Publications

Beicip-Franlab will present the following paper in 2021, First Break, volume 39.

Integration of VSP in the process of surface seismic data inversion

N. de Freslon*, L. Cuilhe*, S. Yareshchenko**, Y. Solodkyi**, I. Gafych**, C. Rudling***, N. Lucet*, N. Desgoutte* and V. Machault*
*Beicip-Franlab, **DTEK, ***RPS

https://www.earthdoc.org/content/journals/10.3997/1365-2397.fb2021041

Abstract

The measurements of vertical seismic profiles (VSP) used in the petroleum industry are often limited to direct arrivals to establish time-depth laws. Many other measurements such as PP and PS corridor stacks, offset vertical seismic profiles (OVSP) and walkaway can help to predict P and S wave impedances estimated by inversion of surface seismic data.
This article shows the use of all available VSP records to constrain the inversion of surface seismic data and predict matrix properties of Carboniferous and Devonian intervals in the Machukhske gas field in the Ukrainian Dnieper-Donetsk basin.
The use of PS corridor stack, in addition to PP corridor stack, allows a better optimization of the S impedance at the well. Moreover, corridor stacks allow a better estimate of the P and S impedance below the well TD than surface seismic data alone, and therefore an enhanced characterization of the Devonian sands, which has been drilled by only a few wells. OVSPs help build a more reliable a priori model by confirming or discarding the faults identified on the 3D seismic.
Results of reservoir characterization show a clear impact of the VSP integration on lithology prediction from surface seismic data.

Optimized P-impedance sections resulting from WVSP and surface seismic data (left) and P-impedance traces comparison (right): well-log P-impedance in black, optimized P-impedance from WVSP inversion in blue and from surface data inversion in red

Beicip-Franlab will present the following talk at EAGE 2021.

Use of classification technique to characterize porous carbonate reservoir in Machukhy field, onshore Ukraine, 2021

N. de Freslon*, L. Cuilhe*, S. Yareshchenko**, C. Rudling***, N. Lucet*, N. Desgoutte*, V. Machault*, Y. Solodkyi** and I. Gafych**
*Beicip-Franlab, **DTEK, ***RPS

https://www.earthdoc.org/content/papers/10.3997/2214-4609.202112537

Abstract

Seismic reservoir characterization, following a seismic inversion, plays a key role to capture the vertical and lateral variations of matrix properties for advanced geosciences workflow. Geological constraint can be obtained by using a classification technique trained by well data samples such as discriminant analysis, which is a Bayesian supervised approach, to obtain probability of assignment into facies. Additional properties such as porosity can therefore be characterized depending on the predicted facies for more accuracy.
The present paper describes the work performed on the Machukhy field, focusing on the evaluation of Carboniferous carbonate reservoirs in the Ukrainian Dniepr-Donetsk Basin. The objective consists in performing model-based inversion (Aki and Richards, 1980) and reservoir characterization workflows in order to provide key elements to help predicting inter-well reservoir location, thickness and properties behaviour using inversion results and identifying possible drilling locations for development and exploration wells. The main targets are associated with the Tournaisian carbonate formation.
Reservoir characterization, following 3D PP surface seismic inversion, is performed to assess the reservoir potential of the area in term of facies and porosity distribution. A two-pass discriminant analysis is performed in order to first to isolate massive carbonate facies and predict the porous carbonate facies. Then, the porosity is predicted within the massive carbonate facies.

Discriminant analysis of porous carbonate facies after upscaling (a) Histogram of effective porosity distribution with a cut-off to define the porous carbonate facies (b) Inverted IP versus IS crossplot coloured by facies before assignment (c) Re-assignment histogram (d) Inverted IP versus IS crossplot coloured by the probability of good assignment into porous carbonate facies

Beicip-Franlab will present the following talk at EAGE 2021.

Forward Stratigraphic Modelling at reservoir scale, statistical comparison with common geostatistical methods and fractal behaviour

Arnaud FOURNILLON, Samer BOU DAHER, Emerson MARFISI, Nicolas HAWIE, Marie CALLIES
Division of Global Solutions, Beicip-Franlab, Rueil-Malmaison, France, 
arnaud.fournillon@beicip.com

Abstract

Capturing lithofacies heterogeneities and their associated petrophysical properties is a key challenge to provide reliable static models. The several geostatistical methods commonly used for this task apply a combination of hard and soft constraints provided from cores, well logs and seismic interpretation. A major challenge remains in bridging the resolution gap between these multi-disciplinary datasets and thus reproducing the geological complexity of depositional environments where few data is available.
In this communication, we propose an innovative approach that combines Forward Stratigraphic Modelling (FSM) with geostatistics in order to construct geomodels that accurately capture the reservoir heterogeneities while accounting for geological processes and uncertainties. Fractals and metrics of geobodies connectivity are used in order to quantify the benefits of such FSM method compared to Truncated Gaussian Simulation (TGS) and Sequential Indicator Simulation (SIS). It appears that forward stratigraphic modelling produces more realistic results compared to TGS and SIS. Both visual aspect and statistical parameters show that the obtained distribution of facies is more geologically sound. 
It enables both preserving the observed heterogeneity at wells and gaining in geobodies connectivity. 
This last parameter is a key advantage when passing from static to dynamic models.

Beicip-Franlab will present the following talk at EAGE 2021.

Geological Equiprobable Multi-Models for Resources Assessment. Carson, Bonnition and Salar Basin, NL, Canada

Presenter: Dr Erwan Le Guerroué (Beicip-Franlab) 
Author(s): E. Le Guerroué [1]*, P. Jermannaud [1], G. Perez-Drago [1], B. Lebreuilly [1], T. Pichot [1], P. Chenet [1], D. Norris [2], E. Gillis [2], R. Wright [2] 
Affiliation(s): [1] Beicip-Franlab; [2] Nalcor Energy

Introduction

The underexplored Carson, Bonnition and Salar basins appear prospective for oil and gas, after newly acquired regional 2D seismic data shows evidence of leads that have been tested using data-calibrated, equiprobable alternative petroleum system models. The objective of the petroleum system assessment was to provide petroleum resource estimates for the area through seismic structural and stratigraphic interpretation, and 2D/3D basin modelling for play risk analysis and volume estimates of hydrocarbon (HC) accumulation. Basin modeling was set up in order to account for alternative realistic (geologically possible) models. Such a multi-scenario approach was designed to account for some parameters that contained inherent uncertainty due to the limited data available in this frontier region.

