Constant-Internal-Phase Design Improves Stimulation Results

Abstract

Summary For several years, foam fracturing has been an excellent technique forstimulating low-pressure reservoirs. Conventional foam treatments, however, have been inconsistent in placing high sand concentrations and often reached apressure limitation, which prematurely terminated the treatment. A new designapproach to foam fracturing, the constant-internal-phase- technique, hasovercome previous sand limitations and has allowed treatments to be pumped withless severe pressure fluctuations. This approach treats all internal phases(gas, liquid, or solid) the same and recognizes the similarities in behavioramong foams, emulsions, and slurries. A fluid's bulk viscosity increases as thetotal internal-phase fraction increases, particularly at high internal-phaseratios. The constant-internal-phase approach has produced more predictablewellhead treating pressures (WHTP'S), used less hydraulic horsepower, andvirtually eliminated premature job termination owing to pressurelimitations. Introduction In the 1970's, high-quality foams were developed into a viable fracturingstimulation tool for oil and gas wells. Foam fluids, typically containing from65 to 80 vol % nitrogen gas, were noted for low damage to sensitive formationsand rapid recovery of treatment fluid. Early foam treatments were limited inproppant concentrations (2 to 3 lbm/gal) as a result of blender and pumpdesigns. By the early 1980's these limitations had generally been overcome, andhigher proppant concentrations (5 to 7 lbm/gal) in the foam could be achieved. Laboratory data were generated to meet engineering requirements for stimulationdesign computations. King reviewed foam-fluid history and discussed how foamfluids gained a reputation as a standard fracturing fluid, much like linear gelor crosslinked gelled fluids. High-quality CO2-foam fluids were introduced in1982. Since the 1950's, 5 to 50% CO2 had been used to provide gas-assistedfluid recovery. However, the use of 65 to 80% CO2 caused a significant boost inviscosity for carrying proppant into a formation. In addition to the otheradvantages of N2-foam fluids. CO2 foams provided better compatibility withformation fluids, lowered interfacial tension, and provided greater foamstability and generally lower pumping pressures because of its higher density. The greater solubility of CO2 in formation fluids provides gas assist to formations having lower pressures, thus enhancing fluid recovery. The advantageprovided by the high density of CO2 was realized when 70%-quality foamtreatments were pumped down casing at significantly lower treating pressuresthan needed for similar N2 foam treatments. The application of CO2 foamsallowed treatments to be pumped into deeper, hotter formations than practicalwith N2 foams. CO2 foams pumped at high rates down small-diameter tubing, however, often produced excessive treating pressures. During such foamstimulations with either CO2 or N2, the treating pressure would often increaseas proppant was added until the maximum allowable pressure was reached. Although operators on location often perceived a "sandout" frequentlyno evidence was found after the treatment. The problem usually resulted fromhigher-than-expected friction pressure, which caused operators to believe thata sandout was imminent, so treatments were prematurely terminated. Foam Structure The observation of high friction pressures for CO2 foams pumped down smalltubing required re-examination of the structure of foam fracturing fluids. Fornonfoamed fracturing fluids, when proppant is added to the fluid, the proppantcauses no major change in the viscous character of the fluid. Foam, however, isa two-phase structured fluid, consisting of a gaseous "internal" phaseand a liquid "external" phase. Discrete gaseous bubbles are surroundedby a continuous, thin liquid coating. The viscosity of the foam fluid is afunction of the foam quality, as shown in Fig. 1. "Quality" is theratio of gas volume to gas-plus-liquid volume at a specific temperature andpressure. A similar relationship exists for two-phase liquid/liquid emulsions. As the percentage of internal phase increases in a two-phase fluid, the fluidviscosity increases. When a solid proppant particle is added to a two-phasefoam, it is readily apparent that a solid particle cannot become part of thecontinuous liquid phase. Rather, it must exist as a discrete entity, alongsidethe gas bubbles. Because the solid particles occupy volume, they produce theeffect of increasing the quality and hence the viscosity. Although the addition of proppant to a nonfoamed gelled fluid may increase viscosity slightly, addingit to a high-quality foam will cause a larger increase in viscosity. Forexample, addition of 1-lbm/gal sand to a 40-lbm/1,000-gal linear gel willincrease the viscosity by 5 cp at 100 seconds(-1). Addition of 1-lbm/gel sandto a 70%-quality, foamed, 40-lbm/1,000-gel will increase the viscosity by 14 cpat 100 seconds(-1). To maintain a constant-viscosity fracturing fluid, thebalance between the internal and external phases must be kept constant, hencethe term "constant internal phase". Fig. 2 illustrates the concept of constant internal phase. Fluid A is a conventional foam pad fluid (no proppant)containing a field volume of gas and liquid. Fluid B is a proppant-laden fluidwith solid added while gas and liquid volumes are held constant. During afracturing treatment, these volumes are pumped in a given time, so the ratiosalso relate to pumping rates. The volume of internal phase (gas plus solid) in Fluid B is greater than that of Fluid A, although the liquid is constant, andwould result in higher viscosity and a higher downstream rate. This conditionhas often led to excessive friction losses, higher wellhead pressures, andpremature job termination. An attempt to reduce solid, liquid, and gas ratesproportionally to make the downstream rate the same as the pad does not solvethe overall problem. Although the ratios in Fluid C are the same as in Fluid B, the internal phase ratio of Fluid C is higher than that of Fluid A, so theviscosity of Fluid C is higher than that of Fluid A and will give higherfriction pressure. In addition, adjusting all three ratios increasesoperational difficulty. An example of the viscosity increase caused by proppantaddition may be calculated. Addition of 5-lbm/gal sand to a 70%-quality foamcontaining 40-lbm/1,000-gel base gel will increase the internal-phase fractionto 75.6%. The apparent viscosity of the fluid will increase from 325 to 4 45 cpat 40 seconds(-1). A solution was proposed to keep both downstream flow rateand viscosity constant. When solid proppant is added, a constant liquid rateshould be maintained but the gas flow rate should be decreased sufficiently toequal the absolute solid flow rate. Application of the constant-internal-phaseconcept has allowed much better control of foam fracturing treatments downsmall tubing, especially with CO2.