Gel treatment applications have been used for production well WOR reduction. There have been a number of cases where conformance was very poor and, by invocation of gel treatment strategies, WOR was significantly reduced. This paper discusses both the characteristics of reservoirs and wells which result in high WOR, as well as characteristics of gel treatments which need to be designed in order to effectively minimize the produced water from a reservoir or an oil field. Examples are provided in this paper whereby, through the use of gel treatments in production wells, WOR and oil production was increased. The paper concludes that there is a significant upside to gel treatments for reservoir optimization and production well revitalization. Introduction A serious problem in oil-producing reservoirs is water production. As with most things in nature, fluids also tend to follow paths of least resistance which, in reservoirs, are often created by the heterogeneous nature of the rock. There are two levels to this heterogeneity. The first is microscale heterogeneity which could be represented as a simple porous feature distribution, and the second is macroscale heterogeneity which includes layering, natural or induced fractures, and high vertical and horizontal permeabilities. Both can lead to poor conformance and, therefore, need to be controlled. If conduits for water flow are available then they need to be blocked in order for production wells to continue operation. In terms of water disposal costs, approximately $1 billion is spent in Alberta alone each year. The macroscale heterogeneities are more commonly understood and more intuitive. It is commonly known that, in some instances where fracturing operations have been misapplied or resulted in unfortunate connections to bottom water sources, the fracture permeability (100 to 1,000 times greater than the permeability of the rest of the rock) has resulted in very quick water breakthrough and very low recovery of the hydrocarbons in the reservoir. A similar response can also be observed where high permeability layers are present in certain porous media. Nevertheless, their effect is that much of the rock remains unswept. Another form of macroscale heterogeneity, which contributes to very poor conformance is the case where poor cementing operations are present. In such cases, in order to produce anything from the well, near wellbore fluid profile modification must occur. The same applies for injection wells. For microscale conformance difficulties, often simple laboratory tests can identify problems associated with exploitation strategies. For instance, the recovery efficiency associated with a waterflood is often based on analogous reservoirs or past experience. In some cases, subtle changes in the structure of the rock can result in vast changes in the sweep associated with the flow unit even though the porosity remains about the same value. Many examples exist in the literature where permeability and porosity of reservoirs have been sufficiently high to motivate operating companies to full developmental strategies only to find out that, upon implementation, the sweep through the homogeneous flow unit is much less than the average literature numbers would have indicated.

With the discovery of new fields becoming less common and the continued development of brownfields, water control is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured reservoirs with openhole completions, such as in the Boscan field in West Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection, combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the development, implementation, and results of an innovative solution for water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the temporary isolation of the producing layers, the permanent shutoff of the water zones, and the effective cleanup of the isolated producing layers. The results of ten water control treatments are presented here. The average water cut was reduced to 30% from 88% and oil production was increased by an average of 300 BOPD per well through the application of this water shut-off solution. In one particular well, two previous water control treatments using a conventional water shutoff technique, including a relative permeability modifier (RPM), had left the well producing 100% water. The new solution reduced the water cut to 25%, resulting in a gain in oil production of 300 BOPD. This innovative solution was established as a standard practice for water shutoff in the Boscan field. Introduction The Boscan field lies 40-km southwest of Maracaibo, Venezuela and covers an area of approximately 660 km2, produces a 10.5°API gravity asphaltic oil from the upper Eocene, Boscan (Misoa) Formation with a live oil viscosity ranging from 200–400 cp at reservoir conditions. The reservoir dips to the southwest and ranges from 5000 to 9000 ft in depth. Boscan Field is a combination structural/stratigraphic trap. The reservoir sands were deposited in a tidal-dominated depositional setting. Boscan Field has a complex stratigraphic framework, the interpretation of which is made particularly difficult by the 1 to 0.6 kilometer well spacing. The field currently produces ~ 115,000 BOPD. Figure 1 shows the geographic location of the Boscan field. Since its discovery by the Richmond Exploration Company in 1947, the Boscan field has had over 800 wells drilled with 525 of them currently active. Most of the shut-in wells in the field are located in the south end of the field that in recent years has experienced a surge in water production. Most of the wells in this particular area are experiencing water cut of 90% or higher. Problem Scope The main production challenges in south Boscan wells are;Surface facility limitations in handling produced water; therefore the volume of fluid produced is limited. In addition, production enhancement is restricted.