Wednesday, May 29, 2019

ConocoPhillips McKowen #1 - Geological Post-Evaluation

ConocoPhillips' first well, the McKowen #1, has been closely watched by the industry.  I provided a detailed post on potential interpretations of the initial potential that they released.

Below I'm sharing my geological and geophysical evaluation of the horizontal wellbore with respects to the rock properties of the Austin Chalk formation.  I've integrated the data released by ConocoPhillips ("COP") through SONRIS.

The cross section schematic below is drawn to actual scale except for the "cartoon figures" at the surface and the vertical height to the surface.  The wellbore, faults, and formation tops are to scale.  The cross section is parallel to the wellbore heading from north-northeast to south-southwest.  The geological/geophysical interpretation is my own.  I've been interpreting well logs, 2D seismic, and 3D seismic in this area for 29 years.

The cross section illustrates that the COP well was drilled within a graben.  Minor faulting was encountered during the vertical hole in the Midway, Selma, Taylor, and Austin Chalk intervals.  The initial 2/3's of the horizontal also appear to be "quiet" with regards to faults.  The final third of the wellbore intersected two faults, one of those exists through the entire Upper Cretaceous chalk section.  It is at this point in the wellbore that COP reported that they "encountered losses".  This makes sense that drilling mud was lost into the fault/fractures.  They also reported that the losses were "cured".  That's typically achieved by placing lost circulation material ("LCM") into the wellbore to "plug up" the fractures.  This is a common practice in the Austin Chalk, but it always presents potential damage to the rock formation.  The chemistry of the Austin Chalk is very sensitive to drilling fluids.  It's possible that part or all of the wellbore sustained some damage which could inhibit production.  The large rate of produced water indicates that permeability exists somewhere to deliver that large volume.  Placing a large-proppant frac on top of potentially partially damaged reservoir creates some unknowns.  COP chose to stop drilling the well after they experienced the losses.  This shortened the lateral to 3600'.  It's unfortunate that the well wasn't drilled to planned total depth.

The additional well in the second diagram, Osprey LA McKowen #1 is a vertical conventional well that I drilled in 2006 which is just west of COP's well.  The Osprey well drilled through both the Austin Chalk and Tuscaloosa Marine Shale.  The second graphic presents a correlation of the Austin Chalk and Eutaw in both wells.  The logs indicate slightly higher resistivities in the COP well along with slightly lower gamma rays.

The third graphic presents a Passey Log display highlighting a profile of the calculated "total organic carbon"("TOC") section of the Austin Chalk.  In the Osprey well, the basal 135' has the best porosity and the highest TOC's.  COP has not released their porosity logs from the McKowen #1.  These wells are located very close so similar rock parameters are expected.

 The fourth graphic presents the gamma ray and resistivity in the COP well.  At approximately 100' above the base of the Austin Chalk, a bentonite volcanic ash bed exists.  These are common in the Austin Chalk representing the large volcanic activity at this point in the Cretaceous.  It is important to understand the vertical and spatial distribution of these beds because they create barriers and seals within the reservoir.  It's well known that they can wreak havoc on a frac job.

This is from a technical paper on the Niobrara Formation (same geologic age as the Austin Chalk):
 Not only do the bentonite (and marl) interbeds divide the chalks into multiple subtle mechanical stratigraphic intervals, but marly intervals with most abundant bentonites impact hydraulic fracture efficiency by limiting proppant placement to the main chalk benches. While fluid-filled fractures have rather extensive vertical propagation throughout the Niobrara A-B-C at peak pump rates, fracture offsets across bentonites and ensuing proppant embedment phenomena eventually render the main marl intervals as barriers to effective stimulation.

The fifth graphic creates a composite of some key information.  My integration of the directional survey of the wellbore and subsequent "landing zone" is 100' to 135' above the base of the Austin Chalk.  The 135' is at the "heel" of the wellbore and it slowly drifts down to 100' above at the "toe".  If this is accurate, that indicates that the landing zone is not only above the best saturated reservoir and source rock, but it's also above the volcanic ash barrier which would impact the proppant distribution in the frac in the downward direction.  Lastly, the gamma ray also indicates that the best "chalky" zone (low gamma) for landing the well is at the very base of the Austin Chalk.  COP drilled a vertical pilot hole so they had that to use for guiding geosteering into the lateral.  I don't have access to that data.

One final thought is presented in the last graphic. The water saturation increases overall as you progress vertically upward in the Austin Chalk.  Landing higher puts the wellbore in a zone with higher water saturations.  This reason alone could explain the high water volumes in the well if it's not still producing frac water.  I estimate that the McKowen #1 still has 40% of the frac water that has yet to produce back.

In summary, if my interpretation of the landing zone is correct, the wellbore missed the best target zone.  The 2nd well, the Hebert #1, drilled a full lateral and I've not heard of any issues with it.  I hope that they landed this well lower in the section.  Those results will be interesting in the weeks ahead.

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