Significant Hydrocarbon Accumulations Research Articles

The Rafael gas-condensate discovery – a potential game-changer in the Canning Basin

The Rafael 1 exploration well discovered an abnormally high-pressured gas-condensate pool in the Kimberley region in late 2021. Data supports a minimum gross gas column of 165 m at the well location trapped within a large faulted four-way closure in a dolomite reservoir sequence with strong similarities and age equivalent to the oil-bearing Ungani Dolomite reservoir in the Ungani Field. A successful production test in March 2022 resulted in sustained natural flows of gas and condensate to surface. The presence of thick sandstones of the Anderson Formation and a complete Laurel section beneath the Meda Unconformity were unexpected based on the pre-drill interpretation. Serendipitously, it provided the perfect geological setting for a significant hydrocarbon accumulation and emphasised the need to consider multiple geological scenarios when evaluating prospects to capture the full range of uncertainties and potential pool sizes. Although the range in size of the contingent resources is wide and requires further drilling for refinement, the Rafael 1 discovery could be one of the most significant onshore gas discoveries since Waitsia 1 and provides impetus and incentive for continued exploration in the basin. Several pathways for commercialisation have been identified linked to the resource size. A comprehensive appraisal program is underway including the recently completed acquisition of a 200 km2 3D seismic survey to optimally locate wells, and plans for drilling to reduce uncertainty and support the first phase of development based on a low case contingent resource that could underpin the energy needs of the Kimberley region.

Fracture distribution along open folds in southern Tunisia: implications for naturally fractured reservoirs

Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences of these networks. Our study focuses on the Southern Chotts–Jeffara Basin, which hosts reservoirs within Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proved that a regional shortening phase occurred between the Permian and Jurassic, forming open folds and a distributed fracture network. Analysis of late Paleozoic and Mesozoic outcrops within the basin has identified several sets of fractures (with dip directions and dip angles of 150/80 and 212/86) and compressional structural features that support this shortening hypothesis. We have integrated fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we found that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid-flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provide an insight into network characterization within naturally fractured reservoirs of Tunisia, and how certain structures form fluid pathways that influence flow and production. Supplementary material: Data and figures detailing fracture characterisation and modelling along open folds in southern Tunisia are available at https://doi.org/10.6084/m9.figshare.c.6904499

Integrated geochemical and statistical evaluation of the source rock potential in the deep-water, Western Basin of Ghana

Ghana is recognised as one of the recent oil and gas producing countries in the Gulf of Guinea, West Africa. However, despite the significant hydrocarbon accumulation in the Western Basin of Ghana, not much is known about the current potential of source rocks in this Basin. To broaden the scope of current knowledge on the Western Basin of Ghana, this paper identifies the current formation potential, organic matter origin, thermal maturity, and possible ages within the Cretaceous Period for hydrocarbon generation in the basin, using geochemical techniques and statistical analyses of 1530 cuttings and core samples. The geochemical parameters include pyrolysis data such as free hydrocarbon (S1), hydrocarbon generated (S2), carbon dioxide released (S3), hydrogen index (HI), production index (PI), maximum temperature (Tmax), oxygen index (OI) and total organic carbon (TOC). The formations encountered in the Western Basin, which have various ages within the Cretaceous Period , show a good to very good possibility of producing hydrocarbon with mainly kerogen type II/III and some amount of type I in certain formations. The majority of the Cretaceous ages fall in the early mature to peak maturity zone, with Campanian and Santonian considered as additional hydrocarbon sources to the Albian, Cenomanian, and Turonian. Pearson coefficient showed that TOC has a strong positive correlation with S2, positive correlation with S1 and HI, and negative correlation with Tmax. Two-Step and K-means clustering on the studied samples show that TOC, S2, and S3 are the major parameters for source rock potential prediction. Factor analysis gave three factors affecting source rock evaluation. Factor 1 highlights TOC, S1, and S2 as the parameters for identifying the quantity and quality of organic matter. This is confirmed by factor 2, which identifies HI and OI as the determining variables. Factor 3 identifies PI and Tmax as indicators of the thermal maturity of the source rock.

