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Tubing Handling and Running Operational and Safety Guidelines

Oilquest International Limited operational manual is in line with API RP 5C1,"Recommended Practice for Care and Use of Casing and Tubing."   This operational manual is directed primarily at API connections, though some is applicable to Specialty connection products. In any event, if the tubing is equipped with Specialty connections, we refer to the manufacturer's Recommended Practice for handling and running before using it.

I.  UNLOADING

  • Ensure that the pipe racks are level and properly positioned to allow transfer of tubing
  • from the rack to the catwalk.
  • Ensure that thread protectors are in place on all connections before unloading tubing.
  • Avoid rough handling of tubing which might  dent, bend, or damage in any fashion the
  • pipe body or connections. Mechanical damage of the pipe is injurious, and can result in failure of the tubing in service. Particular care must be taken when handling tubing with an internal plastic coating.
  • Do not unload tubing by dropping joints onto the racks or by allowing pipe to tumble
  • from the transport. Maintain control of the tubing at all times by handling a small number of joints.
  • Do not place hooks in the ends of the tubing. Joints should be slung from spreaders,
  • evenly spaced along the joint.
  • When rolling tubing on the racks, do not allow joints to strike each other.
  • Always leave thread protectors in place when the tubing is being moved.
  • Tubing should be placed on level tumble racks or clean metal or wooden surfaces, free of any debris.

II. PREPARATION AND INSPECTION

  • All tubing and accessory equipment should be visually inspected before it is run in the hole. Where possible, the function of accessory pieces should be confirmed before assembly.
  • Any joints or accessories with obvious body or connection damage should be laid aside and not run.

 Any accessories which are questionable should not be used.

  • The basic running order of the tubing and accessories should be determined early, and the make/model/type of accessories verified.
  • The size and condition of all related handling equipment should be checked thoroughly.
  • Particularly, slips or tubing spiders, back-up tongs, elevators, and power tongs.

III RIG FLOOR EQUIPMENT

  • While the use of slip-type elevators is preferred for any length of tubing string, their use is strongly recommended for long or heavy strings, and for Special Clearance and Specialty Connection equipped tubing.
  • Check the elevator body, latch mechanism, links, and dies and setting plate if slip-type elevators are used. The elevators must close completely, and the latch engage properly for safety.
  • If slips are used, ensure the dies are clean and sharp, and all of the same size. Do not mix old or resharpened dies with new dies in either the slips of the elevators.
  • If a tubing spider is used, ensure it does not crimp the tubing when closed, and also that it releases completely to avoid gouging the tubing when lowering.
  • Slips and elevators should be cleaned frequently during use to reduce the risk of slippage, and to ensure their correct function.
  • The condition of the slip bushing must also be checked to ensure that the slips will fit properly and engage the tubing evenly. NOTE: Slip and tong marks are injurious, and can result in failure of the tubing in service. Properly fitting and well maintained equipment can greatly reduce the risk of damaging the tubing.
  • Check that the blocks are centered over the rotary table. If not, make the crew aware that the misalignment can result in difficulty when stabbing and spinning up connections.
  • Check the rig-in of the power tongs, making sure that the tong back-up line is at right angles to the tongs, the tongs are level, are free to move and are at the correct height above the floor.
  • Check the size and rating of the power tongs. The nominal size of the tongs should not be more than one size larger than the tubing being run (i.e. do not use 7" tongs to run 3-1/2" tubing) and the tongs must be able to readily attain the expected maximum torque.
  • Ensure that the power tongs are equipped with an accurate and reliable torque gauge -either electronic or hydraulic, possibly equipped with a pressure activated dump valve. 3
  • Check the size and condition of the back-up tongs. They must be sized properly, have clean and sharp die segments, and be in good repair to avoid damaging the tubing. The use of pipe wrenches as back-ups is not permissible under any circumstance. Check that the back-up tongs are level and do not interfere with the suspension or operation of the power tongs.

IV TUBING PREPARATION

  • Remove pin and box protectors from tubing and accessory pieces, and thoroughly clean the connections, removing all previously applied thread or storage compound.
  • Inspect all connections, particularly noting any mechanical damage to the threads. While minor corrosion damage is of little concern, mechanical damage of the threads can lead to failures in service. If a connection is damaged or questionable, it should be laid aside.
  • When inspecting box connections, check to see that the couplings are made up power tight. On pup joints and accessories, the couplings may be only spun on by hand, and may not have thread compound applied to the connection surfaces. On round thread connections, there should be no pin threads extending beyond the coupling face.

