METHOD FOR DRILLING AND FRACTURE TREATING MULTIPLE WELLBORES

Abstract

A method includes completing multiple wellbores in a subsurface formation. The method includes a first wellbore having been drilled along a first selected trajectory through the subsurface formation. The first wellbore is fracture treated. A second wellbore is drilled along a second selected trajectory through the subsurface formation. The second trajectory is laterally spaced from the first trajectory. The second wellbore is fracture treated. A third wellbore is drilled along a third selected trajectory through the subsurface formation. The third trajectory is disposed between the first and second trajectories. The third wellbore is fractured treated such that a fracture network extending therefrom hydraulically connects to fracture networks extending from the first and second wellbores and hydraulically connects the first, second and third wellbores proximate an upper end thereof so that the first, second and third wellbores may all produce fluids.

Claims

1. A method for drilling and completing multiple wellbores in a subsurface formation, comprising: fracture treating a third lateral wellbore extending from a bend in a pilot wellbore to a selected length along a third selected trajectory through the subsurface formation, the fracture treating performed such that a fracture network extending from the third lateral wellbore hydraulically connects respective fracture networks extending from a first lateral wellbore and a second lateral wellbore, the fracture network hydraulically connecting the first lateral wellbore, the second lateral wellbore and the third lateral wellbore; wherein the first lateral wellbore is drilled along a first selected trajectory through the subsurface formation from the pilot wellbore or a different pilot wellbore, the first lateral wellbore fracture treated to a position proximate a bend from the pilot wellbore or the different pilot wellbore to the first selected trajectory, the first wellbore being plugged; wherein the second lateral wellbore is drilled along a second selected trajectory through the subsurface formation from the pilot wellbore or a different pilot wellbore, the second lateral wellbore fracture treated to a position proximate a bend from the pilot wellbore or the different pilot wellbore to the first selected trajectory, the first wellbore being plugged; wherein the third wellbore is drilled along the third selected trajectory through the subsurface formation, the third selected trajectory disposed between the first and second trajectories.

2. The method of claim 1 wherein the first, second and third lateral wellbores are drilled from a same pilot wellbore.

3. The method of claim 1 wherein the respective trajectory of each of the first, second and third lateral wellbores substantially follows a bedding plane of the subsurface formation.

4. The method of claim 1 wherein the respective trajectory of each of the first, second and third lateral wellbores is substantially horizontal through the subsurface formation.

5. The method of claim 1 wherein the first and second lateral wellbores being plugged comprise having set a respective plug therein at a wellbore depth above the subsurface formation.

6. The method of claim 1 wherein at least one of the first and second lateral wellbores is flowed back and cleaned up after fracture treatment.

7. The method of claim 6 wherein the flow back and cleanup is performed prior to plugging.

8. The method of claim 6 wherein the flow back and cleanup is performed after plugging.

9. The method of claim 1 wherein at least one of the first lateral wellbore and the second lateral wellbore produces fluid from the subsurface formation prior to the fracture treating the third lateral wellbore.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] FIG. 1 shows a plan view of a multiple lateral wellbore.

[0010] FIG. 1A shows a multiple lateral wellbore after fracture treatment.

[0011] FIG. 2 shows drilling a first wellbore according to the present disclosure.

[0012] FIG. 3 shows fracture treating the first wellbore.

[0013] FIG. 4 shows abandoning the first wellbore and drilling a second wellbore.

[0014] FIG. 5 shows fracture treating the second wellbore.

[0015] FIG. 6 shows abandoning the second wellbore and drilling a third wellbore generally disposed between the first and second wellbores.

[0016] FIG. 7 shows fracture treating the third wellbore to connect the fracture networks created in the first and second wells.

[0017] FIG. 8 shows fracturing the third wellbore within the bend from the “pilot” well to the lateral wellbore so as to hydraulically connect the first, second and third wellbores to the pilot wellbore.

DETAILED DESCRIPTION

[0018] FIG. 2 shows an initial element in creating a reservoir drainage network in a subsurface formation. A first lateral wellbore 1 may be drilled from a selected surface location, substantially as explained in the Background section herein, into a target subsurface formation 10. The first lateral wellbore 1 may be a lateral or horizontal wellbore drilled from an existing or concurrently drilled substantially vertical wellbore 4 from the selected surface location. The existing or concurrently drilled wellbore 4, known as a “pilot wellbore” may also be inclined from vertical. For purposes of defining the scope of the present disclosure, the term “lateral” as used herein to describe a wellbore trajectory means that the wellbore trajectory generally remains within a selected subsurface formation that may extend along a determinable geologic inclination angle (dip), and generally extends a selected horizontal distance from the surface location. The trajectory of any lateral wellbore (or lateral portion of a wellbore that is initially drilled substantially vertically) may therefore be horizontal or may be inclined, depending on the geologic structure of the subsurface formation through which the lateral wellbore or portion thereof is drilled. The position in the pilot wellbore 4 at which directional drilling commences to extend into the first lateral wellbore 1 may be referred to as a “curve” 4A.

