The Paleozoic prospectivity of the Browse Basin, Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 685
Author(s):  
Said Amiribesheli ◽  
Joshua Thorp ◽  
Julia Davies
Keyword(s):  
Seismic Data ◽  
Inversion Algorithm ◽  
Reservoir Properties ◽  
Depth Migration ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Amplitude Versus Offset ◽  
Long Offset ◽  
Well Data

Most of the discovered hydrocarbons in the Browse Basin occurred within the Mesozoic intervals, while deeper Paleozoic sequences have been seldom explored. Lack of Paleozoic exploration in the Browse Basin has been attributed to the lack of well penetrations, poor understanding of the petroleum systems and paucity of seismic data. The onshore Canning Basin with several commercial fields and discoveries is the most appropriate analogue for understanding the Paleozoic sequences in the region. With the integration of geophysical data (i.e. gravity, magnetic and seismic), well data and geology, the Paleozoic prospectivity of the Browse Basin can be further enlightened. Modern long offset (8 m) Vampire 2D seismic data were acquired by Searcher to address some of the complex challenges in the Browse Basin. Reservoir quality of the Brewster Formation, volcanic discrimination within the Plover Formation and identification of deeper Triassic and Paleozoic plays are some examples of these challenges in the Browse Basin. Recently Searcher reprocessed this regionally important Vampire 2D seismic dataset that ties to 60 wells. The broadband pre-stack depth migration reprocessed data were inverted to extract three petro-elastic properties of acoustic impedance, Vp/Vs and density by three-term amplitude versus offset inversion algorithm to improve imaging of deeper plays and delineate reservoir properties. This paper discusses how several potential Paleozoic reservoir-seal pairs can be identified in the Browse Basin by utilising the integration of Vampire 2D seismic data, quantitative interpretation products, regional geology and knowledge of the Canning Basin’s fields and discoveries. Previously there was little exploration of Paleozoic plays because they could not be imaged on seismic data. The potential Paleozoic reservoirs identified in this study include Permo-Carboniferous subcrop, Carboniferous-Devonian anticline and Carboniferous-Devonian rollover plays.

Stochastic inversion by trace matching for carbonate reservoir property prediction: A Mishrif Reservoir case study

2019 ◽  
Vol 38 (1) ◽  
pp. 27-34 ◽  
Author(s):  
Sara R. Grant ◽  
Matthew J. Hughes ◽  
O. J. Olatoke ◽  
Neil Philip
Keyword(s):  
Seismic Data ◽  
Carbonate Reservoir ◽  
Inversion Process ◽  
Reservoir Properties ◽  
Stochastic Inversion ◽  
Large Numbers ◽  
Well Data ◽  
Established Technique

Estimation of reservoir properties and facies from seismic data is a well-established technique, and there are numerous methods in common usage. Our 1D stochastic inversion process (ODiSI), based on matching large numbers of pseudowells to color-inverted angle stacks, produces good estimations of reservoir properties, facies probabilities, and associated uncertainties. Historically, ODiSI has only been applied to siliciclastic reservoir intervals. However, the technique is equally suited to carbonate reservoirs, and ODiSI gives good results for the Mishrif Reservoir interval in the Rumaila Field in Iraq. Of course, a thorough awareness of the quality of all input well data and detailed validation of the parameters input to the inversion process is crucial to understanding the accuracy of the results.

Evaluating the efficiency of using different variants of background models for inversion calculations

2020 ◽  
pp. 36-52
Author(s):  
I. A. Kopysova ◽  
A. S. Shirokov ◽  
D. V. Grandov ◽  
S. A. Eremin ◽  
E. N. Zhilin
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Rock Properties ◽  
Elastic Parameters ◽  
Reservoir Properties ◽  
Acoustic Inversion ◽  
Well Data ◽  
Background Models ◽  
Effective Penetration

The use of the method of seismic data acoustic inversion, in the presence of thick gas cap, can lead to difficulties when building background models of elastic parameters. In this regard, in the conditions of acoustically contrast thin environments within the perimeter of the Russkoye oil and gas condensate field, in addition to the standard version based on the well data, the authors considered a number of modified techniques ("block", "flat", and background models). The use of these background models provided the best results and made it possible to significantly improve the quality of predicting rock properties; based on the drilling results, effective penetration was ensured at 66 %, which was 102 % of the plan. Also, based on the inversion results, it became possible to predict reservoir properties using the Bayesian lithotype classification method.

scholarly journals Monte Carlo reservoir analysis combining seismic reflection data and informed priors

