Any correlation between wellhead pressure and future production?

Started November 20, 2013 at 03:45 pm by @Kagay in Eagle Ford Shale

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11/20/13 03:45:09PM

Is there any correlation between early wellhead pressure readings and how it declines over time, and successful production numbers? What is a good pressure to start out with and what is an acceptable reduction over time?

Within a couple of days after first production, C5H (A-1052) in Gardendale, LaSalle County, was reading at about1900 psi. This was on Sep. 1. The next time I visited the site on Oct. 16, the reading on the tree was at about 1185 psi. RRC site production numbers for Sep. were recently posted and was at about 14,800 bbls for that month, the first full month of production.

I understand that I should expect a decline in production after three or four months (or more if lucky). Is this pressure drop indicative of anything to expect in the way of production decline? Where do these pressure numbers fall in relation to other wells? Normal? Less? Is there any correlation between pressure and what we will see in future months for production? Seems like there must be, but have no idea what this tells about the overall picture.

I assume that when pressure drops to zero that pump jacks will be installed. Or is it at pressures somewhere higher than zero that the decision to install them begins?

Thanks in advance for any insights you can provide!


11/20/13 11:45:55PM @mark25:

IMO very difficult to make conclusions from just pressure readings. What you don't know when you are looking at pressure readings is the choke size associated with the pressure. Operators will adjust choke to either increase production or decrease rate. Smaller choke = higher pressure and vice versa.

Another issue that impacts relationship of wellhead pressure to timing of artificial lift installation is the pressure of the gas gathering line and whether or not comppression is in place to "push" gas into a line if needed.

Bottom line is that one needs to know the details of a full range of issues before making any conclusions tied to wellhead pressures.

11/21/13 10:40:01AM @kagay:

Thanks Mark. Yes, I figured choke size was integral to the discussion and CHK confirmed that they are using a choke but could not tell me what size. Got you on the pipe line issue.

So with the same variables in place, whatever they may be, realizing a drop from 1900 to 1200 psi in a month and a half is not indicative of reasonable or sub-par performance on wells in this area?

11/21/13 01:33:43PM @mark25:

A 700# drop over 45 days is a reasonable decline as I see it.

Using an example from a really good EF well in Dimmit County (CHK Lazy A Cotulla 1H), I see a 550# drop over the first 45 flowing days or 1650# to 1100#. I know that this was on a constant choke.

Even more important, when well has shut in for a couple of months due to offset drilling from same pad, the SIP got up to 1450-1500# in a very short time frame.

Based on production decline curve analysis, engineers are giving this well about 500 MBOE EUR numbers.

11/22/13 02:08:56PM @kagay:

Do you by any chance have 60, 90, and 120 day pressures on the same choke size for that same well? Anything on a different well in Gardendale?



11/22/13 08:47:05PM @mark25:

With respect to the Lazy A Cotulla 1H:

  • Initial FTP @ 1660#
  • 30 day FTP @ 1200#
  • 60 day FTP @ 1100#
  • 90 day FTP @ 1140#
  • 120 day FTP @ 1070#

Same choke size / well was flowing continuously during this 4 month time frame with no shut in periods.

I believe the increase @ 90 day mark is tied to different frac stages kicking in and starting to contribute over time.

Sorry, but don't have any info of this nature for the Gardendale area

11/23/13 09:29:49PM @kagay:

If it's alright to share this, do you have an abstract or lease number so that I can look up the production numbers that correspond with those numbers?
Is this a typical case, exceptional, or what?

Your remark about other frack stages kicking in is interesting. I just assumed that all the stages would all be producing at approx the same time. I would have figured that neighboring fracking might re-excite flow in certain areas of an existing lateral, but never thought that different areas of a lateral would produce at different times. Tied to pressure drops as other stages flow out?

As to the neighboring frack effects on existing laterals, I've read where owners commented that production on the existing lateral increased. Is it just as common for existing production to drop off after an adjacent fracking?

Mike Chandler
11/24/13 05:18:52PM @mike-chandler:

The temporary increase in FTP would indicate more gas/less liquid in the vertical production string at that time. If some of the frac zones are more gassy than others and some are higher pressure than others, it wouldn't surprise me to see fluctuations in both oil cut and FTP (at surface). Remember - FTP is a result of BHP/choke size/liquid content.

