Assertions in the article aside, the Encana Haynesville re-fracs that have been discussed here do not seem to provide a sufficient return on investment. The technology is still evolving and the jury is out. What all Haynesville operators know is that they have left behind a lot of un-stimulated, non-producing rock. A lot of that rock lies in the unit set backs that limited lateral lengths before the state decided to approve Cross Unit Laterals. A CUL well is so designated by the letters, HC, in the well name. The latest well designs with longer laterals and pressure pumping greater volumes of water and sand have improved profitability sufficiently to lure back all the original Haynesville operators, or their successors regardless of NG prices Those profit margins are now benefiting from reduced drilling and completion costs. Indeed all service costs have been driven down in an increasingly competitive environment that should last through the remainder of the year.
As to P&A wells, there is no general answer for that question. There are a lot of dry holes among those P&As plus wells with collapsed casings and other mechanical problems that will not allow for a re-frac. In addition to efforts to design economic re-frac methods the industry is attempting to define what well/formation characteristics make for a good re-frac candidate. When energy companies and pressure pumping contractors figure out a successful formula we won't have to hunt for articles. It will be splashed across the Internet and touted in every corporate presentation and press release.
Thanks, olddog. Please re-post the link as the next few months' production is entered in the database. This was a very good well initially. I don't recall any of the prior re-fracs mentioned having this good of a profile.
From the monthly L/U/W production reports it would appear the well was taken off line in November and returned to production in December. The average monthly production for Aug.-Oct. was 10,968 mcf. We can compare that to the average of the three months after re-frac (Dec.-Feb.) and get an idea of not only the increase in production but also the decline rate.
If the December production is taken as the average for the first three months of production after re-frac (no decline) at $2/mcf profit to ECA would be about $110,000. That would not appear to be economic for a process that cost $1 to $2 million.
We have an Encana refrackin Red River Parish. The well was never abandoned. We got the first refrack payment this month. Don't know if it was for a full month of production. The refrack production was about 1/5 of the original first full month of production.
I'll take a closer look when I get home to see if there is any additional information regarding well operations in Nov. and Dec. The January production isn't that much of a bumpwhen compared to Oct.
The refrac began with new perforation clusters on Dec. 2. There's no report data that indicates what was going on prior to that date but it is possible that some preparation occurred in November that accounts for that low producing month. The actual frac operation occurred from Dec. 2 to Dec. 14. The well was flowed again sometime between the 14th and the 26th. when a new allowable test was performed so December production is a partial month and January is the first full month of production (31 days).
olddog, if you would, please post the following months production as it is appears on SONRIS and we'll see how it holds up.
Skip, just got our monthly ck on 2.5 ac. for well serial no. 242761 and it was a lot larger. This is from an old lease that was held by production but we haven't even received a ck for a few months. I looked back at production and noticed extreme increase in production in Jan. 2015. Exco is operator. Wonder if this well was refracked
The monthly production reports look like other wells that have been re-fraced. Shut In in November, re-fraced in December with partial month production and then January first full month of production. The January production only returns the well to the flow rate of six months earlier. That doesn't appear to be enough of an increase to make a reasonable return on the cost of the refrac. We'll have to wait and see. Unless the decline is much shallower after the refrac the well will be back to the flow rate prior to refrac in a relative few months.
REFRACS RAISE QUESTIONS ABOUT FURTHER US OIL PRODUCTION: AT THE WELLHEAD
By Starr Spencer | April 6, 2015 12:01 AM - platts.com
While technology can now let companiesgo back to wells and further spur oil production, it remains a question whether refracs are the best option in the current crude price environment, as Starr Spencer explains in this weeks Oilgram News column, At the Wellhead.
Low oil prices present the shale industry with a problem: how to keep production up while trying to push costs down.
One possible solution is refracturing existing wells. It sounds simple, elegant and logical: if output is declining in an oil or natural gas well, and hydraulic fracturing the well prodded it to produce initially sizeable volumes, then operators should just refracture it, i.e. shales version of enhanced oil recovery.
Refractures, popularly known as refracs, have snagged industrys interest recently as oil prices in the US where the majority of shale wells are located have stubbornly bobbed around the $50/barrel mark. The reasoning is that since the all-in cost of most horizontal wells sport price tags of $8 million and up, and refracs can run roughly 25% of that sum or about $2 million if done correctly, refracs make a lot of sense.
