ATHABASCA OIL CORPORATION - AER€¦ · ATHABASCA 2015 ARTIFICIAL LIFT 21 ARTIFICIAL LIFT o All...

LEISMER D54 PERFORMANCE REPORT

ATHABASCA OIL CORPORATION

April 2019

ATHABASCA 2015

INTRODUCTION

DEVELOPMENT OVERVIEW

SUBSURFACE

o Geoscience

o 4-D Seismic & Monitoring

o Well Design & Instrumentation

o Scheme Performance

o Pilots

o Future Plans

SURFACE OPERATIONS & COMPLIANCE

o Facilities

o Measurement & Reporting

o Facility Performance

o Water Production, Injection & Uses

o Sulphur Production

o Future Plans

o Compliance

2

ATHABASCA 2015

DEVELOPMENT OVERVIEW

PROJECT DETAILS

o First steam September 2010

o Approved processing capacity 40,000 bbl/d

o 6 producing pads

• 35 horizontal well pairs

• 13 infill wells

o 2 approved drainage areas

• Pad 7 spud Q4 2018, first steam summer 2019

• Pad 8 approval received September 2018

INFRASTRUCTURE

o Fuel gas from TransCanada Pipeline (TCPL)

o Dilbit export to Enbridge Cheecham Terminal

o Diluent supply from Enbridge Cheecham Terminal

3

4 AOC Lease AreaDevelopment AreaPad Drainage AreaPad Drainage Area (Not on Production)Planned and Approved Drainage AreaSAGD Well-PairInfill Well

SUBSURFACEGEOSCIENCE OVERVIEW

ATHABASCA 2015

Pad 7 Observation WellCored WellImage Log(HMI) Well

4 AOC Lease AreaDevelopment AreaPad Drainage AreaPad Drainage Area (Not on Production)

SURFACE DATA OVERVIEW 5

NO NEW GEOSCIENCE DATA ACQUIRED DURING THE REPORTING PERIOD

o Cores, petrophysics, geomechanical, fracture pressure or caprock integrity tests

Area Area (km2) Cored Wells Image Logs

Lease Area 326 369 621

DevelopmentArea

37.4 144 240

ATHABASCA 2015

STRATIGRAPHY AND REFERENCE WELL 6

De

pth

(m

SST

VD

)

100/09-33-078-10SEISMIC

PEAK

TROUGH

HIGH

LOW

GR

RESISTIVITY

HIGH

LOW Wabiskaw

McMurray

GBIP Top

GBIP Base

Devonian

Left-Gamma Ray

Right-Resistivity

SandSandy IHSMuddy IHSMudstoneLimestone

FACIES

4 AOC Lease AreaDevelopment AreaPad Drainage AreaPad Drainage Area (Not on Production)Type Well (00/09-33-078-10W4)SAGD Well-PairInfill Well

ATHABASCA 2015

4 AOC Lease AreaDevelopment AreaPad Drainage AreaPad Drainage Area (Not on Production)Type Well (00/09-33-078-10W4)

BITUMEN PAY CLASSIFICATION: GBIP 7

ELEVATION RANGE

o 202 -241 masl

GROSS BITUMEN IN PLACE (GBIP)

o GBIP represents the total pay interval accessible via SAGD

o Petrophysical criteria:

• Gamma Ray (GR) = 40 ohm-m

• Porosity (DPSS) >= 27%

o Non-Non-reservoir lithofacies (F6–F7) are not included if greater than 2m in thickness

ATHABASCA 2015

BITUMEN PAY CLASSIFICATION: DBIP 8

ELEVATION RANGE

o 202 -237 masl


DEVELOPABLE BITUMEN IN PLACE (DBIP)

o DBIP has the same petrophysical properties as GBIP but is restricted to higher quality lithofacies:

• F1: Shale-Clast Breccia (if

ATHABASCA 2015

27.1m 24.8m 28.2m 24.5m

31.2m 27.3m

A’AWABISKAW

MCMURRAY

GBIP TOP

GBIP BASEBOTTOM

WATER TOP

DEVONIAN

WABISKAW

MCMURRAY

GBIP TOP

GBIP BASEBOTTOM WATER TOP

DEVONIAN

PADS 1-6 STRUCTURAL CROSS SECTION N-S 9

A A’

Wabiskaw

McMurray

GBIP Top

GBIP Base

Devonian

PEAK

TROUGH

Left - Gamma Ray

Right - Resistivity

HIGH

LOW

GRRESISTIVITY

HIGH

LOW

Development AreaPad Drainage AreaPad Drainage Area (Not on Production)

Cross Section WellSAGD Well-PairInfill Well

A

A’

