Risk of Encountering Non-Hydrocarbon Gas Contaminants
Evaluating the risk of encountering non-hydrocarbon gas contaminants (CO2, N2, H2S) impacts the exploration strategy for an area, and the development strategy for a field. Gas geochemistry is a key to this evaluation.
As discussed below, the risk of encountering high concentrations of non-hydrocarbon gases in a natural gas accumulation can sometimes be assessed.
Non-hydrocarbon gases (CO2, N2, H2S) can account for <1% to >99% of a gas accumulation. These gases reduce the resource value by lowering BTU content, and by requiring infrastructure to:
- Prevent corrosion,
- Remove the non-hydrocarbon gases, and
- Dispose of these gases
Carbon Dioxide (CO2):
On average, the global risk of encountering >1% concentrations of CO2 in a gas accumulation is < 1 in 10, and the risk of encountering >20% concentrations of CO2 is < 1 in 100 (Thrasher and Fleet, 1995). However, here is the issue: the mean CO2 content of reservoirs with >20% CO2 is 50% CO2. In other words, when CO2 is abundant, it is frequently so abundant that it can kill the prospect economics. Furthermore, high CO2 concentrations are encountered in diverse areas (Thrasher and Fleet, 1995), including:
- South China sea
- Gulf of Thailand
- Central European Pannonian basin
- Australian Cooper-Eromanga basin
- Colombian Putumayo basin
- Ibleo platform, Sicily
- Taranaki basin, New Zealand
- North Sea South Viking Graben
CO2 sources include:
- Organic sources (i.e., kerogen cracking, and bacterial degradation of petroleum).
- Thermal decarbonation of carbonate minerals.
- Exsolution from magmas.
- Thermochemical sulfate reduction (TSR) of hydrocarbons.
Various geochemical characteristics can be used to distinguish CO2 from each of these sources (e.g., Jenden et al., 1992; Ballentine et al., 1999; Brown, 1999; Cathles and Schoell, 1999; Battani et al., 1999; Imbus et al., 1998; Thrasher and Fleet, 1995). These techniques have revealed that, in gases with very high (>50%) CO2 contents, the CO2 is typically derived from thermal destruction of marine carbonates and/or exsolution from magmas (Jenden et al., 1992; Thrasher and Fleet, 1995). TSR, a process described in the H2S section below, does not yield gases with very high (>50%) CO2 contents. Similarly, CO2 derived from organic sources (kerogen cracking and bacterial degradation of petroleum) rarely exceeds 20% of an accumulation and is only important in special cases, such as certain heavily biodegraded oil fields. Regardless of the source of the CO2 in an accumulation, its abundance is controlled not only by its origin, but also by in-reservoir reaction of the CO2 with silicate minerals, a temperature-dependent process (Smith and Ehrenberg, 1989).
Figure 1: Sources of CO2 in natural gas accumulations (figure courtesy of and used with permission, Alton Brown).
When a gas is found to contain a few percent CO2, a legitimate question is "what is the risk of encountering much higher CO2 contents elsewhere in this basin?" Since high-CO2 contents are associated with decarbonation reactions and/or exsolution from magmas, a first step in assessing the risk of encountering high CO2 in nearby areas is to use geochemistry to determine the origin of the CO2 in the existing gas sample. If the gas composition suggests derivation from either decarbonation reactions or mantle degassing, then the next step is to evaluate where in the basin the risk for these types of CO2 is greatest.
Thermal decomposition of minerals such as dolomite, ankerite, and siderite occur at lower temperatures than thermal decomposition of calcite, but the temperatures are still very high (>300°C). Decarbonation by reaction of carbonate minerals with aluminosilicates occurs at somewhat lower temperatures (Brown, 1999). As a result, carbonate cements in siliciclastic lithologies are more readily decarbonated than calcite in a pure limestone (Brown, 1999). However, for CO2 from mineral decarbonation to migrate and accumulate, a free CO2 gas phase must form, and that requires shallow depths (in order for the CO2 concentration to exceed the pore water solubility). Therefore, since even carbonate/aluminosilicate decarbonation reactions require relatively high temperatures (>250°C), special conditions are required for a CO2 gas phase to form. Those conditions are provided by shallow intrusions and proximity to hot basement (i.e., high geothermal gradients). By evaluating where those conditions are present, and by considering conditions that buffer the partial pressure of CO2 (reservoir temperature and lithology), the risk of encountering significant CO2 contamination in a natural gas prospect can be assessed.
