Much more to goUpping recoverable reserves at Prudhoe Bay requires high-tech solutions Alan Bailey Petroleum News
With an estimated 22 billion barrels of oil in place at the start of production in 1977, Prudhoe Bay on Alaska’s North Slope is one of the world’s largest oil fields.
The cumulative production of the field’s originally estimated volume of 9.6 billion barrels of oil reserves — the volume that engineers thought could realistically be drawn from the field reservoir — was reached in 1998. And today the field continues to dominate North Slope oil production and underpin Alaska’s economy, as engineers, geoscientists and drillers figure out ever more ingenious ways of teasing more oil from the field’s underground reservoirs.
“It’s all about additional (oil) recovery through the use of technology and continued investment in the field,” Scott Digert, BP’s Alaska subsurface manager, told Petroleum News in a July 18 interview.
Cumulative production from the field passed the 12 billion barrel mark in 2012 and production is still going strong, Digert said. However, techniques such as high-tech horizontal drilling, used to exploit ever more resources in the field, are also expensive to implement, upping the cost of bringing new barrels on line, he commented.
Massive reservoir The main Prudhoe Bay oil reservoir occupies an area of about 254 square miles and lies in the 450-foot-thick Permo-Triassic Ivishak formation, an assemblage of sandstone, shale and coarse pebbly rocks called conglomerates, laid down in an ancient river and river delta system. A much thinner reservoir, a 35-foot shallow marine sandstone known as the Sag River formation, lies about 100 feet above the main reservoir.
At the time of its discovery, the field contained a huge cap of natural gas trapped at the top of the gently sloping reservoir rock formation. Below the gas cap lay an equally huge oil pool. A thin layer of tar and heavy oil marked the base of the oil, separating and largely sealing the oil from water in the rock below.
From the outset of oil production in 1977, pressure in the gas cap drove production of oil from the section of the oil pool directly below and in pressure communication with that cap, with gravity assisting the process by causing oil to flow down the reservoir slope into production wells. Gas produced along with the oil was injected back into the gas cap to maintain reservoir pressure. Farther down the slope of the reservoir, where the oil was not in direct contact with the expanding gas, water has been injected into the reservoir to support reservoir pressure and to drive oil into production wells in a process known as waterflood. The massive quantities of water required for this operation have come from water produced along with the oil and from a seawater plant on the neighboring Beaufort Sea coast.
These two production schemes led people to distinguish two major field areas: the “gravity drainage” area of the field, underlying the gas cap, and the waterflood areas. But, with gas pressure in the gas cap progressively declining as oil and gas in the field were produced, in 2002 BP started to inject water into the gas cap to stem the pressure decline.
Continuing strategy The overall approach to oil production at Prudhoe Bay continues these two essential strategies: gas cycling supplemented by water injection in the gravity drainage area and waterflood elsewhere, Digert explained. However, with the field now very mature as less and less oil remains in the reservoir, BP has had to find new ways of accessing that oil, he said.
And to evaluate development decisions, such as overall changes in water injection or the possibility of a new drilling program, BP uses a computer model that simulates the workings of the field reservoir. This model is one of the largest and most sophisticated reservoir simulators used anywhere in the world, Digert said.
Thin oil layer The main challenge in the gravity drainage area, the source of much of the current Prudhoe Bay production, is the fact that the remaining oil now forms a relatively thin layer within the rock, Digert said. Rather than driving simple production wells down through the reservoir, drillers now “sidetrack” new wells out at relatively shallow angles from old well bores, using modern seismic images to target areas of the reservoir where oil can still be found. Many of these new wells use technology called coiled tubing drilling, threading continuous lengths of small-diameter, flexible drill pipe through the thin oil column.
And, while the “sharpening” of seismic images through the use of ever improving seismic processing enables the identification of ever thinner drilling targets, the drilling itself has become increasingly precise.
“Today we can place a well fairly accurately within 10 vertical feet,” Digert said.
