New technologies often take time to find their niche in oil and gas fields. A number of hurdles stand in the path of rapid deployment.
Equipment run downhole presents the dilemma that, if it does not work, one could spend much money in trying to retrieve the equipment or even lose the well. But even new equipment installed at the surface often requires much testing before it is judged reliable or applicable for a field. One problem is that a typical oil and gas field does not exist. The produced fluids and pressures differ among fields, well depth and spacing varies, producing economics are not the same, and various fields are at different stages of depletion. It takes operators time to under stand the best field and well candidates for applying a technology.
Depletion presents a particular problem for designing production facilities, because as fields deplete, the production stream changes in respect to composition, pressure, and temperature. What may have been initially a high-pressure, low-GOR oil stream may turn into a gassy stream that later becomes a low-pressure water stream containing a minor volume of oil. Depletion may also cause production cost per hydrocarbon unit to increase over time.
Changing out equipment frequently can be cost-prohibitive, so most operators try to install equipment that is capable of handling a wide range of producing conditions.
Multiphase pumps
One new technology becoming more widely accepted is multiphase pumping. Although oil field applications for these pumps have been under development for more than a decade, it is only in the last few years that these pumps have seen increased use.
Because multiphase pumps handle the full well stream of oil, gas, water, solids, sand, etc., the pumps eliminate the need to install separators near a well and multiple flowlines. With the pump, the fluid is pumped in one flowline directly to a central facility for separation and treatment, thus decreasing the capital cost of developing remote locations, reducing equipment footprints, and eliminating gas flaring.
But as with any equipment, the pumps also have disadvantages, such as flow assurance issues caused by wax, hydrates, etc.; the need for higher pump pressures to move fluids; and the complication of having to meter multiphase flow.
An article in the Production Special that begins on p. 80 describes one application of multiphase pumps in a heavy oil production operation in California.
A May 2001 conference organized by Texas A&M University highlighted the progress made in multiphase pump applications. Chairman of the conference was Stuart L. Scott, associate professor in the petroleum engineering department at Texas A&M.
The conference divided multiphase pumps into the two primary categories: positive displacement, which includes progressive cavity, twin-screw, and piston pumps; and rotodynamic, which includes helico-axial "Poseidon type" and multistage centrifugal (electric submersible) pumps (ESPs).
A survey, presented at the conference, showed that, from 1989 through 2001, the number of multiphase pump installations had increased from 1 to about 240. This number excludes progressive cavity pump applications. Of the 240 installations, 212 had twin-screw pumps, while most of the remaining had helico-axial pumps.
Venezuela, 28%, and the former Soviet Union countries, 29%, accounted for more than half of the twin-screw installations in the survey. About 7% were in stalled in the US, 9% in Canada, and 8% in Germany and Austria.
Pump applications
Although installed in oil fields, some pumps are not being used for pumping a production stream containing oil. For instance, a wet vent gas was the stream pumped by a twin-screw pump in a pilot installation at Imperial Oil Resources Ltd.'s Cold Lake, Alta., in situ oil sands operation.
A presentation on this Cold Lake installation at the May conference indicated that the multiphase pump significantly simplified the process flow of the vent gas. The facilities initially required to handle this flow consisted of three pumps, three vessels, three heat ex changers, and two compressors. With installation of the multiphase pump, the process flow facility was reduced to only the pump, one vessel, and one heat exchanger.
Another application involved the PT Caltex Pacific Indonesia steamflood in Duri field on Sumatra Island. This entailed using a multiphase pump to collect and boost casing fluid, consisting of 95% gas and vapor from condensation. The pump also helped maintain wellhead pressure to ensure ESP intake was below liquid level and eliminated venting and flaring, according to another presentation at the May conference.
Pressure boosting from remote subsea projects is another application with great potential for multiphase pumps, but to date only a few such installations are in place. The Texas A&M conference noted existing installations in the North Sea, off Italy, and off Brazil.
But because multiphase pumps have started to establish a good land-based track record, their role in offshore is bound to become better defined.
