Colloidal gas aphrons (CGAs) recently used as part of water-based drilling fluids have been found effective in controlling the filtration rate by bridging the pores of the reservoir rock and therefore, reducing the formation damage. This research aims to generate colloidal gas aphrons (CGA) in oil based drilling fluids; to study stability, rheology and the filtration loss characteristics of CGAs and to investigate formation damage properties of CGAs as a drilling fluid. Aphrons were generated in mineral oil using a polymer-surfactant mix. Based on how changing the polymer and surfactant concentration affects the physico-chemical characteristics of the fluid, an optimum formulation for the aphron drilling fluid was suggested. The stability of microbubbles was investigated by looking at the effects of time, temperature and pressure on the aphron yield and bubble size distribution. Effects of temperature and pressure on the density of the oil-based aphron fluids have been investigated. Based on the PVT analysis results, an equation of state was proposed. Finally, the performance of the oil-based aphron fluid in porous media was investigated. The effects of changing the CGA fluid injection rate, the type of saturating fluid and the wettability of the porous media on the pressure drop were examined. An assessment of the formation damage following the oil-based CGA fluid injection was also made. / Petroleum Engineering

No description available.

Polymers are among the most important of various oilfield chemicals and are used for a variety of applications in the oil and gas industry (OGI) including water and gas shutoff, drilling mud viscosity modification, filtration loss control (FLC), swellable packers, loss circulation material (LCM) pills, enhanced oil recovery (EOR), fracture treatment and cleanup, chemical placement, etc. The deposition and retention of polymer molecules in porous media and their interactions with rock and fluids present complex phenomena that can induce formation damage. Formation damage due to polymer retention can occur via mobility reduction in three possible mechanisms of polymer-induced formation damage: 1) pore-throat blocking, 2) wettability alteration (which can alter permeability), and 3) increase in reservoir fluid viscosity. Physical adsorption can also cause permanent permeability impairment (formation damage). This polymer-induced formation damage (causing a reduction in net oil recovery) continues to be a fundamental problem in the industry owing to the rather shallow understanding of the mechanics of polymer-brine-rock interactions and the polymer-aided formation damage mechanisms. Most models available for polymer risk assessments appear to be utilised for all scenarios with unsatisfying results. For example, only very little, if any, is known on how polymer type, particularly in the presence of brine type impact on formation damage. In order words, one of current industry challenges is finding effective polymers for high salinity environments. Also, the effect of polymer charge, as well as charges at the brine-rock interface are issues that require a deeper understanding in order to address the role polymer play in formation damage. Furthermore, no much recognition has been given to polymer rheological behaviour in complex porous media, etc. The OGI therefore still faces the challenge of the inability to correctly predict hydrolysed polyacrylamide (HPAM) viscosity under shear degradation; and consequently have not been able to meet the need of production predictions. The effect of the above mentioned factors, etc have not been fully integrated into the polymer formation damage modelling. In this PhD research work, theoretical, numerical, laboratory experiments and analytical methods were used to further investigate the mechanics of polymer-brine-rock interactions and establish the mechanisms for formation damage related to polymer application. Three different hydrolysed polyacrylamide (HPAM) products (SNF FP3630 S, 3330 S and FloComb C3525) were used in the experiments; while Xanthan gum was used in the simulation work. The following variables were considered: 1) polymer type, 2) effect of concentration, 3) effect of salinity/hardness, 4) effect of permeability and pore size distributions, 5) effect of inaccessible pore volume (IAPV) on retention, 6) effect of flow rate (where a special method was established to quantify the effect of flow rate on polymer retention). Laboratory rheological and adsorption experiments were designed and conducted. Experimental results indicate that higher concentration of calcium divalent ions in brine help promote polymer retention on rock surface. On the basis of the experimental results, empirical models were developed and validated to: 1) predict HPAM rheological behaviour over a wide range of shear rates, 2) predict salinity-dependent polymer-induced formation damage, 3) in addition, a modified screening model that can aid polymer selection for field application design is proposed. Overall, these models can therefore serve as useful tools, and be used for quick look-ahead prediction and evaluation of polymer related formation damage in oil and gas-bearing formations.

Viscoelastic surfactants (VES) have been widely used in acidizing and acid fracturing. They are used as diversion agents during matrix acid treatments and leakoff control agents during acid fracturing. At high temperatures, viscoelastic surfactants hydrolyze, resulting in phase separation after a certain time. Their viscosities significantly decrease and it is much easier for them to flow back causing much less damage to the formation. In this study, 4 to 8 wt% of a new VES-acid system was tested at temperatures of up to 250°F over hydrolysis times of 0 to 6 hours. Then, the solutions were neutralized by calcium carbonate until the pH reached 4.5. An HP/HT rheometer was used to measure the viscosity of the spent acids. Mass spectrometry (MS) was conducted to analyze the hydrolysis products of the VES. Coreflood tests were also conducted on Indiana limestone to determine the effects of the hydrolysis products on the permeability of these cores. The temperature was set at 250°F and the flow rate at 2.5 cm^(3)/s. The viscosities of all VES-acid systems remained high at the beginning of hydrolysis, which was good for acid diversion. After that, the VES acid systems experienced a significant viscosity reduction due to phase separation; it became much easier for the spent acid to flow back. Coreflood experiments caused little damage to the Indiana limestone. MS results indicated hydrolysis of peptide bonds. Fatty acids formed the top oil layer, and amine-based molecules formed the aqueous phase. This study will summarize and discuss the details of viscosity changes of the acid systems of this kind of viscoelastic surfactant, the damage caused by hydrolysis products, and how this kind of viscoelastic surfactant can be used to improve treatments.

