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Vermilion Energy Inc.

Steady Growth

Stable Dividends

2 0 2 0 V I S I O N the best oil and gas company in the world

September 2013 – Drill Well Presentation

Andy Wroth

2012 Wandoo Infill Project

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2 2 2 2 2 2 2

Wandoo Field Location

2 Perth

Dampier Perth to Dampier

~1800km or 2 days by road

2 ½ hrs by air

Dampier

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Scope of Work

Multi-Lateral conversions of 2 wells

Aim – To access stranded “flank & unswept” oil in A3 & B Sands

Sidetrack Existing Production Wells – B9, B5 wells

Level 5 Multilateral Junctions – non-cemented sealed junctions

Shallow TVD ERD Horizontal Trajectories

Open Hole Sand-screens – 6-5/8” and 5-1/2” screens in 9” open hole for sand control and

swell packers for annular flow control

Production from both new laterals & existing well bores - smart completions providing

selective production from one (or both) lateral at a time

B15 conductor repair

Repair damaged conductor to create usable well slot – collapsed at 30”x20” swedge

below mud-line during cement job on 2008 well construction campaign

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Wandoo Infrastructure

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Wandoo B Platform North Face

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Wandoo B & Ensco 109– side view

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Wandoo B & Ensco 109 – top view

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Wandoo

Geological Setting

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Geological Setting L

ow

er

Mu

de

ron

g S

ha

le

Me

mb

er

M. A

us

tra

lis

Sa

nd

sto

ne

Me

mb

er

Upper

Muderong

Shale

Member

E

D

C2

C1

B1

B2

A3

A1 A2

Reservoir

Stratigraphy

U

L

U

L

A2 Flaser-bedded greensand/very glauconitic

sandstone – well developed siderite beds

A1 Argillaceous greensand/very glauconitic

sandstone – some siderite beds

A3 Bioturbated/cross-bedded greensand/very

glauconitic sandstone – occasional siderite bed

B1 Dominantly cross-bedded sandstone with some

bioturbated sandstone and cross-bedded

glauconitic sandstoneG

G

GG

G

G

G

B2 Dominantly bioturbated glauconitic sandstone but

ranges from cross-bedded sandstone to

bioturbated greensand/very glauconitic sandstone

C1 Can be cross-bedded sandstone at the top but

ranges to bioturbated and cross-bedded glauconitic

sandstone

G

G

GG

G

G

G

Top A3 is

effectively

top reservoir

B S

and

A S

and

– Vertical heterogeneity present because B Sand comprised

of three coarsening-upwards units (D,C & B) with each

becoming progressively more dominated by clean cross-

bedded sandstone towards the top

– Lateral variation occurs due to shoaling such that clean

cross-bedded sandstones can pass into glauconitic bio-

turbated sandstones laterally

– Base of reservoir transitional as no real shale below

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Original Proposed Targets

A3/B Sand Oil Thickness Mid 2011 A3/B Sand Oil Thickness End 2029

A7 West

B8 East

A Platform

A7 East

A5 West

A7 West

B8 East

A Platform

A7 East

A5 West

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Spider Plot

As Drilled

2012 Trajectory Evolution

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B9ST1 Cross-Section

Exit in lower Muderong, near horizontal past Siderite beds

in A2, multiple well crossings while attempting to stay

between 1 and 1.5m below top A3 Sand

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2010 Campaign Overview

World First - Successfully converted 3 EXISTING producing wells to TAML

Level 5 bi-lateral wells with surface controlled subsurface flow control

capability enabling selective or co-mingled production

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Prepare well bores for setting ML anchor to side track

Cut tubing below production packer & install straddle (before rig arrives)

Kill & suspend wells (before rig arrives 1st well, off critical path 2nd well)

Remove tree (before rig arrives 1st well, off critical path 2nd well)

Recover 5 ½” Upper Completion

Mill and recover production packer and pull 5 ½” tail pipe to tubing cut

Casing scraper / clean out run

Conduct casing and cement log

Run 5½” external tubing patch, flapper valve and new anchor packer

High Level Outline of Well Work

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Drill new lateral and complete well

Run milling machine and cut first pass window

Run whipstock and open / dress window

Drill 9” Horizontal Lateral with Rotary Steerable Assembly and Under-reamer

Run Lower Completion - Sandscreens & ML Junction

•6-5/8” & 5-1/2” Sandscreens, Swell Packers with MLT and Hanger Packer

Run Upper Completion

•5-1/2” Tubing c/w TRSV, Gas Lift Valve and Flow Control Valves

Set hanger plug and remove BOP

Install tree and remove hanger plug

High Level Outline of Well Work

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B5 Completion Diagram – Pre Campaign

16 16 16 16

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Proposed B5/B9 Well Schematic

