Managed Pressure Drilling Operations Research Articles

Enhancing Offshore Drilling Efficiency through Multilevel Flow Modeling of MPD Operations

Exploiting all forms of energy must be coupled with the preservation of human safety and the environment. Despite the energy reserves beneath the ocean depths, challenging obstacles confront offshore drilling operations, notably the high pressure beneath the well. To comprehend this process better, we turned to modeling the managed pressure drilling (MPD) using multilevel flow modeling (MFM). These models provide a robust framework enabling us to understand and analyze the intricacies of this complex process. Our use of these models allows us to examine the causes and effects associated with various aspects of this process. All of this enables us to drill safely for the well, achieving our primary goal in this context.

New Experimental Results Show the Application of Fiber Optic to Detect and to Track Gas Position in Marine Risers and Shed Light on the Gas Migration Phenomenon Inside a Closed Well

SummaryThe main objective of this paper is to present and discuss the results and significant observations gathered during 13 experimental runs conducted in a full-scale test well at Louisiana State University (LSU). The other two objectives of this manuscript are to show the use of distributed fiber-optic sensing and downhole pressure sensors data to detect and track the gas position inside the test well during the experiments, and to discuss experimental and simulated data of the gas migration phenomenon in a closed well.An existing test well at LSU research facilities was recompleted and instrumented with fiber-optic sensors to continuously collect downhole data and with four pressure and temperature downhole gauges at four discrete depths within an annulus formed by 9 5/8 in. casing and 2 7/8 in. to a depth of 5,025 ft. A chemical line was attached to the tubing allowing the nitrogen injection at the bottom of the hole. The research facilities were also equipped with a surface data acquisition system. The experiments consisted in injecting nitrogen into the test well filled with water by two means: either injecting it down through the chemical line or down through the tubing to be subsequently bullheaded to the annulus. Afterward, either the nitrogen was circulated out of the well with a backpressure being applied at surface to mimic a managed pressure drilling (MPD) operation or left to migrate to the surface with the test well closed.During the runs, the three acquisition systems (fiber optic, downhole gauges, and surface data acquisition) recorded all relevant well control parameters for a variety of gas injected volumes (2.0–15.1 bbl), circulation rates (100–300 gal/min), and applied backpressures (100–300 psi). The experimental results gathered by the acquisition systems were very consistent in measuring gas velocities inside the well. The numerical model predictions matched very close to the pressure behavior observed in the experimental trials. In the gas migration experiments, it was observed that the stabilized casing pressure at the end of gas migration is less than the initial bottomhole pressure, and it is a function of the volume of gas injected in the well. These facts are supported by the numerical simulation results.In this paper, we show the possibility of the use of fiber-optic and downhole pressure sensors information to detect and track the gas position inside a well or the marine riser during normal or MPD operations. Additionally, the vast amount of experimental data gathered during the experiments in which the nitrogen was left in the closed well to migrate to surface helped shed light on the controversial issue concerning the surface pressure buildup while the gas migrates to surface in a closed well. Numerical simulations were all instrumental for supporting the findings.

A real-time probabilistic risk assessment method for the petrochemical industry based on data monitoring

Safety is of high societal concern in the petrochemical industry. With advancing digitalization, the techniques of probabilistic risk assessment (PRA), which provide a system-level perspective for industrial risk analysis, have become increasingly dynamic. This paper provides a further advancement in this direction by proposing a risk updating method based on the dynamic Bayesian network (DBN) to incorporate data monitoring into PRA in real-time. We update the probabilistic risk for basic events in Bayesian networks based on their prior probability and the probability of their online monitoring signals exceeding the alarm threshold. The key idea behind this approach is that if the signal of a basic event exceeds the alarm threshold, the corresponding risk should increase. Otherwise, the basic event should have a low risk. The contribution in this paper is twofold. First, residual methods are developed to estimate signal probabilities exceeding abnormal thresholds. Second, a DBN model is proposed to integrate prior risk with data monitoring for risk analysis. The proposed DBN model does not require additional expert knowledge and historical accident data to define the conditional relationship between data monitoring and prior risk. The proposed approach is validated using the RT 580 experimental setup and managed pressure drilling operations.

