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NORTHERN PETROLEUM PLC
23rd October 2014
Northern Petroleum Virgo Technical Update
Disclaimer
October 2014 2
These presentation materials (the "Presentation Materials") are being solely issued to and directed at persons having professional experience in matters relating to investments and who are investment professionals as specified in Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the "Financial Promotions Order") or to persons who are high net worth companies, unincorporated associations or high value trusts as specified in Article 49(2) of the Financial Promotions Order (“Exempt Persons”).
The Presentation Materials are exempt from the general restriction on the communication of invitations or inducements to enter into investment activity on the basis that they are only being made to Exempt Persons and have therefore not been approved by an authorised person as would otherwise be required by section 21 of the Financial Services and Markets Act 2000 (“FSMA”). Any investment to which this document relates is available to (and any investment activity to which it relates will be engaged with) Exempt Persons. In consideration of receipt of the Presentation Materials each recipient warrants and represents that he or it is an Exempt Person.
The Presentation Materials do not constitute or form any part of any offer or invitation to sell or issue or purchase or subscribe for any shares in Northern Petroleum PLC (“Northern Petroleum”) nor shall they or any part of them, or the fact of their distribution, form the basis of, or be relied on in connection with, any contract with Northern Petroleum relating to any securities. Any decision regarding any proposed purchase of shares in Northern Petroleum must be made solely on the basis of the information issued by Northern Petroleum at the relevant time. Past performance cannot be relied upon as a guide to future performance. The Presentation Materials are being provided to recipients on the basis that they keep confidential any information contained within them or otherwise made available, whether orally or in writing in connection with Northern Petroleum or otherwise. The Presentation Materials are not intended to be distributed or passed on, directly or indirectly, whether to Exempt Persons or to any other class of persons. They are being supplied to you solely for your information and may not be reproduced, forwarded to any other person or published, in whole or in part, for any other purpose. In particular they, directly or indirectly, must not be distributed to persons in the United States of America, its territories or possessions or Australia or Canada or Japan or the Republic of Ireland or South Africa. Any such distribution could result in a violation of law in those territories.
The Presentation Materials do not constitute or form part of a prospectus prepared in accordance with the Prospectus Rules (being the rules produced and implemented by the Financial Conduct Authority (“FCA”) by virtue of the Prospectus Rules Instrument 2005) and have not been approved as a prospectus by the FCA (as the competent authority in the UK). The Presentation Materials do not contain any offer of transferable securities to the public as such expression is defined in section 102(b) FSMA or otherwise and do not constitute or form part of any offer or invitation to subscribe for, underwrite or purchase securities nor shall they, or any part of them, form the basis of, or be relied upon in connection with, any contract with Northern Petroleum relating to any securities.
Project summary
Northern Petroleum has established a 30,000 acre land position in the Virgo area of NW Alberta to undertake a field re-development project
The area is prospective for light oil from Devonian Keg River vuggy carbonate reefs
— approximately 1,500m depth
The recovery factor in the Virgo reefs is lower than analogue Keg River reefs to the south in the Rainbow area
Production to date has been through bottom aquifer drive
There has been lower recovery at Virgo from poor sweep efficiency at the reef edge due to reduced vertical permeability within hetrolithic strata
Trapped oil at the reef edge is an attractive development target and well results prove its existence
— additionally, vuggy carbonate reefs remain prolific, even at the reef edge
— well placed development locations have demonstrated high oil productivity
Recent well results have highlighted the importance of seismic interpretation to locate wells in a ‘sweet spot’ between the core and edge of the reefs
October 14 3
The Virgo area
October 14 4
Virgo is located in a remote Boreal forested wilderness setting, 500 miles north west of Edmonton, Alberta
Northern land position (five year petroleum and natural gas lease)
10 miles
Virgo area geological background
October 14 5
The area is prospective for oil and gas in several formations at Cretaceous and Devonian Levels
Upper Keg River formation has been prolific for oil with over 110 MMSTB produced to date in the area of the Northern’s land position
Up hole zones include the Sulphur and Slave Point formations
— these tend to contain non-associated sour gas (although oil is also present)
Oil is present in the Muskeg formation and the Muskwa Shale is prospective for oil and wet gas
Formation Pool Count Average STOIIP MMSTB
Jean Marie 1 2.1
Slave Point 3 0.1
Sulphur Point 11 0.3
Muskeg 64 0.9
Keg River 416 1.5
Chinchaga
Lower Keg River
Upper Keg
River
Muskeg
Sulphur Pt.
Slave Pt.
