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Collaborating Authors
Kaur, Amarpreet
Abstract Hydrodynamic factors, such as shear stress and turbulence, are known to affect scale deposition and corrosion in oilfield production systems. Systems in which the configuration promotes sudden changes in the degree of turbulence can be particularly susceptible to scale deposition problems, as is often observed in chokes, pumps, valves and (most relevant here) in the vicinity of inflow controls devices (ICDs). This paper documents the development of pilot rig testing methodology, which aims to achieve far more field-realistic flow regimes than typically obtained in laboratory tests, and applies it to the study of scaling phenomena in and around ICDs, using up to 8000 liters (L) of scaling brine flowing through the system on a single-pass basis at a fluid flow of 10 L/min. Custom designed and manufactured test pieces were incorporated into the rig to determine the extent and location of scale deposition as a function of varying wall shear stress. Interpretation of the observations was enhanced through the use of computational fluid dynamics (CFD) to quantify and assess the contribution of various hydrodynamic factors on scale deposition. The work therefore demonstrates the effectiveness of pilot-rig test methodologies for use in oilfield applications where the influence of the hydrodynamic regime is likely to be significant. Moreover, by showing how the scaling results correlate with CFD predictions, it increases the confidence that design decisions based upon laboratory tests will be valid under field conditions. Introduction Limitations of Current Scale Prediction Models The vast majority of scale prediction models are based on thermodynamic calculations. They may be used to predict the Saturation Ratio (SR, the thermodynamic driving force for precipitation) and the Excess Solute (the maximum mass of scale that can precipitate per unit volume of brine if the system were to reach equilibrium) for a particular system, but thermodynamic models do not take kinetic factors into account and cannot predict the rate of scale formation. Kinetic factors are particularly important in mildly supersaturated systems, as has been reported in numerous publications. Kinetic factors mean that some mildly supersaturated systems do not significantly precipitate within production timescales but remain metastable. A simplified illustration of this is shown in Figure 1 for calcium carbonate (CaCO3), showing that various stability regimes can be defined as a function of temperature. Saturation Ratio is defined such its value is unity at equilibrium; SR < 1 represents an under-saturated system; SR > 1 represents a supersaturated system, which may precipitate to some extent if kinetic factors are favourable.
- North America > United States (0.28)
- Europe > United Kingdom (0.28)
- South America > Brazil (0.28)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 29/5b > Elgin Franklin Field > Fulmar Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30c > Elgin Franklin Field > Fulmar Formation (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30b > Elgin Franklin Field > Fulmar Formation (0.98)
- (3 more...)
Abstract Inflow Control Devices (ICDs) are being increasingly used in complex, heterogeneous reservoirs to make the inflow profile more uniform, delay breakthrough of water and/or gas and limit differential depletion, which can lead to crossflow and other detrimental phenomena. However, ICDs not only alter inflow behaviour: they also affect outflow of fluid during chemical treatments, such as scale squeezes, stimulation, etc., which may be applied periodically during well life. Methods to account for the additional flow resistance from ICDs when predicting placement of bullheaded treatments are discussed in this paper, in particular, to evaluate whether a theoretical approach based upon Bernoulli's Theorem leads to sufficiently accurate predictions in the absence of laboratory correlations between pressure drop across the ICD and flow rate. This approach may also become significant where the laboratory calibration might be expected to have changed during well life, such as, under the influence of erosion. The paper describes two analytical methods of simulating placement in a multi-zone well in a heterogeneous reservoir in the Middle East: the first is empirical and models the pressure drop using an equation derived from calibration data in the laboratory; the second uses the Bernoulli equation, and is theoretical. For the empirical approach, the laboratory-based pressure-drop/flowrate calibration data were fitted to an equation, with parameters that depended upon the nozzle dimensions. The theoretical approach calculated the pressure drop using the Bernoulli equation for a cylindrical ICD nozzle. Both methods were used to simulate placement of a generic scale-inhibitor squeeze treatment and the corresponding chemical returns for each zone in the well. In general, the differences in the predictions between the two models were found to be very minor, showing that a theoretical approach is sufficiently accurate to design and evaluate chemical treatments in wells fitted with ICDs in most cases. This means a very rapid analytical approach can be used to design and evaluate near-wellbore treatments in such wells without resorting to much more complex, numerical-based reservoir simulators, even when calibration data about the ICD performance are not available.
- North America > United States (0.28)
- Europe > Middle East (0.25)
- Asia > Middle East (0.25)
- Africa > Middle East (0.25)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (0.82)
Abstract This paper considers the placement challenge in selected wells in a North Sea Field and presents the importance of understanding reservoir properties such as relative permeability, mobility and fluid in place when attempting to simulate treatments in complex wells such as these. The work presents the challenges and solutions offered to minimise the scale risk in this mature field as a result of changes in the overall drainage strategy. Many wells in the North Sea Field are complex and produce from multiple heterogeneous formations which makes them difficult to treat, and so effective placement is vital to mitigate downhole scaling. The wells highlighted in this paper were originally planned for minimal interventions. However as the field development plan matured an increased (albeit mild) sulphate scaling risk became evident in several production wells. Therefore, pre-emptive squeeze treatments were planned to mitigate downhole barium sulphate scaling. Given the heterogeneity in the formation this resulted in potential risks in the event that squeeze treatments could not be designed to give effective placement. This paper presents the placement challenge that is seen in these wells in addition to potential methods of overcoming these challenges. Effective placement does not necessarily mean placement into all producing layers, but means placement of inhibitor into layers upstream of any potential mixing point of scaling brines. Therefore, this work highlights the necessary placement required for effective inhibition and the corresponding treatment designs that may achieve this. One treatment injection strategy to assist effective placement is the use of a staged diversion treatment which is simulated using a near-wellbore placement model. This paper documents a case study of modelling placement, and the corresponding squeeze return, in a mature North Sea Field. It highlights the important influence of reservoir properties such as relative permeability effects (in addition to permeability, porosity, fluid mobility etc.) and how these are used such that chemical treatments in complex heterogeneous wells can be readily simulated without the necessity of using complex full field reservoir simulators.
