Patent Publication Number: US-8122953-B2

Title: Drainage of heavy oil reservoir via horizontal wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATION APPLICATIONS 
     This application is a division of prior application Ser. No. 12/625,302 filed on Nov. 24, 2009 which is a division of prior application Ser. No. 11/832,620 filed on Aug. 1, 2007 (now U.S. Pat. No. 7,647,966). The entire disclosures of these prior applications are incorporated herein by this reference. 
    
    
     BACKGROUND 
     The present invention relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides drainage of a heavy oil reservoir via a generally horizontal wellbore. 
     It is well known that extensive heavy oil reservoirs are found in formations comprising unconsolidated, weakly cemented sediments. Unfortunately, the methods currently used for extracting the heavy oil from these formations have not produced entirely satisfactory results. 
     Heavy oil is not very mobile in these formations, and so it would be desirable to be able to form increased permeability planes in the formations. The increased permeability planes would increase the mobility of the heavy oil in the formations and/or increase the effectiveness of steam or solvent injection, in situ combustion, etc. 
     However, techniques used in hard, brittle rock to form fractures therein are typically not applicable to ductile formations comprising unconsolidated, weakly cemented sediments. Therefore, it will be appreciated that improvements are needed in the art of draining heavy oil from unconsolidated, weakly cemented formations. 
     SUMMARY 
     In carrying out the principles of the present invention, well systems and methods are provided which solve at least one problem in the art. One example is described below in which an inclusion is propagated into a formation comprising weakly cemented sediment. Another example is described below in which the inclusion facilitates production from the formation into a generally horizontal wellbore. 
     In one aspect, a method of improving production of fluid from a subterranean formation is provided. The method includes the step of propagating a generally vertical inclusion into the formation from a generally horizontal wellbore intersecting the formation. The inclusion is propagated into a portion of the formation having a bulk modulus of less than approximately 750,000 psi. 
     In another aspect, a well system is provided which includes a generally vertical inclusion propagated into a subterranean formation from a generally horizontal wellbore which intersects the formation. The formation comprises weakly cemented sediment. 
     These and other features, advantages, benefits and objects will become apparent to one of ordinary skill in the art upon careful consideration of the detailed description of representative embodiments of the invention hereinbelow and the accompanying drawings, in which similar elements are indicated in the various figures using the same reference numbers. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic partially cross-sectional view of a well system and associated method embodying principles of the present invention; 
         FIG. 2  is an enlarged scale schematic cross-sectional view through the well system, taken along line  2 - 2  of  FIG. 1 ; 
         FIG. 3  is a schematic partially cross-sectional view of an alternate configuration of the well system; 
         FIG. 4  is an enlarged scale schematic cross-sectional view through the alternate configuration of the well system, taken along line  4 - 4  of  FIG. 3 ; 
         FIGS. 5A  &amp; B are schematic partially cross-sectional views of another alternate configuration of the well system, with fluid injection being depicted in  FIG. 5A , and fluid production being depicted in  FIG. 5B ; and 
         FIGS. 6A  &amp; B are enlarged scale schematic cross-sectional views of the well system, taken along respective lines  6 A- 6 A and  6 B- 6 B of  FIGS. 5A  &amp; B. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention. The embodiments are described merely as examples of useful applications of the principles of the invention, which is not limited to any specific details of these embodiments. 
     Representatively illustrated in  FIG. 1  is a well system  10  and associated method which embody principles of the present invention. The system  10  is particularly useful for producing heavy oil  12  from a formation  14 . The formation  14  may comprise unconsolidated and/or weakly cemented sediments for which conventional fracturing operations are not well suited. 
     The term “heavy oil” is used herein to indicate relatively high viscosity and high density hydrocarbons, such as bitumen. Heavy oil is typically not recoverable in its natural state (e.g., without heating or diluting) via wells, and may be either mined or recovered via wells through use of steam and solvent injection, in situ combustion, etc. Gas-free heavy oil generally has a viscosity of greater than 100 centipoise and a density of less than 20 degrees API gravity (greater than about 900 kilograms/cubic meter). 
     As depicted in  FIG. 1 , two generally horizontal wellbores  16 ,  18  have been drilled into the formation  14 . Two casing strings  20 ,  22  have been installed and cemented in the respective wellbores  16 ,  18 . 
     The term “casing” is used herein to indicate a protective lining for a wellbore. Any type of protective lining may be used, including those known to persons skilled in the art as liner, casing, tubing, etc. Casing may be segmented or continuous, jointed or unjointed, made of any material (such as steel, aluminum, polymers, composite materials, etc.), and may be expanded or unexpanded, etc. 
     Note that it is not necessary for either or both of the casing strings  20 ,  22  to be cemented in the wellbores  16 ,  18 . For example, one or both of the wellbores  16 ,  18  could be uncemented or “open hole” in the portions of the wellbores intersecting the formation  14 . 
     Preferably, at least the casing string  20  is cemented in the upper wellbore  16  and has expansion devices  24  interconnected therein. The expansion devices  24  operate to expand the casing string  20  radially outward and thereby dilate the formation  14  proximate the devices, in order to initiate forming of generally vertical and planar inclusions  26 ,  28  extending outwardly from the wellbore  16 . 
     Suitable expansion devices for use in the well system  10  are described in U.S. Pat. Nos. 6,991,037, 6,792,720, 6,216,783, 6,330,914, 6,443,227 and their progeny, and in U.S. patent application Ser. No. 11/610,819. The entire disclosures of these prior patents and patent applications are incorporated herein by this reference. Other expansion devices may be used in the well system  10  in keeping with the principles of the invention. 