Fort Simpson and Muskwa Shales
Fort Vermillion
Formation Pool Count Average GIIP (BCF)
Bluesky (Cret.) 1 9.9
Slave Point 171 0.9
Sulphur Point 128 0.6
Muskeg 2 0.3
Keg River 23 0.6
Oil Pools Non-Associated Gas Pools
Pool count in the 576 square mile region around company lands Does not include co-mingled pools nor associated/solution gas volumes
Reef count
October 14 6
The Company participated in eight Crown land sales in 2013 and 2014
Acquired just under 30,000 acres for a total of Cdn2.9 million
The Company has obtained mineral rights covering 118 full or partial Keg River reefs
It is estimated that these reefs did contain 108 MMSTB of original oil in place based on the Alberta Energy Regulator’s (AER) estimate
The average recovery factor on these reefs is 18%
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1,500 -2,000
2,000 -2,500
2,500 -3,000
3,000 -3,500
3,500 -4,000
4,000 -4,500
Re
ef C
ou
nt
Stock Tank Original Oil in Place (,000 STB)
AER Reported Pool STOIIP for Keg River Reefs Completely or Partially Located on the Company's Land Position
43 Reefs with STOIIP > 1 MMSTB
16 Reefs with STOIIP > 2 MMSTB
Infrastructure
October 14 7
Roads Emulsion Gathering Gas Gathering & Export
The area benefits from extensive infrastructure which was constructed between 1968 and the present day
Good road infrastructure and proximal tie-in locations significantly reduce the cost of entry
3D seismic position
October 14 8
The company has purchased and interpreted over 50 sq km of 3D seismic
Just under 30% of the land position is now covered
SLAVE POINT
WABAMUN
FORT SIMPSON
KEG RIVER
COLD LAKE
Keg River Formation at Virgo
October 14 9
Average KR Reef properties
Porosity 8%
Water Saturation 15%
Net Pay 35m
Radius 250m
Kh (air) 100mD
Oil Gravity 32-40 API
Reservoir Temperature 75 C
Original Solution Gas Oil Ratio200-450 scf/STB
Initial Pressure 150 Bara
(2200 PSIA)
Primary gas in the Keg River Formation
October 14 10
The Keg River formation deepens to the West and is sourced from later basinal Keg River equivalent strata
The increased maturity of the source rock leads to higher API gravity oils and additional gas generation
Oil API gravity increases to the west (from 32 to 40 API), the saturation pressure increases and primary gas caps begin to develop
Lands were deliberately targeted which did not have primary gas caps
Saturated Oils and Primary Gas Caps in the Keg River
Under-Saturated oils no Primary Gas Caps in the Keg River
Depth of Burial
Increasing API Gravity
Increasing Saturation Pressure
Production performance in Keg River Reefs
October 14 11
Sweep Displacement of oil by
water within swept areas of the reef can achieve recovery factors between 45 – 65%
To the south of Virgo, in the Rainbow area, recovery factors in the Keg River are much higher and demonstrate little un-swept pore volume
This is due to many more wells / reef and larger reef size
Why is the recovery factor at Virgo half as high and where is the un-swept pore volume?
Rainbow Area
Wells / Reef 4.6
Average Pool Area 223 acre
Average pool Size 9.0 MMSTB
Primary Recovery Factor 32%
Secondary Recovery Factor 51%
Virgo / Zama / Amber
Wells / Reef 1.5
Average Pool Area 37 acre
Average pool Size 1.5 MMSTB
Primary Recovery Factor 16%
Secondary Recovery Factor 29%
Production performance in Keg River Pinnacle Reefs
October 14 12
Water Displaces oil through the massive core of the reef
Langton and Chin 1968
Initial Well Waters out
The core of the reef tends to be homogenous and vertically continuous
— whereas, the reef edge tends to be heterolithic and have vertical barriers to flow.
These vertical barriers at the reef edge can trap oil resulting in low recovery factors where well penetration counts are low
When the reef is produced, aquifer support from the base sweeps oil from the core of the reef towards the production well until the well waters out
After an extended shut-in, some oil migrates from the reef edge back to the core of the reef and some oil remains trapped at the reef edge
This is not coning, it is low areal sweep efficiency
Geological Model
Production performance in Keg River Pinnacle Reefs
October 14 13
Primary production performance from original wells tends to show extended low water cut production followed by sharp water breakthrough
— consistent with piston like displacement of oil by water
The live oil viscosity varies from below 1 to 3 cP
— good mobility ratio for the displacement of oil by water
— again consistent with piston like displacement
This suggests that coning is not occurring to a material degree and that un-swept pore volume results from geological factors rather than fluid dynamics
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Wat
er
Cu
t (%
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Cumulative Oil (STB)
Water Cut v Cumulative OilInitial Perforations : 100/15-23-114-06W6M
Drive Displacement (original well in reef)
Generally, under primary production, the reefs were produced with perforations near the top of the structure
Drive energy came, predominately, from bottom aquifer drive
Displacement is gravity stabilised
Development history: horizontal wells
6th October 14 14
Distance calculated for each grid block from intersection of surface with constant depth plane
In 2001
100/15-23 Sidetrack (05 Event)
Produces 500 STB before watering out
A series of horizontal sidetrack wells were drilled in the area between 1995 – 2005
They were singularly unsuccessful at increasing recovery factor from the reefs
Conventional horizontal wells are advantageous to suppress coning
Due to oil being trapped by vertical layering at the reef edge, horizontal wells do not increase sweep
In 2014
102/15-23 Vertical
Tests >1300 STB/D dry oil
at the reef edge
Water, which has already displaced oil from the core of the reef will water out the heel of the horizontal well almost immediately. No additional oil will be captured from the heterolithic strata at the reef edge
Phase 1B results (Oct 2014)
October 14 15
Well and Objective Drilling Result Production Result
102/15-23 14m net oil pay Well flowed at over 1,300 STB/D on test. Waiting on delivery of separator package.
