Operators demand continuous improvements in drilling efficiency to reduce their costs. Improvement in rate of penetration (ROP) is the most important factor in reducing variable costs and the drill bit is a critical element in this advancement.

Downhole bit balling is a common problem that negatively affects penetration rates. This is especially true when drilling large-diameter surface intervals. While these intervals are usually softer formations, they are often sticky and yield slower ROP than expected. Downhole balling is the most likely cause of these slower-than-expected penetration rates.

Improved research technology allows us to make improvements in hydraulic cleaning and now allows us to do much of the expected performance verification prior to actual field tests. This paper examines the research and development process undertaken to enhance hydraulic cleaning for reduced bit balling and improved ROP in roller cone bits larger than 121/4 in. in diameter. It also reviews the associated ROP improvements and subsequent cost reductions.

While there has been extensive research in hydraulics configurations for roller cone bits, the vast majority has involved smaller diameter bits. This research is still critical to studying hydraulic configurations, both for the small bits and bits in general, but we feel there is a definite need for increased research into hydraulics configurations specific to larger diameter bits.

It is important to understand the prior research that has brought us to this point. The first portion of this paper briefly details the background of some of the hydraulics research before going into the more recent large diameter bit research.

Background

Conventional hydraulics configurations for roller cone bits have basically been the same since the introduction of jet bits - three nozzle ports essentially directed fluid straight to the bottom of the hole. The flow was then forced back up the annulus without effectively cleaning the cones. In fact, it created stagnant zones, indicated by the yellow ovals in the graphics, which correspond to where inserts actually contact the bottom of the hole (Figure 1a). While this was the accepted configuration in the industry, it did not effectively clean the cones or the bottom of the hole. A more effective cleaning pattern was needed. This pattern was achieved with the development of the patented Mudpick (MP) hydraulics, which use slightly extended directional nozzles to precisely direct the fluid flow tangentially to the leading edge of the cutter trailing the nozzles. This action cleans the teeth or inserts prior to engagement of the cutting element with the formation and then cleans the bottom of the hole. It also shifts the previously mentioned stagnant zones closer to the annulus area and more effectively cleans the inserts that are actually contacting the bottom of the hole, as indicated by the green dots in Figure 1b. The improved cleaning effect of this hydraulics configuration delivered ROP increases of up to 25% in laboratory tests. Field tests produced ROP increases of approximately 15% to 20%.

Further testing developed other fluid-flow angles with continued improvements in cleaning the cones and the hole bottom. This led to the second generation of patented, directed-flow hydraulics commercially known as Mudpick II (MPII), which has a different flow angle and impingement point at the critical gauge area of the cones (Figure 1c). Laboratory tests of this angle delivered ROP increases of 70%, and field tests provided ROP increases of 15% to 50%. The precise nozzle direction required to achieve both patterns was arrived at through extensive testing in the ReedHycalog pressurized drilling laboratory (PDL) utilizing a pressure simulation vessel and visual flow chamber. The PDL is essentially a small drilling rig in the laboratory which provides the power for weight on bit (WOB) and rpm as well as flow rate and pump pressure through two 500-hp triplex pumps. Controls and all data gathering systems are computerized.

The pressure vessel is part of a closed mud system, which holds a core of specified rock formation that is subjected to different flow rates, mud weights and mud types to simulate downhole drilling conditions. The visual flow chamber is a clear acrylic cylinder representing the borehole that allows visual inspection of actual fluid flow through the bit nozzles. High-speed photography records the fluid flow patterns on the bit, and the film is played back frame by frame to assist in evaluating the test.
Thousands of bits with an extended and precisely directed nozzle configuration have been used worldwide. This nozzle configuration is now the most accepted way to increase ROP.

Big bit testing

The tests described in the previous paragraphs were performed with 77/8-in., 81/2-in., 83/4-in. and 97/8-in. bits and could not take design differences of larger diameter bits into consideration. While our large-diameter insert bits already utilize MPII hydraulics (and we had seen significant ROP improvements as a result), previous field tests of large-diameter tooth bits with that hydraulic configuration indicated some erosion on tooth hardmetal. Therefore, that particular angle was not used on commercial tooth bits and further testing had not been performed.

Previous laboratory testing was also limited to bit sizes 121/4-in. and smaller because of limitations imposed by test equipment. For more extensive testing on larger bits we designed and developed a visual flow chamber and pressure simulation vessel, which allows us to perform laboratory tests on bits up to 171/2-in. in diameter (Figure 2). Some design tools have also been improved.

Computational Fluid Dynamics (CFD) is now critical to hydraulics design. CFD is the science of predicting fluid motion as well as heat and mass transfer by simulating computer models. CFD uses physical laws governing the motion of fluid that are determined numerically by solving incompressible Navier-Stokes equations for the conservation of mass, momentum and energy. The computer calculations are extensive and may be used for:

• Velocity, pressure and temperature distributions;
• Bit and formation shear stresses ; and
• Flow turbulence information and flow path lines.

While CFD has been in use for several years, the models created in the past were forced to undergo many simplifications due to the inability of computer hardware to provide a simulated result in a satisfactory period of time. As computer technology has advanced, so has CFD, and it is now possible to provide accurate bit design models to simulate and predict the complex turbulent fluid path around a drill bit. More importantly, many hydraulic modifications may be processed as part of the design/research process to allow us to more accurately view actual flow patterns on a bit design prior to manufacture.

CFD computation results

Large-diameter simulation vessels and CFD were not available at the time of MP II development, so detailed tests had not been conducted to precisely determine the effects this hydraulics configuration has on cleaning. This was of particular interest because the distance from the nozzle to the cutter face and the bottom of the hole was substantially further from the exit point of the nozzle than with smaller diameter bits. The primary objective of the tests was to find an angle that delivered performance equal to MPII hydraulics without creating erosion on the tooth hardmetal. CFD modeling was performed on a 16-in. 1-1-5 IADC code bit with MP hydraulics. This was designated the standard bit in the tests. While the modeling on the standard bit displayed some cleaning action from the fluid, much of the action remained in the area directly below the nozzle exit. A change in the angle produced more sweeping action and moved the impact of the fluid closer to the cones prior to engaging the formation. This angle was chosen for the laboratory test bit. Once the optimized jet impingement had been finalized it was decided to build a prototype bit so that laboratory tests could be performed.

Laboratory test results

A performance baseline was established using the standard bit. The test bit used an identical cutting structure to help maintain controlled conditions. All tests were conducted under similar conditions: 45,000 lb WOB, 100 rpm, 300 gpm and 700 psi borehole pressure. All bits used three 14/32-in. jets with no center jet. HSI for these tests was held at 0.32 to help induce balling. There were 27 different PDL tests conducted on the standard and test bits drilling through the 36-in. cores of Mancos Shale. Cores would be drilled at consistent parameters, and the PDL would measure and record the ROP. The bits were pulled out of the pressure vessel following each test and inspected for the amount of balling.

Although there were different degrees of balling on the standard bit tests, the standard bit consistently displayed heavy balling tendencies (Figure 3a). The test bit was consistently much cleaner when pulled from the PDL tests (Figure 3b). The test bit had varying degrees of ROP improvement but achieved a higher ROP than the standard bit in all tests. Analysis of the data following the tests indicated that the nozzle angle in the test bit provided up to a 35% increase in ROP over the standard bit. Based on the laboratory tests it was recommended that a series of field test bits be built.

Field test results

The test nozzle angle was used on both 1-1-5 and 1-3-5 bits. Several applications were identified that typically suffer from downhole balling problems or were suspected to have downhole balling because of slow ROP.

At the time of publishing this paper, field tests had been performed in three different applications, all offshore. Three 1-1-5 bits have been run on the Northwest Shelf in Australia, one 1-1-5 bit has been run off the east coast of Canada and two 1-3-5 bits have been run in the Mediterranean Sea off the coast of Egypt.

It is generally understood that it is extremely difficult to precisely duplicate field conditions from well to well to ensure accurate field test data. However, we were able to field-test our new bits directly against our standard bits in two of the three cases. In all cases, we were diligent in comparing bits with like-run conditions as closely as possible.
Australia. The standard bits and test bits for this application, which carry an IADC code of 1-1-5, are the same as used in the laboratory tests. The formations drilled consisted of siltstone, claystone, marl, limestone and calcarenite.
In a vertical well, a test bit was run against four of the standard bits and four other runs we will refer to as X. The WOB, rpm and total flow area (TFA) were similar in all cases. Center jets were run in all bits. The test bit had 10% less flow rate than the next closest flow rate and 32% less than the highest flow rate.
The test bit drilled at an average ROP of 160 ft/hr (48.5 m/hr), 42% faster than the average ROP of the standard bits. The test bit also drilled 15% faster than the X bits. No increased erosion was observed on the test bits.

