International audienceThe aim of this paper was to study cake filterability and compressibility as a function of the particle shape and particle size distribution (PSD). Different shapes and PSD of calcium carbonate and uranium oxalate particles covering the classical types encountered in industry (sphere, cube, needle and platelet) were obtained by precipitation. The size and shape factor distributions were measured using an image analysis system on SEM pictures. The cake filtration properties were measured in ideal monitored operating conditions, because of a miniaturised filtration cell set-up. The impact of the PSD and the shape were quantitatively assessed. These two solid features have an impact on cake resistance and compressibility, but not in the same way. The PSD has the strongest effect on cake resistance and compressibility. The particle shape is a decisive parameter for cake compressibility when the shape is far from the sphere. Both parameters need to be considered when working on the development of a filtration operation. Here, a practical model built following the Darcy law coupled with a new correlation for compressibility factor assessment is proposed. It gave satisfactory estimates of cake filterability and compressibility for the four shapes studied

Inst. Fran9ais du Petrole; M.J. Argaud, SPE, Elf Aquitaine; and J.-P. Feraud, Total-CFP Summary.Laboratory equipment aimed at determining the exact correlation between resistivity and water saturation under stress, pressure, and temperature conditions is described in the first part of this paper. The porous-plate method adapted to reservoir conditions is used to obtain different saturation values during both drainage and imbibition. With this equipment, the influence of the effective stress on the porosity and formation resistivity factor can be studied before the test. In the second part of this paper, the values of the formation resistivity factor and resistivity index are compared for water-wet samples from sandstone and carbonate reservoirs. These measurements indicate that the influence of the effective stress depends on the nature of the rock sample. In addition, the resistivity/water-saturation law depends on the direction of the saturation change (drainage or imbibition) and on the nature of the fluids (water/oil or water/gas).

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Summary Back production of proppant from hydraulically fractured wells continues to create operational problems for oil and gas producers. As much as 20% of the proppant placed in the fracture can be returned to the surface, necessitating costly and labor-intensive surface-handling procedures. The development of unmanned platform operations remains impossible in some areas because of proppant back production. Flexibility in well turnaround and production strategies also can be very limited. Curable resin-coated proppant (RCP) has provided the most cost-effective and widely used method to control proppant back production. While this is a valuable technique that has served the industry well for many years, it is not universally successful. A new technology has been developed to control proppant back production and to increase flexibility in well turnaround and production strategies. The technology has been used successfully on several hundred hydraulic fracturing treatments. In this technology, a mixture of fibers and proppant is pumped into the fracture to form a pack that is resistant to proppant back production under typical oil/gas production conditions. The proppant/fiber mixture depends on a physical mechanism rather than chemical bonding to increase pack resistance to flowback. There are no minimum closure stress, temperature, or shut-in time requirements associated with the use of this technology, which increases the flexibility available to the operator to optimize well turnaround and production strategy. This paper reviews the laboratory data relevant to the understanding and application of this technology. Studies include proppant pack resistance to flowback in one- and two-phase flow, the effect of cyclic loading, aging phenomena, permeability/conductivity studies, and fluid/breaker interactions. The benefits of the technology are illustrated with field studies. Introduction Proppant back production has been of concern in hydraulic fracturing for more than 20 years. It has received increased attention in recent years as larger fracture widths and the use of higher proppant concentrations have become more prominent. Back production usually is observed when the well is turned around after the hydraulic fracturing treatment. Back production may stop in time, be controlled by limiting the production rate from the well, or continue through the economic life of the well. Back production from hydraulically fractured wells presents operational problems. It often necessitates costly and labor-intensive surface-handling procedures and on-site control of chokes when beaning up the wells. The erosion of well and surface facilities presents a safety hazard. Proppant remaining in the wellbore can shut off production by covering the productive interval. The magnitude of the problem and the range of viable approaches vary from location to location. As much as 20% of the proppant placed in the fracture has been returned to the surface in Alaska, and as much as 10% is not uncommon in the North Sea.7 Back production can yield as much as 100,000 lbm of proppant. In Alaska, many operators "live with" the problem. In the North Sea, the development of offshore, unmanned platforms is often impossible. Continuous proppant production can sometimes be stopped by producing wells on a restricted choke. In some cases, changes in job design (proppant type, proppant size, final concentration of proppant in slurry, final pumping pressure, forced fracture closure, or lengthened fracture shut-in period) can be effective in reducing or eliminating proppant flowback. The most economical and widely used proppant-flowback-control technique is the curable RCP, which has been the single most effective technology available. Sales of curable RCPs exceed 60,000,000 lbm/yr (and could be significantly higher than that). While curable RCP's have had a great deal of success, they are not, nor could they be expected to be, universally applicable. A new technology has been developed to prevent proppant back production and to allow more flexibility in flowback design and production strategy. The technology relies on a physical mechanism - fiber reinforcement - to increase the resistance of the pack to flowback during production of oil or gas. This report presents laboratory data and field examples of the advantages of this new technology. Its limitations are also presented.

