Gas Flaring

4 hours ago, ceo_energemsier said:

Great story! Added to Natural Gas News. https://docs.google.com/document/d/1_QZTgxCECgIj7EItX9P6Q2J4BjsSt_nPyrDG1zAl4b0/edit#heading=h.kuslkgqytxpd

There is some trucking of LNG to New England. CNG is also trucked. I think most of it goes to individual plants. 

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2 hours ago, ronwagn said:

Great story! Added to Natural Gas News. https://docs.google.com/document/d/1_QZTgxCECgIj7EItX9P6Q2J4BjsSt_nPyrDG1zAl4b0/edit#heading=h.kuslkgqytxpd

There is some trucking of LNG to New England. CNG is also trucked. I think most of it goes to individual plants. 

I am not sure if you read my post earlier on this discussion topic re. the options available to not flare.

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1 hour ago, ceo_energemsier said:

I am not sure if you read my post earlier on this discussion topic re. the options available to not flare.

I think I have. I have been saying the same thing for quite a while. They can do whatever they need or want to do with the natural gas. No pipelines are mandatory. I have all the information in my natural gas stories if anyone wants them. Plenty of companies will be happy to assist them in the various processes and provide the equipment needed. 

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Personaly, I can't figure why someone doesn't combine modular power generation with Bitcoin compute ASIC's and profit?

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Being able to use the gas for power or fuel would be great.  Problem is, the stuff coming out of the ground when the wells come on is often high pressure, and field gas can have a lot of other stuff in it besides methane and/or NGLs.  The tender tummies of turbines and LNG trains can't eat it as-is.  Dropping out NGL at the lease means high pressure trucks and storage tanks that cost a lot more than the ones for oil and wster.  Bottom line, it costs a lot more to handle the gas stream per dollar of revenue than oil.  So oil comes first.  

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On 4/17/2019 at 9:10 AM, ceo_energemsier said:

Sempra is also developing Port Arthur LNG project in Texas and Energía Costa Azul (ECA) LNG Phase 1 and Phase 2 in Mexico.

How pathetic and disgusting are the idiots in CA/OR/WA that they will not make LNG terminals... USA will now export gas to Mexico, who pipe it clear across Mexico, so they can turn it into LNG on the border of California by San Diego and export it...  Watch CA start to import the stuff... Who wants to lay bets that CA will start importing LNG...

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6 minutes ago, Wastral said:

How pathetic and disgusting are the idiots in CA/OR/WA that they will not make LNG terminals... USA will now export gas to Mexico, who pipe it clear across Mexico, so they can turn it into LNG on the border of California by San Diego and export it...  Watch CA start to import the stuff... Who wants to lay bets that CA will start importing LNG...

It is extremely disgusting, sickening and pathetic and idiotic.

One of the company's we have, we will be providing support to the the Mexican industry players, to build a pipeline(s) to run through mostly uninhabited areas south from TX to Mexico's Pacific coast for a deep water port for export of Permian/Eagle Ford other crude and petro products that would go over to the PacRim, Far East ..... CA wont give a permit to build or even reverse existing pipeline(s) and take it to the USWC for export.

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23 minutes ago, ceo_energemsier said:

It is extremely disgusting, sickening and pathetic and idiotic.

One of the company's we have, we will be providing support to the the Mexican industry players, to build a pipeline(s) to run through mostly uninhabited areas south from TX to Mexico's Pacific coast for a deep water port for export of Permian/Eagle Ford other crude and petro products that would go over to the PacRim, Far East ..... CA wont give a permit to build or even reverse existing pipeline(s) and take it to the USWC for export.

Double Sick: Sempra is based in San Diego/LA...  You know they tried to make it in the USA first...

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Addressing energy and environmental challenges through commercializing flare gas for productive use

Associated gas AG) is produced from the reservoir during oil production. In this post, Tetra Tech’s John Sachs, Director of Project Finance, and Artur Davtyan, Manager of Project Finance, discuss how AG could be used to fuel power plants, used as bottled gas, serve as a feedstock, exported as liquid natural gas (LNG), or put to other productive use with contributions by John Beardsworth and William Newton of Hunton Andrews Kurth, LLP. All opinions expressed in this post are the authors’ own. 

INTRODUCTION

Instead of being put to productive use, an estimated 140 billion cubic meters of AG is flared every year, equating to more than USD$10 billion of resource value. Flaring contributes approximately 350 million tons of CO2 emissions to the atmosphere annually, in some cases having been cited as having a negative impact on the health and livelihoods of local populations.

While much progress has been made in recent years to reduce flaring, AG continues to be flared at thousands of oil production sites around the world. A further reduction may be achieved through a market-oriented approach to commercialization that can produce a win-win-win: for the oil producer, the buyer and seller, and the environment.

Levels of Associated Gas Flared by Country in 2017

 

THE DIFFICULTIES IN COMMERCIALIZING AG

AG is frequently viewed by oil producers as an unwanted byproduct of oil production. Though flaring can be reduced through the commercialization of AG, doing so requires the resolution of many constraints and the creation of appropriate incentives.

The technology to address the problem of AG flaring is well developed and can include gas reinjection for enhanced oil recovery (EOR), power generation, compressed natural gas (CNG), liquefied natural gas (LNG), gas-to-liquids (GTL), and processing and pipeline development. Rather, AG continues to be flared due to a combination of factors related to physical characteristics and infrastructure, and the legal, policy, and market factors that must be overcome to successfully commercialize AG.

