Assessing Carbon Capture and Storage (CCS) value chains units... · Master course on CCS,...

Master course on CCS, University of Zagreb

6-7 May, 2011

CO2 storage in subsurface reservoirs 1

Assessing Carbon Capture and Storage (CCS) value chains

May 6th, 2011

Chain units: subsurface storages

Slide 26-7 May 2011, CCS master course University of Zagreb

CO2 value chain


Ref: www.sintef.no/ecco

��

��Slide 46-7 May 2011, CCS master course University of Zagreb

Transport

Pipeline Ship

Source

Industry Power Plant

Storage / Sinks

Buffer Geology

Pip

elin

e 1

Pipeline 4

Pip

elin

e 5

Pip

elin

e 3

Define Network / Components / Contracts

Power Plant w/ Capture

EOR Field

Pip

elin

e 2

Steel Mill w/ Capture

DGF1-n

The Network can build-out with time as components are added

ECCO tool: integrated technical/economical CCS evaluation tool

Contracts

C1-nTSO1-n SO1-n

Tool output:

� Tech KPIs

� DCF-KPIs

� Planning charts

� EUA price

� Cost indices

� Govt matching

funds req’d

Initially LT

contracts?Later, more

ST?


Subsurface chain units (storage)

� Oil Fields

− CO2-EOR: Enhanced Oil Recovery through CO2 injection

− Potential incremental recovery 5-10+% of STOIIP

− EOR on top of / concurrent with primary recovery operations

� Depleted Gas Fields

− Subsequent to gas production operations

− DGF at abandonment pressure (10-50 bar)

− CO2 injection to re-fill pore space up to original pressure

� Aquifers

− Usually, little information (sealingness etc)

− Undepleted pressure: high injection back pressure

− Geochemical issues, brine displacement, storage capacity

→ EGR


Storage by means ofCO2-EOR

High pressure.Steady-state injection.

Injectivity remains ≈ constant as reservoir is filled with CO2.


6-7 May, 2011



Typical production history oil field


Window of Opportunity

Typical field annual oil production curve as a percentage of maximum rate showing CO2-EOR window of opportunity


Principles CO2 enhanced oil recovery (1)

� Immiscible CO2 flooding

− Below minimum miscibility pressure (MMP)

− Partitioning CO2 in oil phase > swelling > lowering viscosity

Viscous oil :

− For pressures > 80 Bar (steam injection too expensive)

− CO2 net use: 0.15-0.26 ton/bbl.

� Miscible CO2 flooding

− Above the MMP, CO2 extracts/puts lighter components in the oil.

− Mixtures miscible with original oil: interfacial tension reduces to zero.

− CO2 net use 0.30-0.52 ton/bbl.

shallow

deeper


Physical principles of CO2-EOR (2)

� Dissolution of CO2 in oil, resulting in − Swelling of oil (expansion drive)− Reduced viscosity of oil (higher rates at given ∆P)

� Reduction of oil/water interfacial tension (IT)− Reduction of irreducible (residual) oil saturation Sor

− Microscopic displacement efficiency is enhanced� Less energy required for deformation of droplets through pore-throats

� Vaporising of light HC-components into CO2 phase + condensing into heavier oil

− This enhances overall miscibility

� Above effects are a function of Pr, Tr, oil composition, water salinity, rock properties, etc

Immiscible

Miscible

Miscible


∆∆∆∆IT results in higher krow end-point

� CO2 reduces IT between oil and water

� Rel perm end-point to oil becomes higher

Swc=0.2krw=0

Swc=0.65kro=0 Swc=0.75

kro=0


CO2-EOR technical feasibility (1)

� Primarily: miscibility of CO2 in oil. Transition point. − Depends on type of oil, on P and T of reservoir. See XL file

CO2-EOR Minimum Miscibility Pressure

as a function of the C5+ Molecular Weight of the crude oil

and of the reservoir temperature(ref Holtz et al. correlation)

ECCO; M =254

0

100

200

300

400

500

600

700

800

900

1000

0 50 100 150 200 250 300 350 400

Reservoir temperature (?C)

MM

P (b

ar)