     Once the devices  24  are operated to expand the casing string  20  radially outward, fluid is forced into the dilated formation  14  to propagate the inclusions  26 ,  28  into the formation. It is not necessary for the inclusions  26 ,  28  to be formed simultaneously or for all of the upwardly or downwardly extending inclusions to be formed together. 
     The formation  14  could be comprised of relatively hard and brittle rock, but the system  10  and method find especially beneficial application in ductile rock formations made up of unconsolidated or weakly cemented sediments, in which it is typically very difficult to obtain directional or geometric control over inclusions as they are being formed. 
     Weakly cemented sediments are primarily frictional materials since they have minimal cohesive strength. An uncemented sand having no inherent cohesive strength (i.e., no cement bonding holding the sand grains together) cannot contain a stable crack within its structure and cannot undergo brittle fracture. Such materials are categorized as frictional materials which fail under shear stress, whereas brittle cohesive materials, such as strong rocks, fail under normal stress. 
     The term “cohesion” is used in the art to describe the strength of a material at zero effective mean stress. Weakly cemented materials may appear to have some apparent cohesion due to suction or negative pore pressures created by capillary attraction in fine grained sediment, with the sediment being only partially saturated. These suction pressures hold the grains together at low effective stresses and, thus, are often called apparent cohesion. 
     The suction pressures are not true bonding of the sediment&#39;s grains, since the suction pressures would dissipate due to complete saturation of the sediment. Apparent cohesion is generally such a small component of strength that it cannot be effectively measured for strong rocks, and only becomes apparent when testing very weakly cemented sediments. 
     Geological strong materials, such as relatively strong rock, behave as brittle materials at normal petroleum reservoir depths, but at great depth (i.e. at very high confining stress) or at highly elevated temperatures, these rocks can behave like ductile frictional materials. Unconsolidated sands and weakly cemented formations behave as ductile frictional materials from shallow to deep depths, and the behavior of such materials are fundamentally different from rocks that exhibit brittle fracture behavior. Ductile frictional materials fail under shear stress and consume energy due to frictional sliding, rotation and displacement. 
     Conventional hydraulic dilation of weakly cemented sediments is conducted extensively on petroleum reservoirs as a means of sand control. The procedure is commonly referred to as “Frac-and-Pack.” In a typical operation, the casing is perforated over the formation interval intended to be fractured and the formation is injected with a treatment fluid of low gel loading without proppant, in order to form the desired two winged structure of a fracture. Then, the proppant loading in the treatment fluid is increased substantially to yield tip screen-out of the fracture. In this manner, the fracture tip does not extend further, and the fracture and perforations are backfilled with proppant. 
     The process assumes a two winged fracture is formed as in conventional brittle hydraulic fracturing. However, such a process has not been duplicated in the laboratory or in shallow field trials. In laboratory experiments and shallow field trials what has been observed is chaotic geometries of the injected fluid, with many cases evidencing cavity expansion growth of the treatment fluid around the well and with deformation or compaction of the host formation. 
     Weakly cemented sediments behave like a ductile frictional material in yield due to the predominantly frictional behavior and the low cohesion between the grains of the sediment. Such materials do not “fracture” and, therefore, there is no inherent fracturing process in these materials as compared to conventional hydraulic fracturing of strong brittle rocks. 
     Linear elastic fracture mechanics is not generally applicable to the behavior of weakly cemented sediments. The knowledge base of propagating viscous planar inclusions in weakly cemented sediments is primarily from recent experience over the past ten years and much is still not known regarding the process of viscous fluid propagation in these sediments. 
     However, the present disclosure provides information to enable those skilled in the art of hydraulic fracturing, soil and rock mechanics to practice a method and system  10  to initiate and control the propagation of a viscous fluid in weakly cemented sediments. The viscous fluid propagation process in these sediments involves the unloading of the formation in the vicinity of the tip  30  of the propagating viscous fluid  32 , causing dilation of the formation  14 , which generates pore pressure gradients towards this dilating zone. As the formation  14  dilates at the tips  30  of the advancing viscous fluid  32 , the pore pressure decreases dramatically at the tips, resulting in increased pore pressure gradients surrounding the tips. 
     The pore pressure gradients at the tips  30  of the inclusions  26 ,  28  result in the liquefaction, cavitation (degassing) or fluidization of the formation  14  immediately surrounding the tips. That is, the formation  14  in the dilating zone about the tips  30  acts like a fluid since its strength, fabric and in situ stresses have been destroyed by the fluidizing process, and this fluidized zone in the formation immediately ahead of the viscous fluid  32  propagating tip  30  is a planar path of least resistance for the viscous fluid to propagate further. In at least this manner, the system  10  and associated method provide for directional and geometric control over the advancing inclusions  26 ,  28 . 
     The behavioral characteristics of the viscous fluid  32  are preferably controlled to ensure the propagating viscous fluid does not overrun the fluidized zone and lead to a loss of control of the propagating process. Thus, the viscosity of the fluid  32  and the volumetric rate of injection of the fluid should be controlled to ensure that the conditions described above persist while the inclusions  26 ,  28  are being propagated through the formation  14 . 
     For example, the viscosity of the fluid  32  is preferably greater than approximately 100 centipoise. However, if foamed fluid  32  is used in the system  10  and method, a greater range of viscosity and injection rate may be permitted while still maintaining directional and geometric control over the inclusions  26 ,  28 . 
     The system  10  and associated method are applicable to formations of weakly cemented sediments with low cohesive strength compared to the vertical overburden stress prevailing at the depth of interest. Low cohesive strength is defined herein as no greater than 400 pounds per square inch (psi) plus 0.4 times the mean effective stress (p′) at the depth of propagations.
 
