Baker Hughes (Germany)

Abstract High-Frequency Torsional Oscillations (HFTO) present a major challenge when drilling hard formations, often leading to reduced performance and tool failure. This paper compares two modeling approaches for evaluating HFTO stability across the drilling system: a fast analytical criterion-based simulation and a detailed time-domain simulation using reduced-order modeling (ROM). Both aim to predict bit-induced HFTO excitation and rank bit designs accordingly. Both modeling approaches use a shared physics-based bit force model to compute torque response as a function of weight-on-bit (WOB), depth-of-cut (DOC), and RPM. The first method applies a damping-based criterion for rapid HFTO stability assessment. The second uses a physics-informed ROM to simulate dynamic responses over a wide range of operating conditions. Both incorporate BHA configuration via sub-models to generate torsional stability maps. Validation against lab and field data confirms their reliability and practical relevance. Experimental testing of ten 8½″ bit designs on a full-scale lab BHA showed that cutter and blade configurations can influence the HFTO-stable operating space by up to 40%. Both models successfully ranked bit designs while accounting for key BHA parameters such as motorization, damping tools, and inertia. The criterion-based model enables fast evaluation (under 5 minutes), making it suitable for early-stage design screening and real-time field use where speed is critical. It integrates well with automated drilling control systems to enhance rate of penetration and decision-making efficiency. In contrast, the ROM approach featuring axial-torsional coupling offers deeper insight into instability mechanisms and is best suited for thorough system validation prior to deployment, albeit with higher computational effort. This work introduces two complementary simulation frameworks that advance HFTO prediction and mitigation. The ability to rank bit designs without extensive experimental calibration marks a significant technical step forward, supporting more stable and efficient drilling operations in challenging environments.

This work presents a 3-in-1 multi-mode amplifier, including automatic gain control (AGC) and logarithmic gain, which achieves a total gain of 9.5–85.5 dB and an input-referred noise (IRN) of 4.7<inline-formula xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink"> <tex-math notation="LaTeX">$\mu $</tex-math> </inline-formula>Vrms within a bandwidth of 136 kHz. The PVT-focused amplifier design operates from −25 °C to 200 °C and does not require any trimming. Incorporating a parallel piecewise logarithmic approximation using nine passive-switched-capacitor (PSC) stages with a fixed gain of three (0.015 dB error per stage), the temperature stable absolute logarithmic error is 0.5 dB. This leads to a logarithmic conformity error (LCE) of 0.75 % up to 200 °C.

Abstract The Steerable Liner While Drilling (SLWD) technology has proven to be an effective solution for drilling through challenging formations such as rubble zones, unstable tar layers, and weak overburden. Today, this technology is also used to drill through different pressure zones in mature assets. This publication will describe the evolution of the Steerable Liner While Drilling system and outlines some of the case studies. A Steerable Liner While Drilling system is a combination of advanced Rotary Steerable Drilling system and Liner Drilling allowing to drill complex wellbore trajectories. The liner is carried directly with the Drilling BHA. This concept mitigates the risk of hole stability issues and hole collapse between drilling and liner runs. After drilling to target depth, the pilot drilling BHA is disconnected from the liner which is left downhole. A typical application is where the section can be drilled easily but running the liner is problematic. The smearing, or plastering effect brings additional benefits in strengthening the bore wall. Steerable Liner While Drilling technology is used for more than 15 years and has proven its functionality in various applications in new and mature fields. It has been used in different formations like sandstone and carbonates where unstable formations or depleted reservoirs lead to drilling- or liner running problems. The technology has evolved based on changing objectives and increasing requirements, becoming a strong and reliable solution to drill instable formations and to bridge different pressure zones in mature assets. Originally developed to navigate trouble zones, SLWD technology has enabled faster wellbore construction in these applications and, in some cases, access to formations previously considered un-drillable using conventional drilling and completion technologies. SLWD systems mitigate the risk of wellbore collapse or losing the wellbore before the liner is run. Depleted reservoirs in mature assets becoming more and more the focus of operators globally. With the advent of second-generation BHA designs, SLWD continues to push the boundaries of what is technically feasible in complex drilling environments. The design has improved compared to first generation tools allowing longer and more reliable liner runs.

