Numerical Approaches to CO2−Sequestrationin a Faulted and Low−Permeable Saline Aquifer in NW Germany

M. W. Wuttke1, C. M. Sperber1

1Leibniz Institute for Applied Geophysics (LIAG), Geothermics and Information−Systems, Hannover, Germany (manfred.wuttke@liag−hannover.de)

Abstract: Stabilisation at an atmospheric CO2−concentration of 450 ppm (associated with a maximum globaltemperature increase of 2°C) requires radical measures. Storage of CO2 in deep saline aquifers offers a quickand economic solution. In MUSTANG (A Multiple Space and Time scale Approach for the quantification of deepsaline formations for CO2 storage), a number of test sites exhibiting a wide range of reservoir properties areinvestigated for CO2−sequestration. Horstberg is one of the test sites, unique for its low−permeable Triassicsandstones. This study simulates the effects of CO2−injection into this tight reservoir. Two strategies aresimulated employing the TOUGH2 code: (1) an injection−relaxation and (2) an injection−production combination.While the latter strategy dominates over the former the model indicates that both the strategies are uneconomicaldue to small CO2−injection rates or amounts which can be accomodated.

0˚ 3˚E 6˚E 9˚E 12˚E 15˚E

48˚N

51˚N

54˚N

57˚NNorth Permian Basin

South Permian Basin

London−Brabant Massif

Rh

enis

h M

ass

if

Bohemian Massif

Mid

North Sea

High

Ringkøbing−Fynn

High

Fenno− Scandian High

Alemannian−

Vindelician H

igh

LowerSaxony Basin

Horstberg

0 100 200

km

Legend

Jurassic � sediments outline of � Roet salt Bunter hights Bunter � sediments Permian � sediments sediment transport direction Allertal � lineament

Horstberg

Fig. 1: The borehole Horstberg Z1 is located in NW Germany at the southern flank of the South Permian Basin.In North Germany, the basin is bordered by the Ringkøbing−Fyn High and the Variscan Orogene in the north andsouth, respectively (Ziegler, 1990). The sedimentary record ranges from Upper Carboniferous to Quaternary andincludes economically relevant reservoir rocks that characterise this area as the most important oil and gasprovince in Germany. Initiated as a foreland basin of the Variscan orogenic belt during Late Carboniferous toEarly Permian times (e.g. Bachmann & Grosse, 1989) the Permian Basin subsided until Late Jurassic times as aresult of a combination of salt tectonics and intra−plate stresses (e.g. Betz et al., 1987). Characterised byalternating periods of re− and transgressions the Triassic Middle Bunter sandstones and intercalated mudstonesof the targeted reservoirs were deposited into this depression. (Modified after Ziegler (1990) and Betz et al.(1987)).

Role of Horstberg site in the MUSTANG project:For the GeneSys−project a comprehensive dataset characterizing this particular reservoir was produced. Thisdataset is now being used in the MUSTANG project to perform theoretical model−studies of the CO2 spreadingbehavior in fractured sedimentary rocks of low permeability by applying the standard tools developed in theMUSTANG project.In the strictly scientific MUSTANG project there are no plans to inject CO2 in Horstberg or to perform anyfurther experiments at this site.

0 m

1000 m

2000 m

3000 m

4000 m

5000 m

Quaternary

Tertiary

Upper Cretaceous

Lower Cretaceous

Jurassic

Triassic

Permian

dept

h [m

]

3444

3650

3688

37243737

3765

3805

3902

3926

38

13

40

24

thic

knes

s [m

]

206

36

28

97

24

7

25

7

effe

ctiv

e th

ickn

ess

[m]

