Saline Formations

The sequestration of C02 in deep saline formations does not produce value-added by-products, but it has other advantages. First, the estimated carbon storage capacity of saline formations in the United States is large, making them a viable long-term solution. It has been estimated that deep saline formations in the United States could potentially store up to 500 billion ton of C02. 

Second, most existing large C02 point sources are within easy access to a saline formation injection point, and therefore sequestration in saline formations is compatible with a strategy of transforming large portions of the existing U.S. energy and industrial assets to near-zero carbon emissions via low-cost carbon sequestration retrofits. 

In addition, the Norwegian oil company, Statoil, is injecting approximately 1 million ton per year of recovered COz into the Utsira Sand, a saline formation 

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The mud contamination with chlorides results from salt intrusion. Salt can enter and contaminate the mud system when salt formations are drilled and when saline formation water enters the wellbore. 

R. F. Scheuerman and B. M. Bergersen. Injection water salinity, formation pretreatment, and well operations fluid selection guidelines. In Proceedings Volume, pages 33-49. SPE Oilfield Chem Int Symp (Houston, TX, 2/8-2/10), 1989. 

Kraemer T, Reid D (1984) The occurrence and behavior of radium in saline formation water of the US gulf coast region. Isot Geosci 2 153-174... 

Kreitler, C.W., Akhter, M.S., and Donnelly, A.C.A., Hydrologic-Hydrochemical Characterization of Texas Gulf Coast Saline Formations Used for Deep Well Injection of Chemical Wastes, Prepared for U.S. Environmental Protection Agency by University of Texas at Austin, Bureau of Economic Geology, 1988. 

Scale inhibitors are used to prevent the formation of insoluble calcium salts when the drilling fluid contacts formation minerals and saline formation waters. Commonly used scale inhibitors include sodium hydroxide, sodium carbonate, sodium bicarbonate, polyacrylates, polyphosphates, and phosphonates. 

Earlier corrosion inhibitors limited the maximum strength of the acid to 15% by weight. Improved corrosion inhibitors (see below) have made the use of higher acid concentrations, such as 28% HCl more common. More dilute solutions may initially be injected in sandstone acidizing to reduce the formation of insoluble sodium and potassium fluorosilicates by displacing saline formation water before injection of hydrochloric acid. 

Ennis-King J.P. and Paterson L. Role of convective mixing in the long-term storage of carbon dioxide in deep saline formations. 2003 SPE 10 349-356. 

Hovorka S.D., Benson S.M., et al. Measuring permanence of C02 storage in saline formations the Frio experient. 2006 Environmental Geoscience 13 105-121. 

Formation waters are saline with salt contents ranging from ocean water to very dense Ca-Na-Cl brines. Their origin and evolution are still controversial, because the processes involved in the development of saline formation waters are complicated by the extensive changes that have taken place in the brines after sediment deposition. 

Knauth LP, Beeunas MA (1986) Isotope geochemistry of fluid inclusions in Permian hahte with implications for the isotopic history of ocean water and the origin of saline formation waters. Geochim Cosmochim Acta 50 419 33... 

The subsurface situation, however, with respect to dolomitization is more complex, as shown by the work of Land and Prezbindowski (1981). It appears that in the Cenozoic Gulf Coast basin of the United States, subsurface, Ca-rich saline formation waters may be undersaturated with respect to dolomite, and as the brine moves updip, and is progressively diluted by shallow subsurface waters, the brine may cause dedolomitization of carbonates encountered in the subsurface. 

Land L.S. and Mackenzie F.T. (1970) Field Guide to Bermuda Geology. Bermuda Biological Station for Research Spec. Publ. 4, St. Georges, Bermuda, 14 pp. Land L.S. and Prezbindowski D.R. (1981) The origin and evolution of saline formation water, Lower Cretaceous carbonates, south-central Texas. J. Hydrology 54, 51-74. 

Vodyanitsky BA (1948) Main water exchange and history of salinity formation in the Black Sea. In Transactions of the Sevastopol biological station, vol 6. (in Russian)... 

Considerable attention has been paid to complexing of metals by reduced sulfur species. Some of the complexes of zinc and lead which have been considered include Zn(HS)f, Zn(HS)4, Pb(HS)3, Pb(HS)°, and PbS(H2S)° (Barnes, 1979 Kharaka et al., 1987). Giordano and Barnes (1981) concluded, on the basis of experimental studies, that ore-forming solutions at temperatures less than 200 °C with total dissolved sulfur contents of less than 1 m (ca. 3.2 X 10" mg L ) cannot transport significant quantities of lead as bisulfide complexes. Extensive metal complexing by the bisulfide complexes requires much higher pH values than those found in saline formation waters (Kharaka et al., 2000). 

Graf D. L., Meents W. F., and Shimp N. F. (1966) Chemical composition and origin of saline formation waters in the Illinois and Michigan basins. Geol. Soc. Am. Spec. Pap. 87. 

Land L. S. and Macpherson G. L. (1992a) Origin of saline formation waters, Cenozoic section. Gulf of Mexico sedimentary basin. Am. Assoc. Petrol. Geol. Bull. 76, 1344-1362. 

THE ORIGIN AND EVOLUTION OF SALINE FORMATION WATER, LOWER CRETACEOUS CARBONATES, SOUTH-CENTRAL TEXAS, U.S.A. 

The origin of saline formation water in sedimentary basins has been problematical since it was first recognized that basinal fluids typically contain dissolved solids in concentrations considerably in excess of seawater. Vast differences in major-ion ratios quickly dispelled early assiunptions that basinal fluids were connate and represented buried seawater (Chave, 1960). Since then, different mechanisms have been advocated to account for the composition of subsurface water, and indeed, different mechanisms probably operate in basins with different lithologies and different burial histories. In some cases saline formation water may evolve in near isochemical rock—water systems during burial, as increasing temperature and pressure induce reactions which transfer components from the solid to the dissolved state. At the other end of the spectrum, fluid bearing no resemblance to the interstitial burial water may be imported from another part of the basin, or even from outside the basin, for example, by meteoric recharge, and modified by rock—water interaction. 

Land, L.S. (1995) Na-Ca-Cl saline formation waters, Frio Formation (Oligocene), south Texas, USA products of diagenesis. Geochim. Cosmochim. Acta, 59,2163-2174. 

Studies have shown that the storage of carbon dioxide is possible in various geological settings. The main candidates are sedimentary basins, e.g., oil and gas reservoirs (working or abandoned), deep unmineable coal-seams and saline formations (aquifers). Sub-surface storage can take place at both on-shore and off-shore locations access to the latter is via pipelines from the shore or from off-shore platforms. Other prospective sites for storage include salt caverns, basalts, oil/gas shales and disused mines. The various options are shown schematically in Figure 3.4. 

Figure 3.4 Options for the geological storage of carbon dioxide. 1. Deep unused saline formations (aquifers). 2. Use of carbon dioxide for enhanced oil recovery. 3. Depleted oil and gas reservoirs. 4. Deep unmineable coal seams. 5. Use of carbon dioxide in enhanced coal-bed methane recovery. 6. Other suggested options (e.g., salt caverns, basalts, oil/gas shales, disused mines)." (Courtesy of Intergovernmental Panel on Climate Change).

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