FLARE GAS MONETIZATION CHALLENGES

 

PHYSICAL CHARACTERISTICS AND INFRASTRUCTURE

AG is produced as a byproduct of oil production and is subject to production fluctuations, given that the ratio of AG to oil naturally varies over time.In addition, the physical solutions can be very flare-site specific: AG can be found far offshore, in remote and scattered locations. Volumes may vary significantly from site to site. Distance to demand centers, as well as infrastructure (pipeline, transmission lines, etc.), also impact the commercial viability of gas utilization projects.

LEGAL, POLICY, AND MARKET

Legal uncertainties and lack of enforcement of anti-flaring regulations also contribute to the problem. The greatest flaring often occurs in countries where legal uncertainties or lack of anti-flaring policies exist. Subsidized hydrocarbon prices and regulated end-product prices may result in a market distortion that impedes investment in gas monetization projects.

While the scale and complexity of AG flaring may seem discouraging, some large oil producing countries and oil producers have taken important steps to reduce flaring. Routine flaring is no longer as widely accepted as a standard business practice. Countries such as Saudi Arabia, Norway, Kuwait, the United Arab Emirates, and Canada all have taken steps to harness and put AG to productive use. Other countries also now require that any new field development plans include provisions for sustainably managing the AG and putting it to productive use.

SUCCESSFULLY SELLING ASSOCIATED GAS

While producers typically have the right to use AG to support oil production (e.g., reinjection for EOR, power production at the site), under many production sharing agreements or statutes, governments often have ownership of any surplus AG. Unfortunately, the governments of developing countries often do not have the expertise or the capital to develop their own AG capture and monetization projects. Typically, the oil producers, who are physically in charge of production, have technical expertise, and are better capitalized. Thus, one option to provide for the commercialization of AG is to remove the government’s preemptive rights to authorize private sector development of AG capture and monetization projects or the private sector sale of the AG.

Where a government owns AG, another option for monetization is for the government to sell the AG itself. A properly administered government-run auction can bring benefits that a producer-run auction may not be able to offer, such as enabling buyers to purchase from multiple flare sites across the country, providing tax incentives, or addressing political risk.

Many governments in oil-producing countries are familiar with the lease of oil blocks, so the sale of AG may seem like an easy next step. However, differences between AG buyers and oil block lessees need to be factored into the design of any AG monetization efforts. Oil can more readily be exported and sold in USD on the international market to any number of creditworthy parties. AG buyers may need to monetize the product locally, if it is not monetized through an export project, relying on local customers and sales denominated in local currency. Depending on the locale, this can introduce far more risk into a monetization project and attract a different universe of buyers.

To maximize the chance of success, the government seller needs to consider the perspective of the AG buyer and address various issues in the gas sales agreement.

IMPORTANT FACTORS TO A FLARE GAS SALES AGREEMENT  

TERM

A buyer may need a long-term gas supply commitment (typically 15-25 years) to justify the investment needed for development of a project.

RELIABLE SUPPLY; MAKE WHOLE IN CASE OF NON-SUPPLY

A buyer will likely need a consistent and reliable supply of gas, because revenues can be interrupted if the gas stops. In such a situation, a buyer may request that it be kept whole for its financial losses. Where supply is less reliable and make-whole payments are insufficient, AG prices may be low.

RELIABLE QUALITY

A buyer’s project is typically built for a tolerable range of gas specs, and supply of gas outside those specs may impact operations or damage a buyer’s project. Where there are concerns as to potential gas specs, AG prices may be low.

REASONABLE TAKE-OR-PAY

A buyer can usually guarantee a reasonable quantity of gas purchases year-to-year, but a buyer may need some reasonable flexibility.

CREDITWORTHINESS OF SELLER

A buyer will consider the seller’s creditworthiness to protect the buyer’s investment from the risk of a serious breach of contract by the seller.

POLITICAL RISK NOT BORNE BY AG BUYER

In countries where political risks are high, a buyer may request protection from political events.

Readers familiar with international project finance will recognize these as key features to making a buyer’s project bankable. While there are tools to make AG sale and related monetization projects more bankable, structuring the terms and conditions must be done with great care to attract investors.

The tools to achieve a bankable gas sale are available. Where the sale is conducted by the producer, these tools are largely in the hands of the producer. However, where a government is the seller of gas, some of the key factors for creating a bankable project are still under the control of the oil producers, and the commercialization must be done in a manner that includes the producers. For example, the oil producers are in the unique position of controlling production and physical delivery of any AG. As a result, they remain best positioned to manage that risk and to stand behind any such a guarantee (e.g. through a make-whole payment if the AG supply is interrupted). This dynamic effectively requires a government-producer-buyer tripartite relationship. This tripartite relationship, however, is not necessary if the producer itself commercializes the AG.

POLICY ACTIONS TO ENCOURAGE AG MONETIZATION

If putting AG to productive uses were as simple as putting the product up for auction and populating a data room, AG flares would have been extinguished across the globe. While some progress has been made in successfully commercializing AG, enactment of new—or refinement of existing—government policies may be needed to further support its commercialization.

