Abstract

Thermal effects become an important factor in gas well pressure buildup tests with a surface shut-in. Welltest data from Western Canada demonstrate that, due to the PVT relationship, temperature changes of wellbore fluids can cause thermal-storage effects that can be misinterpreted as complex reservoir characteristics by unexplained pressure transient response or non-unique pressure response. Understanding the duration of thermal effects can improve the interpretation of buildup tests to allow enough time for observation of true reservoir pressure transient responses.

Temperature effects can be significant and extended depending on many in-situ and imposed factors. Thermal effects can be important, even when pressure recorders are placed at mid-point of the producing interval, due to Joule-Thompson effects. Field observations demonstrate that Joule-Thompson cooling exists in many gas wells. Cooling effects were observed to extend 50 m in the formation, suggesting that significantly long time periods are required for formation fluids to reach thermal equilibrium after shut-in.

Implications of not understanding the thermal effects in a buildup test analysis can result in "heterogeneities" being interpreted when there are none and skin calculations indicating an improved wellbore condition when the well has only been perforated.

It is the purpose of this paper to show how temperature data diagnostics can be used to aid the Welltest Engineer in distinguishing between general wellbore effects and reservoir behavior in the pressure transient data. In this paper, we have adopted the acronym PTTA for (P)ressure (T)emperature (T)ransient (A)nalsysis.

Introduction

Use of pressure transient tests has become an established practice to determine reservoir parameters, potential reserves and near wellbore conditions. It is widely recognized that wellbore and near wellbore effects redistribution, such as liquid influx/efflux, wellbore (and near wellbore) clean-up, plugging, recorder effects, etc., have been discussed in the past decade6–8. However, theoretical and numerical analyses of thermal effects have only been addressed recently9–12.

Implicit assumptions that require well test data to reflect information from an isothermal condition in both wellbore and reservoir are generally made in interpretation models. Such assumptions only hold if the pressure and temperature recorders are placed at the middle of the perforation interval, and neither Joule- Thompson cooling or heating occurs. Although various aspects of heat transfer between a wellbore and the formation have been studied, most of them are steadystate models, which assume that fluid properties and flow rate are not functions of time in the wellbore9.

Thermal effects are more pronounced in gas wells because gas properties are strong functions of pressure and temperature. Observations demonstrate that gas well pressure buildup tests often exhibit complex reservoir pressure behaviors. These models, such as narrow channels, double porosity, or multiple nearby boundaries, often did not agree with the actual reservoir system and, consequently, resulted in incorrect interpretation of well and formation parameters12.

Empirical analysis based on well test simulations and field data were presented by Al-Haddad et al12.

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