Negative Gas Prices in the Permian

Yes, you have to pony up $$$ to flare.

  • Like 1

Share this post


Link to post
Share on other sites

15 hours ago, Marina Schwarz said:

"Energy Independence" is just around the corner ... just after going over the edge of the cliff ...

  • Like 2

Share this post


Link to post
Share on other sites

I'm having a hard time wrapping my head around this. Why send it to the pipelines at all and not store it? Use it-or-pay basis?

  • Like 2
  • Upvote 1

Share this post


Link to post
Share on other sites

Along with electric power, at least some of the time.

ERCOTRealTime20180411TooCheepToMeter.png

  • Like 2

Share this post


Link to post
Share on other sites

NG to LNG (export) is the key for NG prices and the numerous petchem facilities to be built along the USGC will help also plus the pipeline take away capacity being expanded . Another good and viable option is the compact GTL plants, that can utilize in basin gas and convert to liquids and or NG to direct liquid fuels.

_____________________________________

 

  • 3 Apr, 2019


EagleClaw gives green light for 1.2-Bcf/d Permian gas line to Waha hub

EagleClaw Midstream Ventures LLC will build a new residue natural gas transportation pipeline from the prolific Permian Basin to the Waha, Texas, hub to connect growing supplies with takeaway options farther downstream.

The midstream company backed by Blackstone Energy Partners and I Squared Capital said April 2 that it reached a final investment decision to build the 1.2-Bcf/d, 40-mile Delaware Link pipeline from EagleClaw's three existing gas processing facilities in Reeves County, Texas. It is also considering expanding the project's 30-inch-diameter and capacity "given the level of producer inquiry," according to a statement.

EagleClaw did not provide details about how much the project will cost and when it is expected to come online.

The interconnections available to Delaware Link will include the Permian Highway pipeline under development by EagleClaw, Kinder Morgan Inc. and Exxon Mobil Corp., expected to begin service in the second half of 2020. EagleClaw also announced that it started commissioning its fourth Pecos Bend cryogenic processing plant due to start up in May, upping the company's total interconnected processing capacity in the Delaware Basin to 1.3 Bcf/d. It aims to bring a high-pressure connector line online in June to connect the Sierra Grande site in Culberson County to its system.

In addition, the company disclosed that Jamie Welch will succeed co-founder Bob Milam as CEO. Welch had been EagleClaw's CFO following a stint as group CFO of Energy Transfer LP from 2013 to 2016.

EagleClaw increased its Permian footprint in 2018 with the acquisition of rival Caprock Midstream LLC and I Squared Capital's contribution of Pinnacle Midstream LLC as part of a $500 million equity commitment. Before announcing the Delaware Link pipeline, EagleClaw had nearly 1,000 miles of natural gas, NGL, crude and water gathering pipelines; over 1.4 Bcf/d of processing capacity; crude and water storage and disposal facilities; and nearly half a million acres in the southern Delaware Basin dedicated to midstream services.

The final investment decision came just days after Cresta Fund Management-backed NAmerico Energy Holdings pushed back the startup date for its Pecos Trail gas pipeline from West Texas to the Corpus Christi area to mid-2021 as it continues to gauge shippers' interest amid a rush to alleviate Permian takeaway bottlenecks.

The Waha hub is so swamped with natural gas that prices went negative in late March after a compressor station outage on one of the connecting gas systems.

  • Like 1

Share this post


Link to post
Share on other sites

On 4/3/2019 at 8:10 AM, Marina Schwarz said:

That blurb forgets to mention:

" The Waha hub is so swamped with natural gas that prices went negative in late March after a compressor station outage on one of the connecting gas systems. "

  • Like 1

Share this post


Link to post
Share on other sites

I actually read that in some places, the natural gas goes for -$6 MMbtu (the regular Waha at -$3 on Wednesday..)

  • Like 1
  • Upvote 1

Share this post


Link to post
Share on other sites

I worked on a rig that began drilling that portion of the basin over two years ago and saw the rapid growth of drilling that is still escalating. None of this surprises me considering the number of rigs that were there back then as well as now. We even drilled some wells on the WAHA lease itself. The amount of new pipeline construction in the Coyanosa, TX area is just astounding. Once completed, the entire pricing dynamic of this region is going to change dramatically. Gonna be fun to watch. 

