consul inquiry

Consul wants to do a core 3" sample on my land. Any advisement as they want to measure coal thickness and say 8000 ft. is their target. I own gas and oil tights, but not coal.

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Permalink Reply by rmc on January 19, 2013 at 2:24am
Is it possible to drill a 3" core 8000 thousand feet'?
Permalink Reply by Jack Straw on January 19, 2013 at 5:32am

 

Possible? Yes, darn near anything is possible,

Practical? No, it would be obscenely slow and prohibitively expensive.

In drilling an Oil or Gas well there are times when it is desirable to obtain core samples.

Especially in new areas, where minimal data are available.

Core samples are obtained by either of two means:

1). side wall cores. A wireline tool is run into the hole. This tool has a number of hollow side wall core barrels that are propelled (by explosive charge) into the side of the borehole ..... thus retrieving samples.      Obtaining side wall cores requires rig time and often fails in recovering cores.

2). Conventional core barrel. These obtain a vertical core, typically 30 feet or 60 feet long.                                       Running a core barrel into the hole and coring is very expensive (in rig time, etc.) and is done on a very limited basis. A Geologist needs to have a very convincing argument to justify obtaining core samples (if a Geological question needs an answer). Or, a Reservoir Engineer needs to have a very convincing argument to justify obtaining core samples (if a reservoir question needs an answer).

 

It is my opinion that what Rebecca was told makes no sense; things just do not add up.

 

All IMHO,

                  JS

 

Permalink Reply by Rebecca Loftis on January 19, 2013 at 5:44am

Thank you.

Permalink Reply by Tim Tarr on January 19, 2013 at 8:31am

Jack Straw,

  Core Barrel:

 Could this be why a company would drill one pilot hole (7000') months before main drilling (4 wells scheduled)  on a pad ? Pilot hole  was 6 months after 3 D seismic completed.

Only other reason I can guess is it was done to HBP (Develop) an old lease.

Permalink Reply by Jack Straw on January 19, 2013 at 9:01am

 

You do not discover Oil & Gas with 3D Seismic or Geologic Mapping.

Oil & Gas are found via the drill bit.

3D Seismic and/or Geologic Mapping can identify the circumstances conducive; but until such time as a well is drilled, it is just conjecture.

 

The 3D Seismic illuminates the subsurface with sound waves. The data obtained are in the form of travel times. This data needs to be converted to depths; using a “time versus depth” equation. Assumptions are made in arriving at the “time versus depth” equation unless (and until) it is calibrated with well data.

 

By drilling an initial 7000' vertical hole, they can:

discern the exact depth to the top and bottom of the Marcellus Shale (and thus its thickness). This allows them to calibrate the 3D Seismic Data and extrapolate that data away from the well bore.

obtain Core and/or Sidewall Core samples, from which to evaluate such factors as Total Organic Carbon (TOC) and Thermal Maturity (by such means such as Vitrinite Reflectance).

determine what is present (Natural Gas?, Natural Gas Liquids (NGLs)?, Condensate?, Oil (and the API Gravity of any oil).

determine Formation Pressure, potential best drilling fluid, and potential best frac fluid chemistry.

and likely some other valuable information that I have not thought of.

 

With the information obtained from the vertical well, they are in a much better position to plan the horizontal drilling program in a manner that most efficiently and effectively exploits what is down there.

And, of course, another reason is it was done to HBP (Develop) an old lease

 

All IMHO,

                     JS

Permalink Reply by Tim Tarr on January 19, 2013 at 10:09am

Thanks JS,

  I'm sure it was for Rhinestreet and Marcellus perhaps more. Do you think they might have tested for porosity and permeabilty of reservoir rock too? Perhaps for enhanced recovery.

There is oil and gas there just a question of where and how profitable would it be.

I sure would like that report!

Permalink Reply by Jack Straw on January 19, 2013 at 10:52am

RE: "Do you think they might have tested for porosity and permeabilty of reservoir rock too? Perhaps for enhanced recovery."

There is the possibilty that they would have obtained Sidewall Cores for any organic rich shale that gave them good kicks on the Gas Chromatograph, whilst drilling through. And, of course they will have three more vertical penetrations as they drill out the pad.

Porosity and Permeability are tricky parameters when dealing with shales.

The effective permeability present is highly dependant upon and to a degree restricted to the avenues afforded bt the jointing present.

