Posted on 10/07/2008 5:22:11 AM PDT by thackney
BP Exploration (Alaska) Inc. achieved success in an initial test for production of heavy oil from the Ugnu formation at Milne Point S-Pad on Alaska’s North Slope, according to a company spokesman.
The test well succeeded in bringing sand and oil to the surface with a peak rate of about 120 barrels per day. By the end of the test Sept. 15, about 700 barrels of the oil with a consistency similar to chocolate syrup had been mixed with conventional crude produced at Milne Point and shipped down the trans-Alaska oil pipeline, BP’s Steve Rinehart told Petroleum News Sept. 30.
“The well brought oil and sand to the surface,” Rinehart said. “It did it reliably, sustainably.”
The oil has API gravity of about 10, he said. By comparison, conventional oil from the central North Slope typically has an API in the 20s, though light crude from the Alpine field has an API of 40.
“It was a welcome discovery that the reservoir itself appears very robust,” Rinehart said. That suggests that the Ugnu reservoir could sustain higher production rates, he said.
Downhole pump
The initial test was intended to determine whether a procedure called cold heavy oil production with sand, or CHOPS, could produce heavy oil at Milne Point. CHOPS involves using a downhole pump with an augur-like rotor to suck a mixture of sand and oil up the well, without applying any heat to the reservoir formation — the Ugnu sands that form the heavy oil reservoir lie 4,200 feet below the surface and are relatively unconsolidated. Once at the surface, the sand is separated from the oil by heating the mixture of sand and oil in a tank.
A novel feature of the pumping arrangement is that the electric drive motor is at the surface, connected to the downhole pump rotor by a long rotating rod that is passed down the well from a huge spool called a mobile gripper unit. Placing the drive motor in the well would cause the motor to overheat.
“The pump proved effective at pulling a lot of sand out of the formation,” Rinehart said.
In ramping up to the peak production rate, oil content in the oil/sand mixture flowing from the well varied from about 50 percent to 80 percent. Those production characteristics, together with the facility with which the pump drew sand from the formation, suggest that “wormholes” had formed in the sand reservoir, as BP had hoped, Rinehart said. And the sand settled out of the oil fairly easily in the production facilities at the surface, he said.
Next stage
Having completed the hurdle of this initial test — proof that sand with oil can be induced to flow continuously to the surface — BP plans to proceed to the next stage of its Milne Point heavy oil project. “This was a success and we are going forward with the multi-well, multi-year program,” Rinehart said.
For that test program, BP will build a permanent test facility by installing custom-built, truckable heavy oil production modules on the Milne Point pad during the coming winter; the initial test used standard oilfield equipment.
The planned multi-well tests will involve three new wells. Two of them wells will be CHOPS wells of the type used for the initial test, while the third well will be a horizontal well with a sand screen to prevent sand production. The purpose of the horizontal well will be to test heavy oil production using a technique that has already proved successful for producing viscous oil on the North Slope — viscous oil is lighter than heavy oil but not as light as conventional crude. BP wants to know how that viscous oil horizontal well production technique compares with the CHOPS technique when it comes to producing heavy oil.
“The goal here is to test a number of scenarios and a variety of equipment, so we can see what works best under what circumstances,” Rinehart said. The testing may take three to five years to complete, he said.
During the next phase of testing, BP also plans to re-complete the first CHOPS well, to test production from another reservoir zone, he said.
Economic viability
In addition to a technically feasible production method, the multi-year route to commercial heavy oil production will require proof of economic viability. Economic success will depend on overcoming the major challenges of maximizing heavy oil flow rates, while reducing production costs. For example, BP is considering using multilateral horizontal wells to improve flow rates, but no one yet knows whether the type of downhole pump used for CHOPS production will actually work in a horizontal well. Further, heavy oil is will not command as high a price per barrel as light oil even though today’s high oil prices provide a strong incentive for heavy oil production.
Successful heavy oil production at Milne Point could open the way to large-scale production of some of the estimated 20 billion barrels of heavy oil in place under the central North Slope. And BP is anxious try to move heavy oil into production while there is ample production of conventional, lighter oil from the North Slope. This will allow the heavy oil to be mixed with the light oil for transportation via the pipeline.
“There’s a big prize if we can find a way,” Rinehart said. “It’s an important part of our long-term strategy. … Heavy oil production enables other things to happen at Prudhoe Bay for a longer period of time.”
More information than listed in last weeks thread.
API 10° - Very heavy indeed
Most of Venezuela’s Crude Oil is already refined outside the US.
Also, even though the very heavy oil is a majority of Venezuela’s reserves, it is not a majority of their current production. The very heavy oil is relatively new discoveries and still not produced as much as their older fields.
10 API; That’s a man’s bbl.
Like a Dairy Queen Blizard,
You can turn the barrel upside down and not spill any.
