hydrocarbon

Because UBD involves working on a live well, a hazard operational ("hazop") analysis is required for the full process. To this end, a flow chart is created that shows all the elements in the UBD process.

By analyzing cuttings, drilling mud, and drilling parameters for hydrocarbon-associated phenomena, we can develop a great deal of information and understanding concerning the physical properties of a well from the surface to final depth. A critical function in data analysis is familiarity with the different sensors used for gathering surface data. The primary types of surface data sensors are discussed in this page. Current depth-tracking sensors digitally count the amount of rotational movement as the draw-works drum turns when the drilling line moves up or down. Each count represents a fixed amount of distance traveled, which can be related directly to depth movement (increasing or decreasing depth).

Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. Depending on the reservoir fluid and the type of recovery process, the deposited solid may consist of asphaltenes, waxes, or a mixture of these materials. The deposits also can contain resins, crude oil, fines, scales, and water.[1] Models for solid deposition in the reservoir and in pipelines also are presented. Although some of the laboratory techniques for determining solid precipitation are applicable to both waxes and asphaltenes, the characteristic behaviors of these materials can be very different; therefore, wax and asphaltene topics are treated separately.

Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. Depending on the reservoir fluid and the type of recovery process, the deposited solid may consist of asphaltenes, waxes, or a mixture of these materials. The deposits also can contain resins, crude oil, fines, scales, and water.[1] Models for solid deposition in the reservoir and in pipelines also are presented. Although some of the laboratory techniques for determining solid precipitation are applicable to both waxes and asphaltenes, the characteristic behaviors of these materials can be very different; therefore, wax and asphaltene topics are treated separately.

The Petroleum Engineering Handbook has long been recognized as a valuable, comprehensive reference book that offers practical day-to-day applications for students and experienced engineering professionals alike. This new edition, the first since 1987, has been greatly expanded and consists of seven volumes. Volume I presents material that is needed by all practicing petroleum engineers. The mathematics covered in the book will help readers to better understand the literature and software they use on a daily basis; other chapters include discussions of fluid and rock properties, as well as essential aspects of the economic and regulatory environment and a brief review of the social context of fossil energy.

Perhaps the most common formation damage problem reported in the mature oil-producing regions of the world is organic deposits forming both in and around the wellbore. These deposits can occur in tubing, or in the pores of the reservoir rock. Both effectively choke the flow of hydrocarbons. Table 1 shows the gross composition of crude oils, tars, and bitumens obtained from various sources. It is evident that crude oils contain substantial proportions of saturated and aromatic hydrocarbons with relatively small percentages of resins and asphaltenes.

In order to provide the best possible strategy in dealing with hydrate formation, it is important to have a comprehensive understanding of the underlying conditions that lead to initial hydrate formation. While commercial software programs are available to examine phase equilibria, it is useful to understand the basics as a means to evaluate the computer results. The most accurate predictions of hydrate formation conditions are made using commercial phase equilibria computer programs. Of these two program types, the flash/Gibbs type is gaining pre-eminence because its predictions are available in the phase diagram interior (where many systems operate), whereas the incipient type provides the pressure/temperature (P/T) points of hydrate initiation. State-of-the-art programs are transitioning to the flash/Gibbs free-energy type.

In order to provide the best possible strategy in dealing with hydrate formation, it is important to have a comprehensive understanding of the underlying conditions that lead to initial hydrate formation. While commercial software programs are available to examine phase equilibria, it is useful to understand the basics as a means to evaluate the computer results. The most accurate predictions of hydrate formation conditions are made using commercial phase equilibria computer programs. Of these two program types, the flash/Gibbs type is gaining pre-eminence because its predictions are available in the phase diagram interior (where many systems operate), whereas the incipient type provides the pressure/temperature (P/T) points of hydrate initiation. State-of-the-art programs are transitioning to the flash/Gibbs free-energy type.

Oil and gas wells produce a mixture of hydrocarbon gas, condensate or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing.