COMBINED WELL SYSTEM AND METHOD FOR ENHANCED PRODUCTION

A combined well system which may comprise two or more wells. The wells may be connected in the subterranean earth. Fracking operations may be initiated from the wellhead of one well towards the toe section of a second well. The combined well system may allow for enhanced production by altering pressure drawdown in the toe sections of long lateral wells.

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Description
CROSS REFERENCE

This application is based on and claims priority to U.S. Provisional Patent Application No. 63/649,355, filed May 18, 2024, which is incorporated herein in its entirety by reference.

BACKGROUND OF THE INVENTION Field of the Invention

This invention relates generally to a combined well system and more particularly, but not by way of limitation, to a combined well system comprising a first wellhead and a second wellhead connected in a subterranean formation for enhanced resource production.

Description of the Related Art

Across the hydrocarbon producing regions of the world, oil and gas technology has progressed from utilizing vertical wells, to more complex deviated wells, to even more complex and challenging horizontal wells. Today, in certain areas of the world where oil and gas plays are being developed, complex, lengthy horizontal multilateral well completions have allowed oil and gas to be extracted profitably. However, the success of horizontal wells has created an ever-increasing level of complexity with lateral lengths of 3.5 miles or more and complex well bore paths becoming common.

Although successful, horizontal well technology applications are plagued with challenges. First, undesirable fracture results in the toe sections of deep horizontal wells have been noted across the industry. Poor fracturing of the toe sections causes poor fracture widths, poor fracture half-lengths, poor pump velocity and poor volume of frac proppant placed in the fracture stage. The effect of poor fracturing in these toe intervals is ultimately poor production and recovery.

Another issue with horizontal wells is the size of the borehole drilled and the subsequent production casing that is set. Cost, hole size, drilling limitations, torturous hole paths, casing rigidity, fluid issues, well control issues and weight handling limitations impede the ultimate size of the casing that is installed into boreholes. The casing installed will have a defined Area Open to Flow based on the casing internal diameter. The casing and tubular internal diameters and lengths installed have consequences to pressure drawdown, friction, flow rates and recovered reserves.

Yet another issue with fractured completions is formation damage as a result of the tremendous amount of frac water, the proppant carrier proppant fluid, that is pumped into the formations. The water that is pumped into the formation can cause clays to swell, reducing permeability to oil and gas. This clay swelling causes pressure losses and reduced oil and gas flow.

Another issue occurs due to lengthy well bores. During flowing operations, pressure losses in these lengthy sections due to friction effects are present. Initially the toe sections may not contribute to its maximum production capability leading to delayed production in the toe sections until the pressure drawdown becomes conducive to allow flow. Further, low velocities in the toe sections can cause sediment settling in the casing.

Yet another issue with horizontal wells is the risk and complexity of performing traditional interventions such as wire line and coiled tubing operations. The high risk and cost usually result in proper remediation services not being performed.

Each of the above factors and more contribute to low performing toe sections of lateral wells, leaving valuable hydrocarbon resources un-produced and reducing the profitability of the overall investment.

Based on the foregoing, it is desirable to provide a combined well system which solves production problems by utilizing partitioning of a well bore to alter pressure drawdown and rate profile along the length of the well bore.

It is further desirable for the combined well system to provide two surface outlets with a full-bore loop of casing tubulars joined in the subterranean earth for passage of tools and fluids from one well bore to the other well bore.

It is further desirable to provide a method for joining of two existing well bores or an existing well bore with a new well bore.

It is further desirable to provide a method for increasing the effective casing size of one well without increasing the actual casing size. This method may provide an increase in effective Area Open to Flow allowing for accelerated and increased production, altering of pressure drawdowns and recovery of valuable hydrocarbon resources. Accelerated production rates may have a huge impact on the Return on Investment of a project.

It is further desirable to provide a method to accelerate removal of the frac water from the formation as quickly as possible in order to minimize formation damage. Minimizing formation damage will result in a lower delta pressure skin and allow more oil and gas to flow from the formation.

It is further desirable to provide a method for super lengthy lateral wells.

SUMMARY OF THE INVENTION

In general, in a first aspect, the invention relates to a combined well system which may comprise a first well and a second well. The first well may comprise a first wellhead and first casing segment, and the second well may comprise a second wellhead and second casing segment. The combined system may comprise a connector connecting the first casing segment and second casing segment in a subterranean formation. The first and second well may be lateral wells. The connector may connect the toe section of the first well with the toe section of the second well. The combined system creates an effective down hole casing internal diameter and area open to flow that is larger than one single well. The combined system may be piggable. The combined system may or may not comprise an isolation plug which may be a fixed isolation plug.

The invention may comprise a method for fracking the toe section of the first well from the second well. An isolation plug may be set in the toe section of the first well at a distance from the connector. Fracturing fluid may be pumped into the subterranean formation from the second wellhead. Simultaneously, fracturing fluid may be pumped into the subterranean formation from the first wellhead. The invention may also comprise a method of co-mingled fracturing whereby an isolation plug is not set and fracturing fluid is pumped simultaneously from both wellheads.

The invention may also comprise a method for simultaneous injection and production. An isolation plug may be set into the toe section of the first well. Fracture or injection fluid may be pumped from the second wellhead to perform fracture operations on one side of the isolation plug. On the other side of the isolation plug, production fluids may be permitted to flow towards the first wellhead. The invention may comprise a method of production for flowing both well bores simultaneously, with or without an isolation plug, to facilitate accelerated production and accelerated removal of frac water from the formation.

Another aspect of the invention may comprise a method for connecting two wells to form the combined well system. A first well and second well may be drilled to a target point, and the two wells connected. The drill assembly of the first and second wells may comprise a ranging sensor for locating a connection point.

The invention may also comprise a method of connecting a second well to an existing first well. A rat hole may be drilled at an end of the toe section of the existing well. The rat hole may be drilled at an upwardly inclined angle relative to horizontal. A spotted tracer pill may be deployed into the rat hole. The spotted tracer pill may be detected by a ranging sensor on a drilling assembly of the second well. A drill trajectory may be calculated to direct the drilling assembly to the rat hole. The drill assembly may be steered towards the rat hole. This process may occur automatically using a computer with software.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram of the combined well system.

FIG. 2A is a diagram showing connector means.

FIG. 2B is a diagram showing connector means.

FIG. 3 is a diagram showing a method of creating a super length combined lateral well.

FIG. 4 is a diagram of the combined well system showing a method of co-mingled fracking.

FIG. 5 is a diagram of the combined well system showing a method of using a tool launcher and receiver for intervention and fluid flows.

FIG. 6 is a diagram demonstrating the use of multiple isolations in the combined well system.

FIG. 7 is a diagram of a combined well system showing a method of partitioning of a lateral segment for fracking.

FIG. 8 is a diagram of a combined well system showing a method of partitioning of a lateral segment for injection and production.

FIG. 9 is a chart and diagram showing a method of partitioning the combined well system and altering the pressure drawdown and rate along the well bore length.

FIG. 10A illustrates a software model method for combined well production.

FIG. 10B illustrates a Q v P chart for a combined well without a plug.

FIG. 10C illustrates a Q v P chart for a combined well with a plug.

FIG. 11A illustrates a method of utilizing a preexisting first well to create a combined well system.

FIG. 11B illustrates a method of drilling a first well of the combined well system.

FIG. 11C illustrates a method of drilling the second well to create a combined well system.

FIG. 12 is a diagram of the toe section of a first well drilled at an upward angle for connecting to a second well.

FIG. 13 is a diagram showing how a first well toe section may be connected to a second well approaching at a high angle or a low angle.

FIG. 14 illustrates an Z/X axis view of a seismic mapping for drill steering and pinpoint target selection.

FIG. 15 illustrates an X/Y axis view of a seismic mapping for drill steering and pinpoint target selection

FIG. 16 illustrates a closed system pressure measurement environment for true vertical depth determination.

FIG. 17 illustrates a 3D visual map model of the bottom hole assembly positioning.

FIG. 18 is a diagram showing the method of drilling and ranging connecting the well system.

FIG. 19 is a diagram showing the method of connecting two separate well systems to form the combined well system.

FIG. 20 is a diagram showing the method of pulling production casing around the combined system.

FIG. 21 is a diagram showing the method of using ranging to align the toe sections of two separate well systems.

FIG. 22 is a diagram showing the toe section of a first well with a rat hole drilled and tracer pill deployed.

FIG. 23 is a diagram of a first and second well system showing a method of aligning the two wells by pinpoint targeting.

FIG. 24 is a diagram of a first and second well showing a method of aligning the two wells by using ranging and real time adjustments to steering to target pinpoint.

FIG. 25 shows a flow diagram detailing the logic used to compute ranging data.

FIG. 26 is a diagram showing the method of casing being pulled around, cemented, and drilled out creating a full-bore system.

FIG. 27 illustrates a method for conducting the completion process.

FIG. 28 is a diagram of a combined well system showing a method for cementing a first casing segment and second casing segment using inverted casing shoe tracks.

FIG. 29 is a diagram of a combined well system showing a method of fracking the toe section of a first well towards the heel of the first well and fracking the toe section of a second well towards the heel of the second well and altering the pressure and production profile.

FIG. 30 is a diagram of a combined well system showing a method of reducing skin damage during simultaneous operations of a first and second well.

FIG. 31 is a flow diagram showing a method for fracking a lateral toe section in a second well from a first well using the combined well system.

Other advantages and features will be apparent from the following description and from the claims.

DETAILED DESCRIPTION OF THE INVENTION

The devices and methods discussed herein are merely illustrative of specific manners in which to make and use this invention and are not to be interpreted as limiting in scope.

While the devices and methods have been described with a certain degree of particularity, it is to be noted that many modifications may be made in the details of the construction and the arrangement of the devices and components without departing from the spirit and scope of this disclosure. It is understood that the devices and methods are not limited to the embodiments set forth herein for purposes of exemplification.

In general, in a first aspect, the invention relates to a combined well system 104 for enhanced production. The combined system 104 may comprise two or more wells. By way of example but not limitation, the combined system 104 may comprise a first well 50 and a second well 51. The first well 50 and second well 51 may each be a horizontal, lateral, extended reach wells, C shaped wells, U shaped wells, multilateral wells, or each well 50, 51 may be a different type of well from one another. The first well 50 may be an existing well or a new well build. The second 51 well may be a new well build. The wells 50, 51 may further be pad or non-pad wells. Additionally, the wells 50, 51 may be drilled at any angle in relation to the surface 1, further described below.

