Scale inhibitors (SI) have been applied very successfully over many years in oilfields to prevent the formation of mineral scale. Both barium sulphate and calcium carbonate scales may be prevented using inhibitors, although in this work we will focus on the more difficult barite inhibition problem. A number of publications have appeared discussing the mechanisms by which barium sulphate scale inhibitors operate to prevent or retard scale formation. The mechanisms are discussed here in terms of (a) nucleation inhibition where the scale proto-crystals forms but are then disrupted or redissolved by the action of the inhibitor molecules, and (b) crystal growth inhibition where the inhibitor is thought to adsorb or interact with the active crystal growth sites (growing edges or spirals) hence retarding or stopping the crystal growth process. Both of these mechanisms are consistent with the inhibition of mineral scale at "threshold" levels, typically for MIC=0.5 - 20 ppm (MIC=minimum inhibitor concentration for a defined level of inhibition for a given test procedure). The MIC is always considerably below stoichiometric values in terms of the scale inhibitor to mineral scale molar ratios. It is known that most inhibitor types from the small molecular phosphonates (e.g. DETPMP) to polymeric species (e.g. PAA, PVS, PPCA) actually operate through both of the above mechanisms although one of these may predominate for specific species. Previous work has established that, broadly speaking, smaller phosphonates operate principally as crystal growth inhibitors and polymeric species work mainly as nucleation inhibitors. A number of factors are known to affect the inhibition efficiency (IE) of scale inhibitors against barite formation, the main ones of concern here being pH, temperature and the calcium and magnesium levels in the scaling brine mixture. The general observed effects of these factors have been described in the literature and will be discussed in detail in this paper. However, no complete description of the mechanism of barite inhibition has appeared which clearly and consistently explains all of the observed effects of these parameters for different scale inhibitor types. It is the central aim of this paper to present a complete and consistent set of mechanisms for barite inhibition which may vary in degree for different inhibitor types. Our proposed mechanisms are based on a wide range of observations from the open literature analysed with our own experimental and modelling results. Experimental Details To develop a set of mechanisms for barite inhibition, we use a number of experimental techniques and data sources. Since the experimental techniques used are well known, we refer the reader to literature descriptions for details. Static inhibition (bottle) tests and dynamic (tube blocking) tests are both very well known techniques for determining inhibition efficiency (IE) and are described in detail elsewhere1,2. The brine compositions used in the new static IE results presented here are given in Table 1. The scale inhibitors used in this study are: diethylene triamine penta (methylene phosphonic acid) (DETPMP), phosphino polycarboxylic acid (PPCA) and polyvinyl sulphonate (PVS) and their structures are given in Fig.1 Crystal structure measurements of the a-axis deformation of the barite lattice from this work and the literature are used here3,4. The theory behind this is given in Ref. 5. We also present some simple calculations of the equilibrium system containing calcium ions, magnesium ions and scale inhibitor. Results are given for the Ca/Mg/DETPMP system close to MIC levels for which the stability constants are known6.

