Dissertations / Theses on the topic 'Reservoir simulation pressures'

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

Several types of transient well testing in Norne field are presented in this thesis. One production well from each segment in Norne field was participated in different type of test. The well test data of all cases were generated from reservoir simulation. It allows flexibility in modifying reservoir model condition to understand different behavior of pressure response. The tests were first started by producing the well at a constant rate for 10 days, and then shutting-in the well for at least 24 hours. The importance of reservoir model grid refinement, determination of reservoir communication across the fault, and the complexity of horizontal well test analysis are the three main discussions in this thesis work.Series of buildup tests at well D-1H in C-Segment were performed to recognize the significance level of Local Grid Refinement (LGR) near the wellbore. There are two sensitivities performed in the reservoir model, extension of LGR area and increase of LGR factor. Based on pressure responses, wider area of LGR affected permeability estimation, while increase of LGR factor impacted the storage capacity calculation. In the next discussions, LGR near the wellbore becomes a standard procedure in generating well test data.The next type of transient well testing performed in Norne field is interference test. This test was executed at well E-3H as an observation well in E-Segment; while well E-1H and E-2H acted as interfering wells in D- and E-Segments respectively. According to pressure and production trends, it can be ensured both interfering wells are located in different segments. A reservoir communication across segments was identified through pressure drop analysis at well E-3H; hence presence of a major fault between segments is not fully sealed.Transient well testing in horizontal well gives a special and more complex analysis compare to vertical well analysis. A buildup test was examined at horizontal well E-4AH in G-Segment to determine vertical and horizontal permeability. Two flow regimes existed during the test, early-time radial flow and intermediate-time linear flow. They were discovered from pressure versus time plot and pressure derivative analysis. Interpretation results from both flow regimes show a very low kv/kh ratio in the segment around the well.All data tests were interpreted manually using practical equations after doing comprehensive literature studies. The data were also evaluated quantitatively using F.A.S.T WelltestTM – engineering software of pressure transient analysis from Fekete reservoir engineering software and services. Reservoir properties obtained from pressure transient analysis have similar results with the original data on the reservoir model. To simplify the study, production rate which was used in build-up and interference tests are only from oil production basis. In addition, no injections in Norne field were included during the tests to have the same comparison in all analysis. As the future work, any other types of tests are strongly recommended, both in single-well and multiple-well testing, also in vertical and horizontal wells.

Research, pilot scale and field developments of In-Situ Combustion (ISC) for enhanced oil recovery (EOR) in shallow, low pressure, heavy oil reservoirs intensified between the first and the second oil crisis from 1973 to 1981. A decline of interest in EOR followed the collapse of the oil prices in 1986. Renewed interest on in-situ combustion EOR research in the late 1980’s and beginning of the 1990’s was expanded and focused on high pressure medium and light oil reservoirs. The applicability of air injection in deep high pressure light petroleum reservoirs was established by research work of Greaves et al. in 1987 & 1988, Yannimaras et al. in 1991 and Ramey et a l in 1992. Accelerating rate calorimeter (ARC) tests were used to screen the applicability of various types of light oil reservoirs for in-situ combustion EOR by Yannimaras and Tiffin in 1994. The most successful light oil air injection project in the 1990s in the Medicine Pole Hills Unit, Williston Basin, N. Dakota started in 1987 and was reported by Kumar, Fassihi & Yannimaras, in 1994. Low temperature oxidation of light North Sea petroleum was studied at the University of Bath. A high-pressure combustion tube laboratory system was built at Bath University to evaluate performance of medium and light petroleum in-situ combustion processes. Gravity effects and the impact of horizontal wells in Forced Flow In-Situ Combustion Drainage Assisted by Gravity (FFISCDAG) were studied with three-dimensional combustion experiments. In this study, the university of Bath combustion tube experiments have been simulated and history matched. The tube experiments were up-scaled and field simulation studies were performed. A generic PVT characterization scheme based on 5 hydrocarbon pseudo-components was used, which was validated for light Australian and medium ‘Clair’ oil. A generic chemical reaction characterization scheme was used, which was validated for light Australian and medium ‘Clair’ oil. Advanced PVT and chemical reaction characterizations have been recommended for future work with more powerful hardware platforms. Extensive front track and flame extinction studies were performed to evaluate the performance of currently available non-iso-thermal simulators and to appraise their necessity in air injection processes. Comparative ISC field scale numerical simulation studies of Clair medium oil and light Australian petroleum were based on up-scaled combustion tube experimental results. These studies showed higher than expected hydrocarbon recovery in alternative EOR processes for both pre and post water flood implementation of ISC. Further in this study field scale numerical simulation studies revealed high incremental hydrocarbon recovery was possible by gravity assisted forced flow. The applicability of light oil ISC to gas condensate and sour petroleum reservoirs has been examined in this study with promising results. Light petroleum ISC implemented by a modified water flood including oxidants such as H2O2 and NH4NO3 are expected to widen the applicability of ISC processes in medium and light petroleum reservoirs, especially water flooded North Sea reservoirs.

