Drilling a multilateral closed-loop geothermal well

Abstract

A method performed on a wellbore system with a first surface wellbore extending from a terranean surface to a subterranean zone, a second surface wellbore extending from the terranean surface to the subterranean zone and a plurality of connecting wellbores in the subterranean zone each connecting the first and second surface wellbores. A lateral wellbore is drilled using a drill string extending through the first surface wellbore. While drilling, flow of drilling fluid from the drill string is sealed against returning towards the first surface wellbore through the connecting wellbores.

Description

DRILLING A MULTILATERAL CLOSED-LOOP GEOTHERMAL WELLTECHNICAL FIELD

[0001] This disclosure relates to closed-loop geothermal systems, including constructing geothermal wells.BACKGROUND

[0002] Closed-loop geothermal systems include a working fluid circulated between a subsurface well in a subterranean zone and a surface facility. The working fluid absorbs heat from the subterranean zone, which can be harvested to produce electricity, heat or for other applications. The system is closed-loop in that the system is constructed to limit, and ideally prevent, exchange of fluids with the surrounding formation(s) of the subterranean zone. Thus, the working fluid flows from the surface to the subterranean zone, is heated in the subterranean zone, is flowed back to the surface where heat is extracted from the working fluid, and then the working fluid is flowed back to the subterranean zone. When the subsurface well is a multilateral, the loop nature of the well introduces difficulties in drilling. Among those difficulties is managing the flow of drilling fluid back to the surface.SUMMARY

[0003] This disclosure relates to closed-loop geothermal systems, including constructing geothermal wells.

[0004] Certain aspects encompass a method performed on a wellbore system comprising a first surface wellbore extending from a terranean surface to a subterranean zone, a second surface wellbore extending from the terranean surface to the subterranean zone and a plurality of connecting wellbores in the subterranean zone each connecting the first and second surface wellbores. A lateral wellbore is drilled using a drill string extending through the first surface wellbore. While drilling, flow of drilling fluid from the drill string is sealed against returning towards the first surface wellbore through the connecting wellbores.

[0005] Certain aspects encompass a system that includes a first surface wellbore extending from a terranean surface into a subterranean zone, a second surfacewellbore extending from the terranean surface into the subterranean zone, and a plurality of connecting wellbores each connecting the first and second surface wellbores. A lateral wellbore is being drilled using a drill string extending through the first surface wellbore. A seal is provided in one of the wellbores. The seal seals against flow of drilling fluid from the drill string returning to the first surface wellbore through the connecting wellbores.

[0006] Certain aspects encompass a method in which a lateral wellbore is drilled from a first surface wellbore, where the first surface wellbore coupled to a second surface wellbore by a plurality of connecting wellbores. While drilling, the return of drilling fluid to the first surface wellbore from the lateral wellbore through the connecting wellbores is sealed against.

[0007] The aspects above can include some, none or all of these additional features. In certain instances, drilling the lateral wellbore can begin by drilling through a side wall of the first surface wellbore uphole from the connecting wellbores. The sealing then includes sealing the bore of the first surface wellbore uphole from the connecting wellbores. In certain instances, the bore of the first surface wellbore is sealed downhole from the beginning of the lateral wellbore. The sealing can be accomplished by placing a whipstock with a seal in the first surface wellbore.

[0008] In certain instances, a second lateral wellbore is drilled using a second drill string extending through the second surface wellbore towards the first mentioned wellbore. The first and second surface wellbores can reside at the same wellsite. Drilling the second lateral wellbore can include drilling the second lateral wellbore parallel to and extending in the same direction as the first mentioned lateral wellbore, and joining the first mentioned lateral wellbore and the second lateral wellbore at an intersection of the lateral wellbores. The annulus is sealed around the second drill string, and fluid flow is controlled out of an annulus port from the annulus around the second drill string at a flow rate based on a flow rate of drilling fluid supplied through the second drill string.

[0009] In certain instances, the lateral wellbore is begun by drilling through a sidewall of one of the connecting wellbores and the sealing is between the beginning of the lateral wellbore and one or more of the connecting wellbores.

[0010] Other features and aspects are described below.BRIEF DESCRIPTION OF DRAWINGS

[0011] FIG. 1A is a schematic side cross-sectional view of an example closed- loop geothermal system in accordance with the concepts herein.

[0012] FIG. IB is a schematic side cross-sectional view of another example closed-loop geothermal system in accordance with the concepts herein.

[0013] FIG. 2A is a schematic side cross-sectional view of a mother bore wellbore configuration being drilled.

[0014] FIG. 2B is a schematic side cross-sectional view of the mother bore configuration of FIG. 2A being drilled according to the concepts herein.

[0015] FIG. 3A is a schematic top cross-sectional view of a split fishbone wellbore configuration being drilled.

[0016] FIG. 3B is a schematic top cross-sectional view of the split fishbone wellbore configuration of FIG. 3A being drilled according to the concepts herein.

[0017] FIG. 4A-E show an example seal tool in various states of operation.

[0018] FIG. 5A-C show another example seal tool deployed via a bottom hole assembly.

[0019] Like reference numbers in the drawings represent like elements.DETAILED DESCRIPTION

[0020] In closed-loop geothermal systems, a working fluid is circulated within a closed loop that includes a subsurface well and a (typically) surface facility. The working fluid is heated by the Earth surrounding the well, and then circulated to the surface, where the surface facility extracts heat from the working fluid. In certain instances, the facility includes a heat exchanger for extracting heat and conveying that heat into a related process such as an Organic Rankine Cycle or other heat cycle that generates electricity, a district heating plant, a steam generation process, or another process. In certain instances, the process directly uses the heated working fluid, such as by passing it through an expander (e.g., a turbine) that drives an electric generator or directly using the working fluid in an industrial, agricultural or residential process. In closed-loop systems, the primary heat transfer between the working fluid and the Earth (rock) surrounding the well is conductive. Therefore, the well is drilled in an impermeable (entirely or substantially) subterranean zone, sealed to prevent (entirely or substantially) comingling of the working fluid and the natural fluids in the formation (for example, groundwater) or both.

