Hydrocarbon Volumes Research Articles

Performance of Cubic Eos At High Pressures

This paper presents an evaluation of the performance of cubic equations of state in the prediction of the phase behavior of hyperbaric mixtures. It points out a number of problems that should be resolved in a cooperative way. Items related to EoS parameter definitions such as interaction coefficients, critical properties of hydrocarbon compounds and volume translation are investigated. VLE experimental data, isothermal flash compositional and volumetric data up to 4000 bar as well as PVT data up to 2000 bar for binary mixtures and synthetic multicomponent systems have been considered in this study. Correlation and prediction results are presented with the translated and modified Peng-Robinson (t-mPR) EoS. It is shown that serious problems are encountered at high pressure, when extrapolated interaction coefficients are used. Prediction of saturation pressures of gas condensates is more satisfactory when binary interaction parameters are obtained from high pressure dew point correlations. Compositional and volumetric predictions are remarkable under the assumption that definition of the EoS parameters is based on high pressure VLE binary data. Contradictory results are obtained with different methods for estimating the critical properties of high molecular weight hydrocarbons. Generalized expressions for the volume translation appear to be very efficient even at very high temperatures and pressures (up to 2000 bar).

Uncertainty estimation in volumetrics for supporting hydrocarbon exploration and production decision-making

A methodology is presented for uncertainty estimation in volumetrics. Firstly, we stress the need for an open hierarchical methodology. This allows for a flexible work process in estimating uncertainty throughout the asset life cycle, in which data of various scales and accuracy must be integrated. Secondly, a method is explained for the transfer of spatial uncertainty in structure and rock properties to uncertainty in hydrocarbon volume. Thirdly, a new technique is presented for calculating average water saturation. Application to a synthetic case study shows that scalar uncertainty calculation leads to an underestimation of the uncertainty compared to a spatial approach. Spatial mapping of standard deviation of net hydrocarbon column indicates extra potential in the field. Incorporation of correlations in the field between, for example, porosity, permeability and water saturation, increases the uncertainty range. Using extra wells in the uncertainty estimation reduces uncertainty. Now, the known volume lies within the estimated proven-to-probable range.

Well‐based seismic lithology inversion for porosity and pay‐thickness mapping

Well log data and 3-D seismic data were integrated in a Gulf of Mexico field to estimate the volume of commercial hydrocarbons in place. This was accomplished by using a patented seismic‐inversion scheme that determined the distribution of porosity and reservoir thickness and calculated variances thereof, which were geologically bounded. These data were used in conjunction with a 3-D AVO analysis to predict the areal extent of the hydrocarbons and for economic evaluation of the field.

DEVELOPMENT AND PETROLEUM RESOURCE EVALUATION OF THE BOWEN, GUNNEDAH AND SURAT BASINS, EASTERN AUSTRALIA

The Early Permian to Middle Triassic Bowen and Gunnedah basins and the Early Jurassic to Early Cretaceous Surat Basin in eastern Australia developed in response to a series of interplate and intraplate tectonic events located to the east of the basin system. The initial event was extensional and stretched the continental crust to form a significant Early Permian East Australian Rift System. The most important of the rift-related features are a series of half graben that form the Denison Trough, now the site of several commercial gas fields. Several contractional events from the mid-Permian to the Middle Triassic are associated with the development of a foreland fold and thrust belt in the New England Orogen. This caused a foreland loading phase of subsidence in the Bowen and Gunnedah basins. Thick coal measures deposited towards the end of the Permian are the most important hydrocarbon source rocks in these basins. The development of the Surat Basin marked a major change in the subsidence and sedimentation patterns. It was only towards the end of this subsidence that sufficient burial was achieved to put the source rocks over much of the basin into the oil window. Based on an evaluation of the undiscovered hydrocarbon resources for the Bowen and Surat basins in southern Queensland, our estimates of the yields of hydrocarbons suggest that significant volumes of hydrocarbons have been produced in the basins. The bulk of the hydrocarbons were generated after 140 Ma and most of the generation occurred in the late Early Cretaceous. Because the estimated volume of the hydrocarbons generated far exceeds the volume of discovered hydrocarbons, preservation of accumulations may be the main risk factor. The yield analysis, by demonstrating the potentially large quantities of hydrocarbons available, should act as a stimulus to exploration initiatives, particularly in the search for stratigraphic traps.

