[JV153]

http://www.halliburton.com/en-US/ps/sol ... d=hgjyd44q

Halliburton says 220 million b/d worldwide production of water barrels

http://www.ogj.com/articles/print/volum ... r-cut.html

Oil and Gas Journal states 300-400 million b/d of worldwide water barrels

[Subjectivist]

So basic math says we now produce 3.5 to 6.5 bbl of water for every bbl of petroleum/natural gas? I know it does not take a lot of energy to pump one barrel of water out and then reinject it but make that 300 million bbl/d. Suddenly you are talking about a significant energy cost. Every day 24/7/365, and getting worse into the future.

[Unit30Bull]

It definitely pays to be a landowner with a commerical SWD on your property. Making people rich by the barrel.

[rockdoc123]

Water cut is generally quite manageable in fields at only slightly elevated operating costs. I remember being involved in a field we were producing at the time that had 90% water cut and we were producing 125,000 barrels of OIL/d. It was a big field with lots of wells but this was when oil was around $50/bbl and it was still immensely profitable. The real costs that have been continually rising that make oil and gas economics challenging is energy costs and manpower costs. Usually when the industry goes through a downturn the cost of equipment (rigs, compressors etc) drops as does the cost of steel (hence tubulars and drillpipe costs drop). But throughout all of those fallbacks salaries manpower costs continued to rise. Also higher energy prices means that it costs more to run all of your equipment unless you are able to use gas from your production to offset a portion of it.

Where water production becomes a problem is if you develop and adverse mobility ratio or your wettabilty flips (hence you suddenly produce nothing but water) or you do not have a means of getting rid of produced water (i.e. either surface percolation ponds in areas where the water can be used for agriculture or existing well bores that can be converted to injection wells) and have to drill new wells to accomplish that. That results in higher costs.

[ROCKMAN]

No way for me to do an accurate estimate but I would guess Halliburton’s number is low. They’re saying the average water cut globally is 72%. The trend I’m redeveloping in Texas has been producing since the late 40’s and has made 4.5 billion bo. And a lot of those wells are still producing today…at a 97%+ water cut. And most have been producing at 90% WC of higher for a decade…or two.

Two primary ways to get rid of water in Texas: disposal wells on the lease or haul by truck to commercial SDW well. Lease injection: $0.25 to $0.40 per bbl. Hauling it to SWD well: $3.50 to $7 per bbl.

So you make 200 bbl of fluid per day at 1% oil cut: that’s 2 bopd and 198 bwpd. So 2 bopd X .75 (royalty) X 0.94 (severance tax) X $95/bbl X 365 days = $49,000/year.

So 198 bwpd X 365 days X $0.35 = $25,000/year. Thus $49k - $25k = $24k profit. Except you have to deduct about $400/month for a gauger so more like $19k/yr. And then there are incidental costs that can run several thousand per month. So closer to $16k per month.

That doesn’t sound like much but if you have an old nearly depleted field with 20 wells left you netting over $300k per year. Not a bad living for a guy that might not have more than a high school degree and 30+ years experience in the oil patch.

[shallow sand]

Have been reading board for awhile and especially enjoy your posts ROCKMAN. I am sort of like your example of a guy with 20 old wells. We say we are in the water handling business, because our cut is over 99/1. I'm in an area that doesn't have the shale plays and so am unfamiliar with the facts about them. Am concerned that they could drive the price too low for us higher cost operators. I read that the break even is high, but I've been through enough low price times to know that they won't necessarily stop drilling once the price drops below that point, at least not till they've really cratered it. Is it possible they could drive WTI below $50 or is that become pretty much impossible absent panic selling in a financial collapse. For years we needed 10-12 to break even, 15 to live on. Incredible what has happened to both price and expenses since we invaded Iraq. The thing that amazes me is how they are finding enough decent help in these intense horizontal drilling areas. It is getting harder all the time to find dependable workers. Any comments that help inform us stripper well people are greatly appreciated. Keep up the posts!

[rockdoc123]

Is it possible they could drive WTI below $50 or is that become pretty much impossible absent panic selling in a financial collapse. For years we needed 10-12 to break even, 15 to live on. Incredible what has happened to both price and expenses since we invaded Iraq.

breakeven price for new heavy oil projects in Canada is thought to be ~$85/bbl, breakeven price for existing production is somewhere between $50 - $60 dollars last time I looked. I know what the breakeven costs are for the various shale gas plays but not sure on what that equates to in oil. That's a number that isn't generally used since all of the liquid rich shale plays have a high gas content so the economics are subject to price of gas, the high liquid prices serve to lower the breakeven cost based on "gas" (as an example the higher liquid yield wells in Eagleford have a lower breakeven cost than the lower liquid yield wells). Given the recent drop in natural gas price there are a lot of areas that are running on extremely tight if not negative economics already. If at the sametime oil price drops to below $80 (I don't it will but who knows) I doubt there will be many of the shale plays making much profit as there isn't enough liquid revenue to offset the crappy natural gas prices.