  • Like 3

Share this post


Link to post
Share on other sites

(edited)

You are being misled if you believe this article and extrapolate this to all gas produced in the Permian.  This negative tariff applies to INTERRUPTIBLE  CAPACITY and is for the lowest tier of customers.  If you have firm capacity commitments you get full price for your gas.  This kind of reporting is BEYOND STUPID!  It is either complete ignorance on the part of the writer or it's purposely misleading with the intent to paint a different picture than what is really going on out there.

All of my gas is being marketed at $6.50 to $7/mcf including liquids.  

Edited by wrs
  • Like 1

Share this post


Link to post
Share on other sites

(edited)

On 4/4/2019 at 12:47 AM, Marina Schwarz said:

I'm having a hard time wrapping my head around this. Why send it to the pipelines at all and not store it? Use it-or-pay basis?

If you don't have a firm capacity commitment this is what happens. Producers make firm capacity commitments on new pipelines to make sure this doesn't happen to them.  Then they have to provide the volume of product they committed to or pay a penalty.  Whatever the capacity of the pipelines out of the Permian is, those with firm commitments are not being dinged and that gas is being sold at what are right now very good prices.  The NGLs that are stripped out are currently worth more than the gas remaining after processing.  My wells are currently receiving between $6.50 and $7.00 per mcf for gas (inclusive of NGLs).

Edited by wrs
  • Like 1

Share this post


Link to post
Share on other sites

Anyone that trades gas from the Permian basin knows that no one is getting $6-7/mmbtu for their gas including liquids.  That is total BS.  Sure if you have firm transport out of the Permian to, say the Gulf Coast, then you will get the price at that point, which is no where what wrs is touting.  Pick up a Gas Daily and look at both the bidweek prices and the daily prices and the volumes traded and you will see what prices are traded.  Look at trades on ICE.  WRS your $7 gas is all in your mind.  If producers want to flow their crude, they have to get rid of their gas.  Flaring is limited by the states, so if you can cram gas into a pipeline selling at the wellhead or via firm or interruptible transport you take what price you're given.

Share this post


Link to post
Share on other sites

(edited)

I am extracting the info on the 1h well from the  most recent XTO check stub as it includes all prices.  This is $7.07/mcf if calculated at 10mmcf which is the residual volume.  If you assume 30% shrinkage then it's $4.95/mcf.  Not all operators are stranded.  The NGLs are worth more than the residual gas.

1hpayout.png

Edited by wrs
  • Like 1

Share this post


Link to post
Share on other sites

On 4/4/2019 at 12:38 AM, Tom Kirkman said:

"Energy Independence" is just around the corner ... just after going over the edge of the cliff ...

We could easily be energy independent by using more natural gas and less diesel. 

  • Like 1

Share this post


Link to post
Share on other sites

On ‎4‎/‎5‎/‎2019 at 1:12 PM, wrs said:

I am extracting the info on the 1h well from the  most recent XTO check stub as it includes all prices.  This is $7.07/mcf if calculated at 10mmcf which is the residual volume.  If you assume 30% shrinkage then it's $4.95/mcf.  Not all operators are stranded.  The NGLs are worth more than the residual gas.

1hpayout.png

WRS

I get $40.88/BOE for your natural gas including NGL, based on the payment statement above.  About 29% of your revenue for that well comes from natural gas and NGL. and also 29% of your BOE is from natural gas, wow you get a lot for your natural gas and NGL, is this typical or was January a strange month?

Share this post


Link to post
Share on other sites

(edited)

4 hours ago, D Coyne said:

WRS

I get $40.88/BOE for your natural gas including NGL, based on the payment statement above.  About 29% of your revenue for that well comes from natural gas and NGL. and also 29% of your BOE is from natural gas, wow you get a lot for your natural gas and NGL, is this typical or was January a strange month?

This is about as good as it gets for gas and NGL.  Depending on the different markets, NGLs go up and down but as you can see, ethane is a big contributor.  The volume of ethane in West Texas gas is pretty substantial but before China quit taking recycled plastic and producing recycled plastics, ethane was as low as seven cents a gallon.  Propane, butane and natural gasoline always fetch good prices.  The residual gas is good at $2.77, the late fall and early winter are when the residual gas prices are highest.  So this is seasonally good for gas and NGLs but oil comes back up in the spring and summer while the residual gas goes down.  So when oil is up, gas might be more like 20% of the royalties. 

The point is that there is more to the associated gas than just dry gas.  The headlines are misleading because NGLs are at least as valuable as the residual gas if not more in many months.  So whenever they post these silly WAHA prices, just know they don't apply across the board and even to the operators that do get penalized, they offset that with the NGLs that get processed.

