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Dispelling well perforation myths - Part 2

Oilfield Technology,

Read part one Perforating myths and misconceptions.

‘Customising a perforating system for my application will be cost prohibitive’

The vast majority of off-the-shelf perforating systems are developed using unstressed cement targets, meaning they are never optimised for a particular wellbore situation. Whether or not a customised solution will add value depends on the well performance that can be gained and the associated cost of developing the system.

Custom solutions can be much more affordable than might be expected, and their development need not take months. GEODynamics recently optimised systems for a series of high-profile deepwater projects. Each system took less than four months to design, optimise, test and prepare for production. The results were impressive: flowing more than 25 000 boepd from a previously un-producible zone, and an improvement of more than 20% in open flow area when perforating heavy wall casing prior to installing sand control. However, the results need not be this dramatic to make economic sense – a modest increase in productivity quickly pays for the project, with typical pay-back times measured in days rather than weeks or months.


Whenever the best off-the-shelf solution still is not yielding ideal well performance, consider investing in the optimisation of a field-specific system. Be sure to work with a provider that can conduct tests under representative wellbore conditions (such as API RP19B, Section 4) to ensure maximum benefit when the solution is deployed in the field.

Shooting the same zone multiple times will cause casing failure

This is perhaps the simplest myth to debunk – it is just a case of simple maths! Example: the total wall area of one foot of 4 ½ in. casing is approximately 170 in.2 Perforating with a typical 6 shots/ft system will remove about 0.2 in.2 per shot (0.5 in. entry hole diameter), for a total of 1.2 in.2 That is approximately 1% of the wall. Even if the same system was shot four times – for a total of 24 shots/ft – it would remove less than 5% of the wall. The reduction in casing strength would still be minimal.

The other lesson to be learned from this simple calculator exercise is that perforating at low shot density creates a very small connection between the well and the formation. The impairment caused by insufficient penetration (often called partial penetration skin) should not be underestimated! In a naturally flowing well, double or triple perforating the same zone with the highest-available shot density system will likely add significant productivity and may be very effective in mitigating inflow deterioration caused by fines migration and other phenomena that plug perforations over time.


Unless attempting to deliberately limit the area open to flow (e.g. using a limited entry technique to divert stimulation fluids), shoot more perforations! The economics are almost universally favourable, with the benefits of increased productivity (or injectivity) and reduced decline rates disproportionately outweighing the cost of higher shot density or an additional perforating run.

Most charges and guns are interchangeable, so mix-and-match to save money

It is common practice for operating company completion engineers to use generic system descriptions or performance criteria when writing well completion programmes; for example, specifying a certain system size and gram weight of charge, or a minimum depth of penetration (and/or entry hole diameter), without naming a particular system manufacturer or product designation. This affords the service provider(s) freedom to select whichever perforating system components meet the programme requirements at a favourable cost.

The unintended consequence of this practice is that charges and guns from different vendors are frequently mixed-and-matched. While it is true that some charges can be run in multiple vendors’ gun bodies, just because it fits does not mean it is properly deployed! Slight tolerance differences can result in loose fit or difficulties loading the gun. Improper fit can result in separation between the detonating cord and the charge, causing a misfire. While a catastrophic loss of performance may be infrequent, the performance of a mixed system will not be the same as when the charge is run in the gun system for which it was designed, and any mechanical performance assurances (such as gun survival and post-shot swell diameter) will cease to apply. Excessive gun swell may result in difficulty retrieving spent guns from the wellbore.

It can be argued that the completion engineer is responsible for specifying perforating system requirements to a level of detail that assures the equipment deployed actually delivers the required performance (and yields corresponding well performance). This should not allow for mixing and matching of components. Even if a generic performance specification is used, the programme should require the use of matching charges and guns from the same vendor.


The completion engineer should do his/her homework and specify a particular charge and gun system from a named vendor. If the programme includes the words ‘or equivalent’, the engineer should be very specific as to how that equivalency is to be demonstrated.

Spotting acid dissolves debris from the tunnel, helping fracture initiation

When a well is not performing, oilmen are frequently tempted to ‘spot a little acid’ and see whether it helps. It is the oilfield equivalent of multi-purpose cleaner or aspirin! Unfortunately, acid can have negative effects on tubular goods, as well as creating HSE risks associated with handling the acid and pumping toxic corrosion inhibitors, so it is important to know why the acid might help and pump it accordingly.

In the case of fracture stimulation, many companies routinely include an acid pre-flush ahead of the stimulation fluid to assist in fracture initiation. There are several theories as to why acid facilitates break down of the formation, and it is possible that more than one mechanism is in play, depending on the formation type and prevailing geomechanical properties.

When the jet from a deep penetrating shaped charge penetrates a competent formation it displaces rock to the sides, plastically deforming the rock matrix and leaving a residual stress ‘cage’ around the tunnel. As the stimulation treatment begins, fluid pressure builds until the rock fails at the point of lowest stress, which, as a result of the stress cages around each tunnel, will be somewhere between two tunnels – not at the tunnel itself. Pressure communication behind pipe (i.e. around the micro-annulus between cement sheath and rock) will allow this to happen. Once the fracture initiates, fluid will flow around the casing from the exit hole (perforation) to the point of fracture initiation. This creates a very narrow, tortuous path and significant near-wellbore pressure loss (tortuosity).

Acid assists breakdown and treating pressure by dissolving away (or at least weakening) the cement sheath, widening and smoothing the pathway from exit hole to frac. However, significant tortuosity will remain (and will be seen on a step-rate test) and the risk of premature pressure increase or even screen-out will be high.

As an alternative, Reactive perforating fractures the tip of each tunnel, which relieves the stress cage. The lowest point of stress ‘seen’ by the fracturing fluid is then found at the tip of the tunnel, so the fracture should initiate there. With a clean, open tunnel from casing to fracture initiation point, tortuosity is virtually eliminated (as seen from step rate tests) and there should be no need for acid to open or widen the pathway.


Experiment with other perforating systems, including Reactive perforating, to evaluate whether acid can be eliminated, or at least reduced, to save money and reduce HSE risks.

Read part three Well perforation myths

Written by Matt Bell, GEODynamics, USA.

This is part two of a three part article that originally featured in the August 2013 issue of Oilfield Technology.

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