Cement Plugs: Stability and Failure by Buoyancy-Driven Mechanism

Cement Plugs: Stability and Failure by Buoyancy-Driven Mechanism

J. P. Crawshaw, Schlumberger, and I. Frigaard, Schlumberger Dowell

Setting cement plugs off bottom is a well recognised problem

in the industry. Different causes of failure have been

identified over the years and many have been addressed by

improving practices used in the field. A remaining problem is

the instability of the lower interface between the cement and

the fluid below, driven by the greater density of the cement.

That is, once a cement plug has been injected into the wellbore

it must resist the tendency to fall through the less dense

drilling fluid below until the cement has set. The fluid

properties which ensure stability have never been satisfactorily

established and it is this gap which is addressed by the current

work.

Theoretical and experiment results are presented in this

paper which allow the estimation of the yield stresses required

of the fluids to stabilise a cement plug under any conditions of

hole size, inclination and density difference between the

cement and the fluid underneath. The experimental work

shows that the model is somewhat conservative and this is

discussed in terms of the assumptions made in each case.Introduction

Cement plugs can be placed either through tubing or by a

dump bailer. The dump bailer has limited applications and

only the placement of a balanced plug through tubing will be

discussed in this paper.

Plugging oilwells is a very common operation. Every well

must at some time be abandoned and this usually involves

setting cement plugs at several depths1. Renewed interest in

recovering more oil from well established fields has lead to an

increase in sidetracking from existing wells and this

commonly requires a cement plug to be set to kick off from.

Problems in drilling a new well are also sometimes addressed

by using cement plugs, for example to cure lost circulation.

However, plug cementing is an operation which has long2

been neglected as a minor task in which several attempts to set

a successful plug are the rule and not the exception. A widely

quoted figure3,4 for the industry average success rate in setting

cement plugs is 2.4 attempts per successful plug. A more

recent survey5,6 of plug failure mechanisms in the North Sea

concluded that, for off bottom plugs with no mechanical

barrier below the cement, only 30% were complete failures,

although 70% had the top of cement more than 30 meters

below planned depth. In general the failure rate can vary

considerably according to local conditions.

The reasons for the low success ratio have been

investigated by several authors7,3,4 and best practice guidelines

have been suggested to deal with many of the operational

problems. Some of the problems encountered can be related to

the circumstances in which the plugs are set, which are often

adverse in that the plug must be set quickly in response to an

unplanned event, and other problems are a consequence of the

fluid properties. The volume of cement which must be placed

is frequently small compared to the total volume of fluids in

the well, particularly in deep wells8, and this can lead to

contamination problems, both inside the tubing and in the

annulus. Additional contamination can also be induced when

the placement pipe is pulled out of the balanced plug.

Eliminating the causes of plug failure mentioned above by

application of best practices still leaves one mechanism for

which the physics has not been understood well enough to

derive quantitative, preventative measures: buoyancy driven

flow, in which the cement channels down through the less

dense fluid below. This is a well known problem investigated

in a largely empirical way in the literature. Only one paper9

addresses the modeling of this mode of plug failure and that

analysis was restricted to vertical wells and for a particular

symmetric mode of failure.

One solution would be to place a mechanical device below

the desired bottom of cement5. However, this incurs an

additional expense and it may not be needed in every

circumstance, as some off-bottom plugs succeed in the field

with no attempt to provide a base to support the lower

interface.

Other authors have carried out experiments with a viscous

pill7 or reactive viscous pill10 placed below the cement to give

additional stability. The most recent of these studies11

describes extensive experimentation in model wellbores at

several angles between vertical and horizontal. However, the

stability criterion developed in this work was flawed and

cannot be used to predict when a cement plug will remain

stationary after placement.

The aim of this paper is to develop an understanding of the

physics of the buoyancy driven failure mode, such that

quantitative predictions can be made of the rheology required

of both the cement and the fluid below to prevent fluid

movement after the pumping phase of the plug placement

process has ended. The theory will be briefly outlined in the

next section followed by a description of new experimental

results which will be compared to the theoretical predictions.

