Not a kick: Controlling ballooning effect with MPD during directional drilling
Driven by increased stress on the energy industry, many operators are seeking additional resources from reservoirs once considered unattainable. Some of these reservoirs require drilling solutions to precisely and reliably achieve complex wellbore trajectories to reach the pay zones. During these drilling operations, unplanned events increase costs, safety risks and nonproductive time (NPT). Nearly 40% of all NPT caused by unplanned events is related to wellbore pressure, but too often, the typical approach to solving these problems is to use managed pressure drilling (MPD) technology only as a last resort. Thus, operators gamble and hope their projects will not encounter these types of challenges.
Most all drilling operations encounter challenges, and certain reservoirs have inherent qualities that enable operators to predict problems and proactively mitigate challenges. One offshore field in Mexico requires the operator to drill through carbonates of the Upper Cretaceous Breccia. To reach the reservoir, the operator has to drill through a high-pressure zone with formations that are prone to ballooning behaviors during drilling activities.
Some field personnel can confuse this phenomenon as a kick, since both events display similar signs on the surface, such as flow during connection. In addition, drilling operators spend considerable time waiting for flow checks, stabilizing flow returns, and detrimental mud weight-up schedules and the corresponding impact on ROP, which further exacerbate the ballooning effect. As a result, these ballooning events often contribute to significant NPT.
To counter the intrinsic challenges present in this field, the operator needed an innovative solution that managed downhole pressure while optimizing directional drilling.
Planning and designing for optimal performance. In the planning phase, a standardized drilling engineering process was adopted to safely identify the technical limits and accurately position the wells through a job’s lifecycle. Early collaboration between the operator, service company, and rig contractor aligned the team’s focus to determine drilling challenges and associated risks.
For the design phase, the teams analyzed data from offset wells to establish important risks and best drilling practices. The goal was to generate a specific drilling program, where all risks were met with fit-to-purpose mitigation plans to reduce drilling hazards and unplanned events as much as possible.
One challenge involved the drilling contractor. The previous two wells experienced considerable NPT related to the ballooning effect, largely as a result of waiting for stabilization of the well, rig crew confusion, and the initiation of the well control protocol.
The teams agreed to manage the downhole equivalent circulating density (ECD) and not allow it to exceed 2.04 gr/cc, the threshold that triggers the ballooning effect, as verified in the previous well. With the ECD limit set, Weatherford’s MPD experts conducted extensive hydraulics modeling and proposed a suitable mud density of 1.90 gr/cc. This density enables an ample flowrate for hole cleaning while accounting for the expected ROP to avoid the breaching the ECD threshold.
The second consideration focused on setting the minimum equivalent density at the bottom of the hole to maintain wellbore stability. The value selected was 1.96 gr/cc (the maximum collapse pressure being 1.925 gr/cc) and, by applying a surface backpressure (SBP) of 250 psi during connections, the objective would be achieved.
With a strategy to manage downhole pressure in place, the directional drilling team focused on design settings for the optimum performance of the rotary steerable system (RSS). The decision was made to use a push-the-bit RSS with three independent steering pads, in order to reduce wellbore tortuosity and improve reliability.
The engineers extensively modeled different bottomhole assembly (BHA) configurations, seeking the optimal design according to well trajectory. These simulations were conducted along the planned well trajectory to gather a wide scope of results that identified potential hazards related to vibrations, Fig.1. Calibration of the torque and drag friction factors and hydraulics from the offset wells confirmed the drilling parameters were within the rig operating limits. Static analyses played an important role by giving a safe range for weight-on-bit (WOB) to avoid contact forces that could potentially damage tools and identify stresses that could provoke the yielding of BHA components.
Seeing everything via downhole sensors. Real-time directional sensors were used to comply with the programmed targets and minimize wellbore tortuosity. These near-bit sensors accurately measure the inclination tendency while drilling, allowing the directional driller to monitor and make timely steering corrections to avoid a micro-dogleg, which is a typical consequence of aggressive directional work. Micro-doglegs result in a tortuous wellbore that significantly increase downhole torque and drag, risks of mechanical stuck pipe, and issues with getting the casing string to the setting depth. The RSS aided in this effort, due to its proportional steering capability, which also dramatically reduced micro-doglegs in the well and provided a significant improvement in tortuosity.