Summary This paper describes the development and implementation of a pore-scale simulator into which pore-wettability effects have been incorporated. Relative permeability and capillary pressure curves from this steady-state model have been analyzed to allow better interpretation of experimental observations from a microscopic stand-point. The simulated capillary pressure data demonstrate that some standard wettability tests (such as Amott-Harvey and free imbibition) may give misleading results when the sample is fractionally wet in nature. Waterflood displacement efficiencies for a range of wettability conditions have been calculated, and recovery is shown to be maximum when the oil-wet pore fraction approaches 0.5. Furthermore, a novel experimental test is proposed that can be used to distinguish between fractionally wet and mixed-wet porous media. To date, no such satisfactory test exists. Introduction The wettability characteristics of a porous medium play a major role in a diverse range of petrophysical measurements that include capillary pressure data, relative permeability curves, and waterflood recovery efficiency. Throughout the current literature, however, much conflicting evidence exists as to the effects of wettability on a variety of displacement processes. Instead of examining the many factors that affect the ultimate wettability state of a system, however, this paper concentrates on the expected waterflooding consequences once a certain wettability condition has been specified at the pore scale. In any given rock sample, wettability may be considered as being either uniform or nonuniform. In the former case, the wettability of the entire pore space is the same (100% oil-wet, 100% water-wet, or 100% "intermediate"-wet) and the wetting- and nonwetting-phase contact angles will remain essentially constant throughout the system. In the more realistic nonuniform case, however, the rock may show heterogeneous wettability, with variations in wetting preference from pore to pore (e.g., 70% oil-wet pores and 30% water-wet pores). Indeed, wettability discontinuities may exist even at the subpore level, but such cases will not be considered here. Nonuniform wettability can be further subdivided into two subclasses: fractional wettability and mixed wettability. Fractional wettability is generally related to the rock matrix itself and is the result of differences in surface chemistry of the constituent minerals. Because of these variations, crude-oil components may adsorb onto some pore walls while ignoring others. In effect, this means that fractionally wet rock may contain oil-wet pores of all sizes (Fig. 1). Salathiel1 first introduced the term "mixed" wettability to describe systems where the oil-wet pores correspond to the largest in the sample, with the small pores remaining water-wet (Fig. 2). Such situations may arise when oil migrates to water-wet reservoirs and preferentially fills the larger interstices. The wettability characteristics of these pores may then be altered by adsorption of polar compounds and/or by deposition of organic matter from the original crude, thereby rendering them oil-wet. The network modeling approach has been widely used in the past, but usually in an attempt to quantify flow parameters2,3 or to fit experimental data.4 Unfortunately, quantitative prediction has proved unsuccessful, while the fitting of experimental data is less informative. We believe that network modeling should be used to examine the sensitivities of a given process to a variety of phenomena; this is the approach taken here. Although much work has been done with strongly water-wet networks, very few studies have been reported that attempt to simulate flow in networks of heterogeneous wettability. Mohanty and Salter5 have used a pore-and-throat model to investigate the effect of wettability on a variety of primary and secondary displacements but considered only one mixed-wet regime (25.5% PV oil-wet). In another study,6 a Bethe lattice was used to approximate pore connectivity and displacements were described usefully in terms of pore-filling sequences (schematic representations that use the pore-size-distribution curve of the system). Two nonuniform networks were studied, both of which appear to be fractionally wet. The simulator described in this work is used to investigate systematically the vital role played by wettability at the pore scale in both fractionally- and mixed-wet media and to explain how wettability influences the resulting capillary pressure, relative permeability, and waterflood recovery efficiency. In addition to explaining certain wettability sensitivities, an important goal of this work is to propose a new wettability test that eventually could be used in the laboratory. Model Setup and Implementation Network Details. The porous medium is modeled as an interconnected network of pore elements. The results presented in this paper come from simulations performed on a 3D regular cubic network comprising 20×20×20 nodes (junctions) that contains 24,400 intersecting pore elements. To simulate larger systems, periodic boundary conditions are imposed across planes perpendicular to the direction of the applied pressure gradient. Each pore in the network is assigned a radius, f(r), from a modified Rayleigh distribution. Network Details. The porous medium is modeled as an interconnected network of pore elements. The results presented in this paper come from simulations performed on a 3D regular cubic network comprising 20×20×20 nodes (junctions) that contains 24,400 intersecting pore elements. To simulate larger systems, periodic boundary conditions are imposed across planes perpendicular to the direction of the applied pressure gradient. Each pore in the network is assigned a radius, f(r), from a modified Rayleigh distribution.

The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters ͑e.g., P c and k rw /k ro ) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the ''target'' oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted ͑mixed and fractionally wet͒ systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive-i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general ''regime based'' theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil-and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed.

