One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

Acoustic logs provide the primary means for evaluating the mechanical integrity and quality of the cement bond.[1][2][3][4][5] Acoustic logs do not measure cement quality directly, rather, this value is inferred from the degree of acoustic coupling of the cement to the casing and to the formation. Properly run and interpreted, cement-bond logs (CBL) provide highly reliable estimates of well integrity and zone isolation. Just as filtrate invasion and formation alteration may produce changes in formation acoustic properties, and thus variation in acoustic logs over time,[6][7][8] so too, cement-bond logs may vary over time as the cement cures and its properties change. Modern acoustic cement-evaluation (bond) devices are comprised of monopole (axisymmetric) transmitters (one or more) and receivers (two or more). They operate on the principle that acoustic amplitude is rapidly attenuated in good cement bond but not in partial bond or free pipe. Conventional CBL tools provide omnidirectional measurements, while the newer radial cement-evaluation tools provide azimuthally sensitive measurements for channel evaluation. Tool response depends on the acoustic impedance of the cement, which, in turn is function of density and velocity.

The term "borehole imaging" refers to those logging and data-processing methods that are used to produce centimeter-scale images of the borehole wall and the rocks that make it up. The context is, therefore, that of open hole, but some of the tools are closely related to their cased-hole equivalents. Borehole imaging has been one of the most rapidly advancing technologies in wireline well logging. The applications range from detailed reservoir description through reservoir performance to enhanced hydrocarbon recovery. Specific applications are fracture identification, analysis of small-scale sedimentological features, evaluation of net pay in thinly bedded formations, and the identification of breakouts (irregularities in the borehole wall that are aligned with the minimum horizontal stress and appear where stresses around the wellbore exceed the compressive strength of the rock). Prensky[1] has provided an excellent review of this important subject. Downhole cameras were the first borehole-imaging devices.

Floating equipment, cementing plugs, stage tools, centralizers, and scratchers are mechanical devices commonly used in running pipe and in placing cement around casing. The simplest guide shoe is an open-end collar, with or without a molded nose. It is run on the first joint of casing and simply guides the casing past irregularities in the hole. Circulation is established down the casing and out the open end of the guide shoe or through side ports designed to create more agitation as the cement slurry is circulated up the annulus. If the casing rests on bottom or is plugged with cuttings, circulation can be achieved through the side ports. A modified guide or float shoe with side ports may aid in running the casing into a hole where obstructions are anticipated. This tool has side ports above, and a smaller opening through, the rounded nose. The smaller opening ensures that approximately 60% of the fluid is pumped through the existing side ports. These ports help wash away obstructions that may be encountered and also aid in getting the casing to bottom, if some of the cuttings have settled in the bottom of the hole. The jetting action of the side-port tool types aids in removing the cuttings and helps provide a cleaner wellbore with increased turbulence during circulation and cementing. It also aids in the uniform distribution of the slurry around the shoe. The combination guide or float shoe usually incorporates a ball or spring-loaded backpressure valve. The outside body is made of steel of the same strength as that of the casing.

Managing pipeline integrity revolves around abundance of data and information from monitoring of safe operating limits, inspections and maintenance. Those data and information may come from real-time/on-line systems, manually input ad-hoc, manually input from inspections and maintenance carried out on a particular pipeline. The oil and gas pipeline industry have sort of mature with respect to having a software/tool in aiding and assisting personnel in performing risk, fitness-for-service, repair assessments, and executing management of change for a pipeline system; and many more assessments/analyses.

Nevertheless with the invent of analytics, there is strong need to explore the new ways of working with those abundance data and information OR maximising the utilisation of the data and information for the benefit of assessing or evaluating pipeline's risk and integrity to predict 'accurately' risk and integrity so that specific and cost-effective actions and mitigations can be deployed within a stipulated period of time.

In those regard, PETRONAS is actively working with industry to establish predictive analytics for critical offshore and onshore pipelines' threats/anomalies i.e. internal corrosion and free span for offshore; and external corrosion and geotechnical hazard for onshore. This paper will dwell on the principles, concepts and methodology of predictive analytics tools for the development. It is envisaged that eventually those threats/anomalies will be analytics-managed to eliminate unwanted incidents to PETRONAS's offshore and onshore pipelines. In addition, analytics-pipeline integrity management will also likely to provide 'accurate' prediction of 'future' pipeline integrity.

In the early 2000, a consortium of Oil and Gas Companies operating the Kashagan, a super-giant oil field located in the North East of Caspian Sea, Kazakhstan area, embraced the challenge of maritime transportation in ultra-shallow waters, combined with a 5-months ice season per year and the potential risk of exposure to sour gas as a result of a blowout. The paper will present the ad hoc solution studied, tested and implemented for the first time in the naval architecture literature.

A fleet of bespoke vessels was designed, model tested in the ice tanks of internationally recognized research centers, constructed and successfully tested in real scale in the field. For such vessels, unique of their type, Classification Societies were involved through all project stages, in order to comprehend these new technical characteristics, thus issue a new set of Class Rules accordingly. A multidisciplinary activity of reverse engineering was performed, involving Environmental, Metocean, Ice Engineering and Naval Architecture teams, starting from the probabilistic forecasted of the ice thickness, its temperature and corresponding actual tensile strength. Vessels structure and propulsion power were dimensioned as a direct consequence of that, allowed to achieve minimum weight, hence minimum draft.