ATHABASCA 2015

TOP STRUCTURE MAP 10

Elevation Range 202 -241 masl


ATHABASCA 2015

BASE STRUCTURE MAP 11



ATHABASCA 2015

BOTTOM WATER THICKNESS MAP 12



ATHABASCA 2015

TOP GAS THICKNESS MAP 13

M. McMurray Gas

Elevation Range 221-253 masl

MINIMAL GAS THICKNESS AND LIMITED DISTRIBUTION WITHIN DEVELOPMENT AREA


ATHABASCA 2015

GEOMECHANICS

2018

o No new caprock core, mini-frac or tri-axial testing completed during the reporting period

HISTORICAL

o Caprock defined as the Clearwater Formation

• Includes regionally continuous shale of the Wabiskaw Member

• mini-frac tests completed at two locations (01-04-079-10W4, 01-28-078-10W4)

o Approved maximum operating pressure is 5,500 kPag

o All injectors operating at ~ 3,000 - 3,300 kPag

SURFACE HEAVE MONITORING

o No new data acquired during reporting period

14

Development AreaPad Drainage AreaPad Drainage Area (Not on Production)Mini-Frac LocationSAGD Well-PairInfill Well

ATHABASCA 2015

GBIP RESERVOIR PROPERTIES 15

RESERVOIR PROPERTIES

o Original Reservoir Pressure: 2,300 to 2,600 kPa

o Original Reservoir Temperature: 14⁰C

o Average Horizontal Permeability: 5 to 6 D

o Average Vertical Permeability: 4 to 5 D

o Depth: 410 to 444 m TVD (-230 to -216 m subsea)

4 AOC Lease AreaDevelopment AreaPad Drainage AreaPad Drainage Area (Not on Production)

SUBSURFACE4D SEISMIC & MONITORING

ATHABASCA 2015

SEISMIC ACQUISITION HISTORY 17

2009 4D Seismic (Baseline)2012 4D Seismic2013 4D Seismic

2014 4D Seismic 2015 4D Seismic2016 4D Seismic

4 4

2018

o No new data acquired during the reporting period

HISTORICAL

o Q1 2016: 2.0 km2 first 4D survey for Pad 5

o Q1 2015: 9.0 km2 3D survey

• Third 4D repeat survey (2.2 km2 active SAGD Pads 1 & 2)

• Repeat 3D seismic for higher resolution data

o Q1 2014: 2.1 km2 4D survey (active SAGD Pads 3 & 4)

o Q1 2013: 4.5 km2 3D survey

• Second repeat survey (4.9 km2 of active SAGD Pads 1– 4)

o Q1 2012: 8.6 km2 3D survey

• First 4D survey (4.9 km2 of active SAGD Pads 1–4)

• New baseline survey for Pads 5 and 6 (3.7 km2)

o Q1 2009: 4.9 km2 baseline survey (pre-steam) Pads 1–4

ATHABASCA 2015

RESERVOIR SATURATION LOGGING 18

2018

o RSTs acquired from 13 wells during the reporting period

HISTORICAL

o Baseline acquired in 2010 - 23 wells

o 2011 - 18 wells

o 2012 - 7 wells

o 2013 - 12 wells

o 2014 - 11 wells

o 2015 - 6 wells

o 2018 - 13 wells

o Saturation log results show steam chamber thickness

correlates with observation well temperature profiles


SAGD WellInfill Well2010 RST2011 RST2012 RST2013 RST2014 RST2015 RST2018 RST

SUBSURFACEWELL DESIGN, INSTRUMENTATION & ARTIFICIAL LIFT

ATHABASCA 2015

SAGD DRILLING SUMMARY

2018

o 5 well pairs were drilled on Pad 7 during Q4 2018- Q1 2019

HISTORICAL

o The Leismer project includes a Central Processing Facility

(CPF) and six well pads, with 35 well pairs and 13 infill wells

20


SAGD WellInfill Well

ATHABASCA 2015

ARTIFICIAL LIFT 21

ARTIFICIAL LIFT

o All wells completed with ESP’s with the exception of two infill wells

• Rod pumps installed on infills L5N3 and L5N4

o Typical artificial lift operating conditions:

