WO2009148723A1 - Inter and intra-reservoir flow controls - Google Patents

Inter and intra-reservoir flow controls Download PDF

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Publication number
WO2009148723A1
WO2009148723A1 PCT/US2009/041970 US2009041970W WO2009148723A1 WO 2009148723 A1 WO2009148723 A1 WO 2009148723A1 US 2009041970 W US2009041970 W US 2009041970W WO 2009148723 A1 WO2009148723 A1 WO 2009148723A1
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conduit
well
subterranean
formation
surface
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PCT/US2009/041970
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French (fr)
Inventor
Scott R. Clingman
Bruce A. Dale
Ted A. Long
Claudia M. Zettner
James S. Brown
Nissan Shoykhet
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Exxonmobil Upstream Research Company
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/20Displacing by water
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/30Specific pattern of wells, e.g. optimizing the spacing of wells

Abstract

Systems and methods for altering fluid flow in a subterranean formation include a surface-connected well extending from a surface into a subterranean formation and at least one subterranean conduit at least substantially isolated from the surface- connected well. The subterranean conduit is adapted to control or adapt the flow fields within a subterranean formation by altering the resistance to flow through particular regions of the formation, thereby causing the fluids to flow in a more desirable pattern through the formation. The reduced resistance is accomplished by changing the permeability of a particular region of the formation through the use of a subterranean conduit having a higher permeability than the permeability of the surrounding formation.

Description

INTER- AND INTRA-RESERVOIR FLOW CONTROLS CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U. S. Provisional Application Nos.

61/130,906, filed 04 June 2008, and 61/166,1 14, filed 02 April 2009, which are incorporated herein by reference in their entirety for all purposes. FIELD

[0002] The present disclosure relates generally to systems and methods for producing hydrocarbons. More particularly, the present disclosure relates to systems and methods for altering subterranean flow fields in formations including at least one production well.

BACKGROUND

[0003] 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.

[0004] Subterranean fluids, like fluids above-ground, tend to flow from regions of high pressure to regions of low pressure, provided there is some form of fluid communication between the two regions. When a wellbore is drilled into a subterranean formation, the wellbore provides a potential low pressure region in the formation to which fluids may flow naturally. This potential low pressure region is controlled during the drilling and production phases to regulate what formation fluids enter the wellbore, from where in the formation the fluids originate, and at what rate the fluids are allowed to enter the wellbore. One area of concern in the production of hydrocarbons is maximizing the total recovery of hydrocarbons from a given reservoir or collection of reservoirs in a formation.

[0005] The total recovery of hydrocarbons in a reservoir or formation is often referred to as a percentage of Original Oil In Place (OOIP), which is a ratio of oil or hydrocarbon recovered over the estimated total oil or hydrocarbon in the particular reservoir or formation being evaluated, and which is often referred to as "recovery factor". Depending on the conditions of the block in which a particular well is being operated, the total recovery may be a measure relative to a particular reservoir or relative to a formation, which may include one or more reservoirs such as may be the case when the formation includes fault lines or other geologic features breaking the formation into effectively discrete reservoirs. [0006] As suggested above, the presence of a wellbore providing a low pressure region in a formation may not be sufficient to recover all of the hydrocarbons from the formation if there is not adequate fluid communication between the hydrocarbon in its original location and the low pressure region of the wellbore. The degree of fluid communication between the hydrocarbon's source position and the wellbore depends on a variety of factors, including the permeability of the formation between the wellbore and the source position and the distance between the two. Several technologies have been developed to improve the total recovery through a wellbore. Exemplary technologies include various initial stimulation treatments and workover treatments, such as fracturing treatments and matrix acidizing treatments, which can be generally characterized as changing the properties of the formation by causing agents to move from the production well into the formation adjacent the wellbore (proppants, acids, etc.). The paradigm for these technologies is an effort to improve the permeability of the formation adjacent the wellbore. However, the effectiveness of these technologies is limited by the need to emanate from the production well. The relatively limited reach of these technologies and the impact on production during the workover limits the desirability of a workover treatment. [0007] Total recovery can also be increased by injecting fluids into the formation near a production well. The injected fluids are typically introduced into the formation through an injection well drilled at a distance from the production well. The injection wells are drilled or positioned so that fluids injected therethrough will drive or push the hydrocarbons from the source position towards the production well. Such operations are often referred to as flooding and may include the injection of a variety of fluids, including water, steam, carbon dioxide, etc. Injection operations to increase hydrocarbon recovery through a production well have been used for many years.

[0008] In conventional flooding operations, substantial volumes of hydrocarbons can be bypassed entirely for a variety of reasons, including the natural permeability variations within the formation. As introduced above, the fluids in a subterranean formation, including injected fluids, will follow the path of least resistance, which is a function of distance and permeability among other things. Accordingly, hydrocarbons disposed in portions or pockets of a reservoir having low permeability relative to other portions of the reservoir are often bypassed. Similarly, hydrocarbons disposed in portions of the reservoir outside of the path of least resistance will generally be bypassed. [0009] Fig. 1 provides an illustrative streamline pattern for a formation 100 during a conventional 5-spot water injection flooding operation. As illustrated, four injection wells 1 10 are disposed around a central production well 112. Water is injected through the injection wells 110 and flows through the subterranean formation to the production well 112. For the purposes of the illustrative representation of Fig. 1 , a hypothetical formation having uniform or homogeneous permeability is shown. The contours 1 14, 1 16, 1 18, 120 illustrated in Fig. 1 correspond to streamlines through the formation wherein a substantially similar flowrate occurs between each pair of contours (i.e. approximately 20% of the injected fluids flow through each pair of streamlines). The majority (generally greater than 80-90%) of the injected fluids flow within contours 1 14, 1 16, 1 18, and 120. This results in very little fluid flow outside of contour 120 in the region 122. Accordingly, as discussed above, there are large areas of the formation in which the flooding operations simply do not affect the hydrocarbons as desired. In the event that substantial hydrocarbons are deposited in these regions, the conventional 5-spot flooding pattern would be inefficient. Conventional approaches would suggest the addition of still further infill injection wells to flood the bypassed areas. Accordingly, it is common to hear of 9-spot and even 13-spot operations. For purposes of convenience, the variety of configurations for these injection flooding patterns may be referred to herein as X-spot flooding patterns in recognition that the number of injection wells can be varied.

[0010] Fig. 2 illustrates a flood pattern similar to the pattern of Fig. 1 illustrating the representative streamlines of an injection operation using a conventional 5-spot pattern. However, Fig. 2 schematically illustrates the streamlines for a heterogeneous formation, which refers to formations having varied permeability. As can be seen in comparing Fig. 1 and Fig. 2, the regions to the left and right of the production well (i.e., the center of the graphic) in Fig. 2 have a much larger area outside of contour 120. In the representative formation of Fig. 2, the regions of the formation to the right and left of the production well have a lower permeability than the regions of the formation above and below the production well. Accordingly, the injected fluid fails to sweep or flood an even larger region of the formation in Fig. 2 than in Fig. 1. As many hydrocarbon-containing formations are in fact heterogeneous, it is not uncommon for flooding treatments to bypass large quantities of hydrocarbons stored in these less permeable regions. The greater the heterogeneity, the more infill wells are generally required, which significantly increases the costs and the delays associated with recovering the remaining hydrocarbons.

[0011] The foregoing discussion of Figs. 1 and 2 illustrate common problems inherent in conventional flooding operations. As is well known, the illustrated flooding patterns are repeated throughout a field as believed to be appropriate or helpful. The repetition of the flood pattern creates a grid-like pattern on the field, with each production well having a plurality of injection wells around it. While a single X-spot pattern may leave some regions un-flooded, the repetition of this pattern across an entire field can leave large portions of the field unaffected by the flooding operations.

[0012] It is also common for hydrocarbon accumulations to be deposited in distinct fault blocks within a given formation. Fault blocks are formed in formations due to various geological stresses over long periods of time. While the blocks are adjacent to each other, the blocks are often effectively sealed from each other so that little or no fluid flow occurs across the block boundaries. Some instances of fault blocks are believed to allow some flow across the block boundaries, but the flow is acknowledged to be substantially limited. In a formation having multiple fault blocks, the flooding treatments can be highly inefficient unless the production well and the injection well are in the same fault block.

