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Restricted © Siemens Industry, Inc. 2013 All rights reserved. Answers for industry.

Implementation of Subpart Ja for Flares – Understanding the Details

June 18, 2013Jerry CombsSiemens Industry

Restricted © Siemens Industry, Inc. 2013 All rights reserved. Siemens Industry/IA/SC/Process Analytics20130618 Jerry Combs, PhD


Understanding Ja goes well beyond simply knowing the key dates

Several aspects either misunderstood or not mentioned

Clear interpretation of what has to be measured

Interpretations of system requirements: probes, sample transfer, sample conditioning systems, sample return to process, and data handling and reporting

Knowledge of allowable alternatives to on-line monitoring and thresholds for Root Cause Analysis is needed

Strategies for approaching Ja implementation at a refinery and corporate level should be established



Now What ??The “Ja Peanut”


What is the new “Flare Definition” ?



Clarified definitions of “fuel gas combustion device” and “flare” to specify that a flare is a separate affected facility rather than a type of fuel gas combustion device.

Clarified definition of “flare” - in the case of an interconnected flare gas header system (i.e., two or more flare tips share the same flare gas header system or are otherwise connected such that they receive flare gas from the same source), the “flare” includes each combustion device serviced by the interconnected flare gas header system and the interconnected flare gas header system.




What is the “Suite of Standards”?



This “suite of standards” requires refineries to:(1) Develop and implement a flare management plan

(2) Conduct root cause analyses and take corrective action when waste gas sent to flare exceeds a flow rate of 500,000 scf above the baseline flow to a flare in any 24- hour period

(3) Conduct root cause analyses and take corrective action when the emissions from the flare exceed 500 lb of SO2 in a 24-hour period

(4) Optimize management of the fuel gas by limiting the short-term concentration of H2S to 162 ppmv during normal operating conditions (determined hourly on a 3-hour rolling average basis).

If a discharge exceeding either or both of the SO2 or flow thresholds is the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connected to the flare, and the flare management plan procedures for minimizing flow (which minimizes emissions) during that type of event are followed, a root cause analysis and corrective action analysis are not required.





When is a “Root Cause Analysis” Required?




Root Cause Analysis

RCA = Work practice standard (Ref. 60.13(c))

Thresholds:

• SO2 emissions exceed 500lb/24 hr period

• Discharge to flare of 500,000 SCF above baseline in 24 hr period

RCA and CAA complete <45 days after event

Exceed the Thresholds? - Identify and Correct !!





What is considered a “Modification” to Flare ?



Modification to a flare commences when a project that includes any of the activities is commenced:

(1) Any new piping from a refinery process unit, including ancillary equipment, or a fuel gas system is physically connected to the flare (e.g., for direct emergency relief or some form of continuous or intermittent venting).

(2) Flare is physically altered to increase the flow capacity of the flare.







What is not considered a “Modification” to Flare ?



The following seven types of connections are not considered a modification of the flare:(1) Connections made to install monitoring systems to the flare.

(2) Connections made to install a flare gas recovery system or connections made to upgrade or enhance components of a flare gas recovery system (e.g., addition of compressors or recycle lines).

(3) Connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded.

(4) Connections that interconnect two or more flares.

(5) Connections made for flare gas sulfur removal.

(6) Connections made to install back-up (redundant) equipment associated with the flare (such as a back-up compressor) that does not increase the capacity of the flare.

(7) Replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved.








What are the Alternatives to Monitoring?



Alternative Flow & Sulfur Monitoring [60.107a(g)]

Flares that only receive inherently low sulfur gas streams, continuous sulfur monitors are not necessary because a root cause analysis will be triggered by an exceedance of the flow rate threshold long before they exceed the 500 lb SO2 trigger in a 24-hour period.

If flare only burns natural gas, fuel gas monitored elsewhere or fuel gas streams that are inherently low in sulfur content no H2S monitor is needed.

Gases exempt from H2S monitoring due to low sulfur content also exempt from sulfur monitoring requirements for flares.

