As offshore exploration moves into ultra-deepwater, the demands placed on accurate hydrocarbon measurement with minimal maintenance, space and weight requirements become increasingly greater. In addition to weight and space restrictions, a number of other factors highlight the importance of accuracy in these measurements:
- Capital expense spending and production operation expense budgets are increasingly tight.
- Environmental health and safety requirements are on the rise.
- It is increasingly important for oil companies to maintain a greener image.
These financial, governmental, and technical challenges, coupled with high flow rates, have enhanced the development and application of new technologies. These include ultrasonic gas and liquid meters, multiphase flow meters, microwave and near infrared water-cut analyzers, coriolis flow meters for oil and gas, and compact orifice meter tubes using isolating flow conditioners, and liquid meter provers.
This article will provide guidelines for selecting, installing, and operating such equipment with the goal of insuring cost-effective designs, reliable operation, and a high degree of accuracy. Emphasis will be placed on the decision process of selecting, installing, and commissioning metering equipment, reflecting the author's project design background.
Nearly every E&P project group responsible for the design, engineering, and fabrication of an offshore production platform goes through a decision process whereby conventional measurement equipment is compared to alternative equipment - based on space and weight requirements. Traditional equipment in this context refers to orifice meters for gas sales, and pipe provers for liquid turbine/displacement meter calibration.
The project group's responsibility to reduce capex (capital expenditures) by installing compact metering must be balanced by operational factors such as reliability or mean time between failure (MTBF), which translates to opex (operating expenditures). Other key considerations are safety, governmental and contractual requirements, and approval of interested parties such as partners, purchasers, and pipeline operators.
Regardless of country location, depth of water or fluid application (oil or gas field) there is often a strong argument for the use of a multiphase flow meter (MPFM) for well testing and/or allocation. The primary advantage of MPFM over conventional separators and associated metering equipment is the reduction of topsides weight and space. Vendors offer volumes of information to support the installation of MPFM in various applications.
Engineering studies have shown that "alternative metering concepts (multipath ultrasonic meters for gas and compact provers for liquids) with the same accuracy of today's conventional concepts, might reduce space and weight by more than 50% compared to present layouts," states Nil-Rik Hannisdal (See Hannesdal, N.) "The total cost savings might be twice the actual procurement cost of the metering skid."
This comparison does not address the question of reliability, but it is inferred that these alternative devices are as reliable as their conventional counterparts. Another engineering study conducted on behalf of North Sea operators estimated (based primarily on vendor's input) the MTBF for multi-path ultrasonic meters to be two hours of downtime over a period of 78 years or an estimated "uptime" of more than 99.99%.
However, this may not be the case as an offshore platform in the North Sea that installed 13 ultrasonic meters, reported 11 failures within the first two years of operation. This lack of reliability in emerging technology is not uniform. Consider the example of compact provers, some of which have well over 100,000 cycles, or piston strokes, between failures in offshore, crude oil applications.
A common question when facing equipment selection is the application of conventional orifice versus multi-path ultrasonic measurement equipment for the custody transfer of natural gas. Among the arguments supporting the use of the ultrasonic meter over orifice include space and weight savings, increased flow rangeability, reduced pressure drop, inherent diagnostics, reduced maintenance (calibration), tolerance to entrained liquids (wet gas), and improved accuracy.
The incremental cost ($/lbm) to support topsides facilities on a deepwater floater such as a tension leg platform (TLP) is estimated to be $5.5/lbm (excluding deck, drilling facilities, and hull) which translates into $180,000 for 100-ft of 20-in. Sch 120 pipe with two pair of 600# RF flanges.
This estimated incremental cost does not reflect any associated cost savings from decreasing the deck size and weight by reducing the size of facility equipment such as orifice meters or liquid provers.
Another deepwater challenge is the potential for hydrate formation in flowlines. When one considers that costs can rise to $12 million to workover a deepwater subsea well, it is understandable why deepwater project teams are keen to investigate new ways to reduce weight and space of topside measurement equipment. The teams also work with vendors to develop new equipment to measure relatively small amounts of free water and/or water vapor for hydrate control.
There are various international, regional, and national regulations that define operational standards for oil-contaminated effluents and discharge water from offshore platforms and facilities. Typically, the average discharge limits of oil in water is 29-40 mg/l (36-50 ppmv for 0.8 SG oil) over a period of 30 days with maximum discharge levels 42-100 mg/l.
