Petroleum Emplacement Research Articles

Evolution and controls of high reservoir quality in Oligocene sandstones from moderate to deep burial, Nanpu Sag, Bohai Bay Basin, China

The Oligocene sandstones characterized by highly variable reservoir quality are the main hydrocarbon exploration and development targets in the Nanpu Sag, Bohai Bay Basin, China. In this study, the evolution and controls of reservoir quality in Oligocene sandstones from moderate to deep burial were investigated using petrographic and petrological data. The results show that the Oligocene sandstones are mostly fine-to coarse-grained, subangular to subrounded roundness, moderately sorted feldspathic litharenites and lithic arkoses with an average Q/F/R distribution of 48.4: 29.1: 22.5. Three anomalously high porosity/permeability zones (AHPZs, hereinafter named AHPZ-I, AHPZ-II, and AHPZ-III, respectively) are developed at depth ranges of 2300–3100 m, 3200–3550 m, and 3700–4200 m, respectively. Notably, the three zones are featured by distinctly different pore types: mainly primary pores in AHPZ-I; pore combination (average primary pore volume > average secondary pore volume) in AHPZ-II; primary pores with a few microfractures in AHPZ-III. The pore-throat sizes controlling permeability in anomalously high porosity sandstones (AHPS) decrease steadily from AHPZ-I to AHPZ-III-1 and then increase significantly at AHPZ-III-2. The AHPS reservoirs are characterized by low displacement pressure, large pore throat and mercury intrusion saturation, and high free fluid index (FFI) and reservoir quality index (RQI).Compaction greatly degraded the reservoir quality of Oligocene sandstones; carbonate cementation further restricts the formation of high-quality reservoirs. The sandstones with low content (<10 %) of carbonate cements tend to have larger primary porosity and secondary porosity, hence a larger RQI. The formation of AHPZ-I and AHPZ-II is attributed to higher content of rigid particle components, lower carbonate cements, and strong dissolution. Moreover, good sorting, responsible for a higher original porosity, also plays a positive role in the cause of AHPZ-I. The coarse-grained particles and early petroleum emplacement are the keys to the preservation of primary porosity in AHPZ-III. The petroleum emplacement effectively inhibits the feldspar dissolution and kaolinite precipitation in the deeply buried sandstones with depths larger than 4000 m. In addition, the generation of crushed microfractures in coarse grains leads to relatively low porosity and high permeability.

Petroleum emplacement inhibits quartz cementation and feldspar dissolution in a deeply buried sandstone

Whether the emplacement of petroleum in sandstone reservoirs can preserve porosity during burial remains controversial. In the Kessog Field, UK Central North Sea, average porosities of the crestal sections of the fluvial-deltaic Pentland Formation reservoir can exceed 25% despite burial to 4 km or more. The predicted porosity for the reservoir at this depth is only around 14% based on regional data. Oil saturation data, thin-section point counts, grain-size and sorting measurements, reservoir pressure, and SEM images were combined to analyze the cause of the high reservoir porosity. Petroleum emplacement preventing cementation is the most likely mechanism for porosity preservation. Facies variation is not responsible, as the high-porosity sandstones from the crestal well are, in terms of average grain-size (fine-grained) and sorting coefficient (moderately well-sorted), nearly the same as the lower porosity sandstones from the flanks of the field (average porosity 13–15%). Other potential porosity-preservation mechanisms, such as overpressure, grain-coats and feldspar dissolution can be discounted. The sandstones with high oil saturations are characterized by: 1) most porosity being primary as opposed to secondary; 2) there being 2–5% less quartz cement than in the water-saturated sandstones; 3) there being 2–3% more K-feldspar and 2–6% less kaolin than the water-saturated counterparts. This study demonstrates that petroleum emplacement can effectively inhibit quartz cementation and K-feldspar transformation to kaolin in sandstone reservoirs.

