A numerical reservoir model was created to optimize CO₂ Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery treatment in which a well alternates between injection, soaking, and production. Injecting CO₂ into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator was used to study the various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical CO₂ injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO₂ to migrate deep into the formation and mix with the reservoir fluids. The discretization of the computational domain has a large impact on the simulation results, with coarser gridding corresponding to larger projected recoveries. Doubling the number of hydraulic fractures per stage results in considerably greater CO₂ injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO₂ Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO₂ and produced hydrocarbon gases was proven to be technically and economically viable, which could significantly improve profit margins of Huff-and-Puff operations. A substantial portion of this project involved studying alternative numerical methods for modeling hydraulically-fractured reservoir models. A domain decomposition technique known as mortar coupling was used to model the reservoir system as two individually-solved subdomains: fracture and matrix. A mortar-based numerical reservoir simulator was developed and its results compared to a tradition full-domain finite difference model for the Cinco-Ley et al. (1978) finite-conductivity vertical fracture problem. Despite some numerical issues, mortar coupling closely matched Cinco-Ley et al.'s (1978) solution and has potential applications in complex problems where decoupling the fracture-matrix system might be advantageous. / text

This laboratory project has been done to evaluate pressure pulsing as an Enhanced Oil Recovery (EOR) technique. To perform the study, a consistent laboratory methodology was developed, including the construction of a Consistent Pulsing Source (CPS). Tests compared pulsed and non-pulsed waterfloods in a paraffin or crude oil saturated medium, which also contained connate water (an irreducible water saturation). Results revealed that pulsed tests had maximum flow rates 2. 5--3 times higher, greater oil recovery rates, and final sweep efficiencies that were more than 10% greater than non-pulsed tests. The CPS design has proven very successful, and has since been copied by a major oil corporation. However, there are two limitations, both caused by fluctuating water reservoir levels. Longer pulsed tests (reservoir-depletion tests) were periodically paused to refill the water reservoir, resulting in reservoir depressurization and lower flow rates. The final effect of this was impossible to quantify without correcting the problem. The second CPS limitation was the change in pulse shape with time. However, it is not expected that this had any major effect on the results. The pulse pressure and period studies were limited by early tests, which did not have the necessary time duration. Both increasing pulse pressure and decreasing pulse period were found to increase the final sweep efficiency. Slightly decreasing porosity (0. 4% lower) was found to lower sweep efficiencies. However, the 34. 9% porosity results were not done until reservoir depletion, so it is difficult to quantitatively compare results. An emulsion appeared after water breakthrough when using the CPS on light oils (mineral oil). This may have been the result of isolated oil ganglia being torn apart by the sharp pulses. Although it is difficult to apply laboratory results to the field, this study indicates that pressure pulsing as an EOR technique would be beneficial. Doubled or tripled oil recovery rates and 10% more oil recovery than waterflooding would be significant numbers in a field operation. A valuable application would be in pulsing excitation wells to both pressurize the reservoir and enhance the conformance of the displacing fluid over a long-term period. It would also be valuable for short-term chemical injections, where mixing with the largest volume possible is desirable.

This thesis is concerned with the modelling of miscible fluid flow through porous media, with the intended application being the displacement of oil from a reservoir by a solvent with which the oil is miscible. The primary difficulty that we encounter with such modelling is the existence of a fingering instability that arises from the viscosity and the density differences between the oil and solvent. We take as our basic model the Peaceman model, which we derive from first principles as the combination of Darcy’s law with the mass transport of solvent by advection and hydrodynamic dispersion. In the oil industry, advection is usually dominant, so that the Péclet number, Pe, is large. We begin by neglecting the effect of density differences between the two fluids and concentrate only on the viscous fingering instability. A stability analysis and numerical simulations are used to show that the wavelength of the instability is proportional to Pe^−1/2, and hence that a large number of fingers will be formed. We next apply homogenisation theory to investigate the evolution of the average concentration of solvent when the mean flow is one-dimensional, and discuss the rationale behind the Koval model. We then attempt to explain why the mixing zone in which fingering is present grows at the observed rate, which is different from that predicted by a naive version of the Koval model. We associate the shocks that appear in our homogenised model with the tips and roots of the fingers, the tip-regions being modelled by Saffman-Taylor finger solutions. We then extend our model to consider flow through porous media that are heterogeneous at the macroscopic scale, and where the mean flow is not one dimensional. We compare our model with that of Todd & Longstaff and also models for immiscible flow through porous media. Finally, we extend our work to consider miscible displacements in which both density and viscosity differences between the two fluids are relevant.