[0013] Directional drilling has become more common in recent years, providing directional or horizontal wells of various configurations. Horizontal and directional wells have some advantages over vertical wells due to the extended horizontal reach of the well. For example, the horizontal or directional portion of the well can increase the contact area with a pay zone for a reservoir, can intersect multiple reservoirs and/or fault blocks, and can extend through regions of varying permeability. While horizontal wells have these advantages, they are also recognized as being somewhat more expensive than complex than simple vertical wells. Additionally, the physics of the flow in highly deviated wells is less well understood than in vertical wells, which increases the challenge of modeling the fluid flows and designing systems to maximize the production efficiency. Despite advances in directional drilling and completions technology, directional drilling has not yet overcome these disadvantages.

[0014] In the event that directional wells were in fact comparable in cost and complexity to simple vertical wells, the use of directional production or injection wells to address the total recovery problems discussed above would still be impractical in many situations. For example, the sheer number of directional wells that would need to be operated to address these total recovery problems may be impractical, such as when multiple fault blocks are distributed in a formation in a manner such that a single directional well could not intersect all of them. Moreover, it is not uncommon for surface conditions to limit the number of wellheads that can be maintained at the surface, such as on offshore platforms or in environmentally sensitive or harsh regions. [0015] Figs. 1 and 2 illustrate a schematic two-dimensional perspective of conventional 5-spot flooding operations using vertical wells in a formation having homogeneous or substantially homogeneous permeability at the depth illustrated. Fig. 3 illustrates that the problems of heterogeneous permeability may exist in three dimensions. Fig. 3 schematically illustrates a side-view of a formation 100 having two horizontal wells: an injection well 110 and a production well 1 12. The formation is illustrated as having a permeability difference in adjacent zones, identified by the dashed line 132. In the illustrated formation, there is a low permeability zone 134 adjacent the production well and the injection well and a high permeability zone 136 disposed above the low permeability zone. In some implementations, the distance between the wells may be far greater than the distance between the injection well and the high permeability zone 136. Accordingly, and as illustrated by the schematic flow streamlines 114, 116, 118, and 120, the vast majority of the flow from the injection well 1 10 goes through the high permeability zone 136 en route to the production well 112 rather than through the low permeability zone 134. In such situations, the low permeability zone will be bypassed and the hydrocarbons therein will not be swept to the production well.

[0016] It should be understood that formations, reservoirs, zones, and wells are found in all manners of configurations and orientations. The relatively simple vertical (Figs. 1 and 2) and horizontal wells (Fig. 3) and corresponding permeability challenges discussed here are exemplary only of the variety of orientations and configurations that may be addressed by the present technology. For example, the three-dimensional representation of Fig. 3 may be representative of a vertical well segment, a directional well segment, or any other portion of a well.

[0017] In light of the various challenges faced when attempting to produce a reservoir and maximize the recovery percentage, multi-lateral wells have been developed to increase the contact of the well with the reservoir. The multi-lateral wells include multiple directional or horizontal well lengths extending from a common vertical well. While multi- laterals reduce costs by reducing the number of times a well is drilled to depth and by reducing the number of wellheads at the surface, multi-laterals are operationally complex and risky compared to vertical wells. As is well known, every foot of drilled wellbore includes inherent risks. In some drilling operations, a failure in the last foot of drilling can render the prior thousands of feet of drilling wasted. When additional laterals are started from a single well, risks inherent in each lateral are cumulative thereby increasing the risks associated with the parent well. Additionally, the junction of a lateral to a vertical well is itself a complex and risky operation and configuration. Due to the cumulative nature of risk, the use of multiple laterals at individually low risk can result in unacceptably high total risk for the desired multi-lateral well configuration. For these and other reasons, multi-lateral well technology remains limited in the number and configuration of laterals.

[0018] Other related material may be found in at least U.S. Patent Nos. 6,729,394;

5,314,019; 4,886,118; 4,522,260; 4,223,734; 3,830,299; 3,592,266; and 2,923,535 and in U.S. Patent Publication Nos. 2005/0269088 and 2005/0028975. Further, additional information may also be found in R. Quttainah, J. Al-Hunaif, "Umm Gudair Dumpflood Pilot Project, The Applicability of Dumpflood to Enhance Sweep & Maintain Reservoir Pressure," SPE 68721 , April 2001 ; Al-Khodhori, S., et al, "Connector Conductor Wells Technology in Brunei Shell Petroleum Achieve High Profitability Through Multiwell Bores and Downhole Connections," IADC/SPE 11 1441 , March 2008; Poe, B. D., et al, "Prediction of Future Well Performance, Including Reservoir Depletion Effects," SPE 29465 (1995); and Huang, W.S., et al, "Evaluation of Steamflood Processes with Horizontal Wells," SPE Reservoir Engineering, February 1989, pages 69-76. SUMMARY

[0019] In some implementations of the present invention, systems for altering fluid flow in a subterranean formation include a surface-connected well extending from a surface into a subterranean formation and at least one subterranean conduit at least substantially isolated from the surface-connected well. In some implementations, the subterranean conduit is a cavity opened from the surface-connected well and at least substantially isolated from the surface-connected well. In some implementations, the subterranean conduit is a cavity isolated from the surface. Additionally or alternatively, the subterranean conduit may be packed, such as by gravel packing, prior to being isolated from the surface. Still additionally or alternatively, the subterranean conduit may be cased and perforated prior to being isolated from the surface. In some implementations, the subterranean conduit may be completed with one or more completion elements prior to being isolated from the surface. For example, the one or more completion elements may include at least one autonomous completion element and/or at least one responsive completion element. In some implementations, the at least one subterranean conduit may include at least one induced fracture at least substantially isolated from the surface and from the surface-connected well. Additionally or alternatively, the at least one subterranean conduit may include at least one acidized wormhole at least substantially isolated from the surface and from the surface- connected well. [0020] In some implementations, the surface-connected well of the present systems may include a production well. Additionally or alternatively, the surface-connected well may include an injection well. In some implementations, the system may include an injection well spaced from a production well with both the injection well and the production well being surface-connected wells. In such implementations, at least one subterranean conduit may be disposed between the injection well and the production well such that the at least one subterranean conduit is at least substantially isolated from both the injection well and the production well. Additionally or alternatively, the at least one subterranean conduit may extend adjacent to two or more wells while remaining at least substantially isolated from any production wells or injection wells. [0021] Some implementations of the present systems include at least one subterranean conduit configured to have a higher permeability than the formation in which it is disposed. The higher permeability may be provided in a variety of suitable manners. For example, the permeability of the conduit may be elevated by dissolving formation material. Additionally or alternatively, the subterranean conduit may be configured to have a higher permeability by mechanically disturbing the formation material, such as with conventional rotary drill strings, with unconventional drilling equipment, or with other mechanical equipment. Still additionally or alternatively, the subterranean conduit may be configured to have a higher permeability by hydraulically disturbing the formation material, such as by hydraulic fracturing. The at least one subterranean conduit may be configured to alter a subterranean flow field around a surface-connected well.

[0022] In some implementations, the subterranean conduit may be provided after the production well has begun production. Additionally or alternatively, the subterranean conduit may comprise at least a portion of a previously drilled directional well at least substantially isolated from the surface and from the surface-connected well. For example, the previously drilled directional well may have been used as a production well or an injection well prior to being converted to a subterranean conduit. [0023] The present disclosure further provides methods of altering fluid flow in a subterranean formation. Some implementations of the present methods include configuring a surface-connected well to participate in hydrocarbon-production operations, such as being configured as a production well or an injection well, wherein the surface-connected well extends from a surface into a formation. The methods further include providing a subterranean conduit in the formation into which the surface-connected well extends, wherein the subterranean conduit is at least substantially isolated from the surface- connected well. Additionally, the methods include isolating the subterranean conduit from the surface. [0024] Providing a subterranean conduit may include one or more of: gravel packing the conduit; providing fluid communication between the conduit and the formation; and completing the conduit to have a permeability higher than the formation in which the conduit is formed. Additionally or alternatively, providing a subterranean conduit may include providing at least one induced fracture and/or providing at least one acidized wormhole. Still additionally or alternatively, providing a subterranean conduit may comprise drilling a directional wellbore into the formation, wherein the directional wellbore is at least substantially isolated from the surface-connected well.

