Patent Publication Number: US-10329873-B2

Title: Methods for cementing a subterranean wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. provisional patent application Ser. No. 62/378,781 filed Aug. 24, 2016, and entitled “Methods for Cementing a Subterranean Wellbore,” which is hereby incorporated herein by reference in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     This disclosure relates generally to wellbore cementing operations. In particular, this disclosure relates to methods for more effectively drawing cement up an annulus toward the surface during wellbore cementing operations. 
     In drilling a borehole (or wellbore) into the earth for the recovery of hydrocarbons from a subsurface formation, it is conventional practice to connect a drill bit to the lower end of a tubular conduit (e.g., drill string, coiled tubing, etc.). The drill bit is then rotated either alone or along with the tubular conduit as weight-on-bit (WOB) is applied to engage the formation and drill the borehole along a predetermined path. As the borehole extends deeper within the subterranean formation, casing is inserted into the borehole to line the borehole, to provide additional structural reinforcement for borehole (i.e., to prevent collapse of the borehole wall), to prevent undesired outflow of drilling fluid into the formation or inflow of fluid from the formation into the borehole, and to prevent cross-flow between different formations via the borehole. 
     To secure the casing in position within the borehole, cement is pumped down the casing, and allowed to flow back up the annulus between the casing and the borehole sidewall. The cement is then allowed to set and cure, thereby securing the casing in position within the borehole. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     Embodiments of methods for cementing a tubular member within a subterranean wellbore extending from a surface into a subterranean formation and through a hydrocarbon reservoir are disclosed herein. In some embodiments, the method comprises (a) injecting a gas from the surface into an annulus surrounding the tubular member within the wellbore. In addition, the method comprises (b) flowing cement through a throughbore of the tubular member. Further, the method comprises (c) displacing the cement from the throughbore of the tubular member into the annulus. Still further, the method comprises (d) reducing a pressure of the gas in the annulus during (c). 
     Other embodiments disclosed herein are directed to a method for cementing a tubular member within a subterranean wellbore extending from the surface into a subterranean formation and through a hydrocarbon reservoir. In an embodiment, the method comprises (a) injecting a gas from the surface into an annulus surrounding the tubular member within the wellbore. In addition, the method comprises (b) pressurizing the gas in the annulus to push a fluid in the annulus downhole to a predetermined depth in the annulus. Further, the method comprises (c) flowing cement into a throughbore of the tubular member after (a). Still further, the method comprises (c) displacing the cement from the throughbore of the tubular member into the annulus. The method also comprises (d) bleeding the gas from the annulus during (c). 
     Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical characteristics of the disclosed embodiments in order that the detailed description that follows may be better understood. The various characteristics and features described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes as the disclosed embodiments. It should also be realized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of various exemplary embodiments, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a schematic cross-sectional view of an embodiment of a system for producing hydrocarbons from a subterranean wellbore in accordance with the principles disclosed herein; 
         FIGS. 2-7  are sequential schematic cross-sectional views of an embodiment of a method for performing a cementing operation utilizing the system of  FIG. 1  in accordance with the principles disclosed herein; and 
         FIG. 8  is a block diagram of an embodiment of a method for performing a cementing operation in accordance with the principles disclosed herein. 
     
    
    
     DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS 
     The following discussion is directed to various exemplary embodiments. However, one of ordinary skill in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. 
     The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection of the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a particular axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to a particular axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. As used herein, the terms “approximately,” “about,” “substantially,” and the like mean within 10% (i.e., plus or minus 10%) of the recited value. Thus, for example, a recited angle of “about 80 degrees” refers to an angle ranging from 72 degrees to 88 degrees. As used herein, the terms “fluid” and “fluids” refer to either a gas or liquid, or combinations thereof. 
     As previously described, during a typical cementing operation liquid (or semi-liquid) cement is pumped down the casing extending through the borehole, and is then directed up the annulus between the casing and the borehole sidewall. Cementing operations in wellbores extending through formations containing fractures (e.g., natural fractures, faults, cracks, fractures caused by hydraulic fracturing, etc.) are more complex as some of the cement flowing up the annulus may be lost into the surrounding formation (i.e., flows from the annulus through the fractures into the surrounding formation). In such formations, to ensure the cement continues to flow up the annulus toward the surface (e.g., to minimize losses of cement into the formation via the fractures), the pressure of the cement (or displacement fluid displacing the cement) may be increased. However, in fractured formations with relatively low reservoir pressures, an increase in the pressure of the cement may result in additional loss of cement to the surrounding formation. Further, if the pressure of the cement is increased beyond the formation fracture pressure, the cementing operation may result in undesirable additional fracturing of the formation. However, embodiments of systems and methods described herein are specifically designed and configured to manage pressures in the annulus to offer the potential to facilitate flow of cement through the annulus to the desired depth while simultaneously reducing the likelihood of inadvertently fracturing the formation and/or losing excessive cement volume to the formation. As will be explained in more detail below, embodiments described herein include injecting a pressurized gas into the annulus being cemented to set and control the pressure within the annulus. As cement is pumped into the annulus, the pressurized gas is bled from the annulus so that the pressure therein can be more precisely and carefully controlled (e.g., reduced) to allow the cement to be more effectively circulated up the annulus toward the surface. Through use of systems and methods described herein, the amount of cement lost to the formation, and the formation of additional fractures in the formation during a cementing operation may be minimized or even avoided. 