 c&lt; 400 psi+0.4  p′   (1)
 
     where c is cohesive strength and p′ is mean effective stress in the formation  14 . 
     Examples of such weakly cemented sediments are sand and sandstone formations, mudstones, shales, and siltstones, all of which have inherent low cohesive strength. Critical state soil mechanics assists in defining when a material is behaving as a cohesive material capable of brittle fracture or when it behaves predominantly as a ductile frictional material. 
     Weakly cemented sediments are also characterized as having a soft skeleton structure at low effective mean stress due to the lack of cohesive bonding between the grains. On the other hand, hard strong stiff rocks will not substantially decrease in volume under an increment of load due to an increase in mean stress. 
     In the art of poroelasticity, the Skempton B parameter is a measure of a sediment&#39;s characteristic stiffness compared to the fluid contained within the sediment&#39;s pores. The Skempton B parameter is a measure of the rise in pore pressure in the material for an incremental rise in mean stress under undrained conditions. 
     In stiff rocks, the rock skeleton takes on the increment of mean stress and thus the pore pressure does not rise, i.e., corresponding to a Skempton B parameter value of at or about 0. But in a soft soil, the soil skeleton deforms easily under the increment of mean stress and, thus, the increment of mean stress is supported by the pore fluid under undrained conditions (corresponding to a Skempton B parameter of at or about 1). 
     The following equations illustrate the relationships between these parameters:
 
Δ u=B Δp   (2)
 
 B= ( K   u   −K )/(α  K   u )  (3)
 
