Case History: Field Development Design Using A Risk-Based Integrated Production Model

Abstract

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract A risk-based integrated production model (RIPM) was used to guide development of an offshore volatile-oil field and a retrograde-condensate-gas field. Strategic decisions regarding facility alternatives and well completion design were analyzed in light of uncertainties in reservoir size and performance by use of a systems approach. Key parameters and business drivers were identified to focus the technical work on important development decisions. The RIPM enabled making decisions and evaluating a large number of options under a "fast-track" mandate in which relatively little data existed. The RIPM analysis was facilitated with predictions from technical tools for reservoir performance and completion design. Field results to date have validated this decision-making approach. Introduction This paper presents a case history in which the RIPM approach1,2 provided the ability to make key early decisions with relatively little data while evaluating a large number of options in light of reservoir uncertainties. The process continued through the entire project timeline from strategic front-end infrastructure design, development execution, and initial operation of a hydrocarbon asset. The asset is a recently discovered, relatively small offshore volatile-oil and retrograde-condensate-gas field. The small reservoir size dictated that project economic success was crucially linked to the proper integration and optimization of each subsystem (reservoir, wells, and facility) component. With a traditional approach to development planning, the reservoir engineer would commonly make estimations of the reserves in place and formation parameters (e.g., pressure and permeability), then hand them off to the completions engineer to size production tubing and determine flow rates. Then, the facilities engineers would be given the assumed production profiles to design the facilities. This approach severely limits any ability to optimize the project interactively between the engineering disciplines or to investigate the effect of changes in any one part of the system with corresponding effects elsewhere in the system (e.g., reserve size, tubing size, completion technique, or various facility options). The RIPM process combines the benefits of an integrated systems analysis and quantitative risk analysis to guide strategic decision-making in the design, implementation, and operation phases of reservoir management. Details of the concepts and benefits of the RIPM process and tools1 and high-level application examples2 have been presented. For this case, the integrated production model (IPM) tool was key for quickly evaluating the effect of different subsystem options on the value delivered by the overall system. A risk-based IPM (i.e., RIPM) tool was needed to quantify the effects of a number of uncertainties on the project's overall value to facilitate strategic decision-making. The RIPM methodology was used throughout the asset's development. For the purposes of this paper, discussions will be directed at two phases of the project - the front-end strategic design/decision phase and the development operation phase - in which initial data was acquired and analyzed to validate the approach and decisions made. Front-End Design and Strategic Decisions Initially, the field was identified as amplitude events from 3D seismic analysis. Two primary structures exist on two offshore blocks separated by three miles. Reservoir depths range from 10,000 to 13,000 ft. Initial reservoir pressure was roughly 10,200 psi, and formation temperature was 260°F. The seismic amplitude maps indicate three likely reservoir compartments on the western structure and one on the eastern structure. Considerable uncertainty existed in delineating actual reservoir boundaries and thickness from seismic, as well as extent of reservoir connectivity within an amplitude event. As a result of the desire to fast-track project development, many important, consequential decisions had to be made with very limited data. At the point that facility decisions were made, two successful exploration wells were drilled and tested on two stratigraphic accumulations. The fluid system was characterized as a volatile oil on the eastern structure and a retrograde condensate on the western structure based on data from the exploration wells. Excellent productivity resulted from permeability on the order of 10 to 100 md. Good-quality seismic data in the area and nearby discoveries led to very high confidence in finding hydrocarbons. The more difficult question concerned whether reserves were sufficient to justify setting the facilities needed for development.