[0021] In certain instances, the closed loop well is configured with two surface wellbores, an inlet wellbore and an outlet wellbore, coupled by one or more connecting wellbores each connecting the first and second surface wellbores. The well can be constructed by drilling the surface wellbores, and then by drilling the connecting wellbores as intersecting lateral wellbores drilled from each of the surface wellbores. As discussed in more detail below, the intersecting lateral wellbores can be drilled in a motherbore configuration or in a fishbone configuration. In either instance, however, once a first pair of laterals are drilled and intersected, there is a connecting wellbore hydraulically connecting the inlet wellbore and the outlet wellbore. When drilling subsequent pairs of connecting laterals, the completed connecting wellbore provides an alternate flow path for the cuttings laden drilling fluid that results from drilling the subsequent pairs of laterals. The alternate flow path reduces the volume and flow rate of the drilling fluid flowing uphole from the wellbore being drilled through the drill string annulus in the surface wellbore. This reduced volume and flow rate thus reduces the tendency of the flowing drilling fluidto carry the cuttings to the surface and reduces the ability to remove the cuttings from the wellbores. The concepts herein address this alternate path. In certain instances, the alternate path is addressed by sealing against the flow of drilling fluid returning towards the surface wellbores through the connecting wellbores. In certain instances, managed pressure drilling techniques are used to control the pressure in the connecting wellbores to reduce drilling fluid flow into the connecting wellbores. More detail on both techniques is provided below.

[0022] Turning now to FIG. 1A, FIG. 1A shows an example closed-loop geothermal system 100 in schematic, side cross-sectional view in accordance with the concepts herein. In certain instances, the closed-loop geothermal wellbore system can be, for example, a system such as that developed by Eavor Technologies Inc. of Calgary, Alberta, which includes a network of sealed lateral wellbores that exchange heat with the subterranean zone.

[0023] System 100 includes a geothermal well 102 drilled into the Earth through a geothermal subterranean zone of interest 104. In certain instances, the subterranean zone is a dry, impermeable (matrix permeability of 0. 1 millidarcy or less) formation, portion of formation or multiple formations having little to no naturally occurring recoverable fluids. In certain instances, the subterranean zone is in a crystalline basement formation. In certain instances, the rock of the subterranean zone is in a granitic formation (e.g., granite). In the illustrated instance, well 102 includes an inlet surface wellbore 120 and an outlet surface wellbore 130 in close proximity, each extending between the terranean surface and the subterranean zone 104. The inlet surface wellbore 120 and outlet surface wellbore 130 are connected within the subterranean zone 104 by one or more connecting wellbores 140. In the illustrated instance, connecting wellbores 140 define a multilateral pattern of wellbores, including a plurality of pairs of lateral wellbores 150, a subset of which are kicked off from the inlet wellbore 120 and a subset of which are kicked off from the outlet wellbore 130. The pairs of lateral wellbores 150 each intersect at a respective junction 154 at or near their respective toes. Thus, the inlet wellbore 120, outlet wellbore 130 and connecting wellbores 140 define a closed loop.

[0024] The inlet wellbore 120 and the outlet wellbore 130 can be drilled from the same drilling pad and / or reside on the same well site. In certain instances, the wellbores 120, 130 are drilled within 10, 25, 50 or 100 meters of one another. Inother instances, the inlet surface wellbore 120 and the outlet surface wellbore 130 can be separated by a longer distance. For example, FIG. IB, discussed in more detail below, shows a configuration where the surface wellbores 120, 130 and the connecting wellbores 140 define a U-shape configuration. In certain instances, the inlet surface wellbore 120 and the outlet surface wellbore 130, when the geothermal well 102 is configured as a U-shape, are drilled 3,000 meters or more apart.

[0025] In the illustrated instance, inlet surface wellbore 120 and outlet surface wellbore 130 are vertical wellbores, drilled substantially straight (i.e., without the use of directional drilling methods or equipment). In other instances, one or both of the surface wellbores are other than vertical (e.g., slanted) and / or may be drilled with the use of directional drilling techniques. The connecting wellbores 140 are drilled using directional drilling techniques through the surface wellbores 120, 130, and include a curve in their trajectory beginning at a kickoff 148 at surface wellbores 120, 130. Although shown as slanted downward, in some instances, some or all of the connecting wellbores are horizontal. In some instances, the connecting wellbores 140 follow the geological dip of the formation in the subterranean zone. In some instances, lateral wellbores 150 are anywhere from 2,000 meters to 10,000 meters or more in length and from 1,000 meters to 8,000 meters or more in depth from the surface.

[0026] FIG. 1A shows each pair of lateral wellbores 150 parallel to one another extending in the same direction (azimuth) from their respective surface wellbore 120, 130. The lateral wellbores 150 extending from the inlet surface wellbore 120 are shown above the lateral wellbores 150 extending from the outlet surface wellbore 130. In some instances, the upper lateral wellbores 150 are directly above their (and are, in some instances, directly above a respective one of the lower lateral wellbores 150. In FIG. 1A the upper lateral wellbores 150 each turn to intersect its adjacent lower lateral wellbore 150 pair at the junction 154 to connect the surface wellbores 120, 130. In other instances, one or more of the lower lateral wellbores 150 could intersect the upper lateral wellbores 150. Regardless, the configuration of connecting wellbores 140, one set atop the other defines a stacked wellbore pattern, with one sub-pattern of wellbores above and one sub-pattern of wellbores below. In certain instances, one or more additional sets of stacked patterns can be drilled from the surface wellbores 120, 130 at different depths (i.e., with different kickoffs 148). InFIG. 1A, the lower lateral wellbores 150 extend past and below the junction 154 to define a sump 152. The sump 152 provides a location for debris to accumulate outside of the flow path through the wellbores. In other instances, one or more of the upper lateral wellbores 150 could extend past the junction to define the sump 152.

[0027] FIG. IB another embodiment of a geothermal well system 100’ having lateral wellbores 150 extending, respectively, from the inlet and outlet surface wellbores 120, 130 toward one another. The pairs of lateral wellbores 150, once intersected, together with the inlet and outlet wellbores 120, 130, define a generally U-shape. The configuration of connecting wellbores 140 defines a pattern of wellbores, in certain instances, in the same plane. In certain instances, one or more additional patterns of connecting wellbores can be drilled between the surface wellbores 120, 130 at different depths (i.e., with different kickoffs 148).

