Abstract

This paper discusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis, the paper also addresses the economic value of the campaign.

Oil production from this field with complex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting off these gas zones included:

  1. Poor cement bond behind the liner shoe.

  2. Massive fractures resulting in loss circulation.

  3. Uncertainty with fractures volume estimation.

  4. Fracture shut-off in open-hole sections.

  5. Treatment execution under sub-hydrostatic conditions.

To overcome these challenges a robust chemical shut off methodology had to be innovated. This methodology consisted of the following main pillars:

  • Utilize various reservoir diagnostics tools to identify fractures and sources of high GOR.

  • Use of flowing cross-linked polymer gel combined with a ringing type of cross-linked polymer gel as a capping fluid.

  • Utilize an on-fly mixing system that enables volume and concentration adjustment as plugging progression dictates.

  • Utilize matrix diagnostics plot along with modified hall plot in real-time to continually estimate flowing gel volume.

  • Deploy a fit-for-purpose gel placement assembly for treatment under Sub-hydrostatic conditions.

Introduction

The giant fractured carbonate field was discovered in 1964 and came on stream three years later. The field has 7 reservoir layers (A to G) and multiple subunits within each layer. The upper layers A, B, C, D and E1/E2 are more intensely fractured than lower layers E3/E4, F and G reservoirs. Initial production from the reservoirs (1967 to 1970) was by natural depletion, supported by gas injection in the A reservoir unit starting 1968. After this initial period of gas injection, water injection was implemented in the A, C, D and E reservoirs (1970 to 1984). Previously unknown fracture networks in these layers resulted in rapid water breakthrough. This was followed by GOGD (Gas-Oil-Gravity-Drainage) development (1984 to 1998), which was successful in arresting the decline in the oil production. Following a simulation study in 1996, it was decided to implement a line-drive waterflood with horizontal wells in those layers considered to be sparsely fractured. Because GOGD is not effective in sparsely fractured reservoir, water flooding those layers was expected to substantially increase recovery in those layers. Since 1997, field development and operation has utilized this combination of GOGD and localized waterflood 1.

This content is only available via PDF.
You can access this article if you purchase or spend a download.