Abdul Ghani, Mohamad (IFP Energies nouvelles) | Ayache, Simon Victor (IFP Energies nouvelles) | Batôt, Guillaume (IFP Energies nouvelles) | Gasser-Dorado, Julien (IFP Energies nouvelles) | Delamaide, Eric (IFP Technologies Canada Inc)
Although SAGD is a very popular in-situ extraction method in Canada, this thermal process relies on huge energy and water consumption to generate the steam. Irregular growth of the steam-chamber due to heterogeneities further degrades its yield. Contact between the steam chamber and the overburden also leads to heat losses. The objective of this paper is to investigate how Foam Assisted-SAGD could mitigate these technical issues and improve the efficiency of the SAGD process. Compositional thermal reservoir simulations are used to simulate and analyze a Foam Assisted-SAGD pilot. The shear-thinning effect close to the wells is also accounted for. The simulations are run on a homogeneous model mimicking the Foster Creek project in Alberta, Canada. Several type of injection sequences have been analyzed in terms of foam formation, back-produced surfactants and cumulative Steam-Oil-Ratio. Results are compared with the original SAGD performance. In order to propagate the foaming surfactants throughout the steam chamber the injection sequence needs to be properly determined. A simple continuous Foam Assisted-SAGD injection would lead to an accumulation of surfactant between the wells due to gravity segregation, preventing the foam from acting on the upper part of the steam chamber. Furthermore surfactant production occurs after a few weeks due to the proximity of the producer and the injector. A proper injection strategy of the type SAGD/slug/SAGD/slug is found to delay the chemical breakthrough and increase the amount of surfactant retained in the reservoir while allowing the surfactant propagation throughout the steam chamber. After optimization the Foam Assisted-SAGD process appears to be technically promising.
A numerical simulation model was designed to evaluate the technical viability of in-situ upgrading using dispersed nanocatalysts in heavy oil reservoirs. Aquathermolysis reactions are represented by a practical kinetic model based on SARA analysis, being consistent with the thermodynamic characterization. With this simplified model, the API gravity enhancement in core-flooding tests was reproduced. The mathematical formulation couples mass and energy transport equations along with a rigorous three-phase equilibrium equation of state. Also, a nanoparticle transport equation was coupled to account for reversible and irreversible non-equilibrium retention, and water-oil partitioning. PVT data were matched successfully, including API gravities and oil viscosities. Reaction rates were adjusted by means of batch-reactor information, while nanoparticle retention was validated using reported single-phase core-flooding tests. Different core-flooding experiments from the literature were reproduced to calibrate the phases transport parameters, and further up-scaled to reservoir conditions. Validation of the model with experimental data suggests that the lumping scheme based on SARA analysis and the modeling of nanoparticle transport and retention, capture the most important phenomena occurring during in-situ upgrading processes. Field-scale simulations, of a sector model from an oil reservoir in the Magdalena Medio Valley basin in Colombia, showed that the in-situ upgrading with nanoparticles can increase the recovery factor up to 5% compared with typical steam injection. However, the oil upgrading achieved in the continuous injection was lower than the one obtained in the core-flooding tests. The numerical model presented in this work, which includes a dynamic nanoparticle retention model, changes on relative permeability alteration due to nanoparticle surface deposition, and a suited kinetic-thermodynamic representation, is able to describe correctly the most relevant phenomena observed during nanocatalysts in-situ upgrading process.
Gasser-Dorado, Julien (IFP Energies nouvelles) | Ayache, Simon Victor (IFP Energies nouvelles) | Lamoureux-Var, Violaine (IFP Energies nouvelles) | Preux, Christophe (IFP Energies nouvelles) | Michel, Pauline (IFP Energies nouvelles)
SAGD is commonly used as a thermal EOR method to produce heavy oil. However it suffers from the production of acid gases formed by aquathermolysis chemical reactions that occur between the steam, the sulfur-rich oil and the mineral matrix. The objectives of this paper are to take advantage of a comprehensive chemical model coupled to compositional thermal reservoir simulations to predict and understand the H2S production variation at surface according to the type of reservoir.
Thermal reservoir simulations coupled to both a SARA based 10-component / 5-reaction chemical model fully calibrated against laboratory data and a compositional PVT are used to simulate SAGD processes on heavy oil fields in Athabasca, Canada. Numerical results are then analyzed to provide a comprehensive analysis of the mechanisms leading to in-situ H2S generation and its production at wellheads based on compositional thermal simulations coupled to a fully laboratory calibrated SARA-based chemical model. Composition of the pre-steam, post-steam and produced oil are compared to understand the effect of the aquathermolysis reactions. The impact of heterogeneities on H2S production both in-situ and at surface can also be observed and explained, especially the variations in vertical permeability. Then simple reservoir models with two facies are used to further understand the impact of heterogeneities on H2S production at surface. Overall heterogeneous cases show important changes in the temperature distribution, fluid flows, reactions kinetics and steam chamber shape that lead to H2S production variations at surface. This detailed description of the involved mechanisms in acid gases production will allow operators to better forecast their H2S risks according to their reservoir properties.
This article highlights interesting applications of machine learning in the oil and gas industry in drilling, formation evaluation, and reservoir engineering. Each project uses a data-driven model to solve a previously complex problem using machine learning to augment an existing solution. Graham Hack shares his experience working for a large and a small E&P company and discusses how the role of young professionals can differ in these companies. This article presents three important R&D realms that demonstrate good collaborative efforts between independents and academic research institutions. Three women working in R&D offer perspectives on their work, why they joined that branch of the industry, what projects they work on, and what keeps them challenged.
Cenovus Energy announced that it reached 1 billion bbl of cumulative production from its oil sands facilities in northern Alberta, becoming the first company to reach this milestone using SAGD technology. Steam-assisted gravity drainage (SAGD) is a prime example of how structured research and development (R&D) has led to the commercial implementation of technology, helping unlock hydrocarbon resources to fulfill society’s energy demands.
The addition of a hydrocarbon condensate to steam operations in heavy-oil and bitumen reservoirs has emerged as a potential technology to improve not only oil recovery but also energy efficiency. Thermal steam stimulation is considered the most effective of current methods for heavy-oil production. However, the method has problems with low coverage by steam injection and decreased efficiency.
An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. The optimization model presented in the complete paper is the first multioperator offshore network-optimization model that considers decommissioning in the Netherlands. A study was required to determine the origin of the tremor, evaluate if it could be followed by other tremors in the future, and estimate its magnitude. A reservoir-monitoring system has been installed on a medium-heavy-oil onshore field in the context of redevelopment by gravity-assisted steamflood.
A horizontal-steam-injection pilot project has been under way for the last 4 years in the Kern River heavy-oil field in the southern San Joaquin Valley of California. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. The operator has initiated a cyclic-steam-stimulation project in the Opal A diatomite of the Sisquoc formation on the Careaga lease in the Orcutt oil field in Santa Barbara County, California.
This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. The Eagle Ford formation has produced approximately 2 billion bbl of oil during the last 7 years, yet its potential may be even greater. Using improved oil-recovery (IOR) methods could result in billions of additional barrels of production.
The objective of this study was to look at factors that can affect a temperature log and steps that can be taken to improve temperature-measurement accuracy. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. The First Eocene is a multibillion-barrel heavy-oil carbonate reservoir in the Wafra field, located in the Partitioned Zone between Saudi Arabia and Kuwait. After more than 60 years of primary production, expected recovery is low and provides a good target for enhanced-oil-recovery processes.