How extended reach torque, drag may be affected by composites
Composite tubulars are already used in short horizontal sections drilled with a short-radius configuration, but their use in longer throw wells is considered risky. Flexibility is required for short-radius drilling, but not so for extended reach drilling. Also, composite tubular costs are as much as five times that of steel, and well engineers have stayed away from composite investigation for extended reach wells. However, well throw distances now are rapidly approaching the torque and drag limits of steel tubulars (27,000-30,000 ft). The use of composite tubulars will have to be re-considered.
Drillstring torque and drag equations show a linear dependence on the weight of the drill string and the friction coefficient between the drillstring and wellbore walls. In highly deviated and extended reach wells, this dependence is shifted but the relationship remains. Newer drilling fluid components have reduced drillstring-wellbore wall friction, but they are expensive and not always environmentally acceptable, so the only remaining option is to deal with drillpipe weight.
The Drilling Engineering Association says that current products do not meet extended reach drilling needs, and more product development is needed. The group has proposed a study of how composite drill pipe relates to drillstring torque and drag and what characteristics are needed for composite tubulars in extended reach wells. For extended reach wells, flexibility would be minimum. More important would be cost, followed by strength in compression, tension, burst, and collapse.
- When pipe is pushed or pulled in extended reach wells, drag results from the friction created by drilling - wall contact. Drillstring - wall contact also creates a frictional torque, which resists rotation of the drilling string. Total torque and drag is the sum of these resistnces, multiplied by weight of string an/or area of contact, and in the case of torque, the tubular's radius.
Slimhole troubles driving interest in pin-up drillstrings
Drilling with the drillstring upside down, in effect reversing the pin and box positions, is becoming more popular in slimhole drilling in highly deviated wells in order to run with larger strings and to extend the life of older strings. The need to conserve drilling costs has made the procedure more popular.
A corollary maneuver is to cut drill pipe shoulders to 18, instead of the customary 35, which better supports reversal of the drillstring. Both measures were developed years ago when contractors wanted to continue using drill pipe that was damaged by slips. Reversing the string provides a new surface - the pin end instead of the box end - for slips. Slimhole drilling became popular in the early 1990s.
The 18 shoulder reduces drag when tripping out of horizontal and highly deviated sections of slim holes, since it offers a better surface. Also, the lower angle allows for the use of slightly larger drill pipe. Putting a larger diameter drillstring in a slimhole reduces hole deviation, increases rate of penetration, and reduces fatigue accumulation.
References: Roy Dudman, The Hole Truth, Amoco Production, February, 1944; Tom Smith, Drilling Contractor, November 1993.
Mud pulsing can remove drill chips
Chips broken off the rock face by drill bit teeth are often not dislodged by the stream of drilling fluid emanating from the bit nozzles. The constant flow of fluid can hold down the chips, forcing the drill bit teeth to grind the chips, slowing cuttings removal and ultimately, rate of penetration.
Tests of a mud pulsing system developed six years ago at the University of Cork in Ireland (patented by William Griffin) are continuing and some results seem promising. The pulsing method appears to work best in chalk-and-chert formations.
The method creates a water hammer effect. The alternating sweep of the fluid streams minimizes the chip holddown effect. The pulsing is achieved by the shape of the bit nozzle. No moving parts are involved. A polychrystalline diamond ring forms the edge of the jet nozzle, providing a durable surface in an area where metal erosion is a problem.
Jet salt leacher can penetrate long sections in hours
Jet leaching equipment was used in place of a conventional drill to cut through 3,900 ft of salt body on an onshore test well recently. The time required was 26 hours, compared with an estimated conventional drilling time of 24 days.
The technology was developed originally for creating salt cavern storage. Now, the system has significant potential for subsalt drilling in the US Gulf of Mexico where salt encroachment and underreaming are constant experiences. The leaching system was developed by CMI of Lafayette, Louisiana.
The jetting system forces water at angled projections at varying speeds to wash the salt away. Computer analysis allows the driller to monitor the progress of the hole and made adjustments. The disadvantage of the use of salt jetting is a dependable supply of under-saturated water, tankage for the higher volume of circulation fluids, and a means to dispose of saturated water.
Normally, drilling with a drill bit through salt structures requires the addition of under-reamers and side-reamers in the bottom hole assembly. Because of salt encroachment or creep in the borehole after the section is drilled, the reamers grind the salt away during tripping or periodically when the drillstring is pulled uphole. An active salt structure can reduce borehole gauge by as much as 1/2-in. of diameter per day, and drillers like to install casing or casing backed with liners in salt sections as soon as possible.
With the jet leaching process, the circulating water in the hole, even at saturated levels, dissolves the face of the borehole, keeping the hole in gauge or over-gauge.
CMI engineers said the onshore well was drilled from 2,500 ft where the salt body was encountered to the 6,400 ft before emerging from the body. The actual washing time for the 40-in borehole was 26 hours. Tight areas were opened up selectively without endangering the casing seat.
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