Brian Grayson
Weatherford International Ltd.
Well control related events present the greatest risk to operational safety during offshore drilling and completion. Misdiagnosis of an event and the failure to quickly and correctly take action can result in the loss of millions of dollars in non-productive time, and in the extreme, loss of life, environmental damage, and loss of the rig.
These risks to well control and drilling efficiency are being mitigated by combining a closed-loop mud circulating system with an innovative, software-enabled risk management approach. The combination is bringing drilling crews an unprecedented degree of early warning regarding downhole events and the ability to respond to them immediately before they can escalate into a well control event.
Costly problem
A 2009 analysis of deepwater Gulf of Mexico non-productive time (NPT) resulting from stuck pipe, well control, and fluid loss revealed that these hazards accounted for 5.6% of total well time and 31% of total NPT in non-subsalt wells. In subsalt wells, the metric doubled to 12.6% of total well time and 41% of NPT.
Extrapolated losses in a well of 20,000 ft (6,096 m) measured depth (MD) were $2.5 million and $7.66 million, respectively. These metrics do not include the total well failures resulting from drilling hazards. A 2010 Gulf of Mexico study showed that pressure-related events comprised 48% of incidents when drilling conventionally.
Well teams have traditionally sought to minimize drilling hazards and maintain well control by applying best practices that focus on:
- Managing the margin between the lowest equivalent circulating density (ECD) required to ensure safety
- Wellbore integrity and drilling efficiency
- The highest ECD achievable without risking fluid loss or fracturing the formation.
However, applying these best practices doesn't address drilling hazards and resulting well control issues that result from unnecessary or inappropriate actions taken when wellbore dynamics within narrow drilling margins are incorrectly interpreted or simply not recognized.
Successful mitigation depends on recognizing, interpreting the data, and making the right decisions. Assessment must be undertaken from both a holistic and detailed perspective on technology, people, and organization.
To mitigate drilling hazards and control the well, the operator must identify and design for potential causes and be able to respond appropriately if an influx occurs.
Conventional techniques to understand and control wellbore dynamics are limited by rig circulating systems with an annulus that is open to the atmosphere. Relevant information is typically limited to what does or does not flow from the annulus. Measurements occur at the surface some time after the downhole stimulus, whether it is a minor influx, wellbore breathing, or a dangerous kick.
To avoid a well control event, drillers must often make immediate well control decisions based on limited information and incomplete understanding of ongoing downhole conditions. However, responding incorrectly may exacerbate the problem and potentially precipitate a larger well control event. Traditionally, responses are limited to primary well control options such as fluid program and casing design, and secondary control consisting of the BOP system and procedures.
Closing the loop
A closed-loop circulating system dramatically improves downhole visibility and response to downhole events. The system complements and enhances conventional well control with proactive or preventive wellbore pressure management through real-time monitoring and precise control of downhole pressure profile.
The closed-loop system integrates several common oilfield technologies – rotating control devices (RCDs), flow-metering technologies, automated drilling choke systems, and downhole isolation valves. The elements are field proven, readily available and relatively economical. Individually they add incremental safety and efficiency benefits. When integrated to create a closed and pressurizable mud-return system, the benefits escalate exponentially and a watershed change in well control capabilities often results.
In the Weatherford closed-loop circulating system, RCD directs annular flow through a measurement and control system consisting of an automated choke, pressure gauges, and coriolis mass flow meters. Current RCD technology includes specialized devices for land and a full scope of marine applications. Onshore and from fixed platforms, RCDs are mounted atop the BOP. On floating systems, subsea below-the-tension-ring (BTR) RCDs are integrated with the riser system to close the circulating loop.
Reducing or increasing flow through the choke assembly increases or decreases backpressure in the closed-loop system. These surface changes are felt immediately in the wellbore just as pressure on a car's brake pedal is felt at the brake pad. The information travels equally well from the wellbore to the surface.
A closed system thus provides not only control but also a rich source of high-resolution data. Precise pressure and mass flow information is acquired in seconds. Wellbore volume variations, measured in gallons, can be detected almost immediately.
These measurements of micro-fluxes in the wellbore fluid column are obtainable while circulating, drilling, tripping, making connections and stripping, and are precursors to kick or loss events. This information and its speed and quality enable a more effective and advanced response to mitigate a critical well event.
Real-time analysis of the data is performed with a Microflux analysis and control system that applies proprietary algorithms to the flow and pressure data. The system acquires downhole and surface data from multiple sources and characterizes it to provide real-time, high-quality information. On a fixed rig, the control system has detected kicks at 0.25 bbl of influx. On a floating drilling unit, where vessel movement had introduced a 25 barrels per minute peak-to-peak variation, a kick was detected at less than 3 bbl influx.
