1111 Nineteenth Street, NW, Suite 800 ▪ Washington, DC 20036 ▪ 202 463-2700 Fax: 202 463-2785 ▪ www.afandpa.org 

 July 27, 2012 

Ms. Gina McCarthy 

Assistant Administrator for Air & Radiation 

United States Environmental Protection Agency 

Ariel Rios Building 

1200 Pennsylvania Avenue, N.W. 

Washington, DC 20460 

RE: Docket ID No. EPA–HQ–OAR–2007-0544, National Emission 

Standards for Hazardous Air Pollutants From the Pulp and Paper Industry 

(76 Federal Register 81328, December 27, 2011) 

Dear Assistant Administrator McCarthy, 

The American Forest & Paper Association (“AF&PA”) appreciates the opportunity to 

submit supplemental comments on the Proposed National Emission Standards for 

Hazardous Air Pollutants From the Pulp and Paper Industry (76 Fed. Reg. 81,328, 

December 27, 2011) (the “Proposed Rule”). These comments provide additional 

information in response to EPA statements and requests for comments in the 

preamble to the Proposed Rule concerning the provisions of the existing Pulp and 

Paper MACT standards, 40 C.F.R. Part 63 Subpart S, related to excess emission 

allowances for periods of venting of non-condensible gases (NCGs) and steam 

stripper downtime, and related provisions for equipment startup, shutdown, and 

malfunction. See 76 Fed. Reg. at 81,346. 

These comments supplement comments AF&PA filed on the Proposed Rule on 

February 27, 2012 (the “AF&PA RTR Comments”). The Proposed Rule raised 

issues about the excess emission allowance provisions that had not been discussed 

with EPA during the development of the Proposed Rule and asked numerous 

questions about industry practices that called for the collection of additional 

information. In your February 22, 2012 letter to me, EPA agreed to consider 

information regarding excess emission allowances, including the results of a survey 

to be conducted by the National Council for Air and Stream Improvement, Inc. 

(NCASI) and “any other relevant information” received by June 27, 2012, in deciding 

how EPA should proceed with the excess emission allowance provisions. 

These comments submit the results of that NCASI survey, which was developed 

with input from EPA’s Office of Air Quality Planning and Standards, in the attached 

NCASI report, “The Collection and Transport of Noncondensible Gases (NCG) in 
Assistant Administrator McCarthy 

June 27, 2012 

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NCG Systems at Pulp and Paper Mills.” The NCASI Report also provides important 

explanatory information about the production process and pollution control 

operations at pulp mills that is critical for an understanding of why the existing 

Subpart S standards are written the way they are and of the implications of any 

changes EPA might make to those standards. The following discussion further 

explains some of the key implications of the NCASI Report and presents AF&PA’s 

position on what actions EPA is authorized to and should take with respect to the 

Subpart S standards. 

AF&PA believes that the information and arguments supplied here strongly support 

the conclusion that the excess emission allowances and related provisions of the 

current Subpart S regulations were consistent with the Clean Air Act and with the 

performance of best-performing mills representing the "MACT floor" when they were 

promulgated, and that they continue to be so today. We want to emphasize that the 

OAQPS staff, none of whom were involved in the development of the existing 

Subpart S regulations, have made a great effort to understand the complexity of 

chemical pulp mill operations and of the various compliance options the regulations 

currently provide and the reasons for those options. After your staff have 

considered the information submitted here, AF&PA is ready and willing to continue 

our dialogue and attempt to further EPA's understanding of the regulated facilities. 

Background

The National Emission Standards for Hazardous Air Pollutants for the Pulp and 

Paper Industry, 40 C.F.R. Part 63 Subpart S, require that various processes in the 

pulp mill be enclosed and vented into a closed-vent system and routed to a control 

device. The regulations provide that periods of excess emissions must be reported 

but will not be considered a violation if, for each semi-annual reporting period, the 

time of excess emissions (excluding periods of startup, shutdown, or malfunction) 

divided by the total process operating time does not exceed 1% for control devices 

used to reduce emissions from the low volume, high concentration system and 4% 

for control devices used to reduce emissions from the high volume, low 

concentration system (or used for both LVHC and HVLC systems). 40 C.F.R. § 

63.443(e). For control devices used to treat pulping process condensates 

(wastewaters) from specified pulp mill processes, the excess emission allowance 

(including periods of startup, shutdown, or malfunction) is 10%. 40 C.F.R. § 

63.446(g). In addition to continuous monitoring of the control devices, the 

regulations require indicators on closed-vent system bypass lines, periodic 

inspections for leaks, procedures for prompt repair of defects in the enclosures or 

piping, inspection and maintenance recordkeeping, and so forth. 

As explained in the AF&PA RTR Comments, the excess emission allowance 

provisions in the current Subpart S regulations reflect EPA’s careful determination, 

after years of study of a large quantity of emissions information and public 

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comments, that the “MACT floor,” representing the emissions of the “best 

performers,” includes emissions during unavoidable periods of releases of 

uncontrolled or partially controlled pulping process vent gases and unavoidable 

sewering of untreated or partially treated pulping process condensates. See 63 Fed. 

Reg. 18,504, 18,529 (April 15, 1998). “EPA established appropriate excess 

emission allowances to approximate the level of backup control that exists at the 

best-performing mills and the associated period of time during which no control 

device is available.” Id. After “an analysis of the public comments and the available 

data regarding excess emissions and the level of backup control in the industry,” 

EPA determined that the “best-performing mills achieve a one percent downtime in 

their LVHC system control devices” and “best-performing mills achieve a four 

percent downtime in the control devices used to reduce emissions from their HVLC 

system to account for flow balancing problems and unpredictable pressure changes 

inherent in HVLC control systems.” Id. “The allowances address normal operating 

variations in the LVHC and HVLC system control devices for which the equipment is 

designed. The variations would not be considered startup, shutdown, or malfunction 

under the Part 63 General Provisions....” 63 Fed. Reg. at 18,530 (emphasis added). 

The 10 percent excess emission allowance for steam strippers systems “accounts 

for stripper tray damage or plugging, efficiency losses in the stripper due to 

contamination of condensate with fiber or black liquor, steam supply downtime, and 

combustion control device downtime.” Id. 

EPA adopted the excess emission allowances after reviewing extensive data from 

continuous monitoring systems and considering industry comments that although 

some mills had backup combustion devices as part of their LVHC control system, 

venting of pulping gases is an essential safety practice (because of their explosion 

hazard) even for those systems with backup control devices, since the startup of, 

and transfer of vent gases to, the backup controls cannot be immediate or automatic 

for safety reasons, and operating variability in the control devices themselves was 

unavoidable for process and other reasons. See, e.g., Pulp, Paper and Paperboard 

Industry – Background Information for Promulgated Air Emission Standards – Final 

EIS, EPA-453/R-93-050b (October 1997) (“BID”) at 4-81, 4-82 to 4-84. For HVLC 

systems, few mills had backup controls that could handle the large volume of vent 

gases, so any standard that required the use of backup devices would have been 

beyond the MACT floor and would not have been cost-effective due to the low 

concentration of pollutants in the large gas stream. See 63 Fed. Reg. at 18,529; BID 

at 4-81 to 4-82. See also BID at p. 1-41 (“EPA established excess emission 

allowances to approximate the level of downtime and number of backup control 

devices that exist at the best-performing mills. The Excess emissions allowances 

are designed to account for periods when the control device is inoperable and when 

the operating parameter values established during the initial performance test 

cannot be maintained due to problems with the process.”). 

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In short, the MACT determinations that EPA made when promulgating the Subpart S 

emission standards correctly concluded that available technology involves 

unavoidable periods where not all vent gases or condensates can be routed to the 

control device, and/or when the control device is inoperable or necessarily operating 

at a reduced rate. The Subpart S emission standards (including the excess 

emission allowances) were designed to reflect the performance of the MACT 

technology and the actual performance of the “best performing” mills. Without the 

excess emission allowances, the remainder of the Subpart S emissions standards 

would have imposed limitations not achieved even by the “best performers” and not 

demonstrated as achievable at any facility. The NCASI Report submitted with these 

comments reinforces those conclusions. 

The Proposed Rule

In the December 27, 2011 Proposed Rule, EPA proposed a significant change to the 

excess emission allowance provisions of the Subpart S standards: EPA proposed to 

remove the parenthetical clause in 40 C.F.R. § 63.443(e), “(excluding periods of 

startup, shutdown, or malfunction).” The effect of this proposed change would be to 

make the excess emission allowance provisions of the Subpart S standards for NCG 

systems significantly more stringent, because not only would normal operating 

variations in the LVHC and HVLC system leading to excess emissions have to fall 

below 1 percent or 4 percent, respectively, of the operating hours, but in addition 

periods of startup, shutdown, and malfunction (which were not intended to be 

addressed by the excess emission allowance provisions, see 63 Fed. Reg. at 

18,530, quoted above) would have to be less than those percentages, as well. 

EPA stated, in the preamble to the Proposed Rule: “In proposing the standards in 

this rule, the EPA has taken into account startup and shutdown periods and is not 

proposing a different standard for those periods. Nothing in the record suggests 

that the operations (and attendant emissions) are significantly different during 

startup or shutdown than during normal operation. Periods of startup, normal 

operations and shutdown are all predictable and routine aspects of a source’s 

operations. However, by contrast, malfunction is defined as a “sudden, infrequent, 

and not reasonably preventable failure of air pollution control and monitoring 

equipment, process equipment or a process to operate in a normal or usual 

manner * * *” (40 CFR 63.2). The EPA has determined that CAA section 112 

does not require that emissions that occur during periods of malfunction be 

factored into development of CAA section 112 standards.” 77 Fed. Reg. at 81,346. 

In addition, in the preamble to the Proposed Rule EPA indicated that it was 

considering changing or removing the excess emission allowance provisions of the 

Subpart S rule more generally: “We request comment on whether these provisions 

should be removed or modified in the final rule, as the provisions create time periods 

during which a source does not have to comply with a CAA section 112-compliant 

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standard, which we believe is arguably at odds with [Sierra Club v. EPA, 551 F.3d 

1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (2010)].” 76 Fed. Reg. at 

81,346. EPA explained that the excess emission provisions for LVHC, HVLC, and 

steam stripper systems were intended to reflect the performance of best-performing 

mills [and therefore reflective of the “MACT floor”], but EPA did not offer any 

explanation of how it could remove those excess emission provisions without 

violating Clean Air Act requirements that EPA must either base MACT standards on 

the performance of the best-performing mills or justify beyond-the-floor standards. 

See id. EPA sought considerable information about how the excess emission 

allowances in the existing Subpart S. standards are used, how facilities distinguish 

between routine venting and malfunctions, etc. Id. These comments and the 

attached NCASI Report attempt to respond to those questions. See NCASI Report 

– discussion in item # 3, p.23. 

EPA Lacks Authority To Change the Excess Allowance Provisions

As a threshold matter, AF&PA wishes to reiterate its position, expressed in the 

AF&PA RTR Comments, that the Clean Air Act does not authorize EPA to revise the 

excess emission allowance provisions, either by eliminating those provisions or 

adding additional conditions to them, as EPA has indicated it is contemplating, or by 

removing the exclusion for SSM periods and thereby forcing mills to use the 1% and 

4% venting allowances for SSM periods as well as for routine operating events that 

trigger intermittent NCG venting, as EPA has proposed. 

The Proposed Rule generally reflects EPA’s efforts to consider whether additional 

emission limitations are necessary to address residual risk, under CAA section 

112(f), and whether changes to the MACT standards are “necessary” in light of 

“developments in practices, processes, and control technologies,” under CAA 

section 112(d)(6). EPA has determined that the minimal residual risk after 

implementation of the MACT standards does not justify additional requirements 

under section 112(f). With respect to the technology review under section 112(d)(6), 

nothing has changed about the technology available to control volatile HAP 

emissions at pulp mills that eliminates the unavoidable excess emission the events 

that EPA accurately described and addressed when promulgating the current MACT 

standards—a fact confirmed by the NCASI Report. Absent such new technology, 

there is no statutory predicate for EPA to go back and change the MACT standards 

at this time. Cf. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008) (rejecting 

contention that CAA section 112(d)(6) requires EPA to “start from scratch” and 

develop new MACT standards). To the contrary, Congress (1) did not provide for 

periodic review and revision of MACT standards (other than the 8-year technology 

review under CAA section 112(d)(6)), as it has for many other types of standards 

under the Clean Air Act and other environmental statutes, and (2) made the MACT 

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standards subject to a strict 60-day deadline for seeking judicial review, under CAA 

section 307(b), so that sources would have certainty about what standards they 

face. 

Note that, even if the Clean Air Act allowed EPA to second-guess and revise the 

existing MACT standards, EPA has no technical basis for eliminating the Subpart S 

excess emission allowances. An agency cannot simply change its mind and reach a 

diametrically opposed conclusion from the determination it made in a prior 

rulemaking. Rather, EPA must demonstrate sufficient basis for changing its prior 

conclusions; in this case, technical justification for concluding that mills with MACT 

do not experience the unavoidable variability accommodated by the excess emission 

allowance. See, e.g., FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009) (“a 

reasoned explanation is needed for disregarding facts and circumstances that 

underlay...the prior policy”); Transactive Corp. v. United States, 91 F.3d 232, 237 

(D.C. Cir. 1996). 

In the case of standards under CAA section 112(d), EPA not only would have to 

have a substantial technical basis for reversing its conclusions reflected in the 

current Subpart S standards, it also would have to demonstrate that the revised 

standards would reflect the MACT “floor” or are justified as “beyond-be-floor” 

requirements. As AF&PA’s RTR Comments showed, EPA has not made any effort 

to show that the elimination of the SSM portion of the NCG venting allowances in 40 

C.F.R. § 63.443(e) would be consistent with the performance of the best-performing 

mills that characterized the MACT floor when the Subpart S standards were 

promulgated (or the current best-performers, for that matter). Nor has EPA 

assessed elimination of the SSM provision as a beyond-the-floor technology. 

The same would be true of eliminating or narrowing the excess emission allowances 

for NCG systems and steam strippers. Before EPA could propose such a change to 

the Subpart S. standards, EPA would have to show how emission limitations that did 

not include those excess emission allowances reflect the MACT floor (despite EPA’s 

conclusion in 1998 to the contrary) or are justified as a beyond-the-floor requirement. 

The Excess Emission Allowances Have a Firm Basis in Fact and Law

In the preamble to the Proposed Rule, EPA stated that the existing Subpart S 

excess emission “provisions create time periods during which a source does not 

have to comply with a CAA section 112-compliant standard, which we believe is 

arguably at odds with Sierra Club.” 76 Fed. Reg. at 81,346. That is simply wrong, 

on several levels. 

First, the Sierra Club decision interpreted the NESHAPs General Provisions, not the 

Subpart S NESHAPs or indeed any categorical NESHAPs. Secondly, the decision 

addressed an exemption for startups, shutdowns, and malfunctions, while the 

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Subpart S excess emission provisions for pulping vent gases specifically does not 

address excess emissions during startup, shutdown, and malfunction (see 40 C.F.R. 

§ 63.443(e)). 

Thirdly, the Sierra Club decision rejected the General Provisions’ blanket, openended exemption for emissions during startup, shutdown, and malfunction periods, 

finding it to be inconsistent with Congress’s intention that “there must be continuous 

section 112-compliant standards” for sources subject to MACT standards, rather 

than periods where no standard of any kind applies. See 551 F.3d at 1027. The 

problem with the General Provisions SSM exemption, in the Court’s eyes, was that it 

allowed sources to be exempt from any standard at all, and that it was not derived 

(by EPA’s admission) applying the factors in CAA section 112(d) or 112(h). See id. 

at 1027-28, 1030. The Sierra Club opinion did not address a situation, such as the 

Subpart S standards, where EPA finds that the MACT standard, which applies 

continuously, must account for periods of higher emissions during unavoidable 

operational variability to accurately reflect the available technology and the best 

performers’ emissions. In fact, the Sierra Club decision explicitly acknowledged that 

it may be appropriate for MACT standards to have different limitations for different 

situations. See 551 F.3d at 1021; id. at 1027 (standard may “’assure continuous 

emission reduction’ without necessarily continuously applying a single standard”). 

The excess emission allowances in the existing Subpart S rule are no different 

conceptually than other emission standards EPA has established for scores of 

sources that are expressed as an average calculated over a day, a month, or 

longer.1

 MACT standards that require a source to meet a particular emission rate 

measured as, e.g., a 30-day average do not require that the source emit at any 

specific rate during each hour of operation, so long as the 30-day average is below 

the limit. EPA effectively recognized this in the preamble to the Proposed Rule, 

asking whether the events currently covered by the excess emissions allowances in 

the Subpart S rule can be addressed through an emission standard with a longer 

averaging time. See 76 Fed. Reg. at 81,346. Such emission limitations expressed 

as averages, about which there can be no reasonable question as to their validity 

under CAA section 112, are no more (or less) compliant with the D.C. Circuit’s 

 

1

 Many MACT standards, including “all past part 63 NESHAPs affecting the chemical and 

refining sectors,” use daily averaging periods (see 77 Fed. Reg. 17,898, 17,963 (March 26, 

2012), and it is not uncommon for MACT standards to allow averaging over a month or a 

year. See, e.g., 40 C.F.R. §§ 63.491(c), 63.3522 (MACT standards for Surface Coating of 

Metal Cans requires demonstration of compliance with limit on HAP content of coatings, or 

emission rate if using control equipment, as a rolling 12-month average determined on a 

monthly basis); 40 C.F.R. § 63.2840 (MACT standards for Vegetable Oil Production require 

facilities to meet limit on gallons of HAP lost per ton of oilseeds processed, expressed as 

ratio of actual gallons lost during previous 12 months to allowable); 68 Fed. Reg. 19375, 

19378 (Apr. 21, 2003) (Reinforced Plastic Composites Production) (compliance based on 

weighted HAP emission factor based on a 12-month rolling average calculated monthly). 

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interpretation that MACT standards must meet a section 112-compliant standard at 

all times than are the Subpart S standards, which require that, e.g., LVHC systems 

stay within the specified limits at least 99% of the time for each six-month period.2

To put it another way, If one assumes that six months equals 180 days or 4320 

hours, the 1% excess emission allowance the existing Subpart S standards provide 

for LVHC systems means that a mill would be allowed, at most, to exceed the 

emission limitations for LVHC systems a little over 43 hours in a six-month period. 

Even if the mill's LVHC NCG emissions were not controlled at all during those 43 

hours, and even if the mill's LVHC system were emitting just at the Subpart S 

emission limitation of 98% volatile HAP reduction for the remaining 4277 hours, that 

would still be equivalent to an average 97% reduction of volatile HAPs during the 

six-month period. Since EPA has issued many MACT standards that allow 

averaging over a day, a month, or more, EPA has no basis for claiming there is 

something inconsistent with the Clean Air Act about the excess emissions 

allowances in the Subpart S standards, which are functionally equivalent to, e.g., a 

97% reduction standard for LVHC gases, expressed as a six-month average.3 In 

fact, EPA has specifically used averaging times to accommodate process variability, 

as it did with the excess emission allowances in the Subpart S rule, in other MACT 

rulemakings.4

Without the excess emission provisions, the Subpart S standards would not comply 

with CAA section 112. Section 112(d) standards based upon the performance of the 

best-performing facilities are supposed to represent "the emissions control that is 

achieved in practice" by the best performers, which means that the best-performing 

mills would not violate the standards, which “only results if ‘achieved in practice’ is 

 

2

 EPA has promulgated numerous other MACT standards that are even more directly 

comparable to the excess emission allowances in Subpart S, in that they allow a source to 

exceed the numerical limit with a certain frequency. See, e.g., NESHAPs for Catalytic 

Cracking Units at Petroleum Refineries, 40 C.F. R. pt. 63 subpt. UUU Table 6 (sources 

subject to NSPS must “maintain[] each 6-minute average [opacity] at or below 30 percent 

except that one 6-minute average during a 1-hour period can exceed 30 percent”)—

effectively a 10% excess emission allowance. 

3

 EPA also has issued many New Source Performance Standards under CAA § 111 that are 

expressed in terms of long averaging times, and which rely on the same definition of 

“emission limitation” that the Sierra Club court relied on in striking down the NESHAP 

General Provisions. See, e.g., 40 C.F.R. § 60.72a (emission limit for Nitric Acid Plants 

expressed “as a 30-day emission rate calculated based on 30 consecutive operating days”) 

77 Fed. Reg. ___ (signed May 14, 2012). 

4

 See, e.g., 66 Fed. Reg. 44217, 44225 (Aug. 22, 2001) (Boat Manufacturing) (“one of our 

objectives was to provide flexibility to use some higher HAP materials by adopting the 

averaging provisions and using weighted-average HAP contents in setting the MACT for 

each operation.”); 65 Fed. Reg. 15,690, 15,699 (March 23, 2000) (Secondary Aluminum) (3-

day, 24-hour rolling average selected to accommodate variations in cycle times and 

schedules). 

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interpreted to mean ‘achieved under the worst foreseeable circumstances.’” Sierra 

Club v. EPA, 167 F.3d 658, 665 (D.C. Cir. 1999). The courts (and EPA) have 

recognized that there is variability in the performance of control technologies, which 

needs to be accounted for in establishing emission limitations based on the MACT 

floor. See, e.g., Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855, 862-865 

(D.C.Cir.2001). As the record (including, now, the NCASI Report) reflects, it is 

certainly foreseeable that even the best performers would experience violations of 

the MACT standards, due to process variability and control technology limitations, 

without an excess emission allowance. 

It should be emphasized that the excess emission allowances in the current Subpart 

S standards do not result in periods where emissions from NCG and condensate 

streams are subject to no restrictions at all. Obviously, a mill could only tolerate a 

small amount of equipment downtime or unavoidable venting and still stay under the 

percentage allowances. The Subpart S regulations contain numerous obligations 

that continue to apply irrespective of the excess emission allowances, e.g., 

indicators on closed-vent system bypass lines, periodic inspections for leaks, 

procedures for prompt repair of defects in the enclosures or piping, inspection and 

maintenance recordkeeping, and so forth. In addition, the mill’s operation remains 

subject to the “general duty” in 40 C.F.R. § 63.6(e) to operate and maintain the 

affected sources, and associated air pollution control and monitoring equipment, 

consistent with safety and good air pollution control practices for minimizing 

emissions. Similar requirements apply under the laws and regulations of many 

states, and the mill may also be subject to state emission limitations, or limitations 

under NSPS or other applicable regulations, that restrict emissions from the mill. 

(See, e.g., reference to the State of Maine’s TRS control regulations in the NCASI 

Report at p.30) Moreover, since the NCG and condensate systems have the 

potential for causing releases of objectionable odor to the community, as well as 

potentially harmful worker exposures, kraft pulp mills must continually strive for 

reducing emissions from those streams. The potential for triggering releases of 

reportable quantities under the Emergency Planning and Community Right-to-Know 

Act provides yet another restraint on venting. The venting events described in the 

NCASI Report therefore represent the minimal emissions that are unavoidable using 

best practices, and subject to the restraints not only of the Subpart S standards but 

also numerous other requirements or incentives for the mills to minimize emissions. 

Finally, even if the current Subpart S standards were inconsistent with the Sierra 

Club decision, which the discussion above shows they clearly are not, that fact alone 

would not allow EPA to change the excess emission allowance provisions in the 

Subpart S rule. The Subpart S NESHAPs were never judicially challenged, and the 

time for such a challenge under CAA section 307(b) has long passed. Even if the 

rationale that the D.C. Circuit used in overturning a different regulation in one of the 

many cases challenging other NESHAPs is arguably inconsistent with the approach 

EPA took in promulgating the Subpart S NESHAPs, that would not provide a means 

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or a justification for reopening the Subpart S standards that were never challenged 

on that grounds. See id. and, e.g., Sierra Club v. EPA, 353 F. 3d at 986 (MACT 

standards must be judged on the adequacy of EPA’s explanation in the particular 

rulemaking, not on what EPA did based on a different record in a different 

rulemaking). 

In short, the excess emission allowance provisions of the existing Subpart S 

standards not only are permissible under the Clean Air Act, they are necessary. The 

MACT floor performance includes unavoidable periods when mill operations 

preclude compliance with the limitations EPA established for steady-state 

operations, and so to reflect that performance the MACT standards need to 

accommodate those periods. EPA already has assessed—as past court decisions, 

including even the recent Sierra Club decision, have indicated it must—whether 

different emission limitations need to apply to those periods of operational variability 

and has addressed that need through the excess emission allowances in existing 

sections 63.443(e) and 63.446(g). No further EPA action is necessary. 

The Excess Emission Allowances Are Not Unauthorized Exemptions for 

Malfunctions

In recent discussions with EPA OAQPS staff, EPA’s default position seems to be 

that, with the possible exception of startup and shutdown periods, any venting of 

NCGs or sewering of condensates under the excess emission allowance provisions 

of the existing Subpart S standards is the result of a “malfunction,” and therefore 

cannot be allowed by MACT standards. This is wrong on several levels. First, it is 

directly contrary to EPA’s analysis of the facts in support of the current MACT 

standards, in which EPA stated: “The allowances address normal operating 

variations in the LVHC and HVLC system control devices for which the equipment is 

designed. The variations would not be considered startup, shutdown, or malfunction 

under the Part 63 General Provisions....” 63 Fed. Reg. at 18,530. From everything 

AF&PA is aware of, EPA’s current, diametrically opposite conclusion is not based on 

any new analysis of data, making it necessarily arbitrary and capricious. 

Secondly, both AF&PA’s RTR Comments and the NCASI Report submitted with 

these comments explain, with real-world examples, why the excess emission 

allowances are necessary to reflect actual performance of even the best-performing 

mills, because of unavoidable fluctuations in the production processes and the NCG 

and condensate collection and treatment systems. See AF&PA RTR Comments at 

pp.53 - 57; NCASI Report at pp.15 - 20. EPA has not presented, and could not 

present, any factual basis to the contrary. 

An easy-to-understand example is availability of a thermal destruction device used 

to comply with the emission standards for NCGs (and for off-gases from steam 

strippers used to treat condensates). In the original Subpart S rulemaking, EPA 

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recognized that most mills did not have backup equipment for incinerating HVLC gas 

streams, and even if backup equipment was available for treating LVHC gas 

streams, there would be a period of uncontrolled emissions when switching to a 

backup thermal destruction device. The primary thermal destruction device might be 

unavailable for a number of reasons that have nothing to do with malfunctions, such 

as routine maintenance, the temporary loss of NCG burning permissives even 

though the device itself is operational, or, if a piece of process equipment is used as 

the primary thermal destruction device, because the associated process is not 

operating or is starting up or shutting down. Similarly, a steam stripper will, over 

time, have to be taken offline because of the temporary unavailability of the thermal 

destruction device, as described above, or to remediate ordinary clogging of the 

stripper trays (during which time the condensates typically are routed to the mill’s 

wastewater treatment system, see NCASI Report at p.29). Even the bestperforming mills do not have redundant stream strippers to avoid these periods 

when the stripper has to be offline. 

These periods are not periods of malfunction, as defined in 40 C.F.R. § 63.2, 

because they are not “infrequent,” they do not represent a “failure” of equipment “to 

operate in a normal or usual manner,” and they are not “reasonably preventable.” 

As recently as this March, EPA has reiterated that it is appropriate, in comparable 

situations, to establish alternative MACT standards, rather than claiming, as the 

preamble to the Proposed Rule implied, that such situations cannot be 

accommodated by MACT standards and must not only be considered malfunctions 

but also be treated as violations.5

 The NCASI Report presents numerous examples, 

in addition to and further explaining the examples in the AF&PA RTR Comments, 

about why the NCG or condensate collection and treatment systems at a pulp mill 

may not be able to meet the Subpart S emission limits and performance standards 

due to routine events that are part of expected process and pollution control 

variability and for which the system is designed. See, e.g., NCASI Report at pp. 15 - 

20. 

EPA’s position in the original Subpart S rulemaking that the excess emission 

allowances are necessary “to address normal operating variations in the LVHC and 

HVLC system control devices for which the equipment is designed” and would not 

be considered malfunctions, 63 Fed. Reg. at 18,530, is consistent as well with 

 

5

 See 77 Fed. Reg. at 17,923 ("As in current rules, we are proposing to require different 

standards for periods of planned routine maintenance of the control device. We are not 

proposing to require compliance with the same standard at all times because the cost of 

such a requirement would be unreasonable. Instead, we are proposing to prohibit the 

addition of material to the storage vessel during periods of planned routine maintenance and 

to limit the time of planned routine maintenance to less than 360 hr/yr. If you need more 

than 240 hr/yr, you would be required to keep a record documenting why 240 hours is 

insufficient and the steps you took to minimize the additional time for planned routine 

maintenance.") 

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information the industry provided in comments on the proposed Subpart S. 

regulations. AF&PA’s comments stated that the definition of “malfunction” and the 

malfunction exemption in the NESHAPS General Provisions would not cover the 

excess emissions for which an allowance was sought for “the process venting we 

have described since these episodes are not generally considered by the industry or 

regulatory officials to be malfunctions, in the sense that that term conveys technical 

limitations of pollution control equipment. These are truly situations of process 

variability. Thus, the agency must provide for excess emissions venting during 

these minimal periods of process equipment downtime.” AF&PA Comments, April 

18, 1994, at MACT-64. Nothing has changed, and in fact the information in the 

NCASI Report provides further support for this conclusion. NCASI Report at pp. 15 

– 20. EPA has no factual basis for concluding otherwise. 

Note that EPA has recognized similar situations, where a facility experiences nonstandard operating conditions which are not malfunctions. For example, in proposed 

National Uniform Emission Standards for Storage Vessel and Transfer Operations, 

Equipment Leaks, and Closed Vent Systems and Control Devices, March 26, 2012, 

77 Fed. Reg. 17,898, proposed 40 C.F.R. § 65.925 recognizes that “nonstandard 

batches” can occur in chemical processing that do not represent “malfunctions”: 

Nonstandard batch means a batch process that is operated outside 

of the range of operating conditions that are documented in an 

existing operating scenario, but is still a reasonably anticipated 

event. For example, a nonstandard batch occurs when additional 

processing or processing at different operating conditions must be 

conducted to produce a product that is normally produced under the 

conditions described by the standard batch. A nonstandard batch 

may be necessary, as a result of a malfunction, but it is not itself a 

malfunction. 

77 Fed. Reg. at 17,984. 

Finally, even if none of the facts presented in AF&PA’s 1994 comments, the AF&PA 

RTR Comments, and the NCASI Report existed, and EPA instead had some basis 

for asserting that all of the (non-startup or -shutdown) events covered by the excess 

emission allowances in the existing Subpart S rule are malfunctions, that alone still 

would not justify deleting the excess emission allowance provisions from the rule. 

Despite EPA’s implication, nothing in the 2008 Sierra Club decision said that 

malfunctions cannot be considered when setting emission standards. Nor did the 

decision say that MACT standards cannot accommodate malfunctions, through a 

separate numerical standard under CAA section 112(d) or through a design, 

equipment, work practice or operational standard under CAA section 112(h).6

 To 

 

6

 As AF&PA’s RTR Comments noted, in the Proposed Rule EPA did not even consider the 

latter, which made EPA’s proposed decision to treat all malfunctions as per se violations 

arbitrary and capricious. 

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the contrary, the Sierra Club decision acknowledged the possibility of having more 

than one MACT standard that would apply to different circumstances and of having 

design, equipment, work practice, or operational standards that applied in lieu of 

limitations on the amount or concentration of pollutants emitted. See 551 F.3d at 

1021, 1027-28. 

The Excess Emission Allowances Are Necessary To Address Periods of Startup and 

Shutdown

The current Subpart S emission standards contain an exemption for excess 

emissions of NCGs related to startup and shutdown (and malfunction). EPA 

determined that this exemption was necessary in addition to the excess emission 

allowance in 40 C.F.R. § 63.443(e). Excess emissions during startup and shutdown 

are not exempted from the pulping condensate steam stripping requirement, but only 

because EPA did not have data to distinguish those situations from “normal stripper 

operating emissions.” See 72 Fed. Reg. at 18,529-30. In the preamble to the 

Proposed Rule, however, EPA stated, without explanation, that it had “taken into 

account startup and shutdown periods and is not proposing a different standard for 

those periods. Nothing in the record suggests that the operations (and attendant 

emissions) are significantly different during startup or shutdown than during normal 

operation.” 76 Fed. Reg. at 81,346. This appears to be just an arbitrary, 

unsupported rejection of EPA’s prior factual determinations. 

In any event, it is inaccurate. Supplementing information in the docket for the 

original Subpart S rulemaking, the NCASI Report documents that startup and 

shutdown conditions at pulp mills are unlike normal operations and create distinct 

situations in NCG and condensate collection and treatment systems that result in 

intermittent venting episodes. NCASI Report at pp. 21 - 23. Additionally, startup or 

shutdown of a production process can result in unusual variability in the NCG or 

condensate system, resulting in higher emissions during startup or shutdown 

conditions, including intermittent venting, than occur during steady-state operations. 

Id. 

EPA has repeatedly acknowledged that it has authority under CAA section 112 to 

promulgate different emission limitations for startup and shutdown periods than for 

steady-state operations. See, e.g., 75 Fed. Reg. 54,970, 54991-92 (Sept. 9, 2010) 

(Portland Cement); 76 Fed. Reg.72,220, 72,794 (Nov. 25, 2011) (proposed 

alternative limits for startup and shutdown in the Mineral Wool and Wool Fiberglass 

Manufacturing source category) So the Agency’s position for the Pulp and Paper 

Proposed Rule has to be not that it is precluded from establishing separate emission 

standards for startup and shutdown, but only that there is no need for such 

standards to accurately reflect the performance of the best performers. As 

explained above, the facts do not support that conclusion. 

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Since EPA is permitted to establish separate emission standards for startups and 

shutdowns, unless the Agency has a clear justification for departing from its 

decisions in the original Subpart S rulemaking, EPA should not disturb the provisions 

of the existing rules that address emissions during startup and shutdown. If EPA 

ignores the admonitions above about revising MACT standards and wishes to revise 

the standards that apply during startup and shutdown, EPA should develop, and 

propose for public comment, standards that reflect the criteria in CAA section 112(d) 

or in section 112(h). If EPA retains the excess emission allowances currently in the 

Subpart S regulations, it may be possible to fold startup and shutdown periods (as 

well as malfunctions) into the excess emission allowances for NCG systems, as EPA 

already did for steam strippers. 

The NCASI Report Shows the Subpart S Excess Emission Allowances Are 

Justified 

The NCASI NCG survey was conducted in order to answer specific questions 

raised by the EPA, in the December 27, 2011 proposal, on intermittent NCG venting 

that occurs during routine operations and is covered under the venting allowances in 

the existing Subpart S regulations. The NCASI report also provides a summary of 

the main characteristics NCG systems. While it is true that each individual NCG 

system is unique in the types of sources it collects, its configuration, and its 

accommodation of site-specific constraints, the same basic principles apply in 

designing and operating these systems. With this heterogeneity and complexity in 

mind, facilities were requested to provide qualitative information, based on prevailing 

process knowledge and experience, on the types of events triggering these 

intermittent venting episodes. Additionally, facilities were also requested to identify 

operating conditions or threshold operating parameters used to differentiate SSM 

venting events from those occurring during routine operation. A total of 81 kraft 

mills responded to the survey. The NCASI report, provided as item #1 in the 

Appendix, analyzes the survey responses and draws collective conclusions on the 

types of events triggering intermittent venting. 

Survey responses indicate that routine venting events can largely be 

attributed to process variability. As facilities have gained more experience in 

operating NCG systems, they have progressed along the learning curve in managing 

some of this process variability. However, it is impossible to eliminate all sources of 

process variability – hence the term inherent. Inherent process variability is an 

expected facet of day-to-day continuous operations, cannot be mitigated through 

better equipment design, and is inevitable. In fact, system designers expect this 

inherent variability – this is the reason why they design “fail-safe” / “fail-open” control 

systems to alarm and subsequently vent when the potential for unsafe conditions 

exist within these systems. This is the same reason why insurance companies and 

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technical committees like the Black Liquor Recovery Boiler Advisory Committee 

provide comprehensive recommendations on how best to design and operate these 

systems. 

The primary objective of the NCG control system and associated interlocks is 

to (a) prevent NCGs from approaching flammability limits, (b) minimize the potential 

for unsafe conditions in the transport system and at the thermal destruction device, 

and (c) maintain safety and system integrity and prevent explosions. The network of 

alarms designed into NCG systems serves to provide operating boundaries for 

facilities and greatly minimizes venting episodes. These alarms also facilitate the 

secondary, but equally important, objective of minimizing the release of TRS 

compounds that cause objectionable odor in the community. In spite of tight control 

and operation, circumstances do arise that result in the tripping of vent thresholds. 

Given the primary objective of promoting safety and preventing explosions, facilities 

have no option but to mitigate these conditions using “fail-safe” strategies, viz., 

through intermittent venting. 

Key takeaways from the NCASI survey are summarized below. More details 

and data are provided in the attached report. 

1. Intermittent venting episodes can occur during routine or normal 

operation. These events are triggered by the expected inherent process 

variability and by transient conditions in the collection, transport, and 

conditioning equipment. This results in the tripping of safety and system 

integrity interlocks. These venting episodes and the events that trigger them 

are not malfunctions of associated equipment, because the systems continue 

to operate as designed and within expected ranges. These venting episodes 

are critical to maintaining system integrity and preventing catastrophic 

scenarios that could result in unsafe conditions for workers, equipment 

damage, and explosions. 

Inherent process variability is an expected component of day-to-day 

manufacturing processes. System designers expect this variability and 

design control/interlock systems to ensure safe operation in spite of this 

variability. If this variability were unexpected and uncharacteristic of these 

systems, there would be no need to design and implement “fail-open” control 

strategies. 

 

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2. Intermittent venting can also be caused by Startup and Shutdown (SS) 

events. In the context of the NCG system, Startup and Shutdown (SS) 

conditions are distinct and therefore unlike routine operations. 

 A subset of SS conditions trigger distinct interlocks and permissives 

within the NCG transport system or sub-systems, thus resulting in 

intermittent venting episodes. 

 Some of the intermittent venting during SS conditions can also be 

attributed to increased levels of process variability not expected or 

observed during routine operation. 

