Three-Phase Well-Level Production Allocation at Prudhoe Bay

Abstract

Summary Three-phase production-allocation programs have continuously evolved in the Prudhoe Bay Eastern Operating Area (PBEOA) over the past 19 years. These programs are necessary because the actual production rate of a well can be measured only when a well is being tested. Since each well is tested for about 6 hours per week, some method of estimating well production rates in real time while the well is not being tested is required. These estimates are used to optimize well and field production as surface processing and product shipping constraints vary. These estimates are also used to estimate field production rates in real time, track well performance, and allocate production volumes to wells for accounting and reservoir management purposes. Rate tables for most naturally flowing wells and all gas lifted wells are based upon the Fetkovich inflow performance model and tubing performance relationships (TPR's) developed from various tubing hydraulics models. Specialty rate table programs allow engineers to allocate production to wells which always produce at the same choke setting, wells which are in the process of gassing out, and to automatically allocate wells which maintain consistent performance. A recent upgrade of the allocation system, utilizing current generation computer hardware, communications hardware, and software has resulted in a 60% reduction in engineering time required for production allocation. The allocation process discussed here can be applied to many other fields to improve the link between field well test data and the optimization of field production rate, estimation of well and field production rates in real time, well performance tracking and allocation of field production to wells for reservoir management and accounting purposes. Introduction The oil rate at the Prudhoe Bay Field is limited by the available gas handling capacity. The main objective of production rate optimization at the PBEOA is to utilize the gas compression facilities as efficiently as possible to maximize oil, natural gas liquids (NGL), and miscible injectant (MI) production rates. Well production rates are changed almost continuously to optimize these field production rates. Reliable estimates of well performance are essential to this optimization effort. Since it is not possible to obtain real-time measurements of three-phase production from each well, estimates of well performance are generated by Anchorage-based Drill Site Surveillance Engineers from well test data and a personal knowledge of the history of each well. These estimates of well performance are then stored in look-up tables known as "rate tables."

Effect of systematic and random flow measurement errors on history matching: a case study on oil and wet gas reservoirs

“…There is a dearth of publications on the application of allocation data in reservoir analysis, reservoir management and history matching. Among the latter publications is the work of Bergren et al (1997). They reported their successful experience in employing an allocation system including computers, communications hardware, and software for both hydrocarbon accounting and reservoir management for Prudhoe Bay oil field in Alaska.…”

Asset-Wide Reconciled Production Monitoring—A Key Enabler to Successful Real-Time Field Management

“…[23]), metered flows throughout an entire oil and gas production network are now often available in real time in the office domain and are archived in databases. In some cases, even individual well production is either measured or estimated in real time (references [10], [11], [12]). The availability of real time data allows the concepts of conventional daily or monthly network flow surveillance and reconciliation to be extended to real time operations.…”