[0025] Completing the conduit to have a permeability higher than the formation may include one or more of dissolving formation material, mechanically disturbing formation material, and hydraulically disturbing formation material. Completing the segment may include providing one or more responsive completion elements in the conduit and/or providing one or more autonomous completion elements in the conduit. In some implementations, the subterranean conduit is configured to alter a subterranean flow field around one or more surface-connected wells. [0026] Additionally or alternatively, in some implementations, the subterranean conduit is provided adjacent to one or more production wells and is at least substantially isolated from all of the production wells. The subterranean conduit additionally may be provided adjacent to at least one production well and adjacent to at least one injection well, while being at least substantially isolated from all production wells and injection wells. In some implementations, the subterranean conduit is provided after the production well has begun production. In implementations utilizing a portion of a directional wellbore to provide a subterranean conduit, the directional wellbore may have been used as an injection well or a production well prior to having at least a portion thereof at least substantially isolated from the surface to form the subterranean conduit.

[0027] Still further, the present disclosure provides methods of operating a hydrocarbon producing well including 1 ) configuring a production well to produce hydrocarbons, wherein the production well extends from a surface into a formation, and wherein the production well induces an initial flow field in the formation; 2) providing a subterranean conduit in the formation into which the production well extends, wherein the subterranean conduit does not intersect the producing well; and 3) configuring the subterranean conduit to induce an altered flow field in the formation relative to the initial flow field induced by the production well. In some implementations, the subterranean conduit traverses at least two reservoirs. Additionally or alternatively, providing a subterranean conduit may include providing at least one induced fracture and/or providing at least one acidized wormhole. Configuring the subterranean conduit may include a variety of operations, including one or more of gravel packing the subterranean conduit; providing fluid communication between the conduit and the formation; and completing the conduit to have a permeability higher than the formation in which the conduit is formed. Completing the conduit to have a permeability higher than the formation may include one or more of dissolving formation material, mechanically disturbing formation material, and hydraulically disturbing formation material. In some implementations, completing the conduit may providing one or more responsive completion elements in the conduit and/or providing one or more autonomous completion elements in the conduit. Methods of operating the well may further include providing an injection well spaced from the production well. In such implementations, configuring the subterranean conduit may be adapted to induce an altered flow field in the formation that directs injected fluids along preferred paths between the injection well and the production well. The present methods may further include producing hydrocarbons from the production well.

[0028] The present disclosure further provides methods of operating a hydrocarbon producing well including: 1 ) configuring a production well to produce hydrocarbons, wherein the production well extends from a surface into a formation, and wherein the production well induces an initial flow field in the formation; 2) providing a subterranean conduit in the formation into which the production well extends, wherein the subterranean conduit does not intersect the producing well; 3) configuring the subterranean conduit to induce an altered flow field in the formation relative to the initial flow field induced by the production well; and 4) producing hydrocarbons from the production well. The methods may further include providing an injection well spaced from the production well and in operative association with, but not intersecting, the subterranean conduit. Additionally or alternatively, the methods may include injecting a fluid into the formation through the injection well. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The foregoing and other advantages of the present technique may become apparent upon reading the following detailed description and upon reference to the drawings in which:

[0030] Fig. 1 is a schematic illustration of representative streamlines between injection wells and a production well during a 5-spot flooding treatment in a homogeneous formation;

[0031] Fig. 2 is a schematic illustration of representative streamlines between injection wells and a production well during a 5-spot flooding treatment in a heterogeneous formation; [0032] Fig. 3 is a schematic illustration of representative streamlines between an injection well and a production well during a flooding treatment in a heterogeneous formation;

[0033] Fig. 4 is a schematic illustration of representative streamlines between injection wells and a production well during 5-spot flooding treatment in a formation provided with subterranean conduits;

[0034] Fig. 5 is a schematic illustration of representative pressure fields around a production well in a formation provided with subterranean conduits;

[0035] Fig. 6 is a schematic illustration of representative streamlines between an injection well and a production well during a flooding treatment in a formation provided with subterranean conduits;

[0036] Fig. 7 is a schematic illustration of a subterranean conduit disposed in a formation;

[0037] Fig. 8 is a schematic illustration of a plurality of subterranean conduits being formed; [0038] Fig. 9 is another schematic illustration of a plurality of subterranean conduits being formed; and

[0039] Fig. 10 is a schematic side view of a subterranean conduit in a formation.

DETAILED DESCRIPTION

[0040] In the following detailed description, specific aspects and features of the present invention are described in connection with several embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, it is intended to be illustrative only and merely provides a concise description of exemplary embodiments. Moreover, in the event that a particular aspect or feature is described in connection with a particular embodiment, such aspects and features may be found and/or implemented with other embodiments of the present invention where appropriate. Accordingly, the invention is not limited to the specific embodiments described below, but rather; the invention includes all alternatives, modifications, and equivalents falling within the scope of the appended claims.

[0041] Despite the many diverse technologies developed to improve the total recovery of hydrocarbons from a field, continual challenges are faced due to the diversity of geologic conditions in which hydrocarbons are deposited, the ever-increasing difficulty in accessing the fields, and the increasing costs associated with drilling additional infill wells among other factors. As described above, conventional flooding treatments to sweep fluids towards the production wells are known to bypass areas of low permeability and fault blocks leaving potentially large volumes of hydrocarbons behind. For a variety of reasons, including cost and available space at the surface, the provision of additional infill wells according to conventional methods is not desirable in many circumstances. The present systems and methods provide means to manage or control the subterranean flow fields to improve the total recovery from a field without requiring additional topside wellheads. As described above, multi-laterals and horizontal wells are also limited in their ability to increase the recovery of hydrocarbons. For example, the increased risks associated with increasing the number of laterals in a multi-lateral may be unacceptable. The present systems and methods additionally or alternatively provide means to obtain many of the benefits of multi- laterals without the risks associated with conventional multi-laterals. [0042] Fig. 4 provides a schematic illustration of stream lines in a subterranean formation 200 between injection wells and a production well in a 5-spot treatment operation. Similar to the illustrations of Figs. 1 and 2, the formation 200 in Fig. 4 includes a production well 212 and four injection wells 210 spaced away from the production well. The formation 200 is divided effectively into four quadrants 222 by the flow fields created by the 5-spot treatment pattern. However, the formation 200 differs from the formation 100 illustrated in Fig. 1 by the inclusion of subterranean conduits 230 in the formation. As illustrated, there are four subterranean conduits 230 in Fig. 4 disposed at the edges of the quadrants 222 created by the 5-spot treatment flow fields. The conduits 230, as will be explained in more detail below, alter the flow fields in the formation, which can be seen by comparing the flow fields and contours of Fig. 4 with the flow fields and contours of Figs. 1 and 2. [0043] Subterranean conduits 230 consist of a region of the formation that has been altered from the natural state to have a higher permeability. In many implementations, the subterranean conduit 230 is provided by drilling a directional wellbore that is subsequently at least substantially isolated from the surface. In some implementations, the wellbore that is utilized as a subterranean conduit (being isolated from the surface) may be drilled for the purpose of providing a subterranean conduit. In other implementations, a previously drilled directional well having been once used as a production or injection well may be converted to a subterranean conduit by isolating a portion of the wellbore from the surface. In some implementations, the conduit 230 may be drilled in a field including multiple production wells, which may include one or more X-spot flooding patterns. Such implementations may configure the conduit 230 to pass proximate to or adjacent to two or more production wells. As described herein, the conduits 230 are configured to be at least substantially isolated from, and therefore to not intersect, the injection and/or production wells that are open to the surface. These subterranean conduits 230 do not provide nor require a direct fluid communication path to the surface. Accordingly, the subterranean conduits can be provided adjacent to the production and injection wells without requiring complex operations to ensure alignment and/or intersection with the wells. As used in the present application, subterranean conduits may be understood to be distinct from surface-connected wells, such as production wells and/or injection wells.