[0028] Referring to FIGS. 1A and IB, collectively, In some instances, the surface wellbores 120, 130 are cased (at least partially or entirely), and the connecting wellbores 140, including the junctures at the kickoffs 148 are open hole (i.e., without casing or liner or a junction liner). In some instances, the connecting wellbores 140 can be at least partially lined (e.g., include a liner or casing in those portions where the subterranean zone 104 is fractured, susceptible to collapse, unconsolidated or otherwise needing a liner). The connecting wellbores 140, including the junctures to the inlet and outlet surface wellbores 120, 130 are sealed (entirely or substantially) with a sealant against exchange of fluids with the surrounding subterranean zone 104. The sealant is designed such that all or substantially all of the working fluid circulated through the well 102 during operation is recovered to the surface, and no or little naturally occurring fluids from the subterranean zone 104 are recovered. In other words, the resulting well 102 is closed loop. In certain instances, the sealant can be applied to the wellbores during drilling the connecting wellbores 140, e.g., included in the drilling fluid and / or supplied in fluid slugs distinct from the drilling fluid. Alternatively or additionally, the sealant is applied after drilling and / or during operation of the well. In certain instances, the sealant can be included in the heat transfer working fluid and / or supplied in fluid slugs, distinct from the heat transfer working fluid.

[0029] In the illustrated instance, system 100 further includes a facility 110 disposed between inlet surface wellbore 120 and outlet surface wellbore 130. Well102 can be sealed and a working fluid added to the closed loop and circulated in the system such that it absorbs heat from subterranean zone 104. In certain instances, facility 110 includes valves and pumps for controlling the flow of the working fluid through the well 102, as well as a heat exchanger for extracting the heat from the working fluid and conveying it into a related process, such as a Rankine cycle (e.g., Organic Rankine Cycle) or other heat cycle that generates electricity, a steam generation process for industrial, agricultural or residential use, or another process. In certain instances, instead of, or in addition to a heat exchanger, facility 110 directly uses the heated working fluid, such as by passing it through an expander (e.g., a turbine) that drives a electric generator or directly using the heat of the working fluid in an industrial, agricultural or residential process. In some instances, facility 110 is disposed at or near the Earth’s surface; in other instances, facility 110 may be disposed partially or fully within a subsurface location. The facility 110 need not be housed in one location, and, for example as shown in FIG. IB, it can be split between one or more discrete locations (shown as facility 110a, 110b) connected by piping.

[0030] FIGS. 2A and 2B are examples of a well 200 during construction shown in cross-section. The configuration shown in FIGS. 2A and 2B can be referred to as a mother bore configuration, where multiple lateral wellbores are drilled from a common “mother” wellbore. In FIGS. 2A and 2B, the inlet wellbore 202 and the outlet wellbore 204 are mother bores, each having multiple connecting wellbores 206. The connecting wellbores 206 are drilled as intersecting lateral wellbores 208 from the inlet wellbore 202 and the outlet wellbore 204. In particular, each connecting wellbore 206 is constructed as a lateral wellbore 208 beginning at the sidewall of the inlet wellbore 202, i.e., kicking off from the inlet wellbore 202, and a lateral wellbore 208 beginning at the sidewall of the outlet wellbore 204, i.e., kicking off from the outlet wellbore 204. The lateral wellbores 208 are drilled to intersect at a junction 210. The wells of FIGS. 1A and IB can be constructed, in part or entirely, in a mother bore configuration, with surface wellbores 120, 130 as mother wellbores 202, 204 and connecting wellbores 140 as connecting wellbores 206.

[0031] In FIGS. 2A and 2B, the inlet wellbore 202 and outlet wellbore 204 have been finished and are cased (i.e., have a casing 212). These figures show multiple open hole (i.e., without casing or liner) connecting wellbores 206 extending betweenthe inlet wellbore 202 and the outlet wellbore 204, but in certain instances, the connecting wellbores 206 could be partially or wholly lined (i.e., provided with a liner). In certain instances, the junctions 210 between the inlet and outlet wellbores 202, 204 and the connecting wellbore 206 are open hole, but they could alternatively be lined (i.e., provided with a junction liner). The lateral wellbores 208 are shown being drilled from the inlet wellbore 202 and from the outlet wellbore 204. The lateral wellbores 208 are being drilled using directional drilling techniques with a drill string 216 extending from the terranean surface 218 through the inlet wellbore 202 and outlet wellbore 204, respectively. In certain instances, one or both of the wellbores 208 can be drilled using managed pressure drilling techniques. In managed pressure drilling, the pressure, flow rate and type of the fluid (e.g., mud of different densities, liquids of different densities, foam) can be controlled to manage the pressure of the drilling fluid along the wellbore and at the rock face. The inlet and outlet wellbores 202, 204 have an annular seal 220 at the surface 218 to seal the annulus around the drill string 216 in a manner that lets the drill string 216 rotate while being sealed (e.g., a rotating control device, or other device) and an annulus outlet below the annular seal 220 with a valve 224 that allows restricting the returning flow of fluid, thus applying desired pressure to the fluid in the annulus. In typical managed pressure drilling, there is only one surface wellbore. Thus, the pressure in the wellbore being drilled can be controlled by controlling the hydraulic pressure of the fluid in the wellbore by controlling the density of the drilling fluid and by changing the flow restriction of the valve 224. As will be discussed in more detail below, once the first connecting wellbore 206 is completed, having two valves 224, i.e., at the inlet and outlet wellbores 202, 204, adds another degree of control over the pressure and flow path of the drilling fluid through the wellbores.

[0032] The drilling of the inlet and outlet wellbores 202, 204 and connecting wellbores 206 can be conducted sequentially with one drill rig and drill string 216, or concurrently and, in some instances simultaneously, with the two drill strings 216 each operating to drill their respective lateral wellbore 208 at the same time. In some instances, the inlet wellbore 202, the outlet wellbore 204 and the connecting wellbores 206 are drilled with two drilling rigs, one atop the inlet wellbore 202 and one atop the outlet wellbore 204. In other instances, the wellbores are drilled with a single drilling rig configured to drill two wellbores at the same time (e.g., having twomasts, two top drives and / or two rotary tables, etc.). Each drill string 216 includes a string of tubing 226 with a bottom hole assembly (BHA) 228, with the BHA 228 including among other things, a drill bit, a mud motor, and directional drilling tools, such as measurement while drilling (MWD) and logging while drilling (LWD) tools. In certain instances, insulated tubing can be used in the drill string 216 to reduce heating of the drilling fluid flowed to the BHA 228 through the drill string by the surrounding formation, thus cooling the BHA 228 during the drilling operations.

