Sabiriyah Upper Burgan is a clastic reservoir in North Kuwait, under active development through water flooding and ongoing development drilling. The reservoir is one of the most heterogeneous reservoirs in NK, both geologically and with respect to pressure-production performance. There is wide variance in rock & fluid quality laterally and vertically, compounding the development challenges while water flooding.
The crestal portion of the dome-shaped reservoir exhibited a sharp drop in reservoir pressure. As a result of which, Sea Water injection was started at 3 vertical injectors. Surprisingly, the injectivity in 500-1000 md rock was found to be very poor. Well interventions were attempted to improve the injectivity, including a proppant frac. A series of Step rate tests were conducted to understand & evaluate the possibility of injecting above the parting pressure. The wellhead injection pressure requirement was estimated to be about 3700 psia to attain the desired level of injectivity. This was a turning point on the water flooding strategy for the reservoir, as a new project for water flooding was needed with the surface injection pressure capability.
During the preliminary water flood response, it was observed that there were compartments, even 250 ft. away from the injector. In addition, a major part of the mid-flank & lower-flank segments had questionable connectivity. Expansion of water flood was delayed in order to provide sufficient time for data acquisition, interpretation, and analysis, using the sub surface data of all wells penetrating the Upper Burgan. The strategy was to produce and further develop the reservoir with limited drilling of new wells in high pressure channels/segments and adopting Integrated Reservoir Management (IRM) approach. Now the expanded Injection facility is complete, and enhanced injection quantum have been initiated since March 2014. An active surveillance master plan & segment wise review of pressure-production data are under implementation to maximize the benefit of the water flood to this reservoir.
The reservoir response due to water flood has been realized to get 100% production increase with sustainable rates. The pressure sink locales are re-vitalized with indications of pressure increase. The Voidage Replacement Ratio has improved to 1:1 at identified segments (producer-injection combinations) as per channelized architecture. There is indeed a positive response despite a few premature water breakthrough instances in producers located very close to the injectors. The results have led to plan for water flow regulators in injectors so that zonal conformance control can be achieved to improve the areal & vertical sweep. The reservoir simulation model is being updated with all dynamic pressure-production as well as surveillance data so as to optimize the ultimate recovery.
The paper is focused to share the learning curve and the quick adoption of the implementation of actions adhering to the best practice reservoir management.
This paper presents the basic reservoir characteristics and the key improved oil recovery/enhanced oil recovery (IOR/EOR) methods for sandstone reservoir fields that have achieved recovery factors toward 70%. The study is based on a global analog knowledge base and associated analytical tools. The knowledge base contains both static (STOIIP, primary and ultimate recovery factors, reservoir/fluid properties, well spacing, drive mechanism, and IOR/EOR methods etc.) and dynamic data (oil rate, water-cut, and GOR, etc.) for more than 730 sandstone oil reservoirs. These reservoirs were subdivided into two groups: heavy and conventional oil reservoirs. This study focuses on the reservoirs with recovery factors great than 50% for heavy oil, and recovery factors from 60% to 79% for conventional oil with a view to understand the key factors for such a high recovery efficiency. These key factors include reservoir and fluid properties, wettability, development strategies and the IOR/EOR methods.
The high ultimate recovery factors for heavy oil reservoirs are attributed to excellent reservoir properties, horizontal well application, high efficiency of cyclic steam stimulating (CSS) and steam flood, and very tight well spacing (P50 value of 4 acres, as close as 0.25 acres) development strategy. The 51 high recovery conventional clastic reservoirs are characterized by favorable reservoir and fluid properties, water-wet or mixed-wet wettability, high net to gross ratio, and strong natural aquifer drive mechanism. Infill drilling and water flood led to an incremental recovery of 20% to 50%. EOR technologies, such as CO2 miscible and polymer flood, led to an incremental recovery of 8% to 15%. Homogeneous sandstone reservoirs with a good lateral correlation can reach 79% final recovery through water flood and adoption of close well spacing.
The lessons learned and best practices from the global analog reservoir knowledge base can be used to identify opportunities for reserve growth of mature fields. With favorable reservoir conditions, it is feasible to move final recovery factor toward 70% through integrating good reservoir management practices with the appropriate IOR/EOR technology.
There is considerable and timely interest in oil and condensate production from liquid-rich regions, placing emphasis on the ability to predict the behavior of gas condensate bank developments and saturation dynamics in shale gas reservoirs. As the pressure in the near-wellbore region drops below the dew-point, liquid droplets are formed and tend to be trapped in small pores. It has been suggested that the injection of CO2 into shale gas reservoirs can be a feasible option to enhance recovery of natural gas and valuable condensate oil, while at the same time sequestering CO2 underground. This work develops simulation capabilities to understand and predict complex transport processes and phase behavior in these reservoirs for efficient and environmentally friendly production management.
