Main Gas Reservoirs Research Articles

An enhancement in the petrophysical evaluation in a vuggy carbonate gas reservoir by integrating the core data and empirical methods, Zagros basin, south of Iran

The presence of vuggy pore types poses challenges in accurately assessing effective porosity. This study focuses on the significant scientific issue of improving petrophysical evaluation in vuggy carbonate gas reservoirs. The Kangan Formation is one of the main gas reservoir formations in the southern Zagros region, Iran. The main objective of the current research is to distinguish and exclude the influence of vuggy pore types from effective porosity in the reservoir pay zones of the Kangan reservoir.In the current research, a combination of full suite logs, image logs, core analysis, and thin section studies was employed. The image logs illustrate that vuggy porosity is abundant in the Kangan Formation and these results are confirmed by the available core thin sections, specifically in Zone Kangan_B; Additionally, the cross plots of compressional velocity versus bulk density and total porosity, as a part of rock physics study, indicate the characteristics of the vuggy reservoir. Two methods are utilized to quantify vuggy porosity. The first method, the Velocity Deviation Log (VDL) approach, identifies various available pore types, especially vugs. The second method is a newly proposed approach that can exclude vuggy porosity from the computed effective porosity. In this novel approach, a variable porosity exponent (m) is derived by adopting the Lucia equation to exclude vuggy porosity from the effective porosity computations. Thus, petrophysical evaluation can be implemented based on the constant and variable “m”. Comparing both petrophysical results, it is evident that the amounts of effective porosity and water saturation are modified in the vuggy-bearing intervals. Applying the proposed approach will improve the accuracy of petrophysical properties and lead to the proper calculation of the hydrocarbon volume in the carbonate reservoir rocks containing isolated vugs, particularly in gas-bearing reservoirs where conventional logs are affected by gas contents.

Cloud properties across spatial scales in simulations of the interstellar medium

Molecular clouds (MCs) are structures of dense gas in the interstellar medium (ISM) that extend from ten to a few hundred parsecs and form the main gas reservoir available for star formation. Hydrodynamical simulations of a varying complexity are a promising way to investigate MCs evolution and their properties. However, each simulation typically has a limited range in resolution and different cloud extraction algorithms are used, which complicates the comparison between simulations. In this work, we aim to extract clouds from different simulations covering a wide range of spatial scales. We compare their properties, such as size, shape, mass, internal velocity dispersion, and virial state. We applied the Hop cloud detection algorithm on (M)HD numerical simulations of stratified ISM boxes and isolated galactic disk simulations that were produced using Flash Ramses and Arepo We find that the extracted clouds are complex in shape, ranging from round objects to complex filamentary networks in all setups. Despite the wide range of scales, resolution, and sub-grid physics, we observe surprisingly robust trends in the investigated metrics. The mass spectrum matches in the overlap between simulations without rescaling and with a high-mass power-law index of -1 for logarithmic bins of mass, in accordance with theoretical predictions. The internal velocity dispersion scales with the size of the cloud as $ $ for large clouds ($R pc $). For small clouds we find larger sigma compared to the power-law scaling, as seen in observations, which is due to supernova-driven turbulence. Almost all clouds are gravitationally unbound with the virial parameter scaling as $ vir $, which is slightly flatter compared to observed scaling but in agreement given the large scatter. We note that the cloud distribution towards the low-mass end is only complete if the more dilute gas is also refined, rather than only the collapsing regions.

A correction factor for the resistivity log in gas reservoirs with low resistivity pay zone in the Poti Formation, Parnaiba Basin, Brazil

The Parnaiba Basin, even being a new frontier basin, it’s already one of the most profitable for natural gas in Brazil. The shallow marine sandstones of the Poti Formation are the main gas reservoirs at Park of the Hawks. These reservoirs hold anomalously low resistivities which directly impacts water saturation calculations and leading to underestimations of their true potential as gas reservoirs. We propose a method for the characterization and mitigation of the problem and for the correction of the resistivity log based on the case study of well PGN-5, seeking to obtain more adjusted results for the reservoir evaluation. The methodology used is based on the integration data, where the main inputs were drill cuttings samples, well logs, gamma-spectral data and geochemical analyzes through X-rays fluorescence. We observed that the presence of pyrite and clay minerals are the causes of the low resistivities, still in the presence of gas-charged intervals, attested by crossover between density and neutron logs and through pressure gradients data. We propose a correction factor for the resistivity log in the anomalous low resistivity zone, allowing a new evaluation of the well, leading to a significant reduction in water saturation and a remarkable net pay gain.

