Natural gas production creates a byproduct of natural gas liquids (or NGL), often referred to as “condensate.” The physical properties of condensate vary with the hydrocarbon constituents and differing fluid vapor pressures depending on the deposit at the location from which they are drawn. This constituent variation and the presence of water or natural gas in the flow stream discharge from the separator compromises the integrity of the measurement.
The Bureau of Land Management (BLM) Onshore Order #4, “Oil and Gas Measurement,” regulations point to positive displacement flowmeter or tank gauging technology as best practices for the measurement of liquid hydrocarbons departing Federal Leases.
Several technical shortcomings exist with mechanical meters in liquid hydrocarbon measurement service where condensate is at “un-weathered” conditions. Such condensate applications are challenging with gas breakout, and the liquid readily cavitates due to the low fluid vapor pressure. Positive displacement flowmeters exhibit no short-term ill effects but erroneously over-measure when vaporization occurs. Over time, mechanical wear leads to undetected drift from baseline conditions between physical proving sessions.
Since mechanical positive displacement flowmeters do not measure process density, sampling is required. This leads to a higher cost of ownership due to additional apparatus needed to comply with API practices. The economic realities of mechanical meter measurement expose an operator to greater uncertainty in measurement of liquid hydrocarbons. Monthly correction of improper or failed measurements leads to questioning of the reported volume. Finally, the methodology of monthly proving or mechanical flowmeter exchange poses a significant health, safety and environmental impact in practice.
Shell Exploration and Production Co. understood the technical limitations of positive displacement technology and proposed a new approach for bulk condensate measurement using Coriolis flowmeters for the Pinedale Anticline natural gas field in Wyoming. The producing company requested and obtained conditional approval of a variance from the BLM (part of the U.S. Department of the Interior) for bulk separator measurement of condensate by Coriolis flowmeters prior to comingling the production streams from other leases. The benefits of Coriolis mass flowmeter measurement include:
- Refinement of separation operation and process control.
- Immunity from process changes such as viscosity or density.
- Accuracy and repeatability designed to meet lease automated custody transfer (LACT) flow metering requirements.
- Limited health, safety and environmental impact.
- Multi-variable digital and analog outputs assigned to key measurement parameters.
- National Institute of Standards and Technology (NIST) traceable calibrations with laboratory accreditation for duty and master meters.
- Master meter proving methods and extension of the proving test interval.
- Advanced diagnostics detection of transient or long term process effects.
- Traceable in-situ verification technique for predictive non-detected fault diagnosis over the lifespan of the meter.
- Extended mean time between failure (MTBF) benefits and immediate measurement failure notification.
- Coriolis flow meters produce redundant digital and analog outputs of key measured variables.
- Metering solution allowed leveraging the use of Coriolis Meters to achieve sales quality measurement uncertainty for live (“unweathered”) condensate.
- Liquid gathering system development results in field wide reduction of truck hauling of condensate, produced water with tankage elimination.
- Sustainability improvements resulting in less field visits to the pads for calibration and equipment oversight due to remote telemetry and monitoring capabilities (metering facilities).
- Reduced overall environmental impacts including: a. lower activity levels and disturbances, b. lower vehicle air emissions and traffic dust, c. lower noise levels and d. lower risk of accidents.
Coriolis mass flow meters are multi-variable, multi-output electronic flow instruments. Unlike traditional volumetric flowmeters, Coriolis flowmeters directly measure the fluid mass flow rate based on the “Coriolis Effect.” With this principle, the phase offset of the balanced sensing element is measured. When a flowing fluid enters the measurement sensor, a force is imparted perpendicular to the sensing tube wall by the passing fluid. Electrodynamic sensors mounted on both the inlet and outlet detect a phase offset imparted on the movement of the flow tubes. The measurement of the phase offset is directly proportional to the mass flow rate of the fluid in the tube. The transmitter converts the phase offset measurement to a usable pulse and/or analog flow output.
The Coriolis flow meter also measures the liquid density. The flow tube vibrates at a resonant frequency which corresponds to the sensing tube material and the density of the fluid in the tube. Feed back from the sensing system’s variable gain drive circuit permits the drive frequency to migrate to the resonant frequency. During the flow meter calibration process, the resonant frequency of each sensor is determined on air and water. When the process liquid density changes the resonance frequency also changes. Consequently, the resonance frequency corresponds directly to the liquid density in the sensor. To counter the effects of density changes due to changing process conditions, Pt-1000 RTDs (resistance temperature devices) are mounted on the flow tube to measure the process fluid temperature.
Positive displacement flowmeters do not have provisions for measuring the product density directly. Consequently, only uncorrected volume flow rate measurement is possible. Additional systems are required to periodically sample the flow stream to determine the average quality of the liquid hydrocarbon.
