Quest CCS Project
Learnings from the First Year of Operations

CCS Technical WorkshopTokyo, JapanJanuary, 2017
Simon O’Brien
Quest Storage Manager

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Cautionary Statement
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2Shell’s Response to the CO2 Challenge

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3Shell’s CCS/CCUS Project Portfolio

TCM

QuestGorgon

Boundary Dam

 Industrial scale projects in operation
 Industrial scale projects in construction
 Involvement through Shell Cansolv
Technology

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Lula CCUS

4Quest Overview

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5Quest Project at a Glance• World First – the first full-scale CCS
project for oil sands• Who – joint venture between Shell,
Chevron and Marathon• Where – capture at Scotford Upgrader;storage in saline aquifer: the Basal
Cambrian Sands (at a depth of 2000m)• Impact – 25 million tonnes of CO2
captured over a 25 year period (1/3 ofCO2 from the Upgrader) – equivalent to
the emissions of 250,000 cars

• Technology – syngas capture usingamines
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6The Athabasca Oil Sands Project (AOSP)
MUSKEGRIVER MINE
Fort McMurray

BitumenPeace River

CORRIDORPIPELINE
Edmonton

H2
Calgary

SCOTFORDUPGRADER
Bitumen to Synthetic crude(255,000 bpd)

SCOTFORD
REFINERY(SHELL ONLY)Copyright of Shell Canada

QUEST: CO2CAPTURE FROM
3 HMUS7

CO2 Capture• The Hydrogen Unit combines
steam and natural gas to produce
high pressure steam and H2 for use
in the upgrader• The Amine Unit uses Shelltechnology to capture the CO2
directly from the process• The process produces a 99% pureCO2 output• Award winning integrated,
modular construction (Fluor)

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8Transport• CO2 dehydrated and compressed to >10 MPa tokeep the CO2 in dense phase through entirepipeline• 65 km pipeline with 6 block valves (every 4-15 km)• Pipeline construction Oct 2013 – Aug 2014, withconsiderable stakeholder interaction• Cleaning and preserved with nitrogen byOctober 2014

• First CO2 into pipeline August 2015

Copyright of Shell Canada9Storage
3 well pads:

SurfaceCasingCement• Each pad has 1 injection well, 1 deep
monitoring well and multiple shallow groundwater wells

Intermediate
CasingTubingMain Injection
Casing• Conventional drilling methods• Multiple steel casings for injection wells, 3 in
freshwater zone, all cemented to surface• Comprehensive Measurement, Monitoring andVerification program

SALT SEALS
PackerAssembly
SHALE SEALSTARGET FORMATION
Perforations allow
CO2 to penetrate
the formation

Copyright of Shell Canada10The Storage Complex
BCS Storage Complex••Deep (~2km) saline aquifer•Multiple thick, continuous seals (>150m within
the complex)••High quality (~17% porosity) sandstone reservoir

Below potable water zones, zones withhydrocarbon potential

Excellent permeability (~1000mD)

85m

Prairie Evaporite– Additional Seal

85m

Upper Lotsberg Salt

– Ultimate Seal

10m
70m

Lower Lotsberg Salt

– Secondary Seal

40m

Basal Cambrian SandMiddle Cambrian Shale – Primary SealBCS
StorageComplex– Storage Reservoir

PreCambrian Shield
Copyright of Shell Canada11Geology and Wells

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Sea is Getting Deeper and Muddier

Storage Complex Geology

Schematic of the Core
Middle Cambrian Shale(MCS) – The Primary Seal
Predominantly shale.
Deposited in an offshore
environment as sea gotdeeper

FWWB

OffshoreTide-dominated bay margin

Proximal bay
Distal bay

Lower Marine Siltstone(LMS) – Impedes CO2
migration.
Intermixed mudstones andsandstones

Basal Cambrian Sandstone(BCS) – The injection zone.

Proximal bay

Tide-dominated bay margin

Dominantly sandstones,
with local thin - to very
thin-bedded mudstones
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13Reservoir Screening
BCS Thickness Map (1m contours)

Stratigraphic
Cross-section

Upper Lotsberg

Lower Lotsberg

BCS Reservoir Quality

Seal Thickness Maps

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After Grobe and Stewart, 200214

Regional Correlations

Regional correlation of welldata provides confidence inour depositional model andhelps us predict how thereservoir will respond to CO2

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Reservoir Modeling (Static, Dynamic)• Well Correlations• Structural Framework• Facies Interpretation• Regional PropertyTrends• Upscaled Well Logs
Pressure Scale Sector Model

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CO2 Plume Scale Sector Model

16

Development Scenario Modelling
Expectation Case

Low Case
Porostiy

3 wells
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Porostiy

5+3 wells

3+2+3 wells
17Conceptual Storage Plan
CO2Saturation

DeltaP(kPa)

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Drilling Campaign

Injection Well

BCS Legacy Well
Quest Appraisal Well
Cross Section Figure 2-3
3D Seismic Coverage• 2 appraisal wells(~ 2 km MD, to BCS)

• 3 injection wells

Westcoast 9-31(~ 2 km MD, to BCS)NE

Imp. Darling
No.1• 3 deep monitoring wells(~ 1.7 km MD, to top of seal)• 9 groundwater monitoring wells

Well pad
Well Pad
5-35(< 0.2 km MD, in GWP zone)

5-35

Imp. Egremont
W 6-36

Well Pad
8-19

Well pad 8-19
Well Pad
7-11

Well pad 7-11

Imp. Eastgate
No. 1-34

Redwater 3-4

SWPreCRedwater
11-32

BCS

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Well Pad Schematic~ 40m~ 30m

