John Lewis
BBL Brit Bit Ltd.
Aberdeen
Arthur Dacre
Mobil North Sea Ltd.
Aberdeen
Lateral nozzles built into specially manufactured polycrystalline diamond compact (PDC) bits improve hydraulics at the bit face, thereby increasing penetration rates.
The new bit manufacturing process, investment casting, uses a unique body material for PDC drill bits, allowing design freedom for a lateral-jet-hydraulics concept.
Lateral jets set into the blades of the bit improve the cutter cleaning efficiency. In addition to cleaning the slot in front of the blade, the jet creates a venturi effect drawing the fluid across the blades serviced by the downward jets. This flow is then ejected at high speed to the junk slots. Increased efficiency of cutter cleaning can directly improve the rate of penetration (ROP).
Several wells drilled in Mobil North Sea Ltd.'s Beryl field in the U. K. sector of the North Sea showed direct benefits of lateral nozzles. The lateral jet bit runs had more footage and greater ROPs than other similar bit runs.
PDC drill bits have been available for more than 20 years, and bit manufacturers have steadily improved the design and quality of their products by using advances in technology. Research and development on bit profile, cutter types, cutter sizes, cutter layouts, and hydraulic configurations have had varying degrees of success.
Lateral jet hydraulics have greatly contributed to the improvement in performance of PDC bits. There is potential for further development and wider application of the concept.
With the exception of the bits discussed in this article, the crowns or bodies of all fixed-cutter bits are either tungsten carbide matrix (powder metallurgy) or steel.
The fundamental advantages or benefits of these two body materials and manufacturing processes are covered in the drilling literature by Feenestra. 1 The basic arguments (tungsten carbide matrix vs. steel) are erosion resistance vs. ductility with hard facing, perceived cost advantages of machining vs. casting, and gauge protection of natural diamonds vs. inserts, respectively.
Although the manufacturing processes have undoubtedly been refined and improved by various manufacturers, the preceding arguments have not changed to any degree since Feenestra's paper was written in 1988.1
For the design concept of a laterally focused jet to be incorporated into a commercially viable product, a new manufacturing process was needed. In 1986, investment casting, then primarily used by the aerospace industry, was identified as feasible.
INVESTMENT CASTING
The investment casting, or lost wax process, manufacturing method dates back several thousand years and was used to produce fine articles from gold and other castable metals. For every mold a wax model must be invested, hence the name investment casting.
To make a mold, a wax model is coated in a slurry of clay and fine silica sand and allowed to dry. A second coat is added and coarser sand is rained on to the wet slurry as reinforcement and then allowed to dry. This process is repeated a number of times to build sufficient shell thickness to withstand the forces applied during casting.
The wax and its shell then go though a furnace cycle which melts out the wax and bakes the shell, leaving a perfect impression of the invested wax. Thus, for each mold a new wax is required. It is therefore the wax which controls the quality, repeatability, and accuracy of the final casting. These waxes can be injection molded in a set of mold dies. (The dies can rapidly produce large numbers of identical, high-quality wax models of the component and from these an exact mirror image mold can be produced in the form of a ceramic shell.)
Investment casting is a well accepted method of producing many engineering and aerospace products (for example, engine rocker arms, turbine engine blades, and parts of military weapons). This process was considered suitable for producing relatively small (11-22 lb) high-quality castings. The process was of particular interest because of the wide range of metals and alloys that could be cast, especially in the high melting point, super-hard alloys, such as those based on cobalt and nickel (for example, stellite).
DRILL BITS
In 1986, the potential was realized for the use of this process for casting oil field bit crowns. Considerable work was required to develop processes capable of producing the very large casting necessary for drill bit crowns.
The reward has been the ability to manufacture large drill bits in super alloys that combine the properties of high strength, wear, and erosion resistance from high quality castings requiring a minimum of machining. Additionally, internal details such as complex flow path geometry to the nozzles can be formed with the same high quality and accuracy of the external shape, providing flexibility of design for hydraulics.