And since upwards of 100,000 oil wells have been fracked in North America during the last four years, according to some studies, a sizeable portion of those may be able to be refracked, proponents say.
The idea has had support from many parts of industry for years. For example, ExxonMobils US shale subsidiary XTO Energy, in a presentation to the North Dakota Petroleum Council annual meeting in 2011, said refracs in the Bakken Shale of North Dakota and Montana appeared economically and operationally effective and were especially successful in wells with inefficient completions.
Ample opportunity exists for further development of refrac techniques, the presentation stated.
Experts say refracking stimulates bypassed pay intervals, re-inflates natural fissures and often contacts new rock. They say only about 8% of a reservoirs oil is recovered from shale wells the first time around, but claim refracking can boost output to or near original levels, although the decline rate is likely to remain high from 40%-70% the first year for oil wells.
Even so, some fracking experts are not convinced the market is ripe for refracs.
The technology is not ready for prime time, said Chris Robart, a director at energy consultancy IHS. The challenge is that identifying candidates for refracs, and deciding how to refrac the well, are not that simple. Theres a lot of gaps in data that need to be there to make good decisions about how to design a refrac operation.
Robart said refrac operations can be pricey unless well bores are designed in a way to facilitate them. And refracking doesnt fit the highly efficient, manufacturing mobile factory model of shale wells, he said.
Others say there is no easy way to ensure the refrac treatment will go to the left-behind parts of the reservoir when it is placed on a long lateral of, say, 6,000 or 7,000 feet. A lateral is the horizontal portion of a well.
How do I actually get to the [areas] that dont produce at all and crack those open? said Richard Spears, vice president of oil services consultants Spears & Associates. You can do it, but the challenge and cost of doing it can be big. Its technically risky, economically expensive, and in the end, will you really get something out?
Not all wells are refrac candidates and it is important to evaluate wells first which is what oil services giant Halliburton does, said David Adams, the companys vice president-operations technology in North America. Halliburton looks at numerous criteria, such as prior well treatment, well integrity, the type of proppant used to hold the fractures open.
The cost of the evaluation is minimal, Adams said maybe a couple of percent of the overall cost of a refrac.
Once a well is deemed suitable, technologies exist to gauge how the well has produced at various points along the lateral during the prior month, he said.
We have ways of diagnosing which portions of the reservoir need a refrac the most, Adams said. We can derive some information on how the well should be refracked, just by pumping pressure diagnostics into the fracs and watching how they react to that pressure.
And to ensure the refrac treatment actually travels to the right area instead of going into already high-producing sites, the company uses an engineered diverting solution, Nick Gardiner, strategic business manager for Halliburton Production Enhancement, said.
We have diagnostics on where toblock off better-stimulated areas so [the refrac] goes to lesser-stimulated areas, Gardiner said.
But even if wells are good refrac candidates, oil prices may prove to be too low right now, even though refracs are relatively cheap, some experts say.
If youre a producer, would you rather produce more oil at $50/barrel, or just keep the lights on [flat output] until oil prices recover? David Choi, E&P analyst for Lux Research, said. I suspect [refrac] candidates would change if oil prices recover to $70-$80/b.
Here's a Vine refrac I've been watching. If my memory is correct it was refracted in December.http://sonlite.dnr.state.la.us/sundown/cart_prod/cart_con_wellinfo2?p_wsn=240903
@Old Dog, Sec. 18 or 14/14 Holly Field, Desoto, EnCana was refraced in May 2014 if you want to follow a history on another one. I think it was the first refract EnCana did
That's a much better result, olddog. Of course the well was probably a good candidate for refrac considering that the original frac was not very effective. I think there are a significant number of wells that fit this profile and might make good candidates for refrac.
Encana did a refrack of Crestwood Land 4H-1 in T13 N R10 W in Red River Parish. We got the first refracked payment in Feb 2015 for production in Dec 2014. Beginning refrack production was only about 1/5of the original first month production on that well. On the original production it took 7 or 8 months to get down to 1/5 of the 1st full month's production. Talk was that they messed up the refrack somehow but thatwas not official information.
Thanks, James. Little is being made public regarding the details of the re-fracs being conducted in the Haynesville Shale Play. It appears to be a steep learning curve for choosing the best well candidate profile for a re-frac and actually executing the pressure pumping operation. The one thing we know is there is a lot of un-stimulated and/or under-stimulated rock in the majority of Haynesville Drilling Units. The remaining reserves are vast but a challenge to unlock.