Geophysics ◽  
2015 ◽  
Vol 80 (1) ◽  
pp. R31-R41 ◽  
Author(s):  
Andrea Zunino ◽  
Klaus Mosegaard ◽  
Katrine Lange ◽  
Yulia Melnikova ◽  
Thomas Mejer Hansen
Keyword(s):  
Monte Carlo ◽  
Seismic Data ◽  
Seismic Reflection ◽  
Probabilistic Approach ◽  
Multiple Point ◽  
Petroleum Reservoir ◽  
Inversion Algorithm ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Reflection Data

Determination of a petroleum reservoir structure and rock bulk properties relies extensively on inference from reflection seismology. However, classic deterministic methods to invert seismic data for reservoir properties suffer from some limitations, among which are the difficulty of handling complex, possibly nonlinear forward models, and the lack of robust uncertainty estimations. To overcome these limitations, we studied a methodology to invert seismic reflection data in the framework of the probabilistic approach to inverse problems, using a Markov chain Monte Carlo (McMC) algorithm with the goal to directly infer the rock facies and porosity of a target reservoir zone. We thus combined a rock-physics model with seismic data in a single inversion algorithm. For large data sets, the McMC method may become computationally impractical, so we relied on multiple-point-based a priori information to quantify geologically plausible models. We tested this methodology on a synthetic reservoir model. The solution of the inverse problem was then represented by a collection of facies and porosity reservoir models, which were samples of the posterior distribution. The final product included probability maps of the reservoir properties in obtained by performing statistical analysis on the collection of solutions.

Model-based amplitude versus offset and azimuth inversion for estimating fracture parameters and fluid content

Geophysics ◽  
2017 ◽  
Vol 82 (2) ◽  
pp. M1-M17 ◽  
Author(s):  
Jiao Xue ◽  
Hanming Gu ◽  
Chengguo Cai
Keyword(s):  
Seismic Data ◽  
Shear Fracture ◽  
Influencing Factor ◽  
Fractured Reservoirs ◽  
Fracture Density ◽  
Inversion Algorithm ◽  
Fluid Content ◽  
Fracture Parameters ◽  
Amplitude Versus Offset ◽  
Amplitude Versus

The normal-to-shear fracture compliance ratio is commonly used as a fluid indicator. In the seismic frequency range, the fluid indicator lies between the values for isolated fluid-filled fractures and dry fractures, and it is not easy to discriminate the fluid content. Assuming that the fracture surfaces are smooth, we use [Formula: see text], with [Formula: see text] and [Formula: see text] representing the normal fracture weakness of the saturated and dry rock, to indicate fluid types, and to define a fluid influencing factor. The fluid influencing factor is sensitive to the fluid properties, the aspect ratio of the fractures, and the frequency. Conventionally, the amplitude versus offset and azimuth (AVOA) inversion is formulated in terms of the contrasts of the fracture weaknesses across the interface, assuming that the fractures are vertical with the same symmetry axis. We consider fractures with arbitrary azimuths, and develop a method to estimate fracture parameters from wide-azimuth seismic data. The proposed AVOA inversion algorithm is tested on real 3D prestack seismic data from the Tarim Basin, China, and the inverted fracture density show good agreement with well log data, except that there are some discrepancies for one of the fractured reservoir sections. The discrepancies can be ascribed to neglect of the dip angle for the tilted fractures and the conjugate fracture sets, and to the validity of the linear-slip model. The fractured reservoirs are expected to be liquid saturated, under the assumption of smooth fractures. Overall, the inverted fracture density and fluid influencing factor can be potentially used for better well planning in fractured reservoirs and quantitatively estimating the fluid effects.

scholarly journals Application of geophysical methods in the extrapolation of sedimentological data on unmastered areas of deposits (on the example of Pennsylvanian carbonate reservoir, Akanskoye oilfield, east of Russian Platform)

2021 ◽  
pp. 128-134
Author(s):  
B. V. Platov ◽  
◽  
A. N. Kolchugin ◽  
E. A. Korolev ◽  
D. S. Nikolaev ◽  
...  
Keyword(s):  
Seismic Data ◽  
Geophysical Methods ◽  
Russian Platform ◽  
Carbonate Reservoir ◽  
Reservoir Properties ◽  
Reservoir Characteristics ◽  
The North ◽  
Study Results ◽  
Core Study ◽  
Well Data

A feature of the oil-bearing carbonate deposits of the lower Pennsylvanian in the east of the Russian platform is their rapid vertical and horizontal change. It is often difficult to make correlations between sections, especially in the absence of core data when using only geophysical data. In addition, not all facies are reliably identified and traceable from log data and not all have high reservoir properties. Authors made an attempt to trace the promising facies both to adjacent wells and, in general, to the entire field area using core study results and translation of these results using log and seismic data. The data showed pinching of rocks with high reservoir characteristics in the direction of the selected profile (from south to north within the field). Coastal shallow water facies, represented by Grainstones and Packstones, with high reservoir properties in the south of the field, are replaced by lagoon facies and facies of subaerial exposures, represented by Wakestones and Mudstones with low reservoir characteristics, in the north of the field. The authors suggest that this approach can be applicable for rocks both in this region and for areas with a similar structure. Keywords: pinch-out; well data; seismic data; limestone; facies; reservoir rocks.

