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Logan County, Oklahoma

The North Coon Creek Prospect is a development drilling program to recover proven Gas reserves from previously drilled wells, and utilizing modern engineering techniques to economically dispose of potential formation saltwater production. The producing zone objective is the Osage Layton Sandstone and in certain areas, the Misner-Hunton Limestone.

The Layton sand was penetrated by numerous well bores with some of these being completed and produced in structurally deeper reservoirs, i.e. Skinner, Hunton, Viola, and Wilcox, with the remainder wells being plugged and abandoned as dry holes. An evaluation of these various well logs and tests allows the Layton to be defined for quality geological structures.

Two wells drilled in the prospect area were produced from the Layton sand (McCoon No. 3 & Bobwhite Thomas "A" No. 1). A third well (Russell No. 1) was drilled through the Layton sand and tested. A drill stem test of the Layton in the McCoon No. 3 well located in the W/2 NE/4 Sec. 3, T14N-R1W had the following results: Gas to Surface (GTS) in 37 minutes, Flow Rate of 51 MCFPD, Recovered 350 feet of mud and 60 feet of saltwater. The final shut-in pressure was 1890 psi. The completion report after a nitrogen foam fracture treatment was flowing 866 MCFPD on a 12/64" choke with a flowing tubing pressure of 1080 psi, with 20 barrels of water in a 9 hour period. When placed on production, the well had to flow against a 400 psi line pressure, which resulted in early abandonment.

The Bobwhite Thomas "A" No. 1, located in the NW/4 SW/4 Sec. 2, T14N-R1W, was recompleted in the Layton in May 2000. The Thomas "A" No. 1 is approximately 20 feet higher structurally than the McCoon No. 3, with only 2 feet of Layton sand zone. The Thomas "A" tested 460 MCFPD with flowing tubing pressure of 400 psi. Gas sales began in May 2000 and the well flowed until September 2000 when a pumping unit was installed. This well has reported cumulative gas sales of 114,000 MCF with a steady rate of 108 MCFPD through the sales meter.

The Russell No. 1 well is located in the SW/4 NE/4 SE/4 Sec. 26, T15N-R1W. The open hole logs indicated the Layton to have lower permeability than the Thomas "A" No. 1, but had 2 feet of micro-log permeability. Completion was attempted in the Layton, but did not achieve a good cement squeeze above and below the Layton zone. There was a gas build-up at the surface after perforating for the cement squeeze and after perforating for the nitrogen foam fracture treatment. The well was re-squeezed and re-fractured. Production tests reported 12 MCFPD with 30 BWPD, and was determined not commercial.

It can be concluded in the Russell No. 1 hydrocarbon testing, that the open hole logs over the Layton should have at least 40 MV of SP separation from the shale line, and if available, good indication from a micro-log. The Russell No. 1 testing does indicate that gas is present in the Layton sand.

The first well to be re-entered in the program is the Knightlinger #1 located in the SE/4 NE/4 NW/4 of Section 13, T15N-R1W. This well was initially drilled to the Hunton Limestone in 1969. In May 1953 the Chestnut was drilled (direct offset to the Knightlinger #1) and a DST of the Layton reported: a good blow of gas in 33 minutes, estimated 25 MCFPD and recovered 50 feet of gas cut mud with no water; the 30 minute shut-in bottom hole pressure was 1575 psi. The fact that no saltwater was recovered indicates that gas production from the Layton in the Chestnut #1 may be water free. Further support for gas production from the Chestnut #1 is the reported 370 unit gas show while drilling through the Layton in the Boeckman #1 located one mile south. The Kirkpatrick #1, a cable tool hole drilled in 1928 less than a mile north in the SW/4 Section 12, T15N-R1W, reported a good oil and gas show in the Layton.


The Osage Layton sands are comprised of very fine grained sands deposited in elongated marine bars trending NW-SE throughout the area (see enclosed map). The 1st Osage Layton sand occurs more widespread than the 2nd Osage Layton sand. The marine bars of the Osage Layton sand also appear to have a greater opportunity to be in communication with those bars that are adjacent to and along trend as compared to the marine bars of the 2nd Osage Layton sand which trends to occur in small isolated clusters. Both Osage Layton sands have net sand thicknesses that typically range from 5 to 15 feet.

