Thesis (Ph. D.)--West Virginia University, 2010. / Title from document title page. Document formatted into pages; contains xii, 140 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 99-104).

Gas production from low-permeability (tight) gas sandstones is increasingly important in the USA as conventional gas reservoirs are being depleted, and its importance will increase worldwide in future decades. Travis Peak tight sandstones have produced gas since the 1940s. In this study, well log, 2D seismic, core, and production data were used to evaluate the geologic setting and reservoir characteristics of the Travis Peak formation. The primary objective was to assess the potential for basinward extension of Travis Peak gas production along the west margin of the East Texas Basin. Along the west margin of the East Texas Basin, southeast-trending Travis Peak sandstones belts were deposited by the Ancestral Red River fluvial-deltaic system. The sandstones are fine-grained, moderately well sorted, subangular to subrounded, quartz arenites and subarkoses; reservoir quality decreases with depth, primarily due to diagenetic quartz overgrowths. Evaluation of drilling mud densities suggests that strata deeper than 12,500 ft may be overpressured. Assessment of the geothermal gradient (1.6 °F/100 ft) indicates that overpressure may be relict, resulting from hydrocarbon generation by Smackover and Bossier formation potential source rocks. In the study area, Travis Peak cumulative gas production was 1.43 trillion cubic feet from January 1, 1961, through December 31, 2005. Mean daily gas production from 923 wells was 925,000 cubic ft/well/day, during the best year of production. The number of Travis Peak gas wells in “high-cost” (tight sandstone) fields increased from 18 in the decade 1966-75 to 333 in the decade 1996-2005, when high-cost fields accounted for 33.2% of the Travis Peak gas production. However, 2005 gas production from high cost fields accounted for 63.2% of the Travis Peak total production, indicating that production from high-cost gas wells has increased markedly. Along the west margin of the East Texas Basin, hydrocarbon occurs in structural, stratigraphic, and combination traps associated with salt deformation. Downdip extension of Travis Peak production will depend on the (1) burial history and diagenesis, (2) reservoir sedimentary facies, and (3) structural setting. Potential Travis Peak hydrocarbon plays include: updip pinch-outs of sandstones; sandstone pinch-outs at margins of salt-withdrawal basins; domal traps above salt structures; and deepwater sands.

Shale gas reservoirs have become a major source of energy in recent years. Developments in hydraulic fracturing technology have made these reservoirs more accessible and productive. Apart from other dissimilarities from conventional gas reservoirs, one major difference is that a considerable amount of gas produced from these reservoirs comes from desorption. Ignoring a major component of production, such as desorption, could result in significant errors in analysis of these wells. Therefore it is important to understand the adsorption phenomenon and to include its effect in order to avoid erroneous analysis. The objective of this work was to imbed the adsorbed gas in the techniques used previously for the analysis of tight gas reservoirs. Most of the desorption from shale gas reservoirs takes place in later time when there is considerable depletion of free gas and the well is undergoing boundary dominated flow (BDF). For that matter BDF methods, to estimate original gas in place (OGIP), that are presented in previous literature are reviewed to include adsorbed gas in them. More over end of the transient time data can also be used to estimate OGIP. Kings modified z* and Bumb and McKee’s adsorption compressibility factor for adsorbed gas are used in this work to include adsorption in the BDF and end of transient time methods. Employing a mass balance, including adsorbed gas, and the productivity index equation for BDF, a procedure is presented to analyze the decline trend when adsorbed gas is included. This procedure was programmed in EXCEL VBA named as shale gas PSS with adsorption (SGPA). SGPA is used for field data analysis to show the contribution of adsorbed gas during the life of the well and to apply the BDF methods to estimate OGIP with and without adsorbed gas. The estimated OGIP’s were than used to forecast future performance of wells with and without adsorption. OGIP estimation methods when applied on field data from selected wells showed that inclusion of adsorbed gas resulted in approximately 30 percent increase in OGIP estimates and 17 percent decrease in recovery factor (RF) estimates. This work also demonstrates that including adsorbed gas results in approximately 5percent less stimulated reservoir volume estimate.

