Commercial Hydrocarbon Research Articles

An unconventional Neoproterozoic – Early Cambrian source rock interval in southern Oman: Implications for oil and gas generation

ABSTRACT The Neoproterozoic – Early Cambrian Ara intra-salt petroleum system in Oman has been the subject of several studies since the early 1990s, not least because of the exploration success that has accompanied the emergence of the play. As one of the oldest known commercial hydrocarbon systems, the properties of the source organic matter have been of particular interest. The Ara intra-salt hydrocarbon system consists of the Al Shomou Silicilyte, a rock which is composed of pure microcristalline silica, and carbonate colloquially known as “stringers”. Both occur as slabs encased in the Ara salt. In the case of the Silicilyte, the slabs can be shown to act both as source rock and reservoir. However, in the case of the carbonate stringers, the association is more ambiguous. A set of rock and oil samples have been selected from different wells penetrating the silicilyte and carbonate stringer plays to better characterize and understand these systems. As far as the sedimentary organic matter is concerned, the Al Shomou Silicilyte domain has an average Total Organic Carbon (TOC) of approximately 4 wt.%. The carbonate-prone domains exhibit rare organic-rich lithofacies (TOC of approximately 2 wt.%) and additional intra-salt shales (TOC of approximately 4 wt.%). The organic matter present in both the Silicilyte and carbonate plays is associated with a hypersaline and anoxic depositional environment, rich in sulfur, and showing very similar chemical signatures (bulk composition, elemental analysis, biomarker content, δ13C). The organic matter associated with these sequences is characterized by an unusual “asphaltenic” nature. Compared to classical fossil organic matter taken at an equivalent maturity level, the organic matter found in the intra-salt silicilyte, shales or carbonates releases a large amount of solvent soluble material, which is very rich in Nitrogen-Sulfur-Oxygen (NSO) compounds, implying a standard Type II-S kerogen. However, the organic matter differs from this classic characterization of kerogen (solvent insoluble) in that a large proportion appears to be a sulfur-rich “soluble” kerogen, which has not been previously described. Independent geochemical parameters (Rock-Eval analysis, kinetic parameters) seem to be consistent with this hypothesis. The thermal maturity of the whole set of samples examined places them in the oil window. Moreover, Thermochemical Sulfate Reduction (TSR) did not occur in these samples. As far as the soluble part is concerned, differences in the molecular (significant molecular variations for norhopanes, secobenzohopanes, carotane, X compounds, thianes, thiolanes) and sulfur isotopic composition were demonstrated, and are assumed to reflect subtle variations in depositional settings between Silicilyte and carbonate stringers. The specific properties of this unconventional organic matter has to be accounted for in the thermal modeling of oil and gas generation. Although the kinetic distribution for kerogen cracking is close to that of a Type II-S kerogen, it is slightly more mono-energetic. A compositional 2-D basin modeling (Temis 2D) was performed on a cross-section through the South Oman Salt Basin, using specific kinetic parameters measured on this unconventional Neoproterozoic – Early Cambrian kerogen (based on a linear grouping of insoluble kerogen and NSO like “soluble kerogen” kinetic parameters). The gas-to-oil ratio GOR prediction was improved within the silicilyte, when compared to the use of classical parameters assigned to Type II-S kerogen. Finally, the microcrystalline silica mineral matrix of the silicilyte plays is proposed to play a major role in the composition of the fluid, which is expelled and produced by imposing a strong geochromatographic effect on fluids and the retention of polar compounds. The preferential release of aliphatics would lead to the production of oils exhibiting a strong condensate character. This effect has to be considered when modeling the actual composition of the movable fluid in the silicilyte. The significance of the geochromatographic effect is yet to be quantified, but according to available observations, we suggest that this geochromatographic effect could explain the observed API gravity difference between oils produced from silicilyte and carbonate plays.

