Innovative RSS design increasing efficiency of drilling more complex wellbore profiles
The oil and gas wells of today present more complexities. Drilling often challenges operators with wells that have higher pressures, temperatures, and step-outs, as they attempt to maximize existing reservoir production and exploit deeper reservoirs. These wells may have complex designs and deeper depths through troublesome formations, which can result in nonproductive time (NPT) and exceeding the well authorizations for expenditure (AFEs).
Historically, the oilfield industry has solved drilling challenges and technical limits through core technology improvements. The pursuit of drilling longer, deeper and faster wells at the turn of the millennium led to many advances in drilling technology, including the invention of the rotary steerable system (RSS). Now, increasing capabilities, drilling a quality borehole and optimizing the well construction process often demand this technology, at a minimum.
Rather than simply using the same approach time and again for the same results, complex wells require unconventional thinking and innovative solutions. Unconventional thinking is complemented by the paradigm of working in tandem with operators to resolve concerns and improve performance. Doing things differently enables drilling with higher efficiency and achieving new benchmarks in challenging applications. Strategies that push performance boundaries involve following a proven drilling engineering process, leveraging digitalization and automation solutions, incorporating offset well analyses, and creating a comprehensive drilling plan and contingencies, based on a risk assessment.
Weatherford uses this kind of approach to consistently deliver quality directional drilling. Several case studies from multiple countries in different regions throughout the world illustrate tangible performance improvements, from onshore land wells in Canada and Mexico, to deep offshore wells in the Black and North Seas. Accomplishments include increasing on-bottom rates of penetration (ROPs), drilling longer step-outs, using fewer bottomhole assemblies, finishing ahead of AFE, intersecting all planned targets, and even setting field records for ROPs, lateral lengths, and footage drilled.
RSS built to solve operators’ challenges. In 2018, Weatherford launched a push-the-bit technology, the Magnus rotary steerable system, which represented a fundamentally different approach from those used in the past, Fig. 1. Weatherford purposefully engineered the RSS to reflect the market’s current needs for longer horizontals, faster drilling, more power to transmit, and more demands on wellbore quality.
The simple, cost-effective design improved asset utilization, compared with its predecessors, to reflect the economics of the existing market. As a reliable technology that enables drilling ahead while maintaining directional control, the RSS led to a rapid adoption curve. The Magnus RSS portfolio covers a broad scope of applications, with five different collar sizes from 4¾-in. to 11-in. and capabilities in borehole sizes from 57/8-in. to 18¼-in.
Each Magnus RSS in the portfolio features innovations in steering and power to address well requirements, such as smoother wellbores and longer laterals. A unique differentiator—three independently controlled pads—offers not only control of each of three pads to push the bit laterally, but also built-in redundancy for continued drilling in the unlikely event of actuator failure. One or all mechanisms can be turned off to drill a smooth curve and a less tortuous well at a planned dogleg. With all the pads de-activated, operators can safely trip in and out of the hole, drill out of casing, ream, and log with a completely passive steering head.
Aside from steering, the RSS also delivers capabilities to handle the anticipated torque and speed from current and future developments in drive technology. It eliminates non-rotating parts for a slick design that minimizes the risk of stuck-pipe events, saves on the expense of a highly stressed driveshaft, and uses the full diameter of the tool body to transmit torque to the drill bit.
Extending the RSS portfolio to slim hole sizes. After the success of the larger system sizes, Weatherford rolled out the slim-hole, 4¾-in. design tool, the Magnus 475 system, in 2020 with an equally aggressive field test and development strategy. Scaling the RSS designs up proved to be very efficient exercises, which allowed for vast cross-utilization of existing electronics and mechanical components. The RSS system used the 6¾-in. sized system as a basis but proved quite a bit more complicated, with almost all components requiring a scale-down and re-design. The main challenge consisted of fitting three independent valve and motor assemblies into the small 4¾-in. OD collar. At the same time, keeping the independent pad controller as a key differentiating feature was imperative to setting the RSS apart from existing push-the-bit technology on the market and affirming its position as the industry’s first fully rotating RSS to offer proportional steering control.
