The proposed work provides a new definition of the pressure derivative function [that is the β-derivative function, Δp βd(t)], which is defined as the derivative of the logarithm of pressure drop data with respect to the logarithm of time This formulation is based on the "power-law" concept. This is not a trivial definition, but rather a definition that provides a unique characterization of "power-law" flow regimes which are uniquely defined by the Δp βd(t) function [that is a constant Δp βd(t) behavior]. The Δp βd(t) function represents a new application of the traditional pressure derivative function, the "power-law" differentiation method (that is computing the dln(Δp)/dln(t) derivative) provides an accurate and consistent mechanism for computing the primary pressure derivative (that is the Cartesian derivative, dΔp/dt) as well as the "Bourdet" well testing derivative [that is the "semilog" derivative, Δpd(t)=dΔp/dln(t)]. The Cartesian and semilog derivatives can be extracted directly from the power-law derivative (and vice-versa) using the definition given above.

Shale gas has become increasingly important to United States energy supply. During recent decades, the mechanisms of shale gas storage and transport were gradually recognized. Gas desorption was also realized and quantitatively described. Models and approaches special for estimating rate decline and recovery of shale gas wells were developed. As the strategy of the horizontal well with multiple transverse fractures (MTFHW) was discovered and its significance to economic shale gas production was understood, rate decline and pressure transient analysis models for this type of well were developed to reveal the well behavior. In this thesis, we considered a “Triple-porosity/Dual-permeability” model and performed sensitivity studies to understand long term pressure drawdown behavior of MTFHWs. A key observation from this study is that the early linear flow regime before interfracture interference gives a relationship between summed fracture half-length and permeability, from which we can estimate either when the other is known. We studied the impact of gas desorption on the time when the pressure perturbation caused by production from adjacent transference fractures (fracture interference time) and programmed an empirical method to calculate a time shift that can be used to qualify the gas desorption impact on long term production behavior. We focused on the field case Well A in New Albany Shale. We estimated the EUR for 33 wells, including Well A, using an existing analysis approach. We applied a unified BU-RNP method to process the one-year production/pressure transient data and performed PTA to the resulting virtual constant-rate pressure drawdown. Production analysis was performed meanwhile. Diagnosis plots for PTA and RNP analysis revealed that only the early linear flow regime was visible in the data, and permeability was estimated both from a model match and from the relationship between fracture halflength and permeability. Considering gas desorption, the fracture interference will occur only after several centuries. Based on this result, we recommend a well design strategy to increase the gas recovery factor by decreasing the facture spacing. The higher EUR of Well A compared to the vertical wells encourages drilling more MTFHWs in New Albany Shale.

A sudden change in flow in a confined system results in the formation of a series of pressure pulses known as a water hammer. Pump shutdown at the conclusion of a hydraulic fracture treatment frequently generates a water hammer, which sends a pressure pulse down the wellbore that interacts with the created fracture before returning towards the surface. This study confirms that created hydraulic fractures alter the period, amplitude, and duration of the water hammer signal. Water hammer pressure signals were simulated with a previously presented numerical model that combined the continuity and momentum equations of the wellbore with a created hydraulic fracture represented by a RCI series circuit. Field data from several multi-stage stimulation treatments were history matched with the numerical model by iteratively altering R, C, and I until an appropriate match was obtained. Equivalent fracture dimensions were calculated from R, C, and I, and were in agreement with acquired micro-seismic SRV. Finally, the obtained R, C, and I values were compared to SRV and production log data. Capacitance was directly correlated with SRV, while resistance was inversely correlated with SRV, and no correlations with production data were observed. / text

