Damage Mechanisms and Identification

Formation damage can be referred to as the mechanism that alters the permeability of the near wellbore region, causing loss of injectivity performance. It has proved to be a major challenge to predict when it is expected, what mechanisms will be involved and what effects the damage will cause. There are many factors that contribute to the formation damage mechanisms. Still, it is not fully known which factors are involved, what effect each one of them has and how they interact with each other. The most general factors involved are believed to be:


The most common form of the formation damage, as identified by researchers:

The effects of these factors are various, many of them interact with each other and many are not considered a major problem in relation to injection of produced water and some can even in some instances have great advantages.

Particle Invasion

Many researchers have studied invasion and formation plugging of small particles in the injection fluid, small enough to flow through the intergranular pore space.

Sources of Particles
The particles causing formation plugging can either be “fines” loose in the formation pores, as described later, or transported with the injected produced water. The latter are of many different types sources, such as:

Particle Plugging Mechanisms
Plugging or bridging due to invasion into the formation of solid particles suspended in the injected water is traditionally the most common explanation for reduced injectivity. Extensive laboratory work has been done in an attempt to gain understanding of the phenomenon to be able to predict the required water quality for injection wells. These observations confirm that small micron size particles, either loose within the formation pores or suspended in injection water, may cause considerable decline in injectivity.

The various investigators studying the issue of particle capturing associated with water injection have given almost as many descriptions on the mechanisms involved. In 1972, Barkman and Davidson of Shell, suggested that impairment from suspended solids occurred by one or more of four mechanisms [Barkman, 1972 ]. Since then, their description has been widely recognised. More recently, Roque et al. of Elf and Institut Français du Pétrole in France, explained the retention of solids suspended in injection water as consisting in four overlapping phases [Roque, 1995 ]. These two descriptions are listed in the table below.

Table 1.   Descriptions of Formation Damage Mechanisms

Barkman and Davidson (Shell), 1972 Roque et al. (IFP), 1995
Wellbore Narrowing: The solids from a filter cake on the face of the wellbore. Deposition onto grain and pore throat surfaces.
Invasion: The solids invade the formation, bridge and form an internal filter cake. Formation of mono- or multi-particle bridges across pore throats, followed by retention upstream from the bridges.
Perforation Plugging: The solids become lodged in the perforations. Internal cake building when non-percolating threshold is reached near the entrance of porous medium.
Wellbore Fill-up: The solids settle to the bottom of the well by gravity and decrease the net zone height. External cake formation.

 

The following is a brief description of the formation damage mechanisms, as described by Roque et al., 1995.

  
Surface Deposition

In this phase, the kinetics of this deposition is strongly anisotropic. The effect of particle deposition on permeability is significant only if it takes place in pore throats. Thus permeability reduction is not related to the total amount deposited but only to the fraction deposited in pore throat area.

        
Pore Bridging

Once a particle is flowing through a pore throat it may get attached to one or more particles already deposited onto the pore throat surface, forming a bridge. Once a bridge is formed and consolidated, the newly arriving particles accumulate upstream from bridged pores, thus decreasing drastically fluid flow rate through these pores.

        
Internal Cake Formation

When the fraction of bridged pore throats reaches a critical value, the pores are no longer connected over some critical characteristic depth (damage depth). Then all the incoming particles accumulate not only upstream from the bridged pore throats but also inside all pore bodies still accessible, forming what is called internal cake.

        
External Cake Building

As soon as internal cake formation is achieved, particles accumulate upstream from the inlet of the porous medium, thus forming the external cake. External cake may also be formed by particles which are bigger then the average pore throat size.

        

Laboratory and field observations confirmed the theoretical prediction that small micron size particles suspended in injection waters may cause severe injectivity decline. In contrast with large particles that form a remediable external filter cake, small particles can penetrate at large distances from injection wells (internal accumulation) where remediation is questionable. The bridging of pore throats is strongly dependent on the effective pore throat-to-particle size ratio, and the pore-throat size is often reduced by previous surface deposition.

