Complex accumulation and leakage of YC21-1 gas bearing structure in Yanan sag,Qiongdongnan basin,South China Sea

YC21-1 is a gas-bearing structure found within the Yanan sag in the Qiongdongnan Basin, South China Sea. While the structure bears many geological similarities to the nearby YC13-1 gas field, it nevertheless does not contain commercially viable gas volumes. The main reservoirs of the YC21-1 structure contain high overpressures, which is greatly different from those of the YC13-1 structure. The pressure coefficients from drillstem tests, wireline formation tests and mud weights are above 2.1. Based on well-log analysis, illite content and vitrinite reflectance data of mudstones in well YC21-1-2, combining with tectonic and sedimentation characteristics, the timing and causes of overpressure generation are here interpreted. The results indicate the existence of two overpressure segments in the YC21-1 structure. The first overpressure segment resides mainly within the lower and the middle intervals of the Yinggehai Formation, and is interpreted to have been mainly caused by clay diagenesis, while disequilibrium compaction and hydrocarbon generation may also have contributed to overpressure generation. The second overpressure segment comprising the Sanya Formation (Pressure transition zone) and the Lingshui and Yacheng Formations (Hard overpressure zone) is interpreted to owe its presence to kerogen-to-gas cracking. According to petrography, homogenization temperature and salinity of fluid inclusions, two stages of oil-gas charge occurred within the main reservoirs. On the basis of overpressure causes and oil-gas charge history, combining with restored tectonic evolution and fluid inclusion characteristics, a complex accumulation and leakage process in the YC21-1 gas bearing structure has been interpreted. Collective evidence suggests that the first oil charge occurred in the Middle Miocene (circa 16.3–11.2 Ma). Small amount of oil generation and absence of caprocks led to the failure of oil accumulation. Rapid subsidence in the Pliocene and Quaternary gave rise to a sharp increase in geotemperature over a short period of time, leading to prolific gas-generation through pyrolysis and, consequently, overpressure within the main reservoirs (the second overpressure segment). During this period, the second gas charge occurred in the Pliocene and Quaternary (circa 4.5–0.4 Ma). The natural gas migrated in several phases, consisting of free and water soluble phases in a high-pressure environment. Large amounts of free gas are considered to have been consumed due to dissolution within formation water in highly pressured conditions. Water soluble gas could not accumulate in high point of structure. When the pore-fluid pressures in main reservoirs reached the fracture pressure of formation, free gas could leak via opened fractures within cracked caprocks. A repeated fracturing of caprocks may have consumed natural gas stored in formation water and have made water-soluble gas unsaturated. Therefore, the two factors including caprocks fracturing and dissolution of formation water are interpreted to be mainly responsible for the failure of natural gas accumulation in the YC21-1 structure.     

Palaeopressure reconstruction to explain observed natural hydraulic fractures in the Cleveland Basin

Natural fractures observed within the Lower Jurassic shales of the Cleveland Basin show evidence that pore pressure must have exceeded the lithostatic pressure in order to initiate horizontal fractures observed in cliff sections. Other field localities do not show horizontal fracturing, indicating lower pore pressures there. Deriving the burial history of the basin from outcrop, VR and heat-flow data gives values of sedimentation rates and periods of depositional hiatus which can be used to assess the porosity and pore pressure evolution within the shales. This gives us our estimate of overpressure caused by disequilibrium compaction alone, of 11 MPa, not sufficient to initiate horizontal fractures. However, as the thermal information shows us that temperatures were in excess of 95 °C, secondary overpressure mechanisms such as clay diagenesis and hydrocarbon generation occurred, contributing an extra 11 MPa of overpressure. The remaining 8.5 MPa of overpressure required to initiate horizontal fractures was caused by fluid expansion due to hydrocarbon generation and tectonic compression related to Alpine orogenic and Atlantic opening events. Where horizontal fractures are not present within the Lower Jurassic shales, overpressure was unable to build up as high due to proximity to the lateral draining of pressure within the Dogger Formation. The palaeopressure reconstruction techniques used within this study give a quick assessment of the pressure history of a basin and help to identify shales which may currently have enhanced permeability due to naturally-occurring hydraulic fractures.     

