Excess fluid leak-off, a challenge in Kuwait's naturally fractured tight carbonate formations, can compromise post-fracture productivity. Past acid fracture treatments, both for moderate and high temperature formations failed to generate the long differently etched fracture due to excessive leak-off. Treating zones with multiple perforated intervals in a single stage, particularly in pay zones with long heterogeneous rock properties can result in non optimal stimulation. Therefore, a new approach was developed with proven success to enhance fracture conductivity and overall production by efficient control of fluid leak-off. This novel approach incorporates the use of far-field and near-wellbore diverting systems into the acid fracture design. These solid particulate diverters (SPD) include low and high temperature systems that provide enhanced near-wellbore diversion in both case and open-hole applications. The SPD are designed to bridge across perforations and fractures in the higher permeability zones, diverting the stimulation fluid into lower permeability zones. A smaller sized multi-modal distribution of SPD controls the fluid in narrower natural fractures and wormholes, deepening penetration of the stimulation fluid along the entire fracture length. The SPD agents are fully degradable and do not contribute to permeability loss of the created fracture or the perforated interval when production starts. The production of the wells where the SPD agents were applied were higher in comparison to expected production of offset wells where non-acid crosslinked fracturing pad stages alternated with gelled or emulsified acid, and visco-elastic surfactant (VES) slugs. Both crosslinked fracturing pads, VES and emulsified acid slugs do not effectly control live acid leak off. Two case histories, documenting successes where this new approach to acid fracturing has been applied in the Tuba and Middle Marrat formations, have superior production results that correspond to enhanced fracture geometry.

The industry has long recognized the need to divert stimulation fluids away from a path of least resistance into one that stimulates new/more reservoir volume. However, relatively little research has been published specifically on the application of solid particulate diverters to increase fracture complexity in the far-field and to control fluid loss in acid fracturing. As the industry focuses more on well economics and increasing stage efficiency, proper engineering and application of far-field dissolvable solid particulate diversion technologies can increase overall well productivity in propped hydraulic fracturing and acid fracturing applications. To support the concept of far-field diversion in propped hydraulic fracturing and acid fracturing, laboratory studies including bridging tests, diversion efficiency through permeability reduction, and dissolution rates have been performed. To enhance these studies, operational guidelines and engineering the field application will help determine when different types of diversion can improve efficiency. Combining the information learned from laboratory testing and the new operational efficiency guidelines, a recommendation will be presented on the optimal way to run dissolvable solid particulate diverters in order to increase reservoir contact in the far-field. Multiple techniques exist to increase fracture complexity in the industry today. However, chemical diversion using solid particulates with an optimized particle size distribution enables the ability to reach more hydrocarbons in the reservoir. In addition, an advanced solid particulate diverter will be discussed for propped fracturing which includes the combination of particulate diverter material and a specially designed proppant to keep the fracture network open in the far-field.

Enhancing complexity of the created fracture geometry is the primary challenge for hydraulic fracturing treatment design in shale formations because of their stress anisotropy. Therefore, near-wellbore diversion is required to evenly stimulate all perforated clusters while far-field diversion inside the created fracture induces additional branch fracturing by overcoming the stresses holding the natural fractures closed. Solid particles with different shapes and sizes are widely used as diverting agents during fracture treatments. The recommended particles should temporarily bridge inside the fracture to create a temporary low-permeability pack that increases the pressure within the fracture and enables redirection of next-stage fluid to under-stimulated intervals. The objective of this study is to experimentally investigate and optimize parameters affecting the selection of solid particles as diversion agents such as material chemistry, particle size, particle shape, particle size distribution, particle loading, carrier fluid type, and carrier fluid viscosity. Three tests were performed in this study: Bridging tests to determine the optimized particle size and loading as function of fracture width (0.04 to 0.2 in.); pack permeability tests to optimize the particle size distribution and shape needed to minimize fracture conductivity and build the needed pressure; and dissolution tests under static and dynamic conditions to determine the time need to dissolve the particles as function of temperature, rate, particle size, carrier and produced fluid. At both static and dynamic conditions, the tested solid diverters will dissolve in an aqueous solution with temperature and time. However, temperature has a more significant effect than time on the dissolution rate. For Diverter A, Increasing the water salinity reduced the dissolution of Diverter A. However, water salinity did not affect dissolution until a certain amount of solid was dissolved into solution. Dissolution was increased by reducing the particle size (and therefore increasing particle surface area). Live and spent HCl acid dissolve significantly less Diverter A than Deionized water (DI water) or Potassium chloride (KCl) solution. For Diverter B (10/30), DI water dissolved 0.06 ppg (14.2% dissolution) of Diverter B after 24 hrs. However, increasing the temperature to 225 and 250 °F, increased the dissolution to 28.7%, and 95.7%, respectively. Finally, at 300°F, 100% dissolution was noted for Diverter B after 8 hrs. Diverter B dissolves in 3 wt% KCl solution very similarly to dissolution in DI water. This gives indication that above 225°F, the dissolution of Diverter B is independent of water salinity. Hydrochloric acid (HCl acid) significantly increases the dissolution of Divert B (10/30) and (20/70), taking only 4 hrs for completely dissolution (100%). Also, the dissolution rate in live 15wt% of HCl was independent of particle size. The ratio between the fracture width and the average particle size needed to bridge was found to be 2.4. Diverters A and B tested in this study were able to bridge inside a fracture, reducing its conductivity by converting the open width into a porous medium with a tight permeability for both applications: far-field (FF) and near-wellbore (NW). Diverter A (NW) is more efficient and effective than commodity field grade benzoic acid flakes for a simulated near-wellbore application with a fracture width of 0.2 in. The diverter pack dissolved more slowly in slickwater fluid than in DI water, probably more due to the slickwater's polymer content than its minimal increase in viscosity.