Integrating Numerical Modelling Approaches in Conceptual Hydrocarbon Exploration

Beicip-Franlab will present the following talk at AAPG GTW Saudi Arabia 2019 

Nicolas Hawie¹

1 Beicip-Franlab, Rueil-Malmaison, France

Abstract

This communication discusses the return on experience of the latest innovation tackling Hydrocarbon Exploration in mixed sedimentary systems (i.e., carbonate, evaporites and siliciclastics) using integrated modelling approaches and sensitivity analysis.

Predicting the presence as well as the lateral and vertical extent and heterogeneities of Petroleum Systems elements remains a major challenge in the Oil and Gas industry as traditional conceptual and/or stochastic techniques appear to be insufficient in capturing vertical and lateral variability of facies and textures in complex reservoirs.

The use of Forward Stratigraphic models helps testing the proposed Conceptual Plays by achieving a more geologically sound and constrained 3D sequence stratigraphic framework that results in the generation of ecological, bathymetric and facies maps needed to better localize the development of reservoirs, seals as well as stratigraphic traps.

The workflow developed following various international projects (Arabian Plate, North and Central America, Europe) tackles the several limitations witnessed while using stochastic methodologies by (1) achieving a multi-disciplinary data integration, (2) accounting for the evolution of geological processes with time, (3) representing complex sedimentary geometries (algal mounds, reefs, aggradation, progradation, clinoforms), (4) assessing the sensitivity of the proposed geological model with regards to the evolution of environmental conditions and by (5) generating multiple plausible geological scenarios and facies probability/risk grids (6) Integrating the FSM results in a Basin Model to map the hydrocarbon expulsion, migration, charge and accumulation with regards to the tectonostratigraphic evolution of the system. The ultimate aim of this approach is to push the industry towards more geologically plausible and integrated numerical techniques to tackle the Play Fairway Assessment and de-risk petroleum systems elements. 

Exploring Siliciclastic Systems of Arabia Through Integrated Forward Stratigraphic Modeling and Multi-simulation Approaches

Beicip-Franlab will present the following talk at AAPG GTW Oman 2019 

 Nicolas Hawie¹

1 Beicip-Franlab, Rueil-Malmaison, France

Abstract

This work comes in the context of off-structure assessment of Paleozoic and Mesozoic siliciclastic systems of Arabia using innovative and integrated G&G approaches. Many challenges linked to the exploration of new hydrocarbon resources in such Mature Basins are driving innovative ideas towards the identification, the assessment and the de-risking of new subtle Plays. As important multi-scale and multi-disciplinary dataset (e.g., 2D, 3D seismic data, core and well log data and imagery…) have been acquired in the past decades along major structural features new frontiers are opening around major discovered sectors as well as in the offshore. This paper discusses the results of an innovative methodology developed to assess the detection of subtle stratigraphic trapping mechanisms using multi-disciplinary and multi-scale sedimentological, stratigraphic, petrophysical and geophysical techniques including seismic inversion and characterization as well as supported by regional process based deterministic DionisosFlow™ 4D forward stratigraphic models. The integration of CougarFlow™ automated multi-simulation approaches permits a better assessment of the impact of structural as well as environmental parameters on the sedimentary transport as well as deposition of fine versus coarse grained sediments laterally but also vertically. We also discuss the importance of stratigraphic scaling in the identification of sub-seismic stratigraphic traps and highlight the more consistent approaches to build sedimentary facies maps that are later integrated in petroleum systems models to simulate the impact of basinal evolution on hydrocarbon generation, migration and trapping. This workflow applied in mature sectors of the Arabian Plate sets new grounds for the generation of regional Play Fairway Maps, Common Risk Maps for the different Petroleum systems elements (reservoir, seal, trap and charge) as well as Composite Common Risk Maps. These tasks are aimed at assessing the overall risk associated to Plays and thus contribute to the identification of new exploration Lead Areas to be further de-risked in the near future

Coreflood Model Optimization Workflow for ASP Pilot Design Risk Analysis

Beicip-Franlab will present the following talk at MEOS Manama Bahrein March 2019

Olga Borozdina¹, Magnolia Mamaghani¹, Romain Barsalou¹, Martin Lantoine¹, Agnes Pain¹

1 Beicip-Franlab, Rueil-Malmaison, France.

Abstract

This work presents a new workflow to obtain a better-constrained reservoir-scale model for an Alkaline-Surfactant-Polymer (ASP) injection pilot design. It is explained how the impact of uncertain parameters related to ASP flooding can be quantified, using calibrated core-scale simulation based on experimental results, and how the influential parameters range for future reservoir-scale simulation can be determined. Computational costs of core-scale model are therefore much lower, and the final reservoir model is better constrained.
ASP flooding feasibility implies core scale studies, where chemical formulations are validated in the laboratory under field conditions. In the objective of the pilot designing, a numerical model is constructed and calibrated to history-match the core flood sequences: Remaining Oil Saturation (ROS), surfactant-polymer (SP) and polymer-alkaline (PA) injection and eventually the chase water slug. In order to quantify the impact of ASP chemical parameters on the history match, the Global Sensitivity Analysis (GSA) was performed using Response Surface Modeling (RSM). To obtain the acceptable range of influential parameters for future reservoir-scale simulation, the Bayesian optimization is used.
Applying this methodology on a real reservoir core, the laboratory measurements are accurately reproduced. Nevertheless, once the core-scale model was matched, the transition to reservoir-scale model must be done. Due to a large number of parameters and their associated uncertainties, this transition is not straight-forward. Thus, an additional step in our workflow is included. A new methodology is applied to firstly quantify the impact of uncertain parameters related to ASP flooding (adsorption of surfactant on the rock, critical micellar concentration, water mobility reduction by polymer etc.). To do so, the RSM is used and influential parameters are identified. In this study, the surfactant adsorption coefficients are the most influential parameters while others related to SPA have a poor impact on experiment results matching. Secondly, the acceptable range of influential parameters for future reservoir-scale simulation and feasibility study is obtained during Bayesian optimization. Thus, instead of using a wide (prior) range of uncertain parameters values, refined (posterior) distribution laws can be used for future reservoir model.
While the classical approach consists in matching experimental results to obtain calibrated values of certain properties (that are then entered in the reservoir model) and finally determine the influential parameters at the reservoir scale, here the choice was made to determine influential parameters and characterize their impacts at the core scale. This step helps to better constrain the reservoir model. Ongoing work is using the results of this workflow for pilot design and risk analysis.

