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Fracture abundance and strain in folded cardium formation, Alberta fold-and-thrust belt, CanadaOzkul, Canalp 02 February 2015 (has links)
The folded and thrusted Mesozoic clastic sequence of the Canadian Rocky Mountain foothills forms important hydrocarbon reservoirs. Understanding the distribution of natural fractures, their evolution, and timing of formation relative to the evolution of the fold-and-thrust system could potentially improve exploration and development outcomes in these otherwise tight unconventional reservoirs. However, the formation of fractures and their timing relative to folding and thrusting have remained unclear. I investigated the relation between folding and fracture formation in the Upper Cretaceous Cardium Sandstone by combining field structural observations and kinematic modeling of the fold-and-thrust belt evolution. I explored the relationship between fracture intensity and fracture strain with structural position by analyzing fracture spacing or frequency and aperture data collected along outcrop and micro-scanlines in the backlimb, in the forelimb close to the crest, and in the steeper dipping forelimb away from the crest of the Red Deer River anticline. Fracture frequency and aperture data collected both at the outcrop and micro scales indicate that variation in fracture strain is small across these three structural domains of the fold, with somewhat lower fracture intensity in the forelimb close to the crest. These fracture strain measurements are qualitatively consistent with calculated horizontal strain in the tectonic transport direction obtained through kinematic numerical models that simulate fold development associated with slip along the underlying Burnt Timber thrust. The models predict roughly similar amount of horizontal extension in both the back and forelimbs, and somewhat lower extension in the upper forelimb during early development of the Red Deer River anticline. Fracture formation early during fold development is consistent with the field structural observations of shear reactivation during later stages of folding. This combined kinematic modeling and field structural study demonstrates that deforming fold and thrust belts can undergo a complex evolution of bed-parallel extension in both space and time, resulting in spatially variable fracture formation in such structurally complex subsurface reservoirs. / text
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Modeling CO2 Sequestration and Enhanced Gas Recovery in Complex Unconventional ReservoirsVasilikou, Foteini 23 June 2014 (has links)
Geologic sequestration of CO2 into unmineable coal seams is proposed as a way to mitigate the greenhouse gas effect and potentially contribute to economic prosperity through enhanced methane recovery.
In 2009, the Virginia Center for Coal and Energy Research (VCCER) injected 907 tonnes of CO2 into one vertical coalbed methane well for one month in Russell County, Virginia (VA). The main objective of the test was to assess storage potential of coal seams and to investigate the potential of enhanced gas recovery. In 2014, a larger scale test is planned where 20,000 tonnes of CO2 will be injected into three vertical coalbed methane wells over a period of a year in Buchanan County, VA.
During primary coalbed methane production and enhanced production through CO2 injection, a series of complex physical and mechanical phenomena occur. The ability to represent the behavior of a coalbed reservoir as accurately as possible via computer simulations yields insight into the processes taking place and is an indispensable tool for the decision process of future operations. More specifically, the economic viability of projects can be assessed by predicting production: well performance can be maximized, drilling patterns can be optimized and, most importantly, associated risks with operations can be accounted for and possibly avoided.
However, developing representative computer models and successfully simulating reservoir production and injection regimes is challenging. A large number of input parameters are required, many of which are uncertain even if they are determined experimentally or via in-situ measurements. Such parameters include, but are not limited to, seam geometry, formation properties, production constraints, etc.
Modeling of production and injection in multi-seam formations for hydraulically fractured wells is a recent development in coalbed methane/enhanced coalbed methane (CBM/ECBM) reservoir modeling, where models become even more complex and demanding. In such cases model simulation times become important.
The development of accurate simulation models that correctly account for the behavior of coalbeds in primary and enhanced production is a process that requires attention to detail, data validation, and model verification. A number of simplifying assumptions are necessary to run these models, where the user should be able to balance accuracy with computational time.
In this thesis, pre- and post-injection simulations for the site in Russell County, VA, and preliminary reservoir simulations for the Buchanan County, VA, site are performed. The concepts of multi-well, multi-seam, explicitly modeled hydraulic fractures and skin factors are incorporated with field results to provide accurate modeling predictions. / Ph. D.
