examples of armstrong service, inc

Examples of Armstrong Service, Inc.

Engineering Audit Reports

Prepared By: Armstrong Service Inc

8615 Commodity Circle, Suite 17 Orlando FL-32819

Ph: 407-370-3301 / Fax: 407-370-3399

Audit Report Example 2 of 15

Armstrong Service, Inc.

8615 Commodity Circle, Suite #17 Orlando, Florida 32819-9002 Ph: 407-370-3301 Fax: 407-370-3399

The goal of an Engineering Audit is to expand upon the Energy Conservation Measures (ECM’s) discovered during the Pre-Audit. The Engineering Audit report will include:

• Description or background of the issue • Diagrams, photos, and calculations • Recommendations or conceptual solutions • Savings +/-10% • Investment +/-40 (Optional)

The report will list any needed measurement procedures that provide appropriate system oversight to properly manage and evaluate on-going efficiencies. Electronic copies, in Portable Document Format (PDF), will be provided. The following are examples taken from ASI client Audits Example #1: ECM Reduce steam pressure to 175 psig Current System Description and Observed Deficiency The boilers generate saturated steam at 195 psig. Steam is distributed at this pressure and used with pressure reduction stations throughout the plant. Steam users, as identified during the site visit, do not require steam pressures higher than 150 psig. The roasters use steam between 87 psig and 145 psig, while the concentrators units use steam at 150 psig. Generating steam at lower pressure presents opportunities for fuel and steam savings. Proposed System Recommendation Based on the observed operating conditions and steam usage there is a potential to decrease the operating steam pressure from 195 psig to 175 psig. The different components of the steam system that will be affected by this project are:

• Boilers • HP distribution system and the pressure reducing valves (PRVs).

High pressure steam generation (boilers) and users are not the restricting factors in the system. The limiting items are the components related to the steam distribution system (pipes and pressure reducing/control valves). These items may need adjustments but are not expected to be replaced. The steam pressure should be decreased in maximum intervals of 5 psig. The steam system should be monitored for 24 hours (or more) to observe steam quality and capacity (PRV and piping).




Estimated Benefit The reduction in steam pressure and temperature has the following advantages:

• Reduced fuel consumption - total heat in steam at 195 psig is only 1.3 Btu/lb greater than the total heat in steam at 175 psig.

• Reduce the standby losses, radiation losses and losses associated with steam leaks in the pipes, joints, valves, and fittings. (These savings are not included in the total project savings)

• Reduce the losses associated with the continuous blow-down and flash steam. • Decrease scale formation and oxygen corrosion in the entire steam and condensate system. Scale

formation and oxygen corrosion rise dramatically with boiler pressure. (These savings are not included in the total project savings)

The implementation of this project will save $3,250 annually. The savings are calculated based on 2005 annual NG consumption and the respective calculated efficiencies. Savings of fuel Reducing the steam pressure will lead to a reduction in the fuel consumption by 428 MMBTU per year and will reduce the CO2 emissions by 23 metric tons annually.

Estimated investment and Payback The payback of this project should be immediate, and not require capital investments




Example #2: ECM Optimize Boiler Efficiency Current System Description and Observed Deficiency Currently the system has two 600 Hp boilers in operation. The lead boiler satisfies the process demand load (modulating between 190 and 200 psig) and the lag boiler is in hot standby. The standby boiler’s pressure is allowed to drop to 180 psig before firing. During start up of the roasters both boilers are fired to operating pressure to meet the large swings in the site’s steam demand. The lead and lag boilers are alternated every month. The facility has a combustion analysis/test performed every year. Based on last year’s combustion report, #1 boiler is not providing complete combustion. The amount of unburned fuel was higher than normal (best practices) and the efficiency was below 80%. The combustion efficiency of boiler #2 shows potential for improvement as well. The losses from incomplete combustion can be reduced and the overall boiler efficiency increased. Last years combustion test reports




Essentials of low excess air boiler operation Combustion is a chemical reaction in which a fuel constituent reacts with oxygen and releases energy as heat. As a result all fuels need oxygen and the best available oxygen source is air. However, air contains nitrogen which has no role in the combustion reaction, except to absorb a portion of the released heat. Every cubic foot of oxygen brings four cubic feet of nitrogen along with it. This unwanted nitrogen leaves the boiler stack as a part of the waste gases taking with it a portion of the heat released from the fuel. Therefore the quantity of unwanted nitrogen has to be kept at a minimum by controlling the excess oxygen level in stack gases. The optimum excess air level depends on the type of fuel and burner design. In general gas burners are designed to operate at 10% - 15% excess air (2% to 3% oxygen O2 in the exhaust flue gas). The recommended excess air level by the burner manufacturer already includes a safety margin. Any additional margin simply lowers the boiler efficiency. A periodic check of combustion conditions are needed to ensure optimum excess air levels, and to maintain heat generation efficiency.




Proposed System ASI recommends that the burners be tuned allowing the boilers to operated with lower excess air levels. After proper alignment of the burners, reducing the excess air level in the boilers can be achieved through the following steps:

1. Stabilize the boiler at given operating loads. Note: A minimum of three firing levels are required: low, medium and high.

2. Verify the present combustion conditions with a portable flue gas analyzer. The analyzer must be capable of measuring O2, minor combustibles, and CO in the stack gases.

3. Once the analyzer is in place determine the levels of the combustion gases. If minor combustibles and CO are not present, then (in small steps) adjust the fuel/air ratio to reduce the excess air supply.

4. Verify the combustion conditions again after 10 minutes of stable boiler operation. 5. If minor combustibles and CO are still not present, repeat steps 3 and 4 until the oxygen in stack

gas reaches the level recommended by the manufacturer. A combustion management system incorporating fuel air ratio control, lead/lag sequencing, continuous data acquisition, and remote control could be installed for more stable and consistent results. ASI does not recommend this system due to the high capital cost and long pay back period. Estimated Benefit Lowering the oxygen (excess air) in the boiler’s flue gas from the observed level down to 4% O2 will increase the boiler efficiency and will save and estimated $6,772 annually. The savings are calculated based on 2005 annual NG consumption and the respective calculated efficiencies.

Improving boilers combustion will lead to a reduction in the fuel consumption by 888 MMBTU per year and will reduce the CO2 emissions by 47 metric tons per year. Estimated Investment and Payback The investment to tune-up the boilers, procure a portable combustion efficiency analyzer, and train boiler house personnel in the analyzers use is estimated to be $11,000. The payback period for these investments would be less than two years.




Example #3: ECM Recover the heat rejected in the process air-fin cooler X-180 to preheat the incoming process stream Current System Description and Observed Deficiency Hot stream from diesel stripper W-38 is currently being cooled in X-169, X-287 and then in the air-fin cooler X-180. The actual temperatures at the inlet and outlet of X-180 are 521oF and 100oF. The air-fin cooler X-180 rejects significant amounts of useful heat to the atmosphere. It is possible to use this waste heat to preheat an incoming process stream (distillate from T-80) in the #2HDS plant. The distillate/naphtha (at 60oF) is pumped into #2HDS through pumps 201/ 202, mixed with the recycle gas stream and then preheated to over 500oF in a series of heat exchangers before it is sent to heater (H-10). This process stream could be a suitable heat sink (for the hot diesel) that is presently being rejected at X-180. This heat integration would result in energy savings and could marginally increase the furnace throughput of H-10. Currently the heater H-10 is firing natural gas to provide heating to the process stream. The heat recovery using the process stream from T-80 would reduce this gas usage in H-10 proportionally. Proposed System ASI recommends the installation of a shell & tube heat exchanger for heat integration/recovery purposes. The hot stream coming from X-287 would be routed to this new heat exchanger and return to X-180 after releasing some of its heat content. The naphtha stream from the discharge of pumps 201/202 (prior to mixing with the recycle stream) would pass through this new heat exchanger to pick up additional heat. This new heat exchanger could be located where heat exchangers X-425/426 (out of service) are presently located. This proposal would require a new heat exchanger & piping modifications. If sufficient static head is unavailable pump replacement may be required.

Proposed piping arrangement

CONDENSATE FRACTIONATION UNIT

Hot stream

NO. 2 HDS UNIT

576(dsg)

567(actual)

New HE

X-169 X-287 X-180

T-80

60deg FInlet Temp.