Some of the policy issues are broader than AG. For example, subsidized competing fuels or electricity prices in some countries frustrates the sale of AG or end-products produced from AG feedstock into the local market. Domestic integrated incumbent utilities and the legal and regulatory frameworks applicable to the gas sector also can prevent or stifle the private sector’s development of a natural gas-based business. These policy issues go beyond the AG sector.
Other policy approaches can be targeted at AG, where a mix of carrots and sticks can be used to create incentives for the commercialization of AG. Incentives can include a mix of fiscal incentives, AG commercialization profit sharing, fines, and taxes. As an example, under a carbon tax system AG would not just have zero value, as it does now, but would have negative value since the flared gas would count in the calculation of the carbon footprint. However, several other approaches to setting appropriate flare gas fines exist and do not need to be linked to a carbon tax calculation. Governments also need to adopt transparent and efficient regulatory regimes that cover enforcement of operational standards, flare gas measurement, monitoring, and other requirements. Transparent enforcement of the flare gas regulatory regime creates the right incentives for producers to participate in flare gas commercialization.

There is no one-size-fits-all solution to the commercialization of AG; each set of market reforms, incentives, and policy and regulatory reforms needs to be tailored to the specific country. Significant collaboration between government and producers is needed when tailoring the regulations and policies to ensure they not only meet the government’s objectives of reducing the flares, but also do not unintentionally materially impact oil production.

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Qatar Petroleum issued an invitation to tender for construction of the LNG carrier fleet for its North Field Expansion (NFE) project. The invitation foresees initial delivery of 60 LNG carriers, with the potential to exceed 100 new carriers over the next 10 years. The tender would increase the global LNG fleet by 11-19%. International Gas Union counted 525 LNG carriers at end-2018.

In addition to addressing shipping requirements for NFE, the tender covers shipping requirements for LNG that will be purchased and offtaken by Ocean LNG—a joint venture between Qatar Petroleum (70%) and ExxonMobil (30%)—from the Golden Pass LNG export project in Port Arthur, Tex., which is under construction and planned to start by 2024. The tender also includes options for replacement requirements for Qatar’s existing LNG fleet.

NFE will increase Qatar’s LNG production capacity to 110 million tonnes/year (tpy) starting in 2024 from 77 million tpy. The project will include construction of four new 8.25 million tpy LNG trains, which Qatar Petroleum tendered earlier this month

 

Qatargas will execute the LNG ship building program on Qatar Petroleum’s behalf.

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On 4/20/2019 at 9:23 AM, Bandanna said:

Being able to use the gas for power or fuel would be great.  Problem is, the stuff coming out of the ground when the wells come on is often high pressure, and field gas can have a lot of other stuff in it besides methane and/or NGLs.  The tender tummies of turbines and LNG trains can't eat it as-is.  Dropping out NGL at the lease means high pressure trucks and storage tanks that cost a lot more than the ones for oil and wster.  Bottom line, it costs a lot more to handle the gas stream per dollar of revenue than oil.  So oil comes first.  

The big producers can afford to do it right. You will have to be able to pay to play if Texas gets with it. Too much wasted natural gas resources. 

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  • 23 Apr 2019 | 22:14 UTC
  • Denver

Discounted Permian gas sees potential lift from Wahalajara startup

Highlights

El Encino-Laguna pipeline flows ramp up to 40 MMcf/d

Waha cash up 25 cents/MMBtu from weekend flow dates

Wahalajara could offer outlet for 250 MMcf/d upon completion

 

Denver — Heavily discounted Permian Basin gas could soon access downstream markets in Mexico, following the recent startup of incremental gas deliveries to Fermaca's Wahalajara pipeline system.

On Monday, updated electronic bulletin board flow data showed that a new downstream segment on Wahalajara, the El Encino - La Laguna pipeline, began receiving about 40 MMcf/d on April 17.

In Tuesday trading, cash prices at Waha traded as high at 65 cents/MMBtu, up about 25 cents from weekend flow dates. Forwards prices for May jumped 32 cents on the day, rising to a $2.47/MMBtu discount to benchmark Henry Hub gas on the improving outlook for Permian supply.

The startup of incremental demand on Wahalajara bodes well for Permian producers since all of the system's supply comes entirely from the West Texas play.

Over the past month, about 185 MMcf/d of Permian gas production has flowed westbound on Roadrunner Gas Transmission Pipeline where it meets the border-crossing Tarahumara Pipeline -- Wahalajara's northern-most segment.

After flowing southbound on Tarahumara, an interconnection to El Encino - La Laguna offers access to additional demand in north-central Mexico, and to uncompleted Wahalajara segments and interconnections farther downstream.

Upon its completion, the Wahalajara system could ultimately provide an outlet for an incremental 250 MMcf/d of Permian gas production, according to S&P Global Platts Analytics.

042319-tarahumara.jpg

DOWNSTREAM DEMAND

On Tuesday, flow data provided by Fermaca offered no clear indication on the current southbound reach of Permian gas production. It was also unclear whether recent deliveries to El Encino - La Laguna reflect line-packing or actual demand on the pipeline.

According to Platts Analytics, downstream demand on the Wahalajara system is likely to see its biggest boost upon completion of the Guadalajara interconnect in central Mexico. Recent construction status reports show that interconnection entering service sometime during third-quarter 2019.

Another potential outlet for Permian gas production could come from a connection to Mexico's national Sistrangas pipeline grid. The 70 MMcf/d interconnect at El Encino in Chihuahua state is being jointly developed by Fermaca and Cenagas, Mexico's natural gas system operator.

The interconnect is expected to enter service sometime this year, although Sistrangas has yet to identify a new meter for the project.

WAHA PRICES

The startup of incremental demand on Wahalajara gives Permian Basin gas producers some cause for optimism following an extended period of negative pricing from late March to mid-April.

On April 3, cash prices at Waha settled at a record-low negative-$5.79/MMBtu as gas production reached the ceiling on available takeaway capacity, which was exacerbated by a series of maintenances.

