Read the case study to see how deeper chemistry insight helps resolve complex corrosion challenges and improve upstream performance.
Upstream Chemistry. Quantified.
Reservoir fluids evolve as pressure and temperature change from formation to surface. OLI models electrolyte and hydrocarbon behavior, phase partitioning, and mineral solubility to support production decisions grounded in thermodynamics.
Understanding Fluid Chemistry in Upstream Assets
Upstream asset performance and production efficiency depend on understanding how complex fluids behave as conditions change from reservoir to surface. Scaling, corrosion, and fluid compatibility are governed by fluid chemistry. OLI simulation tools quantify these risks before they impact production.
Trusted in Upstream Production Environments
OLI technology supports upstream operators and engineering teams who require detailed scaling and corrosion chemistry evaluation for well design, flow assurance, and integrity management. Our solutions support drilling, production and operations, and decommissioning activities in both onshore and offshore environments, across conventional and unconventional plays.
Managing Upstream Risk Through Chemistry
Electrolyte modeling captures real reservoir fluids and evolving production conditions so upstream decisions reflect the true chemistry of reservoir fluids.
Stream
Define reservoir and surface compositions using data from lab and field analysis. Simulate multiphase electrolyte and hydrocarbon behavior across changing pressure and temperature conditions to ensure production models reflect actual fluid chemistry.
Corrosion
Quantify corrosion risk through accurate prediction of species speciation and pH under produced fluid conditions. Evaluate material compatibility and the effects of acid gases, chlorides, and other aggressive species across upstream operating envelopes.
Scale
Predict mineral precipitation in oil and gas wells and production facilities, including high temperature and high-pressure systems. Assess scaling tendency as temperature and pressure change and composition evolves during production.
Process
Model the full production workflow from wellhead through surface processing (gas separation, chemical injection) to reinjection, using thermodynamic frameworks that capture reactive equilibria.
Water
Simulate produced water composition to evaluate treatment performance and reinjection compatibility under defined operating constraints.
Automation
Deploy validated chemistry models within surveillance environments to support near real-time assessment of scaling and corrosion risk.
Stream
Define reservoir and surface compositions using data from lab and field analysis. Simulate multiphase electrolyte and hydrocarbon behavior across changing pressure and temperature conditions to ensure production models reflect actual fluid chemistry.
Corrosion
Quantify corrosion risk through accurate prediction of species speciation and pH under produced fluid conditions. Evaluate material compatibility and the effects of acid gases, chlorides, and other aggressive species across upstream operating envelopes.
Scale
Predict mineral precipitation in oil and gas wells and production facilities, including high temperature and high-pressure systems. Assess scaling tendency as temperature and pressure change and composition evolves during production.
Process
Model the full production workflow from wellhead through surface processing (gas separation, chemical injection) to reinjection, using thermodynamic frameworks that capture reactive equilibria.
Water
Simulate produced water composition to evaluate treatment performance and reinjection compatibility under defined operating constraints.
Automation
Deploy validated chemistry models within surveillance environments to support near real-time assessment of scaling and corrosion risk.
Upstream chemistry is often evaluated using safety margins that mask the underlying mechanisms. Accurate chemistry modeling provides clarity on where risk originates, how it evolves and how it can be most effectively mitigated.
Ali Eslamimanesh
R&D Director of Corrosion
Understanding OLI’s Modeling Approach
Clear answers to common technical questions about reservoir fluid modeling and how OLI’s thermodynamic framework supports upstream operating decisions.
OLI uses electrolyte thermodynamic models calibrated for concentrated brines and complex hydrocarbon systems. Simulations account for pressure dependent phase equilibria and ionic interactions relevant to upstream environments. The model is built on the most comprehensive thermodynamic database available in the industry, covering high-pressure, high-temperature, and high-salinity conditions.
Yes. The platform evaluates mineral scale formation as temperature and pressure change along the production path, enabling assessment of precipitation risk before field intervention. This includes the impact of artificial lift such as ESPs and gas lift.
Corrosion risk is quantified based on bulk fluid chemistry, including pH, acid gas partitioning (CO₂ and H₂S), and the presence of aggressive species (e.g. Chlorides) that drive corrosion. This enables chemistry-driven material selection and corrosion mitigation planning.
Through rigorous chemical modeling, OLI predicts H₂S partitioning throughout the system and calculates its concentration in both aqueous and hydrocarbon phases, as well as the resulting H₂S partial pressure (and fugacity). OLI’s corrosion model then uses these accurate in-situ compositions to predict corrosion rates along the system and over time as H₂S concentrations change.
Validated chemistry models can be deployed within digital environments to support ongoing assessment of scaling and corrosion risk as operating data changes.
CASE STUDY
Resolving upstream corrosion with rigorous water chemistry simulation
Corrosion in upstream operations continues to drive equipment failure, production loss, and rising costs. In the Bakken oil fields, Creedence Energy faced repeated tubing failures caused by a complex mix of heat, fluids, and unexpected chemical interactions that could not be fully explained through conventional assumptions. Through detailed chemistry analysis, the team identified oxygen-induced corrosion as a key driver and refined their treatment strategy. This led to a sharp reduction in tubing replacements, extended asset life, and improved reliability across multiple wells.
Quantify Upstream Chemistry. Reduce Production Risk.
Production decisions rely on how fluids behave as conditions shift from reservoir to surface. OLI models the underlying chemistry so scaling, corrosion, and compatibility risks are defined before they affect operations. Replace assumptions with thermodynamic insight grounded in real fluid behavior. Understand where risk originates, how it develops, and how it can be managed across the full production workflow. Share your operating conditions to explore how this approach applies to your assets.