This thesis discusses the effect of cryogenic temperatures on composite materials. The work includes estimating the shear strength of carbon/epoxy and glass/polyester composites at low temperatures and finding the rate of generation of microcracks in composites at cryogenic temperatures by acoustic emission technique. Microcracks increase the permeability of composites. So to study the permeability growth with microcracks, equipment is also designed to measure the permeability of composite to low temperature fluids. With short beam shear testing it was observed that the shear strength of composites increases with decreasing temperatures. Also carbon/epoxy composites were found to be much stronger than glass/polyester composites. Cryogenic temperatures improve the strength of composites but also generate microcracks in the structure due to the thermal expansion mismatch between the matrix and fiber. With acoustic emission testing from room to –150ºC, it was found that the rate of generation of microcracks increases with reducing temperatures. The work is extended to design a permeability equipment.

Abstract Burrow-associated diagenetic alteration and eventual reservoir quality parameters such as porosity and permeability may be altered due to reorganization of the sediment fabric associated with animal burrowing, or result from heterogeneous cement distribution influenced by the bioturbate texture. Petrographic analysis has significant application in recognizing burrow-associated porosity characteristics in marine sandstones. Petrographic analysis can provide mineral identification due to diagenetic chemical alterations and textural evidence regarding cementation history that can lead to more accurate hydrocarbon target interpretations. Overlooking burrow structures may lead to misinterpretations of permeability streaks in hydrocarbon reservoirs. This may be extremely important for reservoirs where slight permeability variations have an effect on hydrocarbon reserve calculations. Understanding biogeochemical reactions and burrow-associated diagenesis that ultimately control reservoir quality is necessary if production from ancient bioturbated marine sandstone reservoirs is to be optimized.

People in the oil and gas industry sometimes do not consider pressure-dependent permeability in reservoir performance calculations. It basically happens due to lack of lab data to determine level of dependency. This thesis attempts to evaluate the error introduced in calculations when a constant permeability is assumed in tight gas reservoir. It is desired to determine how accurate are conventional pressure analysis calculations when the reservoir has a strong pressure-dependent permeability. The analysis considers the error due to effects of permeability and skin factor. Also included is the error associated when calculating Original Gas in Place in the reservoir. The mathematical model considers analytical and numerical solutions of radial and linear flow of gas through porous media. The model includes both the conventional method, which assumes a constant permeability (pressure-independent), and a numerical method that incorporates a pressure-dependent permeability. Analysis focuses on different levels of pressure draw down in a well located in the center of a homogeneous reservoir considering two types of flow field geometries: radial and linear. Two different producing control modes for the producer well are considered: constant rate and constant bottom hole pressure. Methodology consists of simulated tight gas well production with k(p) included. Then, we analyze results as though k(p) effects were ignored and finally, observe errors in determining permeability (k) and skin factor (s). Additionally, we calculate pore volume and OGIP in the reservoir. Analysis demonstrates that incorporation of pressure-dependence of permeability k(p) is critical in order to avoid inference of erroneous values of permeability, skin factor and OGIP from well test analysis of tight gas reservoirs. Estimation of these parameters depends on draw down in the reservoir. The great impact of permeability, skin factor and OGIP calculations are useful in business decisions and profitability for the oil company. Miscalculation of permeability and skin factor can lead to wrong decisions regarding well stimulation, which reduces well profitability. In most cases the OGIP calculated is underestimated. Calculated values are lower than the correct value. It can be taken as an advantage if we consider that additional gas wells and reserves would be incorporated in the exploitation plan.

The objective of this project was to design a prototype field air permeameter that can be used to track changes in the hydraulic conductivity within soil covers with time. The evolution of soil structure in reclamation soil covers at the Syncrude Canada Ltd. oilsands mine is currently being studied. The Guelph permeameter is currently used to measure hydraulic conductivity, but gathering the data is a very time consuming task due to the relatively low hydraulic conductivity of the cover materials. The use of a faster, more efficient method would increase the capabilities for tracking changes in hydraulic conductivity of reclamation soil covers with time. <p>Three air permeameter design options were evaluated. One design was chosen and a prototype was built. Preliminary field trials were conducted at the Syncrude Canada Ltd. oilsands mine in August 2005. Air permeability measurements were taken on various soil cover treatments and slope positions. Improvements to the air permeameter were implemented in 2006, and additional data gathered. Guelph permeameter testing was carried out alongside the air permeameter in both field seasons. The air permeameter and Guelph permeameter were also tested under controlled laboratory conditions and compared to standard constant head column tests. <p>Results include correlations of air and water permeability for various materials and soil structures. Using dry uniform sand in a laboratory setting, the full scale air permeameter provided permeability values within 21% of a standard constant head column test. Testing of the air and Guelph permeameters on a cover constructed of peat-mineral mix over tailings sand revealed a difference of approximately one order of magnitude in permeability values. A difference of approximately two orders of magnitude existed between permeability values measured with the air and Guelph permeameters on till/secondary soil covers. <p>Further investigation into the difference between values of permeability measured with both methods is necessary. If successful, the air permeameter could prove to be a viable alternative to the Guelph permeameter for use in long-term monitoring of soil covers used in mine reclamation or waste containment. A more efficient air permeability method would allow a greater number of measurements to be made in a shorter time and could be used to track temporal as well as spatial variability in hydraulic conductivity.

