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Publications

  • December, 2019

    Integrating Numerical Modelling Approaches in Conceptual Hydrocarbon . . .

    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. 

     

  • December, 2019

    Benefits of Forward Stratigraphic Modeling for Reservoir Characterization

    Benefits of Forward Stratigraphic Modeling for Reservoir Characterization

    Beicip-Franlab will present the following talk at NFS 2019, Norway.

    M. Callies1, S. Bou Daher1, N. Hawie1, E. Marfisi1

    1 Beicip-Franlab, Rueil-Malmaison, France

    Abstract

    Forward Stratigraphic Modeling (FSM) is a deterministic approach that reproduces the interactions between the main mechanisms driving sedimentation. Traditionally applied to quantify the stratigraphic architecture and facies distribution at basin scale, it can also be used at field scale as an efficient tool bridging the gap between the relatively coarse seismic vertical resolution and the very high resolution that wireline logs or detailed core analysis can provide. 

    This presentation illustrates this approach through two examples, one from Gulf of Mexico, to predict deep-sea fans facies distribution and architecture, and a second one from Middle East, to model complex carbonate geometries and associated facies heterogeneities. In both cases, models were calibrated to well and seismic data. Sensitivity analysis and multiple realization workflows were applied to understand the impact of main controls and provide probabilistic results that can be used as a driver in geostatistical simulations.

    The lateral continuity and vertical connectivity of facies are important uncertainties in reservoir characterization that influence fluid-flow behavior during hydrocarbon production. Based on geological concepts, FSM is an efficient tool to reduce these uncertainties, should it be to define new drilling targets or develop accurate and usable static and dynamic models for field development.

  • October, 2019

    Exploring Siliciclastic Systems of Arabia . . .

    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

  • October, 2019

    Surfactant-Polymer Feasibility for a Sandstone Reservoir in Kuwait . . .

    Surfactant-Polymer Feasibility for a Sandstone Reservoir in Kuwait. Successful Integrated Approach From Laboratory to Pilot Design

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

    Mohammed Al-Murayri1, Abrahim Hassan1, Isabelle Hénaut2, Claire Marlière2, Aurélie Mouret2, David Lalanne-Aulet3, Juan-Pablo Sanchez4, Guillaume Suzanne4

    1 Kuwait Oil Company, Kuwait City, Kuwait
    2 IFPEN, Rueil-Malmaison, France
    3 SOLVAY, Paris, France
    4 Beicip-Franlab, Rueil-Malmaison, France

     

    Abstract

    This study presents an integrated approach to design a fit-for-purpose surfactant-polymer process for a major sandstone reservoir in Kuwait. The adopted procedure is described covering core flood experiments through pilot design using a reservoir simulation tool that was calibrated using laboratory results.

     

    The surfactant-polymer formulation design was already described in another publication (SPE-183933). In this paper, further optimization of the chemical formulation is described, including core floods to minimize the quantity of the injected chemicals while maintaining high oil recovery. Formulation robustness and its impacts on water-oil separation at the surface are also evaluated. Furthermore, reservoir simulation was utilized to design a field trial. At first, the parameters that were used to model surfactant-polymer performance were calibrated using core flood results. Then, the reservoir simulation model was used at a larger scale to identify the most appropriate injection sequence for field implementation.

     

    The performance of the designed surfactant-polymer formulation is promising. Core flood experiments demonstrate that the injection of the chemical formulation recovers more than 85% of the remaining oil after waterflooding, while having relatively low adsorption values. The designed formulation was also found to be quite resilient to variations in divalent cations concentration, water-oil ratio and oil composition. It was noticed that rock facies heterogeneity has a limited effect on surfactant adsorption. Favorable phase behavior properties were maintained around reservoir temperature and the formulation exhibited good aqueous stability between reservoir and surface temperatures. EOR parameters including salinity-dependent surfactant adsorption, capillary desaturation and polymer-induced water mobility reduction were calibrated in the reservoir simulation model using core flood data. Larger scale reservoir simulation enabled the design of a suitable injection sequence including a main surfactant-polymer slug followed by a polymer slug. The main variables of the design, including slug injection durations, chemical concentrations and pattern size were optimized through numerous sensitivity scenarios. Using a 5-spot pattern with a spacing of 75 m, surfactant-polymer injection effects should be observed within a short timeframe of around 14 months.

    This paper describes a successful approach to design a surfactant-polymer process, integrating laboratory experiments and reservoir simulation. This work paves the way for a 5-spot EOR pilot involving a major sandstone reservoir and will undoubtedly provide valuable insights for chemical EOR applications in similar reservoirs elsewhere.

    Method used to build Winsor III (interfacial tension) sensitivity graphs from phase diagrams

  • October, 2019

    Coreflood Model Optimization Workflow for ASP Pilot Design Risk Analysis . . .

    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.

    Initial and optimized distributions of parameter A (top)

    Initial and optimized distributions of parameter B (bottom)

  • October, 2019

    Downward migration as a potential mechanism for HC accumulation . . .

    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.

    Beicip-Franlab will present the following talk at EPC Tunis, Tunisia, October 2018

    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.

    Hydrocarbon migration model and concept for Mid-Cretaceous plays

     

  • October, 2019

    Downward migration as a potential mechanism for HC accumulation . . .

    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.

    Hydrocarbon migration model and concept for Mid-Cretaceous plays

     

  • October, 2019

    Origin of Natural Oil Seabed Seepage along Mexican Ridges. . .

    Origin of Natural Oil Seabed Seepage along Mexican Ridges, Southwestern Gulf of Mexico: Petroleum Systems Implications and Potential

    Beicip-Franlab will present the following talk at EAGE Workshop, Cancun, Mexico

    Pérez-Drago G1, Pérez-Cruz G2, Chenet P1

    1. Beicip-Franlab, Rueil-Malmaison, France.
    2. Facultad de Ingeniería UNAM, Ciudad Universitaria, Coyoacán Mexico City, Mexico.

    Abstract

    Several satellite mapping and piston core studies of oil and gas seabed seepage over the Mexican Ridges Province indicate the existence of an active petroleum system. Biomarker analysis of hydrocarbons recovered from the sea floor sediments by piston cores, indicate an aligned pattern of fluid type distribution (oil-gas) with a predominant Upper Jurassic carbonate-rich source rock affinity. On the other hand, based on regional subsurface interpretation, the potential Upper Jurassic source rocks in this region are found at depths well above the gas window. Therefore, it seems that there is no correspondence between oil shows observed on the seabed and the type of hydrocarbons that the source rocks might be expelling at present day.

    The objective of this work is to evaluate the petroleum system elements burial history and the thermal-pressure regimes through geological time, responsible for the timing of oil and gas expulsion and fluid migration from deep thermogenic sources. This is accomplished throughout a 2D basin modeling approach accounting for heat flow transfer, compaction-effective stress and HC fluid flow modeling through simulated geological time. The model aims to explain the origin of the type of seabed hydrocarbons seepage and the implications for the hydrocarbon potential of the Province.

    Location of oil and gas seabed piston cores

  • October, 2019

    Biogenic and Thermogenic Hydrocarbon Potential . . .

    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.

    Regional hydrodynamism conditioned by the pressure field

  • October, 2019

    Potential of the Eastern Jeanne d’Arc Basin . . .

    Potential of the Eastern Jeanne d’Arc Basin

    Beicip-Franlab will present the following talk at EAGE NL, Canada

    Erwan Le Guerroué1, Pierre-Yves Filleaudeau1, Djowan Thomas1, Amandine Prelat1, Thibaud Pichot1,Pierre-Yves Chenet1, David Norris2, Victoria Mitchell2, Erin Gillis2, Richard Wright2

    1. Beicip-Franlab, Rueil-Malmaison, France.
    2. Nalcor Energy, St. John's, NL, Canada.

     

    Abstract

    The underexplored Eastern Jeanne d’Arc appears prospective for oil and gas, after new regional seismic data validates the extension of know plays in the area.
    The objective was to provide petroleum resource estimates for the area using 2D/3D basin modelling for play risk analysis and volume estimates.
    Regional sequence stratigraphy and geodynamic work coupled to a Forward Stratigraphic Model (DionisosFlow™) helped to map the extension of reservoirs, carrier beds and seals. Source rock potential was assessed using the FSM model to estimate deposition and degradation of organic matter during early burial.
    After calibration of the thermal and fluid flow regime temperature, maturity and pressure, an integrated 3D model was built using TemisFlow™ to estimate the oil and gas charge in the potential traps (stratigraphic and structural) in the various plays.
    The resource assessment of the Eastern Jeanne d’Arc area demonstrates a potentially prolific petroleum system. The uncertainty on HC volumes is given by the distribution of unrisked volumes in place. The range varies from 2.1 BOE to 9.8 BOE. The Probability of Geological Success is estimated to 11%.

