Well testing equipment for unconventional onshore applications generally comprises a sand removal unit (Desander), a dual choke manifold, a test separator with metering, various types of tanks for temporary storage and in some cases a flare. This equipment is typically interconnected through high pressure temporary flowline generally referred to as flow-iron, which is made up from modular components that are joined by quick connect hammer unions. Installation of the equipment and the well testing itself is labor intensive. Personnel is on location 24 hours a day, working on or near high pressure piping and climbing onto open top tanks during well testing. This results in significant labor costs and exposes personnel to numerous health and safety risks. This paper starts with introducing a modularized Automated Well Testing system (AWT) which has been developed to rig-in and out faster, minimize personnel exposure to health and safety risks, minimize transport cost, reduce footprint and eliminate greenhouse gas emissions to operate the unit. A first unit has been built and applied at various shale plays across North America during the past two years. Learnings and conclusions from these applications are summarized and used to evaluate the design.

Facility optimization and control using continuous measurement of oil vapor pressure allows the oil and gas producer to reduce facility flaring and emissions while increasing oil production. By preventing over processing of oil, through vapor pressure process control of the facilty oil heaters, the producer sells more stabilized oil in the liquid phase instead of compressing or flaring in the vapor phase. The novel vapor pressure monitoring and emission control system is installed on new or existing facilities and utilizes existing pressure and temperature instrumentation with added supplemental wireless instrumentation as necessary. The pressure and temperature process data arer outed to a proprietary process simulation algorithm which continuously calculates the oil vapor pressure and compares the result to the operator's allowable facility output oil vapor pressure. The system additionally provides the required facility output oil temperature and sends a process control signal to the facility conditioning equipment, such as heater treaters or oil coolers, and maintains a consistent, full-time traceable facility output oil vapor pressure. The benefits of this oil vapor pressure control system include higher profitability and return on investment from higher oil sales volume, substantial reduction in greenhouse gas emissions, substantial reduction in tank venting and facility flaring, elimination of capital cost for vapor recovery towers, reduction in capital cost and operating cost for vapor recovery compression, reduction in fuel gas cost from heater treater burner optimization and control, and vapor pressure alarms provide immediate notification of operational upsets. A six-month North Dakota Bakken case study is presented showing field data and performance across summer and winter operation at a 5,000 - 6,000 barrel of oil per day facility. The oil vapor pressure monitoring and control system provided a 55% reduction in low pressure flaring, increased the oil sales volume approximately 1%, and avoided 2,240 metric tons of green house gas emissions over a 6-month period.