Prediction of interwell connectivity and interference degree between production wells in a tight gas reservoir

Sulige gas field has poor reservoir physical properties and strong heterogeneity. The existing development well pattern is difficult to realize the overall effective production of reserves, especially in block SuX. Therefore, this paper takes SuX block in the east of Sulige as an example to describe an effective method suitable for the development of well pattern in this area. Combined with logging and production data, the connectivity of gas wells in X infill area in the east of Sulige is determined from the aspects of pressure, sand body, logging, performance and well test. By using the method of dynamic and static analysis, the connectivity between wells of main gas reservoir is judged. Through the analysis of flow unit, the discharge area and the stable value of well-controlled reserves are determined. The degree of interference determined by curve fitting and the distribution characteristics of sand bodies are comprehensively analyzed. A new oil well interference degree model defined by mathematical expression of production is established. The interference degree is quantified by gas production through numerical simulation. Based on the comprehensive analysis of the connectivity, interference degree and other factors in the area, it is determined that 500 * 600 well pattern is a reasonable well pattern in SuX block, and the interference degree is about 20%. Based on the analysis of the connectivity between wells and the interference degree between production wells in SuX block, the distribution and connectivity of sand bodies in tight sandstone gas field under complex geological conditions are determined. It provides a reasonable basis for the network encryption development of tight sandstone gas in this block. It provides a powerful technical support for the efficient development of different tight gas reservoirs in Sulige area.

Reconstruction of rapid charge of a giant gas field across a major fault zone using 3D petroleum systems modelling (Taranaki Basin, New Zealand)

The timing of petroleum charge, especially in structurally complex basins, is often poorly defined, with few data to constrain petroleum systems models. In this study we reconstruct in detail the evolution of the >6 Tcf Maui Field, a mature gas-condensate field in the southern Taranaki Basin, northwestern New Zealand. Structural restoration suggests that closure developed between 6 and 5.3 Ma. Maturation modelling shows that charge of the main gas reservoir is only feasible from the nearby Maui sub-basin kitchen, across a major fault zone, the Cape Egmont Fault Zone (CEFZ). We apply petroleum systems modelling to predict timing and amount of charge using a reconstructed distribution of shaly fault rock as an approximation of fault permeability. Models reproducing the variable oil and gas accumulations in different areas of the field suggest that the field was charged within 4 Myr. This supports the notion that connected permeability exists even across large fault zones, allowing charge in geologically short times frames. Models using a range of fault and carrier bed properties suggest that presence of connected sandy carrier beds linking the fault zone with reservoirs is essential for petroleum migration. Predicted migration pathways occur through outer parts of the CEFZ characterized by greater architectural complexity as well as through the central area of the CEFZ with the largest offset. This suggests that the impact of shale-rich fault rock on petroleum migration across large fault zones is smaller than commonly expected. In particular, in deeper parts of the basin, a major fault zone can provide sufficient permeability to be the preferred pathway for vertical migration. These results illustrate that despite the complexity of migration pathways, petroleum migration can occur in geologically short time.