Abstract Drilling automation has emerged as a transformative force in the oil and gas industry, revolutionizing traditional drilling operations to enhance efficiency, safety, and cost-effectiveness. Central to its successful implementation are robust verification and validation (V&amp;V) processes, which ensure the reliability, accuracy, and safety of automated systems. This paper explores the V&amp;V of applications deploying wellbore protection and drilling optimization Advisors integrated with automated drilling control systems (ADCS). Drilling automation applications performing wellbore protection (e.g., pack-off, hookload, over-torque, among others) and drilling optimization functions (e.g., rate-of-penetration (ROP) optimization) are deployed on an edge device connected to an automated rig control system (ADCS). The Advisors parameterize existing capabilities of the ADCS to carry out protection and optimization tasks. The interplay between Advisors and the ADCS is evaluated using a simulated rig environment at different levels: system integration test (SIT) and hardware-in-the-loop (HIL). A variety of test cases are executed to assess how each Advisor performs in conjunction with the ADCS and how stable the integration is under both normal and contingency conditions. Each Advisor performs a self-assessment of its readiness to execute its function safely. The ADCS determines how to assign control of rig activities based on the availability of Advisors. The first layer of V&amp;V, using SIT, simulates surface and downhole sensor signals that are ingested by the Advisors to test the interoperable system. The second layer, using HIL, generates sensor signals via actual programmable logic controllers (PLCs) to achieve a more realistic representation of the rig site. A series of tests enables a thorough assessment of whether each interoperable function between Advisor and ADCS meets design requirements (verification). Furthermore, the execution of these tests in the presence of multiple stakeholders (i.e., operators, drilling contractors, service companies) ensures that the systems perform as intended under real-world conditions (validation). Given the high stakes in drilling operations—including financial risks and environmental concerns—a comprehensive V&amp;V framework is essential. With this approach, potential flaws are detected early in the process and can be resolved during the development phase. This paper presents a summary of the test cases executed for each Advisor across all rounds of testing, along with the corresponding learnings toward achieving seamless interoperability at the rig site. All tests were witnessed by multiple stakeholders representing operators, drilling contractors, service companies, and even assurance and risk management auditors.

Abstract Many oil and gas fields are approaching the end of their productive life. Production rates are declining, forcing operators to decide whether to shut down production and plug and abandon (P&amp;A) the wells or explore cost-effective revitalization methods instead of drilling new wells. Coiled Tubing Drilling (CTD) has been used for over 30 years to improve production rates in aging fields. This technology has evolved in response to changing operational objectives and increasing technical requirements, becoming a robust and reliable solution for enhancing production in mature fields. Today, most operators are reviewing their existing, aging assets and evaluating solutions to revitalize fields while maximizing the recovery factor. CTD has emerged as a preferred method for re-entering existing wells and accessing undrained reservoir sections at a fraction of the cost of drilling a new well. This paper examines the evolution of CTD technology, drawing insights from past lessons and technological advancements. It covers the progression from the first-generation CTD bottom hole assembly (BHA) in the 1990s, to the second generation with enhanced measurement capabilities and higher build rate performance, and finally, to the latest advanced high-temperature version. The development of these technologies is analyzed in correlation with evolving market requirements. Different regions have specific CTD applications and operational constraints. The Middle East, for example, has utilized CTD since 1998 and has been a key driver in the development of high-temperature-rated and H^S-resistant BHAs. Examples of successful longterm projects, spanning 15 to 20 years, will be presented to demonstrate the technical and economic viability of CTD for field redevelopment. Recently, the increasing demand for longer wells and more precise well placement has driven innovations in rib -steered motor technology. The first-generation rib-steered motor was designed to drill straight, long lateral sections, effectively mitigating early lockup issues experienced with conventional orienter-steered BHAs. The second-generation rib-steered motor introduced significantly higher build rates, making it suitable for both lateral and build sections. Future developments will continue to optimize these tools, particularly for high-temperature applications in the Middle East. Additional and optimized Logging While Drilling (LWD) services like Gamma and Resistivity which can measure into different directions will enhance reservoir placement and Geosteering capabilities for Coiled Tubing Drilling in the future.

Flat objects like electronic boards are challenging samples for high-resolution X-ray computed tomography scanning because their largest dimension significantly limits the magnification using circular trajectory scans. One way to improve spatial resolution for such samples is to utilize variable zoom trajectory. During variable zoom trajectory scanning, the source-to-object distance changes during the 360° rotation to maximize the magnification in the projections. Here, we propose an automatic variable zoom trajectory generation algorithm for arbitrary object and region of interest (ROI). We analyze how such a trajectory can enhance resolution in different cases and how isotropic is the resolution in the reconstructed volume. We demonstrate that the resolution can be improved without destroying the sample. However, the improvement is manifested mainly in directions in which we achieved the highest magnification in the projection.

