Well barrier verification is having the confidence and being able to prove that "the folk on the rig will do the right thing and the equipment will function as intended when called upon to do so". This paper describes a method of achieving that aim by analyzing well control barrier systems in a logical and complete manner with regard to the technical, operational and organizational elements so that the results can be used as the basis for a straightforward means of barrier verification during operations.
BowTie diagrams, while a useful illustrative starting point, are limited in their ability to depict well control barriers as systems consisting of individual elements that interact with each other. Portraying them as systems enables the processes, people and equipment required for effective well control to be analyzed in a way that is both logical and complete. Further examination of the elements reveals the critical aspects that must be checked to verify barrier effectiveness. Operationalising the verification process is done by extending and formalizing established practices of wellsite supervisor oversight and cross-checking complemented with periodic inspections.
The analysis is resource intensive because each operational mode must be considered separately to ensure completeness. Once this work is done, general themes within critical aspects emerge that enable the verification tasks to be grouped into a set of logical activities that include: conversations with crew members to verify knowledge, criteria for drills to check on team capability and periodic inspections to ensure equipment integrity. Although difficult to achieve, the process must be carried out in a way that engages the crews in a sense of self-preservation to avoid becoming a box ticking exercise.
This paper describes an automated system for the capture of torque and drag (T&D) data that can alert the driller to impending issues. The automated system is managed by a real-time operating center (RTOC) that utilizes live T&D data to make informed recommendations to the driller.
The system utilizes existing high-frequency surface sensor data to sample hookload and torque and, through an automated system, intelligently determines T&D data. This data is displayed to the driller and managed via a rig floor mounted human-machine interface (HMI). An RTOC is employed to remotely manage this system and provide the driller with feedback and recommendations on remedial action based on observed wellbore conditions.
This continual feedback loop of actual T&D data to the RTOC also allows for a more accurate model to be updated and simultaneously displayed on the driller screen while drilling. An updated friction factor roadmap provides the driller/RTOC an accurate reference point for their T&D data.
Given the multitasking nature of a driller's job, it has been seen that T&D information can be overshadowed by other operational matters. It is observed that the automatic update of friction factors and automated, intelligent hookload and torque alarms can alert a driller/RTOC of impending problems that may be missed otherwise.
Historically, T&D had been manually recorded by a driller and periodically sent in to the office or calculated at an RTOC but disconnected from the rig floor. By applying "capture" logic to raw, high-frequency sensor data, we can now get consistent and reliable T&D data that is immediately available to the driller, the RTOC, and the drilling team.
The 13 3/8 to 14-in. cement wiper plug system is a critical component for successfully separating fluids during displacement of cement for long strings of casing in deepwater applications. With casing strings becoming longer, there was a need to validate the endurance capabilities of these plugs. This paper will discuss the methods used to test the endurance of a cement wiper plug system.
The test consisted of pumping the same plugs through 130 ft of casing repeatedly, until a maximum length of 40,000 ft was achieved. These plugs were displaced horizontally through the casing using water. This created the worst case scenario because no fluid would be in front of the plug: The elastomer is more susceptible to abrasion in dry pipe than in lubricated pipe. Each plug was dimensionally analyzed every 5,000 ft and then was validated by measuring the bypass pressure from the downhole side. The bypass pressure is directly related to the amount of surface contact between the plug fins and the casing wall and can be used to validate wiping efficiency. Theoretically, the farther the plug travels, the more likely the surface contact is reduced between the plug fins and the casing wall, and that is validated by measuring the bypass pressure.
The results of the endurance test are based on the relative wiping-efficiency test in the same inside diameter as the casing through which the plug is pumped. These results are compared to minimum allowable bypass pressure determined from a test using the largest published inside diameter. Results show that the bypass pressure decreases until a certain length and that at this length, contact force becomes significantly less, inadvertently causing the plug to wear at a slower rate. This relates to the reduction of the bypass pressure until a point where the pressure equalizes at approximately 20 percent less than the control.
Plug bypass can result in displacement errors, which further result in either underdisplacement leaving excess cement in the casing or over displacement, potentially contaminating the shoe tracks. Testing the ability of the plug to mechanically separate fluids and wipe the pipe eliminates the potential for bypass around the plug fins in the forward or reverse direction in long strings of casing.
In areas of the United Kingdom Continental Shelf (UKCS) operators are progressively seeking to drill increasingly complex well profiles to access un-swept reserves. Wells of such complexity require the introduction of new drilling technology to meet the challenge. In a recent UKCS operation, operator objectives for a wellbore required continuously high rates of curvature and tight dogleg severity control in a soft formation with unconfined compressive strengths (UCS) of 5 to 10 kpsi.
A new, integrated high build-up rate rotary steerable system (RSS), capable of delivering up to 12°/100ft in an 8½-in. hole, was implemented as a solution to achieve and optimize the wellbore placement, thus accessing untapped reserves beneath the offshore platform. In this mature field, collision avoidance with existing wells presented an additional challenge. Focusing on a total system approach, new polycrystalline diamond compact (PDC) drill bit technology was designed to integrate with the high build-up rate (BUR) drilling system. The PDC bit includes features for a smooth torque response, enhanced rate of penetration (ROP), improved durability, and precise steering control. Proprietary software provided confidence in the planning phase that the bit responses, in combination with the deployed steering system and the overall BHA set-up, would deliver the demanding well profile.