Seismic Attributes Aided Characterization of Margin Backstepping and Advance along Isolated Carbonate Sequences, Sirt Basin, Libya

Isolated carbonate platforms are common and contain significant hydrocarbon accumulations, particularly in the tectonically complex Sirt Basin in Libya. This study investigates the margin cyclicity of two carbonate stratigraphic sequences developed on an isolated carbonate platform in the NW Sirt Basin using 3-D post-stack seismic volume and wireline log data. The two sequences (sequences 4 and 5) are bounded by unconformity surfaces from the base and top. Seismic attributes show that each sequence displays a cycle of margin backstepping followed by margin advance for several hundred meters. This study concludes that the margin backstepping and advance are mainly influenced by sea-level changes. A rapid sea-level rise caused the backstepping, whereas slow sea-level rise caused the margin advance.

Age, microfacies and depositional environment of the Middle to Late Paleocene shallow-marine carbonates in the Sirt Basin of Libya (Upper Sabil Formation): \u201cAre Intisar domal structures pinnacle reefs?\u201d

In the central-eastern Sirt Basin, enigmatic Intisar domal structures host significant hydrocarbon accumulations. These structures have been commonly interpreted as pinnacle reefs/bioherms occurring in the open-marine basinal environment. Generally, pinnacle reefs/bioherms are mainly characterized by in situ carbonates. The current study challenges the Intisar pinnacle reef/bioherm model by examining one of the domal structures in terms of biostratigraphy, microfacies and depositional environment. These structures were dated using larger benthic foraminifera, which yielded a Middle to Late Paleocene age (Selandian–Early Thanetian). Thirteen microfacies types representing different carbonate ramp environments ranging from outer ramp to inner ramp, were defined. Outer ramp deposits have been observed adjacent to the domal structure, represented mainly by wackestone with small benthic and planktonic foraminifera. The outer ramp deposits are most likely isochronous to the domal structures. The lower part of the domal structures is composed mainly of foraminiferal–algal–echinodermal packstones. The upper part is characterized by foraminiferal–algal–echinodermal packstones with intercalated microbialite–coral boundstones. The euphotic inner ramp deposits are preserved on the crest of the domal structure, consisting of grainstone and packstone rich in Glomalveolina. As a result of this study, the Intisar domal structures are seen as erosional relics of a carbonate ramp and no evidence for pinnacle reef/bioherm model was found.

Analysis of hydrocarbon under-filled and water-filled Miocene deepwater reservoirs, eastern Mexico offshore

Hydrocarbon exploration in the deepwater portion of the southwestern Gulf of Mexico commenced a decade ago, but discoveries have not been able to meet the optimistic expectations based on historical success in the northern Gulf of Mexico. Despite the existence of organic-rich source rocks and high-quality Miocene reservoir rocks, there is a concern that the lack of significant hydrocarbon accumulations in some prominent traps in the northern Catemaco fold belt (Veracruz Trough) resulted from an ineffective sealing and/or trapping mechanism.By integrating drill core, 3D seismic, and well data provided by the Mexican National Hydrocarbon Commission (CNH), this paper attempts to evaluate the cause of hydrocarbon under-filled or water-filled Miocene traps within the Veracruz Trough, using the prominent structural closures drilled by Pemex-operated Kunah-1 and Yoka-1 deepwater wells as case studies. Three hypotheses are considered and analyzed for these two large traps: top seal leakage, existence of unmapped shallow spill points, and late trap formation relative to timing of hydrocarbon generation and migration.Seal rock leakage analyses, which involves downhole pressure data analysis and mercury injection capillary pressure laboratory measurements on cuttings, suggest that many of the evaluated intra reservoir and top seal rocks could have held significantly taller hydrocarbon columns than encountered by the wells. In addition, 3D seismic structural interpretation around the Yoka trap indicates that all mapped spill points are much deeper than the observed fluid contacts. However, the trap formation timing assessment shows that by the time the traps began to develop, the main oil generation phases had largely concluded, and gas generation was at a very late stage for the most prominent source rocks. Consequently, a more robust explanation for the Kunah and Yoka under-filled and water-filled structures is due to a timing mismatch, with late trap formation relative to an earlier hydrocarbon charge.

