Due to technical and economical limitations of hydrofracturing operations in unconventional reservoirs worldwide, an optimized hydraulic fracturing design is critical to achieve a successful well stimulation operation. The number and length of perforation clusters in each stage, proppant and fluid frac compatibilities, and optimum spacing, are some of the challenges inhibiting successful hydraulic fracturing operations across the world. In this study, we aim to investigate the effects of varying fracture-cluster lengths, proppant types and sizes, and frac fluid types, on hydraulic fracturing treatments using 2D and 3D simulation models. Our study relies on petrophysical log data, geologic data, well data, reservoir data, and production data from a well in the Eagle Ford shale formation. Firstly, we created stress log and developed a stress profile to determine fracture initiation location and orientation. We selected different combinations of frac-fluids and proppant types, 5 fracture-cluster lengths in a single stage, 2 different spacing lengths between fracture clusters, determined the maximum allowable treatment pressure, and selected an ideal fracture propagation model. Secondly, we selected an optimum treatment size, followed by performing the production forecast and the net present value analyses. In the third task, we determine the optimal specifications of the fracturing fluid and proppant, fluid volume and proppant weight, followed by creating a schedule for fluid injection and proppant mixing, and injection pressure profile prediction. Our results show that greater cluster lengths provide better and optimized hydraulic fracture treatment in some cases because of greater proppant coverage, fracture conductivity, stimulated reservoir volume (SRV), fracture half-length, and propped length. In the results obtained from varying proppant sizes and frac fluids in cases 2 and 3, we observed that Northern White 30-50 proppant produced a lower fracture conductivity (average of 2.0 md-ft) and fracture half-length (91 to 123 ft), in comparison with proppant composed of Badger 100 mesh and RC Sand PC 16-30, which achieved a greater fracture conductivity (> 3.0 md-ft) and fracture half-length (129 to 148 ft). In the 3 cases we investigated, we observed that stress shadowing and interference hindered the growing fractures which eventually led to a collapse of some fractures. We believe that our preliminary study will provide valuable critical decision-making during hydraulic fracturing operations in various unconventional formations across the world.

To economically produce gas from tight reservoirs poses challenges resulting from high bottomhole temperature, low permeability, and high Young’s modulus and rock compressive strength. Hydraulic fracturing, which is necessary to exploit the tight reservoirs, faces constraints such as high fracture initiation and treating pressures, risk of premature screenout, and conductivity degradation. A conventional fracturing treatment in such challenging environment necessitates increased polymer concentration in fracturing fluids and using smaller-size proppant at low concentrations. This results in shorter effective fracture half-length and low fracture conductivity. Additionally, high polymer concentration is not easily cleaned up and may create further damage to the proppant pack. These challenges are compounded where the reservoir is relatively tight and often cannot supply enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced in which proppants are added in pulses to the fracturing fluids, creating stacks of pillar-like structures inside the fracture. These pillars hold the fracture open, and the voids surrounding them form stable channels along the entire geometry of the fracture thereby providing an open pathway with near-infinite conductivity. The technology reduces amount of proppant pumped compared to a conventional treatment, and most of the standard expensive high-strength proppant, required for fracturing in high-stress environment, can be substituted by intermediateand low-strength proppants or even natural sand. The hydrocarbons will flow through the open channels and not through the pack. Additionally, pulsation of proppant during pumping virtually eliminates the risk of a screenout. Extensive laboratory tests have been conducted to verify the concept of using nonstandard proppant with channel fracturing in high-stress formations. The results of these tests were positive, and trial treatments have been pumped. To date, more than 50 channel fracturing treatments have been conducted in the clastic reservoirs. Some of them have been performed with nonstandard proppant as a part of the treatment. No screenouts were observed even in the formations that were tight with narrow pressure margin between the in-situ stress and completion integrity limitations. Production results after channel fracturing treatments are more consistent compared to conventional proppant fracturing and are not related to the type of propping material used.

