Ultra-large diameter bit designed for GOM salt sections through cutting-structure solutions

Posted on 13 July 2010

By Steve Barton, Ryan Weeden, NOV Downhole; Graham Mensa-Wilmot, Yoseph Harjadi, Chevron

Figure 1: In earlier industry attempts to design a bit to drill challenging salt intervals in the Gulf of Mexico, fixed-cutter bits with a gauge ring were developed to improve directional response by improving the lateral stability of the bit, reducing the propensity of the bit to whirl. By minimizing lateral vibration, the ring bit reduces torque fluctuations that can occur due to bit whirl. This reduces the potential of the bit to laterally over-engage the formation, which can cause issues with the directional tool.

Figure 1: In earlier industry attempts to design a bit to drill challenging salt intervals in the Gulf of Mexico, fixed-cutter bits with a gauge ring were developed to improve directional response by improving the lateral stability of the bit, reducing the propensity of the bit to whirl. By minimizing lateral vibration, the ring bit reduces torque fluctuations that can occur due to bit whirl. This reduces the potential of the bit to laterally over-engage the formation, which can cause issues with the directional tool.

Salt formations present unique drilling challenges relative to other formation types of comparable compressive strength and abrasivity.  Due to its properties, many detrimental issues can occur when using bit designs that are not optimized for salt. These include severe stick-slip, lateral vibration and poor directional control.

Gulf of Mexico (GOM) projects typically have to contend with high rig rates and the use of expensive BHAs, and improved drilling performance 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 article will focus on various design techniques developed for drilling a 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 the bit profile for improved performance, will be discussed.

The focus will be on a novel design philosophy that was developed and incorporated into an ultra-large diameter (26-in.) FC drill bit. This concept was successfully used to extend the capability of drilling the 26-in. salt section with rotary steerable systems (RSS) in the GOM. This was achieved while significantly improving penetration rates and lowering operating costs.

Case studies are presented from the GOM that demonstrate true solutions to drilling salt in deepwater applications with FC drill bits.

THE FORMS OF SALT

There are three primary forms of salt:

1. Halite, or rock salt, forms in either thin or massive layers. It occurs as a relatively soft white rock, with red or yellow coloring caused by impurities.

2. Anhydrite 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.

3. Gypsum 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, compared with 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 salt, it will tend to move upwards, 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 masses where it can help to form oil traps.

Salt deposits are found in many locations around the world, including Mexico, Spain, United Kingdom, Russia, Saudi Arabia, India, Colorado and Utah onshore the United States, and the Gulf Coast region of the US. This article will focus on the Gulf Coast.

Extensive subsurface salt structures exist throughout the Lower Tertiary trend within the GOM deepwater. These structures range from 2,000 ft to 12,000 ft in thickness and have trapped considerable amounts of hydrocarbons. The high purity of the salt in this region, combined with relatively low subsurface temperatures, has resulted in slow-creeping salt bodies.

These properties of salt lead to several distinct drilling challenges in the Gulf. These include:

•  Hole creep – Salt may extrude (or “creep”) into the wellbore due to its plastic nature. This creep can potentially cause stuck pipe and fatigue damage to the drillstring. The rate of creep will depend on the specific properties of the salt, pressure and temperature. An increase in the last two tends to increase rate of creep.

•  Washout – Salt is soluble. Under certain conditions, salt will dissolve and result in borehole enlargement. This causes unpredictable directional tendencies, poor BHA performance and stability issues.

•  Formation pressure issues – During the formation of domes, the salt may “drag” deeply buried formations closer to the surface as the plastic salt rises, bringing their corresponding formation pressures. These abnormal pressures can cause unexpected overbalanced or underbalanced drilling conditions.

•  Rubble zones/sutures – These are commonly associated with salt domes and can present performance problems (e.g., vibrations), especially when drill bits are used in these applications.

•  Tar zones – When encountered in salt drilling, they present a different set of operational problems.

Figure 2: The 17 ½-in. RSX816S-A bit, developed in 2001, uses the ring gauge to enhance lateral stability. The gauge-cutting structure provided side cutting for the rotary steerable system. This design was used successfully for several years but has been replaced by newer technology as salt applications became more refined.

Figure 2: The 17 ½-in. RSX816S-A bit, developed in 2001, uses the ring gauge to enhance lateral stability. The gauge-cutting structure provided side cutting for the rotary steerable system. This design was used successfully for several years but has been replaced by newer technology as salt applications became more refined.