It is observed that the flowing bottom-hole temperature (FBHT) changes as a result of production, injection or shutting the well down. Variations in temperature mainly occur due to geothermal gradient, injected fluid temperature, frictional heating and the Joule-Thomson effect. The latter is the change of temperature because of expansion or compression of a fluid in a flow process involving no heat transfer or work. CMG STARS thermal simulation sector model developed in this study was used to analyze FBHT changes and understand the reasons. Twenty three main and five additional cases that were developed by using this model were simulated and relation of BHT with other parameters was investigated. Indeed the response of temperature to the change of some parameters such as bottom-hole pressure and gas-oil ratio was detected and correlation was tried to set between these elements. Observations showed that generally FBHT increases when GOR decreases and/or flowing bottom-hole pressure (FBHP) increases. This information allows estimating daily gas-oil ratios from continuously measured BHT. Results of simulation were compared with a real case and almost the same responses were seen. The increase in temperature after the start of water and gas injection or due to stopping of neighboring production wells indicated interwell communications. Additional cases were run to determine whether there are BHT changes when initial temperature was kept constant throughout the reservoir. Different iteration numbers and refined grids were used during these runs to analyze iteration errors
however no significant changes were observed due to iteration number differences and refined grids. These latter cases showed clearly that variations of temperature don&rsquo
t occur only due to geothermal gradient, but also pressure and saturation changes. On the whole, BHT can be used to get data ranging from daily gas-oil ratios to interwell connection if analyzed correctly.

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Nearly 3 x 1011 m3 of medium and light oils will remain in reservoirs worldwide after conventional recovery methods have been exhausted and much of this volume would be recovered by Enhanced Oil Recovery (EOR) methods. The in-situ combustion (ISC) is an EOR method in which an oxygen-containing gas is injected into a reservoir where it reacts with the crude oil to create a high-temperature combustion front that is propagated through the reservoir. The High Pressure Air Injection (HPAI) method is a particular denomination of the air injection process applied in light oil reservoirs, for which the combustion reactions are dominant between 150 and 300?C and the generation of flue gas is the main factor to the oil displacement. A simulation model of a homogeneous reservoir was built to study, which was initially undergone to primary production, for 3 years, next by a waterflooding process for 21 more years. At this point, with the mature condition established into the reservoir, three variations of this model were selected, according to the recovery factors (RF) reached, for study the in-situ combustion (HPAI) technique. Next to this, a sensitivity analysis on the RF of characteristic operational parameters of the method was carried out: air injection rate per well, oxygen concentration into the injected gas, patterns of air injection and wells perforations configuration. This analysis, for 10 more years of production time, was performed with assistance of the central composite design. The reservoir behavior and the impacts of chemical reactions parameters and of reservoir particularities on the RF were also evaluated. An economic analysis and a study to maximize the RF of the process were also carried out. The simulation runs were performed in the simulator of thermal processes in reservoirs STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) from CMG (Computer Modelling Group). The results showed the incremental RF were small and the net present value (NPV) is affected by high initial investments to compress the air. It was noticed that the adoption of high oxygen concentration into the injected gas and of the five spot pattern tends to improve the RF, and the wells perforations configuration has more influence with the increase of the oil thickness. Simulated cases relating to the reservoir particularities showed that smaller residual oil saturations to gas lead to greater RF and the presence of heterogeneities results in important variations on the RF and on the production curves
Aproximadamente 3 x 1011 m3 de ?leos m?dios e leves restar?o nos reservat?rios ao redor do mundo ap?s a aplica??o dos m?todos convencionais de recupera??o e grande parte desse volume seria recuper?vel com o uso de m?todos especiais. A combust?o in-situ (CIS) ? um m?todo de recupera??o avan?ada de petr?leo no qual um g?s que cont?m oxig?nio ? injetado no reservat?rio onde reage com o ?leo cru para criar uma frente de combust?o de alta temperatura que se propaga pelo reservat?rio. O m?todo HPAI (High Pressure Air Injection) ? uma denomina??o particular do processo de inje??o de ar aplicado em reservat?rios de ?leos leves, onde as rea??es de combust?o s?o dominantes entre 150 e 300?C e a gera??o de flue gas ? o principal fator de deslocamento do ?leo. Um modelo de simula??o de fluxo de um reservat?rio homog?neo foi constru?do para o estudo, o qual foi inicialmente submetido ? produ??o prim?ria, por 3 anos, e em seguida, ao processo de inje??o de ?gua por mais 21 anos. Nesse ponto, com a condi??o madura estabelecida no reservat?rio, foram