Downward migration as a potential mechanism for HC accumulation in the Early Cretaceous Serdj and Allam plays of the Kaboudia Block, Gulf of Hammamet, offshore Tunisia.

Mouchot Nicolas¹, Doublet Stefan¹, Arab Mohamed², Hassaim Mohamed², Aissaoui Safia², Guizani Aymen², Bedjaoui Chakib², El Mahersi Chokri², Hmad Zakaria², Abderrahmane Rachedi², Karim Belabed³, Pierre-Yves Chenet¹

1 Beicip-Franlab - 232 avenue Napoléon Bonaparte, F-92500 Rueil-Malmaison, France
2 NUMHYD - Imm l'Union Centre .R du Lac de Mazuerie, Les Berges du Lac T-1053 Tunis, Tunisie
3 SIPEX

Abstract

The Kaboudia Offshore Permit is a prospective Mesozoic hydrocarbon province in the Gulf of Hammamet. The main petroleum system of the Kaboudia area comprises 2 proven plays in the Mid-Cretaceous time: the Aptian Serdj reservoir and the Albian Allam reservoir. These plays were proven positive with several oil discoveries in the area of interest.
The Mouelha organic-rich layer is a proven Late Albian regional source rock Tunisia. It is recognised onshore Tunisia and locally offshore when drilled by wells. Based on geochemical evidences, it is suggested that the regional Mouelha source-rock could feed these reservoirs. In this setting, the Mouelha SR is stratigraphically above the lower Allam and the upper Serdj reservoirs (Figure 1) leading HCs migration either by a “per descensum” migration process (Chi et al., 2010; Dubille et al., 2017) or by a fault-driven process.
Despite a fair knowledge of the elements of the petroleum system offshore Tunisia, no integrated study has been performed to evaluate the assumption on the petroleum system. In 2017, a complete 1D, 2D and 3D migration modelling study has been performed by Beicip-Franlab and Numhyd in order to synthetize information and to improve the knowledge on the mechanism that drives the HCs in the Allam-Serdj reservoirs.

Biogenic and Thermogenic Hydrocarbon Potential of the South Levant Basin and Eastern Nile Delta, Offshore

Beicip-Franlab will present the following talk at EAGE Egypt

Pérez-Drago G¹, Dubille M¹, Montadert L¹, di Biase D², Brivio L², Hosni M³, Zaky A³

1. Beicip-Franlab, Rueil-Malmaison, France.
2. Edison E&P, Milano, Italy.
3. Edison E&P Egypt Branch, New Cairo, Egypt.

Abstract

Edison E&P and Beicip-Franlab carried out a petroleum system analysis honoring recent 3D seismic interpretation and regional knowledge in a large area around the Edison’s operated license North Thekah Offshore (NTO), Egypt. The objective was to evaluate the hydrocarbon potential and the petroleum system efficiency of the area for derisking Plays and Prospects, through a 3D basin modeling approach accounting for biogenic and thermogenic hydrocarbons generation and charge. The methodology comprises a macroscopic modeling of microbial gas generation within a compositional kinetic scheme accounting for biogenic and thermogenic HC generation in function of thermal stress. Crustal heat-flow evolution with synchronous burial history and pore pressure regimes were simulated through geological time in order to identify favorable conditions for biogenic gas generation and preservation (heating rates ~7 to 18 °C/Ma). Simulated thermal and pressure variations during Messinian crisis had a significant impact on source rock expulsion timing and HC fluid migration and charge. HC expulsion and migration modeling evidences three (3) main Plays charged by local sources: 1) Lower/Late Oligocene biogenic to thermogenic source, charging Lower Miocene-Late Oligocene reservoirs and Cretaceous shallow water carbonates (locally liquid-rich thermogenic condensates), 2) Middle/Upper Miocene biogenic gas source, charging Middle/Upper Miocene reservoirs, 3) Pliocene biogenic gas source charging Plio-Pleistocene reservoirs.

Petroleum System Modeling in Complex Structural Settings: Application to the Bolivian Southern Andean Foothills.

Beicip-Franlab will present the following talk at AAPG ICE Buenos Aires, Argentina, August 2019

F. Schneider¹, A. Thebault¹, M. Callies¹, and R. Giraudo¹.

1 Beicip-Franlab, Rueil-Malmaison, France.

Abstract

Petroleum system modeling is recognized as a critical step in exploration workflows. However, fold and thrust belts are typical regions where classic basin modeling tools do not accurately manage the combination of lateral and vertical tectonic displacements. These complex areas require more accurate modeling approaches integrating active faulting, folding and fluid flow. The basin burial and geometry reconstruction, and fault connectivity should thus account for the horizontal deformation through time. Then, the basin simulator should use the produced kinematic scenario for the forward simulation of heat transfer, pressure, hydrocarbon generation, migration and accumulation considering the faults impact on fluid flow.

An application case from the Bolivian Southern Andean foothills illustrates the applicability of these technology and workflow. Preliminary structural reconstruction work detailing the main deformation phases of the area is used to guide the complete kinematic scenario. Forward basin simulation is then run and the model, calibrated to available well, outcrop, and field data, allows testing the impact of thrusting on maturation, migration pathways, and hydrocarbon charge.

The model is made of 15 stratigraphic units from Paleozoic to Present Day. Three source rock levels are included in the model, and main reservoirs are good sands deposited during the Paleozoic. The initial shortening is received between 12 and 10Ma from the Inter Andean and transmitted to the East until present day, resulting in a complex succession of thrusts, out of sequence thrusts and back-thrusts. The model shows good maturity levels with high transformation ratios for deepest source rocks. Hydrocarbon generation started during Permian-Triassic time and is boosted during Pliocene. It leads to a favorable timing for HC trapping with deformation in the Western area where we observe accumulations in structural and fault traps. In particular, the existing accumulations are well reproduced, and the model predicts favorable charge conditions for a prospect that is about to be drilled.

