Patent Publication Number: US-2015083495-A1

Title: Systems and Methods for Vertical Depth Control During Extended-Reach Drilling Operations

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Patent Application No. 61/657,361, filed Jun. 8, 2012, the complete disclosure of which is hereby incorporated by reference. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure is directed generally to systems and methods for vertical depth control during extended-reach drilling operations, and more particularly to systems and methods that utilize reference pressure within a subsurface region for improved depth control. 
     BACKGROUND OF THE DISCLOSURE 
     Extended-reach drilling (ERD) operations often involve drilling a wellbore that includes a vertical or angled portion and that also includes a horizontal portion. The vertical or angled portion may extend between a surface region and a reservoir, while the horizontal portion may extend within the reservoir. Generally, accurate placement of the horizontal portion of the wellbore within and/or near the target depth, or target vertical depth, may be desirable. Accordingly, it may be desirable to locate the horizontal portion at a target depth within the reservoir, in order to decrease a potential for premature water and/or gas production from the reservoir and/or to permit standoff to and/or from reservoir boundaries. This target depth also may be referred to herein as a target total vertical depth (TVD). 
     Traditional measurement while drilling (MWD) surveying techniques rely upon accelerometers, gravitometers, magnetometers, and/or gyroscopes, hereinafter collectively referred to as surveying techniques, traditional surveying techniques, MWD surveying techniques, and/or standard MWD survey techniques, to measure an angle of inclination and/or an angle of azimuth of the wellbore at a given point in time during the drilling operation. These traditional MWD surveying techniques have inherent uncertainties associated with the use thereof. As an illustrative, non-exclusive example, traditional MWD surveying techniques only may be able to determine the angle of inclination and/or the angle of azimuth at any given time to within a threshold value and/or within a threshold accuracy. Thus, an uncertainty of a TVD that is determined thereby may be an integrated and/or cumulative uncertainty that increases with a length of the wellbore. 
     As an illustrative, non-exclusive example, standard MWD surveying techniques may have a TVD uncertainty of ±1.0-1.5 m for every 1000 m of wellbore length. Even under the best conditions and utilizing the most stringent conventional quality control techniques, this uncertainty only may be reduced to approximately ±0.6 m for every 1000 m of wellbore length. 
     While this level of uncertainty may be sufficient under certain conditions and/or in certain drilling operations, it may preclude, or at least hinder, the effective use of extended-reach drilling operations under other conditions and/or in other drilling operations. As an illustrative, non-exclusive example, an extended-reach drilling operation may be utilized to produce a wellbore with a length of 12,000 m (or more) and may target a reservoir that is (or that includes an oil column and/or an oil-filled region that is) only 10-20 m thick. Under these conditions, traditional MWD surveying techniques would have a vertical uncertainty within the reservoir of ±7-18 meters, which is significantly larger than a vertical uncertainty that may be needed to accurately place the wellbore within, or at least near, a target TVD within the reservoir (such as a vertical center, or other desired depth, of the reservoir). Thus, there exists a need for improved systems and methods for vertical depth control during extended-reach drilling operations. 
     SUMMARY OF THE DISCLOSURE 
     Systems and methods for vertical depth control during extended-reach drilling operations are disclosed herein. The methods may include extending a length of a wellbore to locate a directional drilling assembly at a selected location within an intermediate portion of a subsurface region and detecting a detected pressure at the selected location. The methods further may include determining an expected pressure at the selected location, comparing the detected pressure to the expected pressure, and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparison. The expected pressure may be determined based, at least in part, on a reference pressure that was detected previously within the intermediate portion of the subsurface region. The systems may include extended-reach drilling operations and/or directional drilling assemblies that include and/or are associated with controllers that are programmed to perform the methods. 
     In some embodiments, the orientation of the directional drilling assembly may be adjusted to adjust a trajectory of the wellbore within the subsurface region. In some embodiments, the adjusting may include increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being more than the expected pressure and/or decreasing the angle of inclination responsive to the detected pressure being less than the expected pressure. In some embodiments, the systems and methods further may include determining an orientation adjustment magnitude. 
     In some embodiments, the systems and methods may include detecting the reference pressure. In some embodiments, the wellbore is a second wellbore and the reference pressure is detected within a first wellbore that is spaced apart from the second wellbore. In some embodiments, the reference pressure is detected at a reference location. In some embodiments, the systems and methods further include calculating a reference depth of the reference location. 
     In some embodiments, the systems and methods may include detecting a plurality of reference pressures at a plurality of reference locations. In some embodiments, the systems and methods further may include determining a plurality of reference depths of the plurality of reference locations. In some embodiments, the systems and methods further may include determining a pressure vs. depth profile within the intermediate and/or reservoir portion of the subsurface region. 
     In some embodiments, the systems and methods may include repeating at least a portion of the methods a plurality of times to extend the wellbore from the surface region to the wellbore. In some embodiments, the systems and methods further may include extending the wellbore within the reservoir. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic representation of illustrative, non-exclusive examples of an extended-reach drilling operation that may include and/or be utilized with the systems and methods according to the present disclosure. 
         FIG. 2  is a plot of depth vs. pressure that may be obtained from and/or utilized with the systems and methods according to the present disclosure. 
         FIG. 3  is a flowchart depicting methods according to the present disclosure of controlling a directional drilling assembly. 
     
    
    
     DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE 
       FIG. 1  is a schematic representation of illustrative, non-exclusive examples of an extended-reach drilling operation  20  that may include and/or be utilized with the systems and methods according to the present disclosure. As illustrated in solid lines in  FIG. 1 , a drilling rig  30  may be utilized to drill a first well  40  that extends between a surface region  22  and a reservoir  80  that is located within a subsurface region  24 . Reservoir  80  also may be referred to herein as a subterranean formation  80  and/or as a target formation  80 . Reservoir  80  may include a gas-filled region  82 , which may include a gas  83 , and an oil-filled region  84 , which may contain oil  85  and which also may be referred to herein as a pay zone  84 . One or more upper formations  26  may be located in an intermediate portion  25  of subsurface region  24  that extends between surface region  22  and reservoir  80 . In addition, one or more lower formations  28  may be located vertically below reservoir  80 . 
     As illustrated in  FIG. 1  at  86 , subsurface region  24  may define a fluid barrier between upper formation  26  and gas-filled region  82 , which may permit gas  83  that is present within gas-filled region  82  to remain therein. In addition, subsurface region  24  further may define a gas-oil interface  88 , which also may be referred to herein as a gas-oil contact region  88 , and may define a boundary between gas-filled region  82  and oil-filled region  84 . Similarly, subsurface region  24  also may define an oil-water interface  90 , which also may be referred to herein as an oil-water contact region  90 , and may define a boundary between oil-filled region  84  and lower formation  28 . 
     Extended-reach drilling operation  20 , and/or drilling rig  30  thereof, may utilize a directional drilling assembly  70  to drill a first wellbore  42 , which also may be referred to herein as a wellbore  42 , that is associated with and/or defines first well  40 . Directional drilling assembly  70  may permit control of an orientation of wellbore  42  and/or of a path, or trajectory, of wellbore  42  as it extends through subsurface region  24 . As illustrated in  FIG. 1 , reservoir  80  may be spaced apart from drilling rig  30  in a horizontal direction  60  and also in a vertical direction  62 . As such, directional drilling assembly  70  may be directed and/or steered during operation of drilling rig  30  such that wellbore  42  extends along a desired path, or trajectory, within subsurface region  24 , such that a portion of wellbore  42  enters, or is located within, reservoir  80 , and/or such that a portion of wellbore  42  extends within and/or proximal to a desired portion of reservoir  80 . 
     Directional drilling assembly  70  may utilize measure while drilling (MWD) surveying techniques and/or equipment  71  to estimate and/or approximate the trajectory and/or TVD of a given point along a length of wellbore  42  within subsurface region  24 . However, and as discussed, the positional uncertainty of the wellbore associated with the use of MWD surveying techniques increases with increased length of wellbore  42 . Thus, and for long wellbores  42 , for large distances between drilling rig  30  and reservoir  80  in horizontal direction  60 , for large distances between drilling rig  30  and reservoir  80  in vertical direction  62 , and/or for small thicknesses, or depths,  92  of reservoir  80 , gas-filled region  82 , and/or oil-filled region  84 , it may be difficult to accurately locate wellbore  42  within a desired portion of oil-filled region  84  (such as may be defined by a target total vertical depth (TVD)  64  of a portion of wellbore  42  that extends within oil-filled region  84 ). 
     Thus, and as illustrated in  FIG. 1 , conventional extended-reach drilling operations may utilize a pilot leg  44  to determine a location of gas-oil interface  88  and to determine a location of oil-water interface  90 . Subsequently, the pilot leg may be plugged and a separate production leg  46  may be drilled at and/or near target TVD within oil-filled region  84 . In general, such a procedure may decrease and/or eliminate the measurement uncertainty associated with the portion of wellbore  42  that extends within intermediate portion  25  of subsurface region  24  and thereby may permit more accurate location of production leg  46  within the desired portion of oil-filled region  84  (and/or at target TVD  64 ). However, drilling of pilot leg  44 , plugging of pilot leg  44 , and subsequent drilling of production leg  46  may be a labor- and/or time-intensive process that may significantly increase an overall cost associated with producing oil  85  from reservoir  80 , especially when a plurality of wells are to be drilled within the reservoir and the above-described procedure must be repeated for each of the wells. 
     With this in mind, the systems and methods according to the present disclosure are configured to collect pressure data, such as through the use of a pressure gauge  72 . This pressure data may include any suitable pressure that is, is indicative of, and/or is related to, a pressure at a given point within subsurface region  24  prior to formation of wellbore  42  therein. Thus, the pressure data may be different and/or distinct from a hydrostatic pressure that may be measured within a drilling mud that fills a wellbore during drilling of the wellbore. As an illustrative, non-exclusive example, and when upper formation  26  includes one or more water sands formations, the pressure data may include the pressure of the water that is present within the water sands layer. As additional illustrative, non-exclusive examples, this pressure data also may include the pressure of gas  83  that may be present in gas-filled region  82 , the pressure of oil  85  that may be present in oil-filled region  84 , the pressure of any suitable fluid that may be present within upper formation  26 , and/or the pressure of any suitable fluid that may be present within lower formation  28 . 
     Pressure gauge  72  may be associated with drilling rig  30  and/or may be configured to collect pressure at or near directional drilling assembly  70  and/or at or near a terminal end of a drill string  74  that may include directional drilling assembly  70  and that may be utilized to form wellbore  42 . This may include collecting pressure data during the drilling of first well  40  (including during the drilling of pilot leg  44  and/or of production leg  46  thereof) and utilizing this pressure data during drilling of a second, or subsequent, well  50  that also may extend between surface region  22  and oil-filled region  84 . This process may decrease a time and/or expense associated with drilling second well  50  (such as by elimination of a need to drill pilot leg  44 ), thereby decreasing an overall cost associated with producing gas  83  and/or oil  85  from reservoir  80 . As illustrative, non-exclusive examples, utilizing the pressure data during drilling of second well  50  may decrease the time needed to drill the second well by at least 20%, at least 30%, at least 40%, at least 50%, or at least 60%. As a more specific but still illustrative, non-exclusive example, consider the time and expense savings when the systems and methods disclosed herein are utilized to reduce a drilling time for a 12,000 meter-long well from 120 days to 60 days. The drilling may be performed and/or controlled manually and/or using any suitable controller  96 , which may be programmed to control the operation of extended-reach drilling operation  20  using methods  200 , which are discussed herein. 
       FIG. 1  illustrates extended-reach drilling operation  20  as including two wells, namely, first well  40  and second well  50 . However, it is within the scope of the present disclosure that extended-reach drilling operation  20  may be utilized to form more than two wells within subsurface region  24  and/or that subsurface region  24  may include more than two wells. As illustrative, non-exclusive examples, subsurface region  24  may include a plurality of wells including at least 3 wells, at least 4 wells, at least 5 wells, at least 6 well, at least 8 wells, at least 10 wells, or more than 10 wells. 
     When subsurface region  24  includes a plurality of wells, it is within the scope of the present disclosure that the systems and methods disclosed herein may be utilized to form a portion, or all, of the plurality of wells. As an illustrative, non-exclusive example, the pressure data that is collected during the drilling of first well  40  may be utilized during the drilling of a portion, or all, of the subsequent wells that may be drilled within the subsurface region. As another illustrative, non-exclusive example, pressure data that is collected during drilling of a given well (which may or may not be first well  40 ) may be utilized during drilling of a portion, or all, of the wells that may be drilled subsequently to drilling of the given well. 
       FIG. 2  is an illustrative, non-exclusive example of a plot of depth (as determined from MWD surveying techniques) vs. pressure that may be obtained from and/or utilized with the systems and methods according to the present disclosure. In  FIG. 2 , solid, or filled, symbols represent pressure data that may be collected during the drilling of first well  40 , while open, or unfilled, symbols represent pressure data that may be collected during the drilling of second well  50  (as also illustrated in  FIG. 1 ). 
     As illustrated in solid circles in  FIG. 2 , one or more pressure measurements may be collected at one or more depths (as determined from MWD surveying techniques) within intermediate portion  25  of subsurface region  24  during the drilling of first well  40 . These one or more pressure measurements may be utilized to determine an upper formation pressure gradient  100  (i.e., a slope of the line that connects the solid circles), which also may be referred to herein as, and/or may be, a pressure gradient  100  and/or as a pressure vs. depth profile  100 . When subsurface region  24  includes only a single upper formation  26  and/or when subsurface region  24  includes a plurality of upper formations  26  that are in fluid communication with one another, these pressure measurements may fall on, or nearly on, a straight line, as illustrated. 
     However, and when subsurface region  24  includes a plurality of upper formations  26  that are hydraulically isolated from one another, a pressure step change may be observed upon transitioning from one layer to the next. This pressure step change may be at least substantially similar to a pressure step change  110 , which is discussed in more detail herein, and the systems and methods according to the present disclosure may include determining a respective pressure gradient in at least a portion and/or all of the plurality of hydraulically isolated upper formations  26 . 