     Referring now to  FIG. 1 , an embodiment of a system  10  for producing hydrocarbons from a subterranean formation  11  via a wellbore  2  that extends through the formation  11  is shown. In this embodiment, system  10  generally includes a wellhead or other surface equipment  20  at the surface  9 , a primary conductor or surface casing  14  extending from the surface  9  downhole through wellbore  2 , and an intermediate casing  16  extending from the surface  9  downhole through surface casing  14  and wellbore  2 . In addition, system  10  includes a tubular string  12  extending from the surface  9  through intermediate casing  16 . A setting tool  22  is disposed on a lower end of tubular string  12 , and a production liner  30  is coupled to and extends from setting tool  22  through wellbore  2 . It should be appreciated that in at least some embodiments, the setting tool  22  is omitted, and the production liner  30  may be disposed on the end of some other tubular member (e.g., a casing pipe, tubular string, etc.). The production liner  30  may also be referred to as a production long string or production string. 
     Referring still to  FIG. 1 , wellbore  2  includes a vertical section  3  and a lateral section  5  extending from vertical section  3 . A heel or bend is provided along wellbore  2  at the transition between sections  3 ,  5 . Vertical section  3  has a substantially vertically oriented central axis  4  and horizontal section  5  has a substantially horizontally oriented central axis  6 . However, in other embodiments, the central axis of the vertical section (e.g., axis  4  of vertical section  3 ) may be oriented +/−45° from vertical, and the central axis of the horizontal section (e.g., axis  6  of horizontal section  5 ) may be oriented +/−45° from horizontal. Wellbore  2  includes an inner sidewall  2   a  that extends along and defines both sections  3 ,  5  of wellbore  2 . In general, the diameter of each section  3 ,  5  defined by sidewall  2   a  can be uniform or variable. In this embodiment, the diameter of vertical section  3  varies along it length. In particular, vertical section  3  includes a first or upper portion  3   a  extending from surface  9 , a second or intermediate portion  3   b  extending from upper portion  3   a , and a third or lower portion  3   c  extending from intermediate portion  3   b . The diameter of upper portion  3   a  is larger than the diameters of both intermediate portion  3   b  and lower portion  3   c , and the diameter of intermediate portion  3   b  is larger than the diameter of lower portion  3   c . In this embodiment, the diameter of lateral section  5  is substantially the same as the diameter of lower portion  3   c.    
     A plurality of fractures  7  extend through subterranean formation  11  and intersect lateral section  5  of wellbore  2 . In general, fractures  7  may result from natural geologic processes, drilling of wellbore  2 , a hydraulic fracturing operation, other downhole operation(s), or combinations thereof. The fractures  7  enhance access to a hydrocarbon reservoir (e.g., natural gas reservoir) in formation  11  through which lateral section  5  extends. Due to the general horizontal orientation of lateral section  5  and fluid communication along section  5  with the surrounding reservoir via fractures  7 , the fluid pressure within lateral section  5  is substantially constant along its length and is substantially equalized with the pore pressure of the surrounding reservoir, also referred to herein as the “reservoir pressure.” While not specifically shown, it should be appreciated that similar fractures  7  may intersect with vertical section  3  of wellbore  2 . 
     Surface casing  14  and intermediate casing  16  are tubular members that extend downhole from surface  9  into vertical section  3  of wellbore  2 . Specifically, surface casing  14  and intermediate casing  16  include a first or upper end  14   a ,  16   a , respectively, and a second or lower end  14   b ,  16   b , respectively. In this embodiment, upper ends  14   a ,  16   a  of casings  14 ,  16 , respectively, are aligned with one another at (or proximate to) surface  9 . However, it should be appreciated that one or both of casings  14 ,  16  may not extend all the way from surface  9  in other embodiments. For example, in some embodiments, surface casing  14  may extending from surface  9  (or proximate surface  9 ) such that upper end  14   a  is disposed at (or proximate to) surface  9 , and intermediate casing  16  is disposed within surface casing  14  and extends from some point within vertical section  3  of wellbore  2  that is spaced from surface  9  such that upper end  16   a  is disposed at some point below upper end  14   a  and surface  9 . In either case, lower end  16   b  of intermediate casing  16  is disposed below lower end  14   b  of surface casing  14 . In addition, each casing  14 ,  16  includes a radially outer surface  14   c ,  16   c , respectively, and a radially inner surface  14   d ,  16   d , respectively. Surface casing  14  is disposed within upper portion  3   a  of vertical section  3  of wellbore  2 , and intermediate casing  16  is disposed both within surface casing  14  and within intermediate portion  3   b . Upper portion  3   a  of vertical section  3  has an inner diameter that is larger than an outer diameter of surface casing  14  such that an annulus  13  is formed radially between radially outer surface  14   c  and the inner wall  2   a  of wellbore  2 . In addition, both casing  14  and intermediate portion  3   b  of vertical section  3  of wellbore  2  have an inner diameter that is larger than an outer diameter of intermediate casing  16  such that when intermediate casing  16  is installed within surface casing  14  and intermediate portion  3   b , an annulus  19  is formed between the radially outer surface  16   c  of intermediate casing  16  and radially inner surface  14   d  of surface casing  14  and wellbore wall  2   a  within intermediate portion  3   b . In this embodiment, each of the annuli  13 ,  19  are filled with cement to, among other things, secure casings  14 ,  16  within vertical section  3  of wellbore  2 , to prevent the flow of fluids between inner wall  2   a  of wellbore  2  and casings  14 ,  16 , and to prevent the flow of fluids between casings  14 ,  16 . 
