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ABSTRACT: Providing reliable petrophysical interpretations in complex reservoirs can be particularly challenging. These challenges are exacerbated when the sediments are rich in lithics and subsequent diagenesis has modified the pore structure by filling the pores with a variety of clays and other cements. In order to constrain the petrophysical models for the oil reservoirs in the Eromanga Basin, an extensive petrological study was proposed, incorporating thin sections analysis, X-Ray diffraction (XRD) and Scanning Electron Microscopy (SEM) to quantify the mineralogy and pore structure, document provenance evolution and redefine the petrophysical model used in the area. Four cored wells were selected within a wide area of the Cooper region to provide coverage of the majority of producing horizons. The target sandstones were the Hutton, Birkhead, Westbourne, Namur and Cadna-owie formations. Detailed work was completed using traditional grainsize-permeability plots, XRD analysis and SEM to identify trends and mineralogy. This was complemented with Quartz-Feldspars-Rock Fragment (QFR) plots to understand composition and provenance. Following the QFR classification (Folk, 1974), results suggested that most analysed samples classify as arkose, subarkose, lithic arkose and feldsphatic litharenites. XRD analyses and SEM photomicrographs revealed the presence of smectite, kaolinite, illite and chlorite as the main authigenic clays. Siderite and calcite were identified as the main cements in the Westbourne/Birkhead formations, whilst silica and kaolin cements were present in the Namur/Hutton formations. The determination of clay mineralogy by formation represented a key factor in understanding clay variations with depth and how these influence the physical properties of the reservoirs. As a result, an improved petrophysical model was built, generating more accurate interpretations for further wells drilled in the basin. Since water saturation and porosity represent important inputs for the estimation of oil in place, changes observed in this study will ultimately cause modifications in a new estimation of reserves.
ABSTRACT Big quarries are mined out in the Tournai's region (Belgium) for cement or crushed raw materials production. The development of this industrial activity is due to famous outcrops of carboniferous limestone in the region. The rock masses in the area are characterised by three sets of discontinuities among which two have a near vertical dipping; and these sets are intersected a time to time by some typical faults. It is generally recognised that, when subjected to the effect of percolating water, the limestone undergoes a weathering leading to very poor material on the mechanical point of view. Such a material cannot be used as crushed rock. When designing the rock blast, the mining engineer has to plan and drive the operations in order to decide about the most suitable destination for the mined out material, i.e. crusher of waste dump. A particular method has been developed in this paper to assess continuously the quality of the rock being drilled for blast holes. This uses the drilling logs (i.e. weight on bit, rate of penetration, and rotation torque) to evaluate the strength of the rock mass.A mechanical "energy index" that can be related to the destruction specific energy is defined.A correlation is then built with the GSI (Geological Strength Index) as described by Hoek and Brown (1997). The working method involves the definition of the GSI per zone and a specific treatment to assess the magnitude of the corresponding energy index. This can be used to update the geological map of a quarry based mainly on the directions of natural fractures. 1 INTRODUCTION The "Societe des Carrières du Tournaisis (SCT)" is mining the "Carrière du Milieu", a quarry in Gaurain-Ramecroix, a village close to the Tournai city, Belgium. This quarry supplies two big companies with crushed materials (Holcim) and cement+crushed materials (Italcimenti) for an overall planed production of 11 millions tons per year. While the cement production relies on the chemical quality of the limestone, the production of crushed rocks requires good mechanical properties. The Tournai's limestone deposit is intersected by a series a sub vertical joints that divide the body into different blocks, and hence, lead to the typical cave weathering phenomenon. The mining operations in the quarry show that the extent of weathering, mainly in the shallowbenches, can lead to a recovering of less than 40% of the rocks, the remaining material is dumped in the waste backfilling area of the western depleted part of the quarry. It is therefore of some importance to develop a prediction tool that can rapidly allowthe production engineer to decide about the destination of the removed block. 2 GEOLOGICAL DESCRIPTION OF THE SITE UNDER STUDY TheTournai's limestone outcrop belongs to the Carboniferous formations of the northern border of Namur's Synclinorium (Belgium). This is a strip lying from eastern Namur to western Lille in France.
