Salt is typically underreamed in the deepwater Gulf of Mexico wells to manage equivalent circulating density (ECD) and creep. Rapidly drilling the long salt sections is an opportunity to significantly reduce the overall drilling time and cost of deepwater wells. Rapid penetration rates while under-reaming through salt have been achieved by running near maximum torque with high weight on bit (WOB) and rotation speeds (RPM). However, the consequence of these parameters is high vibration and an increased potential for downhole tool failure. The operator's well was located in over 3000 feet of water in Mississippi Canyon and the well plan included a hole-enlargement-while-drilling (HEWD) interval opening a 12-1/4?? pilot hole to 14-3/4?? from 13,000ft MD to the base of the salt at 21,222ft MD while building angle at 1.5°/100ft, holding tangent for 4500ft and dropping back to vertical. The formation was evaluated using sonic and gamma ray offset data to confirm the interval was homogeneous salt. To optimize the penetration rate while maintaining low vibration, the service provider utilized proprietary technologies to assess the drill bit, BHA and drilling parameters using laboratory data derived from physical testing of salt formations. The BHA was assessed using finite element simulation software to model the behavior of the drillstring and BHA, including the bit and reamer as a drilling system in the geometry of the wellbore. An optimization process was followed to determine sequentially the allowable surface torque, fastest penetrating drill bit, most stable BHA and finally optimized parameters. The process involves running hundreds of iterations using different BHA configurations and parameter combinations in a virtual environment. The parameters were checked for optimization at specific measured depths representing build, tangent and drop sections of the interval. In the simulated BHA, the recommended weight on bit was limited to maintain the neutral point below the heavy weight drill pipe (HWDP) and the torque was restricted to a factor of safety below the make-up torque of the drill pipe. Two candidate PDC bits were modeled for ROP, torsional oscillation and surface torque. Four BHA combinations were simulated using different stabilizer configurations. The optimal BHA was selected based on evaluation of lateral bit/reamer vibrations, stick-slip and torsional oscillation. The dynamic parameter analysis used permissible bit and reamer vibration levels, torsional oscillations and surface torque to determine the maximum recommended parameters of 30 klbs WOB and 150 RPM in salt. The parameter analysis was conducted for the vertical section which encountered transitions of sub-salt and parameters of 20klbf WOB & 125 RPM were recommended The operator ran the recommended BHA and documented an increase of 24% in ROP compared to the vertical offset well. Excluding the directional portions, the increase in penetration rate was 43%. This resulted in 13.4 hrs of reduced drilling time saving the operator $558,000USD. Introduction Sub-salt exploration in the Gulf of Mexico (GoM) routinely requires drilling through salt sections in excess of 6000ft. As these salt-sections account for a significant portion of the total drilled depth, it is necessary to drill them efficiently. Due to the higher fracture gradient of salt, it is possible to drill these long sections without intermediate casings. However, the length of these sections coupled with the tendency of salt to creep can introduce problems with tight spots while running casing.

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.

Operators of Gulf of Mexico (GOM) wells frequently reported overtorque issue of bottomhole assembly (BHA) connections when drilling the 26-in. section through salt. Such overtorque often leads to costly tool damage beyond repair (DBR), additional trips, and high nonproductive time (NPT). The average DBR cost per BHA can be as high as USD 1 million. Combined with a complete BHA roundtrip, it can easily cost more than USD 3 million for operators if such failure happens. This has been a problem for several years and has caused significant damage: In 2014, of 15 26-in. PDC bit runs in salt, 40% had overtorque connections and 20% led to DBR. This paper discusses how an integrated multidisciplinary team identified the root cause of and the solution to the overtorque problem. Torsional vibration was believed to be the cause of such failure. Comprehensive drilling dynamics simulation software that is based on empirical bit design knowledge was used to design a new bit to reduce the vibration. A newly developed high frequency downhole recording tool used in the 26-in. section recorded high-frequency torque, acceleration, and RPM fluctuation downhole. This dataset became the key to understanding the downhole vibration in detail because it provided information that cannot be acquired by a traditional MWD tool. Field-recorded data were fed into drilling dynamics simulations to accurately calibrate the drilling dynamics model. The simulations resembled downhole drilling conditions and clearly identified the root cause. The simulations precisely predicted the torque along the entire drillstring and identified why overtorque is present in only a certain part of the drillstring. The calibrated model was used to compare old and new bit designs. The newly designed bit showed much lower torque amplitude with similar torsional vibration frequencies. The simulation indicated that the newly designed bit can significantly alleviate the overtorque issue. Implementation of the new bit mitigated the overtorque issue immediately. As of May 2016, there have been 18 runs with the new bit. Only one run had a slight overtorque issue whereas the rest showed no sign of overtorque connections. DBR and NPT related to overtorque were eliminated. As a byproduct, the average on-bottom rate of penetration increased by 9%. This case demonstrates the effectiveness of the integrated approach to solving drilling challenges.

