The Golfo San Jorge (GSJ) is located in the southern Argentina provinces of Santa Cruz and Chubut. This hydrocarbon basin occupies a surface area of approximately 170,000 km2, approximately 1/3 of which is offshore. Waterflood oil recovery in many GSJ reservoirs does not exceed 10% OOIP due to the combined effects of reservoir heterogeneity and, in many fields, an adverse mobility ratio. The most significant hydrocarbon accumulations of the basin occur in a series of fluvial and shallow lacustrine reservoirs with significant tuffaceous content. A typical GSJ hydrocarbon reservoir includes a series of relatively thin sandstone packages that are not believed to be naturally fractured. In an effort to distribute water injection more uniformly, most injection wells are equipped with injection mandrels. However, heterogeneity within the productive layers limits the effectiveness of near wellbore selective injection. A recent field pilot combining two types of gel technologies in the Comodoro Rivadavia Formation, one of the most prolific GSJ reservoirs, is encouraging. Based on tracer studies, historical production data and reservoir characterization, approximately 15,000 barrels of MarcitSM gels were injected in each of two adjacent injection wells. Seven months after the Marcit gel treatments, the operator began a colloidal dispersion gel (CDG) pilot in the same two patterns, injecting a total CDG pore volume of approximately 18% in certain layers of the Comodoro Rivadavia Formation. A chemical injection plant was connected at a point upstream of the two injectors so that both wells could be treated simultaneously, with the flexibility to vary the rate and polymer gel concentration in each well. A discussion of the reservoir characterization will be presented as well as the chemical treatment designs, subsequent modifications in the course of the pilot, and recommendations. Introduction Reservoir heterogeneity is the biggest challenge to oil recovery in waterfloods. Heterogenity is essentially any nonuniformity in the productive reservoir, including, but not limited to variablilty in permeability and porosity, anisotrophy, fractures, faults and compartmentalization. Anyone who has studied the classic theories of Buckley and Leverett (1942), Stiles (1949), and Dyktra-Parsons (1950) among others appreciates the dramatic effect of heterogeneity on ultimate oil recovery. In the GSJ of Argentina, injection wells are typically completed with downhole selective injection installations (mandrels) designed to improve vertical distribution of water injection. However, near wellbore mechanical configurations do not address in-depth reservoir heterogeneities. Polymer gels are designed to reduce the effects of reservoir heterogeneity beyond the near wellbore area. The basic premise of any gel technology is that the pre-gel solution, or gelant, will preferentially enter high permeability anomalies responsible for low volumetric sweep efficiency. The theory is that once the gels reduce the flow capacity in the "thief zones", areal and vertical sweep efficiency will be improved. This project describes the pilot area evaluation, gel design and field implementation of two polymer gel technologies: Marcit gels (Sydansk 1938) and colloidal dispersion gels (CDG) (Mack 1994). Marcit gels are high polymer concentration gels designed for application in reservoirs with extreme heterogeneities such as natural or induced fractures, fissures and other multi-darcy permeability anomalies. CDG's are typically large volume, low polymer concentration gels designed to improve sweep efficiency in unfractured matrix reservoirs that exhibit poor waterflood performance. Many waterfloods exhibit both types of heterogeneities.
The San Jorge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undesired effects such as uncontrollable height growth, significant proppant pack damage, lengthy clean up times and high friction pressures. In recent times, polymer-free viscoelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Nevertheless, VES were known up to now, for their limitation to withstand elevated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits of even this HT fluid, simulations indicated that a series of cool-down brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into water - or non - productive zones, resulting in reduced fluid and proppant volumes. Field implementation proved also to be successful in terms of operational simplicity, reduced clean up time and consequently work over rig cost savings. Overall, the use of polymer-free fluids improved well productivity. Design, laboratory studies, temperature simulations confirmed by downhole measurements, field implementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range of permeability and temperatures. Introduction The oil producing sands of the San Jorge Basin store important hydrocarbon reserves, covering an extensive area across South Argentina. The basin-fill was by fluvial deposition during the Cretaceous period. Wells are typically vertical and penetrate several thin laminated layers, of thickness ranging between one to eight meters. (Figs. 1 and 2) Furthermore, imprecise clay volume determination, uncertainty in the lithology, rock texture, structure and formation damage, are all aspects that represent a major challange in managing reservoirs in the San Jorge Gulf Basin. To make matters worse, the low well productivity offers operators only a marginal return on their investments. In an effort to increase productivity, the hydraulic fracturing technique has been adopted since many years, being in most cases the only method of achieving commercial production levels. A typical San Jorge Gulf Basin well has an interval of interest located between 800 to 1200 meters, with dozens of sand beds ranging from one to four, five or eight meters thick, many of them strongly laminated 1. This productive intervals were formed during the Cretaceous period, and is of continental origin, covering several formations whose names depend on the geographical area (see Fig. 2). The lithology changes from nine sands at the bottom of the well to twelve sands at the top of the productive interval. Many of these sand beds contain hydrocarbons but produce oil, water or gas, depending on the fluid saturations, relative permeabilities, rock and fluid characteristics. Presently fluid prediction success rate varies between 65% and 80%.
