Badami has been an underperformer from the start, and was in warm shutdown for several years. Rising crude prices and some technological tweaks are combining to make it more profitable.
From Petroleum News (www.petroleumnews.com):
Vol. 12, No. 34 Week of August 26, 2007
BP to shut down Badami for recharge
Kristen Nelson, Petroleum News
The Badami field will go offline temporarily this fall — probably in September — after some two years of continuous production.
The most easterly of North Slope developed fields, Badami has had a lot of downtime since BP Exploration (Alaska) brought it online in 1998.
Most recently Badami has been in production since September 2005, even though BP said in 2005 it planned to shut the field down every six months for six months of reservoir recharge when that restart began.
When BP initially brought Badami online it expected the field to reach a production level of 30,000-35,000 barrels per day from some 30 wells.
But initial results were disappointing.
Production began in August 1998 and by October of that year the field was producing only 4,000-5,000 bpd from seven wells, not the 10,000 bpd the company had expected at that stage.
BP said at the time that the issue was the reservoir.
Badami produces from the Brookian, a complex turbidite reservoir — and the first of its type to be produced on the North Slope. Before the field came online BP officials said it was one of the most challenging reservoirs the company had attempted anywhere, with the oil in compartmentalized channels.
Badami was shut in early in 1999 when production dropped to 2,500 bpd and there was a risk that the Badami pipeline would freeze. The pipeline transports oil back to a central North Slope connection with the Endicott pipeline. The field was put back into production in May 1999.
Production continued, but the Badami sands participating area — the area within the unit that is in production — was contracted in 2000 from 12,737 acres to 3,680 acres.
“Poor hydrocarbon communication and high gravity oil within the reservoir resulted in low production rates,” the state said in commenting on BP’s 2000 decision not to drill additional delineation wells.
BP said at that time it would “continue production as long as production rates and temperatures remain at safe and economic levels,” but if production had to be shut in to protect the pipeline due to low production during low temperatures it would evaluate restarting the facilities.
The economic problem associated with low production caused a two-year shutdown starting in 2003. BP told the state at that time the 1,350 bpd production rate wasn’t enough to offset the field’s operating costs.
BP said in early 2003 that it would review the field’s economics but was also open to a sale or use of the field’s facilities to process and/or transport oil from nearby fields which were expected to come online, although none have yet done so.
Three-year test under way
In 2005 BP restarted Badami for what it said would be up to three years to test new recovery techniques. It told the state in mid-2005 that the high price of oil was a factor in the restart, as were new reservoir oil recovery methods designed specifically for Badami. BP said in 2005 that the reservoir could be a good “intermittent producer” but that there was the possibility it could become a good “continuous producer.” BP told the state that changing oil economics would determine if short-term or long-term operations are possible at Badami.
The company anticipated that six months of production and six months of recharge would alternate over the three-year period.
BP told the state this June in an annual update of the Badami plan of development that production has been continuous at Badami since the restart on Sept. 17, 2005, with production at an annual average rate of 1,100 bpd.
This production period, BP said, was “significantly longer than the nominal six months” the company anticipated when it filed the current plan of development for the field.
The company said it had been able to maximize the field’s production by focusing on depletion planning and reservoir management. This included close monitoring of well tests and gas-oil-ratio data.
The reservoir continued to decline, BP said, although frequent treatments to remove paraffin and asphaltenes helped maximize production. “These measures, combined with gas-lift optimization, contributed to the continuous production,” the company said.
One well has been used for gas injection, with production from the other wells.
The latest production reports from the Alaska Oil and Gas Conservation Commission, for June, show production from four completions and gas injection from one completion.
Alternatives for test
BP told the state in 2005 that the Badami restart operations were part of a “production exploration program” which was expected to take a maximum of three years, “or even shorter if the oil reservoir production results are not satisfactory.”
BP said it expected reservoir recovery to benefit from new recovery technologies. It told the state “there is a chance that it will become a good producer,” probably a good “intermittent producer,” with a chance the field could become a good “continuous producer.”
BP told the state this June that the company was developing plans to temporarily shut-in the field, probably in September, because of production decline. The shut-in would allow the reservoir to recharge.
“Previous work confirmed the highly compartmented nature of the Badami reservoir in which reservoir pressure slowly recharges during periods of no offtake,” BP said. Well pressure would be measured during the shut-in period “to monitor reservoir pressure recharge. The rate of reservoir recharge will be a key factor in determining the merit and timing of field restart.”