Anticlinal Structure Research Articles

Upper Cenomanian-Lower Campanian Derdere and Karababa formations in the Çemberlitaş oil field, southeastern Turkey: their microfacies analyses, depositional environments, and sequence stratigraphy

The frontal belt of the southeastern Anatolia fold-thrust belt in Turkey contains several small to mid-size oilfields, producing from carbonate reservoirs of the Cretaceous Mardin group. Many of these fields are found along narrow, asymmetrical anticlinal structures, associated with the formation of the fold-thrust belt. The Cemberlitas oil field in Adiyaman, southeastern Turkey, is one of the most important oilfields in the region. It produces from the Upper Cretaceous Derdere and Karababa formations of the Mardin group. We have conducted a detailed study of the microfacies, depositional environments, and sequence stratigraphy of the Karababa (Coniacian-lower Campanian) and Derdere (mid-Cenomanian-Turonian) formations in the oil field. Eight microfacies in the Karababa and Derdere formations have been identified; the microfacies in the Karababa formation are 1) mollusk-echinoid wackestone/packstone, 2) dolomitic planktonic foraminifera wackestone, 3) planktonic foraminifera bearing wackestone/packstone, and 4) phosphatic-glauconitic planktonic foraminifera bearing wackestone. The microfacies in the Derdere formation are 5) lime mudstone, 6) bioclastic wackestone/packstone, 7) medium-coarse crystalline dolomite, and 8) fine crystalline dolomite. These microfacies suggest that the Derdere formation was deposited in lagoonal to shelf depositional environments and the Karababa formation was deposited in a deep to shallow marine intrashelf basin. Two third-order sequence boundaries of late Turonian and early Campanian in age have been recognized in the reservoir interval. Depositional sequences contain transgressive and highstand systems tracts. These sequences are compared with those in other regions to differentiate the local, regional, and global factors that controlled sedimentation within the Cemberlitas oil field area.

Wide Line Seismic Acquisition Technique in a Hilly Terrain of Onshore Myanmar

Myanmar's onshore block EP-2 is a small exploration concession with high potential structures located on the eastern side of the Irrawaddy River. One of the major anticlinal structures can be mapped based on surface geological survey, but the recent 2D seismic data has extremely poor quality due to a severe static and strong side scattered noise. Although the size of this prospect is attractive, the subsurface uncertainties are considered too risky for further drilling operation. An alternative acquisition technique called 2D-wide line was firstly implemented in Myanmar. Its results provide better stack sections, more reliable velocity function and higher geological probability of success.

Paleofluid Evolution In Fault-Damage Zones: Evidence From Fault–Fold Interaction Events In the Jabal Qusaybah Anticline (Adam Foothills, North Oman)

Abstract Fault zones are known to play a key role in controlling fluid migration, including hydrocarbons, at local and regional scales. In this contribution physicochemical data from veins are used to document the extent and maintenance of fluid conductivity associated with fault-damage zones in an anticlinal structure occurring in the frontal part of a foreland fold and thrust belt. Migration of fluids during major deformational events has been recorded by several generations of calcite and localized dolomite cementation in veins in marine Cretaceous carbonates of the Jabal Qusaybah Anticline (North Oman). Applying detailed petrographic and paragenetic relations, geochemical analysis (stable carbon and oxygen isotopes, strontium isotopes, and trace elements), and microthermometry, coupled with structural studies of fault zones and associated calcite veins, made it possible to link fluid circulation to the structural evolution of the Jabal Qusaybah Anticline. Based on the structural framework and fault systems, three groups of veins were distinguished. Group 1 veins are interpreted to be linked to burial and early-tectonic deformation in association with E–W extensional fault zones. Calcite cementation in this group occurred in a closed to semiclosed fluid system, which originated as a result of intraformational fluid movement along a low-connectivity fracture network. The δ13C values of these veins range from 3‰ to 3.5‰, and δ18O values vary from –10.3 to –8.1‰ V-PDB. Group 2 veins are related to syntectonic deformation along NE–SW strike–slip and incipient N–S extensional faults linked to culmination of the Jabal Qusaybah Anticline. From this stage onward, fluids correspond to progressive fault connectivity and dilation related to interaction of fault–folding systems. The cements precipitated during this stage have more variable δ13C values ranging from 0.9 to 3.2‰ and possess a wide range of δ18O values varying between –11.2 and 0.3‰ V-PDB. The cements in Group 2 veins originated from fluids characterized by a relatively broad range of precipitation temperature (75–107°C) and salinities evolving from seawater to moderately saline fluids (3.4–12.8 eq. wt% NaCl), with H2O–NaCl composition. The source of salinity is inferred to be evaporitic brines that originated from the Ara Group, and the large range of salinity is interpreted as the result of mixing between those brines and modified seawater. Group 3 veins are considered to be related to late–tectonic deformation corresponding to late fold amplification of the anticline hinge, transition from NE–SW left-lateral strike–slip to N–S extensional faulting, progressive regional and local uplift, and exhumation. Stable-isotope data support the occurrence of bacterial methanogenesis or CO2 degassing at the end of this stage. Their associated cements are characterized by higher δ13C and δ18O values compared to other groups of veins, ranging from 0.6 to 8.0‰ and –3.6 to 1.5‰ V-PDB, respectively. Fluids responsible for calcite precipitation in this group evolved from a moderate saline to a more saline (8.5–16 eq. wt. % NaCl) H2O–NaCl–CaCl2 brine. The progressive 18O enrichment relative to seawater and preceding cements and its covariation with fluid salinity in the later stage suggest the higher contribution of the evaporitic brines. This hypothesis is further supported by the increase in their 87Sr/86Sr ratios compared to both middle to Upper Cretaceous marine carbonates and other groups of veins. Although during this episode calcite cementation occurred at temperatures below 50°C, their geochemical signatures reveal that the faults were sufficiently conductive to transfer extraformational fluids late in the deformation history of this structure. The interference between strike-slip and extensional fault systems and their interaction with fold amplification is invoked to be responsible for enhanced conductivity in fault-damage zones.

