Welcome to Algorithmic Gas System

The New Technology Solution to Today's Low Oil Proces




About The Algorithmic Gas System

Algorithmic Gas System is a proprietary new enhanced oil recovery technology offered as a service worldwide by Algorithmic Gas System LLC, a subsidiary of Gotham Energy Trade and Logistics of New York. AGS increases crude production per well by 15% and 100%, while substantially cutting the emission of both water and gas. The result is increased well efficiency, lower production cost, extended reservoir life and environmental benefit.

AGS works by increasing the pressure of free gas in the annulus, a production technique that has never before been used. The pressure is controlled by a proprietary valve connected to the wellhead and managed by an on-site computer and control center linked by satellite. Proprietary algorithms follow changing patterns in the gas and direct the opening and closing of the valve.

The science behind the success of the technology rests on the mobility of oil and water under pressure. Relatively more crude and less water rise than before. The pressure deters both water and free gas in the reservoir from entering the annulus. Secondary effects aid as well.

AGS has a perfect safety record. There is no down-hole alteration and thus no down-hole risk; the equipment is installed at the wellhead. When the algorithms open the control valve, the excess gas is funneled back to the production line, to be disposed by the well’s normal means. AGS has never suffered a leak.

AGS was developed over a decade of trial, error and research. It is proven in production and extended tests on nearly 100 conventional wells in Ecuador and Venezuela, under a variety of reservoir and well conditions, at land and sea. It has never been tested for fracking.

Data and testimonials on these wells from the China National Petroleum Company, Repsol, PDVSA and the Venezuelan National Petroleum Technology Institute conclude that AGS offers the following results:

• Crude increase of between 15% and more than 100%, depending on API
• Water decline of between 11% and 14%
• Gas decline of up to 70%
• Average production cost per barrel plummets accordingly

Installation is usually done in one day. Contract terms are economical. The return on investment is considerable and almost immediate.



Crude increase of between 15% and more than 100%, depending on API


Water decline of between 11% and 14% Gas Decline of up to 70%


Average production cost per barrel plummets accordingly



ALGORITHMIC GAS SYSTEM involves an operational and conceptual leap that has never been made before: increase gas pressure in the annulus to increase a well’s crude production. Using algorithms to manage the pressure entails a second leap. Heard the first time, the operation sounds too simple to be true. The science, meanwhile, seems counter-intuitive, at least for non-scientists. But the same was said of Google and search engine algorithms.

The oil and gas industry has employed ever-improving technology to increase production. Generally, the efforts have divided between using sophisticated geosciences (geophysics, petrophysics, geomechanics, etc) and pragmatic engineering improvements based on data and analytics. Both approaches are still in mid-development.

Our approach comes from the pragmatic engineering side, but is based on reservoir and liquid science and adds a digital twist. We use real-time digital technology in a closed feedback loop to follow patterns in the gas resulting from the pressure. Each well is different, and our algorithms adjust accordingly, without human intervention. That said, we intimately know the parameters and physical uniqueness of each well, and monitor its “vital signs.”

Ultimately, a producer may want to run an actual field test. We are confident that once they have seen AGS work on some of their own wells, they will want to contract the service.


Does the gas:oil ratio change? What influences the gas fluctuations that you are measuring?

The gas:oil ratio indeed changes, often significantly, just as water:oil changes.

Increasing the pressure in the annulus prevents gas from entering the annulus in the same quantities as before. The total reduction has been as high as 70%, though an overall reduction of roughly 50% is more common. This is an environmental benefit, as less gas has to be flared or otherwise disposed. The size of the reduction, however, varies widely among wells, depending in large part on the amount of gas and its composition and movement in the reservoir. This is why we do not give projections on the reduction in the total amount of gas that has to disposed.

The gas that is not allowed to enter the annulus stays in the reservoir.

Separate from volume, meanwhile, is the question of fluctuation. Even when the annulus is under pressure, the amount of gas that enters at the bottom fluctuates, sometimes as much as 50%. During operation, our system maintains a steady range of pressure in the annulus by measuring and responding to each such fluctuation.

What are we measuring the gas against, when we control the pressure?

Nothing. Just as search algorithms or language translation programs are not measuring anything other than usage patterns, AGS only monitors the fluctuations in gas pressure. We understand that this is often hard to conceive, but just look at the monitor screen shot in slide 17 of the presentation.

How then are we or the algorithms judging when to adjust the gas pressure? What are the adjustments based on?

That’s the secret sauce

What is the production feedback in the system? Must you or we run a separator all the time, for example?

We have no real-time production feedback and don’t need it, from you or by us. We do want weekly production feedback, to confirm the uplift. If you don’t do any sort of weekly tests, then we will, usually with a chemical testing of the liquid mix in the production line. Our engineers are trained to do the tests. We assume that you will want to be present; that is your choice. You also are welcome to continue to measure your production as you always have. Whether you want to use a separator is totally up to you. If we agree on an uplift split, then of course we will want to participate in, or follow, whatever measurement system you use.

How do we know if the AGS production levels are sustainable over time?

We can provide data from the Venezuelan Petroleum Technology Institute (INTEVEP) on tests they ran on wells for two uninterrupted years. Those tests show that AGS performed sustainably and consistently. We have not had the opportunity to run for more than two years on a well, but see no long term operational limits to AGS. One reason is because AGS also extends reservoir life by expanding the amount of its recoverable crude.

How does AGS expand the recoverable crude in the reservoir and well life? Can this be measured?

Stopping up the escape of water and gas via the well maintains the energy and pressure in the reservoir, much like capping a soda bottle. The reservoir, in other words, doesn’t go flat, at least not as fast. The energy moves the crude, which is doubly impacted by the same chemical reaction as happens in the annulus. The free gas that is held back in the reservoir increases the mobility and decreases the viscosity of the crude there. It decreases the mobility of the water. More crude in the reservoir is thus loosened and drawn toward the pumping well. We cannot reliably measure how much the recoverable reserves increase without doing a full study of the reservoir over time.

