Hydrocarbon Volumes Research Articles

Structurally complex reservoirs: an introduction

Abstract Structurally complex reservoirs form a distinct class of reservoir, in which fault arrays and fracture networks, in particular, exert an over-riding control on petroleum trapping and production behaviour. With modern exploration and production portfolios commonly held in geologically complex settings, there is an increasing technical challenge to find new prospects and to extract remaining hydrocarbons from these more structurally complex reservoirs. Improved analytical and modelling techniques will enhance our ability to locate connected hydrocarbon volumes and unswept sections of reservoir, and thus help optimize field development, production rates and ultimate recovery. This volume reviews our current understanding and ability to model the complex distribution and behaviour of fault and fracture networks, highlighting their fluid compartmentalizing effects and storage-transmissivity characteristics, and outlining approaches for predicting the dynamic fluid flow and geomechanical behaviour of structurally complex reservoirs. This introductory paper provides an overview of the research status on structurally complex reservoirs and aims to create a context for the collection of papers presented in this volume and, in doing so, an entry point for the reader into the subject. We have focused on the recent progress and outstanding issues in the areas of: (i) structural complexity and fault geometry; (ii) the detection and prediction of faults and fractures; (iii) the compartmentalizing effects of fault systems and complex siliciclastic reservoirs; and (iv) the critical controls that affect fractured reservoirs.

Conductive faults and sealing fractures in the West Sole gas fields, southern North Sea

Abstract Understanding the distribution and geometry of sealing faults and conductive natural fractures is important at all stages of field development and infill drilling. Sealing faults or fractures reduce contacted hydrocarbon volume per well by compartmentalizing the reservoir and reduce rate by locally impairing permeability. Open fractures or conductive faults enhance well productivity and contacted volume, but cause drilling difficulties and may lead to early aquifer influx or injection water breakthrough. With their lengthy drilling and production history, the West Sole area gas fields provide a natural laboratory for the study of sealing and conductive fractures and their inter-relationships. Conductive fractures were recognized early in field life, but the poor performance of some wells indicated that fractures were not uniformly distributed. As development continued, entire field segments were found to be unfractured. Subsequent appraisal drilling identified undepleted and partially depleted compartments, demonstrating that sealing faults or fractures are also present. More recent development of the satellite fields Newsham and Hoton has confirmed the presence in a single field of both conductive and sealing fractures, although there is a general inverse spatial relationship between the two. The structural history of the reservoirs provides an explanation for this phenomenon. Faulting at high pressures and temperatures during Jurassic rifting gave rise to sealing lithified cataclasite fault rocks. Inversion to form the hydrocarbon traps took place at lower pressures and temperatures. The associated brittle deformation breached sealing faults and generated open fractures.

Calculation of the molar volume of liquid hydrocarbons

Equations are proposed for calculating the molar volume of liquid hydrocarbons used in production of surfactants. With such data, it will be possible to calculate most of the physicochemical properties of these hydrocarbons to solve many process problems.

IS THERE A VIABLE PETROLEUM SYSTEM IN THE CARSON AND SALAR BASINS, OFFSHORE NEWFOUNDLAND?

The Carson Basin on the eastern Grand Banks of Newfoundland has been penetrated by four wells ‐ Bonnition H‐32, Osprey H‐84, Skua E‐41 and St. George J‐55 ‐ which were drilled along its western margin. The adjacent deeper‐water Salar Basin to the east remains undrilled with the exception of ODP holes 1276A and 1277. The Carson Basin wells contain a thick Mesozoic and Cenozoic sedimentary section which includes reservoirs and seals; but source rocks, such as those present in the adjacent Jeanne d'Arc Basin, have not been found. To assess the petroleum system, well samples were collected to provide Rock Eval and vitrinite reflectance data, and analysed biostratigraphically to obtain ages and depositional environments. These analyses indicate that a Late Jurassic source rock, similar to the Egret Member (of the Rankin Formation) of the Jeanne d'Arc Basin, may be present in the deeper‐water, distal parts of the Carson and Salar Basins; this is based on a regional palaeotectonic reconstruction, together with gravity and magnetic data, including sea‐floor spreading magnetic anomalies. We interpret the absence of the Egret Member in the four wells to reflect the wells' locations rather than the Member's absence from the two basins.An integrated 4D model of the Carson Basin was built from biostratigraphy and seismic surfaces, to which an Egret‐like source rock was added. The modelling showed that significant volumes of hydrocarbons could have been generated, mostly during the main Late Cretaceous drifting event in the area. Hence, significant volumes of hydrocarbons could be present in the Carson and Salar Basins, mainly in stratigraphic traps in Early Cretaceous clastic reservoirs.

