During the past decade, multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this technique vary, but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing treatments in a single pumping operation. Nevertheless, the high direct and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology to offshore applications. Sometimes, the misplaced perception of hydraulic fracturing as risky and costly operation prevented, rather than encouraged, its application in marginal offshore oilfields. Recent increases in oil prices and the success in onshore applications have encouraged the use of hydraulic fracturing in offshore applications. This study documents the successful effort of taking these techniques to the offshore environment. Transverse fracturing with multistage completion concept— with properly engineered design of well trajectory—can make the difference between the economic success or failure in the field development of low-permeability reservoirs. This study used multidisciplinary and integrated approach to design and execute the treatments, involving reservoir, production optimization, and fracturing engineers from the early stages of well planning to construction. The multilayer Foukanda field, located 52km offshore from Pointe Noire, Congo, has a low permeability and virgin target that was considered noncommercial after discouraging results of two wells. Based on the production results of three cased-hole wells in an analogous field where multiple propped fracturing was applied, the operator decided to drill an open-hole horizontal well that was to be multi-fractured. The initial 90 days average production of this Foukanda well was more than 2500bbl/day. This production rate was double the simulated rate of a vertical well and opened a wide range of further developments both in Foukanda and in other analogue fields in the offshore Congo. Introduction The Foukanda Marine field is located, 20 km to the north of the Kitina platform and 52km to the west of the city of Pointe Noire. Average water depth is around 100 meters. The field was discovered in 1998 by the well FOKM-1. Production started on June 2001. In the same year one well was drilled in the reservoir D but, due to very poor reservoir characteristic this level was abandoned and the well was recompleted on the shallower reservoir B4. The low permeability reservoir D (less than 10 md) was therefore abandoned and only the reservoir B4 and B7 put on production. In the first months of 2007 Foukanda field had a production potential of about 3000–3500 bopd with 6 producer wells (5 in the reservoir B4 and 1 in the B7) and 2 injector wells (2 in B4 and 1 in B7).

Perforations provide the communication between wellbore and formation resulting in a communication path both for injected and produced fluids from the reservoir. Many perforation parameters such as shot phasing, charges size, shot density, type of gun and length of interval play an important role in the correct execution of a fracturing job. Those parameters have to be engineered to guarantee easy formation breakdown, minimize near wellbore restrictions (or tortuosity) and be big enough to prevent proppant bridging while considering fracture treatment size, proppant concentration, proppant size and treatment flow rate. Ideal fracture initiation perforations would create a minimum injection pressure initiating a single fracture (not for shale gas reservoirs) and generate a fracture with minimum tortuosity at an achievable fracture initiation pressure. Best perforation practices are important during the decisional and designing phase but have to be confirmed by field experience even in well known reservoir where formation heterogenity, well deviation, local stress anomalies, cement bound and many other factors can result in unexpected behaviors that could compromise the success of the stimulation treatment. In the following paper a briefly description of perforating theories and different field experiences are reported showing test results executed for a better perforation strategy. Unexpected deviations both from theory recommendations and from field analogies were analyzed as well as successful and unsuccessful remedial solutions in cases of injectivity issues.

This paper reviews the fracture stimulation improvement achieved over the well stimulation experience to attempt a field redevelopment through a well revitalization after workover and recompletion with a multistage hydraulic fracturing string using energized fluids, notwithstanding the limited background of fracture technology applications in Italy. The objectives were concentrated on the reserves final recovery of the principal layers and assessment of potential thin layers that has never produce before, which entail the use of technologies state-of-theart for drilling, completions, stimulation and development plans.The hydraulic fracturing stimulation technique pumping energized fluids introduced in the Roseto-Montestillo field has proved to be very successful recovering well productivity, however some associated problems have required a process optimization during the intervention. The problems ranged from in situ stress variation, that lead to very high pumping pressure (even in presence of very depleted reservoir), plastic or soft formation with potential proppant embedment issues, effective vertical coverage of the target pays intervals and gel residue with the consequent damage to fracture conductivity.Here significant gains in production have been observed following the successful fracture treatment optimization moving from conventional borate crosslinked guar polymer to an optimized zirconate fracturing fluid energized with CO 2 . The use of energized fracturing fluids, expedite the fracture clean up process and dramatically reduce the amount of fluids to be recovered, while aid the lifting process on the other layers where conventional treatments were pumped. All this lead to a higher well productivity sustained along the time while minimize post fracturing problems compare to the jobs with conventional fracture treatment. This paper summarize the fracture stimulation treatment best practices and review the design along with the operational considerations for the area, including treatment volumes, pump rates, surface equipment, completion selection and fluid chemistry.

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The declining reserves in conventional gas reservoirs imply that the oil and gas companies must consider the production of tight no-conventional gas reservoir. The Cupén Mahuida Field is a naturally fractured reservoir composed of series of volcanic and volcaniclastic layers developed into a synrift stage at the Triassic in the Neuquén Basin. To obtain economical production all interesting layers had to be fractured. Therefore, we can assimilate that field to a tight gas, no-conventional reservoir. Due to the huge difference in production between the different layers fractured in the existing wells, and due to the differences in behavior of the pressure during the treatments, it was decided to conduct a detailed analysis of each case. This included well construction, perforating strategy, geology, petrophysics, images log, minifracs and fracture treatments. The results of the study showed two directions of work: First, necessity to modify the operations schedule; second, we needed to improve the definition of what are the layers candidates to stimulation. So operationally, we decided to change the casing size, the perforation scheme and we included as normal practice the use of proppant slugs to reduce the tortuosity effects we may see. The selection of candidate was improved by a better understanding of the formation thru an evaluation of outcrops that permitted to characterize the volcano clastic events and to correlate them with images, nuclear magnetic resonance logs and pressure measurements. With that information and the pressure response in the minifrac analysis we define the optimum size of treatment and the final proppant concentration. Introduction This case study describes a multi disciplinary evaluation of fracture treatments in a naturally fractured volcanoclastic reservoir. It corresponds to the Precuyano formation in the Cupén Mahuida field situated at around 80 Km of Neuquén city, center of Argentina (fig. 1). All the evaluated wells are vertical. Fig. 1: Location Map The net pay is composed of several layers (3 to 7) of porous volcanic rock situated between 3100 and 3700 m and is overpresurized. The net pay height of each layer may vary between 5 and 30 m. Based on the first petrophysical interpretation it was considered that the net pay could be assimilated to a non-fractured clastic rock, and the stimulations were first designed on that basis. The first wells drilled were exploratory and completed with 7" casing. Now the development wells are completed with 5" casing. Those changes allowed to improve the perforation strategy and to reduce the fracture entry problems. An overview of the first results showed that the response of the reservoir was the one of a naturally fractured rock, and that we could not draw a direct relation between the production results of the individual layers and the log information as porosity, height and pressure. So, each individual fracture was evaluated and its production in time, looking at more detailed reservoir characteristics, as natural fractures density, rock deposition system, to be able to define what layers are best candidates and how to design the frac operation for the different type of candidates.