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9 ⅝” x 7” VCH

Screen Hanger

Lateral Flow Path

Mainbore Flow Path

9 ⅝” x 5 ½” Production

Packer & Tailpipe

MLJ Completion Deflector

6⅝” & 5½” Sand Face

Completion

MLJ Anchor

Packer and Tailpipe

Main Bore

Gas Lift Mandrel

Multi-Lateral

Junction Assembly

Upside Down

Flapper Valve

Lateral

TRFC - Tubing

Retrievable Flow

Control

TRSV – Tubing

Retrievable Sub

Surface Safety Valve

Xmas

Tree

Common Flow Path

MLJ Swivel and

Safety Sub

MLJ Production Flow Path Schematic

Lower Completion and

Sand Screen hanger

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Design Considerations

Re-entry of existing producing wells in a depleted reservoir, drilling ERD

laterals at extremely shallow TVD, running sand screens and then installing a

Level 5 multilateral junction with intelligent completions.

Current Well & Reservoir Conditions Depleted Reservoir / Potential Losses / FG – ECD Management

KOP for Multilateral Junction System Inclination, DLS & Casing Collar limitations

Well Integrity Potential casing corrosion

Trajectory Shallow TVD, +4:1 ratio, tortuous path, rotary steerable & geosteered, high

torque drill pipe

Hole Size – 8½” hole under-reamed to 9” due to ECD>FG

Drilling Fluids • Inhibition / Wellbore Stability / Solids Free Weighted Completion Fluid

Running Sand-Screens • Ability to run sand-screens to planned TD

• Buckling Mitigation – 6 5/8” screens and tubing

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B5 B9 A5 Units

10 3/4 Csg 108ppf 35-343m 15-371m - 9 5/8 Csg 53.5ppf 343-523m 371 - 570m - 9 5/8 Csg 47ppf 523-736m 570 - 886m 0-855m 9 5/8 Csg 40ppf - - - 9 5/8 Csg 36ppf 736-1491m 886-1611m - Well TD 2,609m AHD 2,350m AHD 1857m AHD Current Well

Reservoir Pressure 783 psi 783 psi 783 psi @ 582m ss

Equiv Mud Weight 7.4 ppg 7.4 ppg 7.4 ppg Datum RT

Fracture Gradient ~1.65 ~1.65 ~1.65 sg

Permeability

5,000 -

12,000md

5,000 -

12,000md

5,000 -

12,000md “B” sand

500 - 2,000md 500 - 2,000md 500 - 2,000md “A” sand

Reservoir Conditions

Depleted Reservoir – expect losses

Decompletion

Losses while de-completing wells – continuous top up of annulus w/ floating cap

Drilling Lateral and Completion Phase

Flapper Valve installed in ML Anchor Packer tailpipe – can shear early

Fracture Gradient

Drilling Lateral

8 ½” hole opened to 9” required, along with 5” HT DP to prevent ECDs > FG

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Kick Off Depths

DLS <4deg/30m

Inclination >65deg**

NOTE: RT = 40mMDRT

Multi Lateral Kick Off Point

Legend Inclination DLSOutside acceptable Range <45° >6°/30m

Marginal Range - Further testing required 45°-65° 4°-6°/30m

Acceptable Range 65°-93° <4°/30m

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ERD Well Designs

Wandoo 2010 Sidetracks

Conventional

Extended Reach ( >2 : 1 stepout down to 2000-2500m TVD)

Extended Reach = very ER (>3 : 1 stepout)

Extended Reach = extreme ER

Wandoo 2012 Sidetracks

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ECD – Hole Size

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Key Operational Concerns

Production Packer Retrieval The tubing required to be cut prior to milling the production packer to allow

window to be milled at depth required

Done on e-line conveyed tractor prior to rig arrival

Completions on Depth – no flexibility Modelling based on 2010 friction factors

Equipment in place to reduce friction factors in 2012

Real Time data collected as an assurance modelling is applicable

As a contingency a lateral swivel installed will allow rotation of the running string to reduce drag if required

Well crossings are a managed risk and mitigations include: Trajectories to minimize crossing risk and include measurement uncertainty

Consideration for where in the well the crossing will take place (screen, blank pipe, casing, abandoned section)

Geo-steering in A sands

Shut-in of producers while crossing to reduce area of drawdown.

While every well has it’s individual challenges and intricacies, the program as a whole was not significantly more complex than the 2010 campaign.

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MLJ Installation – 2010 Lessons Learned

Spinning of Anchor Packer Anchor Packer and tail pipe string was inadvertently rotated at 120 rpm

on B8 well. Although packer was subsequently set and successfully

pressure tested, the occurrence was far from ideal and resulted in

premature shearing of upside down flapper valve lock open sleeve and

subsequent lost circulation during completion activities.