selecionadas tr?s varia??es desse modelo, de acordo com o fator de recupera??o (FR) obtido, para o estudo da t?cnica de combust?o in-situ (HPAI). Em seguida realizou-se uma an?lise de sensibilidade sobre o FR de par?metros operacionais pr?prios do m?todo: vaz?o de inje??o de ar por po?o, concentra??o de oxig?nio no g?s injetado, esquema de inje??o de ar e configura??o dos canhoneados dos po?os. Essa an?lise, para um per?odo adicional de at? 10 anos produ??o, foi efetuada com o aux?lio da t?cnica de planejamento composto central. O comportamento do reservat?rio e os impactos de par?metros envolvendo as rea??es qu?micas e de particularidades de reservat?rio sobre o FR tamb?m foram avaliados. Adicionalmente foram elaborados uma an?lise econ?mica e um estudo de maximiza??o do FR do processo. As simula??es foram realizadas com o simulador de processos t?rmicos em reservat?rios STARS (Steam, Thermal and Advanced Process Reservoir Simulation) da CMG (Computer Modelling Group). Os resultados mostraram que os FR incrementais foram baixos e que o valor presente l?quido (VPL) ? impactado negativamente pelos elevados investimentos iniciais para compress?o do ar. Observou-se que a ado??o de maiores concentra??es de oxig?nio no g?s injetado e do esquema de inje??o de ar tipo five spot tende a favorecer o FR, e que a configura??o dos canhoneados dos po?os apresenta influ?ncia crescente com o aumento da espessura porosa com ?leo do reservat?rio. Casos simulados referentes ?s particularidades de reservat?rio indicaram que menores satura??es residuais de ?leo ao g?s levam a FR maiores e que a exist?ncia de heterogeneidades resulta em varia??es consider?veis nos FR e nas curvas de produ??o

Extremely small pore size, low porosity, and ultra-low permeability are among the characteristics of shale rocks. In tight shale reservoirs, the nano-confinement effects that include large gas-oil capillary pressure and critical property shifts could alter the phase behaviors, thereby affecting the oil or gas production. In this research, two in-house simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. Meanwhile, the effect of nano-confinement and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are investigated. First, a previously developed compositionally extended black-oil simulation approach is modified, and extended, to include the effect of large gas-oil capillary pressure for modeling first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery estimations. A dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR. Molecular diffusion plays an important role in oil and gas migration in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within porous media. Another objective of this research is to estimate the diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts could alter the phase behaviors. This study estimates the diffusivities of shale fluids in nanometer-scale shale rock from two perspectives: 1) examining the shift of diffusivity caused by nanopore confinement effects from phase change (phase composition and fluid property) perspective, and 2) calculating the effective diffusion coefficient in porous media by incorporating rock intrinsic properties (porosity and tortuosity factor). The tortuosity is obtained by using tortuosity-porosity relations as well as the measured tortuosity of shale from 3D imaging techniques. The results indicated that nano-confinement effects could affect the diffusion coefficient through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in porous shale rock is reduced by 102 to 104 times as porosity decreases from 0.1 to 0.03. Finally, a fully compositional model is developed, which enables us to process multi-component multi-phase fluid flow in shale nano-porous media. The validation results for primary depletion, water injection, and gas injection show a good match with the results of a commercial software (CMG, GEM). The nano-confinement effects (capillary pressure effect and critical property shifts) are incorporated in the flash calculation and flow equations, and their effects on Bakken oil production and Marcellus shale gas production are examined. The results show that including oil-gas capillary pressure effect could increase the oil production but decrease the gas production. Inclusion of critical property shift could increase the oil production but decrease the gas production very slightly. The effect of molecular diffusion on Bakken oil and Marcellus shale gas production are also examined. The effect of diffusion coefficient calculated by using Sigmund correlation is negligible on the production from both Bakken oil and Marcellus shale gas huff-n-puff. Noticeable increase in oil and gas production happens only after the diffusion coefficient is multiplied by 10 or 100 times.
Doctor of Philosophy
Shale reservoir is one type of unconventional reservoir and it has extremely small pore size, low porosity, and ultra-low permeability. In tight shale reservoirs, the pore size is in nanometer scale and the oil-gas capillary pressure reaches hundreds of psi. In addition, the critical properties (such as critical pressure and critical temperature) of hydrocarbon components will be altered in those nano-sized pores. In this research, two in-house reservoir simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. The large nano-confinement effects (large gas-oil capillary pressure and critical property shifts) on oil or gas production behaviors will be investigated. Meanwhile, the nano-confinement effects and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are also studied.

