Field Tests of the Water/Liquid Oxygen Injection Process

In 1980 Len Andersen invented and disclosed to many concerns a process for oil recovery by injecting liquid oxygen into an oil formation. Since then he patented the process, spoke to people concerning how they used the process, beard people had been robbed and killed taken in by fraud concerning the process and put no money in his pocket from the process. In 1988 he got enough money to do a field test.

It appeared that the injection of liquid oxygen might also control channeling in water flooding. A program was put together in 1989 to investigate the effects of injecting liquid oxygen into an oil formation with a field test and making public the results. To control cost, a change in the process was done. Liquid oxygen was mixed with water at the injection well head and the mixture of water, ice, liquid oxygen and oxygen gas was injected. This yielded a bulk temperature of approximately 32° F (0°C), which is compatible with well assembiy steel. Otherwise at the boiling temperature of oxygen −297 ° F (− 183°C) special materials such as copper, aluminum and stainless steel would have had to be used. Jim Hester provided field selection and field knowledge.

The field test was done as an initial step. A quantity of liquid oxygen mixed with water was injected as quickly as possible into the oil formation and monitoring of production, water injection pressure, physical properties of the produced crude, etc. was done. The success in the first test led to a simiiar second field test in the same geographical area. On the second test the litology, produced crude, degree of consolidation, depth and well assemblies were different.

The field started producing August 1984 with a water injection pressure of 450 psi (3102 kpa), and a production of 30-35 b/d (135 m^-3/d), Injection pressure dropped off rapidly in August 1988 to approximately 280 psi (1930 kPa) with a production rate of 6-7 b/d (1.0-1.1 m^-3/d.

In July of 1989 the field had borderline economics, before the test. The cap rock is shale and 145 ft.(44.2m.) thick. Initially the well pattern was an "irregular 6 spot". The injection well was a 4 1/2 inch casing without a tubular with an open hole completion, the producing wells are perforated completions with the thickness of the pay zones between 4 ft.(1.22m.) and 40 ft(12.2 m.) measured at the wells.

Initially a liquid oxygen pump was the way liquid oxygen was to be delivered to the well head. No suitable liquid oxygen pump could be found therefore an alternative system was developed. The generalized PI&E (Piping Instrumentation & Equipment (diagram Figure 1 " PI&E Diagram for First Field Test Using the Water/Liquid Oxygen Injection Process" Said fluid (water/liquid oxygen) is a mixture of liquid oxygen, gaseous oxygen, water and ice at approximately 32°F (0°C).

The initial view of the effect of the liquid oxygen is that upon getting injected into the formation that it goes along the path of least resistance, this path would follow naturally occurring weakness (imperfections) in the formation. These channels have irregular geometries and directions. The cold gaseous oxygen, water, ice, little if any liquid oxygen mixture in the formation would have vaporization, reaction combustion, detonation occurring in close proximity. This yields fracturing, a change in the oil-wet/water-wet nature of the formation rock, heat shock and local pressure builds up. It was envisioned that the channels would structurally fail. This would result in an increase in injection pressure and the amount of the oil in the produced fluids. The secondary effects would be changing formation wetting properties, insitually upgrading the oil and carbon dioxide flooding.

On July 13, 1989 the initial reading of water injection pressure of 230 psi (1586 kPa) was taken, the existing injection wellhead was removed and the set up of Figure 1 installed, a cylinder of oxygen gas was flowed into the injection well as a pretreatment with injection water flowing, and a cannister of liquid oxygen was flowed in driven by three cylinders of oxygen gas. Tn total 18% of the injected oxygen was injected on July 13, 1989. On July 14, 1989 with the receipt of additional oxygen gas cylinders 82% of the liquid oxygen and 74% of the gaseous oxygen was injected in 5.3 hours. The injection of the mixture of liquid oxygen, gaseous oxygen, water and ice caused the liqlid Oxygen pressure to reach 480 psi(330 g kPa) and the water injection pressure to reach 460 psi(3172 k Pa). on July 16, 1989 the water injection pressure dropped to 150 psi(1034 k Pa), the residud amount of oxygen gas (8% of the total gas) was flowed in, and the field was shut in, The water injection pumps and producing pumps were turned on, on July 23, 1989 with production resuming. There was a change in which well the injected water went into on September 9, 1989 ending the fieid test.

