Blowout preventer protector and method of using same

TECHNICAL FIELD

[0001] The present invention relates to equipment for servicing oil and gas wells and, in particular, to an apparatus and method for protecting blowout preventers from exposure to high pressure and abrasive or corrosive fluids during well fracturing and stimulation procedures while providing direct access to production tubing in the well and permitting production tubing to be run in or out of the well.

BACKGROUND OF THE INVENTION

[0002] Most oil and gas wells eventually require some form of stimulation to enhance hydrocarbon flow to make or keep them economically viable. The servicing of oil and gas wells to stimulate production requires the pumping of fluids under high pressure. The fluids are generally corrosive and abrasive because they are frequently laden with corrosive acids and abrasive proppants such as sharp sand.

[0003] The components which make up the wellhead such as the valves, tubing hanger, casing hanger, casing head and the blowout preventer equipment are generally selected for the characteristics of the well and not capable of withstanding the fluid pressures required for well fracturing and stimulation procedures. Wellhead components are available that are able to withstand high pressures but it is not economical to equip every well with them.

[0004] There are many wellhead isolation tools used in the field that conduct corrosive and abrasive high pressure fluids and gases through the wellhead components to prevent damage thereto.

[0005] The wellhead isolation tools in the prior art generally insert a mandrel through the various valves and spools of the wellhead to isolate those components from the elevated pressures and the corrosive and abrasive fluids used in the well treatment to stimulate production. A top end of the mandrel is connected to one or more high pressure valves, through which the stimulation fluids are pumped. In some applications, a pack-off assembly is provided at a bottom end of the mandrel for achieving a fluid seal against an inside of the production tubing or casing so that the wellhead is completely isolated from the stimulation fluids. One such tool is described in Applicant's U.S. Pat. No. 4,867,243, which issued Sep. 19, 1989 and is entitled WELLHEAD ISOLATION TOOL AND SETTING TOOL AND METHOD OF USING SAME.

[0006] In an improved wellhead isolation tool configuration, the mandrel in an operative position, requires fixed-point pack-off in the well, as described in Applicant's U.S. Pat. No. 5,819,851, which issued Oct. 13, 1998 and is entitled BLOWOUT PREVENTER PROTECTOR FOR USE DURING HIGH-PRESSURE OIL/GAS WELL STIMULATION. A further improvement of that tool is described in Applicant's co-pending U.S. patent application Ser. No. 09/299,551 which was filed on Apr. 26, 1999 and is entitled HIGH PRESSURE FLUID SEAL FOR SEALING AGAINST A BIT GUIDE IN A WELLHEAD AND METHOD OF USING SAME. The mandrel described in this patent and patent application includes an annular sealing body attached to the bottom end of the mandrel for sealing against a bit guide which is mounted on the top of a casing in the wellhead.

[0007] This type of isolation tool advantageously provides full access to a well casing and permits use of downhole tools during a well stimulation treatment. A mechanical lockdown mechanism for securing a mandrel requiring fixed-point pack-off in the well is described in Applicant's U.S. patent application Ser. No. 09/338,752 which was filed on Jun. 23, 1999 and is entitled BLOWOUT PREVENTER PROTECTOR AND SETTING TOOL. The mechanical lockdown mechanism has an axial adjusting length adequate to compensate for variations in a distance between a top of the blowout preventer and the top of the casing of the different wellheads to permit the mandrel to be secured in the operative position even if a length of a mandrel is not precisely matched with a particular wellhead. The mechanical lockdown mechanism secures the mandrel against the bit guide to maintain a fluid seal but does not restrain the mandrel from downwards movement. The force exerted on the annular sealing body between the bottom end of the mandrel and the bit guide results from a combination of the weight of the isolation tool and attached valves and fittings, a force applied by the lockdown mechanism and an upward force exerted by fluid pressures acting on the mandrel.

