Under-Balanced Drilling

Patented

Under-Balanced Drilling Solutions

Piston Concentric SpaceMaker units are designed for easy rig-up on all Under-Balanced Drilling operations. Rig Assist #3, with a 20' built in 7" lubricator our units provide a the tools necessary for lubricating longer bottom hole assemblies in and out of the well with increased safety, efficiency and cost effectiveness. Our newest snubbing unit RA#3 has been designed specifically with UBD in mind. Four sets of slips will grip on any nominal or non-conforming pipe or tool diameter from 2" - 7" without changing dyes. This feature in combination with the 6m of lubricating space built into the concentric unit will set new standards in UBD snubbing operations.

Piston Well Services has also designed a new UBD reciprocating drilling head around our Patented Concentric Technology.

Our thinking is as follows;

Objectives:

· Reduce rig and N2 drilling services operational time through a reduction of the number of RS element changes throughout the operation.

· Reduce rig and N2 drilling services operational time through safer, faster and more efficient element changes.

· Utilize a modified concentric snubbing unit as a fully guided Hydraulic Pull-Down Unit to compensate for lateral drag in the well bore and achieve better penetration rates at the drill bit.

It was brought to our attention that multiple RS stripping elements per well, are being worn out through the course of normal UBD operations. The primary reason for the excessive wear on the elements is attributed to the hard banding on the heavy-weight drill pipe. Apparently, the hard banding sections being rotated through the element wears excessively on the rubber and subsequently elements are being worn out prematurely. The time to change out an element is approximately 30 minutes or more based on the information we have been provided.

Proposed Solutions:

· Replace the current equipment being used today with Piston's Concentric RS UBD System to eliminate the hard banding being adjacent to the element while rotating.
When a section of hard banding on the drill pipe approaches the element while drilling down, reposition the RS stripping element upward and over top of the section through extension of the concentric spool. While drilling ahead, the concentric stripping/snubbing unit remains in a stationary position until the hard banding section has been drilled down allowing the unit to then be retracted. The unit is then retracted to a collapsed position ready for the next section of hard banding. Upon the next section of banding approaching the element, the snubbing unit is again stroked up and over that section, eliminating any rotating time with the banding adjacent to the RS pack off element. The procedure is repeated as needed throughout the drilling operation. Hard banding is subsequently never adjacent to the stripping element while rotating, substantially reducing wear and ultimately reducing the number of elements being consumed on each well. With this equipment configuration and procedure we feel we can substantially reduce the number of element changes on a per well basis. We have also done some preliminary testing with a new urethane composition element at low pressures with very good results. The different material may potentially outlast a conventional rubber element in this application by as much as 2:1. It will however require further real world testing to be proven, but has huge potential to further reduce rig time and element usage beyond that of what the concentric positioning method proposed above should provide.

With the employment of Piston's patented concentric system, element changes can now be performed above the rig floor rather than under the sub-structure.

· The Concentric System employs a patented telescopic spool that effectively maintains well pressure with an annular preventer or in this case RS stripping head attached on top. In result, the attached BOP is fully positional as described above. In a typical drilling configuration, the space between the bottom of the sub-structure and the rig's BOP stack is minimal upon the installation of a conventional RS stripping head currently being employed. This space has been identified as being as small as 17" on various rigs. We feel that with the proper configuration and spacing of the unit during rig up will result in the upper portion of the stripping head being able to be exposed above the rig floor though extension of the concentric spool. This will allow faster and safer element changes to take place from the rig floor.

· One consideration is that with the minimal inside dimension of the rotary table restricts having a permanently mounted inverted snubbing slip mounted above the RS stripping head because it will not pass through opening. Most small rotary tables apparently have a 17" inside dimension with the bushings removed and a standard snubbing slip has an 18.5" outside dimension. Under normal (marginal applications) UBD operations the pipe is heavy and there is no immediate need to have snubbing slip in place. When and if snubbing becomes inevitable, the top of concentric unit will be positioned through the rig floor (much the same as would be to change an element) prior to becoming pipe light. An adapter plate and snubbing slips would then be installed to the top of the RS body. With the bushings out of the table, the rig slips would be immobilized and a conventional spider and slip would be installed on top of the snubbing slip now situated just above the rig floor. This would handle the heavy pipe throughout the transition to pipe light. Upon becoming pipe light, the snubbing slips are then closed and a cable snubbing system would then be rigged up to complete the operation. To snub the pipe into the well, the equipment would be rigged in as described. Upon the snubbing operation being completed (pipe heavy) the adapter plate and slips would then be removed and drilling operations could then begin.