NCASI survey responses indicate that SS conditions trigger distinct 

scenarios within the process and within the NCG system. In other words, SS 

conditions are distinctly different from conditions that prevail during routine 

operation. Additionally, SS conditions result in unusually high levels of 

variability within the system, at levels that are not typically observed during 

normal operation. These high levels of variability during SS conditions cannot 

be avoided. It is therefore inappropriate to consider SS conditions to be 

similar to normal operation. EPA’s premise in removing the SSM exclusions, 

specifically SS exclusions for NCG venting, was that “....nothing in the record 

suggests that the operations (and attendant emissions) are significantly 

different during startup or shutdown than during normal operation.” 76 Fed. 

Reg. at 81,346. As discussed earlier, the survey results speak to the 

contrary, as it pertains to unit operations in pulp and paper mills and, 

specifically, NCG systems. NCASI survey responses indicate that SS 

conditions are indeed distinct as it pertains to the NCG collection and 

transport system and can trigger distinct operating conditions, non-steadystate operations, and interlock exceedances. Likewise, SS conditions affect 

steam stripper operations and justify the excess emission allowance covering 

steam stripper SS periods that is in the current Subpart S regulations. 

3. The majority of mills use threshold parameters to differentiate routine 

operating periods from startup and shutdown (SS) periods. Others have 

defined specific actions that are required to be carried out in order to 

startup or shutdown a piece of equipment or process, thus 

differentiating the two. 

NCASI survey responses indicate that facilities utilize varying 

approaches to distinguish SS periods from routine operation. While some 

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facilities use threshold parameters, others make the distinction by assessing 

the completion of a pre-defined set of tasks before the process can be termed 

“normal and ongoing” as opposed to under “SS.” Given the fact that SS 

conditions are distinct, clearly differentiated, and trigger distinct conditions 

within the NCG system, AF&PA contends that EPA needs to preserve the 

venting allowances for these periods. Eliminating the SS venting allowances 

would seriously jeopardize safety and system integrity. It would effectively 

undo a decade worth of hard work and learning that the industry has 

developed and implemented, in the design and safe operation of these 

systems.

4. Survey results indicate that problems related to transport system 

equipment (gas conditioning equipment, sensors, and fiber/liquor 

separation equipment) are as prevalent as malfunctions related to 

process equipment and thermal destruction devices. Given the ability to 

isolate sub-systems, the former are less disruptive to overall NCG system 

operation than the latter. Transport system equipment problems also can be 

triggered by inherent process variability. Adequate consideration of the 

triggering events is therefore justified, before classifying all these as 

malfunctions as defined by the rule. 

NCASI survey results indicate that equipment malfunctions can fall into 

broadly variant categories. Those related to sensors, NCG conditioning and 

monitoring equipment etc., are distinctly different from those related to 

process equipment and control devices. The former are less disruptive, given 

the ability to isolate sub-systems and continue to operate the remainder of the 

system normally. 

Additionally, some problems with NCG sensing and conditioning 

equipment are the direct result of process variability (like foam and fiber 

carryover, steam supply variability, etc.) and cannot be considered as events 

that are “sudden, infrequent, and not reasonably preventable.” First, given 

that inherent process variability is not reasonably preventable, these events 

also would not be reasonably preventable. More importantly, these events 

also have the potential to recur given that they are directly caused by process 

variability, i.e. it would be impossible to assure that these events are 

infrequent. It is therefore inappropriate (and too simplistic) to group all these 

problems with transport system equipment into a single category. 

 

AF&PA recommends that EPA draw additional distinctions when 

categorizing malfunctions and its applicability of affirmative defense 

provisions. Events related to transport system and conditioning system 

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equipment that are attributed to process variability should not be categorized 

as malfunctions as defined in the rule. 

5. Steam stripper downtimes do not reflect “no HAP control” scenarios. 

Facilities routinely route their condensates to biological wastewater treatment 

systems during steam stripper downtime periods and thereby continue to 

achieve high levels of treatment for methanol and major non-methanol HAPs. 

6. A handful of states impose limits on the duration of individual LVHC 

system vents. An example is the 40 minute limit imposed by the state of 

Maine.7 Individual LVHC system vents in Arkansas, Oregon, and Alabama 

are limited to 30, 60, and 240 minutes, respectively. 

Other pertinent takeaways relating to specific technical and operational aspects of 

NCG systems are as follows: 

 

7. Intermittent venting is a consequence of “Fail-safe” systems, interlocks, 

and system permissives. These interlocks and the resulting intermittent 

venting are an essential “first line of defense” against system failures and 

potential hazardous conditions, including catastrophic explosions. Some are 

attributed to inherent process variability, others to SS conditions, and a third 

category can be the result of malfunctions. 

8. Interlocks and permissives are essential components of any NCG 

system. These protections are designed into systems in order to prevent 

equipment damage, injuries, and potential fatalities. These are integrated into 

system design and considered as “prerequisites of insurability” by insurance 

companies. As discussed earlier, the BLRBAC recommendations and 

Factory Mutual Guidelines on the design and operation of NCG systems, both 

illustrate the importance of these permissives. Their suggested guidelines 

are widely followed in designing these systems and in carrying out insurance 

audits. 

9. Intermittent venting episodes that occur during normal operation 

frequently resolve themselves or can be resolved through effective 

system isolation. In fact, NCG system interlocks are designed to effectively 

isolate the source and prevent momentary exceedances from propagating 

throughout the system and causing a broader venting episode of the entire 

system. The ability to isolate and vent sub-systems protects overall system 

integrity and minimizes potential emissions. 

 

7

 The State of Maine Department of Environmental Protection (Maine DEP), in comments 

filed for the RTR proposal, has opined that the EPA should maintain the venting allowances. 

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Given the myriad of other state emission limitations, limitations under 

NSPS or other applicable regulations, etc. that constrain emissions from the 

mill, facilities have in place best operating and management practices to 

identify, as soon as practical, the source of an unresolved venting episode. 

These operating practices also include troubleshooting procedures, 

approaches to isolate sub-systems, and instituting corrective actions.

Possible Elimination of Excess Emission Allowances Is Extremely Costly and 

Unachievable 

In the AF&PA RTR Comments, we presented the potential capital costs that might 

be imposed on mills if the current venting allowances were eliminated - $1.6 billion. 

The costs included redundant control costs and collection systems for both LVHC 

and HVLC systems as well as installation of back-up strippers. This analysis was 

done very quickly in light of the short comment period and reflected the best analysis 

possible given the available data and input from member companies. 

Since February, we have had a little more time to gather information from member 

companies, discuss other control technology requirements and costs with EPA, and 

examine the EPA data base in more depth. This has allowed AF&PA to develop a 

revised estimate of the potential cost of eliminating the excess emission allowances 

- $750 million. As the cost estimate document explains (see Attachment 8), the 

number of mills affected and the unit cost of investments were lower for a couple of 

key categories of costs, especially upgrades to collection systems and existence of 

alternative control/combustion devices. 

While the cost is lower, it is still a very significant cost for the industry, especially 

considering that EPA has concluded that risks from this source category (in an 

analysis that included emissions that occur under the current excess emission 

allowances) are acceptable and there is no legal reason to change the excess 

emission allowance. Furthermore, investment of these hundreds of millions of dollars 

will NOT eliminate all venting periods, since some are part of normal operations and 

cannot be prevented in all circumstances. Thus, our conclusion remains that 

elimination of the excess emission allowances is cost-prohibitive, unnecessary, and 

would severely impact the ability of pulp and paper mills to operate. 

* * * * * * 

AF&PA appreciates the opportunity to comment on these issues. AF&PA wants to 

acknowledge the tremendous effort that OAQPS staff has taken since the issuance 

of the proposal to better understand pulp and paper operations and how Subpart S 

has been implemented and works, since none of the current staff were involved in 

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Assistant Administrator McCarthy 

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Page 20 

the original Subpart S rulemaking. They have made themselves available to discuss 

the data provided by our mills during the information collection request and the 

background analyses used to support the rule. As the attached information 

suggests, as well as our earlier comments, mill operations are very complex and 

each mill is unique given the array of equipment used, products made, and control 

options selected. AF&PA, NCASI and its member companies continue to stand 

ready to help explain the types and causes of venting that are inherent to our mill 

operations and provide information that is useful to the rulemaking proceedings. 

Please direct any questions to Tim Hunt, AF&PA’s Senior Director, Air Quality 

Programs, at (202) 463-2588 or at tim_hunt@afandpa.org. 

 Sincerely, 

 

 /s/ 

 Paul Noe 

Vice President for Public Policy 

Enclosures 

cc: Docket EPA-HQ-OAR-2007-0544 

 John Bradfield, EPA-RTP 

 Bill Schrock, EPA-RTP

 Robin Dunkins, EPA-RTP 

 Peter Tsirigotis, EPA-RTP

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LIST OF ATTACHMENTS 

1. NCASI, The Collection and Transport of Noncondensible Gases (NCG) in 

NCG Systems at Pulp and Paper Mills: Background and Characteristics of 

NCG Systems and Summary of NCASI Survey Responses, June 27, 2012 

2. Attachment A, NCASI Non Condensible Gas Venting Survey Questionnaire, 

May 2012 

3. Attachment B, Recommended Good Practice Thermal Oxidation of Waste 

Streams in Black Liquor Recovery Boilers, The Black Liquor Recovery Boiler 

Advisory Committee (BLRBAC), February, 2012 

4. Attachment C, NCASI, Experience with the Collection, Transport, and Burning 

of Kraft Mill High Volume Low Concentration Gases, August 2003 

5. Attachment D, FM Global, Property Loss Prevention Data Sheets, January 

2012 

6. Attachment E, FM Global, Property Loss Prevention Data Sheets, May 2010 

7. Attachment F, FM Global, Property Loss Prevention Data Sheets, May 2006 

8. Cost Estimate for Elimination of Excess Emission Allowances, June 2012 

a. Attachment A to Cost Estimate, Excel File, Cost Estimate of Proposed 

Rules Changes to 40 CFR 63 Subpart S, Elimination of Excess 

Emission Allowances, June 2012 

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Attachment 1 

NCASI, The Collection and Transport of Noncondensible Gases (NCG) in NCG 

Systems at Pulp and Paper Mills: Background and Characteristics of NCG 

Systems and Summary of NCASI Survey Responses, June 27, 2012 

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1 National Council for Air and Stream Improvement Inc. (NCASI)

The Collection and Transport of Noncondensible Gases (NCG) in 

NCG Systems at Pulp and Paper Mills: 

Background and Characteristics of NCG Systems and 

Summary of NCASI Survey Responses 

June 27, 2012 

1.0 INTRODUCTION

Pulp and paper manufacturing utilizes an intricate network of interconnected processes.  

Unit operations are tied together by intermediate product flows, energy reuse, and chemical

recovery cycles.  Steam generated in power and recovery boilers is delivered to the process to

satisfy system heat/energy demands.  Recovered chemicals are brought back to the pulping and

causticizing systems through the recovery cycle.  There can be significant variability in operating

rates, material throughputs, noncondensible gas generation, etc. at any one part of the mill.  To

some extent, throughput variability is ubiquitous and expected in continuous manufacturing

operations.  The interconnected nature of unit operations also contributes to variability.   Many

of these unit operations include multiple pieces of equipment, some operating in parallel, that

create additional variability in flows, e.g., multiple batch digesters and blow tanks, operating on

different cycles; multiple brownstock washers; and multiple pulp storage tanks feeding multiple

paper machines.

Non‐condensible gases (NCGs) generated in the pulping cycle are collected and

transported in a complex and interconnected system, parts of which are under pressure while

others are under vacuum.  By virtue of their composition, these gases are potentially explosive

and require extensive engineering controls to ensure safe handling.  “Fail‐safe” venting

systems, interlocks, and permissives1 ensure that these gases are transported safely to the

combustion device.  These systems operate under very strict criteria designed to intermittingly

vent to ensure that the system stays in balance and is operated without compromising worker

safety or equipment integrity.  There is also considerable heterogeneity in the components and

configuration of NCG systems, viz., in the types and mix of sources collected, how the transport

                                                           

1 “Fail‐Safe” Systems and Interlocks – An automatic control logic that results in an alarm or an automatic venting

episode.  Condition occurs when monitored parameter falls outside acceptable ranges.  These systems are “fail‐

safe” because the venting event avoids a potential condition that compromises system integrity or results in an

explosion.  Non control logic / non computer controlled fail safe systems such as rupture disks, water loop seals,

and P/V breakers, are also designed to vent if electronic systems fail.  Permissives – A set of active conditions that

need to be satisfied before NCG gases are introduced into the collection/transport system OR to the thermal

destruction device, e.g., steam flow into steam ejectors and complete steam purge before introducing LVHC gases

into transport system and control device.

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2 National Council for Air and Stream Improvement Inc. (NCASI)

and conditioning systems are configured to meet system‐specific requirements and constraints,

and the types of primary and secondary thermal destruction devices used.

As part of proposed amendments to the National Emission Standards for Hazardous Air

Pollutants (NESHAP) for the pulp and paper industry [FR 76 (247) 81328‐81358, December 27,

2011], EPA has proposed to eliminate language pertaining to Startups, Shutdowns, and

Malfunctions (SSM) to be consistent with the Agency’s interpretation of the ruling in Sierra Club

v. EPA.  (Sierra Club v. EPA, 551 F.3d 1019, DC Cir. 2008).  Additionally, EPA has also requested

comments on whether it would be appropriate to remove or modify currently available NCG

venting allowances and steam stripper downtime provisions (40 CFR 63.443(e), 40 CFR

63.446(g), and 40 CFR 63.459(b)(11)(ii)) of the 1998 NESHAP).  EPA has requested additional

information on the characteristics and drivers of intermittent NCG venting and on how facilities

differentiate venting that occurs during SSM periods from those that occur during normal

operation (intermittent safety‐related venting not related to SSM conditions).  In response to

EPA’s request for information, NCASI has conducted a survey to better understand the drivers

of intermittent NCG venting episodes at pulp and paper facilities.   

2.0 NCASI SURVEY ON PULP AND PAPER NCG VENTING AND STEAM STRIPPER PRACTICES

The NCASI survey on NCG venting (NCASI survey) was distributed to NCASI and AF&PA

member companies on April 30, 2012.  The survey attempts to answer specific questions posed

by EPA on the following aspects of NCG venting:

a. Events during routine or normal operation that trigger intermittent NCG venting

b. Startup, shutdown, and malfunction (SSM) events triggering intermittent NCG venting, and

c. Approaches used by facilities to differentiate normal operation (and associated venting

episodes) from SSM conditions

Survey questions were reviewed by technical staff at EPA’s Office of Air Quality Planning

and Standards (OAQPS) prior to distribution.  In response to a specific request by OAQPS during

this review, the survey also requested information on other applicable restrictions imposed by

States, if any, on recording, reporting, and classifying NCG venting episodes.  The survey

questionnaire is provided as Attachment A.

3.0 ORGANIZATION OF THIS DOCUMENT

This document provides a primer on the background and characteristics of NCG systems

at pulp and paper mills, a compilation of available information on NCG constituents, and a

discussion of the major design considerations involved in building and operating these systems.  

Secondly, industry responses to specific questions in the NCASI Survey are compiled along with

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3 National Council for Air and Stream Improvement Inc. (NCASI)

associated observations and conclusions.  In addition to summarizing the key takeaways from

the NCASI survey, this report also includes the following documents in Addenda;

 Technical assessment report developed by the Black Liquor Recovery Boiler Advisory

Committee (BLRBAC) on safety and control system considerations while burning flammable

NCGs in recovery furnaces.  This report further highlights the complexity of NCG transport

systems and illustrates the need for adequately designed control systems to maintain

system integrity and safety (Attachment B).

 NCASI Special report 03‐03 summarizing industry experience with HVLC systems.  This

report provides additional background information on NCGs and the various components

that make‐up LVHC and HVLC systems (Attachment C).

 Selected compilations from Factory Mutual Insurance Company on recommended practices

for the design, operation, and maintenance of chemical recovery furnaces, wood fuel

boilers, and for the combustion of NCGs.2

  Specifically, FM global has provided suggested

guidelines for the design of boiler pressure parts and burning of liquid fuels, gaseous fuels,

and auxiliary fuels like NCGs.  These documents are also used as guidelines when assessing

insurability of systems (Attachments D, E, and F).

4.0 BACKGROUND ON KRAFT MILL NCGs AND THEIR COMBUSTIBILITY3

Characterization studies carried out on kraft mill NCGs indicate that the main

components are methanol, turpentine (predominantly α‐pinene), hydrogen sulfide (H2S),

methyl mercaptan (CH3SH), dimethyl sulfide (DMS) and dimethyl disulfide (DMDS).  The sulfur

compounds present in NCG are collectively referred to as total reduced sulfur (TRS)

compounds.  The NCGs are generated and released from pulping systems, turpentine recovery

systems, brownstock washers, liquor evaporation, and liquor storage tanks.

4.1 Characteristics of combustible gases

The protection of personnel, public, and equipment remains in the forefront when

designing collection and transport systems for NCGs, given its combustible components.  

Equipment designers evaluate the potential for explosions during the first step of the design

phase.   Several studies have been carried out in order to better understand the dangers

                                                           

2 Designing piping for auxiliary fuel gas and LVHC gases – Data Sheets 6‐5, Section 2.2 of 7‐32, and 7‐54

Designing ductwork for HVLC gases – Data Sheet 7‐78.   

Data sheets available for download at http://www.fmglobal.com/FMGlobalRegistration/Downloads.aspx 3 Excerpts taken from NCASI Special Report 03‐03 – “Experience with the collection, transport, and burning of kraft

mill high volume low concentration gases,” Vipin K. Varma, PhD, August 2003.

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associated with transporting combustible gases.  These studies indicate that the flammability

and ignitability of combustibles are dictated by the five characteristics described below.

Lower Explosive Limit (LEL): The lower explosive limit (LEL) of a combustible component in a

gas is defined as the minimum concentration by volume at which the gas ignites when provided

with enough oxygen and an ignition source and continues to burn when the ignition source is

removed.

Upper Explosive Limit (UEL): The UEL of a combustible component in a gas is the maximum

concentration above which the gas will not ignite due to a lack of oxygen, even when provided

with an ignition source.

Flammability Range: Combustible components in NCGs will ignite when their concentrations

are in the range of percentages from the LEL to the UEL, if provided an ignition source.

Flame Propagation Speed: The speed at which the flame travels from the point of ignition,

through a flammable vapor, along the length of a long pipe (such as the one used to transport

NCGs to the combustion device).  

Auto Ignition Temperature (AIT): The approximate lowest temperature at which a flammable

gas or vapor‐air mixture will spontaneously ignite without a spark or a flame.  

4.2 Characteristics of Kraft Mill NCGs

Kraft mill NCGs are characterized based on the composition of the main constituents

into four categories, viz., low volume high concentration (LVHC), high volume low concentration

(HVLC), stripper off‐gases (SOG), and chip bin vent gases.  Extensive characterization studies

have established the concentration ranges of main combustible components in these various

streams.4

  The LEL and UEL values, flame speeds, and auto ignition temperatures for the main

kraft mill NCG components are summarized in Table 1.5

  Main characteristics of these gases are

summarized below.

LVHC gases (concentrated NCGs)

 Consist of relatively high concentrations of TRS compounds and air depleted of nearly

half of its oxygen  

 TRS compounds are typically present at concentrations in the flammable range i.e.,

between the LEL and UEL

                                                           

4 Burgess, T. L.  1998.  Collecting and Burning Noncondensible Gases.  Kraft Recovery Operations Short Course

Proceedings.  Section 4.2: 1‐19. Atlanta, GA. TAPPI Press. 5 Burgess, T. L., Kjerulf, E. B., and Tenn, T. I.  1984.  Design Considerations for High Concentration Low Volume

Noncondensible Gas Systems.  TAPPI Journal 67(9): 92‐96.

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 Since these gases do not contain sufficient oxygen to allow for ignition, LVHC systems

are designed with the objective of minimizing air ingression and thereby reducing the

explosion hazard.

 LVHC gases are therefore transported using steam, instead of air, as the motive force.

Table 1. Combustion Properties of Kraft Mill NCGs in Air 5

Compound

Explosive Limits, % volume   

Flame Speed,

ft/sec (m/sec)

Auto Ignition

Temp, °F (°C) LEL UEL

        

H2S 4.3 45.0    500 (260)

CH3SH 3.9 21.8 1.8 (0.55)   

CH3SCH3 (DMS) 2.2 19.7    400 (206)

CH3SSCH3

(DMDS) 1.1 8.0    572 (300)

α‐Pinene 0.8 6.0 500 (154) 487 (253)

Methanol 6.7 36.5 1.5 (0.5) 867 (464)

Stripper off‐gases (SOG)

 Mixture of methanol, TRS compounds, turpentine6 , and saturated steam

 Methanol concentrations in SOGs are typically greater than methanol concentrations in

LVHC gases.

 Contain condensible components unlike in LVHC gases.

HVLC gases (dilute NCGs)  

 Combustible components in HVLC gases, or dilute NCGs, are typically present at levels

well below their individual lower explosive limits (LEL).   

 Oxygen levels in HVLC gases approach that of atmospheric air.   

Chip bin vent gases

 The combustible components in chip bin vent gases are also present at concentrations

well below their respective LELs.

                                                           

6 Occasional carryover of turpentine in foul condensates

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 Chip bin vent gases are different from HVLC gases in that they have the potential to

contain significant quantities of turpentine, sometimes at concentrations approaching

its LEL.   

5.0 DESIGN AND OPERATING PHILOSOPHIES FOR NCG SYSTEMS 7, 8, 9

5.1 NCG Collection and Transport Systems

The governing principles for designing NCG collection and transport systems have been

established based on years of experience and are well documented in literature.  The primary

consideration in the design of kraft mill NCG systems is to prevent explosions.  Explosions in

collection and transport systems are caused by the coexistence of all three primary

ingredients, viz., combustibles in the flammable range, sufficient oxygen, and an ignition

source.  Therefore, the strategy adopted for the design and operation of these systems is to

prevent explosions by excluding one or more of the above‐mentioned components from these

systems at all times.  Key design philosophies are summarized in the following section and

additional details are provided in NCASI Special Report 03‐03 and NCASI Technical Bulletin 469.

LVHC systems

As discussed earlier, LVHC systems typically include vent gases from turpentine

recovery, blow heat recovery, evaporator hotwell, foul condensate storage tanks, and digester

relief vents.  The combustible components in these gases are typically present within the

flammable range (between LEL and UEL).  However, LVHC gases, as collected, generally have

insufficient oxygen to cause ignition.  Hence, the design philosophy for LVHC systems is to

prevent air ingression and eliminate the explosion hazard by oxidant concentration reduction.  

Fans used for transporting LVHC gases have provided ignition sources in the past, due to hot

spots in the casing, bearing failure etc.  Consequently, steam ejectors are used as motive force

for LVHC gases.  This provides an additional line of defense against explosions by eliminating

ignition sources and providing a safe motive force without air ingression.  Condensate

accumulation has been known to cause two‐phase flows, in the presence of even minimal

amounts of turpentine, leading to the buildup of static electricity that could generate a spark

and lead to an explosion.  Therefore, system designers incorporate an additional line of defense

                                                           

7 Allen, T. 2001. NCG handling and incineration concerns drive need for safe system design.

Pulp and Paper 2001(3): 43‐51. 8 Barynin, J.A., Berg, L., and Lee, B. 1993. Recent trends in NCG disposal system design. Pulp

and Paper Canada 94(12): 74‐78. 9 NCASI Technical Bulletin No. 469 – Collection and burning of kraft non‐condensible gases – current practices,

operating experience, and important aspects of design and operation, Parts I and II, 1985

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against explosions by advising that the system be operated without condensate accumulation

and with minimal turpentine entrainment.  The latter involves optimal operation of the

turpentine recovery system.

SOG Systems

Like LVHC gases, SOGs are collected and transported with minimal air ingression.  SOG

streams contain increased levels of methanol and saturated steam at temperatures higher than

that of LVHC streams.  SOG stream can occasionally contain turpentine due to its carryover into

foul condensates.  SOG streams do contain condensible components, as a result of which they

are not combined with LVHC streams prior to incineration.  The temperature differential

between the streams could result in condensation of SOG constituents, thereby creating two‐

phase flows and the potential for buildup of static electricity.  The prevalent practice is to

collect and transport each stream using a dedicated system.  Steam ejectors are used as motive

forces when steam strippers are operated at or near atmospheric pressure.  Some system

designers exclude steam ejectors when the steam strippers operate under pressure and provide

sufficient motive force at the collection source.  

HVLC Systems

Unlike LVHC gases, HVLC gases contain significantly lower TRS concentrations and

oxygen levels approaching that of ambient air.  Sources of HVLC gases include brown stock

washers, deckers, O2 delignification systems, knotters, screens, intermediate storage tanks,

filtrate tanks, and weak liquor storage tanks.  The design philosophy with these gases is to

eliminate the explosion hazard by ensuring that the combustibles remain at concentrations well

below their LEL.  This is accomplished by further diluting the sources with sufficient air to

ensure that the TRS compound concentrations remain well below their LEL values.  Fans are

generally used as motive forces for HVLC gases. System designers advise that HVLC gases

should not be combined with LVHC gases and SOG prior to incineration since the associated

dilution may move the combustible concentrations in the LVHC stream, generally maintained

above the UEL, into the flammable range.

Chip Bins

Vent gases from chip bins utilizing flash steam are different from LVHC gases because

they contain higher levels of oxygen.  They are also different from HVLC gases because they can

potentially contain turpentine at levels approaching its LEL.  System designers recommend that

chip bin vent gases be collected as part of the HVLC system, because the increased levels of

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oxygen in these streams make it unsuitable to be collected along with LVHC streams.  However,

when pulping softwood, it is common practice to remove turpentine by passing these gases

through a cooler or a condenser, before introducing them into the HVLC stream.  This is

because condensate accumulation and turpentine entry into the system can potentially create

ignition sources.  Since water and turpentine are immiscible, they decant in the pipeline, cause

two‐phase flows and may build sufficient static charges to ignite the turpentine as it cascades

down a pipe run.

It is common practice to design NCG systems to operate at gas velocities above the

flame propagation speed of the combustible components.  Experience indicates NCG systems

can be designed to operate at gas velocities greater than the flame propagation speeds of the

TRS compounds and methanol.  However, these systems cannot be operated at velocities

greater than the flame propagation speed of turpentine.  It has been reported that maintaining

gas velocities between 50 and 100 ft/sec provides an adequate safety factor during operation.  

This is another reason why effective turpentine removal is critical when operating these

systems.  It is also recommended that all systems be adequately grounded in order to prevent

the buildup of static electricity.  Flow rate and temperature monitoring, with interlocks,

immediately upstream of the combustion device protects against flame propagation hazards.

5.2 Thermal Destruction Devices

In addition to the safety considerations associated with the collection and transport of

NCGs, system designers need to adequately design the NCG introduction system into the

incineration device.  Design considerations for NCG introduction (and control) systems for

thermal oxidizers, boilers, recovery furnaces, and lime kilns are to ensure that the devices (a)

are ready to receive NCGs, (b) can achieve complete combustion, and (c) are equipped with

monitoring and control systems to prevent NCG introduction into unsafe combustion

environments.  As discussed earlier, BLRBAC has provided detailed recommendations on best

practices and procedures while burning NCGs in recovery furnaces.  Factory Mutual Insurance

Company has developed a series of data sheets with recommendations on the construction of

NCG systems, the control equipment and permissives that need to be in operation, and on how

to operate and maintain boilers and recovery furnaces.10

LVHC gases can be transported from the collection point to the incineration device using

the two approaches listed below.

a. Vapor phase transfer system

b. Conditioned gas transfer system

                                                           

10 Provided as Attachments D, E, and F

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In a vapor phase system, NCGs are directly transported from the collection point to the

incineration device.  These systems are generally heavily insulated and heat traced using steam,

in order to prevent the accumulation of condensible components like methanol, water, and

turpentine.  By contrast, the intent of a conditioned gas transfer system is to reduce the

amount of water vapor and condensible components being incinerated.  A conditioned gas

transfer system includes the following additional components.

a. Gas cooler/Condenser

b. Mist eliminator

c. Indirect steam pre‐heater to re‐heat gases

The condensates from the cooler/condenser and mist eliminator are typically

transferred to the foul condensate treatment system. 11  The gases are re‐heated after the

condensates are removed so that the operating temperature is increased and process upsets

due to further condensation are minimized.  Conditioned gas transfer systems are especially

critical when burning NCGs in recovery furnaces, as discussed below.

The incineration of LVHC, HVLC, and SOG in recovery furnaces presents operational

problems that far exceed the safety, gas flammability, and tube explosion concerns that

designers tackle in the case of thermal oxidizers, conventional boilers, and lime kilns.  A

significant added concern is the possibility of furnace explosions.  Furnace explosions can be

broadly classified into the three categories listed below.12

a. Smelt‐water explosion

b. Auxiliary fuel explosion, and

c. Pyrolysis gas explosion

Smelt‐water explosions are attributed to the introduction of moisture into the furnace.  

Although a majority of these explosions are caused by the failure of boiler pressure parts inside

furnaces, they can also be the result of introduction of moisture through LVHC, HVLC, and

SOGs.  Auxiliary fuel and pyrolysis gas explosions are caused by the uncontrolled ignition of

auxiliary fuels or pyrolysis gases accumulating in the upper furnace region without being

incinerated.  LVHC gases are similar to auxiliary fuels in that they have significant heat value.  

Therefore, explosions can occur when these gases are introduced into the furnace in the

absence of a controlled ignition source.  Explosions are also possible when HVLC gases,

                                                           

11 Barynin, J.A., Berg, L., and Lee, B. 1993. Recent trends in NCG disposal system design. Pulp

and Paper Canada 94(12): 74‐78. 12 Grace, T. M.  Recovery Boiler Explosion Experience.  1992.  TAPPI International Chemical Recovery Conference

Proceedings  25‐31.  Atlanta, GA. TAPPI Press.

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generally maintained well below their LEL limits, get concentrated in the furnace to within

flammability limits and accumulate without being completely destroyed.

5.3 NCG System Interlocks and Permissives

The primary objective of safety interlocks in NCG systems is to isolate and vent portions

of the system during unsafe conditions.  Additionally, when the system becomes unstable or

when incineration permissives are lost, safety interlocks allow for automatic venting and

prevent potential explosions.  Interlocks are typically set up to warn (alarm) plant operators

when the “low/high” set‐point is reached and vent when the “low‐low/high‐high” set‐point is

exceeded (alarm and venting thresholds, respectively).   

The following is a list of common interlocks that result in an alarm, and if unresolved, a

venting episode:

1. Steam flow from boiler or recovery furnace falls below predetermined cut‐off value (e.g.

30% of Maximum Continuous Rating (MCR) for boilers and 50% for recovery furnaces).  Loss

of flame, if incineration device is a thermal oxidizer.

2. HVLC gas flow at the outlet of the main HVLC fan falls below acceptable threshold.  In the

case of LVHC gases, temperature or pressure measurements at the outlet of the steam

ejector (or for steam supply into the ejector) fall outside acceptable ranges.  Differential

pressure alarms are also common as a way to identify plugged flame arrestors.

3. System pressure at the HVLC cooler or re‐heater increases above the acceptable threshold.

4. Temperature at the exit of the LVHC or HVLC cooler exceeds acceptable thresholds.  In the

case of HVLC gas re‐heaters, if the temperature at the re‐heater exit falls below acceptable

thresholds.

5. Temperature at the exit of the HVLC gas re‐heater increases above the “high‐high” set‐

point, indicating potential burn‐back.

6. HVLC fan speed falls below the “low‐low” set‐point.  When steam ejectors are used (as in

the case of LVHC and SOG), when steam flow to the ejector falls below the “low‐low” set‐

point or total system flow exceeds acceptable ranges.

7. When alarm and vent thresholds for LEL meters, when used near the incineration device,

are exceeded.

8. Differential pressures across flame arrestors, mist eliminators, or condensate drains exceed

acceptable thresholds.

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11

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Figure 1. Schematic of typical vapor phase NCG Transport and Introduction System

  

Figure 2. Schematic of typical conditioned gas HVLC transport and introduction system

6.0 SUMMARY OF INDUSTRY RESPONSES TO THE NCASI SURVEY

6.1 Background and Key Takeaways

The NCASI NCG survey was conducted in order to answer specific questions raised by

the EPA, in the December 27, 2011 proposal, on intermittent NCG venting that occurs during

routine or normal operations and covered under existing venting allowances.  Facilities were

requested to provide qualitative information, based on prevailing process knowledge and

experience, on the types of events triggering these intermittent venting episodes.  Additionally,

facilities were also requested to identify operating conditions or threshold operating

parameters used to differentiate SSM venting events from those occurring during routine

operation.  A total of 81 kraft mills responded to the survey.  This report analyzes survey

responses and draws collective conclusions on the types of events triggering intermittent

venting.  Given the large number of survey responses and the time constraints that EPA has for

reviewing these results, this report is designed to provide comprehensive summarizes of survey

responses, discuss survey results in the context of the questions being posed, and draw

relevant conclusions in light of survey results and the system characteristics presented above.

HVLC

Cooler

Primary 

Incineration

Secondary 

Incineration

HVLC Gases

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TT L - Low Temperature Alarm

PDI - Pressure Drop Indicator

Condensate

Drain

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Make-Up Air

F L

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Feedback Control Loop

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4 - Automatic Vent Valve

5 - Flame Arrestor

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Intermittent venting episodes of the NCG system can be broadly categorized into the

following:

a. Events occurring during equipment startup, shutdown, and malfunctions (SSM) periods, and   

b. Events occurring during routine or normal operation.   

Routine venting events can largely be attributed to process variability.  As facilities have

gained more experience in operating NCG systems, they have progressed along the learning

curve and learned to manage some of this process variability.  However, it is impossible to

eliminate all sources of process variability – hence the term inherent.  Inherent process

variability inevitably results in the tripping of control system interlocks and intermittent venting

episodes.  The primary objective of the NCG control system and associated interlocks is to (a)

prevent NCGs from approaching flammability limits, (b) minimize the potential for unsafe

conditions in the transport system and at the thermal destruction device, and (c) maintain

safety, system integrity, and prevent explosions.  The network of alarms designed into NCG

systems serves to provide operating boundaries for facilities and greatly minimizes venting

episodes.  These alarms facilitate the secondary, but equally important, objective of minimizing

the release of TRS compounds that cause objectionable odor in the community.  In spite of tight

control and operation, circumstances do arise that result in the tripping of vent thresholds.  

Given the primary objective of promoting safety and preventing explosions, facilities have to

mitigate these conditions using “fail‐safe” strategies, viz., through intermittent venting.  

Key takeaways from the NCASI survey are summarized below.  More details and data

are provided in the remainder of this report.

1. Intermittent venting episodes can occur during routine or normal operation.  These

events are triggered by the expected inherent process variability and by transient

conditions in the collection, transport, and conditioning equipment.  This results in the

tripping of safety and system integrity interlocks.  These venting episodes and the

events that trigger them are not malfunctions of associated equipment as they continue

to operate as designed and within expected ranges.  These venting episodes are critical

to maintaining system integrity and preventing catastrophic scenarios that could result

in unsafe conditions for workers, equipment damage, and explosions.

2. Intermittent venting can also be caused by Startup and Shutdown (SS) events.  In the

context of the NCG system, Startup and Shutdown (SS) conditions are distinct and

therefore unlike routine operations.   

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 A subset of SS conditions trigger distinct interlocks and permissives within the

NCG transport system or sub‐systems, thus resulting in intermittent venting

episodes.

 Some of the intermittent venting during SS conditions can also be traced to

increased levels of process variability not expected or observed during routine

operation.

3. A vast majority of facilities use threshold parameters to differentiate routine

operating periods from startup and shutdown (SS) periods.  Others have defined

specific actions that are required to be carried out in order to startup or shutdown a

piece of equipment or process, thus differentiating the two.  

4. Survey results indicate that problems related to transport system equipment (gas

conditioning equipment, sensors, and fiber/liquor separation equipment) are as

prevalent as malfunctions related to process equipment and thermal destruction

devices.  Given the ability to isolate sub‐systems, the former are less disruptive to

overall NCG system operation than the latter.  Transport system equipment problems

also can be triggered by inherent process variability.  Adequate consideration of the

triggering events is therefore justified, before these are all grouped as malfunctions as

defined by the rule.

5. Steam stripper downtimes do not reflect “no HAP control” scenarios.  Facilities

routinely route their condensates to biological wastewater treatment systems during

steam stripper downtime periods and thereby maintain high levels of treatment for

methanol and major non‐methanol HAPs.

6. A handful of states do impose limits on the duration of individual LVHC system vents.  

This is similar to the 40 minute limit imposed by the state of Maine.13  Individual LVHC

system vents are limited to 30, 60, and 240 minutes in AR, OR, and AL, respectively.

Other pertinent takeaways relating to specific technical and operational aspects of NCG

systems are as follows:

  

7. Intermittent venting is a consequence of “Fail‐safe” systems, interlocks, and system

permissives.  These interlocks and the resulting intermittent venting are an essential

“first line of defense” against system failures and potential hazardous conditions,

including catastrophic explosions.  Some are attributed to inherent process variability,

others to SS conditions, and a third category can be the result of malfunctions.

8. Interlocks and permissives are essential components of any NCG system.  These

protections are designed into systems in order to prevent equipment damage, injuries,

                                                           

13 The State of Maine Department of Environmental Protection (Maine DEP), in comments filed for the RTR

proposal, has opined that the EPA should maintain the venting allowances.

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and potential fatalities.  These are integrated into system design and considered as

“prerequisites of insurability” by insurance companies.  As discussed earlier, the BLRBAC

recommendations and Factory Mutual Guidelines on the design and operation of NCG

systems, both illustrate the importance of these permissives.  Their suggested guidelines

are widely followed in designing these systems and in carrying out insurance audits.     

9. Intermittent venting episodes that occur during normal operation frequently resolve

themselves or can be resolved through effective system isolation.  NCG system

interlocks are designed to effectively isolate the source and prevent momentary

exceedances from propagating throughout the system and causing a broader venting

episode of the entire system.  The ability to isolate and vent sub‐systems protects

overall system integrity and minimizes potential emissions.