Fines Migration and Sanding

Muecke et al. demonstrated with wide variety of microscopic photographs that all natural porous materials contain small mobile solids that uniformly cover the interstitial solid surface of the pore space. These particles are classified as “fines” and are either deposited over geological time or introduced during drilling and completion. Studies on number of sandstone cores in the U.S. Gulf of Mexico showed that typically these fines are (Muecke):

If the fluid saturating the pores is set in motion, e.g. during waterflooding (in water wet reservoirs) these fines can be entrained, and subsequently are either carried all the way through the formation by produced fluids or redeposited at preferred accumulation sites, causing pore restrictions and large reduction in permeability. The trapping mechanism can be simple bridging, flocculation or coagulation. Once bridges are formed they act as increasingly effective trapping the particles that follow, e.g. solids in the injected fluid.

Muecke identified several mechanisms affecting the particle migration, such as particle size, concentration, velocity and interactions of the wettability of the fines and the injected fluid. He discovered that the tendency for bridging is related to concentration but the bridge stability is related to the flow velocity when the bridging occurs. Bridges formed at low rate can be easily broken by varying or reversing the flow or by pressure pulses but bridges formed at higher rate can be very stable.

Gruesbeck and Collins showed that even though fines can be mobilised at very low velocities, they don’t get trapped until the flow velocity has reached a certain critical limit. This critical velocity depends on water salinity, but for corefloods in sandstone with 2-3% KCl, this velocity has been reported to be around 5x10-5 m/s (BP REPORT).

Many researchers have observed fine particles unsuspended within the formation pores [Gruesbeck, 1982], Muecke and others. If the pressure difference is increased by injection, these fines are free to move until they reach equilibrium again, i.e. are re-deposited. During that process, they can plug the pore throats by one or more of the plugging mechanisms described before.

Most researchers assume particles of sub-micron sizes flow through the formation with the injected fluid without being captured. Others claim that this is not necessarily the case, sub-micron particles can also be captured by the same means as the larger particles as well as by van der Waals-type electronic forces [Vetter, 1987].

Oil Droplets Invasion

A special case of “fines” migration is “sanding” of unconsolidated sandstone formations (soft sands). These are dealt with specifically in Task 3.

The stream of produced water will always contain oil even though it has been carefully treated by a free water knock-out drum tanks or modern hydrocyclones. The oil is in the form of:

  • Free oil
  • Emulsified oil
  • Dissolved oil
        

Core flood experiments have shown that the first two can cause permeability damage and the two main processes believed to be involved are:

The free oil can cause a reduction in relative permeability to water where as emulsions can act as a pore throat blocking agent. Coleman and McLelland have shown that for an emulsion to be an effective blocking agent, the oil droplet size should be slightly larger than the pore throat size, as can be seen on the picture on the right [Coleman, 1994].

In core tests made during a design of PWRI scheme below fracture gradient for Shell Nigeria, it was claimed that the greatest contributor to skin damage was resulting from the combination of fines migration and emulsion block in the near wellbore area. Using solvents decreased the injectivity loss of 40-50% [Ohen et al. 1996].

The effects of dissolved oil are not as well understood. Some researchers even claim it has no impact on injectivity [Coleman, 1994].

Pore Blocking of Droplets

Results of core studies indicate that injection of oily water can cause formation permeability to decline and that droplet size can have a greater effect on the permeability decline than oil concentration. In the experiments reported by Todd et al., a dispersion containing 100 ppm crude oil, having a mean diameter of 7.09 mm caused more severe permeability damage to core plugs with a median pore radius of 12.3 mm than another 500 ppm crude oil concentration dispersion having a mean diameter of 3.43 mm. The average permeability decline rate for the former dispersion injected was 2.83% per pore volume injected. The dispersion with 500 ppm and 3.43 mm droplet size injected had a permeability decline rate of only 1.14% per pore volume injected.

