P R E P R I N T ICPWS XV Berlin, September 811, 2008

Introduction

One option for long-term CO2 storage with the purpose of greenhouse emissions reduction is the injection of this gas into saline aquifers. Saline aquifer is understood here as a brine reservoir or geological formation with reservoir characteristics (porosity and permeability) and pores filled with brine. The term saline expresses that CO2 storage is planned in reservoirs not intended to be used as fresh water resources.

Often this kind of geological formation is not well known compared to areas for hydrocarbon or mining exploration. Data coverage is sparse and uncertainty large. Therefore, simulations play an important role to explore a range of possible scenarios and help constrain geologic risk of potential CO2 storage sites.

Injection of CO2 into brine forms always an immiscible system. Generally, CO2 is less dense than brine and exhibits a strong gravitational drive (buoyancy).

The mutual solubility between CO2 and brine affects the injection process and flow properties in three ways:

1. CO2 dissolves in the brine increasing its density. The CO2 enriched brine may sink [1].

2. CO2 dissolves in brine and reacts with water forming an acid, inducing chemical reactions between the fluids and the solid rock matrix [2].

3. H2O dissolves or vaporizes into CO2, removing water from the brine and increasing its salinity. This may lead to dry-out and in some cases salt precipitation around the injection well. Salt precipitation may disturb injection operations and need to be remediated.

In this article, we first discuss in more detail the impact of mutual solubility for CO2 storage in saline aquifers. Then numerical models are presentented for the case of high salinity reservoirs. We focus on looking into the factors that influence amount and distribution of precipitation and test the mitigation options of adjusting injection strategy (rate) and pre-treating the reservoir with a dilute fluid preceeding CO2 injection. Simulations for a very simple geometry for a CO2 injection well illustrate impact on operations and mitigation options.

Mutual Solubility of CO2 and H2O

CO2 solubility in brine increases with pressure and diminishes with increasing temperature. The

Impact of Mutual Solubility of H2O and CO2 on Injection Operations for Geological Storage of CO2

Suzanne Hurter, Diane Labregere, Johan Berge and Arnaud Desitter

Schlumberger Carbon Services, Paris Shurter@slb.com

Interactions between injected CO2 and the brine in the pores of a subsurface reservoir may strongly affect injection operations for long-term geological CO2 storage. As a continuous stream of CO2 is injected into a reservoir, the water is continuously extracted from the brine, to the point that the irreducible water saturation may attain zero. This dry-out effect results in enhanced injectivity in a low salinity environment. In formations saturated with highly saline brine, however, injectivity is impaired. Here, the brine becomes supersaturated w.r.t. the salts dissolved in it as H2O continues to evaporate into the CO2 and salt (generally halite or NaCl) precipitates in the pores. The porosity and permeability diminish, some times to the point at which a well may completely plug up and may have to be abandoned. We present simulations performed with a commercial compositional code to illustrate these phenomena. Choices of injection strategy, injection interval as well as rock properties are shown to significantly affect the amount and the spatial and temporal distribution of salt precipitation. The influence of relative permeability and capillary pressure is especially dramatic: all conditions being the same, unimpeded injection over the decades to complete plugging of the injection well within a few days is possible in the models. Models also show that pre-flushing the reservoir with lower salinity fluid may prevent salt precipitation. Laboratory expemiments are needed to validate and calibrate the models before application to field operations.

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greater the brine salinity, the less CO2 will dissolve into it. Salinity is generally expressed as Total Dissolved Solids (TDS) that can be obtained by evaporating water from a sample and measuring the mass of salts that precipitates out. Brines contain a variety of chemical species that compose density and salinity. Brine composition depends on its chemical evolution and reservoir rock composition [3]. In many brines the amount of Na and Cl is orders of magnitude greater than the other components and a simplification is made: salinity (TDS) is completely attributed to NaCl (halite).

H2O is not very soluble in supercritical CO2. However, a continuous stream of CO2 being injected into a geological formation, will cause a region around the injection well to dry out. As the water of the formation brine is continuously extra-cted, even the irreducible water saturation (Swirr) may reduce to practically zero, increasing the effective permeability. Enhanced injectivity is the result in low-salinity brine environments [4].

As dry-out progresses, the salinity and density of the brine increase and it becomes supersaturated w.r.t. to the salts it contains. In the near wellbore area and in wells, pipes and other facilities, this phenomenon is refered to as scaling or salting out. The saturation state of a specific mineral and sequence of precipitation of various salts will be influenced by other cations and anions present. Once salts precipitate, the porosity and per-meability diminish. In high-salinity brine environments, the most important type of scale is halite. This phenomena is also known in operations involving injection and production of natural hydrocarbon gas [5].