Compaction of smectite-rich mudstone and its influence on pore pressure in the deepwater Joetsu Basin,Sea of Japan

Pore pressure prediction is needed for drilling deepwater wildcats in the Sea of Japan because it is known from past experience that there can be drilling problems can arise due to overpressure at shallow depths. The “Joetsu Basin” area is located offshore to the southwest of Sado Island on the eastern margin of the Sea of Japan. The sedimentary succession of the Neogene is mainly composed of turbidite sediments which contained smectite-rich mudstones. The cause of overpressure in the study area is expected to be a combination of mechanical disequilibrium compaction and chemical compaction, especially from the illitization of smectite.We have constructed basin models and performed numerical simulations by using 1D and 3D PetroMod to understand clearly the history of fluid flow and overpressure development in the lower Pliocene Shiya Formation and Middle to Upper Miocene Teradomari Formations. A compaction model coupled with both mechanical and chemical compaction for smectite-rich sediments is used for pore pressure calibration. We have examined three key relationships: porosity-effective stress, porosity-permeability, and the kinetics of smectite-illite transformation. We determined the ranges for the parameter values in those relationships that allow a good fit between measured and modelled pore pressures to be obtained. Results showed that for the most likely case, high pore pressure in the Lower and Upper Teradomari developed since 8.5 Ma and 5.5 Ma, respectively. Pore pressures in studied structures have approximately doubled since 1 Ma due to the high deposition rate of the Pleistocene Haizume Formation and smectite-illite transformation in the lower Pliocene-Shiya and Middle to Upper Miocene- Lower and Upperr Teradomari formations. In three cases (high case, most likely case and low case), the overpressures in the Shiya, Upper and Lower Teradomari Formations are less than 1 MPa, 15 and 30 Ma, respectively.The results provide a basis for planning future wells in the “Joetsu Basin” area and in other basins where geological conditions are similar, i.e., deepwater, high sedimentation rate, high geothermal gradient and smectite-rich sediments.     

Evolution of pore-fluid pressure during folding and basin contraction in overpressured reservoirs: Insights from the Madison–Phosphoria carbonate formations in the Bighorn Basin (Wyoming,USA)

Reconstructing the evolution of paleofluid (over)pressure in sedimentary basins during deformation is a challenging problem, especially when no hydrocarbon-bearing fluid inclusions are available to provide barometric constraints on the fluid system. This contribution reports the application to a natural case (the Bighorn Basin) of recent methodological advance to access fluid (over)pressure level prevailing in strata during sub-seismic fracture development. The fluid pressure evolution in the Mississippian-Permian Madison–Phosphoria limestone reservoir is tentatively reconstructed from the early Sevier Layer Parallel Shortening to the Laramide folding in two basement-cored folds: the Sheep Mountain Anticline and the Rattlesnake Mountain Anticline. Results point out that supra-hydrostatic pressure values prevail in the limestone reservoir during most of its whole Sevier–Laramide history. The comparison of the reconstructed fluid overpressure values within situ measurements in various overpressure reservoirs in other oil-producing basins highlights that the supra-hydrostatic fluid pressure gradually reaches the lithostatic value during the whole basin contraction and fold development. During most of the LPS history, however, overpressure level can be defined by a mean gradient. Among the factors that control the pressure evolution, the mechanical stratigraphy, the stress regime under which fractures developed and regional fluid flow are likely dominating in the case of the Bighorn Basin, rather than classical factors like disequilibrium compaction or fluid generation during burial. A coeval evolution between fluid overpressure and differential stress build-up is also emphasized. The approach presented in this paper also provides estimates of strata exhumation during folding.     