    Triassic to Cretaceous Wheeler diagrams of the study area with schematic subsidence model for key tectono-stratigraphic phases

  • October, 2019

    Petroleum System Modeling in Complex Structural Settings . . .

    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.

  • October, 2019

    Hydrocarbon Potential of the Bolivian Santa Cruz . . .

    Hydrocarbon Potential of the Bolivian Santa Cruz – Tarija Foreland Basin.

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

    F. Schneider, J1. Esquivel, S1. Rousse, J. Faure1, R. Mayta1

    1 Beicip-Franlab, Rueil-Malmaison, France.

    Abstract

    The Santa Cruz - Tarija Foreland Basin, located in the southeastern part of Bolivia is, from an exploration point of view, an intermediate sub-Andean basin (1800 km2 / exploration well). A complete stratigraphic revision has been carried out; it suggests some changes in the historical sedimentary models. In particular, the intimate stratigraphic architecture of glaciogenic Carboniferous series has been partially resolved at basin scale. The results allow to distinguish an extremely strong intrinsic architectural complexity relying on the glaciogenic nature of deposits as well as the occurrences of numerous undrilled stratigraphic traps.
    The geochemical study indicates the existence of various Silurian to Devonian source rocks with influence of continental-marine environments, in which, a Pridoli shale sequence below the El Carmen Formation and the Lochkovian Boomerang Shale Member of the Robore Formation could be good candidates for unconventional exploration.
    To evaluate the hydrocarbon potential of the basin, a 3D dynamic model has been built. The thermal calibration of the temperature and maturity data is only possible considering an increase of the heat flow during Triassic–Jurassic time. Therefore, most of the hydrocarbons are expelled before Cretaceous times by the identified kitchen. The remaining were expelled between the Oligocene and present time.
    Lateral long-distance migration through the Silurian and Devonian carrier beds occurred before Andean deformation. Silurian or Devonian pinch out against the Brazilian craton were then filled during the first expulsion phase. The Mesozoic and Cenozoic plays were then charged by vertical and lateral migration. The Andean deformation resulted in enhancing the structural closures and vertical migration.
    At present day, the regional study allowed identifying more than 60 leads and prospects in the Boomerang area and close to 85 leads in the Chaco Plain. The average in place yet to find, evaluated combining basin modeling results and creaming curve analysis, is 16 Tcf of gas and 470 MMbbl of oil for the Boomerang area while it is 30 Tcf of gas and 900 MMbbl of oil for the Chaco Plain.

    3D basin modeling results – HC saturation and main HC flows

  • October, 2019

    Importance Of Multi-Scale Petroleum System Assessment . . .

    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.

    Overpressure field and regional waterflows along the section

  • October, 2019

    Quantifying the risk on reservoir quality with forward stratigraphic . . .

    Quantifying the risk on reservoir quality with forward stratigraphic modelling in frontier areas – Orphan Basin, Canada

    Beicip-Franlab will present the following talk at AAPG ACE San Antonio, USA May 2019

    Alcide THEBAULT 1, Véronique GERVAIS 2, Marie CALLIES 1, Paul JERMANNAUD 1

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

    Abstract

    Forward stratigraphic modeling allows assessing the extension, thickness and quality of reservoir bodies in underexplored areas. However, most of the data used in such basins is subject to uncertainties which become critical in frontier areas where very little information is available for calibration. The potential range of input parameters variation leads to a high variability of the modeling simulation results that should be quantified to reduce the exploration risk.

    Traditionally, risk assessment is done performing multi-realizations with a Monte-Carlo sampling which requires a lot of time, sometimes months, when hundreds of simulations are required on a high resolution model. To overcome these delays unaligned to the E&P industry constraints, we here present a new workflow linking forward stratigraphic modeling to a dedicated uncertainty analysis tool based on response surfaces.

    If the later technology is commonly used in reservoir engineering, it is quite unknown in exploration. In this approach, a set of simulations – the experimental design – is used to compute response surfaces that provide very fast estimations of the simulator outputs for any parameter values. The uncertainty study is then conducted from the response surface predictions only. A limited number of simulations is generally enough to obtain reliable estimations. The total time required to estimate the risk associated to the model uncertainties is thus drastically reduced.

    The Canadian passive margin is used to illustrate this workflow. The focus is made on the turbiditic sandy reservoirs of the Upper Cretaceous formation of the Orphan Basin and the uncertainties linked to its quality in terms of net to gross ratio and thickness. Only one well being available for calibration, the impact of subsidence, sediment sources supply and content, and sediment transport is analyzed to understand the influence of each parameter. A propagation is then realized to quantify the risk on the reservoir quality and the probability of presence of reservoir facies. Applied to the full reservoir unit and not only at a single well location, this approach provides relevant probability maps critical in the decision-making process.

     

    Average standard deviation and percentile maps for the net sand thickness

  • October, 2019

    Reducing Exploratory Risks Using Advanced Basin Modeling . . .

    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, KronosFlowTM, coupled with an unstructured mesh forward basin modeling tool (TemisFlowTM), 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.

     

    Simulated vitrinite reflectance at present day and extraction at base of sediments through time along the profile with heat flow

  • October, 2019

    Challenges and solutions for modeling naturally fractured carbonates . . .

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

    Challenges and solutions for modeling naturally fractured carbonates

    Weber M1.

    1 Beicip-Franlab, Rueil-Malmaison, France

    Abstract

    Natural fractures act as major heterogeneities within carbonate reservoirs and as such provide preferential paths for flow. As a result, fractures may have a major impact on field production and affect considerably field development through the following:
    -    Increased well productivity, reservoir connectivity and therefore possible reduction of the number of required wells;
    -    Risks of early gas or water breakthrough, requiring careful well positioning and monitoring;
    -    Complex matrix-fracture exchanges, driven by capillarity and gravity drainage, resulting in different kinetics of recovery from the matrix and the fractures;
    A reliable fracture model is essential to accurate assess those possible effects, but this task is generally rendered difficult by limited availability of data related to fractures. Lessons learnt from several studies performed in various fractured carbonate fields will be synthesized in this presentation. Indeed, this experience has showed the utmost importance of some critical steps in the fractured modelling workflow, which include:
    -    Integration of static and dynamic data to understand the fracture network impact on flow;
    -    Identification of geologically sound fracture density drivers to predict fracture distribution;
    -    Dynamic calibration of fracture properties to reproduce fracture impact on flow;
    -    Accurate fracture upscaling techniques to preserve the fracture network properties in the reservoir simulator;
    -    Dedicated handling of uncertainties;
    This presentation will demonstrate the importance of those aspects and provide advice to perform them as accurately as possible.

  • October, 2019

    The potential of foam-based injection processes for unlocking . . .

    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.

  • September, 2019

    Importance of multi-scale petroleum system assessment for plays . . .

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

    IMPORTANCE OF MULTI-SCALE PETROLEUM SYSTEM ASSESSMENT FOR PLAYS AND PROSPECTS DE-RISKING IN THE EASTERN MEDITERRANEAN BASIN

    Pérez-Drago G.1, Dubille M.1, Montadert L.1, Schneider F.1, Mouchot N.1, Chenet P.1, Callies M.1, Thebault A.1
    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.

    Overpressure field and regional waterflows along the section

  • September, 2019

    Importance of paleoenvironment reconstructions in geomodeling with . . .

