To improve the industry’s ability to efficiently and economically drill deep wells by improving rate-of-penetration (ROP) performance of drill bit and fluid systems.
TerraTek, Inc., Salt Lake City, Utah 84104
This project addresses improvements in deep well drilling performance through rigorous proof-of-concept testing of new drilling components at high borehole pressures on the order of 12,000 psi. Terra Tek has assembled a team of Industry and Academic contributors who are recognized leaders in hostile environment drilling operations, engineering development and large-scale testing, downhole tool engineering and supply, mechanics and rock cutting characterization, rig pump manufacturer, and commercial experience. Objectives for this project include: Phase I – Benchmark ‘best in class’ diamond and other product drilling bits and fluids and develop concepts for a next level of deep drilling performance, Phase 2 – Develop advanced smart bit-fluid prototypes and test at large scale, and Phase 3 – Field trial smart bit-fluid concepts, modify as necessary and commercialize products.
The relevance of benchmarking downhole tool performance at high pressures and developing innovative impregnated bit cutting structures is highlighted by the technical challenges operators are facing. As noted by BP’s senior drilling engineer for the Tuscaloosa trend, “over 50% of the rig time is spent in the last 10% of the hole.” The Tuscaloosa sands produce from depths greater than 20,000 feet and provide one of the scenarios for the Phase 1 test matrix. The deep Arbuckle is the other one. Increasing the rate of penetration and reducing rig time will lower costs and improve the economics in drilling for deep gas reserves.
Test results have revealed that under high pressures, adding weight to water or “base oil” can reduce performance up to 80-90 percent while drilling in hard sandstone. While diamond product bits generally showed substantial performance advantages compared to roller cone bits, the cuttings were much smaller than expected suggesting that the bit is doing more grinding than previously believed.
Tests intended to model challenging stratigraphy in the deep Tuscaloosa and Arbuckle plays highlighted several combinations of bits and drilling fluids that exhibited ROPs significantly at or above ten feet per hour, in some cases exceeding 50 ft/hr. These findings provide a significant opportunity for reducing well costs and improving the economics of deep exploration and development plays in the Rocky Mountains, Tuscaloosa trend, and Anadarko basin in particular.
Large-scale laboratory testing of downhole drilling tools at simulated deep conditions has a proven track record in determining actual performance and identifying crucial design parameters. Establishing a benchmark of drilling ROP in selected simulated deep formations provided a basis for analyses and design improvements. These improvements in both bit and drilling fluid design were further tested with a goal to significantly improve ROP through team development of aggressive diamond product drill bit and fluid system technologies. Utilization of this improved technology by the industry as the potential of increasing ROP which can significantly reduce drilling costs and improve the economics of drilling for deep gas reserves.
TerraTek finished their Phase I testing of their Deep Trek project May, 2005. This data was used for design improvements in bits and drilling mud for testing in Phase II. A series of 16 tests were run, half with water base mud and half with oil base mud. Four different bits were used: a 4-blade and 7-blade PDC, a roller cone and impregnated bit. Rock samples used were Carthage Marble, Crab Orchard Sandstone and Mancos Shale. The intention here was to model drilling environments in the Arbuckle and deep Tuscaloosa trends. These tests were run with a borehole pressure of 10,000 psi, a first for a drilling simulator test vessel in the industry. Hughes Christensen and Baker Hughes Drilling Fluids, both divisions of Baker Hughes, provided the bits, mud and an extra mud pump in support of these tests. Other industry participants have provided drilling data and technical input. Test results show that under high pressures, adding weight to water or “base oil” can reduce performance up to 80% to 90% while drilling in hard sandstone. Diamond product bits generally show substantial improvements against that of roller come bits. Also, cuttings were much smaller than expected suggesting that the bit is doing more grinding and cutting of the rock. Data from these tests were presented at the DEA (Drilling Engineering Association) Workshop in Galveston at the end of May 2006. NETL was a co-sponsor of the workshop and DEA is a co-sponsor of this project. A paper titled “Optimization of Deep Drilling Performance: Benchmark Testing Drives ROP Improvements for Bits and Drilling Fluids” was presented at the 2007 SPE/IADC Drilling Conference in February 2007. This paper highlighted the results of Phase II testing.
Phase II testing was completed the first week of September, 2006. Twenty-one full scale tests of 6” bits and drilling fluids were conducted with identical drilling parameters and rock samples as used in the benchmark testing. As in the benchmark testing, sample lithologies drilled intended to model challenging stratigraphy in the deep Tuscaloosa and Arbuckle plays. Carthage Marble, Crab Orchard Sandstone and Mancos Shale were the rock types drilled in these tests. Bit design changes included adjusting the cutter angle for the 4 and 7-blade PDC bits as well as providing a long profile blade for a second 7-blade PDC bit. The grit size was modified on the impreg bit. Several drilling fluid designs were selected for the second test matrix which included an 11 ppg water base and a 16 ppg oil base fluid. Other drilling fluids tested were a 16 ppg cesium formate, with and without solids, and several modifications of the 16 ppg oil base fluid to include a lubricant, an altered solids distribution material and MicroMax. Testing here focused on the drilling fluids as the benchmark test suggested that there is more advantage to be gained here in improving ROP. Several tests in the second test matrix were designed to tie directly back to the benchmark tests, providing comparison across all thirty-seven tests conducted.
Test results show that several combinations of bits and drilling fluids exhibited ROP’s at or above ten feet per hour. For the drilling fluids, the cesium formate exhibited the best ROP in the Carthage Marble and Mancos Shale. The PDC bits exhibited better ROP in all three lithologies over the impreg and TCI bit. The ability to increase ROP from two to five feet per hour to as much as ten feet per hour in the hard rock stratigraphy of deep oil and gas plays provides a significant opportunity to reduce well costs and improve the economics of deep exploration and development plays. These plays include the Rocky Mountains, Tuscaloosa trend, Anadarko basin, and many other areas. The net result for operators is cost reduction as well as an improved position on reserves. Asummary of the Phase II findings was presented to the DOE in Morgantown in January 2007. A similar presentation was given at Drilling Engineering Association meetins in Houston in March 2007 and Galveston in June 2007.
This project is completed. A re-direction of funding has precluded the ability to conduct Phase III of this project. The final report is available below under "Additional Information".
Final Project Report [PDF-822KB] - January, 2008
Technology Assessment [PDF-115KB]
Judzis, A., Collins, G. and T. Grant, 2006, Drilling Advancements Essential to Deep gas Recovery, GasTIPS, vol. 12, no. 1, p. 18-20.
Judzis, A., Grant, T., Curry, D., and R. Bland, 2005, Benchmark testing improves ROP, Hart’s E&P, November 2005, P. 97-99.
Judzis, A., Bland, R.G., Curry, D.A., Black, A.D., Robertson, H.A., Meiners, M.J., and T. C. Grant, 2007, Optimization of Deep Drilling Performance; Benchmark Testing Drives ROP Improvements for Bits and Drilling Fluids, Society of Petroleum Engineers, paper 105885
Benchmark testing improves ROP. Hart’s E&P, November 2005, pages 97 – 99.