Assaad, Wissam (Shell Global Solutions International B.V.) | Di Crescenzo, Daniele (Shell Exploration & Production Company) | Murphy, Darren (Shell Exploration & Production Company) | Boyd, John (Shell Exploration & Production Company)
In this paper, we present a method of modeling surge pressures and wave propagation that can occur during well execution. The surge pressures have an effect on formations [i.e., formation fracture resulting in mud losses and nonproductive time (NPT)]. Knowing the amplitude of surge pressure in advance can lead to operation redesign to avoid losses. Swab- and surge-pressure waves can occur at numerous events during well execution. For example, during liner operations, pressure waves can occur at dart landing or plug shearing, liner-hanger setting, or clearing a plugged shoe-track component. It is possible for surge-pressure waves to create fractures in shale and sand layers (i.e., when surge-pressure-wave amplitude exceeds formation fracturing resistance).
A transient-state physical model is built to compute pressure-wave propagation through drillstring, casing, and open hole to predict the amplitude of a surge-pressure wave and to warn when a fracture might occur in the formation, to avoid mud losses and NPT.
In the model, continuity and energy partial-differential equations (PDEs) are built for a cylindrical fluid element contained in an elastic hollow cylinder. The method of characteristics is applied to convert the PDEs to ordinary-differential equations (ODEs). The ODEs are solved numerically to compute pressure distribution along well depth and in time. The model is implemented as a graphical-user-interface (GUI) tool to be used by drilling engineers at the design phase of a well to avoid losses. The GUI tool is targeted to address different scenarios that take place during the cementation process. To date, the transient-state physical model has been applied successfully in various applications, such as monodiameter technology, running casing, and perforating operations. Two cases are studied, one for a well in the Gulf of Mexico (GOM) where mud losses have been reported, and the other for a well in Malaysia where no mud losses have occurred. Pressure-wave computations are performed with the GUI tool for the two cases. The results of both cases are presented in this paper and show that formation fracture can be predicted by the GUI tool and subsequent losses can be avoided.
Human factors are identified as the major contributor to oil and gas drilling and other operations related accidents. Offshore oil and gas operations involve complex scenarios and decision-making with potentially catastrophic consequences. The current simulation-based training modules are often criticized for their lack of objective and validated measures for human factors and non-technical skills. There is also a need to include measures for enhanced situational awareness and decision-making for the offshore drilling crew. In this study, we present holistic human-centered training framework equipped with assessment techniques to analyses situational awareness of partcipants in customized well-control operations.
The training exercise used in this work included real-time well control operation customized for drilling break and kick detection scenarios. The assessment approach consisted of eye-tracking data analysis, questionnaire analysis, checklist score analysis, and communication log analysis. After individual analysis from each technique, a new framework was developed to triangulate results from each technique to provide a comprehensive assessment. The participants included seven group of novices and one group of experts. The preliminary results indicate significant differences between the situation awareness and performance of participants. Furthermore, there were observed notable differences between the perceptual, comprehensive, and projection ability of novices and experts in routine jobs on a drilling platform. The eye-tracking data features included fixation count and fixation duration, and it was inferred that eye-tracking results can be representative of cognitive abilities of the partcipants. Furthermore, the fixation count and duration results were highly correlated with the checklist scores.
Overall, the adopted methodology in this study have potential to open new avenues for human- centered training framework and improvement in traditional assessment approach. Furthermore, it can also be helpful in understanding of cognitive responses of the offshore professionals.
Maintaining well control is one of the most important considerations of any drilling operation, and early detection of formation fluid influx or mud losses is vital to safe drilling.
Today's gain and loss detection tends to trigger too many false alarms; major improvements in reliability (few to no false alarms) and reactivity (no missed events) are needed without being user dependent. The new developed system optimizes both accuracy and efficiency. This system maintains a false alarm rate lower than current system, while detecting influxes or losses as low as 40 gal. It applies also to a wide variety of configuration: deepwater, managed pressure drilling, land rig operations, etc. This performance is achieved through a new flow-modeling processes combined with automated settings, real-time quality control and guided, intuitive software interfaces. From a purely user-dependent system, the new kick detection software is now based on automated processes, ensuring repeatable and optimal detection performances while minimizing risks of human error. The detection of abnormal flow conditions in the well relies on the comparison of predicted and measured flow at the exit of the well. The improvements of the flow modeling, such as new, calibrated pump-efficiency models based on the isothermal modeling of the pumps, increase the robustness and the reactivity of the detection system. The presented case studies allow quantifying improvements of the kick detection performance between the existing system and the new version, benchmarking both the influx-detection reactivity and the system reliability. Kick detection charts used in the study represent a new way of illustrating detection performances.
