Thursday, December 26, 2013

Goodrich Update

Goodrich provided this update on their TMS operations:
HOUSTON, Dec. 26, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced that its Huff 18-7H-1 (97% WI) well in Amite County, Mississippi was successfully fracture stimulated with 17 stages and had commenced flowback at expected fluid rates when the well became plugged up with frac-related debris at a frac plug approximately 500 feet into the lateral, which will need to be cleaned out prior to resuming flowback.  Therefore, completion results are expected to be released after the first of the year as soon as flowback has resumed and peak rate achieved.

The Company is near total depth on its Weyerhaeuser 51-1H-1 (67% WI) well in St. Helena Parish, Louisiana, which is expected to be completed in January, and is currently running intermediate casing in preparation of drilling the lateral on its CMR 8-5H-1 (100% WI) well in Amite County, Mississippi.

The Company has in excess of 300,000 net acres in the play with two rigs currently running.  A third rig is set to commence drilling operations in the first quarter of 2014, and the Company anticipates up to five rigs running by year-end 2014 pending continued drilling results.

Tuesday, December 17, 2013

Comstock Announces 2014 Budget

"The 2014 budget includes $80 million for completion costs of 29 (21.0 net) South Texas Eagle Ford shale wells that were drilled in 2013 but will be completed in 2014.  In addition to completing the wells drilled in 2013, Comstock has budgeted to drill 71 (47.6 net) horizontal wells in 2014.  The Company expects to spend $264 million for drilling 59 (40.2 net) wells in the South Texas Eagle Ford shale, $50 million for drilling ten (5.6 net) East Texas Eagle Ford shale wells, $27 million for drilling two (1.8 net) Tuscaloosa Marine shale wells and $29 million on facilities, recompletions and other capital projects.  Depending on oil and natural gas prices in 2014, the Company anticipates funding its drilling expenditures with operating cash flow."


Wednesday, December 11, 2013

Encana - 2014 Guidance

Encana announced this today as part of their 2014 guidance:
"In order to transition to a more balanced commodity portfolio and achieve a goal of deriving approximately 75 percent of its cash flow from oil and natural gas liquids by 2017, Encana will focus three quarters of its planned $2.4 billion to $2.5 billion capital investment in 2014 on five oil and liquids-rich assets: the Montney, Duvernay, DJ Basin, San Juan Basin and the Tuscaloosa Marine Shale (TMS)  These five assets are expected to make up about 25 percent of total production in 2014 while generating approximately 45 percent of total upstream operating cash flow before the impact of commodity price hedging."

Slide Presentation:



Tuesday, November 26, 2013

Happy Thanksgiving

It's almost Thanksgiving and the TuscaloosaTrenders have a lot to be thankful for.  I estimate that over the past three years approximately 1.7 million acres have been leased.  At an average of $200 per acre, that's $340 million of income for mineral owners.  Let's figure that land acquisition costs are $20 per acre.  That's $34 million to the landmen of the world.  With 34 wells drilled, I estimate a total of $544 million spent by the operators with the service companies as benefactors.  Some mineral owners are already blessed with that amazing "mailbox money" every month. Over the past year, some speculators have made a really nice return on their high risk investments.

With all that said, it's a great time to offer some tax deductions to all of you.  I'm giving you the choice to fund the rewriting of the ObamaCare website or make a tax deductible donation to an organization that serves the poor directly and efficiently.  As many of you know, my favorite charitable organization is Emmaus House of Harlem.  The organization was founded by my uncle, the late Father David Kirk, in 1966.  The organization continues on today and has a staff made up of 100% volunteers.  Your donation goes directly to serving those in need.  I serve as the President of the board of directors.  Your donation is in good hands. This week, Emmaus will distribute 250 turkeys to families in need. An interesting calculation...a 1% tithe on $340,000,000 is $3.4 million.

Make a donation today:

Emmaus Harlem on Facebook:

2014 appears to be the "proof in the pudding" year for the TMS. From recent presentations, it appears that 40-50 wells could be drilled next year.  With all of this excitement, I look forward to making many "late night" posts keeping all of you up to date on the activity.  Your generosity is sure to inspire me. GEAUX BIG!

Happy Thanksgiving to all!

SPE Business Development Meeting - TMS Panel

Along with Rob Turnham (Goodrich) and Joe DeDominic (Sanchez), I presented last week at the SPE Business Development meeting as part of a TMS panel.  130 people attended.  Several have requested a copy of my presentation.

Thursday, November 14, 2013

Comstock Resources Announces Entry Into The Tuscaloosa Marine Shale

This was released by Comstock this morning:

Comstock Resources, Inc. Announces Acreage Acquisitions

FRISCO, TexasNov. 14, 2013 /PRNewswire/ -- Comstock Resources, Inc. ("Comstock" or the "Company") (NYSE: CRK) announced today that it has entered into agreements with certain parties to acquire leases on 55,000 acres (53,000 net) in Louisiana and Mississippi for $54.5 million aggregate consideration.  The purchase agreements are subject to customary closing conditions and adjustments.  The Company believes the acreage being acquired is prospective for oil in the Tuscaloosa Marine shale formation and is near successful wells drilled by other industry participants.  The leases cover acreage in Wilkinson and Amite Counties in Mississippi and in East Feliciana and St. Helena Parishes in Louisiana.  Comstock expects to complete the acquisitions in the fourth quarter and is pursuing other lease acquisition opportunities in this and another play prospective for oil development.

"These acreage acquisitions will allow Comstock to expand its oil drilling program beyond its current successful program in South Texas's prolific Eagle Ford shale play" stated M. Jay Allison, Chief Executive Officer of Comstock.  "The Company's 2014 drilling program will still be primarily focused on developing our Eagle Ford shale properties as we await a more favorable natural gas price environment to resume drilling in our Haynesville shale natural gas properties.  By adding new acreage in plays prospective for oil we can ensure that we have an adequate inventory of future drilling locations which will allow us to continue to grow our oil production and oil reserves base in future years."

This press release may contain "forward-looking statements" as that term is defined in the Private Securities Litigation Reform Act of 1995.  Such statements are based on management's current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described herein.  Although the Company believes the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.
Comstock Resources, Inc. is an independent energy company based in Frisco, Texas and is engaged in oil and gas acquisitions, exploration and development primarily in Texas and Louisiana.  The Company's stock is traded on the New York Stock Exchangeunder the symbol CRK.

