Gas-bearing Sands Research Articles

Assessing the hydrocarbon potential of the Kadanwari gas field using integrated seismic and petrophysical data

Kadanwari is a major gas-producing field in Pakistan's Lower Indus Basin (LIB), extensively explored for optimized production. However, the reservoir sands of the Lower Goru Formation (LGF), deposited in a complex river-dominated delta, bear severe variability and hinder accurate facies approximation for optimal production. Furthermore, the regionally extended NNW-SSE directed horst and graben structures significantly compartmentalized these reservoir facies. The main E-sand interval is analyzed for its geological properties, depositional environment, and distribution. The integration of various approaches, including seismic interpretation, attribute extraction, well-based facies modeling, and petrophysical evaluation, proved significant in evaluating the heterogeneous and tectonically influenced E-sands. The discontinuity attribute substantially highlighted the structural style and aided in analyzing the geometries of faults. The low values of the frequency attribute (< 10 Hz) signified the entrapped gas-bearing sands along the faulted zones. The high responses of instantaneous amplitude and sweetness profoundly illuminated the gas-significant deposits throughout the field in association with the well-identified gas-prone sand facies. The outcomes of the neutron-density crossplot depicted gas-bearing sands having low density (< 2.3 g/cc) and good porosity (12%) with the assessment of various cements. The facies modeling distinguished between clean and intermixed sand-shale reservoir zones. Petrophysical analysis revealed a net pay of 14 m within E-sand having gas saturation of about 68%. The adopted approach is robust and efficient, employing a limited data set for developing well-associated seismic responses for potential zone delineation within structural arrangements. The techniques can be optimistic about the LGF's complex potential sands demarcation throughout the Indus Basin.

Evaluation of seismic responses from well-associated gas producing sands using integrated approaches for optimal field production in Zamzama gas field, Pakistan

The producing fields often observe early decline due to many misapprehended factors concerning structural interpretation, facies identification, and proper estimation of geological properties. The accuracy of the estimation of these characteristics is critical for enhanced recovery. An integrated approach based on well identified potential lithofacies distribution in relation to seismic trace responses and accurate fluid estimation is vital. In the present study, gas-bearing sands are appraised for their reservoir characteristics within a complex anticline structure. The faulted anticline's hanging wall provided suitable locations for optimum gas entrapment; however, its connection with the footwall through lateral ramps allows the aquifer's early encroachment into the reservoir. For enhanced recovery, the combination of well-derived petrophysical parameters with seismic extracted responses provided insight into the producing facies with quantitative fluids identification using fluid replacement modeling (FRM) and their amplitude variation with offset (AVO) responses. The reliable AVO responses of substituted fluids comprising 85% gas with 15% brine are observed for identified potential sands, classifying sands as class-II. Similarly, the intercept (A), gradient (B), and product (A*B) of angle dependent seismic traces were mapped within the Pab Formation and showed amplitude anomalies for porous channelized gas-bearing sands. Finally, crossplotting intercept-gradient volumes differentiated the gas-bearing sands and precisely demarcated the identified gas sands throughout the field, with confirmation at producing well locations. Hence, the integrated assessment of the outcomes resulting from structural interpretation, petrophysical evaluation, and seismic trace valuation can be readily employed for distinguishing the producing sand facies in complex structures and demarcating risk-efficient zones.

Integrating seismic attributes, post-stack seismic inversion, and static modeling for assessing the Pliocene-Pleistocene hydrocarbon potentialities, Offshore North Sinai Field, Egypt

