Water is the world’s most available resource. It occupies about 70.9% of the earth surface and also serves as a home for aquatic animals. It’s a chemical substance with the chemical formula H2O in its purified state. A water molecule contains one oxygen and two hydrogen atoms connected by covalent bonds. Water is a liquid at ambient conditions, but it often co-exists on earth with its solid state, ice and gaseous state (water vapor or steam). Water also exists in a liquid crystal state near hydrophilic surface. Water is continually dissolving or depositing solids. The phrase depositing solids encompasses the scope of this work. These deposited solids are classified as scale or foulant – commonly occur together. This study focuses on scale type deposits.
Scale is a hard, adherent mineral deposit that usually precipitate from solution and grows in places. It is a crystalline form of deposit. Cooling waters contains a large number of these potential scale and deposit-causing constituents. These include soluble ions (such as calcium, magnesium, soluble silica, zinc and iron salts) that precipitates as insoluble deposits when they encounter changes in water temperature, pH, concentration or incompatible addictives. Examples of these deposits are calcium carbonate (CaCO3), Calcium phosphate (Ca(PO4)), silica, iron hydroxides, sulfides, calcium sulfate (CaSO4), magnesium salt, zinc sulfate and zinc hydroxide.
1.2 OBJECTIVES OF STUDY
Scale described economically as a menace to an oilfield. The build-up of scale causes loss of millions of dollars every year. Thereby this work is aimed at the considering “the formation, effects and also remedy of scale” due to the cost of stimulating an oil flowline (or at worst replacing it).
The major problems caused by scale formation
• Reduced oil production
• Well plugging
• Reduction in pipe carrying capacity
• Impedance of heat transfer
• Increase in operational safety hazards
• Localization of corrosion attack
• Increases in operational costs
In production operations, scale problems may be encountered whenever water is produced with oil and gas due to the destabilization of water caused by changes as fluids pass through the production processing equipment.
1.3 SIGNIFICANCE OF STUDY
A complete understanding of scale phenomenal (formation, its effects and remedy in a crude oil flowline) requires intensive and prolonged study. However, a general knowledge of the subject can be gained through a review of the various ways in which scale manifest itself, the factors that govern scale formation process and the means available for prevention of scale.
Scale removal techniques must be quick, non-damaging to the wellbore, tubing or formation environment, and effective at preventing re-precipitation. The best scale removal technique depends on knowing the type and quantity of scale, and its physical composition and texture. A poor choice of removal method can actually produce rapid recurrence of scale.
This work will provide a concise solution which will serve as a guide to those in the oil and gas sector to install pipelines in an environment that will be more favorable.
1.4 LITERATURE REVIEW
1.4.1 OVERVIEW OF SCALE FORMATION
Water is of primary importance, since scale will occur only if water is produced. Water is a solvent for many materials and can carry large quantities of scaling minerals, all natural water contain with mineral phases in the natural environment. Scale begins to form when the state of any natural fluid is perturbed such that the solubility limit for more components is exceeded. (Autumm 1999)
Formation damage occurs during the life of many wells. Loss of well performance because of formation of scale has been the subject of several review articles. Fines migration, inorganic scale, emulsion blockage, asphaltene and other organic deposition are a few mechanism that cause scale formation (Nasr-El-Din, 2003).
Precipitation of mineral scales causes many effects in oil and gas production operations: formation damage, production losses, increased workovers in producers and injectors, poor injection water quality, and equipment failure due to under-deposit corrosion. The most common mineral scales are sulfates and carbonates based mineral. However, scale problems are not limited to these minerals and there have recently been reports of unusual scale types such as zinc and leads sulfides (Collins and Jordan, 2003).
1.4.2 SCALE FORMATION MECHANISM
Scale deposition is a complex crystallization process. Most natural waters contain considerable quantities of dissolved impurities, which are present as ions. Combinations of some of these ions form compounds that have low solubility in water. When the water’s limited capacity to dissolve these compounds is exceeded (supersaturated), then these compounds can precipitate as solids. The time it time it takes for an initial scale layer to form and its subsequent rate of growth are determined by the interaction of several rate processes examples are ( supersaturation, nucleation, contact time, adherence, crystal growth).
` a solution is saturated if it is in equilibrium with its solute ( i.e dissolved compounds). Supersaturation is when a solution contains higher concentrations of dissolved compounds than the equilibrium concentration. It can come about for a number of reasons such as;
1 change in temperature of a water
2 change in pH of a water
3 change in pressure on a water
4 change in agitation
5 comingling of incompatible waters
6 change in concentration of solute i.e mineral ions.