The models presented later focus on the influence of various factors on the amount and distribution of precipitation.

Numerical Implementation

The simulation tool used here is a commercial compositional code used extensively in the oil and gas industry. The functionalities relevant to this article are described here. Additional capabilities are described in the references [4, 6]. The code has the capability of computing accurately the physical properties (density, viscosity, compressibility, etc.) of pure and impure CO2 as a function of temperature and pressure. Water partitions into the CO2-rich phase and changes of the properties of the mixture (density, viscosity) that affect its flow. Similarly, CO2 partitions into the water-rich phase causing its density, viscosity and salinity to change

accordingly. The mutual solubility of CO2 and water includes a correction for salinity [7,8]. The salinity of the brine is adjusted accordingly until the saturation threshold is reached and halite is precipitated. These functionalities allow processes such as dry-out and salting-out to be simulated in a large variety of geological environments.

Here the possible brine components are H2O, CO2, NaCl and CaCl2. Halite (NaCl) precipitates whenever, in a time step and cell, the saturation of NaCl is reached using an empirical relationship of halite saturation as a function of temperature [4]. At each time step this value is compared to the NaCl concentration in the brine. The excess amount is removed from the brine (density is adjusted) and added to the solid saturation, i.e. the amount of porosity occupied by precipitate.

The effect of precipitation on the porosity is calculated from the mass of solid formed and the density of the minerals that are precipitated in the pores. The impact of the porosity change on permeability is a classical unsolved problem. Some minerals grow in large pores, while others are found preferentially in pore throats. In the first case, permeability may not be affected much, while in the second permeability may change dramatically even if porosity does not change significantly. A large body of scientific literature presents and discusses many models correlating porosity change to permeability change based on laboratory experiments, well log interpretation as well as scaling and diagenetic studies [9].

In the simulation models presented here, precipitation is captured through a solid saturation (Ss) concept that affects the volume available to fluid movement in the pores. This is expressed by:

psf VSV = )1( where, Vf is the volume of fluid and Vp the pore

volume in a grid cell. The impact of precipitation (solid saturation) on fluid flow is implemented with a mobility multiplier. The user may choose the severity of flow impairment caused by salt precipitation by allocating values to the mobility multiplier. The values will be the result of expert judgement based on detailed knowledge of the system under investigation, hopefully calibrated with core flood experiments. Fig. 1 presents the relationship used in this article, which is arbitrary. The mobility of the fluid decreases with increasing solid saturation up to 0.8, that is, when 80% of the pore space is filled with precipitate, permeability is assumed to reduce to zero. At a solid saturation of 0.4, for example, the absolute (intrinsic) permeability would be multiplied by 0.35.

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Simulation Problem Set Up

The simulations presented herein illustrate CO2 injection into a highly saline aquifer, such as found in the North German basin [10,11]. Total Dissolved Solids (TDS) and brine density are 250 g/L and 1160 kg/m3, respectively. For this exercise, the molar fractions (X) of NaCl and CaCl2 are XNaCl =0.0859 and XCaCl2=1.1x10-3.

The simulations consist of injecting CO2 into a radially symmetric reservoir section at a specified rate that is controled by a maximum bottom hole pressure (BHPmax) of 85 bars, to avoid pressure rising above the reservoir fracturing pressure. Injection continues through time unless it is interrupted because the BHPmax has been reached. This occurs whenever enough halite precipitation has occurred to cause pressure to increase. In practice, fracturing pressure would need to be determined in the field and the mobility factor curve in laboratory experiments in cores of the reservoir. CO2 is injected at rates of approximately 1 kg/s (53 000 m3/day at surface conditions of pressure and temperature) and 100,000 m3/day, depending on the example.

The parameters of this model are listed in Table 1 and detailed below.

Model geometry. The numerical model represents a 30 m thick cylindrical sandstone section (Fig. 2). The top is horizontal at 730 m depth. Reservoir temperature is 35C. The radial grid comprises grid-elements increasing in size outwards. The smallest grid interval is 0.1 m at the injection well and the largest is 10,000 m at the outer boundary 10,250 m away (the number of cells in the radial direction is 210). Vertical grid interval is uniform and is 3 m. The injection well is completed such that injection occurs in the lower 15 m of the domain.

