CROSS-REFERENCE TO RELATED APPLICATIONS 
     This continuation application claims the benefit of U.S. patent application Ser. No. 13/089,165, filed Apr. 18, 2011 which is a continuation of U.S. patent application Ser. No. 11/760,728, filed Jun. 8, 2007 (now U.S. Pat. No. 7,926,571), which is a continuation-in-part of U.S. patent application Ser. No. 11/359,059, filed Feb. 22, 2006 (now U.S. Pat. No. 7,377,322), which is a continuation-in-part application of U.S. patent application Ser. No. 11/079,950, filed Mar. 15, 2005 (now U.S. Pat. No. 7,267,172), each of which is incorporated by reference herein. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates to a system for fracing producing formations for the production of oil or gas and, more particularly, for fracing in a cemented open hole using sliding valves, which sliding valves may be selectively opened or closed according to the preference of the producer. 
     2. Description of the Related Art 
     Fracing is a method to stimulate a subterranean formation to increase the production of fluids, such as oil or natural gas. In hydraulic fracing, a fracing fluid is injected through a well bore into the formation at a pressure and flow rate at least sufficient to overcome the pressure of the reservoir and extend fractures into the formation. The fracing fluid may be of any of a number of different media, including sand and water, bauxite, foam, liquid CO 2 , nitrogen, etc. The fracing fluid keeps the formation from closing back upon itself when the pressure is released. The objective is for the fracing fluid to provide channels through which the formation fluids, such as oil and gas, can flow into the well bore and be produced. 
     One of the prior problems with earlier fracing methods is they require cementing of a casing in place and then perforating the casing at the producing zones. This in turn requires packers between various stages of the producing zone. An example of prior art that shows perforating the casing to gain access to the producing zone is shown in U.S. Pat. No. 6,446,727 to Zemlak, assigned to Schlumberger Technology Corporation. The perforating of the casing requires setting off an explosive charge in the producing zone. The explosion used to perforate the casing can many times cause damage to the formation. Plus, once the casing is perforated, then it becomes hard to isolate that particular zone and normally requires the use of packers both above and below the zone. 
     Another example of producing in the open hole by perforating the casing is shown in U.S. Pat. No. 5,894,888 to Wiemers. One of the problems with Wiemers is the fracing fluid is delivered over the entire production zone and you will not get concentrated pressures in preselected areas of the formation. Once the pipe is perforated, it is very hard to restore and selectively produce certain portions of the zone and not produce other portions of the zone. 
     When fracing with sand, sand can accumulate and block flow. United States Published Application 2004/0050551 to Jones shows fracing through perforated casing and the use of shunt tubes to give alternate flow paths. Jones does not provide a method for alternately producing different zones or stages of a formation. 
     One of the methods used in producing horizontal formations is to provide casing in the vertical hole almost to the horizontal zone being produced. At the bottom of the casing, either one or multiple holes extend horizontally. Also, at the bottom of the casing, a liner hanger is set with production tubing then extending into the open hole. Packers are placed between each stage of production in the open hole, with sliding valves along the production tubing opening or closing depending upon the stage being produced. An example is shown in U.S. Published Application 2003/0121663 A1 to Weng, wherein packers separate different zones to be produced with nozzles (referred to as “burst disks”) being placed along the production tubing to inject fracing fluid into the formations. However, there are disadvantages to this particular method. The fracing fluid will be delivered the entire length of the production tubing between packers. This means there will not be a concentrated high pressure fluid being delivered to a small area of the formation. Also, the packers are expensive to run and set inside of the open hole in the formation. 
     Applicant previously worked for Packers Plus Energy Services, Inc., which had a system similar to that shown in Weng. By visiting the Packers Plus website of www.packersplus.com, more information can be gained about Packers Plus and their products. Examples of the technology used by Packers Plus can be found in United States Published Application Nos. 2004/0129422, 2004/0118564, and 2003/0127227. Each of these published patent applications shows packers being used to separate different producing zones. However, the producing zones may be along long lengths of the production tubing, rather than in a concentrated area. 
     The founders of Packers Plus previously worked for Guiberson, which was acquired by Dresser Industries and later by Halliburton. The techniques used by Packers Plus were previously used by Guiberson/Dresser/Halliburton. Some examples of well completion methods by Halliburton can be found on the website of www.halliburton.com, including the various techniques they utilize. Also, the sister companies of Dresser Industries and Guiberson can be visited on the website of www.dresser.com. Examples of the Guiberson retrievable packer systems can be found on the Mesquite Oil Tool Inc. website of www.snydertex.com/mesquite/guiberson/htm. 
