The prediction of residual oil saturation (Sor) and relative permeabilities after waterflooding in mixed-wet systems is a very challenging task. These are important parameters which must be estimated for a full field simulation of waterflooding. The Sor also defines the target oil for any proposed EOR process after an initial waterflood. Pore-scale network modelling can be used to estimate relative permeabilities, and the amount and nature of the trapped residual oil if the correct physics of oil displacement are properly included. During the waterflooding of mixed-wet systems, oil may drain down to relatively low residual saturations. Such Sor levels can only be calculated correctly when oil layers in pore corners are included in the pore-scale modelling. van Dijke and Sorbie (J. Coll. Int. Sci. 293 (2006) 455) obtained an accurate thermodynamically derived criterion for oil layers’ existence in pores with non-uniform wettability caused by ageing, which is more restrictive than the previously used geometrical layer existence criterion. This thermodynamic criterion has been included in a newly developed two-phase pore network model to calculate realistic Sor values for mixed-wet sandstones. A new ncornered star pore shape characterization technique has also been implemented in this model since the precise description of the pore shape was found to be important. Two unstructured networks, derived from Berea sandstone have been used for a number of sensitivities of the Sor and relative permeabilities with respect to wettability conditions. It is shown that Sor is lower for the more strongly oil-wet cases, while the water relative permeability curves increase gradually with oil-wetness at the higher water saturations. It has also been shown that pore shape approximations and oil layers collapse criterion have a significant impact on the Sor and the relative permeabilities. In particular, the thermodynamic oil layer existence criterion gives higher and more realistic Sor compared to previously used geometrical criterion. The network modelling has been used to match experimental data for water-wet and mixed-wet systems. In particular, the good agreement with mixed-wet systems strongly indicates that using the correct oil layer existence criteria is a significant step forward in the reliable prediction of Sor.

Fluid flow and transport in fractured geological formations is of fundamental socio-economic importance, with applications ranging from oil recovery from the largest remaining hydrocarbon reserves to bioremediation techniques. Two mechanisms are particularly relevant for flow and transport, namely spontaneous imbibition (SI) and hydrodynamic dispersion. This thesis investigates the influence of SI and dispersion on flow and transport during immiscible two-phase flow. We make four main contributions. Firstly, we derive general, exact analytic solutions for SI that are valid for arbitrary petrophysical properties. This should finalize the decades-long search for analytical solutions for SI. Secondly, we derive the first non-dimensional time for SI that incorporates the influence of all parameters present in the two-phase Darcy formulation - a problem that was open for more than 90 years. Thirdly, we show how the growth of the dispersive zone depends on the flow regime and on adsorption. To that end we derive the first known set of analytical solutions for transport that fully accounts for the effects of capillarity, viscous forces and dispersion. Finally, we provide numerical tools to investigate the influence of heterogeneity by extending the higher order finite-element finite-volume method on unstructured grids to the case of transport and two-phase flow.

Large quantities of oil usually remain in oil reservoirs after conventional water floods. A significant part of this remaining oil can still be economically recovered by Water- Alternating-Gas (WAG) injection. WAG injection involves drainage and imbibition processes taking place sequentially, hence the numerical simulation of the WAG process requires reliable knowledge of three-phase relative permeability (kr) accounting for cyclic hysteresis effects. In this study, the results of a series of unsteady-state two-phase displacements and WAG coreflood experiments were employed to investigate the behaviour of three-phase kr and hysteresis effects in the WAG process. The experiments were carried out on two different cores with different characteristics and wettability conditions, using a low IFT (interfacial tension) gas–oil system. The first part of this study, evaluates the current approach used in the oil industry for simulation of the WAG process, in which the two-phase relative permeability data are employed to generate three-phase kr values using correlations (e.g. Stone, Baker). The performance of each of the existing three-phase relative permeability models was assessed against the experimental data. The results showed that choosing inappropriate three-phase kr model in simulation of the WAG experiments can lead to large errors in prediction of fluid production and differential pressure. While some models perform better than others, all of the three-phase kr models examined in this study failed to adequately predict the fluid production behaviour observed in the experiments. The continued production of oil after the breakthrough of the gas, which was one of the features of gas and WAG injection experiments at low gas-oil IFT, was not captured with these models. The second aim of this research was to develop a method for obtaining the values of three-phase relative permeabilities directly from WAG core flood experiments. For this purpose, a new history matching method was devised based on a Genetic Algorithm to estimate three-phase kr from unsteady-state coreflood experiments. Based on this methodology, a three-phase coreflood optimizer was developed that generates best kr values by matching the experimentally obtained production and pressure data. First, the iii integrity of the developed software was successfully verified by using two sets of experimental three-phase kr data published in the literature. Then, the program was used to determine three-phase relative permeability of various cycles of the WAG experiments performed at different wettability conditions. Two key parameters affecting the WAG performance, including the hysteresis phenomena occurring between kr of the different WAG cycles and the impact of wettability of the rock, have been investigated. The data have been used to evaluate the existing hysteresis models published in the literature. Some of the shortcomings associated with the existing methods have been revealed and discussed. In the latter part of the thesis, a new methodology is proposed for modelling of threephase relative permeability for WAG injection. This approach addresses the hysteresis effects in the three-phase kr taking place during the WAG process and attempts to reduce the inadequacies observed in the existing models. The integrity of this technique has been validated against the three-phase kr data obtained from our WAG experiments.

