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.

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.

Carbon Capture and Storage (CCS) technology could help reduce anthropogenic CO2 emissions to the atmosphere. So far, CCS has failed to attract government support in the UK due to high costs of implementation. The broad deployment of CO2-EOR could aid the development of CCS by providing additional revenue streams for investors. The success of the CO2- EOR in the United States has raised the question of whether this success could be replicated in the UKCS. This thesis answers these questions by introducing two distinct models, which analyse the similarities and differences between the two oil provinces from the subsurface and economic perspectives. The first model integrates into the economic framework the behaviour of oil and CO2 in a reservoir. The model is applied to an oil field in the North Sea. It analyses whether the screening criteria developed based on the onshore US experience to screen for oil field candidates for the CO2 would be suitable for the oil fields in the UKCS. The second model is a theoretical CO2-EOR with storage model, which analyses how the inclusion of permanent storage changes the economics of CO2-EOR. The CO2-EOR with storage model allows for an endogenous switching point between the CO2-EOR and the permanent CO2 storage phase depending on the various economic factors, such as oil prices, sequestration subsidies and fees, CO2 price, and oil and gas tax rates. The CO2-EOR with storage model shows different behaviour compared to the case without permanent storage. On the policy level, the main difference between the two countries revealed that the UK strongly focuses on cutting CO2 emissions while the U.S. on boosting domestic oil production. Therefore, the third study in this thesis investigates the net carbon footprint of the CO2-EOR activity in the North Sea.

Carbon dioxide enhanced oil recovery (CO2EOR) is a proven and available technology used to produce incremental oil from depleted fields. Although this technology has been used successfully onshore in North America and Europe, projects have maximised oil recovery and not CO2 storage. While the majority of onshore CO2EOR projects to date have used CO2 from natural sources, CO2EOR is now more and more being considered as a storage option for captured anthropogenic CO2. In the North Sea the lack of low cost CO2, in large volumes, has meant that no EOR projects have utilised CO2 as an injection fluid. However CO2EOR has the highest potential of all EOR techniques to maximise recovery from depleted UK oil fields. With the prospect of Carbon Capture and Storage (CCS) capturing large tonnages of CO2 from point source emission sites, the feasibility of CO2EOR deployment in the North Sea is high. This thesis primarily aims to address a number of discrete issues which assess the effectiveness of CO2EOR to both produce oil and store CO2. Given the fundamental shift in approach proposed in North Sea CO2EOR projects, the carbon balance of such projects is examined. Using a life cycle accounting approach on a theoretical North Sea field, we examine whether offshore CO2EOR can store more CO2 than onshore projects traditionally have, and whether CO2 storage can offset additional emissions produced through offshore operations and incremental oil production. Using two design scenarios which optimise oil production and CO2 storage, we find that that net GHG emissions were negative in both ‘oil optimised’ and ‘CO2 storage optimised’. However when emissions from transporting, refining and combusting the produced crude oil are incorporated into the life cycle calculations the ‘oil optimised scenario’ became a net emitter of GHG and highlights the importance of continuing CO2 import and injection after oil production has been maximised at a field. This is something that has not traditionally occurred. After assessing rates of flaring and venting of produced associated gas at UK oil fields it is found that the flaring or venting of reproduced CH4 and CO2 has a large control on emissions. Much like currently operating UK oil fields the rates of flaring and venting has a control on the carbon intensity of oil produced. Here values for the carbon intensity of oil produced through CO2EOR are presented. Carbon intensity values are found to be similar to levels of current UK oil production and significantly lower than other unconventional sources. As well as assessing the climate benefits of CO2EOR, a new assessment of CO2EOR potential in Residual Oil Zones (ROZ) is also made. ROZ resource, which is thought to add significant potential to both the oil reserves and CO2 storage potential in some US basins, is here identified in the North Sea for the first time. Based on the foundation of North Sea hydrodynamics study, this thesis identifies the Pierce field as a candidate ROZ field where hydrodynamic tilting of the oil water contact has naturally occurred leaving a zone of residual oil. To test the feasibility of CO2EOR in such a zone a methodology is presented and applied. Notably the study highlights that in this case study recoverable reserves from the ROZ may approach 20% of total field recoverable reserves and have the capability to store up to 11Mt of CO2. While highlighting the CO2EOR potential in the ROZ the thesis discusses the importance in expanding the analysis to quantify its importance on a basin scale. Discussion is also made on whether new resource identification is necessary in a mature basin like the North Sea. With CO2EOR being considered as a feasible option for storing captured anthropogenic CO2, it is important to assess the security of storage in CO2EOR. Using real geochemical and production data from a pilot CO2EOR development in Western Canada two approaches are used to assess the partitioning of CO2 between reservoir fluids through time. Using a number of correlations it is found that CO2 dissolution in oil is up to 7 times greater than in reservoir brine when saturations between the two fluids are equal. It is found that after two years of CO2 injection solubility trapping accounts for 26% of injected CO2. The finding that significantly more dissolution occurs in oil rather than brine indicates that CO2 storage in EOR is safer than in brine storage. However a number of factors such as the increase in oil/CO2 mobility due to CO2 injection is also discussed. The overall conclusion from the work is that CO2EOR in the North Sea has the potential to be an effective way of producing oil and storing CO2 in the North Sea. A number of design, operational and accounting factors are however essential to operate an exemplar CO2EOR project where low carbon intensity oil can be produced from a mature basin while storing large tonnages of captured anthropogenic CO2.