Summary Polymer flooding of oil fields has not reached the same maturity as waterflooding. Hence, implementing polymer projects at field scale requires a workflow comprising several steps. The workflow starts with screening of the portfolio of an organization for oil fields potentially amenable for this enhanced-oil-recovery (EOR) method. Next, laboratory and field testing is required, followed by sector and field implementation and finally rollout in the portfolio. Going through the workflow, not only is the subsurface uncertainty reduced, but also the knowledge regarding the cost structure and operating capabilities of the organization is improved. Analyzing the economics of polymer-injection projects shows that costs can be split into costs dependent on the polymer injector/producer (polymer pattern) and costs that are independent. Knowing these costs, a minimum economic number of patterns (MENP) is defined to achieve net present value (NPV) of zero. This number is used to determine a minimum economic field size (MEFS) for polymer injection, which is taken into account in the screening of the portfolio. A robustness criterion for economic-evaluation purposes is defined as the minimum number of patterns required for economic polymer injection. By use of this criterion, a diagram is derived allowing for screening of fields for polymer economics by use of pattern-dependent and pattern-independent costs and the utility factor (UF). The cost structure reveals how the NPV of polymer projects changes with the number of patterns, incremental oil, and injectivity. Injectivity is particularly important because it determines the chemical-affected reservoir volume (CARV) or speed of production. A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer-injection project.

Summary A polymer pilot in the 8th Torton Horizon (8 TH) Reservoir in Austria showed promising results. The utility factors were 1.8 kg of polymer injected per incremental bbl of oil produced (polymer costs are EUR 1.74 to 3.48/kg). Furthermore, substantial incremental oil was produced, which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding. To optimize the economics of field implementation, a work flow was chosen ensuring that known uncertainties were covered. There were 1,200 geological models generated that cover a variety of different geological concepts. These geological models were clustered according to their dynamic response into 100 representative geological realizations, and then used for history matching. To screen areas of the reservoir that might benefit from polymer injection, probabilistic incremental net-present-value (NPV) maps were generated. Next, the well configuration was investigated using horizontal or vertical wells and the well distances. Afterward, operational parameters, polymer concentration, and duration of polymer injection were optimized for NPV. Finally, full-field simulation was performed to determine the cumulative distribution function (CDF) of incremental NPV. Applying the work flow to the 8 TH Reservoir in Austria led to the following results: Some areas of the reservoir were excluded from polymer injection because the P50 NPV map showed poor economics. Horizontal wells might lead to injection under matrix conditions, whereas vertical wells lead to injection under fracturing conditions for the conditions of the 8 TH Reservoir. In particular, the near-wellbore polymer rheology has a meaningful effect on injectivity. The NPV per reservoir area is higher for horizontal wells (EUR 43/m2) than for vertical wells (EUR 30/m2) because of the well cost vs. incremental recovery differences of the two configurations. The optimal well distance of the horizontal wells in the 8 TH Reservoir is 200 m for operational reasons. As operating parameters, a polymer concentration of 2,000 ppm and 8 years of injection were chosen to maximize NPV. The resulting CDF of incremental NPV showed a probability of economic success of 91% and an expected monetary value of EUR 73 million.

A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding. To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching. For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns. The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters. The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.

As polymer injection has not reached the same maturity as waterflooding, implementing polymer injection projects at field scale requires a workflow comprising screening of the portfolio of an organization for oil fields potentially amenable for polymer injection, laboratory and field testing followed by sector- and field implementation and roll-out in the portfolio. Going through the workflow, not only the subsurface uncertainty is reduced but also the knowledge about the cost structure and operating capabilities of the organization improved. Analyzing the economics of polymer injection projects shows that costs can be split into polymer injector-producer (polymer pattern) dependent and independent costs. Knowing these costs, a Minimum Economic Number of Patterns (MENP) is defined to achieve Net Present Value zero. This number is used to determine a Minimum Economic Field Size (MEFS) for polymer injection which is taken into account in the screening of the portfolio. Defining a robustness criterion for economics, the minimum number of patterns for polymer injection meeting this criterion is calculated. This criterion is applied to generate a diagram allowing for screening of fields for polymer economics using pattern dependent and pattern independent costs and Utility Factor. The cost structure reveals how the NPV of polymer projects changes with number of patterns, incremental oil and injectivity. Injectivity is of particular importance as it determines the Chemical Affected Reservoir Volume (CARV) or speed of production. A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer injection project.

OMV Austria E&P GmbH operates 26 oil fields in Lower Austria. The majority was developed in the 1950s and 1960s and shows an extended decline period. The challenge of operating brown fields is seen to maintain a reasonable oil production over time in a cost effective manner - this can be tackled by a major chemical enhanced oil recovery field redevelopment project. The scope of the polymer field rollout is to create and efficiently operate horizontal polymer injection patterns in two horizons in Lower Austria. OMV follows the strategy to pilot new reservoir and production technologies before their application in field rollouts. Due to the large project investment volume it is crucial to derive information and lessons learned from existing pilot patterns to optimize conceptual decisions on artificial lift, completion, sand control and injection strategy and to reduce technical risk. In the past 10 years several vertical pilot patterns were created to analyze the efficacy of polymer injection in the Tortonian Horizon. Significant operational experience in water treatment, polymer injection and polymer back production, but also in tracer testing was established. Since already the vertical polymer patterns showed not only operational success, but also significant incremental oil production, the idea of horizontal flooding patterns was born. To confirm and understand the impact of polymer injection also in horizontal wells, a first horizontal pilot pattern was drilled; additional pilot wells are currently following. For a future field redevelopment the technology selection should be de facto based on either standard or pilot-proven technologies. This paper describes measures undertaken in the discipline of production technology to prepare for one of the largest field redevelopment projects in the history of OMV Austria. These measures include the application of several pilot projects in the field of artificial lift, completion design and sand control, production and injection allocation. Therewith production technology serves the needs for active reservoir management and thus, follows a holistic field development approach.