Romania is a key pioneer in oil and gas industry with a history of more than 150 years'experience. Many of the oil fields discovered in the early days are still being produced. Extending the production life of mature fields presents a variety of challenges including low reservoir pressure, high water cut, limited well data, aging completions and bypassed pay. The target field is a mature oil field situated in the heart of Romania that has been operated since the 1960s and exhibits many of the aforementioned issues. This paper describes the reservoir, exploitation difficulties and new techniques applied to overcome the key challenges to effectively producing this aging asset. Production enhancement in mature assets require new approaches that can address key challenges and risks associated with the reservoir and completion age. Application of conventional can easily lead to failures including ineffective stimulation, completion failure, screen-out, and increased water cut, all causing difficulties to put wells back in production and resulting in disappointing results. In mature fields, a different approach is required. This paper details first time application of the flow channel hydraulic stimulation in one of the wells in the field, describing the importance of well candidate selection phase, engineered design, execution, and evaluation. The applied channel hydraulic stimulation combines geomechanical modeling with intermittent proppant pumping and degradable fibers to obtain heterogeneous placement of proppant within the fracture. A post job production evaluation compares the production after the conventional treatments versus post flow channel hydraulic stimulation job. The results for all conventional hydraulic stimulation treatments show a steep production decline rate, while the positive impact of channel hydraulic stimulation is apparent resulting in higher initial production and an overall slower production decline. The productive reservoirs besides of low reservoir pressure, are characterized by an increased degree of lamination. The target interval is usually described by a sequence of marls and lenticular streaks of sandstone and shaly-marly sandstone. Conventional hydraulic stimulation treatments have had a marginal effect in this reservoir. Due to the variable lithology, gained limited connection through conventional ways of stimulation and/or perforation end up in quick depletion and production decrease. Channel hydraulic stimulation was applied for the first time in this field and may now be considered to be an efficient way of enhancing production in this and similar reservoirs.

Brine workover fluid has a confirmed damage for gas condensate wells generated by both water blockage and fines presented in it. Studied reservoir is a gas condensate field where workover operations performed for replacing downhole equipment have induced severe damage. Formation damage for brine workover fluid was tested on core for both hydrocarbon flowing phases (condensate and gas) and revealed up to four times decreasing in permeability. Laboratory research was then oriented to identify the best solution to remove induced damage. It was tried to identify how much of damage was induced by water blockage and how much by fines present in workover fluid. Tests revealed a good recovery of permeability for gas by using alcohol/surfactant fluids but not close to original permeability. On the other hand correctly formulated mud acid solution have removed induced damage and increased the permeability up to three times more than original permeability. Results have been implemented on field Burcioaia and foam acidizing was used successfully in field tests. For very long perforated intervals foam was used as diverter. In some cases only acid solution was foamed and in other cases also neutral foam was pumped in slugs in between acid stages. Case histories for performed removing damage jobs are also presented.

In an effort of maximizing the production from low permeability reservoirs in mature fields, operators often strive to implement innovative technologies and engineering approaches that can help achieve that goal. This paper presents an analysis of the temperature responses from bottom hole gauges of several horizontal wells that have been stimulated offshore Black Sea. The analysis covers the fluid cool down and heat back profile during stimulation and production. Ultimately, the analysis' goal being to better understand the rheological properties of the stimulation fluid and enhance well clean-up by avoiding miss-allocation of temperature ranges during fluid testing for when the well is brought on production. Based on available data from bottom hole gauges implemented in the horizontal wells stimulated in the Black Sea, an analysis of the temperature gauge responses has been performed. The analysis includes a workflow of temperature change validation per well, considering fluid pumped per port in stimulation phase and fluids produced per port in production phases. The fluid production allocation per port was done utilizing chemical tracer technology results. Stimulation treatments in the same reservoir offshore Black Sea, Romania have been analyzed in terms of bottom hole gauge readings of temperature during the stimulation fluid pumping and during the early production period of each well. A workflow was implemented on each well to correlate fluid per stimulation stage pumped to temperature changes during the treatments. Similar approach was used to correlate the temperature heat back profile during the shut in of wells in the initial 48 hours for proppant curing to the production phase clean-up of the wells. The observed cool down during pumping was of no surprise, but the heat back indicated a slower process of warm back that affects the stimulation fluid testing approach and the understanding of possible near wellbore pressure differentials caused by misallocation of temperature range testing of pre job rheology tests. A combination of temperature data with diagnostic tools and the pertaining analysis will provide a better description of wells' performance. In conclusion, misinterpretation of modelled cool down and reservoir heat back can lead to erroneous understanding of fluid clean up, ultimately affecting reservoir fluid inflow. Understanding the areal temperature response helped optimize fluid testing approach and plan for better clean up. The approach and the sensitivity analysis results are beneficial in understanding the temperature behavior during treatment pumping and production of stimulated wells. This process can enhance an engineer's approach in scrutinizing stimulation fluid testing for improved post stimulation clean up.