Permeability Changes due to Wettability and Surface /Interfacial Forces

Relative permeability is a measure of the ability of the formation to conduct one fluid in the presence of one or more other miscible fluid types. Long-term injection of produced water with oil content of 100 ppm could leave behind a residual oil bank. This could reduce the relative permeability to water and introduce the tendency of other suspended material to be entrained near the wellbore. The result would be injectivity loss due to the formation of a stable emulsion. Ohen et al. studied the increase of oil saturation in the near welbore area as a function of time by injecting synthetic produced water with 100 ppm OIW into cores [Ohen et. al 1996]. After injection of about 5000 pore volumes 10% residual oil saturation had been created and permeability to water had reduced by 70%.

Hydrocarbon Deposition

Not much has been dealt with deposition of hydrocarbon materials in injectors, else than emulsions or free or dissolved oil and these are usually not considered as severe damage mechanisms. Still, reporting on three different mechanisms can be found, mainly where “heavy” hydrocarbons are present:

Wax Deposition

King and Adegbesan reported in-situ wax precipitation associated with particle deposition in injection wells in the Pembina Cardium reservoir in Canada, causing injectivity decline (King, R.W. and Adegbesan, K.O.: “Resolution of the principal formation damage mechanisms causing injectivity and productivity impairment in the Pembina Cardium reservoir.”) [King, 1997].

Organic Deposits

Organic deposits are heavy hydrocarbons (paraffins or asphaltenes) that precipitate as the pressure or temperature is reduced. They are typically located in the tubing, perforations or formation. Although the formation mechanisms of organic deposits are numerous and complex, the main mechanism is a change in temperature or pressure in the flow system. Cooling of the wellbore due to injection of cold water has a much more pronounced effect.

Scaling

Scales are water-soluble chemicals that precipitate out of solution in response to changes in conditions. Scaling is usually caused by incompatibility of injected and formation waters. The formation of scale and subsequent plugging of injection wells can present serious problems in water injection, particularly where PWRI is concerned. Scaling in production systems has been a fairly common experience in the North Sea. The most common types of scale are calcium carbonate, calcium sulphate, barium sulphate, strontium sulphate and iron complexes. Reservoir scaling is not a serious concern in seawater injection schemes. Production well and systems scaling is the major concern and PWRI systems will be similar.

Injection well scaling with PWRI may be more of a concern as a result of the release of dissolved gases and the downhole temperature effect.

Where produced water is re-injected as part of a waterflood operation, the volumes produced will not be sufficient for pressure maintenance purposes, even when significant water breakthrough has occurred. Thus an additional water source will be required unless the reservoir is allowed to deplete. Mixing of sea water and formation water usually causes various insoluble salts to form and precipitate, also causing scaling of the reservoir and production system. In the Pembina Cardium field, analysis of scale samples from an injection well was reported to contain a very high iron content, probably corrosion material from the injection equipment and tubing [King, 1997].

Calcium Carbonate

Calcium Carbonate is by far the most common form of scale encountered. Calcium carbonate scale results from the following reaction:

Ca2+ + 2(HCO3-) = CaCo3 +H2O + CO2

Precipitation can occur in systems where the operating pressure is insufficient to keep the carbon dioxide in solution. Pressure drops and turbulence commonly occur downstream of restrictions in the production string and surface production system. With PWRI, further precipitation may occur in injection wells due to increased temperature and the fact that a portion of any CO2 present will have been separated during topside treatment.

Calcium Sulphate

Calcium Sulphate forms the second most prevalent type of scale generally formed in injection wells. It may occur in three forms:

The pressure and temperature of the system determine the form of calcium sulphate precipitated. Gypsum solubility is much greater than calcium carbonate. Thus, a water containing sulphate, carbonate ions and calcium ions will precipitate calcium carbonate first. However the solubility of calcium sulphate becomes less at high temperatures and some of the deeper hotter fields may encounter this scale. Calcium sulphate scales are found in the shallower tubing and surface equipment, where the pressure and temperature are lower than downhole. But they can also occur in the reservoir at temperatures higher than 110°C.