100/14-23 4m net oil pay Well swabbed 20 STB/D and pump run. Waiting on delivery of separator package.
100/01-27 0m net oil pay MDT showed Keg River to be swept
102/15-23 100/14-23
100/01-27
Phase 1B – 102/15-23-114-05W6
6th October 14 16
102/15-23
SLAVE POINT
102/15-23
100/15-23
KEG RIVER
COLD LAKE
Top Keg River
100/15-23
Demonstrated un-swept oil at the reef edge and significant oil deliverability
Original Well
New Well
102/15-23 cross section with original wells
October 14 17
Original Free Water Level 1190mSS
Keg River reef was clearly oil saturated at 102/15-23 with a total of 14m of net pay interpreted based on the wireline logs
Un-swept oil has been encountered in a heterolithic sequence at least 32m below the top of the Keg River perforated in the original producer, 350m away
This well clearly indicates that significant un-swept oil is present at the reef edge
Un-swept
Swept
32m
Original Well (100/15-23) New Well (102/15-23)
New well encounters oil down dip from the top of the perforation in the original well
102/15-23 wireline formation pressure results
October 14 18
MDT pressure show good overpressure, consistent with a significant gross hydrocarbon column and demonstrating the reef to be at original pressure
This suggests that the perforated interval may not be in hydrostatic equilibrium with the swept interval
Original Free Water Level 1190mSS
Un
-sw
ept
Swep
t
32m
1120
1130
1140
1150
1160
1170
1180
1190
1200
1210
1220
2100 2150 2200 2250 2300 2350 2400
De
pth
(m
SS)
Pressure (PSIA)
102/15-23 MDT Pretest Results
102/15-23 flow test and performance
October 14 19
Flow Period Start End Hours Oil Rate Water Rate Gas Rate Water Cut GOR Cumulative Oil Cumulative Water Cumulative Gas
(h) (STB/D) (BBL/D) (MSCF/D) (fraction) (scf/STB) (STB) (BBL) (MSCF)
Clean-Up 07/10/2014 13:00 07/10/2014 15:45 2.75 675 65 44 0.09 65 77 59 44
Main Flow Period 07/10/2014 15:45 09/10/2014 08:00 40.25 304 1 136 0.00 448 588 64 180
High Rate Flow Period 09/10/2014 08:00 09/10/2014 20:00 12.00 1313 0 237 0.00 180 1,245 64 417
Final Flow Period 09/10/2014 20:00 10/10/2014 13:00 17.00 181 0 69 0.00 381 1,373 64 486
The well cleaned up quickly and showed excellent deliverability with a productivity index of approximately 2.9 STB/D/Psi
The flow test was conducted over exactly 72 hours and was divided into the flow periods shown above
The average rate during the 12 hour high rate flow period was 1,313 STB/D against a ½” choke with 300 to 400 psi tubing head pressure
Perforated Interval 1499.4 – 1508.8mMD
Net Perforated Pay 9.2m
PHIE 0.074
102/15-23 production and pressure history
October 14 20
Flow Period
Clean-Up
Main Flow Period
High Rate Flow Period
Final Flow Period
Perforation Interval
Depth Curve
DEPTH.m
1499.4128
1499.4382
1499.4636
1499.489
1499.5144
1499.5398
1499.5652
1499.5906
1499.616
1499.6414
1499.6668
1499.6922
1499.7176
1499.743
1499.7684
1499.7938
1499.8192
1499.8446
1499.87
1499.8954
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6000
07/10/2014 07:12 07/10/2014 19:12 08/10/2014 07:12 08/10/2014 19:12 09/10/2014 07:12 09/10/2014 19:12 10/10/2014 07:12 10/10/2014 19:12 11/10/2014 07:12
Tub
ing
He
ad P
ress
ure
(kP
ag)
102/15-23 : Flow Test : Tubing Head Pressure
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3000
07/10/2014 07:12 07/10/2014 19:12 08/10/2014 07:12 08/10/2014 19:12 09/10/2014 07:12 09/10/2014 19:12 10/10/2014 07:12 10/10/2014 19:12 11/10/2014 07:12
Oil
Rat
e (
STB
/D)
102/15-23 : Flow Test : Oil Rate
Clean-up Period
Main Flow Period
High Rate Period
Build-up Period
Final Flow Period
102/15-23 rate comparison to other wells in Alberta
October 14 21
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Average Daily Oil Rate (STB/D)
Distribution of Oil Rates (Last 12 Months) of All Flowing Oil Wells in the Province of Alberta
Production from 102/15-23 expected to be between 300 – 400 stb/d after tie-in