Nucleation is the initial formation of a precipitate. There are two mechanisms;
Homogeneous nucleation which does not require the presence of a foreign substance; this is not a likely mechanism because in nature it is not likely that environments free from foreign nucleating sites will be experienced.
Heterogeneous nucleation which require the presence of a foreign substance to trigger nucleation. The foreign substance can be one of a number of things, example;
(a) foreign scale nuclei or corrosion products
(b) welds/stress points on metal surface
(c) corrosion sites on metal surface
(d) scratches on metal surfaces
(e) small particles of suspended solids
For scale to form after a solution has become supersaturated and nucleation has occurred, there must be sufficient contact time between the solution and the nucleating sites on the surface. Generally, the longer the contact time, the more likely the scale formation becomes.
Corroding surface are more likely to promote scale deposition than noncorroding surfaces. Studies using polished surfaces indicate that microscopic roughness, whether natural or produced by corrosion; makes subsequent scale deposits more adherent.
Although the solubility limit must be exceeded for scale to form, the rate of scale formation is controlled by the presence or absence of scale inhibitor and other factors. The rate of crystal growth and the rate of inhibition of crystal growth can be studied by monitoring the amount of inhibitor required to keep the calcium level constant during periods when solubility limits are exceeded. (i.e during scale formation).
1.4.3 SOLUBILITY OF SCALE FORMATION
Solubility is defined as the limiting amount of solute that can dissolve in a solvent under a given set of physical conditions. When a sufficiently large amount of solute is maintained in contact with a limited amount of solvent, dissolution occurs continuously till the solution reaches a state when the reserve process becomes equally important. This reverse process is the return of dissolved species (atoms, ions, or molecules) to the un-dissolved state, a process called precipitation.
When the temperature or concentration of a solvent is increased, the solubility may increase, decrease, or remain constant depending on the nature of the system. For example, if the dissolution process is exothermic, the solubility decrease with increased temperature; if endothermic, the solubility increase with temperature.
There are two solubilities of scale;
(1) Calcium, strontium, barium sulfates, and calcium carbonate solubilities.
(2) Zinc sulfide, lead sulfide, and iron sulfide solubilities.
(1) Calcium, Strontium, Barium Sulfates, and Calcium Carbonate Solubilities
The chemical species of interest to us are present in aqueous solutions as ions. Certain combinations of these ions lead to compounds, which have very little solubility in water. The water has a limited capacity for maintaining those compounds in solution and once this capacity (i.e. solubility) is exceeded, the water becomes supersaturated; and the compounds precipitate from solution as solids. The solubilities of typical oilfield scales are given in Figure 2.3 (Connell, 1983).
Although the solubility curves (Figure 2.3) of these crystalline forms versus temperature show that above about 40 ºC (104 ºF), anhydrite is the chemically stable form, it is known from experience that gypsum is the form most likely to precipitate up to a temperature of about 100 ºC (212 ºF). Above this temperature, hemihydrate becomes less soluble than gypsum and will normally be the form precipitated. This, in turn, can dehydrate to form a scale at temperatures below 100 ºC and hemihydrate forms above this temperature (Connell, 1983).
Therefore, precipitation of solid materials, which may form scale, will occur if:
(a) The water contains ions, which are capable of forming compounds of limited solubility.
(b) There is a change in the physical conditions or water composition, lowering the solubility.
Factors that affect scale precipitation, deposition and crystal growth can be summarized as: supersaturation, temperature, pressure, ionic strength, evaporation, contact time, and pH. Effective scale control should be one of the primary objectives
of any efficient water injection and normal production operation in oil and gas fields
(2) Zinc Sulfide, Lead Sulfide, and Iron Sulfide Solubilities
Lead and zinc sulfide solubility is much lower even than iron sulfide, which is the common sulfide in oil field environments. The very low solubility of lead and zinc sulfide would make it unlikely that zinc/lead and sulfide ions could exist together in solution for any length of time.
It is more likely that the zinc/lead ion source mixes with the hydrogen sulfide-rich source within the near wellbore or the production tubing during fluid extraction; form then on, changes in temperature, solution pH, and residence time control where scales deposit within the process system.
For example, in a 1M (mole/dm3) NaCl brine solution as presented in Figure 2.6 at pH = 5 the solubility of iron sulfide is 65 ppm, whereas lead and zinc sulfides are 0.002 ppm and 0.063 ppm respectively. Depending on the exact brine conditions, the solubility of zinc sulfide is between 30 to 100 times more soluble than lead sulfide. As with iron sulfide, the solubility of both lead and zinc sulfide increases with increasing solution pH (Collins and Jordan, 2001).