    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

  • September, 2019

    Assessing karst-impacted hydrocarbon fields: choosing their modeling . . .

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

    Assessing karst-impacted hydrocarbon fields: choosing their modeling strategies through decision tree

    Dr. Arnaud Fournillon (Beicip-Franlab)

    ABSTRACT

    Carbonate hydrocarbon fields represent near the half of worldwide hydrocarbon reserve. Carbonate rocks react to emersion processes by dissolution. Such processes affect the reservoir properties in several ways depending on the time span of the emersion, climatic conditions and other numerous factors. It may provoke slight enhancement of the matrix up to the development of hundreds of kilometers-long cave system. In karst-impacted hydrocardon fields, the diagenetic evolution of the karst into paleokarst adds a level of heterogeneity. This study focuses solely on epigenetic karst (karst created by meteoric waters and emersion processes). Hypogenetic karst (karst created by circulation of hydrothermal waters during mesogenesis or telogenesis) is therefore not part of this study.

    According to speleogenetical experiments, and geological and geomorphological studies of caves, the main factors controlling paleokarst formation are (1) the combination of climate and duration of unconformity, (2) original properties of impacted host-rock (original porosity and permeability, and fractures parameters), (3) the mode of hydraulic recharge (diffuse, concentrated along faults, through sinkholes or streams), (4) the eventual infilling and burial history of karst.

    A typology of karst-impacted hydrocarbon fields has been made on a basis of a careful literature review that covers all main carbonate regions of the world and a time frame ranging from Miocene to Proterozoic. It results in the definition of three broad classes: (1) short-lived (proto) karst that is due to an emersion generally shorter than 100 ka, (2) medium-lived (transitional) karst linked to time frame ranges from 100 ka to 1 Ma and (3) long-lived (or true) karst that is due to an emersion generally longer than 1Ma. Short-lived karst affects preferentially porous and unfractured carbonate. It develops within the matrix or in interstratal position and provokes porosity enhancement, vuggy dissolution and/or hardened surfaces, which may act as baffles to flow. Medium-lived karst is characterized by intense vug formation, isolated caves development and small cave system (<hm) development. In carbonate islands, such karstification processes provoke flank caves and fresh-water lenses development. Associated emersion surface may act as barrier to flow. Long-lived karstification is characterized by intense speleogenetical processes. It affects generally compact carbonate rocks. Long cave systems develop along fractures and faults, and/or in interstratal position. There vertical stacking depends on base level variations. They exhibit a strong vertical zonation affecting over hundreds of meters with enlarged fractures, vugs and caves. They may evolve as preserved, collapsed or infilled/cemented paleocaves.In terms of modeling strategies, a decision tree has been made that relies on the link between geological context and the combination of the previously cited four main parameters that controls paleokarst formation. Four main modeling strategies may be associated to these various karst types: (1) equivalent matrix model (1K1Φ), (2) matrix associated with fractures (2K1Φ or 2K2Φ), (3) discrete karst model (object-based models) or (4) cascading reservoir models (derived from hydrogeological tools).

    Preserved paleocave encolsed in tight Lower Cretaceous limestone (Provence, France)

  • June, 2018

    Play Elements of the Chidley Basin, offshore ...

    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.

  • June, 2018

    Bolivian Petroleum Systems: Paradigm Shifts

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

    Bolivian Petroleum Systems: Paradigm Shifts

    Frederic Schneider

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

    ABSTRACT

    The petroleum systems of the Bolivian basins have been revised under the light of a fully integrated regional study.

    The stratigraphic review, including biostratigraphy, sedimentological core description and seismo-stratigraphic investigations led to new consistent tectono-sedimentary models and allowed the identification of several conceptual plays. The geochemical synthesis coupled with the stratigraphic study allowed a better definition of the potential source rocks.

    The thermal calibration of the temperature and maturity data is only possible by taking into account an increase of the heat flow during Triassic-Jurassic times. Two main phases of hydrocarbon expulsion are calculated. The first began in Triassic-Jurassic time and the second was contemporaneous with Andean deformation and associated foreland basin.

    During the Andean phase, the hydrocarbon charge of the sub Andean traps is controlled by expulsion in the synclines and in the anticlines. Mechanical expulsion related to burial is the main expulsion mechanism in the synclines sometime associated with increase of maturity. In the anticlines expulsion occurred due to the hydrocarbons volume expansion during uplift.

  • June, 2018

    Stratigraphic and sedimentary processes simulation to explore . . .

    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 DionisosFlowTM 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.

  • June, 2018

    Modelling of a sub-andean fractured reservoir

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

    Modelling of a sub-andean fractured reservoir

    Thomas Piolle1, Luca Micarelli1, Andrea Moccia1, Valentina Caceres Castro2 ; Carlos David Limachi Alcon2

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

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

    ABSTRACT

    The gas-condensate field, object of this study, is located in the Sub-Andean compressive zone. The structure is a typical faulted asymmetric anticline, 60km long, 5km across. The Devonian sandstones constitute the reservoir.

    Tests have shown the existence of a developed fracture network. The reservoir is a classical type 2 fractured reservoir: the fractures provide the permeability (15-70mD) while the matrix provides the porosity (2-6%). These characteristics make the fracture study a key element to understand the field behavior in order to maximize the production and anticipate possible issue like water-breakthrough.

    The applied workflow is mainly based on borehole imagery (BHI) analysis and implies the following phases:

    The BHI of 5 wells were analyzed and interpreted. Depending on the quality of the images, fractures crossing the wellbores can be picked. As induced fractures or artefacts of various origins can be easily confused with natural fractures, a quick analysis of core pictures was performed to minimize uncertainties. The output of BHI analysis is a log of fractures for each well.

    While the previous static data bring information regarding fractures at well, seismic data bring inter-well information allowing the detection of the major thrust-faults of the field.

    Faults and fracture logs along with other logs were then imported in the dedicated software FracaFlowTM for analysis and modeling. From the BHI analysis output, the number of fracture sets can be determined as well as their density and their possible relationships with facies, porosity, volumes of shale… This allows understanding the spatial organization of the fracture network. In this case, a clear relationship between the fracture density and the distance to faults was highlighted. However, the understanding of the contribution of fractures to the fluid flow requires dynamic well data: mud-losses, PLT, well-test and production data were thus carefully analyzed. By computing locally the equivalent permeability of the fracture network, FracaFlowTM calibration algorithm found the optimal fracture conductivity to match the KH interpreted from well-tests.

    All the equivalent properties (permeability along x/y/z, porosity and shape factor) were finally computed with a dual-media hypothesis.

    This study allowed building a fracture network, consistent with the geological context and matching the dynamic data. It is now ready to be used for the history matching and simulation/forecasts.

  • June, 2018

    Petroleum Systems Modeling and Hydrocarbon Charge Assessment . . .

    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.

  • June, 2018

    A New Kinematic Tool for Petroleum System Modeling in Complex . . .

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

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

    Marie Callies[1], Alcide Thebault[1], Jean-Luc Faure[1], Françoise Willien[2], Raul Eduardo Giraudo[3]

    1. Beicip-Franlab, Rueil-Malmaison, France

    2. IFPEN, Rueil-Malmaison, France

    3. YPFB, La Paz, Bolivia

    ABSTRACT

    Petroleum system modeling is today 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 where hydrocarbon expulsion from source rocks can be prior or simultaneous to compressive tectonics require more accurate modeling approaches integrating active faulting, folding and fluid flow. The basin burial and geometry reconstruction, fault connectivity and fluid movements should thus account for the actual horizontal deformation through time, which is impossible with a regular backstripping approach.

