City Pumping

?Ryan Davis, production engineer for Merrion Oil and Gas, says,
“We expect a lower operating cost with these units. The only cost is the recompression
of the supply gas to the system.”

?Oil- and gas-field pumping units have been lifting fluids since the 1920s. The globally recognized “horsehead” counterbalance pumping units are unquestionably the dominant lifting tool of the oil field. However, some operators with coalbed-methane wells and in-city production are finding a newer, smaller and quieter way to go.

Ryan Davis, production engineer for Farmington, New Mexico-based Merrion Oil and Gas Corp., first learned of Nojak Pumping Solutions from an outsourced pumping specialist hired to maintain and optimize production wells. Merrion is a 25-person private independent that produces from some 200 wells spread throughout New Mexico, Utah, Wyoming and Colorado, and from nonoperated assets in southern New Mexico, northern California and Texas.

“Mark Turland, with Proactive Pumping Solutions, diagnoses a lot of our pumping wells,” says Davis. “He uses dynocards in conjunction with fluid level shoots, to determine pump fillage and make sure everything downhole is working as it should. Last year, he mentioned that he had come across some interesting new pumping technology for coalbed-methane wells.”

Turland introduced Davis to Nojak Pumping Solutions, an Alexandria, Indiana-based private portfolio company partially funded by Shell Technology Ventures Fund 1 BV.

Nojak manufactures, sells and installs small-footprint oil and gas pumps for shallow wells. Representatives from Nojak visited Merrion’s Farmington, New Mexico, well sites and offered to install two Nojak systems for a 60-day trial period with no up-front cost.

“We installed two Nojaks on our assets within the Farmington city limits,” says Davis. “They are Fruitland coal and Picture Cliff wells. These are shallow San Juan Basin gas wells. The Vinecom #1 well is about 1,300 feet and the Panther #1 is about 1,800 feet.”

The pumping system undergoes installation through a well's blow-out preventer.

The wells were previously worked using traditional rod-pumping units, but Merrion wanted to try something different. The rod-pumping units had a larger footprint than Davis wanted to use for in-city production.

The Nojak pumping system is small, using pressure-actuated chamber technology instead of counter-balance action. Depending on an individual well, either gas, air or nitrogen is used to apply pressure to downhole chambers. Fluid chambers are installed at 250-foot intervals and are number-designated either odd or even.

The system is operated by a control panel that automatically applies gas at a pre-set 150-psi pressure to the top of the odd-numbered chambers through internal control lines. It simultaneously vents the pressure from the even-numbered chambers through other lines.

The pressurized gas in the odd chambers displaces well fluid, causing it to flow to the even chambers directly above them. Check valves prevent downward flow. The control panel then directs pressurized air or gas to the top of the even-numbered chambers, while at the same time venting the pressure on odd-numbered chambers, causing fluid to rise from the even chambers to the odd chambers above them.

Finally, the lowest fluid chamber empties and vents as a combination of gravity and reservoir pressure causes more fluid to flow back into the chamber, then the process is repeated. Fluid reaching the surface flows into the production facility.

“We thought installing Nojak on these wells would give us a good comparison, as Nojak is limited to about 3,000 feet. The system is not suitable for deep wells, but the San Juan Basin is a good fit,” Davis says. Coalbed-methane wells are typically characterized by low-pressure reservoirs. “We have to keep the back pressure off them,” says Davis. “We need to lift the fluid out of the formation so they can flow at their maximum potential.”

During the first few days of the trial, Nojak and Turland worked to fine-tune the units.

“Now, the first well is completely dialed in, and we are at our previous production level. We are fine-tuning the second well to get our gas rate back up to where it was,” says Davis. “It took two to three weeks to get the Vinecom well dialed in and we have yet to get the Panther dialed in. We have changed line assemblies to increase capacity by 20%.”

?Dan Roberts, president of Nojak Pumping Solutions, says, “We want to get to the point where we basically install the pump in the ground and have the system optimize itself electronically.”

When the Vine was dialed in and gas production was back to its target rate, compressor problems revealed that neither system had enough excess capacity to make up flush production within an expected period of time. “The larger line assemblies have taken care of this issue,” he says. The Vine well was able to be pumped off in one day. In three days of production on the Panther, the larger system achieved the same fluid level that the smaller system produced in three weeks.

He notes that one of the main advantages of the Nojak unit is the visually aesthetic value. It has a smaller footprint on the surface than traditional rod pumps. “When someone drives by the Nojak, there is only the wellhead and the control panel with the small solar panel.”

The units are also quieter than a counter-balance pumping unit, emitting only a small hiss as the solenoid valves vent. Also, there are no moving parts above ground, which increases safety.

“We expect a lower operating cost with these units. The only cost is the recompression of the supply gas to the system,” Davis says.