Optimal gas production from marginal fields vulnerable to tidal energetic effects is exceedingly challenging. Conventional seismic analysis is insufficient for a significant understanding of the geomorphological description, volumetric calculations, and microfacies analysis of the anticipated heterogeneous gas-bearing sands. New insights into the offshore North Sinai (ONS) Field based on quantitative and geostatistical interpretations integrated with physical and geometrical attribute analyses are boosted for reconstructing diverse-scale reservoir internal architecture.Deterministic band-limited inversion using acoustic impedance logs contributed to the initial knowledge of facies migration during tidal-dominated delta progradation and revealed four 2nd-order sequence boundaries dependent on P-velocity variations with depth as a function of rock elasticity, low impedance gas content of 2500–3000 kPa s/m and overburden compressional factors. Gradual boundaries confining reservoir bases due to spatiotemporal facies discrepancies triggered the implementation of stochastic algorism as a model norm for tracing thin-bedded and internal heterogeneous reservoirs with no predictable gas-water contacts across subtle dismantled areas. Stochastic inversion with intensive layering below −1 ms along with static property reservoir modeling allowed the evaluation of both fine and coarse-scale reservoirs discovered as extensions of injector-controlled stacked mouth bars, fan-lobes, and distributary channels crosscutting tidal mudflats of delta top facies associations within a system of spatially migrated clinoforms to the north. Stream avulsion-induced and accommodation space inconsistencies across syn-sedimentary faults caused the shifting of the Late Plio-Pleistocene clinoform depocenter northward and deltaic facies variation inside each individual sand system, not eustatic sea level fall.After calculating the biogenic gas reserves occupying each reservoir, the present strategy offers an additional seven broad gas prospects within four dismantled blocks, raising the ONS initial gas in place to 967.95 Bcf. In addition, it depicts five gas shoals emplaced at shallow depths, posing considerable drilling hazards. This paper workflow is the first of its kind in the Neogene section of the OSN Basin.

Target-oriented elastic full-waveform inversion through acoustic extended image-space redatuming

Elastic full-waveform inversion (FWI) can provide accurate and high-resolution subsurface parameters. However, its high computational cost prevents the application of this method to large-scale field-data scenarios. To mitigate this limitation, we have developed a target-oriented elastic FWI methodology based on a redatuming step that relies upon an extended least-squares migration process. In our approach, the surface-reflection data can be attributed to a given subsurface portion when mapped into the image space. This process allows us to reconstruct reflection data generated by a target area and recorded with a virtual acquisition geometry positioned directly above it. The redatuming step enables the application of an elastic FWI method within the target portion only. The entire workflow drastically decreases the overall cost of the surface-data inversion and allows the retrieval of accurate elastic parameters of the area of interest. We determine the effectiveness of our approach on a synthetic case based on the well-known Marmousi2 model and on 3D ocean-bottom node pressure data recorded in the Gulf of Mexico in which we retrieve the elastic parameters of a potential prospect, positioned in proximity of a salt-dome flank, and whose rock-physical properties are consistent with the presence of a gas-bearing sand reservoir.

Gas-bearing sands appraisal for Zamzama Gas field in Pakistan through inverted elastic attributes assisted with PNN approximation of petrophysical properties

The Pab Formation of Zamzama block, lying in the Lower Indus Basin of Pakistan, is a prominent gas-producing sand reservoir. The optimized production is limited by water encroachment in producing wells, thus it is required to distinguish the gas-sand facies from the remainder of the wet sands and shales for additional drilling zones. An approach is adopted based on a relation between petrophysical and elastic properties to characterize the prospect locations. Petro-elastic models for the identified facies are generated to discriminate lithologies in their elastic ranges. Several elastic properties, including p-impedance (11,600-12,100 m/s*g/cc), s-impedance (7,000-7,330 m/s*g/cc), and Vp/Vs ratio (1.57-1.62), are calculated from the simultaneous prestack seismic inversion, allowing the identification of gas sands in the field. Furthermore, inverted elastic attributes and well-based lithologies are incorporated into the Bayesian framework to evaluate the probability of gas sands. To better determine reservoir quality, bulk volumes of PHIE and clay are estimated using elastic volumes trained on well logs employing Probabilistic Neural Networking (PNN), which effectively handles heterogeneity effects. The results showed that the channelized gas-sands passing through existing well locations exhibited reduced clay content and maximum effective porosities of 9%, confirming the reservoir's good quality. Such approaches can be widely implemented in producing fields to completely assess litho-facies and achieve maximum production with minimal risk.