Some major oil companies have endorsed self-imposed "greener" guidelines to further reduce emissions. BPAmoco plans to maintain total current emissions levels (that meet or exceed regional guidelines), regardless of new field development or production rates. These conservative discharge limits place increased demands on separation facilities and associated measurement equipment in mature oil fields where water cuts are greater than 60-80%.
The typical offshore platform location of sales or allocation measurement equipment is downstream of final phase separation facilities (no dehydration of gas, if not compressed) and immediately before the fluid leaves the platform in a subsea pipeline. The measured fluids at this point have been subject to some separation, but are typically at hydrocarbon and water dewpoint for gas and at bubble point for liquids. Neither of these conditions is considered ideal for custody transfer measurement and sampling.
In the event of an upset in the production separators, liquids may carry over the top. This would allow liquids in the gas line or gas may carry under, allowing free vapors into the liquid line. Even without an operational upset, normal cooling of gas (due to ambient temperatures or inevitable pressure drop from frictional piping losses) will cause liquids to condense.
Likewise, any pressure drop in the liquid line will allow free gas to evolve. These conditions will cause numerous metering problems such as liquid accumulation near the orifice plate, cavitation in liquid meters, inability to obtain a representative sampling from gas streams, and repeatability in proving of liquid meters. If liquids are introduced to an on-line gas chromatograph catastrophic failure of the analyzer could result.
For offshore fiscal gas metering applications, the author's preference is to use two or more conventional, concentric orifice meters installed in parallel. This recommendation is made assuming economic space constraints require a compact design with a high degree of reliability, life of field design criteria requires extreme rangeablity in flow rate, and accuracy is considered to be essential. In such a case, consider the following parallel design:
- Low loss, isolating flow conditioner with a minimum of 13 pipe diameters upstream meter tube
- Maximum thickness allowed orifice plates
- Single 0-400 IWC differential pressure range smart type transmitter
- Orifice flange taps oriented above the pipe centerline (12 o'clock preferred) with transmitters installed on direct mount, full bore manifolds.
The above design, when using 0.2-0.6 orifice-to-pipe ratio (beta) and 30-150 in. of water column (IWC), differential pressure for normal operations, and a maximum beta of 0.66 and 300 IWC differential pressure for emergency capacity operations, will provide a flow range of 80-to-1, with an estimated random uncertainty in volume of less than +/- 0.75%. This uncertainty may be validated from the following sources:
- Offshore, wet gas pipeline accumulated system energy and volume balance of < 0.2%
- Flow conditioner tests results from South west Research Institute (See Behring, K.; Morrow, T.)
- Orifice discharge coefficient data from API 14.3 Part 1
- Mass error due to plate bending by Jepson and Chipchase (See Corneliussen, Sidsel)
- Differential pressure transmitter field calibrations.
With all the vendor information available and the emphasis to reduce deck space to save capex and reduce maintenance in order to save opex, it would be easy to conclude that the multi-path ultrasonic is a better choice over the orifice meter for offshore, wet gas applications. After all, the ultrasonic meter is reported to be more accurate than the orifice (when wet calibrated), be more tolerant of the effects of wet gas, require significantly less deck space and maintenance, and have greater flow range capability.
However, lets take an objective look at each of these comparison claims starting with the accuracy claim. Regardless of the vendors' statements on meter accuracy, keep in mind that the MTBF is also extremely important when depending on the meter's output for the monthly accounting statement. A loss of data for any reason will always produce negatively biased errors (losses to the seller) such that a downtime of an hour in a contract month will cause a -0.14% error, and an 8-hour downtime will cause a -1.1% error.
The implementation of an isolating flow conditioner installed at a proper distance upstream (13-17 pipe diameters overall from last piping disturbance to the plate) will reduce the established upstream length requirements for an orifice meter. In addition, lab tests have shown a near perfect correlation and excellent precision with the API 14.3 Reader-Harris/Gallagher (RG) empirical coefficient of discharge equation (database using 45-80 diameters of straight pipe upstream) over a wide range of beta ratios.
This improvement in measurement is due to the isolating flow conditioner's capability to eliminate any effects from upstream piping and create an ideal flow pattern or axisymmetric velocity profile, free of swirl for virtually all worst case disturbances.
There is an inherent overall uncertainty advantage of the orifice over the ultrasonic. The orifice is an inferential head-type device with flow computed as a function of the square root of differential pressure and fluid density, compared with the ultrasonic meter, a linear device, so that any error in density will have roughly twice the additive effect on the ultrasonic.