As shown in FIG. 1 by way of example but not limitation, the first well 50 and second well 51 may comprise a first wellhead 4 and a second wellhead 6. The combined well system 104 encompasses wellheads 4, 6 may be placed in the same or separate regions. For example, wellheads 4, 6 may both be located in a region that include land, ocean platforms, subsea, etc., or be separately placed in different areas from one another. Each region may include particular formation characteristics identified by rock type, porosity, thickness, and other geological information.

In some embodiments, the system 104 may comprise optional hardware 99 such as a gas lift, tubing, packers, rod pumps, electrical sump pumps, hydraulic pumps, or any other equipment common in the industry. The system 104 may further comprise a first tool launcher/catcher 7 and second tool launcher/catcher 9.

In some embodiments, the first well 50 and second well 51 may each, respectively, comprise a first casing segment 24 and second casing segment 25, a first heel section 90 and second heel section 91, a first toe section 88 and second toe section 89, and a connector 11. First casing segment 24 and second casing segment 25 may include a plurality of production liners that hang in their respective intermediate casings. Alternatively, the first and second casing segments 24, 25 can be a tie back string of casings back to their respective wellheads 50, 51.

In some embodiments, connector 11 may connect the first casing segment 24 of the first toe section 88 of the first well 50 to the second casing segment 25 of the second toe section 89 of the second well 51 in a subterranean formation 2. The connector 11 is configured to allow at least production materials to flow between the first well 50 and the second well 51 via the first casing segment 24 and the second casing segment 25.

As illustrated in FIGS. 2A and 2B, the combined well system may use a variety of well connectors. In one embodiment, the connector 11 may be a screw-on connector 101. The screw-on connector may include the first casing segment 24 having a threaded end and the second casing segment 25 having a receiving end. The threaded end can be the end of the first casing segment 24 at toe end 88. The receiving end can be the end of the second casing segment 25 at the end of the toe end segment 89. The receiving end is configured to allow the threaded end to be inserted into the second casing segment 25.

In an alternative embodiment, the connector 11 may be an expandable tube connector 102, which is inserted from second casing segment 25 into first casing segment 24 and expanded to seal the connection.

In an alternative embodiment, the connector may be an overshot connector 103, which is affixed to second casing segment 25 and fits around the outer perimeter of first casing segment 24.

In an alternative embodiment, the connector 11 may be an insertable tube 108 with a liner hanger or packer 107 attached to the end of the insertable tube. The insertable tube 108 and the liner hanger or packer 107 may be affixed to the end of the second casing segment 25 and inserted into the first casing segment 24, or vice versa. The liner hanger or packer 107 may anchor to the internal wall of the first or second casing segment 24, 25, forming a sealed connection.

In an alternative embodiment, the connector 11 may be a gap connector 115. The end 110 of first casing segment 24 and end 111 of second casing segment 25 may be placed such as to form a gap 112 between both ends. Cement 18 may be placed into the gap 112 to cement the casings 24, 25 together. The gap 112 filled with cement 18 may then be drilled out such as to leave a hollow center and sealed outer portion, forming a sealed connection.

In an alternative embodiment, the connector 11 may be an overlap cemented connector 116. The first casing segment 24 may be fitted inside of a portion of second casing segment 25 such that the end 110 of first casing segment 24 rests inside of second casing segment 25, or vice versa. Cement 18 may then be placed in between the outer surface of end 110 of first casing segment 24 and the inner surface of second casing segment 25, forming a sealed connection.

In an alternative embodiment, the connector 11 may be a side-by-side connector 114. The first casing segment 24 and second casing segment 25 may run past and align parallel, or close to parallel, with one another creating a parallel section of each casing segment 24, 25. Perforations 113 may be placed along the parallel sections to which the first casing segment 24 and the second casing segment may access the perforations 113. The parallel sections may be aligned such that fluid may flow freely between perforations 113 of the respective casings.

In an alternative embodiment, the connector 11 may comprise a fracture connector 117. The first casing segment 24 and second casing segment 25 may run past and align parallel, or close to parallel, with one another creating a parallel section of each casing segment 24, 25. The parallel sections may include fractures in between the first casing segment 24 and the second casing segment 25, in which fluid flows through perforations 113 on the first casing segment 24, through fractures 16, and through opposing perforations 113 on the second casing segment 25.

In an alternative embodiment, the connector 11 may be an inflatable connector 102. The inflatable connector 102 may be comprised of elastomer material. The inflatable connector 102 may be affixed to the end of the second casing segment 25 and inserted into the first casing segment 24, or vice versa. The inflatable connector may include a bladder. The bladder may be filled with an inflating material. The inflating material may fill the bladder causing the elastomer material to swell to an inner surface of either the first or second casing segment 24, 25, forming a seal.

In an alternative embodiment, the connector may be a connector comprising swellable sealing elements. This may comprise an elastomer material which swells in the presence of chemical(s). These chemicals may be pumped though a connection region of the connector causing the material to swell, forming a seal.

In an alternative embodiment, the connector 11 may be a proprietary connector of any kind.

Referring back to FIG. 1, in some embodiments, the combined system 104 may comprise a total casing length 30. The total casing length 30 may be the sum of a length of the first casing segment 19 and a length of the second casing segment 29. Alternatively, the length 30 may be measured from heel 90 to heel 91. Alternatively, the length 30 may be measured from the first wellhead 4 to the second wellhead 6. The combined system 104 may comprise the cumulative internal cross section area of first casing segment 24 and second casing segment 25, creating a larger combined effective area open to flow as compared to the single internal cross section area of first casing segment 24 with internal diameter 63. The completed combined system 104 allows for creation of a super length lateral well, as illustrated by FIG. 3. Lengths 19 and 29 of a first and second lateral well may approach approximately 3.5 miles or more from toe-end section 88, 89 to heel 90, 91 respectively. The total length 30 of the combined system 104, as measured from heel 90 to heel 91 along the full bore length, may therefore be at least seven miles in length.

In some embodiments, the subterranean area 2 may be an area within the reservoir where the production of production material (i.e. water, oil, and gas) may take place. The subterranean area 2 may include an area along the super length lateral well in which the casings of the first and/or second casing segments 24, 25 pass through a plurality of fracture clusters 16. The fracture clusters 16 may be natural or man-made, via fracturing. The first and/or second casing segment 24, 25 may have perforations throughout their casings located in the subterranean area 2. The perforations are configured to allow the combined well system 104 to perform operations (e.g. fracking, stimulation, and injection) on the subterranean area 2 to prepare and/or improve the fracture clusters 16 for oil and gas production. These improved fracture clusters 16 may be characterized as production clusters 83 (not shown).

In some embodiments, the combined system 104 allows for full or limited bore connection. This classification of a full or limited bore connection is determined based on the use of an isolation plug 26. For example, if the combined well system 104 uses the isolation plug 26, the system 104 will be classified as a limited connection while a combined well system 104 that does not use the isolation plug 26 is classified as a full bore connection.

In some embodiments, the system 104 may allow for full bore connection into the well bore of first well 50 from the well bore of second well 51 or vice versa. The system 104 may allow for full bore connection by either having no isolation plug 26 in place or removing the isolation plug 26 that has been previously set. Through having no isolation plug 26 in the combined well system 104, the combined length of first casing segment 24 and the second casing segment 25 may have a maximum combined effective area for production to flow. By not installing isolation plug 26 in between fracture clusters 16, pressure drawdown may be applied to the entirety of fracture clusters 16 in the subterranean area 2 from first well 50 and second well 51 simultaneously or independently. The simultaneous application of pressure drawdowns may improve production flow rate of the system 104, as discussed below.

Fracturing may occur on the system 104, without an isolation plug 26, by co-mingled fracturing as illustrated by a non-limiting embodiment illustrated in FIG. 4. First well fracture treatment 69 and second well fracture treatment 70 may flow together into the same fracture clusters 16. This may allow for combined fracture pump rates and increased velocity and volume of proppant, leading to enhanced fracturing widths, half-length, placement, production drawdowns and increased production rates. Additionally, this method allows for subterranean mixing of treatment materials (i.e. proppants or chemicals) at the fracture cluster 16 as pumped from surface well head 4 and well head 6 simultaneously. Fluid diverters may also be used to allow for multiple co-mingled fracks stages along the entire combined well bore length. Perforation density and hole size may need to be matched to the combined pump rates.

In some embodiments, the full-bore connection may allow for hydraulic and mechanical communication from the surface of second well 51 to the surface of first well 50. For example, the communication may allow for pigging operations. The communication may allow for intervention of the toe sections 88 and 89 from either the first well 50 or the second well 51. For example, the system 104 may allow for completion treatments to be initiated toward toe sections 88 and 89 from the opposing wellhead 4, 6, respectively, as discussed below.

The intervention may include a method of using a tool launcher and receiver as illustrated in FIG. 5. Since the combined system 104 may comprise a closed hydraulic/mechanical loop, mechanical and diagnostic tools from first wellhead 4 may be pumped around to second wellhead 6. First wellhead 4 may comprise a first tool launcher and receiver 7, and second wellhead 6 may comprise, but not limited to, a second tool launcher and receiver 9. Each tool launcher may comprise a crown valve 77, swab cup 81, and mechanical or diagnostic tool 82. The swab cups 81, pigs, tools, and/or fluid may flow according to tool flow direction 79 from first tool launcher and receiver 7 to second tool launcher and receiver 9, or vice-versa.

Using the method as illustrated in FIG. 5, tools and pigs may be pumped, pulled, pushed, tractored, or allowed to free fall around the combined system 104 from first tool launcher and receiver 7 to second tool launcher and receiver 9 and vice versa, allowing for mechanical pig and fluid sweeps for hole cleaning. Fluid treatments and abandonment material or cement for abandonment of the entire system may also be pumped.

Referring back to FIG. 1, in alternative embodiments, the limited connection combined system 104 may include the isolation plug 26. The isolation plug 26 may be mechanically, electrically, or hydraulically set along the super length lateral well. The isolation plug 26 may partition the combined well system 104 into two separate regions. For example, the isolation plug 26 may be placed along the subterranean area 2, in between production clusters 83. The placement of the isolation plug 26 may increase the production rates of the combined well system 104, further discussed below.

In some embodiments, the combined well system 104 may have multiple partitions on either side of the isolation plug 26 as illustrated in FIG. 6. As illustrated in FIG. 6, an isolation plug 26 may be set into first casing segment 24 at a distance 109 from connector 11. On either side of isolation plug 26, a packer and tubing 107 may be set in-between production clusters 83, forming distinct flow paths and flow regimes of produced fluid 85 and 87 to the respective wellheads 4, 5. For example, one regime may flow into inner tubing or casing 108, whereas a second regime may flow outside of inner tubing or casing 108 but within first casing segment 24 back to first wellhead 4. These flow regimes may allow for further altering of pressure drawdown.

