Fines migration occurs predominantly in clastic formations because they have a high content of transportable materials within the rock. Common fines migration remedial measures include reducing production rates, increasing the flow area by adding perforations or using openhole completions. Engineers may also inject chemical stabilizers that adhere to the surface of fines and reduce their mobility to mitigate the effects of fines migration.
Chemical damage mechanisms are generally divided into adverse rock-fluid interactions, adverse fluid-fluid interactions and near-wellbore wettability alteration. A common chemical damage mechanism is clay swelling, in which hydrophilic materials in the formation, such as reactive smectite and mixed layer clays, are hydrated and expand when interacting with fresh or low-salinity water. This swelling can severely reduce permeability when clay lines the pore throats of a formation. In formations where this potential exists, engineers use high-salinity drilling fluids or add glycols and other chemical inhibitors to keep reactive clays from becoming hydrated.
Clay deflocculation, another common chemical damage mechanism, results from rapid changes in pH or salinity. Clay particles can change from a flocculated state—a condition in which clays, polymers or small charged particles attach to one another to form a fragile structure—and then deflocculate when the electrostatic forces holding the surfaces of individual clay particles are disturbed. Deflocculation can be inhibited by avoiding cationic and pH shocks.
Formation dissolution occurs in formations containing components that are soluble in water-base fluids. This condition may lead to a collapse of the wellbore wall. If the operator uses oil-base fluids or highly inhibitive water-base fluids, formation dissolution can be avoided.
Incompatibilities between introduced fluids and native fluids can lead to the creation of emulsions and sludges that plug formation pores and impair permeability. Introduced solids from drilling and completion fluids may also be chemically incompatible with reservoir fluids.
Wettability alteration is another major formation damage concern. Many common additives, such as corrosion inhibitors, can invade the near-wellbore region and induce a change from water-wet to oil-wet conditions. The formation's permeability to water increases while oil permeability is reduced. The result is an unwelcome increase in produced formation water and a decrease in the oil/water ratio. Wettability conditions are typically controlled by the addition of surfactants and solvents to the drilling fluids.
Biological formation damage can occur when bacteria and nutrients are introduced into the formation. Bacterial contamination is most associated with water injection operations, such as fracture stimulations, but may also occur when drilling with water-base fluids. Biological damage mechanisms can be divided into three main categories: plugging, corrosion and toxicity. Polymers secreted by bacteria may adsorb to the surface of pores in the formation and eventually plug them. Some bacteria induce hydrogen-reduction reactions that can cause corrosion, pitting and stress cracking of downhole and surface equipment. Sulfate-reducing bacteria reduce sulfates in formation or injection water and create hydrogen sulfide [H2S] gas. Biocides or oxygen scavengers may be added to drilling and hydraulic fracture fluids to prevent bacterial damage.
Thermal damage mechanisms occur in high-temperature operations, such as steam injection and in-situ combustion. Thermal degradation of oil and rock compounds that contain sulfate, at temperatures above 200°C [390°F], may produce undesired byproducts, such as H2S and carbon dioxide [CO2]. Elevated temperatures may also lead to mineral dissolution and mineral transformation, in which minerals are catalyzed and transformed from nonreactive clays to reactive products that can swell, merge and reduce formation permeability. This problem is more common at temperatures above 250°C [480°F].
Indicators and Effects of Formation Damage
If a well is producing at lower rates than expected, the source of the reduc-tion must be determined before corrective measures can be attempted. If production engineers determine that formation damage is responsible for reduced productivity, several techniques can be used to verify the cause of the problem. Permeability impairment, skin damage and decrease of well performance are all indicators of formation damage. Skin damage—a mea-sureable reduction in permeability in the vicinity of the wellbore—can occur for a variety of reasons, for example, incompatibility of the workover fluid with the native formation fluids. The incompatibility leads to chemical reactions and scale deposits precipitate, depending on fluid compositions and wellbore pressure. Scale precipitation, or skin, reduces permeability near the wellbore and creates what is referred to as skin effect. If the skin is not removed by remedial measures, such as acid stimulation and carbonate stimulation, it will reduce well productivity.
Reductions or changes in well productivity can be identified through well tests such as pressure transient analysis and productivity index measurements during flow. Laboratory tests can identify damage mechanisms and aid in determining options for avoiding or removing the damage. Drilling, completion and workover data help engineers devise laboratory tests to assess potential damage arising from fluid-to-fluid or fluid-to- formation incompatibilities. For situations in which formation damage has been detected and defined, laboratory tests are used to model the effective-ness of remedial treatments. Because some types of formation damage can be difficult or impossible to reverse, avoidance may be the best approach.
Specialized formation damage analyses can be performed on reservoir rock samples after cores have been extracted from the formation (Figure 2). Formation damage specialists measure permeability changes by testing cores before and after they have been exposed to drilling and completion fluids. The cores are tested at representative downhole temperature and pressure conditions to evaluate the formation damage potential of a specific fluid. After testing, analysts inspect the cores and measure fluid invasion. Data collected from these tests help engineers optimize fluid design and ascertain what measures can be taken to minimize the risk of formation damage.