What Causes Formation Damage? - Part-2

Flow Rates

Fine particles loosely attached on pore surface can also move if viscous drag promotes such movement. It was found by researchers that there is a critical velocity, below which entrainment of particles from pore surfaces cannot occur, and above which the rate of entrainment is proportional to the flow rate.

Scale Precipitation 

Changes in reservoir conditions and/or the mixing of formation water with incompatible injection fluids can lead to chemical reactions, cause some water-soluble chemicals to precipitate out of the aqueous solution as scales, and thus result in formation damage. Scale precipitation can cause both formation and facility damage as it can occur in the reservoir, inside the well and surface facilities. The injection fluids can also dissolve minerals on the pore surface of the formation. The dissolved minerals can then migrate with the injection fluids and precipitate deeper in the formation as reservoir conditions change. The precipitates can accumulate around pore throats and eventually block off flow paths, resulting in reduced permeability. The most common scales in oilfields are calcium carbonate, calcium sulfate, barium sulfate; and other commonly occurring scales include iron scales, silica scales, sodium chloride, etc. Scale precipitation can occur due to any change to the fluid equilibrium conditions such as pressure drop, changes in temperature, hydrocarbon contents, and by other factors such as nucleation sites.

Organic Precipitation

Asphaltenes and paraffins in crude oil are a source of potential organic precipitation. These organic compounds in crude oil can precipitate when the equilibrium is disturbed due to the changes in reservoir temperature and pressure as well as the change in the crude oil composition. These organic precipitates often occur on the tubing wall inside a well or around the nearwellbore area inside the reservoir. It can be quite expensive to treat organic precipitates. The mechanisms of organic precipitation are complex, but a change in temperature or pressure in the reservoir and/or the system is the main mechanism. Damage by organic scaling can not only cause plugging of formation pores but also alter the rock wettability. In the latter case, the rock tends to become more oil-wet, which reduces the relative permeability to oil.

Wettability Alteration

Rock wettability is a major factor when determining the location and flow of fluids in a reservoir formation. In a water-wet formation, water can contact the rock surfaces and occupy the smaller pore spaces. Similarly, in an oil-wet formation, oil can contact the pore surfaces and occupy the smaller pore spaces. Since sandstone formations were formed in aqueous environments, a water-wet condition is expected. However, when oil later migrated into sandstone formations, the oil displaced water from the larger pores, leaving a water film on the pore wall. If the water film broke, oil could contact the pore wall directly. The wettability of the pore wall was then altered by the adsorption of polar compounds or by the deposition of organic matter from the oil onto the rock surface. The degree of alteration in rock wettability is determined by the stability of the aqueous thin film, which depends on the composition of the oil, rock mineral surfaces, formation water, and surfactants introduced during field operation. When the rock surfaces of a formation exhibit oil-wet behavior, the surface area upon which water can come in contact is significantly diminished. The transformation from water-wet to oil-wet in the near wellbore region is not advantageous for production of oil because it will cause a reduction in the relative permeability to oil. 

Clays and fines present on the pore surfaces of a sedimentary rock are usually negatively charged and exhibit water-wet characteristics in their native state. Inorganic particles in injected water or water-based drilling and completion fluids are water-wet. Solids in oil-based and emulsion fluids are oil-wet or intermediately wet. The wettability of such particles plays an important role in formation damage occurring in multiphase systems. It was determined that particle wettability and interfacial tension strongly influence the movement of particles in multiphase flow systems. It was observed that fine particles remain in the wetting phase and therefore become mobile when the wetting phase moves. In addition, it was observed that fines of intermediate wettability are located at the interface of fluids. 

The alteration of wettability to fines and rock surface affect both fine retention mechanisms and relative permeability values. In addition to these potential damages, formation damage can also be caused by the plugging of nonwetting droplets of liquid or gas at the pore throats due to adverse changes in rock wettability.