     Additionally or alternatively, it also is within the scope of the present disclosure that, as discussed in more detail herein, the pressure measurements within a given formation and/or within a plurality of hydraulically connected formations may not fall on or otherwise define a straight line. Thus, in some implementations of the systems and/or systems according to the present disclosure, a curve and/or other non-linear mathematical function may be fit to the pressure measurement data and later utilized to determine the expected pressure at a given location within the subsurface region. As an illustrative, non-exclusive example, a density of a fluid that is located within a given upper formation  26  (or, similarly, reservoir  80  and/or lower formation  28 ) may vary with depth within the formation. As such, pressure vs. depth profile  100  (or, similarly, pressure vs. depth profile  120 ,  130 , and/or  140  that are discussed herein) may not be described accurately, or as accurately, by a straight line (than a curve or other non-linear expression), the pressure measurements may not fall on the straight line, and/or another mathematical function (such as a curve or other non-linear expression) may be utilized to describe the pressure vs. depth profile. 
     As discussed herein with reference to  FIG. 1 , subsurface region  24  may include a fluid barrier  86  that fluidly isolates gas-filled region  82  from upper formation  26 . This fluid barrier may permit a discontinuity, or step change, in pressure upon moving from the upper formation to gas-filled region  84  due to evolution of gas  83  from oil  85  and resultant pressurization of the gas-filled region. As such, and upon extending wellbore  42  into gas-filled region  82 , pressure step change  110  may be observed (as illustrated in  FIG. 2 ). Subsequently, and as illustrated in solid triangles in  FIG. 2 , one or more pressure measurements may be collected within gas-filled region  82 . These pressure measurements may be utilized to determine a gas-filled region pressure gradient  120  (i.e., a slope of the line that connects the solid triangles), which also may be referred to herein as, and/or may be, a pressure gradient  120  and/or as a pressure vs. depth profile  120 . 
     While  FIGS. 1-2  illustrate subsurface region  24  as including fluid barrier  86  and gas-filled region  82 , it is within the scope of the present disclosure that subsurface region  24  may not include fluid barrier  86  and/or that subsurface region  24  may not include gas-filled region  82 . When subsurface region  24  does not include fluid barrier  86  and/or gas-filled region  82 , a depth vs. pressure plot that is obtained therefrom may not include pressure step change  110 . 
     Subsequently, wellbore  42  may be extended into oil-filled region  84 . As illustrated in solid squares in  FIG. 2 , one or more pressure measurements may be collected within oil-filled region  84 . These pressure measurements may be utilized to determine an oil-filled region pressure gradient  130  (i.e., a slope of the line that connects the solid squares), which also may be referred to herein as, and/or may be, a pressure gradient  130  and/or as a pressure vs. depth profile  130 . 
     Wellbore  42  then may be extended into lower formation  28 . As illustrated in solid diamonds in  FIG. 2 , one or more pressure measurements may be collected within lower formation  28 . These pressure measurements may be utilized to determine a lower formation pressure gradient  140  (i.e., a slope of the line that connects the solid diamonds), which also may be referred to herein as, and/or may be, a pressure gradient  140  and/or as a pressure vs. depth profile  140 . 
     Additionally or alternatively, and distinct from traditional pilot leg  44  that is discussed herein with reference to  FIG. 1 , the systems and methods according to the present disclosure further may include turning wellbore  42  and/or pilot leg  44  thereof back toward surface region  22  and extending the wellbore in an upward direction through oil-water interface  90 , through oil-filled region  84 , through gas-oil interface  88 , through gas-filled region  82 , through fluid barrier  86 , and/or into upper formations  26 , as illustrated in dotted lines in  FIG. 1  at  45 . This additional length of wellbore  42 , which may be referred to herein as pilot leg extension  45 , may permit additional pressure measurements to be obtained at additional depths within lower formations  28 , oil-filled region  84 , gas-filled region  82 , and/or upper formations  26 , thereby increasing the accuracy of pressure gradients  100 ,  120 ,  130 , and/or  140 . 
     Additionally or alternatively, and as illustrated in solid lines in  FIG. 1 , wellbore  42  may not extend through reservoir  80  until formation of pilot leg extension  45 . As such, pressure measurements within lower formations  28 , oil-filled region  84 , gas-filled region  82 , and/or upper formations  26  only may be collected during formation of pilot leg extension  45 . 
     Additionally or alternatively, a depth of gas-oil interface  88 , as well as a pressure that may be associated therewith, may be approximated and/or calculated from an intersection point between the line (or curve) that extends through the solid triangles of  FIG. 2  and the line (or curve) that extends through the solid squares. Similarly, a depth of oil-water interface  90 , as well as a pressure that may be associated therewith, may be approximated from an intersection point between the line (or curve) that extends through the solid squares of  FIG. 2  and the line (or curve) that extends through the solid diamonds (as may be defined by pressure vs. depth profile  140 ). 
     Under these conditions, drilling of pilot leg extension  45  also may permit verification of the depth and/or pressure of gas-oil interface  88  and/or verification of the depth and/or pressure of oil-water interface  90 . As an illustrative, non-exclusive example, the depth of oil-water interface  90  may be calculated as discussed above. Then, as pilot leg  45  passes through the calculated depth of the oil-water interface (as determined by MWD surveying techniques), the pressure may be measured and compared to the calculated pressure. A similar procedure may be utilized to verify the location of gas-oil interface  88 . 
     During and/or subsequent to formation of first well  40 , a value of target TVD  64  and/or a pressure that is associated therewith also may be measured and/or calculated. As an illustrative, non-exclusive example, wellbore  42  may be extended to target TVD  64  and the pressure that is associated therewith may be measured. As another illustrative, non-exclusive example and subsequent to determining the pressure and depth of gas-oil interface  88  and the pressure and depth of oil-water interface  90 , a point along the line (or curve) that connects the solid squares of  FIG. 2  may be selected, with the depth that is associated therewith corresponding to target TVD  64  and the pressure that is associated therewith corresponding to the pressure at the target TVD. This may include selecting any suitable point, such as a midpoint between gas-oil interface  88  and oil-water interface  90 . 
     Subsequent to drilling pilot leg  44  and/or pilot leg extension  45 , and as discussed herein, the pilot leg may be plugged and a production leg  46  may be drilled at and/or near target TVD  64  within oil-filled region  84 , as illustrated in dash-dot lines in  FIG. 1 . This may include drilling production leg  46  and/or controlling a depth of production leg  46  in any suitable manner, including in a manner that is at least substantially similar to the drilling of second well  50 , which is discussed in more detail herein. 
     Subsequent to formation of first well  40  and/or subsequent to collection and/or determination of some and/or all of the above pressure data, second well  50  may be drilled within subsurface region  24 . As illustrated in dashed lines in  FIG. 1 , second well  50  may be separate, distinct, and/or spaced apart from first well  40  but may be constructed to extend within the same reservoir  80  as first well  40 . 
     Drilling of second well  50  may include extending a length of, or drilling, a second wellbore  52 , which also may be referred to herein as a wellbore  52 , that is associated therewith. As discussed in more detail herein, this drilling (and/or the operation of a directional drilling assembly  70  that is associated with the formation of second well  50 ) may be manually and/or automatically controlled, regulated, and/or directed based, at least in part, on the pressure data that was collected during the drilling of first well  40 . 
     As an illustrative, non-exclusive example, and subsequent to determining the pressure at target TVD  64  (during formation of first well  40 ), drilling of second well  50  may include extending wellbore  52  progressively deeper into subsurface region  24  until a terminal end of wellbore  52  is at, or near, the determined pressure at target TVD  64 . Then, wellbore  52  may be extended in horizontal, or at least substantially horizontal, direction  60 , such as to maintain wellbore  52  at, or within a threshold distance of, target TVD  64  and/or such as to maintain a pressure that is measured within wellbore  52  at, or within a threshold pressure of, the determined pressure at target TVD  64 . 
     As another illustrative, non-exclusive example, and while wellbore  52  is being extended progressively deeper into subsurface region  24 , a pressure at one or more selected locations, or points, along a length of wellbore  52  may be measured and compared to an expected pressure, with the expected pressure being determined and/or calculated based upon the pressure data that was measured during formation of first well  40 , which also may be referred to herein as a reference pressure. As an illustrative, non-exclusive example, the expected pressure may be calculated using pressure vs. depth profiles  100 ,  120 ,  130 , and/or  140  to calculate the expected pressure at the selected location along the length of wellbore  52 . 
     As another illustrative, non-exclusive example, the selected location along the length of wellbore  52  may be selected such that a depth thereof (as determined using MWD surveying techniques) corresponds to and/or is the same as a depth at which a pressure measurement was taken during formation of first well  40 . Under these conditions, the expected pressure may correspond to and/or be the pressure that was measured at a corresponding depth (as measured using MWD surveying techniques) during formation of first well  40 . 
