Article Cite This: Energy Fuels 2019, 33, 6197−6204
pubs.acs.org/EF
Sulfonated Nonpolymeric Aminophosphonate Scale InhibitorsImproving the Compatibility and Biodegradability Mohamed F. Mady,* Halvar Malmin, and Malcolm A. Kelland*
Downloaded via BUFFALO STATE on August 1, 2019 at 01:06:17 (UTC). See https://pubs.acs.org/sharingguidelines for options on how to legitimately share published articles.
Department of Chemistry, Bioscience and Environmental Engineering, Faculty of Science and Technology, University of Stavanger, N-4036 Stavanger, Norway ABSTRACT: Phosphonate-based scale inhibitors are widely used in the upstream oil and gas industry, but many of them lack good compatibility with high calcium brines. Here, we report the synthesis of several nonpolymeric aminobismethylenephosphonates with an added sulfonate group to improve the compatibility. The chemicals are 2(bis(phosphonomethyl)amino)alkane-1-sulfonic acid (alkane = methane, ethane, and propane labeled SI-1 to SI-3, respectively), N,N-bis(phosphonomethyl)cysteic acid (SI-4), and N,N-bis(phosphonomethyl) metanilic acid (SI-5). To screen their performance, we carried out dynamic scale loop inhibition performance tests for calcium carbonate and barium sulfate, thermal stability tests, and calcium compatibility tests up to 10 000 ppm calcium ions and compared them to some well-known oilfield scale inhibitors. Seawater biodegradation over 28 days (BOD28) was also investigated by the OECD 306 method. All new inhibitors demonstrated good calcite inhibition properties, but only SI-1 and SI-2 gave fairly good barite inhibition. SI-2 stood out as an excellent calcite inhibitor, suitable for use in very high calcium-containing brines. SI-2 could also provide protection against barite deposition under mild to medium scaling potentials and gave a reasonable rate of biodegradation (BOD28 = 46%). SI-1 and SI-4 gave BOD28 values of 79 and 84%, respectively, and can be classed as “readily biodegradable”. Of the two products, SI-1 seems the most promising for further studies given the better calcite and barite scale inhibition properties. Of the SIs tested, SI-5 showed the best thermal stability at 130 °C and could therefore be a useful downhole squeeze SI for fairly high-temperature wells. Its BOD28 value was 41%. Overall, the study highlights the difficulty of designing a scale inhibitor with all of the major features required for application over a wide range of field conditions.
1. INTRODUCTION Production of hydrocarbons from a subterranean reservoir is usually accompanied by produced water. Depending on the amount and composition of the dissolved ions, the produced water can form inorganic scale deposits.1 Oilfield scaling is one of the top oil and gas production problems related to water and can be formed at any step of hydrocarbon production, including upstream, midstream, and downstream. Oilfield scale can block the reservoir fluid flow in pipelines and equipment such as pumps and valves.2 Calcium carbonate (calcite, CaCO3) and barium sulfate (barite, BaSO4) are the most common oilfield scale in the oil and gas industry.2 For carbonate scales, many formation brines are saturated with CaCO3 because of significant amounts of the mineral in almost all petroleum reservoirs. For sulfate scale, barite is commonly formed due to seawater containing sulfate ions being injected into a reservoir to maintain pressure. Mixing of this seawater with formation water containing barium ions can lead to precipitation of barite scale as formation damage or blocking of conduits.2 Several technologies are employed in the field to tackle the problem of scale formation, both preventative and remedial.3,4 Two of the most widely used preventative technologies are continuous injection (topside and downhole) or squeeze treatment of chemical scale inhibitors (SIs) into the oil production and/or water injection system. SIs are organic chemicals and polymers, which dissolve into produced water to avoid scale precipitation. The mechanism of scale inhibition using SIs includes inhibiting nucleation and crystal growth of © 2019 American Chemical Society
the precipitated mineral, but some SIs also have dispersant qualities. Phosphonate scale inhibitors (SIs) are commonly used in the oil industry, particularly in squeeze treatments as they have good adsorption properties on rock and are easily detected.5 Many commercial SIs for CaCO3 and BaSO4 oilfield scale are polymeric compounds, usually containing multiple carboxylate and sulfonate groups.2 For example, polysulfonates have a lower pKa value compared to carboxylate or phosphonates SIs. In addition, polysulfonates have lower stability constants with calcium and magnesium ions in water. It is well known that polysulfonates SIs show high thermal stability and calcium tolerance.6 Therefore, polysulfonated SIs have often been applied for high-pressure high-temperature applications for oilfield scale.6 Very recently, it has been reported that the small amount of sulfonation groups in the polymer backbone raises the cloud point to prevent the hydrolysis of SIs in different brines in the reservoir at harsh conditions.7 However, commercial sulfonate and phosphonic acid SIs, such as polyvinyl sulfonate (PVS), diethylenetriaminepentakis (methylenephosphonic acid) (DTPMP), and aminotris(methylenephosphonic acid) (ATMP), as shown in Figure 1, show poor biodegradation properties and are to be phased out for offshore deployment in Norway. Received: April 3, 2019 Revised: May 23, 2019 Published: May 30, 2019 6197
DOI: 10.1021/acs.energyfuels.9b01032 Energy Fuels 2019, 33, 6197−6204
Article
Energy & Fuels
Figure 1. Commercial oilfield SIs with sulfonate or phosphonate groups.