Referring back to FIG. 1, the isolation plug 26 may create two separate regions of the combined well system 104 designated for first well 50 or second well 51 operations (ex. fracking, producing, stimulation, and injection). These separate regions may include the casing segments 24, 25 of the combined system 104 on either side of the isolation plug 26. For example, the area to the left of the isolation plug 26 may be designated for first well 50 operations while the area to the right of the isolation plug 26 may be designated for the second well 51 operations. Each region may encompass production clusters 83 (i.e. the fracture clusters 16). The separate regions of the combined well system 104 may have their own pressure drawdown environments to facilitate separate operations, including the operations' physical effects, placed on the region by their respective well 50, 51. For example, separate pressure environments may help facilitate production and fracturing operations. These separate operations may be based on the configurations of their respective well 50, 51.

In some embodiments, partitioning the combined system 104 may improve well fracturing operations. In long lateral wells, high frictional forces cause poor fracturing in the toe sections 88, 89 and poor production as a result. As shown by a non-limiting embodiment illustrated in FIG. 7, the isolation plug 26 may be set at a point along the length of the first well 50 well bore so that the toe sections 88, 89 of a long first lateral well 50 may be fractured from the second well 51. First well fracture treatment 69 may be pumped according to first fracture treatment flow path 66 into the fracture clusters 16 in the first toe section 88. Likewise, a second well fracture treatment 70 may be pumped according to second fracture treatment flow path 67 past the connector 11 into the fracture clusters 16 in the first toe section 88. Thus, the fracking operations may be performed on both sides of the isolation plug 26. Additionally, the first fracture treatment 69 and the second fracture treatment 70 may occur simultaneously or independently of one another.

By way of example, a plug, perforate, and frack sequence may be performed from the second well 51 surface location. Ideally, the second well 51 may have a short distance to the surface using the methods described below to form a combined system 104. Because the fracture treatment may travel a much shorter distance from the surface of second well 51 to the first toe section 88 than from the surface of first well 50 to the first toe section 88, frictional forces may be reduced and fracture performance is increased.

In some embodiments, partitioning, via the isolation plug 26, of the combined system 104 may isolate production intervals from injection intervals. A non-limiting embodiment is illustrated in FIG. 8, whereby the isolation plug 26 may be installed into the combined system 104. For example, the isolation plug 26 may be set in the first casing segment 24 in between two production clusters 83 and perforations. Production fluids 85 may be produced from production clusters 83 and flow toward first wellhead 4. Simultaneously, injection fluids 86 may be injected from the second wellhead 6 into the production clusters 83 on the other side of isolation plug 26. Thus, the system 104 may allow production and injection operations to occur simultaneously.

Referring back to FIG. 1, in some embodiments, the partition, via the isolation plug 26, may allow the first well 50 and second well 51 to have little to no operational interference with the other's region. For example, the pressure drawdown placed on the production clusters 83 in the first well 50 region may not affect the production clusters 83 in the second well 50 region. Additionally, the partition of each region may allow each well 50, 51 to alter their pressure drawdown profile based on production needs. The pressure drawdown on each side of the isolation plug 26 may be applied by regulating a respective surface choke (not shown) on either the first wellhead 4 or second wellhead 6. Additionally, artificial lift technology such as gas lifts, electrical sump pumps, hydraulic pumps, or rod pumps (all not shown), can be used on either side of the isolation plug 26 to further compound the pressure drawdown on the subterranean area 2.

In some embodiments, the first well 50 and second well 51 ability to apply their own pressure drawdown on their respective region may create two distinct flow regimes. The two distinct flow regimes indicate a flow of material 27, 28. The material may comprise of production material resulting from the production operation performed on the region and material pumped into the system 104 for other operations such as fracking and injecting.

In some embodiments, the combined system 104 may allow for separate and/or combined metering of produced fluids from both wells. First material flow 27 may flow through first flow line 8 to a first production facility and metering well 46. First material flow 27 may flow to a header/manifold 48 and be characterized by a first combined flow rate 44. The first combined flow rate 44 may include water rate (Qw1), gas rate (Qg1), and oil rate (Qo1). First combined flow rate 44 may be the total flow rate of water, oil, and gas from first material flow 27. Second material flow 28 may flow through second flow line 10 to a second production facility and metering well 47. Second material flow 28 may flow to the header/manifold 48 and be characterized by second combined flow rate 45. The second combined flow rate 45 may include water rate (Qw2), gas rate (Qg2), and oil rate (Qo2). The first combined flow rate 44 and the second combined flow rate 45 may flow to the header/manifold 48 either simultaneously or independently. From header/manifold 48, the simultaneous flow of the first combined flow rate 44 and the second combined flow 45 rate may create a total combined material flow rate 49, which may be the sum of the water rate (Qwt), gas rate (Qgt), and oil rate (Qot).

The joining of the first well 50 and the second well 51 may accelerate the total production 49 of the combined well system 104 as illustrated in FIG. 9. FIG. 9 illustrates a typical pressure drawdown and rate profile along the length of a single, stand-alone well compared to the combined system 104 with and without an isolation plug 26 set. The length of the combined well system 104 may affect the water, gas, and oil flow rates in which the length of the combined system 104 has an inverse effect on the pressure drawdown. In some embodiments, the combined well system 104 may have no isolation plug 26. The combined well system 104 may have both the first well 50 and the second well 51 apply pressure drawdown to the combined well 104. The increase in pressure drawdown through having the first well 50 and the second well 51 may increase the combined flow rate of the combined system 104.

In an alternative embodiment, the combined well system 104 may have an isolation plug 26. The placement of the isolation plug 26 may create two separate regions of the combined well system 104, one for the first well 50 and second well 51. The two separate regions may be smaller in length than the combined well system 104. The change in length may alter the effects of the pressure drawdown that the first well 50 and the second well 51 have on their respective region. The amount of pressure drawdown of the first well 50 and second well 51 apply to their respective region may directly influence their respective combined flow rates 44, 45, thereby also directly influencing the total combined flow rate 49. By way of example but not limitation, the isolation plug 26 may be set at a distance 109 into the first well 50 from connector 11. As illustrated in the chart of FIG. 9, when the combined well system 104 sets an isolation plug 26 at the distance 109, the combined well flow profile 93 of the combined system 104 may be improved by an additional rate 96 over a single well flow profile 92. Similarly, the combined well pressure drawdown 95 shows improvement in comparison to a single well pressure drawdown 94 by an additional pressure drawdown amount 97.

The improvement in pressure drawdown 97 may allow the combined well system 104, with or without an isolation plug 26, to accelerate the total oil, gas, and frac water/load water production 49.

Historically, the toe intervals in longer lateral sections suffer from poorly pumped fracture treatments caused by frictional pressure losses while pumping. The net result is that the toe section of wells under produce and mineral reserves are ultimately left behind. By installing a partition isolation plug 26 in first well 50 between selected fracture clusters 16, two separate pressure systems are created. Thus, pressure drawdown can be applied separately to first well 50 and second well 51 thereby increasing production of the mineral reserves at an accelerated rate and lowering the amount of mineral reserves left behind in the subterranean area 2. Additionally, it is important to note, in either embodiment, of the inclusion or exclusion of the isolation plug 26, that the acceleration of flow back or frack water production will limit the time that frac water could potentially be in the subterranean producing formation 2 or fracture network. The longer that frac water sits in the producing formation, the more the clays swell, which will reduce the permeability of flow within the rock formation and may cause damage to the formation. By accelerating the frac water flow back, the time of clay swelling is minimized, therefore improved permeability of flow of reservoir fluids will result.

The production flow rates of the combined well system 104 may be predicted using a combined well production software model as illustrated in FIG. 10A. The production software model may use nodal analysis and plot the reservoir performance for combined well system 104 with and without the isolation plug 26, as shown in an Inflow Performance Relationship (IPR), and a well performance, as shown in the Vertical Lift Performance (VLP). The variables used to create the IPR and VLP curves may be obtained through well testing and drilling operations. The intersection being the stable flow rate and pressure at which the well system 104 may operate at. The well performance may be calculated based on the pressure drop of the first well 50 and the second well 51.

The reservoir performance is calculated based on the flowing bottomhole pressure, the flow rate of the well 50, 51, and the reservoir pressure. Additionally, the reservoir performance may be calculated based on variables that include the reservoir's permeability, formation thickness, viscosity, formation volume factor, drainage radius, wellbore radius, and skin factor. The flowing bottomhole pressure of the first well 50 may be the pressure near the isolation plug 26 in the first well 50 region of pressure drawdown effect. The flowing bottomhole pressure of the second well 51 may be the pressure near the isolation plug 26 in the second well 51 region of pressure drawdown effect. The flow rate of the well 50, 51 may include the water, oil, and gas flow rates. The production model may calculate the IPR curve data points by varying the flowing bottom hole pressure to determine the flowrate output. Additionally, the variables may be varied to calculate the IPR curve at different variable values. For example, the production model may vary the Skin variable to determine the IPR curve at different Skin values. The IPR curve may be illustrated on a Pressure vs. Flow Rate graph.

The well performance of the first well 50 includes the first well 50 parameters up to the toe section 88 minus the parameters of a casing segment defined by distance 89 (i.e. the well performance of the first well 50 includes the parameters of the first well 50 region affected by the first well 50 pressure drawdown). The well performance of the second well 51 includes the first well 50 parameters up to the toe section 89 plus the parameters of a casing segment defined by distance 89 (i.e. the well performance of the second well 51 includes the parameters of the second well 51 region affected by the second well 50 pressure drawdown). The parameters of the first well 50 and the second well 51 may include their respective wellhead pressure, fluid density, elevation increase, fluid velocity, fanning friction factor, tubing length, tubing inner diameter, roughness, artificial lift, etc. The production model may input the parameters into the pressure drop equation to generate a VLP curve of each well 50, 51. The production model may calculate the VLP curve data points by varying the flowing bottom hole pressure to determine the flowrate output. Additionally, the variables may be varied to calculate VLP curve at different variable values. For example, the production model may vary the tubing inner diameter variable to determine the VLP curve at different diameter values. The VLP curve may be illustrated on a Pressure vs. Flow Rate graph.

FIG. 10B illustrates a P v. Q production model for the combined well system 104 without the isolation plug 26. The production model may include a first IPR curve 118 of the first well 51 and a second IPR curve 119 for the second well 51. The first and second IPR curve 118, 119 may be added together to form a combined IPR curve 120. Additionally, the production model may present a VLP curve 121 representing the combined inflow of the combined well system 104.