Distribution law of helium in Leshan-Longnvsi paleo-uplift in Sichuan Basin, China

The Weiyuan and Anyue large gas fields discovered on the Leshan-Longnvsi paleo-uplift in Sichuan Basin have the oldest marine gas reservoir discovered in China so far, and Weiyuan is also the first gas field to utilize helium resources in China. The Helium in natural gas of Leshan-Longnvsi paleo-uplift belongs to crust-derived helium formed by radioactivity, and its content distribution shows obvious regularity. The content of helium is highly correlated with the age of reservoir in the same gas field, and the helium content is gradually increased from the top to the bottom. However, the content of helium in natural gas presents significantly different in various tectonic units. The content of helium in Anyue gas field developed on Gaoshiti-Moxi structure is very low. The average contents of Sinian and Cambrian are 0.0356% and 0.0078%, respectively. The content of helium in Weiyuan gas field developed on Weiyuan structure is relatively higher, and the average contents of Sinian and Cambrian are 0.28% and 0.18% respectively. The high helium content of natural gas in Weiyuan gas field is related to the large-scale granite body developed on the basement on the one hand and the water-soluble gas accumulation on the other hand. The main gas reservoirs in the Weiyuan gas field and adjacent areas are located in the Sinian system. From the slope area to the high point of the Weiyuan structure, the helium content has increased significantly. With the tectonic movement of the Himalayan period, the Weiyuan area is greatly uplifted, causing structural traps. Natural gas dissolved in the water, including helium gas, is decomposed by decompression, and the released gas is trapped, then released gases accumulated in traps and thus formed Weiyuan gas field with high content of helium.

Sources of quartz grains influencing quartz cementation and reservoir quality in ultra-deeply buried sandstones in Keshen-2 gas field, north-west China

Quartz cementation is a critical factor in the reservoir quality of ultra-deeply buried sandstones because of the high temperature and high-pressure at great depths. Therefore, determining the main influences retarding the growth of the quartz overgrowths is important for predicting the sweet spots of tight gas sandstones. The vast Keshen-2 gas field in Kuqa Depression is typical of such ultra-deep gas fields, despite the porosity and permeability of the target sandstones in the Lower Cretaceous Bashijiqike Formation being less than 10% and 0.5 md, respectively. The main gas reservoirs had been buried previously to a depth of 7000 m, with the maximum fluid temperature approaching 160 °C, in which authigenic quartz cements are extremely common. The heterogeneity of the physical properties and quartz cementation was investigated using core analysis, log interpretation, thin sections and scanning electron microscopy (SEM). The findings indicated that the Bashijiqike Formation could be stratified into upper porous and lower tight zones. The porosity of the sandstones in the upper zone is generally higher than 5% and abundant polycrystalline quartz grains are present. However, the reservoirs in the lower zone with low overall porosity values below 5%, contain high contents of monocrystalline quartz grains. The polycrystalline quartz grains show brown cathodoluminescence that indicates mainly a metamorphic source from the southern Tianshan provenance which is located to the north of Keshen-2. The monocrystalline quartz grains display primarily blue to violet luminescence colours, suggesting an origin from volcanic or plutonic mother rocks of the Wensu and Kuluketage provenance areas, situated to the southwest and southeast, respectively. The monocrystalline quartz grains are surrounded commonly by quartz overgrowths, whereas the polycrystalline quartz grains are cemented slightly. The presence of polycrystalline quartz grains hampers potential quartz overgrowths—the critical reason preserving the intergranular pores in the ultra-deeply buried sandstones of this gas field. Accordingly, we propose that the metamorphic quartz grain content is the main factor inhibiting quartz cementation, which preserves reservoir quality. This knowledge is conducive to determining the growing mechanism of high-quality reservoirs and predicting the sweet spots of gas production in the ultra-deeply buried sandstones.

Reservoir heterogeneity and quality of Khuff carbonates in outcrops of central Saudi Arabia