6.2 Detailed Discussion of Survey Responses

1. Intermittent NCG venting in Pulp and Paper mills can be caused by events that occur during

routine or normal operation.  These events can be traced back to inherent process

variability that results in the tripping of safety and system integrity interlocks.  These events

are not malfunctions, as defined by the regulation, and the resulting venting episodes are

an essential “first line of defense,” for preventing the onset of more dangerous and

potentially catastrophic conditions in the NCG system.   

Facility responses to the following questions have been summarized in this section:

Q8. Rank or select the top six causes of routine venting events in the LVHC System

Q10. Rank or select the top six causes of routine venting events in the HVLC System

LVHC SYSTEMS

Four (4) most identified events that occur during routine/normal operation and trigger

intermittent venting

As discussed earlier, a multitude of normal operating scenarios can cause intermittent

venting of LVHC NCGs.  These are all transient in nature and frequently resolve themselves or

can be rectified with minimal intervention.  The following four scenarios were the top triggering

events, associated with LVHC systems, identified by facilities responding to the survey.  (Ranked

in the descending order on how frequently they were identified by facilities).  

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# (Area) Conditions Occurring during

Normal Operation

Facilities

Identifying these

Conditions 1

1. Cause

2. Reason for venting

1

(Control device)

Primary Combustion Device Not Available

(not due to malfunction) 51

 Loss of permissives

 Safety‐related

2

(Transport system)

Pressure / Temperature Interlocks in Gas

Transport System 42

 Inherent variability  

 Safety‐related

3

(Transport system)

Pressure / Temperature Parameters on

Process Equipment Outside Normal

Operating Ranges

40  Inherent variability

 Safety‐related

4

(Control device) Switching between Incineration Points 36

 Steam purge

requirement  

 Safety‐related

1

Facilities were given the option to select all applicable reasons for venting during normal operation

Two of the four events most frequently identified by facilities in the survey relate to

operating conditions in the control device (# 1 and #4).  # 2 relates to process swings and the

resulting tripping of system interlocks in the transport system.  # 3 is predominantly driven by

momentary swings in the process areas that result in pressure or temperature parameters

exceeding normal operating ranges.   More details on these events are provided below.

# 1 – Primary combustion device not available (not due to malfunctions) – The combustion

device becomes temporarily unavailable due to the momentary loss of NCG burning

permissives.  This condition is not caused by malfunctions of associated equipment and affects

only the ability of the control device to burn NCGs.  Examples include the following:

 Transient changes in process steam/energy demands in the mill (inherent variability in

upstream processes or swings in production rates) cause variations in steam header

pressure.  This could lead to changes in fuel feed rates and/or fuel mixes and trip NCG

burning permissives.   

 A reduction in steam demand could result in steaming rates being reduced below a certain

threshold, thus preventing the burning of NCGs in the boiler or recovery furnace.  

When steaming rates in a boiler or a recovery furnace fall below a certain threshold

percentage of the maximum continuous rating (MCR), it triggers a “boiler permissive” that

prevents NCGs from being burned in the boiler.  NCG burning is not recommended at low MCR

as the resulting lower combustion temperatures increases the potential for incomplete

combustion of NCGs, which is an unsafe operating condition.  In the case of a thermal oxidizer,

a temporary flameout could result in loss of the “burner permissive” and result in NCG venting

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until the flame is relit and the unit is stabilized.  These temporary losses of permissives are not

malfunctions of the associated equipment but primarily driven by inherent process swings and

variations.  These are typically resolved when the associated parameters stabilize and the NCG

burning permissive is restored.

When the primary combustion device becomes temporarily unavailable, LVHC gases are

typically routed to the secondary combustion device.  In the case of LVHC systems, this transfer

can occur without intermittent venting if and only if all transfer piping conveying the gases to

the secondary combustion device is maintained in “ready” mode.  This condition is satisfied by

maintaining a continuous steam purge through all transfer piping, thus allowing for ventless

transfer of gases.   Switching between incineration points was another routine/normal

operating condition identified in the survey (#4 below).

# 2 – Pressure / Temperature Interlocks in Gas Transport System – These interlocks can be

tripped due to exceedances of either the flow rate OR temperature set‐points in the transport

system.  Pressure variations can frequently be caused by inherent swings in production rates or,

as in the case of batch digester mills, pulping blow sequences.  Pressure interlocks can also trip

due to flow balancing issues within the various branches of the NCG system.  Temperature

interlocks in the transport system are instituted as a way to prevent excess carryover of hot

gases, foam, and liquor.  They are also used to detect flame blow‐backs through NCG piping,

inadequate cooling of NCGs, etc.  For instance, NCG temperatures could temporarily exceed

alarm limits when condensers/coolers are over‐extended, either due to variability in cooling

water temperatures or due to excess NCG flows.  As facilities have gained operating experience

with NCG systems, they have increasingly reduced manageable process variability.  However,

inherent process variability still results in the tripping of these essential safety interlocks.

#3 ‐ Pressure / Temperature Parameters on Process Equipment outside Normal Operating

Ranges – This is another category of events that occur during normal operation and can trigger

intermittent venting.  Unlike # 2 above, interlocks at or near process equipment are designed to

effectively isolate any variability that occurs within process vessels from propagating into the

transport system.  Isolating the process vessel during temporary periods of process upsets

allows the facility to isolate the problem and continue operating the NCG system.  The ability to

prevent the propagation of isolated process variability into the transport system, through the

use of a local interlock (a) effectively isolates the source of the variability, (b) averts the onset

of a more dangerous and potentially catastrophic condition in the NCG system, and (c)

minimizes potential venting as other components of the system continue to operate normally.   

#4 – Switching between incineration points – This was the identified as the fourth most

prevalent reason for intermittent venting during routine operation.  The driver for this venting

episode is primarily safety and system integrity.  As discussed in Section 5.1, flammability

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considerations prevent the use of air as the motive force while transporting LVHC gases.14  

Consequently, LVHC gases are transported to the combustion device using steam as the motive

force.  LVHC systems are designed and operated to prevent any ingression of air because of the

potential for these gases to move into the flammability range (between the LEL and UEL).  The

sequence of events that lead to intermittent venting due to switching between incineration

points is given below:

 Facilities operating LVHC systems have a backup combustion device that is “ready” to

receive LVHC gases.   

 Given the need to prevent air ingression, transfers of LVHC gases from primary to secondary

incineration devices are preceded by steam purges to remove entrained air from transfer

piping.  This steam purge requirement is frequently a permissive built into the control logic.

 As a consequence, any unplanned switching of LVHC gases between incineration devices

results in a momentary venting episode while the steam purge requirement is being

satisfied.

The only alternative to this momentary venting episode would be to maintain a constant

steam purge throughout all transfer piping between the “divert point” and the secondary

incineration device, thus continuously maintaining the permissive.  This alternative is infeasible

and economically impractical in many cases due to the distance between the primary and

secondary control device and the significant energy penalty associated with maintaining the

constant steam purge.

These four identified scenarios occur during routine operations and can trigger

intermittent venting episodes.  These conditions are not caused by malfunctions of any

associated equipment and are primarily the result of inherent process variability.  The

associated venting episodes are designed into the control system to maintain safety and system

integrity.

   

                                                           

14 The concentrations of organic compounds in LVHC (concentrated NCG) systems are typically above the UEL

thresholds.  The ingression of air could potentially dilute these gases to within flammability ranges (between the

LEL and UEL), while providing oxygen to support combustion.  This potential explosive scenario is avoided by

minimizing air entry into HVLC systems.  More details on the characteristics of NCGs and transport systems are

provided in NCASI Special Report 03‐03 (NCASI 2003).   

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Other prevalent events that trigger intermittent venting in LVHC Systems during routine

operations

# Conditions Occurring during

Normal Operation

Facilities identifying

these conditions

1. Cause

2. Reason for venting

5 Flow balancing issues or  

tripping of flow interlocks 27

 Inherent variability

 Safety

6 Steam Interlocks in Gas Transport System 22

 Inherent variability

 Safety

7 Back‐up combustion device not available 20

 Loss of permissives

 Safety

The LVHC system is an interconnected network of transport piping that collects NCGs from

various sub‐systems and transports these gases to the combustion device.  Some of these

systems tend to cycle (e.g., flows from the digester and turpentine recovery system) while

others are continuous (e.g., non‐condensible gases from the evaporator system).  Given these

varying characteristics in flows, LVHC systems are designed with flow interlocks that monitor

and protect the system from excess flows, gas blow back into the process when sub‐systems

under lower pressure operate with reduced flows, etc.   

Steam interlocks are tripped in LVHC systems when variations in process steam demands

result in momentary swings in steam flows to ejectors.  In the absence of the motive force,

LVHC gases are forced to vent, thus preventing accumulation inside the transport system and

the potential for other dangerous consequences.   

There are instances when, immediately following an LVHC gas diversion, the secondary

combustion device also becomes unavailable due to the momentary loss of permissives.  Once

again, this control device unavailability is not due to a malfunction of associated equipment but

merely a safety mechanism designed to prevent the burning of flammable NCGs in an unsafe

combustion environment.  These instances also result in venting episodes.

HVLC SYSTEMS

The following four conditions have been identified as the top events associated with

HVLC systems by the 48 facilities responding to the survey that had HVLC systems.

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# Conditions Occurring during

Normal Operation

Facilities

identifying this

condition

1. Cause

2. Reason for venting

1 Primary Combustion Device Not Available

(not due to malfunction) 27  Loss of permissives

 Safety

2 Pressure / Temperature Interlocks in Gas

Transport System 18  Inherent variability  

 Safety

3

Pressure / Temperature Parameters on

Process Equipment Outside Normal

Operating Ranges

14

 Inherent variability  

 Safety

4 Flow interlocks in transport system (overall

system flow, make‐up air flow, etc.) 14  Inherent variability  

 Safety

  

Once again, as discussed under the section on LVHC venting episodes, the leading event

that occurs during normal operation and triggers venting of HVLC systems was the

unavailability of the combustion device due to the momentary loss of permissives.  This

observation is expected given that the loss of the primary control device was also the #1 driver

for venting episodes in LVHC systems.  The #2 and #3 most frequent events are similar to those

discussed earlier under LVHC systems, except that it pertains to the HVLC systems in this case.  

The #4 condition identified in the survey (flow interlocks) stems from inherent fluctuations in

HVLC gas flows from the various components of the system like weak liquor storage tanks,

brown stock washer area storage tanks, brown stock washers (BSWs), etc.

KEY TAKEAWAYS ON INTERMITTENT VENTING EVENTS DURING NORMAL OPERATION

The following aspects are worth reiterating about the operating conditions, interlocks,

and the venting episodes described above:

 The inherent process variability that triggers these events cannot be reasonably prevented

through corrective actions and is an unavoidable part of normal, continuous operations.

 The conditions triggering these venting events are normal and expected fluctuations in

operations rather than equipment failures or operator errors, and therefore would not be

considered malfunctions of equipment, processes, or control devices.

 These venting episodes are designed to promote safety and system integrity while averting

the potential for accumulation of NCG gases within transport systems and control devices.

 Although facilities continue to make strides in reducing manageable process variability,

there is inherent variability in many of the relevant processes and waste streams that

cannot feasibly be eliminated.

 These venting events are necessary both for technological and operational reasons.

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 Lastly, the elimination of venting allowances for normal operating periods would jeopardize

system integrity, compromise safety considerations, and ultimately render safe and

continued operation infeasible.

2. Startup and shutdown (SS) conditions are distinctly different from normal operation.  A

subset of SS conditions trigger distinct interlocks and permissives within the NCG transport

system or sub‐systems, thus resulting in intermittent venting episodes.  Some of the

intermittent venting during SS conditions can be traced to unusual levels of process

variability not observed during normal operation.

The NCASI survey has identified several unique conditions, occurring during startup and

shutdown periods, that result in the temporary loss of permissives or can trip control interlocks.  

These conditions are unlike those observed during normal operation and are typically not

encountered when the mill is operating in stable production mode.  The ~ 80 facilities

responding to the survey have identified the following SS conditions that lead to venting

episodes of NCG systems:

# Venting Episodes Related to Startup / Shutdown

Conditions

Facilities

Identifying this

Condition

1. Cause

2. Reason for Venting

1 Isolated venting of process equipment before

reaching steady state

45

 SS Condition

 Isolate system and

prevent propagation into

other areas

2 Inability to resolve interlocks due to process

variability during startup and shutdown 41

 SS Condition and higher

process variability

 Safety

3

Intermittent venting of isolated sections of the

transport system due to flow balancing issues (higher

than usual variability in flows from sub‐systems)

35

 SS Condition and higher

flow variability

 Safety

4

Purge requirement of concentrated NCG line before

pulp mill start‐up (to prevent air from entering LVHC

system)

25  SS Condition

 Safety

5

Transient venting of LVHC and HVLC sources due to

slow "warm up" of boiler (low process steam

requirements)

24

 SS Condition resulting in

loss of permissives

 Safety

# 1 above occurs near process equipment and stems from unusual variability in flows

from process equipment during SS conditions.  #2 may be temperature, pressure, and flow

interlocks in the transport system that cannot be resolved due to unusual variability that exists

during SS conditions.  Issues due to flow balancing were also identified as being prevalent

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during normal operation.  While # 3 above may have the same end‐result (the venting episode),

the trigger is once again unusual process variability, germane to SS conditions.  #4 is again a

distinct SS condition that is encountered during a cold startup (when the purge requirement

has to be satisfied).

In addition to the five SS scenarios identified above, 20+ facilities identified additional

distinct conditions, from startup and shutdown periods, that cause intermittent venting of

LVHC, HVLC, and SOG systems:

1. Transient venting due to combustion device instability on startup   

2. SOG venting during steam stripper startup due to high pressure conditions which are the

result of temperature fluctuations in the steam stripper reflux condenser

3. Tramp air purge from evaporators until vacuum is achieved   

4. Venting due to high moisture caused by reduced flows and low system temperatures

5. Venting of HVLC sources due to "warm up" of thermal oxidizer    

6. Evacuating air from storage vessels to prevent air ingression into LVHC system    

7. Evaporator liquor carryover causing foaming and flame arrestor plugging   

8. False instrumentation indications (causing safety vents to open) during switching between

primary and back‐up mill power supplies   

9. Boilers not achieving the temperature needed to satisfy NCG burning permissives    

10. Evaporator hotwell venting before vacuum is established

11. Transient venting from blow heat accumulator due to air ingression during a cold start‐up.  

Steam purge used for keeping the accumulator “hot” is sometimes unsuccessful.   

The above SS conditions and the associated increased levels of variability result in the

tripping of interlocks and venting in LVHC, HVLC, and SOG systems.  In addition to SS conditions

in the steam stripper itself (# 2 above), any variability in steaming rates, steam availability, and

condensate collection during SS conditions can also cause increased levels of operational

variability in the steam stripper and lead to intermittent venting of SOGs.  Again, the primary

reason for venting is safety and system integrity.

KEY TAKEAWAYS ON INTERMITTENT VENTING EVENTS DURING STARTUP AND SHUTDOWN

Survey responses have identified several distinct SS conditions that trigger intermittent

venting events.  While the venting episode itself may be no different from a venting episode

that occurs during routine or normal operation, the triggering conditions are unique SS

conditions.  Some of these events are caused by process variability, which in many cases

exceeds the variability observed during normal operation.   

In the preamble to the RTR rule proposal, EPA has stated there was no information in

the record indicating that operations (and attendant emissions) during startup and shutdown

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conditions would differ from those during normal operation.  However, the information

obtained from this survey clearly indicates that SS conditions are not similar to normal

operations, as it pertains to NCG and SOG control systems.  Therefore, further consideration of

startup and shutdown conditions is necessary.

3. Facilities are able to distinguish between routine operating periods and startup/shutdown

(SS) periods.  Survey results indicate that majority of facilities use threshold parameters to

differentiate normal operating periods from startup and shutdown (SS) periods.  Others

have defined specific actions that are required to be carried out in order to startup or

shutdown a piece of equipment or process.

EPA had requested specific information on how facilities differentiate venting episodes

that occur during normal operation from those that occur during SS periods.  This question was

posed in the survey and the responses are discussed in detail below.  Facilities have defined

multiple threshold parameters to differentiate SS events from normal operation.  More

information on the threshold parameters used for LVHC systems, HVLC systems, and

combustion devices are provided below.15

LVHC Systems

The following four parameters were most frequently identified by facilities as “threshold

parameters” for differentiating normal operation from SS periods in LVHC systems.

# Parameter Facilities Identifying this

Parameter

1 Steam flow to digesters 42

2 Flow and Temperature of weak black liquor

feed to evaporators

34

3 Steam flow to evaporators 42

4 Total LVHC system Pressure or Flow 23

In addition to the threshold parameters identified above, 40+ facilities have identified

additional operating parameters that are used to differentiate normal operating conditions

from SS conditions.  These include:

                                                           

15 It should be noted that, as with NCG systems during normal operations, mills have continued to improve their

practices over the past dozen years to minimize venting during SS events.  As the understanding of these

practices has evolved, along with guidance from EPA and the states, in some cases the criteria mills have used

for characterizing a condition as related to SS, normal operations, or malfunctions have evolved as well.  The

following attempts to provide a snapshot of current practices.  In some cases, the criteria for distinguishing SS,

M, and normal operations may be spelled out in state regulations or as guidance in Title V permits and related

documents, but often the criteria are less rigid or explicitly specified as that.

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 Flow of strong black liquor product from evaporators ‐ foul condensate conductivity < 800

μmhos/cm AND combined condensate conductivity < 1,000 μmhos/cm

 Blow valve and relief valve opening

 Chip feed to digester (feeder rpm threshold)

 Digester steaming and blow heat system online.  SS condition continues for at least 2

digester blows to blow heat accumulator system

 Steam flow plus pressure threshold at evaporator set (LVHC for evaporators    

 Control device (boiler) operating and meeting permissives

 Flow of weak black liquor from digesters  

 Chip feed to steaming vessel

 Product liquor flow valve open and water valve to evaporators closed

 Vacuum threshold in evaporator set

 Steam flow to liquor concentrators

 Final effect evaporator and surface condenser condensate conductivity

Stripper Off‐Gas (SOG) Systems

The following four parameters were most frequently identified by facilities as “threshold

parameters” for differentiating normal operating periods from SS periods associated with

steam strippers.   

# Parameter Facilities Identifying

this Parameter

1 Condensate flow to steam stripper 35

2 Steam flow to steam stripper 27

3 SOG flow and/or other SOG parameters 13

4 Other (please specify) 14

   

In addition to the threshold parameters identified above, 14 facilities have identified

additional operating parameters that are used to differentiate normal operation from SS

conditions.  These include:

 Having both condensate flow and steam to stripper begins the Startup period.  Having

sufficient SOG flow to continuously meet permissives for at least 30 min ends the startup

period

 Control device (boiler) operating and meeting permissives

 Condensate stripper feed temperature

 Evaporator foul condensate flow

 Steam‐to‐condensate ratio

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HVLC Systems

The following three parameters were most frequently identified by facilities as

“threshold parameters” for differentiating normal operating periods from SS periods in HVLC

systems.

# Parameter Facilities Identifying

this Parameter

1 Stock flow to Brownstock washers (BSW) 30

2 Total HVLC gas flow from BSWs 15

3 Total system flow 14

In addition to the threshold parameters identified above, 15 facilities have identified

additional operating parameters that are used to differentiate normal operation from SS

conditions.  These include:

 Steam flow to digesters   

 Control device (recovery boiler) operating and meeting permissives   

 Flow of weak black liquor from digesters   

 Chip feed to steaming vessel

 Stock flow or pump amperage indicating oxygen delignification system operational

 Power to HVLC fan on

 Stock flow to knotter system   

 Steam to the chip bin (chip bin goes to LVHC system in continuous digester)

 Meeting boiler permissives

Combustion Devices

The following three parameters were most frequently identified by facilities as

“threshold parameters” for differentiating normal operating periods from SS periods in

combustion devices.

# Parameter Facilities Identifying

this Parameter

1 Primary and/or auxiliary fuel

feed rate

35

2 Steam generation rate 26

3 Combustion air feed rate 11

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In addition to the threshold parameters identified above, ~30 facilities have identified

additional operating parameters that are used to differentiate normal operation from SS

conditions.  These include:

 Flame detection    

 Combustion temperature and presence of gases (SS irrelevant if gases are diverted to

alternative device or NCG sources are down)

 Mud flow to pre‐coat filter or vacuum in pre‐coat filter  

 ID fan damper position

 Recovery furnace temperature    

 Oxygen content in flue gas    

 For a cold startup, lime kiln operating at a stable rate not less than 300 gpm of lime mud,

incineration interlocks are met, and the manual switch is in the “Accept” mode – lime mud

flow threshold dependent on number of sources collected

 For power boilers ‐ a minimum steaming rate of 120000 lb/hr.  Steam pressure > 1200 psig

 Steam flow to ejectors and permissives satisfied to burn NCG gases

 Combustion temperature

 NCG flow to thermal oxidizer

 Continuous parameter monitoring systems fully operational prior to introduction of

pollutants to combustion device

 Flame safety system operational and all permissives met

 Minimum flame temperature

 Thermal oxidizer temperature   

 Scrubber pH and flow rate, and

 Meeting boiler permissives

Twelve of the 81 facilities reported using a pre‐defined set of specific actions to

differentiate between SS conditions and normal operation.  These specific actions needed to be

carried out successfully in order for a startup or shutdown of a piece of equipment or process

to be completed.  The completion of this set of actions was subsequently used as a benchmark

to differentiate the SS condition from normal operating conditions.

KEY TAKEAWAYS ON DIFFERENTIATING STARTUP AND SHUTDOWN EVENTS FROM NORMAL

OPERATIONS

The majority of the facilities use threshold parameters to differentiate normal operating

periods from SS periods.  There is considerable variation from mill to mill, based on individual

mill configuration and operating practices.  Survey responses provide a better understanding of

the types of threshold parameters used by facilities to differentiate between these two periods.

   

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4. Malfunctions can also result in intermittent venting episodes.  Survey responses suggest

that venting episodes related to malfunctions fall into four categories, viz.; (a) those related

to process equipment, (b) those related to the thermal destruction device, (c) those related

to equipment in the transport system including sensors, gas conditioning equipment, and

fiber/liquor separation equipment, and (d) those driven by uncontrollable events.  Survey

responses indicate that events in all four categories were equally prevalent.

The industry survey has provided information on the above four categories of events.  More

details on the number of facilities responding about malfunctions are provided below:  

Category Source and Type of Malfunction Response

Process Malfunctioning process equipment (control valves, blow heat

accumulator circulation pumps, liquor heaters, etc.) 60

Transport

Equipment

Malfunctioning collection and transport system equipment (pumps,

fans, steam ejectors, flame arrestors, etc.) 62

Transport

Equipment

Malfunctioning foam breakers that cannot be repaired "on‐the fly"

(causing excessive foam carryover) 14

Transport

Equipment

Malfunctioning sensors (Pressure relief valves, temperature / flow /

pH / pressure sensors, etc.) ‐ System cannot be operated without

fixing these devices

64

Control Device Incineration device(s) unavailable due to burner plugging, flame‐

outs, tube leaks, or other major issues 60

Control Device Malfunctioning control device equipment (condensate collection

pumps, scrubber ID fans, ESP plates, etc.) 53

Uncontrollable

Events Loss of power, loss of instrument air, loss of water supply, etc. 66

   

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Facilities have identified additional examples that include:

Category Source or Type of Malfunction

Process Bark screw malfunction (malfunctioning controller)

Process Seal pot water flow interruptions

Process Unusual pressure surge due to a process malfunction causing rupture disc to fail, P/V

relief to lift, or loop seals to blow out.

Process Foaming, level control issues in stripper caused by black liquor carryover or other

contamination in the condensate feed

Process Air entrainment in blow heat system during system cool‐down during lower

throughput periods, over‐pressurization, blown loop seals and/or P/V relief valves

Transport

Equipment

Fan, ducting, demister, flame arrestor, dampers, or any other associated in‐line

equipment plugged or plugging

Transport

Equipment

Malfunction of process control systems/distributed control systems (bad I/O card,

power surge, etc.)

Transport

Equipment

HVLC fan malfunction (broken shaft, motor failure, belt failure, etc.)

Uncontrollable

events

Natural gas supply interruption due to internal or external line failure (required for

thermal oxidizer and lime kiln)

A closer examination of the most frequently identified malfunction triggers of venting

events would suggest that it is inappropriate to combine these four categories of events into a

single bucket.  The following characteristics are worth additional consideration:

 Malfunctions of isolated equipment and sensors in the transport system are expected to be

less disruptive to overall NCG system operation than are malfunctions of process equipment

and control devices.  Sub‐systems can be effectively isolated while the rest of the system

remains in operation.  

 A subset of transport system equipment problems are momentary and could stem from

inherent process variability (plugging of condensate drains, foam carryover, malfunctioning

steam ejectors etc.).  These may recur and hence are not reasonably preventable through

maintenance or corrective actions.

 Malfunctions of process equipment or combustion devices, on the other hand, are of a

different level of significance than the ones described above.

    

A closer examination of these different categories of malfunctions is therefore justified,

specifically from the stand‐points of (a) what triggers them, (b) whether they are infrequent

and reasonably preventable and (c) whether they can be classified as malfunctions, as defined

by the rule, with the option to avail of affirmative defense.  A broad‐based classification of

malfunctions, as it pertains to the NCG collection and transport system, has the potential to

significantly increase the regulatory burden for facilities.

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5. Steam stripper downtimes do not reflect “no HAP control” scenarios.  Facilities routinely

route their condensates to biological wastewater treatment systems during steam stripper

downtime periods.  Biological treatment systems have been demonstrated to achieve high

levels of treatment for methanol and major non‐methanol HAPs.  They are currently being

employed by facilities to demonstrate compliance with condensate treatment

requirements.

The following information applies to the 33 facilities that reported employing steam strippers

for demonstrating compliance with condensate treatment requirements:

 All 33 (100%) of the facilities continue to collect condensates in the condensate tank

during temporary outages.  Temporary outages or downtimes may be the result of

momentary unavailability of the combustion devices (due to momentary loss of

permissives etc.), or temporary operational issues with steam availability, etc.

 The following practices apply to longer downtimes of the steam stripper

o 20 out of the 33 facilities route condensates through the primary clarifier to

biological treatment systems

o 6 facilities bypass the primary clarifier and directly route condensates to the

biological wastewater treatment system

o Remainder of the facilities reported utilizing different condensate reuse,

recycling, or re‐routing practices.   

o 3 of the facilities that also operate HVLC systems reported routing their

condensates back to liquor storage tanks (the tanks are air‐swept and collected

as part of the HVLC system).

Survey responses indicate that the vast majority of facilities continue to achieve HAP

treatment during steam stripper outages/downtimes.  Downtime periods in the steam stripper

do not mean that the facility is achieving zero HAP control from condensate treatment.  

Facilities routing condensates to biological treatment systems are expected to achieve greater

than 80% methanol removal.

   

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6. Compilation of applicable state‐specific recording, reporting, and other requirements

pertaining to NCG venting events

In discussions leading up to the distribution of the NCASI survey, OAQPS

requested specific information on restrictions, if any, imposed by States on the duration

of single NCG venting episodes.  This request was in response to comments filed by The

State of Maine Department of Environmental Protection (Maine DEP) on the proposed

elimination of the venting allowances.  In its comments, Maine DEP urged EPA to

maintain the 1% and 4% venting allowances.  The agency indicated that the state TRS

rule (06‐096 CMR Ch. 124) limits any single LVHC system vent to 40 minutes.  Maine DEP

also indicated that the 40 minute individual vent limit imposed as part of the TRS rule, in

conjunction with venting allowances, was effective in minimizing the total duration of

venting.    

The agency also acknowledges the fact that intermittent NCG venting episodes

are inevitable given the complexity of the system and the need to deliver flammable

NCG gases safely to combustion devices.  A compilation of alternate rule or other

applicable State requirements pertaining to the recording, reporting, and classifying of

NCG venting episodes, as reported by facilities responding to this survey, is provided

below.

   

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State Alternate State rule

OR operating permit

threshold for

recording vents

(MINUTES)

Threshold above which a

SINGLE VENTING EVENT

is further investigated

and recorded as a

MALFUNCTION

(MINUTES)

State/Operating permit

that limits individual

venting events from

exceeding a specific

threshold (MINUTES)

LVHC/SOG HVLC LVHC/SOG HVLC LVHC/SOG HVLC

AL 60 60 240 240

GA 5 5 30 30

MS     240      

AR 1 30 30

SC     60 60    

TN 15

NC 240 240    

VA 60 60

WI     120 480    

ME 1 1 15 240 40

OR     60    60   

WA 1 600 1

       

1 600 minutes of total LVHC venting allowed per month

As indicated in the Table, a handful of states impose limits on the duration of individual

LVHC system vents.  Arkansas, Oregon, and Alabama impose limits of 30, 60, and 240 minutes

for any individual vent from the LVHC system.  The state of Washington imposes a cumulative

monthly limit of 600 minutes for vents from the LVHC system.   

In addition to limiting the duration of individual vents, several states also impose

duration limits above which any single venting event needs to be further investigated to

identify the root cause and prevent recurrence.  This duration limit varied from State to State

and ranged from 15 minutes to 240 minutes.

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Attachment 2 

Attachment A, NCASI Non Condensible Gas Venting Survey Questionnaire, May 

2012 

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Low Volume High Concentration (LVHC) System High Volume Low Concentration (HVLC) System Stripper-off-Gas (SOG) System

SOG collected and treated in dedicated system

GENERAL QUESTIONS

Facility Details _ Company, City, and State

Describe your facility's NCG Collection Practices (please select all that apply)

Incineration Points for LVHC System

Primary Incineration Point

Secondary Incineration Point 

Tertiary Incineration Point 

Incineration Points for SOG System

Primary Incineration Point 

Secondary Incineration Point 

Tertiary Incineration Point 

Incineration Points for HVLC System

Primary Incineration Point

Secondary Incineration Point 

Tertiary Incineration Point 

QUESTIONS ON VENTING EVENTS

Qualtrics Survey Software https://new.qualtrics.com/ControlPanel/PopUp.php?PopType=SurveyPri...

1 of 7 6/27/2012 12:07 PM

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HVLC Collection and Incineration

Clean Condensate Alternative (CCA)

Approved Alternative Approach

LVHC System Venting Events

From the list below., RANK the TOP SIX causes of venting events (NOT including SSM). Rank the events

"1" thru "6". 

In the absence of information to RANK these events, please SELECT the TOP SIX by entering an "x" in

the corresponding boxes.

By # of

Occurrences

By Total

Duration

Low chip level in the Chip Bin 

Flow balancing issues 

Pressure or Temperature Parameters on Process Equipment outside normal operating ranges 

Flow Interlocks at or near Process Equipment (low flow to secondary blow heat condenser, etc.) 

Pressure, Temperature, Flow Interlocks at the Steam Stripper 

Pressure or Temperature Interlocks in Gas Transport System (overall system pressure, frequent digester

blows, process variability, etc) 

Temperature interlocks in Gas Conditioning System (condenser exit temp., cooling water temperature,

etc.) 

Flow Interlocks in Gas Transport System (overall system flow, cooling water flow, etc.) 

Steam Interlocks in Gas Transport System (Steam flow in Ejectors) 

Primary combustion device not available (low steam rate, loss of burner permissive, flame-out etc.) 

Back-up combustion device also unavailable 

Switching between incineration points 

Other (please specify)

 

Describe your facility's MACT I Phase 2 compliance approach {please select all that apply]

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Total number (SSM + non-SSM) of Venting events

Total duration of venting events (SSM + non-SSM) in MINUTES

Number of non-SSM venting events

Duration of non-SSM events in MINUTES (counts towards the 1% excess emissions limit)

Enter YYYY of alternative reporting period if used

Total number (SSM + non-SSM) of Venting events

Total duration of venting events (SSM + non-SSM) in MINUTES

Number of non-SSM venting events

Duration of non-SSM events in MINUTES (counts towards the 1% excess emissions limit)

Enter YYYY of alternate reporting period if used

HVLC System Venting Events

From the list below., RANK the TOP SIX causes of venting events (NOT including SSM). Rank the events

"1" thru "6". 

In the absence of information to RANK these events, please SELECT the TOP SIX by entering an "x" in

the corresponding boxes.

By # of

Occurrences

By Total

Duration

Low chip levels in chip bin 

Flow balancing issues 

Pressure or Temperature parameters on Process Equipment outside normal operating ranges 

Flow Interlocks in Isolated Process Equipment (washers, chip bins, etc.) 

Temperature interlocks in Gas Conditioning System (condenser exit temp., cooling water temperature,

etc.) 

Pressure or Temperature Interlocks in Gas Transport System (condenser exit temp, system pressure,

etc.) 

Flow Interlocks in Gas Transport System (overall system flow, make-up air flow, etc.) 

Steam Interlocks in Gas Transport System (Steam flow in Ejectors) 

Primary combustion device not available (low steam rate, loss of burner permissive, flame-out etc.) 

Backup combustion device (if applicable) not ready 

No Backup system _ Primary combustion device outage for maintenance 

Switching between incineration points 

Other (please specify) 

Total Number and Duration (in MINUTES) of LVHC Venting Events in FIRST reporting period of 2011 (January -

June)

Please select alternative reporting period (2009 or 2010) if facility had unusual incidents in 2011

Total Number and Duration (in Minutes) of LVHC Venting Events in SECOND reporting period of 2011 (July -

December)

Please select alternative reporting period (2009 or 2010) if facility had unusual incidents in 2011

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Total number (SSM + non-SSM) of Venting events

Total duration of venting events (SSM + non-SSM) in MINUTES

Number of non-SSM venting events

Duration of non-SSM events in MINUTES (counts towards the 4% excess emissions limit)

Enter YYYY of alternate reporting period if used

Total number (SSM + non-SSM) of Venting events

Total duration of venting events (SSM + non-SSM) in MINUTES

Number of non-SSM venting events

Duration of non-SSM events in MINUTES (counts towards the 4% excess emissions limit)

Enter YYYY of alternate reporting period if used

Steam flow to digesters

Flow and Temperature of weak black liquor feed to evaporators

Steam flow to evaporators

Total LVHC system Pressure or Flow

Other (Please specify)

Other (please specify)

Total Number and Duration (in MINUTES) of HVLC Venting Events in FIRST reporting period of 2011 (Jan -

June)

Please select alternative reporting period (2009 or 2010) if facility had unusual incidents in 2011

Total Number and Duration (in MINUTES) of HVLC Venting Events in SECOND reporting period of 2011 (July -

December)

Clarification: Please select alternative reporting period (2009 or 2010) if facility had unusual incidents in

2011

Defining Startup, Shutdown, and Malfunction (SSM)

Identify all applicable Threshold parameters used to define Start-up/Shutdown (SS) conditions in the LVHC

system [please select all that apply]

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Condensate flow to steam stripper

Steam flow to steam stripper

SOG flow and/or other SOG parameters

Other (please specify)

Other (Please specify)

Stock flow to Brownstock washers (BSW)

Total HVLC gas flow from BSWs

Total system flow

Other (please specify)

Other (Please specify)

Primary AND/OR Auxiliary fuel feed rate

Steam generation rate

Combustion air feed rate

Other (please specify)

Other (Please specify)

Purge requirement of concentrated NCG line before pulp mill start-up (to prevent air from entering LVHC system)

Transient venting of LVHC and HVLC sources due to slow "warm up" of boiler (low process steam requirements)

Isolated venting of process equipment before reaching steady state

Intermittent venting of isolated sections of the transport system due to flow balancing issues

Inability to resolve interlocks due to process variability during start-up and shutdown

Other (Please specify)

Threshold parameters used to define Start-up/Shutdown (SS) conditions in the Steam Stripper and SOG System

[please select all that apply]

Threshold parameters used to define Start-up/Shutdown (SS) conditions in the HVLC System [please select all

that apply]

Threshold parameters and conditions used to define Start-up/Shutdown (SS) conditions in the Incineration

Device(s) [please select all that apply]

Examples of Venting events that could occur during Start-up and Shutdown periods (check all that apply)

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Malfunctioning process equipment (control valves,accumulator circulation pumps, liquor heaters, etc.)

Malfunctioning collection and transport system equipment (pumps, fans, steam ejectors, flame arrestors etc.)

Malfunctioning foam breakers that cannot be repaired "on-the fly" (causing excessive foam carryover)

Malfunctioning sensors (Pressure relief valves, temperature / flow / pH / pressure sensors etc.) - System cannot be operated without

fixing these devices

Incineration device(s) unavailable due to burner plugging, flame-outs, tube leaks OR other major issues

Malfunctioning control device equipment (condensate collection pumps, scrubber ID fans, ESP plates, etc.)

Loss of power, loss of instrument air, loss of water supply, etc.

Other (Please specify)

Other (please specify)

Other (please specify)

Other (please specify)

Yes

No

Continue collecting condensates in condensate tank for TEMPORARY OUTAGES

Route condensates through primary clarifier and biological wastewater treatment system FOR LONGER OUTAGES and DURING

MAINTENANCE DOWNTIME

Bypass primary clarifier and route condensates to biological wastewater treatment system FOR LONGER OUTAGES and DURING

MAINTENANCE DOWNTIME

Other (please specify)

Defining a MALFUNCTION _ Categories of Malfunctions in NCG collection and treatment [please select all that

apply]

Steam Stripper Practices

Does your facility operate a Steam Stripper for complying with the condensate treatment requirements under

MACT?

Condensate collection and treatment practices during Steam Stripper downtime periods (check all that apply)

Recording / Reporting Thresholds for Venting Events

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Recording and Reporting of Venting events (if these questions are not applicable for your facility, enter

"X" in Not Applicable)

LVHC / SOG System HVLC System Not Applicable

RECORDING THRESHOLD - What is the

minimum threshold (in MINUTES) for

recording venting events at your facility?

 

Is there a NESHAP, an alternate State rule,

OR operating permit threshold (in

MINUTES) for recording vents at your

facility?

 

Is there a Threshold (in MINUTES) above

which your State requires any SINGLE

VENTING EVENT to be further investigated

and recorded as a MALFUNCTION?

