The drying dynamics in three dimensional porous media are studied with confocal microscopy. We observe abrupt air invasions in size from single particle to hundreds of particles. We show that these result from the strong flow from menisci in large pores to menisci in small pores during drying. This flow causes air invasions to start in large menisci and subsequently spread throughout the entire system. We measure the size and structure of the air invasions and show that they are in accord with invasion percolation. By varying the particle size and contact angle we unambiguously demonstrate that capillary pressure dominates the drying process.

We investigate the 3D structure and drying dynamics of complex mixtures of emulsion droplets and colloidal particles, using confocal microscopy. Air invades and rapidly collapses large emulsion droplets, forcing their contents into the surrounding porous particle pack at a rate proportional to the square of the droplet radius. By contrast, small droplets do not collapse, but remain intact and are merely deformed. A simple model coupling the Laplace pressure to Darcy's law correctly estimates both the threshold radius separating these two behaviors, and the rate of large-droplet evacuation. Finally, we use these systems to make novel hierarchical structures. The drying of suspensions of colloidal particles gives rise a plethora of fascinating phenomena, from the "coffee-ring" effect[1] to episodic crack propogation [2] and the fractal patterns arising from invasion percolation [3][4][5][6][7]. Drying of colloidal suspensions is also important technologically: paints and other coatings depend on colloidal particles for many of their key properties, many ceramics go through a stage of particle drying, and cosmetics often exploit the unique properties of colloidal-scale particles, particularly for such beneficial properties as screening the harmful effects of the sun. However, for many of these technological applications, the colloidal particles are but one of many different components, and drying of the colloids is accompanied by many other phase changes. While these mixtures can become highly complex, a simpler, yet still rich system that embodies many of the complex phenomena of these technological suspensions is a mixture of immiscible fluids with a colloidal suspension; a simple example is a mixture of an emulsion and colloidal particles. The behavior of the emulsion embodies many of the archetypal phenomena of such systems, while still remaining sufficiently tractable to enable it to be fully understood. However, emulsions themselves typically scatter light significantly, and when mixed with a colloidal suspension, this scattering is only enhanced. As a result, it is very difficult to image this mixture, precluding optical studies of its behavior, and knowledge of the actual behavior is woefully missing.In this Letter, we explore the drying of mixtures of aqueous emulsion droplets and spherical colloidal particles with confocal microscopy, which allows us to resolve the full 3D structure of these mixtures and their temporal dynamics. We find that the particles first jam into a solidified pack, throughout which emulsion drops are dispersed; a front of air then passes through the entire system. When this drying front reaches large emulsion droplets, the droplets unexpectedly collapse and their internal contents are forced into the pore space between the surrounding colloids, driven by an imbalance of pressures at the droplets' interfaces with air and with the solvent. By contrast, small droplets are deformed by the drying front, yet remain intact without bursting. By coupling the Laplace pressure with Darcy's la...