Source: Comstock Resources

Source: Comstock Resources

Sanchez Energy's Earnings Call

Last week, Sanchez hosted an earnings call. Here are the TMS highlights:
  • Additionally we have entered the Tuscaloosa Marine Shale, which will provide substantial upside and value creation as that play continues to be de-risked through an increased drilling pace.  While our drilling focus continues to be on the Eagle Ford, we are very excited about recent developments in the TMS and look forward to participating with other operators in the area, as well as kicking off our operated drilling program early next year.  Other operators in the play have recently announced increased capital commitments for the purpose of accelerated drilling programs, which is a positive move for the TMS in terms of its development cycle.
  • In the TMS we’re in the midst of planning for our 2014 program, which we expect will include participation in several non-operated wells prior to the start of our operated program. We are in the process of filing several drilling unit requests with the Mississippi state board of oil and gas and are evaluating options on drilling rigs. With the majority of our leases either HBP by shallow production or with sufficient remaining term, we can take the time needed to correctly plan our operations.  
  • As mentioned, we’ve significantly strengthened our balance sheet and liquidity this quarter with the issuance of the 11 million shares of common stock at a price of $23 per share before operating costs and added $200 million of tack-on notes to our second quarter $400 million senior note offering. These offerings are used in part to fund our previously announced acquisitions in the TMS, Wycross and Five Mile Creek areas in the Eagle Ford.

  • Q&A

    Neal Dingmann - SunTrust
    And two more if I could. Tony just moving over to TMS, what do you envision? I know you mentioned a few non-op wells initially. Is that the plan maybe for the first half of next year? Number one, is it mostly just on the non, you’ll stay on the non-operated side? I’m trying to get a sense of how many of these wells you’ll be part of early on or when we can think about the first operated well?

    Tony Sanchez - President & CEO
    Yes, I’d say we are shooting for our first operated well as soon as possible. I think the logistics of drilling wells in Mississippi has some leave time associated with them from a permitting process principally, but we are working on getting our units formed that we would operate and would spud as soon as possible.

    The most likely would be, hopefully sometime early in the first quarter. You had commented that and you thought that we were gong to be participating principally as a non-op into the first half. I think we’ll always participate as a non-op, but I think our operated program will become the voice point starting in the first quarter of next year.

    I’m looking at the math now. Other companies are actively forming units, and principally in Wilkinson and Amite Counties of Mississippi and I’ve seen AFEs come across my desk that we are signing off on. Some of them are low interest wells, 3% to 5% working interest. Others are hired at 20% or 30% and our more times than now we’re going to participate, but we are working diligently to get our units set up, to get the paperwork in place, the services sourced rigs and on to start really as soon as practically possibility. I just think its going to fall hopefully in the first half of the first quarter of next year.

    Ron Mills - Johnson Rice
    Okay. And then Tony, just to clarify some comments about the TMS, it sounds like you want to start the operated program as soon as possible. It sounds like you have some at least well proposals in front of you. Do you think it’s one of these things where the non-op definitely comes before the operated or could you start your operated program even before you’ve really participated in many non-op wells?

    Tony Sanchez - President & CEO
    No, I think logistically that non-op is going to begin first and so when we get a better sense of the ordering of the wells, what our working interest is in the wells, where they are, we’ll start to put that out there. But the way a lot of this planning goes is you go out and you form a bunch of units, you take it to the Mississippi Oil and Gas Board and get them approved, send letters to the non-participating other mineral owners or lessees and get the things like surface use agreements and air permits and things done.

    So you basically because of the lead-time you got to start working on a bunch of them at the same time. When we get a better idea of the ordering, we’ll put that out, but its highly likely that we’ll be predicating as a non-op first, and that’s entirely a function of timing at this point.

    Phillips Johnston - Capital One
    Okay, and then just in TMS, you talked about getting units set up, but have you actually determined yet where the first three operated wells will be located or is that going to be sort of contingent on how some of the non-op results come in?

    Tony Sanchez - President & CEO
    I would say, we’re actually in the process of filing units across the – across section of we’ll consider it the mid county and then we’re looking at recent well results where the non-op interest would be what’s the timing of the non-op wells and where it makes sense for us to test the TMS. So there’s a lot of factors in play and we don’t have it determined yet.

    Joe DeDominic - Chief Operating Officer
    Fundamentally we’re going to approach it the same way we did the Eagle Ford in 2011 and 2010. Just get up as close as to where its proven successful as possible, then we work our way out from there.

    Ben Wyatt - Stephens
    Great. Just jumping over to the TMS, Joe I know you spent some time down there in a previous slide, but just curious kind of how you guys are thinking with your initial wells. Will you guys be kind of above the rubble zone, below the rubble zone or are you guys kind of think there’s already a secret sauce on the way to drill and complete these wells? Just maybe some initial thoughts around how you guys will go about that.

    Tony Sanchez - President & CEO
    Yes, we talked about that. Obviously we’re talking a couple of wells for next year initially. We’ve actually talked internally about do we want to drill one above, one below and maybe one just partially in the rubble zone, because there’s actually some thinking that maybe the rubble zone is important for productivity.

    So we’re evaluating new data that comes in. We’ve of course been with and talking to other operators in the play and I think as an industry we’re all trying to land in the right spot to be most effective and get the most oil for the cheapest amount, dollars right. So there is some sharing going on among operators and so we’re trying to figure out how best to approach it. But I think you’d see us trying to do a little bit of both initially, to try and learn the best way to go forward.

    Paul Grigel - Macquarie Research Equities
    Hi, good afternoon. Most of my questions have been answered. Just a quick one on the TMS, really two parts. One, on the AFEs that you guys have been looking at on the non-op side, where have well costs been coming in and then on your first off wells, I know it’s still early, but any projection or change in projection on what you’re expecting for well costs as well?

    Joe DeDominic - Chief Operating Officer
    What was the second part of the question?

    Paul Grigel - Macquarie Research Equities
    On the operated wells that you guys will be going forward, if there’s been any change to what you’ve presumed for well costs in the TMS.

    Joe DeDominic - Chief Operating Officer
    Yes, ASC’s have been coming in the $13 million to $15 million range per well and we see our preliminary estimates of what it would cost on an operated basis in that same range.

    I think like we experienced in the Eagle Ford, the big decrease in well cost will come as a result of development drilling. The TMS people had complained about the high well costs. Our first Eagle Ford wells would cost in $15 million to $16 million. Now we’re regularly bringing them in at $9 million.