The ability to measure mass and density allows for the calculated measurement of gross volume. This allows the producing company to produce and report: (1.) the direct measurement of mass flow rate (lb/m), (2.) the direct measurement of the fluid density (lb/bbl), and (3.) the computed measurement of gross volume (bbl/day).
Viscosity changes impact the measuring range of a positive displacement flowmeter and affect the linearity of the measurement. The Coriolis mass flowmeter measures the mass flow rate regardless of changing liquid viscosity.
A Coriolis flow meter’s density measurement capability permits a gross volumetric calculation of the liquid hydrocarbon.
Process temperature is the third measurement provided by the Coriolis flow meter. The process flow tube and secondary containment case temperatures are measured by Pt-1000 RTDs. The process density can be corrected to a reference temperature (e.g. API at 60° F). When the process liquid and ambient conditions differ, external temperature influences can be accounted for by measuring the temperature of the secondary containment housing.
Positive displacement flowmeters require additional external hardware to account for the fluid density and temperature changes to produce an accurate measurement.
It can be demonstrated by uncertainty analysis that a Coriolis flowmeter system is a factor of two times better than the equivalent volume-based metering system using a positive displacement flow metering system. Given the high value of some liquids, this is a considerable reduction in monetary uncertainty.
Users select the Coriolis flowmeters for highly accurate and repeatable measurement, long term stability, and resistance to wear. The broad range of industrial applications enables the evaluation of the operational safety of the Coriolis technology. A relevant safety factor called the mean time between failure (MTBF) of the flow meter is calculated. Coriolis flowmeters have one of the highest MTBF for electronic instrumentation – greater than 43 years – far exceeding the life span and expectations of positive displacement flowmeter.
Standard diagnostics in the Coriolis flowmeter microprocessor based electronics monitor the sensor signals and calculate measurement parameters. Additionally, the microprocessor detects faults and process conditions which exceed control limits. The transmitter provides alarm notification when faults are detected. Coriolis flowmeters use the vibrating tube control system to diagnose process effects. Limits can be programmed on density measurement values greater and lesser than the known process density. When the electronics detect dramatic changes in resonance frequency, which can be indicative of empty process piping or liquid vaporization, the flowmeter measurement ceases output and provides an alarm signaling the upset process condition.
During the Coriolis flowmeter variance testing and implementation process at Pinedale, data collected during the first year was used to improve bulk separator operations. Process upsets were determined when water undercut or when gas breakout occurred.
The long term monitoring and detection of process effects are advantageous for any flow measurement device. Coriolis flowmeters detect the conditions which would compromise measurement stability, induce drift, or could add measurement error. Coriolis flowmeter transmitters are microprocessor based devices which provide not only standard measurement capabilities but also advanced diagnostics functions.
Advanced diagnostics extend further analysis of the flow sensor signals beyond the basic monitoring offered with the standard diagnostics. When Advanced Diagnostics is implemented in a process application, adverse conditions can be identified when they occur. A unique signature or “thumbprint” is created during this commissioning process. Advanced diagnostics limits are set by field service personnel based on previous manufacturer service experience. These limits are configured for automatic detection:
Excitation Current: This Coriolis flowmeter electronic measurement parameter indicates the amount of power required to maintain the sensor oscillation. With single phase fluid in the meter, excitation current normally remains at less than 3.5 mA during flowing and non-flowing conditions. Excellent measurement quality is expected with excitation current at this level. Gas breakout in the condensate upsets the balance of the meter and increases the excitation current to a value up to 30 times higher (30-99 mA). Sustained excitation current events greater than 5 mA compromise measurement accuracy.
Tube Damping: With a constant, known flowing process condition and with uniformly constant temperature, the detection of long term buildup from coating of the Coriolis sensing tube is possible. With buildup, the mass of the sensing tube increases. This causes a change in the drive power requirement needed to maintain the amplitude of the sensing tube oscillation. Tube damping is expressed in mathematical terms as:
Tube Damping (Aeff/mA) = Excitation Current (mA) / Tube Excitation Amplitude (mA)
The real-time analysis at Pinedale revealed a steady tube damping factor with no evidence of coating of the flow tubes over the first year of installation. A side benefit from monitoring tube damping is the confirmation of transient events. Instantaneous spikes resulting from cavitation or gas bubbles passing through the sensor are easily diagnosed. Other than the use of dual pulsers, diagnostics options are not known to exist regarding positive displacement flow meter health, stability, process or functional analysis.
The long term performance of the Coriolis flowmeter is monitored by NIST traceable “verification.” Verification isolates drift which might impact the sensor or transmitter uncertainty. This process includes the testing of internal circuits and wiring, temperature elements, and pickups or coils used to drive the sensing tube. Similarly, testing of the amplifier circuit can detect drift in the transmitter digital to analog output conversion. Verification identifies non-detected faults before they impact the quality of the Coriolis measurement.