Figure 2. Synthesis of sulfonated aminomethylenephosphonates.
formation and seawater water) in this work was based on the Heidrun oilfield, Norway. The dynamic tube blocking tests were carried out for carbonate and sulfate scale at 100 °C and 1200 psi.
In the last two decades, several chemicals have been developed to afford eco-friendly biodegradable SIs but usually with one or more disadvantages.8−10 For example, Devaux et al. patented phosphonate products made from a series of amino acids using the Moedritzer−Irani reaction.11,12 These synthesized phosphonated amino acids were evaluated for CaCO3 and BaSO4 oilfield scale inhibition. However, these scale inhibitors had limited calcium compatibility and thermal stability. In addition, Bendiksen et al. described compositions and methods for inhibiting calcite scale formation using sulfonated aminophosphonates, such as N,N-bis(phosphonomethyl) taurine.13 However, there are no studies of sulfate scale inhibition, calcium compatibility, and seawater biodegradation for the final products.13 We report here calcite and barite and other oilfield scalerelated studies for a series of aliphatic sulfonated nonpolymeric aminophosphonates (SI-1, SI-2, and SI-3) as well as a derivative of a nonproteinogenic amino acid, N,N-bis(phosphonomethyl)cysteic acid (SI-4). Furthermore, we looked for other biodegradable cores that could be easily functionalized with sulfonate and phosphonate groups. Metanilic acid (m-anilinesulfonic acid) with an aromatic ring has attracted great attention for the preparation of cytocompatible sulfonated polyanilines.14 Furthermore, metanilic acid has been used in the fabrication of a new glucose biosensor.15 Herein, we also report scale inhibition studies on a derivative of metanilic acid (SI-5) by functionalizing the amino group with phosphonic acid using the Moedritzer−Irani reaction.16 All synthesized SIs were screened for CaCO3 and BaSO4 oilfield scale against several commercial SIs through a variety of experiments, involving dynamic tube blocking test, thermal aging, Ca2+ compatibility, and biodegradability in seawater. The water composition of the reservoir fluids (50:50 mix of
2. EXPERIMENTAL SECTION 2.1. Chemicals. All starting materials and solvents for preparation of SIs were purchased from Sigma-Aldrich (Merck), Acros Organics, and VWR. The sodium salts of diethylenetriaminepentakis(methylenephosphonic acid) (DTPMP) and aminotris(methylenephosphonic acid) (ATMP) were obtained from Solvay. Hydroxyethyl-N-iminobisphosphonate (tradename Hydrodis) was received from Bozzetto Group, Italy. Polyvinyl sulfonate (PVS, Mw unknown) was supplied by Clariant Oil Services. Poly(4-styrenesulfonic acid-co-maleic acid) sodium salt (SS−MA copolymer, Mw 20 000 g/mol) and N,N-bis(phosphonomethylene)glycine were purchased from Sigma-Aldrich (Merck). 2.2. Characterization of Oilfield Scale Inhibitors. To characterize the target chemicals and to verify the reactions, nuclear magnetic resonance (NMR) spectroscopy was used. The NMR spectra were recorded on a 400 MHz Bruker NMR spectrometer in deuterium oxide (D2O) with two drops of sodium deuteroxide solution. 31P NMR and 1H NMR chemical shifts were recorded in D2O. SI-5 was monitored by thin-layer chromatography using Fluka GF254 silica gel plates with detection under UV light at 254 and 360 nm. 2.3. Synthesis of Oilfield Scale Inhibitors. 2.3.1. General Procedure for the Synthesis of Aliphatic Sulfonated Nonpolymeric Aminophosphonates via the Moedritzer−Irani Reaction. 2.3.1.1. Synthesis of Sulfonyl-Derived Alkyl Moieties Involving 1− 3 Carbon Atoms Incorporating Aminophosphonates (SI-1, SI-2, SI3). To a 100 mL Erlenmeyer round-bottom flask attached with an additional funnel and a strong magnetic stirring bar were placed the appropriate N-sulfo alkane amines 1−3 (1 mol equiv), phosphorous acid (2 mol equiv), and hydrochloric acid (37 wt %, 2 mol equiv) in distilled water (20 mL). The mixture was flushed with dinitrogen gas 6198