Oil quality in deep-water settings: Concerns, perceptions, observations, and reality

As exploration migrates into deeper water, crude-oil quality becomes increasingly important. Variations in oil quality, which are reflected in such properties as API gravity, viscosity, sulfur content, and acid number impact both value and producibility. In fact, issues of oil quality in deep water may, in some cases, be more critical than issues of hydrocarbon volume. Problems associated with deep water are commonly thought to be amplified largely as a result of the expansion of the biodegradation window. The expanded window is a result of lower temperatures at the mud line. A review of data from the Gulf of Mexico and the Gulf of Guinea reveals that other factors may have a greater influence on oil quality. For example, in the Gulf of Mexico, strong evidence exists that the nature of the source rock is a major factor in establishing sulfur content and API gravity. Oils derived from an Upper Jurassic Oxfordian calcareous source rock generate oils with higher sulfur contents than those derived from Cretaceous argillaceous source rocks. In the Gulf of Guinea, although many of the newly discovered pools are shallowly buried and evidence for biodegradation exists, crude-oil quality is mitigated by multiple charging events. In both regions, evidence also exists for phase segregation, which introduces light oils and condensates into the shallow part of the sedimentary sequence. Both phase segregation and multiple charging events appear to be largely a result of an individual trap's structural evolution. The available data, therefore, suggest that some of the risks associated with oil quality may be reduced through a more detailed assessment of a prospect's filling history and structural evolution and an understanding of the nature of the source facies. However, there clearly are such situations as offshore Brazil, where the risks associated with oil quality appear more difficult to mitigate.

Theoretical Investigations of the Effect of a Homologous Series of Anionic Surfactants on the Metabolism Bioactivity of Chromobacterium violaceum

Theoretical calculations were performed to obtain physicochemical properties associated with the effect of homologous anionic n-alkylsulfate surfactants on the metabolism of Chromobacterium violaceum. The quantitative experimental effects on the respiration process were those obtained from calorimetric data and were used to correlate the Structure–Activity–Relationship (SAR) of these compounds. Semiempirical AM1 and ab initio DFT levels, employing the set CEP-31G, were used for the theoretical calculations and were parameterized using the continuum-solvation model COSMO for solvent contributions. Chemometric analyses (HCA: hierarchical cluster analysis and PCA: principal component analysis) were used to correlate the physicochemical properties of these compounds and their biological activities. The results indicate that the biological activities of these compounds increase as the hydrocarbon chain length, volume, molar volume and exothermic enthalpy of formation (ΔfH∘) increase; in contrast they decrease with decreases of the solvent effect (SE), ionization enthalpy (IE) and HOMO (highest occupied molecular orbital) and LUMO (lowest unoccupied molecular orbital) energies.

Overview: Heavy Oil (April 2006)

