Legacy oilfield reinvestment: producers getting every obtainable drop.
People have been asking this question for years, but there's no clear answer. Oil is considered a nonrenewable resource, which leads to the idea that it will eventually be depleted.
Sounds logical, but the earth's endowment of hydrocarbons and other minerals appears much more ample than previously believed, and when deposits of oil and gas, or minerals, are discovered, improved technology almost always leads to more of the resource being extracted than originally estimated.
When the North Slope oilfields started up in 1977, the common assumption is that they would be drained by 1999, with the Trans Alaska Pipeline System (TAPS) shut down. That didn't happen. Instead, the large "legacy" fields of the slope, which are the economic anchors for critical infrastructure like the pipeline, are still going strong thirty-eight years later, and new fields are even being found.
The same is happening in Cook Inlet, fields that date from the late 1950s and early 1960s.
Like anything else, how long oilfields will last depends on circumstances like the size and quality of the oil reservoir in question, the price of oil and the cost of producing oil in the field (which will vary over time), taxes of course, and finally, the aggressiveness of the owner in pursuing redevelopment, enhanced oil recovery, or other strategies aimed at coaxing more oil out of the rocks.
Typically, oilfields have a "flush" early stage where production peaks, or in the case of most producing reservoirs, plateaus at a steady rate. Decline then sets in, and companies employ a variety of technologies to minimize the decline as much as possible. In their late stages of life field production typically tapers off to a low, but actually fairly stable rate, with a decline curve that is much more modest.
Again, industry has become very inventive in finding ways to coax more oil out of the rocks, extending the life of even aged fields. New ideas and a fresh approach count for a lot, too. In their older stages of life oilfields are sometimes sold to companies with fresh ideas of how to rejuvenate them. This has happened in Cook Inlet and is now happening on the slope.
Alaska has notable examples of oilfields that are producing well beyond their expected economic lives and some where production has even been increased by a new operator with fresh ideas.
Two examples of this are in Cook Inlet, where Hilcorp Energy, a Houston-based major independent company that entered Alaska in 2012, has invested and reworked two aged fields in the Inlet basin, one being offshore at Trading Bay, which is served by the Monopod platform, and a second with the small onshore Swanson River field, on the Kenai Peninsula.
Swanson River was the first modern-era commercial oil discovery in Alaska, made in 1957 by Richfield Oil. The discovery confirmed Alaska's resource potential, enough to convince a doubtful Congress that Alaska, then a territory, could financially support itself as a state.
Through an aggressive program of well improvements and new drilling, Hilcorp has increased production in both fields after taking ownership from Chevron Corporation in 2012. Trading Bay is an example. The field produced thirty thousand barrels per day when it was first developed in the 1960s, but its output had dwindled to about six hundred to seven hundred barrels per day when Hilcorp purchased it in 2012 (the economic limit of the platform was estimated at three hundred to four hundred barrels per day).
Hilcorp invested about $73 million in Trading Bay between 2012 and 2014, and the field is now producing about fifteen hundred barrels per day.
Alaska's most dramatic example of an oilfield pushed far beyond its preconceived limits is on the North Slope, where oil recovery in the large Prudhoe Bay field was originally estimated to be 9.6 billion barrels. The field has now produced over 12 billion barrels since it started up in 1977, and its ultimate recovery is almost certain to reach 13 billion barrels and possibly more.
Thirty-eight years after its production started, Prudhoe is still the nation's largest oilfield. However, the Kuparuk River field on the slope, second largest in Alaska and also in the nation, is also a maturing field that has been pushed well beyond its original estimate. Kuparuk started production in 1981, four years after Prudhoe Bay.
Prudhoe Bay is important because it is still the largest oilfield on the slope and is still the "anchor" producer that keeps TAPS economically viable. Without Kuparuk it is doubtful that the other oilfields on the slope would be able to produce enough oil to keeps TAPS operating, at least in the near term until there is a large supply of oil coming from the federal Outer Continental Shelf or some other source, which will take years.