• Bottomhole pressure (BHP) range: 2,500-3,300 kPag

• BHP temperature range: 180-235 °C

Artificial Lift Performance ESP Rod

Typical Minimum Rate (m³/d) 120 100

Typical Maximum Rate (m³/d) 1,200 300

ATHABASCA 2015

TYPICAL COMPLETION: PADS 1–4 22

3-½” production tubing1.75" Instrumentation coil

11-¾” x 9-5/8" intermediate casing; or 11-¾” casing full length

3-½ x 2-7/8" x 3-½” long tubing

4-½” x 3-½” short tubing

7" wire-wrap screen; or7" slotted liner; or8-5/8" slotted liner

8-5/8" slotted liner

11-3/4" intermediate casing

Pump

PADS 1-4 COMPLETIONS

o Pads 1-4 injection wells completed with parallel tubing strings

o In production wells, instrumentation carried within a 1.75” coiled tubing

ATHABASCA 2015

TYPICAL COMPLETION: PADS 5-6 23

PADS 5-6 COMPLETIONS

o Pads 5-6 injection wells completed with concentric tubing strings

o In production wells, instrumentation carried within a 1.5” coiled tubing (coil runs inside a 2-3/8” guide string)

o 5 of 7 injectors on Pad 5 completed with Vacuum Insulated Tubing (VIT) on long tubing string

ATHABASCA 2015

7" liner (WWS)

2-3/8" x 3-½” guide string

3-½” production tubing

Instrumentation string

16" x 13-3/8" surface casing

11-¾” x 9-5/8" intermediate casing

casing gas

Pump

TYPICAL COMPLETION: INFILL WELL 24

ATHABASCA 2015

INSTRUMENTATION 25

TEMPERATURE

o Mixture of thermocouples (TC) and fiber measurements

o Both systems adequate for temperature management along the wellbore

PRESSURE

o Injector BHP is measured with blanket gas

o Producer and infill BHP is measured using optical gauges and/or bubble tubes

Pad Drainage AreaDevelopment AreaSAGD Well-PairInfill WellProducer with TCProducer with FiberProducer and Injector with TCProducer with TC and Injector with FiberProducer with Fiber and Injector with TC

ATHABASCA 2015

OBSERVATION WELL INSTRUMENTATION

OBSERVATION WELLS

o Instrumentation used to monitor reservoir pressure and temperature

o 30 thermocouples spaced at 1 m above, below, and within SAGD pay

o 10 thermocouple bundles installed in wells previously equipped with fibre optics (DTS), February 2018

26

Pad Drainage AreaDevelopment AreaThermocoupleThermocouple RepurposedFiberPiezometer

ATHABASCA 2015

FLOW CONTROL DEVICES 27

2018

o Installed 1 tubing deployed flow control device (FCD) into L3P3 in 2018

HISTORICAL

o Liner deployed and tubing deployed FCD configurations have been used to optimize asset performance

o Able to operate at lower subcool with positive impact on temperature conformance

Pad Drainage AreaDevelopment AreaSAGD Well-PairInfill WellLiner Deployed Producer FCDLiner Deployed Injector FCDTubing Deployed Injector FCDTubing Deployed Producer FCDLiner Deployed Producer FCD and Injector FCDLinder Deployed Producer FCD and Tubing Deployed Injector FCD

Pre- FCD Install

16 months after FCD Install

Tem

per

atu

re (

⁰C)

180200220240

180200220240

L3P4 TEMPERATURE PROFILES

SUBSURFACESCHEME PERFORMANCE

ATHABASCA 2015

FIELD HISTORY 29

LEISMER CONTINUES TO BE A TOP-TIER OIL SANDS ASSET

o 6 producing pads

• 35 SAGD well pairs (34 pairs on production) and 13 infill wells on production

o L3P3 FCD installed in May 2018

o 4 infill wells started on Pad 5 in June 2018

o Once through steam generator (OTSG) commissioned in September 2018 to improve reliability

• Steam capacity increased to ~ 11,600 m3/d (73,000 bbl/d)

o Maximum produced monthly bitumen rate of 3,493m³/d (21,967 bbl/d) with SOR of 3.07 (Mar 2018)

0

1

2

3

4

5

6

SOR

0

20

40

60

80

100

120

140

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Wel

l Co

un

t, P

rod

uce

d G

as, 1

03

m3/d

, In

ject

ed G

as, 1

03

m3/d

Flu

id R

ate,

m3/d

Oil Rate (CD) Water Rate (CD) Steam Inj Rate (CD)

Well count Gas Prod Rate (CD) Gas Inj Rate (CD)

CSOR ISOR

ATHABASCA 2015

PAD RECOVERY FACTOR 30

NOTES:

1 Recovery Factor based on cumulative oil production in Feb 2019

o Volumetrics include 50 m at heel and toe of well pair

Pad

DBIP Above

Producer (103 m3)

DBIP (103 m3)

GBIP(103 m3)

Cumulative Production

(103 m3)