LOL! For the record, the January production was 89,460 mcf and February was 84,243 mcf. Please keep posting. The 90 and 180 day IP numbers will give a good picture of the decline rate and the long term economics of the refrac operation.
U.S. shale oil firms say refracking not the best path in downturn
Tue May 5, 2015 5:58pm GMT By Anna Driver and Ernest Scheyder
HOUSTON/WILLISTON, N.D. May 5 (Reuters) - Refracking, the practice of fracking an oil and gas well a second time, is still too unpredictable to rely on as a way to slash costs and increase output during the oil price slump, top U.S. shale oil executives said on Tuesday.
Oilfield service companies, including Schlumberger NV and Baker Hughes Inc., have touted refracking as a cheap way to revive output from existing shale wells. Output from existing wells, measured in barrels per day, normally drops as much as 70 percent in the year of operation. Also, some wells were not thoroughly fracked the first time.
But executives from producers say the refracking technology, while promising, remains tricky.
"We have not tried any refracks. Our outlook on that is that it is really technical," said Bill Thomas, CEO of EOG Resources Inc., widely regarded as one of the most efficient U.S. shale oil producers. "We believe that just drilling a new well, and kind of starting fresh ... is probably the preferred way to go."
In fracking, a mix of pressurized water, sand and chemicals is injected into a well to force out oil and gas. In one type of refracking, tiny plastic balls, known as diverting agents, are pumped into wells to block older fractures and increase the overall pressure of the well so output climbs.
Output from a new well can be easier to forecast than output from refracking.
"Right now we see that (refracking) as a good forward option," said Chuck Meloy, the outgoing head of U.S. onshore exploration and production for Anadarko Petroleum Corp., a leading independent. "We'd like to see the technology improve and get enhanced some and make it more predictable."
Oilfield services companies, which have laid off thousands of employees and seen revenue plunge after a 50 percent collapse in crude prices since June, have talked up refracking because it would allow producers to save money on drilling, normally about 40 percent of the cost of a new well.
Pullbacks by producers will likely lead to a drop in U.S. crude production this quarter, according to government forecasts.
In Schlumberger's first-quarter results report, Chairman and CEO Paal Kibsgaard said the company expected the refracking market to expand.
"This is quite a significant market opportunity," he said on the company's conference call. He added that Schlumberger was prepared to "foot the entire bill for the refracturing work, and then get paid back in production." (Reporting by Anna Driver and Ernest Scheyder; Writing by Terry Wade; Editing by Phil Berlowitz and David Gregorio)
Trade secrets, and so nobody really knows? Stock options
& Credit Default Swaps (leveraging) to hedge the bet? Just
my two cents, but it seems that seismic charts would weigh
very heavily into such decisions? I'd also think that very radical
chemistry (downhole cracking, reactors) would better the odds;
but raise flags?
Here is an excellent example of how confusion is created by writers that don't know their subject. It happens all too frequently in the online articles that come across my computer. Re-fracking a vertical well is nothing like re-fracking a horizontal well. Vertical wells have been successfully and economically re-fracked for years. Here the writer is making statements about the Barnett Shale where the formation was developed with vertical wells for years before horizontal drilling became the norm. Devon and Chesapeake seem to be making statements about vertical re-fracks and Anadarko is referencing re-frack technology for horizontal wells. The tiny balls don't increase pressure as such. They temporarily block some existing perf clusters so that the pumping pressure can be concentrated in specific, often new, perf clusters to create new fracture networks.
Devon, Chesapeake see refracking prospects in Barnett wells in Texas
HOUSTON May 6 (Reuters) - Devon Energy Corp and Chesapeake Energy Corp said on Wednesday they see an opportunity to produce more natural gas in the Barnett Shale in Texas with a second round of fracking on older wells.
The companies, two of the largest operators in the Barnett during the natural gas boom where production peaked in 2012, believe they can breathe new life into wells that were fracked while that technology was still in the early stages, executives said on earnings calls.
"We've seen such a dramatic improvement in our completion results with the newer technology," said Tony Vaughn, executive vice president for exploration and production at Devon. "We've gone back and are starting to test some of these new completion techniques with our existing (wells)."
