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Permalink Reply by FXEF on March 4, 2010 at 5:30

Muddigger, am I right in thinking that an 80 choke would have a 1.33" opening and a 120 choke would have a 2" opening?

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Permalink Reply by Bobi Carr ("parker") on February 24, 2010 at 10:37

Jay,

Does it hurt just that one well or does it do damage to a larger area?

My thought was that HK might produce as much as they can while they have good hedge prices.

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Permalink Reply by Mattie on February 24, 2010 at 11:12

Parker,

Hedge prices are only good for volumes committed to those hedges - in most cases, companies don't hedge more than 60-70% of their overall portfolio, and usually that % is estimated on the conservative side. So, any extra volume derived from opening up wells "full bore" probably aren't slated for covering hedge positions, unless they are trying to makeup for having produced less than expected in other areas. Any surplus volumes will be sold on the open spot market at current prices.

The current forward curve is getting less and less supportive of locking in more future volumes 1-2 years out - much different than the opportunity just a few short months ago, and particularly less attractive than 18 months ago - thus, you see more headlines about CHK and others balancing their portfolios in the future with E&P efforts looking for oil and/or rich gas (high liquids content).

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Permalink Reply by Les Bamburg on February 24, 2010 at 12:01

Mattie, all Haynesville Shale wells are choked and not flowed "full bore". The level of production for a company is more a function of drilling rigs and completion schedules rather than individual well choke sizes.

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Permalink Reply by Les Bamburg on February 24, 2010 at 11:55

Parker, there has not been any confirmation of "damage" but to the extent there is any it would only relate to that specific well.

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Permalink Reply by RBH on February 24, 2010 at 16:49

also, being "over-pressured"--performance declines change as pressure is drawn down and reaches "normal" pressure..have we seen any wells reach this point yet..any info leaking out about this analysis of pressure versus cum reserves...

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Permalink Reply by Augetter on February 24, 2010 at 15:12

While not a petroleum engineer, I have had experience as an engineer in the mining field. This is what I have learned about situations that bear some resemblance to this problem. Consider that the Haynesville is overpressured by a depth of 13,000 feet of cover. To keep it simple, assume the static pressure of gas at the bottom is 13,000 psi. The wells typically produce at 7,000 psi with a choke of 22/64ths, which means there is a pressure differential across the rock/fracture face of 5,000 psi. With this differential you can expect small flakes of shale, smaller than the proppant, spalling off the fracture face, filling the fracture with fragments that will interfere with the flow of gas through the proppant bed. What you have done by pulling the well at these rates is to effectivly introduced a pressure reducing mechanism. While the EUR should be the same as a well that was not treaded so roughly, it will probably will not be economical to attain this when the production falls below a certain level. Old saying in the mining circles;"Fast, cheap, good, pick two".

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Permalink Reply by Ademola Oyerokun on February 25, 2010 at 3:57

Typically, the productivity of unconventional plays is difficult to extrapolate from one area to another. I quite agree with Jay about the geographical location of the best part of the Haynesville shale. However, there are some favorable factors that make a good shale well. They are Pressure, lithology,maturity,TOC, existence of natural fractures to mention some. These factors are not present in the same percentage across the play area. Therefore, sometimes luck is needed, every other thing remaining constant - lateral lengths, completion techniques and drilling parameters, etc.

Therefore, if one strikes a good well, it is in the best interest of the operator and the "reservoir" to engage some reservoir management techniques or practices in order to produce the well optimally. Though, the immediate benefits always tend to overshadow best practices.

In my opinion, the best rate to flowback or produce a well is the highest rate commnesurate to the drawdown pressure necessary to prevent liquid loading and damaging due to reservoir contact with frac fluids. And...after flowback in the stabilized flow regime, it is the optimized rate that supports the inflow performance Relationship and Vertical lift Performance curves. i.e, the optimized rate with reference to the deliverability of the well.

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Permalink Reply by Mattie on March 4, 2010 at 6:47

Les,

I am quite familiar with the fact that producers don't flow wells on "open-choke" - I've been in the O&G business for many years (probably similar to yourself), and have a long background in trading/hedging the product. My comment about "full bore" was in response to Parker's question about "why don't producers produce as much as possible......". It was not meant to imply that I thought producers did this regularly and/or even produced on a larger-than-normal choke - quite the opposite - the point of my comment was to inform him that producers hedge based on current and forecasted production levels, not on a short-term basis utilizing increased choke levels (nothing more, nothing less).

The only benefit to increasing well flows thru larger-than-normal choke-size (which we all know could cause serious wellbore damage) is to take advantage of short-term "peaking prices" in the day market - not suited for taking advantage of forward NYMEX prices. One example that I can immediately think of on a personal level happened 5+ years ago in South LA wherein a fairly large independent producer (who should know better) elected to flow their wells on our gathering system at a larger choke (and higher immediate production rate) in order to take advantage of $12.00+ daily prices during Hurricane Katrina - they cashed out on some big dollars for a couple of months, but their wells soon thereafter "sanded up" - and, after several costly attempts to rework the wells, they are now producing at 1/20th of their normal flow rate - different animal (geology) from the HS, but a good example of what can happen when you meddle with choke sizes/well flows to take advantage of a "price arbitrage".

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Permalink Reply by Les Bamburg on March 4, 2010 at 8:49

Mattie, thanks for your clarification. My comment was for the benefit of some members of the site that are not as knowlegeable as yourself and may misconstrue the term "full bore" to imply open-choke.

In the early 80's I was aware of an Area Operations Manager permanently damaging a few GOM wells in an effort to enhance his bonus. Sad but true. Fortunately today it is less likely for such events to occur.

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Permalink Reply by Les Bamburg on March 4, 2010 at 11:54

Jay, no - it was one of the major O&G's.

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Permalink Reply by CatShale on April 30, 2010 at 6:26

We (Petroleum Habitats) have recently discovered that shales generate a catalytic gas in real time during production, and that it can comprise over half of produced gas. This new catalytic process could explain why choking back wells improves performance. For reference, our most recent paper was published this month in the Proceedings of the Royal Society (http://rspa.royalsocietypublishing.org/content/early/2010/04/15/rsp... ), and offers unequivocal evidence that shales can make natural gas catalytically, vs. thermally or desorption.

In terms of explaining choke back, we know that the catalytic process is very sensitive to pressure levels (in fact, the process gets "ignited" when the shale is fractured and drilled, which lowers the pressure below the critical stopping point). The process also likely stops when pressures drop too far. We believe there's an "optimal range" that may be reached by choking back, which in turn lowers decline curves because catalytic generation has been boosted.

What do you think?

BTW, You can read more about our company, Petroleum Habitats, and the science at www.petroleumhabitats.com.

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