DBIP Above Producer Recovery Factor1

DBIP Recovery Factor1

GBIP Recovery Factor1

Predicted Recovery

Factor

1 2,590 3,467 3,914 2,066 80% 60% 53% 65–75%

2 2,857 2,821 3,344 1,661 58% 59% 50% 65–75%

3 2,650 3,003 3,443 1,658 63% 55% 48% 50–60%

4 1,747 2,236 2,433 1,126 64% 50% 46% 50–60%

5 2,739 3,477 4,479 973 36% 28% 22% 50–60%

6 2,914 3,471 3,836 686 24% 20% 18% 65–75%

Total 15,498 18,475 21,449 8,170 53% 44% 38% ~65%

ATHABASCA 2015

31PAD PERFORMANCE

HIGH: Pad 6 Medium: Pad 3 LOW: Pad 4

PAD PERFORMANCE DEPENDS ON GEOLOGY AND OPERATING PARAMETERS

o Pads 6, 3 and 4 selected as examples of high, medium and low performing pads, respectively

• Selection based on average monthly oil rate and iSOR

• Differences in the productivity of the wells primarily due to geological variability

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

0

200

400

600

800

1,000

1,200

1,400

Flu

id R

ate,

m3

/d

HIGH

MEDIUM

LOW

0

2

4

6

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

iSO

R

Pad 1 Pad 2 Pad 3 Pad 4 Pad 5 Pad 6

HIGH

MEDIUM

LOW

ATHABASCA 2015

PAD 6 SUMMARY

o First steam 2016

o Peak oil rate: ~790 m3/d (600-1300 bbl/d/wellpair)

o cSOR ~ 2.8

o High reservoir quality with thick pay

• Mostly sandy reservoir

• High oil saturation

o Significant steam chamber development since last reporting period

• OBS well 100/09-33 shows 7 m steam chamber rise near heel of L6P5

PAD PERFORMANCE: HIGH PAD 6 32

0

2

4

6

8

10

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Jan 16 Jul 16 Jan 17 Jul 17 Jan 18 Jul 18 Jan 19

SOR

Flu

id R

ate,

m³/

d

Oil Rate Water Rate Steam Rate iSOR cSOR

Temperature PlotsMar 1, 2018Mar 1, 2019

L6P5H-100/09-33-078-10W400 (15m from L6P5)

Thermocouple

Injector

Producer

Res Top

Res Base

OWC

Dev

ATHABASCA 2015

PAD 3 SUMMARY

o First steam 2010

o Peak oil rate: ~480 m3/d (150-800 bbl/d/wellpair)

o cSOR ~ 3.0

o Good reservoir quality

o Significant steam chamber development since last reporting period

• OBS well 103/13-27 shows 5 m steam chamber development at the base after FCD installation on L3P4 well

PAD PERFORMANCE: MEDIUM PAD 3 33

0

2

4

6

8

10

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

SOR

Flu

id R

ate,

m³/

d


L3P4M2- 103/13-27-078-10W400 (14m from L3P4)


Thermocouple

Injector

Producer

Res Top

Res BaseOWC

Dev

ATHABASCA 2015

PAD 4 SUMMARY

o First steam 2010

o Peak oil rate: 311 m3/d (150-700 bbl/d/wellpair)

o cSOR ~ 3.25

o Average reservoir quality

o Historical NCG co-injection on this pad

PAD PERFORMANCE: LOW PAD 4 34

0

2

4

6

8

10

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

SOR

Flu

id R

ate,

m³/

d


L4P3T- 102/16-28-078-10W400 (19m from L4P3)

Dev

OWC

Res Base

Producer

Injector

Res Top


Thermocouple

ATHABASCA 2015

FCD PERFORMANCE 35

4 DEVICES HAVE BEEN INSTALLED AT LEISMER SINCE 2017

o After installation, oil production increased 125-150% per well

0

1

2

3

4

5

6

7

8

9

10

0

200

400

600

800

1,000

1,200

1,400

Jan 2017 Apr 2017 Jul 2017 Oct 2017 Jan 2018 Apr 2018 Jul 2018 Oct 2018 Jan 2019 Apr 2019

Oil Incremental Oil SORL3P3 Install June 2018

Oil

Rat

e, b

bl/

d

iSOR

0

1

2

3

4

5

6

7

8

9

10

0

200

400

600

800

1,000

1,200

1,400


L3P4 Install November 2017

Oil

Rat

e, b

bl/

d

iSOR

0

1

2

3

4

5

6

7

8

9

10

0

200

400

600

800

1,000


L3P6 Install November 2017

iSOR

Oil

Rat

e, b

bl/

d

0

1

2

3

4

5

6

7

8

9

10

0

200

400

600

800

1,000


L5P5 Install September 2017

Oil

Rat

e, b

bl/

d

iSOR

FCD

Inst

all

FCD

Inst

all

FCD

Inst

all

FCD

Inst

all

ATHABASCA 2015

STEAM

STEAM PRESSURE

o Steam upstream of pads 7,000–9,000 kPa

o Steam pressure let-down to 5,000–6,000 kPa at pads

STEAM QUALITY

o Steam quality decreases during transportation to well pads due to heat losses

• Estimated at 95% for Pads 1–4, 6

• Estimated at 90% at Pad 5 due to longer, larger diameter pipe line

36

ATHABASCA 2015

WELL INTEGRITY & ABANDONMENTS

WELL INTEGRITY

o No wellbore integrity failures during the reporting period (liner or casing)