New ideas on the tectonic of the Kurveleshi anticlinal belt in Albania, and the perspective for exploration in its subthrust

Abstract The external thrustbelt of Albania consists of some tectonic zones (Ionian, Kruja and Krasta-Cukali zones), that are westward overthrust, with a large amplitude (50–100 km), above the Apulian platform and South Adriatic Basin. The relative movement of the Adriatico-Apulian sub-plate between, the Euro Asiatic and African plates during from the Mesozoic to the Tertiary period, mainly controlled the tectonic evolution of the Albanides. The Ionian zone consists of anticline belts (Berati, Kurveleshi and Cika), that are overthrust toward the west with an amplitude about 20–30 km Their overthrustings was realized through regional sliding evaporitic horizons, which caused the masking of folded structures in the subthrust, with the perspective plays. The Kurveleshi anticlinal belt represents a mega-anticlinal with a length of 210 km and a width of about 20 km, and it is characterized by anticline structures with heterogeneous dimensions, predominantly those of great dimensions and linear type. The overthrusting of the anticline units has a local character, and it is more developed in the Kurveleshi anticlinal belt. Its magnitude is about 8–10 km. As a result of these overthrusts, imbrication and duplex styles are formed, leadind to the masking of the subthrust complex with structures of large interest (e.g. Delvina, Karbunara, etc.) where two oil fields have been dioscovered beneath the Mali Gjere anticline (Delvina oil field) and the Kremenara anticline (Karbunara oil field). Backthrust faults phenomena are secondary and they taken place in the post-collision stage. Generally they are easterward thrust faults of structural units with an amplitude of 5–10 km. The Kurveleshi anticlinal belt, based on tectonic features, is divided into two parts: The southern part, from Qafa Sevaster in the north down to Greece to the south. and northern part, from Qafa Sevaster in the south up to the end of the Patos-Verbas structure. In the southern part these features predominate: The anticline structures are large in size, and overthrust with a large amplitude (8–10 km) westward. The evaporitic diapirs have erupted through local faults of the anticline structures of the Kurveleshi anticlinal belt (Mali Gjere, Kurveleshi and Fterra anticlines). These eruptions (Delvina, Picar-Kapariel-Bashaj, etc.) have helped in the overthrusting of these structural units. It must be mentioned that the backthrusting is also affected by the diapir action. Moreover, vertical diapir occur, in the center of the structures like Navarica. In the northern part, the anticline structures are generally small to medium in size. Only the Patos-Verbas anticline is larger in size. In the Kurveleshi anticlinal belt the Ballsh and Visoka oilfields have developed. The eastern flank of the Shushica synclinal belt apears folded, and the carbonate anticline structures have developed. Existing oil fields include the Gorisht-Kocul, Cakran-Moallaj-Kreshpan and Amonica. These oil fields shoud continue towards the north (under the overthrust of the Patos-Verbas antcline) and in the south (under the regional ovethrust of the Kuervelesh anticlinal belt).

