No abstract

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. After their migration into the trap, various forces shape the fluids. Among them, gravity has the most striking effect and has been widely studied. But in many cases, there is evidence for the contribution of other forces like thermal gradients and external mass flux at a geological time-scale. Taking all these phenomena into account to obtain a consistent picture of fluid distribution is an important challenge for the petroleum industry. 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, the actual profile differs from the one calculated. The discrepancies are imputed to other external forces: the mass fluxes at the reservoir boundaries. In this paper, we present the modeling of diffusion fluxes across the reservoir. Drawing on field examples, the paper provides a methodology for dealing with dynamic reservoir fluid systems and offers petroleum engineers guidelines to avoid many pitfalls during the field evaluation procedure. The model matches the observed compositional gradient and corresponding PVT properties. It allows reliable connectivity assessment in cases where gravitational modeling fails. The main contributions are a methodology for integrating the geological constraints in the evaluation of fluid distribution in a reservoir and the description of the model, which includes the impact of gravity, thermal gradient and external component fluxes. Introduction The PVT properties of the various samples taken from a reservoir may be very different. Although accurate knowledge of each sample is necessary, it does not usually extend in any obvious fashion to the reservoir as a whole. Evaluation of the reservoir fluid therefore becomes a compulsory preliminary step before any development plan and it has subsequently to be updated regularly throughout the life of the field. All the fluid data are required to reach a comprehensive knowledge of the fluid system, together with essential additional reservoir data such as pressure, temperature and logs. Gravity segregation models enable the composition of the fluid at any depth in the reservoir fluid column to be calculated 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 PVT software. Unfortunately, in many field cases, the actual compositional profile cannot be obtained with simply the gravity force. Capillary forces can cause significant differences in the case of two-phase reservoirs [5–6] and the thermal field is obviously responsible for some discrepancies [7–12], but the most striking difference certainly stems from the dynamic situation of the reservoirs [13–16]. It has already been established [14] that the characteristic time for component redistribution within a reservoir is very short compared to the geological time scale. This is due to the efficiency of the natural convection induced by density heterogeneities or by the geothermal gradient. But there are two situations where redistribution is still active: the first is observed when the pressure increases in a trap where the fluid is split into two phases, and the second can be found in reservoirs subjected to significant gas diffusion flux. In the first case, diffusion is the only possible mechanism for redistribution of the components between the two phases, and the characteristic time for diffusion across the whole fluid column may be very long. In the second case, if the gas flux remains below a critical value, the fluid column reaches a stationary state, which differs significantly from the segregated situation.

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].

No abstract

Formation Testers provide valuable information on compositional gradient within a reservoir fluid column. But it has been established that fluid samples obtained with oil-based muds (OBM) are contaminated by the filtrate to an extent dependent on the "pump out" time and the original fluid properties. Except in some very specific cases, the contamination reaches a residual asymptotic level with the pump-out duration. When fluid viscosity is high, the residual contamination is high too and its impact on the physical properties can be huge. New techniques have been developped to deal with contaminated samples. This paper describes different ways to get rid of contamination and assess the reservoir fluid composition and associated PVT properties. It then offers some recommendations for sampling procedures. A distinction is made between simple miscible cases and complex two-phase cases where the mass exchange between reservoir fluid and filtrate is no longer negligible. Three decontamination methods are presented, and the reliability of the calculated properties of the de-contaminated fluid is discussed. Through field examples, the paper provides a methodology for dealing with contaminated samples and tips for getting the best from Formation Tester samples. The main contributions are the methodology for decontamination of Formation Tester samples in the case of OBM drilling, and the integration of the information from this sampling tool into the reservoir fluid evaluation procedure. Introduction Oil-based mud (OBM) systems are often required to drill wells successfully. Their use generally results in better wellbore quality, increased rate of penetration, reduced drilling time and environmental acceptability. There are several classes of base oils: organic phase fluids (OPF), oil base fluids and synthetic fluids. Despite the obvious advantages of Oil-Based muds, their use hasadverse effects geochemical interpretation, wells logs and fluid characterization. Formation Testing Samplers such as RFT, MDT, RDT or RCI make it possible to recover reservoir fluids and take the decision whether or not to test. As the OBM filtrate is miscible with the reservoir fluid, it may strongly affect composition and phase behavior of the reservoir fluid. On site, specific characterization methods such as OFA or RMN enable mud contamination to be controlled with the pump-out time. However, the miscibility effect of OBM with reservoir fluid samples cannot be avoided. Mud contamination, even slight, has an impact on the measured thermodynamic parameters such as saturation pressure, formation volume factor, gas-liquid ratio, density, viscosity and molecular weight of the reservoir fluid and of the dead oil. For reservoir developments, it is highly desirable to determine with accuracy the un-contaminated composition and phase behavior of the reservoir fluid column. Initially, in fabrication state, the composition of OBM is well known, but progressively, depending on the number of wells drilled, the mud filtrate composition changes due to the contact with in-situ hydrocarbons. The simplest de-contamination method is based on the contamination level deduced from on-site measurements. The contaminated fluid samples are analyzed by gas chromatography. The initial mud oil composition is known, either from analysis of a sample from the rig, or from the manufacturer. The true composition of the reservoir fluid is obtained by subtracting the mass of the mud oil from the fluid sample composition. This method assumes that the mud oil contamination is purely additive (i.e. full miscibility between reservoir fluid and mud oil under sampling conditions).