Automatic Rig Leaves Soon for North Slope
Abstract:Combining automated pipe handling and drilling capabilities with lighter weight materials is a natural extension of today's "systems" approach to solving exploration and production (E&P) challenges. The result will be fewer injuries, lower costs, and more environmentally acceptable drilling equipment.
Analysis:The sharp end of an "automatic" drilling rig designed for Alaska's North Slope is scheduled for field-testing this coming spring, and if things go just right, BP could end up leading the way in developing shallow arctic oil and gas reserves much more safely and economically and with significantly reduced environmental effect.
Fabrication of the rig—called the "Light, Automated Drilling System (LADS)"—is in the final stages at Heartland Rig International's yard in Brady, TX, only a few miles from the exact center point of the Lone Star State. According to the rig designer, Phoenix Alaska Technology, a subsidiary of the Japanese multinational company Nissho Iwai Corp., the rig will be ready for loading out of the Port of Houston in the January to February range for shipment to Anchorage, AK, where it will then be trucked to the slope. The whole trip should take about 80 days.
BP Exploration (Alaska) Inc. plans to use it to drill up to six wells in the Milne Point field, a 400-million-barrel oil field located about 35 miles northwest of Prudhoe Bay. Discovered in 1969, the field currently contains more than 200 wells drilled from gravel pads. BP estimates that with development of the shallow, Schrader Bluff heavy oil reservoir in the field, an additional 300 wells could be required.
The problem is, conventional North Slope types of drilling rigs are too heavy and too expensive to use for shallow wells such as those required for Schrader Bluff development at Milne Point. What's more, moving costs for conventional rigs also add to front-end expenses in an area where economic returns are narrower than those gained earlier from deeper, larger North Slope reservoirs.
The LADS rig is a product of original BP Alaska research begun in 1997. At that time, the company funded an internal study and design effort specifically for Milne Point development. The effort was aimed at delivering a step change in cost savings. Using state-of-the-art 3D computer-aided design (CAD) software, the BP team designed a compact, lightweight, fully automated drilling rig made up of self-contained modules, all of which are mounted on either pneumatic rologon types of tires or rubber tracks for easy, less damaging transport over thawed gravel roads, narrow bridges, and frozen tundra. Once assembled, the rig takes up about a third of the footprint of a conventional arctic rig. It weighs less than a third of a conventional rig, as well, yet can drill the same medium-depth wells as those rigs currently in use.
The self-contained features of the LADS rig include a complete pipe-handling system that features pipe "magazines" from which an automated pipe pickup-laydown system allows hoisting equipment to draw single lengths of drill pipe from the horizontal magazines and add them individually to the drill string as the bit progresses into the wellbore. As a result, the derrick, though rated for 1 million pound hook-load capacity, is only 90 feet (27 meters) tall, rather than the 140-foot (43-meter) height of conventional derricks, in which triple stands of pipe are stacked vertically in the derrick itself. The drill pipe and/or casing is made up or broken out by an automatic tong system. Drilling is controlled with a top head rotary drive in the derrick. These operations are controlled from a single console, much the same as those conducted from modern offshore drilling units.
The LADS rig design also drew on the experience of drilling contractors in Western Canada by fixing the derrick at a slanted angle to allow for easier drilling of directional and horizontal wellbores. The rig has a number of self-contained service functions, including its own well fluid mixers and pumps, so that even cementing operations can be conducted by the rig itself rather than by cementing service companies.
However, using such an automated rig, particularly under trying North Slope climatic conditions, has as much to do with personnel safety and environmental awareness as it does with overall economics.
BP officials point out that once optimized, five persons can operate the LADS rig—fewer than half the crew necessary to operate a conventional rig with similar drilling capabilities. Initially, the company probably will have more workers on the rig. However, once using the system in the field reveals optimum operating conditions, the number of rig crew personnel eventually could be reduced. Ideally, the LADS rig would be operated by a permanent crew comprised of a driller, stationed at the drilling console; an assistant driller, who manages the drilling fluid system; a mechanics technician, who watches over the rig's hydraulic and engine systems; an electronics technician; and a general rig hand, who conducts various other rig chores. Other crew can be added for larger temporary jobs.
