Determination of Fluid Composition Equilibrium under Consideration of Asphaltenes - a Substantially Superior Way to Assess Reservoir Connectivity than Formation Pressure Surveys
- Thomas Pfeiffer (Schlumberger) | Zulfiquar Reza (Schlumberger Middle East SA) | William D. McCain (Texas A&M University) | David Schechter | Oliver C. Mullins (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 30 October-2 November, Denver, Colorado, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.3.3 Aspaltenes, 5.5 Reservoir Simulation, 4.3.4 Scale, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 5.8.8 Gas-condensate reservoirs, 4.1.5 Processing Equipment, 5.2 Reservoir Fluid Dynamics, 5.1.1 Exploration, Development, Structural Geology
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Assessing reservoir connectivity during the earliest stages of reservoir evaluation is highly desirable for successful field development. Static pressure measurements with wireline formation testers have been used to assess compartmentalization; if two permeable zones are not in pressure communication, they are not in flow communication. However, the presumption that pressure communication implies flow communication has repeatedly proven to be incorrect. Pressure equilibration requires relatively low mass flow compared to fluid composition equilibration. Thus pressure communication does not impose a stringent condition on connectivity. In contrast, fluid composition equilibration requires mixing of the entire content of the reservoir. Fluid composition equilibration provides a correspondingly much more rigorous set of conditions to determine connectivity.
In this paper, a comparison is made between the time constants for pressure versus fluid composition equilibration for identical reservoir parameters. A reservoir model is designed to simulate numerically equilibration processes over geologic timescales at isothermal conditions where diffusion and gravity are the active mechanisms. A variety of initial conditions and reservoir fluid types are considered. The fluid component with the largest molecular weight and volume is expected to have the longest equilibration time. For black oil, this work accounts for asphaltene nanoaggregates in their own component group. The results are compared with analytical calculations. Longer equilibration times correspond to tighter constraints on connectivity.
Fluid composition equilibration is seen to constrain connectivity by 6 or more orders of magnitude beyond pressure equilibration. The equilibration time of the asphaltenes nanoaggregates exceeds the the compositional equilibration of all other fluid components by a factor of five.
Only a process that stretches across the entire age of the reservoir is likely to capture geologic events that cause compartmentalization. Consequently, the evaluation of the distribution of fluid compositions is shown to be a far better method to test for connectivity than pressure communication. Determination of fluid equilibrium should become part of the standard procedure for reservoir connectivity evaluation.
A compartment is a part of a reservoir that needs to be penetrated by a well to be drained. Undetected flow barriers may lead to disappointing production results. Establishing reservoir connectivity prior to production is highly desirable.
Identifying compartments is not very difficult. The use of wireline formation testers to acquire static formation pressure surveys is common practice. The word static refers to pressure gradient analysis in single or in multiple wells prior to production at virgin conditions. Even subtle discontinuities and differences in pressure gradients can indicate reservoir compartmentalization (Canas et al. 2008; Elshahawi et al. 2005; Jackson et al. 2007).
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