Salinity design goals are to keep as much surfactant as possible in the active region and to minimize surfactant retention. Achieving these is complicated because (1) compositions change as a result of dispersion, chromatographic separation of components distributed among two or more phases, and retention by adsorption onto rock and/or absorption in a trapped phase; (2) in the presence of divalent ions, optimal salinity is not constant but a function of surfactant concentration and calcium/sodium ratio; and (3) the changing composition of a system strongly influences transport of the components.A one-dimensional (ID) six-component finitedifference simulator was used to compare a salinity gradient design with a constant salinity design. Numerical dispersion was used to evaluate the effects of dispersive mixing. These simulations show that, with a salinity gradient, change of phase behavior with salinity can be used to advantage both to keep surfactant in the active region and to minimize retention. By contrast, under some conditions with a constant salinity design, it is possible to have early surfactant breakthrough and/or large surfactant retention.Other experiments conducted showed that high salinity does retard surfactant, and, if the drive has high salinity, a great amount of surfactant retention can result. The design that produced the best recovery had the waterflood brine overoptimum and the drive underop-0197-752018310006-8825$00.25

Experiments on oil displacement from homogeneous porous media have shown that the component of fi0t4 across the layer is o~ten negilgibiy small compared with that parallel to it. This result is applied in the inspectional analysis of the equations governing the macroscopic displacement processes.

The theoretical analysis of the acid-fracturing process for turbulent-flow conditions has been process for turbulent-flow conditions has been reconsidered taking fluid losses into account. For a simple fracture model and an idealized acidizing process, the acid concentration in the fracture process, the acid concentration in the fracture during acid injection and the fracture width have been determined as functions of time and place for three loss conditions:no fluid loss,fluid loss proportional to time, andfluid loss proportional to the square root of time. proportional to the square root of time. From the results of the analysis, it is concluded that even under the unfavorable conditions of turbulent flow in the fracture and fluid loss, acid penetration is, in general, not a limiting factor in penetration is, in general, not a limiting factor in the application of the acid-fracturing process. However, it will not be possible to predict the productivity increase resulting from a given productivity increase resulting from a given treatment until more experimental data on the conductivity of etched fractures and on certain aspects of the reaction kinetics have been gathered. Introduction Acid-fracturing treatments are frequently applied to improve well productivity in limestone formations. In this process, hydrochloric acid is injected into a hydraulically induced fracture, which extends diametrically from the wellbore into the formation. During injection, the limestone faces of the fracture are dissolved. As a result, acid is consumed and its concentration decreases in the direction of flow. The width of the fracture increases, and the fracture faces may become irregularly etched as a result of the natural anisotropies of the formation. The etching pattern produced may contribute to an improvement in fracture conductivity after the fracture is allowed to close. The extent of this etching into the fracture and its final fluid conductivity determine the increase in productivity. Barron et al. have presented an empirical formulation of the acid-fracturing process for laminar flow conditions without fluid loss. When a theoretical description given by Prins et al. concerning the heat-transfer in laminar flow between parallel plates, is applied to the acid-fracturing parallel plates, is applied to the acid-fracturing process, the acid concentration in a fracture for process, the acid concentration in a fracture for steady-state laminar flow can be exactly described, provided that the fracture width is constant and no provided that the fracture width is constant and no fluid loss occurs. A comparison of the acid concentrations calculated from the empirical reaction-rate data of Barron with those theoretically derived according to Prins shows that these values are of the same order of magnitude and can be made equal for acceptable values of the diffusion rate only in the range of low velocities. Judging from the experimental set-up of Barron, we believe that for higher velocities the entrance transition length for fully developed laminar flow should be longer. For this reason, no agreement in the higher velocity ranges can be expected. This view is supported by Williams et al., who compared theoretically derived reaction rates in the heterogeneous calcium-carbonate /hydrochloric-acid system with those of Barron et al., who also conclude that entry effects may be responsible for the discrepancies in the higher velocity range. Nierode and Williams determined a kinetic model for the heterogeneous reaction of hydrochloric acid with limestone. The reaction order and rate constant used in their model were obtained from experiments. On the basis of this model, they derived an acid-fracturing design for laminar flow conditions including fluid loss. In the study described below, the acid-fracturing process has been reconsidered for turbulent-flow process has been reconsidered for turbulent-flow conditions in which both fluid loss and change in fracture width have been taken into account. We feel that the study provides a more realistic description of the process for both a vertical and horizontal fracture and that it may be used as a bask for designing acid-fracturing treatments. MATHEMATICAL DESCRIPTION OF THE ACIDIZING PROCESS FOR A RECTILINEAR FRACTURE A vertical rectangular fracture (rectilinear) with initially plan-parallel and flat fracture faces was adopted as a fracture model. SPEJ P. 239

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract From theoretical considerations if follows that the production improvement factor (PIF) for dry oil or gas production due to natural and/or hydraulically induced vertical fractures in bottom water reservoir showing water coning is identical with the PIF obtainable with the same fracture configuration in a reservoir without bottom water. This is generally derived for a single, symmetrical fracture of arbitrary shape. It has been found that the highest PIF is obtained for a fracture with a PIF is obtained for a fracture with a technically-optimised tapered cross section. Results of calculated examples are discussed. Introduction In oil reservoirs with bottom water the height of a steady-state water cone depends on the potential gradient of the fluid moving along the interface: the greater the gradient (production rate), the higher is the cone. A decrease of the potential gradient, and thus a suppression of the cone, can be achieved by means of a fracture that effectively reduces the resistance to flow. Alternatively, if the cone is allowed to reach the same height, a higher production rate would be achieved. Hydraulically-induced vertical fractures would thus permit higher critical rates (maximum water-free oil production-rates), and make it possible to reduce the number of wells to be drilled for a required off-take. The shape of vertical fractures can be better controlled nowadays. This prompted us to investigate the problem of steady-state fluid flow in the presence of vertical fractures in reservoirs with presence of vertical fractures in reservoirs with bottom water, in order to derive the production improvement factors (PIF) for fractures of various prescribed practicable shapes. The PIF is prescribed practicable shapes. The PIF is defined as the ratio between the critical production rates with and without a fracture. The following considerations are generally valid for the movement of a fluid in the presence of a second non-flowing fluid of different density. hence, the results are equally applicable to the case of oil production over bottom water, respectively from under a gas cap, as to the case of gas production over bottom water. production over bottom water.

Determination of rheological parameters of rod-type bio-polymer (Xanthan) solutions as a single (mobile) phase in sand packs is discussed. In one series residual oil is present. Apparent viscosities approximated from sand pack experiments could be described by a Carreau type of equation. Since no real in situ polymer solution viscosities and permeabilities to these solutions can be determined up to now a practical way out of this problem is the determination of mobilities to the polymer solution with the help of the Darcy equation. These polymer mobilities can be described with a modified Carreau type of equation. RF, RRF values and polymer mobilities are discussed in the context of apparent polymer viscosities. Up-front and residual polymer retention have been estimated for conditions of 100 % accessible porevolume.