Importance Of Multi-Scale Petroleum System Assessment For Plays And Prospects De-Risking In The Eastern Mediterranean Basin.

Beicip-Franlab will present the following talk at AAPG GTW Alexandria, Egypt, September 2019

Pérez-Drago G¹, Dubille M¹, Montadert¹, Schneider F¹, Mouchot N¹, Chenet P¹, Callies M¹, Thebault A¹

1 Beicip-Franlab, Rueil-Malmaison, France

Abstract

Identifying the potential geological risks before drilling leads and prospects is a common practice for E&P operator companies. Traps and reservoir quality often receive the main attention during risk assessment. However, in the Eastern Mediterranean the biogenic gas sources generation, the synchrony between trap formation and hydrocarbon charge, and more important, the hydrocarbon preservation related to the large-scale hydrodynamics of the basin, are less analyzed or understood.

A key element in the Eastern Mediterranean mega basin is the assessment of the biogenic gas potential, both in term of generation but also of preservation in the geological system. The effectiveness of biogenic gas systems is mainly controlled by the past thermal gradients and sedimentation rates. Contrarily to conventional source rocks, significant rock volumes with low organic matter content are likely involved in the biogenic gas generation process. In the deepest parts of the basin, Tertiary biogenic gas source rocks are now undergoing catagenesis.

Another key element is the fluid flow history from the core of the Eastern Mediterranean basin toward its margins (including Eratosthenes Sea Mount). The hydrodynamics is first induced by high sedimentation rates and sediments compaction within the Nile Delta and the Levant Basin during the Oligo-Miocene and Plio-Pleistocene. During the Messinian Crisis short term 1400m sea level drop followed by massive impervious evaporite deposition plays a very important role in the evolution of fluid flow orientation, pressure gradients and hydrocarbon migration and dis-migration. The fluid flow is also controlled by the presence of a relatively well-connected pressure unit in Oligo-Miocene sands throughout the Levant Basin. Active hydrodynamism and buoyancy of biogenic gas are the main factors controlling the hydrocarbon migration mechanisms. A lateral long distance up-dip fill-and-spill migration is observed.

Therefore, a more complete understanding of the petroleum system behavior is achieved by recognizing the origin of the geochemical and physical phenomena occurring in the subsurface, in a regional or semi-regional basin scale. It will allow to recognize the hydrocarbon generation and the pore pressure and fluid flow regime patterns, which are not caught at limited prospect scale. Basin modeling techniques offer the possibility to estimate the heating rates of sedimentary basins, the timing and quantities of generation of biogenic or thermogenic hydrocarbons and, finally the pore pressure-effective stress regimes responsible, in part, for the hydrocarbon migration and effective charge.

Reducing Exploratory Risks Using Advanced Basin Modeling In a Complex Structural Setting – Parã-Maranhão Basin - Brazilian Equatorial Margin

Beicip-Franlab will present the following talk at AAPG ACE San Antonio, USA

Abstract
Felipe Nascimento1, Alcide Thebault², Marcia Kuhn Karam¹, Marie Callies², Eduardo de Mio¹
Queiroz Galvão Exploração e Produção, Rio de Janeiro, Brasil ¹
Beicip-Franlab, Rueil Malmaison, France ²

The Pará-Maranhão Basin is characterized as a passive margin basin with an orthogonal separation component related to the oblique opening of Equatorial Atlantic Margin during the Upper Albian.

The exploration efforts began in the middle seventies with few oil and gas discoveries from Cretaceous to Paleogene in shallow water. In the 2010´s decade, these efforts were moved from platform to deep water settings due to high resolution 3D seismic surveys that allowed the identification of potential hydrocarbon source rocks and well-developed channel-lobes turbidite systems rich in sandstones.

Those potential reservoirs were disconnected from slope to deep water settings by a gravity driven fold and thrust belt characterized by extensional, transitional and compressional domains which developed during Paleogene age. That disruption of the system was probably due to overloading caused by the deposition of a thick carbonate platform related to faults reactivation of the rift phase..

The main exploratory risks in this context are related to migration and charge issues due to structural complexity, the role of faults in migration and sealing, the effects of overloading in source rock maturation and expulsion timing, and the overpressure resultant of the material displacement.

The use of a new kinematic restoration tool, KronosFlow^TM, coupled with an unstructured mesh forward basin modeling tool (TemisFlow^TM), allowed the best prediction of the deformation timing, the evaluation of the synchronism between trap formation and hydrocarbon charge as well as the prediction of overpressure related to deformation and overloading.

Restoration results showed that the gravity driven system took place from Paleocene with the development of the listric growth fault systems in platform area and near slope, in the extensional domain. This imbricated fault system converges at the base to a detachment surface from Upper Albian. The evolution of this system from Eocene, with the overloading caused by sediment capture in roll-over systems triggered the rupture of the Santonian/Campanian sequences against a basement structural high and the beginning of the fold and thrust belt in the deepwater settings.

The timing of deformation and trap development improves the chance of charge from late source rock levels, as Turonian and Coniacian, believed to be present and mature in deep water settings in Pará-Maranhão Basin.

Beicip-Franlab will present the following talk at SPE Workshop, Bahrain 2019

The potential of foam-based injection processes for unlocking additional reserves in a giant fractured carbonate oil reservoir in the Middle East

Weber M¹.
1 Beicip-Franlab, Rueil-Malmaison, France

Abstract

Production of naturally fractured oil reservoirs is extremely challenging because of their adverse physics where viscous forces, which could be controlled, are inhibited and gravitational and capillary forces, which are inherent to the reservoir context and properties, are the only forces involved in oil recovery.
In fractured carbonate oil reservoirs, the typically strongly oil-wet character of rocks also prevents from implementing waterflooding techniques, leaving only gas injection and the associated Gas-Oil Gravity Drainage (GOGD) as a possible improved oil recovery technique beyond simple depletion scenarios. GOGD is however a slow process associated to limited ultimate oil recovery, and more advanced, enhanced oil recovery techniques should be considered in order to maximize oil production in such a context.
In this paper, we present the first step of an ambitious workflow aiming at unlocking the full potential of a giant fractured carbonate reservoir in the Middle East, which has yielded only about 25% of its oil in a 50-years production period, mostly by GOGD.
We test the potential of promising foam-based injection methods using a phenomenological flow simulation modeling approach at matrix block scale. In a first step, we describe the reservoir context and physical principles of our foam models. In a second step, we present encouraging flow simulation results indicating that (1) the foam injection processes tested allow improving the ultimate oil recovery in the blocks by several tens of percent compared with the GOGD case and, (2) that this incremental recovery is obtained with much improved kinetics, i.e. over a much shorter amount of time.
Finally, we discuss these results in terms of reservoir applicability and identify ways forward in order to de-risk the processes tested and pave the way to a future pilot implementation.