DOI: 10.1021/acs.energyfuels.9b01032 Energy Fuels 2019, 33, 6197−6204
Article
Energy & Fuels
Figure 3. Synthesis of N,N-bis(phosphonomethyl)cysteic acid. for at least 15−20 min. Under the protection of dinitrogen gas, the reaction solution was heated stepwise from room temperature (25 °C) to 100 °C, at which time aqueous formaldehyde (37 wt %, 2 mol equiv) was added dropwise. The reaction was refluxed with vigorous stirring at 100 °C overnight. The mixture was cooled to 25 °C, and the solvent of the mixture was collected under vacuum. The crude phosphonate obtained was crystallized from H2O and methanol to yield aliphatic sulfonated methylenephosphonates SI-1, SI-2, and SI-3 in high yields, as shown in Figure 2. 2.3.1.2. (Bis(phosphonomethyl)amino)methanesulfonic Acid (SI1). Yield: 52%, 1H NMR (D2O, 400 MHz) δ ppm: 3.17 (s, br, 2H, 1CH2), 2.61−2.41 (d, br, 4H, 2CH2); 31P NMR (D2O, 162.00 MHz) δ 17.00 ppm. 2.3.1.3. 2-(Bis(phosphonomethyl)amino)ethane-1-sulfonic Acid (SI-2).13 Yield: 71%, 1H NMR (D2O, 400 MHz) δ ppm: 3.78 (t, 2H, 1CH2), 3.48−3.45 (d, 4H, 2CH2), 2.86 (t, 2H, 1CH2); 31P NMR (D2O, 162.00 MHz) δ 22.5 ppm. 2.3.1.4. 3-(Bis(phosphonomethyl)amino)propane-1-sulfonic Acid (SI-3). Yield: 76%, 1H NMR (D2O, 400 MHz) δ ppm: 3.51 (t, 2H, 1CH2), 3.53−3.50 (d, 4H, 2CH2), 3.28 (t, 2H, 1CH2), 2.14−2.10 (m, 2H, 1CH2); 31P NMR (D2O, 162.00 MHz) δ 22.5 ppm. 2.3.1.5. Synthesis of N,N-bis(phosphonomethyl)cysteic Acid (SI4). To a 100 mL Erlenmeyer round-bottom flask attached with an additional funnel and a strong magnetic stirring bar were added cysteic acid 6 (2 g, 11.82 mmol, 1.0 equiv), phosphorous acid (1.94 g, 23.65 mmol, 2 equiv), and hydrochloric acid (37 wt %, 2.30 g, 63.91 mmol, 2 equiv) in distilled water (20 mL). The mixture was flushed with dinitrogen gas for at least 15−20 min. Under the protection of nitrogen gas, the reaction solution was heated stepwise from 25 to 100 °C, at which time aqueous formaldehyde (37 wt %, 1.92 g, 63.91 mmol, 2 equiv) was added dropwise. The reaction was stirred at 100 °C overnight. Then, the reaction was cooled to 25 °C and the solvent of the mixture was collected under vacuum. The crude phosphonate obtained was crystallized from H2O and methanol to afford N,Nbis(phosphonomethyl)cysteic acid SI-4, as shown in Figure 3. 2.3.1.6. N,N-bis(phosphonomethyl)cysteic Acid (SI-4).13 Yield: 54%, 1H NMR (D2O, 400 MHz) δ ppm: 3.58−3.21 (d, 4H, 2CH2), 2.87 (d, br, 2H, 1CH2), 2.35 (t, br, 1H, 1CH); 31P NMR (D2O, 162.00 MHz) δ 17.8 ppm. 2.3.2. General Procedure for the Synthesis of Aromatic Sulfonated Nonpolymeric Aminophosphonates via the Moedritzer−Irani Reaction. To a 100 mL Erlenmeyer round-bottom flask attached with an additional funnel and a strong magnetic stirring bar were added metanilic acid 7 (2 g, 11.55 mmol, 1 equiv), phosphorous acid (1.89 g, 23.10 mmol, 2 equiv), and hydrochloric (37 wt %, 2.25 g, 62.42 mmol, 2 equiv) in distilled water (20 mL). After flushing with dinitrogen for at least 15−20 min, the reaction solution was allowed to heat stepwise from 25 to 100 °C, at which time aqueous formaldehyde (37 wt %, 1.87 g, 11.55 mmol, 2 equiv) was added dropwise. The reaction was stirred at 100 °C overnight. The mixture was cooled to room temperature, and the solvent of the mixture was collected under vacuum. The crude phosphonate obtained was crystallized from H 2 O and methanol to afford N,N-bis(phosphonomethyl) metanilic acid SI-5, as shown in Figure 4. 