technology to commerciality.

Husky Oil believes there is potential in developing this technology, and the first two cycles of the HWVP are an initial milestone on the economic development of this technology. We hope that the

Government of Saskatchewan shares a similar opinion and will continue to lend the support that has got

this project and technology to where it is today.

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