CASE STUDIES
North America. The initial global rollout of the Magnus 475 RSS began in Mexico on land drilling applications to evaluate its features and functionality. Immediate successes on these land wells led to quickly rolling out the new system in more complex applications in the Gulf of Mexico, where it has since drilled over 10 wells with more than 2,000 operating hours.
On its very first deployment in Canada, the RSS drilled two consecutive record-breaking wells in the Notikewin formation. It drilled the fastest and longest laterals with a record 8,307-ft (2,532-m) lateral drilled at an average ROP of 295 ft/hr (90 m/hr). Driving the RSS at speeds up to 285 rpm, with a powerful 8/9 lobe 6.0 stage positive displacement motor, and downlinking on-bottom while drilling, enabled the bottomhole assembly (BHA) to achieve a 20% improvement in ROP, compared to the next-fastest well in the field. The advanced control system samples rpm at more than 1,000 times per second to resolve valve position and efficiently activate the pads at the correct toolface for directional steering.
Offshore Romania. In one of the first deployments of the Magnus 475 system in the Eastern Hemisphere, it enabled the drilling of a 6-in. horizontal section on a deep well in Romania’s portion of the Black Sea. The objective was to improve drilling performance, compared to offset wells in the field drilled using a competitor’s RSS system, by increasing the on-bottom ROP, reducing stick-slip and vibration levels, and achieving zero NPT while acquiring critical resistivity and sonic logging-while-drilling (LWD) data. The trajectory required a dogleg severity (DLS) of 5.5°/100 ft (30 m) right out of the 7-in. sidetrack and over a 9,000-ft (2,743-m) lateral step-out at a 90° inclination.
During the planning stage, the team engaged with the customer to develop a front-end engineering design (FEED) report, based on an offset well analysis and Weatherford experience in this field. A tailored BHA design with focus on bit design, torque and drag, hydraulics, and a vibration mitigation tool and strategy, was utilized, along with a customized driller’s roadmap. This included critical operations and field-crew guidance that covered all the trajectory sections and formation specifics.
The RSS equipped with near-bit inclination and azimuthal gamma ray, coupled with LWD resistivity and sonic imaging, helped minimize reservoir uncertainties, maintain pay-zone contact and land the well in the target zone. LWD pressure measurements provided live information on downhole hydraulics and fluid performance. The RSS worked against a formation dip angle of 5° to 10°, to intercept all planned geological targets within a window having a 33-ft (10-m) radius and running 6.6 ft (2 m) above and 13.1 ft (4 m) below the reservoir top. The Weatherford solution, including the RSS and LWD technologies, acquired accurate data to mitigate drilling problems and optimize the process. The RSS helped to deliver the 9,249-ft (2,819-m) well nine days faster than previous offset wells, for a savings to the operator of more than $2.5 million by increasing average ROP 26% and avoiding any NPT, Fig. 2.
NORTH SEA
Over the last four decades, the North Sea has become the center of one of the world’s most productive energy industries. The British industry developed rapidly in the Southern North Sea gas fields and, as exploration and investment extended further north, oil was found in great quantities. Production grew and peaked around 2000 to 2001, and now the North Sea is regarded as a mature province. However, with the advent of more sophisticated technology, new discoveries are still being made and mature fields redeveloped with 21st century technologies.
The RSS was introduced into the North Sea in December 2020. Since then, it has been deployed for four different operators in five fields in the Central Graben area of the North Sea, to drill hole sizes from 17½ to 8½ in., which includes planned sidetracks, hole enlargement while drilling, and high-pressure/high-temperature (HPHT) applications. The RSS has proven its performance capabilities by setting many field records and achieving new benchmarks for performance in the North Sea.
Surpassed previous field performance on inaugural RSS deployment. The first deployment of the Magnus 1100 system in the North Sea was in an HPHT field for a major IOC. The job involved drilling the 17½-in. section from the 20-in. shoe in Tertiary formations down through the Paleocene formations to the casing point in the Tor chalk formation. The offset analysis and risk assessment conducted as part of the basis of design identified the challenges for this section. Risks identified included attempting a much higher step-out than had previously been drilled in the field and drilling the difficult Paleocene formations at an angle of 25.5° inclination, whereas the previous maximum inclination had been approximately 13°.
