There is no doubt if we read the DD that has been released

Quote:

David Holcomb is the president of Pentagon Technical Services, Inc an oil & gas related consulting company based in Florence, Arizona. His oil and gas industry experience covers 46 years of continuous effort in research, development, technical training and technical marketing for well stimulation, oilfield chemistry and fracture diagnostics technologies. He has worked for Cardinal Chemical, Inc., Smith International Inc.’s Energy Division, Protechnics, a Division of Core Laboratories, FTS International, Inc., Flotek Industries, Inc. and Pentagon Technical Services, Inc. He has held various technical and technology management positions and has developed numerous products and methods for well intervention, most of which are in use today.

His educational background includes receiving his B.S. from Texas State University in biology and chemistry and his M.S., and Ph.D. in Chemical Engineering from the University of Texas. He has written and published over 40 technical and professional papers for SPE, SPEJ, AIChE, AGA, and SWPSC. He has been a distinguished lecturer for SPE (1984-85) on the topic of formation damage, and is an active member of SPE, ACS, and AIChE. He is on the SPE Young Professionals lecture circuit. He is the past chairman of the SPE International Oilfield Chemistry Symposium and the Texas Tech University Southwestern Petroleum Short Course as well as a retired board member for them. He was elected a Distinguished Member of the Denver Section of SPE in 1985. He holds three patents and has three pending in the areas of oilfield chemistry, fracture placement diagnostics, acid fracturing and nanotechnology. He has worked on assignments around the world including the USA, Canada, North Sea (Scotland and Norway), Mexico, Brazil, Ecuador, Australia and Algeria.

Now, compare the DD just posted as to what they are doing now! Note:

Grassy Creek Overview
https://www.para-con.com/2021-02-04-grassy-cr...erview.php

by David L. Holcomb, President - Pentagon Technical Services Inc.
Gary Grieco, CEO and Chairman - PCT LTD

February 4, 2021

Maverick Energy Services – PCT LTD.

Catholyte – Grassy Creek Oilfield, Waterflood Improvement Project, Vernon County, MO

PCT Ltd. is working with Maverick Energy Services in Vernon County, Missouri, to use a unique electrochemically produced catholyte to enhance the injectivity, sweep efficiency, and oil production in a modified seven-spot well pattern. This seven-spot pattern #2A is a part of the larger Grassy Creek Oilfield where all seven wells are situated in the eastern part of the field and are closely spaced making them ideal for a field pilot test. These particular wells have not been treated other than by traditional waterflood. (Other wells in Grassy Creek were treated with a steam flood and a surfactant with limited success.) The pay thickness is between 20 and 25 feet for the lower Bluejacket SS and up to 80 feet in the Warner SS. The porosity in the Bluejacket is between 14-16% and 21-24% in the Warner. The permeability is between 20 and 40 md in Bluejacket and between 118 and 687 md (avg. 350 md) in the Warner. The crude oil is moderate to low gravity (19-29 degrees API), and reservoir temperatures average approximately 90 degrees F. The catholyte is produced onsite from special electroionizing process machinery using clean brine water. It can produce up to 700 gallons per day of 600-700 pm and 600-900 ORP catholyte. Storage is provided for up to 2000 gallons onsite, and a distribution line and pump is tied directly to the 2A seven-spot well injection well(s).

The project is using catholyte which has been initiated with Maverick Energy Services by designing up to an initial 30-day trial using varying volumes of the catholyte. The trial is being preceded by doing production and injection testing with fluorescent tracers on the two injectors (Warner and Bluejacket zones) as well as production tests on wells 2-1 through 2-6 to establish a baseline injection/production rate and pressure (if any since in the past some have gone on a vacuum), and monitoring every 4 hours for two to three days for tracer at each producer.

Once the baseline rates and pressures are established and the producing wells validated with positive or negative tracer shows, then the catholyte will be produced onsite and injected into the two injection wells or one injector depending on the results of the tracer testing for each zone. If all wells are not in communication with the injection well(s), then the issue will be addressed by considering polyacrylamide polymer as a small volume (250-500 gallon) pumped ahead of the next volume of catholyte to help slow breakthrough or channeling to certain wells and allow a more efficient distribution to the other wells. This may or may not be required to provide more uniform distribution of the catholyte in as many producing wells as possible on the seven-spot pattern.

Once the injection profile is understood, then 1000 gallons of the (hot) 600-900 ppm catholyte solution will be manufactured and injected into the appropriate 2A injection wells. Then the injectors will be returned to injection of normal brine and monitored on day two with bucket tests performed on each well that is producing, looking for improved oil cut in the WOR as well as any pressure changes. Samples will be collected at each producing well. Then on day three, another 750 gallons (hot) catholyte will be injected followed by putting the well back on injection with clean injection brine water. Injection will continue over the next 24 hours (day four) followed by the production and sample testing protocol as before. This will be followed on the fifth day by another 500 gallons of (hot) catholyte and injection over the next 24 hours to monitor production rates and pressures as well as WOR. If oil ratio begins to increase, then the seven spot can be maintained on injection and repeating repeating the catholyte injection sequence described above over the next several days up to 30 days if necessary. The goal is to prove the catholyte technology for this reservoir type by a markedly improved oil cut after two to four weeks injection of catholyte alternating with injection brine water mix).

The results will be evaluated, and it will be decided that the injection will be continued as catholyte alternating with brine water as may be required to maintain improved oil cut in the water oil ratio (WOR).

Copyright © 2021

Holcomb's nanoparticle invention (which is already proven to increase production 30%+) combining with PCTL's Catholyte (which is already proven to increase production 30+ under different EPA register) work together, what will be the outcome?

