Identification of the produced hydrocarbon liquid stream, as either oil or condensate, in two-phase hydrocarbon reservoirs, gains special significance in cases where the gas cap and its associated condensate owners are different from the oil rim owners. Thus, the definition of the produced hydrocarbon liquid stream is critical in determining the allocation of the produced liquid phase and accounting for the volumes of oil and condensate produced to satisfy marketing constraints. In this paper we will discuss classification procedures of the produced hydrocarbon liquid stream, laboratory sampling and analysis, and compositional modeling demonstrated for a saturated oil reservoir with a large gas cap and a critical fluid reservoir.
The definition of the hydrocarbon liquid stream and the characteristics of oil or condensate received significant focus in the petroleum literature. Appropriate sampling and conventional analysis of oil and condensate was discussed as early as 1941 by Flaitz et. al.1 and later in 1954 by Reudelhuber2,3,4. Eilerts et. al.5 in 1957 reported observed characteristics of a number of condensate fluids highlighting the wide range in physical properties and deriving "rule of thumb" to classify condensates based on gas-oil-ratio (GOR) and API gravity. In 1986 Moses et. al.6 discussed the characteristics of oil, near critical fluid and condensate, his work received significant discussion that advanced the understanding of the defining characteristics of the hydrocarbon fluid systems. A more detailed classification was presented by McCain et. al.7,8,9,10,11,12. McCain's classification identified color, API gravity and gas-liquid ratio (GLR) as defining characteristics of the produced hydrocarbon stream.
Legal definitions and classifications were also adopted by various governmental agencies and are applied as references. Specifically, the Alberta Mines and Minerals Act 13,14 and the 1988 OPEC classification15.
The significance of establishing an agreed criteria and procedure to classify and allocate oil and condensate production is realized in mixed ownership, where the owners of the oil and condensate are different. For mixed production situations, that will inevitably evolve during the development cycle of two-phase hydrocarbon reservoirs, present a challenge in determining the accurate allocation ratio of oil and condensate. We will demonstrate that appropriate periodic sampling and analysis of mixed producing wells provide the technical basis of validating compositional modeling techniques capable of component tracking permitting differentiation of liquid streams originating from the gas-cap or oil column. The procedure was applied to a saturated oil reservoir and a critical fluid reservoir and the results and specific technical challenges will be discussed.
Definition of produced hydrocarbon liquid stream as "condensate" based on surface determined properties was presented by Eilerts et. al.5 in 1957, observing that condensates range from very rich with a condensate-gas ratio (CGR) of 500 Stb/MMScf to very lean 10 Stb/MMScf with API gravities reported as low as 30 ° API to as high as 80 ° API. Based on the data reviewed, Eilerts et. al.5 observed that the API gravity of 85% of the samples reviewed ranges between 45 - 65 ° API, and quoted a rule of thumb for a gas condensate system to exist when the GLR exceeds 5000 Scf/Stb and the liquid is lighter than 50 ° API.