Impact of inversion tectonics on hydrocarbon entrapment in the Baggara Basin, western Sudan

The Baggara Basin of Sudan is an ENE-WSW trending basin located within the West and Central Africa Rift System (WCARS) and NW of the Muglad Basin. The trend of the Baggara Basin is similar to other basins in eastern Chad, where oil has been discovered. Since there are no published studies for the Baggara Basin, the present paper represents an addition to the geology of eastern extension of the WCARS in Sudan. The 2D seismic data interpretation sheds light on the development and evolution of key regional and local structures of the basin. The Baggara Basin is characterized by graben geometry with two boundary faults, characterized by dextral strike slip movement, and a depocenter at the central part. The interpretation reveals the presence of two types of structures within the Baggara Basin; inversion tectonics restricted to the larger basin-bounding faults in the western part and en-echelon faults in the central part. The timing of inversion tectonics is during the Eocene and it is related to a brief major compressional event due to the collision of the African and Eurasian plates. Although the inversion created a four-way dip closed anticline structure, this anticline postdated the initial migration from the source rock. Accordingly, the anticline structural is unsuccessful for hydrocarbon entrapment.

Structural Evolution and Hydrocarbon Potential of the Upper Paleozoic Northern Ordos Basin, North China

AbstractThe hydrocarbon potential of the Hangjinqi area in the northern Ordos Basin is not well known, compared to the other areas of the basin, despite its substantial petroleum system. Restoration of a depth‐converted seismic profile across the Hangjinqi Fault Zone (HFZ) in the eastern Hangjinqi area shows one compression that created anticlinal structures in the Late Triassic, and two extensions in ∼Middle Jurassic and Late Early Cretaceous, which were interrupted by inversions in the Late Jurassic–Early Early Cretaceous and Late Cretaceous, respectively. Hydrocarbon generation at the well locations in the Central Ordos Basin (COB) began in the Late Triassic. Basin modeling of Well Zhao‐4 suggests that hydrocarbon generation from the Late Carboniferous–Early Permian coal measures of the northern Shanbei Slope peaked in the Early Cretaceous, predating the inversion in the Late Cretaceous. Most source rocks in the Shanbei Slope passed the main gas‐migration phase except for the Hangjinqi area source rocks (Well Jin‐48). Hydrocarbons generated from the COB are likely to have migrated northward toward the anticlinal structures and traps along the HFZ because the basin‐fill strata are dipping south. Faulting that continued during the extensional phase (Late Early Cretaceous) of the Hangjinqi area probably acted as conduits for the migration of hydrocarbons. Thus, the anticlinal structures and associated traps to the north of the HFZ might have trapped hydrocarbons that were charged from the Late Carboniferous–Early Permian coal measures in the COB since the Middle Jurassic.

Genesis of the vein-type tungsten mineralization at Nyakabingo (Rwanda) in the Karagwe–Ankole belt, Central Africa

The vein-type tungsten deposit at Nyakabingo in the central Tungsten belt of Rwanda is located in the eastern flank of the complex Bumbogo anticlinal structure. The host rock is composed of alternating sequences of sandstones, quartzites, and black pyritiferous metapelitic rocks. Two types of W-mineralized quartz veins have been observed: bedding-parallel and quartz veins that are at high angle to the bedding, which are termed crosscutting veins. Both vein types have been interpreted to have been formed in a late stage of a compressional deformation event. Both vein types are associated with small alteration zones, comprising silicification, tourmalinization, and muscovitization. Dating of muscovite crystals at the border of the veins resulted in a maximum age of 992.4 ± 1.5 Ma. This age is within error similar to the ages obtained for the specialized G4 granites (i.e., 986 ± 10 Ma). The W-bearing minerals formed during two different phases. The first phase is characterized by scheelite and massive wolframite, while the second phase is formed by ferberite pseudomorphs after scheelite. These minerals occur late in the evolution of the massive quartz veins, sometimes even in fractures that crosscut the veins. The ore minerals precipitated from a H2O–CO2–CH4–N2–NaCl–(KCl) fluid with low to moderate salinity (0.6–13.8 eq. wt% NaCl), and minimal trapping temperatures between 247 and 344 °C. The quartz veins have been crosscut by sulfide-rich veins. Based on the similar setting, mineralogy, stable isotope, and fluid composition, it is considered that both types of W-mineralized quartz veins formed during the same mineralizing event. Given the overlap in age between the G4 granites and the mineralized quartz veins, and the typical association of the W deposits in Rwanda, but also worldwide, with granite intrusions, W originated from the geochemically specialized G4 granites. Intense water–rock interaction and mixing with metamorphic fluids largely overprinted the original magmatic-hydrothermal signature.

