Dynamic kill operations in a legacy Texas oil field

MOHAMED AMER, Wild Well Control, a Superior Energy Services company 

In December 2024, a complex well control operation was successfully completed on a legacy oil well—dating back to the early 20th century—located in a historically prolific oil field in Texas. The operation underscored vital lessons in well integrity management and highlighted the inherent challenges of aging infrastructure in mature oil fields. After initial surface interventions proved inadequate, Wild Well Control regained control of the well through a dynamic kill operation, leveraging advanced engineering techniques, multiphase flow modeling and deep operational expertise. 

BACKGROUND AND INITIAL CONDITIONS 

The subject well was originally drilled in the 1920s, and as such, it experienced a series of events that resulted in the ultimate mechanical failure of the well barriers' envelope. At the early stages of the well, it was reported that approximately 500 ft of the surface casing was removed for metal recovery during the Great Depression era. Due to the well's age, historical records were incomplete, resulting in substantial uncertainty in data accuracy and operational challenges for modern intervention techniques. 

The incident well was drilled to approximately 1,600 ft and completed with a 2⅜-in single-tubing completion string. The well was completed as an oil producer through a CO₂ gas drive mechanism. The field's geological characteristics presented unique challenges, including a widely connected fracture network that lifted the oil-producing formation to the surface by utilizing a CO₂ gas cap. The geologically fractured formations presented an operational challenge, including the loss of the primary well barrier and significant fluid circulation losses during drilling and intervention operations. The well continued to produce for more than six decades before it was converted to an observation well. 

INCIDENT DISCOVERY AND INITIAL ASSESSMENT 

During a routine field visit, production supervisors from the operating company observed gas and water emanating from the well cellar. The uncontrolled release contained hydrogen sulfide (H₂S), forming a toxic plume that necessitated the establishment of exclusion zones and the use of specialized personal protective equipment (PPE) protocols to safely access the site. 

Fig. 1. Wellhead status during blowout.

Wild Well Control personnel were promptly mobilized to initiate containment efforts and conduct a comprehensive wellsite assessment. The initial evaluation identified flow originating from outside the production casing, confirming a complete failure of the well's barrier envelope. As a result, the well was classified as Tier 3 in well control severity, which indicates a total loss of containment and the onset of a blowout condition, Fig. 1. 

INTERVENTION STRATEGY AND OPERATIONS 

Phase 1: Surface kill attempts. Upon completing the initial site assessment, Wild Well Control's team developed the initial plan. The intervention strategy focused on regaining hydrostatic control through surface kill operations. Wild Well Control coordinated the mobilization of equipment, including 1,000 bbl of kill fluid commonly used by the operator and completion brine (10 ppg), both of which were supplemented by an additional 500 bbl of solids-laden mud, treated with calcium carbonate loss circulation material. Additional pump trucks were deployed to ensure operational redundancy and maintain continuous fluid delivery throughout the kill procedure. Fluid volumes and pump truck deployment were guided by the operator’s field experience, leveraging readily available resources to support typical low-pressure kill operations. 

The initial kill attempt achieved partial success, temporarily reducing flowrates; however, due to insufficient fluid volumes, it did not halt the blowout. The operation confirmed extensive fluid losses into the fractured formation system, with loss rates significantly exceeding the initial estimates derived from offset well data by the operator's field personnel. Operational parameters from the first attempt were carefully documented and analyzed to inform subsequent kill strategies, incorporating key findings and lessons learned to optimize future intervention efforts. 

Second kill attempt. As the wellhead tree began to lean, early signs of compromised structural integrity emerged. In response, a second kill attempt was expedited, to intervene before further deterioration threatened complete loss of surface access. This attempt employed elevated pump rates and increased fluid volumes, which yielded promising indicators, such as surface mud returns and a significantly reduced flowrate. However, mechanical equipment failures during the operation necessitated an unplanned shutdown, ultimately preventing successful completion of the kill. 

Phase 2: Operational challenges and reassessment. Between kill attempts, significant wellhead washout and ground subsidence occurred, causing the wellhead assembly to lean and impeding safe access for valve manipulation. This structural alteration to the well conditions necessitated a reassessment of intervention strategies. In response, the operational team initiated parallel planning for blowout recovery via a relief well, while concurrently assessing the feasibility of a dynamic kill under the newly altered well conditions using advanced multiphase flow modeling. 

Fig. 2. Example of exclusion zone assessment for worst-case horizontal release scenario.

Phase 3: Dynamic kill execution. After seven days of preparation and planning, Wild Well Control executed a successful dynamic kill operation using engineered parameters, derived from multiphase simulation modeling. 

Key operational parameters: 

• Kill fluid density: 12.5 ppg with loss circulation additives. 
• Staging distance: 1,000 ft from wellhead, for personnel safety. The 1,000-ft zone was based on the exclusion zone assessment, using gas dispersion analysis completed by Wild Well Control's in-house personnel, Fig. 2. 
• Equipment redundancy: Four pump trucks (100% backup capacity). 
• Fluid volume: Double the calculated requirement. 