An important goal of using the system is to reduce exposure of personnel to rotating equipment, an age-old problem in drilling operations. Before automation began to reach the pipe-handling sequence aboard drilling rigs a decade or so ago, missing fingers and thumbs were commonplace among roughnecks. What's more, since the rig itself hoists, stabs, and connects pipe automatically, there is no need for human presence at the top of the derrick, and the risk of injury to rig floor personnel by falling objects also is mitigated. Overall reduced risk of injuries and fewer accidents are the expected results, along with lower labor costs.
But the LADS rig's much-reduced footprint, both while drilling and while in transit, also is an important factor, particularly since North Slope development has entered its later stages with smaller, shallower reservoirs calling for increased numbers of wells.
Except for the drilling module with substructure, mast, and drilling equipment—which are fitted with pneumatic tires that distribute the weight equally over a wide area—each of the other modules is mounted on four sets of heavy-duty rubber tracks. This track system was developed by Caterpillar for use by the National Science Foundation in Antarctica, and distributes the weight of each module so that the pressure at any point is about 15 psi. This allows the rig to be moved over North Slope roads, even during the spring ice breakup, when other rigs moves require special road mats.
And, of course, the LADS rig is designed for zero discharge. Rig liquids are double-contained to 110 percent of tank volume. It is the first Alaska rig to use a closed-tank drilling fluid system designed to reduce volatile compounds, noxious odors, and other emissions commonly associated with current advanced mud formulas. Modular air locks and ventilation systems provide further crew protection.
Finally, although largely operated hydraulically, the LADS rig employs multiple, state-of-the-art power systems. It can operate with computer-controlled, low-emission diesel engines, highline power, or with a combination of the two using a motor/generator and the diesel engines.
However, while the LADS rig probably is going to be watched closely by oil and gas producers with arctic and other remote prospects, it's really not as revolutionary as it might seem. Even BP points out that individual components are used alone or in combination on other drilling rigs almost routinely. It's all part of the "systems" approach borrowed from the aerospace industry years ago.
In fact, back in the 1950s and 1960s, development of a so-called "automatic" rig, although possible, was considered impractical and perhaps even dangerous. In those days, hydraulics was not as well developed a discipline as it is today. However, pioneers like R.J. Brummel—who actually built and demonstrated a fledgling "automatic drilling machine"—proved, for instance, that drill pipe could be handled and drilling conducted without a rig floor crew and a man in the derrick. But operators found it difficult to entrust the hazardous job of piercing underground formations to a machine. The Brummel rig attracted some attention in the industry in the late sixties, but problems with hydraulics and other rig equipment eventually stemmed operators' interest.
Max M. Dillard, a veteran Houston-based drilling contractor and oilfield service/supply specialist and business broker, acquired the Brummel rig some years ago, and had it upgraded to include new equipment and systems with improved reliability.
Dillard has said the rig still could be used effectively for development drilling.
And Dillard is still enthusiastic about the rig. Several years ago, he remembered a "stunt" often performed when he showed the rig to prospects.
"We'd take the prospective customer to look at the rig, which we had working over an existing wellbore. Then, when lunchtime came, we'd put the rig on 'automatic pilot,' and the driller would leave the console. We'd have lunch, and when we got back to the well site, the rig would still be racking and connecting pipe and lowering or pulling it from the hole," Dillard recalled in an interview several years ago. "They were always impressed by that."
Largely, however, advances in both automation and "systems" engineering in the petroleum industry almost dictate that the drilling operation continues to become more efficient, less expensive, and much safer. That, combined with the tremendous advances in exploration and production technology during the last decade or so, is probably one of the chief reasons why using the "rig count" to determine the health of the industry may be a measuring point of the past.
Whether LADS rig will revolutionize North Slope development drilling remains to be seen. However, it marks still another advance in equipment used to drill oil and gas wells. And a rig designed for arctic drilling, if workable and economic, could be redesigned to perform almost anywhere, from the Mid-Continent to offshore.