Temperature Prediction Model for Flowing Distribution in Wellbores and Pipelines

Temperature Prediction Model for Flowing Distribution in Wellbores and Pipelines.

ABSTRACT

Down-hole temperature and pressure data are important information needed to understand flowing conditions and production optimization. For example, knowing the wellbore temperature profile is useful in predicting the wax formation in the tubing, which is important in flow assurance.

While gas production usually causes a temperature decrease due to Joule Thomson effect, water entry results in warming of the wellbore.

Warmer water entry is as a result of inflow from a warmer aquifer zone due to water coning. Water entry by water coning can therefore easily be detected from temperature profile since it increases the wellbore temperature.

In this study, we successfully developed a temperature prediction model which calculates temperature profiles for flowing temperature in the wellbore and considers Joule Thomson coefficient as a function of mass flow rate of the fluid phases (oil, water, and gas).

We modified Alves et al temperature equation and the modified temperature equation  was  used  to  produce the work done by Alves et al which produces close result.

The model was used to investigate the effect of gas and water entry that created change in temperature profile along the wellbore.

The temperature equation can be applied to pipelines or production and injection wells under single phase, two phase, and three phase flow, for horizontal, vertical, and inclined wells.

Cases were considered to verify the effect of water and gas entry into the wellbore. The result shows that water entry increases wellbore temperature and gas entry decreases wellbore temperature and also temperature profile is a function of the flow rate of the fluid.

Since the prediction requires the fluid composition in the wellbore, accurate prediction of the temperature profile can give an idea of how much component of each fluid is present in the wellbore.

TABLE OF CONTENTS

ACKNOWLEDGEMENT IV
TABLE OF CONTENT V
ABSTRACT X

CHAPTER 1: INTRODUCTION 1

1.1 LITERATURE REVIEW 1
1.2 PROBLEM STATEMENT 6
1.3 OBJECTIVES 7
1.4 THESIS ORGANISATION 7

CHAPTER 2: REVIEW OF TEMPERARURE LOGS 9

2.1 TEMPERATURE LOGS 9
2.1.1 HEAT BALANCE 9
2.1.2 WELLBORE HEAT TRANSFER 10
2.1.3 GEOTHERMAL TEMPERATURE 10
2.1.4 JOULE THOMSON EFFECT 11
2.2 DISTRIBUTED TEMPERATURE SENSING (DTS) 15
2.2.1 APPLICATION OF DTS 15
2.3 INTERPRETATION OF TEMPERATURE LOGS IN HORIZONTAL WELL 18
2.3.1 TEMPERATURE ANALYSIS IN HORIZONTAL WELL 18
2 . 4 TEMPERATURE INTERPRETATION 18
2.4.1 CLASSIC LIQUID ENTRIES 19
2.4.2 CLASSIC GAS ENTRIES 21

CHAPTER 3: ANALYTICAL TEMPERATUREMODEL DEVELOPMENT 24

3.1 MODEL DEVELOPMENT 24
3.2 GEOMETRY OF MODEL 24
3 .3 DERIVATION OF GOVERNING EQUATION 25
3.31 MASS CONSERVATION PRINCIPLE 25
3.3.2 MOMENTUM CONSERVATION PRINCIPLE 26
3.3.2 ENERGY CONSERVATION PRINCIPLE 26
3 .4 APPROXIMATION FOR BLACK OIL MODEL 34
3 .5 CALCULATION PROCEDURE 36
3.6 VALIDATION OF ANALYTICAL MODEL 36
3.61 TEMPERATURE PROFILE FOR TWO PHASE FLOW MODEL 37

CHAPTER 4: ANALYSIS AND INTERPRETATION 38

4.1 RESULT AND DISCUSSION 39
4.1.1 TEMPERATURE PROFILES FOR SINGLE PHASE OIL PRODUCTION 41
4.1.2 TEMPERATURE PROFILES FOR GAS ENTRY EFFECT 43
4.1.3 TEMPERATURE PROFILES FOR WATER ENTRY EFFECT 44
4.1.4 COMPARISON FOR SINGLE PHASE, 2-PHASE, AND THREE PHASE 46

CHAPTER 5: CONCLUSIONS AND RECOMMENDATION 47

5.1 CONCLUSIONS 47
5.2 RECOMMENDATIONS 48
NOMENCLATURE 49
REFERENCES 51

NTRODUCTION

Down-hole temperature and pressure data are important information to help us understand bottom- hole flow conditions .

The temperature and pressure distributions can be measured by production logging or down-hole permanent sensors such as fiber optic distributed temperature sensors (DTS).

Correct interpretation of temperature and pressure data can be used to obtain down-hole flow conditions such as oil, gas, and water entry which is used in production optimization.

The interpretation of the measured data is often complex due to the multiphase fluid flow in the reservoir. To properly interpret this data, a unified and simplified model is used in predicting the flowing temperature distribution which incorporates the complex process of transient heat transfer between the wellbore and the reservoir.

Distributed temperature sensor technology (DTS) uses a thin glass fiber optical cable installed    along the entire well length .

Laser light sent through the cable scatters with characteristics that depend on the local temperature. It is then possible to obtain a temperature profile with resolution less than 0.1 ºF, at a distance of several thousand feet, and with a measurement time of typically a few minutes.

Unlike a production log that provides only snap shots of the reservoir performance, the DTS enables continuous monitoring of a well to detect temporal changes in the temperature profiles.

REFERENCES

Alves, I.N., Alhanatl, F.J.S., Shoham, O.: “A unified model for predicting flowing temperature distribution in wellbores and Pipelines”. SPE Prod. Eng. 20632, 363– 367. (Nov. 1992).

James, J.S. Alex, V.S.: “Distributed temperature sensing-A DTS primer for oil and gas production”. (May 2003).

Leksono, M., Michael A.:”A  compositional  two  phase  flow  model  for  analyzing  and  designing complex pipeline network systems”. (June 1990).

Beggs, H.D., Brill, J.P.: “A study of two – phase flow in inclined pipes”. (May 1973).

Gould, T.L.: “Compositional two phase flow in pipelines”. JPT (March 1979) 373-84 : Trans.,AIME,267

Pinan D.: “Temperature prediction model for a producing horizontal well”. (Aug. 2006).