Heavy oil reservoirs are known for their low recovery factors. Additional energy consumption, special operations, and enhanced oil recovery (EOR) techniques are required for production due to high viscosities. Also, unfavorable water-oil mobility ratio is a serious problem when waterflooding (WF) is implemented, usually causing early breakthrough and higher water cut. Developing and managing a production strategy through a comprehensive decision-making procedure is also complex due to the high number of variables, uncertainties, and physical phenomena involved. Polymer flooding (PF) is an EOR method that can be applied to heavy oil reservoirs to improve field performance by producing more oil and reducing water production. This improvement is achieved through the increase in water viscosity caused by the injection of polymers, thus reducing water-oil mobility ratio, and obtaining better oil displacement efficiency. In the case of intelligent wells (IW) equipped with Inflow Control Valves (ICVs), the WF limitations can be mitigated by controlling multiple production/injection zones, increasing oil production, and maintaining the reservoir pressure. This work aims to perform a nominal production strategy optimization to develop and manage a heavy oil reservoir considering PF as a production strategy (using conventional wells only) and comparing it to waterflooding with ICVs (WF+ICV) for the same case. A complete methodology to optimize the design and control variables is applied to the strategies by using model-based reservoir simulation. The objective function (OF) is the Net Present Value (NPV), this study case is named EPIC001, which has a 13° API heavy oil reservoir that represents part of a Brazilian offshore field. We have applied a specific methodology to optimize the PF strategy for a heavy oil reservoir of a nominal case which is practical and clear in the selection and comparison of strategies for similar cases. The results found PF strategy is the more suitable for the case, obtaining an NPV that is 21% higher than WF+ICV. Injecting polymers in the earlier stages of the life cycle at lower polymer concentration rendered PF with greater oil recovery (+13%) with a better efficiency in management of water and polymers, therefore surpassing the good ICV management from WF+ICV.
Mês: janeiro 2026
High-pressure PVT properties of synthetic oil/gas systems for EOR: The effect of CH4 and a CO2-rich gas on a heptane/toluene mixture
Understanding the flow and phase behavior properties of reservoir fluid–injected gas systems is essential for optimizing oil production strategies and designing gas injection-based Enhanced Oil Recovery (EOR) techniques. In the absence of live oil data, synthetic model mixtures with similar characteristics can provide reliable input for reservoir simulation. This study investigates the bubble point pressures (BPP) and the volumetric behavior of two synthetic systems: (n-heptane + toluene + methane) and (n-heptane + toluene + carbon dioxide + methane). BPP values were measured for mixtures with varying CH4 or (CO2 + CH4) content over the (304.7–363.2) K range. The two experimental techniques used, a stepwise and a visual method, showed excellent agreement with each other (RMSD = 0.01 MPa). Liquid phase densities were determined across wide temperature (293.2–363.2) K and pressure (5–90) MPa ranges.
The Soave-Redlich-Kwong (SRK) and Peng-Robinson (PR) equations of state (EoS) were applied to model the saturation pressures, achieving average relative deviations (ARDs) of 5.8% and 6.0%, respectively. The experimental density data were correlated using the Tammann-Tait equation, yielding low ARDs of 0.09% (ternary system) and 0.03% (quaternary system). Isothermal compressibility and the isobaric thermal expansivity were subsequently derived from the fitted Tammann-Tait equation parameters. Finally, liquid densities were predicted using the original and volume-translated (VT) forms of the SRK and PR EoS. The volume-translated correction significantly improved predictive accuracy, reducing the global ARD from 11.2% (SRK) to 2.1% (SRK-VT) and from 2.0% (PR) to 1.4% (PR-VT).