There was before, during and afler monitoring of

• Water injection pressure

• Oil production

• Physical properties of the crude oil produced.

• Separators

Gas which came from the wells when the pump were shut off and select crude oil samples were chemically analyzed. The most important question is what is the oxygen doing in the formation? Was there a significant amount of combustion in the oil formation caused by the injected water/liquid oxygen oil? There was a total of 1030Ibs.(467kgs) of liquid oxygen injected mixed with approximately 20 times that Much water.

There were the following indications of combustion being achieved

• On the next lease over, there was a large amount of "gas" in the gun barrel (separator) which caused mixing (the liquid to turn over) and water go into the stock tank. This was noticed on gauging tanks on July 17, 1989, within 24 hours of the last oxygen addition [31 Ibs.(14 kgs.)] and turning off of the pumps. The next lease was 3000 ft, (911.4 m.) away.

• One of the production wells produced a "good oil cut" before the treatment produced "pure water" after.

• Three of the production wells while they were shut in were sampled for gas. One of the said gas samples was analyzed as having 10% carbon dioxide "calculated air free".

• A well which was being drained by a rod pump was not being drained down adequately after the treatment.

• The sound of a rifle range was heard three hours after the water injection pump and production pumps were turned off, from the direction of the said next Iease over.

• Three barrels of crude oil flowed into the stock tank with the pumps off.

• The API gravity of the oil was apparently increased by the water/liquid oxygen treatment. The baseline for the API gravity for the crude was approximately 29.50° (0.8789 gm/cm^-3)on the flow into the stock tank. On said flow the API gravity was 29.66° (0.8780 g/cm^-3) on July 26 1989, 29.70 (0.8778g/cm^-3)on August 6, 1989 29.75° (0.8775g/cm^-3), on August 14 1989 and approximately 29.5° (0.8789 g/cm^-3) August 21, 1989. The crude oil was sampled at individual wells. On a well between the injection well and said next lease over the API gravity was 31.71° (0.8679 g/cm^-3) on July 19, 1989 during the shut in.

• There was the sound of gas and foaming in the separator in the day after production was restarted.

• There was a 20% increase oil production for forty days fioxn a baseline of 5.6 b/d as shown in Figure 2, "Oil Production from July 23, 1989 to September 1989 with Field Test I" The water injection pressure was effected by the treatment. The anticipated effect was a water injection pressure increase. That did not happen. Fifteen days after resuming water injection the pressure of 200 psi (1379 g kPa), 87% of previous levels occurred. The highest pressure observed was 220 psi (1517 k Pa), 95% of previous levels 20 days after resuming water injection.

  The crude oil produced as observed in the gun barrel (separator) and the stock tank was different than previously observed. The sound of gas was heard for three days after restart of production. There was little 1 to 1 1/2 in. (2.54-3.81 cm) of emulsion in the separator 18 hours after of the resumption of production. Fourteen days after the resumption of production there was no emulsion in the gun barrel. Before the water/liquid oxygen injection there had been up to 6 in (15 cm.) of emulsion in the separator.

1. The injection of liquid oxygen with produced water into a water injection well in a water flooded non consolidated channel (gun sight) sand oil field increased oil production by 20% for forty days.

2. The hoped for channeling control did not develops. The water injection pressure did not increase. It decreased initially and after 20 days achieved approximately 95% of previous levels.

3. More than 50% of the injected liquid and gaseous oxygen was consumed in combustion and reaction.

4. Less than 5% of the injected liquid oxygen reached oil formation as a liquid.

5. There was rapid and concentrated combustion in high parts of the oil formation supported by the injected oxygen. This causes a large steam "bubble" which moved oil around in the oil formation facilitating producing said oil.