Stress and pore pressure histories in complex tectonic settings predicted with coupled geomechanical-fluid flow models

Most of the methods currently used for pore pressure prediction in sedimentary basins assume one-dimensional compaction based on relationships between vertical effective stress and porosity. These methods may be inaccurate in complex tectonic regimes where stress tensors are variable. Modelling approaches for compaction adopted within the geotechnical field account for both the full three-dimensional stress tensor and the stress history. In this paper a coupled geomechanical-fluid flow model is used, along with an advanced version of the Cam-Clay constitutive model, to investigate stress, pore pressure and porosity in a Gulf of Mexico style mini-basin bounded by salt subjected to lateral deformation. The modelled structure consists of two depocentres separated by a salt diapir. 20% of horizontal shortening synchronous to basin sedimentation is imposed. An additional model accounting solely for the overpressure generated due to 1D disequilibrium compaction is also defined. The predicted deformation regime in the two depocentres of the mini-basin is one of tectonic lateral compression, in which the horizontal effective stress is higher than the vertical effective stress. In contrast, sediments above the central salt diapir show lateral extension and tectonic vertical compaction due to the rise of the diapir. Compared to the 1D model, the horizontal shortening in the mini-basin increases the predicted present-day overpressure by 50%, from 20 MPa to 30 MPa. The porosities predicted by the mini-basin models are used to perform 1D, porosity-based pore pressure predictions. The 1D method underestimated overpressure by up to 6 MPa at 3400 m depth (26% of the total overpressure) in the well located at the basin depocentre and up to 3 MPa at 1900 m depth (34% of the total overpressure) in the well located above the salt diapir. The results show how 2D/3D methods are required to accurately predict overpressure in regions in which tectonic stresses are important.     

Pore pressure assessment from well data and overpressure mechanism: Case study in Eastern Tunisia basins

Abstract

Independent and complementary methods were used for pore pressure assessment in the eastern Tunisian basins. Drilling data and surveys allow settling the pore pressure profile in these basins. The main used parameters are mud weights, formation pressure surveys, drilling parameters, well logs, fluids exchange with formation and borehole issues. In the eastern Tunisia platform, the pore pressure profiles show changes in overpressure magnitude in all the three dimensions of the basin (location and depth/stratigraphy). We highlighted two overpressure intervals form bottom to top: The late Cretaceous in the North-eastern part, and the Tertiary overpressure interval hosted in the Palaeocene to Miocene series. The structural analysis of overpressure location shows that the Tertiary interval is likely to have originated in a disequilibrium compaction in Cenozoic grabens. Pore pressure cross sections and maps confirm the link between active normal faults that segmented the basin to grabens and highs and pore pressure anomalous area. In the Senonian interval, we noted mature source-rocks that can explain the overpressure in the late Cretaceous interval. In addition, the recent to active compressive tectonics may have contributed to both pore pressure anomaly generations. The fluid overpressures characterization in the eastern Tunisian sedimentary basins helps in hydrocarbons exploration. Indeed, the overpressure interval in the reservoir levels stimulates and improves the production in the oilfields and contributes to hydrocarbon trapping. Moreover, the adequate prediction of pore pressure profile contributes to reduce drilling cost and enhance the drilling operations safety.     

Comparison of modern fluid distribution,pressure and flow in sediments associated with anticlines growing in deepwater (Brunei) and continental environments (Iran)

Differences in fluids origin, creation of overpressure and migration are compared for end member Neogene fold and thrust environments: the deepwater region offshore Brunei (shale detachment), and the onshore, arid Central Basin of Iran (salt detachment). Variations in overpressure mechanism arise from a) the availability of water trapped in pore-space during early burial (deepwater marine environment vs arid, continental environment), and b) the depth/temperature at which mechanical compaction becomes a secondary effect and chemical processes start to dominate overpressure development. Chemical reactions associated with smectite rich mud rocks in Iran occur shallow (∼1900 m, smectite to illite transformation) causing load-transfer related (moderate) overpressures, whereas mechanical compaction and inflationary overpressures dominate smectite poor mud rocks offshore Brunei. The basal detachment in deepwater Brunei generally lies below temperatures of about 150 °C, where chemical processes and metagenesis are inferred to drive overpressure development. Overall the deepwater Brunei system is very water rich, and multiple opportunities for overpressure generation and fluid leakage have occurred throughout the growth of the anticlines. The result is a wide variety of fluid migration pathways and structures from deep to shallow levels (particularly mud dykes, sills, laccoliths, volcanoes and pipes, fluid escape pipes, crestal normal faults, thrust faults) and widespread inflationary-type overpressure. In the Central Basin the near surface environment is water limited. Mechanical and chemical compaction led to moderate overpressure development above the Upper Red Formation evaporites. Only below thick Early Miocene evaporites have near lithostatic overpressures developed in carbonates and marls affected by a wide range of overpressure mechanisms. Fluid leakage episodes across the evaporites have either been very few or absent in most areas. Locations where leakage can episodically occur (e.g. detaching thrusts, deep normal faults, salt welds) are sparse. However, in both Iran and Brunei crestal normal faults play an important role in the transmission of fluids in the upper regions of folds.     