All tubing joints and accessory pieces should be drifted full-length with a standard API drift mandrel, from the box end to the pin end. While it is preferable to drift the tubing on the racks, a rabbit may be used instead as the tubing is pulled up through the V-door.

  • With the thread protectors removed and the connections cleaned, tally the tubing by measuring from the face of the coupling to the point on the pin connection where the coupling stops when the connection is assembled power tight. The distance from the pin nose to this point is referred to as the "make-up loss". Alternately, the total length of the joint can be measured, and the make-up loss subtracted from the overall length. Tallies should be made to the nearest 0.01m.
  • The cleaning, inspection and tallying operations are repeated as each tier of tubing is uncovered.
  • Before the tubing is moved to the catwalk, clean thread compound should be applied, and thread protectors must be replaced. Unless specified otherwise, API 5A2 type thread compounds should be used. Fresh compound should be used, the applicator brush must be clean and free of any debris, compound must be mixed well and never thinned.
  • Note that certain service applications (heavy oil thermal or extremely high pressure) may require use of a different compound. In no event are rotary shoulder (drill pipe or drill collar) compounds to be used.

When moving pipe from the racks to the catwalk, ensure that joints are not dropped or allowed to hit against other tubing or rig equipment. Tubing should be pulled up to the Vdoor with a choker, and then elevators used to pull the tubing joint into the derrick.
Thread protectors must be in place on both pin and box connections any time the pipe or accessories are moved.

  • If it is impractical to replace all thread protectors, several only can be cleaned and used repeatedly, being installed on the pipe rack and removed from the tubing when hung in the derrick.
  • If a mixed string is to be run (more than one grade and/or weight), ensure that sufficient pipe of the required type is available, and that it is laid out on the racks so that it will be accessible when called for in the program.

V RUNNING TUBING

  • Once the tubing has been pulled into the derrick, the pin end thread protector can be removed, thread compound applied (if required) and the joint stabbed.
  • In stabbing the joint, lower the tubing slowly to avoid connection damage, and ensure that the connection is aligned before starting rotation. A man on the stabbing board can be of great assistance, particularly if any misalignment of the blocks over the rotary exists.
  • Care should be taken when running tubing in stands of doubles or triples as the pipe may bow when the connections are stabbed, resulting in misalignment.
  • If the tubing does not stab correctly or jams, the pin should be picked up from the box, both connections cleaned, inspected, and repaired (remove any filings or wickers), thread compound re-applied, and the connection re-stabbed.
  • Once the  joint is stabbed, make-up can proceed, with the connection being spun up slowly initially, ensuring that the connection is not cross-threaded or jammed.
  • API Round thread connections are assembled to position; the assembly torque values provided are representative of the torque range required to attain the power-tight position based on nominal conditions, and must be used only as a guide.Torque must relate to the make-up position, and as a result, the torques used in the field for a given connection can vary from those listed.
  • A suggested procedure for tubing make-up is as follows:
    •  As the nominal power tight position for Round thread tubing connections is two turns past the hand tight position, it is advisable to assemble a number connections (at least  ten) from each particular manufacturer or mill lot on location to establish the torque required to attain this  position. The torque required to attain this position may or may not be Optimum as listed in API RP5C1, and the torque must be within the Minimum/Maximum range.
    •  During the initial spin up of the connections, watch for any irregularities in the assembly (torque spikes, heat, etc.) as these may indicate dirty connections, damaged threads, cross threading, etc., which can compromise the connection's integrity. If the initial spin up is erratic, the assembly should be stopped, and the connection broken out, cleaned, and inspected. If no damage is obvious, the assembly can be repeated, but if the initial spin up is again erratic, the connection is suspect and should not be run. To reduce the risk of galling assembly speeds should be kept below 25 RPM.
    •  As the assembly progresses, watch the position of the pin member last scratch relative to the coupling face, and monitor the torque.
    •  The Optimum torque value suggested should provide for a complete make-up to the power tight position under nominal conditions.
    •  If the pin thread last scratch is buried beyond the coupling face and Minimum torque has not been attained, the connection is suspect and should not be run. Conversely, if at Maximum torque the pin thread last scratch is not within two turns of the coupling face, the connection is suspect and should not be run.
    •  If at Optimum torque several threads are still showing, the torque should be increased, up to Maximum, to see if the power tight position can be attained.
    •  Once the ten or more connections are thus assembled a representative Optimum torque for that particular lot can be determined, and the balance of the connections run using this Optimum value.
    •  Suspect connections should be broken out and laid down, and not rerun unless inspected and repaired. The mating box connection should be cleaned and inspected for damage after break-out.
  • Note that when assembling the field connection, it is possible that the mill end of the connection will make up slightly. This does not suggest that the mill end is too loose, but rather that the field end torque applied is more than was used to assemble the mill end.
  • Tubing must be lowered carefully, first to avoid shock loads to the tubing string, but also to prevent pressure surges which may damage downhole formations. The slips must not be set until all downward motion of the tubing string has stopped. Great care should beexercised to ensure that the string does not spud the bottom of the hole or any downhole equipment - the compressive loads can cause the string to buckle and/or connections to loosen with the subsequent risk of failure in service.
  • Note that often there is a predetermined running order for tubing and related accessories -due to design criteria or downhole conditions. It is vital that this order be followed, and in the event that a specific joint of tubing cannot be identified with respect to its weight or grade, the joint should not be run.