    So again, once we go into a development program where we’re drilling off multi well pads, we have some continuity to the program and we would expect well costs to come substantially down, but on a one off basis we’re seeing them in the $13 million to $15 million range, which is certainly lower than where they were even six months ago. So they’ve already started to come down, no question, but I would expect another big step down once we start pad drilling.


    Tuesday, November 12, 2013

    Amelia Resources LLC Announces an Update on Acreage Sales

    November 12, 2013 10:54 AM Central Standard Time
    THE WOODLANDS, Texas--(BUSINESS WIRE)--Amelia Resources, LLC announces an update on the status of acreage sales in the Tuscaloosa Marine Shale (TMS) play.
    Amelia Resources announced today that it has facilitated the sale of over 95,000 acres in the TMS play. The company has served as a consultant hosting a data room and marketing large acreage blocks in the TMS. Amelia is marketing 85,000 additional acres that represent the last remaining large acreage block available in the play.
    Amelia’s President, Kirk Barrell, said, “The TMS play continues to gain momentum with additional drilling and acreage acquisitions. Recent announcements by TMS operators indicate that there will be a significant increase in capital invested and drilling across the play in 2014.”
    With 23 years of experience across the Tuscaloosa Trend, Amelia Resources, LLC has evaluated over 1,000 wells in the TMS across Louisiana, Mississippi, and Texas.
    Barrell stated, “Wells such as Goodrich’s Crosby 12H-1 illustrate that this unconventional reservoir has the ability to produce prolific amounts of oil in a short period of time. As in all unconventional plays, costs and operational challenges will decrease through time. 2014 will be an exciting time for this play as it moves to development mode and new operators enter the project.”
    Amelia Resources LLC is a privately held exploration and production company. The company generates drilling prospects and is actively engaged in several projects across the onshore Gulf Coast. Amelia was founded in 2003 by Kirk Barrell and has offices in The Woodlands, Texas, 30 miles north of Houston. The company leverages its 27 years of geological and geophysical experience to obtain strategic positions in drilling projects. Updates on the TMS and Austin Chalk projects are provided by the company at
    CAUTIONARY STATEMENT: This press release contains certain forward-looking statements regarding various oil and gas discoveries, oil and gas exploration, development and production activities, anticipated and potential production and flow rates and the economic potential of properties. Accuracy of these forward-looking statements depends on assumptions about events that change over time and is thus susceptible to periodic change based on actual experience and new developments. Amelia Resources LLC cautions readers that it assumes no obligation to update or publicly release any revisions to the forward-looking statements in this press release and, except to the extent required by applicable law, does not intend to update or otherwise revise these statements more frequently than quarterly. Important factors that might cause future results to differ from these forward-looking statements include adverse conditions such as high temperature and pressure that could lead to mechanical failures or increased costs, variations in the market prices of oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells, oil and natural gas reserves expectations, the ability to satisfy future cash obligations and environmental costs, and other general exploration and development risks and hazards.
    Amelia Resources, LLC
    Kirk A. Barrell, 281-798-6741

    Wednesday, November 6, 2013

    Encana Corporate Strategy Launch

    Encana presented an update on their corporate strategy yesterday.  The company will focus on five oil plays of which the TMS is one of them.

    The slide below was presented summarizing their plan for the TMS.

    Acreage approximated from Encana's website presentations; Wells: TMS producers; Structure: base of TMS

    Tuesday, November 5, 2013

    Goodrich Earnings Call - 11/5/13

    Goodrich Petroleum presented their third quarter results today.  The TMS highlights are:

    • execute an increased capital budget and acceleration of the TMS in 2014
    • currently have 2 rigs running in the TMS, going to 3 rigs in the first quarter of 2014, and 5 rigs by the end of the year with continued success.
    • We've established a preliminary capital expenditure budget for 2014 at $375 million, with $300 million allocated to acceleration of development of the TMS, where we estimate that we will drill or participate in as many as 31 gross, 24 net wells, which is a blend of 100% working interest wells and 67% working interest wells.
    • We are budgeting 45-day drill times, although we think we will do better, 60 days spud to spud, and 75 days spud to sales cycles times.
    • We continue to be optimistic with the resource potential of the play as our Crosby wells cumulative production has reached 138,000 barrels of oil equivalent per day or over 90% crude oil in 8.5 months, with a current rate of approximately 250 BOE per day on a very flat declining curve. This would compare to similar cumulative production from the Anderson 17 #1 well in 15.5 months, and 155,000 BOE for the Anderson 18 #1 in 16 months. 
    • When considering recent wells in which we've operated or participated as an non-operator, 5 of the last 6 wells are trending on or between our 600,000 BOE and 800,000 BOE curves, with the oldest of these wells now approximately 18 months old.
    • The Crosby well continues to perform in excess of our 800,000 BOE curve.
    • We have drilled our Huff well in Amite County, Mississippi, with 5400 feet of usable lateral. We drilled the curve and lateral in a record time of 12 days but have experienced completion delays due to temporarily sticking to drill pipe, which we have now resolved, and cleaning up the wellbore prior to running production casing.
    • We believe our ability to knock at least 10 days off of our 45-day AFE of $13 million, which will save $1 million in drilling costs is very achievable, considering that we normally drill the vertical portion of the well and run intermediate casing in less than 25 days.
    • We spudded our Weyerhaeuser 51-1 well last week, which is the initial well on our newly acquired acreage with our partner, Sinopec, with plans to drill 3 wells back to back on the acreage.
    • After the Huff, that rig will move to the CMR 8-5 well in Amite County, Mississippi. 
    • The 3 wells drilled on Sinopec JV acreage will be spread out from the Weyerhaeuser in the middle to a well on the east and an additional well to the west.
    • We continue to see very consistent results across the CMS when similar frac recipes are pumped. 
    • The increased activity levels in 2014 from us, Encana, which today announced it will spend $200 million to $300 million in the TMS next year, and other companies we know are building positions, to allow for rapid delineation and progression to development mode for the company.
    • We feel like we've got a nice core acreage position that's already de-risked. You will see us with a combination of stepping out away from the core in a gradual manner, and in particular, locating wells near Devon wells, in particular, on our acreage block, where we could put the proper or the more effective completion recipe on those wells.
    • We are seeing new operators in the play. To answer your last question, we expect 2 or 3 of them. Certainly 2 of them to potentially start talking about that, so we're aware of the files from assignments in the parish courthouse. And so I think that's a given, but we'll let them discuss it when they're ready to talk.