Suppression of Anode Degradation by Sulfur using an Anionic Catalyst

Fuel cells can be regarded as catalysed chemical reactors. They can therefore be highly sensitive to the purity of the relevant reagent, the fuel. The anode catalyst in the standard SOFC is a metal-ceramic composite characterised by rapid and significant deterioration of its activity when exposed to sulfur contaminants in the fuel, even in ppm. concentrations. However commercial hydrocarbon liquid fuels regularly contain some quantity of sulfur compounds as impurities, and sulfur compounds are even deliberately added as odorants for safety reasons in gaseous fuels. Therefore a desulfuriser unit is a normal subsystem in any SOFC installation. An anode with high intrinsic sulfur tolerance would clearly simplify SOFC system design, as well as offering lower capital and operation costs. In a technology transfer from petrochemicals practice, hydrodesulfurisation catalysts using heavy metals have been investigated and showed partial protection of the anode. However a recent observation established an even more effective desensitisation to sulfur of a Ni-YSZ cermet anode modified by an anionic activator.

On the probable lifting of deep hydrocarbons into the crustal waveguide

The equilibrium thermodynamic calculations made for C-H and C-H-N-O-S systems show that the mantle might contain a fluid consisting of heavy (high-molecular) hydrocarbons (HHC) and their derivatives, as well as of inorganic gases (H2O, CO2, N2, NH4, H2S, etc.). In the range of diamond-graphite phase transition, the HHC are decomposed to form methane, its nearest homologues, and graphite. The geochemical and experimental data by different authors point to possible HHC occurrence in the upper mantle. These results confirm the concept by Dmitrievskii (2006) that the deep fluids might be lifted to the crustal waveguide to fill its fractures and cavities. Owing to compaction, the fluids are squeezed from the waveguide and lifted into sedimentary layers to form the commercial hydrocarbon deposits. Resulting from the “washing“ of sedimentary rocks with the fluids, hydrocarbon gases and oil of organic origin might be formed.

Understanding the critical success factors determining prospectivity—Otway Basin, Victoria

The critical success factors that control hydrocarbon prospectivity in the Otway Basin have been investigated using petroleum systems approaches. It have revealed that greater than 99% of the discovered hydrocarbons in the Victorian Otway Basin have been sourced from Austral 2 (Albian-Aptian) source rocks and that these Austral 2-sourced hydrocarbon accumulations either directly overlie—or are located within 3,000 m—of actively generating Austral 2 source rock kitchens. Importantly, the zones of greatest prospectivity are located where these source rocks have been actively generating and expelling hydrocarbons throughout the Late Paleogene, primarily as a result of sediment loading associated with progradation of the Heytesbury shelfal carbonates. This peak generation window occurs at an average depth of approximately 2,500–3,500 m sub-mud across much of the basin, which has allowed prospective hydrocarbon fairways to be mapped out, thereby highlighting areas of greatest prospectivity. The close spatial proximity of the actively generating source rocks to the accumulations is due to several factors, which include overall poor fault seal in the basin (success cases occur where charge rate exceeds leakage rate) and relatively complex and tortuous migration fairways (which means that large volumes of hydrocarbons are only focussed and migrate for relatively short distances). In areas within which the Austral 2 system comprises the sole hydrocarbon charge—such as across the inner Mussel Platform—the reservoired gas compositions are typically very dry. In contrast, the gas compositions in accumulations sited along or immediately inboard of the Mussel-Tartwaup Fault Zone (La Bella, Geographe and Thylacine) are significantly wetter and also have higher CO2 contents. Throughout this area, the wetter components of the reservoired hydrocarbon inventory may have a source contribution from within the basal (Turonian) part of the younger Austral 3 system, in sequences that have been confirmed by δTLogR analysis to be significantly enriched in total organic carbon content. This observation has significantly upgraded the potential of the upper shelf areas, where a relatively more liquids-rich hydrocarbon inventory might be expected. The CO2 in accumulations located along the Mussel-Tartwaup Fault Zone is interpreted, based upon new helium isotope data, to be of mixed deep crustal-magmatic origin. This CO2 is believed to have migrated from great depth up the crustal-scale fault arrays into the shallower Late Cretaceous reservoirs. Here, the CO2 mixed with crustal gases, typified by helium with a mixed magmatic-crustal isotopic signature. Throughout this area, the traps tend to be large and hence—even though their CO2 contents are only 8–12%—the total CO2 volumes contained in these accumulations are much greater than those in the very CO2-rich—but volumetrically small traps—located onshore (e.g. Boggy Creek). Hydrocarbon accumulations located on the inner shelf, such as Minerva and Casino, have distinctly lower CO2 contents, perhaps because large displacement, through-going faults are lacking in this area. These observations collectively provide a predictive regional framework for understanding the likely distribution of commercial hydrocarbon accumulations in the offshore Otway Basin, as well as for forecasting the gas wetnesses and CO2 contents of undrilled exploration targets in both well-explored and frontier parts of the basin.

