Abstract Cutting-edge techniques have always been utilized in petroleum exploration and production to reduce costs and improve efficiencies. Innovations in analytical methods will continue to play a key role in the industry moving forwards, as society shifts towards lower carbon energy systems. This volume brings together new analytical approaches and describes how they can be applied to the study of petroleum systems. The papers within this volume cover a wide range of topics and case studies, in the fields of fluid and isotope geochemistry, organic geochemistry, imaging and sediment provenance. The work illustrates how the current, state-of-the-art technology can be effectively utilized to address ongoing challenges in petroleum geoscience.

Abstract The application of production geochemistry techniques has been shown to provide abundant and often low-cost high-value fluid information that helps to maximize and safeguard production. Critical aspects to providing successful data relate to the appropriate sampling strategy and sampling selection which are generally project-aim-specific. In addition, the continuous direct integration of the production geochemistry data with subsurface and surface understanding is pivotal. Examples from two specific areas have been presented including: (a) the effective use of IsoTubes in the production realm; and (b) the application of geochemical fingerprinting primarily based on multidimensional gas chromatography. Mud gas stable carbon isotopes from low-cost IsoTubes have been shown to be very effective in recognizing within-well fluid compartments, as well as recognizing specific hydrocarbon seals in overburden section, including the selective partial seal for only C 2+ gas species. With respect to geochemical fingerprinting, examples have been presented related to reservoir surveillance including compartmentalization, lateral and vertical connectivity, as well as fluid movements and fault/baffle breakthrough. The production-related examples focus on fluid allocation within a single well, as well as on its application for pipeline residence times, fluid identification and well testing.

Abstract Palaeoformation water trapped in quartz cements in sandstone during diagenesis is typically of interest for constraining the temperature history, cementation and timing of hydrocarbon charge. Recent progresses in developing methods for salinity measurement, gas detection (CH 4 , CO 2 , N 2 , H 2 S) and fluid modelling of the CH 4 –H 2 O–NaCl system by combining conventional microthermometry techniques with Raman spectroscopy provide powerful tools for investigating formation water and its evolution in gas-bearing basins. Samples from the aquifer, in the Plover Formation and in the Brewster Member in the Upper Vulcan Formation, underlying large gas accumulations in the Caswell Sub-basin provided an opportunity to test these new techniques and generate data on formation water evolution. Temperature of homogenization, salinity and gas content of water inclusions show that the salinity of the palaeoformation waters decreased with increasing methane content and temperature. Detection of CO 2 shows, however, that water inclusions with dissolved CO 2 , often in association with CH 4 , do not follow the same salinity trend. These inclusions are often associated with higher trapping temperatures. The salinities associated with water reaching methane saturation (coeval with free gas) are between 8500 and 24 000 ppm eq. NaCl (0.8–2.4 wt%). An influx of meteoric water from the Ashmore Platform in the north is presented as a hypothesis on the origin of the low salinities of the formation water in the Plover Formation in the Browse Basin, supported by the distribution of the lowest palaeowater salinities, but still remains problematic.

Abstract Stable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. Many isotope classification systems used for gas to source rock correlation and thermal maturity determination are primarily based on empirical observations made in conventional reservoirs and the kinetic isotope effects observed during pyrolysis experiments performed on source rocks. However, such relationships may not be readily applicable to onshore unconventional reservoirs due to the strong molecular and isotope fractionation that occur during extensive gas expulsion associated with basin uplift and depressurization. Degassing studies of freshly recovered core samples can provide useful insight into the behaviour of gas molecules in unconventional reservoirs during basin uplift. The analyses of Australian coal and marine shale samples demonstrate that during desorption both molecular and isotopic compositions of gas change at variable rates. Gas initially desorbed from the samples is mostly CH 4 , whereas later desorbed gas becomes increasingly enriched in C 2 H 6 and higher hydrocarbons. Hydrocarbon molecules also fractionate according to their isotopic composition, where the early released gas is enriched in 12 C causing the remaining gas in the reservoir to be enriched in the heavier 13 C isotope. During the release of gas from the Bowen Basin coals the C isotope ratio of CH 4 ( δ 13 C 1 ) changes by up to 21‰ (VPDB), whereas that for C 2 H 6 ( δ 13 C 2 ) and C 3 H 8 ( δ 13 C 3 ) changes by <6‰. Similar changes in the isotope composition can be seen during the release of gas from marine source rocks of the Beetaloo Sub-basin. In a fully gas-mature middle Velkerri shale sample, δ 13 C 1 changes by up to 28‰ and δ 13 C 2 by up to 3‰ with no appreciable change occurring in δ 13 C 3 . The extent of molecular fractionation during gas flow through carbonaceous rocks is primarily related to the adsorption–desorption properties of organic matter and diffusivity through the overall rock matrix. Using the current dataset, the magnitude of the contributions exerted by the desorption and diffusion processes cannot be readily distinguished. However, both Bowen Basin coals and Beetaloo Sub-basin shale show similar fractionation effects during gas flow, where the heavier alkane molecules, including those containing more 13 C, desorb and move slowly compared with the lighter components, in particular CH 4 . Different rates of isotope fractionation between hydrocarbon molecules during gas flow cause the shape of compound-specific-isotope (CSI) curve to change with time. Early released gas is characterized by a normal CSI trend where the short-chain hydrocarbons are isotopically lighter compared with the longer-chain hydrocarbons. Because CH 4 and C 2 H 6 molecules enriched in 12 C desorb and diffuse more readily than the heavier hydrocarbons (including those enriched 13 C), the gas remaining in the coal and shale samples after extensive desorption shows a reversed CSI trend where CH 4 and C 2 H 6 are isotopically heavier compared with the longer chain hydrocarbons. Reversed isotope trends may also develop over geological time, particularly where the source rock is fully gas-mature and has expelled hydrocarbons due to prolonged degassing. As seen in the Beetaloo Sub-basin, the CSI trend in the dry-gas-mature Velkerri shale is reversed, possibly due to the loss of a large proportion of originally generated CH 4 during post-Cambrian basin uplift.