Sealing potential of contourite drifts in deep-water fold and thrust belts: Examples from the Hikurangi Margin, New Zealand

Contourite drifts form an important component of many deep-water sedimentary systems. Although their role as reservoirs, particularly along passive margins, is recognised, their sealing potential has been relatively understudied, especially along convergent margins. A range of contourite drifts has recently been recognised along the Hikurangi subduction margin, off the east coast of the North Island of New Zealand. Those occurring in shallower depths comprise giant elongate mounded and plastered drifts; they are mud-rich and blanket the crests and flanks of thrust-cored ridges. These drifts may seal reservoirs that principally comprise the turbiditic component of deformed trench-slope basin fill that was deposited adjacent to the ridges. The locations of modern hydrocarbon seeps appear to confirm the sealing potential of these drifts, which could trap significant hydrocarbon accumulations. The faults that underpin the ridges appear to act as primary charge pathways. Because the drifts are documented to drape the crests and flanks of the structural highs against which the reservoirs pinch out, there is a specific spatial and structural correspondence between seal, reservoir and charge pathways in this location. Such an association could be of broader economic significance if developed in convergent settings elsewhere.

Introduction to this special section: Southeast Asia

This special section on Southeast Asia features geophysical topics that cover several of the magnificent geotectonic provinces of the region. Southeast Asia is the site of the world's largest archipelago, which features more than 20,000 islands extending east to west more than 3500 miles. The extent of the offshore regions of the archipelago is many times greater than its land area. The Sunda Shelf, with its numerous Tertiary basins in the western part of the archipelago, contains areas of India, Myanmar, Thailand, Laos, Cambodia, Vietnam, Malaysia, Singapore, the Philippines, Brunei, West Indonesia, and their offshore regions that extend from the Andaman Sea to the Makassar Strait. By contrast, eastern Sunda, with its pre-Tertiary basins, embraces the islands along and north of the Banda Arc, from Sulawesi to western Papua in Indonesia and Timor-Leste and surrounding seas ( Figure 1 ). The most distinguishing tectonic features of the archipelago are related to the collision of the Indo-Australian Plate with the Sunda Shelf and the areas east of it. Numerous volcanoes and earthquake epicenters trace an extensive arc of collision-related subduction zones, which makes this one of the most tectonically active regions in the world. Back-arc and other basins within the stable parts of the Sunda Shelf are the sites of significant hydrocarbon accumulation, primarily within the territorial boundaries of Indonesia and Malaysia.

