Modelling Drawdown Induced Salt Precipitation in Gas Producing Reservoirs: A Field Case Example

Oluwatosin Matthew Ogundipe, Eric James Mackay

Research output: Chapter in Book/Report/Conference proceedingConference contribution

Abstract

Halite scaling in natural gas production systems may cause formation damage, particularly in zones immediately surrounding the well and perforations. The clogging of flow paths has induced the loss of productivity (and injectivity in CO2 injection wells) and, in some cases, total abandonment of wells. This paper captures the process of drawdown as the main driver of the salt precipitation phenomena under specific field conditions.

Calculations were performed using reactive transport compositional reservoir simulation software to model the impact of drawdown on the change in water solubility in the gas phase during low water-cut gas production in a specific field. 1D and 2D radial models with small near-well blocks and large outer blocks were developed to account for water vaporization at irreducible and mobile water saturations, considering capillary pressure effects (horizontal and vertical imbibition) and gravity segregation. Changes in the values of critical parameters such as absolute permeability, production rate, and initial reservoir pressures were inputted to test their impact on salt precipitation.

Calculations confirm that the steepest pressure gradients occur closest to the wellbore. Consequently, there is an increase in water solubility in the methane as the gas approaches the well, which causes an increase in the rate of evaporation and a greater propensity toward drying out in the near-wellbore region. For the 1D model at irreducible water conditions, the dry-out zone increases as the permeabilities, and initial reservoir pressures decrease. In contrast, there is reduced salt deposition as the production rate is reduced. Under mobile water conditions and horizontal imbibition, the dry-out zone is extended, but only a slight increase in formation damage occurs. Horizontal imbibition causes an increase in pressure gradient because it reduces gas mobility. The Kozeny-Carman porosity-permeability relationship meant a 16% reduction in porosity resulting in a ~35% reduction in permeability near the well. The 2D modelling suggests a similar trend to 1D, but with a much stronger localized effect in the lower parts of the well due to vertical imbibition, resulting in up to 95% porosity loss locally. In contrast to the horizontal imbibition, this is due to the vertical imbibition causing a greater mass of salt to be transported into the dry-out zone.

The information presented in this study provides a platform for operators by which the theory and concepts underlying salt precipitation may be better understood. Improved reservoir management decisions may then be made, and methods of optimally producing the wells in this field could be adequately deployed. Depending on economic considerations, reducing flow rates and managing well bottom hole pressures could be considered, in addition to the application of wash water treatments whilst the problem remains localized.
Original languageEnglish
Title of host publicationSPE International Conference on Oilfield Chemistry 2023
PublisherSociety of Petroleum Engineers
ISBN (Print)9781613998748
DOIs
Publication statusPublished - 21 Jun 2023
EventSPE International Conference on Oilfield Chemistry 2023 - The Woodlands, Texas, USA
Duration: 28 Jun 202329 Jun 2023

Conference

ConferenceSPE International Conference on Oilfield Chemistry 2023
Period28/06/2329/06/23

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