    The entire transcript:

    Monday, November 4, 2013

    Goodrich Petroleum Announces Quarterly Results

    Here is the TMS related information from Goodrich's earnings announcement today:

    Goodrich Petroleum Announces Financial Results And Operational Update

    HOUSTON, Nov. 4, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) (the "Company") today announced financial and operating results for the quarter ended September 30, 2013 and provided an operational update.

    Tuscaloosa Marine Shale ("TMS"):
    Preliminary 2014 capital expenditure budget allocates $300 million for the TMS to drill up to 31 gross (24 net) wells with five operated rigs running in the play by the end of 2014 pending continued success.
    The Company drilled its Huff 18-7H No. 1 (97% WI) well with usable lateral of approximately 5,400 feet. The Company drilled the curve and lateral in a record time of 12 days but has experienced completion delays due to temporarily sticking the drill pipe shortly after reaching total depth. The Company successfully freed the drill pipe and is currently cleaning out the wellbore in preparation of running production casing. The cleanout of the wellbore is expected to be completed within the next few days.
    Cumulative production from the Company's Crosby well has reached 138,000 barrels of oil equivalent ("BOE", 90% oil) in 8.5 months, and five of the last six completed wells are currently producing at or above the Company's 600,000 BOE type curve (See current Management Presentation posted on website).
    The Company currently has two rigs running in the play and has commenced drilling operations on its Weyerhaeuser 51H-1 (67% WI) well in St. Helena Parish, Louisiana, the initial well of three consecutive wells planned on its recently acquired acreage block, with plans to move a rig to its CMR 8-5 (100% WI) well in Amite County, Mississippi after the Huff 18-7 well.


    Capital expenditures for the quarter were $91.4 million, of which $66.3 million was spent on drilling and completion costs, $22.7 million on the Company's producing property and leasehold acquisition in the TMS and $2.4 million on other leasehold acquisitions and extensions, facilities and other expenditures.  Capital expenditures for the first nine months of the year were $204.2 million, of which $174.6 million was spent on drilling and completion costs, $22.7 million primarily for the TMS acquisition, $5.9 million on acreage acquisitions and $1.0 million on facilities and other expenditures.


    For the quarter, the Company spent approximately 32% of the capital in the Eagle Ford Shale trend, 57% in the TMS and 11% on the completion of previously drilled Haynesville Shale wells.  The Company conducted drilling operations on 8 gross (6 net) wells in the quarter, including 6 gross (4 net) Eagle Ford Shale trend wells  and 2 gross (1.96 net) wells in the TMS. We added 9 gross (4.87 net) wells to production in the quarter, of which 5 gross (3 net) were in the Eagle Ford Shale trend, 1 gross (0.90 net) in the TMS and 1 gross (0.50 net) in the Haynesville Shale trend.  As of quarter-end, the Company had 8 gross (5.32 net) wells drilled and waiting on completion comprised of 2 gross (1 net) in the Haynesville Shale trend, 5 gross (3.33 net) in the Eagle Ford Shale trend and 1 gross (0.99 net) in the TMS.

    For the year, the Company expects to drill and complete 21 gross (14 net) wells in the Eagle Ford Shale trend (down 1 gross (0.7 net) wells due to the reallocation of capital from the Eagle Ford Shale to the TMS), 9 gross (5 net) wells in the TMS and 13 gross (5.7 net) wells in the Haynesville Shale trend.

    TMS Permits

    The map below depicts the latest drilling permits.  2014 should be a more active drilling year.  The locations indicate a focus between -11200 and -13000 subsea true vertical depth.  

    Friday, November 1, 2013

    Upcoming Earnings Calls

    Get the popcorn popping for back-to-back earnings calls for Goodrich and Halcon on November 5.  Sanchez Energy will present on November 7.  It will be interesting to hear their plans for 2014.




    Thursday, October 24, 2013

    Coiled Tubing Challenges

    The TMS has been plagued with challenges while using coiled tubing to drill out the plugs in the horizontal wellbore.  This is not my area of expertise, so I've aggregated some online content to provide some perspective into the process and alternative options.  

    A nice overview:
    Working in the shale plays poses some new challenges for coiled tubing. Currently in these fields a large majority of the wells drilled are horizontal wells. Due to the length of horizontal sections that are now being drilled, one of the challenges has been horizontal reach with the coiled tubing due to helical buckling.

    A 2-3/8” deep well unit working in the Eagle Ford Shale.
    Most wells in these shale plays require some type of stimulation to maximize production. Currently multi-stage hydraulic fracturing is the method of choice. During the hydraulic fracturing, the well is treated from the bottom up. The treatment begins with the bottom treatment zone or stage being perforated and treated. After the treatment is complete a composite plug is set above the zone to isolate it from the subsequent treatments (in the long horizontal sections the plugs are pumped down when they will no longer fall with wireline). The next zone up is then perforated and treated and another plug is set. This will continue until the entire horizontal section has been treated. Wells can have 15 or more treatment stages depending on the length of the horizontal section. After the final zone has been treated the plugs need to be removed from the well. It is not economical to attempt to pull the plugs so a coiled tubing unit is used with downhole motors and mills to drill these composite plugs. These jobs are called “coiled tubing drillouts” or CTDO.

    Buckling of the CT 
    One of the challenges associated with CT operations on extended-reach shale wells is to utilize techniques to delay the onset of CT “buckling” so that CT can reach the target working depth. Buckling of the CT occurs when the axial force required to push the CT to the toe of the well exceeds a critical level. When pushing CT into a long horizontal lateral, the CT first buckles into a sinusoidal shape. As the CT is pushed further into the horizontal section, the increased axial force applied to the CT (required to overcome additional friction between the CT and wellbore) will then cause the CT to deform into the shape of a helix inside the wellbore, which is referred to as helical buckling. Frictional drag forces on the CT will increase exponentially when the axial force applied on the CT exceed the critical helical buckling limit. If additional axial force is applied to helically buckled CT, it will rapidly reach a point where 1 percent or less of the additional weight applied at surface reaches the downhole end of the CT. This is known as CT “lock-up” and will prevent any further movement of the CT into the horizontal lateral.

