The Role of Capillary-Pressure in Improving the Numerical Simulation of Multi-Phase Flow in Porous Media

The oil recovery factor from oil reservoirs must be increased significantly to meet the ever-increasing demand for energy. Majority of oil reserves worldwide (estimated as 60%) are held in carbonate reservoirs. It is believed that most carbonate reservoirs are mixed-wet to oil wet with high variation in wettability within the reservoir rock. Water-Alternating-Gas (WAG) injection is one of the most applicable EOR techniques known to increase oil recovery factor by 8-20% on top of waterflood alone. To maximize recovery from carbonate reservoirs, numerical simulation is the best available tool to aid with such objective. In this paper, we are presenting a new approach to simulate near-miscible water- alternating-gas injection for mixed-wet reservoirs. The coreflood experiment used in this study was performed on a 65mD mixed-wet sandstone core sample at 38°C (100°F) and 12.69 MPa (1840 psia) where calculated Interfacial tension (IFT) between gas and oil at these conditions is 0.04 mN/m. As recorded in the literature, the current simulation capabilities to model WAG injection behaviour is questionable. Some authors suggested that Land’s gas trapping parameter [C] should be variable during the WAG injection process. In this study, we investigated the best way to match the results of WAG injection experiments performed on a mixed-wet core. Matching the full experimental results were not possible without varying gas trapping parameter [C]. However, by updating the gas trapping parameter, based on our suggested procedure, the match between the simulation results and experimental data improved significantly. This paper highlights the shortcomings of the commercial simulators in modelling WAG injection process. The current WAG hysteresis model can be improved based on the information published in this paper for better WAG injection simulation.

show abstract

Practical Chemical Formulation Design – Time to Break Away from Micellar Polymer Floods, Again

Dean¹,

Pitts²,

Wyatt³

et al. 2020

SPE Improved Oil Recovery Conference

View full text Add to dashboard Cite

With a resurgence of chemical EOR opportunities throughout the world, high concentration surfactant design has re-emerged its uneconomic face. High concentration surfactant formulation is the micellar polymer design from the past that produced high oil recoveries in the lab but were uneconomic in the field. Formulation designs must consider factors beyond simply oil recovery for economic success and to minimize production issues in the field. Analysis and comparison of micellar polymer design projects from the 1970-1980s to current SP/ASP formulation designs are discussed. A simple formulation cost calculator is showcased, costs of all formulations are presented, and price per incremental barrel produced (chemical cost only) are shown assuming a 0.1 PV of incremental recovery. Analysis concludes the following: Micellar polymer floods were phased out because they were uneconomic. Key reasons are high cost of surfactant and emulsion problems faced when produced surfactant concentration exceed a certain threshold resulting in either greater production cost or disposal of produced oil in the form an unbreakable emulsion. Alkali can improve economics as a low-cost commodity product that can be used to reduce surfactant concentration required to attain high oil recoveries. Alkali is an order of magnitude lower cost per pound than the typical surfactant and can be used as an enhancing agent to improve the performance of other injected chemicals. Alkali is not a "silver bullet" that will save economics, and adds challenges and cost for water softening, which can be economically detrimental to field projects. Many high concentration surfactant formulation floods are being re-introduced to the industry. Not only are these designs un-economic but include multiple chemicals that add complexity and cost to the facilities and difficulty for facility personnel. A formulation that requires more than $20 of chemical per barrel of incremental oil is unlikely to be economic with $50/bbl oil. Key differences between laboratory results and field implementation results are discussed. Geologic uncertainty is addressed since it is the greatest challenge to field economic success. The industry is taking steps back to an uneconomic time of chemical EOR by obscuring the difference between designs meant to increase reserves (economic oil) versus those that serve an academic or research purpose. Operators are unwittingly paying the price to advance the science of chemical EOR when service companies provide formulations that are not economic. This paper is meant to remind the industry that high concentration surfactant formulations never were economic and certainly will not be economic in today's price environment.

show abstract

The Role of Capillary-Pressure in Improving the Numerical Simulation of Multi-Phase Flow in Porous Media

Cited by 3 publications

References 8 publications

Multi-period Optimization for Long-Term Oilfield Production Planning

Multi-period Optimization for Long-Term Oilfield Production Planning

A New Approach to Simulate Near-Miscible Water-Alternating-Gas Injection for Mixed-Wet Reservoirs

Practical Chemical Formulation Design – Time to Break Away from Micellar Polymer Floods, Again

Contact Info

Product

Resources

About