A blowout contingency plan was made for a gas field in a remote area with water depth exceeding 1600 m. The worst-case discharge analysis for a representative well in the field concluded that the reservoir is capable of producing at a highly prolific rate, which posed a challenge when developing a source control contingency plan that complies with governing regulators' and operators' internal requirements. Simulations using a transient multiphase flow simulator showed that the kill requirements could exceed the capability of a single conventional relief well; however, planning to intersect and coordinate a dynamic kill using multiple relief wells involved unacceptable operations risks. Furthermore, considering rig availability, limited pumping resources, and long mobilization times for this region, planning to use multiple relief wells is not a feasable option. A recently developed subsea flow spool system can eliminate the need for multiple relief wells in the case of potentially hard-to-kill blowouts, especially where a dynamic kill using multiple relief wells would involve unacceptable operations risks. Dynamic kill simulation shows that the subsea flow spool, coupled with a supporting mobile offshore drilling unit (MODU), flexible flow lines, a supplementary flow spool, and a casing string placed inside the riser will be able to achieve a successful kill if needed. Furthermore, detailed engineering analysis of triaxial loads, fatigue, and erosion were done for critical hardware components to ensure all potential failure points were addressed.
Dooply, Mohammed (Schlumberger) | Schupbach, Michael (Murphy Exploration & Production Co.) | Hampshire, Kenneth (Murphy Exploration & Production Co.) | Contreras, Jose (Schlumberger) | Flamant, Nicolas (Schlumberger)
Two of the most important parameters to monitor during a primary cementing job are the pumped-in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often resulted in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out). This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.
Several mature fields in the North Sea experience significant challenges relating to high pressures and temperatures accompanied with the infill drilling challenge of very narrow margins between pore and fracture pressures. To navigate these narrow mud weight windows, it is critical to understand the bottom hole pressure. However, in the cases of fractured formations above the target zones, severe losses can be encountered during drilling and cementing operations often leading to the inability to maintain a full mud column at all times and even threaten the ability to reach TD.
The operator therefore decided to investigate the use of a new acoustic telemetry system that could provide internal and external pressure measurements, (along with other downhole measurements) independently of traditional mud pulse telemetry in the drilling assembly. Real-time distributed pressure data essential to understanding the downhole conditions could therefore be provided regardless of circulation, even under severe losses or during tripping and cementing operations.
This acoustic telemetry network was deployed on several wells through multiple hole sizes and including losses management, liner running and cementing operations.
The initial primary purpose of running the network was the ability to monitor the top of the mud at all times, even in significant loss situations. As real-time data was acquired it became apparent that the data could also be used in real-time to aid and help quantify the actual downhole pressures. The use of this downhole data was modified and new calculations designed for simpler visualization of equivalent circulating densities at the shoe, bit and identified weak zones in the well at depths beyond the acoustic tools themselves. This data was used to manage the bottom hole pressure within a 300 psi mud weight window to ultimately enable the well to be delivered to planned TD.
The tool and calculations helped verify managed pressure connections and subsequent pump ramp up and down operations to minimize pressure fluctuations in the well. Additionally the data was used during dynamic formation integrity testing and to measure and calculate ECD at various positions along the drillstring and casing when downhole PWD measurements were unavailable.
This paper will describe how the implementation of new technology through the downhole acoustic network was deployed and the lessons learned in how the real-time data was used, changed and adapted in this particular well. Due to this deployment the acoustic telemetry network will now be used on upcoming equally challenging wells and its range of operations expanded to include drilling, tripping and liner cementing operations.
Following the significant reservoir depletion on Elgin / Franklin fields since 2007, drilling infill wells was considered to not only be high cost but also carry a high probability of failure to reach the well objective. The recent campaign on the Elgin field, one of the most heavily depleted reservoirs worldwide, demonstrated that infill drilling can be achieved safely while improving performance.
Drilling of HPHT infill wells on the Elgin field faced increasing challenges arising from the reduction of reservoir pressure that changed the stresses in the formations above and influenced the overall pressure regime. This stress reorganization in the overburden has affected the fracture network in these formations resulting in reduction in Fracture Initiation Pressure (FIP) and increase of gas levels.
Challenges were faced during the drilling of three wells in the 2015-2017 campaign. Loss events in Chalk formations in the intermediate sections significantly decreased the already Narrow Mud Weight Window (NMWW). A strategy to define and validate the minimum required MWW in 12-1/2" and 8-1/2" sections was developed following a complex subsurface well control event. Managed Pressure Drilling (MPD) technique was extensively used to safely manage gas levels and assess pore pressure.
Reservoir entry with more than 850 bar of overbalance remains the main challenge in infill drilling. A total loss event during first reservoir entry in the latest campaign confirmed the limitations of wellbore strengthening mud and stress caging materials available today.
Lessons learned from each well in this campaign were implemented to address these challenges and improve performance. This paper describes the Elgin HP/HT infill drilling experience and the specific techniques and practices that were developed to address these challenges and improve performance. The importance of Equivalent Circulating Density (ECD) management with very narrow MWW, successful high gas level management with MPD and depleted reservoir entry, shows that even in a highly complex environment, drilling performance can be improved allowing for further economical development drilling. The successful and safe delivery of the Elgin 2015-2017 infill drilling campaign demonstrates this at a time the industry moves toward unlocking the reserves of more challenging HPHT fields.