This article focuses on the development of an ultra-large diameter (26-in.) FC drill bit to tackle the salt section in the deepwater GOM. A unique challenge was to provide a bit that would allow the operator to overcome the vibration and operational issues that had led to ROP compromises.

Torsional vibration is a common event when using FC bits in salt. To overcome this issue, specific design features that end up compromising penetration rates had been typically employed.

The solution to this problem rested on the ability to develop a bit that could function effectively. As a primary requirement, the bit had to exhibit good stabilization characteristics; this would negate the need for vibration-reducing features that compromise ROP.

As a means to further improve operational efficiency and reduce costs, the bit had to be operationally compatible and directionally effective with the selected drilling system (BHA/drive system). These benefits, especially for the hole size under discussion, will reduce operational costs.

To deliver a 26-in. drill bit solution for this specific salt application, all aspects affecting drill bit performance had to be considered and understood. The four characteristics that affect drill bit performance are steerability, stability, durability and aggressivity. Each of these characteristics is interwoven into a complex system where a misapplied improvement to one characteristic can cause detrimental effects to the others.

Often, deepwater salt drill bit solutions are the outcome of an intense focus on the bit’s ability to achieve improved stabilization characteristics at the expense of the penetrating ability of the cutting structure through aggressivity capping features. These salt formations are relatively soft and, in an idealized laboratory environment, could be drilled at ROPs much greater than a deepwater operator using the same bits could ever hope for.

These differences between the ideal laboratory environment and the real world suggest that salt drilling efficiency is not directly related to the bit’s aggressivity.  However, in the quest to improve stabilization, bit solutions routinely fail to meet their objectives.

This is because of operational issues associated with the aggressivity-limiting features that have been applied to overcome the destructive vibration characteristics of salt drilling. Much higher rates of penetration could be possible if the underlying factors holding back the bit’s existing potential for high ROP were addressed through engineered cutting structure solutions, rather than specific limitations to the bit’s aggressively.

A successful innovation in salt drilling bit design would require an understanding of the underlying factors affecting the bit’s performance and the application of solutions to minimize these effects in an unconventional way.

THE DRILL BIT CHALLENGE

Hole quality is the result of the interaction of all components of the drilling system: bit design, BHA, rig capacity, well trajectory, mud program, etc. Poor hole quality can be caused by deficiencies in the design of any of these components and subsequently cascade into costly drilling and completion problems.

Because of this, it is imperative that maximum hole quality be the primary goal for any drill bit solution applied to these intervals. However, due to the economics of deepwater drilling, it is also extremely important to provide a solution that can drill at the highest ROP.  The ultimate goal for any deepwater operator is to efficiently provide superior hole quality.

To achieve maximum hole quality, bit-induced vibrations must be minimized.  In addition, the bit must be directionally responsive so as to minimize BHA and/or formation-related deviation tendencies.  These requirements must be achieved without resorting to ROP-compromising features or technologies. Although the mechanical properties associated with salt drilling suggest that cutter/formation interaction can more easily result in damaging drilling vibrations than in other formation types, much of this infamy is undeserved.

HOLE CREEP

Hole creep, caused by geomechanical stresses plastically deforming the weak salt annulus, can instigate destructive vibrations and cause steerability problems. Hole creep can induce torsional and lateral vibrations by creating undesired friction between the borehole wall and BHA components. Annulus non-concentricity created by hole creep can also cause steering difficulties for directional tools, thus resulting in poor hole quality.

In this application, these issues were adequately addressed through operational considerations focusing on the drilling fluid system.

HOLE WASHOUT

Figure 3: The 26-in. RSR816S-A bit was developed in 2008 to drill a GOM section with clay-rich sediment and massive salt formations. Torque-limiting features on this design helped to prevent over-engagement of the cutting structure.

Figure 3: The 26-in. RSR816S-A bit was developed in 2008 to drill a GOM section with clay-rich sediment and massive salt formations. Torque-limiting features on this design helped to prevent over-engagement of the cutting structure.

Hole washout, caused by hydraulic erosion or dissolution of the salt, can also cause steerability problems for the directional tool. Hole washout causes further steerability problems with push-the-bit RSS. The majority of hole washout problems in this application were solved by operational optimization of the drilling fluid system. However, from the bit’s perspective, certain features intended to minimize hole washout were incorporated into the design. These features were analyzed using predictive fluid dynamics models.

