Faulted Anticline Research Articles

Quantification of factors affecting fault sealing by using machine learning: Shuangtaizi fault anticline, southern margin of the Liaohe Western Depression, Northeastern China

There are many factors that affect the faults sealing capacity, but the traditional lateral sealing model only considers the clay content, which leads to the great limitations of the established evaluation model. The objective of this study is to comprehensively examine the influence of potentially contributing factors on the fault sealing capacity. The Shuangtaizi structure is selected as the research focus in this study, where a 3D geological model is established to conduct detailed reservoir characterization for calculating trap elements and hydrocarbon column height. Subsequently, a dataset on the sealing attributes of fault-bounded traps is constructed after optimizing the dataset. By utilizing both machine learning evaluation models and traditional methods, the evaluation of the lateral sealing capacity of Shuangtaizi structural faults is performed. The influencing factors of fault rock sealing are clearly delineated as ten key parameters: effective normal stress, clay content, fault strike, fault throw, dip angle, transverse gradient, dip slip gradient, longitudinal gradient, longitudinal strain and shear strain in descending order of importance. Among these factors analyzed for fault sealing considerations, the most significant is the effective normal stress followed by clay content. By establishing a novel machine learning-based lateral sealing evaluation model and comparing it with the traditional SGR-AFPD fault lateral sealing evaluation model, it could be observed that the machine learning model exhibits a smaller error range and higher confidence in its evaluation results compared to the traditional model. Notably, the conventional model fails to consider the crucial influence of effective normal stress on sealing performance, which accounts for its inadequate accuracy. The model incorporates a comprehensive assessment of various factors that influence the lateral sealing capability of faults. In order to obtain objective and more realistic evaluation results, it is imperative to establish a multidimensional evaluation model in future studies.

Sedimentary thickness and basement depths of eastern Niger delta, Nigeria, from aeromagnetic data and implications for hydrocarbon prospects

A knowledge of sedimentary thickness and basement depths of a basin is necessary in understanding the structural set up of formations and evaluation of the hydrocarbon potentials of a region. In this work aeromagnetic data, obtained from the Nigerian Geological Survey Agency (NGSA) Abuja, has been interpreted to obtain sedimentary thickness, structural faults and intrusions including the basement depths of the eastern Niger Delta, Nigeria with the implications for hydrocarbon prospecting. Results from magnetic attribute analysis, total horizontal derivative operations, spectral analysis and source parameter imaging reveal the following: the study area is magnetically heterogeneous; the magnetic intensities range for the region is from – 46.2 nT to 160.3 nT, with residual magnetic intensity values of -15 nT to 13 nT revealing sediments with low magnetic rocks in the southwestern and southeastern parts of the study area and magnetic rocks and basement intrusions in the northwestern, northeastern and central parts of the study area; sedimentary thickness range from 96.5 m to 6601.5 m hosting faulted anticline and syncline structural bodies good enough for hydrocarbon formation and trapping and a maximum depth to basement of 6601.5 m. The sedimentary thickness and structural types, influenced by the basement intrusions, make the region a hydrocarbon potential area and it is recommended that prospecting in the southern and northern parts of the study area should be intensified.

Yukon’s Carlin-Type Gold Deposits (Rackla Belt, Canada): Main Characteristics and New Insights on Alteration Styles and Geochemistry

AbstractIn central Yukon, the Neoproterozoic to Carboniferous complexly deformed Rackla belt is along the northern boundary of the Selwyn basin. Toward the eastern end of the Rackla belt, a series of gold deposits in the Nadaleen trend exhibit similarities with Carlin-type deposits of the southwestern United States and may represent some of the best examples of this type of mineralization outside Nevada. These replacement-style gold deposits are hosted in two Neoproterozoic carbonate-dominated intervals and in a Paleozoic siltstone/mudstone unit at the contact with less permeable strata. In Neoproterozoic-hosted deposits, mineralized zones are grossly concordant with bedding. Favorable host rocks (including sedimentary units formed through debris flows) form complexly shaped faulted anticlines that constituted mixed stratigraphic/structural traps for mineralizing fluids. This and the association of gold with arsenic-rich pyrite, the common occurrence of realgar/orpiment, alteration styles dominated by decarbonatization of impure carbonate rocks, late Au-stage calcite characterized by a depleted δ18O signature, the very low base metal content and Ag/Au ratio, and enrichment in a series of diagnostic pathfinder elements (Hg, Tl ± Sb, As) are among the key features that are consistent with classification of the eastern Rackla belt as a Carlin-type district.Mineralization style varies significantly at the centimeter to 10-m scale, indicating that mineralizing fluids exploited permeable pathways, regardless of their sedimentary and/or tectonic origin. Alternating finely laminated limestone, siltstone, and floatstone intervals are the dominant host rocks to mineralization in the Conrad, Sunrise, and Osiris deposits. Premineralization fractures acted as feeders for selective bed replacement, and premineralization calcite vein networks, preferentially dissolved by early acidic fluids, acted as conduits to later gold-bearing fluids. Limited evidence suggests that synmineralization deformation was relatively minor and possibly dominated by oblique strike-slip faulting.

