Due to the increases in completion costs demand for production improvements, fracturing through double casing in upper reservoirs for mature wells and refracturing early stimulated wells to change the completion design, has become more and more popular. One of the most common technologies used to re-stimulate previously fracked wells, is to run a second, smaller casing or tubular inside of the existing and already perforated pipes of the completed well. The new inner and old outer casing are isolated from each other by a cement layer, which prevents any hydraulic communication between the pre-existing and new perforations, as well as between adjacent new perforations. For these smaller inner casing diameters, specially tailored and designed re-fracturing perforation systems are deployed, which can shoot casing entrance holes of very similar size through both casings, nearly independent of the phasing and still capable of creating tunnels reaching beyond the cement layer into the natural rock formation. Although discussing on the API RP-19B section VII test format has recently been initiated and many companies have started to test multiple casing scenarios and charge performance, not much is known about the complex flow through two radially aligned holes in dual casings. In the paper we will look in detail at the parameters which influence the flow, especially the Coefficient of Discharge of such a dual casing setup. We will evaluate how much the near wellbore pressure drop is affected by the hole's sizes in the first and second casing, respectively the difference between them and investigate how the cement layer is influenced by turbulences, which might build up in the annulus. The results will enhance the design and provide a better understanding of fracturing or refracturing through double casings for hydraulic fracturing specialists and both operation and services companies.

Hydraulic fracturing or fracking is a well stimulation technique for extracting hydrocarbons from naturally low (extra low) permeable oil and gas reservoirs. In this process water, proppant and chemicals are injected through the wellbore and from the perforation hole into the reservoir. The main goal of this treatment is to create artificial fluid path conduits in the formation and finally increase the permeability (and productivity) of the reservoirs. One of the important factors which affects the near wellbore fluid pressure drop is the coefficient of discharge (Cd) which is a characteristic of the perforated hole in the wellbore tubular. The coefficient of discharge is defined as the ratio of the measured mass flow to the theoretical mass flow. The Cd depends on many factors and may change with time due to erosion caused by the injected sand, which was pumped into the formation. In this research, we investigated some of the factors that can affect the coefficient of discharge like the erosion of the perforated hole and the backpressure given by the fracture. For this purpose, we have developed a new high-pressure high-flow rate setup for examining the effect of the following parameters which can alter the coefficient of discharge. More specifically we have investigated the effect of perforation hole size, perforation hole geometry and perforation shape on the Cd value at ambient conditions and with backpressure, before and after sand erosion. To do so, in a first step we have used machined holes with a clearly defined geometry and then compared the results with real perforated holes which were generated using various shaped charge designs. The coefficient of discharge was measured using water or gelled water with different pressure differentials and back-pressures. In our study, we have injected sand slurry for 30 minutes with a constant concentration. The flow rate and pressure drop were also recorded simultaneously during the injection of the sand. Our results show how the erosion directly affects the Cd value and the subsequent pressure drop near the perforated hole. A clear increase of the Cd magnitude becomes visible only due to a change of the inlet geometry without changing the diameter. Also, the backpressure, which represents real fracking conditions, leads to a significant increase compared to the measurements at ambient outlet pressures. The measured values before and after the erosion for real perforation holes differ from simple drilled holes. From the recorded results, it also seems that certain perforation shapes or geometries are more effected by erosion than others.

Numerous papers have dealt with the description and measurements of the erosion of perforation holes during a hydraulic fracturing treatment in single casing completions, but not much is known about the erosion of perforations in dual casing setups. This study addresses this topic and compares it to the erosion rate of single casing scenarios and how this is influenced by the backpressure, which is created by the fracture closure pressure. The API 19B norm provides a guideline on how to test perforators under the most realistic downhole conditions. All casings used in our experiments were perforated in such a Section IV test set-up and subsequently installed in a specially designed high pressure flow apparatus. The casing holes were carefully measured, their hydraulic resistance was determined by a flow test and successively eroded by a slurry using high pressure pumping equipment. After each test, the holes were again geometrically measured, and their flow resistance was tested. In addition, the sand grain sizes were analyzed before and after the tests. Our tests revealed a significant difference in the erosion characteristic of dual casing compared to single casing setups. Especially the diameter of the hole in the inner casing is critical for the progress of the erosion and the final hole diameters. Equal holes on both casings provide a better control of the treating pressures, especially after the first minutes of the treatment. The back pressure, which is created by the fluid in the fractures, influences mainly the flow rate through the perforation. For identical flow rates, the pressure differential becomes less with back pressure, however the erosion rate as a function of the cumulative energy pumped through the perforation, remains similar. Finally, the application and design of a bigger test cell was evaluated and will be discussed as well. Although many perforating companies have started testing the charge performance for multiple casing completions, not much is known about the flow and erosion of two radially aligned holes in dual cemented casings during the fracture treatment and the influence of the back pressure created by the reservoir. The results will enhance the completion design and provide a better understanding of fracturing or refracturing through double-casings for hydraulic fracturing specialists and both operation and services companies.

