Pliocene Reservoirs Research Articles

Origin of natural gases in the Apulian basin in south Italy: A case history of mixing of gases of deep and shallow origin

Pliocene reservoirs in the Apulian Basin in south Italy produce gases of highly variable composition. C 2+ concentrations range between 0 and 8%, nitrogen between 0 and 20%, CO 2 between 0 and 80%, and δ 13C and δD in methane between -67 and -41% 0 and -212 and -153% 0, respectively; δ 13C in ethane and propane measures −31.6± 0.6% and −26.2± 0.5%, respectively, being very similar in all gases. Variations are found even in single reservoir sands. The ratio of methane deuterium and carbon-13 concentrations from different samples ( ΔD/ Δ 13C) are approximately ∼2/1. Because of diffusional processes and chromatographic effects, the relative change of deuterium vs carbon-13 is mostly in the order of 10–15. This relationship suggests that conservative mixing of two end member controls the isotopic variability of hydrocarbons. The concentrations of the higher hydrocarbons also follow this mixing relationship. If nitrogen and carbon dioxide are included, a more complex three end member mixing has to be assumed. The data suggest that in a deep pre-Pliocene setting, CO 2 of possible volcanic origin mixes in various proportions with an associated gas having an original composition of 20% nitrogen, approximately 8–10% C 2+ hydrocarbons, and approximately 70% methane. These gases of different mixing proportions enter shallow sands and again become mixed with a pure bacterial methane. In the shallow reservoirs, CO 2 is removed from the gases through water/rock interactions indicated by the deficiency of CO 2 in gases in shallow reservoirs.

CRUDE OIL AND NATURAL GAS IN THE FEDERAL REPUBLIC OF GERMANY: DEVELOPMENT AND PROSPECTS

Before making a critical evaluation of the crude oil and natural gas prospects for the years to the end of the century, it is necessary to review the geology and structure of the three German hydrocarbon‐producing provinces. Furthermore, past exploration, production and reserves should be discussed.The three hydrocarbon‐producing provinces are: the NW German Basin, the Upper Rhine Graben and the Molasse Basin, which together make up about 41% of West German territory (Fig. 1).The NW German Basin contains a sedimentary sequence over 8,000 m thick ranging in age from Permian to Quaternary. Gas and oil, the two natural hydrocarbons, are generally confined to separate lower and higher stratigraphic levels respectively (Fig. 2). The NW German Basin is the most important prospective area in West Germany. It extends into the North Sea.The tectonic rift feature of the Upper Rhine Graben originated in the Eocene. The Tertiary fill is over 4,000 m thick. Oil is found mainly in Mesozoic, Eocene and Oligocene rocks; the Miocene and Pliocene reservoir rocks contain natural gas almost exclusively (Fig. 3).The Molasse Basin is part of the foredeep north of the Alpine and Carpathian mountain ranges. The basin is filled with Upper Eocene to Pliocene and Quaternary sediments which, near the Alpine nappes, reach a thickness of over 5,000m (Fig. 4).During this century there were peaks in annual oil‐production in 1910, 1940 and 1968 (see Fig. 5). The 1910 peak was the result of drilling activity in the Wietze oilfield. During the period 1934–1945, government financial aid was made available for drilling exploration wells. The success of this collaboration is demonstrated by the oil output in 1940 of 1 × 106 t. After World War II, many different types of oil‐bearing structure were found, particularly by reflection seismic techniques in conjunction with detailed stratigraphical and palaeogeographical investigations. The success achieved can be seen by the peak of 8 × 106 t oil production for 1968 (Fig. 5) and in the growth of oil reserves (Fig. 7). Intensive exploration also enabled many new gasfields to be developed, especially in the deeper horizons of the NW German Basin. In 1971, estimated gas reserves reached 360 × 109 m3 (Fig. 11), and annual gas production in 1979 was 20.7 × 109 m3 (731 Bcf) (Fig. 9).There is, no doubt, still scope for the discovery and exploitation of oil and gas in Germany, especially in the NW German Basin where the best prospects for the future lie. This is borne out by two recent offshore oil discoveries and also by the successful application of enhanced recovery methods in the oilfields. The chances of finding more gas at the lower stratigraphic levels are promising now that gas has been discovered in the deeper parts of the Permian basin. The results of massive‐hydraulic‐fracturing tests in low‐permeability pay‐horizons are also encouraging. The deeper parts of oil‐ and gas‐producing basins contain interesting prospects and have yet to be tested by ultra‐deep wells.Provided that the economic climate remains favourable, there should be no difficulty in finding and supplying German oil and gas in the future. Geologically and technically possible reserves should be converted into proven and/or probable reserves. German crude oil will be available for several years beyond the year 2000, and German natural gas for a far longer time. A production rate of 19 to 20 × 109 m3 of gas per annum is feasible over the next twenty years, and oil production will probably not sink below 3 × 106 t/a in this period.