Abstract The potential of polar compound compositions from electrospray ionization ultra-high resolution mass spectrometry (FT-ICR-MS) to characterize petroleum fluids as well as petroleum system processes is shown in the example of the Eagle Ford Formation in Texas, USA. A set of six black oil and nine source-rock bitumen samples is investigated with respect to its organic nitrogen-, sulphur- and oxygen-compound inventory in order to assess maturity, depositional environment, lithofacies and retention and migration behaviour. Compared to conventional geochemical tools based on molecular parameters from gas chromatographic analyses, FT-ICR-MS enables a maturity assessment from immature to late mature stage, which is barely influenced by source or depositional environment. Due to the increased molecular mass and polarity range of its target compounds, FT-ICR-MS is the most convincing tool to describe the retention and fractionation of polar compounds in a petroleum system.

Abstract In traditional organic geochemical investigations analyses are usually segmented in rather time-consuming single working steps that also require off-line preparation for each analytical instrument which can add to analytical bias. Since industry laboratories need to be precise, as well as cost- and time-efficient, we present a flexible and modular analytical concept which enables the user to perform advanced organic geochemical methods on a single gas chromatograph coupled to multiple detectors. The coupled analytical system can perform analyses of natural gas composition up to n -butane, stable carbon isotopes of natural gas compounds up to n -butane, identification and quantification of major compounds in oils and extracts, and compound-specific isotopes of oil and extracts. The analytical methodologies are appropriate for enhancement to broaden the application spectrum of coupled detectors.

Abstract An automatic approach for analyses of Raman spectra of dispersed organic matter in diagenesis is proposed in this work. The need for a reproducible method of thermal maturity assessment by means of Raman spectroscopic analyses on the organic matter is essential for the development of this technique as a robust support in organic petrographical analyses. The new method was tested on concentrated kerogen derived from a set of 33 samples that originated from cuttings from a 5000 m-thick section drilled in offshore Angola. The proposed method can be applied separately in the D and G bands regions of the Raman spectra, and uses a fitting approach based on asymmetrical Gaussian deconvolution and on the measurement of the integrated area. Results from this work demonstrate that Raman parameters carried out by the new methods reflect the increase in aromaticity in kerogen in diagenesis. Finally, two parametric equations have been proposed to correlate Raman parameters and thermal maturity: the first is for the thermal maturity interval between 0.3 and 1.5% R o ; and the second has a higher precision of between 1.0 and 1.5% R o . The two equations are the result of a multi-linear regression based on robust correlations between Raman parameters and vitrinite reflectance (R o %).