The ever increasing energy demand brings about widespread interest to rapidly, profitably and efficiently develop unconventional resources, among which tight gas sands hold a significant portion. However, optimization of development strategies in tight gas fields is challenging, not only because of the wide range of depositional environments and large variability in reservoir properties, but also because the evaluation often has to deal with a multitude of wells, limited reservoir information, and time and budget constraints. Unfortunately, classical full-scale reservoir evaluation cannot be routinely employed by small- to medium-sized operators, given its timeconsuming and expensive nature. In addition, the full-scale evaluation is generally built on deterministic principles and produces a single realization of the reservoir, despite the significant uncertainty faced by operators. This work addresses the need for rapid and cost-efficient technologies to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs. To achieve the research objectives, an integrated reservoir and decision modeling tool that fully incorporates uncertainty was developed. Monte Carlo simulation was used with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results were then fit with decline curves to enable direct integration of the reservoir model into a Bayesian decision model. These integrated tools were applied to the tight gas assets of Unconventional Gas Resources Inc. in the Berland River area, Alberta, Canada.

With the rapidly increasing demand for energy and the increasing prices for oil and gas, the role of unconventional gas reservoirs (UGRs) as energy sources is becoming more important throughout the world. Because of high risks and uncertainties associated with UGRs, their profitable development requires experts to be involved in the most critical development stages, such as drilling, completion, stimulation, and production. However, many companies operating UGRs lack this expertise. The advisory system we developed will help them make efficient decisions by providing insight from analogous basins that can be applied to the wells drilled in target basins. In North America, UGRs have been in development for more than 50 years. The petroleum literature has thousands of papers describing best practices in management of these resources. If we can define the characteristics of the target basin anywhere in the world and find an analogous basin in North America, we should be able to study the best practices in the analogous basin or formation and provide the best practices to the operators. In this research, we have built an advisory system that we call the Unconventional Gas Reservoir (UGR) Advisor. UGR Advisor incorporates three major modules: BASIN, PRISE and Drilling & Completion (D&C) Advisor. BASIN is used to identify the reference basin and formations in North America that are the best analogs to the target basin or formation. With these data, PRISE is used to estimate the technically recoverable gas volume in the target basin. Finally, by analogy with data from the reference formation, we use D&C Advisor to find the best practice for drilling and producing the target reservoir. To create this module, we reviewed the literature and interviewed experts to gather the information required to determine best completion and stimulation practices as a function of reservoir properties. We used these best practices to build decision trees that allow the user to take an elementary data set and end up with a decision that honors the best practices. From the decision trees, we developed simple computer algorithms that streamline the process.

The growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure. / text

Thesis (M.S.)--West Virginia University, 2000. / Title from document title page. Document formatted into pages; contains ix, 176 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 64-65).

In the recent years, the shale gas discourse has become central to discussions about future energy supply in South Africa. In particular, the Permian black shales of the Lower Ecca Group formations in the Karoo Basin are considered potential source rocks for shale gas. The research presented in this thesis advances the understanding of the shale gas potential of mainly the Prince Albert, Whitehill and Tierberg/Collingham Formations. These shale sequences were sampled from eight deep boreholes spread across the main Karoo Basin and geochemically analysed at the GFZ - Helmholtz Centre Potsdam, Germany. Three key questions guided the study, these are: (i) what is the lithology of the sequence; (ii) where in the basin do the shale sequences attain maximum thickness at optimum depth i.e. beneath 1000-1500m; and (iii) and their shale characteristics. To evaluate these, borehole core logging, petrology and organic geochemistry were used extensively. Petrology involved the use of thin section, scanned electron and transmission electron microscopy for mineralogy as well as the identification of sedimentary features, organic matter and nano-scale porosity. These were coupled with standard organic geochemistry techniques such as Rock Eval. analysis, open pyrolysis gas chromatography and thermovaporisation to quantify the free gas, total organic carbon (TOC), present-day gas generative potential and kerogen type. The results show that the Whitehill Formation, away from the CFB and not intruded by dolerite, has the most potential for shale gas. Microscopic studies of this pyritic black shale reveal the occurrence of porous amorphous matter, indicating thermal maturity within the gas generation zone (i.e. > 1.1 percent Ro, 120ºC). The TOC content is consistently high within the Whitehill (exceeding industry requirement of 2 percent), attaining maximum of 7.3 percent. The highest yields of free and desorbed gas, especially methane, were emitted within this formation (S1 and nC1 peaks); mostly within its dolomitic units. In addition, dissolution porosity within dolomite units of the Whitehill Formation was identified as the predominant type of porosity. Thus, it is deduced that the dolomitic units of Whitehill Formation potentially contain the greatest volumes of free gas. HI values attain maximum of 25 mg HC/g TOC, whereas the OI values 26 mg CO2/g TOC. Such low HI and OI values are typically attributed to the dominance of Type IV kerogen, and consistent with overmaturity. Open pyrolysis (GC) show the main the chemical compound of the organic matter to be m-p-xylene, consistent with a mix of Type III, Type I/II and Type IV kerogen. Lithologically, the Whitehill Formation is composed of ~ 35 quartz, 13 percent feldspar, 26 percent illite and ~ 23 percent dolomite with variable amounts of pyrite. The dominance of quartz is directly proportional to the brittleness of the rock. Thus it can be deduced that the Whitehill Formation is relatively brittle and therefore fraccable. Burial trends indicate increasing depth (from ground level) to the top of the Whitehill Formation towards the south and south-eastern portion of the basin. It is in the southern region where thicknesses of this black shale exceeding 50m occur at depths more than 1500m; 1000m beneath fresh water aquifers. It therefore concluded that Whitehill Formation in the southern portion of Karoo Basin, but away from the thermo-tectonic overprint of the Cape Orogeny, is the most probable shale gas reservoir in South Africa.

