Keyu Liu

Fluorescence evidence of polar hydrocarbon interaction on mineral surfaces and implications to alteration of reservoir wettability

Abstract Petrographic analysis of reservoir rocks in an apparently water-wet system under UV light indicates the ubiquitous presence of microscopic oil inclusions within quartz grains. The micro-sized inclusions are often trapped along healed micro-fractures or along quartz overgrowth boundaries. The apertures of the micro-fractures are usually a few microns in width, an order of magnitude smaller than the typical pore aperture (throat) of reservoir rocks. When these same reservoir rocks were analysed using a highly sensitive fluorescence spectrophotometer after series of cleaning steps using solvents and oxidizing agents, it was revealed that polar organic compounds are present on quartz grain surfaces. Examination of the quartz grain surface using scanning electron microscope (SEM) and an energy dispersive X-ray (EDAX) system confirmed the presence of fine residual hydrocarbon particles associated with clay minerals coated on the highly irregular quartz grain surface. The presence of polar organic compounds and/or asphaltenes on water-wet quartz surfaces results in wettability alteration under reservoir conditions, which may allow direct contact between hydrocarbon and the water-wet quartz grains, resulting in the formation of micro-size oil inclusions in quartz grains.

A Sedimentological Approach to Upscaling

Optimised upscaling in reservoir simulations requires the construction of realistic petrophysical properties that are representative of the heterogeneity in the sedimentary deposits. Reservoir heterogeneities are controlled by the arrangement of various hierarchies of sedimentary facies and their internal bounding surfaces. The conventional sedimentological approach to reservoir upscaling involves subdivision and ranking of various hierarchies of architectural units and associated bounding surfaces of the reservoir sequence according to their geological significance. This global upscaling approach produces realistic scaled up models that retain both the structural and non-structural heterogeneities of the original sedimentological models. Analyses of sedimentary sequences from various depositional environments indicate that the fractional Levy model can adequately describe the heterogeneity and scaling characteristics of individual genetic sediment sequences in the clastic sedimentary system without further subdividing and ranking of the heterogeneous sequences. The heterogeneous nature of each sedimentary system can be quantified by the Levy index parameter, whereas the maximum upscaling magnitude (or upscaling index) for a particular sequence can be determined from the Levy width parameter plot. Depositional modelling mimics the sedimentary processes in a range of scales and honours hierarchies of sedimentary facies and their bounding surfaces. It can be used effectively for upgridding and upscaling in accordance with the stratigraphic framework and sedimentological models. Both the fractional Levy model and the depositional modelling provide quantitative alternatives to the conventional global sedimentological upscaling approach.

A new method for identifying secondary oil migration pathways

Abstract A method called Oil Migration Intervals (OMI) is presented to assist identifying lateral oil migration pathways intersected inexploration boreholes. It predicts potential profiles of residual oil saturation due to partial confinement of oil below sealing strata using a pseudodisplacement pressure log and the buoyancy gradient. The OMI method performs calculations on wireline log data and uses empirical correlations between permeability and displacement pressure to derive a continuous pseudodisplacement pressure log for an intersection of reservoir or carrier bed. A pseudopermeability log is calculated from a modified Wyllie-Rose equation by replacing the irreducible water saturation factor with an empirical pore aperture parameter utilising V -Shale and Porosity. The pseudodisplacement pressure is subtracted from the buoyancy gradient to obtain profiles of potential excess buoyancy pressure and thus relative residual oil saturation due to partial confinement beneath sealing strata. The OMI log can then be directly compared with scaled field or laboratory measured oil show indicators to identify genuine secondary (lateral) oil migration. The steps in the calculation of the OMI log have been calibrated using laboratory and field data from exploration oil wells in the Timor Sea, NW Shelf, Australia.

Effect of Nutrient Addition on an Oil Reservoir Microbial Population:Implications for Enhanced Oil Recovery

The increasing demand for petroleum is driving the development of technologies including MEOR (Microbial enhanced oil recovery)—the use of microbes within a reservoir to enhance oil recovery. In this study we initially determined that availablilty of suitable carbon sources was limiting microbial growth and metabolism of an oil reservoir microbial community. Subsequently we identified metabolic processes that are initiated after addition of nutrients that addressed this limitation. Four distinct metabolic pathways were stimulated: (i) fermentation of the added nutrient; (ii) methanogenises of the metabolites of fermentation; (iii) accumulation and decay of biomass; and (iv) oxidation/co-metabolism of petroleum. Biomass, when introduced as a nutrient, led to similar increases in live cell numbers in oil reservoir microcosms as addition of molasses. In addition to acting as a nutrient, disrupted microbial biomass led to formation of oil-water emulsions and significant lowering of the interfacial tension. These results suggest biomass manipulation can play an important role in MEOR.

