Evolution of Tubular Handling Brings Big Safety, Efficiency Gain
Safety and efficiency have long been the drivers in the evolution of tubular handling and running technology, from manual systems to highly mechanized and automated processes. As increasingly complex well construction demands have created new challenges and a heightened emphasis on well integrity, a more comprehensive approach to tubular management and running has emerged. Evolving beyond rotary table operations, today’s tubular running services also encompass an upstream focus on pipe preparation and makeup offline and a downstream emphasis that ensures high-integrity casing string installations to total depth (TD).
Tubular management requires a comprehensive process that involves logistical planning, pipe storage, preparation, makeup, and wellsite planning to deliver pipe ready to run. A successfully executed offline process covering all of these factors yields greater consistency and reduces personnel and infrastructure requirements. Safety and efficiency gains are achievable by controlling how the pipe is handled, controlled, and run in onshore and offshore operations.
Offline pipe makeup for casing, tubing, and drillpipe is done at Weatherford with advanced oilfield bucking (Fig. 1) and torque-control makeup systems that employ the same technology used on rig systems for many years. The technology, which can be positioned at permanent facilities and on remote locations, is used to build ready-to-run double or triple stands of tubulars for delivery to the rig.
Delivery of rig-ready pipe to the wellsite limits the exposure of rig personnel to makeup and running operations and reduces pipe preparation cost and rig time. It also reduces openhole exposure time, which helps minimize wellbore stability issues and contributes to better casing running times.
Connection integrity control, beginning with planning and preparation, reduces the chance of failure and well repairs. As with rig-based systems, the offline technology makes or breaks connections using highly accurate torque measurements that are displayed and recorded.
The system ensures connection integrity and makeup parameters for API and premium thread tubing, casing, production riser, and drillpipe. Cementing accessories can also be made up and the system can be configured for subassembly of downhole equipment. Faster makeup speeds are enabled by rotational makeup and breakout technology that can be instantly reversed.
Detailed pipe connection data is collected off site or on the rig with unique identifiers barcoded on the pipe. Information recorded during offline makeup is merged with data from connections made up on the rig, including torque, length, drift, and tally. This synchronized data collection and automated traceability improves research, reduces nonproductive time, and lowers costs associated with connection integrity.
Efficiency and cost reductions are also achieved through streamlined tubulars selection, improved supply chain efficiency, and application of vendor and supplier management systems. For tubulars headed offshore, smooth logistics, packaging, and transportation depend on well-designed and -executed quayside operations.
US, Australian Case Studies
Significant well construction safety and efficiency gains have been achieved in using this tubular management process, whether working from permanent facilities in areas with mature infrastructure or from mobile systems in remote locations.
For example, in the United States Gulf of Mexico (GOM), an offline tubular makeup system was used to build double stands of 14×13⅝-in. casing, which was delivered rig-ready to the wellsite. Operations were based at a newly built company tubular preparation and automated pipe makeup facility in Port Fourchon, Louisiana.
The 17,000-ft string was run in 26 hours compared with a previous well in which a similar 14,000-ft string run in single joints required 41 hours of semisubmersible rig time.
Across multiple GOM applications, the tubing management process has improved handling and run times by as much as 78% (Fig. 2) and resulted in substantial commensurate cost savings over 28 casing string installations.
Similar results were achieved offshore northwest Australia, where double stands of casing and tubing were built offline and delivered to a semisubmersible rig. A bucking unit with torque turn process-control systems was placed at the operator’s onshore support base to make up double stands of 9⅝-in., 7-in., and 4½-in. tubulars.
Running double instead of single joints improved efficiency by 30% to save an average of 4 hours per tubing running operation and 32 hours in total tubing running. Offsite pipe preparation saved additional rig time. The cost savings achieved throughout the tubular management process were significant.
Evolution of Tubular Handling, Running
Tubular management capabilities reflect substantial advances in tubular running and handling technology achieved over the past 2 decades. These advances have helped to move personnel out of harm’s way and significantly improve rig efficiency. Key innovations have included topdrive technology, pipe racking systems, and increased rig mechanization.
In the 1980s, semiautomated and mechanized rig applications began to replace conventional tools such as manual tongs, hand slips, and elevators, as safety engineers sought to remove hazards from the system. This advance primarily involved modifying existing hardware for modularity and, preferably, remote control.