    Increasing the OD and wall thickness of coiled tubing will help extend the reach of coiled tubing. But it comes with the added size and weight of the extra coiled tubing and larger equipment. Larger, two-trailer coiled tubing units are being manufactured to accommodate the extra weight and bulk. One of the larger two-trailer CTUs has been utilized in the Eagle Ford Shale in South Texas. This unit can carry 23,000′ of 23/8″ coiled tubing. It is 12′ wide x 14’8″ high x 61′ long and has a HR-6100 injector with a pulling capacity of 100,000 lbs. and snubbing capacity of 50,000 lbs. These units can weigh up to 200,000 pounds with a full reel of tubing and are permit loads in the lower 48. These units are not single purpose, their main use is for milling plugs following frac jobs but they also have a history of being a go-to service in horizontal wells for operations such as coiled tubing logging, toe shots (frac prep) and coiled tubing fracturing.

    Horizontal well completions have also led to a step change in the coil tubing manufacturing business. Three years ago the primary market for coiled tubing was vertical well cleanouts and the typical size was 11/2″ and 13/4″ coil with lengths ranging from 17,000′ to 20,000′. Today the horizontal extended reach wells have changed that market mix to 2.00″ and 23/8″ strings ranging from 18,500′ up to 24,000′ in length.

    Larger coil tubing sizes 
    The challenges for coil tubing in the horizontal wells is to make sure the plugs are properly drilled out, getting to the end of the horizontal sections and removing all the debris from the wellbore. The key to accomplishing all of these challenges is the larger coil tubing sizes, higher flow rates and higher surface treating pressures. So not only has the size of the coil strings changed, the wall thickness and grade of coil strings have changed too. In today’s shale play market higher grades of coil tubing such as QT-900 and QT-1000 have become the predominant grades of choice. Wall thickness designs have also changed. In order to operate at surface treating pressure from 7,000 to 10,000 psi, which is needed to clean out these sections and have the tube strength needed to snub in the horizontal sections, string designs have changed to heavier walls usually ranging from .175″ to .203″ wall thickness. As the length of the horizontal sections of the shale plays grows so will the demand for higher strength, larger OD, heavier wall and longer length coil tubing strings. As coiled tubing sizes increase, the need for larger bore pressure control equipment also increases.

    Larger bore pressure equipment
    Larger bore BOP’s are required to run the larger diameter mills, the mills are up to 43/8″ diameter, which is too large for a 41/16″ BOP. The bore size has stepped up to a 51/8″. Depending on the surface pressure it could be 10,000 psi or 15,000 psi working pressure well control equipment. The BOP stacks used have a dual barrier philosophy. The dual barrier provides two barriers between the well bore and the environment in case of an emergency. The BOP will have a blind shear ram in the stack that will be able to shear the coiled tubing and provide a seal after shearing. The Blind shear rams used have been qualified to the most recent API specifications. The additional rams used in the BOP stack include pipe rams, slip rams and grip seal rams. The grip rams are bi-directional and are qualified to hold the coiled tubing and prevent the tubing from moving so the pipe rams can seal on the tubing.

    The BOP stack features include integral equalizing valves, hydraulic ram change, low torque bonnet bolts, metal x metal well bore seals, indicator rods on all rams, and Viton ram seals. The two main bore sizes used are 41/16″ and 51/8″. Depending on the type of CT application that is being run will determine which BOP stack will be required.

    The uppermost piece of equipment in the BOP stack is the Stripper Packer. The latest technology has a design that has two individual packer elements. These high-pressure packer elements will seal around the coiled tubing while it is stripped in and out of the well at pressure up to 15,000 psi. The unique feature of this tool allows the packers to be run alone or in combination. Inhibitors can also be pumped between the packer elements to lubricate the coiled tubing.

    The lower section of the Stripper Packer has a special rotating flange that provides a means to allow a flanged rig up to align the injector, wellhead and the spool if there is a misalignment. The rotating flange was designed for the high-pressure flanged rig ups and has reduced the time spent on alignment in tight job sites dramatically. 

    Milling operations
    The ability of keeping the motor and mill on bottom drilling efficiently and reliably is an economical factor that cannot be overlooked. Drilling 15+ plugs in a single run not only requires an experienced operator with a knack for drilling plugs, it also requires top-of-the-line equipment.

    What is needed in shale play milling operations is an economical, conventional type, power section that can generate higher power and torque, has the proper elastomer to deal with temperature extremes found in the shale plays, and is capable of running on commingled fluids containing N2 or air. A power section capable of generating 75 percent more torque and power (compared to current offerings) allows the BHA to better withstand sudden tension releases in the CT without stalling and allows the mill to “drill through” plugs without having to constantly cycle the CT string off bottom. In addition, a power section capable of generating high differential pressures (i.e., between 2500 – 3300 psi on a 27/8″ power section) means the tool operator can predict potential stalls more readily. As a result, fatigue damage to the CT is substantially reduced due to less frequent off bottom cycling while at the same time increasing ROP. A power section delivering these properties would be a welcome addition to the industry; lowering initial expenditure, delivering increased performance, and reducing costs due to CT cycling fatigue.

    Vibration for extended reach 
    Vibratory tools have been used for several years to overcome the extended reach issue with CT. A tool that can effectively excite the CT string axially, along its entire length, will reduce the fictional drag between the CT and the wellbore tubular. This will delay the onset of helical lockup and also offers a side benefit of shorter plug milling times. There are two main types of CT vibratory tools available. One that utilizes a piston to create the pulses (similar to a downhole hammer) and one that uses a patented rotor/stator arrangement driving a valve pack that creates the pressure pulses. Piston style tools, by design, have to completely block the fluid flow to achieve vibration. This will affect the flow of fluid to the power section and can affect its performance. They also are erratic, and sometimes uncontrollable, when pumping a multiphase fluid or straight gas. The vibration is usually localized close to the tool. The other type of vibratory tool that uses the rotor/stator combination never completely blocks the flow of fluid. The operation of this type of tool is smooth and controlled, regardless of whether a multiphase liquid or straight gas is being pumped through it. This type of tool is widely regarded as the standard tool to use in the shale plays to gain extended reach and decrease plug milling times.

    Roller cones 
    Roller cones are fast becoming the defacto in composite plug milling in the shale plays. A series of roller cone bits, sized from 41/2″ to 43/4″, are in trials now. They feature improved hydraulics and sealed bearings, along with improvements to the roller cone bearing surfaces. Compared to current bit offerings, early indications are extended bit life and improved hole cleaning.

