ARTICLE pubs.acs.org/IECR
Effect of Various Cations on the Formation of Calcium Carbonate and Barium Sulfate Scale with and without Scale Inhibitors Malcolm A. Kelland*,† †
Department of Mathematics and Natural Science, Faculty of Science and Technology, University of Stavanger, N-4036 Stavanger, Norway ABSTRACT: High pressure dynamic tube blocking tests have been conducted to determine the effect of iron (divalent and trivalent), calcium, magnesium, and sodium ions on the formation of calcium carbonate and barium sulfate scale with and without added scale inhibitors. Scale inhibitors were chosen to represent the three main functional groups used in commercial oilfield scale inhibitors: the phosphonate group (found in sodium diethylenetriaminepentaphosphonate), the carboxylate group (in sodium polyaspartate), and the sulfonate group (in sodium polyvinysulfonate). A fourth proprietary inhibitor with phosphonate and carboxylate groups was also used in some studies.
1. INTRODUCTION Scale formation is the deposition of sparingly soluble inorganic salts from aqueous solutions.14 It is a major problem for the upstream oil and gas industry during production of well fluids. Scale can deposit on almost any surface so that once a scale layer is first formed it will continue to get thicker unless treated. Scales can block pore throats in the near-well bore region or in the well itself causing formation damage and loss of well productivity. They can deposit on equipment in the well causing it to malfunction. Scale can occur anywhere along the production conduit narrowing the internal diameter and blocking flow and can even occur as far along as the processing facilities. Next to corrosion and gas hydrates, scale is probably one of the three biggest water-related production problems and needs to be anticipated in advance to determine the best treatment strategy. The four commonest scales encountered in the oil industry are calcium carbonate (calcite and aragonite) and sulfate salts of calcium (gypsum), strontium (celestite), and barium (Barite). Small amounts of radioactive radium ions may also be found in the lattices especially that of barium sulfate. Formation water usually contains bicarbonate ions as well as calcium ions. Calcium carbonate can deposit as a consequence due to the following equilibrium moving to the right as the pressure drops 2HCO3 T CO3 2 þ H2 O þ CO2 ðgÞ At some point the concentration of carbonate ions may be high enough that calcium carbonate precipitates Ca2þ þ CO3 2 f CaCO3 ðsÞ In brines with high concentration of iron(II) ions it is possible to obtain iron carbonate deposition in addition to calcium carbonate scale.5 Sulfate scales are usually formed when formation water containing alkali earth metal ions and injected seawater for enhanced oil recovery containing sulfate ions mix. When this occurs in the r 2011 American Chemical Society
near-well bore region of the producing wells it causes precipitation of sulfate scales as formation damage. The commonest method of preventing scale formation in the oil industry is the use of scale inhibitors. These inhibitors work by preventing either nucleation and/or crystal growth of the scale. Most classes of commercial scale inhibitors for carbonate and sulfate scaling contain one of more of the following functional groups: phosphonate, carboxylate, or sulfonate.6,7 It has been known for some time that the presence of iron ions in the aqueous fluids affects both the rate of scaling and the performance of some scale inhibitors. However, the results published to date appear to be conflicting. Thus, one group reported that blank times for CaCO3 scale formation in high pressure dynamic tube blocking tests increased when 10 ppm iron(II) ions were added.5 In addition, using a 3 m scaling coil, low concentrations of iron(II) ions (ca. 5 ppm) did not affect the performance of a polyvinylsulfonate (PVS) inhibitor, but 10 ppm did affect the performance of the PVS and a polyphosphinocarboxylate. However, the 10 ppm solution could have contained up to 5 ppm iron(III) ions using their degassing method (ca. 1 ppm O2 in brine measured). Even when degassing with ultrapure N2 the brine with 10 ppm iron(II) ions (with no possibility of iron(III) ions) still lowered the PVS inhibition performance at fairly low calcium carbonate scaling regimes. A small effect on sulfate scaling by iron(II) ions has been reported.8 In general for both sulfate and carbonate scaling, small aminophosphonate scale inhibitors, such as diethylenetriaminepentamethylenephosphonates, were least tolerant of iron(II) ions, polysulfonate scale inhibitors were hardly affected at all, and polycarboxylate scale inhibitors were intermediately affected by iron(II) ions. These results conflict with another report by a different research group.9 The authors report that in scrupulously Received: February 20, 2011 Accepted: March 29, 2011 Revised: March 19, 2011 Published: March 29, 2011 5852
dx.doi.org/10.1021/ie2003494 | Ind. Eng. Chem. Res. 2011, 50, 5852–5861
Industrial & Engineering Chemistry Research anaerobic conditions that iron(II) ions improved the performance of a phosphonate-based scale inhibitor on carbonate and sulfate scaling regimes. They claim that it is iron(III) ions which are responsible for any reduced scale inhibitor performance. It is also known that the presence of other cations such as magnesium and calcium ions can affect the performance of common scale inhibitors on barium sulfate scaling.10 However, there are different opinions on whether these ions promote or inhibit the formation of barium sulfate. One group showed that calcium ions increased the effectiveness of polyaminophosphonate inhibitors.11,12 It was assumed that aminophosphonate inhibitors form a complex with divalent cations. (This is certainly true since many inhibitors are not compatible with brines with high calcium concentrations and can lead to precipitation of its own “scale”).1 This complex is most likely to occur between the inhibitor and calcium ions. It was proposed that this is one of the reasons that the presence of calcium in the reacting mixture increased the effectiveness of the