# Lessons Learned

from Natural Gas STAR Partners



# Replacing Wet Seals with Dry Seals in Centrifugal Compressors

Executive Summary

Centrifugal compressors are widely used in production and transmission of natural gas. Seals on the rotating shafts prevent the high-pressure natural gas from escaping the compressor casing. Traditionall y, these seals used highpressure oil as a barrier against escaping gas. Natural Gas STAR partners have found that replacing these “wet” (oil) seals with dry seals signific antly reduces operating costs
and methane emissions.

Methane emissions from wet seals typically range from 40 to 200 standard cubic feet per minute (scfm). Most of these emissions occur when the circulating oil is stripped of the gas it absorbs at the high-pre ssure seal face . Dry seals, which use high-pressure gas to seal the compressor, emit less natural gas (up to 6 scfm for a two seal system), have lower power requirements, improve compressor and pipeline operating efficiency and performance, enhance compressor reliability, and require significantly less
maintenance.

Although dry seal co nversions might not be possible on some compressors because of housing design or operational requirements, partners should select dry seals over wet seals whenever they replace or install centrifugal compressors where possible. A dry seal can save about $315,000 per year and pay for itself in as little as 11months. One Natural Gas STAR partner who installed a dry seal on an existing compressor, for example, reduced emissions by 97 percent, from 75 to 2 Mcf per day, saving almost $187,000 per year in gas alone. 

### Technology Background

Wet Seals

Centrifugal compressors require seals around the rotating shaft to prevent gases from escaping where the shaft exits the compressor casing. The more common “beam” type compressors have two seals, one on each end of the compressor, while “over-hung” co mpressors have a seal on only the“ inboard” (motor) side. As shown in Exhibit 1, these seals use oil, which is circulated under high pressure between three rings around th e compressor shaft, forming a barrier against the compressed gas leakage. The center ring is attached to the rotating shaft, while the two rings on each side are stationary in the seal housing, pressed against a thin film of oil flowing between the rings to both lubricate and act as a leak barrier. “O-ring” rubber seals prevent leakage around the stationary rings. Very little gas escapes through the oil ba rrier; considerably more gas is absorbed by the oil under the high pressures at the “inboard” (compressor side) seal oil/gas interface, thus contaminating the seal oil. Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated. The recovered methane is commonly vented to the atmosphere.

Dry Seals

An alternative to the traditional wet (oil) seal system is the mechanical dry seal system . This seal system does not use any circulating seal oil. Dry seals operate mechanically under the opposing force created by hydrodynamic grooves and static pressure.

Method for Reducing
Natural Gas Losses Volume of
Natural Gas Savings (Mcf) Value of Natural Gas Savings ($) Implementation Cost ($) Payback (Months)

$3 per Mcf $5 per Mcf $7 per Mcf $3 per
Mcf $5 per
Mcf $7 per
Mcf

Replacing wet oil seals with dry seals in centrifugal

compressors 45,120 a per
year $135,360

per year $225,600

per year $315,840

per year $324,000 b 29 18

General Assumptions:

a Based on the difference between typical vent rates of wet and dr y seals (i.e. 100 scfm versus 6 scfm) on a “beam” type compress or (2 seals) operating 8,000 hrs/yr.

b Based on replacement of a fully functioning wet seal with additional $102,400 in O&M cost reductions. 13 

### Economic and Environmental Benefits

1

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

Exhibit 1: Wet Seals

As shown in Exhibits 2a and 2b, hydrodynamic grooves are etched into the surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at high speed, co mpressed gas has only one pathway to leak down the shaft, and that is between the rotating and stationary rings. This gas is pumped between the rings by grooves in the rotating ring.

The opposing force of high-pressure gas pumped between the rings and springs trying to push the rings together creates a very thin gap between the rings through which little gas can leak. While the compressor is operating, the



### Exhibit 2a: Dry Seal rings are not in contact with each other, and therefore, do not wear or need lubrication. O-rings seal the stationary rings in the seal case.