FIG. 10C illustrates a P v. Q production model for the combined well system 104 with the isolation plug 26. The production model may include a first plug IPR curve 122 of the first well 51 and a second plug IPR curve 123 for the second well 51. The first and second plug IPR curve 122, 123 may be added together to form a combined plug IPR curve 127. Additionally, the production model may include a first plug VLP curve 124 for the first well 51 and a second plug VLP curve 125 for the second well 51. The first and second plug IPR curve 124, 125 may be added together to from a combined plug VLP curve 127. By adding the plug IPR curves 122, and 123 and the plug VLP curves 124, 125 from each well 50, 51 together, the production model derives the combined well system 104 Flowing Bottom Hole Pressure and Flow Rate 128.

The production model may combine the IPR curve and the VLP curve of each well 50, 51. The production model may create two separate graphs, one for each well 50, 51, illustrating the respective wells' IPR and VLP curve. Additionally or alternatively, the production model may create one graph illustrating the IPR and VLP curves of both wells 50, 51.

Referring back to FIG. 1, in some embodiments, the isolation plug 26 may be a fixed or movable isolation plug 26.

In some embodiments, the fixed isolation plug 26 may be a sealing, isolation, and pressure altering device. In some embodiments, the fixed isolation plug 26 may be a cement fixed plug in which cement is placed in a location along the super length lateral well.

In an alternative embodiment, the isolation plug 26 may be a movable isolation plug 26. A movable isolation plug 26 may comprise sensors on either or both sides of the plug 26 that can be deployed into the super length lateral well. The sensors may be pressure, temperature, sonic sensors, or a combination thereof. Additionally or alternatively, the sensors may include time and production logging tools, nuclear tools, or any other tool used in the industry. The movable isolation plug 26 may be deployed into the system 104 via wireline, slick line, coiled tubing, drill pipe, freefall, pump around, pull around, or tractor. The movable isolation plug may be set in between production clusters 83 and/or perforations and may measure test parameters of the combined system flow rate. Rates and pressures may be measured on both sides of the plug 26. The movable isolation plug 26 may be unset and moved to a new location along the combined system 104, setting the movable isolation plug 26 in between different sets of production clusters 83 and/or perforations. This process may continue until all production clusters 83 are measured. This method may be used to calculate the amount of flow coming from each individual production cluster. This method may also be used to calculate the pressure drawdown on each production cluster.

In an alternative embodiment, the isolation plug 26 may be a solid plug or an adjustable or fixed choke. The isolation plug 26 may be a solid plug or an orifice/choke. The plug or choke isolation plug 26 may be controlled from either well 50, 51 surface location by electrical wires extending from the surface 1 to the plug choke. The isolation plug 26 may be temporary or permanent in nature.

Embodiments of the combined well system 104 are made using various drilling methods. The present apparatus may develop the combined well system 104 by utilizing a preexisting first well 50 and then drilling the second well 51 until the second well 51 is connected to the first well 50. Alternatively, the combined well system 104 may drill the first well 50 and drill the second well 51 until the second well 51 is connected to the first well 50. In either case, the method allows for two long well bores to be joined together, eliminating the impracticalities of drilling a deep long lateral well using one drilling location. Because the weights, hydraulics, and frictional effects are shared between the two surface rigs, the drilling of a deep long lateral well with two surface connections is made more practical and effective.

FIG. 11A describes a non-limiting embodiment of a method for utilizing a preexisting first well 1. FIG. 11B describes a non-limiting embodiment of a method for drilling the first well 1. FIG. 11C describes a non-limiting embodiment of a method for drilling the second well 51. Depending on the method of developing the first well 50, the steps of each method may impact the steps of drilling the second well 1 and vice versa.

FIG. 11A illustrates a method of utilizing a preexisting first well 50 to create the combined well system 104.

In act 1102, well planners may determine the pinpoint target coordinates 58. The pinpoint coordinates 58 may be based on the structure of the first well 50 as planned in its original well plan. These pinpoint target coordinates 58 are 3-Dimensional coordinates based on the optimal intersection of the first well 50 and second well 51. In some embodiments, the pinpoint target coordinates 58 may be at the toe end 88 of the first well 50. Alternatively, the pinpoint target coordinates 58 may be anywhere along the horizontal section. Alternatively, the pinpoint coordinates 58 may be further along in the subterranean formation 2. The planned pinpoint target coordinates 58 are represented by value A and may be used in the method of drilling the second well 51 in act 1136 and act 1138.

In act 1104, operators may clean the first well 50. Casing segments 24, 25 are cleaned to remove debris, mudcake, cement sheaths, mineral deposits, etc. The cleaning process may involve mechanical, chemical, hydraulic methods, or a combination thereof, using tools and fluids to clean the casing interior.

In act 1106, operators may conduct surveys on the first well 50. The surveys may include gyroscopic surveys and/or cased-hole magnetic surveys. The surveys may record data every 30-100 ft. The data may include measured depth, inclination, and azimuth. The data may be used to calculate TVD, Northing, Easting, and Dogleg severity data. Easting, Northing, and TVD may be used as the X, Y, and Z values for a 3D coordinate of points along the first well 51. The results of the data may create a wellbore trajectory plot and/or a survey table showing the data.

In act 1108, the path of the first well 50 may be defined with certainty. The certainty valuation may be coordinates of points along the first well 50 based on the results of the survey data. In some embodiments, act 1108 may begin when act 1146 begins to drill to the pinpoint target coordinates 58 as represented by value F. In alternative embodiments, act 1108 may begin before act 1146 begins.

In act 1110, the toe section 88 of the first well 50 is determined whether it is suitable for the second well 51 to connect. The determination may be based on criteria for optimizing the layout of the first well 50. The criteria may include the length of the lateral section of the first well 50, the size and trajectory of the toe section 88, sufficient space at the toe section 88 to be classified as a rat hole, or a combination thereof. The criteria may be based on the definition of the first well 50. The pinpoint target coordinates 58 may be compared against the definition to determine if the first well 50 encompasses, is close enough, or significantly falls short of the pinpoint target coordinates 58 of the combined well system 104. For example, if the optimal pinpoint target coordinates 58 are in an area that is not located in the first well 50, the rat hole may be drilled out at the pinpoint target coordinates 58. If the pinpoint target coordinates 58 is in an open area within the first well 50 then the rat hole may not be drilled out. If the toe section 88 of first well 50 is suitable for the second well 51 connection, then the method goes to act 1114. If the toe section 88 of first well 50 is not suitable for the second well 51 connection, then the method goes to act 1112.

In act 1112, if the toe section 88 of first well 50 is not suitable for the second well 51 connection, then the toe section 88 may be modified. The modification may be based on the determination of act 1110 that the first well 1 has to satisfy. For example, if the length of the lateral section is not at an appropriate length, the toe section 88 may be drilled further in order for the toe section to encompass the pinpoint target coordinates 58. Or a casing shoe and/or rat hole may be drilled out if a spot tracer pill and/or ranging devices cannot be placed at the toe section. Or the trajectory of the toe section 88 may be directed downward or have an nonoptimized angle of approach in which the second well 51 may not have an appropriate angle of attack to allow the casing segment 24 of the first well 50 to connect to the casing segment 25 of the second well 51.

In act 1114, a spot tracer pill or other ranging devices may be placed at the pinpoint target coordinates 58. The spotted tracer pill 34 material may be a chemical source such as a nuclear source, earth element, or compound within regulations that is detectable by the second drill assembly to steer the second drill assembly, via the second rotary steerable 38, to the target pinpoint location 58 at a terminal end of first toe section 88, further discussed below.

In act 1116, the casing segment 24 of the first well 50 and the borehole of the second well 51 may be verified if they are touching. Additionally, confirmation value G of the borehole of the second well 51 is touching the casing segment 24 is received from the second well 51 drilling method at act 1148. Verification (value H) will be sent to the second well 51 drilling method in act 1150. When it is verified that the second well 51 borehole is touching the casing segment 24 by both act 1116 and 1148, act 1150 may proceed, as discussed below.

FIG. 11B illustrates a method of drilling the first well 50 to create the combined well system 104.

In act 1118, operators may construct a well plan for the first well 50. The well plan may include the determination of the pinpoint coordinates 58 (value B). Additionally, the well plan may include a design of the second well's 51 trajectory to drill through the earth to the pinpoint coordinates 58 in the subterranean area 2. The trajectory may be based on factors that include reservoir geometry, surface constraints, building sections, and anti-collision analysis. The pinpoint coordinates 58 (value B) may be sent to act 1136 of the method of drilling the second well 50.

In act 1120, a first drilling rig 3 may initially drill the first well 50 to a depth. At certain depths, operators may set different casings into the first well 50. For example, a conductor casing may be set at 150 ft, a surface casing may be set at 5000 ft, etc. When the operators set the casings, cement 18 may be used to affix the casings into place.

In act 1122, operators may set an intermediate casing when the first drilling rig 3 reaches a certain depth. When the operators set the intermediate casing, cement 18 may be used to affix the intermediate casing, via casing shoe track 13.

In act 1124, a first drilling rig 3 may deploy a first bottom hole assembly to drill the wellbore for the production casing of the casing segment 24. The first bottom hole assembly may drill to the planned pinpoint target 58 via a first drill bit 35. The first bottom hole assembly may include a rotary steerable system (RSS), drill bit, sensor system, mud motor, magnets 32, etc. Alternatively or additionally, the first bottom hole assembly may include production logging tools, nuclear, sonic, sources, seismic, ranging tools may be deployed with the first bottom hole assembly.

In some embodiments, as the first bottom hole assembly drills to the pinpoint coordinates 58, the sensor system may collect sensor data about the drilling operation and the first bottom hole assembly. For example, the sensor system may include measuring while drilling (MWD) and/or logging while drilling (LWD) components for obtaining sensor data, such as toolface, formation logging, inclination, azimuth information and measured depth. The sensor data may be transmitted to a control unit 62 via a communication means 61 (e.g. wireless, wireline, electromagnetic, or mud pulse telemetry). The surface control unit 62 may monitor real-time or near real-time sensor data. The control unit 62 may operate at the discretion of a directional driller personnel or an automated drilling software at the first drilling rig 3. The control unit 62 may use the sensor data to calculate Easting, Northing, and TVD as the X, Y, and Z coordinates of the current position of the first bottom hole assembly. The control unit 62 may compare the current coordinates with the pinpoint target coordinates 58. The control unit 62 may determine steering commands for the first bottom hole assembly based on the comparison. Alternatively, the directional driller may provide inputs to the control unit 62 as to the steering commands for RSS direction corrections (i.e. corrections in drilling azimuth, inclination, etc.). The control unit 62 may transmit the steering commands downhole via the communication means 61 to the RSS. The RSS may receive the steering commands and converts the command into a mechanical action. This process may continue until the first bottom hole assembly reaches the pinpoint coordinates 58. The control unit 62 may determine if the first bottom hole assembly reaches the pinpoint target 58 by comparing the current coordinates with the pinpoint target coordinates 58. If the current coordinates is substantially the same as the pinpoint target coordinates 58, then the drilling operation stops.

