This thesis provides a detailed evaluation of different environmentally friendly dispersants in invert-emulsion drilling fluids that can be used to drill wells under difficult conditions such as HPHT. The drilling fluid is weighted by manganese tetraoxide (Mn3O4) particles, which have a specific gravity of 4.8 and a mean particle diameter of ca1 micrometers. Manganese tetraoxide has different wetting properties and surface chemistry than other weighting agents. Hence, there is a need to find dispersants for manganese tetraoxide that give reduced sag, reduced rheology, and low fluid-loss at HPHT conditions. This is particularly important for deep wells with narrow operating windows between pore-pressure and fracture pressure gradients. The stricter global environmental regulations mandated the dispersants to be environmentally friendly, e.g. within OCNS group D or E. First, oil compatibility tests and particle settling time experiments were conducted on 31 dispersants. From the experiments, we identified 3 oil-compatible dispersants that gave the longest settling time in base oil and belonged to OCNS group D. We investigated the effectiveness of selected chemicals in dispersing manganese tetraoxide at HPHT conditions. 1.95 and 2.4 S.G. drilling fluid samples were first prepared and tested without any contaminant and then in the presence of rev dust and cement as contaminants. Drilling fluid samples were statically aged at 400 degrees F and 500 psi for 16 hours. Sag and rheological measurements were taken before and after aging to determine the effect of HPHT conditions on fluid properties. Then, HPHT dynamic filtration tests were done at 500 psi differential pressure and 300 degrees F to determine HPHT dynamic fluid-loss. We have found that one of the dispersants (nonionic) gives low rheology and reduced sag before and after static aging. It also gives the lowest fluid-loss of the selected dispersants. For 2.4 S.G. fluid without contaminants, 10-minute gel strength was reduced from 50 to 32 lb/100 ft^2, plastic viscosity from 37 to 25 cp, sag from 0.249 to 0.135 lbm/gal, and fluid-loss was reduced from 44.4 to 39.6 cm^3 with the addition of dispersant. This dispersant prevents agglomeration of particles, thereby reducing fluid rheology, sag, and fluid-loss.

Thesis (M.S.)--West Virginia University, 2007. / Title from document title page. Document formatted into pages; contains x, 65 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 58-60).

Analysis of the drilling fluid temperature in a circulating well is the main objective of this study. Initially, an analytical temperature distribution model, which utilizes basic energy conservation principle, is presented for this purpose. A computer program is written in order to easily implement this model to different cases. Variables that have significant effect on temperature profile are observed. Since the verification of the analytical model is not probable for many cases, a computer program (ANSYS) that uses finite element method is employed to simulate different well conditions. Three different wells were modeled by using rectangular FLOTRAN CFD element that has four nodes. Maximum drilling fluid temperature data corresponding to significant variables is collectedfrom these models. This data is then used to develop an empirical correlation in order to determine maximum drilling fluid temperature. The proposed empirical correlation can estimate the temperature distribution within the wellbore with an average error of less than 16%, and maximum drilling fluid temperature with an average error of less than 7 %.

The ability of starch to impart functions including fluid-loss control, cuttings transport, and rheological characteristics to water-based drilling fluids has led to its widespread use in the oil industry. The filter cake deposited by these drilling fluids often employs sized solid particles and starch to inhibit fluid loss into the formation. This inherently causes damage to the formation by impairing the permeability and must be removed before production. An alpha-amylase enzyme treatment was found to provide an effective approach to degrading starch in filter cake. In this work, an alpha-amylase enzyme treatment was analyzed by determining the extent of degradation of starch in filter cake using the iodine test, identifying degradants using high performance liquid chromatography, spectrophotometrically monitoring the concentration of enzyme, and measuring the cleanup efficiency of the enzyme treatment using a static filter press apparatus. The alpha-amylase enzyme used in this study was found to have a molecular weight under 30,000. The activity of the alpha-amylase enzyme was found to be sensitive to pH and temperature. The alpha-amylase enzyme was found to denature at temperatures above 165 degrees F and reversibly deactivate at pH below 4. Optimal conditions for alpha-amylase activity were found to be 150 degrees F and pH 6.5. The enzyme treatment works by hydrolyzing the interior glycosidic bonds of amylose and amylopectin residues of starch, creating soluble poly- and oligosaccharides and glucose. The enzyme treatment did not dissolve the calcium carbonate sized solids and a 5 wt. % hydrochloric acid postflush was necessary. The cleanup efficiency of the enzyme at pH 6.5 and room temperature treatment in conjunction with the postflush in a static test was 73% at 10% v/v concentration. Degradants resulting from alpha-amylase were identified chromatographically. Enzyme concentration remained steady prior to and after treatment.