     Referring still to  FIG. 1 , tubular string  12  is inserted within intermediate casing  16 . Tubular string  12  includes a first or upper end  12   a  disposed at (or proximate to) surface  9 , a second or lower end  12   b  disposed within intermediate casing  16 , a radially outer surface  12   c  extending between ends  12   a ,  12   b , and a radially inner surface  12   d  extending between ends  12   a ,  12   b . Radially inner surface  12   d  forms or defines a throughbore  15  extending between ends  12   a ,  12   b.    
     Setting tool  22  is a tubular member inserted within intermediate casing  16  and mounted to tubular string  12 . Setting tool  22  includes a first or upper end  22   a  coupled to lower end  12   b  of tubular string  12 , a second or lower end  22   b  disposed within intermediate casing  16 , a radially outer surface  22   c  extending between ends  22   a ,  22   b , and a radially inner surface  22   d  also extending between ends  22   a ,  22   b . Radially inner surface  22   d  forms or defines a throughbore  23  extending between ends  22   a ,  22   b.    
     Production liner  30  is an elongate tubular member including a first or upper end  30   a  coupled to the lower end  22   b  of setting tool  22 , a second or lower end  30   b  opposite upper end  30   a , a first or vertical section  32  extending from upper end  30   a , and a second or lateral section  34  extending from vertical section  32  to lower end  30   b . Vertical section  32  of production liner  30  is disposed within vertical section  3  of wellbore  2  and lateral section  34  of production liner  30  is disposed within lateral section  5  of wellbore  2 . In addition, vertical section  32  and lateral section  34  are generally coaxially aligned with vertical section  3  and lateral section  5 , respectively, of wellbore  2 . As a result, in at least some embodiments, vertical section  32  may extend within +/−45° of the vertical direction and lateral section  34  may be angled between 0° and 180° relative to vertical section  32 . However, it should be appreciated that in some embodiments, one or more of the portions (e.g., portions  3   a ,  3   b ,  3   c ) of vertical section  3  of wellbore  2  may extend along a direction that is approximately +/−60°, 90°, or more from the vertical direction. Further, production liner  30  includes a radially outer surface  30   c  extending between ends  30   a ,  30   b , and a radially inner surface  30   d  also extending axially between ends  30   a ,  30   b . Radially inner surface  30   d  defines a throughbore  36  extending between ends  30   a ,  30   b . Throughbores  15 ,  23 ,  36  are contiguous and in direct fluid communication. As shown in  FIG. 1 , upper end  30   a  is coupled to lower end  22   b  of setting tool  22  and upper end  22   a  of setting tool  22  is coupled to lower end  12   b  of tubular string  12  such that production liner  30  is suspended from setting tool  22  and tubular string  12  (at least initially). 
     The inner diameter of intermediate casing  16  is larger than the outer diameters of tubular string  12 , setting tool  22 , and production liner  30 , and the outer diameter of production liner  30  is smaller than the inner diameter of lower portion  3   c  of vertical section  3  and lateral section  5  of wellbore  2 . As a result, an annulus  21  is formed radially between tubular string  12  and intermediate casing  16 , radially between setting tool  22  and intermediate casing  16 , radially between production liner  30  and intermediate casing  16 , and radially between production liner  30  and sidewall  2   a  along lower portion  3   c  of vertical section  3  and lateral section  5 . Thus, in this embodiment, annulus  21  extends from surface  9  through to the lowermost end of wellbore  2  (i.e., within lateral section  5 ). 
     Referring still to  FIG. 1 , a liner wiper plug  40  is disposed within throughbore  36  of production liner  30  proximate upper end  30   a . Liner wiper plug  40  sealingly engages inner surface  30   d  and includes an axial throughbore including a dart seat  42 . Thus, fluid flowing through throughbores  15 ,  23 ,  36  flows through the open throughbore of liner wiper plug  40 . As will be described in more detail below, during cementing operations, a dart (e.g., dart  44 ) is passed down throughbores  15 ,  23 ,  36  until it seats against and sealing engages dart seat  42 , thereby preventing fluid flow through wiper plug  40 . Thereafter, liner wiper plug  40  and the dart seated therein move together downhole within throughbore  36  toward lower end  30   b  of production liner  30 . In addition, a bump plug  48  is disposed within throughbore  36  at lower end  30   b  of production liner  30 . Bump plug  48  includes an axial throughbore and a plug seat  49  that engages liner wiper plug  40  during cementing operations described in more detail below. 
     Referring still to  FIG. 1 , in this embodiment, a plurality of open hole (OH) packers  50  are disposed about production liner  30 . At least one of the OH packers  50  is disposed about outer surface  30   c  along vertical section  32 , and a plurality of the OH packers  50  are disposed about outer surface  30   c  along lateral section  34 . Each of the OH packers  50  is hydraulically actuated such that it can be selectively radially expanded into sealing engagement with the outer surface  30   c  of production liner  30  and the inner wall  2   a  of wellbore  2  (or the radially inner surface  16   d  of intermediate casing  16  for the OH packer  50  disposed about vertical section  32  of production liner  30  in  FIG. 1 ). For example, in this embodiment, OH packers  50  are actuated by increasing the fluid pressure within throughbores  15 ,  23 ,  36  above a predetermined pressure threshold. When actuated, the OH packers  50  divide and separate annulus  21  into a plurality of fluidly isolated, axially adjacent portions or sections. It should be appreciated however, that some embodiments may not include packers  50 . 