The first bottom hole assembly may reach the pinpoint target 58 via a low angle approach, a high angle approach, or a horizontal approach. The approach may define the trajectory the first bottom hole assembly drills to the pinpoint target 58. In some embodiments, the first bottom hole assembly may take a high angle approach. For example, FIG. 12 shows a non-limiting embodiment of a complete connection of the second casing segment 25 of the second well 51 to the first casing segment 24 of the first well 50 when using a high angle approach. When drilling to the pinpoint target 58 of the first well 50, the RSS may angle the first bottom hole assembly upwards at an angle 41, relative to the horizontal plane, to reach the pinpoint target 58. This high angle approach facilitates a short radius second well 51 approach. As shown in FIG. 13, by using a first well high angle toe 105 and second well high angle approach 53, the overall distance between first wellhead 4 and second wellhead 6 may be shortened by a distance 55 compared to using a first well low angle toe 106 and second well low angle approach 54. Also, higher angles 41 as compared to horizontal will facilitate casing segment 25 weight to be transferred to connector 11.

In an alternative embodiment, FIG. 14 illustrates an X-Z axis view of a seismic mapping for drill steering and pinpoint target 58 selection. FIG. 15 illustrates an X-Y axis view of a seismic mapping for drill steering and pinpoint target 58 selection. Operators may place fixed arrays 131 across the surface 1. Additionally, mobile arrays 132 may be attached to a vehicle. The vehicle may comprise an area that can fit a plurality of mobile arrays. The vehicle may include a flatbed truck, box truck, drop-side trucks, dry vans, etc. The fixed arrays 131 and the mobile arrays 132 may be deployed in areas, designated by the first well 50 well plan and the second well 51 well plan, the first bottom hole assembly and a second bottom hole assembly will drill under. The fixed arrays 131 may be equally spaced 151 from one another on the surface while the mobile arrays may be equally spaced 151 on the vehicle. The fixed arrays 131 and mobile arrays 132 may include seismic sensors. The seismic sensors may include accelerometers, magnetometers, geophones, etc. The seismic sensors are communicatively coupled to the control unit 62. The seismic sensors may record data including the first drill bit 35 and the second drill bit 36 seismic activity as they drill through the subterranean area 2. The seismic sensors may record the data continuously or at time intervals. The seismic activity data may include the seismic wave's vectors 135. The vectors 135 may include the arrival time, direction, angle, etc. of a bottom hole assembly's seismic activity at a certain time. The seismic sensors may transmit the seismic activity data to the control unit 62. The control unit 62 may process the seismic activity data of each seismic sensor and analyze the travel time difference between each seismic sensor. The control unit 62 may process the seismic activity data and classify them as the seismic activity data of either the first bottom hole assembly or the second bottom hole assembly. The seismic activity is classified by comparing the location of the seismic sensor with the amplitude and frequency value of the seismic activity it received with the location of the bottom hole assembly. For example, if the first bottom hole assembly is drilling from the left side, the seismic activity received by the left most seismic sensors may be higher values in comparison to the sensors further to the right. In the same breadth, as the second bottom hole assembly is drilling from the right side, the right most seismic sensor may additionally receive higher values of seismic activity along with the seismic activity from the first bottom hole assembly. As a result, the control unit 62 may classify the higher value seismic activity from the rightmost seismic sensor as the seismic activity of the second bottom hole assembly while the weaker seismic activity received from the rightmost seismic sensor is classified as the seismic activity of the first bottom hole assembly. This process may be conducted on each of the seismic sensors. The control unit 62 may use a velocity model software to determine the X, Y coordinates of the first bottom hole assembly and the second bottom hole assembly.

FIG. 16 illustrates a closed system pressure measurement environment for true vertical depth (TVD) determination. True vertical depth is measured from the wellhead 4, 6 to the target well TVD plane 145. The control unit 62 may determine the Z-axis of the first bottom hole assembly by calculating the true vertical depth of the first bottom hole assembly. True vertical depth may be calculated by determining the bottom hole pressure, the fluid density, surface pressure, and elevation difference between the first wellhead elevation 136 and the second wellhead elevation 137.

The bottom hole pressure may be measured in a closed end system of the bottom hole assembly with known measured fluid density. The closed end system of the first bottom hole assembly may include a drilling valve 130 and at least one first pressure sensor 129. The closed end system of the second bottom hole assembly may include a drilling valve 134 and at least one second pressure sensor 133. The pressure sensors 129, 133 may be located below their respective drilling valve 130, 134 and/or above the drilling valve 130, 134. The pressure sensor 129, 133 placement may be accommodated by ports 146 placed around the drilling valve 130, 134. The bottom hole pressure of the first well 50 may be measured by the at least one first pressure sensor 133. The bottom hole pressure of the second well 51 may be measured by the at least one first pressure sensor 133. A first surface densitometer 140 may measure the fluid density of the first well 50. A second surface densitometer 141 may measure the fluid density of the second well 51. A first surface pressure sensor 138 may measure surface pressure of the first well 50 at the first wellhead 4, relative to a first elevation 136. A second surface pressure sensor 139 may measure surface pressure of the second well 51 at the second wellhead 6, relative to a second elevation 137. The down hole pressure sensor 129, 133, the surface sensor 138, 139, and the surface densitometer 140, 141 may monitor the bottom hole pressure, the fluid density, and the surface pressure continuously or at time intervals. A down hole densitometer may also be placed in the bottom hole assembly to measure a down hole density of the fluid. The BHP may be acquired along the length of the well for a gradient survey along the measured length of the respective well bores. The bottom hole pressure, fluid density, and surface pressure may be transmitted to the control unit 62 via communication means 152.

True vertical depth of the first bottom hole assembly may be calculated by the equation:

TVD 1 = BHP 1 - SP 1 .052 × D 1

wherein TVD1 is the true vertical depth, BHP1 is the bottom hole pressure, D1 is the fluid density of the first bottom hole assembly, and SP1 is the surface pressure of first well 50 measured at the surface wellhead 4 as reference elevation.

True vertical depth of the second bottom hole assembly may be calculated by the equation:

TVD 2 = BHP 2 - SP 2 .052 × D 2 ± Δ ⁢ E

wherein TVD2 is the true vertical depth, BHP2 is the bottom hole pressure, and D2 is the fluid density of the second bottom hole assembly, SP2 is the surface pressure of the second well 51 measured at the surface wellhead 6 as reference elevation, and ΔE 142 is the change in elevation 136 of the first wellhead 4 in relation to the elevation 137 of the second wellhead 6. ΔE 142 may be the difference of the first true vertical depth 143 and the second true vertical depth 144

The control unit 62 may correlate the first bottom hole assembly and the second bottom hole assembly seismic data received from the seismic sensors with the true vertical depth calculated for each assembly. The data may be correlated based on time and order the data was received and calculated.

In some embodiments, the X, Y, Z coordinates calculated from the seismic activity may be the coordinates used to determine the positioning of the bottom hole assembly. The control unit 62 may plot the X, Y, Z coordinates in a 3D visual mapping grid model 147 as illustrated in FIG. 17. This model 147 may represent the well trajectory of the first wellbore and/or the second wellbore. For example, the model 147 may depict the second bottom hole assembly's descent from the surface plane 148 to the TVD plane 149. As the second bottom hole assembly descends to the pinpoint target 58, the fixed array 131 may receive seismic activity from the second bottom hole assembly. Based on the vectors 135 of the seismic activity, the control unit 62 may plot the location of the second bottom hole assembly on the 3D model 147. For example, the bottom hole assembly may be incoming to the TVD plane 148 and the model 147 may position the second bottom hole assembly in area 153 based on the seismic data. As the second bottom hole assembly reaches the TVD plane, the model 147 would position the assembly at area 154 based on the seismic data. Additionally, the control unit 62 may use the trajectory of the first and second bottom hole assembly to determine the trajectory of the wellbores of the first and second well 50, 51. The wellbores may be plotted for general wellbore mapping, intersection, anti-collision, drill steering, and pinpoint target 58 selection. Additionally or alternatively, the control unit 62 may calculate the X, Y, Z coordinates of the first and second bottom hole assembly via MWD and/or LWD. The control unit 62 may compare and map the X, Y, Z coordinates calculated from the seismic activity and the X, Y, Z coordinates of their respective first and second bottom hole assembly via MWD and/or LWD. This comparison map 147 may triangulate the most probable location of the first and second bottom hole assembly and estimate the end of well trajectory.

Referring back to FIG. 11B, in act 1126, when the first bottom hole assembly reaches the pinpoint target 58, the control unit 62 may process the coordinates received from first bottom hole assembly and create an end of well trajectory toward the pinpoint target 58. The control unit 62 may save the end of well trajectory and the last coordinates received from the first bottom hole assembly to be later used to revise the second well plan, further discussed below. The last coordinates and the end of well trajectory are represented by value C. Value C may be sent to act 1138 of the method of drilling the second well 51.

In some embodiments, the first drilling rig 3 may remove the first bottom hole assembly from the wellbore 17 when the first bottom hole assembly reaches the pinpoint target 58.

In alternative embodiments, when the first bottom hole assembly reaches the pinpoint target 58 the first bottom hole assembly may sit in place while drilling operations for the second well 51 are underway. FIG. 18, illustrates a method of drilling and ranging connecting the well system. Here, the first drill assembly and second drill assembly may each emit a ranging signal 42, which may be detected by the first rig ranging sensor 39 and second rig ranging sensor 40. The path of the second rig drill bit 36, may then be adjusted in real time using the second rotary steerable 38 system, further discussed below. The process may continue until the drilled open boreholes 17 form a complete loop back to the first wellhead 4 and second wellhead 6. When the complete loop back is complete the first drilling rig 3 may remove the first bottom hole assembly from the wellbore 17.

In act 1128, when the first bottom hole assembly is removed, the first drilling rig 3 may lower hole cleaners and reamers into the wellbore 17. The hole cleaner may help clear the wellbore of cuttings and debris while reamers help shape and size the wellbore for smooth production casing runs and tool passage.

