Novel Fracture Technology Proves Marginal Viking Prospect Economic, Part I: Implementation of Fracture Treatments
Authors: Rylance M. , Haidar S. , Sykes G. , Pyecroft J. 
Published: December 2007

Abstract
This paper describes the implementation of a twin propped fracture stimulation treatment, carried out on the 49/17-12 exploration well of the Viking Wx structure, in the Southern North Sea (SNS). Initial appraisal of the potential field development was disappointing, the well flowing at a rate of only 8.5 MM.scf/d, indicating a field development to be uneconomic. Stimulation by a joint Conoco/BPX team, employing novel fracturing technology, provided dramatic increases in production to ca. 43.5 MM.scf/d with less applied drawdown. The design approaches employed during these treatments could have potential for widespread application to other SNS gas fields.
In this paper critical pre-treatment testing and reasoning behind operational decisions are discussed. In a companion paper the post stimulation rates/testing and well clean-up are described. Several key aspects of these treatments included: the use of two stacked fractures in order to successfully place proppant across the entire 830 ft reservoir section; the use of a Step Down Test (SDT) to identify the nature of high near wellbore pressure losses and subsequent removal using sand slugs; the use of a newly developed dual-coat partially curable Resin Coated Proppant (RCP) product, never previously utilised in the field, to minimise the opportunity for prolonged proppant back production and a seawater Mini-Frac to attempt to help identify the true in-situ permeability. Finally, the use of a Surface Read-Out (SRO) gauge enabled real-time decision making to optimise the treatment schedule.

Introduction
The Viking Wx formation is located in block 49/17 within the V-fields area of the SNS. When first drilled, during late November 1994, the exploration well 49/17-12 encountered the Rotliegendes sandstone at 8,591 ft.MD(RTKB). At this location the gas bearing sandstone was ca. 830 ft thick. Open-hole logs indicated that the best reservoir quality was located between 9,040-9,160 ft.MD(RTKB).
The well was initially perforated and tested across the 9,040-9,160 ft.MD(RTKB) interval, in order to assess the potential productivity from this zone. The poorer quality Rotliegendes reservoir section was not completed because interpretation of the Drill Stem Test (DST) would have been confused and potential future well operations may have been complicated.
The results from the DST were very disappointing, and from an initial rate of ca. 14.5 MM.scf/d the productivity fell quickly away to 8.5 MM.scf/d within 24 hours, at which point the well was shut-in. Several different interpretations of the DST were made, including one that indicated the possibility of two no flow boundaries forming a flow restriction/baffle either side of the well. The well was then suspended for potential re-entry.
Conoco and BPX then cooperated closely and formed a fracturing team, with a view to examining the possibility of re-entering the well and carrying out propped hydraulic fracturing operations. The group provided a feasibility study which indicated that successful fracture stimulation was possible but that there were some technical challenges to be overcome. These included the necessity to carry out two stimulations to ensure full zonal coverage and the need for long term proppant free production.

Well and Reservoir Data
The following Section outlines the information acquired, prior to the implementation of the fracturing treatments, concerning the reservoir and completion properties for 49/17-12. These properties were assumed for all of the calculations regarding potential productivities that were contained in the original feasibility study.
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