Exploration of an unconventional petroleum resource through extensive core analysis and basin geology interpretation utilising play element methodology: the Lower Goldwyer Formation, onshore Canning Basin, Western Australia

2019 ◽  
Vol 59 (1) ◽  
pp. 464 ◽  
Author(s):  
Jop van Hattum ◽  
Aaron Bond ◽  
Dariusz Jablonski ◽  
Ryan Taylor-Walshe
Keyword(s):  
Oil And Gas ◽  
Fluid Composition ◽  
Reservoir Properties ◽  
Oil And Gas Development ◽  
Flow Rates ◽  
Canning Basin ◽  
Petroleum Systems ◽  
Multi Stage ◽  
Play Elements ◽  
Extractable Organic Matter

Theia Energy Pty Ltd1 (Theia Energy) discovered a potential unconventional hydrocarbon resource in the Ordovician Lower Goldwyer (GIII) Formation shale located on the Broome Platform of the onshore Canning Basin. The collation, processing, analysis and interpretation of all available regional data culminated in a successful exploration well, Theia-1 (drilled in 2015), which, based upon petrophysical and core analyses, intersected a 70 m gross oil column at 1500–1570 m depth. Theia-1 recovered essential core and wireline log data required to analyse and assess the play elements and reservoir properties necessary for a viable shale oil and gas development. Utilisation of an ‘Unconventional Play Element’ methodology has proven the unconventional hydrocarbon potential of the GIII Formation, and preliminary modelling indicates that economic stimulated flow rates may be achieved. Further operations (a test well with multi-stage hydraulic fracture stimulation) are scheduled in the coming permit year to further quantify the presence of extractable organic matter in the GIII Formation, assess hydrocarbon flow rates, determine fluid composition and appraise commercial viability. This paper will discuss Theia Energy’s exploration campaign in the onshore Canning Basin starting with the regional evaluation, which encompassed all available geoscience data (offset wells, pre-existing seismic and potential analogue fields) and modern specialised shale analysis (sequence stratigraphy, paleogeography, geochemistry, unconventional petrophysics and petroleum systems modelling), to develop a robust regional geological model for the GIII Formation. Pre-drill analysis reduced exploration risk and successfully identified the key geological play elements essential for the successful Theia-1 exploration evaluation program.

Pre-Messinian Petroleum Systems and Trap Style in the Offshore Western of Nile Delta; An Integrated Geological and Geophysical Approach

2016 ◽  
Author(s):  
Mostafa Monir ◽  
Omar Shenkar
Keyword(s):  
Seismic Data ◽  
Nile Delta ◽  
Lower Pressure ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Geochemical Data ◽  
Peak Oil ◽  
West Nile ◽  
Petroleum Systems ◽  
Well Data

ABSTRACT Exploration in the offshore Nile Delta province has revealed several hydrocarbon plays. Deep marine Turbidites is considered one of the most important plays for hydrocarbon exploration in the Nile Delta. These turbidites vary from submarine turbidite channels to submarine basin floor fans. An integrated exploration approach was applied for a selected area within West Delta Deep Marine (WDDM) Concession offshore western Nile Delta using a variety of geophysical, geological and geochemical data to assess the prospectivity of the Pre-Messinian sequences. This paper relies on the integration of several seismic data sets for a new detailed interpretation and characterization of the sub-Messinian structure and stratigraphy based on regional correlation of seismic markers and honoured the well data. The interpretation focused mainly on the Oligocene and Miocene mega-sequences. The seismic expression of stratigraphic sequences shows a variety of turbidite channel/canyon systems having examples from West Nile delta basin discoveries and failures. The approach is seismically based focusing on seismic stratigraphic analysis, combination of structure and stratigraphic traps and channels interpretation. Linking the geological and geophysical data together enabled the generation of different sets of geological models to reflect the spatial distribution of the reservoir units. The variety of tectonic styles and depositional patterns in the West Nile delta provide favourable trapping conditions for hydrocarbon generations and accumulations. The shallow oil and gas discoveries in the Pliocene sands and the high-grade oils in the Oligo-Miocene and Mesozoic reservoirs indicate the presence of multiple source rocks and an appropriate conditions for hydrocarbon accumulations in both biogenic and thermogenic petroleum systems. The presence of multi-overpressurized intervals in the Pliocene and Oligo-Miocene Nile delta stratigraphic column increase the depth oil window and the peak oil generation due to decrease of the effective stress. Fluids have the tendency to migrate from high pressure zones toward a lower pressure zones, either laterally or vertically. Also, hydrocarbons might migrate downward if there is a lower pressure in the deeper layers. Well data and the available geochemical database have been integrated with the interpreted seismic data to identify potential areas of future prospectivity in the study area.