Reprint of: Comparison of modern fluid distribution,pressure and flow in sediments associated with anticlines growing in deepwater (Brunei) and continental environments (Iran)

Differences in fluids origin, creation of overpressure and migration are compared for end member Neogene fold and thrust environments: the deepwater region offshore Brunei (shale detachment), and the onshore, arid Central Basin of Iran (salt detachment). Variations in overpressure mechanism arise from a) the availability of water trapped in pore-space during early burial (deepwater marine environment vs arid, continental environment), and b) the depth/temperature at which mechanical compaction becomes a secondary effect and chemical processes start to dominate overpressure development. Chemical reactions associated with smectite rich mud rocks in Iran occur shallow (∼1900 m, smectite to illite transformation) causing load-transfer related (moderate) overpressures, whereas mechanical compaction and inflationary overpressures dominate smectite poor mud rocks offshore Brunei. The basal detachment in deepwater Brunei generally lies below temperatures of about 150 °C, where chemical processes and metagenesis are inferred to drive overpressure development. Overall the deepwater Brunei system is very water rich, and multiple opportunities for overpressure generation and fluid leakage have occurred throughout the growth of the anticlines. The result is a wide variety of fluid migration pathways and structures from deep to shallow levels (particularly mud dykes, sills, laccoliths, volcanoes and pipes, fluid escape pipes, crestal normal faults, thrust faults) and widespread inflationary-type overpressure. In the Central Basin the near surface environment is water limited. Mechanical and chemical compaction led to moderate overpressure development above the Upper Red Formation evaporites. Only below thick Early Miocene evaporites have near lithostatic overpressures developed in carbonates and marls affected by a wide range of overpressure mechanisms. Fluid leakage episodes across the evaporites have either been very few or absent in most areas. Locations where leakage can episodically occur (e.g. detaching thrusts, deep normal faults, salt welds) are sparse. However, in both Iran and Brunei crestal normal faults play an important role in the transmission of fluids in the upper regions of folds.     

A sub-salt structural model of the Kelasu structure in the Kuqa foreland basin,northwest China

The Kuqa foreland basin, adjacent to the South Tianshan Mountains, is a major hydrocarbon accumulation basin in Western China. The Kelasu structural belt is the focus for hydrocarbon exploration in the basin due to the presence of ramp-related anticline traps and a thick salt seal. The model of the Kelasu sub-salt structure is still contentious because of the structural complexity and poor seismic imaging below the salt layer. The area–depth–strain (ADS) method is applied to the southern part of the Kelasu Fault, a regional fault that cuts basement rocks. The ADS results are consistent with the seismic data, which indicate that both thin-skinned thrusting and basement-involved deformation occur within the Kelasu structure, with the Kelasu Fault acting as the boundary between the two regions of contrasting deformation. The ADS results also suggest that the depth of the lower detachment of the thin-skinned thrust belt is 9.5–10 km, which may correspond to the base of the Triassic. The Kelasu structure has undergone approximately 8.15–10.76 km of horizontal shortening in the east and 16.34 km in the west of the structure.     