In act 1130, the first drill rig 3 may lower the first casing segment 24 into the wellbore. The toe section 88 of the first casing segment 24 may include a casing shoe track 22. When the toe section reaches the pinpoint target 58, cement 18 may flow through the first casing segment 24 and directed out by the casing shoe track 22 to cement it into place. Completion of running the production casing is represented by value I which is sent to act 1150 of the method of drilling the second well 51.

Act 1130, can be illustrated by FIG. 19 describing a non-limiting embodiment of a method of lowering production casing. As indicated by motion 31, the casing segment 24 of first well 50 may be lowered from the surface of first drilling rig 3 into the borehole 17 to the subterranean formation 2.

In an alternative embodiment, FIG. 20 describes a non-limiting embodiment of a method of pulling around production casing from the surface of first well 50 to the surface of second well 51. First casing segment 24, first casing shoe track 22, second casing shoe track 23, and second casing segment 25 may be lowered from first drilling rig 3 into borehole 17, as indicated by the motion of casing segment 31. Drill pipe 20 from second drilling rig 5 may be attached to the end of the second casing segment 25 by a casing drill pipe connector 21. The drill pipe 20 may be pulled from second drilling rig 5, pulling the production casing around the full bore length from the surface of first well 50 to the surface of second well 51.

In some embodiments, the first drilling rig 3 may lower a smaller first bottom hole assembly into the first casing segment 24. As illustrated in FIG. 21, the smaller first bottom hole assembly may drill a rat hole 33 at the toe section 88, via the drill bit 35. A spotted tracer pill 34 may be placed in the rat hole 33. In some embodiments, as illustrated in FIG. 22, the spotted tracer pill 34 may travel from the surface 1 and through the drill pipe 20 to the rat hole 33. In alternative embodiments, when the production casing of casing segment 24 is set, as discussed below, the spotted tracer pill 34 may travel down the production casing to the rat hole 33. The spotted tracer pill 34 may be a chemical source such as a nuclear source, earth element, or compound within regulations. The spotted tracer pill 25 may sit at the rat hole and act as a guide for the second drilling assembly, further discussed below.

Referring back to FIG. 11B, in act 1132, operators may conduct surveys on the first casing segment 50 to verify the end of well trajectory and the pinpoint target coordinates 58. The surveys may include gyroscopic surveys and/or cased-hole magnetic surveys. The surveys may record data that includes the measured depth, inclination, and azimuth of the area leading to the toe 88. The data may be used to confirm the end of well trajectory and verify the toe section 88 coordinates in relation to the pinpoint target coordinates 58. If the toe section coordinates deviates from the pinpoint target coordinates 58, the toe section 88 coordinates may replace the pinpoint target coordinates 58 used in the drilling operation of the second well 50, further discussed below. If the toe section 88 coordinates is substantially the same as the pinpoint target coordinates 58 then the drilling operation of well 1 may still use the pinpoint target coordinates 58. The verified end of well trajectory and the pinpoint target coordinates 58 (or the toe section 88 coordinates depending on deviation) is represented by value D which is sent to act 1138 of the method of drilling the second well 51.

In act 1134, the control unit 62 of the first drilling rig 3 may transmit the end of well trajectory and the pinpoint target coordinates 58 (or the toe section 88 coordinates depending on deviation), represented by value E, to act 2502 of the second drilling rig 5 control unit 62.

FIG. 11C illustrates a method of drilling the second well 51 to create the combined well system 104.

In act 1136, operators may construct a well plan for the second well 51. The well plan may include the determination of the pinpoint coordinates 58. Additionally, the well plan may include a design of the second well's 51 trajectory to drill through the earth to the pinpoint coordinates 58 in the subterranean area 2. The trajectory may be based on factors that include reservoir geometry, surface constraints, building sections, and anti-collision analysis.

In some embodiments, when the first well 50 is pre-built, the determination of the pinpoint target coordinates 58 of the second well plan may use the pinpoint target coordinates 58 (value A) of act 1102.

In alternative embodiments, when the first well 51 is drilled, the determination of the pinpoint target coordinates 58 of second well plan may use the pinpoint coordinates 58 (value B) of act 1118.

In act 1138, operators may revise the well plan of the second well 51. The operators may verify the pinpoint target coordinates 58 by comparing the coordinates to the toe 88 coordinates. If the pinpoint targets coordinates 58 deviate from the toe 88 coordinates, then the well plan may use the toe 88 coordinates as the new pinpoint target coordinates 58.

In some embodiments, when the first well 50 is pre-built, operators may revise the well plan of the second well 51 using the planned pinpoint target coordinates 58 (value A) of act 1102.

In alternative embodiments, when the first well 51 is drilled, operators may revise the well plan of the second well 51 using the verified pinpoint target coordinates 58 of act 1126 and act 1132.

In act 1140, a second drilling rig 5 may initially drill the second well 51 to a depth. At certain depths, operators may set different casings into the second well 51. For example, a conductor casing may be set at 150 ft, a surface casing may be set at 5000 ft, etc. When the operators set the casings, cement 18 may be used to affix the casings into place.

In act 1142, operators may set an intermediate casing when the second drilling rig 5 reaches a certain depth. When the operators set the intermediate casing, cement 18 may be used to affix the intermediate casing, via casing shoe track 15.

In act 1144, operators may configure the second bottom hole assembly to include a hole finder bit, RSS, MWD and/or LWD, ranging sensors, and ahead of the bit sensors.

In act 1146, the second bottom hole assembly may drill to the pinpoint target coordinates 58. FIG. 23 further describes an embodiment of a method of pinpoint targeting. Along the 3D axis 65 of the first well 50 and second well 51, there may be a target pinpoint 58 in the center of the target casing internal diameter 63. The target pinpoint 58 may be at the terminal end of first toe section 88, or may be at any point in the center of the casing along a length 59. If the target pinpoint 58 is not at the terminal end of first toe section 88, the method may involve milling into the casing along the length 59 to reach the target pinpoint 58.

In some embodiments, beginning to drill the second well (value F) may be set to act 1108 to start determining the pinpoint target coordinates 58 with certainty.

Act 1146 can be illustrated in FIG. 24 and FIG. 25 demonstrating a non-limiting embodiment of a closed loop method of the control unit 62 using a CPU logic program to drill to the target pinpoint 58.

In act 2500, the RSS drills ahead further into in the rock formation. The distance the RSS drills may adjustable depending on systems geographical location in relation to the pinpoint target 58. For example, the further away the RSS is from the pinpoint target 58, the longer the distance the drill rig 5 drills for during each iteration of the closed loop method. In an alternative embodiment, the drill rig 5 may drill a constant distance at each iteration of the closed loop method. As the second bottom hole assembly drills to the pinpoint coordinates 58, the measuring while drilling (MWD) and/or logging while drilling (LWD) components obtain sensory data, such as toolface, formation logging, inclination, azimuth information and measured depth. Additionally, the second bottom hole assembly may emit ranging signals 42 through the subterranean area 2. The ranging signal may interact with the spotted tracer pill and reflect the signal back to the ranging sensor 40. The sensory data and the reflected signal may be transmitted to the control unit 62 via a communication means 61 (e.g. wireless, wireline, electromagnetic, or mud pulse telemetry). The surface control unit 62 may monitor real-time or near real-time sensory data. The control unit 62 may operate at the discretion of the directional driller personnel or an automated drilling software (“CPU”) at the second drilling rig 5. After the drill rig 5 reaches the certain distance the method moves to act 2502.

In act 2502, in some embodiments, the control unit 62 may receive the sensory data and the reflected signal. Additionally, the control unit 62 may receive the pinpoint target coordinates 58 (value E) from act 1134. The control unit 62 may use the sensory data to calculate Easting, Northing, and TVD as the X, Y, and Z coordinates of the current position of the second bottom hole assembly. The control unit 62 may determine the distance and angle the toe 88 is from the second bottom hole assembly by comparing the current coordinates with the pinpoint target coordinates 58.

Additionally, the control unit 62 may use the reflected signal to determine the distance and angle the toe 88 is from the second bottom hole assembly. The control unit 62 may determine the distance by measuring the time difference between the ranging sensor sending the ranging signal 42 and when the ranging sensor received the reflected signal. Additionally or alternatively, the control unit 62 may determine the distance by measuring the strength of the reflected signal. Alternatively, the directional driller may receive the reflected signal, via the control unit 62, and determine the distance of the second bottom hole assembly based on either the time difference and/or the strength of the reflected signal.

In some embodiments, the control unit 62, similar to the control unit 62 as discussed above, may receive seismic data from the seismic sensors, bottom hole pressure from the pressure transducer, and the fluid density from the surface densitometer. The control unit 62 may use the seismic data, bottom hole pressure, and fluid density values to calculate the X, Y, Z coordinates of the second bottom hole assembly, as discussed above. The control unit 62 may determine the distance and angle the toe 88 is from the second bottom hole assembly by comparing these coordinates with the pinpoint target coordinates 58.

In some embodiments, magnets or other detectable devices (sonic, nuclear, thermal, electrical) may be placed in or on the end first casing segment 24 near the pinpoint target 58 to further facilitate locating the target by the ranging sensor on the second well 51 drilling assembly.

In alternative embodiments, after the first bottom hole assembly reaches the pinpoint target 58 of act 1124, the first bottom hole assembly may sit at the pinpoint target 58. FIG. 18, illustrates a method of drilling and ranging connecting the well system. The first bottom hole assembly may include a first rig ranging sensor 39. The first drill assembly and second drill assembly may each emit a ranging signal 42, which may be detected by the first rig ranging sensor 39 and second rig ranging sensor 40. The first bottom hole assembly and the second bottom hole assembly may transmit the ranging signals 42 received to the control unit 62. The control unit 62 may process the ranging signals 42 to determine the distance the second bottom hole assembly is from the first bottom hole assembly.

In act 2504, the control unit 62 may determine whether the second drilling rig 5 has reached the pinpoint target 58. The control unit 62 may compare the current coordinates with the pinpoint target coordinates 58. If the second drill rig 5 reaches the pinpoint target 58, the second drill rig 5 stops. If the second drill rig 5 did not reach the pinpoint target 58, the method goes to act 2506.

In act 2506, the control unit 62 may determine steering commands for the second bottom hole assembly based on the comparison.

In act 2508, the control unit 62 may transmit the steering commands downhole via the communication means 61 to the RSS. The RSS may receive the steering commands and converts the command into a mechanical action.

