Mechanisms of Formation Damage: Solids Plugging
Fig 1.
Illite
Formation damage that occurs when water-based filtrates from drilling, completion, workover or stimulation fluids enter the formation altering the ionic environment of clays via ion exchanges, changes in pH, and/or changes in salinity, thus leading to a reduction in porosity and permeability. Figures 1A-1E show SEM photographs of several different clays: Clay Swelling:
Figure 2: Smectite
Fig. 3 Kaolinite
Fig. 4 Chlorite
Fig. 5 Smectite-Illite Smectite, for example, possesses negative charges on the faces of the clay crystal, while the edges are positively charged. The density of negative charges on the clay structure is determined in terms of the cation exchange capacity (CEC); which is the amount of positively charged ions (cations) that the clay structure can accommodate on its negatively charged exterior. Thus, CEC values are a measure of the clay's propensity to swell under aqueous conditions. Table 1 CEC ranges of several clays. Clay Type
CEC Range (Meq/100g)
Smectite
80 - 150
Kaolinite
3 - 15
Illite
10 - 40
Chlorite
10 - 40
Table 1: Cation Exchange Capacity Ranges of Several Clays1
A common laboratory method for measuring CEC is through multiple salinity tests, a technique used for the determination of the electrical properties of shale containing core samples. In this test, the sample is flushed with brines of different salinities, and the conductivity determined after each flush. A plot of the conductivity of the sample versus the conductivity of the brine gives the excess conductivity caused by clays and other surface
conductors. Then, using a suitable model (e.g., Waxman-Smits, dual water, SGS) it is possible to determine the intrinsic formation factor and porosity exponent, and the cation-exchange capacity.2 Another source of clay disturbance is usually associated with changes to the wetting phase (often native formation water). In the case of smectite and mixed-layer clays (primarily smectite-illite), a change in size due to swelling or water retention enhances their probability of getting dislodged and migrate with the mobile wetting phase. This phenomenon is referred to as swelling-induced clay migration.3 Formation damage which arises when the drawdown forces during flowback or production exceed the cohesive forces between fines and the rock fabric. This in turn causes particles suspended in the produced fluid to bridge the pore throats near the wellbore, reducing well productivity. Fines can include different materials such as clays (phyllosilicates smaller than 4 microns) and silts (silicates or aluminosilicates with sizes ranging from 4 to 64 microns).4 Fines migration can be exacerbated by the use of incompatible fluid treatments. Commercial products have been developed to minimize the potential for fines migration (e.g. resin consolidation, tackifiers, and covalent bonding of polymers). Fines Migration:
Ultra-thin tackifying agents (UTTA), like Halliburton's SandTrap®, have been developed to stabilize fines in high-rate producing or injection wells. These systems can be applied during initial fracturing or gravel-packing operations, as a remedial treatment, or as a follow up to fracturing or acidizing treatments. Schlumberger's K300 is an example of technology based on the polymerization of resin. All of the developed products address the issue of fines migration and have similar solutions. They all involve the application of some form of coating to adhere fines to the mineral surfaces. Advantages of resin consolidation are that it is suitable for through-tubing applications, applicable in small diameter casing, and that it can be applied in abnormal pressure well.5 Problems arise because resin consolidation involves multistage processes in which several fluids must be uniformly applied sequentially into a perforated interval and frequently are highly toxic and relatively expensive. Moreover, resin consolidation can significantly reduce the permeability to oil by changing the wettability of the rock and by occluding the pore space with resin. Formation damage that results from the production of sand and its subsequent movement into pore throats and ⁄ or proppant-packs, causing plugging and productivity impairment. Key factors influencing sand production are: Sand Production:
Degree of formation consolidation which depends on cementation of sand grains around the perforation tunnel, the geological age, and depositional environment. Reduction in pore pressure throughout the life of the well which results in an increasing amount of stress on the formation sand, causing it to break loose from the matrix and get crushed, thus creating movable fines that are produced along with the wellbore fluids. Production rate of reservoir fluids which creates a pressure gradient and frictional drag forces that exceed the formation strength. Thus, there is a critical flow rate below which these forces will not exceed the formation strength. Reservoir fluid viscosity which plays a vital role in the case of heavy oil reservoirs with low-gravity, high-viscosity oils even at low production rates.
Increase in water-cut influences sand production twofold. On one hand it decreases the relative permeability of oil over the time after production, thus increasing the pressure differential and induced stresses required to produce the well at the same rate, yielding sand production. On the other hand it increases the likelihood of water-wet particles to move along with the aqueous (wetting) phase.