During hydraulic fracturing - or fracking - water, sand and chemicals are blasted into shale and other rocks to create fissures that allow oil and natural gas to flow out.
In one type of refracking, tiny plastic balls, known as diverting agents, are used to block older fractures and increase the overall pressure of the well so output climbs.
Devon has completed about 50 refracks on vertical Barnett wells and expects to complete a 200-well program this year, said Vaughn.
Chesapeake is also testing refracks in the Barnett, where it has identified more than 1,000 wells where the technology might work. So far it has tested nine wells using two different techniques, Jason Pigott, executive vice president for Chesapeake's southern division, said on a conference call.
Not everyone is sold on the emerging technology.
On Tuesday, executives at Anadarko Petroleum Corp and EOG Resources Inc said refracking is still too unpredictable to rely on as a way to slash costs and increase output during the oil price slump.
I agree that Devon was specifically referring to re-fracs of vertical wells, however I can't see in the above articlethat Chesapeake necessarily was referring to vertical Barnett Shale wells. In the Haynesville, CHK is obviously referring to horizontal re-fracs; Very possibly Mr. Pigott was referring to horizontal re-fracs in the Barnett as well. Also, I can certainly understand why Anadarko and EOG would be perfectly willing to let others prove up the technology.
Pigot goes straight from talking about Devon re-frack plans for vertical wells to talking about Chesapeake re-frack plans without stating that he is now referring to something beyond vertical wells. If he is referring to horizontal wells being at least some part of Chesapeake's plans he fails to make such clear.
This goes back to multiple GHS discussions, some now several or more years old. where refracks of vertical wells get confused with those of horizontal wells. The first is common, the second is not. Even now. Horizontal well re-frack knowledge and technology is still in its infancy.
The reason it will remain part of the conversation is the fact that horizontal operators now know that their early wells left a lot of rock unstimulated and a lot of stages not contributing to production. A Schlumberger scientist, in a scholarly paper presented at a Paris industry symposium a couple of years back stated that to that point their data set showed that on average 35% of stages and 40% of perf clusters in horizontal wells did not contribute to production. That's too much value to leave behind in horizontal wells so the efforts to come up with an economic re-frac technology will continue.
Looks like my original well in 5-13-13 in Desoto Parish was re-fracked when the new wells were done. It is now putting out as much as it did when 6 months old. It is now 5 years old. Will have to watch it to determine decline rate. Serial #239745. DNR has not updated it yet but my check stub shows the increase.
The last normal month (Jan) showed 23 MM per month. This check for March showed 153 MM. Operator is EXCO.
Not a re-frac, TL DS1. New wells. The LUW Production section of the well file is the cumulative total production of all wells reporting under that specific LUW code. Here is the list.
|LUW Code||LUW Name||LUW Type|
|616088||HA RA SUDD;||2|
|Effective Date||End Date||Well Serial||Well Status||Field Id||Organization Id||Well Name||Well Number||Parish Code|
|20-FEB-15||248120||10||4541||E183||HA RA SUDD;AMS TIMBER 5||002-ALT||16|
|20-FEB-15||248119||10||4541||E183||HA RA SUDD;AMS TIMBER 5||001-ALT||16|
|17-FEB-15||248123||10||4541||E183||HA RA SUDD;GENTRY 5||003-ALT||16|
|16-FEB-15||248122||10||4541||E183||HA RA SUDD;GENTRY 5||002-ALT||16|
|16-FEB-15||248121||10||4541||E183||HA RA SUDD;GENTRY 5||001-ALT||16|
|01-JUL-13||239745||10||4541||E183||HA RA SUDD;FULLER 5||001||16|
|09-MAR-10||30-JUN-13||239745||10||4541||C084||HA RA SUDD;FULLER 5-13-13 H||001||16|
Not a re-frac. Three new wells. Congratulations.
HA RA SUDD;GENTRY 5
HA RA SUDD;GENTRY 5
HA RA SUDD;GENTRY 5
The breakdown shows each individual well. My original well is now putting out the amount in my original post. Don't know why that well would now be putting out 6 times what it did 3 months ago if it wasn't re-fracked.
Click on the Serial Number for each well (first number in blue). Look under LUW Production. You will see that the production for February (partial month) and March (first full month) are identical. If you look up February and March production for your original well, you will see that it is also the same. That's because these are not production numbers for individual wells but cumulative production for all the wells in the unit.