 

Does your State/Operating permit LIMIT

individual venting events from exceeding a

specific threshold (in MINUTES)? e.g., the

state of Maine limits individual venting

events from exceeding 40minutes

 

Please Add any Additional Comments OR Clarifications in this Section.

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Attachment 3 

Attachment B, Recommended Good Practice Thermal Oxidation of Waste 

Streams in Black Liquor Recovery Boilers, The Black Liquor Recovery Boiler 

Advisory Committee (BLRBAC), February, 2012 

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RECOMMENDED GOOD PRACTICE

THERMAL OXIDATION OF WASTE STREAMS

IN 

BLACK LIQUOR RECOVERY BOILERS

THE BLACK LIQUOR RECOVERY BOILER ADVISORY COMMITTEE

February 2012

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Page 2 

Notice and Disclaimer of Liability Concerning Recommended Guidelines and 

Procedures

BLRBAC brings together volunteers from operating companies, manufacturers and 

insurance companies representing varied viewpoints and interests to achieve consensus 

on Guidelines and Recommended Practices for the safe operation of recovery boilers. 

While BLRBAC facilitates this process, it does not independently test, evaluate or verify 

the accuracy of any information or the soundness of any judgments contained in its 

Recommended Guidelines and Procedures. 

BLRBAC disclaims liability for any personal injury, property or other damages of any 

nature whatsoever, whether special, indirect, consequential or compensatory, directly or 

indirectly resulting from the publication, use of, or reliance on BLRBAC Guidelines and 

Recommended Practices. BLRBAC also makes no guaranty or warranty as to the 

accuracy or completeness of any information published herein. 

In issuing and making this document available, BLRBAC is not undertaking to render 

professional or other services of or on behalf of any person or entity. Nor is BLRBAC 

undertaking to perform any duty owed by any person or entity to someone else. Anyone 

using BLRBAC Guidelines and Recommended Practices should rely on his or her own 

independent judgment or, as appropriate, seek the advice of a competent professional in 

determining the exercise of reasonable care in any given circumstance.

Users of BLRBAC Guidelines and Recommended Practices should consult applicable 

federal, state and local laws and regulations relating to the safe manufacture and 

operation of recovery boilers. BLRBAC does not, by the publication of its Guidelines and 

Recommended Practices intend to urge action that is not in compliance with applicable 

laws, and its publications may not be construed as doing so. 

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Table of Contents 

CHANGES .................................................................................................................................................... 7

CHAPTER 1 INTRODUCTION................................................................................................................. 8

CHAPTER 2 DEFINITIONS AND ABBREVIATIONS .........................................................................10

CHAPTER 3 MAJOR CONSIDERATIONS............................................................................................13

3.1 INTRODUCTION ....................................................................................................................................13

3.2 EXPLOSION ..........................................................................................................................................13

3.3 TURPENTINE HAZARDS........................................................................................................................15

3.4 EMERGENCY SHUTDOWN PROCEDURE (ESP)......................................................................................15

3.5 CORROSION .........................................................................................................................................15

3.6 THE EFFECT OF SULFUR INPUT AND SOLIDS CONCENTRATION ON SO2 ...............................................16

3.7 THE EFFECT OF SOG INPUT ON NOX EMISSIONS.................................................................................17

3.8 HEALTH CONSIDERATIONS ..................................................................................................................18

3.9 SYSTEM COMPLEXITY .........................................................................................................................18

3.10 INTEGRATION/RELIABILITY OF TRANSPORT SYSTEMS.......................................................................19

3.11 INPUT.................................................................................................................................................19

3.12 CONDITION OF THE RECOVERY BOILER.............................................................................................20

CHAPTER 4 GUIDELINES FOR THERMAL OXIDATION OF DNCG ............................................21

4.1 INTRODUCTION ....................................................................................................................................21

4.1.1 Safety...........................................................................................................................................21

4.1.2 Sources........................................................................................................................................21

4.1.3 Recovery Boiler Introduction System..........................................................................................22

4.2 COLLECTION AND TRANSFER OF DNCG..............................................................................................23

4.2.1 Collection of DNCG....................................................................................................................23

4.2.2 Chip Bin Gas...............................................................................................................................23

4.2.3 Dissolving Tank Vent Gases........................................................................................................23

4.2.4 DNCG Transfer System...............................................................................................................24

4.2.5 DNCG Piping System and Auxiliary Equipment.........................................................................25

4.3 MONITORING AND CONTROL...............................................................................................................26

4.4 SAFETY SYSTEMS ................................................................................................................................27

4.4.1 Permissive Starting Logic - DNCG.............................................................................................27

4.4.2 Protective Tripping Logic - DNCG.............................................................................................27

4.5 PERSONNEL SAFETY ............................................................................................................................28

CHAPTER 5 GUIDELINES FOR THERMAL OXIDATION OF CNCG AND SOG .........................35

5.1 INTRODUCTION ....................................................................................................................................35

5.1.1 Safety...........................................................................................................................................35

5.1.2 Sources........................................................................................................................................35

5.1.3 Dedicated Burner........................................................................................................................36

5.1.4 The Recovery Boiler as Primary Control Device........................................................................36

5.2 COLLECTION AND TRANSFER OF CNCG AND SOG .............................................................................36

5.2.1 CNCG..........................................................................................................................................37

5.2.2 SOG.............................................................................................................................................39

5.2.3 CNCG and SOG Piping System and Auxiliary Equipment..........................................................40

5.3 THERMAL OXIDATION .........................................................................................................................42

5.3.1 Burner.........................................................................................................................................42

5.3.2 Continuous Igniter ......................................................................................................................42

5.3.3 Combustion Air...........................................................................................................................43

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5.4 SAFETY SYSTEM ..................................................................................................................................43

5.4.1 Permissive Starting Logic - CNCG .............................................................................................43

5.4.2 Protective Tripping Logic - CNCG .............................................................................................44

5.4.3 Permissive Starting Logic - SOG ................................................................................................44

5.4.4 Protective Tripping Logic - SOG ................................................................................................45

5.5 PERSONNEL SAFETY ............................................................................................................................45

5.6 SYSTEM DESCRIPTION AND OPERATION ..............................................................................................46

5.6.1 Description..................................................................................................................................46

5.6.2 Operation ....................................................................................................................................47

CHAPTER 6 LIQUID WASTE STREAMS BLENDED WITH BLACK LIQUOR.............................60

6.1 INTRODUCTION ....................................................................................................................................60

6.2 METHANOL..........................................................................................................................................62

6.3 SECONDARY SLUDGE...........................................................................................................................67

6.4 SOAP....................................................................................................................................................69

6.5 SPENT ACID FROM CLO2 AND TALL OIL BRINE ...................................................................................74

6.6 TALL OIL.............................................................................................................................................79

6.7 TURPENTINE ........................................................................................................................................84

CHAPTER 7 GUIDELINES FOR THERMAL OXIDATION OF LIQUID WASTE STREAMS IN 

DEDICATED BURNERS ...........................................................................................................................90

7.1 INTRODUCTION ....................................................................................................................................90

7.2 SAFETY................................................................................................................................................91

7.2.1 System Safety...............................................................................................................................91

7.2.2 Personnel Safety..........................................................................................................................91

7.3 DESCRIPTIONS OF LIQUID WASTE STREAMS EXPECTED TO BE FIRED IN DEDICATED BURNERS ..........93

7.3.1 Methanol .....................................................................................................................................93

7.3.2 Turpentine and Red Oil...............................................................................................................94

7.3.3 Crude Tall Oil.............................................................................................................................95

7.4 RECOMMENDED WASTE STREAM CHARACTERISTICS ..........................................................................96

7.4.1 Basic Acceptable Characteristics for Combustion in a Dedicated Burner.................................96

7.4.2 Characteristics of Class A Waste Streams..................................................................................96

7.4.3 Characteristics of Class B Waste Streams..................................................................................97

7.4.4 Characteristics of Class C Waste Streams..................................................................................97

7.5 DEDICATED BURNERS FOR THERMAL OXIDATION...............................................................................97

7.5.1 All Dedicated Burners .................................................................................................................97

7.5.2 Burners Firing Class A Streams .................................................................................................98

7.5.3 Burners Firing Class B Streams .................................................................................................98

7.6 PROTECTIVE STARTING AND TRIPPING LOGIC .....................................................................................98

CHAPTER 8 GUIDELINES FOR THERMAL OXIDATION OF CHIP BIN NCG..........................100

8.1 INTRODUCTION ..................................................................................................................................100

8.1.1 Safety.........................................................................................................................................100

8.1.2 Flammability of CBNCG...........................................................................................................100

8.2 COLLECTION AND TRANSFER OF CBNCG .........................................................................................102

8.2.1 CBBNCG Conditioning System.................................................................................................102

8.2.2 Recovery Boiler Introduction System........................................................................................102

8.2.3 Chip Bin NCG Transfer System ................................................................................................106

8.2.4 CBNCG Piping System and Auxiliary Equipment.....................................................................109

8.3 MONITORING AND CONTROL.............................................................................................................110

8.4 SAFETY SYSTEM ................................................................................................................................110

8.4.1 Permissive Starting Logic – CBNCG – Fan Delivery ...............................................................110

8.4.2 Protective Tripping Logic – CBNCG – Fan Delivery ...............................................................111

8.4.3 Permissive Starting Logic – CBNCG – Steam Ejector Delivery ...............................................117

8.4.4 Protective Tripping Logic – CBNCG – Steam Ejector Delivery ...............................................117

8.5 PERSONNEL SAFETY ..........................................................................................................................123

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APPENDIX A DOCUMENT REVISION HISTORY............................................................................124

Table of Figures

FIGURE 1 DNCG TRANSFER SYSTEM. ............................................................................................................29

FIGURE 2 DNCG PERMISSIVE STARTING LOGIC ............................................................................................30

FIGURE 3 DNCG INJECTION PROTECTIVE TRIPPING LOGIC. ...........................................................................32

FIGURE 4 DNCG TRANSFER SYSTEM OF DISSOLVING TANK VENT. ...............................................................34

FIGURE 5 CNCG AND SOG TRANSFER SYSTEMS. ..........................................................................................50

FIGURE 6 CNCG & SOG SINGLE BURNER FOR THERMAL OXIDATION IN RECOVERY BOILER. ......................51

FIGURE 7 WASTE SYSTEM BURNER PERMISSIVE STARTING LOGIC FOR CNCG .............................................52

FIGURE 8 WASTE STREAM BURNER PROTECTIVE TRIPPING LOGIC FOR CNCG. ............................................54

FIGURE 9 WASTE STREAM BURNER PERMISSIVE STARTING LOGIC FOR SOG................................................56

FIGURE 10 WASTE STREAM BURNER PROTECTIVE TRIPPING LOGIC FOR SOG. .............................................58

FIGURE 11 PERMISSIVE STARTING LOGIC FOR METHANOL. ...........................................................................65

FIGURE 12 TRIPPING LOGIC FOR METHANOL. ................................................................................................66

FIGURE 13 PERMISSIVE STARTING LOGIC FOR SOAP. .....................................................................................72

FIGURE 14 TRIPPING LOGIC FOR SOAP. ..........................................................................................................73

FIGURE 15 PERMISSIVE STARTING LOGIC FOR SPENT ACID WHEN ADDED AFTER POINT OF FINAL 

CONCENTRATION. .................................................................................................................................77

FIGURE 16 TRIPPING LOGIC FOR SPENT ACID WHEN ADDED AFTER POINT OF FINAL CONCENTRATION. ........78

FIGURE 17 PERMISSIVE STARTING LOGIC FOR TALL OIL. ..............................................................................82

FIGURE 18 TRIPPING LOGIC FOR TALL OIL. ....................................................................................................83

FIGURE 19 PERMISSIVE STARTING LOGIC FOR TURPENTINE. ..........................................................................88

FIGURE 20 TRIPPING LOGIC FOR TURPENTINE. ...............................................................................................89

FIGURE 21 EXAMPLE - CBNCG VENT CONDENSING SYSTEM. ......................................................................105

FIGURE 22 EXAMPLE - CBNCG FAN DELIVERY SYSTEM. .............................................................................107

FIGURE 23 EXAMPLE - CBNCG EJECTOR DELIVERY SYSTEM. ......................................................................108

FIGURE 24 CBNCG FAN DELIVERY PERMISSIVE STARTING LOGIC. ............................................................112

FIGURE 25 CBNCG FAN DELIVERY TRIPPING LOGIC. .................................................................................114

FIGURE 26 CBNCG STEAM EJECTOR DELIVERY PERMISSIVE STARTING LOGIC. .........................................118

FIGURE 27 CBNCG STEAM EJECTOR DELIVERY TRIPPING LOGIC. ..............................................................120

Table of Tables

TABLE 1 EXPLOSION LIMITS OF NCG CONSTITUENTS....................................................................................13

TABLE 2 HEATS OF COMBUSTION FOR NCG COMPONENTS............................................................................20

TABLE 3 LOGIC EXPLANATION CHART FOR FIGURE 2 - DNCG INJECTION PERMISSIVE STARTING LOGIC .....31

TABLE 4 LOGIC EXPLANATION CHART FOR FIGURE 3 - INJECTION PROTECTIVE TRIPPING LOGIC..................33

TABLE 5 VALVE STATUS AND ACTIONS AT MFT AND ESP; FIGURES 5 AND 6................................................49

TABLE 6 LOGIC EXPLANATION CHART FOR FIGURE 7 PERMISSIVE STARTING LOGIC - WASTE STREAMS 

BURNER................................................................................................................................................53

TABLE 7 LOGIC EXPLANATION CHART FOR FIGURE 8 PROTECTIVE TRIPPING LOGIC - WASTE STREAM 

BURNER................................................................................................................................................55

TABLE 8 LOGIC EXPLANATION CHART FOR FIGURE 9 PERMISSIVE STARTING LOGIC FOR SOG - WASTE 

STREAMS BURNER ................................................................................................................................57

TABLE 9 LOGIC EXPLANATION CHART FOR FIGURE 10 PROTECTIVE TRIPPING LOGIC FOR SOG - WASTE 

STREAM BURNER..................................................................................................................................59

TABLE 10 RISK FACTORS AFFECTING THE FLAMMABILITY OF CHIP BIN NCG.............................................101

TABLE 11 EXPLANATION CHART FOR CBNCG INJECTION PERMISSIVE STARTING LOGIC - FAN DELIVERY 

FOR FIGURE 24....................................................................................................................................113

TABLE 12 EXPLANATION CHART FOR CBNCG INJECTION PROTECTIVE TRIPPING LOGIC - FAN DELIVERY FOR 

FIGURE 25...........................................................................................................................................115

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TABLE 13 EXPLANATION CHART FOR CBNCG INJECTION PERMISSIVE STARTING LOGIC - STEAM EJECTOR 

DELIVERY FOR FIGURE 26...................................................................................................................119

TABLE 14 EXPLANATION CHART FOR CBNCG INJECTION PROTECTIVE TRIPPING LOGIC - STEAM EJECTOR 

DELIVERY FOR FIGURE 27...................................................................................................................121

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Page 7 

CHANGES

February 2012 

“Notice of Disclaimer of Liability” has been added to page 2.

For a summary of prior changes to this document refer to Appendix A, Document 

Revision History. 

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CHAPTER 1 INTRODUCTION

The black liquor recovery boiler presents problems of operation and safety that far 

exceed those of the conventional power boiler or other forms of combustion equipment 

that can be used for the thermal oxidation of waste streams. The recovery boiler is 

primarily a chemical recovery process unit in which organic materials in the black liquor 

are burned while the oxidized sulfur compounds of sodium and potassium are reduced 

and drained as molten smelt from the furnace bottom. At the same time, the heat released 

is used for generation of steam for power and process. 

This document is intended to address concerns of the industry relating to safe thermal 

oxidation of waste streams in recovery boilers. “Waste streams” for this document are 

produced in the pulping process. The major waste stream is noncondensible gases (NCG), 

which are gases that contain reduced sulfur compounds from the digester and evaporator 

operations and are a source of odor. The following list is representative of the pulping 

process waste streams that are addressed:

• Dilute Noncondensible Gas (DNCG) 

• Concentrated Noncondensible Gas (CNCG) 

• Stripper Off Gas (SOG)

• Chip Bin Noncondensible Gas (CBNCG) 

• Dissolving Tank Vent Gas (DTVG) 

• Soap

• Methanol 

• Turpentine 

• Tall Oil

• Spent Acid

• Secondary Sludge 

The principal process benefit to thermally oxidizing these streams in the recovery furnace 

is that the sulfur content of the streams can be retained within the process rather than be 

discharged to the surroundings. While most of the heat for the chemical recovery process 

is from the burning of black liquor, the waste streams may introduce additional heat and 

moisture into the furnace. 

The thermal oxidation of waste streams in the recovery boiler increases the complexity of 

the operation as well as the potential safety risks in the recovery boiler building. This 

Recommended Good Practice for the Thermal Oxidation of Waste Streams in Black 

Liquor Recovery Boilers should be reviewed regarding equipment, safety systems and 

operating procedures for the design and operation of waste stream systems installed on 

the recovery boiler. Information included in this Good Practice can assist in minimizing 

the risk for the operating company that chooses to thermally oxidize any of these streams 

in the recovery boiler. 

The complexity of the chemical recovery process and the severe environment combine to 

present a formidable challenge to operators of recovery boilers. The difficulty of the 

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operation is increased if the waste streams are thermally oxidized in the recovery furnace. 

Further, there is a potential to degrade the environment in the recovery boiler building 

with the introduction of waste streams. In most cases, the recovery boiler operators must 

depend on the thoroughness of their training, their own personal senses and reactions, and 

instrumentation to aid in safe operation. Many times the operators are forced to evaluate a 

situation rapidly, and it is hoped, correctly, without having all of the facts. The burden on 

the recovery boiler operator is truly great and the industry has realized that they must 

have help, guidance and proper tools to promote safety and boiler availability. These take 

on increased importance in a mill that introduces waste streams into the recovery boiler.

The Waste Streams Subcommittee was formed in 1997 to evaluate the experience with 

thermal oxidation of liquid and gaseous waste streams in the recovery boiler. The 

industry experience level had evolved at that time with a substantial number of recovery 

boilers thermally oxidizing both DNCG and CNCG. The considerable experience with 

burning NCG in other control devices, such as bark boilers and lime kilns, had resulted in 

substantial advances in technology and operation of collections systems and combustion 

of NCG. After evaluation of the industry experience, the Waste Streams Subcommittee 

determined with the agreement of the Executive Committee that there was justification to 

develop recommended BLRBAC guidelines for using the recovery boiler as an emission 

control device. The result is this Recommended Good Practice for Thermal Oxidation of 

Waste Streams in Black Liquor Recovery Boilers. 

The following publications are additional references concerning thermal oxidation of 

waste streams in recovery boilers, and they were part of the foundation upon which this 

document was prepared. 

Soda House Committee of the Swedish Steam Users Association:

• Guidelines Regarding Equipment and Safety Systems for Destruction of 

Concentrated NCG, Methanol and Turpentine in Recovery Boilers, Publication No. 

B16. 

• Destruction by Means of Combustion of LVHC Gases, Methanol and Turpentine in 

Black Liquor Recovery Boilers, Publication No. C9. 

• Recommendations Concerning Equipment and Safety Systems for Oil and Gas 

Firing in Black Liquor Recovery Boilers, Publication No. B13. 

Finnish Recovery Boiler Association:

• Recommended Procedure for Incineration of Noncondensible Gases. 

FM Global: 

• Property Loss Prevention Data Sheet 6-21, Chemical Recovery Boilers. 

• Property Loss Prevention Data Sheet 6-13, Waste Fuel-Fired Boilers.

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CHAPTER 2 DEFINITIONS AND ABBREVIATIONS

Terms that are used in the Recommended Good Practice are defined. Definitions where 

applicable are used as they appear in the Final Pulp and Paper Cluster Rule (63 FR 

18504-18751). 

Chip bin: A vessel used for the purpose of preheating or pretreating wood chips prior to 

the digester, using flash steam from the digester or live steam.

Chip Bin Non-Condensible Gas (CBNCG) – Gas containing a concentration of sulfur 

compounds and/or turpentine, methanol and other hydrocarbons that is generated from 

the pre-steaming of chips prior to entering the Digester. As a consequence, this source of 

NCG will normally be high in oxygen content and can, under upset Chip Bin operation, 

exceed 100% LEL.

Control device or combustion device: An individual unit of equipment, including but 

not limited to, a thermal oxidizer, lime kiln, recovery furnace, process heater, or boiler, 

used for the thermal oxidation of organic hazardous air pollutant vapors or combustible 

liquids extracted in the process, such as, turpentine or methanol. These Guidelines will 

only take into consideration the recovery furnace as the control device. 

Concentrated noncondensible gas (CNCG): Gas containing a concentration of sulfur 

compounds and/or turpentine, methanol and other hydrocarbons that is ideally above the 

upper explosion limit (UEL), frequently referred to as Low Volume, High Concentration 

gases (LVHC). The CNCG definition is exclusive of volume. 

CNCG system: The gas collection and transport system used to convey gases from the 

CNCG sources to the recovery boiler, or other combustion device. Sources are closed 

systems (no air intrusion) and may include: digesters, turpentine recovery, evaporators, 

and steam stripper systems.

Dilute noncondensible gas (DNCG): Gas containing a concentration of sulfur 

compounds that is below the lower explosion limit (LEL), frequently referred to as High 

Volume, Low Concentration Gases (HVLC). The DNCG definition is exclusive of 

volume. 

DNCG system: The gas collection and transport system used to convey gases from the 

DNCG system to the recovery boiler, or other combustion device. Sources may include 

pulp washing, knotter, screen, decker, and oxygen delignification systems, black liquor 

storage tanks, and boiler house chemical ash mix tank. 

Dissolving Tank Vent Gas (DTVG): The exhaust from the dissolving tank, considered a 

DNCG. This gas is primarily air and steam with particulate, green liquor droplets, and 

other compounds. 

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Dissolving Tank Vent Gas System: The gas collection, cleanup and transport system 

used to convey gases from the dissolving tank to the furnace. 

ESP: emergency shutdown procedure (ESP) - A shutdown procedure that must be 

performed whenever any amount of water is known or suspected to be entering the 

furnace and cannot be stopped immediately. 

Flame propagation: The velocity at which a flame will travel through a flammable 

vapor. 

Flammable: Refers to a fuel, which could be gaseous, liquid, or solid, that is explosive, 

easy to ignite and/or burns quickly. 

Flash Steam: Steam derived from the flashing of hot, pressurized liquor extracted from 

the digester. Flash steam is used for pre-steaming chips in the Digester Steaming Vessel 

and in the Chip Bin and is rich in turpentine, methanol, and TRS. 

High Volume, Low Concentration (HVLC): Another name for DNCG.

Lower Explosion Limit (LEL): A concentration by volume of a compound in air below 

which the mixture will not catch on fire. Also called Lower Flammability Limit (LFL). 

Low volume, high concentration (LVHC): Another name for CNCG.

Maximum Continuous Rating (MCR): The maximum design/nameplate steaming rate 

or liquor firing rate for a recovery boiler. 

Methanol (CH30H): A by-product created during the pulping and bleaching process by 

the degradation of the methoxy groups on hemicellulose and lignin. Methanol is 

flammable and provides positive net Btu value. Methanol is water soluble and may be 

found in solution or as a vapor. 

Noncondensible gas (NCG): Refers to the gases containing sulfur and/or organic 

compounds, i.e., CNCG, DCNG, and SOG. Some mills refer to NCG as TRS gases. 

Recovery boiler building (or area): The boundary used within a mill to identify the 

areas around a recovery boiler that are affected by an ESP. Personnel are not to enter 

these areas until after an ESP is completed and entry is permitted.

Red oil: A mixture of terpenes and TRS compounds. “Red oil” is highly contaminated 

turpentine with a lower flash point and a higher sulfur content. For these guidelines, red 

oil should be treated as turpentine. 

Secondary Sludge: The waste residue resulting from the biological treatment of 

wastewater.

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Soap: A by-product formed during the pulping process by the reaction of alkali and fatty 

wood acids. 

Spent Acid: The aqueous solution by-product from the acidulation of tall oil soap to tall 

oil, usually consisting primarily of sodium sulfate in water solution. ClO2 spent acid is 

the effluent from a ClO2 generator. The term “spent acid” is used to refer to both tall oil 

brine and ClO2 spent acid.

SSV: Safety shutoff valve.

Stripper Off-Gas (SOG): Methanol, reduced sulfur gases and other volatiles removed 

by a steam stripping and distillation process from digester and condenser condensates 

(this definition deviates from the Cluster Rule definition).

Tall Oil: A mixture of fatty acids, rosin and neutral materials resulting from the 

acidulation of soap skimmings from kraft black liquor. 

Total reduced sulfur (TRS): The total sulfur compounds existing in gaseous sulfate 

emissions, condensate, and waste waters that are the result of the reduction of sulfur by 

the pulping process. TRS typically includes hydrogen sulfide (H2S), methyl mercaptan 

(CH3SH), dimethyl sulfide (CH3SCH3), and dimethyl disulfide (CH3SSCH3).

Upper Explosion Limit (UEL): A concentration by volume of a compound in air above 

which the mixture will not catch on fire. Also called Upper Flammability Limit (UFL).

Waste Stream(s): For this document, the term “waste stream” refers only to byproducts 

of the pulping process. 

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CHAPTER 3 MAJOR CONSIDERATIONS

3.1 Introduction 

This Recommended Good Practice describes some of the special considerations required 

for system design and operation of waste streams incineration in a kraft recovery boiler. 

This information is intended to provide guidelines for safe firing of NCGs and other kraft 

recovery process waste streams. It is not the intent of this document to design the 

systems.

3.2 Explosion 

By definition, the DNCG are gases from those sources that are below the lower explosion 

limit (LEL). CNCG are gases from those sources that are generally above the upper 

explosion limit (UEL). During abnormal operating conditions, individual DNCG sources 

can be occasionally prone to have concentrations spike above the LEL, particularly gases 

generated from chip bins, digester blow tanks, washer foam tanks, and heavy black liquor 

storage tanks. Gas streams combined from several sources in a DNCG system require the 

system be designed to operate below the LEL to prevent potential explosive or flammable 

conditions from occurring. Air infiltration in a DNCG system serves to dilute the gases, 

lessening the potential for explosion. 

CNCG and SOG are rendered non-flammable due to low oxygen content. The 

composition of SOG is typically a saturated vapor stream and explosion risk is low. The 

composition of CNCG is not always above the UEL. The risk of explosion occurs when 

gas composition changes occur, creating a situation where the stream drops below the 

UEL. Such changes in a CNCG system could be brought about due to an operational 

upset, system failure or air infiltration from leaking flanges, gaskets or valves on the 

vacuum section of the collection header.

The explosion limits of NCG constituents are listed in Table 1. 

Table 1 Explosion Limits of NCG Constituents1

Constituent

Gases

Lower Explosion Limit (LEL) 

% Volume in Air

Upper Explosion Limit (UEL) 

% Volume in Air

Turpentine (α-Pinene) 0.80 Not Established

Methanol (CH3OH) 7.3 36

Methyl Mercaptan 

(CH3SH)

3.9 21.8

Dimethyl Sulfide

(CH3SCH3) 

2.2 19.7

Dimethyl Disulfide

(CH3SSCH3)

1.1 16.1

 

1 U.S. Bureau of Mines, Bulletin No. 503

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Burgess cites values of explosion limits that are equal or very close to the above values.2

The author further indicates the generally accepted values for combined gases to be 2% 

for LEL and 50% for UEL, that is, gases are flammable over the range of 2 to 50% for all 

combustibles.

Due to the explosive nature of these NCG constituents, the DNCG, CNCG and SOG gas 

streams should be collected and transported in separate dedicated pipelines. Mixing of 

DNCG and CNCG could lead to combined stream with concentrations within the 

explosive range. Combining a SOG stream with other concentrated gases may produce 

two phase flows from the condensation of SOG constituents. Turpentine is the primary 

concern in this situation due to its very low explosion limit, and high flame propagation 

speed (505 fps). In comparison, the flame velocity of methanol (1.6 fps) and methyl 

mercaptan (1.8 fps) are much lower.

2

The removal of condensate from NCG pipelines is critical to ensure safe operation. The 

design of a NCG transport system includes steam ejectors or fan, mist eliminators, sloped 

piping, low point drains, and condensate collection systems. The transport systems also 

incorporate line pressure sensors, rupture discs, emergency purge vents, temperature 

sensors, flow meters, flame arresters, and isolation valves. The recovery boiler burner 

management system must address key interlocks for safe firing of NCG including SSVs 

fully closed or open, scanner proving “no flame” for the continuous igniter (if required) 

and adequate furnace temperature proven by proxy of a steam flow minimum. The open

or closed position of all SSVs should be confirmed by limit switches that provide a 

control room indication and initiate an alarm if improperly positioned. 

A gas explosion within the recovery furnace or burn back into the NCG collection system

are the greatest potential hazards. This could occur if a CNCG or SOG stream is 

introduced into a furnace that does not have a continuous igniter in service and adequate 

furnace temperature from the firing of auxiliary fuel and/or black liquor combustion, or if 

a DNCG stream being used as combustion air becomes concentrated above its LEL. Gas 

explosions could also take place in the gas handling system close to the recovery boiler. 

Explosions in the gas handling system could trigger a sequence of events leading too 

much more serious consequences. 

The velocity of the waste gas stream entering the furnace should be above the flame 

propagation speed to reduce the opportunity for burn back. Flame propagation speeds for 

gas streams containing turpentine are very high and this requirement is virtually

impossible to meet if the turpentine is not removed from the gas stream prior to

incineration. Contamination of the gas stream with turpentine is the most frequent cause 

of explosions in DNCG handling systems.

Condensate formed in NCG collection and transport systems provides the potential route 

for water to enter the furnace cavity. Waste gas streams are frequently collected at 

saturated conditions and steam ejectors are recommended for use as prime movers in the 

gas collection and transport systems. The steam brought into the system with an ejector is 

 

2 Burgess, T.L., Noncondesible Gases, Chemical Recovery in the Alkaline Pulping Process, Chapter 3

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used to purge the piping and warm the line prior to introducing NCG’s, and also to act as 

a “flame arrestor” of sorts while reducing the percent oxygen concentration in the stream 

during normal operation. It is possible to have large aqueous streams, such as digester 

extraction liquor or foam formed in the evaporator and carried through a condensate 

stripper, back up into the waste gas collection system. 

Possible modes for water entry into the furnace when burning waste streams include: 

1. Flooding the gas stream with liquid due to inadequate sloping of the ductwork and 

 inadequate or malfunctioning drains in the gas transport system. 

2. Condensation from high-moisture gas in cold ductwork or inside the boiler 

during start-up, boiler trips or blackouts. 

3. An explosion in the gas handling system close to the boiler could damage boiler 

pressure parts and result in a water leak into the furnace.

The Waste Streams Subcommittee emphasizes the importance during the design of the 

NCG systems to carefully analyze all automatic actions that can occur during upsets or 

other upset conditions at the NCG source or at the boiler and/or transport system. This 

analysis should include start-up, shutdown and upset conditions of the system, and 

consider all sources, such as, evaporator, condensate stripper and digester, and the boiler. 

Liquid waste streams blended with black liquor and liquid waste streams fired in 

dedicated burners do not, in themselves, represent an explosion hazard during transport to 

the recovery furnace. There are design considerations important to both and these are 

described in later chapters.

3.3 Turpentine Hazards

The most prevalent cause of fires and explosions in NCG collection, transport and 

combustion systems is the presence of terpenes (turpentine vapor) in the gas stream in 

concentrations that result in explosive mixtures. These can be easily ignited from a 

number of sources such as static electricity, an electrical spark, or reaching the autoignition temperature of the α-pinene (487°F). The upper and lower explosion limits for 

turpentine vapor are not very well defined, but the explosion range is known to be very 

wide due to the variability in turpentine composition. 

3.4 Emergency Shutdown Procedure (ESP)

The protocol for the recovery boiler operation is that an ESP shall result in the 

immediate diversion of all fuels from the furnace. This includes any waste streams which 

can be fired in the recovery boiler. DNCG, CNCG and SOG, or other waste streams 

entering the recovery furnace, must be automatically diverted upon initiation of an 

Emergency Shutdown Procedure (ESP). 

3.5 Corrosion 

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In some instances, the introduction of DNCGs into existing air systems has led to 

corrosion of the air ducts. Proper design of the collection and transport system will 

minimize the potential for corrosion. Use of a gas cooler with DNCG will remove water 

vapor. If a cooler is used, a heater should be installed (after the mist eliminator) to reheat 

the DNCG. Heating should be a part of the system regardless of whether the DNCG is 

injected into the furnace through ports or mixed with combustion air in the ducts. The 

transport system should be designed to deliver the gas at approximately 50% or less 

relative humidity and at least 150°F. The temperature should be higher than the dew point 

of the gas stream. 

Proper material selection is critical for avoiding corrosion. An additional safety measure 

is installation of corrosion coupons to monitor corrosion and predict the remaining life of 

a given system. At a minimum, all components of the transport and combustion system 

should be inspected regularly. 

Thermal oxidation of liquid or gaseous waste streams could lead to higher SO2 levels in 

the furnace and a greater potential for pressure part corrosion. Lower drum (“near drum”) 

corrosion caused by acidic sulfates has been reported by a number of mills. Corrosion 

could lead to a boiler pressure part failure. In addition, any burners and/or flame arresters 

in the NCG system are very susceptible to corrosion and need to be inspected regularly. 

SO2 in the flue gases leaving the recovery furnace must be maintained at a low level to 

minimize the potential for corrosion. An important consideration for thermal oxidation of 

liquid or gaseous waste streams in the recovery furnace is adequate black liquor

concentration (typically over 70%) to provide furnace conditions that make it possible to 

control the SO2 at the desirable low levels for corrosion and emissions control. 

The Waste Streams Subcommittee is not aware of any boilers that have suffered pressure 

part corrosion due to admission of liquid or gaseous waste streams to the furnace. 

3.6 The Effect of Sulfur Input and Solids Concentration on SO2

The Cluster Rule (in North America) requires incineration of liquid or gaseous waste 

streams in a boiler by introducing the gases to the ‘flame zone’ so as to insure destruction 

of these gases via oxidation to sulfur dioxide (SO2). Flame zone is not defined. 

In a recovery boiler, the SO2 produced in the thermal oxidation of black liquor is 

scrubbed by the alkali fume present in the upper furnace to form sodium sulfate (Na2SO4) 

which deposits on tube surfaces and is captured in the electrostatic precipitator. In this 

sense, recovery boiler chemistry provides a self-scrubbing mechanism for SO2. The 

limiting factor for SO2 scrubbing is the amount of alkali hydroxides, sodium and 

potassium, that are present in the furnace. In general, furnaces that burn hotter (those with 

higher black liquor solids) will volatilize more sodium and in turn have a higher sulfur 

capture efficiency. There are many cases reported in the literature of recovery boilers 

operating with low or no detectable SO2. 

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The high sulfur capture efficiency is one of the factors that make incineration of liquid

and gaseous waste streams in the recovery furnace an attractive alternative. The impact 

on emissions is less than other incineration devices (such as bark boilers or stand alone 

incinerators) and the sulfur is maintained within the liquor cycle. For example, if the mill 

is incinerating 500 lb/hr of sulfur from the waste stream compounds in a recovery boiler 

with a capture efficiency of 98%, 490 lb/hr of the sulfur would be recovered in the form 

of saltcake (equivalent to 10.3 tpd NaHS or 26.1 tpd Na2SO4).

Analysis of the ash from a recovery boiler can give an indication of its capacity to scrub 

additional sulfur. If the ash collected in the electrostatic precipitator contains sodium 

carbonate (Na2CO3), there is sodium available for scrubbing more sulfur in proportion to 

the Na2CO3 content. Investigations by the University of Toronto demonstrate that the 

black liquor solids concentration should be above 70% to assure sufficient Na2CO3 in the 

flue gas.3 The data shows ash generally containing 8-10 mole percent carbonate 

[CO3/(Na2 + K2)] when the black liquor is fired at 70% solids. This level of carbonate 

would, in most installations, be sufficient for sulfation of alkali hydroxides to provide 

complete SO2 removal.

Most modern recovery boiler installations and an increasing number of the older units are 

firing black liquor at concentrations exceeding 70%. One of the most noticeable results of 

burning the liquor at the higher solids concentrations is that the SO2 content of the flue 

gas is frequently negligible. This is particularly true in North America where sulfidity 

levels are commonly in the 25 to 30% range. For sulfidity levels on the order of 40%, 

such as those common in Nordic countries, even higher solids levels may be required to 

ensure a negligible concentration of SO2 in the flue gas. Higher solids mean that less 

water is introduced into the furnace to absorb heat by evaporation, resulting in higher 

temperatures in the lower furnace. This results in an increased level of alkali (sodium and 

potassium) in the flue gas to react with the SO2 that is also formed as a combustion 

product. 

3.7 The Effect of SOG Input on NOx Emissions 

The SOG stream from the stripper typically contains ammonia. The ammonia may be in 

sufficient concentration to cause the formation of NOx in the recovery furnace. One study 

indicates that approximately 20% of the nitrogen in the black liquor is removed during 

evaporation.4

 Most of this nitrogen ends up in the evaporator condensate. Subsequent 

stripping will remove the nitrogen from the condensate and it will ultimately be found in 

the SOG. The stripper supplier and the boiler manufacturer should be consulted to 

ascertain the effect on the boiler NOx emission, if any.

 

3 Tran, H., Villarroal, R., Effect of CNCG Combustion on Recovery Boiler Performance and Precipitator 

Dust Composition, unpublished paper, Annual Research Review Meeting, University of Toronto Pulp & 

Paper Centre, November 18-19, 1998. 4 Kymalainen, M, Forssen, M, Hupa, M, The Fate of Nitrogen in the Chemical Recovery Boiler Process in 

a Kraft Pulp Mill, Proceedings of the International Chemical Recovery Conference, TAPPI Press 1998, p. 

19-32.

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3.8 Health Considerations 

Liquid and gaseous waste steams contain hydrogen sulfide, as well as other reduced 

sulfur gases, and can be hazardous to human health. 