As I write this overview, the price of benchmark Brent crude ranges between U.S. $62 and $65/bbl, and heavy crude oils, such as Midway Sunset (13°API), hover around U.S. $53/bbl. There are many reasons for the increase in oil price, including market forces, political tensions, and speculation that world conventional-oil production is about to peak. Propelled by high oil prices, the phrase "peak oil" has become familiar to most people. I Googled the phrase "peak oil," and it produced 14,200,000 hits. Worries about the finite nature of the oil supply are reported in the common media and resonate with the public paying high prices for gasoline at the pump. The perception that peak oil is imminent and that the world is running out of hydrocarbon molecules is inconsistent with the reality of the heavy-hydrocarbon (less than 20°API) resource base. Conservative estimates of the volume of heavy hydrocarbons place the total resource in excess of 6 trillion bbl. If world oil demand could be held to 80 million B/D, the ratio of heavy resource to production rate is greater than 200 years. These figures do not include oil-shale resources that, in the U.S. alone, are estimated to be greater than 2 trillion bbl. In my view, at least two significant issues exist regarding heavy-hydrocarbon exploitation. The first is expansion of the knowledge base of specialized techniques needed to exploit the resource. Steam injection, whether in cyclic, drive, or gravity-drainage modes, has proved successful and economical. Yet, many resources do not fit the profile needed for steam injection. The suite of in-situ recovery technologies for heavy and viscous oil, ranging from waterflooding to in-situ combustion to solvent injection and electrical heating remains to be perfected. The development of such a suite thereby allows transformation of heavy resources to reserves and, ultimately, to a producible product. The second, and seemingly more difficult, issue is minimization of carbon dioxide (CO2) emissions associated with heavy-oil production operations. At oil/steam ratios ranging from 0.3 to 0.5, production of a barrel of heavy oil produces 80 to 140 lbm of CO2. Similarly, exploiting Alberta tar sands, by mining and upgrading bitumen to 1 bbl of light synthetic crude, produces slightly more than 220 lbm of CO2. For reference, combustion of 1 bbl of oil may emit 800 to 900 lbm of CO2. Thus, the CO2 footprint of heavy-oil production is significant in relation to that of combustion. These sobering figures are offset by the reality that the heat needed for thermal recovery comes increasingly from cogeneration operations that produce electricity and steam with large overall efficiency. This trend toward integrated energy solutions and greater efficiency is an important part of our energy future and holds one of the keys to producing heavy oil while keeping CO2-related emissions in check. Heavy Oil additional reading available at the SPE eLibrary: www.spe.org SPE 97279 "North Slope Heavy-Oil Sand-Control Strategy: Detailed Case Study of Sand-Production Predictions and Field Measurements for Alaskan Heavy-Oil Multilateral Field Developments," by R.C. Burton, SPE, ConocoPhillips, et al. SPE 94001 "Downhole Harmonic-Vibration Oil-Displacement System: A New IOR Tool," by T. Zhu, SPE, U. of Alaska, et al. SPE 97708 "Controlling Water Risks in Extra-Heavy-Oil Environments," by E. Pereira, SPE, Sincor, et al. SPE 97894 "Pore-Level Investigation of Heavy-Oil Depressurization," by K. Shahabi-Nejad, Heriot-Watt U., et al.

Disruption of extended defects in solid oxide fuel cell anodes for methane oxidation

Point defects largely govern the electrochemical properties of oxides: at low defect concentrations, conductivity increases with concentration; however, at higher concentrations, defect-defect interactions start to dominate. Thus, in searching for electrochemically active materials for fuel cell anodes, high defect concentration is generally avoided. Here we describe an oxide anode formed from lanthanum-substituted strontium titanate (La-SrTiO3) in which we control the oxygen stoichiometry in order to break down the extended defect intergrowth regions and create phases with considerable disordered oxygen defects. We substitute Ti in these phases with Ga and Mn to induce redox activity and allow more flexible coordination. The material demonstrates impressive fuel cell performance using wet hydrogen at 950 degrees C. It is also important for fuel cell technology to achieve efficient electrode operation with different hydrocarbon fuels, although such fuels are more demanding than pure hydrogen. The best anode materials to date--Ni-YSZ (yttria-stabilized zirconia) cermets--suffer some disadvantages related to low tolerance to sulphur, carbon build-up when using hydrocarbon fuels (though device modifications and lower temperature operation can avoid this) and volume instability on redox cycling. Our anode material is very active for methane oxidation at high temperatures, with open circuit voltages in excess of 1.2 V. The materials design concept that we use here could lead to devices that enable more-efficient energy extraction from fossil fuels and carbon-neutral fuels.