    This work introduces a 2D kinematic tool specifically designed to meet this objective. Starting from present day section digitalization, KronosFlowTM aims at producing rapidly consistent geological scenarios for basin modeling purposes. The first challenge of this approach is related to the number of restoration steps to provide as basin modeling requires a detailed kinematic scenario with, at minimum, a basin geometry at the end of each simulated layer deposition. Combining several geometrical and mechanical methods, the tool thus focuses on ergonomics to enhance productivity and afford multiple scenarios testing. The second challenge is linked to the mesh preservation through time that we believe essential for mass balance. In this regard, a new meshing technology has been developed to track sediments deformation while being compatible with a simulator able to take advantage of an accurate description of the basin evolution through time. Running on unstructured meshes and accounting for lateral displacement, this basin simulator uses the produced kinematic scenario for the forward simulation of heat transfer, pressure, hydrocarbon generation, migration and accumulation. Faults impact on fluid flow is assessed through an implicit modeling of the gouge and damage zones properties through time.

    An application case from the Andean foothills illustrates the applicability of these new technology and workflow. Preliminary structural reconstruction work detailing the main deformation phases of the area is used to guide the complete kinematic scenario made of more than fifteen steps. Forward basin simulation is then run and the model, calibrated to available well data, allows testing the impact of thrusting on maturation, migration pathways and hydrocarbon charge and quality. Several scenarios are elaborated, contributing to reduce the exploration risk.

  • June, 2018

    Probabilistic attribute derived from Pre-stack seismic inversion . . .

    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.

  • May, 2018

    The Importance of Evaluating Initial Kerogen Potential and Restoring . . .

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

    The Importance of Evaluating Initial Kerogen Potential and Restoring Kinetic Schemes from Mature Samples, Example from Late Jurassic Source Rocks

    Matthieu Dubille (Beicip-Franlab), Gaelle Maury (Beicip-Franlab), Emerson Marfisi (Beicip-Franlab)

    Abstract

    Evaluation of initial source rock potential is usually challenging for lack of suitable samples: source rocks may be mature everywhere and/or organo-facies changes complicate extrapolations at basin scale. Consequently, although it is critical to obtain a good estimation of generated HC quantities, explorationists often use analogs and neglect this task.

    We propose good practices for kinetic schemes restorations, combining geological elements and basin modeling, thermal calibration data and pyrolysis data. A case study (Jurassic kerogens) is used to illustrate the methodology which consists in several steps:

    1/ Detailed analysis and filtering of pyrolysis data along with SARA. Identification of different maturity trends on HI vs. Depth and HI vs. Tmax plots (preliminary evaluation of HI0). Estimation of a “minimum TR” through amounts of free hydrocarbons.

    2/ Estimation of S20, HI0, TOC0 and checking geological and geochemical consistency of proposed HI0, hydrocarbon mass balance, correlation with Tmax and VRo data. At this step basin modeling helps to assess absolute maturity levels.

    3/ Available kinetic schemes restoration. “Missing” and “partially consumed” activation energies can be identified. Rebuilding of the full spectrum is constrained by assumptions made on HI0 and by calculated TR. Hypotheses are validated if TR vs. VRo and HI vs. VRo trends obtained with restored kinetic schemes are consistent with observed data. Computed Tmax are also calibrated (HI vs.Tmax , TR vs. Tmax, and VR0 vs. Tmax trends).

    4/ Finally hypothesis on HI0, TR, and “missing” activation energies are adjusted to a compromise explaining all observed features. The calibration is confirmed through basin modeling.

    This workflow reduces uncertainties on source rocks behavior in basin models, better constraining maturity timings and volumes of generated hydrocarbons, which is invaluable for exploration of both conventional and unconventional petroleum systems. In this particular case study, careful integration of all available data allowed a more consistent assessment of initial kerogen states (S20, TOC0, HI0) and transformation ratios (TR). Finally the study demonstrated that the source rock potential was significantly underestimated: what was believed to be an early mature type II-III source rock was in fact a mature type II-IIS, much more prolific, which led to the reevaluation of the yet-to-find in the basin.

  • May, 2018

    Slope-Fan Depositional Architecture From High-Resolution Forward ...

    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 DionisosFlowTM 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.    

  • May, 2018

    New Tools for New Challenges: Petroleum System Modeling of the ...

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

    New Tools for New Challenges: Petroleum System Modeling of the Kurdish Foothills

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

    Abstract

    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 where hydrocarbon expulsion from source rocks is prior or simultaneous to compressive tectonics require more accurate modeling approaches integrating active faulting, folding and fluid flow. The basin burial and geometry reconstruction, fault connectivity and fluid movements should thus account for the actual horizontal deformation through time, which is impossible with a regular backstripping approach.

    We here introduce a 2D kinematic tool specifically designed to meet this objective. Starting from present day section digitalization, it aims at producing rapidly consistent geological scenarios for basin modeling purposes. The first challenge of this approach is related to the number of restoration steps to provide as basin modeling requires a detailed kinematic scenario with, at minimum, a basin geometry at the end of each simulated layer deposition. Combining several geometrical and mechanical methods, the tool thus focuses on ergonomics to enhance productivity and afford multiple scenarios testing. The second challenge is linked to the mesh preservation through time that we believe essential for mass balance. In this regard, a new meshing technology has been developed to track sediments deformation while being compatible with a simulator able to take advantage of an accurate description of the basin evolution through time. Running on unstructured meshes and accounting for lateral displacement, this basin simulator uses the produced kinematic scenario for the forward simulation of heat transfer, pressure, hydrocarbon generation, migration and accumulation. Faults impact on fluid flow is assessed through an implicit modeling of the gouge and damage zones properties through time.   

    An application case from the Kurdish foothills illustrates the applicability of these new technology and workflow. Preliminary structural reconstruction work detailing the four main deformation phases of the area is used to guide the complete kinematic scenario made of more than twenty steps. Forward basin simulation is then run. The model, calibrated to available well data, allows testing the impact of thrusting on maturation, migration pathways and hydrocarbon charge and quality. Several scenarios are elaborated, contributing to reduce the exploration risk.

  • May, 2018

    Predicting Recoverable Liquid-Rich Sweet-Spots with ...

    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.

     

  • May, 2018

    Pore Pressure Prediction From Basin Simulation of Heat and ...

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

    Pore Pressure Prediction From Basin Simulation of Heat and Fluid Flow: Application to a Realistic Earth Model in the Gulf of Mexico

    Felipe Medellin*(Beicip-Franlab), Michael Fehler*(MIT), Nazim Louni*(Independent Consultant), Jean-Marie Laigle*(Independent Consultant)

    Abstract

    Pore pressure prediction in the Gulf of Mexico remains critical for exploration and development of hydrocarbon resources locked in deep and variably pressured reservoirs. This is especially true in areas dominated by salt tectonics, facies heterogeneity in terms of low permeability versus porous and permeable rocks, and connectivity of porous and permeable rocks both laterally and vertically. Society of Exploration Geophysicists Advance Modeling consortium has developed a compelling and realistic earth model to understand in detail critical mechanisms that drive the pore pressure distribution in the Gulf of Mexico. Structural restoration of complex allochthonous and autochthonous salt bodies has proven to have an impact on the overall mechanisms that affect pore pressure, such as disequilibrium compaction and lateral fluid transfer as well as secondary modification of shales properties. Heat flow and thermal conductivity through time and in the presence of salt not only impacts smectite to illite transformation depth, resulting from natural distortion of temperature isolines but also affects the timing of the transformation. The objective of the study was to sample the solution space for a number of uncertain parameters affecting a simulated pore pressure. Analyzed parameters are: simulated grid size, constitutive laws for compaction and fluid flow, illitization and fault permeability. The geological history, salt geometry evolution through time and differential sedimentation rates are additional drivers for the pore pressure. Comparison of a scenario with no clay diagenesis and proposed salt geometry reconstruction simulation shows overpressure variation of up to 30% at the units away from the salt canopy and less than 5% below the salt, which is explained by the thermal conductivity of the salt and its impact on the illitization process. As a consequence of thermal cooling generated by salt emplacement, water replacement during the illitization process is not as aggressive in the salt surroundings. On the other hand, it is substantially away from the salt body. This phenomenon combined with the hydraulic connectivity of the facies, generates unique overpressure trends controlled by a rather large number of variables that can be fully investigated by a 3D full-physics forward basin modeling. The results of the modeling were blind-checked with the overpressure profile from a well in the Gulf of Mexico, proving outstanding calibration on similar geological settings.

