Scale formation in the oilfield is considered to be one of the major problems associated with oil and gas production. This mineral scaling problem relates directly to the water produced in hydrocarbon production and the worldwide industry produces more than 10 times the volume of water than oil. Barium sulphate and calcium carbonate scales are the most common mineral scales found in oilfield operations. The formation of these scales may result in the blockage of tubulars or safety valves, the failure of ESPs (electrical submersible pumps) and in the blockage of rock pores (in the near wellbore formation), which will greatly reduce the well production. The most effective way to prevent the scale formation is to treat the near wellbore region of the producer wells with chemical scale inhibitors (SI). Chemical scale inhibitors are widely applied in the oil industry to prevent downhole scale formation in so-called squeeze treatments. A successful squeeze treatment can be defined by two attributes; one it must prevent scale crystal growth at sub-stoichiometric concentrations between 2–20 ppm and it must interact with the formation in such a way to give low concentration returns to provide longer squeeze lifetime, typically in the range of 3-12 months. Scale inhibitors are generally either phosphonate species or they are polymeric and both of these SIs can be applied as adsorption or precipitation squeeze treatments, depending on the mechanism of SI retention in the formation. Phosphino Poly-Carboxylic Acid (PPCA) is a well-known industry standard polymeric scale inhibitor which is often applied in precipitation squeeze treatments. In these, the PPCA forms a sparingly soluble complex with calcium ions, denoted PPCA_Ca. The research on PPCA precipitation processes described in this thesis aims to fully develop its potential to provide reliable and long-lived squeeze lifetimes. The objectives of this research are as follows: 1. To develop the full understanding of the Phase Envelop of PPCA. 2. To define the important role of the molecular weight (MW) and molecular weight distribution (MWD) of PPCA in the return curve in precipitation squeeze treatments. 3. To understand the dynamics of PPCA precipitation treatments in sand-pack floods carried out over a range of flow rates. 4. The development of a retention model based on the MWD of the precipitate/supernatant/stock for polymeric scale inhibitors. Static and dynamic lab tests were carried out at realistic reservoir conditions in order to understand the phase behaviour of PPCA, the solubility of the precipitated PPCA_Ca complex and why/how the precipitated polymeric species performed better than the stock. All of the parameters governing the phase behavior have been studied and reviewed as they relate to the MWD of PPCA in precipitation or phase separation squeeze treatments. These processes rely upon the interaction of the inhibitors with metal cations such as calcium (Ca2+), pH and temperature. The non-equilibrium dynamic sand-pack floods suggest that the reduced flow rate leads to higher effluent concentrations and vice-versa. The static and dynamic results from this work will be used to develop improved models of coupled adsorption/precipitation and inhibition efficiency (IE) for polymeric scale inhibitors. These models will be incorporated into future field squeeze design models for adsorption/precipitation (Γ/Π) processes using polymeric scale inhibitors such as PPCA. It is believed that these results are the most detailed to be published in the literature on the PPCA system applied as a precipitation processes and that they are of particular significance and application for all polymeric scale inhibitor precipitation squeeze treatments.