[0033] In certain instances, a whipstock 230 is used to kick off the lateral wellbores 208 from their respective surface wellbore 202, 204. FIG. 2B shows the whipstock 230 being used in the inlet wellbore 202, but it should be understood that when a lateral wellbore 208 is kicked off from the outlet wellbore 204, a whipstock could also be used. The whipstock 230 has slips and / or dogs (not shown), actuable to grip the wall of the wellbore and set the whipstock 230 in a fixed location, or the whipstock 230 is configured to land on a specified profile provided in the casing or liner or the wall of the wellbore. In certain instances, the whipstock 230 is of a type that can be deployed and retrieved on wireline, or it can be of a type deployed and retrieved on tubing (e.g., with a running tool carried into / out of the wellbore on a tubing string), or it can be of a type that is deployed and / or retrieved in another manner. The whipstock 230 includes a wedge shape 232 on its uphole end that, when contacted by the drill bit (or mill bit, if used) drives the drill string 216 into the wall of the wellbore to cause it to deviate from the wellbore and drill in the direction of the lateral wellbore 208. In certain instances, the whipstock 230 is configured to engage with a profile (not shown) in the casing 212 of the wellbore to orient the whipstock 230 in a specified azimuthal direction relative to the wellbore. In certain instances, the whipstock 230 can have a key and the profile corresponding keyway, or vice versa, to effect the azimuthal orientation. The casing 212 in the inlet wellbore 202 and outlet wellbore 204 can be provided with such profiles at each location along the wellbores where a connecting wellbore 206 will be drilled. Whether or not dogs / profiles are used, in certain instances, the casing 212 can be provided with windows (not shown) of material configured to be drilled through (e.g., aluminum, fiberglass, and / or another material) more easily than the surrounding casing. The windows can be provided at each location that a lateral wellbore 208 is anticipated being kicked off. When profiles in the casing 212 are used, the profiles can belocated relative to the windows to precisely place and azimuthally orient the whipstocks to direct the drill string 216 to drill through the windows, thus kicking off the lateral wellbores 208 at the windows.

[0034] The lateral wellbores 208 are drilled beginning with the deepest lateral wellbores 208, sequentially upward to the shallowest lateral wellbores 208. In other words, the lowest lateral wellbores 208 are drilled first, with a lateral wellbore 208 at the lowest position in the inlet wellbore 202 drilled and a lateral wellbore 208 at the lowest position in the outlet wellbore 204 drilled to intersect at a junction 210. Then, the next (second) lowest lateral wellbores 208 are drilled to intersect at a second junction 210, the third lowest lateral wellbores 208 are drilled to intersect at a third junction 210 and so on until all connecting wellbores 206 have been drilled. Thus, once the first lateral wellbores 208 are drilled and intersected, there is a connecting wellbore 206 fluidically connecting the inlet wellbore 202 and the outlet wellbore 204.

[0035] As a lateral wellbore 208 is being drilled, drilling fluid is pumped down the drill string 216 and out through the BHA 228 to the rock face being drilled. One purpose of the drilling fluid is to entrain cuttings from the rock face and carry the cuttings to the terranean surface 218 for removal from the wellbores. The flow of drilling fluid (indicated by arrows) is intended to flow uphole in the annulus between the drill string 216 and the wall of the lateral wellbore 208 being drilled, into the surface bore (e.g., the inlet wellbore 202 or the outlet wellbore 204) and uphole to the surface 218 in the annulus between the drill string 216 and the wall of the surface bore. However, once the lowest connecting wellbore 206 is completed, there is an alternate flow path that hampers cuttings removal. For example, FIGS. 2A and 2B show a lateral wellbore 208 being drilled from the inlet wellbore 202 and three completed connecting wellbores 206 downhole from the lateral wellbore 208 being drilled. If uncontrolled, as in FIG. 2A, a portion of the cutting laden drilling fluid from the lateral wellbore 208 being drilled can flow downhole in the inlet wellbore 202 and through the connecting wellbores 206 into the outlet wellbore 204. The alternate flow paths created by the connecting wellbores 206 reduce the volume and flow rate of the fluid flowing uphole through the annulus in the inlet wellbore 202, reducing the tendency of the flowing drilling fluid to carry the cuttings to the surface 218 and reducing the ability to remove the cuttings from the wellbores. Similarly, thevolume and flow rate of fluid through the connecting wellbores 206, when split between the various wellbores, can be too low to effectively maintain the cuttings entrained in the fluid, causing cuttings to drop out at various locations in the wellbores. The cuttings left in the wellbores can potentially restrict or plug the flow areas, and thus flow, through the well 200. The resulting flow restrictions or blockages can reduce the effectiveness of the completed geothermal well 200 in circulating heat-transfer working fluid. Cuttings not effectively removed from the lateral wellbore 208 being drilled can also bind against the drill string 216, potentially causing the drill string 216 to become stuck in the lateral wellbore 208. The reduced flow rate of the drilling fluid and the potential for inconsistent flow rates of drilling fluid through the alternate flow paths can cause additional problems with the mud pulse telemetry used by the BHA 228 to communicate to the surface 218. Also, the fluid flowing through the connecting wellbores 206 will bring heated fluid into the annulus of the inlet and / or outlet wellbores 202, 204 (to the junction point). The flow of heated fluid will affect the circulation temperature and pseudostatic (between trips) temperature in the annulus and wellbores.

[0036] According to the concepts herein, however, a seal 240 can be placed in the mother wellbore being drilled through (the inlet wellbore 202 in FIGS. 2A and 2B), downhole from the lateral wellbore 208 being drilled, and uphole from all of the completed connecting wellbores 206. The seal 240 seals off (entirely or substantially) the entire bore of the mother wellbore against flow of fluids past the seal 240, sealing off flow to the alternate flow paths created by the completed connecting wellbores 206. In FIG. 2B, the seal 240 is shown in the inlet wellbore 202, sealing against the wall of the inlet wellbore 202, and sealing the bore against flow of the drilling fluid downhole and into the completed connecting wellbores 206 towards the outlet wellbore 204. In certain instances, a similar seal 240 can, alternatively or additionally, be placed in the outlet wellbore 204.

[0037] The sealing need not be perfect, and while the seal 240 can be water tight (substantially or entirely), it can alternatively be configured to simply reduce (partially, substantially, or nearly entirely) the flow towards the connecting wellbores 206. A number of different types of seals can be used. In some instances, the seal 240 is an inflatable seal (e.g., via a hydraulic supply line from the surface to the seal), a mechanically actuated seal (e.g., via shifting a sleeve, piston or movinganother aspect of a structure supporting and carrying the seal), a cup or disk type seal of a diameter equal to or nominally larger than the wellbore diameter, and / or another type of seal. In certain instances, the seal 240 can be biased to be pressure energized by a pressure differential across the seal that is higher uphole than downhole. Thus, when a pressure differential is experienced across the seal 240, the pressure uphole tends to drive the seal to seal more tightly against the wall of the wellbore. For example, in the case of a cup seal, the cups can be oriented with the concave end uphole such that fluid uphole will tend to cause the sidewalls of the cup to press into and seal with the wall of the wellbore.

