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Collaborating Authors
North America
Polymer Selection for Sandstone Reservoirs Using Heterogeneous Micromodels, Field Flow Fractionation and Corefloods
Borovina, Ante (OMV Exploration & Production GmbH) | Reina, Rafael E. Hincapie (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH) | Hoffmann, Eugen (HOT Microfluidics GmbH) | Wegner, Jonas (HOT Microfluidics GmbH) | Steindl, Johannes (OMV Exploration & Production GmbH)
Abstract Incremental oil recovery due to polymer flooding results from acceleration of oil production along flow paths and improving sweep efficiency. To achieve favorable economics, polymers should have a high viscosifying power and low adsorption. However, in addition, incremental oil production from various rock qualities needs to be maximized. We developed a workflow using a layered micromodel, corefloods and Field-Flow Fractionation (FFF) to determine the Molecular Weight Distribution (MWD) for the selection of polymers addressing heterogeneous reservoirs. We have designed micromodels consisting of two layers with different permeabilities, one four times larger than the other. The micromodel structure is based on the characteristics of a real sandstone core, with the dimensions 6 cm × 2 cm. These micromodels were used as preliminary screening of the polymers incorporating heterogeneity effects. Subsequently, single- and two-phase core experiments were performed to determine injectivity effects and displacement efficiency of the selected polymers. In addition, FFF was used to measure the molecular weight distribution, gyration radii and conformance of the polymers. Based on the workflow a polymer was selected. All polymers were tested at target viscosity at 7 1/s shear rate. Micromodel experiments showed that tested polymers are leading to improved sweep efficiency of heterogeneous structure. The displacement efficiency within the higher permeable layer was similar for the investigated polymers whereas the oil recovery from the lower permeable layer showed differences. FFF revealed that the MWD's of the tested polymers were different. The MWD of one of the polymers showed a large number of larger molecules compared with the other polymers. This polymer did not lead to the highest oil recovery in the micromodel. Injectivity and propagation of the higher MW polymer in both single- and two-phase core-floods was falling behind the other polymers. Measurements of the MWD of the core effluent showed that for all tested polymers the larger molecules are initially retained more than the smaller molecules. The polymer with the smallest molecules and narrow MWD showed the best propagation characteristics in the core. Owing to the good performance of this polymer in terms of sweep efficiency improvement, injectivity, and propagation, this polymer was selected for a field application. Therefore, the novelty presented here can be summarised as follow: Heterogeneous micromodels were used to screen polymers for one-dimensional displacement efficiency and sweep efficiency effects Single- and two-phase core floods in combination with Field-Flow Fractionation revealed the impact of the molecular weight distribution (MWD) on polymer injectivity, propagation and retention Selection of polymers need to include MWD to find the most effective polymer Polymer selection needs to take near-wellbore and reservoir effects (micro- and sweep efficiency in heterogeneous reservoirs) into account
- Europe (1.00)
- Asia (1.00)
- North America > United States > California (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (3 more...)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Measurement while drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Abstract Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model. By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection. Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
- Europe (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (37 more...)
Abstract 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.
- Asia > Middle East (1.00)
- South America (0.93)
- Africa (0.93)
- (3 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (30 more...)
Abstract 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.
- Europe > Austria (0.83)
- North America > Mexico (0.68)
- Asia > Middle East (0.68)
- (2 more...)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)