Abstract Petroleum geochemistry has historically relied on the analysis of field samples – source rocks, oils and gases. Data collected for individual samples are considered characteristic of a specific geographical location and geological position that, when aggregated with data from other samples, can be extrapolated to larger scales. These scale-ups may be as small as a few metres, such as a detailed characterization of source rocks penetrated by a single well, to global, such as petroleum systems that now span continents due to plate tectonics. However, a single sample contains a wealth of information at smaller scales. In situ analytical techniques have improved significantly over the last decade, allowing us to examine sedimentary rocks at ever higher spatial (areal and temporal) resolution. Mass spectrometric imaging is an emerging, enabling technology that can be performed at c. 200 µm (matrix-assisted laser desorption) to 50 nm (nanoSIMS) resolution. X-ray microcomputed tomography (µ-CT) is being applied to examine the storage and transport of petroleum in low-permeability shales and carbonates at spatial resolutions as low as c. 8 µm. Pore architecture in shale, both organic and inorganic, can be modelled from small-angle neutron scattering (SANS) data and imaged directly with helium ion microscopy at c. 1 nm resolution. Atomic force microscopy (AFM) can now resolve the molecular structure of individual asphaltene molecules. Information obtained with these techniques is now revealing the fundamental nature of geological organic materials, opening the span of petroleum geochemistry from atoms to continents.

Abstract The Elgin–Franklin complex contains gas condensates in Upper Jurassic reservoirs in the North Sea Central Graben. Upper parts of the reservoirs contain bitumens, which previous studies have suggested were formed by the thermal cracking of oil as the reservoirs experienced temperatures of >150°C during rapid Plio-Pleistocene subsidence. Bitumen-stained cores contaminated by oil-based drilling muds have been analysed by hydropyrolysis. Asphaltene-bound aliphatic hydrocarbon fractions were dominated by n -hexadecane and n -octadecane originating from fatty acid additives in the muds. Uncontaminated asphaltene-bound aromatic hydrocarbon fractions, however, contained a PAH distribution very similar to normal North Sea oils, suggesting that the bitumens may not have been derived from oil cracking. 1D basin models of well 29/5b-6 and a pseudo-well east of the Elgin–Franklin complex utilize a thermal history derived from the basin's rifting and subsidence histories, combined with the conservation of energy currently not contained in the thermal histories. Vitrinite reflectance values predicted by the conventional kinetic models do not match the measured data. Using the pressure-dependent PresRo ® model, however, a good match was achieved between observed and measured data. The predicted petroleum generation is combined with published diagenetic cement data from the Elgin and Franklin fields to produce a composite model for petroleum generation, diagenetic cement and bitumen formation.

Abstract Mudrocks are highly heterogeneous in a range of physical and chemical properties, including: porosity and permeability, fissility, colour, particle composition, size, orientation, carbon loading, degree of compaction, and diagenetic overprint. It is therefore important that the maximum information be extracted as efficiently and completely as possible. This can be accomplished through high-resolution analysis of polished thin sections by scanning electron microscopy (SEM), with the collection of large-area images and X-ray elemental map montages, and the application of targeted particle analysis. A workflow model, based on these techniques, for the digitization of mudrocks is presented herein. A range of the data that can be collected and the variety of analyses that can be achieved are also illustrated. Data collection is discussed in terms of inherent problems with acquisition, storage, transfer and manipulation, which can be time-consuming and non-trivial. Similar information and resolutions can be achieved through other techniques, such as QEMSCAN and infra-red (IR)/Raman spectroscopic mapping. These can be seen as complementary to the workflow described herein.

Abstract Chlorite is a key mineral in the control of reservoir quality in many siliciclastic rocks. In deeply buried reservoirs, chlorite coats on sand grains prevent the growth of quartz cements and lead to anomalously good reservoir quality. By contrast, an excess of chlorite – for example, in clay-rich siltstone and sandstone – leads to blocked pore throats and very low permeability. Determining which compositional type is present, how it occurs spatially, and quantifying the many and varied habits of chlorite that are of commercial importance remains a challenge. With the advent of automated techniques based on scanning electron microscopy (SEM), it is possible to provide instant phase identification and mapping of entire thin sections of rock. The resulting quantitative mineralogy and rock fabric data can be compared with well logs and core analysis data. We present here a completely novel Quantitative Evaluation of Minerals by SCANning electron microscopy (QEMSCAN®) SEM–energy-dispersive spectrometry (EDS) methodology to differentiate, quantify and image 11 different compositional types of chlorite based on Fe : Mg ratios using thin sections of rocks and grain mounts of cuttings or loose sediment. No other analytical technique, or combination of techniques, is capable of easily quantifying and imaging different compositional types of chlorite. Here we present examples of chlorite from seven different geological settings analysed using QEMSCAN® SEM–EDS. By illustrating the reliability of identification under automated analysis, and the ability to capture realistic textures in a fully digital format, we can clearly visualize the various forms of chlorite. This new approach has led to the creation of a digital chlorite library, in which we have co-registered optical and SEM-based images, and validated the mineral identification with complimentary techniques such as X-ray diffraction. This new methodology will be of interest and use to all those concerned with the identification and formation of chlorite in sandstones and the effects that diagenetic chlorite growth may have had on reservoir quality. The same approach may be adopted for other minerals (e.g. carbonates) with major element compositional variability that may influence the porosity and permeability of sandstone reservoirs.

