The chemistry of chemical scale inhibitors and the mechanism of interactions with carbonate reservoir rock.
Mineral scale deposition is a common phenomenon in the water treatment plants and more especially in the oil industries when an oil producer well starts to produce water. At this period, secondary injection by seawater flooding is commonly employed to ensure enhanced oil recovery by ideal displacement. Anionic species such as sulfate (S[O4.sup.2-]) and carbonates (C[O3.sup.2-]) in the sea water react with the inorganic ions like calcium ([Ca.sup.2+]), magnesium ([Mg.sup.2+]), barium ([Ba.sup.2+]) and strontium ([Sr.sup.2+]) present in the formation brine to get precipitated and deposited as mineral scales. These deposits constrict oil flow (Figure 1) and therefore, optimum oil production cannot be attained [1, 2, 3]. The overall consequence is the annual loss of millions of dollars and increase in production expenses on the side of oil companies.
[FIGURE 1 OMITTED]
The deposits however, can be handled by employing one or more of the following methods; its deposition can be predicted and then prevented or it can be removed mechanically after deposition . However, the most effective means of handling the mineral scale is to prevent its deposition by the use of chemical scale inhibitors. These inhibitors are chemical substances, organic or inorganic, usually applied in to the formation by means of "squeeze" treatments to prevent the precipitation of mineral scales. Once these chemicals are placed in to the formation, the chemicals will interact with the formation through some processes, it is these interactions that help slow down or completely prevent the deposition of mineral scale in an oil well . As about 50% of the world oil production takes place from carbonate formations, especially in the Middle East, understanding the chemistry behind the mode of actions of the inhibitors is an inevitable issue. The paper therefore tailors key issues from the types of inhibitors available in the oil industry to the mechanism of their interactions with carbonate reservoirs. Effects of pH, reservoir properties and the structure of the chemicals in scales inhibition have also been discussed.
Mineral (inorganic) scales
Deposition of mineral scales is a common production problem encountered in the oil industries. These mineral scales deposition may lead to the loss of well integrity, jeopardizing the well safety and may even leads to the loss of productivity of the well if not properly managed. Most oil company operators believe that it is much better to prevent the formation of such mineral scales rather than treating it after depositions. The most common ways of preventing mineral scale deposition is by the use of chemical scale inhibitors which interacts with the rock minerals in the porous medium [4-8].
The term mineral scale refers to inorganic solid deposits formed from the reactions of ions present in the formation brine or injected waters, which may precipitate either down hole, top side or both, during the water production period of a well under production. This commonly occurs when the reservoir conditions change (such as the time of water productions, reservoir pressure depletion and changes in the pH conditions around the wellbore) [8, 9]. There are many types of mineral scales that can be deposited during the lifetime of a producer well, however, the most commonly encountered mineral scales in the oilfields such as North Sea and many places in the world are the calcium carbonate (CaC[O.sub.3]) called calcite, the barium sulphate (BaS[O.sub.4]) commonly called barite and the calcium sulphate (CaS[O.sub.4) called gypsum. Carbonate scale deposition is essentially caused by the presence of calcium and bicarbonate ions in the formation brine, which when the pressure falls may get precipitated as calcite (CaC[O.sub.3]). Sulphate scales such as barite and gypsum on the other hand, are generally formed when there is co-production of incompatible brines (for example mixing formation water containing barium ions with the injected sea water which is rich in the sulphate ions) . Below is the classification of mineral scales commonly encountered in the oilfields based on their solubility in acid.
Acid soluble scales
* Calcium carbonate, (CaC[O.sub.3]) Calcite, formed when the formation brine is supersaturated with [Ca.sup.2+] and C[O3.sup.2-] ions.
* Iron carbonates (FeC[O.sub.3]) siderite. [Fe.sup.2+] mostly from the corrosion materials and C[O3.sup.2-] ions from the formation brine.
* Iron oxides (e.g Fe (OH) 2, [Fe.sub.2][O.sub.3], etc) [Fe.sup.2+] and [Fe.sup.3+] from the corrosion materials and [O.sup.2-] from oxygen rich injected sea water.
Acid insoluble scales
* Barium sulphate (BaSO4) barite, [Ba.sup.2+] ion mostly from the formation brine and S[O.sub.4.sup.2-] ions from the injected sea water.
