deepwater well temperature predictionspe-176089-ms

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SPE-176089-MS

Special Considerations for Deepwater Well Temperature PredictionZhongming Chen and Liangjun Xie, Baker Hughes

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition held in Nusa Dua, Bali, Indonesia, 20–22 October 2015.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents

of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect

any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written

consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may

not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Accurate wellbore temperature prediction is essential in deepwater drilling and completion operations.

The wellbore temperature profile is the most dominant factor to consider when the cement slurry

properties are designed. These properties are critical to ensure the success of cement placement. Many

wellbore temperature simulators described in the literature use a finite difference approach in transient

temperature profile modeling. However, for deepwater drilling and completion, the process is more

complex. Seawater currents and natural convection cannot be ignored in heat-transfer modeling, espe-

cially for subsea pipelines and risers. Also, there are few published results of thermal property correlations

for non-Newtonian, high-viscosity cement slurry. Special treatments accounting for transient heat transfer

for those cases are necessary.

Mud and cement slurry are typically pumped at lower flow rates for cementing operations. At these

rates, apparent viscosity may be used in heat transfer coefficient calculations. However, rheology

properties for non-Newtonian fluids are changed abruptly for different models, and so are simulation

results. For high viscosity fluids, such as cement slurry, there is a general need for experimentally derived

heat transfer correlations.

A novel heat transfer model has been introduced for deepwater cementing. Special considerations for

non-Newtonian fluids are included based on theoretical analysis, real field data correlations, and transient

heat transfer of deepwater subsea pipelines and risers.

The predictions of the wellbore temperature profiles from this model are validated through measured

wellbore temperature profiles, both in offshore and onshore cases. The model has been successfully

applied in deepwater circulating, cementing, and hydraulic fracturing. Cases will be presented in this paper.

Introduction

Successful primary cementing of every casing string is a key element of a wellbore integrity. Poor primary

cement operations result in high costs for rig time and for material in subsequent repairs. To ensure a good

cement job, accurately predicting wellbore temperatures more important than any other parameter, the

single most influencing assumption made in designing and testing of cement slurry. Wellbore temperature

affects all aspects of cement slurry design, including thickening time, compressive strength development,

fluid rheology, and fluid loss. Over- or under-estimating the wellbore temperature can lead to any number



of possible non productive-time events ranging from excessive Wait On Cementing (WOC) time to the

drilling out of cement-filled casing. The effect of small changes in estimated temperature on additives

used to control cement slurry properties can be significant.

Many wellbore temperature simulators use finite difference approaches in transient temperature profile

modeling. However, the literature demonstrates that results deviate from actual measurement under

conditions, such as deepwater jobs, where sea water currents and natural convection affect the results.

Also, there are few published results of thermal correlations for non-Newtonian, high-viscosity cementslurries, where rheology properties at lower flow rates are quite different for different models, and so are

simulation results. Special treatments for those cases are necessary.

Chin and Wang (2004) studied the mechanics of heat loss in dry-tree, top-tensioned risers. Because of

the large height gap ratio, secondary flow or vortices are induced by the buoyancy along the gap. This

buoyancy enhances the internal natural convection heat transfer coefficient. Sarker et al. (2013) similarly

studied production jobs, determining that radiation is no longer negligible when the temperature difference

between the production tubing and casing is high. Mathews’ study (2012) also included the heat transfer

coefficient for natural convection of the surrounding sea water with constraints. A correlation was

provided by Churchill and Chu (1975).

Numerical ApproachTo accurately describe the heat transfer phenomenon in a wellbore (casing, tubing, coiled tubing, and

annulus) and the formation, a set of rigorous governing differential equations were derivated. The

governing differential equations were then solved numerically by means of finite difference techniques.

Model Development

The governing differential equations were developed based on the law of conservation of mass and energy

transfer. The heat transfer between tubing and annulus was considered as steady-state heat flow. The heat

transfer between the annulus and formation was treated as unsteady transient flow.