Upp

er B

unte

r M

iddl

e B

unte

r

Middle Roet

Lower Roet

Solling

Hardegsen

Detfurth

Volpriehausen

Lower Bunter

C1

R1

C2

R2

C3

R3

C4

R4

reservoir unit #1

reservoir unit #2

reservoir unit #3

reservoir unit #4

main caprock unit #1

caprock unit #2

caprock unit #3

caprock unit #4

0 50 100 150gamma ray

200 250sonic

1.4 1

3.6

0.4 1.4 0.6

9

0.6 1.4

4.6

0 50 100 150gamma ray

200 250sonic

2.2

21.2

8.2

0.8 1.8 0.4 2.2

1.4

0 50 100 150gamma ray

200 250sonic

2.2

2.2

2.4

2.6 0.8 2.6 0.2

0 50 100 150gamma ray

200 250sonic

4.6

1.8 1.6

3.6

7.6

3

4.2

5.8

1.4

9.2

0.6 1.2 0.4

R1 R2

R3

R4

Legend

anhydrite halite � sandstone argillaceous interbedding

unconformity fault thrust

Fig. 2: Stratigraphy from the 4900 m deep Horstberg Z1 borehole. Important sandstone layers are emphasised within the stratigraphic column. Effectivethicknesses of the targeted CO2−reservoirs (Middle Bunter) were evaluated based on both sonic and gamma−ray data. The deposits of the Bunterformation consist of interbedded strata of mudstones and sandstones which are typical layer cake sediments i.e. of continuous distribution throughout theentire basin (Röhling, 1991). In Triassic times the main source area of these sediments was located towards the south of the basin (cf. Fig. 1) resulting ina gradual decrease of grain size transitioning into silt and clay with increasing distance towards the north. Bunter formation consist of interbedded strataof mudstones and sandstones which are typical layer cake sediments i.e. of continuous distribution throughout the entire basin (Röhling, 1991). InTriassic times the main source area of these sediments was located towards the south of the basin (cf. Fig. 1) resulting in a gradual decrease of grainsize transitioning into silt and clay with increasing distance towards the north. Thus, in the area of Horstberg the sandstone thicknesses and sand fractionare significantly reduced. Therefore, only two sandstone layers are thick enough to be considered reservoirs for CO2−storage: the upper Volpriehausensandstone including the lower Detfurth sandstone with an effective thickness of 25 m as well as the Solling sandstone with an effective thickness of 24 m.The seal of the entire aquifer is formed by the 300 m thick Roet salt deposit (cf. Fig. 1); a halite layer of the Upper Bunter formation.

References:1) Bachmann, G.H. & Grosse, S. (1989): Struktur und Entstehung des Norddeutschen Beckens − geologische und geophysikalische Interpretation einerverbesserten Bouguer−Schwerekarte. Niedersächsische Akademie der Geowissenschaften Veröffentlichungen, 2, 23−47.2) Betz, D., Führer, F., Greiner, G. & Plein, E. (1987): Evolution of the Lower Saxony Basin. Tectonophysics, 137, 127−170.3) Röhling, H.−G. (1991): A lithostratigraphic subdivision of the Lower Triassic in the Northwest German Lowlands and the German sector of the NorthSea, based on gamma−ray and sonic logs. Geologisches Jahrbuch. Reihe A, Allgemeine und regionale Geologie Bundesrepublik Deutschland undNachbargebiete, Tektonik, Stratigraphie, Paläontologie, 119, S. 3 − 24.4) Wessling, S., Junker, R., Rutqvist, J. et al. (2009): Pressure analysis of the hydromechanical fracture behaviour in stimulated tight sedimentarygeothermal reservoirs. Geothermics, 38: 211¢226.5) Ziegler, P.A. (1990): Geological Atlas of Western and Central Europe. Shell internationale Maatschappij B.V, The Hague.

3660

3680

3700

3720

dept

h [m

]

0 1000 2000 3000

distance [m]

01095 days

CO2 distribution

0.0 0.2 0.4 0.6

XCO2

3660

3680

3700

3720

dept

h [m

]

0 1000 2000 3000

distance [m]

01095 days

pressure

600 650 700 750 800

bar

injection

no injection

injection

no injection

injection

no injection

formation pressure 600

700

800

900

pres

sure

[bar

]

0 200 400 600 800 1000

time [days]

0.00

0.05

0.10

0.15

CO

2 [t

103 ]

0 200 400 600 800 1000

time [days]