[0008] The wellhead isolation tools described in the above patents and patent applications work well and are in significant demand. However, it is also desirable from a cost and safety standpoint, to be able to leave the tubing string, or as it is sometimes called the “kill string”, in the well during a well stimulation treatment. The above-described wellhead isolation tool is not adapted to support a tubing string left in the well because the weight of a long tubing string may damage the seal between the bottom of the mandrel and the bit guide.

[0009] Some prior art wellhead isolation tools are adapted for well stimulation treatment with a tubing string left in the well. For example, Canadian Patent No. 1,281,280 which is entitled ANNULAR AND CONCENTRIC FLOW WELLHEAD ISOLATION TOOL AND METHOD OF USE THEREOF, which issued to McLeod on Mar. 12, 1991, describes an apparatus for isolating the wellhead equipment from the high pressure fluids pumped down to the production formation during the procedures of fracturing and acidizing oil and gas wells. The apparatus utilizes a central mandrel inside an outer mandrel and an expandable sealing nipple to seal the outer mandrel against the casing. The bottom end of the central mandrel is connected to a top of the tubing string and a sealing nipple is provided with passageways to permit fluids to be pumped down the tubing and/or the annulus between the tubing and the casing in an oil or gas well. One disadvantage of this apparatus is that the fluid flow rate is restricted by the diameter of the outer mandrel which must be smaller than the diameter of the casing of the well and further restricted by the passageways in the sealing nipple between the central and outer mandrels. The sealing nipple also blocks the annulus, preventing tools from being run down the wellbore. The passageways in the sealing nipple are also susceptible to damage by the abrasive particle-laden fluids and are easily washed-out during a well stimulation treatment. A further disadvantage of the isolation tool is that the tool has to be removed and re-installed every time the tubing string is to be moved up or down in the well.

[0010] Applicant's co-pending U.S. patent application entitled BLOWOUT PREVENTER PROTECTOR AND METHOD OF USING SAME which was filed on Jan. 28, 2000 and has been assigned Ser. No. ______, describes an improved isolation tool which is adapted for use with a tubing string to be left in the well, or run into or out of the well during a well stimulation treatment. The blowout preventer protector seals against a bit guide of the well and provides full access to the casing of the well to permit downhole tools to be run in or out of the casing. However, there are certain types of wellheads which do not include a bit guide. Such wellheads are generally referred to as “Larkin-type” wellheads. In Larkin-type wellheads, the top of the casing is threaded and the wellhead is screwed to the top of the wellhead using a high-pressure sealing compound, or the like. Consequently, the blowout preventer protector described in Applicant's co-pending patent application filed Jan. 28, 2000 cannot be used to service such wells. In addition, as wells age and are stressed by extended use, the seal between the bit guide and the casing cannot always be relied on to withstand elevated fluid pressures.

[0011] There therefore exists a need for a blowout preventer protector that seals off in the casing of the well while providing access to tubing in the well or permitting tubing to be run into or out of the well.

SUMMARY OF THE INVENTION

[0012] It is an object of the invention to provide a BOP protector which is adapted to support a tubing string in a wellbore so that the tubing string is accessible during a well treatment to stimulate production.

[0013] It is a further object of the invention to provide a BOP protector that permits a tubing string to be moved up and down in the wellbore without removing the BOP protector from the wellhead.

[0014] It is another object of the present invention to provide a BOP protector that permits a tubing string to be run into or out of the wellbore without removing the BOP protector from the wellhead.

[0015] In accordance with one aspect of the invention, there is provided an apparatus for protecting a blowout preventer from exposure to fluid pressures, abrasives and corrosive fluids used in a well treatment to stimulate production. The apparatus is adapted to support a tubing string in a wellbore so that the tubing string is accessible during the well treatment. The apparatus includes a mandrel adapted to be inserted down through the blowout preventer to an operative position. The mandrel has a mandrel top end and a mandrel bottom end. The mandrel bottom end includes a sealing assembly for sealing engagement with a casing of the well when the mandrel is in the operative position. A base member is adapted for connection to the wellhead and includes fluid seals through which the mandrel is reciprocally moveable. The apparatus further comprises a fracturing head, a tubing adapter and a lock mechanism. The fracturing head includes a central passage in fluid communication with the mandrel and at least one radial passage in fluid communication with the central passage. The tubing adapter is mounted to a top end of the fracturing head and supports the tubing string while permitting fluid communication with the tubing string. The lock mechanism for locking the apparatus in the operative position to inhibit upward movement of the mandrel induced by fluid pressures in the wellbore.

