The increased use of hole opening tools remote from the drill bit has led to a critical need to understand the interaction between the drill bit and the hole opening tool itself. Problems that can result from improper matching include vibration, inability to open hole, mechanical damage to string tools or to the bit, and sub-optimal drilling performance. This paper explores the theoretical relationship between bit and reamer and modeling the relative aggressivity and stability of both tools, building on already established indices for predicting and comparing the performance of bits. It reviews the calculations and methodology of placement and development of both the bit and reamer for optimal interaction and performance. It also considers stabilization of the hole opening tool using both concentric and eccentric devices. The paper also reveals the development of an interactive, intranet tool. This software incorporates logic regarding the configuration of the reamer and assesses these against key characteristics of the drill bit. The tool enables the user to accurately select the drill bit that best complements the reamer that will be utilized. A number of examples from global applications are presented. These demonstrate reduced vibration, improved hole quality and hole opening performance, superior penetration rates, and overall significantly reduced drilling costs.
There is a critical need to understand the interaction between a drill bit and underreaming tool in hole opening assemblies. Problems that can result from improper matching include vibration, inability to open hole, mechanical damage to string tools or to the bit, and sub-optimal drilling performance. Matching of the bit and reamer to avoid these dysfunctions is not a simple process, and certainly is not resultant from simply having a similar cutter size in both cutting structures, or from compromising the rate of penetration potential of the bit. There are four indices that substantially describe the performance of a bit and reamer system: Aggressivity; Stability; Durability; and Steerability. A tool that is capable of calculating the four indices for a bit and reamer allows optimal solutions to be developed for an application once the importance of the rankings are defined for that application. Accurate modeling of bit and reamer solutions must investigate the torque and weight balance in a number of different lithology scenarios. This must take into account the range of compressive strengths plus the type of transition encountered. Suitability of bits for specific reamers can be assessed using a sophisticated and novel reamer matcher tool. These can be tailored, via user input, to the specific parameters of the application. This matching tool uses logic tables based on theory, modeling, and field experience to provide a consistent, logical and quantitative approach to bit selection for reamers. Case studies are presented from deepwater applications that clearly demonstrate the value of the use of indices and reamer matching tool. In combination, these have enabled high efficiency drilling performance, reducing cost per foot to the operator.
Carbonate formation drilling with PDC drill bits often leads to accelerated catastrophic diamond table loss of the PDC cutter. Historically, PDC toughness related failures have been blamed on the bit/formation interaction producing destructive drilling dysfunctions such as; axial, lateral, and torsional vibrations. A number of design techniques have been applied to cutting structure/bit body design in an attempt to reduce the intensity and frequency of bit/formation interaction related drilling dysfunctions. These techniques were successful in reducing bit/formation interaction instigated drilling dysfunctions, however accelerated catastrophic diamond table failures were still observed at historical rates. This has led to the hypothesis that the accelerated catastrophic diamond table loss observed in carbonate formations is not exclusively related to drilling dysfunctions. The aforementioned hypothesis initiated a detailed study focusing on the relationship between cutting structure design and the damage observed from drilling carbonate formations. The results of this study clearly identified a relationship between hydraulic configuration, the relative magnitude and orientation of individual cutter’s impact force, and observed catastrophic diamond table failure. Several experimental PDC drill bit designs were constructed using different hydraulic and cutting structure design techniques. These techniques were aimed at reducing the hydraulic erosion potential of cutter substrates and normalizing forces across the majority of the cutting structure. The product of these experimental bit runs has been incredibly positive. In every case, the optimized hydraulic configuration and impact force normalized cutting structure design has outperformed the control designs while drilling carbonate intervals. This paper will focus on the performance differences between several control and experimental fixed cutter designs operating in the Anadarko Basin. The salient differences between these designs are the hydraulic configurations and the orientations of individual cutters on the control and experimental cutting structures. The slight modification of hydraulic configuration and individual cutter orientations (from control to experimental) has produced remarkable improvements in efficiency and durability. Several 7 7/8" diameter bit designs will provide the technical basis for this paper.
Salt formations present unique drilling challenges relative to other formation types of comparable compressive strength and abrasivity. Due to its unique properties, many detrimental issues can occur when employing bit designs which are not optimized for salt. These issues include severe stick-slip, lateral vibration, and poor directional control. In addition to high rig rates, Gulf of Mexico (GOM) projects typically use expensive BHA's. Consequently, improved drilling performance is seen as one of the enablers that can help reduce operational costs. Many considerations must be made relating to the design techniques employed in the development of Fixed Cutter (FC) bits for drilling salt intervals. This paper will focus on various design techniques developed for drilling a wide variety of salt sections in the GOM. Aspects such as load balancing, unique blade geometry and materials, gauge design, and utilization of secondary components will be covered. In addition, cutting structure design (cutter layout aimed at achieving specific performance objectives), as well as the analysis and adaptation of bit profile for improved performance will also be discussed. In summary, the paper will focus on a novel design philosophy that was developed and incorporated into an ultra-large diameter (26") FC drill bit. This concept was successfully utilized to extend the capability of drilling the 26" salt section with Rotary Steerable Systems (RSS) in the GOM. This was achieved while significantly improving penetration rates and lowering operating cost. Case studies are presented from the GOM that demonstrate true solutions to drilling salt in deepwater applications with FC drill bits. Introduction There are three primary forms of salt:Halite, or rock salt - Formed in either thin or massive layers. Occurs as a relatively soft white rock, with red or yellow coloring caused by impuritiesAnhydrite - This occurs extensively in beds associated with halite deposits. It is harder and less soluble than halite, and harder and denser than gypsum. It often occurs as fibrous, granular, or more compact masses.Gypsum - This is basically the hydrated version of anhydrite. It generally occurs in beds associated with layers of halite and dolomite. Salt is notably less dense than other sedimentary rocks. As a result, salt deposits tend to flow under pressure, as compared to either folding or faulting which occurs with lithologies such as sandstones and shales. Salt mobility occurs due to the difference in density between the salt and any surrounding sedimentary formations. Due to the lower specific gravity of the salt, it will tend to move upwards, in a similar manner as a lighter fluid would rise through an overlaying denser fluid. The actual rate of movement is mainly affected by temperature. This plastic flow (or deformation) allows salt to concentrate into large, domed-shaped masses1, where it can help to form oil traps. Salt deposits are found in a number of locations around the world, including Colorado and Utah (in the United States), Mexico, Spain, United Kingdom, Russia, Saudi Arabia, India, and the Gulf Coast region of the U.S. The latter is the focus of this paper. Extensive subsurface salt structures exist throughout the Lower Tertiary trend2 within the deepwater area of the GOM. These structures range from 2000 to 12000' in thickness and have trapped considerable amounts of hydrocarbons. The high purity of the salt in this region, combined with relatively low sub-surface temperatures, has resulted in slow-creeping salt bodies.
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