Determination of Virgin Rock Temperature From Drillstem Tests
Authors: Hermanrud Christian , Lerche Ian , Meisingset Knut K. 
Published: December 2007

The accuracy of virgin rock temperatures determined from drillstem tests (DST's) was investigated by examining factors that affect the temperatures recorded downhole during DST's. It is shown that virgin rock temperatures can be calculated with a standard deviation of about 1.5°C. The data base for the investigation consisted of more than 300 measurement series recorded from DST's in the Norwegian North Sea, encompassing temperature readings from 208 DST's in 112 different wells.

Introduction

Temperatures in a well are important for many aspects of drilling, completion, production, and injection. Wooley1 mentions applications to (1) cement composition, placement, and setting time; (2) drilling mud and annulus fluid formulation; (3) packer design and selection; (4) logging tool design and log interpretation; (5) wax deposition in producing tubing; (6) corrosion and thermal stresses in casings and tubing; (7) permafrost thawing and refreezing; (8) wellhead and production equipment design; (9) drill bit design; and (10) elastomer and seal selection.

Temperatures are also used for PVT modeling of hydrocarbons, for reservoir modeling and volume estimates, for detection of zones with poor casing cement, for correlation between wells, and for understanding such temperature-dependent geological processes as cementation/dissolution of minerals, alteration of maturation indicators, and generation of hydrocarbons.

Some of these areas require knowledge of the temperature actually encountered in the well. Others require knowledge of the virgin (undisturbed) rock temperature, while still others need the virgin rock temperature to calculate the temperature at other places in the basin (e.g., modeling of hydrocarbon generation).

In this paper, we describe a study undertaken to find the best method for determining the virgin rock temperature from DST data and to determine the uncertainty of such temperature estimates. First, factors that may contribute to the temperatures recorded during DST's are investigated, and the results are used to determine how virgin rock temperatures should be deduced from DST data. Second, several DST's from the Troll and Gullfaks fields in the Norwegian North Sea are compared to assess the uncertainty of the obtained estimates.

Investigation of Factors Affecting DST's

Hydrocarbons flowing from a formation into a well experience a pressure drop that introduces a temperature change in the fluids (the Joule-Thomson effect). This effect can be modeled with equations of state. Such modeling has been carried out for a number of DST's. The Joule-Thomson effect will not be discussed here. Other factors influencing the temperatures measured during DST's are below.

Cooling/Heating of Formations Before and During Testing.

A well has been affected by the cooling of circulating mud several times after logging was completed before the well began to flow. In addition to this, the reservoir may have been exposed to circulating mud during drilling for several days or weeks before the final logging of the well. Actual exposure time depends mainly on the drilling rate and the distance between the reservoir and the bottom of the hole. In the Norwegian North Sea, this exposure time is commonly between 3 and 30 days and is typically longer for exploration wells than for production wells. Such exposure can lead to a thermal-invasion zone of several meters,2 substantially more than the thermal-invasion distance encountered at the bottom of the hole (˜50 cm).3

Fig. 1 shows traces from the temperature profile in the reservoir and in the formation surrounding the gauges before the first flow period (Trace a). Both Trace a curves have the same general shape, but their detailed shapes and magnitudes depend on the thermal diffusivity of the two formations and the cooling/recovery history of the well.

When the well is flowing, the reservoir rocks near the borehole are invaded by thermally undisturbed fluids. These fluids deliver thermal energy to the reservoir rocks, so the fluids and surrounding rock particles, for all practical purposes, can be considered to have the same temperature at all times. Because of the Joule-Thomson effect, this temperature is not necessarily equal to the virgin rock temperature. The fluid-flow velocity in the test string is tens of meters per second for a fairly good oil or water test and can be even higher for a good gas test.

Cooling/Heating of Formations Before and During Testing.

A well has been affected by the cooling of circulating mud several times after logging was completed before the well began to flow. In addition to this, the reservoir may have been exposed to circulating mud during drilling for several days or weeks before the final logging of the well. Actual exposure time depends mainly on the drilling rate and the distance between the reservoir and the bottom of the hole. In the Norwegian North Sea, this exposure time is commonly between 3 and 30 days and is typically longer for exploration wells than for production wells. Such exposure can lead to a thermal-invasion zone of several meters,2 substantially more than the thermal-invasion distance encountered at the bottom of the hole (˜50 cm).3

Fig. 1 shows traces from the temperature profile in the reservoir and in the formation surrounding the gauges before the first flow period (Trace a). Both Trace a curves have the same general shape, but their detailed shapes and magnitudes depend on the thermal diffusivity of the two formations and the cooling/recovery history of the well.

When the well is flowing, the reservoir rocks near the borehole are invaded by thermally undisturbed fluids. These fluids deliver thermal energy to the reservoir rocks, so the fluids and surrounding rock particles, for all practical purposes, can be considered to have the same temperature at all times. Because of the Joule-Thomson effect, this temperature is not necessarily equal to the virgin rock temperature. The fluid-flow velocity in the test string is tens of meters per second for a fairly good oil or water test and can be even higher for a good gas test.