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Beck, Griffin (Southwest Research Institute) | Bhagwat, Swanand (Southwest Research Institute) | Day, Carolyn (Southwest Research Institute) | Gordon, Emilio (Southwest Research Institute) | Daeffler, Chris (Schlumberger) | Malpani, Raj (Schlumberger) | Verma, Sandeep (Schlumberger) | Chaves, Leo (Chevron) | Comeaux, Bruce (Chevron) | Chrusch, Larry (Chevron) | Naik, Sarvesh (Chevron) | Renk, Joseph (National Energy Technology Laboratory)
Nitrogen (N2) and Carbon Dioxide (CO2) foams have been used as hydraulic fracturing fluids for several decades to reduce water usage and minimize damage in water-sensitive reservoirs. These foam treatments require gases to be liquefied and transported to site. An alternative approach would be to use natural gas (NG) that is readily available from nearby wells, pipelines, and processing facilities as the internal, gaseous phase to create a NG-based foam. Hydraulic fracturing with NG foam is a relatively inexpensive option, makes use of an abundant and often wasted resource, and may even provide production benefits in certain reservoirs. As part of an ongoing development project sponsored by the Department of Energy (DOE), the surface process to create NG foam is being developed and the properties of NG foam are being explored. This paper presents recent results from a rigorous pilot-scale demonstration of NG foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures.
The NG foams explored in these investigations exhibited typical, shear-thinning behavior observed in rheological studies of N2- and CO2-based foams. The measured viscosity and observed stability indicate that NG foams are well suited for fracturing applications. Like other foams, NG foam exhibits sensitivity to operating temperature characterized by a decrease in apparent viscosity as temperature increases. Rapid foam breakdown was observed at significantly elevated temperatures exceeding 290°F. In addition to fluid characterization, these investigations also yielded several key lessons that should be applied to future field demonstrations of NG foam.
Foam made with natural gas could one day help US shale producers overcome two of their sector's oldest and most inherent challenges: a heavy reliance on water supplies for hydraulic fracturing and the flaring of uneconomic associated gas. This is the big idea behind a 6-year project led by the Southwest Research Institute (SwRI) in San Antonio, Texas. The nonprofit applied-research group announced the project culminated this week with the completion of a pilot-scale system built to study how natural-gas foams perform under different pressures and temperatures. "The foam is created by jetting the natural-gas stream into the pressurized water," explained Griffin Beck, who added, "The process utilizes up to 80% less water than typical fracking treatments." Beck is the project's principal investigator at SwRI and hopes that a commercial version eventually makes it to the field one day.
This issue marks the debut of the Hydraulic Fracturing Operations feature in JPT. While hydraulic fracturing has long been a feature topic, this year, we are branching this major area of interest into both this feature and a Hydraulic Fracturing Modeling feature, which will appear in the November issue of the magazine. For this issue, reviewer Nabila Lazreq of ADNOC has selected three papers that reflect industry efforts to achieve new goals in production and sustainability. Paper 201450 investigates the potential of natural gas (NG) foam fracturing fluid to reduce the major water requirements seen in stimulation. The authors write that such requirements can be reduced up to 80% in some cases by the use of NG foams.
This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8-11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Equations for steady-state flow of aqueous foam in circular pipes were formulated from laboratory and pilot-scale experimental data. pilot-scale experimental data. These equations were incorporated into a mathematical model of foam circulation in oil wells. The model was tested in two oil wells, and predictions were satisfactory for predictions were satisfactory for engineering calculations. Accuracy of the model may be increased further by accounting for liquid holdup during foam circulation in large-diameter wells.
Aqueous foams have proven effective and economic as circulating fluids in well cleanout and drilling operations, and are becoming increasingly important for a wide range of oil field work. Information on the flow behavior of foam in oil wells is important for designing and conducting these foam operations.
Previous work on foam rheology by David and Marsden pertained to capillary tubes only, and validity of results in oil field-size systems is not known. Mitchell measured flow characteristics of foam in tubes up to 0.1 inch in diameter. Results were used by Krug and Mitchell to develop a calculation method for circulation of foam in oil wells, but no field-scale experiments were reported to demonstrate accuracy of their predictions Work published by Wenzel et al. was for larger pipe sizes, but the foam was drier pipe sizes, but the foam was drier than that normally used in oil field applications.
The foam flow equations presented herein have been tested in field-scale systems. These equations should improve the industry's ability to design and conduct oil field foam operations.
This paper presents the results of laboratory tests, performed in a mobility control foam design for Western Venezuelan Reservoirs. In this operational area, two Water Alternate Gas (WAG) injection projects are currently under way using natural gas, but they are expected to change to nitrogen.
The tests presented in this paper were performed mainly with nitrogen, although a final displacement test was designed using fluids that are currently under use in the Lagocinco VLE WAG injection project. The final goal was to achieve a mobility control foam, for gas profile modification in WAG injector wells.
The experimental work was divided in several steps: (1) preliminary screening tests for adequate surfactant selection; (2) mobility reduction tests at average Western Venezuelan conditions; (3) adsorption tests; and (4) a final displacement test in a composite reservoir core using fluids and conditions for the Lagocinco VLE Field.
The selected surfactant for the foam was an alpha oleofinsulfonate (AOS) combined with a fluorinated surfactant for added stability to oil. Surfactant-gas co-injection was used in all core displacement tests as injection scheme. The foam achieved a Mobility Reduction Factor (MRF) of 100 at average Western Venezuelan conditions, while at Lagocinco VLE conditions the MRF values were as high as 800.
PDVSA's Western oilfields were the first discovered in the country and are probably the most highly exploited reservoirs in Venezuela. For more than 4 decades, they have been under water and gas injection with recovery factors that sometimes fall below the expected values of 29 and 44% of the original oil in place, respectively.1,2 As these oil resources have approached maturity, it has become clear for PDVSA that improving recovery will only be possible through the incorporation of new and proven technologies, designed to meet specific regional needs.
Worldwide, oil recovery obtained by injecting fluids, not initially present in the reservoir, only represent 3.5 % of the world's oil production. Approximately, 82 % of this oil is obtained by steam or gas injection.3 However, oil recovery efficiency by these gas processes has not been as high as expected, mainly because not all the oil is contacted by the injected fluids.4 Gravity override and channeling are responsible for the low sweep efficiency of any gas-injection project. Additionally, early gas breakthrough in producer wells increases operational costs.
WAG processes have been commonly applied in gas floods to reduce mobility, add stability to the gas displacement front and reduce override effects caused by the domination of gravity forces over viscosity forces in highly heterogeneous reservoirs.5 However, even in these cases, early gas breakthrough and gravity unstable displacements have been evidenced as potential or mayor problems in the field.6,7
Foams, were first evaluated as a gas-blocking agent, in a porous media, by Fried8 in 1961. Since then, foams have been used in Improved Oil Recovery (IOR) processes to mitigate gravity override and channeling by reducing gas mobility. The use of foams in WAG injection projects has been documented by Hanssen et al.7 as a process that could allow a considerable improvement in the efficiency of WAG in heterogeneous reservoirs. The main advantages are associated with GOR reduction and increased oil rates. The foam diverts the injected gases into unswept areas with high oil saturation, increasing sweep efficiency and gas-breakthrough time.7
Foam in porous media reduces the gas mobility by blocking the pores through which the gas flows. It consists of individual lamellae, thin liquid films, each straddling a pore body or a throat and separated from each other at least a pore length.9 These thin films block gas flow paths where they reside.