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Geological Storage - Risk Assessment & Monitoring

IEA GHG Summer School, Beijing

David White 12th-17th August 2012

Schlumberger - over 80 years of history & technology

First electrical log run by Marcel and Conrad Schlumberger Pechelbronn, Alsace, France September 5, 1927

Why Monitor? – Manage Risk

Risk =

“ (Impact of Undesirable Occurrence) x

(The Probability of its Occurrence)”

But it is not that simple……

Risk Perception Public vs. Experts

Public Feels - The Dread Factor - reacts very negatively to “worst-case” risk assessments, Public: Risk Size= (“Known” factor)*(”Dread” factor) Experts Calculate - tend to rely on quantifiable “realist” perspectives, Risk Size= (Probability)*(Loss)

Expert risk studies are rarely effective for convincing the public that a proposed project is safe.

Thesis by Gregory Singleton, MIT May 2007

CCS Risk Types

GENERAL RISKS

● Public acceptance ● Economic ● Legal TECHNICAL RISKS:

● Extreme events (major releases) ● Ground fresh water resources contamination ● Soil contamination ● Leaks

● Risk Acceptance Criteria ● Standards ● Regulations and Policies

Key Concerns: Leakage & Seismicity

Risks can be managed – we do it all the time

● Evaluate & Understand ● Model & Simulate ● Measure & Monitor ● Mitigate ● Experiment and

Demonstrate

(I bet they tried it with a dummy first … …and it might be a fake!)

http://www.youtube.com/watch?v=UXXC2etJeZQ

What do we need?

Finding the right Storage Site

…the best risk reduction approach is to choose the right site in the first place

Capacity: The amount of CO2 that can be safely stored

Injectivity: The ease with which the CO2 can be injected

Containment: The ability to store CO2 safely and permanently

Other: • Environment • Infrastructure • Regulation • Public opinion • Finance

CO2 Monitoring – 3 objectives

Boundaries

Containment

#1: Watch stored CO2

#2: Watch possible leakage paths

#3: Monitor the environment Well Integrity

Sealed fault

Monitoring well

Abandoned well

Monitoring well

CO2 injection

well

Freshwater aquifer

Operational Monitoring

Drawing from the Oilfield: Static and Dynamic Modeling Workflow

Surface imaging Mapping

Data input

3D Geological model

Log interpretation and correlation

Reservoir and Aquifer property population

History match

Fault and Fracture modelling

3-D flow simulation Geochemistry Geomechanics

ECLIPSE

Zooming in on the sub-surface

The Need for Technology: Hi-Res versus Conventional

Monitoring in the Storage Lifecycle

Pre Selection

Appraisal /

Characterization

Development CO2 Injection

Closure

Post closure

Post liability transfer

Performance Management & Risk Control

Pre-injection Injection Post-injection

Abide by laws & Regulations:

EU CCS, EU ETS, state law

Designing a Monitoring Plan

Minimize Costs:

For each technique, For the overall plan over time

Site & technical constraints:

Deployment restrictions, Measurement sensitivity

Reduce Risk & Optimize Performance:

Added value for the operator

Monitoring Plan

Monitoring challenges

Range of scales ● Time - from the very short to the very long ● Space - from the very small to the very large

You can’t directly measure what you want to… ● Spatial distribution and concentration of CO2

● Sealing boundaries, capacity, permeability.

You can’t measure where you want to… ● Confined to the surface or wells

…BUT you measure what you CAN and construct models ● Consistent with available information ● Improve with time ● With some predictive power (within limits)

Questions for Designing a Monitoring System

● What do I want to monitor? ● What property change can I monitor? ● What variation am I considering?

● What measurement technique to use? ● What should be my sensor

specifications?

● Where should I place my sensor? ● For how long? ● How can I deploy it? ● How can I interrogate it?

● How can I interpret the measurement?

● CO2 movements, leaks… ● P, CO2 Saturation, Resistivity

● Accuracy / Precision

● Surface, Obs. Well ● (Permanent, Logging…)

● Operation phase, surveillance

0.001

0.01

0.1

1

10

100

1000

10000

Verti

cal R

esol

utio

n, m

Areal Reservoir Coverage

Tracking CO2 evolution – what we can see

In-well measurements

4D Seismic

Surface-to-well measurements

Well-to-well (Seismic, EM)

CSEM (Offshore only) Gravity

(Onshore only)

InSAR

Microseismic (Onshore)

Size = relative cost

What we can monitor?

CO2 Saturation (neutron, density, resistivity, sonic) Sampling, downhole fluid analysis Cased Hole Formation Resistivity Pressure & Temperature Well Integrity (Cement, Corrosion) Electrical resistivity tomography (ERT) Microseismic X-well seismic X-well EM Distributed Temperature Sensing Tiltmeters

2D, 3D Seismic Microseismic Gravimetry (to back up time-lapse seismic) Echosounding, Seafloor samples Noble Gas Tracers MT (natural source plane wave electrical method) CSEM InSAR (Satellite Radar Imaging)

In boreholes From the surface

CO2 Saturation Measurement - Ketzin

CO2 Saturation ~ 60% in upper sand section (yellow). Little presence of CO2 in lower sand No CO2 above 625 m

625 m

CO2 presence over 4 week interval

Contrast between formation water and CO2 properties can be detected by neutron capture cross-section, hydrogen index, density, resistivity and sonic velocity to quantify the amount of free-phase CO2 present in the pore volume.

Site feasibility

• Are there any wells on the potential storage site? • Do we have access to the well data? • If yes, can we assess the current state of the wells?

Site appraisal

• What data do we need to acquire to assess/reduce the risk of

leakage from wells? • What data do we need to satisfy regulatory requirements

Concept selection

• Can we convert existing wells to CO2 injectors? • Does any well pose a risk of leakage during project life? • If yes, how could the risk be managed/eliminated?