STRATIGRAPHIC FRAMEWORK AND PETROLEUM GEOCHEMISTRY OLIGOCENE SOURCE ROCKS, NORTHERN SONG HONG BASIN

The lacustrine oil-prone organic-rich mudstones in the Oligocene are the most important source rocks which have contributed to generate significant hydrocarbon accumulations in the northern Song Hong basin but still poor understanding due to the limitation of data. Newly c. 800km2 3D seismic data and well data allows investigating the stratigraphy and geochemistry of the northern Song Hong basin in detail to define the stratigraphic framework and hydrocarbon potential. The area is characterized by three relatively elongate grabens which are separated by the northeast-southwest basement faults. The most completed synrift sequence is observed in the central graben and is divided into three distinct sections, lower section (Ol), middle (Om) and upper (Ou), corresponding to three phases defined by tectonic systems tracts, from rift initiation to rift development and finally fill up phase. Uplift at the end of Oligocene has strongly modified the syn-rift sequences, resulting in folding, reactivated some basement faults and generated a series of new EW trending faults which may act as potential structural traps in the area. Organic geochemical analysis of the lacustrine mudstone samples from Ol and Om section of well D-1X shows fair to high organic carbon contents, Total Organic Carbon (TOC) 0.51 - 4.86 wt% and Hydrogen Index (HI) 273 - 552 mg HC/g TOC, corresponding to the type II kerogen. Biomarkers indicate the contribution of algal, high land plant, and bacterial sources to the composition of organic matters. Organic matters were deposited in the less oxic environment, in the fresh-water to brackish marine influence.

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA, NORTHERN SOMALIA, PART 2: HYDROCARBON POTENTIAL

Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (∼35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates.ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting.The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN, NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations.In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded.In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations.Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.

Challenge of Water Saturation in Low Resistivity Cretaceous Reservoirs

This study presents causes and reasons for lowering resistivity logs in carbonate deposit. Moreover this abstract elucidate methods for relieving of challenge water saturation estimation in cretaceous carbonate deposits with Low Resistivity Pay, in Persian Gulf. Reservoirs in the Cretaceous like Zubair, Buwaib, Shuaiba and Khatiyah formations of Southern fields have been analyzed as low resistivity carbonate. Resistivity responses reach less than 6 and even less than 1 ohm.m. Significant hydrocarbon accumulations are “hidden” these Pay zone, (LRPZ). Experimental analysis shows that reservoirs contain clay-coated grains of Lithocodyum algal and is along with Micrtization, Pyritization of digenetic process are reasons for effect on resistivity response. On the other side Smectite and Kaolinite of main clays types have high CEC and greater impact on lowering resistivity. Lønøy method applied to address pore throat sizes which contain Inter crystalline porosity, Chalky Limestone, Mudstone micro porosity. NMR (Nuclear magnetic resonance and Pulse Neutron-Neutron logs have been used to modify the calculated water saturation of the wells. The study shows that reduced specific resistivity is due to texture change and presence of microscopic porosity. For defining reliable water saturation, Core NMR and Log NMR results have been used. NMR results explain that decreasing of resistivity in pay zone is related to texture and grain size variation not being existence of moved water. Irreducible water for the reservoirs is estimated between 30 to 50 %. Low resistivity zone related to microspores with less than 3 micron. Variable T2 cut off is allows to choice suitable T2 cut off values to differentiate movable from bound fluids adapted for the specific carbonate rock. T2 cut off varies between 45 to 110ms. The proper T2 cut off for these formations are extremely crucial to being able to estimate permeability and water saturation.

Source rock characterization of mesozoic to cenozoic organic matter rich marls and shales of the Eratosthenes Seamount, Eastern Mediterranean Sea