Investment casting has the following advantages over the conventional fixed-cutter bit manufacturing process:
- Potential for the use of superior metal alloys for the bit crown or body to combine the advantages of both steel and matrix bits
- Flexibility of design and most importantly its suitability for the cost-effective production of the lateral jet-type drill bit.
LATERAL JETS
The most unusual feature of the new bits is the inclusion of two central lateral jets, in addition to two or four interchangeable downward nozzles (Figs. 1 and 2). The jets are set opposite each other in the crown and direct a portion of the drilling fluid laterally across the debris slots. In addition to cleaning the slot in front of it, the jet creates a venture effect, drawing the fluid across the blades serviced by the downward jets. This flow enhances cutter cleaning and cuttings removal.
Hydraulic optimization plays an important part in the improvement of drilling bit performance.2 Many studies show that jetting improves the penetration rate. For PDC bits, however, the influence of the nozzle jets on the flow behavior is still relatively unknown. Until King's research on PDC hydraulics, roller cone bits had mainly been studied.2 Lateral jetting was not evaluated in this study, but the results were obtained through the analysis of jets at several inclinations (0, 11, 45, radial, and azimuthal).
There have been very few visualization studies of the flow beneath a bit.3-7 One visualization method involved sketching some flow lines inferred from measured cross flow velocities. Another method used dye injection to study the flow pattern from the nozzle in a PDC bit, but the utility of such a technique was low.5 Another method tried neutrally buoyant beads which were tracked photographically and the results projected onto a horizontal plane.6 One researcher determined that the flow pattern in a wing-type bit was very complex. The flow area through the different wings of the bit are not reliable indicators of the velocity distributions, and the hydraulic design of a PDC bit is one of the most crucial factors affecting its drilling performance.7 8
The lateral jet concept has increased the rate of penetration of PDC products in known quantifiable applications up to as much as 70%. Increased performance has been observed across a broad spectrum of applications, from shale and mudstones with sonic transit times greater than 140 u sec/ft to hard limestones with sonic transit times as low as 44 u sec/ft. The increased penetration rate has not been confined to oilbased or water-based mud. The geographical area of performance improvement has extended from the North Sea to the Arabian Gulf.
Although the entire theoretical effects of lateral jetting are not precisely definable at this time, the practical results and the benefits afforded by the technology are worthy of further research. The current concept demonstrates a technological advancement over conventional down-jet hydraulics.
INITIAL CONCEPT
The initial concept to use lateral jetting was based on extensive field data which confirmed that nozzle inclination and cross flow had a positive influence on drill bit performance.
The degree to which nozzle inclination had been applied in the past had been clearly influenced by drill bit geometry and the two main manufacturing processes (steel body and matrix). These factors especially influenced roller cone bits because the geometry was well defined (and restricted) with respect to nozzle placement.
The advent of fixed-cutter PDC drill bits provided the designer with what appeared to be infinite scope for hydraulic design and nozzle placement. Thus, there is a vast array of differing configurations of fixed cutter bits on the market.
Despite this apparent diversity, it is interesting to note that the majority of drill bits currently available have jets directed toward the formation at an angle close to 90 to the point of impact. This setup is greatly influenced by manufacturing constraints and, to some degree, conservatism within the industry towards known and tested hydraulics.
The steel body and matrix manufacturing methods have limitations in this area, and some of these limitations can be seen from these types of bits in the market place. The vast majority of these bits have their nozzles arranged such that their position and inclination angles align the axis of each nozzle to intersect the central bore of the bit. This arrangement would suggest that a significant compromise is being made to the bit hydraulics to conform to the limitations of manufacture.
The main manufacturing constraint that affects nozzle inclination is the difficulty in machining curved flow paths from the central bore of the bit to communicate with the desired nozzle position and its inclination angle. If optimized bit hydraulics dictate that nozzle position and inclination are such that the axis of the nozzle does not pass through the central bore of the bit, then the inability to form curved internal flow paths is a severe limitation to the scope of the designer (Fig. 3).
The introduction of investment casting as a third manufacturing method was key to changing this approach and allowing nozzle position and inclination angle to be modified dramatically. Investment casting allows the forming of curved and complex geometry flow paths within the bit crown. The bit designer thus has a greater degree of flexibility to place nozzles in positions and at angles that will optimize their effect on drill bit performance.
