monitoring of co2 injected at sleipner using time-lapse seismic data

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2004 Elsevier Ltd. All rights reserved.

Energy 29 (2004) 1383–1392

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Monitoring of CO2 injected at Sleipner using time-lapseseismic data

R. Arts a,�, O. Eiken b, A. Chadwick c, P. Zweigel d, L. van der Meer a,B. Zinszner e

a Netherlands Institute of Applied Geoscience TNO—National Geological Survey, PO Box 80015,3508 TA Utrecht, Netherlands

b Statoil, R&D Centre, NO-7005 Trondheim, Norwayc Britsh Geological Survey, Kingsley Dunham Centre, Keyworth, Nottingham, Nottinghamshire NG12 5GG, UK

d SINTEF Petroleum Research, S.P. Andersens vei 15B, 7465 Trondheim, Norwaye Institut Francais du Petrole, 1 et 4 Av. de Bois-Preau, F-92852, Rueil-Malmaison, France

Abstract

Since October 1996, Statoil and its Sleipner partners have injected CO2 into a saline aquifer, the UtsiraSand, at a depth of approximately 1000 m. The aquifer has a thickness of more than 200 m near the injectionsite and is sealed by thick shales. A multi-institutional research project SACS (Saline Aquifer CO2 Storage)was formed to predict and monitor the migration of the injected CO2. To this end two time-lapse seismicsurveys over the injection area have been acquired, one in October 1999, after 2.35 million tonnes of CO2had been injected, and the second in October 2001, after approximately 4.26 million tonnes of CO2 had beeninjected. Comparison with the baseline seismic survey of 1994 prior to injection provides insights into themigration of the CO2. In this paper the results of the seismic interpretation will be shown, supported by syn-thetic seismic modelling and reservoir flow simulation of the migrating CO2 at the two different time-steps.# 2004 Elsevier Ltd. All rights reserved.

1. Introduction

CO2 is injected near the base of the Utsira Sand at a depth of 1012 m below sea level. With

the injected CO2 in a supercritical or liquid state the main mechanism driving the flow of the

CO2 is gravity, the CO2 rising buoyantly until it reaches a shale layer [1,2]. Beneath each intra-

reservoir shale the CO2 accumulates with high saturations which follow the structural relief.

R. Arts et al. / Energy 29 (2004) 1383–13921384

The overall effect of the CO2 on the seismic signal is significant [3]. By 1999 the CO2 appearedto have reached the top of the reservoir. At several depth levels within the Utsira Sand a largeincrease in reflectivity has been observed on the time-lapse seismic data caused by individualCO2 accumulations under thin, intra-reservoir, shale layers. The presence of these thin shale lay-ers acting as (at least temporary) boundaries has been demonstrated on well data, but theireffect on the 1994 (pre-injection) seismic signal is too small for a reliable lateral interpretation[3]. With CO2 captured underneath, the location of these shale layers can be identified on theseismic data as amplitude anomalies, despite the thicknesses of the accumulations being belowwhat is generally considered to be the limit of seismic resolution. This is mainly caused by thehigh compressibility of the CO2 and by the constructive tuning effects of the top and bottomreflections at the CO2 accumulations. The effect of the density is less important since the CO2 isin a dense-fluid supercritical state at the reservoir conditions and not in a gaseous phase. Thethicknesses of the accumulations can be estimated quantitatively using the seismic amplitudeinformation and assuming a tuning relationship [4,5]. The seismic interpretation has been sup-ported by synthetic seismic modelling in order to understand the seismic response below thethin intra-reservoir shale layers.Beneath the CO2 plume, a ‘‘velocity push-down effect’’ can be observed on the seismic data

due to seismic waves travelling more slowly through CO2-saturated rock than through water-saturated rock [4,5]. In the first section of this paper the effect of CO2 in the Utsira Sand onseismic velocities is explained using the so-called Gassmann model [6,7]. The consequences forthe seismic data are illustrated on synthetic seismic models.The results of the seismic interpretation of the CO2 accumulations in 1999 and 2001 are dis-

cussed. The seismic interpretation has been used to construct a reservoir flow simulation model.With this model the injection process has been simulated and the distribution of the CO2 at thetimes of the monitoring seismic surveys has been ‘predicted’. These distributions have been usedto generate synthetic seismics that are compared directly to the seismic field data. The satisfac-tory match increases our confidence in a correct understanding of the fluid flow in the reservoir.

2. Gassmann modelling

Seismic velocities were modelled as a function of CO2 saturation using the Gassmann rela-tionships [6] which enable the elastic properties of a porous medium saturated with a fluid to bederived from the known properties of the same medium saturated with a different fluid. A verypractical overview of the use and implementation of Gassmann’s theory is given in Ref. [7]. Asa basic assumption in this analysis, homogeneous mixtures of brine and CO2 with respect to theseismic wavelength are assumed. In reality this condition is likely to be only approximately ful-filled. The densities and compressibilities of the saturating fluids, the rock matrix and theporosity of the rock are assumed to be known (Fig. 1).In the Sleipner case the 100% water-saturated P- and S-wave velocities are known from well

logs. The main constituent of the rock matrix is quartz with a known density and compress-ibility. The natural pressure and temperature at the injection point are estimated from regionalwell data measurements at 10 MPa and 36

vC, respectively. Under these conditions CO2 is in a

supercritical state. In practice this means that it has the density of a fluid, but the compressibilityof a gas. The most likely values for the density of the CO2 are between 600 and 700 kg m

�3.