     None of the prior art known by applicant, including that of his prior employer, utilized cementing production tubing in place in the production zone with sliding valves being selectively located along the production tubing. None of the prior systems show (1) the sliding valve being selectively opened or closed, (2) the cement therearound being removed, and/or (3) selectively fracing with predetermined sliding valves. All of the prior systems known by applicant utilize packers between the various stages to be produced and have fracing fluid injected over a substantial distance of the production tubing in the formation, not at preselected points adjacent the sliding valves. 
     BRIEF SUMMARY OF THE INVENTION 
     The invention is a method of producing petroleum from at least one open hole in at least one petroleum production zone of a hydrocarbon well. The method comprising the steps of locating a plurality of sliding valves along at least one production tubing; inserting the plurality of sliding valves and the production tubing into the at least one open hole; cementing the plurality of sliding valves in the at least one open hole; opening at least one of the cemented sliding valves; removing at least some of the cement adjacent the opened sliding valves without using jetting tools or cutting tools to establish at least one communication path between the interior of the production tubing and the at least one petroleum production zone; directing a fracing material radially through the at least one sliding valve radially toward the at least one production zone; producing hydrocarbons from the at least one petroleum production zone through the plurality of the sliding valves the cement adjacent to which has been removed. 
     According to another aspect of the invention, an open hole fracing system comprises at least one production tubing inserted into the at least one open hole; a plurality of sliding valves located along the at least one production tubing and in the at least one petroleum production zone, each of the sliding valves having radially-orientated openings therethrough; cement adjacent to the plurality of sliding valves; a fluid flowable radially through the openings of the at least one sliding valve to remove at least some of the adjacent cement without using jetting tools or cutting tools; a fracing material flowable radially through the plurality of sliding valves to cause fracturing of the at least one production zone. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
         FIG. 1  is a partial sectional view of a well with a cemented open hole fracing system in a lateral located in a producing zone. 
         FIG. 2  is a longitudinal view of a mechanical shifting tool. 
         FIG. 3  is an elongated partial sectional view of a sliding valve. 
         FIG. 4  is an elongated partial sectional view of a single mechanical shifting tool. 
         FIG. 5A  is an elongated partial sectional view illustrating a mechanical shifting tool opening the sliding valve. 
         FIG. 5B  is an elongated partial sectional view illustrating a mechanical shifting tool closing the sliding valve. 
         FIG. 6  is a pictorial sectional view of a cemented open hole fracing system having multiple laterals. 
         FIG. 7  is an elevated view of a wellhead. 
         FIG. 8  is a cemented open hole horizontal fracing system. 
         FIG. 9  is a cemented open hole vertical fracing system. 
         FIG. 10A  is an elongated partial sectional view illustrating a ball-and-seat sliding valve in the “opened” position. 
         FIG. 10B  is an elongated partial sectional view illustrating a ball-and seat sliding valve in the “closed” position. 
         FIGS. 11A-11C  are enlarged sectional views of the valves of the cemented open hole vertical fracing system shown in  FIG. 9  that disclose in more detail how the ball-and-seat sliding valves are selectively opened and closed. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     A preferred embodiment of an open hole fracing system is pictorially illustrated in  FIG. 1 . A production well  10  is drilled in the earth  12  to a hydrocarbon production zone  14 . A casing  16  is held in place in the production well  10  by cement  18 . At the lower end  20  of production casing  16  is located liner hanger  22 . Liner hanger  22  may be either hydraulically or mechanically set. 
     Below liner hanger  22  extends production tubing  24 . To extend laterally, the production well  10  and production tubing  24  bends around a radius  26 . The radius  26  may vary from well to well and may be as small as thirty feet and as large as four hundred feet. The radius of the bend in production well  10  and production tubing  24  depends upon the formation and equipment used. 
     Inside of the hydrocarbon production zone  14 , the production tubing  24  has a series of sliding valves pictorially illustrated as  28   a - 28   h . The distance between the sliding valves  28   a - 28   h  may vary according to the preference of the particular operator. A normal distance is the length of a standard production tubing of  30  feet. However, the production tubing segments  30   a - 30   h  may vary in length depending upon where the sliding valves  28  should be located in the formation. 
     The entire production tubing  24 , sliding valves  28   a - 28   h , and the production tubing segments  30  are all encased in cement  32 . Cement  32  located around production tubing  24  may be different from the cement  18  located around the casing  16 . 
     In actual operation, sliding valves  28   a - 28   h  may be selectively opened or closed as will be subsequently described. The sliding valves  28   a - 28   h  may be opened in any order or sequence. 
