Unlocking flow pathways in complex carbonate reservoirs: Benefits of an integrated subsurface study from the Cretaceous Mauddud Formation, North Kuwait

Abstract

Despite its long production history (since 1958) and extensive reservoir stimulation by water injection, the Mauddud reservoir of the Sabiriyah field (SAMA) in northern Kuwait has been plagued by relatively disappointing oil production increase, low oil-by-water replacement ratios, and early water-breakthrough observations. The work described in this paper indicates that reservoir complexity and associated permeability heterogeneity are at the root cause of this and are the result of the interplay between sedimentology, diagenesis and the structural evolution of the area.A multi-disciplinary study involving structural geology, sedimentology, diagenesis, reservoir engineering and geomechanics identified the geological processes responsible for the development of principal high-permeability (High-K) elements in SAMA. Their 3D distribution has been characterized and reservoir property ranges have been established, based on integrated evaluation of static (e.g., seismic, core, borehole image, wireline logs, and drilling information such as losses) and dynamic information (e.g., production and injection logging tools, well test information, pressure data, historical production data and tracer information). Feedback loops between geological realizations and dynamic simulations allowed the testing of various concepts and property ranges with learnings implemented in updates of the geological realizations. This approach increases the confidence level in the conceptual geological models.Three principal plumbing elements contribute to the reservoir and property heterogeneity in the SAMA reservoir. Firstly, relatively thin (one to several decimeters) cemented zones characterized by low matrix porosity but significant secondary vuggy and fracture porosity with high permeability occur in two distinct stratigraphic intervals in the reservoir. These intervals occur near sequence boundaries when the carbonates likely experienced brief periods of exposure. They are interpreted to be cemented cycle tops formed during meteoric diagenesis and represent key flow zones for the initial hydrocarbon production as well as for later high-rate production of formation water and injected water, as identified by production/injection logging tools. Faults and associated fault (damage) zones with abundant fractures are the second key plumbing element. Core recovery and observations from wells located closely to a fault zone identified from detailed seismic interpretation highlight the occurrence of abundant fractures. Tracer information clearly identifies faults as preferential migration pathways between injector and producer wells. Thirdly, induced fracture growth near injectors is an important process in the context of High K development. Hall plots identified that injectivity often increases near injectors after a certain period of injection. Geomechanical analysis suggests that induced fracture growth is plausible due to reduction in total horizontal stress due to the combined effect of depletion and water-injection-induced cooling of the reservoir.Reservoir simulations validate the requirement of presence of these three key elements in the plumbing diagram. Yet, dynamic sensitivity testing shows that the three processes each have a variable impact on flow in the reservoir, depending on local factors such as the nearby presence of faults and the development of the cemented cycle tops. Dynamic simulations further indicate that (1) porosity in the cemented cycle tops is likely low, in line with core observations and out of sync with upscaled porosities and (2) lateral extent of individual cemented cycle tops is in the order of few hundred meters, but final connectivity is enhanced by the stacking of different cemented cycle tops and their concentration in two distinct zones in the Mauddud.Armed with the insight from core analyses and dynamic model results, recommendations are made to improve oil production in SAMA: (1) inject away from the zones and faults, and (2) reduce the injection pressure, thus limiting the likelihood of “new” induced fractures and faults forming that may connect to “old” geologic fracture and faults and cause early-water-breakthrough and thus ineffective oil sweep. Reservoir stimulation via matrix injection, rather than under fracturing conditions, may reduce the initial oil production boost but will most likely lead to significantly better ultimate recovery over the long life of SAMA.