1385R. Arts et al. / Energy 29 (2004) 1383–1392

The bulk modulus K of the CO2 is considered likely to have a value not greater than 0.0675 GPaunder these conditions. This implies generally a fairly constant P-wave velocity < 1450 m s�1

for the Utsira Sand for CO2 saturations in the range of 20–100% compared to a P-wave velocityof 2050 m s�1 for fully water-saturated Utsira sand. Fig. 1 shows the modelling results for thevelocities as a function of water–CO2 saturation for three different bulk moduli. The relevantparameters for the Gassmann calculations are reported on the side.

3. Seismic modelling

In order to perform seismic modelling, a (zero-phase) wavelet was estimated from the seismicdata [8]. Using the estimated elastic parameters for the 100% water-saturated sandstone and forthe (100%) CO2-saturated sandstone, a simplified impedance model was created in order to pre-dict the seismic response of the injected CO2. The elastic properties of the shale layers have beenestimated from sonic and density logs (Vp ¼ 2270 m s�1, Vs ¼ 850 m s�1 and q ¼ 2100 kg m�3).Fig. 2 shows the synthetic seismic response for CO2 accumulating under a thin intra-reservoirshale layer. A range of thicknesses of the CO2 plume was modelled in order to investigate theinfluence on the seismic signal.Two dominant effects determine the seismic response:

. The negative seismic impedance contrast between the shale and the sandstone becomes morenegative (larger in absolute value) when CO2 is present.

. The seismic response is a composite wavelet caused by interference from sequences of water-saturated sand and shale, CO2 saturated sand and water-saturated sand again.

The first effect leads to stronger negative seismic amplitudes as for a classical ‘‘bright spot’’.The second effect (tuning) can lead to destructive or constructive interference, depending on thethickness of the CO2 layer, as evident from the seismic modelling. As the thickness of the CO2

nd S-wave velocities of the Utsira Sand as a function of water–CO2 saturation using Gassman
Fig. 1. P- a n’s model.


column increases, a gradual increase of the (negative) amplitude is observed. Maximum construc-tive interference corresponds to a CO2 thickness of about 8 m, the so-called ‘tuning thickness’.

4. Seismic interpretation

As expected from seismic modelling, introducing CO2 into the Utsira Sand has a dramaticeffect on the reflectivity. This is illustrated in Fig. 3 showing the seismic inline (of the 1994, 1999and 2001 survey) through the injection point. A number of strong negative reflections (black

lified model of a variable thickness (0–8 m) of CO2 beneath a thin shale layer (2 m) and the c
Fig. 2. Simp orrespond-ing synthetic seismic response.
Fig. 3. An inline through the injection area for the 1994, 1999 and the 2001 surveys.


peaks) are observed both on the 1999- and the 2001 time-lapse surveys. The consistency betweenthe CO2 levels of both vintages is striking. In general, the 2001 CO2 levels have a larger lateralextent and have been ‘‘pushed down’’ slightly more with respect to the 1999 CO2 levels. Thiscan be easily explained considering that more injected CO2 causes more pushdown. A moredetailed analysis on the interpretation can be found in Refs. [5,8].By 1999 the CO2 had reached the top of the reservoir. Nine separate stratigraphic levels with

CO2 accumulations below shale layers have been interpreted, with the deepest level referred toas level 1 and the shallowest as level 9 [8]. Note that all but one of the reflections of the thinshale layers on the 1994 baseline data without CO2 present are below the limit of seismic resol-ution. Only with CO2 underneath them the seismic signal is ‘amplified’ above seismic resolutionand the shale layers become detectable.The tuning effect as described in the previous section is illustrated in Fig. 4. For this figure,

locations have been selected in the 1999 and 2001 survey, where only a single shale layer withCO2 trapped underneath is present. As expected these locations are concentrated towards the

tration of the tuning relation derived from synthetic seismics compared to the observed
Fig. 4. Demons relation in theseismic data of 1999 and 2001 originating from locations where only a single shale layer is present.


outer limits of the total CO2 accumulations. Note that the only criterion is the presence of a sin-gle shale layer, but not necessarily the same layer everywhere. For these selected locations the‘‘pushdown’’ in time (which for a single layer is linearly related to the thickness of the CO2accumulation) has been plotted against the seismic reflection amplitude. The data appear to fol-low a tuning relation as expected from the synthetic seismic modelling.A prominent vertical feature, which can be clearly distinguished in Fig. 3, is characterized by

localized pushdown and much decreased reflection amplitudes. This is interpreted as a ‘‘chim-ney’’ of CO2, situated approximately above the injection point and forming a major verticalmigration path which conducts CO2 almost directly to the top of the reservoir. Note that Fig. 4suffers from some ‘‘large pushdown, low amplitude’’ anomalies not consistent with the tuningrelation. These anomalies correspond to interpretations within the chimney where most of theseismic amplitude information is destroyed.

