The Use of Scale Dissolver and Scale Inhibitor Squeeze Treatments to Repair and Prevent Formation Damage in Two Statfjord Field Wells

Lejon, K.; Vikane, Olav

doi:10.2118/31126-ms

Cited by 14 publications

(2 citation statements)

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“…After seawater breakthrough, both sulphate and carbonate scale has been identified in the near well bore areas and tubing. 1,2,3 More recently scale build up in the 7" re-entry guide was confirmed during caliper logging in June 2003 in one of the wells. Severe scale build up was detected in the wire line reentry guide, which prevented access to the formation interval.…”

Section: Introductionmentioning

confidence: 91%

Field Experiences in the Application of an Inhibitor/Additive Interaction Package To Extend an Inhibitor Squeeze Life

Chen¹,

Vikane

Asheim

et al. 2006

Proceedings of SPE International Oilfield Scale Symposium

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince the middle 1980s, seawater breakthrough has been observed for a number of wells in a major offshore Field operated by Statoil. This Field has also several tie-ins. Both sulphate and carbonate scale deposition has been identified in the near well bore area and tubing. Inhibitor squeeze treatments were regularly carried out to prevent wells from damages due to scale precipitation.The conventional phosphonate scale inhibitor (DETA-phosphonate) was often used. Some of the sandstone formations in the oil field are relatively "clean" with very little amount of clay materials i.e. Etive and Tarbert formation. As a result, a relatively short inhibitor squeeze life was seen in these formations after the squeeze treatments with a phosphonate scale inhibitor. Other reservoirs had acceptable squeeze life, but due to environmental requirements a wide set of inhibitors was studied.In order to reduce the well intervention frequency and extend an inhibitor squeeze life, a method involving a polymer interaction between a polymer scale inhibitor and polymer additive has been developed. In addition to the enhanced adsorption; attributed by the surface charge modification by the adsorption of the positively charged polymer additive on the sandstone surface, the interactions between polymer inhibitor and additive further increase the inhibitor retention in the formation. This polymer interaction approach is different from a conventional precipitation squeeze where calcium chloride was used. Also, unlike the conventional precipitation squeeze, the polymer additive can be pre-injected and rapidly adsorbed onto a rock surface. The subsequently injected inhibitor will react with the additive on the rock surfaces, resulting in a precipitation on a rock surface. This avoids the bulk precipitations where a permeability reduction was often caused by a conventional precipitation squeeze. During the production, the precipitated polymer inhibitor was released through a hydrolysis process.This paper presents a detailed method and field results based on the treatments using the polymer inhibitor and additive package in the oil field. The application of polymer interaction package significantly improved the inhibitor squeeze life. Satisfactory results have been achieved from the field trials. The unique polymer reaction package satisfies the stringent Norwegian environmental regulations of low toxicity, high biodegradation and low bioaccumulation.

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Section: Introductionmentioning

confidence: 91%

Field Experiences in the Application of an Inhibitor/Additive Interaction Package To Extend an Inhibitor Squeeze Life

Chen¹,

Vikane

Asheim

et al. 2006

Proceedings of SPE International Oilfield Scale Symposium

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“…Certain commercial sulfate scale dissolvers based on amino-carboxylic acids, such as EDTA and DTPA, have been shown to lead to the successful dissolution of barium sulfate when applied appropriately. [6][7][8][9][10][11][12][13][14][15] In such treatments, the dissolvers may be deliberately injected into the near-wellbore formation to remove scale which has formed there. 7,10,12,14 However, in addition to causing reservoir stimulation, these packages also have the potential to cause mineral dissolution and formation damage.…”

Section: Introductionmentioning

confidence: 99%

Scale Dissolver Application: Production Enhancement and Formation-Damage Potential