Barium Sulphate and Strontium Sulphate

Barium and strontium sulphate occurrences are not as common as the two calcium scales mentioned previously. However, some reservoirs contain significant quantities of both barium and strontium ions. When there is mixing between sea water and formation water, such as occurs when injected sea water breaks through at a production well, then sulphate scales will precipitate. Barium sulphate scale can be the most critical type of scale deposit in surface and downhole equipment in oil wells. Since it has the lowest solubility of the sulphates in the mixed water, it precipitates most easily. Hence it can form in the tubing as the fluids rise to the surface. It is not soluble in hydrochloric acid, but can be dissolved with chemicals such as Ethylene Diamine Tetra Acetic Acid (EDTA). Strontium sulphate is more soluble than barium sulphate and hence precipitates more slowly. However, it is still likely to form in association with barium sulphate in the production string, near and on surface and particularly in settling vessels.

Corrosion

Corrosion results from the chemical interaction of the steel with various gasses and fluids found in the down-hole environment leading to the formation of iron sulfide and iron oxide both of which are reactive with acids and other chemicals. Corrosion can also arise from the steel coming in contact with the acid itself. Reaction between water and CO2 can lead corrosion problems. Presence of H2S accelerates the corrosion rates. Common problems associated with iron sulfide are plugging of equipment, filters, injection lines and the formation face. Solution to corrosion mitigation includes water treatment with acrolein [Salma, 2000], biocide [Rosser et al., 1999], sulfur dioxide to scavenge dissolved oxygen. [Nassivera and Essel, 1979; Meyers et al., 1977] to use corrosion resistance steel or alloys [Chitwood and Coyle, 1994; Nielsen and Bingham, 1998].

Bacteria Growth

The role of bacteria in produced water systems and their contribution to plugging, souring and corrosion can be a great concern. Microorganisms can be a source of plugging in much the same way as sand and other agents. Three types of bacteria are of concern in produced water, namely:

Sulphate reducers probably cause more serious problems in oilfield injection systems than any other bacteria. They occur in such quantities that they do not always constitute a menace by plugging with their physical bodies. However, they are of great concern because they induce corrosion and pitting, produce H2S, which will increase the corrosivity of the water, and form iron sulphide solids that may plug injection wells.

The production of H2S occurs by the following mechanism:

SO42- + 8(H) =  H2S + 2 H2O +2 OH-

SRB prefer a neutral pH environment. In the laboratory activity is observed within a pH range of about 5.5 to 8.5. However, in more acidic conditions, the metabolic products of SRB represent buffers namely the HS- H2S and the HCO3-.

Corrosion of surface and downhole equipment has been associated with sulphate-reducing bacteria. It induces iron sulphide solids that, if they become free and are transported to the sandface, could have a plugging effect.

Slime Forming Bacteria

Slime forming bacteria can cause formation damage in water injection wells. These bacteria attach to solid surfaces by a “glycocalyx” film in nature, but do not manufacture this substance in laboratory cultures. Glycocalyx or biofilm layer is a tangled mass of polysaccharide fibres that extend from the individual bacteria cells or colony of cells to allow the bacteria to adhere to surfaces in the oil production system and to rock formations. This film may cover or trap the Sulphate-Reducing Bacteria (SRB). The SRB growth within the biofilm can also generate H2S gas that reacts with dissolved iron to precipitate iron sulphide, increasing solid particle loading in the injection water. The belief is that the glycocalyx is not required in laboratory cultures because there are no forces acting against the bacteria, as there are in a flowing water stream.

Bacteria can produce exopolysachcarides that coalesce to form a confluent biofilm. Oil and solid particles entrained in the injection water can also be trapped by the developing bacterial biofilm to significantly accelerate water injectivity decline rates.

Biofilm growth in surface facilities can interfere with separator and gas flotation cell performance, resulting in increased oil-in-water carryovers. Additionally, underneath the biofilm, corrosion can occur.

Iron Bacteria

Iron bacteria deposit a sheet of iron hydroxide around them as they grow. The iron bacteria are obtained from soluble iron ions in the water. They are classified as aerobic bacteria, although they can apparently grow well with only trace amounts of oxygen. Iron bacteria can cause both corrosion and plugging. Although they do not directly participate in the corrosion reaction, corrosion can either result from the activity of sulphate reducers under the hydroxide sheet or by the creation of an oxygen concentrated cell.