Exemption can only be used for flares that are configured to receive only fuel gas streams that are inherently low in sulfur content, such as flares used for pressure relief of propane or butane product spheres (fuel gas streams meeting commercial grade product specifications for sulfur content of 30 ppmv or less) or flares used to combust fuel gas streams.



Alternative Flow & Sulfur Monitoring [60.107a(g)]

Emergency Flare - combusts gas from a malfunction

•Must have a water seal

•Measure/Record Pressure in flare gas Header between Knock-out Pot and Water Seal

•Only for flares with <5 pressure exceedances in 365 rolling days

•5th pressure exceedance → install sulfur/flow monitors (180 days)









What are the Alternatives for SCAQMD and BAAQMD?



SCAQMD and BAAQMD Alternatives

Refineries located in SCAQMD: affected flare subject to subpart Ja may elect to comply with SCAQMD Rule 1118 as an alternative to complying with the requirements for flares.

Refineries located in BAAQMD: affected flare subject to subpart Ja may elect to comply with both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12.

EPA will not allow the owner or operator to “choose” to comply with SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 instead of subpart Ja.

Source must always demonstrate compliance with subpart Ja.

If SCAQMD Rule 1118 or BAAQMD Regulation 12, Rule 11 and Regulation 12, Rule 12 are determined to be equivalent to subpart Ja, then these requirements would be provided as an alternative within subpart Ja for the source to demonstrate that it is meeting the requirements of subpart Ja.









What are the Alternatives for SCAQMD and BAAQMD?

What are the Important Dates ?



On-Line Total Sulfur or TRS (Method 15A) - which is it?



From: "Combs, Jerry" <[email protected]> To: Brenda Shine/RTP/USEPA/US@EPA Date: 11/13/2012 04:13 PM Subject: Ja Question - Total Sulfur vs. TRS

Hi Brenda,

Confusion still exists at many US Refineries regarding Ja Flare sulfur monitoring (40CFR Part 60 published in the Federal Register Sept 12, 2012). In particular, questions arise regarding the measurement of waste gas sulfur to flare in order to determine if, upon combustion, more than 500lbs of SO2 are emitted in a 24 hr period.

Does the Rule specify a Total Sulfur analyzer for this measurement? Is a Total Reduced

Sulfur (H2S, COS, CS2) analyzer an acceptable alternative?

The two terms appear to be used interchangeably within the rule, but dictate very different on-line analytical approaches. (I also realize an H2S analyzer, spanned correctly and correlated to a grab sample Total Sulfur determination, is allowed as an alternative approach.)

I found several references to "Total Sulfur" within Federal Register / Vol. 77, No. 177 / Wednesday, September 12, 2012

Page:56424 - "Continuous TRS, using reference method 15A (Total Sulfur)"56430 - "considering the public comments we received. We consolidated the proposed alternatives to monitor reduced sulfur compounds and total sulfur compounds into a provision that allows the use of total reduced sulfur monitoring"56431 - ....................................................



From: [email protected] [mailto:[email protected]]

Sent: Wednesday, November 14, 2012 9:43 AM

To: Combs, Jerry

Subject: Re: Ja Question - Total Sulfur vs. TRS

Hi Jerry

It was our intent to require a method that best correlated with the potential SO2 emissions from a flaring event. However, EPA does not have a “total sulfur”

test method.

Most of the EPA test methods are for reduced sulfur compounds (H2S, COS, and CS2 as in EPA Method 15) or for

selected reduced sulfur compounds (e.g., EPA Methods 16 and 16B). EPA Method 16A does rely on the oxidation of reduced sulfur compounds, but includes a citrate buffer to remove SO2 prior

to the oxidation step. Only EPA Method 15A relies on oxidation with no pre-removal of SO2.

As such, this test method appears to be essentially a total sulfur measurement; however, the test method is “Total Reduced Sulfur Emissions from Sulfur Recovery Plants in Petroleum Refineries.”