    Effective stress and Overpressure results

  • September, 2017

    From basin-scale exploration to field-scale production . . .

    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.

  • September, 2017

    Benefits of forward stratigraphic modeling in petroleum exploration . . .

    Benefits of forward stratigraphic modeling in petroleum exploration: the example of offshore NL, Canada

    Paul JERMANNAUD(1,@), Erwan LE GUERROUÉ(1), Jonathan PITZ(1), Olivier VIDAL(1)

    (1) Beicip Franlab (France)
    (@) paul.jermannaud@beicip.com

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

    Abstract

    In Petroleum Exploration, understanding the lithological and stratigraphic basin architecture is a key component of a successful resource assessment. We here propose a constrained 4D stratigraphic model to better assess lithology variations and the exploration risk in an integrated exploration workflows. This workflow is conducted on the underexplored Orphan / Flemish basins, located offshore Newfoundland, Canada.
    The initial geological and geophysical work consists in a well and seismic sequence stratigraphic analysis. It aims at understanding and refining the sequence stratigraphic framework of the basin. Interpreted paleoenvironments are firstly defined on 2D seismic sections. This stratigraphic / geomorphologic framework is then transposed to the whole study area using the complete seismic and well dataset to create conceptual Gross Depositional Environment (GDE) maps per main stratigraphic units.
    Ultimately, the G&G interpretation helps to constrain a numerical forward stratigraphic model. The conceptual GDE maps, and more specifically their estimations on paleobathymetry, sedimentary source dynamics, pathways and sedimentary object styles, are dynamically tested using the 4D forward stratigraphic modelling tool DionisosFlowTM. This model, which takes into account the interplay between sediment supply, transport and accommodation change, allows the paleoenvironment interpretations to be tested. Eventually, the model provides a geocube with various environmental properties such as lithologies (volume of sand and shale) but also water energy; bathymetry, etc.
    From the geocube, facies are interpreted as a function of their environmental properties allowing lateral and vertical extension of main sediment packages and geobodies to be recognized. Based on this exhaustive G&G analysis a reliable 3D stratigraphic grid is generated, allowing the following:

    - An optimal outline of the petroleum play definition: the defined plays are based on 4D (spatial and temporal) distribution of main organic-prone sediments, reservoir and seal with respect to the stratigraphic framework (regression/transgression trend).

    - A detailed lithological input within the 3D petroleum system model skeleton for further hydrocarbon generation/expulsion/migration & entrapment modelling.

    - A better assessment of the geological risk (Common Risk Segment mapping), by considering reservoir/seal presence and effectiveness. Risks are evaluated via the Sand and Shale distribution in the 3D stratigraphic model in terms of Net thickness, together with the presence and thickness of continuous beds

  • September, 2017

    A New Kinematic Tool for Petroleum System Modeling in Complex . . .

    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.

  • September, 2017

    Pore Pressure in Jurassic and Cretaceous of Kuwait: concepts . . .

    Pore Pressure in Jurassic and Cretaceous of Kuwait: concepts, basin modelling, and prediction

    M. Dubille(1), G. Maury(1), R. Baillet(1), N. Guyomar(1), O. Vidal(1), T. Pichot(1), S. Al-Ali(2), A. Al-Khamiss(2), N. Hawie(1)

    1. Beicip-Franlab, Rueil-Malmaison, France

    2. KOC, Kuwait

    This paper was prepared for poster at AAPG held in London, UK, 15-18 October 2017.

    Abstract

    Pore Pressure regimes result from complex interactions between various phenomena from micro to regional scale, controlling sediments porosity-permeability distribution, fluids characteristics and expansion.

    Our objective is to present a case study where basin modelling has been used for understanding and predicting the pressure field at regional scale; it covers both onshore and offshore Kuwait, from the Precambrian basement to the surface. Although Kuwait is a mature basin, the occurrence of strong overpressures (20ppg and more) within and beneath Gotnia-Hith evaporitic deposits (Kimmeridgian-Tithonian) is not fully constrained. In addition, above the salt, the distribution of overpressures in Northern Kuwait is still poorly understood.

    The model is calibrated with field data and geomechanical analysis of well reports. It shows that the main cause of overpressure at basin scale is the confinement of pre-salt Jurassic units. Formation waters mobilized by the sedimentary compaction (mechanical and chemical) and other fluids generated by diagenetic processes and catagenesis must escape the system. The model proves the importance of vertical fluid migration through low permeability faults and discontinuities in the Gotnia-Hith Formation. Several of these discontinuities have been mapped for the first time according to their directions and vertical extensions, thanks to a dedicated geophysical analysis performed in parallel. Local “salt windows” exist both in Burgan and Sabiriyah-Raudhatain areas. The model also shows that fluids “injected” in low porous Lower Cretaceous carbonates “propagate” the overpressure above the salt, locally forming “pressure plumes”. These results have of course consequences on our understanding of imbricated petroleum systems feeding super giant oil fields in the area. In the first place the model demonstrates that hydrocarbons generated by the prolific Najmah source rock (Callovo-Oxfordian, below the salt) can feed Marrat reservoirs (Middle Jurassic) and contribute to the charge of several Cretaceous plays.

    Finally basin modelling results have been used as boundary conditions for a high resolution geomechanical finite element modeling of the pressure field within the Gotnia-Hith formation itself, spatial variations of mechanical properties being defined through seismic characterization. Depending on the scale and on involved mechanisms, only integration of various approaches provides reliable enough prediction of pore pressure.

  • June, 2017

    Foam injection: calibration methodology from laboratory experiments . . .

    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

  • June, 2017

    Downward migration, theory and application to Najmah-Marrat petroleum system

    Downward migration, theory and application to Najmah-Marrat petroleum system

    DUBILLE Matthieu [1], MAURY Gaelle [1], AL-ALI Salem Abdullah Abdul Karim [2], AL-KHAMISS Awatif [2]

    1. Beicip-Franlab, Rueil-Malmaison, France

    2. KOC, Kuwait

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

    Abstract

    This work aims at explaining the combination of geological and physical processes that may induce downward migration in a basin, a phenomenon which is still debated among the community.
    Based on the example of the Jurassic sequence in Kuwait, we propose 4 circumstances in which downward migration is possible: 1/ Juxtaposition of source rocks and older reservoirs along geological discontinuities such as faults; 2/ Juxtaposition of source rocks and older reservoirs along steep slopes (e.g. the flank of an anticline); 3/ “Fill and Spill” process (generated hydrocarbons saturating the source rock first, then reaching underlying formations if there is no other “escape way”); 4/ “Fill and Spill” process enhanced by the water flow and/or capillary process.
    Petroleum system modelling (using the Darcy’s Law) shows that in fact downward migration results in a combination of different processes. It proves that the Najmah-Marrat petroleum system is physically possible. This result is compatible with oil-source correlations (geochemistry).
    Complex downward migration paths are particularly sensitive to parameters which are not often properly constrained in sources rocks and in low porous carrier beds: petrophysical properties, fractures and faults distribution, facies distribution. Understanding downward migration requires cogent basin models fully integrating physics and geology.

     

  • June, 2017

    Integration of forward stratigraphic modeling and petroleum system modeling in Northeastern West Siberia . . .

    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.

  • June, 2017

    Potential of the Orphan Basin

    Potential of the Orphan Basin, NL, Canada

    Erwan Le Guerroué [1], Pierre-Yves Chenet [1], Bertrand Lebreuilly [1], Paul Jermannaud [1], David McCallum [2], Victoria Mitchell [2], Nicholas Montevecchi [2], Ian Atkinson [2], Richard Wright [2].

    1. Beicip-Franlab, Rueil-Malmaison, France

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

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

    Abstract

    The underexplored West Orphan Basin appears prospective for oil and gas, after new regional seismic data uncovered a large play trend in the Lower Tertiary sands, indicative of turbiditic fan complexes.

    The objective was to provide petroleum resource estimates for the area using seismic reservoir characterization, and 2D/3D basin modelling for play risk analysis and volume estimates.

    A seismic inversion and characterization was performed to discriminate sand probability. Some Tertiary and Cretaceous sands appear to have high porosity (~30%) with a clear indication of the presence of hydrocarbons, most probably light oil.