Abstract This study gives valuable insights into the microstructure and pore space characteristics of 17 compositionally variable Visean shale samples from the Ukrainian Dniepr-Donets Basin (the ‘Rudov Beds’). The representative imaging area varies considerably (from 10 000 to >300 000 µm 2 ) as a function of the mineralogy and diagenetic overprinting. The pores hosted in organic matter (OM) are restricted to secondary solid bitumen. Based on high-resolution maps from broad ion beam scanning electron microscopy combined with organic geochemical and bulk mineralogical data, we propose that the amount of OM-hosted porosity responds to the availability of pore space, enabling the accumulation of an early oil phase, which is then progressively transformed to a porous solid bitumen residue. The type of OM porosity (pendular/interface v. spongy) is reflected in the individual pore size distributions: the spongy pores are usually smaller (<50 nm) than the pendular or OM–mineral interface pores. The OM-hosted porosity coincides with differences in the composition of the extract, with high amounts of extractable OM and saturated/aromatic compound ratios indicative of abundant porous solid bitumen. The average circularity and aspect ratio of the mineral matrix pores correlate with the corresponding values for the OM-hosted pores, which show a preferred bedding-parallel orientation, suggesting that compaction influenced both types of pore.

Abstract Reliable evaluation of shale-play potential requires robust geological models that can simulate the generation and retention of petroleum, porosity and permeability in source rocks from first principles, and that can be implemented in basin modelling software. To be predictive, such basin models need to be calibrated against observations from real shale plays. A key control on the amount of retained petroleum is the porosity in the shale and the abundance of organic matter. Scanning electron microscopy of argon-ion milled shale samples can potentially reveal systematic variations in the amount of porosity, pore types and distributions across a range of thermal maturities. These observed variations in porosity can be used to calibrate basin modelling outputs and refine predictive models. For these reasons BP has conducted scanning electron microscopy studies of shale plays including the Eagle Ford Shale, a carbonate-rich mudstone sequence of Cenomanian to Turonian age. The results clearly show that the mean pore size decreases as thermal maturity increases and that organic matter-hosted pores are absent in low thermal maturity samples (where vitrinite random reflectance R o <0.7) and become increasingly more abundant as thermal maturity increases). In moderately mature samples there are organic matter hosted pores that range in pore size from 5 to 500 nm. In highly mature samples, small (<50 nm) organic matter-hosted pores predominate. Our studies reveal that porosity evolution in this organic-rich, fine-grained, carbonate mudrock shows a strong correlation with increasing thermal maturity.

Abstract The relationship between pore structures was examined using a combination of normalized topographical and topological measurements in two qualitatively different pore systems: organic-hosted porosity, common in unconventional shale reservoirs; and intergranular porosity, common in conventional siliciclastic reservoirs. The organic-hosted pore network was found to be less well connected than the intergranular pore network, with volume-weighted coordination numbers of 1.16 and 8.14 for organic-hosted and intergranular pore systems, respectively. This disparity in coordination number was explained by differences in the pore shapes that are caused by variations in the geological processes associated with the generation of the pore network. Measurements of pore shape showed that the pores in the organic-hosted network were both significantly more spherical and had a more positive curvature distribution than the pores present within the intergranular network. The impact of such changes in pore shape on pore-network connectivity was examined by creating a suite of synthetic pore geometries using both erosion/dilation of the existing network and image-guided object-based methods. Coordination number, Euler characteristic and aggregate porosity analyses performed on these synthetic networks showed that organic-type pore networks become connected at much higher aggregate porosities (35–50%) than intergranular-type pore networks (5–10%).

Abstract The development of laser ablation techniques using inductively coupled plasma mass spectrometry has enabled the routine and fast acquisition of in situ U–Pb and Pb–Pb isotope ratio data from single detrital grains or parts of grains. Detrital zircon dating is a technique that is increasingly applied to sedimentary provenance studies. However, sand routing information using zircon analysis alone may be obscured by repeated sedimentary reworking cycles and mineral fertility variations. These biases are illustrated by two clear case studies from the Triassic–Jurassic of the Barents Shelf where the use of U–Pb geochronology on apatite and rutile and Pb–Pb isotopic data from K-feldspar is highly beneficial for provenance interpretations. In the first case study, U–Pb apatite ages from the (Induan – Norian) Havert, Kobbe and Snadd formations indicate an evolving provenance and identify possible episodes of storage within foreland basins prior to delivery onto the Barents Shelf. In the second case study, U–Pb rutile and Pb isotopic analyses of K-feldspar from the Norian–Pliensbachian Realgrunnen Subgroup provide a clear distinction between north Norwegian Caledonides and Fennoscandian Shield sources and suggest that a similar approach may be used to test competing models for sand dispersal for this Subgroup in regions farther north than this study.

