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Fluid Characterization
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.
Abstract Characterization of reservoir fluids is important for developing a strategy tomanage the reservoir production scheme effectively and efficiently. Reservoirfluid properties (e.g., density, viscosity, gas/oil ratio, bubble-pointpressure, compressibility, and formation volume factor) are crucial for bothreservoir and petroleum engineering; they are the fundamental inputs formaterial balance calculation, determination of oil reservoir volumes, andestimation of oil recovery with the use of a reservoir simulator. Ideally, thereservoir fluid properties are determined from laboratory studies on thebottomhole samples or on the recombined separator oil and gas samples. Whenonly field measurements or limited laboratory data are available, empiricalblack oil correlations can be used to determine the essential fluid propertieswithout the knowledge of fluid compositions. In the past few decades, withlarge sets of petroleum fluid data at various reservoir conditions andproperties, the development of black oil correlations forpressure-volume-temperature (PVT) analysis study has been researchedextensively. Consequently, numerous correlations that are applicable to varioustypes of oil have been proposed and published. In this paper, we compare andprovide guideline for the various correlations that were used to determine theblack oil fluid properties. For this study, more than 30 theoretical and empirical black oil correlationsfor bubble-point pressure, gas/oil ratio and oil formation volume factor werereviewed and validated; variations of the calculated fluid properties versusinput parameters were studied and compared across the stated ranges ofapplicability. The comparison results are presented graphically. Thecorrelations of this study are also summarized in tables that can be used toguide PVT users in selecting the most appropriate black oil correlation forspecific reservoir fluids and conditions. Introduction The physical properties of the reservoir fluids are very important input datain reservoir engineering calculations. Well characterized reservoir fluidproperties are crucial for a good estimate of oil or gas reserves, productionforecasts and the efficiency of enhanced oil recovery (EOR) methods. It is notalways the case that reservoir fluid samples are available and thoroughlystudied to characterize the reservoir fluid properties in the most accuratemanner. In situations where no samples are available, one must rely onempirically derived correlations to estimate the physical properties ofreservoir fluid. This paper reviews the existing black oil correlations thathave been published in the literature and elaborates how they are used in ourin-house consolidated pressure-volume-temperature (PVT) library. There are many parameters to be considered for reservoir characterization andmodeling; however in this paper we focus and discuss on those publishedcorrelations for bubble-point pressure, gas/oil ratio and oil formation volumefactor. The decision was made as these parameters are more influential in theaccuracy of fluid properties calculation and facilities planning than otherssuch as fluid compressibility, viscosity, density and etc. In the first part of this paper, we present a literature review of variouscorrelations for bubble-point pressure, gas/oil ratio and oil formation volumefactor. For each correlation, the origin of oil used for the developedcorrelation is presented, its range of applicability and any related potentialissues are discussed. In the second part, the studied correlations that havebeen used in our in-house consolidated PVT library are summarized, compared anddiscussed, together with their applicability.
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- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)