No description available.

No description available.

No description available.

No description available.

An integrated, multi-disciplinary approach was developed to examine waterflooding processes in deepwater stacked turbidite reservoirs. Fluid flow in porous rocks was reviewed both at the pore and the reservoir section scales. The importance of a favourable mobility ratio for a stable oil/water displacement was highlighted. This information guided our choices for fluids characteristics to use in our fluid flow simulation models. A geological review of deepwater turbidite reservoirs provided a sound understanding of their geological characteristics, with a special emphasis on their impact on fluid flow within the reservoir. The vertical permeability distribution across the reservoir was identified as having a crucial impact on waterflooding efficiency in turbidite reservoirs. Permeability distribution within a channel element of a stacked turbidite reservoir follows three characteristic trends: homogeneous distribution, fining upward distribution, and coarsening upward distribution. A series of idealised reservoir models, representative of a single flow unit within a turbidite reservoir, was built. The idealised models represented the three different permeability distributions commonly found in turbidites and another model was added to simulate bottom drive waterflooding. Two scenarios were run on the models: water injection with pressure support and water injection where the pressure dropped by a maximum of 1500 psi. The change in Vp was around 4 to 5% regardless of the reservoir geology or the pressure variations. Pressure change has a global dimming effect on the P-wave velocity. It happens very briefly after the start of the simulation and spreads across the whole reservoir. Change in Vp due to pressure decline was around -0.5% and could not be detected on the synthetic seismic. The waterfront is easily interpreted both on 4D cross-section and 4D attribute maps. A realistic turbidite geological model based on the Ainsa II outcrop was built. The model was populated with rock characteristics of a turbidite reservoir on the West of Africa. The model was then up-scaled and fluid flow simulation was performed. Permeability values and NTG distribution played a major role in the advance of the waterfront inside the reservoir and controlled its shape and location. Petrophysical modelling showed that P-waves velocity would increase by up to 7% due to the substitution of oil by water and suggested that it can be extremely sensitive to water saturation changes. Even the smallest changes (less than 10%) would have a noticeable effect on Vp values, which is of crucial importance when time-lapse seismic is to be used in a quantitative way. Synthetic seismic was created using three different frequencies (35 Hz, 62 Hz, and 125 Hz). On 3D seismic sections, different channels within the reservoir were resolved separately on the high resolution seismic. Tuning phenomenon is observed for the three modelled frequencies due to the presence of very thin beds (1-2 meter thick). The interpretation of the OOWC or the MOWC on those sections is challenging because the reflections at the fluids front are obscured by reflections from geological interfaces. The complex geology of the reservoir resulted in 3 different RMS seismic amplitude maps showing an increasing degree of heterogeneity as the seismic dominant frequency increased. Interpretation of MOWC on time-lapse seismic cross-sections and maps is challenging and the inclusion of different attributes in the interpretation workflow might be necessary in order to assess the complexity of the waterflooding signature. Time-lapse seismic monitoring of waterflooding processes in deepwater turbidite reservoirs requires sound a-priori knowledge of the geology of the reservoir. On the other hand, an accurate interpretation of the time-lapse seismic signature of Waterflooding can improve our understanding of the reservoir characteristics. Therefore, the task should be performed by multi-disciplinary teams, where geologists, reservoir engineers, and geophysicists work closely together.