Following the much-anticipated, full ramp-up in demand on Wahalajara, the next major pipeline expansion isn't scheduled to enter service until early autumn.

With the startup of Kinder Morgan's 2 Bcf/d Gulf Coast Express pipeline in October 2019, and an anticipated in-service date of late 2020 for the midstream developer's 2.1 Bcf/d Permian Highway Pipeline, Platts Analytics anticipates a longer-term resolution for Permian producer's gas transportation constraints, at least though the early 2020s.

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Houston (TX) Chronicle
Houston oilfield service company Baker Hughes is using the Permian Basin in West Texas to debut a fleet of new turbines that use excess natural gas from a drilling site to power hydraulic fracturing equipment — reducing flaring, carbon dioxide emissions, people and equipment in remote locations. Baker Hughes CEO Lorenzo Simonelli spoke about the company’s “electric frack” technology during a Tuesday morning investors call. The company said its first quarter profit fell more than half to $32 million from $70 million during the same period a year earlier. Revenues rose to $5.6 billion from $5.4 billion revenue inthe first quarter of 2018. As production continues to outpace pipeline construction in the Permian Basin, operators are burning off, or flaring, an estimated 104 billion cubic feet of natural gas per year instead of shipping it to market. Simonelli said he views wasted natural gas, a byproduct of oil drilling, as a business opportunity. “We’re solving some of our customers’ toughest challenges such as logistics, power and reducing flare gas emissions with products from our portfolio,” Simonelli said during the call. Baker Hughes estimates 500 hydraulic fracturing fleets are deployed in shale basins across the United States and Canada. Most of them are powered by trailer-mounted diesel engines. Each fleet consumes more than 7 million gallons of diesel per year, emits an average of 70,000 metric tons of carbon dioxide and require 700,000 tanker truck loads of diesel supplied to remote sites, according to Baker Hughes. “Electric frack enables the switch from diesel-driven to electrical-driven pumps powered by modular gas turbine generating units,” Simonelli said. “This alleviates several limiting factors for the operator and the pressure pumping company such as diesel truck logistics, excess gas handling, carbon emissions and the reliability of the pressure pumping operation.” Baker Hughes estimates that the 500 diesel frack fleets require a combined 20 million horsepower of energy, which translates into a potential market to provide 15 gigawatts of electricity using gas-fired turbines. So far, eight electric frack crews are deployed in the Permian Basin.

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On 4/22/2019 at 1:58 PM, ceo_energemsier said:
Addressing energy and environmental challenges through commercializing flare gas for productive use

Associated gas AG) is produced from the reservoir during oil production. In this post, Tetra Tech’s John Sachs, Director of Project Finance, and Artur Davtyan, Manager of Project Finance, discuss how AG could be used to fuel power plants, used as bottled gas, serve as a feedstock, exported as liquid natural gas (LNG), or put to other productive use with contributions by John Beardsworth and William Newton of Hunton Andrews Kurth, LLP. All opinions expressed in this post are the authors’ own. 

INTRODUCTION

Instead of being put to productive use, an estimated 140 billion cubic meters of AG is flared every year, equating to more than USD$10 billion of resource value. Flaring contributes approximately 350 million tons of CO2 emissions to the atmosphere annually, in some cases having been cited as having a negative impact on the health and livelihoods of local populations.

While much progress has been made in recent years to reduce flaring, AG continues to be flared at thousands of oil production sites around the world. A further reduction may be achieved through a market-oriented approach to commercialization that can produce a win-win-win: for the oil producer, the buyer and seller, and the environment.

Levels of Associated Gas Flared by Country in 2017

 

THE DIFFICULTIES IN COMMERCIALIZING AG

AG is frequently viewed by oil producers as an unwanted byproduct of oil production. Though flaring can be reduced through the commercialization of AG, doing so requires the resolution of many constraints and the creation of appropriate incentives.

The technology to address the problem of AG flaring is well developed and can include gas reinjection for enhanced oil recovery (EOR), power generation, compressed natural gas (CNG), liquefied natural gas (LNG), gas-to-liquids (GTL), and processing and pipeline development. Rather, AG continues to be flared due to a combination of factors related to physical characteristics and infrastructure, and the legal, policy, and market factors that must be overcome to successfully commercialize AG.

FLARE GAS MONETIZATION CHALLENGES

 

PHYSICAL CHARACTERISTICS AND INFRASTRUCTURE

AG is produced as a byproduct of oil production and is subject to production fluctuations, given that the ratio of AG to oil naturally varies over time.In addition, the physical solutions can be very flare-site specific: AG can be found far offshore, in remote and scattered locations. Volumes may vary significantly from site to site. Distance to demand centers, as well as infrastructure (pipeline, transmission lines, etc.), also impact the commercial viability of gas utilization projects.

LEGAL, POLICY, AND MARKET

Legal uncertainties and lack of enforcement of anti-flaring regulations also contribute to the problem. The greatest flaring often occurs in countries where legal uncertainties or lack of anti-flaring policies exist. Subsidized hydrocarbon prices and regulated end-product prices may result in a market distortion that impedes investment in gas monetization projects.

While the scale and complexity of AG flaring may seem discouraging, some large oil producing countries and oil producers have taken important steps to reduce flaring. Routine flaring is no longer as widely accepted as a standard business practice. Countries such as Saudi Arabia, Norway, Kuwait, the United Arab Emirates, and Canada all have taken steps to harness and put AG to productive use. Other countries also now require that any new field development plans include provisions for sustainably managing the AG and putting it to productive use.