100oF

Inlet Temp.

227oF

Inlet Temp.

285oF

Inlet Temp.

439oF Recycle stream

inlet @ 118oF

Design @ 180oF

Cold stream as heat sink

W-38

Outlet Temp.

100oF

Outlet Temp.

521oF

Fired Heater H-10

Outlet Temp.

>900oF

X-5706 X-5707 X-397 X-396

Diesel Stripper

Distillate / Naptha storage




Calculations All savings estimate calculations presented in this report is based on these utility costs.

Hot Stream Hot Stream from Tower W-38 through the air-fin cooler X-180:

• Flow = 21,400 lbs/hr (design) • Tin = 521oF (CCB data) • Tout = 100oF (CCB data)

Calculate Cp from W-38 data sheet:

• Design heat duty = 3.555 MMBtu/hr • Design Tin = 415oF • Design Tout = 135oF • Design flow = 21,400 lbs/hr • Calculated Cp = 0.593 Btu/lboF • Calculated heat rejected in the X-180 = 5.345 MMBtu/hr

o (This is the available heat to be recovered)

Unit energy costs at Billings refinery

600# Steam cost $7.14 / mlbs with no return of condensate175# Steam cost $6.61 / mlbs with no return of condensate40# Steam cost $6.17 / mlbs with no return of condensate

Raw water $1.19 / mGalCooling water $0.06 / mGal

Electricity cost $0.04 $/kWhNatural gas $4.43 $/MMBtu

Condensate @ 220oF $1.10 / mlbsBFW @ 250oF $1.19 / mlbs

600# Steam cost $6.04 / mlbs with 100% condensate return 175# Steam cost $5.51 / mlbs with 100% condensate return 40# Steam cost $5.07 / mlbs with 100% condensate return 20# Steam cost $6.11 / mlbs with 100% condensate return 20# Steam cost $5.01 / mlbs with no return of condensate

Incremental heat cost from fuel $5.27 /MMBtu @ 84% Boiiler efficiencyHeat cost of condensate $0.84 /mlbs cost of cond heat only

Treated water cost $0.26 / mlbsCondensate @ 200oF $0.99 / mlbsCondensate @ 180oF $0.89 / mlbs




Cold Stream The discharge of T-80 will be used as the heat sink to recover heat from the discharge of the W-38 tower. Flow from T-80 = 295,600 lbs/hr (design) Heat rejected from Hot Stream = 5.345 MMBtu/hr Percentage of heat recovered from Hot Stream = 70% (est) Heat recovery = 3.742 MMBtu/hr Heat cost = $5.274/MMBtu Operating hours = 8000 hr/yr Savings = $157,861 Estimated Investment and Payback The estimated project cost for implementing this ECM is $269,000 with a simple payback of 1.7 years. Example #4: ECM Insulation for the superheated steam system Current System Description and Observed Deficiency The roasting processes attached to this system require superheated 87 psig steam. At 195 psig the steam saturation temperature is 386°F and contains a total heat of 1198 BTU/lb. At 87 psig the steam saturation temperature is 329°F and contains a total heat of 1187.5 BTU/lb. When steam pressure is reduced through a PRV the heat content of the steam does not change (Isenthalpic flow). This means the difference between the saturated steam heat content (1187 BTU/lb) and the additional heat available in the steam (10.5 BTU/lb) accounts for the 20°F of superheat found in the lower pressure system (195 psig vs. 87 psig). 87 psig saturated steam temperature is 329oF while the 87 psig superheated steam temperature is 349oF. All of the valves and separators in superheater system are not insulated. This lost heat must be compensated for by burning additional fuel in the boiler. This loss of heat must also be compensated for by the processes electrical superheaters.

Proposed System ASI recommends insulating all bare surfaces around the superheaters.




Estimated Benefit The implementation of this project will save $10,545 annually. The savings are calculated based on 2008 annual NG consumption and the respective calculated efficiencies. Savings of fuel and electricity Improving the insulation at the Debacs will lead to a reduction in the fuel consumption by 318 MMBTU per year, electrical consumption reduction of 76,260 kWh, and will reduce the CO2 emissions by 64 metric tons annually.

