Thursday, March 28, 2019

Regions - Geological Comparison and Contrast









In my November 5, 2018 post, I presented detailed maps illustrating geographic regions across the Austin Chalk Trend.  This allows for comparison and contrast across this vast trend.


The table below provides a comparison and contrast of the geographic regions of the Austin Chalk in Louisiana and Mississippi.  Due to the fact that I've not evaluated the Texas Austin Chalk trend to the same extensive detail that I have in Louisiana, I'm only presenting the table for LA and MS.



The table subdivides various attributes into the categories of geology, hydrocarbons, and log analysis.  At the top, the range in depth for the base of the Austin Chalk is presented.  The updip limit of my region line is not based on any geochemical maturation data, but is purely based on a consistent distance from the shelf edge.  The top line does align with the shallowest production in Giddings Field (Texas).  The updip limit will be defined in the future as wells delineate this important termination point.  At some point updip, the Austin Chalk of Louisiana/Mississippi will be immature.  It's very likely that the updip limit varies across the play due to variations in burial depth and local tectonics.  Giddings Field in Texas (TX-Central) produces as shallow as -5200' (SSTVD).  In Texas the Eagle Ford provides most of the hydrocarbon source.  The downdip limit across the entire play has yet to be defined.  Pressure, temperature, costs, and economics will be the limiting criteria at some point.

Today I will focus on the geological aspects of the play. One of the major contrasts between the updip and downdip fairways in Louisiana is the geological structure.  I use the Lower Cretaceous (Fredericksburg) Shelf Edge as the defining boundary for updip and downdip.  The updip region exists upon a very stable Lower Cretaceous platform which results in a simpler and "quieter" geological structure.  The region exhibits gentle monoclinal dip with limited faulting.  Drilling and staying "in zone" will be much easier in this region.  Dip occurs in the southwestern direction.


Example of the structure in the Updip Region (Source: Amelia Resources LLC)



South of the Fredericksburg Shelf Edge in the downdip region, the basinal setting presents an environment for major subsidence, accommodation space, depositional faulting, and salt tectonics.  South of the shelf edge is a very typical Gulf Coast basin with 3-way and 4-way structural closures.  Structural dip in a given fault block can occur in any direction as a result of the complex depositional faulting.  These structures trapped and produced 1.4 trillion cubic feet equivalent of natural gas from the expanded Tuscaloosa Sands.
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Example of the structure in the Downdip Region (Source: Amelia Resources LLC)



At the Austin Chalk level, most faults are strike trending and parallel the shelf edge with splinter faults oriented in oblique directions.  Continued subsidence after the deposition of the Tuscaloosa clastics, presents large faults displacing the Austin Chalk with throws ranging from 50-500'.  The orientation, spacing, and throw of these faults can present significant challenges to drilling a horizontal wellbore that has a 5,000-10,000' lateral.  Crossing over a 250' fault wreaks havoc on geosteering and zone placement. 

I believe that the most important risk in the downdip region is the risk of fracking into the faults and natural fracture clusters connecting to large water sources.  In the downdip region of LA-WEST, Masters Creek, Burr Ferry South, and Cheneyville produced on average 6.29 barrels of water per barrel of oil.  Many wells in Masters Creek had ratios as high as 10-35.  In contrast, Burr Ferry North in the updip region produced 0.5 barrels of water per barrel of oil. The same low water ratio is seen on trend in the northern updip portion of Brookeland Field in TX-EAST.  A large proppant frac in the Masters Creek fairway could produce a lot of water.

Cross section schematic (Source: Amelia Resources LLC)

Fortunately, for the downdip operators in LA-EAST,  a merged mega-3D seismic survey is available across most of the deep Tuscaloosa fields (Seismic Exchange Inc.).  We acquired most of these data in the early 90's while I was at Amoco. The 3D will be a key technological tool for success in that environment.  EOG and Devon have acquired most of the leases in this area.  It is for this reason that Marathon, in partnership with CGG and Fairfield, is acquiring a very large 3D survey (500 square miles) across their downdip acreage in LA-WEST.
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A conventional core from West Feliciana Parish reveals a very cyclic sequence of chalk and chalky-marl facies.  The higher TOCs occur in the chalky-marl facies. Higher gamma ray also occurs with the increase in marl content.  On a regional basis, the LA-West region generally contains a higher percent of chalk facies.  This is likely due to the ancestral Mississippi River sourcing clastics into the LA-EAST region.  In 1992 while at Amoco, our research center preformed a geochemical study on the Tuscaloosa Trend oils (LA-EAST).  The Austin Chalk was confirmed to be a source rock.  It's very possible that the hydrocarbons in LA-WEST are sourced from older formations.  The gas/oil ratios in Masters Creek Field greatly contrast those in southern Avoyelles Parish.  Resistivities are also lower in LA-WEST compared to LA-EAST.  

