Tabary, Rene (IFP Energies Nouvelles) | Douarche, Frederic (IFP Energies Nouvelles) | Bazin, Brigitte (IFP Energies Nouvelles) | Lemouzy, Pierre Maxime (Beicip-Franlab) | Moreau, Patrick (Rhodia) | Morvan, Mikel (Rhodia)
Bramberge reservoir is a low temperature (40°C), high permeability (~1 Darcy) sandstone reservoir located in Germany. Waterflooded during several decades, oil production has been declining for the past few years. These conditions make this reservoir a good candidate for surfactant-polymer flooding.
Despite favourable attributes, the use of production brine, which exhibits very high hardness, as a re-injection fluid makes this project challenging and unique.
In this paper, we illustrate how this specific hurdle can be managed using a new strategy specifically developed for hard brines.
We show that surfactant/polymer formulations can be optimized in Bramberge re-injection brine despite its hardness with adequate properties for SP flooding (ultra-low interfacial tension and good solubility). The high level of divalent ions, and especially calcium ions, makes alkalis irrelevant for this project. We demonstrate using coreflood experiments that conventional injection strategies, successfully applied in soft brines (salinity gradient, etc…), and brine management options fail in these specific conditions because of the high chemicals adsorption. This high adsorption is showed to be strongly related to divalent ions.
We finally propose a successful alternative based on a careful selection of adsorption inhibitors. Using these additives, high oil recovery (94 %OOIP) was obtained together with low anionic surfactant and polymer adsorption. The overall technical performance is in line with conventional alkali-surfactant-polymer strategy in soft brine making this project very attractive and promising.
The process is currently in an optimization phase for pilot and field scale simulations allowing technical and economical optimization.
After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency - so that one can recover some of this remaining capillary-trapped or water-by-passed oil -, it is necessary to screen enhanced oil recovery (EOR) techniques and to apply processes such as surfactant flooding, either Surfactant (S), Surfactant Polymer (SP) or Alkaline Surfactant Polymer (ASP), when recommended.
This paper describes an advanced methodology to select EOR surfactant based processes with special emphasis on the design of a formulation by considering real brine compositions. Salinity is the major parameter for the design of an efficient surfactant process. Salinity is defined by running reservoir numerical simulations with SARIPCH, a black oil simulator for chemical tertiary recovery. Inputs are formation water salinity and composition of waterflood brine. Strong heterogeneity of flow properties and resisual oil zones as well as reservoir geometry, for example crossflow, are considered. Results help to define the effective salinity and the salinity window for the surfactant formulation design.
Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted in order to take into account the potential efficiency and the economics of the process. Core flood experiments are performed to validate performances of selected
chemical formulation(s). Conclusions are drawn on the key effect of salinity and on the necessity of adopting a methodology giving a first appraisal of the salinity that will be seen by the surfactant slug during its transport.
After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency - so that one can recover some of this remaining capillary-trapped or water-by-passed oil -, it is necessary to apply enhanced oil recovery (EOR) techniques such as surfactant flooding, either Surfactant (S), Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP).
This paper describes a complete workflow for optimizing S, SP or ASP processes for chemical EOR. The workflow consists in successive steps: reservoir fluid and rock characterizations, formulation screening, core flood validation and simulation including sensitivity studies.
Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Objective of the formulation platform is to provide a robust formulation adapted to the variability of the reservoir conditions (temperature and salinity windows, oil composition). Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted for the selection of the best formulations. Core flood experiments are performed to validate performances of selected chemical formulation(s) and define simulation input data. IFT measurements, adsorption data, capillary desaturation curves, and diphasic water-oil relative permeabilities are further used as input for simulations. A chemical EOR simulator (SaripCH software), specifically designed for ASP processes design, has been developed. After the lab study, pilot design is the next step towards the application of the S, SP or ASP process in the field. SaripCH simulator is used to evaluate the performances of the process at the reservoir scale.