In design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability. The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field. Introduction The ASP technology is an enhanced oil recovery method which combines the synergetic effects of three components (alkali, surfactant and polymer) in order to improve the sweep efficiency to oil residual saturation. This effect is achieved with the reduction of the IFT from the injection of surfactants and alkaline solutions which also acts like sacrificing agent to diminish the adsorption of surfactant and polymer into the porous media. The polymer injection lets to increase the viscosity of ASP slug, which is fundamental to improve the volumetric sweep efficiency. There are numerous successful international experiences in the ASP technology application. Particularly, those in US and China fields represent the most emblematic experiences 1, 2, 3. La Salina Field, on the eastern coast of Maracaibo Lake in Venezuela, is ASP pilot project designated contemplating all different and crucial stages of this process: development of the corresponding optimal ASP formulation for LL-03/Phase III reservoir, numerical simulation model and design of an injection plant 4. An estimate of 19.0% was considered as the incremental recovery factor for reservoirs of Miocene with the injection of ASP according to previous studies to optimal ASP formulation. The area of Phase III has been subject to water injection project since 1987. The injection has been carried on by inverted seven spot well patterns. The ASP injection project contemplates to implant the technology in three arrangements initially. The subject tests development in this study corresponds to the first arrangement, where is located the well PB-734. The type of arrangement is a triangular form with a separation between wells of 150 mts aproximately. In the center of the triangle, a well injector of ASP and one observer are located. All these wells were completed with sensors of pressure and temperature of bottom. Figure 1 shows the area of study into the Phase III and the Table 1 lists the reservoir typical characteristics of the LL-03, La Salina.

fax 01-972-952-9435. AbstractIn design and implementation of Alkali Surfactant Polymer (ASP) formulation for IOR processes, the inorganic alkali component acts as sacrificing agent avoiding the surfactant adsorption and decreasing the IFT. Nevertheless, as a part of this process there are some potential problems to be considered previously and during ASP injection processes such as: the ASP injection water should be softened to prevent scale formation that produces higher costs for water treatment, possible tubing corrosion problems and possible viscosity reduction. The effect of organic alkali on IFT, adsorption and viscosity has been previously focussed on comparing to the conventional inorganic alkali in these formulations. In those investigations, it was founded that organic alkalis are compatible with unsoftened waters and the rest of ASP slug components, reduce adsorption, minimize the surface equipment and the formation damage what reduces initial investment costs and greater project profitability.The objective of this study is to show the advantages and outcomes in applying an improved design of the current ASP formulation for the pilot project La Salina Field Maracaibo Lake, using an organic compound-surfactant-polymer (OCSP) formulation, which uses an organic compound as substitute for traditional inorganic alkali. In fact, fluid-fluid and rock-fluid compatibility laboratory tests, new chemical components concentrations, phase behavior study, IFT screening and porous media evaluations (adsorption and recovery factors) were performed in laboratory in berea cores. Linear corefloods displacements for La Salina LL-03 let to obtain the OCSP flood recovery and additional OOIP estimated of 22.2%. Finally, these results confirm the technical advantages of applying an optimized formulation using an organic agent for this field.

Pursuing new alternatives to develop and produce sands B1 and B4 together, belonging to the reservoir VLG-3729 of Moporo Field located in western Venezuela, different exploitation schemes were evaluated, where intelligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well oil production, avoiding cross-flow, minimizing operational risks and well interventions(coil-tubing operations), leading to better reservoir management. To evaluate the intelligent completion technology, an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first section involves the reservoir model using a reservoir simulator, which includes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump, ESP) through a network simulator. Both sections were coupled taking an intermediate point between the ESP and ICVs as a coupled node. The differences using a stand alone model and a coupled model were analyzed. Given that in both models the main constraints are handled in different ways, the calculated liquid production trend is different for each model. The stand alone model is constrained by maximum liquid rate and minimum bottom hole pressure (BHP), while the BHP constraints on the coupled model is calculated dynamically by the production system. In this case, the stand alone reservoir model leads to an optimistic production profile. These results show the advantage in the use of an IAM, taking into account the network constraints to obtain more accurate results. To evaluate the performance of the smart well, several sensitivities to the coupled model were made, changing the opening valves position at the beginning of the forecast. An increment in the cumulative oil production was observed when the cross flow between sands were not allowed. Introduction The VLG-3729 Moporo field is located between Zulia and Trujillo states (Western of Venezuela). It was discovered in 1988 by an advanced well (VLG-3729) from a neighbor reservoir. See Fig. 1. Six regions are defined by two primary faults and several secondary faults, which have compartmentalized the field. The depths vary from 15000 and 17000 ft, initial pressure of 7500 psi, net thickness from 400 to 500 ft, porosity from 10 to 15% and effective permeability from 50 to 500 md. It represents the most prolific and potential field from Maracaibo Basin. Moporo field has a cumulative production at 320 MMSTB under natural depletion with reservoir temperatures range from 280 to 300 °F and 22 °API approximately. The field development currently consists of 96 wells (88 active, 5 inactive and 3 abandoned wells), which produce from two separated reservoirs: B-1 and B-4. B1 sand is under initial conditions with a 3500 STB/d as estimated potential, whereas B4 sand accounts 90% of total production with an initial production from 6000 STB/d. The driven mechanism has been identified as solution gas and water drive.