Reservoir Mapping Research Articles

Towards mixed physical node reservoir computing: light-emitting synaptic reservoir system with dual photoelectric output

Memristor-based physical reservoir computing holds significant potential for efficiently processing complex spatiotemporal data, which is crucial for advancing artificial intelligence. However, owing to the single physical node mapping characteristic of traditional memristor reservoir computing, it inevitably induces high repeatability of eigenvalues to a certain extent and significantly limits the efficiency and performance of memristor-based reservoir computing for complex tasks. Hence, this work firstly reports an artificial light-emitting synaptic (LES) device with dual photoelectric output for reservoir computing, and a reservoir system with mixed physical nodes is proposed. The system effectively transforms the input signal into two eigenvalue outputs using a mixed physical node reservoir comprising distinct physical quantities, namely optical output with nonlinear optical effects and electrical output with memory characteristics. Unlike previously reported memristor-based reservoir systems, which pursue rich reservoir states in one physical dimension, our mixed physical node reservoir system can obtain reservoir states in two physical dimensions with one input without increasing the number and types of devices. The recognition rate of the artificial light-emitting synaptic reservoir system can achieve 97.22% in MNIST recognition. Furthermore, the recognition task of multichannel images can be realized through the nonlinear mapping of the photoelectric dual reservoir, resulting in a recognition accuracy of 99.25%. The mixed physical node reservoir computing proposed in this work is promising for implementing the development of photoelectric mixed neural networks and material-algorithm collaborative design.

Determine the Reservoir Characterization, Using Seismic Data, Well Logs, Attribute Interpretation, and Static Modelling in the Duhok Province, Kurdistan Region, Iraq

Although the High Folded Zone in the Kurdistan Region of Iraq forms part of the Zagros-Taurus Folds and Thrust belt considered one of the potential hydrocarbon provinces, the oil fields within the zone are still lacking in geophysical exploration and scientific research. So, the rationale behind this study is the prospecting and evaluation of one of the Tertiary carbonate reservoirs at the “WN” oil field in the Duhok area by integrating the 3D seismic and well-log data. The methodology covered seismic interpretation, well logs and their relevant petrophysical analysis, attribute computation, and 3D static property modeling. The constructed reservoir maps revealed a double-plunging rollover anticlinal structure trending in the East-West direction parallel to the Taurus Mountain series. A total of nineteen minor reversal faults trending E-W to ENE-WSW dissecting the northern limb of the anticline were manually interpreted. The isopach map shows various thicknesses ranging from 160 to 330 m, averaging 245 m. The property models show the limited values of their parameters as the effective porosity is limited (0.97-23%), the secondary porosity (0.43-11.7%), permeability (0.00-238.8 mD), the water saturation (12.44-99.8%), and the clay volume (0.00-9.8%). The results of this research indicate that the horizon is a promising reservoir characteristic.

Seismic Reprocessing Overcomes Uncertainty in Offshore Egyptian Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214066, “Seismic Reprocessing Leads to New Breakthroughs—A Successful Case in the ASH Field, AG Basin in Egypt,” by Mohamed Elokr and Ahmed Lotfy, Kuwait Energy Egypt, and Wei Xing, United Energy Group, et al. The paper has not been peer reviewed. _ The ASH oil field is in the eastern portion of the AG Basin in Egypt. The Lower Cretaceous Alam El Bueib is the main oil-producing formation. Because of the high heterogeneity of the Abu Roash succession, in addition to the influence of thick limestone of the Upper Cretaceous and the influence of multiple complex faults, the quality of seismic data is very poor, requiring seismic reprocessing. Two key techniques were used to achieve the goal: New vertical seismic profile (VSP) well data were acquired to adjust the velocity model, and common reflection angle migration (CRAM) prestack depth migration (PSDM) was used for reprocessing. Introduction The ASH field produces oil from the Aptian Lower Cretaceous reservoir. The ASH structure is interpreted as an elongated east-northeast/west-southwest anticline with intensive breaching on the downthrown side of northwest/southeast to west-northwest/east-southeast-oriented normal faults with obvious signature of synsedimentary activities. The entire area was subject to a series of tectonic events affecting the Western Desert, which led to a complex fault regime clearly recognized in the ASH structure by a series of horizontal displacement across the northwest/southeast faults. Strike/slip to oblique-slip faults also are observed from thicknesses of the cretaceous formations, creating significant difficulty in fault definition. The 3D seismic data acquired in 2007 suffered from losing amplitude of the Lower Cretaceous and deep Jurassic reflectors because of the complex structure. The strong carbonate markers disappear north of the field, where high, dense fault intersection is present closing from the main bounding fault. Loss of seismic amplitude could have severe effects on of the future economics of the field. The seismic survey was reprocessed two times without significant enhancement of the fault imaging. PSDM was run without velocity control, resulting in an uncertain velocity model with inaccurate fault imaging and a mismatching between actual and prognosed depths of the drilled wells of greater than 50 m. This contradiction in reservoir mapping meant that the northern portion of the field remained unexplored. Acquiring VSP in the recently drilled well encouraged reprocessing of the 3D seismic survey using well velocity as a control point in adjusting the seismic velocity model, and application of CRAM technology to improve fault imaging and appraise the uncertain area of the ASH field. CRAM Methodology CRAM was developed as a type of beam migration. Asymptotic ray tracing is performed, assuming that one-way diffraction rays from the subsurface image point to the surface sources and receivers. The takeoff angles from the image point are measured around a given local normal to a background reflection surface for each source ray and receiver ray. A system of source and receiver ray pairs is formed, and the recorded seismic data can be mapped into a local angle domain based on the reflection angles at the subsurface image points.​​​​