[0019] In FIG. 3, the first lateral wellbore 1 may be hydraulically fracture treated after drilling is completed to create a first fracture network 1A extending laterally into the target subsurface formation 10 from the first lateral wellbore 1. The first fracture network 1A may be generally transversely oriented with respect to the longitudinal axis of the first lateral wellbore 1, and may follow the geologic structure of the target subsurface formation 10. In FIG. 4, the first lateral wellbore 1 may be abandoned, such as by plugging. Plugging may be performed by setting a first wellbore plug 5, e.g., a mechanically operated, radially expanding seal element, at a selected depth in the first wellbore 1, followed by inserting cement into a portion of the first lateral wellbore 1 above the first wellbore plug 5. The first wellbore plug 5 may be set at a wellbore depth shallower than the wellbore depth of the first fracture network 1A, but below the bottom of the vertical portion of the wellbore (e.g., the pilot wellbore 4) extending from the surface location so that other lateral wellbores may be drilled from the same surface location, e.g., the pilot wellbore 4. “Wellbore depth” as used in the present context may be understood as the length along the first lateral wellbore 1 from the surface location. Such length is known in the art as “measured depth.” As will be appreciated by those skilled in the art, “measured depth” of a wellbore is directly related to the vertical depth of the wellbore if the trajectory is essentially vertical, but a horizontal portion of such a wellbore may sustain substantially no change in vertical depth, while the length or measured depth increases with wellbore length.

[0020] In the present example, the first lateral wellbore 1 may be fracture treated from a selected depth therein (e.g., close to the total measured depth) to a position very close (within several tens of meters) to the bend 4A from the vertical wellbore 4 to the first lateral wellbore 1. Thus, only a small distance between the fracture treated part of the first lateral wellbore 1 and the vertical wellbore 4 exists.

[0021] After plugging the first lateral wellbore 1 a second lateral wellbore 2 is drilled, which may also be drilled into another part of the target formation 10. The second lateral wellbore 2 may also generally follow the geologic structure of the target formation 10, and may laterally displaced from the first lateral wellbore 1 by a selected lateral distance and extend generally parallel to the first lateral wellbore 1. The selected lateral distance between the first wellbore 1 and the second wellbore 2 may be selected such that the fracture network 1A extending from the first wellbore 1 does not connect directly to a fracture network (explained below) that may be created in the second lateral wellbore 2. The second lateral wellbore 2 may be directionally drilled so as to create a second bend 4B in the pilot wellbore 4 if the second lateral wellbore 2 is drilled from the same pilot wellbore 4 or a different pilot wellbore (not shown).

[0022] In FIG. 5, after drilling the second lateral wellbore 2 through the target formation 10 is completed, the second lateral wellbore 2 may be hydraulically fracture treated to create a second fracture network 2A extending laterally from the second lateral wellbore 2, similar in orientation and extent with respect to the second lateral wellbore 2 as the first fracture network 1A with respect to the first lateral wellbore 1.

[0023] In FIG. 6, the second wellbore 2 may be abandoned, such as by plugging (e.g., setting a second wellbore plug 5A and cementing above the second wellbore plug 5A). A third lateral wellbore 3 may then be drilled through the target formation 10. Just as for the first wellbore 1, the second wellbore 2 may be fracture treated to a distance close to the substantially vertical wellbore 4.

[0024] The third lateral wellbore 3 may be drilled along the target formation 10 in a lateral position between the first and second fracture networks 1A, 2A created previously by fracture treating the first 1 and second 2 lateral wellbores, respectively. The third lateral wellbore 3 may have a bend 4C where the trajectory of the third lateral wellbore 3 is turned from the pilot wellbore 4 trajectory to the lateral trajectory in the target formation 10.

[0025] In FIG. 7, the third lateral wellbore 3 may be hydraulically fracture treated such that a third fracture network 3A is generated. The third fracture network 3A may hydraulically connect the first 1A and second 2A fracture networks. Thus, the target formation 10 may be in hydraulic communication with the entire drainage area of the three fracture networks 1A, 2A, 3A, respectively, while being hydraulically connected to only one wellbore, that being the third lateral wellbore 3 in the present example. Fluids such as oil and/or gas may be extracted from the target formation 10 using the connected wellbore, e.g., the third lateral wellbore 3 in the present example.

