Abstract:
A core drill assembly with replaceable fluid nozzles permitting effective total flow area adjustment (TFA), substantial optimization of hydraulic force at the cutting face to improve rate of penetration (ROP) and core quality. At least one seal assembly to restrict drilling fluid flow while permitting mutual rotation between the core head ID and the lower shoe is disposed in an annulus defined therebetween.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims the benefit of U.S. Provisional Patent Application Ser. No. 60/800,620, filed May 15, 2006, the entire disclosure of which is incorporated herein by reference. 
     
     FIELD OF THE INVENTION 
       [0002]    Embodiments of the present invention are related to a core drill assembly with adjustable drill fluid total flow area and, more particularly, to a core drill assembly which includes replaceable cutting fluid nozzles and a seal assembly disposed between adjacent portions of the outer barrel assembly and the inner barrel assembly, as well as to methods of coring. 
       BACKGROUND 
       [0003]    Current core head designs use a fixed total flow area (TFA) to circulate drilling fluid through the core head, also known as a core bit, during down-hole coring operations. The TFA is a calculated discharge area for the drilling fluid which may include an annulus ID gauge fluid course between the core head ID and the exterior of the lower shoe, carried by the inner barrel assembly, or core head face discharge ports, or a combination of the two. Drilling fluid is circulated through the ID fluid courses and the face discharge ports to cool and clean cutting structure carried on the face of the core head, and to remove cuttings generated when the cutting head penetrates the formation being cored. The hydraulic force, or the ability of the drilling fluid to removing material cuttings from the cutting head face, is measured in hydraulic horsepower/in 2  (HSI) and is an indicator of drilling fluid cleaning efficiency. If the hydraulic force is too low, there will be poor cleaning of the cutting structure and cuttings will interfere with the rate of penetration (ROP) in forming the bore hole. If the hydraulic force is too high, there may be erosion of the bole hole, which can result in a stuck drill string, and the drilling fluid may contaminate the core sample. By using HSI and ROP measurements, the optimum amount of hydraulic force can be designed into a core drill assembly. 
         [0004]      FIG. 1  is a cross-section of a conventional core drill assembly  10 , with a non-adjustable TFA or drilling fluid flow area defined by the areas of the annulus  50  and the discharge ports  30 . The annulus  50  is the gap between the ID of core head  14  and the outside of the lower shoe  18 . With this arrangement, drilling fluid is pumped down the drill string, to core drill assembly  10 , where a portion of the drilling fluid will travel through the annulus  50  and exit the core drill assembly  10  proximate the leading edge of the lower shoe  18 , while the remaining drilling fluid enters the fluid course  20  within core head  14 , and exits the discharge ports  30  located on the face  16  of core head  14 , as respectively shown by the arrows in  FIG. 1l  The drilling fluid is used to cool the cutters  60  and flush cuttings away from the face  16  of core head  14 . However, since the TFA is non-adjustable, the operator cannot optimize the amount of drilling fluid at the drill face  16  of core head  14  and the HSI. 
         [0005]    With the non-adjustable TFA of current core head designs, the only variable is the circulation rate of the drilling fluid, and therefore, the HSI cannot be optimized. Also, in current core heads there is always some drilling fluid flow through the annular space between the core head ID and the lower shoe. In core heads using ID fluid courses only, all of the flow travels through the annulus whereas, when core head face discharge ports are used in combination with the annulus, it is difficult to determine amount of drilling fluid “split” between the discharge ports and the annulus. The difficulty arises because the actual annulus gap spacing between the core head ID and the lower shoe is not known when the core head is down hole. The annulus gap is nominally ⅜ inch to ½ inch ; however, when using an aluminum or fiberglass inner tube, in the inner barrel assembly, gaps up to 5½ inches may be required in order to compensate for the different rates of thermal expansion attributed to the materials of the inner tube and the core head. Under bottom-hole temperature, the gap may decrease to the estimated desirable gap of ⅜ inch to ½ inch, but uncertainty about the actual and estimated bottom-hole temperature, can result in a significant error in spacing adjustment. As the area of the annulus gap is added directly into the TFA calculation, the uncertainty of the gap size makes accurately calculating TFA difficult. The split of flow between the annulus between the OD of the inner tube shoe and the ID of the core head, and the face discharge ports is dependent upon their relative TFA. Depending upon actual spacing down hole, the annular TFA could be higher than the TFA of the face discharge ports, with the result that most of the flow of drilling fluid will pass through the ID annulus. This significantly reduces the effectiveness of the face discharge ports, and reduces further the HSI delivered to the cutting structure of the core head. Adjusting the TFA of the face discharge ports in this case would not increase HSI, since the bypass flow would simply be increased through the ID annulus. To increase HSI, the bypass flow through the ID annulus must be sealed off, or severely restricted, to divert as much of the flow as possible to the face discharge ports, or nozzles. 