Passive microseismic monitoring provides a non-invasive method of monitoring deformation and changes in the stress distribution within a rock mass. Recently the petroleum industry has applied and focussed such studies on the monitoring of hydraulic fracturing stimulation: the fracturing of a reservoir by the injection of a high pressure fluid into reservoir causing the rock to fracture, increasing the permeability. However, the development of passive seismic monitoring of a fully operational oil field has been slow largely due to economic constraints limiting the geophone array to be deployed within a single vertical borehole. The challenge is thus to refine the seismic methods applied to datasets from the vertical arrays and to explore the extent to which further investment in more sophisticated seismic arrays would advance the understanding of the reservoir architecture and evolution. The Ekofisk reservoir in the North Sea provides an excellent opportunity to address these issues and is the focus of this study. Discovered in 1969 the Ekofisk field is located within the Central Graben of the Norwegian North Sea and is operated by Conoco-Phillips. It was one of the world's first economically viable chalk reser- voirs and comprises two main oil bearing intervals: the Ekofisk and Tor Formation chalks, separated by a relatively impermeable siliceous chalk. Since the onset of production in 1971, the reservoir has expe- rienced appreciable subsidence. A water injection program was initiated but has done little to mitigate the problem. In April 1997, one of the first hydrocarbon passive micro seismic monitoring studies was undertaken over an 18 day period at Ekofisk in an attempt to understand the mechanism of deformation. Data were acquired using a six station geophone array deployed in a vertical borehole. Fundamental to the study of seismicity at any scale is the accurate determination of the event source. Events for borehole microseismics are usually located using a ID velocity model, P- and S-wave arrival times and the polarisation azimuth of the P-wave particle motion. However, in the case of all sensors being deployed within a vertical or near-vertical bore hole such analysis leads to an inherent 1800 ambiguity in source location. In this study, this ambiguity is removed by using the back-projecion of the dip of the particle motion from multiple stations until they converge on one side of the well or the other as a priori information to constrain the initial source location. The procedure is developed and tested using a dataset acquired from another field during hydraulic fracture stimulation, where event locations are known. Applying this procedure to the Ekofisk dataset 627 events are successfully located with coherent features clustering around production/waterflooding wells and fractures. Most are located less than 250 m away from the monitoring well and at a depth of ",3 km in the Ekofisk chalk formation. Little seismicity is observed from the underlying Tor Formation chalk, which is separated from the Ekofisk Formation by an impermeable layer of siliceous chalk. There is no evidence of seismicity in the overburden. Repeating earthquakes (multiplets) are identified and relatively re-located in order to enhance the resolution of active features and gain further insight into the mechanism of deformation. Qualitative analysis of the waveforms of the multiplets shows a number of potential mechanisms such as production/waterflooding induced activity, fault re-activation and stress triggering. Having established precise hypocentres for the Ekofisk microseismicity the final goal of this study is to gain information along the source-receiver raypath using a shear wave splitting study of anisotropy. An automated shear wave splitting approach is applied to the Ekofisk dataset yielding 1125 reliable measurements. A number of near-vertical fracture sets with fracture strike orientations of NE-SW and W-SE agrees with previous core based studies of Ekofisk. In summary, this thesis shows that a single borehole deployment of geophones can be used to gather detailed information about the spatial and temporal variation in seismicity in a hydrocarbon setting. The seismic data can then be used via study of seismic anisotropy to place fundamental new constraints on the state of stress, mineral alignment, layering of sedimentary structures or the presence of aligned fracture sets all of which have profound implications for reservoir management.

The Middle Miocene Miri Formation outcrops in Miri, Sarawak which represent possible surface analogue to the offshore Baram field, consist of meter-scale, multiple- stacked, fining-upward successions which predominantly comprise medium to fine- grained, trough cross-bedded sandstones. These rocks represent transgressive, tide- dominated deltaic or estuarine sedimentation. The Baram field is a small oil field situated in the north-eastern side of the Baram Delta Province, offshore Sarawak. The cored intervals of the Upper Cycle V (Late Miocene) of Baram field display reservoir successions dominated by thick swaley cross stratified (SCS) sandstones and other associated shallow marine, wave and storm- dominated facies. The vertical facies organisation of these successions suggest deposition during shoreface pro gradation associated with fall of relative sea level. Parasequence stacking patterns in the Upper Cycle V (Late Miocene) of Baram field suggest that deposition and build-up stratigraphy were controlled by superimposed short-term, medium-term and long-term sea level changes. Well log correlation of these stacking patterns reveal three scales of depositional cyclicity, the parasequence (-10 to -30 m thick), the parasequence set (-45 to -130 m thick) and the major cycles (-600 to -800 m thick). The parasequences and the parasequence sets represent the -20K precessionary and -lOOK eccentricity Milankovitch cycles, respectively. This interpretation places the lower boundary of the Upper Major Cycle (Upper Cycle V) to -6.3 Ma, which correlates with a major eustatic fall on the Haq et al. (1988) sea level curve. Modal analysis of the Baram sandstones reveal that mechanical compaction resulted in the reduction of about 30 to 60 % of the original intergranular porosity. Siderite, chlorite-smectite, chlorite and quartz overgrowth represent the principle authigenic phases. Siderite cementation occurred early, initially below sediment-water interface and continued to depths of -450 to -800 m. Chlorite-smectite, grain-coating and pore-filling chlorites, and authigenic quartz characterize advanced stage burial diagenesis, possibly at temperatures between 100 to 150°C. Other minor phases identified include hematite, kaolinite, framboidal pyrite, and localised carbonate and feldspar dissolution. The reservoir sandstones of Baram field record porosities and permeabilities ranging from 11.0-28.6% and 1.13-819 mD respectively. Primary depositional fabric strongly influenced the poro-perm characteristics of these sandstones. The very well- sorted SCS sandstones constituted the principal reservoir units (-20-26% porosity; -50.00-400 mD permeability). The heterogeneous sandstones also show good reservoir quality (10-25% porosity and 10.0-681 mD permeability). Overpressuring contributed to porosity preservation at depths. The presence of detrital mud clasts, clayey laminations, bioturbation and siderite cement commonly resulted in the reduction of reservoir quality.