The performance of barium sulphate oilfield scale inhibitors (SIs) is affected by a number of factors, including temperature, pH and brine composition. This thesis focuses mainly on the effect of varying brine composition – in particular, Ca2+ and Mg2+ divalent cations on SI inhibition efficiency (IE) and minimum inhibitor concentration (MIC) levels. The molar ratio of Ca2+/Mg2+ in field formation waters is known to vary widely and is typically between 1 and 10. Since Ca2+ tends to improve the performance of phosphonate scale inhibitors and Mg2+ “poisons” them, then the effect of Ca2+/Mg2+ ratio is of great practical importance in SI applications. This occurs since Ca2+ has the ability to be incorporated into the growing barium sulphate lattice whereas Mg2+ cannot. The effect of divalent ions on polymeric SIs is rather less and different SIs respond in different ways, as reported in detail here. In this work, the possible mechanisms of scale inhibition are discussed with regard to different generic SI types, e.g. sulphonated polymers, phosphonates, etc. A range of 9 phosphonate and 9 polymeric SIs are tested. The SIs tested are categorised into Type 1 and Type 2 scale inhibitors, with regard to their sensitivity to Ca2+ and Mg2+ cations. Furthermore, they are all sub-categorised into further sub-types – Type A and Type B – depending on their compatibility at higher levels of calcium, [Ca2+] = ~1000–2000ppm. At the end of this work, all SIs are given categorisation codes, e.g. Type 1A, Type 2B etc., depending on this classification. In series of additional experiments, the effect of varying pH on IE/MIC is examined; the degree of SI depletion from solution is monitored during static IE experiments (these are referred to as SI consumption experiments); and ESEM images and EDAX analyses of scale deposits are obtained. The relation between IE and SI chemical molecular structure is also explained. Of the SIs tested, only three are classed as Type 1 because MIC is primarily affected by BaSO4 Saturation Ratio, not molar ratio Ca2+/Mg2+. Conversely, the MIC of all other SIs tested is primarily affected by molar ratio Ca2+/Mg2+; these are classed as Type 2. There are notable differences between the SI consumption profiles ([SI] remaining vs. time) of Type 1 and Type 2 SIs. Generally Type 1 SIs are not consumed significantly and maintain good IE and a high % of SI in solution over long periods, e.g. 96 hours; whereas Type 2 species are consumed rapidly, sometimes to ~ 0% in solution and IE also declines rapidly. There are two exceptions to this general observation – HEDP and HPAA. Non-ICP analytical methods for SI assay, including C18/Hyamine and Pinacyanol techniques can be applied for the assay of non-ICP detectable SIs such as MAT during static IE/consumption experiments. The IE of all SIs depends on their chemical structure. Chemical structures of SI-metal complexes presented in this thesis illustrate that SI molecules containing multiple amino methylene phosphonate functional groups have the greatest tendency to be Type 1 (e.g. OMTHP, DETPMP, and PMPA). This relies upon the inclusion of nitrogen atoms within the main carbon chain of SI molecules.