Setting Equipment in MLAP Ratch-Latch Insufficient set down weight followed by insufficient overpull after

setting the milling machine in the Anchor Packer ratch-latch to confirm

latched. The milling machine was not latched correctly which resulted

in the window being milled at the wrong orientation and ~7 days of

subsequent NPT to rectify the situation

Damage to Mill (Milling Machine) ~1.15m normal progress, p/u then erratic torques when back on bottom

Very “fast” ROP from 1.15m to 5.08m. Little to nil milling torque

Mill trashed,, large pieces of mill blades and centralizer blades on

magnets and in junk baskets

Ensure competent person in the Driller’s chair during critical

operations.

Ensure sufficient set down weight (40klb) is applied to ensure latch

of MLJ equipment into Anchor Packer ratch-latch.

Latch to be confirmed with 25 klb overpull and orientation to be

confirmed prior to commencement of window milling.

Check for Anchor Packer “scar” marks on recovered tools on POOH

to confirm they were in fact latched correctly

Ensure conservative milling parameters are used;

Never pick up with the mill while rotating.

Lesson Learned Control and Mitigation

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2012 Innovations & Challenges

Main Bore Lower Completion Tie Back

In 2010 packer was milled and straddle completions were pulled as one with the

packer.

Due to different lower completion design on remaining Wandoo wells a different

approach was required for the 2012 wells.

De-completion requires tubing cut below production packer

Electrical tubing cut, tubing stump overshot.

Tubing will be cut on e-line with tractor with electrical cutter

Tubing “dimple” tool (for centraliser retention)

Isolation straddle system – produce well until rig arrival

Tubing overshot tie-back system

Seal integrity of tubing patch for sand ingress prevention (pressure integrity not

required)

Tubing centraliser positions relative to cut impeding tubing patch swallow

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2012 Innovations & Challenges

Electronic plug technology to reduce slick line operations with rig

Opens or closes when a trigger is detected on a pre-programmed value of applied

pressure, ambient pressure or time, or any combination of all three

Increased well length of the B5 and B9 wells

Pushed ERD envelope further

Increased tortuosity of the B5 and B9 wells

Requirement for new generation rotary steerable system to achieve and maintain

required dogleg severity

Pushed ERD envelope slightly further

Increased torque drove requirement for High Torque Drill Pipe

Numerous well crossings – collision separation factors <<1

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Wells kicked off and drilled in one BHA run

During 2010 Campaign a down hole motor BHA was required to achieve sufficient

separation from mother bore to avoid magnetic interference resulting in RSS tool

tracking down the casing

New generation RSS tool removed this requirement

Revised Lower Completion Design

In 2010 the production packer and straddle completions were stung in to a lower

sandscreen hanger packer and thus the entire straddle could be recovered with a

straight pull once the packer was milled and the sand screen hanger packer seal

bore utilized for a direct tie back to the mother bore

The 2012 wells had sandscreens installed as part of the straddle (assumed to be

packed off) thus the tubing had to be severed above the screens making tie back

more complex

Regulatory Submissions

EP and OSCP updates

Safety Case Revisions for Wandoo and Rig

WOMP update

2012 Innovations & Challenges

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ERD Mitigation Variations From 2010

High Torque Drill Pipe 5” XT50 String

Increased use of Hybrid Stands (1x 5” HWDP + 2 x 6-5/8” DC) in lower

completion running string

Increased quantity of 6-5/8” sand screens and blank tubing, both

specifically placed in lower completion for buckling mitigation

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ERD Mitigation Innovations

Latest design ultra low friction centralisers

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Anti-Collision Planning

Ellipsoid of

uncertainty of

existing well

Ellipsoid of

uncertainty of

proposed well

Based on various

characteristics of the well

survey, ellipsoids of

uncertainty around existing

wells and the proposed well

trajectory can be calculated to

determine the separation

required – usually ~4 m B A3L

A3U

A2

A1

A3L A3LA3U A3UA2

LWD (logging while drilling) can be used ‘real time’ to distinguish between the various A Sand

reservoir units and the B Sand from the A Sand – this tells us where in the reservoir we are. DDR

(directional deep resistivity) can be used ‘real time’ to tell if the well is about to pass from one reservoir

unit to another.

Where the proposed and existing wells should be in different reservoir units, LWD-DDR can further

reduce the collision risk by ensuring the well is kept in the appropriate unit – using this method we can

actually pass an existing well within its ellipse of uncertainty.