ABANDONMENTS

o No producer/injector well pairs have been abandoned or suspended to date

o Well network in place to monitor conditions at 102/05-08-079-10W4

• 107/05-08-079-10W4 observation well

• 100/02-08-079-10W4 observation well

• Pressure differentials across the LGR and CLW-B have remained stable year over year

o No near term plans for well pad abandonments

37

SUBSURFACEPILOTS

ATHABASCA 2015



NON-CONDENSABLE GAS CO-INJECTION 39

PAD 4 NCG PERFORMANCE

o Pad 4 NCG co-injection stopped Nov 2018 after installation of once

through steam generator 5 (OTSG 5)

LEISMER FUTURE NCG PLANS

o Field-wide NCG co-injection approval received in Nov 2018

• Implementation as required in the medium term to optimize steam allocation

ATHABASCA 2015

LEISMER FUTURE DEVELOPMENT PLANS

2019 SUBSURFACE DEVELOPMENT PLANS

o Finish Pad 7 well completions on 5 wellpairs

• Anticipated first steam in summer 2019

• Producer wells completed with ESPs and FCDs

o Evaluating opportunities for tubing deployed FCDs into producer wells on Pads 1-5

o Regulatory approval received for 10 well pairs and 9 infills on Pad 8, August 2018

o Regulatory approval received for 4 infills on Pad 6, September 2018

PAD ABANDONMENTS

o No pad abandonments anticipated at Leismer within next five years

40



SURFACE OPERATIONSFACILITIES

ATHABASCA 2015

CENTRAL PROCESSING FACILITY 42

OTSG 5

Degasser

Diluent Optimization

INLET DEGASSER, OTSG 5 AND DILUENT OPTIMIZATION COMPLETED DURING REPORTING PERIOD

ATHABASCA 2015

FACILITY SCHEMATIC 43

UPDATED FACILITY SCHEMATIC

SURFACEMEASUREMENT, ACCOUNTING AND REPORTING PLAN (MARP)

ATHABASCA 2015

MEASUREMENT AND REPORTING 45

WELL TESTING

o Well tests used to calculate daily bitumen and water production

o Six hour test with 1 hr. purge to improve oil calculation accuracy

o Pads 1, 3, 5 and equipped with full test headers and test separators

o Pad 4 equipped with full test header and Multi-Phase Flow Meters (MPFM)

o Pad 2 and 4 equipped with MFPM

FQI – flow quantity indicator

AE – analyzer element

OR - orifice plate

CPF

o MARP updated to reflect additional metering associated with OTSG 5, diluent optimization and degasser projects

ATHABASCA 2015

PRORATION FACTORS 46

0.9

2

0.8

9

0.7

7

0.9

2

0.9

4

0.9

5

0.9

5

0.9

7

0.9

6

1.0

5

1.0

5

1.0

8

1.0

8

1.0

7

0.9

9

1.0

4

1.0

3

1.0

3

1.0

4

1.0

4

1.0

0

1.0

0

1.0

2

1.0

3

0.70

0.75

0.80

0.85

0.90

0.95

1.00

1.05

1.10

1.15

1.20

Pro

rati

on

Fact

or

(-)

Net Oil Proration Net Water Proration Proration Limits

Out of range due to facility turnaround

ATHABASCA 2015

SURFACEFACILITY PERFORMANCE

ATHABASCA 2015

FACILITY PERFORMANCE

SITE RELIABILITY HAS REMAINED HIGH

o CPF availability was 93% for 2018 including shutdown for planned turnaround

o Plant availability > 97% excluding turnaround

o Availability calculated based on steam capacity

MAJOR ACTIVITIES

o Completed planned turnaround at CPF - May

o Completed Norlite pipeline tie-in (reduces diluent costs) - June

o Installed and start-up of de-gasser (reduces diluent use) - May

o Commissioned OTSG 5 (improves steam reliability) - September

o Completed diluent optimization at CPF (reduces diluent costs) - November

48

ATHABASCA 2015

PRODUCTION & ELECTRICITY CONSUMPTION 49

0

20,000

40,000

60,000

80,000

100,000

120,000

Pro

du

ced

Bit

um

en

(m

3)

Bitumen Production

voluntary curtailment

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Ele

ctri

cty

Co

nsu

mp

tio

n (

MW

h)

