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Halite scale has long been a challenge in the oil and gas industry. In recent years there has been a marked increase in the occurrence of this scale type due to the increased development of hotter and deeper gas and gas condensate fields. As the formation of this scale is commonly in the downhole production tubing, it is a challenge to identify and mitigate, so a non- conventional approach has to be taken for removal and control. Furthermore, it is very difficult to replicate the formation of this scale in the laboratory with complex and specific equipment being utilized to replicate field observations. This paper provides a review of several examples of halite scale formation in the field, detailing the mechanism of deposition and the strategies employed to remove and subsequently prevent reoccurrence. Details are also provided for two different types of laboratory test methods; the first being a simple static test method designed to quickly screen the extent of halite challenge and the suitability of a range of inhibitors. The second laboratory method concerns a novel, dynamic method whose primary aim is to accurately measure and predict the severity of scaling in the field, and then go on to determine the minimum effective dose of inhibitor required to prevent build-up. The different types of halite inhibitor chemistries are evaluated, including the use of wash water and where this is used in combination with organo-ferrous compounds, as well as more novel polymeric compounds. The paper concludes by providing an insight into the economics of the different types of treatment, namely the use of wash water versus the use of chemical inhibitors and combinations of these two techniques.

This paper details the complete evolution of a new cleaning chemical for heavy oil and gas pipelines. Information is offered regarding the reason for development, the research involved in formulation of the new product, as well as the laboratory testing. This paper concludes by giving several case histories of application in cleaning operations in Western United States and Texas. Oil naturally contains paraffins, asphaltenes and naphthenates. During transport these hydrocarbon components can precipitate and adhere to the pipeline walls and can become associated with iron sulfide scale. Corrosion can often occur on pipeline walls under these organic deposits. Pigging operations are normally performed to remove organic and inorganic debris from the walls of a pipeline. However, these scales can become very compacted and adhere to the walls of the pipeline. It is often necessary to add surfactant based chemicals to assist in the break-up, softening, and transportation of these deposits. A detailed literature review of the current theory in the chemistry of pipeline cleaning chemicals is presented together with a critical account of the key properties required of these chemistries: wettability alternation, solubilization efficacy of organic materials, emulsification of phases, dispersion, detergency, and defoaming. An explanation of the laboratory development and evaluation has been given as a preamble for the case histories. One case history details how a pipeline operator unsuccessfully tried to clean a 12" 9-mile section of pipeline with a pig. The pig was launched and became stuck along the length of the pipeline. Application of the newly developed product was able to free the stuck pig and removed significant debris. By way of conclusion the paper offers suggestions on how chemicals can be most efficiently used in conjunction with these programs. Introduction Pipeline Fouling Mechanisms and Typical Deposits Pipelines often saddled with internal deposits that restrict flow of the transported media, necessitating shut downs and offline cleaning programs. Many types of solids are found adhered internally in pipelines due to a wide variety of sources. The media throughput of a pipeline transports can be used to broadly characterize the type of deposits that are most commonly observed. This is a general rule only, linked with the fact that very few pipelines transport 100% of any single phase. For example, all oil export pipelines transport a small associated amount of water typically between 0.2 and 2.0% BS&W. This small amount of water can result in aqueous originated deposits even though by far the dominant phase in the pipeline is hydrocarbon based. Typically, a pipeline that transports crude oil becomes fouled with organic scale. Oil naturally contains paraffins, asphaltenes, and naphthenates. During transport in a pipeline, these can precipitate and adhere to the walls of the pipeline 1.

The Canadian Bakken has been produced for over 40 years but with advances in fracturing technology during the last 10 years, there has been an exponential increase in Bakken activity. Concurrent with this, there has been a step-change in frequency and severity of scale formation from high value, high productivity wells. This paper summarizes the scaling observations made over the producing life of this high producing formation drawn from treating and servicing over 400 wells through Southern Manitoba and Saskatchewan.The most common scale types are calcite and anhydrite, although there is also evidence of siderite and iron sulfide. Formation of scale in Bakken wells is seen from the bottom of the tubing and open-hole sections up through the casing and rods. Formation water salinity can reach over 250,000 mg/L with up to 20,000 mg/L calcium. When combined with the high down-hole temperature, this brine causes a significant challenge for selection and application of scale inhibitor chemistries.A typical scaling life cycle is given for a Bakken extended reach horizontal well. With production reaching maturity, the severity of scaling in this formation has been found to increase. The influence of fracturing and frequent well interventions has been discussed in terms of the profound effect these activities have on the onset of scale formation.The experiences and strategies of over a dozen different operators have been combined, and the lessons learned from these activities used to determine a common approach in the management of scale in these challenging wells.The paper concludes with several detailed case histories. These show how the development of an innovative scale management philosophy has been successfully put to the test in proactively preventing scale, thereby reducing the overall failure rate for the Bakken operating companies.

This paper details the laboratory evaluation and product development for auniquely applied gas-lift paraffin inhibitor. Several crude oils, specific toone particular Gulf of Mexico subsea network, were characterized with respectto cloud point, pour point and paraffin content. This information was used todetermine suitable wax inhibitors to test for application into the productionfluids offshore. Cold finger wax deposition tests were performed to evaluateeight different inhibitor chemistries. Details are given on the test methodologies used, with particular focus on thespecific evaluation to determine gas-lift suitability. Volatile flash analysiswas performed by a third party laboratory, coupled with a unique dynamicgas-lift test method, to find a suitable candidate. Of the products tested, twonew and specific formulations were developed for gas-lift applications thatdisplayed low weight loss and very little increase in viscosity. There is very little documented in open literature on the formulations and testmethodologies employed to evaluate paraffin inhibitors for gas-liftapplication. This paper describes the most important treatment parameters anddetails on how gas-lift application was performed. This includes somesignificant learning lessons on the design and implementation of gas-liftparaffin inhibitors, as well as conclusions regarding the most appropriatedeployment parameters to avoid gunking and clogging of injection systems. Italso details the specific chemistries that can and should be used for this typeof application. Introduction Paraffin Deposition from Crude Oil Crude oils naturally contain paraffinic, waxy components, defined as aliphatichydrocarbon molecules with the empirical formula CnH2n+2 (n is most commonly>18). Paraffin can exist in three forms:Macrocrystalline: these tend to be dominated by straight chained n-alkanesand are classically defined by paraffin deposits found in subsea and exportpipelines.Semi-microcrystalline: this is an intermediate form of macro- andmicrocrystalline paraffin.Microcrystalline: these tend to be cycloalkanes and branched alkanes oftenassociated with asphaltenes and other solid deposits. These are normallyencountered in tank bottoms as a sludge-like deposit. Paraffin precipitation increases the viscosity of crude oil creating higherdrag and pressure. Deposition on the walls of tubulars, flowlines and pipelinescan increase surface roughness and create a higher differential pressure. Physical restriction of the pipeline can also occur, creating less flow orincreased energy costs to maintain flow.