Master of Science / Department of Geology / Abdelmoneam Raef / Advancements, applications, and success of time-lapse (4D) seismic monitoring of carbonate reservoirs is limited by these systems’ inherent heterogeneity and low compressibility relative to siliciclastic systems. To contribute to the advancement of 4D seismic monitoring in carbonates, an investigation of amplitude envelope across frequency sub-bands was conducted on a high-resolution 4D seismic data set acquired in fine temporal intervals between a baseline and eight monitor surveys to track CO₂-EOR from 2003-2005 in the Hall-Gurney Field, Kansas. The shallow (approximately 900 m) Plattsburg ‘C Zone’ target reservoir is an oomoldic limestone within the Lansing-Kansas City (LKC) supergroup – deposited as a sequence of high-frequency, stacked cyclothems. The LKC reservoir fluctuates around thin-bed thickness within the well pattern region and is susceptible to amplitude tuning effects, in which CO₂ replacement of initial reservoir fluid generates a complex tuning phenomena with reduction and brightening of amplitude at reservoir thickness above and below thin-bed thickness, respectively. A thorough analysis of horizon snapping criteria and parameters was conducted to understand the sensitivity of these autonomous operations and produce a robust horizon tracking workflow to extend the Baseline Survey horizon data to subsequent Monitor Surveys. This 4D seismic horizon tracking workflow expedited the horizon tracking process across monitor surveys, while following a quantitative, repeatable approach in tracking the LKC and maintaining geologic integrity despite low signal-to-noise ratio (SNR) data and misties between surveys. Analysis of amplitude envelope data across frequency sub-bands (30-80 Hz) following spectral decomposition identified geometric features of multiple LKC shoal bodies at the reservoir interval. In corroboration with prior geologic interpretation, shoal boundaries, zones of overlap between stacked shoals, thickness variation, and lateral changes in lithofacies were delineated in the Baseline Survey, which enhanced detail of these features’ extent beyond capacity offered from well log data. Lineaments dominated by low-frequency anomalies within regions of adjacent shoals’ boundaries suggest thicker zones of potential shoal overlap. Analysis of frequency band-to-band analysis reveals relative thickness variation. Spectral decomposition of the amplitude envelope was analyzed between the Baseline and Monitor Surveys to identify spectral and tuning changes to monitor CO₂ migration. Ambiguity of CO₂ effects on tuning phenomena was observed in zones of known CO₂ fluid replacement. A series of lineaments highlighted by amplitude brightening from the Baseline to Monitor Surveys is observed, which compete with a more spatially extensive effect of subtle amplitude dimming. These lineaments are suggestive of features below tuning thickness, such as stratigraphic structures of shoals, fractures, and/or thin shoal edges, which are highlighted by an increased apparent thickness and onset of tuning from CO₂. Detailed analysis of these 4D seismic data across frequency sub-bands provide enhanced interpretation of shoal geometry, position, and overlap; identification of lateral changes in lithofacies suggestive of barriers and conduits; insight into relative thickness variation; and the ability of CO₂ tuning ambiguity to highlight zones below tuning thickness and improve reservoir characterization. These results suggest improved efficiency of CO₂ -EOR reservoir surveillance in carbonates, with implications to ensure optimal field planning and flood performance for analogous targets.