Selection of Sensitive Post-Stack and Pre-Stack Seismic Inversion Attributes for Improved Characterization of Thin Gas-Bearing Sands

Selection of Sensitive Post-Stack and Pre-Stack Seismic Inversion Attributes for Improved Characterization of Thin Gas-Bearing Sands

Characterization of Pliocene Biogenic Gas Reservoirs from the Western Black Sea Shelf (Romanian Offshore) by Integration of Well Logs and Core Data

The successful interpretation of open-hole well logging data relies on jointly using all available petrophysical and geological information. This paper presents relevant case studies related to the integration of well logs with core measurements for exploration wells drilled in the Romanian continental shelf area of the Western Black Sea basin. The analyzed wells targeted gas-bearing sands and silts complexes of Early Pliocene (Dacian) age, developed in a deltaic to shallow marine sedimentary environment in two distinct fields. The wireline logging programs included conventional formation evaluation logs, pressure surveys, nuclear magnetic resonance, and borehole electrical imaging logs. The core dataset comprised routine and special measurements (porosity, grain density, permeability, water saturation, and Archie parameters) carried out at quasi-reservoir confining pressure. The wireline logging suites were interpreted via a deterministic workflow, including core-derived interpretation parameters. Other core-derived parameters were used for constraining and validating the log interpretations. The results show that a problem related to the ambiguity of formation water resistivity can be overcome through resistivity–porosity dependencies constructed to include potential aquifer zones in the proximity of the Dacian gas-bearing reservoirs. This study also revealed and quantified uncertainties regarding the estimation of gas–water contacts from formation pressure surveys, which can be mitigated by the confirmation or correction of pressure-derived fluid contacts via the well log interpretation results. Lastly, we identified a probable resistivity logs suppression effect related both to high contents of capillary-bound water and also to the limited resolution of electrical logging tools in the presence of sand-shale thin bedding or laminations.

Lithology Identification, Shale Volume Estimation and Formation Wate Saturation of Fenchuganj Gas Field Using Wireline Log Data

This study has been undertaken with a view to interpreting and analyzing different types of logs, detecting hydrocarbon-bearing sand zone, identifying the lithology, estimating shale volume, and determining water saturation of the formation of the Fenchuganj gas field. Fenchuganj gas field is in the southern part of Bangladesh in the Sylhet division. It lies in the Surma basin and characterized as a water drive gas field. Gamma Ray (GR) log and Spontaneous Potential (SP) log analysis help to interpret the formation lithology. After interpreting lithology, the gamma-ray log and SP log were analyzed further, and the hydrocarbon-bearing zone was detected. From the analysis of different logs, for well 4, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (1585-1595) m, (1600-1610) m, (2409-2420) m, (2265-2270) m, (2295-2303) m, (2435-2450) m, (2465-2480) m, (3150-3155) m, (2955- 2960) m. These are the gas-bearing zones of fenchugonj well-4 determined from the composite log of this field. Water-bearing sand zones are between (1708-1714) m and the fully compacted shale zone is between (1920-1930) m. From the analysis of different logs, for well 5, so many gas-bearing sand zones have been detected. The gas-bearing zones are found between (2365-2385.5) m, (1820-1830) m, (1782-1803) m, (305-308) m, (336.5-338.5) m, (607.5-609.5) m. These are the gas-bearing zone of fenchugonj well-5 determined from the composite log of the field. Shale volume has been estimated from the gamma-ray log and from resistivity logs by the true resistivity method. In well 4, the calculated value of shale volume by Gamma Ray method and true Resistivity methods were respectively 15% and 6%, in well 5 these values were 7.25% and 7.64%. Formation water resistivity was determined from the formula and taken as 0. 1ohm-m and mud filtrate resistivity 0.76 ohm-m. for well-4 and for well-5 it was taken as 0.7 ohm-m (from the provided composite log of well 4 and 5). Formation true resistivity Rt was estimated directly from the ILD log and true resistivity log. The average value of Rt for well-5 was 33.75 ohm-m and for well-4 the value is 34.09 ohm-m. From the RFOC log, flushed zone resistivity Rxo was calculated directly. Water saturation has been determined by three different techniques named Archie, Indonesia, and Simandoux method. For well 5, the value of average water saturation found from Archie, Indonesia, and Simandoux model was 8.5%,22%, and 24.84%, and for well-4. The value of average water saturation was found as 7.3%,18%, 20.51%respectively.