Edited by wrs
  • Great Response! 1

Share this post


Link to post
Share on other sites

The -ive prices will go up in smoke!! Even the end result in most cases, the -ive prices are not -ive at the end of the day when settlement is made for various components of the gas

____But more take away capacity means more access to demand heavy markets

________________________________

 

Permian gas pipeline could ease bottlenecks, give global access

For $3.7 billion, Permian Global Access Pipeline LLC intends to build a shale gas pipeline that would connect the Permian shale play to Lake Charles, Louisiana. The shale gas would be utilized by Tellurian Inc., a publicly traded natural gas entity looking to source natural gas from the U.S. for export across the globe.

An open season call on the pipeline has been started. If completed, the pipeline will use a 42-inch diameter line to move roughly two billion cubic feet per day of natural gas. For Tellurian, the pipeline is only part of a larger infrastructure buildout plan. In total, Tellurian wants to invest $7.3 billion in U.S. infrastructure in addition to another $15.2 billion on a liquified natural gas export facility in Lake Charles.

The Permian is currently one of the top shale gas producing regions in the world. Meg Gentle, CEO, said producers there have had to pay $9.00/mmBtu just to move their gas from the region to outside markets.

The proposed pipeline would originate in Pecos County, Texas. Construction could be finished by

2023.

The U.S. currently has one LNG export facility located in Louisiana. By 2021, the U.S. Energy Information Administration believes the country will house five LNG export facilities capable of exporting 9.2 bcf/d.

According to April data from the EIA, the Permian is producing more than 14 mcf/d of shale gas.

Gentle said in addition to helping Permian producers, some of the natural gas sourced from West Texas could be used in Louisiana.

“Southwest Louisiana is a market expected to grow 300 percent in the next five years,” she said. “The Permian Global Access Pipeline is critical infrastructure that will interconnect stranded Permian gas production with growing markets, reduce flaring, and provide a valuable cleaner fuel to reduce urban pollution and carbon globally.”

Earlier this year, Tellurian also signed a long-term offtake deal with India for LNG sourced from the U.S.

image.png.74e13f0612425655f5a1d79c9242e48d.png

Share this post


Link to post
Share on other sites

If gas is cheap,it could be converted to liquids by Fischer-Tropsch. The standard proven ammonia plant has externally-fired steam reforming followed by addition of exothermic air to give a gas with high hydrogen:carbon monoxide ratio and 22% nitrogen. Putting this through a SASOL Synthol reactor without recycle would produce high-value liquids and leave a tail-gas containing hydrogen and a high proportion of inerts. General Electric  and others have found that this sort of mixture can be used in a gas turbine.

  • Great Response! 1

Share this post


Link to post
Share on other sites

Negative Permian Prices a Positive for Some

Sunday, 04/14/2019 JF

 

 

It’s said that everything is bigger and better in Texas, and when it comes to the magnitude of negative natural gas prices, the Lone Star State recently captured the crown by a wide margin. By now, you’ve probably heard that Permian spot gas prices plumbed new depths in the past couple of weeks, falling as low as $9/MMBtu below zero in intraday trading and easily setting the record for the “biggest” negative absolute price ever recorded in U.S. gas markets. Certainly, that was bad news for many of the Permian producers selling gas into the day-ahead market. But every market has its losers and winners, and negative prices were likely “better” — dare we say much better — for those buying gas in the Permian. Today, we look at some of the players that are benefitting from negative Permian natural gas prices.

The Permian gas market has been keeping us busy lately, with wild prices swings that can’t go by without some explanation. As we’ve detailed in previous blogs on the topic, those swings have been driven by limited takeaway pipeline capacity that will continue to impact the Permian gas market until Kinder Morgan’s Gulf Coast Express Pipeline starts up later this year. Two weeks ago, in Don’t Dream It’s Over, we discussed the most recent price plunge at the region’s Waha Hub. In that blog, we detailed how pipeline maintenance and steady gas production growth further congested an already constrained market and pushed prices into negative territory for the third time in the past five months. We first saw Waha prices fall below zero during intraday trading in November 2018 (dashed purple circle in Figure 1; see Keep Breathin’ for more on that event), and subzero pricing returned in February (dashed orange circle; see King of Pain). But as we had expected, those first two negative-price events were just the beginning and, as it turns out, only blips by current standards.

