Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers, P.O. Box 228, The Hague, The Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Over the past few years the Permian Rotliegendes Sandstone in the North Sea area has been established as a profilic and fascinating gasbearing formation. Realistic evaluation of major gas deposits accumulated in this reservoir rock requires an engineered use of well logging data and core interpretation on a comparative basis. Permeability relationship, data on cementation factor and saturation exponent, matrix grain density, rock compressibility, etc. are discussed on several field cases. Introduction Over the past several years the shelf region of the North Sea has developed into Europe's most promising offshore area of exploration for gas and oil. In rapid succession substantial gas reserves have been delineated especially in the southern region of the North Sea area. This is illustrated by figure 1 showing a generalized map of offshore operation in the North Sea area (Hark et.al., 1971). A corresponding schematic geological profile through the southern part of the British North Sea shelf profile through the southern part of the British North Sea shelf area is given in figure 2 (Hornabrook, 1967). The so-called Rotliegendes sandstone, or Lower Permian age, has been established as a profilic gasbearing formation of major areal extent, covering large parts of both the North Sea and NW-Europe (Holland, Germany). A stratigraphic table of the North Sea area is given in figure 3 (Heybroek et.al., 1967). Despite the fact that several hundred wells have been drilled in the North Sea, only limited data have been published on formation properties of the Rotliegendes. Our present discussion attempts to shed some light on our many observations and the problems one may face in evaluating reservoir characteristics problems one may face in evaluating reservoir characteristics of the Rotliegendes using well logging, core analysis, and other laboratory data. FORMATION PARAMETERS OF ROTLIEGENDES SAND-STONE Grain Matrix Density (pma) Quite often the Rotliegendes appears to be a fairly clean sandstone with shalier, tighter streaks of limited areal extent. Based upon more than 1000 samples we have found the typical sand matrix density to range from 2.64 g/cc to 2.69 g/cc, In general, however, values of 2.67 g/cc to 2.68 g/cc appear to be the most representative and are recommended for computerized well log analysis. Sometimes, problems can arise due to the fact that the parts of the pay sand may be somewhat dolomitic or anhydritic. However, application of properly selected well log interpretation techniques will still give reliable results. Associated Clay Minerals Based upon our experience we can describe the shale component in the Rotliegendes reservoir rock as a mixture of approximately 2/3 illite and 1/3 kaolinite and chlorite, with traces of montmorillonite. Thus, one would expect the pay zone not to be water sensitive and we recommend for computerized logging interpretations a shale density of about 2.80 g/cc to 2.85 g/cc. Since the amount of shaliness is usually low, the "exact" shale density appears to be not too critical. Nevertheless, it can be seen from the recommended shale density values that presence of high shaliness would increase, rather than decrease, porosity values obtained from the density log. However, a question mark is imposed for the use of proper shale resistivity values in logging interpretations. Depending on the situation present in the subject well either a value in the overlying shale or underlying Carboniferous could be used. Usually the latter gives too high shale resistivity values, but unfortunately may be the only "reference" shale present in the vicinity of the Rotliegendes.

Conventional core data and analyses of sidewall samples have been compared with data derived from well logs in reservoir rocks of varying lithologies. Correlation of porosity, hydrocarbon and water saturation, and permeability variations makes it possible to use one data set-taking special precautions when only sidewall samples are available-in the absence of other measurements. Introduction The comparison of core data from both conventional and sidewall samples with log-derived data makes possible a more realistic and reliable evaluation of possible a more realistic and reliable evaluation of the reservoir. Unfortunately, published comparisons of rock properties obtained from core and sidewall samples are scarce. Included in the many generalized conclusions in those papers are thatpercussion sample porosities in softer, looser sands are only slightly higher than those of conventional cores;sidewall sample permeabilities are decreased in higher permeability formations; andwater saturations of the sidewall cores are higher and oil saturations slightly lower than those of conventional cores. Although similar conclusions can be drawn from this study, our investigation uncovered additional complications. Comparison of Conventional and Sidewall Samples An example from Offshore Louisiana shows the comparison between conventional cores using a rubber-sleeved core barrel and sidewall samples (Figs. 1 and 2) in a Pliocene sand. Handling of this Pliocene reservoir rock was complicated by its semiconsolidated nature and by the presence of hydratable clays, which gave up water even at room temperatures if exposed for long periods of time. Since the core-gamma ray log showed multiple sand and shale partings corresponding to lithology variations over short distances, it was difficult in many cases to find comparable porosities within a 6-in. interval of the original core sample. Windows were cut in the rubber sleeve, test plugs were removed and the rubber sleeve was plugs were removed and the rubber sleeve was rescaled to preserve the remaining core. As the study progressed it became apparent that the Dean-Stark extraction method for determining saturations was releasing clay-bound water along with pore water, resulting in too high a measurement of water saturation; using the summation-of-fluids method with varying water plateaus gave more reasonable results. Finally, the plateaus gave more reasonable results. Finally, the remaining rubber sleeve was slit lengthwise and a continuous colored photographic log was taken of the core. Such photographs show clearly the varying degrees of both lenticularity and consolidation. The effect of these two core analyses on the porosity and permeability data in this shaly pay sand as reported permeability data in this shaly pay sand as reported by a commercial core laboratory are shown in Tables 1 and 2. We do not mean to imply by the tables that fluid saturations by "summation of fluid" (SOF) is generally or usually better than the Dean-Stark method. In fact, we prefer the latter method over the SOF method almost exclusively. However, in this particular case, the SOF method under closely controlled particular case, the SOF method under closely controlled conditions (not routine procedures) resulted in data that were reasonable and acceptable. A Miocene Gulf Coast formation was also cored using rubber-sleeve coring equipment. JPT P. 1409