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Viscous oil could be big plus
for North Slope production Most of 15 billion barrels not producible today; horizontal wells allow production of deeper oil; successful EOR could expand what can be developed to 1-2 billion barrels Kristen Nelson PNA Editor-in-Chief
As production declines from maturing Alaska North Slope fields, per-barrel production costs rise, economically hampering further development efforts.
Natural gas, known satellites and in-fill drilling opportunities at existing fields all add to reserves, resetting the clock on that production decline, BP Exploration (Alaska) Inc.’s David Jenkins told the Alaska Support Industry Alliance May 9.
If technical and cost challenges can be met, help can also come from production of some of the 15 billion barrels of viscous oil on the North Slope, said Jenkins, who is BP’s viscous oil team leader at the Milne Point field.
New approaches and new technology are already bringing more viscous oil into production, with a new pad, S pad, pipelines and road under construction at Milne Point to develop some 55 million barrels of viscous.
Developing the shallow crude at Milne Point, which BP acquired from Conoco in 1994, has been a challenge, Jenkins said.
Prudhoe oil with light ends stripped out Two lessons have been learned about viscous oil development on the North Slope over the last decade, Jenkins said: viscous oil has to be approached differently than conventional oil and what can be developed now is only the deeper, warmer, more fluid portion of the 15 billion barrel accumulation.
Most of the viscous oil footprint on the North Slope, called West Sak in the west and Schrader Bluff in the east, lies west of Prudhoe Bay field and overlies the Kuparuk River and Milne Point fields.
The viscous accumulation “is probably broken up into hundreds of individual pools and layers of oil that have to b e collected separately,” Jenkins said.
At Milne Point, the viscous oil is about 4,000 feet subsea, some 2,000 feet deeper than the permafrost, and fairly cold, about 80 degrees Fahrenheit.
The viscous oil is “really the same oil deposits as what we find in Prudhoe Bay, but the problem is because these oil deposits have been trapped up in these shallow sands, we’re at a depth where biologic activity exists and the bugs have basically been eating away the light ends of these oils for many, many, many years. And so what we have left there are kind of the heavier components,” Jenkins said.
That is one reason the North Slope accumulation is called viscous, distinguishing it from the heavy oils in Canada, some parts of the Lower 48 and Venezuela.
“This really is just the same stuff as Prudhoe, but with the light ends stripped out, making it a lot thicker, a lot harder to produce,” Jenkins said. Not conventional oil development In a typical oil field, Jenkins said, a find is made and development plans are laid, based on the size of the accumulation and the reservoir mechanism that will drive production.
“And a very common one up on the North Slope is water flood. And from a typical water flood we’ll get averages around the world, you might expect a 50 percent recovery of the original oil in place if it’s a pretty decent solid water flood,” he said.
Producing a field with water flood requires both producing wells and injection wells and facilities to handle the fluids.
With the general size known, a decision is made on how fast the field should be produced — what the plateau oil production rate will be. Given the production rate of wells, a decision is then made on how many well will be required initially to reach that plateau production rate and how many wells will have to be drilled over the years to keep up the production rate until field decline begins.
A lot of time will be spent optimizing development and assessing the economics of the development, Jenkins said, “and once you think you’ve got it pretty well solved, then you actually go ask for money, get permission to do it and off you go.” But viscous isn’t typical Conoco, although it focused on Kuparuk oil, made an effort to develop the field’s shallower reserves.
“Having the shallow viscous oil overlying every well penetration that they drilled was really an intriguing target, because the volumes are fairly large,” Jenkins said.
Conoco put in pads and drilled wells targeting the Schrader Bluff formation but they found the viscous, thick oils didn’t flow very well. And, because the formation is shallow, the formation isn’t as solid as it is at greater depth, so it produces sand into the wells, “which means then you have to put in extra equipment … to try and hold the sand back and that costs you extra money.
“And it’s kind of a double whammy, because at the same time you put that sand control equipment in to hold the sand back, it also has a tendency to plug up a bit and hold the oil back.” Viscous oil is going to flow at maybe a fifth the rate of conventional oil to begin with, Jenkins said, and the sand control equipment further reduces the rate of flow.
And the wells cost more to begin with because of the extra equipment to control the sand.
Conoco decided, Jenkins said, that they couldn’t develop the Schrader Bluff accumulation at Milne Point because it just wasn’t economic. BP bought Milne for Kuparuk accumulation When BP bought Milne Point in 1994, it was for the deeper Kuparuk River accumulation, Jenkins said: “We didn’t put much value in the Schrader Bluff sands.”
But the accumulation was there, and it was too big to ignore, and BP has been plugging away at the problem over the years, trying to see what technology could do, he said.