Precambrian–Pleistocene tectno-stratigraphic evolution of the southern Llanos basin, Colombia

The Llanos basin, located in the eastern region of Colombia, northwestern South America, is an Andean foreland basin between the Eastern Cordillera (Colombian Andes) and the Guyana Precambrian shield. The basin is the latest stage of a complex multiphase evolution that began in the Paleozoic at the latest. A Paleozoic–Pleistocene basin evolution model is presented based on a regional, two-dimensional, industry seismic data set and well-log observations for the southern part of the basin. Five tectono-stratigraphic sequences were identified: (1) lower Paleozoic depocenters preserved along inverted Neoproterozoic basement blocks; (2) an upper Paleozoic marine sequence folded and faulted in the late Paleozoic during assembly of Pangea; (3) Upper Cretaceous–Paleocene shallow marine sediments deposited in a distal foreland basin related to uplift of the Western and Central Cordilleras of Colombia, the sequence pinches out against a Paleozoic hinge or foreland bulge area; (4) an Eocene–Miocene foreland basin related to uplift of the Eastern Cordillera resulting in a wedge geometry; and (5) Pliocene–Pleistocene fluvial deltaic rocks overfilling the foreland basin. Reactivation of Paleozoic structures occurs at the top of this sequence with the development of anticlinal structures. Present-day stress fields indicate that subduction of the Nazca plate beneath South America may be responsible for reactivation of Paleozoic structures. Inversion of north–south structures with the Neoproterozoic basement is interpreted to be responsible for the Paleozoic and Pleistocene deformation, whereas Cenozoic deformation is related to the two main stages of foreland development of the basin. To the east, where the Paleoproterozoic basement is present, no deformation is interpreted.

Local pressure lows as possible sinks of fluids in geologic structures

Local pressure lows in layered sections perturbed by anticlinal structures are studied analytically using equations for pressure change across interfaces. They are simple equations of pressure difference for low-angle structures and boundary integral equations for steeply dipping anticlines. Pressure may decrease locally near the crests of anticlines, as well as away from them at distances commensurate to the anticline height. Predicting stress patterns, which are specific for different groups of geologic structures, is a difficult task. However, some components of the stress field, such as low-pressure zones which may act as sinks for fluids, are relatively easy to constrain. Stress in these zones depends on the dip of anticlines and their curvature at each surface point. Negative curvature causes additional lateral extension and promotes further decrease of overburden pressure around the crests.

Production Optimization With Artificial-Lift ESP Pilot Systems in a Mature Oil Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171917, “Production Optimization Over 20% With Artificial-Lift ESP Pilot Systems in Mature Oil Field: Case Study From Middle East,” by Hector Aguilar, Aref Ali Al Marzooqi, Tarek Mohamed El Sonbaty, and Leigber Villarreal, ADCO, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. A production-optimization strategy of an artificial-lift system resulted in the mitigation of challenges related to reservoir heterogeneities and completion design. An approach integrating reservoir dynamic data and electrical-submersible-pump (ESP) performance was established as a guideline for ESP surveillance and diagnostics and for targeting candidates for production optimization by implementing at least one of the possible solutions: upgrading ESP surface equipment, anticipating workovers for ESP-resizing and -deepening jobs, and reviewing well-design strategy. Introduction The field is an anticlinal structure 26 km long and 6 km wide with two main complex carbonate reservoirs, upper (U1) and lower (U2), exhibiting considerable lateral and vertical lithological changes and, consequently, variations of reservoir properties. Oil production started in 1983 through an initial-development phase. An artificial-lift project using ESP systems was implemented in 1994 to increase and sustain oil production. All producer wells are equipped with an ESP, a Y-tool, and a single completion string. All wells completed before 2014 have been operated on a fixed frequency of 50 Hz through switchboard (SWB) panels. A full-field development plan was reviewed to increase oil production by 40% by the end of 2013, to consider long-term sustainability in view of future expansion, and to stretch the target plateau beyond 2013. This target has been reached mainly by increasing the number of infill horizontal producer wells but also through the upgrading and expansion of surface facilities to handle increased volume of produced fluids. Optimization Strategy The asset team managing the field was presented with the challenge of increasing field production. An experienced project manager was assigned to lead a team representing different disciplines (development, engineering, operation, and ESP design and optimization) that cover all surface and subsurface aspects of the project. A detailed performance review was conducted per well for the entire field. It indicated that 27 wells were suitable candidates for potential production optimization, representing approximately 50% of the wells. The three well categories were defined as follows. Boost Production. This includes wells in which the ESP operates at a relatively high intake pressure. The only identified constraint has been the fixed frequency of 50 Hz delivered by the existing SWB panels. Reactivate Production. This includes wells that did not produce at stable flow rates or never produced because of shallow ESP settings. Sustain Production. This includes wells whose performance has been deteriorating because of backpressure or wells with increasing water cut. The optimization team has identified three possible optimization techniques to be evaluated and implemented in pilot wells on the basis of well category. Optimizing ESP Surface Equipment A methodology established priorities and qualified the best candidates to replace existing SWB panels with variablespeed drives (VSDs). The project was conducted in three phases. Phase I—Well Modeling. Wells were modeled through nodal-analysis software on the basis of historical production and actual performance data from recent available production tests to identify wells in which the backpressure effect becomes relevant and lifting capacity has deteriorated considerably. Phase II—VSD Trial Test Campaign. Three out of 27 wells were tested with VSDs by hooking up a portable power skid for a long-duration test.