The shales are far from being the (relatively) homogeneous/isotropic media of traditional sandstone reservoirs.

I would not expect shales to benefit  from most established means of enhanced recovery. With the highest (by far) values of permeability (and to a large extent porosity) restricted to the avenues provided by jointing ... most means of enhanced recovery would simply bypass the hard to reach areas.

Effectively moving liquids out of a shale and into the borehole would benefit greatly from the presense of a sufficiently high Gas/Oil Ratio (GOR). Natural Gas (expanding as it comes out of solution) can 'push" the oil out of the shale and into fractures. A paucity of Natural Gas associated with Oil could greatly limit the ultimate recovery factor.

 

All IMHO,

                 JS   

Permalink Reply by Tim Tarr on January 19, 2013 at 1:15pm

JS,   

I was reffering to the porosity and permeabilty of the sandstone formation(s) for enhanced recoverey.  Venango group 5th sandstone to be specific.

Thanks again.

Permalink Reply by Todd on January 22, 2013 at 3:19pm

Mr. Jack Straw,

What can an operator do to enhance oil recovery in the case where there is alot of oil in the shale but there is a low GOR?

Permalink Reply by Jack Straw on January 22, 2013 at 4:03pm

 

Horizontal drilling and multi-stage fracing was developed to to maximize primary recovery in rocks that otherwise would not produce.

To further enhance recovery under the circumstances you posed ... I am not sure that they have developed a technique; but there are doubtless people currently looking at that problem.

I will make a guess, once production on a multi-well pad reaches the point where it is un-economic to continue production ....

they will try things like injecting into one of the horizontal wells in an attempt to mobilize and push oil into an adjacent horizontal well bore, Perhaps injecting: natural gas, or CO2 (sequestered from flu gas of nearby power plants), or NGLs (to act as a solvent), steam?

All just a guess. They will likely try a variety of things; but, I am not sure that any will really work ... the existance of the fraced natural jointing (with proppant) suggests to me that attempts of EOR will result in failure as the trapped oil will be bypassed (as it takes the already flushed path of least resistance). Maybe they will start by injecting grout into the existing joints and then re-frac (in hopes of providing new pathways.

 

It took a long time (and a lot of new technology) to discover how to exploit the shales. Developing EOR technology might prove to be even more challenging.

I am am optimist, but my optimism has limits.

 

All IMHO,

                JS 

 

Permalink Reply by Todd on January 22, 2013 at 4:46pm

Excellent Info Mr. Jack.  I copied and pasted this from Wikipedia:

Examples of current EOR projects

In Canada, a CO2-EOR project has been established by Cenovus Energy at the Weyburn Oil Field in southern Saskatchewan.[when?] The project is expected to inject a net 18 million ton CO2 and recover an additional 130 million barrels (21,000,000 m3) of oil, extending the life of the oil field by 25 years.[19] There is a projected 26+ million tonnes (net of production) of CO2 to be stored in Weyburn, plus another 8.5 million tonnes (net of production) stored at the Weyburn-Midale Carbon Dioxide Project, resulting in a net reduction in atmospheric CO2). That's the equivalent of taking nearly 7 million cars off the road for a year.[20] Since CO2 injection began in late 2000, the EOR project has performed largely as predicted. Currently, some 1600 m3 (10,063 barrels) per day of incremental oil is being produced from the field.

[edit] Potential for EOR in United States

The United States has been using EOR for several decades. For over 30 years, oil fields in the Permian Basin have implemented CO2 EOR using naturally sourced CO2 from New Mexico and Colorado.[21] The Department of Energy (DOE) has estimated that full use of 'next generation' CO2-EOR in United States could generate an additional 240 billion barrels (38 km3) of recoverable oil resources. Developing this potential would depend on the availability of commercial CO2 in large volumes, which could be made possible by widespread use of carbon capture and storage. For comparison, the total undeveloped US domestic oil resources still in the ground total more than 1 trillion barrels (160 km3), most of it remaining unrecoverable. The DOE estimates that if the EOR potential were to be fully realised, state and local treasuries would gain $280 billion in revenues from future royalties, severance taxes, and state income taxes on oil production, aside from other economic benefits

Permalink Reply by Todd on January 22, 2013 at 5:31pm

Another somewhat related question for Mr. Jack:

How much of a choke is typically placed on a gas well, NGL well or oil well once production begins?  In other words, how does production usually compare to final open flow on completion reports?

Thanks for your help!

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