This paper presents the details of the integrated drilling technology, as well as the background of pre-drill planning and setup processes necessary for the successful application where no offset experience was available. In addition, this paper details the process management and implementation steps during the service introduction of the new drilling technology. The final performance of the integrated system that drilled the ‘corkscrew’ profile in one drilling run, providing the required well placement and hole quality will be shown. The overall new approach enables the industry to utilize previously inaccessible reserves and drive field economics further.
For a geothermal project in France, a customer planned to cement 7" glass-reinforced epoxy (GRE) tubulars in old corroded 9 �?" carbon steel casings. Through extensive laboratory research, the authors developed and applied a new low-weight cement system specially customized to isolate the annular interval. The premium quality of the first trials and hence the supreme adhesion efficiency of this state-of-the-art system onto GRE and steel surfaces was verified by wireline logging.
With the downturn in oil price and recent reduction in drilling activity, especially in high-cost environments, the industry is increasingly looking to save time, cost, and risk throughout all drilling and well operations. Conventional completion operations are being challenged to identify possible ways of reducing time and cost. To address this, the industry is adopting new technologies and methodologies to reduce risk, rig time, and nonproductive time (NPT) and to conduct operations in way that traditional tools do not allow. This paper focuses on the first subsea deployment of a remotely activated annular safety valve (ASV) in a deepwater well located in the Norwegian sector of the North Sea.
ASVs are traditionally set by one of four methods: a dedicated setting line to surface, applied tubing pressure, applied annulus pressure, or the shifting of a mechanical sleeve, which allows communication to a setting chamber. This paper describes an approach for running the ASV that requires no dedicated setting line and is initially insensitive to tubing pressure; this facilitates the full testing of the completion prior to setting the ASV packer. Using existing rig infrastructure, a frequency modulated pressure cycle is sent from surface to command a sleeve to move and allow communication with the setting chamber. The ASV packer is then set and tested.
The first subsea deepwater installation of the ASV was completed in August 2016, and this method of deploying the ASV provided several advantages over traditional methods.
Payette, G. S. (ExxonMobil Upstream Research Company) | Spivey, B. J. (ExxonMobil Upstream Research Company) | Wang, L. (ExxonMobil Upstream Research Company) | Bailey, J. R. (ExxonMobil Development Company) | Sanderson, D. (XTO Energy) | Kong, R. (Pason Systems) | Pawson, M. (Pason Systems) | Eddy, A. (Pason Systems)
We describe recent technology advances, basic workflows and field trial results for a real-time well-site based surveillance and optimization software platform for drilling. The system integrates with existing infrastructures available at a typical rig-site and may be deployed in the driller's cabin to enable real-time decisions by drilling personnel. The platform leverages as input one-second real-time surface data (obtained from sensors instrumented on surface equipment and available at most well sites). The platform provides surveillance capabilities, trending analysis tools, and controllable drilling parameter recommendations to improve drilling performance by enhancing decision-making at the well-site.
The platform supports active drilling parameter management by encouraging regular drill-off tests. Understandings obtained from these tests allow the system to provide real-time information on performance trends and drilling dysfunctions through various displays which aid in the drilling optimization process. We describe recent technology enhancements to the system which leverage adaptive response surface technologies that map out performance and dysfunction for the controllable drilling parameters as drill-off tests are performed. The system allows users to view performance maps for a variety of system outputs including Mechanical Specific Energy, Rate of Penetration, stick-slip severity, and Depth of Cut, as well as combinations of these outputs. The performance maps give precedence to "new" data and adapt as the bit wears and/or new formations are encountered and are leveraged to provide controllable drilling parameter recommendations to the driller.
We present examples from recent field applications of the system which demonstrate the value of real-time well-site based drilling optimization and parameter management leveraging surface data. We provide examples where the software was able to provide operation personnel with the confidence to increase Weight on Bit beyond "field rules" to enable faster drilling operations as compared with offsets. We provide additional examples highlighting how active surveillance and parameter management using the system's recommendations and response surface maps was able to produce multiple record bit runs in mature fields. We also discuss workflows enabled by the system and efforts taken to enhance field personnel uptake by working to address the human machine interaction aspect of the platform during software development.
The Drill Well on Paper (DWOP) exercise is an accepted tool for use in planning an offshore well, and in post-drilling analysis to demonstrate real and potential efficiency gains when comparing latest generation drilling and floater designs. However, given accelerated advances in drilling systems and operational practices, does the DWOP methodology of strictly analyzing fixed line-item data adequately capture non-apparent flat time and enhance overall operational efficiencies?