     Under certain conditions, there may be a difference between the measured pressure and the expected pressure. This pressure difference may be caused by the inherent uncertainty associated with the use of MWD surveying techniques to calculate wellbore depth, as discussed in more detail herein. This uncertainty may be cumulative and/or integrated over a length of the wellbore and thereby increases with increasing wellbore length. In contrast, and while the pressure measurements that are discussed herein also may include inherent pressure uncertainty, this inherent pressure uncertainty may be due to the accuracy and/or precision of pressure gauge  72 . As such, this pressure uncertainty is not cumulative and/or integrated over (or does not increase with) the length of the wellbore and is therefore constant, or at least substantially constant, for all of the pressure measurements. 
     Thus, and while an exact, actual, and/or real depth of a given pressure measurement may not be exactly known (since this depth is calculated via MWD surveying techniques), pressure measurements may be utilized to compare two depths that were determined by MWD surveying techniques in a relative fashion, which also may be referred to herein as MWD-determined depths. As an illustrative, non-exclusive example, a given MWD-determined depth in first well  40  may have a corresponding MWD-determined depth uncertainty of several meters, or more, associated therewith. In contrast, a pressure that is measured at the given depth may have a pressure uncertainty of, for example, 7 kilopascals (kPa). Assuming that the given point is located within a water-bearing formation with a density of 1 gram per cubic centimeter, this pressure uncertainty may correspond to a depth uncertainty of approximately 0.7 meters and may be independent, or at least substantially independent, of the wellbore length. 
     As such, and for long wellbores (i.e., wellbores of a few thousand meters in length or more), the depth uncertainty associated with drilling the wellbore to a target formation pressure may be significantly less than the depth uncertainty associated with drilling the wellbore to a target MWD-determined depth. Thus, the use of first well  40  to establish one or more reference pressures within subsurface region  24  and control of the drilling of second well  50  using these pressures may permit accurate location of the depth of second wellbore  52  relative to the depth of first wellbore  42 , permitting accurate targeting of target TVD  64  without the need to drill pilot leg(s) in the second well. 
     If the measured pressure differs from the expected pressure (or differs by more than a threshold amount) an adjustment to the drilling process may be made. As an illustrative, non-exclusive example, and if the measured pressure is greater than the expected pressure, an actual depth at the selected point along the length of wellbore  52  may be greater than expected and/or greater than an actual depth of wellbore  42  at a corresponding MWD-determined depth. Thus, an angle of inclination  54  of directional drilling assembly  70  within wellbore  52  may be increased. As another illustrative, non-exclusive example, and if the measured pressure is less than the expected pressure, the actual depth at the selected point may be less than expected and/or less than the actual depth of wellbore  42  at the corresponding depth. Thus, the angle of inclination of the directional drilling assembly may be decreased. This process may be repeated any suitable number of times during the drilling of second well  50  and may permit extension of wellbore  52  within subsurface region  24  to target TVD  64  without the need to drill pilot leg  44 , without the need to drill pilot leg extension  45 , without the need to plug pilot leg  44 , and/or without the need to drill production leg  46  subsequent to drilling and plugging of pilot leg  44 . 
     As an illustrative, non-exclusive example, and as illustrated in dashed lines in  FIG. 2 , drilling of second well  50  may include extending wellbore  52  to a first location  150  that has a first MWD-determined depth and a first pressure associated therewith. In the illustrative, non-exclusive example of  FIG. 2 , the first pressure is greater than the expected pressure (i.e., the pressure of first well  40  at the first depth as indicated by the solid line and solid symbols in  FIG. 2 ), indicating that the actual depth of second well  50  is greater than the actual depth of first well  40  for the same MWD-determined depth for the two wells (i.e., that the angle of inclination of the directional drilling assembly may be too small). Thus, the angle of inclination may be increased, and the drilling process continued to a second location  154  that has a second depth and a second pressure associated therewith. At second location  154 , the second pressure is approximately equal to the expected pressure. Thus, the angle of inclination may not be adjusted. 
     The drilling process may be continued to a third location  158  that has a third depth and a third pressure associated therewith. At third location  158 , the third pressure may be less than the expected pressure, indicating that the actual depth of second well  50  is less than the actual depth of first well  40  at the same MWD-determined depth (i.e., that the angle of inclination of the directional drilling assembly may be too great). Thus, the angle of inclination may be decreased and the drilling process continued to a fourth location  162 . This process may be repeated any suitable number of times, such as at a fifth location  166 , a sixth location  170 , a seventh location  174 , etc. until the measured pressure corresponds to the expected pressure at target TVD  64 . Then, wellbore  52  may be extended in a horizontal, or at least substantially horizontal, direction within gas-filled region  82  (as illustrated in  FIG. 1 ). This may include repeating the pressure measurements and repeating the adjustments to the angle of inclination while wellbore  52  is being extended within the oil-filled region to maintain wellbore  52  within a threshold depth difference of target TVD  64  (or to maintain the detected pressure within a threshold pressure difference of the expected pressure at target TVD  64 ). 
     The systems and methods disclosed herein have been discussed in the context of extended-reach drilling operations  20  that may be utilized to produce oil from a thin, or relatively thin, oil-filled region  84 . As illustrative, non-exclusive examples, and with reference to  FIG. 1 , the oil-filled region may define a thickness  92 , which also may be referred to herein as (and/or may be) an average thickness  92 , of at least 0.1 meters (m), at least 0.25 m, at least 0.5 m, at least 0.75 m, at least 1 m, at least 2 m, at least 3 m, at least 4 m, at least 5 m, at least 6 m, at least 7 m, at least 8 m, at least 9 m, at least 10 m, at least 12 m, at least 14 m, at least 16 m, at least 18 m, or at least 20 m. Additionally or alternatively, thickness  92  also may be less than 40 m, less than 35 m, less than 30 m, less than 28 m, less than 26 m, less than 24 m, less than 22 m, less than 20 m, less than 18 m, less than 16 m, less than 14 m, less than 12 m, or less than 10 m. 
     Similarly, wellbores  42 / 52  may define any suitable wellbore length and/or wellbore trajectory between surface region  22  and reservoir  80 . As illustrative, non-exclusive examples, the wellbore length may be at least 2 kilometers (km), at least 3 km, at 4 km, at least 5 km, at least 6 km, at least 7 km, at least 8 km, at least 9 km, at least 10 km, at least 11 km, at least 12 km, or at least 13 km. Additionally or alternatively, the wellbore length may be less than 30 km, less than 25 km, less than 20 km, less than 19 km, less than 18 km, less than 17 km, less than 16 km, less than 15 km, less than 14 km, less than 13 km, less than 12 km, less than 11 km, or less than 10 km. 
     Additionally or alternatively, it is also within the scope of the present disclosure that the systems and methods disclosed herein may be utilized to increase the accuracy, or vertical depth accuracy, of any suitable drilling operation. This may include drilling operations that are not extended-reach drilling operations (such as drilling operations with a wellbore length of less than 2 km) and/or drilling operations that produce oil from a thick, or relatively thick, oil-filled region  84  (such as oil-filled regions with an average thickness of greater than 40 m). 
     As used herein the phrase “measurement while drilling surveying” and/or the phrase “MWD surveying techniques” may include measuring and/or calculating a location of directional drilling assembly  70  within wellbore  42 / 52  in any suitable manner using any suitable MWD surveying equipment. As an illustrative, non-exclusive example, drill string  74  and/or directional drilling assembly  70  thereof may include and/or be associated with any suitable accelerometer, gravitometer, gyroscope, and/or magnetometer that may be configured to determine and/or measure any suitable angle of inclination and/or angle of azimuth thereof to calculate a location of the directional drilling assembly and/or a trajectory of wellbore  42 / 52  within subsurface region  24 . This may include accelerometers, gravitometers, gyroscopes, and/or magnetometers that are operatively attached to drill string  74 , operatively attached to directional drilling assembly  70 , conveyed into the wellbore via a wireline, and/or dropped into the wellbore. 
     Directional drilling assembly  70  may include any suitable structure that may be configured to drill a non-linear and/or non-vertical wellbore  42 / 52  and/or that may be configured to be controlled to control an orientation, path, and/or trajectory, of wellbore  42 / 52  within subsurface region  24 . As illustrative, non-exclusive examples, directional drilling assembly  70  may include and/or be any suitable whipstock, mud motor, drill bit, and/or rotary steerable system. 
