SPE 155124 Prediction of Mineral Scaling in a MEG Loop System of a Gas Production Offshore Baraka-Lokmane, S. 1, Hurtevent, C. 1, Ohanessian, J-L. 1, Rousseau, G. 1, Seiersten, M. 2, Deshmush, S. 3, 1 Total, 2 Institute of Energy Technology, IFE, 3 Aker Solutions Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Conference and Exhibition on Oilfield Scale held in Aberdeen, UK, 30 31 May 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract An offshore gas field located in the Far East has two reservoirs: reservoir A and reservoir B. Production fluids consist of gas and hydrocarbon condensate with some produced water from the two reservoirs. The producing fields are in water depths varying between 250 and 275m with ambient seawater temperatures and operating conditions that result in only occasional concerns about potential hydrate formation in the production systems. Lean Monoethylene Gylcol (MEG) is injected near the wellheads for hydrate inhibition. This paper presents the risk of mineral scaling at critical points throughout the process with the three production scenarios: reservoir A alone, reservoir A and reservoir B, and finally reservoir B alone. Special attention has been put on the effect of mixing produced waters from reservoir A and reservoir B topside. Furthermore there are considerable uncertainties with respect to the amount of organic acids that may be produced; therefore some evaluations have been performed with and without organic acids. Introduction The Far East gas/condensate field consists of two reservoirs: A and B. It is a High Pressure High Temperature (HTHP) field with a Flowing Tubing Head Pressure (FTHP) from 27500 kpa to end of plateau pressure of 4800 kpa. The maximum FTHP temperature varies between 135 C (A reservoir) and 155 C (B reservoir). Reservoirs A and B are sour gases containing respectively 8 and 15% of CO 2. The early phase of production will be from reservoir A and will be boosted by reservoir B when reservoir A begins to decline (expected at Year 12.5). The fluids will be processed on a Central Processing Facility, where primary gas/liquid separation will take place. The liquids will then be sent via subsea transfer lines to a Floating Production, Storage and Offloading facility (FPSO) where further processing and MEG regeneration will be carried out. The design of the MEG Regeneration Plant covers two phases of this project represented by cases 1 and 2 as described below. Case 3 covers the sensitivity case and due to uncertainties is not covered in the design but rather commented on with respect to the design. Case 1 is for the produced water from reservoir A and represents the first 9.5 years of production. Case 2 represents the maximum produced water rates and will be a combination of the produced water from reservoirs A and B and covers the years 9.5 to 16. After 12.5 years, the production of reservoir B will start up and the highest Rich MEG rates are reached with peak water production in Year 16. Case 3 (the sensitivity case) represents the highest formation water rate and covers years 16 to 22.5. The largest production of salts will be later in field life, when the production of reservoir A declines whereas the production of reservoir B will increase. An ever increasing number of gas condensate fields are being operated with MEG as the hydrate inhibitor 1,2. MEG injection will manage and prevent hydrate formation at the offshore facilities and the pipelines. Two MEG Regeneration Packages will be designed for this project (Figure 1).
2 SPE 155124 The purpose of this study is to map the ph of the MEG loop in order to determine the potential scaling points and to estimate the chemical dosing rates required, to avoid scaling in the said points. The chemical injection rates determined in this study will also be used to determine the Reclaimer size in the MEG Regeneration plant, as some of the chemicals injected must be removed to avoid the build up of salts in the MEG loop. Input data The reservoir data are presented in Table 1. Table 2 gives the formation water analyses. It is noted that both the calcium concentration and the bicarbonate (HCO 3 - ) concentration in the input data are high; this may be a result of including carboxylates in the bicarbonate value. In presence of organic acids, the bicarbonate concentration does not have a definitive value. The parameter that governs the bicarbonate concentration and the speciation of the organic acids is the total alkalinity. That is used in the present calculation and it is set to the value that gives SR=1 for CaCO 3 at the given reservoir conditions. The given reservoir conditions are the same for Case 2 and 3 and hence the tuned formation water analyses are identical (Table 3). The formation water properties are presented in Table 4. The calculated and given condensed water rates are presented in Table 5. The hydrocarbon composition used in the evaluation is given in Table 6. The hydrocarbon composition changes with time is small, therefore the same