In-situ combustion requires standard field equipment for oil production, but with particular attention to air compression, ignition, well design, completion, and production practices. Air-compression systems are critical to the success of any in-situ combustion field project. Past failures often can be traced to poor compressor design, faulty maintenance, or operating mistakes. See Compressors for a detailed discussion of compressors and sizing considerations. Other discussions are available in Sarathi.
Specially designed pressure/vacuum vent valves should be provided to protect the tank against overpressure or vacuum conditions. Safety should be a primary concern when selecting a storage tank vent system for a specific application. In production operations, this normally means that a safe way of handling vapors that evolve from the liquid must be designed into the system, and air must be excluded from entering the tank and mixing with hydrocarbon in the vapor space. Fixed-roof tanks should be configured to operate with a suitable gas blanketing system that maintains the tank at positive pressures under all operating conditions. Tank vent piping should include flame arrestors such as that shown in Figure 1, which protect the tank against ignition of the vent gases owing to lightning strike or a discharge of static electricity at the vent location.
The project team is now fully assembled, and it is time to start the physical project work with all members becoming involved in the engineering, purchasing, and contracting effort. These accomplishments must be measured and reported to determine the efficiency of the work and the true financial impact of the project. Real progress on a job is determined by a counting of such things as the number of documents delivered vs. the total number or the number of welds made vs. the total number required. Progress is not measured by comparing the money spent vs. the money allocated. The requirement for real progress monitoring increases as the job grows in size and complexity.
For successful floating mobile offshore drilling unit (MODU) operations, proper marine riser and mooring equipment and their management are critical. When dealing with MODU operations, there are two types of stationkeeping systems, spread mooring and DP. The vast majority of floating MODUs are equipped with spread-mooring systems. Some have a limited amount of dynamic thruster assist to their spread-mooring system. Almost all of today's semi and drillship MODUs have an eight-point mooring system consisting of anchor chain, wire rope, or a combination.
Production facilities contain, or may contain, flammable gases and vapors in normal operations. In the right concentration with air, these can form an explosive environment that is ignitable by hot surfaces, electrical arcs, and sparks. To prevent this from happening, facilities must be classified properly, so that all electrical equipment and systems are properly selected and installed. In the U.S., facilities are classified according to NEC,  and a nationally recognized testing laboratory must approve all arcing electrical equipment installed in the classified areas. Groups A through G are acetylene, hydrogen, ethylene, propane/methane, metal dust, coat dust, and grains/fibers, respectively.
Spacers and flushes are effective displacement aids, because they separate incompatible fluids such as cement and drilling fluid. A spacer is a fluid used to separate drilling fluids and cementing slurries. A spacer can be designed for use with either water-based or oil-based drilling fluids, and prepares both pipe and formation for the cementing operation. Spacers are typically densified with insoluble-solid weighting agents. For example, a spacer is a volume of fluid injected ahead of the cement, but behind the drilling fluid.
Production, refining, and distribution of petroleum products require many different types and sizes of storage tanks. Small bolted or welded tanks might be ideal for production fields while larger, welded storage tanks are used in distribution terminals and refineries throughout the world. Product operating conditions, storage capacities, and specific design issues can affect the tank selection process. Storage tanks come in all sizes and shapes. Special applications might require tanks to be rectangular, in the form of horizontal cylinders, or even spherical in shape.
Many general petroleum engineering texts have sections covering the measurement of phase behavior or pressure/volume/temperature (PVT) analysis, but few have detailed descriptions of reservoir fluid-sampling practices. This article discusses the rationale for fluid sampling, general guidance for establishing a sampling program, and some special cases that go beyond the typical fluid sampling approaches. An enormous range of reservoir fluids exists, and this means that the limited measurements of produced oil and gas properties that can be made in the field are far from adequate to provide the detailed characterization that modern petroleum engineering requires. The lack of such data could easily represent more risk than that tolerated when the decision to perform sampling and laboratory studies is taken. Examples of the financial impact of errors in fluid-property measurements are given elsewhere. Fluid samples are thus required to enable advanced physical and chemical analyses to be carried out in specialized laboratories.
A progressing cavity pump (PCP) system includes a variety of components. The basic system includes downhole PC pumps (and appropriate elastomers), along with sucker rod and production tubing strings and surface drive equipment(which must include a stuffing box). Surface-driven PCP systems require a sucker-rod string to transfer the torsional and axial loads from the surface drive system down to the bottomhole PC pump. Several different rod-string configurations are commonly used in PCP applications. These include continuous rods, standard rods with couplings (including hollow rods), standard rods with centralizers, and standard rods with bonded/molded rod guides. Within these categories are numerous additional variations resulting from differences in centralizer and rod guide design. The centralizers can be divided into two groups based on functionality. The first group consists of "coated" centralizers that have a urethane, plastic, or elastomer sleeve bonded to either a coupling or the rod body. The second group consists of "spin-thru" centralizers that have an outer stabilizer that is free to rotate on either an inner core or the rod body. With the spin-thru design, the rod string rotates inside the stabilizer, which remains stationary against the tubing.