         [0006]    For a conventional drill bit with replaceable nozzles, the TFA can be optimized by utilizing different diameter nozzles in the discharge ports. However, in a conventional core drill assembly, since at least some of the drilling fluid flow travels through the annulus, a change of discharge port size will change the resistance at the nozzles and will proportionally change the amount of drilling fluid bypassing through the annulus. This problem is highlighted when looking at the performance of the drill bit versus a core drill. A drill bit will normally operate in the range of 4-8 HSI, whereas an 8½ inch by 4 inch core drill may operate as low as 0.2 HSI. 
         [0007]    In view of the shortcomings in the art, it would be advantageous to provide a core drill with adjustable TFA, by fitting the core head with replaceable nozzles and sealing off the annulus between the core head ID and the lower shoe. This will allow an operator to apply the same drilling optimization concepts to coring as used with conventional drilling, and allow the HSI to be improved over conventional core head designs, with corresponding improvements in coring performance, ROP and core quality. 
       BRIEF SUMMARY OF THE INVENTION 
       [0008]    Embodiments of the invention include replaceable nozzles fitted in at least some of the drilling fluid outlet ports, proximate the face of the core head. The nozzle design will compensate for the smaller surface area of the typical core drill face and new nozzle locations and jet directions are contemplated to take advantage of the improved HSI at the cutting face, including directing nozzles towards interior cutters of the core head in order to clear cuttings and provide cooling. 
         [0009]    In one embodiment of the present invention, the annulus between the cutting head and the lower shoe is substantially sealed with a seal structure, which may be broadly characterized as a seal assembly or a seal element, without substantial rotational interference between the core head and the lower shoe, which would cause the lower shoe and inner tube to turn with the outer barrel assembly and core head. 
         [0010]    One embodiment includes one or more grooves formed into the ID of the core head to accommodate an annular seal similar to an O-ring in each of the grooves. The design of the O-ring or other annular seal allows some drilling fluid flow to bypass under reduced pressure, but under normal operating circumstances the O-ring or other annular seal seals substantially completely. 
         [0011]    In a second embodiment of the present invention, the annulus between the core head and the lower shoe is substantially sealed using split rings made from a material such as nylon or Teflon®. This embodiment includes one or more grooves formed in the ID of the core head where split rings of the appropriate size are installed to seal the annulus. The seals will fit somewhat loosely in the grooves and may rotate during coring operations, but will provide a sufficient seal to enable effective TFA adjustments by installing different sizes of drilling fluid nozzles. The loose fit will reduce friction between the core head ID and the lower shoe, to eliminate any tendency for the lower shoe and inner tube to rotate. 
         [0012]    Other embodiments of the present invention employ one or more of a wiper seal, a chevron seal, a packer cup or a restrictor sleeve disposed between the core head and the lower shoe to substantially restrict fluid flow therebetween while permitting rotational movement of the core head about the lower shoe. 
         [0013]    Embodiments of the present invention also include methods of using a core drill assembly. 
     
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
         [0014]    The foregoing and other advantages of the invention will become apparent upon reading the following detailed description and upon reference to the drawings in which: 
           [0015]      FIG. 1  is a cross-section of a conventional core drill assembly with an non-adjustable TFA defined by the area of the annulus between the core head and the lower shoe, and the area of the drilling fluid ports. 
           [0016]      FIG. 2  is a cross-section of a core drill assembly with a seal structure between the core head and the lower shoe and replaceable nozzles; 
           [0017]      FIG. 3  is a partial cross-section of a core drill assembly including an O-ring or wiper seal type seal assembly; 
           [0018]      FIG. 4  is a partial cross-section of a core drill assembly including a split-ring type seal assembly; 
           [0019]      FIG. 5  is a partial cross-section of a core drill assembly including a labyrinth seal assembly; and 
           [0020]      FIG. 6  is a partial cross-section of a core drill assembly including a restrictor sleeve. 