* Strontium sulphate (SrSO4) celestite, [Sr.sup.2+] from the formation brine and S[O.sub.4.sup.2-] ions from the injected sea water.
* Mixed barium /strontium sulphate (Ba, Sr/S[O.sub.4]).
There are unusual mineral scales that are usually associated with high temperatures and pressures such as barium carbonate etc . However for any mineral scale to be deposited, two stages of precipitations are encountered, firstly nucleation which involves the formation of nuclei of the scale crystal due to the supersaturation of the solution with respect to that mineral scale, the second stage is the crystal growth which involves the subsequent growth of the already formed nuclei to form a stable scale crystal. Mineral scales can present a lot of production problems and if ignored can lead to the constriction of the production tubing, it can be more dangerous if it involves the blockage of sub-surface safety valves and some other top side chokes and valves. Figure 1 shows how tubing can be constricted by the mineral scales if its deposition is not prevented.
The Scale Inhibitor Chemicals
Chemical scale inhibitors are organic or inorganic materials with ability to inhibit the formation of scales during oil production. They are composed of classes of compounds such as polyelectrolytes, polyphosphates, phosphate esters, phosphonates and polyacrylates. Some specific examples are given in Table 1. These chemicals are applied by either direct injection in to the sea water or by their "squeezing" in to the formation. Once these chemicals are placed in to the formation, they will interact with the formation (through adsorption/desorption or precipitation/dissolution process), it is this interaction that helps slow down or completely prevent the deposition of mineral scale in an oil wells . Generally these chemicals are divided in to two forms which are the polymeric and the phosphonates based chemical scale inhibitors, in any case these chemicals are required in oil industries to prevent the depositions of mineral scales.
Polymeric scale inhibitors
These are polymer molecules usually formed chemically by the process called polymerization reaction where by the smaller molecular units called the monomers joined together repeatedly and chemically by means of covalent bonding to form a long polymeric structure called polymers. Examples of these chemicals include; polyacrylate, phosphino carboxylate, polyvinyl sulphonates etc.
[FIGURE 2 OMITTED]
These molecules are available in natural and synthetic forms, with a variety of biological (such as Nucleic acids, proteins etc) and industrial applications. However in oil industries the most frequently used polymers in mineral scale prevention are artificially synthesized and can therefore be improved upon, to meet the target requirements. Due to the possible breakage of the bond holding the monomers in a polymeric molecule upon application of heat, these compounds are less readily stable under reservoir conditions; however these properties vary with the type of polymers in question.
In contrast to the polymeric scale inhibitors, organic based inhibitor otherwise known as the phosphonate chemical scale inhibitors are structurally not as long as their polymeric counterparts, they are usually smaller organic species having -C-P[O.sub.3][H.sub.2] as the functional unit, (19) Phosphonate-based organic inhibitors have been widely used in the oil industries to control mineral scale by slowing down or completely preventing its deposition. These chemicals are found to be more advantageous in preventing the deposition of mineral scales than their polymeric counterparts because they have the ability of preventing the scale nucleation and/or crystal growth processes, and are relatively more stable over wide range of reservoir conditions. DETPMP as one of the most commonly used phosphonate scale inhibitors has been used in oil industries with some degree of success to prevent some common mineral scales such as Barite, Calcite, and Gypsum.
[FIGURE 3 OMITTED]
These organic molecules are very effective in preventing mineral scale depositions because of their high ability to form a complex with the divalent cat ions in the porous media; this complex is generally a less soluble precipitate that prolongs the "squeeze" lifetimes.
In all cases whether polymeric or phosphonate based scale inhibitors are used to prevent mineral scale deposition, the selection of scale inhibitor for any practical application should satisfy the following conditions;
* The chosen chemicals must have the ability of preventing mineral scale deposition at a very low sub-stoichiometric concentration (typically 1 to 20 ppm).
* The chosen chemicals should have long "squeeze" life times (typically 3 to 12 months)
* The chemicals should be compatible with the formation brine and should be stable under wide range of reservoir conditions.
* Some researchers have compared the inhibition efficiency of polymeric and phosphonate based scale inhibitors, they observed that there is much lower retention of polymeric based scale inhibitors on the carbonate formation than the phosphonate based inhibitor. Hence this research pays more attention to the phosphonates based inhibitors and their interactions with the carbonate rock in controlling mineral scale depositions..