[0044] While some subterranean conduits according to the present systems and methods may be provided through drilling relatively conventional wellbores, subterranean conduits may be provided in other suitable manners. For example, cavities in the formation may be opened in any conventional manner that allows them to remain, or that allows them to be configured to be, at least substantially isolated from the surface and from the adjacent surface-connected wells. Exemplary methods may include hydraulically fracturing the formation in a manner to extend the fracture proximate an adjacent production well without intersecting or connecting the fracture and the production well. Similarly, acidized wormholes may be extended towards an adjacent production and/or injection well. As used herein, acidized wormholes refers to the various formation modifications that may occur during acid treatments, including matrix acidizing and wormhole development. A wormhole may include a main or principle wormhole and several dendritic extensions. Still additionally, non-conventional drilling technologies, such as the burrowing technology developed by Badger Explorer ASA, may be employed to create a subterranean cavity. Regardless of how the cavity is formed (drilling, burrowing, acidizing, fracturing, etc), the cavity is a subterranean conduit by being at least substantially isolated from the surface and from any adjacent surface-connected wells. In some implementations, the subterranean conduit may be drilled or otherwise created from the production/injection well itself provided that the conduit is at least substantially isolated from the production/injection well and other adjacent production and/or injection wells. [0045] As illustrated in Fig. 4, the subterranean conduits 230 are disposed in the formation 200 and are adjacent to the production well 212 and the injection wells 210. However, it is noted that the conduits 230 do not intersect the production or injection wells. The degree of separation illustrated in Fig. 4 is representative only to show that the conduits are at least substantially isolated from the wells and not to show a particular physical relationship between the conduits and the wells. In application, the conduits may get much closer to the wells or may stay further away from wells, which proximity may vary depending on the conditions of the field and the operations to be performed thereon. For example, a subterranean conduit being drilled toward a producing well may terminate further away from the well to ensure that that drilling operation does not disturb the existing well. As illustrated in Fig. 4, the subterranean conduits 230 have the effect of drawing the fluids from the injection wells 210 toward the subterranean conduit en route to the production well 212. Accordingly, the dead-space or bypassed region outside of contour 220 is substantially smaller in Fig. 4 than in Figs. 1 and 2. [0046] As indicated above, the subterranean conduits 230 of the present disclosure are at least substantially isolated from any production and/or injection wells near to which the conduit is disposed. As further described above, the subterranean conduits may be provided in any of a variety of manners provided that the conduit is at least substantially isolated from adjacent production and injection wells. As used herein in this context, a subterranean conduit is considered to be "at least substantially isolated" from adjacent wells when there are no production or injection pathways to the adjacent surface-connected well. A production/injection pathway as used herein refers to a pathway that allows measurable fluid flow therethrough to the production/injection well. Accordingly, subterranean conduits at least substantially isolated from adjacent production/injection wells lack a production/injection pathway to the adjacent production/injection well, and, therefore, do not function as part of the production/injection well. As described above, conventional efforts to optimize recovery are limited by technologies that operate in the wellbore or in the near-well region of the formation. Subterranean conduits, on the other hand, are at least substantially isolated from the production and/or injection wells and are a variance in the formation rather than an extension of or variance from the wellbore.

[0047] In some implementations, the conduit is formed from a vertical bore that is neither a production well or an injection well. Such a vertical bore may be drilled for the purpose of providing one or more subterranean conduits and the communication to the surface may be closed, temporarily or permanently, once the subterranean conduits are configured. In other implementations, the subterranean conduit may be drilled or otherwise formed from a well that, whether past, present, or future, may be (or may have been) used for production and/or injection. In such implementations, the conduit may be isolated from the well in any suitable manner that sufficiently restricts flow such that an insignificant amount of fluid flow into the well comes directly from the cavity used to form the conduit compared to the fluid entering the well from the formation around the cavity. For example, in some implementations, the isolation may be provided by one or more of a packer, a plug, cement, gravel accumulation, cuttings accumulations, or other suitable materials that restrict flow through the cavity or bore used to form the conduit. In some implementations, the equipment and/or materials used to provide the isolation may be selected and/or configured to provide a resistance to flow through the bore comparable to the resistance to flow through the formation, such as having a permeability within two or three orders of magnitude of the permeability of the formation. In other implementations, such as when a packer and/or cement is used, the resistance to flow through the bore may be substantially greater than the resistance to flow through the formation. In either implementation, only an insignificant amount of fluid would enter the well through the cavity used to form the conduit. [0048] The amount of fluid flow through the cavity used to form the conduit may vary from implementation to implementation. For example, when the formation adjacent the wellbore is highly permeable, the isolation of the conduit from the production/injection well may allow a fair amount of fluid therethrough while still being insignificant compared to the amount of fluid flowing through the formation. In any event, the isolation of the conduit from the production/injection well restricts the flow between the conduit and the well. While the isolation of the conduit restricts the flow between the conduit and the well, the flow fields in the region around the production/injection well are still favorably altered due to the decreased distance through which the fluids must travel after reaching the end of the conduit. [0049] As discussed above and well understood, fluids, including subterranean fluids, will follow the path of least resistance between the injection well and the production well. Generally, that path of least resistance is a direct path, such as the region bounded within contour lines 214. However, permeability differences in the formation can affect the flow fields between the injection wells and the production well. As was illustrated in Fig. 2, a naturally occurring area of low permeability can redirect injected fluids increasing the size of the dead-zone. Similarly, an area of higher permeability can attract the injected fluids, as illustrated schematically in Fig. 3 and discussed above.

[0050] Fig. 5 provides a schematic representation of the pressure fields 240 around a production well in formation 200. The pressure fields are represented by dashed contours 242, 243, 244, 246, 248, 250, and 252. As illustrated, the pressure gradients extend away from the production well, with each contour representing successively higher pressure, in a circular pattern corresponding to the production well until the subterranean conduits are reached. Due to the high permeability of the subterranean conduits 230, the low pressure of the production well is able to extend along the conduit further than it is able to extend into the formation that is not provided with a conduit. The schematic pressure gradients illustrated in Fig. 5 are representative of theoretical pressure gradients only with the illustrated asymmetry representing exemplary heterogeneity in the formation. Actual pressure gradients will be affected by the multiplicity of physical processes that affect fluid flow. However, assuming that all other factors are equal across a formation, the higher permeability of the subterranean conduit would affect the pressure gradient in a manner at least somewhat approximate to what is schematically illustrated in Fig. 5. [0051] The tendency of an injected fluid to flow along a certain path will generally depend on the resistance to flow and the relative pressure differences between two locations. The resistance to flow is a function of the distance over which the fluid must flow and the permeability of the formation over that distance. By increasing the permeability along the subterranean conduit 230, the distance over which in injected fluid must travel to reach similarly low pressures is roughly the same along the direct route as it is along the indirect route (represented by contour 220 in Fig. 4). Accordingly, assuming the permeability of the formation is the same over the relevant distances, the provision of the subterranean conduits renders the indirect route (of contour 220) as likely a course of travel as the direct path from the injection well to the production well. Therefore, as illustrated in Fig. 4, the provision of subterranean conduits 230 in the formation results in a reduction in the dead- space and greater injected fluid flow along the outer contours 220.

[0052] Fig. 6 provides a schematic three-dimensional view of a formation 200, similar to that described above in connection with Fig. 3. The formation 200 has a low permeability zone 234 and a high permeability zone 236, which may be separated or defined by any number of geologic features, which are represented schematically by the dashed line 232. Fig. 6 illustrates that the positioning of the injection well 210, the production well 212, and the subterranean conduits 230 can affect the effectiveness of the flood treatment. As illustrated, the subterranean conduits 230 and surface-connected wells are positioned "low" in the low permeability zone 234. As discussed above, the representative formation illustrated in Fig. 6 is divided vertically and includes horizontal wells. Discussions of Fig. 6 will refer to relative positions in the context of having a high permeability zone above a low permeability zone. It will be understood that such terms of relativity will vary depending on the orientations of the wells and the formation's zones.

[0053] As illustrated in Fig. 6, as compared to Fig. 3, the streamlines or contours

214, 216, 218, and 220 have shifted lower in the three-dimensional space resulting in greater fluid flow through the low permeability zone 234. The subterranean conduits 230 do not change the permeability of the entire zone 234, but positioning the subterranean conduit 230 having high permeability proximate to the injection well 210 results in at least some of the injected fluid flowing horizontally toward the subterranean conduit 230 rather than predominantly vertically as in Fig. 3. While the specific flow lines into the conduits and exiting the conduits are not illustrated, it will be understood that the flow contours are altered from the illustration of Fig. 3 by virtue of the injected fluid flowing through the subterranean conduits 230.

[0054] Fig. 6 provides an exemplary illustration of multiple conduits 230 disposed between an injection well 210 and a production well 212. The subterranean conduits 230 are disposed at a distance from the high permeability zone 236 so as to maximize or increase the amount of the low permeability zone covered by the fluid exiting the conduits and flowing toward the high permeability zone. Similarly, Fig. 6 illustrates that the subterranean conduits 230 are spaced from the injection well 210 by a first distance and from the production well 212 by a second distance. The illustrated separations, including the relative separations, are exemplary only and the degree of separation may vary depending on the specifics of a particular formation. The subterranean conduit 230 may be disposed close enough to the injection well 210 such that the high permeability of the conduit induces horizontal fluid flow. Too much separation between the conduits and the injection well and the flow will proceed along the contours of Fig. 3 as the pressure fields induced by the conduits do not reach to the injection well. Similarly, if the subterranean conduit 230 extends too close to the production well 212, the injected fluid will flow directly through the conduit to the production well without passing through the vertical extent of the low permeability zone 234.