     A liner top packer  52  is disposed about production liner  30  at (or proximate to) upper end  30   a  and setting tool  22 . Liner top packer  52  can be selectively actuated hydraulically, mechanically, or by any other actuation method known in the art. Similarl to OH packers  50 , when liner top packer  52  is actuated, it expands radially outward into sealing engagement with the radially outer surface  30   c  of production liner  30  and the radially inner surface  16   d  of intermediate casing  16 . 
     Referring now to  FIGS. 2-7 , a method for performing a cementing operation utilizing system  10  is schematically shown in sequence. In  FIGS. 2-7 , production liner  30  is cemented within wellbore  2  prior to the initiation of production from wellbore  2  via liner  30 . As will be described in more detail below, the fluid pressure within annulus  21  is controlled during the cementing operation illustrated in  FIGS. 2-7  with a pressurized gas injected into the annulus  21  from the surface  9 . 
     Referring first to  FIG. 2 , initially, throughbores  15 ,  23 ,  36  and annulus  21  are at least partially filled with fluid  60 , which may be water or another fluid such as drilling mud. For example, fluid  60  may be water and/or drilling mud remaining in wellbore  2  following drilling and installation of casings  14 ,  16 . The top of fluid  60  is disposed at a depth D 60  measured vertically from the surface  9  to the top of fluid  60 . In  FIG. 2 , the depth D 60  is the depth of fluid  60  at equilibrium within wellbore  2  with the upper end of the annulus open to ambient surface pressure, and thus, is also identified with reference numeral D 60eq . As is known in the art, the vertical depth to which a fluid at equilibrium in a wellbore extends (e.g., depth D 60  of fluid  60 ) is a function of a variety of factors including, without limitation, the hydrostatic head of the fluid (depends on the weight/density of fluid  60  and the vertical height of the column of fluid  60  in vertical section  3 ), the reservoir pressure, and friction between the fluid and the surrounding structures (e.g., friction between fluid  60  and production liner  30  and sidewall  2   a ). Thus, the depth D 60  of fluid  60  in wellbore  2  can be used to determine (e.g., calculate) the reservoir pressure using techniques known in the art. Alternatively, the reservoir pressure can be more directly measured with a gauge lowered into lateral section  5  to measure the pressure therein, which is substantially equalized with the reservoir pressure as previously described. 
     As previously described, in many conventional wellbores, a cementing operation relies on over pressurization of the cement to flow the cement down a tubular string (e.g., a casing string or production string), out the lower end of the string, and up the annulus between the string and the borehole sidewall to the desired location along the annulus. However, in wellbores with extensive fractures extending therefrom into the formation, such as wellbore  2  and associated fractures  7  in formation  11 , over pressurization of the cement may result in substantial loss of the cement into the surrounding formation via the fractures. In addition, in formations having relatively low fracture pressures, over pressurization of the cement may undesirably initiate new fractures and/or enhance existing fractures. Accordingly, over pressurization of the cement to drive it to the desired location in the annulus may not be a viable option in wellbores associated with extensive fractures and/or relatively low formation fracture pressures. Therefore, in embodiments disclosed herein, the formation fracture pressure is relied on to support circulation of cement in the annulus  21  and the reservoir pressure is relied on to push or circulate cement in the annulus  21  during the cementing operations. Using the reservoir pressure determined as previously described, the anticipated location to which the reservoir can push or circulate cement  64  (and fluid  60  disposed atop cement  64 ) within annulus  21  is determined (e.g., calculated). For relatively low reservoir pressures such as the reservoir surrounding lateral section  5 , the reservoir pressure alone may be insufficient to circulate the cement to the desired location due to the hydrostatic head of fluids (e.g., fluid  60  and/or cement) in the vertical section  3 . Accordingly, in embodiments described herein, a pressurized gas  62  is used to effectively reduce the hydrostatic head of fluids in the vertical section  3  to enhance the circulation of the cement at the reservoir pressure. 
     Moving now to  FIG. 3 , next, the pressurized gas  62  is injected into annulus  21  from the surface  9 . In this embodiment, the gas  62  is injected directly into annulus  21  from the surface  9 , and thus, is not injected into the throughbores  23 ,  36  and circulated back up annulus  21 . In general, the gas  62  can be any suitable gas including, without limitation, nitrogen (N 2 ), carbon dioxide (CO 2 ), air, hydrocarbon gases (e.g., natural gas), or combinations thereof. In some embodiments, gas  62  is an inert gas to avoid an interaction (e.g., explosive, chemical, etc.) between the injected gas  62  and any other fluids (i.e., liquid or gas) (e.g., fluid  60 ) that may be present within the wellbore  2 . 
     The injected gas  62  fills the open upper portion of annulus  21  above fluid  60 . As gas  62  continues to be pumped into annulus  21 , the pressure of gas  62  increases within annulus  21  (e.g., gas is pressurized within annulus  21 ) and begins to push fluid  60  in annulus  21  downward within vertical section  3 , thereby effectively reducing the hydrostatic head of fluid  60  in annulus  21  along vertical section  3 . The gas  62  in annulus  21  is injected and pressurized within annulus  21  to a predetermined pressure (measured at the surface) sufficient to push fluid  60  down to a predetermined depth D 60p . In other words, gas  62  is injected into annulus and pressurized within annulus  21  to the predetermine pressure necessary to fill annulus  21  with gas  62  to depth D 60p . As will be described in more detail below, the predetermined pressure of gas  62  and the corresponding predetermined depth D 60p  of fluid  60  is chosen to displace a sufficient volume of fluid  60  in annulus  21  and sufficiently reduce the hydrostatic head of fluid  60  in annulus  21  along vertical section  3  to allow for cement  64  supplied to annulus  21  at end  30   b  of liner  30  to be driven uphole within annulus  21  by the reservoir pressure to a desired or predetermined location within annulus  21  as the pressurized gas  62  is bled from annulus  21 . It should be appreciated that at least a portion of the volume of fluid  60  in annulus  21  displaced by pressurized gas  62  may be pushed into formation  11  via fractures  7 . 