Summary In hole enlargement while drilling (HEWD) operations, underreamers are used extensively to enlarge the pilot hole. Reamer wipeout failure can cause additional bottomhole assembly (BHA) trips, which can cost operators millions of dollars. Excessive reamer shock and vibration are leading causes of reamer wipeout; therefore, careful monitoring of reamer vibration is important in mitigating such a risk. Currently, downhole vibration sensors and drilling dynamics simulations (DDSs) are used to comprehend and reduce downhole vibration, but vibration sensors cannot be placed exactly at the reamer to monitor the vibrations in real time. DDSs are difficult to calibrate and are computationally expensive for use in real time; therefore, the real-time reamer vibration status is typically unknown during drilling operations. A process digital twin using a hybrid modeling approach is proposed and tested to address the vibration issue. Large amounts of field data are used in advanced DDSs to calibrate the HEWD runs. For each HEWD section, calibrated DDSs are performed to comprehend the downhole vibration at the reamer and downhole vibration sensors. A surrogate regression model between reamer vibration and sensor vibration is built using machine learning. This surrogate model is implemented in a drilling monitoring software platform as a process digital twin. During drilling, the surrogate model uses downhole measurement while drilling (MWD) data as inputs to predict reamer vibration. Wipeout risk levels are calculated and sent to the operators for real-time decision-making to reduce the possibility of reamer wipeout. Large volumes of reamer field data, including field recorded vibration and reamer dull conditions were used to validate the digital twin workflow. Then, the process digital twin was implemented and tested in two reamer runs in the Gulf of Mexico. A downhole high-frequency sensor was placed 8 ft above the reamer cutting structure in one field run, and the recorded sensor vibration data and corresponding reamer dull conditions showed a very good match with the real-time digital twin predictions in a low-vibration scenario. Cases in high vibration are needed to fully validate the feasibility and accuracy of the digital twin. State-of-the-art downhole sensors, DDS packages, large amounts of field data, and a hybrid approach are the solutions to building, calibrating, and field testing the reamer digital twin to ensure its effectiveness and accuracy. Such a hybrid modeling approach can not only be applied to reamers but also to other critical BHA components.

The deepwater region east of the Mexican state Tamaulipas remains virtually unexplored despite its close proximity to prolific oil production in the USA portion of the Gulf of Mexico. To locate new reserves, PEMEX launched an initiative to outline a deepwater exploratory strategy, assess risk and classify hydrocarbon type by area. A comprehensive geological modeling study was funded to analyze Upper Jurassic and Tertiary strata with 2D/3D seismic, well logs and to map naturally occurring gas seeps and oil shows. The project enabled geologists to accurately identify several key play elements including reservoir presence/quality in addition to hydrocarbon source rocks, migration patterns and trapping mechanisms. The study characterized the area's sedimentary environments and complex structural features including growth faults and downthrown rollover folds that created multiple anticlinal features in addition to typical gulf coast salt/shale diapirs. The study concluded the offshore basin has high potential for hydrocarbon accumulations in a variety of trap styles. To test the hypothesis, the Caxa-1 exploratory well (150km offshore) would kickoff from 3.67° and build to 6° inclination, then drill tangent for 400m. The wellbore would penetrate shale overburden to evaluate Miocene sands at 3400-4000m before reaching TD (4474m). The shale/sand section between 2900-3400m has low UCS, but engineers wanted to drillout the 18-in casing shoe without tripping for BHA change-out and still have adequate clearance to run the subsequent 16-in string without NPT. This technique would eliminate the requirement for extra 12¼-in pilot hole significantly reducing rig-days. The challenge was to build an industry-first tandem reamer directional BHA. The objective would be to complete the section in one run, deliver all directional requirements at fast ROP with minimal vibrations to allow the use of advanced MLWD. The provider recommended a 12¼ x16½ x20-in tandem reamer BHA including an RSS driven 12¼-in PDC bit, a 12¼x16½ fixed-blade hole opener followed by an expandable reamer. The BHA would prevent ID damage to the 18-in casing and allow the operator to set 16-in casing in the next run while 20-in hydraulic opener would create adequate clearance for cementing. Real-time MLWD would be used for formation evaluation and accurate well placement. An engineering analysis was performed to balance the cutting structures, minimize vibration potential and set optimum operating parameters. Based on the simulations a 716-type PDC was selected. The BHA drilled out the 18-in casing shoe and a 382m of section in one run at a fast ROP of 18.6 m/hr. No vibrations were recorded resulting in high-quality MLWD data. The 18-in casing was undamaged and the 16-in string was set on the first attempt. The BHA was pulled at section TD in excellent dull condition with no wear on the three tool's cutting structures. The technique was used on Trion-1 exploratory well with a similar BHA (12¼"x17½"x22"), Sumpremus-1 (12¼"x14½"x17½") and Maximino-1 (12¼"x16½"x20") with comparable results.