Water production control is a key issue in most mature reservoirs worldwide. Many techniques have been developed to achieve this purpose. Water Shut-off (WSO) treatments using crosslinked gels have proven to be an effective alternative. When appropriately designed and applied, these systems generate flow restrictions in high permeable or fractured formations that bypass water from highly saturated zones (injection water or natural brines). WSO treatments efficiency depends on several aspects as reservoir fluids flow patterns, rock petrophysics, formation heterogeneity, and WSO gel characteristics. This last aspect is adjusted to optimize the treatment based on experimental tests performed in the laboratory. This paper presents an experimental methodology to evaluate and adjust WSO polymer systems according to operational and treatment performance requirements. These studies go from qualitative gel consistency and fluid compatibility bottle tests, to rheological characterizations to determine viscosity variations and gelation time (outside porous media tests), as well as flow tests performed on formation and Berea core plugs at reservoir conditions (inside porous media tests). These properties are highly important to avoid early gelations and, at the same time, assure the appropriate WSO placement in the reservoir. Viscoelastic properties such as G* (complex modulus), G′ (storage modulus) and G″ (loss modulus) define the gel strength and provide structural information such as crosslinking density. These parameters are essential to design the gel formulations (polymer and crosslinker type and concentration) depending on the operational and reservoir requirements. Finally, the flow tests performed on core plugs show the changes in water and oil permeability after injecting the treatment. This information is used to calculate the residual resistance factors to water (RRFw), oil (RRFo) and the gel resistance index (GRI). These parameters define the treatment blockage degree and allow estimate probable well production response as well as the best production regimes to extend the treatment life time. This methodology was applied on a new WSO gel system, developed for a wide range of applications. The effect of polymer concentration, temperature, salinity and flow rate are examined in detail. Experimental tests are many times underestimated when planning a WSO job; however these tests will always provide valuable information that will increase the chances of successful water shut-off treatments. The connection between laboratory and field parameters and its influence in the oil and water productivity were analyzed.

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A fracture-stimulation technique that includes an in-situ gener- ated relative-permeability modifier (RPM) preflush has been used to tap previously bypassed reserves in an Argentina forma- tion. The formation was reported to have high water-saturation levels. Fracture-stimulation treatments performed in similar intervals usuallyintersect a stringer of water within the targeted interval, orextend into the highly saturated areas above and/or below the interval. Water cuts as high as 60 to 70% have made production of such intervals uneconomical. A major operator has used the new RPM polymer-based preflush (PBP) technique on more than 15 wells in an Argentina formation. Data gathered from the first 3 months of production economically justify the stimulation treatments. In many cases, the treatment has limited water production to less than 15%, and some applications have reduced water production to negligible levels. This paper discusses the job design, field application, and results of several RPM preflush treatments performed in this area between 1997 and 1999. Introduction Controlling water production has been an objective of the oil industry almost since its inception. Produced water has a major economic impact on the profitability of a field. Producing 1 bbl of water requires as much or more energy required to produce the same volume of oil. Often, each barrel of produced water represents an equal amount of unproduced oil. In addition, water production causes other problems, such as sand production, the need for separators, disposal and handling concerns, and the corrosion of tubulars and surface equipment. The reflective analysis of lifting water is normally based on a barrel of oil equivalent (BOE) cost. This value reflects the cost of the energy required to lift sufficient produced fluid to gain 1 bbl of oil. BOE is calculated from the total energy costs required during the production of all fluids divided by the barrels of oil actually produced. The profit obtained from the well is deter- mined by the BOE subtracted from the selling price of the oil. All other overhead expenses are paid out of the remaining profit. For several years, research has been dedicated to the devel- opment of chemical systems that can selectively reduce water production without reducing oil production. 1–4 Initially, two methods were used to reduce water-production problems:produced water was separated from the oil for disposal, ora plugging agent was squeezed into the formation to stop water entry. However, because these methods were designed to stop water production, they often curtailed oil production and/or damaged the formation. Early conformance chemicals intro- duced to decrease the water-oil ratio (WOR) of the formation werewater-reactive agents that selectively plugged water- filled pore throats, andchemicals that increased water viscos- ity, thereby impeding its mobility while only minimally altering oil production. Polyacrylamides (PA(tm)s) have been used with this technique with only limited success.5

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Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells. However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model. A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations. This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.