The equation of conservation of energy for a control volume inside the pipe is:

The equation of conservation of energy for a control volume inside the annulus is:

The temperature in the formation is governed by the equation:

Offshore Seawater Effect

Natural Convection in Seawater

Natural or free convection is the result of the motion of the fluid due to density change arising from the

heating process (Holman, 2005). The fluid density near the heat transfer surface decreases when it is

heated. Thus the buoyancy force imposes on the fluid and forces the fluid into motion. For a riser in

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seawater as a vertical cylinder, when , it may be treated as a vertical flat plate (Churchill and

Chu, 1975),

and

where Reynolds number , and Prandtl number .

Grashof number G rL

is defined as:

where is the inverse of the absolute temperature.

Rayleigh number is

Forced Convection

Generally, the sea water current can have different speeds at different depths. This can be modeled as

external forced convection of flow across a cylinder (Holman, 2005). It should be treated on heat transfer

as equal importance when the speed is sufficiently large. The boundary layer separation development on

the cylinder determines the heat-transfer characteristics. Churchill and Bernstein (1977) developed a

comprehensive correlation over the complete range of available data.

and

Nakai and Okazaki (1975) presented the following relation:

where Peclect number P e R

e P

r .

The film coefficient can be calculated by:

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Natural Convection in Annulus

Free convection in the annulus of a riser can be considered as free convection in enclosed spaces where

a fluid is contained between two vertical plates separated by the distance . It can be divided into five

regimes based on the Rayleigh number Ra

: conduction regime ( Ra 103); asymptotic flow regime (103

Ra 3 104); laminar boundary layer flow regime (3 104

Ra 106); transition regime (106

Ra 107); and turbulent boundary layer flow regime ( R

a 107). Empirical correlations obtained for

liquids under constant-heat-flux were (Holman 2005):

and

and (Sarkar et al. 2013)

and (Chin and Wang, 2004)

where is the gap in the annulus.

For the case of 40 L/, the value of 40 may be used conservatively.

For horizontal annulus (Holman, 2005),

and

Offshore Seawater EffectCase History 1

This first comparison was for deepwater deviated wellbore with 5.5-in. drill pipe. The riser has 21 in.

Outer diameter (OD) and 19.5 in. inner diameter (ID) in water depth 6,253 ft. There is a casing with

12.4 in. ID to 9,100 ft MD. The final hole depth is 10,794 ft with a 12.25-in. open hole.

Casing Size 12.4 in.

Casing Depth 9,100 ft

Riser OD 21 in.

Riser ID 19.5 in.

4 SPE-176089-MS



Temperature Gauge Depth 10,794 ft

Workstring Size (OD) 5.5 in.

Ambient temperature 80 °F

BHST 128.4 °F

The input mud has inlet temperature 75 °F, density of 10 ppg, Cf 0.79 btu/(lbm.°F), and k 0.37

btu/(hr.ft.°F). The Herschel Bulkley parameters are n 0.528, k 2.609 lbf. sn/100 ft 2, and yield point

6.3377 lbf/100 ft 2.Mud was circulated through an open-ended 5.5-in. drill pipe, and a gauge on bottom recorded the

circulating temperature. During the circulation period the gauges recorded temperature every 20 seconds.

The pumping schedule is listed in Table 1.

Fig.1 shows a comparison of the measured and predicted temperatures from the model with and

without modifications. In general, the prediction from the software with modifications is better and differs by a maximum of only 10°F from the measured at any point of time during this period. These results

demonstrate that under these specific well conditions – that is, especially in very deep water - the model

is more realistic than the original model.

Case History 2

The effect of introducing natural and forced convection to sea water is more pronounced for deepwater.

When water depth is deeper than 6,000 ft, the added modifications generates better results. Under other

conditions – for example, shallower water -- the effect of modifications is less obvious. Still, the result

should be equivalent, if not better. This second comparison was a simple circulation exercise with 5-in.

drillpipe in a 20-in. casing using seawater.

Water Depth 3,780 ft

Casing OD 20 in.

Casing depth 5,778 ft

Riser OD 21 in.

Table 1—Operation Schedule

Time (min) 63 50 24 32 175 87 67 19 62 36 172 44 30

Rate (bpm) 12.1 0 2.4 12.1 2.4 3.6 0 7.4 0 8.3 12.1 0 12.1

Figure 1—Real time data of bottomhole temperature vs. simulated result

SPE-176089-MS 5



Riser ID 19.75 in.

Temperature gauge depth 5,721 ft

Workstring OD 5 in.


