This paper demonstrates the requirement for incorporating completion and artificial lift considerations into multi-lateral well design, and describes a methodology for rigorously predicting the performance of these wells. In this low pressure, heavy oil reservoir, herringbone multi-laterals are favoured over dual and tri-lateral wells, due to the impact of positioning the artificial lift closer to the sandface. Economic ranking is required to compare performance of different well types, due to significant differences in well costs. The optimal development scenario for drainage of three infill locations, consists of a long herringbone multi-lateral plus a conventional horizontal well.


The reservoir, situated on the Eastern shores of Lake Maracaibo, has been producing 12 API crude since 1958. Current reservoir pressures around 830 psi. coupled with insitu viscosity of 170 cp and high water cuts in many areas, mean that new vertical wells produce under 100 stb/d, and are now uneconomic. Additionally, expanding population density in the area makes finding new drilling sites problematical. New technology is being investigated as a means of enhancing productivity.

A recent internal report identified 3 possible infill locations, without water production problems, and concluded that drilling horizontal wells would be economic. The proximity of the locations (figure 1) raised the possibility of draining all three from the same surface location, either by individual, or multi-lateral wells. This paper describes the methodology adopted for accurate simulation of the different multi-lateral configurations, and the use of simple economics to rank the well performances.

Reservoir Model

The reservoir comprises two main channel sand bodies, Unit 2 (upper) and Unit 1, both of which average around 35 feet thick in the zone of interest, and are separated by a 40 feet shale. The proposed drilling locations (figure 1) comprise one well in each sand in the A location, and a well in Unit 1 in the B location; these will be referred to as wells A(1), A(2) and B(2), respectively. The top of unit 2 lies at 3880 feet in the A location, and is some 100 feet lower at B.

Reservoir permeability averages 400 md in Unit 2 and 500 md in Unit 1, with 35% porosity and 30% water saturation in both sands; The Kv/Kh ratio has been estimated as 0.15 from core data. Well to well correlation of the channel is good, and steering the horizontal section in the reasonably competent sand is not expected to pose problems.

Numerical simulation models (figure 2) have been constructed, initially of the A area, and later with the B area added, to allow modeling of the multi-laterals. The model contains 18x23x11 cells in the X, Y and Z directions (4554 cells), and uses fine grids, with dimensions fulfilling Peaceman's criteria, to allow accurate modeling of the branch inflows. Existing vertical wells have been included, to properly model the influence of the offset producers.

Multi-lateral Performance Modeling

A review of the literature showed that a number of papers have been published in recent years, dealing with analytical modeling of multi-lateral wells, but that these mostly concentrated on the interference effects of multiple well branches in the same formation; the paper by Salas mentions that well trajectory impacts on artificial lift efficiency, but does not quantify the effect.

In view of the low reservoir pressures here, it was felt that a modeling technique that accounted for both the artificial lift positioning, and the interaction between the different well branches, would have to be used to get realistic results. P. 379

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