Well Control And Intervention

A blowout is generally defined as an uncontrolled flow of formation fluids. A surface blowout, then, is an above-ground uncontrolled flow, while an underground blowout (UGBO) is its below-ground brother. Previous articles in this UGBO series show some profound statistics. About 65% of all blowouts are UGBOs. According to insurance experts, UGBOs occur about 1.5 - 2 times more frequently than surface blowouts. The average cost per event approaches $1.8 million. Cumulative costs are believed to far exceed that for surface blowouts. This data demands that we, as a responsible industry, identify common UGBO causes as a means to develop prudent control and prevention methods. Rather than simply defining causes, let's learn from several field examples. As we shall see, a large majority of UGBOs have a common cause. Hopefully, you will be able to quickly identify the source of the problem without further prompting.

FIELD EXAMPLES

Four real-life examples of UGBOs are described.

Example 1: Exceeding formation strength. An offshore operator planned a vertical well with a 11,000-ft TD. Before the UGBO incident, the well had been drilled as shown in Fig. 1. Some pertinent morning report excerpts describe the situation:

Fig. 1. Example 1: Typical UGBO scenario. The kick-equivalent mud weight of 14.35 lb/gal exceeded the earlier LOT results of 12.5 lb/gal. A fracture followed, allowing the original SICP of 700 psi to drop to 580 psi.

"Drilling and surveys from 10,749 to 10,862 ft. Got a drilling break. Picked up the pipe and checked for flow. No flow. Drilled to 10,871 ft. Got drilling break. Picked up and checked for flow. Well flowing. Closed Hydril BOP. Had 16 bbl gain?(later)? Had 750 psi on drill pipe and 700 psi on casing. After 2 min., drill pipe decreased to 620 psi and casing to 580 psi."

In this case, mud weight was 10.5 lb/gal when the kick was observed. Using the original SICP of 700 psi, the kick-imposed equivalent mud weight at the casing seat was:

(see World Oil, Jan. 2005)

The kick-equivalent mud weight ( r _e-k) of 14.35 lb/gal easily exceeded the earlier Leak Off Test (LOT) results of 12.5 lb/gal. A fracture followed, which allowed the original SICP of 700 psi to drop to 580 psi.

Example 2: Exceeding formation strength. The well was planned to 16,500 ft, in abnormally high formation pressures. Casing had been run and cemented as shown in Fig. 3. While drilling with an 8.5-in. bit and a 16.9-lb/gal mud at 16,348 ft, a drilling break was taken. A check for flow showed nothing. Next, the crew pulled up two stands for a wiper trip and a flow was observed. The well was then closed in. An UGBO followed, Fig. 2.

Fig. 2. Example 2: UGBO in a deep well with deep intermediate casing.

Fig. 3. Pre-Drill UGBO analysis shows a deeper casing seat is needed.

There is a lesson here. The two examples above tell the same story: While drilling an openhole section, drilling and kick conditions created kick-imposed stresses at the upper exposed casing seat. These two examples were selected to show UGBO scenarios occurring with shallow and deep casing strings.

Where a shallow surface string exists above a long openhole section, high equivalent-kick stresses can occur. They are the result of higher formation pressures from a deeper formation acting on a shallower zone.

In the above examples, we have "out-drilled our casing seat." This means that the formation pressure experienced while drilling at the bottomhole is in excess of the upper casing seat's ability to resist kick-imposed stresses. In such cases, the options are simple:

1. Continue drilling and pray to encounter only non-permeable, non-porous zones, or
2. Halt operations, cement the existing section, and run an additional casing string.

Unfortunately, all too often, human nature entices us to optimistically follow the first option, with the hope that we'll get lucky or that bad luck always hits the other guy. Halting operations to run an additional casing string when all seems to be going well is a difficult decision.

Let's take a moment to note an important fallacy often followed in casing-setting depth selection. Consider a well with a formation pressure profile shown in Fig. 3. An 11.0-lb/gal formation pressure is anticipated at a 10,000-ft TD. Our mud weight is 11.5 lb/gal (with a 0.5 lb/gal safety factor). A common method is to select a shallow casing depth with a formation integrity equal to, or slightly greater than, the maximum formation pressure at 10,000 ft. In this example, a seat depth of 2,000 ft has an approximate integrity of 12.9-lb/gal equivalent (using Eaton's calculations). This far exceeds the anticipated bottomhole formation pressure of 11.0 lb/gal.

Now, let's assume we are drilling at 10,000 ft with an 11.5 -lb/gal mud, and a kick is taken, requiring a 0.5-lb/gal mud-weight increase to 12.0-lb/gal to control formation pressure. The minimum SICP would be 260 psi, which assumes a quick shut-in with negligible pit gains. Using an equivalent mud-weight equation ( World Oil, January 2005 ), the 260-psi SICP results in an incremental 3.0-lb/gal stress increase at 2,000 ft. Considering that the original mud weight was 11.5 lb/gal, the kick-imposed stresses are 14.5-lb/gal equivalent and exceed the formation integrity, established by an LOT, of 12.9 lb/gal at 2,000 ft. A UGBO is likely to develop.

Kick-imposed stresses are calculated for various depths and shown in Fig. 3. To prevent a UGBO in the event of a kick, the formation integrity must exceed kick stresses. The plot shows that, in this well, this was achieved at 3,000 ft (~13.4 lb/gal formation strength versus 13.1 kick-equivalent stress), which became the minimum acceptable surface casing depth to prevent a UGBO. Note, however, that this depth assumed a quick BOP closure. Large pit gains could require a deeper setting depth.

This is the key point: Statistics show this scenario is the cause of about 75% of UGBOs.