There is no re-frac. There are three new alternate unit wells in addition to the original unit well.
The info on my check stub shows the production of each well. The production for the month was 1.33 billion for all 6 wells. Again, my original well is making 6.6 times what it did in Jan. As you know DNR info is not up to date.
TL, yes production reporting to the state is two months behind the fact. What was the January production for you original unit well? And the February and March production for the same?
The last normal month (Dec) showed 23 MM per month. This check for March showed 153 MM.
Jan. was only 6 MM because they evidently shut it down to frac.
Feb. was about 48 MM (partial month)
(Had to go back and edit some dates)
Gotcha. Thanks for the details. The are so few wells that we can identify as re-fracs and then follow the decline rate to get a feel for how effective they are from an economic stand point. If the technology and cost work out a good percentage of the ~2300 currently producing HA wells may be good candidates.
The legal implications of consent to re-frac a well by working interest owners is an unsettled question under Louisiana law.
Refrac Obligations Under Model Form JOA-How Will Louisiana Courts Interpret? (Excerpt)
In this period of depressed oil and gas prices, many companies are considering refracturing and/or reworking older wells to gain production at lower costs than from drilling new wells. Refracking allows companies to extract more hydrocarbons from already existing wells by recompleting the well. Nowadays, companies have better technology and are more efficient in their completion techniques and thus are able to capture additional hydrocarbons from existing well bores. For example, instead of spending around ten million dollars to drill and complete a new well in the Haynesville shale in Northwest Louisiana, a company can usually refrac an existing well for around two million dollars. Along with the cost savings, the results also look promising. According to Comstock Resources 2015 first quarter earnings call:
We [Comstock] began the year by executing our first refrac of a Haynesville shale well during the first quarter of 2015. Following the refrac, the Pace 33 #1 well in DeSoto Parish, Louisiana, had an initial production rate of 4 million cubic feet per day, which was an eight-fold increase from its 0.5 million per day production rate before the refrac. Were currently producing this well at a stable rate of 3.5 million cubic feet per day.
This example is just one of many where refrac operations on existing wells in shale plays have been profitable. However, refracs also pose risks, including the total loss of a well bore resulting in both additional costs and no production.
Despite these risks and as the technology continues to improve, refrac operations are likely to become even more common in shale plays. Thus, it is helpful to review common contractual provisions that may address or affect refrac operations.
Companies operating under joint operating agreements and those looking to acquire interests in properties burdened by such agreements should be mindful of how such agreements may affect refrac operations. Many standard form joint operating agreements do not specifically address the refrac of a well already producing in paying quantities. Thus, the question arises whether a party is allowed to undertake refrac operations without all parties consent for wells that are producing in paying quantities. Moreover, if a party does not consent, can that party be treated as a non-consenting party and thus be subject to the non-consent penalties under the terms of most joint operating agreements. At present, there does not yet appear to be a Louisiana case decided on these questions, and the jurisprudence from neighboring Texas is unsettled.
Link to full article:
Bloomburg likes Refracking - says it's there is a "fever" around it although the technology is new.
This is a very positive article claiming 30% MORE gas from refracked wells than from new ones. What do you guys think?
It came across my desk also, Hopeful. Like most articles on the subject it is optimistic but short on specifics. That's likely because operators are still experimenting and not settled on the best re-frac design for the wells that meet their criteria. Note that the graph is an 80 well sample from the Bakken. The one mention of possible problems, siphoning oil from adjacent wells and ruining an entire reservoir, is IMO unlikely. The real question is what does the re-frac cost and how much incremental increase in production is stimulated with what decline characteristics. In a time of little good news many operators are looking for any positive spin they can utilize to bolster their prospects with analysts, stock holders and creditors.
Study: Refracturing not all its fracked up to be
Posted on July 7, 2015 | By Robert Grattan fuelfix.com
HOUSTON Refracturing likely wont have a measurable impact on the oil market for the next five years or so, according to a new analysis by energy consulting group IHS.
Early chatter about the refracturing process, where drillers return to previously fractured shale wells and pump them full of sand and fluid again hoping to unlockeven more oil, has had traders and oil market watchers wondering if the U.S. wells whose prolific production sparked a collapse in oil prices are sitting on a second bounty, just waiting to be tapped.