Geology and hydrocarbon occurrences in the Ghadames Basin, Algeria, Tunisia, Libya

Abstract The Ghadames Basin is a large intra-cratonic basin, covering portions of Algeria, Tunisia and Libya. The three countries are independently conducting petroleum exploration in their portions of the basin, using different play concepts and consequently obtaining different exploration results. This paper presents the first published basin-wide view of petroleum stratigraphy and play types. Some 700 exploratory wells have been drilled in the basin, resulting in the discovery of at least 150 oil pools with 9500 MMBO (million barrels of oil) in place. Most wells were located in the structurally higher parts of the basin, with deeper portions being less explored because of shifting dune conditions and an expectation of reservoir thinning into the basin centre. Silurian and Devonian source rocks occur across large parts of the basin and have generated volumes of hydrocarbon orders of magnitude above those discovered. The numerous structural phases (Taconic, Caledonian, Hercynian and Austrian) that have affected the basin have had important implications for depocentre migration, structural style, and for patterns of trap formation, alteration and destruction. The erosion pattern and topography developed on the Hercynian unconformity is a key control on petroleum systems within the basin, controlling the preservation of Palaeozoic hydrocarbons, communication between source and higher reservoirs and patterns of long-distance migration in the Triassic reservoir. For each of the producing plays, an analysis is presented of the geological factors controlling the habitat of hydrocarbons (e.g. the effect of various tectonic phases, the influence of basin-scale facies variations on reservoir quality, and the source rock-reservoir relationship), and is related to the variations that have been observed in exploration success rate and producibility. It is believed that a substantial volume of hydrocarbons still remains undiscovered in a range of trap and play types.

Homogeneous Nucleation in an Emulsion/Droplet Microemulsion System

We present a theoretical analysis of a model nucleation process where an oil phase separates out from a droplet microemulsion phase. We consider a homogeneous nucleation where aggregate growth occurs through addition of monomers. The nucleus is formed by the growth of an already existing microemulsion droplet. On the basis of previous equilibrium studies of the microemulsions of the same system we can be confident about the accuracy of the description of free energy changes during nucleation. Using the constraints of constant hydrocarbon volume and aggregate area, the change in curvature free energy is determined as an oil drop is nucleated rather than the change in surface free energy, as in a conventional nucleation theory. We obtain a simple analytical expression for the barrier which has the feature that it only exists in a finite parameter range. In the particular system that we have studied experimentally a two-phase system of microemulsion plus excess oil is reached through a temperature quench and...

RIPHEAN HYDROCARBON RESERVOIRS OF THE YURUBCHEN‐TOKHOM ZONE, LENA‐TUNGUSKA PROVINCE, NE RUSSIA

The Siberian Craton covers an area of about 4.5 million sq. km in northern Russia, of which up to 3.5 million sq. km may be prospective for hydrocarbons. The craton was consolidated in the Early Proterozoic, and above the basement granitoids and gneisses is a variable thickness of sedimentary strata ranging in age from Riphean (Middle‐Late Proterozoic) to Quaternary.Reservoir rocks are known to occur in the interval between the Middle Riphean and the Upper Cretaceous; those of Riphean age have produced oil commercially since 1973. Geochemical data indicate that the oil within the Riphean reservoir rocks was generated by source rocks of Riphean age. Riphean reservoir rocks include both carbonates and siliciclastics, but commercial volumes of hydrocarbons have only been discovered within the carbonates.Three petroleum‐bearing “provinces” or megabasins are located on the Siberian Craton: Lena‐Tunguska, Lena‐Vilyuyand Yenisey‐Anabar. The Yurubchen‐Tokhom Zone in Lena‐Tunguska Province is potentially the most important oil‐producing area in the craton, and comprises a number of distinct fields. Reservoir rocks here consist principally of thick Riphean dolomites. Both the development of reservoir characteristics within these dolomites and the formation of stratigraphic traps are related to an episode of emergence and karstification at the end of the Riphean.

