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.

Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid, organic acids, or mixtures of these acids are typically used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks including high and uncontrolled reaction rate and corrosion to well tubulars, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at high temperatures. Hydrochloric acid (HCl) and its based fluids have a major drawback in stimulating shallow (low fracture gradient) formations as they may cause face dissolution (formation surface washout) if injected at low rates. The objective of stimulation of sandstone reservoirs is to remove the damage caused to the production zone during drilling or completion operations. Many problems may occur during sandstone acidizing with Hydrochloric/Hydrofluoric acids (HCl/HF) mud acid. Among those problems: decomposition of clays in HCl acids, precipitation of fluosilicates, the presence of carbonate can cause the precipitation of calcium fluorides, silica-gel filming, colloidal silica-gel precipitation, and mixing between various stages of the treatment. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact. Glutamic acid diacetic acid (GLDA) a newly developed environmentally friendly chelate was examined as stand-alone stimulation fluid in deep oil and gas wells. In this study we used GLDA to stimulate carbonate cores (calcite and dolomite). GLDA was also used to stimulate and remove the damage from different sandstone cores containing different compositions of clay minerals. Carbonate cores (calcite and dolomite) of 6 and 20 in. length and 1.5 in. diameter were used in the coreflood experiments. Coreflood experiments were run at temperatures ranging from 180 to 300oF. Ethylene diamine tetra acetic acid (EDTA), hydroxyl ethylethylene diaminetriacetic acid (HEDTA), and GLDA were used to stimulate and remove the damage from different sandstone cores at high temperatures. X-ray Computed Topography (CT) scans were used to determine the effectiveness of these fluids in stimulation calcite and dolomite cores and removing the damage from sandstone cores. The sandstone cores used in this study contain from 1 to 18 wt percent illite (swellable and migratable clay mineral). GLDA was found to be highly effective in creating wormholes over a wide range of pH (1.7-13) in calcite cores. Increasing temperature enhanced the reaction rate, more calcite was dissolved, and larger wormholes were formed for different pH with smaller volumes of GLDA solutions. GLDA has a prolonged activity and leads to a decreased surface spending resulting in face dissolution and therefore acts deeper in the formation. In addition, GLDA was very effective in creating wormholes in the dolomite core as it is a good chelate for magnesium. Coreflood experiments showed that at high pH values (pH =11) GLDA, HEDTA, and EDTA were almost the same in increasing the permeability of both Berea and Bandera sandstone cores. GLDA, HEDTA, and EDTA were compatible with Bandera sandstone cores which contains 10 wt percent Illite. The weight loss from the core was highest in case of HEDTA and lowest in case of GLDA at pH 11. At low pH values (pH =4) 0.6M GLDA performed better than 0.6M HEDTA in the coreflood experiments. The permeability ratio (final/initial) for Bandera sandstone cores was 2 in the case of GLDA and 1.2 in the case of HEDTA at pH of 4 and 300oF. At high pH HEDTA was the best chelating agent to stimulate different sandstone cores, and at low pH GLDA was the best one. For Berea sandstone cores EDTA at high pH of 11 was the best in increasing the permeability of the core at 300oF. The low pH GLDA based fluid has been especially designed for high temperature oil well stimulation in carbonate and sandstone rock. Extensive studies have proved that GLDA effectively created wormholes in carbonate cores, is gentle to most types of casing including Cr-based tubular, has a high thermal stability and gives no unwanted interactions with carbonate or sandstone formations. These unique properties ensure that it can be safely used under extreme conditions for which the current technologies do not give optimal results. Furthermore, this stimulation fluid contributes to a sustainable future as it based on readily biodegradable GLDA that is made from natural and renewable raw material.

This work proposes to survey new chemical knowledge, developed since 1984, on fluid additives used in matrix stimulation treatments of carbonate and sandstone petroleum reservoirs and describes one method of organizing this new knowledge in a software program using the Visual Basic for Applications programming language. While matrix stimulation treatments have been used in the petroleum industry for over 100 years, the last major review of the technical literature addressing this process occurred in 1984. Currently though, the petroleum industry better understands formation damage; uses different and more chemical additives in matrix stimulation treatments; and understands how some additives interact with one another affecting well performance. As a result, a new and thorough review of the literature regarding chemical additive choices for matrix stimulation treatments will help practicing engineers achieve better results worldwide. Moreover, organizing this chemical knowledge in a software program using VBA allows an engineer to access the information through Microsoft's widely available spreadsheet program, Microsoft Excel.