In this paper, we propose a detailed, semi-quantitative, theory of how the low salinity waterflooding effect works based upon pore-scale theoretical considerations. This theory follows on from detailed core flooding work performed in our laboratories demonstrating the importance of multicomponent ion exchange (MIE) as the underlying mechanism of low salinity waterflooding (Lager et al, 2006). Whilst this earlier work highlighted the importance of MIE, it did not explain the precise consequences of the theory in terms of quantifying the incremental oil recovery nor the precise impact on pore-scale physics. For example, with MIE occurring, the changes in the divalent cation concentrations (Ca2+ and Mg2+) leads to the development of a "self freshening" zone within the waterflooded region within which certain changes in the surface chemistry of the pore walls may occur. Such effects include expansion of the electrical double layers, changes in the adsorption of polar organic species, and resulting changes in wetting. The theory presented here attempts to show the consequences of these changes which are supported by some plausible pore-scale model calculations. These calculations i) indicate the pore-scale origins of the low salinity oil recovery mechanism, ii) show the magnitude of the effect semi-quantitatively, and iii) allow some clear predictions to be made which can be tested experimentally. This work also follows Lager et al (2006) in further explaining why both crude oil and clay-bearing reservoir rock are required for the low salinity effect to occur, and why the effect is not seen in strongly water-wet, clay-free porous media with mineral oils. Thus, this proposed pore-scale physical model of the low salinity waterflooding effect both complements and extends previous mechanistic explanations based upon multicomponent ion exchange (MIE). Although this proposed mechanism is consistent with all the available observations, further experimental studies are required to definitively confirm it.

First presented at the SPE Annual Technical Conference & Exhibition held in New Orleans, 25-28 September, 1994, as " Development and Application of a New Two-Phase Scaleup Method Based on Tensor Permeabilities". Abstract The effects of different levels of geological heterogeneity on a fluid displacement process may be captured at a larger scale using scaleup techniques. In the context of reservoir simulation, these are algorithms which should reproduce the results of fine grid calculations on a coarser grid. These techniques are referred to as pseudo-isation, the main objective being to produce pseudo-functions which can be used on the coarse grid. When carried out successfully, the pseudo-functions (e.g. pseudo relative permeabilities)incorporate the interaction between the fluid mechanics and the heterogeneity as well as correcting for numerical dispersion. These pseudo-functions also depend on the viscous/capillary and viscous/gravity ratios and are valid for the boundary conditions relevant to the particular flows. For single phase flow, the scaleup problem involves the derivation of effective permeability which, in general, is a tensor quantity. Multi-phase flow is more complex since scaled-up dynamic transport quantities must be calculated which depend on phase saturation, flow rate etc. In this paper, we present a method which extends the idea of tensor (absolute) permeability to tensor effective phase permeabilities. They are extensions of conventional functions which also include the off-diagonal phase crossflow terms which maybe important in certain systems. Two- phase tensor methods are presented which are valid (a) in the capillary equilibrium limit and (b) for arbitrary values of viscous/capillary and viscous/gravity ratios. Numerical examples of the application of these methods are presented for ripple-bedded systems where the two-phase crossflow effects are significant, and where oil trapping within the lamina structure may occur under certain conditions. The results show that it is important to use phase tensors in upscaling where gravity effects are significant, in order to generate the correct vertical flows. Introduction The modelling of two-phase flow through porous media is important for forecasting hydrocarbon recovery in oil and gas reservoirs. This process is complicated by the fact that rocks may be very heterogeneous over a wide range of length scales. If the effects of these heterogeneities are to be taken into account in full-scale simulations, a method is required for averaging flow properties from small-scale models, for incorporation in larger-scale ones. The calculation of effective flow properties (sometimes known as pseudoproperties)has been studied, from different view points, by a number of authors. Generally speaking, scaleup can only be carried out successfully when there is a separation of length-scales. In fact, many sedimentary rocks do exhibit heterogeneities at distinct length scales, e.g. laminae (em), beds (m), formations (10m). Corbett et al have shown that it is feasible to scaleup two-phase flow using such geologically based length scales.