Front-loaded approach to well control stresses planning, prevention

Lower risk tolerance across industry leads to sustained focus on competency, early kick detection technologies

By Katie Mazerov, Contributing Editor

An ounce of prevention is worth a pound of cure. Benjamin Franklin’s sage advice still resonates today, even in 10,000-ft laterals and subsea wells a mile or more beneath the sea floor. The adage is especially fitting when it comes to well control, which, in a post-Macondo world, is increasingly about prevention, planning and preparedness.

“With the complexities, risks and costs of wells being drilled, there is a heightened focus on HSE competency and upfront efforts, including engineering and contingency planning, to prepare for an event we hope will never happen,” said Carl Cramm, Relief Well Operations Manager for Boots & Coots, a division of Halliburton.

“We are seeing an emphasis on improving competency up and down the organizational structures of operating and well control companies, especially in the offshore sector, as more regulatory agencies and countries take a deeper look into ‘what if’ scenarios and the practicality and thoroughness of the plans in place to deal with a well control event,” he continued.

Alongside state-of-the-art BOPs and effective well-capping techniques, which are reactionary measures to an advanced well control situation, the industry is shifting from a backend-loaded approach to a more front-end one. This includes everything from casing design and how a formation behaves to sophisticated early-detection tools.

While the trend has particularly impacted the offshore sector, it is occurring on land, as well, with many smaller operators adopting the stricter protocols that larger companies have likely had in place for several years, Mr Cramm added.

In response to both Macondo and the devastating hurricanes in the US Gulf of Mexico (GOM) in recent years, Boots & Coots established a dedicated relief well operations group that is taking a holistic approach to well control. The group examines all aspects of the process, including talent recruitment, development of better relief well contingency planning and more effective use of technology.

“For example, we’re taking existing technologies and using them in new applications to respond early to well control situations,” Mr Cramm said. “New applications of technology will be needed for the expected increase in well decommissioning work, especially in the GOM, where extended-reach, high-pressure, high-temperature (HPHT) and deepwater wells drilled as far back as the 1960s are coming to the end of their lives and can’t be re-entered due to geological or mechanical issues.”

Attitudes on rigs also are changing, as adherence to plans is strictly enforced with little or no tolerance for wavering from operational guidelines or relying on past knowledge and protocols. “Plan the work, and work the plan,” he said. “If there is a deviation from a drilling procedure, the supervisor must officially sign off on it as opposed to verbally reporting action after the fact.”

However, even the best-laid plans can go awry. “If we write the perfect plan and execute it perfectly, everything should be fine all the time,” Mr Cramm said. “Yet, no matter how well we plan, we deal in a world of so many unknowns – geology, geophysics, subsurface hazards, the human aspect. We don’t always know what we don’t know.”

Which is where detection comes in. “With the advent of more sophisticated electronics and sensors, the ability to detect a problem before it becomes a problem is a huge goal,” Mr Cramm said. “Advances in drilling are enabling us to drill much closer to that definitive line in the sand where, if we cross the line, we’re in trouble, but if we drill close to the line, we can effectively extend the technical boundaries and achieve better margins.”

A grand vision

OnSite Integrated Services, established in January 2013, is developing a software system that optimizes drilling efficiencies by measuring, in real time, several downhole and surface parameters. The goal is to provide a better, quicker response time for kick detection, ballooning and loss circulation severity. OnSite is able to use the same data to infer hole-cleaning, sweep and mud pump efficiencies, Managing Partner Jason Norman explained.

The system uses Coriolis meter technology on the flow and suction lines to measure a mass balance of the circulatory system. The mass flow going into the well, coupled with the amount of cuttings being generated at the bit, provides a window into mitigating many common NPT drilling events. “By using mathematics to determine the amount of cuttings being generated, I can plot the amount of cuttings being removed from the well; the difference is what I should be seeing at surface to ensure efficient hole cleaning.”

The technology is being tested on a rig working for ConocoPhillips in the Eagle Ford. “There are areas in almost every operator’s portfolio that have significant hole-cleaning problems, stuck-pipe incidents, frequent kicks and losses of varying severity, ballooning events that are hard to determine and mud management issues that we can help address,” he noted.