scholarly journals Tectonosedimentary framework of Upper Cretaceous –Neogene series in the Gulf of Tunis inferred from subsurface data: implications for petroleum exploration

2017 ◽  
Vol 68 (2) ◽  
pp. 97-108 ◽  
Author(s):  
Wissem Dhraief ◽  
Ferid Dhahri ◽  
Imen Chalwati ◽  
Noureddine Boukadi
Keyword(s):  
Seismic Data ◽  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Tectonic Activity ◽  
Petroleum Systems ◽  
Subsurface Structures ◽  
Gulf Of Tunis ◽  
Northeastern Tunisia ◽  
Well Data

Abstract The objective and the main contribution of this issue are dedicated to using subsurface data to delineate a basin beneath the Gulf of Tunis and its neighbouring areas, and to investigate the potential of this area in terms of hydrocarbon resources. Available well data provided information about the subsurface geology beneath the Gulf of Tunis. 2D seismic data allowed delineation of the basin shape, strata geometries, and some potential promising subsurface structures in terms of hydrocarbon accumulation. Together with lithostratigraphic data obtained from drilled wells, seismic data permitted the construction of isochron and isobath maps of Upper Cretaceous-Neogene strata. Structural and lithostratigraphic interpretations indicate that the area is tectonically complex, and they highlight the tectonic control of strata deposition during the Cretaceous and Neogene. Tectonic activity related to the geodynamic evolution of the northern African margin appears to have been responsible for several thickness and facies variations, and to have played a significant role in the establishment and evolution of petroleum systems in northeastern Tunisia. As for petroleum systems in the basin, the Cretaceous series of the Bahloul, Mouelha and Fahdene formations are acknowledged to be the main source rocks. In addition, potential reservoirs (Fractured Abiod and Bou Dabbous carbonated formations) sealed by shaly and marly formations (Haria and Souar formations respectively) show favourable geometries of trap structures (anticlines, tilted blocks, unconformities, etc.) which make this area adequate for hydrocarbon accumulations.

Integrated geologic, geophysical, and petrophysical data to construct full field geologic model of Cambrian-Ordovician and Upper Cretaceous reservoir formations, Central Western Sirte Basin, Libya

2019 ◽  
Vol 7 (1) ◽  
pp. T21-T37
Author(s):  
Abdalla A. Abdelnabi ◽  
Yousf Abushalah ◽  
Kelly H. Liu ◽  
Stephen S. Gao
Keyword(s):  
Upper Cretaceous ◽  
Thickness Variation ◽  
Reservoir Properties ◽  
Full Field ◽  
Vertical Heterogeneity ◽  
Field Static ◽  
Original Oil In Place ◽  
Well Data ◽  
Sirte Basin

The Cambrian-Ordovician and Upper Cretaceous formations, which are the main oil-producing formations in the central Sirte Basin, are structurally complex. The lateral and vertical heterogeneity of the reservoir formations is not well-understood, which negatively affects the performance of the reservoirs. We constructed efficient full-field static models that incorporate the lateral and vertical variation of those reservoir formations by integrating geologic and geophysical data. We determined lithology and reservoir properties by selecting appropriate petrophysical techniques that suit the available well data and overcome issues with unreliable well-log measurements. In the process of building structural models, defining and mapping the base of the Cambrian-Ordovician Gargaf Formation was very challenging because wells did not penetrate the basal formation, and the quality of the seismic data decreases with depth. Therefore, we applied techniques of adding isochore maps of the overlying Upper Cretaceous of the Bahi and Waha Formations to map basal contact and determine the thickness of the Gargaf Formation for the first time in the area. The constructed isochore maps showed the thickness variation and the distributions of the Bahi and Waha Formations and explained the influence of Gargaf paleotopography and faults on them. The fault models combined with facies and property models suggested an interconnection among the three main reservoirs. They also indicated that the quality of the Waha reservoir enhances as the lithology varies from limestones to calcareous sandstones, whereas the quality of the Gargaf reservoir was primarily controlled by fractures. The total estimate of the original oil in place with the largest contribution of hydrocarbon volume from the Waha Formation was [Formula: see text] stock tank barrel. The created model with a fine-scale geocellular covering an area of [Formula: see text] is unique to the study area and it can be updated and refined at any time with new data production and drilling activities.

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