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Stretched Exponential Decline Model as a Probabilistic and Deterministic Tool for Production Forecasting and Reserve Estimation in Oil and Gas ShalesAkbarnejad Nesheli, Babak 2012 May 1900 (has links)
Today everyone seems to agree that ultra-low permeability and shale reservoirs have become the potentials to transform North America's oil and gas industry to a new phase.
Unfortunately, transient flow is of long duration (perhaps life of the well) in ultra-low permeability reservoirs, and traditional decline curve analysis (DCA) models can lead to significantly over-optimistic production forecasts without additional safeguards.
Stretched Exponential decline model (SEDM) gives considerably more stabilized production forecast than traditional DCA models and in this work it is shown that it produces unchanging EUR forecasts after only two-three years of production data are available in selected reservoirs, notably the Barnett Shale.
For an individual well, the SEDM model parameters, can be determined by the method of least squares in various ways, but the inherent nonlinear character of the least squares problem cannot be bypassed. To assure a unique solution to the parameter estimation problem, this work suggests a physics-based regularization approach, based on critical velocity concept. Applied to selected Barnett Shale gas wells, the suggested method leads to reliable and consistent EURs.
To further understand the interaction of the different fracture properties on reservoir response and production decline curve behavior, a series of Discrete Fracture Network (DFN) simulations were performed. Results show that at least a 3-layer model is required to reproduce the decline behavior as captured in the published SEDM parameters for Barnett Shale. Further, DFN modeling implies a large number of parameters like fracture density and fracture length are in such a way that their effect can be compensated by the other one. The results of DFN modeling of several Barnett Shale horizontal wells, with numerous fracture stages, showed a very good agreement with the estimated SEDM model for the same wells.
Estimation of P90 reserves that meet SEC criteria is required by law for all companies that raise capital in the United States. Estimation of P50 and P10 reserves that meet SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) criteria is important for internal resource inventories for most companies. In this work a systematic methodology was developed to quantify the range of uncertainty in production forecast using SEDM. This methodology can be used as a probabilistic tool to quantify P90, P50, and P10 reserves and hence might provide one possible way to satisfy the various legal and technical-society-suggested criteria.
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Development of an efficient embedded discrete fracture model for 3D compositional reservoir simulation in fractured reservoirsMoinfar, Ali, 1984- 02 October 2013 (has links)
Naturally fractured reservoirs (NFRs) hold a significant amount of the world's hydrocarbon reserves. Compared to conventional reservoirs, NFRs exhibit a higher degree of heterogeneity and complexity created by fractures. The importance of fractures in production of oil and gas is not limited to naturally fractured reservoirs. The economic exploitation of unconventional reservoirs, which is increasingly a major source of short- and long-term energy in the United States, hinges in part on effective stimulation of low-permeability rock through multi-stage hydraulic fracturing of horizontal wells. Accurate modeling and simulation of fractured media is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make these methods inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent approaches for discrete fracture modeling may require large computational times and hence the oil industry has not widely used such approaches, even though they give more accurate representations of fractured reservoirs than dual continuum models.
We developed an embedded discrete fracture model (EDFM) for an in-house fully-implicit compositional reservoir simulator. EDFM borrows the dual-medium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity and heterogeneity of a typical fractured reservoir. EDFM employs a structured grid to remediate challenges associated with unstructured gridding required for other discrete fracture models. Also, the EDFM approach can be easily incorporated in existing finite difference reservoir simulators. The accuracy of the EDFM approach was confirmed by comparing the results with analytical solutions and fine-grid, explicit-fracture simulations. Comparison of our results using the EDFM approach with fine-grid simulations showed that accurate results can be achieved using moderate grid refinements. This was further verified in a mesh sensitivity study that the EDFM approach with moderate grid refinement can obtain a converged solution. Hence, EDFM offers a computationally-efficient approach for simulating fluid flow in NFRs. Furthermore, several case studies presented in this study demonstrate the applicability, robustness, and efficiency of the EDFM approach for modeling fluid flow in fractured porous media.