E&P Notes (July 2021)

E&P Notes (July 2021)

An elemental and 87Sr/86Sr isotopic restitution of contaminated pore waters from sandy sediments of the Peciko gas field (Mahakam Delta, Indonesia)

Pore waters of hydrocarbon-bearing sand layers from gigantic Peciko gas reservoir located to the South of the Mahakam Delta in Indonesia were reconstructed and studied by applying the restored pore-water technique. The method is based on the Sr isotopic compositions of rock chips leached with de-ionized water aided, here, by the associated contents of major, metal and rare-earth elements (REEs). The soluble minerals were also leached with dilute hydrochloric acid and analyzed for their Sr isotopic compositions. The main founding is that many of the recovered H 2 O leachates were most probably contaminated during coring, which induced abnormally high metal and REE contents. The leachates considered free of pollution yield 87 Sr/ 86 Sr ratios that increase progressively with depth, which suggests a recent supply of surface waters to the upper pore waters. It seems also that only a few sedimentary horizons are interconnected at intermediate depths. Furthermore, the minerals dissolved by dilute HCl yield quite systematically lower 87 Sr/ 86 Sr ratios than the associated pore waters, which suggests a crystallization earlier than the recent flushing of the upper sediments by surface-type waters. • Pore waters of gas-bearing sands from Peciko reservoir in Indonesia were reconstructed. • The method includes the 87 Sr/ 86 Sr ratios and the major, metal and REEs of H 2 O leachates. • The H 2 O leachates with high metal and REE contents were contaminated during coring. • Only a few sand units seem to be connected at intermediate depths. • The minerals dissolved by HCl are older than recent fluid supplies in the upper sediments.

Extended Elastic Impedance Inversion for Better Delineation of Gasbearing Sand Reservoir, Saffron Gas Field, Offshore Nile Delta, Egypt

Extended Elastic Impedance (EEI) is a very useful seismic reconnaissance attribute. EEI logs can directly correspond to the petrophysical properties of the reservoir and the seismic. EEI reflectivity volumes can be obtained directly from the pre-stack seismic data. Better discrimination between the seismic anomaly caused by either lithology or fluid content can be utilized by applying this approach. The concept of extended elastic impedance is used to derive the petrophysical properties and distribute the reservoir facies. The study area was a Pliocene gas field, that lies in the deep marine, Offshore Nile Delta, Egypt. The workflow is simple, efficient, and uses very few inputs. We started with the fluid/ lithology logs and investigated the optimum projection in the intercept/gradient domain. Then, we used the conditioned angle stacks, to calculate the intercept/ gradient volumes, using Shuey’s two-term Approximation. The intercept and gradient volumes are converted directly to the fluid and lithology 3D volumes, without any of the pre-stack inversion constraints. The outputs were tested using a blind well and the correlation exceeds 80%. The results show that the EEI is a worthy effort to highlight the difference between the reservoir and nonreservoir sections, to identify the hydrocarbon area.

An improved specimen preparation method for marine shallow gas-bearing sand sediments and its validations

Instabilities of shallow gas-charged seabed are potential geological hazards in ocean engineering. In practice, the conventional field sampling techniques failed to obtain undisturbed gas-bearing sediments from the seabed for laboratory mechanical testing because of sensitive gas exsolution and escape from sediments. However, preparation of representative remoulded gas-charged specimens is a challenging issue, because it is rather difficult to quantitatively control the gas content and obtain uniform distribution of gas bubbles within the specimen. Given the above problems, this work proposes a reliable approach to reconstitute the high-saturation specimen of gas-charged sediments in the laboratory by an improved multifunction integrated triaxial apparatus (MITA). This apparatus is developed based on an advanced stress path triaxial system by introducing a temperature-controlled system and a wave-monitoring system. The temperature-controlled system is used to accurately mimic the in situ environments of sediments in the seabed. The wave-monitoring system is utilized to identify exsolution point of free gas and examine the disturbance of gas to specimens during gas exsolution. The detailed procedure of gassy specimen preparation is introduced. Then, the quality of prepared specimens using our improved apparatus is validated by the high-resolution micro-X-ray computed tomography (μCT) scanning test, from which bubble occurrence and size distribution within the gassy sand specimen can be obtained; and preliminary mechanical tests on gassy sand specimens with various initial saturation degrees are performed. The proposed specimen preparation procedure succeeds in proving the postulated occurrence state of gas bubbles in coarse-grained sediments and accurately controlling the gas content.