Sand production is detrimental to productivity over the life of the well. Some of the issues seen with sand production are: Plugging of perforations, reducing production efficiency.
Erosion in surface and downhole equipment when the velocity of sand is high, increasing the need for workover treatments. Collapse of formation may take place due to void formation around perforation tunnel over the time as sand is being produced, decreasing permeability and increasing pressure drop.
Sand control can be achieved through various means including reducing drag forces (i.e. lower production rates), mechanically bridging sand (e.g., gravel packs), and resin consolidation. An example of resin consolidation is the silanol resin consolidation system. This sand control technology is a resin s ystem consisting of aromatic polyester amide and tri-alkoxy organosilane. The tri-alkoxy organosilane acts as a coupling agent between the reservoir sand grains and aromatic polyesteramide which acts as the load bearing resin due to the pore pressure gradient and overburden stresses. It is applicable at high pressures and temperatures, from about 50°F to 450°F. When in contact with formation water, the chemicals react to hydrolyze it at the specific sites to form silanol glue which bonds the sand grains together, forming a strong bond. Additional information can be found in SPE paper 120472. Formation damage caused by perforating is one of the highest risks in well completions. As shown in Figure 26 (Published by Schlumberger ; Used courtesy of Schlumberger; Permission obtained Sept. 9, 2009 ), common types of damage that can occur inside the perforation tunnel are fractured and compacted zones, perforation gun debris, and the reaction of perforating charge liner materials (e.g. zinc) with high density brines upon detonation, seen in Figure 3. Perforating Charge Debris:
When sprayed into clear completion brines at a high detonation temperature, high surface area particles become activated and then react with the aqueous phase to form metal oxides, metal hydroxides and hydrogen gas. For instance, when calcium chloride completion brines are used along with perforating charge cases containing zinc alloy materials, a number of chemical reactions may take place, resulting in the formation of cementing materials that can significantly block pore throats (SPE paper 58758). Equations 1A-1D demonstrates the sequence of chemical reactions leading to the formation of cement type materials. Moreover, the chemical nature of the reaction products suggests that typical scale inhibitors might function to reduce interparticle associations and minimize the cementing or agglomeration process.7 Zn° + H2O → H2(g) + ZnO(ppt)
Equation 1A: Zinc Oxide Precipitate Formation Reaction
Zn° + 2H2O → H2(g) + Zn(OH)2(ppt)
Equation 1B: Zinc Hydroxide Precipitate Formation Reaction Zn° + CaCl2 + 2H2O → ZnCl2 + Ca (OH) 2(ppt) + H2 (g)
Equation 1C: Zinc Chloride & Calcium Hydroxide Precipitate Reaction xZn (OH)2 + yZnCl2 + zH2O → 2Zn(x+y)(OH)xCly(H20)z(ppt)
Equation 1D: Complex Zinc Hydroxy Chloride Precipitate Formation Reaction
High-temperature ⁄ high pressure (HTHP) wells are particularly susceptible to this source of damage. A post perforating acid treatment can be performed in order to revert some of the damage; however, as formation temperatures increase, metal corrosion and acid sensitivity of the formation become problematic. At higher temperatures, organic acids are frequently used, but many of them do not have the acid strength or the capability to dissolve zinc or zinc salts. The long-chained organic acid HTO has been shown to dissolve zinc and perforating gun debris. The solubilities of zinc metal and gun debris at 250° F (121° C) are shown in table 2. It is estimated that typical weights of debris can range from 0.2 lb/ft (1.4 kg/m) in low debris carriers to 1.4 lb⁄ft (13 kg⁄m) in steel carriers at a 12 shot⁄ft density. At the higher temperatures, above 250° F (121° C), a savings
of up to 20% on acid volume can be realized based on the increased dissolving power of a long chained organic acid (e.g. HTO). Table 2 shows the solubilities of zinc and gun debris in different acids at different temperatures. 10% Formic Acid
10% Acetic Acid
10% HTO Acid
Zn metal @ 21° C
0.10 lb⁄gal
0.02 lb⁄gal
0.09 lb⁄gal
Zn metal @ 121° C
0.28 lb⁄gal
0.24 lb⁄gal
0.34 lb⁄gal
Gun Debris @ 21° C
0.23 lb⁄gal
0.27 lb⁄gal
0.17 lb⁄gal
Gun Debris @ 121° C
0.28 lb⁄gal
0.27 lb⁄gal
0.28 lb⁄gal
Table 2: Zinc & Gun Debris Solubilities in Various Acid s8
Particle Precipitation: Formation damage caused by the formation of an insoluble material in a fluid. Particle
precipitates can be classified as organic, inorganic, or organometallic. Inorganic:
Calcium carbonate (CaCO3) scale, the most common inorganic scale, precipitates as pressure is reduced and CO2 is given off from the formation water and calcium scale is deposited. The production of scale produces a further drop in reservoir pressure, causing more scale to be formed. The deposition takes place through the following reaction (Equation 2): Calcite:
2+
Ca
+ 2HCO3 → CaCO3 (s) + CO2 (g) + H2O
Equation 2: Calcium Carbonate Scale Formation Reaction Induced scaling also occurs by mixing of formation brine with extraneous incompatible fluids invading the reservoir during drilling, cementing, completion, and workover operations. For the example above, any increase of the dissolved calcium (Ca 2+) cation concentration caused by these operations is compensated by calcium carbonate (CaCO3) precipitation.9 Effective calcium carbonate scale removal can often be achieved through acid treatments, as CaCO 3 is highly soluble in acid. However, spent acid can contain high concentrations of scale producing ions, often leading to short lived stimulation treatments as the calcium carbonate re-precipitates around the near wellbore region. Also effective are chelating agents, but they can be expensive. Chelating agents work by preventing the chelated Ca2+ cations from re-precipitating after treatment. In order to prevent calcium carbonate scaling, inhibitors squeezes have been used. These treatments work by either adsorbing onto the formation material, providing a prolonged treatment through desorption into production fluids, or through a precipitation mechanism. The precipitation mechanism functions by precipitating a calcium salt into the pores which dissolve over time during production, providing inhibition. This method might increase treatment life, but also presents the possibility of inducing damage into the producing formation.10 Barite Scale: Barium sulfate (BaSO 4) scale formation occurs when the concentration of barium sulfate exceeds
the saturation point, causing the excess BaSO 4 to precipitate. The saturation point of an aqueous solution dependent upon temperature, pressure, and solvent composition. Solubility of barium sulfate increases with temperature, pressure, and salt content of the brine. Factors that commonly induce BaSO 4 are lower temperatures, brine dilution, pressure drops, and mixing of incompatible waters. The deposition takes place through the following reaction (Equation3):
2+ (aq)
Ba
2-
+ SO4
(aq)
→ BaSO4
Equation 3: Barium Sulfate Formation Reaction Barium sulfate scale is especially difficult to remove through acid treatments due to the high cost of treatments. However, EDTA and nitrilotriacetic acid (NTA) are two chemicals that can be used for removal. Mechanical removal and coiled tubing operation are the only effective methods of BaSO 4 scale removal. Laboratory test should be performed to determine the inhibitor concentration needed to prevent barium sulfate scale formation and to evaluate the effectiveness of the inhibitor as changes in temperature, pH, and salinity. Inhibitors commonly used are phosphonates, phosphate esters, polyphosphonates, and polymeric species. Additional treatments can include: squeeze treatments, continuous injection (upstream of known risk points, capillary string injection), precipitation squeezes (where scale inhibitor precipitates and dissolves slowly over time into the brine), solid inhibitors (placed in the rat hole, associated with proppant), scale inhibitors included in hydraulic fluids, or gas lift deployed inhibitors.11 Calcium sulfate (CaSO 4) scale deposition is largely dependent upon pressure changes. The deposition takes place through the following reaction (Equation 4): Anhydrite Scale:
2+ (aq)
Ca
2(aq)
+ SO4
→ CaSO4(s)
Equation 4: Calcium Sulfate Scale Formation Reaction Temperature is also a factor, with higher temperatures lowering the anhydrite solubility and increasing scaling tendency. In seawater injections, scale such as anhydrite will become more significant as seawater breakthrough occurs. There are 3 available methods for chemical removal of anhydrite scales.12,13
Inorganic converters, which modifies the scale into an acid soluble byproduct. This method will also remove other acid soluble materials present. Organic converters, which converts the scale into a dispersion/sludge that is able to flow. This method can include an acid treatment or not. The acid treatment will effectively remove the reaction products because they are soluble in acid. Chelants, which work by complexing the Ca2+ ions. This method effectively reduces the ions capacity to re-precipitate. Inhibition of anhydrite scale could involve polyphosphonates or polyorganic acid salt compounds.
