Petroleum Accountant’s Society of Oklahoma

Name: Petroleum Accountant’s Society of Oklahoma
Uploaded: 2017-08-13T06:57:00+00:00
Duration: PTM46S39
Channel: Cori York
Description: Petroleum Accountant’s Society of Oklahoma

Petroleum Accountant’s Society of Oklahoma
Update of Onshore Orders 3, 4, and 5 Richard Estabrook, BLM Washington Office (Ukiah, CA) Petroleum Accountant’s Society of Oklahoma February 12, 2015

DISCLAIMER These are draft proposed revisions;
The BLM is not soliciting comments today; The BLM discourages you from paying attention to this presentation DISCLAIMER

Outline Overview of BLM jurisdiction, responsibility, and statistics
Current measurement regulations Draft proposed changes Status and timeframes

BLM Jurisdiction and Responsibility (oil and gas)
245 million acres of public land (BLM) 325 million acres of other federal land 60 million acres of Indian trust land 57 million acres of split estate 700 million acres

BLM oil and gas responsibility: Leasing Permitting
Inspection and Enforcement Drilling, plugging Environmental Proper measurement

Federal Onshore Oil and Gas Statistics (FY2013)
23,000 producing leases 12.6 million acres of producing leases 93,000 wells 135 million bbls/year of oil 2.6 trillion cubic feet of gas per year $3 billion in Federal royalty per year

Federal Onshore Measurement Regulations
Federal Oil and Gas Royalty Management Act 43 CFR Part 3160 § Oil Measurement § Gas Measurement § Disposition of Production NTL-4A Venting, flaring, bene. use, loss Onshore Order 3 Site Security Onshore Order 4 Oil Measurement Statewide NTLs EFCs Onshore Order 5 Gas Measurement

Onshore Order 3 – Site Security
Seals (tanks and LACTS) Run tickets No meter bypasses Reporting of theft Self inspection Seal records: 6-year retention Site security plan Site facility diagram Federal seals

Onshore Order 4 – Oil Measurement
Tank gauging procedures Tank sampling procedures LACT, positive displacement meter requirements LACT proving requirements Sediment and Water (S&W) determination API gravity determination Variance required for other methods (e.g. Coriolis) Incorporates numerous API standards (pre-1989)

Onshore Order 5 – Gas Measurement
Flange and pipe tapped orifice plates: AGA Report 3 (1985) Chart recorders: calibration outer 2/3 Gas sampling: BTU determined once per year Calculations:

NTL 2007-1 Electronic Flow Computers
Parallels Onshore Order 5 requirements Adopts AGA-8, API (1992), and portions of API 21.1 (1993) Display requirements Instantaneous DP, SP, Temp, Flow rate Yesterday’s volume (except Wyoming) Calibration Transducer accuracy basis for calibration Operation Overall uncertainty ±3% for >100 Mcf/day Low-flow cutoff ≤0.5” Calculations per API (1992) are OK

NTL-4A Addresses “beneficial use”
Defines “avoidable” vs. “unavoidable” loss Sets standards for venting and flaring: Emergencies Testing Prohibits venting/flaring of “gas well” gas Venting/flaring of “oil well” gas for 1 year if justified and approved Reporting of gas used beneficially, vented, flared, or lost

Federal Oil and Gas Royalty Management Act 43 CFR Part 3160
Existing Regulations Federal Oil and Gas Royalty Management Act 43 CFR Part 3160 § Oil Measurement § Gas Measurement § Disposition of Production NTL-4A Venting, flaring, bene. use, loss Onshore Order 3 Site Security Onshore Order 4 Oil Measurement Statewide NTLs EFCs Onshore Order 5 Gas Measurement

Federal Oil and Gas Royalty Management Act 43 CFR Part 3170
Proposed Revisions Federal Oil and Gas Royalty Management Act 43 CFR Part 3170 § 3170 Records, variances, def’s § 3173 Site Security, comm, OLM, FMP § 3174 Oil Measurement § 3175 Gas Measurement § 3178 Beneficial Use § 3179 Venting, flaring, avoidable loss

