Estimating In-Situ Reservoir Fluid Compositions

Author: Markus Hays Nielsen

Having a good estimate for the in-situ fluid composition is crucial for modeling and forecasting surface gas and oil rate (GOR) behavior, resulting in enhanced reserves estimation. Moreover, if we have in-situ compositions for all wells, it is possible to generate a compositional map which can be used for optimizing the development of a field or basin. The main reason why this is not common practice today is because of the misconception that in-situ compositions can only be found by sampling and PVT laboratory measurement. This is not necessarily the case.

Before we discuss how it is possible to estimate in-situ compositions, we introduce the difference between “reservoir representative” and “in-situ representative” fluid samples. A reservoir representative fluid sample is any uncontaminated fluid sample that originates from the reservoir. This definition spans anything from expensive down-hole sampling to inexpensive separator samples. An in-situ representative fluid sample is a sample representative of the original fluid in place. It is worth noting that any in-situ representative sample will, by definition, also be reservoir representative, but not all reservoir representative samples are in-situ representative. In the 1994 paper by Fevang and Whitson, some experimental and some computational methods were proposed in which inexpensive, reservoir representative, fluid samples are used to recombine and reconstruct a fluid composition that is in-situ representative. The proposed methods are called equilibrium contact mixing (ECM) and have been studied and used for many reservoirs around the world for the past 25 years.

In summary we can (1) use experimental methods to reconstruct the in-situ fluid, (2) rely on computational methods or (3) use a hybrid ECM method. Laboratory experiments may be expensive. However, the main issue with an experimental approach is that not all possible compositional path reconstructions will yield experimental compositions for both phases. Let’s say the original reservoir fluid is two-phase saturated, but when the fluid sample is reconstructed to yield in-situ representative compositions there is only a single phase. Computationally, the composition of the secondary phase can be estimated by calculating the incipient phase composition, but there is no way of measuring such a composition in the laboratory. In short, a computational method will always yield an estimate of the in-situ composition for all phases at a low cost for any well having common test data (e.g. separator compositions, GOR, pressure and temperatures).

By applying the methods developed by Fevang and Whitson for conventional reservoirs, or by Carlsen et al. for unconventional reservoirs, compositional mapping is not only possible, but relatively simple based on readily-available data (public or in-house). Although confirmation of the estimated fluid compositions will require continual verification, having approximate in-situ compositional maps based on readily-available data – and a consistent EOS model – provides many opportunities to improve field, basin, and resource development.

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About whitson
whitson supports energy companies, oil services companies, investors and government organizations with expertise and expansive analysis within PVT, gas condensate reservoirs and gas-based EOR. Our coverage ranges from R&D based industry studies to detailed due diligence, transaction or court case projects. We help our clients find best possible answers to complex questions and assist them in the successful decision-making on technical challenges. We do this through a continuous, transparent dialog with our clients – before, during and after our engagement. The company was founded by Dr. Curtis Hays Whitson in 1988 and is a Norwegian corporation located in Trondheim, Norway, with local presence in USA, Middle East, India and Indonesia