Beicip-Franlab will present the following talk at IAS Roma 2019 :

Importance of paleoenvironment reconstructions in geomodeling with scarce dataset: Cenomanian-Turonian carbonate platform from Northern Algeria

PRESENTED BY

Dr. Arnaud Fournillon (Beicip-Franlab)

AUTHORS

Dr. Arnaud Fournillon¹, Dr. Stefan Doublet¹, Dr. Jean-Marc Chautru¹, Ms. Naima Kherfi², Ms. Zahra Boudjemadi², Mr. Youcef Baba Ali² 

1. Beicip-Franlab
2. Sonatrach 

ABSTRACT

Upper Cretaceous from Northern Algeria is still a play under development. Most of structures are drilled with only few wells. In such condition, assessing the uncertainties and controlling the distribution of properties in undrilled areas is a key prerequisite for field development plans. We propose to integrate constraints from environment of deposition (EoD) reconstruction in order to improve the 3D geological models. This method is twofold with, firstly, a sedimentological study for defining the sedimentary sequences and building EoD maps. Secondly, geological modeling process, using these sequences and maps, is applied to compute a 3D trend cube of EoD on which is nested the distributions of reservoir properties. Volumetrics study shows the benefits of such methodology compared to direct interpolation/simulation of reservoir properties.

This study focuses on the Cenomanian and Turonian carbonate platform, covering the Ras Toumb and the upper part of the Zebbag formation. It consists in a rapid succession of carbonate, marls and shales over a thickness of around 300m. The reconstructed conceptual model of environment ranges from mud flat with fenestrae up to upper to lower offshore with calcisphere and planktic foraminifera mudstone/wackestone. In-between, shallow marine carbonate occurs characterized by grainstone/packstone with mollusks (including rudists), green algae and peloids.

Available dataset for the sedimentological study area is very scarce: only few wells, a single good quality core and scattered cuttings description, along with conventional logs. Consequently, the vertical resolution of the study has been limited to the cuttings description resolution. A continuous vertical curve of shallowing/deepening trend has been derived from the well-logs, tied with cuttings description, in order to overcome this issue. The studied interval has been represented by only five gross EoD maps, one per stratigraphic member, in order to limit the impact of low-resolution data. The full 3D cube of EoD is then derived by the integration of this vertical trend with EoD maps into a geomodelling software. This property cube enables the consistent representation of the rapid vertical transition, the conceptual geological model and the gross depositional environments per stratigraphic member. Stochastic simulations of reservoir properties, such as electrofacies and porosity, have been nested into this EoD cube.

Volumetric evaluations of hydrocarbons have been compared in order to assess the benefit of this method: firstly, a probabilistic Monte-Carlo approach has been applied in order to obtain a broad range of probable volumes; secondly, volume derived from direct stochastic simulation of properties has been compared to the volume obtained with paleoenvironmental constraints. Model without constraint has its volume around the P70 value, whereas the model with constraints is close to the P50 value.Thus, this method enables the control of stochastic simulation or interpolation in the extrapolated domain (faraway from hard data like wells) by the use of soft external (like EoD maps) data as trend. The scarcity of the dataset has been overcome by a careful management of resolution issues of all the available data.

General workflow from sedimentological and well data to volumetrics

Beicip-Franlab will present the following talk at EAGE Denmark 2018 :

Play Elements of the Chidley Basin, offshore Newfoundland and Labrador Canada

Erwan Le Guerroué¹, Paul Jermannaud¹, Pierre-Yves Filleaudeau¹, Guillermo Perez-Drago¹, Pierre-Yves Chenet¹ , Erin Gillis², Victoria Mitchell², Nicholas Montevecchi², Richard Wright²

1. Beicip-Franlab, Rueil-Malmaison, France.

2. Nalcor Energy, St. John's, NL, Canada.

Abstract

The underexplored Chidley Basin off the Labrador coast of Newfoundland Labrador, Canada is being investigated for oil and gas prospectivity after new seismic data acquisition.

We present here how the geology and geophysics data were integrated into a comprehensive 3D stratigraphic model which allowed the play elements of a potential petroleum system to be tested.

Regional geodynamic and sequence stratigraphic work facilitated the understanding of the basin architecture and infilling through the Labrador sea opening and transform fault zone activities. This provided the inputs of Gross Depositional Environment maps that ultimately enabled a forward stratigraphic model (DionisosFlow™) to be built.

This forward numerical model simulates the stratigraphic record of the basin through calibration of well record and integration of seismic data. The model helps to resolve the extension of known, hypothetical, and/or speculative source rocks, reservoirs, carrier beds and seals at the basin scale.

Based on this regional stratigraphic understanding, the source rocks, reservoir, and seal presence seven main plays in the basin were identified, defining a complete petroleum system that shall be now tested offshore in the light of the past shelf discoveries.

Beicip-Franlab will present the following poster at AAPG Bolivia 2018 :

Stratigraphic and sedimentary processes simulation to explore the Silurian and Devonian sequence in the Madre de Dios basin

Djowan Thomas¹, Frederic Schneider¹, Stephane Rousse¹, Jean-luc Faure¹, Olvis Padilla², and Bertrand Valsardieu¹,  Jorge. Pareja²

¹Beicip-Franlab, 232 av. Napoleon Bonaparte, 92500 Rueil-malmaison, France; djowan.thomas@beicip.com

² YPFB;  Av. Grigotá Calle Regimiento Lanza, Santa Cruz, Bolivia

ABSTRACT

Petroleum exploration of frontier areas, such as the Madre de Dios basin, requires an innovative model based approach in order to lower the exploration risks. For this purpose, the DionisosFlow^TM software has been used to explore the Silurian and Devonian stratigraphic sequence at regional scale and to determine if reservoirs observed at the wells location were likely to extend to the South where no well has been drilled.