Past wells drilled from the platform used, on average, five BHAs to reach total depth (TD) in the upper chalks. The bit runs were characterized by fast ROP through the upper Tertiary formations, with incredibly low ROPs from the Balder to section TD, which led to extensive BHA wear in the abrasive Maureen sands. BHAs included a variety of motors, RSSs and rotary assemblies to reach TD, with many examples of severe BHA and bit wear and LWD component failures caused by severe downhole vibration.
Offsets also showed wellbore instability in the upper formations. Instability risks increase, the longer the hole is left open and for this reason, the increased inclination was of concern, due to the extremely low ROPs for the last 1,600 ft (500 m) of the section, which could potentially leave the upper portion of the section open for up to 3 weeks. There had also previously been issues with ledges and difficulty in passing the BHA through stringers, which resulted in poor weight transfer, erratic torque and significant risk of differential sticking in the Paleocene sands. The objective was to complete the section in three bit runs—without any compromise on the directional plan, which could exacerbate anti-collision issues further on in the well—while not sustaining damage to downhole equipment as had been seen on repeated BHAs in the previous wells.
Optimization included extensive pre-job modeling on the RSS BHA design, stabilizer quantity, and placement. Enhanced protective diamonds were added to all the LWD stabilizers, and the RSS stabilizer was modified to 0.125-in. under gauge versus the standard 0.25-in. under gauge. This optimization would help to reduce downhole lateral vibrations and eliminate the poor weight transfer issues previously caused by ledges in the interbedded formations.
The optimal BHA and bit combinations were planned, along with the operator, and formed the basis of a robust BHA strategy, including contingency options. Additionally, key decision trees—such as criteria to trip for ROP, downhole vibration management, and a BHA and contingency strategy—were prepared to avoid on-the-fly decision-making during execution. For example, formation changes were highlighted in the transition zone, where conditions rapidly change from readily drillable into the extremely hard Paleocene formations, and parameters were managed to minimize damages to the bit. This enabled the first BHA to drill far deeper than had been achieved before in the field, with overall average ROPs higher than offset, Fig. 3.
This RSS BHA also set a field record for the operator by drilling 2,906 ft (886 m), or the highest footage drilled in 24 hrs. The BHA design optimization was further validated because lateral vibration and stick slip were predominately low throughout the run, again something that historically had not been seen in the field. All the careful design and planning enabled reaching TD in the section with three BHAs as planned in the Tor formation—a first for the field.
On this first BHA alone, the drilling time was ahead of AFE by 0.82 days, and this includes drilling further than anticipated with ROPs in the region of around 10 ft/hr (3.0 m/hr) in the more difficult Paleocene formations. This breakthrough performance continued with the next BHAs for a huge improvement on the AFE. The rigorous pre-job analysis and discipline in adhering to the drilling engineering process enabled designing the optimum BHAs and bit recommendations for the client, with the results clearly demonstrating best-in-field performance.
Overcame anti-collision risks to set several field records. After replacing a competitor, a drilling campaign commenced to drill a series of sidetracks in a congested mature North Sea field for a major operator. The wells were 8½-in. directional sidetracks from a whipstock in the host casing. A major challenge for this well was anti-collision risks with offset wells falling within close-proximity and one with a separation factor (SF) falling below 1, which is “stop drilling” criteria for Weatherford.
First, the same drilling engineering process was used for BHA optimization, contingency planning, and a driller’s roadmap. Then a Magnus 675 RSS, along with an LWD suite of gamma, resistivity, and neutron density tools, was used to drill these sidetracks, which resulted in drilling to a 9,766-ft (2,977-m) measured depth (MD), with an average ROP of 101 ft/hr (31 m/hr).