11/24/13 05:35:58PM @mark25:

This info is from the Chesapeake 1H Lazy A Cotulla in Dimmit County. Trying to look at the specific well production will be difficuilt since there have been multiple wells drilled on this unit and all the production as been combined on a lease basis.

IMO Lazy A Cotulla is one of the better EF producing areas in S Tx part of the trend.

Changing gears - not all perfs / frac clusters are producing at the same time and with the same degree of input (e.g. 20 frac stages with each contributing 5% of the total production). Various factors serve to limit frac stage contribution over time - remember heterogeneity in the reservoir impacts frac propogation. Production logs run post frac and after some production has shown in almost all cases that there is a wide range of contribution along any horizontal - in some plays like the EF, there are zones that are producing nothing early on that then begin to produce later in the well life.

Last point - frac's in offsetting wells may or may not impact the original well IMO. Depends on well spacing / distance between horizontals, how the well is frac, presence of natural fractures, timing of new frac vs older frac'd well (e.g. pressure decline in older well), etc.

Need to keep in mind the complexity of both the reservoir as well as the manner in which induced fractures are created in the EF reservoir when trying to understand well performance and overall reservoir performance in any one productive area.

11/24/13 05:48:09PM @mark25:

Re: Lazy A Cotulla 1H Production

Managed to extract the daily production rates and pressures plus associated details (e.g. SI periods) for this well covering its first 14-15 months of production. Data is attached in EXCEL spreadsheet.

11/24/13 08:39:49PM @kagay:

Wow - quite a bit to chew on - thanks so much. Impressive well, at least based on the small number of wells that I am familiar with. There are a few acronyms that I could not track down - SAA, FTP vs FCP (pressure, but what is the differentiation?), to name a couple. SAA relate to artificial lift?

11/24/13 08:54:48PM @mark25:

SAA = same as above

FTP = flowing tubing pressure

FCP = flowing casing pressure

FCP ties to pressures prior to tubing being installed / FTP after installation. Apparently they were still getting some flow / pressure up annulus between casing and tubing after tubing installation.

11/24/13 09:00:00PM @kagay:

So no artificial lift in the months shown?

11/24/13 09:40:14PM @mark25:

No artificial lift during the time frame in the file (see comments section) but you do have a series of issues that are common to EF wells:

  • Tubing installation
  • SI for offset frac / drilling operations
  • Central compressor problems impacting flow rate
  • SI due to lack of tankers to pull oil out of on site storage tanks
  • VOC testing (air quality control) / emissions)
  • Gas pipeline hook up

11/24/13 09:54:10PM @kagay:

What part does the compressor play if not lift assist?

11/24/13 10:51:58PM @mark25:

Re: Compressor

The compressor in question is the central compression unit on the central gas gathering system (at Dilley) that all the CHK wells were flowing into at this time. Compressor helped maintain a lower overall line prressure that allowed all wells to get their gas into the line. When central compressor went down, line pressure increased and ended up shutting down or reducing rates on many wells that did not have sufficient flowing pressures to "buck" the higher line pressure.

11/25/13 01:19:42PM @kagay:

A few notes/questions on the spreadsheet data -

After the first month drop in casing pressure, the pressure remained the same for the next six months, but the production steadily dropped to 15% of the first month. So - not very much correlation between pressure and production. Pressure stayed up as production dropped off.

On the seventh month, production jumped back up to about 50% of the first month and then did a roller coaster ride down to 30% at the 14th month. The casing pressure similarly jumped back up to above initial pressures after month six and continued to hover above month 1 pressures till almost month 11 (so some correlation between pressure and production both went up), and then trailed off steadily to nada in casing pressure, but 600 or 700 psi tubing pressure. Why this crossover between tubing and casing pressures?

Choked back between month 6 and 7 means reducing choke diameter?

11/25/13 01:50:20PM @mark25:

Choked back = smaller choke size / choke size listed in column on the left side of spread sheet ("ck") in top number of a "X/64" choke measurement, e.g. 18 = 18/64" choke.

Cannot explain the tubing vs casing pressure crossover.

Make sure you are not taking SICP readings as flowing pressures - these are Shut in Casing pressure readings.

I don't know the intimate details behind the plumbing and results tied to all these daily data points - just received the data and tried to capture as much info as possible for future reference.

