There still is consistent demand for “basic skills” material. A Mid-Continent workshop organized by Dwayne McCune with the University of Kansas Tertiary Oil Recovery Project focused on casing, cementing and well stimulation.

McCune noted the types of couplings and casing commonly used and reviewed critical design parameters: burst pressure, collapse pressure, body yield strength, joint strength, and API design safety factors. When it comes to the design process
itself, there are many software packages available. More than design, McCune emphasized field practices for handling/racking,
inspecting/drifting, numbering and running.

Buddy Petersen and Kevin Brungardt with Allied Cementing Co. LLC addressed cementing concerns. There are numerous
classes of cement, so an operator must study the tables and choose the class that fits his application. Factors that influence
mud displacement include mud conditioning, pipe movement, centralization, fluid velocity, and spacers/flushes. In choosing a
spacer/flush, consider mud properties, mud chemistry, well bore geometry and conditions, and the cement slurry.

Displacement practices, mud rheology and cement slurry design should be tailored for deviated wells. Using a sonic log alone to evaluate a cement job can lead to many unnecessary squeezes. Running both a cement bond log and pulsed echo tool is recommended. Communication among the drilling contractor, cementing company and company representative is essential.

McCune also covered formation damage. Drilling damage can result from solids invasion, fluids, or cement filtrate. To minimize solids invasion, one should include wide particle sizes in muds, have low spurt loss, condition the mud, use a high bit weight and low rpm, use acid, water, or oil soluble additives, and minimize use of barite.

Fluid invasion can cause clay swelling, clay mobilization and water blocking. It can create emulsions, oil wet the formation, and precipitate scales. Use low-invasion fluids, minimize drilling time, use low overbalance, and consider air/foam/gas drilling. Oil-based or inverted muds with compatible fluid salinities also will minimize the effects of fluid invasion.

Approaches for mud removal include inhibited hydrochloric acid, surfactants and mud dispersants. Abrasive jet cleaning also can be used. Surfactants affect wettability and can break or create emulsions. Anionic and cationic surfactants have different effects when it comes to breaking emulsions, forming emulsions, and affecting wettability. Oil-wetting caused by oil-based mud can be reversed by using strong water-wetting surfactants. Water blocks may remedy themselves with time, or they can be relieved by using 2-3 percent surfactant. Clay damage can be addressed by using surfactant with acid, or high pH fluid can be used to disperse clays.

Daniel Klaus with Basic Energy Services covered acidizing. Hydrochloric acid strength varies widely with the application (3
percent for fines suspension, 7.5 percent for sandstones, 15 percent for limestones, 20 percent for dolomites). In sandstones,
hydrofluoric acid often is used in conjunction with hydrochloric acid. To prevent calcium fluoride precipitation, always pump hydrochloric acid first. Hydrofluoric acid never should be used in formations with more than 20 percent limestone or dolomite.

Acetic and formic acids also have their places. Common acid systems include nonemulsifying acids, mud cleanout acid,
iron-reducing acid, iron-chelating acid, Stimsol acid (acid with aromatic solvent), surfactant-based gel system (fracturing, fluid
loss control), hydrocarbon-soluble acid system (acetic acid in a hydrocarbon solvent), and foamed acid (nitrogen or carbon
dioxide). Most acid systems also contain several special-purpose additives.

Slow-rate or matrix acidizing stimulates the pore spaces. The goal with higher rate/pressure acidizing is to create fractures.
Controlling leak-off is critical for acid fracturing. Leak-off can be controlled by viscosifying the acid (emulsified or gelled acid),
adding solid particulates, or using alternating stages of acid and water. Rock properties and fluid loss affect fracture geometry. In
general, fracture height is controlled by pump rate and limiting perforation, while length is controlled by the volume of fluid
pumped. Fracture width is controlled by fluid viscosity.

Water-based frac fluids include linear gels, cross-linked gels and slick water. Foamed (nitrogen or carbon dioxide) frac fluids
apply less hydrostatic pressure, allowing wells to flow back faster. Oil-based frac fluids can be used in water sensitive zones.

It’s widely accepted that adjusting fracture treatments “on the fly” in response to what the well is telling you improves results.
Doug Walser with Pinnacle Technologies reviewed numerous pressure, rate and density charts, challenging participants to identify what was happening and determine the best course of action.

Also serving the basic-skills market, the American Association of Petroleum Geologists has a number of low cost ($34) “getting
started” digital products available at http://bookstore.aapg.org. Topics include coalbed methane, 3-D seismic, carbonate reservoirs, and fluvial stratigraphy. These are a convenient, affordable resource for all disciplines.