High Performance Oilfield Scale Inhibitors

 

CORROS ON97

Paper No.

  9

HIGH

PERFORMANCE

OILFIELD

SCALE

INHIBITORS

Y. Duccini and A. Dufour Nor orssoHaas aas S.A. Pare Technologique Afata -60550 Vemeuil En Haflatte, France W.M. Harm, T.W. Sanders and B. Weinstein Rohm and Haas Company Spring House, PA 19477-0904

ABSTRACT Sea water often reacts with the formation water in offshore fields to produce barium, calcium and strontium sulfate deposits that hinder oil production. Newer fields often have more difficult to control scafe problems than older ones, and current technology scafe inhibitors are not able to control the deposits as well as needed. In addition, ever more stringent regulations designed to minimize the impact of inhibhorx on the environment are being enacted. Three new inhibhors are presented that overcome many of the problems of older technology scrde inhibitors. Keywords:

scale inhibitors, squeeze treatment, oil production, polymers, bwium sulfate, adsorption,

biodegradabilky

Copyright al 997 997 byNACEInter byNACEInternat nation ional. al.R Reques equests tsfor per permi missi ssion on to publishthismanuscriptnanyfO fOrm rm,, inpart inpart or inwhole inwhole mu must st be ma made de inwrit inwritin ing g to NACE NACE

Inte ntern rnat atio iona nal, l, Conf Confe ere ren nces ces rev revision sion,, P.O P.O. Bo Box x 21834 18340, 0, Hous Houstton, on, Texa exas 7721 7721 SS-83 8340 40.. The The mate teri rial al prese resent nted ed and and th the e vi view ews s expr expres ess sed inthis inthis pape paperr are sol solely ely th thos ose e of th the e aut author( hor(s) s) and and are are not not neces ecessa sari rilly endo endors rse ed by th the e Ass Associ ociat atiion. on. Pri Print nted ed inthe U.S .S..A.

 

INTRODUCTION. Water flooding is the most commonly used technique to maintain oil production on offshore platforms. In this process, sea water is injected under pressure into the reservoir via injection wells, which drives the oil through the formation into nearby production wells. Since sea water contains high concentrations

of dissolved salts such as sulfate, chemical reactions

with the formation water can give rise to unwanted inorganic deposits that can block the formation, tubing, valves and pumps. These deposits are primarily composed of BaS04, CaSO~, and SrSOq. In some fields, CaCO~ is a major problem. In the North Sea area, formation water chemistry can vary enormously ‘. In the Central North Sea Province, Ba+’ levels can vary from a few mg/L to over 1000 mg/L and pH varies from about 4.4 (otlen due to high partird pressures of CO,, such as in the Ula and Gyda fields) to over 7.5. In the Northern North Sea province, pHs as high as 11.7 have been measured. In the Southern North Sea, the waters are high salinity, sulfate rich and acidic. Recently, there has been a push for low toxicity chemicals to handle scrde and corrosion problems 2‘7. New inhibitors must now conform to guidelines s~ci~ing

maximum usage for materials having an

im imp pact on the the en env vironmen entt. Since the conditions vary widely and the regulations governing the use of scafe and corrosion inhibitors arc becoming ever more stringent, it is impossible today for a single inhibitor to meet afl the requirements at a commercially feasible cost. The ideal inhibitor that could be used in both downhole squeeze treatments and topside application would require the foflowing properties:  

effe effect ctiive sca calle contro trol at low inh inhibitor tor con concent entrati ratio on.

 

compatibility

 

with sea and formation water.

brdanced adsorption - resorption properties aflowing the chemicals to be slowly and homogeneously released into production water at concentrations that provide effective scal scalee cont contro rol. l.

 

hi high gh ther therma mall st stab abil ilit ity. y.

 

lo low w toxicity an and d hig igh h bbdegr egradabili ility. ty.

 

lo low w cost.

Currently there are a variety of scale inhibitors available such as polyaerylic acid, phosphinocaboxylic acid, sulfonated polymers and phosphonates. None of these are fully satisfactory for the demanding conditions currently encountered in the North Sea. To meet these requirements,

we have developed three new scale control chemistries that we believe

come closer to fulfilling the requirements

of an ideal scrde inhibitoc

1. An improved general purpose scale inhibitor for moderate condhions. 2. A high performance

scale inhibitor for hamh conditions.

3. A low toxicity, biodegradable

inhibitor for environmentally

169/2

sensitive areas.

 

In an emlier paper 8, w wee f~st introduced these chemistries to the North Sea oil production industry. Since then, we have made modifications to further improve their performance attributes and conducted additional studies to more fully evaluate them. In this paper, these tbrw inhibitors arc compared to widely used conventional inhibitors. chemistries and acronyms used to describe all the inhibitors tested are given in Table 1. 1. IMPROVED

SCALE INHIBITOR

FOR MODERATE

The

CONDITIONS.

By moderate condhions, we mean cases where formation water contains reasonable levels of calcium, barium and strontium, and has pH values from about 5.0 to 7.5. An example of this is Forties water (see appendix for details). Under these conditions, DETPMP and phosphinocarboxylic acid (PPCA) perform less than ideally. Polyacrylic acid, although somewhat effective, does not have adsorption - resorption properties suited for squeeze treatment. The product we developed for moderate conditions is a phosphonocarboxylic

acid (P-CA).

