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Income and education were important factors; overall, "younger" ekEerly were more influenced by television than over-70 viewers.Demographically, America is getting older. According to the 1978 U.S. census, persons 65 and over constitute nearly 11 percent of the population, and this group is increasing at a more rapid rate than is the general population (8, pp. 27-32; 9, p. 10). This age group has also been found to watch more television than any other. Nielsen statistics (5) show that among people over 55, women watch slightly over 37 hours and men watch almost 33 hours per week.Several factors have been found to affect how the elderly TV viewer perceives television. According to Davis (2), age, more than other socioeconomic factors, determines the viewer's perception, and positive feelings toward television wane as the viewer ages. Phillips and Sternthal (7) concluded that social and psychological changes which accompany the aging process also have an impact on how the elderly process and use information gained from television.The negative portrayal of the elderly on television may also be a factor in their use of television information. In an examination of prime-time dramatic television from 1969 to 1971, Aronoff (1) found that the aging process was associated with increasing evil, failure, and unhappiness. Northcott's (6) 1974 study indicated that the elderly are both under-represented and negatively portrayed, while Harris and Feinberg (4) concluded that under-representation per se was not a main problem, but rather that older characters were essentially one-dimensional and were rarely well developed. Commercials, too, seemed to exhibit

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The evaluation of the reservoir wettability is fundamental to the understanding of fluid flow in porous media. Wettability has direct impact on saturation end points and the shape of capillary pressure and relative permeability curves. This will, in turn, directly affect the relative movement of the reservoir fluids and eventually affect the displacement efficiency of oil by the different injected fluids. Having reliable wettability data deems very necessary for reliable predictions of expected oil recoveries under different development options. The Amott and the USBM tests are the most commonly used methods for quantifying reservoir wettability. Combination of the two methods is also in use. In addition to the elaborate experimental effort and time required for these methods, the USBM method does not recognize very strongly water or oil wet systems, while Amott method fails to distinguish between important degrees of strong water and oil-wetness. This paper describes a new technique, the Rise in Core (RIC), wettability characterization method based on a modified form of the Washburn equation. It enables relatively quick, accurate measurements of wettability in terms of contact angle and not wettability index as the other methods do. The method is easy to use and requires no complex equipment. During the RIC experiments, core samples saturated with one reservoir fluid are subjected to imbibitions from a second reservoir fluid. As the imbibition process takes place, the core samples weight changes continuously due to adjustments in relative saturations of the two fluids. Monitoring the square of the core mass change with time using a high precision balance, the acquired data is analyzed with modified Washburn equation to determine the cores wettability. For the sake of assurance, RIC wettability measurements were compared to ambient conditions modified Amott-USBM measurements for a thick limestone oil reservoir using core plug pairs from different heights above the free water level. The results compare well. The RIC technique proved to be much simpler to construct, much faster to perform and much easier to analyze and interpret than traditional methods. Moreover, the method gives the operator a chance to evaluate the uncertainty in the wettability data.

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The success of land-and sea-based radio broadcasters has prompted both restrictice and competitiue responses f r o m British legislators and broadcasters plus some awareness of need9 not being met b y the national systems.

Summary Accurately modeling water-saturation variation in transition zones is important to reservoir simulation for predicting recoverable oil and guiding field-development plans. The large transition zone of a heterogeneous Middle East reservoir was challenging to model. Core-calibrated, log-derived water saturations were used to generate saturation-height-function groups for nine reservoir-rock types. To match the large span of log water saturation (Sw) in the transition zone from the free-water level (FWL) to minimum Sw high in the oil column, three saturation-height functions per rock type (RT) were developed, one each for the low-, medium-, and high-porosity range. Though developed on a different scale from the simulation-model cells, the saturation profiles generated are a good statistical match to the wireline-log-interpreted Sw, and bulk volume of water (BVW) and fluid volumetrics agree with the geological model. RT-guided saturation-height functions proved a good method for modeling water saturation in the simulation model. The technique emphasizes the importance of oil/brine capillary pressures measured under reservoir conditions and of collecting an adequate number of Archie saturation and cementation exponents to reduce uncertainties in well-log interpretation. Introduction The heterogeneous carbonate reservoir in this study is composed of both limestone and dolomite layers frequently separated by non-reservoir anhydrite layers (Ghedan et al. 2002). Because of its heterogeneity, this reservoir, like other carbonate reservoirs, contains long saturation-transition zones of significant sizes. Transition zones are conventionally defined as that part of the reservoir between the FWL and the level at which water saturation reaches a minimum near-constant (irreducible water saturation, Swirr) high in the reservoir (Masalmeh 2000). For the purpose of this paper, however, we define transition zones as those parts of the reservoir between the FWL and the dry-oil limit (DOL), where both water and oil are mobile irrespective of the saturation level. Both water and oil are mobile in the transition zone, while only oil is mobile above the transition zone. By either definition, the oil/water transition zone contains a sizable part of this field's oil in place. Predicting the amount of recoverable oil in a transition zone through simulation depends on (among other things) the distribution of initial oil saturation as a function of depth as well as the mobility of the oil in these zones (Masalmeh 2000). Therefore, the characterization of transition zones in terms of original water and oil distribution has a potentially large effect on reservoir recoverable reserves and, in turn, reservoir economics.

