Blowout Preventer Research Articles

Analysis of modes, mechanisms and causes of failure for blowout preventer components and parts

Analysis of modes, mechanisms and causes of failure for blowout preventer components and parts

Quantitative analysis of blowout preventer flat time for well control operation: Value added data aimed at performance enhancement

Flat-time operations are essential to the well construction process in the oil and gas drilling operation. However, the technical time limit (to construct the well as fast as possible for a certain set of conditions) for a well is not always achieved, which leads to increased operating costs. By reducing flat time, the cost of the well can be reduced. The safe handling of the Blowout Preventer (BOP) is one of the basic operations during the flat time period to ensure control of the well during drilling. Therefore, an example case study has been conducted using 14 wells drilled in Malaysia to determine the significance of BOP flat time versus total flat time. Findings of present study clarifies that BOP flat time has a significant impact on the total flat time. Therefore, if the BOP flat time as a total time is reduced, the cost of a well will decrease considerably. Additional research was conducted to analyze BOP flat time using 32 wells drilled in Malaysia for benchmarking purposes. The times for each BOP activity were recorded and a statistical analysis was performed. Mean times for each activity were calculated and outliers were examined. The target time for nippling up (when the BOP is installed onto the wellhead) BOP is 8 h. The target time for nippling down BOP (BOP is removed from the wellhead) is 6 h. The target time to change the BOP rams is 2 h. The target time for the pressure test change out of BOP rams is 1.5 h. The target duration of the BOP pressure test is 6 h. Based on the results of the statistical analysis, the factors affecting the BOP flat time were dependent on rig procedure, rig facilities, BOP configuration, BOP pressure rating, and BOP connection type.

A novel dilution control strategy for gas kick handling and riser gas unloading mitigation in deepwater drilling

Non-aqueous drilling fluids are generally favored in risered deepwater drilling operations for their capability to significantly improve drilling performance. However, their use may increase the difficulty of gas kick detection and handling, due to the high solubility of gas at downhole pressure and temperature conditions. A novel managed pressure drilling (MPD) control strategy is proposed here to handle gas kicks and prevent riser gas unloading (RGU) events in cases of gas influxes in non-aqueous drilling fluids. With the proposed strategy, the dissolved gas kick is diluted to a less severe level after it passes the subsea blow-out preventers by injecting mud into the riser through the booster line. Since the dissolved gas concentration is decreased after dilution, it is easier to mitigate or even fully eliminate an RGU event by applying an appropriate MPD backpressure. This MPD backpressure keeps the kick in solution when it is in the riser, and only allows it to come out of solution after passing the MPD choke.The proposed strategy's effectiveness is demonstrated using multiphase flow model simulations. The modeling approach considers the transient behavior of the two-phase gas-fluid mixture, and is validated against full-scale experimental data. Simulation results for a typical deepwater drilling operation show that the proposed MPD control strategy with riser dilution can greatly improve both the safety and speed of handling gas kicks in deepwater drilling. The improved safety derives from the ability to eliminate RGU events, and the increased speed comes from handling the kick directly in the riser using MPD backpressure and booster line dilution rather than through the lengthy conventional process of circulating it out through the choke line. Sensitivity analysis is conducted to investigate how the performance of the proposed control strategy is affected by influx gas composition, reservoir depth, seawater column height, kick size, and dilution ratio. A main conclusion is that the backpressures required after dilution are within the operating limits of regular marine risers, and therefore the majority of gas influx cases can be handled without the need for high-pressure risers. This allows for the relatively straightforward deployment of the proposed control strategy in the field.