It is commonly thought that unconformities may both cause reservoir deterioration by being highly cemented and therefore form low permeability zones, or they promote reservoir development by being associated with coarse-grained sediments that offer high permeability pathways for fluid flow. Unconformity surfaces play a significant role in sequence stratigraphy and correlation of parasequences. However, they are also of fundamental importance for understanding petroleum prospectivity in many sedimentary basins. They commonly promote diagenetic change and either enhance reservoir porosity in subcropping sedimentary layers through leaching or promote cementation to create low permeability, poorer quality reservoirs. This thesis reports the results of a systematic analysis at different scales of the Caledonian and Variscan Unconformities, the two most prominent unconformities affecting British Stratigraphy, to provide new insights for our understanding that the subcrop and supracrop of unconformities are important in controlling reservoir properties. The Base Devonian Unconformity outcropping onshore in the Siccar Point, Scotland, represents the most famous angular unconformity ("Hutton’s Unconformity") and provides an exceptionally well exposed, hitherto unrecognized, wadi channel. Application of a new technique - LiDAR laser scanner, shed new light on this world famous unconformity. By generating a three-dimensional model representing the surface, highly angular character of the unconformity and its controlling factor in the deposition and distribution of the overlying sediments could be reflected. Furthermore, evaluation of the Base Permian Unconformity (BPU) through integration of seismic, electrical well-log, outcrop and core data has afforded the opportunity to determine the effects that it has on highly prospective Carboniferous gas-reservoirs which have been sealed beneath its overlying sealing Lower Permian, Rotliegend Group, Silverpit Claystone Formation cover in the UK Southern North Sea (SNS). Conventional wisdom has polarised views and has been a part of an on-going debate with opinion divided as to whether reservoir properties are enhanced or not by the unconformity. Given the significance for exploration, appraisal and development of the prospective Carboniferous play fairway in the SNS, the research has attempted to resolve this issue through seismic interpretation of the BPU, stratigraphic assessment of supracropping horizons and the systematic sampling and analysis of all relevant field exposures and cored sections. The interpretation of high-fidelity 3D seismic data has also permitted the identification of areas of structural inversion and the presence of a suite of WNW-ESE striking, sub-vertical Tertiary igneous dykes. The zones of structural inversion and the transecting dykes both affect the Carboniferous sediments and the BPU affecting the reservoir quality by instigating additional, overprinting diagenetic changes and the compartmentalisation of the reservoirs.

The main concern in the monitoring of gas injection, exsolution and dissolution is the exact spatial distribution of the gas volumes in the subsurface. In principle, this concern is addressed by the use of 4D seismic data. However, it is recognised that the seismic response still largely provides a qualitative estimate of the moved subsurface fluids; exact quantitative evaluation of fluid distributions and associated saturations remains a challenge still to be solved. It is widely believed that a few percent of gas makes the pore fluid mixture very compressible, so that it cannot be distinguished from a more complete gas saturation using seismic techniques. However, because of the fact that a gas distribution viewed at the reservoir scale is distinctly different from that observed at the laboratory scale, conclusions from laboratory measurements may not, in fact, be wholly applicable. Indeed, it is found in this study that the main factor controlling the seismic response is gas thickness, whilst gas saturation per se remains approximately constant. Modelling studies show that, for thin reservoirs (less than tuning thickness), both timeshift and amplitude change attributes have a linear trend with gas volume. In theory, this conclusion does not apply to thick reservoirs, as the amplitude change then becomes non-linear. However, because thick reservoirs are normally combinations of intra reservoir sand and shale, it is anticipated that a linear amplitude response can still be expected in most reservoirs. Reservoir heterogeneity is observed to affect these results by less than 2%. In the modeling, a spurious deviation from linearity is evident with increasing simulation model cell size (especially the vertical dimension). The understanding above is applied to both timeshift and amplitude change attributes in a North Sea gas injection field. Here, seismic scale calibration coefficients are obtained by a volumetric method which aims to calculate gas volume maps using the 4D seismic attributes. The work reveals that the results from the two mapped attributes appear reasonably close but still have regions of disparity. Synthetic data based on the reservoir model and further analysis of the observed data have been able to replicate some of these differences and identify them as due to inter-layer wave interferences and 4D noise. Similar findings to the above also apply to gas exsolution, in which gas migrates after arriving at the critical gas saturation, and establishes two specific gas saturations in the ii reservoir: maximum gas saturation within the gas cap and critical or minimum gas saturation within the oil leg. On the other hand, for the reverse process, in which reservoir pressure builds up, it is noted that it is not only the fluid type that impacts the gas when it goes back into solution, but also other reservoir properties such as relative permeability curves, transmissibility, Kv/Kh, and the injection/production plan. The laboratory-proposed equations for calculation of solution gas oil ratio (Rs) and pressure dependency of the fluid and rock are found to be not directly valid in cases in which the reservoir pressure drops below the bubble point pressure. In this situation, gas evolves, migrates and alters the pressure dependency of the saturated rock and solution gas oil ratio. A compositional change of the gas and oil is found to occur with pressure drop. However, it is observed to have a negligible impact on the seismic domain. Finally, importance is drawn to the role of engineering principles when interpreting dynamic reservoir changes from 4D seismic data. In particular, it is found that, in clastic reservoirs, the principal parameters controlling mapped 4D signatures are not the pressure and saturation changes per se, but these changes scaled by the corresponding thickness (or pore volume) of the reservoir volume that these effects occupy. This understanding is validated both with numerical modelling and analytic calculation. This provides a basis for a linear equation that can readily and accurately be used to invert for pressure and saturation changes. The observed seismic data are then inverted for pressure and saturation changes using the principles above. The results show that the simulator does appear to predict the inverted seismic observations fairly accurately. However, there are also some noticeable differences which require some specific updates to the transmissibility multipliers (and hence barriers) and the net-to-gross distribution in the simulation model. This project reveals the ability of 4D seismic to quantitatively monitor the gas injection and exsolution, and highlights the fact that laboratory measures are not directly applicable at the reservoir scale. It can be concluded that the impact of the reservoir scale phenomena needs to be taken into account during time-lapse seismic interpretations.