compositions were used for all cases. The water, MEG and gas production rates are summarized in Table 7. The organic acids are volatile and will be produced with the gas as well as the formation water. The amount produced with the gas was estimated by performing a flash calculation at reservoir conditions. The reservoir data in Table 1 was used together with the formation water analyses in Table 3 and the gas rates in Table 7. MEG regeneration and reclaiming package The MEG loop System used in this project consists of a pretreatment of Rich MEG followed by a regeneration step and finally a reclaiming of one part of Lean MEG. - Divalent cations (Ca 2+, Mg 2+ ) would be precipitated in the pretreatment step - Water would be distilled in the regeneration step in order to increase MEG concentration roughly from 50% to 90%. - Pure MEG and water would be distilled from a slip stream of Lean MEG in order to get a total salt concentration lower than 2%. As shown in Figure 1, the MEG System configuration consists of the following units: Pretreatment A pretreatment system is designed for removing carbon dioxide, hydrocarbons and low soluble/divalent salts; as shown in Figure 2, the MEG Pretreatment is twofold: - Removal of Hydrocarbons The rich MEG is heated up to 80 C to flash off dissolved gases and break any hydrocarbon-meg emulsions, and then physically separate the hydrocarbons from the MEG. A heater and a 3-phase separator are installed upstream of a rich MEG storage tank to remove the bulk of the hydrocarbons. Then a liquid-liquid coalescer placed at the outlet of the rich MEG storage tank pump will reduce the hydrocarbon content to below 20 ppm before the salts pretreatment system. - Removal of divalent salts Sodium hydroxide is added for precipitating the divalent salts. The types of solids formed will be predominantly low soluble salts from formation water (CaCO 3, MgCO 3, BaCO 3 ) with particle size between 10 and 25 μm, and to a less extent corrosion products (FeCO 3, FeO, Fe 3 O 4, FeS) with particle size between 1 and 10 μm. The high amounts of organic acids along with the likely low concentration of iron particles favor a design where pretreatment is on the Lean MEG instead of the Rich MEG. As a result, no scaling is observed on the MEG regeneration reboilers and the pretreatment size is a lot smaller since only 20% of the full stream is treated. MEG Reclaimer Design The main purpose of the system is to crystallise and remove high solubility salts (mainly chlorides) from the Lean MEG. The single train Slip-Stream MEG Reclaimer for Cases 1 and 2 is based on maintaining a maximum of 20 g/l of salts in the Lean MEG at a maximum formation water production. It will be increased up to 30 g/l of salts for Case 3. The slurries are removed from the sidestream loop of the Reclaimer as shown on Figure 3. A downstream Slip-Stream Reclamation system is designed for the high soluble/monovalent salt removal. The Slip Stream rate is determined by the allowable amount of highly soluble salts in the Lean MEG (NaCl, KCl), set at 20 g/l. This value is conservative and well below the solubility limit (usually around 70 to 80 g/l) anywhere in the closed MEG loop, as such reducing the criticality of the reclaimer on a short term basis and thereby increasing the overall system availability.
SPE 155124 3 A drawback of the MEG Reclaimer is that the slurries from the vacuum evaporator are extracted from the sidestream loop in which flows a slurry containing around 15% of solids and 95% of MEG at a temperature of 135 C i.e. above the MEG flash point (111 C). This results in corrosive emissions that have been deteriorating some metallic parts of the installation. Such a process can work only if all produced calcium is precipitated inside the pretreatment step; otherwise some calcium would be recycled in the loop leading to scaling problems from MEG injection point to surface facilities. To precipitate all calcium, a sufficient amount of carbonates must be present in order to react with calcium according to the following chemical reaction: Ca 2+ + CO 3 2- CaCO 3 (eq.1) Carbonates come from bicarbonates, carbonates and dissolved carbon dioxide, the optimum carbon dioxide content in MEG is the concentration that exactly balances calcium concentration (equation 2): Ca 2+ (aq) + CO 2(aq) + 2OH - (aq) CaCO 3(s) + H 2 O (eq.2) The crucial point is the operating pressure of Rich MEG flash drum, a too low pressure means less carbon dioxide content in MEG thus less caustic soda to add in order to precipitate calcium carbonate but with the risk to have not enough CO 2 available to do it completely. Simulation results showed that enough CO 2 would be available to precipitate all calcium, however for case 2 it is mentioned that if the pressure of the flash drum would be reduced to 1bar, extra carbonate injection in the form of Na 2 CO 3 would be required in addition to the NaOH to promote the entire precipitation of calcium. The treatment of Rich MEG will need of huge quantities of potassium or