Thursday, May 26, 2011

Alaska's "National Treasure"

by Deborah Brollini

May 20, 2011, I had the pleasure of meeting Jon Voight at Middleway CafĂ©. I thought he looked like “Jon Voight,” and his response to me was “I am Jon Voight.” I thought to myself WOW. I visited with him briefly, and I left very star struck, and felt pretty darn special because he called me “sweetie.” My children humored me by watching National Treasure movies all weekend long, over and over and over again. The story lines of his movies remind me much of what I’ve been fighting for. The characters in the National Treasure movies were fighting for our past, and my friends and I are fighting for Alaska, and our children’s future.

This past legislative session was a brutal one, and a very bipolar one to say the least. One day would be filled with optimism that oil tax reform was moving forward, and then the next day we’d hit a barrier, which would then be followed by disappointment and tears. You wake up the next day, and you see wee ones walking and riding their bikes to school, and back to the trenches you go, because their futures are worth fighting for. Today their futures hang in the balance and we all must get up off the couch and fight for our children and our grandchildren’s future. If not, we will repeat history of Alaska’s economic crash of 1986. However, this imminent crash will be self-inflicted, and we will only have ourselves to blame.

You see I survived the Alaska economic crash of 1986. Therefore, I am hypersensitive to matters regarding our economy, and I foresee our economy going off a cliff in 2014. Even sooner if the Trans Alaska Pipeline (TAPS) experiences another shutdown as it did in January. Alaska was lucky that Alyeska was able to bring up TAPS in just a few days rather than weeks, or months. Another shutdown would be devastating to Alaska’s economy, and would pose life and safety issues for the citizens of Alaska. Especially, those in the interior where North Pole only has two weeks of fuel available if there was another TAPS shutdown. What’s it going to be Alaska?

I traveled to Juneau in February for the Alaska State Chamber of Commerce’s annual legislative fly-in. I decided to research the year Alaska’s economy crashed upon my return from Juneau. In 1986, Alaska’s economy crashed in 90 days. January 1, 1986 oil prices hit $20 dollars, and by April 1, 1986 our economy had totally crashed. It’s a fact, and it’s history, and it is up to Alaskans whether or not we want to repeat it. The difference between 2011, and 1986 is that we had lots of oil in our pipeline, and today we have Tom Barrett, President of Alyeska Pipeline Service Company begging for more oil to avoid another shut down. This is scary stuff folks, and I want you to remember that it is my friends and I that will continue the fight for Alaska with or without you. Much like the characters in the National Treasure movies did when the whole world was against them, because Alaska is future is worth fighting for.

Friday, May 13, 2011

Monday, May 9, 2011

Linc says LEA reservoir too tight; next well planned at Trading Bay

—Eric Lidji, Petroleum News

Linc Energy failed to identify a commercial deposit of natural gas with its first well in Alaska, but the Australian independent remains bullish about its opportunities in the state.

Linc tested three sandstone targets using its LEA No. 1 well in the Cook Inlet basin, but although the company found several gas-bearing coal seams, it decided the structure was “too tight” to produce without “swabbing” the well with large amounts of formation water.

“The conclusion from the testing is that although gas is trapped within the coal, there is not sufficient natural fracturing in the coal to allow for the recovery of commercial quantities of gas,” the company wrote in a statement on May 2.

LEA No. 1 was an onshore vertical well near Point MacKenzie.

Despite the disappointing news, Linc said the prospect is not lost. The well encountered a “significant” coal seam that “appears to be highly suitable for Underground Coal Gasification,” perhaps even enough to support future development in the region.

Underground Coal Gasification, or UCG, is a process of creating a synthesis gas from methane-rich coal deposits too deep to mine, and is Linc’s primary objective in Alaska.

Conventional gas to fund UCG

Shortly after arriving in the state in March 2010, Linc proposed a business model of using conventional natural gas production to help fund UCG development in the Cook Inlet.
That is still Linc’s strategy, despite the disappointing well results. The company said it is currently permitting a well at its Trading Bay leases on the west side of Cook Inlet.

Shell discovered natural gas in the area while looking for oil in the 1960s, but didn’t pursue development because of the low value of natural gas in the Cook Inlet at that time.

Although still refining its target, Linc plans to mobilize a rig “before December,” once the ground freezes up in the area, and plans to use existing roads from earlier exploration.