A new approach to satellite-derived bathymetry: the use of NDWI and ANN with bathymetry sections for reservoir mapping

A new approach to satellite-derived bathymetry: the use of NDWI and ANN with bathymetry sections for reservoir mapping

Accurate Petrophysical Interpretation of Carbonate using the Elemental Capture Spectroscopy (ECS)

Elemental capture spectroscopy (ECS) is an important tool in the petroleum industry for determining the composition and properties of rock formations in a reservoir. Knowledge of the types and abundance of different minerals in the reservoir is crucial for accurate petrophysical interpretation, reservoir engineering practices, and stratigraphic correlation. ECS measures the elemental content of the rock, which directly impacts several physical properties that are essential for reservoir characterization, such as porosity, fluid saturation, permeability, and matrix density. The ability to accurately determine these properties leads to better reservoir mapping, improved production, and more effective resource management. Accurately determining the mineralogy and porosity of carbonate rocks and other materials is the aim of this paper. Calcite, dolomite, quartz, clay (illite), anhydrite, and pyrite, in addition to water as a fluid, are taken into account in the computation. The formation's lithology and porosity can be ascertained from this data. When compared to the core descriptions in the geological report, the results demonstrated a distinct zone of unique lithology with good prediction accuracy.

Combining Magnetic and Gyroscopic Surveys Provides the Best Possible Accuracy

Summary A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding a collision with nearby offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying tools and technologies taken individually is insufficient. This high level of wellbore positioning accuracy is achieved by combining two independent wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic measurement-while-drilling (MWD) definitive dynamic surveys (DDS). The accuracy of the MWD DDS can be further improved by minimizing error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, the use of localized geomagnetic reference, using high-accuracy accelerometer sensors, and a high-accuracy gravity reference. Furthermore, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the rotary steerable system. A first wellbore position is calculated from the magnetic MWD DDS after applying in-field referencing (IFR), multistation analysis (MSA), bottomhole assembly (BHA), sag correction (SAG), and dual-inclination (DI) corrections to improve both azimuth and inclination accuracy. A second wellbore position is calculated using gyro-MWD (GWD) technology. The results and comparisons of multiple combined survey runs are presented. The highest accuracy of wellbore positioning had been proved in this successful case study by penetrating a very small reservoir target on an extended-reach well that was unfeasible using either the most accurate enhanced MWD DDS or GWD technology individually. The presented case study shows how the wellbore objectives of penetrating a very small reservoir target had been confirmed by logging-while-drilling images and the reservoir mapping interpretation of the client subsurface team. This gave a high-accuracy wellbore position during drilling and provided higher confidence in wellbore placement to maximize reservoir production without colliding with nearby offset wells. Wellbore survey accuracy limits a borehole’s lateral and true vertical depth (TVD) spacing, constraining reservoir production in those sections. In the top and intermediate sections, wellbore survey accuracy limits how close the wellbore can be drilled to other offset wells due to collision concerns. This directly impacts the complexity of the directional work and the cost per section. Combining independent wellbore surveys unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy that can be achieved to date compared with the latest magnetic MWD surveys after correcting all known errors or compared with GWD.