While we can specify this method for use on the flares, we must

continue to

refer to it as a “total reduced sulfur” method.

We specifically did not refer to this system as a “reduced sulfur compounds” monitor, which we would have done had we intended to require measure of only H2S, COS, and CS2 (and we would have also allowed EPA Method 15 for the RATA). Using the term “total reduced sulfur” was intended to include methyl mercaptan, dimethyl sulfide, and dimethyl disulfide in addition to the

reduced sulfur compounds (compounds specifically listed in EPA Method 16A). However, since we wanted to allow total sulfur analyzers (i.e., monitors that would also measure SO2 in the flare gas stream), we specified only EPA Method 15A.

Method 15A, Section 4.1, notes that “Reduced sulfur compounds, other than CS2, COS, and H2S, that are present in the emissions will also be oxidized to SO2, causing a positive bias relative to emission standards that limit only the three compounds listed above.” We believe that it is clear from the preamble discussion that we had no intent to specifically limit the total reduced sulfur monitor to only CS2, COS, and H2S so that there is no positive bias from using EPA Method 15A to assess the SO2 root cause analysis threshold.

That said, the rule does not necessarily preclude the use of a reduced sulfur compound monitor provided that it meets the performance specifications when compared to EPA Method 15A.

Thus, if the 3 reduced sulfur compounds represent

98% of the total sulfur, then a reduced sulfur compound monitor would likely be able to meet the performance specifications when compared to EPA Method 15A, and would meet the requirements of the rule.

Brenda Shine Environmental Engineer US Environmental Protection Agency Research Triangle Park, NC 27711 (919) 541-3608, Mail Drop E143-01




What are the Total Sulfur Monitoring Options?



Option 1: Total Reduced Sulfur (i.e. Total Sulfur)

“..... intend monitor be capable of determining the sulfur concentration for the range of concentrations expected to be seen at the flare”.

Span - 1.1 to 1.3 times the maximum anticipated sulfur concentration; no less than 5,000ppmv.

Wet or Dry basis

Single dual range monitor may be used to comply with short-term 162 ppmv H2S concentration requirement for the fuel gas and the SO2 root cause analysis threshold monitoring requirement provided the applicable span specifications are met. Otherwise, must install a continuous H2S monitor.

Install, operate and maintain each total reduced sulfur monitor according to Performance Specification 5 of Appendix B to part 60.

Performance evaluations of each total reduced sulfur monitor according to requirements in 60.13(c) and Performance Specification 5 of Appendix B to part 60.

Must comply with the applicable quality assurance procedures in Appendix F to part 60 for each total reduced sulfur monitor.



Option 2: H2S:Total Sulfur Ratio Method

May use H2S analyzer for 162 ppmv H2S and RCA threshold of 500 lb in any 24- hour period

Requires H2S analyzer for continuously monitoring H2S in gas discharged while also collecting and analyzing samples of the gas to calculate total sulfur concentrations.

Span value based on the maximum sulfur content of gas that can be discharged to the flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur concentration), but may be no less than 5,000 ppmv.

In first 10 operating days collect representative daily samples of the gas discharged to flare.

Collect subsequent representative daily samples at least once per week and analyze each daily sample for total sulfur

Develop a 10-day average total sulfur-to-H2S ratio w/ 95-percent confidence interval

Subsequent weekly samples must be within 95-percent confidence interval




Option 3: SO2 CEMS

May use SO2 analyzer to measure [SO2] from a process heater or other Fuel Gas Combustion Device that is combusting gas that is representative of the gas that is being combusted by the flare.

Determine the F factor of the fuel gas at least daily

Determine the HHV of the fuel gas at least daily

Calculate the Total Sulfur content (as SO2) daily




Flare Fuel Gas “short-term H2S” rule?