One of the most common and efficient ways for preventing formation of inorganic solids deposition such as carbonate and sulphate scales in reservoir and near wellbore formation is by applying scale inhibitor (SI) squeeze treatments. The two main mechanisms that govern the scale inhibitor retention and release process in the formation are by adsorption/desorption and precipitation/dissolution. They are described by different but related modelling approaches, and there is not complete agreement in the literature about when to use one mechanistic description or another. The equilibrium adsorption isotherm determines the general nature and extent of the scale inhibitor return process in the low concentration flow regime. However, the additional SI “loading” within the near wellbore formation may be greatly enhanced by precipitation. The dynamic effects of adsorption and precipitation, also have a strong bearing on a field squeeze treatment and may significantly affect the profile of the inhibitor return curve. Field observations are not accurate enough to distinguish between different mechanisms and a detailed analysis of a given retention mechanism (e.g. pure adsorption or coupled adsorption/ precipitation) requires carefully designed laboratory experiments at the appropriate “field relevant” conditions. In this study, we present novel experimental techniques systematically from static to dynamic tests, as follows; 1. Static Adsorption/Compatibility Experiments – these experiments were conducted on two phosphonate scale inhibitors; namely DETPMP (a penta-phosphonate) and OMTHP (an hexa-phosphonate) using sand, kaolinite and siderite as the mineral phase. Adsorption experiments were carried out at a range of adsorbent mass/ fluid volume ratios (m/V), since this indicates whether we are in the purely adsorbing or in the coupled adsorption/precipitation regime. 2. Dynamic Sand Pack Experiments – based on the static tests, OMTHP scale inhibitor and sand mineral were selected for dynamic tests as it has the most clearly interpretable results. The experiments were conducted using a sand pack flow apparatus at different flow rates using identical procedures, which demonstrates the non-equilibrium effects which occur in both adsorption and precipitation treatments. iii The experimental results from static tests show excellent agreement with the theory in different regions of pure adsorption and coupled adsorption/precipitation. Whereas for dynamic sand pack experiments, the effect on post flush effluent inhibitor concentration is in the same direction for each system under test, i.e. reduced flow rate leads to higher effluent concentrations and vice-versa. These results also show clearly how such laboratory measurements should be carried out to determine both the levels of SI retention and the precise retention mechanism. The generated data from this work will be used as a basis to further develop existing coupled adsorption-precipitation () models within the Flow Assurance Scale Team (FAST) in Institute of Petroleum Engineering, Heriot-Watt University to improve the future prediction of scale inhibitor squeeze treatments.

