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The Explorers 2008: BP: Exploration through technology
Kristen Nelson Petroleum News
BP Exploration (Alaska) Inc. no longer drills wildcat wells on Alaska’s North Slope, but that doesn’t mean it isn’t risking dollars to expand production.
When BP said in July 2008 that it was going ahead with development at its Liberty field offshore the North Slope east of Prudhoe Bay and Endicott, with investment expected to approach $1.5 billion, Doug Suttles, president of BP Exploration (Alaska) called the development “an example of what I refer to as exploring through technology.”
Liberty is “no different than exploration,” he said. “Actually, the goal is the same: We’re expending financial resources, taking risks with it, to try to get new oil and gas out.”
Instead of taking the risk of finding oil, BP is taking the risk of developing technology needed to produce the oil.
BP knew the oil was there at Liberty but had to develop the technology to extract it including “drilling the longest wells ever drilled” using “the largest land rig ever built.” The Liberty wells will be drilled from the Endicott satellite drilling island and will extend out some six to eight miles.
To drill those wells requires extending drill-pipe technology by developing higher-strength drill pipe. To plot the path for the wells requires gathering seismic data along the lateral length of the wells, not just at the target formation, Suttles said.
BP expects to recover some 100 million barrels of oil from Liberty, with a peak production rate approaching 40,000 barrels per day.
Doubtful if on state land "The easy developments are done,” Suttles said, and industry is taking on the challenges of difficult projects like Liberty. It takes “more and more levels of sophistication to develop these tougher pools. And in effect this is where a company like BP really shines, because we have the capability ... and experience to go out and tap into these technologies.”
Suttles said that Liberty development is possible because the field is on federal land. “If this was on state lands it’s ... doubtful we’d have been able to move it forward, with the current tax rules.”
This is because the project has financial risk. Getting the six to eight mile wells into the reservoir is what makes Liberty work and “these are state-of-the-art wells. If they don’t get down, we will have spent a considerable amount of money, a billion dollars or more, and ended up with nothing,” Suttles said.
Because of the risk, there needs to be a financial reward for success: “You have to have some access to the upside.” But under Alaska’s current tax rules, “you’re denied the upside because the tax rate gets up around 80 percent,” he said, referring to the progressivity feature in ACES, Alaska’s Clear and Equitable Share, the new oil and gas production tax the Alaska Legislature passed in late 2007.
Because of the new tax, “you can just take less risk — it just collapses that zone which makes it attractive.”
And with easy developments gone and the “hard stuff” remaining, “how far you go depends on things like technology — but also depends on the environment you’re operating in and is it going to reward your investment? Because that’s what we have to do — we have to return a profit to our shareholders,” Suttles said.
Emphasis on technology Technology isn’t an issue only for new and difficult developments.
New technology was required to make North Slope development possible, Suttles said. “When the oil was discovered at Prudhoe Bay in 1968, no one had ever done an Arctic development before. And we had to develop the technology to do that.”
Technology continues to be important at existing North Slope fields, Gordon Pospisil, BP Exploration (Alaska) technology manager, told Petroleum News Sept. 11.
At Prudhoe Bay, the initial North Slope discovery and the largest field in North America, the initial expectation was that some 9.7 billion barrels could be recovered from Prudhoe Bay, Pospisil said.
To date some 11.5 billion barrels have been recovered from Prudhoe, he said, a recovery factor approaching 50 percent of the original oil in place. Total recovery from the field is now expected to be more than 13 billion barrels of oil.
These figures are for the original discovery at Prudhoe Bay, what is called the initial participating area. The Greater Prudhoe Bay area, including Prudhoe satellites and the Point McIntyre area, had produced more than 12.13 billion barrels through the end of 2006, according to figures from the Alaska Department of Natural Resources, Division of Oil and Gas’ 2007 annual report, the latest available. The report indicated almost 3 billion barrels of recoverable reserves remained at the end of 2006.
How do these recovery rates compare? In “Lower 48 U.S. reservoirs typically you recover about a third of the oil,” looking at average recovery rates, Pospisil said.
“And so with Prudhoe we see the potential ... with the activities and these technologies, to recover two-thirds of the original oil in place.”
Aggressive waterflood What technologies are used? Both water and gas are injected at Prudhoe Bay to increase production levels.
At Prudhoe more than a million barrels of water a day are injected, Pospisil said. Gas, more than 7 billion cubic feet a day, is re-injected into the gas cap at the field and the rich components of the gas are separated and used for miscible gas displacement within the waterflood EOR area.
Displacement is the key — oil must move to the well.
As BP continues to sidetrack wells at Prudhoe, closing off an original well bore and re-drilling out to a new target, a lot of sidetracks are done to expand waterflood and EOR, enhanced oil recovery.