The Khuff carbonates host several main gas reservoirs in the Middle East. These reservoirs are known for their heterogeneity, both of sub-seismic scale and beyond the interwell spacing. To get a better insight in these reservoirs, the heterogeneity of the Upper Khartam Member, placed in a high-frequency sequence stratigraphic framework, was studied with a lateral resolution between logged sections of 5 m. The sedimentology and sequence stratigraphy of four outcrop localities were studied, and approximately 600 samples were collected for petrographic, porosity and permeability analyses.Seventeen lithofacies types were recognised and six major diagenetic processes could be differentiated in the studied outcrops. Dissolution is likely the result of intensive circulation of meteoric water undersaturated with respect to calcite. Significantly, cementation has blocked most of the original intergranular porosity. Pore lining detrital clay severely impacted reservoir permeability and complicated the pore geometry. Dolomitization is associated with the upper Khuff–Sudair boundary, and is likely the result of influx of water highly saturated with Mg+2 that developed during the deposition of the Sudair evaporites. Finally, stylolites are to a major extend controlled by lithofacies and geobody configuration. Ten porosity types could be namely: intergranular, intragranular, shelter, dissolution-enlarged, moldic, vuggy, micro-porosity, and porosity in relation to dolomite–dedolomite, dolomite-leaching, and fracture development. Overall intertidal creeks are characterized by a complex and heterogeneous pore geometry if compared to the intertidal channels, and this can be attributed to the geobody architecture, with intertidal creeks being composed of dense and small tidal bodies (1 m in length and 20 cm in thickness), while intertidal channels are composed of thick amalgamations of intertidal channels (5 m by 50 cm). Most critically, the horizontal reservoir quality was influenced differentially by diagenesis, which resulted in a lateral segmentation of single bodies into different, hydraulic units. The differential mold-filling calcite cements have significantly reduced porosity and permeability. Generally, mineral content has little impact on the reservoir quality, although clay minerals played a central role in lining the pore space and affecting permeability. Finally, horizontal reservoir heterogeneity seems to have been controlled by fractures and stylolites which respectively acted as conduits to and barriers for vertical fluid flow and, hence, controlled the differential cementation and dissolution processes.

The study of deep water submarine reservoir in Bangle Bay Basin

ABSTRACTAlthough the huge potential of the Bangle Bay Basin has been proven by a series of discoveries, recent drilling and other studies still have not demonstrated the mechanism of hydrocarbon accumulations in Bangle Bay Basin because of the low exploration degree and less geological data available. So, it is difficult to identify and predict the distribution patterns of the main gas reservoir by now. Based on a review of previous work and the latest exploration activities in the study area, the depositional environment and reservoir distribution had been discussed, and thereby assess the location of reservoir–seal couplets for the purposes of stratigraphic traps identification and prospect evaluation within the study area. This paper has also discussed the sequence stratigraphic framework, depositional environment, and facies features by using the biostratigraphic, geochemical analyses and wireline, image logs data. Various broad depositional environments and depositional subsettings have been identified or updated, meanwhile some new environment modeling had been proposed. In this article, reservoir geology study had been conducted after regional depositional feature analysis. Reservoir architecture had been summarized as mouthbars, submarine canyon fill, submarine channels, and levees. Most prospective reservoir intervals identified within the study area are in the Lower Pliocene, Upper Pliocene, and Lower Pleistocene formations.

Sedimentary Microfacies and Porosity Modeling of Deep‐Water Sandy Debris Flows by Combining Sedimentary Patterns with Seismic Data: An Example from Unit I of Gas Field A, South China Sea

AbstractSandy debris flow deposits are present in Unit I during Miocene of Gas Field A in the Baiyun Depression of the South China Sea. The paucity of well data and the great variability of the sedimentary microfacies make it difficult to identify and predict the distribution patterns of the main gas reservoir, and have seriously hindered further exploration and development of the gas field. Therefore, making full use of the available seismic data is extremely important for predicting the spatial distribution of sedimentary microfacies when constructing three‐dimensional reservoir models. A suitable reservoir modeling strategy or workflow controlled by sedimentary microfacies and seismic data has been developed. Five types of seismic attributes were selected to correlate with the sand percentage, and the root mean square (RMS) amplitude performed the best The relation between the RMS amplitude and the sand percentage was used to construct a reservoir sand distribution map. Three types of main sedimentary microfacies were identified: debris channels, fan lobes, and natural levees. Using constraints from the sedimentary microfacies boundaries, a sedimentary microfacies model was constructed using the sequential indicator and assigned value simulation methods. Finally, reservoir models of physical properties for sandy debris flow deposits controlled by sedimentary microfacies and seismic inversion data were established. Property cutoff values were adopted because the sedimentary microfacies and the reservoir properties from well‐logging interpretation are intrinsically different. Selection of appropriate reservoir property cutoffs is a key step in reservoir modeling when using simulation methods based on sedimentary microfacies control. When the abnormal data are truncated and the reservoir properties probability distribution fits a normal distribution, microfacies‐controlled reservoir property models are more reliable than those obtained from the sequence Gauss simulation method. The cutoffs for effective porosity of the debris channel, fan lobe, and natural levee facies were 0.2, 0.09, and 0.12, respectively; the corresponding average effective porosities were 0.24, 0.13, and 0.15. The proposed modeling method makes full use of seismic attributes and seismic inversion data, and also makes the property data of single‐well depositional microfacies more conformable to a normal distribution with geological significance. Thus, the method allows use of more reliable input data when we construct a model of a sandy debris flow.