Why is the recovery of oil from an underground reservoir so difficult to predict? First, although oil reservoirs are sometimes called "pools," they don't exist as a pool, as in an underground cavern that acts like a big oil tank. Instead, the oil is saturated in porous rock like sandstone or limestone where the oil lies in microscopic pores in the rock. The pore must be connected by tiny channels, too, which allows the oil to move (or natural gas, for that matter, which exists in liquid form under pressure in the rock) through the rock to a nearby well.
The reservoir does exist as a kind of "trap" however in that the oil typically migrates upward from some deeper source, often from hydrocarbon-rich shale rocks where the oil formed, to accumulate, becoming trapped, in the porous sandstone or limestone rock formation. This requires a "cap rock," or an impervious rock layer that becomes a seal over the reservoir. This reservoir is thus capped and becomes a kind of tank. But if there is no cap rock the oil seeps out of the reservoir rock and is diffused upward through other rocks, sometimes even reaching the surface as an oil seep.
There are countless, and even famous, examples of oil explorers and geologists finding all the right conditions for an oilfield only to discover, when the exploration well drill bit finally reaches the reservoir, that the oil was drained away due to a hole in the cap rock. The most dramatic case of this was "Mukluk," a very expensive well drilled by Sohio Petroleum (now BP) in 1981 in Harrison Bay off the Colville River delta of the North Slope. All the right geologic conditions were there for a giant oil discovery, and indeed the oil had once been in the Mukluk formation, Sohio found. But it had long since escaped due to a hole in the cap which Sohio's geologists missed in their research.
Even where the right conditions occur and an oilfield is successfully found and tapped, it's impossible to capture all of the oil locked in the rock. A typical recovery is 40 percent, which was estimated originally at Prudhoe Bay, where the "oil in place" in the rock totals about 23 billion barrels. BP, the Prudhoe Bay field operator, has steadily improved the ultimate recovery, however, and it may wind up being 60 percent, which is outstanding performance for an oilfield.
Recovery Boosting Tools
There are several tools typically used in boosting recovery in an oilfield. Which ones are used, and the sequence in which they are used, depends on the technical characteristics of the reservoir and, as always, the economics--whether a particular project undertaken to boost production pays for itself and makes a profit. In a maturing field the operating company always looks at these discrete projects on their own, even new drilling.
When an oilfield is first tapped it often produces oil up the wells through its own energy of natural gas dissolved in the oil. Also, many oil accumulations sit atop layers of underground water, which are also under pressure. As the oil deposit is produced through wells, and the oil reservoir pressure drops, the water layer rises. Since oil and water don't mix, the water becomes another force pushing the oil up the wells. Both of these natural "drives" are present in Cook Inlet and many North Slope fields.
When natural forces begin to dissipate, and usually before (operating companies want to get ahead of the game), the first step most field operators take is to inject water from the surface ("water-flood" in industry jargon) to supplement the natural water force in the reservoir. This was done at Prudhoe Bay in the mid-1980s, soon after the field started.
Having a source of water is important, and in the case of the North Slope, sea water was, and still is, taken from the nearby Beaufort Sea. It must be treated before being injected, which adds some costs. Some of the water occurring in the reservoir also winds up being produced up the producing wells with crude oil and must be separated at the surface. This is often injected back underground to supplement the natural water drive.
In many fields there is also a freestanding "gas cap" or deposit of pressurized natural gas that overlies the oil deposit. If there is no market for the natural gas, which is now the case on the North Slope (a pipeline is planned but not yet built), the gas cap becomes a source of energy to produce oil. As the oil is produced the pressure in the oil reservoir drops and the pressurized gas from above expands and helps drive more oil into the producing wells, just like the water rising from below.
The gas cap can be repressured with gas injected from the surface, also. Using Prudhoe Bay as an example, gas that is produced with the crude oil in wells must be separated from the oil at the surface. Since there is no gas pipeline yet and state laws will not allow the gas to be flared, or burned, the operators inject the gas back underground to repressurize the field and produce more oil. This has been going on for years at Prudhoe and the field operators have added several billion barrels of additional oil recovery by reinforcing the reservoir pressure with gas injection.
