ABSTRACT Estimated recoverable oil and gas from giant field discoveries from 2000 through 2009 was 383 billion barrels of oil equivalent (BBOE)—a 92% increase from the prior decade and the largest addition from giant fields since the 1970s. This dramatic increase in giant field resources was driven by the emergence of shale gas and tight oil discoveries in North America. These so-called unconventional or continuous resource plays added almost 177 BBOE of new resources—mostly from super-giant plays like the Marcellus, Bakken-Three Forks, Eagle Ford, and Montney formations. In harmony with recent trends, giant natural gas discovery volumes greatly exceeded those of oil and contributed about 260 BBOE (1558 trillion cubic feet) of new resources. Traditional conventional giant discoveries added 198 BBOE of new resource—slightly less than in the prior decade and almost 55% of the total. Super-giant fields such as Galyknysh (Yoloten) with 67 BBOE gas and condensate in Turkmenistan, Kashagan in Kazakhstan; Lula in Brazil; and Kish 2 in Iran accounted for almost 60% of the giant conventional resources. The share of deepwater discoveries increased and contributed 23% of the conventional giant field volumes. The Santos Basin mega presalt and the Levantine Basin were the most important deepwater play openers.

Abstract In this paper production geochemical data from oil fields where CO 2 has been injected to enhance oil recovery (CO 2 -EOR) and experimental simulations of this process are reviewed. These data show that over the timescale of days to many years, CO 2 injected into the subsurface typically results in the bulk dissolution of carbonate minerals. There is little evidence for the sequestration of the injected greenhouse gas as a solid phase carbonate mineral on the timescale of the CO 2 -EOR projects or experiments. There is extensive aqueous geochemical, petrographic and core analysis evidence that supports the conclusion that CO 2 , injected into oil fields to enhance secondary recovery, leads to the bulk dissolution of calcite, dolomite and siderite. Although carbonate dissolution leads to enhanced porosity, the expected commensurate increase in permeability may be offset by the migration of clays, liberated by the action of the acidic water on the rock, with consequent blocking of pore throats. Additionally, injection of CO 2 into oil fields can result in asphaltene deposition on mineral surfaces. Such a bitumen coat could ultimately isolate the mineral matrix from injected fluids and insulate the rock to the injected greenhouse gas. Localized precipitation of calcite scale has been reported in the topside facilities of CO 2 -EOR projects and in the low-pressure region of experimental simulations.

Abstract Predicted cation ratio geothermometry temperatures, using equations of Na-K, Na-K-Ca, Mg-Na-K-Ca and Mg-Li, were compared between oilfield and geothermal settings. Geothermometers in oilfield waters yielded less consistent temperature predictions compared to geothermal waters in the same temperature range. Scatter of predicted temperature in oilfield waters is greatest in the temperature interval where carboxylic acid anions (CAAs) are in greatest concentration. CAAs are not present in geothermal systems. Temperature prediction improves in those oilfield waters where CAAs are present and account for less than 80% of total alkalinity. The assumptions of cation ratio geothermometry are violated to varying degrees in oilfield waters where CAAs are abundant. These assumptions are: (1) cation ratios are controlled by exchange between solid aluminosilicates. However, CAAs affect mineral solubility by forming complexes with the cations. Therefore. the ratios of cations in solution differ from those values expected when cation exchange between aluminosilicate minerais is the only control on the cation ratios. Furthermore, concentrations of Ca and Mg are strongly controlled by carbonate equilibria, which in turn is strongly affected by the presence of CAAs; (2) aluminum is conserved in solid phases. However, CAAs form stable complexes with Al, increasing Al-silicate solubility and mobilizing Al; thus Al may not be conserved m mineral phases; (3) neither H 1 nor CO, enter into the net reactions (i.e., pH is buffered by aluminosilicate hydrolysis). However, acetate (the dominant CAA found in oilfield waters) is an effective buffer of pH in feldspathic rocks. Also, at higher temperatures, decarboxylation of CAAs increases the P C02 of oilfield waters. The consistently worse temperature prediction of cation ratio geothermometers in oilfield waters in the 80-120°C temperature range is another indication that organic-inorganic diagenesis is an important control on oilfield water chemistry.