The toxic nature of the NCG and the potential explosion hazard must be carefully 

considered in plant design and training. The rupture or other failure of the gas handling 

system could allow these gases to enter the recovery boiler building in hazardous 

concentrations. Effort should be made to minimize the routed distance of CNCG piping 

inside the boiler house. Personnel Safety Procedures and Training of personnel must be 

implemented for the additional equipment and systems. Continuous monitors for TRS 

must be installed to warn personnel in the event of a leak. For extra precaution, 

operations personnel can be equipped with respirators. 

The DNCG stream will generally contain gas compounds at a much lower concentration 

representing a reduced health hazard. There have been reports of operating personnel 

suffering nausea as a result of the gases escaping into the recovery building. The digester 

vent gas could be at a concentration higher than other DNCG streams and thereby 

constitute an increased hazard. This Good Practice recognizes alternatives for handling 

the DNCG in the recovery boiler building in Chapter 4. 

The American Petroleum Industry has published API Recommended Practice 55 that in 

Appendices summarizes the Physical Properties and Physiological Effects of Hydrogen 

Sulfide5

 and Physical Properties and Physiological Effects of Sulfur Dioxide6. The first 

Appendix includes Tables A-1 of typical characteristics of Hydrogen Sulfide and A-2, 

Summary of Occupational Exposure Values for Hydrogen Sulfide. 

Other liquid waste streams will not generally represent a direct personnel hazard as these 

are contained in piping systems to the recovery furnace. Health hazards would occur if 

there was a rupture or other failure of the piping system. 

3.9 System Complexity 

Adding additional gas or liquid streams to a recovery boiler increases the system 

complexity. With the availability of distributed control systems, proper training, and 

proper design of the systems, recovery boilers can be operated with the added complexity 

without posing a threat to safe operations. DNCG can be viewed as odorous air and adds 

minimal complexity, but CNCG, SOG, and other liquid streams should be treated similar 

to an auxiliary fuel with specifics on safety interlock requirements as provided in the 

following chapters. 

 

5 Appendix A, with Tables A-1, Hydrogen Sulfide, and Table A-2, Summary of Occupational Exposure 

Values for Hydrogen Sulfide, API Recommended Practice 55, Recommended Practices for Oil and Gas 

Producing and Gas Processing Plant Operations Involving Hydrogen Sulfide. 6 Appendix B, Practice 55, Physical Properties and Physiological Effects of Sulfur Dioxide.

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Operational upsets are a major consideration in the design and operation of the system to 

introduce the CNCG into the recovery furnace. Instabilities in the gas incineration system 

could upset the boiler operation or distract the operator’s attention. This increases the 

vulnerability of the recovery boiler to other hazards. Similarly, upsets in the recovery 

boiler may lead to unsafe conditions for the thermal oxidation of the CNCG. Either 

situation requires the immediate diversion of the CNCG to the recovery building vent or 

alternate point of incineration. Failure to satisfy any of the normal recovery boiler safety 

interlocks would be a further cause for immediate diversion of the CNCG from the 

recovery boiler, as would the load on the boiler falling below the level prescribed within 

this Good Practice. The conditions for tripping and diverting this stream from the boiler 

will be addressed more specifically in Chapter 5 titled “Guidelines for Thermal Oxidation 

of CNCG and SOG”.

Chip bin NCG (CBNCG) adds a level of complexity due to the potential for turpentine 

being present in the transport system to the recovery furnace. The chip bin gases can be a 

separate gas stream or can be included in the DNCG stream. The conditions for tripping 

and diverting this stream from the recovery furnace are addressed more specifically in 

Chapter 8. 

Other liquid waste streams are introduced by mixing with black liquor or in dedicated 

burners. Those liquids mixed with black liquor can add complexity to the black liquor 

firing system. Those liquids fired in dedicated burners add complexity associated with the 

presence of an additional burner in the recovery furnace and the recommended interlocks 

for safe operation. 

3.10 Integration/Reliability of Transport Systems 

While proper design of the transport systems is an important facet of liquid and gaseous 

waste stream combustion, it is beyond the scope of this document. Waste streams must be 

properly conditioned. 

Specifications for gas conditioning required for introduction to the recovery boiler are 

included in Chapters 4, 5 and 8. Interlocks should be designed so that, in the event the 

specified gas or boiler conditions are not met, or there is an instrument failure, the 

transport of gases is isolated from the recovery boiler. In other words, the system must be 

“fail safe”.

Specifications for liquid streams in black liquor or fired in dedicated burners for 

introduction to the recovery boiler are included in Chapters 6 and 7. 

3.11 Input 

The design of a new recovery boiler provides the engineer the opportunity to take into 

account the additional heat input that may be entering the furnace with the liquid and 

gaseous waste streams. The furnace size, additional burner requirements, and placement 

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of the entry points for waste streams, as well as the location and air volumes for air ports, 

can be optimized by the designer. 

The design evaluation to thermally oxidize NCG in an existing recovery boiler must 

consider all boiler and auxiliaries limitations. These limitations will vary on a case-bycase basis. In cases where the recovery boiler capacity is limited by the heat input, it may 

be necessary to decrease proportionately the input of black liquor when firing waste 

streams. As an order of magnitude example, if a mill is firing CNCG and SOG at 3000 

ACFM with an average heating value of 65 BTU/ACF the heat input is 11.7 million 

BTU/hr. Assuming the recovery boiler at maximum heat input is burning 3.5 million 

lb/day of black liquor solids with a heating value of 6600 BTU/lb, the heat input from 

liquor is 962.5 million BTU/hr. Thus the heat input from CNCG/SOG is equivalent to 

approximately 1.2% of the heat from liquor (i.e., the mill would need to consider 

reducing the liquor firing in order to reduce the liquor heat input by 1.2%). 

Many North American recovery boilers being considered for the thermal oxidation of 

CNCG will require an increased level of solids concentration to assure that SO2 is not 

leaving the boiler. The additional benefit to raising the solids concentration is that the 

flue gas volume is reduced, thereby providing an opportunity to increase heat input 

without increasing the gas velocity in the furnace or through convection surfaces. The 

actual heat input for NCG will depend on the composition of the stream. The heats of 

combustion for different NCG components are listed in Table 2. 

Table 2 Heats of Combustion for NCG Components7

Component HHV (BTU/lb)

Methanol (gas) 9,770

Turpentine 17,870

Hydrogen Sulfide 6,570

Methyl Mercaptan 11,220

Dimethyl Sulfide 13,280

Dimethyl Disulfide 10,160

3.12 Condition of the Recovery Boiler 

In general, it is always easier to design an auxiliary system for new construction as 

opposed to retrofitting an existing unit. As mentioned above, heat input can be a concern 

for an existing unit. Older units in particular have short furnace heights that compromise 

residence time and heat release per unit of volume. The furnace wall construction is 

another consideration; units pre-dating membrane wall construction have questionable 

integrity of the walls to contain the waste streams. For DNCG, the integrity of the duct 

work can also become a major concern. If the condition of the duct work is not 

considered suitable for transport of DNCG, then a separate duct system may have to be 

designed. This has been done on some units. 

 

7 Collection and Burning of Kraft Noncondensible Gases – Current Practices, Operating Experience, and 

Important Aspects of Design and Operation, Technical Bulletin No. 469, NCASI, Aug. 29, 1985.

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CHAPTER 4 GUIDELINES FOR THERMAL OXIDATION OF DNCG

4.1 Introduction 

These guidelines cover the use of the recovery boiler as a control device for safe thermal 

oxidation of DNCG. Chip Bin NCG (CBNCG) can be one of the DNCG streams that this 

chapter covers, but Chapter 8 must be referenced to understand CBNCG. This chapter 

also applies to dedicated systems for thermal oxidation of dissolving tank vent gases in 

the recovery boiler.

4.1.1 Safety 

During the thermal oxidation of DNCG, the safety for both personnel and equipment, as 

well as health hazards for personnel, must be considered. 

The DNCG system is considered an “odorous-air” system and DNCG becomes a 

substitute for a part of the combustion air supply. DNCG is not a fuel. Systems and 

equipment for thermal oxidation of DNCG, as well as the systems and equipment for 

collection and treatment, should be designed and controlled such that: 

• The escape of DNCG into the recovery building area is prevented insofar as design 

makes it possible. 

• Condensate cannot carry into the recovery boiler. 

• Special consideration should be placed on the design of the system for collecting and 

handling the digester chip bin gases recognizing that conditions can occur where the 

concentration can become flammable.

• In no case shall the safety requirements be less restrictive than those presented in the 

following BLRBAC publications: 

1. Recommended Good Practice for the Safe Firing of Auxiliary Fuel in Black 

Liquor Recovery Boilers 

2. Recommended Good Practice for the Safe Firing of Black Liquor in Black Liquor 

Recovery Boilers

3. Instrumentation Checklist and Classification Guide for Instruments and Control 

Systems Used in Operation of Black Liquor Recovery Boilers 

4. Recommended Rules for Personnel Safety Black Liquor Recovery Boilers

4.1.2 Sources 

The main sources of DNCG may include: 

• Chip bin vents 

• Digester blow and stock surge tank vents 

• Digester stand pipe vents 

• Brown stock and post-oxygen delignification washer vents 

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• Cylinder molds/decker hood vents 

• Oxygen reactor and oxygen blow tank vents 

• Knotter and screening reject drainer vents

• Miscellaneous filtrate and stock tank vents in fiberline operations 

• Weak and strong black liquor storage and mixing tank vents 

• Crude tall oil soap skimming tank vents 

• Clean evaporator process condensate tank vents

• Recovery boiler dissolving tank vents 

Regarding the selection of suitable DNCG sources, see the Section in this Chapter on 

Collection of DNCG. 

4.1.3 Recovery Boiler Introduction System 

DNCGs can be introduced for thermal oxidation into the recovery boiler furnace in 

several ways.

• Into the suction of the forced draft fan (primary, secondary, tertiary). 

• Into the primary, secondary or tertiary air duct either prior to or after the steam coil 

air heater.

• Through multiple injection nozzles located in a suitable furnace air zone. 

The selected method of introduction of the ‘odorous air’ into the furnace needs to 

consider the gas concentration at the point of injection and the volume of DNCG. The 

designer selecting a system to introduce DNCG into the air duct should recognize the 

potential for release of odorous gas into the boiler area due to ductwork leaks, port 

rodding leakage, sight glass breakage or other leakage sites. A system design that uses 

direct injection into the furnace through multiple dedicated nozzles significantly reduces 

the possibility of odorous gas release. 

DNCG replaces a part of the volume of combustion air. Accordingly, the pressure and 

temperature of the DNCG at the point of introduction should optimally match the 

conditions of the air being replaced. The volume of DNCG relative to the air volume is a 

factor to consider. Consideration needs be given for each installation to the percent of the 

air being replaced in an air zone. DNCG introduction at the tertiary level, that is, above 

the liquor gun level, may not be appropriate because the volume of DNCG may equal or 

exceed the full load tertiary air requirement. This could result in conditions of operation 

where the furnace might become air deficient. The operating function and load 

characteristic of the “above gun” air required becomes the most important consideration 

for design of a DNCG system. From a functional standpoint, it may be desirable to use a 

portion of ambient air for the required combustion air to provide flow modulation for 

oxygen control and turndown at reduced boiler operating loads. 

The exact method of introduction of gas into the recovery boiler is determined during 

system design in consultation with the boiler manufacturer, process safety resources and 

insurance carriers.

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4.2 Collection and Transfer of DNCG 

The placement outside the recovery boiler area of the collection and the transfer motive 

equipment (fan or blower) shown in Figure 1 for the DNCG system should consider the 

need for access to equipment when the recovery boiler area is evacuated for an ESP. 

Access is layout dependent. For example, if the DNCG block and vent is upstream of the 

transfer fan or blower, there is probably no need to access equipment. The “recovery 

boiler area” corresponds to the area to be vacated in the event of an ESP.

The introduction and diversion of DNCG should be controlled from the recovery boiler 

control room. 

4.2.1 Collection of DNCG 

A thorough sampling and evaluation study of all components entering the dilute gas 

system should be performed to determine the temperature, volumetric flow, moisture 

content, and %LEL of each individual source. This study should include both normal 

steady state operation and maximum rates with upset conditions. This data should be used 

by a qualified specialist to determine the operating conditions and properties of the 

combined DNCG stream at the recovery boiler. All liquor based vents will exhibit lower 

LEL levels for hardwood liquor than for corresponding softwood liquor vents. 

4.2.2 Chip Bin Gas 

Chip bin noncombustible gas (CBNCG) is covered in detail in Chapter 8. In that the Chip 

Bin can be the most significant NCG source that can jeopardize the safety of a combined 

DNCG system, particular attention should be given to the detailed discussion provided in 

that chapter. An evaluation of risk factors is necessary to qualify a particular chip bin 

vent gas as “blendable” with DNCG. If a particular CBNCG qualifies for blending, then 

the DNCG guidelines in this chapter (Chapter 4) can be used for that CBNCG. 

4.2.3 Dissolving Tank Vent Gases 

Dissolving tank vent gases are DNCGs containing primarily air and water vapor. 

Dissolving tank vent gases should only be handled through a dedicated system for the 

following reasons: 

• The dissolving tank only operates when the boiler is on line, while generation of other 

DNCGs is dependent on their process source. By separating dissolving tank DNCG 

from other process DNCGs, designing for a wide range of flow is avoided. 

• The dissolving tank DNCG flow is very large. If it is combined with other DNCGs, the 

total DNCG volume may be too large for any single method of delivery to the recovery 

furnace.

• By keeping the dissolving tank stream separate from the other DNCG streams, a 

different furnace injection method can be used for each stream.

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• Dissolving tank vent gases and DNCGs are covered by different environmental 

regulations. 

4.2.4 DNCG Transfer System

The intent of the DNCG transfer system is to reduce the amount of water vapor and 

condensable gases. The condensate would be typically transferred to a foul condensate 

collection system.

The DNCG stream should be conditioned to prevent liquid condensate from entering the 

furnace and/or contributing to corrosion of carbon steel ductwork and other air system 

components. Mixing of the DNCG with combustion or dilution air at a lower temperature 

than the DNCG can cause condensation. A maximum of 50% relative humidity in the 

DNCG stream is a typical target to avoid condensation after mixing with an air stream 

but higher relative humidity might be possible in some systems. To achieve a condition 

of 50% relative humidity, the DNCG would likely be cooled to 110°F or lower. The 

DNCG should be reheated before injection into the recovery boiler air system or furnace. 

The expected DNCG temperature after reheating would be 150°F if the gas is cooled to 

110°F. Should the cooled gas temperature be above 110°F, a higher reheating 

temperature would be expected. A mist eliminator (or other method of water/gas 

separation) should be provided to remove condensate. 

A dissolving tank vent gas collection system should include a scrubber/cooler to remove 

water, particulate and green liquor droplets. The scrubber/cooler should be upstream of 

the DNCG system fan to avoid deposits on the fan rotor and resulting imbalance. There is 

no a need for a separate mist eliminator in dissolving tank vent gas systems if the 

scrubber/cooler has an integral mist eliminator.

The principal motive force for transferring the DNCG to the boiler shall be provided by 

system fan(s)/blower(s) as shown on Figures 1 and 4. All system fan(s)/blower(s) should 

be of non-sparking construction. The transport system including the fan casing and shaft 

should be grounded. The fan casing should have a sealed condensate outlet at its lowest 

point. 

For systems with injection into combustion air ducts, DNCG flow and pressure should be 

monitored and alarmed. These systems will generally include a transfer fan(s)/blower(s) 

to transport the DNCG to the boiler area and into the air system that uses a combustion 

air fan. For systems with dedicated injection nozzles, the transfer fan(s)/blower(s) may be 

designed to develop the DNCG pressure required at the furnace nozzles. DNCG pressure 

should be monitored and alarmed. 

The piping system beginning at the common collection point (suction of fan(s)/blower(s)) 

shall typically include the following equipment (see Figures 1 and 4).

• Transfer fan(s)/blower(s)

• Local pressure/vacuum indicators before and after prime mover [fan(s)/blower(s)]

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• Pressure transmitters with high and low alarms for monitoring and control located 

before and after transfer fan(s)/blower(s)

• Gas cooling, condensing, and mist entrainment separating equipment 

• Automatic vent valve to atmosphere 

• Optional tie-ins with automatic switchover to alternate oxidation control device

• DNCG gas temperature conditioning equipment (Reheat can be accomplished by a 

steam preheater, using the combustion air heating system, or mixing with combustion 

air.) 

• System low point drains with loop seals 

• Automatic shut-off valve with means to positively double block and vent. The double 

block and vent ensures sealing DNCG from the boiler and provides maintenance 

access.

• Flow and pressure transmitters with alarm functions 

• Temperature transmitters with high/low alarms for gas condensers/preheaters

Automatic vent lines for DNCG systems should be routed to a safe location. 

For DNCG systems handling dissolving tank vent gases, there must be an additional vent 

directly from the dissolving tank to a safe location, which will open on dissolving tank 

high pressure. 

4.2.5 DNCG Piping System and Auxiliary Equipment

Good engineering practices should be employed for all design aspects of the DNCG gas 

system including metallurgy selection, transport velocities, sloping and draining of 

piping, accessibility and safety. 

The DNCG equipment and transport piping or ducting inside the boiler area should be 

minimized as much as possible to reduce exposure to gas leakage. The control 

mechanisms should be user friendly. Proactive maintenance and repairs for all electrical 

and mechanical equipment should be practiced. 

A DNCG system handling dissolving tank vent gases can have build up problems from 

particulate and green liquor droplets. It should have provisions for frequent cleaning of 

heat exchangers – either installed spares or planned maintenance periods. Provisions 

should also be made for frequent planned maintenance of flow measurement devices. 

Materials of construction for ductwork, piping, and equipment in contact with wet 

unconditioned DNCG should be AISI type 304L or 316L stainless steel, or other metals 

with equivalent or better corrosion resistance and strength properties. 

Gas piping should be designed to prevent accumulation of condensate and flammable 

deposits. Generally, piping should be sloped in the direction of gas flow to minimize 

deposits. A low point with a liquid seal drain should be provided in the gas line prior to 

injection into the recovery boiler system. From the last drain to the recovery boiler, the 

piping should be designed to prevent condensate from entering the recovery boiler. 

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Sealed liquid drains should have a method of verifying that the seal is in place. Since 

fiber and organic deposits can be expected, provisions should be made for inspection and 

cleaning on periodic preventative maintenance schedules. 

When a DNCG line is idle due to the boiler being down or when the DNCG is transferred 

to another incineration point, it is recommended, but not required, that the line 

downstream of the last shut off valve be purged of NCGs. This may be done with mill air 

or with a slip stream from existing intake or combustion air as long as there is no NCG 

component mixed with the air. The steps in this process may be programmed in the 

permissive logic during the “ventless transfer” or the shutdown of the boiler. This should 

be designed for a single purge, immediately after idling.

In addition to purging the idle DNCG lines, it is also recommended that the DNCG 

nozzles that penetrate the boiler be evaluated for possible cooling during long idle 

periods when the boiler is still operational. The idle nozzles lose the cooling properties 

from the DNCG flow and are subject to degradation. The owner may consider using mill 

air for short periods, or piping in a slip stream from a DNCG-free combustion air source. 

Piping should not be routed close to critical areas such as furnace corners (to the extent 

possible), or near areas likely to be occupied by personnel such as normal access ways. 

For boilers designed with a “weak corner”, the area in the vicinity of the corner should 

also be avoided. Piping should be constructed according to all applicable codes; 

recognition needs to be given to pressure, explosion hazards, and static charge build-ups. 

If a system can be subject to deflagration pressure then consideration should be given to 

designing for that possibility.

Automatic shut-off valves in DNCG piping should be equipped with fail-closed actuators. 

Automatic vent valves to atmosphere should be fail-open. Gases should be securely 

isolated when shutting down the thermal oxidation system, therefore, valves in the system 

must be chosen carefully with attention given to shut-off classifications. Automatic 

valves should have position with feedback to a manned control room switches to confirm 

valve position status. 

4.3 Monitoring and Control 

Monitoring and control for the DNCG system should be in accordance with any 

information that is a part of the BLRBAC “Instrumentation Checklist and Classification 

Guide for Instruments and Control Systems Used in Operation of Black Liquor Recovery 

Boilers”. The system design should evaluate NFPA Standards for guidelines for system 

design and comply with insurance carrier recommendations. 

Bearing failures in transfer blowers have been sources of ignition and consideration 

should be given to providing continuous or routine vibration and bearing temperature 

monitoring. 

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NFPA 69, Chapter 6, sets the allowable level of combustibles. Systems without automatic 

interlocks should be designed to operate below LEL levels of 25%. Operation of DNCG 

up to 60% LEL is permitted if automatic interlocks are provided and operational. 

DNCG systems that include Chip Bin NCG may be prone to upset conditions where high 

percent LEL levels can occur. The risk of developing flammable conditions should be 

evaluated to determine whether continuous percent LEL monitoring is warranted. 

Guidelines provided in Chapter 8 may be useful in this regard. 

4.4 Safety Systems 

The DNCG system is considered an “odorous-air” system and a part of the combustion 

air supply, not as a fuel, and should be considered as an air stream when applying the 

appropriate sections of the BLRBAC Recommended Good Practices for Safe Firing of 

Auxiliary Fuel and Black Liquor in Black Liquor Recovery Boilers.

4.4.1 Permissive Starting Logic - DNCG

To admit DNCG to the recovery furnace, the following conditions should be fulfilled: 

• Purge credit established and maintained

• Steam flow is above 30% of MCR 

• DNCG temperature after reheat not low 

• DNCG temperature after condenser not high 

• DNCG flow above minimum 

• If vent gas from a steaming chip bin is included in the collection system, the chip bin 

gas temperature after the gas cooler is not high

• Dissolving tank pressure not high (if applicable) 

• DNCG temperature after scrubber/cooler for dissolving tank vent gas below 

maximum (if applicable)

Permissive starting logic for thermal oxidation of DNCG is shown in Figure 2, which is 

supported by a Logic Explanation Chart. 

4.4.2 Protective Tripping Logic - DNCG

Any of the following conditions will disallow introduction of DNCG to the recovery 

furnace:

• Master Fuel Trip (purge credit lost)

• DNCG flow low 

• Gas temperature after chip bin gas cooler high (if applicable)

• DNCG temperature after gas condenser high

• DNCG temperature after reheater low

• Boiler steam flow less than 30% of MCR 

• Shut-off valve to alternative control device not closed (if applicable) 

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• Automatic vent valve not closed. 

• Dissolving tank pressure high (if applicable) 

• DNCG temperature after scrubber/cooler for dissolving tank vent gas high (if 

applicable)

Protective tripping logic for thermal oxidation of DNCG is shown in Figure 3, which is 

supported by a Logic Explanation Chart. 

4.5 Personnel Safety 

Operational problems, which have to do with collecting, treatment and destruction of 

DNCG can lead to accidents and serious injury. 

The DNCGs contain, among other things, H2S, organic sulfides and methanol, and at 

certain times, even high levels of turpentine. In addition to the health risk, there is also 

risk of a gas explosion. 

OSHA Guidelines should be reviewed regarding the risks and precautions for hazardous 

compounds present in DNCG. 

The installation of a TRS monitoring system to detect unsafe levels of gas in the boiler 

area should be considered. Monitoring should be in accordance with federal, state, local, 

and mill safety codes and regulations. 

Daily inspection and control is needed to check for leaks in systems for DNCG. Leaks in 

the system shall be corrected immediately.

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Figure 1 DNCG Transfer System.

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Figure 2 DNCG Permissive Starting Logic

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Table 3 Logic Explanation Chart for Figure 2 - DNCG Injection Permissive Starting Logic

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit 

Maintained

(From Figure 2 ‘Common 

Permissive Starting Logic’ 

in Safe Firing of Auxiliary 

Fuel Recommended Good 

Practice)

Ensure firing permissive Prevent introduction of DNCG 

while boiler is not being fired.

Steam flow >30% MCR Ensure furnace 

combustion is stable. 

Unstable operation of boiler may 

minimize furnace residence time 

or too low of temperature for 

oxidation.

Temperature after reheater 

not low 

Ensure proper gas phase 

of DNCG

Prevent liquid from entering 

boiler. 

DNCG flow established* Ensure sufficient motive 

force

Flame propagation up nozzle or 

pipeline.

Temperature after gas 

cooler not high

Ensure proper gas 

properties

Reduce gas volume and 

moisture.

Temperature after chip bin 

gas cooler not high 

Ensure proper gas 

properties

Explosion hazard due to 

entrainment of turpentine.

Start Approval Start permissive after 

satisfying interlocks

Interlocks made.

Dissolving tank pressure 

not high (if applicable) 

Ensure stable dissolving 

tank operation

Prevents pressure pulse from 

dissolving tank from affecting 

DNCG system operation.

Temperature after 

scrubber/cooler for 

dissolving tank vent gases 

not high (if applicable)

Ensure proper gas 

properties 

Reduces gas volume and 

moisture

* Flow can be proven with pressure, flow, fan operating and control damper position (fan 

operation should be proven with shaft speed), or other means. 

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Figure 3 DNCG Injection Protective Tripping Logic.

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Table 4 Logic Explanation Chart for Figure 3 - Injection Protective Tripping Logic

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Lost

Master Fuel Trip

(From Figure 3 ‘Common 

Permissive Starting Logic’ 

in Safe Firing of Auxiliary 

Fuel Recommended Good 

Practice)

Stop DNCG introduction 

when boiler firing 

permissives not met

Prevent introduction of DNCG 

while boiler is not being fired. 

DNCG flow low* Ensure sufficient motive 

force

Flame propagation up nozzle or 

pipeline. 

DNCG temperature after 

reheater low

Ensure proper gas phase 

of DNCG

Prevent liquid from entering 

boiler.

DNCG temperature after 

cooler high 

Ensure proper gas 

properties 

Entrainment of liquid, Explosion 

if temperature above autoignition point.

Steam Flow <30% MCR Ensure furnace 

combustion is stable.

Unstable operation of boiler may 

minimize furnace residence time 

or provide too low a temperature 

for proper oxidation.

Temperature after chip bin 

gas cooler high

Ensure proper gas 

properties 

Excursions above LEL.

Automatic vent valve not 

closed

Ensure stable flow Unstable flow due to leakage.

Manual switch to vent 

activated

Firing not desired System exposed to flame source 

with no minimum flow signal.

Alternative control device 

shutoff valve not closed 

Ensure stable flow Unstable flow due to flow 

bypass.

Switch DNCG from boiler 

to vent 

Stop DNCG flow into 

boiler when parameters 

are out range.

Hazardous conditions in the 

DNCG system or boiler.

Dissolving tank pressure 

high (if applicable) 

Ensure stable dissolving 

tank operation 

Prevents pressure pulse from 

dissolving tank from affecting 

DNCG operation.

Temperature after 

scrubber/cooler for 

dissolving tank vent gases 

high (if applicable)

Ensure proper gas 

properties 

Entrainment of liquid.

* Flow can be proven with pressure, flow, fan operating and control damper position (fan 

operation should be proven with shaft speed), or other means. 

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Figure 4 DNCG Transfer System of Dissolving Tank Vent.

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CHAPTER 5 GUIDELINES FOR THERMAL OXIDATION OF CNCG AND SOG

5.1 Introduction

This Recommended Good Practice presents the use of the recovery boiler as the control 

device for thermal oxidation of CNCG and SOG. 

5.1.1 Safety 

During the thermal oxidation of CNCG and SOG, the safety hazards for both personnel 

and equipment have to be considered. 

The equipment for thermal oxidation as well as collection and treatment of CNCG should 

be designed and controlled such that: 

• CNCG cannot escape into the recovery boiler building area. 

• Condensate cannot carry into the recovery boiler.

• Fire and explosion in equipment and pipe systems is prevented. 

• Positive ignition of gases entering the furnace is provided. 

In no case shall the safety requirements be less restrictive than those presented in the 

following BLRBAC publications: 

• Recommended Good Practice for the Safe Firing of Auxiliary Fuel in Black Liquor 

Recovery Boilers.

• Recommended Good Practice for the Safe Firing of Black Liquor in Black Liquor 

Recovery Boilers.

• BLRBAC Recommended Rules for Personnel Safety for Black Liquor Recovery 

Boilers.

• Instrumentation Checklist and Classification Guide for Instruments and Control 

Systems Used in Operation of Black Liquor Recovery Boilers. 

5.1.2 Sources 

5.1.2.1 CNCG

The main sources of concentrated noncondensible gases (CNCG) are:

• Noncondensible gases from black liquor evaporation 

• Vents from foul condensate tank, turpentine decanter, turpentine tank, methanol tank 

and various pumping tanks. 

• Vents from flash tanks, condensers and specialty process equipment--these need to be 

evaluated on an individual basis concerning classification as a dilute or concentrated 

NCG. The digester chip bin vent gases cannot be included in the CNCG system 

because of high air content. 

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5.1.2.2 SOG 

SOG from a foul condensate steam stripper is handled in a separate and independent 

system for introduction into the recovery furnace for thermal oxidation. These gases 

generally are the gas product from the stripper reflux condenser and reflux tank, and 

consist principally of water vapor, methanol, reduced sulfur components and potentially 

small amounts of turpentine and other hydrocarbons. An additional process step is 

incorporated in some mills to condense the methanol from the gases and handle the 

methanol liquid stream separately.

Vents from a high solids concentrator system are similar in nature to the SOG from a 

stripper column and should be handled in a gas system similar in design to that used for 

SOG. The system should be independent of other NCG systems from the source to and 

including the burner gun. 

As an option, SOG can be modified by removing its methanol content. The remaining gas 

is a low volume CNCG. 

5.1.3 Dedicated Burner 

A dedicated burner should be used for thermal oxidation of CNCG and SOG in the 

recovery boiler. The burner should be equipped with an NFPA Class 1 continuous igniter 

and igniter flame scanner. This arrangement will provide more stable and safer firing of 

the gases than arrangements that depend on the heat from black liquor combustion to 

sustain the thermal oxidation of the NCG. This arrangement further considers that there is 

not a reliable means of detecting a loss of black liquor flame to shut off the NCG flows to 

the recovery boiler.

5.1.4 The Recovery Boiler as Primary Control Device 

When the recovery boiler is used, it should be the primary control device. In the recovery 

boiler the sulfur compounds in the NCG are captured back into the process. When the 

recovery boiler is the primary control device, the effect of the NCG on the recovery 

boiler sodium-sulfur balance will be constant. This balance would be changing if the 

recovery boiler were used as a secondary control device with the NCG being thermally 

oxidized in the boiler intermittently.

5.2 Collection and Transfer of CNCG and SOG 

A thorough sampling and evaluation study of all components of the CNCG and SOG 

should be performed to determine temperature, volumetric flow, moisture content and 

percentage UEL of each individual source. That study should include both normal steady 

state operation and maximum rate with upset conditions. This data should be used by a 

qualified specialist to determine the operating condition and properties of the combined 

CNCG streams and the SOG stream at the recovery boiler.

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Consider locating motive equipment for collecting gases and the diversion system in an 

area outside the recovery boiler area so they can be accessed even at times when the 

recovery boiler area is evacuated. Where facilities are subject to winter climates with 

temperatures below freezing, consideration should be given to locating the equipment in 

a warm enclosure. Control of the system should be from the recovery boiler control room. 

The engineer should give highest piority to the selection of the ejector and other control 

components to maximize the best control and safety of the CNCG system.

5.2.1 CNCG 

The sources of gases connected to the CNCG system must be of such nature that air 

cannot enter the system.

The CNCG from the common collection point to the waste streams burner can be handled 

in two different ways. 

• Vapor phase transfer system (no gas conditioning involving any change in component 

concentration) 

• Conditioned gas transfer system 

5.2.1.1 Vapor Phase Transfer System 

After the common collection point the gases are moved by means of a steam ejector or 

water ring blower directly to the waste streams burner system. No conditioning involving 

any change in component concentration is done. 

The piping system starting at the steam ejector (water ring blower) typically includes the 

following equipment.

Figure 5 - Equipment Outside the Recovery Boiler Area

• Steam ejector or water ring blower

• Pressure transmitter for monitoring with high and low alarms located after the steam 

ejector (water ring blower)

• Mist eliminator(s) (with pressure drop monitoring and high pressure drop alarm)

• Flow transmitter with interlock function

• Main header vent line with automatic valve, drain function included 

• Recovery boiler line automatic shut-off valve 

• Tie-in to alternate thermal oxidation device (optional)

• Steam purge connection 

Figure 6 - Equipment Inside the Recovery Boiler Area 

• Recovery boiler vent line with automatic valve, drain function included 

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• Automatic double block and bleed valves (located close to burner) 

• Pressure and temperature switches for interlock functions located before the 

automatic double block and bleed valves 

• Monitoring pressure and temperature transmitters with high and low alarms located 

before the automatic double block and bleed valves 

Flame arresters or detonation arresters (with pressure drop monitoring and high pressure 

drop alarm) located as close to the burner as possible. 

The following equipment will be located in the system as required. 

• Rupture disk(s) 

• Low point drains 

• Steam Heat tracing and /or indirect steam preheater (not shown in figures) 

The intent of the design for the system is to ensure that no condensates of the condensible 

components--methanol, water or turpentine--can collect and cause upsets to the waste 

streams burner system or the recovery boiler. The CNCG piping should be heavily 

insulated from the source to the waste streams burner to minimize condensation 

formation in the line. Depending on local conditions, heat tracing may be considered. 

5.2.1.2 Conditioned Gas Transfer System 

The following components are included in addition to those used in a vapor phase 

transfer system.

• Gas cooler / condenser 

• Indirect steam preheater with auxiliaries

A concentrated NCG system with a seal pot is considered to be a conditioned gas transfer 

system. The seal pot is used to isolate lines and prevent flashback. It will act as a quench 

cooler and thereby will perform partial condensation. 

The intent of the Conditioned Gas Transfer System is to reduce the amount of water 

vapor and condensible gases and increase thermal efficiency by reducing the loss due to 

water vapor. The condensate would be typically transferred to a foul condensate 

treatment system which may include a steam stripper.

The gas analysis needs to be carefully evaluated before and after the condenser with 

regard to explosion range and combustion characteristics to determine the impact of 

conditioning on the gas. Condensing of large amounts of water vapor, methanol and 

turpentine may shift the resulting gas mixture into the explosive range depending on the 

residual amount of infiltration air and the combustible gas concentrations. The heating 

value and combustion characteristics may also be changed due to condensing of 

turpentine and methanol. 

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It is recommended to heat the gas after the cooler and/or heat trace the down stream 

piping to raise the operating temperature of the gas burner system to well above the 

dewpoint and thereby protect it from upsets due to condensates. 

5.2.2 SOG 

SOG is primarily a mixture of TRS compounds, methanol and steam at saturated steam 

conditions that can be hotter than other CNCG. Frequently, the pressure of the gas at the 

stripper condenser discharge is much higher than that of other CNCG streams. The SOG 

must be handled in lines separate from the other CNCG to prevent condensation of the 

SOG constituents in the collection system and to handle the differences in pressure. The 

SOG handling system does not provide conditioning involving any change in component 

concentration with the exception of a stripper system where methanol is condensed and 

recovered as a liquid. 

Upset conditions caused by black liquor carryover or evaporator boilout can result in 

generating foam in the condensate stripper. This foam can then be transported with the 

SOG to the recovery furnace. Provisions must be made to prevent foam carryover into the 

SOG to preclude introducing foam into the furnace. 

The SOG piping should be heavily insulated from the source to the waste streams burner 

to minimize condensation formation in the line. Steam tracing of the stripper off-gas 

piping should be considered in cold climates.

If the stripper off-gases at the source are at an adequate pressure to provide the motive 

force to transport them to the waste streams burner, then the piping system leading to the 

burner typically would include the following equipment. This arrangement would also 

apply to CNCG from a high solids concentrator. 

Figure 5 - Equipment Outside the Recovery Boiler Area 

• Pressure transmitter for monitoring with high and low alarms

• Mist eliminator(s) (with pressure drop monitoring)

• Flow transmitter with interlock function

• Main header vent line with automatic valve, drain function included 

• Recovery boiler line automatic shut-off valve 

• Tie-in to alternate thermal oxidation point (optional)

• Steam purge connection 

Figure 6 - Equipment Inside the Recovery Boiler Area

• Recovery boiler vent line with automatic valve, drain function included 

• Automatic double block and bleed valves (located close to burner) 

Pressure and temperature switches for interlock functions located before the automatic 

double block and bleed valves. 

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• Monitoring pressure and temperature transmitters with high and low alarms located 

before the automatic double block and bleed valves. 

Flame arresters or detonator arresters (with pressure drop monitoring and high pressure 

drop alarm) located as close to the burner as possible. 

The following equipment will be located in the system as required. 

• Rupture disk(s) 

• Low point drains 

• Heat tracing and/or indirect steam preheater (not shown in figures) 

If the SOG at the source are not at an adequate pressure to provide the motive force to 

transport it to the waste streams burner, then the piping system leading to the burner 

typically would include the previously mentioned equipment and a steam ejector. 

5.2.3 CNCG and SOG Piping System and Auxiliary Equipment

CNCG and SOG should be handled in completely independent collection systems due to 

temperature and pressure differences between the two streams being handled. There is a 

risk of condensing methanol from SOG with the cooler CNCG stream. 

Due to system pressure differentials, it is recommended that the SOG system and CNCG 

system not share any common auxiliary equipment such as condensate collection vessels. 

There is a risk of one system discharging into the other. 

Piping system and steam ejector or water ring blower should be sized so that minimum 

transport velocities for gases are maintained.

Gas piping should be designed to prevent accumulation of condensate and should be 

designed with the shortest possible pipe run inside the recovery boiler building. The 

piping should not be routed close to critical areas such as the dissolving tank or the 

corners of the furnace or near areas likely to be occupied by personnel such as normal 

accessways.

CNCG and SOG should be securely isolated when shutting down the thermal oxidation 

system, therefore valves in the system should be chosen carefully with attention given to 

shutoff classifications. Automatic valves should have position switches to confirm valve 

position status. 

Piping downstream of the mist eliminator should be insulated and heat traced to prevent 

condensate formation in the line. Consideration should be given to sloping the piping in 

the direction of gas flow for drainage rather than having horizontal lines. This avoids the 

accumulation of a quantity of water, which could be suddenly released into the furnace as 

well as the likelihood of accumulating flammable organic deposits. The designer should 

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proceed on the basis that there will be condensate in the pipe from time to time and that it

must be removed. 