The mechanization process contrasted with traditional automation concepts that typically required expensive and cost-prohibitive redesign of rig components. Instead, rig mechanization provided a much more cost-effective approach that achieved safety goals by distancing rig personnel from the hazardous location.
Replacement of these semiautomated and mechanized packages began with the introduction of topdrive casing running systems and the ability to control all derrick and drill floor operations remotely. The use of fully automated pipe handling and makeup equipment eliminated power tongs and other casing running equipment on the rig floor, along with the personnel required to run them.
The benefit of these automated casing running and tubular handling systems was leveraged by many other innovations. Casing circulation and fill-up tools along with flush-mounted casing slips eliminated backup tongs and greatly reduced working heights. Improvements to automated tong positioning systems eliminated the need for manual handling of larger power tongs. Modular systems provided interchangeable mechanized power tongs for casing, tubing, and drillpipe. Multitask versatility combined the capability to perform casing connection makeup, torque monitoring, casing fill-up and circulation, rotation and casing reaming and drilling, and elevator functions.
The focus on risk reduction and efficiency gains resulted in the removal of workers from the drill floor casing running operations and the elimination of some functions. For instance, automated casing stabbing systems removed the individual in the derrick, which has led to a major reduction in casing stabbing board incidents over the past 14 years.
For example, the use of automatic side doors has eliminated the risk of hand, finger, and back injuries from manual operations, particularly with larger-diameter pipe. Power tong positioning systems have also reduced manual handling in moving large, heavy power equipment around drill floors, which poses particular risk in bad weather by contributing to rig heave and causing dangerous pipe swaying.
These advanced tubular handling systems have played a significant role in improving safety. Industry figures in the GOM for casing and pipe handing incidents show a decline from a high of almost 14% in 1997 to 0.09% today. Similar figures have also been reported in the North Sea and Australian operations.
Below the Rotary
Technology advances that have revolutionized the rig floor have also had a significant benefit downhole. The right choice of running equipment and its integration into the rig systems during front-end engineering and development is critical to downhole and rig performance.
Improvement in the downhole dimension of casing running resulted from the development of topdrive systems that simultaneously rotate, circulate, and push casing strings. These systems significantly improved traditional tubular running operations. But they also required downhole engineering measures, as opposed to reliance on traditional rig-floor competencies. Rotating and pushing casing introduced torque and drag, cyclic fatigue, bending, and compressive loading, all of which require complex analyses.
Integration of the new capabilities with the existing process required multidiscipline expertise and an understanding that exceeded traditional tubing running operations, which generally ended at the rig floor. The expanded competency, combined with enabling technologies, widened the perspective from the traditional tubular running process to a TD-enabling process more closely aligned with the operators’ overall wellbore objectives.
Today, new levels of safety and efficiency are being achieved by extending the focus from making connections at the rotary to bringing high-integrity casing strings with the planned diameter to TD and securing the wellbore over the life of the well.
Evolution of Performance
The evolution of tubular handling and running technology from manual systems to highly mechanized and automated processes has resulted in remarkable improvements in safety and efficiency. While new challenges are presented by increasingly complex operational and economic demands, advances in technology and methods are being combined in a comprehensive approach to tubular handling and running that is achieving even greater levels of performance.
Degradable Frac Ball Holds Solution to Persistent Problem in Fracturing
A highly efficient and popular technique for multistage fracturing involves placing a completion string in the open hole with a series of ball-actuated stages isolated by hydraulically set or swellable packers. This practice has been instrumental to the increase of activity in hydrocarbon-bearing reservoirs, as it allows continuous operation while performing a large number of stimulation treatments.
When using this technique, sections of the reservoir can be selectively accessed by pumping actuators, or frac balls, from surface that land on correspondingly sized seats that have progressively larger diameters as operations advance from toe to heel. When all stages have been treated, the well is allowed to flow back, flushing the balls back to surface where they are caught in a ball trap.
Despite more than a quarter of a million stages that have been treated using the sliding sleeve technique, the results are not always up to expectation. Operators have experienced suboptimal production from wells in which logs and tests indicated high productivity. In searching for a root cause, it has been discovered that often not all balls are recovered. Further investigation has sometimes found that balls may have deformed and become jammed in their seats, plugging all production from beneath. The only solution is to trip into the well and mill out the seats.
Aside from the added cost and risk, the challenge is that this undesirable situation is difficult to identify because other reservoir problems that milling will not solve can present a similar production profile. This adds uncertainty to any decision to mill out the system.