Autonomous Inflow-Control Devices Boost Production While Managing Sand

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm3, and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.

Structural and Economic Analysis of Meyal Oil Field in the Northern Potwar Deformed Zone, Upper Indus Basin, Pakistan

Potwar sub-basin is famous for its structural style, hydrocarbon exploration and production activities from Cambrian to Pliocene rocks. Foreland basin related subsurface structures, in the presence of source and seal rocks offer a variety of traps to host hydrocarbons. Meyal Oil field, situated in the NW Potwar sub-basin, is a hydrocarbon resource for the country. Subsurface structures of Meyal area were outlined by interpreting two strike and four dip lines in IHS Kingdom suite. Borehole data of MYL-10, MYL-12 and MYL-13 exploratory wells were incorporated to improve the subsurface understanding. A total five prominent reflectors of Permian, Triassic, Jurassic, Paleocene and Eocene rocks were marked on the seismic sections. The seismic interpretation shows a post Eocene pop-up structure flanked by a back thrust and a fore thrust. Moreover, the time structure maps for Meyal area display a doubly plunging and faulted anticline as a result of south directed compression. Four isochron maps show thickness variation in Permian to Eocene sediments in the study area. The results of interpretation show favorable structural trap for economic hydrocarbon exploration.

Extensional fault-related folding of the North West shelf, Western Australia

The occurrence of fault-related folds in extensional settings has been gaining increased recognition during the past 20 yr. Passive margins and rift basins often present intriguing structural complexities that are potential sites for the development of extensional fault–related folds. Fault-related folds are important anticlinal traps for hydrocarbon exploration, and understanding their evolution is critical for derisking the timing of trap formation and hydrocarbon generation. This study presents folds from three areas across the North West shelf (NWS) of Western Australia and aims to determine their relationship to associated extensional faults. A series of kinematic forward models are presented as well as detailed structural and stratigraphic interpretation of folding at the three locations. The models suggest each of the three examples have formed under extension that impacted the region during the Mesozoic. The modeling also highlights different characteristics of folding that are caused by fault geometry (ramp–flat) and a propagating fault tip (trishear) that can be used as diagnostic features to distinguish different fold mechanisms. Historical exploration across the NWS has targeted a relatively small number of these anticlinal traps, some of which have been successful (e.g., Marina-1 well, Petrel subbasin) and some have not (e.g., Candace-1, Sholl Island fault anticline). This paper suggests that the prospectivity of anticlinal structures should be more carefully assessed to determine whether or not they are related to extensional activity and hence likely to have formed prior to the bulk of the hydrocarbon charge. Similar structures undoubtedly exist in other basins that have experienced repeated extension.