In practice today, pressure transient analysis (PTA) and production data analysis (PDA) are done separately and differently by different interpreters in different companies using different analysis techniques, different interpreter-dependent inputs, on pressure and production rate data from the same well, with different software packages. This has led to different analyses outputs and characterizations of the same reservoir. To avoid inconsistent results from different interpretations, this study presents a new way to integrate PTA and PDA on a single diagnostic plot to account for and see the early time and mid-time responses (from the transient tests) and late time (boundary affected/PSS) responses achievable with production analysis, on the same plot; thereby unifying short and long-term analyses and improving the reservoir characterization. The rate normalized pressure (RNP) technique was combined with conventional pressure buildup PTA technique. Data processing algorithms were formulated to improve plot presentation and a stepwise analysis procedure is presented to apply the new technique. The new technique is simple to use and the same conventional interpretation techniques as PTA apply. We have applied the technique to a simulated well case and two field cases. Finally, this new technique represents improvements over previous PDA methods and can help give a long term dynamic description of the well’s drainage area.

With the increase in energy consumption, new oil and gas extraction methods in unconventional resources have been explored. Hydraulic fracturing creates fractures to produce and make low permeability reservoirs economically profitable. Hydraulic fractures are also caused unintentionally by the uncontrolled injection in secondary recovery projects or CO2 geological storage. During proppant placement and CO2 injection, the permeability is reduced near the wellbore region due to pore clogging and mineral precipitation. The generated fractures act as high conductivity conduits that increase the capacity of flow in the reservoir. The fracture conductivity is strictly related to its geometry and hydraulic properties. However, these tend to degrade as pressure decreases. The current models do not consider fracture width change in the diffusivity inside the fracture. Additionally, the effect of fracture face skin in fracture closure has not been incorporated. This work focuses on the identification of fracture closure in fractured wells using Pressure Transient data. A semi-analytical model was developed for including the effects of fracture closure, fracture face skin, and complex fracture geometries. The matrix and fracture systems are coupled by pressure continuity at the interface. Fracture face skin is added, assuming a thin layer surrounding the fracture. The model is solved in Laplace space using a semi-analytical approach. The results are validated using a commercial simulator (CMG) and previous models. The pressure response in fractured wells with stress-sensitive fractures is analyzed at early, middle, and late times. In each time period, we identify pressure signals to detect fracture closure by incorporating effective fracture compressibility and fracture conductivity reduction. By incorporating the effective fracture compressibility, the model can reproduce a high storage capacity fracture signal. This signal occurs at early times and can help in post-fracture analysis. The fracture face skin creates an additional pressure drop in the fracture system, triggering conductivity reduction earlier than an undamaged fracture. We proposed a semi-log approach to identify fracture closure for slow rates of fracture closure and the pseudo-radial simplification to generate late time response curves instead of the complete solution for the model.

Reservoir testing and analysis are fundamental tools in understanding reservoir hydraulics and hence forecasting reservoir responses. The quality of the analysis is very dependent on the conceptual model used in investigating the responses under different flowing conditions. The use of reservoir testing in the characterization and derivation of reservoir parameters is widely established, especially in conventional oil and gas reservoirs. However, with depleting conventional reserves, the quest for unconventional reservoirs to secure the increasing demand for energy is increasing; which has triggered intensive research in the fields of reservoir characterization. Gas hydrate reservoirs, being one of the unconventional gas reservoirs with huge energy potential, is still in the juvenile stage with reservoir testing as compared to the other unconventional reservoirs. The endothermic dissociation hydrates to gas and water requires addressing multiphase flow and heat energy balance, which has made efforts to develop reservoir testing models in this field difficult. As of now, analytically quantifying the effect on hydrate dissociation on rate and pressure transient responses are till date a huge challenge. During depressurization, the heat energy stored in the reservoir is used up and due to the endothermic nature of the dissociation; heat flux begins from the confining layers. For Class 3 gas hydrates, just heat conduction would be responsible for the heat influx and further hydrate dissociation; however, the moving boundary problem could also be an issue to address in this reservoir, depending on the equilibrium pressure. To address heat flux problem, a proper definition of the inner boundary condition for temperature propagation using a Clausius-Clapeyron type hydrate equilibrium model is required. In Class 1 and 2, crossflow problems would occur and depending on the layer of production, convective heat influx from the free fluid layer and heat conduction from the cap rock of the hydrate layer would be further issues to address. All these phenomena make the derivation of a suitable reservoir testing model very complex. However, with a strong combination of heat energy and mass balance techniques, a representative diffusivity equation can be derived. Reservoir testing models have been developed and responses investigated for different boundary conditions in normally pressured Class 3 gas hydrates, over-pressured Class 3 gas hydrates (moving boundary problem) and Class 1 and 2 gas hydrates (crossflow problem). The effects of heat flux on the reservoir responses have been addressed in detail.

