A research project has recently been launched in the UK investigating residual stress (RS) in nuclear power plant [1]. At the outset there is a need to review techniques available for modifying/relieving residual stress levels in weldments, since it is well known that large tensile RS levels generated in welds can be detrimental in terms of fatigue, fracture resistance and environmentally assisted cracking (EAC). Therefore current RS mitigation methods have been reviewed. Mitigation methods can be categorised into three main groups as follows: a) Surface treatment to induce compressive skin stress; b) Stress relief through thickness; c) Weld design optimisation to produce low/favourable RS levels and minimize distortion. A brief description is provided of how each method works, together with the capability and potential benefit in terms of RS reduction, as well as references for further information. Metallurgical effects of treatment are also an important consideration. The practicality of application to nuclear plant is considered, both in manufacture and in-service, together with any limitations and risks. Several techniques are identified that are likely to be beneficial and warrant funding for further development. RS mitigation should be targeted at key/critical weld locations in the plant, where loadings and degradation mechanisms (such as corrosion, fatigue, EAC or fracture) are most significant. Treatment would be carried out in order to improve plant integrity and reliability (eg safety margins). There are potentially substantial cost savings since through-life inspection/maintenance work could be reduced and expensive repairs and shutdowns avoided. Note that it is important to understand whether the benefits in terms of RS improvement are likely to be long term. In certain systems large thermal transients are applied that might generate additional surface plastic strains, thereby modifying RS magnitudes and distributions.

Summary Water production becomes a major problem as hydrocarbon-producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success. For approximately eight years, a polymer gel system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This article describes results from a sampling of over 200 jobs performed throughout the world, including the average results from more than 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The upper placement temperature of the system originally was ~260°F. Data presented in this article indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350°F. 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 as producing the same volume of oil. Often, each barrel of produced water represents some lesser, but significant, amount of unproduced oil. In addition, water production causes other related problems such as sand production, the need for separators, disposal and handling concerns, and the corrosion of tubulars and surface equipment. Many methods are available to mitigate water-production problems, and perhaps the most widely used chemical system has been chrome-crosslinked polyacrylamide gels. A previous publication described the advantages of the acrylamide- (PAtBA) copolymer/polyethyleneimine system (herein referred to as OCP, or organically crosslinked polymer) (Hardy et al. 1998). A brief discussion of these advantages follows, with presentations of case histories using OCP and data showing expansion of OCP technology. OCP System Description Gel systems for water and gas shutoff have many requirements, including:Low viscosity allowing easy injection deep into a formation matrix.Capability to control gelation time of the fluid.Sufficient strength to resist drawdown in the wellbore.Temperature stability of the gel for extended periods of time. As will be shown in the following discussion, the OCP system meets all these requirements. The viscosity of the system is ~25 cp as mixed. This relatively low viscosity is due to the relatively low molecular weight, ~250,000, of the PAtBA. This polymer is covalently crosslinked with PEI, which results in excellent control over gelation time. Sufficient strength and temperature stability are also obtainable. In addition, the OCP system is insensitive to formation fluids, lithology, and/or heavy metals. Another advantage of the OCP system is its predictable viscosity profile that can be used to improve diversion over long treatment intervals.

The Anton Irish field was discovered in 1945, unitized in 1950 for a produced gas pressure maintenance project and converted to a waterflood in 1969. In 1997 CO 2 flooding began and currently accounts for about 85% of the unit production. Presently, the entire field produces around 6,500 BOPD; 36.5 MMCFPD of recycled CO 2 , and 69,200 BWPD. Over the years of flooding, various conformance problems have been identified and many attempts have been made to address these problems with limited to no success. In 2003 a new program was initiated to re-evaluate the problems and design better solutions. This paper will outline the diagnostic efforts that were undertaken, discuss the basic findings of that effort, review the resulting solutions that were designed to resolve these problems, and show the results of this work.

