While planning a wildcat exploration well, an operator faced formation depth uncertainty as a result of poor seismic imaging as well as limited offset pore pressure and fracture pressure data. A steep pressure ramp was anticipated at some depth below surface casing, and casing design included a 16-in liner to secure this interval. To properly evaluate and understand the lithology and pressure while drilling would require high-quality LWD data, but it was also essential that the liner and casing could be fully run to the bottom of the hole. Underreaming near the bit while drilling would compromise the LWD data, but underreaming above the LWD tools would not enable the casing to be fully run to bottom. Two hole-enlargement-while-drilling (HEWD) BHAs with the option for rathole elimination (RHE) were proposed and enabled these objectives to be efficiently achieved without compromise. A combined HEWD and RHE BHA is not new in the industry, but it is challenging in large hole sizes. With multiple cutting structures in the BHA, drillstring dynamics become complex. The resultant vibration and shock can lead to diminished drilling performance, or even failure of BHA components. A prejob finite-element analysis (FEA) modeling simulation was used to investigate the dynamic drilling behavior of the initially-planned BHAs. The simulation results from initial BHA design predicted high vibrations. A BHA optimization analysis was then conducted to determine the most favorable BHA configuration for effective LWD tool placement and minimized vibration issues, taking into account the BHA geometry and stabilization points, cutting structures, and formation type. The simulation results from the final BHA exhibited a significant reduction in shock and vibration levels. Suitable drilling parameters were identified, and hydraulics simulations were performed to ensure that both the HEWD and RHE underreamers could be reliably actuated. The operator implemented the recommended BHAs, cutting structures, and parameter roadmaps on both the 17-in × 20-in and 14¾-in × 17½-in sections, and the solution successfully drilled 501-m and 605-m intervals, respectively. Each interval was drilled and enlarged in a single trip. Both HEWD BHAs exhibited low levels of vibration during the original underreaming, enabling quality LWD data to be obtained. After maximizing section depth, the HEWD underreamer was deactivated and the RHE underreamer activated, enabling the rathole to be underreamed and subsequently the liner and casing strings run fully to the bottom of the hole. Advanced dynamic drillstring modeling can simulate downhole drilling conditions, enabling improved prejob planning and thus more efficient drilling operations. Proper design of HEWD and RHE BHAs can help the operator efficiently maximize the quality of LWD data while drilling.
Among the challenges facing an operator while drilling offshore in the Middle East are the 16-in. sections of wells where highrisk of losses and torque and drag limitations force the operator to be extremely conservative during the planning stage. Operator objectives for this particular interval normally call for mitigating any high-potential incidents, which is driven by the past experiences as well as decades of old best practices. The approach used in the past has been to drill with a positive-displacement mud motor and weighted mud until losses are experienced, and then switch to mudcap drilling to maintain hydrostatic while drilling. The positive displacement mud motor efficiency is excellent in lower inclination wells but deteriorates once the inclination exceeds 30n, leading to significantly lower penetration rates and extending the openhole wellbore exposure time. This prolonged openhole time exposes the bottomhole assembly and wellbore to the same risks the operator has always attempted to avoid. A service provider evaluated the drilling method with the objective of reducing the drilling time and drilling risks. Drawing from offset well experiences and the conditions of successful operations, a motorized rotary steerable system (RSS) was proposed to the operator. Time and cost analysis were performed, showing that improved hydraulics and drilling dynamics would result in significanttime savings and should be compounded as the 16-in sections are drilled in batches of up to seven wells. The operator implemented the recommended BHA and parameter design for the remaining seven wells, resulting in up to a 120% increase in the average rate of penetration by the motorized RSS over conventional positive displacement motors. The accompanying benefits to the operator included increased hole cleaning capacity, torque and drag reduction in tripping times, and reduced risk exposure in the 16-in. sections. The results obtained with the updated design demonstrated that in the current challenging energy market environment, using proven technologies to challenge decades of best practices can bring significant benefits to the well construction and enhance the performance benchmarks for future wells.
In the past year, a client in the Arabian Gulf has been increasing appraisal and development well activity from the same slot to reduce the uncertainty of reservoir depth, identify oil-water contact, and determine reservoir production strategy. The operator has been addressing these issues by drilling pilot sections from planned development wells, then plugging and abandoning the section prior to drilling the production lateral. The sidetracking operation is then performed from the previous casing shoe, aided by cement plug and landed to the required horizontal depth provided by the data from pilot section. Conventionally, positive displacement motors (PDM) have been used to perform the sidetrack effectively, then followed by a rotary steerable system (RSS) in the bottom hole assembly (BHA) combined with near-bit logging-while-drilling (LWD) tools to land the well. Because the pilot section is often drilled with water-based mud and penetrates through multiple layers of unstable shales and the reservoir, the hole condition normally deteriorates especially after extensive wireline logging runs, even after the cement plug has been set. In collaboration with other service providers such as cementing and wireline, the directional service provider revisits the sidetracking procedures to improve the sidetrack operation and reduce overall well construction time. Combining extensive data otherwise kept within each service provider's domain, the directional service provider analyzes the hole condition specific to each pilot section using formation evaluation data, wireline caliper logs, and pilot section drilling mechanics data to determine the sidetrack depth, drilling parameters, cement plug type, and the optimized RSS and BHA to perform the sidetrack efficiently. This detailed sidetracking procedure is then shared to all concerned parties, including to clients at the wellsite and in the office, and other service providers for discussion to align all objectives and ensure the sidetracking operation will be efficient. In 2018, the operator implemented the sidetracking procedures on 9 wells and achieved 100% success for drilling sidetrack from shoe-to-shoe in a single run. The detailed procedures mitigated the risks of using an RSS and subsequently eliminated the need to run a PDM to initiate the sidetracks. Comparative to sidetracks performed by the PDM, the sidetracking procedure using the RSS BHA managed to reduce drilling time on average of 1 day per well. The RSS BHAs also improved the hole condition for the subsequent activities of the well construction cycle, leading to less casing running issues and improved torque and drag for subsequent sections.
Conventionally offset well studies are performed by individuals where the results depend very much on visual perception, interpretation, and experience. In the specific cases for predicting the dogleg severity (DLS) output, the offset well study will take time proportionate to the volume of input, with the results being averaged out and contain high tolerances. In specific projects, these tolerances are larger than accepted, encouraging the service provider to utilize conservative solutions such as rotary steerable system (RSS) with high DLS capability in order to reduce the residual risks. These solutions can often be more costly in terms of maintenance and may add unnecessary tortuosity to the hole leading to issues during execution. This paper explores the concept of using machine learning (ML) to perform offset well study and defining key parameters affecting the DLS output. This concept consolidates the vast volumes of data that have been acquired while drilling and defines the relationship of each parameter to the final output of DLS. The first analysis reviewed five offset wells and found a multivariable correlation between applied drilling parameters to the DLS output. This correlation was then applied in 6 boreholes (3 multilateral wells), observing consistent DLS output increase by 50% using the same technology and optimal drilling parameters. The second analysis uses the same process to determine a planning DLS limit in a curve section over different formations. This paper demonstrates the potential of ML in offset well studies and beyond to predict behavior and define the relationship in a big data environment.
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