There are many other production enhancement tools--"Enhanced Oil Recovery," or EOR in industry jargon--that can be used to prolong the economic lives of fields. When the field is very large, such as the case with Prudhoe Bay, the potential gain with a new, innovative, or even exotic EOR technique is worth the investment. Prudhoe Bay had about 24 billion barrels of oil in place (locked in the reservoir) when production started in 1977 and about 12 billion barrels have been produced so far, leaving a huge prize--another 12 billion barrels--for new technology to squeeze out more oil.
BP, the field operator, believes that 13 billion barrels, perhaps 14 billion barrels, might eventually be produced, but getting another 1 percent equals 240 million barrels, the equivalent of a major oil discovery if it were in a separate field.
Because of these financial incentives, Prudhoe has become a kind of laboratory for EOR. One technique developed early on is injecting a mixture of natural gas liquids, called "miscible injectant," or MI in industry shorthand, into the rocks to help lubricate the oil movement through the pores.
When this is combined with waterflood, in pushing the oil through the rocks, it becomes a very effective tool. The use of MI combined with waterflood has resulted in several hundred million barrels of additional oil recovery, BP says.
Another innovation in EOR is "Bright Water," a proprietary technique developed by BP in its corporate laboratories, which involves a chemical, a polymer, that when injected into the rocks swells up and blocks the pore spaces at critical points where waterflood has been underperforming. That forces the waterflood into alternative paths where there are small deposits of oil bypassed earlier.
Bright Water has been used by BP in several North Slope fields and is also being used worldwide by BP, an example of a technology developed and tested on the North Slope and then used elsewhere as well as in Alaska. Sometimes there are techniques developed and tested here but not used, for various reasons, and then used successfully elsewhere. One example, again by BP, is "Low-Sal:" or injection of low-salinity (fresh) water in water injection, in lieu of the briny water typically used in water injection (the fresh water can be more effective in flushing out the oil). The cost of obtaining fresh water on the slope has inhibited Low-Sal here, although it proved very effective in tests at the Endicott field.
Innovation and Strategy
Another innovation that has worked well at Prudhoe Bay, however, is the injection of water from the surface directly into the large gas "cap" that overlies the reservoir. This has not been done previously, at least on the scale that it was implemented at Prudhoe. While most waterflood is done from below the oil, pushing it up into producing wells, or from the sides, pushing the oil laterally, the gas-cap water injection is done from above. Its purpose is to repressurize the gas, making it more effective in pushing oil down into the wells.
A lot of study was done on this idea before it was implemented, both by BP and other Prudhoe Bay owners and the Alaska Oil and Gas Conservation Commission, the state agency that regulates oilfield practices. The commission is charged with, among other things, maximizing total recovery of oil and gas from producing fields and must approve the development plans of companies to ensure that this happens.
The risk was that the water being injected would break through the gas, developing channels through the rocks that reduce its effectiveness, and even damage the gas cap as a mechanism to drive out the oil. This hasn't happened, at least to any large extent. The project has been a great success in improving recovery.
A fundamental strategy in getting more oil out of the rocks is in drilling more wells and different kinds of wells. For example, horizontal drilling of production wells, to tap very thin layers of oil in the reservoir, was done at Prudhoe Bay in a way not done elsewhere. "Multi-lateral" wells were also developed by ConocoPhillips and BP for the North Slope oilfields. These are wells where several separate producing "legs" are drilled underground off a single well to the surface. "Sidetracks," or new wells underground, and now commonly drilled of older wells. These wells, which can be drilled with great accuracy to their designated endpoint, have allowed the companies to tap small pockets of oil bypassed earlier with conventional wells.
The credit for all of these innovations must be shared among all the owner companies, but mainly BP, ConocoPhillips, and ExxonMobil, which share their considerable technical expertise in developing and implementing innovations like multilateral wells and gas-cap water injection.
Alaska's fortune is not only in having such a large fields like Prudhoe to economically anchor the North Slope infrastructure, but in having the field as a laboratory for intensive field development and enhanced oil recovery, the learning from which is being applied to Alaska's other oilfields and even worldwide.
Mike Bradner is publisher of the Alaska Economic Report and Alaska Legislative Digest.
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|Title Annotation:||OIL & GAS|
|Comment:||Legacy oilfield reinvestment: producers getting every obtainable drop.(OIL & GAS)|
|Publication:||Alaska Business Monthly|
|Date:||Jul 1, 2015|
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