A long-term suspended subsea exploration well within a producing gas reservoir needed to be decommissioned after 21 years. During a pre-decommissioning diving campaign, bubbles confirmed as reservoir gas were observed to be percolating from the well bore through a hard silt / cement debris plug inside the wellhead. A pressure study established that the reservoir may have re-charged to 2,200 psi. An alternative pressure controlled well re-entry method was required to safely re-enter, tie-back the well to surface with 16-in. high pressure riser, install BOP while preventing gas from reaching the rig floor from seabed. Two existing cement plugs would then be drilled out under controlled conditions due to the potential for high-pressure gas beneath the plugs. Casing integrity evaluation and cement bond logging would be carried out to establish the path of gas ingress into the wellbore. Remedial work would be conducted, and permanent abandonment barriers installed in the well. Casings and wellheads would then be recovered from a depth below the seabed.
A customized managed pressure drilling (MPD) system was designed using a rotating control device (RCD) and modified drilling chokes. A pioneering plan was developed to meet the specific well re-entry requirements of the percolating suspended well to account for the potential for virgin reservoir pressure at seabed and the wellhead silt plug preventing deployment of BOP test tools. A hazard and operability study (HAZOP) was conducted with key personnel, which supported development of well-specific operating procedures and decision matrices. Successful deployment included MPD system calibration, well behavior fingerprinting, and training of rig personnel at the well site.
The combination of experienced personnel, innovative MPD equipment, specific procedures, team interactions and risk analyses were key to safely completing this well re-entry and decommissioning scope. The strategy enabled drilling out of two cement plugs with potential high-pressure gas trapped beneath them. Both cement plugs, 356ft and 669ft long, were drilled without any well-control or plugged-choke events. Throughout the process, the well was monitored using MPD equipment, which included an RCD on top of rig's BOP, modular drilling chokes and multiple pressure gauges and sensors installed at critical points. Additionally, temporary modifications were made to the rig and new lines of communication between the rig crew and the MPD team were established to ensure all pressures were correctly interpreted and the decision matrix was correctly applied. An effective close partnership developed between the equipment service provider, well operator and drilling contractor was a key enabler to deliver this very challenging novel implementation of MPD technology within eight weeks. The MPD approach was estimated to have saved 9 days of rig time, when compared to alternative coiled tubing-based solutions.
This paper describes the first MPD-assisted well re-entry for well decommissioning in the UK North Sea sector. The novel application of existing technology can help operators to cost effectively re-enter and decommission troublesome legacy wells without harm to people, environment or assets. This new approach resulted in the safe unconventional re-entry and decommissioning of a potentially live gas well.
Nine years have passed since the Deepwater Horizon disaster and industry is in a considerably better position to respond to a loss of well control of that scale. With the delivery of the Offset Installation Equipment (OIE) in January 2018 the joint industry Subsea Well Response Project (SWRP) has drawn to a close. Despite this, equipment and services continue to be developed. This paper will communicate developments in subsea well response technologies and the latest guidance developed by industry.
This paper provides an overview of the International Oil and Gas Producers (IOGP) Report 594 - Source Control Emergency Response Planning Guide for Subsea Wells. What should a comprehensive subsea Source Control Emergency Response Plan (SCERP) consider? What resources including manpower, expertise and equipment would be required for a controlled response? In addition, it provides an overview of recent enhancements in subsea well response equipment. This includes; offset installation equipment (OIE) for shallow water scenarios where vertical access above a wellhead may not be possible and air-freight capping stack solutions to minimise incident country configuration and testing.
The findings from technical and logistical studies, whilst developing this technology, will be clearly communicated for industry consideration. This includes critical activities to be considered in developing response times models. This paper will demonstrate that capping equipment located in country does not necessarily improve the overall response time for a loss of well control event; an effectively planned response is more important than immediate hardware availability. The importance of mutual aid of personnel and equipment in a response will be key as not one company can provide all the solutions.
Although only required for remote or land locked basins, to further enhance industries capabilities, it has recently been demonstrated that existing ram based capping stacks can be transported by air, without disassembly, and thereby maintaining pressure boundaries. This allows for a more rapid air mobilisation to the incident location without the need for major re-assembly upon arrival.
Understanding pressure and pressure relationships is the key to safe well control. Yet, to date, the primary focus of well control has centred on recovery rather than prevention. Incidents related to loss of well control largely occur when the primary barrier, hydrostatic pressure from the drilling fluid, fails to prevent an influx; thus requiring the secondary barrier, closing of the BOPs, to engage in order stop the breach from becoming a full-blown, well control incident. Influxes occur, most often, during the tripping operation where the swab effect lowers the bottomhole pressure below the formation's pressure and can be commonly misidentified when "wellbore breathing," nuisances gases, or cement setting are involved. Influxes can also occur when drilling into unexpected, higher-pressure zones.