Prestack simultaneous inversion for delineation of the Lower Wilcox erosional remnant sandstone beneath the Texas Gulf Coastal Plain: A case study

The Lower Wilcox lowstand sand deposits encased between two sequence boundaries along the Texas Gulf Coastal Plain are of good reservoir quality and usually gas productive. However, the sedimentation is sparsely scattered within such a depositional environment and it is hard to predict by qualitative interpretation methods. Simultaneous inversion of elastic parameters such as P-impedance, S-impedance, and density by the integration of prestack data and well logs allows us to quantitatively characterize the reservoirs and to distinguish them from the surrounding rocks. We have used prestack simultaneous inversion of the elastic parameters for delineation of the gas reservoir in an active field with limited log availabilities. For wells that are missing sonic and density logs, we estimate the parameters using the time-average equation (TAE) and Gardner’s equation, respectively. The shear wave velocity estimation methods are tested and compared using the measured log value. The estimation results are verified using well-log correlations in adjacent wells. Rock-physics analyses on wells are conducted to find the optimal elastic parameters for characterizing the gas-bearing sand. We successfully delineate the reservoir using the crossplot of VP/ VS versus S-impedance values. The inversion results are quality controlled by a producing well in the reservoir zone, and probability maps of each lithology are calculated by the probability density function. Our results from the Lower Wilcox Formation indicate that simultaneous inversion based on the estimated parameters using TAE is feasible, and the gas-bearing reservoirs can be recommended with high confidence.

Elastic parameter inversion of a sand body based on the exact reflection coefficient

Prestack seismic inversion is an important technology for oil and gas exploration that can provide accurate lithology and pore fluid information on underground media. Prestack inversion is theoretically based on the Zoeppritz equations, which establish the relationship between the seismic reflection coefficients of different offsets and elastic parameter contrasts between the interface of two lithologies. However, these are fourth-order matrix equations with a complex form and are difficult to be directly applied to inversion. Approximate analytical solutions have been used to establish a linear relationship between the seismic reflection coefficients and elastic parameters. And the approximations are based on the assumptions of a small angle and weak contrast, they cannot be applied to layers of high contrast, such as gas-bearing sandstones and coal seams. In this paper, we present an accurate prestack seismic inversion method that can be applied to a wider range of geological models. First, we derive the partial derivatives of the exact reflection coefficients of PP waves based on the Zoeppritz equations with respect to the elastic parameters and establish the exact Jacobian and Hessian matrices. Then, we use the least-squares algorithm to construct objective functions for the simultaneous inversion of three elastic parameters: The P-wave velocity, S-wave velocity, and density. Examples show that our inversion method is more accurate for strata with strong reflection interfaces than the approximate prestack inversion methods and stable under noisy conditions. The inversion method was applied in channel sand depositions of the Lower Permian Shanxi and Shihezi Formation of the Ordos Basin, and it was efficient to identify the gas-bearing sand layers and determine the range of potentially favorable areas.

Accumulation conditions and key technologies for exploration and development in Sebei gas field in Qaidam Basin, NW China

The Sebei gas field, located in the northern slope of the Sanhu depression in the eastern Qaidam Basin, is the largest inland biogas producing area in China. It is a typical Quaternary biogenetic gas reservoir composed of multiple layers of unconsolidated sandstone. Through systematic study of gas generating mechanism of source rock, reservoir-caprock combination and trap evolution, the unique biogas accumulation model characterized by “continuous hydrocarbon generation and dynamic accumulation” is established. Its uniqueness is reflected in the biogas generation mechanism under dual effect of low-temperature thermodynamics and microbial degradation, source-reservoir one body, self generation and self storage, dynamic source-reservoir-caprock assemblages and anticline trap formation mechanism of multi-factor mutual promotion. This understanding reveals the intrinsic factors for formation of large-scale biogas field under frigid climate, high salinity and low organic matter abundance. A number of exploration and development technologies have been worked out during the exploration and development of the Sebei gas field. Among them, the low-amplitude structure identification technique, multi-parameter gas-bearing detection technique, sand control and comprehensive water control technique for unconsolidated sandstone are well applied in discovering the gas field, increasing reserve, and increasing and maintaining gas production. The above understandings and key technologies have great reference significance and demonstration effect for biogas exploration and development in China and the world.

