|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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.
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 evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place. Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model. Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during cold-water injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model. Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.
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 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.