UNDERBALANCED DRILLING SOLIDS-CONTROL POSSIBLE PROBLEMS

Shale

In general, thick shale sections cause problems with UBD. They slough or cave into the hole. This is probably due to thick shale sections having some elements of laminating, geo pressuring, or sensitivity to water. As a general rule, thick shale sections should not be drilled underbalanced. In the special case of air/gas drilling, shale usually remains stable as long as it is kept dry. Even the small amount of water in mist drilling will destabilize most shale. These formations need to be put behind casing within a few days. Watch out for excessive caving and especially long, thin cuttings. Once caving starts, it cannot be controlled with under-balance operations.

dual deck shale shakers
dual deck shale shakers

Hydrogen Sulfide Gas

H2S gas poses a special problem for underbalanced operations but can be controlled with a specially designed Canadian type of totally closed loop circulating system. Care and training are required in order to prevent H2S from escaping into the atmosphere. Controlling H2S contributes to solids-control problems. Some gas attaches to the solids and must be treated with a scavenger before the cuttings are released to the atmosphere for standard removal with the shaker and downstream equipment. During drilling of short intervals of H2S gas-bearing zones, cuttings may be allowed to settle in the closed separator, from which they can be removed after drilling is finished. A specially designed system may be used to sweeten the H2S gas before it is released to the flare. In 1998, Shell Canada proposed the use of a sweet-gas counterflow system to remove the H2S from the flare gas.

Excess Formation Water

If excess formation water is encountered, the system must be modified to accept it. Large water flows overwhelm the chemistry of the system as well as overloading the liquid disposal system. Small amounts of formation water may require addition of a foaming agent and a corrosion
control agent. Excessive amounts of water require that the system density be increased, the system changed, or the water squeezed or cased off in order to provide adequate hydrostatic pressure to control the volume of water influx.

Downhole Fires and Explosions

Downhole fires are one of the problems that can occur during air drilling. For years it has been suggested that one of the major causes of downhole fires in air drilling was the formation of fluid rings. It was assumed that damp cuttings and poor hole cleaning caused the rings to form. It was also assumed that as the rings became larger, the restricted annulus caused pressures to increase to the point at which spontaneous combustion of the dry gas occurred. The fire would then melt downhole tools, including drill collars. Further investigation has shown that it is impossible to develop pressure high enough to spontaneously ignite dry gas under these conditions. However, distillate will spontaneously ignite at temperatures and pressures that exist in the hole. It is not necessary for fluid rings to develop for combustion to occur. Drilling with a mist does not reduce the chances of downhole fires. The danger of downhole fires, which typically start at about 9000 feet and 150°F bottom-hole temperature, can be avoided with the use of natural gas or nitrogen as the drilling fluid.

Very Small Air- or Gas-Drilled Cuttings

Evaluation of air- or gas-drilled cuttings can be difficult. The extra-small particle size of air-drilled cuttings makes the identification of index fossils very difficult. Air cuttings get smaller as the hole gets deeper. Inadequate hole cleaning and hole erosion can create additional formation identification problems. Inadequate compressor capacity is often the cause of poor hole cleaning. If additional compressor capacity is not available, air requirements may be reduced by decreasing the well annulus area. A smaller annulus imparts higher velocity for a given injection rate. Decreasing hole size or increasing drill-pipe diameter reduces the annulus area. Fine dust should be damped with water and retained in a steel pit.

An equivalent annular velocity of 3000 ft/min is adequate in most cases. When the penetration rate exceeds 60 ft/hr, or when cuttings are large or become wet, higher air volumes are needed to provide higher air velocities to effectively clean the hole during drilling (see Angel, Air Drilling Handbook, for the mathematics of velocity).

Gas-eat-ed or Aerated Fluid Surges

All gas-eat-ed or aerated fluid systems will surge because the gas and liquid are not tied together. Surging can occur during drilling and it becomes worse on connections and after a trip. The volume and pressure surge can change bottom-hole and well-bore pressure by as much as 1000 psi. Changes in circulating pressure, as read on the pump gage, gives an idea of the bottom-hole pressure change. Less air or gas, high fluid viscosity, and smaller annular size all reduce surging. There are other techniques and equipment that also help in surge control. Surges must be evened out for solids control. The easiest way to do that is with a dedicated pit and pump for the shaker.

Foam Control

Drilling foam is a balance between a very weak foam (wet foam) that surges and does not clean the hole and a very strong foam (dry foam) that causes a high annular pressure drop and will not break in the pit. Foam is not ‘‘soap suds.’’ Drilling foam is chemically stabilized gas bubbles in a liquid. Proper drilling foam will carry up to 40% drilled solids and yet break quickly at the separator or flowline. Overflow of the foam in the pits is a sign of poor foam control. Good foam starts with good water. Excessive ionic solids in the water will make the foam more expensive and probably less satisfactory than is desired.

Corrosion Control

The potential for corrosion exists any time oxygen is induced into water. The prerequisites for corrosion control are good makeup water and a 9 pH. Any sign of red rust on the drill pipe or red color in the drilling fluid at the flowline is a sign of corrosion and should be corrected.

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