Recent trends towards carbon net zero and the push to develop renewable energy as an alternative to fossil fuels have resulted in major environmental focus on de-carbonisation projects with an emphasis on carbon capture, utilisation, and storage (CCUS). Both carbon capture and utilisation (CCU) and carbon capture and storage (CCS), capture carbon dioxide (CO2) from heavy industries and air, by direct air capture (DAC), and transport it to sites by rail, boat, or pipeline for injection into geological reservoirs for permanent storage and/or enhanced oil recovery (EOR). A range of issues related to mineral scale deposition can be encountered that impact the efficiency of CO2 injection and utilisation/storage. These can include calcium carbonate deposition during CO2 capture in a calcium looping process, halite (NaCl) precipitation during supercritical dry CO2 injection and CO2 leakage due to the dissolution of carbonate cements and minerals in reservoir rocks which impact both cement and reservoir rock integrity. During CO2 utilisation for EOR, downhole and topside calcium carbonate deposition can occur in the production facilities. Effective scale management strategies are essential to maintain a safe, sustainable, and efficient CCUS process. It will also be necessary to minimise CO2 footprint during the whole lifecycle by making it less energy demanding. Scale control can be based on continuous scale inhibitor injection or squeeze treatments. Additionally, for wellbore integrity and to better isolate the well from the formation, sulphate scale may deliberately be deposited to provide extra strength to cements impacted by contact with CO2. This intentional precipitation of sulphate minerals needs special attention to be paid to ensure precipitation in the correct location. This involves consideration of pumping equipment, well completion, and rock type as they impact the deployment process to control the location, rate and mass of sulphate mineral deposition. This paper reviews the scale issues arising during CCUS including calcium carbonate deposition during carbon capture, halite and microbial induced calcium carbonate deposition during CO2 injection. Both conventional and unconventional scale management approaches are considered including treatments with and without scale inhibitors. The impact of well completion, cement type, and CO2 injection rates on CCUS and the selected scale management process are discussed. In addition, laboratory data for controlled barium sulphate (BaSO4) mineral scale deposition is presented coupled with field designs for CO2 utilisation through disposal in injection water in a calcareous sandstone and CO2 water alternating gas (WAG) injection in a carbonate reservoir.

Summary Wells generally face barium, strontium and calcium sulphates (BaSO4/SrSO4/CaSO4) scaling due to incompatibility of formation water and seawater injected in the reservoir. Barium sulphate deposit was expected in this field due to the high level of barium in the formation water. Scale mitigation is achieved using conventional treatments such as continuous scale inhibitor injection or batch scale inhibitor squeeze treatment; another non-chemical and environmental preventive mitigation is the injection of low sulphate seawater (LWSW). This study showed that the increasing level of heterogeneity (layering permeability contrast), size of aquifer and high initial barium concentration in the formation water, delay the optimal relaxation timing from desulphated seawater to full seawater injection. Sulphate level in the desulphated seawater, the existing of horizontal flow barriers and slow barium sulphate reaction rate, have marginal impact on the optimal relaxation timing from desulphated seawater to full seawater injection. Gradual build-up in the sulphate concentration allows earlier relaxation behavior, with lower degree of risks compared to the direct switch to full seawater injection.

Injection of low-sulfate seawater (LSSW) instead of untreated full-sulfate seawater (FSSW) is widely used to mitigate barium sulfate scaling risk at the production wells. LSSW injection may no longer be required when the barium concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the barium sulfate precipitation tendency. Relaxation of requirements for the sulfate reduction plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulfate concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case. The strategy for switching from LSSW to FSSW (e.g., time and method; direct or gradual increase in the sulfate concentration) was initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and the initial barium and sulfate ion concentrations. Findings were later applied on a full-field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity. The results show that barium concentrations in the formation brine affect the choice of switching time more than the output sulfate concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows a longer period of coproduction of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of barium ions because of its in-situ precipitation. Barium is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier buildup of the injected sulfate concentration compared with the direct FSSW switch. The study investigates the reservoir parameters that affect sulfate relaxation of LSSW injection for a field. After the proposed workflow, the optimal relaxation strategy can be designed for other field cases.

