## Drilling With Foam

Compute the volume of water required to drop the density of 200 bbl of 11.5-tb/gal CaCl, brine to 10.5 lb/gal.

### Solution:

• 1) From Table B4: %CaCl2I - 36.6 %CaCl,F = 26.7 sp gr = 1.3806
• 2) Using Eq. 8.2:

### H,0/CaClz = 42(1.3806)(36.6 - 26.7)/26.7 - 21.5 gai/bbl

• 3) 21.5 gal/bbl x 200 bbl = 4,300 gal
• 102 bbl (water)

Solids Systems (solids tolerance). The solids concentration in the mud may be used to describe the system. A Clearwater mud has virtually no detectable solids. A low-solids system has some solids, although efforts are usually made to minimize solids concentration. A high-so)ids system is normally used when "mud-making" formations are penetrated or high mud weights requiring barite are used. The solids content of a high-weight mud must be controlled within acceptable ranges. The degree to which formation solids contaminate a water-based mud depends on the characteristics of the continuous phase and the type and amount of clay in the rock cuttings. Excess solids may be controlled by surface mechanical equipment and/or water dilution. Water dilution is the most expensive process for correcting drilled solids accumulation. Fig. 8-8 shows acceptable ranges for mud solids as developed by several mud companies.

Example 8,3

A drilling engineer plans to use a lignosulfonate mud to drill a deep, high pressure well in the Niger basin. The pore pressures are provided below. Develop a mud program showing mud weight, minimum and maximum solids levels, and recommended rhcological properties. Use Fig. 8-8 and Table 18-1. The engineer normally uses a 0.3-lb/gal mud weight safety margin.

Depth, ft 1,000 3,000 5,000 7,000 9,000 10,000 11,000 12,000 14,000 16,000

Pore Pressure, lb/gal

### Solution:

1. Use Fig. 8-8 to obtain minimum and maximum solids,
2. Use Table 18-1 to obtain PV and YP ranges.

Fig. 8-8 Field-developed solids guidelines for clay-based mud systems

 Mud Solids, % Depth, Weight, ft Ib/gal Min Max 1,000 9.3 6 7 3,000 9.3 6 7 5,000 9.3 6 7 7,000 9.3 6 7 9,000 9.3 6 7 10,000 II.1 13 17 11,000 13.6 21 25 12,000 15.0 27 31 14,000 16.4 30 35 16,000 17.2 33 37
 Funnel Viscosity, PV, YP, Sec/qt cp lb/100 ft; 32-40 5-8 5-18 32-40 5-8 5-18 32-40 5-8 5-18 32-40 5-8 5-18 32-40 5-8 5-18 34-40 16-20 5-14 42-46 23-27 5-12 42-48 29-34 5-12 46-52 33-39 5-12 48-54 37-44 5-13

Oil-Based Fluids. Oil-based fluids use crude or refined oils as the continuous phase. These muds may have water emulsified in the oil. Two types of oil-based fluids are commonly used. An oil mud has less than 5% water. An invert emulsion has a water concentration greater than 5%. The oil-based fluids are generally used for specific purposes, such as maintaining hole stability in hydratable formations or drilling hydrogen sulfide-bearing zones. While drilling hydratable formations, it is important that the salinity level of an oil-based mud be maintained at levels greater than the salinity of the formation being drilled. Mud contamination from hydrogen sulfide or carbon dioxide gas can be control led with excess lime in an oil-based system.

Historically, diesel has been the primary oil source for the continuous phase of oil-based muds. Pollution restrictions, especially in offshore environments, have necessitated the use of a mineral oil phase that is within environmental safety levels. Refineries arc now supplying highly processed paraffin-based oils that meet these environmental safety standards. Except for a few physical characteristics, these new oils are handled and mixed in a manner similar to diesel oil.

Aerated Fluids. Aerated fluids used in drilling operations include air. natural gas, mist, foam, or aerated muds. These fluids allow high penetration rates because of the reduced hydrostatic pressure, thus allowing the drilled rock fragment to explode into the wellbore. Lost circulation problems are minimized when using aerated fluids.

Drilling equipment for aerated muds is basically the same as with conventional muds with the exception of compressors and rotating heads. The compressors are analogous to mud pumps. The rotating head diverts the high-velocity air in the annulus through the blowdown line {Figs. 8-9 and 8-10).

Fig. 8-9 Air drilling equipment (Courtesy 1ADC)

Problems associated with air or natural gas drilling are often due to insufficient air volumes for removal of the cuttings. Annular velocity below 2.500 ft/min may not remove the chips. In addition, these high velocities commonly erode and enlarge the wellbore such that a volume previously satisfactory before the erosion will not lift cuttings after the erosion. Surface (low restrictions should be minimized because of the ease at which air or natural gas can be compressed, thereby reducing its flow rate. The approximate required circulation rate for air drilling can be calculated with Eq. 8.4. The equation is based on a minimum annular velocity of 3,000 ft/min to lift the water with air.

Fig. 8-1© Air drilling equipment (Courtesy Gulf Publishing Co.)

Mist or foam drilling is an alternate procedure for lifting cuttings from the hole while reducing the annulus hydrostatic pressures. These fluids with higher viscosities than air or gas do not require the high flow rates. As an example, a stable foam may require only 200-300 ft/min to clean the annulus. Common mud additives for air systems are detergents for foaming, corrosion inhibitors, lubricants for friction reduction, and viscosifiers such as CMC.

Aerated muds are used when greater lifting capacity is required and when a reduced hydrostatic pressure is desired. Air is injected into the mud at the standpipe, circulated down the drillstring, and channeled up the annulus where it expands and reduces the hydrostatic pressure. The required air volume can be computed with Fq. 8.3:

 Where; n = volume percent of air in air-mud mixture al wellhead discharge pressure D - depth, ft w, = initial mud weight, lb/gal wf = desired final average mud weight, lb/gal

The ratio n/{100 - n) is the value of cubic feet of air per cubic foot of mud at surface flow line pressure:

Where:

Q = required flow rate, cu ft/min dH — hole diameter, in. dp — pipe diameter, in. R = expected drill rate, ft/hr D = well depth, 1,000 ft

Field experience has shown that the results from Eq. 8,4 may be 15-20% above the required volumes for dry drilling and possibly 15-20% below the necessary amount for mist drilling.