Enhancing complexity of the created fracture geometry is the primary challenge for hydraulic fracturing treatment design in shale formations because of their stress anisotropy. Therefore, near-wellbore diversion is required to evenly stimulate all perforated clusters while far-field diversion inside the created fracture induces additional branch fracturing by overcoming the stresses holding the natural fractures closed. Solid particles with different shapes and sizes are widely used as diverting agents during fracture treatments. The recommended particles should temporarily bridge inside the fracture to create a low- permeability pack that increases the pressure within the fracture and enables redirection of next-stage fluid to understimulated intervals. The objective of this study is to experimentally investigate and optimize parameters affecting the selection of solid particles as diversion agents such as material chemistry, particle size, particle shape, particle size distribution, particle loading, carrier fluid type, and carrier fluid viscosity. Three tests were performed in this study: Bridging tests to determine the optimized particle size and loading as function of fracture width (0.04 to 0.2 in.); pack permeability tests to optimize the particle size distribution and shape needed to minimize fracture conductivity and build the needed pressure; and dynamic dissolution tests to determine the time need to completely dissolve the particles as function of temperature, rate, particle size, and produced fluid. The results of this paper can help in understanding the diversion parameters required to effectively enhance the complexity of the fracturing geometry. For far-field diversion applications (targeting fracture widths of 0.04 to 0.08 in.), larger particles are not required, as the fracture width is small. However, very tight particle pack permeability is needed. For near-wellbore and perforation diversion (targeting fracture widths of 0.2 in. and higher), only larger particles can bridge the wider fractures. Therefore, a wider (in this case tri-modal) particle size distribution is required: coarse particles to bridge the fracture along with a bi-modal distribution of medium and small particles to minimize the particle pack permeability and achieve the diversion. A diverter pack with bi-modal size distribution and higher concentration of small particles reduces particle pack permeability more than a tri-modal size distribution with more medium-size particles. Diverter A and B tested in this study were able to bridge inside the fracture, reducing its conductivity by converting the open width into a porous medium with a tight permeability for both applications: far-field and near-wellbore. Diverter A (NW) is more efficient and effective than commodity benzoic acid flakes for a simulated near-wellbore application with a fracture width of 0.2 in. The diverter pack dissolved more slowly in slickwater fluid than in DI water, probably more due to the slickwater's polymer content than its minimal increase in viscosity.

Carbonate acidizing restores and enhances production by dissolving a fraction of the rock to create highly conductive channels or wormholes. Most experimental acidizing studies are focused on acid injection at Constant Volumetric Rate (CVR) rather than at Constant Injection Pressure (CIP). A recent study highlighted the benefits of each injection technique for 15% wt. HCl acid. Formations with high injectivity should be treated at CVR as efficient wormholes can be propagated with less acid volume. Aditionally, the increasing injection rate characteristic of CIP can be beneficial in formations with initial low injectivity where wormhole dissolution can change from face and conical to dominant pattern. The injection rate and injection pressure for acid and chemical diverters are important variables because they affect wormholing, treatment distribution, and therefore the overall skin reduction. The primary objective of the present work is to investigate the effect of chemical diversion when acid treatments are injected at CVR and CIP. This study focused on the behavior of a Viscoelastic Surfactant (VES) based acid diverter inside the porous media and its effect on the treatment and wormhole distribution for low and high injectivity formations. A core-flood study was conducted using Pink Desert Limestone cores with similar permeability to assess the pressure response of the diverter at CIP. Additionally, a 2-D wormhole model was used to describe the acidizing phenomena. This model captures the acid reaction and chemical diversion coupled with Darcy flow. Synthetic scenarios were created to evaluate the effect of each acid injection technique (CVR and CIP) and diversion staging on the post-treatment skin and wormhole length. The results of these simulations showed that proper staging of a the chemical diverter aided to improve the treatment placement injected at CVR in a long, highly permeable and homogenous zone as shown by smoother wormhole and skin profiles. CIP delivered nearly uniform treatment placement without chemical diverter when applied at the highest rate below fracture pressure in a long, homogenous and low permeable zone. For a synthetic case of a long and heterogeneous treatment zone, this study confirmed that CIP generated branched wormholing in the high-permeability zones in the early stages of a treatment sequence and did not significantly reduce the skin in the low injectivity layers. Fluid placement turned less efficient as the injection rate increased over the course of the treatment. Based on these results, the simulation outputs suggest that CIP is not an effective diversion technique in long treatment intervals with significant injectivity contrast. Additionally, it was observed that the inclusion of diverter stages can improve the treatment distribution.