Drilling Problems - Directional Drilling Club

Drilling Problems - directional drilling club

d i r e c t i o n a l d r il il l i n g c l u b Introduction

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Tarus Gundrills Deephole drill at compound angles w/ Rotary Tables and Tilting Slides

D e f l ec ec t i n g a wellbore

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Downhole Mud Motors

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There are many operational decisions made between the directional driller and the operator’s representative. To cover all aspects of these considerations would be a book in itself. As with any drilling operation, the most important item on a directional well is TEAM COOPERATION. The biggest hurtle to overcome in any multi-disciplined operation is the egos that come together on-site. It is this human characteristic that if not properly controlled or utilized in a positive manner can be the downfall on a directional project. Many oil field workers are very good working with equipment and getting the job down but have a difficult time dealing with the various personalities on-site. Sometimes the school of hard knocks becomes a tough learning environment known as “Employment Survival – 101”. A group of team players that share their knowledge, communicate well and mutually arrive at the best solution will always produce the record well. In order to address some of the operational considerations that directional company representatives must consider, the following sections are prepared to address what affects the equipment and performance of a directional operation or what could go wrong. These items may be discussed discussed in the field with the operator’s operator’s representati representative ve and it is important to realize the impact. As technologies are developed so will the potential problem areas increase.

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Rig Mud Pumps Too small of a mud pump can restrict restrict the performance of of the PDM and drilling drilling rate. The PDM has an optimum optimum flow rate operating range. Insufficient available flow rate due to pressure restrictions and/or liner sizing can result in poor hole cleaning in high angle wells. The pressure restrictions can also affect the MWD system utilized. As discussed earlier the negative pulse system requires a pressure differential between the MWD and bit of 4000 KPa. If smaller nozzles are required in the bit but the pump cannot handle the pressure the MWD system may not work or you may have to cycle the pumps more often just to get a signal. This This can lead to hole washes and lost time.

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Duplex pumps produce more noise than a triplex triplex pump and it can be very difficult difficult to filter these these noise out with an MWD system to allow decoding of the pulses received on surface.

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A low pre-charge can also decrease the efficiency of decoding pulse signals.

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Solids Control Equipment This is a key area that affects affects all equipment equipment performance. performance. Poor solids control can plug up MWD systems, create aggressive wear on all equipment, reduce penetration rates, create potential downhole sticking situations and increase formation damage. In many cases poor solids control affects the mud properties and limits its ability to suspend solids. We have witnessed cases where circulation of the drill string after running to bottom was impossible because the solids settled out in the motor causing it to pack off. On horizontal wells drill solids are pulverized into smaller particles due to a grinding action. If the best attempt to remove solids is not made on the first circulati circulation, on, these fine solids are left in the system and tend to increase formation formation plugging.

Rotary Equipment

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When directionally directionally drilling, it is imperative imperative that all rotary equipment is in good condition. condition. When When table locks do not work it is extremely extremely difficult difficult to control the tool-face when slide drilling. drilling. Wrapping tugger lines lines around the kelly bushing to control tool-face is a very dangerous dangerous situation.


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Tong lines that are out of calibration can result in incorrect torque applied to critical connections that may result in motors backing off downhole. Automatic diggers that do not allow subtle increases in WOB can result in motors frequently stalling when trying to initiate drilling after each connection. This affects the average ROP and time spent drilling. Smaller diameter drill pipe will twist more due to torque than larger diameter. Single shot operations with 3 ½” drill pipe can become very difficult if not impossible as the depth increase beyond 500m (1500 feet). Insufficient hevi-wate drill pipe will quickly limit the depth you can drill to and still make any slide corrections. Drilling vertical hole to KOP with too small of drill collars can result in having to pick- up directional tools earlier than planned due to deviation.

G r o u n d i n g Of El e c t r i c a l E q u i p m e n t All MWD systems use computers and special algorithms to decode pulse or electromagnetic signals. In some cases poorly grounded light plants and ge nerators have created sufficient interference to prevent clear reception of these signals. In some cases the signal noise is too large to filter out.