The simulation of stratigraphic and sedimentary processes allowed to create a 3D geogrid predicting the internal stratigraphic architecture of the Silurian and Devonian series, consistent with well data, seismic and regional geological information. The geogrid includes reservoir distribution, sealing capacity and deposit environments.

Particularly, the resulting model has highlighted the presence of a large clinoform sequence during the middle Devonian period revealing a reservoir unit made of coastal to deltaic front sands extending toward the South of the basin. Such prograding sequence results from an uplift of about 200m where erosion and remobilization of sediment provided a large quantity of silico-clastic deposits to the south in deeper bathymetric area.

3D simulations of stratigraphic and sedimentary processes provided maps of net sand thickness and seal distribution all over the basin. A subtle tectonic event was identified defining a new potential play in the Madre de Dios basin originating from a mild regional structuration inducing structural traps. Additionally, the model provided a consistent stratigraphic chart for Silurian and Devonian period.

Beicip-Franlab will present the following poster at AAPG Bolivia 2018 :

Petroleum Systems Modeling and Hydrocarbon Charge Assessment in Pie De Monte Boomerang Province, Bolivia 

Guillermo Pérez-Drago¹, Frederic Schneider¹, Stephane Rousse¹, Jean-Luc Faure¹, Olvis Padilla² 

¹Beicip-Franlab, 232 av. Napoleon Bonaparte, 92500 Rueil-malmaison, France;

² YPFB;  Av. Grigotá Calle Regimiento Lanza, Santa Cruz, Bolivia

ABSTRACT

An active petroleum system is recognized by producing fields in Boomerang Pie de Monte foreland basin in stratigraphic up-dip and structural traps of Silurian-Devonian and Cretaceous formations. The area is considered as one of the most prolific gas provinces in Bolivia. However, the timing of hydrocarbon expulsion and migration versus trap formation remains unclear as confirmed by dry wells showing low gas shows of residual by-passed hydrocarbons.  

To reduce this uncertainty, we built a basin model that honors seismic structural interpretation and well data to simulate burial history, temperature, source rock maturity and pressure regimes through geological time. Hydrocarbon expulsion from source-rocks and further HC migration was simulated using 3D basin fluid flow modeling based on Darcy flow equation, followed by a map based fetch area trap charge assessment.

The main source rock units correspond to Silurian-Devonian sequences with influence of continental-marine environments (kerogen Type II/III). Maturity trend increases from north to south due to higher burial. Two phases of hydrocarbon expulsion were recognized: one early expulsion phase from Silurian source rocks during Late Triassic and a second expulsion phase from Early Devonian source rocks during Late Jurassic-Early-Cretaceous times.

Lateral long distance up-dip migration through Robore formation occurred before Andean deformation, following a northward fill and spill trap charge accumulating below Late Jurassic erosive unconformity. The Cretaceous plays were charged by vertical and lateral migration above the unconformity. The Andean deformation resulted in enhancing the structural closures and vertical migration towards Cretaceous plays.

The results of this study provided to YPFB a model based approach to predict yet to find volumes in place for undrilled prospects and leads and a proposition for a future drilling strategy.

Beicip-Franlab will present the following poster at AAPG Bolivia 2018 :

Probabilistic attribute derived from Pre-stack seismic inversion and characterization for prospect identification into Boomerang area.

Hermann Behira¹, Frédéric Schneider¹,Stephane Roussé¹, Donald Roccabruna¹, Olvis Padilla², Alcibiades Franco², and Bertrand Valsardieu¹

¹Beicip-Franlab, 232 av. Napoléon Bonaparte, 92500 Rueil-malmaison, France; hermann.behira@beicip.com

² YPFB;  Av. Grigotá Calle Regimiento Lanza, Santa Cruz, Bolivia

ABSTRACT

In the prospect evaluation work performed in Boomerang area, the uncertainty on the estimation of the hydrocarbon occurrence derived from seismic data has been a major importance in the exploration of this area. For this purpose, a dedicated workflow using Interwell^™ and Easytrace^™ integrating geological, petrophysical and seismic data has been applied to constrain petrophysical property distribution using elastic inversion.

Initially, a detailed petro-elastic analysis was performed on the well near the prospect in order to define the relationships between petrophysical properties and elastic parameters (P and S velocity). Then, the available pre-stack seismic data were inverted using a stratigraphic inversion methodology prior to be used in a discriminant analysis to predict the presence of hydrocarbon and the probability associated. 

Therefore, both software provided a solution combining seismic inversion and seismic characterization to predict specific seismic facies distribution (including HC bearing facies) and associated probabilities for the entire seismic grid. The probabilistic attribute was helpful to evaluate the geological chances of success for finding HC in the prospect.

Beicip-Franlab will present the following talk at AAPG ACE 2018 :

Slope-Fan Depositional Architecture From High-Resolution Forward Stratigraphic Models