Abstract This paper shows how heavy minerals and single-grain varietal studies can be conducted on silt (representing c. 50% of world's sediments) sediments to obtain quantitative data as efficiently as for sand-sized sediments. The analytical workflows include heavy mineral separation using a wide grain-size window (15–355 μ) analysed through integrated optical analysis, Raman spectroscopy, QEMSCAN microscopy and U–Pb dating of detrital zircon. Upper Jurassic–Cretaceous silt-sized sediments from the Mandawa Basin of central-southern Tanzania have been selected for the scope of this research. Raman-aided heavy mineral analysis reveals garnet and apatite to be the most common minerals together with durable zircon, tourmaline and subordinate rutile. Accessory but diagnostic phases are titanite, staurolite, epidote and monazite. Etch pits on garnet and cockscomb features on staurolite document the significant effect of diagenesis on the pristine heavy mineral assemblage. Multivariate statistical analysis highlights a close association among durable minerals (zircon, tourmaline and rutile, ZTR) while garnet and apatite plot alone reflecting independence between the three groups of variables with garnet increasing in Jurassic samples. Raman data for garnet end-member analysis document different associations between Jurassic (richer in A, Bi and Bii types) and Cretaceous (dominant A, Ci and Cii types) samples. U–Pb dating of detrital zircon and their statistical integration with the above-mentioned datasets provide further insights into changes in provenance and/or drainage systems. Metamorphic rocks of the early and late Pan-African orogeny terranes of the Mozambique Belt and those of the Irumide Belt acted as main source of sediment during the Jurassic. Cretaceous sediments record a broadening of the drainage system reaching as far as the Usagran–Ubendian Belt and the Tanzanian Archean Craton.

Abstract Petroleum systems within rifted margin basins affected by volcanism continue to remain challenging for the exploration of hydrocarbons, most notably owing to the volume of intrusions that pose imaging, drilling and exploration problems. Typically, intrusions possess small thermal aureoles, but despite this, there is evidence that intrusions could none the less be responsible for the generation of commercial volumes of hydrocarbons. Here we shed new light on this petroleum systems challenge by integrating organic geochemical and Raman spectroscopic techniques to produce potential volumetric data for hydrocarbons generated as a result of igneous intrusion. The results indicate that, in areas with immature source rock intervals, it may be possible for intrusions to generate volumes of oil that would be capable of comfortably filling likely known oil reservoirs. This is a critical step forward in integrating several analytical techniques, indicating that under the right conditions there is the potential for hydrocarbon generation as a result of igneous intrusion.

Abstract Wireline and seismic acoustic impedance imaging show that the marine part of the clastic Brent Group reservoir in the Heather Field, northern North Sea, contains much calcite cement in the flank parts of the structure. The non-marine Ness Formation and crest parts of the structure contain negligible calcite cement. This localized calcite cement has led to relatively poor reservoir performance since first oil in 1978, although a new suite of wells has boosted production with plans to keep the field active until 2030. Understanding the origin and distribution of calcite cement would help the development of more realistic reservoir models and boost production rates through optimum well location. We have thus used a suite of techniques, including standard point counting, SEM-EDS mineralogy, BSE microscopy, fluid inclusion thermometry and stable isotope analysis, to develop new and improved models of calcite distribution. Calcite seems to have attributes of both early and late diagenetic cement. A 30–40% intergranular volume in calcite cemented beds seems to support pre-compactional growth but high-temperature fluid inclusions and the presence of primary oil inclusions suggest late growth. Much calcite may have developed early but it seems to have recrystallized, and possibly undergone redistribution, at close to maximum burial or had a late growth event. Calcite cement probably originated as marine-derived micrite, bioclasts or early marine cement but adopted the isotopic characteristics of high-temperature growth as it recrystallized. Quartz grains have corroded outlines in calcite-cemented areas with one sample, with 79% calcite cement, displaying signs of nearly total replacement of quartz grains by calcite. The flank localization of calcite cement remains to be explained, although it could be due to primary depositional factors, early diagenetic loss of calcite from crestal regions or late diagenetic loss of calcite from crestal regions. Controversially, the growth of calcite seems to be associated with quartz dissolution, although the geochemical and petrophysical cause of this remains obscure. Diagenetic loss of quartz from sandstones cannot easily be explained by conventional modelling approaches and yet seems to be an important phenomenon in Heather sandstones.