Integrated petrophysical and geological characterization for the Sidi Salem-Wakar sandstones, off-shore Nile Delta, Egypt

The present work provides a preliminary study to clarify the geological setting and petrophysical potential of the offshore Temsah gas field, which is located as a NW–SE trending anticlinal structure. In the Temsah gas field, the main target is the Serravallian Sidi Salem sandstones while the second target is the Tortonian Wakar Formation. The Sidi Salem Formation produces gas and condensates from three main sand lobes, while Wakar Formation produces from some sand interbeds. The seismic velocity in Temsah gas field was a major problem due to the complexity of the structural and stratigraphic setting, and the existence of a strong pattern of multiples generated by the Rosetta evaporites at the top of the Miocene sequence. In the present study, an integrated interpretation was applied for the available well logs and the subsurface geological data as well as some available seismic sections.The highest hydrocarbon potential in the Sidi Salem sand lobes has been assigned for sand lobe III, which has the largest net pay thickness and the best petrophysical properties, particularly in the southern to the northern central wells across the crest of the structure. The basin depocenter extends along the central parts through Temsah-1, -2, -3 and -8 wells.The maximum average effective porosity values of the Sidi Salem reservoir were recorded in Temsah-5 and Temsah-1 wells (27% and 30%, respectively), to the northwestern and southeastern parts of the field at the crest of Temsah anticlinal structure, while the considerable porosity values of the Wakar reservoir were measured in the southern wells. Permeability of the Wakar reservoir increases with increasing porosity and decreases with increasing the water saturation, whereas for the Sidi Salem reservoir, permeability is dependent on porosity rather than the water saturation.The minimum average water saturation values for Sidi Salem and Wakar reservoirs were recorded in the central parts of the field (25% and 30%). The shale volume in both reservoirs is not effective (smaller than 13%).In general, the net oil column of Sidi Salem reservoir wells indicates a better reservoir quality for Temsah-1, Temsah-3, and Temsah-7 wells (the net pay varies in thickness from 48 to 69m) at the crest of Temsah anticlinal structure to the north and central west of the field; while for Wakar reservoir it indicates a better quality in Temsah-3 well (9.0m) to the north of the field.

OIL AND GAS IN THE ADRIATIC FORELAND, ITALY

The offshore Adriatic Basin holds more than 50% of Italian gas reserves together with significant volumes of oil. A number of large and giant‐size biogenic gasfields and medium to large oilfields have been discovered here during the past 60 years. Two petroleum systems have been identified: a Plio‐Pleistocene biogenic gas system, and an Upper Triassic – Lower Jurassic oil system. These systems are described in this paper within a regional geological framework, with particular focus on petroleum system elements (source, reservoir, seal, trap and charge). The biogenic gas play was for several decades the prime focus of Italian E&P efforts throughout the Adriatic area but is now mature, and significant additional discoveries are unlikely to be made without a breakthrough in DHI (direct hydrocarbon indicator) technology. The Mesozoic oil play is as yet unproved in the northern Adriatic area, where large anticlinal structures at depths of up to ca. 6000 m are available for exploration and constitute high‐risk – high‐reward targets. By contrast, the play is proved in the Central and Southern Adriatic where several oilfields are currently producing. Exploration targets still exist here and may generate medium‐sized discoveries although the prevalent heavy‐oil phase may jeopardize their economic value.