Proposed Revisions Common to Part 3170
Definitions Records, including purchasers/transporters Tampering Variances Appeals and enforcement Major/minor, corrective action, timeframe Implemented through policy

Facility Measurement Points Off-lease measurement
Proposed Revisions to Onshore Order 3 Site Security Facility Measurement Points Commingling Off-lease measurement

Subjects Covered Existing Proposed Revisions Seals – tanks and LACTs
Run tickets (sales) Theft or mishandling Self inspection Site security plan Site facility diagram Federal seals Proposed Revisions Seals – tanks and LACTs Run tickets (sales) Record of all access Theft or mishandling Site facility diagram (added) Federal seals Facility Msmt. Points (FMP) Commingling Off-lease measurement

Facility Measurement Points
Existing No consistent tracking of royalty meters or measurement facilities Measurement standards (Orders 4, 5) apply to “sales and allocation” facilities

Measurement must be on the lease [CA, unit] unless otherwise approved…
1-1 #1 #2 #8 1-2 #3 1-3 #9 2-1 #4 #5 2-2 #7 #6 NM-16113 2-3

Proposed Revisions FMP: A measurement facility used in the calculation of royalty Requires BLM approval and would be assigned an FMP number by the BLM Measurement standards (3174, 3175) would only apply to FMPs Allocation meters would not be FMPs

New facilities would require FMP number prior to removal of production Existing facilities within 18 or 24 months FMP number would be shown on all measurement equipment All documentation (including OGORs) would require FMP number

Questions about FMPs Does the new requirement for FMP numbers apply to both oil and gas? Yes. An FMP would include: - A gas meter - A LACT - An oil tank facility (multiple tanks) Would the reporting on the OGOR (card ‘C’) be at an FMP number? Yes

Questions about FMPs How are downhole commingling situations impacted by the new FMP requirement? An FMP can measure oil and gas from more than one lease, CA, or PA Are the reporting changes going to be prospective or retroactive? Prospective Who will assign the FMP number? BLM How will existing facilities get FMP numbers assigned? Operators will apply to BLM

Commingling Existing BLM can approve commingling
IM : BLM can approve if…

Category 1: Allocation doesn’t affect royalty
Federal Lease 12.5% #1 1-2 Not FMPs FMP NMN-25533 #3 Federal Lease 12.5% #2 2-2 NMN-25211

Category 2: Marginal volume wells
Fee lease #1 1-2 Not FMPs FMP #3 Federal Lease 12.5% #2 2-2 NMN-25211

Category 3: Other considerations - environmental
Fee lease 1-2 FMP Not FMPs Federal Lease 12.5% 2-2 NMN-25211

Commingling Proposed The provisions of IM would generally be codified Would apply to existing commingling approvals

Proposed Revisions to Onshore Order 4
Oil Measurement

Subjects Covered Existing Proposed Revisions Industry standards (old)
Tank gauging Sampling – S&W LACT components LACT proving Alternate methods Proposed Revisions Industry standards (new) Uncertainty standards Tank gauging Sampling – S&W LACT components Coriolis Meas. System Meter proving Measurement tickets Alternate methods

Proposed Revisions to Onshore Order 5
Gas Measurement

Subjects Covered Existing Proposed Revisions Industry standards (old)
Orifice plate and charts Low-flow exemptions Chart recorders Btu once per year AGA 3 (1985) calcs Proposed Revisions Industry standards (new) List of approved equipment 4 tiers based on flow rate Meter tube inspections Charts ≤ 100 Mcf/day Integration statements Gauge line standards Dynamic sampling frequency Gas sampling and reporting Transducer testing protocol Flow computer testing prot. Calculations

Subjects Covered - EGM Existing (NTLs) Proposed Revisions
API 21.1, API 14.2 (old) Displayed data On-site data LFCO = 0.5” Verification Gas expansion (B&B) Atmos. pressure IV not required Proposed Revisions API 21.1, API 14.2 (new) Displayed data On-site data LFCO = 0.5” Verification (initial and rtn.) Gas expansion (API ) Atmos. Pressure (no cntrct) IV required Reporting raw data

Sampling Frequency Common practice: Higher volume meters: monthly
Lower volume meters: quarterly Why?