FDP

• What is the residual risk of leakage from the wells? • What remediation/contingency plans need to be in place during

operations life? • What monitoring plans will be implemented during injection?

Well integrity risk: questions…

EU regulations state that risk of leakage from a potential storage site must be assessed before a storage licence can be granted. During operations, risk assessment drives site monitoring, post-closure and liability transfer plans.

Pitting Corrosion

Cement Alteration

Wellbore Integrity

Isolation Scanner of the formation wall through casing and cement reveals hole enlargement

Mechanical: multi-finger

caliper

Acoustic: imaging

A primary electromagnetic field is generated from a first well, inducing currents in the formation and a secondary EM field, detected by receivers in the second well. It has a limited resolution but could be used to track the CO2 plume, possibly in conjunction with seismic methods.

Electromagnetic technology - Local application Cross-well Electro-Magnetic

Global measurements

Time-lapse Seismic

InSAR Elevations determined from Synthetic Aperture Radar (SAR) images by interferometric methods. Uses two (microwave) antennas, displaced either vertically or horizontally, installed on the same satellite or aircraft platform. One of the antennas transmits the signal, but both receive it, resulting in two images being created.

Gravimetry Sensitive to formation density

CO2 replacing water can be detected due to contrast between CO2 and water Gravimeters are placed at the surface or downhole

Sleipner 4D: Courtesy of Statoil

Magnetotelluric (MT) Measures the natural low-frequency electromagnetic field of the Earth

CO2 storage in Norway? Utsira formation (Millenium atlas, 2000)

Tordis

Important to perform a 3D mapping of storage volumes

Crater created by injection of bore fluids into the wrong formation (shale instead of Utsira sand) close to Tordis field: 8 m deep and 25 m wide

Quantitative Analysis of time-lapse seismic monitoring

Source: Quantitative Analysis of time-lapse seismic monitoring data at the Sleipner CO2 storage operation. The Leading Edge, Feb. 2010, BGS, IFP, SINTEF, Schlumberger, TNO, INIOAG

Seismic amplitudes in 2006

Top Utsira Sand CO2 – Water contacts 2001 --------- 2004 --------- 2006 ---------

Calculate the expected time-lapse seismic signal (rock physics modelling, based on Gassman’s equation ), to decide on 4D seismic. Some indicative rules of thumb:

Signal will be stronger in aquifer than in depleted gas reservoirs Shallower reservoirs will result in a stronger signal than deep reservoirs

Gravity technology - application

Courtesy: - Arts et al., 2008, First Break - Gravity monitoring at Sleipner CO2 injection site Report on 2002 baseline survey ,O. Eiken, T. Stenvold, M. Zumberge, S. Nooner, 2003

Time-lapse gravity: CO2 density is lower than water density, higher than gas density Resolution is an order of magnitude lower than seismic resolution Surface gravity and borehole gravity

4D gravimetry and 4D seismic - Sleipner

Note: Accuracy of ~4 microGal

Courtesy of Statoil

How Microseismic data can be recorded

MONITOR WELL

Live well Monitor well Behind casing

Surface seismic Buried seismic array

LIVE WELL

Sensor locations

Microseismic visualisation

Microseismicity induced by injection

Remote sensing technology - InSAR

We can calculate the expected changes in surface elevation based on pressure changes and a 1D Mechanical Earth Model. This allows us to decide if a satellite acquisition will provide the required resolution (several mm).

From Mathieson et al. GHGT9; 2008

Ground deformation monitoring using radar imaging by satellite. Interferometric synthetic aperture radar is a space borne geodetic tool used to obtain high spatial

resolution surface deformation maps.

1989 – Underground flow from well 2/4-14 (Saga-well) – first 4D on Norwegian shelf

Figure from Dag O. Larsens SEG-presentasjon in 1990.

Fractured cap-rock due to high injection pressure

Source: Well performance diagnostics by integrating 4D seismic in a coupled fluid flow / geomechanical model Jarle Haukås*, Jan Øystein Haavig Bakke, Martin Häge, Lars Sønneland, Schlumberger Stavanger Research.

Top reservoir Measured time shifts

Assurance Monitoring

Tracking the CO2 plume

• Geophysics techniques • Pressure, Temperature • Well logs (CO2 Saturation) • Sampling • Geodetic methods

Quantification of leaks • Soil gas measurements • Surface gas measurements • …

• Potable water quality • Soils acidity • Atmospheric concentration • Surface deformation

Impact: HSE monitoring Injection operation control • Wellhead pressure • Bottom hole Pressure and Temperature • Injection rate • Microseismicity

Quantification of injected CO2

• Mass flow • Gas stream composition and phase

Well Integrity • Annulus pressure • Corrosion • Cement • Soil gas measurements

Cap Rock / Fault Integrity

• Microseismicity • Pressure interference

Detection of leaks/migration • Sampling & chemical analysis • Geophysics techniques • Pressure interference • Soil gas measurements • Vegetation stress • Eddy correlation tower

Verification Monitoring

Operational Monitoring

Verification Monitoring

Operational Monitoring

Objectives of the monitoring plan - Summary

Conclusion: Monitoring as part of Minimizing Storage Risk

Containment – THE storage issue: ● Failure of sealing cap rock ● Permeable faults and fractures ● Migration along wellbores Risk reduction through: ● Choosing the right site ● Detailed reservoir characterization ● Comprehensive modelling ● Ongoing monitoring Risk mitigation through: ● Remediation methodologies ● Risk-based approach to project

management

Monitoring: ● Different types of monitoring objectives ● Existing technologies and tools ● More work/research on the integration ● Closely related to Modelling

Capacity

Injectivity

Containment