Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
Performance analysis of large numbers of bit runs is often anecdotal and uses historical cost data. To this end, there are numerous problems with this approach. There is no uniform approach to identifying good performance. At best, the analysis provides an imprecise picture of overall performance. Large datasets need to be condensed into runs of interest. Difficulties arise when comparing multiple runs through long intervals with variable thicknesses of hard stringers. Since BHA, rig, and other costs change over time, it is problematic using historical cost per foot (CPF) data for the current target well. Finally, how does one determine if long slow runs or short fast ones are better since both could have the same CPF?
In this paper, the authors discuss a structured benchmarking method that can be applied regardless of the application or area studied. The basic process is simple and can be tailored to the requirements of different applications. The goal is to deliver a statistical benchmarking process that helps filter large sets of data and facilitates a consistent approach to bit performance analysis that is independent of historical cost data. A process flow chart is developed to guide engineers step-by-step through the benchmarking method. Good offsets are identified and included in the benchmarking population. Eligible bit runs are then ranked by a new key performance indicator (KPI): ROP*Distance Drilled. No historical cost data is included in the analysis. A detailed engineering study is then carried out on the identified best runs to develop recommendations for future applications. As the last step of the process, a financial analysis is carried out using cost data for the current well.
The paper will describe the use of this process to analyze bit performance in the operator's gas drilling operation and show how it allowed the identification of ‘true' unbiased top performance. The benchmarking process standardizes performance analysis and ensures sound engineering principles are applied resulting in a better understanding of past performance and better recommendations for future applications.
Many drilling engineers still associate the use of impregnated bits for hard and abrasive formations with the use of hydrodynamic turbines. In fact, turbines were the first high speed direct bit drive systems on the marketplace - providing maximum bit speed, long life on bottom and, due to the lack of elastomers in the power section, could be used in high temperature environments. However, turbines offer low drilling efficiency, especially in combination with low flow rates, and are very expensive to build and maintain. Positive displacement mud motors are more cost effective and show much better efficiencies, even at lower flow rates, but used to survive fewer hours on bottom and tended to fail at higher bottomhole temperatures. Current manufacturing technologies, especially the capability to manufacture pre-contoured stator tubes covered with a thin layer of elastomer, have helped to overcome the above mentioned problems. Today's latest generation high speed mud motors combine the industry's highest bit speeds with unmatched torque - resulting in a power output of up to 1000 HP. These motors can be used in temperatures up to 160 C and have survived numerous runs consisting of hundreds of hours of on-bottom drilling time without failure. The paper describes latest developments in mud motor design and shows case histories of motor runs from different vertical and directional wells of various hole sizes across multiple continents. Premium drilling performance is not only dependent on the availability on latest mud motor technology, but requires a detailed understanding of the entire drilling process as well as the optimization of the drill rig, the drill string, the BHA and the bit. Special attention is therefore given to an ongoing optimization project, which has taken place in close coordination between a service company and an operator in North Germany. Drilling the very hard and abrasive Bunter Sandstone used to be a time consuming and costly enterprise. Within few years the ROP could be doubled and the distance drilled per BHA could be tripled.
The very hard, abrasive Middle and Lower Bunter Sandstones in Northwest Germany is very difficult to drill. Economic success is only achievable with impregnated diamond bits which possess a very small depth of cut, as they work like sand paper. Based on several case studies from the Middle East and Italy, it is typically assumed that there is a linear relationship between the rotating speed and the penetration rate of an impregnated bit (i.e., if bit speed is doubled then penetration rates also double). The same rule applies for weight on bit (WOB). Maximum penetration rates therefore require both high WOB and high bit RPM.
The situation is more complex in the North German Bunter Sandstone. A series of drill-off tests indicated that high penetration rates could only be achieved at very high mud flow rates. Using the test data, optimal flow rates were extrapolated. However, these rates clearly exceeded the technical limits for the existing rigs, drillstrings, and BHA's - especially in the commonly used hole size 12 1/4".
In recent years, some dedicated drilling rigs were equipped with stronger mud pumps and larger diameter drill pipes to enhance drilling performance in these applications and the higher flow rates did increase the penetration rate. Additional improvements were made by introducing impregnated bits with an interrupted cutting structure. However, optimum conditions could still not be achieved as the system's hydraulic "bottleneck" shifted from the rig equipment and bit to the downhole BHA - specifically the high-speed motor.
The paper describes latest developments and features of a new, custom-engineered 9 1/2" high-speed motor for drilling the Bunter Sandstone. This high-performance motor provided a 25% increase in flow rates vs. previously used motors. Due to its extreme bit speed and unmatched torque capabilities, the motor is the first commercial downhole motor in the field breaking the 1000 horsepower (HP) limit. The combination with a customized drill bit led to another step change in downhole performance. Case histories from Germany are used to demonstrate, how ongoing combined efforts from an operator and a service company lead to doubled penetration rates and tripled the footage of continuous BHA runs in the hard and abrasive Bunter Sandstone.