缅甸睡宝盆地A井区古近系碎屑岩储层成岩作用与孔隙演化

首次分析睡宝盆地A井区古近系成岩演化序列并提出其储层处于中成岩A1-A2期,此成岩阶段有利于次生孔隙的保护。研究区古近系储层成岩演化序列具有特殊性：第一期胶结作用为硅质胶结,早于机械压实作用或者同时进行,强烈的机械压实作用使得孔隙度减小15%,此后第二期碳酸盐胶结作用占主导,镜下统计两期胶结作用的减孔量为4%~6%;渐新世受到挤压构造运动和表生成岩作用的双重影响,紧临渐新统不整合面以下的储层由于碳酸盐胶结物溶解而形成次生孔隙。2009年中海油新钻井地处冲起构造,后期的这种构造变形对始新统及其以下的核部地层产生侧向挤压形成构造压实效应,原始孔隙遭到更多的破坏,而对渐新统起到构造托举的作用,可以减缓上覆沉积物的静岩压实效应。成岩演化序列的特殊性和多期构造运动使得古近系储层物性出现差异,总结储集性好的储层并分析其成因机制,对睡宝盆地下一步勘探具有重要指导意义。     

Is stress-insensitive chemical compaction responsible for high overpressures in deeply buried North Sea chalks?

Chalk compaction is often assumed to be controlled by a combination of mechanical and effective stress-related chemical processes, the latter commonly referred to as pressure solution. Such effective stress-driven compaction would result in elevated porosities in overpressured chalks compared with otherwise identical, but normally pressured chalks. The high porosities that are frequently observed in overpressured North Sea chalks have previously been reported to reflect such effective stress-dependent compaction.However, several wells with deeply buried chalk sequences also exhibit low porosities at high pore pressures. To investigate the possible origins of these overpressures, basin modeling was performed in a selected well (NOR 1/3-5) offshore Norway. This modeling was based on both effective stress-driven mechanical porosity reduction, which enables modeling of disequilibrium compaction, and on stress-insensitive chemical compaction where the porosity reduction is caused by thermally activated diagenesis.The modeling has demonstrated that the present day porosities and pore pressures of the chalks could be successfully replicated with mechanical porosity loss as the only process leading to chalk porosity reduction. However, the modeled porosity and fluid pressure history of the sediments deviated significantly from the porosity and pore pressure versus depth relationships observed in non-reservoir North Sea chalks today. To the contrary, modeling which was based on thermally activated porosity loss due to diagenesis (as a supplement to mechanical compaction), resulted in modeled chalk histories that are consistent with present day observations.It was therefore inferred that disequilibrium compaction could not account for all of the pore pressure development in overpressured chalks in the study area. The observation that modeling including temperature-controlled diagenetic porosity reduction gave plausible results, suggests that such porosity reduction may in fact be operating in chalks as well as in clastic rocks. If this is correct, then improved methods for pore pressure identification and fluid flow analysis in basins containing chalks should be developed.     

Temporal changes of fault seal and early charge of the Maui Gas-condensate field,Taranaki Basin,New Zealand

Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.     

Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression,Bohai Bay Basin,China: New insights from fluid inclusions,natural gas geochemistry,and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, P_c = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (F_v) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.     

Compaction of diagenetically altered mudstones – Part 2: Implications for pore pressure estimation

Diagenetically altered mudstones compact mechanically and chemically. Consequently, their normal compaction trends depend upon their temperature history as well as on the maximum effective stress they have experienced. A further complication is that mudstones are commonly overpressured where clay diagenesis occurs, preventing direct observation of the hydrostatic normal compaction trend. A popular way to estimate pore pressure in these circumstances is to calculate the sonic normal compaction trend in a well with a known pressure–depth profile by applying Eaton's method in reverse, and then to estimate pore pressure in offset wells using Eaton's method conventionally. We tested this procedure for Cretaceous mudstones at Haltenbanken. The results were inconsistent because the sonic log responds differently to disequilibrium compaction overpressure and unloading overpressure, and their relative contributions vary across the basin. In theory, a two-step method using the density and sonic logs could estimate the contributions to overpressure from disequilibrium compaction and unloading. The normal compaction trend for density should be the normal compaction trend at the maximum effective stress the mudstones have experienced, not at hydrostatic effective stress. We advocate the Budge-Fudge approach as a starting point for pore pressure estimation in diagenetically altered mudstones, a two-step method that requires geological input to help estimate the overpressure contribution from disequilibrium compaction. In principle, the Budge-Fudge approach could be used to estimate the normal compaction trend for mudstones at the maximum effective stress they have experienced, and so form the basis of the full two-step method through the use of offset wells. Our initial efforts to implement the full two-step method in this way at Haltenbanken produced inconsistent results with fluctuations in estimated pore pressure reflecting some of the fluctuations in the density logs. We suspect that variations in the mineralogical composition of the mudstones are responsible.     