Electricity Consumption

turnaround

ATHABASCA 2015

PURCHASED & PRODUCED GAS VOLUMES 50

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

Pu

rch

ase

d G

as

(Se

3m

3)

Purchased Gas

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Pro

du

ced

Gas

(Se

3m

3)

Produced Gas

ATHABASCA 2015

FLARING AND VENTING 51

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

Flare

d G

as

(Se

3m

3)

Flaring

LP Flare HP Flare

0.0

0.5

1.0

1.5

2.0

Raw

Wate

r V

en

ted

Gas

(Se

3m

3)

Venting

CPF Plant Trip

Lightning Strike –Partial CPF Trip

Turnaround –Shutdown/ Startup

OTSG 5 Commissioning

ATHABASCA 2015

CO2 EMISSIONS 52

0

10,000

20,000

30,000

40,000

50,000

60,000

CO

2Eq

uiv

ale

nt

(to

nn

e)

CO2e Emissions

0.30

0.35

0.40

0.45

0.50

0.55

0.60

Em

issi

on

s In

ten

sity

(to

nn

es

CO

2e/m

3b

itu

men

)

CO2e Emissions Intensity

SURFACEWATER PRODUCTION, INJECTION & USES

ATHABASCA 2015

WATER USE

SOURCE WATER USE o Water Act license allocation 317,915 m3/year (871 m3/day)

o Total non-saline water use from source wells during reporting period 199,000 m³ (545 m³/d)

• 62% of license allocation

• ~ 98.5% for process use at CPF

• ~ 1.5% for domestic use at CPF

o No saline water use

SOURCE WATER MINIMIZATION o Source water use reduced by approximately 20% from previous reporting period

o Source water intensity of 0.18 bbl water/bbl bitumen over the reporting period

o Balanced reservoir conditions minimize make-up water volume requirements

o High blowdown recycle rates minimize source water demand

TYPICAL WATER QUALITY

54

Parameter Non-saline Water Produced Water Disposal Water

TDS [mg/L]

1,475 2,450 28,400

pH [-]

8.1 7.4 12.0

Hardness [mg/L as CaCO3]

4.7 22 1.1

Total Alkalinity[mg/L as CaCO3]

850 230 6,300

SiO2[mg/L]

0 255 200

Cl[mg/L]

230 1200 11,000

ATHABASCA 2015

SOURCE AND DISPOSAL WELLS

SOURCE WATER NETWORK

o 5 Lower Grand Rapids non-saline wells

• 1F1/16-09-079-10W4/00, 1F1/07-10-079-10W4/00

• F1/04-09-079-10W4/00, 1F1/16-04-079-10W4/00

• 1F1/03-04-079-10W4/00

o 2 Clearwater B saline wells

• 1F2/04-28-078-10W4/00

• 1F2/01-10-078-10W4/00

o 3 well source water monitoring network

• 100/03-05-079-10 W4/00 (local)

• 100/11-02-078-10 W4/00 (regional)

• 100/03-22-081-08 W4/00 (regional)

DISPOSAL NETWORK

o Class 1b Disposal, Approval No. 11479B

o 2 Basal McMurray disposal wells

• 100/12-33-078-10W4/00

• 100/13-33-078-10W4/00

o 2 well disposal monitoring network

55

Development AreaPad Drainage Area

Pad Drainage Area (Not on Production)

Disposal WellNon-saline WellSaline WellDisposal Monitoring WellSource Monitoring Well

ATHABASCA 2015

DISPOSAL WELL MONITORING 56

5

8

11

14

17

20

Feb 18 Apr 18 Jun 18 Aug 18 Oct 18 Dec 18 Feb 19

Tem

per

atu

re (

C)

Bottom Water Temperature

15-28 L6 10-33

DISPOSAL WELL MONITORING

o 2 monitoring wells measuring pressure and temperature

• 100/10-33-078-10W4/2

• 102/15-28-078-10W4/00

o Bottom water temperature and pressure measurements consistent year-over-year

2,500

2,700

2,900

3,100

3,300

3,500

Feb 18 Apr 18 Jun 18 Aug 18 Oct 18 Dec 18 Feb 19

Pre

ssu

re (

kPa)

Bottom Water Pressure

15-28 L6 10-33

Data transmission offline

ATHABASCA 2015

SOURCE WATER USAGE 57

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Vo

lum

e (

m3)

03-04-079-10W4 04-09-079-10W4 07-10-079-10W4 16-04-079-10W4 16-09-079-10W4

ATHABASCA 2015

STEAM INJECTION 58

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

Mo

nth

ly V

olu

me (

m³)

Monthly Volume Monthly Capacity

Turnaround

Voluntary Curtailment

ATHABASCA 2015

PRODUCED WATER 59

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

Mo

nth

ly V

olu

me (

m³)

