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Maximizing economic recovery

By  Neil Bowman, NEL Wednesday, 02 November 2016 08:18
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NEL’s Neil Bowman outlines how current well testing practice has generated uncertainties, and provides alternative methods that can impact economic recovery.

Image of the flow measurement facility, from NEL.

The immense variability in geology across the Asia-Pacific region means that hydrocarbon production is rarely straightforward. A range of bespoke equipment is therefore required to extract hydrocarbons from subsea wells, including specialist drilling equipment, piping systems, offshore platforms, separation, fluid conditioning, and handling systems.

A comprehensive understanding of the operating conditions faced by subsea systems, both during the design stage and during the operational lifetime of the system, allows engineers to better design and configure such systems to optimize their performance, and therefore maximize economic recovery.

Of course, it is rarely possible to produce  purely oil or gas from a well during hydrocarbon production, and the stream is typically a mixture of hydrocarbons and a range of undesired contaminants like produced water and sand. In addition, the presence of hydrocarbon-based solids such as waxes and asphaltenes can also deliver significant flow assurance challenges.

Furthermore, process conditions can vary enormously from well to well, and even a given production stream can vary significantly as a well matures. In order to maintain efficient and safe production, a production system must adapt to these evolving operating conditions.

This can pose a significant engineering challenge. These challenges ultimately have an impact on the commercial profitability, and ultimately the viability of the well.

The ability to accurately characterize and monitor the flow rates of constituent components with a production stream in addition to other key parameters, such as temperature and pressure within the well is therefore a vital step in the process of maximizing economic recovery (MER).

Well testing

The conventional approach to characterizing constituent flow rates from a well is a process known as well testing, which generally involves two major pieces of equipment. The first is a series of gauges, check valves, flow switching valves, isolation valves and packer assemblies located subsea, often as part of a dedicated string that can extract a range of data about the health of the well and operating conditions.

The second component is the test separators and metering skids. These are normally located topside, although subsea systems are becoming increasingly common. The rationale for the well test being designed this way is a consequence of flow measurement technology.

Owing to the advantages of single-phase metering over current multiphase metering technology, well test procedures are designed around test separators which allow the production fluid to be periodically sampled.

By separating a sample into its constituent components and measuring them using single phase flow meters it is possible to gain insight into the behavior of the production stream.

While well testing is conducted during the exploration phase, allowing geologists and engineers to predict the life and production rates from a well, it is also used throughout the life of the well to monitor and track production rates.

This data is then used to profile the well using a number of important characteristics such as its flow capacity, skin factor, and the structural and/or hydrodynamic boundaries - all of which ultimately dictate the commercial viability of the well and the design/configuration of the production system.

There are obvious advantages in well testing to characterize the production profile of a well as it allows the production process to be optimized, and thereby streamline production and maximize efficiency in order to maximize economic recovery.

While this characterization fundamentally relies on accurate measurement, when using test separators and single phase flow meters there are a number of potential sources of error which can reduce the overall accuracy of a well test.

This includes large or sudden changes in the composition of the production fluid; presence of second phases; poor maintenance schedule; poor calibration schedule; fouling installation effects; and well test frequency or duration

The MER effect

One of the key questions to consider is: “Just what effect does measurement accuracy have on MER”? In a recent study, a team from Coventry University set out to answer this question.

As part of this analysis the team created an example reservoir case where typical values for key reservoir parameters were chosen. A series of tests were completed to examine how different recorded measurement data influenced the reservoir characterization when compared with the actual flow rates.

The output from each case was then used to select an appropriate reservoir fracture model which would be used to predict reservoir recovery factor. The results showed that the flow measurement error was only weakly linked to recovery factor directly.

However, the secondary effect of using the data to select which model to use was very significant. A flow measurement error of ±10 % was enough to mis-select the predicted reservoir model, resulting in a shift in recovery factor by around 12% over a 20 year period.

In the case study reservoir, the in-place hydrocarbon volume contained almost 40 MMbo at US$60/bbl this would result in an error of around £75 million. To put this in context, Malaysia alone had an approximate oil production of 657,000 b/d in 2013.

Applying the same logic as above, this results in a decrease of around $34 billion in total production, a large percentage of which would be available to the government as royalties for public spending. The sample reservoir also highlighted the need for continuous measurements as opposed to periodic ones.

When a test separator is used, it is typically only for a few days a month before another well is tested in the campaign. The recorded data is assumed to be correct for the month before the next well test is completed, where a new set of data is produced.

During the assumed constant period, any changes in the component flows will not be monitored and hence issues such as water breakthrough are not identified. In addition, the constant use of test separator systems can have implications on their measurement performance.

The major advantage of using multiphase flow meters for well testing applications is that it is possible to monitor the production stream in real-time, providing continuous data to operators which would be impractical with conventional well-testing techniques. In addition to this they can greatly reduce the cost, complexity and size of the infrastructure required to conduct well tests.

Multiphase flow meters do not generally constitute a well test system on their own, but more commonly operate as part of a wider well-testing strategy. As the technology improves, their uptake is increasing and they are becoming ever more commonplace.

However, regardless of which technology is used, accurate characterization of reservoirs and production streams is vital in order to optimize production processes and ultimately maximize economic recovery.

Through research and operational experience it has been found that the financial exposure caused by inaccurate flow measurement can be significant. Effective well testing procedures are vital in optimizing production and maximizing economic recovery.

Flow measurement technologies such as multiphase flow meters are developing rapidly with the capacity to provide increased accuracy, new insight and diagnostic capabilities. Most importantly however, they provide a continuous method of measurement allowing for a fast response for production optimization, flow assurance and a reduction in inefficiency.


Neil Bowman
is a project engineer at NEL, a provider of technical consultancy, research, testing and program management services. 

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