Each vent line should have one shut-off valve with “fail open” actuator that will open 

automatically when waste stream firing to the recovery boiler is stopped.

Each gas line to the recovery boiler should have a flame arrester. There should be a 

differential pressure tranmitter across the flame arrester to alarm high differential 

pressure. Provision can be made to clean the flame arrester using steam or inert gas.

Any water or steam connections to the system should have double block and bleed valves 

or removeable spool pieces per BLRBAC Recommended Good Practice for Safe Firing 

of Black Liquor in Black Liquor Recovery Boilers. Automatic valves should have 

position switches to confirm valves position status. Steam piping should be properly 

designed and trapped to prevent condensate collection. Air should not be used as a 

purge medium due to the possible risk of creating an explosive gas mixture. 

If a seal pot (for isolation and flashback prevention) is used, it should be constructed and 

controlled so that water cannot carry into the recovery boiler through the waste stream 

line. Therefore there should be two (2) independent protective systems such as switches 

with alarm and interlock functions. It is imperative that the seal pot not overflow into the 

CNCG transport line to the recovery boiler. 

The condensate collection system should be designed so that it cannot be pressurized 

causing condensate to back flow to the transport line. As an example, an overflow to a 

closed sewer system could cause pressurization. 

Drains in the system are prone to plugging and should be of a size to reduce that 

possibility, with consideration given to at least 1-1/2” drain lines. 

Materials of construction for ductwork, piping and equipment in contact with CNCG and 

SOG should be AISI type 304L or 316L stainless steel, or other metals with equivalent or 

better corrosion resistant and strength properties. 

Material containing iron that might turn into FeS in contact with NCG should not be 

used. Under certain conditions in the presence of air, FeS can oxidize and create heat 

with explosions or fire as a result.

The system designer must take into account the movement of the waste streams burner 

due to the expansion of the furnace, and make sure that the movement does not induce 

unacceptable stresses in the piping. 

Piping must meet the required service conditions and be acceptable to the authorities

which may have jurisdiction. 

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5.3 Thermal Oxidation 

5.3.1 Burner 

The waste stream burner(s) should be mechanically suited for installation and operation 

in a recovery boiler.

The waste stream burner(s) should have a dedicated air system. The combustion air can 

be supplied from a separate fan or from the recovery boiler secondary air or tertiary air 

fan. Proof of adequate combustion air flow is required as proven by a flow switch or 

other suitable means.

CNCG and SOG should be conveyed to the burner through independent lines and 

injected into the flame zone separately. A separate system to feed fuel to the continuous 

igniter is required.

The burner should be placed in the high heat zone of the furnace at or below the tertiary 

air level. It should be placed in such a manner that disturbances in the continuous flame 

of the igniter are avoided so as to not create difficulty with detection.

Example of equipment for monitoring and controlling a single burner installation for 

CNCG and SOG is shown in Figure 6. Multiple burner installations should follow 

multiple burner standards. 

When the NCG system is down, the second automatic shut-off valve should be locked in 

the closed position. The connections in the CNCG and SOG piping downstream of the 

shut off valve at the gun should be designed and installed to allow ease of maintenance 

and inspection on a routine basis. 

Cooling of a CNCG/SOG nozzle that is not in use can not be accomplished by injection 

of air into the CNCG/SOG nozzle. 

5.3.2 Continuous Igniter 

An NFPA Class 1 igniter (NFPA 8501) is a key element in the thermal oxidation of 

CNCG and SOG. The capacity of the igniter should be large enough to provide safe 

ignition and be at least 10 percent of the maximum energy release of the gases being 

thermally oxidized. The igniter shall be continuous. The igniter should have proof of 

adequate ignition energy using a low pressure switch on the igniter fuel header. 

The igniter can have a common air duct with the burner for CNCG and SOG. Air feed to 

the igniter should provide stable ignition and operating conditions. 

The oil or gas system to the igniter as well as flame monitoring should, in all aspects, 

follow the BLRBAC Recommended Good Practice for Safe Firing of Auxiliary Fuel. 

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Light-off of the igniter must be initiated at the burner front, and then only after inspecting 

the burner opening in the furnace wall to ensure that there is no plugging. 

5.3.3 Combustion Air 

The recovery boiler secondary or tertiary air fan can be used. If the combustion air is 

supplied by the secondary air fan, a booster fan may be necessary to provide minimum air 

pressure to the waste stream burner. The system design should be such that uninterrupted 

air flow to the recovery boiler for black liquor combustion is first priority. 

The following instrumentation for monitoring and control of combustion air should be 

provided. 

• Local pressure indicator 

• Suitable means for proving adequate air flow 

• Indicating pressure transmitter

• Booster fan running--signal from motor starter, speed switch, etc.

5.4 Safety System 

The waste streams burner should have a flame safety system complying with the 

BLRBAC Recommended Good Practice for the Safe Firing of Auxiliary Fuel. The 

system design should comply with NFPA standards and insurance carrier 

recommendations. The waste streams burner flame safety system can be integrated with 

the auxiliary fuel’s burner management system or can be stand-alone.

The permissive starting logic and protective tripping logic contain the logic of Safe Firing 

of Auxiliary Fuel plus additional requirements. The additional requirements pertain to the 

quality of the NCG. 

Care must be taken to never allow the waste streams burner to maintain purge credit. In 

other words, the waste streams burner cannot be counted as an auxiliary fuel burner when 

the burner management system checks if there is an auxiliary burner in service.

5.4.1 Permissive Starting Logic - CNCG

To start thermal oxidation of CNCG in the waste streams burner the following conditions 

must be fulfilled.

• Purge credit established and maintained

• Steam flow greater than 50% of the steam flow at MCR

• Combustion air fan for waste streams burner running 

• Combustion air flow normal 

• CNCG flow (velocity) above minimum 

• CNCG temperature above minimum

• CNCG pressure not high 

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• CNCG pressure not low 

• Seal pot level not high (if used) 

• Burner switch in START position 

• Igniter has been in stable operation for minimum one minute

• Igniter interlocks satisfied

Staging of injection of multiple streams into a waste stream burner should be part of the 

Start Permissives.

Permissive Starting Logic for thermal oxidation of CNCG in the waste streams burner is 

shown in Figure 7. 

5.4.2 Protective Tripping Logic - CNCG

Any of the following conditions will cause the waste streams burner to shut down thermal 

oxidation of CNCG. 

• Master Fuel Trip (purge credit lost)

• Steam flow less than 50% of steam flow at MCR

• CNCG pressure high 

• CNCG pressure low 

• Combustion air fan for waste streams burner off 

• CNCG temperature below minimum

• CNCG flow (velocity) below minimum

• Combustion air flow not normal 

• Igniter interlocks not satisfied

• Burner switch in STOP position 

• Seal pot level high (if used)

Protective Tripping Logic for thermal oxidation of CNCG in the waste streams burner is 

shown in Figure 8. 

5.4.3 Permissive Starting Logic - SOG

To start thermal oxidation of SOG in the waste streams burner the following conditions 

must be fulfilled.

• Purge credit established and maintained

• Steam flow greater than 50% of the steam flow at MCR

• Combustion air fan for waste streams burner running 

• Combustion air flow normal 

• SOG flow (velocity) above minimum 

• SOG temperature above minimum 

• SOG pressure not high 

• SOG pressure not low 

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• Seal pot level not high (if used) 

• Burner switch in START position 

• Igniter has been in stable operation for a minimum of one minute 

• Igniter interlocks satisfied

Permissive Starting Logic for thermal oxidation of SOG in the waste streams burner is 

shown in Figure 9. 

5.4.4 Protective Tripping Logic - SOG

Any of the following conditions will cause the waste streams burner to shut down thermal 

oxidation of SOG. 

• Master Fuel Trip (purge credit lost)

• Steam flow less than 50% of steam flow at MCR

• SOG pressure high 

• SOG pressure low 

• Combustion air fan for waste streams burner off 

• SOG temperature below minimum

• SOG flow (velocity) below minimum

• Combustion air flow not normal 

• Igniter interlocks not satisfied

• Burner switch in STOP position 

• Seal pot level high (if used) 

Protective tripping logic for thermal oxidation of SOG in the waste streams burner is 

shown in Figure 10. 

5.5 Personnel Safety 

Operational problems, which have to do with collecting, treatment and destruction of 

CNCG can lead to accidents and serious injury. 

CNCG contain among other things, H2S , organic sulfides and methanol, and at certain 

times, even high level of turpentine. In addition to the health risk, there is also a risk of a 

gas explosion.

Regarding the risks with hazardous compounds present in CNCG and SOG, see OSHA 

Guidelines concerning these compounds. 

Areas containing NCG piping and equipment should be monitored in accordance with 

applicable safety codes.

Daily inspection and control is needed to check for leaks in systems for CNCGs and 

SOGs. Leaks in the system should be corrected immediately. 

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5.6 System Description and Operation

This section is included to illustrate the application of Chapter 5 guidelines. It is for 

information purposes only and is not to be considered as additional guidelines. 

The arrangement of piping and equipment as shown on the flow sheets (Figures 5 and 6) 

are the same for both CNCG and SOG. For the purposes of this discussion, the CNCG 

system is used.

5.6.1 Description 

Steam to the gas transport steam ejector has a double block and bleed valve arrangement 

consisting of valves S1, S2 and S3. This steam connection and other steam connections 

on Figures 5 and 6 are shown with double block valves and a bleed (or “free blow”) valve 

because they are potential sources of water injection into the furnace. The double block 

and bleed valve set provides secure sealing plus, with proper sequencing of valve 

opening, collected condensate can be blown out the bleed line before steam is routed to 

the gas line.

Downstream of the steam ejector and outside the recovery boiler area, the CNCG line 

will have a vent to atmosphere controlled by an automated shutoff valve, CG2. Following 

this vent connection there is an automated valve, CG1, which isolates the branch line to 

the recovery boiler. If required, there can be a tee ahead of CG1. The tee will allow the 

gas to be transported to an alternate thermal oxidizer through valve CG3. 

It is important that valves CG1, CG2 and CG3 be located outside of the recovery boiler 

area or in the case of indoor installations in a “designated safe area” so that they are 

accessible at all times, even in the event of an ESP. Being located outside of the recovery 

boiler area does not preclude the valves from being in another building. 

Immediately downstream of valve CG1 is an automated steam connection consisting of 

valves S5, S6 and S7. It purges and preheats the next “leg” of CNCG line. 

Located immediately before valve CG4 is a line size vent isolated by valve CG7. This 

vent line serves the CNCG line from valve CG1 to valve CG4. It is used for steam 

preheating, CNCG venting in anticipation of CNCG firing, and purging after ceasing 

CNCG firing. The steam for preheating and purging is supplied by the previously 

mentioned valves S5, S6 and S7. 

The vent discharges to the outside of the boiler area. Both this vent and the previously 

mentioned vent controlled by valve CG2 must be above roofs and away from air intakes. 

The outlets of these vents must be arranged in such a way that ice plugs are avoided. 

A condensate drain from the CNCG line must be included at both vent locations to ensure 

removal of liquid that is swept along by the venting gases. The drain function can be 

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included with the vent, or two connections can be used; one to vent and the other to drain 

the line.

A CNCG line double block and bleed valve arrangement represented by valves CG4, 

CG5 and CG6 provides the final isolation of CNCG from the furnace. The “bleed”, CG5, 

must be designed so that vapor can be vented from the isolated portion of CNCG line 

while liquid is vented out of the bottom of the line. Valve CG5 could be two valves, one 

for venting and the other for draining. The vent from CG5 can be connected to the main 

vent on the discharge of valve CG7. 

The CG4, CG5 and CG6 valve set must be located as close to the burner as possible to 

minimize the retained CNCG volume from these isolation valves to the burner. 

If the volume of CNCG that is retained is small and the piping system has the mechanical 

integrity to sustain a burn back after the isolation valves shut, then purging of the piping 

from the isolation valves to the burner is not necessary. Not purging the line avoids the 

possibility of water introduction to the furnace if steam is used for purging.

There are, however, system designs and maintenance safety issues that make purging of 

this piping run an attractive consideration; for example, large CNCG systems that have a 

substantial volumetric capacity in this last piping leg. Section 5.2.3, Piping System and 

Auxiliary Equipment, discusses line sloping, steam supply requirements, and insulating 

and heat tracing waste gas lines. An important part of this concept is the use of a burner 

design that is drainable, that is, a burner that cannot retain liquid. The purge must be done 

immediately after firing the CNCG system is terminated, while the piping is still hot, and 

with the igniter in service.

If steam purging is used, special attention must be given to keeping the steam free of 

condensate, thus avoiding introduction of water into the furnace. A steam line that is only 

occasionally used has a high probability of containing condensate and therefore injecting 

that condensate into the CNCG piping when the steam line is opened. The system design 

and operation must ensure that the purging steam is dry. As an alternative to steam, 

another inert gas can be used as a purging medium. For any purging medium (steam or an 

inert gas), the purge should displace the volume of gas contained in the piping between 

the last isolation valve and the furnace. 

A flame arrester is located in the CNCG line as close to the burner as possible. The flame 

arrester physical location must be convenient for isolation and maintenance. 

5.6.2 Operation 

The CNCG/SOG thermal oxidation system is put into service from a local panel board by 

and operator who is in contact with the control room. Discontinuing thermal oxidation 

under normal circumstances is also done locally.

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The CNCG transport system is put into operation with branch line isolation valve CG1 

closed and vent valve CG2 open. At this point the double block and bleed CNCG valves, 

CG4, CG5 and CG6, are shut meaning the shutoff valves are closed and the bleed valve 

(providing vent and drain service) is open. 

Next, the steam purge and preheat valves, S5, S6 and S7, are opened along with the 

vent/drain valve(s), CG7. This provides preheating of the CNCG line from the branch 

isolation valve outside of the boiler building to the vicinity of the burner. The branch 

valve CG1 remains closed. Admission of steam preheats the line and exits through the 

vent/drain. 

Adequate preheating of the line will be determined by an operator observing the 

temperature indicator on the DCS. Once the line between the CG1and CG4 is heated, the 

preheat steam is shut off, the branch valve CG1 is opened and vent CG2 is closed 

allowing gas to be vented out of the second vent, CG7. Upon satisfying all permissives, 

the final gas block and bleed valves are opened, vent CG7 is closed and CNCG gases will 

be admitted to the furnace for thermal oxidation. 

For a normal shut down, CNCG shutoff valves CG4 and CG6 and branch valve CG1 are 

closed, and both vent valves, CG7 and CG2, are opened as is bleed valve CG5. In 

addition, steam purge is immediately initiated. After adequate time for thorough purging, 

the steam purge is shut off. 

Table 5 shows the actions that constitute a burner shutdown, both MFT and ESP. The 

valve positions for “normal operation” and “fail” status are also shown. If an ESP is 

activated, a MFT will be exercised as well as isolating all steam and water sources. An 

ESP will not initiate automatic purging of the CNCG line to the burner.

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Table 5 Valve status and Actions at MFT and ESP; Figures 5 and 6

Valve # Description MFT ESP Operating 

status

Fail status

S1 EJECTOR STEAM 

BLOCKVALVE

NA NA OPEN OPEN 

S2 EJECTOR STEAM BLEED 

VALVE

NA NA CLOSE CLOSE

S3 EJECTOR STEAM BLOCK 

VALVE

NA NA OPEN OPEN

S4 STEAM EJECTOR CNTR 

VALVE

NA NA MOD LAST P

S5 PURGE STEAM BLOCK 

VALVE

OPEN OPEN CLOSE CLOSE

S6 PURGE STEAM BLEED 

VALVE

CLOSE CLOSE OPEN OPEN

S7 PURGE STEAM BLOCK 

VALVE

OPEN OPEN CLOSE CLOSE

S8 PURGE STEAM BLOCK 

VALVE

OPEN OPEN CLOSE CLOSE

S9 PURGE STEAM BLEED 

VALVE

CLOSE CLOSE OPEN OPEN

S10 PURGE STEAM BLOCK 

VALVE

OPEN OPEN CLOSE CLOSE

CG1 CNCG SHUT OFF VALVE CLOSE CLOSE OPEN CLOSE

CG2 CNCG MAIN VENT VALVE OPEN OPEN CLOSE OPEN

CG3 ALTERNATE SYSTEM 

SHUTOFF

NA NA CLOSE NA/CLOSE

CG4 BURNER SHUT OFF VALVE CLOSE CLOSE OPEN CLOSE

CG5 BURNER VENT VALVE OPEN OPEN CLOSE OPEN

CG6 BURNER SHUT OFF VALVE CLOSE CLOSE OPEN CLOSE

CG7 CNCG VENT VALVE OPEN OPEN CLOSE OPEN

SG1 SOG SHUT OFF VALVE CLOSE CLOSE OPEN CLOSE

SG2 SOG MAIN VENT VALVE OPEN OPEN CLOSE OPEN

SG3 ALTERNATE SYSTEM 

SHUTOFF

NA NA CLOSE NA/CLOSE

SG4 BURNER SHUTOFF VALVE CLOSE CLOSE OPEN CLOSE

SG5 BURNER VENT VALVE OPEN OPEN CLOSE OPEN

SG6 BURNER SHUT OFF VALVE CLOSE CLOSE OPEN CLOSE

SG7 SOG VENT VALVE OPEN OPEN CLOSE OPEN

D1 AIR CONTROL DAMPER LAST P CLOSE MOD LAST P

IGNITER GT IGNITER GAS TRAIN CLOSE CLOSE OPEN CLOSE

GREY BLOCK OPERATIONS ARE ACTIVATED VIA A TIMER TO ALLOW FOR 

PURGING OF THE CNCG AND SOG LINES.

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Figure 5 CNCG and SOG Transfer Systems.

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Figure 6 CNCG & SOG Single Burner for Thermal Oxidation in Recovery Boiler.

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Figure 7 Waste System Burner Permissive Starting Logic for CNCG

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Table 6 Logic Explanation Chart for Figure 7 Permissive Starting Logic - Waste Streams Burner

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Maintained

(From Figure 2 Common 

Permissive Starting Logic in 

Safe Firing of Auxiliary Fuel 

Guidelines).

Ensure firing permissive. Prevent introduction of NCGs 

while boiler is not being fired. 

Steam Flow >50% MCR. Ensure furnace combustion is 

stable.

Explosion or improper oxidation 

of gases. This may require a 

higher steam flow based upon 

CNCG requirements.

Combustion air fan for waste 

stream burner - proven running. 

Ensure proper combustion air 

to burner. 

Potential explosion from 

improper or impaired air flow. 

CNCG/SOG temperature above 

minimum.

Ensure proper gas properties. Introduction of liquid. 

CNCG/SOG pressure not high. Ensure proper gas properties 

and injection at proper 

velocity.

CNCG/SOG pressure not low. Ensure proper gas properties 

and emitted at proper velocity.

CNCG/SOG flow not low Ensure proper gas velocity Avoid plugged nozzle

Seal pot level not high. Prevent liquid back up. Possible explosion due to 

moisture introduction to boiler

Combustion air flow normal. Ensure air flow through 

burner.

Potential explosion from 

improper or impaired air flow.

Combustion air pressure normal. Ensure proper combustion air 

properties. 

Potential explosion from 

improper or impaired combustion 

air supply.

Ignition system in operation -

minimum of one minute. 

Ensure stable ignition system 

operation. 

Possible explosion due to 

CNCG/SOG gas burner 

introduction cycling.

Burner switch in start position. Allow start after interlocks 

satisfied.

By operator.

Igniter interlocks satisfied. Interlocks from Auxiliary Fuel 

Guidelines 4 and 17.

Explosion from improper or 

delayed ignition.

Start approval. All burner/igniter interlocks 

satisfied.

Energize CNCG/SOV SSV. Admit gas to furnace.

CNCG/SOG burner in operation. Verify oxidation. Operator function

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Figure 8 Waste Stream Burner Protective Tripping Logic for CNCG.

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Table 7 Logic Explanation Chart for Figure 8 Protective Tripping Logic - Waste Stream Burner

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Lost 

Master Fuel Trip

(From Figure 2 Common 

Permissive Starting Logic 

in Safe Firing of Aux Fuel 

Guidelines).

Stop CNCG introduction 

when boiler firing 

permissives not met.

Prevent introduction of CNCG 

while boiler is not being fired. 

Steam Flow <50% MCR. Stop CNCG firing when 

firing rate below 

minimum.

Explosion or improper oxidation 

of gases.

Combustion air flow not 

normal. 

Stop CNCG firing in the 

event of air flow upsets to 

burner.

Potential explosion from 

improper or impaired air flow. 

Combustion air fan for 

waste stream burner not 

running.

Stop CNCG firing when 

no combustion air to 

burner.

Potential explosion from 

improper or impaired air flow. 

CNCG/SOG pressure low 

or high. 

Ensure proper gas 

properties and injection at 

proper velocity.

Flash back up piping or poor 

ignition beyond igniter. 

CNCG/SOG flow low Ensure proper velocity Plugged nozzle

CNCG/SOG temperature 

low.

Ensure proper gas 

properties.

Introduction of liquid.

Combustion air pressure 

not normal. 

Ensure proper combustion 

air properties.

Potential explosion from 

improper or impaired 

combustion air supply.

Igniter Interlocks not 

satisfied.

Interlocks from Auxiliary 

Fuel Guidelines 4 and 17 

not met.

Explosion from improper or 

delayed ignition. 

Seal pot level high. Prevent liquid back up. Possible explosion due to 

moisture introduction to boiler. 

Burner switch in stop 

mode.

Prevent firing of burner. Operator action.

Close CNCG/SOG SSV. Shutdown CNCG/SOG 

burner.

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Figure 9 Waste Stream Burner Permissive Starting Logic for SOG.

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Table 8 Logic Explanation Chart for Figure 9 Permissive Starting Logic for SOG - Waste Streams 

Burner

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit 

Maintained

(From Figure 2 Common 

Permissive Starting Logic in 

Safe Firing of Auxiliary Fuel 

Guidelines).

Ensure firing permissive. Prevent introduction of SOG while 

boiler is not being fired.

Steam Flow >50% MCR. Ensure furnace combustion 

is stable.

Explosion or improper oxidation of 

gases. This may require a higher 

steam flow based upon SOG 

requirements.

Combustion air fan for waste 

stream burner - proven 

running.

Ensure proper combustion 

air to burner.

Potential explosion from improper 

or impaired air flow. 

SOG temperature above 

minimum.

Ensure proper gas properties. Introduction of liquid. 

SOG pressure not high. Ensure proper gas properties 

and injection at proper 

velocity.

SOG pressure not low. Ensure proper gas properties 

and emitted at proper 

velocity.

Seal pot level not high. Prevent liquid back up. Possible explosion due to moisture 

introduction to boiler

SOG flow not low. Ensure SOG line velocity is 

adequate

Prevent flame propagation back 

through SOG line

Combustion air flow normal. Ensure air flow through 

burner.

Potential explosion from improper 

or impaired air flow.

Ignition system in operation -

minimum of one minute.

Ensure stable ignition system 

operation.

Possible explosion due to SOG gas 

burner introduction cycling.

Burner switch in start 

position. 

Allow operator to start 

burner after all other 

interlocks satisfied.

By operator. 

Igniter interlocks satisfied. Interlocks from Auxiliary 

Fuel Guidelines 4 and 17. 

Explosion from improper or 

delayed ignition.

Start approval. All burner/igniter interlocks 

satisfied.

Energize SOV SSV. Admit gas to furnace.

SOG burner in operation. Verify oxidation. Operator function.

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Figure 10 Waste Stream Burner Protective Tripping Logic for SOG.

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Table 9 Logic Explanation Chart for Figure 10 Protective Tripping Logic for SOG - Waste Stream 

Burner

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Lost 

Master Fuel Trip

(From Figure 3 Common 

Permissive Starting Logic 

in Safe Firing of Aux Fuel 

Guidelines).

Stop SOG introduction 

when boiler firing 

permissives not met.

Prevent introduction of SOG 

while boiler is not being fired. 

Steam Flow <50% MCR. Stop SOG firing when 

firing rate below 

minimum.

Explosion or improper oxidation 

of gases.

Combustion air flow not 

normal. 

Stop SOG firing in the 

event of air flow upsets to 

burner.

Potential explosion from 

improper or impaired air flow. 

Combustion air fan for 

waste stream burner not 

running. 

Stop SOG firing when no 

combustion air to burner. 

Potential explosion from 

improper or impaired air flow. 

SOG pressure low or high. Ensure proper gas 

properties and injection at 

proper velocity. 

Flash back up piping or poor 

ignition beyond igniter. 

SOG temperature low. Ensure proper gas 

properties.

Introduction of liquid. 

SOG flow low. Ensure SOG line velocity 

is adequate.

Prevent flame propagation back 

through SOG line.

Igniter Interlocks not 

satisfied.

Interlocks from Auxiliary 

Fuel Guidelines 5 and 18 

not met.

Explosion from improper or 

delayed ignition. 

Seal pot level high. Prevent liquid back up. Possible explosion due to 

moisture introduction to boiler.

Burner switch in stop 

mode.

Prevent firing of burner. Operator action.

Close SOG SSV. Shutdown SOG burner.

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CHAPTER 6 LIQUID WASTE STREAMS BLENDED WITH BLACK LIQUOR

6.1 Introduction

In the arena of thermal oxidation of liquid waste streams, presently the most common 

method for thermal oxidation is blending the waste stream into black liquor. The most 

common stream is spent acid from ClO2 or from tall oil. The second most common 

stream is soap. These two streams (spent acid and soap) represent the two general 

categories of streams covered by this guideline: those with a high water content and those 

that are waterless. In addition, this chapter addresses blending methanol, secondary 

sludge, tall oil, and turpentine (or red oil) with black liquor. 

The system designer should take into consideration features such as limit switches, “fail” 

position of valves and other safety features as appropriate. 

Here are some summary comments covering these guidelines:

• The boiler operation must be stable and firing liquor at a minimum load of 50% MCR 

when adding waste streams. The minimum load requirement assists in ensuring stable 

operation. 

• The waste stream must always be blended into black liquor before the refractometers 

to ensure that the refractometers read the stream that is being fired.

• Off-line solids testing of black liquor must be done every two hours when firing 

liquid waste streams.

• Adding a waste stream continuously provides better recovery furnace operation than a 

batch operation. 

• For streams added to black liquor after final concentration, the waste streams should 

be metered and proportioned to the black liquor flow rate. Waste stream flows should 

be limited such that if the stream flows were 100% water, the black liquor solids 

concentration would not fall below minimum safe firing level.

• High water content streams should be added before black liquor reaches its final 

concentration. Waterless streams should be added after the final mix tank. 

• Include a “management of change” procedure when you are designing or modifying a 

system to blend a waste stream with black liquor.

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• Effect of waste streams on refractometers:

• Waste streams can coat prisms.

• Soap lowers the refractive index.

• Un-neutralized spent acid lowers the refractive index due to precipitation of 

dissolved solids. The refractometer does not “see” suspended solids. 

• Turpentine or red oil lowers the refractive index. 

• AF&PA Recovery Boiler Reference Manual, Volume III section 5.2.1.4, is a good 

reference and was used in preparing this document.

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6.2 Methanol 

Definition: Liquid methanol is condensed from stripper off gas (SOG). SOG consists of 

approximately 50 percent methanol vapor by weight. SOG can be converted to a liquid of 

high methanol concentration and heating value through the process of methanol 

rectification. This liquid typically has a methanol content of 50 percent to 80 percent by 

weight, but can range from 30% to 90%. Specific gravity of 100% methanol is 0.79. 

Methanol from SOG usually contains TRS, terpenes, and other contaminants that make it 

noxious. 

Safeguards for combining methanol with the black liquor stream to the recovery 

boiler:

Where: Add methanol to black liquor after the point of final concentration in black 

liquor piping downstream of tankage including the salt cake mix tank. This will reduce 

the possibility of explosive gases in the vapor space in tanks. 

Ensure that there is adequate mixing of methanol and black liquor. The addition should 

occur far enough upstream in the piping to ensure proper mixing. 

If methanol is added upstream of black liquor pumps, be aware that methanol’s vapor 

pressure at black liquor’s temperature may result in flashing at the eye of the impeller, 

which will reduce pump capacity. 

Indirect black liquor heaters should be examined for ability to hold a “pocket” of 

methanol vapor. Injection of methanol downstream of an indirect black liquor heater may 

be preferable.

Addition point must be upstream of refractometers.

Although methanol has some water content, it cannot be added to black liquor before 

final concentration is reached because evaporators are an original source of methanol. 

Returning methanol to the evaporators will build the concentration of methanol rather 

than dispose of methanol. 

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend methanol with black liquor. 

Methanol flow rate must be measured to maintain a safe black liquor to methanol ratio. A 

safe upper limit is 1% by volume of methanol solution due to its volatile nature and 

potential instability.

Blend with black liquor using in-line mixing.

Methanol should be fed continuously to provide consistent refractometer readings. 

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Be aware of the possibility of methanol build-up in black liquor piping high points. 

Methanol must be isolated with a double isolation valve arrangement located near the 

methanol injection point in the black liquor line. This location minimizes residual 

methanol drainage into black liquor after the valves shut. 

Interlocks: Boiler must be operated in accordance with the Safe Firing of Black Liquor 

Guidelines. 

Methanol can only be added to the liquor system only when the operation of the recovery 

boiler is stable and firing liquor at a minimum load of 50% MCR. 

When safe firing system trips the black liquor system feed, the methanol feed is isolated 

by stopping the pump and automatically closing both isolation valves on the methanol 

feed line. Both stopping the pump and closing valves will ensure positive isolation of 

methanol.

Methanol feed must be stopped whenever black liquor is recirculated rather than fired to 

prevent build up of methanol and resulting vapors in black liquor and in liquor storage 

tanks. 

Do not blend methanol in a liquor firing system that continuously recirculates a portion of 

the liquor stream to a tank. A liquor system that continuously recirculates a portion of the 

liquor stream to a tank will suffer from build up of the methanol and resulting vapors in 

the black liquor and in liquor storage tanks. 

Methanol feed must be stopped at the low black liquor solids alarm point. Waste stream 

addition could be the cause of the low solids alarm, so a reasonable first step when solids 

are low is to stop waste stream addition.

A minimum black liquor solids content for allowing methanol introduction should be 

determined and used as a starting permissive for methanol incineration. This permissive 

can avoid a low solids alarm caused by a drop in refractometer liquor solids due to 

methanol addition. 

Starting and tripping logic diagrams for methanol are included at the end of this methanol 

section (see Figures 11 and 12).

Measurements: The methanol delivery system must have control room indication when 

methanol is being introduced. 

Flow rate should be measured. 

Consider measuring methanol concentration and isolating methanol line if methanol 

concentration indicates increased water presence.

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Consider having high and low flow alarms. 

Impacts of combining methanol with the black liquor stream to the recovery boiler: 

Heating Value: Higher heating value for 100% methanol is about 9200 Btu/lb. 

Volatility: Methanol’s boiling point is 148°F. Black liquor sampling upstream of 

methanol addition will avoid flashing methanol in sample. 

Corrosiveness: Corrosive; use stainless steel. 

Combustion: Flash point from 54°F (closed cup) as compared to 100°F to 150°F for fuel oil.

Solids Measurement: When firing methanol with black liquor, the black liquor 

refractive index may decrease, causing an apparent lower solids measurement. The 

decrease would be due to methanol having a refractive index lower than black liquor. 

Off-line testing will not be affected by methanol (but there will be an odor during off-line 

testing.) Operators and Instrument Technicians must understand the effect of methanol on 

the refractive index and off-line testing. The system must not compromise the minimum 

solids liquor divert recommended by Safe Firing of Black Liquor. 

An off-line solids measurement test must be conducted immediately after introduction or 

removal of methanol and at 2-hour intervals any time methanol is blended into black 

liquor. Off-line testing must recognize the odor potential of methanol. After removal of 

methanol, a second test must be done within 2 hours. The last test provides data for reestablishing correct on-line solids readings.

Methanol may accelerate build-up on the refractive lens resulting in inaccurate readings. 

The prism wash frequency may increase.

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Figure 11 Permissive Starting Logic for Methanol.

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Figure 12 Tripping Logic for Methanol.

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6.3 Secondary Sludge 

Definition: Secondary sludge is the waste residue resulting from the biological treatment 

of wastewater. The treatment of wastewater is usually a two stage process; the first stage 

(primary treatment) removes suspended solids and fibrous material. The wastewater is 

then passed on to the secondary treatment where bacteria digest organic material in the 

wastewater. The residue from the treatment forms a sludge that has a very high moisture 

content (>90%). The sludge can have a portion of the moisture mechanically removed 

(i.e. by centrifuge) prior to introduction into the black liquor system. 

Safeguards for combining secondary sludge with the black liquor stream to the 

recovery boiler:

Where: Secondary sludge shall only be introduced into the black liquor system prior to 

the point of final concentration. The preferred location for introduction is prior to or into 

the evaporator system.

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend secondary sludge with black liquor. 

Secondary sludge may be introduced into the black liquor system as a separate stream 

upstream of the evaporators, between evaporator effects, or upstream of the 

concentrators. Sludge should be introduced into a location that provides adequate 

blending with the black liquor. Sludge blending with black liquor should be on a 

continuous basis as opposed to batch-process to provide more uniform and predictable 

performance.

A typical secondary sludge feed rate is approximately 2% of the black liquor solids. This 

small quantity is not expected to create significant volatility, corrosiveness, or 

combustion problems in the recovery boiler furnace. 

Interlocks: Since the addition of secondary sludge may only be added prior to the point 

of final concentration, use and design of interlocks will be up to the user. 

Measurement: The quantity of secondary sludge delivered to the black liquor system 

should be monitored. 

The secondary sludge delivery system must have control room indication when sludge is 

being introduced. 

Impacts of combining secondary sludge with the black liquor stream to the recovery 

boiler:

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Heating value of liquor: Introducing the sludge in to the black liquor system upstream 

of the final evaporation stages will minimize the sludge’s effect on as-fired heating value 

and dilution of black liquor solids levels. 

Volatility: Based on limited information, the addition of secondary sludge to the black 

liquor system should not affect the liquor volatility.

Corrosiveness: The end user shall determine the impact of secondary sludge on black 

liquor chemistry to identify the potential for increased corrosion of boiler components. 

Based on limited information, secondary sludge should not create additional corrosion 

mechanisms in the black liquor system. Corrosion resistant materials already in use in 

black liquor systems should be suitable for the dilute mixture of secondary sludge and 

black liquor. 

Combustion: Based on limited information, the addition of secondary sludge to the black 

liquor upstream of the evaporators may have a favorable impact due to a slight increase 

in liquor heating value. 

Solids measurement: Secondary sludge may accelerate the buildup on the optical 

components of the solids measuring devices (refractometers), requiring more frequent 

cleaning and calibration.

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6.4 Soap 

Definition: Black liquor soap is a mixture of resin and fatty acids that is separated from 

weak and intermediate black liquors. It is removed to avoid scaling and foaming in the 

evaporators and concentrators. Soap may have commercial value. Softwoods contain 

more soap than hardwoods, which necessitates soap removal. 

Safeguards for combining soap with the black liquor stream to the recovery boiler:

Where: Add soap to black liquor after the point of final concentration. 

To ensure adequate mixing, consider adding the soap to the suction of the black liquor 

fuel pumps. If not added to the black liquor pump suction, the addition should occur far 

enough upstream in the piping to ensure proper mixing. It is critical that soap be 

prevented from separating from the black liquor after mixing. Soap should not be 

introduced upstream of a non-agitated tank.

Addition point must be upstream of refractometers.

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend soap with black liquor. 

Blend with black liquor using in-line mixing.

Soap should be fed continuously to provide consistent boiler operation and refractometer 

readings.

Soap must be isolated with a double isolation valve arrangement located near the soap 

injection point in the black liquor line. This location minimizes residual soap drainage 

into black liquor after the valves shut. 

Soap should be metered relative to BL to maintain a constant soap concentration. This 

might be accomplished with an in-line device such as a separate density meter to verify 

the quality of soap to water content. 

The upper limit on soap firing should be established by assuming that if the soap flow 

were 100% water, the black liquor solids concentration would not fall below minimum 

safe firing level.

Interlocks: Boiler must be operated in accordance with the Safe Firing of Black Liquor 

Guidelines. 

Soap can only be added to the liquor system when the operation of the recovery boiler is 

stable and firing liquor at a minimum load of 50% MCR. 

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When safe firing system trips the black liquor system feed, the soap feed is isolated by 

automatically closing both isolation valves on the soap feed line. The soap pump can continue to 

run, allowing soap to recirculate when not being blended with black liquor. 

Soap feed must be stopped whenever black liquor is recirculated rather than fired to 

prevent build up of soap in liquor storage tanks.

Soap blending in a liquor firing system that continuously recirculates a portion of the 

liquor stream to tank(s) must have continuous agitation in the tank(s) to avoid separation 

of soap and liquor. 

Soap feed must be stopped at the low black liquor solids alarm point. Waste stream 

addition could be the cause of the low solids alarm, so a reasonable first step when solids 

are low is to stop waste stream addition.

A minimum black liquor solids content for allowing soap introduction should be 

determined and used as a starting permissive for soap incineration. This permissive can 

avoid a low solids alarm caused by a drop in refractometer liquor solids due to soap 

addition. 

Starting and tripping logic diagrams for soap are included at the end of this soap section

(see Figures 13 and 14).

Measurement: The soap delivery system must have control room indication when soap 

is being introduced. 

The soap delivery system should have either a flow meter or a delivery system design 

that will maintain soap in proportion to the liquor flow. 

Consider using an in-line device to determine the amount of water in soap. Soap density 

measurement is a proven method of monitoring water content. 

Impacts of combining soap with the black liquor stream to the recovery boiler:

Heating Value: Soap has a greater heating value than black liquor. 

Corrosiveness: Not corrosive.

Volatility: Low

Combustion: Addition of soap will increase the liquor HHV. Soap burns more 

aggressively than black liquor resulting in a hotter fire and smaller bed. Operators must 

adjust to the burning characteristics of soap. 