6. The process done on an on going basis with appropriate equipment and all the same conditions would have been a financial success.

7. The shut in time could have been reduced from 7 days to 1 day.

Basis: $15.00 per barred of crude oil in stock tank and linearity of production versus time.

Average oil production before treatment = 5.6 inches/day

Average oil production: days 1 to 47 = 6.5 inches/day

Average oil production: days 31 to 40 = 7.55 inches/day

Average oil production: days 41 to 47 = 6.43 inches/day on a linear decline the production loss per day = 0.16 in.

The numbers of days for production to decline to previous levels = 12

(0.16 inches) × (12 days)(1.17 barrel)(15 dollars)= 776 U.S.Dollars

Cost Basis: $1.00 per 9.5 pounds of oxygen

Basis-Servicing cost estimate at the materials costs =$148 U.S.

Total Cost = 297 U.S. Dollars

Basis on going operation

The test is on a five spot water flooded field with produced salt water being batch injected as it is produced. The lease is 160 acres (64.7 ha.) with a separate reservoir which borders one end of a larger reservoir. These two reservoirs defined by drilling are 811 acres (328.2 ha.). These reservoir produced 2 1/2 million bbls. (397,500 ^m-3) of oil on primary production from discovery in 1954 to 1974. There was a pilot water flood on 25% on the reservoirs between 1974 and 1979 with 4 million barrels (636,000 m^-3) of fresh water injected of which only 60,000 barrels (9540 m^-3) of salt water and 30,000 barrels (4770 m^-3) of oil were produced. A water injection pressure of 1300 psi (8960 kPa) was reached. The majority of the reservoirs and all of it after 1979 was on stripper, salt water injected production, total production was depleted to about 6 b/d (0.95 m^-3/d) in August 1989.

This pilot water flood was done 9% on the reservoir which water/liquid oxygen injection was done. The high water injection pressure approached the tlacture pressure of the shale cap rock. Jim Hester had worked the lease for two years and reviewed data on the previous work on the oil field. His belief is that injected fresh water went to a shallower zone and the high paraffin content of the oil was such that the injected water did not displace the oil. Based on a study of cores, the water flooding of the reservoirs should produce 1.85 to 2.67 × 10⁶ bbl.(2.94 to 4.24 × 10⁵ m^-3) of oil.

This test was done with a reservoir which produced a light high paraffin oil in the believe that there would be an oxygen-oil reaction over coming the paraffin blockage of the formation problem. Beyond the paraffin oxygen reaction possibility the theory was the same as with the frst field test. With this field test a liquid oxygen pump with a 600 gallon liquid oxygen feed tank was used. The Piping, Instrumentation and Equipment (PI & E) diagram is shown in Figure 3, "P I & E Diagram for the Second Field Test."

On August 11, 1989 Jim Hester and Len Andersen surveyed the lease and made plans to do a field test. To determine the reservoirs response to the injection of the produced salt water with liquid oxygen. On October 1989 a liquid oxygen canister of 250 lb (114 Kg.) of liquid oxygen driven by four 240 scf gas cylinders was injected with salt water. The water injection pressure went to 510 psi (3516 kpa) in 44 minutes. Previously the water injection pressure would go between 0 and 230 psi (0 and 1590 kPa). After the salt water/ liquid oxygen injection, the injection well head pressure varied from 120 to 430 psi (827 to 2965 kPa). On November 1989, 33 days after the salt water/ liquid oxygen injection the high pressure of 430 psi (2965 KPa) was followed by a pressure of 416 psi (2827 kpa) with the next salt water injection.