The answer:
The nanoparticle technology has greater penetration but Catholyte is critical because it reduces buildup allowing the nanoparticles even greater access...

I wonder if this has been explained to RB Capital???? Actually, I don't have to wonder since they provided loans at the following conversion rates (they must know that .10, .15 & .20 cents is nothing) Note:

Read More: https://investorshangout.com/post/view?id=606...PDuh/quote]

Quote:

Small dose, big results
Scientists are turning to nanoparticles to extend enhanced oil recovery’s reach

27 November 2017 8:23 GMT UPDATED 27 November 2017 8:23 GMT
By Jennifer Pallanich in Houston

Operators are using more proppant and more clusters to increase production. Yet decline curves can be steep. One problem is that the proppant may not end up in the desired location.

Enter the nanoparticle.

David Holcomb, a consultant and founder of Pentagon Technical Services, developed a nanoparticle dispersion, nanoActiv HRT (hydrocarbon recovery technology), that will diffuse into the reservoir’s natural fracture network, dislodge the oil from the reservoir, and separate and reduce it into smaller droplets for easier production.

Holcomb describes how the nanoparticles work thusly: “Diffusion is the way they get there, disjoining pressure is what they do when they get there, and fragmentation is what allows the oil to more easily move back to the wellbore.”

Yusra Ahmad, an oil and gas research scientist with Nissan Chemical, was involved in lab testing the technology.

“Don’t confuse nanoActiv HRT with a surfactant,” she says.

“The mechanism of action between the two is very different. Surfactants work chemically and nanoparticles work mechanically.”

The nanoparticles are sent downhole in a pre-packaged pill with a colloidal solution before the well is hydraulically fractured.

“The slick water pushes it further into the reservoir, and when you pump the frack pad, it sends the pill beyond the reach of the general fracture, so you get more interaction with your reservoir, which helps with increased production,” Ahmad says.

The nanoparticles diffuse rapidly into the reservoir. There are no adverse adsorption or wettability issues, so they can work in any type of reservoir, according to the manufacturer.

Holcomb, referring to the formulae used to determine rates of diffusion, says the nanoparticles “appear to break Fick’s law of diffusion by orders of magnitude.” A slug of 500 gallons of nanoActiv HRT can treat millions of square feet of reservoir.

“Understanding how the nanoparticles in nanoActiv HRT behave has been difficult because they’re small and difficult to observe,” he says.

Inspired by scientist Dr Darsh Wasan’s groundbreaking work on disjoining pressure and fragmentation, Holcomb worked with Nissan Chemical to adapt and improve the technology for oilfield use.

Testing revealed that the nanoparticles fragmented oil into much smaller droplets. The smaller droplets of oil flow more easily through the reservoir and fracture network.

The nanoparticles wedge themselves at the three-phase contact angle to create the disjoining pressure, which dislodges the hydrocarbon off the surfaces of the reservoir. The nanoparticles encase the newly mobilised hydrocarbon and fragment it.

“We’re still trying to learn why this fragmentation happens,” Holcomb says. “The nanoparticles will surround whatever liquid hydrocarbon they come into contact with and break it into smaller droplets.”

Holcomb says the nanoparticles have also been known to break down paraffin and other heavy hydrocarbon deposits, allowing them to be more easily removed from the reservoir or wellbore.

The nanoparticles go after and break down fluids and gases in the reservoir in order of density, from lowest to highest—for example, gas all the way up to brine.

Nissan Chemical is working with Linde Corporation to further develop nanoparticle dispersion technologies and industrial gases specifically designed for natural gas as well as oil wells.

NanoActiv HRT is a dispersion of surface-modified silica nanoparticles dispersed in water designed to withstand high salinity. A high-temperature version of nanoActiv HRT is rated to 350 degrees Fahrenheit. The technology is compatible with all frack fluids, Holcomb says, provided the nanoActiv HRT is placed in a fresh water pill and preceded and followed by a small fresh water spacer.

“Because there’s so much surface area in a given volume, you can design the nanoparticles to increase the efficiency of any application. You can optimise not just completions, but also (enhanced oil recovery), remediation, et cetera,” Ahmad says.

NanoActiv HRT has seen a number of deployments for remediation.

“Our laboratory has essentially been the Permian basin, and we have recently started in the Bakken and D-J basins,” Holcomb says.

A deployment in a Niobrara reservoir revealed a “persistence effect” that significantly slows a well’s natural rate of decline.

“We don’t know how long the effect lasts because we only have about two years of data,” Holcomb says.

Some of the first commercial deployments of the nanoparticles were in Texas wells in the Wolfberry formation. In one well, nanoActiv was introduced at the outset, and it flowed almost seven months before the operator put it on a pump to drive up output.

This well, Holcomb says, reflected a reduced decline curve of only about 39% compared to untreated wells in the field, which showed an average decline curve of 60% decline over an annualized period.

In another Wolfberry well, the operator added an electrical submersible pump to a treated well after three months. After 241 days, this well was performing nearly 225% better than a group of offset wells, Holcomb claims.

“Recent data from horizontal well applications reflects an average of 20% to 30% higher (barrels of oil equivalent) than direct offsets over a one-year period with a typically higher oil cut and/or a lower decline rate,” he says.

As of early October, the technology had been used in more than 48 wells to treat nearly 2000 stages. In one deployment, it was run in a well with 62 stages.

In the future, it may be possible to learn more about why some nanoparticles remain in the reservoir while some flow back to the surface with the produced fluids.

“Such low volumes are required for an effective treatment, so there’s little chance you’d see them,” Ahmad says. “But we want to know more.”(Copyright)/