A wide variety of mechanical and chemical technologies have been implemented for controlling unwanted fluid production in hydrocarbon-producing wells. This paper presents the field implementation of a porosity-fill sealant (PFS) system for water and gas shutoff applications. Proper diagnostics and candidate selection process is the key to a high success ratio with this type of treatment. Case histories are presented along with lessons learned from more than 1,000 treatments highlighting the diagnostic stage. The PFS system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). The PFS system is placed into the formation as a low-viscosity solution that eventually actives at a predicted time to form a three-dimensional (3D) gel structure. The crosslinked gel provides a total shutoff of pore spaces and channels, thus limiting undesired water or gas flow. The PFS is not a selective treatment; thus, zonal isolation might be required. The working temperature range of this system is 40 to 400°F. This system has been successfully tested to withstand a differential pressure of at least 2,600 psi and is resistant to acid, CO2, and H2S environments. The following parameters are discussed: (1) PFS performance testing, (2) design considerations, and (3) case histories. To date, more than 1,000 treatments have been performed with the PFS system worldwide to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and/or casing-leak repair. Because of the capability of the PFS system to withstand high-pressure environments, workover operations have been successfully performed in previously treated wells, including acid stimulation, sand control, and frac-pack treatments, among others. Case histories are presented for different types of water production mechanisms and different wellbore completions and reservoir conditions where the PFS system was successfully implemented.

This case history describes a procedure in which a polymer sealant and a bridge plug were used to shut off water production from upper zones to enable gas production from productive lower zones. Offshore gas fields operated in East Kalimantan were producing gas and water. When water production increased, gas production was greatly reduced. This paper presents a case history of water-shutoff work performed in the Peciko field, offshore East Kalimantan, Indonesia.Typically, the production of these wells is commingled with multiple perforations inside the production casing and the water breakthrough could happen at any layer; therefore, a selective shutoff is required. A production-logging tool (PLT) was run to identify the source of the water influx, and the uppermost set of perforations was identified to be the main contributor to the water production.The objective was to completely shut off the uppermost zones with sealant, without a cement tail-in. The chosen sealant was an organically crosslinked polymer system and tail-in with a particle-gel system (PGS) to increase near-wellbore shutoff integrity. Because the target shutoff zone was the uppermost set of perforations, a retrievable bridge plug was used to provide isolation from all the lower zones while pumping the sealant.The operation sequence consists of (1) setting the retrievable bridge plug, (2) performing an injectivity test, (3) pumping the sealants, (4) shutting-in to allow the polymer to develop strength, (5) cleaning out excess particle gel inside the wellbore (without milling), (6) retrieving the bridge plug in an underbalanced condition, and then (7) flowing the well.The job was initially evaluated by flowing the well and observing the well performance. Later, a PLT was run to confirm the amount of influx from the shutoff zone. Results from both were very satisfactory, as is detailed in the paper.

The demand for hydrocarbon production increases each year as world population continues to grow and more energy is consumed. This increasing demand has caused the oil and gas industry not only to develop new technology but also to develop reservoirs that were previously overlooked. These marginal reservoirs were deemed uneconomic, primarily because they typically existed on the outer fringes of known reservoirs or the potential productive formations were subject to excessive water production.Many of these previously-overlooked reservoirs need to be hydraulically stimulated to make them economic. When using fracture stimulation to complete a wellbore in marginal reservoirs, it is not uncommon to produce excessive amounts of water. This excessive water production can come from the producing formation, water-wet formations which bound the producing interval, or lack of sufficient barriers between the productive zone and nearby water-bearing zones.Because wells drilled in these marginal reservoirs are economically borderline, any additional water production resulting from the completion of these wells jeopardizes the already questionable economics. Consequently, the operators run a much higher economic risk when completing wells in these marginal reservoirs.This paper describes a case history using a relative permeability modifier (RPM) incorporated into a hydraulic fracture stimulation treatment to reduce excessive water production. By implementing this process, it gives the operator an additional tool to increase the chances of producing formations containing hydrocarbons which had been previously overlooked. Therefore, this process can help reduce the higher economic risk of completing marginal reservoirs. Incorporating this technique into a fracture stimulation treatment resulted in the best producing well in the study area.

Since its commercialization in 1949, hydraulic stimulation has been used on thousands of wells worldwide to increase hydrocarbon production. There are some areas where hydrocarbon production would not be economically viable without this process. The application of hydraulic stimulation has become even more critical when trying to produce hydrocarbons from unconventional reservoirs, such as coalbed methane, shale, and tight gas sands. Throughout the oil and gas industry, hundreds of millions of dollars have been spent by operators and service companies to develop stimulation-fluid systems that increase proppant-carrying capacity and minimize formation damage. The base fluid has run the gambit of oil, water, foam, alcohol, and sometimes a combination of these. Fluid selection can have a direct bearing on how much proppant can be placed in the formation of interest and have a direct impact on the economics for the operator. In some areas, the associated cost of hydraulic stimulation can be as much as 50% of the overall cost of drilling and completing a well. Because unconventional reservoirs have become more important in the oil and gas industry, fluid selection has become even more critical because of the nature of the reservoirs. Recently, there has been a change within the industry from using crosslinked gelled-fluids to water systems that use a friction-reducing additive as the fluid of choice when completing wells in unconventional reservoirs, specifically tight-gas sands. These fluid systems are referred to as slickwater. This paper describes a case history of comparing production data from wells stimulated using crosslinked fluid systems to slickwater fracs in an effort to determine which fluid system gives the best production from an economic standpoint. This paper compares wells from several different operators in the Natural Buttes field, located in northeastern Utah, that were stimulated from 2005 through 2007. Introduction Unconventional reservoirs such as tight-gas sands, have become more important to the oil and gas industry, and the selection of stimulation fluids has become more critical to the overall production of these reservoirs. Tight-gas sands are typically defined as gas-bearing reservoirs with extremely low-permeability formations, typically = 1 md (Kasemi et al. 1982). Formations with permeabilities less that 10 md need to be hydraulically stimulated to be economical. Historically, most hydraulic fracturing treatments used gelled fluid with a crosslinker to create a subterranean fracture to carry and place a proppant within the fracture (Harris et al. 2005). In recent years, the use of slickwater (SLW) fracs as the hydraulic stimulation treatment in these tight gas sands has increased in popularity. In this paper, a SLW frac is defined as being a treating fluid that uses water as a base fluid, with no type of gelling agent to act as a viscosifier. However, some type of friction reducer (FR) material is normally incorporated into the fluid system to reduce wellhead treating pressures during the stimulation treatment. FR products typically provide little or no increased viscosity to the base fluid; therefore, fluid viscosities are typically around 1 to 2 cp. Gelled fluids, on the other hand, normally contain some type of polymer added to the base fluid, typically water, which greatly increases the viscosity of the fluid. The base viscosity of gelled fluids used in this study ranged from around 15 to as high as 25 cp. Once the base-fluid rheology was increased to the required viscosity, a crosslinker was typically added that increased the viscosity as much as 25 times that of the initial base-gel viscosity. The primary purpose of using a gelling agent and then crosslinking it is to increase proppant-carrying capacity, not only for fracture length, but also increased proppant concentration placed in the fracture itself. The gelled fluids for hydraulic stimulation wells in this study were all crosslinked fluids and will be referred to as XLK throughout the remainder of this paper.

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