co2 storage in depleted gas fields

CO2 STORAGE IN DEPLETED GAS FIELDSFilip Neele, Stefan Belfroid, Aris Twerda

STORAGE IN DEPLETED GAS FIELDS

First choice for CO2 storage in The Netherlands~ 1.5 Gt capacity in ~100 offshore fieldsRe-use of pipelines, platforms, wells

Competition with other uses for offshore areaWind farmsEnergy storage or conversion

First gas fields (cluster) under development for CCSPorthos consortium (Rotterdam)

2 11-12 February 20204th offshore CO2 storage workshop IEAGHG

North Sea Energywww.north-sea-energy.eu

http://www.north-sea-energy.eu/

ALIGN - CCUS DEVELOPING CAPACITY

Abundant storage capacity, but how to develop it?

Potential timeline of field developmentRanking of options – unit storage cost, location, capacity, etc.


P18 cluster35 Mt

P15 cluster35 Mt

Q1 clusterDGF, DSF

K14-K15 clusterSeveral fields

First choice(~25 km dist.)

Second choice?(~20 km)

Re-use oil pipeline?(~75 km)

Several clusters in central DCS

DGF: depleted gas fieldDSF: deep saline formation

T&S SYSTEM

11-12 February 20204th offshore CO2 storage workshop IEAGHG

Compressor

Platform

Riser

Reservoir

Wells

Large pressure drops in system – management of CO2 temperature is

key element of operations

High-pressure pipeline(s)

Low pressure (at start)Well integrity, fault stability, flow rates, intermittency, low-

temperature cycling, …

Pressure and temperature distribution and development in reservoir (injection of cold CO2)

Risk management planMonitoring plan

Site conformanceSite handover

Re-using platforms, wells, pipelines

Network developmentFlexibility, robustness

4

RE-USING DEPLETED FIELDS(AND THE WELLS)


15 °C

CO2 hydrate

Need water…

Safe storageWell integrity maintained during operations

Injection on – off: temperature cycling in wellWellhead: T > -10 °C (material constraint)

Reservoir and cap rock integrity preservedLarge contrast temperature CO2 - reservoir

Maintain operability of reservoirAvoid salt deposition and hydrate formationHydrates: bottomhole T > 15 °C

Flow rates through well: limits due to erosion, vibration

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

Distance [km]

-50

-40

-30

-20

-10

0

10

20

30

Tem

pera

ture

[deg

C]

0

0.05

0.1

0.15

0.2

0.25

Dia

met

er [m

]

10

20

40

80

130

170

T=15

D

-10 °C (wellhead)

15 °C (bottom hole)

TVD ~ 3.5 km (deviated well)

At wellhead:Massflow: 10 - 170 kg/sPipeline pressure 100 barWellhead temperature: 10 °C

Near bottom of well:Reservoir pressure: 20 barReservoir temperature: 120 °C


Minimum safe injection rate

80 kg/s (~2.5 Mtpa)(only for this

particular set-up!)

EXAMPLE: LIQUID, COLD CO2CONDITIONS ALONG WELL

Results depend on well completion, reservoir properties, etc.: system design to take the flow phenomena into account

DYNAMIC OPERATIONS – SHUTINShutin

Reservoir pressure 20 bar Initial mass flow rate 30 kg/sWell shut in

During shutinWellhead pressure decreasesLiquid is formedConditions shift to phase lineResults in temporary low temperatures

Requires detailed heat transfer calculations including heat capacity

Tubing temperaturesAnnulus temperaturesCement bonding

11-12 February 20204th offshore CO2 storage workshop IEAGHG7

Total time: 90 minutes

CONFORMANCE MONITORING

Define site conformance indicatorsPressure, temperature in places in system

Compare measured and observed field performance indicators

Measured: noiseModelled: uncertainties, model limitations

What is magnitude of signal in monitoring data from risks that do occur, compared to noise and uncertainties?

11-12 February 20204th offshore CO2 storage workshop IEAGHG

Regulations in place, but not tested yet

EU Storage Directive & ETS: emphasis on monitoring, measuring and verification

How well can we assess conformance?

8

EXAMPLE: BHP BASED MONITORING


Correct assessment depends on (a.o.):Uncertainties in a priorimodel, variations in CO2quality, noise in monitoring data

False negatives, false positives

Improve: decrease uncertainties, add other monitoring

techniques

0 5000 10000 15000

Time (days)

0

0.2

0.4

0.6

0.8

1

Frac

tion

of c

orre

ct a

sses

smen

ts

t = 30 days

BHP = 0.5 bar

BHP = 1.0 bar

BHP = 1.5 bar

BHP = 2.0 bar

BHP = 2.5 bar

BHP = 3.0 bar

CONCLUSIONS

Depleted fields: blessing in disguise?

Abundance of data from production periodWell-defined storage capacityPipelines, platforms and wells to be re-used

Low pressure represents challenge – injection project becomes temperature management projectFor NL fields: size (capacity) of fields requires many fields to be developed



This work has been produced with support from the ERA-NET ACT Pre-ACT project (Project No. 271497) funded by RCN (Norway), Gassnova (Norway), BEIS (UK), RVO (Netherlands), and BMWi (Germany) and co-funded by the European Commission under the

Horizon 2020 programme, ACT Grant Agreement No 691712. We also acknowledge the following industry partners for their contributions: Total, Equinor, Shell, TAQA.

AcknowledgementsACT ALIGN CCUS Project No 271501

This project has received funding from RVO (NL), FZJ/PtJ (DE), Gassnova (NO), UEFISCDI (RO), BEIS (UK) and is cofunded by the European Commission under the Horizon 2020 programme ACT, Grant Agreement No 691712

www.alignccus.eu

http://www.alignccus.eu/

THANK YOU FOR YOUR ATTENTION

TNO.NL/ECNPARTOFTNO

co2 storage in depleted gas fields

Documents