    Straightening the CT 
    Another effective method of delaying the onset of buckling is to straighten the coiled tubing. Although the idea of straightening the coiled tubing has been around for a while, the concept has been effectively utilized in the long horizontal sections of the major shale plays. Contractors have found that removing the residual bend from the coiled tubing can reduce the well bore friction to extend the reach. Most cases the downhole end is straightened to cover the distance from TD to the top of the build section.

    Friction reducers 
    Another method to delay the onset of buckling is the use of friction reducers and other chemicals. Use of friction reducers is the simplest method because it is an additive to the mud system and utilized “as needed.” Most mud companies will provide personnel, and chemicals for coil tubing drillout operations. CTDO require blended sweeps to clean out the wellbore after each plug is drilled and regular additions of friction reducer, to the active fluid system. In addition surfactants, in conjunction with friction reducers, helps reduce friction as well as torque and drag during coil tubing operations. Friction reducer also reduces the surface tension of the drillout fluid which in turn aids in friction reduction, allows the fluid to more easily flow back, and minimizes the amount of friction reducer required during the CTDO. Other optional products that may be used during a CTDO are lubricants and coil tubing corrosion inhibitor.

    Take your pick 

    These are some of the options to the challenges of coiled tubing while working in the long horizontal sections now being drilled. There is no hard and fast rule about which method or methods should be used. Some operator’s use the economical approach of “just enough to get me there” and others use all of the above, “remove all doubt” approach.


    A nice comparison of workover rigs versus coiled tubing: 
    Workover Rig
    Many times, remedial work constitutes employing a workover rig to repair the well. Similar to a drilling rig, a workover rig is smaller and requires no mud pumping or pressure-control systems. A workover rig is used to retrieve the sucker rod string, pump or production tubing from the well or run wireline cleaning and repair equipment into the well. It is important to note that with workover activities, production must be stopped and the pressure in the reservoir contained, a process known as “killing” the well.

    Coiled Tubing
    A cost- and time-effective solution for well intervention operations employs coiled tubing. Instead of removing the tubing from the well, which is how workover rigs fix the problem, coiled tubing is inserted into the tubing against the pressure of the well and during production. Coiled Tubing Coiled Tubing Source: US Department of Labor The coiled tubing is a continuous length of steel or composite tubing that is flexible enough to be wound on a large reel for transportation. The coiled tubing unit is composed of a reel with the coiled tubing, an injector, control console, power supply and well-control stack. The coiled tubing is injected into the existing production string, unwound from the reel and inserted into the well. Coiled tubing is chosen over conventional straight tubing because conventional tubing has to be screwed together. Additionally, coiled tubing does not require a workover rig. 

    Because coiled tubing is inserted into the well while production is ongoing, it is also a cost-effective choice and can be used on high-pressure wells. Coiled Tubing Operations All performed on a live well, there are a number of well intervention operations that can be achieved via coiled tubing. These include cleanout and perforating the wellbore, as well as retrieving and replacing damaged equipment. Additionally, some advances in coiled tubing allow for real-time downhole measurements that can be used in logging operations and wellbore treatments. Enhanced Oil Recovery (EOR) processes, such as hydraulic and acid fracturing, can also be performed using coiled tubing. Furthermore, sand control and cementing operations can be performed via coiled tubing. 

    Source: Rigzone

    A nice video illustrating coiled tubing being used to drill out plugs:

    Wednesday, October 23, 2013

    Encana Earnings Call - 10/23/13

    Here are the TMS highlights from Encana's conference call today:

    Mike Rimmel - Barclays Capital
    Hi, thanks for taking my questions, two from me. Would you mind talking about any infrastructure constraints you guys maybe facing going into the next year particularly wondering about Piceance area? And then, the next one is, just wondering whether there are any updates on the TMS, I know you were in the middle of [indiscernible] wells last quarter? And that’s it from me, thanks.
    Michael G. McAllister - Designated COO
    Hi Mike, it’s Mike McAllister here. Yeah, first on with respect to infrastructure constraints, we were actually in really good shape here in Bighorn. We have contracts to take all of our product out of that area with – so we’re feeling very confident with respect to that. Up in Peace River Arch, we actually again have, we’re in really good position, we have aligned to our growth out of the Peace River Arch with infrastructure actually that’s being built. And that’s in private chip as well. And I think your third question was related to the TMS and three of the last four wells are meeting, are actually exceeding type curve. The other well, the fourth well if you will below type curve but we understand and that specific well that is was frac communication and re-interference that affected that. So we understand what that issue is and ready to move forward.
    Matthew Portillo - Tudor, Pickering, Holt & Co.
    Great. And then, just in regards to TMS, you mentioned that the curves are performing at kind of your expectation on three of the wells, could you remind us how you guys think about the EURs in the play and then what you need to see from here to progress that towards commercial development?
    Doug Suttles - President & CEO
    You know Matt well, well Mike grabbed some of the data, you know, I think the way we are thinking about the TMS is that, we really need to gain the confidence, we really need to move forward rapidly there which is around the type curve not only the early performance on the type curve which as Mike said, we are very encouraged but I would like to get a bit more time under our belt. The second thing is, we have a massive land position there, I think, over 300,000 acres and as we think about that play we need to actually make sure we are confident in the rocks across the play. And the last thing is confident that the costs are coming down, this will be a big focus in 2014 and I hope by the time we exit the year, we actually know the answers to those questions.
    Michael G. McAllister - Designated COO
    And just with respect to what we’re targeting approximately 600,000 barrels oil equivalent per well.
    Matthew Portillo - Tudor, Pickering, Holt & Co.
    Okay and just one clarification there, so as you guys think about the wells you’ve seen so far is, is the big takeaway that we should think about it effectively the initial production is meeting your curve expectation, but you’d like to see longer term data before gaining additional confidence in that kind of getting to that 600,000 curve?
    Doug Suttles - President & CEO
    Yes, absolutely with all of our plays, you see initial IPs very encouraging, but really we want to see sustained production performance and see how well it matches, what are resolute modeling telling us, so really need to see some history there to give us the confidence.
    Michael Dunn - FirstEnergy Capital
    Good morning or good afternoon everyone. Couple of questions one on the TMS one and the San Juan, on the TMS guys just wondering what your latest thinking is on completions in terms of I believe on the last call or earlier this year, you were talking about targeting completing it above the rubble zone and it seems like we have had maybe some mixed results above or maybe a couple of wells what might like they may have been better below the rubble zone, so just wondering if you are still confident in targeting above the rubble zone? And in the San Juan, you have mentioned 400 to 500 barrels a day, 30 day period there, how should we think about that relative to the targeted EUR you guys talk about the 550,000 BOE EUR, is that sort of above that or on trend with that EUR you talked about? Thank you.
    Doug Suttles - President & CEO
    Yes, I think Mike this is Doug, I think on the TMS, I think we would probably need to get you on that level of detail about the completion, I can tell you that the big focus there has actually been on changing the completion design itself, changing the frac design which clearly made a big improvement in the last few wells. But I would also caution that I don’t think we believe we’ve yet get the best formula and that will be part of the plan in 2014 and Mike if you want to pick on them San Juan well and --