Geochemical evidence for coal-derived hydrocarbons and their charge history in the Dabei Gas Field, Kuqa Thrust Belt, Tarim Basin, NW China

Large to middle-scale thrust structures are important reservoir plays for coal-derived hydrocarbons in the foreland basins of NW China, with both gas and some accompanying oil. In the Dabei Gas Field of the Kuqa Thrust, however, the oil and gas pools are vertically distributed in a quite unique way: (1) liquid oil and some dissolved gas are present in the Dawanqi Anticline with the reservoir at 300-700 m depth, forming the only oil field in the Kuqa Thrust; (2) gas and minor accompanying oil are found in the deep reservoir of the Dabei-1 and Dabei-2 thrust traps around 5000-6000 m depth; (3) an extremely dry gas pool is found in the Dabei-3 thrust trap where the depth of the reservoir is over 7000 m. Geochemical data suggest that the hydrocarbons in the Dawanqi Anticline and the Dabei thrust traps originated from a similar source, i.e. the underlying Jurassic coal measures, with some contribution from Jurassic lacustrine shales. The Jurassic source rocks did not start to generate oil until the Miocene (around the Kangcun Stage), and extended into the Pliocene (the Kuche Stage) with the main gas generation period in the Pliocene (the Kuche Stage) and the Quaternary. Because the traps formed relatively early, the Dabei-1 and Dabei-2 thrusts could trap some of the early generated oils, but most of the early charged oil was redistributed to the shallower Dawanqi Anticline during the Kuche Stage. The Dabei-3 thrust trap formed concurrently with major gas generation and thus could not trap liquid hydrocarbons. The difference in the vertical distribution of the hydrocarbon accumulations in the Dabei Gas Field resulted from a complex interplay of source variability, structural evolution of the basin and thermal maturation.     

Controls on reservoir quality of Lower Cretaceous tight sandstones in the Laiyang Sag,Jiaolai Basin,Eastern China: Integrated sedimentologic,diagenetic and microfracturing data

The Jiaolai Basin (Fig. 1) is an under-explored rift basin that has produced minor oil from Lower Cretaceous lacustrine deltaic sandstones. The reservoir quality is highly heterogeneous and is an important exploratory unknown in the basin. This study investigates how reservoir porosity and permeability vary with diagenetic minerals and burial history, particularly the effects of fracturing on the diagenesis and reservoir deliverability. The Laiyang sandstones are tight reservoirs with low porosity and permeability (Φ < 10% and K < 1 mD). Spatial variations in detrital supply and burial history significantly affected the diagenetic alterations during burial. In the western Laiyang Sag, the rocks are primarily feldspathic litharenites that underwent progressive burial, and thus, the primary porosity was partially to completely eliminated as a result of significant mechanical compaction of ductile grains. In contrast, in the eastern Laiyang Sag, the rocks are lithic arkoses that were uplifted to the surface and extensively eroded, which resulted in less porosity reduction by compaction. The tectonic uplift could promote leaching by meteoric water and the dissolution of remaining feldspars and calcite cement. Relatively high-quality reservoirs are preferentially developed in distributary channel and mouth-bar sandstones with chlorite rims on detrital quartz grains, which are also the locations of aqueous fluid flow that produced secondary porosity. The fold-related fractures are primarily developed in the silt–sandstones of Longwangzhuang and Shuinan members in the eastern Laiyang Sag. Quartz is the most prevalent fracture filling mineral in the Laiyang sandstones, and most of the small-aperture fractures are completely sealed, whereas the large-aperture fractures in a given set may be only partially sealed. The greatest fracture density is in the silt–sandstones containing more brittle minerals such as calcite and quartz cement. The wide apertures are crucial to preservation of the fracture porosity, and the great variation in the distribution of fracture-filling cements presents an opportunity for targeting fractures that contribute to fluid flow.     

