TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Pirital Field is located in the eastern basin of Venezuela and is characterized by large high-pressure/high-temperature (HP/HT) reservoirs. The geology is complex with heavy faulting, natural fracturing and high-formation dip angles. To optimize the evaluation of the new HP/HT reservoirs in the Bosque block, a development and delineation project team was assembled. To fully assess the potential of the HP/HT reservoirs, two exploratory wells were drilled (PIC-25 and PIC-26) to confirm the feasibility of drilling and completing these wells. The mission of the project team was to deliver prolific producers with optimum completion efficiency while minimizing environmental impact.One of the most important tasks was the perforation planning to ensure adequate connectivity to the reservoir in order to successfully test and evaluate each respective horizon. Available petrophysical data indicated that the reservoirs under study were of low porosity (<5%) and permeability (<0.8 md) at a measured depth of 21,000 ft. Several perforating strategies were evaluated, and the final decision was to use propellant-assisted perforating in scenarios where conventional hydraulic fracturing was not in the evaluation plans.This paper covers the methodology used to validate the application of propellant-assisted perforating in HP/HT wells. The perforation-gun assembly selection, along with the analysis of generated peak pressures from the propellant burn process, will be reviewed. The mechanical configuration, wire line design and benefits derived from propellants will be fully explained.The results presented in the two case histories presented will show the benefits observed in the form of low completion skin factors. Propellant-assisted perforating has shown to be an effective method for achieving perforation breakdown when testing tight, HP/HT sandstone reservoirs. Perforating Techniques Pirital and North Monagas AreaTight sandstone formations are typically hydraulically fractured to obtain adequate flow rates required for production testing. Since the two PIC wells were considered to be tight, NomenclatureBHP = bottomhole pressure, psia (Kpa) BHT = bottomhole temperature, ºF (ºC) PI = initial reservoir pressure, psia (Kpa) Pwf = flowing bottomhole pressure, psia (Kpa) k = permeability, md kh = permeability thickness, md-ft C = wellbore storage constant, bbl/psi (m 3 /Kpa) S = skin factor, dimensionless Xf = fracture half-length, ft (m) PI = productivity index, bbl/day/psi (m 3 /day/Kpa)

Uniform distribution of stimulation fluids in a naturally fractured reservoir with high permeability contrasts and a long open hole configuration (more than 800 m) requires an efficient temporary blocking of the preferential zones to allow the fluid to be diverted towards zones with less admission. While having bottomhole temperatures above 175°C means that controlling reaction rates and achieving effective etching to allow appropriate penetration into the invaded zone will be required and thus eliminate skin damage caused during drilling and completion. Therefore, accomplishing the optimal stimulation involves improving not only acid etching efficiency, natural fractures connectivity and adequate fluid penetration, but also achieving homogeneous fluid distribution throughout the interest zone to assure production enhancement. A chelating base fluid system was formulated based on reservoir evaluation through an engineering process that involved numerous laboratory tests, such as rock dissolution capability, acid etching patter analysis, acid spending time evaluation, corrosion control, and compatibility with reservoir fluids, while optimal diverting agent was carefully selected using advance CFD modeling to confirm diversion effectiveness to uniformly distribute fluids under bottomhole conditions and complex well configuration. Finally, stimulation treatment was defined considering fluid invasion, skin removal and productivity analysis. This paper discusses laboratory tests and modeling results as a coupled engineering process to improve acid coverage during an actual implementation in a HPHT well. Laboratory results confirmed that the smart fluid system can create long conductive channels increasing conductivity by dissolving rock formation and prevent by-products precipitation. On the other hand, CFD results demonstrated that the application of multi-stage chemical diversion pills at specific conditions (flow rate, volume, rheology) optimizes fluid distribution. Oil production increased from 3,973 to 4,375 BPD and gas production from 10.0 to 13.4 MMSCFD (½"choke) after executing the stimulation job. Wellhead pressure registered before was 3,845 psi, and after the job increased up to 5,276 psi. Successful stimulation was confirmed with bottomhole conditions which showed an increase of 2,045 psi and 5°C, logged through a bottomhole sensor while the productivity analysis allowed to support skin damage reduction from S=76 to S=0.

Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.