Heterogeneities Modeling and Uncertainty Quantification of the Gullfaks Sør Brent Formation In-Place Hydrocarbon Volumes

Summary The Gullfaks Sør oil- and gas-filled Brent reservoir can be divided into 14 fault Segments, five of which are penetrated by wells that have proven hydrocarbon columns between 32 and 316 m. The uncertainties in gas and oil in-place volumes have delayed the time from discovery in 1978 to the current partial development plan that was submitted to the Norwegian authorities in 1995 for development of the oil reserves. This paper describes the method used for modeling fault-segment reservoir heterogeneities and the method of quantifying the distribution of oil and gas accumulations. The final product is the most likely stock tank oil initially in place/gas initially in place (STOIIP/GIIP) with reliable high- and low-volume estimates for management decision making. We evaluated the initial reservoir fluid pressures and fault-sealing properties together with observed internal reservoir barriers to vertical fluid flow and several fluid-contact observations. We established a quantification of the oil-leg thicknesses, including uncertainty ranges, on the basis of the field gas- and water-pressure gradients and the fluid densities. This quantification had to honor the various fluid contacts, the fluid gradients, and log observations, such as water up to, gas down to, and geochemical core analysis. We evaluated the degree of communication between drilled fault Segments by determining probabilities of static-pressure communication between the drilled and undrilled fault Segments and between the various reservoir units across the faults. We assessed communication of fluid flow across faults by evaluating the clay smear (amount of clay material in relation to the fault planes) and juxtaposition relations of the reservoir units across faults. We used a Statistical approach to quantify the uncertainty in the proven and probable in-place Gullfaks Sør Brent formation hydrocarbon volumes for field-development decision making. A geostatistical program designed to handle laterally varying uncertainties was used for quantifying uncertainties in the seismic Interpretation, velocity model, depth conversion, isochores, and fluid contacts. To evaluate the petrophysical uncertainties and the probabilities for gas- or oil-filled reservoir Segments, we used a classical Monte Carlo Simulation method. The combined use of geostatistical analysis and Monte Carlo Simulation has proved to be a useful and fast approach for modeling the Gullfaks Sør field.

Uncertainties in hydrocarbon charge prediction

Computer simulations allow the prediction of hydrocarbon volumes, composition and charge timing in undrilled petroleum prospects. Whereas different models may give different hydrocarbon charge predictions, it has now become evident that a dominant cause of erroneous predictions is the poor quality of input data. The main culprit for prediction errors is the uncertainty in the initial hydrogen index (H/C) of the source rock. A 10% uncertainty in the H/C may lead to 50% error in the predicted hydrocarbon volumes, and associated gas–oil ratio. Similarly, uncertainties in the maximum burial temperature and the kinetics of hydrocarbon generation may lead to 20–50% error. Despite this, charge modelling can have great value for the ranking of prospects in the same area with comparable geological histories.

Prediction of volumes and risk in hydrocarbon exploration: a quantification of geology

The prediction of the hydrocarbon potential of a specific trap or of a number of specific traps (venture), referred to herein as prospect appraisal, concerns a probabilistic exercise based on the quantification of geology in terms of structural closure, reservoir quality, hydrocarbon charge, and the retention potential of the seal. Its objectives include: (a) prediction of the hydrocarbon volumes that could be present in the trap from an analysis of its geologic attributes; (b) the amount of uncertainty introduced in the volumetric prediction by the uncertainties in the subsurface geology; (c) the risk that one or more of the essential attributes of the prospect are underdeveloped and recoverable reserves are absent. The uncertainty of the geologic input requires a probabilistic approach, for which the Monte Carlo procedure is well suited.