Scalable well control
The higher fidelity information acquired by the closed-loop circulating system is easily scaled to support a variety of drilling hazard and well control applications, including monitoring wellbore parameters, kick/loss detection and management, constant bottomhole pressure (CBHP) drilling, and pressurized mud-cap drilling (PMCD). Pore pressure, ECD, and swab-and-surge pressure can be measured while drilling and making connections. Mud weight can be managed more effectively during tripping operations to detect pipe washouts and surface leaks. Minute downhole pressure fluctuations can be detected and automatically managed to prevent kicks and the further development of kick-loss cycles.
One key advantage of the closed-loop system is its ability to help differentiate between an impending kick and other downhole events such as ballooning, breathing, or micro-fracturing. Ballooning and breathing occurs when mud that is forced into the formation while pumping is returned to the wellbore when pumps are turned off, such as when making a connection.
With open-to-atmosphere systems, it is easy to overlook the trending and misinterpret this flowback as a kick. The risks presented by a kick are so great and conventional control options so limited that a well control response must be considered immediately. False diagnosis can be costly and dangerous. Weighting up the mud system to mitigate a misdiagnosed kick poses the risk of overbalancing the hole and initiating a loss. The event can dissolve into a cycle of kicks and losses that consume days of lost time, cost millions of dollars, harm formation productivity, and potentially result in loss of the well.
Deepwater drillers face a similar situation with riser gas, which occurs when gas is released from cuttings or from the mud itself with reduced hydrostatic pressure as fluid is circulated up from great depths. Released in the relatively low-pressure environment of the riser, the gas presents an immediate risk to personnel, the environment, and the rig. Because it occurs in the riser, it is above the BOP and too close to the surface for an effective mud response. Misinterpreted as a kick, it may nevertheless initiate a well control response.
Expanding value
The bowtie diagram that applies risk modeling to the causes and consequences of an influx of hydrocarbons into the well illustrates the value that closed-loop circulating systems bring to well control and drilling hazard mitigation. The closed-loop system adds layers of options to both the prevention and mitigation sides of the diagram. To prevent an influx, closed-loop drilling (CLD) adds real-time data for early event detection and identification. Annular pressure control provides a means of proactively managing pressure variations to prevent them from developing into well control events. Continually monitoring and capturing data also provides feedback for updating pore pressure predictions on the fly and for modeling future well designs.
Should an influx occur, a CLD system provides a greater degree of mitigation finesse ahead of closing the blowout preventer (BOP). The simple addition of an RCD greatly enhances crew and rig safety by diverting any returns away from the rig floor. In the event of sour gas or a blowout, an RCD provides a fundamental improvement without any changes to conventional rig operations.
Automated control of an influx using managed pressure drilling methods applies annular backpressure to mitigate the influx and to enable controlled circulation out of the wellbore. Both options enhance and supplement traditional control with methods that can be applied early, effectively and with much less disruption and cost associated with NPT than traditional means.
Real results
Closed-loop circulating systems have proven successful in mitigating well control related risk and improving economics across a range of deepwater drilling applications. While drilling a high-pressure, high-temperature (HP/HT) well in the North Sea Elgin/Franklin field, using the closed-loop system in a managed-pressure drilling (MPD) application enabled the operator to reach total depth (TD) approximately 75 days ahead of plans based on experience with conventionally drilled offset wells. Abnormally pressured formation layers were drilled by manipulating backpressure to achieve dynamic mud weight management. Five separate influxes were successfully managed over nine days to facilitate fast resumption of drilling.
The ability to quickly identify the high-pressure, low-volume gas stringers while drilling enhanced safety and well control. A kick was processed quickly and safely without having to circulate it out of the wellbore. Being able to safely drill through these troubled zones allowed for the elimination of a planned liner section.
A deepwater exploratory well was drilled successfully in an area of Indonesia where pore pressures and fracture gradients were not well understood. The application aboard a drillship in 3,400 ft of water was the industry's first use of a submerged RCD. The Weatherford Model 7875 RCD was installed below the tension ring as an integral riser component. Early in the drilling process, the closed-loop system detected a 2 bbl influx and successfully processed it out of the well. The upper part of the structure was drilled using CBHP methods and experienced no losses. When losses did occurred in the deeper hole section, the system was transitioned to pressurized mud-cap drilling methods and the well was drilled to TD.
Estimated surface pressure of nearly 15,000 psi made pore pressure evaluation and kick detection critical while drilling an exploratory well on the Norwegian continental shelf. A key objective was setting the 97⁄8-in. production-casing shoe as close to the reservoir as possible, facilitating drilling of the 8½-in. section to TD within a very narrow 0.4 ppg drilling window.
A closed-loop system helped avoid well breathing problems while maintaining an overbalanced wellbore. Ballooning issues when making connections were mitigated by eliminating the time required to circulate gas out of the hole. Using the closed-loop system saved an estimated 10 rig days and $7.5 million while reducing risk and improving safety. The system accurately determined pore pressure without the need for wireline tools, even during a sudden rise from 17.5 to 18.6 ppg.
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