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One challenge in the upstream exploration and production industry is that the nature of the work is dynamic, as is the makeup of the workforce. This is especially true when trying to integrate an effective behavioral safety process (BSP). Although it is counter to change management philosophy, the theory was tested: does mandating the use of behavioral safety tools (i.e., observation, feedback, positive intervention, etc.) prior to a group's understanding of its value, then experiencing multiple positive events in the field, lead to identical results achieved through conventional methods? Behavior-based performance (BBP), the company's process, was re-implemented in mid-2004 for a Rock Springs, Wyoming test group, utilizing mandatory participation. Remaining company camps in the western U.S. were control groups that used conventional implementation methods. Following introductory training and explanation of mandatory activities, tracking/monitoring began. Analyses of field data and comparative results from 2003–2007 determined "mandatory" effectiveness and indicated all the test group's BBP metrics were significantly better and improved earlier than those of the control groups. The resulting conclusion was that requiring participation resulted in equal or better engagement than control groups utilizing voluntary techniques. All components influencing process engagement were not controlled; however, evaluating whether program maturity, culture, management support, etc., affects implementation was addressed through ongoing BBP sustainability audits. BSPs are strongly embraced by petroleum producers, to the extent that even their service contracts require BSP utilization and frequently stipulate metrics to be achieved. As a service contractor, the objective becomes how to effectively implement a BSP. Challenges include the often fluid employee base, remote assignments, and erratic hours worked by the typical petroleum workforce. Conversely, stable manufacturing workforces working steady schedules can receive continuous BSP training, reinforcement, and "real-time" coaching, ideally resulting in engagement and voluntary participation.

Abstract Tidelands Oil Production Company is conducting a Class III Near-Term Waterflood Project partially supported by the Department of Energy (DOE) titled "Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management." The project takes place across fault blocks IV & V of the Wilmington Field, Long Beach. CA. Using advanced reservoir characterization tools and reservoir management software, researchers identified bypassed oil. This oil was exploited by recompleting idle wells in danger of abandonment. Recompletion results were significantly better with a novel steam consolidation technique compared to a standard Wilmington recompletion technique. Introduction The objective of this DOE demonstration project is to increase waterflood reserves in fault blocks IV & V of the Wilmington Field and other slope and basin clastic reservoirs through improved methods of identifying sands containing oil bypassed by the waterflood and exploiting this oil by recompleting existing idle wells. Specific objectives include: identifying sands containing high remaining oil saturation using a multi-pole acoustic cased hole logging tool, determining geophysical parameters for interpretation of the acoustic data, demonstrating and gaining experience with a short radius lateral recompletion optimizing our standard and steam recompletion techniques, generating a three dimensional (3-d) geologic model, and transferring the technologies and methodologies developed to other operators of slope and basin clastic reservoirs. The Wilmington Field is located within a NW-SE trending faulted anticline beneath and immediately offshore of Long Beach, CA. Reservoir sands are Pliocene and Upper Miocene-age turbidites. Targeted zones were the Tar, Ranger, Upper Terminal, and Lower Terminal which range from 2500' to 4000' in depth (Fig. 1). Waterflood oil recovery in the Wilmington Field has been inefficient due to reservoir heterogeneities, poor vertical sweep efficiencies, high producing water cuts, poor water injection profiles, and unfavorable oil-water mobility ratios. Sands with bypassed oil are still present despite extensive waterflooding but locating these sands and quantifying the remaining oil reserves has been a formidable task. The project was divided into seven activities as follows: reservoir characterization. reservoir engineering deterministic 3-d geologic modeling, multi-pole acoustic logging, recompletions tech transfer, and project management. Each activity consisted of several main tasks. This paper will cover each activity except project management. Results and Data The original strategy for this project was to identity areas of bypassed oil through reservoir characterization and reservoir engineering, verify its location behind pipe with the multi-pole acoustic sonic log, and produce the oil from recompleted idle wells. As the project advanced it became evident we had to modify this strategy as project activities evolved and progressed at differing rates. Rather than a series of activities. researchers pursued the activities in parallel. Activity 1 Reservoir Characterization. Reservoir characterization in this project denotes not only defining gross geologic features such as structure, faults, and rock properties such as porosity and lithology, but also the distribution of remaining oil saturation in the reservoirs of interest. This requires complete integration of geologic and engineering data. The first step in integrating the data for reservoir characterization was developing basic geologic and engineering representations of the data. This included revising geologic structure maps, isopach maps, and cross sections. Structure maps experienced the most changes and reinterpretations mainly due to the availability of new well data. A key part of the characterization work involved developing and calibrating rock-log and fluid-log models from which to interpret the acoustic log data. Theoretical relationships, confirmed by laboratory and field data, suggest that hydrocarbon bearing rocks in situ can be differentiated from rocks containing brines using sonic velocity measurements. P. 255^