Submitted by Maria Cristina (library@lncc.br) on 2017-08-10T14:46:54Z No. of bitstreams: 1 tese_AlineRocha_2017.pdf: 17879231 bytes, checksum: 4f4051ece6ff4381064ab5338f79624d (MD5) / Approved for entry into archive by Maria Cristina (library@lncc.br) on 2017-08-10T14:47:10Z (GMT) No. of bitstreams: 1 tese_AlineRocha_2017.pdf: 17879231 bytes, checksum: 4f4051ece6ff4381064ab5338f79624d (MD5) / Made available in DSpace on 2017-08-10T14:47:21Z (GMT). No. of bitstreams: 1 tese_AlineRocha_2017.pdf: 17879231 bytes, checksum: 4f4051ece6ff4381064ab5338f79624d (MD5) Previous issue date: 2017-03-20 / Conselho Nacional de Desenvolvimento Científico e Tecnológico (CNPq) / In this work we construct a new multiscale computational model to describe the flow of gases in unconventional reservoirs (shale gas) containing distinct levels of fractures (natural and hydraulic). Such reservoirs exhibit peculiar characteristics that make an accurate description of the physical phenomenon involved a hard task. Among the characteristics we can highlight the low permeability (order of nanodarcys) and the multiple levels of porosity related to the multiple scales involved. In the present work the multiscale modeling of the gas flow is built with the formal homogenization procedure. The geological formation is characterized by four distinct length scales. The finest one, the nanoscopic, is related to the nanopores in the organic matter (kerogen) where gas is adsorbed. In order to accurately describe the gas adsorption in kerogen we pursue in the context of the Thermodynamics of Inhomogeneous Fluids. More precisely, the isotherms that describe the gas adsorption in nanopores are built based on the Density Functional Theory (DFT). The upscaling to the microscale is reached through the homogenization procedure. The window of observation related to this scale is composed of kerogen aggregates and inorganic matter (clay, quartz, calcite). Such phases are separated by the network of interparticle pores exibting characteristic length between 10^{-4} and 10^{-9} meters. The micropores are partially-saturated, filled with a free gas phase in thermodynamic equilibrium with the dissolved gas in the aqueous phase. The model considers immobile water phase with the equation of fickian diffusion of the dissolved gas coupled to the Darcyan flow of the free gas. At the mesoscale the shale matrix (where interparticle pores, kerogen aggregates and inorganic matter are envisioned as an homogenized media) is intertwined by the network of natural fractures exhibiting preferred paths for the flow of gas. The upscaling of this coupled system of partial differential equations gives rise to a macroscopic model of double porosity in the sense of Arbogast and coworkers (ARBOGAST; DOUGLAS JR.; HORNUNG, 1990). Within this context the shale matrix behaves as a microstructural distributed mass source term in the mass balance equation that describes the gas movement in the homogenized network of natural fractures. Finally we establish the coupling between the hydrodynamics in the networks of natural and hydraulic fractures, where single phase gas flow takes place. Such coupling is accomplished by reduced dimension techniques where induced fractures are treated as (n-1), n = 2,3 lower dimensional geological objects. The resulting model is composed of three partial differential nonlinear equations governing the gas hydrodynamics in the shale matrix and networks of natural and hydraulic fractures. In order to decouple the system we proceed within the context proposed by Arbogast (ARBOGAST,1997) which adopts a variable decomposition leading to the numerical solution of independent subsystems. This strategy allows the solution of the system mentioned above to be made in a sequential form avoiding additional iterations between the subsystems. The resultant governing equations are discretized by the finite element method with the introduction of submeshes to threat the gas transport in shale matrix and compute the source term in the pressure equation of the natural fractures network. The discretized model is used to simulate gas