Merrion already had wellhead compressors at its two locations, so the Nojak unit uses produced gas from the discharge side of the compressor, and exhausts it back into the suction side, to power operations. This decreases power usage by eliminating the need for additional power.

The system is more durable than rod pumps, which have moving parts that lead to surface wear and tear, says Davis. “Using rod pumps, sometimes we have to pull wells because the rod has worn a hole in the tubing or the pump wears out. Rig time is a big cost for us when we have to go out and pull the wells. When we eliminate pulling costs, it lowers our lifting costs per thousand cubic feet. It seems that the downsides of rod-pumping units are the upside benefits of the Nojak system.”

Also, the installation does not require a rig. Merrion’s Nojak units were spooled out and put into the wells by a Nojak truck at the rate of one system per day.

Davis is now evaluating the longevity of the units. “We know rod-pumping units have been around forever, running 24 hours a day, seven days a week. They are very robust and reliable. So we are monitoring how well these Nojak units are going to stand up to the competition. They haven’t required any maintenance yet, and they seem fairly user friendly.”

If the trial and subsequent operations go well, Merrion will likely install more Nojak systems on its producing properties where applicable, where onsite compression facilities are already installed.

“As soon as we have the second well dialed in and the systems prove to be reliable with extended run time, we will be looking for more candidate wells for this technology,” he says.

Meanwhile, his neighbors have taken notice. “Other companies in the area have contacted us for our opinion of the system.”

Dan Roberts, president of Nojak Pumping Solutions, is pleased with the opportunity to prove the technology.

“This technology was first developed in the 1990s for marginal oil wells when oil prices were between $15 and $20 per barrel,” says Roberts. The technology was marketed initially to reduce downtime in highly corrosive and high-paraffin oil wells, and then launched for general use under the Nojak brand in mid-2008.

“It’s a unique design because it has no precision parts downhole,” he says. “It’s all basically check balls and floats, without moving parts to wear out in the fluid or wellbore.” The operation moves fluids consistently, with no fear of “pump off” like traditional rod pumps that must have fluid at all times to avoid being destroyed.

“With this system, when there is no more fluid in the wellbore, the unit shuts down automatically, waits for fluid to enter the wellbore, then starts again. That eliminates the need for pump-off controls,” he says.

?Nojak technicians install connection line assemblies through a pumping chamber.

Nojak has installed several systems in coalbed-methane wells in New Mexico, where onsite compressors are used to increase gas pressure for pipeline transportation. Because Nojak units use a small amount of that available pressure to run the pump, no power is required beyond the solar panel that runs the 50-watt control electronics. In coalbed-methane or gas basins without on-site compressors, the company can install a small, efficient gas or electric compressor.

The system design limitations currently are at 3,000 feet (production capability reduces as it nears that maximum depth) and about 100 barrels of water per day.

“Some of the coalbed-methane wells come online producing as much as 300- to 500 barrels per day, which we can’t do,” says Roberts. “But once the well gets pumped down, our pump works much better, because it can handle the fines and there is no need for pump-off controls. We can originally install a Nojak system in wells that start out producing less than 100 barrels of water per day.”

Meanwhile, Nojak engineers are working to enable the system to go deeper and to handle larger amounts of produced fluids. If the system can break through its current 3,000-foot barrier, Roberts sees another big market for the system.

“We are also working on our electronics methodology to enable automatic optimization,” he says. “We want to get to the point where we basically install the pump in the ground and have the system optimize itself electronically.” At this point, the system requires no mechanical adjustments. Nojak is working on an electronic methodology as a next step.

“We have also tested this in a horizontal shale play in Kentucky, where we de-liquefied the heel of a horizontal well,” Roberts says. The system was able to successfully pump down water produced at a 30- to 40-degree angle in a deviated wellbore. However, after the removal of the water, it was decided that the well did not produce enough gas to be commercially viable.

“It also works efficiently in wells with sand, fines and corrosion. Marginal shallow wells, both gas and oil, and conventional or shale plays are our niche markets.”

Currently, a 1,000-foot-deep system costs between $25,000 and $30,000. Leasing is also an option, but most producers purchase the system, he says.

“We are not a big player yet. We have 15 employees, and we only started installing these commercially in June 2008, with 22 installations to date,” he says. The company has installed units in Texas, Oklahoma, Indiana, Kentucky, New York, New Mexico and Wyoming.

“The oil and gas industry is a show-me industry,” Roberts says. “These producers have seen a lot of crazy technology ideas over the years, and they have a lot of money invested in their wellbores. While most everyone is interested in new technology, they want to be sure it will work. But we are doing well so far. While we are still quoting systems for oil wells, our primary focus is coalbed methane and gas.”