Scale formation is a problem in many processes that handle large volumes of water. The retention and release of phosphonates, as relates to their use in the squeeze procedure for the petroleum industry, were studied. A new method for measuring bicarbonate alkalinity in the presence of carboxylic acids was developed using a CO$\sb2$ evolution technique. Solubility and core flow-through experiments were used for phosphonate studies. Dissociation constants and solubility products for the aminomethyl and methyl phosphonic acids were determined at 70$\sp\circ$C. The effects of one, three and five phosphonate functional group(s) on the retention and the release of diethylenetriaminepenta(methylene phosphonic acid), aminotri(methylene phosphonic acid), aminomethylphosphonic acid, and methylphosphonic acid were examined. Amine functional group(s) have an effect on retention and release of the phosphonates. The retention of the amine phosphonates under acidic conditions is directly dependent on the number of phosphonate functional groups.

<p> The Spraberry Formation is a Leonardian age submarine fan deposit restricted to the Midland Basin. The formation consists of very fine-grained sandstone, medium to coarse grain size siltstones, organic shales and carbonate mudstones. These rocks show variability in sedimentary structures and bedding types varied from thinly laminated to convolute laminations. Bioturbations were present in some samples and soft sediment deformation, such as water escape features, sediment loading and flame structures. </p><p> The Spraberry Formation is a naturally fractured reservoir with low porosity and low matrix permeability. Porosity measured varied from 2% in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9%. Seven lithofacies were identified based on sedimentary structures, grain size and rock fabrics. Petrographic analysis showed four porosity types: (1) intragraular porosity; (2) dissolution porosity; (3) fracture porosity and (4) intergranular porosity. Fractured porosity was only observed in the argillaceous siltstone lithofacies. </p><p> The prominent diagenetic influences on the Spraberry Formation are: quartz cementation, quartz overgrowth, illtization of smectite, feldspar dissolution, clay precipitation, carbonate cementation, formation of framboidal pyrite and fracture formation. These diagenetic features were observed using scanning electron microscope (SEM) and in thin sections. Generally, petrophysical properties, such as porosity and permeability, vary gradually from reservoir rocks to non-reservoir rock. Observed trends where: 1) increasing organic and argillaceous content with decreasing porosity and 2) increasing carbonate sediments and calcite cements with decreasing porosity. Mineralogical analysis from FTIR showed an abundance of quartz and calcite, while illite is the prominent clay mineral observed in all samples.</p>

<p> Hydrocarbon recovery rates within the Niobrara Shale are estimated as low as 2&ndash;8%. These recovery rates are controlled by the ability to effectively hydraulic fracture stimulate the reservoir using multistage horizontal wells. Subsequent to any mechanical issues that affect production from lateral wells, the variability in production performance and reserve recovery along multistage lateral shale wells is controlled by the reservoir heterogeneity and its consequent effect on hydraulic fracture stimulation efficiency. Using identical stimulation designs on a number of wells that are as close as 600ft apart can yield variable production and recovery rates due to inefficiencies in hydraulic fracture stimulation that result from the variability in elastic rock properties and in-situ stress conditions. </p><p> As a means for examining the effect of the geological heterogeneity on hydraulic fracturing and production within the Niobrara Formation, a 3D geomechanical model is derived using geostatistical methods and volumetric calculations as an input to hydraulic fracture stimulation. The 3D geomechanical model incorporates the faults, lithological facies changes and lateral variation in reservoir properties and elastic rock properties that best represent the static reservoir conditions pre-hydraulic fracturing. Using a 3D numerical reservoir simulator, a hydraulic fracture predictive model is generated and calibrated to field diagnostic measurements (DFIT) and observations (microseismic and 4D/9C multicomponent time-lapse seismic). By incorporating the geological heterogeneity into the 3D hydraulic fracture simulation, a more representative response is generated that demonstrate the variability in hydraulic fracturing efficiency along the lateral wells that will inevitability influence production performance. </p><p> Based on the 3D hydraulic fracture simulation results, integrated with microseismic observations and 4D/9C time-lapse seismic analysis (post-hydraulic fracturing &amp; post production), the variability in production performance within the Niobrara Shale wells is shown to significantly be affected by the lateral variability in reservoir quality, well and stage positioning relative to the target interval, and the relative completion efficiency. The variation in reservoir properties, faults, rock strength parameters, and in-situ stress conditions are shown to influence and control the hydraulic fracturing geometry and stimulation efficiency resulting in complex and isolated induced fracture geometries to form within the reservoir. This consequently impacts the effective drainage areas, production performance and recovery rates from inefficiently stimulated horizontal wells. </p><p> The 3D simulation results coupled with the 4D seismic interpretations illustrate that there is still room for improvement to be made in optimizing well spacing and hydraulic fracturing efficiency within the Niobrara Formation. Integrated analysis show that the Niobrara reservoir is not uniformly stimulated. The vertical and lateral variability in rock properties control the hydraulic fracturing efficiency and geometry. Better production is also correlated to higher fracture conductivity. 4D seismic interpretation is also shown to be essential for the validation and calibration hydraulic fracture simulation models. The hydraulic fracture modeling also demonstrations that there is bypassed pay in the Niobrara B chalk resulting from initial Niobrara C chalk stimulation treatments. Forward modeling also shows that low pressure intervals within the Niobrara reservoir influence hydraulic fracturing and infill drilling during field development.</p><p>