· The concentric stripping unit will employ a very simple but effective control mechanism for positioning the RS element. Hydraulic screws (power nuts) require very little fluid volume and have inherent load holding capabilities. The system can be easily powered by tying into the rig's hydraulic system with a simple up / down control valve positioned at the driller's console. A separate independent power pack could be available upon request. Upon hard banding approaching the pack-off rubber, the rig operator will stroke the concentric unit up or down as necessary all while drilling ahead. Element changes will become less frequent, very safe, simple and the lost rig time will be reduced substantially. We expect to reduce this time by as much as 1/3 or more plus reduce the actual number of changes currently being performed by at least the same margin.

Future Considerations:

· It is our intent with this design to eliminate the old fashion cable-snubbing operations that are presently the norm when working on marginal wells with conventional RS Stripping Heads. The premise is to employ the concentric unit with slips mounted on top, travelling up and down through the rig floor in combination with a simple "Straddle-Sub" (see diagram below) resting on the rig floor and anchored to a stationary portion the concentric snubbing unit. This small structure would support an upper set of stationary snubbing slips with the travelling set below. The rig up time when required to snub would be reduced to only a few minutes. Until a alternate slip design with an outside dimension of less then 17" can be designed and tested we are proposing to employ a cable system as is currently being used when snubbing operations become necessary. Improved configurations will be implemented on the next generation units. If the rotary table could be removed (as it not warranted for top-drive drilling) from the substructure, the Straddle-Sub system could then be easily implemented and eliminate the cable snubbing method. The substructure will still support any loads from the drill string and when snubbing is necessary it would take about 10 minutes to be rigged up ready to snub.
It is also conceivable that the proposed operation based on predicable intervals of hard banding on the drill pipe and penetration rates etc. can be fully automated through simple PC programming.

Hydraulic Pull-Down Unit:

· It is apparent that when drilling lateral hole that the ability to achieve optimum penetration at the bit is reduced because of friction and drag on the pipe in the lateral section of the well bore. With the inherent pipe guiding capabilities of the concentric snubbing unit, the ability to apply downward force on the drill string from surface is a natural capability. The pipe is fully supported externally within the walls of the concentric tube, which allows it to be safely snubbed down without fear of bending or bucking at surface. To facilitate this option, a passive rotary would be installed above the stripping head and the travelling snubbing slips. The snubbing unit is extended, the travelling snubbing slips are closed, and an initial snub force is exerted on to the drill string and the top drive is engaged slowly. The snub force is gradually increased with rotation speed so that the slips keep up with the rotation of the pipe without the dyes of the slips slipping around the pipe. The more snub force that is applied, the easier this procedure is. The snubbing unit is collapsed in unison with the penetration rate while maintaining a constant snub force on the drill string. When the snubbing unit has drilled down to its collapsed position, rotating would stop long enough to for the slips to be opened and the snubbing unit extended. The slips are once again closed in preparation to begin drilling down the next section. A separate hydraulic power pack for this type of operation would be desirable, but a small mobile control console with the appropriate valving and weight indicators may be able to be incorporated into the existing hydraulic system powering the top drive. This system will still allow for stripping head elements to be changed above the rig floor as proposed.

At Piston safety and efficiency are our mandate and when you can combine this with measurable reductions in rig time, reduced consumption of costly expendables and more efficient operations, this can only contribute to the bottom line. Although there is still work to be done, we remain on course searching for avenues to further reduce unnecessary risks, increase safety and efficiency for all live well servicing operations and applications. We hope you will agree and recognize the merits of this proposal in the form of expressions of interest and ultimately long-term contracts, which will promote the construction of multiple, site-specific units to facilitate all your UBD needs.

Piston Well Services is currently on many major oil companies approved list of suppliers such as Encana, Husky, Rio Alto and others.

CONCEPTUAL DRAWINGS

A concentric unit is shown in retracted and extended positions as would be during normal UB drilling operations. The increase in unit length to facilitate the concentric portion is about 17 inches taller than existing equipment being used today. The unit shown above has a 36-inch effective stroke. Under most UBD operations, no more than a couple of drill collars would be snubbed allowing the short stroke to be very effective. Not shown in the diagrams are built in guided posts designed to absorb any drilling torque.

The concentric unit remains collapsed until the hard banding section arrives at the top of the element and is then extended above that section. The extended position is the same as it would be to change the element above the rig floor. The retaining cap is removed and the element is changed out. For quick and easy removal of the element from the body the element is held stationary while the unit is hydraulically collapsed to expose the element.

The concentric unit is shown as two pieces for fast and simple rig ups. The receiving flange and base plate complete with the hydraulic screws (1 piece) are installed under the rig floor. The concentric portion is then lowered through the rotary table and bolted into position with four pins. For multiple well applications the receiving flange portion would be left in place on the rig's BOP stack and moved to the next well. As two pieces the receiving flange portion is very light and easy to manipulate for quick and easy rig up.

