The codified regulations, known as 43 CFR 3173, 3174, and 3175, that replaced the Onshore Oil & Gas Orders measurement requirements (Onshore Orders 3, 4, and 5) became effective on January 17, 2017. With federal administrative changes and a tumultuous environment, many operators were left with a great deal of uncertainty about how these new orders might practically be put into effect. Further, many questioned when and how they might be enforced, if at all. In addition to the public and private concerns, the BLM itself had a steep learning curve to traverse as they absorbed the realities of the new regulations and how to enforce them. Immediately they sought to bring industry accredited experts, inspectors, and auditors into familiarity with the new requirements and set up regular opportunities for the industry to ask questions, debate the mandates, and work together to better understand the new requirements. These sessions identified gaps and errors as well as language that was easily misinterpreted and difficult to comply with. However, by late 2019 it had become clear that the 43 CFR 3170 rules would stand as written and would be enforced as such. Then in 2020, as the industry began to take steps towards compliance, the COVID-19 pandemic swept the nation and again delayed much of the enforcement of these new requirements. As the world emerged from the pandemic, supply chain delays reduced, and the regulated community returned to the office, many operators have found themselves in a difficult situation. While the world went on pause, the new 3170 regulations did not and now they have technically been in effect for seven years. Many operators are behind on or haven’t begun to take steps to ensure compliance with the new regulations and are beginning to see the repercussions of non-compliance as the BLM increases enforcement actions.
One of the most difficult areas for the regulated community to deal with is the requirements around record keeping. In this article we will highlight 10 of the most common deficiencies around record keeping and possible areas of exposure for your organization.
1. The scope is the first possible pitfall. Who exactly must keep records? Who can the BLM seek records from? § 3170.7 is one of the only regulatory requirements that extend beyond the BLM lease holder. Any party directly involved in producing, transporting, purchasing, selling, or measuring oil or gas through the point of royalty measurement/point of first sale, whichever is later, must retain all records. Further, records must be retained for 7 years on Federal agreements and for 6 years on tribal agreements.
2. Source records are not exempt. In addition to knowing who is responsible for the measurement records, § 3170.7 requires source records to be maintained. A source record is defined as any unedited and original record, document, or data that is used to determine volume and quality of production, regardless of format or how it was created or stored. This means that it is the responsibility of all parties directly involved in producing, transporting, purchasing, and/or selling oil or gas through a royalty point or point of first sale to keep the original record of data.
3. Identifying your FMPs. In the 3170 rules you will see a requirement for all facility measurement points to have an “FMP or Facility Measurement Point number”. It was the BLM’s original intention to assign unique numbers for each Facility Measurement Point (FMP) for all operators. However, this system was never developed. What is often overlooked is that § 3170.7(g) STILL contains requirements for information that must be included on all records, including source records, until those numbers are assigned. This includes location information and an operator assigned unique identifier number so that all records can be tied to specific measurement points.
4. Configuration Logs. All gas meters that are not using a chart recorder and all oil Coriolis meters must be able to produce records of configuration logs to the BLM upon request. This log must contain and identify all constant flow parameters used by the meter. While most flow computers store this information, it will only be held in memory for around 45 days. This means the SCADA or back-office systems must collect and store this information for the same retention period mentioned above.
5. Events & Alarms. The same requirements exist for event and alarm logs.
a. The event logs must record exceptions and changes to the flow parameters or fixed data contained in the configuration log. This means that if a parameter that could affect the quantity transaction record (QTR) is made it must be documented and kept in your records for the required amount of time. Further, you must retain the date and time of such changes or events.
b. The regulation requires that an alarm log records specific exceptions to the flow parameters. If any of the specific alarms occur records must be maintained that indicate the date and time that the alarm began and was closed. Parties must keep a record of all deviations or alarms that occur in the data for the FMPs for the same duration of time.
Ultimately, your event & alarm log can be combined as long as protection is in place to keep the alarm log from overwriting the events.
