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Summary The foam-assisted underbalanced-drilling technique is more advantageous than the traditional overbalanced drilling near the productive water-sensitive formations because of its reduced formation damage, improved rate of penetration, higher cuttings-transport capacity, and lower circulation losses. However, the complicated nature of foam rheology has been a major impediment to the optimal design of field applications. Earlier studies with surfactant foams without oils and polymers show that foam flow in pipe can be represented by two different flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. The objective of this study is to investigate foam-flow characteristics in horizontal pipes at different injection conditions, with or without oils, by using polymer-free and polymer-added surfactant foams. The results of this study were presented in two different ways—by steady-state pressure drops (or, apparent foam viscosity, equivalently) measured by multiple pressure taps and by the visualization of bubble size, size distribution, and flow patterns in transparent pipes. The results with surfactant foams and oil showed that first, oil reduced the stability of foams in pipes, thus decreasing the steady-state pressure drops and foam viscosities, and second, the presence of oil tended to lower the transition between the high-quality and the low-quality regimes (i.e., lower foam quality at the boundary, or lower f*g equivalently). In addition, the results with surfactant foams with polymer showed that first, polymer thickened the liquid phase and, if enough agitation was supplied, could make foams long-lived and increase foam viscosities, and second, the system sometimes did not reach the steady state readily, showing systematic oscillations. In both cases, though, the experiments carried out in this study showed the presence of two distinct high-quality and low-quality flow regimes.

Offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. This results in a significant impact on operational efficiency by lowering costs and ultimately increasing hydrocarbon production. To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single operation, adding additional savings to the process and improving efficiency. Interpreted openhole images and advanced sonic logs were used to determine the optimum completion configuration and to select favorable fracture initiation points and treatment designs. Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks. To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously. This novel multistage fracturing system was introduced in Europe for the first time. Results indicate a sustained increased production. Because of this success, additional wells are scheduled to be stimulated using same approach in the following months.

Current offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single pumping operation, improving efficiency and adding additional savings to the process. Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks. To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously. This novel multistage fracturing system combined with polymer-free viscoelastic surfactant fluid system prepared with seawater was applied in the World for the first time. Results indicate a sustained increased production.

Hydraulic fracturing treatments in unconventional (coalbed and carboniferous shale) natural gas wells have been successful in stimulating gas production. However, the wells often do not perform up to potential following the treatments for various reasons. Some of the factors that can contribute to the relatively poor performance include low coal or shale permeability, complex cleating and natural fracture networks, gas content and adsorption characteristics, water content, and fracturing fluid interaction with formation surfaces. Fracturing fluid damage in coal formations has been shown to cause significant reductions in permeability, and whole gel leakoff into the cleat networks can further impair production. The same damage mechanisms can impair the production of carboniferous shale formations. To avoid the damage associated with polymer-based fluids, a coal/carboniferous shale-compatible solids-free (CCSF) fluid was developed for unconventional natural gas well applications. The CCSF fluid is a nitrogen-foamed fluid that was designed to be environmentally friendly to minimize risk to ground water that could be contacted during fracturing treatments. This study investigates the effects of various hydraulic fracturing fluids including conventional polymer-based fluids, water containing friction reducers, and a coal/carboniferous shale-compatible solids-free fluid on coal and shale pack cleanup. Laboratory coal pack cleanup tests demonstrate a significant reduction in retained permeability with polymer-based fluids. In addition, a high cleanup factor (a parameter introduced to provide a measure of the pressure and time required for cleanup) is required to establish only marginal flow conditions with brine injected in the production direction. Even water containing low concentrations of friction reducer may result in less than 50% retained permeability. The CCSF fluid provides 70 to 100% retained permeability and a low cleanup factor for effective coal pack cleanup with coal samples from seven coal basins in North America. Similar improvements were observed with carboniferous shale pack cleanup tests. Field case histories in coal and carboniferous shale formations are consistent with laboratory observations and demonstrate a dependence of fracture cleanup on retained permeability and the cleanup factor measured in the laboratory. Production results demonstrate a 30 to 60% increase in production with the CCSF fluid compared to conventional fracturing fluids in coal and carboniferous shale basins in the United States.