Drilling the Undrillable; a Review of Indonesia Onshore Managed Pressure Drilling (MPD) Operation Experiences

MPD (Managed Pressure Drilling) has been used worldwide to overcome drilling challenges in onshore and offshore operations. MPD has proven to save significant cost efficiency in every applications, by reducing NPT (Non Productive Time) caused by drilling problems such as, severe loss circulations, loss-kick cycle, and well control events. Indonesia is one of major country in Asia Pacific that has several needs to developing or exploring new opportunities with drilling challenges, especially in vuggular carbonate reservoirs, narrow drilling windows, and wellbore in-stability. This paper will present the basic theory on MPD, MPD equipment’s, types of MPD, and elaborate more on successful MPD operation in onshore Indonesia, and clustering the solutions of drilling challenges.

Prediction of Reservoir-Kick Effect and Its Management in the Managed-Pressure-Drilling Operation

Summary The sudden influx of reservoir fluids (i.e., reservoir kick) into the drilling annulus is one of the common abnormal events encountered in drilling operations. A kick can lead to a blowout, causing loss of lives, assets, and damage to the environment. This study presents a framework for real-time kick monitoring and management in managed-pressure-drilling (MPD) operation. The proposed framework consists of three distinct steps: the unscented Kalman filter (UKF) is used to detect and estimate the kick's severity; the estimated kick size and optimal control theory are used to calculate the time to mitigate the kick in the best-case scenario; and on the basis of the total predicted influx and pressure rise, the monitoring system generates a warning and activates the mitigation strategy. Thus, the proposed method can estimate, monitor, and manage kick in real time, enhancing the safety and efficiency of the MPD operation. The developed method was validated and demonstrated using a simulated MPD system, a pilot-scale experimental setup, and field data collected from an MPD operation in western Canada.

MPD Well-Design Process Optimizes Design, Delivery of Deepwater Well

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200504, “Using MPD Well-Design Process To Optimize Design and Delivery of a Deepwater Exploration Well,” by Sharief Moghazy, SPE, Wilmer Gaviria, SPE, and Roger Van Noort, SPE, Shell, et al., prepared for the 2020 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 21-22 April. The paper has not been peer reviewed. The complete paper presents a case for using managed pressure drilling (MPD), and the full capabilities of its associated well-design process, to optimize all aspects of the well-delivery process in deep water, including design, safety, and subsurface data acquisition. The process was used to design and drill a deepwater exploration well with an expected pressure ramp and narrow drilling margins while acquiring valuable subsurface data. Introduction The operator’s only offset well in the area faced many challenges including a pressure ramp, resulting in narrow drilling margins. The team experienced several margin-related issues, such as kicks and losses, that resulted in permanent abandonment of the well without reaching the objectives. Given those results, and the subsurface uncertainty, the operator determined that the use of MPD would have mitigated many of the risks and non-productive-time events experienced in that well. The drilling contractor procured a rig fitted with an MPD system to drill a new exploratory well. MPD and the MPD well-design process were employed to increase the likelihood of drilling the well to total depth (TD) safely and successfully by providing the capability to accomplish the following: Account for pore pressure/fracture gradient (PPFG) uncertainty and navigate the expected pressure ramp and narrow margin sections safely by holding a constant bottomhole pressure and adjusting as needed during drilling operations Optimize the location of the casing/liner shoes by identifying the pressure profile based on real-time pore pressure data to potentially eliminate casing/liners, streamline the well design, and retain contingency strings in the event of a more-aggressive pore-pressure ramp Enable early kick and loss-detection capabilities and dynamic influx management to identify, react, and address downhole issues more quickly Use dynamic formation integrity tests (DFIT), dynamic leakoff tests, and dynamic pore-pressure tests (DPPT) to identify the extremes of the drilling margin, derisk subsurface uncertainty, and make decisions while drilling The process used hydraulics modeling to assess the feasibility of several potential scenarios and to understand the deepest possible casing points for a particular PPFG case, mud weight (MW), and well-design scheme. After a base-case well design was created, the maximum allowable kick tolerance was determined using an influx management envelope (IME) analysis, which was used as an input for an MPD operations matrix to be used during the operational phase. During the drilling of the well, the use of the MPD system and the calibration of the hydraulics model to the actual subsurface information allowed the team to continue drilling through more-benign conditions and optimize the well-design configuration.