[0016] The apparatus preferably includes a mandrel head affixed to the mandrel top end and the fracturing head is mounted to the mandrel head. The lock mechanism preferably includes a mechanical lockdown mechanism which is adapted to inhibit upward movement of the mandrel head induced by fluid pressures when the mandrel is in the operative position.

[0017] More especially, according to an embodiment of the invention, the base member has a central passage to permit the insertion and removal of the mandrel. The passage is surrounded by an integral sleeve having an elongated spiral thread for engaging a lockdown nut that is adapted to secure the mandrel in the operative position. A passage from the mandrel head top end to the mandrel head bottom end is provided for fluid communication with the mandrel and permits the tubing string to extend therethrough.

[0018] The tubing adapter is configured to meet the requirements of a job. It may be a flange for mounting a BOP to the top of the apparatus so that tubing can be run into or out of the well. Alternatively, the tubing adapter may include a threaded connector to permit the connection of a tubing string that is already in the well.

[0019] A blast joint may be connected to the tubing adapter if coil tubing is run into the well. The blast joint protects the coil tubing from erosion when abrasive fluids are pumped through the fracturing head.

[0020] In accordance with another aspect of the invention, a method is described for providing access to a tubing string while protecting a blowout preventer on a wellhead from exposure to fluid pressure as well as to abrasive and corrosive fluids during a well treatment to stimulate production. The method comprises:

[0021] a) suspending the apparatus above the wellhead;

[0022] b) aligning the apparatus with a tubing string supported on the wellhead and lowering the apparatus until a top end of the tubing string extends through the axial passage above the fracturing head;

[0023] c) connecting the top end of the tubing string to a top end of the fracturing head, lowering the tubing string and the apparatus until the apparatus rests on the wellhead, and mounting the base member to the wellhead;

[0024] d) opening the blowout preventer;

[0025] e) lowering the tubing string and the fracturing head to stroke the mandrel bottom end down through the wellhead into the casing of the well until the mandrel reaches an operative position in which the fracturing head rests on the base member and the seal assembly is in sealing contact with an inner wall of the casing; and

[0026] f) locking the fracturing head to the base member to inhibit the mandrel from upward movement induced by fluid pressure in the well.

[0027] In accordance with a further aspect of the invention, a method is described for running a tubing string into or out of a well while protecting a first blowout preventer on a wellhead of the well from exposure to fluid pressure as well as to abrasive and corrosive fluids during a well treatment to stimulate production. The method related to the use of the above-described apparatus comprises:

[0028] a) mounting the base member of the apparatus to the wellhead;

[0029] b) closing at least one second blowout preventer which is mounted to an adapter flange mounted to a top the fracturing head;

[0030] c) opening the first blowout preventer;

[0031] d) lowering the fracturing head to stroke the mandrel bottom end down through the wellhead into the casing until the mandrel is in an operative position in which the fracturing head rests against the base member and the annular sealing assembly is in fluid sealing engagement with an inner wall of the casing of the well;

[0032] e) locking the mandrel in the operative position to prevent the mandrel from upward movement induced by fluid pressure in the well; and

[0033] f) running the tubing string into or out of the well through the at least one second blowout preventer.

[0034] A primary advantage of the invention is the capability to support a tubing string in a wellbore during the well stimulation treatment. This provides direct access to both the tubing string and the well casing so that the use of the apparatus is extended to a wide range of well service applications.

