Used Drill Pipe Coating
As the demand and overall cost for drill pipe continues to increase, maximizing the usable life out is paramount. With the vast majority of new drill pipe being internally coated for benefits such as corrosion resistance, hydraulic improvement and scale mitigation, the recoating of used drill pipe to further ensure these benefits is beginning to become a more common practice. Frequent coating evaluations are recommended to improve the longevity of the drill string and ensuring the coating if fit for service at hand.
NOV Tuboscope Drilling Services 2011 www.tuboscope.com 1-713 799-5100 [email protected]
Coating Services Cont…
Case History #1
Onshore Drilling Contractor Uses Drill Pipe Maintenance to Extend Drill String Life As the pipe ages, and the coating either becomes sufficiently mechanically damaged or finally succumbs to the environment, its benefits can be reduced. An onshore drilling contractor has practiced drill pipe maintenance for many years, which has included a recoating program.
Prior to using any internal coating on their drill pipe, they would expect approximately 180,000 to 200,000 foot of drilled hole with bare pipe prior to having to downgrade the string and pick up a new one. When examining one of their recent successes after their implementation of an internal plastic coating maintenance program, this contractor was able to drill 27 wells totaling 257,652 ft of total hole prior to recoating the string. The pipe was then recoated and went on to drill an additional 55 wells and a grand total of 781,101 ft of total hole drilled. Inspection results showed 6 double white premium class, 241 yellow band, and 30 orange band joints. This
particular operator drills with joints that are yellow band or better which means that 247 out of 277 joints were still usable in daily operations after over 780,000 foot drilled. Below is a table outlining the economic benefit that was achieved by the implementation of a recoating program for used drill pipe for this contractor.
4 1/2" 16.6# X-95 Drill Pipe
Bare Drill Pipe Coated Drill Pipe
Number of Joints 340 340
Cost of Pipe/jt $ 1,200.00 $ 1,200.00
Cost to Coat/ft $ - $ 4.00
Coating Applied 0 2
Cost of Initial Pipe $ 408,000.00 $ 451,520.00 Cost to Reach
780,000 ft Drilled $ 1,632,000.00 $ 495,040.00
Tuboscope’s drill pipe maintenance program was able to save this drilling contractor $1,136,960 for this particular application.
NOV Tuboscope Drilling Services 2011 www.tuboscope.com 1-713 799-5100 [email protected]
Coating Services Cont…
Case History #2
Field History of Bare and Coated Drill Pipe
A Summary of Nippon Steel investigation of washouts in drill pipe dated May 95:
Coated Pipe Bare Pipe
Footage Purchased 130,000 feet 65,000 feet
Pipe in Service 2 years 1 year
Washouts to Date 0 22
Estimated Cost Associated with
Washouts 0 $2,200,000
Cost of Failed or
Replacement Pipe 0 $66,000
Total Cost of Failure 0 $2,266,000
NOV Tuboscope Drilling Services 2011 www.tuboscope.com 1-713 799-5100 [email protected]
Coating Services Cont…
Case History #3
Outline of SPE Paper # 77687 – Case History: Internally Coated Completion Workstring Successes
The coated string was composed of 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe some of which was 20 years old and was classified as Class 2 due to undersized tool joints.
o A wall loss of 0.036” could downrate the Premium Class tubes to Class 3, making the pipe scrap.
Preliminary proppant erosional tests exposed the TK-34 to 750,000 pounds of 12 ppg, 20/40 mesh ceramic proppant to 30 barrels per minute, equating to a velocity of 33 ft/sec.
o “Although there were small and infrequent holidays over ~3% of the surface area, the coating served its purpose of minimizing metal exposure and wear (~97% of the area was protected with coating).”
“No acid pickling treatments were needed throughout the 17 completions saving
$170,000. These savings more than offset initial coating costs and any re-coating costs.
This cut the cost to purchase, transport, and dispose of the acid along with eliminating the safety, environmental, and liability risks associated with handling and disposing the acid.”