Dual orifice meter
The use of dual-orifice meter runs with isolating flow conditioners upstream, taps rotated above centerline, smart transmitters mounted directly on fittings by means of full bore manifolds, higher differential pressure ranges, and thicker plates with beta ratios up to 0.66, allow for a flow range of 80 to 1. Such runs also prevent dishing of orifice plates from inadvertent blowdowns and provide for an accurate, reliable wet gas system balance (< +/- 0.2%) with minimal maintenance requirements.
The issue of improved wet gas tolerance has not been fully evaluated to date though data is currently being compiled as part of the GRI sponsored Wet Gas Metering JIP conducted at CEESI. At present, the use of self-draining, full bore direct mount manifolds and tap rotation above pipe centerline minimize any detrimental effects in the impulse lines.
Regarding reduced maintenance, the smart-type transmitters appear to be very stable. These transmitters require less frequent calibrations, making this a moot point as most companies prefer to have qualified technicians carefully check all metering components on a monthly basis, especially if the gas volume is significant. Offshore gas volume measurement facilities may be complimented with reliable, accurate on-line gas chromatographs (GC) to providing real-time energy measurement. But the GC must be installed as follows:
- Sample probe installed with the tip in the center third of the pipe
- Use heat traced, 1/8 in. SS tubing to insure no liquid drop out and minimal lag time
- Heated regulator (located near the probe) to insure no condensation due to J-T cooling
- 1/8-in. SS heat-traced tubing from the regulator to the GC sample inlet
- Emergency shutoff solenoid valve in the sample line - fail upon high-high level alarm from the production separator
- Inlet sample filter types and sizes to minimize possibility of liquid contamination without removing any heavy-end hydrocarbons; protect sample exhaust manifold from wind velocity effects; appropriately blended, tested, and heated calibration gas.
For offshore fiscal liquid metering applications (custody transfer and allocation), where deck space, cost effectiveness, pressure drop, fluid stability (bubble point) and accuracy are critical issues, meters may be installed as follows:
- Dual (parallel) metering is preferred
- Locate meter/prover at least one deck below separator
- Use oversized, low loss piping to minimize pressure drop
- Operate separators at highest liquid level, especially during proving
- Install small volume prover upstream of meter(s)
- Install separator control valve(s) downstream of metering
- Locate sample probe downstream of meter(s) in a vertical pipe section.
The above design does not require a pump to increase pressure above the bubble point. It uses the fluid hydraulic head pressure and meter component location to maintain sufficient pressure for metering and proving. This design has been validated to provide repeatable results (See Corneliussen, Sidsel) (repeatability <0.05% for five consecutive runs) where repeatability is defined as:
Repeatability (%) = (Vhigh -Vlow) * 100/V avg
The type of meter selected should be based on the particular application depending on gravity, flow rate, viscosity, sand production, and water cut (if operating separator in two-phase mode). Regardless of meter principal of operation or type, low pressure drop sizes and models are required.
The issue of external corrosion due to high humidity, sea sprays, saltwater washdowns and deluge systems, is common to all offshore facilities. Solutions to corrosion problems include the use of 316 SS over 304 due to increased resistance from chloride pitting due to 3-4% molybdenum content. Care should be given to insure all components are resistant to corrosion as if two stainless steel components are fastened with a mild steel. Even if cadmium plated, the result will be evident in a matter of days.
The use of Denso (Petrolatum tape systems) in highly corrosive environment such as offshore facilities can significantly reduce the effects of a salt laden atmosphere. All electrical conduit should be PVC coated using SS fasteners and bulkhead connectors with SS or fiberglass enclosures.
Several common problems are encountered during the commissioning phase of the construction project. Some of these problems are preventable and some inevitable. These problems are caused by the use of seawater for hydrostatic pipeline testing, careless deposits of foreign materials, and debris from drill bit cuttings, welding slag and sand blast particles, acids and produced sand during the well completion process, and the application of extreme physical force to overcome unexpected resistance. Many of these problems are preventable. Some of these problems may be avoided completely by following a few simple guidelines:
- Allow measurement technicians to commission new equipment. This will allow technicians to become familiar with equipment before actual operation begins as well as protecting equipment from destruction by the "construction gorillas."
- Remove turbine and displacement meters and orifice plates from the line and bypass the prover until final commissioning is complete.