PROSPECTIVITY OF THE DEEPWATER GULF OF PAPUA AND SURROUNDS IN PAPUA NEW GUINEA (PNG)—A NEW LOOK AT A FRONTIER REGION

Despite limited well control and paucity of seismic data, a regional study of the deepwater portion of the Gulf of Papua, Papua New Guinea (PNG), indicates a number of large structures at a variety of stratigraphic levels that are capable of holding significant volumes of hydrocarbons. The main structural elements east of the Fly River Platform the Pandora Ridge, Pandora Trough, Aure Trough, Port Moresby Trough and the northern portion of the Eastern Plateau were established during the Paleozoic and further enhanced by Late Cretaceous to Early Paleocene Coral Sea rifting in the southeast. Structuring in the region is mostly basement involved and extensional, and is overprinted by a later compressional pulse. Extensional and compressional regimes produce many potential traps. To date, exploration in the Gulf of Papua has been sporadic and mainly focussed in shallow water depths. The new reprocessed seismic data indicate the following Paleozoic to Recent plays, some of which contain multiple reservoir-seal pairs, sourced by non-marine and marine source rocks:extensional Paleozoic rift fault blocks;Upper Jurassic to Lower Cretaceous turbidites (Iagifu- Hedina-Toro sandstone equivalents);Campanian to Middle Paleocene Coral Sea synrift sandstone and basin floor fan equivalents (Pale/Barune Formations and equivalents);Middle Paleocene break-up unconformity fault blocks and intra-basinal highs;Upper Paleocene to Lower Eocene Pima Sandstone equivalent associated with the Middle Paleocene uplift and erosion;Oligocene to Lower Miocene lowstand deltas and turbidites;Miocene to Recent biohermal build-ups (possibly including a new limestone high, the Box Ridge, in front of the Pandora Ridge); Karstified Darai Limestone equivalent sealed by Aure Beds claystones;Miocene to Recent lowstand deltas and turbidites;Eocene to Pliocene stratigraphic onlaps flanking main structural highs; and,compressional plays associated with the Pliocene to Recent collision of the PNG and Pacific plates.

Late-Holocene evolution of the Mahakam delta, East Kalimantan, Indonesia

The late-Holocene Mahakam delta, located along the tropical eastern shore of Kalimantan, Indonesia, is considered to be a textbook example of a mixed tide–fluvial dominated delta system. The delta prograded about 60 km during the past 5000 years, which led to the development of a distinct network of distributary and tidal channels. Wave action is low due the limited fetch in the narrow strait of Makassar. Mahakam River discharge is about a quarter of the Mississippi River discharge and is characterized by absence of flood surges. Therefore, natural levees, crevasse splays and avulsions are absent in the delta plain. For the past four decennia, both modern and ancient Mahakam delta deposits have been studied in detail in order to better understand subsurface Miocene and Tertiary Mahakam deposits, which host large volumes of hydrocarbons. This study focuses on the dynamics and stratal patterns of delta plain, delta-front platform deposits and suspended sediments. Due to the predominance of semi-diurnal tides and the associated flow reversals, depositional patterns are highly variable which has resulted in the formation of characteristic sand–mud couplets. The distribution of the sand–mud couplets found in this study differs from previously proposed conceptual models. They are limited to the fluvial domain and form in the distributary channels (lateral channel bar) or at the fluvial dominated delta-front platform, which flanks the mouth bar deposits in offshore direction. The sand–mud couplets which formed as delta-front platform and lateral channel bar deposits are similar and can only be identified based on their 14C age. The sand content decreases significantly towards the tidal dominated areas due to limitation in transport capacity. Turbidity measurements taken in front of the river mouth also show rapid settlement of river plume sediments. Some 22 new AMS 14C dates show that late Holocene sea level history resembles the eustatic sea level curve giving a first approximation of the Late Holocene sea level history for East Kalimantan. The dates suggest that the progradational delta system evolved under conditions of slowly rising sea level, which compares well to the eustatic sea level curve. In addition, calculated averaged deposition rates of the sand–mud couplets indicate that deposition is driven by the spring–neap tide cycles instead of the daily tidal cycle.