This

chemistry is an ‘alloy’ of the chemistry of phosphonates and polycarboxylic acids, and consists of a phosphonatc group at the end of a polycarboxylic acid chain. As will be shown, the chemistry and prope operties of phosphon honocarboxy oxylic acid are are significantly diff diffeerent fro rom m that of phosph osphiinoca ocarboxylic acid acid (P (PPC PCA) A).. Screening of polycarboxylic acids. We compared P-CA to PPCA and pAA at various molecular weights using DETPMP as a control in conventional bottle tests under conditions typical of the Forties Field. The results of these tests are listed in Table 2. Although all the polymeric inhibkors in the table are baaed on carboxylic acids, their responses to Mw arc different. PPCA seems to be insensitive to Mw changes within the ranges studied. On the other hand, better performance is attained with P-CA at lower Mw. For pAA, the trend is that higher Mw produces better inhibition. In this screening test, DETPMP gave the highest BsS04 inhibition, with the commercial P-CA inhibitor second highest. Dosage - performance of PPCA vs P-CA. Dosage performance profdes enable assessment of inhibition et ciency, an importamt parameter in providing effective squeeze life. In Figure 1, BsS04 inhibition is plotted as a function of active inhibitor dosage. As is well known, scale inhibitors often produce a characteristic S-shaped curve in their dosage-performance profile. At the inflection point, tbe inhibitor dosage begins to be high enough to show an effect of controlling the scale. Comparisons of the curves shows that, under these conditions, P-CA requires about 27 ppm to reach the inflection point while PPCA requires about 40 ppm. Stated another way, it requires nearly 50 more PPCA to produce the same inhibkion as P-CA under Forties Field conditions at pH 6. It is clew from this figure that the required minimum inhibitor concentration (MIC) of P-CA is far less than that of PPCA. Adsorption scre reeening. P-CA was compared to PPCA for adsorption onto crushed Tarbert sandstone cores. The composition of the Tarbert core samples used in these studies comprised 74- 78 quartz, 11.5 -12.5   f el eldspar, 7-12 autbigenic clay, 2 muscovite mica and 0.5 lithic fragments. Stock solutions of 2500 ppm active inhibitor were adjusted to pH 3, 4, 5 and 6 using HC1 or NaOH. All tests were prepared using 10 g of disaggregate rock poured into a 50 ml plastic bottle with cap. Twenty ml of 169/3

 

the test solution was pipetted into the bottle, shaken and placed in a 95 ‘C oven for 24 hours. The samples were then vacuum filtered through 0.22 p pore size filter. As shown in Table 3, P-CA gives significantly more adsorption onto sandstone than PPCA. si~]m s~dies g.1°DE’fpMp   so gave higher adsorption th~ PPCA, tdthough DETPMp wm

In

evaluated at pH 3 and 4 only. The data for DETPMP at pH 5 or higher was not given in the earlier studies because they found that at 2500 ppm inhibitor, the phosphonate precipitated in sea water at 95

“c.

Resorption tests - core flooding. Dynamic corefloods were conducted compwirrg PPCA to P-CA in Clashach sandstone cores saturated with high calcium Forties formation water (FW). Five to ten pore volumes of 50,000 mg/L active inhibitor adjusted to pH 4.5 in synthetic sea water (SW) were injected into the core and shut in at 1050 C for 18 hours. Postflush was carried out at 105” C with 20SW/80FW at pH 5.5. At the conclusion of the test, the core was flooded with methanol to displace the brine before drying and examination by SEM for degradation of clays/carbonate and changes in pore morphology. The inhibitor return profiles (Figure 2) show that P-CA has a longer squeeze lifetime in the useful concentration region (a minimum of about 2 ppm active) by approximately a factor of two under these conditions. No permeability decline was observed atler either of the P-CA or PPCA floods. In addition, no residuaf polymer precipitate or silicate dissolution was observed during petrographic examination. Ther Th erma mall stab abiility. Thermal stability tests were conducted on P-CA and PPCA at 2500 mg/L active inhibitor in deoxygenated seawater at pH 5 held at 1700 C for seven days in sealed tetratluoroethylene-lined pressure bombs. BaSO, inhibition efficacy at 24 mgll-. active inhibkor was then evaluated in 50 SW/50 Forties water atpH6after24hoursat850 C. The results (Table 4) show that P-CA retains its high BaSOl inhibition under these conditions. Although PPCA is also unaffected, its performance remains considerably less than P-CA as previously shown. Compatibfity

scre reeening.

Compatibility of P-CA and PPCA were evrduated in sea water, Forties water and a 50/50 blend of SW/FW at inhibitor concentrations ranging from 0.1 to 10 ( as as is basis), and at temperatures up to 950 c. As shown in Figures 3 and 4, P-CA has about the same compatibility as PPCA in Forties water and slightly less compatibility in 50 SW/50 FW. In SW alone, both inhibitors are completely compatible. Eco cottox oxic icit ity y st stud udiies es.. P-CA was tested under OECD guidelines 3f or or aquatic toxicity on a sediment reworker, sheepshead minnow, marine algae and a marine cmstacearr (Table 5). In addition, biodegradation studies and bioaccumulation studies were also conducted using OECD guidelines 11’12. From the results, the predicted no effect concentrations (NEC) for aquatic and sediment dwelling organisms were calculated. The calculated CHARM 4’5hazard quotients (0.030 for sediment dwellers and 0.070 for aquatic organisms) indicate that no significant adverse effects are predicted from the use of P-CA. Under the Harmonised Offshore Chemical Notification Format c, P-CA would likely fall in 16914

 

hazard group C (notification trigger of 150 tons on platform use), downgraded by one group because inherent biodegradation haa not yet been performed. Similar products have inherent biodegradation of >20 Yo,which if the same for P-CA, would allow upgrading to hazard group D (375 tons notification trigger). 2. HIGH PERFORMANCE

SCALE

INHIBITOR

FOR HARSH

CONDITIONS.