MW C5+ = 340

MW C5+ = 300

MW C5+ = 280

MW C5+ = 260

MW C5+ = 220

MW C5+ = 200

MW C5+ = 180

MW C5+ = 160

ECCO; M =254

Reservoir MMP

Regional P vs T


6-7 May, 2011



CO2-EOR technical feasibility (2)

� If miscibility of CO2 in oil not obtained, then still a swelling and ∆µoil effect. No/minor ∆(IT) effect. This will result in lower ∆(recovery factor) than P>MMP

− Perhaps ∆RF only 0-5%

− Re-pressurising reservoir may be considered

� Other main technical feasibility issues:− Vertical sweep efficiency: depending on kv/kh ratio

� Under certain conditions, this can be improved by alternating the injection between CO2 and water: WAG injection

− Well integrity: production wells should be stainless steel� Water is produced and CO2 is being re-circulated: water + CO2 is

corrosive


EOR pre-requisites

A good EOR process implies:

1) good contact of oil by drive fluid

2) viscous forces dominate over capillary forces

Good mobility control

1>=c

oM

λ

λ

1>>=σ

µuN

c

Good microscopicdisplacement


Pseudo ternary phase diagram

P>MMPVaporizing Gas Drive

mechanism

Stripping

U2

Plate point

100% mole CO2

100% mole light oil (C2-C13)100% mole heavy oil (C14+)

Initial composition of oil

Dilution lines

Tie line

Critical tie line

U1

L1

L2

Dilution line

Miscible CO2 flooding (a)

100%C14+ heavy oil

components

L+G

Liquid

100%C2-C13 light oilcomponents

100% CO2


G2

Intemediate

Heavy

Initial composition of oil

Tie lines

G1

L1L2

Light

Initial composition of gas

L0

G0

Dilution line

Critical tie line

L3

G3

L4

G4

Oil rich in heavy components

Condensing Gas Drive

Mechanism

Oil extracts intermediate compounds

Miscible CO2 flooding (b)

Fractionheavy oil

components

Fractionlight oilcomponents

Mixture CO2-intermediate compounds

L+G

Liquid

Slide 176-7 May 2011, CCS master course University of Zagreb Slide 186-7 May 2011, CCS master course University of Zagreb

Gas cap

Fine-grid reservoir model required

Residual oil

Cap rock

Sweep efficiency

� Gas migration very sensitive to heterogeneities

� Buoyancy effect may contribute to sweep efficiency


6-7 May, 2011



Injection strategy

� Continuous injection

� WAG/WACO water-alternating CO2

− More stability for flood

− Less use of expensive CO2

� May not be relevant if CO2 storage provides income

3-fluid relpermsHysteresis

A lot of circulation of CO2, separation and re-injection

Typically, gross volume of CO2≈2* net volume (purchased CO2)


Continuous vs. WAG injection (1)



� Vertical sweep efficiency much improved due to WAG

∆recoveryWAG

∆CO2-injWAG



� WAG initially lower qoil, then sustained higher qoil

Onset of CO2

injection



� Note higher water production of WAG: ∆cost


Simplified CO2-EOR production

facility diagram (Austell, 2009)


6-7 May, 2011



Gas / Oil / Water separator


Multi-stage separation


CO2 separation and injection at

Szank field, Hungary


SACROC, KMCO2 Snyder, Texas, USA

� CO2-recycling facility

− onshore solution


Pailin Field, Unocal Thailand

� CO2-recycling facility

� Offshore solution to meet contractual gas production requirements


CO2-EOR: geochemical

complications in reservoir

� Asphaltene precipitation in reservoir (pore clogging) and production wells

� Dissolution of rock (CaCO3) and subsequent re-precipitation in carbonate reservoirs → pore clogging

� Salt precipitation → pore clogging


6-7 May, 2011



Corrosion: Causes and Mechanisms

Corrosion in production (or injection)

wells or pipelines.

� Dissolved gases (oxygen O2, carbon dioxide CO2 or hydrogen sulphide H2S) can cause corrosion. In addition, salts may produce corrosion.

� Bacterial activity can cause high levels of H2S.

� Water is necessary for corrosion to occur. There is a chance that corrosion will begin when the water-cut is above 20%.

� Consequences of corrosion can be dangerous and costly.