[0038] In certain instances, the seal 240 is incorporated in a tubing or wireline deployed bridge plug (not shown) having slips actuable to grip the wall of the wellbore, dogs actuable to engage a profde in a casing in the wellbore, or that is configured to land on a specified profile in the casing or liner. The slips and / or dogs to set (i.e., anchor) the bridge plug in a fixed location in the wellbore. The seal 240 can be set in the wellbore and whipstock 230 set above the seal 240. Alternatively, as shown, the whipstock 230 can be configured to carry the seal 240 into the wellbore at the downhole end of the whipstock 230. If the seal is of an actuable type, in certain instances, the whipstock 230 can be configured to actuate the seal 240 to seal the bore. In certain instances, the seal 240 is integral with the whipstock 230 or the whipstock 230 can be configured to releaseably attach to a bridge plug or similar tool having the seal 240. In certain instances, the whipstock 230 is configured so that when its slips or dogs are actuated, the seal 240 is likewise actuated to seal the wellbore and when the whipstock 230 is actuated to release, the seal 240 is likewise actuated to release its seal.

[0039] With the seal 240 in place, the lateral wellbore 208 is kicked off from the mother wellbore, here inlet wellbore 202, and drilled towards the planned location of the junction 210 with the lateral wellbore 208 that was drilled (or is being drilled) from the outlet wellbore 204. Drilling fluid is supplied down the drill string 216, and out through the BHA 228 at the rock face being drilled. The drilling fluid then flows uphole through the annulus in the lateral wellbore 208 being drilled, into the inlet wellbore 202, and to the surface 218 in the annulus in the inlet wellbore 202. The seal 240 prevents or reduces the flow of drilling fluid downhole in the inlet wellbore 202, and into the completed connecting wellbores 206.

[0040] In certain instances, in connection with or as an alternative to sealing the mother bore being drilled through (i.e., omitting seal 240), the pressure and flow rate of fluid in the mother bores can be controlled using managed pressure drilling techniques to reduce or prevent (substantially or entirely) flow of drilling fluid through the alternative flow paths. For example, in FIG. 2A, where drilling is occurring with a drill string extending through the inlet wellbore 202, no fluid is flowed through the drill string 216 in the outlet wellbore 204. The seal 220 around the drill string 216 in the outlet wellbore 204 is sealed and the valve 224 on the annulus port of the outlet wellbore 204 is closed. This prevents drilling fluid from flowing up the outlet wellbore 202, and in turn, pressure will build in the outlet wellbore 202 that also prevents drilling fluid from flowing through the connecting wellbores 206 toward the outlet wellbore 204. The valve 224 on the annulus port of the inlet wellbore 202, however, is open. Thus, all drilling fluid flowed through the drill string 216 in the inlet wellbore 202 returns up the drill string annulus in the inlet wellbore 202 to the surface.

[0041] Drilling can also be performed through both the inlet wellbore 202 and the outlet wellbore 204 concurrently. When both drill strings 216 are drilling, drilling fluid is flowed through both drill strings 216 and up both the inlet wellbore 202 and the outlet wellbore 204. If the flow of drill fluid returned through one surface wellbore (i.e., through its annulus) exceeds the flow of drilling fluid supplied down its corresponding drill string 216, the valves 224 of the annulus ports can be adjusted to balance the flow such that the flow returned through the surface wellbores 202, 204 is equal (approximately or precisely) to the flow of drilling fluid supplied down their corresponding drill string 216. For example, if the flow of drilling fluid received through the annulus port at the inlet wellbore 202 exceeds the flow of fluid down the drill string 216 through the inlet wellbore 202, it is likely due to flow from the drill string 216 through the outlet wellbore 204 being communicated through the connecting wellbores 206 back towards the inlet wellbore 202. To mitigate this, the valve 224 on the annulus port at the inlet wellbore 202 can be adjusted to reduce the flow of fluid out of the inlet wellbore 202 to match (approximately or precisely) the flow of drill fluid down the drill string 216 through the inlet wellbore 202. The valve 224 on the annulus port of the outlet wellbore 204 can be likewise adjusted if the flow of drilling fluid received through the annulus port at the outlet wellbore 202exceeds the flow of drilling fluid down the drill string 216 in the outlet wellbore 204. Alternately, one of the valves 224 (e.g., the valve on the outlet wellbore 204) can remain static and the other valve (e.g., the valve on the inlet wellbore 204) opened to decrease the pressure in the wellbore returning a higher flow than provided through its drill string 216. While this adjustment process can be performed manually, in certain instances, a controller 244 coupled to sensors to receive inputs on flows and pressures in the annuluses and in the drill strings 216 can be provided that is configured to continuously adjust one or both valves based on the difference between the flow down the drill string 216 and the flow returned through its corresponding surface wellbore.

[0042] Turning now to FIGS. 3A and 3B, these figures show an alternate example configuration of well during construction. Except as noted below, this alternate configuration of well is drilled similarly to the configuration of FIGS. 2A and 2B, for example, using directional drilling techniques, using managed pressure drilling techniques, using whipstocks, and, in some instances, drilling currently or simultaneously with two drilling rigs. FIGS. 3A and 3B show a top view of the example well 300, which can be thought of as special case of a dual, half fishbone or split fishbone wellbore configuration.

[0043] The configuration shown in FIGS. 3A and 3B has two half fishbone patterns of wellbores, and thus can be referred to as a dual, half fishbone or split fishbone multilateral pattern. The well configuration shown in FIGS. 3A and 3B, however, is a dual, half fishbone pattern in that the lateral wellbores 208 define a pattern of connecting wellbores 206, each connected to the initial connecting wellbore 208 in two locations (proximate the ends of the initial connecting wellbore) and the initial connecting wellbore 208 is connected to both mother bores 204. Although discussed in connection with a special case of a dual, half fishbone multilateral pattern, the concepts here in are equally applicable to other multilateral patterns.