[0035] Furthermore, the apparatus permits the tubing string to be moved up and down, or run in or out of the well without removing the apparatus from the wellhead. The tubing string can even be moved up or down in the well while well treatment fluids are being pumped into the well. Labour and the associated costs are thus reduced.

BRIEF DESCRIPTION OF THE DRAWINGS

[0036] The invention will now be further described by way of illustration only and with reference to the accompanying drawings, in which:

[0037]FIG. 1 is a cross-sectional view of a preferred embodiment of the BOP protector in accordance with the invention, showing the mandrel in an exploded view;

[0038]FIG. 2 is a cross-sectional view of the embodiment shown in FIG. 1 illustrating the BOP protector in a condition ready to be mounted to a wellhead;

[0039]FIG. 3 is a cross-sectional view of the BOP protector shown in FIG. 2 suspended over the wellhead prior to installation on the wellhead;

[0040]FIG. 4 is a cross-sectional view of the BOP protector shown in FIG. 3 illustrating a further step in the installation procedure, in which the tubing string is connected to a tubing adapter;

[0041]FIG. 5 is a cross-sectional view of the BOP protector shown in FIG. 4, in which the mandrel of the BOP protector is inserted through the wellhead and locked in an operative position;

[0042]FIG. 6 is a partial cross-sectional view of a BOP protector in accordance with the invention, showing a tubing adapter flange used for mounting a BOP to permit tubing to be run into or out of the well without removing the BOP protector from the wellhead; and

[0043]FIG. 7 is a cross-sectional view of a preferred embodiment of a sealing assembly for the BOP protector shown in FIGS. <b>1</b>-<b>6</b>.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

[0044]FIG. 1 shows a cross-sectional view of the apparatus for protecting the blowout preventers (hereinafter referred to as a BOP protector) in accordance with the invention, generally indicated by reference numeral <b>10</b>. The apparatus includes a lockdown mechanism <b>12</b> which includes a base member <b>14</b>, a mandrel head <b>16</b> and a lockdown nut <b>18</b> that detachably interconnects the base member <b>14</b> and the mandrel head <b>16</b>. The base member <b>14</b> includes a flange and an integral sleeve <b>20</b> that is perpendicular to the flange of the base member <b>14</b>. A spiral thread <b>22</b> is provided on an exterior of the integral sleeve <b>20</b>. The spiral thread <b>22</b> is engageable by a complimentary spiral thread <b>24</b> on an interior surface of the lockdown nut <b>18</b>. The flange of the base member <b>14</b> with the integral sleeve <b>20</b> form a passage <b>26</b> that permits a mandrel <b>28</b> to pass therethrough. The mandrel head <b>16</b> includes an annular flange, having a central passage <b>30</b> defined by an interior wall <b>32</b>. A top flange <b>34</b> is adapted for connection to a fracturing head <b>35</b>. A lower flange <b>36</b> retains a top flange <b>38</b> of the lockdown nut <b>18</b>. The lockdown nut <b>18</b> secures the mandrel head <b>16</b> from upward movement with respect to the base member <b>14</b> when the lockdown nut <b>18</b> engages the spiral thread <b>22</b> on the integral sleeve <b>20</b>.

[0045] The mandrel <b>28</b> has a mandrel top end <b>40</b> and a mandrel bottom end <b>42</b>. Complimentary spiral threads <b>43</b> are provided on the exterior of the mandrel top end <b>40</b> and on a lower end of the interior wall <b>32</b> of the mandrel head <b>16</b> so that the mandrel top end <b>40</b> may be securely attached to the mandrel head <b>16</b>. One or more O-rings (not shown) provide a fluid-tight seal between the mandrel head <b>34</b> and the mandrel <b>28</b>. The passage <b>26</b> through the base member <b>14</b> has a recessed region at the lower end for receiving a steel spacer <b>44</b> and packing rings <b>46</b> preferably constructed of brass, rubber and fabric. The steel spacer <b>44</b> and packing rings <b>46</b> define a passage of the same diameter as the periphery of the mandrel <b>28</b>. The packing rings <b>46</b> are removable and may be interchanged to accommodate different sizes of mandrel <b>28</b>. The steel spacer <b>44</b> and packing rings <b>46</b> are retained in the passage <b>26</b> by a retainer nut <b>48</b>. The combination of the steel spacer <b>44</b>, packing rings <b>46</b> and the retainer nut, provide a fluid seal to prevent passage to the atmosphere of well fluids from an exterior of the mandrel <b>28</b> and the interior of the BOP when the mandrel <b>28</b> is inserted into the BOP, as will be described below with reference to FIGS. <b>3</b>-<b>5</b>.