Master of Science / Department of Geology / Abdelmoneam Raef / This study focuses on characterizing subsurface rock formations of the Wellington Field, in Sumner County, Kansas, for both geosequestration of carbon dioxide (CO₂) in the saline Arbuckle formation, and enhanced oil recovery of a depleting Mississippian oil reservoir. Multi-scale data including rock core plug samples, laboratory ultrasonic P-&S-waves, X-ray diffraction, and well log data including sonic and dipole sonic, is integrated in an effort to evaluate existing rock physics models, with the objective of establishing a model that best represents our reservoir and/or saline aquifer rock formations. We estimated compressional and shear wave velocities of rock core plugs for a Mississippian reservoir and Arbuckle saline aquifer, based on first arrival times using a laboratory setup consisting of an Ult 100 Ultrasonic System, a 12-ton hydraulic jack, and a force gauge; the laboratory setup is located in the geophysics lab in Thompson Hall at Kansas State University. The dynamic elastic constants Young’s Modulus, Bulk Modulus, Shear (Rigidity) Modulus and Poisson’s Ratio have been calculated based on the estimated P- and S-wave velocity data. Ultrasonic velocities have been compared to velocities estimated based on sonic and dipole sonic log data from the Wellington 1-32 well. We were unable to create a transformation of compressional wave sonic velocities to shear wave sonic for all wells where compressional wave sonic is available, due to a lack of understandable patterns observed from a relatively limited dataset. Furthermore, saturated elastic moduli and velocities based on sonic and dipole sonic well logs, in addition to dry rock moduli acquired from core plug samples allowed for the testing of various rock physics models. These models predict effects of changing effective (brine + CO₂ +hydrocarbon) fluid composition on seismic properties, and were compared to known values to ensure accuracy, thus revealing implications for feasibility of seismic monitoring in the KGS 1-32 well vicinity.

Gas injection, the fastest growing tertiary oil recovery technique, holds the promise of significant recoveries from those depleted oil reservoirs around the world which fall into a pressure range of (50-200) bar mainly. However, its application with the usual techniques is restricted by the need for various surface facilities such as enormous gas supply and storage. The only surface facility that downhole gasification of hydrocarbons (DHG) requires, on the other hand, is a portable electricity generator. DHG consists in producing inert gases, H2, CO, CO2 and CH4 through the steam reforming reaction of a part of the produced oil in a gasifier-reformer reactor positioned alongside the producer well in the reservoir. The gases, mainly H2 -the most effective displacing gas among produced gases- are injected into a gas cap above the oil formation, to increase oil recovery through a gas displacement drive mechanism. So far, DHG has only been tested under laboratory conditions using methane, pentane/reservoir gas and naphtha/reservoir gas as feedstock at conditions of reservoir pressure up to 130 bar. The studies varied reaction temperature, steam to carbon (S/C) ratio, catalyst types and catalyst loading in the gasifier-reformer reactor of a small pilot scale rig. These experimental studies demonstrated that pressure is one of the main factors influencing the effectiveness of the DHG process. From this starting point, the present investigation was directed at extending the pressure range up to 160 bar in the gasifier-reformer reactor using a naphtha fraction as feedstock in order to investigate whether the conversion and H2 concentration in produced dry gas can be maintained at acceptable levels under conditions of high pressure. To this end, experimental studies were carried out within the laboratory using the existing DHG rig on the small pilot scale, which was successfully commissioned and revamped for the purposes of this study. Initially, the investigation focused on exploring operating conditions, namely, steam to carbon (S/C) ratio, length of the gasifier-reformer reactor tube/ catalyst loading and the relative performance of two different catalysts. Subsequently, experiments on shutdown/start up cycles followed by variation of temperature were performed to simulate the effect of sudden electrical disruptions that usually occur in field operations. Experimental results using naphtha at pressure from 80 to 160 bar at 650 ºC, S/C= 6 achieved total feedstock conversion, no coke deposits and, most importantly, high H2 concentration in the produced dry gas (56-63 vol. % plus other gases). The best result was obtained with a crushed HiFUEL R110 catalyst (40-60 wt. % of NiO/CaO.Al2O3) and a reactor tube length of 72 cm, but the results with a C11-PR catalyst (40 wt. % of NiO/MgO.Al2O3) and a reactor tube length of 30 cm were similarly favourable. These results were supported by results of a numerical DHG model which indicated total feedstock conversion and values of H2 around 67 vol. % (using n-heptane as model surrogate). The results suggest that the DHG process is technically feasible at the pressure values studied, perhaps up to 200 bar where there are many hundreds of depleted, light oil reservoirs, especially in North America and other parts of the world below that pressure value.