sodium hydroxide, concentrated hydrochloric acid, potential solid sodium carbonate and will generate tons of solids. From 700 to 3000 tons per year of Calcium Carbonate, From 15 to 35m 3 /day of KOH 28%. From 2 to 10m 3 /day of HCl 32%. Need of oxygen scavenger qualified for 90wt% MEG. The organic acid content is 500 ppm. As the pretreatment is located downstream the regeneration unit, the ph of the rich MEG is therefore acidic (ph of 5). This allows to avoid the scaling of the reboilers but causes corrosion of the carbon steel reboiler shells that need to be repaired every 3 years. However, no corrosion of the overheads of the regeneration unit has been observed. Scale Inhibition strategy The precipitation (solid drop-out) and scaling risk depends on the lean MEG composition and the MEG regeneration. In this case MEG regeneration may consist of pretreatment where alkali is added to drop out salts from the rich MEG, but it is also an alternative not to use pretreatment. Both alternatives are evaluated. Furthermore there are considerable uncertainties with respect to the amount of organic acids that may be produced. Some of the evaluations are hence done with and without organic acids. The modeling methodology used as a basis for the report is a purely thermodynamic approach. The equilibrium calculations are done with the MultiScale software* with the glycol add-in (MEGScale). MultiScale is a computer program for the prediction of mineral deposition in oil operation. The electrolyte model in MultiScale is a Pitzer model for dissolved species in addition to a complete PVT model. MultiScale is a point model, but can handle mixing of streams. It has a PT (pressure temperature) flash calculation considering gas, oil and aqueous phases and calculating the speciation of the included compounds between these three phases 3. Three production scenarios have been considered: (i) Case 1 is for the produced water from A reservoir and represents the first 9.5 years of production; (ii) Case 2 represents the maximum produced water rates and will be a combination of the produced water from A and B fields and covers the years 9.5 to 16; (iii) Case 3 the A reservoir production declines whereas the B production will increase. Case 1: Production of Reservoir A only, year 9.5 Apart from BaSO 4, no other compounds reach supersaturation upstream pretreatment. The alkalinity injection required in pretreatment to precipitate divalent cations depends on the CO 2 concentration in addition to the divalent cation concentration. This is because the CO 2 must be consumed before the CO 3 2- and the OH - concentration increases sufficiently to precipitate the
4 SPE 155124 divalent cations. To illustrate this, the pretreatment calculations were performed for two pressures in the rich MEG flash drum; 2 bar as the original input and 1 bar. When the rich MEG is flashed to 2 bar, 27.9 mmol/kg alkalinity is required to precipitate the divalent cations to less than 1 mg/l. That corresponds to e.g. 22.6 m 3 /d of 28 wt% KOH. In the evaluation KOH is used in order to be conservative as it gives a higher salt loading (in weight) in the lean MEG because K has higher molecular weight than Na. The implication of replacing KOH with NaOH will be minor on the results in Table 2-5). Reducing the pressure in the flash drum to 1 bar reduces the alkalinity requirement to 16.2 mmol/kg (13.1 m 3 /d of 28% KOH). It also seen that with the given alkalinity addition there is potential for additional precipitation of Mg(OH) 2 in the reboiler. A relative large amount of acid (13.1 m 3 /d of 32 wt% HCl) is required to neutralise the lean MEG in base case. That will also be reduced when the alkalinity injection is reduced due to lower CO 2 in the rich MEG. The slip stream to the reclaimer required to maintain 2 wt% salt in the lean MEG is 20% with a CO 2 content in the rich MEG corresponding to 2 bar in the flash drum and 15% if the CO 2 content in the rich MEG is reduced by flashing at 1 bar. Changing the base from KOH to NaOH reduces the slip stream further to 13%. The pipelines at this field will have corrosion resistant cladding and the source of iron is limited to formation waters and a limited amount of corrosion products from the MEG injection line (no corrosion products from injection line included in this evaluation). The low iron concentration and the alkalinity in the formation water, anticipated to be comprised of carboxylates rather than bicarbonate, reduce the possible precipitation in the reboiler without pretreatment. It is thus a possibility to treat the lean MEG from the reboiler instead of the rich MEG. The advantage, in addition to less volume to treat, is that dissolved CO 2 is effectively removed in the reboiler. Thus, it is not necessary to inject alkalinity to consume excess CO 2. However, with no CO 2 in the lean MEG, alkalinity must be added as carbonate or a combination of carbonate and hydroxide. Calculations were done to evaluate this possibility. The condition for this treatment was