[0046] An internal threaded connector <b>50</b> on the mandrel bottom end <b>42</b> is adapted for the connection of mandrel extension sections of the same diameter. The extension sections permit the mandrel <b>28</b> to be lengthened, as required by different wellhead configurations. An optional mandrel extension <b>52</b>, has a threaded connector <b>54</b> at a top end <b>56</b> adapted to be threadedly connected to the mandrel bottom end <b>42</b>. An extension bottom end <b>58</b>, includes a threaded connector <b>60</b> that is used to connect a sealing assembly <b>62</b>, which will be described below with reference to FIG. 7. High pressure O-ring seals <b>64</b>, well known in the art, provide a high pressure fluid seal in the threaded connectors between the mandrel <b>28</b>, the optional mandrel extension(s) <b>52</b> and the sealing assembly <b>62</b>.

[0047] The mandrel <b>28</b>, the mandrel extension <b>52</b> and the sealing assembly <b>62</b> are preferably each made from 4140 steel, a high-strength steel that is commercially available. 4140 steel has a high tensile strength and a Burnell hardness of about 300. Consequently, the assembled mandrel <b>28</b> is adequately robust to contain extremely high fluid pressures of up to 15,000 psi, which approaches the burst pressure of the well casing.

[0048] The fracturing head <b>35</b> includes a sidewall <b>74</b> surrounding a central passage <b>76</b> that has a diameter not smaller than the internal diameter of the mandrel <b>28</b>. A bottom flange <b>78</b> is provided for connection in a fluid tight seal to the mandrel head <b>16</b>. Two or more radial passages <b>80</b>, <b>82</b> with threaded connectors <b>84</b>, <b>86</b> are provided to permit well stimulation fluids to be pumped through the wellhead.

[0049] The radial passages <b>80</b>, <b>82</b> are preferably oriented at an acute upward angle with respect to the sidewall <b>74</b>. At the top end <b>88</b> of the sidewall <b>74</b>, a threaded connector <b>90</b> removably engages a threaded connector <b>92</b> of one embodiment of a tubing adaptor <b>94</b>, in accordance with the invention. The tubing adapter <b>94</b> includes a flange <b>96</b>, the threaded connector <b>92</b> and a sleeve <b>98</b>. The tubing adapter <b>94</b> also includes a central passage <b>100</b> with the threads <b>102</b> for detachably connecting a tubing joint of a tubing string. A spiral thread <b>104</b> is provided on the exterior of the sleeve <b>98</b> and adapted for connecting other equipment, for example, a high pressure valve <b>36</b> (FIG. 4).

[0050] The mandrel head <b>16</b> with its upper and lower flanges <b>34</b>, <b>36</b>, and the lockdown nut <b>18</b> with its top flange <b>38</b> are illustrated in FIG. 1 respectively as an integral unit assembled, for example, by welding or the like. However, persons skilled in the art will understand that any one of the mandrel head <b>16</b> or the lockdown nut <b>18</b> may be constructed to permit the mandrel head <b>16</b> or the lockdown nut <b>18</b> to be independently replaced.

[0051]FIG. 2 illustrates the BOP protector <b>10</b> shown in FIG. 1, prior to being mounted to a BOP for a well stimulation treatment. The mandrel head <b>16</b> is connected to the top end of the mandrel <b>28</b>, which includes any required extension section(s) <b>52</b> and the pack-off assembly <b>62</b> to provide a total length of the mandrel <b>16</b> required for a particular wellhead.

