Successfully implementing polymer flooding and maximizing benefits requires selecting best options of variables such as polymer concentration and slug, and number and location of new wells. Option-decisions combined generate thousands of scenarios. Therefore, even using smart algorithm optimizers to efficiently find the maximum of a business objective mathematical function can be a very time-consuming process. The objective of this article is to demonstrate a methodology to improve the chances of finding the maximum net present value (NPV) solution for planning an offshore polymer-flooding; this includes finding, for example, the minimum injection volume to more easily offshore operations. The reservoir and economy models included here were automatically coupled with software that encloses a smart numerical algorithm for searching complex maximum/minimum functions. The options of the previously mentioned decision variables were selected to maximize the NPV of the inverted five-spot polymer-flooding project under constrained rig availability. The process was conducted in three stages: Stage 1: potential value estimation Stage 2: narrowing options through deterministic numerical simulation Stage 3: A) numerical optimization of all decision variable options except the drilling sequence; B) numerical optimization of the drilling sequence   A total of 379 scenarios were numerically forecasted in just a few months. The best scenario showed three times the NPV of the nonflooding case. Compared to the reference water-flooding scenario (i.e., all the same options but with the fluid injected), the NPV was 1.3 times greater, the water-oil ratio (WOR) was 0.45 times lower, and Np was 1.25 times greater. Unobvious scenarios, such as reducing the yearly drilling rig availability but extending drilling by four years, were revealed. A comparison of the working time for Stage 2 with Stages 3A and 3B showed that the numerical optimization is six times faster per scenario generated. This study demonstrates that the use of numerical algorithms of polymer flooding yields a significant incremental value over traditional deterministic simulations in a much shorter time frame and with fewer costs compared to previous steps related to building a reservoir model. It is expected to be applicable to all types of enhanced oil recovery (EOR) processes.

The Lower Lagunillas-03 reservoir, in Maracaibo Lake, Venezuela, has been producing for more than 80 years from La Rosa (25 API gravity) and Lower Lagunillas (19 API gravity) formations. The average pressure is less than a 1/3 of its oil bubble point pressure; whereas more than 70% of the OOIP remains in place. Several waterflooding projects (Modules) with different injection patterns have been implemented since last 40 years, which have shown different results in term of production behavior and oil recovery. Therefore, an optimal waterflooding scheme has not been identified yet for the fifth waterflooding module (Lower Lagunillas Formation) and also for future waterflooding modules to be implemented for revitalizing the potential of this mature reservoir. It is essential in this case to ascertain the objective of an optimal waterflooding scheme in order to unlock the promissory oil recovery potential considering current reservoir conditions and financial resources. This was accomplished based on an innovative hypotetico-deductive method, which considers cycles of formulation-testing-analysis-emerging of hypotheses (scenarios), and starts with the formulation of a simple or relevant hypothesis (expectation) about a feasible exploitation plan. It is tested using a numerical or analytical model campaigned with economical optimization workflow and its results inquires to evaluate the hypothesis in the light of initial expectations as discarded or chosen, or whether some emerging hypotheses might be conducted and others might not. In turn, they are cycled until analysis of prediction determines probity of hypotheses or the refined research of hypotheses is stopped. Contrary to initial expectations, many hypotheses about waterflooding patterns for the fifth module were tested, such as new horizontal injector-producer wells (direct line drive), inverted seven-spot, and inverted five-spot from existing wells. Nevertheless a substantially increased Net Present Value (2 times greater compared to Base Case) was reached by testing inverted five-spot patterns using infill drilling and extending the area to be flooded so that it emerges as a novel strategy for unlock the potential of this mature reservoir.