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.
Al-Murayri, Mohammed (Kuwait Oil Company) | Hassan, Abrahim (Kuwait Oil Company) | Hénaut, Isabelle (IFPEN) | Marlière, Claire (IFPEN) | Mouret, Aurélie (IFPEN) | Lalanne-Aulet, David (SOLVAY) | Sanchez, Juan-Pablo (Beicip-Franlab) | Suzanne, Guillaume (Beicip-Franlab)
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.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdelgadir (Kuwait Oil Company) | Al-Ajmi, Naser Ammash (Kuwait Oil Company) | Wartenberg, Nicolas (Solvay) | Delbos, Aline (IFPEN) | Suzanne, Guillaume (Beicip-Franlab)
There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.
Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery.
Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot.
This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdulgadir (Kuwait Oil Company) | Al-Mahmeed, Narjes (Kuwait Oil Company) | Suzanne, Guillaume (Beicip-Franlab) | Sanchez, Juan-Pablo (Beicip-Franlab)
This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment.
Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation.
It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity test Polymer solution injection Measurement of oil saturation Surfactant-polymer injection followed by polymer drive Measurement of oil saturation
Initial water injectivity test
Polymer solution injection
Measurement of oil saturation
Surfactant-polymer injection followed by polymer drive
Measurement of oil saturation
This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.
Kumar, Rajive (Kuwait Oil Company) | Al-Kanderi, Jassim (Kuwait Oil Company) | Mishra, Prasanta Kumar (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Baillet, Romain (Beicip-Franlab) | Stozicky, Eléonore (Beicip-Franlab) | Lecante, Gaeël (Beicip-Franlab)
This paper describes an advanced methodology for fault and fracture detection using seismic data. The understanding of the fracture network is often necessary for both exploration or production context, as it can be a key driver controlling the fluid movements. In case of highly fractured field, it has to be considered in basin and reservoir models while performing flow simulations or to be taken into account while performing risk analysis for sealing issues. In this paper, we will illustrate the seismic fracture characterization workflow from a study in Kuwait to substantiate this. In this study, in high pore pressure conditions in the formation, the presence of fractures can enhance the drilling risks for future well planning.
A dedicated workflow to detect faults and more subtle fractures has been carried out, based on inversion results. The 3D seismic data under study is contaminated with inter-bed multiple reflections. During the seismic inversion, the Inter-Bed Multiple Modeling (IBMM) allows significantly attenuating the multiple contamination of the formation, while maximizing the resolution and reducing the random noise. Then, the fracture characterization consists in computing 3D discontinuity attributes (geometrical, coherence or energy-based) and then capture the fracture intensity. Several 3D attributes are used for fracture detection in order to involve different computation methods, each one being sensitive to discontinuities of the seismic signal that can be subtle and of different nature.
Such workflow requires in the end a synthesis of the fracture information to obtain a final seismic fracture index. The obtained result relies strongly on the quality of the attributes. Therefore, several attribute enhancements, aimed at decoupling the fine-scale fracture response from the broad-scale structure response are described and compared. Two complementary methodologies to propose a fracture index are proposed and discussed.
Presentation Date: Wednesday, September 27, 2017
Start Time: 9:20 AM
Presentation Type: ORAL
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.
Suzanne, G. (IFP Middle East Consulting) | Nurseitova, M. (Beicip-Franlab) | Andjar, K. (Beicip-Franlab) | Garifullin, R. (Beicip GeoTechnologies) | Lantoine, M. (Beicip-Franlab) | Roosz, S. (Beicip-Franlab) | Lemaux, T. (Beicip-Franlab)
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.
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.
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.
Saikia, Pabitra (Kuwait Oil Company) | Shanat, Faisal (Kuwait Oil Company) | Ahmed, Khalid (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Ferdous, Hasan (Kuwait Oil Company) | Ahmed, Fatma (Kuwait Oil Company) | Fournier, Frédérique (Beicip-Franlab)
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.
Hawie, N. (Beicip-Franlab) | Dubille, M. (Beicip-Franlab) | Guyomar, N. (Beicip-Franlab) | Maury, G. (Beicip-Franlab) | Thomas, V. (Beicip-Franlab) | Vidal, O. (Beicip-Franlab) | Carayon, V. (Beicip-Franlab) | Cuilhe, L. (Beicip-Franlab) | Al-Sahlan, G. (Kuwait Oil Company) | Al-Ali, S. (Kuwait Oil Company) | Al-Khamis, A. (Kuwait Oil Company) | Dawwas Al-Ajmi, M. (Kuwait Oil Company)
Hydrocarbon exploration along the Arabian Peninsula is almost celebrating a century of successes. Major structures were drilled and hundreds of billions of barrels consequently discovered and still producing at increasing rates. Remarkable 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 allowing geoscientists to better assess the diverse onshore and offshore Petroleum Systems’ potential. 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. "Integration" remains a key problematic that needs to be tackled in order to answer properly to how much resources are still left unexplored. Thus, multi-disciplinary expertise, multi-scale dataset combination should be supported by recent technological advances in data acquisition and processing (e.g., 3D Seismic inversion and characterization) as well as by integrated modelling approaches (e.g., 4D Forward Stratigraphic and Basin Modelling).
This paper discusses the results of an innovative methodology developed to assess the exploration potential of the Lower Cretaceous along a wide sector of the mature Eastern Arabian Plate that extends over more than 35 000 km2 (Onshore and Offshore Kuwait).
As major structural features have already been drilled, a focus is set on the detection of subtle stratigraphic trapping mechanisms using multi-disciplinary and multi-scale sedimentological, stratigraphic, petrophysical and geophysical techniques. Seismic stratigraphy study based on reflectors configuration and internal geometry analysis has enabled the delineation of geobodies, i.e. reservoir/seal pairs and proposed conceptual models associated to the presence of subtle traps. A regional
This innovative and integrated 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.
Bellentani, G. (Edison) | Godi, A. (Edison) | Siliprandi, F. (Edison) | Terdich, P. (Edison) | Famy, C. (Beicip-Franlab) | Fournier, F. (Beicip-Franlab) | Jumeaucourt, C. (Beicip-Franlab) | Leandri, P. (Beicip-Franlab) | Le Maux, T. (Beicip-Franlab)
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.