In-situ stress orientations in the UK Southern North Sea: Regional trends, deviations and detachment of the post-Zechstein stress field

The orientation of the maximum horizontal compressive stress (SHmax) in the UK Southern North Sea has been determined using data derived from borehole breakout analysis of four-arm caliper logs. The results agree with existing stress models for NW Europe, confirming that horizontal stresses in the region have an approximately NW–SE orientation of SHmax. This is interpreted as being a result of plate boundary convergence. Local deviations in the SHmax orientations are observed spatially and also vertically within some wells. Some of these deviations are attributed to rotations of the stress field adjacent to faults or between different fault blocks. The data also suggest detachment of the stress regime in the post-Permian cover rocks, caused by the presence of a thick underlying Permian-aged evaporite sequence and associated halokinesis. Analyses of borehole resistivity image logs have been used to verify the SHmax orientations in some wells. These image logs validate some of the stress indicators whilst highlighting a number of deficiencies in the use of four-arm caliper data to characterise borehole breakouts. From the available data it is difficult to unambiguously define the nature of variations from the mean SHmax orientations observed. Further analyses of image log data over greater depth-ranges are therefore required in order to investigate more fully the effects of stress rotations near faults and apparent stress detachment above salt-cored anticlinal structures.

Geomorphological approaching to the karst of the Sierra de la Utrera (Málaga province)

This paper present the main features of the karst of the Sierra de la Utrera (Costa del Sol Occidental, Málaga), a particular and unknown limestone outcrop with an anticline structure. This massif show very well the fracturing like a determinant factor, but not the only one, of it karstification, controlling the infiltration rates and many others geomorphological features at different scales. The aerial photography analysing shows a first geomorphological scheme of this unusual area. At the end we analysed the karst processes that determine the superficial and subterranean characteristic evolution. This converts the Sierra de la Utrera in a litological landscape with own identity.

The Hecataeus Rise, easternmost Mediterranean: A structural record of Miocene-Quaternary convergence and incipient continent-continent-collision at the African-Anatolian plate boundary

The Hecataeus Rise represents a plateau-like structure, adjacent to the southern Cyprus margin and directly next to the Cyprus – Eratosthenes Seamount convergence zone, where incipient continent-continent-collision is believed to occur. Based on newly acquired seismic reflection and bathymetric data, we report on the Miocene to Quaternary structural evolution of this yet underexplored sector along the African-Anatolian plate boundary. A period of pre-Messinian compression has significantly deformed the western and southern part of the plateau area. Offshore continuation of onshore Cyprus lineaments attests the existence of a pre-Messinian structural link between Cyprus and the Hecataeus Rise. Owing to its relatively elevated position during the Messinian Salinity Crisis, the Hecataeus Rise experienced wide-spread Messinian erosion and only local deposition of evaporites which were precipitated within small, isolated sub-basins. Post-Messinian convergence was accommodated along the southeastern flank of the Hecataeus Rise, where NE–SW trending anticlinal structures experienced reactivation and significant growth. A prominent intra-Pliocene-Quaternary unconformity in the northwestern part of the plateau area may correlate with the Pliocene–Pleistocene transition and indicates the near synchronous occurrence of several tectonostratigraphic events. We suggest that these events represent a chain of structural and depositional changes initiated by incipient collision of Eratosthenes Seamount with Cyprus and the northwestern corner of the Hecataeus Rise. Collision-derived uplift of Cyprus resulted in vertical separation between Cyprus and the Hecataeus Rise and the development of a prominent unconformity in the northwestern part of the plateau area. Increasing the slopes adjacent to Cyprus facilitated more energetic downslope sediment transport, expressed by the development of sediment waves and the evolution of a prominent canyon structure at the northeastern limit of the plateau area.

A MODEL OF TECTONIC STRUCTURE AND EVOLUTION OF THE ABU GHARADIG BASIN BASED ON NEW HYDROCARBON EXPLORATION RESULTS, WESTERN DESERT PROVINCE, EGYPT

Structural traps in the deep reservoirs of the Lower Cretaceous Kharita and Alam el Bueib as well as Middle Jurassic Khatatba formations are on the exploration agenda for the Abu Gharadig basin in the Western Desert petroleum province of Egypt. A new seismic and litho-stratigraphic interpretation made by SE Naukanaftogaz substantiates further development of hydrocarbon potential of the Alam El Shawish concession block operated by Petrosannan Co. (JV of EGPC and NJSC Naftogaz of Ukraine Overseas in A.R.E.). Recently acquired 3D seismic dataset, parametric analysis of seismic wave field to predict spatial development of improved reservoir properties combining with drilling, well-to-well correlation of strata and petrophysical rock parameters coupling with testing results have enabled to propose a new stratigraphic and tectonic model of the area studied that offers an upside exploration prospectivity for several deep structural traps related to pop-up and drape anticline structures derived from wrench faulting and local structural inversion of the Abu Gharadig basin.