Iron control during acidizing plays a key role in the success of matrix treatment. Ferric ion precipitates in the formation once the acid is spent and the pH exceeds 1-2. Precipitation of iron (III) within the formation can cause formation damage. Chelating agents such as EDTA and NTA are usually added to acids to minimize iron precipitation. Drawbacks of these chelating agents include limited solubility in strong acids and poor environmental profile. Hydroxy EDTA was introduced because of its higher solubility in 15 wt% HCl. However, its solubility in 28 wt% HCl is low and it is not readily biodegradable. In this study we studied the formation damage caused by iron precipitation in acidizing operations and tested the chelate L-glutamic acid, N,N-diacetic acid (GLDA). This chelant is soluble in higher concentrations of HCl. It is readily biodegradable, and is an effective iron control agent. A study was conducted to study the concentration of iron at different pHs ranging from 1-4 without the presence of any chelating agent at room temperature. A similar study was conducted in the presence of a chelating agent. To simulate field conditions, coreflood tests were conducted on Indiana Limestone, Austin Chalk and Pink Desert. Tests were conducted with and without the chelant. Samples of core effluent were collected and iron and calcium concentrations were measured using atomic absorption spectroscopy (AA). The cores were scanned using X-ray before and after acid injection. Results indicated that precipitation of iron can cause serious reduction in core permeability. The chelate was found to be very effective in chelating iron upto 300 degrees F. No permeability reduction was noted when GLDA was added to the acid. Material balance calculations show that significant amount of the iron that was added to the injected acid was produced when GLDA was used. This chelant is effective, environmentally friendly and can used up to 300 degrees F.

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.

Thesis (Ph. D.)--University of Texas at Austin, 2008. / Vita. Includes bibliographical references and index.

[pt] A filtração profunda de suspensões particuladas ocorre em muitos processos industriais e ambientais, como filtração de água e contaminação do solo. Na indústria petrolífera, a filtração profunda ocorre próximo ao poço injetor durante a injeção de água, causando redução de injetividade. A captura de partículas no meio poroso pode ser causada por diferentes mecanismos físicos (exclusão pelo tamanho, forças elétricas, gravidade (sedimentação), etc.). No caso do mecanismo de exclusão pelo tamanho, quanto maiores forem as partículas e menores forem os poros, mais intensa será a captura. Conseqüentemente, maior será o dano à formação. Entretanto, o modelo tradicional não considera as distribuições de tamanho de partículas e de poros. Assumindo que as partículas são capturadas pelo mecanismo de exclusão pelo tamanho, foram deduzidas as equações básicas para o transporte de suspensões particuladas no meio poroso considerando as distribuições de tamanho de poros e de partículas. Apenas o fluxo de água via poros acessíveis transporta partículas, ou seja, as partículas não podem acessar poros menores do que elas. No presente trabalho, os efeitos da redução do fluxo de partículas e da inacessibilidade devido ao fluxo seletivo de diferentes tamanhos de partículas são incluídos no modelo estocástico para a filtração profunda. As soluções analíticas obtidas mostram um comportamento físico mais realístico do que o previsto pelo modelo tradicional. O modelo de medição (concentrações totais) obtido difere substancialmente do modelo tradicional para a filtração profunda. Vários dados experimentais foram tratados, mostrando boa concordância e validando o modelo proposto. Um sistema de equações estocásticas para modelar a formação do reboco externo foi proposto e soluções analíticas foram obtidas, permitindo tratar a filtração profunda e a formação do reboco externo, utilizando o mesmo formalismo matemático. / [en] Deep bed filtration of water with particles occurs in several industrial and environmental processes like water filtration and soil contamination. In petroleum industry, deep bed filtration occurs near to injection wells during water injection, causing injectivity reduction. It also takes place during well drilling, sand production control, produced water disposal in aquifers, etc. The particle capture in porous media can be caused by different physical mechanisms (size exclusion, electrical forces, bridging, gravity (sedimentation), etc.). In case of size exclusion mechanism, the larger are the particles and the smaller are the pores, the more intensive is the capture and the larger is the formation damage. Nevertheless, the widely used traditional model does not account for particle and pore size distributions. Considering that particles are captured due to size exclusion mechanism, we derived basic equations for transport of particulate suspensions in porous media, accounting for particle and pore radii distributions. Particles are carried by water flowing through the accessible pore space only, i.e. particles cannot access smaller pores. In the current work, the effects of porous space accessibility and particle flux reduction due to selective flow of different size particles are included into the stochastic deep bed filtration model. The particle and pore ensembles for analytical solutions of the derived system show more realistic physics behaviour than that of the traditional model. Averaging of the derived stochastic equations leads to a new deep bed filtration model that significantly differs from the classical deep bed filtration system. Treatment of several experimental data shows good agreement between the laboratory and modelling data and validates the proposed model. The derived stochastic model has been extended to model formation of external filter cake by particles from the injected polydispersed suspension, allowing treating both deep bed filtration and external filter cake formation in the framework of the same system of governing equations.

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.