LARGER DIVERTERS SAFER FOR SHALLOW GAS CONTROL

David Mills
Glasgow Polytechnic
Glasgow, Scotland

Einar Dyhr
Copeman Engineering
Copenhagen, Denmark

Reducing the back pressure buildup on the wellhead during shallow gas control minimizes the risk of the gas broaching the seabed around the conductor pipe. This allows for an orderly procedure to divert the gas.

Most diverter systems cause the gas/sand mixture to approach critical velocity, resulting in extreme wear and short life expectancy of the surface piping. Calculations based on standard drilling programs indicate that only a few existing diverter systems can handle a sizeable volume of shallow gas without creating excess back pressure on the wellhead.

During the past 10 years six jack up rigs have been totally destroyed by shallow gas blowouts. Estimates for the total losses sustained by oil companies and drilling contractors from these accidents has been well over $1 billion.

The following cause the most severe damage from shallow gas blowouts:

Erosion of the seabed and possible cratering of the rig from gas around the conductor pipe
Wear on the diverter system from the high velocity gas/sand mixture, with possible fire threat to the rig.

The diverter systems most commonly used on jack up rigs have flow capacities inadequate to divert large volumes of gas from a large shallow gas reservoir without building excessive back pressure in the well. The large pressure buildup may subsequently fracture the formation at the conductor casing shoe.

If the well is flowed, the diverter pipe will act as a long choke, causing the gas/sand mixture to reach critical speed. This, in turn, will cause the diverter pipe to wear down in a matter of minutes, resulting in a gas fire hazard below the drill floor.

Several industry studies have pointed out the problems associated with excessively long or small diameter pipe used for diverting the gas overboard. Following the West Vanguard accident in Norway, Statoil investigated new ways to extend the service life of the piping system. Some suggestions included the hardfacing of pipes and bends as well as testing of a variable choke mounted on the overboard end of the diverter pipe.

The latest rig design in the Norwegian North Sea requires a minimum diameter of 16 in. for diverter lines, which should run overboard as straight as possible. On a Norsk Hydro platform in the North Sea, the diverter line diameter has been increased to 16 in., and a fixed choke with an ID of 12 in. has been mounted on the overboard end. These changes result in a reduced velocity through the diverter. 5

Outside Norway the most common diverter pipe diameters are between 8 and 12 in.

Oil companies, rig designers, and drilling contractors have indicated a need to develop design criteria for shallow gas surface equipment. The design criteria include a minimum gas flow capacity of the surface piping to prevent excessive back pressure buildup and calculations showing the expected life of the surface system while flowing a gas/sand mixture.

SHALLOW GAS FLOW

High gas flow rates and sonic velocity can occur if high pressure gas is vented to the atmosphere.

Steady state conditions are established for any given difference in pressure between the gas in the well and the atmosphere. This pressure difference provides the driving force for the gas flow, and equilibrium conditions prevail if it is balanced by the gas flow resistance. It is possible to calculate with accuracy the gas flow rate and the resulting pressure and velocity profiles for any given drilling program and surface pipe system.

As a result of the turbulence and the high gas velocity at the wellhead, particles of sand may be carried in suspension by the gas. Gas velocities will not have to be high to convey sand vertically, particularly if the gas is pressurized.

The pressure gradient of the flow increases as the concentration of sand in the gas increases. Steady state conditions also prevail in this situation.

For a given pressure drop, however, the rate of gas flow decreases with an increase in sand concentration. It is also possible to calculate the pressure and velocity profiles for gas/sand suspension flows. However, the result depends on the concentration of the sand in the gas, and this may not be known with any certainty. The concentration of sand may also change with respect to time, further complicating the problem.

Pipe surfaces erode rapidly with the increasing sand impaction. The rate of erosive wear depends on the surface material, the impact geometry, the sand, and the flow conditions. The gas/sand velocity is the most important of these conditions.

Erosive wear increases exponentially with the increase in velocity; the exponent ranges around 2.65. Thus, if the velocity doubles, the wear rate will increase by a factor of about six. 1 Likewise, the wear rate will decrease by a factor of about six if the velocity is halved.

Specific erosion, or the mass of surface material per unit mass of particles impacted, decreases as concentration increases. In a gas flow situation, however, the mass of impacting particles increases with respect to time and concentration. The time factor generally has an overriding effect.

As the concentration of the sand increases, the wear rate also increases. 2

Following extensive re-search programs, models have been developed to evaluate the life expectancy of components for given flow conditions. 3

FLOW CONTROL

The pressure gradient increases with the increase in sand concentration; for a given system pressure drop, the gas flow rate, and hence velocity, falls. The net effect of reduction in velocity and increase in concentration does not result in a significant change in the wear rate. To reduce the wear rate, both the velocity and sand concentration must drop. This can be achieved through the use of an artificial resistance in the flow, or a choking mechanism.