LITHOFACIES PECULIARITIES OF OIL AND GAS-CONTAINING COMPLEXES OF THE PURSK REGION OF WESTERN SIBERIA

In the article, regional and local conditions of sediment accumulation in the Pursky region of Western Siberia are considered. It is shown that during the Jurassic-Cretaceous time, the sedimentation facies conditions were repeatedly changed due to the multiscale transgressive-regressive cycles of the basin development. The Jurassic transgressive macrocycle of sedimentation led to the platform cover formation on most of the ter- ritory and a gradual change of the continental sedimentation regime (tyumen suite), shallow-marine and marine (vasyugan / abalak suites) and further deep-sea (bazhenov suite) regimes. At the beginning of the neocom there is regression and reorganization of the basin, the formation of a prograde wedge-shaped complex of sediments with lateral build-up bodies and synchronous gravitational-landslide cones of removal. During the sea basin regression, a typical facial profile was formed, which was represented in the east near the drift sources by continental, further to the west by coastal-marine, shallow-marine and relatively deep-water facies. Oil and gas bearing sand deposits are characterized by a polyfacial structure and refer to natural reservoirs of non-structural type, formed in alluvial, deltaic, coastal-marine and relatively deep-water environments. To identify such reservoirs and assess their quality, the use of lithofacies studies aimed at restoring sedimentary environments is recommended. This is necessary primarily for the effective search of hydrocarbons, forecasting of oil and gas complexes, assessment of spatial changes in their quality, which largely determines the direction and strategy of exploration and production operations. Facial studies are important not only for the search of non-structural deposits, but also for the creation of realistic three-dimensional geological models. Such models with facies properties allow more reasonably assess the lithological complexity of the field, more reliably predict the petrophysical properties distribution, provide a selection of influence technological tools on the reservoir.

A Contribution of the CDP Gathers and Pre-Stack Seismic Inversion in the Prospect Evaluation: A Case Study of El Mansoura Field, Nile Delta, Egypt

This case study showing the usefulness of the Common Depth Point (CDP’s) analysis to assess the amplitude response which is similar at two cases (gas-bearing and dry sands) after stack, using the Amplitude Versus Offset (AVO) analysis and the pre-stack inversion to understand the reservoir configuration and its relationship to the different amplitude response. The results led to a high success of exploration ratio as the positives vastly outweigh the negatives. Several lessons have been learned, which how to differentiate between the similar amplitude responses for two dry and gas discovery wells-by understanding the relationship between the near traces (near offset) and the far traces (far offset) from the CDP gathers in order to reduce the amplitude anomalies to their right justification. Consequently, a variation in the reflectivity strength is observed, which is controlled by the mechanical properties of the rocks: compression wave (VP), shear wave (Vs) and density. These properties are affected by litho logy and fluid contents. The analysis of the CDP’s gathers and the inversion results help in validating the prospects before drilling and in determining the response of the seismic amplitude deviation with the offset, so it is possible to confirm the amplitude anomaly if it is related to hydrocarbon or not.

The Totumo mud volcano and its near-shore marine sedimentological setting (North Colombia) — From sedimentary volcanism to epithermal mineralization

