In North Africa oil fields, numerous old wells have been completed with 4.5- or 5-in. slotted liners. These wells have been producing oil for several years and have a history of stimulation activity performed to clean up near-wellbore damage caused by scale and asphaltene deposits and workover-fluid invasion. The prevalent technique used for removing near-wellbore damage has been to jet the scale buildup with a jetting nozzle run on coiled tubing (CT) and use an appropriate solvent (i.e., acid or aromatic solvents) for dissolving it. The results from these routine stimulation treatments have been good, with an increase in production two to three times pre stimulation production rates. However, a recent change in stimulation technique involves use of a "fluidic oscillator" (FO) tool. Results from using the FO tool instead of the conventional jetting tool have been significant; the post-stimulation production has improved several times over the previous stimulation gains seen in the same wells. The advantage the FO tool provides is that it generates pulsating pressure waves. The pressure waves radiate spherically from the point of origin (from the FO tool) and provide 360° coverage. When the pressure wave contacts the formation, the energy is absorbed by the rock matrix, and the continuous cycling of these pressure waves causes the damage to reach its fatigue-failure point. As the damage is removed and the original permeability is restored, the pressure waves can penetrate more deeply into the formation matrix, for more complete damage removal. Benefits are quite evident from the comparative results provided by several wells in the North Africa oil fields. The FO tool technique should help other operators optimize their treatments and achieve these benefits. Introduction One North Africa oil field covers about 2000 km2 with more than 1,000 wells. It has two thick plays, separated by a fault zone, producing from two formations, the Cambrian and Ordovician, at depths up to 10,500 ft. The porosity is low and ranges from 5 to 10% while the average permeability ranges from 0.5 to 1.0 mD but can reach up to 1000 mD in cases where opened fractures are encountered. The oil density ranges from 43.7 to 45° API with the average gas:oil ratio (GOR) of about 200 m3/m3 and formation temperature of approximately 248°F. Well completions in this field can be openholes, slotted liners, and mixed liners, and cemented and perforated liners with or without concentric pipes. Slotted liners are used in about 80% of the completions (Allouti et al. 1998). They contribute to development of an environment conducive to scale buildup (Gholineezhadm 2006) and the accumulation of clays and fine particles that can choke and plug the liner slots. Wells in this field have been producing for several years, normally requiring remediation from workover, recompletion, and snubbing operations. In most cases, the well is killed for safe operation using oil-based mud or workover-fluids. These fluids usually invade the formation during workover operations and are incompatible with formation fluids, causing severe damage to the near-wellbore matrix. The most common formation-damage modes in this field are salt deposition, scale deposition, asphaltene deposition, clay and fines migration, emulsions, perforations, and reservoir-pressure evolution. Near-wellbore treatment procedures have been standardized and includeTube cleaning and perforation wash with 7.5 to 15% HClPreflush containing HCl (7.5% or 10%) or brineMain treatment with HCl and HF acid for matrix acidizing or aromatic solvent for asphaltene removalOverflush containing HCl (7.5 or 10%), brine, or light hydrocarbonDiversion with foam (most preferred technique to help ensure maximum zonal coverage)

Hydrajet perforating (HJP) has been used in the oil industry for several decades to perforate or slot through casing by high-pressure abrasive jetting, which generally is not cost effective compared to conventional explosive (shaped-charge) perforating. However, within the Algerian oil fields, perforating using explosives has become time consuming and costly because of the strict security requirements associated with explosives. Operators commonly encounter delays in getting the explosives, varying from one week to one month, causing loss of production time and added standby costs for the rig and associated service equipment. Therefore, a nonexplosive solution like HJP has great value as an alternative to explosive perforating. HJP, which forces highly pressured abrasives through jets to impinge/penetrate casing, cement, and formation, can be deployed on coiled tubing (CT) or jointed pipe. Typical penetration depths of 5 to 8 in. can be achieved, depending on the formation characteristics, tool configurations, pressure differential through the jet, and stand-off of the tool inside the casing. Perforation diameters from 0.75 to 3 in. have been achieved, as indicated by field tests and image logs run after perforating. This process has been developed and optimized for various applications, such as perforating for production, remedial cementing, or for hydraulic fracturing. It also has often shown advantages over explosive perforating, not only on a technical level but also from an economic perspective. Therefore, hydrajet perforating is a valuable alternative to explosive-perforating techniques and does not require special authorizations for transportation and handling. This technique has benefited several operators in Algeria, saving cost and time, and also providing other advantages. This paper presents various applications of this technique and how it became an effective alternative to explosive perforating in several case histories from Algeria.

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An operator recently launched a "water-shutoff" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite. Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface. The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place. This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.

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