Another advantage of EDFM is its extensibility for various applications by incorporating different physics in the model. In order to examine the effect of pressure-dependent fracture properties on production, we incorporated the dynamic behavior of fractures into EDFM by employing empirical fracture deformation models. Our simulations showed that fracture deformation, caused by effective stress changes, substantially affects pressure depletion and hydrocarbon recovery. Based on the examples presented in this study, implementation of fracture geomechanical effects in EDFM did not degrade the computational performance of EDFM.
Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns suggested by microseismic data. We developed a coupled dual continuum and discrete fracture model to efficiently simulate production from these reservoirs. Large-scale hydraulic fractures were modeled explicitly using the EDFM approach and numerous small-scale natural fractures were modeled using a dual continuum approach. The transport parameters for dual continuum modeling of numerous natural fractures were derived by upscaling the EDFM equations. Comparison of the results using the coupled model with that of using the EDFM approach to represent all natural and hydraulic fractures explicitly showed that reasonably accurate results can be obtained at much lower computational cost by using the coupled approach with moderate grid refinements. / text
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Numerical modeling of complex hydraulic fracture development in unconventional reservoirsWu, Kan 15 January 2015 (has links)
Successful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis. / text
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Applications of Level Set and Fast Marching Methods in Reservoir CharacterizationXie, Jiang 2012 August 1900 (has links)
Reservoir characterization is one of the most important problems in petroleum engineering. It involves forward reservoir modeling that predicts the fluid behavior in the reservoir and inverse problem that calibrates created reservoir models with given data. In this dissertation, we focus on two problems in the field of reservoir characterization: depth of investigation in heterogeneous reservoirs, and history matching and uncertainty quantification of channelized reservoirs.
The concept of depth of investigation is fundamental to well test analysis. Much of the current well test analysis relies on analytical solutions based on homogeneous or layered reservoirs. However, such analytic solutions are severely limited for heterogeneous and fractured reservoirs, particularly for unconventional reservoirs with multistage hydraulic fractures. We first generalize the concept to heterogeneous reservoirs and provide an efficient tool to calculate drainage volume using fast marching methods and estimate pressure depletion based on geometric pressure approximation. The applicability of proposed method is illustrated using two applications in unconventional reservoirs including flow regime visualization and stimulated reservoir volume estimation.
Due to high permeability contrast and non-Gaussianity of channelized permeability field, it is difficult to history match and quantify uncertainty of channelized reservoirs using traditional approaches. We treat facies boundaries as level set functions and solve the moving boundary problem (history matching) with the level set equation. In addition to level set methods, we also exploit the problem using pixel based approach. The reversible jump Markov Chain Monte Carlo approach is utilized to search the parameter space with flexible dimensions. Both proposed approaches are demonstrated with two and three dimensional examples.
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The evaluation of waterfrac technology in low-permeability gas sands in the East Texas basinTschirhart, Nicholas Ray 01 November 2005 (has links)
The petroleum engineering literature clearly shows that large proppant volumes
and concentrations are required to effectively stimulate low-permeability gas
sands. To pump large proppant concentrations, one must use a viscous fluid.
However, many operators believe that low-viscosity, low-proppant concentration
fracture stimulation treatments known as ??waterfracs?? produce comparable
stimulation results in low-permeability gas sands and are preferred because they
are less expensive than gelled fracture treatments.
This study evaluates fracture stimulation technology in tight gas sands by using
case histories found in the petroleum engineering literature and by using a
comparison of the performance of wells stimulated with different treatment sizes
in the Cotton Valley sands of the East Texas basin. This study shows that large
proppant volumes and viscous fluids are necessary to optimally stimulate tight
gas sand reservoirs. When large proppant volumes and viscous fluids are not
successful in stimulating tight sands, it is typically because the fracture fluids
have not been optimal for the reservoir conditions. This study shows that
waterfracs do produce comparable results to conventional large treatments in the Cotton Valley sands of the East Texas basin, but we believe it is because the
conventional treatments have not been optimized. This is most likely because
the fluids used in conventional treatments are not appropriate or have not been
used appropriately for Cotton Valley conditions.
