D.N. Balraj, A. Chandra
Oil & Natural Gas Corp. Ltd.
Dehradun, India
The use of equivalent circulating density (ECD) trend lines and fracture gradient plots provides greater flexibility in choosing the discharge rate required for dynamic well control of shallow gas influxes.
These curves also help the engineer choose the intermediate mud weights and corresponding discharge rates required for a dynamic kill.
The presence of shallow gas complicates well planning and drilling operations. Before a rig is moved onto a location where shallow gas pockets are anticipated, the operator or contractor should identify the depth, the areal extent, the thickness, and the pressure gradient of each gas-bearing zone (using high resolution seismic, if available). When encountered, a shallow gas zone should be controlled first, and then the zone must be isolated permanently prior to drilling additional formations.
The casing shoe depth should be selected mainly to exercise better well control rather than on the conventional kick-tolerance method.
Dynamic well control is suitable when the exposed formations exhibit pressure reversals.
The pressure integrity test is a good tool for evaluating formation strength and limiting parameters for shallow depth well control. Both the pressure integrity test and annular pressure loss test procedures provide a means to estimate working pressure limits for dynamic well control.
SHALLOW GAS
A recent survey found that 9% of the worldwide shallow gas zones occur at depths less than 150 m, 25% between 150 m and 600 m, and 66% between 600 m and 1,500 m. Most shallow gas zones occur in deltaic geologic environments offshore.
In deltaic areas, the depositional environment is unstable. The rapid sedimentation pattern in deltaic areas, irrespective of depth, may be conducive to the evolution of pressure seals (gas pockets), undercompacted layers, and pressure gradient reversals. Because of rapid sedimentation, some interformation layers may exhibit a minimum margin of difference between formation pressure, drilling mud hydrostatic head, and fracture pressure gradients.
In some areas, the effect of upthrust from tectonic movement may cause faults. Such characteristics may give rise to interconnected reservoirs, with pressure regimes extended to near the surface, causing overpressured shallow sedimentary layers.
Fig. 1 depicts the sequence of events in a shallow gas well control event. The rate of penetration is typically faster in shallow sediments. The identification of higher formation pressure zones using conventional methods is difficult.
Because of the shallow depth, a gas influx reaches the surface in a short span of time, and mud is unloaded from the annulus at a faster rate. This quick, drastic reduction in mud hydrostatic head increases the formation gas influx rate.
According to well control events in the drilling literature, the failure rate of conventional well control techniques is high when shallow gas pockets are encountered.
The dynamic well control method should be considered a viable option for killing shallow gas kicks.
PILED CONDUCTOR
Piled conductors are set 30-50 m, to the point of refusal, below the mud line. The diverter equipment is then fitted prior to resuming drilling.
Because there is no cement bond between the piled conductor and the formation, the fracture gradient at the conductor shoe is represented by the frictional resistance between the conductor and formation or weak formation below the shoe, whichever is less. Therefore, to avoid fracturing a formation in the event of a kick, the well bore flow is diverted, and dynamic well control is attempted to regain control.
In this process, the well bore is subjected to the following loads:
- Drilling mud hydrostatic head (gas and mud mixture)
- Annular pressure losses generated by gas and mud mixture movement in the well bore annulus
- Pressure loss generated by the gas and mud mixture flow in the diverter lines.
The well bore pressure is a combination of these three factors. During diversion and well control attempts, the combined well bore pressure may exceed the frictional resistance/fracture pressure gradient limits of the exposed formation. Thus, the influx may surface through fractures or by broaching the seafloor around the casing.
SURFACE CASING
Surface casing is typically set at depths approximately 100-200 m below the mud line and is cemented to surface. The blowout preventers (BOPs) and wellhead equipment are fitted and tested, and then a leakoff test is typically conducted below the surface casing shoe. Generally, the leakoff test/kick tolerance Emit is 1.2-1.3 g/cc mud weight equivalent but may be larger in extreme cases.