Vertical effective stress and temperature as controls of quartz cementation in sandstones: Evidence from North Sea Fulmar and Gulf of Mexico Wilcox sandstones

Abstract We present quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation for two Paleocene-Eocene Wilcox Group sandstones from Texas and two Jurassic Fulmar Formation sandstones from the Central North Sea. At each location, one sandstone has been buried to ca. 145 °C and one to ca. 185 °C. A key difference between the Wilcox and Fulmar burial histories is that the Wilcox sandstones are currently at higher vertical effective stresses and, from basin modelling studies, have been subjected to generally higher vertical effective stresses through their burial history. The amounts of quartz cement in the Wilcox sandstones are between 12 and 18%, and between 2 and 6% in the Fulmar sandstones. High-spatial-resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 °C to values approaching maximum burial temperature. Factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement. Petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution. Although the sample set is small, we interpret the results to suggest that the differences in quartz cementation in Fulmar and Wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history; in this case, the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation.

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

Abstract The porosity and permeability of sandstone and carbonate reservoirs (known as reservoir quality) are essential inputs for successful oil and gas resource exploration and exploitation. This chapter introduces basic concepts, analytical and modelling techniques and some of the key controversies to be discussed in 20 research papers that were initially presented at a Geological Society conference in 2014 titled ‘Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction’. Reservoir quality in both sandstones and carbonates is studied using a wide range of techniques: log analysis and petrophysical core analysis, core description, routine petrographic tools and, ideally, less routine techniques such as stable isotope analysis, fluid inclusion analysis and other geochemical approaches. Sandstone and carbonate reservoirs both benefit from the study of modern analogues to constrain the primary character of sediment before they become a hydrocarbon reservoir. Prediction of sandstone and carbonate reservoir properties also benefits from running constrained experiments to simulate diagenetic processes during burial, compaction and heating. There are many common controls on sandstone and carbonate reservoir quality, including environment of deposition, rate of deposition and rate and magnitude of sea-level change, and many eogenetic processes. Compactional and mesogenetic processes tend to affect sandstone and carbonate somewhat differently but are both influenced by rate of burial, and the thermal and pressure history of a basin. Key differences in sandstone and carbonate reservoir quality include the specific influence of stratigraphic age on seawater composition (calcite v. aragonite oceans), the greater role of compaction in sandstones and the greater reactivity and geochemical openness of carbonate systems. Some of the key controversies in sandstone and carbonate reservoir quality focus on the role of petroleum emplacement on diagenesis and porosity loss, the role of effective stress in chemical compaction (pressure solution) and the degree of geochemical openness of reservoirs during diagenesis and cementation. This collection of papers contains case study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.

The source kitchen of the Niger Delta oils: case study on Nembe Creek E1.0 and the Kolo Creek E2.0 reservoirs

The source kitchen of a petroleum system is that part of the pod of active source rock which is mature and generates the petroleum that charges the reservoir rock. The location of the source kitchen of a petroleum system is vital to the explorationist, its knowledge fosters the prediction of migratory pathways and the migratory losses prior to present times, also estimates potential volume of accumulation. Hither to, mapping of the petroleum basins was based on total organic carbon (TOC), hydrogen index (HI) signatures and maturity history of the source rock and has been used as the basis to suggest locations of petroleum kitchens. In contemporary times, 4D seismic or 3D time lapse geochemistry had been used to suggest location of source kitchen. However, settled is the concept of lateral maturity gradients, implying that within reservoir scales of a kilometer to tens of kilometers, regional petroleum emplacement direction could be deduced from subtle changes in maturity of successive charges of petroleum into the reservoir. In this study, the sterane isomerization ratio (20S/20S + 20R αααC29) was used to determine the maturities of the hydrocarbons from various wells in the Kolo Creek and the Nembe Creek reservoirs. Subtle increases in maturities were observed to be in a NE–SW direction for the Kolo Creek reservoir and in a NW–SE direction for the Nembe Creek reservoir. The direction of increasing maturities relative to the location of the reservoirs could be extrapolated for both reservoirs towards offshore Gulf of Guinea; this is invariably the direction of location of the source kitchen for the Niger Delta oils.