2.3.2.1. N,N-bis(phosphonomethyl) Metanilic Acid (SI-5). Yield: 53%, 1H NMR (D2O, 400 MHz) δ ppm: 7.51−6.56 (m, br, 4H, ArH), 2.63 (d, br, 4H, 2CH2); 31P NMR (D2O, 162.00 MHz) δ 16.7 ppm. 2.4. High-Pressure Dynamic Tube Blocking Test Methods. We used the well-known high-pressure dynamic tube blocking test method to determine the relative performance of oilfield scale
Figure 4. Synthesis of N,N-bis(phosphonomethyl) metanilic acid. inhibitors. The flow of aqueous fluid through the tube emulates the downhole conditions in a flow line during production. Our dynamic tube blocking rig was built by Scaled Solutions Ltd., Scotland (Figure 5). The scale rig consists of three pumps that pump fluids up to 10.00
Figure 5. Equipment used for high-pressure tube blocking testing of SIs (from left: pump 1, pump 2, and pump 3). mL/min through a 3.00 m microbore coil made of 316 steel with a diameter of 1 mm. The coil is placed in an oven, which in this experiment was set to 100 °C. The pressure in the tube was 80.0 bar.25 In Figure 5, the three pumps are numbered 1, 2, and 3 from left to right. Pump 1 is pumping brine 1 (scaling cations), pump 2 is pumping brine 2 (scaling anions), and pump 3 is pumping the scale inhibitor solution (SI). The results from this dynamic test are able to give a good estimate of the minimum inhibitor concentration (MIC) for the SIs to prevent scaling. An acceptable value of MIC can be from 1 to 100 ppm, but the target is often between 1 and 5 ppm. The test equipment can be used to evaluate the performance of the SI for both calcium carbonate and barium sulfate scales. The scale rig completes four tests in automatic mode: 1. First blank test with no added inhibitor. 2. A first inhibitor test, with decreasing dosages of SI every hour. 3. A repeated inhibitor test. This test starts with the previous concentration of SI that led to scale formation in the first inhibitor test. 4. Second blank test with no added inhibitor. The scale rig is connected to a computer with software that records time and pressure, and controls the injected brine and inhibitor amounts. We set the concentration of SI to begin at 100 ppm and 6199
DOI: 10.1021/acs.energyfuels.9b01032 Energy Fuels 2019, 33, 6197−6204
Article
Energy & Fuels drop to 50, 20, 10, 5, 2, and finally 1 ppm, with 1 h for each concentration until scale is formed in the coil. The lower limit for the SI concentration, which we call the “fail inhibitor concentration” (FIC), is set to the SI concentration where the differential pressure increases more than 0.5 bar (7 psi). (FIC should not be confused with MIC, which is the minimum inhibitor concentration that prevents scale formation). Between each run, the coil is cleaned, first with ethylenediaminetetraacetic acid (EDTA, pH = 12−13) for 10 min at 9.99 mL/min flow rate and for the next 10 min, the coil is flushed with distilled water with the same flow rate. After cleaning, the coil is ready for the next test. In this work, we again chose to use model fluids based on production from the Heidrun oilfield, Norway, as this also allows us to compare with previous results at the same conditions and in the same rig. Tables 1 and 2 show the composition of aqueous produced fluids