Corroded pipe


Stress corrosion cracking


Corrosion : Prevention

Important to monitor the corrosion that is taking place. Monitoring methods are:

�Small recoverable samples of the steel (“coupons”)

�Caliper tool or borehole televiewer

�Analyse the produced fluids for iron compounds.

Methods of prevention of corrosion are:

�Use of corrosion resistant steel, or composites

�Chemical inhibition, by injection at the bottom of the well.

�Tests needed to check effectiveness and unwanted side effects.


Composites are being

increasingly used

against corrosion

Bonstrandsteel strip composite

tubing


Use of “type curves” (1)

� Rather than making each time a case-specific, full-field 3D full-physics numerical reservoir simulation model, reservoir performance can be approximated using “type curves”.

− These can be derived from “typical” reservoir simulation studies, that are representative for certain types of geology and for a certain PDO.

� Time domain is eliminated

� All volumes are expressed in cum. HCPV

� User has to judge representativeness of type curve for his case study.


6-7 May, 2011



Use of “type curves” (2)CO2-EOR performance after onset of CO2 injection

Reservoir: type1; PDO: cont CO2inj;

MatBal at start CO2inj: RFO=45%, p=0.91pi

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

0% 50% 100% 150% 200%

Cumulative CO2 + w ater injected (%HCPV)

Cu

mu

lati

ve p

rod

ucti

on

(%

HC

PV

)

CumCO2Prod

CumWatProd

CumEOR

CumPrimOR

� X-axis: Cum amount of CO2 (and water) injected (in HCPV)

� Y-axis (curves): Cumulative amount of produced fluids (in HCPV)


How much CO2 can CO2-EOR oil

field permanently store?

� Limited: << DGF with same PV− Oil field was originally at high pressure

− HCPV oil+water produced replaced by CO2 (and water)

� CO2 is being injected and re-circulated until Opex > oil revenue: economic stopping criterion.− ETS: stop if Opex > (oil + ETS revenue)

� At time of shutting-in field, a certain amount of CO2 will remain in reservoir. This is the amount permanently stored.


ECCOtool example

� STOIIP = 27 MSm3 = 170 MMbbl: 19 Mt CO2 permanently stored → 0.7 MtCO2 / MSm3 STOIIP

CO2 permanently stored cumulative (Mt)

0

5

10

15

20

25

2010 2015 2020 2025 2030 2035 2040 2045 2050

Year

Mt

CO

2 p

erm

an

en

tly s

tore

d


Weyburn (Canada) man-made CO2 (coal gasification plant N. Dakota)West Texas (USA): Natural CO2 from surrounding states

CO2-EOR in North America


CO2 EOR economics

�Extra oil

− Miscible 10-15% STOIIP

− Immiscible 5-7%

�CO2 net consumption

− Miscible 0.4 t/bbl

− Immiscible 0.2 t/bbl

�CO2 purchase price dominates UTC


CO2 EOR economics, Texas

� West Texas: CO2 cost indexed to oil price

Crude @ 50$/bbl => CO2 @ 33$/t

� Miscible net consumption 0.4 t/bbl

CO2 purchasing cost: 14 $/bbl

� Assume CAPEX+OPEX ≈ CO2 costs, so CO2

EOR miscible UTC: 28$/bbl

� Immiscible UTC estimated at 21 $/bbl @50 $/bbl; and 11 $/bbl @25 $/bbl


6-7 May, 2011



CO2 EOR economics with viscosity booster

� Assume CO2 foam has viscosity increase by factor 10 – 100

� Vertical sweep Schoonebeek improves by factor of +/- 2 (Shell CO2 sequestration screening tool)

=> extra oil: 2*0.05= 10 %

� Schoonebeek: 50 .106 BBL


Unit Technical Cost

� Dominated by high costs CO2

Current CO2 EOR

Natural CO2 West Texas

Man-made CO2

Partnerships with owners CO2, tax incentives /subsidies

Increase CO2 credits to 35/40 $/ton



CO2 enhanced oil recovery in USA

� Miscible/immiscible (roughly: light oil vs. HVO)

� 90% of floods is miscible

� Breakthrough generally between 0.5 and 2 yrs, independent of miscibility

� Severe gravity override limits RF, independent of miscibility


Bati Raman structure (Turkey)