Frac balls are typically made from phenolic or composite materials. The composite material is laminated and, depending upon the orientation of the laminar planes, it can fracture when it seats and is subjected to additional hydraulic pressure during fracturing operations. If the ball fractures before it has served its purpose, the entire job may be jeopardized. Both types of balls are subject to deformation, often referred to as egging, when under pressure (Fig. 3).
Slight egging can cause the ball to stick in the upper seats when the well is put on production, or the ball can jam itself into the seat so tightly that the only way to remove it is by milling. A stuck or jammed frac ball acts as a permanent isolation point for all treated stages below it.
Alloy Ball Technology
Schlumberger has recently introduced a degradable alloy technology suitable for ball drop systems. The Elemental degradable alloy balls disintegrate after making contact with well fluid within a few hours of deployment. The ball does not dissolve, but rather goes through a controlled degradation (Fig. 4) in which an electrochemical reaction occurs over hours or days that slowly transforms the material into hydrate oxides and hydroxides while slowly releasing a small amount of hydrogen. All that remains is a fine powder (micron scale) that does not interfere with flowback or production.
The mechanism of this material degradation includes intra-galvanic cells and depassivation. During the first process, different crystallographic phases electrochemically interact, leading to one dissolving, while another remains and slowly generates hydrogen. The first mechanism resembles the electrochemical process that takes place in a car battery and is well understood in the oil field.
To understand the second degradation mechanism, take the analogy of stainless steel—a metal or alloy known for its self-passivating behavior in aerated conditions. Stainless steel, because it has at least 12 wt% chromium in iron, naturally forms a thin protective layer of chromium oxide, among possibly other more complex oxides. When one or several of the oxides are removed, for instance as a result of abrasive wear, they instantly re-form as long as sufficient aeration is present. In contrast to stainless steel, the degradable material is unable to form a self-protective passive film. Instead, it has a strong chemical affinity toward disintegrating in water-containing fluids.
The frac ball does not have to degrade completely before flowing back because, once its outside diameter is reduced below the seat’s inside diameter, the ball falls through to the bottom where it continues to degrade until it disappears. With a compressive strength comparable to mild steel, the new metal alloy balls can withstand differential well pressures exceeding 10,000 psi without deforming or fracturing.
During development, more than 700 prototypes were subjected to more than 6,000 hardness tests and 300 fluid compatibility tests to validate manufacturing quality. Most importantly, degradation is more uniform and consistent with the new metallic alloy frac balls than with previous designs. Measured dimensions during degradation have a near 1:1 correlation with predicted diameters. When tested under extreme temperatures, the balls were undamaged and not desensitized by exposure to ambient heat or cold.
Since their introduction, the new metal alloy degradable frac balls have been run on 500 stimulation stages in the United States, Canada, and other countries. The balls demonstrated predictable degradation in a wide variety of well depths, temperatures, pressures, and fluids. The frac balls and the wells in which they were deployed performed as expected. One operator wanted assurance that the balls could be easily milled in case of a contingency. The balls were quickly milled with no special operational requirements.
The Elemental degradable alloy balls were run in a six-stage well scheduled to be hydraulically fractured. The pressure log showed a clear frac ball signature for all stages. Different fracturing profiles for the stages confirmed that each was fully isolated from the others. Following treatment, the well did not flow back naturally to surface. This was expected, and coiled tubing (CT) was brought in to lift the well and recover any debris or ball residue. The CT passed through all six seats, indicating that there was no ball residue impeding flow. The job was completed in 5 hours.
Another well with 16 stages was to be treated using low-temperature foam at 50°C (122°F). Following treatment, five partially degraded frac balls were caught in the ball catcher 53 hours after completion of the 16th stage. After 72 hours, the ball catcher was rechecked and found to be empty. All stages were deemed to be open by a comparison of production with a nearby offset well. The recovered balls were determined to be from the last five stages pumped—the balls from the deeper 11 stages fully disintegrated.
Other equipment improvements have also been implemented. Whereas most seats have conical geometry, it was determined that better sealing action would result from concave seats that have profiles matching the spherical surface of the ball designed for that seat. Not only was the sealing improved, but also the differential pressure rating was raised beyond 10,000 psi.
The advent of the degradable alloy frac balls helps to ensure that production is maximized. This assurance gives operators added confidence that each well is performing to its limit, thus enabling better management of reservoir development. By eliminating the risk of balls breaking or jamming in the seats, considerable time and money is saved because cleanout milling trips will no longer be necessary.