DRILL BIT CONSIDERATIONS

After studying the application, performance-inhibiting issues that would affect hole quality while drilling this section were individually identified, and the four bit performance criteria were addressed through consideration of the positive and negative effects associated with all potential characteristics of the bit design:

• Stability issues (from drill bit and string) will have significant detrimental consequences to steerability, durability and aggressivity.

• Steerability: If the bit deviates from the planned trajectory, it would need to be efficiently steered back.

• Durability: Analysis was done to ensure that the design could complete the interval.

• Aggressivity: This was evaluated as a contributor to improved drilling performance without the usual initiation and amplification of vibrations.

Drill bit design considerations for each performance criteria are discussed below.

STABILITY: STICK-SLIP

GOM salt, while generally possessing a relatively low compressive strength, is infamous for inducing damaging torsional vibrations, especially when drilled with ultra-large diameter FC bits. To address this issue, downhole motors (PDMs) have had to be used.

In addition, extensive BHA design and verification methods have been incorporated. However, these strategies were not able to improve ROP due to the types of bits that had been developed to help address the vibrations issues. Whereas the use of PDMs usually mitigates or dampens vibrations, they do not always improve ROP.

Consequently, the project required an effective resolution. Without having to incorporate a PDM in the BHA, a solution that improves ROP without initiating stick-slip vibrations had to be developed. To address this issue, technologies and features that ensure effective WOB transfer were analyzed.

It was also identified that an efficient torque-versus-RPM relationship had to be established. Whereas previous industry attempts at solving this issue have focused on torque reduction, the emphasis this time focused on torque behavior. To improve ROP, a clear torque elevation with increasing WOB was established. These requirements were achieved through the development of a unique cutting structure arrangement that focuses on the root causes of torsional vibrations. Through this effort, which did not focus on bit aggressivity limitations, the usual ROP limitations were removed.

Consequently, an effective solution that improves ROP and limits stick-slip events was developed.

STABILITY: BIT WHIRL

Lateral vibrations, as well as whirl vibration tendencies, are common events during salt drilling. Consequently, a primary requirement is the elimination of lateral movement tendencies. In addition, rotation about points on the bit’s face, other than the geometric center of rotation (referred to as whirling), must be minimized.

Proprietary design software that evaluate and quantify bit properties, such as lateral stabilization index (LSI) and out-of-balance force (OOBF), were used to evaluate bit dynamic behaviors.

These processes helped minimize the bit’s tendencies to go into whirl. In addition, the bit’s effectiveness at dynamically dampening lateral or whirl vibrations, created by external sources (e.g., BHA), was enhanced.

STEERABILITY

Figure 4: The newly engineered 26-in. E1019-A addresses limitations of earlier large-diameter salt-drilling bits. The 10-bladed bit has 10 nozzles and 19-mm cutting elements. On its first run in salt, the bit drilled 968 ft at 53 ft/hr.

Figure 4: The newly engineered 26-in. E1019-A addresses limitations of earlier large-diameter salt-drilling bits. The 10-bladed bit has 10 nozzles and 19-mm cutting elements. On its first run in salt, the bit drilled 968 ft at 53 ft/hr.

Steerability can be significantly affected by a wide range of factors, including formation type and hardness, hydraulics issues, stick-slip and lateral vibrations (hole enlargement), bit design attributes, etc. In addition, unpredictable inclusions (sutures) in the salt intervals can quickly cause unwanted directional control issues.

Developing a steerable solution requires a careful balance between the bit’s tendency to easily correct for undesired deviations (under the influence of the drive system).

In addition, the bit must be stable and able to drill effectively without self-initiating or creating deviation issues. Due to the use of a push-the-bit RSS, the gauge design for the 26-in. bit included several proven steerability- and stability-enhancing features. The gauge was designed to have controllable and predictable lateral aggressivity. To fine-tune the bit’s lateral tendencies, its side-cutting index (a proprietary calculation that predicts lateral aggressivity) was assessed and manipulated to levels deemed acceptable by the development team.

DURABILITY

Durability in these intervals is typically dictated by the PDC cutter’s tendency to survive the impact loads caused by the types of vibrations that are typically associated with salt drilling.