Although liquid-rich shale plays are economically producible, existing simulation techniques fail to include many of the production phenomena associated with the fluid system that consists of multiple gas species or phases. In this work, we develop a multicomponent compositional simulator for the modeling of gas-condensate shale reservoirs with complex fracture systems. Related storage and transport mechanisms such as multicomponent apparent permeability (MAP), sorption and molecular diffusion are considered. In order to accurately capture the complicated phase behavior of the multiphase fluids, an equation of State (EOS) based phase package is incorporated into the simulator. Due to the large capillary pressure that exists in the nanopores of ultra-tight shale matrix, the phase package considers the effect of capillary pressure on phase equilibrium calculations. A modified negative-flash algorithm that combines Newton's method and successive substitution iteration (SSI) is used for phase stability analysis under the effect of capillary pressure between oil and gas phases.
In addition, a lower-dimensional discrete fracture and matrix (DFM) model is implemented. The DFM model is based on unstructured gridding, and can accurately and efficiently handle the non-ideal geometries of hydraulic fracture in stimulated unconventional formation. Optimized local grid refinement (LGR) is employed to capture the extremely sharp potential gradient and saturation dynamics in the ultra-tight matrix around fracture.
We apply the developed simulator to study the combined effects of capillary pressure and multicomponent storage and transport mechanisms that are closely associated with the phase behavior and hydrocarbon recovery in gas-condensate shale reservoirs. We present preliminary simulation studies to show the applicability of CO2 huff-n-puff for the purpose of enhanced hydrocarbons recovery. Several design components such as the number of cycles and the length of injection period in the huff-n-puff process are also briefly investigated.
Okwen, Roland T. (Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign) | Frailey, Scott M. (Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign)
Historically, deep oil reservoirs with temperatures and pressures above the critical point of carbon dioxide (CO2) are generally preferred over shallower reservoirs in enhanced oil recovery (EOR) and CO2 storage operations because of high recovery and storage efficiencies associated with miscible floods. As a result, shallower reservoirs containing significant volumes of recoverable resource are generally overlooked. However, basins with relatively low geothermal gradients and high fracture gradients, such as the Illinois Basin, can sustain pressures above the vapor pressure of CO2 where CO2 changes from a gas to liquid. Liquid CO2 has fluid properties similar to that of supercritical CO2 and is more readily miscible with oil.
This study evaluates the EOR potential of low-temperature reservoirs based on the performance of a miscible liquid CO2 flood pilot at the Mumford Hills oil field in Posey County, Indiana. About 7,000 tons (6,350 tonnes) of CO2 were injected into a Mississippian sandstone reservoir over a period of 1 year to demonstrate miscible CO2 EOR in low-temperature oil reservoirs. The reservoir model was calibrated with available historical primary waterflood, and CO2 flood pilot data. The calibrated reservoir model was used to simulate different full-field CO2 EOR development scenarios. The projected oil recovery factors range between 10% and 14%, which compares well to the Permian Basin supercritical CO2 flood recovery range of 8% to 16%.
The oil recovery factors from the simulated scenarios suggest that liquid CO2 floods in low-temperature oil reservoirs can achieve an incremental oil recovery similar to deeper, supercritical CO2 floods. Re-evaluating previously overlooked shallow depleted reservoirs as potential candidates for liquid CO2 EOR provides the opportunity to increase the development of these shallow oil reservoirs available for miscible CO2 flooding
As one of the unconventional resources, tight oil has become one of the most important contributor of oil reserves and production growth. The successful commercial production of tight oil is mainly reliant on the advancement in horizontal drilling and multistage hydraulic fracturing technique. Development of tight oil reservoirs remains in an early stage. Primary oil recovery factor in these reservoirs is very low, leaving substantial volume of oil trapped underground due to the low porosity, low permeability characteristic of tight oil reservoirs. Thus, investigation of enhanced oil recovery methods is more than imperative in tight oil reservoirs. CO2 Huff-and-Puff technology has been effectively applied in conventional reservoirs and can be tailored to adapt for the characteristics of tight oil reservoirs.
In this study, the performance of water flooding in tight oil reservoir is studied and compared with that of the CO2 Huff-and-Puff process. Sensitivity analysis demonstrates that the performance of CO2 Huff-and-Puff is more sensitive to the length of gas injection and production step in each cycle, compared to the soaking time. The CO2 Huff-and-Puff process is optimized and an adaptive CO2 Huff-and-Puff process is conducted for tight oil reservoirs after primary production. Simulation results show that the adaptive cycle length CO2 Huff-and-Puff process can improve the incremental oil recovery by 11.1% over a fixed cycle length process. Finally, the inter-well interference during CO2 Huff-and-Puff is studied, and it is found that a multi-well asynchronous CO2 Huff-and-Puff pattern can improve the incremental oil recovery by 31.6% over that of a synchronous pattern.