Freshwater
Colorado

3 ½” TubingInjection Well (IW)Deep Monitoring
Well (DMW)

Groundwater
Monitoring Well (GMW)~ 180m13 3/8”~ 450m5 9/16”8 ¾”

Datalogger(pH, Eh)

Downhole
P/T Gauge
CKLK

Geophone array (1 well only)~ 1750m

Upper

Lotsberg Lower
UMSMCS
LMS ~ 2000m
BCS~ 2150m

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5 ½”

Fibre optic cable
9 5/8”

7“20Reservoir Model – Plume Predictions

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Based on pre-injection model•Current estimate of max plume lengths:
2.5 to 4.2 km
21Remaining uncertainty on relativepermeability of CO2 reduced in 2016 withmodel update and tuning to performancedata.

Measure, Monitor and Verify (MMV)

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Quest MMV Plan 2015
Baseline
Atmosphere

Injection

ClosureLightSource Laser CO2 Monitoring
Eddy Covariance Flux Monitoring?

Biosphere

CO2 Natural Tracer Monitoring
CO2 Flux and Soil Gas
Remote Sensing (Brine & NDVI)•Shell Groundwater Wells: Continuous EC, pH
First of a kind –Discrete Chemical and Isotopic Analysis on water and gas

Hydrosphereconservative
Private Landowner Groundwater Wells (discrete chemistry and Isotopes
on water andapproachgas)

Geosphere?

Time-Lapse Walkaway VSP Surveys•

Time-Lapse 3D Surface Seismic

Comprehensive: fromatmosphere to geosphere• Risk-based
Downhole Pressure & Temperature (DHPT) above Storage
Complex (CKLK Fm)• Site-specific
Downhole Microseismic Monitoring• Independently reviewed
Injection Rate Metering, RST Logging, Temperature logging• Combination of new andDHPT, Well Head PT, Distributed Temperature and Acoustic Sensing,
InSAR

Deep
Monitoring
Wells
Injection
Wells

traditional
technologies
Annulus Pressure Monitoring, Wellhead CO2 Sensor, MechanicalWell Integrity
Testing,
Operational Integrity Assurance•

CBL, USIT2010

2015

2020

2025

2030

2035

Baseline data collected
before2040 start-up
2045
2050

Time (years)
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Atmosphere: LightSourcefrom Hirst et al. 2015

• LightSource system installed and functional at all
injection sites prior to CO2 injection• Release testing very successful – all releases
detected, quantified and located• Confirmed as the technology
for atmospheric monitoring atQuest

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Hydrosphere: Groundwater Monitoring• Continuous monitoring of Shell project wells (onwell pads) – recently changed sensors to improvereliability• Extensive field sampling campaign of landownerwells, many measurements taken

Ground water wells within Quest SLA(Brydie et al.,2015)• Comprehensive baseline data
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Geosphere: Microseismic
Surface noise
Regional Events(not Quest related)
Locatable Events• Microseismic array installed in DMW 8-19 recording baseline MS activity
in November 2014 – re-installed in April 2015.

• Three small (M < -1) locatable events have been detected through the endof 2016
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Geosphere: Time Lapse VSPs

• Baseline VSP acquired preinjection in April, 2015 (noCO2 is present in the reservoir).

• The first monitor VSP wasrecorded in March, 2016.

• Time lapse signal quite strong,
consistent with modelled plume
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Geosphere: Pulsed Neutron Logging• Pulsed Neutron log was run in May 2015 prior toinjection (Black line), and a repeat was run after 6
months of CO2 injection. (Red line)• Initial Observations• Change in the pulsed neutron response over theperforated (Red rectangle).

• No change in log response above or below theperforated interval or through the LMS member.

• Conclusions:• CO2 is contained within the perforated interval
and the BCS reservoir. (Red rectangle).

• The injected CO2 is mainly within the highpermeability streaks (Green Arrows).

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Storage Operations

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Quest – First 16 Months’ Performance• Kept 8-19 steady initiallyto simplify pressure data at5-35• Capacity testing inFebruary• Well logging runs during
Turn Around• First million tonnes
captured and stored byAugust, 2016

• Wells have not been alimiting factor
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Reservoir Model – Pressure Forecasting• Still too early for reliable
history matching• Reservoir properties looking
more like our modelled highcase scenarios• (Far field) data from 5-35
considerably better than
expected• Pressure build-up in the BCS
is still forecast to be less than
2 MPa (∆P) by the end of theproject life

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Quest Storage Learnings
MMV:• MMV systems working well – no triggers• Microseismic array has been very quiet• VSPs can image CO2 in the BCS, DASworking very well
Wells:• Only 2 wells active – contributing tosignificant wells and MMV savings• Pulse neutron logging confirmed that CO2 is where it is supposed to be• Important to keep water out of the wells, even the small amounts routinely usedduring logging
Reservoir:• Excellent injectivity – comparable to high case scenarios• After 25 years, we expect to use 5-7% of the available pore space• Current estimate is that the ∆P at the end of the project may only be 2 MPa.
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Acknowledgements• Government of Alberta, Department of Energy (DOE)• Government of Canada, Natural Resources Canada (NRCan)• Shell staff (Calgary, Houston, EU, Scotford and in the field)• 3rd Party Contractors: Fluor, Golder Assoc., ESG, Boreal, Air Liquide, U.
of C., U.B.C., U. Vic., et al.

• Partners: Chevron Canada Ltd & Marathon Oil Canada

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