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(i.e., that abiogenic replenishment is negligible) and future world oil production must inevitably reach a peak and then decline as these reserves are exhausted (Hubbert, 1956, 1962). There is no doubt that crude oil and natural gas are being consumed at a steady rate but whether or not the Hubbert peak oil theory will affect the consumption of crude oil is another issue. It is a theory that is based on reserve estimates and reserve consumption. No one will disagree that hydrocarbon resources (in the form of crude oil and natural gas) are finite resources and will run out at some future point in time but the proponents of an energy precipice must recognize that this will not be the case, at least not for now (Speight and Islam, 2016). The issue is the timing of this event – whether it is tomorrow, next week, next month, next year, or in 50 or more years remains to be seen. Current evidence (Speight, 2011a, 2011c; BP, 2019) favors a lifetime of more than 50 years for the current reserves of crude oil and natural gas, perhaps longer if hydraulic fracturing continues to play a dominant role in crude oil and natural gas production (Speight, 2015a). Thus, controversy surrounds the theory – not so much from the theory itself which is quite realistic but from the way in which the theory is used by varying collections of alarmists – since predictions for the time of the global peak is dependent on the past production and discovery data used in the calculation.

      To date, crude oil production on a worldwide basis has come almost exclusively from what are considered to be conventional crude oil reservoirs from which crude oil can be produced using tried-and-true recovery technologies compared with non-conventional sources that require more complex or more expensive technologies to extract – examples of such resources are tar sand bitumen, liquids from coal, liquids from biomass, and liquids from oil shale (Lee, 1990; Scouten, 1990; Lee, 1991; Speight, 2008, 2011b, 2012, 2013a, 2014b, 2016).

Generally, crude oil from tight formations (sometimes referred to as unconventional tight oil resources) are found at considerable depths in sedimentary rock formations that are characterized by very low permeability. While some of the tight oil plays produce oil directly from shales, tight oil resources are also produced from low-permeability siltstone formations, sandstone formations, and carbonate formations that occur in close association with a shale source rock.

      Oil from tight shale formation is characterized by a low content of high-boiling (resid) constituents, low-sulfur content, and a significant molecular weight distribution of the paraffinic wax content (Speight, 2014a, 2015b). Finally, the properties of crude oils from tight formations are highly variable. Density and other properties can show wide variation, even within the same field. The Bakken crude is light and sweet with an API of 42° and a sulfur content of 0.19% w/w. Similarly, Eagle Ford is a light sweet feed, with a sulfur content of approximately 0.1% w/w and with published API gravity between 40° API and 62° API.

      There is also the need for a refinery to be configured to accommodate opportunity crude oils and/or high acid crude oils which, for many purposes are often included with heavy feedstocks (Speight, 2014a, 2014b; Yeung, 2014). Opportunity crude oils are either new crude oils with unknown or poorly understood properties relating to processing issues or are existing crude oils with well-known properties and processing concerns (Ohmes, 2014). Opportunity crude oils are often, but not always, heavy crude oils but in either case are more difficult to process due to high levels of solids (and other contaminants) produced with the oil, high levels of acidity, and high viscosity. These crude oils may also be incompatible with other oils in the refinery feedstock blend and cause excessive equipment fouling when processed either in a blend or separately (Speight, 2015b). There is also the need for a refinery to be configured to accommodate opportunity crude oils and/or high acid crude oils which, for many purposes are often included with heavy feedstocks.

      Opportunity crude oils, while offering initial pricing advantages, may have composition problems which can cause severe problems at the refinery, harming infrastructure, yield, and profitability. Before refining, there is the need for comprehensive evaluations of opportunity crudes, giving the potential buyer and seller the needed data to make informed decisions regarding fair pricing and the suitability of a particular opportunity crude oil for a refinery. This will assist the refiner to manage the ever-changing crude oil quality input to a refinery – including quality and quantity requirements and situations, crude oil variations, contractual specifications, and risks associated with such opportunity crudes.

      High-acid crude oils are crude oils that contain considerable proportions of naphthenic acids which, as commonly used in the crude oil industry, refers collectively to all of the organic acids present in the crude oil (Shalaby, 2005; Speight, 2014b). In many instances, the high-acid crude oils are actually the heavier crude oils (Speight, 2014a, 2014b). The total acid matrix is therefore complex and it is unlikely that a simple titration, such as the traditional methods for measurement of the total acid number, can give meaningful results to use in predictions of problems. An alternative way of defining the relative organic acid fraction of crude oils is therefore a real need in the oil industry, both upstream and downstream.

      High acid crude oils cause corrosion in the refinery – corrosion is predominant at temperatures in excess of 180^oC (355^oF) (Kane and Cayard, 2002; Ghoshal and Sainik, 2013; Speight, 2014c) – and occurs particularly in the atmospheric distillation unit (the first point of entry of the high-acid crude oil) and also in the vacuum distillation units. In addition, overhead corrosion is caused by the mineral salts, magnesium, calcium and sodium chloride which are hydrolyzed to produce volatile hydrochloric acid, causing a highly corrosive condition in the overhead exchangers. Therefore, these salts present a significant contamination in opportunity crude oils. Other contaminants in opportunity crude oils which are shown to accelerate the hydrolysis reactions are inorganic clay minerals and organic acids.

Foamy oil is oil-continuous foam that contains dispersed gas bubbles produced at the well head from heavy crude oil reservoirs under solution gas drive (Maini, 1999; Sheng et al., 1999; Maini, 2001). The nature of the gas dispersions in oil distinguishes foamy oil behavior from conventional heavy crude oil. The gas that comes out of solution in the reservoir does not coalesce into large gas bubbles nor into a continuous flowing gas phase. Instead it remains as small bubbles entrained in the crude oil, keeping the effective oil viscosity low while providing expansive energy that helps drive the oil toward the producing. Foamy oil accounts for unusually high production in heavy crude oil reservoirs under solutiongas drive.

      During primary production of heavy crude oil from solution gas drive reservoirs, the oil is pushed into the production wells by energy supplied by the dissolved gas. As fluid is withdrawn from the production wells, the pressure in the reservoir declines and the gas that was dissolved in the oil at high pressure starts to come out of solution (foamy oil). As pressure declines further with continued removal of fluids from the production wells, more gas is released from solution and the gas already released expands in volume. The expanding gas, which at this point is in the form of isolated bubbles, pushes the oil out of the pores and provides energy for the flow of oil into the production well. This process is very efficient until the isolated gas bubbles link up and the gas itself starts flowing into the production well. Once the gas flow starts, the oil has to compete with the gas for available flow energy. Thus, in some heavy crude oil reservoirs, due to the properties of the oil and the sand and also due to the production methods, the released gas forms foam with the oil and remains subdivided in the form of dispersed bubbles much longer.

      Heavy crude oil is a type of crude oil that is different from conventional crude oil insofar as it is much more difficult to recover from the subsurface reservoir. Heavy crude oil, particularly heavy crude oil formed by biodegradation of organic deposits, is found in shallow reservoirs, formed by unconsolidated sands. This characteristic, which causes difficulties during well drilling and completion operations, may become a production advantage due to higher permeability. In simple terms, heavy crude oil is a type of crude oil which is very viscous and does not flow easily. The common characteristic properties (relative to conventional crude oil) are high specific gravity, low hydrogen to carbon ratios, high carbon residues, and high contents of asphaltenes, heavy metal, sulfur and nitrogen. Specialized refining processes are required to produce more useful fractions, such as: naphtha, kerosene, and gas oil.

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