For harsh conditions we used synthetic Miller water (see appendix) to evaluate performance. This water is characterised by extremely high levels of barium and low pH, which can produce a severe sc scal alin ing g co cond ndit itio ion. n. Static inhibition tests. Three experimental multiciwboxylate polymers (SMCA-1, SMCA-2 and SMCA-3) were compared to PVS and PPCA for barium sulfate inhibition under the harsh conditions typified by the Miller field formation water at 20/80 and 50/50 SW/FW ratios at pH 4.2 (Tables 6,7 and Figures 5, 6). At 20/80//SW/FW, the largest quantity of barium sulfate scale is expected. At the 50/50 ratio, the driving force for BaSOg scrde formation is highest even though the quantity of scale is predicted to be less than at 20 2018 1801 011S 1SWI WIFW FW 13 13.. At the 20/80 ratio (Figure 5), SMCA-3 was the most effective BaSOg inhibitor, maintaining about 80 inhibition at 15 ppm active. At 15 ppm, SMCA-3 was at least equal to 25 ppm PVS. PPCA had the lowest inhibition in this seriesat31 -36 inhibition after 22 hours. At 50/50//SW/FW (Figure 6), SMCA-3 remains the most effective, with SMCA-2 and PVS second. The PPCA control was not effective under these conditions as expected. Dynamic inhibition - tube blocking tests. To ensure that the performance of the SMCA inhibitors would remain high under the somewhat different mechanism of scale formation found under tube blocking conditions, brief comparisons were made to DETPMP and the PPCA control using the 50 SW/50 Miller water ratio at pH 4. The tests were run in a P-MAC apparatus at 90 “C at 1 Bar, with inhibitor concentration at 8 ppm active. As shown in Table 8, SMCA-2 did not produce plugging of the capillary after 480 minutes and SMCA-1 required over 300 minutes. SMCA-3 was not yet run in this test, but is expected to perform about equal to SMCA- 1 and SMCA-2. In contrast, DETPMP and PPCA plugged the tube at 110 and 120 120 minu minute tess resp respec ecti tive vely ly.. Adsorption scmming. SMCA was compared to PVS for adsorption onto cmshed Tsrbert sandstone cores. The sandstone and test procedures were the same as used for the earlier studies with P-CA. As shown in Table 9, SMCA-2 gives the highest adsorption onto sandstone, and PVS gives the lowest adsorption. SMCA- 1 and -3 gave intermediate adsorption levels. Resorption

studies - core tloodng.

Dynamic corcfloods were conducted comparing SMCA to PVS in Clashach sandstone cores saturated with Miller formation water (FW). Five to ten pore volumes of 50,000 mg/L active inhibitor adjusted to pH 4.5 in synthetic seawater (SW) were injected into the core and shut in at 120 “C for 16 hours. Post flush was carried out at 120 “C with 20 SW/80 FW at pH 5.5. 169/5

 

The squeeze inhibitor profiles of SMCA-2 and SMCA-3 after post flushing are presented in Figure 7. Effective concentrations of SMCA-2 and SMCA-3 are maintained up to about 75 pore volumes. By way of contrast, PVS under the same conditions lasts only to about 10-15 pore volumes. It is likely that the lower resorption of PVS is due to its lack of adsorption onto sandstone as shown in the pr prev evio ious us st stud udie ies. s. Ther Th erm mal st staabi bifi fitty. Thermal stability tests were conducted on SMCA polymers versus other sulfonated polymers and phosphonates at 2500 mg/L active inhibitor in deoxygenated sea water at pH 5 held at 1700 C for seven days in seafed tetrafluorcdhylene-lined pressure bombs. BsS04 inhibition efficacy at 25 mg/L active inhibitor was then evaluated in 20 SW/80 Miller water at pH 4.3 -4.6 after 22 hours at 750 C. The results (Table 10) show that the SMCA polymers retain their high BaSO~ inhibition under these conditions. The other sulfonated polymers tested also retain inhibition, but remain less effective than the SMCA polymers. The two phosphonate polymers lose some effectiveness under these conditions, as has been reported elsewhere 14. Compatibility. Compatibility of SMCA was evrduated in sea water, Miller water and a 50/50 blend of SW/FW at inhibhor concentrations ranging from 0.1 to 10 YO(as is basis), and at temperatures up to 95 ‘C. As shown in Figures 8-13, SMCA is more compatible than HEXA and SPCA in Miller water and in 50 SW/50 Miller FW. DETPMP has a different compatibility profile than SMCA and it is difficult to compare directfy to SMCA. PVS and SCP are both essentially compatible with Miller water and SW//FW bl SW bleend nds. s. 3. LOW TOXICITY,

BIODEGRADABLE

fNHIBITOR.

Process chemistry of poly(Aspartic acid). Poly(Aspartic acid) (pAsp), has been shown to have both barium sulfate scale inhibition and M ~s ~ombination of propties would be of considerable v~ue, corrosion inhibiting properties . especially when combined with the inherent low toxicity and biodegradability of polyarnino acids. However, we have found that tbe particular process used to manufacture this polymer has a major At present, there are three commercird processes used to make pAsp: (a) a im mapleaicct socnidi/tN sH pr~opreorutitees, (b 1)6.thermal polymerization of L-aspmtic acid without acid catalyst, and (c) thermal polymerization of L-aspsrtic acid using acid catalyst. process are su mm mmarized in Table 11.

The properties and advantages of each

In each of the processes, polysuccinimide is first formed (Figure 14). The polysuccinirnide is then hydrolyzed with base to open the ring and form poly(Aspartic acid). The key differences among these three processes are the formation of branched structures and control of moleculru weight. The branched and linear forms of the precursor polysuccinimide are shown in the figure below. Detailed studies of these structures” have shown that tbe maleic acidhmnonia route to pAsp produces low molecular weight products between 1000 and 2000 Mw, and highly branched polymers. Thermal poly(Aspartic acid) produced without acid catalyst forms moderately branched polymers of about 4000 to 5000 Mw. Acid-catalyzed thermal pAsp allows control of Mw to between 5000 and about 40,000 with minimal or no branching.

lew

 

pAsp scale control. Table 12 shows comparisons among the three processes along with a DETPMP control for barium sulfate and calcium carbonate inhibition using jar tests simulating sea water/Forties water//5O/5O and Mille illerr Fie ielld wate water, r, re resp speecti ctive vely ly.. From the table, acid-catalyzed L-Aspartic acid process at 7,100 Mw provides the best barium sulfate and calcium carbonate inhibition of the three processes. Thermal pAsp without catalyst (4700 Mw) provides slightly less inhibkion and Msleic acid/NH, is the least effective of the polymers tested. pAsp corrosion Poly(Aspartic

inhibition. acid) samples made by each of the three processes were compared to a formulated

commercial corrosion inhibitor using the Bubble Test method 18”19.Briefly, the Bubble Test method involved saturating about 400 MI of test solution with C02 and heating it to 50 oC. The corrosion rates were measured by the linear polarization resistance method.