[0055] In Fig. 6, the distances of separation, between wells, conduits, and high permeability zones, are used as representative of the more relevant factor, which is the degree of fluid communication. As can be understood from the description herein, some subterranean conduits are disposed in very close proximity to the injection well and/or production well, such as when being drilled or formed from the surface-connected well. However, the subterranean conduits of the present systems and methods are isolated, or at least substantially isolated, from the surface-connected well(s). The isolation of the subterranean conduit does not need to be provided by a predetermined distance of native formation, but may be provided by any means (e.g., packers, plugs, cement, packing material, etc.) that reduces the fluid communication between the surface-connected well and the subterranean conduit.

[0056] The preferred degree of fluid communication between the subterranean conduits and the surface-connected well(s) may vary between implementations. For example, some implementations may prefer a degree of fluid communication low enough to avoid the complications associated with joining or connecting multi-laterals. In other implementations, the degree of fluid communication may be selected to create particular flow profiles within the formation to effectively sweep a zone or region of the formation, such as during flood treatments. In some implementations, the preferred relative positions of the surface-connected wells and the subterranean conduits may be determined through modeling exercises. For example, data regarding formation properties may be provided and input into one or more modeling programs to provide flow contours in the reservoir and/or in the near-well region. The positioning of the surface-connected wells and/or subterranean conduits may be varied within the modeling program(s) to obtain a preferred flow profile within the formation. Similarly, the flow rate and composition of the injected fluids may be varied to determine optimal operating conditions together with optimal conduit-well configurations. In some implementations, the modeling and planning of the subterranean conduits may be limited by the fixed position of existing wells and/or by the capacities of drilling or conduit-forming technologies. However, the use of suitable fluid flow modeling programs will enable users of the present systems and methods to obtain a degree of fluid communication between the surface-connected well(s) and the subterranean conduits that will create the desired pressure profiles and corresponding flow contours within the formation.

[0057] By way of example, EMpowΘr™ software was used to model the formation schematically illustrated in Figs. 3 and 6. Specifically, the formation was modeled as having 200 feet of total vertical depth (100 feet of high permeability zone 236 and 100 feet of low permeability zone 234) and 10,000 feet of separation between the injection well 210 and the production well 212. Moreover, the high and low permeability zones were modeled as having a permeability contrast of 100:1. The fluid flow during a flood treatment operation was modeled without subterranean conduits resulting in a recovery factor of about 39% as much of the injected fluids traveled directly to the high permeability zone bypassing the low permeability zone. The position of the surface-connected wells was varied to determine that positioning the injection and production wells low in the low permeability zone 234 resulted in the highest recovery possible in this baseline configuration.

[0058] The same formation was modeled again with varying configurations of the subterranean conduits 230. The relative positions of the injection well 210, the production well 212, and the subterranean conduits 230 were varied to identify a configuration having the highest recovery factor during the same flood treatment operation used in the model represented by Fig. 3. The subterranean conduits were modeled as conduits having a permeability contrast of 100:1 relative to the low permeability zone 234 (i.e., the same permeability as the high permeability zone 236). For the exemplary formation and the exemplary subterranean conduit permeability, it was determined that the subterranean conduit 230 should be spaced about 50 feet from the injection well 210 and about 2,000 feet from the production well 212 to obtain a recovery factor of about 48%. The use of EMpowΘr™ software or other modeling software enables users of the present system to optimize the configuration of the subterranean conduits 230, the degree of fluid communication between the conduits and the surface-connected wells, and/or the means used to provide the isolation between the subterranean conduits 230 and the surface-connected wells. [0059] With continuing reference to Figs. 4, 5, and 6, the subterranean conduits 230 will be described in greater detail. The subterranean conduits 230 may be provided in virtually any configuration or dimension available with current or future developed technology. However, the subterranean conduits have two identifying characteristics. First, the subterranean conduits 230 are at least substantially isolated from the surface. Second, the subterranean conduits 230 are at least substantially isolated from any wellbores that are connected to the surface. In some implementations, this could mean that the subterranean conduit is isolated from the surface by disposing material within a surface-connected wellbore to isolate a segment of the wellbore from the surface-connected remainder of the wellbore. In other implementations, the conduits 230 may approach the wells 210 and 212 without intersecting them, thereby leaving 'virgin' formation between the conduit and the surface-connected well.

[0060] With respect to the first characteristic, the subterranean conduits 230 may be disposed at any suitable depth and at any suitable orientation within the formation. The geologic properties of the formation, including the presence or absence of fault blocks and the configuration and location of the reservoirs, may affect or influence to the disposition of the subterranean conduits. For example, the subterranean conduits may be adapted to extend substantially horizontally above, below, or within a hydrocarbon reservoir. Additionally or alternatively, the conduits 230 may be configured to extend on a downward or upward angle to traverse multiple layers or reservoirs. The relative positions of the reservoirs, the production wells, and the injection wells may also influence the disposition of the subterranean conduits 230. For example, in a formation having multiple horizontal wells, a single conduit may be drilled or otherwise formed to run adjacent to more than 2 of the wells, such as by being vertically offset from the horizontal wells. In this manner, a single drilling operation can provide multiple conduits by crossing the multiple surface-connected horizontal wells at a depth different from the depth(s) of the horizontal wells leaving native or virgin formation between the conduit and the wells, which native formation can provide the at least substantial isolation. Additionally, as described above, the at least substantial isolation of the subterranean conduit from the surface may be accomplished through any suitable means, including the use of packers, plugs, cement, gravel, cuttings, or other materials that will restrict flow from the conduit reaching the surface.

[0061] With respect to the second characteristic, the subterranean conduits 230 may extend proximate to a production wellbore 212 and/or an injection wellbore 210 without intersecting the same, thereby leaving untouched formation between the conduit and the well providing the at least substantial isolation. In some implementations, the subterranean conduits 230 may be drilled or otherwise provided, such as by chemically, mechanically, or hydraulically disturbing the formation, in a manner that positions a portion of the conduit within a predetermined distance of a wellbore. The chemical disturbance may be provided by matrix acidizing, wormhole acidizing, or other available techniques; the mechanical disturbance may be provided by conventional drilling techniques, by unconventional drilling techniques, by burrowing, or by other suitable techniques; the hydraulic disturbance may be provided by hydraulic fracturing or other suitable techniques. In other implementations, the conduit may be provided in a manner that merely disposes a portion of the conduit within the same reservoir or formation region (such as fault block) as the wellbore. In still other implementations, the subterranean conduits 230 are provided as bores, fractures, wormholes, or other cavities extending away from a production and/or injection well that is subsequently isolated, or at least substantially isolated, from the production/injection well. In all of these situations and other implementations within the scope of the present disclosure and invention, the conduit may be said to be at least substantially isolated from an adjacent well when the subterranean conduit 230 is in fluid communication with the well through the formation or other equipment or materials placed in the formation to isolate the conduit, rather than by intersecting the well directly or by direct fluid communication through a perforation or other production/injection flow path.

