A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.

In a dynamic calculation, there are two effects not considered in steady flow: fluid inertia and fluid accumulation. In steady-state mass conservation, flow of fluid into a volume was matched by an equivalent flow out of the volume. In the dynamic calculation, there may not be equal inflow and outflow, but fluid may accumulate within the volume. For fluid accumulation to occur, either the fluid must compress, or the wellbore must expand. When considering the momentum equation, the fluid at rest must be accelerated to its final flow rate.

As with most technology, proper candidate selection is key to success. The economics are often determined by the number of and locations of the wells and by the overall geographical development plan. It is important to recognize that downhole processing is not a substitute for prudent profile control of wells through workovers, gel polymer treatments, cement squeezes, and so on. The following discussion applies to both gas/liquid and water/oil processing, followed by sections that discuss screening criteria specific to each. From an equipment standpoint, gas/liquid separation is much easier than oil/water separation. This generally means that it is a more robust application. All separation and pump equipment has an expected lifetime that is typically much shorter than the lifetime of the well. The cost of replacing or repairing the equipment must be considered as well as the initial capital cost.

Based on the results of many laboratories' research and various field experiences and observations, the following general guidelines are recommended.

The acquisition of bottomhole pressure and temperature data can be planned and executed in a cost-effective manner with a minimum disruption to normal operating routines. In many cases, early on-site interpretation is useful in guiding decisions about continuing the acquisition program. Measurements can be transmitted to the surface, usually via an electric cable, or recorded in downhole memory powered by batteries. SRO has the obvious advantage of providing data in real time. Real-time readouts are especially beneficial for transient measurements that require time for the pressure to stabilize and radial flow to develop.

While most types of logs are used to characterize the wellbore, formation, and fluids prior to well completion, a number of logging tools are available to provide information during production operations and beyond. The temperature-logging tool includes a cage, which is open to the wellbore fluid, at the tool's bottom end. Inside the cage is a thermistor that senses the surrounding fluid temperature. The preferred sensor is a platinum element because the electrical resistance of the sensor varies linearly with temperature over a wide range and is stable over time. The circuitry of the tool is designed so that the voltage across the sensor is proportional to the sensor's electrical resistance.

Measurements of mass flow and the constituents of the mass produced are integral in the production of geothermal fluids. From regulatory and royalty payment issues to monitoring the condition of the resource and abatement of corrosive constituents in the geothermal fluid, physical and chemical measurements are a necessity for geothermal production and utilization. Depending on the phase being produced, the operator has a choice of many instruments for measuring flow. Conventional methods are typically used to measure flow for single-phase systems. The choice of flow element and meter initially depends on the mass and/or volumetric flow rate, turn-down ratio (range of flow to be measured), the pressure, temperature, and extent of flow surging.

The three primary functions of a drilling fluid depend on the flow of drilling fluids and the pressures associated with that flow. These functions includes: The transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability. If the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore.

In recent years, Aker BP has explored and developed a number of digital improvements to optimize production. The underlying business drivers are meant to improve efficiency, increase production and reserves, decrease costs, and reduce the carbon footprint from operations. The example described in this article has innovative elements of digitalization and automation of workflows which provide a new approach for better handling of slugging in subsea developments with long tiebacks. The new solution has a potential for optimizing production and limiting the amount of flaring. The Aker BP-operated Vilje field in the Norwegian Continental Shelf has occasionally experienced production-flow instabilities in the production pipelines and risers due to slugging.

An isotope tracer in a bead with the same density of the flowing fluid that is used to track fluid flow rates and therefore fluid entry and exit points along the wellbore.