The increase in deepwater production in the Gulf of Mexico and other locations around the world has brought a corresponding increase in the use of subsea multiphase flowmeters.  The placement of subsea multiphase flowmeters near the well provides improved reservoir management, well diagnostics and allocation.  However, multiphase flowmeters require timely, accurate fluid properties, at meter conditions, to realize their full potential.  Subsea architectures with long flow lines and risers have led to the realization that well tests and topside samples cannot meet the needs of this new measurement technology.  Sampling at or near the wellhead can provide samples representative of the fluid flowing through the meter, yielding more accurate fluid properties and more accurate multiphase measurements.  A method for ROV-deployed subsea sampling is needed to provide a means to capture representative fluid samples at the multiphase meter and other locations at various times throughout the life of the well. 

 

The current method of determining gas properties via topside samples is costly and inaccurate.  The potential inaccuracy of the samples and the cost of deferred production suggest that the method should be replaced by newer technology.  Current methods do little to improve the allocation process or reservoir management.  A standardized, ROV-deployed sampling system, such as proposed, will provide the ability to gather subsea samples in situ, near the well, resulting in fluid properties that are more timely and more accurately represent the produced fluids.  It will also result in improved allocation, improved well monitoring and diagnostics and improved reservoir management.

 

In this task, existing sample systems and conceptual designs of sampling systems deployed via ROV will be reviewed for their potential as standardized sampling systems.  A candidate system will be selected, developed and tested with an ROV.  Draft standards for sampling connections (interfaces), tools, equipment and operations will be developed.

Verification of deepwater subsea flow meters is key to removal of risk from both the allocation of revenue among producers and the collection of royalties in US Federal waters. While the meters may be perfectly capable of measuring multiphase flow from wells when they are first installed, this becomes an increasingly difficult task as fields (and equipment) age. The consequence of this drift away from correct operation is that the fiscal allocation of revenues and assessment of royalties will almost surely be wrong.

 

This task aims to address this issue by developing methods for conveying measurement equipment to the well site where it will be clamped on at a pre-defined position. By making measurements on each of several wells that contribute to a commingled flow stream and comparing each to the others, an equitable allocation of production can be made.

 

Both producers and the US government benefit from reduced risk. Allocation is a zero-sum game – it is possible to gain or lose large sums from meters that make erroneous measurements. Most affected parties would prefer to remove this lost revenue exposure by having verifiable measurement on all contributing meters in deepwater allocation applications. The successful culmination of this task will provide momentum toward this goal.

Current subsea multiphase and wet-gas flowmeters are limited to measurement of production fluids at a maximum temperature of 125°C and operating pressures of 10,000 psi.  Improvements are required in the design of the mechanical components of the meters to allow qualification for operational pressures up to 15,000 psi.  The temperature limitation is related to the sensors that must measure the produced fluids.

 

Task 3 aims to address these serious operational restrictions by identifying the sources of the pressure and temperature limitations in the most universally utilized sensors in multiphase and wet-gas flowmeters.  These sensors will include those that measure pressure (P), temperature (T) and differential pressure (DP).  Once these sensor technology limitations have been verified, a program will be formulated to increase the operational environmental limits of these key sensors for use both in the flowmeters and also at monitoring points along the subsea flow path, including at the wellhead.

 

Prototypes of sensors with increased pressure and temperature limits will be assembled and if required, designed and fabricated.  These sensing elements will be integrated into transmitter housings designed to meet an operational pressure of at least 15,000 psi.  The integrated transmitters will be tested at a selected testing facility, according to a qualification program developed as part of this task.

 

As the anticipated completion of “extreme” HP/HT reservoirs becomes a reality, systems for monitoring and allocation of production fluids must be available.  Without them, it will not be possible to monitor and control a well’s production.  In addition, production allocation to individual wells in a commingled system will be difficult and require a measurement-by-difference approach.  This will result in deferred and potentially lost production.