Abstract Drilling operations in the US Permian Basin shale play with a new 4-¾" Rotary-Steerable Drilling System (RSS) revealed that with high Rates Of Penetration (ROP), high Weight On Bit (WOB) (and other drilling parameters) encountering stringers or interbedded formations can lead to unwanted effects. The Bottom Hole Assembly (BHA) can be deflected before the steering unit with its steering pads can counteract the deflection. This can lead to deviations from the directional plan and High Local Doglegs (HLD) when drilling in the horizontal/lateral section, which can have a negative impact on the electronics within the steering unit. As a countermeasure, a combination of a pin-down connection steering unit with a short box-up connection drill bit, or Integrated Bit (IB), was developed. This combination allows a much shorter bit to steering pad distance. Due to the shorter bit-to-pad-distance an improved steering response is expected resulting in fewer high local dogleg occurrences. The integrated box-up bit basically moves the drive-shaft pin-down connection into the drill bit. The remaining bit shank is very short requiring modifications to the make-up and break-out procedure. Results from the data acquired in the Permian Basin shale play yielded promising results in terms of steering accuracy. When comparing bending cycle load vs. local Dogleg Severity (DLS), local DLS are typically lower and have less bending cycles drilling through these critical local DLS when IB were deployed. The overall average ROP of runs with IB is higher than the overall average ROP of runs with standard bits. The amount of data collected for this study allows a good statistical approach for comparison of the performance of a standard drilling BHA and bit versus a BHA featuring an IB. It proves that by further reducing the distance between the first formation contact point at the drill bit to the second contact point at the steering unit there is an overall improvement in performance and wellbore placement. This provides opportunities for incremental future optimization of the drill bit and BHA system.

Abstract This paper describes the solution developed by Baker Hughes to maximize efficiency in a de-flaring project by applying a Dry Gas, Liquified Petroleum Gas, and Condensate recovery system to a mid-size associated gas source. The target of the solution is to combat climate change and generate value for the industry by providing an effective approach to address the major environmental challenge of associated gas flaring (The World Bank Group, 2023). The methodology used to provide a detailed description of the recovery system is constituted by outlining the key components and their functions. The main process parameters are also presented, including temperature, pressure, and flow rate, as well as the by-product deliverables of the plant. To provide a practical example, a typical flare gas stream is used as a reference case study, representing 100MMSCFD of raw gas and equivalent to 338 CO2t/hour calculated emission. Field validated models, regularly employed by Baker Hughes in project executions, are adopted as the method to simulate process and rotating equipment performances. The fractionation of raw gas, which involves separating the different hydrocarbons present in the gas stream, is a highly effective method of reducing associated gas flaring emissions. In combination with other measures, such as improved flare management and process optimization, it can reduce emissions by up to 95%. Moreover, the recovered gases can be used to produce export products, with a recovery efficiency of over 98% for propane and heavier hydrocarbons, depending on feed gas composition. By implementing this solution, the yearly revenues generation is expected to be up to $0.2 billion (U.S. Energy Information Administration, 2022), while also helping to combat climate change. This approach represents a significant step forward for the oil and gas industry, offering a way to turn waste into value and improve sustainability. This paper presents an innovative solution to combat routine gas flaring by describing an integrated gas processing solution for associated gas recovery. The paper provides valuable insights for researchers, engineers, and stakeholders interested in addressing climate change and maximizing the efficiency and efficacy of de-flaring projects.

This article describes a certification procedure which includes both the qualitative and quantitative characterisation of the acoustic response of reference reflectors. It is dedicated to one-dimensional reference defects such as notches or side drilled holes but can be generalized also to two-dimensional reflectors such as flat bottom holes. At the beginning relevant measured quantities are introduced. This includes the defect homogeneity and the effective defect length which are extracted from the acoustic reflection profile. Afterwards, a setup for the performance of certification measurements is shown and the overall procedure is described. All results are summarized in a standardized protocol. At the end, the reference certification in the daily use is discussed. Due to the large database a statistic evaluation can be presented. It shows that a significant percentage of references do not fulfil the given quality criteria. The importance of a quality monitoring at different time periods is illustrated with an example of a reference notch where measurements before and after commissioning revealed a significant quality degradation. Finally, the presented method can serve as basis for updates of common standards with respect to a more complete specification of reference reflectors which will be needed due to the increasing demands on the accuracy of ultrasonic testing systems.

Abstract The majority of directional, measure-while- and logging-while drilling tools as well as non-magnetic drill collars (NMCD) are manufactured using austenitic CrMn-stainless steels. These proprietary grades meet the demanding requirements in terms of mechanical, magnetic and corrosion resistance properties necessary for these applications. However, these grades might become susceptible to pitting and environmentally assisted cracking (EAC) when subjected to high chloride-containing water-based drilling fluids at elevated temperatures. Consequently, Ni-stabilized austenitic stainless steels with higher contents of chromium and molybdenum are preferred in these environments. In a similar manner as for CrMn-stainless steels, thermo-mechanical processing including warm or hot working as well as welding can lead to sensitization of these grades. Sensitization in CrMn-stainless steels was indeed the driving force behind the introduction of quality assurance testing per ASTM A262 in API specification 7-1. Recent studies have shown that ASTM A262 Practice A has limitations when used in high Ni-containing grades used in drilling technology, though. In this study, ASTM G48 Method A was evaluated as a potential standardized test method for assessing sensitization and pitting corrosion resistance of CrNi-stainless steels used in drilling equipment. Results from ASTM G48 were also compared with results from more traditional quality assurance methods like Charpy V-notch impact energy and ASTM A262 Practice A obtained on several commercially available grades.