VI POSSIBLE RUNNING PROBLEMS

  • Some of the more common causes of problems encountered when running tubing are:
    • Inadequate inspection of tubing or connections prior to running.
    • Improper transportation, storage, and handling practices.
    • Ignorance of Recommended Practices for handling and running of tubing.
    • Improper manufacture of accessory or repair facility produced connections.
    • Use of improperly manufactured couplings for replacement parts or additions.
    • Excessive spin up speeds for initial assembly.
    • Excessive or inadequate assembly torques applied.
    • Use of improper thread compound.
    • Use of poorly maintained equipment (slips, elevators, power tongs, etc.).

There are three main types of conventional natural gas wells. Since oil is commonly associated with natural gas deposits, a certain amount of natural gas may be obtained from wells that were drilled primarily for oil production. These are known as oil wells. In some cases, this "associated"natural gas is used to help in the production of oil, by providing pressure in the formation for the oils extraction. The associated natural gas may also exist in large enough quantities to allow its extraction along with the oil. Natural gas wells are wells drilled specifically for natural gas, and contain little or no oil.
Condensate wells are wells that contain natural gas, as well as a liquid condensate. This condensate is a liquid hydrocarbon mixture that is often separated from the natural gas either at the wellhead, or during the processing of the natural gas. Depending on the type of well that is being drilled, completion may differ slightly. It is important to remember that natural gas, being lighter than air, will naturally rise to the surface of a well. Because of this, in many natural gas and condensate wells, lifting equipment and well treatment are not necessary.
Completing a well consists of a number of steps; installing the well casing, completing the well, installing the wellhead, and installing lifting equipment or treating the formation should that be required. Click on the links below to learn about these aspects of the well completion process:

  • Well Casing
  • Completion
  • The Wellhead
  • Lifting and Well Treatment

Well Casing
Installing well casing is an important part of the drilling and completion process. Well casing consists of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well. A good deal of planning is necessary to ensure that the proper casing for each well is installed. Types of casing used depend on the subsurface characteristics of the well, including the diameter of the well (which is dependent on the size of the drill bit used) and the pressures and temperatures experienced throughout the well. In most wells, the diameter of the well hole decreases the deeper it is drilled, leading to a type of conical shape that must be taken into account when installing casing. There are five different types of well casing. They include:

  • Conductor Casing
  • Surface Casing
  • Intermediate Casing
  • Liner String
  • Production Casing
  • Conductor Casing
  •  

Conductor casing is installed first, usually prior to the arrival of the drilling rig. The hole for conductor casing is often drilled with a small auger drill, mounted on the back of a truck.
Conductor casing, which is usually no more than 20 to 50 feet long, is installed to prevent the top of the well from caving in and to help in the process of circulating the drilling fluid up from the bottom of the well. Onshore, this casing is usually 16 to 20 inches in diameter while offshore casing usually measures 30 to 42 inches. The conductor casing is cemented into place before drilling begins

Surface Casing
Surface casing is the next type of casing to be installed. It can be anywhere from a few hundred to 2,000 feet long, and is smaller in diameter than the conductor casing. When installed, the surface casing fits inside the top of the conductor casing. The primary purpose of surface casing is to protect fresh water deposits near the surface of the well from being contaminated by leaking hydrocarbons or salt water from deeper underground. It also serves as a conduit for drilling mud returning to the surface, and helps protect the drill hole from being damaged during drilling. Surface casing, like conductor casing, is also cemented into place. Regulations often dictate the thickness of the cement to be used, to ensure that there is little possibility of freshwater contamination.Intermediate CasingIntermediate casing is usually the longest section of casing found in a well. The primary purpose of intermediate casing is to minimize the hazards that come along with subsurface formations that may affect the well. These include abnormal underground pressure zones, underground shales, and formations that might otherwise contaminated the well, such as underground salt-water deposits. In many instances, even though there may be no evidence of an unusual underground formation, intermediate casing is run as insurance against the possibility of such a formation affecting the well. These intermediate casing areas may also be cemented into place for added protection.