Summary Operators are collecting abundant produced-water data that are often underused. Produced-water-composition data provide clues related to the geochemical reactions that are occurring in the subsurface. This information can be useful for monitoring interwell connectivity and predicting and managing oilfield scale resulting from brine supersaturation. Coupling thermodynamic calculations with produced-water analysis helps to identify geochemical effects that could affect oil recovery. This work addresses the difference that reservoir temperature has on geochemical reactions in carbonate reservoirs by comparing data from two offshore fields and identifying the rock/brine and brine/brine reactions that will affect scale management. Two seawater-flooded chalk fields located near each other were selected as candidates for comparison. The temperature of one field is 130°C, whereas for the other field, it is 90°C. Produced-water samples (a total of 6,800) from these two fields were analyzed, and the compositional trends were plotted to identify the deviation from conservative (nonreacting) behavior. The compositional trends were then grouped to identify if there were common features between wells. This analysis was complemented by 1D reactive-transport modeling to identify the reactions that would be consistent with the observed trends. Two groups of wells were identified within each reservoir on the basis of the produced-brine compositional behavior. Each well group exhibits a distinct ion-trend behavior, especially with respect to barium, calcium, strontium, and magnesium concentrations—because these are divalent cations that are abundant in the formation brines. The breakthrough of sulfate, a component primarily introduced during seawater flooding, varies very significantly between the two groups in each case. In one grouping, the sulfate is barely retarded, and it breaks through at seawater fractions lower than 10%. In the other grouping, however, sulfate does not break through until the seawater fraction in the produced brine exceeds 75%. This retardation of sulfate occurs most strongly in the hotter reservoir, and this might be attributed to the lower solubility of the calcium sulfate mineral anhydrite at a higher temperature. The retardation of sulfate then means that barium is produced at higher concentrations because barite precipitation in the reservoir is thus restricted, caused by sulfate being the limiting ion. However, some sulfate stripping does occur in the cooler reservoir, despite the higher solubility of anhydrite. Furthermore, in all cases, magnesium is retarded, with some groupings exhibiting the complete stripping of magnesium from the injected seawater. The magnesium-stripping behavior is reproduced in the reactive-transport models when calcium- and magnesium-replacement reactions are allowed. This phenomenon has been observed elsewhere in coreflood experiments, and it also contributes to the sulfate stripping through the promotion of anhydrite precipitation within the rock. This process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. Therefore, higher-temperature chalk reservoirs might act as natural sulfate-reduction plants, reducing scaling, souring risks and, thus, operating costs of the fields.

Summary This work presents a way how the water production and injection profiles extracted from the full field reservoir simulation model may then be used as input for near wellbore squeeze treatment calculations, such as those performed using a squeeze model, to calculate inhibitor displacement, retention in the reservoir and then flow back into the wells, so that inhibitor returns and squeeze lifetimes can be calculated. An advantage of the simulator being available in the cloud is that it allowed the authors to perform the required calculations in a short timeframe using only the resources required, thus increasing efficiency of the evaluation and management of the inorganic scale risk. Integration of cloud-based reservoir simulator with the squeeze modelling package enabled not only an identification of the probable extent of the scaling problem, and also paved a path to optimising the design of squeeze treatments. Coupling of software combines the best estimate of water production rates and profiles available to the reservoir engineering team with placement calculations, and thus represents the best estimate of the well performance that can be updated on regular basis and integrated with a concept of a “digital field”.

Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation. This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C. This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions. The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator. A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.