Effects of various hydrocarbons on micellar growth

AbstractThe effect of aliphatic and aromatic hydrocarbons on surfactant micellar growth has been investigated by viscosity measurements at 40°C. Aqueous and aqueous KBr (0.1 M) solutions of 0.1 M cetylpyridinium bromide (CPB) showed that the viscosity behavior changed substantially in the presence of KBr. This is attributed to favorable conditions produced by KBr that assist micellar growth by addition of hydrocarbons. Reasons for the effectiveness of the solubilized hydrocarbons are suggested and supported by theoretical arguments. The causes of viscosity decrease at higher aromatic hydrocarbon concentrations are also explained. Micellar growth with soluble aromatic/aliphatic hydrocarbons could also be initiated if a moderate salt concentration is present in CPB micellar solutions. The chainlength, solubilization site, and molar volume of the soluble hydrocarbons all affect the bulk viscosity of the solution. Such surfactant and hydrocarbon combinations may find use in micellar‐enhanced ultrafiltration of benzene and its derivatives, but it should be kept in mind that micellar shape may change and be more curved at higher benzene derivative concentrations.

Mathematical procedure for the determination of the breakthrough volumes of polycyclic aromatic hydrocarbons (PAHs)

A mathematical procedure has been developed to calculate the breakthrough volumes of 15 polycyclic aromatic hydrocarbons in a C 18 preconcentration column for aqueous solutions containing 10% acetonitrile as organic modifier. This procedure uses the peaks obtained by the injection of a solution of the polycyclic aromatic hydrocarbons (PAHs) studied in mobile phases with different percentages of organic modifier to calculate the elution curve of the PAHs at the percentage of organic modifier in the water solution. This method allows a faster and easier determination of the values of the breakthrough volumes of these compounds, specially in the case of PAHs which have long retention times.

Geologically Consistent Resolution Enhancement of Petrophysical Analysis With Image Log Data

Summary Very thin, laminated sand-shale sequences pose a challenge to petrophysical evaluation. The poor vertical resolution of the log measurements results in pessimistic estimates of hydrocarbon volumes and producibility. An earlier proposal by Flaum1 to enhance the resolution of the analysis using a high-resolution clay indicator did not account for variations in clay mineralogy and porosity with clay content. We present a technique to incorporate results of core mineralogy measurements to ensure a geologically consistent resolution enhancement of the petrophysical analysis, and we compare the results in an actual field example.