48EOR June 2010

SPE 89400


6-7 May, 2011



Bati Raman characteristics� Fractured limestone reservoir, caprock tight limestone

� STOIIP 300x106 m3 (1.9 Bbbls) of 10-13 API, 600 cP

� Pb = 11 bar (160 psi)

� D = 1300 mss (4300 ft)

� CO2 injection started 1986, 1600 t/d (30 MMscf/d), natural source

� CO2 utilisation: gross 2.7 t/m3 (8 Mscf/bbl); net 0.67 tCO2/m3

(0.11 tCO2/bbl, 2 Mscf CO2/bbl)

� Swelling: 20% increase of Boil

� µoil : 10-fold decrease

� Maximum oil rate 2000 m3/d (13,000 bbl/d)

� Expected ultimate ∆RF 5%

49EOR June 2010


1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

1

10

100

1000

1000

10000

100000

GOR [Mscf/bbl]

Average injection pressure [psi]

Gas Utilization Factor [Mscf/bbl]

Oil

pro

ductio

n R

ate

[b

pd

]

Ref. SPE 89400

Bati Raman production performance

50EOR June 2010


Conclusions

� CO2 enhanced oil production is technically feasible (companies are ready), but…

� Currently too expensive unless CO2 is readily available, and not too expensive.

− Building new infrastructure prohibitive, especially offshore

− Creating CO2 market for EOR chicken/egg problem: nobody prepared to take the marketing risk

− Window of opportunity: beyond 20xx, fields will be abandoned.

� Situation may change as emission restrictions increase / if permanent CO2 storage provides additional income.


Storage by means ofCO2 injection in DGF

Initially, low pressure.Non-steady-state!

Injectivity reduces as reservoir is filled with CO2. Non income from ∆∆∆∆hydrocarbons.


Economic limit

Gas

pro

d. ra

te/ C

O2

inj.

rate

t0 t1 = early C/Idue to CCS

planning

t2 = regular C/I due to econ. limit

t6 = start of CO2 injection

Legend:

Business decision

t3 = abd. decision Y/N. If Y, exit. If N,

mothballing capex or

CCS decision

Mothballing Y/N

t4 = inj. test

decision Y/N

Inj.

test

t5 = CCSPDO

decision Y/N

t8 = CCSre-devt. decision

Y/N

t7 = start of CO2 inj.plateau

Economic limit

∆NPV to be transferred as capex to

CCS operator

t9 = CCSfield C/I

decision

t10 = field C/I

Monitoring+ abd.

Post-monitoring(50 yrs?)

t11 = stopmonitoringdecision

t12 = end of

liability period

Exit option

Exit option

CO2-EGR?

Transition DGF to CCS (1)


Transition DGF to CCS (2)

� Technologically, no big issues− Except perhaps in case of EGR: mixing risk CO2/CH4

� However, complicated legal issues:− End of production license not simple: postponing abandonment

capex may be more profitable than paying opex for continued production: PVabd + Cash-ingas > Cash-outopex

− Transfer of ownership depleted asset complicated:

� What is Fair Market Value? (at too low / uncertain CO2 price)

� Liability

� Existing pipeline infrastructure required for fields still producing

• Construction of new pipelines prohibitive.

• CO2-DGF only flies if infrastructure can be re-used.

− Post-injection monitoring obligations and liability not yet clear.


6-7 May, 2011



CO2-DGF physics

� Material balance equation− Normally, if field has history of linear P/Z vs. Gp

graph, then simple material balance can be used for calculating reservoir pressure as a function of cumulative CO2 injected

� Well outflow equation− Highly non-linear PVT: pseudo-pressure formulation

− Joule-Thompson effect around well: pot. problems

� Vertical Flow Performance− Calculation of ∆(FTHP-FBHP) as a function of

injection rate, ∆(FTHT-FBHT) and reservoir pressure


Material balance� Fundamental relationship between pressure and volume

produced

− If original volume and fluid properties are known, the depletionrate can be predicted (p as function of volume produced)

� This allows the evolution of well capacities to be estimated: q=f(p) !