Approximately 20,000 metric tons of CO2 were injected in the top sequence of the Mississippian age carbonate reservoir to evaluate potential for CO2 Enhanced Oil Recovery (EOR) and to estimate potential of transitioning to geologic CO2 storage through EOR. This paper focuses on tracking of CO2 plume movement in the reservoir using results of reservoir fluid chemical composition monitoring, CO2 plume and injection impact delineation, and studying effects of faults and naturally occurring fractures on fluid movement at the Wellington Field. We found that one of 12 identified and mapped faults worked as a partial barrier to CO2 movement and the associated damage zone and fracture network performed as a flow conduit, determining CO2 flow paths.

SummaryIn waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.

Abstract Understanding the reservoir connectivity advances engineering and management decisions and enhances overall field performance. A method to investigate injector to producer connectivity from an identified proportion of the injected brine in the produced water is proposed. Chloride, sodium, boron and lithium are ideal tracers: typically they do not participate in geochemical reactions. These ions track injection water without retardation, and if their concentration differences with formation brine are high enough to overcome measurement errors, then they may be used as indicators of the mixing ratio between injection and formation brines. This paper proposes the use of this mixing ratio to distinguish brines and to calculate the normalised contribution of injected water in the cumulative produced water volume. A producer to injector connectivity plot allows engineers to categorise the pressure support for production wells in one plot. This approach was applied to North Sea field data. A mineral scaling risk analysis was performed using the Injector Contribution characteristic plot. Wells being supported by commingled injected seawater and aquifer water were most at risk of BaSO4 precipitation. Historic data for a field case were analysed to examine potential scaling regimes. A set of well candidates for enhanced oil recovery to reduce residual oil in the oil leg was also identified. Most of the water produced in these wells came from injectors, rather than from the aquifer. Those wells have good communication throughout the oil leg and as a result quick water breakthrough occurs. As well as resulting in an early onset of BaSO4 scaling, an Enhanced Oil Recovery (EOR) chemical that is injected would more quickly reach the producers and therefore the potential for chemical EOR applications can be measured. This suggested metric helps to identify that other wells do not experience much seawater production, but are more strongly supported by the aquifer, and so there would be no apparent benefit in reducing residual oil by injecting chemical. This set of wells might benefit potentially from infill drilling nearby, or conformance control methods. The proposed technique does not require additional sampling to be performed over and above the measured historical produced water compositions that are routinely collected by operators during offshore production for scale management purposes. The analysis to select well candidates for EOR or areas for infill drilling is significantly more challenging using a conventional approach, and we propose that this novel metric of "Producer to Injector connectivity" will be beneficial for the decision making process.

Abstract The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised. A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods. All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells. Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed. This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.

Abstract The deployment of scale squeeze treatments in subsea horizontal wells has always presented a challenge in terms of understanding the location of injected fluids vs the location of the produced water where scale formation will occur. Over the years software packages such as Eclipse has been able to provide valuable information on the possible placement options for such wells when production logging tool (PLT) data have not been available. The development of multi-lateral drilling/completion technology has further complicated the placement challenges in such wells. In this paper Eclipse simulation data has been linked to SQUEEZE designs software for two subsea production wells completed with multi laterals and sliding sleeves to allow selective placement of the squeeze treatment. The objective of the study was to evaluate the options of bullhead deployment in terms of both laterals being open during the squeeze vs two squeeze stages being sized and selectively placed into each lateral again via bullhead deployment, but this time using the sliding sleeve technology to divert the chemical. Information on cross flow issues, the pump rates required to allow effective placement are presented, along with the differences in chemical volumes, pump time and soak times required for the two potential treatment options. The finding from this study show the clear advantages in terms of treatment volumes, reduced clean up time and extended treatment life (reduced intervention frequency) of bullhead deployment of two squeeze steps, one to each lateral, achieved by utilizing the sliding sleeve technology in these two production wells.