The most recent negative-price event in late-March/early-April (dashed red circle) marked the first time that daily trades set not only an intraday low in negative territory (going as low as minus-$9/MMBtu on April 3) but also averaged below zero — and not just for one day but for multiple trading days, including for 10 days straight from March 25 to April 5. Even the intraday high on some of those days was in negative territory. While day-ahead spot prices last week improved dramatically — the daily average returning to positive on many days — they’re still on track to average below zero this month, and the forward price for May is also negative, indicating the oversupply situation continues to weigh heavily on the Permian gas market.

Fig1_PermianGas_2.PNG?itok=QsWe0SvF

Figure 1. Waha Daily Cash Prices. Source: Natural Gas Intelligence (Click to Enlarge)

We’ve talked a lot previously about how this type of distressed pricing affects producers. With this new reality in place for at least a few more months until new gas pipeline takeaway capacity arrives, it’s worth also evaluating who might be benefitting from the price crash — that is the focus of today’s blog. Before we get to that though, it’s necessary to briefly recap the major components of the Permian natural gas supply-demand balance at a high level (the more detailed Permian gas supply-demand balance is available in our weekly NATGAS Permian report). As it stands today, the Permian is producing about 9.5 Bcf/d of dry natural gas, of which an average of about 8.5 Bcf/d leaves the basin on pipelines heading in one of four general directions: south to Mexico, west to California, north to the Midwest, and east to the Texas Gulf Coast. (For more on how gas flows out of the Permian, see our Omaha blog from last spring.) That leaves about 1 Bcf/d or so in the region that is either consumed by local demand in the Permian or injected into gas storage facilities.

The largest source of local demand for Permian gas is power generation plants. So, with takeaway capacity out of the region constrained, it stands to reason that the region’s power sector is likely to be one of the biggest benefactors of the negative Permian gas prices. And, as much as gas-fired generators in the region are able to ramp up in response to the low prices, it could also help put a floor under how low prices go. The question is, can power plants alone soak up enough incremental gas to keep prices from getting worse in the Permian? Next, we take a closer look at the region’s current and potential gas demand for power, starting with a breakdown of power plant capacity in the area. (We’ll also come back to the potential role of gas storage later in this blog series.)

As shown on the map in Figure 2, the Permian Basin is home to eight generation plants that are powered by natural gas. The largest of these plants is the 1,054-MW Odessa-Ector Power Plant, a combined-cycle facility located in Ector County, TX (green circle #1 on the map). The plant’s combined-cycle technology makes it one of the most efficient generators in the region, and at full utilization, it can burn approximately 190 MMcf/d of natural gas, by our calculations. (For more on estimating gas consumption for power plants, see The Strange Magic of Turning Btus Into Kilowatt-Hours.) The Odessa-Ector plant is operated by Luminant, a subsidiary of Vistra Energy, and produces electricity for the Electric Reliability Council of Texas (ERCOT) electric grid. The plant is just slightly larger than another combined-cycle facility in the Permian: the 958-MW Mustang plant (light blue circle #2), which is located in Yoakum County, TX. Mustang is owned and operated by Golden Spread Electric Cooperative and produces electricity for the Southwest Power Pool (SPP), which serves all or part of 14 states (including the Texas Panhandle) and has limited interconnectivity with ERCOT. We estimate that Mustang could burn more than 170 MMcf/d of gas at full utilization.

Across the Texas-New Mexico border in Lea County, NM, is another combined-cycle plant, Harbert Management Corp.’s 604-MW Hobbs Generating Facility (dark gray circle #3), which also sells its power into SPP and which could burn up to 110 MMcf/d at maximum utilization, by our estimates. A fourth combined-cycle plant, Quail Run Energy Center (dark blue circle #4), is located back on the Texas side of the border near Odessa-Ector. The 550-MW Quail Run plant is owned by Starwood Energy Group and sells electricity into the ERCOT grid. We estimate that Quail Run could burn about 100 MMcf/d at full utilization.

There are also four other power plants operating in the Permian, but they are all less efficient than the combined-cycle facilities named above and therefore operated less frequently. Two of the plants — both operated by Southwestern Public Service, a subsidiary of Xcel Energy — are located in Lea County, NM, and sell power into SPP. The larger is the 466-MW Cunningham plant, a steam turbine facility that could burn about 115 MMcf/d at full utilization (purple circle #5). The other is the 173-MW Maddox steam turbine just a few miles away (light gray circle #6). We estimate Maddox’s full burn at 100% utilization is just over 40 MMcf/d. The two final plants are both gas turbines, an even less-efficient type of plant that is typically dispatched (that is, called on to operate) only during periods of high power demand. One is Invenergy’s 330-MW Ector County Energy Center in northern Ector County, TX (yellow circle #7), which we estimate could burn about 90 MMcf/d at max rates. The other gas turbine, Luminant’s 325-MW Permian Basin plant, is in Ward County, TX (red circle #8), and rarely is dispatched, as far as we can tell. That said, if operated around the clock at full capacity, the Permian Basin plant could burn about 105 MMcf/d, by our calculations. Both of the gas turbines sell their power into the ERCOT market.

