Pin-Point Fracturing (PPF) in Challenging Formations

Abstract

Over 145 pin-point fracturing (PPF) treatments have been performed in Australia's Cooper Basin since the introduction of the technology in mid 2004. The PPF method creates perforations by pumping abrasive slurry down the coil tubing through a jetting nozzle while the main treatment is then pumped down the annulus around the coil tubing. Isolation between fracture treatments is accomplished using sand plugs (preferred method) or composite bridge plugs. Fracturing treatments in the Cooper Basin have historically been problematic due to the combination of high rock strengths (average modulus of sand/shales of 4–5 million psi), proximity to coal formations, high formation temperatures (250–400 deg F), and high fracture gradients (often above 1.0 psi/ft). Screen-outs occur in ∼40% of all treatments, so useful experience has been obtained on managing these events. This paper discusses the successful and unsuccessful experiences that have occurred using PPF techniques in these harsh situations. While PPF has improved well performance, the placement of treatments is still problematic. The paper details the experiences with varying abrasive jetting and breakdown techniques, modifying the bottom-hole assembly (BHA), changing the isolation techniques, modifying the treatment schedules, and extending PPF treatments to older wells. Introduction The Cooper Basin extends over 130,000 sq kms in the north eastern corner of South Australia and the south western corner of Queensland (see Figure 1). The basin is Australia's largest onshore producing area, currently producing 600 MMScf/day from 700 gas wells and 2,500 bbl/day from 50 oil wells. The basin is a Late Carboniferous to Middle Triassic, non-marine sedimentary environment characterized as fluvio-lacustrine, with fining upward sandstones, siltstones, interbedded shales and coals1–2. Figure 1 - Location of Cooper Basin Hydraulic fracturing has been a critical technology in the basin development over the last 40 years. To date, over 650 individual treatments have been performed. An extensive review of the fracturing history within the basin is presented by McGowen et al3. The fracturing environment within the basin is very challenging from a number of perspectives. The producing formations are between 7,500 ft and 10,000 ft, with reservoir temperatures ranging from 250 to 400 oF. Multiple reservoir intervals are found interbedded with shales and coals. Fracture gradients are between 0.6 and 1.4 psi/ft with near wellbore pressure losses up to 3000 psi. The basin was originally normally pressured with only a few isolated cases of overpressure being recorded. Depletion effects from offset well production are commonly observed in most new wells, further complicating the ability to obtain adequate fracture growth coverage. A typical well can have as much as 2,500 ft of gross interval with many fracture targets interspaced between numerous coals (see Figure 2). In this example, the PPF stages are identified with black boxes. Track 1 shows Gamma Ray, Track 2&3 shows the Calipers, Track 4 shows resistivities with separation in yellow, Track 5 shows sonic velocity, Track 6 shows gas and water effective pore volumes, Track 7 shows lithologies, and Track 8 shows 4% and 8% effective porosity pay flags.

How to Achieve and Control Branch Fracturing for Unconventional Reservoirs: Two Novel Multistage-Stimulation Processes

“…The value of this technique has been well-documented in vertical well completions , Heji et al 2006, Beatty et al 2007. The maximum number of individual fracture treatments performed on a single well to date in the USA.…”