ABSTRACT Underground exploitation of hard coal deposit in Ostrava-Karvina Coalfield which is the Czech part of Upper Silesian Coal Basin is accompanied by induced seismicity. This seismicity can be manifested negatively by rock bursts occurrence in underground workings and/or by vibration on the surface. The magnitude of surface vibration can be influenced by several factors. The basic factors are geological properties of rock mass – the thickness and the quality of overburden of Carboniferous strata and the level of underground water. In the paper authors analyse possible impact of these factors on surface vibration in conditions of Ostrava-Karvina Coalfield. The influence of rock burst and seismicity on surface is being observed by a network of standard underground and surface seismic stations and interpreted since late 1990's. In previous few years the particle velocity was measured by mobile seismic stations on Earth's surface in selected localities. These values were compared with those interpreted from the standard seismic network data. The analyses of geological properties, in the sites where the mobile seismic stations were situated and the assessment of differences between measured and interpreted velocities, give an idea how the geological properties influence the magnitude of particle velocity on the surface structures. The results are also discussed in the paper. 1 INTRODUCTION Annually several tens thousands of minor induced seismic events are recorded in Karvina part of Ostrava-Karvina Coalfield (OKR) in Czech Republic. OKR is the southern part of the Upper Silesian Coal Basin (see fig. 1). Energetically significant major induced seismic events are only few tens. Some of these events are accompanied by earth tremor. This fact is affected by several factors. Among basic factors the following ones can be included:The quantity of released seismic energy and the location of seismic focal area activity (epicenter), The physical and mechanical properties of rock mass environment between the seismic focal area and the place of seismic performance on surface, The properties of the strata under the surface (ground water level, geological structure, tectonics etc.). The impacts of induced seismicity on the surface are observed more or less in inhabited regions. 2 NATURAL CONDITIONS Carboniferous rock formation in Karvina part of OKR is created by Karvina and Ostrava strata (see figs 3 and 4). The coal seams of Karvina strata are recently massively exploited. Karvina strata represent a continental coal-bearing molasa in OKR (middle and upper Namur, Westphal A). In contrast to lithological nature of western part of OKR the sedimentary cycles are conspicuously longer and moreover sandstones are prevailing. Compression strength values of such rocks are distinctly higher ones than those of mudstones and siltstones. In thicker banks of rigid rock components then higher stress concentrations occur than in other parts of rock massif. This condition has been manifested most conspicuously in Saddle beds, which are basal part of Karvina series of strata. The Saddle beds are featured by several tens of meters thick banks of rigid rocks (sandstones, sandy siltstones and conglomerates (Dopita et al. 1997).
Abstract Typical run lives of electric submersible pumps (ESPs) in the Cooper Basin in Australia are in the range of 600 to 900 days. ESPs have been used in 15 different reservoirs in this area. When highly productive oil reservoirs were recently discovered in the Moomba area similar run lives were expected. However, the first 12 installations in the Moomba fields only ran an average of 87 days. In 2001 a team was formed to target improved run lives. The team included production, manufacturing, engineering and management personnel from the operating company and equipment supplier. The main problem areas identified were protector and electrical wellhead feedthru failures and power supply quality. This paper outlines the operational, engineering and equipment changes made in each of the problem areas and the resulting increase in run lives. Failure analysis of pulled equipment demonstrated that the elastomers utilized for motor protection were being degraded. Compatibility testing of elastomers, produced fluids and injected chemicals revealed that the produced oil and water were causing the elastomers to breakdown. Although the wells were vertical, conventional labyrinth protectors could not be used because of the low gravity of the crude. The solution was to engineer a new motor protection system that was virtually elastomer free. The design utilizes metal bellows, high-density oil for gravity separation protection and high-grade o-rings. This design resulted in the first ESP motor protection system that can be used in environments with light crude that is incompatible with standard elastomers. In addition, analysis of the power quality showed that the crude fuel utilized to power the generator sets was affecting power quality. The poor quality of the power supplied to the ESPs was potentially contributing to motor burns and wellhead penetrator failures. To improve power quality a cleaner fuel supply was sourced. The run life improvement project is ongoing and the outcome of increased run lives is readily demonstrated. The Moomba Field In 1997, after 31 years of gas production, oil was discovered in the Namur and Hutton formations overlying the Moomba gas fields. To date, five oil pools have been discovered. These pools have strong aquifer support and each contain between one and five wells. Initial rates of between 3000 and 5000 barrels of low gravity (50 °API) oil per day (bopd) were typical for the wells. The primary method adopted for artificial lift was ESPs although some of the wells' productivity has declined over time requiring the installation of lower rate artificial lift systems. The Moomba 94 pool was discovered in 1997 during the drilling of Moomba 87, a gas development well. Moomba 94 was drilled as a twin of Moomba 87 and Moomba 97 was the subsequent development well in the pool. Both wells came online at initial free flow rates of 5000 bopd. Initially both wells were completed with ESPs, with Moomba 97 later being recompleted to a jet pump due to decreased productivity. In 1998, Moomba 95, another gas development well, also intersected oil. This oil discovery was developed by Moomba 102, a high angle development well. Moomba 102 was completed with an ESP but was also later recompleted to jet pump. Moomba 104 exploration well, targeting oil, was drilled in 2000 and discovered the third economic oil pool in Moomba. The well tested 5000 bopd on free flow. Four further oil development wells (Moomba 118, 135, 160, 161) were subsequently drilled on this pool. Moomba 104 and 135 were completed with ESPs. The remaining wells had lower initial rates and were completed with other artificial lift methods.
