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.
http://tuscaloosatrend.blogspot.com/2019/07/regional-geology-understanding-basin.html

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.

THE EXPLORATION PROCESS
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

Wednesday, July 31, 2019

ConocoPhillips Provides A Project Update

On their quarterly conference call yesterday, ConocoPhillips ("COP") provided an update on their efforts in the LAMS Stack Play.  They have completed their pilot four well drilling program.  The McKowen #1 and Hebert #1 are producing and the Erwin #1 has begun flowback.  COP chose not to finish drilling the lateral in well #4 (Soterra #1) for unstated reasons.  On SONRIS it states that the pilot hole reached total depth of 13,390' which should be approximately 125' below the base of the Austin Chalk.  SONRIS states that they drilled to 12,156' and ran logs.  It does not state that they ran logs at the total depth of 13,390' which would be hard to imagine.  I assume that they ran a full suite of logs and acquired sidewall cores.  They drilled the curve to 13,349' and terminated drilling.  My speculation is that the data collected in the vertical pilot hole was not encouraging.  The Soterra #1 is across the edge of my "prospective limits" where the DLogR/TOC dramatically decreases to the south (map below).  The Mean DLogR is approximately ~1.2 in the Karnes Trough where EOG is making enormous wells. In southwest Giddings Field (Washington County) where many good wells have been completed, the Mean DLogR ranges from 1.2-1.4.


In prior posts (links below), I provided some insight on the McKowen #1 result. My potential interpretations #1 and #4 are now the likely options for the producing wells that have very high water cut.  Either the formation has very high water saturation or the large proppant frac is penetrating higher water saturations from the Austin Chalk above the target zone.  I don't have their landing zone and completions details, so it's impossible to make a firm interpretation.  Based on log calculations from hundreds of wells, I believe that the McKowen #1 and Hebert #1 are producing from higher water saturated zones above the "target zone".  Containing the frac in the bottom 150' will be the key.  That's where the best quality rock and highest TOC is located in this source rock.




Below are relevant statements from the COP earnings call:
"Lastly, we continue to evaluate our results in the Louisiana Austin Chalk play. So far, although we drilled oil from the first three wells that produced a higher water cuts and we were hoping to see. So the results to date are disappointing. Louisiana Austin Chalk is the primary target, we're also evaluating opportunities and other formations within the acreage."

"On the Austin Chalk, yes, we've tested three of the four wells that we had to test the Austin Chalk play there. And it's just as we brought those wells on the petroleum system isn't working as effectively as we hoped it would. The chalk hasn’t dewatered to the extent that they are – this required to get high enough production rates. I mean unconventional wells produce higher water cuts and other plays, I mean the Delaware Basin for example."

"So that by itself is not a disqualifier. But here the water cut that we've seen it’s been a bet over 90%. The oil rates have been about a 100 barrels a day. It's just unlikely to be enough to justify a development and that part of the play. There are targets in the Wilcox and there are targets and the Tuscaloosa Marine shale. So the acreage is not condemned by that primary target and the Austin Chalk doesn't look encouraging just now."
Matthew Fox - Chief Operating Officer


Note that COP confirmed the "stack" potential in the LAMS Stack Play!  It's mindboggling that they chose not to drill pilot holes through the TMS in all four wells.  At EOG's drilling rate in the Ironwood 37H-1, that's one more day of drilling....cheap and valuable data.

All of the TMSers know that "tenacity" is our core skill set.  Yogi Berra might say it's "deja vu all over again".  See the list below of TMS horizontals from 2011 to the end of drilling in 2015.  Devon was the initial leader in the TMS and after they drilled 7 wells, they exited and sold to Goodrich.  70 wells were drilled through early 2015 after their exit.  A recent TMS well tested 1458 boepd.  EOG has proven that they can drill a TMS well in 19 days.  Does $7-8M DHC/CC at $57/bbl work at 1458 boepd and a 600-800 MMBO EUR?  We'll see!

We await the results from the Erwin #1 and EOG Ironwood 37H-1 in the coming weeks.







Wednesday, July 24, 2019

Austin Chalk 3.0 - A Comparison of EOG and COP

As we await results from ConocoPhillips' 3rd Austin Chalk well (Erwin #1) and the EOG Ironwood 37H-1, it's interesting to review Austin Chalk 3.0 in South Texas where these two companies are competing "head-to-head" in the same fairway.  The Erwin #1 and Ironwood 37H-1 have similar geological parameters so this will be a great operational comparison.  ConocoPhillips took a long conventional core in the Erwin #1 so the lateral placement should be ideal.  For this, advantage goes to ConocoPhillips.

