Phillip C. Harris

Effects of Texture on Rheology of Foam Fracturing Fluids

A new laboratory technique was developed to measure changes in foam texture (bubble-size distribution) vs. foam viscosity in a recirculating pipeline viscometer. Fluid variable studied included foam quality, surfactant type and concentration, gelling-agent concentration, shear history, system pressure, and liquid-phase chemical type. The viscous properties of foam fluids are determined primarily by quality (internal-phase volume) and liquid-phase properties. The viscosity of an equilibrated foam is influenced by texture to a lesser extent. Foams are shear-history-dependent fluids. The bubble size and degree of dispersion will adjust to an equilibrium state that depends on time at a given shear rate. Finer-texture foams are produced by higher shear rates, higher surfactant concentrations, and higher pressures. Viscosity measurements at low pressure may not adequately simulate field use at high pressure. The liquid-phase chemical type influences texture. The structure of methanol and hydrocarbon foams may result in sensitivity to degradation at high shear rates.

Dynamic Fluid-Loss Characteristics Of CO2-Foam Fracturing Fluids

High-quality CO/sub 2/-foam fracturing has recently become a very popular stimulation tool. Dynamic fluid-loss measurements were performed on a broad range of core samples to measure the effect of several parameters on CO/sub 2/-foam fluid-loss coefficients. The parameters tested were core permeability, foam quality, gelling-agent concentration in the aqueous phase, and core temperature. Measurements were performed in a recirculating fluid-flow test loop. Passage of CO/sub 2/ foams through porous media caused a significant modification in quality from the input to the effluent fluid. The ratio of liquid to gas passing through the core was measured as a function of core permeability, quality, and gelling-agent concentration. In low-permeability cores, flow proceeded as separate phases, whereas in higher-permeability cores, the foam structure remained more nearly intact. CO/sub 2/ foams were found to be very similar to N/sub 2/ foams with respect to the above parameters.

Fracturing-Fluid Additives

Fracturing-fluid additives serve two purposes: to enhance fracture creation and proppant-carrying capacity and to minimize formation damage. Additives that assist fracture creation include viscosifiers, temperature stabilizers, pH-control agents, and fluid-loss-control materials. Those used to minimize formation damage are gel breakers, biocides, surfactants, clay stabilizers, and gases. This paper discusses the qualities and applications of each of these additives.

A Comparison of Mixed Gas Foams With N2 and C02 Foam Fracturing Fluids on a Flow Loop Viscometer

A study of the rheological properties of mixed-gas foams was conducted on a flow-loop viscometer. The variables studied included different ratios of N{sub 2} and CO{sub 2} in 70%-quality foams, base gel concentration, crosslinking agent, and temperature. The rheological properties of mixed-gas foams are very similar to the rheologies of N{sub 2} and CO{sub 2} foams. This finding was anticipated, because the rheologies of N{sub 2} and CO{sub 2} foams are similar. The exact static stability behavior of these foams was not anticipated. Pure CO{sub 2} 70%-quality foams have four to five times the static half-life as pure N{sub 2} 70%-quality foams. Replacement of CO{sub 2} by N{sub 2} in a 70%-quality foam decreases the half-life of the foam. The inclusion of only 20%-quality N{sub 2} in a 70%-quality mixed-gas foam decreases the half-life of the foam. The inclusion of only 20%-quality N{sub 2} in a 7%-quality mixed-gas foam decreases the foam stability to equal a pure N{sub 2} 70%-quality foam. The authors saw no evidence that addition of N{sub 2} to a CO{sub 2} foam improved its stability. Fluid loss characteristics of mixed-gas foams were found to be the same as for N{sub 2} or CO{sub 2} foams.

Successful Field Applications of CO2-Foam Fracturing Fluids in the Arkansas-Louisiana-Texas Region

Field experience in the Arkansas-Louisiana-Texas (ArkLa-Tex) area has demonstrated that CO/sub 2/-foam systems can be used successfully in low-permeability oil and/or gas sands and carbonates at depths of 2,900 to 14,000 ft (884 to 4267 m), reservoir temperatures of 120 to 370/sup 0/ F (48 to 188/sup 0/ C), and reservoir pressures of 1,000 to 13,200 psi (7 to 91 MPa). Because of the high density of the water/CO/sub 2/ mixture, CO/sub 2/ foam can be used in deep, hot formations without prohibitive wellhead treating pressures.

