See If This Sounds Like Your Reservoir

Overview The Nacatoch B Sand in Caddo Parish contains 75-80% of the Original Oil In Place in spite of being in production for over 100 years.
This is because water cones in early to the wells. Nonetheless, before the water cones in these wells would typically pay out in 4-6 weeks so intensive drilling through various promotion schemes was done over the years. Net result? About 8-10,000 marginally productive/‘watered out’ oil wells in the immediate area. 

All of the fluids in the reservoir are moving exactly as would be predicted by any competent Petroleum Engineer and our oil/water cut is well under 1%.  The water is outracing the oil to the well bore exactly as would be predicted given that the water has a viscosity of 1 centipoise and the oil is at 250-300 centipoise viscosity. How to change the game forever? Change the viscosity of the water very cheaply and a new equilibrium state, where the water and oil move at different rates to the well bore, will persist indefinitely.

Pertinent History: I pioneered single well treatments with cross-linked polymer gels in the Caddo Pine Island Field in NW Louisiana. Some jobs paid out overnight, some in two weeks. Some lasted two weeks, some have lasted more than 2.5 years but the water always finds its way back to the well bore through ‘viscous fingering’, the well understood mechanism by which a thinner liquid (water) will find it’s way through permeable media (the reservoir) filled with a more viscous fluid (oil). 

I have a video of a Nacatoch well, slated for plugging, that got a regular cross-linked polymer job. We were able to ‘pump the well down’ after the water channels were sealed. You can see it on Angel Petroleum Technologies FaceBook page.
This well had a Drake unit on it with a 24” stroke pumping four strokes a minute. You can hear the unit working in the background. You will notice that the oil flowing up the tubing is not correlated to the action of the pump jack. See the live oil?  
Live oil tells us something interesting. Inhibiting water flow to the well bore allows us to ‘pump a well down’ and causes a pressure drop in a region around the well bore that has not seen a pressure drop before. Otherwise, the gas in the ‘live oil’ would have already come out of solution. Oil with natural gas dissolved into it has a lower effective viscosity in the reservoir, good for us. The lower the differential viscosity between the oil and the water, the more bang for the buck.

History and Life Cycle of an oil well in the Nacatoch B Sand The oil productive region of the Nacatoch sand covers about 90 square miles. The oil is API 20 gravity with a viscosity of about 250 centipoise at reservoir temperature. Underlying the oil sand in this relatively homogenous reservoir is the water productive sand. Viscosity of water is 1 centipedes. (Visualize having a pipe filled with sand and sucking water up through it. Pretty easy.  Now, fill it with 30 weight motor oil. Repeat. Not easy. Viscosity at work. See “Core Flooding” printout.) 