From Completion to Production Without Intervention in a Subsea Well

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30697, “From Completion to Production Without Intervention in a VXT Subsea Completed Well,” by Susanne Loen Ommundsen, Interwell, and Berit Sara Schiefloe and Olle Balstad, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. As part of an improvement program focused on increasing standardization and efficiency on subsea well operations on the Norwegian continental shelf, the operator aimed to standardize future subsea wells using vertical trees (VXT) instead of horizontal trees. This would enable batch completion of several wells with a rig, followed by XT installation with an installation, maintenance, and repair (IMR) vessel, eliminating the need for a rig or lightweight intervention (LWI) vessel. The complete paper describes the development and implementation of a glass-plug solution that closed the technical gaps that had previously inhibited fully intervention-free operation for completion installation. Background and Field Information Trestakk is an oil and gas field in the Norwegian Sea in Block 6406/3. The field lies in 300 m of water approximately 27 km southeast of Åsgard A. Trestakk was discovered in 1986 and the plan for development and operation was approved in 2017. Equinor operates the field with 59.1% ownership interest, with Vår Energi owning the remaining 40.9%. The field development covers a subsea template with four well slots and one satellite well. A total of five wells will be drilled - three for production and two for gas injection. Production from the Trestakk subsea field on Haltenbanken in the Norwegian Sea began 16 July 2019. Trestakk is tied back to the Åsgard A floating production vessel. The Petroleum Safety Authority Norway and the Norwegian Petroleum Directorate approved the application for extending the lifetime of the installation to 2031 as a result of the additional recoverable volumes from Trestakk, for which field production is expected to last for 12 years. The goal for Trestakk was to achieve first recoverable oil at surface as soon as possible. The method selected was deployment of the completion string and VXT from a rig. The proposed solution was a barrier valve to be integrated as part of the completion string. As an operational improvement, the Trestakk team decided to design the wells with the intention of excluding wireline. Common methods for suspension and initiation of subsea wells during blowout-preventer (BOP) removal and VXT installation include installing shallow-set bridge plugs in the tubing or a tubing hanger plug. The plug is then removed using a riserless LWI vessel or rig. This method is often associated with high cost and enhanced operational risk.

Fatigue life optimization towards rubber core sealing surface of under-balanced drilling rotating blowout preventer

In the process of under-balanced drilling, the rubber core of rotating blowout preventer (RBOP) subject to the alternating cycle load was prone to fatigue failure. Firstly, the sealing principle of RBOP was analyzed and the stress of rubber core in dynamic sealing process was obtained. Then, the Yeoh constitutive model in the deformation process was established by the tensile test of the rubber core material. Then we used ABAQUS software to establish the finite element model of the dynamic sealing of the rubber core, and the simulation of the sealing process of the rubber core during the drilling and tripping operations and the optimization analysis of the factors affecting the fatigue life of the sealing surface of the rubber core were carried out. In this paper, the structure of the rubber core was optimized, and the optimal outer angle of the rubber core was 155°, the inner angle was 153°, and the base angle was 125°. Then the inner diameter size of rubber core that was matched with different outer diameter drill pipes was optimized and the best combination of rubber core was obtained. The paper also optimized the lowering and lifting speed of drill pipe under different wellhead pressures. The higher the well pressure, the more likely the rubber core fatigue failure would be. The safe lowering and lifting speed of drill pipe under different pressures was obtained. At last, according to the Chinese standard, indoor seal test and field application test were carried out in the Well Control Equipment Quality Supervision and Inspection Center of China national petroleum industry to confirm the reliability of finite element optimization, which was of great practical significance to improve the service life of rubber core and oilfield operation safety.

Gas in riser: On modeling gas influxes in non-aqueous drilling fluids with time-dependent desorption considerations

The presence of formation gas in a marine riser above the subsea blowout preventer (SSBOP) can pose great risks to personnel, equipment, and the structural stability of the drilling rig. The offshore drilling industry has been seeking to better understand and simulate gas-in-riser events, to optimize mitigation methods and justify the adoption of new flow control equipment and techniques. This paper presents a modified multiphase model to more realistically describe gas-in-riser events by incorporating time-dependent mass transfer processes occurring in non-aqueous muds (NAMs). A hybrid advection upstream splitting scheme (AUSMV) was used as the numerical scheme. Verification of the model and the numerical scheme were performed using field data from well control events with both NAMs and water-based muds (WBMs). The role of time-dependent mass transfer played during the process, and the proper range of desorption coefficient was evaluated in the case study with NAMs. Furthermore, a comprehensive parametric study was conducted, and results show that the severity of unloading will be significantly underestimated without considering mass transfer in NAMs. Meanwhile, unloading severity can be overestimated if the desorption process is considered as instantaneous instead of time-dependent.

