The EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases.
Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper presents an efficient solution approach for the latter issue.
The approach is based on the construction of quadratic response surface models (surrogates) of reservoir simulator outputs and three-level D-optimal design of experiments. It allows to effectively and efficiently establish the optimum ASP injection scheme, and was applied to determine the optimal values of injection rates, slug size and initial date for injection of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela. The optimum injection scheme resulted in substantial savings in chemicals used when compared to the laboratory design.
After conventional waterflood processes the residual oil in the reservoir remains as a discontinuous phase in the form of oil drops trapped by capillary forces and is likely to be around 70% of the original oil in place1. The EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases2 - 5.
Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process specifying injection rates, slug sizes and initial date for injection, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper studies a solution methodology for the latter issue.
Traditional approaches for the optimization of ASP flooding processes have been limited to a trial and error method or local sensitivity analysis using reservoir numerical simulation6-10, where formal optimization is seldom used because of the computationally expensive objective function evaluations (i.e., numerical reservoir simulator model). The surrogate-based optimization approach has been shown to be useful in the sensitivity analysis and optimization of computationally expensive simulation-based models in the aerospace11-13, automotive14,15, and oil industries16-19. This approach involves the construction of an alternative fast model (surrogate) from numerical simulation data and using it for optimization purposes.
This paper presents an efficient approach for the optimization of field scale ASP flooding processes based on quadratic response surface models (to fit reservoir simulator outputs), and a three-level D-optimal design of experiments used to minimize the number of simulations required to build the cited models. The quadratic response surface model allows the effective and efficient location of the optimum ASP injection scheme using a quadratic programming algorithm. Additionally, the response surface models allow to identify sensitivity information between ASP process performance measures and injection scheme variables.
This optimization approach was applied to determine the optimal injection scheme, in terms of injection rates, slug size and initial date for injection, of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela.
Pizzarelli, Sergio G. (PDVSA E, P & M) | Alter, David (Petroleos de Venezuela S.A.) | Tillero, Edwin (Petroleos de Venezuela S.A.) | Garcia, Jose Luis (Petroleos de Venezuela S.A.) | Leal, Tulio (Schlumberger)
One of old and most important West Venezuelan Oil fields is the LL-03 reservoir which has accumulated more than 1200 MMBN and actually represent the 30% medium oil daily production of Exploitation Unit "La Salina??, Maracaibo District, PDVSA.
This reservoir is characterized for contain 30% of shale with not consolidated sand at low pressure with 450 psi at 3500 feet of depth with interleayer of clay and high permeability with lost of severe circulation risks, in order to develop the reserves of 24° API oil it was designed and execute the secondary recovery project called Fase IV through instrumented horizontal wells into low-pressure zone.
Due the depleted conditions of this reservoir it was begun the search of new alternatives for perforation fluids competitive at technical and economic levels, being one of the main challenges to ensure the success in the construction and completion for extend horizontal wells. After obtained the formulation of the optimal fluid to use it was come to design the directional plan and the mechanical completion for sand control, being considered in addition the use of permanent downhole gauge for pressure and temperature readings, conforming therefore the instrumented well.
The stability of the system, the effectiveness of the saline seal and operational practice allowed the successful perforation of 3 instrumented horizontal wells (2 injectors and 1 producer) with the formulated saline fluid in a horizontal section of 2699 feet average without observe hole instability problems having completed the wells with mesh screen for sand control and permanent downhole gauge for pressure and temperature readings in a concentric string, after removing the filter cake generated by the perforating fluid it was obtained 22 months of continuous and stable production of 900 BNPD results Vs 450 BPPD expected for PB-763 well, opening opportunities for the perforation of 3 wells in similar conditions and it was begun the project for perforation of the first multilateral well in this same reservoir.
The reservoir LL-03 of the Miocene from the Rosa Mediano field after 50 years of production maintains reserves surpluses in the order of the 340 MMBN with pressure levels that oscillate between 300 - 600 psi, reason why the drilling has been associated to the risk of lost of circulation.
In order to increase the area of drainage in wells drilled in the LR-60 sand of this field, it was begun the construction of horizontal wells making an investigation of the fluid to use to maintain the stability of the hole in the whole horizontal section of production during the drilling, selecting water based system of "aphrons?? obtaining excellent operational results allowing the construction and completion of the well, but unsuccessful production level due to the low obtained initial production, reason to perform a chemical treatment for the removal of the damage created by the filter cake generated by perforation fluids obtaining an initial production of 1300 BPD, which was lower than the expected potential.
This field has been put under projects of secondary recovery by water injection to maintain the production present of the reservoir, such has been implanted from year 1979 with the construction of vertical wells, denominated Phase I, the second and third project called Phase II and Phase III with peripheral geometric adjustments of seven inverted points and beginning the injection from year 1985, next to this is made an extension of Phase I in 1999. Later to these advances of secondary recovery it was performed a study of simulation made to the LL-03 reservoir from year 2000, being created a new project of secondary recovery denominated Phase IV, which would have a horizontal well adjustment of extended arm (over 1000 feet of length in the horizontal section of production/injection), expecting to recover 70.48 MMBNP.
In order to obtain the objective of this project it was made an investigation of the type of drilling fluid to use, initiating the study with the obtained experience years back with another system of fluid, the same one was evaluated technically and economically against other systems being very competitive, in addition it had to be of easy removal to satisfy the volumetric success.