Several significant hydrocarbon accumulations were discovered over the past decade in the Levant Basin, Eastern Mediterranean Sea. Onshore studies have investigated potential source rock intervals to the east and south of the Levant Basin, whereas its offshore western margin is still relatively underexplored. Only a few cores were recovered from four boreholes offshore southern Cyprus by the Ocean Drilling Program (ODP) during the drilling campaign Leg 160 in 1995. These wells transect the Eratosthenes Seamount, a drowned bathymetric high, and recovered a thick sequence of both pre- and post-Messinian sedimentary rocks, containing mainly marine marls and shales. In this study, 122 core samples of Late Cretaceous to Messinian age were analyzed in order to identify organic-matter-rich intervals and to determine their depositional environment as well as their source rock potential and thermal maturity. Both Total Organic and Inorganic Carbon (TOC, TIC) analyses as well as Rock-Eval pyrolysis were firstly performed for the complete set of samples whereas Total Sulfur (TS) analysis was only carried out on samples containing significant amount of organic matter (>0.3 wt.% TOC). Based on the Rock-Eval results, eight samples were selected for organic petrographic investigations and twelve samples for analysis of major aliphatic hydrocarbon compounds. The organic content is highly variable in the analyzed samples (0–9.3 wt.%). TS/TOC as well as several biomarker ratios (e.g.Pr/Ph < 2) indicate a deposition under dysoxic conditions for the organic matter-rich sections, which were probably reached during sporadically active upwelling periods. Results prove potential oil prone Type II kerogen source rock intervals of fair to very good quality being present in Turonian to Coniacian (average: TOC = 0.93 wt.%, HI = 319 mg HC/g TOC) and in Bartonian to Priabonian (average: TOC = 4.8 wt.%, HI = 469 mg HC/g TOC) intervals. A precise determination of the actual source rock thickness is prevented by low core recovery rates for the respective intervals. All analyzed samples are immature to early mature. However, the presence of deeper buried, thermally mature source rocks and hydrocarbon migration is indicated by the observation of solid bitumen impregnation in one Upper Cretaceous and in one Lower Eocene sample.

Reservoir Characterization and Pore Type Systems of Carbonate Low Resistivity Pay in Persian Gulf

The main focus of study is to characterize lower and upper cretaceous carbonate deposits with Low Resistivity Pay, in Persian Gulf. Four oil reservoirs in the Cretaceous including the Zubair, Buwaib, Shuaiba and Khatiyah Formations of Southern fields have been analyzed. Here is a look at that to determine main factors on decreasing resistivity in pay zone. In some intervals resistivity responses reach less than 6 to 1 ohm·m. Significant hydrocarbon accumulations are “hidden” in low resistivity Pay zone, (LRPZ). LRPZ reservoirs have been found in some formations in Persian Gulf. Causes of LRPZ reservoirs on the basis of experimental analysis include clay-coated grains, carbonate with interstitial dispersed clay. On the other side Smectite and Kaolinite of main clays types have high CEC and greater impact on lowering resistivity. Micritization and Pyritization of digenetic process have noticeable impact on LRPZ. It is mentioned that Lonoy method applied to address pore throat sizes which contain Inter crystalline porosity, Chalky Limestone, Mudstone micro porosity. Pore systems are classified at class 2 and 3 Lucia and pore size varies from 0.5 to 4 micron. NMR Core and Log results show different pore size distribution. NMR core and MRIL results explain that decreasing of resistivity in pay zone is related to texture and grain size variation not being existence of moved water. Irreducible water estimate for this reservoir was between 30% and 50%. T2 cut off estimates, for defining irreducible water saturation, 115 ms.

Deep‐water continental margins: geological and economic frontiers

AbstractDeep‐water margins have been the focus of considerable research during the past decade. They comprise vast, underexplored regions, in which only recently have improvements in seismic imaging and drilling technology allowed the discovery of significant hydrocarbon accumulations. This volume comprises of a series of manuscripts based on studies from continental margins bordering India, East Africa, Australia, China, Norway, the United Kingdom, Iberia, Newfoundland, the southern US, West Africa and Brazil, thus offering a global perspective on the evolution and economic significance of deep‐water margins. The articles in this volume examine: (i) the quantification of extension and hyperextension in distal parts of continental margins, and their relationship with regional subsidence, (ii) the importance of magmatism in the structural and thermal evolution of rifted continental margins, (iii) the processes driving and the significance of regional exhumation during and after syn‐rift stretching, (iv) the tectonic setting of salt basins and (v) depositional patterns along deep‐water margins. To complement this work, we present a personal view of some of the specific questions that need to be addressed in the next few years of deep‐water continental margin research.