Current situation and key technology analysis of downhole blow-out preventer

It is difficult to meet the safety requirements of the existing well control technology with oil & gas exploration and development to deep complex formation. Therefore, it is important to carry out the analysis and research work of new blow out preventers. The downhole blowout preventer can provide a sealing well near the drill bit, which could eliminate the overflow in the bud. Thus, the downhole blowout preventer will be an additional protect barrier for the existing well control procedure. This paper introduces domestic and foreign downhole BOP situation, and analysis the structure and technical features of these downhole BOPs. The author discusses key technology of downhole BOP on the basis of analyzing the defect of the existing technology. It could be helpful for the research of downhole blowout preventer.

Analysis of API S-135 steel drill pipe cutting process by blowout preventer

In offshore oil exploration, the use of a Dynamic Positioning System (DPS) to maintain the platform at a fixed point regardless of the influence of the environment has become common practice. In the event of failure, however, the drill string inside BOP (BlowOut Preventer) must be cut and safely disconnected from the platform. Therefore, it is evident the need for an accurate and realistic virtual model of this failure process. Numerical model analysis, in addition to avoiding expensive and complex experimental tests, allows, through post-processing tools, a detailed understanding of all phases of the failure process. The present work aims to characterize the API S-135 steel, as material commonly used to manufacturing drill strings. The material parameters for the Johnson-Cook model (J-C) are obtained from experimental tensile tests on dog bone and 3-point bending beams specimens with different notch radii, covering a wide range of stress triaxialities. Experimental tests and numerical simulations were compared by means of stress-strain curves, Digital Image Correlation (DIC) and Surface Electron Microscopy (SEM) to validate the model. The material model is applied to simulate the pipe cutting process and to predict the required force for the BOP to cut drill pipes with different geometries, which in comparison to experimental tests permitted to determine BOP internal frictions. Additionally, the numerical simulation also allowed a better understanding of the cutting process here presented as well, coherent to J-C model and SEM imaging of a similar cut tube in BOP.

Condition Monitoring System for Internal Blowout Prevention (IBOP) in Top Drive Assembly System using Discrete Event Systems and Deep Learning Approaches

Offshore oil drilling is a complex process that requires careful coordination of hardware and control systems. Fault monitoring systems play an important role in such systems for safe and profitable operations. Thus, predictive maintenance and monitoring operating conditions of drilling systems are critical to the overall production cycle. In this paper, we are addressing the topic of condition monitoring of a critical part in the process of oil drilling, the Internal Blowout Preventer (IBOP) system in the top drive assembly in offshore oil drilling. In our work, we aim to design an intelligent system for monitoring the health of IBOP system using discrete event systems (DES) based control method in combination with multivariate time series classification deep learning method. The proposed system comprises two stages: 1) produce IBOP system logical behaviour analysis using Hierarchical Colored Petri Nets (HCPN) approach; 2) develop an activity detection or a classifier module using reservoir computing framework for classification of multivariate time series for activity monitoring and fault detection for the top drive assembly.
 The combination of these methods would enable automation of monitoring and early detection of incidents during drilling operations. We present the preliminary results of a model in Petri Nets used to simulate a monitoring system for IBOP valve in top drive assembly and activity classification of activities relevant to IBOP condition monitoring. The effects of failure rate and repair time of each component on system performance are to be researched at a later stage.