The results of these tests are reported in

Table 13. As in the scrde inhibition tests, the acid-catalyzed

L-Aspsrtic acid process gives the lowest corrosion

rates of the three processes, with maleic acid/NHg giving the highest corrosion rates. Thermal pAsp produces an intermediate

corrosion rate under these conditions.

The formulated commercial

inhibitor produces a lower corrosion rate than any of the unformulated commercial corrosion inhibitors are incompatible reduce risk of coprccipitation

pAsp inhibitors.

Most

with scale inhibitors and must be carefully fed to

with the scale control agent and conconrrnitant

Since pAsp has scale and corrosion inhibiting properties, the incompatibility addition, pAsp has about 1000 times lower toxicity than conventional further advantage.

corrosion

loss of both properties. problem is eliminated.

In

corrosion inhibitors, providing a

It is hoped that properly formulated pAsp will provide a corrosion rate equal to that

of the comm ommercial inhibitors current rentlly availabl blee. Effect of additfvea on pAsp scale and corrosion

control.

We found that certain additives can markedly improve BaSO1 scale inhibition, and in some cases slightly improve corrosion.

The chemistry of the additives is not divulged due to patent considerations.

However, they can be described as low molecular weight, low cost and low-toxicity

materials that are

not normally used in oil production. Table 14 shows BaSOd scale inhibition under the Forties Field conditions as described in Table 12. As shown in the table, the additive has increased the effectiveness level beyond that of conventional

of pAsp for BaSOi inhibkion to a

scale control agents.

Corrosion control has also been improved by a small percentage with this additive. The mechanism of action of these addbives is not certain, and research is ongoing to determine the reasons for the dramatic perfo form rmaance improve ovement obtained. Biodegradability. Poly(Aspartic acid) made by each of the three processes was studied for biodegradability in modified Storm tests, i.e., COZ evolution (similar to OECD test 30 lB, fresh water) and carbon removal. COZ evolution does not fully assess biodegradability. attributable either to incomplete biodegradation

Incomplete COZ evolution could be

or assimilation of carbon by the bacterial population. 169/7

 

On the other hand, the carbon removaf measurements give the total amount of polymer consumed by the organisms, which is subsequently degraded to CO, or assimilated by the cells. If the carbon removal data also shows incomplete removrd, then the bafance would be undegraded materiaf at the conclusion of the test. Undegraded polymer in these tests may accumulate in the environment, assuming no further degradation occurs beyond the plateau reached at 28 days in these tests. Due to the variable nature of these tests, numerous samples were tested in the modified Sturm test as presented in Figures 15 and 16. Carbon removal and C02 evolution of acid (H~PO~ catalyzed pAsp is essentially complete biodegradation

and no accumulation

in the environment.

acid (uncatafyzed) by the two tests shows that biodegradation

100 , indicating

Evaluation of thermal polyaspartic

of polymer made by this process is

approximately 7570, indicating that there is a risk of some accumulation in the environment by these measures. Polyaapartic acid made by the maleic acid/NHq process generally produces about 60-7070 biodegradation,

afso indicating a risk of accumulation

in the environment.

Additional biodegradability studies on 7,100 Mw pAsp were conducted in sea water using OECD method 306. In repeat tests, biodegradation reached approximately 70 in 28 days, which is considered ready biodegradability. This result is consistent with CHARM recommendations 5, wh whiich suggests a safety factor of 70 he applied to ftesh water tests. This result implies that the other processes for making pAsp, which typicrdly give 60- 75 biodegradation in fresh water tests would likely be degraded 40 to 60 in sea water under OECD method 306, and would thus not be considered re read adil ily y bi biod odeg egra rada dabl ble. e. 4. MECHANISTIC

STUDIES

- STABILITY

CONSTANT

AND ADSORPTION.

A comprehensive expkmation of the role of inhibitor functional group, ionic matrix and adsorbent substrate on the mechanism of adsorption is given in reference 10. A straightforvmd method of comparing the fundamental properties of inhibitors without knowing details of the functionafities present (e.g., sulfonate, phosphino, or carboxyl) is to measure their This approach often allows evacuation of effects of polymer structure appa appare rent nt st stab abil ilit ity y cons consta tant nts’ s’.. such as type of sulfonate monomer and the proximity of other fmrctionalities that can make an acidic group stronger or weaker. Stabi tabillity con onst staant nt.. The stability constant of a Iigand (in this case an anionic polymer) is defined from the equilibrium cons onstant, &:

K=

[

]

[I@”] [L-”]

The stability constant is equal to log &. A higher stability constant means that the polymer (L-n) has a higher affinity for the metrd ion (M+”). A difference of one unit in the stability constant equals

169/8

 

an order of magnitude difference in the metal-polymer affinity. By way of contrast, the acid dissociation constant below (IQ, is actually the reciprocal of the equilibrium constant with M’” equal to P: [H [H+] +] [A [A-] -]

~.