HYDRAULICS
The bits discussed in this article are fitted with six nozzles: our conventional downward-facing jets which direct their flow towards the formation at an angle of close to 90 and two lateral jets which direct their flow from the center of the bit towards the exit junk slots at a very shallow angle to the formation (Figs. 1 and 2).
In fact, one of these central lateral jets has been placed just behind center and directs its flow across the center of the rotation of the bit.
The four conventional downward jets are deeply set below a high blade profile and create significant levels of turbulence in their respective sectors (Fig. 4).
The lateral jets are set to direct flow along the length of the two primary blades of the bit. Because of the entrainment effect caused by a jet of fluid, the lateral jets draw a large percentage of the flow exiting from the down jets across the blades of the bit ejecting the fluid from both the down and lateral jets out of the junk slots.
The lateral jet bit has two different flow regimes:
- Down-jet flow which strikes the formation after a short travel distance, creating turbulence and breaking any loose formation away from the bottom of the hole
- Lateral-jet flow which is directed at a shallow angle and does not strike the formation for an appreciable distance, creating a fastmoving flow of fluid across the hole bottom which sweeps towards the junk slots.
Because the bit is not normally static but is in rotation, the hole bottom experiences an alternating flow pattern which occurs twice per revolution of the bit: turbulent flow then sweeping, turbulent and sweeping, etc.
FLOW VISUALIZATION
In developing an hydraulic design, there are other considerations besides cleaning and removal of cuttings from the bit face. For example, each PDC cutter must also receive sufficient fluid flow for cooling and cleaning. Extensive flow visualization testing was conducted to create the fine balance of cooling and cleaning.
This work has taken place at a number of locations:
- Terratek USA, Salt Lake city
The effect of jet impact on rock pore pressure was studied for a variety of different nozzle types and formations. This work was carried out under downhole conditions with a series of pressure transducers installed in the rock samples in front of and to the side of an advancing bit.
In this way, the rock pore pressure could be monitored as the bit approached and drilled through, or passed close to, each transducer. In addition, information on vibration and drilling rate was also recorded for each hydraulic configuration. The information gained in these preliminary tests was useful, although inconclusive.
- Koninklijke Shell Exploration & Production Ltd. Rijswyk, Holland, and inhouse at the lateral jet "manufacturer in Aberdeen
The Shell flour powder test procedure was applied to the lateral jet product as a means of hydraulic-flow visualization. This test works on the principle that air, which is exiting the nozzles at sufficient velocity to be fully turbulent, will behave in a similar way to drilling mud at the bit.
The introduction of flour into the air stream leaves patterns on the bit body and around the cutting structures providing information to establish areas of stagnation or high turbulence. The flour pattern also provides information on flow velocity and direction. This test procedure has now been substantially modified from the original test introduced by Shell and is now used by the lateral jet bit manufacturer for a standard verification check on all new bit designs to ensure adequate cutter cooling and cleaning.
- International Downhole Drilling & Technology Centre (Iddtc), Aberdeen
The effects of nozzle strike and distance have been studied under downhole conditions at the Iddtc test rig at Bridge of Don, Aberdeen. This work program was a continuation of the initial studies previously conducted at Terratek. The tests were conducted in a high-pressure test chamber which had been designed and built by the lateral jet bit manufacturer in-house. A test sample is held at the lower end of the test chamber with a rotating nozzle test head located above the sample. The strike distance of the nozzle from the test sample could be varied.
A variety of nozzle types have been tested to date, providing substantial useful data. A further study program is therefore being planned. Ongoing research relating to the new potential hydraulic and physical design characteristics made possible by investment casting techniques is being carried out in Aberdeen.
BERYL FIELD RESULTS
The Beryl field, operated by Mobil North Sea Ltd., is in U.K. Block 9/13 in the northern North Sea approximately 180 miles northeast of the Scottish mainland and 100 miles south of the Brent field in an average water depth of 400 ft (Fig. 5). The Beryl field was discovered in 1972 with the drilling of the 9/13a-1 well.