Marine riser failure analysis for offshore conventional drilling and managed pressure drilling operations

The objective of this paper is to present an analysis of marine riser integrity in conventional and Controlled Annular Mud Level (CALM) offshore drilling operations. A mathematical model was developed to predict the three-dimensional (axial, tangential, radial) and the Von Mises Equivalent (VME) stresses along risers for a typical API X-65 55.88-cm OD, and 2500-m long marine riser. A sensitivity analysis was carried out to investigate the effect of riser thickness, bending, surface backpressure, liquid level, buoyancy modules, and tension from surface tensioners on riser mechanical behavior. To evaluate the riser integrity, the calculated VME stress was compared against the maximum allowable stress recommended by API RP 16Q. The key findings of this study are as follows. First, when maximum VME stress at riser surface is less than the maximum allowable stress, increasing riser thickness does not improve riser integrity. Second, increasing dog-leg severity from 0 to 4 deg./100 ft increases the riser surface VME stress 57% and the riser bottom VME stress 1%. The former VME stress is insignificant because high dog-leg severity occurs near riser bottom where VME stress is small. Third, when tension of 20% of the riser buoyant weight is applied at the surface, the riser integrity is improved more than when using buoyancy modules, which have a density of 4.5 ppg. Fourth, lower liquid level in the riser during CALM drilling operations results in an increase of VME stress, with the highest increase at the top of the riser liquid level. However, under severe conditions, VME stress is often less than maximum allowable stress, indicating that riser collapse is not a concern during controlled annular mud level drilling operations.This study has introduced a simple and accurate method to evaluate the riser's integrity during conventional offshore and Controlled Annular Mud Level drilling operations. The results of this study improve not only the design of risers, but also ensure safe and economic offshore drilling operations.

A sequence-based method for dynamic reliability assessment of MPD systems

Managed Pressure Drilling (MPD) system is widely used in the deepwater drilling operation. Reliability assessment plays a critical role in the MPD system in the management of drilling operation risk and the prevention of blowouts. However, the reliability assessment of the MPD system is challenged due to its sequential operations and multiple processes. Consequently, the present work proposes a sequence-based dynamic reliability assessment method, which focuses on the dynamic modeling of sequential operations for the MPD system by integrating GO-FLOW and dynamic Bayesian Network (DBN). GO-FLOW models are firstly used to define the time interaction between multiple phases for complex systems. A sequence-based mapping method is also proposed for the DBN to construct the reliability model of the MPD system throughout the entire drilling cycle. In the end, the case study analyzed by the proposed framework indicates that the reliability of the MPD system decreases with increasing drilling depth, and the reliability of “tripping in” is highest among four different phases, while the “drilling process” is the lowest. The method provides an important technique that can be implemented with online condition monitoring tools to assess and monitor the reliability of the MPD operation in real-time.

Control-Oriented Modeling for Managed Pressure Drilling Automation Using Model Order Reduction

Automation of managed pressure drilling (MPD) enables fast and accurate pressure control in drilling operations. The performance that can be achieved by automated MPD is determined by, first, the controller design and, second, the hydraulics model that is used as a basis for controller design. On the one hand, such hydraulics model should be able to accurately capture essential flow dynamics, for example, wave propagation effects, for which typically complex models are needed. On the other hand, a suitable model should be simple enough to allow for extensive simulation studies supporting scenario analysis and high-performance controller design well. In this paper, we develop a model order reduction approach for the derivation of such a control-oriented model for single-phase flow MPD operations. In particular, a nonlinear model order reduction procedure is presented that preserves key system properties such as stability and provides guaranteed (accuracy) bounds on the reduction error. To demonstrate the quality of the derived control-oriented model, comparisons with field data and both open-loop and closed-loop simulation-based case studies are presented.