Interplay between an axial channel belt, slope gullies and overbank deposition in the Puchkirchen Formation in the Molasse Basin, Austria

AbstractDeep‐water sediments in the Molasse Basin, Austria, were deposited in a narrow foreland basin dominated by a large channel belt located between the steep Alpine fold and thrust belt to the south and the gentler northern slope off the Bohemian Massif. Several gas fields occur outside the channel belt, along the outer bend of a large meander. Accumulation of these overbank sediments reflects a complicated interplay between slope accommodation and debris‐flow and turbidity‐flow interaction within the channel. The tectonically oversteepened northern slope of the basin (ca 2 to 3°) developed a regionally important erosional surface, the Northern Slope Unconformity, which can be traced seismically for >100 km in an east–west direction and >20 km from the channel to the north. The slope preserves numerous gullies sourced from the north that eroded into the channel belt. These gullies were ca 20 km long, <1 km wide and ca 200 m deep. As the channel aggraded, largely inactive and empty gullies served as entry points into the overbank area for turbidity currents within the axial channel. Subsequently, debris‐flow mounds, 7 km wide and >15 km long, plugged and forced the main channel to step abruptly ca 7 km to the south. This resulted in development of an abrupt turn in the channel pathway that propagated to the east and probably played a role in forming a sinuous channel later. As debris‐flow topography was healed, flows spread out onto narrow area between the main channel and northern slope forming a broad fine‐grained apron that serves as the main gas reservoir in this area. This model of the overbank splay formation and the resulting stratigraphic architecture within the confined basin could be applied in modern and ancient systems or for subsurface hydrocarbon reservoirs where three‐dimensional seismic‐reflection data is limited. This study elucidates the geomorphology of the oversteepened slope of the under‐riding plate and its effects on the sedimentation.

Characteristics and accumulation mechanisms of the Dongfang 13-1 high temperature and overpressured gas field in the Yinggehai Basin, the South China Sea

The Dongfang 13-1 is located in the diapiric structure belt of the Yinggehai Basin. The formation pressure of its main gas reservoir in the Miocene Huangliu Formation is up to 54.6 MPa (pressure coefficient=1.91) and the temperature is as high as 143°C (geothermal gradient 4.36°C/100 m), indicating that it is a typical high-temperature and overpressured gas reservoir. The natural gas is interpreted to be coal-type gas derived from the Miocene mature source rocks containing type II2–III kerogens as evidenced by high dryness index of up to 0.98 and heavy carbon isotopes, i.e., the δ13C1 ranging from −30.76‰ to −37.52‰ and δ13C2 ranging from −25.02‰ to −25.62‰. The high temperature and overpressured Miocene petroleum system is related mainly to diapir in the Yinggehai Basin and contains more pore water in the overpressured reservoirs due to undercompaction process. The experimental and calculated results show that the solubility of natural gas in formation water is as high as 10.5 m3/m3 under the temperature and pressure conditions of the Sanya Formation, indicating that at least part of the gas may migrate in the form of water-soluble phase. Meanwhile, the abundant gas source in the Basin makes it possible for the rapid saturation of natural gas in formation water and exsolution of soluble gas. Therefore, the main elements controlling formation of the Dongfang 13-1 gas pool include that (1) the diapir activities and accompanying changes in temperature and pressure accelerate the water-soluble gas exsolution and release a lot of free gas; (2) submarine fan fine sandstone in the Huangliu Formation provides good gas-water segregation and accumulation space; and (3) the overlying overpressured mud rocks act as effective caps. The accumulation mechanism reveals that the high temperatural and high pressure structure belt near the diapir structures has a good potential for large and medium-sized gas field exploration.