But while longer term advances in the techniques and technology of refracturing might change the calculus, a large-scale redo of oil wells wont make sense until companies see better returns from returning to old wells than from drilling new ones, said Christopher Robart, IHS managing director of unconventional resources.
Were calling a niche market opportunity in the three-to-five year time period, he said. Currently, in just about every case, the returns are going to be significantly better in drilling a new well.
Only about 600 horizontal wells have been refractured since 2000, a very small fraction of the roughly 90,000 horizontal wells that have been fractured over that time, IHS numbers showed. Most of those refractures have been cases where producers were going back and applying new techniques to wells that were fractured years ago when the completion process was relatively new.
In 2014 and 2015, only about 1 percent of total fracturing jobs performed wells done on wells that had been previously fractured, Robart said.
And those refractures yielded mixed results, he added. Bakken wells preformed relatively well, with initial production and decline rates comparable with new wells. Other plays underperformed, though, and it wasnt clear whether the Bakken wells stood out because they may have been inefficiently fractured long ago.
Refracturing a well costs roughly $2 million often less than a new well because the infrastructure needed for the process is already in place. But the uncertainty involved means many companies will be hesitant to pour money down existing holes when there are plenty of new ones waiting to be drilled, Robart said.
Right now the variance of outcomes in refracturing is high, he said. Making this work is going to take time. Its going to be a long-term process.
Skip, thanks for the Fuel Fix article. I would guess they are a more objective source than Bloomburg. It's interesting that they come to widely different conclusions. I guess we will find out more in the next few years.
I get an email from Google every night with the day's important stories in major media about natural gas. Most stories are negative but this was one of the few positive articles I've seen for awhile - but the Fuel Fix article is definitely the Grinch that stole Christmas. lol!
Hopeful, the devil is in the details. The Bloomberg article is a small sample, 80 wells, in one play, Bakken. It's way too early to have a good idea of the economics by play but the operators will get there eventually. Until then those who are under the gun to turn out content can choose a position and find data to support it. I deal with data daily and I want to see the raw numbers, not an Internet reporter's take on those numbers. In my business, skepticism is a required trait.
Take a look at CHK's Ford 23 in section 26 9N 11W. While there have been some down months since October 2014, the majority of months are considerably up. Refrac? This well is now a 5.3 BCF well.
No increase in production on CHK's Ford 26 setting on same well pad.
The well was re-fracked on 12/30/14 and a new state potential test was performed on 3/25/15. A good well to watch for the coming months to see how production holds up. Thanks for posting, olddog.
The SONRIS Data Well File doesn't provide completion details and the Document Access is down. An obvious reason for the quick decline in a well with a reasonably good IP is the short lateral, 3040'. 1000'+ short of the average lateral length for a 2010 well.
Cracking Open Re-fracking: A Flush Rush or Idle Probing?
by Deon Daugherty Rigzone Staff Monday, August 03, 2015
Squirting fluid that made hydraulic fracturing work two years ago down the same old fractured well may not be the surest way to make a buck in an industry eager to turn a profit. Then again, the folks in the lab and in the field might be onto something.
The desire to charm hydrocarbons from the ground without the expense of additional drilling is strong and has lingered for decades. Re-fracking has been in practice, with mixed results, on vertical wells for years. Its only in the last few years that engineers have started returning to the source of all those hydraulically fractured wells with re-fracking.
Most estimates indicate it costs $8 million to drill and complete a new well. Re-fracking a well costs about 25 percent of that figure, which is enticing some of the largest oilfield services companies into the lab.
But exactly what best practices might emerge remains something of a trade secret.
Halliburton, the worlds second largest oilfield services company, which happens to be set on absorbing the worlds third largest oilfield services company, by many accounts appears to be the frontrunner in re-fracking. And, the Houston oilfield titan just scored $500 million BlackRock Inc. to focus on North American unconventional wells.
Without getting too specific during the companys 2Q earnings call July 20, Halliburtons Jeffrey Miller, president director & chief health, safety and environment officer, mentioned the companys mature field strategy.
Halliburton has been involved in re-frack operations for decades, he said, and performed at least twice as many operations as any other service provider.
Although relatively small today, we believe this market has significant potential in the coming years. So why are customers interested? Early horizontal wells were arguably under-stimulated, he said, adding that stages per well with current technology are up more than 30 percent.
