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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.
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).
Before computer modeling was common, the 3D aspects of a waterflood evaluation were simplified so that the technical problem could be treated as either a 2D-areal problem or a 2D-vertical problem. To simplify 3D to 2D areal, either the reservoir must be assumed to be vertically a thin and homogeneous rock interval (hence having no gravity considerations) or one of the published techniques to handle the vertical heterogeneity and expected gravity effects within the context of a 2D-areal calculation must be used. The primary areal considerations for a waterflood involve the choices of the pattern style (see Figure 1) and the well spacing. Maximizing the ultimate oil recovery and economic return from waterflooding requires making many pattern- and spacing-related decisions when secondary recovery is evaluated. This has been particularly true for onshore oil fields in the US in which a significant number of wells were drilled for primary production.
Petroleum engineering is and will be needed for decades to come to provide the required energy for the world and help alleviate the challenges of climate change. Of course, petroleum engineering will evolve into energy transition as it has been changing since its inception in modern history with the Drake well in 1895, located in Pennsylvania. At the same time, we will continue to use the current practices in our daily operations. Petroleum engineering practices can and will also be used in solving some of the climate change issues. This information is described in detail in SPE 200771 (Kamal 2020).
This article describes the chemical make-up and application of the types of gels most commonly used in conformance improvement. It also discusses the ways in which these gels can be classified. Oilfield conformance improvement gels come in a wide range of forms and chemistries. Table 1 provides an overview of various conformance improvement gels. CC/AP gels have an exceptionally robust gel chemistry and are highly insensitive to oilfield and reservoir interferences and environments.
Produced water typically enters the water-treatment system from either a two or three phase separator, a free water knockout, a gun barrel, a heater treater, or other primary separation unit process. It probably includes small amounts of free or dissolved hydrocarbons and solids that must be removed before the water can be re-used, injected or discharged. The level of removal (particularly for hydrocarbons) and disposal options are typically specified by state, province, or national regulations. This article discusses techniques for the removal of free and dissolved hydrocarbons. See Removing solids from water for information on solids removal. Produced water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place. Stokes' law, shown in Eq. 1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase. Several immediate conclusions can be drawn from this equation.
A leading cause of unsuccessful acid treatment is failure to contact all the damage with the acid. Fluids pumped into a formation preferentially take the path of least resistance. This makes the placement and coverage of the acid an important component of the treatment design. In a typical treatment, most acid enters the formation through the least damaged perforation tunnels, as the schematic in Figure 1 shows. When this happens, it can be readily concluded that acidizing does not work well and is expensive.
Real reservoir fluids contain many more than two, three, or four components; therefore, phase-composition data can no longer be represented with two, three or four coordinates. Instead, phase diagrams that give more limited information are used. Figure 1 shows a pressure-temperature phase diagram for a multicomponent mixture; it gives the region of temperatures and pressures at which the mixture forms two phases. The analog of Figure 1 for a binary system can be obtained by taking a slice at constant mole fraction of Component 1 through the diagram in Figure 1. Also given are contours of liquid-volume fractions, which indicate the fraction of total sample volume occupied by the liquid phase; however, Figure 1 does not give any compositional information.
Phase behavior plays an important role in a variety of enhanced oil recovery (EOR) processes. Such processes are designed to overcome, in one way or another, the capillary forces that act to trap oil during waterflooding. Interpretation of phase diagrams is particularly important in the design of surfactant/polymer processes and gas-injection processes. In surfactant/polymer displacement processes, the effects of capillary forces are reduced by injection of surfactant solutions that contain molecules with oil- and water-soluble portions. Such molecules migrate to the oil/water interface and reduce the interfacial tension, thereby reducing the magnitude of the capillary forces that resist movement of trapped oil. Figure 1 shows phase diagrams typical of those used to describe the behavior of surfactant systems.