Solids Measurement: When firing soap with black liquor, the black liquor refractive 

index will decrease, causing an apparent lower solids measurement. The decrease would 

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be due to soap having a refractive index lower than black liquor. Off-line testing will 

include soap solids as part of black liquor solids so the results will be higher than actual 

black liquor solids content. Operators and Instrument Technicians must understand the 

effect of soap on the refractive index and off-line testing. The system must not 

compromise the minimum solids liquor divert recommended by Safe Firing of Black 

Liquor. 

An off-line solids measurement test must be conducted immediately after introduction or 

removal of soap and at 2-hour intervals any time soap is blended into black liquor. 

Addition of soap can give a false high reading for the off-line solids measurement field 

test. After removal of soap, a second test must be done within 2 hours. The last test 

provides data for re-establishing correct on-line solids readings.

The soap can coat the refractive lens resulting in inaccurate readings. The prism wash frequency 

will increase.

Increasing the quality of soap mixing will cause fewer problems with the refractometers.

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Figure 13 Permissive Starting Logic for Soap.

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Figure 14 Tripping Logic for Soap.

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6.5 Spent Acid from ClO2 and Tall Oil Brine

Definitions: The aqueous solution by-product from the acidulation of tall oil soap to tall 

oil, usually consisting primarily of sodium sulfate in water solution. ClO2 spent acid is 

the effluent from a ClO2 generator. It is an aqueous solution containing Na2SO4, H2SO4, 

NaCl and NaClO3. 

The term “spent acid” will be used to refer to both tall oil brine and ClO2 spent acid.

Safeguards for combining spent acid with the black liquor stream to the recovery 

boiler:

Where: Due to water content in this stream, the preferred feed point is prior to the point 

of final concentration. 

To avoid possible evaporator scaling, consider adding the spent acid to the 50% black 

liquor feed to the concentrators or direct contact evaporator. 

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend spent acid with black liquor. 

Neutralize the spent acid before it is added to the black liquor. This will help prevent the 

black liquor viscosity from increasing and will prevent the formation of H2S. 

Neutralization should be to a minimum pH of 10.5. 

Tanks in which tall oil spent acid is added to the black liquor should be vented to the 

NCG system to prevent escape to the atmosphere of any toxic gases formed.

If spent acid is added after final concentration, it should be added continuously to provide 

consistent refractometer readings.

Spent acid added after the point of final concentration must be isolated with a double 

isolation valve arrangement located near the spent acid injection point in the black liquor 

line. This location minimizes residual spent acid drainage into black liquor after the 

valves shut. 

Interlocks: Boiler must be operated in accordance with the Safe Firing of Black Liquor 

Guidelines. 

If added to weak black liquor, addition of spent acid can be independent of black liquor 

firing rate.

If added to concentrated black liquor after the point of final concentration, spent acid can 

only be admitted when the operation of the recovery boiler is stable and firing liquor at a 

minimum load of 50% MCR. 

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If added to concentrated black liquor after the point of final concentration, spent acid feed 

must be stopped whenever black liquor is recirculated rather than fired to prevent build 

up of spent acid in liquor storage tanks. 

When the safe firing system trips the black liquor feed, the spent acid feed after point of 

final concentration is isolated by stopping the pump and automatically closing both 

isolation valves on the feed line. Both stopping the pump and closing valves will ensure 

positive isolation of spent acid. 

Spent acid feed after the point of final concentration must be stopped at the low black 

liquor solids alarm point. Waste stream addition could be the cause of the low solids 

alarm, so a reasonable first step when solids are low is to stop waste stream addition. 

If spent acid is added after point of final concentration, a minimum black liquor solids 

content for allowing spent acid introduction should be determined and used as a starting 

permissive for spent acid. This permissive can avoid a low solids alarm caused by a drop 

in refractometer liquor solids due to spent acid addition. 

Starting and tripping logic diagrams for spent acid when added after the point of final 

concentration are included at the end of this spent acid section (see Figures 15 and 16).

Measurement: Spent acid added after point of final concentration must be measured and 

proportioned to black liquor flow rate. 

The spent acid delivery system must have control room indication when spent acid is 

being introduced. 

If neutralized after point of final concentration, neutralization system must have boiler 

control room indicators and alarms for operating out of normal range. 

Spent acid added after point of final concentration must have control room flow read out 

to avoid excess dilution 

Impacts of combining spent acid with the black liquor stream to the recovery boiler:

Heating Value: Addition of spent acid will reduce the heating value of the black liquor. 

Volatility: Could have H2S release during pH excursion. 

Corrosiveness: Is corrosive, and this must be considered in piping and injection interface 

design. 

Combustion: Non-combustible but could have H2S 

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Solids Measurement: Spent acid might lower the black liquor refractometer solids 

reading by precipitating out lignins if not neutralized. Refractometers do not “see” 

suspended solids so they will not detect precipitated lignins. Spent acid does not affect 

off-line testing. Operators and Instrument Technicians must understand the effect of spent 

acid on the refractive index and off-line testing. The system must not compromise the 

minimum solids liquor divert recommended by Safe Firing of Black Liquor. 

When adding after point of final concentration an off-line solids measurement test must 

be conducted immediately after introduction or removal of spent acid and at 2-hour 

intervals any time spent acid is blended into black liquor. After removal of spent acid, a 

second test must be done within 2 hours. The last test provides data for re-establishing 

correct on-line solids readings. 

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Figure 15 Permissive Starting Logic for Spent Acid when added after Point of Final Concentration.

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Figure 16 Tripping Logic for Spent Acid when added after Point of Final Concentration.

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6.6 Tall Oil

Definition: Tall Oil is a mixture of fatty acids, rosin and neutral materials resulting from 

the acidulation of soap skimmings from kraft black liquor. Specific gravity is 

approximately 0.9. Heating value for tall oil is in the range of 16,000 to 18,000 BTU/Lb. 

Safeguards for combining tall oil with the black liquor stream to the recovery 

boiler:

Where: Due to low specific gravity, add tall oil to black liquor after the point of final 

concentration in black liquor piping downstream of tankage including the salt cake mix 

tank. To ensure adequate mixing, consider adding the tall oil to the suction of the black 

liquor fuel pumps. If not added to the black liquor pump suction, the addition should 

occur far enough upstream in the piping to ensure proper mixing. 

Addition point must be upstream of refractometers.

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend tall oil with black liquor.

Blend with black liquor using in-line mixing.

Ensure consistent refractometer reading by feeding tall oil continuously. 

Tall oil must be isolated with a double isolation valve arrangement located near the tall 

oil injection point in the black liquor line. This location minimizes residual tall oil 

drainage into black liquor after the valves shut. 

The upper limit on tall oil firing should be established by assuming that if the tall oil flow 

were 100% water, the black liquor solids concentration would not fall below minimum 

safe firing level.

Interlocks: Boiler must be operated in accordance with the Safe Firing of Black Liquor 

Guidelines. 

Tall oil can only be added to the liquor system when the operation of the recovery boiler 

is stable and firing liquor at a minimum load of 50% MCR.

When safe firing system trips the black liquor system feed, the tall oil feed is isolated by 

automatically closing both isolation valves on the tall oil feed line. The tall oil pump can 

continue to run, allowing tall oil to recirculate when not being blended with black liquor. 

Tall oil feed must be stopped whenever black liquor is recirculated rather than fired to 

prevent build up of tall oil in liquor storage tanks. 

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Tall oil blending in a liquor firing system that continuously recirculates a portion of the 

liquor stream to tanks must have continuous agitation in the tanks to avoid separation of 

tall oil and liquor.

Tall oil feed must be stopped at the low black liquor solids alarm point. Waste stream 

addition could be the cause of the low solids alarm, so a reasonable first step when solids 

are low is to stop waste stream addition.

A minimum black liquor solids content for allowing tall oil introduction should be 

determined and used as a starting permissive for tall oil incineration. This permissive can 

avoid a low solids alarm caused by a drop in refractometer liquor solids due to tall oil 

addition. 

Starting and tripping logic diagrams for tall oil are included at the end of this tall oil 

section (see Figures 17 and 18). 

Measurements: Tall oil flow rate must be measured and proportioned to black liquor 

firing rate.

The tall oil delivery system must have control room indication when tall oil is being 

introduced. 

Impacts of combining tall oil with the black liquor stream to the recovery boiler:

Heating Value: Tall oil heating value is in the range of 16,000 to 18,000 Btu/lb. Thus the 

heat release of the tall oil will be considerably higher than that of black liquor. 

Volatility: Not volatile at handling temperatures.

Corrosiveness: Not corrosive.

Combustion: Flash point from 385°F to 420°F as compared to 100°F to 150°F for fuel 

oil. 

Solids Measurement: Addition of tall oil will lower the refractive index, making the 

refractometers read a lower solids than actual. The decrease would be due to tall oil 

having a refractive index lower than black liquor. Operators and Instrument Technicians 

must understand the effect of tall oil on the refractive index. The system must not 

compromise the minimum solids liquor divert recommended by Safe Firing of Black 

Liquor. 

An off-line solids measurement test must be conducted immediately after introduction or 

removal of tall oil and at 2-hour intervals any time tall oil is blended into black liquor. 

After removal of tall oil, a second test must be done within 2 hours. The last test provides 

data for re-establishing correct on-line solids readings.

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The tall oil can coat the refractive lens resulting in inaccurate readings. The prism wash 

frequency will increase.

Increasing the quality of tall oil mixing will cause fewer problems with the 

refractometers.

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Figure 17 Permissive Starting Logic for Tall Oil.

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Figure 18 Tripping Logic for Tall Oil.

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6.7 Turpentine

Definition: Most spruces, firs and pines are rich in terpenes that can be recovered from 

flashing and evaporation of black liquor. Typically contaminated to varying degrees with 

sulfides, crude sulfate turpentine has a market value that is usually high enough that it is 

preferably sold rather than burned. In cases where the sulfide levels are too high or the 

terpene composition is of poor quality, incineration may be the only available disposal 

option. 

In addition to direct recovery of turpentine from condensed vapor, foul condensate 

stripping systems can generate sulfide-rich foul turpentine, or “Red Oil” that is not 

marketable. Most stripping systems are designed and operated to keep the turpentine 

vaporized in the methanol-rich Stripper Off-Gas. Some existing older designs still 

generate a decanted oil layer that requires special handling and disposal.

Generation rates in Kraft batch mills where turpentine quality is generally good are about 

0.5-1.5 gallons/bdt softwood chips. Continuous Kraft cooking generates between 0.3-1.0 

gallons of turpentine/bdt chips. 

Mills that produce poor quality turpentine also typically generate less overall, usually 

between 0.1-0.15 gallons/bdt chips. On a 75% black liquor solids basis, this amounts to 

about 0.05% by volume. Addition of Stripper-generated “Red Oil” may increase this rate 

to 0.1%. For example, a mill that burns 400 gpm of heavy liquor will have a turpentine 

flow of about 0.4 gpm, or 1.5 L/min. Some mills are firing black liquor blended with up 

to 1% turpentine by volume. 

Safeguards for combining turpentine with the black liquor stream to the recovery boiler: 

Where: Add turpentine to black liquor after the point of final concentration in black 

liquor piping downstream of tankage including the salt cake mix tank to minimize the 

possibility of explosive gases in the vapor space in tanks. 

Addition should occur far enough upstream in the piping to ensure adequate mixing. 

 

Because of the high recirculation rate in the heating loop, it may be preferable to inject 

turpentine downstream of the black liquor indirect heater system. 

Turpentine injection must be downstream of a direct heater to prevent flashing of 

turpentine when the loss of steam desuperheating results in the steam temperature 

exceeding 350F. 

The addition point must be upstream of refractometers.

How: Include a “management of change” procedure when you are designing or 

modifying a system to blend turpentine with black liquor. 

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Turpentine flow must be metered by continuous injection to maintain a safe black liquor 

to turpentine ratio and to provide consistent refractometer readings. A suggested upper 

limit is 0.5% by volume of turpentine solution in black liquor. 

Blend with black liquor using in-line mixing via direct injection.

As with methanol solution, crude sulfate turpentine and “Red Oil” are high in odorous 

sulfide and nitrogen compounds that can permeate furnace wall deposits and generate 

operating floor odors in the event of furnace pressure upsets. 

Turpentine must be isolated with a double isolation valve arrangement located near the 

turpentine injection point in the black liquor line. This location minimizes residual 

turpentine drainage into black liquor after the valves shut. 

Interlocks: Boiler must be operated in accordance with the Safe Firing of Black Liquor 

Guidelines. 

Turpentine can only be added to the liquor system when the operation of the recovery 

boiler is stable and firing liquor at a minimum load of 50% MCR. 

When safe firing system trips the black liquor system feed, the turpentine feed is isolated 

by stopping the pump and automatically closing the downstream isolation valve on the 

turpentine feed line. Both stopping the pump and closing the valve will ensure positive 

isolation of turpentine.

Turpentine feed must be stopped whenever black liquor is re-circulated rather than fired 

to prevent build up of turpentine and resulting vapors in black liquor piping and in liquor 

storage tanks. An exception to this requirement is partial recirculation to a tank that is 

vented to the CNCG or a pressurized storage tank that flashes back to the evaporators. 

Turpentine feed must be stopped at the low black liquor solids alarm point. Waste stream 

addition could be the cause of the low solids alarm, so a reasonable first step when solids 

are low is to stop waste stream addition.

A minimum black liquor solids content for allowing turpentine introduction should be 

determined and used as a starting permissive for turpentine incineration. This permissive 

can avoid a low solids alarm caused by a drop in refractometer liquor solids due to 

turpentine addition. 

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All turpentine injection should be stopped well in advance of any planned removal of a 

liquor gun or nozzle to allow sufficient time to purge turpentine-bearing liquor from the 

system. 

Starting and tripping logic diagrams for turpentine are included with this turpentine 

section.

Measurements: The turpentine delivery system must have control room indication when 

turpentine is being introduced. 

Flow rate shall be measured.

Consider having high and low flow alarms. 

Impacts of combining turpentine with the black liquor stream to the recovery boiler: 

• Heating Value: Higher heating value for 100% turpentine is about 19,000 Btu/lb. 

• Volatility: Turpentine’s boiling point is about 300°F.

• Corrosiveness: Corrosive due to sulfide content; use stainless steel, preferably 

welded fittings.

• Combustion: Flash point for pure turpentine is about 95°

F (closed cup) as compared 

to 100°F to 150°F for fuel oil; however, sulfide content can lower the measured values 

to <50°

F. Auto-ignition temperature of turpentine is 400°F.

• Solids Measurement: When firing turpentine with black liquor, the black liquor 

refractive index will slightly decrease, causing an apparent lower solids measurement 

of up to 0.6% for a 1% by volume addition of turpentine. The decrease would be due 

to turpentine having a refractive index lower than black liquor. Off-line testing 

method will not be affected by turpentine (but there may be an odor during off-line 

testing.), but results may be slightly lower percent solids due to vaporization of 

turpentine during the cook techniques. The percentage lower would be dependent on 

percent volume of turpentine. Operators and Instrument Technicians must understand 

the effect of turpentine on the refractive index and off-line testing. The system must 

not compromise the minimum solids liquor divert system recommended by Safe 

Firing of Black Liquor.

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• An off-line solids measurement test must be conducted immediately after introduction 

or removal of turpentine and at 2-hour intervals any time turpentine is blended into 

black liquor. Off-line testing must recognize the odor potential of turpentine. 

• Turpentine addition is not expected to accelerate build-up on the refractive lens. 

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Figure 19 Permissive Starting Logic for Turpentine.

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Figure 20 Tripping Logic for Turpentine.

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CHAPTER 7 GUIDELINES FOR THERMAL OXIDATION OF LIQUID WASTE 

STREAMS IN DEDICATED BURNERS

7.1 Introduction

Chapter 7 describes the use of dedicated burners as the control devices for thermal 

oxidation of liquid waste steams in recovery boilers. While many liquid waste streams are 

generated in the chemical recovery and wood pulping processes, this guideline is 

applicable only to combustible liquid waste streams. The most common liquid waste 

streams that meet this requirement are methanol, turpentine and tall oil. These liquid 

streams may be fired separately, or in a blended combination. A dedicated burner may 

not be the best location to oxidize these streams, and there may be other waste streams 

that have similar characteristics to these streams that are not specifically mentioned in 

this document. The purpose of this document is to describe recommended guidelines for 

thermal oxidation of any liquid waste stream in dedicated burners, with additional 

information provided for the waste streams considered to be the most common candidates 

for such incineration. 

Attempting to oxidize a non-combustible liquid waste stream in a dedicated burner may 

be an ineffective oxidation method at best, and a possible hazard to safe boiler operation. 

Non-combustible liquid waste streams should be disposed of by means other than a 

dedicated burner in a recovery boiler. These streams include, but are not limited to spent 

acid and secondary sludge. 

The thermal oxidation of liquid waste streams in dedicated burners in recovery boilers is 

very similar to the firing of fuel oil in auxiliary burners in recovery boilers. The basic 

physical characteristics of the equipment and materials involved are very similar. The 

recommendations described in the “Recommended Good Practice for Safe Firing of 

Auxiliary Fuels in Black Liquor Recovery Boilers,” with some specific additional 

recommendations, apply directly to the thermal oxidation of liquid waste streams in 

dedicated burners in recovery boilers. These specific additional recommendations are 

described in this chapter. 

These recommendations should be followed in addition to those given for fuel oil fired 

burners in the “Recommended Good Practice for Safe Firing of Auxiliary Fuels in Black 

Liquor Recovery Boilers.” In the case of the dedicated liquid waste stream burner, the 

liquid waste stream is treated as an “Auxiliary Fuel” for the burner. This is a direct 

contradiction of the definition of an Auxiliary Fuel given in the “...Safe Firing of 

Auxiliary Fuel...” guideline, but it is necessary for the purposes of this guideline and it 

does not violate the spirit of the recommendations for auxiliary fuels. Consideration of 

the heating pattern generated by the liquid waste stream burner will be of limited 

importance in most cases. As a matter of clarity, the auxiliary fuel guidelines specific to 

gas fired main burners will not apply to liquid waste stream burners. 

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7.2 Safety

7.2.1 System Safety

For the purpose of this guideline, liquid waste streams that are permissible to fire in a 

dedicated burner are considered fuels. For specific guidelines concerning the basic 

acceptable characteristics of liquid waste streams that may be fired in a dedicated burner, 

please refer to section 7.4 of this document. 

During the thermal oxidation of liquid waste streams in dedicated burners, the safety 

hazards for both personnel and equipment have to be considered. The equipment for 

thermal oxidation as well as handling and transporting the liquid waste stream has to be 

designed and controlled such that: 

• The liquid waste stream cannot escape into the recovery boiler building. 

• Fire and explosion in equipment and piping systems is prevented. 

• Positive ignition of the liquid waste stream entering the furnace is provided. 

• The boiler should be operating at a load of 50% or greater. 

• The waste stream does not contain excessive water as determined by density or other 

appropriate measurement.

At a minimum, the safety requirements for the thermal oxidation of liquid waste streams 

in a dedicated burner must meet the guidelines presented in the following BLRBAC 

publications: 

• Recommended Good Practice for the Safe Firing of Auxiliary Fuels in Black Liquor 

Recovery Boilers

• Recommended Good Practice for the Safe Firing of Black Liquor in Black Liquor 

Recovery Boilers

• Recommended Rules for Personnel Safety for Black Liquor Recovery Boilers 

• Instrumentation Checklist and Classification Guide for Instruments and Controls 

Used in Operation of Black Liquor Recovery Boiler 

7.2.2 Personnel Safety

The liquid waste streams must be handled with great care. Each waste stream has unique 

hazards that must be considered. Some general characteristics of various liquid waste 

streams, and their associated hazards are discussed in the next section. For more specific 

risks associated with hazardous compounds present in liquid waste streams, see published 

health and safety guidelines concerning these compounds. The nature of each liquid 

waste stream must be clearly understood prior to the design of a dedicated waste stream 

burner and handling system. 

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Areas containing liquid waste stream piping and equipment should be monitored in 

accordance with applicable safety codes.

Routine inspection and repair of the liquid waste stream transport system should be 

performed at sufficient frequency to prevent leaks in the system and/or malfunction or 

failure of control devices. 

Some tasks associated with the normal operation of a dedicated liquid waste stream 

burner may potentially expose operators to noxious fumes or other hazards. These 

hazards must be clearly understood and the proper personal protective equipment (PPE) 

must be identified and used as needed. Proper system purge, maintenance and lock out 

procedures must be developed and strictly adhered to. 

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7.3 Descriptions of Liquid Waste Streams Expected to be Fired in Dedicated 

Burners

7.3.1 Methanol

Liquid methanol is typically condensed from stripper off gas (SOG). SOG consists of 

approximately 50 percent methanol vapor by weight. SOG can be converted to a liquid of 

high methanol concentration and heating value through the process of methanol 

rectification. This liquid typically has a methanol content of 50 to 80 percent by weight, 

but can range from 30 to 90 percent. Methanol from SOG usually contains TRS, 

turpenes, and other contaminants that make it noxious. Care should be taken to design 

dedicated methanol burners and transport systems to limit personnel exposure to 

methanol vapor and liquid. Proper PPE should be identified for and used by operators of 

methanol burners. The exposure limits and hazards of other chemicals that might be 

present in methanol must also be identified and appropriate protective measures must be 

taken.

Physical & Chemical Properties

Physical State: Liquid

Appearance: clear, colorless

Odor: alcohol-like – weak odor 

pH: N/A

Vapor Pressure: 127 mm Hg @ 25 deg C 

Vapor Density: 1.11 (Air = 1) 

Evaporation Rate: 2 (Butyl acetate = 1)

Viscosity: 0.55 cP @ 20 deg C 

Boiling Point: 64.7 deg C @ 760.00 mm Hg 

Freezing/Melting Point: -98 deg C 

Auto-ignition Temperature: 464 deg C ( 867.20 deg F) 

Flash Point: 11 deg C ( 51.80 deg F) or less depending on Sulfur content 

NFPA Rating: (estimated) Health: 1; Flammability: 3; Reactivity: 0

Explosion Limits, Lower: 6.0 vol %;Upper: 36.00 vol % 

Solubility in water: miscible

Specific Gravity/Density: 0.7910g/cm3 

The above properties are for pure methanol and may vary significantly depending 

on the concentration of contaminants, such as sulfur compounds, in the methanol 

stream. 

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7.3.2 Turpentine and Red Oil

Sulfate turpentine is a by-product of the pulping of softwood. Sulfate turpentine is 

collected from digester relief gases, and may contain additional hazardous chemicals such 

as dimethyl sulfide, dimethyl disulfide and methyl mercaptan. Red oil, such as that 

decanted from foul condensate stripping systems is considered the same as turpentine in 

this Chapter. Turpentine is explosive and has an undefined upper explosion limit. 

Turpentine is noxious. Care should be taken to design dedicated turpentine burners and 

transport systems to limit personnel exposure to turpentine vapor and liquid. Proper PPE 

should be identified for and used by operators of turpentine burners. 

Physical & Chemical Properties

Physical State: Liquid

Appearance: clear to dark brown

Odor: foul Kraft pulp mill odor 

pH: N/A

Vapor Pressure: 5 mm Hg @ 25 deg C 

Vapor Density: 4.8 (Air = 1) 

Evaporation Rate: 0.4 (Butyl acetate = 1)

Viscosity: N/A

Boiling Point: 119 to 173 deg C @ 760.00 mm Hg 

Freezing/Melting Point: -50 to -60 deg C 

Auto-ignition Temperature: 253 deg C ( 488 deg F) 

Flash Point: 23 to 35 deg C (73 to 95 deg F) or less depending on sulfur content 

NFPA Rating: (estimated) Health: 2; Flammability: 3; Reactivity: 0

Explosion Limits, Lower: 0.8 vol %; Upper: Unknown 

Solubility in water: 0.023% @ 25 deg C 

Specific Gravity/Density: 0.87g/cm3 

The above properties are for pure turpentine and may vary significantly depending 

on the concentration of contaminants, such as sulfur compounds, in the turpentine 

stream.

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7.3.3 Crude Tall Oil

Crude tall oil is a mixture of fatty acids, rosin and neutral materials resulting from the 

acidulation of soap skimmings from Kraft black liquor. The crude tall oil is pumped to 

the recovery boiler from the crude tall oil storage tank. Care should be taken to design 

dedicated crude tall oil burners and transport systems to limit personnel exposure to crude 

tall oil liquid or vapor. Proper PPE should be identified for and used by operators of 

crude tall oil burners. 

Physical & Chemical Properties

Physical State: Liquid

Appearance: amber to dark brown 

Odor: acrid

pH: 11 to 12 

Vapor Pressure: negligible @ 25 deg C 

Vapor Density: 0 (Air = 1) 

Evaporation Rate: under 1 (Butyl acetate = 1)

Viscosity: N/A

Boiling Point: 260 deg C @ 760.00 mm Hg 

Freezing/Melting Point: N/A

Auto-ignition Temperature: N/A

Flash Point: 191 to 193 deg C (375 to 380 deg F) 

NFPA Rating: (estimated) Health: ?; Flammability: ?; Reactivity: ?

Explosion Limits, Lower: N/A; Upper: N/A

Solubility in water: negligible

Specific Gravity/Density: 0.95 to 1.00g/cm3 

The above properties are for pure tall oil and may vary significantly depending on 

the concentration of contaminants, such as sulfur compounds, in the tall oil stream. 

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7.4 Recommended Waste Stream Characteristics

7.4.1 Basic Acceptable Characteristics for Combustion in a Dedicated Burner

The water content of any liquid waste stream should be minimized. If the liquid waste 

stream contains water, it should be fully miscible. There should be sufficient heat content 

in the waste stream to fully evaporate any water it contains. If a liquid waste stream is to 

contain water, some positive means of monitoring the water content must be used and an 

acceptable upper limit of water concentration must be established. If this upper limit is 

exceeded, the liquid waste stream must be diverted from the burner. 

The liquid waste stream viscosity should be low enough to allow effective flow and 

atomization. If the viscosity of the liquid waste stream is too high at ambient temperature, 

it should be heated until an acceptable viscosity is achieved. Viscosity should also be 

relatively constant. Significant variation in viscosity can cause poor atomization and 

flame instability. The expected absolute viscosity limits and variability are to be provided 

to the burner designer. 

The liquid waste stream should be as homogeneous as possible. Homogeneity is 

important to flame stability. Should the waste stream be a blend of different streams, the

multiple streams should be fully miscible to avoid slug flow of different streams. 

The liquid waste stream must have a net positive heating value. Wide variation in waste 

stream heating value during burner operation can cause an unsafe air to fuel ratio at the 

burner and flame instability. Heating value variation should be maintained within a 

sufficiently narrow band to avoid these problems. The burner designer must be made 

aware of the absolute limits of the waste stream heating value and of the potential for 

variation of heating value. 

7.4.2 Characteristics of Class A Waste Streams

Class A waste streams possess characteristics that will allow them to be safely fired in a 

dedicated burner without a separate continuous positive ignition source. The flame

produced by these streams can be effectively scanned and discriminated from other 

combustion within the furnace. In addition to the basic acceptable characteristics, the key 

characteristics of these streams are homogeneity, sufficient volatility for positive ignition, 

and limited variation in heating value and other physical characteristics. The specific 

limits of each of these characteristics must be defined by the burner designer with 

consideration of the overall operating environment of the waste stream burner including, 

but not limited to, combustion air conditions and supply, atomizing medium, flame 

scanner performance and combustion conditions within the furnace. Class A waste 

streams may be used to fire support burners for other liquid or gaseous waste streams.

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The final decision on classification of waste streams as Class A rests with the burner 

designer. 

7.4.3 Characteristics of Class B Waste Streams

Class B waste streams posses characteristics that will allow them to be safely fired in a 

dedicated burner with a separate continuous positive ignition source, but are not of 

sufficient quality to be considered Class A waste streams. This separate ignition source 

will be of sufficient heat input to provide positive stable ignition of the liquid waste 

stream based on the requirements of the burner designer. The final decision on 

classification of waste streams as Class B rests with the burner designer.

7.4.4 Characteristics of Class C Waste Streams

Any liquid waste stream not classified as Class A or B is classified Class C. These 

streams do not possess the basic acceptable characteristics. These streams must not be 

fired in dedicated burners. Two examples of these streams are spent acid and secondary 

sludge. 

7.5 Dedicated Burners for Thermal Oxidation 

7.5.1 All Dedicated Burners

The waste stream burner(s) should be mechanically suited for installation and operation 

in a Kraft recovery boiler. Some specific issues might include smelt flow across the 

burner tip and high radiant heat from the furnace. The ultimate responsibility for the final 

design of the waste stream burner, including consideration of all the following parameters 

lies with the burner supplier. 

The waste stream burner(s) should have a dedicated air system. The combustion air can 

be supplied from a separate fan or from a recovery boiler FD fan. Proof of adequate 

combustion air flow is required as proven by a flow switch or other suitable means. 

Liquid waste streams may be conveyed to the burner through independent lines and 

injected into the flame zone separately. It is acceptable to have multiple separate liquid 

waste stream atomizers within a single burner. It is also permissible to fire the liquid 

streams in a blended condition. Should the waste stream be a blend of different streams,

the multiple streams should be fully miscible to be classified as a Class A waste stream. 

Blended waste streams that are not fully miscible must be classified as Class B. The 

combined maximum total heat input for the liquid waste stream burner must not exceed 

the maximum heat input for a single burner recommended by the boiler designer. If the 

burner designer is also an OEM for Kraft recovery boilers, they may set the maximum 

waste stream burner heat input based on their own design criteria. 

The atomizer design and atomizing medium should be selected with consideration of the 

flash point of the liquid waste stream to prevent flashing of the fluid in the atomizer.

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Atomizer design should also consider the viscosity of the waste stream. Heating of the 

waste stream to achieve sufficiently low viscosity may be acceptable, but may present 

problems with blended streams including streams of both high and low flash points. 

The burner should be placed in the high heat zone of the furnace at or below the tertiary 

air level, at an elevation low enough in the furnace to allow complete burn out of the 

waste stream before it can exit the furnace. It should be placed in such a manner that 

disturbances in the main flame and/or igniter flame are avoided so as to not create 

difficulty with flame detection for either the waste streams or the support flame (if 

required), or the lighter. 

7.5.2 Burners Firing Class A Streams

If the waste stream to be fired is a Class A stream, the dedicated waste stream burner is 

not required to have a separate continuous positive ignition source. The flame safety 

system for this type of burner will rely on positive detection of the waste stream flame. 

This liquid waste burner must be equipped with a flame detection device able to detect 

the waste stream flame, and able to discriminate that flame against the furnace 

background. The waste stream flame must have sufficient stability and be located such 

that it can be effectively detected by the flame scanner.

7.5.3 Burners Firing Class B Streams

Liquid waste burners firing Class B streams must be equipped with a continuous ignition 

source with sufficient heat input to ensure stable ignition and combustion of the waste 

stream. The lighter must be equipped with its own independent flame detection device, 

and it must be run at all times the liquid waste burner is in service. This lighter should 

operate during the shut down of the waste stream burner to combust the waste stream 

during this typically unstable period, and while purging liquid waste from the burner. 

7.6 Protective Starting and Tripping Logic 

Unless specifically stated otherwise in this guideline, all general design criteria for 

dedicated burners for liquid waste streams must meet “Recommended Good Practice for 

the Safe Firing of Auxiliary Fuels in Black Liquor Recovery Boilers”. As stated in 

section 7.1, the design and operation of dedicated burners for the thermal oxidation of 

liquid waste streams is very similar to that of auxiliary fuel burners. This similarity also 

applies to protective starting and tripping logic. In an attempt to avoid future inaccuracies 

in the coordination between this guideline and the “Recommended Good Practice for 

Safe Firing of Auxiliary Fuels in Black Liquor Recovery Boilers,” this document refers to 

that guideline for most design and logic requirements.

There will be additional logic requirements for dedicated burners for the thermal 

oxidation of liquid waste streams, but these requirements will be dictated by the specific

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waste stream and burner design. The burner designer will be responsible for identifying 

those logic requirements that are applicable and not described in the “Recommended 

Good Practice for Safe Firing of Auxiliary Fuels in Black Liquor Recovery Boilers”. 

Some examples of additional requirements that may be required are: 

• The waste stream does not contain excessive water as determined by density or other 

appropriate measurement.

• The waste stream meets all limits for physical characteristics set by the burner 

designer, such as minimum and maximum temperature and pressure limits, etc.

• The burner atomizing medium meets all limits for physical characteristics and 

characteristics in relation to the liquid waste stream set by the burner designer.

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CHAPTER 8 GUIDELINES FOR THERMAL OXIDATION OF CHIP BIN NCG

8.1 Introduction 

Environmental regulations may require that the vents from most continuous digester chip 

bins that are pre-steamed be collected and destroyed. This chapter discusses the range of 

risks that chip bin noncondensible gas (CBNCG) presents, the choices for transporting 

these gases to a recovery boiler, and how to use a recovery boiler for safely destroying 

CBNCG.

8.1.1 Safety 

During the thermal oxidation of CBNCG, the safety for both personnel and equipment 

must be considered. 

Chip Bin NCG is ordinarily “malodorous-air” that has the potential of becoming 

flammable under upset operating conditions. Each CBNCG system requires an individual 

evaluation because each system has a unique combination of risk factors. CBNCG is not 

a fuel. Systems and equipment for thermal oxidation of CBNCG, as well as the systems 

and equipment for collection and treatment, should be designed and controlled such that: 

• The escape of CBNCG into the recovery building area is prevented insofar as 

design makes it possible.

• Condensate cannot carry into the recovery boiler. 

• Special consideration should be placed on the design of CBNCG recognizing that 

conditions can occur where the concentration can become flammable.

• Surrogate parameters for a CBNCG combustible content above the LEL are used 

as interlocks to divert CBNCG when it is hazardous. Use of an LEL meter is 

encouraged. NFPA 69, chapter 6, permits operating at up to 60% LEL when 

interlocks are in place.

• In no case shall the safety requirements be less restrictive than those presented in 

the following BLRBAC publications: 

o Recommended Good Practice for the Safe Firing of Auxiliary Fuel in 

Black Liquor Recovery Boilers

o Recommended Good Practice for the Safe Firing of Black Liquor in Black 

Liquor Recovery Boilers 

o Instrumentation Checklist and Classification Guide for Instruments and 

Control Systems Used in Operation of Black Liquor Recovery Boilers 

o Recommended Rules for Personnel Safety Black Liquor Recovery Boilers

8.1.2 Flammability of CBNCG 

Table 10 lists factors that can affect the flammability of CBNCG. An assessment of these 

at a given site will help the system designer select the most appropriate means for safe 

handling of these gases. 

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Table 10 Risk Factors Affecting the Flammability of Chip Bin NCG

Risk Factor Result

Process Risk Factors

• Resinous softwoods (Not hemlock 

nor hardwoods)

• Contributes turpentine 

• Eucalyptus • Contributes volatile oils

• Flash steam pre-steaming • Contributes TRS, methanol, 

turpentine, volatile oils

• Early extraction in cont. digester • Higher turpentine content in flash 

steam

• Chip pile storage time • Short term storage decreases 

volatile losses

• Season • Low temperatures decreases 

volatile losses

• Low residual alkali • Higher TRS in flash steam

Operational Risk Factors

• Chip level • Breakthrough of flash steam 

volatiles

• High top vent temperature • Volatiles in NCG increase with 

temperature

• Lower than normal vent 

temperature 

• Returning to normal temp will revaporize volatile compounds 

• High NCG temperature out of 

condenser

• Reduces turpentine removal

• Chip bin residence time • Increases volatile accumulation

• Excessive sweep air • Reduces condensing efficiency

• Digester start up • Unstable chip bin operation, high 

combustible content

The majority of risk factors involve turpentine, which is a product of resinous softwood, 

and organic sulfides that get returned to the chip bin if digester flash steam is used for 

pre-steaming. TRS and volatile oils behave similarly. A mill that uses fresh steam for presteaming hardwood chips will likely generate CBNCG having lower flammable gas 

concentrations than a mill that pre-steams softwood chips with extraction liquor flash 

steam. The following summarizes the decreasing risk of generating flammable NCG 

concentrations: 

Softwood Chips >> Softwood Chips = Hardwood Chips > Hardwood Chips 

Flash Steam Fresh Steam Flash Steam Fresh Steam

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8.2 Collection and Transfer of CBNCG 

8.2.1 CBBNCG Conditioning System 

The intent of the CBNCG conditioning system is to reduce the amount of water vapor in 

the gas, limit the maximum concentration of turpentine in the NCG from softwood 

processing, and address conditions that can generate flammable gas compositions for any 

fiber source.

While Chip Bin Vent Condenser temperature control is primarily aimed at limiting the 

saturated turpentine concentration of the exit vapor, temperature will have less of an 

impact on TRS content. Operating the Chip Bin at temperatures > 180 oF with flash 

steam increases the risk of having flammable concentrations of CBNCG due to TRS, 

even after cooling. Interlock permissives should include limits on Chip Bin Condenser 

NCG exit temperature. A maximum cooled gas temperature of 90 oF is suggested for 

softwood cooking; however, the maximum temperature setting for hardwood could be set 

higher 120 oF would not be unreasonable. If dilution air is added to lower combustible 

gas concentrations, it should be introduced after the Condenser to reduce the impact on 

condensing efficiency.

Since the Chip Bin vent will often entrain chips, pins, and fines, the Vent Condenser 

should be protected from plugging. Systems will often include a Separator and an 

intermittent tube-side shower. 

Pre-steaming Chip Bins should have process interlocks to vent the Chip Bin to the 

atmosphere under prolonged low Chip Bin level conditions or excessive vent Condenser 

temperatures. Flash steam should be shut off [The flash steam valve should be ramped 

down at a rate that does not create a control problem for the flash steam condensers.] as a 

pre-emptive action before excessive emissions are released into the collection system.

Pre-steaming Chip Bins that operate at cold top temperatures can accumulate high 

concentrations of TRS and condensed volatiles that can re-vaporize under falling chip 

levels that result in steam breakthrough. Chip Bins that normally operate hot (top 

temperature of > 150 o

F) may experience accumulation of TRS and condensed volatiles 

upon loss in steam flow. These combustibles can be rapidly expelled upon resumption of 

steaming. To avoid this potential excursion above the LEL, a low bin vent temperature 

interlock should be included that vents NCG for a minimum time period once conditions 

return to normal with rising temperature.