No description available.

During the production of a hydrocarbon reservoir, the compaction of weakly cemented sedimentary materials can result from increases in effective stress, and lead to surface subsidence. Such a phenomenon has recently been observed in the oil and gas bearing chalk fields in the Central North Sea. In order to evaluate the compaction potential of sedimentary materials during exploitation of a reservoir, laboratory experiments- were performed on chalks and clays. These experiments were predominantly K0 (zero lateral strain) tests. The tests were performed in a high pressure triaxial cell, the development of which continued throughout the experimental 'programme. Tests performed on chalks from the Central North Sea, and from two onshore sites in southern -England showed similar deformational trends. The analyses of these results concentrated on the variables of testing and the possible errors resulting from the use of laboratory data in the modelling of field situations. The analyses of the tests also include a comparison between the experimental methods and the interpretation of the results of this study and those of other workers on the subject of reservoir compaction. A parametric description of the compaction of chalk is presented as a summary to these tests. Two compaction tests on clay samples from the Central North Sea were also undertaken. The clays were uncemented and show contrasting behaviour to the chalks. These tests were performed to evaluate the amount of compaction likely to occur in the overburden of a hydrocarbon reservoir during production. The results of the deformational trends obtained from this study. are compared to those obtained by other workers, with particular reference to the changes in physical parameters during compaction. This follows a literature survey into hydrocarbon reservoir compaction. The K0 tests performed in this study are thought to represent the condition of sediment burial in a tectonically inactive basin. This subject is briefly reviewed, and the relevance of the results presented earlier discussed in terms of the prediction of stresses existing within differing lithologies. The analysis of the results have been performed using parameters commonly used in soil mechanics, this seemed to be appropriate for the deformations undergone by the materials used in this study.

Biodegradation of crude oil in reservoirs has major economic consequences. While the effects of biodegradation are empirically well known, the processes involved, the fraction of oil destroyed and the critical factors controlling degradation remain obscure. A suite of oils and reservoir extracts from the Liaohe basin, NE China, was analyzed to investigate the effects and controls of biodegradation on petroleum composition. The aims of this project were to further our understanding of the factors which influence the biodegradation of crude oils, and the processes by which these factors interact and to assess the role played by biodegradation in controlling the composition of a wide range of crude oils. The geological settings of the study area have been addressed in detail, including structural and stratigraphic characteristics, source rock and reservoir characteristics, tectonic evolution and hydrocarbon generation history, formation water composition. A single source and similar maturity make the study area an ideal site to investigate the constraint of biodegradation. Systematic changes seen as marked gradients in petroleum bulk composition, component concentrations and molecular indicators have been observed in biodegraded oil columns. The susceptibilities of several aromatic hydrocarbon, alkylcarbazole and alkylphenol isomers to biodegradation have been discussed for the first time in this thesis. The author also addressed the biodegradation effects on many classical geochemical evaluation procedures such as those involving facies and maturity assessmenat nd on the physical and chemical properties of petroleum. The variation in the degree of biodegradation at different sites of the column is controlled by water leg size, with a higher level of degradation being associated with a thicker water leg. The supply of nutrients from the water leg is thought to have a significant impact upon the degree of biodegradation. In addition to water leg size/nutrient supply, the compositional gradients are also controlled by the relative rate of mixing of fresh and degraded oils. The conceptual biodegradation model proposed couples geochemical and geological factors to provide a coherent approach to ascertain the impact of degradation on petroleums and to help to reliably predict biodegradation risk for an exploration target. Our data suggest that biodegradation occurs within a narrow region near the base of the oil column, probably at the oil water contact (OWC), and that in this reservoir there has been a late charge of oil to the top of the column. The mixing of oils through continuous charging and the diffusion of hydrocarbons towards the OWC, and the diffusion of metabolites of degraded oil away from the reaction site may be considered as the most important factor controlling the biodegradation process. Based on an oil charging-biodegradation model (Larter et al., 2003) mass balance calculation has been carried out and the results indicate at level 5 biodegradation up to 50% of petroleum mass has been depleted, beyond this level of biodegradation loss of oil mass is less significant but structural rearrangements are important.