Putting two or more of these dry seals together in series, as shown in Exhibit 2b, is called “tandem dry seals,” and is very effective in reducing gas leakage. This type of seal has less than one percent of the leakage of a wet seal system vented into the atmosphere and costs considerably less to
operate.



### Exhibit 2b: Dry Seal

2

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

Economic and Environmental Benefits

Dry gas seals substantially re duce methane emissions. At the same time, they significantly reduce operating costs and enhance compressor efficiency. Economic and environmental benefits of dry seals include:

 Gas Leak Rates . During normal operation, dry seals leak at a rate of 0.5 to 3 scfm across each seal (1 to 6 scfm for a two seal system), depending on the size of the seal and operating pressure. While this is equivalent to a wet seal’s leakage rate at the seal face, wet seals generate a dditional emissions during degassing of the circulating oil. Gas from the oil is usually vented to the atmosphere, bringing the total leakage rate for dual wet seals to between 40 and 200 scfm, depending on the si ze and pressure of the

compressor.

 Mechanically Simpler . Dry seals systems do not require elaborate oil circulation components and
treatment facilities.

 Reduced Power Consumption . Because dry seals have no accessory oil circ ulation pumps and systems, they avoid “parasitic” equipment power losses. Wet systems require 50 to 100 kW per hour, while dry seal systems need about 5 kW to power per hour.

 Improved Reliability . The highest percentage of downtime for a compressor using wet seals is due to seal system proble ms. Dry seals have fewer ancillary components, which translates to higher overall reliability and less compressor downtime.

 Lower Maintenance . Dry seal systems have lower
maintenance costs than wet seals because they do not have moving parts associated with oil circulation (e.g., pumps, control valves, relief valves).

 Elimination of Oil Leakage from Wet Seals

. Substituting dry seals for wet seals eliminates seal oil leakage into the pipeline, thus avoiding contamination of the gas and degradation of the pipeline.



### Decision Process

Partners usually face one of three situations when considering installation of dry seals: they are replacing an entire compressor; they are replacing a worn-out wet seal at an existing compressor; or they are replacing a fully functioning wet seal at an existing compressor. About 90 percent of all new compressors come with dry seals. When purchasing a new compressor, partners should be sure that it includes a dry seal.

The analysis for replacing a wet seal on an existing compressor should consider the methane emissions savings along with capital and operational costs and benefits. The economics for replacing operating wet seals are compelling, and wherever possible, partners should undertake such replacements. The decision process below is a guideline for determining candidates, benefi ts, and costs for replacing wet seals with dry se als in compressors.

Step 1: Identify candidates for wet seal replacement.

Operators should make a comprehensive inventory and
technical evaluation of their existing compressors. Factors to consider include compresso r type, age, hardware, and operating conditions. All wet seal compressors should be
indentified and evaluated for dry seals. When deciding which compressors are candidates for replacement of the wet seal, consider the following:

 Dry seals can be used for compressors up to 3,000 psi safely; applications of 1,500 psi are routine. Dry seals, however, migh t not be safe or higher pressures. Further, dry seals are not appropriate for applications with temperatures above 300 to 400 degrees Fahrenheit (due to O-ring material limitations) 1 . Some compressor de signs prohibit the retrofit of dry seals.

 Some older compressors might be at the end of their economic life and, thus, are candidates for complete replacement rather than a seal replacement. This is usually determined while planning a major over

haul, when operating and maintenance (O&M) costs for the old compressor are projected to increase to a level much greater than O&M costs for a new unit. Some clues that this stage might have been reached included sudden increases in the frequency and magnitude of unscheduled maintenance and the unavailability of replacement parts or lack of technical support.

Centrifugal compressors that meet the Step 1 criteria
should be evaluated further as follows.

Step 2: Estimate the savings of a dry seal retrofit.

In general, the majority of savings from replacing a wet seal with a dry seal are attributable to reductions in

3

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

Four Steps for Converting to Dry Seals:

1. Identify candidates fo r wet seal replacement.

2. Estimate the savings of a dry seal retrofit.
3. Determine the costs for conversion to dry seals.

4. Compare costs to savings.

methane gas loss. To estimate these savings, partners can measure the majority of methane loss from their wet seal compressors at the vent from the seal oil degassing unit by bagging or using a high flow sampler. Some gas also escapes at the seal face, but this is more difficult to
measure and amounts to less th an 10 percent of emissions from the seal oil degassing unit. Typical wet gas seal leakage ranges from 40 to 200 scfm for a beam type

compressor.