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Conselho Nacional de Desenvolvimento Cient?fico e Tecnol?gico
Nowadays, most of the hydrocarbon reserves in the world are in the form of heavy oil, ultra - heavy or bitumen. For the extraction and production of this resource is required to implement new technologies. One of the promising processes for the recovery of this oil is the Expanding Solvent Steam Assisted Gravity Drainage (ES-SAGD) which uses two parallel horizontal wells, where the injection well is situated vertically above the production well. The completion of the process occurs upon injection of a hydrocarbon additive at low concentration in conjunction with steam. The steam adds heat to reduce the viscosity of the oil and solvent aids in reducing the interfacial tension between oil/ solvent. The main force acting in this process is the gravitational and the heat transfer takes place by conduction, convection and latent heat of steam. In this study was used the discretized wellbore model, where the well is discretized in the same way that the reservoir and each section of the well treated as a block of grid, with interblock connection with the reservoir. This study aims to analyze the influence of the pressure drop and heat along the injection well in the ES-SAGD process. The model used for the study is a homogeneous reservoir, semi synthetic with characteristics of the Brazilian Northeast and numerical simulations were performed using the STARS thermal simulator from CMG (Computer Modelling Group). The operational parameters analyzed were: percentage of solvent injected, the flow of steam injection, vertical distance between the wells and steam quality. All of them were significant in oil recovery factor positively influencing this. The results showed that, for all cases analyzed, the model considers the pressure drop has cumulative production of oil below its respective model that disregards such loss. This difference is more pronounced the lower the value of the flow of steam injection
Atualmente, a maior parte das reservas de hidrocarbonetos no mundo se encontram na forma de ?leo pesado, ultra-pesado ou betume. Para a extra??o e produ??o desse recurso ? necess?ria a implanta??o de novas tecnologias. Um dos processos promissores para a recupera??o desse ?leo ? a drenagem gravitacional assistida com vapor e solvente (ESSAGD) que utiliza dois po?os horizontais paralelos, onde o injetor ? disposto acima do produtor. A realiza??o do processo se d? mediante a inje??o de um aditivo de hidrocarboneto em baixa concentra??o em conjunto com vapor. O vapor contribui com calor para redu??o da viscosidade do ?leo e o solvente ajuda na miscibilidade, reduzindo a tens?o interfacial entre ?leo/solvente. A principal for?a atuante neste processo ? a gravitacional e a transfer?ncia de calor ocorre por meio da condu??o, convec??o e pelo calor latente do vapor. Neste estudo foi utilizado o modelo discretizado, onde o po?o ? discretizado da mesma forma que o reservat?rio, sendo cada se??o do po?o tratada como um bloco da grade, com conex?o interblocos com o reservat?rio. O presente trabalho tem como objetivo analisar a influ?ncia da perda de carga e calor ao longo do po?o injetor no processo ES-SAGD. O modelo utilizado para estudo trata-se de um reservat?rio homog?neo, semissint?tico com caracter?sticas do Nordeste Brasileiro e as simula??es num?ricas foram realizadas atrav?s do simulador t?rmico STARS da CMG (Computer Modelling Group). Os par?metros operacionais analisados foram: porcentagem de solvente injetado, vaz?o de inje??o de vapor, dist?ncia vertical entre os po?os e qualidade de vapor. Todos eles foram significativos no Fator de Recupera??o de ?leo. Os resultados demonstraram que, para todos os casos analisados, o modelo que considera a perda de carga apresenta produ??o acumulada de ?leo inferior ao seu respectivo modelo que desconsidera tal perda. Essa diferen?a ? mais acentuada quanto menor o valor da vaz?o de inje??o de vapor

Pore pressure exists ubiquitously in the Earth’s subsurface and very often exhibits a cyclic loading on pre-existing faults due to seasonal and tidal changes, as well as the impoundment and discharge of surface reservoirs. The effect of oscillating pore pressure on induced seismicity is not fully understood. This effect exhibits a dynamic variation in effective stresses in space and time. The redistribution of pore pressure as a result of fluid flow and pressure oscillations can cause spatial and temporal changes in the shear strength of fault zones, which may result in delayed and protracted slips on pre-existing fractures. This research uses an experimental approach to investigate the effects of oscillating pore pressure on induced seismicity. With the aid of geophysical techniques, the spatial and temporal distribution of seismic events was reconstructed and analysed. Triaxial experiments were conducted on two types of sandstone, one with low permeability (Fontainebleau sandstone) and the other with high permeability (Darley Dale sandstone). Cyclic pore pressures were applied to the naturally-fractured samples to activate and reactivate the existing faults. The results indicate that the mechanical properties of the sample and the heterogeneity of the fault zone can influence the seismic response. Initial seismicity was induced by applying pore pressures that exceeded the previous maximum attained during the experiment. The reactivation of faults and foreshock sequences was found in the Fontainebleau sandstone experiment, a finding which indicates that oscillating pore pressure can induce seismicity for a longer period of time than a single-step increase in pore pressure. The corresponding strain change due to cyclic pore pressure changes suggests that progressive shearing occurred during the pore pressure cycles. This shearing progressively damaged the existing fault through the wearing of asperities, which in turn reduced the friction coefficient and, hence, reduced the shear strength of the fault. This ‘slow’ seismic mechanism contributed to the prolonged period of seismicity. This study also applied a material forecast model for the estimation of time-to-failure or peak seismicity in reservoir-induced seismicity, which may provide some general guidelines for short-term field case estimations.