Perforations-A Prime Source of Well Performance Problems

As sure as technology comes up with a nifty solution to a persistent problem you can bet it will have to come up with equally nifty solutions problem you can bet it will have to come up with equally nifty solutions to the new problems caused by he original solution. This is called progress. progress. Introduction This investigation was undertaken to determine the cause of difficulties encountered in injecting fluids through perforations into unconsolidated permeable Pliocene and Miocene sand reservoirs. The particular Pliocene and Miocene sand reservoirs. The particular wells in question are in the South Pass Block 24 and Block 27 fields, located at the mouth of the Mississippi River. We felt that injectivity impairment, by preventing proper placement of sand-control, was a primary cause of the high incidence of sand-control primary cause of the high incidence of sand-control failure and associated casing damage. We expected that by understanding the source of injectivity impairment we could also obtain a better insight into the cause of productivity impairment common to those wells. Impairment of injectivity into unconsolidated sands can be a serious problem since a essential part of the completion is the injection of sand-consolidating fluids into the formation through the perforations, or the deposition of gravel in the perforation tunnels (the holes through the casing and cement sheath). Portions of an interval not accepting consolidating Portions of an interval not accepting consolidating chemicals would be subject to early sand-control failure. Treatment through impaired perforations could cause the impairment to become "locked in place" by the treatment plastics and result in seriously decreased well productivity. In gravel packing, the perforation tunnels must be filled with properly sized perforation tunnels must be filled with properly sized gravel to prevent the tunnels from becoming filled with fine formation sand when the well is put on production. Perforation tunnels filled with fine production. Perforation tunnels filled with fine formation sand severely restrict fluid flow. The tunnels can most likely be filled with gravel only if fluid can flow out of the wellbore through the perforation tunnels and carry gravel into them during perforation tunnels and carry gravel into them during gravel-packing operations. Perforation Flow Impairment Perforation Flow Impairment There has been widespread evidence of a severe perforation flow impairment problem in Shell's perforation flow impairment problem in Shell's Delta Div. in South Louisiana. Plastic consolidation fluids usually could not be pumped outward through the perforations without acid stimulation or fracturing, neither of which has assured uniform placement throughout the perforated interval. Gravel-packed wells have commonly required acidizing before full-depth-allowable production could be obtained. Recovered gravel-pack production could be obtained. Recovered gravel-pack screens and blast joints have frequently shown only one or two eroded holes (Fig. 1), suggesting that most of the produced fluid was coming from only a few of the perforations. Steps were taken, therefore, to isolate the cause of impairment of well injectivity and productivity. A process of elimination was begun in the field concurrently with laboratory investigations. The extent of perforation impairment and its relative importance with perforation impairment and its relative importance with respect to other possible sources of trouble (drilling mud or cement or completion fluid) were studied individually. Drilling mud and cement were considered to be possible contributors to impairment primarily because possible contributors to impairment primarily because of the way dispersant-type filtrates affect the clay material in the formation. P. 399

Comparison of Conventional Core Data, Well Logging Analyses, and Sidewall Samples

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

VARIATIONS IN THE HYDROCARBON COMPOSITION OF GASES IN KOBYSTAN TERTIARY POOLS

The gas in a petroleum pool varies in direct proportion to the concentration of higher methane compounds. This fact,' and strongly characteristic butane‐isobutane and pentane‐isopentane ratios resulting from petroleum reservoirs chemistry, seems to serve as a reliable standard for distinguishing between pools in the Oligocene‐Miocene and Pliocene reservoirs of the Azerbaydzhan (West Caspian) basin. ‐‐M. E. Burgunker.