Middle to Late Cenozoic tectonic events in south and central Palawan (Philippines) and their implications to the evolution of the south-eastern margin of South China Sea: Evidence from onshore structural and offshore seismic data

Using recently gathered onland structural and 2D/3D offshore seismic data in south and central Palawan (Philippines), this paper presents a new perspective in unraveling the Cenozoic tectonic history of the southeastern margin of the South China Sea. South and central Palawan are dominated by Mesozoic ophiolites (Palawan Ophiolite), distinct from the primarily continental composition of the north. These ophiolites are emplaced over syn-rift Eocene turbidites (Panas Formation) along thrust structures best preserved in the ophiolite–turbidite contact as well as within the ophiolites. Thrusting is sealed by Early Miocene (∼20 Ma) sediments of the Pagasa Formation (Isugod Formation onland), constraining the younger limit of ophiolite emplacement at end Late Oligocene (∼23 Ma). The onset of ophiolite emplacement at end Eocene is constrained by thrust-related metamorphism of the Eocene turbidites, and post-emplacement underthrusting of Late Oligocene – Early Miocene Nido Limestone. This carbonate underthrusting at end Early Miocene (∼16 Ma) is marked by the deformation of a seismic unit corresponding to the earliest members of the Early – Middle Miocene Pagasa Formation. Within this formation, a tectonic wedge was built within Middle Miocene (from ∼16 Ma to ∼12 Ma), forming a thrust-fold belt called the Pagasa Wedge. Wedge deformation is truncated by the regionally-observed Middle Miocene Unconformity (MMU ∼12 Ma). A localized, post-kinematic extension affects thrust-fold structures, the MMU, and Late Miocene to Early Pliocene carbonates (e.g. Tabon Limestone). This structural set-up suggests a continuous convergent regime affecting the southeastern margin of the South China Sea between end Eocene to end Middle Miocene. The ensuing structures including juxtaposed carbonates, turbidites and shallow marine clastics within thrust-fold belts have become ideal environments for hydrocarbon generation and accumulation. Best developed in the Northwest Borneo Trough area, the intensity of thrust-fold deformation decreases towards the northeast into offshore southwest Palawan.     

2D modeling of overpressure in a salt withdrawal basin,Gulf of Mexico,USA

This study demonstrates the utilization of 2D basin models to address overpressure development due to compaction disequilibrium in supra-allochthonous salt mini-basins with very high sedimentation rates in the Gulf of Mexico. By properly selecting 2D line sections with moderate stratigraphic resolution, it is possible to predict timing of overpressure development and approximate present-day overpressure distributions in the mini-basin. This study shows that even low resolution models with approximate information on the net-to-gross (sand:shale ratio) can average ±0.4 ppg with a maximum error of 1.0 ppg relative to pressure measurements in sandstones. The models based on age, depth, approximate lithology and an interpretation of complicated salt movement are adequate to evaluate pressure to address issues around trap containment and may be used for preliminary well planning. This study tested the results of overpressure prediction utilizing different stratigraphic resolutions and shows the sensitivity of overpressure modeling to 2D line selection. Also, three models were built to investigate how the permeability of salt welds affects overpressure development in an adjacent salt mini-basin. These results indicate that even a salt weld permeability reduction of 1.5 log mD results in a pressure difference between neighboring mini-basins. Additionally, these models qualitatively reproduced the seismic velocity volume which is supporting evidence that the salt welds in this mini-basin are at least partially sealing.     