Toxic pneumonitis caused by inhalation of hydrocarbon waterproofing spray in two dogs

2 dogs were evaluated because of vomiting and lethargy (a Toy Poodle; dog 1) and acute respiratory distress, vomiting, and anorexia (a Chihuahua; dog 2). Dog 1 had been exposed to a commercial hydrocarbon waterproofing spray 24 hours before the development of clinical signs, and dog 2 was examined 18 hours after exposure to a waterproofing spray containing heptane, a highly flammable liquid hydrocarbon. In both dogs, major gastrointestinal tract abnormalities were ruled out but respiratory status worsened. Thoracic radiography revealed a diffuse interstitial pulmonary pattern, and hypoxemia was detected. Hospitalization for monitoring and care was required for both dogs. The dogs recovered with supportive care, which included administration of oxygen, fluids, and bronchodilators. Additionally, dog 1 received glucocorticoids via inhalation and supplemental enteral nutrition, whereas dog 2 was treated with an antimicrobial. The dogs of this report developed hydrocarbon pneumonitis following exposure to waterproofing sprays. Such sprays contain potentially toxic hydrocarbons. The severity of the adverse effects associated with exposure may have been amplified because the dogs were physically small and were exposed to a relatively large amount of aerosolized spray within small areas. Development of chemical pneumonitis in pet animals is best prevented by application of waterproofing sprays in well-ventilated or outdoor areas from which pets have been excluded. With prolonged hospitalization and considerable monitoring and care, affected dogs can recover from these exposures.

PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA

Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.

Profiling Refined Hydrocarbon Fuels Using Polar Components

Identification of a fuel released into the environment can be difficult due to biodegradation or weathering. Negative electrospray ionization/mass spectrometry was used to screen for unique polar components in a wide variety of commercial hydrocarbon products and mixtures. These fuels produced unique and relatively simple spectra. When applied to hydrocarbon samples from a large, long-term fuel spill in a relatively cool climate in which the alkane, isoprenoid, and alkylcyclohexane portions had begun to biodegrade or weather, the polar components in these samples had changed little over time. This technique provided rapid fuel identification on hydrocarbons released into the environment, without sample preparation, fractionation, or chromatography.