Monthly Volume

ATHABASCA 2015

DISPOSAL WATER 60

o Disposal limit calculated as per Directive 081

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Mo

nth

ly V

olu

me (

m³)

Monthly Volume Monthly D81 Limit

ATHABASCA 2015

DISPOSAL WATER PRESSURE & TEMPERATURE 61

0

10

20

30

40

50

60

70

80

90

-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

Dis

po

sal Te

mp

era

ture

(°C

)

Dis

po

sal W

ellh

ead

Pre

ssu

re (

kPag

)

13-33-078-10W4 WHP (kPag) 12-33-078-10W4 WHP (kPag)

WHP Limit (kPag) Disposal Water Temp. (C)

ATHABASCA 2015

BLOWDOWN RECYCLE & SLOP OIL 62

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Blo

wd

ow

n R

ecy

cle R

ate

(%

)

Axis Title

Blowdown Recycle

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Slo

p V

olu

me (

m3)

Slop Volume

ATHABASCA 2015

OTHER WASTE STREAMS

SOLIDS DISPOSAL:

o Water treatment solids (lime softening) are pumped to settling pond

o The pond is dredged and solids removed for offsite disposal as required

o No disposal required during this reporting period

63

SURFACESULPHUR PRODUCTION

ATHABASCA 2015

SULPHUR & SULPHUR DIOXIDE

SULPHUR & SULPHUR DIOXIDE REPORTING

o EPEA Approval No. 241311 limit is 2.0 t/d of SO2 emissions

o Average daily SO2 emissions over period was 0.99 t/d (50% of approval limit)

o SO2 emissions are calculated based on analytical results of produced gas samples

o There are no sulphur recovery facilities at Leismer

65

ATHABASCA 2015

DAILY & QUARTERLY SULPHUR EMISSIONS 66

0

10

20

30

40

50

60

70

Su

lph

ur

Dio

xid

e E

mis

sio

ns

(to

nn

es)

Sulphur Dioxide Emissions

Avg Quarterly Emissions Q1-2018: 1.29 t/dQ2-2018 0.77 t/dQ3-2018 0.98 t/dQ4-2018 0.96 t/d

ATHABASCA 2015

FUTURE PLANS

LEISMER FUTURE PLAN

o CPF debottlenecking to support additional pads/production as required

67

COMPLIANCEREGULATORY & ENVIRONMENT

ATHABASCA 2015

69

69

Date Approval/Amendment Activity

March 2018OSCA Approval No. 10935

EPEA 241311-00-06Replace approved 104.3 MW OTSG with a 124 MW OTSG

July 2018 Disposal Approval No. 11479B Amend monitoring well network (replacement well)

August 2018 OSCA Approval No. 10935V Pad 8 Development - 10 well pairs and 9 infill wells

September 2018 OSCA Approval No. 10935W Pad 6 Infill Development – 4 infill wells

November 2018 OSCA Approval No. 10935X Non-Condensable Gas Co-injection – project pads as required

January 2019 WA License No. 00239880 Amendment to measure water level when a well is producing

69

APPROVALS AND AMENDMENTS

Noteso OSCA – Oil Sands Conservation Act (scheme approval) o EPEA – Environmental Protection and Enhancement Act Approvalo WA - Water Act

COMPLIANCE - REGULATORY

ATHABASCA 2015

70

70

Inspections

Event Location Inspection ID Result

AER Watercourses, August 3, 2018 LOC 930765LOC 931332

47717 Satisfactory

AEP Borrow Pit, July, 11, 2018 SML 140055 N/A Compliance, August 2018

AER EPEA 241311, October 22, 2018 CPF 08-02-079-10 W4 482196 Satisfactory

AER Pipeline, October 22, 2018 License 58659 482196 Satisfactory

AER EPEA 241311, November 22, 2018 CPF 08-02-079-10 W4 482418 Satisfactory

COMPLIANCE – INSPECTIONS AND AUDITS

70

AUDITS

o AER, July 27, 2018, requested the Site-Specific Liability Assessment (SSLA) for CPF

• SSLA Submitted, August 2018

ATHABASCA 2015

71

71

Non-Compliance Summary

Event Corrective Action

April 18, 2018 – AER Notice of Non-Compliance (MARP), Directive 017, Section 12.3.2

January 21, 2019 - AER requested Directive 017 Variance for bitumen measurement outside the scheme boundary (MARP)

AOC submitted requested information May 24, 2018

AOC submitted Directive 017 Variance Request February 7, 2019

August 27, 2018 – heavy rain washed out berm resulting in unapproved release of surface water (EPEA Approval No. 241311)