Material properties. The reservoir rock has homogeneous and isotropic properties. Porosity is 20%. Rock compressibility is 7.5.10-5 bar-1 at 75 bars. In the horizontal direction, the permeability is 200 mD (milidarcies), while in the vertical (z) direction it is 66 mD. Relative permeability measurements for CO2-brine systems are rare. We utilize here 3 sets of experimental data from literature [12,13]. These correspond to the measurements made on sedimenary rocks of the Alberta Basin in Canada. They are found under conditions different (depth, pressure, temperature, permeability) than those examined here. However, they serve well to illustrate the large range in behavior found as a function of relative

permeability and capillary pressure. Fig.3 displays relative permeability curves for the (a) Basal Cambrian, (b) Viking and (c) Ellerslie sandstones. Details can be found in [12,13]. The shapes of the curves that can be fit are slightly different and the irreducible water saturation (Swirr) is different, 30, 55 and 65%, respectively. The irreducible water saturation determines the maximum relative permeability CO2 can obtain.

Boundary conditions. The top and bottom boundary are impermeable and the outer boundary is described by numerical aquifers that simulate a constant hydraulic gradient and have the same properties than the reservoir [6].

Initial conditions. Before injection starts the reservoir pressure is hydrostatic: 75 bar at 730 m depth. Porosity is homogeneous and isotropic at 20%.

History. Three models are run. In the first injection of CO2 at a rate of 53 000 m3/day is initiated at t=0 and an initial injectio pressure of 85 bars and maintained (if possible) during 2 years. Inflow into the formation is controlled by Bottom Hole Pressure (BHP). This is repeated for each type of rock to compare solid saturation distributions. The second example looks into the influence of changing injection rates (pressures) on the solid saturation using the Viking sandstone characteristics. Finally, the third model compares results obtained previously for the Viking sandstone with results in which CO2 injection has been preceeded by pure water injection.

Model Results

Influence of relative permeability and capillary pressure: Fig. 4 is a display of solid saturation distribution for three different rocks 2 years after injection began: (a) Basal Cambrian, (b) Viking and (c) Ellerslie. It represents a pie shaped section of the model. In the case of the Basal Cambrian Sandstone, precipitation occurs rapidly and the well has to be shut down because the maximum bottom-hole pressure is reached within 14 days of injection begin. In the other 2 settings, injection is not impaired up to 50 years (end of calculation period, equivalent to the lifetime of the injection operation) even with some precipitation present.

If capillary pressure is set to zero, no precipitation at all occurs in any setting.

These results suggest that these properties affect strongly the amount and distribution of halite scaling in the near wellbore zone. Laboratory experiments [14] suggest capillary pressure

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gradients drive precipitation at the dry-out front. This implies that simplifying models by using zero capillary pressure may produce wrong results.

As mentioned before, the mobility impact of precipitation is chosen arbitrarily and the results are a function of the implementation in the code. To validate, specific laboratory experiments, such as core flooding tests, are necessary. No operational decisions can be taken on the basis of these models alone.

Now we turn to investigating models that test mitigation possibilites to address the negative impact of precipitation in the near wellbore on CO2 storage operations: injection pressure and pre-treatment with dilute solutions.

Influence of injection pressure. The same problem discussed previously was run using different injection rates. The results for 3 rates (43,000, 53,000 and 63,000 m3/day) are shown in Table 2.

Maximum precipitation occurs at the top of the injection interval and in the nodes closest to the well. As injection rate increases, therefore increasing the pressure in that region, the maximum solid saturation decreases from 80% to 26%. This suggests, that increasing injection rates helps mitigate the problem of scaling. It may be problematic in very low permeability reservoirs as injection pressure may attain fracturing pressure. This behaviour also explains why no precipitation is felt in project in high permeability sandstones, where easily high injection rates can be imposed [15].

Mitigation by diluting brine in the near wellbore: one possibility of mitigating scale is by avoiding it to occur by diluting the brine in the near well bore area or filling it with low salinity fluid before CO2 injection begins. This can be achieved by injecting a dilute fluid, here we use pure water.

The results depicted in Fig 5 represent with-without (pre-flush) pairs. In the first case (a), only CO2 is injected during 2 years. In the second (b), pure water is injected during one month and then followed by 2 years of injecting CO2.

The pre-flush has diminished strongly the amount and spatial spread of scale. Precipitation is concentrated at the upper part of the injection section, while precipitation occurs all along the injection section when no pre-flush is performed.

This mitigation option is routinely applied in gas storage operations at regular intervals [5].