After the success of drilling the first sidetrack, the next well in this campaign leveraged the learning and best practices captured, such as revisions to the BHA and hydraulic analysis, to keep optimal differential pressure on the RSS for directional capability. With these optimizations, the next sidetrack was drilled with footage of 6,775 ft (2,065 m), MD, at an average ROP of 92 ft/hr (28 m/hr). Subsequently, performance was then repeated on the next sidetrack with footage of 6,930 ft (2,112 m) and average ROP of 106 ft/hr (32 m/hr). The section was drilled significantly ahead of P50 AFE timing, Fig. 4.
In summary for the three sidetracks, the Magnus RSS maintained directional capability throughout the entire 81/2-in. section, with trajectories no more than 6 ft (1.8 m) from the line through the reservoir. This was achieved by utilizing a proven drilling engineering process; optimizing well designs from previous offset and lessons learned; and receiving support from the Real-Time Operations Center (RTOC) while utilizing real-time monitoring, drilling optimization, and intervention during the drilling phase. Sidetrack #1 was the field’s longest 81/2-in. hole section to date and drilled in a single run. Sidetrack #2 was confirmed to be the fastest 81/2-in. section well drilled in the field to date, and sidetrack #3 set a new field record for ROP with a 34% improvement over the previous best performance.
First-time section drilled in one run with 100% LWD data. In August 2021, Weatherford deployed a Magnus RSS, along with a suite of LWD tools, to replace the competition and drill a 12¼-in. section on an HPHT field for the first time for a major IOC. The challenge was to drill the section in one run while maintaining directional control and avoiding failure of LWD components, which had not been achieved through the chalk formations on previous wells.
Following the drilling engineering workflow process, pre-planning concentrated on the BHA design and bit recommendation to minimize the potential for vibration while drilling and rigorous hydraulic analysis to ensure all mud weights, flowrates, and MPD pressures were fully optimized prior to commencing drilling. Drilling hazards—such as differential sticking, stuck pipe, lost circulation, and narrow drilling margins—were all fully considered in the risk assessment with mitigations and contingencies in place.
The Centro well construction optimization platform enabled real-time analysis of the drilling data to optimize drilling parameters and minimize vibration. The 3,637-ft (1,109-m) section was completed in one run, as planned, with 100% real-time and recorded data delivery—a first in this hole section for the client. Average ROP through the chalk interval was 41 ft/hr (12.5 m/hr); however, this was not the technical limit, as the ROP was held back, due to the risk of drilling into gas-bearing zones.
Directionally, the RSS performed as planned. It maintained a tangent angle before dropping angle with minimal DLS to maintain a smooth trajectory and lined up vertically above the drilling target. The BHA condition was significantly better than had previously been seen, with minimal wear on stabilizers and RSS pads. Real-time and memory analysis of the vibration data validated the BHA design, which exhibited minimal levels of shocks and vibrations.
The AFE planned 206 hours for the drilling interval, with a target time (P10) of 182 hr. The actual drilling time was 6.42 hr under the P10 target at 175 hr, and this included 49 hr of rig NPT. Excluding the rig NPT, effective drilling time was 126 hours, well below the P10 AFE target, with room for further improvement, due to limiting ROP and still achieving the technical limit, Fig. 5.
CONCLUSION
In this age of complex and challenging wells, unconventional thinking and innovation enable pushing performance boundaries. Replacing the same approach with newly established strategies—including the integration of a validated drilling engineering process, digitalization and automation solutions, offset well analyses, and a comprehensive drilling plan with contingencies yields improved results on every well. The Magnus RSS has also proven an essential part of the strategy. Disciplined adherence to an approach using this drilling engineering process and reliable technology can drive continuous improvement in North America, Europe, the North Sea, and beyond.
- Coiled tubing drilling’s role in the energy transition (March 2024)
- Digital transformation/Late-life optimization: Harnessing data-driven strategies for late-life optimization (March 2024)
- The reserves replacement dilemma: Can intelligent digital technologies fill the supply gap? (March 2024)
- Digital tool kit enhances real-time decision-making to improve drilling efficiency and performance (February 2024)
- E&P outside the U.S. maintains a disciplined pace (February 2024)
- Prices and governmental policies combine to stymie Canadian upstream growth (February 2024)
