Many tight gas formations are water-wet and under-saturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. The use of water-based conventional fracturing fluids causes water to be trapped in the near-wellbore region, thereby significantly impairing the ability of gas to flow. Formations with sub-irreducible water saturation can be stimulated with fluids that minimize the interfacial tension (such as surfactant gels), minimize the amount of water used in the fluid (such as energized or foamed fluids), dehydrate the formation (such as alcohol-based fluids) or completely eliminate water (such as hydrocarbon-based or liquid carbon dioxide-based fluids). Since the rheology and proppant-carrying properties of these fluids vary, the uses of these fluids are different and will be discussed in detail in the paper. The paper will also present guidelines, based on formation properties, to indicate the need for considering unconventional fluids. Introduction As the industry moves to tighter and tighter formations, particularly formations such as shales or coalbeds where production is controlled by desorption of the gas rather than matrix flow, fluids that are non-damaging to the proppant pack and formation are becoming increasingly important. Wells with adverse capillary effects due to sub-irreducible water or hydrocarbon saturation also require different fluids to minimize those effects or mitigate effects caused by drilling with the wrong fluid. Several unconventional fluids have been developed and successfully used for these unconventional formations in the last decade. Adverse saturation in the formation can contribute to productivity impairment. Production has been successfully achieved in formations with matrix permeability as low as 10-3 md. However, adverse capillary forces, which result in high in situ saturation of trapped water or liquid hydrocarbons even in very low-permeability formations, make economic production difficult. Low-permeability formations are typically tolerant of only minimal saturation damage due to the sensitivity to capillary retention effects, and rock-to-fluid and fluid-to-fluid compatibility issues. In these wells, the damage from drilling and completion can be overcome by a properly designed frac treatment, which can penetrate beyond the zone of induced invasion and damage.

Exploration for unconventional reservoirs has begun in various countries in the Middle East. Widely recognized as the bastion of conventional crude oil and gas production, the area's exploration for natural resources –– in particular unconventional resources –– is in its infancy. The lack of fresh water may derail some of the exploration and production of unconventional resources in the Middle East. One of the solutions is to use the abundant availability of nearby sea water for fracturing treatments. This paper will discuss the applicability of sea water for fracturing fluids for without the need for separate treatment of the water. Rheological data with synthetic sea water as well as source sea water from Saudi Arabia, identification of any potential precipitation and remediation and compatibility with produced water and proppant pack conductivity data, of applicable fluids to show the effectiveness of the systems to the high temperatures of the reservoirs in the kingdom, 325°F will also be presented. The concept of using seawater as a base fluid is not new. Because of the problems associated with substituting seawater for freshwater in polymer-based fracturing fluids, many operators are apprehensive about using seawater for fracturing. There have been noted attempts to mix polymer-based fluids on the fly with seawater, but treatment results have varied widely. Seawater contains dissolved inorganic salts, adversely affecting hydration and viscosity development of polymer-based fluids. High content of calcium and magnesium in seawater can reduce viscosity. These salts also buffer and strongly influence pH control and may inhibit or deactivate certain gel breakers. To gel effectively, polymer fluids need a specific mixing environment with distinct pH windows. Borate crosslinking normally requires a high pH. Rheology and breaker profiles will be shown that provide the desired properties and regain conductivity to establish the non-damaging clean-up of a properly designed fluid. The technology presented uses chemical chelation of the problem ions in the sea water, resulting in the fracturing fluids with enhanced fluid and proppant pack properties, including thermal stability, retained fracture conductivity, pH buffering capacity, scale inhibition and fluid loss control. Further, the addition of the novel additives to the fluid does not interfere with the crosslink delay time and does not complicate the preparation of the fluid. The technology discussed eliminates the need for traditional water treatment and nano-filtration of sea water and associated disposal issues.

Summary Successful fracturing treatments in ultralow-permeability reservoirs require combining the most recent innovations in fracturing technologies. Viscoelastic surfactants, foams, and ultralightweight proppants (ULWPs) have specific properties that when combined offer the unique performance required in fracturing these reservoirs. Viscoelastic-surfactant foams are particularly suited for treating ultralow-permeability reservoirs because they minimize the interfacial tension and minimize the amount of water used in the fracturing fluid. This significantly reduces the permanent retention of water and the amount of water trapped in the near-wellbore region that would impair the ability of gas to flow (Gupta 2009). Inexpensive, logistically simple, polymer-free viscoelastic surfactants provide exceptionally high viscosity under low-shear conditions required for proppant transport. They also provide excellent cleanup characteristics. Foamed viscoelastic surfactants provide increased viscosity for frac width, provide better leakoff control, and further improve fluid cleanup characteristics, particularly in low-pressure reservoirs. ULWPs provide excellent transport properties in conventional fracturing fluids with minimal viscosity, which ensures desired effective propped-fracture conductivity. Use of these ULWPs in foamed viscoelastic fluids provides fracturing treatments with optimum proppant placement and excellent cleanup. As with all successfully applied fracturing fluids, the fluid systems must be optimized. These combined systems require significant laboratory testing to characterize and optimize the fluid system successfully for the demands of ultralow-permeability reservoirs. This paper focuses on small- and large-scale laboratory testing performed to optimize these viscoelastic foamed systems in an effort to test the technical limit of this new technology for future field developments.

As exploration goes deeper, most conventional methods have to be modified or completely re-engineered to hold up to these extreme conditions. Fracturing fluids are no exception to these changes. Fluids have evolved rapidly to adjust to an ever changing market. The trick is to make them as easy as possible to deliver on location. There have been several attempts at developing new high temperature fluids that will give good stability and deliver the fracture properties desired. Most of these to date require special handling and have operational difficulties.A new high temperature synthetic low-pH crosslinked fluid system has been developed to avoid these pitfalls. The system employs a synthetic co-polymer in an environmentally compliant oil-based emulsion that hydrates very rapidly with excellent fluid rheology properties. Proppant pack regain conductivity using encapsulated oxidizers has also shown very good cleanup at these temperatures. The system uses exceedingly low polymer concentrations (18 to 40 pptg) compared to others (60 to 100 pptg) at temperatures from 350 to over 450°F. The fluid can also be energized with nitrogen or carbon dioxide or foamed if needed. Operationally, fracturing with this fluid can be performed with conventional equipment without any modifications. The paper will present the chemistry and technology of this new fluid including rheology and cleanup data. This new technology has the potential to change the manner in which ultrahigh-temperature wells are completed.

Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively lowtemperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field.The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G") during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G= were independent of the frequency and/or shear rate values, while G" increased with increasing frequency and/or shear rate. At higher temperature, both G= and G" increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.