Data-Acquisition Optimization Maximizes Value of Mature Oil-Rim Reservoirs

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196208, “Value Creation From the Reservoir, Well, and Facilities Management (RWFM) Planning in Multistacked Mature Oil-Rim Reservoir, Offshore Sarawak, Malaysia,” by Yeek Huey Ho, SPE, Nor Baizurah Ahmad Tajuddin, SPE, Muhammed Mansor Elharith, SPE, Hui Xuan Dan, Kwang Chian Chiew, Kok Liang Tan, SPE, Raj Deo Tewari, SPE, and Rahim Masoudi, SPE, Petronas, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 29 September–2 October. The paper has not been peer previewed. The XamXung field offshore Sarawak, Malaysia, is a 47-year brownfield with thin remaining oil rims that have made field management challenging. The dynamic oil-rim movement has been a key subsurface uncertainty, particularly with the commencing of a redevelopment project. A reservoir, well, and facilities-management (RWFM) plan was implemented to optimize development decisions. This paper is a continuation of paper SPE 174638 and outlines the outcome of the RWFM plan and the results’ effect on development decisions such as infill well placement and gas/water injection-scheme optimization (Fig. 1). Key decisions affected by the RWFM findings are highlighted in the complete paper. Introduction The XamXung field was discovered in 1967, with commercial production established in 1972. The field is a simple faulted anticline bounded by two major faults in the north and south. The field consists primarily of clastic deposits characterized by thick sands interbedded with thin shale layers of late Miocene to Pliocene age. The field consists of multiple stacked gas and oil reservoirs, with key producing intervals being the oil-rim reservoirs XE/XF and XH/XI, and the deeper oil reservoir XL, as well as major nonassociated gas reservoirs XA, XC, XD, XM, and XN. The main discussion of the complete paper focuses on XE/XF and XH/XI reservoir redevelopment. XE/XF is a saturated oil-rim reservoir with initial oil-rim thicknesses of 95 and 85 ft, respectively. The XE/XF oil rim is overlain by a gas cap with m size (ratio of initial free-gas reservoir volume to initial reservoir oil volume) of 1.1 and 0.4, respectively. XE and XF reservoirs are separated by a fieldwide sealed shale layer of 10–20-ft thickness. Initial reservoir pressure and well log data acquired during the early production his-tory suggested that XE/XF reservoirs originally shared a common gas/oil con-tact (GOC) but different free-water levels. XE/XF reservoirs have an average porosity of 27–32% and average permeability of 500–1500 md. They started production in 1974 and reached peak production in 1977. The reservoir pressure has declined by only 200 psi after 45 years of production, indicating that the reservoir is under a strong aquifer drive. Gas injection into XE reservoir commenced in 1995 following an increasing water-cut trend in most of the producers, with the objective to counteract the aquifer influx and to allow uniform gas-cap gas expansion throughout the reservoir. However, the reservoir historically has produced more free gas compared with the amount of gas reinjected, resulting in the reservoir gas-cap shrinkage.

Major factors controlling the shale gas accumulations in Wufeng-Longmaxi Formation of the Pingqiao Shale Gas Field in Fuling Area, Sichuan Basin, China

Pingqiao Shale Gas Field in Fuling Area of Sichuan Basin in China is located in a narrow-abrupt fault anticline of the Fenglai Syncline. Presently, the proven geological reserves of shale gas are 138.917 × 109 m3 in the Pingqiao Shale Gas Field, suggesting good potential for shale gas exploration in the Pingqiao Shale Gas Field. According to the drilling, logging, as well as the seismic and experimental data, the basic features of the Pingqiao Shale Gas Field with the narrow-abrupt fault anticline structure is outlined. Herein, the major factors controlling the accumulation and the high productivity, as well as the reasons for the differences in the production in the Pingqiao Shale Gas Field are also analyzed. The studies show the following: (1) The thickness of the shale gas layers (TOC ≥ 1%) is 115–155 m, the thickness of quality shale layers (TOC ≥ 3%) at the bottom of Wufeng-Longmaxi Formation in the Pingqiao Shale Gas Field is 36–40 m, which is featured by the high abundance in reserves (1.268 × 109 m3/km2), high pressure of shale gas accumulation (pressure ratio 1.56) and the high production value (average testing production 219.9 × 103 m3/d). (2) Main factors controlling shale gas accumulation and production in the Pingqiao Shale Gas Field include developed quality shales in the deep shelf, no faults stretching to the surface, weak slipping, good sealing, no outcrops and no obvious pressure-released belts in the surrounding area. (3) The development degree of the micro-fractures, structure position and depth are the key factors for the differences in production when shale gas layers have similar enrichment conditions.