     For most wellbores including lateral sections (e.g., wellbore  2  including lateral section  5 ), the cement preferably fills the annulus along at least the entire lateral section (e.g., from lower end  30   b  of liner  30  to the heel between sections  3 ,  5 ), and more preferably fills the annulus along the entire lateral section, the heel, and along the portion of the vertical section extending from the heel to the liner hanger (e.g., from lower end  30   b  of liner  30  to upper end  30   a  and setting tool  22 ). In this embodiment, the predetermined depth D 60p  is the depth to lower end  16   b  of intermediate casing  16 . However, in other embodiments, gas  62  may be injected and pressurized in annulus  21  to push fluid  60  to other predetermined depths D 60p  depending on the desired, predetermined location of cement  64  and the associated reduction in the hydrostatic head of fluid  60  in annulus  21  along vertical section  3  necessary to achieve the desired, predetermined location of cement  64 . 
     Still referring to  FIG. 3 , after gas  62  has been injected into annulus  21 , cement  64  is pumped or otherwise flowed down throughbores  15 ,  23 ,  36 , thereby displacing fluid  60  within liner  30  and pushing fluid  60  from throughbores  15 ,  23 ,  36  into the annulus  21  at lower end  30   b . Annulus  21  is shut in at the surface  9  as cement  64  is pumped down throughbores  15 ,  23 ,  36  to lower end  30   b  of liner  30 . Thus, as cement  64  flows to lower end  30   b , the pressure of the gas  62  within the annulus  21  (as measured at the surface  9 ) and the depth D 60  of fluid  60  in the annulus  21  may fluctuate slightly up or down as fluid  60  is pushed from throughbores  23 ,  36  into annulus  21  by cement  64 . During this process, some fluid  60  in annulus  21  may be forced into formation  11  via fractures  7  as cement  64  is pumped to lower end  30   b  of liner  30 . 
     Referring now to  FIG. 4 , next, a dart  44  is pumped down throughbores  15 ,  23 ,  36  of tubular string  12 , setting tool  22 , and production liner  30 , respectively, and into sealing engagement with dart seat  42  of liner wiper plug  40 . In this embodiment, dart  44  is pumped down throughbores  15 ,  23 ,  36  to plug  40  with fluid  60 . Sealing engagement of dart  44  and seat  42  closes the throughbore of plug  40  and prevents fluid (e.g., fluid  60 , cement  64 , etc.) from flowing past or around liner wiper plug  40  within throughbore  36 . 
     Moving now to  FIGS. 5 and 6 , once dart  44  engages seat  42 , continued pumping of fluid  60  into throughbores  15 ,  23  from surface  9  causes the fluid pressure above plug  40  to increase until it is sufficient to drive plug  40  downward through throughbore  36  of production liner  30  toward lower end  30   b . Because liner wiper plug  40  is sealingly engaged with radially inner surface  30   d  of production liner  30  and dart  44  closes the throughbore of plug  40 , the cement  64  downhole of plug  40  is forced out of lower end  30   b  of production liner  30  and into annulus  21  as liner wiper plug  40  translates toward lower end  30   d . As cement  64  flow uphole within annulus  21 , pressurized gas  62  within annulus  21  is controllably bled off to controllably reduce the pressure of gas  62  within annulus  21 . In this embodiment, the pressure of the gas  62  within annulus  21  is controllably reduced (e.g., bled off) once cement  64  begins to exit lower end  30   b  of production liner  30 . In general, the pressure of gas  62  can be reduced gradually and/or continuously. However, gas  62  is preferably bled to controllably reduce its pressure within annulus  21  at a rate that ensures: (i) fluids in the formation  11  (e.g., fluid  60 , formation fluids, etc.) do not enter the wellbore  2  and contaminate the cement  64  in annulus  21 ; and (ii) a substantial quantity of cement  64  in annulus  21  is not lost into the formation  11  (e.g., via fractures  7 ). It should be appreciated that if the rate of pressure reduction of gas  62  in annulus  21  is too fast, the fluid pressure in annulus  21  along lateral section  5  may undesirably decrease below the reservoir pressure and allow fluids in the formation  11  to enter annulus  21 ; and if the rate of pressure reduction of gas  62  in annulus  21  is too slow, the fluid pressure in annulus  21  along lateral section  5  may undesirably increase sufficiently above the reservoir pressure that a substantial quantity of cement  64  is lost into the formation  11  (e.g., via fractures  7 ). In this embodiment, the pressure of gas  62  in annulus  21  is preferably reduced at a rate that continuously ensures at least about 50 vol % of cement  64  injected into annulus  21  from lower end  30   b  of liner  30  is circulated through annulus  21 , and more preferably reduced at a rate that continuously ensures at least about 80 vol % of cement  64  injected into annulus  21  from lower end  30   b  of liner  30  is circulated through annulus  21 . In other words, the pressure of gas  62  in annulus  21  is preferably reduced at a rate that continuously ensures less than about 50 vol % of cement  64  is lost to formation  11 , and more preferably less than about 20 vol % of cement  64  injected into annulus  21  from liner  30  is lost to formation  11 . 
