Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.

This paper deals with the learning curve of a 5+ years polymer flooding pilot conducted in a mature water-flood that includes several works related to injector and producer wells, reservoir management, etc. The scope of this paper is to describe the learning curve during the last five years rather than the reservoir response of the polymer flooding technique; focus is on the aspects related to reduce cost per incremental oil barrel for a possible extension to other waterflooded areas of the field.Diadema Oil Field is located in the San Jorge Gulf Basin in the Southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil producer company; it has 480 producer and 270 injector wells. The company has been developing waterflooding during more than 18 years (today this technique represents 82% of oil production in the field) and produces about 1,600 m3/d of oil and 40,000 m3/d of gross production (96% water cut) with 38,400 m3/d of water injection.The reservoir being polymer-flooded is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very stratified sand-stone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin) and 20 °API oil (100 cp at reservoir conditions).Diadema's Polymer Flooding Pilot started in October 2007 on 5 water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made using produced water (15000 ppm brine) and 1500 ppm of HPAM polymer reaching 15/20 cp of fluid injection viscosity.Oil rate production from the original "central" producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is about 15%.The main aspects presented in this work are: depth profile modification with cross-linked gel injected along with polymer, use of "curlers" to regulate injection in multiple wells with one injection pump without shearing the polymer and an improved technology on producer wells with PCP to decrease shutting time and number of pulling interventions.The plan for the next years is to extend this project to other areas by using the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation, among them. These improvements will allow the company to reduce operative cost per incremental oil barrel.

Polymer-flood projects with selective polymer injection in different reservoirs within the same injector well has never been a simple task, but it can be achieved. This work explains how. During secondary recovery in several reservoirs (contacted by vertical wells), selective installation at injector wells enables vertical distribution wherever convenient (i.e: reservoirs with a high oil saturation, lower injected poral volumes); such distribution in Polymer-flood projects was not possible since some reservoirs were not completely or effectively swept. A new deep well selective injection system has been developed to be used in multiple reservoirs while preserving viscosity of the polymer solution without mechanical degradation. Thus, injection is increased in those reservoirs with hydrocarbon potential with a low admission of polymer or no admission at all. This device is installed in the well bottom (patent still pending) and has side-pocket mandrels with valves operated by the conventional Slick Line rig. Through the different positions of these valves, the desired flow in each reservoir can be achieved. We are going to introduce the work developed in lab and field pilot in order to prove this development is technically feasible. Different tests have been performed in test benches designed to that purpose, the equipment was manufactured and this new tool was installed in some injector wells. The tool was installed in two polymer injector wells. Reservoirs tests had been previously performed to evaluate injectivity, mainly to dismiss problems (high pressure, skin factor or lack of continuity in the reservoirs). Afterwards, valve combination to achieve target injection rate in each reservoir was defined. This pilot experience was held with a service company in the polymer project located in the Diadema field in the San Jorge Gulf Basin Argentina. The field is operated by CAPSA, an Argentine oil operator with 480 producers and 270 injector wells The reservoir flooded with polymer is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very layered sand layers (4 to 12 m net thickness), poorlateral continuity (fluvial origin) and oil of 20° API (100 cp at reservoir conditions). The permeability and reservoir pressure in the reservoirs led us to develop a system with a selective admission and no polymer degradation. The Polymer flooding in Diadema started in October 2007 using 5 injectors (it nowadays includes 35 injectors) with an injection rate of 1000 m3d (it is 3300 m3d today). Polymer solution used produced water (16000 ppm TDS brine) and 2500 ppm of HPAM (22 MDa average molecular weight) reaching to 70 cp of average viscosity of fluid injection. This device enables a regulated polymer solution admission into those reservoirs where it was scarce or inexistent, thus improving injected pore volumes, increasing RF, an economic return, and resulting in the massification of the polymer-flood project.