Flow-Channel Fracturing Technique was considered as a possible solution for testing the reservoir characterized by poor lithological characteristic, severe heterogeneity, low permeability and fluid movement compared to the other producing reservoirs from the same field. This manuscript provides an insight to the conventional testing technique employed in this field and the methodology of the first application of Flow-Channel Fracturing technique in this reservoir in the pilot well, post job evaluation and way forward for large scale implementation for testing in other wells in the same reservoir. The MB formation in the RA field was selected for the pilot application of this fracturing technique. This formation is described as marine shoreface sands with shale intercalations with an average thickness of about 160 ft. with average porosity varying from 5% to 27% and permeability ≤ 406 mD. This formation requires some stimulation treatment to have economical production. The historical testing technique carried out in this reservoir typically consisted of perforation with casing gun / Through Tubing Perforation gun and testing with Electrical Submersible Pump (ESP), perforation followed by standard mud acid stimulation and testing with ESP. These conventional testing techniques in this reservoir yielded only short term gains with subsequent decrease in the intake pressures of the ESP owing to poor reservoir deliverability and subsequent frequent tripping of ESP system. The Flow-Channel Fracturing Technique was considered as a solution to improve upon the production through creation of infinite production conductivity and greater effective contact area. This technique is similar to conventional proppant fracturing techniques where fluid and proppant are used to create conductive paths in the formation layer to enhance production from new or already existing oil or gas wells. However, owing to its pulsed delivery, engineered design and innovative use of degradable fibers the Flow-Channel Fracturing Technique creates a much more conductive path, thereby increasing the rate at which hydrocarbons are produced from the reservoir. As mentioned before, the primary goal of creating a mechanically stable propped fracture is to provide high flow capacity conduit to deliver the hydrocarbons to the wellbore with the maximum possible rate with the lowest pressure drop across the reservoir. For this purpose a production enhancement plan has been put in place for the scope of this project including three wells to be treated using the flow-channel fracturing technique. Two wells were treated on two stages while one had been treated as a single stage. The three wells were put on production post treatments, with the aid of ESP and illustrated stabilized average production without proppant flow-back issues. The evaluation of the treatments had been performed and showed an average effective flow-channel fracture half-length of +/− 330 ft. with almost infinite conductivity. On the other hand, the total cumulative production up to date is +/− 470 STBOPD per zone. These outstanding results opens the door further application of flow-channel fracturing technique to be applied to existing offset wells and for future production enhancement strategy of KOC.

In a high-perm/strong-aquifer environment, comparatively low-perm/heavy-oil/solution-gas-drive reservoirs inevitably get sidelined. Flow-Channel Hydraulic Fracturing, however, with infinite conductive channels for fluid flow rather than intra-granular flow, as in conventional fracturing techniques, offers a tangible solution for increased productivity. The channels in the proppant pack are created through a patented technique that combines special pumping protocol, perforation scheme, fracturing fluid design and fiber technology. These conductive channels accelerate fracture cleanup, and achieve longer effective fracture half-lengths, thereby enhancing productivity, injectivity& recovery. In North Kuwait, 90% of wells drilled are vertical, penetrating a wide range of reservoir types consisting of high and low permeability sandstones and carbonates, with varying crude types from medium heavy to condensate. Flow-Channel Hydraulic Fracturing technology, with its infinite conductive flow-channels and reduced risk of premature screen-outs, was selected as the optimum stimulation technology for the most challenging low-permeability/low API gravity candidates where conventional stimulation techniques are not providing the aimed results. Conventional propped hydro-frac treatments were attempted previously with marginal benefit and operational failures. This was the first application of this technology in Kuwait. Multi-disciplinary candidate screening and selection for the initial pilot wells, followed by pre-job logistics and operational planning with the service provider, resulted in a flawless execution with text-book results. Post-job production results showed a stabilized flow rates with more than 85% production gain compared to the flow rates expected from conventional completion techniques. Incremental production paid out stimulation expenses in 35 days. This very successful introduction for Flow-Channel Fracturing application opened up opportunities in low API reservoirs where even the flow through the proppant pack from conventional fracture stimulations is limited. Injectors associated with IOR & EOR projects, and Carbonate completions traditionally responding to repeated periodic acid fracture stimulation, may require only single channel proppant fracture during their life cycle.