Summary Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine-chemistry data set was developed. Systematic analysis of this data set enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, along with improving its prevention and remediation. A study of the individual-ion trends in the produced brine by use of the plot types developed for the reacting-ions toolkit (Ishkov et al. 2009) provides insights into the components that are involved in in-situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion-exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells. A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced-water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate, on the basis of the endpoint formation- and injection-brine compositions and the erroneous assumption that no reactions in the reservoir impact the produced-water composition. Nonetheless, the usual effects of temperature, pressure, and brine composition are accounted for in these calculations by use of classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion, which greatly reduces the severity and potential for scale formation. However, ion-exchange reactions are also observed, and these too affect the scale risk and the effectiveness of scale inhibitors in preventing deposition. Additionally, comprehensive analysis by use of a geochemical model is conducted to predict the evolution of the produced-brine compositions at the production wells and to test the assumptions about which in-situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced-brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behavior. This helps to establish confidence that the model can be used as a predictive tool in this field.

Summary The time and subsequent evolution of injection-water breakthrough are two of the main indicators monitored by production chemists. After injected water breaks through, the risk of scaling may change significantly, and scale-mitigation procedures should be planned accordingly. The fraction of the injection water in the produced brine may be ascertained only from analysis of the produced-water samples. However, to date, there has been little discussion about other applications of injection-water-fraction tracking. In this paper, new applications that follow on from accurate knowledge of injection-water fraction are proposed. The calculated injection-water fraction may be applied To quickly and accurately identify when injection-water breakthrough has taken place, at which time remedial action to prevent scale damage needs to be implemented. To identify which ions are involved in in-situ geochemical reactions, and the degree of relative ion deviations (i.e., to identify ion-exchange reactions). To detect the formation or formations from which a well is producing, and to determine (potentially) the amount of flow from each layer without the use of downhole flowmetering. Strong evidence of the involvement of barium, sulfate, and magnesium ions in reactions, on the basis of the calculations of the relative ion deviations, has been shown for field data. In another case, application of injection-water fraction prompted a re-evaluation of formation-water compositions, and as a result, it was discovered that the well was producing from a different formation after reperforation. The significant new developments presented in this paper allow analysts to obtain an indication of which ions are involved in the reactions, and the degree of relative ion deviations. Additionally, a technique is proposed that identifies the formation or formations from which the well is producing.

Abstract In waterflooded reservoirs under active scale management produced water samples are routinely collected and analysed, yielding information on the evolving variations in chemical composition. These produced water chemical compositional data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale management programmes designed to minimise damage and enable improved recovery. In this interdisciplinary paper, the analyses of produced water compositional data from the Miller Field are presented and a 1D reactive transport model is developed to study possible geochemical reactions taking place within the reservoir through matching model results with observed produced water data. However, in the 1D reactive transport model, only one flow path was simulated; this does not fully represent the fluid flow and mixing behaviour in the reservoir. Therefore, this paper also presents a fully 3D reservoir simulation study for the Miller Field to evaluate brine flow and mixing processes occurring in the reservoir, using an available history matched streamline reservoir simulation model integrated with produced water chemical data. Conservative natural tracers were added into the modelled injection water, and then the displacement of injection water and the behaviours of the produced water in two given production wells were further studied. In addition, the connectivity between producers and injectors was investigated based on the comparison of production behaviour calculated by the reservoir model with produced water chemical data, and an assessment of the properties of the intervening faults was also performed. Finally, a model of BaSO4 scale precipitation was included in the model, and the simulation results with and without barite precipitation were compared with produced water chemical data (observed barium and sulphate concentrations in the produced brine). In general, the modelled and observed data were found to be in good agreement, but any discrepancies were in fact found to be very informative also. The model assumes scale deposition is possible everywhere in the formation, whereas in reality the near production well zones were generally protected by scale inhibitor squeeze treatments, and thus the discrepancies between modelled and observed data could be used to diagnose the effectiveness of the chemical treatments to prevent formation damage around the production wells.