[shallow sand]

Thanks for the input rockdoc123. I notice the WTI strip has flattened. I assume this is a sign of a bottom. I just worry about the price given where expenses are now. As we know, LOE doesn't drop when the oil price does. I also worry about the earthquake issue with the shale fracking. What pressure and what zones are they injecting/disposing in? We have been injecting in the producing sand or in the sand immediately below since world war 2, at relatively low pressure. There were several news stories about quakes a month or so ago. A moratorium on salt water disposal via injection/disposal wells would devastate the industry and would cause immediate oil shortages IMO.

[ROCKMAN]

Shallow - Not that the hands aren't skilled but the directional drilling equipment has gotten so sophisticated that it's not that difficult. I wouldn't worry much about frac'ng induced earthquakes...just too deep and too limited an extent. In reality almost all the induced tremors have been associated with swd wells. And even those haven't hurt anyone and there's been little real damage. Old swd wells with failed packers/csg worry me more.

Yep: between public companies drilling too much to keep their stock values up and that imported Canadian oil you and I would have less worries. LOL.

[shallow sand]

Do the shale plays result in a lot of produced water. Assume it varies. I think I have read the Mississippian play in Ok/KS results in a lot of produced water and the need for many SWD wells. On the other hand seems like Bakken does not produce much water. My concern is self serving since we dispose of so much water. Afraid of broad brush regulations. Like the anti-frack contingent who seem to think this is new and want to ban "fracking" in all forms. Just worried that quake issues may affect all SWD/INJ, when there are just a few problem wells.

We monitor our injectors closely. Of course have to MIT for state but rate and pressure maintenance is crucial, but the do fail some and having to slim hole is not enjoyable, plugging worse. Most drilled in 80s or later so pretty good cement jobs. Have to watch the oldies from the 50s pretty close, have plugged several of those.

Have a teen aged son who wants to get in the business. I tell him he needs to get a plugging company set up to specialize in plugging 20000' horizontal holes. Think could be big demand for that 15years from now? Wonder what it costs to plug one of those puppies. Would think one of those making less than 5 bbl not going to be economic, and looks like will be a lot by 2030.

[ROCKMAN]

Shallow - First for everyone else's benefit that play is not strictly a shale play: The Mississippian Lime consists of a number of various formations that are Mississippian in age (~320 – 360 mya). Lithology varies throughout the entire stratigraphic interval, and lithological features include fine-grained limestones, argillaceous muds, spiculites, tripolites and chert. The Mississippian section is roughly 500 feet thick and consists of various reservoir facies that require specific completion design and stimulation, due to differing porosity systems.

Which makes it very different from shale plays like the Eagle Ford (with little to no produced water) which is a pressure depletion drive and not a water drive reservoir. As a result the ML is a very different play then the shales. PIt has recently become clear that the major factor standing in the way of sustainable economic recovery is the costs incurred with the unusually high produced water volumes coming out of the ML when fracced. Therefore, to fully exploit the play's commercial potential, the development of cost-effective produced water transport, disposal, treatment and re-use is absolutely critical. Additionally, while horizontal completions have revolutionized the Oil & Gas industry, production methodology now needs to be optimized to enable a high oil cut and economic Mississippi Lime well. Considering all the geological characteristics of the play, effective artificial lift, choking techniques and production optimization techniques must be identified to yield an optimal oil cut and subsequent increased return on investment.

[shallow sand]

Yes I'm mixing apples and oranges when comparing Mississippian to shale. Really don't know much about either. Both do seem to get a lot of hype, Eagle Ford and Bakken more so. Is there secondary recovery potential in any of these? I don't have a geology background, but would appear that the shales likely would not, which would seem to make long term a challenge for operators in those areas. I picture them like the McCloskey dolomite in our area, big initial pop that declines to nothing pretty fast, with no water flood potential. I'm sure not same geology but same production response, albeit shallow vertical wells with much much lower IP and ultimate recovery.

Also read some about ROZ in older fields. Is there a simple way to explain how that's being exploited?