Estimated Investment and Payback The payback of this installation is expected to be less than one year. A more precise investment number will be calculated after the exact installation and scope of work are defined. Blommer’s management approval is needed to proceed with further design, collection of quotes from equipment manufacturers and installation contractors. Example #5: Replace 175-psig sour water stripping steam with 40-psig steam Background The sour water process uses steam for stripping as well as heating. In addition to the 175 psig steam used in the stripper re-boiler (X-4802), 175 psig steam is injected directly in to the sour water stripper (W-4801). Discussion The bottom temperature of the stripper is 246oF (data from CCB). The overhead temperature is 195oF. The saturated temperature of 40 psig steam is 297oF. Therefore, it is possible to utilize 40 psig steam in lieu of the 175 psig steam currently used in the stripper and re-boiler. In the re-boiler where the latent heat of steam is used for heating the use of 40 psig steam is more economical because of the lower cost of steam and the higher latent heat content. Proposals ASI proposes to replace 175 psig steam with 40 psig steam for both the sour water stripper (W-4801) and re-boiler (X-4802). The condensate return line from X-4802 will also be routed to the low-pressure condensate header.




The proposed piping arrangement is shown in the following sketch;

Estimated Benefits The estimated energy savings projected from implementing this project is $139,700 per year at current operating parameters. Calculations 1) Use of 40 psig vs. 175 psig steam in the stripping process (W-4801) Given:

• Bottom Temperature = 246oF • Overhead Temperature = 195oF • 175 psig steam to the Sour Water Stripper W4801 = 8145 lbs/hr (data per CCB) • Total heat of evaporation (hfg) at 175 psig = 847Btu/lb • Total heat of saturation (hf) at 40 psig = 912 Btu/lb

If 40 psig steam in used in W-4801:

• Steam usage at 40 psig = 7565 lbs/hr • 175 psig steam cost = $6.61/1000 lbs (0% condensate return) • 40 psig steam cost = $6.17/1000 lbs (0% condensate return) • Cost using 175 psig steam = $53.84/hr • Cost using 40 psig steam = $46.68/hr • Steam cost reduction = $7.16/hr • Annual operating hours = 8000hr/yr • Annual savings = $57,304

W 4801

X 4802

SOUR WATER STRIPPER

Stripping steam

Heating steam

Steam 175-psig

Steam 40-psig

Condensateto LP return line

To return line




2) Use of 40 psig vs. 175 psig steam in the stripping re-boiler (X-4802) Given:

• 175 psig steam to re-boiler (X4802) = 12,868/lbs/hr If 40 psig steam is used in the re-boiler:

• Steam usage at 40 psig = 11,952 lbs/hr • 175 psig steam cost = $5.51/1000 lbs (100% condensate return) • 40 psig steam cost = $5.07/1000 lbs (100% condensate return) • Cost using 175 psig steam = $70.90/hr • Cost using 40 psig steam = $60.59/hr • Steam cost reduction = $10.31/hr • Annual operating hours = 8000hr/yr • Annual savings = $82,468

Estimated investment The preliminary estimate of project cost to implement the above recommendations is $244,000 with a simple payback is 1.7 years.




Example #6: Modify the condensate header at the inlets of D-51&D-55 Background The condensate receivers (D-51 & D-55) have multiple inlets and each inlet has multiple streams of condensate. Condensate is either pumped or moved by its own pressure from six satellite receivers located at process units and tank farms. The existing condensate header that serves as the final connection point for all the condensate return is shown in the drawing below.

The two receiver tanks have 7 active condensate inlets in addition to the 20 psig steam and de-ionized (DI) water inlets. In addition to the multiple inlets at the receivers, one of the 6” lines feeding D-51 collects 5 additional condensate return lines within 50’ of the receiver. Two of these return lines have control valves to insure single-phase flow. Discussion The facility has experienced continuous growth over the past 12 years but the condensate system hasn’t grown proportionally. Due to the disproportionate growth of the utility system at the refinery the final condensate headers near receiver tanks D-51 and D-55 have become the bottle-neck in the steam and condensate system at the site. The multiple condensate return headers near the receivers are continuously exposed to bi-phase condensate. Except for the two return lines with control valves, all other lines collect condensate from 175 psig and 40 psig sources.

