Recently, a new fiber-laden, self-diverting, and viscoelastic acid has been successfully used for matrix acidizing of highly heterogeneous carbonate formations The fibers have been designed to be inert under surface and pumping conditions, and their geometry allows them to form strong and stable fiber networks that can effectively bridge across natural fractures, wormholes, and perforation tunnels. Eventually, the fibers degrade into a water-soluble organic liquid that is produced back to the surface during flowback.In the case of perforated wells, experiments suggest that diversion with fibers operates in three phases. First, as the early volumes of fiber-laden acid reach the perforations, the acid penetrates the reservoir as if no fibers were present. Second, as the fibers bridge, they accumulate inside the perforations and form a fiber cake. Third, the fibers plug the perforation, and the injectivity decreases locally, promoting diversion into other perforations. The pressure drop through a plugged perforation was analyzed by performing 340 separate fine-scale 3D simulations. The original work was based on theoretical and laboratory-based experiments, considering typical perforation schemes and for various permeability ratios between the generated fiber cake and the formation's original permeability. The results were compiled, and a correlation was made to model the resulting skin. The model was implemented into an acid placement simulator and was extensively tested and validated in the field.In this paper, we present the model that describes the effect of fiber accumulation within perforations and explain how some of the model parameters such as formation-permeability contrast, fiber-cake permeability, and total permeability thickness (kh) may affect diversion efficiency. Case studies from field testing of the model illustrate methods of pressure history matching, job design, and treatment history evaluation.

Advancement in fluid diverter technology has enabled successful initial stimulation of long interval carbonates without mechanical isolation, in excess of 1000 ft. by using in-situ crosslinked polymer systems and viscoelastic surfactant systems. These fluids build viscosity upon reacting with the formation, enhancing diverter performance. However, heavily stimulated, i.e. wormholed, formations require a step-level change in diversion performance to effectively stimulation new intervals, or previously under-stimulated layers. This paper will present the qualification and optimization of degradable fibers for use in re-stimulation of carbonate formations.The key performance aspects desired and evaluated are: (1) ability to block existing wormholes near the wellbore, as opposed to needing to fill the entire wormhole structure, (2) permeability and diversion capability of resulting fiber bridge, and (3) confirmation of degradation and cleanup in a dry gas environment within a reasonable timeframe. New experimental methods were developed to address these requirements, including gas/fluid degradation testing, bridging tests with slots to represent wormholes and fractures, and bridging experiments with 3D synthetic models of a wormhole structure. To be able to run repeatable experiments, wormholed structures were printed with a 3D printer using high-resolution CT scans from an actual wormholed core plug.Testing results showed the ability of the fibers to bridge within the wormhole network and provided guidance in designing the fiber diverter stages for already-stimulated wells. Addition of degradable particulates was shown to further improve wormhole bridging and diversion performance. Modeling the wormhole diversion process within advanced stimulation software identified additional optimizations, such as increased stage size and increased fiber concentrations to achieve desired diversion. A related presentation will discuss the successful re-stimulation of three high-rate gas wells (B. Clancey 2015).

Hydraulic fracturing is used extensively to increase hydrocarbon production from oil and gas formations. Hydraulic fracture conductivity is a key parameter in optimizing the productivity of a well after the fracture treatment. The American Petroleum Institute (API) proppant permeability / fracture conductivity testing results are frequently used in industry fracturing models when selecting the proppant that provides the optimum fracture conductivity for a well's particular reservoir properties. This design methodology invariably results in a lower than expected fracture conductivity and in many cases, lower than optimum well performance. The industry has recognized that actual fracture conductivity is often a small fraction of what would be expected by using API test results. Non-Darcy flow, multiphase flow, gel damage, stress cycling, fines migration, proppant embedment, proppant flowback, and fracture cleanup are some of the parameters that result in fracture conductivities significantly lower than those measured in an API conductivity test. A new proppant was developed to improve the final fracture conductivity achievable with high-strength spherical proppants currently available in the market place. This new product is an elongated rod-shaped, high-strength particle with integrated proppant flow back control. Initial field testing of the product was conducted in moderate permeability formations where production from prior fracture treatments indicated lower than optimum fracture conductivity. Production results from these field tests confirmed that substantial increases in fracture conductivity can be achieved. The large improvement seen in fracture conductivity can be attributed to increased porosity of the proppant pack and reduced fracture conductivity losses due to non-Darcy and multiphase flow effects. Completely changing the typical geometry of proppants used in hydraulic fracturing is a viable option for improving the conductivity of hydraulic fractures to a point not currently obtainable with spherical proppants.

Oil-saturated strata of Western Siberia fields are represented by laminated low-permeability sandstone separated by shale layers. Therefore, when designing hydraulic fractures, it is important to create longer propped fracture half-length and provide coverage of oil-saturated layers along the entire net height. Implementation of high-volume proppant fractures in combination with high-viscosity crosslinked fluids leads to excessive fracture height growth. This results in ineffective proppant distribution in the target layer and, moreover, to unwanted water production if the water contact is close. To overcome these issues, it was proposed to use a novel hydraulic fracturing fluid that is a viscous slickwater based on synthetic polymer-polyacrylamide (also known as HiVis FR or HVFR). The low viscosity of HVFR (about 10 times lower than that of a crosslinked gel) allows a long fracture to be created and restricts height growth. Additionally, use of polyacrylamide instead of guar gives a larger value of retained conductivity. The full workflow for implementing HVFR for hydraulic fracturing in conventional formations includes candidate evaluation, HVFR laboratory testing, an integrated engineering approach to fracture modeling, operational considerations, and post-fracturing production analysis. The workflow evolved during the technology implementation cycle in a specific oil field, particularly the modeling step, which used a new high precision multiphysics (MP) model. The MP model provides an advanced, high-quality high- precision fracturing design to properly evaluate fracture geometry and proppant distribution by accounting for proppant settling in viscoelastic fluid and an accurate simulation of proppant placement when using a pulsing schedule. During the 2-year project, considerable success was achieved in expanding of the technology implementation scope. Several records were achieved on oil field - a 150-t of ceramic proppant (SG, specific gravity,~3.1) were placed in a conventional reservoir by low-viscosity fracturing fluid and the first worldwide combination of viscous slickwater with channel fracturing technology was successfully performed. The use of HVFR, due to ability of fracture growth control, prevented breakthrough into the water-bearing zone. In addition, considerable improvement of operational efficiency was achieved due to use of cold water, lower amounts of additives, and less equipment, which resulted in a smaller location and environmental footprint. This first implementation of the viscous slickwater in conventional wells in Western Siberia enabled evaluating its effect on production rate. Increasing demand for maximizing production from low-permeability formations makes the result of this viscous slickwater implementation campaign of special interest. The application of a full engineering workflow, including design, execution, and evaluation of the Viscous slickwater treatments is a key to successful technology implementation and production optimization.

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