Proposal
This paper details the results for 33 propped fracture treatments in low porosity zones in the South Arne field, Danish North Sea. To date, seven horizontal wells (2900 m TVD) have been completed using 100 tip screen-out (TSO) propped fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor & Ekofisk intervals range from 40m to 120m of combined thickness, with a Young's modulus and permeability that can vary from less than 0.5 MMpsi to over 2.5 MMpsi and 0.1 to 4 mD, respectively, along the horizontal section. The wide variations in reservoir and rock properties presents significant fracture design and execution challanges.
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. Counter intuitive, 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 gals containing 20,000 lbs of 100-mesh sand allowed the placement of 800,000 lbs of proppant at concentrations up to 15 ppa. However, in the lower porosity, lower permeability southern portion of the field, pad sizes of 200,000 gal containing over 100,000 lbs 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.