1.5 EFFECTS OF SCALE IN OIL FLOWLINE
1.5.1 Effects Of Scale in Oil flowline
Scale deposition is one of the most serious problems where water injection systems are engaged in. Generally, scale deposited in downhole pumps, tubing, casing flowlines, heater treaters, tanks and other production equipment and facilities. The failure of production equipment and instruments could result in safety hazards (Yeboah, 1993).
The formation of inorganic mineral scale within onshore and offshore production facilities around the world is a relatively common problem. Scale can form from a single produced connate or aquifer water due to changes in temperature and pressure, or when two incompatible waters mix. An example of the latter would be seawater support of a reservoir where the formation water is rich in cations (Ba, Sr and Ca) and the injection water is rich in anions (SO4). The production of such comingled fluids results in the formation of inorganic scale deposits.
Oilfield scales costs are high due to intense oil and gas production decline, frequently pulling of downhole equipment for replacement, re-perforation of the producing intervals, re-drilling of plugged oil wells, stimulation of plugged oil bearing formations, and other remedial workovers through production and injection wells. As scale deposits around the wellbore, the porous media of formation becomes plugged and may be rendered impermeable to any fluids (McElhiney,2001).
1.5.2 Effect of Supersaturation
Supersaturation is the most important reason behind mineral precipitation. A supersaturated is the primary cause of scale formation and occurs when a solution contains dissolved materials which are at higher concentrations than their equilibrium concentration. The degree of supersaturation, also known as the scaling index, is the driving force for the precipitation reaction and a high supersaturation, therefore, implies high possibilities for salt precipitation.
1.5.3 Effect of Temperature
Heating the reservoir water tends to precipitate calcium sulfate, calcium sulfate is less soluble at higher temperatures. Calcium sulfate is often observed on the fire tubes of heater theaters. Calcium carbonate also tends to precipitate more at decrease solubility at higher temperatures. Although this increase can be several-fold, solubility still remains at a low level (Connell 1983).
According to (Oddo 1991), calcium carbonate solubility has an inverse relationship with temperature or stated more simply, CaCO3 scale becomes more insoluble with increasing temperature and a solution at equilibrium with CaCO3 will precipitate the solid as the temperature is increased. The tendency to form CaCO3 also increase with increases with increasing pH (as the solution becomes less acid) (Jacques and Bourland 1983).
1.5.4 Effect of Pressure
The sulfate of calcium, barium and strontium are more soluble at higher pressures. Consequently, formation water will often precipitate a sulfate scale when pressure is reduced during production. The scale may deposit round the wellbore, at the perforations, or in the downhole pump if used. Barium sulfate is common at perforations or downstream of chokes, where the pressure is reduced considerably (Connell 1983).
The solubility of scale formation in a two-phase system increases with increased pressure for two reason (Morghadasi 2004)
(1) Increased pressure increase the partial pressure of CO2 and increases the solubility of CaCO3 in water.
(2) Increased pressure also increases the solubility due to thermodynamic consideration.
1.5.5 Effects of Ionic Strength
The solubility of calcium sulfate is strongly affected by the presence and concentration of other ions in the system. The solubility of calcium sulfate is an order of magnitude larger than that of strontium sulfate, with in turn is about one and one-half order of magnitude larger than that of barium sulfate,
The solubility of strontium sulfate can be larger than 950 mg/l. This solubility is depressed remarkably. This is known as the common ion effect (Lindlof and Stoffer 1983). The solubility reaches a maximum in highly concentrated brines.
Relative solubilities of three sulfates in brine (Lindlof and Stoffer, 1983)
1.5.6 Effects of pH
The amount of CO2 present in the water affects the pH of the water and the solubility of calcium carbonate. However it really does not matter what causes the acidity or alkalinity of the water. The lower the pH the less likely is CaCO3 precipitation. Conversely, the higher pH, the more likely that precipitation will occur (Moghadasi 2004)
1.5.7 Effect of Carbon dioxide partial pressure
As opposed to most sulfate scale, the prediction of carbonate scale requires not only the consideration of pressure, temperature, and water composition, but also the knowledge on the chemical reactions within the brine and CO2 in the gas phase. Most oilfield flow lines contain carbonate mineral cements and carbon dioxide, therefore the formation water normally saturated with calcium carbonate under crude flow lines condition where the temperature can be as high as 200̊ C and the pressure up to 30MPa.
Solubility of calcium carbonate is greatly influenced by the carbon dioxide content of the water. CaCO3 solubility increases with increased CO2 partial pressure. The effect becomes less pronounced as the temperature increases. The reverse is also true. It is one of the major causes of CaCO3 scale deposition (Moghadasi, 2004).