Macondo Changed BOPs But There Is a Limit

There is a limit to disruptive innovation in oilfield technology. Blowout preventers (BOP) show how hard it can be. A decade ago on 20 April 2020, the Macondo disaster made a powerful case for change when this last line of defense failed to stop a blowout that caused explosions and a fire that killed 11, destroyed the Deepwater Horizon drilling rig, and set off one of the largest oil spills ever in the Gulf of Mexico. Scathing reports from investigations and staggering payouts from lawsuits against BP and other companies highlighted the shortcomings of machines that failed to serve as the last line of defense when natural gas surged onto the drilling floor, setting off a series of explosions. The investigations highlighted a long string of errors that led to the avoidable crisis. There was a failure to verify the cementing, missed signs of gas building up in the well, and a delayed decision to activate the BOP until the explosions already may have severed the hydraulic lines to the wellhead. But the simple explanation for it all: The shear rams failed to sever the pipe and seal the well. In the aftermath, well-control standards and regulations were rewritten and expanded. The changes required that old recommendations became requirements, and new ones were added, including a strong push toward real-time monitoring. The reports did not propose fundamentally redesigning BOPs. But for engineers with an inventive streak, this looked like a call to rethink the driving force behind these hydraulic devices where the fundamentals have changed little since the first patent was issued nearly 100 years ago. The arguments for rethinking BOPs included a 2003 study by West Engineering Services that found shear rams failed 7.5% of the time based on an estimate of the typical force required to cut pipe at the time. The force needed rises as casing gets tougher, water depths deeper, and well pressures higher, according to the study funded by what is now the US Bureau of Safety and Environmental Enforcement (BSEE). A Det Norske Veritas study for Transocean completed before the Macondo blowout found 11 situations where a BOP was activated in an emergency among the 15,000 wells drilled from 1980 to 2006. The BOPs only worked six times during that period, according to a story in The New York Times published in June 2010 - while the industry was scrambling to find a way to stop the Macondo leak. Different Perspectives The innovators range from startups to major offshore drillers. A Norwegian engineer started a company to sell a design for all-electric BOP stacks and an offshore drilling contractor developed an electric motor to retrofit into a BOP body. Engineers with military and space experience created cutting devices powered by gas generators using solid chemical propellants that send out high-pressure streams of gas when ignited by an electrical signal, similar to the deployment of an airbag or the thrusters on the Space Shuttle (this technology has been around for a long time).

Time‐based replacement policies for a fault tolerant system subject to degradation and two types of shocks

AbstractA single component nonrepairable system suffering from both an internal stochastic degradation process and external random shocks is investigated in this paper. More specifically, the Wiener process with a positive drift coefficient is introduced to describe the gradual deterioration and the arrival number of external shocks is counted with a nonhomogeneous Poisson process (NHPP). Meanwhile, fault tolerant design is incorporated into the stochastically deterioration system so as to protect it from shock failures to some extent and is consummately addressed via a generalized m − δ shock model. From the actual engineering point of view, external shocks are typically classified into two distinct categories in this current research, that is, a minor shock (Type I shock) increasing the damage load on current degradation level and a traumatic shock (Type II shock) resulting in system catastrophic failure immediately. The closed‐form expression of system survival function is derived analytically and is viewed as the generalization of existing reliability function for systems subject to dependent and competing failure processes. Based on which, two time‐based maintenance (TBM) policies including an age replacement model and a block replacement model are scheduled, where the expected long‐run cost rate (ELRCR) in each model is, respectively, optimized to seek the optimal replacement interval. In the illustrative example part, a subsea blowout preventer (BOP) control system is arranged to validate the theoretical results numerically. To compare which policy is more profitable under different conditions, the relative gain on optimal maintenance cost rate of the two TBM policies is presented.