By comparison, expected losses from dry seals can be seen in Exhibit 3, a performance chart provided by a dry seal vendor. This chart shows an example of one type of tandem seal with leak rates ranging between 0.5 to 3 scfm for 1.5 to 10 inch compressor shafts, for compressors operating at 580 to 1,300 psig pressure. Replacing the wet seal with two tandem dry seals can reduce emissions between 34 to 194 scfm. This is equivalent to 16,320 to 93,120 Mcf per 8,000

- hour year, with total annual savings of $114,240 to $651,840.



### Exhibit 3: Dry Seal Performance Chart

This process is applicable to all compressor designs. The less common overhung compressors have a single seal, and The average methane content of na tural gas varies by natural gas industry sector. The Natural Gas STAR Program assumes the following methane content of natural gas when estimating methane savings for Partner Reported Opportunities.

Production 79 %

Processing 87 %

Transmission and Distribution 94 % 

### Methane Content of Natural Gas

switching from wet to dry seals would yield half the savings of doing the same fo r a beam type compressor.

Beyond gas savings, dry se als also yield significant operational and maintenance savings compared with wet
seals. Annual O&M costs fo r dry seals range widely, between $8,400 and $14,000 per year. Wet seal O&M costs can reach up to $140,000 per year. Detailed calculations of
the differences in O&M cost s between dry and wet seals are well documented (see Uptigrove et al., 1987). Exhibit 4
summarizes these estimates for a compressor with a7.5

- inch shaft diameter, operating 8,000 hours per year.



### Exhibit 4: Dry Seal Annual O&M Costs Savings per Compressor a

1. Reduced seal power losses = $19,500

2. Reduced oil pump/fan losses = $5,600

3. Increased pipeline fl ow efficiency = $37,300

4. Reduced oil losses = $4,900

5. Reduced O&M, downtime = $21,000

TOTAL SAVINGS = $88,300

a S.O. Uptigrove et al., adjusted to 2006 operating and maintenance

costs.

Site specific factors used in the calculations include: (1) wet and dry seal drag losses, (2) seal oil pump and cooling fan horsepower, (3) compresso r horsepower, (4) seal oil consumption, and (5) annual emergency and scheduled
maintenance costs.

Step 3: Determine the costs for conversion to dry
seals.

The cost for a dry seal syst em will depend on compressor operating pressure, shaft size , rotation speed, and other installation-specific factors. Costs for the seal typically range between $6,750 and $8,100 per inch of shaft diameter for wet seals and $10,800 to $13,500 per inch for

4

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

tandem dry seals. These costs will double for beam type compressors (t wo seals).

Other costs include engineering, installation and ancillary equipment. Dry seals require a gas console, filtration unit, controls, and monitoring instruments, while wet seals require the seal oil pumps, fan coolers, degassing unit, and controls. Depending on location, type of equipment, number of controls, and availability of components, costs range from $40,500 to $135,000 for dry seals, and up to $270,000 for wet seals. These ancillary facility costs are the same for both the single and dual seal compressor types.

Step 4: Compare costs to savings.

A simple cost comparison be tween converting a compressor to dry seals and replacing existing wet seals with new components will show substant ial savings over a five-year period. Exhibit 5 shows an example for a beam type compressor with a 6-inch shaft operating for 8,000 hours per year using the costs from Steps 2 and 3.

In this example, implementation costs for a conversion to dry seals include the cost of both the seals and the dry gas conditioning, monitoring, and control console. For wet seals, the seal oil circulation, degassing, and cooling ancillary facilities are reused, so only seal replacement
costs are incurred.



### Estimated Savings

Another way of illustrating the economics of this practice is through a five year cash flow table. This analysis



### Nelson Price Indexes

In order to account for in flation in equipment and operating & maintenance costs, Nelson-Farrar Quarterly Cost Indexes (avail able in the first issue of each quarter in the Oil and Gas Journal ) are used to update costs in the Lessons Learned documents.