− If produced volumes vs. time and pressures are known (monitoring), the original volume can be estimated

� Requirement: Calculated material balance volume = Volumetrically calculated volume

− Good cross-check in the face of many uncertainties

− Physics vs. geometry

− Compartmentalisation often not discernable on geological maps


Calculation of gas ultimate recovery

(simple tank model)Fig. 4- P/Z vs. Gp graph

0; 307,8

4,95; 47,4

5,8; 1,00

50

100

150

200

250

300

350

0 1 2 3 4 5 6 7

Cumulative gas produced (bcm)

P/Z

(b

ara

)

Pa/Za =

Pi/Zi + [(1-Pi/Zi)/GIIP] x UR

y = yo + (y1-y0)/(x1-x0) x

UR = (Pa/Za - Pi/Zi ) / [(1-Pi/Zi ) / GIIP]

Pa/Za - Pi/ZiUR = GIIP x

1-Pi/Zi

Pa/Za - Pi/ZiUR

1-Pi/ZiGIIP= RF = RF = 1 -

Pa/Za

Pi/Zi

= 1 -Ei

Ea


Deviations from straight lineWhat may cause …..

� Measured P to fall below straight line?

− Is matbal GIIP < vol. GIIP?

− Or can two still be = ?

� P to be fall above straight line?

− Is matbal GIIP > vol. GIIP?

− What if matbalGIIP = vol. GIIP?

Fig. 4- P/Z vs. Gp graph

0; 307,8

4,95; 47,4

5,8; 1,00

50

100

150

200

250

300

350

0 1 2 3 4 5 6 7

Cumulative gas produced (bcm)

P/Z

(b

ara

)

?


Material balance of CO2 in DGF

Z

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0 100 200 300 400 500 600

p (bar)

Z

CO2

Gas

CO2 Injected

0

50

100

150

200

250

-10 0 10 20 30 40 50

CO2 Injected (Gm3)

p (

ba

r)

GRIP=CO2

GRIP=Gas

Gas Pabd

� Remaining CH4 in DGF; Z-factor of CO2 much more variable than for CH4

� Pres = weighted average of CH4-GIP and CO2-GIP

Tr = 60ºC


Pres = f(mixing) = f(dispersion, diffusion)

� Schematic P/Z graph for HC gas reservoir during depletion and analogous CO2reservoir during sequestration. Dashed lines represent possible transitions from depletion P/Z to CO2 P/Z based on diffusion & dispersion, and sustained production during CO2 injection (ref. McCollum, Ogden, 2006, SPE 90669)


6-7 May, 2011



CO2 storage cap. vs. ultimate Pres

CO2 Storage Capacity versus reservoir pressure

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

0 50 100 150 200 250

Final Reservoir Pressure (bar)

CO

2 s

tora

ge

ca

paci

ty (

Mt) CO2 Ca pacity

Pa bandonment

Pres Init

Pres maxInj

64.4MtCO2 storage capacity @ P=Pmax=193.0

34.4GSm3CO2 storage capacity @ P=Pmax=193.0

193.0barP reservoir max with CO2 injection

41.0barP reservoir abandonment gas production

18.00GSm3Gas Initially In Place (GIIP)


Darcy’s law for flow through porous media

� Laminar flow assumed: not valid for turbulent flow

� Conventional units:− Darcy (D) or milliDarcy (mD)

− bbl/d or m3/d

− Bar or psi

Linear flow:

Radial flow:

p1 p2 Constant influx /efflux velocity:

What is ∆p?liquid

q = kAµ

∆p

l

q = kAµ

∆p

r

l

q = rate (m3/s)k = permeability (m2)µ = viscosity (Pa.s)p = pressure (Pa)A = area (m2)l = length (m)

r = radius (m)

A A

− centiPoise (cP)


Radial Diffusivity Equation - RDE (liquid flow)

� By assuming mass conservation, Darcy’s law and applying the definition of fluid compressibility, the basic DE for radial flow is

� This DE can be linearized assuming that

− µ is independent of pressure

− is small and therefore is negligible

− c is small & constant so that cp << 1

� This results in the radial diffusivity equation (RDE):

� This DE can be solved analytically, with solutions for

− Transient conditions: p = f (r,t); ∂p/∂t = g(r,t)