Post stack seismic data processing for enhancing subsurface reservoir mapping in the Shushan basin, Western Desert, Egypt

ABSTRACT Reprocessing of seismic reflection data over Nader field in the Egyptian Western Desert, improved the images of the surface structural framework. The appearance of seismic data can be affected by various factors apart from subsurface structure, including data acquisition problems and processing artefacts. Different post-stack processing steps were tested and compared to the original seismic data determine the enhancement of data quality and improvements on imaging the subsurface. The applied post-stack processing sequence increased the seismic data resolution through increasing the signal-to-noise ratio, enhancing faults detection, and reflectors sharpness and continuity. The Time Variant Frequency Filter (TVF) application is found to be better than applying the filter in one time window and provided more detailed frequency contents and in turn better reflectors identification. The Frequency/Wave Number (F/K) filter removed lot of the existing linear noises resulted in more clear images. The Frequency/Distance (F/X) Deconvolution enhanced the data coherency by removing the existing random noises. The Spiking Deconvolution showed remarkable enhancement in compressing the reflectors and increasing their continuity. The reprocessed data interpretation of Abu Roash C member in Nader Filed, Shushan basin, North Western Desert, Egypt, comparing to the original, showed better mapping and faults detection, which highlighted new potential structures that could act as hydrocarbon traps.

Quantitative mapping of calcium cell reservoirs in cyanobacteria at the submicrometer scale

Calcium plays an important role in the physiology of bacterial cells and as a free soluble form inside the cells, it is tightly regulated at a low concentration. However, much higher amounts of stored calcium exist within cells and can be remobilized at diverse occasions. As a consequence, there has been a variety of techniques developed to quantitatively map the different forms of Ca in cells. Here we show how scanning transmission x-ray microscopy (STXM), a synchrotron-based microscopy technique, conducted in the soft x-ray range at the Ca L2,3 edges (340–360 eV) offers an original and informative quantitative view of different Ca reservoirs in bacterial cells at a spatial resolution better than 100 nm. To illustrate this, we analyzed mutants of the cyanobacterium Synechococcus elongatus PCC 7942, overexpressing different versions of a gene called ccyA from two phylogenetically distant cyanobacteria: Gloeomargarita lithophora and Synechococcus sp. PCC 6312. This gene is diagnostic of the capability of some cyanobacteria to form intracellular amorphous calcium carbonate (iACC) but its function remains unknown. Here we show that the overexpression of the ccyA gene in the iACC non-forming cyanobacterium S. elongatus PCC 7942 results in an increased Ca content, especially in some Ca-rich cells. Moreover, we show that STXM can discriminate four different reservoirs of Ca in cyanobacteria and provides quantitative assessment of their relative importance.

A novel approach for water reservoir mapping using controlled source audio‐frequency magnetotelluric in Xingning area, Hunan Province, China

AbstractControlled source audio‐frequency magnetotelluric is frequently used in association with other geophysical methods, especially in complex geological areas to highlight geological structures such as water reservoir rock. Although it gives satisfactory results, combining several methods requires time and expense. In addition, despite this combination, several drilling locations proposed after geophysical investigations were inaccurate, resulting in many unsuccessful drillings. The latter occurs due to the difficulty to emphasize the fracture zones properly. To work around this problem, we proposed a novel approach called pseudostratigraphic to reduce the repercussion of unsuccessful drilled boreholes and to demarcate the water reservoir rock. The technique consists to discretize the resistivity of the inverted OCCAM2D model based on the true layer resistivities collected from the borehole log data (observed layers). The discrete resistivity model is known as the new resistivity model. It is used to generate the pseudostratigraphic log at each station by pseudo‐demarcating the thicknesses of the observed layers with a low margin of error. Moreover, the combination of multiple new resistivity models from different survey lines creates a three‐dimensional pseudostratigraphic map useful to emphasize the water reservoir rock. The pseudostratigraphic implementation is carried out in the Xingning area as a real‐world case study. The results show that the intersection of the main fault (F1) and the conductive zones (≤100 Ω m) indicates the potential water reservoir rock. Its thickness is estimated around 150–600 with an error equal to ± 7°m. Based on the three‐dimensional pseudostratigraphic map, the water found in the fracture zone located under the reservoir rock is considered much hotter due to the intense geothermal activity along F1, thereby making it a better place for hot water exploitation. Finally, the pseudostratigraphic technique could be an innovative and cheap strategy to find groundwater reservoirs in complex geological areas.