The objective of this project was to design a prototype field air permeameter that can be used to track changes in the hydraulic conductivity within soil covers with time. The evolution of soil structure in reclamation soil covers at the Syncrude Canada Ltd. oilsands mine is currently being studied. The Guelph permeameter is currently used to measure hydraulic conductivity, but gathering the data is a very time consuming task due to the relatively low hydraulic conductivity of the cover materials. The use of a faster, more efficient method would increase the capabilities for tracking changes in hydraulic conductivity of reclamation soil covers with time. <p>Three air permeameter design options were evaluated. One design was chosen and a prototype was built. Preliminary field trials were conducted at the Syncrude Canada Ltd. oilsands mine in August 2005. Air permeability measurements were taken on various soil cover treatments and slope positions. Improvements to the air permeameter were implemented in 2006, and additional data gathered. Guelph permeameter testing was carried out alongside the air permeameter in both field seasons. The air permeameter and Guelph permeameter were also tested under controlled laboratory conditions and compared to standard constant head column tests. <p>Results include correlations of air and water permeability for various materials and soil structures. Using dry uniform sand in a laboratory setting, the full scale air permeameter provided permeability values within 21% of a standard constant head column test. Testing of the air and Guelph permeameters on a cover constructed of peat-mineral mix over tailings sand revealed a difference of approximately one order of magnitude in permeability values. A difference of approximately two orders of magnitude existed between permeability values measured with the air and Guelph permeameters on till/secondary soil covers. <p>Further investigation into the difference between values of permeability measured with both methods is necessary. If successful, the air permeameter could prove to be a viable alternative to the Guelph permeameter for use in long-term monitoring of soil covers used in mine reclamation or waste containment. A more efficient air permeability method would allow a greater number of measurements to be made in a shorter time and could be used to track temporal as well as spatial variability in hydraulic conductivity.

The fracture aperture and fracture permeability are usually considered to remain the same during the production life of a naturally fractured reservoir, regardless of the degree of depletion; but reservoirs experience different stress state conditions, therefore understanding the fracture behavior becomes more complex. This research analyzes the effect of fracture aperture and fracture permeability on the fluid flow under different overburden pressures. This research investigates the fracture apertures under different stress-state conditions. The equations to quantify the flow through the matrix and the fracture at different overburden pressures are provided. An X-ray CT scanner was used to obtain fracture aperture distributions at various overburden pressures to verify the use of log-normal distribution, which was commonly used for distributing fracture apertures. In addition, reservoir simulations are performed to duplicate the experimental results and to provide a valid model for future stress-sensitive reservoirs. Our experimental results show that the fracture aperture and fracture permeability have significant pressure-dependent changes in response to applying variable injection rates and overburden pressures. The laboratory results show that the change in overburden pressure significantly affects the reservoir properties. The change in matrix permeability with different injection rates under variable overburden pressures is not significant in contrast with that effect on fracture aperture and fracture permeability. A calibration curve was obtained to determine fracture aperture from the X-ray CT scanner results. The aperture distribution from data obtained from X-ray CT scanner confirms lognormal distribution at various overburden pressures. This experimental research will increase the understanding of fluid flow behavior in fractured reservoirs.

People in the oil and gas industry sometimes do not consider pressure-dependent permeability in reservoir performance calculations. It basically happens due to lack of lab data to determine level of dependency. This thesis attempts to evaluate the error introduced in calculations when a constant permeability is assumed in tight gas reservoir. It is desired to determine how accurate are conventional pressure analysis calculations when the reservoir has a strong pressure-dependent permeability. The analysis considers the error due to effects of permeability and skin factor. Also included is the error associated when calculating Original Gas in Place in the reservoir. The mathematical model considers analytical and numerical solutions of radial and linear flow of gas through porous media. The model includes both the conventional method, which assumes a constant permeability (pressure-independent), and a numerical method that incorporates a pressure-dependent permeability. Analysis focuses on different levels of pressure draw down in a well located in the center of a homogeneous reservoir considering two types of flow field geometries: radial and linear. Two different producing control modes for the producer well are considered: constant rate and constant bottom hole pressure. Methodology consists of simulated tight gas well production with k(p) included. Then, we analyze results as though k(p) effects were ignored and finally, observe errors in determining permeability (k) and skin factor (s). Additionally, we calculate pore volume and OGIP in the reservoir. Analysis demonstrates that incorporation of pressure-dependence of permeability k(p) is critical in order to avoid inference of erroneous values of permeability, skin factor and OGIP from well test analysis of tight gas reservoirs. Estimation of these parameters depends on draw down in the reservoir. The great impact of permeability, skin factor and OGIP calculations are useful in business decisions and profitability for the oil company. Miscalculation of permeability and skin factor can lead to wrong decisions regarding well stimulation, which reduces well profitability. In most cases the OGIP calculated is underestimated. Calculated values are lower than the correct value. It can be taken as an advantage if we consider that additional gas wells and reserves would be incorporated in the exploitation plan.