Overview: Heavy Oil (June 2005)

What is heavy oil, and why do you care about it? These are important questions with answers that are simple, but subtle. Heavy hydrocarbons exhibit gravity less than 20°API. They are characterized by high viscosity that increases as API gravity decreases, low hydrogen/carbon ratios, low gas/oil ratio, as well as significant sulfur, asphaltenes, and heavy metals. In short, heavy-oil reservoirs generally present low-energy and low-productivity wells. These characteristics make recovery challenging, yet the volume of heavy hydrocarbons in the world warrants a thorough look. Canada and Venezuela each possess heavy-oil resources of approximately 3 trillion bbl. In comparison, the heavy-oil resource of the U.S. is less than 200 billion bbl. This does, however, represent a more-than-40-year supply at current U.S. oil-consumption rates. Significant heavy-hydrocarbon resources also are found in Indonesia, Russia, and China, as well as elsewhere. A second reason for interest is the difficulty in attaining economical exploitation. It suggests a need for research and development activities. Thermal recovery, and steam injection in particular, is tremendously successful. The addition of heat reduces oil-phase viscosity significantly. Nevertheless, conventional steam-injection candidates are limited to onshore, relatively shallow, thick, and permeable sands. Given the oil volumes in place, the range of reservoir settings, and the difficulties of extraction, a suite of heavy-oil recovery options is needed. Consider an incomplete list of research and development opportunities. First, primary recovery that uses horizontal and multilateral wells is possible and profitable. The production mechanisms of the heavy-oil solution-gas drive process are, however, not completely elucidated, and performance cannot be simulated by conventional techniques. Second, waterflooding of heavy oil is summarily dismissed because of adverse mobility ratios, but is similarly not well understood. In cold and/or offshore environments, waterflooding may present the only viable recovery option following primary production. Third, steam injection is relatively mature, but steam is considerably less viscous and dense than oil. Cost-effective mobility and profile control by use of aqueous-phase surfactants, gels, or advanced well completions remains an open question. Fourth, in-situ combustion achieved by air injection is technically and economically feasible, especially for deeper, thinner, higher-pressure reservoirs. Combustion has seen less field application than steam because of the difficulty in its description and control. Finally, combustion presents possibilities for in-situ upgrading and sulfur removal. In short, the cumulative production totals of heavy oil are on the order of billions of barrels, but this is only a small fraction of the oil in place. Whether the potential and promise of heavy oil are realized depends on the collective action of industry, academia, and governments to deliver a suite of technologies appropriate for the wide range of reservoir and oil-phase conditions. Additional Heavy Oil Technical Papers Available at the SPE eLibrary: www.spe.org SPE 93881 Toward an Adaptive, High-Resolution Simulator for Steam-Injection Processes SPE 93894 A New Reservoir-Simulation Model for Understanding Reservoir Performance in the McKittrick Steamdrive

Modern Carbon/Oxygen Logging: Hydrocarbon- Saturation-Determination Techniques

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90339, "Modern Carbon/Oxygen Logging Methodologies: Comparing Hydrocarbon-Saturation-Determination Techniques," by Ramsin Y. Eyvazzadeh, Oscar Kelder, A.A. Hajari, Shouxiang Ma, and Abdallah M. Behair, SPE, Saudi Aramco, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Recent advances in carbon/oxygen (C/O) logging technology have provided measurements that have become more quantitative in reservoir-monitoring projects, especially in mixed-salinity environments. Although innovations have led to major improvements, fluid-saturation profiles provided by different service companies often vary. These variations are caused by differences in tool design and interpretation method. A study was conducted in a large Middle Eastern carbonate field to evaluate and compare accuracy and precision of different types of pulsed-neutron-spectroscopy (PNS) tools in a controlled environment. Introduction An important reservoir-management factor is accurate determination of water saturation. Accuracy is critical in time-based measurements used in tracking reservoir depletion, enhanced recovery, workover strategies, and injection-water breakthroughs. This parameter is even more sensitive in large fields, where small variations in water-saturation values can translate into large hydrocarbon-volume differences. The carbonate field in this study was discovered in the 1950s, and an enhanced-oil-recovery project was initiated in the 1970s. Since then, several types of water, with varying salinities, have been injected. This salinity variation complicates the saturation computations that rely on accurate measurements of formation-water resistivity (i.e., resistivity-tool data). Resistivity measurements are used in empirical equations to calculate fluid saturations on the basis of known formation-water resistivity. In formations that contain fresh water or unknown water salinity, these equations produce answers with large uncertainties. These limitations contributed to development of the PNS tools. The tools use neutron generators to produce high-energy neutrons that collide with different types of elements in the formation. These collisions produce gamma ray signatures that are used to measure the relative abundance of elements. Two of the most important elements are carbon and oxygen. The abundance of these elements is used directly to calculate hydrocarbon volume. C/O logging was introduced in the 1960s. The early technology was cumbersome, difficult to use, and, often, provided unreliable answers. In the 1990s, several new-generation tools were introduced by three major logging companies: Schlumberger, Halliburton, and Baker Atlas. These new tools have high-output neutron generators with better detectors and characterizations that provide more-accurate answers. Even though these tools operate on the same principles, the service companies use different methods, resulting in nonunique solutions. This study examined these differences in two wells. In the first well, saturation data from nuclear-magnetic-resonance (NMR) logs were compared with C/O-log and laboratory core-measured saturation data to determine the applicability of this technology in this field. In the second well, resistivity and capture data were used as references to compare data from three different types of PNS tools.

