Introduction to Petroleum Reservoirs and Reservoir Engineering
While the modern petroleum industry is commonly said to have started in 1859 with Col. Edwin A. Drake’s find in Titusville, Pennsylvania, recorded history indicates that the oil industry began at least 6000 years ago. The first oil products were used medicinally, as sealants, as mortar, as lubricants, and for illumination. Drake’s find represented the beginning of the modern era; it was the first recorded commercial agreement to drill for the exclusive purpose of finding petroleum. While the well he drilled was not commercially successful, it did begin the petroleum era by leading to an intense interest in the commercial production of petroleum. The petroleum era had begun, and with it came the rise of petroleum geology and reservoir engineering.
1.1 Introduction to Petroleum Reservoirs
Oil and gas accumulations occur in underground traps formed by structural and/or stratigraphic features.1 Figure 1.1 is a schematic representation of a stratigraphic trap. Fortunately, the hydrocarbon accumulations usually occur in the more porous and permeable portion of beds, which are mainly sands, sandstones, limestones, and dolomites; in the intergranular openings; or in pore spaces caused by joints, fractures, and solution activity. A reservoir is that portion of the trapped formation that contains oil and/or gas as a single hydraulically connected system. In some cases the entire trap is filled with oil or gas, and in these instances the trap and the reservoir are the same. Often the hydrocarbon reservoir is hydraulically connected to a volume of water-bearing rock called an aquifer. Many reservoirs are located in large sedimentary basins and share a common aquifer. When this occurs, the production of fluid from one reservoir will cause the pressure to decline in other reservoirs by fluid communication through the aquifer.
Figure 1.1 Schematic representation of a hydrocarbon deposit in a stratigraphic trap.
Hydrocarbon fluids are mixtures of molecules containing carbon and hydrogen. Under initial reservoir conditions, the hydrocarbon fluids are in either a single-phase or a two-phase state. A single-phase reservoir fluid may be in a liquid phase (oil) or a gas phase (natural gas). In either case, when produced to the surface, most hydrocarbon fluids will separate into gas and liquid phases. Gas produced at the surface from a fluid that is liquid in the reservoir is called dissolved gas. Therefore, a volume of reservoir oil will produce both oil and the associated dissolved gas at the surface, and both dissolved natural gas and crude oil volumes must be estimated. On the other hand, liquid produced at the surface from a fluid that is gas in the reservoir is called gas condensate because the liquid condenses from the gas phase. An older name for gas condensate is gas distillate. In this case, a volume of reservoir gas will produce both natural gas and condensate at the surface, and both gas and condensate volumes must be estimated. Where the hydrocarbon accumulation is in a two-phase state, the overlying vapor phase is called the gas cap and the underlying liquid phase is called the oil zone. There will be four types of hydrocarbon volumes to be estimated when this occurs: the free gas or associated gas, the dissolved gas, the oil in the oil zone, and the recoverable natural gas liquid (condensate) from the gas cap.
Although the hydrocarbons in place are fixed quantities, which are referred to as the resource, the reserves depend on the mechanisms by which the reservoir is produced. In the mid-1930s, the American Petroleum Institute (API) created a definition for reserves. Over the next several decades, other institutions, including the American Gas Association (AGA), the Securities and Exchange Commissions (SEC), the Society of Petroleum Engineers (SPE), the World Petroleum Congress (now Council; WPC), and the Society of Petroleum Evaluation Engineers (SPEE), have all been part of creating formal definitions of reserves and other related terms. Recently, the SPE collaborated with the WPC, the American Association of Petroleum Geologists (AAPG), and the SPEE to publish the Petroleum Resources Management System (PRMS).2 Some of the definitions used in the PRMS publication are presented in Table 1.1. The amounts of oil and gas in these definitions are calculated from available engineering and geologic data. The estimates are updated over the producing life of the reservoir as more data become available. The PRMS definitions are obviously fairly complicated and include many other factors that are not discussed in this text. For more detailed information regarding these definitions, the reader is encouraged to obtain a copy of the reference.
Table 1.1 Definitions of Petroleum Terms from the Petroleum Resources Management System2
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain nonhydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide, and sulfur. In rare cases, nonhydrocarbon content could be greater than 50%.
The term resources as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum, whether currently considered “conventional” or “unconventional.”
Further, estimated ultimate recovery (EUR) is not a resources category but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as total resource base or hydrocarbon endowment. Total recoverable or EUR may be termed basin potential. The sum of reserves, contingent resources, and prospective resources may be referred to as remaining recoverable resources. When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.