6. Quantity Transaction Records. Both oil and gas meters must be able to provide the original, unaltered, unprocessed, and unedited Quality Transaction Records or “QTR’s”. For gas meters, these records must be available at both an hourly and daily increment. For oil meters, QTRs must be retained for every transaction period. While there are many specifics to the QTR requirements, most companies understand these documents. Their pitfall, however, is making sure the unedited version is preserved for every QTR. As with the previous records relating to flow computers the limited memory of the flow computer means that these records must be stored in some other system. As part of that storage, records must identify any edits made to the QTR with justifications for such edits as part of the record.
7. Is the heating value real, ideal, and dry? While most operators on BLM properties understand that they must report the real, ideal, and dry heating value for gas, there are many hazards around gas analysis reporting that are not understood. Per the new regulations, operators must capture and retain their original gas analysis data for the same 7-years for federal and 6-years for tribal, while also ensuring they document any edits that effect the calculation of the BTU value. Gas sampling often involves many parties, and this can lead to the loss of required information such as the unnormalized mole percents for each component. It can also be problematic when component values are used to recalculate BTU values. If the proper methods are not used discrepancies might arise and this could lead to audits from the BLM.
8. Proving your meters. Often proving of meters does not happen at the end or beginning of a month so the BLM offers two options for handling these variations and properly recording them. The first and simplest is closing the measurement ticket before the proving and opening a new ticket after the prove. In the second option the BLM will allow a meter factor to be adjusted during the transaction period if the FMP uses a flow computer. This must be supported by changes in the event log and detailed QTRs that can justify the flow weighted averaging used for the meter factor.
9. Capturing Proving Shifts. It can also be found during proving operations that the meter factor from one prove to the next has shifted by more than the regulation’s allowable limits. In such cases, operators must ensure they capture the record of how equipment was handled in addition to actually handling the equipment. This is frequently forgotten and thus, the regulation’s requirements are not met. For example, a shift in meter factor in two successive provings that exceeds ±0.0025 (§ 3174.11(e)) requires the operator to edit previously reported volumes. This is based on the average from the previous meter factor and the one that was found out of tolerance. Many operators mistakenly use the meter factor from the prove conducted after the FMP was repaired rather than making the adjustments to the data per the proving results back to the last in-tolerance meter factor.
10. Detailed Meter Tube Inspections. Another common mistake in maintaining compliant record keeping is found in properly documenting a detailed meter tube inspection for meters that operate over 200 MCF/day over the averaging period. In requirement § 3175.80(i) it states that operators must have a calibration report (often referred to as a mic sheet) detailing the calibration of the meter tube and noting that it is in compliance with the rule. This detailed inspection is frequently done at the meter run fabrication facility, and while many operators are aware of the need for these documents, it is not uncommon that they are misplaced. The rule requires that any meter installed after January 17, 2017, must have one of these documents available upon request. To ensure compliance with this rule we recommend that companies capture their meter tube inspection electronically and keep it in a secure centralized database where data can easily be pulled for audits or requests by the BLM.
As operators work with the BLM to update the rules with clarifications and corrections it is important to remember that the existing 3170 rules are in effect NOW and if you are not capturing and storing your data per the required methods you are out of compliance and could be subject to a costly audit and on-going violations. We know that regulatory compliance can be a difficult and often frustrating process. However, with SPL, we can help you navigate these requirements and operate with confidence.
Stormy Phillips
President, Metrology and Data Services | Stormy is the President of Metrology and Data Services at SPL. He has over 20 years of industry experience and most recently worked as a contractor through the BLM. He is a member of the International School of Hydrocarbon Measurement general committee where he has held multiple roles and will be the General Committee Chairman in 2025. Stormy actively serves as a chair for the American Petroleum Institute Committee on Petroleum Measurement where he has received both the Citation for Service and New Member Impact Awards. He has also served as a regular instructor at the American School of Gas Measurement Technology, the Gas Certification Institute, and many other schools throughout the country. Stormy is dedicated to spreading knowledge about oil & gas measurement and passionate about educating the next generation of leaders in the Energy sector.