With conventional oil reserves in decline, energy companies are increasingly turning to enhanced oil recovery (EOR) processes to extend the productive life of oilfield wells. Laboratory-scale core floods, in which one fluid displaces another from the pore space of a rock core, are widely used in petroleum research for oilfield evaluation and screening EOR processes. Achieving both macro- and pore-scale understandings of such fluid displacement processes is central to being able to optimise EOR strategies. Many of the mechanisms at play, however, are still poorly understood. In this thesis nuclear magnetic resonance (NMR) has been used for quantitatively, non-invasively and dynamically studying laboratory core floods at reservoir-representative conditions. Spatially-resolved relaxation time measurements (L-T1-T2) have been applied to studying a special core analysis laboratory (SCAL) protocol, used for simulating reservoir oil saturations following initial oil migration (primary drainage) and characterising core samples (capillary pressure curves). Axial heterogeneities in pore filling processes were revealed. It was demonstrated that upon approaching irreducible water saturation, brine saturation was reduced to a continuous water-wetting film throughout the pore space; further hydrocarbon injection resulted in pore pressure rise and wetting film thinning. L-T1-T2 techniques were also applied to a xanthan gum polymer-EOR flood in a sandstone core, providing a continuous measurement of core saturation and pore filling behaviours. A total recovery of 56.1% of the original oil in place (OOIP) was achieved, of which 4.9% was from xanthan. It was demonstrated that deposition of xanthan debris in small pores resulted in small-pore blocking, diverting brine to larger pores, enabling greater oil displacement therein. L-T1-T2, spectral and pulsed field gradient (PFG) approaches were applied to a hydrolysed polyacrylamide (HPAM)-EOR flood in a sandstone core. A total recovery of 62.4% of OOIP was achieved, of which 4.3% was from HPAM. Continued brine injection following conventional recovery (waterflooding) and EOR procedures demonstrated most moveable fluid saturation pertained to brine, with a small fraction to hydrocarbon. Increases in residual oil ganglia size was demonstrated following HPAM-EOR, suggesting HPAM encourages ganglia coalescence, supporting the "oil thread/column stabilisation" mechanism proposed in the literature. NMR relaxometry techniques used for assessing surface interaction strengths (T1/T¬2) were benchmarked against an industry-standard SCAL wettability measurement (Amott-Harvey) on a water-wet sandstone at magnetic field strengths comparable to reservoir well-logging tools (WLTs). At 2 MHz, T1/T2 was demonstrated to be weakly sensitive to the core wettability, although yielded wettability information at premature stages of the Amott-Harvey cycle. This suggests the potential for NMR to deliver faster wettability measurements, in SCAL applications or downhole WLT in situ reservoir characterisation.

