Scale and Naphthenate Inhibition in Deep-Offshore Fields

Goldszal, Alexandre; Hurtevent, Christian; Rousseau, Guy

doi:10.2523/74661-ms

Cited by 18 publications

(20 citation statements)

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“…These changes drive the system to be more surface active, significantly changing the multiphase flow by forming foams and emulsions: the phases do not slip past each other, but embed within each other. In particular, the increase in the water pH may stabilize emulsions (Goldszal et al, 2002), and aggregation of asphaltenes and their migration to the gas-oil interface or water-oil interface may stabilize foam and emulsion formation. These mechanisms are not in conventional reservoir simulation models.…”

Section: Chemical Changes Resulting In Emulsification and Foamingmentioning

confidence: 99%

VRR < 1 Is Optimal for Heavy Oil Waterfloods

Vittoratos

West²

2013

SPE Offshore Europe Oil and Gas Conference and Exhibition

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Increasingly, the reservoirs remaining to be developed have lower gravity, particularly for the older offshore basins such as the North Sea. Optimal waterflood VRR management will be the key to their economic success. Current industry paradigms and regulatory mandates assume that the light oil practice of complete voidage replacement, VRR = 1, should be continued for the heavy oil reservoirs to be waterflooded. Empirical data, laboratory experiments, and mathematical simulation methods indicate, however, that for heavy oil waterfloods the optimal voidage replacement ratio (VRR) is less than one. Analysis of empirical data from an Alaskan heavy oil reservoir (18 API) show that after water breakthrough, periods of VRR < 1 are important for increased recovery. Laboratory data from an Alaskan heavy oil (12 API) waterflooded in a five foot long 'big can' show significantly higher recoveries with VRR < 1. Numerical simulations are directionally in agreement with these empirical & laboratory observations even when only using conventional concepts.Many more recovery mechanisms are activated with VRR < 1 than with VRR = 1. Some are readily understood with existing conventional concepts. Common geological depositional environments do not permit complete waterflood sweep, and 'cul de sacs' of unswept oil are left behind that can only be depleted with the activation of solution gas drive by VRR < 1. Less conventional concepts include the chemical changes that accompany pressure declines, that result in more surface activity and increased in-situ emulsion multiphase flow, which may self-divert to increase waterflood conformance. The numerical simulation of the VRR < 1 process is difficult and only a limited number of the mechanisms can be effectively modeled. Nonetheless, directional trends have been identified.

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Section: Chemical Changes Resulting In Emulsification and Foamingmentioning

confidence: 99%

VRR < 1 Is Optimal for Heavy Oil Waterfloods

Vittoratos

West²

2013

SPE Offshore Europe Oil and Gas Conference and Exhibition

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“…Current theory links the naphthenate formation to high total organic acid content (TAN), calcium content in the production brine, and system pH. 6,7 Several heavy crudes surveyed exhibit high TANs. However, a high TAN may not be a direct indicator that naphthenate precipitation will be a problem.…”

Section: Measurement Of Key Fluid Properties and Compositionmentioning

confidence: 99%

Technical Challenges for Offshore Heavy Oil Field Developments

et al. 2003

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This paper discusses technical challenges and technology development opportunities associated with developing and producing offshore heavy oil (OHO) reservoirs, with emphasis on projects in cold or deep waters. The paper addresses how the reservoir and fluid characteristics will impact reservoir characterization, development concept selection, well construction, reservoir performance, artificial lift requirements, flow assurance, and operations. The applicability of common onshore heavy oil practices to OHO developments will be discussed. Emerging technologies and technology development opportunities will also be discussed. The material presented in this paper will be of particular interest to technology development personnel and asset team personnel who are in the appraisal or concept selection stages of a project; however, additional information is provided which may also be valuable later in the project life.

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“…1 and are characterized by a high Total Acid Number (TAN) 1,2,5 . Formation brine is naturally saturated with CO 2 , and as the production process is carried on, a sufficient decrease in the pressure causes CO 2 degassing, leading to an increase in the pH 1,4,5,6 . Then, the rise of pH causes the formation of surface active naphthenates, RCOOanion as referred by Rousseau et al 5 , along the oil-brine interface until pH equilibrium is achieved in the system.…”

Section: Description Of Naphthenate Soap Formationmentioning

confidence: 99%

“…Production of acidic crude may create various adverse problems during oil production [1][2][3][4][5][6][7] . Crude containing high concentration of naphthenic acid frequently leads to naphthenate soap precipitation by interacting with the ions present in the reservoir brine, and cause formation damage and well productivity loss in petroleum reservoirs.…”

Section: Introductionmentioning

confidence: 99%

“…Crude containing high concentration of naphthenic acid frequently leads to naphthenate soap precipitation by interacting with the ions present in the reservoir brine, and cause formation damage and well productivity loss in petroleum reservoirs. Naphthenate soaps create problems in various forms, including emulsification and scale formation [1][2][3][4][5][6][7] . Therefore, acquiring the knowledge about the mechanism, reaction kinetics, and rate equation of the naphthenate soap precipitation is of great importance for the petroleum industry to be able to control and/or minimize the loss of well productivity due to naphthenate soap precipitation in petroleum reservoirs.…”

Section: Introductionmentioning

confidence: 99%

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