Shallow Hazard while Drilling Without a Riser (from a floating rig) and Encountering Gas

According to many company policies, unless circumstances and conditions apply, as stated in the Drilling Policy and Guidelines Manual, the surface hole should be drilled riserless. By doing this, it’s possible to eliminate the most common cause of blowouts in a shallow and pressured gas reservoir (most importantly, the loss of hydrostatic head). Of course, there will still be a risk of penetrating an overpressured reservoir so there must always be a contingency plan in place. Prior to stud, the operator and the drilling contractor must also together on the plan and it needs to include;

  • Common procedure when winching the rig off location
  • Common procedure when a shallow gas flow occurs

Normally, the pre-spud meeting will be the ideal time and place to discuss contingency plans. A 10-degree cone of low-density water is normally produced after a gas blowout in open water and there will also be a discharge of highly-flammable gas. The current and water depth will decide the intensity of the blowout with greater water depth leading to more dispersed water from the plume. When a current is active, the result would be a plume away from the rig.

West Vanguard Blowout

West Vanguard Shallow Gas Blowout

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Introduction to Shallow Gas Well Control

This is the introduction to shallow gas well control which will briefly describe the overview of shallow gas and some related information. We have few articles regarding this topics and we will separate into small parts for better understanding. Let’s get started.

Whenever offshore shallow gas accumulations are seen, they’re normally linked with down sand lenses enveloped by mudstones. Typically, lenses will be permeable, unconsolidated, and highly-porous when found in shallow depths. Although normally flat, thin, and normally pressured, many have previously encountered over-pressured lenses. When at this depth, one cause of over pressure is inclination of the lens; this can therefore increase both the lens height and pore pressure gradient (top of the lens).

Although rare, shallow gas can also be linked with vuggy limestone or buried reefs; these have the risk of being infinitely permeable and incredibly porous.

Shallow gas kick

Shallow gas kick

When drilling in the top-hole section, resulting kicks from shallow sands can be dangerous with short casing strings; there are many case histories to show this. Charged formations can also cause kicks from shallow sands and this itself can be a result of improper abandonments, previous underground blowouts, casing leaks, injection operations, and poor cement jobs.

The example of the shallow gas blow out is below.

Sedco 700 Shallow Gas Blow Out 6 June 2009

 When it comes to shallow gas kicks, the most common cause is a loss of hydrostatic head and this can be a result of two common problems;

  • Expanding drilled gas unloading the annulus
  • Poor hole fill while tripping
  • Losses through the overloading of the annulus with cuttings

In order to minimize the risk of inducing a shallow gas flow, we recommend some general precautions including restricting the rate of penetration, drilling a pilot hole, drilling riserless, and always monitoring the hole.

High flow rates of gas are often produced by shallow gas flows; high quantities of rocks from the formation are also possible. This is particularly true after long sections of sand have been exposed. When a shallow gas flow occurs, the representative responsible should contact a senior contract representative; all non-essential individuals should be evacuated from the rig. This eventuality should always be addressed, and there should be an implementation of the contractor’s emergency evacuation. Continue reading

Possible Wellbore Problems during Well Kill Operation

In the previous article, Common Problems and Complications During Well Kill Operation, it is about commons complications that can be possibly seen while performing well control operation. For this article, it will discuss other wellbore problems which are stuck pipe, surface pressure reaching to MAASP, lost of control and hydrate.

Stuck Pipe

During a well control operation, a stuck pipe can occur and this has the potential to lead to serious issues. Whenever the pipe is off bottom, the chances of the pipe getting stuck increases. Therefore, rotating the pipe should reduce the risk of this problem occurring. However, with the well shut it, it is impossible to rotate to minimize stuck pipe so the stuck pipe should be dealt after the well is properly secured.

Throughout well control operation, wellbore pressures will be high and this means the most common cause of a stuck pipe comes from differential sticking. However, this isn’t to say mechanical sticking can’t occur if the hole sloughs and packs-off after coming into contact with the influx fluids.

Operation can normally continue when the pipe is differentially stuck (with the bit on bottom) because the well can still be killed with circulation. Once the well is killed, then the pipe can be free safely later.

When the bit is off bottom and the pipe becomes differentially stuck, this is a more complicated scenario since it’s more difficult to reduce wellbore pressure; at that depth, it’s normally impossible to achieve a reduction by circulation. Although there may be opportunities to spot a freeing agent and free the pipe, volumetric control is the chosen method if the influx was swabbed in.

When the pipe is mechanically stuck, the pipe can be freed by spotting a freeing agent and working the pipe (by combining the two, the desired result is achievable!).

Stuck Pipe due to Differential Sticking

Figure 1 – Stuck Pipe due to Differential Sticking

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What Cause Lost Circulation in Drilling Leading to a Well Control Situation

Lost circulation whole mud (whether to depleted reservoirs or to natural/induced fractures)is one of biggest causes of well kicks. In the wellbore, fluid levels can decrease and this lowers the hydrostatic pressure. Once hydrotatic pressure is less than formation pressure, it will cause a flow from the formation in permeable zones. Figure 1 illustrates loss of fluid level into a weak zone which will lead a well control incident if a wellbore is not filled up on time with correct mud weight.

Lost Circulation in Drilling Leading to a Well Control Situation

Figure 1 – Lost Circulation in Drilling Leading to a Well Control Situation

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Categories of Well Control

Well control can be categorized into three main categories which are Primary Well Control, Secondary Well Control and Tertiary Well Control. The details are shown below;

Primary Well Control

Primary Well Control is hydrostatic pressureprovided by drilling fluid more than formation pressure but less than fracture gradient while drilling. If hydrostatic pressure is less than reservoir pressure, reservoir fluid may influx into wellbore. This situation is called “Loss Primary Well Control”. Typically, slightly overbalance of hydrostatic pressure over reservoir pressure is normally desired. The basic of maintaining primary well control is to maintain hydrostatic pressure that is heavy enough to overcome formation pressure but not fracture formations.

Figure 1 - Drilling Fluid

Figure 1 – Drilling Fluid

Not only is hydrostatic pressure more than formation pressure, but also hydrostatic pressure must not exceed fracture gradient. If mud in hole is too heavy, it will cause a broken wellbore, that will result in loss circulation problem (partially lost or total lost circulation). When fluid is losing into formation, mud level in well bore will be decreased that will cause reduction in hydrostatic pressure. For the worst case scenario, hydrostatic pressure is less than formation pressure therefore wellbore influx (kick) will enter into wellbore. Continue reading