set to 90 C and 2.5 bar. The results showed that there will be a risk of precipitation in the reboiler in this case; the alkalinity requirement is less than for the pretreatment. The required slip stream in this case is 12% if K 2 CO 3 is used as alkalinity. Case 2: Reservoirs A and B peak production, year 16 Apart from BaSO 4, no other compounds reach supersaturation upstream pretreatment. The alkalinity injection required in pretreatment to precipitate divalent cations to less than 1 mg/l is 26.5 mmol/kg. That corresponds to e.g. 35 m 3 /d of 28 wt% KOH. The effect of the rich MEG flash drum can be seen by comparing the CO 2 concentration. Without the flash drum, additional 18.7 mmol/kg of alkalinity would be required to consume the dissolved CO 2. It also seen that with the given alkalinity addition there is potential for additional precipitation of Mg(OH) 2 in the reboiler. As the alkalinity consumed by CO 2 is less than in case 1, less acid (4.1 m 3 /d of 32 wt% HCl) is required to neutralise the lean MEG. The slip stream to the reclaimer required to maintain 2 wt% salt in the lean MEG is 29%. This can be reduced to 27% if KOH is replaced by NaOH and the 2 wt% requirement in the lean MEG is maintained. Also in this case, the chemical consumption can be reduced by lowering the pressure in the flash drum. The optimum pressure is the one that results in a CO 2 + bicarbonate concentration in the MEG (in mmol/kg) that exactly balance the concentration of divalent cations except Mg 2+ as demonstrated by: Ca 2+ (aq) + CO 2(aq) + 2OH - (aq) = CaCO 3(s) + H 2 O (eq.2) Ca 2+ (aq) + HCO 3- (aq) + OH - (aq) = CaCO 3(s) + H 2 O (eq.3) In this case, concentration of divalent cations is 7.2 mmol/kg, hence the optimum CO 2 content is the same as the amount of bicarbonate which is low. Reducing flash drum pressure from 1.5 bar to 1 bar reduces the CO 2 content in rich MEG resulting in only 5.9 mmol/kg CO 2. Hence, carbonate must be added to compensate. The slip stream is reduced to 25 for 1.5 bar flash drum pressure and 24% for 1 bar. It is also possible to treat the lean MEG, but if rich MEG is not pre-treated, precipitation of Mg(OH) 2 and CaSO 4 is predicted in the reboiler. The amounts are moderate (ca. 100 kg/d). This project has special attention on the risk of scaling if reservoirs A and B formation waters are mixed in the topside facilities. A special evaluation has thus been performed to throw light on the possible increased scaling risk. The main case is with organic acids/carboxylates in formation water, gas and lean MEG. As a sensitivity a similar calculation was performed without organic acid and then also without carboxylates in the lean MEG. The results showed that only BaSO 4 reaches saturation. It is reservoir B formation water that has the highest risk of BaSO 4 precipitation; the saturation ratio is lower in the mixed aqueous phase even though the temperature is lower. The highest saturation ratio is in the separator because it has the lowest temperature. The saturation ratio depends also on the concentration of sulphate in the lean MEG, and two sulphate levels in the lean MEG have been compared: the anticipated accumulated concentration due to sulphate excess relative to strontium and barium in the formation waters and zero sulphate. The results show that even though the saturation ratio is markedly reduced with the lower sulphate concentration, the amount that may precipitate is only reduced by 10 %.
SPE 155124 5 Table 8 shows the estimated organic acid production rates in the gas phase. The simulation results showed that there is little difference in the cases with and without organic acids. That is not surprising as long as only BaSO 4 precipitation is predicted, as that is independent of acidity/alkalinity and ph. The saturation ratios for the carbonates are so low that the effect is marginal. It might be surprising to see that the ph for reservoir B and the mixed aqueous phase is lower without organic acids than with. The reason is that when the organic acids are removed, the carboxylates in the lean MEG are also removed. This buffers the ph of the aqueous phase when it is equilibrated with the high CO 2 reservoir B gas and the lower ph is a result of lower buffer capacity. The overall conclusion from these calculations is that with the given production rates and topside conditions there is a considerable risk of BaSO 4 precipitation when reservoir B formation water is produced. Mixing the reservoirs A and B formation waters does not enhance the possible amount of solid. Case 3: Reservoirs A and B high salt production The produced water is supersaturated with BaSO4 and dilution is not sufficient to lower the saturation ratio to less than 1. In this case, it is also seen that CaCO 3 reaches saturation downstream of the MEG injection point at reservoir B. The alkalinity injection required in pretreatment to precipitate divalent cations to less than 1 mg/l is 29.5 mmol/kg. That corresponds to e.g. 36.2 m 3 /d of 28 wt% KOH. The effect of the rich