Is Technology Outpacing Competency?

Every year, we see new tools and toys designed to increase efficiency and save time and money, but does advanced technology deliver to expectations, or just add unnecessary complexity?

Mark Mitchell, group vice-president of drilling hazard mitigation at Weatherford International, moderated the first of three plenary sessions in New Orleans this week, at the annual drilling conference presented by the International Association of Drilling Contractors (IADC) and Society of Petroleum Engineers (SPE).

Audience

The audience of several hundred represented operators (41%), service providers (28%), drilling contractors (12%), and others (19%), predominantly based in North America (76%) and Europe (17%). A surprising majority (60%) had more than 20 years experience in the industry, and an additional 16% had 11-20 years. What we consider young professionals represented barely a quarter of the audience.

When asked if they believed our current technology is too complex, 34% said, no, we just need to improve training, and another 34% said yes, that we need more input from users at the design stage. Only 7% said our current technology is intuitive and easy.

When asked if current training programs are keeping pace with technology changes, 45% responded only somewhat – their companies provided updated training only every 5-10 years.

When asked if current training programs are keeping pace with technology changes, 45% responded only somewhat – their companies provided updated training only every 5-10 years.

Another 28% said yes, training was cutting-edge, and 20% said “training” was only obtained through on-the-job experience. A disappointed 6% said their companies offered no training.

When asked if the reduction of 2009 hiring programs would have a long-term impact, 42% said very much so, and another 40% said somewhat, that a lack of skilled personnel would be felt 3-5 years out. Too early to tell, said 10%, and a final 8% said no, the reduced hiring would have only a short-term affect.

When asked what changes in mindset and practice the industry needs to make in order to keep pace with technology, 72% said we needed to return to basics, work with universities to upgrade practical training and provide internship opportunities, and offer more training in countries developing their natural resources. 

Another 19% said we needed just a “return to basics,” though admittedly vague.

Statoil

Statoil’s Helge Hove Haldorsen said that drilling will have to become more efficient and cheaper if we are to supply 35% more supply by 2030―the equivalent of 4-6 additional Saudi Arabia-sized reserves. One of the new frontiers is the deepwater Gulf of Mexico, two-thirds of which is covered by salt. Today, a 30,000-ft well in 6,000 ft water depth can easily cost US $100-250 million to drill and complete. Halvorsen challenged the industry to cut those costs in half, while also reducing CO2 emissions.

To do that, he said, sub-salt imaging must improve. We need better technology and competency to be able to map the sub-salt more precisely. The aim is to drill multi-fractured, multi-lateral, undulating wells everywhere. In the Troll field, North Sea, Statoil now has 120 multilateral wells, each with as many as five branches, and a CO2 capture and reinjection program now injects 2.7 tonnes CO2/year, equivalent to the emissions from about 1 million cars.

NOV

National Oilwell Varco’s Fred Florence reviewed significant technology improvements over the past 40 years. In the 1970s, thruster-assist systems evolved to today’s dynamic positioning systems. In the 1980s, we moved from spring-set slips, added air cylinders, and saw the first Varco top-drive. In the 1990s we had iron roughnecks running on tracks, and the first pipe-handling systems, and in the 2000’s, widespread use of remotely operated vehicles (ROVs). In this decade, Florence said advanced control systems would probably be the biggest legacy.

Mechanization, such as power slips and iron roughnecks, provides strength in operations beyond human’s manual capability. Drill-floor robotics is an example of automation that emulates repetitive motions and reduces human exposure.

At the outset, automated systems go to high-end rigs, because the value is easier to see, and more money is available for R&D on those projects. The challenging business case is how to migrate and deploy higher technology on other rigs. Internationally, Florence said it’s important to realize that cultural differences cause equipment to be used differently in disparate geographic areas. And in order for changes to be fully utilized, there must be recognizable value for everyone from the drilling superintendents to the rig crews.

What change can we tolerate? Florence suggested controllers built to reduce training requirements, equipment monitoring and diagnostic improvements, real-time dynamic models, and systems that handle multiple models and multiple control inputs simultaneously. Once we understand how technology on the drill floor affects the well, we’ll drill more wells cost-effectively and drill wells not possible before.

BP

BP’s vice-president of drilling and completion engineering, Scott Sigurdson, said that in all our industry operations, its important to get it right the first time. Wells are getting more complex―deeper, hotter, and higher-pressured, with ever-increasing reach and targeting unconventional reservoirs. Deep gas bottomhole temperatures in the Gulf of Mexico can reach 500º F, with 25,000 psi wellhead pressures. BP’s Liberty wells off Alaska will stretch beyond 40,000 ft.
BP has programs to assess competencies for employee’s early (1-2 year) career, but not beyond 3 years.

Old salt

Mark Childers was the final speaker, and pointed out that for more than 25 years, technology in this industry has been innovative and successful, opening mammoth reserves. But new technology is not always better, nor safer, and adding new some technology has sacrificed rig operational efficiency and reduced the ability of rig personnel to operate independently. He pointed out three main areas of concern:

1. Widespread use of exotic and complex electronics, even for simple and straightforward tasks and equipment.

2. Temperamental deepwater subsea BOP control systems that require extensive repair time and are not redeployable. A typical control pod for an all-hydraulic BOP, which Childers’ recognized could not be used subsea, weighs about 4,000 lbs, while subsea BOPs weigh 40,000 lbs, are non-retrievable and non-reinstallable. The extensive downtime sometimes requires reconditioning of the hole, adding to the cost. It makes sense to modularize subsea control systems, Childers said, so that repairs can be performed with ROVs and wireline operations.

3. Tubular pipe-handling systems that actually introduce inefficiencies and downtime.

We need to consider the cost of new technology versus the savings in operational time and safety.