Spent oil based drilling fluid and cutting wastes are global liabilities due to their hazardous hydrocarbon content which impacts negatively on flora, fauna, and global carbon footprint. The formulation of two demulsifiers to ensure chemically enhanced phase separation of this waste into oil, water and solid components was successfully carried out in addition to recycling the solid phase into PA6 nanocomposite materials. Initial characterisation of the untreated waste was carried out by Fourier Transform Infra Red (FTIR) for total petroleum hydrocarbon (TPH) analysis, Inductively coupled plasma optical emission spectrometry (ICPOES) for quantitative elemental analysis and Energy dispersive xray analysis (EDXA) for qualitative elemental composition amongst other characterisation methods. The analysis showed that the sample had a high hydrocarbon load of 662,500mg/kg and a high heavy metal load for Pb of 122mg/kg. No As, Cd, Hg were detected. The demulsifier formulations were composed of isopropanol, sodium dodecyl sulphate, poloxamer, sodium chloride, chitosan in 0.2M acetic acid and deionised water for demulsifier S4 and addition of phosphoric acid for demulsifier S3. Hydrocarbon reduction on the extracted solid phase nanofiller S3 and nanofiller S4 was 98.6% and 98.5% respectively after demulsification. The demulsified spent oil based drilling fluid solid extracts were below OSPAR regulation of < 1% oil on cutting by weight. However, recycling of the recovered solid was carried out in order to achieve environmentally sustainable management of the waste in Polyamide 6 (PA6) nanocomposite manufacture/fabrication. The formulation of different blends of PA6 nanocomposite materials from untreated, demulsifier treated and thermally treated drilling fluid and cuttings was successfully achieved. Nanocomposite leaching test showed Pb immobilisation. The flexural and compressive - modulus and strength of the PA6 were markedly improved in the presence of the nanofillers and glass fibre. This was attributed to the reinforcement, exfoliating, stiffening, rigidity effect of the nanofillers. S6 (untreated drilling fluid) nanofillers significantly improved the mechanical properties of PA6. This was attributed to the increased interfacial bonding between the fillers and the polymer matrix as a result of the petroleum hydrocarbon present in the sample. The Thermogravemetric analysis (TGA) results showed that nanocomposites PA6/S3 and PA6/S3/GF30 had improved the thermal stability of PA6 by 13.6% and 38.8% respectively compared to PA6/S2 and PA6/S2/GF30 (simulated commercial nanocomposite materials) that improved PA6 by 9.7% and 35.8% respectively.

Na perfuração de poços para extração de petróleo são utilizados fluidos de perfuração compostos por diversos produtos químicos com finalidades específicas em função das características de cada poço. Durante vários anos utilizou-se fluido a base de óleo diesel, devido à excelente performance proporcionada à perfuração. O aumento da preocupação ambiental levou a indústria do petróleo a elaborar composições de fluidos que fossem menos agressivas ao ambiente e, ao mesmo tempo, apresentassem performances semelhantes à do fluido base óleo diesel, destacando-se na atividade de perfuração na bacia do Recôncavo, Bahia, o fluido n-Parafina. Entre os compostos de interesse ambiental presente neste tipo de fluido, destacam-se a n-Parafina e cloretos, algumas vezes com traços de BTEX (benzeno, tolueno, etilbenzeno e xilenos). Como durante a perfuração podem ser atravessados aqüíferos portadores de água doce, resta a preocupação de que o contato desses fluidos com estes aqüíferos possa gerar problemas de contaminação ambiental. Este trabalho apresenta uma avaliação de situações de poços, onde o aqüífero São Sebastião, principal da bacia do Recôncavo, foi atravessado utilizando-se fluido n-Parafina. A avaliação foi baseada em simulações matemáticas do transporte dos compostos encontrados no fluido n-Parafina e em amostras coletadas a partir de testes de formação a cabo durante a perfuração dos poços. A partir da simulação destes valores reais, pôde-se concluir que, a menos de 0,5 m da parede dos poços, as concentrações encontram-se perfeitamente dentro dos padrões de potabilidade para todos os compostos analisados. De acordo com a metodologia utilizada, as utilizações do fluido n-Parafina são ambientalmente inofensivas como fluido de perfuração a ser utilizado neste tipo de cenário hidrogeológico. / The use of drilling fluids or muds is standard practice in oil industry. The composition of these fluids is designed according to the formation and the well properties. For many years oil- based muds (OBM) had a worldwide use because they offered advantages over water-based muds (WBM). Increasing environmental concern led the oil industry into the formulation of a variety of syntetic organic based mud (SBM) or low-tox mineral oil- based mud, like the n-parafin based mud, with a large use at the Reconcavo Basin, Bahia, Brazil. Some of the compounds that are common to most fluid formulas are considered potential environmental contaminants, among them n-parafin and chloride, sometimes with trace BTEX (benzene, toluene, ethylbenzene and xylenes). The drilling of the well might cross aquifers that are used for drinking purposes before reaching the oil reservoir and the contact of the water with the drilling fluid might pose some concern about the aquifer contamination. This paper presents case studies where a well penetrated São Sebastião Aquifer, in Reconcavo Basin, using n-Parafin based mud and a mathematical model was applied to simulate the fate and transport of the compounds found in fluid and samples collected during the drilling. The results indicated that all concentration values of the detected compounds were well below water drinking standards within 0,5 m from the well. According to this conclusion, the use of the n-parafin fluid is considered harmless to the environment and is recommended for similar geological scenarios.