BP looked at different ways of completing the wells to deal with the sand production problem and at trying to drill as efficiently as possible.
And BP came up with a plan to develop Milne Point viscous oil, but it was a plan based on typical oil field development, Jenkins said. That plan included five new pads, 75 miles of new pipeline and 10 miles of new road and had a price tag of $1 billion.
“But when we got to that place of assessing our economics, we just couldn’t make it work. It was going to cost over a billion dollars to produce and was going to have about 500 wells — we just couldn’t make it economic,” Jenkins said. Focus on the accumulation BP stepped back, he said, and took a look at the whole viscous oil footprint, looking for the best place to develop it, how many wells and what will the plateau rate would be.
There are some 15 billion barrels of viscous, but it isn’t all the same. As you move east, the accumulation gets deeper.
“And the association we have with the deeper you get, typically the lighter the oils get, the less viscous they get, the hotter things get, so they actually flow better” and the oil is better quality, Jenkins said.
The deepest part of the Schrader Bluff accumulation is more like conventional oil — the bugs have eaten less of it — and the API gravity is higher, some 20 degrees or more in the deeper portions of the accumulation compared to 16 degrees API or less in the shallower portions.
To the west the accumulation is shallower and the oil is more viscous, colder — it’s closer to the permafrost layer — and the formation is looser and produces more sand.
This shallower portion of the accumulation represents “the vast portion of the deposit,” Jenkins said. “We just don’t actually understand how you would ever develop it.”
Jenkins showed the viscous oil accumulation on a map divided into three zones: green, for the deeper oil, easier to produce; yellow, with a moderate risk of economic success; and red, the high-risk areas. “And you see the vast portion of this deposit is what we’re considering the red zone,” he said.
In addition to grading in quality, the viscous oil accumulation is broken up into sections “and each of these sections are all independent from each other. They have different oil-water contacts. Some of them even at similar depths have different API gravities.” Sand control compounds problems In addition to grading the accumulation, BP also reviewed the different techniques that had been tried from 1991 to 1997, from putting screens into vertical wells linking different thin sands to trying to control the sand with hydraulic fracturing, proppant and resin to hold the sand back, but unfortunately the techniques didn’t work.
But holding back the sand produced with viscous oil drove up costs and drove down productivity, Jenkins said.
“And part of that problem is the need for artificial lift,” Jenkins said. You need to suck viscous oil out of the ground. Artificial lift was provided with electrical submersible pumps means “lots of moving parts, fairly expensive to replace and as you can guess, with lots of spinning parts down hole, not very tolerant to producing sand.” Counterintuitive solution In 1997, Jenkins said, “some very bright people at Milne Point” decided that instead of putting in sand screens for long horizontal holes, to try just pipe in the hole — pipe that wasn’t cemented and had one-inch perforations and no sand control at all. The I-6, he said, was “one of the best wells they drilled in the 1997-1998 timeframe.”
The sand control equipment wasn’t working and the pumps were failing, Jenkins said. It turned out that with vertical wells and producing formations averaging 20 feet thick and pumps to move the viscous oil “the drag forces on the sand grains with viscous oil become very, very high” pulling sand into the well bore.
But with a long horizontal section, thousands of feet in length, “you actually then can reduce the rate at which oil is entering your well bore at any one particular place, which reduces the drag forces that are trying to strip all this sand into the well bore and low and behold you don’t get nearly as much sand as you thought you’d get. And at the same time, you actually begin maximizing rates.” No screens in the hole Because you don’t have screens in the hole — screens which plug up and reduce productivity — “productivity in these wells increases over time as you continue to produce trace amounts of sand, create little wormholes back into the reservoir, little super highways for oil,” Jenkins said.
That solution — long horizontal wells and no sand control — has changed the production level from Schrader Bluff sands from wells averaging 300 barrels a day to wells averaging 1,200 barrels a day.
After the success of the long horizontal well with no sand control, Jenkins said, a shift began in thinking about viscous oil development. The company recognized that because the oil quality grows worse as the accumulation grows shallower, it probably wouldn’t be possible to develop all of the accumulation. The focus shifted from developing everything to developing some chunks of it — and identifying the technology it would take to develop each chunk.
Some economic parameters were also recognized, he said: that production per well would have to be at least tripled over the 300 barrels per day earlier wells had achieved; that operating costs for the wells would have to be reduced; that ending sand control in the wells meant a different kind of pump would be required.
Part 2, which will appear in the May 26 issue of PNA, includes the use of jet pumps in viscous wells, reduction of viscous drilling costs, development of S pad, what enhanced oil recovery could do for viscous production and where viscous oil fits in overall North Slope production.
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