A liquid oxygen tank with a 600 gal. capacity was delivered to the area of the injection well head on November 28, 1989. On November 29 the tank was filled. The liquid oxygen pump was put in place and the connecting plumbing was installed. On December 2, 1989 there was an attempt to pump liquid oxygen. The pump cavitated and pumped gas for 2 1/2 hours. The connecting piping was changed, the high pressure valve of the liquid oxygen pump was disassembled, cleaned and reassembled. At 1830 hours, December 6, 1989 liquid oxygen started pumping into the injection well with the injection water flowing. This continued for 7 hours until the liquid oxygen pump was turned off because of a concern that the pump might be damaged when the liquid oxygen ran out. A total of 4001 lbs. (1815 kgs.) of liquid oxygen was injected with the water injection pressure reaching 780 psi (5378 kpa) and the liquid oxygen injection pressure reaching 900 psi (6205 kPa) after 5 hours 21 minutes, remain constant for more than an hour. The initial injection wellhead pressure was 140 psi (965 kPa). Salt water injection continued for 10.8 hours after the liquid oxygen injection ended with the pressure dropping to 450 psi (3103 kPa) after 45 minutes, of the end of the liquid oxygen pumping and increasing to 500 psi (3447 kPa) after 10.8 hours.

The 5/8 in. (1.59 cm.) tubing connecting the well bead with the liquid oxygen pump was dissconnected and found to have a large amount of salt water in it. Apparently the non return valve isolating the liquid oxygen flowing into the well head tim a back flow of salt water, gets ice in it and allows salt water to back flow. The liquid oxygen tank was refilled and on December 12, 1989 salt water/ liquid oxygen injection was attempted. Due to cavitation only gas was pumped for three hours. On December 13, 1989 with an ambient temperature of 25° F (-4°C) the liquid oxygen pump was switched on for two minutes before the water injection pump liquid oxygen for 69 minutes. A liquid oxygen pressure of 950 psi (6550 kPa) was noted and that the bronz master valve was leaking pure liquid oxygen near its top. An attempt was made to stop the leak by opening the high pressure bleed valve letting some of the pumped liquid oxygen to go to the atmosphere. The valve stopped leaking liquid oxygen at 800 psi (5515 kPa). In view of concerns that there might be a permanent failure of the well head leading to salt water loss and an inability to measure the amount of liquid oxygen loss, the liquid oxygen pumping was stopped 91 minutes, after starting.

The high pressure bleed line was connected to the liquid oxygen tank’s highest valve forming a closed loop. This gave the pump a return line so that the liquid oxygen pressure could be controlled without oxygen loss. The liquid oxygen flow to the well head was done 9 minutes after the start of the salt water injection. At 900 psi (6205 kPa) and 760 psi (5240 kPa) the water injection pressure the bronz master valve leaked again. An adjustment of the high pressure bleed valve brought the liquid oxygen pressure to 800 psi (5516 kPa) stopping the leak. The valve was stiff from ice getting into it. There was a loud sound indicating that water/ice had got into the pump followed by the pump cavitating. The liquid oxygen pump and the water injection pump were turned off. The valves to the liquid oxygen tank were closed and the vent valve for the pump was left open. On December 14, 1989 there was a flow of oxygen gas continuing from the vent valve with the liquid oxygen tank nearly empty. Salt water had flowed back to the highest valve on the liquid oxygen tank. There it formed ice and prevented the liquid oxygen tank’s valve from completely closing. That led to the loss of contents of the liquid oxygen tank, and there was no more salt water/liquid oxygen injecting done on this reservoir. In total 5685 Ibs (2566 kgs.) of oxygen was injected mixed at the well head with 18 times as much water. Liquid oxygen constituted 96% [(5144 Ibs) 2333 kgs.)] of this.

The effect on production was complicated by:

1. The high maintenance requirement of the production. Due to this during the test only two production wells were operating for more than 5 months.