[HA] The p~ is equrd to -log L, with larger numbers indicating greater affinity of the anion (polymer) for ~. At haff neutralization, pIQ = PH. We determined the calcium stability constants for the four polymeric inhibitors: SMCA, P-CA, PPCA and PVS. The results in Table 15 show that P-CA and SMCA have much higher stability constants than PPCA, with PVS having the lowest stability constant. Stability conatsnt versus adsorption. A plot of inhibkor adsorbed at pH 5 as a function of apparent stability constant (Figure 17) shows a li line near ar rela relati tion onsh ship ip.. The relationship

also holds true for pH 3, but is further from a straight line. Thus, other factors

being equal, the higher the stability constant, the greater the adsorption. The data become more linear as pH is raised because the measured stability constant includes the entire molecule at its endpoint, which is generally about pH 6 or 7. At pH 5 or below, the molecule is incompletely ionized and not all the ionizable functional groups are participating. A more direct comparison can be made if the apparent stability constant is measured using only the ionized parts of the molecule in the calculation. DETPMP was not included in this series because the adsorption studies for it were not performed at the same time, introducing an additional variable into any correlations. However, the reported stability constant of DETPMP ranges from about 6.6 to 7.1, which suggests that it may favor excessive adsorption and precipitation under certain conditions, such as very high calcium and pH >5.

CONCLUSIONS. 1. A new polymeric inhibitor for moderate oilfield conditions, phosphonocarboxylic acid (P-CA), gives significantly improved prforrnance over PPCA (phosphinocarboxylic acid). Among the attributes of P-CA are  

impr improv oved ed BaS04 in inhi hibi bittion. ion.

 

increased adsorption on sandstone. ne.

 

improved resorption

.

good compatibility.

 

low low to toxi xici city ty..

profile resulting in longer expected squeeze life.

18

9

18

9

 

2. A new sulfonated multicarboxylic acid (SMCA) polymer class has been shown to have excellent performance over conventional chemistries under harsh oilfield conditions. Among the attributes of SMCA under harsh conditions are  

markedly improved BaS04 inhibition at low pH.

 

increased adsorption over other polymers used in this application.

 

improved resorption

profile over PVS.

3. A process for making highly biodegradable poly(Aspartic acid) has been identified that provides scale control and corrosion inhibition in a single molecule. Poly(Aspartic acid) provides the following advantages:  

.

Risk of performance loss due to incompatibility of scale and corrosion inhibitors is eliminated. Toxicity of pAsp is about 1000x less than conventional corrosion inhibitors.

4. The process used to make poly(Aspartic acid) affects key properties due to differences in branching and Mw of the resulting polyamino acid  

Maleic acid/NHg process, although lowest in cost, provides the poorest scale and corrosion

control, and limited biodegradability

in 28 day tests. This is likely due to the highly branched

structures that result from this process. The L-Aspartic acid process without catalyst has adequate scale control properties, marginal corrosion control and incomplete biodegradability as measured by modified Sturrn tests. These properties are likely to be related to the intermediate branching that occurs with polyamino acids made by this process.  

L-Aspmtic acid, acid-catalyst process provides the best scale control and corrosion protection of the three pAsp processes evaluated. Complete biodegradability of pAsp made by this process is also noted. The superior properties of pAsp made by this process likely derive from the essentially nonbr braanched structures that are produ oduced.  

5. We provided a simple mechanistic

evaluation procedure, which shows how stability constant

measurements can be predictive of adsorption characteristics composition are not known.

of an inhibitor, even if the details of

ACKNOWLEDGEMENTS. We would like to express sincere appreciation to Dr. K.M. Yocom for pAsp and biodegradability studies, to J.J. Karwoski for application studies and to T.F. McCallum for synthesis work. REFERENCJL L 1. Wwren, E.A. and Smalley, P.C., “North Sea Formation Water Atlas”, Memoir No. 15, The Geological Society of London, publisher, 1994. 2. ECETOC. 1993. Environmental hazard assessment of substances. European Centre Ecotoxicology and Toxicology of Chernicrds, Brussels, Belgium. Technical Report No. 51,92 pp.

for

169/10  

3. OECD. 1995. Guidance document for aquatic effects assessment. Organization for Economic operation and Development, Paris, France. OECD Environment Monographs No. 92, 116 pp.

Co-

4. Schobben, H.P.M., Karman, C.C., Scholten, M. C.Th., van het Groenwoud, H.. 1994. CHARM 2.0. TNO Laboratory for Applied Marine Research, Den Helder, Netherlands, 34 pp. 5. Vik, E.A. and S. Bakke. 1994. CHARM: An environmental risk evaluation model for offshore E&P chemicals: Technical background report on the use of safety factors for environmental information and fraction released to the environment, Phase 1. Aquateam-Norwegian Water Technology Centre A/S, Report No. 94-005, Oslo, Norway, 29 pp. 6. MAFF Directorate of Fisheries Research, “Guidelines for the UK Revised Offshore ChernicaJ Notification Scheme in Accordance with the Requirements of the OSPARCOM Harmonised Offshore Chemical Notification Format”, July 1996. 7. Hendriks, R. and Henriques, L., “The Implementation of CHARM in The Netherlands”, paper No. 11, 7tb International Symposium of Oilfield Chemicals, Geilo, Norway, March 17-20, 1996. 8. Duccini, Y., Dufour, A., Hamr,W.M., Sanders, T.W. and Weinstein, B., “Novel Polymers as Scale Inhibitors for Squeeze Treatment”, paper No. 7, 7th International Symposium of Oiltield Chemicals, Gcilo, Norway, March 17-20, 1996. 9. Jordan, M.M., Sorbic, K. S S.., Yuan, M.D., Taylor, K., Hourston, K. E E.., Ramstad, K. and Griffin, P.: “The Adsorption of Phosphonate and Polymeric Scale Inhibitors onto Reservoir Mineral Separates”, presented at the Fitlh International 011 Field Chemicrds Symposium, March 1994, Geilo, Norway. 10. Sorbic, K. S. S., Ping Jiang, Yuan, M. D., Ping Chen, Jordan, M.M., and Todd, A. C. C.: “The Effect of pH, Calcium and Temperature on the Adsorption of Phosphonatc Inhibitor onto Consolidated and Crushed Sandstones”, SPE 26605, presented at Society of Petroleum Engineers, Houston, TX, 3-6 Octobe ober 1993 993. 11. OECD 1989. Guideline for testing of chemicals: Partition coefficient (n-octanol/water), High Performance Liquid Chromatography (HPLC) method. Organization for Economic Co-operation and Development,

Paris, France. OECD Guideline 117, 14 pp.