“Most engineers do not recognize the hydraulic benefits that can be gained by using internally coated workstrings.”
o A 16% water injection rate increase was modeled and it was determined that less surface pressure is needed to pump through the coated workstring at any rate.
o “In addition to obtaining the cleanest well bore from the maximum circulation rate, the reduced pipe friction from a coated workstring could possibly mean the difference between using the rig pumps to displace the well and incurring costs to use the cement unit due to higher surface pump pressures with uncoated pipe.”
o “The added friction pressure from uncoated pipe creates more backpressure on the formation and thus more completion fluid losses.”
“This drill pipe was handled in typical rig fashion without any consideration for the internal coating.”
“No trouble time was experienced due to workstring problems during this challenging completion program.”
“It was the opinion of the rig contractor that the workstring would not have survived the rigors of the Genesis completion program without an internal coating.”
Copyright 2002, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, 29 September–2 October 2002.
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Abstract
Completion workstrings must endure an extremely hostile environment of erosive and corrosive fluids. Today’s improved internal plastic coatings can protect the significant investment in drill pipe from erosion/corrosion, as well as minimize completion trouble time caused by pipe debris (scale). An internally coated, Class 2 drill string was used for 2½ years to successfully Frac Pack seventeen, high productivity, Gulf of Mexico Deepwater completions in the Genesis Field. More than 2,000,000 pounds of abrasive proppant was pumped without a pipe failure.
Introduction
The completion workstring requirements were reviewed during the development well planning for the project in 1998.
During completion processes, this pipe would be subjected to only minimal tensile stress and torsion; however, the pipe would need to bear the rigors of numerous Frac Pack completions. The plan originally included 22 Frac Pack completions from 16 wells with anticipated surface treating pressure of up to 10,000 psi (depending on the selected completion string diameter). The planned wells ranged in depth from 12,000’ to 23,000’ and in hole angle from 16° to 66°. During each completion, the 6 5/8” drill string would be changed to a smaller diameter completion workstring to displace the well to CaCl2/CaBr2 completion fluid, tubing conveyed perforate (TCP) underbalance, pressure surge the perforations, wash sand fill, and Frac Pack. The workstring would then be sent to a pipe yard to be stored outdoors until the next completion operation occurred in roughly one month.
After reviewing the alternatives, the rig contractor’s 5”, 19.50#/ft, S-135, 4 ½” IF drill pipe was selected for the
completion string. This workstring was a collection of used pipe with an RP7G API-IADC Used Drill Pipe Classification System rating of Class 2 due to undersized tool joints.1 Some of this pipe was as old as 20 years yet the tubes met Premium Class standards with ≥80% wall thickness (≥0.290”) remaining. Premium Class tubes have a tensile rating at minimal yield strength of 560,764 lbs and an internal yield pressure rating at minimum yield strength of 15,638 psi. The reduction in torsional strength due to the reduced tool joint diameter was not a concern due to minimal rotation for drilling cement anticipated. These specifications met the anticipated completion workstring requirements and the rig contractor was pleased to find commercial use for this drill pipe rather than scrap it for roughly $50 per joint or replace the tool joints for roughly $700 per set.
An abrasion resistant internal drill pipe coating was considered to combat further internal wall loss due to proppant laden Frac Packs. A wall loss of only 0.036” could downrate the Premium Class tubes to Class 3 (<70% wall) which has no RP7G published rating for tensile forces or internal yield pressure. The drill pipe would then be scrap pipe.
Additionally, the internal coating should minimize internal pipe rust and eliminate the need for acid pickle treatments. For deepwater operations, acid pickle treatments cost roughly
$10,000 for purchase, transportation, rig time, and disposal.
Most importantly, using an internal coating would eliminate the safety, environmental, and liability risks associated with handling and disposing of acid.
A liquid-applied, modified epoxy-phenolic internal coating specifically formulated for drilling environments was considered for the completion program. Standard industry tests for coating abrasion resistance (Taber Abraser test, ASTM #D 4060) measure a test sample’s weight loss in mg over 1000 cycles of abrasion using a CS-17 wheel with a 1000 gm load.2 In 1998, the coating considered for use had results, provided by the supplier, of 47 mg of coating lost / 1000 cycles. A bare steel plate was tested to determine the weight loss without a coating; surprisingly, the results were similar (45 mg of metal lost / 1000 cycles). Taber Abraser test information, although useful to compare coatings, does not answer the question of whether a coating will survive repetitive Frac Pack treatments.