Novel Fracture Technology Proves Marginal Viking Prospect Economic, Part II: Well Clean-Up, Flowback and Testing

Abstract

Abstract Having completed both fracture treatments as discussed in a companion paper, this paper continues on to describe the post fracture shut-in, clean-up and well testing operations that took place on the Viking Wx exploration well 49/17-12. These operations involved the removal of Resin Coated Proppant (RCP) from the wellbore, via Coiled Tubing (CT), through the use of a specially designed jetting nozzle. The RCP pack stability at a concentration of 3.0 lb/ft2 (as per planned design) had already been tested in a flowback cell. The use of a Surface Read-Out (SRO) gauge, combined with gas, water and proppant flow rates as well as the viscosity of fracturing fluids returns, enabled real time calculation of the drag forces, on the proppant pack, during clean-up. The flow rate, in the field, was controlled such that the calculated drag forces remained below those observed in the laboratory. Following the clean-up a flow and build-up test was conducted, to evaluate the fracture half length and fracture conductivity, from which a Pseudo-radial skin was calculated. The Non-Darcy effects in the fracture were also evaluated, and finally the short term and long term well deliverabilities were assessed. Introduction The Viking Wx formation is located in block 49/17-12 within the V-fields area of the Southern North Sea (SNS). When first drilled, during late November 1994, the well encountered an 830.0 ft thick Rotliegendes sandstone. However Drill Stem Test (DST) results were disappointing, with rates of only ca. 8.5 MM.scf/d, and as completed the development was not economic. Shortly after this DST test Conoco and BPX formed a fracturing team to investigate the possibility of achieving economic rates for the development via stimulation. The well was fracture stimulated in April 1995 when two stacked treatments were performed. A total of 830,000 lbs of 20/40 Intermediate Strength ceramic Proppant (ISP) was successfully placed. The RCP utilised a dual-coat curable phenolic resin with low-reactivity outer coating and fully cured inner coating. The companion paper, to this one, describes both of these fracture treatment implementations in detail. Once the second fracture treatment had been completed the well was shut-in for 28 hours, to allow the RCP to cure. Subsequently 2" CT, with a jetting nozzle, was then rigged up and Run In Hole (RIH) to remove the excess RCP material from the 7" liner. The well was then flowed for four and half days to clean-up the load fluid. The flow rate at the end of this cleanup period was ca. 43.5 MM.scf/d and 215 bwpd. A second CT run was made, followed by a spinner survey and a 180 hr flow and build-up test. Slick line was then RIH and tagged bottom indicating no proppant flow during the well test. The well was then suspended and is currently awaiting field development plans. Laboratory Tests The following Section outlines the laboratory tests that were conducted prior to the fracture treatment to help determine allowable drag forces on the proppant pack. A flowback test was conducted at anticipated bottom hole flowing conditions to evaluate the turbulence factor, Beta, in 20/40 ISP partially curable RCP and broken fracturing gel. The methodology is based around the Forchheimer equation. (1) The above equation can be re-arranged to, (2) P. 587