In this sixth article of the Oil and Gas Facilities Savvy Separator series, underperforming gas scrubbers are discussed, and a case study is used to illustrate how an inadequate sizing methodology hinders scrubber performance.

Many operators with large stakes in unconventional shale oil plays have published targets to drastically reduce emissions with some considering carbon emission tax for economic evaluations of future projects. This creates the need for finding electrically powered alternatives to replace equipment that currently consumes fuel gas, such as fired heaters. Production facility designs for unconventional shale must be simple, robust and require relatively low CAPEX and OPEX to be economically viable. This poses a challenge for electrically powered alternatives because fuel gas is freely available at production systems, whilst electricity comes at a cost. To address this challenge, novel fully electric production system designs have been developed based on heat pump technology. The practical and economic feasibility for these designs are evaluated and demonstrated so that these can be considered as realistic solutions for future projects. The major reasons why crude oil must be heated at upstream production facilities are to break potential emulsions of oil and water and to stabilize the oil. Stabilizing the oil means that volatile components are removed from the crude, so that it can be transported and stored in tanks without emission and safety concerns. The novel production systems achieve this by pairing a single stage electrically driven heat pump with heat integration. The novel production system designs are analyzed using steady state and dynamic simulations employing industry accepted process simulation software. The steady state simulations generate metrics such as energy consumption, estimated emissions and hydrocarbon recovery which are used in conjunction with emission factors and other economic factors to compare the performance to standard production facilities. The dynamic simulations are used to demonstrate the feasibility for starting-up and controlling the facility for this novel technology application. The simulation results demonstrate that the heat pump based designs consume around 70% less electrical power compared to direct electrical heating. Further benefits are that the temperatures can be controlled at various stages in the process to substantially increase the facility's oil recovery. This also results in leaner gas, which is particularly attractive for facilities that include gas compression and dehydration. The increased oil recovery results in substantially higher revenue which leads to an economically more attractive design compared to a traditional facility, even without taking carbon emission tax into consideration. These comparisons are provided for different types of facilities during different production scenarios during varying weather conditions.

Operators in the unconventional shale oil space are becoming increasingly focused on methods to reduce emissions, mitigate issues due to NGL production, increase sales oil production, and increase safety. Moreover, for facilities to operate unmanned facility designs are required to be simple and robust. Each facility configuration optimizes for a different utility: some allow more flexibility for the economic investment, while others offer familiarity of operation. The option that adds the most flexibility per dollar invested focuses on low-pressure separation with simultaneous heat introduction with minimum necessary storage tanks. Three different facilities are compared utilizing hydrocarbon recovery, NGL production, gas production, compression power, and Reid Vapor Pressure as key metrics. The three layouts include: a heater treater, a vapor recovery tower, and a novel elevated heated separation design that combines the utility of a heater treater and vapor recovery tower. The novel low-pressure stabilization system allows for stabilized oil to be pumped either to storage tanks or directly to the custody transfer point. Emissions stemming from tank vapor and tank vapor management systems are avoided as the oil is stabilized before entering the storage tanks or being transported directly to custody transfer. The novel system can be scaled for higher production rates seen at central processing facilities where traditional equipment such as heater treaters would require operating several parallel production trains. The novel design avoids known operational safety and maintenance issues regarding direct fired heaters and tanks; thus, improving safety and operational cost. Existing facilities designs include equipment such as direct fired heater treaters, inline heat exchangers, vapor recovery towers and tanks. The results from all process simulations and operational data is summarized in an overview comparing the performance of the various facility designs.

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.