Effective evaluation of gas migration in deep and ultra-deep tight sandstone reservoirs of Keshen structural belt, Kuqa depression

The gas reservoir in the Keshen structural belt, Kuqa depression, Tarim Basin, Xinjiang, China is a typical deep and ultra-deep structural faulted anticline tight sandstone gas reservoir. This reservoir possesses abundant natural gas and exhibits a promising exploration and development prospective. However, the effectiveness of the gas migration (preferred migration pathway) and the contribution of gas source faults as a dominant migration pathway remains to be further investigated. Therefore, this paper examines gas-source correlation to determine the source of natural gas and uses fluid potential analysis combined with the tracer results of geochemical parameters to predict the predominant migration and accumulation pathways of natural gas. Next, the paper determines the contribution of gas source faults to the formation of the gas reservoir during the migration process by making a quantitative assessment of the gas source faults. The results show that the predominant source of natural gas from the deep and ultra-deep tight sandstone gas reservoir in the Keshen structural belt, Kuqa depression is Jurassic and Triassic source rock. Structural units with relatively low fluid potential represent the predominant migration pathway of natural gas. Gas source faults provide the predominant natural gas vertical transport pathway, with differences observed between zones in the south and north. The greater the contribution provided by a gas source fault during transport is, the higher the accumulation that results. The effectiveness of the natural gas migration deep and ultra-deep tight sandstone gas reservoir in the Keshen structural belt, Kuqa depression is as follows: Kela2 trap > Keshen6 trap > Keshen8 trap > Keshen2 trap > Keshen13 trap > Keshen9 trap. This method can be used in effective evaluation of the gas migration under the similar tectonic settings and reservoir formation conditions.

Using Vertical Electrical Soundings for Characterizing Hydrogeological and Tectonic Settings in Deir El-Adas Area, Yarmouk Basin, Syria

The present study is aimed at characterizing the subsurface geological and tectonic structure in Deir El-Adas area, by using Vertical Electrical Sounding survey (VES) and hydrogeological investigations, in order to determine the causes of the failure for the majority of the wells drilled in the area. The survey data was treated in three different approaches including direct VES inversion, pseudo-2D method and horizontal profiling, in order to maximize the reliability of the data interpretation. The results revealed the presence of a local faulted anticline structure at the top of the Paleogene formation, underneath the basaltic outcrops where Deir El-Adas village is situated. The appearance of this subsurface anticline structure has complicated the local hydro-geological situation, and most likely led to limitation of the groundwater recharge in the area. Moreover, the performed piezometric and discharge maps indicated the presence of a notable groundwater watershed, in addition to feeble water productivity of the wells drilled adjacent to Deir El-Adas, mostly related to the subsurface geological and tectonic settings in the area.

Tectonic control of the Meteora conglomeratic formations (Mesohellenic basin, Greece)

AbstractThe Meteora are a famous sightseeing area of northern Greece, namely for the monasteries culminating at the strange pinnacles surrounded by impressive cliffs made of a stack of conglomeratic fan deltas from the Lower Miocene. This paper analyzes the imprint on their stratigraphy of regional deformation related to the subduction of the external zones beneath the Mesohellenic basin (MHB). The onset of deposition of the Meteora series corresponds to a major change in depositional regime (from marls to conglomerates) that can be followed throughout the MHB. The tectonic control on that change is supported by both sedimentological and structural characteristics, such as the progressive tilting of topset dip within the fan-deltas, the input of large volumes of pebbles derived from areas of rapidly renewed reliefs to the east of the Meteora (Pelagonian indentor), and the partitioning of two successive Meteora depocentres apart from a large faulted anticline (Theopetra-Theotokos structure). Most of the recorded deformation corresponds to vertical movements, with the local development of early Miocene synsedimentary normal faults.

Mud volcanoes and methane seeps in Romania: main features and gas flux

Romania is one of the European countries with the most vigorous natural seepage of methane, uprising from pressurised natural gas and petroleum reservoirs through deep faults. The largest seepage zone is represented by large mud volcanoes, with CH4 >80% v/v, occurring on the Berca-Arbanasi hydrocarbon-bearing faulted anticline, in the Carpathian Foredeep. Smaller mud volcanoes have been identified in other areas of the Carpathian Foredeep, in the Transylvanian Depression and on the Moldavian Platform. New surveys carried out in Transylvania allowed us to discover the richest N2 mud volcano zone in the world (N2>90% v/v), with a remarkably high He content and a helium isotopic signature which highlights a contribution of mantle-derived source. The large mud volcanoes are generally quiescent, with rare explosive episodes and provide a methane flux in the order of 102-103 t km?2 y?1. Independently from mud volcanism, a remarkable dry macroseepage, however, has been found, with a degassing rate up to three orders of magnitude higher than that of mud volcanoes (i.e. 103-105 t km?2 y?1). The total gas flux from all investigated macroseepage zones in Romania is estimated in the range of 1500-2500 t y?1. The emission from microseepage, pervasively occurring throughout the hydrocarbon-prone basins, has yet to be assessed and added to the total gas output to the atmosphere.