“I’m disappointed about the final result of LEA No. 1, but in the scheme of opportunity and activity that is currently ongoing within Linc Energy globally, LEA No. 1 represents only about 1 percent of the opportunities we are currently pursuing around the globe,” Linc Energy CEO Peter Bond said in a statement. “At the end of the day exploration is a numbers game, the more smart wells you drill the more likely you are going to be successful. Linc Energy has an extraordinary record of getting our exploration targets right the majority of the time and I still think the coal measures we’ve discovered via the LEA No. 1 program will add a lot of value to the Company in the longer term.”

Linc said the well established it as “a serious and prudent operator in one of the most challenging and closely regulated oil and gas provinces in the world,” and gave it “expertise to continue its Cook Inlet Basin exploration program at an aggressive pace.”

Coal work getting started

While Linc pursues additional conventional targets, it’s also ramping up its UCG work.
The company is making plans to explore the 181,414 acres it received in February from the Alaska Mental Health Land Trust through a seven-year UCG exploration license.

Linc plans to begin exploration “immediately,” by shooting seismic surveys this summer, followed by “drilling and core sampling of targets” to identify the best UGC targets.

Linc also said that it is applied for a coal exploration license on State of Alaska land near LEA No. 1, and is currently permitting the venture with the Department of Natural Resources.


Republished with the permission of the Petroleum News

Monday, May 2, 2011

Heavy oil starts; BP puts test horizontal well into operation in the Ugnu at Milne Point

Alan Bailey, Petroleum News

Following a lengthy delay after the completion of a $100 million heavy oil test facility on Alaska’s North Slope, BP has now put a heavy oil test well into operation — at 6 a.m. on April 22 a change in torque in the well’s down-hole pump finally signaled the flow of oil through the well, something of an historic event for the North Slope oil industry, Eric West, manager of BP’s Alaska renewal team, told Petroleum News April 27. For a couple of days the well had been producing brine, injected into the oil reservoir during the drilling of the well, but the torque change indicated that oil had finally reached the well bore, West said.

West said that since the morning of April 22 the well has been producing oil at a rate of 350 barrels per day and that the test facility had delivered more than 1,000 barrels of heavy oil to the Milne Point processing facility since the oil started flowing.

“But what pleases us so much is that there has been no upset to the well,” West said. “It has produced steadily at that rate.”

And the well is only producing small amounts of sand, with sand coming up the well in quantities ranging from trace amounts to about 2 percent by volume, he said.

BP is carrying out its testing of heavy oil production from the relatively shallow sands of the Ugnu formation, to ferret out the production characteristics of the resource, with an objective of determining whether commercial-scale heavy oil production on the North Slope will be feasible both from a technical and from an economic perspective, Erik Hulm, heavy oil appraisal team leader for BP Alaska, explained to the Alaska Geological Society on April 22. Companies have been producing heavy oil elsewhere, in Canada and Venezuela for example, but no one knows whether production will prove practical in the challenging Alaska Arctic environment, Hulm said.

But the potential prize is huge, he said.

Billions of barrels

Of the 70 billion or so barrels of oil so far discovered in the central North Slope, only about 40 billion barrels consist of conventional light oil that readily flows up a well bore and through a pipeline. The remaining 30 billion barrels are relatively viscous, thus requiring specialized production techniques, Hulm said.
Within the thicker grades of oil, BP distinguishes between what it calls viscous oil, with a consistency of syrup, and heavy oil, with a consistency of honey or molasses. On the North Slope, BP and ConocoPhillips have in recent years started to produce viscous oil from the sands of the Schrader Bluff/West Sak formation, using horizontal wells and waterflood techniques. But no one has yet attempted to tap into the estimated 12 billion to 18 billion barrels of heavy oil in the shallower Ugnu formation — heavy oil is generally too viscous to flow unaided through a pipe.

Being quite depleted in hydrogen relative to light oil and also being difficult to flow, heavy oil is less valuable than light oil. On the other hand, with high oil prices and with North Slope light oil production declining, companies are moving across the oil viscosity spectrum, seeking new commercial opportunities with more difficult resources. And, with BP hoping to use North Slope light oil to dilute the heavy oil for pipeline transportation, the company wants to see if it can achieve success in heavy oil production before light oil production rates decline to a point where it becomes impractical to ship the heavy oil to market — refining the heavy oil into a less viscous fluid on the North Slope for export by pipeline would be prohibitively expensive, Hulm said.

Two methods

For its test production, located on S pad in the Milne Point field, BP is using two techniques, both involving the pumping of oil into a heated tank at the surface, where sand is separated from the oil for disposal through the Prudhoe Bay grind-and-inject facility. The Ugnu sands, rather than being a conventional solid rock, are unconsolidated.
The first technique, called cold heavy oil production with sand, or CHOPS, involves drilling a vertical well through the Ugnu reservoir and then using what is called a progressive cavity pump, a down-hole pump with an augur-like rotor spinning at high speed, to draw the sand-oil mixture into the well and up the well bore. Small holes, known as wormholes, propagate from the well, out through the reservoir sand, increasing the exposed surface area of sand from which oil can be sucked and providing channels for the oil to flow into the well.