1.5.8 The area that can experience scale
(1) The reservoir perforation at the well bore
There are many fields that inject seawater into the reservoir to maintain pressure and maximize extraction of hydrocarbon. Many of the natural formation waters contain barium and strontium but no sulfite, while seawater contains sulfate but no barium/strontium. When these waters commingle in the well bore or reservoir perforation area, precipitate of barium sulfate or strontium sulfate may occur, sometimes calcium sulfate as well.
(2) Well tubular
As the produced fluids pass up the well to the surface there can be changes in temperature and pressure which can;
(a) Destabilize the natural formation water. In certain fields the water contains bicarbonate and is saturated with carbon dioxide. If the pressure drops in the fluids as they pass up the well then calcium carbonate precipitate may occur.
(b) Destabilize further the mixture of sea water and formation water causing further deposition of barium sulfate, strontium sulfate etc.
(3) Downhole safety valve
This area suffers from the same potential scale problems. In addition since the downhole safety valve causes a restriction in the diameter of the well tubular, there is a significant pressure drop and turbulence created which can cause further destabilization of the produced fluids.
The choke is a pressure reducing/flow control valve. An indication of the high pressure drop and turbulence induced in this area is that the diameter of many well tubular are 4 and half while the diameter of the choke is typically I,
(5) Production flow lines
In production flow lines scale problems can be experienced due to;
(a) Destabilization of natural formation water due to reduction in pressure (causing scale formation) and secondly, changes in temperature of produced fluids. Some system have production coolers while some others have heat exchangers that may promote precipitation of scale
(b) Destabilization of mixed sea/formation waters is due to reduction in pressure and changes in temperature. These changes can obviously induce further precipitation of barium and strontium sulfate.
1.6 OILFIELD SCALE TPYES
The most common scale encountered in oilfield operations are sulfates such as calcium sulfate (anhydrite, gypsum), barium sulfate and calcium carbonate. Other less common scales have also been reported such as iron oxides, iron sulfides and iron carbonate. Lead and zinc sulfide scale has recently become a concern in a number of northsea oil and gas fields (Collins and Jordan 2001).
There follows a brief description of each scale type:
1.6.1 Calcium Carbonate Scale
Calcium carbonate or calcite scale is frequently encountered in oilfield operations, but the calcite has the greatest stability in oilfield circumstances, so it is the most common form of calcium encountered in oilfield production operation.
Calcium carbonate crystals are large, but when the scale is found together with impurities in the form of finely divided crystals, then the scale appears uniform. Deposition of CaCO3 scale results from precipitation of calcium carbonate is as per the following equation;
Ca+2 + CO3-2 ↔ CaCO3 (1.0)
Carbonate scale formation occurs when connate water or aquifer water passes through the bubble point and carbon dioxide is evolved. As carbon dioxide is evolved, the solubility with respect to carbonate declines rapidly and forms a precipitate with divalent ions, such as iron, and more commonly calcium, the following equation (Mackay and Jordan, 2005)
Ca (HCO3)2 ↔ CaCO3 + CO2 +H2O (1.1)
Calcium carbonate scale is form by a different mechanism. As few waters contain the actual carbonate ion, the scaling potential arises from decomposition of calcium bicarbonate (Clemmit, 1985).
1.6.2 Calcium Sulfate Scale
Calcium sulfate scale poses a unique problem for the salts under consideration because it occurs with one of three different phases. Calcium sulfate exists in several crystalline forms. These include gypsum (CaSO4.1/2H2O) and anhydrite (CaSO4).
According to Oddo (1991), calcium sulfate scale formation is somewhat dependent on temperature, but is typically precipitated because of a decrease in pressure or an increase in the relative concentrations of calcium or sulfate.
1.6.3 Barium Sulfate Scale
Barium sulfate scale (barite) in oil fields can be precipitated easily on the basis of already available information relating to thermodynamic condition and the kinetics of precipitation (Mitchell, 1980). Barium sulfate is the most insoluble scale that can be precipitated from oilfield waters. It forms a hard scale which is extremely difficult to remove. The solubility of barium sulfate is about a thousand times less than of calcium sulfate, at surface conditions.
The solubility of barium sulfate goes up with increasing temperature, pressure and salt content of the brine. Thus prediction of barium sulfate scale is much easier than the others since a pressure, temperature or salt content drop will increase precipitation (Connell, 1983).