Kick detection and remedial action in managed pressure drilling: a review

Increasing the global demand for natural resources directs the oil industries to explore in geologically challenging structures and offshore reserves. Oil industries are always searching for innovative drilling technologies to optimize field development process in a complex structure. Managed pressure drilling (MPD) is now becoming an attractive alternative to the traditional overbalance drilling in complex formation. MPD offered substantial benefits in terms of project economics and reduced non-productive time (NPT). These benefits are substantial in the offshore structure, where any downtime significantly impacts the project cost. MPD is designed to avoid continuous formation influx into the wellbore, and any incidental fluid is contained with a specific predetermined process. MPD used some specialized tools and techniques to enhance traditional kick detection capabilities and circulate formation influx while keeping NPT at the minimum level. Early kick detection is a primary concern for the drilling industry to ensure the safety of the drilling rig, crews, and environmental protection. This research focused on a systematic review of kick detection and mitigation in MPD operation. A review of recent advancements in MPD, various early kick detection methods, comparative study of different kick indicators with their significance, different gas kick models, and risk analysis are analyzed systemically. Several control methods in the MPD operation are summarized. A systematic comparison of different gas kick circulation methods in conventional drilling and MPD is presented in this study. Also, different alternative responses to conventional kick circulation methods are summarized. This work critically analyzed different kick responses of circulating and non-circulating methods, e.g. shut-in, modified pump shut down, increasing in casing pressure and stepwise increase in pump rate. However, all circulation methods are elementary, and no kick circulation method is universally applicable to all drilling operations. Finally, this review emphasized some recent progress and challenges in kick detection on managed pressure drilling.

Modeling and Numerical Implementation of Managed-Pressure-Drilling Systems for the Assessment of Pressure-Control Systems

SummaryAutomated managed-pressure drilling (MPD) is a method to enhance downhole pressure-control performance and safety during drilling operations. It is becoming more common to use model-based simulation for the evaluation of pressure-control systems designed for MPD automation before using those in the field. This demands a representative hydraulics-simulation model that captures the relevant aspects of a drilling system. This paper presents such a model and an approach to numerically implement that model for simulation studies. The complexity of this simulation model should be limited, first, to support effective numerical implementation and, second and most importantly, to allow for the analysis of the behavior and performance of the automated pressure-control systems during the controller-design phase. To this end, aspects of a drilling system that can considerably affect the performance of the automated MPD system are captured in the model. This hydraulics model incorporates both the distributed and multiphase-flow nature of a drilling system. Moreover, it captures nonlinear boundary conditions at the inlet of the drillstring, at the drill bit, and choke manifold, and also the variations in the cross-sectional area of the flow path. Model validations against field data from real-life MPD operations and simulations of industry-relevant scenarios indicate that these aspects are effectively captured in the model and preserved during the numerical implementation.

A Field Case Study of Managed Pressure Drilling in Offshore Ultra High-Pressure High-Temperature Exploration Well in the South China Sea

Summary The Y basin in the South China Sea has 15 trillion m3 of natural gas and represents typical ultra high-pressure high-temperature (ultra-HPHT) subsurface conditions, with the maximum bottomhole pressure (BHP) of 142 MPa (equivalent density = 2.38 sg), the highest bottomhole temperature (BHT) of 249°C at a depth of 5638 m, and an extremely narrow drilling mud density window. Therefore, there are several kinds of technical challenges during drilling operations. In recent years, managed pressure drilling (MPD) has been successfully applied in the basin with reduction of risks and well cost. Presented research focuses on a successful field case study of MPD in the Y basin. The case study consisted of two parts: MPD operational designs and MPD operational procedures. MPD operational designs included two steps: the precise calculation of drilling fluid equivalent circulating density (ECD) and the optimization of operational parameters. Four models were used in calculating drilling fluid ECD: wellbore heat transfer model, drilling fluid equivalent static density (ESD) model, drilling fluid rheological property model, and incorporating the effects of cuttings in the pressure loss model. The second step included two key operational parameters: mud weight (MW) and surface backpressure (SBP). MPD operational procedures were performed in three steps: roles and responsibilities of key personnel during MPD operations, wellsite training program and emergency procedures. Emergency procedures included unexpected drilling events, downhole equipment failures, and surface equipment failures. Taking X-1 Well as an example from the field case study, the following important observations were made. First, the MPD equipment was installed after remodeling of the drilling platform, installation of the wellhead assembly, and pressure testing of the MPD equipment. Next, the MW was set to 2.15 sg and the SBP was maintained at 525 psi while drilling the 8⅜ in. hole section on the basis of the operational design. In addition, the possible risks and corresponding preventive measures were taken into account and the MPD casedhole fingerprinting exercises were carried out. Finally, the MPD was successfully applied to X gas field featuring offshore ultra-HPHT. In addition, the dynamic formation integrity test (DFIT) and stripping out of hole with SBP were conducted. The well was successfully drilled in the narrow drilling mud density window of 0.05 sg without incidents and a sharp drop in the nonproductive time (NPT) was observed. Also, the casing structure was optimized from 7 to 5 strings with a significant reduction in the well cost and drilling time.

