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Abstract
Many West Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. Large quantities of reserves can be found in low permeability, consolidated, formations and new techniques are being investigated to improve the economic return of completing these formations.

The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic depletion and the operator is looking for alternative production intervals.

The targeted reservoir is the 3A Sand at approximately 2200 meters TVD. The reservoir is a very heterogeneous lithology with varying quantities of siltstone, sandstone and calcite. The intervals of better porosity show a decrease in clay content, but the good “sands” can be either dominated by quartz or calcite with substantial variations with each meter of height.

Three candidate wells were selected for placing multiple propped fractures using a technique that has been used for six years in North America. This technique utilizes a series of mechanical packers and frac ports that are sequentially shifted “on the fly” allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping equipment.

During April to June of 2007, eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the Kitina Field with very encouraging production increases. During the first 90 days of post fracturing production, a production increase of 200% was achieved.

This paper will discuss the steps that were taken to place these propped fractures from an ocean going tender barge using skid equipment and recommendations for the future applications of this stimulation technique.

Introduction
The Kitina Marine offshore field was discovered in 1991 and put on production in November 1997. Originally, the field development considered the three deeper intervals:

• 2A – Limestone,
  
• 1A – Sand with carbonate cementing,
  
• 1B – Limestone.

The three reservoirs were developed via a peripheral water injection scheme and a crestal gas injection displacement process. After a quite significant initial rate (around 50,000 BOPD), the field declined quite rapidly. The recovery factors vary between 15% of the 1B reservoir to around 25-30% of the 1A and 2A reservoirs.

The platform has gas lift installed on some of the completions and others produce in natural flow. Production of the platform was 7,000 BOPD prior to the fracture stimulation.