Dating petroleum emplacement by illite 40Ar/39Ar laser stepwise heating: Reply

Dating petroleum emplacement by illite 40Ar/39Ar laser stepwise heating: Reply

Dating petroleum emplacement by illite 40Ar/39Ar laser stepwise heating: Discussion

Isotopic dating of diagenetic processes in relation to hydrocarbon charge in buried sedimentary sequences is of importance to the oil industry. Yun et al. recently published in the AAPG Bulletin (v. 94, no. 6, p. 759–771) on that topic a study entitled, “Dating Petroleum Emplacement by Illite 40Ar/39Ar Laser Stepwise Heating Technique.” This study raises questions about basic aspects of 40Ar/39Ar dating fine-grained authigenic clay minerals, describes flawed methodology, and ignores important previous work. As isotopic dating of diagenetic processes may interest readers of the AAPG Bulletin that are not necessarily specialists in either isotopic geochronology or clay mineralogy, it appeared necessary to comment on both the technical aspects and the scientific interpretations of this study. We discuss especially the fact that the authors discarded 39Ar recoil followed by an evaluation of its impact on the results and the interpretations.

Dating petroleum emplacement by illite 40Ar/39Ar laser stepwise heating

The timing of petroleum emplacement is crucial in understanding petroleum-forming processes and predicting new prospecting regions. This study investigates the possibility of determining the age of petroleum emplacement by an illite 40Ar/39Ar laser stepwise heating technique. A specially designed apparatus has been used to clean up the organic gases in samples contaminated with residues from oil or gas fields, resulting in credible 40Ar/39Ar data. The sandstone samples are from the Zhuhai and Zhujiang formations in the Huizhou sag in the Pearl River Mouth Basin, South China Sea. Illite 40Ar/39Ar laser stepwise heating consistently yields gradually rising age spectra at the low-temperature steps until reaching age plateaus at high-temperature steps. The first-step apparent ages of the six samples from the Zhujiang formation give a weighted mean age of 11.4 0.5 Ma (1), in agreement with an age of 12.1 1.1 Ma in the first three steps of the sample from the Zhuhai Formation. These dates are interpreted as being caused by the formation of fine authigenic illite and therefore indicative of the maximum age of petroleum emplacement in the Huizhou sag because illite is commonly one of the latest forming minerals prior to hydrocarbon accumulation. The plateau ages ranging from 58 to 276 Ma in high laser-output steps are interpreted as being caused by variable contributions from detrital K feldspar in the sandstones. The older total ages based on the illite 40Ar/39Ar stepwise heating results are equal to the K-Ar ages and are not usable in delineating petroleum emplacement because they represent mixtures with variable contributions from authigenic illite and detrital K feldspar. The 40Ar/39Ar stepwise heating technique thus can be applied to resolve important petroleum emplacement age information from illite samples that otherwise cannot be provided by traditional K-Ar methods.

Diagenesis, Porosity Evolution, and Petroleum Emplacement in Tight Gas Reservoirs, Taranaki Basin, New Zealand