Seawater injection has been used to maintain the reservoir pressure in a carbonate reservoir in Saudi Arabia. However, the injectivity of some vertical wells in this field is limited due to low reservoir permeability (less than 20 md). Conventional matrix acid treatments did improve the injectivity to varying degree. However, to achieve the required injection rate, some of water injectors need to be stimulated by acid fracturing. Various acid systems have been evaluated to acid fracture injection wells. A thorough literature survey and lab testing eliminated acid systems that utilize acid-soluble polymers (both linear and cross-linked). This is mainly due to the formation damage associated with polymers, and also these systems required back-flow of the treated wells for cleanup. To eliminate formation damage due to polymers, flowback for cleanup, and to enhance well performance, a polymer-free viscoelastic surfactant fluid was utilized in acid fracturing treatments. The fluid system includes the non-damaging viscous pad and polymer-free leak-off controlled acids. The treatment was successfully applied in the field. Cleanup by flow back was eliminated with resulting in significant increases in well injectivity comparable to horizontal wells drilled in the same area.

Vertical seawater injectors for a carbonate reservoir in Saudi Arabia have an injection zone (open hole) of approximately 200 ft. This reservoir has drastic permeability variations. Acid stimulation without proper diversion normally results in undesirable stimulation of the high permeability streaks. Therefore, acid diversion plays a key role in improving both the post-acid, well-injectivity and injection profile. Various diverting agents have been used to improve the acid distribution during acid injection, including wellbore gels, foams and in-situ gelled acids. The use of polymers is an excellent means of diversion.1,2 However, evaluation of polymeric systems has demonstrated formation damage due to residual polymer, which is considered unacceptable, especially for water injection wells.3 Conventional foams have also been tested with good success. In the present study, the use of a polymer-free viscoelastic surfactant (VES) as a diverter system is investigated and compared with in-situ gelled acid and foams. The VES is a two-component system, and in the presence of salts, the surfactant molecules associate to form rod-like micelles. These micelles can entangle with each other and form a three dimensional network, responsible for the high viscosity of the system.4,5 This non-damaging "surfactant gel" can be broken completely by injecting mutual solvent or injection water. This added advantage eliminates the need to flow back the well following acid treatments. Laboratory studies demonstrated up to 2-fold increase in viscosity and nearly 20-fold increase in foam stability compared to foams containing polymers. The properties of VES solutions are independent of the salinity and pH of the mixing water. Bullheading the acid enables the operator to pump these treatments at high rates, which are needed in some cases. Pumping pressure, post-acid injectivity history and injection flow profile of several seawater injectors indicate good stimulation results and better acid diversion across the whole target zone. This paper presents the first application worldwide on the use of VES technology in water injection wells. A total of six stimulation treatments were performed using this technology, one treatment using coiled tubing (CT) and five by bullheading. The VES technology provides a solution for heterogeneous carbonate reservoirs, and eliminates formation damage induced by the polymers present in the conventional diversion systems. Stimulation using the VES system on six wells resulted in an injection increase of more that 45,000 bbl of water per day, much higher than similar treatments where conventional foams were used.

This paper presents a case history of the completion procedures applied to a four-well gas reservoir development in the Norwegian sector of the North Sea where open-hole gravel packing was utilized as the sandface completion technique. The chosen technique to gravel pack the wells was based upon Alternate Path Technology, which incorporates shunt tubes with nozzles on the outside of the gravel pack screen. These shunts create an alternative flow path, allowing slurry to bypass premature bridging and fill any voids beyond the bridge. The use of shunt tubes gives the opportunity of achieving a complete gravel pack without the requirement of a filtercake-sealed wellbore. This introduces the possibility for the filter cake to be removed during the packing operation. As a result, a low-solids drilling fluid that deposits a chemically degradable filter cake can be utilized. The reservoir pressure in this field required relatively high-density, reservoir drilling and gravel pack fluids (1.65 SG / 13.75 lb/gal). This paper describes the design and development work involved in formulating a mutually compatible, calcium bromide-based reservoir drilling fluid and a Viscoelastic Surfactant (VES) based gravel pack fluid and the subsequent successful application in a subsea field development.