The chart below, based on DrillingInfo's "Prac IP", EOG has 17 of the top 20 wells in South Texas (EOG and COP completions since Jan-2016).  The best wells are in the 38-45 API oil gravity range.  The Karnes Trough is a special place.  EOG named their wells after "tall peaks" for a reason!







Monday, July 22, 2019

EOG Austin Chalk Permits & Results

Over the past 2.5 years, EOG Resources has filed numerous permits for Austin Chalk wells spanning across South Texas and Central Louisiana.  In the past few months, they've added three new permits in Webb County, Texas.  The concentration of their activity has been in the prolific Karnes Trough.  EOG has outperformed the competition in this play to date.  The chart below depicts the average six month cumulative production (BOE).  Austin Chalk 3.0 continues.

Source: DrillingInfo





Source: DrillingInfo

Friday, July 19, 2019

Austin Chalk Eras

The Austin Chalk first produced in Texas in 1922.  The real first active era of drilling was during the 1970-80's drilling boom.  Most of the wells were vertical in search of naturally occurring fractures in the chalk.  That era ended with the crash in oil prices.

Austin Chalk 2.0 kicked off in 1990 with the advent of horizontal drilling.  This era saw hundreds of wells drilled horizontally in search of intersecting more naturally occurring fractures.  Giddings Field in Texas was heavily drilled during this time.  Austin Chalk 3.0 kicked off approximately in 2016 with the new strategy of hydraulically fracturing areas with higher porosity and hydrocarbon saturation.  Ironically, the most active areas in Texas today are where poor results were found in the 1990's.  Hence, find the porosity and saturation, not the abundant natural fractures.


Tuesday, July 16, 2019

Austin Chalk - Oil Gravity

As the oil and natural gas prices have oscillated wildly over the past fourteen years, companies have shifted from one commodity to the other.  It's been a wild ride.  The recent capitulation in natural gas prices might cause another pivot to oil for some companies. 

The Austin Chalk formation has produced a significant amount of oil across Texas so the oil and gas windows are well defined.  Much less production in Louisiana presents some unknowns with regards to oil gravity in the new exploratory areas of the play.

The maps below were constructed from thousands of completions in Texas.  The western portion of Louisiana has sufficient control to confirm the trends.  These maps have been "clipped" where little data control exists.  The "blue" outlines on the maps define Austin Chalk field boundaries.  In Texas, Giddings Field has a broad range of oil gravity from 30-63 API.  Active drilling today at Giddings Field in Washington County is focused in the range of 45-60 API gravity. EOG's recent "monster" wells in the Karnes Trough range from 38-47 API gravity.  Pearsall Field ranges from 32-35 API.  Brookeland Field in East Texas ranges from 37-60 API.  Masters Creek in LA-West ranges from 39-59 API.  ConocoPhillips' first two wells in Louisiana produced 36-37 API from their initial production.  A historical producer from 1996 north of the ConocoPhillips Hebert #1 produced 43 API from 12970'.











Tuesday, July 9, 2019

EOG Throws A Curve Ball

A couple of months ago I received phone calls with the rumor that EOG was drilling a Wilcox well in Pointe Coupee Parish.  I responded "that's nonsense".  A few weeks ago, EOG filed a permit for a 17100' vertical hole targeting the Austin Chalk (permit below).  Yesterday on SONRIS, plans for a Wilcox test and possibly plans for a Wilcox horizontal well were revealed.  Never say never.  There are some "wildcatters" left in the industry it appears. 

Based on offset wells, EOG plans to perforate and frac a 20" zone in the Lower Wilcox from 13450-70'.  Logs from an offset well are presented below with an estimated correlation for the two targeted zones.  Logs haven't been released on the Brunswick as of today.

The SONRIS data indicates that a horizontal might be drilled with the lateral covering 13062'-18205'.  If 13062' is the TVD, then the lateral will be ~388' above the vertical perforated zone.  EOG's plan should become more clear in the coming weeks.

This target zone represents early Wilcox progradational, lowstand sands with repetitive coarsening upward parasequences.  The Wilcox sands are "dirty" and low permeability with a very complex mineralogy.  They also have very diverse clays and determining "pay" and water on logs can be very challenging.  

This is clearly a "wild" test.  I'm perplexed, but hopeful that a new shallow, oil-bearing unconventional target gets added to the LAMS Stack.  Maybe we'll reach a "Permian-like" 3000' hydrocarbon column after all!




