The biodegradation of sites co-contaminated by organic pollutants and Heavy Metals is often a challenge due to the inhibition of microbial activities. Microbes play important role in the mineralization of petroleum hydrocarbons to CO2 by utilizing petroleum hydrocarbons as a carbon/ energy source. Heavy metals are often constituents of petroleum. Petroleum spills may result to the release associated metals (e.g. Ni, Cd, Pb, As) into the environment. Subsequent spills may cause an increase in metal concentrations in soils that may build to concentrations above intervention values. This may result to the inhibition of important biological activities such as the biodegradation of organic contaminants. This research investigates the effects of Ni, Cd and Pb contamination on biodegradation of petroleum hydrocarbons in complex soil system using a microbiological approach combined with geochemical approach. Such an approach will provide a more detailed understanding of the patterns of oil degradation under different and increasing metal stresses and how microbial communities change in such environments. Results indicated that Ni has stimulatory or no effects on biodegradation of petroleum hydrocarbons in soils depending on the chemical form of added Ni. The stimulatory effect was observed in Ni-Porphyrin contaminated soils and declined with increasing Ni concentration. In NiO soils, no effects occurred at low concentrations and increased concentration of Ni resulted to increased inhibition of biodegradation. This is unlike NiCl2 amended soils where Ni effects on biodegradation were neutral irrespective of Ni concentration. The microbial diversity study of the microbial soil community indicated that there was a selective enrichment of species in the soil communities. Phylogenetic study indicated that the dominant microorganism in the community is a strain of Rhodococcus (100%), which was closely related to most Rhodococcus strains isolated from hydrocarbon-contaminated environments, metal contaminated environments and extreme environments. Results indicated that Cd inhibited biodegradation of crude oil in soils, irrespective of Cd form or concentrations. The inhibitory effect increased with increasing concentrations. Also, the microbial diversity study of the microbial soil community indicated that there was a selective enrichment of species in the soil communities. Similar to Ni, Phylogenetic study indicated that the dominant microorganism in the community is a strain of Rhodococcus. Also biodegradation of petroleum was significantly reduced in crude oil degrading short-term Pb contaminated soils, irrespective of Pb form or concentration. However, in long-term Pb contaminated soils, while maximal rate of petroleum degradation reduced at high- Pb concentration, no effect was observed at low lead concentration. Also, the microbial diversity study of the microbial soil community indicated that there was a selective enrichment of species in the soil communities. Two dominating specie were identified in Pb-soils depending on soil. Both are closely related to a strain belonging to Bacillales that were originally isolated Rock, Scopulibacillus darangshiensis strain (98%) and oil contaminated soil Bacillus circulans (99%). While the former dominated in Pb -short-term contaminated soils as well as Pb-long term contaminated soil at high concentration, the later dominated long-term-Pb contaminated soil at low concentration.

A number of recent giant gas discoveries offshore Levant and in the Nile Delta have established the eastern Mediterranean as a major hydrocarbon province. Future exploration success will rely heavily on a detailed understanding of the regional tectonostratigraphic evolution of the basin. Critical inputs to reservoir, charge and trap modelling such as rifting age, rifting direction and the distribution of oceanic versus continental crust are poorly constrained. Additionally, the impact on the petroleum system of the sudden and significant drop in Mediterranean sea level during the Messinian Salinity Crisis in the Late Miocene, has been largely overlooked. In order to address these fundamental research issues, I conduct a detailed interpretation of an unprecedented coverage of regional two-dimensional (2D) deep reflection seismic lines from the eastern Mediterranean. Importantly, the structural and stratigraphic interpretation has been calibrated with borehole data from the margins of the basin. The seismic interpretation aims primarily to map the rifting direction and document key seismic observations that provide insights to the nature of the crust. A reverse subsidence modelling technique has been used to constrain the age of rifting using palaeo-water depth calibration data from both well data and seismic facies analysis. I also carried out flexural backstripping analysis and 2D petroleum system modelling to investigate the impact of the Messinian Salinity Crisis on the hydrocarbon habitat. The main conclusion of this study is that the eastern Mediterranean opened in response to Early-to-Mid Jurassic, NW-SE directed extension along a series of NE-SW trending normal and NW-SE trending transfer faults. The majority of the basin is predicted to be underlain by highly extended continental crust except offshore northern Levant where evidence suggests a remnant of neo-Tethyan oceanic crust is preserved to the south of the Cyprus subduction zone. The result also predicts that the Messinian Salinity Crisis was associated with a ca. 2070 m drop in sea level. This likely encouraged salt deposition producing a pronounced effect on the basin morphology and subsurface pressure and temperature equilibrium conditions. The 2D petroleum system model predicts that changes in pore pressure will lead to hydrocarbon phase changes within reservoir intervals. The impact of this phase change on the pre-existing hydrocarbon accumulations is controlled by the charge, trap size and the seal parameters - which in the worst case can lead to catastrophic trap integrity failure.

