Programs involving effective use of chemical treatments can have a real impact in increasing production, or at the least, keeping it steady,” said Steve Szymczak, BJ Services product line technology manager, citing advances that include use of water-wetting corrosion inhibitors, improved paraffin inhibitors, and foamers injected through capillary lines as a means to wellbore deliquification.

As is well known, because drilling rigs are built of iron and steel, which rust and corrode in the presence of oxygen or water, the most commonly used production chemicals are corrosion inhibitors. Conventional corrosion inhibitors are oil soluble or water dispersible. In either case, placing them onto an oil-bearing formation would most probably change its wettability from water-wet to oil-wet. Oil wetting will severely limit oil flow through the formation. Therefore, corrosion inhibitors are not typically squeezed into a formation.

That is, until water-wetting inhibitors came along, Szymczak said. “Today’s water-wetting corrosion inhibitors allow users to squeeze a corrosion inhibitor into place so you get better and longer protection, without impacting formation wettability. In areas where corrosion inhibitors are applied through periodic treater-truck applications, a squeeze could reduce treatment cost, maintain acceptable corrosion inhibition, and extend the period between applications.”

Another example of a relatively new technology would be paraffin inhibitors — chemicals injected into the well bore, flowline, or pipeline to prevent or minimize paraffin deposition — suitable for cold climates. Paraffin is a hydrocarbon and a very valuable portion of the crude-oil stream. But it also deposits in pipelines and can inhibit lift, especially in cold weather. In those cases then, where the hydrocarbon is exposed to frigid temperatures, it is critical to maintain its fluidity.

To deal with the paraffin deposition problem, said Szymczak, “paraffin inhibitors are applied to the crude stream. Doing so mitigates deposition, lowers the operational cost of melting or removing the paraffin, and gives you a higher-value crude stream.” Paraffin inhibitors, however, can themselves be difficult to use. Unless specifically formulated for that environment, chemicals used as paraffin inhibitors will solidify in cold weather.

So while paraffin inhibition must occur above the wax appearance temperature of the oil, the paraffin inhibitor must be above the temperature at which it solidifies.

“Through use of very highly specialized formulations we can today mix paraffin inhibitors and co-solvents of alcohol and glycol,” said Szymczak. “So that at winterized conditions they don’t solidify. This innovation didn’t exist in 1999.”

A third innovation cited by Szymczak is use of through-tubing capillary injection lines. Typically, these are of one-quarter or three-eighths inch inside diameter and are used for surfactant injection to achieve wellbore deliquification.

“The production rate of a gas well can drop very quickly,” he said, “and as it does produced water will enter the well bore. When that water-column weight overcomes the ability of the gas to produce through the water it can kill the well, because the gas isn’t able to eject the water.”

To remedy this problem, capillary injection lines are placed through the well head in live conditions. The tubing is typically placed one-third of the way below the top perforation. This is similar to a coiled-tubing operation except that the capillary stays in the hole permanently. Foamer can then be injected into the tubing to enter the well within the perforation zone. Once in the water, the surfactant is agitated due to the gas bubbles and creates foam. The foam has a lighter density than the water, and the existing gas pressure is able to lift the foam. At the surface, the foam breaks down into gas, which is produced, and free water, which goes to the disposal system.

“During the last downturn,” Szymczak said, “this method for deliquification wasn’t fully refined. But it’s become a big part of the industry today. Operators in Texas, for example, often place capillary lines in new wells and those showing signs of liquid loading. Investing in a couple of gallons of chemical per day leads to production increases of several hundred thousand cubic feet per day. If production increases 400,000 cf, that pays for a lot of chemical at eight to twelve dollars a gallon. We can go to an operator, feed their parameters into a model, and tell them whether their wells are a good candidate for a foamer.”

In addition to foamer, other chemicals, including corrosion, scale, and paraffin inhibitors, can be applied through capillary. It is not uncommon to formulate combination products to handle a variety of downhole problems through one application.

“Lifting costs come down through either reduced operating costs or increased production,” Szymczak said.

Downturn or no, he concludes, good chemistry gets good results.