Summary Successful installation and operation of supervisory control and data acquisition (SCADA) systems on two U.S. gulf coast platforms, prompted the installation of the first SCADA, or automation, system in Oklahoma in 1989. The initial installation consisted of four remote terminal units (RTU's) at four beam-pumped leases and a PC-based control system communicating by means of a 900-MHz data repeater. This first installation was a building block for additional wells tobe automated, and then additional systems, consisting of RTU's, a PC, and a data repeater, were installed. By the end of 1992 there were 98 RTU's operating on five separate systems (Fig. 1), and additional RTU's are being installed on a regular basis. The tangible and intangible savings generated by these automation systems have exceeded expectations in all cases. Downtime has been reduced by up to 83%, surface maintenance costs on beam- pumped wells have been reduced by an average of 40%, and the cost of well workovers for rod, tubing, and/or pump repairs has been reduced by 17% to 44%, depending on field conditions. These improvements have led to production increases of up to 30%. Additionally, spills have been significantly reduced and early detection of leaks, when they occur, has reduced the impact of these spills, enhancing the environmental compatibility of operations. This paper outlines the logical development of automation systems on properties in Oklahoma operated by Phillips Petroleum Co. Those factors critical to the success of the effort are (1) designing data-gathering and control capability in conjunction with the field operations staff to meet and not exceed their needs; (2) selection of a computer operating system and automation software package; (3) selection of computer, RTU, and end-device hardware; and (4) continuous involvement of the field operations staff in the installation, operation, and maintenance of the systems. Additionally, specific tangible and intangible results are discussed.