A rod passing down the well bore from the surface turns the pump’s rotor.

In 2008 BP successfully demonstrated the extraction of some oil from the Ugnu using a single CHOPS well, as a precursor to investing in the heavy oil test facility that it has since built.

The second technique involves the drilling of a horizontal well through the reservoir, with slots in the steel well liner creating a large area of contact with the reservoir, allowing oil to enter the well, as in a conventional oil field. A progressive cavity pump located downhole, in the area where the well bore steepens from the horizontal en route to the surface, will push the thick oil up the well. The pump will also draw down the pressure in the horizontal section of the well thus reducing the reservoir pressure — the drop in reservoir pressure should cause gas to effervesce from the oil and drive the oil towards the well, West explained.

Geologic investigation

Hulm explained that BP had arrived at the location and design of its heavy oil test after an exhaustive investigation of the geology of the Ugnu and an evaluation of various heavy oil production techniques.
Quite a lot of information about the Ugnu can be gleaned from the various wells that have passed through this formation en route to drilling targets in the established oil reservoirs deeper below the North Slope, Hulm said. Rock cores pulled from some of these wells provide evidence about the detailed nature of the Ugnu deposits, while well log data enable the extrapolation of rock information to wells from which well cores were not obtained. And seismic data provides a regional picture of the geometry and extent of the Ugnu formation.

Piecing together data from these various sources, geologists have determined that the Ugnu sands commonly fill what must have been meandering river channels within ancient river delta systems during the late Cretaceous and early Tertiary. The most promising looking oil reservoir units consist of multiple sand-filled river channels, stacked together to form large sand bodies in the subsurface.

The entire formation slopes west to east, lying about 2,000 feet below the surface on the western side of the central North Slope and being 5,000 feet deep to the east. Many geologic faults cut through the strata, breaking the reservoir into a multiplicity of compartments but also trapping oil in the sand bodies by juxtaposing the sand against more impervious rocks.

The heavy oil in the Ugnu has formed as a result of bacteria eating the originally formed light oil. And, with the bacteria becoming increasingly active at lower temperatures, the oil at the relatively cold, shallow western end of the Ugnu is heavier and thicker than the oil at the deeper and less cold eastern end, Hulm said.

Choice of technique

That variation in depth and oil type from one part of the Ugnu to another has a critical impact on the choice of technique used to extract oil from the Ugnu sands.
Hulm described a hierarchy of heavy oil extraction techniques, some of which have a multiyear track record of successful use and some of which are more hypothetical in nature. Methods that have seen success in some parts of the world can be broadly categorized as mining, hot extraction and cold extraction.

The direct mining of heavy oil deposits can be eliminated as a possibility for heavy oil production on the North Slope, in part because of the depth of the Ugnu sands and in part because of unacceptable environmental impacts, Hulm said. Hot extraction, typically involving the injection of steam into the underground sand to reduce the oil viscosity, has been used with success in Canada and is a possible candidate for North Slope use. Both CHOPS and the use of horizontal wells are examples of cold oil extraction techniques and both have track records of success in some places.

But the best technique to use in a particular situation depends on the particular combination of oil and rock properties that a would-be heavy oil producer is dealing with, Hulm said.

“It’s actually the rock and fluid properties that dictate which of these methods is going to work,” he said.

For its North Slope heavy oil production test, BP determined that cold techniques — CHOPS and horizontal wells — would be most appropriate. These techniques seemed suitable for the reservoir depths, sand qualities and oil viscosities within the North Slope units where BP is operator, Hulm explained. And the use of cold techniques would avoid some engineering challenges potentially associated with pumping hot steam through well pipes in the North Slope permafrost, he said.

However, it is likely that a hot, steam-driven technique would be more appropriate in the shallower and heavier oil deposits, more toward the western end of the Ugnu, he said.

Risk assessment

Using the results of its geologic analysis, BP developed a set of maps depicting the relative risks to successful cold heavy oil production at different places, using parameters such as the rock porosity, sand thickness and oil quality. The maps led BP to the selection of the Milne Point S-pad as a suitable test location. The location sits over stacked, Ugnu channel sands and is within reaching distance of several reservoir zones and a couple of faulted reservoir compartments, Hulm said.
And BP sees the possibility of 7 billion barrels of oil in place in reservoir areas earmarked as candidates for cold production. If cold extraction works the recovery factor would likely be around 10 percent, but could approach 20 percent, Hulm said.