Subsurface Miocene sequence stratigraphic framework in the Nile Delta, Egypt

The Miocene depositional history of the Nile Delta is dominated by fluvial–deltaic, marginal marine and marine shelf sedimentation. It exhibits radical lateral facies changes due to its tectonic setting. Different attributions in age assignments characterise the Miocene Nile Delta due to the lack of large vertical facies changes, which consists mainly of siliciclastic with different environments. This study uses integrating lithologic, biostratigraphic, gamma-ray log and benthic foraminiferal biofacies, at four boreholes (Tanta-1, Rommana-1X, El-Fayrouz and Rosetta-7) in the Nile Delta, Egypt. Planktonic foraminifera allow subdivision of the Miocene Nile Delta succession into 12 planktonic biozones and benthic species are used in paleobathymetic estimates.Eight third-order Nile Delta Miocene sequences are bounded by eight major sequence boundaries, that can be correlated within and outside Egypt based upon planktonic foraminifera biostratigraphy. Chattian/Aquitanian (SB1) and Aquitanian/Burdigalian (SB2), intra-Burdigalian (SB3), Burdigalian/Langian (SB4), Langian/Serravallian (SB5), Serravallian/Tortonian (SB6) Tortonian/Messinian (SB7) and intra-Messinian (SB8): these boundaries in the Nile Delta are controlled by either eustatic processes and/or tectonic events.Each sequence contains a transgressive system tract bounded above by a maximum-flooding surface, and a highstand system tract. The lowstand systems tract and falling-stage systems tract is the main gas reservoir in the Nile Delta and recorded only below the Tortonian/Messinian and intra-Messinian sequence boundaries, that are marked by deep incisions and truncations. Variable patterns in the timing of regional deposition and erosion indicate different tectonic and sedimentary regimes, that encompass progressively greater periods of time southward in the Nile Delta.

The Bazhenovo formation as a source of economic oils and rich gases in the Tithonian-Neocomian section of the South Kara Region

The main gas reservoir in the South Kara region that comprises Arctic areas of the West Siberia petroliferous basin and adjacent shelf is represented by the Aptian-Cenomanian productive sequence, which encloses unique and large gas and gas condensate fields discovered at depths up to 2.5 km: Urengoiskoe, Yamburgskoe, Medvezh'e, Zapolyarnoe, Novopor� tovskoe, Rusanovskoe, Leningradskoe, and others. In recent decades, large fields were discovered in the same sequence in the Ob and Taz estuaries region: Kamennomysskoemore, SeveroKamenomysskoe, Chugor'yakhinskoe, and others. At the same time, resources of cheap dry gas in easily accessible accumu� lations are not inexhaustible, and in the near future, mankind should purposefully develop deeper forma� tions, which contain, in the opinion of many research� ers, accumulations of rich gas and gas condensate with potential fringes of light oils. In the context of this problem, of interest are the results of the geochemical analysis of the Bazhenovo Formation (Tithonian-lower Berriasian), which is characterized by very high concentrations of plankto� nogenic organic matter and represents a main genera� tor of oils in the central and western parts of the West Siberian petroliferous basin. The unique enrichment of this unit with organic matter should also be charac� teristic of high latitude areas, since similar highcar� bonaceous sediments associated with frequently global anoxic events were deposited in the terminal Late Jurassic epoch through many petroliferous basins (North Sea, West Norwegian, Barents Sea, West Sibe� rian, Northern slope of Alaska, Mackenzie, Sverdrup, Jenna D'Arcy), where similar sequences became sources of the economic oil potential. The Bazhenovo Formation is composed of carbon� ate-siliceous-clayey bituminous sediments with high concentrations of planktonogenic organic matter (average Corg contents 5.1% and up to 30% in some layers) (1). By analogy with domanikites, these sedi� ments are called bazhenovites. They are distributed practically throughout the entire basin, where average Corg and bitumoid concentrations increase from 1 to 11% and from 0.3 to >1.0%, respectively, from its periphery toward the inner deepwater parts. The comparison of the lithological-mineralogical characteristics of rocks and the concentrations and composition of enclosed organic matter with the data obtained by the standard and radioactive logging (SL and GL) revealed certain correlations between terrig� enous, biogenic-terrigenous, and biogenic compo� nents of the Bazhenovo Formation, on the one hand, and the SL and GL values, on the other (2). The defined correlation between these parameters served as a basis for classification of bazhenovite sections and their largescale mapping. The sections with members of highresistance siliceous, carbonate, and siliceous- carbonate sapropelic-clayey rocks confined to depressions and slopes of uplifts are considered to be most favorable for the formation of oil pools. In such sections, organic matter is almost entirely represented by colloalgenite and contains 7.0-8.5% of hydrogen, while microcavities in rocks are frequently filled with oil. Perrozio and Predtechenskii (2) proposed in 1985 the notion "radiolarian paleoabundance," which des� ignates the sum of their visible remains concentrated in the form of small lenses and laminae or present as single skeletons as well as residual cavities through the whole rock volume after their dissolution. It was estab� lished that the radiolarian paleoabundance of