The “Refinery Operation Index” is used to revise operating costs while the “Machinery: Oilfield Itemized Refining Cost Index” is used to update equipment

costs.

To use these indexes in the future, simply look up the most current Nelson-Farrar index number, divide by the February 2006 Nelson-Fa rrar index number, and, finally multiply by the appropriate costs in the Lessons
Learned. considers capital costs, me thane emissions savings, operating and maintenance co sts, and assigns a salvage value to the wet seal system. It is important to note that all analyses will be highly site-specific, but the economics of a dry seal retrofit are so attractive that companies should consider replacing all we t seals, regardless of age. Exhibit 6A presents the economics of replacing a fully
functional wet seal system with a dry seal system.

Exhibit 6B shows the economics for replacing an old wet seal nearing the end of its useful life: salvage value is zero and annual O&M costs for the wet seal system increase (in this example, to $140,000 pe r year). These two examples demonstrate that replacing a wet seal with a dry seal can be cost effective regardless of the age or condition of the wet seal system.

When assessing options for re placing wet seals with dry seals in centrifugal compre ssors, natural gas price may



### Exhibit 5: Cost Comparison for 6-Inch Shaft Beam Type Compressor Seal Replacement

Cost Category Dry Seal ($) Wet Seal ($)

Seal costs (2 dry @ $13,000/shaft-inch, w/ testing) 162,000

Seal costs (2 wet @ $6,750/shaft-inch) 81,000

Other costs (engineering, equipment in

stallation) 162,000 0 b

Total Implementation Costs 324,000 81,000

Annual O&M c 14,100 102,400

Annual methane emissions d (@$7.00/Mcf; 8,000 hrs/yr)

2 dry seals at a total of 6 scfm 20,160

2 wet seals at total 100 scfm 336,000

Total Costs Over 5-Year Period ($): 495,300 2,273,000

Total Dry Seal Savings Over 5 Years:

Savings ($) 1,777,700

Methane Emissions Reductions (Mcf) (at 45,120 Mcf/yr) 225,600 Implementation Costs a

a Flowserve Corporation, adjust ed to 2006 equipment costs.

b Re-use existing seal oil circulation, degassing, and control equipment.

c From Exhibit 4; assumes same O&M costs as 7.5-inch shaft.

d Based on typical vent rates.

5

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

influence the decision making process. Exhibit 7 shows an economic analysis of early replacement of wet seals in a centrifugal compressor with dr y seals at different natural gas prices.



### Lessons Learned

Partners can achieve sign ificant cost savings and emissions reductions by conver ting to dry seal technology. Partners offer the following lessons learned when changing to dry seals:  Dry seals are considered safer to operate than wet seals, because they eliminate the need for a high pressure oil system.

 To make the switch to dr y seals most efficiently,
schedule the conversion for a normal downtime period to avoid disrupting operations.

 When determining the benefits of a seal replacement, partners should take into account that properly installed and maintained dry seals can last more



### Exhibit 6A: Economics of Replacing a Fully Function al Wet Seal System with a New Dry Seal System

Costs and Savings ($) Year 0 Year 1 Year 2 Year 3

Dry seal capitol & installation costs (324,000)

Annual natural gas savings a 315,840 315,840 315,840

Dry seal annual O&M Costs (14,100) (14,100) (14,100)

Wet seal salvage value 20,000

NPV (Net Present Value) b = $1,228,009 IRR (Internal Rate of Return) = 131% Payback Period c = 10 months Retrofit of dry gas seals on a “beam” type compressor, 6-inch shaft, operating 8,000 hours per year, with fully functional wet seals.

Year 4

315,840

(14,100) Year 5

315,840

(14,100)

Avoided wet seal O&M Cost 102,400 102,400 102,400 102,400 102,400

Annual Totals (304,000) 404,140 404,140 404,140 404,140 404,140

a Annual savings represent the difference of natural gas loss between new dry seals and replac ed wet seals, at $7.00/Mcf. b NPV based on 10% discount over five years. C Payback period ranges between 3 and 12 months for wet seal leakage rates between 200 and 40
scfm.