SUCCESSFULLY SELLING ASSOCIATED GAS

While producers typically have the right to use AG to support oil production (e.g., reinjection for EOR, power production at the site), under many production sharing agreements or statutes, governments often have ownership of any surplus AG. Unfortunately, the governments of developing countries often do not have the expertise or the capital to develop their own AG capture and monetization projects. Typically, the oil producers, who are physically in charge of production, have technical expertise, and are better capitalized. Thus, one option to provide for the commercialization of AG is to remove the government’s preemptive rights to authorize private sector development of AG capture and monetization projects or the private sector sale of the AG.

Where a government owns AG, another option for monetization is for the government to sell the AG itself. A properly administered government-run auction can bring benefits that a producer-run auction may not be able to offer, such as enabling buyers to purchase from multiple flare sites across the country, providing tax incentives, or addressing political risk.

Many governments in oil-producing countries are familiar with the lease of oil blocks, so the sale of AG may seem like an easy next step. However, differences between AG buyers and oil block lessees need to be factored into the design of any AG monetization efforts. Oil can more readily be exported and sold in USD on the international market to any number of creditworthy parties. AG buyers may need to monetize the product locally, if it is not monetized through an export project, relying on local customers and sales denominated in local currency. Depending on the locale, this can introduce far more risk into a monetization project and attract a different universe of buyers.

To maximize the chance of success, the government seller needs to consider the perspective of the AG buyer and address various issues in the gas sales agreement.

IMPORTANT FACTORS TO A FLARE GAS SALES AGREEMENT  

TERM

A buyer may need a long-term gas supply commitment (typically 15-25 years) to justify the investment needed for development of a project.

RELIABLE SUPPLY; MAKE WHOLE IN CASE OF NON-SUPPLY

A buyer will likely need a consistent and reliable supply of gas, because revenues can be interrupted if the gas stops. In such a situation, a buyer may request that it be kept whole for its financial losses. Where supply is less reliable and make-whole payments are insufficient, AG prices may be low.

RELIABLE QUALITY

A buyer’s project is typically built for a tolerable range of gas specs, and supply of gas outside those specs may impact operations or damage a buyer’s project. Where there are concerns as to potential gas specs, AG prices may be low.

REASONABLE TAKE-OR-PAY

A buyer can usually guarantee a reasonable quantity of gas purchases year-to-year, but a buyer may need some reasonable flexibility.

CREDITWORTHINESS OF SELLER

A buyer will consider the seller’s creditworthiness to protect the buyer’s investment from the risk of a serious breach of contract by the seller.

POLITICAL RISK NOT BORNE BY AG BUYER

In countries where political risks are high, a buyer may request protection from political events.

Readers familiar with international project finance will recognize these as key features to making a buyer’s project bankable. While there are tools to make AG sale and related monetization projects more bankable, structuring the terms and conditions must be done with great care to attract investors.

The tools to achieve a bankable gas sale are available. Where the sale is conducted by the producer, these tools are largely in the hands of the producer. However, where a government is the seller of gas, some of the key factors for creating a bankable project are still under the control of the oil producers, and the commercialization must be done in a manner that includes the producers. For example, the oil producers are in the unique position of controlling production and physical delivery of any AG. As a result, they remain best positioned to manage that risk and to stand behind any such a guarantee (e.g. through a make-whole payment if the AG supply is interrupted). This dynamic effectively requires a government-producer-buyer tripartite relationship. This tripartite relationship, however, is not necessary if the producer itself commercializes the AG.

POLICY ACTIONS TO ENCOURAGE AG MONETIZATION

If putting AG to productive uses were as simple as putting the product up for auction and populating a data room, AG flares would have been extinguished across the globe. While some progress has been made in successfully commercializing AG, enactment of new—or refinement of existing—government policies may be needed to further support its commercialization.

Some of the policy issues are broader than AG. For example, subsidized competing fuels or electricity prices in some countries frustrates the sale of AG or end-products produced from AG feedstock into the local market. Domestic integrated incumbent utilities and the legal and regulatory frameworks applicable to the gas sector also can prevent or stifle the private sector’s development of a natural gas-based business. These policy issues go beyond the AG sector.
Other policy approaches can be targeted at AG, where a mix of carrots and sticks can be used to create incentives for the commercialization of AG. Incentives can include a mix of fiscal incentives, AG commercialization profit sharing, fines, and taxes. As an example, under a carbon tax system AG would not just have zero value, as it does now, but would have negative value since the flared gas would count in the calculation of the carbon footprint. However, several other approaches to setting appropriate flare gas fines exist and do not need to be linked to a carbon tax calculation. Governments also need to adopt transparent and efficient regulatory regimes that cover enforcement of operational standards, flare gas measurement, monitoring, and other requirements. Transparent enforcement of the flare gas regulatory regime creates the right incentives for producers to participate in flare gas commercialization.

There is no one-size-fits-all solution to the commercialization of AG; each set of market reforms, incentives, and policy and regulatory reforms needs to be tailored to the specific country. Significant collaboration between government and producers is needed when tailoring the regulations and policies to ensure they not only meet the government’s objectives of reducing the flares, but also do not unintentionally materially impact oil production.

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!

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Crusoe Energy developing flare mitigation tech to power big data

Denver-based Crusoe Energy has found a home in the North American shale industry by converting flared gas to a power source for computer intensive datacenters. The company recently announced a new funding round by Bain Capital Ventures and others that will infuse $4.5 million into further development of the technology.