2. Over 6 unscheduled electrical outages, and due to pipelines and well head freezing

   See Table 1 "Production Averaged to show the Effect of the Salt Water/Liquid Oxygen injection in the second Field Test"

There was an upset condition where a shut in well leaked salt water fkom approximately May 28 to approximately July 1, undetected. This resulted in the injection pressure dropping off over a month’s time. The leak was addressed by switching the produced salt water injection from the original well to another well. This was done from July 4, 1990 to September 1, 1990 with 90% of the produced salt water flowing into the second well without pumping. Without the salt water/ liquid oxygen augmented water injection having pressures from 140 to 550 psi (965 to 3792 kpa), the production dropped off 1/2 b/d (0.08^-3/d). With the salt water injection well on September 1, the production increased 1/2 b/d (0.08 m^-3/d).

There was an increase in production from a well on the lease connected to a formation at 3400 ft. (1036 m.) which was thought to have no communication with formation at 1900 ft. (579 m.). The production went from 14 b/d (2.2 m^-3 /d) to 28 b/d (4.4 m^-3 /d) about the time the first salt water/ liquid oxygen injection was done and the production stayed at that level at least until December 15, 1989.

There were changes in the density of the crudes produced are shown in Table 2 "Changes in the API Gravity of the Produced Oil in the Second Field Test." The density of the produced crude oil was lowered by the salt water/liquid oxygen injections. The quickest recorded response was API Gravity going from 38.6° (0.8319 g/cm^-3) to 39.2° (0.8389 g/cm^-3) in 51 hours. This indicates a chemical interaction between oxygen and the reservoir oil and/or thermal cracking of the reservoir oil.

The effect of the salt water/liquid oxygen injection on the subsequent water injection pressures was beyond what would be caused by the increased rate of water injection. On October 8, 1990 an additional 70 b/d (11.1 m^-3/d) of salt water from another reservoir was injected doubling the rate of salt water injection. In the next 31 days the water injection pressure increased from 490 psi (3378 kPa) to 525 psi (3619 kPa).

The increase in the water injection pressure was due to changes in the oil bearing formation. It appears that the injection of the salt water/liquid oxygen mixture had distributed oxygen in voids a long channels within the formation. The oxygen mixed with hydrocarbon and rose in temperature until there was combustion. This combustion caused the structural failures of the channels yielding an increase in water injection Pressure and the injected salt water contacting previously unsweeped parts of the oil formation.

Basis – An on going operation with the cost of liquid oxygen at 1 dollar/gal and the cost of injecting liquid oxygen with salt water at 1 dollar/gal. of liquid oxygen.

Gross = 2552 dollars

The similarities between this and the fmt field test are:

1. Production day(s) immediately following the water/liquid oxygen treatment had low production levels.

2. A high production period occurred after approximately two weeks of producing.

3. There was one well which went to water only production.

4. There was an API gravity increase of 1 degree caused by the water/liquid oxygen treatment.

The big difference was the increase in water injection pressure.

It decreased the first field test initially and returned to previous levels. On this field test the high pressure increased by 139%, 230 to 550 psi (1586 kPa) at the end of the periodic salt water injection and retained wellhead pressure of 300 psi (2068 kPa) where previously the injection well head pressure went to 0 psi. This difference appears to be related to the greater degree of consolidation of the formation in the second field test. The hope for oil front of a classical water flood has not occurred. This could be due to the communication between the 1900 ft. (579 m.) formation and the 3400 ft. (1036 m.) formation and/or the many stoppages allowed the front to dissipate and not give an obvious effect, and/or the complexity of the formation prevented a front from forming. The production on the lease was suspended on November 10, 1990 due to pollution concern requiring an oil pit to be dug out.

This field test indicates that the patented water/liquid oxygen mixed at the well head and injected process can control channeling in water flooding and increase production in a consolidated formation.

The effects of injecting liquid oxygen and water with mixing at the well head into the two oil formation tested were:

1. In an unconsolidated formation moving oil from one part of the formation to another allowing said oil to be produced.

2. In a consolidated formation the channels are closed by breaking up the formation forming said channels yielding higher water injection pressures and production.

In view of these field tests additional opportunities to use injected liquid oxygen in enhanced oil recovery, heavy oil recovery, channeling control in water flooding, formation fracturing and reservoir definition are being sought.