Summary
This paper details the results for 33 propped-fracture treatments in
low-porosity zones in the South Arne (SA) field, Danish North Sea. To date,
seven horizontal wells (2900 m total vertical depth [TVD]) have been completed
using 100 tip screenout (TSO) propped-fracture treatments containing 70 million
pounds of proppant. The target oil bearing Tor and Ekofisk intervals range from
40 to 120 m of combined thickness, with a Young’s modulus and permeability that
can vary from less than 0.5 to over 2.5 million psi and 0.1 to 4 m,
respectively, along the horizontal section. The wide variations in reservoir
and rock properties present significant fracture design and execution
challenges.
Results indicate that propped-fracture treatments become increasingly more
difficult to place as porosity decreases, and this problem is primarily
attributed to higher natural fracture/fissure density in the lower-porosity,
higher-modulus zones. Production data indicate that these natural fractures or
fissures do not measurably contribute to productivity, but can be “activated”
under fracturing conditions. Contrary to intuition, pad size and fluid-loss
additives must be increased and maximum proppant concentration decreased in
low-porosity (low-permeability) zones. In the higher-porosity,
higher-permeability northern portion of the field, pad sizes of 35,000 gal
containing 20,000 lb of 100-mesh sand allowed the placement of 800,000 lb of
proppant at concentrations up to 15pounds of proppant added per gallon of fluid
(ppa). However, in the lower-porosity, lower permeability southern portion of
the field, pad sizes of 200,000 gal containing more than 100,000 lb of 100-mesh
sand were required to place similar proppant volumes, with concentrations
limited to 8 ppa. This paper summarizes field data from 100 treatments,
illustrating the design changes necessary to place propped-fracture treatments
in low-porosity chalk reservoirs. The paper documents the relationship between
chalk porosity, fluid efficiency, and treatment design.
Introduction
The SA field is located in the northern part of the Danish sector of the
North Sea (Mackertich and Goulding 1986). The structure is an elongated
Cretaceous inversion ridge situated on the western margin of the Tail-End
graben. The reservoir rock is high-porosity/low-permeability chalk of
Maastrichtian and Danian age, comprising the Tor and Ekofisk formations,
respectively. A hard, low-porosity interval at the bottom of the Ekofisk
formation separates the two formations. Tor formation permeabilities range from
0.2 to 4 m, whereas the Ekofisk formation permeabilities range from 0 to 0.7 m.
Virgin reservoir pressure is 6,300 to 6,400 psig, and reservoir temperature is
240˚F (9,425 ft TVD). The reservoir is moderately to highly naturally fractured
(Mackertich and Goulding 1986). The combined thickness of the Ekofisk and
Tor reservoir varies from 40 to 120 m.
The SA field is being developed using horizontal wells with multiple
hydraulic fracture treatments. Fig. 1 shows the reservoir layering and typical
values for closure stress, porosity, and thickness for each reservoir section.
The horizontal section targets the Tor formation and is typically about 1800 m
in length (Derbez and Moos 2000). The completion method allows each zone to be
mechanically isolated from the rest during both stimulation and production
(Andersen et al. 1988; Owens et al. 1992). The work string is used for
perforating, stimulating, and isolating the individual zones (Damgaard et al.
1992). The annulus between the work string and the liner is open during
stimulation, providing excellent bottom-hole pressure (BHP) measurements using
the static annulus pressure. There are typically 10 to 15 propped-fracture
treatments performed in each horizontal well.
The direction of maximum horizontal stress is approximately northwest to
southeast. The well trajectories and the location of the propped- and
acid-fracture treatment stages are shown in Fig. 2. A limited number of
acid-fracture treatments were performed in lower-porosity and/or thin
intervals, but the majority of the stimulations were propped-fracture
treatments. The majority of wells were drilled in the approximate direction of
hydraulic fracture growth, with the exception of Well 1, resulting in fractures
that are nearly parallel to the horizontal wellbores.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
19 May 2004
- Meeting paper published:
18 February 2004
- Revised manuscript received:
5 June 2006
- Manuscript approved:
5 June 2006
- Version of record:
20 February 2007
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