Deep, tight carbonate reservoirs of Pliensbachian, Sinemurian, and Hettangian Stages of the mid-Mesozoic Era are becoming very important in the continued pursuit of hydrocarbon prospects in North Kuwait. At present, a total of 21 wells have penetrated the targeted reservoir zones. Of these, 12 have been tested for hydrocarbon production covering a large area of about 1700 sq km. Further, six wells have produced oil and gas, with two deemed commercially successful. The entire workflow to characterize these reservoirs is focused on delineating faults and associated fractures in individual wells. Detailed seismic study and volume curvature maps, revealed the existing fault and fracture corridors. Sub-seismic faults and subtle reverse faults with fractures were detected by log correlations and borehole image. Due to paucity of cores in these zones, descriptions of cuttings samples were used to identify faults and fracture zones, based on the presence of large euhedral crystals in the midst of cryptocrystalline dolomite, suggesting the percolation of hydrothermal fluids through fractures. Many of the wells were drilled with an overbalanced mud system, leading to near-borehole porosity and permeability damage to the rock matrix and to the fracture system. Damage to natural fractures intersecting the well can prevent their detection, leading to missed potentially productive intervals. Mobility of hydrocarbons in these tight, fractured carbonate reservoirs depends upon (i) wells intersecting a natural fracture system that is sufficiently permeable and connected to a large volume of reservoir rock and (ii) the near-borehole area not having suffered irreversible damage due to overbalanced drilling. In summary, the proposed reservoirs are very tight carbonates (average 3 pu porosities) and a fracture play is considered to be the key factor in production. Acid stimulation produced multifold increases in productivity. Most of the wells were drilled overbalanced, which has negative impact on the producibility due to formation damage.
The Deep carbonate reservoirs of North Kuwait are broadly divided into deeper assemblage consisting of diagenitically modified dolomitic layer and shallower fractured-laminated tight limestone and Kerogen units. It is a challenge to establish and quantify the known phenomenon of dynamic changes in the flow path characteristics and properties of the reservoir rocks, as the natural stability condition are altered by production of reservoir fluid. The parameters of the flow path characterization become more uncertain in case of deep HP/HT digenetically altered reservoirs and fractured-tight limestone with laminated kerogen, then similar to the North Kuwait deep reservoirs.In this study an integration of static data such as, borehole image, core and petrophysical evaluation with time lapse dynamic reservoir parameters like production, pressure data from buildup and pressure transient analysis was carried out to understand the flow path characteristic changes. A deterministic approach has been used to characterize the reservoir flow system and to estimate the fracture aperture for each time step. Thus the time dependent alternations in the flow path properties such as reduced fracture aperture and linked causative phenomena have been studied with multiple scenarios.A detailed inventory and analysis of various well intervention operations between the time lapse measurements was carried out to distinguish the natural vs. work over induced causatives of flow path changes. This has assisted proper calibration of fracture properties for the static conditions, dynamic simulation and history matching. This workflow has also optimized the application of appropriate reservoir health checkups and remedial interventions. Cases of two representative wells completed in each of the deep reservoir assemblages are presented as examples to demonstrate the study.
An advanced neutron spectroscopy measurement combining capture and inelastic spectroscopy with state-of-the-art hardware has been used to directly determine total organic content (TOC) and to provide detailed mineralogy characterization in an organic-rich source rock in Kuwait. The advanced spectroscopy measurement provides a direct measurement of TOC, obtained from the difference between the measured total carbon and the inorganic carbon obtained from the rock mineralogy. TOC is an important component of the evaluation of an unconventional reservoir as it is a direct input into the determination of the adsorbed gas volume. Core studies including X-ray fluorescence, dual-range infrared Fourier transform mineralogy evaluation, and coulometry for carbon were conducted to validate the measurement. The log spectroscopy results were compared with core TOC data and to core elemental and mineralogical data. Evaluation of the advanced spectroscopy tool was conducted in parallel with the previous-generation spectroscopy measurement to compare the results. The core TOC and the direct TOC log measurements of the advanced spectroscopy tool compared well. The core-to-log elemental dry weights comparison highlighted that, compared to the previous technology, the advanced measurement provided a more accurate evaluation of several elements (including aluminum, potassium, and magnesium). The core-to-log comparison also demonstrated that the new measurement provided robust answers in a tough logging environment, with an effective correction for the carbon content of oil-base mud and for barite, despite the high barite content in the mud. A particular finding of the chemistry/mineralogy combined core analysis was that a large quantity of sulfur, larger than is typically found in unconventional reservoirs, is associated with the kerogen. For the first time in Kuwait, the application of an advanced spectroscopy technology in a challenging carbonate environment effectively provides a detailed and accurate mineralogical description and a model-independent TOC measurement that were not previously available with conventional spectroscopy logging techniques.
Deep HP-HT sour carbonate reservoirs in Northern Kuwait have varied matrix properties and fracture intensities. The wells are drilled with barite laden OBM with 1,000-2,000 psi overbalance. The intervals suffer substantial formation damage during drilling as is evident from the fact that the wells normally do not get activated, in spite of creating an underbalance of 5,000-6,000 psi by displacing mud with a lighter fluid. During the early exploration phase of these reservoirs, long and/or multiple intervals were perforated and treated with conventional matrix stimulation using 28% retarded/ emulsified acid in stages with chemical diverter (gel based and visco-elastic surfactant based). Post stimulation PLT survey in these wells indicated, that only about 5-10% of the total perforated interval contributed to the production; concluding that the diverters were found to be ineffective leading to sub-optimal reservoir management due to poor zonal contribution. As part of strategic reservoir management process selective bottom up approach in perforation with higher concentrations of HCl treatment and without diverter has been adopted in these reservoirs. To obtain a degree of diversion over the perforated interval, the acid was pumped at higher rate and with higher pressure. Adoption of this changed perforation and stimulation treatment has been proved to be the key enablers for improving zonal productivity. Around 30 wells have been completed with this changed perforation strategy and treated with this new recipe and technique. Post stimulation test results are comparable to those wells treated with regular matrix stimulation. The PLT survey post acid wash treatment by this technique showed that zonal contribution has improved. This process in addition to being simpler is faster and cost effective. This paper presents the comparison between the two types of perforation and stimulation strategies vis-à-vis test results and also the QA/QC followed prior to pumping the acid.
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