During the last 15 years, polymer gels have become an accepted technology for improving volumetric sweep efficiency in heterogeneous waterfloods. Water injected subsequent to the gel treatment ideally enters previously unswept zones with significant mobile oil saturation. Results from several field projects in four hydrocarbon basins in Argentina and Venezuela are described based on the application of two available polymer gel technologies: Marcit and Unogel. The types of reservoirs and reservoir conditions where polymer gels have been successful, and unsuccessful, are illustrated. Fundamental reservoir rock and fluid characteristics, reservoir temperatures, polymer gel designs, and project evaluation are presented for each of the field projects. A high temperature (275ºF) reservoir is included. In multi-layered reservoirs where crossflow is believed to be limited, one strategy is to inject a small gel volume in order to improve the vertical profile in the near wellbore region. If crossflow is believed to exist between layers or within a layer, signficant gel volumes are recommended for deeper placement in the offending zones so that water cannot easily bypass the gel treatment. Gel formulation is a fundmental issue. Traditionally, minimum polymer concentrations of at least 3000 ppm have been recommended for injection well gel treatments. Lower polymer concentrations were believed to be ineffective. A large scale and ongoing field project is presented in which low concentration polymer gels have been successful. In the same field project, the results of multiple gel treatments in the same injection well are discussed. Introduction This paper will summarize polymer gel applications in three basins in Argentina and the Lake Maracaibo basin in Venezuela (Figure 1 and 2), using two of the most widely applied polymer gel technologies: Marcit[1] and Unogel.[2] Several of the case studies presented in the following paragraphs included extensive pre-treatment diagnostics. Due to the space limitations, those procedures are not discussed in detail. Marathon's patented Marcit gel technology was developed for application in naturally fractured reservoirs and was first applied in the Tensleep and Phosphoria reservoirs of northwest Wyoming. The Unogel technology was developed and patented by Union Oil Company of California (Unocal), primarily for use in high temperature (>250ºF) reservoirs. Although somewhat less versatile than the Marcit gels, Unogel has shown promise in high temperature reservoir applications. Both Marcit and Unogel gelants are typically formulated using a partially hydrolyzed polyacrylamide polymer (PHPA). The primary difference lies in the crosslinking mechanism. Marcit gels are crosslinked with a metal ion (Chromium III) while the Unogel technology requires an organic crosslinker and a stabilizing agent for delayed gelation. Although polymer gels evolved from the application of polymers for mobility control, gel treatments are not designed to improve an adverse mobility ratio. One of the primary criteria for polymer gel applications are reservoirs with low oil recovery efficiency and, in many cases, such reservoirs exhibit an adverse mobility ratio. However, the primary objective of any polymer gel treatment is selective permeability reduction due to reservoir heterogeneity. Oil viscosity is not, in itself, an important consideration for well selection or treatment design.
fax 01-972-952-9435. AbstractThe San Jorge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undesired effects such as uncontrollable height growth, significant proppant pack damage, lengthy clean up times and high friction pressures. In recent times, polymer-free viscoelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Nevertheless, VES were known up to now, for their limitation to withstand elevated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits of even this HT fluid, simulations indicated that a series of cool-down brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into wateror non -productive zones, resulting in reduced fluid and proppant volumes. Field implementation proved also to be successful in terms of operational simplicity, reduced clean up time and consequently work over rig cost savings. Overall, the use of polymer-free fluids improved well productivity. Design, laboratory studies, temperature simulations confirmed by downhole measurements, field implementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range of permeability and temperatures.
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