Use this link and pay special attention to Page 5 Bossier data and to Page 9 "Horseshoe" wells.

https://investors.comstockresources.com/static-files/5a596a22-02f6-...

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In the analyst Q&A for the latest Comstock event, it was indicated that 50% of the Western Haynesville gas was going to hedged. That realized price will have a big impact on things.

I am pretty sure that the recent Trinity Gas storage well drilling (6-7 wells) at Bethel Dome in NW Anderson County is tied to Comstock. Taking produced gas and storing it for higher pricing.

Note that Comstock mentioned putting gas into a processing plant at Bethel Dome - is this a coincidence???

Comstock has permitted a 23+ mile step out in this Western Haynesville trend / location in Freestone County (Olajuwon 1H). I am thinking they drill this soon to determine if the play does run out into this deeper part of the E Tx basin.

And although not mentioned in this quarterly report, Comstock has drilled stacked laterals in the Western trend - I expect to hear more public comment on these wells during year-end report.

Considering the massive thickness of the combined Bossier / Haynesville section in the Western Fairway (2000 to over 4000'), multiple target intervals and landing zones are to be expected.

Good info, Rockman.

Does anyone know... if they send produced gas to a storage facility from the wellhead, is the royalty owner paid then or paid when the stored gas is actually sold? Hmmm... seems like it would have to be when it is stored. If so, that would mean that any profit made from stored gas is solely for the producer. If each well had its own storage facility, a royalty owner could be paid when finally sold to the market, but each well having its own storage probably likely doesn't dollar up.

HY 

That is a great question.

I don't think that one needs separate storage wells / "containers" for each well - once produced gas is metered from well from which it came, the operator has a MCF number and Btu value for royalty payments.

Now the question is - when are royalties paid?

I don't have that answer - but I am betting the royalty owners are paid based on the initial production and that the operator gets the benefit of higher prices down the road once gas is pulled out of storage and sold to end user.

I welcome other comments on this topic.

Of course, if a royalty owner did not get paid upon production but paid when the gas is sold from the storage, the price might not reflect a profit, it might be lower. I stand by my original thought that royalties are likely paid upon production at the wellhead. Shut-in royalty also crept into my mind. Kind of a can-o-worms situation if it's not paid upon being produced.

In my experience, I have not seen a producer send gas from the wellhead through a processing plant and into storage for retrieval at a later time. I am not saying it doesn't happen, but it is not the most common practice. One of the primary reasons for this is that producers require cash flow, and their only source of cash is to sell their products as soon as possible. Other strategies, such as hedging, can influence a producer's financials and don't require physical delivery and retrieval of natural gas to a storage facility.

All Haynesville/Bossier gas must be processed to remove impurities (mostly CO2 and H2S) at processing facilities. Most commonly, the gas is sold to several clients, including local distribution companies, interstate pipeline companies, marketing/trading companies, or large industrial users at the tailgate of the processing facility. The mineral owner will receive royalties whenever this first transaction occurs, and the producer will be paid for its gas.  

Once the first transaction occurs, nothing downstream impacts royalty payments. In my opinion, there is no reason for producers in Haynesville to pay additional costs to send their gas to storage and then try to market and sell it at a later date when, hopefully, prices are high. I was (and still am) an advocate of the producer acting like their own storage company by curtailing production when prices are extremely low.  Each producer will require a certain amount of cash flow to pay for development, G&A, financing, etc.  Beyond that, there is an opportunity to reduce production while prices support it and increase production when prices increase.

There are a number of natural gas Gulf Coast storage caverns under construction currently. 

Gulf Coast Gas Storage Activity Picks Up, and More Projects Are In the Works

Read more blogs from this series


Very little new natural gas storage capacity has been built along the Gulf Coast the past few years, but that’s changing. Driven by rising demand from power generators, LNG operators/offtakers, marketers and traders for storage with high deliverability rates — and by improving storage economics — new salt-cavern and depleted-reservoir capacity is now being developed by midstream players large and small, with plans for a lot more. In today’s RBN blog, we‘ll continue our review of gas storage projects in Texas, Louisiana and Mississippi with a look at what Kinder Morgan, EnLink Midstream and Enstor Gas have been up to.

