TECHNOLOGY

The transformative SIP - System of Integrated Production - increases production of crude by compressing anular gas inside the well as indicated by proprietary algorithms measuring anular gas patterns. Environmentally crucial, SIP´s increase in production creates reductions in gas emissions and water cuts. SIP never goes down hole and only requires 2 square meters of space for installation surface-level by the wellhead. SIP never interrupts production and works on top of existing EOR systems on primary, secondary and tertiary wells. Oleum Technology fronts all initial investment in SIP. SIP presents zero risk productively, environmentally, infra-structurally and economically.

Average SIP results include:

  • An increase in oil production between 15% and 40%, and higher with extra heavy crude
  • A decrease in water cuts between 11% and 15%
  • A decline in gas emissions up to 70%

The average cost per barrel plummets as we increase the production of the well.  We are self-powered by solar-panels and present no additional electrical costs to the operator.  As we increase both the efficiency of the well and the amount of recoverable oil and life of the reservoir, we additionally reduce the operator's need to drill more wells - an economic and environmental plus.

SYSTEM OF INTEGRATED PRODUCTION 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 SIP work on some of their own wells, they will want to contract the service.

SOME COMMON QUESTIONS:

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, SIP 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.  We have been awarded a protective status of patent pending from the United States Patent Office. 

Is there a mathematical expression for what is happening underground with SIP? Has a paper been published on the technology?

There is a limit to what we can mathematically tell you, because it, too, is part the proprietary trade secret of how SIP works.  As the technology is not open source, we have not published a related paper, nor will we.  But let us tell you what we can.

For many years in the oil industry, reservoir experts have focused on two types of flows—linear and turbulent—to calculate or predict the production of a reservoir.  Similarly, pressure equations, such as Darcy and Voguel, have been applied to calculate the IPR that will give them the production rate.  These equations express in a summarized manner that a pressure "X" yields well-production "Y". 

What we have discovered is that we can increase the pressure in wells without the IPR changing – both gross and total—if done in a controlled and systematic manner.

A well that has already been exploited loses its condition of linear flow. It becomes turbulent  through several ways, among them the injection of water or gas or by voids that are left in the reservoir. 

The theory of Korteweg-de Vries, or KdV, is a partial differential equation that includes the effects of both nonlinearity and dispersion. Physically, it is a model that describes, in one spatial dimension, the propagation of long waves in a dispersive media.  The surface of the water in deep channels is an example of a dispersive medium in which one can find long, solitary waves. In physics and mathematics, this wave represents the prototypical, non-lineal system that can be completely integrated.  The method to show this ability to integrate is called the inverse dispersion, or backscatter, method.  The equation is written in the literature in many ways.  This is one of them:

   
               
X, t and v respectively represent spatial position, time and amplitude. The first term of the equation denotes the temporal evolution of the disturbance v or field.  (It can be considered as the elevation of the water surface relative to its equilibrium position).  The second is considered the nonlinear term due to the multiplication between and its first partial derivative with respect to space.  And the third term is the dispersive one due to the third spatial partial derivative of v.

To summarize, from the surface we can predict the wave that occurs underground, and this in turn reflects the changes in reservoir behavior that can benefit the well.

Any further explanation is part of our trade secret and applied mathematical model.

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 SIP 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 SIP 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 SIP.  One reason is because SIP also extends reservoir life by expanding the amount of its recoverable crude. 

How does SIP 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 SIP 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.   

Will SIP work with a limited amount of liquid on top of the pump?

There are limits.  The ideal is a minimum of 1000 feet of liquid over the pump. We have worked with as little as 500 feet, but we must physically inspect the well first and you must agree to the risk and be present during the trial.   We will not go below 500 feet.

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 SIP work with external gas injected into the annulus?

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

Can the SIP equipment for one well be used for multiple wells?

This requires a re-engineering that we are beginning to study.  An experiment might be worth doing under a long term contract, but we are not sufficiently advanced to even make it worth trying yet. 

Does SIP work in a single well 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.  SIP 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 SIP 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 SIP 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 SIP would not work on a well exploiting several reservoirs at the same time. 

Does SIP 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.  

What is the minimum number of barrels that a well must produce before we install SIP:

This is an economic question.  From a technical point of view, there is no minimum.  The economic question turns in part on cost questions such as number of wells, their proximity, the total estimated crude production, and the negotiated contract per well. 

Can the equipment be moved among wells during a trial phase?

Yes.  This allows trials in a greater number of wells with a reduced amount of equipment and saves trial cost.  We recommend for your satisfaction, however, that the equipment stay a minimum of one month on a well.  This is for your own confidence in making long term production projections.  But remember: once the equipment is moved, the well goes back to its old production levels.  There is no hangover benefit.

Can a team of 4 field engineers cover a concentrated field of, say, 100 wells and thereby allow a costs reduction?

We would have to study the field, but 100 is pushing it for 4 engineers and is unlikely.  Much depends on the communications, ease of transportation and geographic size of the field.  But, yes, the number of wells and their concentration would go into our cost proposal.

For many wells, we don’t have all the information asked for on the well data sheet that is used to pick wells.  What is the minimum information that you need?

At a minimum, we need recent fluid production numbers and the permeabilities to decide if a well is worth even considering. We can do this now with you as a way to come up with a list of candidate wells for trials.  If we have all or almost all of the data filled in, we can estimate pretty accurately what the production increase will be, without even seeing the well.  (We don’t guarantee this estimate.)  Before we actually settle on a well and install SIP, we fill out the sheet, especially as concerns the petrophysical characteristics of the reservoir and an echometer fluid level analysis of the well.  We talk with field staff and physically inspect and test the well.  The risk if we don’t do chemical analysis of the gas, for example, is that if the gas turns out to be highly corrosive, it will damage our standard SIP equipment. We have specialized equipment that we install for corrosive gas. Or if there are fractures in the cementation below, gas will filter out and undermine the effectiveness of SIP.  Thus, we are careful in working with you to select wells and please you with good results as much as possible.

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. 

Do we have examples in which SIP has failed to achieve a significant uplift in crude production?

The PowerPoint presentation reports on early failures as we were developing SIP.  In recent years, as we have developed our science, methods and algorithms, we have never failed to have a significant crude production increase (and we have never had a safety failure).  One reason is because we are careful in picking wells, as described in the question above. 

You might also look at slide 41 in the presentation.  It shows how we selected and discarded well candidates for China National Petroleum Company in Ecuador. The rejected candidates mostly lacked free gas, though it would have been possible even on these wells to inject cost and increase their crude production (at a cost, of course).

The overwhelming number of conventional wells in most countries, including offshore, are perfect candidates for SIP.   Slide 6 lists the few restrictions.

Is our equipment licensed for Europe?

All our equipment is licensed under both API and European standards.  We don’t see an issue here, but we are willing to get whatever regulatory approvals might be necessary.

If this technology is so great, why haven’t we heard of it before?  After all, its been in development for more than a decade. 

Blame the political chaos in Venezuela and PDVSA.  PDVSA was once the poster child for a well-run state oil company.  The Chavistas have turned the company into an example of some of the worst that can happen, including the failure to take advantage of the technology that was invented by Ender Boscan there.  Houston, Colombia and many other oil centers are filled with talented Venezuelan engineers who have left in disgust.  Oleum Technologyhad the good fortune of knowing Boscan and working with him to fully develop his invention after he went to Ecuador.  Oleum is now introducing SIP to the world.

 

 

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