Inhibitor Adsorption and Precipitation
The primary reason why any chemical scale inhibitor is chosen is to effectively prevent the formation of the commonly encountered sulphates and carbonates mineral scales at a very low sub-stoichiometric concentration and still having a longer squeeze time. For these to be achieved the chemicals chosen must correctly interacts with the rock surface and/or divalent cat ions present in the porous media . Phosphonates based organic inhibitors have been used in the oil industries and proved to be very effective. Diethylene triamine penta methylene phosphonic acid (DETPMP) for example has some advantages, since it has the ability of retarding and/or effectively preventing the Nucleation or Crystal growth of the commonly encountered mineral scales .
The good interactions required between the phosphonate scale inhibitor and the carbonate formation is a necessary condition if a satisfactory long return profile is needed to be achieved throughout the "squeeze" lifetime . This is achievable only if there is a good understanding of how phosphonate chemical inhibitor interacts with the carbonate formation. It is generally believed that the two common ways by which scale inhibitor is retained on to the formation are Adsorption/desorption and Precipitation/dissolution mechanisms . These processes are dependent on the type of scale inhibitor used, the rock mineralogy, pH and presence of divalent cat ions.
Adsorption is the common mechanism by which scale inhibitor is physically or chemically adsorbed on to the rock mineral surface within the porous medium . This process predominantly occurs within the sandstone formation especially in the presence of low concentration of divalent cat ions (such as [Ca.sup.2+], [Mg.sup.2+], [Fe.sup.2+] etc), the process is affected by the surface charge properties of the formation and nature of the inhibitor molecule used . Generally, as the pH increases the degree of dissociation of both the polymeric inhibitor molecule and the rock surface increases, this makes the rock substrate more negatively charged, and the divalent cat ions are then adsorbed on to the negatively charged rock surface making it less negative and slightly more positive, it is this positive site that attracts and lead to the adsorption of an anionic inhibitor molecule . This phenomenon of adsorption is illustrated by the following chemical equations (1-3), where a silinol (SiOH) surface is used as an example;
SiOH + [H.sub.2]O [right arrow] Si[O.sup.-] + [H.sub.3][O.sup.+] (1)
The equation (1) represents how a quartz (silinol) surface dissociates to form a negatively charged surface which then adsorbs the divalent cat ions such as calcium within the porous medium according to the following chemical equation;
Si[O.sup.-] + [Ca.sup.2+] [right arrow] SiO[Ca.sup.+] (2)
Adsorbing this positively charged ion will alter (reverse) the ionic characteristics of the formation surface making it slightly positive; this will then facilitate the rate at which a negatively charged anionic inhibitor molecule would be adsorbed on to the positively charged rock site .
SiO[Ca.sup.+] + R-C[O.sub.2.sup-] [right arrow] SiO[Ca.sup.+].[O.sub.2]-C-R (3)
In contrary to the normal adsorption process, it was found that, the retention mechanism of scale inhibitor on to the carbonate formation can be a more complex process, this is because the carbonate rock itself is a very reactive substrate which can react with the inhibitor molecule chemically, therefore complicating the adsorption process . In carbonate formations, scale inhibitors can go into direct reaction with the carbonate mineral and precipitate as a slightly soluble salt, this precipitation process occurs when the inhibitor molecule precipitate out of the solution and form a thin film of the inhibitor/Ca complex in the form of slightly soluble salts on the carbonate rock surface . The slightly soluble salt precipitate is expected to dissolve and produce back when normal production resumes. This mechanism is controlled by the down hole conditions and the type of the chemical inhibitor used. The formation of this precipitates is desirable in a "squeeze" treatment since it prolongs the "squeeze" lifetimes . Longer "squeeze" time is generally required to minimize the shut-in times for the "squeeze" treatments to be conducted, since when all the inhibitor chemical is being back--produced after a given "squeeze" treatment, the well has to be shut-in to conduct another treatment.