Improved Fossil Energy Technology

New technologies are having significant effects on the exploration and discovery of crude oil and natural gas, as well as on the costs of their production. Geophysical and geochemical techniques are enhancing our knowledge about subsurface geology on land and undersea. The most important of these techniques is three-dimensional seismology (3D seismic). Its expanded use has greatly improved geological interpretations and has led to a much higher rate of successful wildcat drilling. In 3D seismic, a precisely located set of vibration-detecting geophones records the results of a series of experimental seismic disturbances. In one recent onshore survey involving 49 square kilometers, 725,000 geophone traces were recorded in connection with 1700 seismic disturbances. The tests were conducted and the data analyzed in 12 days. This exercise resulted in a substantial increase in estimated local reserves and led to greater production of oil and natural gas. Exploration is also being facilitated by other seismological technologies. In cross-well seismic, a powerful source of wide-spectrum sound is activated at different levels in one well and vibrations are received in one or more other wells. The character of the sound received indicates much about the intervening terrain. Nuclear magnetic resonance is increasingly being used downhole in petroleum exploration and can differentiate between hydrogens bound to clay, hydrogens in water, and hydrogens in hydrocarbons. Horizontal drilling has been used for about a decade. Before its advent, a well was usually drilled straight down and tapped a limited volume of hydrocarbons. A better approach has been to angle off the vertical and drill a path that follows the producing formation. So-called horizontal holes are now producing at rates three to five times those of vertical wells. In one instance, a well with an extended reach of more than 5 kilometers was successful in tapping the petroleum present along its length. In some instances, costs of production are being halved. Horizontal drilling and 3D seismic have been crucial to dramatic developments in fossil energy production in the region of the Gulf of Mexico adjacent to Louisiana and Texas. In that region, beneath waters 500 to 3000 meters deep, are world-class reserves of oil and natural gas that exceed those found at Prudhoe Bay, Alaska. New production technologies are facilitating the exploitation of these hydrocarbons. They include platforms with capabilities for drilling and completing wells and for subsequently producing and processing oil and gases. An underwater infrastructure of pipelines is being expanded to convey products to shore. The contiguous 48 states were originally explored with what are now regarded as primitive methods. The spacing of wells was based on assumptions about the underlying geology that were often erroneous. The large reservoirs were discovered but production from them was incomplete, and smaller reservoirs often went undiscovered. Today's new exploration technologies are finding additional reserves, and a vast infrastructure of pipelines and processing plants is available to minimize the costs of the final products resulting from these discoveries. Applied research sponsored in part by the Gas Research Institute has been effective in decreasing the costs and increasing the potential reserves of natural gas. One result has been a doubling of the estimate of ultimately recoverable quantities of natural gas in the United States. Prospects for the production of crude oil have also improved over those previously projected. The improved technologies are halting declines in the production of domestic oil and aiding in the discovery of additional reserves in other countries. The positive news stemming from developments in petroleum technology should not cause us to forget some troubling realities. The United States will continue to import about half of its supplies of liquid hydrocarbons. The cost of this fuel will contribute to a huge trade deficit that has made the United States the world's largest international debtor. This reliance on imported fuel also makes the United States vulnerable to deleterious political developments in countries on which we depend for fossil energy production. Such developments can happen overnight, in contrast to the 10 or more years required to construct production facilities. The United States has the technological ability needed to foster conservation and to create cost-competitive sources of transportation fuels. Efforts have already led to substantial decreases in the costs of renewable energy sources, but additional innovative programs should be devised and implemented.

The excess molar volumes of (hydrocarbon + branched chain ether) systems at 298.15 K and 308.15 K, and the application of PFP theory

The excess molar volumes, V m E, have been calculated from measured density values over the whole composition range at the temperatures 298.15 K and 308.15 K and under atmospheric pressure for the 12 mixtures {hydrocarbon (heptane, 2,2,4-trimethylpentane, 1-heptene or toluene) + branched chain ether (methyl 1,1-dimethylethyl ether, ethyl 1,1-dimethylethyl ether or methyl 1,1-dimethylpropyl ether)}. The excess volumes of all the mixtures except (toluene + ether) are positive over the whole composition range. The experimental results have been correlated and compared with the results from Prigogine-Flory-Patterson (PFP) theory.

Group contributions to the infinite dilution partial molar volumes of alkanes, alcohols, and glycols in polar organic solvents

Densities of binary mixtures of polar organic solvents with alcohols were measured at 25‡C. The solvents studied were N,N-dimethylformamide, dimethylsulfoxide, and formamide while alcohols were butanol, pentanol, hexanol, and 1,4-butanediol. Density measurements of hydrocarbons (from pentane to dodecane and some heptane isomers) + N,N-dimethylformamide were also performed. From these data the apparent molar volumes of alcohols and hydrocarbons as functions of concentration were calculated. The standard partial molar volumes were obtained by extrapolation to infinite dilution and are discussed in terms of group contributions.