− Semi-steady, and steady state conditions

∂

∂r1r

kρρρρµµµµ r

∂p∂r =

∂p∂t

φφφφcρρρρ

∂p

∂r

∂p

∂r

2

∂

∂r1r r

∂p∂r =

∂p∂tk

φµφµφµφµc


pwf undamaged

prreservoir

pressure

pwf damaged

Pressure loss

due to skin

imp

air

ed

zon

e

wel

lbo

re

radial distance

from wellbore

imp

air

ed

zon

e

rw

Pressure distribution around well for given q


Inflow performance of gas wellsNever linear. The gas expands with decreasing pressure as it flows towards the well bore. Pseudo pressure function m(p) defined by

p

m(p) = 2 ∫ ( p/µ Z) dp, pb is the bubble point pressurepb

In terms of m, the inflow performance is usually assumed to take the form (Forcheimer)

m(pr) - m(pwf) = A q + Fq2 A, F constants

A is a term arising from Darcy flow, allowing for gas expansion.

F is the Forcheimer or non-Darcy coefficient, caused by turbulent flow in the formation at higher inflow rates.


Radial diffusivity equation for gas

� DE was linearized assuming that

− µ is independent of pressure

− is small and therefore is negligible

− c is small & constant so that p << 1

� But in case of gas:

− µ is not independent of pressure

− c is not small & not constant so that p << 1 is not fulfilled

� Using pseudo-pressure transform

� The radial diffusivity equation for gas becomes:

∂p

∂r

∂p

∂r

2

m(p) – m(pwf) = 2 ∫_

p_

pwf

pdp___

µµµµZ

∂

∂r1r r = k

φµφµφµφµc ∂m(p)∂t

∂m(p)

∂r

∂Z

∂p

1

Z

1

pc = - ≈

1

p


6-7 May, 2011



Compare radial diffusivity eqn oil and gas

� Oil:

� Gas:

� The gas DE can now also be solved for transient and (semi-) steady state (SSS) conditions:

− Transient ( = [∂p/ ∂t]r ≠ const ) :

− SSS ( = [∂p/ ∂t]r = const ) :

∂

∂r1r

kρρρρµµµµ

r∂p∂r =

∂p∂t

φφφφcρρρρ

∂

∂r1r r = k

φµφµφµφµc ∂m(p)∂t

∂m(p)∂r

, with S’ = S + DQ

m(p) - m(pwf) =p×Q

Z×p×kh× [0,5×ln + S] + F×Q2

0,5772×CA×rw2

4A= B×Q + F×Q2

m(pi)- m(pwf) =qµµµµ

4ππππkh× [ln + 2S’]

γγγγφµφµφµφµcrw2

4kt2p

µµµµZ


Bottomhole Pressure vs. production rate

pwf

Production Rate

IPR curve

prreservoir pressure

drawdown


Inflow Performance Relationship

� Inflow is function of drawdown ∆P = Pr - Pwf

� Exercise: Plot Pwf on y-axis, Q on x-axis− Q2: How does shape of IPR curve evolve as Pr depletes?

Pri

Pwf

Q

?

Pr

1. Similarly non-linear to same Q

2. Less non-linear to same Q

3. Similarly non-linear to lower Q

4. Less non-linear to lower Q

1234

6-7 May 2011, CCS master course University of Zagreb

RESERVOIR

vertical

flow

pth

pwf pr

WELLHEAD

∆∆∆∆pDarcy + ∆∆∆∆pskin

∆∆∆∆ph

+

∆∆∆∆pfr

inflow

Pressure drops along flow path


VFP� Interaction between FTHP and FBHP

� All pressures are in equilibrium

� Normally, wells produce FTHP-constrained, i.e. the FTHP

is controlled at surface by setting the choke size. The FBHP (and production rates!) adapts itself accordingly.

� Therefore, to calculate the production rate, the FTHP should in principle be known.

− This requires the derivation of complex VFP “lift curves”

� Input: PVT, well geometry, steel properties, tubing diameters, etc.