    Regional sequence stratigraphy work coupled to a forward stratigraphic model (DionisosFlow™) helped to map the extension of reservoirs, carrier beds and seals.

    After calibration of the thermal and fluid flow regime temperature, maturity and pressure, an integrated 3D model was built using TemisFlow™ to estimate the oil and gas charge in the potential traps (stratigraphic and structural) in the various plays.

    The resource assessment of the Orphan area demonstrates a potentially prolific petroleum system. The uncertainty on HC volumes is given by the distribution of unrisked volumes in place. The range varies from 12.9 BOE to 45 BOE. The Probability of Geological Success is estimated to 16%.

  • June, 2017

    Sequence Stratigraphy, Depositional Environment and Numerical Stratigraphic Modelling of the Orphan Basin

    Sequence Stratigraphy, Depositional Environment and Numerical Stratigraphic Modelling of the Orphan Basin (NL, Canada)

    Paul Jermannaud [1], Erwan Le Guerroué [1], Jonathan Pitz [1], Thibauld Pichot [1], David McCallum [2], Victoria Mitchell [2], Ian Atkinson [2], Richard Wright [2].

    1. Beicip-Franlab, Rueil-Malmaison, France

    2. Nalcor Energy, St. !john's, NL, Canada

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

    Abstract

    A sequence stratigraphic analysis coupled with a 3D forward stratigraphic model was performed in the Orphan Basin (NL, Canada). It aimed at understanding the sedimentary and stratigraphic infill of the basin and to define potential plays.

    The basin sequence stratigraphic architecture was initially defined using two composite 2D seismic sections.  This stratigraphic framework was then applied in 3D space using the complete seismic and well dataset to create eight (8) conceptual Gross Depositional Environment (GDE) maps.

    The conceptual GDE were then numerically tested using the 4D forward stratigraphic modelling tool DionisosFlow™. The model allowed the paleoenvironment interpretation to be greatly refined, and the lateral and vertical extension of potential reservoirs on the shelf margin and within large turbiditic complexes to be identified.  Transgressive intervals were highlighted to be favorable to the deposition and preservation of organic-rich sediments.

    The 3D stratigraphic grid results were used to assess the exploration geological risk, considering reservoir/seal presence and effectiveness. Sand and shale distribution in the 3D stratigraphic model is available laterally and vertically in terms of Net sand, Net to Gross and as a minimum continuous thickness. Reservoir / seal couplets, defining plays, were risked (Common Risk Segment mapping) with accurate spatial definition.

     

  • June, 2017

    Uncertainty analysis in forward stratigraphic modeling . . .

    Uncertainty analysis in forward stratigraphic modeling: new approaches to de-risk geological models

    Nicolas Hawie [1] , Alcide Thebault [1]

    1. Beicip-Franlab, Rueil-Malmaison, France

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

    Abstract

    Traditionally, forward stratigraphic models have been used to better assess vertical and lateral facies variations with regards to several environmental parameters affecting both siliciclastic and carbonate realms (i.e., eustasy, carbonate production versus depth and time, wave energy and direction, drainage systems characteristics, subsidence amongst others). Models were generated manually and several scenarios related to input parametrization were tested. Such manual and lengthy tasks hindered the complex assessment of uncertainties and risks related to the geological model while sensitivity of interacting input parameters could not be manually assessed. In order to answer the Oil and Gas industry needs, a new approach has been developed combining forward stratigraphic modeling using DionisosFlow and automated multi-realization and uncertainty analysis using CougarFlow tools. This innovative approach was tested on siliciclastic, carbonate and mixed systems at basin and field scales allowing the end user to simulate hundreds of automated scenarios using a Latin Hypercube Experimental design and a response surface approach. This integrated work tackles challenges faced in classical stochastic geological modelling by providing a stratigraphically-constrained and process based approach of the facies distribution in reservoir and basin models.

    Figure 1 : Uncertainty analysis results for the Abu Dhabi carbonate model (from Hawie et al, 2015)

    Figure 2: Uncertainty analysis results for the Gulf of Mexico clastic model (from Marfisi et al, 2016)

  • June, 2017

    Mesozoic and Cenozoic offshore shallow water carbonates . . .

    Mesozoic and Cenozoic offshore shallow water carbonates of Northwestern Greece: seismic expression of an emerging play.

    Arnaud Fournillon [1], Véronique Carayon [1], Jonathan Allard [1], Øystein Lie [2], Sofia Stamataki [3] and Spyridon Bellas [4].

    1. Beicip-Franlab, Rueil-Malmaison, France

    2. Petroleum Geo-Services-Norway

    3. Hellenic Hydrocarbon Resources Management S.A

    4. Oil & Gas Expert of the EFG, Upstream Expert - Hydrocarbons W/G, Ministry of Reconstruction of Production, Environment & Energy, Hydrocarbons Directorate-Greece.

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

    Abstract

    Carbonate reservoirs are widespread throughout the Mediterranean Sea. Platforms and build-ups represent well-known reservoirs of the Western Mediterranean for both Mesozoic and Cenozoic, whereas they represent proven and promising discoveries in the Eastern Mediterranean. The North Western Greece offshore lying in the less known Central Mediterranean represents one of the last Mediterranean offshore frontiers. This study aims at proposing new carbonate plays in this area and inferring their reservoir potential. It is based on their seismic expression and literature analogue review.

    These carbonates are represented by Mesozoic platforms and build-ups from Jurassic up to Upper Cretaceous, and mostly by build-ups from Eocene to Miocene. The Mesozoic carbonates develop in passive margin condition. They generally form wide rimmed platforms and atoll-like structure. These structures are topped by erosional surface and surrounded by resedimented carbonate belts. The Cenozoic carbonates are quite unique in the Mediterranean as some are formed during the Alpine orogeny climax. This particular geodynamic context favors pinnacle-like structures and isolated build-ups. Local and worldwide analogues, in terms of age, seismic facies and geodynamic context, show that both Mesozoic and Cenozoic shallow-water carbonate represent valuable play.

  • March, 2017

    Risk Analysis in Unexplored Areas: Application of a Response Surface . . .

    Risk Analysis in Unexplored Areas: Application of a Response Surface Model Based Tool Offshore Canada

    Alcide THEBAULT[1], Marie CALLIES[1], Véronique GERVAIS[2]
    1. Beicip-Franlab, Rueil-Malmaison, France.
    2. IFPen, Rueil-Malmaison, France.

    This paper was prepared for presentation at AAPG held in Houston, United States, 2–5 April 2017.

    Abstract

    Coupling the evolution of thermal and pressure regimes through time, petroleum system modeling is recognized as a key tool to estimate source rock maturity and hydrocarbon expulsion timing in unexplored basins. However, most of the data used in such basins is subject to uncertainty which becomes critical in frontier areas where very little information is available for calibration. The potential range of variation of input parameters leads to a high variability of the basin modeling simulation results and there is definitely a need for sensitivity and risk analysis in such studies.

    Traditionally, risk assessment is done performing multi-realizations with a Monte-Carlo sampling which requires a lot of time, sometimes months, when hundreds of simulations are required on a high resolution model. To overcome these delays unaligned to the E&P industry constraints, we here present a new workflow linking basin modeling to a dedicated uncertainty analysis tool based on response surfaces.

    If the later technology is commonly used in reservoir engineering, it is quite unknown in exploration. In this approach, a set of simulations – the experimental design – is used to compute response surfaces that provide very fast estimations of the simulator outputs for any parameter values. The uncertainty study is then conducted from the response surface predictions only. A limited number of simulations is generally sufficient to obtain reliable estimations. The total time required to estimate the risk associated to the model uncertainties is thus drastically reduced.

    The passive margin offshore Canada is used to illustrate this workflow. The focus is made on the deepest Jurassic source rock and the uncertainties linked to its maturity assessment as well as its petroleum potential: depth, surface temperature and basal heat flow variations, initial TOC and HI, etc. Two calibration wells available on the platform are used in the study. A sensitivity analysis is first performed to identify the most influential parameters in the different areas of the basin. A propagation is then realized to estimate the risk on the source rock maturity, the expulsion timing and expelled quantities. Applied to the full source rock unit and not only at a single well location, this approach provides relevant probability maps critical in the decision-making process. 