Use of Low-ECD Synthetic-Based Mud During Topdrive Failure

While drilling in deepwater Gulf of Mexico, a topdrive failure forced the shutdown of all drilling operations for the rig operator and lasted for 114 hours (almost 5 days). At the time of the failure, the equivalent static density (ESD) was 11.36 ppg and the equivalent circulating density (ECD) was 11.5 ppg. The rate of penetration (ROP) was 100 ft/hr. Troubleshooting It was recommended that there be no utilization of the pumps while drilling was stopped, to reduce the chance of packing off the annulus with cuttings until the rotating and reciprocating could continue. During this time, a 100-psi backpressure was maintained using the managed-pressure drilling system. Kronos low-ECD synthetic-based mud (SBM) at a weight of 10.9 ppg was utilized during this event. During troubleshooting and repair work, a 1,500-bbl 11.4-ppg riser cap was spotted. Following the repair of the topdrive, a malfunctioning packer had to be replaced, causing additional delays. After the packer was set and the blowout preventers tested, the 11.4 ppg riser cap was displaced and subsequently replaced with 10.9-ppg low-ECD mud. The Kronos system was designed and maintained to have adequate suspension properties to maintain wellbore integrity without sag during unexpected downtime, even with cuttings left in the hole. The rig continued to trip into the hole to 9,800 ft. At that time, a bottom-up was circulated and a maximum of 575 units of gas was circulated out. Drilling then continued using a base oil and premix for dilution. The lost circulation material in the background continued to be blended into the dilution products being used at the time. During the drilling from 11,636 to 12,845 ft, the decision was made to increase the mud weight to 11.15 ppg. When the drilling continued from 12,845 to 13,234 ft, formation water was detected from the mud check entering the mud system. The system was treated to minimize the damage caused by formation water and maintain the properties sought by the operator. To assist in maintaining the desired weight and to prevent low-gravity solids from impacting the mud weight, two shakers were screened up to API Standard 120. At roughly the same time, the mud weight was increased to 11.2 ppg and then to 11.4 ppg. While continuing to drill, one of the engines that provided power to the mud pumps broke down, reducing the flow rate required to clean the hole. A cement unit was added to the pump to replace much of the volume lost with the broken mud pump. At 13,155 ft, the decision was made to call this current interval at total depth. The back-reaming process also started at that time. To assist with the hole cleaning, a high-viscosity sweep was blended and circulated. An additional high-viscosity sweep was blended and circulated, the second time at 9,058 ft. With continued back reaming through some tight spots to 7,272 ft, operators decided to wash back down 7,938 ft and pump one more high-viscosity sweep. Once the hole was clean, a flow check was performed and operators began to pull out of the hole.

Safety enhancement during deep well pump replacement

In Ukraine, as in other countries of the world, the majority of oil wells are operated using a mechanical method of production, such as rod well pumping method, containing above-ground and underground equipment. For repair or replacement of underground equipment (down hole pump), is brought to the surface. In this case, the well may have oil-water gas inflow caused by the «piston» effect, for example. (Substitution of volume between the pump and the pump rods by fluid from the formation). This could lead to an open flowing well. Many additional complex operations are used to perform safe well workover operations, such as well closure. These operations are performed to control well formation pressure, prevent gas-oil and damage to downhole equipment. It is also worth paying attention to the fact that disruptions in the process of well closure can lead both to a decrease in its productivity and to the complete termination of its operation. To prevent oil-water gas inflow various equipment and devices are used: Cameron ram-type blowout preventer, wellhead stuffing boxes, emergency washers with gate valves, downhole shutoffs, downhole check valves. All this increases safety when replacing downhole equipment, but does not guarantee the avoidance of additional complications in the operation of this equipment: the possibility of controlled shutdown of the well, recovery of oil production without performance of downhole operations, etc. To eliminate these complications, a downhole check valve design was developed. Its design allows: not to change the arrangement of elements in the well; to change the pump without well closure (it reduces repair time and costs); undercut tubing (does not allow the fluid from the formation to enter the well and create an emergency situation that could lead to open well flowing).

Fracture criteria applied to numerical simulation of blowout preventer ram shearing

The interest in predicting the force required for a subsea blowout preventer (BOP) to cut and isolate the drilling pipe has been growing since the Macondo accident. In previous research, numerical simulation using the nonlinear finite element method combined with the blowout preventer (BOP) shear test has been a common approach. As various fracture criteria exist, the selection and application of a suitable fracture criterion are of great interest to achieve a successful ram shearing simulation. In this paper, the CrashFEM criterion, previously employed in crashworthiness simulation, is first adopted in BOP ram shearing simulation to capture the onset of damage to the pipe. The Johnson-Cook (J-C) and Modified Mohr-Coulomb (MMC) criteria are utilized to carry out a comparative study. The TRIP 690 experimental data are used to derive the fracture parameters. These parameters enable the building of numerical models based on boundary and loading conditions for the BOP shear test. Based on the numerical model, a mesh sensitivity study is carried out. The simulation results using refined meshes show that the shearing forces predicted by the CrashFEM and MMC criteria are generally consistent with the experimental data. The results from the three criteria indicate differences originating from the shape of the fracture limit curve, the damage initiation concerning the equivalent plastic strain accumulation, and the damage distribution in the shearing area. These findings are explained in detail in the paper. A comprehensive application of the CrashFEM criteria for BOP shearing simulation is presented and recommendations are provided about the selection of suitable fracture criteria.