Damage Identification

The objective of damage identification is to aid selection of the optimum treatment or stimulation design. To achieve this objective, certain laboratory tests must be performed. These tests may include:

Core Analysis

The detailed analysis of formation cores is required to design the damage removal treatment. It is difficult to determine formation mineralogy without the use of cores (sidewall or conventional). Conventional cores are recommended to complete the analysis because sidewall cores can be contaminated with drilling fluids and may not be representative of the formation. If sidewall cores are used, the analysis should be conducted on duplicate cores.

Formation Mineralogy

The formation mineralogy is an important parameter affecting stimulation success. Knowledge of the petrography of the formation is essential to understanding what the response of the rock (formation material) will be to any fluid. The relation between the rock and the treating fluid depends on the minerals present and the position of the minerals within the rock matrix. The analytical techniques used to characterize the mineralogy are X-ray diffraction (XRD), SEM and thin-section analysis. XRD analysis provides rapid and accurate identification of the crystalline material of the rock matrix. SEM provides information on mineralogy and morphology and the size of pore-lining materials. Thin-section analysis is used widely to study rock structure and quantify minerals.

Formation Wettability

Most formations (sandstone or carbonates) are water-wet. Occasionally, oil-wet formations are encountered. The simplest test to determine formation wettability is to take approximately 10 cm3 of formation material and place it in the produced brine to equilibrate for approximately 30 min. The formation material is then placed in an oil (such as kerosene) and observed. To accentuate the test results, red dye can be added to the clear oil to aid identification of the oil adhering to the formation material. After it is allowed to equilibrate for an additional 30 min, the formation material is added to a fresh aqueous solution. Strongly water-wet formations or other fines disperse readily in aqueous fluids but agglomerate or clump together in the clear oil-base fluids. Conversely, oil-wet particles disperse in oil but agglomerate in water-base fluids. The surface is water-wet if the contact angle of the fluid with the formation material is less than 90°; the surface is oil-wet if the contact angle is greater than or equal to 90°. Wettability can exist in various degrees between extremely water-wet and extremely oil-wet. Intermediate wettability is difficult to identify and describe, with contact angles greater than 80° but less than 100°. The wettability test can also be used to determine if the desired treatment fluid is water-wetting or oil-wetting and how the treatment fluid may affect the desired natural wettability.

Petrophysical Characterization

Core porosity and permeability should be measured before performing a core flow evaluation. The porosity of the rock sample can be determined using one of several techniques. The simplest technique for the determination of effective porosity uses Boyle’s law; the pressure of nitrogen is determined in a constant-volume cell, with and without the core. The total porosity is derived by bulk and matrix density measurements with a helium pycnometer. When required, the pore-size distribution can also be measured using a mercury intrusion porosimeter.

Permeability, an intrinsic characteristic of the rock, is a measure of the rock’s capacity to transmit fluids. The measurement is usually made with gas (e.g., nitrogen [N2]) or liquids (e.g., brines and oils). Permeabilities must be determined using simulated downhole temperature and stress conditions, especially for stress-sensitive formations such as soft sediments.

Formation Fluid and Produced Water Analysis

Analysis of the formation brine and oil can aid in determining the types of damage that may be present. Analysis of the formation brine can be used to predict scale formation. CaCO3 is usually formed when the pressure is reduced on waters that are rich in calcium and bicarbonate ions. Iron scales such as iron carbonate and iron sulfide can be extremely difficult to remove. They are usually seen in wells that have both a high back-groundiron count and a tendency to precipitate calcium carbonate. Iron sulfide scales react according to their structure. Seven different forms of iron sulfide scale have been identified. Only two of these iron sulfide forms are readily soluble in hydrochloric acid (HCl). The remaining iron sulfide scales are either slowly soluble or not significantly soluble.

Chloride scales, such as sodium chloride precipitation from water caused by temperature decrease or evaporation of the water, are common. There is no effective way to prevent salt precipitation, and salt has a limited solubility in acid.

If the injected fluids are incompatible with the oil, formation of emulsions can occur. The oil may also contain paraffins and asphaltenes. The quantity of various fractions of asphaltenes and paraffins and their ratio to each other are used to assess the possibility of organic precipitation damage.

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