Geochemical characteristics, forming conditions and resource evaluation of oil-cracking gas as exemplified by the platform area of the Tarim Basin

Based on the geochemical characteristics of oil-cracking gas and kerogen-cracking gas revealed by simulation experiments and the chemical composition of natural gases in actual gas reservoirs, two kinds of natural gases with different relationships between C2/C3 and C1/C2, C2/C3 and C1/C3, C2/C3 and 100×C1/(C1–C5) were identified in the Tarim Basin, and proposed further by the authors. The relationship charts of C2/C3 and C1/C2, C2/C3 and C1/C3, C2/C3 and 100×C1/(C1–C5) can be used to effectively distinguish oil-cracking gas from kerogen-cracking gas. Petroleum geological analysis of the oil-cracking gas reservoirs showed that the distribution of oil-cracking gas is mostly related with deep-seated faults or faults with a large fault throw, and the burial depth of paleo-oil reservoir is relatively high; crude oil-cracking gas resources have been evaluated by using both forward and inversion methods. The plots of C2/C3 vs. C1/C2, C2/C3 vs. C1/C3, and C2/C3 vs. 100×C1/(C1–C5) were used to distinguish between oil-cracking gas and kerogen-cracking gas, and estimate the mixed ratios of the two kinds of natural gases in the main gas reservoirs of the platform area.

Detection of gas reservoirs by the joint use of P- and PS-waves: A case study on the Ordos basin, China

We present an example of using converted-waves for characterizing onshore gas reservoirs in the Ordos basin in Northwest China. The Ordos basin is the largest gas province in China. The main gas reservoirs (about 3 300 m in depth) are in upper Paleozoic sandstone that has low or reversed P-wave impedance and is immediately above a coal seam. This makes it very difficult to image the gas reservoirs using conventional P-wave data. Analysis of core, log and VSP data shows a weak PP reflection but a relatively strong PS-converted wave reflection, or both strong PP- and PS-reflections but with opposite polarity from the gas bearing sands, which indicates the potential of using PS-waves to image the gas reservoirs in the Ordos basin. Subsequently, thirteen seismic lines were acquired, processed and interpreted to verify the PP- and PS-responses, and two corresponding attributes (PP- and PS- amplitude ratio and polarity ratio) are used to map the reservoirs through joint PP and PS analysis.