Asphaltenes are the heaviest and most complex components in crude oil. Their precipitation and deposition may cause severe problems during production, transportation and processing of crude oil, hence affecting efficiency and cost of production in both upstream and downstream operations. During crude oil production, asphaltenes can deposit in the pores of reservoir rocks resulting in formation damage. Despite significant research, asphaltene behaviour in different flow regimes remains elusive. This thesis presents an investigation into crude oil asphaltene precipitation and deposition at ambient and reservoir conditions, using different experimental techniques and multi-scale simulations. Asphaltene precipitation can be triggered by altering the crude oil composition, which has been studied here through filtration experiments; a useful method to determine the amount of asphaltene precipitation induced by any precipitant. The relationship between the mass of precipitated asphaltenes and the mass of a precipitant in a crude oil+hydrocarbon system was compared to a crude oil+CO2 mixture in high pressure-high temperature experiments under conditions where the assumption of full miscibility is not valid. The precipitation onset point for the heavy crude oil used throughout the study was precisely determined in terms of the Hildebrand solubility parameter, showing for the first time that CO2 follows the same behaviour as hydrocarbon precipitants. However, the solubility parameter was not suitable for correlating precipitation at different temperatures. Subsequently, this work reports on asphaltene deposition in glass capillary flow experiments under laminar conditions where asphaltenes were precipitated with n-heptane, an analogue fluid for CO2. This study elucidates the fundamental behaviour of asphaltene deposition through the unique combination of techniques not previously been illustrated in the literature. The experiments involved co-injecting a toluene diluted crude oil and n-heptane through a capillary at constant volumetric flow rate while simultaneously measuring the pressure drop across the capillary. Increasing the total volumetric flow rate led to more deposition, observed through confocal laser-scanning microscopy and mass measurements, with more deposits build up at the capillary inlet. Beyond a critical flow rate, the deposition rate decreased as entrainment effects became more profound. Deposition was limited as the pressure levelled off in all the experiments, and oscillations in pressure suggested dynamic cycles between deposition and entrainment. In addition, a dependence of deposition on the floc size was revealed, showing that smaller particles dominate the deposition process. The experimental results were then compared to stochastic rotation dynamics simulations at the colloid scale, where a constant pressure drop over the capillary length was imposed. Results show a more homogeneous deposition profile with higher Peclet number, which is in agreement with the experimental findings. Additionally, deposition studies were extended to real sandstone reservoir samples using C7 and CO2 as precipitants at more realistic reservoir conditions. Pressure drop measurements across the core to quantify permeability damage were combined with X-Ray Microtomography (microCT) to visualise the deposits produced within the porous medium. The permeability measured through core-flooding experiments was compared to lattice-Boltzmann calculations in the segmented microCT images before and after deposition, where an increase in the flow rate showed a decrease in dimensionless permeability. Fitting the pressure drop data to a computational Deep Bed Filtration model allowed for a distinction between pore surface and pore throat deposition, which was confirmed by the microCT images of the location of asphaltene deposits. The results elucidate important asphaltene-related issues in porous media and provide a suitable framework for developing and improving deposition models.

Interfacial tension (IFT) is a property of paramount importance in many technical areas as it deals with the forces acting at the interface whenever two immiscible or partially miscible phases are in contact. With respect to petroleum engineering operations, it influences most, if not all, multiphase processes associated with the extraction and refining of Oil and Gas, from the optimisation of reservoir engineering strategies to the design of petrochemical facilities. This property is also of key importance for the development of successful and economical CO2 geological storage projects as it controls, to a large extent, the amount of CO2 that can be safely stored in a target reservoir. Therefore, an accurate knowledge of the IFT of reservoir fluids is needed. Aiming at filling the experimental gap found in literature and extending the measurement of this property to reservoir conditions, the present work contributes with fundamental IFT data of binary and multicomponent synthetic reservoir fluids. Two new setups have been developed, validated and used to study the impact of high pressures (up to 69 MPa) and high temperatures (up to 469 K) on the IFT of hydrocarbon systems including n-alkanes and main gas components such as CH4, CO2, and N2, as well as of the effect sparingly soluble gaseous impurities and NaCl on the IFT of water and CO2 systems. Saturated density data of the phases, required to determine pertinent IFT values, have also been measured with a vibrating U-tube densitometer. Results indicated a strong dependence of the IFT values with temperature, pressure, phase density and salt concentration, whereas changes on the IFT due to the presence of up to 10 mole% gaseous impurities (sparingly soluble in water) laid very close to experimental uncertainties. Additionally, the predictive capabilities of classical methods for computing IFT values have been compared to a more robust theoretical approach, the Density Gradient Theory (DGT), as well as to experimental data measured in this work and collected from literature. Results demonstrated the superior capabilities of the DGT for accurately predicting the IFT of synthetic hydrocarbon mixtures and of a real petroleum fluid with no further adjustable parameters for mixtures. In the case of aqueous systems, one binary interaction coefficient, estimated with the help of a single experimental data point, allowed the correct description of the IFT of binary and multicomponent systems in both two- and three-phase equilibria conditions, as well as the impact of salts with the DGT.