production as well as transient well tests. Promising numerical results are obtained which can be used to improve the description of the involved phenomena giving rise to new diagnostic curves to the characterization of unconventional reservoirs. / Neste trabalho propomos um novo modelo computacional multiescala para descrever o transporte de gases em reservatórios não convencionais (shale gas) com distintos níveis de fraturas (naturais e hidráulicas). Tais reservatórios apresentam características bastante peculiares que tornam a descrição acurada dos fenômenos físicos envolvidos uma tarefa árdua. Dentre estas características podemos ressaltar a baixíssima permeabilidade (da ordem de nanodarcys) e os múltiplos níveis de porosidade associados às múltiplas escalas envolvidas. No presente trabalho a modelagem multiescala do transporte do gás metano é construída fazendo uso do processo formal de homogeneização. O modelo considera o reservatório descrito por quatro escalas espaciais distintas. A escala mais fina, nanoscópica, é associada aos nanoporos na matéria orgânica (querogênio) onde o gás encontra-se adsorvido. Para descrever precisamente a adsorção do gás no querogênio fazemos uso da Termodinâmica de Gases Confinados. Mais precisamente, as isotermas de adsorção do gás nos nanoporos são construídas fazendo uso da Density Functional Theory (DFT). Através do processo de homogeneização é realizado o upscaling para a escala intermediária (microscópica). A janela observacional associada a esta escala consiste dos agregados de querogênio juntamente com a matéria inorgânica (considerada impermeável) e rede de microporos que podem exibir tamanhos entre 10^{-4} a 10^{-9} metros. Consideramos estes, por sua vez, parcialmente saturados preenchidos por uma fase gás livre em equilíbrio termodinâmico local com o gás dissolvido na fase aquosa. O modelo considera a água estagnada com a equação de difusão fickiana do gás dissolvido acoplada ao escoamento do gás livre. Na mesoescala a matriz do folhelho (na qual microporos, agregados de querogênio e matéria inorgânica são tratados como um meio contínuo homogeneizado) é permeada por uma rede de fraturas naturais que exibem caminhos preferenciais para o movimento do gás. O processo do upscaling deste sistema acoplado de equações diferenciais parciais dá origem a um modelo macroscópico de porosidade dupla no sentido de Arbogast e colaboradores (ARBOGAST; DOUGLAS JR.; HORNUNG, 1990). Neste contexto, a matriz atua como uma fonte de massa distribuída microestruturalmente no balanço de massa que descreve o movimento do gás na rede de fraturas naturais. Finalmente estabelecemos o acoplamento entre as hidrodinâmicas nas redes de fraturas naturais e hidráulicas, onde ocorre o escoamento monofásico do gás livre. Tal acoplamento é realizado via técnica de redução de dimensão onde as fraturas hidráulicas são tratadas como objetos geológicos de dimensão reduzida (n-1), n=2,3. O modelo resultante é composto por três equações diferenciais parciais não lineares acopladas que governam a hidrodinâmica do gás na matriz e redes de fraturas naturais e hidráulicas. Com o intuito de desacoplar o sistema procedemos no contexto proposto por Arbogast (ARBOGAST,1997) que consiste em utilizar uma decomposição das variáveis resultando em subsistemas independentes a serem resolvidos numericamente. Esta escolha permite que o sistema supracitado seja resolvido de forma sequencial evitando a necessidade de iterações adicionais entre os subsistemas. Na discretização espacial adotamos o método de elementos finitos com a introdução de submalhas para tratar o transporte do gás na matriz e assim efetuar de forma precisa o cálculo do termo de fonte na equação da pressão do gás na rede de fraturas naturais. O modelo discreto é utilizado para o cômputo da produção de gás bem como para simular testes transientes de pressão em poços. Resultados numéricos promissores são obtidos os quais podem ser empregados para aprimorar a descrição dos fenômenos envolvidos e dar origem a novas curvas de diagnóstico para caracterização de propriedades de reservatórios não convencionais.

