TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractThe candidate selection criteria, job design, and improved implementation techniques are important parameters for success in remedial acidization jobs in mature fields.Effective acid diversion across heterogeneous carbonate reservoirs has always been challenging and is even more difficult when stimulating high-water-cut wells. For these types of wells, it is crucial to stimulate the oil-saturated layers rather than the watered-out layers. Bullheading conventional stimulation treatments tend to result in the aqueous-based stimulation fluid being injected into the high-water-saturated zones and away from the high-oil-saturated zones. This often results in a dramatic increase in water productivity and a minimal gain in incremental oil.Recently, several of Dubai Petroleum's offshore oil wells have been treated using 15% hydrochloric acid (HCl) and a viscoelastic-surfactant (VES)-based diverter, resulting in a significant uplift in oil production and a decrease in water cut. The VES diverter permits the oil-saturated zones to be stimulated while minimizing the stimulation impact of the water zones, despite large permeability contrasts. This VES fluid is able to maintain its viscosity when in contact with water and it breaks when in contact with oil. The increase in production with decreasing water cut showed the success of this stimulation diversion technique.This paper describes the candidate selection criteria, design, and implementation of successful carbonate matrix stimulation for high-water-cut wells in mature, water-flooded offshore fields.

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.

Well "A" was drilled as a horizontal unstimulated producer in the Kuparuk oil reservoir. Though fracturing was considered during the design phase, the operator wanted to evaluate the well's performance without stimulation. The well was completed with a liner with 10 perforated pups spaced evenly along the wellbore without annular isolation. When production from the well fell short of expectations, hydraulic fracturing was considered, but the completion limited the options to effectively stimulate the lateral. The chosen fracturing treatment was designed to balance maximum reservoir contact with economic considerations. In an attempt to place more than a single fracture at the weakest point of the 3,242 ft. lateral, it was decided to attempt eight fracturing stages separated by diversion pills. High-frequency (200 Hz) pressure transducers were used on the treating line. The data obtained from water hammers at the end of each stage allowed the estimation of diversion performance between fractures for each stage. The stimulation treatment was pumped in the middle of the arctic winter, placing 580,000 lbm of 16/20 mesh ceramic proppant. The amount and placement of sequenced fracturing diversion material, consisting of a composite fluid with multimodal degradable particles and fibers, was adjusted based upon the surface pressure responses throughout the treatment. High-frequency pressure monitoring data revealed a shift in the fracture initiation along the lateral, and post-fracturing production exceeded expectations at 1,500 BOPD and stabilized near 300 BOPD, which is on par with project expectations. High-frequency pressure monitoring applied to the evaluation of fracturing operations is still in its infancy, and there are limitations of this technique for wells with open hole completions. Combining high frequency pressure monitoring, ISIP data and post frac production data, it appears that sequencing fracturing diversion material can help to initiate more than one unique fracture.