Seismic facies and reservoir characteristics of a deep-marine channel belt in the Molasse foreland basin, Puchkirchen Formation, Austria

Oligocene–Miocene deep-water deposits of the Puchkirchen and basal Hall formations contain the main gas reservoirs of the Austrian Molasse Basin. A new seismostratigraphic model, based on a 2000-km2 (772-mi2), regional, three-dimensional (3-D) seismic data set, has fundamentally changed our understanding of the depositional processes and reservoir distribution in this classic deep-water foreland basin. Regional 3-D seismic attribute maps, calibrated by nearly 350 wells, reveal that sedimentation occurred primarily within the confines of a large (3–5 km [1.8–3.1 mi] wide by 100 km [62 mi] long), low-sinuosity channel belt that occupied the Molasse Basin foredeep. The channel fill consists predominantly of turbiditic conglomerate and sandstone, as well as chaotic slump and debris-flow deposits. Overbank areas are characterized by fine-grained turbiditic sandstone and mudstone. Incised canyons and ponded slope fans were active along the southern basin margin; lateral tributary channels intersected the axial channel belt in the north. Significant accumulations of gas are stratigraphically and structurally trapped in channel thalweg and slope-fan sandstones, with more modest amounts in overbank lobe and tributary-channel deposits. Basin geometry had a profound effect on the architecture of the channel belt and subsequent sediment distribution. Large-scale deep-water channel systems are poorly documented from foreland basins; the depositional model developed for the Puchkirchen Formation was made possible through the use of high-quality seismic data and an extensive drill-core database. The depositional model may be a useful analog for other elongate, deep-water basins, especially those that lack extensive, modern data sets.

Opon Gas Renews Interest in the Hydrocarbon Prolific Middle Magdalena Basin, Colombia: ABSTRACT

A total of 45 fields have been discovered in the Middle Magdelena basin of Colombia since 1918. In August 1994, the Amoco-operated Opon-3 well tested significant hydrocarbons in the basin. The well flowed 45 MMCFGPD and 2000 BCPD from 1118 ft of perforations between 10,018 and 12,348 feet. A second well, Opon-4, tested 58 MMCFGPD from the same interval. Opon now appears to be a significant gas condensate field. A full assessment of commercial potential requires 3D seismic data, as well as further development drilling. Operational challenges include: drilling, coring, logging, cementing and testing in a world-record setting 23 ppg hematite-weighted mud environment involving simultaneous perforation over a 2330 ft gross pay interval and management of high production rates at >8000 psi FwHP. The Opon structure is a surface anticline on the western edge of the Eastern Cordillera fold and thrust belt. Seismic definition of the trap, however, is complicated by multiple faults, steep dips, rugged topography and variable surface velocities. The main gas reservoirs are fluvial sandstones of the Eocene La Paz Formation sealed by the overlying upper Eocene Las Esmeraldas Formation shales. Individual producing sandstones range from 40 to 200 ft thick in a minimum gross gas columnmore » of 4200 ft. Average porosity is 6%. Tectonically induced fractures probably enhance reservoir performance.« less

Kubiki Gas Field

In 1959, a new gas field was discoverd in the Kubiki district of south-western Niigata Prefecture. The Katamachi, Meiji, Kuroi and Asahi gas fields are included in this gas producing region. Ten exploration wells were drilled in this area between 1936 and 1941. Although all were abandaned because no oil was found, strong gas indications appeared in some of these wells. After gravity and seismic surveys, the first gas accumulation was found in the Meiji field in 1954 by the Teikoku Oil Company, and in 1959 extensive exploration activities were rewarded by discovery of the Katamachi and Kuroi gas fields.These gas fields are stracturally a domal anticline. The axis of the Katamachi and Kuroi structure lines off the coast, and extends along the coast line. The main gas reservoir is the sand lenses of the Teradomari black shale formation of the upper Miocene. The physical characteristics of these sands are variable, but a 100 millidarcy air permeability, a 30 percent porosity and a 40-65 percent interstitial water saturation can be regarded as average. The composition of the gas is 95 percent or more methane with very few heavy hydrocarbons. Recently, heavy oil was discovered within these gas reservoirs. The total gas reserve in the Kubiki region is estimated to be 4, 667 million cubic meters.