As a proof of concept exercise, BP is trying out two horizontal wells and two CHOPS wells in an initial test phase, West said. It will take about a week to draw down the pressure in the horizontal well that has gone into production, after which the heavy oil team will monitor the well for a week before starting up the first CHOPS well, he said.

But extracting heavy oil from a reservoir below 2,000 feet of permafrost in the Arctic represents a move outside the envelope of industry experience of using cold heavy oil extraction techniques, Hulm said. And the production characteristics of the Ugnu reservoir and oil are unknown. Moreover, the use of surface-driven rods to spin the progressive cavity pumps at the bottoms of wells necessarily deviated far from the vertical in the North Slope’s drilling-footprint-conscious environment will present some particular technical challenges.

Depending on the test results, BP could determine that some other production technique is required, Hulm said. However, at some time in the future heavy oil production will hopefully deliver a substantial new resource to market and bring a new source of revenue to Alaska, he said.

Republished with permission from Petroleum News

Exxon’s Thomson warning; Permit delay ‘will directly impact’ start-up of Alaska North Slope gas project

Wesley Loy, For Petroleum News

ExxonMobil is suggesting its Point Thomson project on Alaska’s eastern North Slope might not make its projected start-up date due to further delays in securing a federal wetlands permit.

The U.S. Army Corps of Engineers, which is the lead agency reviewing ExxonMobil’s project, is now running a year behind on its original estimate for concluding an environmental impact statement and rendering a permit decision.

ExxonMobil had pledged to construct facilities and begin production from Point Thomson by year-end 2014. But that timeline now looks questionable.

“ExxonMobil can confirm that the revised schedule for the U.S. Army Corps of Engineers Record of Decision for the Point Thomson Project Environmental Impact Statement will directly impact timing of project site work and ultimately start-up,” company spokeswoman Margaret Ross said in an April 21 e-mail to Petroleum News.

Decision delayed to August 2012

This would appear to be the first time ExxonMobil has wavered on its target for first production from Point Thomson.
ExxonMobil is operator at Point Thomson, located along the Beaufort Sea coast just west of the Arctic National Wildlife Refuge. Other major stakeholders include BP, Chevron and ConocoPhillips.

ExxonMobil is planning a development to cycle natural gas and collect condensate from the high-pressure field.

The company is aiming to produce 10,000 barrels of condensate per day, sending it through a planned 22-mile pipeline that would link up with the existing Badami pipeline to the west. Ultimately, the liquid would go down the trans-Alaska oil pipeline.

ExxonMobil already has drilled two wells at Point Thomson for the project.

But before it can build a production base to process the gas and gather the condensate, it needs the wetlands permit from the Army Corps.

After receiving ExxonMobil’s permit application, the Corps began work on the EIS at the end of 2009. Originally, the Corps projected a record of decision in August 2011.

But a series of schedule extensions, the latest coming on April 19, has pushed out the decision date to August 2012, a full year beyond the original estimate.

The Corps has attributed the schedule slips to such factors as completing certain studies, weighing input on the EIS from other agencies, and considering ExxonMobil’s project design changes.

“ExxonMobil has worked collaboratively with the Corps to fully support the EIS process with timely submission of technical information,” the e-mail from ExxonMobil’s Ross said. “We will continue to work with the Corps, and the cooperating state and federal agencies, to seek EIS schedule improvement opportunities while maintaining the quality of the process.”

Important court date nears

Point Thomson is a hugely important but contentious issue for the state and industry.
The field is believed to be extremely rich in natural gas as well as petroleum liquids, and development of those resources would mean taxes and royalties for the state and good work for oil field contractors.

But Point Thomson has yet to produce anything, despite having been discovered more than three decades ago.

Tired of the slow progress toward development, the state in recent years has taken action to break up the Point Thomson unit and invalidate leases on the state acreage. ExxonMobil and the other oil companies are fighting to preserve the unit, and the matter currently stands before the Alaska Supreme Court.

Lawyers for the state and ExxonMobil have been trying to hammer out a settlement, which has kept the case on hold for several months. But the high court has signaled a limited appetite for waiting much longer, and has set a May 5 deadline for the two sides to either show a deal is near or get on with the proceedings.

Thus, we could learn much by that date on Point Thomson’s fate.

“ExxonMobil remains committed to finalizing settlement of Point Thomson Unit issues with the State and continuing with timely, cost effective and prudent resource development,” the company said.

Republished with permission from the Petroleum News