Trials and Tribulations of a Long-Reach Well in Deepwater GOM

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 118705, "Trials and Tribulations of a Long-Reach Well in the Deepwater GOM," by Ron Day, Ramsey Fisher, SPE, and Louise Jacobsen Plutt, SPE, BP plc, and Nesny Pardo, SPE, Segun Jebutu, SPE, and Hans-Christian Freitag, Baker Hughes, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. For deepwater offshore areas with irregular water-bottom topography, subsea infrastructure above the field often can be limited. Access to reservoir targets becomes constrained, particularly when drilling challenges exist above the reservoir, such as pressure ramps or layers with unstable lithologies. Long stepouts can be required. Strategies implemented to drill and access reservoirs successfully in a large faulted anticline in the deepwater Gulf of Mexico (GOM) are presented. Introduction Discovered in 1998, the subject field is in the Green Canyon protraction area of the GOM in a water depth of 6,800 ft. The main reservoir targets are stacked oil-bearing turbidite sands at a depth of approximately 9,800 ft below the mudline. As shown in Fig. 1, the field is a large faulted anticline 11 miles long by 4 miles wide. Development is complicated by shallow salt fingers that obscure seismic imaging of the north flank of the structure and create a complex water bottom across the middle of the field where water depth changes 2,200 ft across a 1-mile width. Because of this lack of clarity on the northern flank, the south flank of the field was developed first from a central drill center, designated as Drill Center One (DC1). Drilling Challenges Well U was the sixteenth penetration in the field. Like all development wells drilled from DC1, Well U had three strings of casing (36-in. surface casing set approximately 200 ft below mudline; 26-in. conductor casing set at approximately 1,200 ft below mudline; and 20-in. casing set at approximately 2,300 ft below mudline) set during the 2004 batch-set operation. However, Well U, would need to mitigate three main drilling challenges in its remaining 17×20-in., 14 3/4×16 1/2-in., and 12 1/4-in. hole sections. First, Well U would need to navigate through a 1,000-ft-thick laminated and thin-bedded sand, which had caused severe lateral vibrations to the drilling assembly in previous wells, making directional control difficult and occasionally leading to downhole-assembly failures. As a result, vibration management became crucial in drilling the 14 3/4×16 1/2-in. section in one trip. An additional complication in the 14 3/4×16 1/2-in. section was that it would reach total depth in a pressure ramp, which could contribute to borehole instability.

Composite Petroleum System and Advantageous Exploration Targets in the Kongquehe Area of Tarim Basin

Guided by the description methods and evaluation routine for composite petroleum system in superimposed basins, the composite characteristics of the petroleum systems in the Kongquehe area of the Tarim basin was studied and the geological evolution processes of hydrocarbon from source to trap was revealed. The petroleum systems in the Kongquehe area, mainly through fault composite linkage combined with unconformity surface composite linkage, constitute the Cambrian € (!)–Lower Ordovician O 1 (!)–Carboniferous C (*)–Triassic T (*)–Jurassic J (*) + Cambrian € (!)–Lower Ordovician O 1 (*)–Silurian S (*)–Devonian D (*)–Jurassic J (*) modified composite petroleum systems (*). There are three critical periods for composite petroleum system, such as the end of Devonian for forming tectonic framework and paleoreservoir, the end of Jurassic and Cretaceous for hydrocarbon transformation, redistribution, and adjustment. The research area may be classified into three types — destroyed dissipation zone, transformed adjustment zone, and deeply-buried preservation zone, amongst which the latter two zones are favorable for hydrocarbon accumulation. Especially, the Upper Paleozoic and Mesozoic faulted anticline traps of the Longkou anticline and the Weimake–Kaiping anticline and the residual Lower Paleozoic fault paleo-anticline traps in the transformed adjustment zone are the best prospecting targets.