Dynamic Fluid Loss Characteristics of Foam Fracturing Fluids

Dynamic fluid loss measurements were conducted on core samples ranging in permeability between 0.02 to 140 md. These tests were run to measure the effect of several parameters on the foam fluid loss coefficients. The parameters tested were: core permeability, gel concentration in the liquid phase, foam quality, temperature, core length and differential test pressure. The type of foam that is used in most conventional fracturing treatments is a wall building fluid. Although this foam has excellent inherent fluid loss properties, the fluid loss values reported in this paper more closely resemble those of conventional fracturing fluids than reported earlier. These values have been used in the successful design of field fracturing treatments.

A comparison of freshwater- and seawater-based borate-crosslinked fracturing fluids

This paper discusses the chemical factors that operators must address to successfully substitute seawater for fresh water in borate-crosslinked guar fracturing fluids. Seawater contains cations and anions that affect the performance of the fracturing fluids components, as well as the fluids interaction with the formation. Because seawater has high ionic strength, it lowers the viscosity obtained from borate-crosslinked guar. High magnesium in the water consumes hydroxide ions and affects pH control, which in turn affects the equilibrium borate-ion concentration. This paper addresses these problems and provides guidelines for borate fluid formulation to offset seawater characteristics for temperatures as high as 300°F. Borate fluids from seawater can control fluid loss (FL) as well as freshwater borate fluids. Chemical gel breakers for offshore environments have been developed to help control the viscosity reductions in fracturing fluids. Conductivity values with seawater fluids are equal to or better than freshwater fluids. The presence of divalent cations in the seawater fluid caused no harm to the FL properties or the retained conductivity with borate seawater fluids.

Fracturing Fluid Comprised of Components Sourced Solely from the Food Industry Provides Superior Proppant Transport

The industry is seeing significant pressure from regulatory bodies concerning the chemicals that comprise typical fracturing fluids. It has long been the belief of the industry that to obtain the best performance of a fracturing fluid, it is necessary to use certain chemicals in fracturing-fluid formulations. However, this paper clearly illustrates that a fluid comprised solely of components sourced from the food industry can excel in maintaining proppant-transport performance. This paper focuses on the proppant transport of a fracturing fluid that is comprised solely of components sourced from the food industry and approved for direct addition to foods as governed by the Code of Federal Regulations Title 21 (CRF 21). The proppant-transport capabilities of this fluid are compared to a borate-crosslinked galactomannan, a viscoelasticsurfactant (VES) fluid, and a linear-gelled system. The results illustrate that proppant-transport performance does not need to be sacrificed when using a fluid system comprised of components sourced from the food industry. The ability to carry proppant into the fracture is one of the most fundamental attributes necessary for a successful fracturing fluid. This paper provides an evaluation of four types of fluids currently used as gelled fracturing fluids, employing five different methods to measure their ability to transport and support proppant. The methods used in the evaluation include traditional steady-shear viscosity, small-amplitude oscillation rheology, flow-through-a-slot model, a slurry viscometer, and static settling results. The results show clearly that the testing methods and protocols do not necessarily agree on the best performance of a fluid system; a comprehensive examination of the limitations and benefits of each are examined. Some of the gels tested showed good proppant support under static conditions, while others showed good transport under flow conditions. The crosslinked gel that was sourced solely from the food industry showed a dramatic difference in that it was able to support proppant under static- and dynamic-shear conditions, leading to superior proppant-transport performance using the five test methods.

Constant-Internal-Phase Design Improves Stimulation Results

For several years, foam fracturing has been an excellent technique for stimulating low-pressure reservoirs. Conventional foam treatments, however, have been inconsistent in placing high sand concentrations and often reached a pressure limitation, which prematurely terminated the treatment. This paper reports on a design approach to foam fracturing, the constant-internal-phase technique, that has overcome previous sand limitations and has allowed treatments to be pumped with less severe pressure fluctuations. This approach treats all internal phases (gas, liquid, or solid) the same and recognizes the similarities in behavior among foams, emulsions, and slurries. A fluids bulk viscosity increases as the total internal-phase fraction increases, particularly at high internal-phase ratios. The constant-internal-phase approach has produced more predictable wellhead treating pressures (WHTPs), used less hydraulic horsepower, and virtually eliminated premature job termination owing to pressure limitations.

The Use of CO2-Based Fracturing Fluids in the Red Fork Formation in the Anadarko Basin, Oklahoma

The Red Fork formation in Roger Mills County of western Oklahoma recently has been stimulated successfully with CO/sub 2/-based fracturing fluids. Because of the very volatile nature of CO/sub 2/-based fluids, the wells appear to clean up better than wells in the same field fractured with aqueous crosslinked-gel-type fluids. Production results are given comparing the CO/sub 2/-based fluids with gelled water fracturing fluids. The stimulation of a well with CO/sub 2/ involves special engineering considerations. A plan is detailed for the successful placement of proppant in a deep formation with CO/sub 2/-based fluid.