Pospisil said teams are constantly looking at data on production and looking at models of the reservoir and coming up with areas to target. “We have more than 50 new penetrations per year just within the initial participating area; and we’ve been working over more than 50 wells per year to recomplete wells in order to continue with waterflood, gas cycling and gravity drainage performance,” he said, with drilling and well workover technology continually expanding.
Waterflood important Waterflood is an important part of the displacement process, Pospisil said, “and anything that we can do to make it more efficient is very valuable because of the size and scope of the Prudhoe Bay waterflood,” among the largest in the world. Although recovery is pushing 50 percent in the initial participating area at Prudhoe, “there’s still an opportunity to increase that.” It has to do, he said, with variations in the reservoir.
There are high-permeability zones, where oil flows readily, combined with lower-permeability zones in the same reservoir. “So the challenge is to try and have a very efficient displacement front, even though the reservoir quality varies.”
With maturing waterflood, what is called “thief zones” develop in high-permeability zones where “water will tend to channel down a well-established path,” bypassing oil and leaving it in the reservoir. “So by doing surveillance across the more than 200 patterns in Prudhoe Bay, we’re able to establish which patterns have good recovery and high efficiency and those that have relatively low recovery.”
Once those areas are identified, there is the opportunity to do something different, he said.
Changing the rock In the past there hasn’t been much that could be done to change the rock, the reservoir from which oil is produced.
“But with Bright Water we can actually modify the reservoir itself to better give up the oil to production,” Pospisil said.
Bright Water is a new product that BP developed in partnership with Nalco, a chemical company.
The first treatments were pumped in Alaska in 2004.
The goal “is to reduce the amount of water that’s cycling through these thief zones or high-permeability zones.” Pospisil said Bright Water is a polymer that is injected into the reservoir with the injection water stream and reacts with changes in temperature. It’s injected at relatively cool temperatures, he said, and as it warms up, “going deep into the reservoir, it expands to something on the order of 10 to 100 times its size.”
A particle that is very small in the injection water “follows the path of least resistance, following where the high water percentage is going and then as it warms up starts to expand and fill up the pore throats within the reservoir matrix and by doing that it effectively diverts the water behind it so that it better displaces the oil.”
Bright Water has been a “true breakthrough with technology,” Pospisil said.
The product was piloted at Prudhoe Bay and Milne Point in 2004. “We recognized success by 2006 and in the past two years have been expanding to begin treatment across the many patterns we’ve got.” The program is a phased one, with applications expanded each year. Pospisil said BP is also working with the other owners at the Kuparuk River unit, operated by ConocoPhillips Alaska, and this summer began pumping Bright Water treatments at Kuparuk.
There have been polymer injection treatments, well treatments, in the past, he said, but “this is the first where it’s been successful reservoir treatment as opposed to a well treatment application.”
Even in mature production areas where a lot of water has been cycled through, “we’re able to increase the oil rate in the offset producer. So we treat the injector (well) and in six to 12 months we actually see an increase in oil production rate and with that we’re able to improve the long-term recovery from each of the patterns.”
Low salinity water injection BP is also working with the type of water that is injected in waterflood operations.
“BP has long recognized that different injection waters result in different waterflood efficiencies and so we’ve been doing pioneering work within our North Slope operations to establish where we can modify the injection water to increase the waterflood recovery,” Pospisil said.
Seawater is readily available on the North Slope and is routinely used in waterflood. It typically has some 27,000 parts per million or just under 3 percent sodium chloride. It’s not the most efficient displacement water, he said.
By lowering the salinity of the water, you get higher recoveries in typical reservoirs, Pospisil said.
In research and development efforts over recent years BP has defined “as much as 20-30 percent increases in recovery by moving toward a lower salinity injection water,” he said.
The challenge is to come up with a way to modify the salinity of seawater. BP is looking at a reserve osmosis plant at Endicott “and we’re proceeding with a set of evaluations and steps to demonstrate that project.” BP operates waterfloods in more than 14 billion barrels of original oil in place, and “if you can think in terms of a few percentage points in incremental recovery it starts to translate to very large volumes of oil. So we see the potential for up to hundreds of millions of incremental barrels of oil with an efficient low-salinity displacement process.”
The Endicott test, from which results are expected next year, takes LoSal — BP’s trademark name for the process — beyond laboratory and single-well tests, Pospisil said, and will provide “a great first indication, from the reservoir itself, that you can do this on a broader scale.”
With success in this pilot BP would be able to move into a full-scale project at Endicott, “an expanded waterflood with low salinity displacement at Endicott” as well as a project in support of Liberty.
Pospisil said it’s part of the theme “of how we’re using our new technologies to improve recovery from our existing fields.”
Upcoming: CO2 With gas sales on the horizon, once a gas pipeline is built to take North Slope natural gas to market, BP is studying uses of carbon dioxide, which would need to be removed from Prudhoe gas before it entered the gas pipeline.