Salt scale that can be formed during production of high salinity (>200,000 ppm) formation brine as seen in Figure 8. Halite formation may also occur during the evaporation of water into the gas phase. Halite scale is normally easily removed with periodic fresh or low salinity water flushes. Removal can also be achieved with continuous dilution of the fluid stream with water upstream of where deposition occurs .14 Depending on the rate of the salt deposition and the availability of fresh water, such flushes could become an expensive removal method. An example of a salt inhibitor used is potassium hexacyanoferrate (HCF). HCF is a well-known species which has been applied as an anti-caking agent in cooking, and as a drilling-fluid additive for drilling through salt layers, where it both limits hole wash-out (because it also reduces the rate of salt dissolution) and prevents salt from crystallizing from the returned fluid as it cools and becomes supersaturated in salt.15 Halite Scale:
Scale that can occur whenever sources of both iron and hydrogen sulfide are present. H 2S can result from the presence of sulfate reducing bacteria, thermal sulfate decomposition or introduction to a well through gas lift operations. Iron sulfides are able to enhance the corrosion process, decrease productivity, and negatively affect oil-water separation activities. Iron sulfide exists in numerous crystalline forms with numerous acid solubilities. The FeS species responds well to HCl treatment, but the longer the contact time between FeS and H2S the more likely that the scale will become richer in sulfur. While FeS may be effectively removed with acid, FeS2 is not. Since iron sulfide is normally oil-wet, scale removal is impeded. To correct this, adding surfactants and water-wetting agents is important. Acid treatments should also have a corrosion inhibitor, an iron control agent, and a hydrogen sulfide scavenger. Toxic H 2S is produced by the following reaction (Equation 5) between FeS and HCl: Iron Sulfide:
FeS(s) + 2HCl (aq) → FeCl2 (aq) + H2S (g)
Equation 5: Hydrogen Sulfide Gas Formation Reaction
FeS will also precipitate as H2S continues to react with any ferrous iron present at pH > 1.9. If ferric ion is present elemental sulfur can precipitate, which is insoluble in HCl and needs expensive organic solvents to remove.16 Understanding the source of iron and sulfide is key to preventing iron sulfide scaling. Iron can be present in the formation water or supplied by tubing corrosion. If the iron is supplied by tubing corrosion, protecting the metallurgy could reduce the potential for iron sulfide scale. If the iron is present in the formation water, the course of action should be to limit the amount of H 2S through biocides, injection water sulfate ion minimization, or injection of nitrates. One chemical treatment option is tetrakis hydroxymethyl phosphonium (THPS), used to dissolve or chelate iron sulfide once it is formed.17
Organometallic:
Formation damage caused by fluctuations in the reservoir water pH, resulting in the formation of organic scales, carbonate deposits, and the stabilization of emulsions. Reservoir water is naturally saturated with CO2 in equilibrium with bicarbonate anion (HCO3-) as shown in the following reaction (Equation 6): Naphthenates:
-
+
CO2 + 2H2O → HCO3 + H3O
Equation 6: Reservoir Water Equilibrium Fluids injected into the well for various procedures can alter the temperature, pressure, and composition of the fluids in the near wellbore region. Precipitation can occur during production by a chemical reaction of two or more ions in solution or by changing the temperature⁄pressure of a saturated solution which causes a drop in
solubility. Scale can also precipitate due to the mixing of two incompatible fluids, and with the release of CO 2 brought on by a pressure reduction. These pressure drops are accompanied by an increase in pH and oftentimes, the formation of mixed carbonate and naphthenate deposits inside tubing or surface installations, as well as the creation of stable emulsions due to the surface-active naphthenate group RCOO-. Naphthenic acids, R-COOH, are often present in crude oils and the hydrophilic nature of the carboxylic acid group means that they congregate at the oil-water surface .18 Examples of their structures can be seen in Figure 11. Oil and formation water composition is very important in the formation of naphthenates. These variables are naphthenic acid concentration and composition, formation water cations, bicarbonates and pH. Crude oils that present the biggest complications are ones with high total acid number, TAN, and high concentrations of naphthenic acid. Naphthenate problems can be exacerbated by the presence of solids such as formation sand and fines, waxes, and other types of scale. The stability of emulsions containing naphthenic acids has been shown to be a function of pH, asphaltene⁄resin ratios, naphthenic acid types, and cation content of the aqueous phase. Sodium rich emulsions lead to less separated water volume over time, showing the stability of the oil-water emulsion. Calcium rich solutions lead to less stable emulsions, possibly due to excess ionic strength in solution. Sarac and Civan 19 determined through experimentation that the critical minimum initial brine pH required for the onset of naphthenate precipitation to be 5.91. As pressure drops occur during production, degassing of CO 2 takes place, raising the pH of the formation brine and promoting the dissociation of naphthenic acids as shown in Eq uation 7.