‒ Positions the well in the top 2% of flowing oil wells in Alberta in terms of production rate
Only 12% of wells in the province flow to surface with the rest requiring artificial lift
Phase 1B – 100/14-23-114-05W6
6th October 14 22
14-23
SLAVE POINT
14-23
100/15-23
KEG RIVER
COLD LAKE
Top Keg River
100/15-23
Encountered poorly developed, but oil saturated reservoir Completed for production
Keg River expression on the overlying Slave Point
October 14 23
Pre-drill Post-drill Overlying Slave Point formation
A thorough review of the 14-23 result has highlighted the importance of the muted expression of the Keg River structure on the overlying Slave Point surface
This will improve our ability to discriminate between subtle Keg River tops and Muskeg on-lap on the reefs
Phase 1B – 100/01-27-114-05W6
6th October 14 24
08-27
SLAVE POINT 01-27
08-27
KEG RIVER
COLD LAKE
Top Keg River
01-27
Encountered high quality reservoir, but swept by original producer
14-22
16-19
13-33
Well Results Phase 1A
October 14 25
Well and Objective Drilling Result Production Result
14-22
Re-entry
Test for migration of oil after extended shut-in
Successfully re-entered
Up-hole zones cemented
Well swab tested and pump run
Well on test 02/04/2014
Produced over 3000 STB oil at an average water cut of 63%
Peak daily rate 100 STB/D and current rate 35 STB/D oil
13-33
Infill well into previously produced reef
Test for un-swept oil at reef edge
Drilled and encountered 15m gross oil column in the Keg River formation
Produced dry oil on MDT test
Ran liner across Keg River and perforated
Well swab tested and pump run
Well on test 16/04/2014
Produced over 11,300 STB oil at an average water cut of 36%
Peak daily rate 260 STB/D and current rate 50 STB/D oil
16-19
Exploration well into undrilled reef
Test new structure
Drilled and encountered 22m gross oil column in the Keg River formation
Produced dry oil on MDT test
Completed open hole with inflatable packer above oil water contact
Produced at high water cut after Inflatable packer failure
Liner cemented in place and perforated. Well flowing dry oil
Well on test 14/04/2014
Produced over 8,700 STB oil
The well continues to produce dry oil
Peak daily rate 140 STB/D and current rate 70 STB/D oil
Cost (US$)
Drill and complete $1.82m
Equip and tie in $0.55m
Forecast production and reocvery
IP30 (bbls/d) 150
Year 1 decline 33%
Estimated economic reserves (bbls) 125,000
Economics (using $85 WTI flat)
Operating net back per barrel $37
Payback (months) 10
IRR 63%
PV10 $2.09m
Virgo type curve and economics
Update on assumptions
IP rates are higher than originally planned
DCET costs should reduce with larger well programmes and lessons learnt
Variable opex will significantly reduce if water separation and disposal facilities are built
Fixed opex will reduce through synergies of scale
Metrics are robust using a life of well $85 flat
Payback within a year
October 2014 26
Note: assume well tied in upon completion
Potential from existing land position
Virgo notional development plan
AER STOIIP and recovery factors suggest that there are at least 12 reefs with the capacity for a minimum of three additional wells
• minimum well recovery at 125 MSTB
• at least 17 reefs which with capacity for a single producer
Estimated that existing land position can support 64 wells
• providing for 8,000,000 incremental oil recovery
Sufficient for the Virgo asset to grow, organically, to 3,000 – 5,000 STB/D.
Key points for successful development
New wells will increase recovery factors by targeting unswept areas of reefs
Well locations will be optimised with increased understanding of edge reef environment
Well evaluation and completion improved through application of formation tester data acquisition and interpretation
October 14 27
NORTHERN PETROLEUM PLC
Northern Petroleum
Northern Petroleum