N. Hawie, J. Covault, D. Dunlap, Z. Sylvester, E. Marfisi

Abstract

            Submarine fans in tectonically active continental-slope basins are targets of petroleum exploration and production. These slope fans commonly comprise compensationally stacked sandy and muddy architectural elements, including mass-transport deposits, weakly confined to distributary channel-and-lobe deposits, and leveed-channel deposits. The lateral continuity and vertical connectivity of these architectural elements are important uncertainties in reservoir characterization that influence fluid-flow behavior during hydrocarbon production. Here, we use a simple forward stratigraphic model to reproduce the large-scale stratigraphic patterns and illuminate the likely distribution of finer-scale, sub-seismic heterogeneity in a slope fan. We used three-dimensional seismic-reflection data (~40 Hz dominant frequency) in the tectonically active Columbus basin, offshore Trinidad, to document the Pleistocene stratigraphic architecture and evolution of a submarine fan across a stepped slope profile. Isochron maps of the fan show a pattern of compensational stacking of deposits; we interpret that sediment-gravity flows avoided pre-existing mass-transport-deposit topography, and formed compensationally stacked channel-and-lobe deposits. Once the stepped slope profile was healed by deposition, a leveed channel promoted bypass of sediment to the Atlantic abyssal plain. We then evaluated our interpretation of compensation with a series of DionisosFlow^TM forward stratigraphic models. All variables were kept constant during the simulations in order to test the hypothesis that the evolution of the surface topography alone, as a result of erosion and deposition, can produce the compensational-stacking patterns interpreted in the seismic-reflection data. A reference-case model generally matches the thickness trend of our seismic-stratigraphic interpretation; it also produced similar large-scale patterns of compensational stacking and depocenter evolution. However, varying the time step impacts the heterogeneity of the model. Shorter time steps are characterized by less sediment accumulation, which results in less sediment diversion during the subsequent time step, more gradual migration of channel deposits, shorter offset distances of depocenters, and shorter length-scale heterogeneity compared to longer time steps. Thus, a key characteristic of slope-fan deposits is compensational stacking, which governs heterogeneity in these reservoirs. Furthermore, our results suggest that relatively simple diffusion-based models can produce realistic compensation patterns. The impact of environmental parameters on the architectures and connectivity of sedimentary bodies and reservoir facies is later tackled through experimental designs and automated multi-simulations. Encouraging results point to the need for more integrated reservoir characterization workflows that comprise high resolution sedimentology, seismic characterization and forward stratigraphic modeling.    

Beicip-Franlab will present the following poster at AAPG ACE 2018 :

Predicting Recoverable Liquid-Rich Sweet-Spots with PVT Phase Kinetic Modeling: Vaca Muerta Shale, Neuquén Embayment

Guillermo Pérez-Drago*(Beicip-Franlab), Mariana Alvis*(Beicip-Franlab), Pierre-Yves Chenet*(Beicip-Franlab)

Abstract

Prediction of hydrocarbon composition and fluid phase behavior, in function of dew and bubble points, is essential to appraise shale play resources and delineation of recoverable sweet-spots. Sweet-spot detection is based on shale play fairway analysis in order to identify areas with significant retained hydrocarbons in-place but also specific fluid behavior at reservoir conditions (close to critical point) optimal for liquid-rich maximum recovery.

For this purpose we developed a customized household compositional kinetic model for hydrocarbon generation coupled with 1D PVT reservoir fluid modeling (Peng Robinson EOS) for detailed fluid phase behavior properties. The defined kerogen and the associated source rock type fractions react as a function of thermal stress throughout primary and secondary cracking, being possible to quantify the compositional yields (mole fraction) of in-situ retained gas and liquid fractions. Hydrocarbons in-place at reservoir conditions were estimated by net source rock thickness organic porosity development, taking into account the generation of immobile fractions during secondary cracking.

Calculated mole fractions and reservoir conditions (P-T) were used as inputs for PVT modeling to predict fluid phase diagrams as a function of critical point and to create maps of volumetric properties such as Bo, Bg, initial GOR and CGR. Volumetric factors maps were used to quantify hydrocarbon volumes in place at surface conditions. Finally, based on existing production data and forecast profiles (using adapted Arps equation); it was possible to define recovery factors to map recoverable resources in MMstbl/km² and Bscf/km².

This workflow has been applied using public data from the Lower and Upper sections of the marine organic-rich Vaca Muerta Shale Play in the Neuquén Embayment. Calibration with production data comes from developed YPF’s Loma Campana concession block. Results provide a precise position of fluid type limits and detailed PVT properties in less developed areas for volatile oil and retrograde gas condensate windows. Higher potential of recoverable liquid-rich sweet-spots are located in areas where fluid behavior at reservoir conditions is near the condensate-volatile oil limit, close to critical point. Herein ultimate recoverable oil and gas resources vary from 0.7-1.1 MMstb/km² and 3.0-6.5 Bscf/km² Detecting recoverable sweet-spots provides, thus, a significant step forward for shale resource assessment and bidding block ranking.

From basin-scale exploration to field-scale production: an innovative Forward stratigraphic Modelling approach coupled with response surface methodology

Nicolas Hawie^[1] , Jacob Covault^[2] , Emerson Marfisi^[1]

This paper was prepared for talk at International Meeting of Sedimentology 2017 held in Toulouse, France, 10 - 12 October 2017.

[1] Beicip-Franlab

[2] University of Texas Austin

With the huge amount of multi-disciplinary and multi-scale datasets gathered along the past years by the Oil and Gas community, geoscientists face many challenges while trying to solve complex problems related to the E&P chain. Three of the main ones are (1) the integration of such important amounts of data, (2) difficulties in managing scaling while moving from large basin scale exploration to restricted field scale production and finally (3) ways of de-risking the petroleum systems elements through innovative approaches in order to localize leads, characterize reservoirs and later enhance production. In this communication we explore the forward stratigraphic modelling advances used to integrate wide multi-disciplinary and multi-scale datasets along source to sink profiles.
DionisosFlow forward stratigraphic model is a deterministic process based tool that allows reproducing the interaction between subsidence, eustatic variations and the sediment routing systems that represent the integrated behavior of “source to sink” geomorphologic processes comprising sediment erosion, transport and deposition from catchment areas towards the shelf, slope and basin floor. The use of geomorphological, geological and geophysical multi-scale constraints in Forward Stratigraphic Models has shed light on the various interactions between the local, regional and global scale driving mechanisms (e.g. tectonic versus thermal subsidence rates, accommodation, climate evolution, drainage systems activation, eustatic variations amongst others) that influence sediment transport and deposition along evolving landscapes.
The need for more efficient and faster ways of assessing the sensitivity of stratigraphic models with regards to all these driving mechanisms lead to the development of an integrated workflow applicable at basin and reservoir scale. The coupling of DionisosFlow with CougarFlow offshore Novascotia, the Gulf of Mexico and Trinidad allowed the generation of automated multi-realizations using a Latin-hypercube experimental design to measure the impact of varying uncertain environmental parameters on the reference-case geological model. The use of response surface methodologies permits a more robust sensitivity analysis assessment of environmental parameters on sediment texture/facies and thicknesses.
The coupling of multi-scale stratigraphic models with response surface methodolologies and multi-realization opens new opportunities to predict the lateral and vertical extent of sedimentary facies and thus de-risk petroleum systems elements of various geological systems at a global scale from an exploration to production perspective.