Adsorption Saturation and Chromatographic Distortion Effects on Passive Headspace Sampling with Activated Charcoal in Fire Debris Analysis

Distortion of the chromatographic profile obtained for hydrocarbons that have been sampled by adsorption onto activated charcoal is a well-known phenomenon. The work reported here helps to better define the causes of chromatographic profile distortion and offers a potential method to avoid chromatographic distortion in some cases through a subsampling technique. The recovery of hydrocarbons from an equimolar mixture was investigated to determine the influence of hydrocarbon concentration on the molar ratios of recovered components. In a one-quart container, hydrocarbon volumes as small as 24 microL (liquid) were sufficient to saturate the surface area available for adsorption on a 99.0 mm2 square of activated charcoal, resulting in significant distortions in the molar ratio and the chromatographic profile of the recovered hydrocarbons. Passive headspace sampling of a similarly small volume of unweathered gasoline spiked onto carpet padding resulted in a significant distortion of the chromatographic profile. The chromatographic profile of the recovered hydrocarbons closely resembled 75% weathered gasoline. Heating the container spiked with unweathered gasoline to evenly distribute the components and then removing a subsample of the carpet padding to a second container for passive headspace analysis greatly reduced the amount of distortion in the resulting chromatogram.

How wrong can it be? Understanding uncertainty in petroleum systems modelling

Petroleum systems modelling is used in industry to understand and predict the interplay between the main elements of a petroleum system. This is done using numerical modelling because it cannot possibly be done experimentally given the geological time- and space scales. Such models describe the geological processes forward in time and, therefore, generate a single unique solution for a given input dataset. The evidence from data is, in most cases, insufficient to remove any ambiguities. Therefore, it is more interesting to know how much this uncertainty can be reduced, or how wrong it still might be, rather than knowing the right answer. Given the uncertainty of model outcomes, the appropriate solution should, therefore, be probabilistic rather than deterministic, where the variance expresses the remaining uncertainty in the outcome covering all possible valid geological scenarios. This paper describes how experimental design and response surface analysis can be used to perform sensitivity and uncertainty analysis in petroleum generation and migration modelling, focusing on trapped volumes derived from its drainage area. Map properties are parameterized as end-member scenarios, either as discrete or linearly varying maps. Regression coefficients indicate a good representation of trapped hydrocarbon volume by the response surface. In the example presented, hydrocarbon volume is most sensitive to fault characteristics, total organic carbon content and, to a lesser degree, to thickness of the source rock and heat flow. Well data allow a significant reduction of uncertainties, which can be shown by the probability distribution that becomes narrower but remains similar in form. The volume probability distribution of the prospect is multimodal for a discrete parameter scenario and log-normal for both discrete or uniform input distributions. Volume distributions result directly from the deterministic modelling without any prior statistical assumption on the form of the distribution.