For a longer "squeeze" lifetimes to be achieved, there is a requirement for a good understanding of the phosphonate precipitation/dissolution process, since this is what determines the inhibitor return curve following a "squeeze" treatment in a carbonate formation . Research conducted by Baraka & Sorbie  on core floods suggests that, there are number of factors governing reactions that occur when a phosphonate chemical scale inhibitor interacts with the carbonate formation to prevent the deposition of mineral scale, among other things are: the pH, [Ca.sup.2+] ions, [Mg.sup.2+]ions, temperature, rock mineralogy, the type of inhibitor used etc [8, 9].
Moreover, work conducted by the Rice University Brine Chemistry Consortium led to the following observations on the factors governing the retention of scale inhibitors on the carbonate formation ;
* Calcite mineral present in the carbonate formation is the main mineral that accounts for how phosphonates scale inhibitors are retained on the carbonate rock, and clays may play some minor secondary roles in the retention process .
* What actually controls the inhibitor retention and its subsequent return, is the solution pH and concentration, but not the mineralogy of the rock, even though it can be a factor.
* The salt precipitates that is usually formed at high pill concentrations, is due to calcite surface poisoning which leads to a lower pH of the phosphonates/calcite solution.
Another factor that was found to be very influential in phosphonates/carbonate interactions is the presence of divalent cat ions (such as [Ca.sup.2+], [Mg.sup.2+] etc), this was demonstrated in the core flood experiment carried out by Baraka & Sorbie , which shows that, during the actual injection of the scale inhibitor it was observed that there was a loss of [Mg.sup.2+] concentration since [Mg.sup.2+] ions were adsorbed together with the scale inhibitor, however as the production recommences there was an increase in the [Mg.sup.2+] concentrations which was a good indication that these magnesium ions were released by the carbonate rock together with the scale inhibitor during the back production period [8, 9].
In this experiment the role of divalent cat ions were closely monitored, and a conclusion could be drawn that the inhibition efficiency of DETPMP was found to be more effective in the presence of [Ca.sup.2+]ions . However, in an experiment to investigate the effects of divalent cat ions on inhibitor retention on carbonate formation; it was found that the role of calcium ions on the inhibitor retention by a carbonate formation has a limited effect, this is because with increase in the concentration of divalent cat ions there is a stage usually reached where surface poisoning may occur, and the direct effect of this is that; the retention of phosphonate inhibitor by the carbonate rock for example, is determined by the amount of calcite mineral that can dissolve prior to the calcite surface poisoning .
Scale Inhibitor Reactions with the Carbonate Reservoir
Depending on the down hole conditions and nature of the chemical scale inhibitor used to prevent the deposition of mineral scale, there is always a chance that, both the adsorption and precipitation processes could occur concurrently, however the most commonly observed chemical reactions when a phosphonate scale inhibitor is used on carbonate formation during "squeeze" treatments are;
* Dissolution of carbonate mineral (most commonly the calcite CaC[O.sub.3]),
* Formation of Ca-phosphonate complex.
* Retardation of calcite (CaC[O.sub.3]) dissolution due to the surface poisoning by the Ca-phosphonate complex coating,
* Re-dissolution of the Ca-phosphonate complex during the back production period .
That is to say, the most probable mechanism of scale inhibition in carbonate formation is the precipitation mechanism, due to the in-situ generation of calcium ions as the acidic low pH inhibitor slug is injected down hole during "squeeze" treatment, which causes the dissolution of carbonate minerals such as calcite to generate calcium and other divalent cat ions. These processes are in turn described below in details;
Carbonate mineral (Calcite) dissolution
The first chemical process commonly observed upon injection of the acidic chemical scale inhibitor in to a carbonate formation is the dissolution of carbonate rock material, which is most commonly a chemical compound called the calcium carbonate or calcite. As described in the previous section; the most important factor governing the dissolution of this compound is the acidity of the scale inhibitor slug. This is consistent with the core flood experiments conducted by Baraka & Sorbie [9, 10] to investigate the influence of pH on phosphonates/carbonate interactions, this clearly explains how dissolution of carbonate minerals occur on injection of acidic phosphonate scale inhibitor in to the carbonate rock. In this experiment DETPMP was used at various pH values on different core floods. It was observed that throughout the experiments dissolution of carbonate rock occurred during the main inhibitor treatments. In fact, it reached an extent of the formation of warm hole in a core flood where inhibitor slug with the highest acidity was used; this restricted the level of interactions between the inhibitor slug and the carbonate rock. This therefore explains how influential the pH of the chemical scale inhibitor slug could be, in controlling the solubility of the carbonate material .