Este trabalho trata sobre o aproveitamento de reservas minerais através dos conceitos de completa extração e adequada utilização do minério, considerando estes conceitos como parte da gestão de recursos e reservas, e como elementos que poderão contribuir para o aumento da vida útil do empreendimento mineiro e para redução de custos unitários. A gestão de recursos e reservas, no universo da mineração, usualmente, tem foco na ativa descoberta, rigor na quantificação e caracterização do minério. A metodologia utilizada neste trabalho foca no aumento do aproveitamento das reservas minerais em função da identificação e redução de perdas na cadeia produtiva. Tais reduções deverão se aplicar para além da frente de extração do minério (frente de lavra), tratando em especial a questão da recuperação do bem de interesse presente no minério (bem mineral). Apontando no sentido da completa extração e adequada utilização do minério, as soluções propostas para redução das perdas se baseiam em ajustes de operações unitárias e na linearização e integração do aproveitamento do minério numa só cadeia de valor. Desta forma perdas de minério poderão ser transformadas em produto na mesma cadeia, ao invés de considerar aproveitamentos alternativos com diversificação de destinos e produtos. Como estudo de caso, se utilizou a industrialização do folhelho pirobetuminoso do Subgrupo Irati no estado do Paraná - Brasil, operado pela Petróleo Brasileiro S. A. - PETROBRAS. O folhelho pirobetuminoso, mas conhecido como xisto, é um minério cujo principal bem de interesse presente em sua composição é a matéria orgânica que quando decomposta termicamente produz óleo e gás. Para este aproveitamento do folhelho pirobetuminoso há uma cadeia produtiva com três grandes processos: mineração; tratamento de minérios e processamento. Sendo que, se tem associado a cada um destes processos, perdas de minério, que, se reduzidas, considerando o potencial energético e restrições para o processamento, implicam em maior aproveitamento das reservas minerais. / This work is about the use of mineral reserves through of the concepts of complete extraction and appropriate use of the ore, and considers these concepts as part of the management of resources and reserves, and also consider that these concepts help to increase the life of the venture mining and to reduce unit costs. The management of resources and reserves in the world of mining usually has focused on active discovery and accuracy in the quantification and characterization of the ore. The methodology used in this work focuses on increasing the use of mineral reserves according to the identification and reduction of losses in the productive chain of mining beyond the front of extraction of ore (front of mine), addressing in particular the question of the recovery of valuable mineral ore (mineral-ore). Pointing towards the complete extraction and appropriate use of the ore, the proposed solutions for reducing losses are based on adequacy of the unit operations and linearization and integration of the use of ore in a single value chain, so that losses of ore can be processed into product in the same chain instead of considering alternative uses with diversification of destinations and products. As a case study has the industrialization of the oil shale of the Subgroup Irati of the state Paraná - Brazil, operated by Petróleo Brasileiro S. A. - PETROBRAS. Oil shale is a ore whose mineral of interest in this composition is the organic matters that when thermally decomposed produces oil and gas. To achieve the production of oil and gas from the oil shale ore is subjected to three main processes within a supply chain: mining, ore processing and; processing. Since, it has been associated to each of these cases, loss of ore which reduced involve greater use of mineral reserves, considering the energy potential and limitations for the processing of oil shale.

This thesis presents results of a successful simulation study using CO2-EOR technique to enable production from an offshore heavy oil field, named here as Omega, which is located offshore West Africa at a water depth around 2000 m. The findings and contributions to knowledge are outlined below: 1. Long distance CO2 transportation offshore – The solution to the space and weight constraints offshore with respect to CO2-EOR, is a tie-back via long distance CO2 dense phase transportation from onshore to offshore. 2. Cold heavy oil production (CHOP) using CO2-EOR technique - Based on conditions investigated, Miscible Displacement was found to be more efficient for deepwater production. However, Immiscible Displacement can offer greater reliability with regards to CO2 sequestration. 3. CO2 sequestration during CHOP using CO2-EOR technique – Lower CO2 may be released post start-up operation, followed by gradual decline of CO2 retention after the production peak. CO2 retention increases with increasing reservoir pressure, starting with 17.7 % retention at 800 psig to 32.8 % at 5000 psig, based on peak production analysis. 4. Techno-economic Evaluation – Miscible displacement is asssociated with higher cash flow stream that extend throughout the lifetime of the asset due to continuous production while Immiscible Displacement has a longer payback period (in order of 22 years) due to the time lag between the CO2 injection and the incremental heavy oil production. 5. Mathematical Modelling – Improved mathematical models based on existing theories are proposed, to estimate the CO2 requirement and heavy oil production during CHOP using CO2-EOR technique, and to provide an operating envelope for a wide range of operating conditions. As part of further work, the proposed models will require more refinement and validation across a broad range of operating conditions, could be adapted and modified to increase its predictive capability over time.

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