PREHISTORIC, ANCIENT AND MEDIAEVAL OCCURRENCES AND USES OF HYDROCARBONS IN THE GREATER MIDDLE EAST REGION

THE ARABIAN PLATE, and neighbouring parts of Egypt, Turkey, Iran and the southern Caucasus, includes within its boundaries numerous active hydrocarbon seepages. Their origin is related to the beginning of the current tectonic regime, which commenced in Oligocene‐Miocene times. The culmination of Alpine tectonics around the northern edge of this region gave rise to stress regimes that deformed the plate margins and ruptured the integrity of hydrocarbon traps and seals. This resulted in the many seepages recorded throughout the Arabian Plate and adjoining areas to the north.Extensional plate margins bound the Arabian Plate to the SW and south; transform margins are on the west and SE; and collisional margins on the north and NE. It is along these (or along splays from them) that most of the major active seepages occur.The collisional regimes along the Taurus and Zagros foldbelts in the north and NE caused considerable subsurface movement of Cretaceous and older hydrocarbons and their migration and remigration. As folding intensified, inefficient seals were ruptured, and very large volumes of hydrocarbons migrated vertically upwards until trapped close to the surface in vast carbonate reservoirs beneath the regionally‐efficient evaporite seals provided by the Miocene Lower Fars/Gachsaran Formations. Where these seals were thin, poorly‐developed or eroded, major seepages developed, and huge volumes of hydrocarbons may have escaped to the surface. Indeed, there is speculation whether the Zagros foreland basin, overprinted onto the vast NE Arabian Shelf as a result of the Arabian/Eurasian Alpine collision, has not lost more hydrocarbons than it has retained through this process (Beydoun et al., 1992).

Effect of Vertical Heterogeneities in a Petrophysical Evaluation of Low Resistivity Pay Zones, B Sands Upper Eocene, Block III, Lake Maracaibo : ABSTRACTS

Thin-bed reservoirs can exist as intercalations of thin porous beds and shales. For a proper petrophysical evaluation and geological characterization of this type of reservoir it is necessary to implement an integrated analysis, which includes knowledge of the depositional environment to avoid missing oil zones by applying standard petrophysical evaluations. The normal resistivity logs used on this area do not have enough vertical resolution for detecting thin low resistivity pay zones. Consequently, the common water saturation models indicate high water saturation when they are evaluated. The Middle Eocene Upper B sands are part of the Misoa Formation in Block III of Lake Maracaibo. They have been exploited since 1965 when the first production test was made. The cumulative oil production to date stands at 11.49 MMSTB. In order to supplement the existing geological information in this area, a continuous core was taken which showed the high degree of shales and thin sands intercalations in the pay zone. A careful core-log calibration was made and a new set of petrophysical parameters were established for this reservoir based on the core measurements. This allowed the establishment of a new petrophysical evaluation procedure that helps the calculation of permeability, hydrocarbon volume in placemore » and productivity of this reservoir.« less

GAS DISPLACEMENT: AN IMPORTANT CONTROL ON OIL AND GAS DISTRIBUTION IN THE TIMOR SEA?

