Clay stabilizers are means to prevent fines migration and clay swelling, which are caused by the contact of formation with low salinity or high pH brines at high temperature. Previous clay stabilizers including: Al and Zr compounds and cationic polymers have several drawbacks. Al and Zr compounds can be removed by acids. Cationic polymers can cause formation damage in some cases. Quaternary amine-based chemicals have been used for many years as clay stabilizer, however, environmental profile of some has limited their use. There is a need to develop new clay stabilizers that can work following acid treatment and are environmentally acceptable. Laboratory studies were conducted on newly developed Al/Zr-based compound (Stabilizer A) to determine the optimum conditions for field application. Zeta potential was used to determine surface charge of different types of clays; and to optimize clay stabilizer concentration. Coreflood experiments were conducted on Berea and Bandera sandstone cores to assess the effectiveness of the new compound at high temperature, and determine the impact of acids on its performance. Also the effectiveness of this stabilizer was investigated at high pH medium and in low permeability cores. Inductively Coupled Plasma was used to measure the concentrations of e key cations in the core flood effluent. Three different commercial clay stabilizers (zirconium oxychloride, choline chloride and tetramethyl ammonium chloride) were also tested to validate the new chemical. The new clay stabilizer was very effective in mitigating fines migration. Zeta potential indicated that the isoelectric point at which complete shields of surface charge of clay particles was achieved at a stabilizer concentration of 0.2 wt%. Coreflood tests showed that this new chemical was effective, and unlike previous Al-based and Zr-based stabilizers (hydroxy aluminum and zirconium oxychloride solutions), it did not dissolve in acids and worked very well up to 300oF. Stabilizer A proved to be better than the three commercial stabilizers. Stabilizer A worked effectively at the high pH and no reduction in permeability was noticed after NaOH injection, unlike the other stabilizers. In addition, Stabilizer A is an inorganic-based fluid, environmentally friendly, in contrast to Quaternary amine chemicals.

Acidizing sandstone reservoirs is a complex process. If not fully studied, it could lead to formation damage. A combination of HCl/HF has been widely used to stimulate sandstone reservoirs. However, the success rate is low due to the complexity of the reactions involved in this process. These reactions result in potentially damaging precipitation and cause formation damage. The problem is more severe when dealing with Bandera sandstone formations that contain a high concentration of carbonate minerals and clay particles. The purpose of this study is to present and evaluate multi-stage acid injection into the Bandera sandstone cores to remove formation damage. In this study, coreflood experiments were conducted on Bandera sandstone cores (1.5 in. x 6 in.) at a flow rate of 4 cm^3/ min and temperature of 140°F. A mixture of formic acid and HF was used as an organic mud acid. Preflush of hydrochloric and formic acid was employed to remove carbonate minerals. Bandera sandstone cores contain a considerable amount of HCl sensitive clays. So another stage was employed to cover clay minerals and prevent HCl attack on the surface of clay particles. Different clay stabilizers as well as preflush pore volume were examined in this study. At the end, this multi-stage treatment design was tested on a Berea sandstone core to investigate the impact of mineralogy. During each experiment effluent samples were collected. Samples were analyzed using Inductively Coupled Plasma (ICP) and Scanning Electron Microscopy (SEM) to investigate reaction kinetics and chemistry of precipitation. Chemical analysis confirmed incompatibility of HCl with clays in Bandera cores at 140°F. Clay stabilizer CSA showed the ability to prevent HCl attack on the clay particle’s surface. As a result, a coreflood experiment conducted using CSA led to permeability improvement. The result of the coreflood experiment conducted using CSC indicated that this chemical is able to exchange cations with clay particles, however permeability decreased due to an insufficient injection of preflush. As in another experiment, increasing preflush pore volume using CSC resulted in permeability improvement. CSB completely failed to cover clay minerals and permeability decreased drastically at the end of the treatment.

Mathematical Modeling of Fines Migration and Clogging in Porous Media Guido Kampel 87 Pages Directed by Dr. Guillermo H. Goldsztein A porous medium is a material that contains regions filled with fluid embedded in a solid matrix. These fluid filled regions are called pores or voids. Suspensions are fluids with small particles called fines. As a suspension flows through a porous material, some fines are trapped within the material while others that were trapped may be released. Filters are an example of porous media. We model filters as networks of channels. As a suspension flows across the filter, particles clog channels. We assume that there is no flow through clogged channels. In the first part of this thesis, we compute a sharp upper bound on the number of channels that can clog before fluid can no longer flow through the filter. Soil mass is another example of porous media. Fluid in porous media flows through tortuous paths. This tortuosity and inertial effects cause fines to collide with pore walls. After each collision, a particle looses momentum and needs to be accelerated again by hydrodynamic forces. As a result, the average velocity of fines is smaller than that of the fluid. This retardation of the fines with respect to the fluid may lead to an increase of the concentration of fines in certain regions which may eventually result in the plugging of the porous medium. This effect is of importance in flows near wells where the flow has circular symmetry and thus, it is not macroscopically homogeneous. In the second part of this thesis we develop and analyze a mathematical model to study the physical effect described above. In the third and last part of this thesis we study particle migration and clogging as suspension flows through filters by means of numerical simulations and elementary analysis. We explore the effect that network geometry, probability distribution of the width of the channels and probability distribution of the diameter of the particles have on the performance of filters.

In this thesis, permeability impairment caused by drilling fluids and subsequent cleaning and permeability enhancement by back-flow were investigated by means of experimental and simulation studies. Permeability damage caused by three different drilling fluids was measured experimentally by core tests as a function of the filtration pressure and analyzed using a simulator describing the fines migration and retention in porous media. The pore throat plugging criteria for the three drilling fluids were determined. The particle concentration and the fraction of depositing particles were obtained simultaneously as a function of time and distance along the core length by numerical solution. Simulations were run both with experimental data in forward and backward directions along the core samples. Permeability damage ratio was correlated with respect to drilling filtration pressure specially for each type of the drilling fluids and type curves were constructed. Simulation results accurately match the experimental data, indicating that this simulator can be used for the estimation of permeability reduction, and the permeability and porosity variation along the core samples at various filtration pressures. X-Ray digital image subtraction was applied to different sections of the core plugs before and after the circulation to visualize the fines migration into porous media. The maximum damage ratio was obtained with the CMC added drilling fluid with 81 %. In the absence of CMC and Polymer-XT, the damage ratio was found as 72.8%. It was also determined that a polymer-added drilling fluid characterized with 63.8% permeability damage ratio is the optimum drilling fluid, causing less formation damage than the water-based bentonite mud.