Application of Nonlinear Adaptive Modeling for Rigorous Representation of Production Facilities in Reservoir Simulation

Abstract

SPE Members Abstract: A nonlinear adaptive modeling technique has been used to encode a rigorous deterministic model for optimal allocation-of lift gas to wells. This model was incorporated into the Kuparuk Full Field Reservoir Simulator, for the purpose of evaluating the effect of additional lift gas compression capacity on production from the Kuparuk River Field. Simulation results indicate the nonlinear adaptive model technique yields more accurate lift gas allocations than the prior allocation paradigm which was based on nonlinear regression of field data. INTRODUCTION: The Kuparuk River Reservoir contains approximately five billion barrels of original oil in place. The reservoir is located on the Alaskan North Slope, approximately forty miles west of the Prudhoe Bay field. The field produces from two physically independent sands of the Kuparuk river Formation, a lower Cretaceous, shallow marine sandstone. The productive sands are informally named the A and C Sand members. the C Sand overlies the A Sand and is highly permeable, having an average permeability thickness of 5000 md-ft. The A Sand is considerably less productive than the C Sand, having an average permeability thickness of 1000 md-ft. the two sands do not communicate within the reservoir; however, they are hydraulically coupled through the wellbores. Many development issues have faced the Kuparuk River Field Unit Owners since startup in 1981. The field has experienced a variety of development processes including primary production, waterflood, a water alternating immiscible gas injection (immiscible WAG) project, and a pilot scale miscible WAG project. With these various recovery mechanisms, the field has grown in complexity. The Kuparuk River Field has reached a point in field development where decisions concerning future strategies are usually complex and interrelated. Various development strategies are simultaneously being investigated: infill-drilling, further peripheral development, and enhanced oil recovery projects. Some of these strategies require facility additions with long equipment lead times, which necessitates early identification of field development plans and reliable rate projections. Factoring these possibilities and uncertainties into the evaluation of development options at Kuparuk has required the development of enhanced simulation tools. To address the complex nature of these decisions, a Kuparuk specific facilities model and well management logic for a gas capacity constrained system were added to a full field reservoir simulator. A modelling scheme specific to the Kuparuk River Field was needed because of the unique facility configuration. Equipment limits are used with a well ranking system to shut in marginal production when facility limits are exceeded. To properly simulate field operations in a compression capacity constrained environment, additional features were developed for the well management package. A wellbore hydraulics routine that enables flowing bottom hole pressures to change as a function of gas lift rates, fluid production characteristics, and reservoir pressure was implemented. The impact of lift gas on production from a gas lifted will is nonlinear in nature. Production rate passes through a maximum with increasing lift gas volume at the point where increased frictional losses due to higher volumetric flow outweigh the benefits of lower static head pressure due to increased gas holdup in the tubing string (Figure 3). The objective of a lift gas allocation mechanism is to optimally distribute available lift gas to the various wells based on each individual well's production versus lift gas response curve, while taking into consideration facility constraints such as gas compression capacity. The optimal point on each well's lift gas response curve is a function of variables such as: reservoir pressure, the well's productivity index, water cut, wellhead pressure, tubing geometry, and gas compression capacity. The use of a gas optimization strategy is crucial in the efficient operation of a field that is limited by gas compression capacity. The Kuparuk River Field operates on an Incremental Gas Oil Ratio (IGOR) concept that maximizes production from a group of wells. This concept yields the optimum Gas Liquid Ratio (GLR) for each well in order to maximize field production while taking into account gas compression constraints. The IGOR concept is employed in the Kuparuk Full Field Reservoir Simulation Model (KFFM) with gas handling logic that mimics the field operating strategy. Briefly, the logic dictates that free-flowing wells with the highest producing formation Gas Oil Ratio (GOR) are shut in if facility limits are exceeded. P. 425^