Comments: Deepwater Promise

The successful completion of an extended production test by Chevron, Statoil, and Devon on a well in the Lower Tertiary of the U.S. Gulf of Mexico (GOM) may prove to be a watershed event for the GOM and several operators, and could even usher in a new era of deepwater production. The much-anticipated test on the Jack #2 well on Walker Ridge Block 758 showed sustained flows of more than 6,000 BOPD. Operator Chevron, which has a 50% interest, and Statoil and Devon, each with a quarter share, plan an additional appraisal well next year. Jack, which was discovered in 2004, was one of the most closely watched GOM developments in recent memory because if development of the Lower Tertiary is feasible, it could open up a potentially prolific area to production. It is one of eight discoveries in the past 3 years in this GOM trend offshore Louisiana. Several analysts believe the area could produce as much as 500,000 BOPD within several years and hold as much as 15 billion bbl in reserves. Other estimates are more optimistic, predicting up to 800,000 BOPD of light, sweet crude and 1 billion cf/D day of natural gas coming from the reservoir by 2012. Chevron said that the Jack production test was the deepest successful well test in the GOM. Currently, there is no production from the Lower Tertiary, and Jack is one of several recent promising discoveries from this zone. Now the industry is finally beginning to get an idea of the extent of commercial hydrocarbons there. But output from the Lower Tertiary is not without significant hurdles. Mapping will be a challenge because of the thick salt layers, and wells and production facilities will be expensive. The Jack well is located in 7,000 ft of water and was drilled to a depth of more than 28,000 ft. Getting the production to the U.S. mainland—whether by pipeline or through the use of floating production systems—also presents issues. And, while the Jack test well met producers' expectations, overly optimistic expectations seem premature. Some of the industry's most promising and recent production developments are of increasing complexity. Hydro's Ormen Lange gas project in the North Sea, for example, is requiring complicated subsea installation and pipeline infrastructure. If the development of this trend confirms its expected potential, it will be another tribute to what upstream technology advances are making possible. Output from this deepwater frontier would not be possible without recent seismic advances as well as advances in rig technology. The news is certainly promising to several producers who hold additional leases nearby, including Chevron, Devon, Shell, Anadarko, and others. Devon said its Lower Tertiary acreage could more than double its reserves base of 2 billion BOE. Jack is one of four discoveries by Devon in the Lower Tertiary. The others are the Kaskida discovery made this year, the Malo prospect drilled in 2003, and Cascade—in which Devon doubled its working interest to 50% this summer—drilled in 2002. The Cascade prospect, scheduled for startup in 2009, will be the first deepwater Lower Tertiary field to come on line, according to the company. Devon, once a small U.S. independent, has grown rapidly during Chief Executive Officer Larry Nichols' tenure through a series of careful acquisitions and strategic drill-bit plays (see July 2006 JPT Q&A).

Experimental study of thin-layer boilover in large-scale pool fires

By performing a series of pool fire experiments, the authors attempt to apply knowledge of thin-layer boilover to the large scale (pool diameter from 1.5 to 6 m). Two commercial hydrocarbons were used: gasoline and diesel. As expected, only in the case of diesel did the phenomenon of thin-layer boilover occur. Data were used to analyze various features of thin-layer boilover in fires, particularly its intensity and onset time. A comparison with results published in the literature shows the importance of this study.

Nonconventional hydrocarbon targets in the crystalline basement, and the problem of the recent replenishment of hydrocarbon reserves

Analysis of the distribution of oil pools in sedimentary cover has shown that known platform hydrocarbon fields are closely associated with faults in the crystalline basement and the sedimentary cover itself. Oil pools in the lower productive beds of the sedimentary cover are linked to faulted zones in the crystalline basement. A genetic relationship between oil fields and tectonic dislocations indicates a dominant role for vertical migration in the accumulation of commercial hydrocarbons in the Paleozoic. The conducted geochemical, palynological, geophysical and geological studies have shown that oil and gas pools in the upper sedimentary cover have been formed due to the vertical migration of hydrocarbons, which is also confirmed by the vertical alignment of the oil pools.

Assessing the aquatic hazard of commercial hydrocarbon resins

Hydrocarbon resins are used to modify polymer products to achieve desired functional properties for a diverse range of products. These complex hydrocarbon-based mixtures are typically poorly soluble in water. However, resins may leach lower-molecular-weight monomers or impurities upon contact with water, thus posing a potential hazard to the aquatic environment. The bioavailability and toxicity of leachable constituents of four solid and three liquid resins were evaluated by analyzing water-accommodated fractions prepared with each resin, using biomimetic solid phase microextraction (SPME) techniques. Liquid resins exhibited concentrations of bioavailable constituents that were sufficiently elevated to cause acute toxicity to the aquatic organism Daphnia magna. All solid resins exhibited lower bioavailable concentrations of leachable constituents that were unlikely to pose an aquatic toxicity concern. Since observed toxicity of both resin types was generally consistent with bioavailable concentrations determined using SPME fiber measurements, it is concluded that this approach provides a convenient in vitro screening tool that can help reduce the use of animal testing in environmental hazard assessment of complex hydrocarbon-based substances.