Royalty Policy Committee (2007):
“MMS and BLM should develop a procedure to determine the potential BTU variability of produced natural gas on a by-reservoir or by-lease basis, and estimate the implications for royalty payments” “MMS and BLM should adjust BTU frequency requirements for sampling and reporting on a case-by- case basis, or consider other regulatory requirements”

BLM Heating Value Study The goals…
Determine heating value variability for each meter Correlate variability with variables (type of reservoir, type of lift, rich/lean gas, temperature…) Figure out appropriate sampling frequency

BLM Heating Value Study
The data…

Meter #1 Heating Value History - 2007
1280 True heating value? 1240 1200 Heating Value, Btu/scf 1160 1120 1080 1040 2007

1280 1240 True heating value? 1200 Heating Value, Btu/scf 1160 1120 1080 1040 2007

±2σ Meter #1 Heating Value History - 2007 Heating Value, Btu/scf 1280
1240 1200 Heating Value, Btu/scf 1160 Average 1120 1080 1040 2007

Variability vs Reservoir Type
Coal bed methane Gas cap Retrograde Tight sands 100 200 300 400 500 600 Average sample period, days 5 10 15 20 V95% Variability vs Reservoir Type

Variability vs Lift Type
Flowing Pump jack Plunger lift 100 200 300 400 500 600 Average sample period, days 5 10 15 20 V95% Variability vs Lift Type Figure 15

Variability vs Separator
No separator Separator 5 10 15 20 100 200 300 400 500 600 Average sample period, days V95% Variability vs Separator

Variability vs Pressure
> 500 psi < 50 psi 50 – 500 psi 5 10 15 20 100 200 300 400 500 600 Average sample period, days V95% Variability vs Pressure

Variability vs Heating Value
> 1141 Btu/scf < 1081 5 10 15 20 100 200 300 400 500 600 Average sample period, days V95% Variability vs Heating Value

Variability vs Flow Rate
5 10 15 20 25 < 50 Mcf/day > 500 100 200 300 400 500 600 Average sample period, days V95% Variability vs Flow Rate

1280 1240 1200 Heating Value, Btu/scf 1160 Average 1120 1080 1040 2007

BLM Heating Value Study Conclusion
Heating value variability is random and meter specific

BLM Heating Value Study Conclusions
Heating value variability is random and meter specific Assume variability is randomly distributed around the true average Look at the accuracy of annual average heating value, not the accuracy of each sample

1280 1240 1200 Heating Value, Btu/scf 1160 Average 1120 1080 1040 2007

1280 1240 1200 Heating Value, Btu/scf 1160 1120 1080 1040 2007

1280 1240 Average 1200 Heating Value, Btu/scf 1160 1120 1080 1040 2007

BLM Heating Value Study More conclusions:
Set performance standard for average annual heating value uncertainty High historic variability = more samples Low historic variability = less samples Incentive for good sampling practice

Questions about Btu determination
Currently, the BLM requires Btu sampling at least once a year, while ONRR is requiring it to be done at least twice a year. Who has jurisdiction on this issue? Both. Operators would comply with both requirements by sampling twice per year What could be changing? New sampling frequencies may be proposed in the 3175

Questions about venting and flaring
Will the BLM require venting (non-tank) and flaring from gas operations to be reported on the OGOR? Is there a situation where this may be royalty bearing? OGOR reporting requirements are the jurisdiction of ONRR NTL-4A already requires the reporting of vented/flared volumes Under NTL-4A it could be royalty bearing if it is unapproved or deemed to be avoidably lost

Questions about venting and flaring
Will tank venting require measurement and reporting on the OGOR as “flash gas” or “vapor recovery” or some other report type? If this is NOT sold (ie. flared or combusted) would it be royalty bearing?

Status and Timeframe 3173, 3174, 3175 currently under review by the Secretary’s Office Draft published in the Federal Register by July, 2015 Final published by August, 2016

Petroleum Accountant’s Society of Oklahoma

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