     For the purpose of illustration, assume the operator of the production well  10  desires to open sliding valve  28   h . A mechanical shifting tool  34 , such as that shown in  FIG. 2 , connected on shifting string would be lowered into the production well  10  through casing  16  and production tubing  24 . The shifting tool  34  has two elements  34   a ,  34   b  that are identical, except they are reversed in direction and connected by a shifting string segment  38 . While the shifting string segment  38  is identical to shifting string  36 , shifting string segment  38  provides the distance that is necessary to separate shifting tools  34   a ,  34   b . Typically, the shifting string segment  38  would be about thirty feet in length. 
     To understand the operation of shifting tool  34  inside sliding valves  28   a - 28   h , an explanation as to how the shifting tool  34  and sliding valves  28   a - 28   h  work internally is necessary. Referring to  FIG. 3 , a partial cross-sectional view of the sliding valve  28  is shown. An upper housing sub  40  is connected to a lower housing sub  42  by threaded connections via the nozzle body  44 . A series of nozzles  46  extend through the nozzle body  44 . Inside of the upper housing sub  40 , lower housing sub  42 , and nozzle body  44  is an inner sleeve  48 . Inside of the inner sleeve  48  are slots  50  that allow fluid communication from the inside passage  52  through the slots  50  and nozzles  46  to the outside of the sliding valve  28 . The inner sleeve  48  has an opening shoulder  54  and a closing shoulder  56  located therein. 
     When the shifting tool  34  shown in  FIG. 4  goes into the sliding valve  28 , shifting tool  34   a  performs the closing function and shifting tool  34   b  performs the opening function. Shifting tools  34   a  and  34   b  are identical, except reverse and connected through the shifting string segment  38 . 
     Assume the shifting tool  34  is lowered into production well  10  through the casing  16  and into the production tubing  24 . Thereafter, the shifting tool  34  will go around the radius  26  through the shifting valves  28  and production pipe segments  30 . Once the shifting tool  34   b  extends beyond the last sliding valve  28   h , the shifting tool  34   b  may be pulled back in the opposite direction as illustrated in  FIG. 5A  to open the sliding valve  28 , as will be explained in more detail subsequently. 
     Referring to  FIG. 3 , the sliding valve  28  has wiper seals  58  between the inner sleeve  48  and the upper housing sub  42  and the lower housing sub  44 . The wiper seals  58  keep debris from getting back behind the inner sleeve  48 , which could interfere with its operation. This is particularly important when sand is part of the fracing fluid. 
     Also located between the inner sleeve  48  and nozzle body  44  is a C-clamp  60  that fits in a notch undercut in the nozzle body  44  and into a C-clamp notch  61  in the outer surface of inner sleeve  48 . The C-clamp puts pressure in the notches and prevents the inner sleeve  48  from being accidentally moved from the opened to closed position or vice versa, as the shifting tool is moving there through. 
     Also, seal stacks  62  and  64  are compressed between (1) the upper housing sub  40  and nozzle body  44  and (2) lower housing sub  42  and nozzle body  44 , respectively. The seal stacks  62 ,  64  are compressed in place and prevent leakage from the inner passage  52  to the area outside sliding valve  28  when the sliding valve  28  is closed. 
     Turning now to the mechanical shifting tool  34 , an enlarged partial cross-sectional view is shown in  FIG. 4 . Selective keys  66  extend outward from the shifting tool  34 . Typically, a plurality of selective keys  66 , such as four, would be contained in any shifting tool  34 , though the number of selective keys  66  may vary. The selective keys  66  are spring loaded so they normally will extend outward from the shifting tool  34  as is illustrated in  FIG. 4 . The selective keys  66  have a beveled slope  68  on one side to push the selective keys  66  in, if moving in a first direction to engage the beveled slope  68 , and a notch  70  to engage any shoulders, if moving in the opposite direction. Also, because the selective keys  66  are moved outward by spring  72 , by applying proper pressure inside passage  74 , the force of spring  72  can be overcome and the selective keys  66  may be retracted by fluid pressure applied from the surface. 
     Referring now to  FIG. 5A , assume the opening shifting tool  34   b  has been lowered through sliding valve  28  and thereafter the direction reversed. Upon reversing the direction of the shifting tool  34   b , the notch  70  in the shifting tool will engage the opening shoulder  54  of the inner sleeve  48  of sliding valve  28 . This will cause the inner sleeve  48  to move from a closed position to an opened position as is illustrated in  FIG. 5A . This allows fluid in the inside passage  58  to flow through slots  50  and nozzles  46  into the formation around sliding valve  28 . As the inner sleeve  48  moves into the position as shown in  FIG. 5A , C-clamp  60  will hold the inner sleeve  48  in position to prevent accidental shifting by engaging one of two C-clamp notches  61 . Also, as the inner sleeve  48  reaches its open position and C-clamp  60  engages, simultaneously the inner diameter  59  of the upper housing sub  40  presses against the slope  76  of the selective key  66 , thereby causing the selective keys  66  to move inward and notch  70  to disengage from the opening shoulder  54 . 