BHST 59 °F

The 20-in. cemented casing with riser installed was circulated with sea water through an open-ended

5-in. drill pipe, whilst a gauge on bottom recorded the circulating temperature. During the circulation period the gauges recorded temperature every 30 seconds. A similar measurement was made on surface

to determine the temperature of the returned fluid.

Fig. 2 shows a comparison of the measured and the predicted bottomhole temperatures from models

with and without modifications. Fig. 3 shows a comparison of the returned annular temperature at surface.

In general, the both predictions from simulations closely match the measurements and differ by a

maximum of only 3 to 4 °F from the measured at any point of time during this period. These results

demonstrate that under these specific well conditions the new model is within only a few degrees of the

original model prediction and the realtime data.

Case History 3

This is also an offshore well, not in deep water, but with the added complication of circulating

non-Newtonian fluids (i.e. a Bingham plastic fluids). Since the heat transfer mechanism depends on the

Figure 2—Real time data of bottomhole temperature vs. simulated result

Figure 3—Real time data of returned annular temperature at surface vs. simulated result

6 SPE-176089-MS



state of flow of the fluids, this is a good example to determine the models’ ability to deal with complex

fluid systems.

Water Depth 2,998 ft

Hole Size 22 in.

Hole Depth 6,829 ft

Temperature Gauge Depth 918 ft

Workstring Size 5 in.Workstring Weight 19.5 lbm/ft


BHST 69 °F

Fluid Density 10.7 ppg

Fluid Type Bingham plastic

PV/YP 11 / 19

Pump Rate 430 gpm for first 9 minutes, and then 930 gpm

Fig. 4 shows the comparison of measured temperatures and those predicted with and without

modifications from finite difference model (FDM). From the predictions, FDM results matched the actual

measured results, with a maximum difference of 5 degrees. It also varied less than 1 degree from the

original calculation for this well condition.

Conclusions

Accurate prediction of temperature profile in wellbore is necessary for proper cement slurry properties

design. Offshore deepwater complicates the heat transfer process, and special considerations are needed

to take all offshore conditions into account.

1. Rigorous numerical schemes were developed to simulate the transient temperature profile in

onshore and offshore well configurations.

2. Sea water flow and associated characteristics, including current velocities at different depths,

natural convection, and forced convection, have significant effect on heat transfer on riser and also

wellbore annulus temperature profile.

3. Simulation results for actual job histories at different water depths match measured temperatures

within a few degrees. For the case with water depth deeper than 6,000 ft, the results with model

modifications generated results closer to the actual measured data, indicating that in deepwater, the

Figure 4 —Real time data of bottom hole temperature vs. simulated result

SPE-176089-MS 7



modified model is more accurate than the original model. In water depths less than 6,000 ft, the

modified prediction is within minimal variance from both original prediction and realtime data,

indicating the modification is as accurate as the original version under these conditions.

AcknowledgementsThe authors would like to thank the management of Baker Hughes for their permission to prepare and

present this paper.

Nomenclature

API American Petroleum Institute

BHCT bottomhole circulation temperature

BHST bottomhole static temperature

the inverse of the absolute temperature.

FDM finite difference model

ft feet

gpm gallon per minute

HSD hot spot depth

HST hot spot temperature

ID inner diameter

in. inch

MD measured depth

OD outer diameter

PV plastic viscosity

T.D. total depth

WOC wait on cementing

YP yield point

AP drill pipe or workstring cross section area

Cf

formation heat capacitycf fluid heat capacity

G temperature gradient

h film coefficient

H wellbore bottom boundary depth

k f formation heat conductivity

ma mass flow in annulus

m p mass flow in drill pipe or workstring

Nu Nusselt Number

P e

Peclect number

Pr Prandtl Number

r

radial distance from wellborer a annulus radius

r P drill pipe or workstring radius

R a Rayleigh Number

R e Reynolds Number

formation density

f fluid density

Ta annulus temperature

Tf formation temperature

8 SPE-176089-MS



TP drill pipe or workstring temperature

Ts surface static temperature

t time

Ua overall annulus heat transfer coefficient

Uf heat transfer coefficient at fluid-formation interface

U p overall pipe heat transfer coefficient

va annulus fluid velocityvP drill pipe or workstring fluid velocity

z length in wellbore direction

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