This section is intended to introduce the reader to various aspects of art, which may be associated with embodiments of the present invention. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
Conventional hydrocarbon producing wells and other wells associated with hydrocarbon production, such as injection wells, include a wellbore extending deep into the earth and a tubing extending through the wellbore to a region in which hydrocarbons are able to enter the wellbore (or fluids from the wellbore are able to enter the formation). Such wells can be configured in various manners utilizing continually advancing technologies. For example, some wells are drilled vertically while others utilize directional drilling techniques to expand the horizontal reach of the wells drilled from a single surface pad or offshore platform. Depending on the region being drilled and the nature of the geological formations being drilled, the wellbore may include cased and/or uncased (open-hole) lengths. Within a given formation being drilled, the wellbore may pass through a number of intervals having varying properties. While a single wellbore may pass through tens or hundreds of formation regions having different properties, operators are generally interested in whether a particular region is a producing interval or a non-producing interval and the lengths of the wellbore can be characterized as such. Accordingly, for the purposes of this application the term “interval” will be used to refer to lengths of the wellbore or formation which are predominantly producing or non-producing rather than to specific lengths of the formation having homogenous formation properties. For example, a producing interval may include a number of variations along the length thereof, including segments or sub-lengths that are non-producing. FIG. 1 schematically illustrates one exemplary wellbore 10 drilled into a formation 12 and having a producing interval 14. The producing interval 14 illustrated includes reservoirs 16 spaced along the length of the wellbore 18 by non-producing or less permeable regions of the formation 12.
As is well-known, wellbores are frequently drilled to great lengths and under difficult environmental conditions. Depending on the field being drilled, the wellbores may be tens of thousands of feet long with multiple producing intervals and/or with producing intervals spanning hundreds or thousands of feet. In order to facilitate wellbore operations, such as injection, production, etc., wellbores are often divided lengthwise through the use of packers, which come in a variety of configurations. FIG. 2 schematically illustrates the wellbore 18 of FIG. 1 configured with packers 20. While packers can be used in a variety of circumstances, their operation is similar regardless of the purpose for use. Conventional packers are typically coupled to other tubing members, such as production tubing members, and run into the wellbore in a first configuration smaller than the diameter of the wellbore. Once the packer is positioned within the wellbore, the packer is set, which may be effected by mechanical actuation, by hydraulics, or by other initiation paths (such as by using a swellable packer that expands when contacted by predetermined substances that can be pumped into the wellbore or allowed to enter the wellbore from the formation). When the packer is set in the wellbore, the outer diameter of the packer is designed to be larger than the inner diameter of the wellbore causing the packer to create a positive seal against the wellbore wall (whether cased or open-hole). Packers are often rated by the pressure difference across the packer that the packer can withstand without having the seal break and the intended isolation lost.
Because packers are designed and configured to create a positive seal that can withstand pressure differences across the packer without leaking, packer design and construction is generally relatively complex and expensive. Cup-type packers are among the simplest of packer configurations because they have no moving parts and are still able to provide a positive seal against pressure differences. Regardless of the packer configuration, conventional packers present several common problems. Packers, including cup-type packers, are known to be expensive tools due to the complexity of the materials and/or the parts and assemblies. Additionally, packers present additional steps and costs during installation of the packers and during removal of the packers. It is not uncommon for the positive seal created by the packer to become a substantially permanent seal over the course of time under the conditions of a common wellbore. For example, many wellbores equipped with one or more packers must be worked over to remove the tubing and packers. Accordingly, while operators have long recognized the desirability of dividing the wellbore into multiple intervals with packers, the costs and complexities associated with packers has generally limited packer use to no more than two or three packers per wellbore.
While limiting the use of packers can simplify the initial completion and reduce the initial capital investment of a wellbore, production zones including multiple reservoirs of different characteristics and/or of great length present a variety of challenges to the well's operation, at least some of which are illustrated in FIG. 1. As introduced above, the interval 14 of FIG. 1 includes several reservoirs 16 having different properties, such as differing reservoir volumes, different reservoir pressures, and different permeabilities. The schematic well 10 of FIG. 1 represents these different properties with different sizes of the reservoirs 16. Similarly, the production rate from the different reservoirs may vary in accordance with one or more of the properties of the reservoir and/or depending on the operation of the wellbore. FIG. 1 represents the differences in flow rates by the use of directional arrows, which vary in number and/or magnitude according to the exemplary flow from the exemplary reservoirs.
The well 10 of FIG. 1 is a conventional wellbore completion with or without packers. The wellbore 18 and interval 14 illustrated in FIG. 1 may be hundreds of feet long or may be several thousand feet long. The wellbore 18 is completed with a casing 22, which is perforated to allow fluid flow between the reservoir 16 in the formation 12 and the wellbore annulus 24. Fluids entering the wellbore annulus 24 flow in the annulus according to the natural forces applied thereto. The flow path preferred by operators of well's similar to FIG. 1 is for the fluid to descend to the end of the tubular 26, such as illustrated by the descending flow arrows 28, enter the tubular 26 and flow out of the wellbore, such as illustrated by tubular flow arrow 30.
