This paper was prepared for presentation at the 1999 SPE International Symposium on Oilfield Chemistry held in Houston, Texas, 16-19 February 1999.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes the design, operation and results of two different water shut-off applications in a field located in Southern Venezuela. The production mechanism of the main reservoirs of the studied field is strong water drive. The presence of the active aquifer, the geological complexity and the high drawdown produced by the electric submersible pumps, it has abruptly increased the water-oil ratio causing premature shutting. The limitations of the traditional water shut-off applications in this field are the slotted liners gravel pack completion of the wells, the high formation permeability and the presence of caverns in the near wellbore due to sand production. A project was proposed to evaluate the gel technology, including the diagnosis of the high water production source and the design of applications to overcome these limitations. Two mayor causes were detected, water channeling through high permeability strakes at the top of the reservoir where thin shale barriers are present; and rapid coning at the base, where the sand has a higher vertical permeability and the water-oil contact is present. According to this, two different applications were designed and successfully evaluated in three wells of the field, two of them correctives and the other preventive. Relevant aspects of the design are the use of an elastic gel system of high consistency with easily controlled gelling times; and the use of placement techniques to guarantee the seal of offensive zones and the protection of the productive ones. In the corrective treatments the gelant was injected using mechanical isolation and the total volume was pumped in two batches, while dual injection was carried out in the preventive application. A reduction of 3000 barrels per day of water production was obtained, as well as a substantial increase in the productive life of the three wells.

Some of the most important oil reservoirs located at the Maracaibo Lake Basin are produced by a waterdrive mechanism. After four decades since the beginning of production, oil rates have declined mainly due to a continuous increase in water production. These reservoirs are characterized by highly heterogeneous sandstone formations in which water channeling through high permeability strakes is a very common cause of water production. Another type of problem affecting production in these reservoirs is behind casing communication between producing sand and nearby water sands. Both problems have caused a rapid increase in the water-oil ratio of the wells, which in most of the cases were abandoned affecting considerably the oil recovery of the reservoirs. This paper describes four successful selective water shutoff applications in producing wells from mature reservoirs at Maracaibo Lake Basin performed during the last seven years. The aim was to correct problems of channeling and behind casing communication. An elastic gel system of variable consistency with easily controlled gelling times was used. In some applications a gel-cement combination was necessary to improve results. Reservoir and well characteristics, diagnostic analysis and the different types of selective placement used are shown as key factors for success. Using the elastic gel system the water production has been reduced to a minimum, obtaining an increase in wells productive life-time, which in global terms reaches a volume higher than 2 millions barrels of additional oil recovered. Introduction In mature oil reservoirs, produced by waterdrive mechanism and with strong vertical variability in permeability, water channeling problems are very frequent, being the main cause of wells abnormal oil production declining. If this problem is not properly identified and corrected can lead to premature abandonment which compromises the reservoir recovery and causes an increase in field development investments because the need of drilling new wells to access bypassed oil reserves. In Maracaibo Lake Basin the biggest light-oil reservoirs have been produced over the last 40 years. Main recovery mechanism of these important oil accumulations is waterdrive, in some cases supported by flanks water injection. Current oil remaining reserves are no higher than 9% of total oil recoverable volume. These consolidated sandstone reservoirs of fluval-deltaic origin are characterized by highly complex stratigrafy, which determines its lenticularity. The reservoirs are compound by several sand layers separated by shales of variable thickness. Permeability values can vary between 200 and 1000 mD, favoring water channeling and a rapid increase in wells water production. Additionally, behind casing communication problems due to deficiencies in primary cementing are also very frequent, affecting considerably wells production behavior. Traditional water control technique applied in wells with high water-oil ratios (WOR) had consisted on setting a plug in the well to abandon watered-out intervals and perforating upper prospective sand layers to increase oil production. This operational practice very frequently used in development stage had caused severe oil bypassing, recoverable only with new wells. To increase wells productive life-time and improve oil recovery in these today's mature reservoirs, a water shutoff project has been carried out during the last 7 years of production[1]. Water shutoff applications consisted on a gel system injection based on a previous diagnostic of the type of problem present and precise identification of offensives and productive intervals. Selective placement techniques were considered necessary to protect wells productivity[2]. This paper presents four successful water shutoff field experiences showing the evolution in time of selective placement technique used to perform the gel injection. The results in terms of reduction in WOR and additional oil recovery are also presented. Finally, some learned lessons form these experiences are included.