α=1−( K/K   s )  (4)
 
     where Δu is the increment of pore pressure, B the Skempton B parameter, Δp the increment of mean stress, K u  is the undrained formation bulk modulus, K the drained formation bulk modulus, α is the Biot-Willis poroelastic parameter, and K s  is the bulk modulus of the formation grains. In the system  10  and associated method, the bulk modulus K of the formation  14  is preferably less than approximately 750,000 psi. 
     For use of the system  10  and method in weakly cemented sediments, preferably the Skempton B parameter is as follows:
 
 B&gt; 0.95 exp(−0.04  p′ )+0.008  p′   (5)
 
     The system  10  and associated method are applicable to formations of weakly cemented sediments (such as tight gas sands, mudstones and shales) where large entensive propped vertical permeable drainage planes are desired to intersect thin sand lenses and provide drainage paths for greater gas production from the formations. In weakly cemented formations containing heavy oil (viscosity&gt;100 centipoise) or bitumen (extremely high viscosity&gt;100,000 centipoise), generally known as oil sands, propped vertical permeable drainage planes provide drainage paths for cold production from these formations, and access for steam, solvents, oils, and heat to increase the mobility of the petroleum hydrocarbons and thus aid in the extraction of the hydrocarbons from the formation. In highly permeable weak sand formations, permeable drainage planes of large lateral length result in lower drawdown of the pressure in the reservoir, which reduces the fluid gradients acting towards the wellbore, resulting in less drag on fines in the formation, resulting in reduced flow of formation fines into the wellbore. 
     Although the present invention contemplates the formation of permeable drainage paths which generally extend laterally away from a horizontal or near horizontal wellbore  16  penetrating an earth formation  14  and generally in a vertical plane in opposite directions from the wellbore, those skilled in the art will recognize that the invention may be carried out in earth formations wherein the permeable drainage paths can extend in directions other than vertical, such as in inclined or horizontal directions. Furthermore, it is not necessary for the planar inclusions  26 ,  28  to be used for drainage, since in some circumstances it may be desirable to use the planar inclusions exclusively for injecting fluids into the formation  14 , for forming an impermeable barrier in the formation, etc. 
     An enlarged scale cross-sectional view of the well system  10  is representatively illustrated in  FIG. 2 . This view depicts the system  10  after the inclusions  26 ,  28  have been formed and the heavy oil  12  is being produced from the formation  14 . 
     Note that the inclusions  26  extending downwardly from the upper wellbore  16  and toward the lower wellbore  18  may be used both for injecting fluid  34  into the formation  14  from the upper wellbore, and for producing the heavy oil  12  from the formation into the lower wellbore. The injected fluid  34  could be steam, solvent, fuel for in situ combustion, or any other type of fluid for enhancing mobility of the heavy oil  12 . 
     The heavy oil  12  is received in the lower wellbore  18 , for example, via perforations  36  if the casing string  22  is cemented in the wellbore. Alternatively, the casing string  22  could be a perforated or slotted liner which is gravel-packed in an open portion of the wellbore  18 , etc. However, it should be clearly understood that the invention is not limited to any particular means or configuration of elements in the wellbores  16 ,  18  for injecting the fluid  34  into the formation  14  or recovering the heavy oil  12  from the formation. 
     Referring additionally now to  FIG. 3 , an alternate configuration of the well system  10  is representatively illustrated. In this configuration, the lower wellbore  18  and the inclusions  26  are not used. Instead, the expansion devices  24  are used to facilitate initiation and propagation of the upwardly extending inclusions  28  into the formation  14 . 
     An enlarged scale cross-sectional view of the well system  10  configuration of  FIG. 3  is representatively illustrated in  FIG. 4 . In this view it may be seen that the inclusions  28  may be used to inject the fluid  34  into the formation  14  and/or to produce the heavy oil  12  from the formation into the wellbore  16 . 
     Note that the devices  24  as depicted in  FIGS. 3 &amp; 4  are somewhat different from the devices depicted in  FIGS. 1 &amp; 2 . In particular, the device  24  illustrated in  FIG. 4  has only one dilation opening for zero degree phasing of the resulting inclusions  28 , whereas the device  24  illustrated in  FIG. 2  has two dilation openings for 180 degree relative phasing of the inclusions  26 ,  28 . 
     However, it should be understood that any phasing or combination of relative phasings may be used in the various configurations of the well system  10  described herein, without departing from the principles of the invention. For example, the well system  10  configuration of  FIGS. 3 &amp; 4  could include the expansion devices  24  having 180 degree relative phasing, in which case both the upwardly and downwardly extending inclusions  26 ,  28  could be formed in this configuration. 