[0052]FIGS. 3 through 5 illustrate the installation procedure of the BOP protector <b>10</b> to a wellhead <b>120</b> with a tubing string <b>122</b> supported, for example, by slips <b>124</b> or some other supporting device, at the top of the wellhead <b>120</b>. Several components may be included in a wellhead. For purposes of illustration, the wellhead <b>120</b> is simplified and includes only a BOP <b>126</b> and a tubing head spool <b>128</b>. The BOP <b>126</b> is a piece of wellhead equipment that is well known in the art and its construction and function do not form a part of this invention. The BOP <b>126</b>, the tubing head spool <b>128</b> and the slips <b>124</b> are, therefore, not described. The tubing string <b>122</b> is usually supported by a tubing hanger, not shown, in the tubing head spool <b>128</b>. The tubing string <b>122</b> is therefore pulled out of the well to an extent that a length of the tubing string <b>122</b> extending above the wellhead <b>120</b> is greater than a length of the BOP protector <b>10</b>. The tubing string <b>122</b> is then supported at the top of the BOP <b>126</b> using slips, for example, before the installation procedure begins. Two high pressure valves <b>130</b> and <b>132</b> are mounted to the threaded connectors <b>84</b>, <b>86</b>, preferably before the BOP protector <b>10</b> is installed.

[0053] As illustrated in FIG. 3, the BOP protector <b>10</b> is suspended over the wellhead <b>122</b> by a crane or other lift equipment (not shown). The BOP protector <b>10</b> is aligned with the tubing string <b>122</b> and lowered over the tubing until the top end <b>134</b> of the tubing string <b>122</b> extends above the top end <b>88</b> of the sidewall <b>74</b>.

[0054]FIG. 4 illustrates the next step of the installation procedure. A tubing adapter <b>94</b> is first connected to the top end <b>134</b> of the tubing string <b>122</b>. The tubing adapter <b>134</b> is then connected to the top of the fracturing head. A high pressure valve <b>136</b> is mounted to the tubing adapter <b>94</b> via the thread <b>104</b> on the sleeve <b>98</b>. The tubing string <b>122</b> and the BOP protector <b>10</b> are then lifted using a rig, for example, so that the slips <b>124</b> can be removed. The rig lowers the tubing string <b>122</b> and the BOP protector <b>10</b> onto the top of the BOP so that the base member <b>14</b> rests on the BOP <b>126</b>. The mandrel <b>28</b> is inserted from the top into to the BOP <b>126</b> but remains above the BOP rams (not shown). Persons skilled in the art will understand that in a high pressure wellbore, the tubing string <b>122</b> is plugged and the rams of the BOP are closed around the tubing string <b>122</b> before the installation procedure begins, so that the fluids under pressure in the wellbore are not permitted to escape from the tubing string or the annulus between the tubing string and the wellhead <b>120</b>.

[0055] To open the rams of the BOP <b>126</b> and further insert the mandrel <b>28</b> down through the wellhead, the high pressure valves <b>130</b>, <b>132</b> and <b>136</b> must be closed and the base member <b>14</b> mounted to the top of the BOP <b>126</b>. The packing rings <b>46</b> and all other seals between interfaces of the connected parts, seal the central passage of the BOP protector <b>10</b> against pressure leaks. The BOP rams are now opened after the pressure is balanced across the BOP rams. This procedure is well known in the art and is not described. After the BOP rams are opened, the rig further lowers the BOP protector <b>10</b> to move the mandrel bottom end down through the BOP. The BOP protector <b>10</b> is in an operative position where the sealing assembly <b>62</b> is inserted into the casing <b>142</b>. As noted above, the extension section(s) is optional and of variable length so that the assembled mandrel <b>28</b>, including the sealing assembly <b>62</b>, has adequate length to ensure that the sealing assembly <b>62</b> is inserted into the casing <b>142</b>. The lockdown nut <b>18</b> shown in FIG. 5, secures the mandrel <b>28</b> in the operative position against an upward fluid pressure.