10 API is the same weight per gallon as clean water.
Not only very heavy, but quite cold as well.
How does it fare in terms of usefulness as compared to "light" crude? Does the heavy stuff have a higher concentration of usable hydrocarbons? Less? The same? What causes this variety to weigh more?
To get products like gasoline or diesel from heavy crude typically requires more post distillation processing at the refinery with units like a catalytic cracker, a reformer or a coker.
Does the heavy stuff have a higher concentration of usable hydrocarbons? Less? The same?
It typically has more long string hydrocarbons than needs to be broken down in units like those described above to make hydrocarbons like octane, pentane, decane and many others.
What causes this variety to weigh more?
Longer string hydrocarbon molecules result in higher densities.
I work at a "Heavy Crude" refinery. I don't understand the entire process in detail, but the main piece of the refinery that allows the use of heavy crude is called the Coker. It separates out the petroleum from the Coke, which is something like hard, oil-impregnated coal.
Heavy Crude is cheaper than Light because it's more work to refine it.
The coke is loaded on rail cars and sold to power plants, etc..
References - Wikipedia: Coke (fuel), Wikipedia: Coker Unit, Wikipedia: Heavy Crude
Sometimes, but not always.
I found this article earlier you might find interesting.
“What causes heavy oil if they don’t have asphaltene or paraffin problems?”
http://www.cpchem.com/enu/docs_drilling/heavyoils.pdf
A coker is not really a separator. The distillation unit provides the separation. The coker takes residual oil for further processing.
It is more of a thermal cracker. But not all of the petroleum stream will be cracked. What is not cracked is the coke.
Refining, Downstream Processing
http://www.eia.doe.gov/pub/oil_gas/petroleum/analysis_publications/oil_market_basics/refining_text.htm#Downstream%20Processing
Petroleum Coke Glossary
http://www.petcokeconsulting.com/glossary/index.html
See coker, Delayed coker, Fluid Coker and Flexi coker
Not to be unnecessarily contrary, but from everything I have read about Ven. oil backs up Domangart. I am told that majority of Hugo’s oil is run through Citgo Corpus Christi plants because of its tar quality and that few other plants world-wide can process the majority of Venezuela crude.
Care to post info backing up different?
No problem, discussion is always good, data for information even better.
I am told that majority of Hugo’s oil is run through Citgo Corpus Christi plants
Venezuela produces 2.8 MMBPD of total petroleum, 2.5 MMBPD of that is crude oil.
Venezuela Energy Profile
http://tonto.eia.doe.gov/country/country_energy_data.cfm?fips=VE
The US was importing 1.4 MMBPD from Venezuela as shown above, but that includes products refined elsewhere. Actual Crude Oil Imports into the US have been running around 0.9 to 1.1 MMBPD lately.
Total U.S. Crude Oil Imports From Venezuela
http://tonto.eia.doe.gov/dnav/pet/hist/mcrimusve2m.htm
Most of their Crude Oil is either refined in Venezuela or the Caribbean. PSDVA owns refineries in several countries.
Home > International > Country Analysis Briefs > Venezuela > Oil
http://www.eia.doe.gov/emeu/cabs/Venezuela/Oil.html
Also, the crude oil we do import from Venezuela goes to many different states. If you follow the following link, you get a list of all petroleum imported into the US. Use the pulldown menus at the top of the columns. Limit the display to "CRUDE OIL" for "PROD_NAME" and "VENEZUELA" for "CNTRY_NAME". Then choose "Sort Ascending" for "PORT_CITY". You will find only ~13% of the Venezuelan crude we do import goes to Corpus Christi.
Company Level Imports Historical - 2007
http://www.eia.doe.gov/pub/oil_gas/petroleum/data_publications/company_level_imports/historical/2007/data/impa07d.xls
Yes. Almost like Bitumen.
Are they actually drilling through a sandstone like rock or is this a solidified suspension of sand in the Hydrocarbon? Is there any resevoir pressure in these types of formations and do they need a cap rock ?
I thought I read somewhere that there was ~800 psi in the formation but I haven’t found that again.
This article talkes about the rotating augur screw “pump” causing a pressure drawdown or drop of around 1,000 pounds per square inch or more at the bottom of the well. So I assume the pressure is well above that.
http://www.petroleumnews.com/pnads/412230.shtml
This one talks about layers of shale with the sand in between them. I haven’t found a lot of other information, yet.
http://www.petroleumnews.com/pnads/656412759.shtml
Other geological information you may be interested in might be found at USGS.gov
This talks about the general area and gives some information about the plays, but is not specific to this particular formation.
U.S. Geological Survey 2005 Oil and Gas Resource
Assessment of the Central North Slope, Alaska:
Play Maps and Results
http://pubs.usgs.gov/of/2005/1182/2005-1182.pdf
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