The best location for a choke is at the very end of the diverter (the location of gas discharge to the atmosphere). The use of a variable choke on the diverter makes it possible to control the flow parameters, further reducing wear to the diverter system.

Application of the choke changes the system resistance and alters both gas and sand flow. Choking the flow changes the pressure profile in the system and results in a higher back pressure. Because gas is compressible, its density increases, resulting in a decrease of flow velocity.

The combined effect of a reduction in the gas velocity together with a reduction in sand concentration should significantly decrease erosive wear.

Test work with a variable choke valve has shown that the wear rate is remarkably low. 4 If the variable choke becomes worn such that the throat area increases gradually with time, the desired upstream or discharge conditions can still be maintained with minor adjustments. 6 These choke adjustments can be manual or automatic.

It is difficult to determine exactly how much sand the gas conveys and whether the rate of sand flow changes with respect to time. Reasonable assumptions for sand concentration values allow approximate calculations. For accurate prediction of pressure and velocity profiles, however, it is necessary to obtain some data on the flow parameters.

Ideally the mass flow rate or velocity of the gas can be determined, together with the mass flow rate or concentration of the sand. However, these values are virtually impossible to measure in a well control situation.

It is possible, however, to determine quite reliably the pressure gradient in the system and the absolute pressure at some reference point with two pressure sensors located on the conductor pipe below the diverter (Fig. 1). With the appropriate gas compressibility models for gas/solids suspension flows, it is possible to calculate the pressure profile throughout the entire cased system.

With the pressure data and a computer analysis for a given well configuration and drilling assembly, the pressure at any critical point of the system, such as the casing shoe, can be determined instantly. As drilling proceeds, the well conditions at the casing shoe change, but the required pressure information can be updated.

Computer predictions for casing shoe pressure can be fed as input to the choke valve control system. By this means, the choke valve can be automatically operated to limit the pressure at the casing shoe. In turn, this will limit the gas velocities in the wellhead and surface piping system.

DIVERTER ANALYSIS

For an example analysis, shallow gas is encountered in a well at a depth of 1,475 ft during hole opening operations.

Gas is swabbed in while pulling out of the hole with the bottom hole assembly at approximately 1,400 ft. The bottom hole pressure of the methane gas is 675 psig at 15 C. and 1,475 ft.

A convenient starting point for an analysis of shallow gas control is to consider gas flow only. The conductor pipe and diverter arrangement are shown in Fig. 1.

Fig. 2 presents the results of the pressure profile analysis for the well.

The pressure at the casing shoe reaches about 385 psi when the well flows pure gas. The gas pressure reaches 110 psi (AP) greater than the estimated fracture pressure.

This clearly presents an extremely dangerous situation. In ordinary well control situations 110 psi may not be a significant pressure, but in a shallow gas flow it may be enough to cause broaching of the seabed around the conductor pipe. The pressure of gas with sand in suspension is not likely to be significantly different from that shown in Fig. 2.

The pressure profile shows that the diverter system itself, having a diameter significantly smaller than that of the casing, chokes the gas flow (Fig. 2). The only way to relieve this situation is to reduce the resistance to flow in the surface pipe section, most effectively accomplished by increasing the diameter of the diverter pipe.

This has the effect of increasing the mass flow rate of the gas through the system. The gas velocity profile changes, resulting in a lowering of the pressure at the casing shoe.

The diverter pipe bore has a significant effect on the pressure at the casing shoe (Fig. 3). An increase in the bore from 16 in. to 20 in. recovers the overpressure situation in the previous example. Any further increase in diverter size enables the pressure to drop below the fracture pressure limit.

This safe zone allows for the operation of a variable choke on the end of the diverter line.

Manipulation of a variable choke results in reduced wear to the system and increases the potential for gaining control of the well. 6

REFERENCES

Mills, D., and Mason, J.S., "Conveying Velocity Effects in Bend Erosion," Journal of Pipelines, pp. 69-81, 1981.
Mills, D., and Mason, J.S., "Particle Concentration Effects in Bend Erosion," Powder Technology, Vol. 17, pp. 37-53, 1977.
Mills, D., and Mason, J.S., "Evaluating the Conveying Capacity and Service Life of Bends in Pneumatic Conveying Systems, "Journal of Powder and Bulk Solids Technology, Vol. 3, pp. 13-20, 1979.
Mills, D., "Erosive Wear Tests," Statoil consultancy report, Contract No. T6796, 244 p., September 1986.
Nokleberg, L., Schuller, R.B., and Sontved, T., "Shallow gas kicks, Safety aspects related to diverter systems," SPE Paper 16545/1.
Dyhr, E., "Shallow Gas Well Control," IADC European Well Control Seminar, November 1990.