Paraffin deposition, resulting in productivity loss of newly completed wells, is a major source of formation damage and is operationally and financially critical to address with a proven solution. Paraffin inhibitors included in the stimulation treatment have limited long term success due to cost and limitations on the amount of inhibitor that can be added to provide the desired longevity. A dispersion based paraffin inhibitor adsorbed on a high surface area substrate was developed which is compatible with fracturing fluids and affords a long term, cost effective solution to the paraffin deposition problem. Laboratory studies were conducted under simulated field conditions, and the effect of inhibitor on oil properties (pour point, cold finger) as the oil is treated in the proppant pack with adsorbed paraffin inhibitor was investigated. Oils with different paraffinic issues were analyzed in this study. The studies estimate the longevity of treatment and the improvement expected using this treatment for field applications using flow-through column tests. Traditional paraffin inhibitor treatments have provided limited long term performance in wells with paraffin issues. Little protection is provided beyond the perforations when continuously treating into the production fluids through capillary injectors. Additionally, squeeze treatments designed to increase the chemical's contact area by forcing the chemical treatments deeper into the reservoir give limited longevity in high paraffinic wells. In the current study, a novel treatment results in greater amounts of inhibitor placed downhole for prolonged treatment. A combination treatment was recommended whereby a compatible submicron-sized paraffin inhibitor dispersion is added to the fracturing fluid. In addition, a dispersion based paraffin inhibitor was adsorbed onto a proppant-like substrate that can be mixed into the proppant and delivered deep into the formation with fracturing or refracturing treatments, providing enhanced flow assurance management.

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 115-160°F. 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.

Current seawater fluid systems were designed to reduce the usage of fresh water and the number of trips needed to transport the water. The composition of such fluids needed gel stabilizers to reduce the negative effects high salinity waters have on fluid performance. However, in solving one problem, another potential problem may have been overlooked. Sea water when met with the formation waters can cause scale production and formation damage. The damage is often worse when wells are shut in for extended periods of time. This paper will discuss the evaluation of a scale inhibitor package for immediate and long-term scale protection that can be delivered in the seawater fracturing operation without detrimental effects to fluid performance. Traditional and nontraditional screening methods were used to demonstrate the longevity of the scale inhibitor additive. Evaluation studies consisted of inhibitor compatibility studies, static bottle testing, and fluid rheology compatibility testing. Inhibitor compatibility studies were conducted to determine the inhibitors efficacy in high calcium environments at the pH of the fracturing fluid. Static bottle longevity testing was completed over 6 weeks using various inhibitor concentrations to optimize the scale inhibitor loading across varying seawater to formation water ratios. Fluid rheology studies were performed to determine compatibility with the inhibitor. Various loadings of the scale inhibitor were evaluated to determine the best loading across varying ratios of seawater to formation water. The scale inhibitor demonstrated that it could effectively inhibit calcium and barium scale formation for at least 6 weeks. Results were confirmed with ICP testing showing more than 80% of the cations in solution as per industry standard. The scale inhibitor had no determinantal effects to the fracturing fluid stability compared to the baseline. The data clearly shows the potential of using a scale inhibitor package with a seawater based fracturing fluid to fracture the formation while simultaneously inhibiting any scale formation. The inhibition was shown to last a minimum of 6 weeks at temperature to simulate shut in. The novelty of this scale package is to decrease use of fresh water and carbon footprint while providing long term prevention of scale through scale control additives. The optimized fluid and additives can provide enhanced management and protection from damaging scale deposition in HTHP wells later in the life of the well.

Conventional asphaltene inhibitor treatments prevent asphaltene deposition in the production string and near the wellbore. However, these liquid injection treatments provide little to no protection deep into the reservoir. A new proppant like slow release asphaltene additive that is mixed with the proppant provides the possibility for long term flow assurance without conductivity impairments. This substrate allows more chemical to be transferred bottomhole resulting in longer treatments. Traditional and nontraditional screening methods were used to demonstrate the longevity of the intermediate strength proppant like slow release asphaltene additive. The additive release profile was evaluated in a mixture with proppant and using untreated crude oil. Long-term protection was then determined. Furthermore, the proppant like substrate was characterized for its proppant like characteristics using API standards. Conductivity studies, to ensure the additive did not affect the proppant pack negatively, and fracturing fluid compatibility were also performed. The results show that the proppant like slow release asphaltene additive has no conductivity losses at increased loadings and can provide a cost effective long-term flow assurance solution and can be used in the same range than an intermediate strength (ISP) proppant. Significant numbers of Gulf of Mexico (GoM) wells experience closure stresses in the range for the ISP product, opening up the possibility of using this product in this stress regime. Presence of asphaltene inhibitor in the deepest part of the fracture allows release of the chemical and resulting in reduction of precipitates and lowered conductivity damage to plugging. Controlled release of the chemical from the ISP like substrate allows only a certain amount of chemical needed for inhibitor control, preserving the rest of the inhibitor for subsequent release. The incorporation of a delay mechanism in the slow release asphaltene additive will provide increased protection as the well ages. This method allows longer protection time and affords a more cost-effective treatment.

The Bakken formation is one of the largest unconventional oil plays in the United States, and large-scale hydrocarbon recovery from this formation has only recently become economically feasible as technological advancements have reduced stimulation costs. These low-permeability zones must be fracture-stimulated with large fracture networks for enhanced well production and improved economics. Guar-based fracturing fluids are the most commonly used in stimulation treatments. Cross-linked fluids with low polymer loading and high viscosity are needed to transport proppant efficiently. However, due to the tight shale formation, efficient proppant pack cleanup is critical to minimize polymer residue. The breaker systems include coated and uncoated oxidative breakers with an enzyme breaker added during the tail-in stages to break down the viscosity and aid in fracture fluid cleanup. In the field, oxidizers were found to perform inconsistently at some temperatures, and the conventional enzymes were inefficient at higher pH and temperatures. To improve reliability, a novel enzyme breaker was field-tested in early 2010 and proven to function more consistently and enhance post-stimulation productivity. In late 2012 and early 2013, this new enzyme breaker was implemented in multiple fields and consistently yielded similar results as the field trials. The enzyme breaker is a polymer-specific, thermostable mannanohydrolase, genetically modified for increased conformational stability. This enzyme breaker can be used from ambient temperatures to ≥ 250°F and functions well at an elevated pH of 11.0, whereas conventional enzymes are inefficient under these conditions. Production results from several wells were compared with offsets that had been treated with the conventional fluid system and breaker package. The wells treated with this new enzyme breaker showed higher increase in oil production. This demonstrated persistence of this new enzyme to improve breakdown of the polymer and enhance cleanup of the proppant pack which resulted in enhanced oil production.