Understanding gas hydrate inhibitor distribution in hydrocarbon phases is essential for the economic design of process equipment. In order to build a clear image of the inhibitor’s distribution in various phases, three experimental investigations were devised; solubility in liquid and vapour phase as well as saturation pressure measurements. These data will contribute significantly to the understanding of the partitioning of these components as the data in the open literature are fairly limited. Aiming at filling the experimental gap found in the literature, the solubility of methane in pure methanol and ethanol as well as 70 and 50 wt% aqueous solutions at 238.15 – 298.15 K and 0.3 – 47 MPa were measured. The data from the ethanol/solution solubility measurements were used to optimise the methane-ethanol Binary Interaction Parameters (BIPs) of the CPA-SRK72 Equation of State (EoS). The model calculations showed an absolute average deviation of 5.3% over the full pure data range. To improve the CPA-SRK72 EoS predictions for aqueous solutions, new methane-ethanol BIPs were regressed showing significant improvement for both solubility and quaternary bubble point predictions. In order to determine the inhibitor loss to the vapour phase, the inhibitor content of methane was measured using Gas Chromatography (GC) between 0.7 – 62 MPa and 273.15 – 298.15 K. Additionally, a number of bubble point measurements were conducted for binary, ternary and quaternary systems containing methane, a liquid hydrocarbon phase (C7 – C12), methanol/ethanol and water. This was to investigate the effect of the inhibitor phase in the ternary, and the dominant excess water phase in the quaternary system, on the bubble point pressure as well as evaluating the CPA-SRK72 predictions. The saturation pressures were measured at 253.15 – 313.15 K. The solubility of CO2 in Mono-ethylene glycol (MEG), Di-ethylene glycol (DEG) and Tri-ethylene glycol (TEG) and their aqueous solutions (90, 60 and 40 wt%), at pressures and temperatures ranging from 0.2 – 43.4 MPa and 263 – 343 K, were measured. The solubility of CO2 in pure MEG, DEG and TEG were predicted using the CPA-SRK72 EoS, using a single binary interaction parameter, showing an absolute average deviation of 5.13%, 9.51% and 2.55% respectively. Correlations for the solubility of CO2 in MEG, DEG and TEG aqueous solutions, using aqueous solution regressed BIPs, showed an overall absolute average deviation of 17.5%, 18.2% and 25.16% respectively, a significant improvement from the non-aqueous solution BIP optimised predictions.

In Nigeria, downstream transportation and distribution of petroleum products is mainly done using pipelines and truck tanker transport systems. These systems have been linked to substantial accidents/incidents with consequences on human safety and the environment. This thesis proposes a risk management framework for the pipelines and road truck tanker transport systems. The study is based on a preliminary review of the entire downstream petroleum industry regulations which identifies key legislations and stakeholder interests within the context of accident prevention and response. This was then integrated into tailored mixed method risk assessment of the pipeline and truck transport systems. The risk assessment made use of accident reports and inputs from semistructure interviews and focus group discussion with relevant stakeholder organisations. For the pipeline systems, 96.46% of failure was attributed to activities of saboteurs and third party interference. The failure frequency of the pipeline (per km-year) was found to be very high (0.351) when compared to failure frequencies in the UK (0.23×10-3) and the US (0.135×10-3). It was discovered that limitations in pipeline legislations and national vested interests limits regulatory and operational capabilities. As a result the operator lacks the human and technical capability for pipeline integrity management and surveillance. Similarly the finding from the truck system revealed that 79% of accidents are due to human factors. The tanker regulators have no structured approach in dealing with the regulation of petroleum road trucking. Also, operating companies poorly adhere to safety standards. From an accident/incident response perspective, it was discovered that local response capability is lacking and the vulnerability of affected communities increases due to poor knowledge of the hazards associated with petroleum products. A framework was proposed for each of the transport systems. For the pipeline system, the framework leverages on the powers of the Petroleum Minister to provide best practice pipeline risk management directives. It also proposes strategies which combine the use of social tactics for engaging host communities in pipeline surveillance with technical tactics to enhance the pipeline integrity. For the truck risk management framework, control points for prevention of truck accidents were identified. It adheres to principles of commitment to change, and regulatory/peer collaboration for deployment of management actions. Suitable policy recommendations were made based on regulatory and operational interest of stakeholder organisations.