Role of the tectonomagmatic factor in formation of giant hydrocarbon accumulations in the East Barents basin

In terms of tectonics, the East Barents basin(megabasin) represents an extended (~1400 km)wedgeshaped ~500 to 300kmwide structure thatcrosses the West Arctic continental–marginal platform in the meridional direction and is truncated by asystem of pericratonic depressions of the East European Platform on the beam of the Kola Peninsula.According to geological–geophysical data, the Paleozoic–Mesozoic sedimentary cover of the basin is presumably >20 km thick [11, 13], although its exactthickness is unknown so far. Approximately 14 km ofthe sedimentary section are represented by Upper Permian–Mesozoic terrigenous sediments, 11 km ofwhich correspond to the Upper Permian–Triassicsequence. The underlying Paleozoic complex is composed of terrigenous–carbonate and carbonate facies.In the opinion of many researchers, such a giantsize of the basin and its sedimentary prism implydevelopment of significant hydrocarbon accumulations in the latter. These assumptions are confirmed bythe discovery of five hydrocarbon fields in the southernhalf of the megabasin (Fig. 1); they are representedonly by gas and gas condensate accumulations confined to Mesozoic sedimentary complexes [2–4, 8, 9,12, 13, 15, and others].Two gas fields (large Murmanskoe and mediumSeveroKil’dinskoe) are located in the southwesternperipheral part of the South Barents Basin in its slopeand nearslope zones, where productive formationsare represented by Triassic sediments.Another group of accumulations associate with thesocalled Shtokman–Lunin Sill (Uplift) [2–4], whichseparates the South and North Barents basins. Withrespect to hydrocarbon reserves, the Shtokman andLedovoe gas condensate and Ludlovskoe gas fieldswith Jurassic productive formations are classed withunique and large categories, respectively.For hydrocarbon accumulations of both groups,source formations are considered to be represented byPermian–Triassic sediments; in the last case, theyprobably also include Lower Jurassic sediments withhumic and sapropelic organic matter.With respect to the economic potential and geological prerequisites for further searches for analogs andspecifying the factors responsible for their formation,of particular interest is the second group of hydrocarbon accumulations confined to the elevated boundaryzone between the two basins (Fig. 1). These problemsare considered in several publications [1–4, 9, 15],where factors responsible for the formation of suchgiant hydrocarbon accumulations are characterized bya different degree of substantiation and from differentstandpoints.In this connection the following question arises:what are the peculiar features that determine the geological structure of hydrocarbon fields in the Shtokman–Lunin Uplift?It should primarily be noted that all the local anticlinal trap structures hosting hydrocarbon accumulations are distinctly reflected in Triassic and Cretaceoussediments as well as in the surface topography of Jurassic sequences with an amplitude of approximately100–200 m (seismic reflector B, Fig. 1). They are isometric in plan and from 500 to 1500 km

Emerging Sensing Technologies For Hydrocarbons and their Potential use as Exploration Devices

Australian waters contain a number of under-explored offshore sedimentary basins, which have or could have significant hydrocarbon accumulations. Current exploration strategies are based primarily upon seismic data acquisition, with other data type acquisition, (e.g. geochemical sampling) requiring further survey cruises. This multiple survey strategy significantly increases exploration costs leading to tough decisions being made upon which surveys to perform when exploration budgets are tight. The attraction of using a single cruise to achieve multiple surveys is therefore of interest in reducing costs and increasing the impact of each exploration dollar.

Abstract: Joint Systems Along the Northeast Margin of the Mississippi Interior Salt Basin, Alabama 

ABSTRACT Joints are commonly overlooked structures in Mesozoic-Cenozoic strata of the eastern Gulf Coast basin, yet significant hydrocarbon accumulations are in fractured and conventional reservoirs in this area. Two orthogonal joint systems are developed in Cenozoic strata along the northeastern margin of the Mississippi interior salt basin. System 1 joints strike subparallel to salt-related faults and fold axes. System 2 joints strike parallel to many modern hillslopes and appear to postdate regional faulting. System 2 joints apparently are forming in response to neotectonic stresses associated with regional unroofing and valley incision and probably do not extend downward to reservoir depths (~1,000 to 4,000 m). Orientation data suggest that system 1 joints formed in the same regional stress field as the salt-related faults. Therefore, system 1 joints and cross joints are predicted to exist at reservoir depths where they may form permeability pathways affecting hydrocarbon recovery.