Archie (1941) found an empirical equation for consolidate sandstone relating some formation parameters, porosity and water saturation. Archie equation is not easy to apply to rocks because formation parameters (a, m and n) are functions of electrical tortuosity. Electrical tortuosity is determined by pore geometry, tortuousity of the pore system and wettability which, affects oil - water distribution in the pores. Carbonate rocks with their complex pore systems and intermediate to oil wettability are difficult to describe petrophysically with a single a, m and n over a reservoir interval. Formation Resistivity Factor (FR) is highly variable. There is often no linear and direct relation between the resistivity index (IR) and formation water saturation (Sw) as the variably sized pores desaturate at different rates. These cases are labeled as non-Archie rocks. Archie is strictly valid only when the rock is strongly water wet, clay free and has a more or less uniform pore size distribution. An important issue that Archie equation misses is the fluid critical point for multi - component state in which different phases co-exist. It is not clear how at reservoir conditions oil and water coexist in the pore system. Introduction Archie (1941)(1) introduced an equation, which combines resistivity index (IR) and Formation Resistivity Factor (FR) in order to calculate water saturation. Using this equation, water saturation is commonly computed. Archie equation requires the values of cementation exponent ‘m’, saturation exponent ‘n’, and the rock consolidation factor ‘a’. He derived two empirical relationships; the formation resistivity factor (FR) which is related to porosity, and the resistivity index (IR) which is related to the water saturation. The equation was not a precise one as he mentioned and was only an approximate relationship. The conventional procedure to determine ‘m’ and ‘n’ parameters is by crossplot techniques. Plotting Formation Resistivity Factor (FR) versus core or log porosity on the log-log paper is used to find ‘a’ and ‘m’ values. The value of ‘m’ is the slope and ‘a’ is the intercept. However, in carbonate rocks most of the points are scattered and one slope cannot be driven. The same situation occurs when water saturation is plotted against resistivity index (IR) to find the value of ‘n’. In his paper, Archie mentioned that formation resistivity (Rt), as a quantitative value is not accurate as a result of the effect of borehole size, mud and its filtrate, bed thickness, wellbore deviation and connate water salinity. The logging industry has made great strides in obtaining accurate information on porosity and resistivity but has failed to narrow the uncertainty for ‘a’, ‘m’, and ‘n’ parameters. In clean, clastic quartz reservoirs, the industry has been able to apply a constant ‘a’, ‘m’ and ‘n’ with some success. Carbonates present a much more difficult situation. Their pore geometry is often complex and infinitely variable foot by foot in the reservoir. The application of constant Archie parameters in carbonates results in inaccurate and occasionally "just plain wrong" water saturation. The industry has for several decades sought a down-hole cementation exponent predictor through various mathematical and empirical models. One method determined ‘m’ in the flushed zone and then applied the results to the virgin zone(2). This method assumed the saturation exponent was equal to the cementation exponent. The effect of the mud cake, the borehole conditions and incomplete invasion complicated the results. The presumption of ‘n’ equal to ‘m’ has proved false(3). Table 1 presents a failed attempt to relate visual examinations of the core pore systems to the cementation exponent in lieu of special core analysis (SCAL) data. There is currently no reliable way to determine in-situ what the continuing varying values of this cementation exponent are. Some researcher(4) found that the values of ‘m’ and ‘n’ only represent two numbers that minimize the error function of the equation. In fact Archie(5) emphasized that rocks are heterogeneous and their characteristics cannot be expressed as a real mathematical equation. The effect of pore structure(6), rock wettability(7), hysteresis, type of oil(8), dispersion(9), pressure, temperature, and effective stress(10) on ‘m’ and ‘n’ parameters were variably addressed by other researchers.