MEG flash drum can be seen by comparing the CO 2 concentration. Without the flash drum, additional 11 mmol/kg of alkalinity would be required to consume the dissolved CO 2. The CO 2 level in the rich MEG should not be lowered more; in this case, it is just sufficient to precipitate the calcium and strontium which amounts to 11 mmol/kg. It is also seen that with the given alkalinity addition there is potential for additional precipitation of Mg(OH) 2 in the reboiler. As the alkalinity consumed by CO 2 is less than in case 1, less acid (1.4 m 3 /d of 32 wt% HCl) is required to neutralise the lean MEG. The slip stream to the reclaimer required to maintain 2 wt% salt in the lean MEG is 32%. That can be reduced to 31% by replacing KOH with NaOH. In this case, the concentration of divalent cations in the rich MEG is 11 mmol/kg. The amount of CO 2 in the rich MEG from the flash drum at 2 bar is thus nearly ideal (12.5 mmol/kg). It is thus nothing to gain by reducing the pressure in the flash drum. There will be a small reduction in the alkalinity requirement in a lean MEG treatment compared to the rich MEG treatment, but that is small. Mercury removal The presence of mercury is anticipated; however its quantity and type are still unclear. In the event it will be on the form of HgS, the tests showed that specific coagulant and flocculent can help migrate most of the HgS from the condensate to the aqueous phase, from where it will be eliminated by centrifuge and filter-press 4,5,6,7,8. Seven disc-stack centrifuges are foreseen to handle the mercury content corresponding to the design phase (22 years from the start-up). It is then tempting to use those centrifuges for mercury removal and for pretreatment (calcium removal) as the same type of centrifugeshave been selected for both applications. However, this could result in contamination of the produced water and of the Rich MEG by mercury. This should therefore be absolutely avoided and dedicated disc stack centrifuges should be chosen for both applications or another filtration technology selected for divalent salt pretreatment should be applied. Discussions In case of a pretreatment, the rich MEG flash drum reduces the alkalinity consumption in pretreatment considerably because the extra flash reduces the CO 2 concentration in the rich MEG. The acid injection required to neutralise the lean MEG is reduced accordingly. For Case 1 it is more optimal to operate the flash drum (FD) at 1 bara than at 2 bara. For case 2 the optimum FD pressure is around 1.5 bara. The lower pressure reduces the chemical consumptions and the required slip stream to the reclaimer considerably. Treating the lean MEG rather than having a rich MEG pretreatment will lead to some sulphate and Mg(OH) 2 precipitation in the reboiler; ca. 50 kg/d for Case 1 and 100 kg/d for Case 2. Mg(OH) 2 precipitation is foreseen with pretreatment as well. A lean MEG treatment will reduce the alkalinity consumption and the slip stream somewhat. A lean MEG treatment relies on injection of carbonate rather than hydroxide. The results from the simulations are conservative and are based solely on thermodynamics. The literature on the kinetic behaviour of salts in MEG is limited and thus the simulations are based on calculations at equilibrium. However, with respect to the Pretreatments operation the system is expected to reach equilibrium within the residence time 9,10,11. The results from the ph mapping lead to a larger Reclamation unit being selected. This is due to the amount of alkalinity required for removing the low soluble salts in the pretreatment and the acid required for neutralizing the excess alkalinity added. The salt from the chemical addition in the pretreatment and the Lean MEG will add on to the high soluble salts to be removed in the Reclaimer. The CO 2 content in the gas and Rich MEG has a large impact on the design. By increasing the ph of the Rich MEG in the pretreatment the dissolved CO 2 in the liquid forms CO 3 2- which can be used as the carbonate source for the divalent cation salt precipitation. If the concentration of CO 2 in the Rich MEG is high, a large amount of alkalinity (NaOH) is required just
6 SPE 155124 to increase the ph up to the point where precipitation starts; this is in addition to the amount required for the precipitation of the divalent cations. Precipitation of the low soluble salts (salts of divalent cations) takes place at ph~9 for the carbonates and >9.6 for the Mg(OH) 2. A CO 2 content that is too low results in the need for extra carbonate injection (in the form of Na 2 CO 3 ) in addition to the NaOH to promote the precipitation. If the amount of CO 2 is very low, the alkalinity injection would be only Na 2 CO 3. In this project there is a high content of CO 2 in the gas and thus also in the Rich MEG. To optimize the Reclaimer size, different operating pressures of the Rich MEG Flash Drum were evaluated. From the ph mapping study it was found that the optimal flashing conditions for CO 2 in the Rich MEG Flash