Historias de Drillingrigcontractor

Through sequenced collaboration between H&P drilling technologies, H&P can help reduce human variability and provide game changing drilling performance solutions with an advanced autodriller control system. Traditional autodriller systems require manual gain adjustments that can cause variable results. A related issue associated with gains that are either set too high manually, or with a semi-fixed gain system, can result in block velocity variability that negatively impacts rate of penetration (ROP), and in some cases bit life that results in additional trips with time, fuel, and emissions impacts.

Challenge A major operator in the Midland Basin had been using the H&P Bit Guidance System with AutoSlide® Technology as their solution to successfully build and scale their remote directional drilling. Although AutoSlide technology was consistently producing better than average curve times, there seemed to be a curve time "ceiling" around 11 hours. H&P believed that curve times below 8 hours were possible in this basin, and set out to raise the bar and help ensure this operator was achieving optimal performance. Solution H&P aims to treat every customer relationship as a true partnership, which is why our Directional Team approached the operator with a bold plan to pause AutoSlide technology for the curve section of the hole where the "ceiling" seemed to exist. Their idea was to drill some of the curves manually to gain new perspective on what could be hindering optimal performance so that they could help the operator achieve their desired outcome.

Drilling practices alone are not enough to accurately deliver a high quality wellbore, as success is equally dependent on the accuracy of the wellbore survey. H&P's Survey Management increases the accuracy and consistency of how we measure boreholes, enabling the delivery of any outcome that relies on knowledge of the wellbore position or shape. These outcomes include landing a curve, properly spacing laterals, safely performing collision avoidance operations, and updating well plans and geological models to accurately reflect data that was measured while drilling.

Staging drilling setpoints after tagging bottom is often inconsistent and can cause drilling dysfunction. H&P transformed this common multi-step task into an automated and configurable process with FlexB2D® technology. Now, with FlexB2D 2.0 operators can realize even more efficiencies than were available before. FlexB2D 2.0 technology performs automated zeroing of the weight-on-bit (WOB) and differential pressure setpoint and helps ensure proper contact with the formation. Automated, configurable, consistent bit engagement ultimately reduces BHA failures and decreases time to target.

This work is novel because it combines a ground based, near-well, magnetic measurement with an airborne derived IFR-1 model. This allows for a greater reduction in positioning uncertainty than has been available in the past. The application of this method to three mile laterals is also new and has a profound impact on being able to plan optimally spaced wells and avoiding collisions. Read out here the full tech paper: https://www.helmerichpayne.com/resources/technical-publications/drilling-three-mile-laterals-tighter-and-safer-with-a-new-magnetic-reference-technique or you can also contact us here: https://www.helmerichpayne.com/contact.

H&P is known for our best-in-class technology and industry-leading rig designs, developed and maintained by the specialized, purpose-driven expertise of our workforce in the field and beyond. Recruiting, hiring, onboarding and initial industry-required training completed offline to begin rig operations Reduces area silos and provides a holistic view of workforce and staffing needs Removes unnecessary burden on Rig Manager recruitment responsibility Detailed analysis of current and future workforce needs Maintain a "bench" of trained and skilled employees is ready for deployment at a moment's notice Best-in-class reduction in workforce processes during downturns allows retention of higher skilled labor and provides employees affected by Reduction In Fleets an opportunity to get back to work as quickly as possible.

We hear the term quite often within the drilling industry. But what does it really mean? Is it even possible to achieve in an industry that operates daily with elevated risk factors? We know it to be true: equipment will fail, and as long as people are involved in the work, failure from human factors is inevitable at some point. However, it is possible for failures to occur in the workplace while maintaining worker safety. In fact, this is what we all should be striving to achieve. That's why the concept of a "SIF-mitigated" category was introduced - framing these mitigated incidents in a positive light, representing the ability to fail safely.