Monday, July 8, 2019

Regional Geology - Understanding the Basin

I believe that one of the key factors for most of the "capital destruction" in Shale 1.0, "The Great Land Rush", was due to two factors.  The first is that the land teams got too far ahead of their technical team's evaluation.  Very large acreage blocks were at risk of being lost so the company chose to invest in the acreage before their technical team had completed a thorough analysis.  I recall a story in Colorado where the land team of a very large independent leased an area where the Niobrara was outcropped at the surface.  Field trip opportunity for the geos!

The second reason is that the technical teams only focused on the "zone of interest" and spent little time gaining an understanding of the basin as a whole.  The regional structural, stratigraphic, and geochemical framework is so important.  The formations below and above the zone of interest provide vital details. 

This phenomena played out in the TMS during its first run from 2010-14.  Mudlogs and resistivity curves were the focus for many.  Now with interest increasing in the Austin Chalk, I'm not sure if many have invested the time to understand the basinal configuration and history.  The old science of "trendology" appears to be the "tool of choice" to date in the LA-West region. 

Austin Chalk 3.0 in Texas is being driven by the mapping of matrix porosity.  The current "hot spot" for drilling in Texas is located where horrible results were found during Austin Chalk 2.0 in the 90's.  Understanding the spatial distribution and thickness of porosity, saturation, geomechanical, and geochemical parameters is now the key to this current puzzle.

The maps below provide some regional views incorporating significant geological structures, salt features, bouguer gravity, and a simplified structural map on the Base of the Austin Chalk.  In the early 90's while at Amoco, I spent five years evaluating this basin incorporating paleo, 2D/3D seismic, logs, production, conventional core, and drill cuttings.  The most significant aspect across this basin is understanding the impact of the different Lower Cretaceous shelf edges and the prominent role that salt played with regards to deposition and structure.  Updip and downdip of the Fredericksburg Shelf Edge are two "different worlds" geologically.  The bouguer gravity map below illustrates the major difference on strike between LA-West to LA-East.  The ancestral Mississippi River created a very different depositional history in LA-East compared to LA-West.

Salt ridges and piercement domes greatly impacted the depositional patterns of the Tuscaloosa sands.  The most prominent Tuscaloosa field, Port Hudson, sits on top of a piercement salt dome.  Salt ridges guided the Tuscaloosa fluvial systems into the basin.  For the Austin Chalk, it will be interesting to see how salt-induced fracturing impacts the frac jobs and producibility of the formation.  Some fracturing combined with good matrix porosity should be a good combination.  Too much natural fracturing combined with a large proppant frac might connect with multiple water sources negatively impacting production.  These structural aspects will be important to evaluate as the results come in.












BOUGUER GRAVITY - Source: USGS https://pubs.usgs.gov/ds/352/arkla_bou.html

Wednesday, July 3, 2019

Active Rigs - July 2019

The LAMS Stack Play has four active drilling rigs.  Let's hope for this number to continue to increase.


Source: DrillingInfo


Source: DrillingInfo



Tuesday, July 2, 2019

Oil Price (WTI)

The "puck chasers" on Wall Street have expressed their "loss of love" for the oil and gas sector.  The chart below illustrates the rollercoaster ride of oil prices the last 3.5 years.  It's hard to plan a business when your product's price is so dynamic and unpredictable.  Venezuela, Russia, Iran, Saudi Arabia, and our tweeting President will likely keep this "wild ride" going for some time.



Sunday, June 30, 2019

PetroQuest Energy OLP LLC et al #1

PetroQuest Energy has commenced drilling on its vertical Austin Chalk pilot well in Pointe Coupee Parish. They plan to obtain a conventional core in the well.  The well is permitted to a total depth of 15,840'.  The location is just south of the Fredericksburg Shelf Edge.  

It will offset two Austin Chalk producers.  The UPRC Lacour #1, drilled in 1994, produced 87 mbo and 28 mmcfg.  This was during the Austin Chalk 2.0 era when the concept was to drill horizontal wellbores across clusters of natural fractures.  To the east of the PetroQuest well is the Anadarko Lacour #43.  Note that UPRC became part of Anadarko in 2000.  UPRC was the Austin Chalk "guru" at Giddings Field for many years.  The Anadarko Lacour #43 was drilled in 2011 during a "mini boom" in the Austin Chalk that came across Louisiana.  Anadarko leased 280,000 acres in Louisiana for the play in 2010-11.  I, along with several partners, drilled three Austin Chalk wells in southern Avoyelles Parish adjacent to Anadarko's position.  None of us had success. Despite an exciting initial potential, the Lacour #43 had a rapid production decline due to producing from natural fractures.  Once the fractures deplete, it's "game over".  

