Calculating the Steam-Stimulated Performance of Gas-Lifted and Flowing Heavy-Oil Wells
Authors: Boberg T.C. , Penberthy W.L. , Hagedom A.R. 
Published: December 2007

Calculating the Steam-Stimulated Performance of Gas-Lifted and Performance of Gas-Lifted and Flowing Heavy-Oil Wells

Here is a method for combining reservoir and wellbore pressure-drop calculations to predict the performance of steam-stimulated wells producing by natural flow or by gas lift. The extent to which such process variables as treatment size, lift-gas rate, wellhead pressure, and prestimulation rate affect performance can be calculated with this method.

Introduction

When fluids are produced from the reservoir in which they are found and transported to separation or treating facilities on the surface, three basic types of multiphase fluid flow are encountered:

Flow to the wellbore through the porousmedium, Vertical flow in the wellbore from thesandface to the wellhead, and Horizontal flow through flowlines from thewellhead to the surface facilities.

The first two types of flow are coupled by the flowing bottom-hole pressure at the sand-face; the latter two types are coupled by the flowing wellhead pressure. A complete description of such a system requires simultaneous solution of the three flow problems. A method for simultaneously solving the reservoir and wellbore flow problems has been developed for use in calculating the steam-stimulated performance of a well that is either flowing or being produced by continuous gas lift. For simplification, it has been assumed that the wellhead pressure can be specified. This implies that the flowline is short or is adequately sized to have only a minor pressure drop. This is not always the case in practice, and it may sometimes be desirable to incorporate a flowline pressure drop calculation. pressure drop calculation. It is important that the wellbore and reservoir flow problems be considered in combination for the problems be considered in combination for the following reason. For a given wellhead pressure, the flowing bottom-hole pressure - and hence production rate - is controlled by the pressure drop that occurs in the wellbore. This pressure drop is a function of the oil, water, and gas flow rates and fluid properties, some of which are strongly temperature properties, some of which are strongly temperature dependent. The problem is compounded in steam-stimulated wells because both the flow rates and the temperature change significantly during the production cycle. For a well producing viscous oil, the production cycle. For a well producing viscous oil, the change in temperature is particularly important because of its effect on oil viscosity. A temperature change of only 60 deg. F in the tubing string can often result in a difference of several hundred psi in the flowing bottom-hole pressure, with a consequent effect on production rate. Under some conditions, variations in pressure drops in surface flowlines can also be significant and must be considered because of their influence on wellhead pressure. The paper describes how two previously published techniques were combined to solve the stated problem, illustrates the combined method by example problem, illustrates the combined method by example calculation, and establishes the validity of the method by comparing calculated and field results. Also, the method is used to calculate the extent to which several important process variables, such as treatment size, lift-gas rate, wellhead pressure, and prestimulated production rate, affect stimulated performance. prestimulated production rate, affect stimulated performance.

JPT

P. 1207