Liner Strings
Liner strings are sometimes used instead of intermediate casing. Liner strings are commonly run from the bottom of another type of casing to the open well area. However, liner strings are usually just attached to the previous casing with 'hangers', instead of being cemented into place. This type of casing is thus less permanent than intermediate casing.

Production Casing
Production casing, alternatively called the 'oil string' or 'long  string', is installed last and is the deepest section of casing in a well. This is the casing that provides a conduit from the surface of the well to the petroleum producing formation. The size of the production casing depends on a number of considerations, including the lifting equipment to be used, the number of completions

A Small Auger Drirequired, and the possibility of deepening the well at a later time. For example, if it is expected that the well will be deepened at a later date, then the production casing must be wide enough to allow the passage of a drill bit later on.
Well casing is a very important part of the completed  well. In addition to strengthening the well hole, it also provides a conduit to allow hydrocarbons to be extracted without intermingling with other fluids and formations found underground. It is also instrumental in preventing blowouts, allowing the formation to be 'sealed' from the top should dangerous pressure levels be reached. For more technical information on blowouts and their prevention, click here. Once the casing has been set, and in most cases  cemented into place, proper lifting equipment is installed to bring the hydrocarbons from the formation to the surface.
Once the casing is installed, tubing is inserted inside the casing, from the opening well at the top, to the formation at the bottom. The hydrocarbons that are extracted run up this tubing to the surface. This tubing may also be attached to pumping systems for more efficient extraction, should that be necessary.

Landing Tubing Introduction
A variety of well heads can be used. Following is a list of typical well
Threaded Flange Well Head
Remove the flange from the well head as the extra weight will cause damage to the fiberglass thread.
Check the thread compatibility prior to installation per procedure 3.4.5.
O-Ring or Doughnut Well Head
Check the thread compatibility prior to installation.
Landing Tubing · Special diameter landing joints can be ordered, however the diameter with Tolerance
At The Well Head must be specified and are subject to approval.
Special machining by an outside vendor will be charged to the customer.  Non-jump size landing
joints for 5½" – 9 5/8" sizes can be manufactured according to specified outside diameter, or prior to installation the landing joint can be select by checking the diameter of the pipe on location.

Hydrotesting - During Installation
Tubing · Quick (two minute) hydrotest while going into the hole are difficult to monitor. The cost accurate way to test fiberglass as it is installed is above the slips where the full joint is exposed.
- The weight of the joint being tested should be held by the elevators, but the slips shouldbe set.
- The test duration should be extended to five minutes.
- Watch the gauge closely and examine the outside of the pipe for continuous drops of water.
- If the pipe is a rerun, examine the pipe closely in areas where the slips or wrenches Contacted the pipe.

After Installation
- Circulate the well and allow for stabilization of temperature and tubing stress.
- It is good practice to monitor pressure inside the tubing and in the annulus.
- Test with fresh water inside the tubing whenever possible.
- When conducting annular tests do not pull the fiberglass tubing if a leak is suspected.
- Always drop a plug (standing valve to seating nipple) to the packer and test the tubinginternally prior to pulling the string.
- If the tubing shows an internal leak it is good practice to test each connection for a leakcoming out of the hole.

Pulling Tubing - Releasing From Bottom Hole Tools Cautiously Or Casing ·
- Make sure tubing is free to exit before pulling.
- A calibrated weight indicator should be used.
- Equalize fluid levels in the tubing and casing.
- Determine the line load of the tubing prior to the first lift.
- Never exceed the rated tensile to get loose from bottom hole tools.

Stuck Bottom Hole Tools
Try lowering the tubing to one half the string line load, then lifting with rotation up tothe maximum tensile rating.
- Several cycles may be required if sludge or sand has accumulated at the bottom of thehole.
- Do not over rotate the pipe such that it may become loosened or over torqued.
- A good rule of thumb is one full rotation at the surface converts to a ¼" turn at the bottom after it is worked up and down.
- Excessive rotation is defined as six or more full turns at the surface.
- The tubing can unscrew and disengage.
- Rather than damage the tubing it is best to shoot off or mill the tubing at the joint above the bottom hole tool, a mechanical jet cutter works well.
- Fishing of fiberglass tubing is accomplished using normal overshot or spear procedures. Pulling Tubing  - Break Out Of The Connection or Casing
- FGS metal friction wrenches are recommended for use on the upset near the coupling for sizes ≤4½".
- Sizes >4½" require the use of qualified power tongs.
- Hammering the coupling or box can cause damage.
- Use a rubber mallet or a wooden slate to pad the connection, if hammering becomes necessary.
- Tap lightly at the center of the engaged thread.
- Tapping should be done while applying constant torque.