No description available.

Detailed geological models usually contain multi-million grid cells, which makes the running of reservoir simulation difficult and time consuming. Therefore, reducing the number of grid cells, and in turn averaging reservoir properties within them, is desirable in order to make running simulations more feasible. Averaging reservoir properties within the coarse cells is usually referred to as upscaling, which can be achieved using different methods. Many upscaling techniques have been introduced in the literature. However, developing a practical and robust upscaling method has been a research topic for a long time. In this thesis, some of the upscaling methods, their application and limitations are presented. Special attention is given to two phase upscaling methods as they are within the scope of this project. Afterwards, a new two phase upscaling method, called Transmissibility Weighted Relative permeabilities (TWR), is proposed to upscale relative permeability curves in heterogeneous reservoirs. Also, a new method to generate well pseudos is introduced as a means of adjusting well results. The TWR method and the well pseudos were tested using synthetic 2D and 3D water flood models for different conditions in order to check the method’s performance. The results showed that the upscaled relative permeability curves (pseudo functions) succeeded in compensating for sub-grid heterogeneity and numerical dispersion so that the coarse models reproduced the fine models results. In order to make the use of the pseudo functions feasible in practice, a new method to group them, based on curve fitting of Chierici (1984) functional models, was introduced. Calculations of the TWR pseudos and the well pseudos were performed by writing C++ codes to do so. The grouping of the pseudos was accomplished using a non-linear regression solver.

Uncertainty quantification is an important task in reservoir simulation and is an active area of research. The main idea of uncertainty quantification is to compute the distribution of a quantity of interest, for example oil rate. That uncertainty, then feeds into the decision making process. A statistically valid way of quantifying the uncertainty is a Markov Chain Monte Carlo (MCMC) method, such as Random Walk Metropolis (RWM). MCMC is a robust technique for estimating the distribution of the quantity of interest. RWM is can be prohibitively expensive, due to the need to run a huge number of realizations, 45% - 70% of these may be rejected and, even for a simple reservoir model it may take 15 minutes for each realization. Hamiltonian Monte Carlo accelerates the convergence for RWM but may lead to a large increase computational cost because it requires the gradient. In this thesis, we present how to use the multilevel concept to accelerate convergence for RWM. The thesis discusses how to apply Multilevel Markov Chain Monte Carlo (MLMCMC) to uncertainty quantification. It proposes two new techniques, one for improving the proxy based on multilevel idea called Multilevel proxy (MLproxy) and the second one for accelerating the convergence of Hamiltonian Monte Carlo is called Multilevel Hamiltonian Monte Carlo (MLHMC). The idea behind the multilevel concept is a simple telescoping sum: which represents the expensive solution (e.g., estimating the distribution for oil rate on finest grid) in terms of a cheap solution (e.g., estimating the distribution for oil rate on coarse grid) and `correction terms', which are the difference between the high resolution solution and a low resolution solution. A small fraction of realizations is then run on the finer grids to compute correction terms. This reduces the computational cost and simulation errors significantly. MLMCMC is a combination between RWM and multilevel concept, it greatly reduces the computational cost compared to the RWM for uncertainty quantification. It makes Monte Carlo estimation a feasible technique for uncertainty quantification in reservoir simulation applications. In this thesis, MLMCMC has been implemented on two reservoir models based on real fields in the central Gulf of Mexico and in North Sea. MLproxy is another way for decreasing the computational cost based on constructing an emulator and then improving it by adding the correction term between the proxy and simulated results. MLHMC is a combination of Multilevel Monte Carlo method with a Hamiltonian Monte Carlo algorithm. It accelerates Hamiltonian Monte Carlo (HMC) and is faster than HMC. In the thesis, it has been implemented on a real field called Teal South to assess the uncertainty.