1.6.4 Strontium Sulfate Scale
Strontium sulfate scale formation has become a growing concern in oil-production systems. Until recently, the appearance of strontium in oilfield scales has been primarily in the presence of barium sulfate scale. Almost pure SrSO4 scale now is observed in several production wells around the world. The scale formation is primarily a result of subsurface commingling of waters, which results in water supersaturated in SrSO4( Nassivera and Essel, 1979).
Strontium sulfate solubilities may play a role in many disciplines of science and engineering. For example, strontium sulfate forms scale in oil and/or alkaline earth metals. Strontium sulfate behaves like barium sulfate except the former is more soluble under the same conditions. Most of the field scale barium sulfate deposits contains strontium sulfate too (Essel and Carlberg, 1982)
1.6.5 Iron Sulfide Scale
Iron sulfide species have been known to cause operational problems in the oil industry. Iron sulfide scale is present in oil and gas producing wells, sour wells and water injectors where the injected water has high sulfate content. The sources of iron are the formation brines (especially in sandstone formations) and the well tubular. Iron produced by corrosion processes can be minimized by employing various corrosion protection techniques (Nasr-El-Din and Al-Humaidan, 2001).
According to Raju (2003), the disposal water contains dissolved H2S, whereas the aquifer water contains dissolved iron. When these two waters are mixed together, H2S reacts with the iron ions and precipitates iron sulfide species.
Fe++ + H2S ⇔ FeS ↓ + 2H+ (1.2)
1.7. REMEDY OF SCALE FORMATION
The most obvious way of preventing a scale from forming during oil production is to prevent the creation of supersaturation of the brine being handled. This may sometimes be possible by altering the operating conditions of the reservoir, for example by ensuring that the flowline pressure is sufficient to prevent the liberation of oil. However, economics usually dictate that the use of inhibitors is preferred.
Scale prevention is achieved by performing squeeze treatments in which chemical scale inhibitors are injected in the producers near flowline (Romero, 2007).
1.7.1. Operational Prevention
There are two operational preventions:
(1) Avoid mixing Incompatible Waters
The importance of avoiding incompatibility problems should be obvious from the preceding discussion. However, in offshore locations like the North Sea there is no economic method of obtaining compatible water, so sea water must be used.
(2) pH Control
Lowering the pH will increase the solubility of carbonate scales (but may cause corrosion problems). This method is not widely used in the oilfield, since accurate pH control is needed. However, it is useful for cooling waters.
1.7.2 Scale Control Chemicals
In oil and gas well operations, water-insoluble scale is formed in tubing, casings, and associated equipment, as well as in the wellbore and the formation itself which carry, at least in part, water or brine waters. These waters can contain insoluble calcium, barium, strontium, magnesium, and iron salts.
Scale inhibitors are chemicals which delay, reduce or prevent scale formation when added in small amounts to normally scaling water. Most of modern scale inhibitors used in the oilfield functions by one or both of the following mechanisms (Connell, 1983):
(1) When scale first begins to form, very tiny crystals precipitate from the water. At this point, the scale inhibitor absorbs onto the crystal surface thus preventing further growth.
(2) In some cases, scale inhibitors prevent the scale crystals from adhering to solid surfaces such as piping or vessels.
In the majority of cases, a good scale inhibitor should be effective at 5-15 ppm in clean water (Chen et al., 2004).
1.7.3 Scale Removal Methods
188.8.131.52 Calcium Carbonate
Hydrochloric acid is the most effective way of dissolving calcium carbonate under most conditions. Concentrations of 5-15% HCl are normally used (Connell, 1983):
CaCO3 + 2HCl → H2O + CO2 + CaCl2 (1.3)
184.108.40.206 Calcium Sulfate
The following may be used to dissolve calcium sulfate (Connell, 1983):
Inorganic converters are usually carbonates or hydroxides which react with calcium sulfate and convert it to acid soluble calcium carbonate or calcium hydroxide. The conversion treatment is then followed by a hydrochloric acid treatment to dissolve the resulting scale:
CaSO4 + (NH4)2CO3 → (NH4)2SO4 + CaCO3 (1.4)
CaCO3 + 2HCl → H2O + CO2 + CaCl2 (1.5)
Solvents are now available which will completely dissolve gypsum scale. Other compounds used (to s lesser extent) are EDTA and salt water.
220.127.116.11 Barium Sulfate
One of the most common reasons for production loss is the development of scales inside the production strings, blocking the flow of the reservoir fluid to the surface facilities. Barium sulfate scale is among the toughest scales to remove, whether mechanically or chemically (Guimarases et al., 2007). Barium sulfate could only be removed by mechanical means. However, chemicals based on EDTA are now available which have had some success in dissolving barium sulfate. Barium sulfate could only be removed by mechanical means.