Overview: Well Testing (February 2006)

Careful well-test design applied intelligently to exploration and development situations is the reality check for information that many times can only be inferred from other reservoir-evaluation tools. With drilling rigs in short supply and day rates at historic high levels, smart application of well-test technology may reduce costs considerably by use of short-duration openhole wireline-test equipment. Commerciality can be determined quickly and rigs moved on to the next objective or well. In contrast, extended well tests, conceived to prove a commercial hydrocarbon accumulation, may provide enough data to validate a reservoir description and clear economic hurdles without drilling an additional well—important for time-critical decisions on adjacent leases. Many times in the operating environment, a petroleum engineer may use well-test results to provide a reality check and economical data acquisition for geophysicists, production geologists, and simulation engineers on one end of the organization and production operations personnel pushed to maximize well rates on the other end. Careful well-test planning and analysis can satisfy both extremes. Reservoir-characterization professionals can validate reservoir boundaries, pressures, and the accuracy of production history. Production operations can maximize production confidently in a miscible-gas flood without going below minimum miscibility pressure and compromising recovery. A delicate balance can be maintained with little or no production loss, allowing responsible reservoir management while maximizing rates and ultimate recovery. With oil prices hovering around U.S. –60/bbl, there has never been a larger incentive to optimize well testing in exploration, development, and production environments. This month's selections show how relatively conventional testing procedures, applied intelligently, can accelerate development decisions. Deconvolution of real-time reservoir performance is always going to be an attractive goal in well-test analysis to eliminate production loss from conventional pressure-transient analysis. Use of multiple analysis techniques can be complementary to other reservoir-characterization methods. Advances in intelligent completions, permanent data-acquisition systems, and flow-measurement technology continue to entice petroleum professionals into devising innovative techniques for advanced well-test analysis. Well Testing additional reading available at the SPE eLibrary: http://www.spe.org/ SPE 96026 "Determination of Optimal Window Size in Pressure-Derivative Computation Using Frequency-Domain Constraints," by Y. Cheng, SPE, Texas A&M U., et al. SPE 94436 "Time-Lapse Production Logging and the Concept of Flowing Units," by O.D. Cortez, SPE, Centrica Energy, et al. SPE 94018 "Application of Buildup Transient-Pressure Analysis to Well-Deliverability Forecasting in Gas/Condensate Reservoirs Using Single-Phase and Two-Phase Pseudo pressures," by M. Bozorgzadeh, SPE, Imperial College, London, et al.

Differentiation of Commercial Fuels Based on Polar Components Using Negative Electrospray Ionization/Mass Spectrometry

Polar components in fuels may enable differentiation between fuel types or commercial fuel sources. A range of commercial fuels from numerous sources were analyzed by flow injection analysis/electrospray ionization/mass spectrometry without extensive sample preparation, separation, or chromatography. This technique enabled screening for unique polar components at parts per million levels in commercial hydrocarbon products, including a range of products from a variety of commercial sources and locations. Because these polar compounds are unique in different fuels, their presence may provide source information on hydrocarbons released into the environment. This analysis was then applied to mixtures of various products, as might be found in accidental releases into the environment.

Exploration history of the Ara intrasalt carbonate stringers in the South Oman Salt Basin