     It is within the scope of the present disclosure that wellbore  42 / 52  may define, and/or that directional drilling assembly  70  may be utilized to form, create, and/or define, any suitable orientation, path, and/or trajectory within subsurface region  24 . As an illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore  42 / 52  may be vertical, or at least substantially vertical. As another illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore  42 / 52  may be horizontal, or at least substantially horizontal. As yet another illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore  42 / 52  may be deviated and/or may define any suitable angle of inclination  54  within the subsurface region. This may include wellbores  42 / 52  that define a single vertical or deviated portion that extends (at least substantially) between surface region  22  and reservoir  80  followed by a single horizontal (or at least substantially horizontal) portion that extends (at least substantially) within reservoir  80 . Additionally or alternatively, this also may include wellbores  42 / 52  that may define curved and/or arcuate shapes within subsurface region  24 , wellbores  42 / 52  that may define “S” shapes within the subsurface region, and/or wellbores that may define a plurality of inflection points within the subsurface region. 
     It is also within the scope of the present disclosure that wellbores  42 / 52  may enter reservoir  80 , gas-filled region  82 , and/or oil-filled region  84  at any suitable angle and/or at (or from) any suitable portion thereof. As an illustrative, non-exclusive example, wellbores  42 / 52 , pilot leg  44 , pilot leg extension  45 , and/or production leg  46  may enter a top, or upper surface, of reservoir  80  (as illustrated in  FIG. 1  for wellbore  52  and/or as illustrated for wellbore  42  when reservoir  80  includes the dashed portion). As another illustrative, non-exclusive example, wellbores  42 / 52  may enter a side, or edge, of reservoir  80  (as illustrated in  FIG. 1  for production leg  46  entering reservoir  80  when the reservoir does not include the dashed portion). As yet another illustrative, non-exclusive example, wellbores  42 / 52  may enter a bottom, or lower surface, of reservoir  80  (as illustrated in  FIG. 1  by pilot leg extension  45 ). 
     Pressure gauge  72  may include any suitable structure that may be selected and/or configured to measure pressure within subsurface region  24 , that may be located on directional drilling assembly  70  and/or drill string  74 , that may be associated with and/or utilized in extended-reach drilling operation  20 , and/or that may be conveyed into the wellbore drilled by directional drilling assembly  70  and/or drill string  74 . As illustrative, non-exclusive examples, pressure gauge  72  may include and/or be a downhole pressure gauge, a bottom hole pressure gauge, and/or any gauge designed to measure pressure of the wellbore and/or of subsurface region  24 . 
     In addition, upper formations  26  and/or lower formations  28  may include and/or be any suitable subsurface formation that may include and/or contain any suitable fluid. As illustrative, non-exclusive examples, upper formations  26  and/or lower formations  28  may include a liquid, water, a liquid hydrocarbon, a gas, and/or a gaseous hydrocarbon. With this in mind, upper formations  26  also may be referred to herein as and/or may be fluid layers  26 , upper fluid layers  26 , fluid sands layers  26 , liquid sands layers  26 , gas sands layers  26 , upper water-bearing layers  26 , and/or water sands layers  26 . Similarly, lower formations  28  also may be referred to herein as and/or may be fluid layers  28 , lower fluid layers  28 , fluid sands layers  28 , liquid sands layers  28 , gas sands layers  28 , lower water-bearing layers  28 , and/or aquifers  28 . 
       FIG. 3  is a flowchart depicting methods  200  according to the present disclosure of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region. Methods  200  may include calibrating a pressure gauge at  205  and/or detecting a reference pressure at  210 . Methods  200  include extending a length of the wellbore at  220  and detecting a detected pressure at a selected location within the wellbore at  225 . Methods  200  further may include determining a selected depth of the selected location at  230 , and methods  200  include determining an expected pressure at the selected location at  235 , comparing the detected pressure to the expected pressure at  240 , and adjusting an orientation of the directional drilling assembly at  245 . Methods  200  further may include repeating the methods to extend the wellbore at  250 , determining a target pressure within a reservoir at  255 , extending the wellbore within the reservoir at  260 , and/or repeating the methods to drill an additional wellbore at  265 . 
     Calibrating the pressure gauge at  205  may include calibrating any suitable pressure gauge, or pressure gauges, that may be utilized during any suitable portion of methods  200 , such as during the detecting at  210  and/or during the detecting at  225 . The calibrating at  205  may be performed at any suitable time, or times, such as prior to performing a remainder of methods  200 , prior to the detecting at  210 , and/or prior to the detecting at  225 , and may include calibrating the pressure gauge in any suitable manner and/or to any suitable accuracy and/or precision. As illustrative, non-exclusive examples, the calibrating at  205  may include calibrating to an accuracy of ±3 pounds per square inch (psi), ±2 psi, ±1.5 psi, ±1 psi, ±0.75 psi, ±0.5 psi, or ±0.25 psi at reservoir pressures. 
     Detecting the reference pressure at  210  may include detecting the reference pressure in any suitable manner, at any suitable location, and/or with any suitable pressure detector (or reference pressure detector). As an illustrative, non-exclusive example, the wellbore may be a second wellbore, and the detecting at  210  may include detecting the reference pressure within a first wellbore that is different from, separate from, distinct from, and/or spaced apart from the second wellbore. The first wellbore may extend within the intermediate portion of the subsurface region, may extend between the surface region and the reservoir, and/or may extend within the reservoir, and it is within the scope of the present disclosure that the detecting at  210  further may include drilling the first wellbore at  212 , determining, at  214 , a reference depth that corresponds to the reference pressure, and/or determining, at  216 , a gas-oil contact depth and/or an oil-water contact depth within the subsurface region. 
     Drilling the first wellbore at  212  may include drilling the first wellbore in any suitable manner and/or using any suitable drilling assembly and/or directional drilling assembly. This may include extending a length of the first wellbore within the subsurface region, within the intermediate portion of the subsurface region, within the reservoir, and/or within one or more lower formations that may be located vertically below the reservoir, and is discussed in more detail herein. 
     Determining, at  214 , the reference depth that corresponds to the reference pressure may include determining the reference depth in any suitable manner. As an illustrative, non-exclusive example, the detecting at  210  may include detecting the reference pressure at a reference location within the intermediate portion of the subsurface region (such as may be defined along a length of the first wellbore), and the determining at  214  may include determining the depth, or total vertical depth, of the reference location. This may include measuring the reference depth and/or calculating the reference depth, such as through the use of any suitable measurement while drilling or surveying equipment. 
     It is within the scope of the present disclosure that the detecting at  210  may include detecting a plurality of reference pressures at a plurality of reference locations within the subsurface region and/or within the intermediate portion thereof. Under these conditions, the determining at  214  may include determining a plurality of reference depths, with each of these reference depths corresponding to a respective one of the plurality of reference pressures (or each of the reference pressures being detected at a respective one of the plurality of reference depths). 
     When the detecting at  210  includes detecting a plurality of reference pressures and the determining at  214  includes determining a corresponding plurality of reference depths, methods  200  further may include determining a pressure vs. depth profile, or gradient, within the subsurface region and/or within the intermediate portion thereof. As an illustrative, non-exclusive example, the pressure vs. depth profile may be determined by fitting a curve, line, and/or a straight line to a plurality of data points that is defined by the plurality of reference pressures and the plurality of respective reference depths. 
     Determining, at  216 , the gas-oil contact depth and/or the oil-water contact depth within the subsurface region may include determining a depth, or total vertical depth, of a gas-oil contact region, or interface, that is defined between a gas-filled region and an oil-filled region and/or determining a depth, or total vertical depth, of an oil-water contact region, or interface, that is defined between the oil-filled region and a lower water-bearing layer that may be present therebelow. This may include determining the gas-oil contact depth and/or the oil-water contact depth in any suitable manner. 
     As an illustrative, non-exclusive example, the drilling at  212  may include drilling the first wellbore to extend within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, and the detecting at  210  may include detecting at least one gas pressure within the gas-filled region, detecting at least one oil pressure within the oil-filled region, and detecting at least one water pressure within the lower water-bearing layer. Additionally or alternatively, the determining at  216  also may include determining a pressure vs. depth profile within the gas-filled region, within the oil-filled region, and/or within the lower water-bearing layer, such as through the use of the detected pressures within the various regions and corresponding measured depths, or total vertical depths, at which those pressures are detected. 
     As an illustrative, non-exclusive example, the determining at  216  may include determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region to determine the gas-oil contact depth. As another illustrative, non-exclusive example, the determining at  216  may include determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer to determine the oil-water contact depth. 