Crusoe has developed mobile, modular data-centers that can be placed at or near well sites. The data centers can then utilize associated gas from the wells that might otherwise be flared to power the data centers.

The company currently has flare mitigation projects operating or under development in the Bakken, Powder River Basin and DJ Basin. The systems are scalable up to millions of cubic feet per day and can be deployed anywhere in the U.S. or Canada, according to the company.

“We are committed to building advanced technologies for flare mitigation that are capable of handling the large-scale gas throughputs

required by today’s North American shale industry. Crusoe’s technology harnesses otherwise wasted energy for growing industries that require energy intensive computing,” said Chase Lochmiller, co-founder and CEO of Crusoe, “such as blockchain and artificial intelligence.”

Salil Deshpande, partner at Bain Capital Ventures, said it was ironic and broken to the team that oil and gas production in the U.S. is now limited by how effectively producers can handle gas production. “The scale and technical sophistication of Crusoe’s digital flare mitigation system, as well as its execution in the field is unique. Crusoe solves an important pain point for oil producers in the booming shale industry,” said Deshpande, “and we’re enjoying working with the team as they advance and scale digital flare mitigation service across the North America.”

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Fueling fracturing with natural gas: Redefining wellsite power for oilfield services

On Aug. 24, 2017, Hurricane Harvey was barreling toward the middle of the Texas Gulf Coast shoreline, packing winds up to 145 mph and reports of anticipated rainfall in excess of 36 in. As the storm loomed closer to making landfall, the team at Evolution Well Services was busy evaluating the best plan of action—Harvey’s projected path was headed directly for one of their newly deployed fleets of electric power generation and fracturing equipment in the Eagle Ford shale.

The personnel decision was an easy one; people on location quickly battened down the hatches and promptly evacuated to safety for an undetermined amount of time, not knowing what the severity, length or aftermath of the storm would be. The newly minted equipment, however, still gleaming with its fresh coat of silver-fleck paint, was not going to be so lucky. The decision was made—the fleet was going to ride out the storm where it stood.

Two days after Harvey had passed, the crew was re-deployed to the wellsite. What they found was incredible; no notable damage to any of the equipment. The team spent the day completing safety checks, ensuring that all systems were “go” for resuming fracturing operations later that night. The natural gas line was opened, feeding the custom turbine generator, and momentarily after that, electricity was flowing out to the pump trailers, blender, and ancillary equipment on location. Pumping operations resumed, and business as usual commenced, Fig 1.

Fig. 1. On location in the Eagle Ford, Evolution’s electric fracturing fleet, powered by local natural gas, provides an alternative to traditional diesel engines.
Fig. 1. On location in the Eagle Ford, Evolution’s electric fracturing fleet, powered by local natural gas, provides an alternative to traditional diesel engines.

 

AN ALTERNATIVE FUEL FOR FRACS

What was not realized at the time, was that the majority of the other frac fleets in the basin were still not operational, and they wouldn’t be for many days or weeks yet to come. The situation confirmed a key value of electric-powered fracturing—the insulation from disruption of a continuous diesel supply to location. Harvey had introduced major disruptions into crude refining and fuel logistics across the Gulf Coast region. On the Wednesday of Harvey’s approach, 110 mi east of Houston, the largest crude oil refinery in the U.S. made the decision to close for an undetermined amount of time. According to CNBC reports, 20% of U.S. refining capacity was taken off-line by the storm.

While other pressure pumpers anxiously awaited the arrival of diesel trucks on wellsites across the Eagle Ford and beyond, Evolution was completing stage after stage on the client’s wells. The service was accomplished with a patented, custom-power generation package, fueled solely by natural gas pulled directly from local in-field gathering lines. In this particular case, the fuel source resided just 10 yards away.

The story is reminiscent of how, and why, Evolution got its start in 2010, in British Columbia, Canada. At that time, the large Kitimat LNG export facility was being planned. The nearby Horn River basin held untapped reserves that would feed the facility, and well completions were required to recover them. Once it was determined that the wells could produce enough gas to fuel a fleet of fracturing equipment, it was clear that there was an opportunity at hand to implement a new technology. 

The geography, harsh climate, and remote location of the planned operation increased the risk of interruptions in consistent fuel supply, which in the case of a conventional hydraulic fracturing fleet would typically be a continuous string of diesel tankers (roughly six per day for today’s fracturing designs). And so, Evolution began exploring how the Horn River field gas could be used to fuel the fracturing operations, thereby eliminating the need to continuously deliver diesel fuel to the remote locations.

During this concept phase, the company filed their first patents for a scalable, electrically powered fracturing system that uses natural gas to generate onsite electrical power.

ENERGIZING THE WELLSITE

The initial technology used a turnkey gas turbine generator package from General Electric: the GE TM2500+. The package delivered 32 MW of mobile generation capacity, and successfully powered Evolution’s first commercial fleet from 2016 to 2018.

The current system was developed to cut the move time between wellsites, which was taking four to upwards of seven days. This meant that nearly a quarter of each month consisted of non-operating time. Any time spent mobilizing equipment between wellsites signifies dollars lost. The non-productive time is so crucial in fact, that it is recorded in intervals of minutes, not hours. 

Optimizing the power generation package. To maximize efficiencies and increase up-time, the power generation package was redesigned to provide a more rugged, rapidly deployable package for hydraulic fracturing and other oilfield applications.

