Stick-slip and whirl are the devastating vibrations that significantly limit drilling performance. They not only cause equipment failures, but also increase non-productive time driving up field development costs. Although the industry has achieved tremendous improvements in fighting against these dysfunctions, the root causes of stick-slip and whirl are still not fully understood. Stick-slip is characterized by the fluctuation of rotary speed of the bottom hole assembly (BHA) while whirl is known as the severe lateral vibration that may occur at bit and/or BHA. A driller's dilemma emerges when increasing weight-on-bit (WOB) induces stick-slip whereas increasing revolutions /minute (RPM) induces whirl. Keeping both WOB and RPM low reduces vibration levels but it negatively affects ROP. As a result, the drilling operation either suffers low ROP or experiences higher ROP but with severe vibrations. The latter can cause damage to the bit and rotary steerable system (RSS), motor (PDM), measurement while drilling/logging while drilling (MWD/LWD) leading to a lack of steerability and poor borehole quality. New research strongly suggests the above dilemma is related to the drillstring's tendency to couple stick-slip and whirl. This coupling is induced by improper bit selection and unfavorable bit-BHA interactions. For a given bit and rock, the critical values of WOB and RPM triggering stick-slip and whirl can be predetermined assuming other drilling conditions are known and fixed. Plotted in a rectangular coordinate with abscissa of RPM and ordinate of WOB, these critical values represent the boundaries of stable drilling parameters. The other important boundaries include: Maximum torque limited by rig capabilityMinimum ROP specified by operatorsMaximum WOB limited by drillstring buckling and directional control These boundaries together define a closed domain in the space of WOB and RPM. This domain is called the "optimum zone" in this paper. The drilling parameters in the optimum zone theoretically guarantee BHA/bit stability. The scope of the optimum zone depends on the bit and the mechanical properties of the rock to be drilled. The drillstring dynamics, however, reduce the optimum zone significantly by creating bit-BHA interactions. In an extreme case, these interactions can push the boundaries of stick-slip and whirl to cross, completely eliminating the optimum zone. In this situation, any attempt to mitigate vibrations by varying drilling parameters will most likely fail. To solve this challenge, an advanced drillstring model was developed and applied to quantify the following effects on the optimum zone: Mechanical rock propertiesBit design including cutter, body and gauge profileBHA design and its interaction with bit The ability to obtain superior stability and ROP simultaneously depends on two key factors: (1) maximizing the optimum zone through bit optimization, and (2) minimizing bit-BHA interactions by BHA optimization. The objective of both is to decouple potential stick-slip and whirl. The authors will present several case studies to illustrate the concept of optimum zone and its effectiveness on decoupling stick-slip and whirl to increase overall drilling performance.

Deepwater drilling often requires simultaneous hole-enlargement-while-drilling to improve project economics and efficiently deliver wellbore requirements. The challenge is to properly adjust reamer aggressiveness to match PDC bit dynamics to reduce damaging vibrations while maximizing overall drilling efficiency. Recent R&D efforts, focused on redesigning the BHA and optimizing drilling parameters, have successfully reduced bit/under- reamer vibrations. In addition, many operators and service providers have established rig-site procedures to recognize and mitigate vibrations. However, the results are still mixed and the lack of understanding the root causes of different vibrations is considered to be the major hurdle to improving drilling efficiency and performance. To solve this challenge an advanced dynamics model was developed which incorporates the following critical information: Mechanical rock properties (UCS) Bit/reamer design including cutter, body, gauge profile Physical characteristics of BHA components Formation characteristics (heterogeneous, anisotropy, interbedded) Well trajectory and borehole geometry Drilling parameters (WOB/RPM) This model can be applied to any drillstring configuration to provide BHA detailed information about RSS, PDM, PDC/roller cone, stabilizers, reamers, MWD/LWD and other downhole tools. This FEA model accurately predicts the drilling system's dynamics behavior from bit to surface and simulates the transient response of the entire system in time domain. Using this model, the combined effects of bit, reamer, BHA and drilling parameters have on vibration can be quantified and optimized before commencing field operations. This innovative technology provides an effective tool to optimize drilling performance without using the costly trial-and-error approach. An operator working in the Gulf of Mexico (GoM) required hole-enlargement-while-drilling to open a 12-1/4" pilot hole to 14- 3/4" from 13,000ft MD to approximately 20,000ft MD. The advanced drillstring dynamics model was utilized to optimize the BHA, bit and drilling parameters to minimize potential stick-slip and lateral vibrations. The optimization study, along with the operator's improved drilling practices, resulted in a 24% increase in penetration rate (ROP) compared to an offset well. Excluding the directional portions of the wellbore, the increase in ROP was calculated at 43%. The penetration rate increase reduced rig-time usage by 13.4hrs for a savings of $558,000USD.

