What Causes Formation Damage? - Part-1

Formation damage is generally referred to as permeability impairment in petroleum reservoirs, which can occur during almost every filed operation, including drilling, completion, production and workover operations, stimulation and remedial treatments, as well as waterflooding, thermal and other enhanced recovery processes.

When the productivity or injectivity of a well is lower than expected, it may be caused by formation damage. Understanding the causes for formation damage is the first step toward the successful control and prevention of formation damage.

During reservoir development, any changes to rock-fluid and fluid-fluid equilibrium conditions can cause formation damage. Most of the damage usually occurs in near wellbore region or around the face of hydraulic fractures.

Fines Migration

Porous media in typical petroleum reservoirs can be viewed to consist of pore throats and pore bodies. As fine particles travel along tortuous pore spaces, particle retention can take three forms: surface deposition, bridging, and plugging. Among these particles retention mechanisms, it is particle bridging and plugging that causes most damage to the formation. Fines that cause formation damage can be either externally introduced or in-situ generated.

When external particles enter the formation, they will fill and plug the pore spaces of the formation near the wellbore and severely reduce the formation permeability. The depth of invasion of fine particles from the wellbore into the formation is dependent on the structure and size of formation pores as well as the shape and size of the particles. Deeper invasion into the formation is favored by large pore size and small particle size. The depth of invasion can signficant if the formation is highly fractured. Once the formation near wellbore becomes totally filled or plugged by particles, a filter cake is established on the formation face, preventing additional particle invasion. Although the external particles usually cannot invade the formation deeply, such an invading process causes extremely severe damage in the formation near wellbore. 

Formation fines can be easily generated in unconsolidated formations during production and reservoir depletion. The problem becomes more severe with larger drawdown pressures and higher production rates. The onset of water production can make the problem worse, as there is a lack of cementation between sand grains and water weakens the bond between grains. These fines will migrate and accumulate in the near wellbore area and inside the wellbore, causing formation damage, sand production, and damages to downhole equipment and surface facilities. 

Nearly all petroleum-bearing, sedimentary formations contain fines and clay minerals. Formation fines are composed of quartz, silica, feldspar, mica, calcite, dolomite, siderite, and chloride. The clay minerals commonly found in reservoirs include smectite, kaolinite, chlorite, and illite. Clays and fine particles are attached to pore surfaces by various forces such as van der Waals, electrical double layer, and hydrodynamic forces. However, rock fluid interactions, high flow velocity, and low salinity of the injected fluids can counteract these forces and often lead to the mobilization of fines. These particles then migrate along the flow paths until they are captured in pore constrictions, and cause formation damage.

Clay Minerals

The presence of clays in petroleum reservoirs is a major factor for formation damage. In order to understand the effects of clays on formation damage, it is important to know their origin and crystal structure. Clays in sedimentary rocks may have two different origins: detrital and authigenic (diagenetic) clays. Detrital clays, which form an integral part of rock framework and are abundant in shale formations, usually do not cause damage to petroleum-bearing formations. Authigenic clays exist as deposits lined or filled in the pore system and do cause formation damage upon contact with various incompatible aqueous fluids during field operations. Clay minerals are composed of hydrous aluminum silicates of either tetrahedral or octahedral patterns. The crystals combine in sheets or layers. Clay minerals can be described according to the pattern of layering of the tetrahedral and octahedral sheets and are referred to as 1:1 or 2:1 type. A type 1:1 clay mineral contains layers of tetrahedral and octahedral crystals in a 1:1 ratio. A type 2:1 clay mineral contains two tetrahedral layers for every octahedral layer. The ratio affects the water adsorption potential of the clay mineral. The basic structure of clay minerals is commonly plate-shaped due to the layering phenomenon. However, elongated, hair-like, and fibrous forms also occur when crystal units combine in a less orderly fashion. The size of clay mineral ranges from a few micrometers down to 0.01 micrometers, which is similar to the size range of colloidal matter. Four major types of clay minerals: kaolinite, smectite (montmorillonite), illite, and chlorite. Each type of clay exhibits a particular problem and has the tendency to cause formation damage. 

Kaolinite is a 1:1 type clay composed of one tetrahedral sheet and one octahedral sheet bound together by strong hydrogen bonds. Kaolinite exhibits little or no swelling characteristics and occurs as platy structures. The maximum dimension of a kaolinite particle ranges between 2 to 4microns. Kaolinites are usually attached loosely to the pore surfaces of the host rock and are released into aqueous fluids by fluid-fluid interactions. 

Smectite is a 2:1 type clay composed of two tetrahedral and one octahedral layers bound together by weak interactive forces. Smectites and mixed-layer clays are referred to as swelling clays. Smectites in particular contain large amounts of sodium ions that cause the mineral to adsorb water and swell several times the original volume in the presence of fresh water. The swelling of smectites on pore surfaces reduces the porosity and permeability of the formation. Smectites can also be released from pore surfaces and migrate during swelling. 

Illite is a hydrous mica and a typical example of the 2:1 type clay. Illite has several crystal structures and sometimes forms an irregular fibrous network in the pore space, reducing the capacity of fluid flow. Illite can also swell when it co-exists with smectite. 

Chlorites are a group of 2:1 type clays and often contain large amounts of iron. During the treatment of hydrochloric acid, chlorites will readily dissolve and the iron will be liberated. When the acid has spent, the liberated iron will then re-precipitate as a gelatinous ferric hydroxide, Fe(OH)3, which has a large crystal size and plugs pore throats. 

Factors that affect formation damage caused by fines and clays include particle and pore size distribution, mobilization and retention forces, salt concentrations, flow rates, pore pressure, and temperature, etc. Among these factors, salt concentrations and flow rates are the most important, and worth discussing in detail.

Salt Concentrations

The concentration of electrolytes in aqueous fluids has significant effects on clay particles, which are negatively charged due to isomorphous substitution of elements in the crystal lattice. Pore walls of sandstone formations are similarly charged. When a charged surface is placed in an aqueous fluid, an electrical double layer is observed at the surface of the particle. The double layer consists of an inner layer of adsorbed ions (Stern layer) and an outer layer of diffusely held ions (diffuse layer). The electrical field near the charged surface decays exponentially with increasing distance from the particle surface. The thickness of the diffuse layer (Debye length) is inversely proportional to the square-root of the electrolyte concentration. A double layer is developed similarly at the pore wall. When the two charged surfaces approach each other, interactions of the two double layers occur. Salinity has a marked effect on water-sensitive formations. Before fresh water is injected into a water-sensitive formation, clays are held on rock surfaces in the formation brine by the net attractive surface forces (van der Waals attractive and electrical double layer repulsive forces). In concentrated brine solution, the diffuse layers are compressed. Consequently, the double layer repulsive forces are less compared to van der Waals attractive forces and clay particles are kept on rock surfaces. As fresh water is injected into the formation, the salinity of the formation brine decreases, the double layers expand, and the double layer forces increase. When the net surface forces can no longer keep clay particles in place, they will be released, migrate, and then plug pore constrictions along the flow path. It was determined that a critical salt concentration exists below which the release of clay particles occurs.

Post a Comment