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No description available.

The incidence of fretting damage in the pressure armour wires of flexible pipes used in offshore oil explorations has been investigated. A novel experimental facility which is capable of simulating nub and valley contact conditions of interlocking wire winding with dynamic slip, representative of actual pipe loading, has been developed. The test set-up is equipped with a state of the art data acquisition system and a controller with transducers to measure and control the normal load, slip amplitude and friction force at the contact, in addition to the hoop stress in the wire. Tests were performed with selected loading and the fretted regions were examined using optical microscopy techniques. Results show that the magnitude of contact loading and the slip amplitude have a distinct influence on surface damage. Surface cracks originated from a fretting scar were observed at high contact loads in mixed slip sliding while surface damage predominantly due to wear was observed under gross slip. The position of surface cracks and the wear profile have been related to the contact pressure distribution. The evolution of friction force and surface damage under different slip and normal pressure conditions has been analysed. A fracture mechanics based numerical procedure has been developed to analyse the fretting damage behaviour. A severity parameter is proposed in order to ascertain whether the crack growth is in mode I or mode II cracking. The analysis show the influence of mode II cracking in the early stages of crack growth following which the crack deviates in the mode I direction making mode I the dominant crack propagation mechanism. The crack path determined by the numerical procedure correlates well with the experimental results. A numerical analysis was carried out for the fretting fatigue condition where a cyclic bulk stress superimposes with the friction force. The analysis correlates well with short crack growth behaviour. The analysis confirms that fretting is a significant factor that should be taken into account in design and operation of the pressure armour wires of flexible pipes at high contact pressure if the bulk cyclic load superimposes with the friction force. As predicted by the numerical procedure and further by experimental investigations, the surface cracks initiating on the wire in this condition are self arresting after propagating into a certain depth.

No description available.

No description available.

One of the most common production problems in oil and gas fields is scale deposition within oil and gas wellbores. Scale formation in surface and subsurface oil and gas production equipment has been recognised to be a major operational problem. The effect of scale formation is a reduction in the well productivity and the damage to safety valves and gas-lift mandrels. This investigation proposes a new and novel technique to address the problem and lay the foundations for a methodology for descaling in-situ production tubing. This problem currently requires either aggressive chemicals or extraction and replacement tubing both of which are very expensive. The overall aim of this investigation is to study the fundamentals of the decaling process using flat fan sprays at high water pressure ( < 6 MPa ) and high impact force (< 0.657MPa). The spray was characterised quantitatively and qualitatively under ambient conditions utilising single flat fan atomiser or a combination of two or three atomisers with an overlapping configurations. The volume (or mass) flux (VLf) was measured using a patternator which was designed during this investigation. Liquid volume (or mass) flux was found to be symmetrical at different downstream distances (25, 50 and 75 mm). Impact force (IF) was also experimentally measured at different downstream distances (25, 50 and 75 mm) and at various water supply pressure of 3.7, 4.8 and 6 MPa for the corresponding sprays. The result showed that impact force can lie between 0.146 to 0.657MPa Sprays were also characterised using Phase-Doppler Anemometry (PDA). The range of velocity (U) was found to be between 62.48 to 81.85 m/s at 25 mm downstream distance whilst at 50 mm downstream, it was in the range of 55.96 to 73.13 m/s and at 75 mm was between 48.89 to 66.98 m/s. However, the Sauter mean drop size diameter (D^ at 25 downstream distances was found to be in the range of 62.45 um to 75.80 urn and at 50 mm downstream the drop size was between 67.30 jam to 81.43 urn whereas at 75 mm it was 73.56um to 86.42 um. Also, from the results, the liquid volume flux (ULf) obtained using PDA was measured to be between 0.063 and 1.2 (cm3/s)/cm2 at 25 mm downstream and 0.016 to 0.250 (cm3/s)/cm2 at 50 mm and 0.010 to 0.120 (cm3/s)/cm2 at 75 mm downstream distance. Comparing these results with those found via patternator mesurements showed in some instanous, that there is significant (i.e up to 90%) difference between each values which were obtained by the PDA, measured at the centre of the sprays. This was mainley to lack of caputuring the certain drop sizes by PDA and also the design geometry of the patternator together with the nature of flat shape of the spray being not truly flat. Simulated laboratory scale removal rig was subsequently designed and built to demonstrate the effects of using overlapping flat sprays atomisers to remove scales that normally found in oil and gas. Four scale samples (candle wax, soft oil wax, soft gas and oil hard) were tested. The quantity of scale removed using soft candle wax was (53 cm3) at 30 degree atomiser angle to the vertical axis. The scales samples which were obtained from both oil and gas fields were also tested as follows: - a total of 11.688 cm3 of soft scale was removed using three high pressure and high impact atomisers whilst the volume of the scale removed from the oil wax was within 13.750 cm3 for the hard oil scale was found to be approximately 0.989 cm3 . The structures of the flat sprays were also mathematically analysed using the Computational Fluid Dynamics (CFD) package which allowed validating the PDA data. The velocity of the drops compared well with those obtained from PDA. The liquid volume flux, however, was found, generally, between 26% < ULf < 90% compared with those of PDA data.

