Operating oil and gas applications in North Dakota can be difficult because of its unpredictable weather, limited and costly labor force and remote locations. These were the main reasons engineers, technicians and operators at Occidental Petroleum were happy when they recently automated more than 200 wells, tanks and other equipment near Dickinson, North Dakota, with wireless transmitters and other components.
These 200 well pads and their oil and water tanks are located in the harsh and often unforgiving terrain of the geological Bakken region. They're widely dispersed, subjected to snow, ice and ambient temperatures that can shift by 80 °F in a day, and typically require large amounts of hardware and costly labor to install and maintain them. Each well has six 400-bbl tanks, including four for storing oil and two for storing water. The wells produce light crude oil and slightly salty water.
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We needed to automate our existing and new oil production facilities located near Dickinson for both monitoring and control, so these facilities could be operated remotely from a centralized control room. This project began in 2012 and included the wells, oil and water tanks, heater-treating and well-monitoring systems, and a central tank battery with five 10-Kbbl, fixed-roof tanks, two LACT units, two produced water injection pumps, three crude oil shipping/sales pumps, three flares, a vapor recovery unit (VRU) and all associated electrical infrastructure.
Because of our aggressive project schedule, the bulk of our well infrastructure, wireless upgrades and other construction had to be executed during the winter. Heavy snow and/or rain at any time during the year in North Dakota results in very muddy and hazardous driving conditions, making it very difficult to reach facilities, and the state's DOT frequently closes roads during inclement weather. We also had an aggressive central tank battery schedule, and our rapid deployment of wells and infrastructure also required us to build more than 120 of the well pads in less than 18 months. Unfortunately, because there's so much oil and gas-related development in this area, limited resources are locally available, especially skilled labor, so resources are either brought in from out of state or hired from the existing pool at a premium.
To meet these challenges, we needed a wireless system that could be used for monitoring and control, and didn't need to fulfill SIL-rated functions, but still had to run reliability in sub-zero and icy conditions. Some applications needed 4-secound update rates, while others could run with 60-second updates. These wireless components also needed to have self-diagnostics, report on instrument health, and had to be self-healing. The main wireless-enabled components implemented on the wells include Emerson Process Management's 3051S pressure transmitters, 6480 temperature transmitters, 3308 level transmitters, 2160 level switches.
The wireless components were installed by May 2012 and immediately reduced our installation complexity and commissioning resources needed. We eliminated the bulk of the traditional loop infrastructure, such as conduit, cable, terminal blocks and fuses and greatly reduced the amount of necessary construction resources. We eliminated point-to-point checkout associated with traditional wired instrument loops and reduced personnel multitasking to bring systems online from installation to commissioning. We also increased data availability via WirelessHART. Our wireless mesh network provides reliability via its self-diagnosis and self-healing network, and it's also easy to expand and add devices to the network.
The new wireless network on Occidental's 200 wells in North Dakota has greatly improved overall reliability. Implementing wireless eliminated more than 96% of call-outs due to communication or equipment failure issues. It also eliminated electrostatic discharge issues while unloading vessels and inherently improved reliability by eliminating loose connections, cracked insulation, broken wiring and crushed conduit. Also, communicating via WirelessHART provided data on device and overall system health.
Finally, the cost benefits of this wireless network include a 35% reduction in overall deployment labor costs and a 15% reduction in overall material costs. Our original estimate for automating a well pad with a traditional wired solution was seven days, but actual deployment time with wireless is now two days, and it can be even faster for multiple wells located at the same site.