-
-
R-COOH + OH → R -COO + H2O
Equation 7: Naphthenic Acid Dissociation
The naphthenate ion is very reactive and tends to complex with Na+ and Ca2+ cations to form sodium and calcium naphthenate scales as shown in Equation 8 and Equation 9. Naphthenate deposits normally collect in oil ⁄ water separators but can deposit in tubing and pipelines as well. -
2+
2R-COO + Ca
→ (R -COO)2Ca
Equation 8: Calcium Naphthenate Formation -
+
R-COO + Na → R -COONa
Equation 9: Sodium Naphthenate Formation Due to its high molecular weight, calcium naphthenate is less soluble than sodium naphthenate in water. This is important because when calcium carbonate and calcium naphthenate form together, the carbonate will decrease the formation of naphthenate. This is due to the reduction in available calcium cations for reactions with the naphthenate anions. When evaluating the stability of emulsion and the amount of naphthenate deposits during processing of acidic crude it is important to take into account the following criteria: 1. Water pH value at process conditions as well as the level of bicarbonate and calcium content at reservoir conditions. 2. Total Acid Number (TAN) of crude oil.20 TAN is the amount of any acid contained in an oil sample. While the test is unable to determine specific types of acids, it is useful in determining if a sample of oil will be corrosive or not. The threshold for corrosive oils is 0.5 mg KOH⁄g oil. Acidizing with HCl and ⁄ or acetic acid is often used to remove naphthenate deposits. An example of naphthenate deposits can be seen in Figure 12. Additional information on naphthenate formation, prevention and mitigation can be found in SPE papers 93407, 80395, 112434, and 68307. Organic:
Formation damage resulting from organic deposit which hamper the production of crude oil. Paraffins are alkanes of relatively high MW (C 18 to C70), which can be either straight-chained or branched. They have specific solubilities and melting points. Because these hydrocarbons have satisfied valence electron configurations, they are almost completely inert to chemical reactions and, as a result, immune to attack by bases and acids. Asphaltenes & Parrafins:
Paraffin waxes are soluble in most liquid petroleum fractions, and their solubility normally decreases as MW increases. Hence, they are soluble in both straight-chain and aromatic petroleum derivatives. They are deposited as solids when the temperature drops below the cloud point for the particular crude oil. SARA analysis can be performed to determine the different constituents present in oil. SARA is a method for characterization of oils
based on fractionation, whereby a heavy oil sample is separated into smaller quantities or fractions, with each fraction having a different composition. Fractionation is based on the solubility of hydrocarbon components in various solvents used in the test. Each fraction consists of a solubility class containing a range of different molecular-weight species. In this method, the oil is fractionated to four solubility classes, referred to collectively as SARA: Saturates-Aromatics- ResinsAsphaltenes. Saturates are generally paraffins, while aromatics, resins, and asphaltenes form a continuum of molecules with increasing molecular weight, aromaticity, and heteroatom contents. Products like Halliburton's Parachek® 160, a polymeric paraffin inhibitor, alter the paraffin structure, decreasing its tendency to precipitate .21 Common solvents used for paraffin removal include condensate, kerosene, and diesel (straight-chain hydrocarbons). Asphaltenes on the other hand are black, polycyclic aromatic, complex compounds, seen in Figure 5. Published by Experimental Soft Condensed Matter Group ( Harvard ); Permission to use obtained Aug. 3, 2009. Generally, they are spherical, 30Å to 65Å in
diameter, with MW of 10,000 to 100,000.