       
    
    
     DETAILED DESCRIPTION 
       [0021]      FIG. 2  schematically depicts a core drill assembly  10  of the present invention including replaceable nozzles  36  at the discharge ends of fluid courses  20 , and at least one seal assembly  40  disposed between the core head  14  and the lower shoe  18 . These features allow the operator to change the TFA of the core drill assembly  10  and optimize the HSI. The operator can select replaceable nozzles  36  having a discharge opening  34  of an appropriate diameter to adjust TFA. Thus, if a volume of drilling fluid is pumped under pressure, at a substantially constant flow rate, down the drill string, seal assembly  40  will divert substantially all of the drilling fluid volume away from the annulus  50  and into the fluid courses  20  where the drilling fluid will exit through discharge opening  34  of replaceable nozzles  36 . The diameters of discharge openings  34  will affect both the rate of discharge and the velocity of the escaping drilling fluid. Under optimized conditions, as provided by the present invention, the drilling fluid, emanating from the discharge openings  34 , will effectively clear cuttings away from the face  16  and of core head  14  and properly cool cutters  60 . The optimum diameter of discharge openings  34  for a specific material or formation, and core head or core size, can be determined or predicted by the use of historical data, including ROP measurements. As shown at the left-hand side of  FIG. 2 , the seal assembly  40  may be partially received in a groove in ID of the core head  14  or, as shown at the right-hand side of  FIG. 2 , the seal assembly  40  may be partially received in a groove in the exterior of the lower shoe  18 . As core head  14  rotates about lower shoe  18  during a coring operation, fluid flow therebetween will be substantially restricted by seal assembly  40 , as indicated by the smaller size of the arrows below annulus  50  in comparison to those in fluid courses  20 . 
         [0022]      FIGS. 3 and 4 , are partial cross-section views of core drill assembly  10  provided, to show additional detail of several embodiments of the at least one seal assembly  40 . The at least one seal assembly  40  is positioned in the annulus  50 , or the gap defined between the ID of core head  14  and the outside of the lower shoe  18 . The seals  42  and  44  are installed in grooves  46  formed in the ID of core head  14 . The seals  44  shown in  FIG. 3  may comprise an O-ring or other continuous ring type that may have a round or oval cross-section, or may include lips which function as “wipers,” as shown. The material of seals  44  may include, but is not limited to, rubber, neoprene, or polyethylene or a combination thereof. The seals  42  shown in  FIG. 4  are of a split-ring design which rides loosely in the grooves  46 . Examples of suitable materials for the split-ring seals  42  are nylon and Teflon® polymers. The at least one seal assembly  40  will substantially restrict the flow of the drilling fluid pumped down the drill string, forcing the drilling fluid to bypass the annulus  50  and into the fluid courses  20 , traveling in the direction of flow arrows  26 . 
         [0023]      FIG. 5  is a partial cross-section view of a core drill assembly  10  including a labyrinth seal  48  having a plurality of radially projecting, axially spaced annular elements separated by labyrinth slots  56 . The labyrinth seal  48  is formed into the structure of one of the core head  14  ID or the exterior surface of the lower shoe  18 . However, a labyrinth seal  48  with mating, interdigitated elements or components as shown in broken lines at E can be formed with the cooperating parts disposed on both the core head  14  ID and the lower shoe  18 . The total number of labyrinth slots  56  is not specified, and will vary depending on the expected pressure differential between the pumped drilling fluid and drill work face. The labyrinth seal  48  must have sufficient length and number of labyrinth slots  56  to effectively seal annulus  50 . With annulus  50  sealed, the drilling fluid will enter fluid courses  20 , flowing in the direction indicated by flow arrows  26 . 
         [0024]    It is also contemplated that the seals may be carried on the exterior of the lower shoe  18  instead of on core head  14 , or may be carried on both components. It is also contemplated that a seal comprising an upwardly facing packer cup with a frustoconical elastomeric skirt may be utilized in addition to, or in lieu of, other seal configurations. Chevron-type seals, as well as metallic or elastomeric seal back-up components, may also be employed. 
         [0025]      FIG. 6  depicts yet another embodiment of the present invention, wherein a seal element in the form of restrictor sleeve  64  is disposed on an annular shoulder  62  machined or otherwise formed on the ID of the core head  14 , and retained therein through the use of an appropriate bonding agent, such as BAKERLOK® compound, available from various operating units of Baker Hughes Incorporated, assignee of the present invention. As with the previous embodiments, discharge openings  34  of replaceable nozzles  36  may be selected for optimum TFA. A conventional lower shoe  18  is run inside of core head  14 , and extends longitudinally therethrough. The outer surface (shown in broken lines for clarity) of lower shoe  18  is in close proximity to the ID of restrictor sleeve  64 , so that a very small clearance radial clearance C, for example about 1 mm, is achieved This small, annular clearance C between lower shoe  18  and restrictor sleeve  64 , while permitting rotation of lower shoe  18  and restrictor sleeve  64  about lower shoe  18 , will substantially restrict the flow of the drilling fluid pumped down the drill string, forcing the drilling fluid to bypass the annulus  50  and into the fluid courses  20  to exit through discharge openings  34  of replaceable nozzles  36 . 
         [0026]    While the present invention has been depicted and described with reference to certain embodiments, the invention is not so limited. Additions and modifications to, and deletions from, the described embodiments will be readily apparent to those of ordinary skill in the art. The present invention is, thus, limited only by the claims which follow, and equivalents thereof.