With the BOP equipment tested and a leakoff test determined at the casing shoe, the general tendency is to adopt conventional well control techniques if a shallow gas kick occurs. Conventional well control may be suitable for containing a kick, but if the exposed formation below surface casing exhibits pressure gradient reversals, these well control procedures can invite catastrophic well bore conditions.
WELL CONTROL
The well control attempt should avoid pressuring up the exposed formations to minimize formation yielding. The basic requirements for shallow gas well control are to minimize the gas influx rate, to minimize the back pressure effects at the diverting outlet line, and to use annular pressure losses to help control the flowing formation.
A shallow gas influx moves to the surface in a short span of time and reduces the hydrostatic head of the mud in the annulus. The lost hydrostatic head must be regained quickly to minimize the influx rate.
Compared to conventional well control, dynamic well control techniques are faster to setup operationally, allow quick control of a flowing formation, and minimize pressuring up of exposed formations by varying mud pump discharge rates.
In a dynamic kill, the pressure at any depth in the well bore is the hydrostatic head plus the annular pressure loss from that depth to surface. The combined pressure effects on the well bore are difficult to ascertain during well control situations. To help clarify the pressures, drilling mud flow can be used as a model to estimate the well bore pressure limits during dynamic well control.
The following example calculation uses these given data: 600-m well depth, 20-in. casing shoe at 200 m, 8 1/2-in. open hole diameter, 1.08 g/cc mud weight, 12P-160 mud pump, 190 m of 6 1/2-in. x 2 13/16-in. drill collars, and 410 m of 5-in. x 4.276-in. drill pipe. (The accompanying equations are used for calculating annular velocity, annular pressure losses, pressure loss at the diverter, and hydrostatic head.)
The approximate fracture pressure gradient (leakoff test) below the 20-in. casing shoe is 1.3 g/cc mud weight equivalent. Fig. 2 shows the well bore pressure for various diverter outlet diameters.
During normal drilling or circulation, the well bore pressure (ECD1) equals the drilling mud hydrostatic pressure plus the annular pressure losses. The equivalent circulating density, or well bore pressure limit, can be increased from the initial mud weight of 1.08 g/cc to 1.25 g/cc mud weight equivalent by increasing pump discharge rates (maximum assumed rate of discharge for 12P-160 mud pump is 2,600 l./min).
If the same flow rate is diverted through 4 1/2-in. diameter x 1-m long diverting lines, the well bore pressure (ECD2) equals the mud hydrostatic pressure plus the annular pressure losses plus the pressure loss at the diverter outlet line. From Fig. 2, it is evident that, with the increase in discharge rate, well bore pressure increases drastically from 1.08 to 1.83 g/cc mud weight equivalent.
Such an abrupt increase in well bore pressure results from a higher percentage of pressure loss in the small diameter diverter line. When the well bore pressure exceeds the fracture gradient limits of the exposed formations at such shallow depths, additional problems such as mud losses, greater kicks following losses, and gas surfacing through fractures become possible.
If the same flow rate is diverted through 12-in. diameter x 1-m long diverter lines, the well bore pressure increases gradually from 1.08 to 1.29 g/cc mud weight equivalent, which is an acceptable increase when the fracture gradients are known.
DIVERTER SIZE
To accomplish dynamic kill objectives, the pressure loss at the diverting outlet lines must be reduced to acceptable limits. The well bore pressure effects can be minimized by the use of larger (inside diameter) diverting lines.
As a general rule of thumb, the minimum size (internal diameter) of diverting lines should be 1.5 times larger than the hole size drilled. For example, from Fig. 2, an 8 1/2-in. hole should have a diverter of at least 12 in. diameter. In comparison, the American Petroleum Institute, International Association of Drilling Contractors, and U.S. Minerals Management Service recommend diverter sizes of 12-16 in., regardless of the hole size drilled.
ANNULAR PRESSURE LOSS TEST
The well depth, drillstring data, diverter outlet sizes (ID x length), and mud parameters should be recorded. During normal drilling or circulation, the ECD1 trend line should be established:
- Calculate the annular pressure loss at incremental pump discharge rates (Q1, Q2 ... Qn) up to the maximum discharge rate of the available mud pump.