Optimizing Gas Export Flexibility for Complex Offshore Reservoirs: A Brazilian Case
Oil and gas reservoir management is associated with uncertainties and risks that can significantly impact performance and economic outcomes. The objective of this work is to present how flexibility can be used to manage risk and uncertainty, as well as evaluate the potential flexibility to export and commercialize natural gas as an alternative to water-alternating-gas (WAG) in Brazilian pre-salt fields, identifying favorable and unfavorable scenarios for its implementation. This work presents a case study that addresses the challenges and opportunities of the expected value of the flexibility associated with natural gas export.
The methodology developed presents a structured technique to assess and select optimal strategies under subsurface uncertainties and possible market fluctuations, combining asset portfolio management with reservoir simulation. One of the main advantages of this methodology is that the chance of success is determined through an automated procedure that can be obtained using the production optimization of representative scenarios. Additionally, to illustrate the applicability, we present an application case study to design flexible facilities that allow future expansion for natural gas commercialization, thus capturing possible upsides considering variations in oil and gas selling prices. We also present how these variations impact the overall design to reduce risks and enhance asset value using a simulation model designed to replicate the Brazilian pre-salt fields and forecasting the value of the natural gas in the country.
The results show that this integrated analysis addresses immediate challenges and highlights future advancement potentials through strategic flexibility in Brazil’s natural gas industry, demonstrating that well-planned flexibility can significantly mitigate risks and enhance the resilience of petroleum management strategies. By aligning sustainable petroleum production with CO2 fraction reinjection, we argue that it is more lucrative to produce the natural gas fraction at lower oil prices and that there is a balance point of WAG miscibility to gas price, coupled with enhanced flexibility. We demonstrate how it is possible to increase asset value and mitigate risks, therefore addressing a major concern for stakeholders.
Investigation of Biases Caused by Model-Based Optimization Processes for Reservoir Management
In reservoir management, many decisions are made considering model-based production forecasts and optimization processes. These approaches can generate biases and the actual production and economic return may be overestimated. One of the reasons for these biases is the optimization process itself (procedure bias). Thus, the objective of this work is to investigate biases caused by model-based optimization processes using synthetic benchmark cases, analyzing the magnitude and the impact on future decisions.
We use synthetic benchmarks composed of: (1) an ensemble of data-assimilated simulation models; (2) a subset of this ensemble, named Representative Models (RMs); (3) a reference case, used as the real response of the reservoir (ground truth). Two case studies are analyzed: one focused on design variables (development phase), and the other on control variables (management phase). We demonstrate how specialized and robust strategies (resulting from nominal and robust optimizations, respectively) behave in relation to the ensemble of models and in relation to the reference case, using Net Present Value (NPV) and Expected Monetary Value (EMV) as objective functions.
The results confirm the presence of bias and overestimated forecasts caused by optimization processes. In Case Study 1 (development phase), the robust strategy showed an expected return improvement of 45% due to optimization, while the actual gain was only 6%. Specialized strategies presented differences between expected and actual economic gains ranging from 38% to 179% (with an average of 79%). In Case Study 2 (management phase), the robust strategy yielded a 4.1% expected increase in economic return compared to a 2.5% actual gain, with specialized strategies showing an average overestimation of 38% for the specialized strategies. The bias was stronger in Case Study 1 due to the greater impact of development variables on reservoir performance. Risk curve and boxplot analyses showed that strategies tend to become overly specialized to the model in which they were optimized, may leading to suboptimal decisions when applied to the real field.
By employing synthetic benchmarks with known reference cases, this work quantifies the overestimation introduced by optimization processes, providing valuable insights to help practitioners recognize and account for procedure bias, reducing the risk of overconfident model-based decisions in real-field applications.
Fast Objective Function Estimator Based on Parametric Dynamic Mode Decomposition for Wag-Co2 Injection in Carbonate Reservoirs
Objective/Scope
Fast-objective function estimators (FOFE) are often used to speed up reservoir management. This work presents a FOFE constructed with the parametric Dynamic Mode Decomposition (DMDp) method for a carbonate reservoir with WAG-CO2 injection. The FOFE results are then compared to simulation results to analyze the FOFE’s efficiency.