Pressure traverse FTHP→FBHP


6-7 May, 2011



CO2 injection: phase change in well

Wellhead

Bottomhole

∆Ps >>∆Pf

∆Ps ≈ ∆Pf

∆Ps >∆Pf


Example of CO2 lift curve

Well data:

● Length: 3200m

● OD: 8.5”

● ID: 4.5”

● Rel roughness: 4.40E-05

● THT: 39ºC

BHP as a function of THP

100

150

200

250

300

350

400

450

500

65 70 75 80 85 90 95 100 105 110 115 120 125 130 135 140 145 150 155 160 165 170 175 180 185 190 195 200 205 210

THP (bar)

BH

P (

bar) Q=1.15Mt/y

Q=1.6Mt/y

Q=1.9 Mt/y


DGF module in ECCOtool

� CO2 injection in DGF is non-steady-state!− Conditions change during injection: ∂Pr / ∂t > 0.− Injectivity per well decreases as Pr builds up due to cum CO2 injected.− Isothermal: no Joule-Thompson effect in reservoir around well

� Automated decision-making to meet contractual obligations.− Well drilling, new platforms, compression, abandonment.

� Capex and opex are automatically updated for new investments.� Well drainage area & injectivity automatically updated for new wells.

XL modeldemo


Storage by means ofCO2 injection in AQF

High pressure.In between non-steady & steady-state.

Injectivity reduces slowly as aquifer is filled with CO2 until ≈ steady-state situation has

developed.


Storage in aquifers

� Usually, much less information than oil/gas fields− Information very costly

− Risk of limited storage potential

� Main concern is sealingness of formation− Risk of leakage

− But also brine displacement into overlying fresh water aquifers

� Expensive monitoring required

� Storage mechanisms:

− CO2 gas bubble, resulting in ∆paqf > 0. Leakage risk!

− Dissolution of CO2 in water

− Mineralisation of CO2 (FeCO3 etc.)


Sleipner

� CO2 injection in Utsira formation

� Extensive aquifer in Central North Sea


6-7 May, 2011



CO2 storage in Sleipner

� Extra equipment cost for CO2 compression and drilling of CO2 injection well ca $100 M.

� Until 2011 ca. 8Mt CO2 stored. � Spreading of CO2 underground mapped in various research projects.


CO2 storage aquifer simulation

� Ref. TNO

� 145 x 114 x 5

� 82,650 grid blocks


Evolution of pressure in aquifer

� CO2 injection in 2 crestal wells, 40 years− Continuous build-up of pressure

� Pressure dissipates after stopping injection− Pressure fully equalized after 10,000 years

Inj.

Post-inj.

When lines have become ≈ parallel,

≈ steady-state


Long-term evolution of gaseous CO2

� Spatiotemporal spread of 400 million tonnes of CO2 injected in the example structure after the 40-year injection phase.

� The initial injection of CO2 through ten injection wells positioned at the flank of the structure is followed by migration into the crest of the structure due to buoyancy.

� All the free CO2 has accumulated in the top of the structure after some 1000 years.


Long-term evolution of dissolved CO2

� Isosurface of the predicted CO2-saturated water distribution for the time intervals 40, 1000, 2000, 4000, 6000 and 10,000 years.

� Gaseous CO2

dissolves only very gradually, expanding the volume of CO2-saturated water


6-7 May, 2011



Future of CO2/aquifer simulation

� Improved dissolution kinetics− Lab measurements, calibration

− Seismic monitoring: calibration of gas-phase bubble

� Improved geochemical modelling− Mineralisation not well understood

− Thermodynamics / phase behaviour

� Coupled FTMC simulation− Flow, Thermal, Mechanical, Chemical


Aquifer storage in ECCOtool

� Simple material balance− Same as DGF, but start CO2 injection at Pinit.

− Pore compressibility included

− Water compressibility included

� No dissolution of CO2 in water

� No mineralisation of CO2 in CO32- salts.

� No gradual expansion of “affected” aqf volume

� No 3D effect of bubble migration (affecting Ct)

� Q: will injectivity be under-estimated / over-estimated?


Conclusion subsurface storage

� CO2-EOR− Technically feasible (depending on conditions)

� Limited storage potential� Timing critical (window of opportunity)

− Chicken/egg problem CO2 infrastructure− Economically problematic

� CO2-DGF− Legal issues + timing issues (window of opportunity)− Technically feasible

� Larger storage potential

� CO2-AQF− Sealingness main concern− Unrestricted aquifer size hard to establish− Expensive data acquisition, monitoring

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