[0062] More preferred configurations or locations for subterranean conduits 230 may be determined with reference to logs or data regarding the formation and/or past operations in the formation. For example, in the event that a subterranean conduit is being provided for an existing well that has been producing, there may be historical production logs and possibly historical treatment and/or injection logs that can be used to better determine the properties of the formation in the region to be treated or influenced by the subterranean conduit 230. Additionally or alternatively, seismic technologies, such as 4D seismic, may be used to identify regions or formations in which subterranean conduits 230 may have practical application. In some implementations, the data regarding the formation may be interpreted by an operator or engineer to determine the desired configuration and location of the subterranean conduit. In other implementations, the data may be input into any of a variety of flow modeling programs to estimate the impact of a variety of subterranean conduit configurations on the operations in the formation, which may enable optimization of the subterranean conduit. While conventional modeling programs may be sufficient to approximate an optimal configuration for a subterranean conduit, other implementations may utilize customized or more advanced modeling programs that account for a greater number of parameters than conventional modeling programs. As described above, EMpowΘr™ software or other suitable flow modeling programs may be used to vary one or more parameters to optimize the configuration of the subterranean conduits 230 and the degree of fluid communication (or the degree of isolation) between the subterranean conduits and the surface-connected wells. [0063] Fig. 7 illustrates a schematic view of a subterranean conduit 330 disposed in a formation 300 that is divided effectively into three reservoirs 360, 362, and 364, which may be formed by fault blocks or by other geologic features. As illustrated in Fig. 7, production well 312 is disposed in reservoir 360 and would be essentially isolated from reservoirs 362 and 364 if not for the subterranean conduit 330 that traverses all three reservoirs. The subterranean conduit 330 of Fig. 7 is configured to have openings along the length thereof in portions disposed within each of the reservoirs. In some implementations, the subterranean conduit may include features, described further below, to control the direction of fluid flow into or out of the subterranean conduit, such as by configuring lengths in reservoirs 362 and 364 as inlet lengths and configuring the length in reservoir 360 as an outlet length. Other such customizations may be provided to the subterranean conduit, as conditions and costs would suggest.

[0064] Fig. 7 illustrates the injection well 310 as optionally disposed in reservoir 364.

It should be understood that the injection well could similarly be disposed in reservoir 362 or in a manner capable of injecting fluids into both reservoirs. Additionally, some implementations of the present systems and methods may provide a subterranean conduit in cooperation with a production well but without an associated injection well. For example, the formation 300 of Fig. 7 may include reservoirs 362 and 364 at sufficient natural pressures to drive the hydrocarbons toward the production well 312 but lacking fluid communication between the reservoirs and the well. The subterranean conduits 330 of the present disclosure when disposed to traverse the several reservoirs would provide the fluid communication needed to allow the natural drive pressures of reservoirs 362 and 364 to move the hydrocarbons towards the production well 312 through the subterranean conduit. One or more injection wells may be provided at a later time, such as when the natural-drive pressures have decreased and a flooding treatment is justified. [0065] While much of the foregoing discussion has described subterranean conduits

230, 330 in connection with flood treatment operations, it should be understood that the subterranean conduits described herein will affect the pressure and flow profiles within a formation around a surface-connected with or without a flood treatment operation. Accordingly, one or more subterranean conduits may be provided in operative association with a production well to facilitate the flow of fluids from regions separated from the production well. As described above, an injection well may be incorporated later for flood treatment if the need should arise. In such implementations, the subterranean conduits may function in a manner similar to a multi-lateral well, but without the risks associated with coupling the multi-laterals to the main vertical well. Similarly, the subterranean conduits of the present disclosure may be used with an injection well without an associated production well, such as when an injection well and formation is used for disposal purposes, such as for disposal of produced water. The subterranean conduits in such implementations may enable the injected fluids to be better distributed in the disposal formation or to reach a portion of the disposal formation having higher permeability and/or lower pressure. [0066] Fig. 8 schematically illustrates one method of providing subterranean conduits

430 in a formation. As illustrated in Fig. 8, a wellbore 470 provides a point of beginning for the formation of multiple subterranean conduits 430a, 430b, 430c, and 43Od. Each of the subterranean conduits 430 illustrated in Fig. 8 may be formed by drilling directionally from the main wellbore 470 followed by isolating the directional portion from the main wellbore using any of a variety of isolation means 472. For example, the directional segment of the wellbore, or at least a portion thereof, may be isolated to form a subterranean conduit 430 by positioning a plug, a packer, or other conventional downhole equipment or materials at the desired location in the wellbore. Additionally or alternatively, concrete, drill cuttings, gravel, or other material may be deposited in the wellbore to at least substantially isolate the subterranean conduit from the surface and, in some implementations from other subterranean conduits drilled from the same wellbore. The equipment, materials, and/or combination of equipment and materials disposed in the wellbore to isolate the subterranean conduit forms an isolation means 472.

[0067] As illustrated in Fig. 8, a plurality of subterranean conduits 430 may be formed from a single wellbore 470. Depending on the formation being produced and the locations of the wellbores and reservoirs, one or more subterranean conduits 430 may be appropriate. Fig. 9 further illustrates that the subterranean conduits 430 may extend away from the wellbore at different depths as appropriate for the formation. Fig. 9, similar to Fig. 8, schematically illustrates that the directional segments may be isolated from the surface by suitable, equipment and/or materials, which may include packers, plugs, concrete, and/or other materials. Fig. 9 further illustrates that the plurality of directional segments may be isolated collectively from the surface by a single isolation means 472 disposed in the wellbore above the collective directional segments that are converted to subterranean conduits 430. Additionally, Fig. 9 illustrates that each of the conduits 430 are provided with isolation means 474, which may be constructed of any of the materials and equipment described above including packers, plugs, concrete, and other materials. The individual isolation means 474 and the single isolation means 472 may be of the same or similar construction varying only in the location relative to the wellbore and the conduits. In some implementations, it may be preferred to isolate each conduit from the other conduits. In other implementations, cross flow between the conduits may be acceptable and the conduits may only be isolated from the surface with the common isolation means 472. Additionally or alternatively, isolation means 472, 474 may be implemented in a manner to provide some redundancy, such as illustrated in Fig. 9. In the event that one or more of the isolation means 474 leaks or fails to isolate adequately, the isolation means 472 is provided to ensure that the subterranean conduits 430 remain isolated from the surface.

[0068] With continuing reference to Fig. 9, some implementations of the present systems and methods may enable a wellbore 470 to be used to provide subterranean conduits 430 and then to be closed or otherwise abandoned without an active connection to the surface (i.e., without having a wellhead at the surface taking up valuable space on the rig or platform). As the benefits of the subterranean conduits are obtained without requiring a live connection to the surface, the at least substantially isolated conduits may be drilled or otherwise formed in the formation using a first slot on a platform, which slot may then be freed up for other uses once the subterranean conduit is formed and isolated from the surface.

[0069] Additionally or alternatively, the wellbore 470 may be used to provide one or more subterranean conduits that are isolated from the main wellbore 470. The main wellbore 470 may then be utilized for production or injection operations as appropriate. In such implementations, the production or injection operations utilize portions of the main wellbore, which may be the vertical portions only or may include one or more directionally drilled portions, while other portions of the wellbore are at least substantially isolated from the main surface-connected wellbore. By selectively isolating, or at least substantially isolating, portions of the wellbore, the costs and risks associated with the junctions are minimized. Additionally, the conversion of at least some of the directional portions of the wellbore to subterranean conduits may facilitate the construction, completion, and production operations in the wellbore.

[0070] As alluded to above, the subterranean conduits of the present disclosure may be formed in a formation at any suitable time. In some implementations, the formation may be sufficiently understood, such as by testing or by reference to prior wells in similar formations, that the current or future need for a subterranean conduit is known before production from the formation is begun. In such implementations, the subterranean conduit may be created or provided in the formation before production begins. For example, the process of forming or creating the subterranean conduit may commence before, during, or after the production well is drilled, completed, etc. In other implementations, a production well may be producing for a period of time before the need or desirability of a subterranean conduit becomes apparent. In such circumstances, the subterranean conduit can be drilled or formed after the production well has been producing. In some implementations, the production well may continue in operation during the provision of the subterranean conduit. As described above, the subterranean conduit need not intersect or otherwise directly impact the production well and as such the production well may continue to operate during some or all of the time required to form the subterranean conduit. Furthermore, as suggested above, an existing well may be converted to a subterranean conduit where appropriate. For example, an existing vertical well can be converted to a subterranean conduit by directionally drilling from the vertical well and then closing or isolating the directionally drilled segment from the vertical segment. Additionally or alternatively, an existing directional well may be converted to a subterranean conduit and a vertical well by isolating the directional segment from the vertical segment, as described herein. Still additionally, as described above, a subterranean conduit can be opened from an existing well by fracturing, acidizing, and/or burrowing into the formation from the existing well followed by at least substantially isolating the opened cavity, such as by using any of the methods described above or otherwise known in the industry to at least substantially isolate an open cavity from a wellbore. [0071] Fig. 10 schematically illustrates a subterranean conduit 530 disposed in a formation 500. The schematic representation of Fig. 10 shows a segment of the subterranean conduit that continues in both directions. Accordingly, Fig. 10 does not illustrate an isolation means at either end. However, it should be understood that the subterranean conduit 530 may be sealed or closed at either end through the use of one or more of the techniques described above. Additionally or alternatively, the subterranean conduit 530 may be closed at one end thereof by the formation into which the conduit is drilled. Fig. 10 illustrates a very basic subterranean conduit 530 and schematically illustrates (via the dash-lined blocks) a variety of features that may be provided to the subterranean conduit should conditions warrant the use of such features. [0072] Starting with a basic configuration of a subterranean conduit 530, the conduit

530 includes a cavity 580, which may be defined by a conduit wall 582 provided by the formation 500. The cavity 580 may be created through any one or more of the means described above, including mechanical, hydraulic, and/or chemical disturbance of the formation 500. In some implementations, the conduit wall 582 may include a casing or lining or other conventional wellbore materials used to stabilize a formation. Similarly, as illustrated in Fig. 10, the conduit wall 582 may include one or more perforations 584. As with conventional boreholes, the perforations 584 may provide fluid communication between the formation and the conduit through the conduit wall. For example, in some implementations, the conduit wall may be damaged during the formation of the conduit reducing the permeability thereof. In such circumstances, the perforations 584 provide improved fluid communication. Additionally or alternatively, where the conduit wall 582 includes a casing and/or a liner, the perforations 584 may provide means of fluid communication between the formation and the conduit cavity 580.