[rockdoc123]

s we know, LOE doesn't drop when the oil price does. I also worry about the earthquake issue with the shale fracking. What pressure and what zones are they injecting/disposing in? We have been injecting in the producing sand or in the sand immediately below since world war 2, at relatively low pressure. There were several news stories about quakes a month or so ago. A moratorium on salt water disposal via injection/disposal wells would devastate the industry and would cause immediate oil shortages IMO.

Its funny that the waste water pumping issue has come to the fore front in places like Oklahoma of late. It was a big issue a few decades ago in California as waste water being pumped had the potential to lower confining pressure around some of the active faults that intersect with the San Andreas. Fracking itself doesn't cause the earthquake issue...the seismicity from such "fractures" is very small. If a well that is being fracked intersects with a fault there is potential for continued pumping to lower confining pressure around the fault or lower the coefficient of sliding friction on the fault allowing for motion and hence an earthquake. Practically unless you have an idiot running the frack it would be pretty difficult to first not know you had intersected a fault with your well, second not have cased it off in some manner and thirdly not to have stopped pumping when you saw pressure wasn't building up.

My understanding is the problem is with waste water from operations. In this case it is injected into wells that often the operator hasn't very much knowledge about other than from a production perspective. In Oklahoma they are changing the regs to avoid these issues.

[phaster]

not to get too far off topic, but too bad all "energy" production plants didn't work out as well one place I saw in iceland (called the blue lagoon)

basically they (people of iceland) drilled wells in a lava field, to inject water (as a means of a heat exchanger), and then took the super heated water from the wells and ran it thur steam turbines to generate electricity

the cooled off water from the generator plant was then dumped in place, and a spa was built to attract tourists...

[ROCKMAN]

Shallow - Yep: EOR is always going to be difficult in low porosity reservoirs...to much surface tension. ROZ...what's that?

Phaster - Yep...too bad we all don't live in a land that's about to blow up under our feet. LOL. I've actually soaked in the Blue Lagoon years ago. Not as hot as you might not suspect. The amazing bit of engineering is how well they isolated piping to get it back to town.

[dolanbaker]

District heating using the waste heat from power stations is fairly common in Mainland Europe, many countries used them.

[Scrub Puller]

Yair . . . ROCKMAN. In my oilfield jargon lexicon ROZ lists as "residual oil zone" . . . just what does that mean or imply?

Cheers.

[toolpush]

Scrub Puller,

The ROZ, is the water layer under an oil reservoir, where some oil still resides in the pores of the rock. One of the geo's can define that better than me. Some people have speculated it is similar to areas of the reservoir that has been produced using water injection, and therefore maybe successfully further produced by CO2 injection. The holy grail of this thinking is to carbon capture CO2 from coal fired power stations and inject in the numerous ROZs below the old oilfields and hopefully produce some oil while sequestering the CO2.
That is the theory, now the question is, has anybody done it? Don't know.
Is is economical? Most likely not at the moment, but it is amazing what some environmental dollars can do for economics.
Will it happen? depends on the price of oil, Carbon and who is in government.

[ROCKMAN]

Pusher: For me the ROZ is the reservoir rock that once contained the oil prior to production. After depletion anywhere from 30% to 70% of that original oil volume remains in the ROZ. Thus "residual oil" as in the remaining oil. What you've descried is what I would call the "transition zone" where the oil saturation decreases from that in the reservoir above it (above the "oil/water contact") towards 100% water saturation somewhere below. The transition zone can be just a couple of feet thick to 50'+ thick. Depends on the nature of the reservoir and the oil characteristics.

BTW: CO2 injection into a depleted water drive reservoir is typically a very poor application of the technique. At that point the oil that's left isn't very movable even with some CO2 added since the permeability to water is very dominant at that stage. Works best in pressure depletion drives especially with heavy oil. There's basically two times to go with CO2 injection (or any other injection such as NG, nitrogen, chemicals, etc.): during the primary production phase when it's called "pressure maintenance" or "production maintenance" and after depletion has incurred to some significant degree when it's typically called "enhanced oil recovery" (EOR) or secondary recovery. It's difficult to judge the net effect of maintenance efforts since the reservoir is still producing rather well anyway. EOR improvements, OTOH, tend to stand out since you see the jump in oil production more readily.

[toolpush]

Attempt #2

Rockman,

I am sure you are correct by technical geological language, but the pop culture seems to have a slightly different interruption, to my understanding anyway. I will put a couple of references up, and you tell me if I am misunderstanding what it is saying.

http://www.co2conference.net/wp-content ... s10-13.pdf

http://www.alrc.doe.gov/technologies/oi ... 55690.html