Hope this helps

11/25/13 02:51:33PM @kagay:

Yep - thanks Mark. I did not take into consideration the SICP readings.

11/27/13 06:09:49PM @kagay:

Going back to FTP vs FCP - the two gauges that I see on the tree when I visit the site - one digital and one analog (both read the same) - is this more than likely tubing pressure or casing pressure?

Where are the sensors for the two different pressures located in the scheme of things? Is the casing pressure sensor down at the bottom of the vertical shaft and the tubing pressure sensor at the top ?

11/27/13 09:02:13PM @mark25:

With respect to gauge location and tree set up, I am no expert - hopefully a field ops person will be able to comment with confidence on this.

I would assume that the gauges on the tree are tied to tubing while gauges at base of tree is related to casing pressures.

11/28/13 02:26:49AM @mark25:

Appears to be compressor - these will be needed on all wells once pressure drops in order to "force" gas into gas gathering systems.

MidCom is a Chesapeake midstream company.

11/29/13 04:19:12PM @kagay:

Got curious about the current pressure and snapped this picture yesterday. I wanted to also determine the choke size but did not know how to find and read it. I labeled my questions about the tree on the attached picture. Anyone help me with answering the labeled questions? (especially the FTP gauge question, and which valve indicates the choke size and how do I read it, but all questions if possible)

The top two valves read 983psi; the bottom ones read zero.



11/29/13 06:09:24PM @mark25:

#1 and #3 are tubing and casing pressure gauges, respectively. Pretty sure #2 is the choke control box but don't ask me how to find choke size on this unit.

Red unit (#7) appears to be the "recorder" where all the digital feeds from tubing, casing and choke indicators are coming into. This in turn should go to a digital recording system and/or remote feed to operational hub.

All the other items are valve controls that allow the flow to be cut off at multiple places. Lots of redundancy here.

I would welcome more input from more knowledgeable field people on any aspect of this tree set up.

11/29/13 06:29:13PM @kagay:

Great start - thanks Mark. If 2 is the adjustable choke, perhaps I can find the model in web images and find out how to read it - shot in the dark. I too still welcome additional info from any other experts.

11/29/13 06:31:03PM @mark25:

Any idea what the choke size and flowing pressure was on the IP report for this well?

11/29/13 06:39:51PM @kagay:

Is the IP report generally available to owners? If so, where - the RRC?

11/29/13 06:43:54PM @mark25:

Yes, all this info is available on the Tx RRC site. Plus directional data and many other filings.

If you know well API number, you can search for all this data.

Or I can find it for you on DrillingInfo (who get most of their data from RRC)

11/29/13 06:59:28PM @kagay:

I did a quick search and have not found the right area of RRC yet. I found the directional data one time before but do not recall the path. Can you refresh my memory on where on RRC I can find this?

11/29/13 07:03:30PM @mark25:

Link to Tx RRC completions section below

If you have API info,this is best option.

If not, suggest you go to operator and lease info section and follow the prompts to find correct data for search

11/29/13 07:21:46PM @kagay:

Found it: FTP-1829psi, 594 bbls, 11/64 choke

11/29/13 07:27:13PM @mark25:

How long ago was that? How many months of production has there been so far?

11/29/13 07:38:50PM @kagay:

The IP report was dated 11/11/2013. Completion or recompletion date was 7/22/2013. Date of test was 8/30/2013. Production started 8/28/2013. We only have production numbers from RRC for Aug and Sep.

11/29/13 07:58:33PM @kagay:

You mention that the DrillingInfo site gets most of their data from RRC, but anything of interest more than that? CHK gives more complete production data to "large ranchers" of which group I do not belong. A bit galling. ( I don't get it. We are all in this together.) So, naturally I would be interested in finding more data, such as what you supplied on the Lazy A Cotulla well, if it were available.

11/29/13 08:56:36PM @kagay:

Now that you've got me looking at the IP report, I notice something else that I am curious about - under "Formation Record" it lists the top of the Eagleford at 8228 and "MD:" for the Eagleford at 8346. Can you tell me what "MD:" stands for? Is this the bottom of the formation? (pretty thin if so)

11/29/13 10:14:16PM @mark25:

I don't have access to additonal data like that from the Lazy A Cotulla 1H. Sorry.

11/29/13 10:16:22PM @mark25:

MD= measured depth

Other depth listed (8228) is most probably TVD - true vertical depth.