Conclusions

When CO2 is injected in brine reservoirs, H2O is continuously vaporized into the CO2 phase in the near wellbore area. In high salinity environments and low permeability, this dessication of the brine leads to higher salinity, oversaturations and ultimately salt precipitation diminishing the porosity and very probably the permeability in this region. This can lead to an interuption in operations.

Numerical simulations are helpful to assess this risk to operations and test mitigation strategies.

Modeling results presented herein suggest: Relative permeability and capillary pressure

are relevant for the amount and spatial distribution of precipitation in reservoir pores.

Increasing injection pressure may help diminish the impact of precipitation on fluid flow.

Preceeding CO2 operations with injection of a dilute solution can prevent precipita-tion of affecting the storage project.

However, before application of these models, the relationship between dry-out, salting-out, pore space change and permeability modification needs to be assessed in laboratory experiments on cores of the reservoir of interest.

Literature

[1] Ennis-King, J. and Paterson, L.: Role of convective mixing in the long-term storage of carbon dioxide in deep saline formations, SPE 84344 prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5-8 october, 2003, 12 pp.

[2] Nghiem, L., Sammon, P., Grabenstetter, J., and Ohkuma, H.: Modeling CO2 storage in aquifers with a fully-coupled geochemical EOS compositional simulator, SPE 89474, prepared for presentation at the 2004 SPe/DOE 14th Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 17-21 April 2004, 16 pp.

[3] Carpenter, A.B.:Origin and chemical evolution of brines in sedimentary basins, SPE 7504 prepared for presentation at the 53rd Annual SPE Technical Conference held in Houston, Texas, 1-3 October 1978, 8 pp.

[4] Hurter, S., Labregere, D. and Berge, J., 2007. Simulations for CO2 injection projects with compo-sitional simulator, SPE 108540, prepared for presentation at Offshore Europe 2007 Conference

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held in Aberdeen, Scotland, U.K., 4-7 September, 2007, 8pp.

[5] Kleinitz, W., Koehler, M., and Dietzsch, G.: The precipitation of salt in gas-producing wells, SPE 68953 prepared for presentation at SPE European Formation Damage Conference held in The Hague, The Netherlands, 21-22 May 2001, 7 pp.

[6] Eclipse Technical Description 2006.1., Schlumberger Information Solutions software.

[7] Spycher, N., Pruess, K., and Ennis-King, J.: CO2-H2O mixtures in the geological sequestration of CO2. I. Assessment and calculation of mutual solubilities from 12 to 100C and up to 600 bar, Geochim. et Cosmochim. Acta, (2003) 67, No. 16, 3015-3031.

[8] Spycher, N. and Pruess, K.: CO2-H2O mixtures in the geological sequestration of CO2. II. Partitioning in chloride brines at 12-100C and up to 600 bar, Geochim. et Cosmochim. Acta (2005), 69, No. 13, 3309-3320.

[9] Nelson, P.H.: Permeability-porosity relation-ships in sedimentary rocks, The Log Analyst, (1994), 35, No.3, 38-62.

[10] Frster, A., Norden, B., Zinck-Jrgensen, K., Frykman, P., Kulenkampff, J. Spangenberg, E., Erzinger, J., Zimmer, M., Kopp, J., Borm, G., Juhlin, C., Cosma, C.-G., and Hurter, S.: Baseline characterization of the CO2SINK geological storage site at Ketzin, Germany, Environmental Geoscie-ces (2006) 13, No. 3, 145-161.

[11] Magri, F., Bauer, U., Clausnitzer, V., Jahnke, C., Diersch, H.-J., Fuhrmann, J., Moeller, P., Pekdeger, A., Tesmser, M. and Voigt, H.: Deep reaching fluid flow close to convective instability in the NE German basin results from water chemistry and numerical modelling, Tectonophysics (2005), 397, 5-20.

[12] Bennion, B. and Bachu, S., 2005. Relative permeability characteristics for supercritical CO2 displacing water in a variety of potential sequestration zones in the Western Canada Sedimentary Basin, SPE 95547, prepared for presentation at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9-12 October, 15 pp.

[13] Bennion, B. and Bachu, S., 2006. The impact of interfacial tension and pore size distribution / capillary pressure character on CO2 relative permeability at reservoir conditions in CO2-Brine

systems, prepared for presentation at the 2006 SPE/DOE Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 22-26 April, 10 pp.

