MANAGING PIPELINE COMPRESSION

PIPELINE ENERGY GROUP EXPLORES MARKET DYNAMICS, DUAL-DRIVEN

COMPRESSORS AND CENTRIFUGAL PUMP BASICS

By Drew Robb

Attendees at the May gathering of the Pipeline Energy Group (PEG) at the Opal Sands Resort in Clearwater, Florida, were treated to briefings on a wide range of topics. Presenters included Engie (formerly GDF Suez), Exelon, OSIsoft, Columbia Pipeline Group, Yaskawa, Toshiba, Plains All-American Pipeline, Siemens, AEP Energy, Energy Transfer, Rockwell Automation, Lubrizol Specialty Products and Sulzer Pumps. Talks on the Electric Reliability Council of Texas (ERCOT), dual-driven compressors, centrifugal pump maintenance and the looming threat of cybersecurity (p. 28) were of particular interest to the turbomachinery industry.

ERCOT accounts for 90% of the Texas power load with 24 million consumers and 79,000 MW of generation. It has 43,000 miles of transmission lines and 550 generation units. “It is a healthy system with a high reserve margin,” said Andrew Elliott, Director of Supply & Portfolio Management for Engie, “so price volatility is low and reliability high.”

ERCOT prefers a 13.75% reserve margin, and its peak usage in August of 2015 was 70,000 MW. The region has managed to stay above its reserve threshold and is expected to do so for many years. But coal plant retirements may change the picture. Gas dictates electric rates Currently, 52% of ERCOT capacity is from natural gas, 22% from coal, 18% from wind and 6% form nuclear. As a result, gas tends to dictate electricity rates in the state. “As the gas price goes, so go electric prices in Texas,” said Elliott. Natural gas and renewables will be future areas of growth in the Texas energy picture, particularly renewables, said Elliott.

Currently, the state boasts 15.7 GW of wind capacity, and expects to erect another 3,000 MW more by 2018. Solar is far behind at 288 MW but could rise as high as 1,000 MW by the end of this year. As for existing coal plants, he expressed concern about the regulatory picture. With Mercury and Air Toxics Standards (MATS) and the Cross-State Air Pollution Rule (CSAPR) already in force, and new rules concerning Regional Haze (calling for state and federal agencies to work together to improve visibility in 156 national parks and wilderness areas) and the Clean Power Plan (CPP) coming into play, coal plants may be required to add expensive scrubbers.

“Based on projected energy prices, the cost of these upgrades is not likely to be worth it for coal producers,” said Elliott. “But if ERCOT mothballs 5,610 MW of coal generation, it cuts the Texas reserve margin in half.”

Faced with regulatory pressure, how much lead time will generators give the market before they decide to shut these plants down? It takes two years to build a combined cycle power plant (CCPP). Gas facilities have the advantage of price: It is around $2.00 per million BTU today and is not expected to increase to more than $3.00 by 2020. This has repercussions on the global liquefied natural gas (LNG) market. Not so long ago, LNG prices were as high as $15 in parts of Europe and Asia, but now are down to $6. If gas costs $3, and another $3 or more to liquefy and transport it, that makes LNG exports only marginally profitable in some areas. With the exception of Mexico, low LNG prices may limit U.S. exports. If the LNG export facilities are built in time, up to 10% of U.S. gas may be exported.

Additionally, gas prices in Mexico are about 50% higher than in the U.S., and pipeline capacity is being rapidly increased to enable gas from the U.S. to head south of the border. “There are so many competing dynamics, as well as lots of lots of bullish and bearish indicators,” said Elliott. “Nothing is certain.”

Greg Kosier, Director of Commodity Management at Constellation, continued the discussion on markets. He noted that natural gas storage is currently at record high levels (nearing 2.8 Tcf) for this time of year (Figure 1).

Figure 1. U.S. natural gas storage levels have risen compared to the previous year

The Sabine Pass LNG export facility on the Gulf Coast in Louisiana has already shipped eight cargoes to places such as Brazil, Argentina, Portugal, India and Dubai. Kosier noted this represents the first meaningful exports LNG from the U.S. and is the precursor to significant growth in the years ahead. Four other LNG export terminals are in development, eventually taking U.S. export capacity to 9 Bcf per day. Due to lower LNG prices worldwide and increasing international growth in export capacity, it will be challenging for a sixth export facility to be built in the U.S. this decade, said Kosier.

Along with the growth in LNG exports, pipeline exports to Mexico will increase as 3.7 Bcf of pipeline capacity to Mexico is slated to come online in the next 18 months. Combining LNG with pipeline exports and growth in other sectors like electric generation and industrial uses, the current high surplus of natural gas should be reduced. One forecast suggests that existing demand (78 Bcf/d in 2016) should approach 95 Bcf/d by 2020 (Figure 2).