[0073] One of the simplest subterranean conduits 530, as represented in Fig. 10, is simply a borehole drilled through a formation having the drill string withdrawn. Effectively, by drilling through the formation, the space opened by the drill string increases the permeability of the conduit, thereby providing the functionality described above. Of course, any of the other hydraulic, mechanical, and/or chemical methods described herein may be used to open a cavity to form the conduit 530. In some implementations, it may be preferred to reinforce or stabilize the borehole wall, or conduit wall, during the drilling process or as the drill string is being removed. Accordingly, the subterranean conduit 530 may include casing or lining materials. Additionally or alternatively, the subterranean conduit 530 may be gravel packed to back fill the cavity 580. The materials selected for the gravel pack can be conventional gravel pack materials or can be selected to provide a customized permeability. For example, it may be determined that a permeability that is too high would be detrimental to the system in some way, such as drawing too much injected fluid toward the conduit and not allowing the injected fluids to sweep or flood other portions of the formation. Accordingly, in some implementations, particular gravel sizes, such as 12/18 gravel or any other suitable gravel, may be preferred to obtain a desired permeability. [0074] Fig. 10 further illustrates several optional features that may be added to a subterranean conduit to further customize or control its performance while disposed below the surface. For example, the subterranean conduit 530 may include an inner tubular 586. The inner tubular 586 and the annulus between the tubular and the conduit wall may have different permeabilities or the same permeabilities. In some implementations, the inner tubular 586 may be provided with a sand screen 588 or other solids control systems to promote the continued functionality of the subterranean conduit even in the event of sand production into the conduit cavity 580.

[0075] Other completion equipment may also be utilized in the subterranean conduit.

For example, Fig. 10 illustrates optional flow control devices 590 and packers 592 in cooperation with the inner tubular 586. Flow control devices 590 may include any one or more of a variety of valves, chokes, nozzles, or other apparatus conventionally used to regulate flow into a tubular. Such devices may be provided on a mandrel, integral with the tubular, or in any other suitable manner. Similarly, the packers 592 may include any of a variety of packers or other zonal isolation systems that are conventional in wellbore completions. Such packers may provide any suitable functionality in the subterranean conduit, such as promoting flow in a predetermined direction or preventing fluids in one portion of the conduit from reaching another portion of the conduit. [0076] In some implementations of the subterranean conduits of the present disclosure, the completion equipment that may be provided therein may be responsive completion equipment. Responsive completion equipment refers to equipment that can change its configuration and/or operation/functionality when operating conditions so warrant. Examples of non-responsive completion equipment include casing that is fixed over the life of the well and the conventional perforations that do not change once formed. Examples of responsive completion equipment include equipment that is controlled by operator intervention and equipment that is responsive to the operating environment without requiring operator intervention. [0077] A wide variety of completion equipment is available, or may become available in the future, that is responsive to some form of operator intervention. For example, adjustable chokes, seals, nozzles, sliding sleeves, packers, and other tools are available that can be controlled via wireline or other communications equipment. In the present implementations of a subterranean conduit, the completion equipment may be positioned in the conduit as desired, the communications equipment may be coupled to the completion equipment (which may occur before or after the completion equipment is in position), and then the conduit may be isolated from the surface with the communications equipment extending through the isolating means. For example, a control line of any suitable configuration may extend through the isolating means, such as an electrical, hydraulic, fiber optic, or other control line. In other implementations, the control line may be incorporated into the casing that extends from the surface to conduit when the conduit is cased. [0078] In an alternative implementation, the completion equipment may be configured to receive commands from an operator without a direct connection via a control line. For example, the completion equipment may respond to other signaling systems including electromagnetic signals. In an exemplary implementation where the completion equipment is not in direct communication with the surface, a communications receiver may be disposed in the conduit near to a production or injection wellbore adjacent to the conduit. The communications receiver may then be coupled to one or more of the completion equipment apparatus to control the same in response to the operator's commands. Similarly, in some implementations, one or more of the completion equipment apparatus may be provided with independent communications receivers. The mode of communication and the distances between the location of the completion equipment and the nearest production or injection well will affect the implementation of the communication receivers. A variety of communication and control equipment are known or may be developed, any of which may be incorporated into the completion equipment of the present conduits.

[0079] Additionally or alternatively, the completion equipment may include one or more apparatus or systems that are autonomous, or responsive to the operating environment but not requiring operator intervention to effect the response. Several examples of such autonomous completion equipment are available or will become available in the future. Exemplary available autonomous equipment include swellable packers, swellable materials used in other contexts, such as around orifices or sand control features, flow-control nozzles, etc. Other autonomous equipment and methods of utilizing such autonomous equipment in a wellbore are described in International Publication Numbers WO2007/094897, WO2007/094900, and WO2007/126496. In accordance with the present disclosure, the autonomous systems disclosed in these publications may be adapted or configured for use in connection with the present subterranean conduits. [0080] Autonomous completion equipment may be provided in the subterranean conduit to prolong to the operable life of the conduit. For example, an autonomous sand control system may allow the subterranean conduit to maintain its relatively higher permeability for a longer period even in the event of sand production from the formation. Similarly, autonomous completion equipment in the subterranean conduit may be configured to respond to the presence of water or gas or other materials in the conduit by increasing or decreasing the permeability of the conduit, as appropriate, to further control the flow of fluids through the formation.

[0081] While completion equipment, responsive or otherwise, may be disposed in the subterranean conduit in some implementations, it should be understood that such equipment is not necessary for the successful implementation of the present systems and methods. As described herein, the subterranean conduit is adapted to control or adapt the flow fields within a subterranean formation by altering the resistance to flow through particular regions of the formation, thereby causing the fluids to flow in a more desirable pattern through the formation. The reduced resistance is accomplished by changing the permeability of a particular region of the formation through the use of a subterranean conduit having a higher permeability than the permeability of the surrounding formation. The subterranean conduit may be adapted or configured in a variety of manners, such as those described herein, to accomplish more specific objectives. [0082] As described herein, the subterranean conduits may provide a variety of benefits to field operations, including improving recovery rates, improving sweep efficiencies in flood treatments, reducing risks associating with joining multiple directional or horizontal wells to a vertical well, reducing risks associated with completing and/or producing from directional and/or horizontal wells, etc. However, field operations are dynamic due to the extended time over which a well is operated. In some fields, a given reservoir and well could be operational for over 20 years. As the conditions of the reservoir change, the subterranean conduits of the present disclosure provide additional treatment or workover possibilities to the operator of the well. For example, the degree of fluid communication between the subterranean conduit and the surface-connected well(s) may be changed after the conduit has been used as a conduit for some time. Depending on the nature of the isolation between the subterranean conduit and the surface-connected well, the fluid communication may be changed through a number of methods, such as by changing the configuration of the packer or plug, by drilling through the cement plug, by penetrating native formation, such as by fracturing, acidizing, perforating, etc., or by another suitable method appropriate for the isolation means. In some implementations, the subterranean conduit may be converted to a connected portion of the surface-connected well, such as a multilateral. One exemplary scenario in which a subterranean conduit may be desirably converted to a segment of the surface-connected well is when the production rate with the subterranean conduit has fallen below acceptable levels and cannot be raised through other techniques, such as by flood treatments, alteration of completion equipment in the conduit, etc. In such situations, the cost of a workover to connect the conduit to the surface- connected well may be minimal and the risk/reward calculations may suggest connecting the conduit, particularly in situations where the connection can be accomplished simply through fracture operations or other conventional workover operations.