     If it is desired to close a sliding valve  28 , the same type of shifting tool will be used, but in the reverse direction, as illustrated in  FIG. 5B . The shifting tool  34   a  is arranged in the opposite direction so that now the notch  70  in the selective keys  66  will engage closing shoulder  56  of the inner sleeve  48 . Therefore, as the shifting tool  34   a  is lowered through the sliding valve  28 , as shown in  FIG. 5B , the inner sleeve  48  is moved to its lowermost position and flow between the slots  50  and nozzles  46  is terminated. The seal stacks  62  and  64  insure there is no leakage. Wiper seals  58  keep the crud from getting behind the inner sleeve  48 . 
     Also, as the shifting tool  34 A moves the inner sleeve  48  to its lowermost position, pressure is exerted on the slope  76  by the inner diameter  61  of lower housing sub  42  of the selective keys  66  to disengage the notch  70  from the closing shoulder  56 . Simultaneously, the C-clamp  60  engages in another C-clamp notch  61  in the outer surface of the inner sleeve  48 . 
     If the shifting tool  34 , as shown in  FIG. 2 , was run into the production well  10  as shown in  FIG. 1 , the shifting tool  34  and shifting string  36  would go through the internal diameter of casing  16 , internal opening of hanger liner  22 , through the internal diameter of production tubing  24 , as well as through sliding valves  28  and production pipe segments  30 . 
     Pressure could be applied to the internal passage  74  of shifting tool  34  through the shifting string  36  to overcome the pressure of springs  72  and to retract the selective keys  66  as the shifting tool  34  is being inserted. However, on the other hand, even without an internal pressure, the shifting tool  34   b , due to the beveled slope  68 , would not engage any of the sliding valves  28   a - 28   h  as it is being inserted. On the other hand, the shifting tool  34   a  would engage each of the sliding valves  28  and make sure the inner sleeve  48  is moved to the closed position. After the shifting tool  34   b  extends through sliding valve  28   h , shifting tool  34   b  can be moved back towards the surface causing the sliding valve  28   h  to open. At that time, the operator of the well can send fracing fluid through the annulus between the production tubing  24  and the shifting string  36 . Normally, an acid would be sent down first to dissolve the acid-soluble cement  32  around sliding valve  28  (see  FIG. 1 ). After dissolving the cement  32 , the operator has the option to frac around sliding valve  28   h , or the operator may elect to dissolve the cement around other sliding valves  28   a - 28   g . Alternatively, the dissolving of the cement could also occur contemporaneously with the fracing process by using a fracing material having acidic properties. 
     Normally, after dissolving the cement  32  around sliding valve  28   h , then shifting tool  34   a  would be inserted there through, which closes sliding valve  28   h . At that point, the system would be pressure checked to insure sliding valve  28   h  was in fact closed. By maintaining the pressure, the selective keys  66  in the shifting tool  34  will remain retracted and the shifting tool  34  can be moved to shifting valve  28   g . The process is now repeated for shifting valve  28   g , so that shifting tool  34   b  will open sliding valve  28   g . Thereafter, the cement  32  is dissolved, sliding valve  28   g  closed, and again the system pressure checked to insure valve  28   g  is closed. This process is repeated until each of the sliding valves  28   a - 28   h  has been opened, the cement dissolved (or otherwise removed), pressure checked after closing, and now the system is ready for fracing. 
     By determining the depth from the surface, the operator can tell exactly which sliding valve  28   a - 28   h  is being opened. By selecting the combination the operator wants to open, then fracing fluid can be pumped through casing  16 , production tubing  24 , sliding valves  28 , and production tubing segments  30  into the formation. 
     By having a very limited area around the sliding valve  28  that is subject to fracing, the operator now gets fracing deeper into the formation with less fracing fluid. The increase in the depth of the fracing results in an increase in production of oil or gas. The cement  32  between the respective sliding valves  28   a - 28   h  confines the fracing fluids to the areas immediately adjacent to the sliding valves  28   a - 28   h  that are open. 
     Any particular combination of the sliding valves  28   a - 28   h  can be selected. The operator at the surface can tell when the shifting tool  34  goes through which sliding valves  28   a - 28   h  by the depth and increased force as the respective sliding valve is being opened or closed. 
