SPE 168186 Successful Treatment of a Green River Sandstone Formation Using a Novel Low-Polymer Crosslinked Fluid Magnus Legemah, Frances Debenedictis, Nigatu Workneh, David Smith, Hoang Le, Hong Sun, Qu Qi, Baker Hughes, Mickey Moulton, Newfield Exploration Company Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, 26–28 February 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Guar-based fracturing fluids are the most commonly used fluids in reservoir stimulation. To provide high viscosity, borate crosslinked gels are preferred for their ability to heal after mechanical shearing and their favorable environmental properties. More efficient crosslinkers capable of cross-linking fluids with reduced polymer loading have always been of great interest to reduce formation and proppant pack damage from polymer residues, and to reduce overall fluid cost. Low permeability and the interwell connectivity of Green River sandstone formations of the Uintah Basin require hydraulic fracturing treatment to economically produce oil. The most typical fracturing treatments use guar crosslinked borate fluids to transport sand into wells with vertical depths of 3500-6,800 feet and bottom-hole temperatures of 115-160ºF. Most operators in this area place emphasis on reduced polymer loadings for stimulation treatments; and even with breakers present, broken polymer residues can remain in the formation even at these reduced polymer loadings, resulting in damage and decreased production. The stimulations for these wells are flow backed at the end of the last stage. This poses a challenge of a proper balance between polymer and breaker loading, so that the fluid effectively transports up to 6 pound per gallon added (ppa) of sand into the formation without screen out, and breaks within the treatment time (30-40 minutes per stage) to minimize flow back of proppant. Recently developed novel poly-aminoboronate crosslinker (also reported in SPE 140817 and SPE 164118) was tested in the aforementioned formation. Multiple boron sites are available in the crosslinker and it is capable of interacting with multiple polysaccharide strands to form more complex crosslinking networks at lower polymer loadings than conventional guar fluids. The crosslinker with up to additional 15% reduced guar loading is capable of matching or out performing conventional crosslinked fluids in fresh water and more impressively in 7% KCl. This paper will discuss the novel crosslinker developed, the laboratory testing and successful field application. Analysis and discussion of the chemistry, crosslinking performance and economics will be presented. Introduction Hydraulic fracturing creates fractures in the formation by forcing a fluid at a rate and pressure that exceeds the parting pressure of the rock. The continued injection of the fracturing fluid expands the fractures. Upon release of the pumping pressure at the surface, proppant incorporated in the fluid is left behind and acts to prevent the expanded fractures from closing, allowing the conductive channels to remain open. Subsequently the broken fluid is flowed back from the well to clean up the formation and initiate oil production. Viscosity of the fluids is typically generated by polymers. The polymers used in fracturing fluid for reservoir stimulation are mostly polysaccharides such as guar gum. The guar molecule is composed of polymannose backbone with galactose branching with an approximate ratio of 2:1. The solubility of guar gum is greatly enhanced by the galactose branching compared to other polysaccharides. Hydrated guar and derivatives create linear gels that do not achieve the required viscosity for proppant transport at elevated temperatures. Therefore, hydrated guar gum is usually crosslinked with borates, whereas derivatized guar gums such as carboxymethyl guar (CMG), hydroxypropyl guar (HPG) and carboxymethyl hydroxypropyl guar (CMHPG) are mostly crosslinked with transition metal crosslinkers. Borate-crosslinked fluids are