Figure 2: Natural gas demand will rise significantly in the coming years, particularly due to exports[/caption]

Duel-drive compression

The basic concept of dual-drive compression is to combine a natural gas-driver and an electric driver to provide greater flexibility, availability and profitability. Users can then switch from natural gas to electricity depending on the price. “Upfront costs of dual-drive equipment are higher than a single-drive system,” said David Coker, Senior Vice President, Energy Transfer, “and maintenance costs tend to be higher.”

Benefits include lower operating expenses, increased reliability, a 99% runtime, emissions reduction, the mitigation of interconnect delays and optimized fuel costs. Electric drives provide reduced emissions and lower maintenance costs. But they have the disadvantage of relying on the availability of the electric grid, peak-rate volatility and construction lead time for supporting infrastructure, such as extra transmission lines. Energy Transfer favors the combination of a Caterpillar engine, a Hyundai electric motor, an SSS clutch and an Ariel compressor in its system (Figure 3). Larger compressor stations, however, often make use of a gas turbine instead of a gas engine.

Figure 3: Energy Transfer’s clutch and hub assembly for its dual-drive compression system[/caption]

Gas to electric

“A seamless transition from gas to electric and back via the clutch is the key to our engine,” said Corker. “We make the changeover at full horsepower and throughput.” Depending on the application, the drives can be deployed in various ways. As it takes a few minutes to get the gas engine warmed up, for example, the electric drive would be used on start up. From then on, economics dictate which drive to use.

Typically, the system runs on electricity unless peak prices spike. At that point, it is immediately changed over to gas drive. Natural gas is usually cheaper than electricity, though not always. “Gas runs about 20% of the time in an unregulated market and about 2% in a regulated market,” said Coker.

One user at the Red Bluff site in West Texas ran the electric drive 78% of the time and the gas engine 21% of the time for a total of 99% availability. Emission levels also play a part in the economic equation. If regulatory requirements dictate a certain level of emissions, it can sometimes make sense to use natural gas if the price is right up to the prescribed emissions limit. For example, it may be possible to operate 3,500 hours per year with natural gas without having to incur the cost of selective catalytic reduction (SCR), said Coker. “The rest of the time you can run on electricity, but in our experience, people rarely go beyond 2,000 hours on gas.”

He gave the example of a gas cryogenics plant designed to have only electric-driven compression. But the South Texas Electric co-op (STEC) had to build a 54 mile, 138 kv line to the facility, which took two years to complete. As a result, the design was switched to dual drive. The co-op ran on gas until the electric line was finished. After that, the facility ran mostly on electricity to keep its emissions totals low. “We tell many of our customers to switch to gas between 3 p.m. and 6 p.m. when grid prices tend to soar,” said Coker. AEP built a financial model for a 10,000 HP compression facility using two 3.7 MW dual-driven compressors. By switching to natural gas during six peak hours per day, AEP saved $200,000 to $400,000 per year, said Jamie Jankowski, Director of Business Development.

Centrifugal pumps

Ankur Kalra, Hydraulic Design Engineer at Sulzer Pumps, educated the PEG audience on the basics of centrifugal pumps. He began by defining a centrifugal pump as a special class of pump which increases the kinetic energy of the fluid stream in a rotating impeller. Most of this kinetic energy is recovered as potential energy by diffusing the flow inside the collector downstream of the impeller. He informed the audience that initial equipment cost is only 5% to 8% of overall lifetime costs, while fuel costs comprise around 90%. Therefore, it is important to optimize the performance of the pump by running it in its comfort zone. Every pump has a comfort zone within its characteristic curves, which is the flow band where the pump is good for continuous operation. Outside this band, certain undesirable phenomena can occur and so, operation there must be separately assessed.

”Centrifugal pumps are happy to run within a small range,” said Kalra. “If you operate them outside of their comfort zone, you more likely to come across cavitation, bearing failures, seal wear and other issues.” He emphasized the difference between NPSHR and NPSHA. Net Positive Suction Head Required (NPSHR) is supplied by the manufacturer and is measured by testing the pump in a controlled factory test loop. Net Positive Suction Head Available (NPSHA), on the other hand, is a metric supplied by the customer. It is calculated based on system settings such as suction, discharge height, vapor pressure and pipe losses. “If you do a good calculation of NPSHA and provide it to the vendor, this can help to avoid cavitation issues in the field,” said Kalra.

The discussion also touched about modifications to centrifugal pumps. Impeller trimming, for example, can be done to adjust performance. Reducing the impeller’s outer diameter can decrease head and flow, thereby changing the best efficiency point (BEP) of the pump. Underfiling (taking out a little material from the underside of the impeller), though, has limited value in improving performance, though Kalra said it may be worth trying in some cases. Destaging, such as going down from 10 to 8 stages has the result of changing the head while the BEP stays the same. “If you destage, you can reduce the friction but it doesn’t shift efficiency much,” said Kalra.

Other modifications included: Increasing or decreasing the volute throat to adjust the position of the BEP; volute lip replacement using an insert that can be installed rapidly in the field; and improving surface finish to decrease fiction or drag.

The next PEG conference will be held in the spring of 2017 in Texas. For more information, contact Stephen Elliott at scelliott@paalp.com or call 713-993-5218.