12. OECD 1992. Guideline for testing of chemicals: Biodegradability in seawater. Organization Economic Co-operation and Development, Paris, France. OECD Guideline 306,29 pp.

for

13. Yuan, M.D., Todd, A. C. C ., Sorbic, K. S. S.: “Sulphate Scale precipitation Arising from Seawater Injection - A Study with Aid of a PC-Compatible Prediction ModeY’, Department of Petroleum Engi nginee neering, ng, Heriot-Watt Univer versity, Edinbu nburgh, 199 1992. 14. Wilson, D., “Novel Polymeric Scale Inhibhor for High Barium, Low pH Reservoirs”, Corrosion/95, 95, 1995.

UK

15. Harm, W.M., Zini, P. and Swift, G.: “Biodegradable Poly(Aspartic acid) as a Multifunctional Additive for North Sea Extraction Operations”, poster presented at 4tb International Workshop on Biodegradable Polymers, Durham NH, October 11-14, 1995.

16 169/ 9/1 11  

16. Freeman, M.B., Paik, Y.H., Swift, G., Wolk, S. and Yocom, K.M. : “Biodegradable Detergent Polymers - Poly(Aspartic Acid)”, paper Presented at Am hemical Society Nationa onal Meeting, Amer eric ican an Chem March, 1994. 17. Freeman, M.B., Paik, Y.H., Swift, G., Wilczynski, R., Wolk, S. and Yocom, K.M. : “Biodegradability of Carboxylates: Structure-Activity Studies”, Chapcter 10, ACS Symp. Series 627, Hydro~els and Biodegradable Polvmers for Bioarxiications, American Chemicrd Society (1996). 18. McMahon, A.J. and Harrop, D.: “Green Corrosion Inhibitors: an Oil Company Perspective”, Paper No 32, presented at Corrosion/95, Orlando, FL, March 26-31, 1995. 19. Webster, S., Hamop, D., McMahon, A.J., and Partridge, G.J.: “Corrosion Inhibitor Selection for Oilfield Pipelines”, Corrosion/93, Paper No. 109, Houston TX March, 1993. 20. Harm, W.M.arrd Robertson, S.T., “Control of Iron and Silica with Polymeric Dispersants”, presented at the International Water Conference, Pittsburgh, PA, October 21-24, 1990.

169/12  

Table 1- Description

of Inhibitors

Evaluated Mw(]) or FW

Inhibitor

Chemical

P-CA PPCA pAA SMCA Pvs SPCA SCP DETPMP HEXA

ph phos osph phon onoc ocaarb rbox oxyl yliic ac aciid po poly lym mer ph phos osph phiino noca carb rbox oxyl yliic ac acid id pdyacrylic acid su sullfo fona nate ted d mul ulttica carb rbox oxyl ylic ic acid acid pol polym ymeers polyvinyl sulfonate sulfonated phosphlnocsrboxylic acid sulfona sul fonatc4 tc4ii copoly copolymer mer diet diethy hyle lene netr tria iami mirr rre( e(pe pent ntam amet ethy hyle lene neph phos osph phon onic ic tripr riprop opyl yleene nete tetr tram amin ine( e(he hexa xarn rneeth thyl ylen eneephos phosph phon onic ic

(1)All ~ol oly ymer~ ~em ~emu~

Description

acid acid)) ac acid id))

3800 3100 2000 or 4500 3000 to 4000 7300 3000 3000 573 738

relative tOpol Opolyacryl yliic acid standards. The pho phosphonate form rmu ula weights ~e

li lite tera ratu ture re valu values es..

Table 2- Effect of Irddhitor Chemistry and Mw on BaSOi Inhibition Forties Field Conditions (50/50 SW/FW, 85 “C/24 bra, pH 6,24 ppm active polymer) In Inhi hibi bito torr

Mw

Desc Descri ript ptiion

 

2000 4500 3110 3620 4090 316Q 3810 4800 7400 --

pAA pAA PPCA PPCA,, ex expe peri rime ment ntal al PPCA PPCA,, ex expe peri rime ment ntal al PPCA PPCA,, ex expe peri rime ment ntal al PPCA PP CA,, comm commer erci cial al P-CA P-CA,, co comm mmer erci cial al P-CA P-CA,, ex expe peri rime ment ntal al P-CA P-CA,, ex expe peri rime ment ntal al DETPMP

BaSO BaSOd d In Inhi hibi biti tion on 26.1 37.5 32.8 25.4 33.3 39.1 66.2 52.0 46.2 83.7

Table 3- Static Inldbitor Adsorption onto Crushed Sandstone (Tarbcrt Core,950 C, reported as mg inhibitor/g sandstone) Inldbitor

pH 3

pH 4

pH 5

pH 6

PPCA P-CA

2.37 3.14

2.22 2.94

2.16 3.58

2.20 3.77

169/13  

(

Table 4- Thermal Stability at 170 “C BaSOl Inhibition, Forties Field conditions) (avera verage ge of 3 replicates) w 62.6 32.2 71.4

P-CA PPCA DETPMP

Zxlal S 68.8 32.3 76.8

Tbenna Tbe nnall stabMy stabMy te test st condhion ions: 25Cllm llmg gll activ tive inh inhibitor in deoxygenated SW at pH 5 held at 170 “C for 7 days. Fortie rtiess Fie ield ld con conditio itions ns:: 2App Appm acti active ve (as (as acid acid)) inbi inbib bkor, 50/50/ /50//S /SW WiF iFW W, pH 6.4.4-6,7,8 ,7,85 5

Table 5Species CoroRhiu iun nr CJpri;odon Skeletonema Acartia

volutator variegates costatum tonsa

Summary

of Aquatic

“C “C,, 24 hr.

