Although reserves estimates for known accumulations historically have used deterministic calculation procedures, the 1997 SPE/WPC definitions allow either deterministic or probabilistic procedures. Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Deterministic calculations of oil and/or gas initially in place (O/GIP) and reserves are based on best estimates of the true values of pertinent parameters, although it is recognized that there may be considerable uncertainty in such values.
The following discussion of emerging drilling technologies will be limited to those technologies now coming into the market, not those, such as rotary steerable and multilateral technologies, that have ready reference on service company Internet websites. Hence, this discussion is not comprehensive, but it is intended to include most of the high-impact technologies that are likely to be commercialized in the next 3 to 5 years with a brief look beyond. The focus on drilling technology in the United States at the beginning of the 21st century is primarily in response to the fact that its remaining oil and gas resources exist in mature provinces of significantly depleted basins or in difficult drilling environments, such as the Arctic or the deepwater Gulf of Mexico (GOM). Because the United States has led the world in petroleum demand, the environment of depletion and push for further development of these mature basins will provide lessons and technology immediately applicable to the rest of the world as the world resource base continues to mature. All nations have a stake and will benefit from this development of the next redefinition of drilling state of the art. The most basic requirement of drilling technology is that it provide safe, economic access to subsurface geologic formations to evaluate/optimize their production potential or to produce the resource existing there. The operative word is "economic." In high-cost environments, such as the deepwater offshore, technology is needed to maximize efficiency and to minimize time on location. In the onshore arena where reservoir potential is lower, the cost of accessing that potential also has to be reduced with such technologies as casing drilling. Also, with the advent of "unconventional resources" and fracture "sweet spots" as primary exploration targets, technology must provide a "smart drilling" capability to enhance finding these more difficult targets and to optimize access to the target in a manner that maximizes the production.
In 1911, 18-year-old Armais Arutunoff organized the Russian Electrical Dynamo of Arutunoff Co. in Ekaterinoslav, Russia, and invented the first electric motor that would operate in water. During World War I, Arutunoff combined his motor with a drill. It had limited use to drill horizontal holes between trenches so that explosives could be pushed through. In 1916, he redesigned a centrifugal pump to be coupled to his motor for dewatering mines and ships. In 1919, he immigrated to Berlin and changed the name of his company to REDA.
Introduction The drilling-fluid system--commonly known as the "mud system"--is the single component of the well-construction process that remains in contact with the wellbore throughout the entire drilling operation. Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions. Advances in drilling-fluid technology have made it possible to implement a cost-effective, fit-for-purpose system for each interval in the well-construction process. The active drilling-fluid system comprises a volume of fluid that is pumped with specially designed mud pumps from the surface pits, through the drillstring exiting at the bit, up the annular space in the wellbore, and back to the surface for solids removal and maintenance treatments as needed. The capacity of the surface system usually is determined by the rig size, and rig selection is determined by the well design. For example, the active drilling-fluid volume on a deepwater well might be several thousand barrels. Much of that volume is required to fill the long drilling riser that connects the rig floor to the seafloor. By contrast, a shallow well on land might only require a few hundred barrels of fluid to reach its objective. Transporting drilled cuttings to surface is the most basic function of drilling fluid. To accomplish this, the fluid should have adequate suspension properties to help ensure that cuttings and commercially added solids such as barite weighing material do not settle during static intervals. The fluid should have the correct chemical properties to help prevent or minimize the dispersion of drilled solids, so that these can be removed efficiently at the surface. Otherwise, these solids can disintegrate into ultrafine particles that can damage the producing zone and impede drilling efficiency. Under normal drilling conditions, this pressure should balance or exceed the natural formation pressure to help prevent an influx of gas or other formation fluids. As the formation pressures increase, the density of the drilling fluid is increased to help maintain a safe margin and prevent "kicks" or "blowouts"; however, if the density of the fluid becomes too heavy, the formation can break down. If drilling fluid is lost in the resultant fractures, a reduction of hydrostatic pressure occurs. This pressure reduction also can lead to an influx from a pressured formation. Therefore, maintaining the appropriate fluid density for the wellbore pressure regime is critical to safety and wellbore stability. Maintaining the optimal drilling-fluid density not only helps contain formation pressures, but also helps prevent hole collapse and shale destabilization. The wellbore should be free of obstructions and tight spots, so that the drillstring can be moved freely in and out of the hole (tripping).
A directional well can be divided into three main sections--the surface hole, overburden section, and reservoir penetration. Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved.
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins.
Figure 1.2 shows world oil production predictions. Simply put, conventional oil is running out because new basins are running out. Furthermore, exploitation costs are large in deep, remote basins (deep offshore, Antarctic fringe, Arctic basins). Only larger finds will be developed, and recovery will be less than for "easy" basins.
For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150 F typical, approximately 250 F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use. There are two primary kinds of hydraulic pumps: jet pumps and reciprocating positive-displacement pumps. Figure 1.7 shows a jet pump arrangement. For jet pumps, high-pressure power fluid is directed down the tubing to the nozzle where the pressure energy is converted to velocity head (kinetic energy).
CO2 sequestration, also known as CO2 capture and storage (CCS), uses a range of technologies and approaches that isolate, extract, and store carbon dioxide emissions from industrial and energy-related sources in order to prevent the release of it into the atmosphere. Carbon capture and storage technology involves the process of trapping and separating the CO2, transporting it to a storage location, and then storing it long-term so that it does not enter into the atmosphere. It is not a new technology and has been used by petroleum, chemical, and power industries for decades. In fact, carbon capture was first used in Texas in 1972 as a method to enhance oil recovery. CO2 emissions from the burning of fossil fuels has been on the incline since the industrial era; and with more than 85% of the world's energy coming from fossil fuels, it will remain an important energy source well into the future. As the demand for fossil fuels is growing, so is the volume of CO2 emitted each year.