Hydrogen release from a high pressure vessel is simulated using a computational fluid dynamic (CFD) code. An existing compressible Euler CFD solver is extended to solve the mixture of fluids together with extra transport equation for hydrogen species concentration. The modifications to the governing equations are presented as well as the discretization with the same techniques as the core solver. The core solver uses an implicit conservative scheme which is based on a finite volume technique for spatial discretization. The mixture of fluids is assumed to obey the ideal gas law and hence pressure, temperature, and density are coupled using the perfect gas equation of state. The code is used to simulate and study an inviscid hydrogen jet exiting a reservoir with initial pressures of 100 and 800 bars. The results obtained for the 100 bars test case are compared with the available data from another numerical simulation. Excellent agreement is observed

Hydrocarbon production from mudrock (“shale”) reservoirs is fundamental in the global energy supply. Extracting commercial amounts of hydrocarbons from shale plays requires a combination of horizontal well drilling, hydraulic fracturing, and multi-stage completions. This technology creates conductive hydrofractures that may interact with pre-existing natural fractures and bedding planes. Microseismic studies and field pilots have uncovered evidence of complex hydrofracture geometries that can lead to unsatisfactory wellbore flow performance. This study examines the effects of three hydrofracture geometries (”scenarios”) on wellbore production in overpressured shale oil reservoirs using a commercial reservoir simulator (CMG IMEX). The first scenario is our reference case. It comprises ideal ized and vertical hydrofractures. The second scenario has an orthogonal hydrofracture network made up of vertical hydrofractures with perpendicular secondary fractures. The third scenario has vertical hydrofractures with horizontal bedding plane frac tures. We generated additional simulation models that aim to capture the effect on hydrocarbon production of different fracture properties, such as natural fracture ori entation and spacing, number of hydrofractures per stage, number of perpendicular secondary fractures and horizontal fractures, and fracture closure mechanism. The results show that ideal planar fractures are an oversimplification of the hydrofracture geometry in anisotropic shale plays. They fail to represent the complex geometry in reservoir simulation and lead to unexpected hydrocarbon production forecasting. They also show that the generation of unpropped horizontal fractures harms hydro carbon productivity, while perpendicular secondary fractures enhance initial reservoir 5 fluid production. The generation of horizontal hydrofractures is a particular scenario that may occur in reservoirs with high pore pressure and transitional strike-slip to reverse faulting regime. These conditions have been reported in unconventional source rock plays, like the Marcellus shale in northeast Pennsylvania and southwest Virginia, and the Tuwaiq Mountain formation in the Jafurah Basin in Saudi Arabia. Our findings reveal that the presence of horizontal hydrofractures might reduce the cumulative hydrocarbon production by 20%, and the initial hydrocarbon production by 55% compared to the reference case. Our work shows unique reservoir simulations that enable us to assess the impact of different variables on wellbore production performance and understand the effects of varied hydrofracture geometries on hydrocarbon production.

Tight gas reservoirs provide almost one quarter of the current U.S. domestic gas production, with significant projected increases in the next several decades in both the U.S. and abroad. These reservoirs constitute an important play type, with opportunities for improved reservoir simulation & management, such as simulation model design, well placement. Our work develops robust and efficient strategies for improved tight gas reservoir simulation and management. Reservoir simulation models are usually acquired by upscaling the detailed 3D geologic models. Earlier studies of flow simulation have developed layer-based coarse reservoir simulation models, from the more detailed 3D geologic models. However, the layer-based approach cannot capture the essential sand and flow. We introduce and utilize the diffusive time of flight to understand the pressure continuity within the fluvial sands, and develop novel adaptive reservoir simulation grids to preserve the continuity of the reservoir sands. Combined with the high resolution transmissibility based upscaling of flow properties, and well index based upscaling of the well connections, we can build accurate simulation models with at least one order magnitude simulation speed up, but the predicted recoveries are almost indistinguishable from those of the geologic models. General practice of well placement usually requires reservoir simulation to predict the dynamic reservoir response. Numerous well placement scenarios require many reservoir simulation runs, which may have significant CPU demands. We propose a novel simulation-free screening approach to generate a quality map, based on a combination of static and dynamic reservoir properties. The geologic uncertainty is taken into consideration through an uncertainty map form the spatial connectivity analysis and variograms. Combining the quality map and uncertainty map, good infill well locations and drilling sequence can be determined for improved reservoir management. We apply this workflow to design the infill well drilling sequence and explore the impact of subsurface also, for a large-scale tight gas reservoir. Also, we evaluated an improved pressure approximation method, through the comparison with the leading order high frequency term of the asymptotic solution. The proposed pressure solution can better predict the heterogeneous reservoir depletion behavior, thus provide good opportunities for tight gas reservoir management.

This work is concerned with the application of finite difference simulation to modelling the pressure response in partially penetrating oil wells. This has relevance to the oil and hydrology industries where pressure behaviour is used to infer the nature of aquifer or reservoir properties, particularly permeability. In the case of partially penetrating wells, the pressure response carries information regarding the magnitude of permeability in the vertical direction, a parameter that can be difficult to measure by other means and one that has a direct influence on both the total volumes of oil that can be recovered and on the rate of recovery. The derivation of the non-linear differential equations that form the basis for multiphase fluid flow in porous media is reviewed and it is shown how they can be converted into a set of finite difference equations. Techniques used to solve these equations are explained, with particular emphasis on the approach followed by the commercial simulation package used in this study. This involves use of Newton's method to linearize the equations followed by application of a pre-conditioned successive minimization technique to solve the resulting linear equations. Finite difference simulation is applied to a hypothetical problem of solving pressure response in a partially penetrating well in an homogenous but anisotropic medium and the results compared with those from analytical solutions. Differences between the results are resolved, demonstrating that the required level of accuracy can be achieved through selective use of sufficiently small grid blocks and time-steps. Residual discrepancies with some of the analytical methods can be traced to differences in the boundary conditions used in their derivation. The simulation method is applied to matching a complex real-life well test with vertical and lateral variation in properties (including fluid saturation). An accurate match can be achieved through judicious adjustment of the problem parameters with the proviso that the vertical permeability needs to be high. This suggests that the recovery mechanism in the oil field concerned can be expected to be highly efficient, something that has recently been confirmed by production results.