The management of a petroleum reservoir requires good understanding of the geology and the properties of the reservoir. This understanding can be obtained from the analysis of results of down-hole tests and laboratory measurements. One of the properties that can be measured is the magnetic behaviour of the reservoir fluids and mineral scales. The build-up of scale is an important process in oil and gas reservoirs, and can have a damaging effect on the flow of fluid in reservoir rocks and in wells. An understanding of the magnetic properties of fluids such as brines, crude oils, brines with a scaling tendency, brines containing scale inhibitors, and of scale minerals is a key objective of this research. These magnetic techniques have the advantage of being environmentally neutral, nondestructive, rapid and low cost (Potter 2005). Understanding of the magnetic properties of the petroleum reservoir matrix rock may provide new techniques for improved reservoir characterisation, petroleum exploration and production. Magnetic susceptibility measurements of brines, crude oils and scale inhibitors have been carried out and are reported in this thesis. All fluids are diamagnetic, with distinct differences between them. The magnetic susceptibility values for brines are related to their solute composition, while for crude oils the magnetic susceptibility values are related to their physical and chemical properties. The effect of solute composition and concentration on the magnetic susceptibility of a brine is also measured. Measuring the magnetic susceptibility of a produced water sample would allow rapid detection of injection water breakthrough at the production facilities, and therefore iii improve the prospect of quickly deploying a preventative or remedial action to mitigate the risk of inorganic scale damage in the production system. The proposed method described herein introduces the potential for either an in line system, or at least an immediate analysis of the sample when captured, thus allowing operators to make important scale management decisions much earlier than is currently possible. Magnetic hysteresis measurements of reservoir scale minerals could be used as a rapid, non-destructive method to characterise and indentify the types of scale minerals occurring (diamagnetic, paramagnetic, ferromagnetic and antiferromagnetic). Changes in the slope (the magnetic susceptibility) of the hysteresis curves may be used to identify different scale minerals. Straight lines with negative slope are due to diamagnetic minerals, whilst straight lines with positive slope are due to paramagnetic minerals. The relative amounts of diamagnetic and paramagnetic minerals contained in a mixture of the two can potentially be quantified by the slope of the straight line at high fields.

The knowledge of reservoir fluids physical properties is crucial in upstream and downstream processes of petroleum industry. Viscosity and interfacial tension are among the most influential parameters on fluid behaviour. These properties have considerable effects on fluid flow characteristics and consequently in many oil and gas production and processing aspects from porous media to surface facilities. Hence, accurate estimation of the mentioned fluid properties plays a significant role in reservoir development. However, experimental data are scarce at high pressure and high temperature (HPHT) conditions. The work presented in this thesis is an integrated experimental and modelling investigation of viscosity and interfacial tension of petroleum reservoir fluids over a wide range of pressure and temperature conditions. Several series of experimental data on the viscosity of reservoir fluids were generated at high pressure and high temperature conditions (up to 20,000 psia and 200 °C). Experiments were conducted on three binary hydrocarbon systems and three synthetic and real multi-component mixtures, in addition to investigating the effect of dissolved water on the viscosity of the above fluids. Besides, the influence of oil-based mud filtrate on the viscosity of various dead oil samples also was studied as part of this thesis. The effect of different salt concentrations on the interfacial tension of gas-brine systems over a wide range of pressure and temperature conditions also was studied experimentally. The experimental data generated were employed to evaluate, improve and propose predictive models to estimate the mentioned physical properties. A new approach to retrieve the viscosity of original fluid (clean dead oil) from contaminated sample was introduced. Also a novel technique for predicting the gas-water (brine) interfacial tension was outlined. The proposed techniques and models were evaluated against independent experimental data generated in this work and the data gathered from open sources. Predictions of the developed methods were in good agreement with the experimental data.

Numerical experiments and field applications proved that there exist percolation non-linearity and fluid multi-variability in low permeability CBM reservoirs. The percolation of fluid needs to overcome threshold pressure gradient, and klinkenberg effects will restrict the gas permeability. In addition, production enhancement and ultimate recovery improvement have given multi-branch horizontal wells the advantage over the vertical wells in many CBM marginal reservoirs. Moreover, Enhance Coalbed Methane (ECBM) recovery through injection of gases has been publicly proven, and can increase gas resources, however, its application in some actual field failed to address the good history matching. In this thesis, the numerical simulation and well testing problems encountered in the reservoir exploration and production are investigated. Firstly, a new dual porosity, single permeability model was developed, which reflects the high velocity non-Darcy flow that considers the threshold pressure, gas slippage and matrix shrinkage effects. It is solved using the fully implicit numerical method, a computer programme called COAFOR has been developed for this purpose. Secondly, an advanced non-analytical coupled CBM model is developed for predicting the flux in the CBM reservoir and single or multi-branch wellbore simultaneously. Thirdly, a coupled compositional triple porosity horizontal wellbore model for CBM reservoir considering the gas slippage and threshold pressure gradient effects is proposed with a newly developed permeability model. The simulator, called TRIPLE-COAL, was developed for this model. Finally, the new models developed in this thesis are validated by applying them into Heshun block, Yanchun South block and Zhijin block respectively. The history matching results checked the reasonability and accuracy of the models built in this thesis. The coupled multi-branch horizontal triple porosity model shows better matching result in Zhijin block than the coupled multi-branch horizontal dual porosity model in Yanchuan South block.