Appropriate pre-emptive interlocks recognizing this behavior should be applied to any 

operating strategy. Figure 19 gives an example of a CBNCG vent condensing system.

8.2.2 Recovery Boiler Introduction System 

CBNCG can be introduced for thermal oxidation into the recovery boiler furnace in 

several ways:

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• Through one or more injection nozzles, typically located within a combustion air 

(tertiary) port entry.

• As part of a dedicated burner for CNCG and SOG

• Combined with DNCG prior to furnace entry 

The selected method of introduction of the CBNCG into the furnace needs to consider the 

gas concentration at the point of injection, the volume of CBNCG and the applicable risk 

factors. The designer selecting a system to introduce CBNCG into a combustion air duct 

should recognize the potential for release of odorous and potentially flammable gas into 

the boiler area due to ductwork leaks, port rodding leakage, sight glass breakage or other 

leakage sites. A system design that uses direct injection into the furnace through 

dedicated nozzles or as a stream to a dedicated waste gas burner significantly reduces the 

possibility of odorous gas release and is the preferred method of disposal. Furthermore, a 

dedicated system that uses a steam ejector provides safety when the CBNCG 

combustibles are above the LEL because it does not have the potential ignition sources of 

a centrifugal fan and steam addition provides dilution of both combustible gas and 

oxygen concentrations.

Dilution air added to CBNCG will not positively ensure that the resulting stream is 

always below the LEL. Some risk factors involve re-vaporizing combustibles; and the 

rate of re-vaporization cannot be accurately predicted, so the resulting concentration, 

even after dilution, cannot be predicted. 

Data from mills indicate that the % LEL of their DNCG systems without the Chip Bin 

vent is typically 5% - 10%. When Chip Bin gases are included, this % LEL can go much 

higher and exceed 100%. In that the Chip Bin, when upset, represents the single most 

likely source of NCG that can jeopardize the safety of a conventional DNCG system, 

more mills are electing to handle this vent gas separately.

Before selecting CBNCG transport and introduction methods, a “management of change” 

procedure should be performed. If the” management of change” procedure and evaluation 

of risk factors allow combining CBNCG with DNCG, then Chapter 4 should be used for 

design of a recovery boiler introduction system. The remainder of this chapter discusses 

introduction of CBNCG into the recovery furnace in a dedicated system. 

Depending on method of collection, CBNCG replaces a small part of the volume of 

combustion air. If conveyed by a Steam Ejector, NCG flow excluding ejector steam is 

typically less than 2000 acfm. If conveyed by a fan, where dilution air is added, total flow 

will typically be in the 4000 acfm range. These flows may have an effect on the 

combustion air requirements and should be considered in the system design.

Where direct injection through a nozzle is used, entry velocities should be above the 

flame propagation velocity to minimize the potential for flameback. A reasonable design 

velocity is 50 fps. The delivery system should be designed to develop the necessary 

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pressure required at the furnace nozzles, in which case CBNCG pressure should be 

monitored and alarmed.

When NCG is diverted, providing a secondary source of air or steam will help prevent 

injection port damage from high heat exposure. 

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Figure 21 Example - CBNCG vent condensing system.

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8.2.3 Chip Bin NCG Transfer System 

Mills may elect to transfer Chip Bin NCG using a spark-resistant fan as is typically 

employed for conventional DNCG systems; however, continuous monitoring of % LEL is 

recommended if risk factors indicate a high likelihood of generating flammable gas 

concentrations during upset conditions. Particular attention should be given to ensure that 

the casing and shaft are well-grounded and that frequent or continuous vibration 

monitoring is performed in order to minimize the risk of the Fan becoming a source of 

ignition. 

A steam ejector is recommended for systems where the possibility of developing 

flammable gas concentrations is high. Potential ignition by the centrifugal fan is avoided. 

The ejector steam, as with CNCG systems, serves to dilute both the flammable gas 

concentration as well as the oxygen.

The relative volume of a separately handled Chip Bin vent collection system, whether 

conveyed by steam ejector or by fan, however, is considerably smaller than typical 

DNCG systems and affords added flexibility with disposal in the Recovery Boiler. Preheating is, therefore, not a requirement. Figures 20 and 21 show typical Fan and Steam 

Ejector delivery systems.

Steam Ejector systems - Steam-ejected Chip Bin NCG can be added to the same burner 

as that used for burning CNCG and SOG, by adding another annulus. 

Advantages: 

• Provides steam dilution of both oxygen and NCG concentration 

• Steam vs Electrical when energy cost is favorable

• May provide a flame quenching point 

• No moving parts 

• Offers no source of ignition 

Disadvantages: 

• Steam consumption 

• Contributes moisture to point of incineration [Condensing Ejector steam results in 

losing several key advantages regarding NCG flammability.] 

• High pressure steam needs to be below auto-ignition point of 400F. 

• Discharge pressure protection is required. 

The NCG may also be injected directly into the Boiler at high velocity (e.g., > 50 fps) 

through one or two tertiary ports. 

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Figure 22 Example - CBNCG fan delivery system.

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Figure 23 Example - CBNCG ejector delivery system. 

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Fan systems – Fan conveyed CBNCG may be handled similarly in that the CNCG burner 

requirement for combustion air can be satisfied by the Chip Bin flow. Use of an auxiliary 

combustion air supply would still be required should the Chip Bin flow be diverted. 

Advantages: 

• Dry delivery of NCG to incineration

• Electrical vs Steam when energy cost is favorable

• Discharge pressures are not potentially high – no pressure relief device to 

maintain

Disadvantages: 

• Can be a source of ignition 

o Foreign material

o Mechanical failure (worn bearing)

o Inadequate grounding (case or shaft) 

• Additional air is typically required for balancing

• Unless fresh steam is used, an LEL Meter is recommended.

• Added number of interlocks 

• Increased frequency of venting likely 

Fan Design Considerations 

• Spark-resistant metallurgy (typically monel) at potential contact points.

• Fan and Shaft grounding with periodic confirmation

• Continuous bearing temperature monitoring

• Continuous vibration monitoring

• Condensate draining provisions

• Provide dilution ahead of Fan, but after the Vent Condenser.

• Provide an LEL Meter after Fan with sample probe protected from entrained 

condensate.

This NCG flow may also be introduced directly into the Boiler at high velocity (e.g., > 50 

fps) through one or two separate ports. 

8.2.4 CBNCG Piping System and Auxiliary Equipment 

Gas piping should be designed to prevent accumulation of condensates. Where possible, 

piping should be sloped in the direction of gas flow to facilitate draining and to minimize 

accumulation of tar deposits. 

Gas piping should be grounded at several locations along the collection system. 

For fan-based systems, refer to Section 4.2.5 covering DNCG piping; for Steam Ejectorbased systems, refer to Section 5.2.3 covering CNCG piping. 

Separate condensate collection systems are preferred; however, CBNCG and DNCG

systems may share common condensate drain collection tanks except where upset 

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pressure differences can interfere with system operation or the integrity of lockout/tagout 

procedures is compromised. 

8.3 Monitoring and Control 

Monitoring and control of the CBNCG system should include indication and response to 

upset Chip Bin operation. Fan-based delivery systems present the greatest risk for fire 

and explosions unless adequate interlock protection is provided. 

Monitoring should include indication of low Chip Bin level, abnormally high top Chip 

Bin temperature; lower than normal top Chip Bin temperature and high vent condenser 

NCG temperature. Fan-based systems that transport CBNCG from flash steam presteaming or wood species that contain volatile oils are subject to higher risk of 

developing flammable NCG conditions. LEL monitoring should be seriously considered 

as well as frequent/continuous monitoring of fan vibration and bearing temperature. 

8.4 Safety System 

CBNCG is not considered a fuel. It is considered as “malodorous air” for fan-delivered 

systems that include added dilution air. Steam-ejected delivery systems will generally 

transport only the air that enters at the Chip Bin and that air’s contribution to combustion 

air requirements, in a properly designed and operated system, will likely be small.

Since upsets at the Chip Bin are primarily responsible for conditions that affect the 

flammability and hazardous nature of CBNCG, process stability is reflected in the logic 

for burning CBNCG in the Recovery Boiler. 

An LEL meter is not required, but use of an LEL meter can provide a more accurate 

indication of combustible content than surrogate parameters. All interlocks must be 

included but an LEL meter that is calibrated and operating properly can be functionally 

substituted for the surrogate parameters in the tripping logic.

For either method of delivery, direct injection is preferred at nozzle velocities > 50 fps. 

8.4.1 Permissive Starting Logic – CBNCG – Fan Delivery

To admit CBNCG to the Recovery Boiler, the following conditions should be fulfilled: 

• Purge credit established and maintained

• Steam flow is above 30% of MCR 

• Drain Collection Tank levels not high 

• CBNCG flow is proven* 

• Fan vibration levels not high 

• Chip Bin level not low** 

• Chip Bin top temperature not high** 

• Chip Bin top temperature not low** 

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• %LEL not high (if used) 

• CBNCG temperature after Vent Condenser not high** 

• CBNCG delivery pressure not low 

• CBNCG delivery pressure not high 

Permissive starting logic for thermal oxidation of CBNCG is shown in Figure 22. 

8.4.2 Protective Tripping Logic – CBNCG – Fan Delivery

Any of the following conditions will divert CBNCG from the Recovery

Boiler:

• Master Fuel Trip (purge credit lost)

• CBNCG pressure low or high 

• CBNCG flow low*

• Gas temperature after Chip Bin Vent Condenser high** 

• Chip Bin top temperature increasing after being low** 

• CBNCG temperature at nozzle high

• CBNCG fan vibration level high 

• %LEL high (if used)

• Boiler steam flow less than 30% of MCR 

• Shut-off valve to alternative control device not closed (if applicable) 

• Automatic vent valve not closed. 

• Drain collection tank level high

• Manual switch to vent valve activated

Protective tripping logic for thermal oxidation of CBNCG is shown in Figure 23. 

* Flow can be proven with pressure, flow, temperature, fan operating and control damper 

 position (fan operation should be proven with shaft speed), or other means. Note that

 pressure alone could indicate pluggage rather than flow. 

**Interlocks typically part of Digester controls. 

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Figure 24 CBNCG Fan Delivery Permissive Starting Logic.

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Table 11 Explanation Chart for CBNCG Injection Permissive Starting Logic - Fan Delivery for 

Figure 24 

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit 

Maintained (From Figure 21 

‘Common Permissive Starting 

Logic’ in Safe Firing of 

Auxiliary Fuel Recommended 

Good 

Practice)

Stop DNCG introduction

when boiler firing

permissives not met

Prevent introduction of DNCG 

while boiler is not being fired. 

Steam Flow >30% MCR Ensure furnace

combustion is stable.

Unstable operation of boiler 

may minimize furnace 

residence time or provide too 

low a temperature

for proper oxidation.

Drain Collection Tank levels 

not high.

Prevent condensate from 

flooding NCG duct.

Prevent condensate from 

entering boiler.

CBNCG flow established* Ensure sufficient motive force 

and dilution 

Provide minimum line and 

nozzle entry velocity to

prevent flame propagation

Fan vibration levels not high Indicates potential spark 

generation

Prevent ignition of flammable 

gas

Chip Bin level not low** Indicates potential 

breakthrough of flammable 

gas

Prevent NCG from exceeding 

100% LEL with explosion 

hazard 

Chip Bin top temperature not 

high** 

Possible breakthrough of 

flammable gas

Prevent NCG from exceeding 

100% LEL 

Chip Bin top temperature, not 

low** 

Avoid a surge of revaporized 

flammable gas as chip bin 

warms up

Prevent CBNCG from 

becoming explosive

CBNCG after Vent Condenser 

not high**

Ensure adequate condensing 

of terpenes

Prevent NCG from exceeding 

100% LEL

% LEL not high** Indicates gas is not flammable Prevent injection of flammable 

gas

CBNCG delivery pressure not 

low 

Ensure sufficient motive force Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation

CBNCG delivery pressure not 

high

System is not plugged or 

flooded 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

Prevent blowing loop seals 

and rupture discs.

Start Approval Start permissive after

satisfying interlocks

Interlocks made.

* Flow can be proven with flow indication or surrogate measures, including fan shaft 

speed.

** Typically part of Digester interlock controls and not part of boiler permissives

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Figure 25 CBNCG Fan Delivery Tripping Logic.

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Table 12 Explanation Chart for CBNCG Injection Protective Tripping Logic - Fan Delivery for 

Figure 25 

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Lost

Master Fuel Trip

(From Figure 21 ‘Common 

Permissive Starting Logic’

in Safe Firing of Auxiliary

Fuel Recommended Good

Practice)

Stop DNCG introduction

when boiler firing 

permissives not met

Prevent introduction of 

DNCG while boiler is not 

being fired.

Steam Flow <30% MCR Furnace combustion may be 

unstable. 

Unstable operation of boiler 

may minimize furnace 

residence time or provide 

too low a temperature 

for proper oxidation.

Drain Collection Tank 

levels high.

Condensate may be 

flooding NCG duct.

Prevent condensate from 

entering boiler.

CBNCG flow low* Ensure sufficient motive 

force

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation

Fan vibration levels high Indicates potential spark 

generation

Prevent ignition of 

flammable gas

Chip Bin level low** Indicates potential 

breakthrough of flammable 

gas

Prevent NCG from 

exceeding 100% LEL with 

explosion hazard

Chip Bin top temperature 

high**

Possible breakthrough of 

flammable gas

Prevent NCG from 

exceeding 100% LEL

Chip Bin top temperature 

increasing after being 

low**

Avoid a surge of 

revaporized flammable gas 

as chip bin warms up

Prevent CBNCG from 

becoming explosive

CBNCG after Vent 

Condenser high**

Possible inadequate 

condensing of terpenes

Prevent NCG from 

exceeding 100% LEL

% LEL high** Indicates gas may be 

flammable

Prevent injection of 

flammable gas

CBNCG delivery pressure 

low 

insufficient motive force or 

dilution

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation

CBNCG delivery pressure 

high

System may be plugged or 

flooded 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

Prevent blowing loop seals 

and rupture discs. 

(continued) 

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Table 12. (cont’d) Explanation Chart for CBNCG Injection Protective Tripping Logic – 

Fan Delivery for Figure 25

LOGIC BLOCK PURPOSE HAZARD PROTECTED

NCG Nozzle temperature 

high

Indicate flameback Prevent explosion in line

Manual switch to vent valve 

activated

Remove foul gas from 

boiler 

Boiler conditions such that 

continued NCG delivery 

creates an unsafe condition.

Automated vent valve not 

closed

Confirm valves in proper

Position to prevent flow to 

more than one location

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation.

Valves to alternate location 

not closed

Confirm valves in proper

Position to prevent flow to 

more than one location 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

* Flow can be proven with flow indication or surrogate measures, including fan shaft 

speed.

** Typically part of Digester interlock controls and not part of boiler permissives 

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8.4.3 Permissive Starting Logic – CBNCG – Steam Ejector Delivery

To admit CBNCG to the Recovery Boiler, the following conditions should be fulfilled: 

• Purge credit established and maintained 

• Steam flow is above 30% of MCR 

• Drain Collection Tank levels not high 

• Ejector steam or discharge flow not low 

• Chip Bin level not low* 

• Chip Bin top temperature not high* 

• Chip Bin top temperature not low* 

• %LEL not high (if used)* 

• CBNCG temperature after Vent Condenser not high* 

• CBNCG delivery pressure not low 

• CBNCG delivery pressure not high 

Permissive starting logic for thermal oxidation of CBNCG is shown in Figure 24. 

8.4.4 Protective Tripping Logic – CBNCG – Steam Ejector Delivery

Any of the following conditions will divert CBNCG from the Recovery

Boiler:

• Master Fuel Trip (purge credit lost)

• CBNCG delivery pressure low

• CBNCG delivery pressure high

• Drain Collection Tank level high 

• CBNCG Ejector steam or discharge flow low

• CBNCG temperature at nozzle high

• Gas temperature after Chip Bin Vent Condenser high* 

• Chip Bin top temperature increasing after being low* 

• %LEL high (if used)* 

• Boiler steam flow less than 30% of MCR 

• Shut-off valve to alternative control device not closed (if applicable) 

• Automatic vent valve not closed. 

• Manual switch to vent valve activated

* Consider these as Digester source interlocks or alarms, but not permissives for the 

 Boiler.

Protective tripping logic for thermal oxidation of CBNCG is shown in Figure 25. 

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Figure 26 CBNCG Steam Ejector Delivery Permissive Starting Logic.

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Table 13 Explanation Chart for CBNCG Injection Permissive Starting Logic - Steam Ejector 

Delivery for Figure 26 

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit 

Maintained (From Figure 21 

‘Common Permissive Starting 

Logic’ in Safe Firing of 

Auxiliary Fuel Recommended 

Good 

Practice)

Stop DNCG introduction

when boiler firing 

permissives not met

Prevent introduction of DNCG 

while boiler is not being fired. 

Steam Flow >30% MCR Ensure furnace

combustion is stable.

Unstable operation of boiler 

may minimize furnace 

residence time or provide too 

low a temperature for proper 

oxidation.

Drain Collection Tank levels 

not high.

Prevent condensate from 

flooding NCG duct.

Prevent condensate from 

entering boiler.

Ejector Steam flow or 

discharge flow not low 

Ensure minimum line velocity 

and gas dilution 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation.

Chip Bin level not low** Indicates potential 

breakthrough of flammable 

gas

Prevent NCG from exceeding 

100% LEL with explosion 

hazard

Chip Bin top temperature not 

high** 

Possible breakthrough of 

flammable gas

Prevent NCG from exceeding 

100% LEL 

Chip Bin top temperature not 

low** 

Avoid a surge of revaporized 

flammable gas as chip bin 

warms up

Prevent CBCG from becoming 

explosive

CBNCG after Vent Condenser 

not high**

Ensure adequate condensing 

of terpenes

Prevent NCG from exceeding 

100% LEL

% LEL not high** Indicates gas is not flammable Prevent injection of flammable

gas

CBNCG delivery pressure not 

low 

Ensure sufficient motive force Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation

CBNCG delivery pressure not 

high

System is not plugged or 

flooded 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

Prevent blowing loop seals 

and rupture discs.

Start Approval Start permissive after

satisfying interlocks

Interlocks made.

* Flow can be proven with flow indication or surrogate measures, including fan shaft 

speed.

** Typically part of Digester interlock controls and not part of boiler permissives 

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Figure 27 CBNCG Steam Ejector Delivery Tripping Logic.

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Table 14 Explanation Chart for CBNCG Injection Protective Tripping Logic - Steam Ejector 

Delivery for Figure 27 

LOGIC BLOCK PURPOSE HAZARD PROTECTED

Boiler Purge Credit Lost

Master Fuel Trip

(From Figure 21 ‘Common 

Permissive Starting Logic’

in Safe Firing of Auxiliary

Fuel Recommended Good

Practice)

Stop DNCG introduction

when boiler firing 

permissives not met 

Prevent introduction of 

DNCG while boiler is not 

being fired. 

Steam Flow <30% MCR Furnace combustion may be 

unstable. 

Unstable operation of boiler 

may minimize furnace 

residence time or provide 

too low a temperature 

for proper oxidation.

Drain Collection Tank 

levels high.

Condensate may be 

flooding NCG duct.

Prevent condensate from 

entering boiler.

Ejector Steam flow or 

discharge flow low

Loss of motive force, line 

velocity and gas dilution

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation.

Chip Bin top temperature 

increasing after being 

low**

Avoid a surge of 

revaporized flammable gas 

as chip bin warms up

Prevent CBNCG from 

becoming explosive

CBNCG after Vent 

Condenser high**

Possible inadequate 

condensing of terpenes

Prevent NCG from 

exceeding 100% LEL

% LEL high** Indicates gas may be 

flammable

Prevent injection of 

flammable gas

CBNCG delivery pressure 

low 

Insufficient motive force Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation

CBNCG delivery pressure 

high

System may be plugged or 

flooded 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

Prevent blowing loop seals 

and rupture discs. 

NCG Nozzle temperature 

high

Indicate flameback Prevent explosion in line

Manual switch to vent valve 

activated

Remove foul gas from 

boiler 

Boiler conditions such that 

continued NCG delivery 

creates an unsafe condition. 

(continued) 

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Table 14. (cont’d) Explanation Chart for CBNCG Injection Protective Tripping Logic – 

Steam Ejector Delivery for Figure 27 

Automated vent valve not 

closed

Confirm valves in proper

Position to prevent flow to 

more than one location 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

Valves to alternate location 

not closed 

Confirm valves in proper

Position to prevent flow to 

more than one location 

Provide minimum line and 

nozzle entry velocity to 

prevent flame propagation. 

* Flow can be proven with flow indication or surrogate measures, including fan shaft 

speed.

** Typically part of Digester interlock controls and not part of boiler permissives 

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8.5 Personnel Safety 

Characteristics for CBNCG and personnel safety considerations are described in Sections 

4.5 for DNCG and 5.5 for CNCG. 

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APPENDIX A DOCUMENT REVISION HISTORY

October 2010

1. Foreword: Deleted in its entirety. A portion was adapted for inclusion in Chapter 1. 

2. Chapter 1

a. Editorial/non-technical changes.

b. The paragraph stating BLRBAC discourages the burning of waste streams in 

recovery boilers has been deleted.

3. Chapter 2: Numerous definitions added, deleted, or revised. 

4. Chapter 3: Primarily editorial with changes to distinguish SOG form other CNCG 

waste streams and to accommodate the addition of liquid waste stream incineration in 

the scope of the document. 

5. Chapter 4:

a. Guidelines for idle DNCG line has been added along with other primarily 

editorial changes.

b. Deleted unnecessary logic blocks after “START Approval” in Figure 2, 

DNCG Permissive Starting Logic.

6. Chapter 5: Primarily editorial changes and:

a. Clarification on the location of flame arrestors in CNCG and SOG lines 

b. Explanation for recommendation to keep SOG separate from other CNCG 

c. Corrections to Tables 6 and 7 to match the logic blocks in their respective 

figures.

d. Fig. 5: Terminology changed from “LP Steam” to “Purge Steam” and “MP 

Steam” to “Ejector Steam”. Also revised to show automatic vent line coming 

off top CNCG and SOG supply lines. 

e. Fig. 6: Flame arrestor location in CNCG and SOG lines moved for 

consistency with text. Also revised to show automatic vent lines coming off 

top CNCG and SOG supply lines. 

7. Chapter 6: Section 6.7 has been completely rewritten to provide guidelines on the 

blending of turpentine and red oil into the black liquor. New Figures 19 and 20 have 

been added for permissive starting and tripping interlock logic for turpentine. 

(Subsequent figures renumbered accordingly.) Other editorial changes were made in 

earlier sections of the chapter for consistency with section 6.7. 

October 2008

• Chapter 5 revised to address purging of the portion of the CNCG supply line to the 

recovery boiler between the final/most downstream shutoff valve and the burner. 

• Added a new chapter 8, Guidelines for Thermal Oxidation of Chip Bin NCG and 

revised Chapter 4 to delete guidance on the incineration of chip bin NCGs.

April 2008

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• Chapter 4, Guidelines for Thermal Oxidation of DNCG 

o Added guidelines for the safe incineration of recovery boiler dissolving tank vent 

gases that includes a recommendation for handling dissolving tank vent gases 

independently of any other NCG system. This material is dispersed throughout the 

chapter as needed in each of the sections including modifications to Figures 2 and 

3 and their associated logic explanation charts and the addition of a new Figure 4, 

DNCG Transfer System for Dissolving Tank Vent. 

o Section 4.2.4, DNCG Transfer System: 

 Added a recommendation that the entire transport system be grounded. 

 Modified the low point drain recommendation to specifically recommend 

the fan casing have a condensate outlet at its lowest point. 

 Added a recommendation for high and low temperature alarms for gas 

condensers/preheaters.

 Clarified DNCG gas temperature conditioning equipment. 

 Added a recommendation that all vent lines for DNCG systems be routed 

to a safe location.

o Section 4.2.5, DNCG Piping System and Auxiliary Equipment: 

 Added a recommendation for sloped piping with a low point drain. 

 Added a recommendation that position switches on automatic valves 

provide feedback to a manned control room. 

o Section 4.3, Monitoring and Control 

 Added a recommendation for routine monitoring of bearing temperature 

and vibration. 

 Added recommended maximum design % LEL values with and without 

automatic interlocks.

o In the logic explanation table for Figure 3, the “Purpose” and “Hazard Protected” 

were added for the “Switch DNCG from boiler to vent” Logic Block. 

• Added a new Chapter 7, Guidelines for Thermal Oxidation of Liquid Waste Streams 

in Dedicated Burners.

October 2006

• Section 4.2.2 – Changed “vented to atmosphere” to “diverted.”

• Section 4.2.3 

o Added “relative” to text so as to read: “50% relative humidity.”

o Added explanation for recommended double block and vent.

• Sections 4.4.1 & 4.4.2, Figure 2 and accompanying Logic Explanation Chart, and 

Figure 3 and accompanying Logic Explanation Chart – Permissive starting logic and 

protective tripping logic modified to recognize a variety of means are available to 

detect DNCG flow.

• Section 5.1.3 – Igniter design recommendation for waste stream burner modified to 

specifically refer to NFPA class 1 continuous igniters.

• Section 5.2.3 – Removed reference to specific piping design codes and added that 

piping must meet the required service conditions and be acceptable to the authorities 

having jurisdiction.

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• Added Chapter 6, Liquid Waste Streams Blended with Black Liquor 

April 2002

This document has been revised to provide a consistent format. With the exception of an 

added sentence in Section 4.2.1, there are no technical changes from the prior issue. 

October 1999

First issue.

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Attachment 4 

Attachment C, NCASI, Experience with the Collection, Transport, and Burning of 

Kraft Mill High Volume Low Concentration Gases, August 2003 

189 of 309
Note to Docket  

EPA–HQ–OAR–2007‐0544

This attachment contains copyrighted

material and has been removed from the

document.
Attachment 5 

Attachment D, FM Global, Property Loss Prevention Data Sheets, January 2012 

226 of 309
Note to Docket  

EPA–HQ–OAR–2007‐0544

This attachment contains copyrighted

material and has been removed from the

document.
Attachment 6 

Attachment E, FM Global, Property Loss Prevention Data Sheets, May 2010 

257 of 309
Note to Docket  

EPA–HQ–OAR–2007‐0544

This attachment contains copyrighted

material and has been removed from the

document.
Attachment 7 

Attachment F, FM Global, Property Loss Prevention Data Sheets, May 2006 

281 of 309
Note to Docket  

EPA–HQ–OAR–2007‐0544

This attachment contains copyrighted

material and has been removed from the

document.
Attachment 8 

Cost Estimate for Elimination of Excess Emission Allowances, June 2012 

302 of 309
Attachment 8

Cost Estimate for Elimination of Excess Emission Allowances

40 CFR 63 Subpart S

Introduction

If the excess emission provisions are eliminated, facilities could choose to implement the

following upgrades/additions to their systems:  (1) Route HVLC gases to a back‐up control

device, (2) Upgrade or replace the gas collection systems (LVHC/HVLC), and/or (3) Install a back‐

up steam stripper at a total cost of $750 M.  While it is expected that installation of these

systems could reduce the number and duration of excess emission events, they will not

eliminate all events.  As noted in Attachment 1, the NCG gas collection systems are complex

systems under pressure that must be designed to meet safety and insurance standards.  Even

the best performing systems are subject to these events and these allowances are a result of

the MACT floor development.  Steam strippers must be maintained and these activities require

downtime of the control device.  Again, this was recognized during development of the MACT

floor which resulted in a downtime allowance for these control devices.  While facilities could

incur capital expenditures in an effort to try to minimize these events, elimination of the

allowances would create a scenario in which no mill could meet the standards.

Cost Estimate

The following tables outline the assumptions and capital cost estimates for the industry to

install redundant systems.  A more detailed table is provided at the end of this section.  

Although there will be increased O&M for these systems, those costs are not included in this

analysis.  In addition, it is assumed that EPA will not require additional collection and treatment

of condensates and therefore mills will still be able to utilize the CCA compliance approach.

Capital Cost Estimate for Redundant Systems

   Capital Cost/Unit

Route HVLC Systems to a Backup Control Device

$  5 M

Upgrade existing HVLC/LVHC Collection Systems $  2 M

Replace existing HVLC/LVHC Collection Systems $ 7.5 M

Install Back‐up Steam Strippers $  7.4 M

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These costs were developed based on the following assumptions:

Assumptions

Number of Units

Affected Capital Cost

Route HVLC Systems to a Backup Control Device 28 $  100 M

Upgrade existing HVLC/LVHC Collection Systems 73 $ 150 M

Replace existing HVLC/LVHC Collection Systems 24 $  200 M

Install Back‐up Strippers 44 $  300 M

TOTAL    $  750 M

Route HVLC Systems to a Backup Control Device

 Assume that 28 facilities (97 facilities less the 35 that demonstrated compliance using

the CCA approach without collecting any HVLC gases and less an estimated 34 facilities

that already have a back‐up control device) will need to have HVLC gases routed to a

backup incineration device.

 As noted, it is assumed that the final rule will maintain the treatment efficiency

requirements at 92% and 10.2 and 6.6 lb/ADUBTP (bleached/unbleached).  Therefore,

facilities that utilized the CCA approach can maintain their systems and will not need to

collect HVLC systems that are currently uncollected.   

 These costs are only for the ductwork and supporting materials/systems to route the

main HVLC trunk line to a backup control device and assume that a backup incineration

device is available (i.e., no  new incinerator, oxidizer, etc.).     

 The HVLC control cost of $5 M per facility is based on member input for recent costs to

route HVLC gases to a back‐up control device

Upgrade/Replace existing HVLC/LVHC Collection Systems

 These costs assume all 97 facilities will need to either upgrade or replace their existing

HVLC/LVHC collection systems.  Of these it is assumed 25% will need to replace their

systems while the remaining 75% will only need to upgrade.  

 System upgrades are estimated at $2 M per facility and could include the costs for

redundant flame arrestors, to overdesign and upgrade condensers, etc.

 The cost of $7.5 M per facility for system replacements is based on member input for

the cost to install these systems for MACT I Phase I which ranged from $5 – 10 M.

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Install Back‐up Strippers

 These costs assume that all 43 facilities that utilize only a steam stripper for compliance

will need to install a back‐up unit.  Systems that also utilize their biological treatment

system for compliance will not need to install back‐up steam strippers.  One facility has

a stand‐alone biological treatment system and it is assumed this facility will need to

install a back‐up stripper.

 The cost of $7.4 M per units is based on a cost estimate for a stand‐alone stripper

installation for member company in 1998 dollars adjusted to 2012 dollars.   

Redundant Collection and Treatment Systems Will Not Eliminate Venting

However, even if facilities upgrade or replace their collection systems and install or provide

access to back‐up treatment systems, it is believed that these measures will not eliminate all

venting episodes.   

LVHC & HVLC Venting

The top four causes of LVHC venting are due to:   

 Primary Control Device being Unavailable,  

 Pressure / Temperature Interlocks in Gas Transport System,  

 Pressure / Temperature Parameters on Process Equipment Outside Normal Operating

Ranges, and  

 Switching between Incineration Points.   

The top three reasons for HVCL events are also similar to the top three reasons for LVHC

events.  However, elimination of these events is not guaranteed by upgrading or replacing the

gas collection systems and routing gases to a back‐up HVLC control device (most LVHC systems

already have a backup control device).  When the primary control device is unavailable either due

to a system trip or maintenance activities, the facility’s only option for treatment is the back‐up

control device.  In the case of a primary treatment system trip, the facility must switch to the

back‐up control device.  It is noted that even “ventless” transfer systems must have a short

term vent when switching between devices for safety reasons (steam purge the line).  In the

case where the primary treatment device is unavailable for maintenance reasons, if conditions

prohibit the backup control device from accepting the LVHC gases, the system will vent.  In

addition to these two circumstances, most facilities will purposely switch between LVHC control

devices on a regular frequency (typically once per week) to test the transfer system.  As noted,

these switches cannot always be ventless.  While installation of a back‐up control device would

help minimize HVLC vents, these systems will have the same challenges as LVHC systems with

dual treatment systems.   

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The other top two reasons for LVHC vents are due to either interlocks in the gas transport

system or parameters on process equipment being outside of the normal range.  If the facility

upgrades or replaces the collection system, it is unlikely that the “improved” system could

accept gases.  In the case where gases cannot be introduced due to process equipment

parameters being out of range, an “improved” collection system would probably not be able to

accept the gases for the same reason.   

Discussions amongst members have not developed potential solutions that will eliminate these

types of non‐SSM events.   

Other prevalent reasons for LVHC/HVLC system vents include:   

 Isolated venting of process equipment before reaching steady state,

 Inability to resolve interlocks due to process variability during start‐up and shutdown,

 Intermittent venting of isolated sections of the transport system due to flow balancing

issues,  

 Purge requirement of concentrated NCG line before pulp mill start‐up (to prevent air

from entering LVHC system), and  

 Transient venting of LVHC and HVLC sources due to slow "warm up" of boiler (low

process steam requirements)

These events are caused due to variability of process equipment and again “improved“  

collection and back‐up treatment systems will not eliminate the need for these events.

Steam Strippers

Under the existing MACT standards, for both steam strippers and stand‐alone biological

treatment systems that treat only condensates, periods of excess emissions are not violations

provided that such periods do not exceed 10 percent of the total process operating time in a

semi‐annual reporting period.  Currently 43 facilities have only steam strippers and at least one

facility has a stand‐alone biological treatment system to meet the compliance standards for

pulp and paper condensates.  In general, facilities do not have back‐up systems for steam‐

strippers or biological treatment systems and facilities that use both devices generally need

both systems to meet the treatment standard.   

Stripper systems require maintenance, and when there are problems with their operation, the

systems can require significant work to get them back to serviceable condition.  Some common

maintenance activities are listed below that can take anywhere from 4 hours to several days.

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 Stripper Boilout/Clean‐out of the Preheater and Trays;

 Acid Clean the Stripper Column

 Process Variation that Require Diversion of Condensates from Treatment Systems, and

 Equipment Failure for the Treatment System

If a stand –alone biological treatment system fails, it can take 15‐18 days for the system to

recover.  For these systems it is not cost effective to install an additional treatment system and

facilities would probably opt to install a back‐up stripper if a back‐up system was required.  

As noted above, when condensates are not being directed to the steam stripper, they are

typically still treated (although not to levels that would meet the treatment standards).  While

back‐up devices could minimize the duration and number of events, the capital costs for these

units is prohibitive especially considering that condensates are treated during these events.

Summary

As noted, the estimated costs to install these systems is $750 M, which is cost‐prohibitive and

unnecessary given that EPA has determined that the remaining health risks associated with the

current rule, which included emissions during venting, are acceptable.  Even with installation of

redundant control systems and “improved” collection systems, mills would not be able to

prevent all incidents of stripper downtime and/or gas collection and control system venting due

to process variability, equipment maintenance, and safety concerns.

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Attachment 8a 

Attachment A to Cost Estimate, Excel File, Cost Estimate of Proposed Rules 

Changes to 40 CFR 63 Subpart S, Elimination of Excess Emission Allowances, 

June 2012 

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Current Treatment Options for Kraft Condensate Mills

Number of

Units

Stripping 43

Biological Treatment 39

Biological Treatment & Stripping 9

Recycle 5

Thermal Incinerator 1

CCA 38

CCA Mills that also collect a subset of HVLC gases 3

Mills that have backup HVLC Control Devices 34

Assumptions Notes Units

Cost to Route HVLC Systems to a Backup Control Device 1 $        5,000,000 $

Costs to Upgrade existing HVLC/LVHC Collection Systems 2 $        2,000,000 $

Costs to Replace existing HVLC/LVHC Collection Systems 3 $        7,500,000 $

Costs to Install Back‐up Steam Strippers 4 $        7,400,000 $

Notes

Number of Units

Affected Capital Cost

Cost to Route HVLC Systems to a Backup Control Device 5 28 $                 100,000,000

Costs to Upgrade existing HVLC/LVHC Collection Systems 6 73 $                 150,000,000

Costs to Replace existing HVLC/LVHC Collection Systems 6 24 $                 200,000,000

Costs to Install Back‐up Steam Strippers 7 43 $                 300,000,000

TOTAL $                 750,000,000

Notes

Cost Estimate of Proposed Rules Changes to 40 CFR 63 Subpart S

Elimination of Excess Emission Allowances

7.  Assume that facilities with strippers will need to install a backup control device.  Systems with dual treatment (strippers and

biological treatment systems) will not need backup strippers.

Notes

Based on information from NCASI.

Based on NCASI Survey (28 of 80 mills that

responded have backup control devices

for HVLC).  Extrapolated results for 97

Based on ICR Collection Request Data

published by EPA.

2.  Based on member input to upgrade HVLC/LVHC collection system (i.e., install redudant flame arrestors, overdesign

condensers, etc.)

3.  Based on member input to replace HVLC/LVHC collection systems ($ 5 ‐ 10 MM/facility).

4.  Stripper upgrade costs based on cost from a AF&PA member facility for an upgrade to a non‐integrated stripper in 2010.

5.  Costs exclude facilities that utilize CCA (except for three facilities that also collect HVLC gases) and facilities with backup

HVLC systems

6.  Assume that 25% of facilities will need to completely replace their HVLC/LVHC collection systems.  The remainig 75% will

only need to upgrade their gas collection systems.

EPA did not include any information  in the record describing  how EPA expected mills to comply with the new standards.  

Therefore, AF&PA carefully examined what would be  necessary to comply with the proposal.  It should be noted that all cost

estimates in these comments are based on the best information available. These are based on conservative estimates of

upgrades and number of units affected  and not detailed mill by mill engineering estimates. Even with these caveats, the

estimates significantly higher than EPA’s.  AF&PA continues to make further refinements based on updated and increased

information from member companies so these costs are different than those previously presented to the agency.

1.  Assumes all units will need to have a backup incineration device and this device is available (i.e., no  new incinerator,

oxidizer, etc.).  Cost estimate of $5 M/per facility is based on recent member costs to route HVLC gases to an existing Recovery

Furnace.  The cost to route to a boiler or other incinerator could be less, but the facility could trigger PSD for SO2 and

therefore have additional costs and/or the need to update the controls on the incineration devices (costs not included in

estimate).

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