In a directional well, two test bits were run against three standard bits and four X bits, Once again, WOB, rpm and TFA were similar throughout the bits in the study. The two test bits drilled the longest and third-longest intervals, respectively. Formations drilled were the same as in the vertical tests. All bits started drilling at 0° and built to an approximately 25° inclination.

In this case the test bits drilled at an average ROP of 191.6 ft/hr (58.4 m/hr), 30% faster than the average of the standard bits. They also drilled 21% faster than the X bits in the study.

Canada. There were no standard bits run in this area for comparison of identical cutting structures. However, there were two X bits used with the same 1-1-5 IADC code as the test bit, so the cutting structures were similar. The bits were all run in the Banquereau formation, which consists primarily of claystone, limestone and siltstone with traces of chert and quartz pebbles. All runs were directional, with the final inclination ranging from 17.8° to 53°. The test bit had the highest build rate at 53 degrees and the longest run at 4,652 ft (1,418 m). The test bit drilled an average ROP of 353.6 ft/hr (107.8 m/hr) while the X bits drilled an average ROP of 191.2 ft/hr (58.3 m/hr). This is a 45.7% increase over the X bits.
It is possible that the large difference in ROP between the test bit and the bit run on well A-1 is due to the improved cleaning on the gauge area of the test bit's cones, providing improved side-cutting action. No increase in erosion was reported.

Egypt. The application for this test was harder than the previous tests and required harder formation bits. The bits used are designated as 1-3-5 IADC code and, therefore, have a higher tooth count and shorter tooth protrusion than the bits in the other field tests and in laboratory tests. However, the nozzle angle for the standard bits in this test was the same as for the other tests. Therefore, we will refer to them as standard bits. The nozzle angle for the test bits in this test was the same as the test bits in the other tests and we will refer to them as test bits. The other bits in this test had similar cutting structures and will be referred to as X.

This test was more difficult to evaluate and provided conflicting results. In an effort to normalize the data, runs were separated into bits with a shallow entry point of 33 ft (10 m) and a deeper entry point of 1,142 ft to 2,625 ft (348 m to 800 m). This also split the offset runs into deviated trajectories in the deeper entries and essentially vertical holes on the shallow entry runs.

One test bit was in the deeper entry point category and displayed significantly slower ROP. However, it was a side-track run so it is difficult to accurately compare, and it was not considered in the test results.
The other test bit fell into the shallow entry category but drilled the longest interval of all the offset runs and included the highly deviated lower interval. When compared to the vertical wells it was 18% slower than the standard run and 34% slower than the X run. However, it drilled 108% more interval than the standard bit and 51% more interval than the X bit.

When compared to the deeper entry directional runs the test bit drilled 5% slower than the X average but 20% faster than the standard average. It also drilled at least 25% more interval. Other than the test bit, one standard bit drilled a comparable interval (only one meter less) and had a 3% slower ROP. However, it drilled in the more difficult lower entry point category and had the highest build rate.

The variations in the data and the inconsistency of the results warrant further testing using this cutting structure. We will also construct CFD models with this cutting structure to determine if a different nozzle angle may be required.

These tests did allow us to evaluate the erosion potential of this nozzle angle on the cutting structure. Both bits were run for extended periods, 113 hours, with no increase in erosion noted.

Conclusions

While the number of field tests provided a smaller number of data points than preferred, it should be noted that the number of proper applications in large diameter bits is less than in small diameter bits. Therefore, extensive prior research was taken into consideration when making some recommendations.
Complex CFD modeling of the bit was used to study flow characteristics and determine the optimal impingement angle. The CFD models delivered a nozzle angle that provided more bottom hole sweeping action than MP hydraulics and placed the impact point of the fluid closer to the cone.
The performance viewed during the full-scale laboratory drilling tests indicated that the new nozzle angle would enhance cleaning properties and reduce the onset of bit balling, resulting in higher ROP. Field tests in different applications verified laboratory findings. Field tests also indicate that this particular nozzle angle does not increase erosion on the cutting structure. While this nozzle angle is not exactly the same as the MPII angle on insert bits, it provides an optimized nozzle for the 1-1-5 tooth bits. As noted, further tests will be performed on the 1-3-5 bits.

ROP is the most important variable when calculating drilling costs since it directly affects drilling time. With other costs being equal, a 35% increase in ROP translates into a 35% reduction in drilling time and subsequent costs.

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