The Coriolis verification process finalizes with the generation of an unalterable report and electronic file for future comparison to subsequent meter verifications. This verification is printed out in a document suitable for submission to the BLM. The Two Sigma method of traceable verification employed at Pinedale allows for random testing in concert with flow proving, extending the mandatory proving interval.
Accredited, traceable calibrations ensure an unbroken chain of confidence to the original artifacts having governance. The Pinedale Coriolis flowmeters are initially calibrated using a gravimetric tank and scale systems, described in ISO-4185 – Measurement of liquid flow in closed conduits – Weighing method, using reference standards traceable to NIST. A gravimetric method of calibration reduces the level of uncertainty found in other methods. The system is accredited by the American Association for Laboratory Accreditation (A2LA). A2LA confirms the traceability of the reference standards, the traceability of the calibration methods, record keeping and training of the calibration personnel in accordance with ISO-17025 – “General requirements for the competence of testing and calibration laboratories.” To maintain a higher level of proficiency, a master meter is used for in-situ proving upon installation. The master meter is also proved gravimetrically but with additional test points along the range of flow. This assures that the master meter proving points are traceable to prove the Pinedale duty meter at the operational flow rate.
Accuracy And Repeatability
After the Coriolis flowmeter variance was submitted for the Pinedale Anticline Lease measurement points, the BLM asked Shell Exploration and Production Co. to conduct a third-party measurement uncertainty analysis. The analysis followed recommendations found in the API Manual of Petroleum Measurement Standards Chapter 13, “Statistical Aspects of Measuring and Sampling,” ISO 5168, “Measurement and Fluid Flow – Evaluation of Uncertainties,” and American National Standards Institute/British Standards Institute/International Organization of Standardization “Guide to the Expression of Uncertainty in Measurement.” Based on the operating flow rates, a root sum squared (RSS) uncertainty analysis was created by an independent auditor, SOLV Limited, Scotland, UK, based on the master and duty meters used across the full range of operating flow rates selected for the service. The resulting calculation of measurement uncertainty was created for the anticipated range of flow.
Tuning Separator Operations
Coriolis flow metering refines the separator operations, achieving the best limits for process control. Separator operations are “tuned” using real-time recognition of flow conditions and adjustment of the separator dump cycle; changing fluid vapor pressures are evaluated as it relates to sensor measurement stability.
The API Manual of Petroleum Measurement Standards, Chapter 5.6, “Measurement of Liquid Hydrocarbons by Coriolis Meters,” makes general recommendations for the broad variety of applications from crude oil to refined petroleum liquids and petroleum chemicals. Section 6.3.2 Piping, Subpart B recommends that “Any condition that tends to contribute to vaporization or cavitation of the liquid stream should be avoided by system design and by operating the meter within its specified flow range. Vaporization or cavitation can be minimized or eliminated by maintaining sufficient pressure in and immediately downstream of the meter.” The recommendation goes further in that same section to state, “In lieu of actual test data to determine back pressure requirements, the following equation can be applied:”
Pb = minimum back pressure (psig)
pe = equilibrium vapor pressure of liquid at the operating temperature (psia)
?p = pressure drop through the flow meter at the maximum operating flow rate (psi)
A period of acceptance testing for the variance request submitted by Shell Exploration and Production Co. allowed a full range of in-situ operation for the Coriolis flowmeters to be applied in the Pinedale Anticline. Flow rate tests provided a direct method to determine dump valve trim size to maintain backpressure at operating flow rates preventing cavitation during normal operations as well as when conducting the master meter proving of the duty meter.
Real-time diagnostics, in-situ verification techniques, and master meter proving techniques are not available with traditionally recognized flowmeter technology. Coriolis mass flowmeters provide reduced uncertainty, reliable long-term stability, low maintenance, and predictive process monitoring. Realizing the benefits of Coriolis flowmeters, Shell Exploration and Production Co. incorporated this technology to assure the BLM mandated measurement uncertainty or improve upon it, while minimizing the overall facility equipment footprint and associated costs. Moreover, this implementation has the enhanced benefits of greatly reducing or eliminating environmental, health and safety exposures.
Mark Davis is staff engineer with Shell Exploration and Production Co.
Jerry E. Stevens is senior product marketing manager of Endress+Hauser. Endress+Hauser is a supplier of industrial measurement and automation equipment, providing services and solutions for industrial processes. It offers comprehensive process solutions for flow, level, pressure, analysis, temperature, recording and digital communications across a wide range of industries, optimizing processes in regards to economic efficiency, safety and environmental protection.
Michael Keilty is business development manager of Endress+Hauser.