Abstract Tight gas reservoirs have become popular targets in petroleum exploration in recent years, due largely to the increasing market demand for gas and also to technology advances used in extraction. Reservoir quality is typically poor due to deep-burial diagenesis, resulting in significant compaction, cementation, and illitization. However, analysis of tight reservoirs using integrated techniques can improve our understanding about the controls on reservoir quality, and these results can potentially be used to help predict reservoir quality at other sites. The use of integrated analysis of diagenetic and burial history is here shown for the Eocene, K3E Kapuni Group reservoir in Cardiff-1, Taranaki Basin, New Zealand. The K3E belongs to a deep gas play that was considered uncommercial in the early 1990's due to poor reservoir quality associated with extensive authigenic illite. Potassium-argon dating has shown that destruction of the reservoir through illitization occurred in the Pliocene, associated with a late-stage heating and/or fluid-flow event. Timing of illite authigenesis in the K3E reservoir postdates the likely circulation of CO2-rich fluids that caused reaction of feldspar to form kaolinite and quartz. Homogenization temperatures from two-phase aqueous fluid inclusions within quartz cements, together with 1D basin models of CO2 expulsion from coaly source rocks, indicate that feldspar reactions may have started in the mid Miocene. The CO2-rich fluids are thought to have been generated by thermal decarboxylation of intraformational Paleocene–Eocene coals. At the same time, oil was being expelled from older, Cretaceous coals and migrated into the mid-late Eocene reservoirs; evidence for oil migration is demonstrated by the presence of residual oil and by the local occurrence of abundant oil-bearing fluid inclusions. The products of feldspar dissolution appear to be in reasonable balance with the amount of dissolved feldspar, suggesting a relatively closed diagenetic system with little improvement in reservoir quality despite the large volume of feldspar dissolved. Petrographic evidence of reservoir sandstones at Cardiff-1 demonstrates the presence of some illite-free secondary macropores lined by residual oil. This local preservation of porosity may be replicating the original distribution of oil-saturated pores in the Pliocene, at the time when authigenic kaolinite underwent reaction to form illite. Remobilization of the oil probably occurred by gas flushing after the main phase of illitization at c. 5 Ma. The data presented in this study are consistent with redistributed liquid petroleum into up-dip traps and represent the potential for a new exploration play. The Eocene reservoir at Cardiff-1 is currently gas-charged, with the pore system composed of approximately one third large macropores connected by a tortuous, microporous network. However, it is possible that, with the currently buoyant gas market and modern hydraulic fracturing techniques, it may now be economic to flow gas from the locally large pores identified in the K3E reservoir.

Direct Radiometric Dating of Hydrocarbon Deposits Using Rhenium-Osmium Isotopes

Rhenium-osmium (Re-Os) data from migrated hydrocarbons establish the timing of petroleum emplacement for the giant oil sand deposits of Alberta, Canada, at 112 +/- 5.3 million years ago. This date does not support models that invoke oil generation and migration for these deposits in the Late Cretaceous. Most Re-Os data from a variety of deposits within the giant hydrocarbon system show similar characteristics, supporting the notion of a single source for these hydrocarbons. The Re-Os data disqualify Cretaceous rocks as the primary hydrocarbon source but suggest an origin from older source rocks. This approach should be applicable to dating oil deposits worldwide.

Petroleum geology and geochemistry of the Council Run gas field, north central Pennsylvania

The Council Run field of north central Pennsylvania is one of the most productive natural gas fields in the central Appalachian basin. The field is enigmatic because of its position near the eastern edge of the Appalachian Plateau, where strata with reservoir potential elsewhere have low porosities and permeabilities or are poorly sealed. Council Run has four principal reservoir sandstones. The lower three occur in a distinct fourth-order type 1 stratigraphic sequence. The stacking pattern of sandstones in this sequence defines lowstand, transgressive, and highstand systems tracts. Core, well-log, and map interpretations reveal that the lowest interval consists of multiple coarsening-upward parasequences deposited in deltaic and nearshore environments of the lowstand systems tract during a forced regression. Most of these sandstones are lithic, and some are highly feldspathic. Productive sandstones display hybrid void textures that consist of reduced primary intergranular pores preserved, in part, by relatively early petroleum emplacement and secondary oversized fabric-selective pores. The generative potential of the organic matter in the potential source rocks is exhausted, but geochemical and petrographic evidences indicate that these black shales originally contained oil-prone kerogens and generated liquid hydrocarbons. Stable isotope geochemistry suggests that gases were generated by primary cracking of kerogens and/or by secondary cracking of oil between 320 and 290 Ma. Dispersive migration paths were both lateral and vertical because of compression associated with Alleghanian orogenesis. Most of the oil in the Devonian section was cracked to gas during deeper burial between 270 and 240 Ma.