    Entire transcript:

    Sunday, October 13, 2013

    Contango Applies For TMS Units

    Conterra Company, Contango's subsidiary, is applying for two TMS units in Northeast Spillman Field (W. Feliciana Parish).  Both units are 995 acres and are just east of Encana's existing units.  The TVD of the TMS in this area is -13300'.  Being located inbetween three underwhelming Devon completions, this will present an interesting opportunity for Contango to prove the value of the area.  We look forward to having a new operator joining the mix.

    Crimson and Contango just recently merged:

    Friday, October 11, 2013

    EOG Paul 15H-1 Results

    The results for the 15H-1 have been posted on SONRIS.

    COMP 07/01/13: OIL, TMS RA SUA, 181 BOPD, 140 MCFD, 773 GOR, CK OPEN, GVTY 47.5, BWD 118, BS&W 39%, FP 448, CP 448, PERFS: 11682'-16348'

    This well lost a string of pipe in the lateral and has been producing with this obstruction. Deciphering the result is not possible.  I estimate this local area to have ~90' of pay and 118' of higher resistivity which should result in attractive rates and economics.  I would expect EOG to twin this location at some point in the future.

    Thursday, October 10, 2013

    Goodrich Announces The Result For The CMR-Foster Creek 20-7H-1

    Goodrich announced the results yesterday for the 20-7H-1.  Once again, we have a well that encountered issues while drilling out the plugs.  Losing a bottom hole assembly is not the norm.  The current thinking appears to be that coiled tubing is not the best approach for this process in the TMS.

    A detective is required to assess the results from the well being that the initial test is only from a portion of the completed lateral.  The quick "back of the envelope" math would say that 527 boepd over 2100' could possibly equate to 1581 boepd for a 6300' lateral or 1555 boepd for the 6200' that was actually stimulated.  That's not a stretch, but we don't know for sure.  

    I believe that the reservoir rock in this location is as good as the Crosby 12H-1.  The goal for this well was repeatability.  I'm confident that our stellar engineers will solve this problem in the near term.  The goal will be to not add additional costs, but increase the probability of completion success.

    HOUSTON, Oct. 9, 2013 /PRNewswire/ -- Goodrich Petroleum Corporation (NYSE: GDP) today announced the completion of its CMR-Foster Creek 20-7H-1 (99% WI) well in Wilkinson County, Mississippi. The well was successfully drilled with a 6,200 foot lateral and fracture stimulated with 23 stages but encountered completion issues while drilling out the frac plugs with coiled tubing resulting in the loss of a bottom hole assembly and fishing tools in the well. The Company replaced the coiled tubing unit with a workover rig in an attempt to remove the downhole tools but fishing operations were un-successful. The well was subsequently placed on production from the approximately 2,100 feet of usable and unobstructed lateral.
    The well has reached a 24-hour peak production rate of 527 barrels of oil equivalent ("BOE") per day, comprised of 500 barrels of oil and 174 Mcf of gas on a 16/64 inch choke from the 2,100 feet of lateral.
    The Company is currently drilling the lateral of the Huff 18-7H-1 (97% WI) well in Amite County, Mississippi, with plans to go to two rigs later this month.
    The Company currently has in excess of 300,000 net acres in the Tuscaloosa Marine Shale.

    The entire press release:

    Tuesday, October 1, 2013

    Encana's New Strategy

    A good article outlining Encana's corporate strategy:

    In his first 100 days on the job, Encana CEO Doug Suttles made it clear that significant changes are in store for Canada's largest natural gas producer.
    The company has seen its workforce drop by about 300 people so far this year and, when 3,800 employees gather for a town hall meeting with the new boss today, they will all be well aware Suttles has told investors current organizational structure is more aligned with Encana's past than its future. "Maintaining the status quo is not an option," Suttles has said.
    When he steps onto the stage at the BMO Centre to address staff in Calgary, it will provide many of them their first real opportunity to see and hear the man who has been charged with reviving what was once Canada's dominant oil and gas producer. For some, it could also be the last time.
    Suttles, who was hired from BP in June, has said Encana will develop fewer properties, bring in a new corporate structure and capital controls as well as better aligning its compensation with persistently low natural gas prices. The company, which had 4,197 employees at the end of 2012, has cut seven per cent of its staff in the first half of this year and
    Suttles warned after the second quarter that further cuts - but not a general layoff- are likely through year end.
    That's quite an introduction - his employees will be keen to see what he does for an encore.
    They didn’t need to wait long. On Tuesday morning Encana announced five senior executives – including Jeff Wojahn, president, Eric Marsh, senior vice-president, of the USA Division – would be leaving as part of a new organizational structure.
    “Doug wants to say it face to face with staff and take their questions,” company spokesman Jay Averill said in an e-mail Monday. 
    Suttles will hit the road this week to speak to staff in Colorado and Texas.
    The issue of job security is bound to be top of mind for some in the audience but Suttles will present a clearer vision of his overall strategy for the $13-billion market cap company. He has said Encana will exit a number of its 28 plays in North America to focus on top assets such as the Duvernay in Western Canada and the Tuscaloosa Marine Shale in the Southern U.S. Suttles told the Barclays investment conference in September he would reveal details of the strategy in the weeks ahead and incorporate them in Encana's 2014 budget.
    "We need to change in a big way, in a bold way," Suttles said in New York.
    Those types of statements are bound to resonate through a company but Averill noted the sentiments were rooted in the company's internal feedback process.
    "When change is spoken about it's quite natural for people to wonder how it will specifically affect them," said Averill. "Doug's comments about change ... were actually drawn from staffsurveys where the vast majority of staffhave said they want and expect significant change."
    Encana has been in change mode for some time, selling assets - mostly dry gas properties - after losing half its market value since 2010. The stock has been held down by the pronounced decline in natural gas prices which began in 2008, the year before former CEO Randy Eresman spun out Encana's profitable oilsands business as Cenovus Energy.
    Encana shares were up 21 cents in Toronto after the announcement Tuesday to $18.01 — still well off the 52-week high of $23.86. Encana shares were up 21 cents in Toronto after the announcement Tuesday to $18.01 — still well off the 52-week high of $23.86. 
    The changes promised by Suttles may be big and bold but they will pave the way to an era of restraint.
    When natural gas were robust five years ago, the attitude in the oil and gas industry was for aggressive production growth. After the fracking revolution unlocked vast new supplies and prices collapsed, companies like Talisman Energy and Encana are putting a premium on financial discipline and profitable production.
    Suttles has sought out internal and external assessments of Encana's assets and business strategy to augment his own review of the company's strengths and weaknesses. It's already shifted the focus from dry gas to produce higher value crude oil and liquidsrich gas.
    While Eresman had been optimistic of a return to better natural gas prices, Suttles has warned North American gas prices will be "rangebound" from $3.50 to $4.50 US per million British thermal unit in the next few years. He's pledged to make capital discipline key to his strategy and has said Encana would "evaluate" its 20-cent quarterly dividend payment as part of its strategic review.
    As part of his pledge to investors, Suttles has said "Encana will be back to winning" - it just this time around it may be winning small rather than winning big.