The actual fracture conductivity contributing to gas flow after a proppant treatment is usually much lower than what is reported in the laboratory tests. This is because the ideal conductivity values can be impaired by numerous factors in the reservoir conditions – from high unconfined compressive strength to condensate yield – that cannot be fully captured in the laboratory measurements. Although there are many publications in the literature discussing this issue and software in the industry that predict certain percentage decreases in conductivity due to various reasons, these results are usually specific to certain reservoirs, formations, and laboratory tests and cannot be extrapolated or used for all reservoirs. To understand and compute actual conductivity values in Saudi Arabian gas reservoirs stimulated by proppant fracturing, a new workflow is proposed. The workflow involves using all available data to first calculate the actual fracture geometry using a mass balance and pressure matching. Subsequently, fracture conductivity is computed from another standard method, such as the Cinco-Ley correlation; and using industry software to estimate realistic conductivity values at static and dynamic conditions using closure pressure, actual well performance, and bottomhole flow pressure measurements. A range of fracture conductivity is computed during initial and later periods by matching the well performance data. The calculations show the fracture conductivity achieved after a fracture treatment at reservoir conditions and also how the values change during the production period of a well. Later, correlations relating to productivity increases with reservoir rock and pumping properties can be used to optimize fracture treatments such that a high rate can be maintained after a fracture treatment.

For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is a requisite to obtain commercial production. One of the key parameters for ensuring successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on the reservoir rock properties as well as the formation softening resulting from fluid-formation interaction. In the past, slickwater treatment fluids often were adopted in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on the formation). While this might work for a few formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use slickwater, linear gel, or crosslinked gel. Similarly, formation softening analysis using a Brinell hardness test and proppant embedment test will ensure that the formation does not close upon fluid treatment and will have conductive flow channels. This paper discusses the impact of different types of fracturing fluids on different shale formations. The paper also discusses processes involving fluid sensitivity tests, formation softening, and rock mechanical tests and shows their influence on the choice of the proper fluid formulation for hydraulic fracturing through data from a few test samples. The formation rock, proppant, and fracturing fluid interaction can also cause diagenetic growth on proppant and formation faces, resulting in formation softening and a large decrease in fracture conductivity. This paper focusses on careful selection of the stimulation fluid based on rock parameters to ensure prolonged production in tight oil and gas shale plays.

Environmental concerns and public opinion have elevated the visibility of hydraulic fracturing. Currently oil companies and operators acquire fresh water for fracturing treatments on the front end and pay to dispose or transport the flowback or produced water on the back end, increasing dramatically the cost of the hydraulic fracturing job. We report a newly developed fracturing fluid system utilizing 100% untreated produced water which eliminates the upfront costs of purchasing fresh water. In addition, the back end costs are significantly reduced by transporting produced and/or flowback water to locations for re-use rather than to disposal well(s) located miles away or even in other states. This new system uses conventional gelling agents and crosslinkers used in active US shale plays, addressing the fracturing focus initiative. This new fluid system was developed for temperature ranges between 120-300+ °F. Field tests prove shear stability and good proppant transport at 20 BPM through a 1.25 in sliding sleeve baffle. The fracturing fluid system can be designed for instant or delayed crosslinking in recycle water with total dissolved solids exceeding 300,000 mg/L with hardness exceeding 30,000 mg/L. Another concern in the past was the presence of boron in produced water. This system can be used in water containing boron levels exceeding 500 mg/L. The code for recycle water has been broken utilizing this unique fracturing fluid system designed to conserve fresh water aquifers and recycle produced and flowback waters, reducing significantly disposal costs. This paper reports laboratory testing of the fluid characteristics in untreated produced water from the Bakken as well as the outcome of hybrid fluids in field applications, recommendations for field applications and economic impacts on fracturing fluid systems.