Summary In this paper, we present the results of successful applications of polymer gels to control water production in Mexico. We discuss three case studies that used a systematic methodology to correctly diagnose near-wellbore water channeling behind the casing. The methodology uses diagnostic plots based on the historical behavior of the water/oil ratio (WOR) as a function of time. These include correlation with information from original cement bond logs (CBL's), oxygen-activated logs during production to effectively determine the origin of the water, and saturation logs to determine the water levels independent of the salinity of the water produced. In addition, we present successful applications of polymer gels to re-establish zonal isolations in the three case studies previously mentioned. We discuss gel placement and present the procedure followed in each case, evaluate a water injectivity test followed by a temperature log taken before gel placement to determine the height propagation of the water, and anticipate potential zone damage of adjacent producing intervals during gel placement. In one case, a new interval completed perforating through the gel with excellent results. Another case involved a zone abandonment with gel, in which positive pressure was tested with 35 and 70 kg/cm2 wellhead pressure at 2500 m. In all cases, the advantages of gel treatments over common cement squeezes are discussed. Finally, we present the treatment results, including the analysis of pressures recorded during gel placement and the oil and water production before and after treatment. Introduction One of the main problems encountered in old wells and wells originally cemented under low reservoir pressure consists of hydraulically isolating different intervals to allow proper production of the zones of interest. This lack of isolation has caused undesired fluid movement behind the casing, generating confusion about the actual levels of the oil/water contact (OWC) and causing premature abandonment of oil reserves. We present a methodology followed in northern Mexico that corrects water channeling behind the pipe with chromium-crosslinked polymer gels. The advantages of using gels over cement include their flexibility for pumping without a workover rig, higher control of setting time, ease of cleaning, lack of milling time, and superior operations cost without risking effective treatment. Included in our methodology is candidate selection with diagnostic plots that allow us to identify near-wellbore flow that correlates with CBL's, indicating poor cement. Finally, we discuss three field case studies in Poza Rica, northern Mexico. The data for each case are presented, including saturation logs, production logs, density logs, and water flow based on the activation of oxygen to monitor the movement of water through a channel. Corrections to water flow are also presented, as well as a detailed overview of the execution and results, showing treatment effectiveness. Near-Wellbore Flow The problems associated with water production and its control present a challenge to reservoir and workover engineers. The central issue lies in defining the source of the water and determining whether the water production of a given interval is necessary to the associated oil production. Therefore, we must define two kinds of water production - bad and good. The production of water is considered good when it sweeps an oil bank and carries important oil production with it. Bad water inhibits the oil production of an interval because of aquifer coning, injection-water channeling, or well-vicinity water flow. Therefore, knowing the source of the water produced is fundamental in defining the problem. The presence of water in a production interval brings questions about the actual level of the OWC. In many cases, this uncertainty causes premature abandonment of oil reserves assumed to be water-invaded. Near-wellbore flow (Fig. 1) is one of the most prominent causes of confusion because of several factors: poor cement bond, caverns formed by sand production, channels in the formation, natural fissures, hydraulic fractures, reduced oil flow caused by formation damage, and frequent stimulation in the near wellbore. Poor Cement Bond. Several factors may explain a poor cement bond. First is the exposure of the cement to adverse conditions of temperature, pressure, and perhaps sulfate waters, which cause the cement to deteriorate and create potential channels behind the pipe that can allow adverse fluids to flow. This is more likely to happen if problems such as low-pressure zones, gas migration, or poor design of washers and spacers were encountered during the primary cementing job. Today, this problem represents one of the most important causes of uncertainty regarding the OWC and a water-invaded interval. Caverns Formed by Sand Production. One of the main problems related to formations with sand production is that caverns can be created that can be detrimental to the hydraulic isolation of the production interval. This causes a potential for communication with a water-invaded zone. These problems are common in friable, poorly consolidated sandstone. Channels, Natural Fissures, and Hydraulic Fractures. Channels, natural fissures, or fractures in the formation create hydraulic communication through an interval. This may allow the water in a zone to percolate up to the production interval, negatively affecting the oil. The effect of natural fractures has been widely discussed in other publications.1–3Fig. 2 illustrates channeling through a fracture. Critical production rates have a direct influence on the invasion of these channels by water and thus on its detrimental effect on oil production.