 

Because of the cost required to develop sensors for these applications and the small yearly sales potential (probably <1000), it would be impossible to persuade a sensor manufacturer to undertake this development without external funding.  Thus, without the combination of RPSEA and a co-funding JIP, these crucial sensors would not be available for use with HP/HT production.

Flow modeling, commercially called Virtual Flow Meter (VFM) technology is maturing rapidly. However, few studies have critically evaluated the performance and accuracy of commercially available VFM’s for subsea systems.  This hinders industry's use of the VFM.

 

Task 4 will address this gap in studies of current VFM technology.  A critical evaluation of existing VFM’s will be carried out by comparing the predictions of the VFM’s with actual field data from subsea multiphase flowmeters or other measurement sources. As such evaluations are documented in publications, positive results will encourage the industry to utilize the VFM technology in monitoring or allocation applications.

 

The objective will be to identify areas of strengths and weaknesses.  By documenting where existing VFM’s can function within the required error limits, boundaries can be established on their use.  By categorizing the operating regions where existing VFM’s need enhancements, this task will provide guidance to future needed developments to extend the operating envelope.

 

This task will provide the industry with applicable operating conditions for VFM’s, enabling thier use them with more confidence.  An expected additional benefit is regulatory authority acceptance of the use of VFM systems, both as a verification method for fiscal allocation and as a backup to physical subsea flowmeters. 

It is known from field operations that meters can become fouled or altered by scale, wax, asphaltenes, hydrates, corrosion and erosion. The effects on measurement of these are not well known, thus the primary objective is to understand their nature and magnitude. The project will address gaps in the deployment and use of multiphase and wet gas metering technology in deepwater production systems. In particular this task will provide insight into the ways in which production alteration of meters affects their response.

 

Tests will be performed to evaluate some commonly used multiphase meter elements, (e.g., Venturi, Cone), for alteration of the meter with synthetic deposition (scale, wax, etc.) or erosion. Measurements of the physical properties and flow through altered meters will be taken in order to characterize the effects of meter alteration. The results will provide a clearer understanding of these effects on subsea multiphase meter response.

 

A better understanding of meter alteration effects will improve the ability to recognize measurement issues, to make corrections, to improve production allocation and to assess royalties. An excellent example of how important these issues are in a deepwater production system is the case of Canyon Express, the first use of multiphase meters in the deepwater environment.

 

Flow rate measurement uncertainty analysis is a key methodology for addressing production allocation, reservoir performance optimization, operational issues and regulatory reasons. No unique collection of procedures is currently available for predicting total system uncertainty associated with multiphase flow meters, well test separator systems, and the pipelines connecting them, especially for commingled flow configurations. This lack of tools for understanding and predicting uncertainty causes significant problems for all parties involved, especially for fiscal allocation of production, with reservoir management, and with proper forecasts for operation of process facilities.

 

The uncertainty (both bias and random) associated with meters in two- or three-phase flow will be investigated and quantified.  Also, detailed characterization of multiphase pipeline flow will be carried out. This will involve both the propagation of uncertainty in PVT models to local flow conditions, as well as uncertainties that result from the transient nature of the multiphase flow in the pipe. An extension of previously developed well test measurement uncertainty analysis to multiphase meters will be conducted.  The extension will be based on the physical principle of the meter and the associated hydrodynamic flow behavior.

 

The main deliverable of the project will include a software tool with a user-friendly interface for predicting total network uncertainties for systems with subsea multiphase flow meters, accounting for meter operating conditions, in-situ PVT properties, system configurations (such as commingled flow), and pipeline uncertainties.  This should be attractive to all parties involved, such as vendors, oil industry and standard regulatory agencies, in order to more equitably allocate production and optimize reservoir performance.

 

Knowledge of system wide uncertainty will facilitate verification of meter performance and fair allocation of produced fluids, provide early indication of measurement problems anywhere in the system, and provide all parties (vendors, operators, partners, service companies, and regulatory agencies) a realistic picture of the measurement quality at all times.