Yuanhang Chen

Summary: Geothermal well control is complicated by elevated temperatures, rapid phase change, and transient multiphase flow during steam kicks and wellbore flashing. Although bullheading is often considered a practical response because it can force fluid downhole while simultaneously cooling the wellbore, the underlying steam/liquid countercurrent behavior and transient thermal effects remain insufficiently characterized for geothermal conditions. In this study, we examine these coupled processes using full-scale nitrogen bullheading experiments to validate wellbore-scale hydrodynamics, followed by RELAP5-3D simulations that extend the analysis to geothermal water/steam bullheading conditions. The study combines full-scale physical testing with numerical modeling. Experiments were performed at Louisiana State University’s (LSU’s) Petroleum Engineering Research, Training, and Testing (PERTT) facility, where nitrogen kicks were introduced into a 5,800-ft wellbore filled with representative water-based mud. These measurements were used to validate the RELAP5-3D simulator’s representation of wellbore-scale hydrodynamics; the validated model was then used to investigate geothermal water/steam bullheading, including wellbore flashing, condensation-driven vapor collapse, and water-hammer transients. The experimental program captured the compression and displacement behavior of a noncondensable gas column and showed that the model reproduced the pressure and temperature response with correlation coefficients greater than 0.95. The geothermal steam simulations further indicate that the dominant challenge is not buoyancy control alone but the management of water-hammer transients generated by rapid steam condensation. Parametric results show that increasing injection rate shortens kick-suppression time but also intensifies the pressure transient, whereas injection fluid temperature plays a smaller role. Specifically, increasing the bullheading rate from 50 gal/min (GPM) to 350 GPM reduced the peak annular steam fraction from approximately 0.75 to below 0.30 within 2 minutes but simultaneously produced significantly higher water-hammer pressure transients. These transients, driven by rapid vapor collapse, represent a previously underappreciated risk to wellbore integrity under geothermal conditions. Overall, the study highlights the distinct physics governing bullheading for conventional gas kicks vs. geothermal steam kicks. By anchoring the wellbore-scale hydrodynamic response to full-scale experimental data and extending the analysis to steam-kick scenarios using RELAP5-3D, the work provides a model-based framework for evaluating geothermal bullheading response. The results indicate that bullheading rate selection must balance kick-suppression speed against condensation-driven pressure transients. The reported peak pressures are best interpreted as conservative, scenario-specific estimates for the modeled pure water/steam system, while the main transferable finding is the rate/severity tradeoff associated with rapid vapor collapse.

Summary: Modern managed pressure drilling (MPD)-based well control operations still face challenges with effective gas influx detection and management, including the application of appropriate kick detection thresholds across different mud systems, and the limited understanding of mass-transfer dynamics and multiphase behaviors when nonaqueous drilling fluids are involved. Through a comprehensive full-scale comparison of gas influx signatures between water-based mud (WBM) and synthetic oil-based mud (SBM) systems with matched rheological properties, the objective of this study is to characterize the mass-transfer-dependent effects on gas influx behavior. Experiments were conducted at Louisiana State University’s Petroleum Engineering Research, Training, and Testing (LSU’s PERTT) Laboratory using a full-scale wellbore equipped with industry-standard MPD systems and distributed fiber-optic sensing (DFOS) technology. A systematic rheological formulation and verification protocol was used to develop WBM and SBM systems with closely comparable flow-governing rheological behavior over the wellbore-relevant shear-rate range. This rheology-controlled design reduces hydrodynamic confounding and enables a controlled assessment of mass-transfer-dependent effects on gas influx behavior. Controlled gas influxes were introduced under various operating conditions, with continuous monitoring of pressure, temperature, and flow parameters throughout the wellbore. Key multiphase phenomena, including gas slippage, dispersion behavior, and mass transfer between phases, were measured and analyzed. The experimental results revealed significant differences in gas influx signatures that challenge the industry practice of applying uniform kick detection thresholds across different mud systems. DFOS measurements provided spatial and temporal resolution of gas influx signatures, showing that SBM systems, despite having closely comparable rheological parameters, exhibited different gas dissolution rates and bubble dynamics compared with WBM. The high-resolution data collected throughout the wellbore showed that conventional models underestimate the complexity of gas-SBM interactions, particularly regarding gas dissolution, reevolution (outgassing), and their time-dependent nature. An advanced transient multiphase flow simulator was used to compare predictions with the experimental observations, enabling refinement of mass transfer submodels and slip correlations in a decoupled manner for each mud system. This improved modeling capability supports the development of enhanced early warning algorithms that account for the unique mass transfer dynamics. This research presents the first comprehensive full-scale experimental comparison between rheology-controlled WBM and SBM systems, providing a controlled full-scale data set that highlights the mass-transfer-dependent effects on gas influx behavior. The unique data set from the full-scale facility with advanced MPD and sensing capabilities addresses a knowledge gap in multiphase flow behavior in different drilling fluids, advancing both theoretical understanding and practical well control applications.

This review explores the population balance method (PBM) and the interfacial area transport equation (IATE) for modeling gas–liquid two-phase flow in vertical pipes. While both methods capture bubble dynamics, they differ in theoretical formulation and computational demands. PBM excels in handling complex coalescence and breakup mechanisms, making it particularly suited for non-Newtonian fluids and high-pressure conditions (up to 2 MPa). However, its computational intensity limits its applicability to large-scale systems. IATE, in contrast, offers an efficient framework for predicting interfacial dynamics and flow regime transitions, making it advantageous for large-scale industrial simulations. However, its empirical correlations remain constrained to air-water systems and moderate pressures (up to 0.6 MPa), limiting its accuracy in complex fluid environments. This review synthesizes these methods’ principles, strengths, and limitations and discusses the implications of choosing one method over another depending on specific application requirements. The comparative analysis emphasizes the need to select appropriate modeling techniques based on targeted operational goals, contributing to more efficient and safer design in engineering practices.