Technology Focus: Well Integrity (January 2020)

Technology Focus Fiber-optic technologies—distributed temperature sensing (DTS) and distributed acoustic sensing (DAS)—have been experiencing an increasing number of applications in the oil and gas industry as monitoring systems. In the area of well integrity, both technologies have been used in combination to monitor and evaluate qualitatively the cement placement and integrity in wells. An interesting technical article showing how these two technologies are used to monitor cement integrity in an actual well is selected as recommended additional reading. Ongoing research studies are also investigating casing deformation and downhole detection of hydro-carbon leakage. The use of these two technologies seems to have a very promising future when considering well-control situations. One potential application of DTS and DAS technologies is being evaluated now at Louisiana State University (LSU) as a part of a 3-year research project currently under way under the auspices of a grant by the Gulf Research Program to investigate the gas-in-riser issue. A 5,000-ft actual well at LSU was recompleted recently and instrumented with DTS and DAS for continuous monitoring information along the well and downhole gauges to record pressure and temperature at four different depths. These instruments were clamped to the outside of the production tubing installed inside the experimental well. A gas-injection line also was run into the well to displace nitrogen to simulate gas-in-riser situations. The data gathered by the downhole instruments are expected to shed light on well-control attributes such as gas velocity and distribution, two-phase-flow patterns, and gas breakout from solution in nonaqueous drilling fluid inside the marine riser. The viability of generating distributed pressure profiles from DTS and DAS data collected in the experiments also will be investigated. Undoubtedly, the research findings will help detect gas-in-riser situations earlier and monitor deepwater managed-pressure drilling operations that may allow for a controlled amount of gas inside the riser. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194553 Evolving Well-Control Procedures With Managed-Pressure Drilling on Floaters by Andre Alonso Fernandes, Petrobras, et al. SPE/IADC 194145 Well-Control Incident in the North Sea as Interpreted With Advanced Gas-Influx Modeling by Jan Ole Skogestad, SINTEF, et al. SPE 195678 Real-Time Well-Integrity Monitoring Using Fiber-Optic Distributed Acoustic Sensing by T. Raab, GFZ German Research Centre for Geosciences, et al.

Personnel Benefit From Advanced Drilling Simulators for Well-Control Training

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194181, “Advanced Drilling Simulators for Well-Control Training: Bringing Together People, Procedures, and New Technology,” by Robert Howell, Brian McKenzie, Craig Leslie, and Isabel Poletzky, Maersk Training, prepared for the 2019 SPE/IADC Drilling Conference and Exhibition, The Hague, 5–7 March. The paper has not been peer reviewed. As new technologies enable the drilling of increasingly complex and challenging wells, well control remains a critical operation that requires personnel to possess not only technical skill but also the ability to communicate effectively during stressful situations. This paper focuses on the preparation for, and implementation of, well-control training, while highlighting the integration of people skills into curricula and what advantages operators and drilling contractors have obtained. Conventional Well-Control Training Well control is of paramount importance and relies on trained teams to maintain well integrity throughout the drilling process. Conventional courses remain the cornerstone in competency training and provide a solid foundation for understanding the fundamental physics associated with well control, and should always remain part of the core curriculum. Crews that use high-fidelity simulations with integrated crew resource management (CRM) will be equipped to mitigate challenges in deepwater drilling environments better. Students who score consistently above average on an individual well-control examination should then be considered for advanced training. Such intensive courses involve a fully immersive simulated drilling rig that mimics real-life situations and well-control scenarios while being guided by drilling and human-factors specialists. On the first day of class, participants will be tested and, upon completion of the course, will be awarded the appropriate certification. Throughout the remainder of the week, participants will be immersed in a realistic and advanced simulated environment where their behavior and interactions, as well as their technical knowledge, will be assessed. First Steps for Training As deepwater drilling operations become more complex using managed-pressure-drilling (MPD) technology, it is fitting that crews receive specialized training focusing on the rig and on company-specific equipment, procedures, and well-control situations. Typically, the training is completed in conjunction with the service company using MPD software and a high-fidelity drilling-floor simulator. To prepare for this training, the MPD provider and operator meet 5 to 6 months before the training date to discuss the details of the venture and develop rig-specific procedures. Then, typically 2 to 3 months before training commences, the providers begin involvement with the operator to establish expectations. During this period, the schedule is developed on the basis of the crew’s experience with MPD and the software being used; well data are also provided to build different scenarios in the simulator to make them as realistic as possible, and to mirror the actual well that will be drilled. The degree of difficulty for each scenario varies depending on the operator and the crew’s experience with MPD operations capabilities. Given the limited exposure that offshore rig contractors have had with MPD, initial scenarios are used to familiarize participants with the software, the limitations of their equipment, and appropriate procedures. Scenarios evolve throughout the course of the training as participants become more knowledgeable. Part of this evolution includes gaining an understanding of how problems with other departments, such as marine, engine-room, and crane personnel, can affect rig-floor activities.