Coriolis meters have been installed on flow and suction lines on many offshore rigs to provide early kick detection or for managed pressure drilling applications. However, traditionally they have not been used as a mud-monitoring system, Mr Norman said. “This system uses mass balance to measure hole cleaning and sweep efficiency, as well as early kick detection, with more clarity than conventional systems that rely strictly on flow paddles or pit volume sensors.

“It’s a unique calculation that can mitigate a well control problem before there is a problem,” he continued. “In the event of a kick, the decision on how a well control procedure is initiated is partially determined by the volume of the kick. If a well can be shut in at 1 barrel, there is almost no issue. At 100 barrels, we could have a problem. We pull all the relevant data into our controller to make use of every piece of available data on the rig to help identify the well control incident as quickly as physically possible.”

Any indication of an increase in flow rate or temperature and any indication of a decrease in density or drill pipe/pump pressure is flagged. The system monitors volume reconciliation in real time and will detect an influx during a connection. It also can differentiate a balloon from a kick. “The primary objective is to remove all doubt from the process and get back to drilling much more quickly than with conventional methods.”

The concept of the system is part of what Mr Norman calls a “grand vision” of a totally optimized drilling fluids process on a rig that has all capabilities of automation. “We’ve tried to build a system where we’re not bombarding the driller with a lot of new data,” he said. “Calculations are done in the background, with alarms if something goes askew.”

For example, the system can provide a “soft” alarm if hole-cleaning efficiency declines. OnSite formed a joint venture with RigMinder to provide the software and system integration. While the software is ideally installed on advanced rigs that provide good-quality torque and pressure readings and pit volume sensors, it can be plumbed into the existing data aggregator on any rig, he said.

Shift in attitudes

While technology is playing an increasingly important role in helping the industry better predict and detect well control events early-on, mitigating risks associated with well control events still depends heavily on the rig floor crew, who are still the first line of defense, maintains Bill Mahler, Executive VP and General Manager, Wild Well Control. “Their ability to recognize then react properly when an incident does occur means the difference between a safe rig and one that suffers a well control incident – possibly a blowout.”

In the past few years, Mr Mahler has seen a decided shift in the industry’s attitude toward well control. “Today’s operators are much more understanding of the need to mitigate these well control risks, whether it be in the initial design, the well planning phase, the execution of the drilling plan or in the preparedness for responding to a well control incident,” he said.

The trend in better management of these risk is global but is much more evident in the US because of the amount of drilling occurring, Mr Mahler noted. “We’re seeing a lot of regulatory changes, specifically regarding wellhead equipment, more attention to well control training and competency assessment of the rig crews in terms of well control, all resulting in the better management of well control risks.

“As the industry begins drilling and developing deeper and higher-pressure wells, operators have a heightened awareness of the greater risks associated with such environments and are more deliberate than ever in completing their due diligence regarding the mitigation of perceived and identified well control risks,” he continued. “As a result, the percentage of well control emergencies versus wells being drilled, specifically in the US, has decreased in part because of the greater attention to the management of these risks.”

The insurance industry is also recognizing the value of incentivizing operators to seek early resolution of well control events. “Two leading insurance underwriters are covering a portion of the cost of bringing in a well control company, not for a blowout, but when the well is still contained,” Mr Mahler said. “In the past, there has been a hesitance to involve well control companies because of the perceived prohibitive costs. However, the insurance company’s goal is to reduce the number of claims and the size of claims. When operators engage a well control company before the well gets out of control, they are minimizing escalation of that event to a blowout.”

Alongside its original mission as an emergency response company to well control events, Wild Well Control provides ongoing risk mitigation services, including well control training, audits of well control equipment on rigs, competency assessments of rig crews, emergency drills and relief well planning in the well planning stage.

Keeping up with regulations

Heightened regulations in recent years have had a significant impact on the expanding focus of well control companies to provide prevention-oriented services. Complicating the picture is that standards vary considerably among regions globally and from state to state in the US. “We have to keep reinventing ourselves to keep up with new government regulations and, based on those regulations, offer new services,” said Bhavesh Ranka, Operations Manager, Cudd Well Control (CWC), a division of Cudd Energy Services. The US Bureau of Safety and Environmental Enforcement, for example, now requires GOM operators to develop models for worst-case scenarios and relief well plans as part of the permitting process, he noted.