These molecules are held in suspension by surrounding asphaltic resins (maltenes). Asphaltenes polar properties result from the presence of oxygen, sulfur, nitrogen and various metals in their structures. Figure 7 shows the blockage that can occur resulting in severe damage. Published by London Center for Nanotechnology; Permission to use obtained Sept. 9, 2009. Deposition occurs not only by temperature ⁄ pressure reductions, but also by destabilizing factors which act on the resins such as contact with acid, CO 2, or aliphatic solvents, that act on the micellar colloidal suspension to strip away the maltene and resin from the micelles. Removal is possible, but selecting the appropriate method is crucial and can be accomplished by field tests. While condensate, kerosene, and diesel are commonly used to dissolve paraffin, they should not be used when attempting to remove asphaltenes. These non-aromatic hydrocarbons, if used, can cause further precipitation of the asphaltenes as the maltene stabilizers are disturbed. Instead, aromatic chemicals such as xylene can be used. Their power can be enhanced by almost ten times with the addition of approximately 5% by volume of a specific primary or secondary amine, such as Halliburton's highly polar organic Targon® II .22 Closely monitored, due to low flash points, moderate heating will hasten the removal process. New solvents that are non-toxic, biodegradable, and work similarly are available, such as Dowell Schlumberger's PARAN ECO®. Another asphaltene solvent is Tretolite's Parid® PD-72, which is a mixture of toluene and a surfactant. While continuous or batch pumping methods are employed, the batch method is recommended with the solvent left in contact with the asphaltenes for up to 24 hours. Common methods for organics scale removal are mechanical, solvents, heat, and dispersants . Hydrates: Hydrates are solid, white, crystalline substances, with cellular structures, formed as a result of water
vapors and gaseous hydrocarbons interaction in the presence of water and under high pressure and low temperature conditions (T > 32° F) as shown in Figure 9. There are three common types of gas hydrate inhibitors; thermodynamic, kinetic, and crystal size modifiers. Thermodynamic inhibitors (e.g., inorganic and organic salts, glycerol or low molecular weight glycol, combination of salt and glycol) work upon injection by preventing the formation of hydrogen bonds or destroying them. Kinetic inhibitors (e.g., polymers and
surfactants) work as a slow reaction to delay nucleation or slow the crystal growth rate. Crystal size modifiers, also known as crystal habit modifiers, do not prevent hydrate formation. Instead, they act as anti-agglomerates to ensure that hydrates form a pumpable slush so that fluid flow is maintained. Bacterial Growth
Formation damage that is caused by the introduction of bacteria while aqueous phase fluids are utilized and improper bacteriological control is maintained. Bacterially induced formation damage is a particularly insidious type of formation damage in that the apparent harmful effects of the introduction of the bacterial agents are usually not noticed until well construction materials fail catastrophically. Bacteria which cause formation damage can be classified into two types, aerobic and anaerobic. Aerobic bacteria require a constant source of oxygen to survive and are mainly problematic with long term water injection operations. Anaerobic bacteria do not require oxygen and tend to be more widespread and problematic. Both types present issues with plugging, corrosion and toxicity.23 Corrosion is caused by anaerobic bacteria, sulfate reducers, which digest sulfate in water to produce corrosive hydrogen sulfide. The resulting iron sulfide corrosion product, particularly in combination with small amounts of oil, can significantly plug water treatment and injection facilities. Slug treatments with bactericide are usually effective in controlling the anaerobic sulfate reducers .24 Other alternatives (still in early development stages) rely on the use of phage cocktails to target specific bacteria within the reservoir and/or in pipe lines.25 Polymer Plugging
Formation damage caused by the addition of polymers typically used to provi de clay stability and ⁄ or control fluid losses during drill-in and completion operations. Chemical fluid loss control (FLC) materials can be grouped into two categories, solids laden and solids free. Sized salts, calcium carbonate, and organosoluble resins are three types of solids typically used as FLC materials. Solids free FLC pills, on the other hand, may consist of linear gels (e.g., Liqui-Vis® and Bromi-Vis®), crosslinked gels, as seen in Figure 13 (e.g., KMax™, Max Seal™, TekPlug™, and Protectozone™), and the more recently developed viscoelastic surfactant gels (e.g., ClearFrac™).
Solids Laden FLC: The
most widely used solids laden FLC materials consist of sized CaCO 3 particles suspended in a polymer matrix. Computer software is used to determine the optimum CaCO 3 loading and particle size distribution to form a seal against the formation rock and minimize fluid losses. The pill can be either bullheaded or spotted with a coil tubing unit. The pill is usually removed with an acid treatment (e.g., HCl or HCl⁄acetic). Other clean-up alternatives include breaker systems (internal or external) based on polymer-specific enzymes, and ⁄ or chelating agents. An alternative to the calcium carbonate⁄polymer system, particularly for injector wells, is the salt⁄polymer system which consists of ground sodium chloride in saturated NaCl brine ⁄ polymer matrix. Since sodium chloride is readily