EXECUTION SEQUENCE 

Diagnostic pumping. To accurately determine the leak path within the production casing, marker fluid injection was performed, prior to the commencement of pumping operations. This diagnostic step was critical for validating the existing flow path and ensuring that engineering models were aligned with actual field conditions. The procedure confirmed flow continuity, as evidenced by the near-instantaneous return of marker fluid through the blowout stream. These results reinforced the reliability of the modeled assumptions and provided essential confirmation before full-scale operations began. 

Pressure management. The pumping plan was designed to establish the necessary Flowing Bottomhole Pressure (FBHP) to exceed the pore pressure within the blowout zones. Initial kill rates were set at 3 barrels per minute (BPM) to verify flow path integrity and prevent potential blockages. Based on the comparison between simulated and observed pressure responses, the rate was incrementally increased to approximately 10 BPM. To safeguard the well's mechanical components, surface pressure was capped at 1,500 psi. Pump rates were staged progressively to stabilize the bottomhole pressure, while accommodating the low-pressure rating of the wellhead valve, ensuring operational safety throughout the procedure.

Fig. 3. Examples of dynamic kill sensitivity.

Flow monitoring. Continuous monitoring of dual flow paths through both the production casing and tubing was maintained throughout operations, to enable rapid intervention, as bottomhole pressure approached static reservoir pressure. This proactive approach ensured early detection and response to any flow path anomalies that could jeopardize operational success. 

Multiphase simulations enabled the development of a range of scenarios related to the downhole fluid conduit, with actual operational parameters falling within the bounds of the analyzed cases. A sensitivity analysis was conducted to evaluate variations in blowout mixture fluid density—an inherently uncertain parameter in blowout kill assessments, Fig. 3. This mixture density plays a critical role in calculating hydrostatic and friction pressures during dynamic kill operations, as it reflects the combined properties of the kill fluid and blowout fluid. Accurate estimation of this density is essential for effective well control planning and execution. 

Results. After pumping 750 bbl of kill fluid, complete flow cessation was achieved. Well stability was confirmed by a 3-hr monitoring period, followed by successful cementing operations, using CO₂-resistant cement with squeeze techniques, Fig. 3. 

TECHNICAL ANALYSIS AND LESSONS LEARNED

This case underscores the critical importance of proactive well integrity programs—particularly for legacy assets in mature fields. The lack of structured monitoring protocols led to an undetected period of uncontrolled flow, prior to discovery. Reliability issues with equipment during key operations further highlight the need for stringent quality control and preventive maintenance, especially in cost-sensitive environments typical of mature field operations. Moreover, the successful use of multiphase flow modeling enabled precise parameter optimization for the dynamic kill procedure, thus showcasing the value of advanced engineering techniques in managing complex well control scenarios. 

INDUSTRY IMPLICATIONS 

This operation highlights several critical considerations for operators managing mature asset portfolios. The first consideration is that regular monitoring and assessment protocols can identify potential issues before they escalate to uncontrolled release events. The second consideration is that maintaining high equipment reliability standards is essential for successful intervention operations. In addition, complex well control operations require specialized engineering capabilities and advanced modeling techniques, and comprehensive record-keeping enables more effective intervention planning and execution. 

CONCLUSION 

The successful resolution of this complex well control event highlights that even severely compromised legacy wells can be managed safely, through rigorous engineering analysis and execution. The operation also highlights the superiority of proactive well integrity management over reactive emergency interventions—both in terms of effectiveness and cost-efficiency. 

Establishing a well control risk management program or a comprehensive well integrity management framework is essential for creating a robust well audit and database. Such systems enable operators to systematically address integrity issues and strengthen overall risk management across oil and gas operations. 

These programs should be developed in a structured manner to support a standardized evaluation of both surface and downhole mechanical integrity of well components. Following this assessment, a targeted risk management strategy should be implemented to prioritize wells based on their integrity status, thereby accelerating intervention efforts for high-risk assets. 

Operators overseeing mature fields must prioritize the implementation of comprehensive well integrity programs that incorporate regular monitoring, preventive maintenance and contingency planning. This proactive approach is critical to minimizing the likelihood of uncontrolled release events and ensuring long-term operational safety. 

MOHAMED AMER is VP of Intervention Wells and Advanced Engineering at Wild Well Control. He leads the operational planning and execution of relief and intervention wells, ensuring daily performance meets the highest standards of safety and efficiency. Mr. Amer focuses on integrating advanced technological solutions to enhance risk management and support critical well control decisions. He oversees complex, high-profile projects, delivering Wild Well’s signature problem-solving expertise and strategic collaboration to operators across both domestic and international operations. He holds a bachelor’s degree in petroleum engineering from Cairo University, a master’s degree in energy and petroleum engineering from Texas A&M University and an MBA from Texas A&M University.