MPD Monitoring Technique Allows Rapid Redesign, Flexibility

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194097, “Real-Time MPD Optimization in Challenging Scenarios,” by Guilherme Siqueira Vanni, SPE, André Alonso Fernandes, Gleber Tacio Teixeira, Antonio Carlos Vieira Martins Lage, André Leibsohn Martins, SPE, and Felipe de Souza Terra, Petrobras, and Marcelo de Souza Cruz, Fabio Rodrigues G. da Silva, and Cristiano édio Dannenhauer, Engineering Simulation and Scientific Software, prepared for the 2019 SPE/IADC International Drilling Conference and Exhibition, The Hague, 5–7 March. The paper has not been peer reviewed. This work focuses on the development of specific methodologies to support managed-pressure-drilling (MPD) operations implemented on real-time diagnostic software. The developed methodology proposes as output ideal operating parameters, such as choke pressure, pump-flow rate, or adjustments related to drilling-fluid properties. The methodology considers the best approach to meet the restrictions imposed by the operational window. The real-time optimization procedures proposed are a further step to ensure reliability of MPD operations in challenging scenarios. Real-Time MPD Optimization Specific modules were developed from a drilling-problem diagnostic software to provide real-time support for MPD operations. The primary advance represented by these modules is the consolidation, in a computational tool, of MPD best practices. The tool, which uses real-time drilling data as input, will propose and enable immediate action in the event of anomalous situations or ones not predicted in project planning. Dynamic Pore-Pressure Test (DPPT) and Dynamic Formation Integrity (DFIT) Procedures. These procedures allow a more-accurate estimate of values for pore and fracture pressures, respectively. These procedures are suited particularly for drilling in narrow operating window scenario, because they allow correction of geological-profile data obtained previously with current field geopressure. Thus, the probability of gain and loss events becomes smaller in an MPD operation when compared with a conventional drilling scenario. During these tests, in each pressure step performed in the choke, the software calculates the volume balance related to the compression or decompression of the fluid in the well. The software calculates the volume that decreased from the active tank (DFIT) or increased in the active tank (DPPT). The software also calculates the volume balance related to the compression (DFIT) or decompression (DPPT) of the fluid in the well. These calculations determine whether these volume variations, both real and expected, follow the same magnitude. The difference between them is the criterion used to stop both procedures (DPPT and DFIT). In Petrobras’ drilling operations, this proposed limit normally is set to 2 bbl. This preset threshold is a minimum acceptable value to consider that a gain or loss is occurring. If this difference surpasses the limit value, the module triggers a message warning the rig crew. After these procedures, the simulator updates the operating window, using real downhole data [effective circulating density (ECD)] in a conservative way. The logic adopted for updating is to use the largest value between the DPPT and the value of the pore gradient present on the project. For the fracture gradient, inverse logic is adopted; the lowest value between the DFIT and the fracture gradient obtained on the project is used. Fig. 1 illustrates the pore-gradient update.

Risk analysis of well blowout scenarios during managed pressure drilling operation

Offshore drilling involves complex operations and equipment; thus, faces many operational challenges, including well control incidents. The managed pressure drilling (MPD) provides a safer alternative; however, this technology, for the most part, is still in its infancy. Potential risks during well control operation in MPD need to be identified, assessed, and managed. The current study presents an advanced dynamic blowout risk model (DBRM) to assess safety during a managed pressure drilling operation. The DBRM involves three key steps of operation: a dynamic Bayesian network (DBN) model to describe the dynamic risk of drilling during an MPD operation, a numerical model to simulate failure of an MPD kick control operation, and dynamic risk analysis to assess the safety of the well control operation as drilling conditions change over time. The proposed DBRM implements a novel approach for simulating an MPD failure and assessing blowout risk through varying MPD kick control parameters/variables in a simulated system. The proposed DBRM successfully replicated the dynamic blowout risk scenarios presented in the Amberjack field case study from the Gulf of Mexico. The results show that the presence of drilling hazards, such as depleted formation, increases the likelihood of circulation loss and thus, the occurrence likelihood of kick. Moreover, as the kick intensity increases over time, the failure likelihood of an MPD system increases until its failure occurs after the kick intensity has exceeded the designed limits of the MPD control system. Thus, the increased likelihoods of these two events (kick and MPD failure) increase the risk of a blowout. Conversely, MPD failure and blowout risk can be reduced by up to 96% by making the MPD control system more robust. The results prove that the kick control variables can be used to assess the success/failure of an MPD operation, i.e. its safety, and are instrumental in providing useful information to predict the performance and/or diagnose the failure of an MPD operation.