When a new well is drilled the only fluid available at the perforations is oil. A production pump is run into the well and fluid is removed until sufficient hydrostatic head has been removed to cause the oil to flow into the well through the perforations. Soon, usually 4 - 6 weeks, water has begun to appear in the production stream and the oil cut begins to diminish. Until now, there was no way to reverse that trend.
Because of this early and profound water coning an estimated 75-80% of the original oil in place remains throughout the field. A well that has coned to water has essentially protected itself from meaningful production.
Water, being so much less viscous than the oil, travels through the sand very readily. As a consequence the pumping fluid level of the well rises until there is no longer a sufficient pressure drop to mobilize the more viscous oil into the well bore. Unlike the oil, the water will move under the influence of a modest pressure drop. The oil will not. There are 8-10,000 Nacatoch wells in the Oil City/Vivian area which are ‘watered out’, the economics are marginal, the reserves in the ground are cheap because leases are valued on the basis of reserves, they are priced according to how many barrels of oil they produce per day.   
Basically, any of these wells will produce all the water you care to pump with only a 15 psi drawdown (lowering the pumping fluid level about 30’) but to get enough of a pressure drop to mobilize the oil in large quantities you need to be able to pump the well down about 175’ from the standing fluid level to get an 85 psi pressure drop between the reservoir and the well bore.
The field is de-risked. Geology is known and understood, wells have already been drilled and paid out, reserves are known. I believe that 60% of the OOIP can be recovered economically through mobility control. Why such a large number? The usual additional increment for Secondary Recovery (water flooding, etc) is 30%. A polymer flood is usually undertaken after a water flood has played out and is good for an additional 30%. The Nacatoch B is not suitable for water flooding so this 30% increment, which would have normally been produced by now through waterflooding, remains to be monetized. Total recoverable reserves with mobility control should be 60% of OOIP.
Our business model does not rely on drilling any new wells. Instead, we will permit and convert existing some producing wells into injection wells. This concept is provable at a modest cost in scale work. All lab work, engineering and field testing has been done and validates the fundamental premises of this technology.
This is about using a cheap, game changing technology to leverage the monetization of a stranded asset, previously unrecoverable oil. Current leasehold valuations are done on the basis of BOPD produced on the lease and is about $50,000/BOPD. What happens to the valuation of a leasehold whose production increases 20X in a short period of time?
At $50/bbl this is in excess of $12 billion in incrementally recoverable oil. 30% for the Secondary Recovery that was never done and 30% for the mobility control in reservoirs of this type which is well documented.
Empirical Results Single well polymer water shut off treatments on Bayou State’s Kelly Lease indicated that it was only necessary to drop the pumping fluid level about 175’ to produce 67 BOPD for two wells on which I did single well polymer treatments, both of which were slated for plugging.
I have been able to achieve over TWICE the amount of pumping fluid level drop necessary to mobilize the oil at the demonstrated Bayou State rate.
This equilibrium, the totally predictable high production rate of water vs oil will persist until that equilibrium is changed and a new equilibrium state is reached.
Actually Simple There are ONLY 3 factors that affect the rate at which a fluid will move through permeable media.
1) Pressure 2) Permeability, and  3) Viscosity
I can’t change the bottom hole pressure to favor oil movement and I wouldn’t want to. We have plenty of drive.
Until now, I couldn’t modify the permeability of the reservoir to water or to increase the viscosity of the water. I can do both now, and cheaply. In fact, in the core flooding trial the Residual Resistance Factor was a little more than 3X, i.e., the sand was three times less permeable to lease water transit than before it was exposed to polymer. Each time the pore throat volume is reduced by half, the volume of flow is reduced by 75%.
As designed, the water sand will NOT see lease water again but the inhibition to water based polymer flow will also manifest, effectively reducing permeability to flow to the well bore and allowing the well to be pumped down to the point where the pressure drop is sufficient to mobilize 15,000% more oil to the well bore.
A New Polymer A new class of polymers called “Associative Polymers” changes the game very economically. The polymer I use is proprietary and private labeled.  
Until recently, all polymers had either a positive or a negative charge on the polymer molecule depending upon the use to which the polymer was put.
An Associative Polymer has a positive charge at one end and a negative charge on the other end and are called Associative because the molecules orient and associate themselves together in low shear regions to hook themselves together like cars in a freight train, enormously increasing viscosity with very little product used.
This is a slow motion video of an Associative Polymer being mixed in a kitchen mixer. See for polymer blending.
Notice that at the beaters that viscosity is low. This stuff will flow through a Marsh Funnel pretty easily.
There is a second ‘band’ out towards the right hand side of the bowl. Look at the bubbles. You will see that at the region at the top is mobile while the region at a the bottom of the bowl, influenced by the smaller radius of the tapered beater, has less mechanical energy and hence higher viscosity and is relatively stationary.
Finally, at the outside right edge of the bowl the polymer is very viscous. If you picked it up in your fingers it would be like holding an egg yolk.
This is an example of a non-Newtonian fluid exhibiting shear-thinning viscoelastic behavior. Cost Disparity By way of illustration, I sold 300 polymer jobs at a cost of $12-14/bbl using 1.75 pounds of product per barrel. I can make an associative polymer blend more viscous than the oil for $0.25/bbl using less that .1 lb/bbl. Because of the close well spacing up here, it should be easy to show results in fairly short order at minimal expense. Once an operator starts this process they will be highly financially disincentivized to stop = captive customer base.