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[en] FLOW SIMULATION IN UNCONVENTIONAL SHALE RESERVOIRS / [pt] SIMULAÇÃO DE FLUXO EM RESERVATÓRIOS NÃO CONVENCIONAIS DE FOLHELHOSJOSE EDUARDO MORENO LEVERENZ 30 July 2020 (has links)
[pt] Os reservatórios não convencionais de folhelho possuem permeabilidades muito baixas sendo necessário fraturar hidraulicamente a formação para aumentar a permeabilidade e conseguir um melhor desempenho do poço. O fraturamento hidráulico em vários estágios criado a partir de um poço horizontal gera uma
complexa rede de fraturas, com variadas condutividades dentro do volume de reservatório estimulado. Neste trabalho realizamos análises paramétricas para avaliar os efeitos no desempenho do poço produtor causadas pela variação dos diferentes parâmetros dentro da complexa rede de fraturas criada. Estes
parâmetros foram principalmente: os espaçamentos na rede de fraturas (sem propante), a condutividade na rede de fraturas (sem propante), a condutividade das fraturas primárias (preenchidas com propante), os espaçamentos das fraturas primárias (preenchidas com propante), a variação da permeabilidade ao longo das fraturas primárias e finalmente a variação das pressões do fundo do poço. Entender as relações entre o tamanho da rede de fraturas, os espaçamentos, a distribuição do propante e a condutividade das fraturas são parâmetros chaves para definir estratégias de estimulação e completação. Finalmente se fez uma
simulação com injeção de água avaliando o impacto que causa na recuperação total de óleo e gás, e analisamos a possibilidade de aplicar este método de recuperação num reservatório fraturado hidraulicamente. / [en] The shale reservoirs have ultralow permeability requiring hydraulically fracturing the formation to improve permeability and get a better well performance. The multistage hydraulic fractures system created from a horizontal well generates a complex fracture network with different conductivities within the stimulated reservoir volume. In this work we made parametric analyzes to assess the effects on producer well performance caused by the variation of different parameters within the complex network fractures created. These parameters were mainly: spacing in the un-propped fracture network, the conductivity in the unpropped fracture network, primary fracture conductivity, primary fracture spacing, the variation of permeability along the primary fractures and finally the variation of downhole pressures. Understanding the relationship between fracture network size, fracture spacing, proppant distribution, and fracture conductivity is critical to stimulation and completion design. Finally a simulation with water injection
evaluating its impact on recovering oil and gas was carried out, and the possibility of applying this method of recovery in a fractured reservoir was evaluated.The shale reservoirs have ultralow permeability requiring hydraulically fracturing the formation to improve permeability and get a better well performance. The multistage hydraulic fractures system created from a horizontal well generates a complex fracture network with different conductivities within the stimulated reservoir volume. In this work we made parametric analyzes to assess the effects on producer well performance caused by the variation of different parameters within the complex network fractures created. These parameters were mainly: spacing in the un-propped fracture network, the conductivity in the unpropped fracture network, primary fracture conductivity, primary fracture spacing, the variation of permeability along the primary fractures and finally the variation of downhole pressures. Understanding the relationship between fracture network
size, fracture spacing, proppant distribution, and fracture conductivity is critical to stimulation and completion design. Finally a simulation with water injection evaluating its impact on recovering oil and gas was carried out, and the possibility of applying this method of recovery in a fractured reservoir was evaluated.