soluble in water, produced water or unsaturated brine treatments will afford removal of residual salt solids. Depending on the polymer uploading in the FLC pill, an acid treatment may also be required. Santrol's Collagen or synthetic polymer balls are also readily dissolved in the presence of unsaturated brines, and thus constitute another alternative for water-soluble FLC materials, particularly for injector wells.26 Oil soluble resins such as benzoic flakes, may be used as FLC materials in low to moderate
temperature producer wells. Resins are typically added to completion brines and delivered to the formation where they plate out onto rock surfaces. After the completion operation is finished, produced oil or condensate flowing over the resin gradually dissolves it. As with the introduction of any foreign fluid into the formation, there are advantages and disadvantages to be evaluated before using a FLC material. Table 3 highlights the strengths, limitations, and costs of the three general types of bridging solids used for FLC. Particulate
Strengths
Limitations
Cost
CaCO3 ⁄ Polymer
Inexpensive Relatively easy to mix Good for bridging on gravel and frac packs Used when lower densities are required
Can plug perforation tunnels Highly damaging if particles are not sized properly Polymer damage may require remedial treatments May cause tools to stick Degradation depends upon contact with acid for removal
Relatively low
NaCl ⁄
Relatively easy to mix Good for bridging on gravel and frac packs Water soluble particles
Can plug perforation tunnels Highly damaging if particles are not sized properly Polymer damage may require remedial treatments May cause tools to stick
Low
Oil Soluble Resin
Easy to mix Good for bridging on gravel and frac packs Water soluble particles
May not stop losses completely Not useful above melting point Only recommended in oil wells
Relatively low
Polymer
Table 3: Bridging Particulate Systems Strengths, Limitations, & Costs
Linear gels can be prepared from a range of polymer systems, most typically natural polymers or natural polymers that have been modified to achieve the necessary purity and solution properties. The chemical structure of common polymers used as FLC materials and viscosifiers are shown in figures 14A14F. Cellulose, Figure 14A, is a natural structural component of wood and in cotton it exists in nearly pure form. However, cellulose is insoluble in water and brines. To make this polymer soluble, it is usually derivatized to hydroxyethyl cellulose (HEC), Figure 14B, which is relatively easy to disperse and hydrate in most brine solutions. Xanthan polymer, Figure 14C, is a more complex system, with excellent solids transport and suspending characteristics, particularly at low shear rates. Note that xanthan has pendant carboxyl groups, which can bind to contaminant ions to produce difficult-to-break gels. Additionally, xanthan polymer systems are incompatible with many biocides and clay stabilizers. Linear polymer gels are useful in operations involving low overbalance, low temperature, low permeability, and short interval length. More recently, viscoelastic surfactants (VES) have been developed as an alternative to polymer-based FLC materials. VES impart viscosity to the fluid by forming a 3D network of rod-like micellar structures, show in Figure 14E. The advantage of viscoelastic surfactants is that they need no added breakers to reduce viscosity after use. Solids Free FLC:
Viscosity is degraded when contact is made with oil, whereby the micelles are disrupted and the viscosifying network is destroyed. Another benefit of the particles is the formation of a pseudo filter cake of viscous VES fluid that greatly decreases fluid loss rates and improves overall efficiency of the fluid. Table 4 lists the strengths, limitations, and cost of some available linear gel systems and VES. New technology has led to the introduction of nanometer-scale particles, which interact with VES micelles, through chemisorptions and surface charge attraction, to form a worm-like micellular structure as seen in Figure 14F (Published by Schlumberger - Used courtesy of Schlumberger. Permission obtained September 9, 2009 ). Such interactions stabilize fluid viscosity at high temperatures. As internal breakers are activated to break the micelles, the fluid drastically loses its viscosity and the pseudo filter cake dissolves into nanometer-sized particles. Since these particles are so small, they are easily carried back to the surface, thus minimizing formation damage potential. SPE paper 107728 provides more information on the new VES system. Polymer
Strengths
Limitations
Cost
Hydroxyethyl Cellulose (HEC)
Relatively easy to mix Readily available Non-toxic, non-corrosive Acid soluble Internally or externally broken
Highly damaging if not pumped correctly Does not stop losses completely Requires multiple treatments Requires shearing and filtering
Relatively inexpensive
Xanthan (XC)
Relatively easy to mix Readily available Non-toxic, non-corrosive Good low-shear viscosity
Highly damaging if not pumped correctly Does not stop losses completely Requires multiple treatments Requires filtering Not readily removed with acid
Relatively inexpensive
Succinoglycan
Easy to mix Non-toxic, non-corrosive Good low-shear viscosity
Does not stop losses completely Requires multiple treatments Requires filtering Temperature limitations
Moderately expensive
Viscoelastic Surfactant (VES)
Easy to mix No solids Good low-shear viscosity
Requires hydrocarbon contact to break Temperature limitations
Relatively expensive
Table 4: Linear Gel Systems (Polymers) Strengths, Limitations, & Cost
Figure 15 shows a comparison of rheological properties of HEC and xanthan (XC) polymer. As seen in this figure, XC polymer displays a higher low shear rate viscosity (LSRV) compared to HEC, which translates in better solids carrying capacity at low flow rates, and under static (no flow) conditions. On the other hand, HEC is easier to remove via the use of internal breakers and ⁄ or remedial acid treatments. To achieve higher
