Summary Carbonate and sulfide scales are directly coupled together and differ from other inorganic scales because they are intimately linked to the in-situ concentrations of carbon dioxide (CO2) and hydrogen sulfide (H2S), which influence the local pH and availability of reactive species. The CO2 in aqueous solutions has the most significant effect on the system pH, on the solution content of bicarbonate ion (HCO3–), and on the final alkalinity. However, the presence of H2S in the system also has a direct and important effect on the total-system alkalinity. When calcium carbonate deposition occurs in a depressurized aqueous fluid, the amount of scale (CaCO3) that forms depends on the initial (prescaling) solution alkalinity. Thus, the occurrence and severity of carbonate scale are linked to both the solution carbonate system (CO2/HCO3–/CO32–) and the sulfide system (H2S/HS–/S2–). In previous publications, we have described a rigorous work flow (step-by-step procedure) to accurately predict carbonate- and sulfide-scaling profiles from reservoir to separator using commonly available field data (Verri et al. 2017a). Although, with perfect data, the work flow is rigorous [i.e., it will correctly predict the types and amounts of scale that can occur in some carbonate systems (e.g., CaCO3, FeCO3, FeS)], the numerical results produced are, of course, subject to errors of different types. In this paper, we identify and describe three key categories of data and procedures that must be correctly gathered and used to obtain accurate carbonate- and sulfide-scale predictions: These relate to field measurements, data-handling procedures, choice of software, model equations, and parameters. Moreover, in this work, the impact of unreliable field measurements on the final carbonate and sulfide scaling profiles is estimated, with a specific focus on gas- and water-chemistry errors. By varying important parameters such as Ca2+ concentration and gas-phase CO2 and H2S, it is possible to assess the impact that errors in these measurements have on the final scale-prediction profiles. Because of the closely coupled nature of the carbonate and sulfide systems, it is essential to consider “groups” of variables that change together.

Predicting the formation of pH-dependent scales requires full thermodynamic calculations of the compositions of all hydrocarbon and aqueous phases present. This is necessary in order to determine the distribution and speciation of CO 2 and H 2 S between the gas, oil, and water phases in the system. Several commercially available software packages combine PVT calculations with scale predictions, but such packages are more targeted to the modeling of aqueous systems and often have limited hydrocarbon capabilities. Likewise, PVT modeling software focusing on the hydrocarbon phase does not fully model the aqueous phase or can only predict a limited number of scales/complexes. Moreover, within each type of software, there are a large number of different equations of state, activity models, and equilibrium parameters, which may ultimately have a significant impact on the final carbonate and sulfide scale predictions. The questions addressed in this work are as follows: How important is the software selection, and which parameters really affect the final scale prediction profiles? In what scenarios do these values matter, and when are they not so important? In this paper, the previously published Heriot-Watt scale prediction workflow is applied using different software packages and EOS models to evaluate their impact on the final carbonate and sulfide scale prediction profiles. The results show that, despite the large number of modeling options available, two parameters play a key role in pH-dependent scale predictions: (i) the partition coefficients of CO 2 and H 2 S between the gas, oil, and water phases and (ii) the relative mole (and volume) distributions between each phase at selected temperature and pressure. The final scale prediction results can be accurate only when these values are accurate, irrespective of how they are obtained.

Microbial reservoir souring poses a significant threat to safe oil and gas production and operations and it is difficult to control and mitigate. Predicting future H2S trends with reservoir souring models is done in an attempt to define the worst-case scenario and make critical decisions related to the asset field life. Unfortunately, these predictions often prove wrong because of the large uncertainties around parameters used within these models and because predicting the behaviour of living microorganisms is much more complex than dealing with most other chemical challenges in oil & gas. This work proposes an alternative data-driven and mechanistic approach to the investigation of the souring problem in Alba, a mature North Sea field water flooded since 1994. A comprehensive dataset including water chemistry analyses, gas composition trends, fluid rates etc. is used to find important correlations between produced fluid compositions and changes in H2S production. The concept of biogenic sulfate loss is introduced to allow the comparison of results for wells located in different parts of the field and drilled at different stages of the field life. When looking at produced sulfate concentration, injection water fraction (IWF) and produced H2S we clearly identify 5 stages of H2S generation in the Alba field. Sulfate loss in produced fluids is detected first and it is followed by a delayed H2S production. Eventually both biogenic sulfate loss and H2S generation reach a plateau although it is not easy to determine the end members of these concentrations. Produced water data shows a significant sulfate loss in excess of 1000 mg/l caused by reservoir biogenic souring. To account for sulfate loss caused by changes in the IWF, the biogenic sulfate loss is calculated. This is defined as the SO42− drop from the expected SO42− concentration calculated using injection water fraction based on boron. A plot of maximum produced H2S and biogenic sulfate loss is constructed to compare all wells, show the souring trend and bracket the maximum H2S generation for the field. Sulfate and BTEX are not the limiting factor in H2S generation in this field but the maximum concentration of sulfide that bacteria can tolerate determines how high H2S can rise. This work shows for the first time how the change in produced sulfate concentration can be used to study the different stages of well reservoir souring in high sulfate waters. A new method of comparing wells based on biogenic sulfate loss and H2S production is proposed to bracket the maximum H2S generation expected in this field. This straightforward data analysis method is generally applicable in fields that are souring due to microbial activity and where the produced fluid compositions are available.