Disengagement Of The Connection
- Exercise care to make sure all threads are unscrewed prior to lifting.
- Do not continue to rotate after the last thread is disengaged.
- Do not jump the connection out of the coupling.

Stacking The Tubing In The Derrick
- Replace thread protectors on tubing.
- Protect the pin end from dirt or damage.
- Set the pin end on wooden pads.
- If the pipe is left overnight and high wind potential exists it is best to tie it back securely at the top of the rig and midway to the ground.
- Tubing 2 7/8" and larger can be pulled in double

Thread Inspection
- Clean the threads with a steel brush to inspect for damage threads.
- Remove any particles or debris that is found.
- Cleaning with water or solvents requires absolute dryness before rerunning.

Storage
- All threads should be cleaned and protectors should be placed on the tubing before it is laid down.
- Before tubing is stored or re-used, tubing and threads should be inspected and defective Joints segregated.
- Store the tubing on four wooden padded racks equally spaced so that it will remainstraight (particularly if stored for an extended period of time).

Tubing or Casing
- Realize that as the threads are made-up, pulled, and reran, the thread standoff will begin to reduce as the threads wear.
- Monitoring wrenching damage from breakout for penetration into the laminate.
- Tubing Failure
- Retrieve the sample in its "as failed" condition.
- Analysis
- Do not pull a string that is suspected of leaking until it is tested internally in the hole in "as installed" condition.
- A seating nipple placed at the packer which will accept a standing valve is the best wayto internally test.

Casing Jamming During Installation
Sometimes it is not possible to lower the casing and well screen to the bottom of the hole. This can be due to part of the borehole collapsing, clays in the aquifer swelling and reducing the size of the borehole or the borehole being crooked resulting in the casing digging into the wall of the borehole. These problems are most common where 10 cm (4 in) schedule 40 casing is being inserted into a 15 cm (6 in) borehole. This is because the outside diameter of the casing couplers is 13 cm (5.25 in), leaving an annular space of just over a quarter inch on each side of the casing! It does not take much swelling of clays or slight deviation from vertical to result in the casing jamming If the casing does not slide freely into the borehole, it is not advisable to try and force the casing down. Striking it hard in an attempt to drive it may cause the screen to deform; rotating and pushing it down can cause the screen openings to become hopelessly plugged with fine materials.

To avoid these problems, minimize the amount of pull-down pressure when drilling so that the bit can run freely under its own weight. Also, casing there is no problem with casing jambing when 7.6 cm (3 in) schedule 40 casing is used. Keep in mind, however, that a 7.6 cm (3 in) casing is too small to take a 6.4 cm (2.5 in) pump cylinder or most submersible pumps. Usually, however, these issues are not a concern.

If you need to construct a 10 cm (4 in) well and the casing has jammed, the best solution is to pull the casing / screen from the borehole. This involves cutting the casing into 6-12 m (20 - 40 ft) lengths (longer than this will result in the casing bending and cracking). Slowly re-drill the borehole with a 15 cm (6 in) reamer bit or, if available, a 18 or 20 cm (7 or 8 in) bit. Concentrate on the portion of the borehole where the casing jammed. While this can take several hours, it often eliminates blockages and allows the casing to slide to the bottom of the borehole. As soon as the reaming is completed, re-glue and re-insert the casing.

If it still jams, your last resort is to try and "wash" the casing down by installing the drilling rods down inside the casing and circulating drilling fluid through a wash-down valve (see Section 7). Fluid is pumped down through the casing and out the bottom of the screen where it will pick-up and carry soil particles back up to the surface between the casing and the hole walls. The amount of water passing through the screen openings can be minimized by attaching a surge block to the lower end of the drill string. Be sure to secure the pipe with a rope to prevent the casing from dropping if the blockage was localized and is removed with the circulation process. Failure to do so could result in the casing dropping to the bottom of the hole without the casing extending to the surface. When the casing is finally installed to the appropriate depth, stabilize the open bottom end of the casing by pouring in 30-60 cm of coarse gravel into the well. If the casing still jams above the water bearing formation, the only other option is to obtain and install 7.6 cm (3 in) casing and well screen.