FIG. 1 illustrates at least two of the problems frequently encountered with such wellbore configurations, each of which are affected by the relationship between the tubular opening 32 and the various reservoirs 16. The placement of the tubular 26, and particularly the end of the tubular providing the tubular opening 32, within the wellbore 18 is important in optimizing the production, particularly when the production interval 14 is long and/or includes multiple reservoirs 16 having different characteristics. The placement of the tubular 26 is particularly important in gas wells, as one of the key functions of the tubing in gas wells is to provide a smaller cross-sectional flow area to raise the gas velocity, allowing co-produced water to be carried to the surface. If the gas velocity is too low, the co-produced liquids will fall downward as a result of gravitational forces forming the liquid accumulation 34 shown in FIG. 1. If the tubing is set too deep in the production interval 14, the liquid accumulation 34 (i.e., water or gas condensate) can build up at the bottom of the wellbore 18 or production interval creating a resistance to gas flow entering the tubular opening 32. This liquid accumulation 34 may be sufficient to change the flow paths in the annulus or even to block the tubular opening 32.
However, for fluids to enter the tubular opening 32 there must be an adequate pressure differential from the point at which the fluid enters the annulus to the tubular opening. The fluids entering the tubular opening 32 reduces the pressure at the bottom of the producing interval 14. Reservoirs that are spaced away from the tubular entry may not experience that pressure differential. For example, the path of least resistance for fluids entering the wellbore annulus 24 from the second reservoir 36 may experience competing pressures, one following the descending flow arrows 28 and another in the direction of the ascending flow arrows 38. The ascending flow arrow 38 may result in cross-flow where the hydrocarbons re-enter the formation 12 through a different reservoir, such as the first reservoir 40. Additionally or alternatively, a reservoir 16 along the path of the descending flow arrows 28 may have a sufficiently low pressure and sufficiently high permeability to allow fluids to re-enter the formation. The cross-flow or re-entry commonly occurs at higher elevations within the wellbore where the pressure in the formation is reduced. Depending on the relative resistance to flow within the wellbore annulus and the pressure variances within the formation, the cross-flow effect can significantly diminish or eliminate production from the interval 14. This effect is most evident when completed comingled zones extend over thousands of feet vertically. If tubing strings are set too high in the wellbore, gas flow falls below a critical sweep velocity below the end of tubing and liquids accumulate in the bottom of the well. If the tubing strings are set too low in the wellbore, the resulting hydrodynamics can result in a well that is unable to flow using well pressure alone.
The above challenges and problems of comingled reservoirs could be addressed by utilizing packers to divide the wellbore into smaller zones, such as illustrated in FIG. 2. As mentioned above, the increased cost and complexity of packers typically limits their use to no more than two or three for each wellbore. FIG. 2 illustrates the use of two packers attempting to sufficiently compartmentalize the multiple reservoirs 16. FIG. 2 also illustrates that each of the producing zones 42 (created by the packers) may be provided with a sand screen 44 or other fluid entry device to allow the produced fluids into the tubular; the sand screen 44 is one of a variety of devices known and available for such uses. The configuration in FIG. 2 can be used when two or more reservoirs are separated from each other by non-producing zones but efficiencies are attempted to be gained by comingling the reservoirs in a single wellbore. In a formation where multiple reservoirs are closely spaced or where a large reservoir has varied properties along its length, the costs, risks, and complexity limit the use of packers. However, as illustrated, the producing zones 42 still comingle two reservoirs presenting the possibility of re-entry and possible liquid drop-out. Due to the cost, complexity, and risks associated with packers, increasing the number of packers to sufficiently isolate the many reservoirs that may be present in an extended length production interval is often impractical, if not impossible.
If the problems are limited to evacuating liquids from the wellbore, various other solutions have been presented, including plunger lift technologies and other artificial lift options. Plunger lift applications have had some success in evacuating liquid accumulations in a gas well, but such applications are very sensitive to pressure variations during operation. With long producing intervals having multiple reservoirs in a drawn-down condition, a 20 psi variation in the surface or tubing pressure can suspend flow until multiple, large, man-made fracture wings can fill with gas to equalize and exceed short term pressure variations. When this occurs, mist flow stops in both the tubing and annulus of the well, thus dropping out liquids and forming heavy columns of fluid weight, that must be overcome with the well's own energy or pressure. Other artificial lift options can be used to accomplish fluid removal from the well. However, these other techniques each require induced energy or horsepower to drive the mechanism such as electrical sub pumps, rod and tubing pumps, gas lift, and jet pumps. Each of these options increases the initial cost and capital investment for the well.
Accordingly, a need still exists for cost-effective technology to optimize hydrocarbon flow to the surface in production intervals of extended length and/or production intervals including multiple reservoirs.