The orifice discharge coefficient (CD) is the constant required to correct theoretical flow rate to actual flow rate. It is known that single phase orifice models and methods of prediction of critical flow do not apply to multiphase flow. Thus the questions that must be answered are how do we determine values of discharge coefficient for multiphase flow metering? Can the values of discharge coefficient for critical multiphase flow be used for subcritical flow? Figures, tables and equations of CD are presented with which metered multiphase flow rates can be corrected to obtain actual multiphase flow rates for both critical and subcritical flows. It is shown that CD for multiphase critical flow cannot be the same for multiphase subcritical flow. Introduction Multiphase flow is a complex phenomenon: As a result the majority of published correlations are highly empirical. This affects the general validity of these correlations for all ranges of fluid properties as they are limited to the quality and scope of the data base from which they are developed. Therefore, correlation which performs well within the range of data used to develop it, may fail outside this range. Multiphase flow through restrictions is usually evaluated under critical or subcritical flow conditions. As a standard oilfield practice, wellhead flow performance is evaluated under critical flow while flow performance through subsurface chokes and safety valves is done through subcritical flow. Critical or sonic flow is flow in which downstream pressure and temperature perturbations are not transmitted upstream to affect the flow rate unlike in subcritical flow. Available critical multiphase orifice flow correlations can be categorized as follows(1):Analytical models, applying mathematical analysis based on fundamental principles, to a simplified physical model with the development of equations.Empirical correlations using dimensional analysis to select and group the most important variables.Empirical correlations from field or laboratory data. Examples of category 1 correlations are those of Tangren et al.(2), Ros(3), Poettmann and Beck(4), Ashford(5), a generalized model by Ajienka(6) and Ajienka and Ikoku(7). The simplified form of the generalized model applicable to both continuous liquid phase flow and continuous gas phase flow is given by Equation (1): Equation (1) (Available In Full Paper) where Equation (2) (Available In Full Paper) Equation (3) (Available In Full Paper) Equation (4) (Available In Full Paper) Letting Equation (Available In Full Paper) To be equal to X, then: Equation (5) (Available In Full Paper) Equation (6) (Available In Full Paper) Flow is critical if the pressure ratio (X = Xc) is equal to the critical pressure ratio. Otherwise, flow is subcritical. Ashford's analytical correlation for critical flow is given by: Equation (7) (Available In Full Paper) where Equation (8) (Available In Full Paper) Equation (9) (Available In Full Paper) Equation (10) (Available In Full Paper) While the earlier analytical models assume that critical flow TABLE 1: Empirical coefficients of category 3 correlations. (Available in full paper) Occurs at a constant pressure ratio of 0.554 (for k = 1.04) as with single phase flow, the Ajienka and Ikoku model uses a predicted critical pressure ratio which is realist
Reservoir fluid properties such its bubble point pressure, formation volume factor, solution gas/oil ratio, and viscosity are required for the analysis of reservoir performance. Ideally, these properties would performance. Ideally, these properties would be determined experimentally, from laboratory PVT analyses. Frequently, these properties PVT analyses. Frequently, these properties must be predicted in advance of PVT studies. Since the crudes from different regions have different properties, it is prudent to assess the accuracy of the available correlations and make an informed selection for each region or type of crude. PVT reports have been assembled from several Alaskan oil fields in the Cook Inlet Basin (CIB). The experimentally determined values f o r bubble point pressure, oil formation volume factor and live and dead oil viscosity have been compared to the values calculated from several popular correlations. CIB crudes are characterized as low sulfur crudes with a high nitrogen content. Crudes from the Alaskan North Slope have high nitrogen and carbon dioxide contents. The presence of non-hydrocarbon gases has a presence of non-hydrocarbon gases has a marked influence on bubble point pressure. Correction factors must be applied. The available correlations and corrections have been compared for application to CIB crudes, and specific recommendations for their use are included in the conclusions. The appendices to the paper also include a convenient compilation of the equations for the correlations. Introduction The accurate prediction of physical properties and the volumetric: behavior of properties and the volumetric: behavior of reservoir fluids as functions of temperature and pressure is essential for the evaluation of reservoir performance. Properties such as bubble point pressure, formation volume factor, solution gas/oil ratio and viscosity form the basis for the calculation of recoverable reserves, producing capacity, producing gas/oil ratio, and nearly all other producing gas/oil ratio, and nearly all other aspects of reservoir engineering calculations. Ideally, these properties can be measured through laboratory PVT analyses of bottom hole samples. However, it is frequently necessary to have property predictions in advance of PVT analyses. predictions in advance