Monday, November 11, 2019

Video Presentation: Louisiana Austin Chalk & LAMS Stack Play

This is the slide presentation that I recently gave at the New Orleans SIPES Luncheon.

For the actual presentation, follow this link to the New Orleans SIPES website.  

Thursday, November 7, 2019

Significant Events

Two significant events have come to light this week. First, Equinor has acquired a 25% working interest position in Marathon's project.  Equinor has acreage near the Texas state line. This joint venture provides some more financial strength to Marathon's efforts.  In today's market, joint ventures make a lot of sense.

The disappointing news of the week is that Prime Rock's Crosby 10-1 well is stuck as of the early week's report on SONRIS.

This ties into my discussion from yesterday and my post on the regions of the play.  The deeper, more pressured region of the play, will have drilling challenges.  Those challenges can be very costly as we saw in Marathon's Crowell #1.

The map below is from my SIPES presentation from a couple of weeks ago. It compares a variety of attributes from the four "quadrants" of the play: LA-EAST Updip, LA-EAST Downdip, LA-WEST Updip, LA-WEST Downdip.

Wednesday, November 6, 2019

Drilling Activity Update

With activity shifted to the LA-WEST region of the Austin Chalk Play, it's a good time to "drill deeper" on the new drilling locations.  Both the Marathon and Prime Rock wells are in the southern and deeper portion of Masters Creek Field.  The map below depicts their locations along with the historical Austin Chalk producing wells.  Marathon had a successful re-drill of the Crowell location in 52 days.  Prime Rock is now drilling the Crosby 10-1.  These are deep wells with TVD's of 16200' and 15332'.  

The next two maps depict cumulative BOE bubble maps across Masters Creek Field.  The larger circles represent the best historical producers.  These maps reveal localized "sweet spots" across the field.  Having interpreted the 3D seismic on the west side of the field, I can state that the prolific producers there were always proximal to down-to-the-basin faults where fracture clusters are greatest.  To date, all acres haven't been created equal in this field.

The next two maps depict the cumulative production of oil and gas for each well. The Marathon Crowell #2 is on strike with poor to decent producers, but has good producers to the northwest.  Note that the offset wells produce primarily natural gas which is currently selling at $2.83/mcf.

The Prime Rock Crosby 10-1 has a nearby well that produced 4 bcf and 1 mmbo.  Most of the other wells on strike are marginal producers.  Both of these wells will be expensive so large volumes of hydrocarbons need to be produced.


The maps below represent gas/oil ratios (GOR) for the historical production across the field.  Both wells will likely be in the 4000 range.  Gas will greatly assist producing from the low porosity and permeability, but at the current market prices, oil is a better strategic and economic target.

This region of the play in Louisiana illustrates much lower resistivities than seen in the prolific trend of Texas and the LA-EAST in Louisiana.  One reason for that could be higher water saturations in the chalk reservoir.  The field historically produced 13.6 barrels of water to every barrel of oil.  That's an extremely high water ratio.  Disposing of water is expensive and impacts the overall economics. One of the risk factors is that a large-proppant frac could increase the water volumes.  

The low DLogR values from the Passey equation indicate low total organic carbon (TOC).  It is my belief that the production at Masters Creek Field is derived from a deeper source rock in the Lower Cretaceous or Jurassic.  Large faults served as migration paths into the Austin Chalk.  

The average porosity compares very well to the current results in southwestern Giddings Field.

These two wells will be watched closely for the LA-WEST and downdip portion of the play.  Marathon proved on the Crowell #1 that drilling in this high pressure environment is very challenging.  Good luck to both companies!

Thursday, October 3, 2019

Upcoming Presentations

I'll be making several presentations on the Louisiana Austin Chalk & LAMS Stack Play in October.

LAGCOE 2019 - New Orleans, LA - October 9-11, 2019

SIPES Monthly Meeting - New Orleans, LA - October 15, 2019

Energy Summit 2019 - LSU - Baton Rouge, LA - October 23, 2019

Tuesday, October 1, 2019

Louisiana Austin Chalk & LAMS Stack Play Update

The activity in the Louisiana play has now shifted to the LA-WEST downdip region where Marathon and PrimeRock/New Dawn will be drilling some wells.

COP has made it official that they're exiting the play after drilling 3.5 wells in the updip portion of the LA-EAST region.  Frac heights penetrating the upper, water-saturated Austin Chalk resulted in very large volumes of water production.  It's astonishing to see them exit so quickly after investing over $300 million.  No TMS pilot holes were drilled on any of the four locations.  It's a tough Wall Street environment at the moment.  Sprint back to the "safe" Eagle Ford appears to be the strategy.

No official result has been posted on SONRIS for the Ironwood 37H-1.