The Holocene mud volcano exposed at Totumo (younger than 4150 ± 50 yr BP) lines up together with some other landforms of its kind along the Caribbean Coast in northern Colombia. It currently vents a mud of the silicate-phosphate-bearing sulfur-sodium chloride type. The mud volcanoes evolved in an active continental margin setting of the South American Cordillera with high seismicity and affected by pervasive neotectonic structural disturbances. During the Neogene and Quaternary linear terrigenous shoreline sediments alternating with delta deposits evolved on this mobile crustal segment between the Andes and ancient Precambrian cratons. Meso- to microtidal sedimentary settings during transgression and progradation created meta- to instable sedimentary and petrophysical conditions (e.g. overpressure and gas-bearing bubble sands), favorable for the formation of mud volcanoes, whose lithofacies is subdivided into (1) footwall facies (detritus from metabasic, -pelitic source rocks), (2) mud volcano plus lateral facies (material from deep-seated hydrothermal sources, hydrocarbon plays, and brine reflux from the sea), (3) hanging wall facies, sand characterized by a strong longshore drift. The sedimentary volcanism in the area is characterized by different temperatures of formation: (1) pre-stage (<100 °C) and (2) recent stage (≈25 °C). Heavy (pyroxene, amphibole, epidote-clinozoisite, Fe-Ti silicates and oxides, garnet, alumosilicates, tourmaline, zircon, barite, Fe sulfides and -sulfates), light (Ca sulfates, calcite, quartz, feldspar) and clay minerals (kaolinite, mica, pyrophyllite, chlorite, vermiculite) are efficient tools to determine the source of mud, to subdivide the mud volcano system as to its facies and describe its physical-chemical regime as to the temperature of formation, pH and Eh values. The mud volcano system of Totumo bridges the gap between sedimentary “volcanism” and epithermal hot spring deposits of intermediate to high sulfidation and forms a useful “guide” to hydrocarbon accumulation.

The Leviathan Miocene Diapir – A novel insight into the tectonic evolution of the Southern Levant Basin, Eastern Mediterranean

The Leviathan gas field is the largest accumulation so far discovered in the Southern Levant Basin within the turbiditic Tamar Sand Complex. The discovery of this and other fields in the basin was made possible following acquisition of a vast amount of data since 2000. A consensus has been reached that the basin is dominated by Early Mesozoic extensional blocks related to opening of the Neotethys while Miocene folds formed as a result of its closing. Through the study of geophysical data over the Leviathan gas field and its vicinity, it is suggested that most of what we observe today has been formed since the Early Miocene and that the alleged old blocks are actually intrusive bodies. Their structural timing is accurately constrained by well and seismic data but not their composition, as none has yet been penetrated at any borehole. Mud diapirism is currently assumed, as volcanic or magmatic origin is discarded by magnetic data and salt is yet a remote possibility. The tectonic reconstruction suggests that the Levant Basin developed during the Mesozoic and Early Cenozoic as a set of regional highs and lows that were buried since the Early Tertiary until the Early Miocene by thick conforming sequences including potential reservoir rocks such as the gas-bearing turbiditic sands. It was then subject to an extensional tectonic regime associated with diapirs in the southern part of the basin that formed folded structures while rotational blocks developed to the north, offshore Lebanon. The implications of this tectonic setting on petroleum systems are of prime importance; widespread intrusions may have breached old traps, if they existed. On the other hand they formed potential traps such as the proven gas-filled structures and potentially others at depth. Presence of reservoir rocks and the timing of expulsion and migration from deep sources are the main geological risks.

A fast complex domain-matching pursuit algorithm and its application to deep-water gas reservoir detection

The main emphasis of exploration and development is shifting from simple structural reservoirs to complex reservoirs, which all have the characteristics of complex structure, thin reservoir thickness and large buried depth. Faced with these complex geological features, hydrocarbon detection technology is a direct indication of changes in hydrocarbon reservoirs and a good approach for delimiting the distribution of underground reservoirs. It is common to utilize the time–frequency (TF) features of seismic data in detecting hydrocarbon reservoirs. Therefore, we research the complex domain-matching pursuit (CDMP) method and propose some improvements. First is the introduction of a scale parameter, which corrects the defect that atomic waveforms only change with the frequency parameter. Its introduction not only decomposes seismic signal with high accuracy and high efficiency but also reduces iterations. We also integrate jumping search with ergodic search to improve computational efficiency while maintaining the reasonable accuracy. Then we combine the improved CDMP with the Wigner–Ville distribution to obtain a high-resolution TF spectrum. A one-dimensional modeling experiment has proved the validity of our method. Basing on the low-frequency domain reflection coefficient in fluid-saturated porous media, we finally get an approximation formula for the mobility attributes of reservoir fluid. This approximation formula is used as a hydrocarbon identification factor to predict deep-water gas-bearing sand of the M oil field in the South China Sea. The results are consistent with the actual well test results and our method can help inform the future exploration of deep-water gas reservoirs.