Strategic Evaluation of Managed Pressure Drilling: An Application on Brazilian Dynamic-Positioning Rigs

Summary The demand for ultradeepwater scenarios invoked the frequent application of managed pressure drilling (MPD) in the last few years. In an ultradeepwater scenario, oil companies face issues such as narrow pressure windows and severe loss zones. Many wells are considered undrillable without the aid of MPD technology. MPD operations need to be correctly evaluated with consideration given to increased time and cost/benefit analysis. In this paper, we propose a probabilistic model to evaluate MPD demand by estimating the optimal number of rigs equipped with MPD and a rotating control device (RCD), and we analyze which intervention strategy is the most cost– and time–effective. Reducing uncertainty is an important factor when making decisions about drilling. We adopted a Monte Carlo simulation using loss–zone estimation, probability of prediction error, the number of rigs equipped with MPD, and several strategies. Better MPD strategies were determined on the basis of available data and the optimal number of rigs equipped with an MPD system and RCD equipment, reducing subjectivity in the decision–making process. The originality of our paper lies in the new quantitative approach to dealing with uncertainty in the prediction of fluid losses and the cost and duration of different MPD strategies, numerically simulating the possible scenarios.

Developing an Influx-Management Envelope for a Deepwater MPD Operation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185289, “Case Study: First Experience of Developing an Influx-Management Envelope for a Deepwater MPD Operation,” by O.R. Gabaldon, P.R. Brand, M.S. Culen, I.U. Haq, R.A. Gonzalez-Luis, T. Pinheiro Da Silva, G. Puerto, and W. Bacon, Blade Energy Partners, prepared for the 2017 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Rio de Janeiro, 28–29 March. The paper has not been peer reviewed. The influx-management-envelope (IME) concept is an advanced, innovative way to assess influx conditions in managed-pressure-drilling (MPD) operations, offering an improved tool for the decision-making process. The complete paper presents the process of developing the IME concept for a deepwater MPD operation for the first time. The IME Concept The IME concept defines the operational envelope in case of incidental influxes during MPD operations. It is based on kick-tolerance concepts, in which a relationship between volume and intensity of the influx is established and plotted as a graph. A resulting combination of regions within the volume-and-intensity graph depicts the conditions in which an influx can be removed safely from the wellbore by use of the elements of the primary wellbore barrier; otherwise, the secondary wellbore barrier should be engaged and the well shut in conventionally. The regions are color coded for ease of identification during the process of managing an influx. Three regions have been described: The Green region identifies normal MPD operations, where drilling and other operations continue as planned. No influx is detected in the wellbore, and surface pressures are within planned parameters. The Yellow region defines the operational region where an influx has been detected in the wellbore and the influx can be circulated safely to surface within the boundaries of the primary wellbore barrier. The Red region defines the conditions in which it is deemed that some limits of the primary barrier would be exceeded during the process, indicating that the well should be secured with a secondary-barrier envelope. The Orange Region. In this work, an additional (optional) Orange region is added as a subset of the Yellow region (Fig. 1). In the Orange region, an influx can be removed safely within the primary wellbore barrier but one or more parameters will need to be modified to avoid exceeding some limits in the process.