     Applicant has just described one way of shifting the sliding sleeves used within the system of the present invention. Other types of shifting devices may be used including electrical, hydraulic, or other mechanical designs. While mechanical shifting using a shifting tool  34  is tried and proven, other designs may be useful depending on how the operator wants to produce the well. For example, the operator may not want to separately dissolve the cement  32  around each sliding valve  28   a - 28   h , and pressure check, prior to fracing. The operator may want to open every third sliding valve  28 , dissolve the cement, then frac. Depending upon the operator preference, some other type shifting device may be easily be used. 
     Another aspect of the invention is to prevent debris from getting inside sliding valves  28  when the sliding valves  28  are being cemented into place inside of the open hole. To prevent the debris from flowing inside the sliding valve  28 , a plug  78  is located in nozzle  46 . The plug  78  can be dissolved by the same acid that is used to dissolve the cement  32 . For example, if a hydrochloric acid is used, by having a weep hole  80  through an aluminum plug  78 , the aluminum plug  78  will quickly be eaten up by the hydrochloric acid. However, to prevent wear at the nozzles  46 , the area around the aluminum plus  78  is normally made of titanium. The titanium resists wear from fracing fluids, such as sand. 
     While the use of plug  78  has been described, plugs  78  may not be necessary. If the sliding valves  28  are closed and the cement  32  does not stick to the inner sleeve  48 , plugs  78  may be unnecessary. It all depends on whether the cement  32  will stick to the inner sleeve  48 . 
     Further, the nozzle  46  may be hardened any of a number of ways instead of making the nozzles  46  out of titanium. The nozzles  46  may be (a) heat treated, (b) frac hardened, (c) made out of tungsten carbide, (d) made out of hardened stainless steel, or (e) made or treated any of a number of different ways to decrease and increase productive life. 
     Assume the system as just described is used in a multi-lateral formation as shown in  FIG. 6 . Again, the production well  10  is drilled into the earth  12  and into a hydrocarbon production zone  14 , but also into hydrocarbon production zone  82 . Again, a liner hanger  22  holds the production tubing  24  that is bent around a radius  26  and connects to sliding valves  28   a - 28   h , via production pipe segments  30   a - 30   h . The production of zone  14 , as illustrated in  FIG. 6 , is the same as the production as illustrated in  FIG. 1 . However, a window  84  has now been cut in casing  16  and cement  18  so that a horizontal lateral  86  may be drilled there through into hydrocarbon production zone  82 . 
     In the drilling of wells with multiple laterals, or multi-lateral wells, an on/off tool  88  is used to connect to the stinger  90  on the liner hanger  22  or the stinger  92  on packer  94 . Packer  94  can be either a hydraulic set or mechanical set packer to the wall  81  of the horizontal lateral  86 . In determining which lateral  86 ,  96  to which the operator is going to connect, a bend  98  in the vertical production tubing  100  helps guide the on/off tool  88  to the proper lateral  86  or  96 . The sliding valves  102   a - 102   g  may be identical to the sliding valves  28   a - 28   h . The only difference is sliding valves  102   a - 102   g  are located in hydrocarbon production zone  82 , which is drilled through the window  84  of the casing  16 . Sliding valves  102   a - 102   g  and production tubing  104   a - 104   g  are cemented into place past the packer  94  in the same manner as previously described in conjunction with  FIG. 1 . Also, the sliding valves  102   a - 102   g  are opened in the same manner as sliding valves  28   a - 28   h  as described in conjunction with  FIG. 1 . Also, the cement  106  may be dissolved in the same manner. 
     Just as the multi laterals as described in  FIG. 6  are shown in hydrocarbon production zones  14  and  82 , there may be other laterals drilled in the same zones  14  and/or  82 . There is no restriction on the number of laterals that can be drilled nor in the number of zones that can be drilled. Any particular sliding valve may be operated, the cement dissolved, and fracing begun. Any particular sliding valve the operator wants to open can be opened for fracing deep into the formation adjacent the sliding valve. 
     By use of the system as just described, more pressure can be created in a smaller zone for fracing than is possible with prior systems. Also, the size of the tubulars is not decreased the further down in the well the fluid flows. Although ball-operated valves may be used with alternative embodiments of the present invention, the decreasing size of tubulars is a particular problem for a series of ball operated valves, each successive ball-operated valve being smaller in diameter. This means the same fluid flow can be created in the last sliding valve at the end of the string as would be created in the first sliding valve along the string. Hence, the flow rates can be maintained for any of the selected sliding valves  28   a - 28   h  or  102   a - 102   g . This results in the use of less fracing fluid, yet fracing deeper into the formation at a uniform pressure regardless of which sliding valve through which fracing may be occurring. Also, the operator has the option of fracing any combination or number of sliding valves at the same time or shutting off other sliding valves that may be producing undesirables, such as water. 