    Percentiles for the mass of expelled oil per area, estimated in each grid block of the target layer

  • February, 2017

    Integrated Multi-disciplinary Forward Stratigraphic Modelling Workflow . . .

    Integrated Multi-disciplinary Forward Stratigraphic Modelling Workflow In Petroleum Systems Assessment

    Hawie N., Callies, M., Marfisi, E. (Beicip-Franlab)

    Copyright 2017, Society of Petroleum Engineers

    This paper was prepared for presentation at the SPE Middle East Oil & Gas Show and Conference held in Manama, Kingdom of Bahrain, 6–9 March 2017.

    https://www.onepetro.org/conference-paper/SPE-183835-MS

    Abstract

    With the continuous acquisition of worldwide multi-disciplinary datasets, geoscientists face the need for more integration. The combination of diverse expertise and multi-scale datasets has lately been supported by a fast rise in technological advances in data acquisition and processing (e.g., well logs, 3D seismic inversion and characterization) as well as by integrated 4D forward stratigraphic and basin modeling approaches.

    This work discusses the results of innovative methodologies developed in order to tackle rising challenges linked to the exploration of new hydrocarbon resources.

    The use of geomorphological, geological and geophysical constraints in process-based forward stratigraphic models shed light on the complex driving mechanisms that influence sediment transport and/or production and deposition along continuously evolving landscapes.

    The impact of subsidence rates, accommodation, climate evolution, drainage systems as well as eustatic variations on sedimentary bodies geometries and associated facies is investigated in various depositional settings (continental, transitional and marine).

    Lateral and vertical facies variations are consequently modelled taking into account the diversity of impacting environmental parameters.

    Coupled with petrophysical analysis as well as seismic inversion and characterization, this approach permits a 3D prediction of lithology, TOC and porosity distributions for the generation of integrated structural, facies and kerogen maps used in basin models in order to simulate the impact the architectural and thermal evolution on source rock burial, maturation, hydrocarbon generation, migration and trapping.

    These workflows set new grounds for the generation of Play Fairway Maps, Common Risk Maps for the different petroleum systems elements (reservoir, seal, trap and charge) as well as Composite Common Risk Maps permitting to produce innovative ideas and reflections around the exploration and production of hydrocarbon resources.

  • February, 2017

    Surfactant-Polymer Flooding: Chemical Formulation Design and Evaluation . . .

    Surfactant-Polymer Flooding: Chemical Formulation Design and Evaluation for the Raudhatain Lower Burgan (RALB) Reservoir in Kuwait

    M.T. Al-Murayri, A.A. Hassan, M.B. Abdullah, A.M. Abdulrahim, Kuwait Oil Company (KOC); C. Marliere, S. Hocine, R. Tabary, The EOR Alliance

    Copyright 2017, Society of Petroleum Engineers

    This paper was prepared for presentation at the SPE Middle East Oil and Gas Show and Exhibition held in Manama, Bahrain, 06–09 March 2017

    https://www.onepetro.org/conference-paper/SPE-183933-MS

    Abstract

    Surfactant-Polymer (SP) flooding is an Enhanced Oil Recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects while the increased viscosity of the displacing fluid allows a more homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (> 200 g/L) is somewhat challenging. This paper describes the extensive laboratory work performed for the light oil Raudhatain Lower Burgan (RALB) reservoir (180°F/82°C) in Kuwait.

    Reservoir fluids were thoroughly characterized to preselect the most suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C1-C3) based on reported Gas-to-Oil (GOR) ratio to reproduce the oil in-place at original reservoir conditions in terms of pressure, temperature and oil composition. A shift of the live oil Equivalent Alkane Carbon Number (EACN) was noticed compared to dead oil EACN.

    Numerous surfactants were screened based on three main criteria: solubility in the envisioned injection brine, ultra-low oil/water interfacial tension and chemical adsorption on reservoir rock. Different brine types were considered and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening, involving temperature resistant polymers, was conducted by means of viscosity, long-term aging and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments mainly based on chemical adsorption on reservoir rock and incremental oil recovery and an injection strategy was designed thereof.

    Laboratory results obtained thus far are encouraging and provide a systematic methodology to design surfactant-polymer injection in high temperature, high salinity and light oil reservoirs that are similar to the RALB reservoir. Additional techno-economic evaluation is in progress in preparation for field-scale deployment of surfactant polymer injection at the RALB reservoir in Kuwait.

    EACN (Equivalent Alkane Carbon Number) determination experiment. Salinity scans using a reference surfactant formulation with model alkanes and RALB dead crude oil. Series were imaged after 11 days at 82°C/180°F. Optimal salinities (S*) are indicated by green rectangles.

    Static adsorption tests results for Formulations 1, 2 and 3 using crushed reservoir rock and different brines.

  • February, 2017

    Multi-Reservoir Fast-Track Evaluation of EOR Potential Using Conceptual . . .

    Multi-Reservoir Fast-Track Evaluation of EOR Potential Using Conceptual Simulation Models. A Tool to Prioritize Future EOR Efforts

    G. Suzanne, IFP Middle East Consulting ; M. Nurseitova ; K. Andjar, Beicip-Franlab ; R. Garifullin, Beicip GeoTechnologies ; M. Lantoine ; S. Roosz ; T. Lemaux, Beicip-Franlab

    Copyright 2017, Society of Petroleum Engineers

    This paper was prepared for presentation at the SPE Middle East Oil & Gas Show and Conference held in Manama, Kingdom of Bahrain, 6—9 March 2017

    https://www.onepetro.org/conference-paper/SPE-183761-MS

    Abstract

    The objective of the approach presented here was to assess the applicability of EOR methods for 10 light-oil reservoirs in a short-time period (6 months). There were two goals in this study:

    - Identify for each reservoir the most promising EOR method in terms of oil recovery and estimated large-scale economics

    - Identify the most promising reservoir(s) on which further efforts on EOR development should be concentrated.

    To meet these objectives, simplified numerical simulations were performed at well-pattern scale. Extracting and history-matching a sector from an existing model being too long for this study specific timeline, the following steps were adopted:

    - Identification of typical well log and pattern geometry

    - Construction of a representative sector model (geometry and petrophysical properties)

    - Dynamic calibration of the sector

    - Simulation of water-based and gas-based EOR processes with a multi-scenario approach scanning the main uncertain parameters

    - Upscaling of the results (production and injection profiles) from the sector to the field scale

    - Economic analysis to calculate usual indicators for each EOR scenario.

    The methodology was successfully developed and applied to 10 light-oil reservoirs.

    Up to 3 water-based or gas-based EOR methods were simulated per reservoir. Since thermal methods were discarded during a preliminary screening, they were not considered at this stage of the study. No laboratory analysis was performed during this study. For each EOR process, parameters were varied within their range of uncertainty in order to scan a wide range of possible scenarios. Consequently, around 50 scenarios were simulated for each EOR process and reservoir.

    Scenarios giving promising results at the simulation scale were extrapolated to the field scale and yearly-based economic analysis was performed for each of them. This economic analysis used estimated CAPEX and OPEX, consistent with each reservoir conditions and extent. The outputs of this economic analysis were common indicators such as net present value and profitability index. These indicators were used to perform a ranking of the most economically promising EOR processes of 10 reservoirs.

    Among these reservoirs, 3 were identified as very promising for chemical EOR application, and 1 for a gas-based method. As a result of this work more detailed feasibility studies, including laboratory work, are now considered for the most promising reservoirs.

    Though the EOR simulations and the economic analysis techniques are not novel in this workflow, this advanced EOR screening approach is innovative since it provides economic indicators, in addition to the usual recovery factor, which helps prioritise reservoirs regarding their EOR potential. This methodology stands between analytical workflows which estimate recovery (usually without capturing geological heterogeneities nor providing economic indicators) and more detailed, time-consuming and more expensive workflows with large-scale reservoir simulations.