The redesign resulted in a custom-power generation package and creation of an affiliated entity, Dynamis Power Solutions, Fig 2Dynamis and Evolution designed, patented, and have manufactured six custom turbine generator packages, using the GE LM2500+ G4 turbine engine. In 2018, the engine had a reliability rating of 99.9%. The generator packages have a high power density, with their road-legal dimensions housing 36 MW (roughly 48,000 hp). The packages have reduced average pad move times by more than 50%, allowing clients to bring producing wells online two to four days faster than before. 

Fig. 2. Custom 36-MW turbine generator package improves mobility of power generation equipment.
Fig. 2. Custom 36-MW turbine generator package improves mobility of power generation equipment.

 

In a February 2019 application, the process of turbine rig-down, mobilization to a location 8 mi away, rig-up and distribution of power to the fleet was accomplished in just 14 hr.

Rounding out the frac fleet. The electric power generation solution opened new opportunities in designing the remainder of the fracturing fleet. Because the pumping trailers no longer had a traditional drive-train (the diesel engine and accompanying transmission) required to power each pump, significant real estate was available on each trailer to do something truly unique.

The most recent generation of pump trailers contain a single 7,000-hp electric motor with a dual shaft. Each end of the dual shaft directly couples to a 3,500-hhp frac pump. The typical frac fleet houses 56,000 pumping horsepower across eight pump trailers.

Controls and automation. The advanced control logic governing the operation of the pump trailers incorporates a balancing process across the two 3,500-hhp frac pumps; this greatly diminishes hydraulic harmonic vibration across the unit. Variable frequency drives control essentially every electric motor on the fleet. Not only does this control provide infinite adjustability to motor speed (and subsequent pump speed—meaning no more having to choose between gears while pumping), but it also provides more efficient use of power and sets the stage for enhanced automation and diagnostic ability. Various data streams from the variable frequency drives are monitored during operations and oftentimes predict component failures prior to an event. When routine pump maintenance is necessary, it is completed safely from ground level—all process equipment is on lay-down trailers that place pumps at a height that does not require elevated maintenance platforms.

Feeding all of the pumping trailers is a custom blender that houses two independent blending systems, each capable of rates of 120 bpm. The need for an external hydration unit was also eliminated with a 250-bbl hydration tank incorporated onto the dual-blending unit. This provides flexibility in blending operations to perform nearly any job design within the footprint of one trailer frame.

Safety implications. Engineering controls are the first line of defense and, ultimately, the most effective way to avoid injury is to keep folks out of harm’s way. Evolution’s custom IMPACT data van allows operation of the entire fleet from safe positions inside the data van. The van, which extends to three separate operating levels once on location, comfortably accommodates the client’s representatives and the entire frac crew, which is half the size of a conventional fracturing crew.

These units, as well as the other custom components that make up the fleet, are all powered by electricity produced by the Dynamis turbine generator package. The generator produces 13,800 V, which feeds through a custom switchgear unit prior to distribution to all process equipment on location, Fig 3.

Fig. 3. Process flow of locally sourced natural gas through the turbine generator, and subsequent electricity distribution to process equipment and ancillary services.
Fig. 3. Process flow of locally sourced natural gas through the turbine generator, and subsequent electricity distribution to process equipment and ancillary services.

 

EVOLUTION OF DESIGN 

The latest generation of equipment reduces the number of ground cables from 59 to just 16, bundling all power and communication lines into one cable per unit. The system uses a custom-designed, circuit-protected plug and receptacle to connect each piece of equipment. This reduces trip hazards, and saves on cost and maintenance, as well as reduces the amount of time required for rig-up.

Reducing environmental impact. The fracturing fleets have a footprint that is 50% of a conventional hydraulic fracturing fleet. In certain basins where pad sizes are particularly small, the reduced footprint has enabled pumping operations without enlarging the pad size. The capability suggests wellsites could theoretically be built smaller, lessening the environmental impact and the effect on surrounding communities.

A GREENER ALTERNATIVE

In addition to fuel savings achieved by fueling frac fleets with natural gas instead of diesel (which typically range from $1 million to $2 million per fleet, per month), the emissions profile and other health, safety and environmental factors achieve wide-reaching improvements. Since inception, Evolution has conserved nearly 450,000 lb of carbon monoxide from being emitted into the atmosphere, and has hydrocarbon emissions (including methane) that are 95% lower than the Tier IV Final Non-road Compression Ignition Standards set by the EPA in March 2016, Fig 4.

Fig. 4. Comparison between EWS’s custom turbine and Tier IV diesel emissions standards.
Fig. 4. Comparison between EWS’s custom turbine and Tier IV diesel emissions standards.

 

Methane from oilfield operations. The topic of methane emissions has recently been in the industry spotlight, and for good reason. While the EPA established carbon dioxide as the reference point for Greenhouse Warming Potential (GWP) with a value of 1, methane, by comparison, has a GWP ranging from 28 to 36. And this is certainly not a game where the high score wins.

Atmospheric impact. In short, the GWP is a metric combining two different factors: radiative efficiency, which is a measure of how much energy the compound can absorb; and lifetime in the atmosphere. While CO2may linger in the atmosphere for a thousand years or more, methane typically only resides there for about 10 years. However, the radiative efficiency of methane is considerably higher, essentially making it a warmer blanket for the earth. Although the industry has reduced methane emissions substantially since 1990, natural gas systems still rate as the second-highest source category for such emissions in the U.S.