     On the top of casing  18  of production well  10  is located a wellhead  108 . While many different types of wellheads are available, the wellhead preferred by applicant is illustrated in further detail in  FIG. 7 . A flange  110  is used to connect to the casing  16  that extends out of the production well  10 . On the sides of the flange  110  are standard valves  112  that can be used to check the pressure in the well, or can be used to pump things into the well. A master valve  114  that is basically a float control valve provides a way to shut off the well in case of an emergency. Above the master valve  114  is a goat head  116 . This particular goat head  116  has four points of entry  118 , whereby fracing fluids, acidizing fluids or other fluids can be pumped into the well. Because sand is many times used as a fracing fluid and is very abrasive, the goat head  116  is modified so sand that is injected at an angle to not excessively wear the goat head. However, by adjusting the flow rate and/or size of the opening, a standard goat head may be used without undue wear. 
     Above the goat head  116  is located blowout preventer  120 , which is standard in the industry. If the well starts to blow, the blowout preventer  120  drives two rams together and squeezes the pipe closed. Above the blowout preventer  120  is located the annular preventer  122 . The annular preventer  122  is basically a big balloon squashed around the pipe to keep the pressure in the well bore from escaping to atmosphere. The annular preventer  122  allows access to the well so that pipe or tubing can be moved up and down there through. The equalizing valve  124  allows the pressure to be equalized above and below the blow out preventer  120 . The equalizing of pressure is necessary to be able to move the pipe up and down for entry into the wellhead. All parts of the wellhead  108  are old, except the modification of the goat head  116  to provide injection of sand at an angle to prevent excessive wear. Even this modification is not necessary by controlling the flow rate. 
     Turning now to  FIG. 8 , the system as presently described has been installed in a well  126  without vertical casing. Well  126  has production tubing  128  held into place by cement  130 . In the production zone  132 , the production tubing  128  bends around radius  134  into a horizontal lateral  136  that follows the production zone  132 . The production tubing  128  extends into production zone  132  around the radius  134  and connects to sliding valves  138   a - 138   f , through production tubing segments  140   a - 140   f . Again, the sliding valves  138   a - 138   f  may be operated so the cement  130  is dissolved therearound. Thereafter (or simultaneously therewith, such as when the fracing material has dissolving properties), any of a combination of sliding valves  138   a - 138   f  can be operated and the production zone  132  fraced around the opened sliding valve. In this type of system, it is not necessary to cement into place a casing nor is it necessary to use any type of packer or liner hanger. The minimum amount of hardware is permanently connected in well  126 , yet fracing throughout the production zone  132  in any particular order as selected by the operator can be accomplished by simply fracing through the selected sliding valves  138   a - 138   f.    
     The system previously described can also be used for an entirely vertical well  140  as shown in  FIG. 9 . The wellhead  108  connects to casing  144  that is cemented into place by cement  146 . At the bottom  147  of casing  144  is located a liner hanger  148 . Below liner hanger  148  is production tubing  150 . In the well  140 , as shown in  FIG. 9 , there are producing zones  152 ,  154 , and  156 . After the production tubing  150  and sliding valves  158 ,  160 , and  162   a - 162   d  are cemented into place by acid soluble cement  164 , the operator may now produce all or selected zones. For example, by dissolving the cement  164  adjacent sliding valve  158 , thereafter, production zone  152  can be fraced and produced through sliding valve  158 . Likewise, the operator could dissolve the cement  164  around sliding valve  160  that is located in production zone  154 . After dissolving the cement  164  around sliding valve  160 , production zone  154  can be fraced and later produced. 
     On the other hand, if the operator wants to have multiple sliding valves  162   a - 162   d  operate in production zone  156 , the operator can operate all or any combination of the sliding valves  162   a - 162   d , dissolve the cement  164  therearound, and later frac through all or any combination of the sliding valves  162   a - 162   d . By use of the method as just described, the operator can produce whichever zone  152 ,  154  or  156  the operator desires with any combination of selected sliding valves  158 ,  160  or  162 . 
     Alternative embodiments of the present invention may include any number of sliding sleeve variants, such as a hydraulically actuated ball-and-seat valve  200  shown in  FIGS. 10A and 10B . More specifically,  FIG. 10A  discloses a ball-and-seat valve  200  that has a mandrel  202  threadedly engaged at its upper end  204  with an upper sub  208  and at the lower end  206  with lower sub  210 , respectively, attachable to production tubing segments (not shown). The mandrel  202  has a series of mandrel ports  212  providing a fluid communication path between the exterior of the ball-and-seat valve  200  to the interior of the mandrel  202 . 
