Pressure and Compositional Gradients in Reservoirs

Abstract

The search for the optimal development of a field involves proper knowledge of the composition of the fluids that impregnated the reservoirs. The development scheme could be strongly affected by the connectivity between the different reservoir units. After their migration into the trap, the fluids are shaped by various forces, among them, gravity has the most striking effect and was widely studied. In many cases there is evidence for the contribution of other forces like thermal gradients. Taking into account all the phenomena, to establish a consistent picture of fluids distribution in the field is an important challenge for the petroleum industry. Reciprocally the actual fluid distribution can be used to assess the connectivity of the different panels and layers. In that case, all the possible compositional redistribution mechanisms have to be taken into account. In some circumstances, particularly in recent mature and permeable petroleum systems, hydrocarbon accumulations are subjected to gas fluxes, which lead to non-conventional fluid distribution. There are already a number of tools available for calculating the compositional gradient within a reservoir, including the contribution of gravity and thermal gradient. In many field cases, however, the calculated profile differs from actual. The discrepancies are input to another external force: the mass flux of light component at the reservoir boundaries. In this paper, the authors present the modeling of diffusion fluxes across the reservoir and point out how the diffusion fluxes can reveal the permeability barriers through the pressure and the compositional profiles. Drawing on a field example, this paper provides a methodology for dealing with dynamic reservoir fluid systems. The model matches the observed compositional gradient and corresponding PVT properties. It allows reliable connectivity assessment in cases where gravitational modeling fails. Introduction The PVT properties of the various samples taken from a reservoir may be very different. Although accurate knowledge of each sample is necessary, this does not usually extend in obvious fashion to the reservoir as a whole. Therefore, reservoir fluid evaluation is compulsory as a preliminary study before any development plan and it must be updated regularly during the life of the field. All the fluid data are required to reach a comprehensive knowledge of the fluid system and many complementary reservoir data as pressure, temperature and logs are essential. Gravity segregation models allow us to calculate the composition of the fluid at any depth in the reservoir fluid column from the composition at a reference depth, just by adding the gravity contribution to the chemical potential of the components[1–4]. This option is now included in most of the PVT software's. Unfortunately in many field cases, the actual compositional profile cannot be obtained with this single external force. The capillary forces can lead to significant differences in the case of two-phase reservoirs[5–6] and the thermal field is obviously responsible for part of the discrepancies[7–12] but the most striking difference certainly comes from the dynamic situation of the reservoirs[13–17].

Wireline Formation Testers Unlock Potential in a Deepwater Gas Condensate Reservoir

“…For example, large depth-dependent fluid property variations have been observed in the Brent field in the North Sea (Kingston & Niko 1975) where the fluid composition changes continuously from oil at the base of the reservoir to gas-condensate at the top; without any conventional or obvious gas-oil contact with saturation pressures equal to the reservoir pressure. Similar cases of compositional gradients are documented for reservoirs in the Norwegian sector of the North Sea (Spencer et al 1987), Gulf of Mexico, offshore West Africa (Montel et al 2003) and Krishna-Godavari MA oil and gas condensate field (SPE109204). Reservoir fluid compositional gradients have been shown to occur from the comparison of fluid gradients from PVT properties with wireline formation tester pressure data and equation-of-state (EOS models (Montel et al 2003).…”

“…Similar cases of compositional gradients are documented for reservoirs in the Norwegian sector of the North Sea (Spencer et al 1987), Gulf of Mexico, offshore West Africa (Montel et al 2003) and Krishna-Godavari MA oil and gas condensate field (SPE109204). Reservoir fluid compositional gradients have been shown to occur from the comparison of fluid gradients from PVT properties with wireline formation tester pressure data and equation-of-state (EOS models (Montel et al 2003).…”

“…For example the development scheme of a field can be strongly influenced by the connectivity between different reservoir units, while the implementation of many pressure-maintenance or secondary recovery schemes have failed to achieve desirable results because of large uncertainty in reservoir geologic description and the lack of reliable rock and fluid data. It has also been stated by many workers (Huc 2003, Montel et al 2003, 2007 that actual reservoir fluid distribution data and information on spatial fluid composition variations is very important for connectivity assessment of the different units and sequences within a reservoir. Rock characterization typically involves quantification of porosity, permeability, capillary pressure and relative permeability.…”

Fluid Composition Equilibrium; a Proxy for Reservoir Connectivity

“…If the gradient suggests a continuous pressure profile, compartmentalization cannot be ruled out. The advantage of integration of DFA and pressure gradient analysis has been indicated by numerous authors Elshahawi et al 2005;Montel et al 2003;O'Keefe et al 2007;Venkataramanan et al 2006;Xian et al 2010). Pressure analysis is still the first step in identifying compartments.…”

How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?

“…As discussed, depth-dependent fluid-property variation has been shown to occur by discerning PVT properties (Hanafy and Mahgoub 2005;Smith et al 2004;Montel et al 2003). However, direct comparison of independent measurements contributing to fluid gradients has been rare.…”