5. Reservoir flow simulation

In order to help understand the CO2 flow in the reservoir and to predict any future flow, afull-field 3D reservoir flow simulation model has been constructed based on the seismicinterpretation [2]. This was not a straightforward task, taking into account that the intra-reser-voir shale layers could only be interpreted on the time-lapse surveys with CO2 present belowthem. Moreover, these interpretations were in two–way traveltime and had to be time-depthconverted for the flow simulation model. With the large velocity variations occurring in the res-ervoir due to the presence of CO2, an accurate time–depth conversion is not simple and an

f a reservoir flow simulation at the time of the first time-lapse seismic survey in Octobe
Fig. 5. Result o r 1999 (after 3years of injection) after 2.35 million tonnes of CO2 injected [2].


accurate depth model of each individual shale layer has not been obtained so far. To circumvent

this problem, these intra-shale layers have been assumed parallel to the upper shale layer just

below the top of the reservoir. The total simulation flow model covers an area of 15.7 km2. The

Utsira Sand was represented by a total of 59 layers. The shale layers were represented in the

model by transmissibility modifiers between the appropriate layers. The result of the simulation

after 3 years of injection, at the time of the first time-lapse seismic survey in October 1999, is

shown in Fig. 5.The resulting saturation model has been transformed into a 3D acoustic impedance model

using the Gassmann relations in order to perform a forward seismic modelling. A cross-section,

representing crossline 3123 in 2001, is shown in Fig. 6. The leftmost image represents the acous-

tic impedance model in depth, the middle image is the synthetic seismic data and the rightmost

image corresponds to the seismic field data both in two-way traveltime.Taking into account the assumptions made to construct the model, the synthetic seismic data

mimic the field data fairly well. The pushdown effect is clearly demonstrated on the synthetic

seismic data. Fig. 7 shows the lateral extent of the pushdown anomalies for the 1999 seismic

data, for the 2001 seismic data and for the synthetic data (based on the simulation for 2001).

The field data show a more north outh elongated shape, whereas the synthetic data follow the

domal shape of the upper shale layer (level 8) topography.

Fig. 6. Cross-section from west to east of the acoustic impedance model derived from the 2001 reservoir simulationmodel in depth (left), the synthetic seismic data (middle) and the corresponding 2001 seismic data both in two-waytraveltime.


This effect can also be observed on the synthetic data shown in Fig. 6. The lateral extent ofthe CO2 anomaly on the east–west synthetic data of crossline 3123 is larger than on the fielddata.

6. Conclusion

Time-lapse seismic surveying appears a highly suitable geophysical technique for monitoringCO2 injection into a saline aquifer. The effects of the CO2 on the seismic data are large both interms of seismic amplitude and in observed velocity pushdown effects.In addition to straightforward mapping of changes in the time-lapse seismic data, quantitative

approaches to mapping the supercritical CO2 saturations have been carried out, supported byseismic modelling. A more detailed analysis can be found in Refs. [4,5].

ture top of the upper shale layer (level 8) with superimposed outlines of the pushdown a
Fig. 7. Struc nomalies asobserved in the 1999 dataset (light grey), in the 2001 dataset (dark grey) and in the 2001 synthetic seismic data(black).


The interpreted seismic data have been used for a full 3D simulation model. The constructionof such a model was problematical for two main reasons:

. The intra-reservoir shale layers could only be interpreted on the time-lapse surveys when CO2was present below them.

. The conversion from time to depth of these intra-reservoir shale layers is not sufficiently accu-rate due to the large velocity variations caused by the presence of CO2.

As a consequence, an assumption on the depth structure of the intra-reservoir shale layers hasbeen made, assuming them to be parallel to the upper shale layer, the only one that has beeninterpreted on the baseline seismic data.The saturation model resulting form the reservoir simulation has been transformed into an

acoustic impedance model using the Gassmann model, which in turn has been used to createsynthetic seismics. Taking into account the assumptions made to construct the model, the syn-thetic seismic data match the field data fairly well.

Acknowledgements

The SACS project was funded by the European Community (Thermie program), by theindustry partners, i.e.: Statoil, BP, Norsk Hydro, ExxonMobil, TotalFinaElf and Vattenfall andby national governments. The R&D partners are TNO-NITG (TNO-Netherlands Institute ofApplied Geoscience—National Geological Survey), SINTEF Petroleum Research, BGS (BritishGeological Survey), BRGM (Bureau de Recherches Geologiques et Minieres), GEUS (Geologi-cal Survey of Denmark and Greenland) and IFP (Institut Francais du Petrole). The IEA-Green-house Gas Programme is involved in the dissemination of the results.

References

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monitoring of co2 injected at sleipner using time-lapse seismic data

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