However, other technologies can often be employed to investigate properties of the earth that correlate better with the properties of interest. If the images from these technologies can be provided at appropriate resolution, and if the knowledge required for interpretation and wise application of these technologies is available within the industry, they should be used. For example, electrical methods are extremely sensitive to variations in saturation, yet surface-based methods provide very poor resolution. Reservoir compaction can be directly observed from surface deformation, and pore-volume or gas-saturation changes can be detected from changes in the gravitational field. Dramatic examples of surface deformation induced by reservoir compaction have been provided by releveling studies (involving repeated high-accuracy surveying) and satellite-based interferometry.
Geological effects can impact the design and successful completion of oil, gas, and geothermal wells. Understanding the stresses and pore pressures within the subsurface are important to development of a geomechanical model that can guide well design as part of an integrated process to minimize cost and maximize safety. Forces in the Earth are quantified by means of a stress tensor, in which the individual components are tractions (with dimensions of force per unit area) acting perpendicular or parallel to three planes that are in turn orthogonal to each other. The normals to the three orthogonal planes define a Cartesian coordinate system (x1, x2, and x3). The stress tensor has nine components, each of which has an orientation and a magnitude (see Figure 1.a).
While always an implicit goal in steamflood processes, overall process heat management became a topic in the literature in the mid-1980s. The growth of the discipline has closely followed the development of the personal computer and computer applications. Heat management consists of data gathering, data monitoring and adjustments to the process as discussed in this page. Figure 1 is a graphical representation of the major components of a heat balance that must be performed to properly manage a steamflood process. Ziegler et al. published a very good summary of a method of implementing the principle.
For any steamflood process, no matter how efficient, the major cost is always that of generating the process steam. Whether the product of oilfield steam generators, industrial boilers, or electrical/steam cogeneration plants, steam must be delivered through a network of pipes and through pipes down a wellbore to the oil bearing formation. It is imperative that the unavoidable heat losses in this distribution system be minimized with some type of insulating system. The rate of heat loss in surface lines is usually calculated at steady-state conditions because transients disappear quickly in surface pipes. The terms in Eq. 2 are the coefficients of heat transfer for each of the layers of an insulated pipe as shown in Figure 1.
Designing a successful steamflooding project requires good candidate selection and an excellent understanding of the mechanisms by which recovery is enhanced. Screening criteria for identification of steamflood candidates have been published for many years. Table 1 shows the screening guides from five different sources. Table 1 - Steamflood project screening criteria It is obvious from Table 1 that there is a finite envelope of properties that define successful candidates. However, within that envelope there is a relatively wide spread of values for the indicators.
In-situ combustion is the oldest thermal recovery technique. It has been used for more than nine decades with many economically successful projects. In-situ combustion is regarded as a high-risk process by many, primarily because of the many failures of early field tests. Most of those failures came from the application of a good process to the wrong reservoirs or the poorest prospects. The objective of this page is to describe the potential of in-situ combustion as an economically viable oil recovery technique for a variety of reservoirs.
Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Reserves calculated using such procedures are classified subjectively on the basis of professional judgments of the uncertainty in each reserve estimate and/or of pertinent regulatory and/or corporate guidelines. Probabilistic procedures recognize that uncertainties in input data and equations to calculate reserves may be significant.
Figure 1.1--Plunger installed in Canada. This cycle can occur over hours or days in wells that have stabilized flow rates below the critical unloading rate. Such is the behavior of many wells that are temporarily shut in or blown to atmosphere to unload liquids. Plungers currently are being used in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to 1,500 psia, and liquid rates of 1 to 100 B/D. These are common ranges of application, but not necessarily limits of operation. The most common plunger-lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high-GLR oil wells, in conjunction with intermittent gas lift operations, and to control paraffin and hydrates. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection. For this use, when plunger lift is installed, paraffin, hydrates, and salt should be removed so that the plunger will travel freely up and down the tubing. Given initially clean tubing, a plunger excels at preventing formation of such deposits because of the scraping action of the plunger against the walls of the tubing, along with slugs of warm reservoir fluids. Wellbore configurations for plunger lift include wells with an open annulus (most desirable), wells with packers, slimhole wells (2.875-in. Also, plunger lift is used in conjunction with intermittent gas lift, external gas supplies/injection, wellhead compression, vent options to tanks or low-pressure systems, some sand production, tubing/casing flow control (three-valve controllers), and carbon dioxide (CO2) floods. Most commonly, plunger lift is applied in a gas or oil well with sufficient pressure and GLR to operate the system without additional supply gas. It is desirable to have tubing with no packer in the well. The annular space provides a storage area (volume chamber) for the gas under pressure and allows this gas to work freely on the plunger and liquid slug. Gas can flow from the casing to the tubing and provide lift with little restriction, and inflow from the reservoir is not relied on as the plunger moves up the hole.
Plunger lift systems can be evaluated using rules of thumb in conjunction with historic well production, or with a mathematical plunger model. Because plunger lift systems typically are inexpensive and easy to install and test, most are evaluated by rules of thumb. Plunger lift operation requires available gas to provide the lifting force, in sufficient quantity per barrel of liquid for a given well depth. The minimum GLR requirement is approximately 400 scf/bbl per 1,000 ft of well depth and is based on the energy stored in a compressed volume of 400 scf of gas expanding under the hydrostatic head of 1 bbl of liquid. One drawback to this rule of thumb is that it does not consider line pressures.