Knowledge of reservoir porosity, permeability, and capillary pressure is essential to exploration and production of hydrocarbons. Although porosity can be interpreted fairly accurately from well logs, permeability and capillary pressure must be measured from core. Estimating permeability and capillary pressure from well logs would be valuable where cores are unavailable. This study is to correlate permeability with porosity to predict permeability and capillary pressures. Relationships between permeability to porosity can be complicated by diagenetic processes like compaction, cementation, dissolution, and occurrence of clay minerals. These diagenetic alterations can reduce total porosity, and more importantly, reduce effective porosity available for fluid flow. To better predict permeability, effective porosity needs to be estimated. A general equation is proposed to estimate effective porosity. Permeability is predicted from effective porosity by empirical and theoretical equations. A new capillary pressure model is proposed. It is based on previous study, and largely empirical. It is tested with over 200 samples covering a wide range of lithology (clean sandstone, shaly sandstone, and carbonates dominated by intergranular pores). Parameters in this model include: interfacial tension, contact angle, shape factor, porosity, permeability, irreducible water saturation, and displacement pressure. These parameters can be measured from routine core analysis, estimated from well log, and assumed. An empirical equation is proposed to calculate displacement pressure from porosity and permeability. The new capillary-pressure model is applied to evaluate sealing capacity of seals, calculate transition zone thickness and saturation above free water level in reservoirs. Good results are achieved through integration of well log data, production data, core, and geological concepts.

When the reservoir pressure is decreased below dew point pressure of the gas near the wellbore, gas-condensate wells start to decrease production because condensate is separated from the gas around the wellbore causing a decrease in gas relative permeability. This effect is more dramatic if the permeability of the reservoir is low. The idea proposed for reducing this problem is to eliminate the irreducible water saturation near the wellbore to leave more space for the gas to flow and therefore increase the productivity of the well. In this research a simulation study was performed to determine the range of permeabilities where the cylinder of condensate will seriously affect the well’s productivity, and the distance the removal of water around the wellbore has to be extended in order to have acceleration of production and an increase in the final reserves. A compositional-radial reservoir was simulated with one well in the center of 109 grids. Three gas-condensate fluids with different heptanes plus compositions ( 4, 8 and 11 mole %), and two irreducible water saturations were used. The fitting of the Equation of State (EOS) was performed using the method proposed by Aguilar and McCain. Several simulations were performed with several permeabilities to determine the permeabilities for which the productivity is not affected by the presence of the cylinder of condensate. At constant permeability, various radii of a region of zero initial water saturation around the wellbore were simulated and comparisons of the effects of removal of irreducible water on productivity were made. Reservoirs with permeabilities lower than 100 mD showed a reduction in the ultimate reserves due to the cylinder of condensate. The optimal radius of water removal depends on the fluid composition and the irreducible water saturation of the reservoir. The expected increase in reserves due to water removal varies from 10 to 80 % for gas production and from 4 to 30% for condensate production.

A systematic study of how mudstone permeability impacts reservoir pore pressure is important to understand the regional fluid field within sedimentary basins and the control of sediment properties on subsurface pressure. I develop a 2D static model to predict reservoir overpressure from information estimated from the bounding mudstones and structural relief. This model shows that close to a dipping reservoir, the mudstone permeability is high in the up-dip location and low in the down-dip location. This characteristic mudstone permeability variation causes the depth where reservoir pressure equals mudstone pressure (equal pressure depth) to be shallower than the mid-point of the reservoir structure. Based on the 2D static model, I constructed a nomogram to determine the equal pressure depth by considering both farfield mudstone vertical effective stress and reservoir structural relief. I find the equal pressure depth becomes shallower with decreasing vertical effective stress, increasing reservoir structural relief, and increasing mudstone compressibility. Pressure predicted by the static model agrees with pressure predicted by a more complete model that simulates the evolution of the basin and is supported by field observations in the Bullwinkle Basin (Green Canyon 65, Gulf of Mexico). This study can be applied to reduce drilling risk, analyze trap integrity, and facilitate safe and efficient exploration. / text