The Fuling Shale Gas Field — A highly productive Silurian gas shale with high thermal maturity and complex evolution history, southeastern Sichuan Basin, China

The organic-rich Lower Silurian Longmaxi and Upper Ordovician Wufeng Shale (LSLUOWS) is one of the most important marine shale gas plays in southern China, with relatively high thermal maturity and complex structural evolution. The delineation of the Jiaoshiba shale gas play has been highly successful for the LSLUOWS in the Fuling area of southeastern Sichuan Basin. The drilling targets the basal part of the LSLUOWS, where the approximately 38–45 m of organic-rich (total organic carbon of greater than 2%) section corresponds to a maturity range around 2.2%–3.0% Ro, with high brittle mineral content (55%–65%). The produced shale gas displays a clear reversal in the stable carbon isotopes. The shale gas play zone is between the overlain mudstone in the Middle-Upper Longmaxi Formation (Fm) and the underlain Upper Ordovician tight limestone in the Jiancaogou Fm. The shale gas reservoir is overpressured, with an average pressure coefficient of 1.55 (relative to hydrostatic pressure). From December 2013 to late 2014, results of production tests determined relatively stable pressure and production curves. Fifty prolific gas wells have been completed to date in the Jiaoshiba Shale Gas Field in Fuling. Preliminary study revealed several characteristics of this structurally complex shale play that are distinctly different from those in the United States, including an anticlinal structure with mild deformation, abundant free gas, and very short gas migration through microfractures, the natural fracture network formed by the two fault systems, and the slip parallel to the layer in the basal LSLUOWS. Movement along strike-slip faults has gone through up into the Quaternary, which is considered to be a significant factor in the establishment and preservation of the overpressured region in the LSLUOWS.

English

The structural trapping mechanism and petrophysical attributes of Afam field, offshore Niger Delta was evaluated using 3D seismic reflection data and composite well logs data. The structure maps and seismic sections show that the anticlinal structure at the centre of the field, which is tied to the crest of the rollover structure assisted by faults, is the principal structure responsible for the hydrocarbon entrapment in the field. Distinctive fault closures are the dominant structural plays in the field. Structural highs, fault assisted closures comprising two-way closure and four-way dip closed structures are evident on the depth structure maps. Petrophysical analysis of four mapped reservoir sand horizons quantitatively revealed water saturation ranging from 3.07 to 12.02% in Well1 and 7.25 to 19.32% in Well 5; hydrocarbon saturation with range 87.98 to 96.93% (well 1), 80.68 to 92.75% (well 5). The porosity and permeability values of the reservoirs within the field proved them to be quite prolific with the porosity ranging from 24.5 to 31% (well 1), 21.25 to 28.25% (well 5) and permeability range of 2606.91 to 11,777.71 mD (well 1), 1050 to 6502.20 mD (well 5). Key words: Niger Delta, trapping mechanism, petrophysical analysis, structural highs, fault assisted closures.

Canyon-confined pockmarks on the western Niger Delta slope

Fluid flow phenomena in the deepwater Niger Delta are important for the safe and efficient exploration, development and production of hydrocarbons in the area. Utilizing 3D seismic data from the western Niger Delta slope, we have identified pockmarks that are confined within a NE–SW oriented submarine canyon system that has been active since the early Quaternary. The pockmarks, subdivided into ‘canyon-margin’ pockmarks and ‘intra-canyon’ pockmarks, on the basis of their plan-form distribution patterns, are found to be spatially and stratigraphically related to stratigraphic discontinuities created by erosion cuts associated with the submarine canyon system.We infer that stratigraphic discontinuities provided pathways for fluid migration within the buried canyon system, allowing fluids from deeper parts of the basin to reach the seafloor as indicated by abundant pockmarks above the partly buried canyon. The transportation of fluids from deeper parts of the basin into the buried segment of the canyon system was facilitated by carrier beds expressed as high amplitude reflection packages and by extensional normal faults. The prevalence of the ‘canyon margin’ pockmarks over the ‘intra-canyon’ pockmarks is attributed to the direct connection of the buried canyon margins with truncated reservoir facies in hydraulic connection with deeper reservoir facies. The formation of the ‘intra-canyon’ pockmarks is interpreted to have been limited by fluid flow disconnection often caused by stratigraphic alternation of sand-rich and shale-rich channel deposits that constitute the canyon fill. Muddy canyon fill units act as baffles to fluid flow, while connected sandy infill units constitute pathways for fluid migration. Occurrence of pockmarks throughout the length of the submarine canyon system is an indication of shallow fluid flow within buried reservoir facies. Systematic alignment of seafloor pockmarks are clues to buried reservoirs and provide insights into reservoir architecture which could be crucial in frontier exploration of buried deepwater canyons reservoirs and for risk assessment of development activities on top of submarine canyons. A single mega pockmark linked by a gas chimney to a deeper anticlinal structure was discovered to the north of the canyon system. This structure may be indicative of subsurface geo-pressures close to the fracture gradient, highlighting a significant drilling hazard in this part of the study area.