Wells producing from an oilfield in Abu Dhabi were investigated to understand the CaCO3 scaling risk at current production conditions, and to predict how the downhole and topside scaling potential will change during a planned CO2 WAG project. The results of this study will be used to design the correct scale inhibitor treatment for each production phase. A rigorous scale prediction procedure for pH dependent scales previously published by the authors was applied using a commercial integrated PVT and aqueous modelling software package to produce scale prediction profiles through the system. This procedure was applied to run many sensitivity studies and determine the impact of field data variables on the final scale predictions. These results were used to examine the scaling potential of current and future fluids by creating a diagnostic "what if" chart. Some of the main variables investigated include changes in operating pressure, CO2 and H2S concentrations and variable water cut. Scale prediction profiles through the entire system from reservoir to stock tank conditions were obtained using the above modelling procedure. The main findings in this study are: (i) That CaCO3 scale is not predicted to form at separator conditions under any of the current or future scenarios investigated for these wells. This is due to the high separator pressure which holds enough CO2 in solution to keep the pH low and prevent scale precipitation. (ii) The water at stock tank conditions was found to be the critical point in the system where the CaCO3 scaling risk is severe, and where preventative action must be taken. (iii) Implementing CO2 WAG does not affect CaCO3 scaling risk at separator conditions where fluids remain undersaturated. However, the additional CO2 dissolves more CaCO3 rock in the reservoir producing higher alkalinity fluids which result in more CaCO3 scale precipitation at stock tank conditions. (iv) Fluids entering the wellbore are likely to precipitate some CaCO3 (albeit at a fairly low saturation ratio, SR) due to a significant pressure drop and the relatively high temperature, and this is not associated with the-bubble point in this case. This downhole scaling potential becomes slightly worse by an increase in CO2 concentration during CO2 WAG operations.(v) Scale inhibitor may or may not be required to treat downhole fluids depending on the wellbore pressure drop, but it is always necessary to treat fluids downstream of the separator due to the very high scaling potential at stock tank conditions. By applying a rigorous scale prediction procedure, it was possible to study the impact of CO2 WAG on the risk of CaCO3 scale precipitation downhole and topside for this field. These results highlight the current threat downhole and at stock tank conditions in particular and show how this will worsen with the implementation of CO2 WAG and this will require a chemical treatment review.

An alkaline-surfactant-polymer (ASP) pilot in a regular five spot well pattern is underway in the Sabriyah Mauddud (SAMA) reservoir in Kuwait. High divalent cation concentrations in formation water and high carbonate concentration of the ASP formulation makes the formation of calcite scale a concern. The main objective of this study is to investigate the severity of the calcium carbonate (CaCO3) scaling issues in the central producer in pursuit of a risk mitigation strategy to treat the potential scale deposition and reduce the flow assurance challenges. Calcite scaling risk in terms of Saturation Ratio (SR) and scale mass (in mg/L of produced water) in the pilot producer is potentially very severe and the probability of forming calcium carbonate scale at the production well is high. Produced Ca2+ concentration is high (> 800 mg/l), which makes the equilibrated calcite SR severe (> 500) and results in significant amount of scale mass precipitation. Different flooding strategies were modelled to evaluate a variety of flood design options to mitigate scale risks (varying slug size, Na2CO3 concentration, and volume of softened pre-flush brine), with marginal impact on scale formation. When the high permeability contrast of the different layers is reduced (to mimic gel injection), calcite SR and precipitated scale mass is significantly reduced to manageable levels. The option of injecting a weak acid in the production well downhole can suppress most of the expected calcite scale through reduction of the brine pH in the produced fluid stream for the ASP flood. Weak acid concentrations in the range of 4,000 to 5,000 mg/l are forecast to mitigate scale formation.