Drum was as follows: (i) Case 1 1 bar; (ii) Case 2 1.5 bar; Case 3 2 bar. At the above pressures there is no need for Na 2 CO 3 in any of the cases. The consumption of NaOH is summarised in Table 9 below. Some Na 2 CO 3 is however required to be injected into the MEG Flash Separator (in Reclaimer); this is required to remove any Ca 2+ and Mg 2+ that may not have been removed in the pretreatment. At high concentration the calcium and magnesium can come together with Cl - ions to form a complex with MEG. Such complexes have high viscosity and high freezing point and should be avoided. NaOH is recommended as the alkalinity source needed to increase the ph of the system as it has less impact on the Reclaimer size compared to KOH; this is due to a lower molecular weight of the cation which results in a lower mass of salts produced from the injection of alkalinity. To minimize injection volume and storage tank capacity requirements, 50 wt% NaOH is suggested. To avoid precipitation at the subsea injection points the Lean MEG needs to be neutralized. The quantity of acid required is given in the report and summarized in the Table 9. The success criterion for the MultiScale simulation was to inject enough alkalinity to remove divalent cations to less than 1 mg/l (except Mg 2+ ). This however leaves some residual Mg 2+ in the Rich MEG which will preferentially precipitate when the ph is increased in the reboiler. If the ph is increased to the extent necessary for removal of all the Mg(OH) 2 from the pretreatment vessel, both the alkalinity injection and the acid injection will be significantly increased and so therefore will the slip stream size. The Reclaimer in the initial module will be designed for Case 1 (14.5m 3 /h) which is 1/3 the size of the Case 2. The Reclaimer in the future module will be designed for Case 2 with a 25% slip stream of the Lean MEG. The result will be 3 equally sized vessels. The information regarding the upstream conditions for Case 3 were not fixed and thus the chemical consumption rates and overall salt formation are preliminary. To avoid oversizing the Reclaimers based on assumed data given in Case 3, it has been agreed to allow an increase in the salt concentration in the Lean MEG from 20 to 30 g/l in order to keep the Reclaimer sized at 14.5 m 3 /h (each). This concentration is far below the solubility limit of NaCl at sea bed conditions and the slip stream size predicted for Case 2 will cover Case 3. An evaluation of injecting the alkalinity in the Lean MEG rather than the Rich MEG was also considered and simulated for Case 1 for the purpose of comparison to the pretreatment procedure. The size of the slip stream was found to be similar to that of pretreatment dosing with 1 bar in the Flash Separator (12%). This alternative was not recommended due to ~4 times more scaling potential in the reboiler, which is the largest unit/vessel with the most comprehensive cleaning procedure and is critical for availability. The chemical consumption would be 0.28 m 3 /day of K 2 CO 3 (40%), which in volume is not much different than the optimized pressure Case 1 shown in Table 9 for the pretreatment design. The results are detailed in the report. Scale inhibitor will be injected at the wellhead. Once mixed with the Rich MEG, it might impair the quality of the precipitation in the pretreatment sections, hence the thorough removal of divalent salts, including mercury which takes place upstream of the MEG pretreatment unit. Conclusions The main conclusions of this study are as follows: Simulations have been performed on a conservative way assuming the production of 100% formation water and the highest possible Well Head temperature. In those conditions, we did not predict any risk of scaling inside reservoir A wells and reservoir B wells. Considering the production of some condensed water associated with formation water thus leading to a dilution of scaling ions; consequently there is no need of downhole scale inhibitor injection for both A and B reservoirs.
SPE 155124 7 Reservoir A and reservoir B formation waters are compatible; therefore the segregation of waters is not necessary to avoid the risk of mineral scaling. MEG is injected continuously at the Well Head in order to prevent hydrates in case of shutdown. Two trains for MEG regeneration are required; one train could be cleaned during the operation of the second one. The simulations showed that some scaling risk would be possible just downstream of the well head in case of production of more than 70m 3 /day of formation water, but taking into account the presence of a significant amount of condensed water, we do not think that some scaling might occur in transport lines in case of injection of a Lean MEG with a low salinity, low calcium concentration and without alkalinity. The Lean MEG specifications have a significant impact on the risk of scaling. The specifications of the Lean MEG are as follows: with a content of soluble salts at a maximum of 2%, a level of divalent cations lower than 