Method/Procedure/Process
We present an example of how changes in the production strategy can affect reservoir behavior. The FOFE utilizes snapshots of gas and water saturation of numerical simulation runs with different sizes of WAG-CO2 cycles to predict the snapshots and fluid rates of a production strategy with a desired WAG-CO2 cycle size. The FOFE utilizes the DMDp method to calculate the saturation snapshots and material balance equations to calculate oil, water, and gas rates. Unlike the standard where snapshots are stacked up for multiple parameters, leading to increased computational costs, here we perform interpolation directly on the reduced Koopman operator. This leads to enhanced performance as the time eigenvalues are no longer shared between all parameters. The case study is the public access benchmark UNΊSFM-ΓV-2022, a carbonate reservoir model with characteristics of the Brazilian pre-salt. This model represents a developed reservoir with a WAG-CO2 recovery method for a compositional simulator with historical data.
Results/Observations/Conclusions
For this work, the FOFE utilizes snapshots of two reservoir simulations, one with a WAG-CO2 cycle size of 6 months and the other with 18 months, to predict the states of a production strategy with 12 months of WAG-CO2 cycle. The FOFE results of gas, oil, and water are compared to a simulation result with the same production strategy. The comparisons for fluid dynamics are shown for reservoir conditions, and their curves with relative differences are provided. The FOFE can predict the states of a different field scenario, dispensing the necessity of extra numerical simulation runs. This result is promising for production optimization problems which require a significant amount of simulation runs to incorporate the many reservoir uncertainties, as it is observed in highly heterogeneous carbonate reservoirs.
Novel/Additive Information
The innovation of this work is the utilization of the DMDp in a highly heterogeneous reservoir with three-phase flow and WAG-CO2 injection utilizing commercial software. This FOFE can be utilized to reduce the time and computational effort necessary for the decision-making process involving the control variable of WAG-CO2 cycle size.
Enhancing Asset Profitability with Flexibility for Life Cycle Field Development – A Comparative Study for Well Placement Allocation and Platform Capacity
In the context of rising global energy demands that are aligned with sustainable energy supply, making informed decisions regarding investments has become increasingly complex. This complexity is particularly challenging in oil and gas management, where devising a production strategy and commencing field development pose challenges given the multitude of uncertain variables and extended timelines involved. Flexibility is key to address these uncertainties. Hence, the objective of this article is to evaluate the importance and advantages of considering the expected value of flexibility in the decision-making process to create a strategy able to deal with the risks imposed in the petroleum industry. Doing so, this article provides an examination of different approaches employed for the implementation of flexibility, considering the well placement allocations, final strategy selection, and platform capacity, thereby offering an informed perspective on this crucial aspect of reservoir strategic management.
The methodology for the construction of a flexible strategy employs theories in decision analysis combined with reservoir simulation models and optimization methods in a Bayesian probabilistic approach to access the expected value of the flexibility (EVoF). We present a structured technique to assess and select optimal strategies, specifically focusing on managing uncertainty in the initial stages of field development to identify potential platform capacities and drilling location strategies in the face of uncertainties related to reservoir characteristics, facility operations, and market conditions. To illustrate the results, we conduct a case study on an offshore benchmark field with Brazilian pre-salt features under WAG-CO2 recovery method, involving the complete reinjection of produced CO2 to mitigate greenhouse gas effects.
The results reveal that the initial strategy can highly impact the final net present value outcome and risk curves due to the first wells drilled. The results also indicate that increasing flexibility in the early stage of development could extract the best results related to financial return. Our study underscores the immense potential of integrating flexibility valuation and uncertainty quantification into the energy planning and policy-making process. It also highlights that the holistic integration between flexibility and reservoir simulation facilitates the identification of innovative investment strategies and enhances the decision-making process with the tools to navigate the complexities of uncertainty with greater confidence and adaptability.