The remaining hydrocarbon potential of the UK Continental Shelf

The United Kingdom Continental Shelf (UKCS) has been a very successful exploration province in the last 38 years, with an average technical success rate of 31% from its 2150 exploration wells. Although the peak of exploration activity on the UKCS occurred during the 1980s and 1990s, there have been 41 technical successes from 82 wells in the last four years, representing an improved recent success rate of 50%. Estimates of undiscovered (yet-to-find) hydrocarbon volumes have been made from a database of prospects compiled over 20 years by the UK Government. This ‘bottom-up’ method provided an estimate of the yet-to-find resources at the end of 2002 of between 3.6 and 22.9 × 10 9 BOE recoverable. Methodology utilizing an inverse timescale to plot cumulative discovered volumes per year provides minimum estimates of between 4.5 and 9.5 × 10 9 BOE in place ( c . 2.5 to 4.4 × 10 9 BOE recoverable). Pool size distribution methodology predicts that 11.5 × 10 9 BOE of in-place ( c . 5.8 × 10 9 BOE recoverable) resources remain to be found on the entire UKCS. Geographically, the UK Central North Sea and Moray Firth area is predicted to contain the largest proportion of undiscovered resources (42%). Thirty-three per cent of the yet-to-find resources are judged to lie within the Atlantic Margin region. Eighty-three per cent of existing UKCS fields and discoveries are located within structural traps. The majority of stratigraphic and combination traps occur in association with syn-rift (Upper Jurassic) and post-rift plays. Many of the major discoveries in these traps were found serendipitously, and there has been relatively little direct exploration for stratigraphic plays. In the UK North Sea, there are few substantial remaining structural traps, except at considerable depth with attendant reservoir quality, high-pressure and high-temperature risks. The future of exploration is believed to lie with the search for subtle stratigraphic traps. Deep-water sandstone stratigraphic plays within the syn- and post-rift sequences offer the greatest potential for substantial new resources.

Prediction of Liquid Molar Volumes by Additive Methods

Liquid molar volumes of typical alcohols and hydrocarbons measured previously under atmospheric pressure at 20–70°C are complied and tabulated. An additive method by Elbro et al. was adopted to predict these liquid molar volumes. The method is found to be useful. However, it cannot be adopted to several substances because additive factors required are not available. In this study, a simple predictive method is proposed by using the expansion coefficient, β = (vb – v25)/(tb – t25). The molar volumes at 25°C, v25, and at the normal boiling point, vb, were predicted by the additive methods of Fedors and Le Bas, respectively. Liquid molar volumes at the temperature t can be predicted by v25 + β(t – 25). The present approach is found to be successful except for small molecules, such as methanol and ethanol.

二方向照射による溶接変形量の低減―レーザ溶接による自動車部品のミクロン・サブミクロンレベルにおける変形挙動に関する研究 （第３報）―

Laser welding systems have been installed in many assembly lines because of small welding distortions. Nonetheless, desires to produce earth-friendly automotive components such as fuel injectors with low volume of residual hydrocarbons in exhaust emissions require higher accuracy of microns or sub-microns order to maintain their function. For examples, circularity deviation of such an injector after welding is requested to be less than 1 micrometer. Laser welding is a processing with small distortion, however, making the distortion smaller is critical to meet such a high level objective. In this paper, we consider the deformation mechanism by using numerical analyses and experiments, and propose a new method, twin beams method, to decrease the deviation of circularity. Twin beams, which is separated by 90 degrees, obtain a smaller deviation of circularity because of canceling expansion and shrinkage during the welding process. This method is brought into production facilities.

Reducing structural uncertainties through anisotropic pre-stack depth imaging: examples from the Elgin/Franklin/Glenelg HP/HT fields area, Central North Sea