    Cumulative oil production profiles for reservoir A at the scale of the conceptual model grid. Left plot displays the waterflood base case (in black) and several surfactant-polymer flooding cases (in red) profiles among the 54 that were simulated. Right plot displays the waterflood base case (in black) and several immiscible gas injection cases (in red) profiles among the 45 that were simulated.

  • January, 2017

    Simulation of Chemical EOR Processes for the Ratqa Lower Fars . . .

    Simulation of Chemical EOR Processes for the Ratqa Lower Fars Heavy Oil Field in Kuwait: Multi-Scenario Results and Discussions

    M.T. Al-Murayri, A.A. Hassan, N.M. Al-Tameemi, R.G. Lara, A. Al-Sane, Kuwait Oil Company (KOC); G. Suzanne, M. Lantoine, The EOR Alliance

    Copyright 2016, Society of Petroleum Engineers

    This paper was prepared for presentation at the SPE International Heavy Oil Conference and Exhibition held in Mangaf, Kuwait, 6–8 December 2016.

    https://www.onepetro.org/conference-paper/SPE-184086-MS

    Abstract

    This paper presents the results of a multi-scenario approach that involves the simulation of chemical EOR processes (polymer- and surfactant-based) for the Ratqa Lower Fars heavy oil (200-1000 cP) field in Kuwait, in order to evaluate the viability of implementing an appropriate chemical EOR strategy. Both technical and economic results are discussed.

    The approach used involves the simulation of various chemical EOR scenarios (injection of chemical slugs with different durations and concentrations) using several wells patterns (inverted 5-spot, inverted 9-spot, inverted 7-spot with vertical wells, line-drive with horizontal wells) covering various sizes in terms of area. Preliminary simulations of depletion and waterflooding scenarios were also conducted, as base cases to be compared to.

    Hundreds of EOR scenarios were hence simulated and compared using economic indicators such as the final recovery factor and the cost of chemicals per additional barrel of oil produced, compared to the waterflooding base case scenario.

    The analysis of the different simulated scenarios shows that due to injectivity issues (low maximum injection pressure to prevent the shale cap rock from being fractured), inverted patterns (inverted 9-spot and especially inverted 7-spot) had to be considered to enhance overall performance and reach promising recovery factors using chemical EOR methods.

    It is also shown that the impact of the pattern area for the same pattern type (inverted 7-spot configuration) is of paramount importance to the final recovery factor obtained after a fixed simulation duration (20 years in the present case). While the overall efficiency of each EOR process - in terms of recovery factor as a function of the injected solution expressed in pore volume - is kept similar when varying the pattern area, the pattern size is directly linked to the final recovery. Indeed when the pattern area is increased, a smaller volume (in terms of pore volume) of chemical solution can be injected in a fixed timeframe.

    Finally, the use of simplified economic indicators allowed comparing different EOR processes (polymer and surfactant-polymer) and potential patterns in order to find the most promising configuration in preparation for field implementation.

    The proposed approach is new as it presents and discusses for the first time the results of a detailed simulation study to evaluate the potential application of chemical EOR processes at the Ratqa Lower Fars heavy oil field in Kuwait. The results of this study are promising and clearly demonstrate the potential applicability of chemical EOR processes in similar heavy oil reservoirs.

    Overview of the EOR scenarios using the 80m-spaced inverted 7-spot pattern

    Cross-sectional view of oil saturation in the simulation grid (80m-spaced inverted 7-spot pattern)

    Surfactant-polymer flood

  • November, 2016

    Integrated Rock-Typing Workflow in Shallow Unconventional Reservoir in Kuwait

    Integrated Rock-Typing Workflow in Shallow Unconventional Reservoir in Kuwait

    Pabitra Saikia, Faisal Shanat, Khalid Ahmed, Pradeep Choudhary, Hasan Ferdous, Fatma Ahmed, Kuwait Oil Company, and Frédérique Fournier[1]

    (1) Beicip-Franlab, 232 Avenue Napoléon Bonaparte, 92500 Rueil-Malmaison, France.

    This paper was prepared for presentation at the SPE International Heavy Oil Conference and Exhibition held in Mangaf, Kuwait, 6–8 December 2016.

    https://www.onepetro.org/conference-paper/SPE-184137-MS

    Heterogeneous lithofacies distribution resulting into a complex rock-type model in shallow unconsolidated reservoir has a direct role on fluid distribution and trapping mechanisms. A systematic evaluation of these rock-types is necessary for proper reservoir characterization and modeling. In reality, the lithofacies leading to rock-types act as the building blocks to construct a realistic static model, which serves in the understanding of the dynamic behavior of the reservoir.

    During this study, 202 wells were selected across the field to capture the vertical and lateral heterogeneity of the reservoir, out of which 93 wells have cores. During a first step, a lithofacies prediction model was created from the core sedimentological description, X-Ray Diffraction (XRD), and wireline logs (raw and mineralogical logs) using probabilistic classification schemes. In a second step, petrophysical data like Routine Core Analysis (RCAL), Mercury Injection Capillary Pressure (MICP), were included to build rock-types associated with the different lithofacies. This integration workflow has resulted in a robust lithofacies and rock-type model consisting of nine lithofacies and five rock-types respectively. It was also noticed that silty non-pay and marginal pay reservoir have inadequate MICP data. Subsequently, two wells were selected and MICP data will be collected for improved and more confident modelling in future.

    This model assists to predict lithofacies and rock-types in un-cored wells provided a set of relevant logs are available. The integrated workflow ensures that the lithofacies and rock-types determined at the wells are consistent all over the study area.

    The identified lithofacies and rock-types will add great value in building a realistic reservoir static model since they are able to explain the fluid distribution pattern and the concept of barriers and baffles in the reservoir. This will also assist in optimized perforation and completion plans for the reservoir. Ultimately, the input data are readily available for future field-intensive reservoir characterization.

     


     

  • September, 2016

    Rospo Mare Integrated Reservoir Study

    Rospo Mare Integrated Reservoir Study (Italy, Adriatic Sea): an Innovative Approach of Karst System Modeling and History Match

    This paper was presented at the SPE Annual Technical Conference and Exhibition held in Dubai, UAE, 26–28 September 2016.

    G. Bellentani, A. Godi, F. Siliprandi, P. Terdich, Edison; C. Famy[1], F. Fournier[1], C. Jumeaucourt[1], P. Leandri[1], T. Le Maux[1]

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

     

    Rospo Mare is a heavy oil fractured karstic carbonate reservoir producing since the 80’s. Reservoir pressure is constant due to a strong aquifer tilted toward north east. The producing wells are systematically operated at critical rate to prevent water production (no water treatment installation). The paper is focused on the modeling of the fractures and the karst system in conjunction with an innovative history match approach used to match the forced anhydrous oil production and to represent the complex water position and behavior through time.

    As the main fracturing phase of Rospo Mare reservoir occurred before the karstification phase, the dissolution of the carbonates was guided by the existing fracture network. The karst system and the fracture network were modeled together thanks to a fracture model that includes several enlarged fracture sets and lineaments. The fracture modeling was also guided by the relative compactness of the matrix facies distribution. Because of limited data for fracture characterization, the dynamic characteristics of fractures, particularly the aperture of enlarged fractures, were fully considered as history match parameters. The history match approach consisted in using both the historical oil production and the prediction period to make sure that the wells were producing at their critical rate and ensure a realistic displacement of water at both field and well levels. This unusual strategy was necessary because of lack of data to constrain history match (no water and gas production, no pressure variation).

    Therefore the history match was performed by taking into account the prediction period through a do nothing case scenario. Based on the assumption of critical rate, a decline of the oil production rate is expected during the prediction period. This allowed assessing the vicinity of water at wells: both the rise of the water table and the coning effect at wells. The matched model successfully honors the water displacement and position at key wells including the last two side tracks drilled in 2012. The model allows a good representation of the reservoir physical behavior and provides a useful tool for piloting the field and assisting future decisions.

    https://www.onepetro.org/conference-paper/SPE-181636-MS

     

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