These tops are listed like this due to hole being deviated at top of the Eagle Ford formation.

11/29/13 10:34:00PM @mark25:

Was there a H-9 filing for your well? H2S.

Also what is GOR based on IP and production data? Lower GOR will mean more rapidly dropping pressure (assuming constatnt choke size) and quicker move to artificial lift (which would be some sort of pumping unit if you are looking at low GOR)

11/29/13 10:35:20PM @kagay:

Makes sense - thanks.

The IP data you asked for - did it add up to any particular conclusions? What did you learn from it?

11/29/13 10:40:16PM @mark25:

To make any signficant conclusions, I need all the IP data including GOR and volumes produced prior to test. Plus overall length of perf / completion interval as well as the general frac info that is normally part of the conpletion paperwork.

Right now I would say that pressure is not bad considering choke size - but rate seems low.

WIthout knowing, I would guess this is alow GOR well (i.e. 250-300:1 range). Not a lot of reservoir energy to move more oil from reservoir into fractures if this is the case.

Gas volume? Water volume?

11/29/13 10:54:14PM @kagay:

Yes, there is an H-9 document.

If GOR is "Gas-Oil Ratio", then that is 304.

I'm not sure if I know how to correctly report that for production numbers, but I'll take a stab at it - looks like 5481 mcf/14754 bbls=371 (?)

What do you make of it?

11/29/13 10:57:58PM @kagay:

OK to share the API in this forum?

11/29/13 11:05:35PM @mark25:

H-9 = some H2S so negative impact on production / negative ding most likely on oil price due due probable sour nature of oil.

As I expected, pretty low GOR which will mean some pretty steep decline and installation of artificial lift pretty quickly.

How much water was being produced in the IP test?

Could you post the completion data?

If the production info that you sent recently is the first full month of production, about 500 BOPD - less than the IP rate. This is normal to see - usually don't see initial full production match IP rate.

Using the 500 BOPD for first full month, I am figuring on about 100 BOPD at end of first year. So roughly about 100-110 MBO production in first year.

03/19/17 04:02:44PM @kagay:

Nice prediction! Turned out to be 108,561.

11/29/13 11:08:12PM @mark25:

Purpose of the Forum is to share info and foster communications back and forth to address questions and concerns. The more data shared - the better product.

Of course, it is up to the individual as to which data to post. Many have opted to keep specific well data confidential for a variety of reasons.

11/29/13 11:15:18PM @kagay:


11/29/13 11:34:06PM @kagay:

To come full circle, and as mentioned earlier, the FTP pressure is down to 983 psi as of yesterday and we are now at about 90 days. This follow along with your synopsis?

11/29/13 11:37:48PM @mark25:


Completion report attached. Standard length lateral for CHK in this area (about 5000') . Proppant volume not listed but over 5 MM gallons of fluid used during frac.

Also looked up H-9 - less than 10 ppm H2S but there will still need to be special treatment and/or pipeline for the gas. OIl may also have sulfur content which may require different handling and purchasing agreement (and related fees).

Lateral appears to have been placed @ 8405' TVD or about 170' into the Eagle Ford (which should put it in the lower third of the Lower EFsweet spot)..

Concern as to the low water volumes produced during IP test. Considering that over 119,000 bbls of frac fluid were used and that CHK normally would like to do post frac flowbacks of up to 100 total bbls of fluid per hour (2400 bbls per day), to have such a low water rate this early in post frac flowback period is a bit disturbing. This low water volume rate (should be closer to 1000 bbsl and not 130) may be tied to issues with low reservoir energy (which ties to low GOR).

Overall bottom line is that decline may be much higher than expected.

Will be interesting to monitor production over the coming months. Operator may be choking well back to keep it flowing but this would result in lower rates.

11/29/13 11:46:53PM @mark25:

Without knowing choke size, it is hard to address this. Losing half its FTP pressure over 90 days with constant choke is one thing. Having pressure this low in parallel with having to reduce the choke to keep pressure up is another thing, i.e. much steeper decline.

I believe you mentioned earlier that there are compressors on location. With FTP at 983#, needing to have compression on location already for this well must mean some pretty high line pressure on the gas gathering line.

11/29/13 11:55:43PM @mark25:

KKL area is definiitely a different animal than the Lazy A Cotulla area. LAC area has higher GOR's, more steady pressures / less decline and much better reservoir quality vs. that seen in the KKL area.