Foreland Basement-Involved Structures

Basement-involved structures commonly occur as long, irregular chains of uplifts in foreland basins. These structures commonly contain significant hydrocarbon accumulations, with most major fields located on the broad crests of these structures. The search for complex traps in deeper targets and in subthrust structures requires an improved understanding of the geometry and evolution of these structures. Characteristic features of basement structures include deformation zones within the sedimentary cover that dissipate significant fault slip, and gently dipping frontlimbs and backlimbs. Fault slip in the basement is usually accommodated in the cover by a triangular, widening-upward deformation zone on the forelimb, with the nature of deformation controlled primarily by the mechanical stratigraphy. If the cover contains interlayered competent and incompetent units, the incompetent units are characterized by significant penetrative deformation, whereas the competent units are faulted after a relatively small amount of penetrative deformation. Depending on the competency contrast between the basement and cover, the nature of basement, and the physical conditions of deformation, the deformation zone may also propagate downward into the basement. Gently dipping backlimb and frontlimb panels are related to movement of the hanging wall over synclinal and anticlinal bends in the major fault, respectively. Many basement faults are characterized by a number of synclinal fault bends within the basement, which result in long and gently dipping backlimbs. Forelimb panels are related to anticlinal bends that typically occur at the basement-cover interface, as well as at one or more locations in the sedimentary cover. Case studies of well-constrained examples of structures from the Bighorn and Uinta basins and the Central Basin platform, demonstrate the development of these characteristic features and their strong dependence on the mechanical stratigraphy. These models and case studies will be useful in interpreting foreland basement structures in areas with poor or limited data.

Natural recession of the eastern margin of the Leofnard salt in western Canada

The Lloydminster area (T35-65, R15W3M-10W4M) of east‐central Alberta and west‐central Saskatchewan, Canada, is dissected by the north‐northwest trending updip active dissolution margin, of the Devonian Leofnard Member rock salt. West of this margin, up to 150 m of rock salt is preserved; updip and to the east, the salt has mostly been leached from the rock record. The margin is up to 40 km wide and characterized by extreme local variations in net salt thickness. The dissolution of the Leofnard rock salt in the Lloydminster area has resulted in the entrapment of significant hydrocarbon accumulation. Stratigraphic traps, for example, have formed where reservoir facies were either preferentially deposited or preserved in salt‐dissolution lows. Structural traps, in contrast, have formed where reservoir facies are draped across residual salt or collapse features. It has been estimated that three trillion barrels of oil (mostly of high viscosity and unrecoverable) are entrapped along the eastern dissolution margin of the Leofnard rock salt in western Canada. A record of the westward progression of the dissolutional edge of the Leofnard salt is locked in the stratigraphic column. This progression is recorded as localized interval thickening in areas where dissolution and deposition were contemporaneous. The horizontal positioning of these interval thicks as a function of their geologic age provides a time record for the positioning of the salt edge. To further explain the process of salt dissolution in the Lloydminster area, we present a suite of contour maps, geologic cross‐sections, and seismic profiles. These data depict the present‐day distribution of the Leofnard salt in the Lloydminster study area. They support the theses that: (1) the dissolution margin of the Leofnard rock salt originated along the Elk Point outcrop to the east of the study area during the pre‐Cretaceous; and (2) the margin receded into the northeastern part of the Lloydminster study area during earliest Cretaceous or pre‐Cretaceous time and migrated progressively thereafter into its current position. From the perspective of the explorationist, such information is important because it identifies prospective play areas with high potential for the formation of salt‐related stratigraphic traps and/or structural traps.