When abundant in natural gas, nitrogen may be derived from high-maturity coals, especially when the final stages of generation (VR > 4%) are captured by late-formed traps (Littke et al., 1995; Idiz and Gerling, 1995; Idiz et al., 1995; Krooss et al., 1993). Although nitrogen can also be derived from magmatic sources, magmatic nitrogen is not a common component of high-nitrogen gases. In contrast, clay diagenesis is an important nitrogen source: Ammonium substituting for potassium is released during the transformation of metastable clays (illite-smectite, or smectite) to illite. This ammonium can then be either inorganically or bacterially oxidized to form molecular nitrogen. Because nitrogen is relatively insoluble in saline pore waters, the nitrogen can readily enter the gas phase, especially when sediments are associated with evaporites. This gas-phase nitrogen can then migrate into shallow traps.
The concentration of nitrogen in a gas accumulation can be enhanced by a process that destroys the hydrocarbon components of the gas. That process, thermochemical sulfate reduction, or "TSR", is described in the H2S section below. In brief, TSR is the reaction of calcium sulfate and hydrocarbons (beginning at temperatures of 120-140 °C) to form H2S and calcium carbonate. Because the resulting H2S can either move into the aqueous phase or react with iron in the reservoir minerals to form pyrite, the net effect of TSR can be to concentrate the gases (such as nitrogen) that are not involved in the reaction. However, because TSR only concentrates the existing nitrogen, it can only lead to a nitrogen-rich gas if the original gas contained at least moderate nitrogen.
By integrating geochemical and geological data, the origin of nitrogen gas in a basin can be assessed, and predictions can be made concerning spatial variations in nitrogen abundance in the area.
Hydrogen Sulfide (H2S):
Concentrations of H2S in natural gas vary from 0% to >98%. With regard to petroleum, the geochemistry of H2S is typically used to help resolve two very different problems:
- During exploration, geochemistry plays a role in minimizing the risk of encountering high H2S gas (Worden et al., 1995), and
- During petroleum production, geochemistry is used to assess the cause of increasing H2S values (i.e., the cause of field souring; Marsland et al., 1989; Hutcheon, 1998; Khatib and Salanitro, 1997; Seto and Beliveau, 2000)
A variety of discrete sources for H2S in petroleum have been identified (e.g., Orr, 1977) including:
- Bacterial reduction of sulfate to H2S. The sulfate can be from connate waters, anhydrite dissolution, injected seawater, or pyrite oxidation by injected water. Bacterial sulfate reduction typically does NOT result in gases containing >5% H2S.
- Thermal decomposition of sulfides in kerogen and/or oil (especially in clay-poor, sulfur-rich source rocks). This process typically does NOT result in gases containing >5% H2S.
- Thermochemical reduction of sulfate to H2S (TSR). TSR is the reaction of sulfate minerals (primarily anhydrite) and hydrocarbons (beginning at temperatures of 120-140 °C) to form H2S and calcium carbonate. Because anhydrite is often associated with carbonate sequences, TSR is commonly associated with deep, hot, carbonate reservoirs and/or source rocks. TSR is the most important process for formation of high-H2S gases (>10% H2S). The highest concentrations of H2S are found in deep, post-mature gases from carbonate sources (e.g., deep Smackover gases in Texas; Worden et al., 1995) where TSR is active. A variety of hydrocarbons can be involved in TSR (e.g., Manzano et al., 1997), but a general form for the reaction is:
CaSO4 + CH4 -> CaCO3 + H2S + H2O
To assess the likelihood of encountering significant H2S in a given area, a variety of factors must be considered, including:
- Reservoir temperature (bacterial sulfate reduction is typically limited to temperatures of <80°C; and TSR is limited to temperatures above 120-140°C).
- Availability of sulfate (necessary for both bacterial sulfate reduction and TSR)
- Potential sinks for H2S, such as pyrite formation in the reservoir or along the migration path by reaction of the H2S with iron-bearing silicates and/or carbonates.
To assess the origin of encountered H2S, the above factors can be considered along with other lines of evidence, such as
- Examination of the distribution and form of pyrite in a reservoir (implications for H2S scavenging and pyrite oxidation).
- Microbiological studies of produced waters (to further assess the potential for in-reservoir bacterial sulfate reduction).
- Sulfur isotopic data for the H2S, organic sulfur compounds in the associated oil, and the sulfate in associated water (Krouse, 1977; Thode, 1981).
- Modeling of the aqueous chemistry of the rock/water/petroleum interactions in a given reservoir.
In addition to the techniques described above, other approaches can be applied to further assess the likelihood of encountering non-hydrocarbon gas contaminants in a particular prospect.
Appropriate gas sample collection methods depend on for which gas species the samples are being collected. Protocols for collection of samples for hydrocarbon gas analysis differ from the protocols for the collection of samples for helium analysis, which differ from the protocol for collection of samples for H2S analysis. For more information on sample collection techniques, please refer to our Geochemical Sampling Procedures page.
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