However, if stability is optimized (as was the case with this project), then abrasive wear becomes the dominant issue with regards to bit durability. Considering the low friction angle of salt, abrasive wear of PDC cutters is fairly benign; consequently, durability from a wear standpoint is of little concern. Given that the bit had been designed and modeled primarily for stability and that the risk of abrasive wear in salt is low, limited attention was paid to cutting-structure design for durability.

Aggressivity was then reviewed. Since the ultimate goal of this bit design is to produce superior hole quality as efficiently as possible, it was important to balance the aggressivity characteristics of the bit design without affecting the three previous performance criteria (stability, steerability, and durability). Because of the bit’s overall ROP dependence on the three performance characteristics, any modification to the PDC cutter count for the sake of aggressivity was approved only when there was no detrimental effect on those three key characteristics.

Several considerations were also made on cutter backrake to increase the design’s ROP response. In each of these cases, when making improvements to the bit’s aggressivity, the most important design criteria were not affected negatively. This aggressivity-optimizing method results in the most aggressive design that is highly stable and can steer effectively through this challenging salt interval.

THE DRILL BIT SOLUTION

This is not the first attempt at producing a drill bit to drill challenging salt intervals in the Gulf of Mexico. Earlier drill bit development also focused on stability and the appropriate matching of side-cutting capability to push-the-bit RSS.

Initial large-diameter RSS designs

A 17 ½-in. FC design was designed in 2001 to accompany the initial introduction of a large-diameter (11-in. OD) push-the-bit RSS. The target application was salt formations in the deepwater GOM, and, as such, the primary focus was on the lateral stability of the drill bit.

At that time, it was customary for the particular bit supplier to use a ring gauge as a solution to applications demanding high drill bit stability. The combination of large diameter, salt formations and a new-size RSS justified the use of this gauge technology within the drill bit. This gauge design features a continuous ring at the gauge diameter rather than discrete pads as seen on conventional bits.

An example of a fixed-cutter bit with a gauge ring can be seen in Figure 1. Ring bits were designed to improve directional response by improving the lateral stability of the bit, reducing the propensity of the bit to whirl. By minimizing lateral vibration, the ring bit reduces torque fluctuations that can occur due to bit whirl. This reduces the potential of the bit to laterally over-engage the formation, which can cause issues with the directional tool.

The final design (RS816) created was a steel-bodied bit with eight blades, equipped with a 16-mm primary cutting structure (Figure 2). The cutting structure was force balanced and featured paired blades that tracked. The ring gauge was used to enhance lateral stability and featured a gauge cutting structure designed to provide sufficient side cutting for the RSS.

Initial trials were successful in terms of both steerability and lateral stability within the salt. The design was expanded in range from 14 ¾ in. through to 18 ½ in. and has delivered consistently good performance over the years for several operators. However, as salt applications became more refined and the nature of drilling challenges changed, newer technology was employed to combat these challenges.

Recent ultra-large diameter RSS designs

To take advantage of the aforementioned drilling practices, the 26-in. RSR816 (Figure 3) was created. This bit was designed to drill a section in the Gulf of Mexico that consisted of rich clay sediment and massive salt formations.  The main goal was to achieve optimum drilling performance while drilling in conjunction with a 9 ½-in. straight hole motor and push-the-bit RSS.

This bit was equipped with torque-limiting features to prevent over-engagement of the cutting structure, which could result in torsional vibrations. Many considerations were also made to improve the lateral stability tendencies of the design, including whirl trigger force prediction (lateral stability indexing), lateral force prediction and dynamic optimization of the cutting action of the bit.

The partial wheel gauge design implemented with the previous 17 ½-in. design was carried over into this new design as well.

Results of this improvement were incredibly positive. This design set several single-run footage records in the Gulf of Mexico, at times drilling more than 50% further than offset bit runs. However, due to the state of evolution of these applications at the time, performance was limited by the fact that downhole motors were still required in order to overcome the perceived inability of bit designs to drill these sections stable at lower weights and RPM.

Furthermore, drilling fluid system design at the time typically caused severe hole washout problems, which resulted in steering and efficiency problems. Only after the operational implementation of the DKD fluid system design could these hole washout issues be conquered.

Learning from the performance of these bits, operational improvements to the drilling fluid system and BHA design allowed progress in understanding the latest challenges and potential solutions for today’s salt drilling challenges. This led to the development of the 26-in. E1019.