Co m m u n i c a t i o n a n d Da t a C o l l e c t i o n Eq u i p m e n t Although an extra cost to the job, a phone system between the drill floor and the command center can save considerable time and relay drilling concerns much quicker. Remote recording instruments that provide all drilling data to the command center also allows a more educated decision when drilling problems arise. They also allow others to review the overall operation from a different point of view than the driller. In some cases small pressure fluctuations noted on the standpipe pressure graph was all that indicated a failing bit. The performance trends are much easier to detect when a graphical display is available.

B i t S e l ec t i o n a n d L i f e Although PDC bits have come a long way in their development they still have some restrictions in their directional applications. A very careful review of the formations being drilled through, especially in the build section, must be made. Their use in horizontal sections has seen dramatic improvement over the years. It is very important the correct motor be selected for these runs otherwise their design cannot be fully utilized. When building inclination or trying to turn the wellbore, the outer row of teeth on the bit has the biggest influence. When erratic build or turn rates are noted, or you can’t build or drop inclination, it may be the teeth are worn down too far to “get a good bite” on the formation. The effective life of bits used on directional wells is usually lower than normal due to the different loading applied to the bit. Remember when rotary drilling with a motor to add the table RPM to the motor RPM and select the bit based upon this.

M o t o r Pr o b l e m s High temperature holes (greater than 100o C) can severely limit the performance life of motors. The temperature tends to cause the elastomer in the stators to swell and cause premature stalling. Hydrocarbon based drilling fluids can cause the stator lining to swell, loose strength and chunk out. Abrasive fine solids left in the drilling fluid may cause aggressive wear of the stator that will result in loss of power and reduced ROP. Excessive back reaming can cause motor connections to back-off. Rotating motors at RPM’s greater than 50 is very hard on the bearing and drive sections. Also rotating motors with adjustable housing settings greater than 1.8 o can cause premature bearing failures. When drilling underbalanced the motor is typically not lubricated to the same degree as overbalanced wells. Consequently, some very strange wear patterns have been seen on these motors and they may not last as long. Unique “pressuring up” situations have been noted on small hole size (121mm) underbalanced wells. Not fully understood at this time but appears to be pressure and temperature related. Motors have pressured up within 12 hours


of drilling but show no problems on surface when disassembled. Stators are vary susceptible to aggressive wear on underbalanced wells with solids contents greater than 5%. Some motors only lasted 12 hours.

M WD S y s t e m s Most are susceptible to solids plugging and have a flow rate limit through the MWD NMDC. Most have a percent solids limit that they can function in. Not all systems can handle lubra beads (or similar additives) before plugging. Each type of system has its own limit to the type and concentration of lost circulation material before plugging. It is always better to discuss with directional company the potential of lost circulation and possible mud additives that may be added. Jarring with MWD systems in the hole can result in damaging the electronic components. If hole problems are a significant problem in the area consider a retrievable system. The only problem here is most retrievable systems have a lower reliability value (mean time between failure). On whipstock operations never mill out casing with an MWD system in the drill string. Excessive damage occurs to the MWD system that the operator will be required to pay for. Pumping acid or bleach through MWD systems prior to tripping out at the end of a well can be very damaging to the equipment. In some cases operators have had to buy complete strings of tubulars due to internal cracking and probe damage just because they didn’t want to make another trip to flush the hole. A unique problem noted with electromagnetic systems is the interference between two rigs working close together. In one case the rigs were 50m apart and each rig could read the signal from the other. There are methods in place to avoid this occurrence. Most electromagnetic systems require some conductive fluid in the wellbore. In some cases the entire signal has been lost when drilling with diesel due to its poor conductivity. Most standard electromagnetic systems have a limit to the depth they can drill to due to the resistivity of the formations between the bit and surface. Resistivity logs must be carefully reviewed and modeled before selecting this tool for service. Failure of Z-axis accelerometer results in incorrect inclination measurements. The variation of these values is very subtle in a horizontal well and must be closely monitored at all times but especially when there are TVD concerns. Most times when the value remains the same for three surveys the tool should be pulled and checked.

