CADDO PINE ISLAND FIELD

The following is the Wikipedia definition of stripper wells.

A stripper well or marginal well is an oil or gas well that is nearing the end of its economically useful life. In the United States of America a "stripper" gas well is defined by the Interstate Oil and Gas Compact Commission as one that produces 60,000 cubic feet (1,700 m3) or less of gas per day at its maximum flow rate; the Internal Revenue Service, for tax purposes, uses a threshold of 75,000 cubic feet (2,100 m3) per day. Oil wells are generally classified as stripper wells when they produce ten barrels per day or less for any twelve month period.

Economical importance

In the United States of America, one out of every six barrels of crude oil produced comes from a marginal oil well, and over 85 percent of the total number of U.S. oil wells are now classified as such. There are over 420,000 of these wells in the United States, and together they produce nearly 915,000 barrels (145,500 m3) of oil per day, 18 percent of U.S. production.

Additionally, as of 2006, there are more than 296,000 natural gas stripper wells in the lower 48 states. Together they account for over 1.7 trillion cubic feet (48 km3) of natural gas, or about 9 percent of the natural gas produced in the lower 48 states. Stripper wells are more common in older oil and gas producing regions, most notably in Appalachia, Texas and Oklahoma.

Many of these wells are marginally economic and at risk of being prematurely abandoned. When world oil prices were in the low tens in the late 1990s, the oil that flowed from marginal wells often cost more to produce than the price it brought on the market. From 1994 to 2006, approximately 177,000 marginal wells were plugged and abandoned, representing a number equal to 42 percent of all operating wells in 2006, costing the U.S. more than $3.8 billion in lost oil revenue at the EIA 2004 average world oil price.

When marginal wells are prematurely abandoned, significant quantities of oil remain behind. In most instances, the remaining reserves are not easily accessible when oil prices subsequently rise again: when marginal fields are abandoned, the surface infrastructure – the pumps, piping, storage vessels, and other processing equipment – is removed and the lease forfeited. Since much of this equipment was probably installed over many years, replacing it over a short period should oil prices jump upward is enormously cost prohibitive. Oil prices would have to rise beyond their historic highs and remain at elevated levels for many years before there would be sufficient economic justification to bring many marginal fields back into production.

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Replies to This Discussion

Permalink Reply by dbob on June 11, 2012 at 10:47

I'm going to send you a friend request.

 

Permalink Reply by Jay Reynolds on June 11, 2012 at 11:31

Thanks Bob, Got the other note.  We do make hundreds of barrels a week of our produced water available as a courtesy to the other operators in the area who need it for operations. 

 

Otherwise, we're kind of far away from folks in the HS who might need it. 

Still have about 25,000 barrels a day to spare : )

JR

Permalink Reply by Skip Peel - Mineral Consultant on June 11, 2012 at 12:08

Jay, are the other operators using your produced water for water flood?

Permalink Reply by Jay Reynolds on June 12, 2012 at 10:05

Skip,

 

My produced lease water is being used for what is incorrectly called a "frac" in the A Sand of the Nacatoch, actually a light "sand pack".  The Nacatoch B is not amenable to waterflooding since the injected water simply bypasses the oil by channeling down into the water productive portion of the sand and re-emerging at a producing well.  We have shown communication between injection and production of a dyed water in about 45 minutes, no change in oil cut.

 

JR

Permalink Reply by dbob on June 11, 2012 at 12:40

Jay

If gas prices ever get back up, that's enough water to do something with.  Of course, if you could get it up to the bakken cheaply enough, you could make a fortune right now.  

Permalink Reply by Skip Peel - Mineral Consultant on June 11, 2012 at 13:06

The Brown Dense is a potential market if it ever proves economic. 

Permalink Reply by Skip Peel - Mineral Consultant on June 12, 2012 at 10:32

Jay, I am aware of at least one water flood in the CPI so it must be a formation other than the Nacatoch.  That brings me to a question that I have not found time to research.  How many different formations are being produced across the field?

Permalink Reply by Jay Reynolds on June 12, 2012 at 11:13

Skip,

 

I'm no authority on what's being produced but this would be a start, Nacatoch A, B, C, D, Anonna Chalk,

Paluxy (Woodbine) Pettit, Cotton Valley, various stringers of the Hill Sand (Rodessa series)...

Permalink Reply by Skip Peel - Mineral Consultant on June 12, 2012 at 11:18

I thought there were a number of producing horizons.  Thanks for the list.

Permalink Reply by Jay Reynolds on June 19, 2012 at 11:03

The Nacatoch A Sand

 

Until Dr. Kirby of Hosston really kicked it off the A Sand part of the Nacatoch, immediately overlying the B Sand was largely overlooked.  Dr. Kirby, being a "science guy" undertook a relentless campaign to figure out the pecularities of the A which had been largely ignored because the B, just below it, would produce with only drilling a well and equipping.

 

While permeabilities in the B may range upwards of 3 Darcies in some areas, the A was "tighter" at 200-350 millidarcies on average and thus required some stimulus to make it produce.  The key was what is called a "frac" but which actually would not be technically classified as such given the very modest pressures required to move a coarse sand out into the near wellbore region.  This process uses only about 3,000 lbs of sand and the pumping pressure, typically at 6-10 bbls/min is not much more than required to overcome frictional losses, typically as low as 350 psi.

 

Another key distinction is that the A is "dirtier" ie, it has more clays in it that are prone to swelling when exposed to fresh water.  And it is fresh water that was used in drilling the B Sand wells and almost always a "native mud" was employed which means that some water was sucked out of a ditch, the drilling created it's own "mud" without amendments to inhibit clay swelling.  During the great promotions when a lot of the drilling was done the emphasis was getting to the B Sand FAST so mud pumps were cranked up and the hole was as much washed down as drilled down.  Our thinking is that the invasion of the fresh water into the A Sand has been responsible for the fact for the wells that were drilled very quickly has a lot to do with the fact that the B Sand wells that have been converted into A Sand wells haven't done as drilling a new A Sand well.

 

This process involves just running a cement bond log, setting a bridge plug, perforating and "frac'ing". The "frac" is under $5,000 and takes about 20 minutes.  Compared to a "watered out" B Sand well (one is which the water has coned in) the economics are compelling.  About $50K to drill and equip a new A Sand, four days from spud to oil in the tanks if one is running a tight operation, payouts in 60 days are not uncommon.  Water handling drops as oil cut improves, maybe 500 BWPD with 1/2-2/3 BOPD with a B Sand equipped with an ESP, 150 BWPD with 5-7 BOPD with an A Sand, the KEY difference being that there is no "ocean" beneath the A so they are not prone to cone to water in the same way as a B Sand well.

 

I was talking with one of the large out of State oil guys who was looking around the area who was asking what percentage dry holes he should work into a spreadsheet if trying to get a grasp of the economics.  We called around a bit and couldn't find any having been drilled, not a big surprise on a massive blanket sand whose boundaries and productive limits are well understood but maybe something of a surprise for somebody from out of the area.

 

JR

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