     Referring additionally now to  FIGS. 5A  &amp; B, another alternate configuration of the well system  10  is representatively illustrated. This configuration is similar in many respects to the configuration of  FIG. 3 . However, in this version of the well system  10 , the inclusions  28  are alternately used for injecting the fluid  34  into the formation  14  (as depicted in  FIG. 5A ) and producing the heavy oil  12  from the formation into the wellbore  16  (as depicted in  FIG. 5B ). 
     For example, the fluid  34  could be steam which is injected into the formation  14  for an extended period of time to heat the heavy oil  12  in the formation. At an appropriate time, the steam injection is ceased and the heated heavy oil  12  is produced into the wellbore  16 . Thus, the inclusions  28  are used both for injecting the fluid  34  into the formation  14 , and for producing the heavy oil  12  from the formation. 
     A cross-sectional view of the well system  10  of  FIG. 5A  during the injection operation is representatively illustrated in  FIG. 6A . Another cross-sectional view of the well system  10  of  FIG. 5B  during the production operation is representatively illustrated in  FIG. 6B . 
     As discussed above for the well system  10  configuration of  FIG. 3 , any phasing or combination of relative phasings may be used for the devices  24  in the well system of  FIGS. 5A-6B . In addition, the downwardly extending inclusions  26  may be formed in the well system  10  of  FIGS. 5A-6B . 
     Although the various configurations of the well system  10  have been described above as being used for recovery of heavy oil  12  from the formation  14 , it should be clearly understood that other types of fluids could be produced using the well systems and associated methods incorporating principles of the present invention. For example, petroleum fluids having lower densities and viscosities could be produced without departing from the principles of the present invention. 
     It may now be fully appreciated that the above detailed description provides a well system  10  and associated method for improving production of fluid (such as heavy oil  12 ) from a subterranean formation  14 . The method includes the step of propagating one or more generally vertical inclusions  26 ,  28  into the formation  14  from a generally horizontal wellbore  16  intersecting the formation. The inclusions  26 ,  28  are preferably propagated into a portion of the formation  14  having a bulk modulus of less than approximately 750,000 psi. 
     The well system  10  preferably includes the generally vertical inclusions  26 ,  28  propagated into the subterranean formation  14  from the wellbore  16  which intersects the formation. The formation  14  may comprise weakly cemented sediment. 
     The inclusions  28  may extend above the wellbore  16 . The method may also include propagating another generally vertical inclusion  26  into the formation  14  below the wellbore  16 . The steps of propagating the inclusions  26 ,  28  may be performed simultaneously, or the steps may be separately performed. 
     The inclusions  26  may be propagated in a direction toward a second generally horizontal wellbore  18  intersecting the formation  14 . A fluid  34  may be injected into the formation  14  from the wellbore  16 , and another fluid  12  may be produced from the formation into the wellbore  18 . 
     The propagating step may include propagating the inclusions  26  toward the generally horizontal wellbore  18  intersecting the formation  14 . The method may include the step of radially outwardly expanding casings  20 ,  22  in the respective wellbores  16 ,  18 . 
     The method may include the steps of alternately injecting a fluid  34  into the formation  14  from the wellbore  16 , and producing another fluid  12  from the formation into the wellbore. 
     The propagating step may include reducing a pore pressure in the formation  14  at tips  30  of the inclusions  26 ,  28  during the propagating step. The propagating step may include increasing a pore pressure gradient in the formation  14  at tips  30  of the inclusions  26 ,  28 . 
     The formation  14  portion may comprise weakly cemented sediment. The propagating step may include fluidizing the formation  14  at tips  30  of the inclusions  26 ,  28 . The formation  14  may have a cohesive strength of less than 400 pounds per square inch plus 0.4 times a mean effective stress in the formation at the depth of the inclusions  26 ,  28 . The formation  14  may have a Skempton B parameter greater than 0.95 exp(−0.04 p′)+0.008 p′, where p′ is a mean effective stress at a depth of the inclusions  26 ,  28 . 
     The propagating step may include injecting a fluid  32  into the formation  14 . A viscosity of the fluid  32  in the fluid injecting step may be greater than approximately 100 centipoise. 
     Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the invention, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to these specific embodiments, and such changes are within the scope of the principles of the present invention. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended claims and their equivalents.