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Stripper Wells

Group Says Marginal Wells Account For 18% Of U.S. Oil, Nine Per Cent Of U.S. Gas Output
[Print Article: December 2007] Oil wells trickling out 10 barrels a day, or less. Gas wells producing no more than 60 thousand cubic feet (mcf) a day. In the United States, wells flowing at those rates fit the official definition of what are known in oilpatch parlance as stripper wells. An obvious question might be: does anyone care?

The answer is an emphatic yes. In the U.S., where dwindling domestic hydrocarbon resources have become a national concern, it isn't surprising there are organizations devoted to stripping the last recoverable hydrocarbons from existing reservoirs.

The Interstate Oil and Gas Compact Commission (IOGCC), an Oklahoma City, Oklahoma-based group representing the governors of 37 hydrocarbon-producing states, has monitored the status of U.S. marginal wells since the 1940s. In this year's 47-page annual report on marginal wells, the commission says roughly 18% of the oil and nine per cent of the gas produced in the U.S. in 2006 came from stripper wells. This is an astounding statistic considering the almost hobby-scale output of those wells.

According to the report, U.S. production from stripper oil wells (those not exceeding 10 bbls a day) averaged only 2.18 bbls a day last year. But because there are so many of those wells -- 422,255 last year -- their combined oil output is 918,000 bbls a day, the report says.

In some cases production is literally a trickle. In Ohio, for example, 28,915 oil wells averaged less than half a bbl a day in 2006, the report says.

Last year, the U.S. had 296,721 stripper gas wells -- wells not exceeding 60 mcf a day. The average output of these wells in 2006 was 15.8 mcf a day. The lowest per-well average for gas wells was in Illinois, where 551 wells produced less than one mcf a day. Still, the combined production from U.S. stripper gas wells averaged nearly 4.7 billion cubic feet a day, according to the IOGCC.

In a country that is increasingly dependent on foreign energy sources, every drop counts. And there's local economic spinoff because stripper wells are owned by thousands of tiny companies, many of which are literally mom-and-pop operations.

Technology deployment

To help develop, demonstrate and deploy low-cost technologies to improve the economics of marginal wells, the U.S. Department of Energy (DOE) established the Stripper Well Consortium at Pennsylvania State University in late 2000. Federal and state sources provided a total of $3 million in base funding over three years. Through the Stripper Well Consortium, which is run by an industry board, the DOE provides grants of $25,000 to $300,000.

Probably more than half the projects involve lifting technologies for getting fluid out of wells, says Gary Covatch, a project manager with the DOE's National Energy Technology Laboratory in Morgantown, West Virginia. He says about three-quarters of the problems with stripper wells result from fluid buildup in the wellbore. These wells operate at extremely low pressures and low flow rates, so an accumulation of water or even oil in the wellbore can choke off production.

Conventional fluid removal techniques -- using beam pumps and swabbing with workover rigs -- are often too costly for stripper wells. For marginal wells, these costs can spell the difference between abandonment and increased recovery.

So the goal was to develop a tool that would have few moving parts to wear out, be simple to operate, require minimal monitoring and use the natural pressure of gas in the wellbore to lift water out of the well.

One result is the Gas-Operated Automatic Lift (GOAL) pump developed by Frazer, Pennsylvania-based Brandywine Energy and Development Co. with Stripper Well Consortium funding in 2001-03.

This smart plunger pump allows the operator to set how much fluid will be brought out of a well on each run by adjusting the pressure setting. The plunger rises when pressure builds up below it, then falls back down the wellbore as wellhead pressure drops.

The tool travels down through any standing liquid (by virtue of a through-tool liquid bypass mechanism) until the weight of fluid atop the tool offsets a preset actuator pressure and automatically closes the bypass.

As gas pressure builds in the well below the tool it is lifted up the wellbore, pushing the fluid load to the surface and out through a wellhead lubricator. This is done without human intervention. The on-board actuator valve assembly senses tool pressure and as wellhead pressure falls to within a preset limit of sales-line pressure, the valve automatically opens, allowing the tool to descend for another cycle.

Well cleanouts

Oil and gas wells can also produce sand, scale and corrosion debris. Stripper wells typically don't flow at high enough velocity to remove this material, requiring periodic cleanouts to maintain flow rates. This remedial work costs money and interrupts production.

Stripper Well Consortium funding helped Pumping Solutions, Inc. (later acquired by Smith Lift, LLC, a division of global oilfield supplier Smith International Inc.) develop a solution to the solids issue.

The company modified a small electrical submersible pump (ESP) that can be deployed inside casing on plastic tubing, which can double as a conduit for produced fluids. The pump's design was based on a hydraulically driven diaphragm that is tolerant of debris-laden fluid. The small-diameter plastic tubing increases the velocity of the pumped fluid, conveying more debris to the surface.

More than 100 hydraulic diaphragm electrical submersible pumps were installed in stripper wells over the past two years to measure the performance of the diaphragm pump, which has since been fully commercialized, according to a Stripper Well Consortium booklet.

The pump, which has no electronics and few moving parts, is designed to use 66% less power than a conventional electrical submersible pump, the consortium says.