[14] Zuluaga, E., Munoz, N.I. and Obando, G.A., 2001. An Experimental study to evaluate water vaporisation and formation damage caused by dry gas flow through porous media, SPE 68335, presentation at the SPE International Symposium on Oilfield Scale, Aberdeen, 30-31 January, 7 pp.

[15] Hansen A., Eiken, O., and Aasum. T.O.: Tracing the path of carbon dioxide from a gas/condensate reservoir, through an amine plant and back into a subsurface aquifer case study: the Sleipner area, Norwegian North Sea, SPE 96742 prepared for presentation at the SPE Offshore Europe 2005 held in Aberdeen, Scotland, U.K., 6-9 September 2005, 15 pp.

Acknowledgements

The authors thank colleagues of Schlumberger Doll Research Center in Boston: T.S. Ramakrishnan, B. Altundas and S. Verma.

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Figure 1. Model for the relationship of effect on permeability of precipitation in the pores. Mobility factor as a function of solid saturation (amount of pore space occupied by precipitated salt). For example, when solid saturation attains 0.4 (40% of porosity), the intrinsic (absolute) permeability is multiplied by 0.35. At a saturation of 0.8, permeability is assumed to reduce to zero.

Figure. 2. Model geometry. Radial symmetric domain with injection well in the centre. Injection section is the lower half. See details in Table 1.

Figure 3. Relative permeability curves for 3 sandstones from the Alberta Basin in Canada: (a) Cambrian, (b) Viking and (c) Ellerslie, respectively. The graphs show relative permeability as a function of water saturation, described by the continuous curve. The dotted curve represents the corresponding relative permeability for CO2.

0.0

0.2

0.4

0.6

0.8

1.0

0 0.2 0.4 0.6 0.8 1

Solid Saturation

Mob

ility

Fac

tor

30 m

Injection Well

injectioninterval, 15 m

Radius=10 km

30 m

Injection Well

injectioninterval, 15 m

Radius=10 km

(a) CambrianSwirr = 0.3

0.0

0.2

0.4

0.6

0.8

1.0

0.0 0.2 0.4 0.6 0.8 1.0Water Saturation

Rel

ativ

e Pe

rmea

bilit

y

(b) VikingSwirr = 0.55

0.0

0.2

0.4

0.6

0.8

1.0

0.0 0.2 0.4 0.6 0.8 1.0

Water Saturation

Rel

ativ

e Pe

rmea

bilit

y

(c) EllerslieSwirr = 0.65

0.0

0.2

0.4

0.6

0.8

1.0

0 0.2 0.4 0.6 0.8 1

Water Saturation

Rel

ativ

e Pe

rmea

bilit

y

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Figure 4. Solid saturation after 2 years modeling time. In case (a) for the Basal Cambrian sandstone injection ceased because precipitation attained 0.8 in most of the injection section. In the other 2 cases precipitation was not enough to affect injectivity, although differences in precipiation distribution are noticed.

Figure 5. Solid saturation for the Viking Sandstone. Left: CO2 injection without pre-treatment (see Fig. 4). Right: 2 yrs of CO2 injection is preceeded by 1 month of pure water injection at the same rate.

Table 1-Summary of Properties

Property Value Radial grid interval increases away from injection well Min. radial grid size (injection well) 0.1 cm

Max. radial grid size (outer edge) 10,000 m

Vertical grid size 3 m Depth of top of reservoir 730 m Reservoir Thickness 30 m Porosity 20% Horizontal Permeability 200 md Vertical Permeability 66 md Brine Composition NaCl/CaCl2 molar fraction

8.59 x 10-2/1.1 x 10-3

Brine salinity (TDS) 250 g/L Brine density 1160 kg/m3

Initial pressure at 730 m 75 bar Reservoir Temperature 35C Rock Compressibility (75 bar) 7.5x10-5 bar Max BHP 85 bar

(a) Cambrian (b) Viking (c) Ellerslie

0% 100%Solid Saturation

(a) Cambrian (b) Viking (c) Ellerslie(a) Cambrian(a) Cambrian (b) Viking(b) Viking (c) Ellerslie(c) Ellerslie

0% 100%Solid Saturation0% 100%Solid Saturation

withoutpre-flush

0% 100%Solid Saturation

with pre-flush

withoutpre-flushwithout

pre-flush

0% 100%Solid Saturation0% 100%Solid Saturation

with pre-flush

with pre-flush

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Table 2. Maximum Precipitate vs Rate

Injection Rate x 103 m3/day

Max Solid Saturation

43 0.80 53 0.39 63 0.26