    Thursday, September 12, 2013

    Encana Provides An Update

    Encana provides an update:

    CALGARY, ALBERTA--(Marketwired - Sept. 12, 2013) - Encana (TSX:ECA)(NYSE:ECA) President & CEO Doug Suttles will provide an update on the company's strategy development process today at the Barclays CEO Energy-Power Conference in New York City.

    Encana engaged internal and external advisory teams to conduct a rigorous assessment of the company's assets and identify the company's strengths and challenges to inform the strategy development process.
    "Initial insights from the independent research combined with our internal analysis showed that Encana's strengths include our vast amount of resources, our robust knowledge of market fundamentals and a proven ability to develop and operate plays very cost-effectively relative to our industry peers," says Suttles.
    In particular, the assessments found that Encana is excellent in the development of very large scale and complex resource reservoirs.

    The assessments also identified several areas where significant changes are required to be successful. Encana has more inventory in its portfolio of plays, particularly dry natural gas, than can be optimally developed. The company must focus its portfolio and concentrate capital in the assets that leverage its strengths and generate the strongest returns. Further, the organizational structure must be fully aligned with the strategy going forward.

    "The resounding message I have received from our shareholders and staff through surveys, focus groups, meetings and interviews across the organization is that they are ready for change and maintaining the status quo is not an option," says Suttles. "I have every intention of making significant change in the areas where improvement is required."

    The company's strategy, supported by a strong balance sheet, will be built on four core competencies:
    1. Resource Identification - It is critical to have world class skills in this area and focus efforts on the highest quality plays and leverage Encana's operating skills.
    2. Market Fundamentals - Encana expects that future oil and natural gas prices will remain volatile. Understanding hydrocarbon type differentiation and regional factors will become increasingly important. This knowledge must be strongly linked to portfolio decisions and capital allocation.
    3. Capital Allocation - Capital decision making must be centralized, focused, completely aligned with strategy and driven by returns.
    4. Operational Excellence - The company's internal and external assessments demonstrated that the difference in capital and operating efficiency between the top performers and the industry average in core plays with scale can be twenty percent or greater and that Encana has consistently performed amongst the best competitors in these areas. Leveraging the company's development expertise will be crucial to achieving higher returns.

    In addition, maintaining a strong balance sheet will be critical to consistent delivery of strong financial performance and to support the company's ability to capture new opportunities.

    "Over the coming weeks, we will be finalizing our strategy and building our implementation plans. Many of the building blocks for success are in place, but in several areas significant change is required," says Suttles. "I am confident that the organization is ready for what lies ahead and I'm fully committed to driving the necessary change that will get Encana back to winning."

    Doug Suttles' presentation to the Barclays conference will be webcast live today (Thursday, September 12) at 10:25 A.M. Mountain Time (12:25 P.M. Eastern Time). The live presentation and presentation materials will be available on Encana's website at:

    TMS Vendor Expo

    Take note of this upcoming event:

    The TMS Expo Committee would like to extend an invitation to your company to participate in the 1st Annual Tuscaloosa Marine Shale Vendor Expo. Your attendance will greatly benefit your company and the many clients that are in attendance. The Expo will be held on Wednesday, October 16th and Thursday, October 17th, 2013, in Summit, MS, and is hosted by The SMCC Training Center. This event is designed to help bring together the suppliers, exploration companies, truckers, safety consultants, operators, producers, hospitality, tourism and those who provide technology solutions to help develop a more efficient supply chain.

    For more details:

    Monday, September 9, 2013

    TMS Market Sentiment

    For all of the TMSers, it's been quite a roller coaster ride over the past few years.  The "highs and lows" have exhausted many, but the "little shale that could" continues to impress.

    Examining market sentiment always provides some interesting lessons in psychology.  In most cases, understanding the "mass psychology" of the herd is the key.  The herd always moves in mass, and at times, very quickly.

    Many believe that Goodrich Petroleum's stock price (GDP) is a great barometer for the TMS.  When comparing operators, Goodrich has the most leverage in the play.  The recent Devon acquisition would indicate that they are "all in" with regards to the TMS.  Stock prices are indicators of sentiment.  When the herd is positive and greedy, prices rise.  When feeling negative or fearful, prices decline.  

    Having now authored this blog since March 2011, I have the ability to track viewing activity.  With these data, I can examine historical trends in usage.  The chart below integrates the monthly closing price for GDP and page views on this blog.  This geologist concludes that there is a nice, tight correlation between these disparate datasets.  I don't believe that one controls the other, but they are two separate indicators that align and indicate the trend of TMS market sentiment. 

    To take it a step further, I've added recent transactions (yellow) on the chart below.  These offer additional evidence that there's been a significant shift in sentiment of late.  Whether you call the Devon sale "distressed" and the Sanchez deal "too close", the trend is still apparent.

    Both Wall Street and U.S. operators have been very slow to migrate to this play.  The tide appears to be rapidly turning.  Goodrich's target of $5000 per acre might be the next quantum leap.