Integrating Managed-Pressure Drilling Into HP/HT-Well Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188335, “Integrating Managed-Pressure Drilling Into HP/HT-Well Planning,” by Michael Cadd, Lewis Steven, and Robert Graham, Shell; Fedderik van der Bos, Nederlandse Aardolie Maatschappij; Craig Leggett, Blade Energy Partners; and Emil Stoian, Weatherford, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Managed-pressure drilling (MPD) is an increasingly common technique in narrow-margin high-pressure/high-temperature (HP/HT) wells. However, MPD is sometimes viewed as a bolt-on technology, only added after much of the planning work has been carried out and all other alternatives have been exhausted. The decision to use MPD should be made at the earliest stage of well planning. An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. Overview Project 1. For an HP/HT field redevelopment in the UK North Sea, seven side-track wells were drilled from a jack-up over an existing platform. MPD was used from the beginning, but the full benefits of MPD were not realized until later in the project. MPD was initially included to hold surface backpressure (SBP) across two connections to mitigate borehole-stability risk in an un stable shale. However, once the system was operational, further benefits continued to be identified and the scope of MPD operations grew significantly. At the same time, more knowledge of the subsurface was being gained, and it became clear that some of the planned wells would not be drillable without MPD because of a significantly reduced drilling window in the overburden. MPD became a key part of the design philosophy for later wells, where managed-pressure techniques were used to set and cement casings significantly deeper than would have been possible conventionally. MPD successfully mitigated classical HP/HT issues so that problems with losses and gains, handling of elevated gas levels, and mud-weight-selection issues were all virtually eliminated. Project 2. For a standalone HP/HT exploration well drilled from a jack-up offshore the Netherlands, MPD was initially selected because of the extremely narrow margins between the pore and fracture pressures in the 8½- and 6-in. sections. Conventional drilling would not have been possible without inducing losses and spending significant time circulating to adjust mud weights, as seen in a key offset well. Taking advantage of the learnings from Project 1, MPD was selected at an early stage of the planning process and was fully integrated into the well design and operations. Mud weight, drilling parameters, and bottomhole-assembly design were all tailored to suit MPD operations. Integrated HP/HT and MPD procedures were developed on the basis of traditional HP/HT techniques but were modified to make full use of the additional functionality provided by MPD. A combined HP/HT and MPD training course was developed, and key personnel were trained in HP/HT and MPD techniques. Rig modifications were made well in advance, and MPD was implemented one hole section earlier than required to familiarize all crews with the new equipment and procedures. The result was a potentially extremely challenging well that was drilled without any of the conventional HP/HT problems observed in the offset wells.

Closed-Loop Drilling Offers Advantages in Process Safety and Cost Savings

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 185283, “Leveraging CLD Potentials: Optimizing Economics Through Dynamic Well Control,” by Robert Ziegler, SPE, Weatherford International, and Evelyn Baldwin, SPE, Maersk Training, prepared for the 2017 SPE/IADC Managed Pressure Drilling/Underbalanced Operations Conference and Exhibition, Rio de Janeiro, 28–29 March. The paper has not been peer reviewed. Maximizing the potential of closed-loop drilling (CLD) to achieve dynamic well control and effectively cut costs is an often overlooked opportunity in times of low oil prices. This paper details the operational effects of CLD to demonstrate its ability to yield operational-process-safety improvements and cost savings over conventional methods. While managed-pressure drilling (MPD) often is the tool that finally enables operators to reach their objectives, major cost savings come when MPD is integrated in the well-planning process from the beginning. MPD for CLD Not too long ago, the topdrive was in a similar position on the technology-adoption curve as MPD is today. The industry was in a downturn at that time, too—oil prices were low, cost pressure was high, and horizontal drilling had just taken off. The topdrive rental business was booming, and, the moment the directional phase of a well was reached, the topdrive was mobilized. Drillers soon started to like the additional abilities the topdrive gave them, such as reducing nonproductive time (NPT) and mitigating stuck-pipe events. Even in the cost-sensitive land market, the topdrive is now considered standard equipment, as it has been offshore for quite a while. For MPD equipment, the situation is reversed. While the land market in the US has adopted the rotating control device as standard equipment, offshore in the Gulf of Mexico, where many of the most challenging wells are being drilled, adoption of the technology has been slow. In other areas of the world, however, MPD adoption is moving quicker. Most notably, in loss-prone carbonates of Southeast Asia; in the subsalt environment of Brazil; and, to a certain extent, in Angola, MPD from floaters has been more widespread. The experience from land wells can be transferred safely to offshore surface-blowout-preventer (BOP) operations (e.g., on jackup rigs, tension-leg platforms, tender-assisted drilling, and other platform rigs). The advantage offshore is that the rig moves are much simpler than for land operations, so complex piping for full MPD operations can remain in place.