Final analysis of the rock material suggests that there was the formation of slightly soluble salt precipitates which was, as a result of the complex formation between the phosphonate inhibitor molecule and the in situ generated divalent cat ions, a phenomenon that cannot be explained using simple adsorption/desorption process commonly observed in the sand stone reservoirs.
It is interesting to note that; this experiment and the spreadsheet analysis of the calcium carbonate compound clearly proved that, dissolution of carbonate material always occur upon injection of acidic chemicals in to the carbonate formation, which is true for any "squeeze" treatment conducted in the carbonate reservoirs. Secondly, this analysis clearly suggests that the higher the pH of the inhibitor slug the lower the possible dissolution of the carbonate material, therefore, factors such as the aqueous carbon dioxide concentration, temperature among other things control the dissolution of this carbonate rock material.
Formation of Ca-inhibitor complex
Presence of amino group (nitrogen atom) in most phosphonate inhibitors increases their tendencies of binding the metal ion(s) to form a complex. This type of reaction is called complexation or complex formation, for a complex to be formed a neutral or charged molecule normally called ligand donates a pair(s) of electrons to a metal ion and in the process the bulk ligand molecule surrounds the metal ion making it at the centre of the complex.
Sorbie and Boak  for example have shown that, Calcium and Magnesium may bind to DETPMP according to the following chemical equations, where A denotes
[MATHEMATICAL EXPRESSION NOT REPRODUCIBLE IN ASCII] (4)
[MATHEMATICAL EXPRESSION NOT REPRODUCIBLE IN ASCII] (5)
It is based on this mechanism that divalent cat ions (such as Mg, Ca etc) get bind to the phosphonate inhibitors to form complex . Complexes when formed are slightly insoluble especially in pure water and other neutral solutions. Inhibitor molecule in this case is essentially a ligand molecule that is capable of forming a coordinate covalent bond using its lone pair(s) of electrons with the divalent cat ions (such as Calcium or Magnesium, Figure 4) in the porous media .
[FIGURE 4 OMITTED]
The stability of such complexes when formed increases with increase in the number of phosphonic acid groups. On the other hand presence of groups like -S[O.sub.3]H, -OH etc increases the solubility of this complexes, that is why phosphonate based inhibitors have been effective in mineral scale prevention. The formation of this complex is controlled by the; scale inhibitor concentration, the concentration of the divalent cat ions, nature of the inhibitor molecule used and temperature. Since the complex formed has lower degree of solubility, it effectively prolongs the "squeeze" life times. The divalent cat ions can be added directly in to the inhibitor slug or can be made in situ when a lower pH inhibitor solution is used on carbonate rock, this will lead to the dissolution of carbonate mineral thereby generating the divalent cat ions. It is suggested that the shape of the inhibitor return curve is controlled by the solubility of this Ca-phosphonate complex during the back production period .
In a core flood experiment conducted by Kan it was observed that, the Ca-phosphonate precipitation occurs in three main steps; firstly at a very low phosphonate concentration the phosphonate-calcite reaction is described by the Langmuir isotherm, (which relates to the low concentration region on the inhibitor return curve where the inhibitor concentration rises slowly suggesting a weaker adsorption affinity . Secondly as the phosphonate concentration increases some small portions of the rock surface would be covered by the phosphonate due to the formation of Ca-phosphonate precipitates (the rock surface covered at this concentration are typically kinks and other imperfect sites) at a much higher concentration, the Ca-phosphonate formed continue to grow on the rock surface forming a bondage of phosphonate layers until about five surface layer thick is formed, where the surface poisoning effect begins. Kan  suggested that these three reaction steps are observed in DETPMP, BHPMP and some other phosphonate inhibitors.
Surface Poisoning by the Ca-phosphonate Coating and Ca-phosphonate Complex Re-dissolution
Presence of divalent cat ions in the reaction medium, due to their presence in the inhibitor solution or when generated in situ as a result of carbonate mineral dissolution will result in the divalent cat ions being bind to the inhibitor molecule leading to the formation of sparingly soluble Ca-inhibitor precipitates, this is considered advantageous due to the longer "squeeze" times achievable. Phosphonate inhibitors with different molecular structures may have different surface poisoning effects towards calcite dissolution and this may account for the difference observed in the inhibition efficiency of different phosphonate inhibitor molecules .