Mass production of hydrogen is a major issue for the coming decades particularly to decrease greenhouse gas production. The development of fourth-generation high-temperature nuclear reactors has led to renewed interest for hydrogen production. In France, the CEA is investigating new processes using nuclear reactors, such as the Westinghouse hybrid cycle. A recent study was devoted to electrical modeling of the hydrogen electrolyzer, which is the key unit of this process. In this electrochemical reactor, hydrogen is reduced at the cathode and SO 2 is oxidized at the anode with the advantage of a very low voltage cell. This paper describes an improved model coupling the electrical and thermal phenomena with hydrodynamics in the electrolyzer, designed for a priori computational optimization of our future pilot cell. The hydrogen electrolyzer chosen here is a filter press design comprising a stack of identical cathode and anode compartments separated by a membrane. In a complex reactor of this type the main coupled physical phenomena involved are forced convection of the electrolyte flows, the plume of evolving hydrogen bubbles that modifies the local electrolyte conductivity, and all the irreversible processes that contribute to local overheating (Joule effect, overpotentials, etc.). The secondary current distribution was modeled with a commercial FEM code, Flux Expert 1 , which was customized with specific finite interfacial elements capable of describing the potential discontinuity associated with the electrochemical overpotential. Since the finite element method is not capable of properly describing the complex two-phase flows in the cathode compartment, the Fluent 1 CFD code was used for thermohydraulic computations. In this way each physical phenomenon was modeled using the best numerical method. The coupling implements an iterative process in which each code computes the physical data it has to transmit to the other one: the two-phase thermohydraulic problem is solved by Fluent 1 using the Flux-Expert 1 current density and heat sources; the secondary distribution and heat losses are solved by FluxExpert 1 using the Fluent 1 temperature field and flow velocities. A set of dedicated library routines was developed for process initiation, message passing, and synchronization of the two codes. The first results obtained with the two coupled commercial codes give realistic distributions for the electrical current density, gas fraction, and velocity in the electrolyzer. This approach allows us to optimize the design of a future experimental device. Notation CpHeat capacity (J kg -1 K -1 ) gGravitational acceleration (m s -2 ) J Current density (A m -2 ) Current density normal to the interface (A m -2 ) kThermal conductivity (W m -1 K -1 ) ñNormal vector NBN Number of integration points Q S Surface heat sources (W m -2 )Nanometric discontinuity thickness of potential (m) d S Dirac surface distribution e g Gas fraction qDensity (kg m -3 ) gOverpotential (V) rViscous stress tensor (Pa) rElectrical conductivity (X -1 m -...

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