A study of gas fields in the Timor Sea has shown that these traps often contain palaeo-oil columns, with a high abundance of oil bearing fluid inclusions recorded in sands which are presently gas saturated. These palaeo- oil columns are substantial, suggesting the volume of liquid hydrocarbons that has been redistributed is significant. This remobilised oil in effect constitutes an oil charge of known volume for nearby structures, with seismic mapping confidently allowing the recognition of remigration fairways into up-dip traps. For example, at Oliver-1, a 115 m relict oil column, equating to original oil in place of over 166 MMBBL, has been identified. However, estimates of current oil in place account for less than 45 MMBBL, suggesting that more than 120 MMBBL of oil has been displaced across the spill point of the Oliver structure. Remigration of this oil can be mapped into an adjacent fault block, representing a new exploration play. Significantly, the likelihood of this untested trap containing liquids is supported by the presence of an oil leg at Oliver-1, which shows that only oil has been displaced from the Oliver trap.At Keeling-1, a smaller palaeo-oil accumulation has been detected which equates to about 14 MMBBL originally in place. However, the mechanisms responsible for the passage from palaeo-oil accumulation to the present gaseous hydrocarbon phase are often complex and decisions regarding a potential oil leg need be made judiciously. For example, at Keeling-1, oil shows and hydrocarbon related diagenesis in the overlying section provide compelling evidence that oil was lost due to fault breach rather than gas displacement.In contrast, a lack of evidence for palaeo-oil accumulation at Sunrise-1 and Troubadour-1 is also significant, as it removes the potential for an oil leg displaced either down-dip within the same structure or as a remigrated oil charge to adjacent up-dip structures. Significantly, these fields presently contain condensate and would have existed as separate oil and gas legs if charge occurred before dew point pressure was reached. The absence of a palaeo-oil column implies that the traps were charged after formation pressures exceeded the dew point of the reservoired gas. At Troubadoirr-1, this observation constrains the time of charge to the last 5-10 Ma, when pressures within the trap are estimated to have reached dew point.

Oil And Gas Fields Offshore Newfoundland And Labrador: Development Potential And Scenarios

Abstract Sixteen oil and gas fields have been discovered offshore Newfoundland and five gas fields were discovered offshore Labrador since exploration drilling started in 1966. Total recoverable resources of these fields care estimated to be 251 × 106m3 of oil, 234 × 109m3 of gas, and 58 × 106m3 of natural gas liquids. The geographic location of a field, resource size, quality and type, and the reservoir and production characteristics of, thepool, will strongly influence the technology and techniques used to develop each field. The technologies used to exploit these resources will likely include floating production facilities, gravity-based systems, satellite developments and horizontal drilling. In addition, potential exists to employ improved recovery techniques in some of the larger pools to increase oil recovery. Introduction 117 exploration wells have been drilled offshore Newfoundland and Labrador resulting in the discovery of 21 oil and gas fields, 16 offshore Newfoundland and five offshore Labrador. All fields offshore Labrador contain gas except for a minor pipe recovery of light waxy oil from the North Leif I-OS well. Exploration results suggest this area is gas prone. Offshore Newfoundland, eight fields contain oil only, two fields contain gas only, while six fields contain oil and gas. Combined recover able oil and gas resources of these fields are estimated to be 251 × 106m3 (1.6 Bbbls) of oil, 234 × 109m3 (8.2 Tscf) of gas, and 58 × 106m3 (360 MMbbls) of natural gas liquids. The term "resource" is used throughout the paper to refer to those volumes of hydrocarbons that are assessed to be technically recoverable but have uncertain economic or technical viability; where the hydrocarbons in question are considered to be recoverable using current technology and under present and anticipated economic conditions, the term "recoverable" reserves is used. The first section of the paper provides a brief review of the recoverable oil, gas and natural gas resource estimates, focussing on the largest fields. Reservoir and production characteristics are presented for each oil and gas pool, and, where appropriate, technical challenges in exploiting these resources, and opportunities for improved recovery schemes are discussed. The second section discusses the potential and scenarios for development of the oil and gas fields. The technology which could be used to exploit the resources and the timing of development of the resources are briefly discussed. FIGURE 1: Oil fields offshore Newfoundland. Available In Full Paper. Discovered Resources and Field Review Oil Resources All the oil fields discovered to date, except for the South Tempest field, are located in the Jeanne d'Arc basin (Figure 1). TABLE 1: Discovered resources*-Northeast Grand Banks and Labrador Shelf regions: The recoverable oil resource estimates for these fields are shown in Table 1. Most of the oil is contained in four fields: Hibernia, Terra Nova, Hebron and Whiterose. Each of these fields is estimated to contain in excess of 238 × 106m3 (1500 MMbbls) of recoverable oil. The remaining ten fields are small, containing less than 4 × 106m3 (25 MMbbls) of oil each.