[0083] While the present techniques of the invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques of the invention are to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.

Claims

CLAIMSWhat is claimed is:
1. A system for altering fluid flow in a subterranean formation, the system comprising: a surface-connected well extending from a surface into a subterranean formation; and at least one subterranean conduit at least substantially isolated from the surface- connected well.
2. The system of claim 1 wherein the subterranean conduit is a cavity opened from the surface-connected well and at least substantially isolated from the surface-connected well
3. The system of claim 1 wherein the subterranean conduit is a cavity at least substantially isolated from the surface.
4. The system of claim 3 wherein the subterranean conduit is packed prior to being at least substantially isolated from the surface.
5. The system of claim 3 wherein the subterranean conduit is cased and perforated prior to being at least substantially isolated from the surface.
6. The system of claim 3 wherein the subterranean conduit is completed with one or more completion elements prior to being at least substantially isolated from the surface.
7. The system of claim 6 wherein the one or more completion elements comprises at least one autonomous completion element.
8. The system of claim 6 wherein the one or more completion elements comprises at least one responsive completion element.
9. The system of claim 1 wherein the surface-connected well is a hydrocarbon production well.
10. The system of claim 9 further comprising an injection well spaced from the production well, wherein at least one subterranean conduit is disposed between the injection well and the production well, and wherein the at least one subterranean conduit is at least substantially isolated from both the injection well and the production well.
11. The system of claim 1 wherein the at least one subterranean conduit extends adjacent to two or more wells and is at least substantially isolated from any production wells or injection wells.
12. The system of claim 1 wherein the at least one subterranean conduit comprises at least one induced fracture at least substantially isolated from the surface and from the surface-connected well.
13. The system of claim 1 wherein the at least one subterranean conduit comprises at least one acidized wormhole at least substantially isolated from the surface and from the surface-connected well.
14. The system of claim 1 wherein the subterranean conduit is configured to have a higher permeability than the formation in which it is disposed.
15. The system of claim 14 wherein the subterranean conduit is configured to have a higher permeability by dissolving formation material.
16. The system of claim 14 wherein the subterranean conduit is configured to have a higher permeability by mechanically disturbing formation material.
17. The system of claim 14 wherein the subterranean conduit is configured to have a higher permeability by hydraulically disturbing formation material.
18. The system of claim 1 wherein the at least one subterranean conduit is configured to alter a subterranean flow field around the surface-connected well.
19. The system of claim 1 wherein the subterranean conduit comprises at least a portion of a previously drilled directional well at least substantially isolated from the surface and from the surface-connected well; wherein the previously drilled directional well was used as a production well or an injection well prior to being converted to a subterranean conduit.
20. A method of altering fluid flow in a subterranean formation, the method comprising: configuring a surface-connected well to participate in hydrocarbon-production operations, wherein the surface-connected well extends from a surface into a formation; providing a subterranean conduit in the formation into which the surface-connected well extends; wherein the subterranean conduit is at least substantially isolated from the surface-connected well; and isolating the subterranean conduit from the surface.
21. The method of claim 20 further comprising gravel packing the subterranean conduit prior to isolating the conduit from the surface.
22. The method of claim 20 further comprising providing fluid communication between the conduit and the formation prior to isolating the conduit from the surface.
23. The method of claim 20 wherein providing a subterranean conduit comprises providing at least one induced fracture at least substantially isolated from the surface and from the surface-connected well.
24. The method of claim 20 wherein providing a subterranean conduit comprises providing at least one acidized wormhole at least substantially isolated from the surface and from the surface-connected well.
25. The method of claim 20 wherein providing a subterranean conduit comprises drilling a directional wellbore into the formation; wherein the directional wellbore is at least substantially isolated from the surface-connected well.
26. The method of claim 20 wherein the subterranean conduit is configured to alter a subterranean flow field around one or more surface-connected wells.
27. The method of claim 20 wherein providing a subterranean conduit comprises completing the conduit to have a permeability higher than the formation in which the conduit is formed.
28. The method of claim 27 wherein completing the conduit comprises dissolving formation material.
29. The method of claim 27 wherein completing the conduit comprises mechanically disturbing formation material.
30. The method of claim 27 wherein completing the conduit comprises hydraulically disturbing formation material.
31. The method of claim 27 wherein completing the segment comprises providing one or more responsive completion elements in the conduit.
32. The method of claim 27 wherein completing the segment comprises providing one or more autonomous completion elements in the conduit.
33. The method of claim 20 wherein the subterranean conduit is provided adjacent to one or more production wells and is at least substantially isolated from all of the production wells.
34. The method of claim 20 wherein the subterranean conduit is provided adjacent to at least one production well and adjacent to at least one injection well and is at least substantially isolated from all production wells and injection wells.
35. The method of claim 20 wherein the surface-connected well is a production well, and wherein providing the subterranean conduit occurs after the production well has begun production.
36. The method of claim 25 wherein the directional wellbore is used as an injection well or a production well prior to having at least a portion thereof at least substantially isolated from the surface to form the subterranean conduit.
37. A method of operating a hydrocarbon producing well, the method comprising: configuring a production well to produce hydrocarbons, wherein the production well extends from a surface into a formation, and wherein the production well induces an initial flow field in the formation; providing a subterranean conduit in the formation into which the production well extends, wherein the subterranean conduit does not intersect the producing well; and configuring the subterranean conduit to induce an altered flow field in the formation relative to the initial flow field induced by the production well.
38. The method of claim 37 wherein the subterranean conduit traverses at least two reservoirs.
39. The method of claim 37 wherein configuring the subterranean conduit comprises gravel packing the subterranean conduit.
40. The method of claim 37 wherein configuring the subterranean conduit comprises providing fluid communication between the conduit and the formation.
41. The method of claim 37 wherein configuring the subterranean conduit comprises providing at least one induced fracture at least substantially isolated from the surface and from the production well.
42. The method of claim 37 wherein configuring the subterranean conduit comprises providing at least one acidized wormhole at least substantially isolated from the surface and from the production well.
43. The method of claim 37 wherein configuring the subterranean conduit comprises completing the conduit to have a permeability higher than the formation in which the conduit is formed.
44. The method of claim 43 wherein completing the conduit comprises dissolving formation material.
45. The method of claim 43 wherein completing the conduit comprises mechanically disturbing the formation material.
46. The method of claim 43 wherein completing the conduit comprises hydraulically disturbing the formation material.
47. The method of claim 43 wherein completing the conduit comprises providing one or more responsive completion elements in the conduit.
48. The method of claim 43 wherein completing the conduit comprises providing one or more autonomous completion elements in the conduit.
49. The method of claim 37 further comprising providing an injection well spaced from the production well, and configuring the subterranean conduit induces an altered flow field in the formation directing injected fluids along preferred paths between the injection well and the production well.
50. The method of claim 37 further comprising producing hydrocarbons from the production well.
51. The method of claim 50 further comprising fluidically connecting the subterranean conduit and the production well after producing hydrocarbons from the production well influenced by the altered flow fields
52. The method of claim 37 wherein the subterranean conduit is provided after the production well has begun production.
53. The method of claim 37 wherein the subterranean conduit is provided by isolating a portion of a previously used production or injection well from the surface and from the production well to convert the previously used production or injection well portion into a subterranean conduit.
54. A method of operating a hydrocarbon producing well, the method comprising: configuring a production well to produce hydrocarbons, wherein the production well extends from a surface into a formation, and wherein the production well induces an initial flow field in the formation; providing a subterranean conduit in the formation into which the production well extends, wherein the subterranean conduit does not intersect the producing well; configuring the subterranean conduit to induce an altered flow field in the formation relative to the initial flow field induced by the production well; and producing hydrocarbons from the production well.
55. The method of claim 54 further comprising providing an injection well spaced from the production well and in operative association with, but not intersecting, the subterranean conduit; and injecting a fluid into the formation through the injection well.
56. The method of claim 54 further comprising fluidically connecting the subterranean conduit and the production well after producing hydrocarbons from the production well influenced by the altered flow fields
PCT/US2009/041970 2008-06-04 2009-04-28 Inter and intra-reservoir flow controls WO2009148723A1 (en)

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