This innovative approach offers a structured technique that not only addresses uncertainties in the subsurface reservoir and economic scenarios but also contributes to the identification of methodologies for investment management, enhancing the adaptability in the dynamic landscape of reservoir engineering.
Investigating Fail in Downhole Chemical Injection Valves (CIVs) – A Teardown Analysis
Chemicals have been injected into the downhole of the oil wells in an attempt to ensure efficient production.
This measure is a usual oilfield strategy to improve the characteristics of crudes or deal with some flow
assurance problems, such as emulsions, scales, paraffin or asphaltenes deposition, etc. To overcome these
issues, downhole chemical injection systems (DHCI) have been installed in production facilities, in which the
injection of chemicals is controlled by chemical injection valves (CIVs). In this work, it was investigated the
possible causes of the failure of four commercial CIVs from demulsifier injection lines installed in heavy oil
production systems. The analysis consisted of disassembling the CIVs and analyzing their internal elements,
seeking the cause of the failure. A solid material (clogging) was found in some specific parts of the CIVs, which
could be the main cause of the CIVs’ failure. Solubility tests indicated a polar or apolar characteristic,
depending on the CIV. After the analysis, the CIVs were cleaned and reassembled, and tests in a high-pressure
line indicated that all of them got back to work properly. These findings have significant implications for
diagnosing the root causes of CIV failures in demulsifier injection lines, presenting a procedure to recover
obstructed CIVs, and offering preventive measures against future clogging issues.
Influence of Fluid Viscosity on the Flow Behavior within the Impeller of an Electrical Submersible Pump (ESP)
The electrical submersible pump (ESP) plays a crucial role in artificial lift operations in the oil and gas industry.
The viscosity of the pumped fluid significantly influences the flow dynamics within the ESP, thereby impacting
the performance of the machine. In this context, flow visualization techniques can unveil intricate details of the
flow in ESP impellers, thus providing a deeper understanding of the relationship between flow behavior and
pump performance. This is the main idea of the present document, which utilizes the particle image velocimetry
(PIV) technique to experimentally investigate a mineral oil flow, 𝜇 = 14 𝑐𝑃, in a transparent prototype of a real
impeller, P23 model. The paper reports insights into the flow in the pump’s rotating component at different flow
rates that correspond to percentages of the best efficiency point (BEP). Average velocity fields and turbulent
kinetic energy plots indicate that flow dynamics are highly dependent on the operating conditions of the ESP.
A comparison between results for oil and water completes the analysis, as it highlights the effects of viscosity
on the flow characteristics. This type of study is useful to validate numerical simulations, support mathematical
models, and develop improved impeller designs.
Incorporation of Conceptual Geological Model for Fracture Distribution in 3D Reservoir Modeling
Conceptual Geological Models (CGM) serve as a robust tool for 3D reservoir model building, since they allow the representation of geological knowledge in the subsurface, guiding the depiction of fault and fracture distribution, providing insights into their local occurrences, densities, orientations, and aperture. The Brazilian pre-salt carbonate reservoirs are characterized by complex fault systems and natural fractures, with variations related to structural geology, paleotopography, and stratigraphy. This study aims to integrate a CGM into 3D reservoir modeling, focusing on faults and fractures below seismic resolution for an area within an oilfield in the Santos Basin (Santos Outer High), centered on the Barra Velha Formation (BVE), where a PSDM seismic volume, wells (with conventional and special logs), and core samples and thin sections were available. Data analysis resulted in the interpretation of the main horizons in the area and the preferential distribution of fracture families (P10, P20, and P21). Findings from a CGM of fracture distribution were incorporated into reservoir modeling through the Discrete Fracture Network (DFN) methodology, in particular, that the fractures in the BVE are generally correlated with silica-rich zones of the formation. From this, maps of silica distribution were elaborated for the different stratigraphic units of the BVE and used as a constraint for the creation of the fracture networks and the DFN model. Preliminary results show that the use of a CGM proved to be advantageous in the DFN model creation process.