On this operation, the engineers deployed a downlink system to send commands automatically and reduce the typical lost time, due to downlinking. This system diverts a small percentage of the mud flowrate during the drilling process and associated negative pressure that serves as digitally coded telemetry signals. These signals are received and decoded by drilling tools placed downhole and interpreted as commands from the surface. The flowrate reductions are generated by tapping off a certain amount of the mud flow coming from the mud pump, routing it through the data link connector, and returning it via a bypass line directly into the mud tank. By reducing wellbore tortuosity and rig down time and a smooth wellbore with the RSS, the operator can run casing to the bottom faster and with less risk, enabling the operator to maintain focus on wellbore stability and ROP.
Execution excellence. The objective of 8½-in. liner was to continue drilling the interval at a measured depth (MD) from 9,022 to 15,118 ft, increasing the angle from 9.71° to 20.66° and turning from 327° to 316.04° in azimuth. During the execution phase, real-time data were transmitted from the rig site via WITSML to a Weatherford Real-Time Operation Center (RTOC), where experts continuously monitored drilling operations. The RTOC engineers tracked the well for any trends of downhole dysfunctions, ensured the planned drilling parameters were applied according to hydraulics and torque and drag simulations, and provided proactive interventions when necessary.
Due to the tight ECD threshold to avoid the ballooning effect, RTOC engineers closely analyzed ECD values in real time from the downhole borehole annular pressure (BAP) sensor to identify unexpected values from the ECD. Additionally, the drop pressure on the BHA was tracked and continuously compared with real-time simulations to ensure pressures were within RSS operating ranges.
As a result of the prompt actions taken after discrepancies were detected, the drilling continued, increasing inclination and turning the azimuth according to the planned trajectory. At a MD of 9,878 ft (3,011 m), the final inclination (21.06°) and azimuthal direction (315.11°) were reached. The RSS performance proved optimal, having a separation from the well plan by only 18.5 ft (5.64 m).
Effective communication and timely intervention from the RTOC experts provided pertinent guidelines during unexpected situations. For example, at 11,909 ft, MD, after a downlink was sent to the RSS, a sudden increase in the BHA drop pressure (1,060 to 1,300 psi) put the continuity of drilling at risk, Fig. 2.
After confirming the event with the field crew, a new flowrate was agreed upon to extend the operational life of the RSS without additional trips to the surface. In this case, the reduction of the flowrate to 350 gpm further minimized the risk of ballooning effect by a decrease in ECD to 2.026 gr/cc. After the flowrate change, the hole condition was further evaluated, taking into account hole cleaning by real-time updated simulations to ensure the cuttings percentage was below 3%, even with an ROP of 131 ft/hr.
Coordinated work between the directional services, rig crew, and MPD services guaranteed sufficient SBP when making connections, maintaining the minimal equivalent static density (ESD) to prevent borehole instability. The operator decided to continue drilling until 15,249 ft (4,648 m), where the geologist determined the casing seat for the 7-in. liner.
During the post-well evaluation, the RSS with the custom-designed BHA achieved the planned well trajectory at the end of the hole section. No ballooning effect was observed; consequently, no NPT related to this phenomenon was counted, and the rotating control device (RCD) performed as planned. The operational life of RSS was enough to complete the section in just one run with no significant damage or wear to the pads. Compared with the average ROP of 60.3 ft/hr in similar offset wells, the average for this operation was 81.4 ft/hr and the drilling time was reduced by 25.89%, Fig. 3.
With an optimal RSS solution, the 8½-in. hole section was completed in one run without the ballooning effect and met all requirements from the operator. The planned parameters effectively worked with the operating envelope limitations from MPD operations, including low RPM and range of flow. Operational adjustments were applied with real-time RTOC monitoring and supporting technology deployment from multiple disciplines and contractors.
The success of deploying this RSS technology to drill the 8½-in. hole section, and case it off with the 7-in. liner confirmed the viability of the integrated managed pressure and directional drilling solution in this field. The lessons learned from this job can be replicated in future wells in the field to avoid NPT related to ballooning effect.
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