The thesis, "Intelligent Fields Added Value Quantification and Real Time Value Creation", covers the "added value" evaluation process and a novel extension of the use of real time pressure data of Intelligent Fields. Intelligent well completion technologies add value via real time optimisation and provide flexibility for future well control. The correct "value adding" evaluation must be developed to become part of the general optimisation process. Hence understanding the value added, which is dependent on the three main factors of additional cost, reliability and equipment functionality. is key to the success of Intelligent Well Technology (I WT). This thesis explores the added value quantification criteria and develops a widely applicable software for quantifying the value added by Intelligent Well Technology and Sensor applications. The work explores and compares the various valuation criteria and their applicability to "Added Value from IWT" whilst modelling the application in various reservoir environments. The importance of the future equipment functionality in the value creation definition is investigated and rigorously factored into the value assessment. Current modelling and optimisation techniques were employed to show the values associated with intelligent completions and with various permanent downhole sensors. Appropriate use of intelligent production information is necessary to effectively contribute to improve operational performance. To achieve this, data driven management techniques such as Artificial Neural Network (ANN) with Wavelets and Time Series were used for the analysis of real time data to create the necessary information. Alternatively, a model driven approach (unlike NN "black" box) which considers the underlying physics of fluid flow in the reservoir and realistically captures the wellborereservoir flow processes is used to show that real time downhole pressure can detect the time and source of water influx into a multi-zone horizontal or near horizontal completion thus permitting a more rapid response to water breakthrough.

The Colorado Group mudstones within the Western Canada Sedimentary Basin (WCSB), have been characterised for their shale gas potential using a range of mineralogical, geochemical (LECO and Rock-Eval), and petrophysical (lithology, porosity, pore size distributions and microfabric) techniques in order to gain an understanding of the shales’ characteristics as suitable source rocks and reservoirs for shale gas. Semi-quantitative mineralogy of the shales was computed using a chemometric technique developed in this study, combining Attenuated Total Reflection Fourier Transform Infra-red Spectroscopy (ATR-FTIR) and multivariate Partial Least Squares (PLS) analysis. The technique estimates quartz, total clay (illite-smectite, kaolinite, chlorite) and total carbonate (calcite, dolomite) to within 5% absolute of true value and demonstrates potential application for high sample throughput and thus high density sampling strategies for ultra-high resolution or multi-well studies. The mineralogy of the Colorado Group shales shows that clay minerals dominate the composition of each Formation, followed by quartz. Minor amounts of calcite, dolomite and feldspars are also present. Grain size data indicate that the Colorado Group lithology consists of substantial amount of clay-grade plus fine silt materials dominated by grains <10μm deposited as floccules. Pore size distributions are predominantly unimodal with an average mean pore radius (rmean) value of 50nm, although some samples exhibit bimodal pore size distributions reflecting mixture of mudstones and silt size materials. The pore size distributions of the Colorado Group Formations are generally influenced by the relative percentages of clay and silt, as well as by the level of compaction. Clay-rich sediments tend to be unimodal with tight pore size distributions while sediments with both clay-sized and silt materials tend to have broader and occasionally bimodal pore size distributions. The unimodal porosity nature of the Colorado Group formations, and the dominance of clay-sized and silt sediments may promotes the adhesion of gas molecules, which makes these sediments optimal for gas adsorption. Integration of the various data revealed that the Colorado Group depositional system is complex with widely changing seaway conditions showing no simple correlations between mineralogy, grain size and organic facies, or their spatial variation from palaeosource. The presence of sands and reworked shell fragments indicate a dominantly advective transport of sediments within the Colorado Group. Mud and clay cements are observed throughout the Upper Colorado Group, whereas calcareous cements are present only within the Second White Specks Formation, Medicine Hat Member and First White Specks Member. Laminations of calcareous coccoliths within the Second White Specks Formation typically display calcite overgrowths. Calcite overgrowths are also observed within mudstones in the basal part of the Medicine Hat Member. Such differences in appearance show the occurrence of temporal and lateral facies changes; the presence of facies changes is an important factor that can affect shale gas production patterns within a single, seemingly laterally-continuous lithological unit. High TOC (>2wt. %) and Type II kerogen appear to indicate that biogenic gas may be a dominant component of the total gas-in-place in the Colorado Group. The Middle Carlile member is likely the best shale gas target within the Upper Colorado Group. The Carlile Formation and Verger Member also appear to have the highest sorption capacity, based on a dominant clay sized fractions. However, mudstones within all formations and members display moderate to high clay minerals (fluid sensitivity), have poor fraccability and contain clay and mud cements. The presence of muddy siltstone within Middle Carlile member and its high potential for gas adsorption is likely to make the unit a viable target for possible horizontal drilling for gas shale.