[0044] As with FIGS. 2A and 2B above, the inlet wellbore 202 and outlet wellbore 204 in FIGS. 3A and 3B have been completed and are cased (i.e., have a casing 212). Connecting wellbores 206 are shown extending between the inlet wellbore 202 and the outlet wellbore 204. For each half fishbone pattern, an initial connecting wellbore 206 is drilled as intersecting lateral wellbores 208 kicking offfrom the inlet wellbore 202 and the outlet wellbore 204, respectively. When the lateral wellbores 208 intersect at their toes, the wellbore becomes a connecting wellbore 206. Then, further connecting wellbores 206 are drilled as intersecting lateral wellbores 208 kicking off from (i.e., through the sidewalls of) the initial connecting wellbore 206. One lateral wellbore 208 is kicked off near the inlet wellbore 202, and one lateral wellbore 208 is kicked off near the outlet wellbore 204, and then the lateral wellbores 208 intersected at their toes. The first half fishbone pattern, shown fully drilled in FIGS. 3 A and 3B, is drilled beginning with the outermost connecting wellbores 206, sequentially inward to the innermost connecting wellbore 206. The second half fishbone pattern, shown being drilled in FIGS. 3 A and 3B, is drilled beginning with the innermost connecting wellbores 206, sequentially outward to the outermost connecting wellbores 206. In FIGS. 3 A and 3B, the first of the half fishbone patterns has been drilled, having six connecting wellbores 206. The initial connecting wellbore 206 of the other, second half fishbone pattern has been drilled. Two further lateral wellbores 208 are shown, each in the process of being drilled through the sidewall of the second half fishbone’s initial connecting wellbore 206. The two further lateral wellbores 208 will eventually intersect at a junction at their toes and become a connecting wellbore 206. In each instance, the junctions between the inlet and outlet wellbores 202, 204 and connecting wellbores 206, respectively, and between the initial connecting wellbores 206 and the further connecting wellbores 206, are open hole. The inlet and outlet wellbores, 202, 204 have a seal 220 at the surface to seal the annulus around the drill strings 216.

[0045] As shown in FIG. 3A, the completed connecting wellbores 206 provide alternate flow paths for the drilling fluid pumped down the drill strings 216 drilling lateral wellbores 208. During drilling, the cuttings laden drilling fluid is intended to flow uphole in the annulus between the drilling string 216 and the wall of the lateral wellbore 208 being drilled, into the surface wellbore having the drilling string 216 (wellbore 204 in FIG. 3 A), and to the surface. However, FIG. 3 A the previously drilled connecting wellbores 206 create a flow path uphole of the lateral wellbores 208 being drilled. Setting a seal 240 below of the lateral wellbore 208 being drilled will not isolate an alternate flow from connecting wellbores 206, as the access point is above the seal 240.. The resulting alternate flow path that hampers cuttingremoval. If uncontrolled, a portion of the cuttings laden drilling fluid from the lateral wellbore 208 being drilled can flow into and through the connecting wellbores 206 and back to the surface wellbore having the drill string 216. As above, this alternate flow path tends to reduce the volume and flow rate of drilling fluid flowing up through the surface wellbore, reducing the ability of the drilling fluid to effectively remove cuttings and the resulting problems discussed above. The flow additionally brings heated fluid into the annulus of the inlet and / or outlet wellbores 202, 204 (to the junction point), which affects the circulation temperature and pseudo-static (between trips) temperature in the annulus and wellbores.

[0046] According to the concepts herein, however, a seal 240 can be placed in the drilled connecting wellbores 206, which together with managed pressure drilling techniques, controls the flow through the alternate flow paths. In FIG. 3B, the seal 240 seals off (partially or entirely) the entire bore of the connecting wellbore 206 where it is placed, to seal against flow between the first half fishbone pattern and the second half fishbone pattern. In FIG. 3B, the seal 240 is positioned at the kickoff of the initially drilled connecting wellbore 206 of the first half fishbone pattern, uphole from all of the connecting wellbores 206 of the first half fishbone pattern and downhole from the surface wellbore having the drilling string 216 (wellbore 204 in FIG. 3B). As discussed above, the seal 240 need not form a perfect water tight seal, can take different forms and can be deployed in different manners. In certain instances, the seal 240 can be integrated with a whipstock 230 or the whipstock 230 can be configured to releasably attach to a bridge plug or similar tool having the seal 240. Additionally, although only one seal 230 is shown in FIG. 3B, one or multiple seals 230 can be placed in the well system. For example, a second seal 230 can be positioned in the connecting wellbores 206, near the outlet wellbore 204.

[0047] With the seal 240 in place, the first connecting wellbore 206 of the second half fishbone pattern is drilled. The lateral wellbore 208 is kicked off from the mother wellbore, here outlet wellbore 204, and drilled towards the planned location of the junction 210 with the lateral wellbore 208 that was drilled (or is being drilled) from the inlet wellbore 202. Subsequent connecting wellbores 206 are drilled similarly, kicking off from the first drilled connecting wellbore 206. In each instance, drilling fluid is supplied down the drill string 216 and out through the BHA 228 at the rock face being drilled. The drilling fluid then flows uphole through the annulusin the lateral wellbore 208 being drilled, into the outlet wellbore 204, and to the surface 218 in the annulus in the outlet wellbore 204. The seal 240 prevents or reduces the flow of drilling fluid downhole from the outlet wellbore 204 and the wellbores of the second half fishbone pattern, and into the drilled connecting wellbores 206 of the first half fishbone pattern. While a portion of the drilling fluid traverses the connecting wellbores 206 of the first half fishbone pattern, and flows into the connecting wellbores 206 of the second half fishbone pattern, it cannot further return to the second half fishbone pattern and recirculate in the connecting wellbores 206 into the drilled connecting wellbores 206 of the second half fishbone pattern. The valve 224 in the outlet wellbore 204 is controlled to allow no more fluid out of the annulus of the outlet wellbore 204 than is supplied down the drill string 216 in the outlet wellbore 204, and the valve in the inlet wellbore 202 is controlled to prevent flow of fluid out of the annulus of the inlet wellbore 202. If drilling is conducted concurrently with a drill string 216 extending through the inlet wellbore 202 and a drill string 216 extending through the outlet wellbore 204, the respective valves 224 can be controlled to allow no more fluid out from the annulus than is supplied down the drill string 216.