Relief Well Challenges and Solutions for Subsea Big-Bore Field Developments

Summary In subsea environments, using large-bore/high-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major benefit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce—that risk being an increased level of difficulty in bringing such a well under control if a blowout were to occur. It is common that multiple relief wells, with their inherent complexities and time investment, would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well. Still, a capping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being damaged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control. This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the crossover piping at the blowout preventer (BOP; erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to affect a dynamic kill. However, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry's history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well. In this paper, we describe methods that can be implemented to transcend traditional relief well limitations via using a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow-water (826 ft) and deepwater (8,260 ft) environments, the techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applicability to most subsea well control events that might arise in the future.

Technology Focus: High Pressure/High Temperature (March 2020)

Technology Focus One would think that, in these challenging times, high-pressure/high-temperature (HP/HT) technology and projects would be put on the back burner, with everybody chasing zipper-fractured barrels from shale. Well, it is not so. The rewards in new reserves and profits of being able to develop HP/HT resources efficiently are just too attractive to ignore. So, we can enjoy some major developments on the project and technical side in the past year, and the highlights are offshore. Let us look at the Gulf of Mexico, which has moved from being just a pioneering area for deepwater developments to an area where deep water and HP/HT combine to provide the ultimate challenge for the best engineers. In 2019, we saw first oil from Appomattox, the first producing high-temperature development in the deepwater Gulf of Mexico; and we can congratulate Shell (operator), Nexen, and the China National Offshore Oil Corporation for a job well done. This project also served as the developing ground for the recently issued Bureau of Safety and Environmental Enforcement HP/HT guidance documents, which certainly will make the next projects more streamlined. And lest we forget, it is also a “green” project, with the first combined-cycle power generation facility deployed offshore in the Gulf of Mexico. The next challenge is now the “HP” part of HP/HT, and Chevron took up the gauntlet and is putting the final touches on a new generation of drillship together with Transocean as the drilling contractor, with NOV providing dual 20,000-psi subsea blowout preventers. And, with the sanctioning of the Chevron-operated Anchor 20,000-psi development in the Green Canyon area at the end of 2019, it is anybody’s guess where this drillship will be deployed first. Total is the partner on this development. These two major HP/HT breakthroughs have been made in deep water, in the toughest industry environment seen at least in my lifetime. Who says our industry is not resilient and innovative? In this year’s paper selection, we are focusing on three technical areas where HP/HT and deep water come together: very-high-pressure and -temperature (supercritical) fluid properties, the latest expandable technology used for liner hangers, and the effect of ambient pressure on the pressure rating of well-construction equipment. Who would have thought that, in these challenging days, we would be able to celebrate the marriage of deep water and HP/HT? And this is happening not just in the Gulf of Mexico; we also hear some very interesting developments in Asia/Pacific (the South China Sea) and in the eastern Mediterranean. It is not aerospace or Silicon Valley, but our industry that is still the most innovative and pioneering in the word. We can only hope that the many highly qualified graduates, and especially post-graduates, in petroleum engineering looking for their first jobs are invited on this journey and don’t wander into other industries where their skills would be quickly appreciated. They are the ones we need to use all the new digital tools, such as simulator-based predrilling exercises. From the days of Shearwater to Appomattox and Anchor, we have almost no time left to tap the experience of the deepwater and HP/HT pioneers who are at the tail end of their careers and have so much knowledge to transfer. Recommended additional reading at OnePetro: www.onepetro.org. SPE 195353 Active Cooling Method for Downhole Systems in High-Temperature Environments by Wenkai Gao, China National Petroleum Corporation, et al. SPE 195725 Improving Performance in Elgin HP/HT Infill Drilling Despite Increasing Challenges by Mohammad Alahmad, Total, et al. SPE 197207 Improved Well Design 15,000-psi Cemented Completion To Deliver Faster and Cheaper Complex Deep Gas HP/HT Wells by Hashil Nasser Said Al Naabi, Petroleum Development Oman, et al.

