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.
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.
In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...
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.
Waterflooding is the use of water injection to increase the production from oil reservoirs. 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. 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). In oil fields such as Wilmington (California, US) and Ekofisk (North Sea), voidage replacement also has been used to mitigate additional surface subsidence.
There are a lot of reports of formation induced damage of wells world-wide. Despite extensive literature on the subject, formation induced damage is not a standardized part of well design. One reason may be that the associated fundamental mechanism is not yet fully understood, which makes it difficult to implement in design rules. As a step towards practical design, this paper aims at improving the understanding of characteristic mechanisms of well formation interaction by analytical solutions to two simple cases. The first case considered is a vertical well in a compacting reservoir and is solved by elasticity theory. An elastic length parameter is derived, which is function of the axial stiffness of well and shear stiffness of formation. The well is then shown to follow the deformation of the compacting reservoir, with exception of a transient zone around the boundary to the overburden. The elastic length determines the size of this transient zone. Through the transient zone, the axial force reduces towards zero in the overburden. A learning is that in many cases it is sufficient to instrument the well casing or liner to measure reservoir compaction. The result also supports the finding that the high number of well damage in the deep overburden is due to another mechanism: shear deformation or slip of a weak plane crossing the well. This second case is also studied analytically yet based on plasticity theory. Input parameters to this model are shear and moment capacity of the well, shear strength of the formation and a load displacement characteristic of the formation. A general finding is that during such slip, the well is normally not able to resist, and it fails by exceeding the moment capacity at a distance from the shear plane.
The final and third case studied is ovalization of the cross section of a horizontal well due to pressure from the formation. This is a phenomenon occurring in salt and weak shale. It is a more complex interaction problem and a numerical simulation by finite element is used to solve it. A workflow is developed for an uncemented part of a horizontal well in a shale formation. Input parameters are in-situ stress, pore pressure and stiffness and strength of well and formation. Since the vertical stress is larger than the horizontal, the shear mobilization is largest to the side of the casing and shear failure starts there, initiating plastic deformation until contact and start of ovalization by reducing the lateral diameter of the well. By reduction of the mud pressure in the outer annulus, the contact area grows. Finally, the structural capacity of an ovalized casing with full formation contact is calculated. The formation is found to have some supporting effect and the resulting capacity is higher than the capacity of an ovalized casing without formation support.
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