Toxicity Studies on P-CA

Description

Endpoint

Value (95 CI)

Sediment reworker Sheepshead minnow Marine algae Mari Ma rine ne crus crusta tace cean an

10 da day EC50 96 ~ LC50 72 h hrr EC50 48 hr LC50

>10000 mgilw >1000 m~>9000 mg/L 950 mglL

Table 6- Barium (95”C, pH 4.2,20

Sulfate Inhibition SW/80 Miller FW,l

Chemical

(Act ctiv ive) e) Ptrm (A

2 Hour Mesrr

SMCA-1 “

10 15 25

33 57 70

36 59 67

SMCA-2

10

22

25

‘, ‘,

15 25

44 56

40 53

PPCA PP CA Comm Commer erci cial al “ ,,,,

10 15 25

41 54 65

31 36 34

Pvs “ ,’

10 15 25

30 44 58

32 44 48

“

22 Hour Mesn

169/14  

Table 7- Barium Sulfate Inhibition (95”C, pH 4.2,50 SW/50 Miller FW) 2 Hour Mean

22 Hour Mean

25 50 ’75

18 33 45

5 8 9

SMCA-2

25

19

14

“ “

50 75

41 54

28 30

PPCA PP CA Comm Commer erci cial al ‘, “

25 50 75

12 20 27

2 3 5

Pvs ‘, “

25 50 75

15 28 33

5 7 7

ChemicaJ

PD m

SMCA-1 “ ‘,

(Active)

Table 8- Dynamic

Inhibition

Mw --

Inhibitor Blank (no polymer) PPC PP CA co cont ntro roll DETPMP SMCA-1 SMCA-2

3200 573 3500 2750

Teat Results Time Before Plugging, 60 120 110 M80 307

Table 9- Static hddbitor Adsorption onto Crushed (Tarbert Core,950 C, reported as mg/g)

Sandstone

Itddlitor

pH 3

pH 4

pH 5

PH 6

SMCA-1 SMCA-2 SMCA-3 Pvs

2.19 3.97 3.03 0.41

2.17 4.01 2.53 0.97

2.78 4.41 2.52 0.64

2.58 4.17 0.98 0.26

minutes

169/15  

Table 10- Thermal Stability at 170 “C ( BaSOq SOq In Inhi hibi bittio ion, n, Mil Miller Fi Fieeld co cond ndiition tions) s) (all data arc single data points, except where noted)

  daYs

--

SMCA-l SMCA-2 SMCA-3 SPCA Pvs SCP DETPMP HEXA

--

51.8 35.6 30.8 32.2 36.2 47.8

mm 55.3 48.0 53.7 36.2 31.9 33.6 14.8’ 34.7

‘ average of 2 repeats.

MillerField MillerFiel d condit condition ions: s: 25 ppm acti active ve (as acid) inhib inhibitor itor,, 20/8 20/8CWSW CWSW/FW, /FW,pH 4.34.3-4. 4.6, 6,75 75 “C “C,22 ,22 hr hr.. Therma The rmalstab lstabili ilitytes tytestt condit condition ionss 2500 2500 mg deoxy oxyge gena nate ted dSWat PH 5 he heldat ldat 17 170“Cfo 0“Cforr 3 or 7 days days mgll ll activ activee inhibitorin de Table 11- Comparison Manufacturing

Process

of Proceaaes to Manufacture Po Poly lyme merr

Char Charac acte teri riza zati tion on

poly(Aspartic

Acid)

Advantages

Male Ma leic ic acid acid/N /NHg Hg

Mw 2K Drdtons; highly branched

lowest cost

L-aapsr psrtic acid, no catalyst

Mw 4-5K Daltons; branched

improved ved scale contro roll

LL-aa aapa part rtic ic acid acid,, acid acid-c -cat atal alyz yzed ed

Controlled Mw from SK to about 40K Daltons; linear polymers

improved ved scale contro roll improved corrosion control comple com plete te biodeg biodegrad radabi abilit lity y

169/16  

Table 12- pAsp Scale Inhibition

Jar Teat Results  

Proeesa

Mw or FW (1)

BaS04

Inhibition

  ( 2)

CaC03

Inhibition

.-

0

0

2,000

4

47

L-Aspartic acid, no ca c atafyst L-Aspartic acid, acid catalyst

4,700 7,100

21 25

65 75

L-Aspmtic acid, acid catalyst L-Aspartic acid, ac a cid ca catalyst (DETPMP co control)

12, 500 22, 000 573

21 22

66 55 50

(Control, with ithout Maleic acid/NH,

inh in hib ibit ito or)

29

(3 )

(1) Mw of the polym lymers rela elativ tive to ind industry try stan standa dard rd poly polyrr rrcr cryl ylk k acid acid star starrd rdar ards ds we were re as foll follow ows: s: Male Maleic ic/N /NH, H, = 2,00Q L-Aspar arti ticc aci cid, d, no catr atrdyst = 4,700; L-A -Assparti articc acid cid, aci cid d cat catal aly yst = 10,000, 18,000 and and 28,000 respectively. (2) SwEorties Field water ter//5 //5O/5Oa /5Oatt 85 oC, 24 mg/L solid lid inhibitor add dded ed (3) Mi]ler Field water at 95 oC, 25 mg/L solid inhibitor added. Table 13- pAsp Corrosion Process

Mw

Irddbition

Bubble

Initial

2 b ra

Test Results

( 1)

Corrosion ram mpy 4 hr a 6 hr s

10 h r a

Male Ma leic ic ac acid id/N /NH H,

2, 000

--

129

50

48

41

L-A L-Asparti ticc aci cid d, no cat ataaly lysst L-A L-Asparti ticc aci cid d, aci cid d cataly talysst L-A L-Asparti ticc aci cid d, aci cid d cataly talysst

4, 700

-122

125 138

25 21

23

20

105

119

20

17 17

15 15

128

140

3

3

2

(F (For ormu mula late ted d comm commer erci cial al in inhi hibi bito torr cont contro rol) l)