Thesis (M.Sc.)-University of Natal, Pietermaritzburg, 2002.

Tese de mestrado, Geologia (Estratigrafia, Sedimentologia e Paleontologia) Universidade de Lisboa, Faculdade de Ciências, 2019
The Sleipner Carbon Capture and Storage project in the North Sea has been injecting CO2 underground into a saline formation for permanent storage for over 22 years. Equinor Energy AS, the field operator, and the license partners have injected about 18 million metric tons (Mt) of CO2 by the end of 2018 into the Utsira Formation at depths around 800 to 1100 m below sea level. The Sleipner CO2 storage reservoir comprises mostly unconsolidated sands with high porosities (36%) and high permeabilities (Darcy range) under near hydrostatic pressure conditions. An intensive geophysical monitoring program has been implemented since CO2 injection commenced in 1996. Nine bright reflections were already identified in the first time-lapse repeat survey in 1999 indicating that the CO2 ascended more than 200m vertically from the injection point to the caprock. The CO2 plume is evidently layered and asymmetric with a vertical stack distribution indicating that it encountered and breached a series of thin shale barriers (about 1m thick) within the storage site. The thin shale layers within the Utsira Formation acting as baffles to the CO2 migration were identified on well data but too thin to be resolved on seismic. Core and cutting samples of the caprock above the storage reservoir have indicated threshold pressures around 1.7 MPa. In order for the CO2 to break through the shale layers within the reservoir and form a vertical stack of thin plume layers, their threshold pressures need to be significantly smaller than the sampled caprock. Despite the high quality time-lapse seismic surveys imaging of the areal distribution of the CO2 plume in Sleipner, to date no published dynamic model has accurately replicated the layered morphology or flow behaviour of the plume. This is due to challenges around the underlying flow physics of CO2 and uncertainties in geological assumptions. Equinor has previously released benchmark reservoir models of Sleipner focusing on the uppermost plume layer (Singh et al., 2010). This master’s thesis objective was to define the full Sleipner multi-layer reservoir model in order to analyse the key factors controlling gravity-dominated flow in CO2 storage reservoirs, based on assumptions from Cavanagh et al. (2015). Fundamental aspects of the plume remain uncertain such as layer thickness, plume temperature profile (which impacts CO2 densities) and gas saturations for the plume layers. These uncertainties are inherited from the remote geophysical monitoring of the CO2 storage reservoir and the broadly constrained fields of pressure, temperature and saturation (Cavanagh and Haszeldine, 2014). Two main reservoir models were built in the Permedia software for the Sleipner CO2 storage in this study, a simple and a map-based approaches. The simple approach defined constant values for the reservoir properties and the map-based assigned lateral distributions to the reservoir properties corresponding to the areal distribution of the CO2 layers observed in seismic. Invasion percolation was applied to simulate the CO2 migration which assumes a flow domain dominated by gravity and capillary forces over viscous forces, similar to the expected in Sleipner. Using iterative experimentation in an Invasion Percolation (Permedia tool) simulator, values of shale threshold pressure (Pth) were modified until a satisfactory match was achieved. It was established that the multi-layer plume was very sensitive to the choice of Pth and the best match was obtained by using lower threshold pressures which could indicate pore sizes associated with silt-rich shales. A sensitivity analysis of the poorly constrained parameters, temperature (and related CO2 densities) and gas saturations, was performed to assess their impact on the CO2 migration simulation. Other models are also possible, such as incorporation of chimneys (leakage points), which need to be investigated in future studies.