inhibitor. The increased solubility of the barium sulfate leads to higher levels of calcium incorporation in the lattice. This increased level of calcium in the bulk may be extrapolated to the crystal surface, where the calcium content is much higher than usual. This increases the likelihood of inhibitor surface interactions, as the inhibitor interacts more strongly with the calcium than it would have done with barium. However, in a later paper by another group, an investigation was carried into the effect of calcium ions when additives such as polyaminophosphonates and polyaminocarboxylates were present.13 The study showed that calcium ions promote nucleation of barium sulfate particles when compared to the appropriate control. The result was independent of the analytical method (conductivity or turbidity) used to assess precipitation. The nucleation promotion produced no change in the barium sulfate crystal morphology. The authors also suggest that the extent of nucleation promotion depends on the functional group of the additive. Calcium ions have also been shown to reduce the precipitation of barium sulfate in the absence of added organic chemicals such as scale inhibitors. The change in ionic strength could be partially responsible for this effect. Other possible mechanisms for reduced precipitation (in addition to the ionic strength effect) have been proposed.13 These include the following: • The adsorption of calcium ions onto the barium sulfate surface hindering further barium sulfate precipitation (surface poisoning). • The ion-pair formation of CaSO4 at high calcium concentrations, which lowers the available concentration of sulfate and thereby the supersaturation of the solution with respect to barium sulfate. • The incorporation of calcium ions into the lattice increasing the internal free energy of the crystal (by incorporating foreign ions, the crystal contains more defects and/or strain and is thereby less stable and consequently more soluble). In this report we have reinvestigated the effect of both iron(II) and iron(III) ions on calcium carbonate and barium sulfate scaling without and with 3 commercial scale inhibitors containing the three commonest functional groups of phosphonate, carboxylate, and sulfonate. We have also reinvestigated the effect on scale inhibitor performance of calcium, magnesium, and sodium ions. All the work was conducted in a dynamic tube blocking rig, commonly used by oilfield companies to qualify the performance of scale inhibitors for field applications. This dynamic rig allows
ARTICLE
Figure 1. Schematic of the dynamic tube blocking equipment for scale inhibitor testing.
one to carry out experiments under conditions that attempt to simulate how real scale would build up in oilfield conduits.
2. EXPERIMENTAL METHODS 2.1. Equipment. A schematic of the high pressure dynamic tube blocking rig is shown in Figure 1, and a photograph of the full rig is shown in Figure 2. This is an automated scale inhibitor dynamic test rig assembled and purchased from Scaled Solutions, Scotland. The heart of the rig consists of 3 pumps which can pump fluids up to 10 mL per minute through a microbore coil of 316 stainless steel (SS316). This coil is placed in a heated oven and is 3 m long with 1 mm internal diameter. The initiation and rate of scaling occurring in the coil is measured by recording the differential pressure across the coil. All data are collected on a PC using Labview 8.0 software. The rig is designed for temperatures between 20 and 200 °C and pressures up to 300 bar (ca. 4350 psi). All experiments described in this work were carried out at 100 °C and 80 bar (ca. 1160 psi). 2.2. Test Methods. The equipment was set up to automatically carry out four stages of testing in each experimental run: 1 A blank test with no scale inhibitor 2 A series of tests with scale inhibitor for one hour each at decreasing concentrations 3 A repeat test with the scale inhibitor starting at the previous concentration that led to rapid scale formation in the first series of scale inhibitor tests 4 A second blank test with no scale inhibitor Pump 1 is used to inject scaling cations (Brine 1), Pump 2 is used to inject scaling anions (Brine 2) as well as the coil cleaning solutions, and Pump 3 is used to inject scale inhibitor solution. The software can be automatically set to reduce the scale inhibitor concentration, which for our experiments was every hour. For example, the scale inhibitor concentrations might begin at 100 ppm and decrease to 50, 20, 10, 5, 2, and 1 ppm every hour until scale formation occurs. Rapid scale formation due to failure at any particular scale inhibitor concentration is taken as the point when the differential pressure increases to over 0.5 bar (7 psi). We call this the fail concentration (FIC) of the scale inhibitor, not the minimum inhibitor concentration (MIC). This is to avoid confusion with the operational use of the term MIC defined as the minimum inhibitor concentration which prevents scale formation. If a chemical failed at the first and highest 5853
dx.doi.org/10.1021/ie2003494 |Ind. Eng. Chem. Res. 2011, 50, 5852–5861
Industrial & Engineering Chemistry Research
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Figure 2. The equipment for dynamic tube blocking testing of scale inhibitors.
concentration injected, the test was repeated at higher concentrations to make sure we determined the true fail concentration. Between each stage, the scale in the coil, whether calcium carbonate or barium sulfate, was cleaned out using 5 wt.% tetrasodium ethylenediaminetetraacetate (Na4EDTA) solution at pH 1213 for 10 min at 9 mL/min flow rate and then with distilled water for 10 min also at 9 mL/min flow rate. Five wt.% aqueous acetic acid was initially used to clean out carbonate scaling, but we found that this gave gradual corrosion and leaks within the microbore coil. Coils lined with PEEK (polyether ether ketone) have been used to reduce corrosion risk during such tests.25 The levels of iron ions in the effluent brines, when no iron ions were deliberately added to the brines, were checked by atomic adsorption spectroscopy and shown to be negligible (