The study on caprock leakage in the North Sea consists of two aspects: first, leakage as Indicated by thermogenic wet gas, which was a survey study comprising the UK and Norwegian North Sea on fifty wells in forty fields. The second, a case study on Valhail well 2/8-8, which dealt with the geochemical evaluation of the caprock for leaked petroleum and the petrophysical characterization of the caprock. The result of the survey study indicate that thermogenic wet gas can serve as a reliable and diagnostic indicator of caprock leakage. High wet gas heights (i.e. ̲> lOOOm) were observed for fractured caprocks of high pore pressured reservoirs.

Water flooding has long since been used to increase oil production from fractured carbonate reservoirs. More recently steam injection has also been applied specifically to enhance oil recovery from fractured carbonate reservoirs containing heavy oil. Production simulation modelling provides a method to optimise these processes. However, such models do not generally consider the impact of steam injection on fracture permeability due to the lack of a quantitative understanding of the impact of thermal and chemical processes on fracture deformation and fluid flow. To help fill : this knowledge gap, a series of flow, loading and unloading experiments were performed on fractured and un fractured samples between ambient and 90°C. Loading fractured samples resulted in non-linear fracture closure. Unloading showed that some of the deformation was permanent. Fracture permeability was reduced dramatically as temperature was increased even when an unreactive mineral oil was used as the permanent while the confining pressure was kept constant. CT images showed that fracture apertures were dramatically reduced and contact areas increased during heating. The results indicate that this was caused by temperature weakening. Recirculation of reactive and equilibrated water through the fractures also resulted in a large reduction in fracture aperture probably as a result of dissolution and water weakening of the chalk. These thermal and water weakening effects have a far bigger impact on fracture permeability than simply loading and unloading the samples but are not accounted for in industry standard production simulation models. Finite element models, incorporating an elastoplastic constitutive model, were generated with fracture geometries based on the CT images obtained during the experiments. These models were able to reproduce the general behaviour of the fracture deformation observed in the experiments including both the nonlinearity and partial irreversibility of the process. These features could not be reproduced using a purely elastic model. The results are consistent with the idea that the contact asperities deformed by plastic deformation. These results suggest that the elastoplastic constitutive relationship probably provides a better tool to model the controls on fracture behaviour. Coupling this model with reservoir production simulation has the potential to improve the prediction of fluid flow in fractured carbonate reservoirs during steam injection. Keywords: Enhanced oil recovery, steam injection geomechanics fractured carbonate reservoirs.