Hydrocarbon habitat of the offshore Bohai Basin, China

The Bohai Basin is a major continental petroliferous basin located in eastern China, of which the offshore part of the basin contains more than one-third of the total petroleum resources in the basin. Although the basin has been explored for nearly 40 years, the offshore part of the basin is just reaching a moderately mature stage of exploration, and its petroleum geological features are gradually becoming known. The subduction of the Pacific Plate to the Eurasia Plate resulted in the convective upwelling of the mantle in the Bohai area and triggered the development of NNE and NE striking extensional faults along the Mesozoic structures in the Late Paleocene, causing the formation of the rift basin. During the Oligocene, the depocenters and subsidence centers of the greater Bohai Basin migrated from west to east and from south to north and finally concentrated in the offshore part of the basin. Since the Oligocene, especially during the Neogene, due to the indentation of the India Block to the Eurasia Plate, the right-lateral strike-slip movement of the Tan-Lu fault was relatively intense in the offshore part of the basin. These characteristics led to the differences between the offshore and onshore sectors in sedimentation, structural features, and petroleum geology. During the deposition of the Dongying Formation, the offshore sector became the depocenter and subsidence center of the basin, resulting in the deposition of the lower Dongying Formation mudstone source rocks; while these mudstones are immature in the onshore part of the basin. In the offshore Bohai, most major discoveries have been made in the drape anticlines on the rises in the Upper Tertiary reservoirs; while the Lower Tertiary reservoirs within the half-grabens only serve as secondary reservoirs. As the Neogene depocenter of the basin, the offshore part accommodated some fine-grained shallow lacustrine clastics of the lower Minghuazhen Formation, serving as important regional seals for the Neogene reservoirs. A set of shallow faults and a central faulted anticlinal belt in the shallow Upper Tertiary sequences were formed during the Neogene in the offshore sector under the influence of right-lateral strike-slip faulting of the Tan-Lu fault. These shallow faults networked with deep extensional faults, serving as hydrocarbon conduits. The central faulted anticline belt, along the Tan-Lu fault system, also provides significant traps.

Hydrocarbon habitat of the offshore Bohai Basin, China

The Bohai Basin is a major continental petroliferous basin located in eastern China, of which the offshore part of the basin contains more than one-third of the total petroleum resources in the basin. Although the basin has been explored for nearly 40 years, the offshore part of the basin is just reaching a moderately mature stage of exploration, and its petroleum geological features are gradually becoming known. The subduction of the Pacific Plate to the Eurasia Plate resulted in the convective upwelling of the mantle in the Bohai area and triggered the development of NNE and NE striking extensional faults along the Mesozoic structures in the Late Paleocene, causing the formation of the rift basin. During the Oligocene, the depocenters and subsidence centers of the greater Bohai Basin migrated from west to east and from south to north and finally concentrated in the offshore part of the basin. Since the Oligocene, especially during the Neogene, due to the indentation of the India Block to the Eurasia Plate, the right-lateral strike-slip movement of the Tan-Lu fault was relatively intense in the offshore part of the basin. These characteristics led to the differences between the offshore and onshore sectors in sedimentation, structural features, and petroleum geology. During the deposition of the Dongying Formation, the offshore sector became the depocenter and subsidence center of the basin, resulting in the deposition of the lower Dongying Formation mudstone source rocks; while these mudstones are immature in the onshore part of the basin. In the offshore Bohai, most major discoveries have been made in the drape anticlines on the rises in the Upper Tertiary reservoirs; while the Lower Tertiary reservoirs within the half-grabens only serve as secondary reservoirs. As the Neogene depocenter of the basin, the offshore part accommodated some fine-grained shallow lacustrine clastics of the lower Minghuazhen Formation, serving as important regional seals for the Neogene reservoirs. A set of shallow faults and a central faulted anticlinal belt in the shallow Upper Tertiary sequences were formed during the Neogene in the offshore sector under the influence of right-lateral strike-slip faulting of the Tan-Lu fault. These shallow faults networked with deep extensional faults, serving as hydrocarbon conduits. The central faulted anticline belt, along the Tan-Lu fault system, also provides significant traps.