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.

Carbon dioxide (CO2) sequestration is defined as the removal of gas that would be emitted into the atmosphere and its subsequent storage in a safe, sound place. CO2 sequestration in underground formations is currently being considered to reduce the amount of CO2 emitted into the atmosphere. However, a better understanding of the chemical and physical interactions between CO2, water, and formation rock is necessary before sequestration. These interactions can be evaluated by the change in mineral content in the water before and after injection, or from the change in well injectivity during CO2 injection. It may affect the permeability positively due to rock dissolution, or negatively due to precipitation. Several physical and chemical processes cover the CO2 injection operations; multiphase flow in porous media is represented by the flow of the brine and CO2, solute transportation is represented by CO2 dissolution in the brine forming weak carbonic acid, dissolution-deposition kinetics can be seen in the rock dissolution by the carbonic acid and the deposition of the reaction products, hydrodynamic instabilities due to displacement of less viscous brine with more viscous CO2 (viscous fingering), capillary effects and upward movement of CO2 due to gravity effect. The objective of the proposed work is to correlate the formation damage to the other variables, i.e. pressure, temperature, formation rock type, rock porosity, water composition, sulfates concentration in the water, CO2 volume injected, water volume injected, CO2 to water volumetric ratio, CO2 injection rate, and water injection rate. In order to achieve the proposed objective, lab experiments will be conducted on different rock types (carbonates, limestone and dolomite, and sandstone) under pressure and temperature that simulate the field conditions. CO2 will be used at the supercritical phase and different CO2-water-rock chemical interactions will be addressed. Quantitative analysis of the experimental results using a geochemical simulator (CMG-GEM) will also be performed. The results showed that for carbonate cores, maintaining the CO2/brine volumetric ratio above 1.0 reduced bicarbonate formation in the formation brine and helped in minimizing precipitation of calcium carbonate. Additionally, increasing cycle volume in WAG injection reduced the damage introduced to the core. Sulfate precipitation during CO2 sequestration was primarily controlled by temperature. For formation brine with high total dissolved solids (TDS), calcium sulfate precipitation occurs, even at a low sulfate concentration. For dolomite rock, temperature, injection flow rate, and injection scheme don't have a clear impact on the core permeability, the main factor that affects the change in core permeability is the initial core permeability. Sandstone cores showed significant damage; between 35% and 55% loss in core permeability was observed after CO2 injection. For shorter WAG injection the damage was higher; decreasing the brine volume injected per cycle, decreased the damage. At higher temperatures, 200 and 250 degrees F, more damage was noted than at 70 degrees F.

Formation damage is a common problem in petroleum reservoirs and happens in different stages of reservoir development from drilling to production. The causes of formation damage include particle invasion, formation fines migration, chemical precipitation, and pore deformation or collapse. Formation damage adversely affects productivity of wells by reducing the permeability of near wellbore region. Furthermore, formation damage also affects well logging results. Therefore, understanding the mechanism of formation damage is vital to predict the extent and severity of formation damage and to control it. This thesis is focused on the study of formation damage caused by external particle invasion. A simplified numerical method based on a commercial code PFC (Particle Flow Code) is proposed to simulate the particle invasion process. The fluid-particle interaction is simplified as hydrodynamic drag forces acted on particles by fluids; the particle-grain interaction is modeled as two rigid balls on contact. Furthermore, an pore network flow model is developed in this study to estimate permeability of damaged formations, which contain two well-separated particle sizes. The effects of the particle size and the initial formation porosity on formation damage are studied in detail. Our study shows that big particles tend to occupy the formation face, while small particles invade deep into the formation. Moreover, particles which are smaller than pore throats (entrances) impair permeability more than those bigger than pore throats. Our study also indicates that a higher initial formation porosity results in more particle invasion and permeability impairment. It is suggested that, in order to reduce formation damage, mud particle size distributions should be carefully selected according to given formation properties. Although our model has some limitations, it may serve as a tool to predict formation damage according to given parameters, and to understand the mechanism of formation damage from a micro-scopic point of view. / text