Severe vibration and stick-slip are devastating dysfunctions that significantly limit drilling performance. They cause equipment failure and increase non-productive time driving up field development costs. The evolution of real-time downhole measurement technologies can monitor the onset and severity of vibrations and stick-slip. However, the low-frequency of the measurement data and increasing BHA complexity, the information does not necessarily pinpoint the root cause of drilling dysfunction. Drillers are often forced to live with the trial-and-error process to mitigate vibrations/stick-slip, which is an expensive and inefficient approach. Combining the engineering expertise with an advanced drilling dynamics model, the service provider has successfully identified the root cause of vibration and stick-slip in a number of challenging drilling applications worldwide. This enables engineers to concentrate on fit-for-purpose solutions rather than the traditional trial-and-error approach.Two case studies are discussed to outline and document the analysis process and the underlying solution technologies. Case study-1: drilling a 16” section in a Middle East gas field through heavily interbedded formations with hard stringers was damaging project economics. The root cause of damage was identified as bit whirl and axial vibration. The PDC was redesigned to improve durability and achieved the longest 16” run in this field with ROP 18% faster than the best offset. Case study-2: hole enlargement while drilling a 17½” x 20” section offshore Brazil was challenging due to hard and abrasive formations. Premature reamer cutter wear was identified as the root cause for stick-slip. A new-generation of abrasion resistant cutters was implemented on the reamer and the BHA was optimized to reduce the weight at the reamer. The new assembly drilled and enlarged shoe-to-shoe in one run with minimum stick-slip and vibration.

Drilling deep 16-in. hole sections in Saudi Arabia's gas wells is particularly challenging due to complex stratigraphy consisting of carbonates with interbedded hard stringers, abrasive sandstone, and dense dolomite. These hard/abrasive formations can cause high-axial and lateral vibrations, which have led to premature PDC bit damage. To combat these drilling performance problems, a holistic approach was undertaken to optimize bit design and the drilling system. This included a thorough analysis: Rock samples that matched the challenging formations were collected and laboratory tested to quantify the forces between the cutters and rocks in order to formulate relative rock removal rates. This information and that gathered from a test BHA—after operating for 24 continuous hours during which drilling parameters were monitored—was evaluated using an advanced dynamics model. This enabled improvements that resulted in an optimized bit design and drilling system. This highly beneficial modeling technology is a comprehensive, 4-D, and finite element model, which accurately predicts the drilling system's performance from bit to surface and simulates the transient response of the entire system in time domain. Applicable for any drillstring configuration, the modeling technology is capable of providing performance information on specific BHA components: RSS, PDM, PDC/roller-cone bits, stabilizers, reamers, MWD/LWD, and other downhole tools. Such information includes: acceleration, velocity, forces, bending moment and displacement at any node along the drillstring. Using an advanced dynamics model enabled engineers, working in a virtual drilling environment, to make an extensive effort toward bit design improvements. The resulting bit design, BHA, drilling parameters, and their effect on instantaneous ROP, drillstring vibrations, and directional tendency were quantified and optimized. This holistic approach significantly improved drilling performance in Saudi Arabia's problematic formations. The newly designed bit drilled an entire 16-in. section 5,219 ft from mid-Thamama to base Jilh Dolomite formation at an average ROP of 29.2 ft/hr and achieved the longest 16-in. PDC run in "deep casing design" wells. ROP was 18% faster than the previous best run in a similar application. The authors will outline the analysis, resulting cost reduction, and how applying advanced modeling technology improved drilling performance through the bit, BHA, and drilling parameter optimization.

Deepwater drilling often requires simultaneously hole-enlargement-while-drilling (HEWD) to improve project economics and preserve hole size for reaching deep reservoirs. The challenge of having two active cutting structures (drill bit and expandable underreamer) in one BHA is improving ROP performance of entire drilling system while preventing premature failure of the underreamer, which is susceptible to vibration induced damages. From an operational standpoint, one potentially disastrous scenario is when underreamer has been severely damaged, but the drill bit is still in good condition. If such situation is not detected promptly and drilling continues, HEWD operation could potentially create a significantly undergauge hole section whose diameter is similar to drill bit. Such consequence can cause enormous difficulty for running/cementing the casing string, and often result in costly remedial operations, or in severe cases, hole abandonment. To mitigate this risk, an advanced data analytics method was developed to early detect the failure of underreamer by utilizing the standard drilling mechanics data from both surface and downhole sensors. This patent-pending method includes the development of new performance metrics for underreamers based on rock cutting physics and cutter wearing mechanism. This new technology enables the operator to extract insights from similar tool failures in historical data and puts those insights into action on real-time data "in motion". A warning flag can be displayed immediately when the underlying failure pattern is detected by the new method. All relevant rig and office personnel are notified in real-time to promote timely discussion and facilitate decision making. The operator working in Gulf of Mexico required hole-enlargement-while-drilling to open a pilot hole from 16.5″ to 20″ from 14,000′ MD to approximately 21,000′ MD. The new technology was utilized to monitor the underreamer performance in real-time for this challenging section. The technology provided a warning signal as soon as the algorithm detected the onset of a failure pattern from the underreamer at about the midpoint of the section. When it was pulled to surface, underreamer showed significant damage on cutting structure and had started becoming undergauge. This case study demonstrated the validity of this new method in detecting underreamer failure in real-time. Since then, this technology has been deployed on more than 10deepwaterwells to mitigate the risk of underreamer failure.