J & Ja – Hydrogen Sulfide

For H2S, option of complying with subpart J by following requirements in subpart Ja

Limit short-term [H2S] to 162 ppmv (rolling 3 hr avg) in the flare fuel gas during normal operating conditions

Process upset gases or fuel gas released to flare as a result of relief valve leakage or other emergency malfunctions are exempt from this limit

Span - 300 ppmv H2S; Allowing the use of cylinder gas audits for relative accuracy assessments

Maintain each H2S monitor according to Performance Specification 7 of Appendix B to part 60

EPA Method 11, 15 or 15A of Appendix A–5 to part 60 or EPA Method 16 of Appendix A–6 to part 60 for determining the H2S concentration for affected facilities using an H2S monitor.

Optional Approach: May use Total Sulfur monitor to assess compliance with the short-term 162 ppmv H2S concentration in the fuel gas. Otherwise, install a continuous H2S monitor. Total Sulfur analyzer must be capable of accurately measuring concentrations between 20 and 300ppmv.

[H2S] always less than the [Total Sulfur]. But, no correction factor to scale down the total sulfur concentration to H2S.






Flare Fuel Gas H2S – Wet or Dry Basis?



Monitoring Requirements – Ja H2S - Wet or Dry Basis?

-----Original Message-----From: Shine, Brenda [mailto:[email protected]] Sent: Tuesday, April 02, 2013 3:09 PMTo: Combs, JerrySubject: RE: TS wet or dry basis zzz

Hi Jerry

Yes I did talk with OECA and I think there are a couple of options that could allow you to use H2S measurements in a wet basis to comply with the 162 standard as dry without the moisture condition system that would involve a correction. I think everyone here is ok with this. We just have to figure out where to put it, either in rule amendments or as alternative monitoring or as guidance.

Option 1: Monitor the temperature of the waste gas exiting the knock out drum and assume the waste gas is saturated with moisture at that temperature. They use that volume % moisture to correct the wet gas concentration to a dry gas concentration.

Option 2: Determine the moisture content of the waste gas (under typical flaring conditions), through bomb samples, wet and dry bulb temperatures, or similar means, to determine the moisture content of the flare gas and use that to correct the wet basis correction factor.

Option 3: Develop a fixed flare gas moisture content correction (based on typical to conservatively high waste gas temperature from the knock out drum and saturated conditions). This would be a conservative moisture correction factor, but would not require any additional monitoring or calculations) by the facility.

How to proceed?

1) H2S on Dry Basis (according to Ja as written)

2) Petition EPA for an alternative which would include Wet Basis along with some form of moisture analysis and/or correction factor.


mailto:[email protected]






Is Pilot Gas included?



Flare Baseline

Pilot gas is considered part of the baseline flow; assumed to be constant.

Monitoring of pilot gas not necessary to determine whether a flare has exceeded 500,000 scf above the baseline in any 24-hour period.








What are the QA requirements?




Daily Checks/Validation• Calibration Drift (span/zero)• “For the daily checks, you don't have to go through the probe, just introducing the cal gases into the analyzer suffices. See PS 2, section 8.3.3 -- "introduce to the CEMS the reference gases...“ “

Quarterly, either:• Cylinder Gas Audit OR• Relative Accuracy Audit

Annually, either:• Relative Accuracy Test Audit OR• Alternative Relative Accuracy Audit









What can substitute for RATA for some cases of non-continuous flaring?


RATA and CGA Tests – Other Considerations

Flaring solely for the purpose of a RATA or other performance test is not desirable.

Flares that do not receive routine flow, RATA and CGA tests are not required to "include as much of the sampling probe or sampling line as practical".

Flares that do not receive routine flow, the alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations, “except that it is not necessary to include as much of the sampling probe or sampling line as practical”.

Flares that do receive routine flow, RATA and CGA tests are required to "include as much of the sampling probe or sampling line as practical".

Flares that routinely have flow, total reduced sulfur monitor shall use EPA Method 15A of Appendix A-5 to part 60 for conducting the relative accuracy evaluations. Performance Specification 2 of Appendix B to part 60 (cylinder gas audits) may be used for conducting the relative accuracy evaluations.











When is the Monitor Out-of-Control?