Jordan

Graham

Matharu

et al. 2000

SPE Production &Amp; Facilities

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Sulfate scale dissolvers have been applied downhole for many years to remove barium and mixed sulfate scale deposits from the wellbore and from the near-wellbore formation. As well as dissolving mineral scales, these corrosive materials also have the potential to cause some degree of formation damage by the dissolution of reservoir minerals. In this study, three commercial scale dissolver formulations and two laboratory prepared amino carboxylic acid dissolvers ͑EDTA and DTPA͒ were tested to assess their comparative capacity to dissolve barium sulfate and, of more importance in the current study, their potential to cause damage in the near-wellbore formation. The potential formation damage capacity of various scale dissolvers has been assessed by measuring the levels of cation release in static tests on mineral separates and by studying the various effluent profiles from core floods using reservoir sand. Possible damage mechanisms include silicate dissolution, fines generation/migration, mechanical strength reduction and wettability changes. We conclude that, when testing sulfate scale dissolvers for field application, their formation damage potential should be assessed as well as their barite dissolution performance.

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The Evaluation of Enhanced (Carbonate/Sulfate) Scale-Dissolver Treatments for Near-Wellbore Stimulation in Subsea Production Wells, Gulf of Mexico

et al. 2006

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Dissolver technology has been developed and applied with varying degrees of success over the past few years to clean carbonate and the more challenging sulphate/sulphide scales from production tubing and process equipment. The intention of this proposed application was to select a chemical that could be applied into the near wellbore region of the reservoir to recover scale induced damage while not creating any secondary precipitation or negative wettability effects. The impact of dissolver chemical formulation on the reservoir formation's wettability and the potential for mobilization of fines (both reservoir silicate and scale) has not been outlined before. In this paper reservoir condition coreflood studies are outlined where scale is formed within the cores to allow assessment of sulphate dissolver performance. This will form a critical part of the technical evaluation of the dissolver formulation suitability for field application. Results from these coreflood studies will be compared to those generated for the same chemicals in conventional static dissolver studies. The practical concerns about deployment methods within subsea production wells are also emphasized. Specific reference will be made to the impact of metallurgy on chemical selection and the need to reduce corrosion risk within developments which utilize both carbon steel and super duplex requiring the development of higher pH non acid carbonate dissolvers. This paper shows that simple dissolver tests can give misleading performance information as they only show dissolution rates, impact of concentration of active chemical or the increased dissolution possible with solvents. The use of pre scaled reservoir cores to assess the impact of dissolver performance and the potential for secondary formation damage allows the most effective dissolver with minimum formation damage potential to be selected for field application. Introduction. Oilfield scale formation and control. The precipitation of insoluble mineral scale deposits (scaling) is a common cause of near wellbore formation damage during the production of hydrocarbons and associated produced water. Precipitation of scale can occur within the formation, near wellbore or in the production tubing. The physical obstruction/restriction caused when scale is deposited within the near welbore and production tubing can lead to sever reduction in near wellbore permeability and reduce the internal diameter (ID) of the production tubing. The reduction in flow area can significantly increase flowing bottom hole pressure and reduce production rates. Two mechanisms of scale formation are commonly encountered. Carbonate scales (Calcite CaCO3, Siderite FeCO3) can be formed when pressure or temperature changes in a flowing fluid leads to the break out of dissolved carbon dioxide which is accompanied by the scale deposition. The mixing of incompatible brines can lead to the formation of sulphate scales. The common sulphate scales include Barite BaSO4, Celestite SrSO4, Anhydrite CaSO4 and Gypsum CaSO4.2H2O though of most concern with seawater injection is Barite owing to its very low solubility[1–4].

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The Use of Scale Dissolver and Scale Inhibitor Squeeze Treatments to Repair and Prevent Formation Damage in Two Statfjord Field Wells

Cited by 14 publications

References 0 publications

Field Experiences in the Application of an Inhibitor/Additive Interaction Package To Extend an Inhibitor Squeeze Life

Field Experiences in the Application of an Inhibitor/Additive Interaction Package To Extend an Inhibitor Squeeze Life

Scale Dissolver Application: Production Enhancement and Formation-Damage Potential

The Evaluation of Enhanced (Carbonate/Sulfate) Scale-Dissolver Treatments for Near-Wellbore Stimulation in Subsea Production Wells, Gulf of Mexico

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