The reservoir quality issues plus lower GOR will make EUR's in KKL area much lower than that in the LAC area.

11/30/13 12:04:26AM @kagay:

Interesting background on issues pretty foreign to me (water, etc.) to this point. Thanks for the new info. I expected pretty steep declines based on most area wells performance to date (attached spreadsheet), but was hoping for slightly better than 80%.

If you were fitting the bill for drilling, would you drill infill wells on this lease based on data up to this point, or is it way too early to tell?

11/30/13 12:05:55AM @kagay:

No, the compressor remark was by a different contributor. No lift assist as yet.

11/30/13 12:07:52AM @kagay:

Still profitable "enough" to the driller?

11/30/13 12:16:56AM @mark25:

Interesting data on other wells in LaSalle County area. Lots of variability.

If it were my company and the one well on production was holding the entire unit HBP, I would be in no hurry to drill addditonal infill wells. I would want to see some long term well performance and decline information.

Building on this, I would be seriously considering looking to sell off these and other properties in the area based on actual production and projected untapped reserves in the offsetting well locations.

This is similar to to Devon buying Geosouthern's undeveloped acreage in Dewitt and Karnes County.

Each operator / company has their own ideas as to ROI objectives and overall economics. Public companies have different drivers than private equity based companies vs private companies with no equity partners.

And oil pricing in the future impacts these decisions. .

My bet for KKL area is that CHK will not be drilling any infill wells for several years. But that is just my opinion.

11/30/13 12:21:00AM @mark25:

Time will tell - wells will most probably payout but actual ROI will be tied to oil price futures. I am still concerned with the initial year decline here due to the low GOR and associated water rates in IP filing.

See my comments in recent posting - I don's see CHK doing infill drilling here unless theysellout to another party who want to accelerate production and cash flow in this specific area.

11/30/13 12:25:54AM @kagay:

Thanks for your educated opinion and candidness.

Is it common for big companies this day and time, with all their research capabilities, to sink a lot of effort and funds into a big pad (12 acres estim.) and huge water tank (400' sqr +/-) and not drill all the wells shown on the plat ? (10 wells total)

11/30/13 12:57:20AM @mark25:

I wouldn't over estimate a company like CHK's research capabillities since there is little to no research being done by them on these wells. They have rarely logged a horizontal well and have minimal corefrom the target section.

The key to their evaluation of the play is post frac drilling results and associated per well economics and looking at those "trends" from area to area.

The costs of building a large location and frac pond is minor compared to drilling costs. Having surface location work completed up front and not having to add more space later is a plus - especially for a potential buyer.

And since an operator cannot predict post frac well results, taking a chance of putting out a little extra money pre drill makes a lot of sense.

Once CHK gets some long term production history, they will determine if infill wells at the "X" ROI for this unit are merited.

11/30/13 10:45:05AM @kagay:

Good to know from a personal planning standpoint - don't want to count the eggs so to speak if this thing is going to likely drag out for a long time and be of debatable return.

Speaking of the water issue you mentioned, and diverging from the FTP topic again, there is a water disposal unit right across the road from this pad. (1000' ft +/- from our lateral) Is the location for this type of service generally indicative of some sort of naturally occurring deep pit on their property?

11/30/13 01:19:36PM @mark25:

Re: Water Disposal

Comment with respect to below inquiry:

  • Speaking of the water issue you mentioned, and diverging from the FTP topic again, there is a water disposal unit right across the road from this pad. (1000' ft +/- from our lateral) Is the location for this type of service generally indicative of some sort of naturally occurring deep pit on their property?


Water disposal wells can pretty much be located anywhere in this area pending landowner approval. Water is disposed downhole via injection into various shallow formations below the fresh water aquifer levels that tend to areally continuous and consistent. No localized "deep pit"

12/03/13 11:18:32AM @kagay:

Thanks Dean - now I need some schooling to interpret. A few questions: on the "well production" tab I see a table to the far right with "manufactured numbers" for KKL III and V.
(1) What relevance do these have since these numbers are clearly not what I have shown on the original table? Some kind of reverse extrapolation since the first month numbers are so high?
(2) Why does III match V?
I assume I am to take from the "Type Curve" a general decline profile for all area wells as sort of an average prediction for months out to 360 (30 years).
(3) So KKL III should perform in this ballpark? (with lift assist at some point, possibly soon)
(4) May I ask what your general background is, and what this data is used for at your end?