7,100 22,000 --

(1) Forties Field water, 25 mg/L solid inhibitor, 50 “C, 1 bat C02, PH 5.6. Table 14- Effect of Additive

on BaSO, Scale Inhibition Additive

Inldbitor L-Asp, acid catalyst

Mw 7, 100

L-Asp, acid catalyst L-Asp, acid catalyst L-Asp, ac acid id cataly talysst

7, 104I 12, 500 12,500

Concentration, 0 4. 8 0 4. 8

by pAsp  

ppm

BaSO,

Inhibition 13 100 14 100

169/17  

Table 15-

Adsorption

Inhibitor

end Apparent

Apparent

Stability

Stability

Constant

Constsnt

-3.5 4 2.5 -1

SMCA P-CA PPCA Pvs

of Polyaneric

Irddbitors

  Inhibitor pH 3

Adsorbed pH 5

79.0 62.8 47.4 8.2

88.0 71.6 43.2 12.8

‘1)

m from Z. ~ of 2500 ~pm solution of active inhibkor solution applied to 10 g of cmshed T~befi smdstone at 95 “C, calculated by (mg inh]b]to ]tor adsor orb bed per g sandstone/mg applied inhibitor) x 100.

Appendix Ionic

Composition

of Forties

Wster,

(Aii Compositions

Miiier

Wster

sndSesWster

in mg/L)

W50

2WS0

50/50

.2W80

Ion

Fortlas

Sea Water

SWiFortias

SWIForties

Miller

Sea Watar

SW/Mlllar

SW/Millar

Na

29370

103su

20134

25674

36mo

10690

23445

30s7s

K

372

460

416

390

2500

460

14s0

2092

Mg

504

136a

936

677

203

136a

764

434

Ca

2803

42S

1618

2333

2100

42S

1264

1766

Sr

574

287

459

450

225

3ao

Sa

252

126

202

1000

500

803

c1

52360

19766

38063

45a41

65@30

19766

42363

55953

2960

14s0

592

2960

1440

592

So4

169/18  

Figure Dosage

Performance

1 of P-CA vs PPCA

100 T

90

20

10 0 o

10

5

15

20

25

30

35

45

40

50

Acti tive ve Poly Polyme merr ppm Ac

Figure Squeeze

14-

2

Inhibitor Resorption for P-CA and PPCA

Profilas

I

12- -; F g

“’.., lo- -

~

c

~ .=

..*..

g ~8

P-CA PPCA

--

c 8 &6 .X .Z = ~4 .?

--

--

y 8

2 2 --

Q, .,,

o~ o

=...~.~..

50

.***

.. . . . . . . . . . . . . . . . . . .... .... .... 100

150

De Deso sorp rpti ticm cm (Por (Pore e Volu Volume mee) e)

— 200

, 250

I

300

169/19  

Figure Compatibility (Forties

 

of P-CA va PPCA

Formation

Water)

“r

L] L] m PPCA

Compat Com patibi ibilit lity y Region Region

OL

20

30

7J

60

50

40

Temperature

Figure

 

I

W

Yu

a )0

80

90

100

~C)

4

Compatlbllity of P-CA (50/50 Forties

Formation

Water/Sea

Water)

12-

10 ~ % m =8 ~ 66 .% s .Z g

~~

%4

~~

  n

2 ~~

0

20

30

40

50

60

Tamp Tamper erat atur ura a ~C) ~C)

70

169/20  

Barium

Figure

5

Sulfate

Inhibition

(95”C, 20 SW/80

2 hours

Miller FW)

It

 

15 ppm PVS

 

25 ppm PVS



15 ppm SMCA-3

 

25 ppm Sh6C Sh6CAA-3 3

2hours 2hours

Resi Reside den nce Ti Tim me

Figure

Barium Sulfat ate e (95”C, 50 SW/50

6

Inhi nhibition Miller FW)

80

1

70 604

950 

75 ppm PVS



50 ppm SMCA-3

975

2 ho hour urs s

Time

22hours

ppm PVS

ppm SMCA-3

169/21  

Figure Squeeze

7

Inhibitor

for SMCA-2

Profiles

and SMCA-3

 

50

0

100

150

Reso esorpt ptio ion n

Figure Compatibility

i

200

250

300

(Po (Pore Volu lume mes) s)

 

of SMCA-3

(Miller Formation

Inhibitor

Water)

Co Comp mpsti stibi bill llty ty Regi Region on

20

30

40

50

70

60 Temperature

~C )

80

90

100

169/22  

Figure Compatibility

9

of SMCA-3

(50/50 Miller Formation

20

30

40

50

Compatibility

Water/Sea

60 Tempereture

Figure

Inhibitor Watar)

70

80

90

t 00

90

100

~C)

10

of Commercial

(Miller Formation

DETPMP

Inhibitor

Water)

12-

10 @ 2 m 98

Compatibility

Region

~ :6 .= ~ c = E4 g &

2 ~~ X//’/ o 20

30

40

50

60 Temperature

70 ~C)

80

169/23  

Figure Compatibility

of Commercial (50/50 Miller Formstion

20

30

40

50

11 Phosphonete Inhibitors Water/Sea Water)

60 Temperature

Figure Compatibility

70

80

90

100

60

90

100

~C)

12

of Commercial

(Miller Formation

SPCA Inhibitor Water)

o

20

30

40

50

60 Temperature

70 ~C)

169/24  

Figure Compatibility

of Commercial

(50/50 Miller Formation

20

30

40

13

50

SPCA Inhibitor

Watar/See

60 Tem emp perat eratur uree

70

Water)

80

~C ~C))

Line Linear ar Form Form

JkkkX-”” 0

Figure

14- Linear

0

vereue Branched

0:

poly(Succinihnide)

90

I

100

169/25  

Figure

16

169/26  

Figure “/. Inhibitor Adsorbed

17 ve Stebility

Constant

90-

 

80.

70~60. :50. s .2 40.5 =   300 20-

10 0 ]-.

1

 –—-—

2

Stab Stabii iiit ity y

Co Cons nsta tant nt

3

4