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Vol. 12, No. 41 Week of October 14, 2007
Providing coverage of Alaska and northern Canada's oil and gas industry

30 STRONG: The drilling waste dilemma

Hardrock mining technology adapted for modern grind-and-inject disposal

Rose Ragsdale

When oil and gas explorers converged on the North Slope in the 1950s and 1960s, they brought industry practices from the Lower 48. These customs included constructing berm-enclosed pits beside new wells for disposal of discarded rock, mud and other solids that came out of the ground during the drilling process.

By the 1980s, these “reserve” pits not only had become eyesores dotting the tundra, they also could melt underlying permafrost and threaten to leak.

The Alaska Department of Environmental Conservation began to regulate disposal of drilling wastes and to issue permits for use of reserve pits.

It’s not that drilling waste is a major hazard per se. Oil and gas drilling in Alaska is actually minuscule, compared with such activity in some other states. Only about 5,000 oil and gas wells have been drilled at 605 sites in Alaska. Compare that with more than 220,000 wells in Louisiana and 500,000-plus active wells in Texas, according to DEC.

Alaska laws, in fact, still allow operators to build reserve pits for drilling waste. But a single reserve pit can cover several acres, marring the landscape in a way that many people find objectionable. State regulations also require companies to monitor water quality near reserve pits for a number of years, and DEC holds operators responsible for pollution at the sites indefinitely.

Thus, ARCO Alaska Inc., a subsidiary of Atlantic Richfield Inc., was ready to talk when an environmental group sued the company in the late 1980s over the use of reserve pits on the North Slope.

ARCO decided to clean up its reserve pits, thereby paving the way for a new approach to drilling waste disposal.

Underground disposal solution

The idea of underground disposal of drilling solids surfaced. But how could operators get chunks of rock and other solids efficiently below ground?

Down-hole disposal of drilling waste, after all, wasn’t a new idea. A few operators, in fact, were injecting water produced from oil and gas drilling as early as 1940. They started by disposing of produced liquids in depleted wells. But when petroleum production increased in adjacent wells, operators quickly recognized the benefits of this practice. The prospect of increased oil recovery encouraged them to favor disposing of produced water down hole, and by 1985, operators nationwide were injecting produced water into wells nine out of 10 times.

Injecting solids down hole on the North Slope, however, was another matter. After some trial and error, including a pilot project in 1988, ARCO drilling engineers realized they could solve the problem economically, with a little help from hardrock mining technology.

“We bought a ball mill and took drill cuttings, which are mostly rock, and crushed them to slurry them with water,” recalled Jim Weeks, then a top manager for ARCO Alaska on the North Slope. “It was an old mining technology applied in a different way.”

It wasn’t long before the reserve pits became yesterday’s news.

“The whole concept of reserve pits next to the wells went away,” Bob Blankenberg, solid waste program director for DEC, said in June. “Solid waste disposal evolved from putting it in the reserve pits to taking it to a central landfill to applying grind-and-inject technology, which is used today.”

North Slope operators soon began cleaning out their in-field reserve pits. They took mud and cuttings to a large-scale grind and injection plant near well Drill Site 4-19 in the Eastern Operating Area of the giant Prudhoe Bay oil field. DS4-19 was a disposal well, drilled and completed as a produced water injection well in September 1989.

By 1994, refined grind-and-inject technology had enabled both Prudhoe Bay operators, BP Exploration (Alaska) Inc. and ARCO to achieve “zero discharge” of drilling wastes, eliminating the need for reserve pits.

ARCO put its grind-and-inject plant into operation and slurry injection began at DS4-19 on March 31, 1995. By 2000, some 1.2 million cubic yards of solid material — mostly cuttings — had been pumped down hole on the slope. That amount in gravel would build a 3-feet-thick-by-27-feet-wide road about 75 miles, or from Anchorage to Willow.

