What is an Offset Well?

Consol Energy just released an operations update and called a well in our area an "offset" well to a neighboring well. What does that mean? Internet research provides pretty vague info. We know the original well has produced oil and ngls. Thanks.

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Permalink Reply by Brian Powers on January 18, 2013 at 9:38am

JR-

an offset well is a well drilled before or after any other well but in the general vicinity. It is extremely useful, but not always possible, to have offset well data at hand , particularly wireline logs, to plan the well you may be about to drill nearby in the same or adjoining unit. If one is fortunate to have geological information or the daily drilling records of an offset well, trouble can often but not always be averted.

 

Brian

Permalink Reply by JR on January 18, 2013 at 9:42am
Tuscarawas County: The TUSC 3A in the western portion of the county had a drilled lateral length of 5,020 feet and was completed with 17 stages. The company had previously announced a peak production rate of 400 barrels of oil per day and 386 Mcfd of gas from the TUSC 3A. The TUSC 8A, with a drilled lateral length of 7,568 feet, was recently drilled as an offset to the TUSC 3A and completion by 24 stages is planned during the first quarter of 2013.

Here's the report I'm talking about. Can someone decipher? Is this good/bad/other?
Permalink Reply by Brian Powers on January 18, 2013 at 10:06am

JR-

without any more data, I'd say the TUSC3A well is a keeper that will have to be placed on pump soon due to a low gas-oil ratio that will impede natural flow to surface.

By contrast, the TUSC8A will require 41% more frac stages than its predeccesor, which to me proportionately increases the likelihood of something going wrong.

 

What's missing to me are the formation names/depths/lithology,gas gravity, oil type, BS&W content, the lateral distance between the two laterals, the depth of the vertical wells from where the laterals originated, etc.

A snippet of data with a few basic details and no other data makes it difficult for anyone not in the direct loop to pass judgement about "good/bad or ugly"

 

Brian

Permalink Reply by JR on January 18, 2013 at 12:56pm

Brian, from earlier this year CONSOL reported this of the TUSC3A:  During initial flow back, commercial amounts of light crude oil with a 38° API gravity, and 1,440 Btu gas, were encountered. 

There has been a large pump jack (or was there, not sure of today).  A CONSOL rep told me they're putting it into production and pipeline easements have recently been recorded.  

CONSOL is very quiet so trying to put all the puzzle pieces together.  Any help from someone who understands the processes would be helpful.  Thanks in advance.

Permalink Reply by JR on January 18, 2013 at 12:58pm

Other company reports show 400 bbd with 100% liquids for this well in their slide shows. Another big reason I think this could be of interest is this well is pretty far west compared to the "liquid rich zone" that is being touted today.  

Permalink Reply by TM on January 18, 2013 at 2:37pm

What does 386 mcfd equal out too in cubic feet? Seems like a low amount of gas even with good liquid potential. If it is 100% liquids why not report the ratios of Ngl's that were present. I also read in the report they want to drill 12 wells this year and they said they will all be drilled in noble county. This company is way too tight lipped about things than other drillers.

Permalink Reply by Brian Powers on January 18, 2013 at 4:45pm

TM- 386 mcfd is three hundred eighty six thousand standard cubic feet. Gas volumes must be corrected to standard conditions of 60°F and atmospheric conditions (roughly 14.7 psi/ft at sea level) to be accurate. Remember, though that gas is marketed not by volume,  but rather heat content (BTU) per volume. My rough calculation showed a gas-oil ratio of less than 1,000 scf/bbl of oil, which is low in my view and would help justify the presence of the pump jack. If the production were actually  ± 400 bbls/day of liquids with no gas, it might help expand the wet zone to the west, but the absence of gas (often the driving force of liquids from the rock or frac to the vertical bore) is troubling to me.

 

Brian  

Permalink Reply by paleface on January 19, 2013 at 2:18am

 Brian will that be a rule with shale extraction,you need natural gas as the vehicle to bring the oils and wet gas to surface? I f there in't sufficient  gas presure could that make some oil and wet gas areas unrecoveriable?

Permalink Reply by Brian Powers on January 19, 2013 at 4:05am

pf -

The ideal well type for any operator in any play is one that flows naturally. Wells that do not flow naturally will have to be pumped at some point, which adds to investment and maintenance costs. Having gas entrained in the formation/ fluid flow pathway is essential for natural flow, but less so for pumped wells, as the fluid simply has to move to the vertical section of the well and to the pump intake. subsurface flow will tend to migrate towards the pressure sink (from high to low pressure areas), but depending upon the geology, fluid can be squeezed to the pump intake by the rock compressibility caused by the overburden pressure (similar to squeezing a toothpaste tube) or gravity drainage in a tilted horizon.

As the gas depletes or dissipates, the gas to oil ratio also declines and any motive force from the gas is lost. In conventional reservoirs, water or gas is often injected for secondary recovery purposes (waterflood or gas flood). In heavy oil reservoirs, steam is injected to loosen the oil and drive it to the vertical section, often using gravity drainage in tilted reservoirs. These methods are not feasible in unconventional shales due to the low matrix rock permeability.

 

To answer the second part of your query, as reservoir energy depletes, or if it wasn't present in the first instance, then recoverable reserves are less or become permanently unrecoverable.

 

Brian

Permalink Reply by paleface on January 19, 2013 at 4:56am

 Thank You Brian

Permalink Reply by JR on January 19, 2013 at 10:33am
Brian, I guess what I'm a bit confused by is the investment in pipeline and the offset well. Is it possible we are still missing puzzle pieces that don't provide the full picture, or are you confident there is essentially a "pressure issue"?
Permalink Reply by TM on January 19, 2013 at 11:53am

There will be pressure issues in the west. The pump jack will help with the pressure but low gas volumes worry me some though. Just because a pump jack is used don't mean the well is no good. I believe the beachy well results will be the deciding factor if they drill all the permitted laterals they got for that area.

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