ABSTRACT The Ara intrasalt carbonate ‘stringer’ play is one of oldest petroleum occurrences known in the world (terminal Neoproterozoic to Early Cambrian age), and it constitutes one of the most complex and unconventional deep oil and gas plays in Oman. The reservoirs are commonly over-pressured, and consist of porous dolomitic carbonates that are encased in salt at depths of 3–5 km. The mostly shallow-water carbonates pose a challenge; both in terms of understanding the origin and spatial distribution of the various lithofacies, and in building predictive reservoir models. In addition, early phases of salt movement influenced carbonate sedimentation and dolomitization, the sedimentation of reservoir and source-rock facies and the structural development that later governed oil migration. While the thick halite sequences provide the seal for the intra-formational trapping of hydrocarbons, the geometry of these thick salt pillows (combined with deep, present-day burial of these reservoirs) affects seismic resolution. The intrasalt stringers were previously regarded as a self-charging hydrocarbon system, containing carbonate source rocks in close proximity or even within the dolomite reservoirs. More recent documentation of a presalt charge, in some of these stringers, adds a new level of complexity to this petroleum system. Carbonate intrasalt stringer exploration in the South Oman Salt Basin (SOSB) started with the unexpected discovery of moveable oil in Nasir-1 in 1976. This launched the first phase of stringer exploration that focused on the Birba and Dhahaban areas. Despite the addition of significant reserves during this campaign, the stringer play proved to be complex. Limited knowledge of the depositional systems and diagenetic history of the stringers made the predicton of reservoir quality difficult and the understanding of production behaviors next to impossible. Difficulty in delivering expected reserves forced the play to become dormant in 1986. The second phase of stringer exploration started in 1988 after a review of deep exploration opportunities that highlighted the play potential outside the proven Birba and Dhahaban areas. All wells drilled during this phase failed to discover commercial hydrocarbon accumulations, thus forcing the play to become dormant for a second time. This short-lived campaign, however, led to the Al Noor Athel discovery, a silicious tight reservoir also encased in the Ara salt. This discovery launched an Athel exploration campaign that lasted until 1997. The Athel campaign did not result in any further commercial discoveries either, however it revived the interest in the Ara stringers with the discovery of oil in Harweel Deep-1 in 1997. Continued success in the Harweel area has maintained interest in stringer exploration to this day and has led to the fast-track development of some Harweel stringer discoveries, which are now contributing significantly to PDO’s oil production. Since 2001, the play has been tested outside the Harweel fairway with limited success. A substantial part of the prospect portfolio remains untested mostly residing outside the Harweel area. Increasing the chance of exploration success will require significant improvements in seismic imaging, better prediction of reservoir occurrence, improved produceability from discovered reservoirs, and a better understanding of hydrocarbon charge history.

AVALIAÇÃO DE DESCOBERTAS DE RECURSOS PETROLÍFEROS: UMA PROPOSTA DE PADRONIZAÇÃO

This paper presents the framework of a standardization proposal for the existing information flow among the Brazilian regulator office of the petroleum industry (ANP) and the concessionary companies which run activities of petroleum exploration in the Brazilian sedimentary basins in case of the discovery of any potentially commercial hydrocarbon resources inside their concession areas. The framework is oriented towards the Brazilian oil and gas regulatory model which employs a guide called Plan of Discoveries Assessment (PAD) which outlines the main procedures that the oil companies have to comply with. Based on the main aspects of the Brazilian regulatory model and upon a small sample of PADs, a standard procedure routine was developed in order to introduce a significant gain in the quality level of the information content of the PADs. In this sense the proposed framework needs to have a broad view to include the information flow in order to achieve better evaluation efficiencies from the discovery process and the decision process. The approach uses a consistency scheme and an evaluation test in the six information blocks in the PADs: Executive Summary, Discovery Description, Geology and Reservoirs Description, Evaluation Program, Safety and Environment and Interpretation Project. Simulation performed with a small group of PADs allowed detecting the prospects characteristics that deserve improvement in the level of information, provoking a substantial gain in the dealing with the geological data.

Screening of Polar Components of Petroleum Products by Electrospray Ionization Mass Spectrometry

The polar components of fuels may enable differentiation between fuel types or commercial fuel sources. Screening for these components in the hydrocarbon product is difficult due to their very low concentrations in such a complex matrix. Various commercial fuels from several sources were analyzed by flow injection analysis/electrospray ionization/mass spectrometry without extensive sample preparation, separation, or chromatography. This technique enabled screening for unique polar components at very low concentrations in commercial hydrocarbon products. This analysis was then applied to hydrocarbon samples collected from the subsurface with a different extent of biodegradation or weathering. Although the alkane and isoprenoid portion had begun to biodegrade or weather, the polar components had changed little over time. Because these polar compounds are unique in different fuels, this screening technique can provide source information on hydrocarbons released into the environment.

