I highly recommend that you read my post from March 13.
ConocoPhillips released an initial potential for the McKowen #1:
COMPLETED 3/8/19 AS A OIL WELL IN THE AUS C RA SUA RES;PM F; 60 BOPD; 34 MCFD; 4806 SITP; 1748 CP; 24/64 CK; 3498 BWPD; 567 GOR; 36.4 GRVTY;PERFS 15048-18745' (ST: 10)
I believe that ConocoPhillips is doing everything possible for this play to be a success and taking care of their stakeholders in the process.
The formation is mostly water bearing
The cores from the well exhibit a high TOC % indicating the presence and thickness of hydrocarbon source rock. Known hydrocarbons in-place can also be calculated from well logs. The well sustained a significant “gas kick” at the end of the wellbore. It was so significant, that ConocoPhillips chose to stop drilling earlier than planned. The initial potential gas rate of 34 mcfgd does not align with a large gas kick. Also, the flare, while sputtering due to water, burns like a much higher gas rate.
INTERPRETATION #2 :
The formation is still producing frac water back
Most important to note is that the frac job injected 240,000 barrels of water. At a daily rate of 3500 barrels of water, that takes 68 days to produce. On March 22, we estimate that the well had been flowing 23 days. That water volume indicates that only 34% of the frac water has been produced. If the water rate has been higher, then maybe the well is 60% through flowback. On day 23, the well appeared to still be producing approximately 3500 barrels of water per day. Tubing could assist with producing the water. Keep your eyes out for a workover rig.
Low formation porosity is limiting hydrocarbon production
It’s possible that the oil and gas numbers are low due to lower matrix porosity in the formation. The well might be primarily producing only the frac fluids from the frac-induced fractures.
INTERPRETATION #4:The large proppant frac could have penetrated into a large water-bearing natural fracture cluster
The proppant volume was 72% above the average volume used last year at Giddings Field in Texas (see table and chart below). They used 4625 pounds of proppant per foot which is very high. It's possible that this penetrated water-bearing natural fractures either above or below the target high-TOC zone. The fracture cluster intersected at the end of the wellbore could be the culprit zone.
There still isn’t enough data. Not knowing the percent chlorides of the current water production makes it impossible to know whether the water is from the formation or the frac job. Only ConocoPhillips knows this. Based on the data we have to date, I conclude that nothing will be known until the frac water has been produced. A full month of production for March will be posted on SONRIS soon enough….and then April, and May….
ConocoPhillips has planned an excellent pilot drilling program with wells scattered very well geographically and geologically. They have significant experience with drilling and completing horizontal wells in the same geologic formations in Texas. After 4-5 wells, some initial interpretations can be made. Ultimately, a 12 month decline curve is the first real data indicating whether a play is economically viable. The upcoming COP and EOG wells will be very important for the play.
Patience, patience, patience.
Patience, patience, patience.