Summary In 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.

Waterflooding is a very common method of oil displacement and pressure support. One particular problem that may arise after injection water (IW) breakthrough at the production well is the formation of sulphate scale. One of the main parameters that determines the severity of this type of scale formation is the amount of injection water/formation water (IW/FW) mixing that has taken place. Thus, the injected water fraction in the produced brine mix is an important value to determine. Our ability to model scale precipitation in situ and in the well is linked to our ability to accurately determine the IW fraction at production wells. Current industry practice is to work on an analytic approach for determining the fraction of IW in the produced brine stream in general, and for identifying IW breakthrough in particular. A robust and accurate method for determining IW fraction in field produced water analysis is required to match the modelled IW fractions. When this is achieved, it is possible to use various modelling techniques with a higher degree of confidence to predict future scaling tendencies, and to help implement an appropriate scale management strategy to economically mitigate the potential effects of scale damage. In this paper, the "Reacting Ions" method is introduced for determining the fraction of IW (and FW) in produced waters. This method is then applied to a synthetic produced water case where the "correct" answer is known, and a very good match is achieved, even when significant noise is applied to the synthetic data. The method is then applied in the analysis of produced brines for several wells in a North Sea field. Results of the study presented here show that the method is more effective in detecting IW fractions than conventional ion tracking techniques, especially at low IW fractions close to when breakthrough occurs. The significant new development presented in this work is that this approach may be used accurately even in situations where scale deposition deep in the reservoir impacts the concentrations of the ions used in this method. Introduction Water is a universally occurring natural solvent in all sedimentary systems where petroleum is found. In contact with rocks, water may dissolve minerals in the matrix, and so subsurface waters are usually solutions containing a wide variety of ions, including Na+, Ca2+, Mg2+, Cl-, etc. The properties which may be used to characterise subsurface brines include temperature, chemical composition, pH, amount of total dissolved solids (TDS) and resistivity. Waters held in deep formations over geological timescales are often referred to as formation water (FW). The properties of subsurface waters vary significantly from one reservoir to another. The chemical compositions may range from relatively fresh waters, evaporated sea water or to highly concentrated brines. Hydrocarbons in reservoirs are coupled with subsurface waters which in turn play an important role in the original hydrocarbon migration and accumulation. Water deep in reservoirs can be present as a result of trapping during sedimentation or filtration, or a combination of both mechanisms (Ostroff, 1975). Over geological timescales, the subsurface waters come into chemical equilibrium with the rock and the hydrocarbons. In the oil industry, waterflooding is a widely applied secondary recovery method. During a waterflood, injection water (IW) is pumped into injection wells into the reservoir to displace mobile oil towards the production wells, and to provide energy to lift hydrocarbons to the surface (Dake, 1978; Craig, 1980; Willhite, 1986; Lake 1989). During water injection, subsurface formation waters (FW) are displaced along with the hydrocarbons, and are often produced in a IW/FW mixture that may contain a range of cations and anions as well as rock particles, sand, hydrocarbons drops, etc. The amount of produced water from a production well (and from an entire reservoir) generally increases with time.

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.

This paper presents the findings of a study into the impact of reservoir flow behaviour on both 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 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, aquifer and sea water in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the lifecycle of each well. The formation brines contain barium and the injection water is full sulphate seawater, and the relative proportion of each brine, the water production rate, and pressure and temperature conditions all determine the scaling risk. The evaluation of the extent of reactions between the injection water (sulphate) 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 scale risk and scale inhibitor concentration required to prevent scale deposition. In this study, as the injection wells were completed with inflow control devices (ICD's) it gave the opportunity to manage the injection split via these ICD's, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. The 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 this data allows an operator to consider prior to commissioning water injection in these challenging environments.

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