A captura e armazenamento geológico de dióxido de carbono é considerada uma solução essencial para atingir os objetivos do Acordo de Paris sobre as alterações climáticas, visando manter o aumento da temperatura média mundial bem abaixo dos 2℃ em relação aos níveis pré-industriais. De acordo com a International Energy Agency (IEA), a captura e armazenamento de carbono – CCS (sigla em inglês para Carbon Capture and Storage) é a única tecnologia com capacidade para reduzir as emissões de CO2 em larga escala, necessária para alcançar os objetivos de longo prazo na mitigação do aquecimento global. O CCS consiste na captura de CO2 de grandes fontes estacionárias, como centrais termo-elétricas e instalações industriais, seguida de sua compressão, transporte por gasodutos ou navios e injeção para armazenamento geológico em formações rochosas com alta porosidade. O campo de Sleipner está localizado a cerca de 250 km da costa da Noruega, na parte central do Mar do Norte. O projeto de captura e armazenamento é combinado com o desenvolvimento e produção deste campo de gás. O campo é dividido em Sleipner Oeste e Leste, sendo que a produção do Sleipner Oeste apresenta conteúdos altos de CO2 para o mercado consumidor. O CO2 é entretanto separado e injetado numa grande formação salina localizada acima do campo Sleipner Leste, a cerca de 800 metros abaixo do fundo oceânico. O CO2 tem sido injetado para armazenamento permanente por mais de 22 anos em Sleipner, sendo este o primeiro projeto de captura e armazenamento de CO2 em larga escala no mundo. A Equinor Energy AS, empresa operadora, e empresas parceiras injetaram na Formação Utsira (depósitos marinhos do Miocénico) cerca de 18 milhões de toneladas métricas (Mt) de CO2 até ao final de 2018. A sequência de lutitos (shales) do Grupo Nordland depositada acima da Formação Utsira foi comprovada como uma rocha selante efetiva para o reservatório de armazenamento de CO2 (Singh et al., 2010). O reservatório Sleipner de armazenamento de CO2 é composto principalmente por arenitos mal consolidados com excelentes propriedades - porosidades em torno de 36% e permeabilidades em torno de 1 a 5 Darcy. Este reservatório está sob condições de pressão próximas a hidrostáticas, com salinidade das águas intra-formacionais com valores similares aos da água do mar. Desde o início do projeto em 1996, um programa intensivo de monitorização geofísica foi implementado. O Sleipner foi monitorizado com levantamentos geofísicos aproximadamente a cada 2 anos, o que permitiu a delineação de uma imagem detalhada da distribuição e dinâmica da pluma de CO2. No primeiro levantamento sísmico 4D (time-lapse seismic) em 1999, apenas 3 anos após o início da injeção, foram identificados 9 refletores com fortes contrastes de impedância acústica (bright reflectors), o que indica que o CO2 ascendeu verticalmente mais de 200 metros, do ponto de injeção até a rocha selante (caprock). A distribuição vertical da pluma de CO2 é evidentemente assimétrica e em camadas, indicativa do encontro e migração através de uma série de finas barreiras de shales (com cerca de 1 metro de espessura) dentro do reservatório. Estas finas camadas de shales que agiram como barreiras semi-permeáveis (baffles) à migração de CO2 foram identificadas em dados de poço mas, com exceção da unidade Thick Shale (com cerca de 6.5 metros de espessura) que separa a Formação Utsira da unidade arenosa Sand Wedge localizada logo abaixo da rocha selante, não foi possível realizar uma correlação devido às grandes distâncias entre os poços nem identificá-los na sísmica devido à resolução. Estima-se que cada camada de CO2 apresentará espessuras entre 7 e 20 metros, com extensão lateral de 1 a 3 quilómetros (Cavanagh et al., 2015). Cada camada de CO2 apresenta um pronunciado alongamento na direção norte-sul, indicativo da forte influência da topografia da rocha selante e da unidade Thick Shale. A migração vertical do CO2 é resultante do grande contraste entre as densidades da água (presente nos poros da formação rochosa, brine) e do CO2. Quando o CO2 atinge uma barreira com rochas de baixa permeabilidade, ele acumula-se abaixo desta barreira, com o preenchimento de pequenas armadilhas ou estruturas (traps) em conformidade com sua topografia. O CO2 migra através destas barreias de baixa permeabilidade quando a pressão exercida pelo fluido de CO2 supera a pressão limite para invasão do CO2 (threshold ou displacement pressures) da rocha de baixa permeabilidade. Amostras de testemunho e cuttings da rocha selante (caprock) acima do reservatório indicaram pressões limite para invasão do CO2 de cerca de 1.7 MPa. Para o CO2 conseguir migrar através das camadas de shales do reservatório e formar uma pluma composta por um empilhamento vertical de camadas finas, as pressões limite para invasão do CO2 precisam de ser significativamente menores que o valor indicado pelas amostras da rocha selante. Apesar da alta qualidade das imagens da distribuição espacial da pluma de CO2 em Sleipner, adquiridas por levantamentos sísmicos 4D, até hoje nenhum modelo dinâmico publicado reproduziu com sucesso a morfologia em camadas ou o comportamento do fluxo da pluma de CO2. Isto é devido aos desafios relacionados com a física inerente aos fluxos de CO2 e às incertezas relacionadas com as interpretações geológicas. A Equinor publicou anteriormente modelos do reservatório Sleipner de armazenamento de CO2, para referência da comunidade científica, com foco na camada superior da pluma, uma vez que as interpretações das estruturas correspondentes ao topo do reservatório foram realizadas no levantamento sísmico 3D, com menos incertezas relacionadas com os efeitos do CO2 (Singh et al., 2010). A presente Tese de Mestrado definiu o modelo do reservatório completo com a incorporação das 9 camadas de CO2 para analisar os fatores principais que controlam o fluxo dominado por gravidade em reservatórios de armazenamento de CO2, com base em suposições de acordo com Cavanagh et al. (2015). Alguns aspectos fundamentais da pluma permanecem incertos, tais como a espessura das camadas (dependentes das pressões limite para invasão do CO2 das unidades shale), o perfil de temperatura da pluma (o qual impacta as densidades do CO2) e a saturação em gás das camadas da pluma (parâmetro difícil de distinguir acima de 30%). Estas