The success or failure of a gravel pack or stimulation treatment performed in the Gulf of Mexico (GOM) is often times directly related to the ability of the diverting agent to force the treatment into different portions of the reservoir. Without the success of these diverter stages, entire treatments can be channeled into small portions of these "unconsolidated" reservoirs. Since most damaged intervals are often times the last intervals to be contacted by the acid, the treatment must be chemically forced to attack these intervals early in the treatment to insure proper stimulation and damage removal. Diversion of acid treatments in the Gulf of Mexico (GOM) have been predominantly accomplished by using either foam, HEC, or particulate matters to "temporarily" block off the zones and force the acid elsewhere. Foam and HEC are the preferred method of diversion due to their "low damaging" characteristics, but are severely hampered by temperature limitations. Foam diversions can also be difficult to control due to foam stability. Although HEC is essentially non-damaging, production can be hindered due to the viscous nature of HEC. Particulate matters such as carbonates, sized salts, and benzoic flakes are not as affected by temperature but can often times be difficult to remove and in some instances impede the production results. This paper describes the development of a new "solids-free non-damaging" diverting agent based on viscoelastic surfactants. The unique fluid properties of this system allow acid diversions to be tailored to specific well conditions and formation characteristics. By incorporating an internal breaker this system does not require contact with formation fluids, brines, or acids for clean up to provide optimum production. This paper describes the fluid properties at various pH's, temperatures, and salt concentrations along with several successful case histories.

Abstract Polymer residues that stay in the fracture after a hydraulic fracturing treatment can limit treatment effectiveness. A new and easy-to-prepare, polymer-free fluid that consists of a quaternary ammonium salt derived from a long-chain fatty acid is described. In brine, it builds viscosity due to the formation of highly entangled worm-like micelles. The micelles have a gross structure similar to a polymer chain. Since the viscosity of the fluid depends on the nature of micelles, the fluid can be broken by changing this micellar structure. The breaking occurs when the fluid is exposed to hydrocarbons or diluted with formation waters. Therefore, conventional breakers are not required, and the produced oil or gas can act as breakers for this fluid system. The structural characteristics of the polymer-free surfactant fluid to its chemical and physical properties are correlated in this paper. Structure, rheology, fluid loss and conductivity of this surfactant fluid together with its production data are presented. Introduction Fracturing fluid is a very critical component of a hydraulic fracturing treatment. Selection of the fracturing fluid, job design, and well turnaround procedure all help to determine the production of a well after a stimulation by hydraulic fracturing. A fracturing fluid should provide sufficient viscosity to suspend and transport proppant into the fracture, and should break into a low-viscosity fluid after the job is completed. This will facilitate the fracture to clean up by allowing rapid flowback of fluid to the surface. Analysis of the fluid returned to the surface (flowback fluid) after hydraulic fracturing indicates that as little as 30 to 45% of the guar-based polymer pumped during the treatment returned from the well during the flowback period. Polymer residues that remain in the fracture significantly contribute to a lowered proppant-pack permeability leading to a loss in fracture treatment effectiveness. The field success of a viscoelastic surfactant-based (VES) polymer-free fluid in frac-pack applications led to the development of a similar fluid for hydraulic fracturing. The VES fluid can be used for the fracturing treatment of potentially all gas and oil wells below 240 F. The principal advantage of this fluid system is its operational simplicity. This fluid is easy to prepare and requires less equipment at the wellsite This fluid does not require polymer hydration, biocides, crosslinkers, or breakers. The hydrocarbons produced, or dilution of VES gel by other formation fluids, can break this fluid. This new fluid has been used for the successful execution of more than 250 fracturing jobs. Results from representative treatments are presented.