TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor the last eight years acid fracturing stimulation has been performed in the Veracruz basin to increase gas production in naturally fractured carbonate formations. Several techniques have been proved to enhance the results of these jobs, including the diverting technique and the application of nondamaging viscoelastic fluids technology specifically a selfdiverting viscoelastic based acid system and a polymer-free viscoelastic surfactant gel for fracture initiation and propagation. This paper presents the results of successful acid fracturing treatments recently performed using nondamaging viscoelastic surfactant-based fluids to increase gas production from naturally fractured carbonate formations.Most of the wells drilled and completed in the carbonate formations of cretaceous age in Veracruz basin do not flow naturally because of low matrix permeability and drilling/completion fluids damage. Therefore, acid fracturing treatments are necessary to produce these wells at economical rates.The objective of these treatments is to increase gas production by creating a deeply etched fracture that will bypass the damaged zone and connect to the network of natural fractures and/or fissures. The etched fracture length affects well performance in low-permeability reservoirs; increased fracture length should result in greater production response. The use of nondamaging viscoelastic fluids is necessary to obtain longer effective etched fractures. Combining this with the properties of a viscoelastic diverting acid will significantly increase fracture conductivity as well as the effective stimulation of all perforated intervals.The fluids were combined by using a pumping technique that consists of alternating stages of nonreactive fluids, reactive fluids and diverter fluid to reduce wormhole creation at the nearwellbore area and increase etched fracture length.Four field cases are presented in this paper. In three, multiple intervals were treated, resulting in longer etched fractures as deduced from after-treatment production response and radioactive tracer logs. In the fourth case, not all the intervals were effectively stimulated because diversion was not used.

Chevron Iraq Limited carried out a drill-stem test (DST) campaign in the Kurdistan Region of Iraq starting in year 2014. Several reservoirs with varying characteristics were targeted. The designs of the executed stimulation treatments were based on reservoir and fluid information acquired during the drilling phase. The complex carbonate formations presented uncertainties in terms of the formation fluids, lithology, and the type and severity of formation damage that may have been present. This was a challenge toward stimulation fluids design and treatment placement. With the objective of optimizing stimulation treatments in the tested intervals, stimulation design best practices were applied and a three different stimulation methods were utilized including a hybrid matrix acidizing / acid fracturing approach. In order to design the treatments, open hole logs, drilling fluids damage from mud losses, fluids compatibility, fracture pressures, placement rates, and other well conditions were considered. The bottom-hole pressure recording and the production results measured through the DST operations enabled an in-depth evaluation of the acid response as the campaign progressed and provided valuable data for optimization of the stimulation strategy from one treatment to the next. This paper explains the stimulation fluids selection, quality assurance, fluids placement design, the three differing stimulation strategies applied and rationale for applying them, operational execution, and evaluation of the results in addition to the lessons learned for the way forward. This will be of interest and may be beneficial to those with similar projects involving complex carbonate reservoirs in northern Iraq and other areas of the world.

Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability. The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate. A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume. A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and water injection field strategy, represents a building platform for further field development optimization plans in Southern Iraq.