Formation evaluation utilizing a new petrophysical automation tool and subsurface mapping of the Upper Cretaceous carbonate reservoirs, the southern periphery of the Abu-Gharadig basin, Western Desert, Egypt

The southern periphery of the Abu-Gharadig basin in the Northern Egyptian Western Desert is characterized by some subsurface geological challenges related to the carbonate reservoir's quality, which requires precise petrophysical evaluation and seismic structural interpretation. Therefore, we conducted a subsurface mapping and formation evaluation for the Upper Cretaceous carbonate reservoirs in the Southwest Abu Sennan (SWS) area utilizing seismic reflection profiles and borehole geophysical data. Seismic mapping of the Upper Cretaceous carbonate reservoirs (Abu Roash (AR)/B,/D, and/F) revealed 3-way folds with NE-SW trends divided by NW-SE normal fault trends presenting significant chances for exploration. These closures were filled by hydrocarbons generated from the Jurassic source rocks. Formation evaluation was performed using the new petrophysical tool “Gaialog” which was coded using Python. Petrophysical parameters for the recognized net pay intervals of AR/B, AR/D, and AR/F carbonate reservoirs showed that the effective porosity (φeff: Phie) and the hydrocarbon saturation (Sh) increases towards the East to Southeast direction while the water saturation (Sw) increases to the Northwest of the study area. The highest net pay and the effective porosity were found in the Eastern part of the study area. The study procedures can be applied in neighboring areas to evaluate and understand similar reservoirs.

From the Editor…

No abstract available

Impact of Using Price Fluctuation Related Conditions on Construction Projects

The inherent nature of construction projects is long duration and high cost. Extended project duration leads to escalation of cost. If the project duration is too long, the initial estimation may not be sufficient to recover the actual cost of the contract. To address this problem, Construction Industry Development Authority (CIDA) has introduced a price adjustment method called the “ICTAD formula method for adjustments to contract price due to fluctuation in prices”. Contract documents related to construction projects also provide some provisions to address the issues with material price fluctuations. This study investigated the practices of contractors to minimize the effect of price variation and support of price fluctuation clauses to minimize the impact of price variation. A questionnaire survey was conducted among the professionals to represent CS2 to C5 grade construction companies registered at CIDA. The questionnaire consisted of practices of contractors to minimize the effect of price variation and the impact of using price fluctuation clauses in different aspects. Collected responses were converted to a quantitative value using the relative importance index (RII). In addition, SPSS software was used for the critical review of responses. The results revealed that contractors mostly agree with using price fluctuation clauses to recover the increased project cost due to increased construction input prices. Further, results are evident that using price fluctuation clauses helps to fair risk sharing between the contractor and the client.

An update on current understanding of the epidemiology and management of the re-emerging endemic Lassa fever outbreaks

An update on current understanding of the epidemiology and management of the re-emerging endemic Lassa fever outbreaks

Automating seismic‐well tie via self‐supervised learning

AbstractAs an essential process in subsurface interpretation, seismic‐well tie aims at calibrating the well measurements in depth domain with the seismic records in time domain for reliable reservoir mapping and modelling. Such a process usually requires massive manual efforts, primarily extracting source wavelets to synthesize seismograms from well measurements and stretching/squeezing synthetic seismograms to match actual seismic signals, and thus becomes time‐consuming and labour intensive with the amount of wells expanding in a field. This paper formulates the seismic‐well tie problem from the perspective of computer vision and, considering the lack of manually prepared training labels in most of real projects, proposes automating it by a self‐supervised workflow of two key components. The first component is to extract time‐variant wavelets in the target interval using a dual‐task autoencoder, which is optimized by maximizing the spectrum similarity between the extracted wavelet and the actual seismic. The second component is to estimate the corresponding time‐shift between a pair of the synthetic seismogram and the actual seismic using a flow net, which is trained by a pseudo dataset derived from the actual well measurements. More specifically, the data generation consists with defining one‐dimensional time‐shift curves to warp the original less accurate time‐depth relationships and then synthesizing the corresponding seismograms based on the convolutional model at all available wells. When turning to the stage of inference at a target well, the proposed workflow automatically extracts a representative wavelet, generates the corresponding synthetic seismogram from the original time‐depth relationship and estimates the time‐shift curve necessary for revising the original time‐depth relationship that would lead to an optimal tying with the actual seismic at the well. The proposed workflow is tested on two field datasets, and both results demonstrate improved tying over traditional methods such as statistical wavelet extraction and dynamic time warping.