     In embodiments described herein, the cement  64  preferably fills the annulus  21  at least along the entire lateral section  5  (e.g., from lower end  30   b  of liner  30  to the heel between sections  3 ,  5 ), and more preferably fills the annulus  21  along the entire lateral section  5 , along the heel, and along the portion of the vertical section  3  extending from the heel to lower end  30   b  of liner  30  to upper end  30   a  and setting tool  22 . Thus, in embodiments described herein, the predetermined pressure of gas  62  and the predetermined depth D 60p  to which gas  62  displaces fluid  60  (at the predetermined pressure of gas  62 ) is preferably selected to allow the reservoir pressure to support circulation of cement  64  (and fluid  60 ) within annulus  21  to at least the heel between sections  3 ,  5 , and more preferably to upper end  30   a  and setting tool  22  before the hydrostatic head of fluid (e.g., fluid  60  and/or cement  64 ) within annulus  21  along vertical section  3  is substantially balanced with the reservoir pressure. 
     As previously described, the desired, predetermined location of cement  64  in annulus  21  is used to determine the predetermined pressure of gas  62  and associated predetermined depth D 60p  of fluid  60  ( FIG. 3 ). In general, the predetermined pressure of the injected gas  62  and predetermined depth D 60p  of fluid  60  can be determined using wellbore models and fluid dynamics principles known in the art, which consider a variety of factors including, without limitation, the reservoir pressure, the weight/density of the various fluids in the annulus  21  (e.g., fluid  60 , cement  64 , gas  60 , etc.), and frictional loads between fluids in the annulus  21  and the surrounding structures. For example, if the depth D 60eq  of fluid  60  in annulus  21  along vertical section  3  at equilibrium is 1,000 feet (with the upper end of the annulus open to ambient surface pressure), it is understood that the reservoir pressure is strong enough to support a hydrostatic head of fluid  60  extending to the depth D 60eq  of 1,000 feet, but cannot support a hydrostatic head of fluid  60  extending to a height above than the 1,000 foot depth D 60eq  (assuming that the lowest pressure at the upper end of annulus  21  is the ambient surface pressure). Thus, if cement  64  is injected into annulus  21  at lower end  30   b  of liner  30  with fluid  60  at depth D 60eq  of 1,000 feet, the reservoir pressure is insufficient to support a hydrostatic head of fluid  60  above the 1,000 foot depth D 60eq  needed to circulate the cement  64  through the annulus  21 . As a result, a substantial amount of the injected cement  64  and/or fluid  60  will be exit the annulus  21  via fractures  7 . To enable the cement  64  to circulate through a 5,000 foot length of the lateral section  5  under reservoir pressure, without a substantial portion of the cement  64  or fluid  60  being lost to the formation via fractures  7 , the reservoir pressure must be sufficient to support a 5,000 foot increase in the vertical height and associated hydrostatic head of the fluid  60  in vertical section  3 . It is known that the reservoir pressure can support fluid  60  to the 1,000 foot depth D 60eq , and thus, gas  62  can be injected into annulus  21  and pressurized to push fluid  60  down vertical section  3  to a predetermined depth D 60p  of at least 6,000 feet, with the understanding that the reservoir pressure is sufficient to support an increase in the height of fluid  60  (and associated increase in hydrostatic head of fluid  60 ) from the 6,000 foot predetermined depth D 60p  back to the 1,000 foot equilibrium depth D 60eq  when pressurized gas  62  is bled to controllably reduce its pressure to ambient surface pressure. This effectively enables the reservoir pressure to support the circulation of fluid  60  to a height increase of about 5,000 feet, which in turn enables the circulation of the cement  64  through about a 5,000 foot length of the lateral section  5  with minimal loss of cement  64  into the formation via fractures  7 . Thus, in this simplified example, the predetermined depth D 60p  of fluid  60  is 6,000 feet and the predetermined pressure of gas  62  is the pressure of gas  62  within annulus  21  at the surface  9  necessary to push fluid  60  to the predetermined depth D 60p  of 6,000 feet. It should be appreciated that in this simplified example, only fluid  60  contributes to the hydrostatic head in vertical section  3  (cement  64  is only circulated within lateral section  5 ), and thus, it is assumed cement  64  does not contribute to the hydrostatic head; the density of pressurized gas  62  in annulus  21  is ignored; and friction between fluid  60  and cement  64  with surrounding structures is ignored. In practice, a safety factor is preferably used to determine the predetermined depth D 60p  to account for potential fluid losses, as well as any other factors that could potentially limit the ability of the reservoir pressure to push fluid  60  back to the equilibrium depth D 60q  when the pressurized gas  62  is bled. 