- Calculate ECD1 at each pump rate,
- Plot ECD1 vs. pump rate (Fig. 3).
When the mud flow is diverted, the ECD2 trend line must be found:
- Calculate the pressure loss in the diverting lines. (Note: In general operating conditions, 30-50 m long diverting lines are used. Longer diverter lines tend to impose additional pressure on the well bore.)
- ECD2 = ECD1 + pressure loss in the diverting lines at each incremental discharge rate.
- Plot ECD2 values at each discharge rate to obtain the ECD2 trend line (Fig. 3). The plots of ECD1 and ECD2 show the magnitude of the back pressure effect when the well bore is diverted.
- Select the discharge rate required for drilling (Qd). Draw a vertical line to cut ECD1 and ECD2 at this flow rate and determine the back pressure effects.
- If there is an indication of mud loss, decrease the discharge rate in steps. Record the discharge rate at which the loss is stabilized, and establish the working pressure limit on an ECD vs. discharge graph. If no mud loss is observed, increase the discharge rate in increments, checking for mud loss. Establish the well bore working pressure limit (previous step).
- Repeat this annular pressure loss test at regular intervals to establish ECD and fracture gradient trend lines for shallow formations.
PRESSURE INTEGRITY TEST
An alterative method of predicting fracture pressure gradients at shallow depths is the pressure integrity test.
Once the pressure integrity test values are established at various depth intervals, then planning for dynamic well control at shallow depths is not difficult. Table I lists the leakoff test (at the 20-in. casing shoe at 200 m) and pressure integrity test values at various depth intervals for an example well.
The minimum recorded pressure integrity test value in open hole is 1.23 g/cc mud weight equivalent at 400 m depth. In the event of a gas kick at 600 m, during the well control attempt the combined well bore pressure must not exceed the minimum recorded pressure integrity test value (1.23 g/cc) in the open hole section.
If such formation fracture gradient variations are anticipated at shallow depths, planning for dynamic well control will help in exercising better control of the well. The following steps demonstrate the use of the pressure integrity test in planning for dynamic well control:
- During drilling at shallow depths, record pressure integrity values at various depth intervals.
- Establish an ECD vs. discharge (Q) or ECD1 and ECD2 trend lines for various depth intervals, following the annular pressure lost test procedure.
- Plot the minimum recorded pressure integrity test value minus safety margin on the ECD vs. Q graphs.
- From the plotted pressure integrity test values, draw a line parallel to the discharge line to cut the ECD1 and ECD2 trend lines (Fig. 3).
- Draw a vertical line down from the ECD2 trend line cut point to establish the required discharge rate (Qr) needed for dynamic well control, The difference between the ECD1 and ECD2 lines shows the back pressure effects during well bore flow diversion.
- Select the discharge rate required for drilling (Qd). Draw a vertical line to intersect ECD1 and ECD2. The difference between these two lines is the margin of operating pressure limit available for dynamic well control.
For example, from Fig. 3, the minimum recorded pressure integrity test value in the open hole section is 1.23 g/cc mud weight equivalent, and the initial mud weight is 1.08 g/cc. The discharge rate selected for drilling (Qd) is 1,600 l./min. ECD1 at 1,600, l./min is 1.158 g/cc mud weight equivalent. ECD2 is 1.168 g/cc mud weight equivalent when the 1,600 l./min is diverted.
In Fig. 3, the minimum pressure integrity test value minus a reasonable safety margin is plotted. The required discharge rate is then estimated for dynamic well control when the well is diverted. Qr equals 2,200 I./min at the ECD2 cut point. The margin of difference between Qd and Qr shows the pressure limit the well bore can be subjected to during a dynamic kill.
ECD PLOTS
These ECD trend lines and fracture gradient plots provide greater flexibility in choosing the discharge rate required when attempting a dynamic kill. Most importantly, these curves help the engineer choose the intermediate mud weights and corresponding discharge rates required for a dynamic kill at shallow depths. (The use of a personal computer with appropriate software makes analysis with this method much easier and more useful.)
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
Issue date: 12/12/94