Estimation of seismic attenuation for reservoirs mapping and inverse Q‐filtering: An application on land seismic data

AbstractSeismic attenuation values based on inverse Q‐filtering are useful in enhancing seismic data resolution for quantitative interpretation. However, as field attenuation estimations are often contaminated by noise and overburden effects, an inverse Q‐filter may reduce the signal‐to‐noise ratio. To help reservoir mapping with seismic resolution enhancement, we use well logs and surface seismic data to estimate the attenuation of a depth interval composed of several carbonate oil reservoirs onshore the Arabian Peninsula. From applying a prestack Q inversion on τ–p gathers from a large 3D seismic survey, the estimated effective attenuation values show spatially coherent patterns, likely corresponding to changes in the petrophysical and fluid properties. The patterns of the estimated effective attenuation values correlate considerably with the anticline geometry, with higher values on its crest than its flanks. The small percentage of the negative effective attenuation values indicates that the apparent attenuation and overburden effects are insignificant. At well locations, the effective attenuation values show a good correlation with the average porosity of the main reservoir, verifying that they are related to changes in petrophysical properties in the analysis interval. We propose an extended inverse Q‐filter with two additional parameters to make it more robust and flexible and test it with synthetic and field datasets. We estimate a multiple‐scattering attenuation value from well logs and use it in the proposed filter for the field dataset. The compensation for the multiple‐scattering effects suppresses the overprints of the data components unrelated to the target interval, hence benefitting the quantitative data interpretation.

Enhancing the Detectability of Deep-Sensing Borehole Electromagnetic Instruments by Joint Inversion of Multiple Logs Within a Probabilistic Geosteering Workflow

The cost of drilling wells on the Norwegian Continental Shelf is exceptionally high, and hydrocarbon reservoirs are often located in spatially complex rock formations. Optimized well placement with real-time geosteering is crucial to efficiently produce from such reservoirs and reduce exploration and development costs. Geosteering is commonly assisted by repeated formation evaluation based on the interpretation of well logs while drilling. Thus, reliable, computationally efficient, and robust workflows that can interpret well logs and capture uncertainties in real time are necessary for successful well placement. We present a formation evaluation workflow for geosteering that implements an iterative version of an ensemble-based method, namely the approximate Levenberg-Marquardt form of the Ensemble Randomized Maximum Likelihood (LM-EnRML). The workflow jointly estimates the petrophysical and geological model parameters and their uncertainties. This paper demonstrates joint estimation of layer-by-layer water saturation, porosity, and layer-boundary locations and inference of layers’ resistivities and densities. The parameters are estimated by minimizing the statistical misfit between the simulated and the observed measurements for several logs on different scales simultaneously (i.e., shallow-sensing nuclear density and shallow to extra-deep electromagnetic (EM) logs). Numerical experiments performed on a synthetic example verified that the iterative ensemble-based method could estimate multiple petrophysical parameters and decrease their uncertainties in a fraction of the time compared to classical Monte Carlo methods. Extra-deep EM measurements provide the best reliable information for geosteering, and we show that they can be interpreted within the proposed workflow. However, we also observe that the parameter uncertainties noticeably decrease when deep-sensing EM logs are combined with shallow-sensing nuclear density logs. Importantly, the estimation quality increases not only in the proximity of the shallow tool but also extends to the look ahead of the extra-deep EM capabilities. We specifically quantify how shallow data can lead to significant uncertainty reduction of the boundary positions ahead of the bit, which is crucial for geosteering decisions and reservoir mapping.

1-D basin modeling, 3-D reservoir mapping and source rock generative potential of Balkassar oilfield, Potwar basin, Pakistan

This study presents geochemical, petrophysical and seismic interpretation and modeling data of source and reservoir rocks of Eocene and Paleocene sequences of Balkassar oilfield, Potwar Basin, Pakistan. Integrated approaches were applied to evaluate structure and various rocks i.e., Patala, Lockhart and Chorgali formations. Grid of eleven seismic lines, well logs, well tops and ten fresh rock cutting samples were used. TOC content of Patala Formation ranges between 0.25 − 1.16 wt. %, with S2 values 0.11–0.63 mg HC/g rock, thus indicating poor to fair hydrocarbon potentialwhich issupported by no distinct presence of hydrocarbon peaks in pyrolysis-GC pyrograms. Petrographic analysis showed dominant presence of vitrinitic Type III and inertinitic Type IV kerogen phytoclasts with minor amount of AOM. High abundance of reworked vitrinite and inertinite phytoclasts appear to have influenced the vitrinite reflectance data. Basin modeling predicts Lockhart Formation began oil generation at 10.30Ma age at depth 1557 m and reached peak generation at 8.43Ma age at depth 1802 m. Patala formation began oil generation at 10.56Ma age at depth 1472 m and reached its peak generation at 8.43Ma age at depth of 1768 m. 3D horizon mapping depicts that Chorgali formation is uniformly distributed and faulted from northwest corner.