     Moving now to  FIGS. 5 and 6 , liner wiper plug  40  and dart  44  are translated within throughbore  36  toward lower end  30   b  until plug  40  and/or dart  44  engages plug seat  49  on bump plug  48 . In this embodiment, liner wiper plug  40  and/or dart  44  sealingly engage with plug seat  49  on bump plug  48  such that fluid (e.g., flow of fluid  60 , cement  64 , etc.) is prevented from flowing across the engaged plugs  40 ,  48 . In other embodiments, engagement between liner wiper plug  40  and/or dart  44  is such that fluid is merely restricted from flowing past the engaged plugs  40 ,  48 . In either case, once plug  40  (and/or dart  44 ) and plug  48  are engaged at lower end  30   b  of production liner  30 , continued pumping of fluid  60  into throughbores  15 ,  23 ,  36  from surface  9  increases the fluid pressure within throughbores  15 ,  23 ,  36  until OH packers  50  are actuated (i.e., packers  50  are actuated via the pressure increase within throughbore  36 ), thereby expanding OH packers  50  into sealing engagement with inner wall  2   a  of wellbore  2  (or radially inner surface  16   d  of intermediate casing  16  such as is the case for the OH packer  50  disposed within vertical section  3  as shown in  FIGS. 5 and 6 ). In this embodiment, actuation of OH packers  50  is completed while the cement  64  disposed within annulus  21  is still liquid (or semi-liquid), so that the expanding packer elements of OH packers  50  may expand radially through the cement  64  and into engagement with inner wall  2   a  (or radially inner surface  16   d ) as previously described. Accordingly, after actuation of OH packers  50 , annulus  21  is separated into a plurality of isolated sections, intervals, or regions. These isolated regions may be individually stimulated (e.g., perforated, hydraulically fractured, etc.) to allow production into throughbore  36  from a desired section of wellbore  2  (which may correspond to a desired region or portion of formation  11 ). In the event that one or more of the packers  50  should not properly and/or fully actuate upon increasing the fluid pressure within throughbores  15 ,  23 ,  36 , subsequent remedial operations may be conducted to accomplish the actuation of the one or more packers  50 . 
     Referring now to  FIG. 7 , once OH packers  50  are actuated in the manner described above, liner top packer  52  is actuated (e.g., mechanically or hydraulically) so that it expands radially to sealingly engage with radially inner surface  16   d  of intermediate casing  16 . Thereafter, setting tool  22  is decoupled from production liner  30  and pulled to the surface  9 . For example, in some embodiments, setting tool  22  is coupled to production liner  30  with an actuatable connector (e.g., a hydraulically, mechanically, and/or pressure actuated connector) such that setting tool  22  may be remotely disconnected from production  30  from surface  9  when desired. 
     While embodiments disclosed herein include injecting a gas (e.g., gas  62 ) into the annulus disposed about the tubular string (e.g., annulus  21  about tubular string  12 , setting tool  22 , and production liner  30 ), it should be appreciated that liquids may be injected into the annulus  21  in other embodiments. In such embodiments, the injected liquid is chosen such that it is generally lighter (e.g., has a lower density, lower specific gravity, etc.) than the other fluids disposed within the wellbore  2  (e.g., fluids  60 ). For example, in at least some embodiments, water is injected into the annulus  21 , which may also contain drilling mud or some other relatively heavy fluid (i.e., fluid  60  would comprise drilling mud or some other relatively heavy fluid in these embodiments). Then the pressure of the injected water is then controllably reduced (e.g., gradually and/or continuously) as cement is produced out of the shoe (e.g., lower end  30   b ) of production liner  30  in substantially the same way as described above (such that these details are omitted in the interests of brevity). Thus, in the same manner as described above, by controllably reducing the pressure of the water previously injected within annulus  21  during cementing operations, the cement may be more effectively drawn up within the annulus  21  toward the surface  9  (thereby minimizing the amount of cement that flows into the formation via fractures  7 ). 
     Referring now to  FIG. 8 , a method  100  for performing a cementing operation in a subterranean well is shown. In this embodiment, method  100  is performed using system  10  previously described, however, in other embodiments, method  100  can be performed with other systems. Accordingly, any reference to system  10  or components thereof is only meant to facilitate the description of method  100  and is not meant to limit application of method  100  to system  10  alone. 
     Starting at block  105 , method  100  includes installing a tubular string (e.g., tubular string  12 , setting tool  22 , and/or production liner  30 ) into a subterranean wellbore (e.g., wellbore  2 ). In some embodiments, at least a portion of the tubular string may comprise a production liner (e.g., production liner  30 ). Some of these embodiments may insert at least a portion of the production liner of the tubular string into a lateral section (or substantially lateral section) (e.g., lateral section  5 ) of the wellbore. In others of these embodiments, method  100  includes inserting the production liner (or at least a portion thereof) of the tubular string into a vertical section (or substantially vertical section) (e.g., vertical section  3 ) of the wellbore. In still others of these embodiments, method  100  includes inserting a portion of the production liner of the tubular string into a vertical section (or substantially vertical section) of the wellbore, and inserting another portion of the production liner into a lateral section (or substantially lateral section) of the wellbore. 
     Next, method  100  includes injecting a fluid into an annulus (e.g., annulus  21 ) formed radially outside (i.e., about) the tubular string at block  110 . In some embodiments, the injected fluid comprises a gas (e.g., N 2 , CO 2 , natural gas, etc.) (e.g., gas  62 ), while in other embodiments, the injected fluid comprises a liquid (e.g., water, brine, sodium chloride, potassium chloride, etc.). In addition, in some embodiments, the annulus is formed radially between the tubular string and another tubular (e.g., intermediate casing  16 ) and/or between the tubular string and the inner wall (e.g., inner wall  2   a ) of the wellbore  2 . The fluid (e.g., gas and/or liquid) may be injected from the surface (e.g., surface  9 ) directly into the annulus so that it fills (or substantially fills) the annulus to a predetermined depth. The injected fluid may be pressurized to a predetermined pressure to achieve the predetermined depth. The predetermined depth and associated predetermined pressure of the injected fluid may be set to result in a desired hydrostatic head reduction within the well sufficient to allow the reservoir pressure to support circulation of cement to a desired location along the annulus of the wellbore. In at least some embodiments, the fluid injected at  110  may be an inert gas such as nitrogen gas (N 2 ) to avoid an interaction (e.g., explosive, chemical, etc.) between the injected gas and any other fluids (i.e., liquid or gas) (e.g., fluid  60 ) that may be present within the wellbore. 