Finally the limitations of the approach and the implications for

field practice are discussed.Theory

It is difficult, if not impossible, to define the shape of the

mud/cement interface at the end of the plug placement process

and, as we shall see, the shape of the interface influences the

conditions for marginal stability. The approach taken in the

modeling, therefore, was to consider a slumping exchange

flow. This flow pattern is the most common way4,11 for the

plug to flow, when it begins to fail in an inclined wellbore

under the influence of gravity. This flow pattern was also

frequently observed in the experimental work described in the

next section and an example is shown in Fig. 1. The field

experience of a cement plug that drills soft but produces hard

cuttings is also evidence for the exchange flow, since the

uncontaminated cement fills only part of the wellbore.

The flow pattern can be divided into three regions where

mud and cement co-exist at a particular crossection of the

wellbore and these are shown schematically in Fig. 2. As the

more dense cement slumps down the low side of the wellbore,

a long axial exchange flow region is created where the motion

of both fluids is almost parallel with the axis of the wellbore.

We assume no fluids enter or leave the well during this stage

of the operation. The cement that moves down the well is

therefore matched by the volume of mud displaced up the

well. It is this phenomena which we refer to as an exchange

flow. The exchange flow region is connected to the

undisturbed cement above and mud below by two transitional

regions in which the flow is more complex

The mathematical analysis seeks to define the conditions

under which the fluids in the wellbore cannot move in an

exchange flow. This gives a conservative estimate of the

stability condition, as other interface shapes may be more

stable, (e.g. an interface that is close to horizantal), but is a

valid upper bound in that any interface which begins to move

under the influence of gravity will, eventually, form into an

exchange flow unless the well is exactly vertical.

The simplest rheological model which captures the general

features of the flow of cement and drilling fluids is that of a

Bingham fluid or plastic. A Bingham fluid has a yield stress

and therefore will not flow until a certain stress is exceeded.

Note that a yield stress is required to prevent movement in the

inherently unstable case of a more dense fluid above a less

dense one, a large viscosity would slow down the motion but

not prevent it.Description of Experiments

In contrast to its mathematical simplicity, it is very difficult

experimentally to produce a stationary exchange flow

geometry with fluids of a known yield stress. The most

reproducible interface shape (and the one chosen for most of

the experimental work) was a flat interface perpendicular to

the axis of the wellbore.

This was constructed by half filling, in the vertical

orientation, a long closed-ended pipe with a dense fluid and

then continuing to fill with a lighter fluid such that the

interface remained sharp and level. Samples of the two fluids

were taken at the time of filling the apparatus so that the yield

stress could be measured using a vane rheometer15. We note

in passing that it is less helpful to report the yield point, YP,

which is extrapolated from high shear rate rheology and may,

therefore, inaccurately represent the very low shear behavior

of the fluid.

To test the stability of the fluids, the pipe was rotated so

that the more dense fluid was above the less dense at a given

inclination to the vertical, q. At the same time the yield stress

of the samples was measured. This procedure was employed

for both 2 and 4 inch diameter pipes. At larger sizes, such as 8

inch, it became difficult to invert the pipe and the procedure

was modified. During the small diameter testing it became

apparent that the vertical orientation was more stable than an

inclined one for the flat interface configuration. For the

largest diameter, therefore, the pipe was half filled with the

less dense fluid first and then the more dense fluid was slowly

injected using a flow diverter tool positioned just above the

horizontal interface. Once the desired yield stresses were

obtained in the two fluids the pipe was moved to the required

inclination and the stability of the interface observed.

The fluids used in the experiments were: (i) Xanthan gum

solutions in water, which are viscous and Newtonian at very

low shear rates (less than 10-3 s-1) becoming shear thinning at

higher shear rates. This was used as the model fluid when no

yield stress was required. (ii) RDS grade Laponite suspensions

in water, which were used when a yield stress was required.

Laponite is a synthetic clay, similar to natural clays such as

hectorite or bentonite, but with a much smaller particle size.

The advantages of the Laponite for these experiments were its

good transparency and the ability to control the yield stress

over a wide range. The yield stress was manipulated by

changing the salt concentration of the 6 wt% Laponite

suspension and the time for which it was left static before an

experiment, as the yield stress continues to build over several

hours. This allowed small variations in the yield stress to be

made between experiments while using the same batch of

fluid. One of the fluids was weighted as required by the

addition of barite to generate the required density difference.

To obtain the marginally stable yield stress for a given Dr,

D and q a series of experiments was conducted with

progressively larger yield stresses until the interface remained

stable at the chosen inclination. Each series of experiments,

therefore, lead to a single point dividing stable from unstable

interfaces.