Abstract This paper presents results of a reservoir and near wellbore modelling study to assist with the evaluation of inorganic scale risk management for a cold sandstone reservoir in the Norwegian sector of the North Sea. Reservoir temperature is in the range 32-48°C and poses a challenge to manage the scale risk. The field is heavily supported by aquifer water, and the development includes five production wells and seven seawater injection wells. The small number of high-cost, highly productive subsea multilateral wells with long horizontal sections, some with sliding sleeves to enhanced flow management, coupled with a high barium sulphate scaling tendency (up to 350ppm barium concentration in the formation water) requires effective scale management. This paper addresses questions of timing and nature of seawater breakthrough, when scale inhibitor squeeze treatments will be required, what is the impact of any reservoir reactions between the formation water and injected seawater on the scale risk at the production wells, what squeeze placement profiles look like under a range of squeeze treatment scenarios (various injection rates and sleeve position options). The treatment of multilateral wells by bullhead scale squeeze treatments is not a subject extensively covered in the literature, so the focus of this paper is to understand the impact on squeeze treatment life of bullhead deployment as a function of pump rate with both laterals open and the impact on treatment lifetime and treatment cost of selective placement into each lateral by treating one lateral at a time via activation of the sliding sleeve mechanism. The paper draws on a wide range of technical inputs to make scale management decisions including: thermodynamic modelling techniques, reservoir simulation of fluid mixing and reaction, laboratory-generated coreflood data to assess chemical selection for scale inhibitor squeeze, and squeeze treatment design drawing on all the information outlined above. Sharing the scale management technical challenges associated with such low temperatures and treating multilateral wells provides an example of the factors that should be taken into account during project design in similar fields under development in Northern Norway, offshore West Africa and offshore Brazil.

SummaryThis paper presents the findings of a study into the impact of reservoir flow behavior on the scaling risk at production wells and the options for managing this scaling risk for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater-injection wells have a great impact, not only on the barium sulfate (BaSO4) scaling tendency, but also on the placement of scale-inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate water, aquifer water, and seawater in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the life cycle of each well. The formation brines contained barium, the injection water was full-sulfate seawater, and the relative proportion of brine (the water-production rate, pressure, and temperature conditions) determined the scaling risk. The evaluation of the extent of reactions between the injection water (sulfate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence, the scaling risk and scale-inhibitor concentration required for prevention of scale deposition. In this study, because the injection wells were completed with inflow-control valves (ICVs), the opportunity was given to manage the injection split by means of these ICVs, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. This study will present the squeeze-treatment volumes and estimated treatment lifetimes possible for two scenarios for the water-injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that these data will allow an operator to consider before commissioning water injection in these challenging environments.

Abstract The injection of seawater into oil bearing reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deepwater subsea developments offshore West Africa, Gulf of Mexico and Brazil have brought into sharp focus the need to manage scale in an effective way. In recent years there has been some consideration given to deployment of scale inhibitor within the fluids associated with the completion of production wells, prior to the start up of production. Until now, effective scale control in frac packed wells at low water cuts has been achieved with phosphonate-based inhibitors applied as part of the acid perforation wash and overflush stages, prior to the actual frac packing operation itself. The deployment of these inhibitors has proved effective in controlling barium sulphate scale formation during initial seawater production, and eliminating the need to scale squeeze the wells at low water cuts (<10% BS&W). Recent developments allowing inclusion of scale inhibitor in the linear and cross linked gel stages has highlighted the need to be able to model this process effectively, thereby enabling optimal use of the chemical and improved squeeze designs. This paper outlines simulation work carried out using the Petroleum Experts REVEAL software to assess introduction of scale inhibitor into frac pack operations, and identify the most suitable stage of the well completion process during which to apply the inhibitor, to maximise treatment life. Simulation results and field data from these treatments are compared to demonstrate the opportunity this technique presents, and to highlight the importance of chemical placement and the post stimulation flow regime to squeeze life.