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Evolution des propriétés réservoir des carbonates peu poreux : exemple des calcaires du Crétacé Inférieur de la Moyenne Durance / Tight Carbonates Reservoir Properties Evolution : A case study of Lower Cretaceous hemipelagic limestone from the Northern Provence regionBruna, Pierre-olivier 11 October 2013 (has links)
Les calcaires hémipélagiques du Sud-Est de la France sont caractérisés par de faibles valeurs de porosité et de perméabilité. Ces caractéristiques permettent de considérer ces roches comme de potentiels analogues des réservoirs pétroliers non-conventionnels ou des aquifères fissurés. Ces réservoirs sont d’une importance capitale dans le contexte économique actuel. Néanmoins, l’exploitation de ce type de réservoir représente des risques industriels et des challenges techniques qui doivent être gérés pour réduire leur empreinte sur l’environnement.Ce travail apporte une quantité significative de nouvelles données et des méthodes pour caractériser les réservoirs carbonatés non-conventionnels. Il démontre l’importance des figures de compaction (stylolites, microstylolites et faisceaux de pression-dissolution) sur la capacité de stockage des fluides dans ce type de réservoir. Il montre aussi que l’évolution diagénétique des sédiments carbonatés hémipélagiques dépend de processus précoces (cimentations précoces, compaction différentielle) et éventuellement de réactivations plus tardives (inversion de contraintes tectoniques). Le couplage des modèles 3D avec les géostatistiques apparaît comme un protocole valide et rapide pour identifier les éléments clef (faciès, fractures et stylolites) qui jouent un rôle dans la distribution des hétérogénéités pétrophysiques des réservoirs non-conventionnels. Cette méthode permet aussi de générer des modèles équiprobable de corps géologiques fracturés et perméables permettant de possible investigations sur la distribution des zones d’écoulement préférentiels. / Hemipelagic limestones from the South-East of France are characterized by low values of porosity and permeability that allow considering these rocks as potential analogs to unconventional oil and gas reservoirs or fissured aquifers. These reservoirs are of primary importance in today’s economical context where the energy and the water’s demands grow with the increase in the world population. Nevertheless, the industrial exploitation of such reservoirs faces series of environmental risks and technical challenges that require to be managed in order to reduce their footprint on the environment.This work brought a significant amount of new data on unconventional carbonate reservoirs. It highlights how important compaction features (stylolites, microstylolites, solution seams) may be to fluids storage in such reservoirs. It shows that the diagenetic evolution of hemipelagic carbonate sediments depends on both early processes (sorting, early cementation, differential compaction) and eventual late reactivations (under tectonic stress inversion for example). Coupling three-dimensional modeling with geostatistics appear as an accurate and fast protocol to identify key elements (facies, fractures and stylolite) that play a role in the petrophysical heterogeneity of such unconventional reservoirs. This method also allows identifying equiprobable models of fractures geobodies and investigating the distribution of flow preferential pathways.
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Pressure Normalization of Production Rates Improves Forecasting ResultsLacayo Ortiz, Juan Manuel 16 December 2013 (has links)
New decline curve models have been developed to overcome the boundary-dominated flow assumption of the basic Arps’ models, which restricts their application in ultra-low permeability reservoirs exhibiting long-duration transient flow regimes. However, these new decline curve analysis (DCA) methods are still based only on production rate data, relying on the assumption of stable flowing pressure. Since this stabilized state is not reached rapidly in most cases, the applicability of these methods and the reliability of their solutions may be compromised. In addition, production performance predictions cannot be disassociated from the existing operation constraints under which production history was developed. On the other hand, DCA is often carried out without a proper identification of flow regimes. The arbitrary application of DCA models regardless of existing flow regimes may produce unrealistic production forecasts, because these models have been designed assuming specific flow regimes.
The main purpose of this study was to evaluate the possible benefits provided by including flowing pressures in production decline analysis. As a result, it have been demonstrated that decline curve analysis based on pressure-normalized rates can be used as a reliable production forecasting technique suited to interpret unconventional wells in specific situations such as unstable operating conditions, limited availability of production data (short production history) and high-pressure, rate-restricted wells. In addition, pressure-normalized DCA techniques proved to have the special ability of dissociating the estimation of future production performance from the existing operation constraints under which production history was developed. On the other hand, it was also observed than more consistent and representative flow regime interpretations may be obtained as diagnostic plots are improved by including MBT, pseudovariables (for gas wells) and pressure-normalized rates. This means that misinterpretations may occur if diagnostic plots are not applied correctly.
In general, an improved forecasting ability implies greater accuracy in the production performance forecasts and more reliable reserve estimations. The petroleum industry may become more confident in reserves estimates, which are the basis for the design of development plans, investment decisions, and valuation of companies’ assets.
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