The application of fluid inclusion PVT analysis to studies ofpetroleum migration and reservoirs

We present two examples of how pressure-volume-temperature (PVT) analysis of fluid inclusions can be used to evaluate oil compositions, migration timing, trap-fill history, paleopressures, and mechanisms of bitumen formation in petroleum reservoirs. Measurements of homogenization temperatures, volumetric liquid/vapor ratios and API gravities from petroleum inclusions are integrated with PVT simulations to estimate the composition and PVT properties of single petroleum inclusions in the Greater Alwyn-South Brent petroleum system of the North Sea and in the Tengiz field of Kazakhstan. Fluid inclusion data combined with models of burial history and petroleum migration yield the timing of petroleum emplacement. Key conclusions are: (1) analysis of six North Sea fields suggests that changes in petroleum compositions through time can be interpreted in terms of gradual mixing of earlier reservoired oil with later migrated, more mature and gas-rich fluids; and (2) depressurization within the Tengiz reservoir is suggested to cause asphaltene/bitumen dropout, particularly as the pressures approach the bubble point of the oil.

Determination of trapping pressure and temperature of petroleum inclusions using PVT simulation software—a case study of Lower Ordovician carbonates from the Lunnan Low Uplift, Tarim Basin

We report a case study carried out on Lower Ordovician reservoir carbonates of the Lunnan Low Uplift, Tarim Basin, to determine trapping pressures and temperatures of petroleum inclusions from the intersection of isochores of coeval petroleum and aqueous fluid inclusions using PVT SIM software. There are four types of petroleum inclusions from this sequence. Their trapping pressures and temperatures are: Type I 80–105 °C, 199–230 bar; Type II 135–145 °C, 235–250 bar; Type III 155–165 °C, 344–360 bar, and Type IV 220–252 °C, 345–390 bar, respectively, which are consistently higher than their homogenization temperature and saturation pressures by about 5–15 °C and 25–70 bar. To confirm the reliability of the PVT simulation approach, fluid inclusions were synthesized in calcite under controlled temperature and pressure conditions and studied using the same methods. The calculated trapping pressure and temperature of the synthetic petroleum inclusions closely match the actual pressure and temperature applied in the experiment. By reference to the burial and geothermal history of the Tarim host rocks, it was inferred that Types I, II and III petroleum inclusions represent fluids associated with three distinct phases of petroleum emplacement in the Lower Ordovician strata of this area, occurring during late Silurian to early Devonian, Cretaceous to early Tertiary, and late Tertiary, respectively. Type IV petroleum inclusions occur only in some fine calcite veins from few samples, and are believed to be related to an anomalous thermal event in this area. On the basis of the trapping pressures and trapping temperatures of the petroleum inclusions, three main phases of the petroleum-filling of the Lower Ordovician reservoirs can be delineated. Phase I and phase III petroleum events were related to petroleum migration and accumulation from the Lunnan Low Uplift or nearby area. The petroleum of the phase II petroleum event appears to have originated from Middle and Upper Ordovician source rocks in the northern slope area of the Manjiaer Depression with a long distance migration.

Effects of petroleum emplacement on cementation in carbonate reservoirs

Abstract Carbonate diagenesis can theoretically either be enhanced or retarded by petroleum emplacement depending on: the oil-water wettability of the rocks, the CO 2 -content of the migrated petroleum, and the presence of oxidised sulphur or iron compounds in the rocks. A detailed case study of Jurassic oolites from a UK oil field showed first that petroleum emplacement retarded diagenesis in the oil leg and thus helped preserve permeability, but second showed that entrained CO 2 caused cementation and pore-system modification in the water leg.

Deep burial diagenesis and reservoir quality along the eastern flank of the Viking Graben. Evidence for illitization and quartz cementation after hydrocarbon emplacement

AbstractThe Tarbert Formation on a north±south oriented structure along the eastern flank of the Viking Graben has been studied. The reservoir in the two wells studied is buried ~100 m deeper in the northern than in the southern well. The present reservoir temperature is ~130°C. The reservoir quality is good, but due to extensive illitization of kaolin, the northern well shows lower permeability values than the southern well, for similar porosity values. The initial composition of the analysed samples in the two wells is very similar. There are no significant differences in total clay content and both wells contain K-feldspars and kaolin. However, the diagenetic alteration is more advanced in the deeper well. Total porosity is about the same in both wells but, due to illitization, the ratio of micro- vs. macro-porosity is higher in the deeper well. Petroleum emplacement in the structure occurred in two phases: oil emplacement predates, whereas gas emplacement postdates, most of the quartz cementation. In the deeper well, illitization occurred after gas emplacement.

