Mixing of sea- and production waters during waterflooding of offshore oil reservoirs results in reaction of barium and sulphate ions causing precipitation of barium sulphate with consequent rock permeability decrease and well productivity decline. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability decreases due to salt precipitation.
Previous works have derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of two scale damage coefficients from just pressure drop measurements during two corefloods with two different ratios "formation water : seawater??.
Data from series of three corefloods on commingled injection with three different "formation water : seawater?? ratios, were treated. Equality of scaling damage parameters as obtained from three different floods in similar artificial cores validates the method proposed.
In deepwater offshore operations where seawater injection is a common development practice, barium, calcium, and strontium sulphate scale deposition is a serious concern. Barium sulphate and related scale occurrence is considered a serious potential problem that causes formation damage near the production-well zone1-5. The major cause of sulphate scaling is the chemical incompatibility between the injected seawater, which is high in sulphate ions, and the formation water, which originally contains high concentrations of barium, calcium, and/or strontium ions6-9.
A reliable model capable of predicting such scaling problems may be helpful in planning a waterflood scheme. It may also aid in selection of an effective scale prevention technique through the prediction of scaling tendency, type, and potential severity.
A reliable predictive model must use well-known values of the model coefficients.
The mathematical model for sulphate scaling contains two phenomenological parameters: the kinetics coefficient from active mass low of chemical reaction showing how fast the reaction and precipitation occurs, and the formation damage coefficient reflecting the permeability decrease due to sulphate salt deposit10-15.
Both coefficients are phenomenological parameters depending on rock surface mineralogy, pore space structure, temperature and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be determined from laboratory corefloods.
Reagent and deposition concentration profiles during reactive flows are non-uniform. So, the sulphate damage parameters cannot be directly calculated from laboratory measurements. They must be determined from laboratory coreflood data using solutions of inverse problems.
The quasi steady state commingled corefloods by sea- and formation waters were performed by numerous authors16-19.
The kinetics coefficient can be calculated from breakthrough concentration in quasi steady state coreflood with commingled injection of sea- and formation waters. Then the formation damage coefficient can be determined from pressure drop increase during flooding20,21.
The pressure drop measurements are simple and robust while breakthrough concentration determination is a cumbersome laboratory procedure. Therefore, often concentration data are unavailable17. Availability of the method for characterisation of scaling damage system from pressure measurements would simplify the laboratory procedure on sulphate scaling studies. This is the subject of the current paper.
Based on analytical model for commingled coreflood by sea- and formation waters, the current paper develops a method to determine two scaling damage parameters from pressure measurements during two floods with different "formation water : seawater?? ratios.
Enhanced Oil Recovery (EOR) methods include injection of different fluids into reservoirs to improve oil displacement. Analytical models for 1-D displacement of oil by gas have been developed during the last 15 years. It was observed from semi-analytical and numerical experiments that several thermodynamic features of the process are not dependent on transport properties. The model for one-dimensional displacement of oil by miscible fluids is analyzed in this paper. The main result is the splitting of thermodynamical and hydrodynamical parts in the EOR mathematical model. The introduction of a potential associated with one of the conservation laws and its use as an independent variable reduces the number of equations. The reduced auxiliary system contains just thermodynamical (equilibrium fractions of each phase, sorption isotherms) variables and the lifting equation contains just hydrodynamical (phases relative permeabilities and viscosities) parameters while the initial EOR model contains both thermodynamical and hydrodynamical functions. So, the problem of EOR displacement was divided into two independent problems: one thermodynamical and one hydrodynamical. Therefore, phase transitions occurring during displacement are determined by the auxiliary system, i.e. they are independent of hydrodynamic properties of fluids and rock. For example, the minimum miscibility pressure (MMP) is independent of relative permeabilities and phases viscosities. The new technique developed permits splitting for both self-similar continuous injection problems and for non-self-similar slug injection problems. Splitting significantly reduces amount of calculations for sensitivity study with respect to transport properties: auxiliary thermodynamic problem may be solved once for given reservoir and injected compositions; variation of relative permeabilities and viscosities should be performed just in the solution of one transport equation. In this paper, different analytical solutions for 4-component gas injection problems are analysed. It was considered the injection of nitrogen and hydrocarbon gases into a three-component liquid reservoir fluid. The eigenvalues of the system are related to the propagation velocity of each component in porous media. The existence of elliptic regions (complex eigenvalues) is well known in three-phase flow, but for the first time it is shown that this feature may also occur in two-phase flow. The independence of compositional dynamics on transport properties can be used for testing numerical compositional simulators. If the mobility ratio is close to one, this model may be applied in the development of streamlines simulators.
The injection of fluids not present in reservoirs is the technical definition of Enhanced Oil Recovery (EOR) methods1. These methods may be classified into three main categories: chemical, solvent and thermal. Solvent methods of EOR may be either miscible or immiscible, depending on the thermodynamic behavior of the mixture of fluids at reservoir temperature and pressure. It was one of the earliest methods used to improve oil recovery.
Immiscible solvent displacement reduces oil viscosity and swells reservoir fluid, whereas miscible flooding; besides the characteristics already cited also develops miscible displacement, eliminating interfacial forces. Miscible solvent flooding techniques always involve some mass transfer between phases, like vaporization or condensation of components. The choice of kind and amount of fluid to be injected is strongly dependent on economical aspects. Although liquefied petroleum gas (LPG) has already been the most used solvent injection fluid, now carbon dioxide plays an important role. Usually, a solvent slug is injected into reservoir and driven by a "follow up" fluid.