Such approach resulted in the construction of 2 highly specialized prototypes: the Mangystau, an ultra-shallow ice breaker for marine logistics supply chain, capable to break up to 1m level ice and navigate at 2.5m draft, as well as and the IBEEV, Ice Breaking Emergency Evacuation Vessel, intended to execute the task of EER - Emergency Evacuation Response, capable to rescue up to 340 people in ice infested waters, with the presence of an H2S toxic gas cloud. These pioneering vessels continue to support the development of the Kashagan oil field today.

The novelty of the above is mainly constituted by the nonstandard approach to the problem, exploring for a new way to apply technology rather than applying an existing one, which resulted in the realization of vessel prototypes and the publication of new set of Class Rules.

An oil/gas separator is a pressure vessel used for separating a well stream into gaseous and liquid components. They are installed either in an onshore processing station or on an offshore platform. Based on the vessel configurations, the oil/gas separators can be divided into horizontal, vertical, or spherical separators. In teams of fluids to be separated, the oil/gas separators can be grouped into gas/liquid two-phase separator or oil/gas/water three-phase separator. Based on separation function, the oil/gas separators can also classified into primary phase separator, test separator, high-pressure separator, low-pressure separator, deliquilizer, degasser, etc. To meet process requirements, the oil/gas separators are normally designed in stages, in which the first stage separator is used for priliminary phase separation, while the second and third stage separator are applied for further treatment of each individual phase (gas, oil and water). Depending on a specific application, oil/gas separators are also called deliquilizer or degasser.

Introduction Plunger lift has become a widely accepted and economical artificial-lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Figure 1.1). Plunger lift uses a free piston that travels up and down in the well's tubing string. It minimizes liquid fallback and uses the well's energy more efficiently than does slug or bubble flow. As with other artificial-lift methods, the purpose of plunger lift is to remove liquids from the wellbore so that the well can be produced at the lowest bottomhole pressures. Figure 1.1--Plunger installed in Canada. Whether in a gas well, oil well, or gas lift well, the mechanics of a plunger-lift system are the same. The plunger, a length of steel, is dropped through the tubing to the bottom of the well and allowed to travel back to the surface. It provides a piston-like interface between liquids and gas in the wellbore and prevents liquid fallback--a part of the liquid load that effectively is lost because it is left behind. Because the plunger provides a "seal" between the liquid and the gas, a well's own energy can be used to lift liquids out of the wellbore efficiently. A plunger changes the rules for liquid removal. In a well without a plunger, gas velocity must be high to remove liquids,[1] but with a plunger, gas velocity can be very low.[2][3][4] Thus, the plunger system is economical because it needs minimal equipment and uses the well's gas pressure as the energy source.[5][6][7] Used with low line pressures or compression, plunger lift can produce many types of wells to depletion.[3][5][8] In recent years, the advent of microprocessors and electronic controllers,[9][10][11][12] the studies detailing the importance of plunger seal and velocity,[13] and an increased focus on gas production have led to a much wider use and broader application of plunger lift. Microprocessors and electronic controllers have increased the reliability of plunger lift.[9][10][12] Earlier controllers were on/off timers or pressure switches that needed frequent adjustment to deal with operating-condition changes such as line pressures, plunger wear, variable production rates, and system upsets. This frustrated many operators and caused failures, and thus limited plunger use. New controllers contain computers that can sense plunger problems and make immediate adjustments. Techniques with telemetry, electronic data collection, and troubleshooting software continue to improve plunger-lift performance and ease of use.[12]

Once oil and gas are located and the well is successfully drilled and completed, the product must be transported to a facility where it can be produced/treated, stored, processed, refined, or transferred for eventual sale. Figure 1.1 is a simplified diagram that illustrates the typical, basic "wellhead to sales" concept. The typical system begins at the well flow-control device on the producing "wing(s)" of the wellhead tree and includes the well "flowline," production/treating/storage equipment, custody-transfer measurement equipment, and the gathering or sales pipeline. Information and detailed discussions concerning petroleum production, treating, storage, and measurement equipment are located in various chapters of this Handbook. The piping and pipeline systems typically associated with producing wells include, but are not limited to, the well flowline, interconnecting equipment piping within the production "battery," the gathering or sales pipeline, and the transmission pipeline. A brief description of the associated piping/pipeline systems is given next. The well flowline, or simply flowline, is the first "pipeline" system connected to the wellhead. The flowline carries total produced fluids (e.g., oil, gas, and production water) from the well to the first piece of production equipment--typically a production separator. The flowline may carry the well-production fluids to a common production battery, a gathering pipeline system, process facility, or other. Interconnecting piping includes the piping between the various pieces of production/treating equipment such as production separators, line heaters, oil heaters, pump units, storage tanks, and gas dehydrators. The piping systems may also include headers, fuel systems, other utility piping, and pressure-relief/flare systems. The pipe that delivers the well production to some intermediate or terminal location is the gathering or sales pipeline. The gathering pipeline literally "gathers" the production from producing wells and conveys the production to a collection system, a processing facility, custody-transfer (sales) point, or other. The transmission pipeline is a "cross-country" pipeline that is specifically designed to transport petroleum products long distances.

At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1.1). The concepts range from fixed platforms to subsea compliant and floating systems. This chapter presents an overview of offshore facility concepts including subsea systems and flow-assurance concepts.