Ron Dusterhoft, a technology fellow in production enhancement at Halliburton, told Rigzone that given the lack of activity in the oil patch, companies are looking at other ways to stimulate production.
Re-fracking offers an alternative to increased production without new drilling, he said.
Halliburton has its own process for weeding out the wells that may respond best to re-fracking. Still, forecasting an actual percentage of the thousands of wells drilled that can become actual candidates, Dusterhoft said, That depends on whether youre an optimist or not.
As may be expected, the wells that are in better reservoirs tend to have the better results, he said. Still, some clients are hesitant to embrace the re-frack.
Once youre able to do a good case history, then they become much more optimistic and willing to go on with additional work, Dusterhoft said.
And while estimated ultimate recovery (EUR) is important, increases in short term production rates from a re-fracked well is critical for Halliburtons clients to keep their production on the upside, he said.
thanks. its interesting that Encana has publicly stated that they have refrac'd a few in the haynesville and Vine has re fracked a few that we've followed here, but has CHK publicly stated they were getting into this? since they continue to have the highest rig counts in the haynesville maybe they are not worried about older wells yet?
You're welcome. I'm not aware of any CHK re-fracks however I'm sure they are experimenting with the technology somewhere. CHK may be placing their emphasis on drilling new Haynesville wells due to Larchmont.
I have minerals in sec. 18 of 14/14.People who live in the area were aware of it as there was lots of noise associated with it. Wish I could find out if they are refracking sections 6 & 7 of 14/14 Desoto. I know Exco is refracking some of theirs. One section I have minerals in has been refracked.
Comstock announced another Haynesville re-Frac today in their 2nd Q release.
"The Company also announced results for its second re-frac of a Haynesville shale well during the first quarter of 2015. Following the re-frac, the Bagley A #4 well in DeSoto Parish, Louisiana had an initial production rate of 3 MMcf per day, a six fold increase from the 0.5 MMcf per day before the re-frac."
Some great comments & stories included here. We did some individual well analysis for some of the wells mentioned on this thread. You can see the summary presentation here:
More and more operators seem to be considering refracs so definitely a trend to watch.
Thank you for posting Todd. Very interesting stuff. Slide 4 stood out to me, as the years have went by rigs have fallen but production has increased. Do you know if Chesapeake has started a refrac program yet?
EnCana just sold part of their N La Haynesville area - wonder how much their re frac results helped encourage a good price?
Welcome, Todd. And thank you for the refrac data. My initial reaction is in regards to proppant volumes. Most operators that I follow have increased proppant loads in conjunction with increasing number of stages and longer perforated lateral lengths. Therefore it's somewhat surprising that the refracs in your sample cohort have reduced proppant volumes.
As you can tell from the thread replies to date one of the pertinent missing data points involves the profile for what makes a well a good candidate for a refrac. That makes it difficult to determine the evolution of the technology. Do operators tend to experiment with wells that are sub-economic and not expected to ever pay out or do they refrac the wells they deem to be the very best candidates?
Skip, great question. For what it is worth, the consistent theme I have heard from operators and service companies is that good wells / good rock react best to re-frac approach. Basically, that you cannot turn a poor well into a good well with this technology.
Hello Skip, those are some great questions.
Going into the study, we expected to see higher fluid volumes and more proppant but that wasn't the case. In some cases, we did see operators increasing the proppant intensity (proppant per stage). It definitely seems to be an area that operators are testing & evaluating.
There are a lot of questions around candidate selection. Operators seem very reluctant to touch their best wells (and possible their best candidates). The discussions I've been apart of seem to point to selecting moderate wells to refrac and test the technology.
I agree that many of the earliest wells re-fraced which I have reviewed appeared to be less than average in production profile but there are so many unknown variables. I agree with Rock Man about good rock making for a good refrac candidate. Have you run across any comparable situations where a well with poor IP and one with average or better profile have been re-fraced in relatively close proximity? Presumably comparable rock quality?
Jay, I generally agree however even within well defined core areas there are numerous instances where wells in relatively close proximity have significantly different production profiles that don't appear to be explained by rock quality. The landing depth in some early wells may explain a portion of those instances but not all. If the operator did not report a mechanical problem during drilling or completion ops it begs the question, what explains the significant variances?
533181 10 MONTHS AFTER THE REFRAC