During the past two decades, fracturing stimulation has become a production driver for a much greater part of the oil industry worldwide. Because of the extensive reservoir formation types, fracturing scenarios widely vary from conventional to unconventional cases. Fracturing is one of the few options for commercial hydrocarbon production in some extremely tight reservoirs. Unfortunately, many of the tight formation scenarios achieve fracture inititation and/or extension only under extremely high pressure, thus frequently reaching mechanical forces close to the well completion limitations. Among the different techniques used, the controlled breakdown technique (CBT) helped significantly improve pump rates in some fracture initiation and injection conditions. This technique controls pressure, while considering the completion's mechanical limits. This paper discusses the process and appropriate conditions for CBT application and evaluates when it is convenient or even crucial to help enhance fracture initiation and development.

An engineering approach is discussed for identifying a potentially unconsolidated reservoir in an exploratory area and controlling sand flowback by fracturing using a liquid-consolidation additive as the binding agent. A vertical gas well targeting an exploratory reservoir was completed and hydraulically fractured to help enhance productivity. A petrophysical evaluation was performed with openhole logs, and results showed a potentially unconsolidated pay zone that posed the risk of producing formation sand. After identifying the issue, precautionary measures were taken to help prevent sand production. An engineered solution to hydraulically fracture the reservoir using a liquid-consolidating additive as a binding agent, opposed to the conventional resin-precoated proppant, was successfully performed. The fracturing technique enhanced well productivity and allowed sand-free high production rate of hydrocarbons. Orienting the perforations toward the maximum horizontal stress direction helped reduce tortuosity and placement of the fracturing treatment. This paper presents petrophysical analysis, treatment design, and application, including production analysis to evaluate the effectiveness of the treatment. Evaluation of the openhole logs and understanding the criteria for potential sand-producing formations can help identify sand flowback in the early stages of well completion to promote the application of solutions that will substantially reduce/eliminate problems associated with sand flowback during the life of the well. This technique helped achieve sand control without using screens, simplifying wellbore equipment while enhancing reservoir production. Early identification of the problem minimized production losses and non-productive time (days) for the operator and potential formation sanding problems.

To evaluate and report the benefits of artificial intelligence driven digital engineered breakdown in a pulsed fracturing technique that has been successfully applied for the first time globally in the western desert of Egypt. In this paper, we will discuss how the artificial intelligence driven digital engineered breakdown can affect the production performance of a pulsed fracturing treatment. When formation breakdown is controlled, there are several benefits observed in the fracture geometry and its placement. However, this has never been applied in a pulsed fracturing treatment where creating a dominant fracture is believed to provide better distribution of proppant agglomerates allowing for enhanced fracture conductivity created by void space between the agglomerates. The productivity benefits of the engineered breakdown will be evaluated. A treatment combining both the pulsing technique and the digital engineered breakdown will be reviewed in details such as well geographic data, reservoir quality, openhole log interpretation, pressure response and production models after matching actual data. The treatment will be compared with offset well that was treated with pulsed fracturing technique but without the digital engineered breakdown. Better pressure response was observed during the treatment and higher proppant concentrations were accepted by the formation with much favorable pressure response compared to offset wells. Post frac well tests indicate excellent production performance for the given reservoir quality observed from the logs in comparison to offset wells. Digital applications in fracturing have been recently improving the way we stimulate formations. This novel combination of pulsed fracturing and digital engineered breakdown shows productivity benefits that is crucial in current market conditions to maximize efficiency of operators assets.

Sand production is a major challenge for many oil and gas industry operators, especially with unconsolidated reservoirs with weak bonding between the sand grains that enter the wellbore. This can eventually lead to damage to production lines and erosion effects to other surface equipment along with well productivity when drawdown exceeds the critical drawdown pressure. Although several techniques are used globally to combat sand production, most are uneconomical when considering the risk versus reward and the overall effectiveness in controlling sand production. An aqueous-based resin consolidation technique was evaluated for application in this case after the mechanical properties of the formation and sanding behavior in the field were estimated to be in the acceptable range for this technique to be applied successfully. An injection test followed by the aqueous-based consolidation treatment was bullheaded into the sand-producing zone resulting in minimal rig up and equipment required to operate. Post-treatment, a curing period allowed the resin to consolidate the coated sand grains. Compared to conventional resin, which requires large volumes to coat the near-wellbore region, this treatment used only a small volume of active resin. This effectively coated and cured in the near-wellbore region, providing excellent consolidation strength allowing the well to produce without any sand particles under the same drawdown applied to offset wells in the field. A case study is presented in this paper illustrating an effective, cost-efficient, and proven sand control solution for the high potential reservoirs of Libya. This solution can help develop fields that previously suffered from impaired well productivity and required expensive formation sand handling and disposal. Such a solution restored oil production without any considerable effects on the relative permeability of the formation to hydrocarbon or water while maintaining sand consolidation without any further sand production problems.

One of essential parts of hydraulic fracture job design optimization in deep sandstone formations is to conduct a minifrac test using fracture fluid to identify the closure pressure for calibration of the stress profile and to calibrate the leak-off coefficient of the fracturing fluid, but the test could not provide good understanding for reservoir properties of permeability, reservoir pressure, and intensity of natural fractures. By conducting the actual DFIT (Diagnostic Fracture Injection Test) and minifrac in more than thirty wells in different formations from different fields, several leak-off behaviors are observed and several conclusions can be reached by integrating minifrac, DFIT, geologic settings information, and production data. With the experience of conducting high rate and low rate DFIT before minifrac jobs, we can conclude that there are several benefits for the DFIT by replacing the minifrac, which conventionallyusesg a polymer fracturing fluid, with a non-wall-building fluid consisting mainly of water from the operations and job design perspective, and from the post frac production perspective. DFIT with water can introduce the best methodology to detect the induced complexity that may cause hydraulic fracture job cancellation in cases of detecting high complexity value early before rig movement. Implementing DFIT in a complete hydraulic fracturing design, execution and evaluation workflow can provide a deep understanding of the fracture geometry propagation and reservoir characterization. The main disadvantages of the DFIT is that it requires a long leak-off observation period but that can be minimized in the mD range of sandstone permeability. This paper introduces DFIT in sandstone formations as a good method for integration between the geology, reservoir management, and fracture operations. The paper provides the operational and integral benefits of replacing minifrac and fracturing fluid with DFIT and water in deep sandstone formations, which provides more accurate data analysis because testing is done with same fluid. In addition, it can reduce fracture operations cost by 10%.