Summary Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s), and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery. This paper reviews progress in the application of large-volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. During the period November 1996-November 1997 three large-volume foam-gel treatments were successfully placed into the Rangely reservoir. The first 36?400 bbl treatment, implemented November 1996, increased the pattern oil rate from 260 barrels of oil per day (BOPD) in March 1997 to ±330 BOPD in August 1998; a conservative estimate of incremental oil recovery is ±40?000 bbl by the end of August 1998. The second 43?450 bbl treatment, implemented August-September 1997, increased the pattern oil rate from ±430 BOPD in March 1998 to ±470 BOPD in August 1998; post-treatment, the pattern oil rate data is described by a linear regression with slope, +56 BOPD but it is too early to make a firm estimate of incremental oil recovery. The third 44?700 bbl treatment, implemented October-November 1997, increased the pattern oil rate from ±330 BOPD in May 1998 to ±375 BOPD in July-August 1998; a linear regression of the post-treatment data gives a positive slope but again it is too early to estimate incremental oil recovery. Some general features in the pattern production response given by the three foam-gel treatments were observed. First, each of the treatments induces a stabilization in the pattern oil rate which, for treatments I and II, is accompanied by a decrease in the pattern gas rate. Second, the first positive oil rate response given by each of the treatments is observed 6-8 months after treatment execution and is dominated by the response at producer wells lying to the west/southwest and/or east/southeast of the treated injector well. For a given treatment volume, the cost of a foam-gel treatment at Rangely is 40%-50% below the average cost of polymer gel treatments. As the foam is injected at a higher rate, the total pump time required for a 40?000 bbl foam-gel treatment is similar to a 20?000 bbl polymer gel treatment. Early during pumping treatments II and III, we attempted to increase the CO2 content of the foam from 80 to 85 vol?%; this resulted in a wellhead pressure which was too close to the CO2 pressure limit necessitating a decrease in foam injection rate. Thus, in optimizing foam-gel treatment cost, there is a balance between maximizing the content of the inexpensive CO2 phase and minimizing total pump time. For Treatments II and III, the cost of the liquid phase formulation was reduced by decreasing the concentrations of surfactant and buffer. The implementation and evaluation of three large-volume foam-gel treatments at Rangely indicates that the foam-gel approach provides a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. Introduction A recent survey1 indicated that the proportion of U.S. EOR production recovered by gas injection has increased from 18% to 41% during the period 1986-1996. A major contribution to this trend has been the strong increase in the number of miscible carbon dioxide (CO2) projects which now account for > 70% of the total number of ongoing gas injection projects in the U.S. The Rangely CO2 flood began in 1986; currently, there are 372 active producer wells and 300 active injector wells, 259 of which are injecting CO2 using the water-alternating-gas (WAG) process. In the application of gas injection to heterogeneous reservoirs, oil recovery efficiency can be limited by poor conformance as an increasing proportion of the injected gas flows through higher permeability thief zones and/or fractures. The importance of conformance improvement has long been recognized at Rangely. The main problem being addressed is poor CO2 conformance due to preferential flow through the natural fracture network leading to premature gas breakthrough at the associated producers. This process increases operating costs and reduces oil recovery. The objective of the Rangely Conformance Improvement Team (CIT) is to improve conformance in order to reduce operating costs and increase the oil recovery to >1 billion bbl (>50% OOIP) compared to the current 815 million bbl (43% OOIP). A number of mechanical methods and chemical treatments have been employed to improve conformance at Rangely. While dual injection strings and selective injection equipment (SIE) have been used for improved injection profile control, chemical treatments using polymer gels2 and CO2 foam3 have been used to improve volumetric sweep efficiency and oil recovery. During the period 1994-1997, 49 injector wells were treated by placing a MARCIT™ gel4 into the fracture network.5 While these treatments have improved local sweep efficiency and oil recovery, economics limit the maximum treatment volume per injector well to 15?000-20?000 bbl. Certain regions of the Rangely reservoir require considerably larger treatment volumes to reduce the permeability of a larger volume of the fracture network and improve conformance in a larger volume of the well pattern.

Summary One of the most important but least well-known parameters in cementing operations is the circulating temperature. Many authors have presented theoretical analyses of the wellbore conditions, formulated mathematical models, and presented actual field measurements. However, very little temperature data have been reported for conditions of greatest concern (i.e., with casing in hole). To gather such data in detail, circulating temperature and pressure measurements were made with downhole tools lowered on wireline. In one case, temperature measurements were made during circulation immediately before cementing to record the circulating temperature in the well. In another case, measurements were made after the slurry was been placed to record the thermal recovery of the well. Data collected during these field trials (with casing in hole) are presented and demonstrate the different thermal response of a well with casing instead of drillpipe in the hole. Measured circulating temperatures are lower than those derived from the API schedules and highlight the necessity to account for well geometry properly when determining downhole temperatures. Introduction The oil industry has long recognized the importance of accurate and reliable determination of downhole circulating temperatures with respect to cementing operations. This is amply illustrated by the number of papers published on the subject. A number of analytical and numerical methods have been proposed to model the circulating well that often quote field data collected under drilling conditions. Various tools have been proposed for downhole flowing temperature measurement, and field data have been presented that show temperatures measured with drillpipe in the hole. However, very few papers have reported field data under the conditions that are most important (i.e., circulating temperatures with casing in hole). This paper presents the results of two field trials where fluid temperatures have been measured either at the casing shoe just before or immediately after the placement of a cement slurry.

Thirty-six thousand four hundred barrels of CO 2 gelled foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were ͑1͒ to improve volumetric conformance in this CO 2 flood by reducing excessive CO 2 breakthrough through fractures, and ͑2͒ to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam gel technology is one way to economically achieve in-depth conformance improvement at Rangely by replacing 60 to 80% of the liquid phase by the less expensive CO 2 phase. A gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria: ͑1͒ to produce strong and robust gelled foams under the harsh pH conditions of a CO 2 flood, ͑2͒ to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction, and ͑3͒ to considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gelled foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection, and corefloods with supercritical CO 2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response, and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior, are given. Finally a preliminary assessment of the impact of the treatment on CO 2 cycling rates and incremental oil production is presented.