By Eric M. Johnson and Nia Williams

CALGARY, Alberta (Reuters) - ConocoPhillips <COP.N> has 25 percent of wells activated at its 60,000 barrels per day Surmont oil sands project, which had been shut down as a precaution due to a massive wildfire in northern Alberta, a company executive said on Tuesday.

Conoco, the largest U.S. independent oil company, restarted production last week after a 29-day shutdown at its thermal project some 63 kilometers (35 miles) southeast of the fire-stricken town of Fort McMurray. First production started flowing on Friday.

The blaze shuttered more than a million barrels per day of crude production in the oil sands region, the world's third-largest crude reserve, though most producers are now in the process of ramping up.

"We have about 25 percent of the wells done," Perry Berkenpas, senior vice president oil sands, said in an interview at the company's offices in Calgary. Conoco said 39 of 156 wells are back on line.

"What we've been able to do is keep within safe operating windows and still ramp-up the production more aggressively than we originally planned," he said.

While he declined to provide a specific timeline for when the site would reach full pre-fire production levels, Berkenpas said it would "probably not" be by early July.

Even so, Berkenpas said the company is "absolutely on track" to reach a capacity of 150,000 bpd gross by the end of 2017. The joint venture between Conoco and Total E&P Canada was producing roughly 60,000 bpd before the fire, or 30,000 bpd net for Conoco alone.

Earlier on Tuesday the company said there was very minor damage at Surmont and the majority of its nearly 700 employees were expected on-site by the end of this week. It said it found "very minor damage" with no impact to on-going operations.

Thermal operations means that steam is injected into the oil sands reservoir, slowly liquefying the tarry bitumen deposits so they can flow to the surface. In general, the length of time operations are halted and the maturity of the reservoir are crucial for determining how difficult and costly a restart process is.

Berkenpas said generally they are finding that the pressures and temperatures either match what they thought they would be, or in some cases were better.

"During the startup we found that we have a couple of different wellbore designs (the wells and internal equipment) and some of those designs seem more robust than others and allow us to do the startup and ramp-up a little bit faster than some of the previous designs," he said.

(Reporting by Eric M. Johnson and Nia Williams in Calgary; Editing by David Gregorio)