Very interesting stuff. Completely new to me. Thanks for the contribution!

12/03/13 01:11:46PM @kagay:

There seems to be some confusion - 16754 was a production number for Winfield C. KKL III and V were 14754 and 14843 in Sep 2013 respectively. (separate leases and wells)

Another question - if I sum up the average monthly production (column N) for 30 years from the table on sheet "Hyperbolic Decline - Oil", I come up with a theoretical EUR of almost 515,000 bbls. I must be mis-using the data. Please know that I am not trying to be critical at all. I am just trying to understand what I am looking at and how I as an outsider to this field of expertise can interpret the data and know what limitations apply.

12/03/13 01:17:50PM @kagay:

PS - there is another month of data for most of these wells available as of today on RRC. I can re-post the updated original table if it will help.

12/04/13 11:43:08AM @kagay:

Dean - looking forward to seeing your revised spreadsheet. Probably won't be enough data to help, but C5H (KKL III) numbers for Oct is 11,774, Nov is around 9000, and CHK relates that Dec will probably also be around 9000.

Say, do you by any chance recognize, or know anybody that could tell me, which component in the attached picture is the adjustable choke, and how to read what the current size is?

Can any other oil equipment experts out there answer the above choke question?

Mike Chandler
12/06/13 01:00:09AM @mike-chandler:

#1: Tubing pressure gauge with Pneumatic/Instrument transmitter (P/I) sending signal to either the emergency shutdown or some other flow measuring device

#2: Emergency shutdown valve set to trip closed based on what pressure signals it receives

#3: Casing pressure gauge with transmitter

#4: Adjustable choke has an indicator to tell you what the opening size is (equivalent cross-section). Basically, a pointed spear in a mating shaped hole.

#5: Simply a flowline block valve.

#6: Simply a bleed valve.

#7: Appears to be a flow transmitter.

12/06/13 11:10:21AM @kagay:

Thanks a lot Mike!

Is there usually an indicator of some sort on the outside of the adjustable choke to read what the size is? Anything I should know about how to interpret it?

12/06/13 07:08:09PM @kagay:

Thanks again for your input. I've just looked at the basics; I may have other questions later. Knee-jerk response to the EUR - I keep hearing 200-300k, so 486k sounds really good, BUT, maybe a little high still?

Mike Chandler
12/06/13 09:07:47PM @mike-chandler:

Kagay, there should be an indication scribed on the body which is usually in 64ths. Turning the handwheel counterclockwise opens the choke.

A lot of times a well has a very high shut-in surface pressurethat needs to be regulated down to flow rates within range of producer's preference and measurement device range. That usually takes time. Initially, the adjustable choke will be slightly cracked and as the well loads up with liquid, the choke will be opened incrementally. Once a column of liquid has entered the production string, that hydrostatic head reduces the surface pressure but not the BHP.

Think of it this way: Bottom hole pressure minus hydrostatic head equals surface pressure. Then, surface pressure minus pressure drop across choke equals pressure slightly higher than what is required to get into the sales line. That is a very elementary explanation.

If you ever notice, shutting a well in usually results in the surface pressure rising well above the previousflowing pressure. That's because when the well is shut-in, the gas bubbles to the top, andthe liquid falls down hole, lessening the vertical column weight. Therefore, you see the surface pressure creeping towards the BHP.

Hope this makes sense.

12/07/13 11:15:01AM @kagay:

OK Mike, you are going to make me have to go dig out my old hydraulics book to follow some of this thread, but I think I get some of your logic. Thanks for the description.

05/07/14 10:58:17AM @kagay:

Mark - if I may revisit this past thread with you - based on your analysis of our well, it appears that LaSalle County taxing authority has way overestimated the value of my portion of the lease. With no more drilling and diminished current or future production projections, the value is probably less than half of what they state. Any suggestions for a protest?



05/07/14 07:40:55PM @mark25:


Please take what I say here with a grain of salt but it seems to me that some sort of EUR projection for your well would be in order to show the long term and discounted value that is associated with this production. Although the well has produced over 66 MBO as of latest date I have info on (see attached), present day flow rate tying this to typical Eagle Ford decline profile should give one a good value.