The relationship between petroleum emplacement and carbonate reservoir quality: examples from Abu Dhabi and the Amu Darya Basin

The relative importance of petroleum emplacement in inhibiting diagenetic processes and preserving porosity and permeability in Lower Cretaceous, Thamama Group (Kharaib Formation) carbonate reservoirs of Abu Dhabi, UAE, and in Callovian-Kimmeridgian carbonate reservoirs of the Amu Darya Basin in Uzbekistan and Turkmenistan, has been evaluated by combining geologic, petrophysical and geochemical data. When petroleum emplacement is synchronous with and prior to significant burial cementation in carbonates, primary petroleum inclusions are trapped in the cements. The process appears to be characterised by steep intra-field porosity-depth trends within a more gradual regional decline in porosity with depth. This has profound implications for the prediction of porosity in carbonate reservoirs. Reservoir quality is better in grainstones and packstones compared to adjacent wackestones and lime mudstones in the Kharaib Formation because of preserved macroporosity (intergranular, vuggy, mouldic); the pore system in the finer units is dominated by micropores. These features indicate a primary textural control on porosity and permeability. Within the grainstones and packstones, macroporosity is variably filled by late equant sparry calcite cements. Porosity and permeability variations in grainstones and packstones at a reservoir scale are therefore controlled by the variation in amount of equant sparry calcite cement. This in turn depends on the timing of the precipitation of this cement relative to petroleum emplacement, as shown by fluid inclusion data. Where petroleum emplacement has occurred relatively early, at migration foci, prior to significant burial cementation by equant sparry calcite, reservoir quality is preserved. Where it has occurred after significant burial cementation, reservoir quality has been destroyed. In the Amu Darya sequences, primary macroporosity is commonly preserved down to depths of 11,000 ft (3.5 km) with differences in the porosity and permeability characteristics of grainstones being controlled by variations in the amount of early, probably freshwater, cement and the extent of associated dissolution. Small volumes of burial cements do occur, but they do not contain petroleum inclusions. Consequently, there is no firm evidence that petroleum emplacement has inhibited diagenesis in this area. This part of the study has shown that it is not always possible to obtain conclusive evidence from the diagenesis to pin down the processes responsible for the preservation of reservoir quality and that petroleum filling may not always be the primary cause. The relationships documented here show that the ‘race for space’ between diagenetic waters and petroleum is a major control on reservoir quality in the Thamama Group carbonate reservoirs, but is not so important for the Jurassic carbonates in the Amu Darya basin.

The reservoir geochemistry of the Eldfisk Field, Norwegian North Sea

Abstract A detailed geochemical study has been performed on the North Sea Eldfisk Field chalk reservoir, which forms part of a larger regional evaluation of the Greater Ekofisk area. Utilizing rapid screening methods (Rock-Eval, Iatroscan), conventional biomarker maturity parameters, stable carbon isotope data (bulk and individual n-alkanes) and pyrrolic nitrogen distributions, it is shown that the Eldfisk Field petroleum is heterogeneous, both laterally on a kilometre scale and vertically on a metre scale. The chemical heterogeneities throughout the field led to a better understanding of the charging of the reservoir, the nature of communication between the Upper Jurassic source rocks and trap, and the identification of geological barriers to petroleum mixing within the field itself. The biomarker maturity and pyrrolic nitrogen compound data suggest that charging of the Eldfisk Field ocurred from the south, petroleum moving northwards up and along the Skrubbe fault zone charging the Eldfisk Alpha and Bravo structures. Although filling has largely taken place since c. 10 Ma BP , initial charging of the Eldfisk structure started c. 20 to 25 Ma BP . The data suggest that petroleum emplacement was via faults and fractures, with communication between the source rocks and trap being discontinuous. The distribution of the different petroleum populations within the field was controlled significantly by the internal field plumbing which is sedimentologically influenced. Sharp, step-like biomarker-parameter maturity variations downhole in several wells have been identified and verified statistically. These geochemial discontinuities can be correlated with specific geological features (hard-grounds and tight zones) which have prevented mixing of the petroleum column. In one case, the presence of a barrier in the reservoir has been confirmed by repeat formation test (RFT) pressure data. The identification of lithofacies variations laterally across the field and barriers vertically in the petroleum column may become important when assessing production scenarios.