SP and Gamma Ray


Gamma ray correlated to facies and rock type



This play across Louisiana and Mississippi will likely see contrasting results in the four sub-regions: LA-EAST Updip and Downdip, LA-WEST Updip and Downdip.  Each sub-region appears to have its "pros and cons".  Simple geology is great for drilling and producing.  Many like oil over gas.  Shallower and simpler is cheaper.  Pressure "is your friend" when producing low perm reservoirs, but it's not easy to drill through.  Marathon's first well is evidence to that.  Faulted structures with varying dip orientations are challenging for planning a horizontal drilling program.  An abundance of old vertical wells penetrating the Austin Chalk presents the opportunity to perform detailed log analysis with an understanding of spatial variability.  Thick high TOC with higher porosities is always the best.  And most importantly, the highest IRR's provide play longevity.





Sunday, March 24, 2019

ConocoPhillips McKowen #1 Results

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)

Interpreting an initial potential from the second well of a new exploratory unconventional play is idiotic.  The first question is “what day during flowback do the initial potential numbers represent?”.  Without knowing that, interpreting them is a moot point.  The Office of Conservation rules regarding initial potentials are very broad so an operator can release data from any time during the flowback.  Would ConocoPhillips purposely release numbers from early in the flowback to make the well look bad? Maybe. All is fair in love and war.  Why would they?  To scare off competition.  Is this likely? Maybe.  
I believe that ConocoPhillips is doing everything possible for this play to be a success and taking care of their stakeholders in the process.

INTERPRETATION #1:
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.

INTERPRETATION #3:
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.


Source - DrillingInfo/SONRIS
Source: DrillingInfo, SONRIS


MY INTERPRETATION
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.

Tuesday, March 19, 2019

Active Drilling - Southern U.S.

The map below provides an excellent view of current drilling activity in the southern U.S.  The Permian is still the main focus of the industry.  The Eagle Ford, Scoop/Stack, and Haynesville are maintaining a steady pace.  The Gulf of Mexico is still quiet compared to historical activity levels.  The Louisiana Austin Chalk and LAMS Stack Play look forward to results from ConocoPhillips, EOG, and Marathon this year.

Source: DrillingInfo

Wednesday, March 13, 2019

Texas Austin Chalk Wells - Early Results

It was interesting in the first phase of the TMS (2011-14) when operators and Wall Street "suits" were comparing the first ten TMS tests to the 9,000th Eagle Ford well.  After 9000 completions, the Eagle Ford operators were far along on their drilling and completion design.  Comparing TMS well #9 to Eagle Ford well #9000 wasn't quite "apples to apples".  But hey, life isn't fair.  

Fast forward to today, and we're on our second Austin Chalk 3.0 completion in Louisiana and the comparisons to Texas have already begun.  While the ConocoPhillips McKowen #1 is still flowing back frac water, the landowners are already spreading false rumors of a 2000 barrel of oil per day initial test.  Let's hope that they are correct.  Prior to the EOG Eagles Ranch 14-1 frac job in Avoyelles Parish, landowners were spreading rumors of a similar result.  2000 barrels must be the lucky guess or fortune tellers have taken over St. Francisville!

Being that the Austin Chalk 3.0 era has been active in Giddings Field (Texas) for a few years, I thought that it would be interesting to review the first 30 completions there starting in 2014.  Some interesting observations:

  • It took seven wells for the first initial potential to exceed 1000 boepd
  • In the first 13 wells, only one has produced over 500 MBOE
  • It took 14 wells to exceed 1500 boepd
  • It took 21 wells to exceed 2000 boepd
  • It took 30 wells to exceed 2500 boepd
  • The 30th well had the best initial potential at 2511 boepd (imagine that!)

The first Louisiana AC-3.0 well, the EOG Eagles Ranch 14-1, had an initial potential of 1120 bopd and 1157 mcfgd (1313 boepd).  That result exceeds the first 13 wells in Texas.  An Eagles Ranch well test reported eleven days later was 2240 bopd and 1837 mcgd (2546 boepd).  That test exceeds all of the first 30 Giddings wells.

Source: DrillingInfo

Initial tests are not significant in the long run.  They're most important to stock "pumpers", acreage "flippers", and royalty buyers.  Monthly production over time and the decline curve present the key data.  

Here are my observations on the first 12 months of production:

  • The Eagles Ranch 14-1 produced 143 MBOE.  
  • It ranks 11th compared to the first 30 wells in Giddings Field. 
  • This 1st well in Louisiana outperformed the 29th well in Giddings.
  • The 1st well in Louisiana outperformed 19 wells of the first 30 at Giddings Field.


Most important to note, the 30th well in Giddings had the best 12 months.  So what do we conclude?....the operators get better results through time.  It's no surprise that the 30th well outperforms the first 29 wells.
Source: DrillingInfo, SONRIS

Each play is different.  Even within a given play, the reservoir rock exhibits variability.  It really takes 100 wells to truly understand Phase 1 of any new unconventional play.  So sit back and enjoy watching the first 30 wells in Louisiana.  I'm sure that the Wall Street "suits" will be full of vinegar along the ride!