     Extending the length of the wellbore at  220  may include extending the length of the wellbore in any suitable manner, such as by drilling the wellbore using the directional drilling assembly. As an illustrative, non-exclusive example, the directional drilling assembly may include and/or be associated with a drill bit and/or a bottom hole assembly that includes a drill bit, and the extending at  220  may include producing cuttings at a terminal end of the wellbore with the drill bit to extend the length of the wellbore. This may include extending the length of the wellbore to locate the directional drilling assembly at the selected location within the intermediate portion of the subsurface region, which also may be referred to herein as a target location, a given location, a respective location, and/or a current location of the directional drilling assembly within the subsurface region and/or within the intermediate portion thereof. 
     Detecting the detected pressure at  225  may include detecting the detected pressure at the selected location and may be accomplished in any suitable manner. As an illustrative, non-exclusive example, the detecting at  225  may include detecting with any suitable pressure detector and/or pressure gauge, such as the pressure gauge that is discussed herein and/or that was calibrated during the calibrating at  205 . 
     Determining the selected depth of the selected location at  230  may include determining the selected depth, which also may be referred to herein as the total vertical depth of the selected location, in any suitable manner. This may include measuring the selected depth and/or calculating the selected depth, such as through the use of any suitable measurement while drilling or surveying equipment. 
     Determining the expected pressure at the selected location at  235  may include determining the expected pressure based, at least in part, on a reference pressure that was previously detected within the subsurface region (which may include and/or be the reference pressure that is detected during the detecting at  210  and/or a reference pressure that was previously detected within the intermediate portion of the subsurface region). As an illustrative, non-exclusive example, the selected depth of the selected location may correspond to and/or equal the reference depth of the reference location. Under these conditions, the determining at  235  may include equating the expected pressure to the reference pressure. 
     As another illustrative, non-exclusive example, and when the detecting at  210  includes determining the pressure vs. depth profile within the intermediate portion of the subsurface region, the determining at  235  may include calculating the expected pressure from the determined pressure vs. depth profile and the selected depth that was determined during the determining at  230 . 
     Comparing the detected pressure to the expected pressure at  240  may include comparing the detected pressure and the expected pressure in any suitable manner. As an illustrative, non-exclusive example, the comparing at  240  may include calculating a difference between the detected pressure and the expected pressure. As another illustrative, non-exclusive example, the comparing at  240  may include determining if, or that, the difference between the reference pressure and the detected pressure is greater than a threshold pressure difference. 
     Adjusting the orientation of the directional drilling assembly at  245  may include adjusting based, at least in part, on the comparing at  240 . As an illustrative, non-exclusive example, the adjusting at  245  may include controlling, regulating, adjusting, and/or changing an orientation and/or trajectory of the wellbore with the directional drilling assembly. As an illustrative, non-exclusive example, the adjusting at  245  may include decreasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure (or less than the expected pressure by at least the threshold pressure difference). Additionally or alternatively, the adjusting at  245  also may include increasing the angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure (or greater than the expected pressure by at least the threshold pressure difference). 
     Additionally or alternatively, the adjusting at  245  also may include determining a magnitude of the orientation adjustment, which also may be referred to herein as an orientation adjustment magnitude. This may include calculating the orientation adjustment magnitude based, at least in part, on a magnitude of the difference between the reference pressure and the detected pressure. As an illustrative, non-exclusive example, the adjusting at  245  may include increasing the orientation adjustment magnitude proportionate to the magnitude of the difference between the reference pressure and the detected pressure. 
     Additionally or alternatively, the adjusting at  245  also may include calculating the orientation adjustment magnitude based, at least in part, on a fluid density. Illustrative, non-exclusive examples of the fluid density include a density of a fluid within the intermediate portion of the subsurface region, a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and/or a density of a fluid within and/or at the selected location. As an illustrative, non-exclusive example, the adjusting at  245  may include increasing the orientation adjustment magnitude proportionate to the fluid density. 
     Repeating the methods at  250  may include repeating any suitable portion of methods  200 . As an illustrative, non-exclusive example, the repeating at  250  may include repeating the extending at  220 , repeating the detecting at  225 , repeating the determining at  235 , repeating the comparing at  240 , and repeating the adjusting at  245  a plurality of times to extend the wellbore through the intermediate portion of the subsurface region and/or from the surface region to the reservoir. As another illustrative, non-exclusive example, the repeating at  250  may include adjusting the trajectory of the wellbore a plurality of times as the wellbore is extended within the intermediate portion of the subsurface region and/or from the surface region to the reservoir. 
     As discussed herein, it is within the scope of the present disclosure that the intermediate portion of the subsurface region may include a plurality of upper formations, which also may be referred to herein as a plurality of intermediate formations. Under these conditions, the repeating at  250  may include detecting a respective reference pressure in each of the plurality of intermediate formations and/or in every intermediate formation that is present between the surface region and the reservoir. Additionally or alternatively, the repeating at  250  also may include repeating the extending at  220 , repeating the detecting at  225 , repeating the determining at  235 , repeating the comparing at  240 , and repeating the adjusting at  245  in at least a portion, a substantial portion, a majority, or all of the plurality of intermediate formations. Under these conditions, the determining at  235  may include determining the expected pressure in a respective formation of the plurality of formations based, at least in part, on a respective reference pressure that was detected within the respective intermediate formation. 
     Determining the target pressure within the reservoir at  255  may include determining the target pressure in any suitable manner. As an illustrative, non-exclusive example, methods  200  may include determining a target depth for the wellbore (or a horizontal portion thereof) within the reservoir. As an illustrative, non-exclusive example, this target depth may be based upon the determined gas-oil contact depth and/or the established oil-water contact depth (such as, for example, a midpoint between the gas-oil contact depth and the oil-water contact depth). Under these conditions, the target pressure may correspond to and/or be the pressure within the reservoir at the target depth. 
     Extending the wellbore within the reservoir at  260  may include extending the wellbore into and/or within the reservoir in any suitable manner. As illustrative, non-exclusive examples, the extending at  260  may include extending the length of the wellbore to locate the directional drilling assembly within the reservoir (and/or at a selected location within the reservoir) and/or detecting a reservoir pressure within the reservoir (and/or at the selected location within the reservoir). The extending at  260  further may include comparing the reservoir pressure to the target pressure and adjusting the orientation of the directional drilling assembly based, at least in part, on the comparison of the reservoir pressure to the target pressure and/or upon a difference therebetween. This may be at least substantially similar to the adjusting at  245 , which is discussed in more detail herein. 
     As discussed herein, the systems and methods according to the present disclosure may include drilling a plurality of wells within the subsurface region. With this in mind, methods  200  further may include repeating the methods to drill an additional wellbore at  265 . This may include repeating any suitable portion of methods  200  any suitable number of times to drill any suitable number of additional wellbores within the subsurface region, within the intermediate portion of the subsurface region, between the surface region and the reservoir, and/or within the reservoir. 
     As an illustrative, non-exclusive example, the repeating at  265  may include repeating at least the extending at  220 , the detecting at  225 , the determining at  235 , the comparing at  240 , and the adjusting at  245  to drill a subsequent wellbore of the plurality of wellbores. As another illustrative, non-exclusive example, the repeating at  265  also may include repeating the detecting at  210  a plurality of times while drilling the plurality of wellbores and using the detected reference pressures from a given wellbore when drilling one or more subsequent wellbores of the plurality of wellbores. 
     In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions. 
     As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like. 
     As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity. 
     In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally. 
     As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa. 
     Illustrative, non-exclusive examples of systems and methods according to the present disclosure are presented in the following enumerated paragraphs. It is within the scope of the present disclosure that an individual step of a method recited herein, including in the following enumerated paragraphs, may additionally or alternatively be referred to as a “step for” performing the recited action. 
     A1. A method of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region, wherein the intermediate portion of the subsurface region extends between a surface region and a reservoir that is present within the subsurface region, the method comprising:
 