[0048] As above, drilling can also be performed through both the inlet wellbore 202 and the outlet wellbore 204 concurrently. If the flow of drill fluid returned through one surface wellbore (i.e., through its annulus) exceeds the flow of drilling fluid supplied down its corresponding drill string 216, the valves 224 of the annulus ports can be adjusted to balance the flow such that the flow returned through the surface wellbores 202, 204 is equal (approximately or precisely) to the flow of drilling fluid supplied down their corresponding drill string 216. Alternately, one of the valves 224 (e.g., the valve on the outlet wellbore 204) can remain static and the other of the valves (e.g., the valve on the inlet wellbore 204) opened to decrease the pressure in the wellbore returning a higher flow than provided through its drill string 216. This adjustment process can be performed manually, or in certain instances, a controller 244 coupled to sensors to receive inputs on flows and pressures in the annuluses and in the drill strings 216.

[0049] Turning now to FIGS. 4A-E, an example seal tool 400 that can be used as seal 240 is described. FIG. 4A is a half cross sectional view of the example seal tool 400. The seal tool 400 includes a cylindrical mandrel 402 with one or more annularseals 404 thereon. The mandrel 402 can additionally include one or more centralizers 406, for example, above and below the seals 404. The seals 404 are depicted as cup seals oriented with their larger diameter uphole, so as to be pressure energized and seal against the wall of the wellbore when pressure above the seals 404 is higher than pressure below the 404. Because of the fact that pressure is higher above the seals than below the seals, the seals 404 are not pressure energized against the wall of the wellbore, and they will allow leakage of fluid from below the seals 404 toward uphole. Although depicted as cup seals, other configurations of seals 404 are contemplated herein, including inflatable, mechanically actuated seals or other types of seals. In other configurations of seals 404, the sealing elements can be omnidirectionally pressure energized against the walls of the wellbore, to restrict the fluid flow in both directions, uphole or downhole the wellbore.

[0050] The mandrel 402 defines an interior bore 408 that extends the length of the mandrel 402. The mandrel 402 includes ports 414 through the sidewall thereof, above the uppermost seal 404 to allow fluid communication between the bore 408 and outside of the tool 400, e.g., an annulus around the tool 400. The upper end of the mandrel 402 is open to receive fluid flow. The lower end of the mandrel 402 includes a float bypass valve 410 in the bore 408.

[0051] The float bypass valve 410 is configured in an initial, first configuration to allow only one-way bypass of fluid from outside of the mandrel 402, beneath the seals 404, uphole through the bore 408 and out through the top of the seal tool 400. The float bypass valve 410 in this first configuration seals against downward, downhole flow through the bore 408 and out of the tool 400 below the seals 404. As shown, the float bypass valve 410 is configured as a pintle 416 that is spring biased by a spring 418 into a lower port 420 through a housing 422 of the float bypass valve 410 to seal the lower port 420. A pressure above a specified threshold from beneath the seals 404 acts through the port 420 to lift the pintle 416 off of the port 420 and allow the flow into the bore 408 and uphole through the mandrel 402. Pressure in the opposite direction, from within the bore 408 downward, acts on the pintle 416 pressing it into sealing with the port 420 and sealing against flow out of the mandrel 402. Although described as a spring biased pintle 416 and port 420, other configurations of float bypass valve 410 are contemplated herein.

[0052] The float bypass valve 410 is changeable to allow omnidirectional bypass flow, to additionally allow flow down through the bore 408 of the mandrel 402, and out of the bottom of the tool 400. As shown, the mandrel 402 has side ports 412 that are covered and sealed by the housing 422 of the float bypass valve 410 when the valve 410 is in the initial, first configuration (i.e., allowing one-way bypass of fluid). The float bypass valve 410 is held in the first configuration by one or more shear pins 428 extending through the wall of the mandrel 402 into a wall of the housing 422 of float bypass valve 410. The configuration is changeable to the second configuration by driving down on the float bypass valve 410 to shear the shear pins 428 and drive the flow bypass valve 410 to drop to a lower shoulder 430 in the mandrel 402. Moving the float bypass valve 410 to the lower shoulder 430 opens the side ports 412 to allow passage of fluid out of the mandrel 402. The float bypass valve 410 can be driven down to shear the shear pins 428 in a number of ways, including via wireline tool (e.g., via jarring), a dedicated running tool on tubing, hydraulically, or in another manner.

[0053] In certain instances, the upper end of the mandrel 402 is threaded or otherwise provided with a profile that would enable the mandrel 402 to be deployed via a wireline tool, via tubing on a running tool, or configured to couple to a whipstock and be deployed with the whipstock. In instances when the tool 400 is deployed apart from a whipstock, it can be provided with an actuable anchor system (e.g., slips, dogs configured to engage a profile in casing, or another manner of anchoring) to fix the tool 400 in position in the wellbore. In certain instances, the mandrel 402 can be integral with a whipstock, for example, having a wedge shaped upper end, as well as an actuable anchor system. In certain instances, the tool 400 can be deployed on a BHA, for example, affixed to the BHA by a shear pin or other actuable release, and provided with an actuable anchor system. Such deployment is useful in circumstances where no whipstock will be used to drill the lateral wellbores.

[0054] FIGS. 4B-4E show the tool 400 in different states of operation, in each instance with a whipstock 424 atop and positioned in a wellbore 426. As noted above, however, deploying the tool 400 apart from a whipstock 424 is also contemplated. FIG. 4B shows the tool 400 as it would operate when drilling operations are being conducted, for example, drilling a lateral wellbore off ofwellbore 426, and while filling down the wellbore 426 when tripping a drill string or other string into the wellbore 426. Fluid flowed down from the surface, into the bore 408 is allowed to flow into the annulus between the tool 400 and wellbore 426 through ports 414, above the seals 404. The float bypass valve 410 seals against flow out of the bore 408, below the seals 404. FIG. 4C shows the tool 400 and whipstock 424 being run into the wellbore 426. Fluid is able to flow from beneath the seals 404, through the float bypass valve 410, into the bore 408 and up through the tool 400 and whipstock 424. Additionally, fluid can flow through ports 414 into the annulus, and if the seals 404 are so configured, leak past the seals 404 in the annulus. FIG. 4D shows the tool 400 with fluids above, such as fluids being circulated through an uphole lateral wellbore 426 that has been drilled or is being drilled. Fluids falling into the bore 408 through the whipstock 424 and annulus around the tool 400 are sealed against falling further past the seals 404 and float bypass valve 410. Fluids may still exit the bore 408 through the ports 414 and flow uphole through the flow bypass valve 410 if the pressure below the tool 400 exceeds the pressure in the bore 408. Finally, FIG. 4E shows the tool 400 preparing to be tripped out of the wellbore 426. The flow bypass valve 410 is being driven down to shear pins 428 and open ports 412 so fluid flowing downhole can flow out of the tool 400 beneath the seals 404. After drilling is complete, the tool 400 is retrieved via wireline or running tool on tubing, or drilled through to open the wellbore 426.