While adsorption isotherm strongly dictates how the inhibitor return curve would be in the adsorption "squeeze" treatment , the solubility of Ca-Inhibitor precipitates has a very strong influence on how the inhibitor return curve would be in the precipitation squeeze treatment. There are essentially two factors governing the inhibitor return curve following a precipitation squeeze commonly observed in carbonate formation; the solubility of the Ca-inhibitor complex and the rate of dissolution of this complex [14, 15]
It is good to appreciate the fact that this chemical processes occurring upon injection of chemical scale inhibitor in to the carbonate formation are primarily controlled by the presence of the divalent cat ions, most notably the calcium ions which are generated in situ as a result of the carbonate mineral dissolutions, this leads to the complexation, a process that is beyond ordinary adsorption/desorption process. Therefore, while the adsorption/desorption process is a common mechanism in sandstone reservoirs, the precipitation/dissolution process is the dominant "squeeze" observed in a carbonate formation.
Contrary to the normal adsorption/desorption processes observed in sandstone reservoirs following a "squeeze" treatment, this paper has demonstrated that; the process is much more complex when the same chemicals are used for the same purpose of mineral scale prevention in carbonate reservoirs, this is because of the high reactivity of the carbonate rock. The main chemical compound that accounts for such high reactivity in carbonate rock is the calcium carbonate (CaC[O.sub.3]), which is a more reactive substrate than the minerals such as quartz, feldspar etc. that are found in the sandstone formation. A slightly soluble Ca-Inhibitor complex is observed in carbonate rock following the injection of chemical scale inhibitors to prevent mineral scale depositions.
Careful analysis of the reactions occurring in carbonate formation following the injection of chemical scale inhibitor in to a carbonate rock, suggests that about four sort of chemical processes occur, namely; carbonate mineral (calcite) dissolution, Ca-Inhibitor complex formation, carbonate rock surface poisoning (due to Ca-phosphonate coating), and re-dissolution of Ca- Inhibitor complex. However, the magnitude at which these reactions occur are determined by several factors including; pH, rock mineralogy, temperature, presence of divalent cations, inhibitor injection rate, shut-in times and flow rate during the production period.
We are thankful to Petroleum Technology Development Fund (PTDF), Nigeria for the full funding of our Postgraduate Studies, under the Overseas Scholarship Scheme (OSS), at two of the World Class Universities in the United Kingdom.
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G. Mohammed (1,2) and A. Galadima (3,4) *
(1) Institute of Petroleum Engineering, Herriot Watt University, Edinburgh, United Kingdom.
(2) Cement Company of Northern Nigeria Plc. P.M.B. 2166, Kalambaina Road, Sokoto, Sokoto State, Nigeria.
(3) Surface Chemistry and Catalysis Research Group, University of Aberdeen, AB24 3UE, Aberdeen, United Kingdom.
(4) Department of Pure and Applied Chemistry, Usmanu Danfodiyo University Sokoto, P.M.B. 2346, Sokoto, Sokoto State, Nigeria
* Corresponding Author E-mail: firstname.lastname@example.org, email@example.com
Table 1: Some chemical inhibitors available to oil industry. Inhibitor Abbreviation Bis(hexamethylene)triamine- penta(methylenephosphonic acid) BHMTPMP Bis(hexamethylene)triamine- Tetra(methylenephosphonic acid) BHTMP Diproplethylenetetraamine- Hexa(methylenephosphonic acid) DETHMP Polyacrylicacid PAA Phosphinopolycarboxylic acid PAA Phosphinopolycarboxylic acid PAA Phosphinopolycarboxylic acid PPPC Sulfonated polyacrylic acid SPA 2-Aminoethylphosphonic acid AEPN Diethylenetriamine penta (methylene phosphonic acid) DTPMP 2-Hydroxyphosphonocarboxylic acid HPAA N-(phosphonomethyl)iminodiacetic acid PMIDA Ethylenediamine tetra(methylene phosphonic acid) EDTMP Phosphonobutane-tricarboxylic acid PBTC
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|Author:||Mohammed, G.; Galadima, A.|
|Publication:||International Journal of Petroleum Science and Technology|
|Date:||Jan 1, 2011|
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