### Exhibit 6B: Economics of Replacing an Aging We t Seal System with a New Dry Seal System

Costs and Savings ($) Year 0 Year 1 Year 2 Year 3

Dry seal capitol & installation costs (324,000)

Annual natural gas savings 315,840 315,840 315,840

Dry seal annual O&M Costs (14,100) (14,100) (14,100)

Wet seal salvage value 0

NPV (Net Present Value) = $1,350,542 IRR (Internal Rate of Return) = 134% Payback Period = 9 months Retrofit of dry gas seals on a “beam” type compressor, 6-inch shaft, operating 8,000 hours per year, with fully functional wet seals.

Year 4

315,840

(14,100) Year 5

315,840

(14,100)

Avoided wet seal O&M Cost 140,000 140,000 140,000 140,000 140,000

Annual Totals (324,000) 441,740 441,740 441,740 441,740 441,740

a Annual savings represent the difference of natural gas loss between new dry seals and replac ed wet seals, at $7.00/Mcf. b NPV based on 10% discount over five years.

6

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

than twice as long as wet seals.

 If the wet seal is near the end of its useful life, a straightforward cost analysis between new seal systems will favor the dry se al. Even if the existing wet seal has substantial remaining useful life, the operational characteristics of dry seals will provide significant savings and could justify yearly replacement.

 Given the clear economic advantages of dry seals, they should be installed wherever it is technically
feasible.

 Ninety percent of all new compressors now have dry gas seal systems. Dry seals should be the technology of choice for all new compressors.

 After replacing wet seals with dry seals, record emissions reductions in annual reports submitted as part of the Natural Gas STAR Program.



### References

American Society of Mechanical Engineers Gas Turbine Conference and
Exhibition. June 1987.

Canadian Association of Petroleum Producers. Options for Reducing Methane and VOC Emissions from Upstream Oil and Gas Operations. December 1993.

Henderson, Carolyn. U.S. EPA Na tural Gas STAR Program. Personal

contact.

Hesje, R.C. and R.A. Peterson. Mechanical Dry Seal Applied to Pipeline (Natural Gas) Centrifugal Compressors. American Society of Mechanical Engineering. Gas Turbine Conference and
Exhibition. June 1984.

Kennedy, J.L. Oil and Gas Pipeline Fundamentals, Second Edition.
PennWell Books. 1993.

Klosek, Marty. Flowserve Corporation. Bridgeport, New Jersey. Personal

contact.

Ronsky, N. Daryl; Harris, T.A.; Conquergood, C. Peter; and Davies, I. An Effective System for Sealing Toxic Gases in Centrifugal Compressors.

Sears, John. Personal contact.

Stahley, John. Dresser-Rand Company. Olean, New York. Personal

contact.

Tingley, Kevin. U.S. EPA Natural Gas STAR Program. Personal contact.

Uptigrove, S.O.; Harris, T.A.; and Holzner, D.O. Economic Justification of Magnetic Bearings and Mechanical Dry Seals for Centrifugal Compressors. American Society of Mechanical Engineers Gas Turbine Conference and Exhibition. June 1987.



### Exhibit 7: Gas Price Impact on Economic Analysis

Value of Gas Saved

Payback Period (Months)

Internal Rate of Re

turn (IRR)

NPV (i=10%) $3/Mcf $5/Mcf $7/Mcf $8/Mcf

$135,360 $225,600 $315,840 $360,960

17 12 10 9

68% 100% 131% 146%

$543,847 $885,928 $1,288,009 $1,399,049 $10/Mcf

$451,200

7

176%

$1,741,129

7

# Replacing Wet Seals with Dry Seals In Centrifugal Compressors
(Cont’d)

United States Environmental Protection Agency Air and Radiation (6202J) 1200 Pennsylvania Ave., NW Washington, DC 20460

October 2006

EPA provides the suggested methane em issions estimating methods contained in this do cument as a tool to develop basic methane e missions estimates only. As regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in t his document may not conform to the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations.

8