Abstract The Eromanga Basin is an established Australian producing region with oil and gas found in several different Formations. At the request of an Operator, a project was undertaken to construct saturation-height functions for all the Eromanga reservoir units with a secondary objective being to define residual hydrocarbon saturations. Initial investigations revealed many reservoirs with residual hydrocarbon columns, the significance of which had not been well understood. The residual hydrocarbons implied that imbibition, rather than drainage, capillary pressure curves were representative of water saturations in the reservoir. This insight suggested higher oil-in-place and reserves volumes than previously assumed since mobile hydrocarbons are present very close to the pressure derived Free-Water Level in imbibition systems. When individual hydrocarbon Fields were considered, there were insufficient special core analyses to derive meaningful residual hydrocarbon or saturation-height relationships. However, on the basin scale, a significant volume of measurements had been acquired over a period of 22 years, albeit using different laboratories and a variety of measurement techniques. With knowledge of the measurement techniques and Formations sampled, the data were combined in such a way that consistent datasets were obtained for end-point relative permeabilities and drainage and imbibition capillary pressure curves. Interpretation of these datasets produced residual oil saturation and drainage and imbibition saturation height relationships. These relations were tested against those log-derived water saturations considered most reliable by the Operator, showing excellent matches. The model developed successfully described the water saturation distributions in the reservoirs tested in a manner not previously possible. Indeed, the use of the drainage and imbibition saturation-height functions together with residual hydrocarbon relationships provides a powerful tool to determine both static and dynamic fluid contacts, while checking the validity of wireline log-based water saturations. Introduction At the request of an Operator, a review has been undertaken of all the available Special Core Analyses (SCAL) for the Jurassic Oil reservoirs found in the Eromanga Basin of Australia. The primary objective of this study was to construct appropriate saturation-height functions for oil volume quantification and reservoir modelling. A secondary objective was the identification of residual oil saturations from suitable core analyses. The Jurassic reservoir units involved were the Adori, Basal-Jurassic, Birkhead, Hutton, McKinlay, Murta, Namur and Westbourne Formations. History The Eromanga Basin is an established producing area, with many fields and a large database of wireline log measurements and core analyses collected over more than 20 years. Despite a number of different Operators and a history of production in the area, the significance of the residual oil found below the pressure derived free-water levels (FWL) of many fields had not been fully recognised. The signs that imbibition may be significant in reservoirs include:presence of "residual oil" below the pressure derived FWL at discovery, dry oil production from close to a FWL, sharper log-derived transition zones than the reservoir permeability suggests. In addition, as oil fields are produced, water sweeps through sections of reservoir. These sections have gone or are undergoing water imbibition.
REVITALISATION OF THE GIDGEALPA OIL FIELD Abstract Appraisal drilling in the Gidgealpa Field which has a 20 year production history has confirmed the existence of a significant oil rim underlying the Permian Age Tirrawarra Sandstone gas reservoir and a large extension of the Jurassic Age Hutton Formation oil reservoir. An oil leg to the Tirrawarra Sandstone reservoir gas pool in the South Dome could be inferred from the geophysical, geological, and production performance data obtained from Gidgealpa-7 and Gidgealpa-16. A PVT analysis of a gas sample collected more recently from Gidgealpa-34 was strong evidence to support this interpretation. Gidgealpa-41 drilled on the northeast flank of a four way dip closed anticline flowed oil at 600 BOPD from clastic Permian aged Tirrawarra Sandstone, consequently confirming an oil leg to a known gas cap. The relatively low decline in production performance of the southern region of the performance of the southern region of the Hutton Sandstone oil pool indicated a reservoir extension. Alternate seismic mapping techniques using isopachs and recognition of high velocity layers were successful in eliminating high velocity calcareous zones in the Jurassic Age Namur Sandstone Member which previously hampered mapping of the field. Appraisal drilling successfully extended the Hutton reservoir limit by 1.5 kilometres to the south. Renewed focus has thus centred on these two (Hutton and Tirrawarra) oil pools which require separate development strategies. Introduction The Gidgealpa Field is located 24 kilometres north-west of the Moomba Gas Plant in the Cooper and Eromanga Basins, Plant in the Cooper and Eromanga Basins, South Australia (Fig. 1). The stratigraphy of the Cooper Basin (Late Carboniferous - Triassic) and Eromanga Basin (Triassic - Recent) is summarised in Figure 2. The Gidgealpa Field a single four way dip closed draped anticline is comprised of two subsidiary (North and South) culminations that are separated by a relatively shallow saddle. The majority of the oil is contained within the South Dome while most of the gas is in the North Dome. The Gidgealpa gas (Permian) field was discovered in 1963 by the drilling of Gidgealpa-2. The Gidgealpa oil field was discovered in 1984 by the drilling of Gidgealpa-17. A history of the Gidgealpa field development was discussed in an earlier paper. This paper presents the geological, geophysical and production performance data which led to further appraisal drilling on the Gidgealpa South Dome during 1990–91. This appraisal drilling programme proved up a large extension of the Hutton Sandstone oil reservoir and the existence of a significant oil leg to the Tirrawarra Sandstone gas reservoir. P. 1