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Polymer solution flow and retention through porous media is of interest to many applications in the oil industry such as drilling, water shut-off and enhanced oil recovery. Operators of mature oil and gas fields are faced with the problem of excessive water production (EWP), which can cause a premature abandonment of some oil and gas wells. It has been found that the injection of high molecular weight polymer solutions through the pay zones of the oil and gas wells would induce a sharp decrease of the water production without affecting the oil and gas production. This effect is called disproportionate permeability reduction (DPR) and the polymer solutions inducing such an effect are called relative permeability modifiers (RPM). Hence, the DPR effect has been utilized in the water shut-off or conformance control of oil and gas wells suffering from EWP. In spite of the extensive research of the DPR effect, there is still a lack of agreement on the mechanisms controlling such an effect and relatively high percentage failures are observed during conformance control field applications. Polymer retention in porous media has been attributed to mechanisms such as bridging-adsorption, adsorption-entanglement, and flow-induced adsorption. These mechanisms have been proposed to account for the increase in flow resistance during or after the flow of polymer solutions through porous media. The DPR effect has been attributed to effects induced by this retained polymer such as steric and lubrication effects, wettability change, segregated oil and water pathways, and swelling and shrinking of the adsorbed polymer layer. The aim of this study is to add knowledge on the effect of polymer solution flow on polymer retention in porous media. In this study, the rheology of high molecular weight polymer solutions was studied using a cone-and-plate setup. Moreover, the characteristics and the effective hydrodynamic thickness of adsorbed polymer layers on glass from these polymer solutions under static conditions were investigated using atomic force microscopy (AFM). Also, quartz crystal microbalance with the dissipation monitoring (QCM-D) was used to investigate the effect of increasing the flow rate of polymer solutions on the adsorbed amount on silica and gold surfaces. Additionally, the mobility reduction and the residual resistance as a result of polymer solution flow through single glass capillaries, 2D and 3D models of porous media were studied. The implementation of the above techniques was used to relate the microscopic effect of the flow of the polymer solutions to the polymer retention in the porous media. The anti-thixotropic behaviour of the polymer solutions, which can be attributed to the shearinduced formation of micron-size transient entanglement networks (TEN), is expected to play a major role in the polymer retention in porous media. These microscopic structures can adsorb on the solid surfaces if the adsorption energy of the polymer/solid system is sufficient. Also, in porous media in which mechanical entrapment is possible, these structures can be entrapped in the small pores and pore throats. Two new mechanisms for polymer retention are proposed in this study: transient-entanglement networks adsorption (TENA) and transient-entanglement networks entrapment (TENE). The TENA is the retention mechanism of the TEN structures in flow systems in which mechanical entrapment is not possible provided that the adsorption energy is sufficient. If mechanical entrapment is possible, then the retention by adsorption and mechanical entrapment are lumped in the TENE mechanism. The results from this study have given a new insight on the flow and retention of polymer solutions through porous media. Hence, it is believed that the improved understanding will improve the design of high molecular

This PhD project describes a high-resolution, three-dimensionanal model of two parasquence sets of the late Cretaceous Ferron Sandstone, a fluvial dominated deltaic reservoir analogue exposed in Utah, USA. The model was first used to quantify the facies architecture of this analogue and then as the reference to compare stochastic modelling techniques: 1) object based modelling (OBM); 2) sequential indicator simulation (SISIM); 3) multiple point statistics (MPS); and 4) spectral component geologic modelling (SCGM).

In order to ascertain whether kerogen and the heavy oil or bitumen generated during the initial stages of source rock maturation then go on to produce similar gas yields compared to the natural situation when they are present in source rocks, a study has been conducted on an immature type II Kimmeridge Clay Formation (KCF) source rock (Dorset, United Kingdom) with different total organic carbon contents (14, 25 and 30 % TOC), and all having an initial vitrinite reflectance (VR) of approx. 0.4 % Ro. Anhydrous and hydrous pyrolysis experiments were conducted on the whole immature source rock, the isolated partially matured bitumen-extracted source rock and the isolated bitumen (bitumen generated and extracted from the initial source rock) and mixtures of the isolated partially matured source rock and bitumen using two types of Hastalloy vessels (22 and 25 ml) at 320-420 °C for 7-48 h over a pressure range of 115-900 bar. Hydrocarbon gas yields and the increase in VR were greater from the whole rock experiments compared to the experiments on the isolated partially matured source rock and isolated bitumen (no mineral matter present), as well as the experiments on mixtures of the isolated partially matured isolated source rock and bitumen combined. The effect of particle size were also found to be of significance as higher gas yields were obtained from recombined mixture experiments using powdered samples (14 % TOC source rocks) compared to using rock chips (30 % TOC source rocks). Hydrocarbon gas yields, pyrobitumen yields, and VR values were found to decrease as pressure increases towards 500 and 900 bar compared to 180 bar at 350 °C where the effects of pressure retardation were found to be much more significant from the partially matured source rock maturation and bitumen in isolation than from the whole source rock. At 420 °C, gas generation, bitumen plus oil and coke yields were not affected by pressure, but VR decreases going from 310 bar to 500 and 900 bar. The results obtained demonstrate that the interplay of inherent mineral matter, reactant phase, source rock/kerogen, bitumen and pressure are key factors in determining the extent of hydrocarbon generation and source rock maturation in geological basins.