Economic Comparisons of Multilateral and Horizontal Wells in Water-Drive Reservoirs
- Nestor Rivera (Texas A&M University) | Jerry L. Jensen (Texas A&M University) | John P. Spivey (Schlumberger) | Mike Jardon (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Production and Operations Symposium, 23-26 March, Oklahoma City, Oklahoma
- Publication Date
- Document Type
- Conference Paper
- 2003. Society of Petroleum Engineers
- 7.4 Energy Economics
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Reservoir studies can help determine what parameters or configurations make multilateral wells (MLs) more economical than single-branch horizontal wells (HWs). We simulated 5 years of production from a water-drive reservoir and evaluated the results, using a range of economic criteria. The reservoir simulator uses a multisegment wellbore model to enable better handling of complex well trajectories and detailed description of pressure losses in the horizontal, building angle, and vertical sections of the well. The study compared Levels 3 and 6 ML junction configurations to HWs. We modeled natural flow applications considering normal gravity oil (20 to 29° API) in a homogeneous reservoir with permeability ranging from 10 to 1,250 md. Detailed well-cost estimates for each configuration included taxes, royalties, and water-handling costs. We found that accounting for friction and hydrostatic pressure losses through all the sections of the well created more realistic models. For the cases we studied, a two-branch ML produces 13% more oil than a HW in high-permeability reservoirs and 80% more oil in low-permeability formations with low viscosity oil (1 cp). In addition, the ML well produces 10 to 15% less water than the HW. The extra production of the ML over the HW increases to more than 50% in low-permeability and higher than 90% in low-permeability. The ML has a higher net present value - 20% or greater - than the HW for all permeabilities. Using a profit-to-investment ratio, the ML is more attractive than the HW in the lower permeability cases. Results using other economic metrics gave similar results.
Multilateral technology continues expanding with some fields being further developed exclusively with multilateral wells. The Troll Olje field in the North Sea is an example where the operator found multilateral technology more appropriate than conventional horizontal techniques and decided to drain additional reserves with 20 multilateral wells.1 In addition to the incremental oil production and multiple-target options, multilateral wells offer the added cost-benefit of slot conservation in offshore applications. One operator in the Arabian Gulf reports 35% savings per well, despite the 44% extra cost of the multilateral well when compared to a single horizontal.2
Published reservoir studies have covered important aspects of ML technology such as performance prediction,3 pressure drops through horizontal and vertical sections,4 comparisons with horizontal wells,5 and effects of water-drive mechanisms.6 The objective of this study is to provide a comprehensive economic evaluation of multilateral and horizontal wells for water drive-reservoirs, which includes friction and hydrostatic pressure losses through the horizontal and vertical sections of the well. We used a range of economic indicators to determine the cases where each type of completion is advantageous. We considered natural flow situations, in which the production is typically controlled by an optimal tubing head or separator pressure. This is generally the case for the early life of many wells in normal-to abnormal-pressure reservoirs. Our production and economic scenarios considered five years of operation.
Reservoir Model and Well Configurations
The numerical reservoir simulator used for this study is coupled with a multisegment well option to account for hydrostatic and pressure losses in the horizontal and built sections of the well (Fig. 1). This model was built from the reservoir up to the ML junction position. The modeling from the junction to the surface was performed in the regular format of tubing tables generated by standard correlations and coupled with the simulator as look-up tables. This process is more accurate and less computer intensive than building multisegments from reservoir to surface. We set the THP to a constant value of 120 psia.
Two currently common multilateral configurations are Levels 3 and 6. The Level 3 junction provides mechanical integrity but not hydraulic isolation whereas the Level 6 provides both mechanical integrity and hydraulic isolation. However, this advantage in Level 6 systems generates the loss of a casing size. The 9 5/8-in. Level 6 junction limits the liner size to 4 1/2- or 5-in. diameters. A single horizontal well would have a 81/2-in. production hole with 7-in. liner below the 9 5/8-in. casing shoe.
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