“The expectation is with major gas sales we’ll have a large supply of CO2 to use for enhanced oil recovery and of course ultimately for sequestration.”
The company’s goal is to be “very aggressive” in using CO2 for enhanced oil recovery in both light oil and viscous oil reservoirs, Pospisil said.
CO2 already comprises more than 20 percent of the miscible injectant in use at Prudhoe, he said. Ultimately, once gas sales begin, CO2 will also be sequestered because gas sales would produce more CO2 than could be used in injection.
If gas sales are 4 billion cubic feet a day, Pospisil said that means there’d be more than 400 million cubic feet a day of CO2 available for enhanced oil recovery.
There are more than 20 reservoirs, he said, and each is being studied to see if CO2 would be a good option for that reservoir, if pressure and efficient displacement could be achieved. It’s an exciting area for future technology applications, Pospisil said. “And CO2 is a very good miscible injectant; it’s very efficient in terms of its reservoir properties for displacing oil.”
CHOPS technology In addition to the original Prudhoe reservoir, with conventional or light oil, new technologies are being used for heavy and viscous oil recovery, although the heaviest and shallowest oil isn’t yet in commercial production.
BP is testing CHOPS, cold heavy oil production with sand, as a way to access some of the very large volume of heavy oil, “something on the order of 20 billion barrels within the BP existing acreage,” Pospisil said. This is a resource which is currently not being produced at all — CHOPS, with a few hundred barrels produced from a single test well, is experimental.
A team has been assembled and testing of wells has begun “that will with success demonstrate the ability to produce the heavy oil in Alaska and will allow us to access that resource ... just like an exploration program ... creating a new proven resource through successful qualification of the well and first surface facilities.”
BP spokesman Steve Rinehart told Petroleum News in late September that the first CHOPS well, at S pad in Milne Point, resulted in a successful initial production test. The test well brought sand and oil to the surface with a peak rate of about 120 barrels per day; some 700 barrels of the oil — with a consistency similar to chocolate syrup — had been mixed with conventional crude and shipped down the trans-Alaska oil pipeline by the end of the test in mid September.
“This was a success and we are going forward with the multi-well, multi-year program,” Rinehart said.
Wells a viscous challenge Another category of oil is viscous — oil deeper than the heavy oil being tested with CHOPS, but shallower, colder and heavier than Prudhoe Bay crude oil.
The challenge with viscous oil has “been to develop the types of wells and types of displacement processes that are effective in establishing economic rates,” Pospisil said.
The successes in the last few years have come from multilateral wells, which put more of the reservoir in contact with the well bore, he said.
When BP first drilled the viscous Schrader Bluff formation in the late 1990s it was with vertical wells which were hydraulically fractured and stimulated.
“In the early 2000 timeframe we began to drill horizontal wells and then soon after that in 2002, 2003, we moved into a program of multilaterals,” he said. BP recently completed a well with six sidetracks, a hexa-lateral.
Drilling horizontal wells was the first step.
Multilaterals allow BP to target the multiple layers that make up the reservoir from a single mother bore and then drill lateral sidetracks out into the layers, with sidetracks running laterally through the horizontal sections of the reservoir.
One of the original vertical viscous wells might have had 50 to 100 feet of section open to the reservoir, he said. The recently completed hexa-lateral well accessed more than 20,000 feet of reservoir through multilaterals, some more than a mile long.
In addition to reaching the different layers, Pospisil said with these wells BP has “the capability to actually manage the reservoir by opening and closing each of these laterals which is an important technology step.”
Multilateral wells are the result of collaboration in deciding what’s possible and then designing an approach to achieving that: Reservoir and petroleum engineers coming up with effective depletion mechanisms and drilling engineers and drilling contractors “coming up with sets of tools that can provide the options,” Pospisil said.
Improved seismic imaging
One technology that makes multilateral wells possible is improved seismic imaging. The improved imaging in today’s seismic, he said, makes it possible “to actually see the lenses and with that map them and that’s part of the design of the well.”
Acquisition of seismic with “much better resolution, much better data quality, has been an important part of being able to drill this type of well because we can again define the target that we’re trying to drill.”
More data is captured — analogous to increasing the pixels in photos, he said, so “just like in your camera imaging we’ve seen that resolution improve,” with improvements both in the acquisition and processing of seismic data.
“So we see faults and we see lenses,” Pospisil said.
And with four-dimensional seismic, images shot over time, “we’ve been able to process it in a way that we can actually see the saturations,” identifying the differences between gas, water and oil, and by repeating seismic acquisition “we can actually see the progress of the waterflood displacement front or the gas displacement front,” which allows drilling of wells which target the remaining oil saturation.
With improved seismic BP aims for a success rate of one out of two in rank exploration drilling, compared to a historic rate of success for exploration wells of about one in 10.
With development wells the expectation is that nine out of 10 wells will be successful.
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