If a horizontal eventually gets drilled in this area, it will be interesting to see the response from a high-proppant frac on the natural fractures.  Good matrix porosity with some fractures could be "magical" formula.  The base of the Austin Chalk in an offset well contains 40' of high log-calculated TOC.













Thursday, June 27, 2019

Play Maps

The maps below depict the current well and lease statuses across the play as best we know it from the public records.  As always, use at your own risk.

Petroquest and Marathon filed new permits this week. I'll have more detail on those later.  The ConocoPhillips Erwin #1 frac job has completed.  

Source: SONRIS, DrillingInfo

Source: SONRIS, DrillingInfo

Source: SONRIS, DrillingInfo








Wednesday, June 19, 2019

EOG Astounds With Record Drilling Time

Today the final total depth was reported on SONRIS for the EOG Ironwood 37H-1.  EOG drilled the well in an astounding 18 days where they averaged 1018 feet per day.  ConocoPhillips' Erwin #1 was drilled in 46 days including taking conventional core.  The Hebert #1 took 54 days based on SONRIS reported data.  EOG's drilling and operational team has proved excellence once again.  Let's hope for an astounding initial potential. Their rig is heading to the Brunswick #1 which will be a vertical drill where they plan to take a conventional core in the Austin Chalk.




Monday, June 17, 2019

ConocoPhillips Hebert #1 Result

ConocoPhillips (COP) released an initial potential for the Hebert #1 on Friday.  Like the McKowen #1, it begs many questions.  If these volumes are post-flowback then this is a very disappointing result.  The details will become apparent over the next 1-2 months.

Initial Potential (IP): 206 barrels of oil per day, 134 thousand cubic feet of gas per day, and 4279 barrels of water per day.

COMPLETED 5/21/19 AS A OIL WELL IN THE AUS C RA SUA RES;PM F; 206 BOPD; 134 MCFD; 3729 SITP; 1871 CP; 27/64 CK; 4279 BWPD; 650 GOR; 37 GRVTY; PERFS 14086-19320' (ST: 10)
SONRIS

Let's start with what we don't know:
-Frac design: proppant/water volume, stage/cluster details, and pressures
-Reservoir pressure
-Mudlog: lithology and gas
-Geosteering; wellbore path and landing zone
-Timing of the volumes that were released as the initial potential 
-Chlorides of the produced water. Is is frac or reservoir water?

There are several potential interpretations from this limited amount of data:
1) The Austin Chalk in this area might not be brittle enough so it doesn't respond well to a "high proppant" frac.  COP obtained a conventional core of the entire Austin Chalk in their 3rd well, the Erwin #1.  They have good "rock" data to make this determination.  I'm highly confident that the Erwin #1 will be landed in the best target zone.
2) Landing too high above the base of the Austin Chalk results in the frac penetrating too high into the more water-saturated reservoir section.  I didn't have a 2D seismic line through this wellbore like I did for the McKowen #1 so I can't analyze as accurately the landing zone of the horizontal wellbore.  I generated a grid on the Base of Austin Chalk ("BAC") horizon from surrounding vertical wells which allowed me to examine the landing zone location.  I estimate that the wellbore was consistently located approximately 80' above the BAC.  I would ideally seek a lower landing zone to best impact the highest TOC section.  Without having COP's geosteering data, it's hard to be confident on the landing zone interpretation (see graphic below).
3) The results that were submitted represent a time period early in the flowback period where the frac water volume is very high.  Future monthly production volumes will prove or disprove this theory.
4) The "high proppant" frac is intersecting natural fracture clusters that are connected to water-wet zones.  Both the McKowen #1 and Hebert #1 are located above deep-seated, dip-trending salt ridges that could have created abundant natural fractures (future post).
5) Austin Chalk oil in this area might be thermally immature.  COP's core data from the Erwin #1 will prove or disprove this theory.
6) Being that we're on well result #3 in the Louisiana Austin Chalk 3.0 era, much research and development lies ahead.  Continued trial and error will be required during the first fifty wells.  The "Permian mania" didn't happen after the first three horizontal Wolfcamp wells.





Wednesday, June 12, 2019

Prime Rock Resources and New Dawn Energy Form A Joint Venture


Prime Rock and New Dawn announced a joint venture today.  The maps below depict the acreage in the Austin Chalk Play.  The large combined contiguous block is within and adjacent to Masters Creek Field that has produced over 45 MMBOE since the 1990's (25.2 mmbo, 116 bcf, 310 mmbw)  The depths of the "core" block range from 14000'-19000' TVD.  It is located south of the Fredericksburg Shelf Edge in the downdip "D" fairway.  Depletion and water production will be the likely risks on the acreage within the old field boundary.

For more details:
PRESS RELEASE - CLICK HERE