A kinetic hydrate inhibitor based on a copolymer of vinylcaprolactam andvinylmethylacetamide has been successfully deployed in a number of fields, including both in-land and offshore applications. The inhibitor has a lowtoxicity and manages a high degree of subcooling, up to 20°F. The effectivedosage ranges from 550 ppm to 3000 ppm, depending upon the severity of theoperating condition in each field. The performance of this inhibitor, the fieldconditions in which it was applied, and the benefits are discussed in thispaper. These field cases helped establish the application technology for properdeployment of kinetic hydrate inhibitors. The success of these programs hasconfirmed the viability of using kinetic inhibitors as an effective hydratecontrol method. This kinetic inhibition technology not only provides anattractive cost-saving alternative to thermodynamic inhibitors; it alsoimproves the safety of operation while lowering the environmental impact. Introduction Formation of natural gas hydrates can present a serious problem in oil andgas production. Hydrates are crystalline, ice-like solids that form when gasmolecules are trapped in hydrogen-bonded water cages under high pressure andlow temperature conditions.1,2 These conditions are oftenencountered in deepwater operations, such as subsea flowlines carrying wetgases, and in cold-weather operations in northern climates. Formation of gas hydrates can be inhibited by several methods.1,2The principle of these methods is to control or eliminate one of the fouressential elements necessary for hydrate formation. The four essential elementsare: the presence of hydrate-forming components in natural gas (e.g., methane), the presence of water, conditions of low temperature and high pressure. Theabsence of any of these four elements would make hydrate formation impossible. For example, the element of low temperature can be removed from the equation byproper heat management techniques using external heating or thermal insulation. Similarly, lowering the pressure by choking-back the production can reduce thetendency for hydrates to form in a production system. Water, another necessaryelement in hydrate formation, can be removed by dehydration of the naturalgas. Although all of these methods can theoretically prevent hydrate formation, some may not be feasible or desirable in the field, especially in offshoreenvironments. For instance, dehydration may not be an option for offshoreoperation due to space limitations for the processing equipment. Therefore, inorder to transport the unprocessed, wet gas production streams, operators oftenrely on chemical inhibitors such as methanol and ethylene glycol. Theseinhibitors shift the hydrate equilibrium condition so that the operatingcondition falls outside of the hydrate formation region. These chemicals areoften classified as "thermodynamic" inhibitors because of their ability toshift the hydrate equilibrium curve toward higher pressures and lowertemperatures by changing the activity of water molecules. Methanol and ethyleneglycol are the most popular choices because of their low cost and widespreadavailability.

TX 75083-3836, U.S.A., fax 01-972-952-9435.Abstract Asphaltene deposition problems have been known to occur world wide, with serious asphaltene deposition problems being associated with oil fields in Venezuela, the Persian Gulf, the Adriatic Sea and the U.S. Gulf of Mexico. Until recently, these problems were resolved in producing fields by the use of chemical solvents, or by pigging, scraping or other mechanical means of asphaltene removal. Recent advances in asphaltene inhibitor technology have provided cost-effective methods of preventing deposition and, in many cases, increasing the production of the wells being treated. This paper will provide field data relating to the on-going successful asphaltene treatment programs being conducted in above-mentioned oil producing regions around the world. In these cases, large revenue increases were noted by the producers due either to an increase in production or reduced maintenance costs. The paper will detail the specific field parameters as well as the process employed for treating the systems.A cost, and return-on-investment will also be calculated for the treatments, where possible.

North Dakota Bakken oil recovery has increased nearly 100 fold over the last five years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken-producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft with horizontal laterals up to 10,000 ft and produced via multi-zone hydraulic fracturing. The operator initially conducted a typical scale prediction study in order to reduce well failures and maintain oil production. However, the scale prediction study was challenging to perform for these Bakken wells due to the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historic field conditions. A ‘post-mortem’ of data collected from all failed wells due to scale was conducted, considering the failure type, date, type of hydraulic fracturing procedure, pump intake pressure, scale inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results showed that 82 percent of the wells failed during early production (defined as less than 20,000 barrels of water produced and two years production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale inhibitor residuals due to high deposition potentials. This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, results obtained and implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.

North Dakota Bakken oil recovery has increased nearly 100-fold over the last 5 years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft, with horizontal laterals up to 10,000 ft, and are produced by means of multizone hydraulic fracturing.The operator initially conducted a typical scale-prediction study to reduce well failures and maintain oil production. However, the scale-prediction study was challenging to perform for these Bakken wells because of the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historical field conditions. A "post-mortem" of data collected from all failed wells because of scale was conducted, considering the failure type, date, type of hydraulic-fracturing procedure, pump-intake pressure, scale-inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure.Results showed that 82% of the wells failed during early production (defined as less than 20,000 bbls of water produced and 2 years' production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing-fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale-inhibitor residuals because of high deposition potentials.This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, the results obtained, and the implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.

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