extending a length of the wellbore to locate the directional drilling assembly at a selected location within the intermediate portion of the subsurface region;
 
detecting a detected pressure at the selected location;
 
determining an expected pressure at the selected location, wherein the determining is based, at least in part, on a reference pressure that was previously detected within the subsurface region, and optionally within the intermediate portion of the subsurface region;
 
comparing the detected pressure to the expected pressure; and
 
adjusting an orientation of the directional drilling assembly based, at least in part, on the comparing.
 
A2. The method of paragraph A1, wherein the method further includes detecting the reference pressure.
 
A3. The method of paragraph A2, wherein the wellbore is a second wellbore, and further wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the intermediate portion of the subsurface region, wherein the first wellbore is spaced apart from the second wellbore.
 
A4. The method of any of paragraphs A2-A3, wherein the detecting the reference pressure includes drilling a/the first wellbore within the subsurface region.
 
A5. The method of any of paragraphs A2-A4, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region, and further wherein the method includes determining a reference depth of the reference location.
 
A6. The method of paragraph A5, wherein the determining the reference depth includes at least one of measuring the reference depth and calculating the reference depth.
 
A7. The method of any of paragraphs A5-A6, wherein the determining a reference depth includes measuring the reference depth via a measurement while drilling survey.
 
A8. The method of any of paragraphs A2-A7, wherein the detecting the reference pressure includes detecting a plurality of reference pressures at a plurality of reference locations within the intermediate portion of the subsurface region, and further wherein the method includes determining a plurality of reference depths of the plurality of reference locations, wherein each of the plurality of reference pressures is detected at a respective one of the plurality of reference depths.
 
A9. The method of any of paragraphs A2-A8, wherein the detecting the reference pressure further includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region.
 
A10. The method of paragraph A9, wherein the pressure vs. depth profile is determined by fitting at least one of a curve, a line and a straight line to a plurality of data points that is defined by a/the plurality of reference pressures and a/the plurality of reference depths.
 
A11. The method of any of paragraphs A1-A10, wherein the directional drilling assembly includes a drill bit, and further wherein the extending includes producing cuttings at a terminal end of the wellbore with the drill bit to extend the length of the wellbore.
 
A12. The method of any of paragraphs A1-A11, wherein the directional drilling assembly includes a pressure gauge, and further wherein the detecting the detected pressure includes detecting the detected pressure with the pressure gauge.
 
A13. The method of paragraph A12, wherein the method further includes calibrating the pressure gauge, optionally prior to performing a remainder of the method.
 
A14. The method of paragraph A13, wherein the calibrating includes calibrating the pressure gauge to an accuracy of ±3 pounds per square inch (psi), ±2 psi, ±1.5 psi, ±1 psi, ±0.75 psi, ±0.5 psi, or ±0.25 psi.
 
A15. The method of any of paragraphs A1-A14, wherein the method further includes determining a selected depth of the selected location.
 
A16. The method of paragraph A15, wherein the determining the selected depth includes at least one of measuring the selected depth and calculating the selected depth.
 
A17. The method of any of paragraphs A15-A16, wherein the determining the selected depth includes measuring the selected depth via a measurement while drilling survey.
 
A18. The method of any of paragraphs A15-A17, when dependent from paragraph A2, wherein the detecting the reference pressure includes detecting the reference pressure at a/the reference location within the intermediate portion of the subterranean formation that defines a/the reference depth within the subterranean formation, wherein the reference depth is equal to the selected depth, and further wherein the determining the expected pressure includes equating the expected pressure to the reference pressure.
 
A19. The method of any of paragraphs A15-A17, when dependent from paragraph A2, wherein the detecting the reference pressure includes determining a/the pressure vs. depth profile within the intermediate portion of the subsurface region.
 
A20. The method of paragraph A1, wherein the determining the expected pressure includes calculating the expected pressure from the determined pressure vs. depth profile within the intermediate portion of the subsurface region and the determined selected depth of the selected location.
 
A21. The method of any of paragraphs A1-A20, wherein the comparing includes calculating a/the difference between the measured pressure and the reference pressure.
 
A22. The method of paragraph A21, wherein the comparing includes determining that the difference between the reference pressure and the detected pressure is greater than a threshold pressure difference.
 
A23. The method of any of paragraphs A1-A22, wherein the adjusting includes controlling an orientation of the wellbore with the directional drilling assembly.
 
A24. The method of any of any of paragraphs A1-A23, wherein the adjusting includes adjusting a trajectory of the wellbore.
 
A25. The method of any of paragraphs A1-A24, wherein the adjusting includes increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure.
 
A26. The method of any of paragraphs A1-A25, wherein the adjusting includes decreasing an/the angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure.
 
A27. The method of any of paragraphs A1-A26, wherein the adjusting further includes determining an orientation adjustment magnitude.
 
A28. The method of paragraph A27, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on a magnitude of a/the difference between the reference pressure and the detected pressure.
 
A29. The method of any of paragraphs A27-A28, wherein the determining the orientation adjustment magnitude includes increasing the orientation adjustment magnitude proportionate to a/the magnitude of a/the difference between the reference pressure and the detected pressure.
 
A30. The method of any of paragraphs A27-A29, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on at least one of (i) a density of a fluid within the intermediate portion of the subsurface region, (ii) a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and (iii) a density of a fluid within the intermediate portion of the subsurface region that is at the selected location.
 
A31. The method of any of paragraphs A27-A30, wherein the determining the orientation adjustment magnitude includes increasing the orientation adjustment magnitude proportionate to at least one of (i) a density of a fluid within the intermediate portion of the subsurface region, (ii) a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and (iii) a density of a fluid within the intermediate portion of the subsurface region that is at the selected location.
 
A32. The method of any of paragraphs A1-A31, wherein the method further includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting a plurality of times to extend the wellbore through the intermediate region and from the surface region to the reservoir.
 
A33. The method of paragraph A32, wherein the repeating includes adjusting a/the trajectory of the wellbore a plurality of times.
 
A34. The method of any of paragraphs A1-A33, wherein the intermediate portion of the subsurface region includes a plurality of intermediate formations, and further wherein the method includes detecting a respective reference pressure in each of the plurality of intermediate formations, and optionally in every intermediate formation that is present between the surface region and the reservoir.
 
A35. The method of paragraph A34, wherein the method includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting in each of the plurality of intermediate formations.
 
A36. The method of paragraph A35, wherein the determining the expected pressure includes determining the expected pressure in a respective intermediate formation of the plurality of intermediate formations based, at least in part, on the respective reference pressure that was detected within the respective intermediate formation.
 
A37. The method of any of paragraphs A1-A36, wherein the method further includes extending the wellbore within the reservoir.
 
A38. The method of paragraph A37, wherein the reservoir defines a gas-filled region, an oil-filled region, and a gas-oil contact region, wherein a lower water-bearing layer is located vertically below the oil-filled region and defines an oil-water contact region, and further wherein, prior to the extending, the method further includes determining a gas-oil contact depth of the gas-oil contact region and determining an oil-water contact depth of the oil-water contact region.
 