Oil and gas accumulations in the Ordovician carbonates in the Tazhong Uplift of Tarim Basin, west China

Oil and gas fields of the Paleozoic cratonic basin in Tarim are mainly distributed in the Tabei and the Tazhong Uplifts. In the Tazhong Uplift, there are three sets of oil and gas stratum systems, of which the Ordovician traps are the largest in size and close to oil source beds with the most favorable conditions to form large-scale oil and gas fields. The Ordovician sediments in the Tazhong Uplift have experienced a stable platform and tableland margin development period. The Ordovician is divided into mudstone interval, interbedded mudstone and limestone interval, limestone interval, limestone and dolomite transitional interval and dolomite interval. Of these intervals, both interbedded mudstone and limestone interval and limestone interval contain source rocks, while limestone interval and dolomite interval are reservoir beds. Fault activities and denudation have an obvious impact on carbonate rock reservoirs. The major Ordovician trap types of the Tazhong Uplift include compressional fault block, fault anticline and buried hill, and regionally. The Tazhong Uplift can be generally divided into central fault horst trap belt, northern slope trap belt and southern slope trap belt. In view of the in-situ oil source in the Tazhong, oil and gas migration in the Tazhong Uplift is characterized by a short distance migration through sand bodies and unconformity surfaces laterally and along faults vertically. Based on this study, it is concluded that the favorable oil and gas accumulation zone should be the northern slope and the northwestern pitchout end of the uplift because these areas are located in the hydrocarbon migration pathway with weak tectonic activities and favorable preservation conditions.

Northstar-Geology, Exploration History, and Development Status, Beaufort Sea, Alaska

Exploration for oil at Northstar has been long and costly. Northstar leases were first acquired in 1979 at a joint state and federal sale by Shell Oil, Amerada Hess, and Texas Eastern. The Northstar Unit is 6 mi offshore and about 4 mi northeast of the Point McIntyre Field. Oil was first discovered in Shell's Seal Island 1 in 1983. Five additional appraisal wells were drilled (1983-1986) from two man-made gravel islands in 40 ft of water. Early engineering estimates put the cost of development at $ 1.6 billion. In February 1995, BP Exploration (Alaska) acquired a 98 % interest in the Northstar Unit from Amerada Hess and Shell Oil. When developed by BP, Northstar will be the first oil produced from federal leases in Alaska. To date, the oil industry has invested in excess of $ 140 million in exploration and appraisal operations. An additional $ 90 million was spent on lease bonus bids. The giant Prudhoe Bay and Kuparuk Fields lie along the Barrow Arch. This arch is bounded to the north by a rift margin that deepens into the present-day offshore region. Northstar is located among a series of down-stepping faults off this northern rift margin of the Prudhoe Kuparuk high. The structure is a gently south-dipping northwest-trending faulted anticline. The crest of the structure is located near 10,850 ft subsea. The primary reservoir is the Ivishak Formation (325 ft thick) of the Sadlerochit Group. This is the same primary reservoir at Prudhoe Bay, approximately 12 mi to the south. At Northstar the Ivishak is a high-energy, coarse-grained conglomeratic facies of the Ivishak Formation. The primary lithology is a pebbly chert to quartz conglomerate with occasional sandstone. This very high net to gross reservoir appears to contain no regionally continuous permeability barriers. Cementation has reduced primary porosity to less than 15 %. Accurate porosity estimates are difficult to make due to the coarse-grained nature of the lithology and the presence of kaolinite and microporous chert. Permeability is highly variable, but averages 10 to 100 mDarcies. Oil is a very light and volatile 42 API crude with approximately 2,100 ft3 of gas per stock tank barrel of oil. This oil is very different from the heavier oils (26) found to the south in Prudhoe Bay. Estimated recoverable oil reserves range from 100 to 160 million barrels. A free-standing drilling rig is required at Northstar because the reserves are beyond extended-reach drilling techniques from shore-based facilities. The current development plan is to expand the existing Seal Island to about 5 acres. This is significantly less than Endicott's 40-acre island. The proposed drilling and produc tion island will be accessed by summer barges and winter ice roads. Oil, gas, and water will be processed at a stand-alone facility and then sent to shore via a subsurface pipeline. Northstar will have the first Arctic subsea pipeline in Alaska to transport oil to shore facilities (TAPS). Preliminary tests in Spring 1996 were very successful in demonstrating the technology to successfully bury a subsea pipeline safely in the Arctic.