In this work a gel of an acrylamide based polymer crosslinked with organic reagents was studied. This gelling system was one of the commonly used in water conformance treatments. Once formed in bottle tests the gel was placed in contact in several proportions with water of various salinities. The tests where carried out at 266°F, and the changes were registered as a function of time. It was found that the gel swelled until a constant final volume. This value depende the difference between the salinity of the water used to prepare the gel and the added water. The performance of this gel in porous media was evaluated by coreflood experiments in Berea sandstone at 266°F with water prepared with the same compositions evaluated in the bottle tests. The results indicated that the RRF values are lower if the salinity of the reservoir water is similar to water salinity used to prepare the gelling mixture; while the Residual Resistance Factor (RRF) increased if the salinity of the reservoir water was much higher than the salinity of the preparation water. These findings show that it is important to take into account the difference between the water salinity used to prepare the gelling system and the water reservoir in the design of water conformance treatments with polymeric gels. Introduction The aqueous gels prepared from crosslinking reactions of water-soluble polymers are nowadays used to reduce the formation permeability in water conformance treatments. Despite, there are still many questions about the behavior of the gels inside the porous media. One of these questions is how the fluids present in the reservoir affect this gel. The aim of this work, as a contribution to the available information, is to study the influence of the difference between the salinity of the reservoir water and the water in which the gelling system has been prepared. The gels are an intermediate state between a liquid and a solid. As a result of this dual character they can show intermediate properties between the cohesion of the solid and the transport of the liquids. The polymer network holds the liquid in place, and the liquid prevents the networks from collapsing into a compact mass2,4,6. They have the capacity of swell or shrink according to the external media against they are put in contact. A gel can swell or shrink when there are changes in the variables of the external environment like pH, temperature, salinity, etc.1,2,4. The studies on gel swelling have demonstrated that small changes in the external conditions as ionic strength, and external electric field can induce drastic changes in the state of the swollen network. In particular, it is well known that under certain conditions polyelectrolyte gels may undergo a discontinuous volume change. The volume of gel is influenced by osmotic pressure7,8. The osmotic pressure is the sum of the following three components; interactions between the polymer strands and the solvent, the pressure relates to the elasticity of the individual resistance to stretching or bunching, and the hydrogen ion pressure, which is associated with the ionization degree of the polymer network9. The magnitude and direction of the components of osmotic pressure in cnjunction each other govern whether a gel swells or shrinks. In this work the interaction between the reservoir water of reservoir and the water in which the gel was prepared was studied in bottle tests and by coreflood experiments in Berea sandstone. Experimental Gelling mixture preparation. The gelling system was prepared dissolving a water-soluble polymer in water of the composition shown in column A in Table 1. Then a mixture of organic crosslinkers was added and the pH was adjusted adding NaOH.

The property by which polymeric gels reduce water permeability in larger proportion than oil permeability is known as disproportionate permeability reduction (DPR). This phenomenon is believed to be the result of preferential blockage of water pore channels combined with the exclusive capacity of oil to deform the gel. This property represents an opportunity to successfully control water production, regardless the cause of the excess water inflow or the type of well completion. For this reason, many investigations intended to understand and improve DPR have been carried out. The relationship between DPR and parameters such as rock permeability, wettability and flow rate has been widely described. Nevertheless, no efforts have been made yet to evaluate the influence of oil viscosity. Considering the importance of heavy oil production for Venezuelan oil industry, as well as the growing impact of excess water production in these reservoirs, an experimental study was carried out to evaluate how DPR is affected by oil viscosity. Four coreflood experiments were carried out in high-permeability Berea cores to measure oil and water permeability before and after gel placement. In the first three tests, DPR was determined using oil with viscosities of 1.8; 67 and 140 cp. The last test consisted on sequentially measure the permeability of each of the oils when flowing through the same fully gel-saturated Berea core. Experimental results indicate that DPR improves as oil viscosity increases because 1) oil viscosity affects gel placement favouring selective plugging of water channels; and 2) the more viscous the oil, the larger the deformation of the gel, thus the easier for the oil to open a channel through it. According to this, a large potential of controlling excess water production in viscous oil reservoirs through gel technology application was established. Introduction In most of cases, as reservoirs reach maturity a steady increase in water production occurs. Production costs relative to lifting, treatment and disposal increases accordingly. However, the largest impact of excess water production is the accelerated decline in oil production caused by oil bypassing, which shortens productive lifetime of wells and affects the ultimate recovery of the reservoir. This situation becomes more severe as the oil-to-water viscosity ratio increases, because of the implied reduction in displacement efficiency. Nowadays, the water cut of those viscous oil reservoirs with larger production history in Venezuela can be as high as 65% and approximately 500 wells from these fields are currently shut-in because of high water production. Many of these wells are horizontal, therefore zonal isolation interventions are limited by the complexity and risk involved in such well completions; instead sidetracks and new wells are drilled.