Monitoring produced oil, gas, and water rates from individual wells plays an important role in reservoir management and production optimization. While monitoring is beneficial, obtaining timely and accurate well test data can be challenging due to a range of factors.

Typically, day-to-day production well testing is performed by utilizing test separators installed at the time the facility was built or by transporting portable well test separators and the associated pressure control equipment to the well site to perform a well test. Both techniques rely on gravity-based well test separators and swinging the well from a production mode to a test mode.

Disadvantages in current technique

While this is a tried and trusted technique for testing wells on an individual basis, there are some disadvantages associated with this method because it relies on the premise that a complete or at least an efficient separation takes place between the produced fluids. However, process fluids very often need conditioning and are treated to achieve optimum separation, requiring a significant amount of ancillary process and pressure control equipment.

Where the separation is inefficient or the separator experiences an upset condition – for example, liquid slugging or foaming – there is an opportunity for carryover or carry under, which lead to downstream process management issues and inherent errors in the single-phase metering.

This process can add complication and risk because of the operations and logistical needs of delivering heavy and bulky equipment to the well site. An upset to the process conditions that breaks into the production line or diverts the well to a test header to facilitate the well test and the associated handling or disposal of the now-separated test fluids also can cause issues.

The size and cost associated with mobilizing and operating portable test separator packages in the field may also limit the number of wells to be tested. Therefore, for field management purposes operators often develop various schemes and models to infer the production rates for each well. Operators may use these models to predict individual well performance and make intervention and workover decisions based on incomplete data with regard to actual well performance.

All models require a minimum of data inputs, which are used to tune or validate predicted vs. actual well performance. Typically, only pressure and temperature data are available, and access to flow data is dependent on well test frequency.

Assuming that each producing well should be tested at least twice a year, a field with 100 wells would require more than 200 well tests to be performed per calendar year. Considering the fact that each test takes an average of three days – a day to mobilize the equipment, divert, and rig up the well test equipment; a day to test the well; and a day to rig down and return the well to production – this would take in excess of 600 days to meet the surveillance requirements.

The only way to meet the objectives on well testing would be to run multiple test packages and crews throughout the field, which can be impractical from a cost and operations perspective.

New technology

To combat these issues, Expro Meters has successfully introduced SONARtest, a new service that uses a small-footprint clamp-on sonar flow meter to facilitate well testing on an individual well basis. The technology uses a sonar flow meter to clamp on to wellhead piping to measure the mixture volumetric flow rate at actual conditions.

Clamp-on sonar-based flow meters utilize sonar processing techniques to determine the speed at which naturally occurring coherent flow structures convect past an array of sensors clamped externally to the pipe, and from this a mixture velocity can be determined. This velocity measurement is then combined with existing customer measurements of the process pressure and temperature and compositional information to determine individual phase flow rates.

During the SONARtest, periodic samples are taken of the fluids at line conditions, and a base sediment and water test is made to determine watercut. The flow computer then calculates the liquid volume fraction at actual conditions within the process flowline using a black oil model. Gas, oil, and water rates are then reported at standard conditions using input watercut.

Gas and liquid rates reported by the sonar meter are within 10% or better of the well test separator. The sonar-based technology eliminates the need to divert the well to test in existing or temporary well test packages, which significantly reduces the amount of equipment or disruption on day-to-day process operations.

This new approach requires approximately 90 minutes for installation and commissioning, which allows the possibility to perform multirate testing of the wells in one day. Therefore, the sonar clamp-on methodology offers the opportunity to increase the well test frequency at a field-wide level, allowing better field/production management.

The efficiency can be realized not only on land-based operations but also offers savings for marine, swamp, or jungle well test operations where the logistics of moving heavy equipment around the field or to an offshore facility are significant.

Case study

An operator working on the redevelopment of a mature field onshore in the Middle East was struggling with completing well tests using conventional trailer-mounted test separators and multiphase meters. It needed to sweep all the producing wells in the field to establish a baseline on field production on an individual basis and establish a program of work, prioritizing the wells that required intervention or workover to improve field production.

Expro Meters successfully tested 100 wells in 108 days, with eight nonproductive days due to national holidays or periods of production curtailment when the field was shut in. This activity was successfully completed with one crew and one set of sonar meters.

A key aspect of realizing this efficiency is in making the well site operations simple and repeatable. While individual flow rates are available at the well site during the test, the final report is created offsite in a data processing center, which is staffed with data analysts and petroleum engineers who replay and validate the raw data gathered in the field. They then create a final report using pre-agreed customer inputs and datasets gathered onsite.

The field engineers who collect the data are removed from the reporting chain and are free to continue to the next well and harvest new data for processing and reporting. This reporting happens offsite, and depending on the given time zone, the final report is delivered the next working day after the well test.

Expro Meters has developed a collaborative environment software tool – Well Test Studio – to manage the task of processing raw data from multiple data sources into a final and published well test report.

This efficiency allows subsurface teams to update reservoir models and identify wells that require remedial treatment or intervention in a regular and timely manner before production levels decline significantly. The ability to predict not only production figures but also utilization of workover and intervention equipment improves overall efficiency. Additionally, rapid mobilization of equipment and personnel is made possible compared to conventional mobile separator-based testing, where more detailed planning is required, deferring the opportunity to mobilize quickly.

The portability of the sonar meters and ability to clamp and test on the existing piping significantly reduces this planning overhead while eliminating the risk associated with well control during conventional mobile testing-based operations.

Wells are tested at the actual production conditions using the existing infrastructure, chokes, valves, and flow-lines rather than at a pseudo set of test conditions and temporary flow control equipment that doesn’t reflect production conditions. With no change in process conditions, there is no additional or nonproductive time required before stable conditions can be reached to start measurement. There also are no additional requirements for disposal of hydrocarbons or produced fluids at the well site. Because all process fluids are produced through to production, there is no impact or disruption to the production separators or permanent process plant.

Typically, to gain an understanding and confidence in the product and service, the customer will run a series of tests against the traditional well test separator, where the multiphase sonar measurement can be compared to separated single phase measurements. This SONARtest well testing production service has been successfully adopted by both international oil companies and national oil companies in Asia, the Middle East, and Europe.