Summary: In an effort to enhance safety and efficiency in offshore drilling operations, we address critical gaps in the current understanding and application of leading indicators for loss of well control (LOWC) events. Existing indicators often fall short in predicting LOWC events accurately and in a timely manner due to a lack of integration of real-time data, which is crucial for proactive risk management. Our study aims to bridge these gaps by identifying robust leading indicators and incorporating them into an advanced real-time detection and response system. The research began with a comprehensive analysis of existing LOWC events to identify the key leading indicators. Using advanced data analytics techniques, including data assimilation (DA) and change-point Bayesian networks (CP-BN), we have developed an integrated real-time kick detection and state estimation framework and evaluated the effectiveness and reliability of the identified indicators. This evaluation was supported by extensive testing, including real-time and offline simulations, as well as full-scale experiments where operational parameters were adjusted to replicate various drilling scenarios. Several key leading indicators were identified based on this study, such as abnormal pressure fluctuations, unexpected changes in drilling fluid properties, and precursors detected through distributed fiber-optic sensing (DFOS) data. We conducted a series of surveys and engaged with industry professionals to gather practical insights and feedback to further validate these findings and enhance the applicability of our results. The integration of these indicators into the kick detection and state estimation framework significantly enhanced early detection capabilities. Experimental testing and assessment of the integrated framework in a full-scale system have demonstrated its operational viability, markedly improved preventive safety measures, and contributed to the reduction of overall system risks. This research represents an advancement in operational safety for offshore drilling operations, facilitating the development of proactive approaches that enable drilling crews to respond more effectively to emerging threats and reduce the likelihood of LOWC incidents. It serves as a foundational study for continued safety enhancements in the oil and gas industry, encouraging the ongoing refinement of safety practices.

Summary: Accurate estimation and prediction of gas rise velocity, length of the gas influx region, and void fraction are important for optimal gas kick removal, riser gas management, and well control planning. These parameters are also essential in monitoring and characterization of multiphase flow. However, gas dynamics in non-Newtonian fluids, such as drilling mud, which is essential for gas influx control, are poorly understood due to the inability to create full-scale annular flow conditions that approximate the conditions observed in the field. This results in a lack of understanding and poor prediction of gas kick behavior in the field. To bridge this gap, we use distributed fiber-optic sensors (DFOS) for real-time estimation of gas rise velocity, void fraction, and influx length in water and oil-based mud (OBM) at the well scale. DFOS can overcome a major limitation of downhole gauges and logging tools by enabling the in-situ monitoring of dynamic events simultaneously across the entire wellbore. This study is the first well-scale deployment of distributed acoustic sensor (DAS), distributed temperature sensor (DTS), and distributed strain sensor (DSS) for investigation of gas behavior in water and OBM. Gas void fraction, migration velocities, and gas influx lengths were analyzed across a 5,163-ft-deep wellbore for multiphase experiments conducted with nitrogen in water and nitrogen in synthetic-based mud, at similar operating conditions. An improved transient drift flux–based numerical model was developed to simulate the experimental processes and understand the gas dynamics in different wellbore fluid environments. The gas velocities, void fractions, and gas influx lengths estimated independently using DAS, DTS, and DSS showed good agreement with the simulation results, as well as the downhole gauge analysis.

Summary: Failed well-capping attempts following offshore-well blowouts undergoing worst case discharge (WCD) can lead to fluid-driven tensile failures (de facto hydraulic fracture initiations). Subsequent propagation of these fractures may lead to broaching of overburden-rock-formation layers and even the seafloor, providing pathways for reservoir hydrocarbons to escape into the seawater. After capping stack shut-in, the pressure buildup in the fluid column inside the wellbore exposes vulnerable locations to tensile (Mode I) failure. If this shut-in wellbore pressure exceeds the formation breakdown pressure (FBP) in any of the exposed-rock-formation layers, a fracture will initiate and will continue to propagate as long as sufficient energy is provided by the reservoir. Scenarios where the propagating fracture(s) broached the seafloor in the past led to severe environmental impacts, disturbing the local ecology. The quintessential example is Union Oil’s 1969 “A-21 Well” blowout in California’s Santa Barbara Channel, where subsequent well-capping attempts led to multiple broaching instances on the seafloor near the well with thousands of hydrocarbon gallons gushing into the seawater (observable from the sea surface as “oil boilups”). In this paper, numerical modeling is performed on a hypothetical case study using deepwater Gulf of Mexico parameters in order to evaluate the likelihood of a similar scenario by modeling a planar-fracture propagation longitudinally-to-the-wellbore, upon well capping. A workflow is developed that integrates post-blowout WCD flowrate and volume estimations, fracture initiation and propagation modeling following the capping stack shut-in, pertaining to a “cap-and-contain” strategy (including predictions in regard to seafloor broaching), along with relief-well intersection followed by kill-weight-mud injection. The casing-shoe depth is the presumed location of fracture initiation, assuming perfect integrity of all casedhole sections above it. Several sensitivity analyses are performed to investigate the impact of the casing-shoe depth, along with the stiffness of the overburden-rock-formation layer, and the post-blowout-discharge duration on the resultant fracture growth. Finally, the mud density and pump flowrate necessary to compensate the oil column to successfully kill the blown well are quantitatively assessed.