Tectonic controls on the hydrocarbon habitats of the Barito, Kutei, and Tarakan Basins, Eastern Kalimantan, Indonesia: major dissimilarities in adjoining basins

The Barito, Kutei, and Tarakan Basins are located in the eastern half of Kalimantan (Borneo) Island, Indonesia. The basins are distinguished by their different tectonic styles during Tertiary and Pleistocene times. In the Barito Basin, the deformation is a consequence of two distinct, separate, regimes. Firstly, an initial transtensional regime during which sinistral shear resulted in the formation of a series of wrench-related rifts, and secondly, a subsequent transpressional regime involving convergent uplift, reactivating old structures and resulting in wrenching, reverse faulting and folding within the basin. Presently, NNE–SSW and E–W trending structures are concentrated in the northeastern and northern parts of the basin, respectively. In the northeastern part, the structures become increasingly imbricated towards the Meratus Mountains and involve the basement. The western and southern parts of the Barito Basin are only weakly deformed. In the Kutei Basin, the present day dominant structural trend is a series of tightly folded, NNE–SSW trending anticlines and synclines forming the Samarinda Anticlinorium which is dominant in the eastern part of the basin. Deformation is less intense offshore. Middle Miocene to Recent structural growth is suggested by depositional thinning over the structures. The western basin area is uplifted, large structures are evident in several places. The origin of the Kutei structures is still in question and proposed mechanisms include vertical diapirism, gravitational gliding, inversion through regional wrenching, detachment folds over inverted structures, and inverted delta growth-fault system. In the Tarakan Basin, the present structural grain is typified by NNE–SSW normal faults which are mostly developed in the marginal and offshore areas. These structures formed on older NW–SE trending folds and are normal to the direction of the basin sedimentary thickening suggesting that they developed contemporaneously with deposition, as growth-faults, and may be the direct result of sedimentary loading by successive deltaic deposits. Older structures were formed in the onshore basin, characterized by the N–S trending folds resulting from the collision of the Central Range terranes to the west of the basin. Hydrocarbon accumulations in the three basins are strongly controlled by their tectonic styles. In the Barito Basin, all fields are located in west-verging faulted anticlines. The history of tectonic inversion and convergent uplift of the Meratus Mountains, isostatically, have caused the generation, migration, and trapping of hydrocarbons. In the Kutei Basin, the onshore Samarinda Anticlinorium and the offshore Mahakam Foldbelt are prolific petroleum provinces, within which most Indonesian giant fields are located. In the offshore, very gentle folds also play a role as hydrocarbon traps, in association with stratigraphic entrapment. These structures have recently become primary targets for exploratory drilling. In the Tarakan Basin, the prominent NW–SE anticlines, fragmented by NE–SW growth-faults, have proved to be petroleum traps. The main producing pools are located in the downthrown blocks of the faults. Diverse tectonic styles within the producing basins of Kalimantan compel separate exploration approaches to each basin. To discover new opportunities in exploration, it is important to understand the structural evolution of neighbouring basins.

Strike-Slip Structural Styles and Petroleum System Evolution, Northeast Sakhalin Island: ABSTRACT

The primary petroleum system of northeast Sakhalin Island and adjacent shelfal areas is comprised of a system of Late Miocene to Quaternary faulted transpressional anticlines that trap oil and gas in Early Miocene to Pliocene deltaic reservoirs sourced from Late Oligocene to Early Miocene diatomaceous shales. Existing production has been limited to onshore anticlines, and offshore structural trends remain undeveloped, despite several discoveries. The regional tectonic evolution of Sakhalin Island can be divided into five major phases: (1) Late Cretaceous to Early Eocene subduction, (2) Middle-Eocene collision and uplift, (3) Late Eocene to Early Oligocene oblique rifting, (4) Late Oligocene to Middle Miocene thermal subsidence, and (5) Late Miocene to Quaternary transpression and inversion. Oil-prone source rocks were deposited during rapid post-rift thermal subsidence of transtensional rift basins and adjacent highs, which provided an ideal sediment-starved setting for source rock accumulation. Reservoir facies were supplied by prograding post-rift Miocene deltaics of the paleo-Amur river, which built a shelf across the thermally subsiding basin and intrabasin highs. Traps were formed when the basin was later inverted during Late Miocene to Pleistocene transpression, which reactivated both Paleogene normal faults and structural trends of the Mesozoic accretionary prism to create a broad zonemore » of distributed shear. Strike-slip structural styles are evidenced by linear, en echelon alignments of doubly-plunging anticlines characterized by numerous small-displacement, transverse normal faults. Strike slip on individual structures is relatively small, however, based on a lack of thorough going faults. Strike-slip structures on Sakhalin Island are considered active, in light of the earthquake of May 27, 1995 (M=7.6) and uplift of Pleistocene marine terraces.« less