Modelling the effects of transient overpressure on the petroleum systems of the UK North East Atlantic Margin and northern North Sea areas: implications for the deep water South Atlantic and Gulf of Mexico

Transient fluid overpressure development appears to be a major control on the contrasting petroleum systems of Faroe–Shetland Basin (FSB) on the UK North East Atlantic margin and the northern North Sea North Viking Graben (NVG). Middle and Upper Jurassic shales are the main source rocks in both the NVG and the FSB, but the hydrocarbons within these basins differ significantly. Oil is predominant with only minor associated gas in the FSB while the NVG has a significantly higher proportion of dry gas. Both are rifted basins but the amount of rifting, heat flow and depth of burial were all considerably greater in the FSB, and consequently higher maturity hydrocarbons should be present in the FSB than in the NVG. The difference in hydrocarbon type between the basins arises from the different Cenozoic burial and, importantly, pressure histories in the two basins. Oil generation commenced during the early Cretaceous in both basins and some Mesozoic reservoirs may have been charged at this time. Rapid burial of thick argillaceous sediments in both basins from the late Cretaceous into the Tertiary led to overpressure development. The thermodynamic effect of this fluid overpressure in the source rocks was the retardation of hydrocarbon generation. In the NVG, regional uplift during the Tertiary resulted in transient overpressure reductions in the source rocks such that hydrocarbon generation, which had ceased prior to the uplift events, restarted due to the pressure reduction outstripping the effects of reduced temperatures. Although the source rocks were cooler than those in the FSB, the reduction in overpressure was sufficient to result in gas generation from both the Middle Jurassic and lower part of the Upper Jurassic source rocks. Conversely, although the FSB was also uplifted during short-lived Paleogene and Neogene events, the greater thickness of argillaceous late Cretaceous sediments reduced the transient overpressure loss in the source kitchens compared with the NVG. The maturity of the source rocks in the FSB was therefore held in the late oil window and, as a consequence, oil is the predominant hydrocarbon phase in this basin. The importance of overpressure development (or lack of it) and its subsequent release has major implications for petroleum prospectivity of basins. This is illustrated using the NE Kwanza Basin (Angola) and the Mississippi Fold Belt in the Gulf of Mexico (GoM). Whereas there are no commercial hydrocarbon discoveries in the deepwater Kwanza Basin due to lack of regional seal between the oil mature Pre-Salt source and the overlying migration conduit into the shelf, significant oil reserves occur in the deepwater GOM where the source rock depth (∼10 km) might be expected to preclude the presence of oil. The key to the release of oil from the source kitchens is the salt movement that occurs during the Neogene with the formation of salt canopies. As the salt moves vertically, it reduces the overpressure, thereby enabling oil generation to restart and migrate vertically along faults.

PETROLEUM POTENTIAL OF THE CEDUNA SUB-BASIN: IMPACT OF GNARLYKNOTS–1A

The Ceduna Sub-basin, located in the eastern Bight Basin, is one of the few frontier deepwater provinces in Australia whose hydrocarbon potential remains largely untested. The sediments of the sub-basin span an area of over 95,000 km2—comparable to the combined area of the Exmouth, Barrow and Dampier sub-basins on Australia’s North West Shelf. Prior to 2003, exploration wells had been drilled only on the present day shelf area of the sub-basin. The recent Gnarlyknots–1A well, drilled in May 2003 by the Woodside operated joint venture in EPP29, has provided the first calibration point in the under-explored deepwater area of the sub-basin.The well was the culmination of a basin analysis project that integrated results from prior drilling in adjacent areas, existing seismic surveys, regional gravity and magnetics interpretations, and a newly acquired 16,000 line km 2D seismic survey. Individual play elements of reservoir, seal, and hydrocarbon charge were analysed and combined to form play maps for key stratigraphic intervals. The Gnarlyknots prospect was chosen from more than 40 leads as the best location to test multiple play levels in an area interpreted pre-drill to be favourable for reservoir, seal, and charge.Gnarlyknots–1A confirmed the presence of several favourable play elements but failed to encounter commercial hydrocarbons. Excellent quality sandstone reservoirs, marine shale top seals and thermogenic hydrocarbon shows—indicating the presence of a hydrocarbon source rock in a mature kitchen area downdip—were all encountered in the well. The failure of the well is attributed to the absence of fault seal on the updip bounding fault of the drilled hanging wall structure. The implications of this well result for the prospectivity of the Ceduna Sub-basin have been analysed, and provide encouragement for Woodside to pursue future exploration programs in the region.

