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Using Gas Geochemistry to Allocate Commingled Gas Production
Gas geochemistry can be used to solve two types of production allocation problems:
(1) Assessing the relative production from multiple pay zones in a given well
(2) Assessing the contribution of multiple fields to commingled pipeline production streams
Gas geochemistry can be used to allocate commingled gas production at points in the production stream where flow meter data are unavailable. Where flow meter data are available, geochemical data provide complementary information for allocating production.
Natural gas is a mixture of various amounts of hydrocarbon gases (methane, ethane, propane, butanes) and non-hydrocarbon gases (e.g., CO2, N2, H2S, He), as well as higher-molecular-weight hydrocarbons (condensate). Production allocation is achieved by identifying chemical differences between "end member" gases (samples of gas from each of the zones or production streams being commingled). Parameters reflecting these compositional differences are then measured in the end-member gases and in the commingled gas. The data are then used to mathematically express the composition of the commingled gas in terms of contributions from the respective end-member gases. Using a simple mixing model, a single geochemical difference between gases from two sands is sufficient to allocate commingled production from those two units (e.g., Schoell et al., 1993). Using several geochemical parameters, the commingled production from several sands (or several fields) can be allocated to the discrete units using a linear algebra approach (described in detail by McCaffrey et al., 1996). The geochemical parameters measured may include the concentrations of major and minor gas components (both hydrocarbon and non-hydrocarbon gases) and the carbon and hydrogen isotopic compositions of specific gas components. Geochemical allocation of commingled gas is conceptually similar to allocation of commingled oil (see Oil Production Allocation); the techniques differ primarily in the types of geochemical parameters measured.
The gas geochemistry approach described here is based on the well-established proposition that gases from separate reservoirs tend to differ from one another in composition. Depending on the field, these compositional differences exist for one or more of the following five reasons:
1. Different compartments may contain different mixtures of biogenic and thermogenic gas.
2. Thermogenic gas which a source rock generates at a given time differs slightly both from subsequently generated gas and previously generated gas due to continuous, subtle changes in the maturity of the source rock and changes in precisely which part of the source rock is in the generative window. Since no two compartments are of identical geometry, and since no two compartments have exactly the same filling history, it is difficult to achieve precisely the same homogenized composition in two separate compartments - even with thermogenic gas from the same source.
3. More than one source rock may contribute thermogenic gas to an accumulation, and the gases from different sources may differ in composition. Since gases from different source rocks have different times of generation and/or different migration paths, the presence of more than one source may cause different compartments to fill with different mixes of gas from the respective sources.
4. Non-hydrocarbon gases (CO2, N2, H2S, He) present in a natural gas accumulation have a variety of sources that differ from the sources of the associated hydrocarbon gases (see Non-hydrocarbon Gas Contaminants). Therefore, different compartments may contain different concentrations of these non-hydrocarbon gases.
5. Processes that affect gas composition after gas enters a reservoir (e.g., processes such as evaporative fractionation, biodegradation, and water washing ) do not operate to exactly the same extent in separate compartments.
When gases from discrete zones are commingled, these chemical differences between the gases can be used to assess the contribution of each zone or each field to the commingled production (as described in the previous section).
For more information on the techniques described here, or to discuss a specific project, e-mail us at email@example.com, or call us at (214) 584-9169.
McCaffrey, M. A., H. A. Legarre, and S. J. Johnson, 1996, Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California: AAPG Bulletin, v. 80, p. 904-919.
Schoell, M., P. D. Jenden, M. A. Beeunas, and D. D. Coleman, 1993, Isotope Analysis of Gases in Gas Field and Gas Storage Operations: Society of Petroleum Engineers #26171, p. 337-344.
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