This paper explores areas where the traditional DWOP may not clearly reflect the efficiencies and HSE gains intrinsic of the latest generation drilling environment, and makes the case for transforming to more of a project management-like approach. For instance, efficiencies demonstrating reduced well delivery days would logically translate into a corresponding reduction in injuries/man-hour, but results of that accepted metric are not recorded in a post-well DWOP. Additionally, despite simultaneous rig operations, often denoted as off-line activities, the typical DWOP only looks at one operation, or line item, at a time. Thus, any efficiencies or bottlenecks in these parallel operations are often neither identified nor recorded in the DWOP.
The authors will present direct comparisons to illustrate how a typical DWOP exercise may not capture and detail the consequential reductions in lost time incident rates (LTIR), flat times and invisible lost time (ILT) achievable with advanced rigs and drilling systems. Standardized robotic pipe manipulators, floaters with increased storage capacity for casing and other consumables that reduce supply vessel requirements, and new rig designs and/or moon pool dimensions that widen the operable window and reduce weather-related downtime, are among the efficiency drivers the authors suggest should be reflected in a DWOP analysis. Additionally, improved operational practices, like pre-installation of casing centralizers, and automated pipe tally and monitoring systems contribute to improved efficiencies and economics, which further justify modifications to the standard DWOP thought process.
This paper aims to broaden the readers our understanding of how deepwater rigs can be assessed with respect to efficiency and HSE gains; thereby, leading to a rethinking of the current methodology used in rig comparison DWOPs.
A 6-1/8 in. sidetrack was planned for well-M as a result of water coning where the water cut climbed to as high as 35% in this old well. Drilling a pilot hole preceded the sidetrack operation in order to assess the surrounding reservoirs in the target area and most prolific candidate. Local geomechanical analysis was carried out in order to establish a mud window and ensure quality drilling with minimal wellbore instability, thus save rig time and operational cost. Cutting flow meters were deployed to monitor the hole cleaning performance and raise any red flags for immediate reactions to any abnormal wellbore behavior that may indicate wellbore instability.
A drillmap was constructed highlighting the different hazard categories that could be encountered throughout the job and the proper solution that needs to be implemented. Tripping and hole cleaning best practices were also established to further increase the operational awareness and alertness throughout the job. Sweep pills, reaming and short trips were optimized to keep a clean hole and avoid disturbing the borehole. Two different BHA's were utilized to complete this borehole: steerable mud motor to drill the curved section, and rotary steerable system to drill the horizontal section.
Well-X witnessed the deployment of the world's longest 4-1/2 in. partially cemented system with ICD screens, 7,389 ft. The competent drilling efforts enabled running this stiff assembly all the way across this extended reach lateral. The off-bottom liner system was hydraulically set and cemented in place where the reservoir was compartmentalized across the section with 48 ICD screens and five non-inflatable mechanical isolation openhole packers. This paper will focus on the drilling design and operational practices that enabled the achievement and deployment of this record system.
In the current challenging global oil and gas market, operators strive to minimize cost-per-foot (CPF) through drilling optimization and the introduction of next-generation tools to maximize return-on-investment. In response, service companies seek game-changing solutions to enhance operators' drilling operations. A cross-functional optimization team was chartered to enhance rate of penetration (ROP) in development drilling Kuwait's prolific Burgan field. The team developed a polycrystalline diamond compact (PDC) drill bit design with 25mm (1 in.) PDC cutters –presently the largest diameter commercial cutter in the industry. This paper presents the outstanding field results that were achieved with the 25mm cutter bit design. The analytical and experimental processes used in the development of the bit design will be described, and the operational results and resulting savings will be presented and compared to the established field benchmark.
The geology of the 12¼ in. intermediate sections of Burgan wells is comprised of layered carbonates, shales and sandstones. The section is known to induce moderate-to-severe torsional vibrations with conventional rotary bottomhole assemblies through the heterogeneous formations. Operational practices to mitigate these vibrations effectively limit the section ROP. To address this challenge, an optimization process was initiated to manage the problematic vibrations and maximize drilling efficiency through bit design and cutter technology.
In an application that was long dominated by conventional PDC bit designs with 19mm cutters, an upgraded 25mm cutter with the latest HP/HT pressing technologies incorporated in a tailored bit design to strike a balance between drilling aggressiveness and vibration control. The large cutter's unique depth-of-cut potential and increased cutter exposure were combined with reduced bit imbalance and degree of rubbing via numerous computerized simulations as part of the analysis for the Burgan application. The 25mm cutters were lab-tested and video-recorded on a dedicated laboratory rock mill to evaluate the ROP potential and apply these concepts to the 25mm cutter bit design. After the experimental bit was manufactured and performance tested in a controlled laboratory environment, the engineering team focused closely on the successful execution of the preliminary field trials, and then evaluated the results.
Deployment of the engineered 25mm cutter bit design led to multiple breakthrough performances in consecutive bit runs, achieving 300%+ increased ROP on each deployment compared to the established 12¼ in. field average. Analysis of the drilling logs indicates the engineered bit design provided the highest drilling efficiency to date in comparison to all conventional PDC bits previously run in this application. Torsional variations were limited through the interbedded formations, which allowed drilling parameters to be optimized throughout the runs. As a result, the operator reduced rotating hours by 70% vs. the field benchmark, with a corresponding 30%+ reduction in CPF.