Uncertainties in Reservoir Fluid Description for Reservoir Modeling
- K.K. Meisingset (Statoil)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 1999
- Document Type
- Journal Paper
- 431 - 435
- 1999. Society of Petroleum Engineers
- 4.1.9 Tanks and storage systems, 5.8.8 Gas-condensate reservoirs, 4.1.2 Separation and Treating, 1.11 Drilling Fluids and Materials, 5.1 Reservoir Characterisation, 5.5 Reservoir Simulation, 1.10 Drilling Equipment, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.6.1 Open hole/cased hole log analysis, 5.1.5 Geologic Modeling, 4.5 Offshore Facilities and Subsea Systems, 5.6.4 Drillstem/Well Testing, 1.6 Drilling Operations, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 4.1.1 Process Simulation, 4.1.5 Processing Equipment, 5.7.5 Economic Evaluations, 5.2.2 Fluid Modeling, Equations of State, 5.1.1 Exploration, Development, Structural Geology
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The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea.
Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions.
The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API).
Fluid Parameters in the Reservoir Model
The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:
- densities at standard conditions of stabilized oil, condensate, gas, and water;
- viscosity (?O) oil formation volume factor (B O ) and gas-oil ratio (RS) of reservoir oil;
- viscosity (?G) gas formation volume factor (B G ) and condensate/gas ratio ( RSG) of reservoir gas;
- viscosity (?W) formation volume factor (BW ) and compressibility of formation water; and
- saturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas.
Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir.
In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model.
Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3).
Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same.
The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by).
For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate.
From Discovery to Production
After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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