Abstract

Fluid cost saving is critical for fracturing operations in low permeability reservoirs where the production revenue is low but the job size is relatively large and the fluid cost is high. Cross-linked fluids (CLF) are usually the first option. However, they can cause significant damage to both propped fractures and formations, and they are not the cheapest option for low permeability reservoirs. Polymer free fluids, on the other hand, have much less damage but they are also expensive and may impair the economic results of fracturing, especially for low permeability reservoirs. This paper presents a new fluid system that is formulated to maximize the economic return of fracturing in low permeability shallow oil reservoirs. It is a solid free linear synthetic polymer based system with a very low formation damage characteristics. The fluids can meet a variety of fracturing requirements but they are much compared with cross-linked guar gel (CLGG). The method for designing fluid components and the procedure for preparing the fluids to achieve minimum formation damage and the least cost are described in the paper. The paper also presents the results of a comparative study where the performance of the new fluids is compared to the performance of the cross-linked guar gel (CLGG) using the data from the same well and nearby wells. Finally, examples of field applications of the new fluids with successful engineering and economic results are given. The data including geology, fluid type and fracturing operation performance results from more than 300 wells located in three different low permeability shallow oil reservoirs (800–1500 m. depth) are presented.

Introduction

Hydraulic fracturing is a necessary technique to develop low permeability reservoirs. Fluid takes a paramount role in fracturing treatments. A good fluid should have proper viscosity, higher sand laden capacity, low fluid loss, less damage to propped fracture and formation, and low cost. In most cases cross-linked fluids (CLF) can meet such requirements. However, severe formation damage is often experienced when using crosslinked guar gel (CLGG) as a fracturing fluid. The core flow tests conducted by Devine et al.[1] have shown that permeability reduction by CLGG fluid damage was 56% ∼71% to the cores of 100 ∼200 md and 12% ∼35% to the cores of less than 1md. The fluid damage to the tight sand was less severe than that of permeable formation[1][2]. A study by Almond[3] under low temperature condition (120 °F) showed that the flow reduction by CLGG fluid damage through 20/40 mesh high-grade sand (simulating fracture) could be as high as 100%. Without doubt the damage of this order of magnitude will greatly decrease well productivity after fractured whatever the damage is to the formation or to the propped fracture. Therefore, productivity impairment caused by the application of CLGG fluids could be a significant problem influencing the success of fracturing operation adversely. The cost of the fluid is another critical factor when fracturing, especially, low permeability and tight reservoirs where the job size is arge and the fluid cost is high but productivity of fractured wells is low with faster decline rate than that of fractured wells in conventional reservoirs.

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