An advanced Archimedes method with all fluid circulation effect has been developed. By tackling the problem of circulating fluid in the drill string using two different approaches and proving their equivalency, a better understanding of the hydraulic effects can be achieved, which in terms can help settle the possible debates and confusions that might arise by drilling engineers. Read out the full tech paper in detail here: https://www.helmerichpayne.com/resources/technical-publications/fluid-circulation-effects-on-torque-and-drag-results-a-new-take-on-an-old-subject or you can also contact us here: https://www.helmerichpayne.com/contact.

The use of time-domain modeling to jointly characterize the behavior of downhole axial and surface oscillation tools introduced in this work allows a better understanding of the coupling between the two tools. This work provides an opportunity to increase the extent of the lateral sections without impairing the wellbore quality. Read out the full tech paper here: https://www.helmerichpayne.com/resources/technical-publications/combining-downhole-axial-and-surface-oscillation-tools-what-are-the-consequences-on-tool-face-control-performance or you can contact us here: https://www.helmerichpayne.com/contact.

The drilling and completion of oil and gas wells is a collaborative business, involving employees from many contractors working together. Well construction generates many documents that are shared cross-functionally between these different groups. A regulator may receive an as-drilled plat from a well planner, using surveys from an MWD operator, based on a pipe tally from a rig contractor. In this scenario, the person legally specifying the well location has likely never physically seen the wellhead or the equipment used to define the location. The regulatory database might later be used by a different operator for identifying offset wells on a nearby drilling program, further confounding matters. While document sharing is critical for successful well construction, there is often little opportunity for verification before use or transmission to another party. A review of documents related to well construction was performed. This included plats, well plans, bottom hole assembly reports, directional surveys, and other drilling records. The examination was performed on which data was contained in these documents, how it might be verified by a third party using it, and the potential for errors to arise when the data is received or transmitted. Of particular concern were documents such as well locations and directional surveys which are not only difficult to verify but are also likely to be further shared with additional parties.

During well planning, specifying the separation that must be maintained from offset wellbores is critical to ensuring safe operations. Recent efforts on API RP 78, an upcoming recommended practice for wellbore placement, have provided guidelines for calculating safe separation distances and engineering considerations for those calculations. A major milestone was the publication of a separation rule (Sawaryn, et al. 2019) standardizing a formula for separation factor (SF), which in turn defines the minimum allowable separation distance (MASD) between two wellbores and the allowable deviation from plan (ADP) for a wellbore being drilled. One element of this formula, σpa, describes the accuracy with which a future wellpath can be predicted. Prior guidance provides a suggested value for σpa (1.6ft or 0.5m at 1-sigma) based on heuristics. A more rigorous approach for estimating this value is presented, where the design of the drilling program can be considered. A framework is proposed for modeling deviation from a projected path using a planned trajectory, bottom hole assembly (BHA) properties, and survey practices. The method identifies where a deviation is detected through survey measurements and estimates a planned recovery operation. Equations are provided for estimating the distance from plan at deviation detection along with the maximum expected deviation during recovery.

Safety performance in the drilling industry is typically measured based on Occupational Safety and Health Administration ("OSHA") recordable injuries and the active rig years worked without an OSHA recordable injury, lost-time, or disabling injury. We view these metrics as lagging indicators, which can and have encouraged the wrong behavior such as under reporting incidents. While we still track these metrics for regulatory purposes, we have improved our safety efforts using a prevention-based methodology called C.A.R.E. (Control and Removal of Exposures). Our employee safety program now focuses on serious injuries and fatalities (SIFs), which places more emphasis on near misses and injury exposures, especially those with SIF potential. We believe it is important to take a more holistic and proactive approach to identify safety issues. By focusing on both actual and potential safety events, we use our SIF system to prevent serious injuries and fatalities as opposed to relying purely on incidents reported after they happen. Our data has identified that approximately 10% to 15% of all OSHA recordable injuries are events in which valuable lessons learned are produced that can be used to reduce potential serious injuries in the future. The remaining recordable cases may not provide the necessary learning opportunities to prevent future serious injuries. Similarly, the data also indicates that SIF Potential incidents, all of which provide information to help prevent future serious injury or fatality, may occur more frequently than recordable incidents.