<p> In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media. </p><p> Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs. </p><p>

Conservation of petroleum reserves in the United States, from a production point of view, becomes problematic even in the case of well-defined surface property rights. The migratory nature of those resources and the common law rule of capture have combined to create a classic example of the problem of the common pool. In the race to reduce their underlying hydrocarbon reserves to possession, holders of sub-surface mineral rights (which evolve from initial surface ownership) have been seen to exemplify the common pool situation; excessive spending to capture the resource and premature depletion of the resource base. Some economic theory and early empirical evidence indicate that the potential losses from overcapitalization toward drilling and premature reservoir depletion can be large in terms of both physical and economic waste in oil field development. / Given the premise that early fieldwide consolidation of a particular reservoir is the optimal solution to conserve the nonrenewable hydrocarbon natural resource, this paper identifies and quantifies the relationship between two separate methods to accomplish this objective--compulsory and voluntary unitization. By comparing the production and drilling activities of a state with a long history of successful and early governmentally sanctioned unitization (Louisiana) to a state with no such statutory requirement (Texas), we are able to discern differences in potential welfare loss between the two regimes. After controlling for geology, price, cost and other state-specific factors, we find that, over the period examined and contrary to the naive economic view that does not allow for private bargaining, more wells are drilled in Louisiana than in Texas and the difference between production rates of the two states is not statistically significant. / Source: Dissertation Abstracts International, Volume: 57-03, Section: A, page: 1240. / Major Professor: Philip E. Sorensen. / Thesis (Ph.D.)--The Florida State University, 1996.

acase@tulane.edu

Competitive reaction in intrazeolitic media is illustrated by the hydroisomerization of hexanes over Pt/Mordenite and Pt/Y, in the presence of an aromatic cofeed. The aromatic inhibits the paraffin reaction, changes the relative reactivities of the different hexane isomers and modifies isomer product distributions. Preferential adsorption by the aromatic modifies catalytic site distributions available for the paraffin reaction, and may also affect diffusional characteristics in the pores of the zeolite Concepts of bifunctional reaction mechanisms and carbenium ion theory are used to explain the mechanism of hexane isomerization and to establish the nature of the reaction network. Based on such mechanistic criteria, the isomer distribution in the presence of an aromatic is rationalized as a consequence of coreactant induced size and shape selectivity modifications to the catalyts The isomerization kinetics are modeled using reaction network analysis to obtain first order rate constants for each individual step of the reaction network. The results indicate that inhibition of the hexane reaction due to the presence of the aromatic affects every step in the reaction network. A generalized framework of transport and reaction in the pores of the zeolite is presented to justify the observed modifications to reaction rates and selectivities / acase@tulane.edu

Thesis (Ph. D.)--University of Texas at Austin, 1999. / Vita. Includes bibliographical references (leaves 237-240). Available also in a digital version from Dissertation Abstracts.

Thesis (Ph.D.)--Lehigh University, 2009. / Adviser: Israel E. Wachs.

Thesis (Ph. D.)--University of Texas at Austin, 2000. / Vita. Includes bibliographical references (leaves 152-158). Available also in a digital version from Dissertation Abstracts.