       FIG. 10A  shows the ball-and-seat valve  200  in a “closed” position, wherein the fluid communication paths through the mandrel ports  212  are blocked by a lower portion  214  of the outer surface of an inner sleeve  216 , which lower portion  214  is defined by a middle seal  218  and a lower seal  220 , respectively. The middle seal  218  and lower seal  220  encircle the inner sleeve  216  to substantially prevent fluid from flowing between the outer surface of the inner sleeve  216  to the mandrel ports  212  in the mandrel  202 . 
     The inner sleeve  216  is cylindrical with open ends to allow fluid communication through the interior thereof. The inner sleeve  216  further contains a cylindrical ball seat  222  opened at both ends and connected to the inner sleeve  216 . When the ball-and-seat valve  200  is closed as shown in  FIG. 10A , fluid may be communicated through the inner sleeve  216  and cylindrical ball seat  222  affixed thereto in either the upwell or downwell direction. 
       FIG. 10B  shows the ball-and-seat valve  200  in an “open” position. When the ball-and-seat valve  200  is to be selectively opened, a ball  223  sealable to a seating surface  224  of the cylindrical ball seat  222  is pumped into the ball-and-seat valve  200  from the upper sub  208 . The ball  223  is sized such that the cylindrical ball seat  222  impedes further movement of the ball  223  through the ball-and-seat valve  200  as the ball  223  contacts the seating surface  224  and seals the interior of the seat  222  from fluid communication therethrough. In other words, the sealing of the ball  223  to the ball seat  222  prevents fluid from flowing downwell past the ball-and-seat valve  200 . 
     To open the ball-and-seat valve  200 —in other words, to move the inner sleeve  216  to the “open” position—downward flow within the production tubing (not shown) is maintained. Because fluid cannot move through the seat  222  because the ball  223  is in sealing contact with the seating surface  224  thereof, pressure upwell from the ball  223  may be increased to force the ball  223 , and therefore the inner sleeve  216 , downwell until further movement of the inner sleeve  216  is impeded by contacting the lower sub  210 . 
     As shown in  FIG. 10B , when the inner sleeve  216  is in the “open” positioned, a series of sleeve ports  226  provide a fluid communication path between the exterior and interior of the inner sleeve  216  and are aligned with the mandrel ports  212  to permit fluid communication therethrough from and to the interior of the ball-and-seat valve  200 , and more specifically to the interior of the inner sleeve  216 . When the ball-and-seat valve  200  is “open,” fluid communication to and from the interior of the ball-and-seat valve  200  other than through the mandrel ports  212  and sleeve ports  226  is prevented by an upper seal  228  and the middle seal  218  encircling the outer surface of the inner sleeve  216 . The ball-and-seat valve  200  may thereafter be closed through the use of conventional means, such as a mechanical shifting tool lowered through the production tubing, as described with reference to the preferred embodiment. 
     When multiple ball-and-seat valves are used in a production well, each of the ball-and-seat valves will have a ball seat sized differently from the ball seats of the other valves used in the same production tubing. Moreover, the valve with the largest diameter ball seat will be located furthest upwell, and the valve with the smallest diameter ball seat will be located furthest downwell. Because the size of the seating surface of each ball seat is designed to mate and seal to a particularly-sized ball, valves are chosen and positioned within the production string so that balls will flow through any larger-sized, upwell ball seats until the appropriately-sized seat is reached. When the appropriately-sized ball seat is reached, the ball will mate and seal to the seat, blocking any upwell-to-downwell fluid flow as described hereinabove. Thus, when selectively opening multiple ball-and-seat valves within a production string, the valve furthest downwell is typically first opened, then the next furthest, and so on. 
     Referring to  FIGS. 11A-11C  in sequence, and by way of example, assume that the production well shown in  FIG. 9  uses four ball-and-seat valves  162   a - 162   d  in the production zone  156 . As shown in  FIG. 11A , further assume that the ball-and-seat valves  162   a - 162   d  are sized as follows: The deepest ball-and-seat valve  162   d  has a ball seat  163   d  with an inner diameter of 1.36″ and matable to a ball (not shown) having a 1.50″ diameter; the next deepest ball-and-seat valve  162   c  has a ball seat  163   c  with an inner diameter of 1.86″ and matable to a ball (not shown) having a 2.00″ diameter; the next deepest valve  162   b  has a ball seat  163   b  with an inner diameter of 2.36″ and matable to a ball (not shown) having a 2.50″ diameter; and the shallowest ball-and-seat valve  162   a  has a ball seat  163   a  with an inner diameter of 2.86″ and matable to a ball (not shown) having a 3.00″ diameter. The ball-and-seat valves  162   a - 162   d  are connected with segments of production tubing  150 . The ball-and-seat valves  162   a - 162   d  and production tubing  150  are cemented into place in an open hole with cement  164 . 