incertezas são devidas às características intrínsecas da monitorização sísmica remota e da ampla variação possível dos parâmetros pressão, temperatura e saturação num reservatório (Cavanagh & Haszeldine, 2014). O desenvolvimento desta Tese de Mestrado incorporou a construção de dois modelos principais do reservatório de CO2 Sleipner no software Permedia, um com uma abordagem simples e o outro baseado em mapas. A abordagem simples consistiu na definição de valores constantes para as propriedades do reservatório, enquanto a abordagem por mapas definiu distribuições laterais para as propriedades das rochas do reservatório conforme a distribuição espacial das camadas de CO2 observada em sísmica com significativo alongamento norte-sul. O método de percolação por invasão (invasion percolation) foi aplicado para simular a migração de CO2, o qual assume um fluxo dominado pelas forças da gravidade e da capilaridade sobre a viscosidade, de modo similar ao processo interpretado para o reservatório Sleipner. As pressões limite para invasão do CO2 (threshold ou displacement pressures) foram estimadas por experimentação, através da sistemática redução do valor medido nas amostras da rocha selante até que a distribuição das 9 camadas de CO2 empilhadas verticalmente fosse reproduzida. As pressões limite para invasão do CO2 (threshold ou displacement pressures) efetivas para as unidades intra-shales e as correspondentes permeabilidades indicaram que seus valores reduzidos poderiam ser devidos a uma maior dimensão da generalidade das gargantas dos poros (pore throat sizes), associada à presença de shales mais ricas em silte. Uma análise de sensibilidade dos parâmetros com alta incerteza - temperatura (e consequentes densidades de CO2) e saturações do CO2 - foi realizada para avaliar os seus impactos na migração de CO2 e identificar os fatores-chave que contribuem para a distribuição da pluma de CO2 em múltiplas camadas. Estudos futuros devem investigar outros modelos possíveis, especialmente com a incorporação de áreas com alta permeabilidade interpretadas como “chaminés” (chimneys, leakage points) em sísmica.

This Ph.D. research project targets Cooper Basin oil reservoirs of very low permeability (approximately 1mD) where injectivities required for water flooding are not achievable. However, the use of injection gases such as CO₂ would not have injectivity problems. CO₂ is abundant in the region and available for EOR use. CO₂ was compared to other CO₂-rich injection gases with a hydrocarbon content including pentane plus components. While the effect of hydrocarbon components up to butane have been investigated in the past, the effect of n-pentane has on impure CO₂ gas streams has not. One particular field of the Cooper Basin was investigated in detail (Field A). However, since similar reservoir and fluid characteristics of Field A are common to the region it is expected that the data measured and developed has applications to many other oil reservoirs of the region and similar reservoirs elsewhere. The aim of this Ph.D. project is to determine the applicability of CO₂ as an injection gas for Enhanced Oil Recovery (EOR) in the Cooper Basin oil reservoirs and to compare CO₂ with other possible CO₂-rich injection gases. The summarised goals of this research are to: • Determine the compatibility of Field A reservoir fluid with CO₂ as an injection gas. • Compare CO₂ to other injection gas options for Field A. • Development of a correlation to predict the effect of nC₅ on MMP for a CO₂- rich injection gas stream. These goals were achieved through the following work: • Extensive experimental studies of the reservoir properties and the effects of interaction between CO₂-rich injection gas streams and Field A reservoir fluid measuring properties related to: • Miscibility of the injection gas with Field A reservoir fluid • Solubility and swelling properties of the injection gas with Field A reservoir fluid • Change in viscosity-pressure relationship of Field A reservoir fluid due to addition of injection gas • A reservoir condition core flood experiment • Compositional simulation of the reservoir condition core flood to compare expected recoveries from different injection gases • Development of a set of Minimum Miscibility Pressure (MMP) measurements targeted at correlating the effect of nC₅ on CO₂ MMP. The key findings of this research are as follows: • Miscibility is achievable at practical pressures for Field A and similar reservoir fluids with pure CO₂ or CO₂-rich injection gases. • For Field A reservoir fluid, viscosity of the remaining flashed liquid will increase at pressures below ~2500psi due to mixing the reservoir fluid with a CO₂-rich injection gas stream. • Comparison of injection gases showed that methane rich gases are miscible with Field A so long as a significant quantity of C₃+ components is also present in the gas stream. • There is a defined trend for effect of nC₅ on MMP of impure CO₂. This trend was correlated with an error of less than 4%. • Even though oil composition is taken into account with the base gas MMP, it still affects the trend for effect of nC₅ on MMP of a CO₂-rich gas stream. • An oil characterisation factor was developed to account for this effect, significantly improving the results, reducing the error of the correlation to only 1.6%. The significance of these findings is as follows: • An injection pressure above ~3000psi should be targeted. At these pressures miscibility is achieved and the viscosity of the reservoir fluid injection gas mix is reduced. • CO₂ should be compared to gases such as Tim Gas should after considering the cost of compression, pipeline costs and distance from source to destination will need to be considered. • The addition of nC₅ will reduce the MMP and increase the recovery factor, however the cost of the nC₅ used would be more than the value of increased oil recovered. • The developed correlation for the effect of nC₅ on impure CO₂ MMP can be used broadly within the limits of the correlation. • Further research using more oils is necessary to validate the developed oil characterisation factor and if successful, using the same or similar method used to improve other correlations.
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Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2009.