20-psig steam

20-psig steam vent

D-51 D-55

Cond. from D-3918

Cond. from D-9309

Cond. from D-82

D-280

To pumps P-239 /481

DI water from P-386, 387 & 388Flash steam vent

Cond. from Control room & Offices

(Cond. from X-4201 & X-352)

Cond. from D-25 & Other downstream connections

Cond. from C-14 jacket & D-129

Cond. from Boiler House area

Cond. from D-3701 & Tank farm

Cond. from Feed Prep & Butamer

4"

Cond. from FCC Barometric Condr.8"

Cond. from Tracer trees

6"

4"

6"

8"

Cond. from Combo

6"

Cond. from GRP

6"




Many 175 psig and 40 psig steam users are also returning condensate to these final receivers without flash separation. Mixing condensate streams of varying physical characteristics causes both abnormal backpressure and water hammer. Despite returning condensate from the six satellite flash tanks located throughout the refinery, large quantities of flash steam is generated at these final receivers D-51 & D-55. DI water is continuously added at quench vessel D-280 to reduce flash steam losses. Water hammer is frequently observed at the 6” return header to D-51 and in the D-3918 return line (after the control valve). Approximately 40% of the boiler feed water (condensate) is handled through the return headers near D-51 & D-55. A failure in the final condensate return headers could seriously affect the overall steam and utility systems at the facility. Proposals ASI recommends modifying the condensate inlet lines feeding D-51 & D-55 into two primary systems. These systems are made up of one pumped and one natural pressure (un-pumped) condensate headers. All pumped condensate lines will be routed to one of the existing 6" inlet lines with options to enter either one or both of the final receivers. All the un-pumped condensate should be routed to the existing D-82 flash tank. Flash separated liquid condensate from D-82 will be routed back to D-51 using an existing 8" inlet line.

Pumped Condensate Header

Condensate lines direct from steam traps

20-psig steam

20-psig steam vent

D-51 D-55

D-280

To pumps P-239 /481

DI water from P-386, 387 & 388

Flash steam vent

4"

8"

6"

6" 4"

6"

Condensate from D-3918

Condensate from #4-HDS (D-9309)

Condensate from D-3701 (pump)

Condensate from D-25 (new dedicated line)

Condensate from new RPT at T-107

Condensate from new RPT at T-88 Condensate from D-129 (pump)

Condensate connections in old D-25 line

Condensate from Combo unit (4")

Condensate from Control room & OfficesCondensate from GRP

Condensate from X-4201 & X-352Cond. from Boiler House area

D-82

To 40-psig steam header

6"

8"

Cond. from FCC Barometric Condr.

Cond. from Tracer trees (4")

6"




Process Design 1. Design Basis Most of the condensate return lines do not have flow measurement devices. However, the proposed modifications could incorporate flow measurement installed in the existing header connections at the receivers. 2. Capacity/Design Considerations The proposed modification will eliminate bi-phase flow in the large lines and prevent backpressure and water hammer problems in condensate headers. The present problems are not capacity issues so changes to line or tanks sizes will not be necessary. However, pumped condensate improvements will provide an increase in condensate return which at present is being drained to sewer. 3. Process Flow Diagrams A new condensate system drawing will be prepared upon review and approval of the CPB engineering personnel, prior to beginning Detailed Engineering Design. 4. Integration with Other Process Units Since most of the condensate return lines merge at the single return header or to the inlet lines to D-51 and D-55, integration with other process units is expected to be minimal. However, there could be some challenging tie-in connections at the boiler house which would require a process unit shutdown or hot-tap connection. 5. Control of Performance No changes are expected in the existing condensate handling operation and/or controls. 6. Utility and Chemical Requirements No utility or chemical requirements envisioned due to the proposed condensate return header modifications 7. Equipment & Instrument Data Sheets New equipment is not being proposed. Additional piping will be added to the existing systems. Estimated Benefits This modification will not provide any direct steam or cost savings however, theses changes are essential for the system to maintain integrity and reliability. In addition, the condensate header modifications proposed for D-51 and D-55 will facilitate future growth at the facility. Estimated investment The estimated investment to implement the above recommendations is $168,000.

examples of armstrong service, inc

Documents