0.0

0.2

0.4

0.6

0.8

1.0

XC

O2

total CO2 CO2 injected CO2 (aq.) CO2 (gas) XCO2 in aq. phase

a

b

c

d

Fig. 3: CO2 injection into reservoir R1 (cf. Fig. 2) is simulated by injection periods of ninemonths alternating with periods of no injection of three months. Although injection occurs atrates as low as 0.001 kg/sec pore pressure increases by 50% of the initial formation pressureafter about 250 days. Avoiding fracturing of the seal by over−pressure, possibly resulting inpathways for the injected CO2 to escape, injection stops allow the pressure to relax towardsits initial values (d). However, the model indicates that relaxation periods have to be extendedto allow injection within pressure brackets below the lithostatic pressure of about 900 bar.The CO2−fraction dissolved in formation waters amounts to 50% of CO2 present in theformation after 1000 days although it drops to about 40% upon pressure relaxation. InjectedCO2 adds up to about 0.1 t after 1000 days (c), which is economically insignificant.Model parameters: porosity − sandstone 0.05, shale 0.15; permeability − sandstone 10−15 m2,shale 10−18 m2, formation pressure 60 MPa (Wessling et al., 2009), isothermal simulation at146°C, heat conductivity 2.51 W/m K, specific heat 1000 J/kg K. Initial NaCl and CO2fractions: 0.45 and 0.34 Radial symmetry around west axis, north and south boundaries exertno flux while east boundery exerts hydraulic pressure as boundary conditions.

3660

3680

3700

3720

dept

h [m

]

0 1000 2000 3000

distance [m]

01200 days

CO2 distribution

0.0 0.2 0.4 0.6

XCO2

3660

3680

3700

3720

dept

h [m

]

0 1000 2000 3000

distance [m]

600 days

pressure

300 400 500 600 700

bar

productionat constant rate

productionat constant pressure no production

at productionpoint

at injectionpoint

formation pressure

200

300

400

500

600

700

800

900

pres

sure

[bar

]

0 200 400 600 800 1000

time [days]

0.00

0.05

0.10

0.15

CO

2 [t

103 ]

0 200 400 600 800 1000

time [days]

0.0

0.2

0.4

0.6

0.8

1.0

XC

O2

total CO2 CO2 injected CO2 (aq.) CO2 (gas) XCO2 in aq. phase

a

b

c

d

Fig. 4: Injecting CO2 into the reservoir R1 (cf. Fig. 2) is simulated by a combination of CO2−injection and formation water production in three stages of which each stage lasts 400 days(d): while CO2 injection occurs at a constant rate of 0.001 kg/sec over the entire simulationperiod production occurs at a constant rate of 0.005 kg/sec in stage 1, under constant porepressure at borehole bottom of about 285 bar in stage 2 whereas no production occurs instage 3. In contrast to the simulation in Figure 3 the pressure increase at injection point iscontrolled by creating a pressure gradient along a distance of 1000 m between the injectionand production borehole so that CO2 can advance more quickly into the reservoir. After about150 days a plateau of pore pressure forms at about 730 bar at injection point after creating alow−pressure of about 285 bar at production point. Keeping the low−pressure at productionpoint constant also retains the over−pressure at injection point (d). Upon production stop after800 days only a small pore pressure increase occurs at injection point. In contrast to thesimulation in Figure 3 the amount of injected CO2 is higher while the fraction of CO2 dissolvedin the formation waters is lower at pore pressures well below 800 bar (d).

form

atio

n pe

rmea

bilit

y

formation pressure

after 60 days after 359 days after 1100 days after 2000 days

550

600

650

700

750

800

850

pres

sure

at i

njec

tion

poin

t [ba

r]

0 2 4 6 8 10

permeability [m2 10−15]

Perspective: The pore pressure at injection point increaseswith decreasing permeability and increasing injection times.The greater the permeability values and the longer theinjection period the smaller the transient pressure contrastbecomes as approaching a plateau at a given pore pressure.Due to the low permeability of the targeted Horstberg reservoirthe maximum pore pressure exceeds the lithostatic pressureafter a period as short as two years. Note that for thissimulation, the permeability/ porosity ratio of 10−15/0.05 m2 isconsidered as constant while all other parameters are identicalto the ones used for Figure 3 and 4.

Leibniz Institute for Applied Geophysics − Stilleweg 2 − D 30655 Hannover − http://www.liag−hannover.de