Classifications of Oil Field Waters admin | May 19, 2011 | Comments (0) Waters can be classified in a number of ways. Most commonly they are grouped according to the following criteria: (1) water origin
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meteoritic, connate, or juvenile waters,
(2) water chemistry, e.g., bicarbonate, sulfate, or chloride waters, and (3) total water salinity, i.e., fresh water, saline water, or brine water. Many chemical classifications have been proposed or discussed by Tolstikhin (1932), De Sitter (1947), Durov (1948), Sulin (1948), Vassoyevich (1954), Chebotarev (1955), Kr ejchi-Graf et al. (1957), Gorrell (1958), Rainwater and White (1958), Chave (1960), and Eremenko ( 1960), to mention just a few investigators. For example, see Table 4.1 (in: Eremenko and Chilingar, 1996). The water classifications have been reviewed in Chilingar (1957, 1958), Chilingar and Degens (1964), and Samedov and Buryakovsky (1966). As an example, the classification scheme of N. I. Tolstikhin (in: Vassoyevich, 1954, p. 112) is presented in Fig. 4.3. It is based principally on the distribution of the most abundant cations (Na+, Mg2+, Ca2+) and anions (HCO3 , Cl , SO4 2 ). In following
The chemical composition of formation waters can be used as an indicator for the presence of petroleum (V. A. Sulin, in: Vassoyevich, 1954): (1) Sodium sulfate type (rNa rCl)/rSO4o1. The sodium sulfate type of formation waters is a usual representative of uncovered formations and, therefore, is not a favorable indicator of the presence of oil. These waters, however, could be present in the uncovered zones o f petroleum deposits. (2) Sodium bicarbonate type (rNa rCl)/rSO441. The high content of bicarbonates or sodium chloride, negligible sulfate content, and the presence of hydrogen sulfide, naphthenic acids, iodine, and other mic rocomponents, which are characteristic of the oilfield waters, make this kind of sodium bicarbonate formation water a favorable indicator for the presence of petroleum. (3) Magnesium chloride type (rCl rNa)/rMgo1. In general, the magnesium chloride type of waters is not a direct indicator for the presence of oil. These waters, however, are sometimes found in petroleum deposits. (4) Calcium chloride type (rCl rNa)/rMg41. The pres ence of microcomponents which are characteristically found in oilfield waters (iodine, naphthenic acids, bromine, and boron) and insignificant quantities or absence of s ulfates are of considerable importance in deciding as to whether the calcium chloride type of water is a favorable hydrochemical indicator or not.
The presence of calcium chloride type of waters having high content of salts, but containing considerable amounts of sulfates and devoid of iodine or naphthenic ac ids, is indicative only of a well-sealed formation. The specific hydrochemical indicators for the presence of oil include: (a) naphthenic acids
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direct hydrochemical indicator;
(b) iodine (in high concentration) (c) bromine
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supposedly a direct hydrochemical indicator;
does not have a genetic relationship to oil; however, many oilfield waters characteristically contain
high concentrations of bromine; (d) boron— supplementary hydrochemical indicator, which is more common in the bicarbonate type of waters; (e) ammonium
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indirect hydrochemical indicator; and
(f) barium and strontium
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supplementary indicators, which do not have genetic relationship to petroleum.
The presence of organic components is the most typical feature of oilfield water. The presence of liquid and gaseous hydrocarbons in water facilitates reduction processes (especially near the hydrocarbon accumulations) and the appearance of various organic substances in water. The reduction of sulfate ions results in the formation of hydrogen sulfide. The generated hydrogen sulfide diffuses into the surrounding rocks and reacts with the oxides of iron, forming pyrite and siderite. The rocks even change in color from reddish and greenish to gray and dark-gray. These indications are considered as favorable in exploration. The presence or absence of sulfates in the subsurface water is not an indicator: concentration of sulfates in water depends not only on the reduction processes but also on the input of the SO4 2 ions from the surrounding rocks. The sulfate reduction is poss ible at rather high temperatures (300 –500 1C). The writers believe that the sulfate reduction may occur at lower temperatures, at a slow rate, in the low-pH environments. Microorganisms can reduce sulfates at temperatures even as low as 70 1C. For example, Desulfovibrio desulfuricans in injection waters can ‘‘sour’’ ones.
reduce sulfates to sulfides and convert ‘‘sweet’’ oilfield waters into
Oilfield waters are highly reduced. The extent of the reduction is evaluated fr om the amount of oxidizing
substance, potassium iodate or permanganate. The oilfield waters are also enriched in volatile and non-volatile phenols and fatty and naphthenic acids. Up to a temperature range of 120 –150 1C, liquid hydrocarbons are barely s oluble in water. Currently, the only compound that was clearly identified was benzene, which is typical for water in the accumulations of highly aromatic condensates. When water is moving, gaseous hydrocarbons soluble in water form, in terms of their concentration, front and back effects. Same effects are typical for all other geochemical indicators. Oilfield waters contain iodine, bromine, boron, aluminum, and mercury. Gas and gas-condensate accumulations usually have elevated amounts of iodine in brines. High-salinity brines contain bromine, whereas alkaline water is enriched in boron. Formation water of gas accumulations contains mercury. Various nitrogen-rich substances (such as amines and complex heterocyclic compounds including pyridine) are also found in brines.