Example 3: Annular gas flow. Flows originating behind casing after cementing are perhaps the second most common UGBO cause. Damage is usually quick and can be extreme. Control options are limited. Loss of the well or a related platform is not uncommon.

Behind-casing, post-cementing flow falls into two, quite opposite causation categories. Fig. 4 shows a casing string or liner required to handle a tight tolerance mud-weight formation-integrity scenario. Additional drilling could require mud weight increases that would exceed formation integrity. Mud losses may have already occurred. The casing or liner is run and cemented in an attempt to isolate the weak zones from the deeper, higher pressured intervals.

Fig. 4. Example 3: Behind casing, post-cement flow.

Running and/or cementing the pipe creates isolation difficulties that can lead to behind-casing flow. Surge pressures can cause mud losses and hydrostatic pressure reductions. Cement densities are usually greater than the original mud weights and can cause losses. If a flow occurs, it can move up the casing-by-casing annulus or through a liner overlap. Also, a cement job that appears successful can fail from kick-induced stresses when drilling below a new casing/ liner seat. In either scenario, the BOPs may not be available to implement conventional well-control procedures.

The second category of behind-casing flows occurs in shallow gas environments and for several causes, most of which are related to cement characteristics. Reaction times may be low and control options are limited. Cratering and rig losses occur more frequently than perhaps commonly perceived.

Example 4: Sidetrack UGBOs. An interesting group of UGBOs can be related to sidetracking operations. In a typical UGBO, the pipe is often stuck throughout most of the openhole section, particularly up to the previous casing seat. This scenario is also common in non-UGBO events where pipe-sticking occurs. Recovery of the original hole and drillstring is seldom economical; the most appropriate operation is often to secure the old wellbore and drillstring with cement and/or mechanical plugs prior to sidetracking. Securing the wellbore/ drillstring is a housekeeping chore that can prove interesting if a UGBO has previously occurred. If not effectively secured before sidetracking, the end result might be surprising and less-than-desirable.

Sidetracking begins by establishing a firm base to initiate the directional work, i.e., setting a whipstock. The oldest, most common approach is to set a cement plug(s) in the openhole above the top of the drillstring fish. (If the drillstring had been stuck up to the casing seat, perhaps only a short section was fished prior to setting the cement plug.) The top of the plug is then dressed, which means the cement is drilled until a firm cement section is encountered. Dressing the plug can result in a short cement section above the top of the fish. A second plug may be required.

The directional drilling begins and is usually blind, i.e., azimuth and angle are uncontrolled. The build angle is low, which results in a hole trajectory dangerously near the old wellbore. Re-establishing communication between the two wellbores, below the top cement plug in the old wellbore, can lead to a live well situation, particularly if the original well had suffered a UGBO and has inherent pressure problems. This can lead to a new UGBO occurrence. This scenario is dangerous and difficult to control, Fig. 5.

Fig. 5. Example 4: Sidetrack UGBOs in a deep well.

Re-entry of the old wellbore from the top is almost impossible. A relief well may be required. An additional complexity arises if the flow is up the drillstring in the old wellbore. An understanding of this UGBO type shows the crucial importance of establishing good safety barriers in the old hole section before sidetracking.

Example 5: Annular cement seal failure. A common production problem that sets the stage for a UGBO occurs during normal production: producing pressures decline, yet pressures in other zones, above or below the producing zone, are native. As the pressure differential increases across the cement barrier, the potential increases to break down the barrier. Failure of the cement seal allows fluids to move vertically, up or down, as dictated by pressure differentials.

Indicators are a sudden and significant increase in the type and volume of produced fluids. If the new flowing zone is primarily water-bearing, produced water volume will increase sharply, usually during the course of one day. Depending on the producing zone characteristics, the sudden influx of water could quickly kill normal production. Perforating and squeeze cementing between the flowing intervals is usually effective at shutting off the flow.

Deep, high-pressure wells can have an affect on cement efficacy over the life of the well. High-pressure production creates casing ballooning over exposed zones. The ballooning serves to assist in maintaining the cement separation between zones. Likewise, production from deep, high-temperature wells create a type of ballooning, even though the tendency is for casing elongation.

If production problems arise that shut off flow at the bottom, the pressure and temperature ballooning effects are reduced. A well that sands up could allow the development of a micro-annulus that could allow gas or water flow outside the casing. An obvious short-term solution is to place the well back on production as soon as possible to reduce or close the micro-annulus. Long-term solutions are usually expensive and depend on well conditions.

Example 6: Downhole pipe failure. Tubing and/or casing failure can result in a UGBO. Its severity is a function of the depth of the leak source and the flowing source pressure. As the leak depth increases, the probability that the flow will find a path to surface is reduced. Also, a deep leak usually corresponds to a higher pressure in the receiving zone, which will reduce the flowrate.

The source pressure varies depending on the zone's production history. A UGBO from a casing leak during drilling can create high flowrates, since the source pressure is usually virgin. If bridging doesn't occur, well-control options for high-rate wells are more difficult. Although this scenario is not common, it has caused a few expensive loss events, i.e., Saga 2-4/14 (1989) where control costs exceeded $250 million, Fig. 6.

Fig. 6. Example 5: Equipment failure resulting in an UGBO in a deep well.

A casing leak UGBO occurring late in the production life of a reservoir may cause minimal problems. Reduced reservoir pressures result in lower flowrates and usually can be easily controlled with water. Complications can arise if junk in the wellbore hinders pumping or running the kill string to bottom.

SUMMARY

These six examples collectively comprise the vast majority of causes of UGBOs. They must be thoroughly understood and should be periodically reviewed to ensure that the drilling team understands them and incorporates their potential into subsequent contingency planning. In addition, their symptoms should be incorporated into well drills to enhance awareness of UGBOs at the wellsite.