of PVT analyses. In these cases, the only data available may be reservoir temperature and pressure, producing gas/oil ratio, stock tank oil gravity and gas gravity. Over a period of years, correlations have been published relating reservoir fluid properties to the commonly measured surface variables. Moreover, even when PVT analyses are available, it is often necessary to extend the data to field conditions through the use of correlations. Of the PVT correlations currently in use, Standing‘s’ work probably enjoys the widest popularity. However, more recent correlations developed by Lasater, Glaso, and Vasquez and Beggs are also in common use. The correlation of Vasquez and Beggs forms the basis for the PVT correlations used in the Petroleum Fluids Pac for the Hewlett-Packard 41-CV calculator. Historically, PVT correlations have been based on data from limited geographical areas, as in the case of Standing's use of California crudes, or on large composite data bases from a wide variety of locations including crudes of widely, differing properties (Vasquez and Beggs). Both properties (Vasquez and Beggs). Both approaches have their own strengths and weaknesses. The PVT behavior of crude oil is a strong function of composition. P. 357
Several correlations for estimating the reservoir permeability from electric well‐log data have previously been developed. Unfortunately, none of these correlations are universally valid, since each correlation is strongly dependent on the local lithology, and the properties and distribution of reservoir fluids in the well. There is therefore a need to develop such a correlation for use in reservoir rocks of the Niger Delta Basin. Using multiple‐regression analysis, the Authors have developed empirical expressions for permeability in terms of log‐derived porosity and irreducible water‐saturation for unconsolidated sands in the Eastern Niger Delta. A comparison is made between this new expression and those previously proposed, using 218 sets of field‐measured data. Permeability estimated by the newly‐ proposed expression is found to be accurate. The expression could be valid for other oil‐producing areas, provided that the reservoir rock and fluid properties are similar to those of unconsolidated sands in the Eastern Niger Delta.
PUBLICATION RIGHTS RESERVED PUBLICATION RIGHTS RESERVED THIS PAPER IS TO BE PRESENTED AT THE INTERNATIONAL TECHNICAL MEETING JOINTLY HOSTED BY THE PETROLEUM SOCIETY OF CIM AND THE SOCIETY OF PETROLEUM ENGINEERS IN CALGARY, JUNE 10 TO 13, 1990. DISCUSSION OF THIS PAPER IS INVITED. SUCH DISCUSSION MAY BE PRESENTED AT THE MEETING AND WILL BE CONSIDERED FOR PUBLICATION IN CIM AND SPE JOURNALS IF FILED IN WRITING WITH THE TECHNICAL PROGRAM CHAIRMAN PRIOR TO THE CONCLUSION OF THE MEETING. Abstract The hazard associated with abnormal pressures are of great concern to operating companies in the oil pressures are of great concern to operating companies in the oil industry worldwide. As an effort to alleviate this problem in the Niger Delta, a spread of overpressures as they occur in the basin are shown in a map of the area. The table from which the map was produced contain the values of the top of overpressures obtained from shale resistivity, acoustic and resistivity plots against true vertical depth. The depth to the top of overpressures from the more than 230 wells studied, range from 6,500ft along the shelf to 15,000ft at the middle belt and 16,000ft at the west-belt of the Niger Delta Basin Complex. Shale resistivity ratios and shale transit time differences obtained from normal and observed (abnormally high pressured) resistivities and transit times respectively, have been used in conjunction with the fluid pressure gradient, to generate the prediction curves. pressure gradient, to generate the prediction curves. Comparison is made between the predicted formation pressures using the predicted curves and actual measured pressures. The standard deviation for the resistivity method is + or - 0.626% psi/ft. (or about + or - 63 psi per 10,000ft.) and the acoustic method is + or - 2.058% psi/ft. (or about 1200 psi/ft. per 10,000ft.) Using data from previously published papers, per 10,000ft.) Using data from previously published papers, correlating equations for predicting formation fluid pressure gradient are presented for some other major producing areas. Introduction Operators involved with the exploration, drilling and production operations, are more and more frequently production operations, are more and more frequently confronted with complications associated with overpressured (abnormally high fluid pressured) formations. This is found to be true in the Niger Delta Basin area of Nigeria. Figure 1 is a location map of the Niger Delta Basin. Nigeria occupies an area of about 370,000 square miles, with the Niger Delta Basin area being the only major oil and gas productive region. Three main areas of Basin Complex have been mapped in Nigeria. These are the West African Massif (eastern end), the Northern Nigerian Massif and the Eastern Nigerian Massif. These Basins and Troughs taken together with onshore part of the Niger Delta Complex, occupy about 178,000 square miles, about half the total area of Nigeria. The Cenozoic Niger Delta Complex area today occupies around 30,000 square miles of the Southern Nigerian Sedimentary basin onshore. The total complex (onshore- offshore area) must exceed 100,000 square miles. REVIEW OF GEOLOGY OF THE NIGER DELTA Details of the geology of the Niger Delta has been discussed in details by several authors. P. 75-1 P. 75-1
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