[0026] Any or all of the first 1, second 2 and third 3 lateral wellbores may be completed in the target formation 10 prior to hydraulic fracture treating by cementing in place therein a pipe such as a casing or liner followed by perforation of the liner or casing within the target formation 10, that is, where each lateral wellbore traverses the target formation 10. The lateral wellbores 1, 2, 3 may also be completed using a slotted pipe or liner, or may be “open hole” completed such as by filling the respective lateral wellbores 1, 2, 3 with gravel or similar material that creates a high permeability fluid conduit. As will be appreciated by those skilled in the art, the completion technique used in any particular lateral wellbore may depend on the mechanical properties of the target formation 10 and the type of fracture treatment used to create the respective fracture networks 1A, 2A, 3A

[0027] Depending on the composition and structure of the target formation 10, the first 1 and/or second 2 lateral wellbores may be hydraulically connected to equipment (not shown) at the surface for the purpose of flow back and well cleanup procedures known in the art to be associated with fracture treatment of wellbores. The timing of such flow back and cleanup procedures may be such that the first and second well plugs 5, 5A, respectively, are removed from the first 1 and/or second 2 lateral wellbores to enable such procedures. Alternatively, the first 1 and/or second 2 lateral wellbores may be flowed back and cleaned up prior to setting the plugs, 5, 5A, respectively.

[0028] In some examples, any two or all of the three lateral wellbores described above may be drilled from a common or “pilot” vertical wellbore, e.g., pilot wellbore 4 drilled to a selected depth above the target formation 10. Non-limiting example procedures and devices for drilling multiple lateral wellbores from a single pilot wellbore are described in U.S. Pat. No. 5,785,133 issued to Murray et al. and in U.S. Pat. No. 5,735,350 issued to Longbottom et al.

[0029] In the present example, and referring to FIG. 8, the third lateral wellbore 3 may be hydraulically fracture treated along its length in the lateral portion thereof (i.e., in the target formation 10) to a position close to or even in the bend 6 from the substantially vertical wellbore 4 to the lateral portion of the third wellbore 3. Because the first wellbore 1 and the second wellbore (2 in FIGS. 2 through 6) have been fracture treated to a position proximate the bend 6 as explained above, by fracture treating the third wellbore proximate to or in the bend 6, the first 1, second (2 in FIGS. 2 through 7) and third 3 lateral wellbores may be placed in hydraulic communication with each other. Because the first 1 and second (2 in FIG. 7) lateral wellbores have previously been filled with permeable material and/or flowed back and cleaned up prior to setting the first and second well plugs (5, 5A, respectively), the first 1 and second (2 in FIG. 10) lateral wellbores will provide a permeable connection to the target formation (10 in FIGS. 2 through 7). The permeable connection provided by the first 1 and second (2 in FIG. 7) lateral wellbores may be hydraulically connected to the third lateral wellbore 3 by fracture treating as explained above, such that all three lateral wellbores 1, 2 in FIG. 7, 3 may produce fluids from the target formation (10 in FIG. 7). The illustration in FIG. 8 shows the first 1 and third 3 lateral wellbores extending laterally away from each other; this is for purposes of illustrating the principle of the present example method and it not intended to limit the scope of trajectories of any lateral wells drilled according to the present disclosure.

[0030] It will be appreciated by those skilled in the art that the particular order in which the lateral wells are drilled, i.e., the first, second and third lateral wellbores as described above is not required in order for the method to work. The lateral wellbores may be drilled and fracture treated in any order. It is convenient in cases where all the lateral wells are drilled from a common pilot wellbore to perform the method in the order as described above, but it is not required, just as it is not required to drill all the lateral wellbores from the same pilot wellbore. In other embodiments, for example, the first and second lateral wellbores may be pre-existing lateral wellbore that have been completed and fracture treated as explained with reference to FIG. 1. In some embodiments, the first and second lateral wellbores may have already been producing fluids, e.g., oil and/or gas prior to commencement of construction of the third lateral wellbore.

[0031] A method for drilling and fracture treating multiple lateral wellbores according to the present disclosure may provide production rates close to those of multiple lateral wellbores known in the art while eliminating the need to provide a multilateral junction between the multiple lateral wellbores and a pilot wellbore.

[0032] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.