They just finished redrilling the offset of the Crowell #1; On September 24, they reached a total depth of 22,500' (TVD 15,332').  They set 5 1/2" liner at 22,490'.  They spud on 8/3/19 so that represents 52 days of drilling.  That's a major success considering the pressure environment in which they are drilling and compared to their initial attempt.  The lateral length is approximately 7,100'.  The well is located just outside the southeastern limits of Masters Creek Field.

At NAPE, Prime Rock revealed that they have a shared contract on Ensign's 777 rig with Marathon.  The rig should be moving to Prime Rock's location soon in Vernon Parish (Crosby 10-1).  The well has a permitted total depth of 23,000' with a TVD of 16,200'.  This is a deep, ambitious well on the southern end of Masters Creek Field.  It will test the concepts of depletion, high pressure, and water production.

The OLP #1 well was a vertical pilot hole where conventional core was acquired.  Petroquest is seeking a partner to drill the lateral portion of the well.

Both Marathon and Equinor are acquiring 3D seismic.  In the downdip portion of the play, this is imperative due to complex geology and faulting.

Australis reports that fracture stimulation operations commenced on September 20 for their 5th and 6th TMS wells.

Tuesday, August 27, 2019

Austin Chalk - Drilling Update

The only people happy with the results in the "updip" region of the LA-EAST Austin Chalk Play so far are those in the saltwater disposal business!  It's not the start that any of us hoped for.  Fortunately, we have some of the best operators in the industry risking their capital to attempt to make this emerging play work.  Not so long ago, there was a time in our industry (pre-unconventional) where we used the term "exploration" for the early "higher risk" phase of the process.  The Wall Streeters are too young to recall those days.

ConocoPhillips just released the results for the Erwin #1.  Like the McKowen #1 and Hebert #1, it is producing primarily water.
Erwin #1 initial potential: 
28 bo, 25 mcf, and 2845 bw
CP 643
GOR 862
Oil gravity: 38
Perfs: 13447-18727 (5280’)

There has not been any official release on the EOG Ironwood 37H-1 results, but word "on the street" is that it's "water plagued" also.

I've shared my post below discussing the post-frac analysis for the McKowen #1.  These four interpretations are all still valid options:

Now with four results in, lets revisit these:

INTERPRETATION #1: The formation is mostly water bearing
The production results to date sure do support this interpretation.  The large unknowns on all of the wells are: how much of the frac water has produced back? landing zone location? How much formation water has been produced?  Frac height? What is the formation pressure?  Only COP and EOG know these answers.  In a normal pressure environment, it's going to be more challenging to get the frac water out of the reservoir.  

The most significant data to dismiss this interpretation is the very consistent high resistivities across the vast area.  A regional map of resistivity conforms extremely well to the depositional basin and decreases quickly and significantly where it should. Secondly, geochemistry data from core on trend with the Erwin #1 illustrates TOC's as high as 2.67%.  The Austin Chalk in the LAMS Stack Play area is a source rock.  The question is, how much is oil and how much is water?

INTERPRETATION #2 : The formation is still producing frac water back
Ditto to my points above. The frac water recovery is unknown. 

INTERPRETATION #3: Low formation porosity is limiting hydrocarbon production
This could be a contributing factor.  I believe that the natural fractures are more of the issue relating to the high water volumes.  In the current "hot spot" in Giddings Field (northwest Washington County) porosities average 7-8.5%.

INTERPRETATION #4: The large proppant frac could have penetrated into a large water-bearing natural fracture cluster
I lean on this interpretation due to the large volume of data in the area supporting the presence of oil in the formation.  All four wells have intersected natural fractures and small faults.  Once you frac up into the higher water saturations, it will be hard to "turn the water off".  Several hundred feet of "wet chalk" exists above the target zone.  The challenge will be designing a frac that stays focused in the bottom 100' of the formation where the oil saturation is highest.  A smaller proppant frac might be the answer. Natural fractures might be the enemy here.  Moving away from the Feliciana Salt Ridge might result in less natural fractures.

With all this said, the key question is whether the operators have the desire to continue the "exploration" era of this play.  Wall Street is not being really friendly to us right now.

Step 1: Determine where the oil/gas is
Step 2: Determine how to extract it from the reservoir
Step 3: Determine how to drill and produce it economically
Step 4: Conduct field wide development

The "updip" region of this play in LA-EAST is on Step 2.  More wells and diverse frac designs will be required.  The TMS is on Step 3.  EOG's 18 day drill on the Ironwood 37H-1 illustrates that they can drill the TMS economically.  Across the US basins, most of the industry (excluding EOG) appears to be stuck on Step 3 at $55 oil.  Much chaos ahead for the industry as a whole.

Tuesday, August 20, 2019