This operation was designed out of a need for hydraulic stimulation - whithno height increase - in a highly homogeneous medium with a water table (SierrasBlancas Formation, YPF.Nq.Bco x-3 ST well). From this, an artificial lowerbarrier was placed to control growth in the direction of the water and acrosslinked gel pad was pumped (followed by sand concentrations carried by alinear gel for sand settling) to give rise -upon fracture closure - to adehydrated gel zone of poor permeability. Furthermore, a water inhibitor wasused as an additive for improved water control. Furthermore, a water inhibitorwas used as an additive for improved water control. As an additional advantage, Bottom Screen Out (BSO) pumping might result inan increased fracture length which in turn would lead to a better productionresponse from stimulation, a "sine qua non" condition in lowpermeability reservoirs. Introduction Both fracture length and fracture conductivity are the two most importantfactors for optimized well performance. For low permeability formations (as inour case), the importance of fracture length prevails over that of fractureconductivity and this, in turn, would be constrained due to the lithologic andmechanical homogeneity of our reservoir because, in the absence of barriers, vertical growth would be significant (as shown on any 3D simulator) and ourfracture length would be impaired leading to water communication. As emphasized in paper SPE 25917 (which served as a basis for our operatingrequirement) fracture growth containment has been studied for more than twodecades. Several authors (Braunlich, Hodges & Paoli) suggested injection ofheavy proppants to create a basal barrier at the tip of the fracture andinjection of light proppants (Nguyen & Larsen) to bridge the tip of thefracture as a result of the effect of buoyancy with an eye for containing theupper part of the fracture. All of these authors validated the data in their operations by positive netpressure slopes and post-treatment temperature logs. In our case, as shownthroughout the operation, fracture confinement was confirmed by both netpressure control and a proppant radioactive tracer survey. Formation characteristics Formation: Sierras Blancas. Perforations: 2,725/30 - 2,747/50 meters,(8,940/57–9,012.5/22.2 ft) below ground level. Well lithology involved a consolidated light gray medium-grained sandstone(sometimes ranging from fine-grained to coarse-grained) with quartz and lithicmaterial (greenish gray); with an inconsistent abundant clay matrix andcalcareous cement. Porosity is below standard with isolated dry and heavy blackhydrocarbon shows and negative direct fluorescence: through solvent extractionthey proved slow, soft and greenish. A significant increase in gas detectionwas recorded while drilling these beds with chromatograph readings such as :methane (78%), ethane (14%), propane (6%), and iso- and n-butane (1%). Duringthe flow period of DST N° 1 (which was performed when well was drilled at depthof 2,768 meters (9081 ft) below ground level) a separator was connectedyielding 59,040 m3/d (1,670 Mcfd) of gas and 4.8 m3/d (30.18 bwpd)of formation water (Cl=42 g/l) through a 14 mm (0,55 inch) choke and a dynamicwellhead pressure of 22.5 kg/cm2 (320 psi). A P* of 420kg/cm2 (5974 psi) was interpreted from the pressure plot. Proposed hydraulic stimulation program Taking into account the possibility that water occurs at a depth of 2,763/65m (9,065/9,071.5 ft), a fracture program preceded by a Bottom Screen Out (BSO)was designed. The objective of the BSO was to create an artificial barrier ofstresses in this homogeneous sand and thus control downward fracture growth. Prior to BSO pumping, a minifrac treatment was conducted to calibratepressures, permeability, and fluid efficiency.

In an offshore mature asset workover jobs involve high cost and operational risk that impact on the profitability of the projects. Non-rig interventions are a more sustainable approach to effectively sustain production. The fact that some reservoirs are depleted while many are water flushed often result in modest incremental gains. Due to the age of the asset, several wells present mechanical issues which make any intervention more challenging. The non-rig methodology has proven to be well-suited to these conditions. This paper will describe the criteria and technology used to mitigate the production decline of the TSP (Teak, Samaan & Poui) asset located off the south-east coast of Trinidad. TSP is a mature oil field which has been producing for almost 40 years. The main constraints for flow assurance are sand production, scale and paraffin deposition, high IGLR, skin damage, high water cut, depleted reservoir and mechanical problems. A variety of non-rig interventions have been employed since 2006 in order to mitigate the mentioned constraints and therefore maximize production from the field. These interventions include tubing and formation acid/de-wax jobs, gas lift valve changeout, addition of new perforations, tubing punch, sand clean out, thru-tubing gravel pack and other jobs aimed to acquire information such as pressure surveys and cement, production, reservoir saturation and multi finger logs. These jobs, together with regular gas lift optimization exercises and re-activation of previously shut-in wells, have proven to be quite effective at slowing the natural production decline. An annual technical and operational screening of all wells (active and shut-in) is performed and the under-performing wells are identified and targeted for the non-rig campaign and reactivation. In addition to that, multi-rate tests are carried out throughout the field prioritizing those critical wells. This ensures that the injection gas rates are at their optimal values, maximizing the oil rates and saving injection gas volumes. The non-rig, well re-activation and GLO campaigns have maintained the annual production decline of the TSP field between 8 to 12% while facing operational and reservoir issues inherent in an aging field.