The results of API RP 19B Section 2 tests conducted at eight charge manufacturer's testing facilities were used to determine whether differences in vessel size and configuration resulted in different depth-of-penetration results. Findings from these round-robin tests were also used to help guide changes to the newly revised Section 2 documentrecently voted on, approved, and currently in review by API. After agreement among the eight companies was reached on the testing specifics, the tests were conducted over a period of time, enabling an independent operator to observe the tests at each facility. A batch of quality, deep-penetrating shaped charge was supplied by a single manufacturer, and the rock targets were sourced from the same block to minimize differences and allow for fair evaluation of the different testing systems. The hardware materials and test configurations used in the tests were specified (scallop plate and casing coupon, wellbore and target pore pressures), and the independent operator verified that each test was conducted accordingly. The independent operator tabulated the penetration-depth and casing-hole-size data from the tests for comparison per Section 2 testing specifications. At each testing site, a set of successfully performed tests was conducted at confining stresses of 1,500, 3,500, 6,500, and 9,500 psi. The resulting penetration depths were all plotted versus confining stress on the same chart. A statistically significant correlation was found between penetration depth and confining stress (as expected); with a minor correlation with porosity. Most of the scatter in the data was observed at confining stresses of 1,500 and 3,500 psi. A statistical analysis showed that the diameter of the core (4, 5.25, and 7 in.) did not influence the penetration results for this particular deep-penetrating, 21-g explosive shaped charge. This knowledge enables a testing company to conduct Section 2 tests at a lower cost. Additionally, based on statistical analysis, the option of housing the shaped charge within the wellbore chamber versus an open-style configuration is valid because it did not affect the penetration results. The information and results collected from the eight different facilities provide options for vessel type and system configuration and also suggestthe variance to expect in Section 2 tests. Insight into the methods used for conducting these tests and background information on handling the cores are included.

An innovative new design of a perforating system for plug-and-perf completions in unconventional wells demonstrates that operations can be made more efficient, safe and reliable. Results from extensive modeling, testing and field tests demonstrate that the entire perforating process, including gun loading, arming, running, perforating, maintenance and disposal, is made more robust by eliminating traditional approaches to selective perforating, detonators, gun hardware and accessory equipment.The new system optimizes perforating operations with fully assembled and ready-to-shoot gun modules delivered to the base or to the wellsite. An innovative integrated switch-detonator design replaces all wiring and crimping to eliminate human error and to significantly reduce the risk of inadvertent ignition or detonation. Arming a gun is now as efficient, safe and reliable as placing a battery in a flashlight. True intrinsically safe microprocessor switch-detonators require no wiring so they achieve measurably higher reliability than standard separate switch-detonator combinations, and they are immune to potential hazards that can impact standard selective perforating equipment in use today. Surface test equipment detects any malfunctions before running in hole, and the software allows continuous monitoring of all downhole components until initiation and in between shots. All wellsite operations can continue without interruption, and full selectivity, communication to all detonators, stage-skipping and gun redundancy are enabled for the most complex completions. Gun length, shot phasing, shot density and charge type are fully customizable with injection-molded gun parts that do not create unwanted debris after perforation.The system design targets a 10X improvement in reliability over existing plug-and-perf equipment. Wireline service companies traditionally experience reliability in unconventional well perforating ranging from 30 runs/misrun to 100 runs/misrun. Early results suggest the new system may exceed 1,000 runs/misrun. By reducing the risk of mishaps, misruns and misfires, rig time is saved, frack costs are lowered, and every stage can be perforated to contribute to higher well productivity.Field tests of the new design demonstrate the advantages of a fully integrated perforating gun system. The new technology leverages innovative component-level features and a system design approach to produce a perforating system that eliminates many of the causes for misruns, increases simplicity and safety of operations, and delivers higher well productivity.