Estimates Of Gas Reserves Research Articles

On the Subject of Reserve Estimates in Water-Drive Gas Reservoirs

In his article in the JPT Forum, William Hurst resumes his discussion of our paper on reserve estimates in water-drive gas reservoirs. We can only make reference to our previous reply and add the following comments.1. The aims of our paper were:to show that the simultaneous determination of gas reserves and aquifer characteristics from the past history of waterdrive gas reservoirs can result in more than one set of solutions; andto evaluate the actual indetermination range of gas reserve estimates for some reservoirs that have a well known past history, where a water-drive had been ascertained, as they had been partially invaded by the water encroaching from edge partially invaded by the water encroaching from edge or bottom aquifers. 2. The detailed geological description of the gas reservoirs of the Po Valley, Italy, was presented in 1957 at the "Symposium on Gas Fields of Western Europe". A feature that is common to almost all of these reservoirs is their being in contact with aquifers of good permeability. 3. Contrary to William Hurst's statement that "the authors claim that they have water-drive reservoirs, but with their computer programs, they are unable to establish this effect", the presence of a water encroachment (calculated according to the van Everdingen-Hurst method) is clearly shown (Ref. 2, Table 3) in all sets of solutions presented for the reservoirs considered. The actual occurrence of a water encroachment into the reservoirs in question 2 has been proved by the following facts:a. In three of the reservoirs (BM-A, R-A, S-F)new wells have been drilled in the last few years. It has been ascertained that the water/gascontacts, at the moment the wells have been drilled, were 220 ft, 65 ft and 1 10 ft, respectively, abovetheir initial position in the three reservoirs inquestion.b. In BM-A field, 3 years after shut-down thereservoir pressure increased by 361 psi from 1,252to 1,613 psia, the initial reservoir pressure being1,927 psia.c. Some time after the production period consideredin our paper a marked deviation from linearityeventually occurred in the p/z vs Gp curve of allthe reservoirs considered. 4. Hurst's discussion seems to imply that linearity in the initial part of the p/z vs Gp curve is enough to prove a depletion-type of performance. That this does not prove a depletion-type of performance. That this does not apply has already been shown by others. There is no ground to support William Hurst's interpretation that the reservoirs in question are depletion-type and, as an unlucky consequence, to validate his "indication that considerable gas reserves may still exist" in those gas reservoirs of the Po Valley which have been abandoned. Of course, we are confident we are able to distinguish between a well needing only a work-over and a well that has been completely invaded by the encroached water (incidentally, we never wrote "logged up"). P. 561

Correlating and Averaging Connate Water Saturation Data

Abstract The use of simple hyperbolic relationships in correlating connate water saturation data is shown to have wide application in a variety of reservoirs. This can be of considerable practical significance to the reservoir engineer because volumetrically weighted average saturations for any combination of core samples, reservoir strat a or lease areas can be obtained directly from such correlations with a knowledge of average porosity alone. Also, in systems represented by a simple equilateral hyperbola the porosity- saturation productis constant and hydrocarbon volumes are conveniently derived from the difference between the pore volume and a constant fraction of the bulk volume. Potential applications and limitations of the technique have been explored fora number of sand and carbonate reservoirs, and several examples are described. Introduction Of fundamental importance in all oil and gas reserve estimates is the concept of connate water saturation. In fact, as it is one of the most basic parameters, like pay thickness or porosity, connate water must be measured orestimated in any and all types of reservoir analyses. Because water saturations may range from as little as 1 or 2 per cent up to 100 percent of the pore space within the same reservoir, it is common practice to condense the data into asingle "average" value related to some other average reservoir characteristic such as porosity or permeability. Although such an average may be applicable tothe reservoir as a whole, it can, in some cases, lead to appreciable errors ifapplied to individual wells or areas within the pool. Even when the entire poolis considered, there may be considerable difficulty in obtaining the correct average. The use of permeability as a correlating parameter has long been popular (1,2, 3), and in some reservoirs it may be the only reasonable choice. Difficulties, however, can be encountered in applying such relationships toobtain true average saturations. Porosity-saturation correlations have beengiven somewhat less attention in the literature, although they have been widely used in Western Canada and in some areas of the United States. There are inherently fewer problems in establishing representative average values from porosity relationships, as the differences between arithmetic and geometric means, medians and modes, and the effects of sample orientation, need not be considered.

A New Compressibility Correlation for Natural Gases and Its Application to Estimates of Gas-In-Place

Abstract This paper presents an evaluation of compressibility factor data and adiscussion of their application to the estimation of gas reserves. A correlation is presented which provides compressibility factors for use inboth two-phase and single-phase hydrocarbon systems. Accuracies comparable tothose obtained previously for single-phase systems only can be expected. Asimple means of predicting the presence or absence of a liquid phase in acondensate system of known composition is illustrated. The correlation is based on 1,030 compressibility determinations from 21hydrocarbon samples taken from eight oil fields. Of the data used, 75 per centwere from California, 15 per cent were from the Mid-Continent area, and 10 percent were from South America. The average numerical deviation of theexperimental data from this compressibility chart is 1.22 per cent. Charts and tables are included and discussed which illustrate the errorsinvolved through the misuse or nonuse of compressibility factors in estimatesof gas-in-place. Introduction The compressibility factor is a coefficient which expresses the deviation ofa gas of given composition from the Perfect Gas Laws. A factor such as this isnecessary in any calculation involving volumes of gaseous mixtures, and findsextensive application in the estimation of natural gas and condensate reserves.It is used in the decline curve, the volumetric, and the material balancemethods of gas reserves estimation. The behavior of gases at high pressures has been investigated extensively inrecent years and considerable data have been assembled on the compressibilitycharacteristics of a number of gases. Notable among the investigators of highpressure gas relationships are Kvalnes and Gaddy, Kay, Sage and Lacey, andBrown, Standing, and Katz. Other contributors are Smith and Watson, Roland andKaveler, and Stevens and Vance. The data on compressibility factors assembledby these investigators have been presented and correlated in numerous ways;particularly noteworthy is the method first presented by Kay which relatescompressibility factor ?Z? to pseudo-reduced temperature and pseudo-reducedpressure. Other investigators have used this empirical relationshipsuccessfully and numerous charts covering a large number of gases have beenconstructed on this basis. It is the purpose of this paper to evaluate compressibility factor data and toillustrate the importance of their proper use in the estimation of gas-in-placefor both gas and condensate reservoirs. T.P. 2642

Estimation by Volumetric Methods of Recoverable Oil and Gas from Sands

The classical formula for volumetric estimates involving factors for area, sand thickness, porosity, saturation, and recovery is reviewed and the need for modification and amplification of the factors demonstrated. Individual factors are redefined in their new content and methods for their evaluation outlined. Necessity for consideration of both physical and economic effects in the choice of a recovery factor is emphasized. Recovery factors for oils are distinguished from those for gases for co-occurring and produced oil and gas mixtures. Applicability of volumetric reserve estimates to engineering appraisal is discussed and inherent limitations of the procedure set forth. In conclusion the writers point out that practical accuracy in volumetric estimates of oil and gas reserves is dependent both on the accuracy and completeness of the data available and on the skill and resourcefulness of the engineer or geologist in analyzing and visualizing reservoir conditions and fitting together the fragmentary data into a compatible whole. Similarities with and differences from other fields within his experience should be recognized as well as the practical limitations of the factors involved, their relative importance and relative weight.