The structural style and hydrocarbon exploration of the subthrust in the Berati Anticlinal Belt, Albania

The Albania thrust belt consists of both internal and external tectonic zones, which are westward overthrusts with large amplitude (50–100 km), above the Apulian Patform and the South Adriatic Basin. The External Albanides are subdivided into distinct tectonic-stratigraphic units: the Kruja zone (shallow carbonate water) in the east and the Ionian zone in the west, which is represented by pelagic limestone. The Ionian zone, located between the Sazan (Pre-Apuliane) and Kruja zones, consists of three anticlinal belts: the Berati, Kurveleshi and Cika anticlinal belts. Their western margin is bordered on overthrust faults, which have produced large westward overthrusts on each of them, with amplitudes of 10–30 kms, and are utilized through a large diapir masses. Therefore, they mask perspective plays in subthrusts. The Berati anticlinal belt is the most eastern in the Ionian zone and lies mostly in the Albanian territory and partly in the Greek territory. It has a length of about 225 kms and a width 12–22 kms, and is differentiated into two sectors: the southern sector (south of the Qafa Kicoku) and the northern sector (north of the Qafa Kicoku). Understanding the evolution of evaporite tectonics is important in determining the principal features of the structural model on the Berati anticlinal belt. The changes in the lithostatic pressure on the space have a greater role in the development of evaporite tectonics, which are conditioned by the deposition thickness of the cover sediments above the evaporites and the presence of weak tectonic loops. These loops belong to the intersecting places of transverse and longitudinal fault generated since the rifting phase (T3-Cr1). Such intersecting places are the Dumrea (Albania) and Zavrohon (Greece) on the surface. We stress that evaporites are also extended over regional thrust faults of the Berati belt, helping its overthrusting westward about 20–30 km (depicted by seismic and deep wells data). The tectonic evaporite effect differs from the expansion of the Berat thrust belt. Thus, in its southern part, as a result of a diapirism that has not emerged on the surface, it is helping orogenies in developing large fan-type anticline structures (Golika, Nemercka, Mitsikeli anticlines, etc.), that have backthrusts in their eastern flank. Moreover, we encountered the presence of a carbonate massive in the middle of the Epiro-Akarnani syncline (e.g. Timfeu massive in Greece), caused by the “blind” evaporite body effect. The northern sector (north of Qafa e Kicoku), is characterized by a smaller evaporite effect, which is reflected in increasing density of the anticlinal structures on the surface units and their normal passing to each other. The Dumrea diapir is a considerable ellipsoid-shape evaporite mass outcropping with a surface area of about 210 km2 and axes 20 × 10 km. It is an ordinary diapir with a westward overthrust (20–30 km). Most oil fields in Albania are in carbonate sections (Cr2-Pg2) in the anticline structures delivered to the thrust of adjacent units. There is another new prospect of the high perspective: The carbonate structures under overthrust of different units (subthrust complex) of the Ionian zone. The subthrust in the Ionian zone is divided into three types: 1. The subthrust beneath overthrust of thrust belts. These overthrusts are related to the evaporite detachment horizon, and they mask folded structures of subthrust. 2. The subthrusts beneath the overthrusts of the anticline units. These overthrusts have a local character and they are more developed in the Kurveleshi thrust belt. 3. The subthrusts beneath the overthrusts of the tectonic zones of the orogenetic front (Ionian and Kruja Zones) above the western autochthonous (Apulian Platform and South Adriatic Basin). These structures display duplex and triplex style. Currently, the more interesting opportunity lies in the subthrust beneath the Berati thrust belt. This has a higher perspective than the other subthrusts beneath the Kurvelesh and Cika anticlinal belts. Actually, the Berati subthrust is in the processes of being the subject of a seismic survey and exploration drilling. The discovery of a new oil field in the subthrust of the Berati anticlinal belt, with drilling of the Shpiragu-2 well, which in the first test gave 800–1300 barrels (light oil with density 35–37° API) and 2–5 mmcfd gas per day, is of great importance for the entire tectonic ensemble of the Dinaric-Albanid-Hellenic. The presence of prospective structures such as the Dumrea anticline in the north and its continuation southward (the Shpiragu oil field, Molishti anticline, etc.), beneath the thrust belt, as shown by both drilling and seismic data, together with the presence of the surface structures (e.g. the Kasidhiaris, Kurenton and Thesprotikon anticlines) in Greece, shows the regional scale potential of petroleum plays. These prospects for new oil and gas discoveries constitute the object of this important paper, offering completely new ideas.