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Europe > North Sea (1.00)
- (2 more...)
Abstract The advent of wells with extremely long producing intervals, extended-reach and multilateral wells, typically completed in heterogeneous formations, brings with it challenges regarding completion design to maximize overall production in a sustained manner. Judicious placement of Inflow Control Devices (ICDs) can ensure a more even inflow of fluids along the full length of the interval, delaying water or gas breakthrough and in some cases restricting water production. Such devices also influence the placement of chemical treatments, such as scale-inhibitor "squeeze" treatments, which in turn affects the subsequent treatment lifetimes and efficiency. This paper presents a new analytical model to explicitly simulate the effect of ICDs on squeeze treatments and, in particular, on treatment placement and consequent lifetimes. The explicit method of modelling ICDs, which is based on Bernoulli's theorem of constricted flow through a pipe, is compared with other implicit phenomenological approaches, such as modelling the effect of an ICD as a damaged region using a dual-permeability model. By this comparison, the relevance of dual permeability modelling for simulating ICDs is presented. The relationship between chemical placement and inhibitor return has been clearly demonstrated in other publications (James et al., 2005, Sorbie et al. 2005). This paper illustrates the additional effects that ICDs bring to the placement challenge, highlighting the key parameters that can influence the zonal injectivity behaviour. The presence of ICDs in the well is shown not only to benefit the well's inflow profile during production but can also favourably influence the outcome of squeeze chemical treatments. In summary, the paper describes the development of an important new tool to assist in the design of optimum chemical treatment strategies in wells completed with ICDs, without the need to use more complex reservoir simulators for near-wellbore treatment in complex completions.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Abstract With developing interest in unconventional fields, such as fractured shales, there has been a need to develop models that accurately reflect the fluid-transport mechanisms in such formations. The current paper does this from the viewpoint of modelling scale inhibitor squeeze treatments. Unlike conventional reservoirs, where chemical transport is dominated by pressure differentials from pumping, in ultra-low permeability systems imbibition and diffusion processes can be as important, if not more so. We report a model that numerically solves either the imbibition equation or Fick's second law of diffusion to simulate these transport mechanisms, and couples these processes to inhibitor adsorption and desorption using either Freundlich or Langmuir isotherms. As only a fraction of the production interval is typically treated, the model interactively allows the user to select which fractures have been treated. The influence of partial treatment of the fracture network on overall treatment effectiveness is presented as is the effect of varying entry location of the produced water into the well. The model was also developed to simulate spontaneous imbibition of the aqueous inhibitor solution in combination with inhibitor adsorption, albeit in the absence of diffusion. The effect of this imbibition has been evaluated from the perspective that it acts as a potential "treatment thief" because it preferentially transports the applied inhibitor solution into oil-producing zones, whence it should contribute very little to mitigation of the current scaling risk.
- North America > United States (0.28)
- Asia (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Heather Formation (0.99)
Modelling Squeeze Treatments in Fractured Systems - A Case History
Kaur, Amarpreet (Scaled Solutions Ltd) | Spooner, Victoria E. (Scaled Solutions Ltd) | Frigo, Dario M. (Scaled Solutions Ltd) | Stalker, Robert (Scaled Solutions Ltd) | Graham, Gordon M. (Scaled Solutions Ltd) | Jordan, Myles M. (Nalco Champion)
Abstract Scale inhibitor squeeze treatments in high-permeability sandstone reservoirs can be readily simulated using matrix flow models. However, designing such treatments for application in fractured shale reservoirs is less developed, partly because the mechanisms for fluid flow are less well understood and partly because the manner by which the inhibitors are transported and retained in fractured shale formations differ considerably from the simple matrix flow encountered in sandstone reservoirs. Accurate prediction of squeeze treatment lifetimes is important for scale management both economically, to ensure optimum productivity at lowest cost of operation, and practically, to schedule treatments appropriately. Until recently this has not been achievable for fractured shale formations without the use of full-field simulators. This paper demonstrates that even a near-wellbore model, if appropriately modified, can achieve good agreement with inhibitor-returns field data from bullheaded squeeze treatments in 7 different multiply fractured wells in 2 different Unconventional shale formations. Field data were compared with simulations using a model that couples inhibitor diffusion into and out of the rock matrix with adsorption either onto the rock matrix or the fracture proppant or both; it was found that in some field cases there is negligible difference between inclusion or exclusion of proppant adsorption, whereas in others much better simulation of inhibitor returns is observed if proppant adsorption is included. Other aspects have been included in the model, such as the influence of proppant embedment (changing the porosity of the fracture void) and treatment of only a fraction of the multiple fractures present in a well. Interestingly, inhibitor returns in the 3 wells in one field correlated best with simulations assuming only a low fraction (up to 30%) of fractures were treated by the squeeze, whereas simulations from 4 wells in another field correlated better with a much higher fraction of fractures (60 – 90%) being treated. This paper illustrates that an appropriate near-wellbore model can give good agreement with field data provided plausible physical phenomena are included, and that such a model can be used to design better squeeze treatments in Unconventional fractured-shale reservoirs without the need for complex full-field simulators.
- North America > Canada > Saskatchewan > Williston Basin > Bakken Shale Formation (0.97)
- North America > Canada > Manitoba > Williston Basin > Bakken Shale Formation (0.97)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)