Fig2_PermianGas.png?itok=sBzdFOKA

Figure 2. Permian Basin Power Plant Map. Sources: RBN, Energy Information Administration (Click to Enlarge)

In total, if all the plants in Figure 2 were operating at full capacity at the same time, Permian power demand for gas (i.e. power burn) would total just above 900 MMcf/d. Note that this is the theoretical maximum power burn capacity, given that power plants don’t usually run full tilt 24/7. Actual power burn volumes have been well below that level, though they showed strong increases during 2018. Figure 3 below shows the actual natural gas consumption by the eight Permian power plants from January 2014 through December 2018, which is the latest available month of data from the Environmental Protection Agency’s (EPA) Continuous Emissions Monitoring System (CEMS).

As you can see, total Permian power burn reached a record of just over 550 MMcf/d in the summer of 2018. While far below the theoretical maximum 900 MMcf/d we calculated, that level was more than 30% higher than the peak set during the summer of 2017. The gains came amid significantly weaker Permian gas prices during 2018. Full-year 2018 power burns in the Permian averaged just over 450 MMcf/d, versus about 320 MMcf/d in 2017. It may come as little surprise that the biggest absolute power burn gain in 2018 came from the Odessa-Ector plant, which, as we noted above, has the largest nameplate capacity of the plants in the area and is highly efficient. The plant — represented by the green layer in Figure 3 — burned 55 MMcf/d (57%) more year-on-year in 2018. Big gains were also seen at the other combined-cycle plants, with Quail Run (navy blue layer) up 22 MMcf/d (112%), Mustang (aqua blue layer) gaining 20 MMcf/d (30%), and Hobbs (medium gray layer) burning an additional 17 MMcf/d (24%). Even the less-efficient steam and gas turbine plants posted substantive gains:  the Cunningham plant (purple layer) gained 13 MMcf/d (48%), and the Ector County plant (yellow layer) burned 7 MMcf/d (54%) more, while the Permian Basin plant (red layer) gained 2 MMcf/d (83%). The one exception was the Maddox plant (light gray layer), which consumed just 0.374 MMcf/d (3%) more year-on-year.

Fig3_PermianGas_1.PNG?itok=n8clwW22

Figure 3. Permian Power Plant Gas Consumption. Source: EPA CEMS database (Click to Enlarge)

What’s apparent from the trend in Figure 3 is that Permian gas burn has been reacting predictably to lower prices. When the CEMS data is released in a few months for March and April of this year, it will very likely show a significant spike for this period. In fact, looking at it from the pipeline flows perspective, Permian-area power plant deliveries off of Berkshire Hathaway’s Northern Natural Gas Pipeline, for one, reached a record two weeks ago, according to pipeline data tracked in our NATGAS Permian report, suggesting total power burn might have set a record at that time. Considering the very low, potentially negative, prices power producers likely paid for that natural gas, it’s safe to assume that power plants in the Permian have had a very good run lately.

That leads us back to the question, will that incremental power burn alone soak up enough gas to keep prices from getting worse in the Permian? While that’s difficult to calculate for any one given day, there are a few factors to consider. On the one hand, the market has just entered shoulder season and power plant demand is very likely to continue increasing as summer cooling season begins in earnest. But, on the other hand, the upside to power burn is still capped by our theoretical maximum power plant capacity of 900 MMcf/d calculated earlier, and even that maximum would be difficult to reach given plant maintenance events and other physical constraints. And there’s one more thing: As we said in Runnin’ Against the Wind, West Texas for years has been a hotbed of wind-farm development, and when the wind is blowing (as it often does), the need for gas-fired generation is reduced.

So, while we’re not saying a maximum summer peak burn near a rate of 900 MMcf/d is impossible if prices remain negative, the plants are just not likely to see that type of burn around the clock, especially with forward gas prices in the Permian still modestly positive for the summer season, at least for now. In our view, more Permian power burn records will be set this summer, but the gains are unlikely to be enough to eliminate the possibility of negative prices in the spot market during injection season, particularly during maintenance events or if Mexico exports don’t increase. As a result, the Permian will become increasingly reliant on storage injections. We estimate Permian gas storage facilities exited winter at historically low levels but have been aggressively injecting over the last few days at a rate of about 400 MMcf/d. How long injections can continue to offset the effects of strained pipeline capacity will be a subject we’ll discuss in the weeks ahead.

