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A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.
The electrical submersible pump, typically called an ESP, is an efficient and reliable artificial-lift method for lifting moderate to high volumes of fluids from wellbores. These volumes range from a low of 150 B/D to as much as 150,000 B/D (24 to 24,600 m3/d). Variable-speed controllers can extend this range significantly, both on the high and low side. The ESP's main components include: The components are normally tubing hung from the wellhead with the pump on top and the motor attached below. There are special applications in which this configuration is inverted.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
Well-to-well tracer tests contribute significantly to the reservoir description, which is essential in determining the best choice of production strategy. Direct dynamic information from a reservoir may be obtained, in principle, from three sources: production history, pressure testing, and tracer testing. The value and importance of tracer tests are broadly recognized. Tracer testing has become a mature technology, and improved knowledge about tracer behavior in the reservoir, improved tracer analysis, and reduction of pitfalls have made tracer tests reliable. Many tracer compounds exist; however, the number of suitable compounds for well-to-well tracers is reduced considerably because of the harsh environment that exists in many reservoirs and the long testing period. Radioactive tracers with a half-life of less than one year are mentioned only briefly in this chapter because of their limited applicability in long-term tests. Tracers may be roughly classified as passive or active. In principle, a passive tracer blindly follows the fluid phase in which it is injected. Interpretation of tracer-production curves must account for this. The results from the application of active tracers may give information about fluid saturation and rock surface properties. This information is especially important when enhanced-oil-recovery techniques that use expensive fluids such as surfactants, micellar fluids, or polymers are considered. In the last 50 years, many tracer studies have been reported and even more have been carried out without being published in the open literature. Wagner pointed out six areas in which tracers could be used as a tool to improve the reservoir description. Many companies apply tracer on a routine basis. The reservoir engineer's problem generally is a lack of adequate information about fluid flow in the reservoir. The information obtained from tracer tests is unique, and tracer tests are a relatively cheap method to obtain this information. The information is an addendum to the general field production history and is used to reduce uncertainties in the reservoir model. Tracer tests provide tracer-response curves that may be evaluated further to obtain relevant additional information. Primarily, the information gained from tracer testing is obtained simply by observing breakthrough and interwell communication.
Tracers are used in geothermal reservoir engineering to determine the connectivity between injection and production wells. Because injected fluids are much cooler than in-situ fluids, knowledge of injectate flow paths helps mitigate premature thermal breakthrough. As in other applications of tracer testing, the goal of the tracer test is to estimate sweep efficiency of a given injection pattern. Because geothermal systems tend to be open, tracer tests can also be used to estimate the extent of recharge/discharge or total pore volume. Currently, however, the primary use of geothermal tracers is to estimate the degree of connectivity between injectors and producers.
This chapter concerns the use of water injection to increase the production from oil reservoirs, and the technologies that have been developed over the past 50 years to evaluate, design, operate, and monitor such projects. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir's natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil. The principal reason for waterflooding an oil reservoir is to increase the oil-production rate and, ultimately, the oil recovery. This is accomplished by "voidage replacement"--injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. The water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics).
There are many opportunities to modify and improve the waterflood as data are acquired and analyzed. Applying material balance concepts means that initially there is "reservoir fill-up" if the reservoir previously had some years of primary production. During this period, the reservoir is repressured to its original reservoir pressure because the injected-water volumes will be substantially greater than the produced-fluid volumes. Thereafter, the waterflood will be operated as a voidage-replacement process. The earliest waterflood monitoring techniques were developed soon after the first field applications of waterflooding; they were based on simple plots, maps, and calculations.
The Long Beach Unit (LBU) area of the Wilmington oil field (southern California, US) is mainly under the Long Beach harbor and contains more than 3 billion bbl of original oil in place (OOIP). This oil field is a large anticline that is crosscut by several faults with displacements of 50 to 450 ft. It consists of seven zones between 2,500 and 7,000 ft true vertical depth subsea (TVDSS), the upper six of which are turbidite deposits of unconsolidated to poorly consolidated sandstone (1 to 1,000 md and 20 to 30% BV porosity) interbedded with shales. The gross thickness of 3,300 ft contains 900 ft of sandstone. From its discovery in 1936 to the 1950s, most of the onshore portion of this oil field (the non-LBU area of the Wilmington oil field) was produced using the pressure-depletion oil-recovery mechanism.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.