As we discussed in Part 1, a combination of factors — among them, rising gas production, increasingly undulating demand for gas (tied in part to the ups and downs of wind and solar power), frequent extreme weather events, new LNG export capacity, and plans for tens of thousands of megawatts (MW) of new gas-fired power generation — have been increasing the value of Gulf Coast gas storage or, more specifically, the merit of quickly injecting and withdrawing gas to respond to market swings. There’s a caveat though: While gas storage capacity is increasingly valued for its role in providing volume assurance and the opportunities created by high deliverability, that doesn’t necessarily mean storage values will be high enough to support the large-scale buildout of new facilities. Instead, the development of new storage capacity is likely to be very targeted — it will happen only where it clearly makes economic sense.

Last time, we looked at the big chunk of Gulf Coast gas storage assets in Louisiana and Mississippi that midstream giant Williams acquired earlier this year from Hartree Partners for $1.95 billion — six facilities with a combined capacity of 115 Bcf — as well as recent comments from Williams suggesting that rising storage rates and interest in storage capacity may soon justify the development of new brownfield (and possibly greenfield) projects. We also looked at Enbridge’s more than 100 Bcf of Gulf Coast salt-cavern storage — including its 35-Bcf Tres Palacio and 22-Bcf Moss Bluff salt cavern facilities in Texas and its 29-Bcf Bobcat and 21-Bcf Egan sites in Louisiana — and the favorable environmental assessment it received from federal regulators in May for a planned 6.5-Bcf expansion at Tres Palacios. Today, we turn our attention to three other companies with existing storage and plans for more.

Kinder Morgan

Kinder Morgan is a big dog in gas storage, not just along the Gulf Coast but nationally, with full or partial ownership in more than 700 Bcf of storage capacity, including more than 155 Bcf (light-blue tank icons in Figure 1 below) along or near the midstream giant’s Texas and Tejas intrastate pipeline systems (brown and purple lines): 99.4 Bcf of capacity at West Clear Lake, 27.8 Bcf of capacity at its recently expanded Markham Storage facility in Matagorda County (more on that in a moment), 11 Bcf at Dayton North, 1.4 Bcf at Stratton Ridge and (if you include West Texas) 6.4 Bcf at Keystone. Kinder also has 1.4 Bcf of storage (Bear Creek) in northern Louisiana along the Southern Natural Gas (SONAT) system (medium-blue tank icon and yellow lines, respectively), in which it holds a 50% stake.

Figure 1. Kinder Morgan Gulf Coast Gas Storage and Related Assets. Source: RBN

Figure 1. Kinder Morgan Gulf Coast Gas Storage and Related Assets. Source: RBN

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FYI - Comstock just spud (11/15) their Olajuwon 1H well in the Western Haynesville (and Bossier) trend.

This is a 23+ mile step out from the nearest drilled lateral in this deep trend.

This well is in SE Freestone County in the deeper part of the East Texas Basin between Red Oak and Oakwood.

If successful, this well proves up significant area for this trend

Thanks, Rock Man.  Just of much deeper is this step out compared to the very deep production wells.  The 23+ mile step out is a long way but I guess not so much for an unconventional reservoir if indeed the Western Haynesville is an unconventional play.

Definitely moving into deeper part of the basin. With prospective Bossier / Haynesville gross interval being in the 3000' to 4000+' range, it will be interesting to see just where they land this first lateral.

I am estimating that TVD of lateral will range from around 15,000' to as deep as 18,000-19,000'

What kind of bottom home temps would you expect with an 18k to 19k TVD?

In excess of 400 degrees F.

In the Leon / Robertson County area, Comstock (and I assume Aethon) are running drilling mud through refrigeration units before pumping them downhole to help with drilling in these very high temp conditions.

Frac effort also using exotic fluids and methods to handle the formation temperatures. Plus using super high strength synthetic proppants.

Major cooling units needed to "cool off" produced gas before putting it into any gas line.

I talked to a colleague who has done downhole work on the wells in Robertson and Leon counties.  He indicated that static bottom hole temperatures are around 375F, while temperatures during drilling operations can approach 400F.  Downhole tools don't survive long operating in temperatures much above 400F which is why operators are running mud coolers. There are also operators in the "legacy" Haynesville basin using mud coolers and having great success improving the life of their downhole tools. This is one of many optimizations that has led to drilling 15,000ft laterals in the time it used to take to drill 5,000ft laterals.  Every trip you can save at this depth is several days and potentially millions of dollars.

I'll be very interested to see the costs and performance results of horizontal wells drilled at 18-19,000ft TVD.

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