Reservoir testing and analysis are fundamental tools in understanding reservoir hydraulics and hence forecasting reservoir responses. The quality of the analysis is very dependent on the conceptual model used in investigating the responses under different flowing conditions. The use of reservoir testing in the characterization and derivation of reservoir parameters is widely established, especially in conventional oil and gas reservoirs. However, with depleting conventional reserves, the quest for unconventional reservoirs to secure the increasing demand for energy is increasing; which has triggered intensive research in the fields of reservoir characterization. Gas hydrate reservoirs, being one of the unconventional gas reservoirs with huge energy potential, is still in the juvenile stage with reservoir testing as compared to the other unconventional reservoirs. The endothermic dissociation hydrates to gas and water requires addressing multiphase flow and heat energy balance, which has made efforts to develop reservoir testing models in this field difficult. As of now, analytically quantifying the effect on hydrate dissociation on rate and pressure transient responses are till date a huge challenge. During depressurization, the heat energy stored in the reservoir is used up and due to the endothermic nature of the dissociation; heat flux begins from the confining layers. For Class 3 gas hydrates, just heat conduction would be responsible for the heat influx and further hydrate dissociation; however, the moving boundary problem could also be an issue to address in this reservoir, depending on the equilibrium pressure. To address heat flux problem, a proper definition of the inner boundary condition for temperature propagation using a Clausius-Clapeyron type hydrate equilibrium model is required. In Class 1 and 2, crossflow problems would occur and depending on the layer of production, convective heat influx from the free fluid layer and heat conduction from the cap rock of the hydrate layer would be further issues to address. All these phenomena make the derivation of a suitable reservoir testing model very complex. However, with a strong combination of heat energy and mass balance techniques, a representative diffusivity equation can be derived. Reservoir testing models have been developed and responses investigated for different boundary conditions in normally pressured Class 3 gas hydrates, over-pressured Class 3 gas hydrates (moving boundary problem) and Class 1 and 2 gas hydrates (crossflow problem). The effects of heat flux on the reservoir responses have been addressed in detail.

Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid. / text

[pt] Este trabalho apresenta um novo modelo térmico analítico que acopla poço e reservatório, constituído por um sistema combinado de reservatório, revestimento e coluna de produção. As soluções analíticas consideram fluxo monofásico de fluido pouco compressível em um reservatório homogêneo e infinito e fornecem dados transitórios de temperatura e pressão ao longo do poço para testes de fluxo e de crescimento de pressão, considerando efeitos Joule-Thomson, de expansão adiabática, de condução e convecção. A massa específica do fluido é modelada como função da temperatura e a solução analítica faz uso da transformada de Laplace para resolver a equação diferencial de fluxo de calor transiente, assumindo o termo aT⁄az totalmente transiente. Com relação à análise de transientes de pressão (PTA), dados de pressão impactados por variações térmicas podem levar à interpretação de falsas heterogeneidades geológicas, pois a perda de calor durante a estática proporciona um aumento da pressão exercida pela coluna de fluido, devido ao incremento de sua massa específica, além de uma contração da coluna de produção, provocando uma mudança na posição do registrador. Esses efeitos podem fazer com que um reservatório homogêneo seja erroneamente interpretado como um reservatório de dupla porosidade, resultando em conclusões inválidas para a modelagem geológica. Os resultados deste trabalho são comparados com a resposta de um simulador comercial não-isotérmico e impactos nas interpretações são extensivamente investigados. Adicionalmente, um estudo de caso de campo é fornecido para validar as soluções analíticas propostas. Comparado à Literatura, o modelo proposto fornece perfis transientes de temperatura mais acurados. / [en] This work presents a new coupled transient-wellbore/reservoir thermal analytical model, consisting of a reservoir/casing/tubing combined system. The analytical solutions consider flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system and provide temperature- and pressure-transient data for drawdown and buildup tests at any gauge location along the wellbore, accounting for Joule-Thomson, adiabatic fluid-expansion, conduction and convection effects. The wellbore fluid mass density is modeled as a function of temperature and the analytical solution makes use of the Laplace transformation to solve the transient heat-flow differential equation, accounting for a rigorous transient wellbore-temperature gradient aT⁄az. Regarding pressure transient analysis (PTA), thermal impacted pressure data may lead to the interpretation of false geological heterogeneities, since the heat loss during the buildup period provides an increase in the pressure exerted by the wellbore-fluid column, due to an increase in the oil mass density, and a change in tubing length, consequently causing a change in the gauge location. These effects can make a homogeneous reservoir be wrongly interpreted as a double-porosity reservoir, yielding invalid conclusions to geological modeling. Results are compared to the response of a commercial non-isothermal simulator and thermal impacts on PTA interpretations are thoroughly investigated. In addition, a field case study is also provided to verify the proposed analytical solutions. The proposed model provides more accurate transient temperature flow profiles along the wellbore when compared to previous models in Literature.

Made available in DSpace on 2015-03-03T13:59:44Z (GMT). No. of bitstreams: 1 GabriellJMA_DISSERT.pdf: 1371633 bytes, checksum: 92e16086f0ca63a45223381e044469ad (MD5) Previous issue date: 2012-03-05 / In February 2011, the National Agency of Petroleum, Natural Gas and Biofuels (ANP) has published a new Technical Rules for Handling Land Pipeline Petroleum and Natural Gas Derivatives (RTDT). Among other things, the RTDT made compulsory the use of monitoring systems and leak detection in all onshore pipelines in the country. This document provides a study on the method for detection of transient pressure. The study was conducted on a industrial duct 16" diameter and 9.8 km long. The pipeline is fully pressurized and carries a multiphase mixture of crude oil, water and natural gas. For the study, was built an infrastructure for data acquisition and validation of detection algorithms. The system was designed with SCADA architecture. Piezoresistive sensors were installed at the ends of the duct and Digital Signal Processors (DSPs) were used for sampling, storage and processing of data. The study was based on simulations of leaks through valves and search for patterns that characterize the occurrence of such phenomena / Em fevereiro de 2011, a Ag?ncia Nacional de Petr?leo, G?s Natural e Biocombust?veis (ANP) publicou o novo Regulamento Tecnico de Dutos Terrestres para Movimenta??o de Petr?leo, Derivados e Gas Natural (RTDT). Entre outros aspectos, o RTDT tornou obrigat?rio o emprego de sistemas de monitoramento e detec??o de vazamentos em todos os dutos terrestres do pa?s. Este documento traz um estudo sobre o m?todo de detec??o por transiente de press?o. O estudo foi realizado num duto industrial de 16" de di?metro e 9,8 Km de extens?o. O duto e totalmente pressurizado e transporta uma mistura multif?sica de ?leo bruto, ?gua e g?s natural. Para a realiza??o do estudo, foi constru?da uma infraestrutura de aquisi??o de dados e valida??o de algoritmos de detec??o. O sistema foi concebido com arquitetura SCADA. Sensores piezoresistivos foram instalados nas extremidades do duto e Processadores Digitais de Sinais (DSPs) foram usados para a amostragem, armazenamento e processamento dos dados. O estudo se baseou na realiza??o de simula??es de vazamentos por meio de valvulas e busca por padr?es que caracterizassem a ocorr?ncia de tais fen?menos