These Osage Layton sands were sourced by Cottage Grove sands which were flowing in small channels southwest into the deeper part of the Anadarko Basin. An example of one of these channels can be found in the eastern portion of T15N-R2W where a field of eleven Cottage Grove producers oriented NE-SW has produced over 4 BCF. As the basin filled up by the advancing sea these channel sands were reworked by long shore currents into their present day orientation as Osage Layton marine bars, and were preserved by the marine shales which buried them as the sea advanced.

Present day structure for the area shows the Osage Layton dipping gently WSW with a slope of about 100 feet per mile and one-half. This means that the ENE portion of each porosity pinch-out of these marine bars are likely to encounter the most amount of recoverable gas and the least amount of water.


The very fine-grained nature of the Osage Layton sand means there is more surface area in the pore spaces of its reservoir. This allows a greater amount of bound or immovable water to be present in its reservoir along with the hydrocarbons (oil & gas). The bound water causes resistivity logs through these sand intervals to read and appear wet when in fact they are productive. The Thomas "A" No. 1 for example was productive with only 2.7 ohms of resistivity. This tendency to look wet is why the Osage Layton sand has been mostly ignored or overlooked by previous operators in the area.

Also, this very fine grained nature of the Osage Layton sand affects the permeability of the reservoir such that a high amount of porosity (15% or greater) is needed to assure that enough permeability will be present to allow the movement of fluids through the reservoir.


With the above reservoir characteristics in mind, a Pickett plot for each Osage Layton sand well was made to help identify the best candidates for a completion in the Osage Layton. Porosity vs. resistivity was plotted on log-log graph paper for the Osage Layton interval for each well in the study area. A Pickett plot treats each well the same so that one can see those wells which have the most favorable porosities with water saturations likely to be the best gas producers. Although limited by only being able to use those wells having both a porosity and resistivity log in the data set, eleven were clearly identified. These best candidates all have porosity greater than or equal to 15%, water saturation less than or equal to 70% and net sand thicknesses greater than or equal to 6 feet. In addition, several other wells, some of which may have had gas shows in the Osage Layton, but without having had a porosity log run on them were also identified. Several of these are up-dip offsets to the best candidates on the Pickett plots. These wells are "highlighted" on the structure-isopach map of the 1st and 2nd Osage Layton sands. For the saturation calculations, water samples from the McCoon and the Thomas "A" wells gave a water resistivity as 0.032 ohms at reservoir temperature.


Our reserve analysis was based on the production history of the Thomas "A" #1 and the use of multi-phase, multi-dimensional reservoir simulator models constructed using the reservoir parameters derived from well logs and other data.

Using saturations of 30% gas, 66% water, 4% oil, average porosity of 15.8%, a permeability of 3 md, and an average thickness of 8 feet, the estimated gas recovery is approximately 1.6 BCF per well. The reservoir properties in the vicinity of the 3 proposed washdowns appear to be much better than around the Thomas "A" #1 area. Micro-log porosity thickness of 10 feet, good SP readings, porosities ranging from 17 to 20.5%, and calculated water saturations of 66% should improve the daily gas production rates and ultimate cumulative recovery.

The reserves and parameters for economic potential that the program may achieve per well are:

  • Initial Gas Price - $3.50 escalated to $5 @ 5%
  • Net Gas Reserves - 2.105 BCF per Well
  • Reserve Life - 20 years
  • Undiscounted Payout - 8 months
  • Undiscounted Net to Investment - 12 to 1


The North Coon Creek project presents the opportunity to economically develop a significant volume of proven gas reserves from a reservoir that is well defined, but has been overlooked for production. The location of low pressure pipelines within the vicinity of the wells permits readily marketable reserves. The re-entry of old well bores and the production technique of simultaneous gas production-water injection significantly reduces development costs and increases net profits.

Click HERE for a map of the North Coon Creek Project.

Pennaco Natural Gas, LLC
Tulsa, Oklahoma

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