Changing an industry

Today, most oilfield waste — drilling mud, drill cuttings, and produced brine water — generated on the North Slope is injected down hole. Produced brine water has never been a problem, but drilling mud and drill cuttings require special handling.

“Grind-and-inject technology changed the way we manage muds and cuttings,” ARCO’s Harry Engel told participants in a technologies conference in 2000. “G&I is a prime example of utilizing technology to improve an environmental management system. This permanent and environmentally sound disposal method isolates wastes, eliminates subsequent disposal and greatly reduces the surface space required for drilling operations,” Engel said.

The elimination of reserve pits onshore has decreased habitat destruction and eliminated the possibility of reserve pit overflow as a potential source of tundra and surface water contamination. Offshore, the probable benefits are not easy to specifically define, but directionally, the potential for contamination of near-shore waters has been eliminated, according to engineers at the Alaska Oil and Gas Conservation Commission.

What is grind & inject?

When a well is spudded, a drilling mud is constructed by mixing a bentonite clay with water to produce a viscous, thixotropic solution that is capable of performing several functions essential to drilling the well, including mud the well bore, overbalance the formation pressure and remove cuttings from the well bore.

As the formation is drilled, rock material is ground up, some into large particles and some pulverized and suspended in the mud system. The process raises the viscosity to a point where the mud is not easily pumped. As the rock-laden mud circulates to the surface, it passes over 80-mesh shaker screens to remove coarse material. To maintain the mud at a pumpable viscosity, demanders, desilters, and centrifuges can be used to remove finer particles. In addition, the mud is diluted, or “watered back” to reduce its viscosity. This increases the volume of mud and some of it must be removed.

Drill cuttings, or the solid material that results from drilling wells, are recovered at the surface through the use of the shakers, demanders, desilters, and centrifuges. This material is run through a ball mill to grind it until it is fine enough to be pumped into the formation without plugging the openings.

Best of available options

Thanks to grind-and-inject technology and the underground disposal of the resulting slurry in wells ranging from 2,000 to 9,000 feet deep, the operators have been able to clean up nearly all of the reserve pits on the North Slope. Some 513 of 605 reserve pits statewide have been cleaned out, while another 17 — mostly on the North Slope — are expected to be closed within the next year, according to DEC.

Another 57, mostly North Slope sites, are slated for future corrective action, and all inactive reserve pits owned by BP, ConocoPhillips Alaska Inc. and ExxonMobil Production Co. are currently expected to be closed by 2014, Blankenberg said.

Grind-and-inject technology and underground disposal also are used for drilling waste from recent exploration and development activities.

Thor Cutler, environmental scientist for the U.S. Environmental Protection Agency’s Region 10, said widespread use of this preferred alternative, especially at newer slope fields like Alpine and Badami, has eliminated the need to transport waste material across the tundra, which further reduces the industry’s footprint on the surface.

“It provides the opportunity for handling the material in a better way,” Cutler said.

Figures compiled by AOGCC show that down-hole disposal of drilling waste may be the most cost-competitive alternative. Of viable options available, grind-and-inject disposal is certainly the most attractive, costing about $100 per cubic yard and offering the prospect of being a permanent solution. Other options include below-ground encapsulation, which also costs about $100 a cubic yard; and shipment to the Lower 48 at an estimated cost of $600 to $1,000 per barrel. Neither of these options can offer a guarantee of being permanent solutions, AOGCC said.

Though down-hole disposal is a “very expensive alternative” in that underground injection wells cost several million dollars to drill and require substantial sums for ongoing operation, Cutler said the technology, in the long run, has improved the net outcome and may lead to net savings.

“Not only is well spacing in newer fields such as Northstar and Alpine much smaller than in the past, we’ve seen significant reduction in the footprint of drilling pads, and permanent roads and river crossings are no longer needed for land transport of waste being hauled to a central site for disposal,” he added.

North Slope fields, in fact, have shrunk to one-fifth of their former size during the past 30 years, due in part to the elimination of reserve pits and the advent of grind and inject technology.

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