This paper highlights how a global approach to quantifying structural uncertainties has ultimately reduced overall structural uncertainty through improved seismic imaging, notably anisotropic pre-stack depth migration, in a structurally complex area. The Elgin/Franklin high pressure/high temperature (HP/HT) fields lie in the Central Graben area of the North Sea UK sector, c . 240 km east of Aberdeen. The fields are the deepest production in the North Sea and represent the largest gas condensate development in the world, with recoverable reserves estimated at over 700 × 10 6 BBL equivalent. The reservoirs produce from the Jurassic Fulmar shallow-marine and Pentland fluvial reservoirs at depths of 5100–5600 m subsea. Production from these HP/HT reservoirs (1100 bar/200°C) started in March 2001 and flows over 200 000 BOE per day from 12 wells. For this type of producing environment, the stakes are high for understanding uncertainties related to imaging. Improved fault imaging translates not only to reduced uncertainties in bulk rock volumes, and ultimately in-place hydrocarbon volumes but also to an increased understanding of the static/dynamic behaviour of the fields through better imaging of internal faulting. The application of various proprietary and contractor-based seismic depth processing since 1997 has allowed for a better understanding of structural configuration of the deep reservoirs. This rich processing history has provided the interpretation team with various processing volumes (isotropic Post-SDM, anisotropic Post-SDM and, most recently, anisotropic Pre-SDM) to allow a more complete understanding of the uncertainties related to different imaging approaches. Historically, the effects of anisotropy on vertical and lateral positioning were realized and a number of internal proprietary software tools were developed to quality control depth imaging processing. The 1998 Glenelg discovery southwest of Elgin Field was the focus for the initial anisotropic Pre-SDM study, which was later expanded to include the Elgin/Franklin fields area. This processing benefited from Total’s internal QC tools and a combination of additional data (e.g. walk-away VSP profiles with different orientations, long-offset 2D seismic data) which provided an optimum mix to derive and verify the anisotropic parameters for the velocity model. Overall, the new seismic data shown significant improvement over the previous time- and depth-migrated datasets, reduced uncertainty on internal and bounding-fault positions and allowed the observation of the vertical and spatial uncertainties attached to different migration approaches. This understanding of the variability in seismic imaging and its effects on the reservoir parameters and structural configurations in depth is used as an input to understand ranges of in-place hydrocarbon volumes, the potential of near-field exploration and future infill-drilling strategies.

Hydrocarbon source rock characterization and thermal maturity of the Upper Triassic Baldonnel and Pardonet formations, northeastern British Columbia, Canada

Abstract Numerous gas and oil fields are hosted in the Baldonnel and Pardonet formations of northeastern British Columbia, Canada. The source of the hydrocarbons in these fields has not been demonstrated using organic geochemical methods. However lithologic characteristics, interpreted depositional settings, and some published organic carbon content values have led to speculation that Upper Triassic strata of northeastern British Columbia, in particular the Pardonet Formation, may include important hydrocarbon source rocks. In order to assess the hydrocarbon source rock potential of Upper Triassic strata in northeastern British Columbia, nine outcrops and seven drillcores were measured, described and sampled for geochemical analyses. Geochemical analyses using Rock-Eval/TOC pyrolysis indicate a total organic carbon (TOC) content ranging from 0.03 to 2.08 weight percent for the Baldonnel (majority Geochemical data from outcrop and core suggest that the Pardonet Formation in northeastern B.C. had good to very good initial hydrocarbon potential, and has generated economically significant quantities of hydrocarbon. However, gas isotopic and gas compositional data, as well as biomarker analysis of oils and source rock extracts, are required to demonstrate whether the Pardonet, or some other, deeper unit, was the source of hydrocarbons found in Upper Triassic reservoirs in northeastern B.C. Mass balance calculations based on the geochemical data presented here for the Pardonet Formation, suggest that current initial in-place reserve estimates for Upper Triassic reservoir strata are four to five times less than expected. We speculate that some proportion of this calculated volume of hydrocarbons may have been retained within the Pardonet Formation itself, suggesting some potential as a fractured shale play. The Baldonnel Formation had only poor to fair initial hydrocarbon potential, and was not a significant hydrocarbon source.

Fault intersections as critical hydrocarbon leakage zones: integrated field study and numerical modelling of an example from the Timor Sea, Australia

Fault intersections are identified as important sites for hydrocarbon leakage from the Skua oil field in the Timor Sea, Australia. Integrated structural and fluid history data sets suggest that these fault intersections may be efficient and long-lived fluid conduits. Three-dimensional (3D) numerical modelling, based on fault patterns observed in the Skua Field, generated zones of high dilation in the vicinity of fault intersections during contraction, even at low bulk strain values. In nature, these dilational zones are likely to be sites of high structural permeability containing concentrated open fracture networks ideal for high fluid flux. The potential for fluid leakage from these zones may be further enhanced where low shear strain occurs due to mechanical locking at the fault intersection. Although not tested in the numerical experiments, fault gouge development is likely to be less extensive in these zones of low shear strain, reducing the probability of forming membrane seals. The modelling results support previously published charge and leakage history studies of the Skua Field and highlight the potential for large volumes of hydrocarbons to be lost where fault intersection zones breach the top seal. Fault intersections may therefore play a significant role in influencing trap integrity conditions in other areas.