Consider the flow path of oil & gas production from the well head. The first stop is typically the production separator where the oil, gas, condensation, water, brine and other fluids and sediment get separated. Traditionally, for multi-well sites, there is a test separator so that each well’s production composition can be assessed.In this arrangement the wells are connect to both a test and production manifold, with valves to isolate the flows from each well into the test separator when it’s being tested. Valves, often manually actuated, are required to open the flow to the test or production manifold, and from backflow to the well.
In and Oil & Gas Engineering article, Wellsite valve manifolds simplified, Emerson’s Joseph Zawacki describes how multiport flow selector technology reduces the complexity of the traditional approach and is:
…safer, less expensive, lighter weight, and more compact than conventional units.
He opens describing the importance of the flow testing process for oil & gas producers:
Oil, water, brine, condensate, gas, and other fluids must be monitored and measured regularly. In addition to separating the well stream into its constituent components, the well test separator records the volume of each component over time, allowing the flow rates to be calculated, most often as barrels per day (b/d) for liquid products or million standard cubic feet per day (MMSCFD) for gas products.
These tests provide the production staff and reservoir engineers with information on current production levels and changes in subsurface production zone. The tests are performed either manually by opening and closing the valves for the appropriate well, or connecting automated valve actuators to a controller device which schedules the tests per the control logic it contains.
Joe compares the traditional approach with a Bettis multiport flow selector (MPFS) approach for a 7-well, 2 manifold offshore production platform or onshore well pad. I visually compared this arrangement in an earlier post, Real-Time Well Testing on Unmanned Offshore Oil and Gas Platforms. The conventional approach takes 21 valves versus 7 valves into the MPFS.
Joe notes to operational differences of the two approaches:
While tests can take less time, the operators most likely are on a rotational visit cycle for the field. The change-over takes too long for them to sit and wait, so test time usually is dependent on the field visitation rotation.
Typically, operators reset a flowmeter on the downstream side of the separator (on the oil outlet). They either assume a certain amount of flow—perhaps a time-based calculation based on previous wells’ flow rates—or they come back after the separator has stabilized with the new well, reset the flow meter, and officially start the test.
With the MPFS approach:
…tests are done about once per day, typically on a rotating schedule from well to well. However, an operator can initiate a test based on anomalous test data, in preparation for work on a well, immediately after such work, during early well-life production when monitoring water cut-back, and artificial-lift management.
Read the article for more about the MPFS architecture, reduced maintenance requirements, automated mode of operation, sour oil & gas applications, and available communications protocols with RTUs, SCADA systems, PLCs and distributed control systems.