Along with impeding production, water produced with gas can cause problems in flowlines. Water in flowlines is hard to remove and contributes to corrosion. Covatch says Vortex Flow LLC of Englewood, Colorado, came up with a simple, inline device to redirect liquids in pipelines and tubing, allowing gas to more effectively carry the liquids along a pipeline or out of a well.

In 2002, Vortex Flow adapted an existing technology (for conveying solids over long distances in pipelines) to improve flow characteristics in stripper well flowlines and wellbores. During the next two years the consortium helped Vortex Flow field test several downhole units, and then develop a new slickline-deployable version of the downhole tool. Covatch says Vortex Flow now has more than 200 tools installed across the U.S.

Reducing costs

Technologies that shave a few dollars off operating costs or yield an extra mcf or two of gas per day can make a huge difference for small operators. Lenape Resources, Inc., which the Stripper Well Consortium describes as one of the larger independents in New York State, has roughly 400 wells averaging 10 mcf of gas a day, "or less," says president John Holko.

The Alexander, New York-based company has eight staff (including administration and field workers) plus four contract personnel. Holko says the key to managing stripper wells profitably is to have a large number and to keep costs at an absolute minimum.

To dewater its wells, Lenape Resources uses the GOAL pump and one-inch (outer-diameter) poly tubing as siphon string. The poly tubing, which Holko says is supplied by PolyFlow, Inc. of Oaks, Pennsylvania, has Kevlar braiding to prevent stretching. (Kevlar is the super-strong, lightweight fibre used in bulletproof vests among other applications.) The small-diameter tubing permits high velocities even with a small amount of fluid.

In its gas gathering system, Lenape Resources uses a compressor package provided by Aurora Compression Systems, LLC of Mars, Pennsylvania. Holko likes the simple and flexible design. He says this new compression technology, called a guided rotor compressor, allows additional capacity to be added more easily and cheaply than with conventional reciprocating or screw compressors.

U.S. vs. Canada

In Canada, marginal wells have a much lower profile. One reason may be the major producing basins are less mature than in the U.S. But another factor is the difference in land ownership, suggests Bruce Peachey, director of increased recovery with Petroleum Technology Alliance Canada (PTAC), an industry group dedicated to improving oilfield technologies.

To get the best economics, it is desirable to have a large concentration of wells in the same area. But in southern and central Alberta (south of township 60) -- where most of Western Canada's major oilfields are located -- many of the pools have as many as 50 stakeholders. These range from the majors down to mom-and-pop producers with one or two wells.

Peachey says the Alberta government owns the mineral rights to 81% of the province's land area. The rest is either national parks, Indian reserve land or freehold. Much of the freehold mineral rights are attached to lands originally granted to the Canadian Pacific Railway to encourage settlement on the Prairies. The CPR resold some of its lands to settlers (often in tiny quarter-section parcels) who passed their holdings on to their offspring, who in turn willed them to their progeny, down through several generations.

The mineral rights went with the freehold land ownership. So today a vast number of private landowners have a toehold in countless Alberta oil pools, and the result is a landman's nightmare. Even doing something with a single well can mean a huge amount of research and multiple consultations and signatures.

Meanwhile, EnCana Corporation, a corporate descendant of the CPR, owns the mineral rights to six per cent of Alberta's land area and more than 12% south of township 60. And because the railway was given every second section, EnCana now has a toe in many oil and gas pools across a wide swath of central and southern Alberta.

Unrelated to the CPR lands, freehold mineral rights were also granted for a planned Edmonton-to-Calgary rail line and then sold piecemeal. In addition, the Hudson's Bay Company also got freehold mineral rights with its vast land holdings, which have since been passed on to other owners. So even though the Alberta government owns 81% of mineral rights to the province's land area, ownership is extremely fragmented because of the piecemeal distribution of the remaining 19%.

Because of the fragmented ownership associated with many of Alberta's major conventional oilfields, putting together pool-based collaborations can be prohibitively expensive. "To do even a waterflood you have to get the whole pool working together.... So it's been a concern for both Saskatchewan and Alberta that people aren't unitizing," says Peachey, who looked at the problem as part of a study assessing the province's potential for enhanced oil and gas recovery. (Unitization creates joint operations to maximize recovery among separate owners in the same reservoir.)

Even putting together EnCana's huge carbon dioxide EOR project at Weyburn in southern Saskatchewan took years of work -- even though the field was already unitized -- and required legislative and regulatory changes.

In the U.S. Lower 48 states, almost all of the mineral rights are freehold and tied to surface land ownership. As a result, Peachey says, those jurisdictions have regulations better tailored to freehold rights and resolving related disputes. And in states such as Oklahoma, he adds, there are big ranches and sparse populations, hence large tracts of land are held by a single owner. This allows greater economies of scale.

In Canada, Peachey believes fragmented ownership remains the biggest barrier to squeezing more oil out of conventional fields. Even as the price of West Texas Intermediate crude approached $100 a bbl there was still no concerted effort to address the issue. "Now, especially, with such a big spread [between heavy and light oil prices] we should be going after light oil," says Peachey. "Yet people are still divesting those assets." By Pat Roche


Gary Covatch, Stripper Well Consortium, Tel: (304) 285-4589, E-mail: [email protected]

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