[0056] The BOP protector <b>10</b>, in accordance with the above-described embodiments of the invention, has extensive applications in well treatments to stimulate production. After the BOP protector <b>10</b> is installed to the wellhead as illustrated in FIG. 5, a pressure test is usually done by opening the tubing head spool side valve to ensure that the BOP and the wellhead are properly sealed. The high pressure lines (not shown) can be hooked up to high pressure valves <b>130</b>, <b>132</b> and <b>136</b> to begin a wellhead stimulation treatment. A high pressure well stimulation fluids can be pumped down through any one or more of the three valves into the well. The tubing string can also be used to pump a different fluid or gas down into the well while other materials are pumped down the casing annulus so that the fluids only commingle downhole at the perforations area and are only mixed in the well.

[0057] In the event of a “screen-out”, the high pressure valve <b>136</b> which controls the tubing string, may be opened and hooked to the pit (not shown). This permits the tubing string <b>122</b> to be used as a well evacuation string, so that the fluids can be pumped down the annulus of the casing and up the tubing string to clean and circulate proppants out of the wellbore. In other applications for well stimulation treatment, the tubing string <b>122</b> can be used as a dead string to measure downhole pressure during a well fracturing process.

[0058] The tubing also can be used to spot acid in the well. To prepare for a spot acid treatment, a lower limit of the area to be acidized is blocked off with a plug set in the well below a lower end of the tubing string, if required. A predetermined quantity of acid is then pumped down the tubing string to treat a portion of the wellbore above the plug. The area to be acidized may be further confined by a second plug set in the well above the first plug. Acid may then be pumped under pressure through the tubing string into the area between the two plugs.

[0059] As will be understood by those skilled in the art, coil tubing can be used for any of the stimulation treatments described above. If coil tubing is used, it is preferably run through a blast joint so that the coil tubing is protected from abrasive proppants.

[0060]FIG. 6 illustrates a configuration of the BOP protector <b>10</b> in accordance with the invention that is adapted to permit tubing to be run into or out of the well. Coil tubing, which is well known in the art, is particularly well adapted for this purpose. Coil tubing is a jointless, flexible tubing available in variable lengths. If tubing is to be run into or out of the well, pressure containment is required. Accordingly, the tubing adapter <b>394</b>, in this embodiment, is different from the tubing adapter <b>94</b> shown in FIGS. <b>1</b>-<b>5</b>. The tubing adapter <b>394</b> has a flange <b>396</b> with a threaded connector <b>392</b> for engaging the thread <b>90</b> on the top of the fracturing head <b>35</b>. The flange <b>396</b> is adapted to permit a second BOP <b>326</b> to be mounted to a top of the fracturing head <b>35</b>. A blast joint <b>300</b>, having a threaded top end <b>301</b> engages a thread <b>302</b> so that the blast joint <b>300</b> is suspended from the tubing adapter <b>394</b>. The blast joint has a inner diameter large enough to permit the coil tubing <b>322</b> to be run up and down therethrough. The blast joint <b>300</b> protects the coil tubing <b>322</b> from erosion when abrasive fluids are pumped through the radial passages <b>80</b>, <b>82</b> in the fracturing head <b>35</b>. The coil tubing <b>322</b> is supported, for example, by slips <b>324</b> or other supporting mechanisms to the top of the BOP <b>326</b>. As is understood by those skilled in the art, a “stripper” for removing hydrocarbons from coil tubing pulled out of the well may also be associated with the second BOP <b>326</b>.

[0061] If tubing is to be run in and out of the well during a stimulation treatment, a third BOP, not shown, may be required, as is also well known in the art. As is well understood, the BOPs are operated in sequence whenever the tubing is pulled from or inserted into the well.