10mg/Kg, oxygen concentration lower than 300ppb, ph value around 6 and a low to very low alkalinity. The quantities of NaOH and HCl required for pretreatment are equal to 15 m 3 /d on average and 17 m 3 /d at the peak. The quality of Lean MEG will depend on the efficiency of MEG regeneration and reclaiming processes. Whatever the organic acids content in Rich MEG, some scaling might occur in MEG regeneration unit due to temperature as high as 130 C and the unavoidable increase concentration of divalent cations. Calcium sulphate scaling risk has not been predicted, a low risk of barium sulphate scaling was identified but easily manageable, thus the main mineral susceptible to precipitate would be calcium carbonate. Simulation results showed that the option of treatment of 10 or 20% of the Lean MEG would lead quickly to calcium carbonate scaling downstream the well head at formation water ratio higher than 5% in the case of reservoir A. Some calcium carbonate scaling might also occur in Central Processing Unit upstream of MEG regeneration and reclaiming units at pressures lower than 5bar. Calcium carbonate scaling might occur at low pressures in surface installations upstream MEG regeneration and reclaiming units. A low and uncertain risk of barium sulphate scaling has also been identified thus a scale inhibitor able to prevent both from carbonates and sulphates deposits could be injected. 6. References 1. Tomson, M.B., Kan, A.T. and Gonigmin Fu (2005) Inhibition of barite scale in the presence of hydrate inhibitors. SPE Journal, 256-266 pp. 2. Van Son, K. and Wallace, C. (2000) Reclamation/regeneration of glycol used for hydrate inhibition. Deep Offshore Technology. 3. Seiersten, M., Brendsdal, E., Deshmukh, S., Dugstad, A., Endrestol, G., Ek, A., Watterud, G., Andreassen, J.P. and Flaten, E.M. (2010) Development of a simulator for ethylene glycol loops based on solution thermodynamics and particle formation kinetics. Nace International Corrosion Conference. 7 pages. 4. Barmashenko, V. I., Chviruk, V. P. and Tsypenyuk, P. B. The activation of carbon steel in the presence of mercury (II), Elektrokhimiya, 18, 146-148 (1982). 5. Bodle, W. W., Attari, A. and Serauskas, R., Considerations for mercury in LNG Operation, Proceedings of the 6th International Conference on LNG, Volume 1, 7-14 April 1980, Kyoto, Institute of Gas Technology. 6. Coade, R. and Coldham, D. The interaction of mercury and aluminium in heat exchangers in a natural gas plants, International Journal of Pressure Vessels and Piping, 83, 336-342 (2006). 7. Leeper, J. E. Mercury-LNG s problem, Hydrocarbon Processing, November, 237-240 (1980). 8. Wilhelm, S. M., The effect of elemental mercury on engineering materials used in ammonia plants, Process Safety Progress, 10, 189-193 (1991). 9. Anderko, A.; Wang, P., Springer, R.D., Lencka, M.M. and Kosinski, J.J. (2010) Prediction of mineral scaling in oil and gas production using a comprehensive thermodynamic model. Nace International Corrosion Conference, 20 pages. 10. Haiping Lu; Kan, A.T. and Tomson, M.B. (2010) Effect of monoethylene glycol on carbonate equilibrium and calcite solubility in gas/monoethylene glycol/nacl/water mixed systels. SPE Journal; 714-725 pp. 11. Jordan, M.M., Feasey, N.D. and Johnston, C.J. (2005) Inorganic scale control with MEG/methanol treated produced fluids. SPE 95034.
8 SPE 155124 Table 1: Reservoir conditions Parameter Case 1 Reservoir A (Yr 9.5) Case 2 (Yr 16) Case 3 (Yr 22.5) Reservoir A Reservoir B Reservoir A Reservoir B Pressure (bar) 312 167 419 167 419 Temperature ( C) 152 152 170 152 170 Table 2: Formation water analysis Ion Reservoir A (mg/l) Reservoir B (mg/l) Calcium, Ca 2000 1670 Magnesium, Mg 32 28 Iron, Fe (soluble) 5.3 6.3 Sodium, Na 2800 5800 Potassium, K 100 120 Strontium, Sr 7.2 49 Barium, Ba 5.1 28 Chloride, Cl 6200 10840 Sulphate, SO 4 86 62 Bicarbonate, HCO 3 1100 890 Carbonate, CO 3 < 1 < 1 Hydroxide, OH < 1 < 1 Summation of ions 12336 19493 Table 3: Formation water composition used in the simulations Ion Reservoir A (mg/l) Reservoir B (mg/l) Case 1 (mg/l) Case 2+3 (mg/l) Case 2+3 (mg/l) Calcium, Ca 2000 2000 1670 Magnesium, Mg 32 32 28 Iron, Fe (soluble) 5.3 5.3 6.3 Sodium, Na 2800 2800 5800 Potassium, K 100 100 120 Strontium, Sr 7.2 7.2 49 Barium, Ba 5.1 5.1 28 Chloride, Cl (Note 1) 7221 7225 11526 Sulphate, SO 4 86 86 62 Bicarbonate, HCO 3 (Note 2) 1100 1100 890 Carbonate, CO 3 < 1 < 1 < 1 Hydroxide, OH < 1 < 1 < 1 Total alkalinity (Note 2) 12336 12336 19493 Note 1: Adjusted to give electroneutrality in the water Note 2: The given bicarbonate concentration is not used in the evaluation. It is replaced by a total alkalinity (including carboxylates and bicarbonate) which is estimated by setting SR=1 for CaCO 3 at reservoir conditions. The total alkalinity is given in mg/l (using the molweight of HCO - - 3 ) to enable comparison with input values. It is impossible to give a HCO 3 concentration for this case; it depends on the total alkalinity and varies with reservoir pressure and temperature.