E&P drive to reduce emissions. There are other drivers, as well, for working to capture the methane that is escaping from oil and gas operations across the globe. According to Newsweek,53% of U.S. companies tied executive compensation to performance targets aimed at being more environmentally friendly. Just a decade ago, that number was less than 10%.

Less wasted fuel. Additionally, 2016 marked the first time in U.S. history that natural gas fueled more electricity production than coal; 34% was produced from natural gas feedstocks and 30% by coal. Most would agree with the consensus that emissions standards are not likely to be relaxed in any material way in the future, meaning that natural gas will likely have a growing role in electricity production in the near-to-mid term. Therefore, all methane escaping these operations to the atmosphere could be looked at as spilled fuel; not contributing to production of useable power for the demands of growing populations.

APPLYING LEAN PRINCIPLES TO COMPLETIONS

During a time in the industry, where efficiencies are paramount, the process of delivering diesel still contains four of the eight types of waste included in classic Six Sigma principles; movement, waiting, transportation, and extra processing.

Where does diesel come from? Let’s follow the journey of a hydrocarbon molecule destined for use as diesel fuel in fracturing operations. How many times does the hydrocarbon molecule change location and chain of custody? It starts at the wellhead with the E&P company; next it is delivered to the midstream company; it then transfers to a holding facility; then on to the refinery; then back to a holding facility; then to the distribution rack; then to a retailer hauling it back to a wellsite, and then ultimately selling it back to an E&P company. 

Ripple effects. What about the emissions from the diesel tankers, delivering fuel to remote wellsites (not to mention the energy intensity of the diesel refining process itself)? Since commercial operations began in 2016, Evolution has conserved nearly 14 million gal of diesel fuel. This equates to over 3,300 tanker truck journeys, Fig 5In addition, Evolution frac fleets contain fewer than half the number of trailers as a conventional frac fleet, meaning 50% fewer tractors are pulling equipment over the road with every pad move.

Fig. 5. The group of sand silos on the left had been working with Evolution on their electric fleet, while the silos on the right had been working on a conventional diesel wellsite.
Fig. 5. The group of sand silos on the left had been working with Evolution on their electric fleet, while the silos on the right had been working on a conventional diesel wellsite.

 

Not only is this beneficial from an environmental perspective, but safety and civil infrastructure are impacted, as well. According to the latest reports from the Bureau of Labor Statistics, truck drivers and delivery workers have the highest rate of workplace fatalities.

Eliminating hot fueling. Once fuel trucks arrive on wellsites to fuel conventional diesel-powered equipment, the danger hasn’t yet passed. The refueling of the fracturing process equipment with diesel, while the pumping operations are occurring, is referred to as “hot-fueling.” The design of the standard conventional frac pump trailer, along with the fact that a large amount of equipment is typically parked very tightly together on a wellsite, poses a health and safety risk to those individuals involved in the hot-fueling process.

Combine these factors with the extremely large volumes of combustible fluid at hand, and the frequency with which this operation is done (daily on hundreds of frac sites nationwide), and risk of a potential disaster is increased. There have been dozens of equipment fires on fracturing sites over the past 15 years, with the vast majority of them pointing to hot-fueling operations as the source. Each fire poses risks to health, safety and the environment, as well as immense capital destruction. In 2018, alone, there was over $100 million in insurance claims filed by North American pressure pumpers, due to fracturing equipment lost in wellsite fires.

QUIET TECHNOLOGY

Many well completion operations in places such as the Barnett shale of North Texas are required to operate on “daylight only” schedules, strictly due to the noise produced by conventional frac fleets and associated services. One operator, currently working in close proximity to Oklahoma City, reached out to Evolution recently, because local residents had issued numerous complaints to local congressmen regarding excessive noise coming from nearby wellsites. Conventional diesel fracturing fleets operate at a noise level of 110 decibels or more. OSHA Standard for Occupational Noise Exposure requires hearing protection be worn anytime that the 8-hr time-weighted noise level exceeds 85 dB. Evolution’s fleet comes in at 85 dB or below.

In efforts to reduce the disruption that fracturing fleets might induce, the company has engineered and manufactured custom exhaust equipment for each power package, substantially dampening the noise during operations to levels that will comply with all currently published North American noise standards.

WHAT EVOLVES NEXT FROM THIS TECHNOLOGY?

Recently, Dynamis and Evolution have worked to improve wellsite operations by feeding produced electricity to other service providers on each location. 

Powering ancillary wellsite services. Plans are to expand the ability to act as an on-site power provider for other ancillary services such as wireline, water transfer and chemical mixing, including the design and manufacture of custom electric pump-down units, which are planned for deployment in the second quarter.

Recently, Evolution worked with Solaris Oilfield Infrastructure to extend the natural gas-fueled power for use with the Solaris sand delivery systems, in lieu of utilizing their conventional diesel generators for power. This was accomplished in short order, because Solaris also uses electric motors, components and controls, all on variable-frequency drives, typically powered by their own 480-V three-phase generator.

Heat capture. Another patent application that was recently added to the list outlines designs to capture otherwise wasted exhaust heat from the turbine generator, and repurpose that energy to a heat exchanger that can be utilized to heat water for fracing operations in cold-weather scenarios. The thermodynamic calculations predict that water will be heated by 30°F at a rate of 100 bpm. 

Data analytics. All of these operations are remotely monitored and, where sensible, are automated, from a joint Evolution and Dynamis Operational Excellence Center that opened this year in The Woodlands, Texas. This space is mission control for all data analytics, predictive maintenance, and artificial intelligence projects currently in the works.

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