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Abstract

AAPG Bulletin, V. 97, No. 12 (December 2013), P. 22332255.

Copyright copy2013. The American Association of Petroleum Geologists. All rights reserved.

DOI:10.1306/04301312142

Controls on CO2 fate and behavior in the Gullfaks oil field (Norway): How hydrogeochemical modeling can help decipher organic-inorganic interactions

Wolfgang van Berk,1 Hans-Martin Schulz,2 Yunjiao Fu3

1Clausthal University of Technology, Department of Hydrogeology, Leibnizstrase 10, Clausthal-Zellerfeld, Germany; wolfgang.van.berk@tu-clausthal.de
2Helmhotz Centre Potsdam—GFZ German Research Centre for Geosciences, Section 4.3 Organic Geochemistry, Telegrafenberg, Potsdam, Germany; schulzhm@gfz-potsdam.de
3Clausthal University of Technology, Department of Hydrogeology, Leibnizstrase 10, Clausthal-Zellerfeld, Germany; yunjiao.fu@tu-clausthal.de

ABSTRACT

Oil degradation in the Gullfaks field led to hydrogeochemical processes that caused high CO2 partial pressure and a massive release of sodium into the formation water. Hydrogeochemical modeling of the inorganic equilibrium reactions of water-rock-gas interactions allows us to quantitatively analyze the pathways and consequences of these complex interconnected reactions. This approach considers interactions among mineral assemblages (anorthite, albite, K-feldspar, quartz, kaolinite, goethite, calcite, dolomite, siderite, dawsonite, and nahcolite), various aqueous solutions, and a multicomponent fixed-pressure gas phase (CO2, CH4, and H2) at 4496-psi (31-mPa) reservoir pressure. The modeling concept is based on the anoxic degradation of crude oil (irreversible conversion of n-alkanes to CO2, CH4, H2, and acetic acid) at oil-water contacts. These water-soluble degradation products are the driving forces for inorganic reactions among mineral assemblages, components dissolved in the formation water, and a coexisting gas at equilibrium conditions.

The modeling results quantitatively reproduce the proven alteration of mineral assemblages in the reservoir triggered by oil degradation, showing (1) nearly complete dissolution of plagioclase; (2) stability of K-feldspar; (3) massive precipitation of kaolinite and, to a lesser degree, of Ca-Mg-Fe carbonate; and (4) observed uncommonly high CO2 partial pressure (61 psi [0.42 mPa] at maximum). The evolving composition of coexisting formation water is strongly influenced by the uptake of carbonate carbon from oil degradation and sodium released from dissolving albitic plagioclase. This causes supersaturation with regard to thermodynamically stable dawsonite. The modeling results also indicate that nahcolite may form as a CO2-sequestering sodium carbonate instead of dawsonite, likely controlling CO2 partial pressure.

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