Build Sections Typically a directional driller will try to get kicked off slightly above the planned point. They should never get to far above the line unless there is a long tangent or hold section to the target. On build and turn profiles for a horizontal well, the driller should try to stay on the line as much as possible since getting behind or to far ahead can result in sharp doglegs later in the well path. If the current motor setting is not achieving the desired build rate do not wait too long before tripping to change the setting. Unless the area build performance is very well known waiting too long can result in missing the target or sharp doglegs. Large hole sizes (greater than 311mm) that require high build rates (greater than 3 o /30m in some cases) may be drilled faster with a smaller assembly and then opened up. This is especially true for deviated surface hole where the formations are too unconsolidated to achieve the build rates. On long reach wells with the build section left open, it is prudent to make a couple of wiper trips (maybe a reamer trip) through the build section to smooth out any ledges. This will reduce the hole torque and drag values as the hold section continues to be drilled. Never ream a build section without MWD equipment since this is when most new holes are started. Always orient through the build section with a reaming assembly, watching the tool-face behaviour.

H o l d S ec t i o n s


Depending upon the inclination this is when correction for azimuth is very important. The first 60m of hole drilled should be surveyed every 10m (single) to ensure the hole is maintaining the desired path. Some operators have released the directional company too early in these sections and when trying to makeup some time they apply too much WOB and push the wellpath off target. Stabilized bottomhole assemblies work well in this section but will require reaming all the way to bottom since the directional assembly typically drills a smaller average hole size. Frequent wiper trips or pumping viscous mud sweeps are highly recommended when the hold section inclination is greater than 60 degrees.

H o r i zo n t a l Se c t i o n s Most common problem in the horizontal section is getting too aggressive in changing the TVD. Abrupt changes may get you back into the zone quicker but can limit the horizontal length. In some cases when requested to climb in TVD very quickly the directional driller was unable to come back down and level off in the zone. Know the h ard boundarie s in TVD before attempting any TVD changes. Determine what could happen to the well productivity if it suddenly climbs too high or drops too low. Beds of cuttings typically build up in the horizontal section like sand dunes. This can be noticed if the drag or torque begins to increase over what a torque/drag program predicts. Routine short wiper trips to stir up these beds helps clean the hole and prevent sticking. Never make quick changes in inclination or azimuth at the heel of a horizontal well, as this will quickly limit the maximum length you can drill.

O pe n H o l e S i d e t r a c k s Biggest mistake made in this operation is pushing too hard and fast. It is imperative a good ledge is built before increasing the differential pressure on the motor. Do not rush the directional driller and have him drill faster once a ledge is built. Never test the ledge by placing weight onto it. This is the quickest way to break off the ledge. Once a good ledge is established slowly increase weight on bit in stages and drill by differential pressure (control drill). Use densified cement plugs whenever possible when planning to sidetrack a well off of cement. Remember the bit will take the path of least resistance so if the cement is softer than the formation the bit will drill up the cement. Plan to have at least 75m of hard cement below sidetrack point. When entering a sidetracked leg always orient through to minimize the chance of breaking off ledges or starting a new hole. Have a sidetrack plan in place and stick to it. Allow the directional driller to show his experience at telling when a good sidetrack has been created.

Whipstocks Biggest problem on these operations is getting the well started in the right direction. When there is angle in the well and it has an established direction you can not just point the whipstock where you want to go. All drilling must be down by tool-face. When high build rates are required (greater than 20 o /30m) it is very easy to get behind the curve. Due to magnetic interference and/or position of directional sensors you may have to drill 30 or 40m of hole before you know if you are achieving the required build rates. If you only needed a change of 30 degrees you may already be behind the curve. Always survey more often in the first 2 to 4 singles to check build rates (every meter in some cases) once the sensors are in new hole. Many times the whipstock is plus or minus 25 degrees from where you planned it to be. Some whipstocks can fall in on themselves when set at tool-faces greater than 90 degrees left or right when the inclination is greater than 45 degrees.

M a g n et i c I n t e r f e r e n c e Whether it is from hot tools, solar flare activity or proximity to steel this can be a very bothersome concern. It takes requires careful attention by both the directional driller and the MWD operator to find these problems. Solar activity has produced local magnetic declination errors of up to 7 degrees in the northern latitudes. Imagine what 7


degree shift in azimuth would do to a 1000m laterals planned end point (122m offset). NWDC’s and motors shipped with casing or drill pipe can in some cases develop magnetic hot spots. It is also easy to record false readings depending upon where the tools are checked (on racks surrounded by drill pipe versus on the catwalk). Magnetic checks should always be taken at multiple spots along the equipment and averaged out. The preceding sections have captured some of the problems that can occur in the field. It is through good team work and communication that their effects can be minimized.

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Drilling Problems - Directional Drilling Club

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