     Moving now to block  115 , method  100  includes pumping or flowing cement (e.g., cement  64 ) into the throughbore (e.g., throughbores  15 ,  23 ,  36 , etc.) of the tubular string. During this process, cement may be injected and/or pumped into the tubular string such that water or other fluids (e.g., fluid  60 ) within the tubular string may at least be partially displaced therefrom into the annulus (e.g., annulus  21 ) and formation (e.g., formation  11 ). Once a desired amount of cement is pumped into the tubular string (e.g., sufficient cement to fill a desired portion of the annulus), pumping of the cement is ceased. Then, at block  120 , the cement is displaced from the shoe of the tubular string (e.g., lower end  30   b  of production liner  30 ) and into the annulus. Displacement of the cement may be accomplished in a number of different fashions. For example, in some embodiments, a displacement fluid (e.g., fluid  60 ) may be pumped into the central bore of the tubular string to flush the cement out of the shoe of the tubular string and into the annulus. As another example, in other embodiments, a dart (e.g., dart  44 ) may be dropped or pumped downhole until it engages with a seat (e.g., seat  42 ) on the wiper plug (e.g., liner wiper plug  40 ). Thereafter, a displacement fluid (e.g., fluid  60 ) may be pumped into the central bore of the tubular string above the engaged dart and wiper plug to cause wiper plug to traverse within the tubular string toward the shoe at the distal or lower end thereof (e.g., lower end  30   b ). The sliding and potentially sealing engagement between the wiper plug and the inner surface (e.g., radially inner surface  30   d ) of the tubular string effectively sweeps the cement from tubular string and into the annulus. 
     Referring still to  FIG. 8 , at block  125 , either after, just after, or simultaneously with displacing the cement from the shoe of the tubular string at  120 , method  100  includes reducing the pressure of the fluid previously injected into the annulus. Specifically, the fluid (e.g., gas and/or liquid) may be emitted, bled, flowed out of the annulus at surface so that the volume and pressure of the previously injected fluid is reduced. The pressure may be gradually and/or continuously reduced such that a desired amount of pressure is maintained within the annulus during displacement of the cement into the annulus to allow circulation of cement through the annulus, rather than into one or more fractures (e.g., natural, un-natural fractures, etc.) (e.g., fractures  7 ) in the formation that intersect with the wellbore. In other words, the reduction in the fluid pressure is set, designed, and/or configured, to maintain sufficient pressure within the wellbore to prevent formation fluids from entering the wellbore from the formation, but also to ensure that the path of least resistance for the cement is up the annulus and toward the surface. As a result method  100  also includes drawing cement into the annulus and toward the surface at  130 . 
     Method  100  also includes activating one or more packers (e.g., OH packers  50 , liner top packer  52 , etc.) disposed about the tubular string at block  135 . In some embodiments, activating the packers at  135  takes place soon (or relatively soon) after drawing the cement up the annulus  130  such that the expanding packing elements may still expand through liquid or semi-liquid cement. Once the packers about the tubular string are actuated, one or more intervals are defined therebetween that may then be individually stimulated (e.g., via perforation, hydraulic fracturing, etc.) so that formation fluids may be produced from the formation into the wellbore. 
     In the manner described, embodiments of systems and methods for performing cementing operation in a wellbore extending into a subterranean formation in accordance with the principles disclosed herein (e.g., system  10 , method  100 ) offer the potential to reduce the potential for cement to flow into fractures (e.g., fractures  7 ) extending through the formation and intersecting the wellbore (e.g., wellbore  2 ). As a result, less cement is used during cementing operation, and cement is better distributed through the annulus being cemented (e.g., annulus  21 ). In addition, embodiments of systems and methods in accordance with the principles disclosed herein offer the potential to maintain fluid pressure within the wellbore at a sufficient level to prevent and/or minimize the influx of formation fluids into the wellbore during cementing operations (thereby limiting cement contamination), and also avoiding the creation of new fractures or lost circulation to the formation during a cementing operation. Thus, embodiments of systems and methods disclosed herein may be particularly useful for formations that are heavily fractured and/or have a relatively low formation fracture pressure. 
     While embodiments disclosed herein include systems and methods for performing cementing operation in a wellbore located at a land-based location, it should be appreciated that other embodiments of system  10  and method  100  may be utilized for a wellbore disposed at an offshore location (i.e., an offshore well). In addition, while embodiments disclosed herein have included a dart (e.g.,  44 ) for engaging with a seat on a liner wiper plug (e.g., wiper plug), it should be appreciated that other embodiments may utilize another type of droppable or pumpable actuation device, such as, for example, a single wiper plug (e.g., in place of liner wiper plug  40 ), a ball, plunger, etc. For example, some embodiments may employ a wiper plug pumped from the surface  9  through setting tool  22  and production liner  30  in place of liner wiper plug  40 , to displace cement  64  into annulus  21  during operations. Further, while embodiments disclosed herein have only shown casings  14 ,  16 , it should be appreciated that other embodiments may employ additional or fewer intermediate casing strings (or liners). 
     While exemplary embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.