Publications

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.

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.

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.

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.

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%.

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.

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.

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.

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

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)

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.

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.

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, KronosFlow^TM 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.

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.

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.

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

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

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.

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.

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%.

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)

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

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.

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