Does LaSalle Co taxing authority have a Petroleum Engineer on staff? Or perhaps you should look to have a certifiedengineering consultant do a work up on your well.

On the flip side of value, CHK appears to be set up here to drill at least two more wells from this pad as they presently have it laid out (see attached permit). Note the "fish hook" for the first well, i.e. surface location and then drilling out to the SE before turning well bore to drill the horizontal.

There is room to do the same with a well to the opposite side of the surface location plus one that goes straight to horizontal from the surface location.

Could the tax authority be looking at this and saying "three wells of value here"?

05/07/14 08:08:31PM @kagay:

Mark - Thanks for the reply on the value/taxing issue. (I could not find a way to reply directly to your last comment by the way, so I went back in the discussion to find the first reply link available.)
A couple of things - yes the original plan was for ten wells off of that pad - five on our lease and five to the lease next door, but as you noted previously in this thread, the well appears to be underperforming and the operator keeps pushing the infill well drilling dates back so that I wonder if they will ever get back to this pad. Maybe not.

And as to your certified engineering consultant suggestion, what is the best way to go about finding one and how much would I expect to pay for that service?

Oh, and FYI, the county is using a firm called Pritchard and Abbot to set the values. Are you familiar with them?


05/08/14 02:13:26PM @mark25:

I have personally never dealt with P&A. Below is their website - you may want to contact them directly to see if they can give you details on your specific valuation.

As for getting your own PE to do a work up, you may want to start a posting on the Forum looking for suggestions / recommendations.

In lieu of that, I will see if I can did up some PE consultant info that may work for you.

Good luck on all this!

05/08/14 05:53:04PM @kagay:

Thanks Mark. I was able to get a reply from P&A and they sent me their calc sheet and their bottom line was actually 30% less than what the county sent me. Waiting to hear why the difference. If I can find a consultant that will work for less than how much they will save me in taxes, then it would sound like a no-brainer, given that the report would actually hold sway over the final county decision. (if it would) I hear it is hard to get the counties to budge though.

06/04/14 11:28:46AM @kagay:

Mark - an update on the behavior of this well and a question for you as to possible explanations for it:

March to April production went from 7100 bbls to 10,400 bbls. The operator will not tell me if or what may have been done to the well (choke, other) to cause this upward spike. What are the typical explanations for a sudden upturn in production? (almost 50% increase) Choke changes, other?

Until this point, the well had been doing a fairly steady decline from around 15,000 to 7,000 bbls over an 8 month period. I assumed it would continue in this fashion. Is this almost always the result of operator manipulation, or, if natural, what can cause these fluctuations?

I have not seen new wells in about a mile radius come online during this time unless I missed one (fracking nearby - effect, ie), and the sister well on the same pad but on the next door lease has continued the downward decline. This one had previously out produced ours by 10 or 15%.

Certainly no complaints, just interested in learning some more about these phenomena.Ideas?


06/04/14 11:34:15AM @mark25:

Probably either operator ran small diameter tubing inside casing (increase annular velocity and lifting capability) or most likely installed some sort of artificial lift to get well unloaded more efficiently

06/04/14 12:52:37PM @kagay:

Thanks Mark. How long does an operator typically have to shut the well down to perform either of those tasks?

Wouldn't it make sense to do that on all wells on the pad if they are performing similarly?

06/04/14 01:06:47PM @mark25:

If all wells were performing the same way, it would make sense to do them all UNLESS the first well was a test case to see what sort of response took place.

If successful, then spend the additional capital.

Some amount of shut in time is needed to do either job - time frame depends on operator and how they had things set in the first place. But 1-3 days is probably the range.

One more idea on what may have happened - if this well is flowing to gas pipeline, there may have been a change in pipeline pressure (i.e. a drop) that would allow the well to flow more easily to the pipeline (and not be held back due to pipeline pressure bucking well flowing pressure).

Pipeline pressure drop most probably tied to compression installation on the overall gathering system.

Just ideas here- may be a mix of all of them

06/05/14 12:53:55PM @kagay:

Just in - the operator projects "4000 bbls for May". No comprende. 7100 to 10,400 to 4000. I wonder if they are just messing with me. How could that be?

06/05/14 12:54:46PM @mark25:

They may have had the well shut in for part of May

07/22/18 08:06:11PM @hilary2018:

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