Abstract

The control of inorganic scale deposition within the reservoir under both natural depletion and injection water support has been a challenge to the oil industry for a number of decades. The challenge has remained identifying the location of water breakthrough within the production interval and the subsequent injection of scale inhibitor into these zones to prevent scale formation within the near welbore and production tubing. As completion technology has advanced, and more complicated completions have been developed and installed to increase the rate of oil recovery, the challenges of water management and scale control have become significant factors if long term production from these wells is to be maintained.

This paper will outline the challenges of chemical deployment via bullheading into subsea wells completed in high permeability reservoirs with sand control technology. The factors considered when designing a self-diverting scale inhibitor system will be outlined in terms of viscosity profile of the chemical and overflush fluid, impact of temperature on fluid viscosity, pump rate, shear effects, tubing diameter vs. wellbore friction and the impact of radial flow on viscosity. Modelling data from vertical and horizontal production wells will be used to illustrate the challenges that pump rate changes and a self-diverting scale inhibitor system has to overcome to allow effective deployed of scale inhibitor without the need for coiled tubing in long (500ft to 3,000 ft) wells in 2 Darcy reservoirs.

The value of this technology in terms of the economic factors will be outlined with field examples where coiled tubing and bullhead applications will be compared and contrasted to illustrate the value in terms of total cost of operation that the self-diverting technology can offer.

Introduction

The process of applying scale inhibitor squeeze chemical to production wells to control the onset of inorganic scale within the near-wellbore and production tubing has been a common practice within the onshore and offshore oil/gas industry for over 30 years.

The typical stages of a scale inhibitor squeeze are as follows. In general the process comprises pumping a preflush solution (0.1% inhibitor in KCl or seawater) followed by the selected scale inhibitor normally in the concentration range of 5 to 20% v/v in KCl or seawater, and overflush stage (using inhibited seawater or KCl) followed by a shut-in period where the inhibitor chemical is adsorbed or precipitated onto the reservoir rock before the well is flowed back into test separator and then main process.1–4

There are two principal types of retention mechanism that exist within a reservoir. One process is the adsorption process which is a physical/chemical adsorption/desorption interaction of the scale inhibitor molecule with the reservoir mineral surfaces.5–9 The amount of adsorption is a function of the chemical type, formation water composition, formation water pH, application pH, reservoir wettability and reservoir mineralogy (principally clay types and abundance).7–9 The precipitation mechanism is the second type of squeeze process whereby the scale inhibitor is adsorbed and then precipitated onto mineral surfaces.10–13 The precipitation process is controlled by inhibitor chemical type, application pH and divalent ion level within the precipitation formulation.12,13 The life of a precipitation squeeze treatment can offer advantages over an adsorption treatment as the squeeze life for a particular system, principally those that require high (>15 ppm) minimum inhibitor concentration (MIC) values, can be extended. This extension in lifetime for the lower concentration region is not always observed.6

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