Harding A Field Case Study: Sand Control Strategy for Ultra High Productivity and Injectivity Wells
Authors: McKay G. , Bakker E.R. , McLellan W. 
Published: March 2010

Abstract
The Harding field is the first horizontal well development by BP and partners in the highly unconsolidated Balder Massive Sandstone. The field development utilizes a TPG 500 Jack-up Drilling and Production Unit in conjunction with a concrete Gravity Base Tank (GBT), providing oil storage of 500,000 bbls. A combination of the highly permeable, unconsolidated formation with active water/gas drives and viscous oil creates a high coning potential. This means that achieving and maintaining sand free production through optimal completion design was critical to the overall success of the development.
The first phase of horizontal wells was drilled and completed for sand free, ultra-high rate production, namely up to 30,000 BOPD per well with PIs in excess of 1,000 bbl/day/psi. High rate water injectors are required for voidage replacement and pressure support. Initial injection water requirements were provided by two dedicated aquifer source wells.
This paper describes the strategy adopted and the factors considered in the development of the sandface completion design for Phase 1 of field life. The experience gained on Phase 1 has contributed to the design enhancements required for the more complex and challenging aspects of Phase II, which will include extended reach horizontal wells to neighbouring satellite pools. These enhancements have been engineered taking into account the variations in reservoir quality, physical installation challenges, and production profile requirements, in order to achieve continuing longevity and the high well PIs/IIs characteristic of the Harding Development.

Introduction
Harding lies 320 km northeast of Aberdeen in block 9/23b in the UK sector of the North Sea, at a water depth of 350 feet (see Figure 1). There are two main reservoirs: Central, which has some support from a large aquifer, and South, which has little natural pressure support. The reservoir is an Eocene submarine fan, lying between 5,300 ft. to 5,800 ft. TVDss, with porosity in the range 30 - 35﹪, permeability in the order of 8 - 12 Darcy, and a net-togross pproximately 98﹪. Recoverable oil reserves are estimated at 190 million barrels. The formations are highly unconsolidated and poorly cemented, and therefore downhole sand control is essential in all wells.
Horizontal oil producers are used to maximize recovery and minimize gas and water coning. Preventing gas coning also reduces loading on the surface separation and gas compression equipment, which was initially sized to handle a GOR of 250 -
FIGURE 1: Area map.
300 scf/bbl associated with the 64MBD design plateau. Horizontal wells have also increased well productivity and reduced well numbers, thereby increasing the cost effectiveness of the development. The reservoirs contain oil slightly above bubble point pressure, therefore water injection is required to maintain pressure support and improve sweep efficiency. To date, two deviated aquifer producers and three high angle water injectors have been completed, primarily utilizing open hole gravel pack technology. As there is currently no gas export facility, produced gas is reinjected into the top of the reservoir.
The TPG 500 platform has process facilities currently capable of handling 93,000 BOPD.