Basin-scale fluid flow in the Gippsland Basin: implications for geological carbon storage

Petroleum systems analysis has been carried out to better understand the geological CO2 storage potential of the Gippsland Basin. From a regional perspective, the hydrocarbon migration architecture of the basin is interpreted to be dominated by two highly connected, filled-to-spill, hydrocarbon fairways; the northern (gas-dominated) and southern (oil-dominated) fill-spill chains, forming a convergent system that extends onshore along the Golden Beach Fill-Spill Chain (GBFSC). A separate oil-dominated Fill-Spill Chain, the Dolphin-Perch Fill-Spill Chain (DPFSC), is identified offshore to the southwest. Two broad flanking provinces, the Northerly Migration Province (NMP) and Southerly Migration Province (SMP), are also identified. Both provinces have broadly ramp-like geometries and relatively low dips. Migration across these provinces is not focused, and hence multiple pathways are present across a wide area. An understanding of the hydrocarbon systems in the basin can be used for characterising the potential for CO2 storage. Previous studies have shown that the top seal potential of the offshore Gippsland Basin is suited to geological carbon storage and that large areas are prospective as storage regions. However, the linked nature of the fluid flow systems and the focused fluid flow fairways between areas of high storage potential and leaky systems onshore will require both a good regional geological understanding and informed resource management.

Impact of Rock Heterogeneity on Interactions of Microbial-Enhanced Oil Recovery Processes

Residual oil saturation reduction and microbial plugging are two crucial factors in microbial-enhanced oil recovery (MEOR) processes. In our previous study, the residual saturation was defined as a nonlinear function of the trapping number, and an explicit relation between the residual oil saturation and the trapping number was incorporated into a fully coupled biological (B) and hydrological (H) finite element model. In this study, the BH model is extended to consider the impact of rock heterogeneity on microbial-enhanced oil recovery phenomena. Numerical simulations of core flooding experiments are performed to demonstrate the influences of different parameters controlling the onset of oil mobilization. X-ray CT core scans are used to construct numerical porosity-permeability distributions for input to the simulations. Results show clear fine-scale fingering processing, and that trapping phenomena have significant effects on residual oil saturation and oil recovery in heterogeneous porous media. Water contents and bacterial distributions for heterogeneous porous media are compared with those for homogenous porous media. The evolution of the trapping number distribution is directly simulated and visualized. It is shown that the oil recovery efficiency of EOR/MEOR will be lower in heterogeneous media than in homogeneous media, largely due to the difficulty in supplying surfactant to unswept low-permeability zones. However, MEOR also provides efficient plugging along high-permeability zones which acts to increase sweep efficiency in heterogeneous media. Thus, MEOR may potentially be more suited for highly heterogeneous media than conventional EOR.

The concept of fluid potential and its practical application to petroleum exploration

In the practical petroleum exploration, there appears to be some issues and confusions when the concept of fluid potential of Hubbert (1953) and England (1987) is applied. If the four kinds of energy in a fluid potential (e.g. buoyancy, stratigraphic pressure, capillary pressure and hydrodynamic forces) are simply added together, it will confuse the relationship between the mechanisms of different forces that cause petroleum to migrate and accumulate while neglect the differences caused by the different forces that control the hydrocarbon accumulation, and thus mix the contributions of different forces to hydrocarbon pooling. The causes to these issues include human factors such as inadequate understanding and/or over simplification of the practical problems and misunderstanding of Hubberts original formula. To make the fluid potential concept more useful and powerful in the practical petroleum exploration further revision and perfection to the conceptual model of fluid potential is required. Fluid potential can be expressed as the potential energy of a unit volume of fluid within a sedimentary basin. For the convenience of discussion, it is here expressed as the work that requires to be done by a unit volume of hydrocarbon fluid in its internal migration to the effective source rock center. In the study of the effect of fluid potential on the control of petroleum, attention should be paid to the fact that different types of fluid potential are produced by different dynamic forces, to which the relative strength consideration must be given respectively. The migration, accumulation and pooling of petroleum may be realized by the joint control of multiple dynamic forces, and the characteristics of such movements remain unchanged in zones with low potential. A successful practical application of the fluid potential concept to petroleum exploration is exemplified using an example from the Dongying Depression, the Bohai Bay Basin, east China, where over 90% of the commercial discoveries in the reservoirs within the Shahejie Formation are distributed in areas with both favourable lithofacies and a low potential.

CHAPTER 4:Advances in Fluorescence Spectroscopy for Petroleum Geosciences

Fluorescence spectroscopy is one of the most sensitive, rapid, versatile, and inexpensive screening techniques in petroleum exploration and production. Some recent developments in instrumentation, software, and analytical procedures have led to the techniques being much more robust and quantitative than was previously possible. Fluorescence spectroscopic techniques may be used to augment or offer an alternative to petrographic, geochemical, and isotopic methods. This chapter provides an overview of recent developments in fluorescence spectroscopy with specific reference to petroleum geoscience and engineering and demonstrates some examples of techniques applicable to petroleum system analysis by providing information relating to petroleum generation, migration, accumulation, and preservation.