Abstract

With modern drilling techniques it is now possible to drill wells with multiple branches emanating from the same vertical or even horizontal trunk. Several heavy crude reservoirs are very thick and had they contained light crudes, their vertical permeability could make them attractive for single horizontal wells. Unfortunately, the much higher viscosity of the reservoir fluid results in highly unfavorable mobility. Thus, drilling several horizontal branches at different levels of the reservoir would effectively create thinner drainage areas and this, in itself, would be attractive because in thin reservoirs the vertical mobility is far more forgiving. However, a clear benefit in heavy crudes is derived from thermal recovery and a scheme is suggested here, where either steam is injected at the top of the reservoir or hot water is injected at the bottom through a dedicated horizontal well injector. (From an operational point of view it is desirable to use the same vertical trunk for both injection, e.g., through the tubing and production through the annulus, or vice versa.) The optimization strategy is to estimate the desirable number and spacing of the producing laterals. The vertical spacing is not even, but instead, it depends on the crude oil viscosity, that, in turn, is affected by the heating process. We present in this work a methodology of multilevel well optimization and several case studies for different numbers of laterals and their vertical spacings.

Introduction

Frequently, highly viscous petroleum (“heavy crude”) is found in relatively shallow reservoirs that are often characterized by thick, loosely-consolidated or unconsolidated rocks. Horizontal permeability is frequently as high as 10 darcies or more, but the crude oil viscosity is also high, frequently exceeding 10,000 cp. The resultant mobility, k/μ = 1 md/cp, is suffuciently low that conventional production from vertical wells is at best marginally economic. By way of comparison, deeper reservoirs with lighter oil frequently have mobilities exceeding 100 md/cp or more.

Often the optimal well trajectory in a thick reservoir is a vertical well because productivity is a function of mobility-thickness. Horizontal wells offer significant productivity improvement in thin reservoirs, but in thick reservoirs the productivity boost from a horizontal well requires a favorable vertical permeability (Joshi et al.[1] and Economides et al.[2]). However, horizontal wells may be a strategy to mitigate gas or water coning in thick reservoirs overlain by a gas cap or underlain by water.

Economic success in heavy oil production has been found both by cold production[3,4,5,6,7] and by steam injection[8,9,10,11] with both vertical and horizontal well strategies.

The emergence of complex well architecture provides a potentially highly attractive configuration where a multilevel/multibranched scheme can be constructed. This paper focuses on the configurations of stacked parallel laterals shown in Fig. [1]. Case studies placing the steam injector above the producer (as in SAGD) or below (inverted SAGD) are considered. Examination of the vertical temperature profiles for various lateral configurations shows that excess temperature can be “mined” to increase both the production rate and the ultimate recovery. A practice that is worth mention is the engineering of a completion that enables both production and injection in the same wellbore with anular flow of the produced oil in the casing and steam injected in the tubing (Single Well SAGD).[12]

The number and positioning of multilevel producers greatly depends on the fluid viscosity and the temperature gradient, which is influenced substantially by the reservoir thickness. Optimizing the multilevel configuration is the subject of this work.