SPE 155124 9 Table 4: Formation water properties Parameter Reservoir A Reservoir B ph 6.4-8.2 6.0 7.7 Resistivity (at 25 C) 0.559 0.868 ohm-m 0.352 0.490 ohm-m Total dissolved solids (mg/l) 6290 13000 mg/l 16280 19000 mg/l Specific gravity 1.006 1.017 1.015 Table 5: Condensed water rates; values calculated by MultiScale compared to input data Source of data Reservoir A Reservoir B Case 1 (m 3 /d) Case 2 (m 3 /d) Case 3 (m 3 /d) Case 2 (m 3 /d) Case 3 (m 3 /d) Input data 1927 826 890.4 1620 1140 MultiScale 1398 661 669 1443 832 Table 6: Main hydrocarbon components Parameter Mole (%) Reservoir A Yr 9.5 Reservoir B Yr 16 Nitrogen 0.4406 0.54 CO 2 8.4543 17.1892 Methane 70.2763 75.4163 Ethane 10.3314 4.1698 Propane 4.1978 1.0399 i-butane 0.6992 0.29 n-butane 1.2481 0.24 i-pentane 0.4989 0.16 n-pentane 0.429 0.08 C 6 0.5277 0.15 C 7 0.6559 0.18 C 8 0.7045 0.18 C 9 0.3959 0.11 + C 10 1.1358 0.25 H 2 S 0.005 0.005 Table 7: Water, MEG and gas production flowrates. Numbers in italic are calculated Case 1 Case 2 Case 3 Reservoir A Reservoir A Reservoir B Reservoir A Reservoir B Condensed water flowrate (m 3 /d) 1927.2 825.6 1620 890.4 1034.4 Formation water flowrate (m 3 /d) 381.6 218.4 1142.4 736.8 1140.0 Rich MEG flowrate (m 3 /d) 4917.3 2187.2 5783.3 3259.9 4346.5 Lean MEG flowrate (m 3 /d) 2618.4 1146.7 3034.1 1631.3 2179.9 Rich MEG concentration, all 50.1 49.4 49.5 47.3 47.5 condensed (wt%) Total hydrocarbon rate (MSm 3 /d) 47.4 16.3 32.7 16.5 18.8
10 SPE 155124 Table 8: Estimated organic acid production rates in the gas phase Case 1 Case 2 Case 3 Reservoir A Reservoir A Reservoir B Reservoir A Reservoir B Acetic in gas (mol%) 8.51 E-05 1.50 E-04 1.01 E-04 1.50 E-04 1.01 E-04 Propanoic in gas (mol%) 3.31 E-04 5.87 E-04 3.34 E-04 5.87 E-04 3.34 E-04 Acetic in gas (kg/d) 107.6 66.1 88.0 66.1 88.0 Propanoic in gas (kg/d) 515.7 318.9 358.8 318.9 358.8 Condensed water flowrate (m 3 /d) 1927.2 825.6 1620 890.4 1034.4 Acetic in condensed water (mg/l) 55.8 80.0 54.4 74.2 85.1 Propanoic in condensed water (mg/l) 267.6 386.3 221.5 358.1 346.9 Table 9: Summary of the main findings for the three production cases Case Case 2 Case 3 Slip stream [% of Lean 13 25 25 MEG] @ 20ºC Lean MEG [m 3 /h] @ 20ºC 109.1 174.2 158.8 Pressure in RM Flash Drum 1 1.5 2 [bar] ph in RM Flash Drum 5.60 5.56 5.5 ph in Pretreatment vessel 9.12 8.96 9.04 NaOH, 50% [m 3 /h] 0.20 0.44 0.56 HCl, 32% [m 3 /h] 0.39 0.10 0.20 Na 2 CO 3, 20% [m 3 /h] 0.003 0.016 0.023
SPE 155124 11 Figure 1: Overall MEG Package Configuration
12 SPE 155124 Figure 2: Overview of the MEG Pretreatment Unit Figure 3: Overview of the MEG Reclaiming Unit