An operation was conducted to resurrect a shut-in injector and producer pair located in the Kuparuk sandstone formation on the North Slope of Alaska. Both wells had been shut in for 5 to 6 years due to low injectivity and low productivity. An injection profile modification was also required for the injection well to redirect injection from the heel to the toe of the horizontal injector. A plan was developed to perform propped fracture stimulations on both wells. This paper focuses primarily on the water-alternating-gas (WAG) injection well due to the additional technical complexity of performing the profile modification and confirming success of both the profile modification and sequenced fracturing treatment at placing multiple propped fractures along the horizontal well. Along with design and execution details, the following material provides insight into propped hydraulic fracturing diversion evaluation through high frequency pressure monitoring (HFPM). Well 1 (the injector) was completed in 2006 as a horizontal injector with a cemented 4.5-in. liner and nine perforated intervals totaling 505 ft along the 1,500 ft of liner through the reservoir. Roughly half of the perforations were toward the heel of the well, and the remainder were toward the toe of the well. Injectivity was much lower than anticipated, on the order of 300 BWPD at 2,600-psi surface injection pressure. Two high-pressure breakdown stimulations yielded little sustained injectivity improvement. By early 2011, injectivity had declined to near zero with the available injection pressure, and the well was shut in. The sequenced fracturing stimulation was planned in 2015 and implemented early 2016 to regain at least some injectivity to provide pressure support and enhanced oil recovery in the offset producer. It was desired to use propped fracture stimulation only on the perforations toward the toe of the well. Hence, it was necessary to isolate the heel perforations prior to fracturing. A coiled-tubing-deployed cement squeeze operation was designed to isolate the heel perforations. This was followed by a sequenced fracturing technique intended to create up to four propped fractures in the toe from 11,830 ft to 12,340 ft. HFPM data processing demonstrated no indication of fracture initiation above 11,900 ft, confirming the integrity of the cement in the squeezed section. HFPM provided good indication of diversion between stimulation stages. The well is achieving its targeted injection rates further verifying the results. For the first time in the industry, high-frequency pressure monitoring has been utilized for the evaluation of a remedial operation that consisted of a cement squeeze and a subsequent stimulation with diversion stages. Confirmed success of the treatment for the well described in this paper may create production enhancement opportunities in different fields.