A Cepstral Technique for Unmasking Vital Sub-Seismic Stratigraphic Details Embedded in Dense 3D Seismic Data from Niger Delta

Seismic visibility is enhanced through the change of the seismic data outlook from the standard amplitude measurement to a new domain in order separate fact from artifact in seismic processing and interpretation. General seismic data interpretation involves direct fault and horizon mapping, sequence stratigraphy and seismic modeling to produce structural, stratigraphic and reservoir maps for the delineation, exploration and production of hydrocarbon in oil fields. These methods operate on stacked and migrated data and without adequate calibration. Besides, final stacks are inadequately displayed, processing is coarse and in time domain. Actual hydrocarbon entrapments are rarely detailed well enough to permit reliable location of wells from these studies alone owing to noise. This paper presents the results of the application of Cepstral transform (CT) in the interpretation of the 3D seismic data in the Niger Delta. The aim of the study was to develop a robust technique for mapping subtle stratigraphic units which are usually masked during normal data interpretation using Cepstral algorithm. The Cepstrum is the Fourier transform of the log of the spectrum of the data. The transform filters the field data recorded in time domain, and recovers lost sub-seismic geologic information in quefrency domain. Cepstral domain analysis separates source and transmission path effects. The algorithm is based on fast Fourier transform technique and was developed within Matlab software. The results of the Cepstral decomposition yielded gamnitude, saphe and quefrency maps of the reservoir and revealed sub-seismic faults, differences in lithology and better reservoir delineation and delimitation.

A simulation study of hydraulic fracturing design in carbonate reservoirs: a middle east oilfield case study

The interactions between hydraulic fracture morphology and fluid transport mechanisms after large-scale fracturing in low-permeability carbonate reservoirs are important factors that could impact post-fracturing productivity. Using an integrated geology-engineering approach that consists of hydraulic fracturing and reservoir simulation, this paper presents the detailed hydraulic fracturing simulation and design of a low-permeability carbonate reservoir in the Middle East based on sweet spot mapping. The fracturing protocol is determined based on productivity charts, which are obtained via sweet spot mapping of the target carbonate reservoir. The daily production of a horizontal well in the reservoir shows an increase from 870 to 2000 bbl/d after the hydraulic fracturing design and implementation, which is the highest among the existing production wells in same oilfield. The results are shown to be consistent with the proposed productivity chart, which suggests that the implemented workflow could be helpful for the large-scale fracturing implementation of similar carbonate reservoirs.

Calculating the large leakage flux of a breached hydrocarbon trap using geophysical interpretation of a paleo-gas-water contact

Integration of three-dimensional seismic and well data from the Northern Carnarvon Basin on the North West Shelf of Australia was used to assess the evidence for top seal breach of a paleo-gas accumulation. Several seismic indicators of vertical hydrocarbon leakage from the crest of the stratigraphic Mungaroo Trap point to a significant flux of gas within the past few hundred thousand years. Mapping of the top reservoir within the Triassic aged Mungaroo Formation revealed strong evidence for a paleo-gas-water contact (GWC), approximately 100 m down flank from the erosional crest of the trap. This contact conforms to structure and delimits an original volume of 1.1 trillion cubic feet (Tcf), based on reservoir property calibration from nearby wells. Mapping also revealed a present-day gas-water contact with a closed volume of 0.2 Tcf, 30 m down flank from the crest. This contact displays a discordant geometry indicative of a dynamic contact.The leakage zone is located directly above the crest of the structure. It is seismically well imaged and comprises seafloor pockmarks, shallow gas anomalies and gas hydrate anomalies. The presence of a leakage zone distributed vertically above a reservoir containing a present and paleo-GWC provides compelling evidence this trap has leaked by breaching of the top seal. Volumetric calculations using the two GWCs indicate that the Mungaroo Trap has been depleted by 0.9–1.1 Tcf. A dynamic-GWC indicates the leakage event within the trap has occurred recently. Analysis of dating of horizons correlated to the seafloor pockmarks places the leakage event at sometime within the last 300 Ka.