AOC repaired damaged berm and inspected entire berm system to ensure no further potential

January 30, 2019 – transducer failure prevented daily water level measurement in wells (Water Act Approval No. 239880)

AOC completed equipment repair and replacement

COMPLIANCE – NON-COMPLIANCE SUMMARY

71

From March 1, 2018 to February 28, 2019 there were 3 reportable releases

ATHABASCA 2015

COMPLIANCE - MONITORING PROGRAMS

AIR QUALITY MONITORING

o Passive air monitoring – no exceedances (SO2, NO2, H2S) of Ambient Air Quality Objectives

o Continuous ambient air monitoring

• WBEA air monitoring station used, Q1 2018 – only March 2018 data applicable for this reporting period

• No exceedances (SO2, NO2, H2S) of Ambient Air Quality Objectives

o All monitoring stations registered as required by new Air Monitoring Directive - Jan. 2019

o Leismer has 2 CEMS units reporting data

• New CEMS units on OTSG 4 & OTSG 5 installed and certified during reporting period

• CEMS unit on OTSG 1 decommissioned December 2018

72

ATHABASCA 2015

COMPLIANCE - MONITORING PROGRAMS 73

0

2

4

6

8

10

12

14

Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19

kg/h

r

OTSG 1 &4 - Monthly Average NOx

OTSG 1 OTSG 4 Limit

0

2

4

6

8

10

12

14

16

18

20

Oct-18 Nov-18 Dec-18 Jan-19 Feb-19

kg/h

r

OTSG 5 - Monthly Average NOx

OTSG 5 Limit

NOX MONTHLY AVERAGE

o New CEMS installed on OTSG 4 & 5, operational October 2018

o CEMS on OTSG 1 no longer reporting as of January 2019

ATHABASCA 2015

COMPLIANCE – MONITORING PROGRAMS

ENVIRONMENTAL PROTECTION & ENHANCEMENT ACT (EPEA) APPROVAL

o EPEA monitoring programs and/or reports completed during the reporting period:

• Monthly and annual air emissions

• Industrial wastewater and runoff

• Groundwater water - including thermal screening assessment for well pads, new requirement June 2018

• Soil Monitoring Program report and Soil Management Program Proposal

• Conservation and Reclamation

• Wildlife – wildlife monitoring report is submitted every 3 years (May 15, 2018)

o The AER authorized the following program/plans during the reporting period:

• Reclamation Monitoring Program - October 2018

• Project-Level Conservation, Reclamation and Closure Plan - January 2019

WATER ACT

o All diversions were below license limits and monthly and annual reporting completed

• Groundwater licenses (0239880, 0029742, 00368609)

• Surface water licenses (00273542,00364442, 00364731)

74

ATHABASCA 2015

COMPLIANCE – RECLAMATION PROGRAMS

RECLAMATION PROGRAMS

o MSL 121772 - completed soil placement, contouring, woody debris placement in preparation for tree planting in spring 2019

o Outstanding OSE sites (251) received reclamation certificates in January 2019

o AOC has received reclamation certificates for all OSE programs at Leismer

75

ATHABASCA 2015

COMPLIANCE – REGIONAL INITIATIVES

AOC IS A FUNDING MEMBER OF:

o Oil Sands Environmental Monitoring

o Wood Buffalo Environmental Association (WBEA) – air shed monitoring

o Regional Industry Caribou Collaboration (RICC)

o Oil Sands Black Bear Partnership

o Faster Forests – reclamation research industry collaboration

o Industrial Footprint Reduction Options Group (iFROG) – wetland reclamation industry collaboration

AOC PARTICIPATES IN:

o Various CAPP Committees

• Oil Sands Environmental Policy and Regulatory Committee

• NE Alberta Caribou Working Group

• Indigenous Affairs Committee

• Air Issues Committee

76

ATHABASCA 2015

COMPLIANCE – STATEMENT OF COMPLIANCE

ATHABASCA OIL CORPORATION LEISMER PROJECT IS IN COMPLIANCE WITH AER APPROVALS AND REGULATORY REQUIREMENTS

o For the period of March 1, 2018 to February 28, 2019 AOC has no unaddressed non-compliant events

77

ATHABASCA 2015

78

78

ATHABASCA OIL CORPORATIONSUITE 1200, 215 - 9TH AVENUE SW

CALGARY, AB T2P 1K3P:403-237-8227F:403-264-4640

ATHABASCA OIL CORPORATION - AER€¦ · ATHABASCA 2015 ARTIFICIAL LIFT 21 ARTIFICIAL LIFT o All...

Documents

Transcript of ATHABASCA OIL CORPORATION - AER€¦ · ATHABASCA 2015 ARTIFICIAL LIFT 21 ARTIFICIAL LIFT o All...