In act 2510, the RSS may adjust the hole finder bit 60 of the second drilling rig 5 toward the target pinpoint 58. The process continues this loop until the control unit 62 determines that the second drilling rig has reached the pinpoint target 58 and the process stops.

Magnets or other detectable devices (i.e. sonic, nuclear, thermal, explosive, and electrical) may be placed in or on the casing near the pinpoint target to 58 further facilitate locating the target 58 by the ranging sensor on the second well 51 drilling assembly.

Referring back to FIG. 11C, in act 1148, the operators may verify that the second well 2 is connected to the first well 51. In some embodiments, the operators may look for a fluid pressure drop for mudding procedures as the second bottom hole assembly is drilling. Additionally or alternatively, operators may look for an increase in the drill bit rate. Additionally or alternatively, the operators may look for an increase in the rate of penetration of the second bottom hole assembly. Additionally or alternatively, the operators may look at the mudding material that reaches the surface 1 to see if any of the spotted tracer pill 34 material is mixed with the mud.

In some embodiments, confirmation (value G) of the second well 50 borehole touching the first casing segment 24 may be sent to act 1116.

In act 1150, the second drilling rig 5 may lower the casing segment 25 with the connector at the end into the wellbore.

In some embodiments, when the first well 50 is pre-built, act 1150 commences when verification (value H) of the first casing segment 24 is touching the second well 51 borehole.

In alternative embodiments, when the first well 50 is being drilled, act 1150 commences when verification (value I) of the first casing segment 24 is touching the second well 51 borehole.

In act 1152, the drilling rig may connect the casing segment 25 with the casing segment 24 via the connector. Act 1152 can be illustrated by FIG. 19 describing a non-limiting embodiment of a method of lowering production casing. As indicated by the motion 31, the casing segment production casing 25 is lowered from the surface of second drilling rig 5 of second well 51, along with shoe track 15 and connector 11, into the borehole 17 to the subterranean formation 2. The connector 11 connects casing segment 24 to casing segment 25. FIG. 19 shows the full bore system with casing connected with full bore connector. The system may also be non-full bore in nature. Using this method, full mirror image access may be permitted to the first well 50 well bore from the second well 51 well bore.

In an alternative embodiment, as discussed above, FIG. 20 describes a non-limiting embodiment of a method of pulling around production casing from the surface of first well 50 to the surface of second well 51. First casing segment 24, first casing shoe track 22, second casing shoe track 23, and second casing segment 25 may be lowered from first drilling rig 3 into borehole 17, as indicated by the motion of casing segment 31. Drill pipe 20 from second drilling rig 5 may be attached to the end of the second casing segment 25 by a casing drill pipe connector 21. The drill pipe 20 may be pulled from second drilling rig 5, pulling the production casing around the full bore length from the surface of first well 50 to the surface of second well 51. A complete combined well system 104 is illustrated in FIG. 26 that shows the full bore system with casing pulled around. The system 104 may also be non-full bore in nature. Using this method, full mirror image access may be permitted to the first well 50 well bore from the second well 51 well bore.

Referring back to FIG. 11C, in act 1154, when the drilling phase is finished, the completion process prepares the combined well system 104 for safe, controlled, and efficient production.

Act 1154 can be illustrated by FIG. 27. FIG. 27 illustrates a method for conducting the completion process. In act 2702, casing segments 24, 25 may be cemented into place.

Act 2702 can be illustrated by FIG. 28 that shows a non-limiting embodiment of a method for cementing first casing segment 24 and second casing segment 25 using opposing casing shoe tracks. Cement 18 from first drilling rig 3 may be pumped through first casing segment 24 and first casing shoe track 22, where the cement 18 exits the first casing shoe track 22 and fills drilled open borehole 17 as indicated by first cement flow 57. Similarly, cement 18 from second drilling rig 5 may be pumped through second casing segment 25 and second casing shoe track 23, where the cement 18 exits second casing shoe track 23 and fills drilled open borehole 17, as indicated by second cement flow 56.

Referring back to FIG. 27, in act 2704, the casing segments 24, 25 may be cleaned out. The cleaning process may involve mechanical, chemical, hydraulic methods, or a combination thereof, using tools and fluids to clean the casing interior.

In act 2706, logging tools may be run through the casing segments 24, 25. The logging tools may include cased-hole logs to verify cement integrity and production logs to collect data to help determine target areas to perforate along the casing segments 24, 25.

In act 2708, a plug, perforate, and frack sequence may be conducted on the casing segments 24, 25 as illustrated by FIG. 29. The first wellhead 4 and second wellhead 6 may perform the plug, perforate, and frack sequence. In some embodiments, placement equipment may lead from either the wellhead 4 or second wellhead 6 to a midway point along the combined well system 104. The placement equipment may set the permanent or temporary isolation plug 26 at the midway point. The isolation plug 26 may create two separation regions of effect of the combined well system 104, each designated to either the first well 50 or the second well 51 operations. The creation of the two separate regions may shorten the length of the combined well system that both the first wellhead 4 and the second wellhead 6 performs the plug, perforate, and frack sequence on. By shortening operators may operate equipment within safe operating limits. In long well lateral sections, friction pressure in the first well 50 and the second well 51 may become very high at high fracking rates. These pressures may approach or exceed safe operating specifications of well equipment such as casings, tubing, liner hangers, wellheads, etc. By isolating the toe sections 88, 89 of a long lateral well and fracking the toe sections 88, 89 from a shortened second well 51, pressures may be reduced to safe operating limits. Additionally, as the fracture treatment 67 may travel a shortened distance from second wellhead 6 to first toe section 88, improved fracture performance may be noted as compared to fracturing the same section from first wellhead 4.

In some embodiments, the placement equipment may place frac plugs 78 to isolate target areas along the combined system 104 allowing each target area to be fractured individually with controlled pressure, flow, and proppant placement. The plugs may seal off previously perforated and fractured target areas to prevent fluid and pressure from escaping current perforation and fracture stages. Additionally, the isolation of target areas enables custom treatment operations for each target area (i.e. different fluid types, rates, or proppant volumes).

In some embodiments, when the frac plug 78 is set, perforation operations may be conducted from the first wellhead 4 and the second wellhead 6 by lowering perforation equipment down their respective casing segment 24, 25. The perforation operations may be conducted at the target area of the casing segments 24, 25.

In some embodiments, when perforation operations is finished on the target area, the frack pump unit 71 may pump fracture treatment down the first casing segment 24 and/or the second casing segment 25. The fracture treatment of the first well 50 may follow a flow path 66 while the fracture treatment of the second well 50 may follow a flow path 67. The fracture treatments may flow to the target area on the inward side of the isolation plug 26. Fracking operations may initiate at the target area closest to the isolation plug 26, in relation to where the fracture treatment is pumped from, and proceeding from the isolation plug 26 towards their respective heel 90, 91.

In some embodiments, the plug, perforate, and frack sequence of each wellhead 4, 6 may begin from the isolation plug 26 to their respective heel 90, 91. For example, the first wellhead 4 may perform the plug, perforate, and frack sequence may start at the isolation plug 26 to heel 90, as illustrated by motion 153. Similarly, the second wellhead 6 may perform the plug, perforate, and frack sequence may start at the isolation plug 26 to heel 91, as illustrated by motion 154.

FIG. 30 shows a non-limiting embodiment of a method for reducing skin damage during the plug perforate and frack sequence. In a combined system 104, fracture treatment 66 may be pumped from a fracture pump unit 71 to fracture clusters 16. For example, the plug, perforate, and fracture stages may proceed from the isolation plug 26 (not shown) (in this example, located at the first toe section 88) to the first heel section 90 to targeted areas in the subterranean formation 2. Targeted areas are determined by frac plug 78 placement along casing segment 24. The frac plug 78 may plug off the targeted area from the second well 51. As the plug, perforate, and fracture stages are complete in one target area (i.e. the fracture 16 cluster is formed), the stages are performed in the next targeted area with the frac plug 78 plugging off the stages from the completed target area, as illustrated by motion 155. Simultaneously, the second drill rig 5 may direct a coiled drill pipe 73, comprising a drill bit clean out assembly 76, from second wellhead 6 through each targeted area to clean drill out the fracture clusters 16, as illustrated by motion 156. To allow the coiled drill pipe 73 access the entire first toe section 88 to the first heel section 90, the placement equipment may remove the isolation plug 26.

These simultaneous operations may drastically limit the time that frac treatment water or fluids are in the fracture network or formation matrix. In the subterranean formation, natural formation clays may swell in the presence of these frac fluids. Swollen clays reduce the permeability of reservoir fluids or cause excessive skin damage and ultimately reduce reservoir fluid flow rates. Therefore, reducing the swelling of clays, may result in better reservoir performance. Fluid from the drill out process is directed up to second wellhead 6 and discharged according to clean out flow direction 74.

The plug, perforate, and frack sequence may allow a reduction skin damage by simultaneously completing in first casing segment 24 while drilling out and cleaning up the well from second casing segment 25. Normally, a well is completed from the toe section towards the heel section in fracture stages. The time required to frack the required number of stages may vary but can be from a few days to weeks. After the fracking stage, the fracture plugs must be drilled out, which can further take days to weeks to months to complete. During this time, frac fluids and water pumped into subterranean formation 2 causes subterranean formation clays to swell resulting in formation damage. The resulting damage reduces permeability of the fracture and fractured rock matrix reducing production rates and increasing pressure drawdown loss due to skin effect.

Act 2708 may be illustrated by FIG. 31 that shows a method for the plug, perforate, and frack sequence.

In act 3102, placement equipment may set the isolation plug 26 along the casing segment 24, 25 of the combined well system 104. The isolation plug 26 may be an isolation plug 26 set anywhere along the lateral well section of the combined well system 104. The isolation plug 26 placement along the casing segments 24, 25 may define target areas on both sides of the isolation plug 26 to have the closest respective wellhead 4, 6 conduct perforation and/or fracking operations on.

In act 3104, perforation equipment may perform perforation operations at the first target area on the first well 50 region of effect closest to the isolation plug 26. When the perforations of act 3104 are complete, the sequence may proceed to act 3108. Similarly, in act 3106, perforation equipment may perform perforation operations at the first target area on the second well 51 region of effect closest to the isolation plug 26. When the perforations of act 3106 are complete, the sequence may proceed to act 3110.

In act 3108, fracking equipment may perform fracking operations at the first target area on the first well 50 region of effect closest to the isolation plug 26. Similarly, in act 3110, fracking equipment may perform fracking operations at the first target area on the second well 51 region of effect closest to the isolation plug 26. When the fracking operations of act 3108 and 3110 are complete, the sequence may proceed to act 3112.