Rheological Properties of Methane Hydrate Slurry in the Presence of Xanthan Gum

Summary Methane hydrate formation in a xanthan-gum (XG) solution is an important problem for drilling in a deepwater environment. It not only alters the rheology of the drilling fluid in the wellbore but increases the risks of a hydrate blockage in the blowout preventer. The current work is performing groups of experiments to investigate the rheology of the hydrate slurry under XG concentrations of 0.15, 0.2, 0.25, and 0.3%, shear rates from 10 to 480 s−1, and hydrate concentrations from 1.01 to 9.12%. The experimental results show that the hydrate slurry with XG additives exhibits an obvious shear-thinning behavior, which is because the XG solution has strong pseudoplastic characteristics, and the inner structures of the flocculated hydrate particles suspended in the hydrate slurry are broken up during the hydrate-slurry flow. The increase of hydrate concentrations in the hydrate slurry can reduce the non-Newtonian fluid index and make the rheology of the hydrate slurry become more shear-thinning. However, as the XG concentration increases in the hydrate slurry, the influence of the hydrate concentration on the rheology of the hydrate slurry gradually weakens. Empirical Herschel–Bulkley-type equations are developed to describe the rheology of the hydrate slurry with XG for the current experimental condition, considering the shear rate, hydrate concentration, and XG concentration. In the proposed equations, the non-Newtonian factor and the consistency factor are expressed as functions of XG concentration empirically. Correction Notice:The preprint version of this paper was modified from its original version to correct Figs. 8 and 9 and Eqs. 6 through 9 on page 7. Errata explaining the corrections are included below as Supporting Information.

A Switching MPD Controller for Mitigating Riser Gas Unloading Events in Offshore Drilling

Summary Riser gas unloading events in subsea well construction are hazardous and difficult to control. When a gas influx enters the wellbore and dissolves in nonaqueous fluids (NAFs), it may go unnoticed because the pit gain on the surface may be minimal and remain below the detection threshold when using conventional well control indicators. Once the dissolved gas is circulated up and comes out of the solution at pressure and temperature conditions below the bubblepoint, it can quickly displace a large volume of mud in the riser or the chokeline. When this breaking out of gas occurs at a shallow depth, it leaves little time for the rig crew to react. In this paper, we present a novel managed pressure drilling (MPD) approach for riser gas unloading control that makes use of a pressurized riser drilling (PRD) controller. The PRD method employs the constant bottomhole pressure (CBHP) controller for normal operations (e.g., drilling and circulation of kick), whereas it offers a more comprehensive way to manage and control a riser gas unloading behavior. The PRD choke controller dynamically applies a backpressure on the dissolved gas–NAF mixture in the riser to delay, minimize, or even prevent the gas breaking out at locations closer to the surface. The control algorithm considers the pressure limits of the riser and of the openhole formations and can adjust for kick uncertainties (e.g., whether the kick is a gas, liquid, or both, its volume and distribution). The proposed PRD controller consists of three operation modes: pressure control mode, flow control mode, and solubility control mode, with each mode applicable to its corresponding operating condition. The controller can automatically switch among different modes on the basis of the observed kick behavior, thereby gaining the ability to compensate for the limitations of the individual control modes and, more importantly, to deal with kicks agnostically, i.e., independent of their nature. The proposed controller is evaluated by simulating different riser gas unloading scenarios. Here, two distinct cases are given special consideration: (1) the case in which the subsea blowout preventers (BOPs) remain open after the kick passes them and the controller regulates the pressure using the maximum allowable surface pressure (MASP) or downhole fracture gradient as an upper limit and (2) the case in which the subsea BOPs are closed after the kick passes them and the controller regulates the pressure within the riser pressure limits when the kick is circulated to the surface using the riser booster pump. Simulation results show that the proposed controller can quickly and robustly control the riser gas unloading situations with complicated transient conditions, without fracturing downhole formations or jeopardizing the pressure integrity of the riser. The developed PRD controller aims to help mitigate some of the concerns about riser gas unloading when the dissolved gas is allowed to pass the subsea BOPs and enter the riser and to facilitate the implementation of more automated subsea well control using MPD technology in the foreseeable future.

