The primary function of fracturing fluids is to provide the means and media for the transport and placement of a conductive proppant pack in the created fracture such that resident hydrocarbons may be more easily produced. In recent years significant effort and expense has been invested to develop an ideal fracturing fluid system. Such efforts have been often been akin to the proverbial dog chasing his tail, rather than on the addressing the engineering objective to place a conductive propped fracture. Development focus has been primarily on optimization of fluid rheological stability to get the treatment pumped and secondarily to mitigating any damage caused by new fluid system. Post-frac production analysis frequently demonstrates less than anticipated fracture area, suggesting excessive proppant-pack damage or that the proppant was not placed in designated areal location due to inadequate proppant transport. Recent testing was conducted in a large-scale slot apparatus at the Well Construction Technology Center in Oklahoma to evaluate the relative effects of proppant slurry component characteristics and the proppant transport capability. The effects of various fluid specific gravities, fluid viscosities, proppant specific gravities, proppant sizes, slurry flow rates, and slot widths were investigated. Testing included fluids from slickwater to gelled, weighted brines, proppants from 40/70 Ottawa sand to 14/30 ultra-lightweight proppants, pump rates from 0.1 to 1.0 bbl/ft/min, and slot widths from 0.25 to 0.5″. Evaluation of the proppant transport testing data and the comparative abilities of current fracturing slurry system technologies to achieve placement of a productive propped fracture will be discussed. Introduction and Background Hydraulic fracturing may be characterized as a complex process involving pumping highly pressurized fluid into a well to create fractures in a subterranean formation[1–3]. The resultant fractures provide flow pathways radiating laterally away from the wellbore. Proppant is placed in the created fractures to ensure that they remain open once the treating pressure is relieved, thus providing the desired highly conductive pathways to increase the productivity of an oil or gas well completion. Optimization of conductive fracture area is among the principal tenets of fracturing design engineering. The conductive fracture area is defined by the propped fracture height and the effective fracture length. The productive intervals are typically bounded by relatively non-productive rock and thus, the potential for maximizing the conductive area via fracture height is limited to placement of proppant across the height of the productive interval. Thus, the key design parameter over which fracturing treatment design engineers may have influence is the effective fracture length. Fracturing Fluids. The industry has focused great effort on the development of products and application techniques to facilitate proppant transport in efforts to maximize effective fracture length[2]. Highly viscous, crosslinked polymer-based fluids and/or relatively high fracture flow velocity have historically been employed to properly place the proppant throughout the fracture area. In the late 1980's it was recognized that the residues of commonly used crosslinked guar-based fracturing fluids often cause greater than 80% damage to proppant-pack conductivity, leading to the rapid evolution of improved breaker systems to mitigate the damage. The past decade has seen much advancement in these areas, including the introduction of crosslinked fluids having reduced polymer concentrations and viscoelastic surfactant-gelled fluid systems.

In recent years successful stimulation and extraction of hydrocarbons from unconventional reservoirs has led to various approaches to the stimulation process. Slickwater stimulations pumped at very high flow rates have become the staple in formations such as the Barnett Shale. High treatment rates are made possible by the implementation of low dosages of polyacrylamide, which lower the effective pipe friction. This type of treatment process is common among other shale and tight gas plays throughout North America. Other types of treatments include conventional crosslinked or linear gelled fluids. Some treatments combine the conventional crosslinked fluids and the slickwater approach. Experimentation with multiple stimulation programs is a response to the changes in formation properties that vary from one formation to the next and within areas of the same formation. Over the last few years there have been several successful treatments implementing a high-quality foam stimulation in some shale formations. These treatments have usually included a gas phase in excess of 90 quality and often as high as 99 quality. This type of treatment is especially fitting for low-pressure reservoirs and in depleted zones. One advantage of a high-quality foam is its reduced environmental impact by using very small quantities of water as compared to high-rate slickwater stimulations. In these particular high-quality foams, a viscoelastic surfactant gel is used in the liquid phase as the gelling and foaming agent. With the combination of high-quality foam and non-damaging viscoelastic gel, the total fluid is completely non-damaging to the formation. Successful treatments in formations in the northeastern United States have led to a demand for use in other formations, necessitating a better understanding of fluid properties in order to design treatments. Very little published data is available for high-quality foam fluid properties. A study has been conducted to examine the fluid characteristics of high-quality foams as compared to typical 50 - 70 quality foams. This study will show trends of viscosity, foam stability and temperature sensitivity of high-quality foams using xanthan, guar-based gelling agents and viscoelastic base fluids.

Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and that optimization of effective fracture area is often critical to economic exploitation of reservoir assets. Extensive testing in a large-scale slot apparatus was conducted to evaluate the relative effects of various component and treatment parameters on the proppant transport capability of various slurry compositions. The acquired data were utilized to determine the minimum horizontal slurry velocities necessary for proppant transport using the respective slurry compositions. An ‘index’ to define the physical properties of a given proppant and fluid composition was defined. An empirical model was then derived to determine the minimum horizontal flow velocity required for suspension transport of a given slurry composition based upon its Slurry Properties Index. The minimum suspension transport velocity may then be compared to the flow velocity profiles from fracture design programs to estimate the propped fracture length likely be observed for those conditions. Utilizing the new model, the most favorable combination of fracturing slurry component properties and pumping parameters can identified and incorporated in fracturing treatment design and applications to optimize effective propped fracture length, and thereby well performance. Introduction and Background Poor proppant transport can result in excessive proppant settling, often into the lower regions of the created fracture below the productive interval, yielding relatively short effective fracture lengths and insufficient coverage of the total height of the productive zone. Additionally, inadequate clean-up of the resultant propped fracture result in significant reduction of the conductivity of the propped fracture area. The cumulative effects of the afore-mentioned phenomena can result in a reduction of overall stimulation efficiency, yielding steeper post-stimulation production declines than may be desired. Post-frac production analyses frequently illustrate that the effective fracture area is less than that expected based upon the design, suggesting the proppant was not placed effectively throughout the designed fracture area or, existence of excessive proppant-pack damage. Optimization of effective fracture area is often critical to economic exploitation of reservoir assets, thus maximization of the propped fracture area is a key parameter for generating desired stimulated well performance. Efforts to improve effective fracture area have historically focused on the proppant transport capability of the fracturing fluid and the fracture clean-up attributes. A better understanding of the proppant transport process and the controlling variables was thought to have the potential for developing improved methodologies to maximize the effective fracture area. The relative effects on proppant transport of the various proppant slurry component and treatment parameters were evaluated via extensive testing at the University of Oklahoma's Well Construction Technology Center. The techniques developed by Biot and Medlin to determine terminal settling velocities and suspension regimes were used to process and analyze the acquired data1.

Friction reducers have been an integral part of the oil and gas industry for many years. They possess very unique properties of reducing friction pressure associated with the flow of fluid in tubulars. Friction pressure loss or hydraulic characteristics of friction reducers depend greatly on how they are tested and evaluated in the laboratory. Today, there is no standard procedure for their evaluation. American Petroleum Institute (API) oversees the development and publication of industry standard practices for various fluids and materials. Recognizing the need for a standard testing procedure for friction reducers, a Committee made up of members from industry and academia was formed and charged to develop a document outlining the standard procedure. Round-robin tests were conducted by four industry organizations and one academic institution, employing their in-house flow loops and were requested to report the results. Tests were to conduct friction pressure measurements of friction reducers, and to develop and deliver to the industry a standard procedure and method to measure and analyze friction reducers data in straight pipes. The test fluids chosen were two friction reducers: one anionic and the other cationic. Water data were also gathered as base line. Same fluid samples were submitted to all laboratories. The calibration procedure and fluid testing procedure was developed and distributed to all involved in fluid testing. The analysis for data reduction and for reporting results was also developed and distributed to all. It was found that the calibration procedure was more critical than originally thought. The determination of internal diameter of the circular tube is the most important parameter that influences the friction pressure loss results greatly. In this paper, the details of various flow loops, calibration procedure, data analysis procedure, and results obtained with water as base line and two friction reducers are presented and discussed. A standard procedure for testing and evaluating friction reducers for their friction loss properties is outlined. Following this standard procedure and carefully performing the testing with friction reducers will yield very similar results among various laboratories in the industry. This will make it easy when comparing the performance of friction reducers for their friction loss properties from different organizations.

Reservoir completion techniques, such as hydraulic fracturing for low permeability wells and frac pack for unconsolidated formation treatments, are normally applied to increase well productivity. The production of treated wells can be greatly enhanced by increased propped fracture area and proppant pack conductivity, both of which are highly dependent on proppant distribution in the fracture. Stimulation fluids with high viscosity are traditionally employed to open fractures and carry proppant into created fracture area in the formation. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids can be difficult to clean up, due to residual gel damage to proppant pack and formation. Post-treatment production analyses with crosslinked gel often indicate that the treatment did not achieve the designed conductive fracture area, which could be attributed to non-ideal proppant placement and/or significantly damaged fracture conductivity. Perfect proppant suspension and transportation under downhole conditions is the ultimate dream for any fracturing fluid technology as it suggests proppant placement throughout the created fracture area to maximize stimulation efficiency of the treatment. Unlike conventional fracturing fluid technology which uses fluid rheology, polymer chains overlap and inter-chain crosslinking to generate viscosity, as the way to suspend proppant. The new concept involves a novel approach of particle packing mechanism to provide the near perfect proppant suspension in the new fluid, while maintaining minimum formation and proppant pack damage after breaking with frac fluid breakers. As to proppant transport mechanics with conventional fluids, viscosity and velocity above threshold levels can move proppant in a generally horizontal direction until gravity prevails as the velocity decays. However, neither viscosity nor velocity can overcome gravity to effectively move proppant upwardly from the wellbore. The packing mechanics of the soft particle fluids substantially mitigate the effects of gravity until such time as fracture closure confines the proppant. This paper discusses laboratory results for this unique particle fluid system (1) to enhance proppant carrying capacity, (2) to deliver significantly better proppant vertical distribution of the fracture, (3) and to yield near 100% regained proppant pack conductivity. The system can unlock reservoir potential in areas requiring high propped fracture area and high regained conductivity, such as unconventional liquid-rich and offshore unconsolidated formations.