Figure 6. Graph showing the four stages of an SI test in the scale rig (pressure−time). ppm), at which point the software switched to cleaning mode. After a new cleaning cycle, the repeat SI test commenced at 215 min, but starting from 50 ppm. At 306 min (i.e., 31 min at 20 ppm), scale formation occurs rapidly again. The fourth peak is for the fourth stage which is the repeated blank test. 2.5. Compatibility Tests. Compatibility tests are needed to check that the scale inhibitor does not precipitate when mixing with formation brines causing formation damage. It is mainly calcium compatibility that is the issue. Chemicals that affect the pH of the produced water will also affect the carbonate scaling potentials.17 In particular, the use of some aminomethylenephosphonate SI derivatives in the presence of high calcium ion concentrations can lead to SI−Ca complex precipitation. This can cause both poor placement of the SI during a squeeze treatment and formation damage and reduced oil production.18 The compatibility test procedure comprises mixing different calcium ion concentrations with various inhibitor concentrations at elevated temperatures to evaluate if precipitation occurs. In our investigation, scale inhibitors of 100, 1000, 10 000, and 50 000 ppm were dissolved in 2 mL of deionized water in 50 mL glass bottles. Sodium chloride (3.0 wt %, 30 000 ppm) and calcium chloride dihydrate in dosages from 10 to 10 000 ppm were then added. The bottles were shaken until all solids had dissolved and the solution looked clear. The bottles were placed in an oven at 80 °C for 24 h. The solutions were checked after 30 min, 1 h, 4 h, and 24 h, and any turbidity and/or precipitation of SIs were recorded. 2.6. Thermal Stability Test. Thermal aging tests are especially needed for high-temperature reservoir application. This is to make sure that the SIs are stable and do not lose efficacy at the reservoir temperature for the expected squeeze lifetime. To carry out this test, a 20 wt % additive solution in deionized water is nitrogen gas-sparged
Table 1. Composition of Heidrun Oilfield, Formation Water, Seawater, and a 50:50 Mixture ion
Heidrun formation water (ppm)
seawater (ppm)
50:50 mixed brine (ppm)
Na+ Ca2+ Mg2+ K+ Ba2+ Sr2+ SO42− HCO3−
19 510 1020 265 545 285 145 0 880
10 890 428 1368 460 0 0 2960 120
15 200 724 816.5 502.5 142.5 72.5 1480 500
from this field. We used 50:50 volume mixture of the formation water and synthetic seawater to produce barium sulfate scaling. To make the brines in Table 2, the salts were mixed with the correct amount of water and stirred until completely dissolved. Then, the brines were degassed for 15 min using a vacuum pump to remove dissolved gas. This was done to avoid bubble formation in the water, which might cause a pump stop and prevent brines from flowing. The EDTA cleaning solution was prepared the same way. Figure 6 shows a typical graph obtained from a single run of the dynamic tube blocking rig, showing, in chronological order, a blank test with no inhibitor, a test to determine the FIC, a repeat FIC test, and finally a repeat blank test. The first blank test gave scale at 15 min. After cleaning for 15−35 min, an inhibitor is injected at 100 ppm. At 95 min, 50 ppm was injected, and at 155 min, this dropped to 20 ppm. Rapid scaling ensued at 195 min (i.e., 40 min after using 20
Table 2. FIC Values for Commercial and New Aromatic Scale Inhibitors (SIs) for Carbonate Scale first blank
first scale test
second scale test
second blank
inhibitor
time (min)
concn. (ppm)
time (min)
concn. (ppm)
time (min)
time (min)
ATMP DTPMP PVS SS−MA copolymer SI-1 SI-2 SI-3 SI-4 SI-5 N,N-bis(phosphonomethylene)glycine hydroxyethyl-N-iminobisphosphonate SI-1a SI-2a SI-5a
7 7 11 10 17 11 6 10 12 12 10 8 12 15
10 20 2 10 1