Abundant water chemistry analyses from nine different locations (predominantly petroleum reservoirs) on five continents were evaluated. This information, together with local mineralogy, depth and temperature relations provided a sound basis from which to investigate the most important controls on formation water composition. In particular, the detailed study of two very different hydrocarbon reservoir case studies (the Central US coalbed methane reservoir, the San Juan Basin and the North Sea oilfield Miller) provided an insight not only into the fundamental controls on formation water composition, but also into the effects of active oilfield development on systems that are very sensitive to change on rapid timescales. The geochemistry of San Juan waters is controlled by the introduction of bicarbonate through carbonate dissolution and methane/coal oxidation leading to leaching of Na-bearing clay minerals, and by ion exchange on clay minerals and dilution by meteoric waters in certain locations. The time series of produced waters from Miller enabled detailed study of fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Changes occur in the concentrations of many water components through time that cannot be explained by linear mixing between formation water and injected water and require dissolution or precipitation reactions to have occurred between injection and production sites. For example Ba, and SO4 concentrations are affected by equilibrium with barite and what is likely to be sulphate reduction. Also, excess Si present in the fluid is due to dissolution of the silicate phases in the reservoir, and demonstrates reactions between silicate minerals occur on a fast enough timescale to buffer the pH of the water. Integration of all available data shows consistent patterns of behaviour, which implicate mineral-fluid interactions in the subsurface as a major control on formation water chemistry. For example, globally, Ca concentrations are shown to behave in one of three ways, all of which depend on water interaction with the host rock, be it silicate or carbonate, clastic or evaporite. Distinct trends arise for bicarbonate waters, brines derived by halite dissolution and formation brines that have evolved extensively with silicates. In addition, K concentrations are closely related to feldspar-clay equilibria and Mg concentrations are influenced predominantly by carbonate minerals with significant contribution from clays. It is likely that initial Ba concentration is related to interaction with K-feldspars and SO4 is controlled by equilibrium with sulphate mineral phases as well as by redox. A greater understanding of formation water chemistry leads to an improved perception of the importance of these systems in terms of both furthering scientific progress and the technological development of the oil and gas industry. In particular, produced water chemistry analyses from Miller were used to appraise and improve the most important aspects of both generic and specific reservoir models. A set of simple models emphasised the point that small variations in reservoir property parameters can have significant effects on model outputs, and thus the highlighted the importance of thorough reservoir characterisation, particularly permeability heterogeneity, capillary pressure and relative fluid permeabilities. Geochemical models of three different systems from the integrated database (the Alberta Basin, a Colombian onshore oilfield and an oilfield from offshore Gulf of Mexico) illustrate that reservoir rocks containing a wide variety of minerals are the most effective at limiting pH decrease following the injection of CO2 into the system. The geochemistry, in particular the salinity, of the formation water present also has a significant bearing on the processes that are likely to occur during CO2 sequestration.

We have identified a CO2 and water injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. We propose the use of counter-current injection of gas and water to improve reservoir sweep and trap CO2; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. This process is referred to as water over gas injection or modified simultaneous water alternating gas injection (SWAG). This thesis is based on the results of quasi-validated compositional reservoir simulations in that exact matches were not obtained for the disparate fluids and reservoirs properties but the trends of oil recovery and water cut were accepted as representative of comparative physical mechanisms of displacement. We have compared oil recovery and water cut trends of the compositional simulation model to the displacement experiments conducted by Dyer and Farouq Ali[1] where varying injection rates, number of WAG cycles and size of CO2 slug were investigated. Dyer and Farouq Ali’s displacement experiments used an Aberfeldy crude mixed with liquid petroleum to obtain an oil viscosity of 1055 mPa.s at standard conditions to represent viscosity reservoir conditions. The fluid description used in our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. At standard conditions the crude viscosity is 1175mPa.s and at reservoir conditions (81° C and 27.9 MPa) 8 mPa.s. In this region oil density ranges between 940 and 1010 kg/m3 (9-18 degrees API). The PVT properties were matched by regressing: the 3-parameter Peng-Robinson[2] equation of state to the oil relative volume, total relative volume and; the coefficients of the Lohrenz Bray Clark [3]correlation to the viscosity of the crude between 0 and 20MPa at 81.7 °C. The reservoir simulation model was scaled to the length to width ratio of the displacement experiment and, the ratio of gravitational to viscous forces of injected water used in displacement experiments. From this we study we identified the limitations of WAG and the injection parameters favourable to oil recovery, gas trapping and gas storage capacity. We have then used a synthetic reservoir to represent an unconsolidated sand measuring 1000m × 150m × 100m with average porosity of 26% and initial water saturation of 20% to investigate with representative parameters, determined from the comparison with the displacement experiments, to investigate the efficacy of water over gas injection. The original oil in place (OOIP) is 3.12 × 106 m3 (19 MMbbl).The two water injection rates investigated, 100 and 200m3/day(630 and 1260 bbl/day). These rates correspond to water gravity numbers (dimensionless ratio of viscous to gravity forces) 6.3 to 3.1 for our reservoir properties. The gas injection surface rate was 50 000 sm3/day (1.8 Mscf/day) in both instances corresponding to gas gravity numbers ranging between 150 and 200 with varying reservoir flow rates .We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. The producer was vertical in each case. The impact of miscibility was investigated by varying the injection gas composition by comparing the effect of using pure CO2 and a mixture of CO2 and C2-C6 in a 2:1 ratio, on oil recovery, carbon storage and field performance. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30% of original oil in place (OOIP). In each instance more than 50% of the injected CO2 remains in the reservoir with less than 15% of retained CO2 in the mobile phase. The remaining CO2 is distributed in oil, water and trapped gas phases. Our reservoir simulations show that water over gas injection can be applied successfully to recover heavy oil and trap CO2 in an unconsolidated sand. This injection design has also shown immiscible and miscible oil recovery can be improved with horizontal injection. Water injection over gas injection increases contact between injected CO2by dispersing the injected gas over a wider volume in the reservoir, hindering gas override and providing reservoir pressure support. Gas storage is inversely proportional to the water gravity number because of the effect the injected water has on gas saturation distribution. In combination with established industry reservoir management techniques such as pressure control and gas cycling, it may be possible to further improve the oil recovery and carbon storage of water over gas injection.

No description available.

No description available.