viscosities, crosslinked polymer systems are typically employed. Crosslinked gels are typically compromised of derivatized HEC and are useful at temperatures up to 300° F. They are available as pre-blended products or can be prepared on the rig. Crosslinking agents for HEC include zirconium and lanthanide salts. Crosslinked gel
particulates, in the form of premanufactured slurries, are oftentimes useful when more complete fluid loss control is needed. Max Seal™ slurries, for example, can effectively plug off formations under relatively high
overbalanced pressures. It is comprised of crosslinked HEC gel, which has been chopped up to form inhomogeneous, lumpy, flowing slurry. Table 5 lists some crosslinked gel systems, along with their strengths, limitations and relative cost. Crosslinked
Crosslinkable HEC
Strengths
Pre-Prepared Crosslinked Gel Particles
Zinc Bromide Crosslinked Gel
Stops losses completely Easily removed with breakers Can withstand high overbalanced pressures Can run tools through it Stops losses completely No on-site mixing required Can withstand high overbalanced pressures Can run tools through it Stops losses completely Only pumpable system available for ZnBr2
Limitations
Cost
Internal breakers used for ≤
Moderately expensive
No internal breakers can be added (must be broken externally) Bulky to ship and store
Moderately expensive to high
Must be mixed on site Must be broken externally
High
48 hrs (fluid begins to degrade with time) Must be mixed on location
Table 5: Cross linked Gel Systems (Polymers) Strengths, Limitations, & Cost Another potential source of formation damage from polymer plugging is that related to clay stabilization via the use of polymers. The polymers include cationic inorganic polymers (CIP) and cationic organic polymers (COP). CIP such as hydroxyl aluminum and zirconium oxychloride provide marginally permanent clay stabilization. They offer resistance to cation exchange, but their application is limited to noncarbonate-containing sandstones. Cationic organic polymers are effective in providing permanent stabilization to clays, especially smectite, and for controlling fines and sand in sandstone and carbonates formations. Permanent protection is provided by the availability of multiple cationic sites of attachment, but their application is limited to low concentrations. COP are applicable in acidizing and fracturing, but their effectiveness is lowered in gelled-water solutions used for hydraulic fracturing and gravel-packing due to gel competition for adsorption on clay surfaces.27 They are often the cause of formation damage via polymer plugging because of their high molecular weight and long chains that have molecular sizes similar to pore throats in porous rock. Figure 16 shows a scanning electron micrograph detailing solids and polymer plugging of pore throats.
Altered Wettability
Formation damage in which the formation wettability is modified, generating a change in relative permeability to oil, gas and ⁄ or water that eventually affects well productivity. In particular, surfactants and other additives in
drilling fluids, especially oil-base mud, can change a naturally water-wet formation to an oil-wet formation with consequent production impairment caused by reduction of relative permeability to oil and/or gas. Brine salinity and pH are another important factor related to wettability because they strongly affect the surface charge density on the formation rock and fluid interfaces, which in turn can affect surfactants adsorption. Figure 17 shows an SEM of water droplets on both kaolinite and quartz, illustrating the contrasting wetting characteristics of different mineral surfaces. Published by University of the West of Scotland; "No further reproduction, please use for this project webpage only." Permission to use obtained Aug. 5, 2009. Relative permeability modifiers, such as Halliburton's WaterWeb® and BJ Services' AquaCon™, are hydrophilic polymers designed to reduce the effective permeability to water, while increasing (or maintaining) the relative permeability, to gas and ⁄ or
oil. They do not typically require special placement techniques. Water Block
Formation damage that occurs when large quantities of water and/or brine are lost to the formation, thus increasing water saturation and decreasing the relative permeability to oil and/or gas. Partially pressure-depleted reservoirs are particularly sensi tive to this type of damage. Water blocking can be prevented ⁄ minimized by adding surface tension reducing agents (e.g. surfactants, alcohols, or microemulsions) to wellbore fluids to not only lower surface and interfacial tension, but also to water-wet the formation, and prevent emulsions.28 Emulsions
Formation damage that is a mixture of two, or more, immiscible liquids in which the liquids are stabilized by one or more emulsifying agents. If an emulsion block exists, well permeability as determined through injectivity test will be much greater than permeability determined through production tests. Oilfield emulsion types consist of water in oil (regular emulsions), oil in water (reverse emulsions) and complex emulsions. Most emulsions break easily when the source of the mixing energy is removed. However, some natural and artificial stabilizing agents, such as surfactants and small particle solids, keep fluids emulsified. Natural surfactants, created by bacteria or during the oil generation process, can be found in many waters and crude oils, while artificial surfactants are part of many drilling, completion or stimulation fluids. Among the most common solids that stabilize emulsions are iron sulfide, paraffin, sand, silt, clay, asphalt, scale, and corrosion products .29 More information regarding emulsions can be found in SPE papers 105858, 100430, and 97886.
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