The drilling industry has undergone significant changes in recent years, leading to increased efficiency, lower costs, and reduced emissions per production unit. As unconventional well construction complexity continues to increase, the next wave of innovation lies in process automation, offering improved consistency and the opportunity to enhance drilling engineering designs. Effectively automating drilling a stand while minimizing human variability requires a scalable control system, providing adaptability, seamless implementation, and improved operational outcomes. The system requires highand low-level process control components to effectively control rig machinery within the bounds of the machine limit controls. By using automation sequences while engaging and disengaging the drill bit, operational states such as breakover, optimal weight on bit (WOB), steady state hookload, and zeroing become easier to distinguish. Through consistent implementation of process automation in drilling operations, the impact on operational outcomes became evident. Analysis of bit disengagement in a series of automatically drilled stands in the lateral revealed a consistent breakover range of 18 to 22 ft. This is particularly noteworthy as breakover is typically more challenging to identify and prone to variability in manual operations. Zeroing WOB in the lateral at a predetermined drilling interval is common practice to calibrate the drilling system, and procedures provided by the operator are often conservative due to human variability resulting in slower process execution. While drilling automated stands in a lateral, it was determined the lowering sequence of the process could be reduced by half to effectively zero the WOB and differential pressure, reducing invisible lost time. Not all invisible lost time and variability is human related; variability due to equipment design was reduced.

These analyses can constitute guidelines about stabilizer design to minimize vibrations. The novelty of this work is to introduce the geometry details of the stabilizers in the time domain dynamics to differentiate designs in terms of likelihood to trigger vibrations. Reach out to us to read out the full tech paper here: https://www.helmerichpayne.com/resources/technical-publications/detailed-dynamics-modeling-helps-to-assess-the-effect-of-stabilizer-design-on-drillstring-vibrations or you can directly reach out to us here: https://www.helmerichpayne.com/contact.

H&P aims to treat every customer relationship as a true partnership, which is why our Directional Team approached the operator with a bold plan to pause AutoSlide technology for the curve section of the hole where the "ceiling" seemed to exist. Their idea was to drill some of the curves manually to gain new perspective on what could be hindering optimal performance so that they could help the operator achieve their desired outcome.

H&P's Advanced Well Engineering service combines the vast experience of their engineering team and DrillScan® digital solutions, an industry-leading technology, to optimize the delivery of high-performance wells for operators. Our comprehensive solutions are tailored to help you achieve your desired outcome by addressing critical areas such as drilling performance, operation efficiency, and well design. We offer reduced cycle times, lighter well architectures, and measures to minimize exposure to safety hazards associated with drilling operations.

Lateral spacing in unconventional plays can have a significant impact in the economics of field development (Bharali et al., 2014; Lalehrokh & Bouma, 2014). This spacing is most often verified using magnetic measurement while drilling (MWD) instruments. In well spacing studies, the distance between two laterals is typically assumed to be precise, however, MWD may have large uncertainties associated with their bottom hole locations (Williamson, 2000; Grindrod et al., 2016). Learn more about us: https://www.helmerichpayne.com/resources/technical-publications/empirical-analysis-of-lateral-spacing-uncertainty-in-north-america-due-to-mwd-survey-error or you can reach out to us directly here: https://www.helmerichpayne.com/contact.

Everyone experiences stress and anxiety, whether it stems from workload, work environment, family challenges, or financial struggles. Sometimes, it results from a traumatic incident or the loss of a loved one. Whatever the cause, we all encounter it at some point. Understanding how to address mental health challenges and knowing the available resources can make a world of difference.

Performance contracts are increasingly common in the drilling industry, especially in recent years. This incentivized contract structure, established as a partnership between operator and contractor, improves both well performance and operational execution while incorporating the rig contractor as an additional stakeholder in the operational performance of the well. Many performance contract styles exist, with one common goal: if targets are met, all parties involved benefit.

Our FlexRig® fleet offers configurations to deliver more power, more finesse, and greater mobility to match the demands of your operations. › The industry leader in performance and safety › Multiple configurations to match the unique demands of your drilling operation › Integrated advanced technologies paired with fully autonomous solutions