Reservoir geochemistry: methods, applications and opportunities

Abstract Petroleum reservoirs often contain compositionally heterogeneous petroleum, water and sometimes gas columns which can be interpreted in geologically useful ways. Kilometre-scale lateral compositional heterogeneities in fluid columns suggest petroleum emplacement directions, directions of water flow in biodegraded oilfields and the presence of major barriers to fluid flow within reservoirs. Vertical fluid column heterogeneities on a 10 m scale suggest that reservoirs are vertically compartmentalized. These data can be used as a tool in reservoir description and are thus relevant to many aspects of reservoir appraisal and development. The data supplement those generated by reservoir geologists and engineers, and can be obtained immediately after drilling, at reasonable cost. Much recent work has focused on polar nitrogen (N) and oxygen (O) containing compounds such as quinolines, carbazoles and phenols. These compounds interact relatively strongly with water, rock minerals and each other, and may significantly influence the viscosity and pressure-volume-temperature (PVT) properties of petroleum, and also reservoir wettability. There are obvious links here between reservoir geochemistry and the more traditional disciplines of petroleum and reservoir engineering which we expect to be exploited in the coming years. In the absence of phase changes during migration, the composition of reservoired oil reflects the expelled oil plus changes induced by adsorption, especially of polar compounds, onto solid phases or by partitioning into porewaters along secondary migration pathways. The extent of change, as measured by the relative abundances of selected compounds in reservoired oil and associated water, is potentially a direct measure of migration volume and thus of the relative amounts of water, oil and rock on a migration pathway. We present a simplified, equilibrium model which may allow one to assess migration volumes, and use n -hexane/benzene ratios of some North Sea oils to suggest that these oils have contacted fewer than one hundred volumes of water on their migration pathways. Future work should aim to quantify the interactions of migrating and reservoired petroleum with rock and water, and should yield a more quantitative assessment of both migration volumes and the controls of reservoir wettability.

Burial Cements, Mineralization and Petroleum Emplacement in the Lower Carboniferous of Northern Britain: ABSTRACT

Burial Cements, Mineralization and Petroleum Emplacement in the Lower Carboniferous of Northern Britain: ABSTRACT

Relationship between reservoir diagenetic evolution and petroleum emplacement in the Ula Field, North Sea

The diagenetic and petroleum filling histories of the Ula Field have been studied by analysing aqueous and petroleum inclusions occurring in authigenic cements. This study shows that diagenesis continues actively after the arrival of petroleum in the sandstones, although the reaction rates and petroleum saturation remain obscure. Microthermometric measurements of fluid inclusions in authigenic quartz suggest an onset of extensive quartz cementation at temperatures around 110°C (i.e. ≈ 2.5 km) and that this cementation has continued to the present day. Synchronously with quartz cementation, authigenic albite was formed as inter- and intragranular cements. Large amounts of petroleum inclusions locally occur in the albite and quartz cements. These inclusions were trapped in the cements as the main charge of petroleum arrived at the structure. Diffusion, through thin water layers between the petroleum and the mineral surface, would probably have dominated mass transfer of solutes for the precipitation of authigenic quartz and albite. It is evident from analysis of the petroleum inclusions in early formed K-feldspar overgrowths that some secondary migrated petroleum probably arrived in the reservoir at a shallow burial depth, before the rapid subsidence in the last 25 my. Compared with petroleum in the free porosity of the Ula Formation, the petroleum in the K-feldspar inclusions is evidently sourced from a different source facies and most maturity parameters testify to the latter being less mature. Later trapped petroleum inclusions, in quartz and albite, have characteristics found both in K-feldspar and in the Ula Formation DST oil and, thus, is likely to reflect the progressive change in the Ula Field petroleum charge which occurred during the time period of quartz diagenesis.