[0055] FIGS. 5A-C show the seal tool 400 deployed via a directional drilling BHA 228. In this configuration, the tool 400 additionally has mount 440 with a shear pin 442 that, in FIG. 5A, is attached to the BHA 228 to support the tool 400 from the BHA 228. FIG. 5A shows the tool 400 being deployed on the BHA 228, where fluid flow down the drill string 216 or down the wellbore 426 is sealed against flow past the seals 404 and valve 410 of the tool 400. However, fluid beneath the tool 400 can flow upward through the valve 410. FIG. 5B shows the tool 400 after the BHA 228 has been jarred or turned to shear the shear pin 442 releasing the tool from the BHA 228. The tool 400 maintains a seal against downward flow through the wellbore 426, but allows upward flow through valve 410. FIG. 5C shows the BHA 228 drilling a lateral wellbore. The tool 400 maintains a seal against downward flow through the wellbore 426, but allows upward flow through valve 410. Thereafter, the tool 400 isretrieved via wireline or running tool on tubing, or drilled through to open the wellbore 426.

[0056] While this disclosure contains many specific implementation details, these should not be construed as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented, in combination, or in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0057] Particular implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications, substitutions, and alterations may be made. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. Accordingly, the previously described example implementations do not define or constrain this disclosure.

Claims

What is claimed is:

1. A method, comprising: in a wellbore system comprising a first surface wellbore extending from a terranean surface to a subterranean zone, a second surface wellbore extending from the terranean surface to the subterranean zone and a plurality of connecting wellbores in the subterranean zone each connecting the first and second surface wellbores, drilling a lateral wellbore using a drill string extending through the first surface wellbore; and sealing, while drilling, against flow of drilling fluid from the drill string returning towards the first surface wellbore through the connecting wellbores.

2. The method of claim 1, comprising beginning drilling the lateral wellbore by drilling through a side wall of the first surface wellbore uphole from the connecting wellbores; and where sealing comprises sealing the bore of the first surface wellbore uphole from the connecting wellbores.

3. The method of claim 2, where sealing comprises sealing the bore of the first surface wellbore downhole from the beginning of the lateral wellbore.

4. The method of claims 2 or 3, where sealing the bore of the first surface wellbore comprises placing a whipstock with a seal in the first surface wellbore.

5. The method of any of claims 1-4, comprising drilling a second lateral wellbore using a second drill string extending through the second surface wellbore towards the first mentioned wellbore.

6. The method of claim 5, where the first and second surface wellbores reside at the same wellsite and drilling the second lateral wellbore comprises drilling the second lateral wellbore parallel to and extending in the same direction as the first mentioned lateral wellbore; and comprising joining the first mentioned lateral wellbore and the second lateral wellbore at an intersection of the lateral wellbores.

7. The method of claim 5, where sealing comprises sealing an annulus around the first mentioned drill string; and where the method comprises controlling fluid flow out of an annulus port from the annulus around the first mentioned drill string at a flow rate based on a flow rate of drilling fluid supplied through the first mentioned drill string.

8. The method of claim 1, comprising beginning drilling the lateral wellbore by drilling through a sidewall of one of the connecting wellbores; and where sealing comprises sealing between the beginning of the lateral wellbore and one or more of the connecting wellbores.

9. The method of claim 8, where a first subset of the plurality of the connecting wellbores begins from a first of the connecting wellbore and a second subset of the connecting wellbores begins from a second of the connecting wellbores; and where sealing comprises sealing the bore of the first connecting wellbore uphole from the first subset connecting wellbores and sealing the second surface wellbore.

10. The method of claim 9, comprising drilling a second lateral using a second drill string extending through the second surface wellbore toward the first mentioned lateral wellbore; where sealing comprises sealing an annulus around the second drill string; and comprising controlling fluid flow out of an annulus port from the annulus around the second drill string at a flow rate based on a flow rate of drilling fluid supplied through the second drill string.

11. A system, comprising: a first surface wellbore extending from a terranean surface into a subterranean zone; a second surface wellbore extending from the terranean surface into the subterranean zone; a plurality of connecting wellbores each connecting the first and second surface wellbores; a lateral wellbore being drilled using a drill string extending through the first surface wellbore; and a seal in one of the wellbores, the seal sealing against flow of drilling fluid from the drill string returning to the first surface wellbore through the connecting wellbores.

12. The system of claim 11, where the lateral wellbore begins at a sidewall of the first surface wellbore and the seal resides in the first surface wellbore sealing the bore of the first surface wellbore uphole from the connecting wellbores and downhole from the beginning of the lateral wellbore.

13. The system of claim 11 or 12, comprising a whipstock carrying the seal.

14. The system of any of claims 11-13, comprising a second lateral wellbore drilled using a drill string extending through the second surface wellbore, the second lateral wellbore drilled parallel to and in the same direction as the first mentioned lateral wellbore.

15. The system of claim 11, where the lateral wellbore begins at a sidewall of a first of the connecting wellbores and the seal resides in a second of the connecting wellbores downhole from the beginning of the lateral wellbore and uphole from a beginning of a third connecting wellbore branching from the second connecting wellbore.

16. The system of any of claims 11-15, comprising a managed pressure drilling system at the second surface wellbore configured to supply fluid to the second surface wellbore based on a flow rate of drilling fluid supplied during drilling the lateral wellbore.

17. A method, comprising: drilling a lateral wellbore from a first surface wellbore, the first surface wellbore coupled to a second surface wellbore by a plurality of connecting wellbores; and sealing, while drilling, against return of drilling fluid to the first surface wellbore from the lateral wellbore through the connecting wellbores.

18. The method of claim 17, where drilling the lateral wellbore comprises kicking off from the first surface wellbore; and where sealing comprises sealing the bore of the first surface wellbore with a whipstock comprising a seal.

19. The method of claim 17, where drilling the lateral wellbore comprises kicking off from one of the connecting wellbores; and where sealing comprises sealing the bore of a connecting wellbore with a whipstock comprising a seal.

20. The method of any of claims 17-19, comprising using managed pressure drilling to control drilling fluid flow up the second wellbore.

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