Improving methods of hydrocarbon production and developing new techniques for the creation of natural gas storage facilities are critically important for the petroleum industry. This dissertation focuses on two key topics: (1) mechanisms of sand production from petroleum reservoirs and (2) mechanical characterization of caverns created in carbonate rock formations for natural gas storage. Sand production is the migration of solid particles together with the hydrocarbons when extracted from petroleum reservoirs. It usually occurs from wells in sandstone formations that fail in response to stress changes caused by hydrocarbon withdrawal. Sand production is generally undesirable since it causes a variety of problems ranging from significant safety risks during high-rate gas production, to the erosion of downhole equipment and surface facilities. It is widely accepted that a better understanding of the mechanics of poorly-consolidated formations is required to manage sand production; which, in turn, enables the cost effective production of gas and oil resources. In this work, a series of large-scale laboratory experiments was conducted in fully saturated, cohesionless sand layers to model the behavior of a petroleum reservoir near a wellbore. We directly observed several key characteristics of the sand production phenomenon including the formations of a stable cavity around the wellbore and a sub-radial flow channel at the upper surface of the tested layer. The flow channel is a first-order feature that appears to be a major part of the sand production mechanism. The channel cross section is orders of magnitude larger than the particle size, and once formed, the channel becomes the dominant conduit for fluid flow and particle transport. The flow channel developed in all of our experiments, and in all experiments, sand production continued from the developing channel after the cavity around the borehole stabilized. Our laboratory results constitute a well constrained data set that can be used to test and calibrate numerical models employed by the petroleum industry for predicting the sand production phenomenon. Although important for practical applications, real field cases are typically much less constrained. We used scaling considerations to develop a simple analytical model, constrained by our experimental results. We also simulated the behavior of a sand layer around a wellbore using two- and three-dimensional discrete element methods. It appears that the main sand production features observed in the laboratory experiments, can indeed be reproduced by means of discrete element modeling. Numerical results indicate that the cavity surface of repose is a key factor in the sand production mechanism. In particular, the sand particles on this surface are not significantly constrained. This lack of confinement reduces the flow velocity required to remove a particle, by many orders of magnitude. Also, the mechanism of channel development in the upper fraction of the sample can be attributed to subsidence of the formation due to lateral extension when an unconstrained cavity slope appears near the wellbore. This is substantiated by the erosion process and continued production of particles from the flow channel. The notion of the existence of this surface channel has the potential to scale up to natural reservoirs and can give insights into real-world sand production issues. It indicates a mechanism explaining why the production of particles does not cease in many petroleum reservoirs. Although the radial character of the fluid flow eventually stops sand production from the cavity near the wellbore, the production of particles still may continue from the propagating surface (interface) flow channel. The second topic of the thesis addresses factors affecting the geometry and, hence, the mechanical stability of caverns excavated in carbonate rock formations for natural gas storage. Storage facilities are required to store gas when supply exceeds demand during the winter months. In many places (such as New England or the Great Lakes region) where no salt domes are available to create gas storage caverns, it is possible to create cavities in limestone employing the acid injection method. In this method, carbonate rock is dissolved, while CO₂ and calcium chloride brine appear as products of the carbonate dissolution reactions. Driven by the density difference, CO₂ rises towards the ceiling whereas the brine sinks to the bottom of the cavern. A zone of mixed CO₂ , acid, and brine forms near the source of acid injection, whereas the brine sinks to the bottom of the cavern. Characterization of the cavern shape is required to understand stress changes during the cavity excavation, which can destabilize the cavern. It is also important to determine the location of the mixture-brine interface to select the place of acid injection. In this work, we propose to characterize the geometry of the cavern and the location of the mixture-brine interface by generating pressure waves in a pipe extending into the cavern, and measuring the reflected waves at various locations in another adjacent pipe. Conventional governing equations describe fluid transients in pipes loaded only by internal pressure (such as in the water hammer effect). To model the pressure wave propagation for realistic geometries, we derived new governing equations for pressure transients in pipes subjected to changes in both internal and external (confining) pressures. This is important because the internal pressure (used in the measurement) is changing in response to the perturbation of the external pressure when the pipe is contained in the cavern filled with fluids. If the pressure in the cavern is perturbed, the perturbation creates an internal pressure wave in the submerged pipe that has a signature of the cavern geometry. We showed that the classic equations are included in our formulation as a particular case, but they have limited validity for some practically important combinations of the controlling parameters. We linearized the governing equations and formulated appropriate boundary and initial conditions. Using a finite element method, we solved the obtained boundary value problem for a system of pipes and a cavern filled with various characteristic fluids such as aqueous acid, calcium chloride brine, and supercritical CO₂ . We found that the pressure waves of moderate amplitudes would create measurable pressure pulses in the submerged pipe. Furthermore, we determined the wavelengths required for resolving the cavern diameter from the pressure history. Our results suggest that the pressure transients technique can indeed be used for characterizing the geometry of gas storage caverns and locations of fluid interfaces in the acid injection method.