Latest ultra-large diameter salt-drilling bit

The E1019 was derived by taking into focus the importance of the four bit characteristics for this specific application.

The final design (Figure 4) is a 10-bladed bit with 19-mm cutting elements and 10 nozzles. As discussed earlier, the cutting structure was adapted to address the limitations of earlier industry products.

In addition, the detailed analysis and evaluations ensured achievement of the objectives and requirements outlined by the project team members.

It is also worth noting that the bit had specialized gauge pads, the length and geometry of which were also adapted to facilitate achievement of the project’s stabilization and steering expectations.

The bit has now been employed successfully on six wells for major operators in deepwater applications. The section below highlights the first initial trial of this 26-in. E1019 design.

Proof of performance

On its first run in salt, the E1019 established a clear advantage over earlier products used in similar applications. The run, which was deemed highly successful by the operator, met all of the project’s defined performance expectations. It is worth stressing that the BHA designed for the run did not have a PDM.

Once the bit tagged bottom, 25,000 lbs weight on bit (WOB) and 120 RPM were applied. Instantly, the bit began drilling with an ROP in excess of 40 ft/hr, a significant accomplishment based on legacy designs and products.

For this first run, the bit drilled 968 ft at 53 ft/hr. All performance objectives identified for the project – deviation control, vibrations control (with no PDM), durability, etc, were achieved.

Compared with offset performances, the ROP gain with the E1019 exceeded more than 200% of what earlier and competitive bits had been achieving.

Following this success, the newly engineered E1019 has been used on six other projects for other operators in deepwater operations. In all instances, the performance has been similar to or better than that on the first run.

CONCLUSIONS

•  Drilling salt formations causes a wide range of problems due to its unique characteristics.

•  Wellbore deviation and vibrations, typically stick-slip and whirl, are common performance-limiting factors with large-diameter drilling in salt.

•  Without understanding the main performance-limiting factors, certain bit design features and technologies used to address vibrations have compromised ROP.

•  A project was initiated to truly understand the underlying factors affecting performance in salt applications. As a result, key drill bit performance characteristics had to be identified and addressed

•  Proprietary modeling techniques were used to establish a unique cutting structure that allows for high penetration rates without initiating vibrations or causing deviation issues.

•  An engineered gauge design was introduced to match the side-cutting requirement of the RSS tool.

•  The initial trial displayed good steerability, low vibrations and high ROP.

•  Similar success with the E1019 was replicated on several other sections within the GOM for major deepwater operators.

REFERENCES

1)     Arndt, S., Gotze, H., Hese, F., Rabbel, W., Schlesinger, A., Theilen, F.,”Salt Diapir Evolution in the North Sea”, Geophysical Research Abstracts, Vol. 8, 2006

2)     Langley, D.,”Lower Tertiary Trend”, Journal Petroleum Technology, March 2002

3)     Clegg, J. and Barton, S.: “Improved Optimisation of Bit Selection Using Mathematically Modelled Bit Performance Indices” paper IADC/SPE 102287 presented at the 2006 IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok 13-15 November

4)     Barton, S., May, H., Johnson, S.:“Gauge, Cutting structure, Torque Control Components – What really counts for Optimal Tool Face Control with FC drill bits” paper AADE-07-NTCE-07 presented at the 2007 AADE National Technical Conference and Exhibition, Houston, April. 10-12 2007

5)     Johnson, S.: “A New Method of Producing Laterally Stable PDC Drill Bits” paper IADC/SPE 98986 presented at the 2006 IADC/SPE Drilling Conference, Miami 21-23 February.

6)     Roberts, T.: “Development of a New Concept of Steerable PDC Bit for Directional Drilling,” paper IADC/SPE 39307 presented at the 1998 IADC/SPE Drilling Conference, Dallas, 3-6 March.

7)     Barton, S.: “Development of Stable PDC Bits for Specific Use on Rotary Steerable Systems” paper IADC/SPE 62779 presented at the 2000 IADC/SPE Asia Pacific Drilling Conference, Kuala Lumpur, 11-13 September.

OTC 20425, “Solving the Salt Challenge: Unique Drill Bit Philosophy Delivers Breakthrough Performance in the Gulf of Mexico,” was presented at the 2010 Offshore Technology Conference, 3-6 May 2010, Houston.

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