  • Great Response! 1

Share this post


Link to post
Share on other sites

(edited)

On 4/5/2019 at 12:12 PM, wrs said:

I am extracting the info on the 1h well from the  most recent XTO check stub as it includes all prices.  This is $7.07/mcf if calculated at 10mmcf which is the residual volume.  If you assume 30% shrinkage then it's $4.95/mcf.  Not all operators are stranded.  The NGLs are worth more than the residual gas.

1hpayout.png

Those prices for the residue don't make a whole lot of sense.  The highest daily Waha trade was for the month of January was $2.675, and the FOM price was $1.54  In addition, 1.3265 for a btu factor is WAAAYYY out of transmission line spec.

But all that is relatively pointless.  You pulled a check for January production, and the whole point of this post was pricing in late March and early April.  Let's see that one when you get it.

Edited by SLL

Share this post


Link to post
Share on other sites

On 4/4/2019 at 12:47 AM, Marina Schwarz said:

I'm having a hard time wrapping my head around this. Why send it to the pipelines at all and not store it? Use it-or-pay basis?

Unless you use it for some sort of EOR, WTX and SE NM is pretty much devoid of natural gas storage facilities.

  • Like 2

Share this post


Link to post
Share on other sites

I have mentioned some where else on this forum recently and last year about the various options for produced gas before pipelines and processing/gathering facilities are in place to prevent the flaring.

These options below can be deployed rapidly in comparison to large scale facilities and can be dismantled and relocated to a new location/new production  basin as needed in the future.

One has to understand that when E&P companies go into an area to explore and drill, the midstream companies (pipelines, oil and gas separation and processing plants, storage and other related infrastructure and services companies) do not go before the E&P companies to lay the pipe and develop the infrastructure, until such time the basin/region proves out to be containing substantial resources (oil gas etc) for years to come and can be sustainable for the long term. Once that is established , they rush in to provide the services and develop the infrastructure. Federal, State and Local permitting is also a major factor how fast these facilities are developed and put into operations.

This, however does not preclude the E&P companies nor the services companies to sit idle and just flare the gas. Can you imagine if E&P companies just let the oil flow out of the wells into the fields and ditches and waterways? Why spew the gas then into the air?!!!

The industry needs to cooperate and collaborate with each other and out of industry players with the right techs and concepts to develop meaningful, sustainable, cost effective, environmentally safe methodologies, technologies and applications and implementation of all these to maximize the use of the resources available and being developed.

1) Produced gas re-injection into the formation or into another zone for later use and or increasing liquid hydrocarbons production volume sa an EOR for liquids recovery.. We tried that in several different parts of the country and different countries and it worked well. Saved a valuable resource for future use and also prevented the air quality issues etc.

2) Compact (and or small scale) GTL plants that would convert the gas to liquids fuels . There are several companies that offered the solution in the oil and gas fields and provided it as a service. Some companies provide tech services that will convert the natgas to high quality methanol, ethanol, formalin/formaldehyde and other petrochem feedstocks and liquid fuels  and further use of inhouse tech to components of cleaner burning fuels. This adds value to the end product compared to just the lower value of the gas and these liquids can be transported off site by tanker trucks with ease or stored at a nearby storage facility for further transportation via rail or connect to a products pipeline if feasible.

3) Compact LNG plants , offering the same as 2) for easy onsite or near site within a play /field region for gas to LNG and further transport by LNG trucks to points of storage/transport or re-gasification

4) On or near sites of production and or production basin based compact NG- LPG plants

5) Portable/mobile natgas power plants that can provide electric power to the operators on site and also can connect that generated electric power into the grid

6) Develop regional gas storage hub as the E&P companies ramp up exploration and production in the basin or region. It could be in salt caverns or man made storage facilities as the production is ramping up. It will require shorter pipeline distances or temporary pipeline setup that are safe and reliable to move the produced gas to the nearby basin /regional storage hub. Collaboration would be required with the permitting and approval process for these as well. Once the trunk pipelines are in place, the companies can move the stored gas to areas where the demand is.. power plants, main gas storage hubs, LNG plants etc.

 

Just some thoughts, some of which have been executed and implemented with success!

  • Great Response! 1
  • Upvote 1

Share this post


Link to post
Share on other sites