[0062] The method of installing the BOP protector <b>10</b> shown in FIG. 6, to permit tubing to be run into or out of a well while protecting the BOP <b>126</b> on the wellhead during a well stimulation treatment is described below. The base member <b>14</b> is first mounted to the top of the BOP <b>126</b> while the bottom end of the mandrel is inserted from the top into the BOP <b>126</b>. The BOP <b>326</b> is closed and the BOP <b>126</b> is opened after the pressure across the BOP <b>126</b> is equalized. The fracturing head <b>35</b> and attached BOP <b>326</b> are lowered to stroke the mandrel bottom end down through the BOP <b>126</b>. The lockdown nut <b>18</b> is screwed down when the mandrel <b>28</b> is in the operative position and the sealing mechanism <b>62</b> is sealed inside the casing <b>142</b>.

[0063] The apparatus in accordance with the invention does not significantly restrict fluid flow along the annulus of the casing or include components susceptible to wash-out. More advantageously, the apparatus in accordance with the invention enables an operator to move the tubing string up and down or run tubing into and out of a well without removing the apparatus from the wellhead. A tubing string can also be moved up or down in the well while stimulation fluids are being pumped into the well, as will be understood by those skilled in the art. The apparatus is especially well adapted for use with coil tubing which provides a safer operation in which there are no joints, no leaking connections and no snubbing unit needed if it is run in under pressure. Running coil tubing is also a faster operation that can be used easier and less expensively in remote areas, such as off-shore.

[0064]FIG. 7 schematically illustrates a sealing assembly <b>62</b> in accordance with a preferred embodiment of the invention inserted into the casing <b>142</b> of a hydrocarbon well. The sealing assembly <b>62</b> includes a cup tool <b>402</b> which threadedly connects to the bottom end of the mandrel <b>28</b> or a mandrel extension <b>52</b> (FIG. 1). The cup tool <b>402</b> has a top end <b>404</b> with a diameter equal to a diameter of the mandrel <b>28</b> and a bottom end <b>406</b> of a smaller outer diameter. Located between the top end <b>404</b> and the bottom end <b>406</b> is a radial shoulder <b>408</b>. A cup <b>410</b> includes a resilient depending skirt <b>412</b>, which is typically formed with a rubber compound well known in the art. The skirt <b>412</b> is bonded to a steel ring <b>414</b> that is axially slidable over the bottom end <b>406</b> of the cup tool <b>402</b>. A pair of O-rings <b>416</b> provide a fluid seal between the steel ring <b>414</b> and the bottom end <b>406</b> of the cup tool <b>402</b>. Located above the cup <b>410</b> is a resilient compressible sealing element <b>420</b> and a gauge ring <b>422</b>. The cup <b>410</b>, sealing element <b>420</b> and gauge ring <b>422</b> are retained on the bottom end <b>406</b> of the cup tool <b>402</b> by a bullnose <b>424</b> which threadedly engages threads <b>426</b> on the bottom end <b>406</b> of the cup tool <b>402</b>. The bullnose <b>426</b> guides the sealing assembly through the wellhead and helps protect the resilient skirt <b>412</b> of the cup <b>410</b> from damage when the tool is inserted through the wellhead into the casing.

[0065] When the sealing assembly <b>62</b> is inserted into the casing <b>142</b> of a wellbore and exposed to fluid pressures in the wellbore, the resilient skirt <b>412</b> of the cup <b>410</b> is forced outwardly against the casing <b>142</b> and the cup is forced upwardly against the resilient sealing element <b>420</b>. The resilient sealing element is compressed against the gauge ring <b>422</b> and deforms radially against the cup tool <b>402</b> and the casing <b>142</b> to provide a high pressure fluid seal in the annulus between the sealing assembly <b>62</b> and the casing <b>142</b>.

[0066] Modifications and improvements to the above-described embodiments of the invention, may become apparent to those skilled in the art. For example, although the mandrel head and the fracturing head are shown and described as separate units, they may be constructed as an integral unit. Many other modifications may also be made.

[0067] The foregoing description is intended to exemplary rather than limiting. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.