A39. The method of paragraph A38, wherein the wellbore is a/the second wellbore, wherein the detecting the reference pressure includes detecting the reference pressure within a/the first wellbore that extends within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, and further wherein the first wellbore is spaced apart from the second wellbore.
 
A40. The method of paragraph A39, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes detecting at least one gas pressure, and optionally a plurality of gas pressures, within the gas-filled region, detecting at least one oil pressure, and optionally a plurality of oil pressures, within the oil-filled region, and detecting at least one water pressure, and optionally a plurality of water pressures, within the lower water-bearing layer.
 
A41. The method of paragraph A40, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes determining a pressure vs. depth profile within the gas-filled region, determining a pressure vs. depth profile within the oil-filled region, and determining a pressure vs. depth profile within the lower water-bearing layer.
 
A42. The method of paragraph A41, wherein the determining the gas-oil contact depth includes determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region.
 
A43. The method of any of paragraphs A41-A42, wherein the determining the oil-water contact depth includes determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer.
 
A44. The method of any of paragraphs A38-A43, wherein the method further includes determining a target depth for the wellbore within the reservoir, wherein the target depth is based, at least in part, on the gas-oil contact depth and the oil-water contact depth, and further wherein the method includes determining a target pressure within the reservoir at the target depth.
 
A45. The method of paragraph A44, wherein the method further includes:
 
     (i) extending the length of the wellbore to locate the directional drilling assembly within the reservoir; 
     (ii) detecting a reservoir pressure within the reservoir; 
     (iii) comparing the reservoir pressure to the target pressure; and 
     (iv) adjusting the orientation of the directional drilling assembly based, at least in part, on the comparing the reservoir pressure to the target pressure. 
     A46. An extended-reach drilling operation, comprising: 
     a directional drilling assembly; and 
     a controller that is programmed to control the operation of the directional drilling assembly using the method of any of paragraphs A1-A45. 
     A47. The drilling operation of paragraph A46, wherein the drilling operation further includes a wellbore that extends between a surface region and a reservoir that is present within a subsurface region.
 
A48. The drilling operation of paragraph A47, wherein the drilling operation further includes the reservoir.
 
B1. The use of any of the methods of any of paragraphs A1-A45 or any of the drilling operations of any of paragraphs A46-A48 to drill an extended-reach well.
 
B2. The use of pressure measurements to adjust an orientation of a directional drilling assembly to control a trajectory of a wellbore that extends within an intermediate portion of a subsurface region that is located between a surface region and a wellbore.
 
B3. A wellbore constructed using the method of any of paragraphs A1-A48.
 
B4. Hydrocarbons produced from the wellbore of paragraph B3.
 
B5. A well that includes the wellbore of paragraph B3.
 
B6. Hydrocarbons produced using the method of any of paragraphs A1-A48
 
PCT1. A method of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region, wherein the intermediate portion of the subsurface region extends between a surface region and a reservoir that is present within the subsurface region, the method comprising:
 
extending a length of the wellbore to locate the directional drilling assembly at a selected location within the intermediate portion of the subsurface region;
 
detecting a detected pressure at the selected location;
 
determining an expected pressure at the selected location, wherein the determining is based, at least in part, on a reference pressure that was previously detected within the intermediate portion of the subsurface region;
 
comparing the detected pressure to the expected pressure; and
 
adjusting an orientation of the directional drilling assembly based, at least in part, on the comparing.
 
PCT2. The method of paragraph PCT1, wherein the method further includes detecting the reference pressure.
 
PCT3. The method of paragraph PCT2, wherein the wellbore is a second wellbore, and further wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the intermediate portion of the subsurface region, wherein the first wellbore is spaced apart from the second wellbore.
 
PCT4. The method of any of paragraphs PCT2-PCT3, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region, and further wherein the method includes determining a reference depth of the reference location.
 
PCT5. The method of any of paragraphs PCT2-PCT4, wherein the detecting the reference pressure includes detecting a plurality of reference pressures at a plurality of reference locations within the intermediate portion of the subsurface region, and further wherein the method includes determining a plurality of reference depths of the plurality of reference locations, wherein each of the plurality of reference pressures is detected at a respective one of the plurality of reference depths.
 
PCT6. The method of any of paragraphs PCT2-PCT5, wherein the method further includes determining a selected depth of the selected location.
 
PCT7. The method of paragraph PCT6, wherein the detecting the reference pressure includes detecting the reference pressure at a/the reference location within the intermediate portion of the subsurface region that defines a/the reference depth within the subsurface region, wherein the reference depth is equal to the selected depth, and further wherein the determining the expected pressure includes equating the expected pressure to the reference pressure.
 
PCT8. The method of any of paragraphs PCT6-PCT7, wherein the detecting the reference pressure includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region, and further wherein the determining the expected pressure includes calculating the expected pressure from the determined pressure vs. depth profile within the intermediate portion of the subsurface region and the determined selected depth of the selected location.
 
PCT9. The method of any of paragraphs PCT1-PCT8, wherein the adjusting includes at least one of:
 
     (i) increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure; and 
     (ii) decreasing the angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure. 
     PCT10. The method of any of paragraphs PCT1-PCT9, wherein the adjusting further includes determining an orientation adjustment magnitude, wherein the determining the orientation adjustment magnitude includes at least one of: 
     (i) calculating the orientation adjustment magnitude based, at least in part, on a magnitude of a difference between the reference pressure and the detected pressure; and 
     (ii) increasing the orientation adjustment magnitude proportionate to a magnitude of the difference between the reference pressure and the detected pressure. 
     PCT11. The method of any of paragraphs PCT1-PCT10, wherein the method further includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting a plurality of times to extend the wellbore through the intermediate portion and from the surface region to the reservoir.
 
PCT12. The method of any of paragraphs PCT1-PCT11, wherein the method further includes extending the wellbore within the reservoir, wherein the reservoir defines a gas-filled region, an oil-filled region, and a gas-oil contact region, wherein a lower water-bearing layer is located vertically below the oil-filled region and defines an oil-water contact region, and further wherein, prior to the extending, the method further includes determining a gas-oil contact depth of the gas-oil contact region and determining an oil-water contact depth of the oil-water contact region.
 
PCT13. The method of paragraph PCT12, wherein the wellbore is a/the second wellbore, wherein the detecting the reference pressure includes detecting the reference pressure within a/the first wellbore that extends within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, wherein the first wellbore is spaced apart from the second wellbore, and further wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes detecting at least one gas pressure within the gas-filled region, detecting at least one oil pressure within the oil-filled region, and detecting at least one water pressure within the lower water-bearing layer, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes determining a pressure vs. depth profile within the gas-filled region, determining a pressure vs. depth profile within the oil-filled region, and determining a pressure vs. depth profile within the lower water-bearing layer, wherein the determining the gas-oil contact depth includes determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region, and further wherein the determining the oil-water contact depth includes determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer.
 
PCT14. The method of paragraph PCT13, wherein the method further includes determining a target depth for the wellbore within the reservoir, wherein the target depth is based, at least in part, on the gas-oil contact depth and the oil-water contact depth, and further wherein the method includes determining a target pressure within the reservoir at the target depth.
 
PCT15. The method of paragraph PCT14, wherein the method further includes:
 
     (i) extending the length of the wellbore to locate the directional drilling assembly within the reservoir; 
     (ii) detecting a reservoir pressure within the reservoir; 
     (iii) comparing the reservoir pressure to the target pressure; and 
     (iv) adjusting the orientation of the directional drilling assembly based, at least in part, on the comparing the reservoir pressure to the target pressure. 
     INDUSTRIAL APPLICABILITY 
     The systems and methods disclosed herein are applicable to the oil and gas industry. 
     It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements. 
     It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.