Experimental Results

Observations of failure modesIn most cases, when the pipe was inclined at more than a few

degrees away from vertical, the flow pattern during the

buoyancy driven failure was that of an exchange flow as

shown in Fig. 1. The vertical case was interesting in that the

flow pattern was much more complex and, as observed by

others16, followed a “roping” or helical pattern. However, this

is of little real world relevance as few wells are so close to

vertical.Comparison to Theoretical Results

The experimental values for the marginally stable yield

stresses in both fluids, as a function of angle and for all three

pipe sizes, are shown in Fig. 5. In this figure the view point

has been changed from that of Fig. 4 so as to reveal the

experimental points, which all lie below the theoretical

surface. From this viewpoint the experimental points are well

clustered and they follow the general shape of the theoretical

surface. This confirms that the initial selection of

dimensionless groups, equation (1), was appropriate and

should be regarded as a partial validation of the theory.

The degree of conservatism in the theoretical surface can

be seen in more detail in Fig. 6 in which the ratio of the

experimental yield stress modulus to the theoretical yield

stress modulus, y,exp y,u t /t , is plotted against the pipe

inclination. The experimental modulus varies between 70%

and 20% of the theoretical value with the better agreement

towards the horizontal orientation. To interpret these results

recall that the experiments were performed with a flat interface

perpendicular to the wellbore axis and that the theory was

developed for the axial exchange flow. Intuitively, the

interface shape which will be most unstable at any given pipe

inclination is that which lies parallel to the direction of gravity,

whereas the interface perpendicular to gravity will be most

stable. This trend is clearly seen in Fig. 6 and accounts for

some of the variation in conservatism. To test this idea two

additional experiments were carried out with the interface

initially at 45° to the pipe axis and these points are also shown

in Fig. 6. With the pipe horizontal, the change in the interface

had little effect on the marginally stable yield stress.

However, with the pipe vertical the experimental value was

much closer to the theoretical.

The influence of the distribution of yield stress between the

two fluids is examined in Fig. 7 where the theoretical and

experimental results are plotted for pipe inclinations of 10°

and 45°. This is equivalent to two slices through the marginal

stability surfaces shown in Fig. 5. The weak dependence of

the sum of the two marginally stable yield stresses on j can be

seen in the experimental data. As in the theoretical predictions

the effect is stronger at lower values of q.

Implications for Field PracticeThe comparisons outlined above give considerable

confidence that equation (6) is a valid representation of the

marginal stability surface. From the limited number of initial

interface shapes considered experimentally, it seems that the

theory over predicts the yield stresses by around 30%, a

reasonable engineering safety margin. However, in applying

the results to the field situation a number of additional

difficulties are encountered.

Firstly, the Bingham representation of the fluids in the

wellbore is a simplification and many real wellbore fluids have

a time and/or shear history dependant rheology. This together

with the pressure and temperature dependence of the rheology

make it difficult to estimate with precision the yield stress of

fluids thousands of meters below the surface.

Secondly, in all this work we have assumed that the

interface remains sharp and no significant mixing processes

take place. Further work is required to quantify the influence

of mixing during the pumping stage, particularly when an

open ended pipe is used and the cement emerges as a jet down

into the wellbore which must turn around before starting to fill

the annulus.

It is possible that mixing processes bring additional

stability to the field placement situation through two

mechanisms: a smearing out of the step in density locally

reduces the buoyancy driving force and incompatibility of the

mud and cement may result in a higher yield stress in the

mixed region than in either of the two fluids alone. This may

explain some of the successes in the field when stability

appears doubtful from a theoretical point of view.Conclusions

Setting cement plugs off bottom is a well recognised problem

in the industry. Many of the causes of failure can be addressed

by current best practice guidelines with the exception of the

swapping of the cement with the fluid below under the

influence of gravity when a significant density difference

exists. Buoyancy drives the interfaces between the cement

and the fluid below to deform as the cement slips down and

the mud up the wellbore in a stratified exchange flow.

Modeling and experimental work have established the

rheology required of the two fluids such that they will remain

stationary once the pumping phase of the plug cementing

operation is complete. This can be used to check the stability

of a given cement plug once it is pumped into the wellbore or

to design a fluid pill to correct an inherently unstable situation.Acknowledgements

We thank the management of Schlumberger for permission to

publish this paper.