A drilling operation leads to thermal disturbances in the near-wellbore stress, which is an important cause of many undesired incidents in well drilling. A major cause of this thermal disturbance is the temperature difference between the drilling fluid and the downhole formation. It is critical for drilling engineers to understand this thermal impact to optimize their drilling plans. This thesis develops a numerical model using partially coupled thermoporoelasticity to study the effects of the temperature difference between the drilling fluid and formation in a drilling operation. This study focuses on the thermal impacts at the bit/formation interface. The model applies the finite-difference method for the pore pressure and temperature solutions, and the finite-element method for the deformation and stress solutions. However, the model also provides the thermoporoelastic effects at the wellbore wall, which involves wellbore fractures and wellbore instability. The simulation results show pronounced effects of the drilling fluid temperature on near-wellbore stresses. At the bottomhole area, a cool drilling fluid reduces the radial and tangential effective stresses in formation, whereas the vertical effective stress increases. The outcome is a possible enhancement in the drilling rate of the drill bit. At the wellbore wall, the cool drilling fluid reduces the vertical and tangential effective stresses but raises the radial effective stress. The result is a lower wellbore fracture gradient; however, it benefits formation stability and prevents wellbore collapse. Conversely, the simulation gives opposite induced stress results to the cooling cases when the drilling fluid is hotter than the formation.

Depleting oil reserves and increased costs of the oil and gas recoveries have created the need to drill in challenging formations. When drilled through, shale formations in particular always generated a wide variety of problems if conventional water-based muds are used. Furthermore, the complexity and variations in shales have compounded the task of developing suitable drilling fluids. In light of these problems, the study of shale properties and their interactions with fluids will continue to be a muchneeded source of information in drilling industry. In this study a low molecular weight quaternary amine compound, which is provided by KarKim Drilling Fluids Inc., and its mixtures with sodium and potassium chloride is investigated in the aspects of capillary suction times, hot rolling recoveries, methylene blue capacities and one-dimensional free swelling properties in order to compare performances of salts and amine compound. For all test methods quaternary amine concentration from 1% to 6% by volume were studied and seen that less amount of quaternary amine compound is needed in order to obtain close shale recoveries and shale volume change potential if compared with sodium and potassium chloride. This prevents the usage of high concentration of chlorides and hence provides environmental sensitiveness. Furthermore, it was concluded that combining an amount of salt with quaternary amine compound gives the system enhanced shale inhibition properties.

The objective of this study is to determine hydrate formation conditions of a multicomponent polymer based drilling fluid. During the study, experimental work is carried out by using a system that contains a high-pressure hydrate formation cell and pressure-temperature data is recorded in each experiment. Different concentrations of four components of drilling fluid, namely potassium chloride (KCl), partially hydrolyzed polyacrylicamide (PHPA), xanthan gum (XCD) and polyalkylene glycol (poly.glycol) were used in the experiments, to study their effect on hydrate formation conditions.

Excessive torque is one of the most important problems in oil/gas drilling industry. Friction between wellbore/casing and drill string causes excessive torque. This study discusses performance analysis of drilling fluid lubricants, which are used as friction reducers in well-bore. Three different types of commercial chemical lubricants, which are fatty acid and glycerid based, triglycerid and vegetable oil based and polypropylene glycol based, diesel oil, and crude oil, which consists of different API gravity, paraffin and asphaltene value samples, were selected for the analysis. In the analysis, different lubricant compositions with the mixture of commercial chemical lubricants, crude oil and diesel oil, which were added to water based lignosulfonate mud, are tested on metal-metal contact surface by Ofite Lubricity Tester to determine the best lubricity/cost ratio of lubricant compositions. Moreover, effects of the lubricants on mud rheology and API fluid loss of mud, foam forming potential and cheesing/greasing of the lubricants and the influence of mud properties on lubricants (calcium, salt, pH and mud density) are examined.