Abstract

Marcy recent projects have demonstrated that the injection of steam into horizontal wells can recover significant quantities of heavy oil at economic rates. A variety of reservoir/wellbore processes have been utilized, including dual well SAGD, single well SAGD, cyclic steam stimulation and steam drive, as well as many hybrids. Specific installations may also include the use of vertical wells, particularly as injectors.

The proper distribution of steam injection and the management of inflow of hot produced fluids into horizontal wellbores is essential to the successful operation of these projects. As typical wells are 500–1000 m in length, there is a significant surface area for heat exchange to occur when there is fluid flow in both the tubing and annulus. If combined with inappropriate designs and operations there can be undesirable and unexpected effects on the overall performance.

Specific examples discussed include:

  1. The performance of circulation systems for both dual well and single well SAGD process shows that insulated tubing may be beneficial under various scenarios while it may be unnecessary for others.

  2. Guidelines for the distribution of steam between tubing and annulus in horizontal injectors.

  3. The basic design considerations for the gas/steam lift of thermal production wells.

Introduction

The use of horizontal wells for thermal recovery has increased significantly during the past decade. There are now a wide range of installations including dual well steam assisted gravity drainage (SAGO), single well SAGO, multi-laterals and various steam drive configurations.

Common to all these applications is the flow of mixtures of steam/water/oil over a considerable range of temperatures. Due to the length of these wells, typically greater than 1200 m measured depth, and the relatively high flow rates, 100+ m3/d, there is a potential of encountering significant pressure drops and/or high rates of heat exchange. Adverse effects can include:

  • Uneven distribution of injected and produced fluids.

  • Significant variations in temperature along the well.

  • Unstable behavior in steam/gas lift systems.

Since one of the major advantages of a thermal horizontal well is the capability to. contact a larger volume of reservoir, it is important that the issues of steam injection and production distribution be evaluated by numerical modeling during the design phase, prior to field installation. In addition, numerical modeling of the wellbore can assist in evaluating field performance, this is particularly applicable to situations where temperature data along the length of the well is unavailable. Careful application of numerical wellbore simulation can also lead to insights into the actual reservoir processes, and can assist in constraining numerical reservoir simulators.

Originally, thermal wellbore simulation was limited to a few analytical techniques. Over the past several decades these have evolved to comprehensive numerical models that can model increasingly complex situations. In the future the trend will be to increasing integration with reservoir simulation.

NUMERICAL SIMULATION TECHNIQUES

The principle components of a successful numerical simulation of thermal horizontal wells include:

  • Heat transfer coefficients across films and insulation.

  • Conduction heat transfer into the formation.

  • Viscosities, enthalpies and interfacial tension data for mixtures of steam/water/oll/gas.

This content is only available via PDF.
You can access this article if you purchase or spend a download.