Summary
This paper describes a methodology for incorporating uncertainties in the optimization of well count for the deepwater Agbami field development. The lack of substantial reservoir-description data is common in many deepwater discoveries. Therefore, the development plan must be optimized and proven to berobust for a wide range of uncertainties. In the Agbami project, the design of experiments, or experimental design (ED) technique, was incorporated to optimize the well count across a wide range of subsurface uncertainties.
The lack of substantial reservoir-description data is common for many deepwater discoveries. In the Agbami project, the uncertainty in oil in place was significant (greater than a factor of 2). This uncertainty was captured in a range of earth (geologic) models. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studied concurrently. Multiple well-count development plans (high, mid, and low) were developed and used as a variable in ED. The ED technique allowed multiple well counts to be tested quickly against multiple geologic models. With the net present value (NPV) calculated for each case, not only was the well count for the overall highest NPV determined, but discrete testing of each geologic model determined the optimum well count for each model. The process allowed for testing the robustness of any well count vs. any uncertainty (or set of uncertainties).
A method was demonstrated quantifying the difference between perfect and imperfect knowledge of the reservoir description (geologic model) as it pertains to well locations.
Introduction
The Agbami structure is a northwest/southeast-trending four-way closure anticline and is located on the Niger delta front approximately 65 miles offshore Nigeria in the Gulf of Guinea (see the map in Fig. 1). The structure spans an area of 45,000 acres at spill point and is located in 4,800 ft of water. The Agbami No. 1 discovery well was drilled in late 1998. The appraisal program was completed in 2001 and included five wells and one sidetrack drilled on the structure, with each encountering oil pay. These five wells and a sidetrack penetrated an average of approximately 350 ft of oil.
In this phase (Phase 3) of the development process, the key objectives are to construct a field-development plan and to obtain sanctioning. With drilling depths of up to 10,000 ft below mudline in 4,800 ft of water, well costs at Agbami will be at the high end of typical deepwater costs. Therefore, an important optimization parameter in the field development is the total well count.
Agbami is typical of many deepwater developments in that the seismic is less than perfect and the appraisal well data are sparse relative to the area coverage. Therefore, subsurface uncertainty is high. In fact, the 5% probable oil in place is more than two times the oil in place at the 95% probability. As a result, the development process is challenged with determining the optimum well count for the field development across the wide range of subsurface uncertainty.
Several key development decisions were determined in the previous phase(Phase 2) of the development process. These decisions were taken as givens in this study and are listed as follows:• The recommended pressure-maintenance scheme and gas-disposition strategy for the 17 million-year (MY) units is a combination of crestal gas injection with peripheral water injection.• The recommended pressure-maintenance scheme and gas-disposition strategy for the 14MY/16MY units is crestal gas injection only.• The facility design capacity recommendations are:- 250,000 stock-tank bbl per day (STB/D) oil.- 450,000 thousand cubic ft per day (Mcf/D) gas production.- 250,000 STB/D water production.- 450,000 STB/D liquid production.- 450,000 STB/D water injection.
OPTIMIZING MARCELLUS FORMATION FIELD DEVELOPMENT, WELL PERFORMANCE, AND OPERATIONS BY INTEGRATING GEOLOGIC AND ENGINEERING DATA INTO A VOLUMETRIC GEOLOGIC MODEL