Issue: Out-Of-Control Period “Definition”

1. For flares which have routine flow, the RATA and CGA samples are required to "include as much of the sampling probe or sampling line as practical".

2. Meanwhile, daily Validation can be introduced at the analyzer, in all cases, instead of including the probe and sampling line.

3. Plant Operator fails the quarterly RATA or CGA - Does previous data since last successful RATA/CGA become invalid? (Maybe?)

4. Should Plant Operator opt to include probe and sample lines with Daily Validations?

APPENDIX F TO PART 60—QUALITY ASSURANCE PROCEDURES/ PROCEDURE 1

Clearly states when the out-of-control period begins and ends when a failed RATA/CGA occurs:

5.2.1 Out-Of-Control Period Definition. The beginning of the out-of-control period is the time corresponding to the completion of the sampling for the RATA, RAA, or CGA. The end of the out-of-control period is the time corresponding to the completion of the sampling of the subsequent successful audit.











What are the Recordkeeping/Reporting Requirements?



Recordkeeping/Reporting

H2S

•Determine rolling 3-hour average as the arithmetic average of the applicable 1- hour averages

•Excess emissions: each rolling 3-hour period during which the average [H2S] exceeds 162ppmv

Flow/Total Sulfur

•Records of discharges > 500 lb SO2 in any 24 hr period

Alternative Methods:

•Record any instance of flare gas line pressure exceeding water seal liquid depth

•Records of H2S/TS ratio data and related calculations











What are the Recordkeeping/Reporting Requirements?

How is Downtime Calculated?



Analyzer Downtime Determination

Section 60.13(h)(2) For continuous monitoring systems other than opacity, 1-hr averages shall be computed as follows,

except that the provisions pertaining to the validation of partial operating hours are only applicable for affected facilities that are required by the applicable subpart to include partial hours in the emission calculations:

(i) Except as provided under paragraph (h)(2)(iii) of this section, for a full operating hour (any clock hour with 60 minutes of unit operation), at least four valid data points are required to calculate the hourly average, i.e., one data point in each of the 15-minute quadrants of the hour.

(ii) Except as provided under paragraph (h)(2)(iii) of this section, for a partial operating hour (any clock hour with less than 60 minutes of unit operation), at least one valid data point in each 15-minute quadrant of the hour in which the unit operates is required to calculate the hourly average.

(iii) For any operating hour in which required maintenance or quality-assurance activities are performed:(A) If the unit operates in two or more quadrants of the hour, a minimum of two valid data points, separated by at

least 15 minutes, is required to calculate the hourly average; or(B) If the unit operates in only one quadrant of the hour, at least one valid data point is required to calculate the

hourly average.(iv) If a daily calibration error check is failed during any operating hour, all data for that hour shall be invalidated, unless a

subsequent calibration error test is passed in the same hour and the requirements of paragraph (h)(2)(iii) of this section are met, based solely on valid data recorded after the successful calibration.

Accordingly, if the activity can be conducted in 30 minutes or less, the hour may still be considered valid data and not count towards the quarterly downtime percentage.

In order to minimize downtime attributed to calibration activities, Siemens recommends that the Total Sulfur zero and span daily validation be conducted on separate hours for each of the analyzer ranges.


Traditional Maxum Hardware

Single Power Supply

Single Set of Physics/PMT

Siemens SCS & Probe Design

The Maxum Flare Compliance Analyzer relies on a fundamental method for total sulfur determination:

Maxum Flare Compliance Analyzer

Same Maxum TS Flare

configuration as used

for Cal. Rule 1118


Projections of QA Activities included within downtimeQA Activity Type No.

Standards to be Used

No. Ranges

No. Runs

First Hour (min) Low and Mid- Low

Ranges

Second Hour (min) Mid- High and High

Ranges

Projected Min. per

Activity (3 min per

Run Low & Mid Range;

4 min/ Range High

Hrs Per Qrtr

Able to achieve 2 valid data

points in one hour?