Will AGS work in extreme conditions, such as the North Sea or Alaska?

Yes. All our equipment is off-the-shelf and comes from the same top-of-the-line manufacturers from which the producers in those areas buy. Just as they do, we weatherize our equipment, including the electronic elements, depending on the climate. We adapt the valves, seals, sensors and monitors, which is part of our patent filing, but this adaptation also is done with the weather in mind and does not compromise the weather rating or manufacturer’s guarantee of the equipment.

Can we accurately predict the uplift on a well before installing the system?

Pretty much so, if we have the petrophysical data of the reservoir and the echometer fluid level analysis of the well. We cannot guarantee the prediction, but we have gotten to be pretty good at well picking and at estimating uplift. That said, we sooner or later have to physically inspect a well before we agree to install a system.

You say that you have a perfect safety record. What near-issues have you had?

Very rarely has our service been ineffective or appeared to malfunction. Bad cementation led to one leak in the early years, which is why we are extremely careful in testing and picking wells beforehand. With the knowledge and approval of the customer, there have been several wells in which we installed the system on wells in which the liquid level over the pump was low. We all agreed to see if we could still safely get to optimum working pressure. On most we did with no problem. On one or two others, we pulled our system off as soon as we were concerned that we were near the down-hole safety limit. We have never had a case of causing down-hole damage.

One reason is because the wells we pick for operation go through several filters. These include discussion with the field staff of the wells, review of the well’s data and parameters, acoustic and other tests of our own, and then a physical test of pressurizing the well for 24 hours.

What happens if the well produces less than 100,000 cubic feet of free gas in the annulus?

The only thing that happens is the well takes longer to calibrate during the installation process. A good candidate well typically takes several hours to calibrate. A well with less than 100,000 cubic feet can take anywhere between 1 day and 1 week, depending on how much less gas there is.

Does AGS work with external gas injected into the annulus?

Yes. Perfectly well. The only inconvenience is the added cost of importing gas.

Does AGS work in wells with multiple feeds? What examples do we have? Does it work on packer wells?

By multiple feeds, we assume you mean wells that are connected to multiple reservoirs at different levels or points along the annulus. If this is so, then, yes, we are experienced with these sorts of wells. AGS is currently installed and operating successfully in one such well connected to two reservoirs in the Mariann well in Ecuador. Slide 44 in the presentation, lists this well. We have worked with other such wells in Venezuela, too, some with more than two feeds or reservoirs. And while we say that AGS does not work on packer wells, it does work when the packer is below the perforated area being exploited.

We are not certain if your question was also whether AGS works if multiple reservoirs or feeds are being exploited simultaneously from the same well. In Venezuela and Ecuador, it is illegal to exploit two reservoirs at the same time from one well. You can switch among the reservoirs, but have to do one at a time. Theoretically, however, we see no reason why AGS would not work on a well exploiting several reservoirs at the same time.

Does AGS work when the ESP drive is down-hole and not on the surface?

We have no experience with this, but see no reason why it would not work with the drive down-hole. We would like to see this configuration.

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Gotham Energy is proud to bring the Algorithmic Gas System to the world.

For a Full Presentation of the Algorithmic Gas System please contact us for a password to the presentation below.

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Key Executives
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  • Peter Kuhn is the CEO of Gotham Energy Trade (GET). He has over 25 years’ experience in the physical energy and metals trading and logistics business. Additionally he has been a project financier and developer to frontier market infrastructure projects related to power generation logistics and natural resource extraction.

    Peter was founder and CEO of a large logistics and trading (GET).  This company purchased and managed nine tanker ships; developed four frontier market power plants in Latin America and Africa; developed or redeveloped 5 mines; traded crude oil, distillates and base metals.

    Prior to founding GET, peter was a partner in a fund that invested in early stage technology and then midstream energy assets. While in that role, he implemented a wide range of innovations and operating efficiencies. These yielded the difference between successful and losing projects and investments. In this capacity he worked with Schlumberger, Baker Hughes, and Kinder Morgan. He started as a clerk on the floor of the NYMEX. Where 4e was promoted to trader. Held a variety of roles which crossed between the derivative and physical markets.

    Mr. Kuhn also, served as a Strategy and project development consultant to a variety of clients including: Sithe Energy, Total, and Stat Oil. Peter has a B.A. from Columbia ’85. He is a frequent lecturer at SIPA at Columbia University.

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  • Luis Saam Migueli is Chief Operations Officer with a long history as an Oil & Gas executive in North America, Europe and Latin America.

    He has experience working with private equity groups and consortiums in acquisitions, turnarounds and PMI advisory roles. He has over 15 years experience in senior executive roles at Haliburton working across the UK, Scotland, Norway, West Europe, West Africa, Mexico, South America, Egypt and Asia.

    He has led organizations in strategy development & implementation of high profile international initiatives and led expansion intitiatives into Mexico, China, Libya, Kuwait, Oman, Algeria, and Argentina.

    He is also the founder and Chairman of Perficientur, the developer of sense2action(TM) Software Technologies for companies to support their initiatives for turnarounds and profitability growth.

    He is Multilingual & Multicultural with a solid operational & technical background and highly committed to Quality, Health, Safety and environmental programs.

    Luis is key to defining the operational strategy, and development of the team at Gotham Energy & Trade.

    Other His focus is operational excellence and development of reliable internal processes and systems to support our staff and customers, often in remote locations around the globe.

    He has great experience in corporate development & strategic planning, business dynamics & financial modeling, and ensuring comprehensive planning and execution.


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