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A Platform Target – 2012 Geological Cross Section

(B5 Mother Bore)

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B8 East – 2012 Geological Cross Section

(B9 Mother Bore)

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Collision Contingency Modelling

Dynamic Conditions: Utilising OPT dynamic wellbore condition flow

loops enable the following data to be collected:

Filter-cake build rates for the Filtration Flood Front Model (FFF)

Fluid loss under simulated wellbore-scaled conditions, with ECD sand-face pressure(s), scaled annular mud pump velocities and circulating & shut-in wellbore temperatures.

Dynamic leak-off rate under simulated wellbore and reservoir conditions & FFF modelled for planned wellbore/completion diameter.

Time required establishing an effective filter-cake under simulated wellbore/reservoir conditions with ‘mud pumps’ on.

Results:

The results of the core tested allowed the volumes of fluid that would be lost to the

formation in the event of a collision to be calculated.

Assuming the 1000m well at 8.5" diameter, the fluid lost to the formation during the first 30 minutes, over and above wellbore displacement volume, would be ~ 32bbls.

A further 170 minutes was then required to form a relatively impermeable filter-cake and stabilise conditions

Over the full 200 minute time lapse until a less permeable filter-cake is formed the total mud lost to the formation of the intersected well would be ~ 110bbls.

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Technical Problems Encountered

ML Anchor Packer Not Setting x 2 Purchased by supplier from another client

Findings Lack of an equipment inspection upon

equipment arrival

Lack of a procedure specifying proper MLP packer storage method

Lack of a packer inspection requirement in the field

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ERD Problems Encountered

Helical Buckling of B5ST1 Lower Completion While running sandscreens just prior to making up the ML Junction, string stood up

from approximately 2120 to 2180 mMDRT

Modelling identified the potential onset of helical buckling, however, this was advised after the fact

Actions Taken Pulled back to up weight and ran back down utilising 10MT of TDS weight with push

sub

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Surface Vibration

2010 campaign: During the drilling phase a high level of vibration “pipe

whip” was observed in the drill string at surface.

Observed when drilling or back-reaming at depths beyond ~1500 mMDRT

Exhibited a dynamic behaviour consistent with backward whirl;

Introduced significant HSE risk through potential for dropped objects;

Pipe whip had to be managed through variation of parameters to minimise severity, restricted access to drill floor and frequent dropped objects inspections.

Observed to a greater or lesser extent on all three 2010 wells along with substantial BHA wear/damage.

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2012 Campaign Actions Taken

Decision was made to additional vibration monitoring in attempt to identify the source of the vibration.

B5ST1 well: 3 x Vibration sensor subs were run in the BHA as follows: Adjacent to the under-reamer,

Adjacent to the string stabiliser ; and

Three joints behind the jars.

Observations: Severe “Pipe Whip” was observed at surface, but results from Black Box data the vibration data were inconclusive showing no down hole source for vibration.

B9ST1 well: 4 x Vibration sensor subs were run in the BHA as follows: Adjacent to the under-reamer;

Two joints behind the jars;

2000m behind the bit in the drill string; and

2700m behind the bit in the drill string.

Surface Vibration Continued

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Surface Vibration: Lateral Vibration – RMS

Observations: Severe “Pipe Whip” was again observed at surface with vibration sensors identifying high level vibration in drill string from surface to ~500mMDRT, peaking at ~300mMDRT.

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It is believed the extreme side forces induced by the high DLS in the build sections before, at and outside the casing exit window, effectively decouple the string dynamics inside the casing from those outside the casing

Overall Management of tortuosity and parameters will reduce damaging dysfunctional

conditions

Lateral Vibration:

Below casing window, lateral vibration maintains acceptable levels

Above the casing window parameter & profile driven lateral activity can occur at very high and damaging levels.

Torsional Vibration occurs at the start of runs, in the reamer and

HWDP positions Run – 1 Driven by casing exit parameters

Run – 2 Driven by hole tortuosity

Surface Vibration: Conclusions

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Project Outcomes

2 x Lateral Sidetracks successfully drilled and completed

1 x Mutli-lateral with intelligent completion

1 x P&A and Sidetrack with scope remaining for future conversion to multi-lateral

Recoverable reserves in excess of expectations

Deliverability (Production flow rates) in excess of expectations

Longest ERD well drilled (and completed) in field to date

Information gained on reservoir structure in south of field enabling identification of future development opportunities.

Successful well slot recovery enabling diversity of well design option for future development opportunities

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Additional Optimisations: Going Forward

Investigate use of asymmetric stabiliser and / or resonant vibration mode upset tool for surface vibration (pipe whip) mitigation;

Investigate alternative to Upside Down Flapper Valve for lost circulation control – 75% Occurrence of early activation to date;

Investigate bi-lateral system with intervention access to each leg with surface operated selective flow control;

Investigate tri-lateral system with surface operated selective flow control to each leg.

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2012 Wandoo Infill Project

QUESTIONS?