Following appraisal drilling, the Beryl Alpha 40-slot Condeep platform was installed and production started in 1976. Beryl Bravo, a 21-slot steel jacket, was added in 1984. To date, 57 Beryl Alpha wells, 30 Beryl Bravo wells, and 14 subsea wells have been drilled to develop the field. Oil production has been maintained at around 100,000 bo/d since 1979, with gas and water injection for pressure support.
Exploration and appraisal drilling around Beryl have defined several smaller satellite fields: Nevis, Katrine, Ness, and Linnhe. The Ness subsea template is tied back through the Beryl Bravo platform. Other noncommercial hydrocarbons have been discovered above the field in the Paleocene and Eocene reservoirs.
Mobil North Sea has operated a real-time, data-acquisition system over the past 18 months. This system has made is possible to recall data for analysis. Making direct comparisons of drilling performance on wells during this period has been difficult, however, because almost every well investigated has differed significantly from the others drilled during this time frame.
Fig. 6 identifies the formations typically drilled with 12-1/4-in. (311 mm) PDC bits: Early Cretaceous limestones, claytones and thick Late Cretaceous marls and limestones, Jurassic Kimmeridge claystones, and Heather shale.
Mobil's experience with the lateral jet bit through these intervals indicates that bit runs in excess of 1,500 ft with high-average ROPs (in the range of 50 ft/hr) are possible (Table 1).
The Beryl sandstones and shale, Triassic Raude shale, and Lewis interbedded sandstone shales are typically drilled with 8-1/2-in. (215.9 mm) PDC bits. Recent wells drilled with the lateral jet bit have shown high ROPs (38-63 ft/hr), with long bit runs of up to 2,306 ft (Table 1). Pyrite stringers often present in the Kimmeridge, Heather, and Beryl formations are found less frequently in the Triassic formations.
Recent changes in well profiles have resulted in a number of deep sidetracks from existing 9-5/8-in. casing by either section milling windows or setting "packstocks" (a whipstock with a packer). This new well profile has very long 8-1/2-in. sections drilled from the top of the Cretaceous to total depth in the Lower Beryl sandstone. Bit longevity and ROPs on these runs with the lateral jet bit have been good, with very high ROPs where flow rates have not been restricted by the use of logging while drilling tools. Fig. 7 shows that increased flow rates from 550 gpm to 600 gpm have improved hydraulics, resulting in marked increases in ROPs averaging up to 89 ft/hr for a 1,577 ft bit run. (ROPs averaged over 5-ft intervals were in excess of 290 ft/hr.)
Mobil is pleased with the performance of these bits and is now using them with some success in southern North Sea operations and on a recent well drilled off the coast of southern Ireland.
ACKNOWLEDGMENT
The authors thank Mobil North Sea Ltd. and BBL Brit Bit Ltd. for their cooperation and approval for the publication of this article. The authors also thank M. Wardley and G. Bumett for their help during the preparation of the article.
REFERENCES
- Feenestra, R., "Status of Polycrystalline Diamond Compact Bits," Journal of Petroleum Technology, June 1988.
- King, I., Bratu, C., Delbast, B., Besson, A., and Chabard, J.P., "Hydraulic Optimisation of PDC bits," SPE paper 20928.
- White, D.S., et al., "Flow patterns under a rock bit," presented at the 1987 Society of Petroleum Engineers annual meeting.
- McLean, R., "Crossflow and impact under jet bits," Journal of Petroleum Technology, 1967, pp. 1229-1306.
- Glowka, D., "Optimisation of bit hydraulics configurations," SPE paper 10240, 1982.
- Cholet, H., and Crausse, R., "Improved hydraulics for rock bits," SPE paper 7516, presented at the SPE Annual Technical Conference and Exhibition, Houston, October 1978.
- Cruz, A.M.G.L, "Simulation of the flow pattern in a wing type PDC bits," Koninklijke Shell Exploration & Production Ltd.
- Cruz, A.M.C.L., "Hydraulic characteristics of a fish tail type PDC
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