In act 3112, placement equipment may set a second frac plug 78 along the area of effect of the first well 50. The frac plug 78 may define target areas in the area of effect of the first well 50. When the second isolation plugs 26 of act 3112 are set, the sequence may proceed to act 3116. Similarly, in act 3114, placement equipment may set a second frac plug 78 along the area of effect of the second well 51. The frac plug 78 may define target areas in the area of effect of the second well 51. When the second isolation plugs 26 of act 3114 are set, the sequence may proceed to act 3118.

In act 3116, perforation equipment may perform perforation operations at the target area along the area of effect of the first well 50. When the perforations of act 3116 are complete, the sequence may proceed to act 3120. Similarly, in act 3118, perforation equipment may perform perforation operations at the first target area on the second well 51 region of effect closest to the isolation plug 26. When the perforations of act 3118 are complete, the sequence may proceed to act 3122.

In act 3120, the frack pump 71 unit may pump fracking fluids to the target area along the area of effect of the first well 50. When the fracking of act 3120 is complete, the sequence may proceed to act 3124. Similarly, in act 3122, fracking equipment may perform fracking operations at the first target area on the second well 51 region of effect closest to the isolation plug 26. When the fracking of act 3122 is complete, the sequence may proceed to act 3126.

In act 3124, operators may remove the frac plug 78 from the first well 50 area of effect. When removal in act 3124 is complete, the sequence may proceed to act 3128. Similarly, in act 3126 operators may remove the frac plug 78 from the second well 51 area of effect. When removal is complete in act 3126 is complete, the sequence may proceed to act 3130. The removal of the frac plug 78 may depend on the type of frac plug 78 used. For example, the frac plug 78 may be removed by way of drilling, milling, detonation, dissolving, disintegrating, etc.

In act 3128, operators of the first wellhead 4 may determine if the target area the plug, perforation, and frack sequence is operating on is the last target area closest to the heel 90. When the plug, plug, perforate and frack sequence on the last target area is complete the sequence may stop for the first well 50 region of effect. Similarly, in act 3130, operators of the second wellhead 6 may determine if the target area the plug, perforation, and frack sequence is operating on is the last target area closest to the heel 91. When the plug, plug, perforate and frack sequence on the last target area is complete the sequence may stop for the second well 51 region of effect.

Referring back to FIG. 27, when the plug, perforate, and frack sequence of act 2708 is complete, the method may proceed to act 2710.

In act 2710, operators may run production tubing through the first casing segment 24 and the second casing segment 25. The production tubing may be run by lowering production tubing through either the first well 50 or second well 51 until production tubing reaches the entry point of the opposing well.

Referring back to FIG. 11C, when the completion process of act 1154 is complete, the combined well system 104 may start well cleanup and flowback, artificial lift installation, workover operations, and oil and gas production.

While various embodiments have been described above, it should be understood that they have been presented by way of example and not limitation. It will be apparent to persons skilled in the relevant art(s) that various changes in form and detail may be made therein without departing from the spirit and scope. In fact, after reading the above description, it will be apparent to one skilled in the relevant art(s) how to implement alternative embodiments. For example, other acts may be provided, or acts may be eliminated, from the described flows, and other components may be added to, or removed from, the described systems. Accordingly, other implementations are within the scope of the following claims.

In addition, it should be understood that any figures which highlight the functionality and advantages are presented for example purposes only. The disclosed methodology and system are each sufficiently flexible and configurable such that they may be utilized in ways other than that shown.

All the features disclosed in this specification (including any accompanying claims, abstract, and drawings) may be replaced by alternative features serving the same, equivalent or similar purpose, unless expressly stated otherwise. Thus, unless expressly stated otherwise, each feature disclosed is one example of a generic series of equivalent or similar features.

Although the term “at least one” may often be used in the specification, claims and drawings, the terms “a”, “an”, “the”, “said”, etc. also signify “at least one” or “the at least one” in the specification, claims and drawings.

Any element in a claim that does not explicitly state “means for” performing a specified function, or “step for” performing a specific function, is not interpreted as a “means” or “step” clause as specified in 35 U.S.C. § 112(f). In particular, the use of “step of” in the claims herein is not intended to invoke the provisions of 35 U.S.C. § 112(f).

Whereas, the devices and methods have been described in relation to the drawings and claims, it should be understood that other and further modifications, apart from those shown or suggested herein, may be made within the spirit and scope of this invention.

Further Example Embodiments

The following examples pertain to further embodiments, from which numerous permutations and configurations will be apparent.

Example 1 is a combined well system. The system comprising a first well, the first well comprising a first casing segment, wherein the first casing segment has a first toe end, a second well, the second well comprising, a second casing segment, wherein the second casing segment has a second toe end, and a connector, wherein the connector connects the first toe end and the second toe end thereby connecting the first casing segment to the second casing segment.

Example 2 includes the system of example 1 wherein the connected first casing segment and second casing segments provides a hydraulic and mechanical communication from a second surface of the second well to a first surface of the first well.

Example 3 includes the system of example 1, further comprising an isolation plug.

Example 4 includes the system of example 3, wherein the isolation plug partitions the combined well system into two regions.

Example 5 includes the system of example 4, wherein a first region of the two regions is designated for a first well operation and a second region of the two regions is designated for a second well operations.

Example 6 includes the system of example 4, wherein a fracking operation and a production operation occur on both sides of the isolation plug.

Example 7 includes the system of example 4, wherein the isolation plug isolates a production operation from an injection operation.

Example 8 includes the system of example 4, wherein a first region of the separate regions has a first drawdown pressure and a second region of the separate regions has a second drawdown pressure.

Example 9 includes the system of example 8, wherein the first drawdown pressure creates a first flow regime to the first well and the second drawdown pressure creates a second flow regime to the second well.

Example 10 includes the system of example 3, wherein the isolation plug allows no operational interference between the first well and the second well.

Example 11 includes the system of example 1, wherein a first well drawdown pressure and a second well drawdown pressure may be applied to the combined well system.

Example 12 is a method of forming a combined well system, the method comprising drilling a first well to a pinpoint target coordinates, via a first bottom hole assembly, drilling a second well to the pinpoint target coordinates, via a second bottom hole assembly, and connecting the first well to the second well.

Example 13 includes the method of example 12 further comprising, placing a first casing segment in the first well and a second casing segment in the second well, wherein a first toe end of the first well is positioned at the pinpoint target coordinates, and connecting the first casing segment to the second casing segment, via a connector.

Example 14 includes the method of example 12 further comprising, setting an isolation plug along the first casing segment or the second casing segment.

Example 15 includes the method of example 12 further comprising, drilling a rat hole at a first toe end of the first casing segment, deploying a spotted tracer pill into the rat hole, detecting the spotted tracer pill, via a ranging sensor on the second bottom hole assembly, calculating, via a control unit, a ranging and distance coordinates between the spotted tracer pill and a second bottom hole assembly coordinates, and adjusting the second bottom hole assembly towards the rat hole based on the ranging and distance coordinates.

Example 16 includes the method of example 12, wherein the first bottom hole assembly drills to the pinpoint target coordinates at a high angle, low angle, or horizontal approach.

Example 17 includes the method of example 12 further comprising, performing a plug, perforate, and frack sequence, wherein the plug, perforate, and frack sequence comprises, plugging at least one target area, perforating the at least one target area, and fracking the at least one target area.

Claims

1. A combined well system, the system comprising:

a first well, the first well comprising: a first casing segment, wherein the first casing segment has a first toe end;
a second well, the second well comprising: a second casing segment, wherein the second casing segment has a second toe end; and a connector, wherein the connector connects the first toe end and the second toe end thereby connecting the first casing segment to the second casing segment.

2. The combined well system of claim 1, wherein the connected first casing segment and second casing segments provides a hydraulic and mechanical communication from a second surface of the second well to a first surface of the first well.

3. The combined well system of claim 1, further comprising an isolation plug.

4. The combined well system of claim 3, wherein the isolation plug partitions the combined well system into two regions.

5. The combined well system of claim 4, wherein a first region of the two regions is designated for a first well operations and a second region of the two regions is designated for a second well operations.

6. The combined well system of claim 4, wherein a fracking operation and a production operation occur on both sides of the isolation plug.

7. The combined well system of claim 4, wherein the isolation plug isolates a production operation from an injection operation.

8. The combined well system of claim 4, wherein a first region of the separate regions has a first drawdown pressure and a second region of the separate regions has a second drawdown pressure.

9. The combined well system of claim 8, wherein the first drawdown pressure creates a first flow regime to the first well and the second drawdown pressure creates a second flow regime to the second well.

10. The combined well system of claim 3, wherein the isolation plug allows no operational interference between the first well and the second well.

11. The combined well system of claim 1, wherein a first well drawdown pressure and a second well drawdown pressure may be applied to the combined well system.

12. A method of forming a combined well system, the method comprising the steps of:

drilling a first well to a pinpoint target coordinates, via a first bottom hole assembly;
drilling a second well to the pinpoint target coordinates, via a second bottom hole assembly; and
connecting the first well to the second well.

13. The method of forming a combined well system of claim 12 further comprising:

placing a first casing segment in the first well and a second casing segment in the second well, wherein a first toe end of the first well is positioned at the pinpoint target coordinates; and
connecting the first casing segment to the second casing segment, via a connector.

14. The method of forming a combined well system of claim 12 further comprising:

setting an isolation plug along the first casing segment or the second casing segment.

15. The method of forming combined well system of claim 12, the method further comprising:

drilling a rat hole at a first toe end of the first casing segment;
deploying a spotted tracer pill into the rat hole;
detecting the spotted tracer pill, via a ranging sensor on the second bottom hole assembly;
calculating, via a control unit, a ranging and distance coordinates between the spotted tracer pill and a second bottom hole assembly coordinates; and
adjusting the second bottom hole assembly towards the rat hole based on the ranging and distance coordinates.

16. The method of forming the combined well system of claim 12 wherein the first bottom hole assembly drills to the pinpoint target coordinates at a high angle, low angle, or horizontal approach.

17. The method of forming a combined well system of claim 12 further comprising:

performing a plug, perforate, and frack sequence, wherein the plug, perforate, and frack sequence comprises: plugging at least one target area; perforating the at least one target area; and fracking the at least one target area.
Patent History
Publication number: 20250354468
Type: Application
Filed: May 19, 2025
Publication Date: Nov 20, 2025
Applicant: Combined Well Systems, LLC (Eufala, OK)
Inventor: Charles Edwin Vise, JR. (Eufaula, OK)
Application Number: 19/212,105
Classifications
International Classification: E21B 43/17 (20060101);