With advances in software programs for modeling kicks and simulating pressures at given depths, CWC is providing more engineering services as well. These include drilling plan reviews, relief well design, kick modeling, equipment inspections, emergency response measures and blowout contingency plans, Mr Ranka said. In remote areas, risk assessment has become increasingly important, often requiring operators to establish a hub for housing well control equipment that otherwise would take days or weeks to be shipped.

“We are doing a lot of inspections of well control equipment on the rigs, making sure the equipment is configured per API, IADC and other regulatory standards,” he said. Operators are inquiring about having a well control expert on the rig during critical drilling phases and when drilling well sections that are anticipated to be troublesome.” CWC also provides services as an independent third-party witness for BOP testing and shear calculations, now required before BOPs can be installed on rigs in the GOM.

Onshore, with the advent of intensive pad drilling campaigns and the associated increase in well control complexity, the focus on preparedness is also increasing, Mr Ranka noted. “With multiple vendors and simultaneous operations going on, there is increased risk. For example, if an incident were to occur on a pad, we could see multiple wells impacted,” he said. As operators engage in more contingency planning, CWC conducts completion and workover equipment audits that examine the entire operation, including coiled-tubing and snubbing units.

Whereas most of the big operating companies have traditionally included well control in their planning and budgets, for smaller companies, integrating contingency planning protocols is a significant step-change. “In working with these companies, we try and convince them of the benefits of being prepared from a cost, safety and compliance standpoint,” he said. “Many insurance companies offer discounts to operators who develop preparedness plans.”

Oftentimes, compliance issues have to do with documentation and/or paperwork, crew attitudes and operational integrity of the equipment. Certification records for BOPs and other well control equipment must be easily accessible on the rig, rather than an offsite location. From an equipment standpoint, manifold chokes are seldom used in land operations, meaning the valves need to be inspected to ensure they are operable.

Training is essential for the growing number of HPHT operations, which require an understanding of how fluids behave in extreme environments. “Human error is still responsible for most well control incidents, due to lack of training regarding everything from appropriate response measures to proper maintenance of the equipment,” Mr Ranka said. “Even the rare equipment failure can be traced to human error.”

Gaining control

In terms of procedures and methods for dealing with a well control event, very little has changed since the 1950s, according to Dr Helio Santos, president of SafeKick, a developer of a software program designed to help rig crews better understand well conditions to react more quickly and safely to well control events. “Historically, the emphasis in well control has been on improving equipment, such as BOPs and, after Macondo, capping the well after a blowout. Our aim is to help companies drill in challenging environments and ensure they are compliant with heightened environmental regulations.”

The company’s SafeVision software family, introduced in early 2013, features a package for office-based staff that enables remote monitoring and interpretation of real-time data from rig sensors. The information is then communicated to the rig crew so they can take the appropriate action for keeping a well control event from escalating. A package for rig-based personnel, which utilizes the same software either independently or with the office package, enables crews to have access to the same screen as the remote users, Dr Santos said. “By using both, the decision-making process is accelerated and in sync, reducing the time to regain control of the wellbore.” Both packages also include alarm systems.

A kick tolerance module takes into account key downhole parameters that are not usually considered by most conventional kick tolerance methods, including temperature, fluid compressibility and additional wellbore weak points. “The primary goal is to provide a valuable tool to help the rig crew after the BOP has been closed,” Dr Santos said.

The software is being used on wells in the GOM, Brazil and Asia, and Dr Santos believes it is especially suited for the deepwater market, where the consequences of a well control event due to pressure issues and narrow drilling windows are very high.

The office package has been used to monitor more than 50 wells in the Mediterranean, West Africa, Middle East, GOM and offshore Brazil. Rig packages have been installed in the GOM by a major drilling contractor and a major operator, and installations are being prepared for additional rigs in the GOM and Brazil.

“One operator successfully used the system during a well control event to better understand the downhole conditions and properly define which operations to conduct to regain control of the well,” he said. The Standalone SafeVision package, a full simulator with the same interface and capabilities of the office and rig packages, is used for well planning and training.

SafeKick also has developed an automated choke that can be installed on any rig to allow crews to automatically maintain pressures at a designated level during a well control event. It can be installed independently or in concert with the software package. “Having just the automated choke is useful, but knowing the correct amount of pressure needed during a well control event is extremely valuable,” Dr Santos pointed out.

SafeVision is a trademark of SafeKick.