A New Kinematic Tool for Petroleum System Modeling in Complex Structural Settings: Application to the Foothills Region of Kurdistan

Marie Callies^[1], Romain Darnault^[2], Zahie Anka^[3], Tristan Cornu^[4], Edouard Le Garzic^[5,6], Françoise Willien^[2], Romain Giboreau^[1], Nicolas Mouchot^[1]

1. Beicip-Franlab, Rueil-Malmaison, France

2. IFPEN, Rueil-Malmaison, France

3. TOTAL E&P, Exploration Excellence Division, Paris La Défense, France

4. TOTAL R&D Frontier Exploration, Pau, France

5. LFC-R, Université de Pau et des Pays de l’Adour, Pau Cedex, France

6. Group of Dynamics of the Lithosphere, Institute of Earth Sciences Jaume Almera, ICTJA-CSIC, Barcelona, Spain

This paper was prepared for talk at the Geological Society Event – Fold and Thrust Belts: Structural style, evolution and exploration, held in London, UK, 31 October - 2 November 2017.

Abstract

Petroleum system modeling is today recognized as a critical step in exploration workflows. However, fold and thrust belt regions are particularly challenging as most of basin modeling tools do not accurately manage the combination of lateral and vertical tectonic displacements. In basins where hydrocarbon expulsion from source rocks is prior or simultaneous to compressive tectonics, there is a need for a more accurate modeling approaches integrating active faulting, folding and fluid flow (hydrocarbon and water). In these complex areas indeed, the reconstruction of basin burial and geometry, faults connectivity and fluids movements through time implies accounting for the actual horizontal deformation, and requires an appropriate methodology for explorationists. New workflows linking structural-restoration packages to basin modeling tools have thus emerged in the industry in the past years, albeit with strong limitations which impact their operational use.

This communication discusses these limitations from a practical point of view and presents a new workflow intending to overcome these problems with a new 2D kinematic tool designed specifically for basin modeling purposes. Honoring both structural geology and basin modeling constraints, this tool aims at producing easily and rapidly consistent geological scenarios to feed new generation basin simulators. In addition to classic geometrical reconstruction methods, a new mechanical engine taking into account compaction and rock mechanical properties is available along with several deformation models. The ability to provide geologically valid results in all structural contexts and an intuitive definition of deformation parameters to optimize productivity constitute the core of the tool. Dynamic mesh deformation is guaranteed through the model topology preservation as restoration work progresses.

An application case from the Kurdish foothills is used to illustrate this new technology and its ability to quickly generate tens of paleo-sections continuously deformed for basin modeling simulation. Foothills are typical regions where classic approaches do not apply and where explorationists use, when possible, time-consuming methodologies to evaluate petroleum systems. This example shows to what extent this new approach allows easily increasing basin models structural complexity while meeting the industrial operations constraints, both in terms of execution time and results quality.

Foam injection:  calibration methodology from laboratory experiments to pilot design

M. Mamaghani* (Beicip-Franlab), V. Alcobia (Beicip-Franlab), B. Bourbiaux (IFPEN), L. Nabzar (IFPEN) & M. Chabert (Solvay)

This paper was prepared for presentation at EAGE held in Paris, France, 12-15 June 2017.

Abstract

Assessing foam injection feasibility implies the design of a foam formulation and tests at core-scale in presence and absence of oil.

In the objective of designing a pilot, a numerical model must be constructed; but foam modelization is difficult as it is influenced by various parameters. It is thus necessary to history-match core-flood experiments according a precise methodology. Numerical simulations are carried out step by step following the respective sequences: co-injection of water and gas in absence of oil (phase 1), foam injection in absence of oil (phase 2), co-injection of water and gas in presence of oil (phase 3) and foam injection in presence of oil (phase 4).

History-match of sequences 1 and 2, allows calibrating water-gas relative permeabilities and foam model influencing parameters (gas mobility reduction, foam concentration, injection velocities, appearance criterion). During history-match of sequences 3 and 4, the water-oil and gas-oil relative permeabilities and, foam disappearance criteria in presence of oil are calibrated. 

Applying this methodology in this work, we show how we accurately reproduce laboratory measures. The transition to the field-scale shows the uncertain behavior of some foam parameters, important aspect of the study as it influences to the pilot profitability evaluation.

Figure 1: Cumulative Oil production of experiment #2

Figure 2:  Simulated pressure differences of experiment #2

Figure 3 LabMRFs comparison in absence and in presence of oil

Integration of forward stratigraphic modeling and petroleum system modeling in Northeastern West Siberia – New concepts

DUBILLE Matthieu^[1], BARES Eric^[1], JERMANNAUD Paul^[1], BELENKAYA Irina^[2], PASYNKOV Andrei^[3], TIKHOMIROV Evgeni^[3], SAINT-GERMES Macha^[1]

1. Beicip-Franlab, Rueil-Malmaison, France

2. Gazpromneft-NTC, Russia

3. Gazpromneft-Razvitie, Russia

This paper was prepared for presentation at EAGE held in Paris, France, 12-15 June 2017.

Abstract

Northern part of the West Siberian petroleum basin attracts much of scientific attention focused on exploration studies. Characteristics of imbricated petroleum systems and relations to giant oil and gas fields are far to be clearly understood.
This integrated study achieved in 2014 was based on the basin modelling of Southern Gydan Peninsula, Messoyakha Arch and Bolshekhet Depression. It was performed for petroleum potential assessment, reservoirs and seals mapping, as well as evaluation of Lower Cretaceous in place resources. Comprehensive workflow included 3D forward stratigraphic modelling (Dionisos) used for detailed sedimentary facies distribution and stratigraphic traps identification, and 3D petroleum system modeling (TemisFlow). The geochemical database included pyrolysis (source rocks analysis), and GC-MS analysis (oil-source correlations).
Numbers of complex processes were taken into account such as rifting events, climate changes and glaciations, Tertiary cryosphere formation and degradation, erosions, biodegradation processes, impact of the diagenesis on the pore pressure prediction. The study enable to assess the “yet to find” around the Messoyaha Arch. It also improved our understanding of petroleum systems at basin scale, confirming the importance of the Bazhenov source rock and highlighting the role of the biodegradation in the distribution of oil and gas fields.