Hours toward

Downtime per Qrtr

1

TS Daily Validation Zero

and High (triplicate)

4 3 18 27 min 33 min60

min/day90 hrs Yes 0

2

TS Quarterly Calibration (assume triplicate)

4 3 1860+60 min* 120 min

2.0 hrs No 2.0

3TS Quarterly

CGA (in triplicate)

3 3 9

30+ 60+ 30

min*

120 min1.5 hrs No 1.5

4Annual TS RATA

(in triplicate) 3 3 9

30+ 60+ 30

min*

120 min0.5 hrs No 0.5

* single failure time allowance



Linearity Results: R² > 0.9990



Repeatability of 197 ppm Total Sulfur (measuring range 0-600 ppm)

n = 120

8Hrs

% RSD = 0.41



Repeatability of 8987 ppm Total Sulfur at measuring range

0-20,000 (0-2%)

n = 120

24 Hrs

% RSD = 0.31




Manually hold Maxum on Low Range, then shift to Mid Range

Manually hold Maxum on Mid Range, then shift to High Range

Analyzer Ranges overlap one another


Analyzer Response – Sulfur Species (propane matrix)

4 samples each containing:{ 200 ppm H2S vs. 200ppm COS

{ 9000 ppm H2S vs. 9000 ppm COS



Analyzer Response – Sulfur Species (Nitrogen matrix; calibrated using COS)

Equal amounts MeSH and COS

Results:Sample 1) 240.9 ppm Methyl Mercaptan

Sample 2) 246.5 ppm COS

Error = 2.3% (w/ in blend error)



Siemens Process Analytics Flare Sample Conditioning System Design


Turn-Key System, Solutions – Depending on your needs

Siemens Process Analytics Systems Integration


Siemens Customer Services Portfolio

Comprehensive Services at all phases of a project:

• Tailored to meet the needs of each individual plant / project

FEES / FEED

• Project definition and engineering services Analytical system integration

• 3-sided enclosures to enclosed shelters

Project commissioning

• Start-up and training

Long-term product support

• Best-in-class service offering


Flare BTU Determination – Why?

NSPS 60.18 Flare

Combustion Efficiency

BTU > 300


60.18 Flare BTU Determination

BTU Speciation – What Additional Information becomes available (relative to Calorimetric analysis) ?

Siemens Maxum Gas Chromatograph vs. Calorimeter Analyzer

• GC provides speciated information of BTU composition

• GC can assist in troubleshooting flare sources

• Provides additional insight into flare composition

–Identify leakage around emergency dump valves on a hydrogen net gas compressor

–Identify leaking safety relief valves on a crude tower

–Identify over-sized restriction orifices on a nitrogen line



Options Available when Including BTU (60.18) and H2S (Ja) in single Maxum

Single Maxum Configurations

Total Sulfur*

H2S (as Total

Sulfur) *

H2S (opt. TCD

method)

H2S & H2O

**

BTU C5+ ***

BTU C3+ ***

SCS Temp

Transport Line Temp

Maxum A ● 115C 110C

Maxum B ● ● 115C 110C

Maxum C ● ● 115C 110C

Maxum D ● ● ● 115C 110C

Maxum E ● 115C 110C

Maxum F ● ● 115C 110C

* Wet or Dry basis** Alternative H2S on Wet Basis will require EPA petition approval *** BTU determination is not a Ja requirement


Siemens’ Recommendations to Refineries for Ja

Refinery Ja Committee at Corporate Level

a) Single Ja Interpretation within Company

b) Standardize Solution & Implementation

c) Avoid Duplication of significant effort

d) Simplify Internal and External Communications

Ja Committee on-going collaboration with Vendor’s Ja Team

a) AM, Enviro Expert, Chemists, PE, SCS, SI

b) Regulation Interpretation

c) Solution and Implementation Details

d) Consent Decree (?)

Consider new Shelter Future Accommodations


Questions?

Jerry Combs

Business Development ManagerEnvironmental & Chemicals

Mobile: 918-691-7927

E-mail: [email protected]

Answers for industry.

mailto:[email protected]

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