- Clean taps and orifice fitting slot of rust and debris.
- Provide for the supply of air-free water for prover waterdraw.
- Do not operate the GC during the first week to month of production operations. Use a fixed composition in the flow computer and edit the data as required.
Net oil measurement
Due to the gradual watering of wells in mature oil fields and the eventual use of waterflood techniques to enhance production, a well's water cut (fraction of water produced in total liquids) may increase to 90% and above. This increase in water cut will significantly increase the total produced fluid resulting in problems in adequate phase separation and water handling capabilities of an offshore platform.
When trying to accurately measure net oil for allocation and reservoir management purposes with real-time reporting, meet desired production expectations at minimal opex budget of management and adhere to increasingly stringent effluent requirements, the implementation of emerging technology measurement devices is essential.
This equipment ranges from the use multiphase flow meters, coriolis meters for volume and water cut, microwave and near infrared or NIR principle devices for water cut, and for other applications, the combination of these devices to complement and work in concert. Extreme diligence is required when selecting the types of equipment to be employed to insure the user's objectives are met.
Coriolis and microwave techniques may be used successfully, if installed and applied appropriately. However, both of these methods are subject to increased errors in net oil at very high water cuts (+/- 10% error in net oil at 90% water cut). NIR devices, relatively new on the market, may be a better fit for very high water cut applications or monitoring interstage rejection water processing.
Early water detection
The investigation into measurement equipment for early water detection for hydrate control in deepwater, subsea flowlines has caused project groups to consider a wide range of equipment and methods.
These include downhole devices using a combination of venturis, in series, and annular capacitance techniques, sand monitoring (acoustical) devices to listen for the sound of ice crystals bouncing along the pipe, system pressure drop to predict pipeline clogging due to reduced hydraulic area from ice, and modified MPFM. Some of these methods might work, but none has been proven in the field.
Multiphase flow meters
For several reasons, multiphase flow meters (MPFM) are being considered for well test and allocation both onshore and offshore. The potential economic benefits from using MPFM for well testing offshore include increased production by use of test lines as flow lines, reduced size and weight as compared to a test separator, reduced well test time and possibly, improved measurement.
Each application must be carefully evaluated considering the range of types of wells to be tested, gas void fractions, effects of salinity, viscosity, accuracy of data and government or royalty owner approval.
When considering the MPFM for allocation keep in mind that although this is not sales, it is fiscal measurement and a 10% error could be very costly to a company's bottom line. However, MPFM may be the best fit for service method when marginal fields are introduced into existing facilities and the only other alternative is additional processing facilities or isolated phase separation for measurement purposes only.
The fiscal measurement of hydrocarbons on offshore facilities, although sometimes more expensive than onshore counterparts, can be very accurate, reliable, and cost effective. The key is to employ common sense:
- Work around the problems that cannot be controlled
- Apply the KISS principle (keep it simple, stupid)
- Apply emerging technology carefully
- Respect "Mother Nature" and protect the equipment
- Use the pipeline balance to monitor results.
Working around the problems that cannot be controlled requires that problems first be recognized. Once a problem is identified, one must find tools, equipment, orientation, and location to prevent failure and insuring reliable, accurate measurement.
The application of the KISS principle could not be more important than when selecting high volume metering equipment for the fiscal measurement of natural gas offshore in today's project management economy. Emerging technology equipment should be carefully, realistically, and objectively evaluated before being installed offshore. Respecting "Mother Nature" means protecting the equipment by using corrosive resistant materials and adequately protecting equipment from the forces of nature.
A gas pipeline energy balance is defined as the percent difference between the total re-delivered energy from the pipeline and the total delivered energy into the pipeline as follows:
Energy balance=( re-delivered - delivered)
A well-designed and operated system with a tight balance may be used to monitor the performance of measurement equipment and identify problems early.
Hannisdal, N-R, "Metering Study to Reduce Topsides Weight," Paper presented at North Sea Workshop, October 1991.
Behring, K., Morrow, T., "Effects of Swirl and Velocity Profile Asymmetry on Flow Conditioner Performance for Orifice Meters," presented at 1998 FLOWMEKO.
Corneliussen, S., "Field Experience with Hod Metering," Paper presented at North Sea Workshop, October 1991.
Jepson, P., Chipchase, J., "Effect of Buckling on Orifice Meter Accuracy," Mechanical Eng. Sc. Vol 17, No 6, 1975.