Originally drillers would not attempt to drill into an oil column less than 100 feet thick. Over time, that limit went down to 50 feet, then 30 feet and now it can be possible to access an oil layer just 15 to 18 feet thick, Digert said.
“We are working to continue to sharpen that pencil, so we can get down to 12 feet and 10 feet,” he said. “That’s where our future is.”
In many places the drillers now skim wells along the top of the tar layer at the base of the oil column, with some relatively heavy oil at the top of the tar being produced along with the typical light oil of the reservoir, Digert said.
Steering a well With the wells needing to be steered through subsurface layers too thin to be resolved from seismic data, the drilling team relies on downhole well logging and the continuous examination of rock cuttings from the well to track the subsurface location of the drill bit. This type of well steering is as much an art as a science, depending on very high levels of expertise and experience, Digert said.
One challenge in accessing a thin oil column under a pressurized gas cap is the tendency for the gas above the oil to “cone” down into a production well, thus disrupting oil production. This problem leads to the periodic stopping and starting of production from individual wells and the eventual relocation of a well by the drilling of another sidetrack, Digert explained.
Pockets of oil In the waterflood areas of the field the main challenge now is to find and develop pockets of oil left behind by earlier waterflood operations, and to scrub as much oil as possible from the pores of the reservoir rock. During waterflood the water passing through the reservoir tends to take the line of least resistance, pushing oil from relatively permeable rock and leaving behind oil in areas where the water can flow less readily. And in any part of the field, faulting of the rock strata can create isolated pieces of reservoir sand holding oil that has become stranded from production.
Using seismic images of the subsurface to identify drilling targets and then using sophisticated drilling techniques to access those targets, it has become possible to develop stranded pockets of oil that years ago would have been left in the ground.
Miscible injectant And the originally simple waterflood operations have morphed into more sophisticated techniques involving the use of a material known as miscible injectant, a mixture of natural gas and natural gas liquids such as butane and propane produced from the field — miscible injectant operates as a solvent, drawing oil from the rock pores and then carrying that dissolved oil into production wells.
A technique called “water alternating gas,” involving the waterflooding of a section of the reservoir alternating with the use of slugs of miscible injectant to flush out remaining oil, has become a standard approach in the waterflood areas. But in some places, depending on the subsurface geology, the water and injectant can tend to part company, with the water flowing under an oil body and the miscible injectant gas floating above, Digert said. This type of situation requires the use of another technique called “miscible injectant side track,” or MIST, to drive out that remaining chunk of oil. A MIST operation involves the drilling of a special sidetrack injector well that loops around an existing injector well low in the reservoir. Bulbs of miscible injectant released from the MIST well float upwards through the reservoir sand, carrying with them oil from the target oil body, Digert said.
Bright Water A trademarked technique called “Bright Water” has also proved useful in moving additional oil out of waterflood areas. Bright Water involves adding particles of a temperature sensitive polymer to water used to flood the reservoir. As the water takes its line of least resistance through more permeable channels in the reservoir, the particles expand, blocking the channels and causing the water to flow through less easily penetrated sections of rock where residual oil still lurks.
A particular challenge arises in the regions of the field where the gravity drainage area transitions into waterflood areas. In these regions gas from the gas cap can flow underneath layers of shale within the reservoir, leaving pockets of oil on top of some of the larger shale bodies. BP has been adding injection wells to push this stranded oil off the shale using injected water and sometimes miscible injectant, Digert said.
Well work In parallel with development work using new wells, existing wells have to be kept in good working order. That necessitates an extensive program of well workovers. BP hopes to expand its total well work program by almost 50 percent in 2014, Digert said. BP has said that plans for expanded well work in the field are linked to recent production tax changes. According to BP’s most recent Prudhoe Bay progress report, the company performed about 1,700 well-work jobs in 2012, with 250 of those jobs resulting in increased production.
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