Snubbing Unit Brings Middle East Well With Underground Blowout Under Control

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194283, “Rapid Deployment and Use of Snubbing Unit Brings Well With Underground Blowout and Surface Broaching Under Control,” by Albert Donaldson, SPE, Victor Marrero-Reyes, and William Scott, Halliburton, and Haitham Al-Mayyan, SPE, Kuwait Oil Company, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. This paper describes the mobilization of a snubbing unit and blowout preventer (BOP) stack in the Middle East that enabled a well with an underground blowout and surface broaching to be brought under control within a short time. The mobilization timeline is provided, along with details about how the snubbing unit and BOPs were integrated with existing equipment to enable re-entry into the blowout well. The procedures and equipment used to enable a stable rig-up and well entry are discussed. The paper also describes the situation within the well and the procedures used to bring it under control. Introduction and Background A well drilled and completed in 1991 was last worked over and recompleted as a single-zone producer in 2010. On 25 March 2018, the perforated zone was isolated riglessly with a through- tubing bridge plug (TTBP) and dumped cement, and new perforations were added between 3,994 and 4,010 ft. After perforation, wellhead pressure (WHP) was only 90 psi, which was not sufficient to flow the well to the nearby gathering center, and the well was shut in. On 29 March, the gathering center reported that WHP had increased to 800 psi and that a nearby cathodic protection well had begun producing oil and gas to atmosphere. Investigations were performed on all production wells in the vicinity, and identified the well that was the source of communication with the cathodic protection well. The tubing pressure was found to be 800 psi, and the casing pressure was recorded as 650 psi. Slickline was mobilized, and on 29 March, a tubing check revealed an obstruction in the tubing at 3,738 ft and provided evidence of damaged tubing at 1,960 ft. Between 29 and 31 March, multiple attempts to kill the well were made with brine weights between 9.0 and 9.6 ppg, followed by oil-based mud (OBM) at 16.0 ppg. Although pressures were temporarily reduced to 0 psi, they quickly returned to 800 psi on the tubing and 650 psi on the tubing by the 7-in. casing annulus. A total of 1,200 bbl of OBM was pumped into the well. On 3 April, wireline was rigged up, and the logs run indicated that the tubing was severely damaged at approximately 1,951 ft, with many holes and wall loss between 1,296 and 3,727 ft. The 7-in. casing was found to have severe damage between 1,585 and 1,620 ft. Pressure and temperature logs indicated gas flow between the tubing and casing at 1,951 ft.

Innovative digital inspection methodology

The paper describes an innovative digital inspection methodology that combines 3D laser scanning, metrology and advanced non-destructive testing data that is merged in 3D space to provide a digital record of the condition and mechanical integrity of critical assets. This advanced inspection method supports condition-based maintenance programs and digital twin models to determine future equipment condition, work scope and inspection schedules, while maintaining a digital record throughout the equipment lifecycle. Testing of the methodology includes 3D scanning of drill platforms, baseline scanning of blowout preventers and sheaves, for quality purposes, and the use of augmented reality for viewing scans. Phased array testing has been conducted on sub-components such as slew ring bolting. Data are combined into digital reports that show 3D images of the equipment with precise dimensional data and identified inspection areas. Such reports can be combined with digital twin models to confirm integrity of the equipment for certificate of conformance and baseline data for future integrity comparisons as equipment ages. This innovative inspection methodology will set a new standard for how equipment data are captured, stored and represented. The process provides a range of benefits for OEMs, drilling contractors and operators alike, including digital quality programs to baseline new equipment condition and compare with design parameters, delivering condition and integrity assessments of critical equipment items in-situ or on deck, providing a consistent methodology for inspection and dimensional control of operational equipment items, and providing precise equipment data that can complement digital twin and real time monitoring programs.