The diagram depicts a typical cable snubbing system. The concentric unit is extended through the substructure. An adapter plate and stationary slips are then installed as one piece. A conventional spider and slip (not shown) is installed on top of the stationary slip while going through transition to pipe light. When the pipe has become light the stationary snubbing slip is closed and the cable snub system is then rigged in. When the pressure on a candidate well is marginal, this configuration can be reduced to a simpler configuration where the pipe being snubbed is managed by a support mechanism attached to the top of the pipe in conjunction with a tugger line rather than the rig blocks as shown.

*This full blown configuration is where we plan on taking this technology.
The concentric unit shown in the extended position. The rotary table has been removed (as it is not warranted for top drive drilling) or has sufficient inside diameter to pass the travelling snubbing slip. When snubbing is anticipated, the concentric unit is extended through the rig floor (as shown) and the travelling snubbing slip is affixed to the stripping head. Depending on the application the slip may have been previously installed or is permanently mounted. The Straddle-Sub is set into place and the attached snub lines are secured to the base plate. A conventional heavy spider and slip (not shown) are set on top of the stationary slip to assist handling the heavy pipe through transition (from heavy to light). Snubbing then begins.
The optional passive rotary is shown built in to allow the unit to be utlized as a "Hydraulic Pull-Down Unit" for maximum bit penetration. On larger applications the RS head would be replaced by an annular blowout preventor.

COST ANALYSIS

This comparison is based on a 5 - 6 day UBD lateral drilling program taking place in northern British Columbia, Canada

Our Concentric UDB unit will cut the number of stripping elements being used in half because of the ability to eliminate hard banding being adjacent to the stripping element while drilling. Based on an average of 4 elements currently being used per well, this is the way the numbers stack up.

Average costs based on existing technology per well:

4 RS elements @ $1600.00 per = $6400.00

30 min. per element change at $1.00 + per second (operating cost of a UBD operation) =
$1800.00 per change x 4 changes = $7200.00

Total cost of elements plus the rig time without including the rental cost of a conventional stripping head currently being supplied by competitors = $13,600.00

(The rental cost of a conventional head may vary, but this number is reasonably close)

Conventional Stripping Head Rental = $5000.00 / month /30 days per month = $167.00 per day

Average well taking 6 days x $167.00 = $1002.00 rental cost

Average Total Cost / well = $ 14,600.00 using existing technology

4 wells per month = $ 58,400.00

6 rigs drilling x $58,400.00 per month = $350,400.00 per month

8 rigs drilling = $467,200.00 per month

Average cost per well based on Piston Well Services Concentric UBD Stripping Head

2 RS elements @ $1600.00 per = $3200.00

15 min. per element change at 1.00 + per second (operating cost of a UBD operation) =
$ 900.00 per change x 2 changes = $1800.00 (Elements are now being changed above the rig floor (safer and faster)

Total cost of elements plus the rig time without including the rental cost of a conventional stripping head currently being supplied by Piston Well Services = $5000.00

Rental on Piston Well Services UBD Concentric Stripping Head = $20,000.00 / month / 30 days per month = $667.00 per day

Average well taking 6 days x $667.00 = $4002.00 rental cost

Average Total Cost / well (Piston Well) = $ 9000.00 using proposed patented technology

4 wells per month = $ 36,000.00

6 rigs drilling x $36,000.00 per month = $216,000.00 per month

8 rigs drilling = $288,000.00 per month

Potential Savings

Savings based on one rig drilling 4 wells per month (24 days utilization) = $22,400.00

Savings per month with 6 rigs drilling = $134,400.00

Savings with 8 rigs drilling $179,200.00 per month

Safety Issues

Changing stripping elements above the rig floor verses having men on top of the rigs BOPs under the substructure is much safer and preferred method. Gas in enclosed areas and men working above ground are two prime concerns.

Efficiency Issues

Eliminating hard banding rotating adjacent to the seal point of the stripper rubber will reduce the number of elements being consumed by as much as half. The savings through a reduction in rig time and the consumable element changes will amount to very substantial savings. When an element is required to be changed, the time it takes to perform the change (now being done above the rig floor) will also be reduced by half, contributing to further rig-time reductions.

Much of the above information is hypothetical, but it is based on proven working snubbing systems and 24 years of drilling, well servicing and snubbing experience. We have been provided much information by existing rig, project and drilling supervisors that have been directly involved in these UBD operations. If we are wrong or misleading in any way, please let us know so we can make the necessary adjustments.

We hope you will agree that the potential savings through the employment of better technology and enhanced safety make this a winning proposition for your company and Piston Well Services. We are confident to a point that we will will guarantee a minimum 20% saving in overall costs associated with our Concentric Stripping Head. The numbers represent a potential 38% savings on a per well basis. If asked, "how much will it cost?" the answer does not reflect the bottom line, but if asked the all-important question, "how much money will we save?" the answer is about 38% with a 20% guarantee.

For more information, please contact Kelly Funk @ (403) 348 1093

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