Variations in mixed-layer illite/smectite diagenesis in the rift and post-rift sediments of the Jeanne d'Arc Basin, Grand Banks offshore Newfoundland, Canada

Mixed-layer illite/smectite (I/S) clays were analyzed from 22 deep exploration wells from the Jeanne d'Arc Basin on the Grand Banks offshore Newfoundland, the host of large commercial hydrocarbon accumulations discovered in the last two and a half decades. The fine fraction of the clays (<0.1 µm) consists mainly of mixed-layer I/S with minor amounts of kaolinite, illite, and chlorite. Smectite and (or) smectite-rich I/S clays were supplied to the Jeanne d'Arc Basin from Upper Jurassic to Tertiary times. Smectite-rich I/S clays occur only in shallow samples irrespective of geologic age. The proportion of illite in I/S mixed-layers, as well as the degree of ordering, increase with depth and temperature indicating that smectite-rich I/S clays have been progressively illitized in both rift and post-rift sediments of the Jeanne d'Arc Basin during burial. The transition from random to R1-ordered I/S occurs between subsurface depths of 1940 and 3720 m and crosses major stratigraphic boundaries. The transition from R1- to R3-ordered I/S generally occurs below 4000 m depth. Variable shapes of I/S depth profiles reflect the influence of temperature, fluid migration, subsidence history, basin structure, lithology, and salt diapirism on I/S diagenesis. Based on these variations, the basin can be subdivided into 4 regions with different illitization gradients. In the Southern Jeanne d'Ac Basin, advanced I/S diagenesis probably reflects uplift and denudation and (or) higher paleogeothermal gradients. Rapid increase of percent illite in I/S with depth in the Trans-Basinal Fault area is most likely controlled by upward flow of hot, K+-bearing fluids along faults. The migration of hydrocarbons probably followed the same pathways as the illitizing fluids. Delayed illitization in the Northern Jeanne d'Arc Basin and Central Ridge area reflects insufficient K+supply because of a lack of detrital K-feldspar in the host sediment, the absence of faulting, and the presence of thick shale intervals. These findings show that I/S depth profiles may vary within the same sedimentary basin due to a variety of geological factors. Single wells generally cannot be considered representative for the basin as a whole.

New geochemical data from the Nigerian sector of the Chad basin: implications on hydrocarbon prospectivity

Organic geochemical studies have been carried out to assess the qualities of source rocks penetrated by four wells (Kemar-1, Murshe-1, Tuma-1 and Ziye-1) in the Nigerian sector of the Chad basin. The Chad basin is a large intracratonic basin in Central West Africa. Commercial hydrocarbon accumulations have been discovered in some sectors of the basin outside the Nigerian border in a structurally related contiguous basin. Fair to poor quality source rocks are inherent in the sequences penetrated by the studied wells. About 80% of all samples have their total organic carbon (TOC) contents more than 0.5 wt.%, the minimum limit for hydrocarbon generation. Juxtaposition of the hydrogen indices against the TOC and T max indicates that the source rocks are entirely gas-prone. However, biomarker chromatograms and extract vs. TOC plots indicate the presence of oil shows in Ziye-1 well at a depth of 1210 m. Although generated hydrocarbons (wherever they have accumulated) would be overwhelmingly gaseous, gas is the energy of the future. The gas resources of this part of Nigeria's inland basins can be economically exploited through policies that will increase the tempo of gas-utilization projects and the construction of a national grid of gas pipelines with nodal points of input and output.