Pricing Factors In Our Favor We don’t want the same viscosity as the oil though, that would lead to unnecessary expense and oil/water separation issues. Because the change in the Adverse Mobility Ratio (why we make so much water and so little oil) changes exponentially with a modest increase in the viscosity of the water from 1 centipoise to 15-20 centipoise dropping the Mobility Ratio from 150 to about 12.
Not only does the polymer increase the viscosity of the produced water, making it more difficult to move it to the well bore so that it no longer out-competes the oil in getting to the perforations this polymer also confers to the water sand what is known as a Residual Resistance Factor because the polymer adheres to the sand facies inhibiting subsequent water flow, and significantly, flow of the water based polymer blend.   

Incentives This method of enhanced oil recovery is Tertiary Oil Recovery and qualifies for windfall profits tax exemption, Federal Tax credits and a reduction of Severance Tax by .8% (Confirming) See below 

Unique qualifications for Caddo Pine Island  
1) Very close well spacing. Each time the distance between an injector and producer doubles the amount of treatment required quadruples.  With close well spacing an operator is waiting weeks, not years to see results as would be the case with 10 acre well spacing and the same water sand thickness.
2) Large water sand under the oil sand prevents a conventional polymer flood.  
3) Because the Nacatoch B has never had any secondary recovery, that increment of oil, estimated to be 30% of the original oil in place, remains to be recovered. Estimated recoverable incremental oil over 6-10 years is estimated to be 60%+, or basically 3X the amount recovered in the last 100 years
4) Field is de-risked, no exploration or drilling risk, market is in pain.

Incentives Enhanced oil recovery (EOR) credit The EOR credit is phased out in a given year depending on the oil reference price for the prior year. The oil reference price is the government’s estimate of the annual average wellhead price per barrel for all domestic crude oil the price of which is not subject to regulation by the United States. Thus, when domestic oil prices are low, the EOR credit is available, but when domestic oil prices are high or even in a middle range, the EOR credit phases out. Specifically, if the inflation adjustment factor (IAF) for the EOR credit for 2015 is not lower than the IAF for 2014, the EOR credit will be available in 2016, and it will not be phased out. The enhanced oil recovery credit is equal to 15% of the taxpayer’s qualified enhanced oil recovery costs for the tax year. “Qualified enhanced oil recovery costs” means any of the following:  

  • An amount paid or incurred during the tax year for tangible property: (1) that is an integral part of a qualified enhanced oil recovery project; and (2) with respect to which depreciation (or amortization in lieu of depreciation) is allowable.
  • Any intangible drilling and development costs: (1) that are paid or incurred in connection with a qualified enhanced oil recovery project; and (2) with respect to which the taxpayer makes an election under section 263(c) for the tax year.
  • Any qualified tertiary injectant expenses that are paid or incurred in connection with a qualified enhanced oil recovery project and for which a deduction is allowable for the tax year.

  • Defined as: An enhanced crude oil recovery project conducted in accordance with sound engineering principles as used in the industry, subject to the approval of the commissioner and employing one of the following methods: miscible gas floods involving the injection of hydrocarbons, carbon dioxide, and nitrogen; near-miscible fluid floods involving the injection of alkaline, surfactant, hydrocarbons, carbon dioxide, or nitrogen; immiscible floods involving the injection of carbon dioxide.
  • No severance tax shall be due in regard to production from qualified tertiary recovery project approved by the assistant secretary of the Office of Conservation of the Department of Natural Resources until such project has reached payout from total production of: investment costs; expenses peculiar to the tertiary recovery project, not to include charges attributable to primary and secondary operations on that reservoir; and interest at commercial rates.