Physical modelling of chemical compaction,overpressure development,hydraulic fracturing and thrust detachments in organic-rich source rock

Geological evidence for overpressure is common worldwide, especially in petroleum-rich sedimentary basins. As a result of an increasing emphasis on unconventional resources, new data are becoming available for source rocks. Abnormally high values of pore fluid pressure are especially common within mature source rock, probably as a result of chemical compaction and increases in volume during hydrocarbon generation. To investigate processes of chemical compaction, overpressure development and hydraulic fracturing, we have developed new techniques of physical modelling in a closed system. During the early stages of our work, we built and deformed models in a small rectangular box (40 × 40 × 10 cm), which rested on an electric flatbed heater; but more recently, in order to accommodate large amounts of horizontal shortening, we used a wider box (77 × 75 × 10 cm). Models consisted of horizontal layers of two materials: (1) a mixture of equal initial volumes of silica powder and beeswax micro-spheres, representing source rock, and (2) pure silica powder, representing overburden. By submerging these materials in water, we avoided the high surface tensions, which otherwise develop within pores containing both air and liquids. Also we were able to measure pore fluid pressure in a model well. During heating, the basal temperature of the model surpassed the melting point of beeswax (∼62 °C), reaching a maximum of 90 °C. To investigate tectonic contexts of compression or extension, we used a piston to apply horizontal displacements.In experiments where the piston was static, rapid melting led to vertical compaction of the source layer, under the weight of overburden, and to high fluid overpressure (lithostatic or greater). Cross-sections of the models, after cooling, revealed that molten wax had migrated through pore space and into open hydraulic fractures (sills). Most of these sills were horizontal and their roofs bulged upwards, as far as the free surface, presumably in response to internal overpressure and loss of strength of the mixture. We also found that sills were less numerous towards the sides of the box, presumably as a result of boundary effects. In other experiments, in which the piston moved inward, causing compression of the model, sills also formed. However, these were thicker than in static models and some of them were subject to folding or faulting. For experiments, in which we imposed some horizontal shortening, before the wax had started to melt, fore-thrusts and back-thrusts developed across all of the layers near the piston, producing a high-angle prism. In contrast, as soon as the wax melted, overpressure developed within the source layer and a basal detachment appeared beneath it. As a result, thin-skinned thrusts propagated further into the model, producing a low-angle prism. In some experiments, bodies of wax formed imbricate zones within the source layer.Thus, in these experiments, it was the transformation, from solid wax to liquid wax, which led to chemical compaction, overpressure development and hydraulic fracturing, all within a closed system. According to the measurements of overpressure, load transfer was the main mechanism, but volume changes also contributed, producing supra-lithostatic overpressure and therefore tensile failure of the mixture.     

Dissolution mechanism of a deep-buried sandstone reservoir in a deep water area: A case study from Baiyun Sag,Zhujiang River (Pearl River) Mouth Basin

Dissolution mechanism and favorable reservoir distribution prediction are the key problems restricting oil and gas exploration in deep-buried layers. In this paper, the Enping Formation and Zhuhai Formation in Baiyun Sag of South China Sea was taken as a target. Based on the thin section, scanning electron microscopy, X-ray diffraction, porosity/permeability measurement, and mercury injection, influencing factors of dissolution were examined, and a dissolution model was established. Further, high-quality reservoirs were predicted temporally and spatially. The results show that dissolved pores constituted the main space of the Paleogene sandstone reservoir. Dissolution primarily occurred in the coarse- and medium-grained sandstones in the subaerial and subaqueous distributary channels, while dissolution was limited in fine-grained sandstones and inequigranular sandstones. The main dissolved minerals were feldspar, tuffaceous matrix, and diagenetic cement. Kaolinization of feldspar and illitization of kaolinite are the main dissolution pathways, but they occur at various depths and temperatures with different geothermal gradients. Dissolution is controlled by four factors, in terms of depositional facies, source rock evolution, overpressure, and fault activities, which co-acted at the period of 23.8–13.8 Ma, and resulted into strong dissolution. Additionally, based on these factors, high-quality reservoirs of the Enping and Zhuhai formations are predicted in the northern slope, southwestern step zone, and Liuhua uplift in the Baiyun Sag.