LITMIR.BIZ

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Gary et al., 2007; Speight, 2008; Siefried and Witzel, 2010; Speight, 2011a, 2014a, 2015b; Hsu and Robinson, 2017; Speight, 2017). The current crude oils are somewhat heavier insofar as they have higher proportions of non-volatile (asphaltic) constituents. In fact, by the standards of yesteryear, many of the crude oils currently in use would have been classified as heavy feedstocks, bearing in mind that they may not approach the definitions that should be used based on the method of recovery. Changes in feedstock character, such as this tendency to more viscous (heavier) crude oils, require adjustments to refinery operations to handle these heavier crude oils to reduce the amount of coke formed during processing and to balance the overall product slate (Speight, 2011a, 2014a).

      As the 21^st century matures, there will continue to be an increased demand for energy to support the needs of commerce industry and residential uses – in fact, as the 2040 to 2049 decade approaches, commercial and residential energy demand is expected to rise considerably – by approximately 30% over current energy demand. This increase is due, in part, to developing countries, where national economies are expanding and the move away from rural living to city living is increasing. In addition, the fuel of the rural population (biomass) is giving way to the fuel of the cities (transportation fuels, electric power) as the lifestyles of the populations of developing countries changes from agrarian to metropolitan. Furthermore, the increased population of the cities requires more effective public transportation systems as the rising middle class seeks private means of transportation (automobiles). As a result, fossil fuels will continue to be the predominant source of energy for at least the next 50 years.

However, there are several variables that can impact energy demand from fossil fuels. For example, coal (as a source of electrical energy) faces significant challenges from governmental policies to reduce greenhouse gas emissions, and fuels from crude oil can also face similar legislation (Speight, 2013a, 2013b, 2014a) in addition to the types of application and use, location and regional resources, cost of energy, cleanness and environmental factors, safety of generation and utilization, and socioeconomic factors, as well as global and regional politics (Speight, 2011a). More particularly, the recovery of natural gas and crude oil from tight sandstone and shale formations face challenges related to hydraulic fracturing. Briefly, hydraulic fracturing is an extractive method used by crude oil and natural gas companies to open pathways in tight (low-permeability) geologic formations so that the oil or gas trapped within can be recovered at a higher flow rate. When used in combination with horizontal drilling, hydraulic fracturing has allowed industry to access natural gas reserves previously considered uneconomical, particularly in shale formations. Although, hydraulic fracturing creates access to more natural gas supplies, but the process requires the use of large quantities of water and fracturing fluids, which are injected underground at high volumes and pressure. Oil and gas service companies design fracturing fluids to create fractures and transport sand or other granular substances to prop open the fractures. The composition of these fluids varies by formation, ranging from a simple mixture of water and sand to more complex mixtures with a multitude of chemical additives. Hydraulic fracturing has opened access to vast domestic reserves of natural gas that could provide an important stepping stone to a clean energy future. Yet questions related to the safety of hydraulic fracturing persist and the technology has been the subject of both enthusiasm and increasing environmental and health concerns in recent years, especially in relation to the possibility (some would say reality) of contaminated drinking water because of the chemicals used in the process and the disturbance of the geological formations (Speight, 2015a).

      The danger revealed by the peak energy theory is that the world is approaching an energy precipice in which (apparently) crude oil that is available one year will not be available the next year. On the other hand, the peak energy opponents take a more realistic view in that the depletion of fossil fuels will occur gradually and, and with the current trends in considering other sources of energy, the concept of the energy precipice is not logical (Speight and Islam, 2016).

      The most unrealistic variable in the peak energy scenario arises from the misuse of data that supposedly indicate that the world is approaching the energy precipice in which fossil fuel will no longer be available for use as energy sources – the date of the energy precipice is not only wildly speculative but, in many cases, totally unrealistic. Fossil fuel energy sources will undoubtedly reach a depletion point in the future when these energy sources are no longer available – but not at the moment or even in the present century. At the same time, new gas-fired generating units use highly efficient technologies and are supported by abundant gas supplies. As a result, gas is increasingly viewed as the most economical fossil fuel choice for electricity generation for the United States. Finally, a word on reserve estimation. There are a number of different methods by which crude oil and natural gas reserves can be calculated. These methods can be grouped into three general categories: (i) volumetric methods, (ii) materials balance method, and (iii) the decline curve method or production performance method.

The methods designated as volumetric methods represent attempts to determine the amount of oil-in-place by using the size of the reservoir as well as the physical properties of the reservoir rock(s) and the reservoir fluids. In the calculation process, a recovery factor is assumed, using data (and assumptions) from other crude oil and natural gas fields with similar characteristics to the field under evaluation. Based on these assumptions, the estimated amount of crude oil or natural gas in-place is multiplied by the recovery factor (derived from the other (similar) fields to arrive at an estimate of the reserves in-place. Current recovery factors for oil fields around the world typically range between 10 and 60% v/v of the crude oil and natural gas in-place while some recovery factors are in excess of 80% v/v of the crude oil and natural gas in place. The wide variance is due largely to the diversity of fluid and reservoir characteristics for different deposits. The method is most useful early in the life of the reservoir, before significant production has occurred. However, site specificity, which arise because of the differences in reservoir character (for example reservoir mineralogy, porosity, permeability) and the character of the reservoir fluids must also be given serious consideration, otherwise the estimation of the reserves in-place may be in error (by an order of magnitude above or below the real amount in-place. Such is the difficulty of estimating the reserves.

      In addition, the materials balance method for a crude oil field or natural gas field uses an equation (or derivation thereof) that relates (in the case of a crude oil reservoir with associated natural gas) the volume of crude oil, water and gas that has been produced from a reservoir, and the change in reservoir pressure, to calculate the remaining crude oil or natural gas. The calculation uses the assumption that as fluids from the reservoir are produced, there will be a change in the reservoir pressure that depends on the remaining volume of oil and gas. The method requires extensive pressure-volume-temperature analysis as well as an accurate pressure history of the field. If the pressure history of the field is not available, the calculation requires some production to occur (or to have occurred) (typically 5% to 10% v/v of ultimate recovery), unless reliable pressure history can be used from a field with similar reservoir rock characteristics as well as the characteristics of the reservoir fluids.

      The decline curve method (also known as the production performance method) uses known production data to fit a decline curve and estimate future oil production – the three most common forms of decline curves are exponential, hyperbolic, and harmonic. The decline curve analysis is a long-established tool for developing future outlook for crude oil and/or natural gas production from an individual well or from an entire oilfield. Depletion has a fundamental role in the extraction of finite resources and is one of the driving mechanisms for oil flows within a reservoir and the depletion rate can be connected to decline curves. Consequently, depletion analysis is a useful tool for analysis and forecasting crude oil and natural gas production.

      In the calculation, it is assumed that the production will decline on a reasonably smooth curve, and so allowances must be made for wells shut in and production restrictions. The curve can be expressed mathematically or plotted on a graph to estimate future production. It has the advantage of (implicitly) including all reservoir characteristics. However, the method requires a sufficient well or reservoir history to establish a statistically significant trend, ideally when production is not curtailed by regulatory or other artificial conditions.

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