     As shown in  FIG. 11B , to open the deepest valve  162   d , a ball  165   d  having a 1.50″ diameter is pumped through the production tubing  150  and shallower ball-and-seat valves  162   a - 162   c . Because the 1.50″ diameter of the ball  165   d  is smaller than the inner diameters of each of the ball seats  163   a - 163   c  of the other valves  162   a - 162   c —which are 2.86″, 2.36″, and 1.86″, respectively—the ball  165   d  will flow in a downwell direction  172  through each of the shallower ball-and-seat valves  162   a - 162   c  until further downwell movement is impeded by the smaller 1.36″ diameter ball seat  163   d  of the deepest ball-and-seat valve  162   d . At that point, if the ball-and-seat valve  162   d  is in the closed position (see  FIG. 10A ), fluid pressure within the production tubing  150  may be increased to selectively open the ball-and-seat valve  162   d  as previously described with reference to  FIG. 10B  hereinabove. After selectively opening the deepest ball-and-seat valve  162   d , the cement  164  adjacent thereto may be dissolved with a solvent  171  and the production zone  156  can be fraced and produced through ball-and-seat valve  162   d , as previously described. As shown in  FIG. 11C , dissolving the cement  164  adjacent thereto leaves passages  170  through which fracing material may be forced into cracks  180  in the production zone  156  and through which oil from the surrounding production zone  156  may be produced. 
     Further referring to  FIG. 11C , to open the next deepest ball-and-seat valve  162   c , a ball  165   c  having a 2.00″ diameter is pumped through the production tubing  150  and two shallower ball-and-seat valves  162   a ,  162   b . Because the 2.00″ diameter of the ball  165   c  is smaller than the inner diameters of the two shallower ball-and-seat valves  162   a ,  162   b —which are 2.86″ and 2.36″, respectively—the ball  165   c  will flow in a downwell direction  172  through each of the ball-and-seat valves  162   a ,  162   b  until further downwell movement is impeded by the smaller 1.86″ diameter ball seat  163   c  of the second deepest valve  162   c . If the ball-and-seat valve  162   c  is closed, fluid pressure within the production tubing  150  may be increased to selectively open the ball-and-seat valve  162   c  as previously described with reference to  FIG. 10B  hereinabove. After selectively opening the ball-and-seat valve  162   c , the cement  164  adjacent thereto may be dissolved and the production zone  156  can be fraced and produced through ball-and-seat valve  162   c . This process may be repeated until all desired valves within the production well have been selectively opened and fraced and/or produced. 
     After having been pumped into the production well to selectively trigger corresponding ball-and-seat sliding valves, the balls may be pumped from the production well during production by reversing the direction of flow. Alternatively, seated balls may be milled, and thus fractured such that the pieces of the balls return to the well surface and may be retrieved therefrom. 
     By use of the method as described, the operator, by cementing the sliding valves into the open hole and thereafter dissolving the cement, can frac just in the area adjacent to the sliding valve. By having a limited area of fracing, more pressure can be built up into the formation with less fracing fluid, thereby causing deeper fracing into the formation. Such deeper fracing will increase the production from the formation. Also, the fracing fluid is not wasted by distributing fracing fluid over a long area of the well, which results in less pressure forcing the fracing fluid deep into the formation. In fracing over long areas of the well, there is less desirable fracing than what would be the case with the present invention. 
     The present invention shows a method of fracing in the open hole through cemented in place sliding valves that can be selectively opened or closed depending upon where the production is to occur. Preliminary experiments have shown that the present system described hereinabove produces better fracing and better production at lower cost than prior methods. 
     The present invention is described above in terms of a preferred illustrative embodiment of a specifically described cemented open-hole selective fracing system and method, as well as an alternative embodiment of the present invention. Those skilled in the art will recognize that other alternative embodiments of such a system and method can be used in carrying out the present invention. Other aspects, features, and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims.
A method of producing petroleum from at least one open hole in at least one petroleum production zone of a hydrocarbon well comprising the steps of locating a plurality of sliding valves along at least one production tubing; inserting the plurality of sliding valves and the production tubing into the at least one open hole; cementing the plurality of sliding valves in the at least one open hole; opening at least one of the cemented sliding valves; removing at least some of the cement adjacent the opened sliding valves without using jetting tools or cutting tools to establish at least one communication path between the interior of the production tubing and the at least one petroleum production zone; directing a fracing material radially through the at least one sliding valve radially toward the at least one production zone; producing hydrocarbons from the at least one petroleum production zone through the plurality of the sliding valves the cement adjacent to which has been removed.