Summary For many years, relative-permeability modifiers (RPMs) have received a great deal of attention from the oil- and gas-production industry. Because of the completion techniques used in many wells, it is not always practical or cost-effective to protect the hydrocarbon interval properly during a water-shutoff treatment. RPMs offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production. This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can be best described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development will be discussed, such as the optimization of the molecular weight of the backbone polymer and the concentration of grafted MPEG. Details of laboratory evaluations will also be provided, including a discussion of the use of multi pressure-tap flow cells for permeability-reduction tests, the effect of polymer concentration, and the effect of saturations. These test results show that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and postflushes for optimum results. 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 as producing the same volume of oil. Often, each barrel of produced water represents an equal amount of unproduced oil. In addition, water production causes other related problems such as sand production, the need for separators, disposal and handling concerns, and the corrosion of tubulars and surface equipment. Current literature describes successful RPM treatments that use various types of chemical treatments in essentially all lithologies. If these RPM treatments were successful in all cases, it would follow that RPM technology would be applied more frequently than currently indicated. Despite these claims of success, none of the materials or techniques used in RPM processes have apparently performed consistently well in field operations. Although the literature contains several theories on RPM mechanisms,1-3 none appear to be universally accepted, perhaps because no single factor determines the success of an RPM. Rather, an RPMs success depends on several well and reservoir characteristics, including chemistry, lithology, problem type, permeability, saturation, and many others. Because all of these factors affect the outcome of an RPM treatment, developing a single RPM for all well situations is unlikely. Instead, a better solution would be to focus on specific reservoir conditions (problem type, lithology, temperature, etc.), and to design a process to fit those circumstances. Conventional Water-Reduction Systems Two broad categories of chemical systems are available for reducing water production:Nonsealing systems that allow the flow of fluids through a porous medium.Sealing systems that completely block the flow of fluids in a porous medium. Nonsealing Systems. Nonsealing systems are typically dilute solutions of water-soluble polymers. These polymers most likely reduce effective water permeability by means of a "wall effect,"1 wherein the polymer adsorbs onto the formation, creating a layer of hydrated polymer along the pore throat that inhibits water flow. Sealing Systems. Sealing systems are porosity-fill materials that can be valuable when a water-producing zone can be mechanically or chemically isolated. However, in many situations, a target zone cannot be isolated, and the sealing system sometimes penetrates zones that should not be treated. Although there are claims that sealing systems will reduce water permeability more than they reduce oil permeability,4 it is extremely risky to pump such a system without zonal isolation. Although some sealants do reduce the permeability to water more than to hydrocarbons, the pressure required for the hydrocarbons to break through the sealant may be so high that hydrocarbon production after the treatment is unlikely. The lack of nonmechanical methods to selectively place a sealing system and the high costs for gel placement have increased interest in developing chemical systems thatselectively reduce effective water permeability.do not decrease oil permeability.do not require special placement techniques. RPMs RPMs (sometimes called disproportionate permeability reducers or selective plugging systems) should have physical and/or chemical properties that help reduce water flow from the treated area of a water-producing zone, thereby reducing the water inflow to the wellbore. In the treated zone of a hydrocarbon-producing layer, an RPM should result in little or no damage to the flow of hydrocarbon. Polymers can selectively reduce water permeability more than they reduce oil permeability. This property does not depend on the rock type or the type of polymer (provided it is hydrophilic).5 Perhaps the simplest system that has been used as an RPM is polyacrylamide (PAM) or hydrolyzed polyacrylamide (HPAM). The effectiveness of PAM has been demonstrated in laboratory and field test results.5–9 PAMs are believed to be useful at temperatures up to 160°F in reservoirs with low-salinity brines.10 PAMs have been used with hydrolysis ranging from 0 to 50% and molecular weights from several hundred thousand to 17 million daltons.

Water production becomes a major problem as hydrocarbon producing fields mature. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually, well shut-in (with associated workover costs). Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still retain large volumes of recoverable hydrocarbons. Many polymer systems have been applied over the years to control undesired water production from hydrocarbon wells, with varying degrees of success. For approximately eight years, a polymer system based on an acrylamide/t-butyl acrylate copolymer (PAtBA) crosslinked with polyethyleneimine (PEI) has been used successfully for various water shutoff applications. This paper will describe results from a sampling of over 200 jobs performed throughout the world, including the average results from over 90 jobs performed in one geographic location alone. In addition to "standard" matrix treatments, results will be shown for other types of treatment, including a design to plug annular communication and a combination of sealant and temporary gel in an openhole horizontal completion. In addition, laboratory data pertaining to work aimed at increasing the temperature limit of the system will be presented. The upper placement temperature of the system originally was ∼260ºF. Data presented in this paper indicates the development of a retarder system that allows the upper placement temperature to be raised to at least 350ºF. 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 as producing the same volume of oil. Often, each barrel of produced water represents some lesser, but significant, amount of unproduced oil. In addition, water production causes other related problems such as sand production, the need for separators, disposal and handling concerns, and the corrosion of tubulars and surface equipment. Many methods are available to mitigate water production problems, and perhaps the most widely used chemical system has been chrome crosslinked polyacrylamide gels. A previous paper described the advantages of the acrylamide- (PAtBA) copolymer/polyethyleneimine system (herein referred to as OCP, or organically crosslinked polymer) over chrome crosslinked polyacrylamide.[1] A brief discussion of these advantages follows, as well as presentations of case histories using the OCP and data showing expansion of the OCP technology. OCP System Description Gel systems for water and gas shutoff have many requirements, some of which include:Low viscosity that can be easily injected deep into a formation matrix.Capability to control gelation time of the fluid.Sufficient strength for resisting drawdown in the wellbore.Temperature stability of the gel for extended periods of time. As will be shown in the following discussion, the OCP system meets all of these requirements. The viscosity of the system is ∼25 cp as mixed; excellent control over gelation time is available with the PEI crosslinker, and sufficient strength and temperature stability are also obtainable. In addition, the OCP system is nonsensitive to formation fluids, lithology, and/or heavy metals. Another advantage of the OCP system is the predictable viscosity profile that can be used to improve diversion over long treatment intervals. The OCP system was developed to improve the properties of chrome crosslinked systems. In particular, it is well known that commonly used chrome crosslinkers tend to undergo hydrolysis and precipitation, especially with increasing pH and temperature.[2,3] Precipitation of the crosslinker as the fluid is injected into the matrix means that the leading edge will not gel, and thus, the intended volume of the matrix will not be filled with gel. It has been shown that the precipitated crosslinker is capable of reacting with subsequently injected polymer, but this can lead to decreased injectivity and possible diversion of the fluid to intervals not intended for treatment.